10-K

UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549

FORM 10-K

[X]	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE      SECURITIES EXCHANGE ACT OF 1934
	For the Fiscal Year Ended December 31, 2012
	OR
[  ]	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE      SECURITIES EXCHANGE ACT OF 1934
	For the transition period from ____________ to ____________

Commission File Number	Registrant; State of Incorporation; Address; and Telephone Number	I.R.S. Employer Identification No.
1-5324	NORTHEAST UTILITIES (a Massachusetts voluntary association) One Federal Street Building 111-4 Springfield, Massachusetts 01105 Telephone:  (413) 785-5871	04-2147929

0-00404 THE CONNECTICUT LIGHT AND POWER COMPANY
(a Connecticut corporation)
107 Selden Street
Berlin, Connecticut 06037-1616
Telephone:  (860) 665-5000 06-0303850

1-02301 NSTAR ELECTRIC COMPANY
(a Massachusetts corporation)
800 Boylston Street
Boston, Massachusetts 02199
Telephone:  (617) 424-2000 04-1278810

1-6392 PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE
(a New Hampshire corporation)
Energy Park
780 North Commercial Street
Manchester, New Hampshire 03101-1134
Telephone:  (603) 669-4000 02-0181050

0-7624 WESTERN MASSACHUSETTS ELECTRIC COMPANY
(a Massachusetts corporation)
One Federal Street
Building 111-4
Springfield, Massachusetts 01105
Telephone:  (413) 785-5871 04-1961130

Securities registered pursuant to Section 12(b) of the Act:

Registrant	Title of Each Class	Name of Each Exchange    on Which Registered
Northeast Utilities	Common Shares, $5.00 par value	New York Stock Exchange, Inc.

Securities registered pursuant to Section 12(g) of the Act:

Registrant	Title of Each Class
The Connecticut Light and Power Company	Preferred Stock, par value $50.00 per share, issuable in series, of which the following series are outstanding:

		$1.90	Series	of 1947
		$2.00	Series	of 1947
		$2.04	Series	of 1949
		$2.20	Series	of 1949
		3.90%	Series	of 1949
		$2.06	Series E	of 1954
		$2.09	Series F	of 1955
		4.50%	Series	of 1956
		4.96%	Series	of 1958
		4.50%	Series	of 1963
		5.28%	Series	of 1967
		$3.24	Series G	of 1968
		6.56%	Series	of 1968
NSTAR Electric Company	Preferred Stock, par value $100.00 per share, issuable in series, of which the following series are outstanding:

4.25%	Series
4.78%	Series

NSTAR Electric Company, Public Service Company of New Hampshire and Western Massachusetts Electric Company each meet the conditions set forth in General Instruction I(1)(a) and (b) of Form 10-K and each is therefore filing this Form 10-K with the reduced disclosure format specified in General Instruction I(2) to Form 10-K.  

Indicate by check mark if the registrants are well-known seasoned issuers, as defined in Rule 405 of the Securities Act.

Yes	No
ü

Indicate by check mark if the registrants are not required to file reports pursuant to Section 13 or Section 15(d) of the Act.

Yes	No
	ü

Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days.

Yes	No
ü

Indicate by check mark whether the registrants have submitted electronically and posted on its corporate Web sites, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

Yes	No
ü

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of the registrants' knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  [ü]

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer.  See definition of "accelerated filer and large accelerated filer" in Rule 12b-2 of the Exchange Act.  (Check one):

	Large Accelerated Filer	Accelerated Filer	Non-accelerated Filer
Northeast Utilities	ü
The Connecticut Light and Power Company			ü
NSTAR Electric Company			ü
Public Service Company of New Hampshire			ü
Western Massachusetts Electric Company			ü

Indicate by check mark whether the registrants are shell companies (as defined in Rule 12b-2 of the Exchange Act):

	Yes	No
Northeast Utilities		ü
The Connecticut Light and Power Company		ü
NSTAR Electric Company		ü
Public Service Company of New Hampshire		ü
Western Massachusetts Electric Company		ü

The aggregate market value of Northeast Utilities’ Common Shares, $5.00 par value, held by non-affiliates, computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of Northeast Utilities’ most recently completed second fiscal quarter (June 30, 2012) was $12,177,646,948 based on a closing sales price of $38.81 per share for the 313,776,010 common shares outstanding on June 30, 2012.  

Northeast Utilities, directly or indirectly, holds all of the 6,035,205 shares, 100 shares, 301 shares, and 434,653 shares of the outstanding common stock of The Connecticut Light and Power Company, NSTAR Electric Company, Public Service Company of New Hampshire and Western Massachusetts Electric Company, respectively.

Indicate the number of shares outstanding of each of the issuers' classes of common stock, as of the latest practicable date:

Company - Class of Stock	Outstanding as of January 31, 2013
Northeast Utilities Common shares, $5.00 par value	314,338,271 shares
The Connecticut Light and Power Company Common stock, $10.00 par value	6,035,205 shares
NSTAR Electric Company Common Stock, $1.00 par value	100 shares
Public Service Company of New Hampshire Common stock, $1.00 par value	301 shares
Western Massachusetts Electric Company Common stock, $25.00 par value	434,653 shares

GLOSSARY OF TERMS

The following is a glossary of abbreviations or acronyms that are found in this report.
CURRENT OR FORMER NU COMPANIES, SEGMENTS OR INVESTMENTS:
CL&P	The Connecticut Light and Power Company
CYAPC	Connecticut Yankee Atomic Power Company
Hopkinton	Hopkinton LNG Corp., a wholly owned subsidiary of NSTAR LLC
HWP	HWP Company, formerly the Holyoke Water Power Company
MYAPC	Maine Yankee Atomic Power Company
NGS	Northeast Generation Services Company and subsidiaries
NPT	Northern Pass Transmission LLC
NSTAR	Parent Company of NSTAR Electric, NSTAR Gas and other subsidiaries (prior to the merger with NU); also the term used for NSTAR LLC and its subsidiaries
NSTAR Electric	NSTAR Electric Company
NSTAR Electric & Gas	NSTAR Electric & Gas Corporation, a Northeast Utilities service company
NSTAR Gas	NSTAR Gas Company
NSTAR LLC	Post-merger parent company of NSTAR Electric, NSTAR Gas and other subsidiaries, and successor to NSTAR
NU Enterprises	NU Enterprises, Inc., the parent company of Select Energy, NGS, NGS Mechanical, Select Energy Contracting, Inc. and E.S. Boulos Company
NU or the Company	Northeast Utilities and subsidiaries
NU parent and other companies	NU parent and other companies is comprised of NU parent, NSTAR LLC, NSTAR Electric & Gas, NUSCO and other subsidiaries, including NU Enterprises, NSTAR Communications, Inc., HWP, RRR (a real estate subsidiary), the non-energy-related subsidiaries of Yankee (Yankee Energy Services Company and Yankee Energy Financial Services Company), and the consolidated operations of CYAPC and YAEC
NUSCO	Northeast Utilities Service Company
NUTV	NU Transmission Ventures, Inc., the parent company of NPT and Renewable Properties, Inc.
PSNH	Public Service Company of New Hampshire
Regulated companies	NU's Regulated companies, comprised of the electric distribution and transmission businesses of CL&P, NSTAR Electric, PSNH, and WMECO, the natural gas distribution businesses of Yankee Gas and NSTAR Gas, the generation activities of PSNH and WMECO, and NPT
RRR	The Rocky River Realty Company
Select Energy	Select Energy, Inc.
WMECO	Western Massachusetts Electric Company
YAEC	Yankee Atomic Electric Company
Yankee	Yankee Energy System, Inc.
Yankee Companies	CYAPC, YAEC and MYAPC
Yankee Gas	Yankee Gas Services Company
REGULATORS:
DEEP	Connecticut Department of Energy and Environmental Protection
DOE	U.S. Department of Energy
DOER	Massachusetts Department of Energy Resources
DPU	Massachusetts Department of Public Utilities
EPA	U.S. Environmental Protection Agency
FERC	Federal Energy Regulatory Commission
ISO-NE	ISO New England, Inc., the New England Independent System Operator
MA DEP	Massachusetts Department of Environmental Protection
NHPUC	New Hampshire Public Utilities Commission
PURA	Connecticut Public Utilities Regulatory Authority
SEC	U.S. Securities and Exchange Commission
SJC	Supreme Judicial Court of Massachusetts
OTHER:
2010 Healthcare Act	Patient Protection and Affordable Care Act
AFUDC	Allowance For Funds Used During Construction
AOCI	Accumulated Other Comprehensive Income/(Loss)
ARO	Asset Retirement Obligation
C&LM	Conservation and Load Management
CfD	Contract for Differences
Clean Air Project	The construction of a wet flue gas desulphurization system, known as "scrubber technology," to reduce mercury emissions of the Merrimack coal-fired generation station in Bow, New Hampshire
CO2	Carbon dioxide
CPSL	Capital Projects Scheduling List
CTA	Competitive Transition Assessment
CWIP	Construction work in progress
EPS	Earnings Per Share
ERISA	Employee Retirement Income Security Act of 1974
ES	Default Energy Service

i

ESOP	Employee Stock Ownership Plan
ESPP	Employee Share Purchase Plan
Fitch	Fitch Ratings
FMCC	Federally Mandated Congestion Charge
FTR	Financial Transmission Rights
GAAP	Accounting principles generally accepted in the United States of America
GSC	Generation Service Charge
GSRP	Greater Springfield Reliability Project
GWh	Gigawatt-Hours
HG&E	Holyoke Gas and Electric, a municipal department of the City of Holyoke, MA
HQ	Hydro-Québec, a corporation wholly owned by the Québec government, including its divisions that produce, transmit and distribute electricity in Québec, Canada
HVDC	High voltage direct current
Hydro Renewable Energy	Hydro Renewable Energy, Inc., a wholly owned subsidiary of Hydro-Québec
IPP	Independent Power Producers
ISO-NE Tariff	ISO-NE FERC Transmission, Markets and Services Tariff
kV	Kilovolt
kW	Kilowatt (equal to one thousand watts)
kWh	Kilowatt-Hours (the basic unit of electricity energy equal to one kilowatt of power supplied for one hour)
LNG	Liquefied natural gas
LOC	Letter of Credit
LRS	Supplier of last resort service
MGP	Manufactured Gas Plant
Millstone	Millstone Nuclear Generating station, made up of Millstone 1, Millstone 2, and Millstone 3.  All three units were sold in March 2001.
MMBtu	One million British thermal units
Moody's	Moody's Investors Services, Inc.
MW	Megawatt
MWh	Megawatt-Hours
NEEWS	New England East-West Solution
Northern Pass	The high voltage direct current transmission line project from Canada into New Hampshire
NOx	Nitrogen oxide
NU Money Pool	Northeast Utilities Money Pool
NU supplemental benefit trust	The NU Trust Under Supplemental Executive Retirement Plan
NU 2011 Form 10-K	The Northeast Utilities and Subsidiaries 2011 combined Annual Report on Form 10-K as filed with the SEC
NSTAR 2011 Form 10-K	NSTAR 2011 Annual Report on Form 10-K as filed with the SEC
NSTAR Electric 2011   Form 10-K	NSTAR Electric 2011 Annual Report on Form 10-K as filed with the SEC
PAM	Pension and PBOP Rate Adjustment Mechanism
PBOP	Postretirement Benefits Other Than Pension
PBOP Plan	Postretirement Benefits Other Than Pension Plan that provides certain retiree health care benefits, primarily medical and dental, and life insurance benefits
PCRBs	Pollution Control Revenue Bonds
Pension Plan	Single uniform noncontributory defined benefit retirement plan
PPA	Pension Protection Act
RECs	Renewable Energy Certificates
Regulatory ROE	The average cost of capital method for calculating the return on equity related to the distribution and generation business segment excluding the wholesale transmission segment
ROE	Return on Equity
RRB	Rate Reduction Bond or Rate Reduction Certificate
RSUs	Restricted share units
S&P	Standard & Poor's Financial Services LLC
SBC	Systems Benefits Charge
SCRC	Stranded Cost Recovery Charge
SERP	Supplemental Executive Retirement Plan
SIP	Simplified Incentive Plan
SO2	Sulfur dioxide
SS	Standard service
TCAM	Transmission Cost Adjustment Mechanism
TSA	Transmission Service Agreement
UI	The United Illuminating Company

ii

NORTHEAST UTILITIES AND SUBSIDIARIES
THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARY
NSTAR ELECTRIC COMPANY AND SUBSIDIARIES
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES
WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY

2012 FORM 10-K ANNUAL REPORT

TABLE OF CONTENTS

	Part I	Page
Item 1.	Business	2
Item 1A.	Risk Factors	19
Item 1B.	Unresolved Staff Comments	23
Item 2.	Properties	24
Item 3.	Legal Proceedings	26
Item 4.	Mine Safety Disclosures	28
	Part II
Item 5.	Market for the Registrants' Common Equity and Related Stockholder Matters	28
Item 6.	Selected Consolidated Financial Data	30
Item 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations	32
Item 7A.	Quantitative and Qualitative Disclosures about Market Risk	72
Item 8.	Financial Statements and Supplementary Data	73
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	175
Item 9A.	Controls and Procedures	175
Item 9B.	Other Information	175
	Part III
Item 10.	Directors, Executive Officers and Corporate Governance	176
Item 11.	Executive Compensation	179
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	205
Item 13.	Certain Relationships and Related Transactions, and Director Independence	207
Item 14.	Principal Accountant Fees and Services	207
	Part IV
Item 15.	Exhibits and Financial Statement Schedules	209
Signatures		210

iii

NORTHEAST UTILITIES AND SUBSIDIARIES

THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARY

NSTAR ELECTRIC COMPANY AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES

WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY

SAFE HARBOR STATEMENT UNDER THE PRIVATE SECURITIES

LITIGATION REFORM ACT OF 1995

References in this Annual Report on Form 10-K to "NU," "we," "our," and "us" refer to Northeast Utilities and its consolidated subsidiaries, including NSTAR LLC and its subsidiaries for periods after April 10, 2012.

From time to time we make statements concerning our expectations, beliefs, plans, objectives, goals, strategies, assumptions of future events, financial performance or growth and other statements that are not historical facts.  These statements are "forward-looking statements" within the meaning of the Private Securities Litigation Reform Act of 1995.  You can generally identify our forward-looking statements through the use of words or phrases such as "estimate," "expect," "anticipate," "intend," "plan," "project," "believe," "forecast," "should," "could," and other similar expressions.  Forward-looking statements are based on the current expectations, estimates, assumptions or projections of management and are not guarantees of future performance.  These expectations, estimates, assumptions or projections may vary materially from actual results.  Accordingly, any such statements are qualified in their entirety by reference to, and are accompanied by, the following important factors that could cause our actual results to differ materially from those contained in our forward-looking statements, including, but not limited to:

·

the possibility that expected merger synergies will not be realized or will not be realized within the expected time period,

·

cyber breaches, acts of war or terrorism, or grid disturbances,

·

actions or inaction by local, state and federal regulatory and taxing bodies,

·

changes in business and economic conditions, including their impact on interest rates, bad debt expense, and demand for our products and services,

·

changes in weather patterns,

·

changes in laws, regulations or regulatory policy,

·

changes in levels and timing of capital expenditures,

·

disruptions in the capital markets or other events that make our access to necessary capital more difficult or costly,

·

developments in legal or public policy doctrines,

·

technological developments,

·

changes in accounting standards and financial reporting regulations,

·

actions of rating agencies, and

·

other presently unknown or unforeseen factors.  

Other risk factors are detailed in our reports filed with the SEC and updated as necessary, and we encourage you to consult such disclosures.

All such factors are difficult to predict, contain uncertainties that may materially affect our actual results and are beyond our control.  You should not place undue reliance on the forward-looking statements, each speaks only as of the date on which such statement is made, and we undertake no obligation to update any forward-looking statement or statements to reflect events or circumstances after the date on which such statement is made or to reflect the occurrence of unanticipated events.  New factors emerge from time to time and it is not possible for us to predict all of such factors, nor can we assess the impact of each such factor on the business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statements.  For more information, see Item 1A, Risk Factors, included in this combined Annual Report on Form 10-K. This Annual Report on Form 10-K also describes material contingencies and critical accounting policies in the accompanying Management’s Discussion and Analysis and Combined Notes to Consolidated Financial Statements.  We encourage you to review these items.

1

NORTHEAST UTILITIES AND SUBSIDIARIES

THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES

NSTAR ELECTRIC COMPANY AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES

WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY

PART I

Item 1.

Business

Please refer to the Glossary of Terms for definitions of defined terms and abbreviations used in this Annual Report on Form 10-K.

NU, headquartered in Boston, Massachusetts and Hartford, Connecticut, is a public utility holding company subject to regulation by FERC under the Public Utility Holding Company Act of 2005.  We are engaged primarily in the energy delivery business through the following wholly owned utility subsidiaries:

●

The Connecticut Light and Power Company (CL&P), a regulated electric utility that serves residential, commercial and industrial customers in parts of Connecticut;

●

NSTAR Electric Company (NSTAR Electric), a regulated electric utility that serves residential, commercial and industrial customers in parts of Massachusetts;

●

Public Service Company of New Hampshire (PSNH), a regulated electric utility that serves residential, commercial and industrial customers in parts of New Hampshire and owns generation assets used to serve customers;

●

Western Massachusetts Electric Company (WMECO), a regulated electric utility that serves residential, commercial and industrial customers in parts of western Massachusetts and owns solar generating assets;

●

NSTAR Gas Company (NSTAR Gas), a regulated natural gas utility that serves residential, commercial and industrial customers in parts of Massachusetts; and

●

Yankee Gas Services Company (Yankee Gas), a regulated natural gas utility that serves residential, commercial and industrial customers in parts of Connecticut.

NU also owns certain unregulated businesses through its wholly owned subsidiaries, NU Enterprises and NSTAR LLC, which are included in its Parent and other companies’ results of operations.

Although NU, CL&P, NSTAR Electric, PSNH and WMECO each report their financial results separately, we also include information in this report on a segment, or line-of-business, basis.  The Regulated companies' segments include the electric distribution segment, the natural gas distribution segment and the electric transmission segment.  The electric distribution segment includes the generation businesses of PSNH and WMECO.  The Regulated companies' segments represented substantially all of NU's total consolidated revenues for years ended December 31, 2012 and 2011.  

MERGER WITH NSTAR

On April 10, 2012, NU completed its merger with NSTAR (Merger).  Pursuant to the terms and conditions of the Agreement and Plan of Merger, as amended, NSTAR was merged with and into a wholly owned subsidiary of NU, which was subsequently renamed NSTAR LLC.  NU’s consolidated financial statements include the results of operations of NSTAR LLC and its subsidiaries for the period after April 10, 2012.

ELECTRIC DISTRIBUTION SEGMENT

General

NU’s electric distribution segment consists of the distribution businesses of CL&P, NSTAR Electric, PSNH and WMECO, which are engaged in the distribution of electricity to retail customers in Connecticut, eastern Massachusetts, New Hampshire and western Massachusetts, respectively, plus the regulated electric generation businesses of PSNH and WMECO.  

The following table shows the sources of 2012 electric franchise retail revenues for NU’s electric distribution companies, collectively, based on categories of customers, including the electric franchise retail revenues of NSTAR Electric from the date of merger, April 10, 2012, through December 31, 2012:

2

(Thousands of Dollars, except percentages)		2012	% of Total
Residential	$	2,731,951	52
Commercial		1,563,709	30
Industrial		753,974	14
Streetlighting and Railroads		40,952	1
Miscellaneous and Eliminations		130,137	3
Total Retail Electric Revenues	$	5,220,723	100%

A summary of our distribution companies’ retail electric GWh sales and percentage changes for 2012, as compared to 2011, is as follows:

	2012 (1)	2011	Percentage Change
Residential	19,719	14,766	33.5%
Commercial	24,117	14,301	68.6%
Industrial	5,462	4,418	23.6%
Other	420	327	28.6%
Total	49,718	33,812	47.0%

⁽¹⁾

NU retail electric sales include the sales of NSTAR Electric from the date of merger, April 10, 2012, through December 31, 2012.

Actual retail electric sales for CL&P, NSTAR Electric and WMECO decreased in 2012, as compared to 2011, due primarily to the warmer than normal weather in the first quarter of 2012, as compared to colder than normal weather in the first quarter of 2011, while actual retail electric sales for PSNH were 0.1 percent higher than last year.  In 2012, heating degree days were 11 percent lower in Connecticut and western Massachusetts, 7 percent lower in the Boston metropolitan area, and 9 percent lower in New Hampshire, as compared to 2011.  On a weather normalized basis (based on 30-year average temperatures), the average NU combined consolidated total retail electric sales decreased 0.2 percent in 2012, as compared to 2011, assuming NSTAR Electric had been part of the NU combined electric distribution system for all periods under consideration.  We believe these decreases were due primarily to increased conservation efforts among all our customer classes and the continued installation of distributed generation at our commercial and industrial customers’ facilities.  For WMECO, the fluctuations in retail electric sales no longer impact earnings as the DPU approved a sales decoupling plan effective February 1, 2011.  Under this decoupling plan, WMECO now has an established annual level of baseline distribution delivery service revenues of $125.4 million that it is able to recover.  This effectively breaks the relationship between sales volume and revenues recognized.

Major Storms

On August 28, 2011, Tropical Storm Irene caused extensive damage to our distribution system.  Approximately 800,000 CL&P, PSNH and WMECO customers were without power at the peak of the outages, with approximately 670,000 of those customers in Connecticut.  Approximately 500,000 customer outages occurred on the NSTAR Electric distribution system in its aftermath.

On October 29, 2011, an unprecedented storm inundated our service territory with heavy snow causing significant damage to our distribution and transmission systems.  Approximately 1.2 million of CL&P, PSNH and WMECO’s electric distribution customers were without power at the peak of the outages, with 810,000 of those customers in Connecticut, 237,000 in New Hampshire, and 140,000 in western Massachusetts.  In terms of customer outages, this was the most severe storm in CL&P’s history, surpassing Tropical Storm Irene; the third most severe in PSNH’s history; and the most severe in WMECO's history.  The storm also caused approximately 200,000 customer outages on the NSTAR Electric distribution system.  

On October 29, 2012, Hurricane Sandy caused extensive damage to our electric distribution system across all three states.  Approximately 1.5 million of our 3.1 million electric distribution customers were without power during or following the storm, with approximately 850,000 of those customers in Connecticut, approximately 472,000 in Massachusetts, and approximately 137,000 in New Hampshire.

As of December 31, 2012, deferred storm restoration costs related to these major storms that are deferred for future recovery at CL&P, NSTAR Electric, PSNH, and WMECO were as follows:

(Millions of Dollars)	Tropical Storm Irene	October Snowstorm	Hurricane Sandy	Total
CL&P	$ 108.6	$ 173.0	$ 159.9	$ 441.5
NSTAR Electric	21.9	13.9	27.8	63.6
PSNH	6.8	15.5	12.1	34.4
WMECO	3.2	23.3	4.2	30.7
Total	$ 140.5	$ 225.7	$ 204.0	$ 570.2

3

On February 8, 2013, a blizzard caused damage to the electric delivery systems of CL&P and NSTAR Electric.  We have estimated that approximately 71,000 and 350,000 of CL&P and NSTAR Electric's distribution customers, respectively, were without power during or following the storm.  We believe that this storm will cost between $100 million to $120 million, with approximately 90 percent of those costs relating to NSTAR Electric.  Management expects the costs to meet the criteria for specific cost recovery in Connecticut and Massachusetts and, as a result, does not expect the storm to have a material impact on the results of operations of CL&P or NSTAR Electric.  Each operating company will seek recovery of these anticipated deferred storm costs through its applicable regulatory recovery process.

ELECTRIC DISTRIBUTION – CONNECTICUT

THE CONNECTICUT LIGHT AND POWER COMPANY

CL&P’s distribution business consists primarily of the purchase, delivery and sale of electricity to its residential, commercial and industrial customers.  As of December 31, 2012, CL&P furnished retail franchise electric service to approximately 1.2 million customers in 149 cities and towns in Connecticut, covering an area of 4,400 square miles.  CL&P does not own any electric generation facilities.  

The following table shows the sources of CL&P’s 2012 electric franchise retail revenues based on categories of customers:

	CL&P
(Thousands of Dollars, except percentages)		2012	% of Total
Residential	$	1,263,845	58
Commercial		711,337	32
Industrial		126,165	6
Streetlighting and Railroads		21,283	1
Miscellaneous		70,012	3
Total Retail Electric Revenues	$	2,192,642	100%

A summary of CL&P’s retail electric GWh sales and percentage changes for 2012, as compared to 2011, is as follows:

	2012	2011	Percentage Change
Residential	9,978	10,092	(1.1)%
Commercial	9,414	9,525	(1.2)%
Industrial	2,426	2,414	0.5 %
Other	291	284	2.3 %
Total	22,109	22,315	(0.9)%

Rates

CL&P is subject to regulation by PURA, which, among other things, has jurisdiction over rates, accounting procedures, certain dispositions of property and plant, mergers and consolidations, issuances of long-term securities, standards of service, management efficiency and construction and operation of facilities.  CL&P's present general rate structure consists of various rate and service classifications covering residential, commercial and industrial services.  CL&P's retail rates include a delivery service component, which includes distribution, transmission, conservation, renewables, CTA, SBC and other charges that are assessed on all customers. Connecticut utilities are entitled under state law to charge rates that are sufficient to allow them an opportunity to recover their reasonable operation and capital costs, to attract needed capital and maintain their financial integrity, while also protecting relevant public interests.

Under Connecticut law, all of CL&P's customers are entitled to choose their energy suppliers, while CL&P remains their electric distribution company.  For those customers who do not choose a competitive energy supplier, under SS rates for customers with less than 500 kilowatts of demand, and LRS rates for customers with 500 kilowatts or more of demand, CL&P purchases power under standard offer contracts and passes the cost of the power to customers through a combined GSC and FMCC charge on customers’ bills.  

CL&P continues to supply approximately 35 percent of its customer load at SS or LRS rates while the other 65 percent of its customer load has migrated to competitive energy suppliers.  Because this customer migration is only for energy supply service, it has no impact on CL&P’s delivery business or its operating income.

The distribution rates established by the PURA for CL&P are comprised of the following:

·

GSC charge (the electric generation services component), which recovers energy-related costs incurred as a result of providing electric generation service supply to all customers that have not migrated to competitive energy suppliers.  The GSC charge is adjusted periodically and reconciled semi-annually in accordance with the directives of PURA.  Expense/revenue reconciliation amounts are recovered in subsequent rates.

4

·

FMCC charge, which recovers any costs imposed by the FERC as part of the New England Standard Market Design, including locational marginal pricing, locational installed capacity payments, any cost approved by PURA to reduce FMCC charges (with conditions) and reliability must run contracts.  The FMCC charge is adjusted periodically and reconciled semi-annually in accordance with the directives of PURA.  Expense/revenue reconciliation amounts are recovered in subsequent rates.

·

SBC charge, established to fund expenses for the public education outreach program, costs associated with various hardship and low income programs, a program to compensate municipalities for losses in property tax revenue due to decreases in the value of electric generating facilities resulting directly from electric industry restructuring, displaced worker protection costs, unfunded storage and disposal costs for spent nuclear fuel generated before January 1, 2000, and decommissioning fund contributions.  Any element of the SBC charge may be revised by PURA as the need arises.  The SBC charge is reconciled annually to actual costs incurred, with any difference refunded to, or recovered from, customers.

·

CTA charge, which pays the principal and interest on RRBs as well as the reasonable and necessary costs related to the RRBs financing.  The CTA charge is also assessed to recover stranded costs associated with electric industry restructuring as well as various IPP contracts that were not funded with the proceeds of the RRBs. The CTA charge is reconciled annually to actual costs incurred, with any difference refunded to, or recovered from, customers.

·

The Renewable Energy Investment Fund charge, which is used to promote investment in renewable energy sources.  Funds collected by this charge are deposited into the Renewable Energy Investment Fund and administered by Connecticut Innovations, Incorporated.  The Renewable Energy Investment Fund charge is set by statute and is currently 0.1 cent per kWh.  

·

C&LM charge, established to implement cost-effective energy conservation programs and market transformation initiatives.  

·

Transmission adjustment clause, which reconciles on a semi-annual basis the transmission revenues billed to customers against the transmission costs of acquiring such services, to recover all of its transmission expenses on a timely basis.  

CL&P, jointly with UI, has entered into four CfDs for a total of approximately 787 MW of capacity consisting of three generation projects and one demand response project.  The capacity CfDs extend through 2026 and obligate the utilities to pay the difference between a set price and the value that the projects receive in the ISO-NE markets.  The contracts have terms of up to 15 years beginning in 2009 and are subject to a sharing agreement with UI, whereby UI will have a 20 percent share of the costs and benefits of these contracts.  CL&P's portion of the costs and benefits of these contracts will be paid by or refunded to CL&P's customers.

CL&P, jointly with UI, has entered into three CfDs (each having a 80 percent to 20 percent sharing mechanism as described above), with developers of peaking generation units approved by the PURA (Peaker CfDs).  These units have a total of approximately 500 MW of peaking capacity.  The Peaker CfDs pay the developer the difference between capacity, forward reserve and energy market revenues and a cost-of-service payment stream for 30 years.  The ultimate cost or benefit to CL&P under these contracts will depend on the costs of plant construction and operation and the prices that the projects receive for capacity and other products in the ISO-NE markets.  CL&P's portion of the amounts paid or received under the Peaker CfDs will be recoverable from or refunded to CL&P's customers.  

On June 30, 2010, PURA issued a final order in CL&P’s most recent retail distribution rate case approving distribution rates and establishing CL&P’s authorized distribution regulatory ROE at 9.4 percent.  

On March 13, 2012, NU and NSTAR reached a comprehensive settlement agreement with both the Connecticut Attorney General and the Connecticut Office of Consumer Counsel related to the Merger.  The settlement agreement covered a variety of matters, including a CL&P base distribution rate freeze until December 1, 2014.  The settlement agreement also provided for a $25 million rate credit to CL&P customers and the establishment of a $15 million fund for energy efficiency and other initiatives to be disbursed at the direction of the DEEP.  CL&P also agreed to forego rate recovery of $40 million of deferred storm costs associated with restoration activities following Tropical Storm Irene and the October 2011 snowstorm.  On April 2, 2012, the PURA approved the settlement agreement and the Merger.

Sources and Availability of Electric Power Supply

As noted above, CL&P does not own any generation assets and purchases energy to serve its SS and LRS loads from a variety of competitive sources through periodic requests for proposals.  CL&P enters into supply contracts for SS periodically for periods of up to three years to mitigate the risks associated with energy price volatility for its residential and small and medium load commercial and industrial customers.  CL&P enters into supply contracts for LRS for larger commercial and industrial customers every three months.  Currently, CL&P has contracts in place with various suppliers for all of its SS loads for the first half of 2013, and 70 percent of expected load for the second half of 2013.  CL&P intends to purchase 10 percent of the SS load for the second half of 2013.  None of the SS load for 2014 has been procured.  CL&P’s contracts for its LRS loads extend through the second quarter of 2013, and CL&P intends to purchase 10 percent of the LRS load for the third quarter of 2013.

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ELECTRIC DISTRIBUTION – MASSACHUSETTS

NSTAR ELECTRIC COMPANY

WESTERN MASSACHUSETTS ELECTRIC COMPANY

The electric distribution businesses of NSTAR Electric and WMECO consist primarily of the purchase, delivery and sale of electricity to residential, commercial and industrial customers within their respective franchise service territories.  As of December 31, 2012, NSTAR Electric furnished retail franchise electric service to approximately 1.1 million customers in Boston and 80 surrounding cities and towns in Massachusetts, including Cape Cod and Martha’s Vineyard, covering an area of 1,702 square miles.  WMECO provides retail franchise electric service to approximately 207,000 retail customers in 59 cities and towns in the western region of Massachusetts, covering an area of 1,500 square miles.  Neither NSTAR Electric nor WMECO owns any fossil or hydro-electric generating facilities, and each purchases its respective energy requirements from competitive suppliers.  

In 2009, WMECO was authorized by the DPU to install 6 MW of solar energy generation in its service territory.  In October 2010, WMECO completed development of a 1.8 MW solar generation facility on a site in Pittsfield, Massachusetts, and in December 2011 completed development of a 2.3 MW solar generation facility in Springfield, Massachusetts.  In connection with the Attorney General settlement agreement (as defined below) that approved the Merger in Massachusetts, WMECO committed to increase its solar generation capacity to 8 MW.  WMECO is continuing to evaluate sites suitable for development of the remaining 3.9 MW of capacity.  WMECO will sell all energy and other products from its solar generation facilities into the ISO-NE market.  NSTAR Electric does not own any solar generating facilities, but agreed to issue a request for proposals to enter into long-term contracts for 10 megawatts of solar power in connection with the Attorney General settlement agreement that approved the Merger in Massachusetts.  NSTAR Electric has entered in two contracts for 5 MW of capacity, which contracts are still pending approval at the DPU.  

The following table shows the sources of the 2012 electric franchise retail revenues of NSTAR Electric and WMECO based on categories of customers:

		NSTAR Electric			WMECO
(Thousands of Dollars, except percentages)		2012	% of Total	2012			% of Total
Residential	$	1,000,038	44	$		213,494	55
Commercial		1,101,575	48			123,651	32
Industrial		94,130	4			40,207	10
Streetlighting and Railroads		13,047	1			3,780	1
Miscellaneous		85,885	3			5,973	2
Total Retail Electric Revenues	$	2,294,675	100%	$		387,105	100%

A summary of NSTAR Electric’s and WMECO’s retail electric GWh sales and percentage changes for 2012, as compared to 2011, is as follows:

	NSTAR Electric			WMECO
	2012	2011	Percentage Change	2012	2011	Percentage Change
Residential	6,741	6,727	0.2 %	1,517	1,533	(1.0)%
Commercial	12,987	13,211	(1.7)%	1,485	1,474	0.7 %
Industrial	1,353	1,418	(4.6)%	663	669	(0.9)%
Other	128	146	(12.2)%	18	19	(5.7)%
Total	21,209	21,502	(1.4)%	3,683	3,695	(0.3)%

Rates

NSTAR Electric and WMECO are each subject to regulation by the DPU, which has jurisdiction over, among other things, rates, accounting procedures, certain dispositions of property and plant, mergers and consolidations, issuances of long-term securities, acquisition of securities, standards of service, management efficiency and construction and operation of distribution, production and storage facilities.  The present general rate structure for both NSTAR Electric and WMECO consists of various rate and service classifications covering residential, commercial and industrial services.  Massachusetts utilities are entitled under state law to charge rates that are sufficient to allow them an opportunity to recover their reasonable operation and capital costs, to attract needed capital and maintain their financial integrity, while also protecting relevant public interests.

Under Massachusetts law, all customers of each of NSTAR Electric and WMECO are entitled to choose their energy suppliers, while NSTAR Electric or WMECO, as the case may be, remains their distribution company.  Both NSTAR Electric and WMECO purchase power from competitive suppliers for, and pass through the cost to, their respective customers who do not choose a competitive energy supplier (basic service).  Basic service charges are adjusted and reconciled on an annual basis.  Most of the residential and small commercial and industrial customers of NSTAR Electric and WMECO have continued to buy their power from NSTAR Electric or WMECO, as the case may be, at basic service rates.  Most large commercial and industrial customers have switched to a competitive energy supplier.

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The Cape Light Compact, an inter-governmental organization consisting of the 21 towns and two counties on Cape Cod and Martha’s Vineyard, serves 200,000 customers through the delivery of energy efficiency programs, effective consumer advocacy, competitive electricity supply and green power options.  NSTAR Electric continues to provide electric service to these customers including the delivery of power, meter reading, billing, and customer service.

NSTAR Electric continues to supply approximately 40 percent of its customer load at basic service rates while the other 60 percent of its customer load has migrated to competitive energy suppliers.  WMECO continues to supply approximately 49 percent of its customer load at basic service rates while the other 51 percent of its customer load has migrated to competitive energy suppliers.  Because customer migration is limited to energy supply service, it has no impact on the delivery business or operating income of NSTAR and WMECO.

The distribution rates established by the DPU for NSTAR Electric and WMECO are comprised of the following:

·

A distribution charge, which includes a fixed customer charge and a demand and/or energy charge to collect the costs of building and expanding the infrastructure to deliver power to its destination, as well as ongoing operating costs.  The distribution charge also includes the recovery, on a fully reconciling basis, of certain DPU-approved safety and reliability program costs, a Pension and PBOP Rate Adjustment Mechanism (PAM) to recover incremental pension and PBOP benefit costs, a reconciling rate adjustment mechanism to recover costs associated with the residential assistance adjustment clause, a net-metering reconciliation surcharge to collect the lost revenues and credits associated with net-metering facilities installed by customers, and an Energy Efficiency Reconciling Factor (EERF) to recover energy efficiency program costs and lost base revenues in addition to those charges recovered in the energy conservation charge.

·

A basic service charge represents the collection of energy costs, including costs related to charge-offs of uncollected energy costs, through DPU-approved rate mechanisms.  Electric distribution companies in Massachusetts are required to obtain and resell power to retail customers through basic service for those who choose not to buy energy from a competitive energy supplier.  Basic service rates are reset every six months (every three months for large commercial and industrial customers).  The price of basic service is intended to reflect the average competitive market price for electric power.  Additionally, the DPU has authorized NSTAR Electric to recover the cost of its Dynamic Pricing Smart Grid Pilot Program through the basic service charge.

·

A transition charge represents costs to be collected primarily from previously held investments in generating plants, costs related to existing above-market power contracts, and contract costs related to long-term power contracts buy-outs.

·

A transmission charge to recover the costs of transporting electricity over high voltage lines from generating plants to substations, including costs allocated by ISO-NE to maintain the wholesale electric market.

·

An energy conservation charge represents a legislatively-mandated charge to collect costs for energy efficiency programs.

·

A renewable energy charge represents a legislatively-mandated charge to collect the costs to support the development and promotion of renewable energy projects.

Rate Settlement Agreement

On February 15, 2012, NU and NSTAR reached comprehensive settlement agreements with the Massachusetts Attorney General (Attorney General settlement agreement) and the DOER related to the Merger.  The Attorney General settlement agreement covered a variety of rate-making and rate design issues, including a base distribution rate freeze through 2015 for NSTAR Electric and WMECO, a rate credit of $15 million to customers of NSTAR Electric and a rate credit of $3 million to customers of WMECO.  The settlement agreement reached with the DOER covered the same rate-making and rate design issues as the Attorney General's settlement agreement, as well as a variety of matters impacting the advancement of Massachusetts clean energy policy established by the Green Communities Act and Global Warming Solutions Act. On April 4, 2012, the DPU approved the settlement agreements and the Merger.

NSTAR Electric is operating under a DPU-approved Rate Settlement Agreement (Rate Settlement Agreement) that was scheduled to expire on December 31, 2012.  As noted above, the rates under the Rate Settlement Agreement are subject to a base distribution rate freeze through 2015 pursuant to the Attorney General settlement agreement.  Pursuant to a 2008 DPU order, Massachusetts electric utilities must adopt rate structures that decouple the volume of energy sales from the utility’s revenues in their next rate case.  The exact timing of NSTAR Electric’s next rate case has not yet been determined, but it will not be before 2015.

In WMECO’s January 31, 2011 rate decision, the DPU approved a revenue decoupling reconciliation mechanism that provides assurance that WMECO will recover a DPU pre-established level of baseline distribution delivery service revenue to manage all other distribution operating expenses and earn a level of return on its capital investment.  The rates under the January 31, 2011 rate decision are subject to a base distribution rate freeze through 2015 pursuant to the Attorney General settlement agreement .

NSTAR Electric and WMECO are each subject to service quality (SQ) metrics that measure safety, reliability and customer service, and must pay to customers any charges incurred for failure to meet such metrics.  Neither NSTAR Electric nor WMECO will be required to

7

pay an assessment charge for its 2012 performance results as both companies performed at or above target for all of their respective SQ metrics in 2012.

Sources and Availability of Electric Power Supply

As noted above, neither NSTAR Electric nor WMECO owns any generation assets (other than WMECO’s recently constructed solar generation), and both companies purchase their respective energy requirements from a variety of competitive sources through requests for proposals issued periodically, consistent with DPU regulations.  NSTAR Electric and WMECO enter into supply contracts for basic service for 50 percent of their respective residential and small commercial and industrial customers twice a year for twelve month terms.  Both NSTAR Electric and WMECO enter into supply contracts for basic service for 100 percent of large commercial and industrial customers every three months.

ELECTRIC DISTRIBUTION – NEW HAMPSHIRE

PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE

PSNH’s distribution business consists primarily of the generation, delivery and sale of electricity to its residential, commercial and industrial customers.  As of December 31, 2012, PSNH furnished retail franchise electric service to approximately 500,000 retail customers in 211 cities and towns in New Hampshire, covering an area of 5,628 square miles. PSNH also owns and operates approximately 1,200 MW of primarily fossil fueled electricity generation plants.  Included in those electric generating plants is PSNH’s 50 MW wood-burning Northern Wood Power Project at its Schiller Station in Portsmouth, New Hampshire, and approximately 70 MW of hydroelectric generation.  PSNH’s distribution business includes the activities of its generation business.

The Clean Air Project, a wet flue gas desulphurization system (Scrubber), was constructed and placed in service by PSNH at its Merrimack Station in September 2011.  The cost of the Scrubber is expected to be recovered through PSNH's ES rates under New Hampshire law.  By November 2011, both of Merrimack Station’s coal-fired units were integrated with the Scrubber, and the Scrubber is now reducing emissions from the units.  PSNH completed remaining project construction activities in 2012 and the final cost of the project was approximately $421 million.

The Clean Air Project was placed in service and began operations nearly two years before the statutory deadline of July 1, 2013.  Tests to date indicate that the Scrubber reduces emissions of SO₂ and mercury from Merrimack Station by over 90 percent, which is well in excess of state and federal requirements.  Notwithstanding the Clean Air Project's environmental successes well in advance of the statutory deadline, competitors and environmental groups continue to challenge PSNH's right to recover the costs of this legally-mandated project.  In particular, TransCanada, a Canadian energy company that is pursuing the transcontinental Keystone XL pipeline across the United States and is a participant in the U.S. competitive electricity market, and the Conservation Law Foundation, an environmental group which initially supported the law requiring installation of the Scrubber and which formally notified PSNH that it intended to sue PSNH under the Clean Air Act for not installing such emissions control technology, both now claim PSNH was imprudent for pursuing the Clean Air Project.  PSNH is vigorously defending its constitutionally protected right to recover the costs of the Clean Air Project, which were invested to comply with the express mandates of state law.

The following table shows the sources of PSNH’s 2012 electric franchise retail revenues based on categories of customers:

	PSNH
(Thousands of Dollars, except percentages)		2012	% of Total
Residential	$	511,036	54
Commercial		313,201	33
Industrial		82,141	9
Streetlighting and Railroads		6,061	1
Miscellaneous		33,948	3
Total Retail Electric Revenues	$	946,387	100%

A summary of PSNH’s retail electric GWh sales and percentage changes for 2012, as compared to 2011, is as follows:

	2012	2011	Percentage Change
Residential	3,138	3,141	(0.1)%
Commercial	3,315	3,315	0.0 %
Industrial	1,345	1,336	0.7 %
Other	23	23	(1.0)%
Total	7,821	7,815	0.1 %

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Rates

PSNH is subject to regulation by the NHPUC, which has jurisdiction over, among other things, rates, certain dispositions of property and plant, mergers and consolidations, issuances of securities, standards of service, management efficiency and construction and operation of facilities.New Hampshire utilities are entitled under state law to charge rates that are sufficient to allow them an opportunity to recover their reasonable operation and capital costs, to attract needed capital and maintain their financial integrity, while also protecting relevant public interests.

Under New Hampshire law, all of PSNH's customers are entitled to choose competitive energy suppliers, with PSNH providing default energy service under its ES rate for those customers who do not elect to use a third party supplier.  Prior to 2009, PSNH experienced only a minimal amount of customer migration.  However, customer migration levels began to increase significantly in 2009 as energy costs decreased from their historic high levels and competitive energy suppliers with more pricing flexibility were able to offer electricity supply at lower prices than PSNH.  By the end of 2012, approximately 9.4 percent of all of PSNH’s customers (approximately 44 percent of load), mostly large commercial and industrial customers, had switched to competitive energy suppliers.  This was an increase from 2011, when 2.6 percent of customers (approximately 36 percent of load) had switched to competitive energy suppliers.  The increased level of migration has caused an increase in the ES rate, as fixed costs of PSNH’s generation assets must be spread over a smaller group of customers and lower sales volume.  The customers that did not choose a third party supplier, predominately residential and small commercial and industrial customers, are now paying a larger proportion of these fixed costs. On July 26, 2011, the NHPUC ordered PSNH to file a rate proposal that would mitigate the impact of customer migration expected to occur when the ES rate is higher than market prices.  On January 26, 2012, the NHPUC rejected the PSNH proposal and ordered PSNH to file a new proposal no later than June 30, 2012, addressing certain issues raised by the NHPUC.  On April 27, 2012, PSNH filed its proposed Alternative Default Energy Service Rate that addresses customer migration, with an effective date of July 1, 2012.  The proposal, if implemented, would result in no impact to earnings and would allow for an increased contribution to fixed costs for all ES customers.  Hearings were held on October 18, 2012 and November 26, 2012.  A final decision is expected in the first quarter of 2013.

PSNH cannot predict if the upward pressure on ES rates due to customer migration will continue into the future, as future migration levels are dependent on market prices and supplier alternatives.  If future market prices once more exceed the average ES rate level, some or all of these customers on third party supply may migrate back to PSNH.  

The distribution rates established by the NHPUC for PSNH are comprised of the following:

·

ES charge, which recovers PSNH’s generation and purchased power costs from customers on a current basis and allows for an ROE of 9.81 percent on its generation investment.  

·

SCRC, which allows PSNH to recover its stranded costs, including above-market expenses incurred under mandated power purchase obligations and other long-term investments and obligations.  PSNH has financed a significant portion of its stranded costs through securitization by issuing RRBs secured by the right to recover these stranded costs from customers over time. PSNH recovers the costs of these RRBs through the SCRC rate.  The amount of the RRB obligation decreases each quarter and the RRBs are scheduled to be retired as of May 1, 2013.

·

TCAM, which allows PSNH to recover its transmission related costs on a fully reconciling basis.  The TCAM is adjusted on July 1 of each year.

On an annual basis, PSNH files with the NHPUC an ES/SCRC cost reconciliation filing for the preceding year.  The difference between revenues and costs are included in the ES/SCRC rate calculations and refunded to or recovered from customers in the subsequent period approved by the NHPUC.  On December 28, 2012, the NHPUC issued orders approving PSNH’s requests to adjust its ES and SCRC rates effective with service rendered on and after January 1, 2013.  The orders approve an increase to the ES billing rate to reflect projected costs for 2013 and a decrease to the SCRC billing rate to reflect the full amortization of RRBs as of May 1, 2013.  The impact to customers that purchase energy from PSNH is a net increase of 1.287 cents per kWh in total rates.

On June 28, 2010, the NHPUC approved a joint settlement of PSNH's rate case.  Under the approved settlement, if PSNH's 12-month rolling average ROE for distribution exceeds 10 percent, amounts over the 10 percent level are to be allocated 75 percent to customers and 25 percent to PSNH.  Additionally, the settlement provided that the authorized regulatory ROE on distribution plant would continue at the previously allowed level of 9.67 percent, and also permitted PSNH to file a request to collect certain exogenous costs and step increases on an annual basis.  In 2012, PSNH filed for a step increase and a change in its accrual to its major storm reserve fund.  On June 27, 2012, the NHPUC approved an annualized distribution rate increase of $7.1 million effective July 1, 2012, for the step increase.  Additionally, PSNH was allowed a $3.5 million increase in the annual accrual to its major storm reserve fund effective July 1, 2012.

On November 22, 2011, the NHPUC opened a docket to review the Clean Air Project including the establishment of temporary rates for near-term recovery of Clean Air Project costs, a prudence review of PSNH's overall construction program, and establishment of permanent rates for recovery of prudently incurred Clean Air Project costs. On April 10, 2012, the NHPUC issued an order authorizing temporary rates, effective April 16, 2012, which recover a significant portion of the Clean Air Project costs, including a return on equity. The docket will continue for a comprehensive prudence review of the Clean Air Project and the establishment of a permanent rate. The temporary rates will remain in effect until a permanent rate allowing full recovery of all prudently incurred costs is approved. At that time,

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the NHPUC will reconcile recoveries collected under the temporary rates with final approved rates.  PSNH expects hearings to commence in this proceeding on or about the third quarter of 2013.  PSNH believes that its actions related to Clean Air Project construction will be deemed prudent. The project was completed for $421 million, approximately $36 million below budget, and has reduced mercury and sulfur emissions by more than 90 percent.  On September 6, 2012, a consultant for the NHPUC filed a report with the NHPUC concluding that PSNH had effectively managed the Clean Air Project.

Sources and Availability of Electric Power Supply

During 2012, approximately 59 percent of PSNH’s load was met through its own generation, long-term power supply provided pursuant to orders of the NHPUC, and contracts with third parties.  The remaining 41 percent of PSNH's load was met by short-term (less than one year) purchases and spot purchases in the competitive New England wholesale power market.  PSNH expects to meet its load requirements in 2013 in a similar manner.  Included in the 59 percent above are PSNH’s obligations to purchase power from approximately two dozen IPPs, the output of which it either uses to serve its customer load or sells into the ISO-NE market.

NATURAL GAS DISTRIBUTION SEGMENT

General

NU’s natural gas distribution segment consists of the distribution businesses of NSTAR Gas and Yankee Gas, which are engaged in the distribution of natural gas to retail customers in eastern Massachusetts and Connecticut, respectively.  

The following table shows the sources of the 2012 natural gas franchise retail revenues of NSTAR Gas and Yankee Gas based on categories of customers:

		NSTAR Gas(1)			Yankee Gas
(Thousands of Dollars, except percentages)		2012	% of Total	2012			% of Total
Residential	$	212,428	63	$		194,110	52
Commercial		110,493	33			118,124	32
Industrial		14,243	4			61,767	16
Total Retail Natural Gas Revenues	$	337,164	100%	$		374,001	100%

⁽¹⁾

NSTAR Gas’ revenue for the full-year ended December 31, 2012, has been provided for comparative purposes only.

A summary of NSTAR Gas’ and Yankee Gas’ retail firm natural gas sales and percentage changes in million cubic feet for 2012, as compared to 2011, is as follows:

	NSTAR Gas(1)			Yankee Gas
	2012	2011	Percentage Change	2012	2011	Percentage Change
Residential	18,385	20,595	(10.7)%	12,488	13,508	(7.6)%
Commercial	19,095	19,662	(2.9)%	16,567	17,175	(3.5)%
Industrial	5,205	5,226	(0.4)%	15,787	16,197	(2.5)%
Total	42,685	45,483	(6.2)%	44,842	46,880	(4.3)%
Total, Net of Special Contracts (2)				39,087	38,197	2.3 %

⁽¹⁾

NSTAR Gas’ sales data for the full-year ended December 31, 2012 compared to 2011 has been provided for comparative purposes only.

⁽²⁾

Special contracts are unique to the Yankee Gas customers who take service under such an arrangement and generally specify the amount of distribution revenue to be paid to Yankee Gas regardless of the customers’ usage.

Our firm natural gas sales are subject to many of the same influences as our retail electric sales, but have benefitted from lower natural gas prices and customer growth across all three customer classes.  In 2012, excluding the impact of NSTAR Gas sales, actual sales decreased, as compared to 2011, due primarily to the warmer than normal weather in the first quarter of 2012, as compared to colder than normal weather in the first quarter of 2011.  On a weather normalized basis, Yankee Gas’ 2012 sales increased due primarily to customer growth, lower cost of natural gas, the migration of interruptible customers switching to firm service rates, and the addition of gas-fired distributed generation in Yankee Gas’ service territory.

On a weather-normalized basis, the average NU combined consolidated total firm natural gas sales increased 2.7 percent in 2012, as compared to 2011, assuming NSTAR Gas had been part of the NU combined natural gas distribution system for all periods under consideration.

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NSTAR GAS COMPANY

NSTAR Gas distributes natural gas to approximately 272,000 customers in 51 communities in central and eastern Massachusetts covering 1,067 square miles.  Total throughput (sales and transportation) in 2012 was approximately 60.5 Bcf.  NSTAR Gas provides firm natural gas sales service to retail customers who require a continuous natural gas supply throughout the year, such as residential customers who rely on gas for heating, hot water and cooking needs, and commercial and industrial customers who choose to purchase natural gas from NSTAR Gas.  

Rates

NSTAR Gas generates revenues primarily through the sale and/or transportation of natural gas. Gas sales and transportation services are divided into two categories: firm, whereby NSTAR Gas must supply gas and/or transportation services to customers on demand; and interruptible, whereby NSTAR Gas may, generally during colder months, temporarily discontinue service to high volume commercial and industrial customers. Sales and transportation of gas to interruptible customers have no impact on NSTAR Gas’ operating income because a substantial portion of the margin for such service is returned to its firm customers as rate reductions.

The Attorney General settlement agreement that approved the Merger provided for a rate freeze through 2015 and a rate credit of $3 million to NSTAR Gas customers.

Retail natural gas delivery and supply rates are established by the DPU and are comprised of:

·

A distribution charge consisting of a fixed customer charge and a demand and/or energy charge that collects the costs of building and expanding the natural gas infrastructure to deliver natural gas supply to its customers. This also includes collection of ongoing operating costs;

·

A seasonal cost of gas adjustment clause (CGAC) that collects natural gas supply costs, pipeline and storage capacity costs, costs related to charge-offs of uncollected energy costs and working capital related costs. The CGAC is reset every six months. In addition, NSTAR Gas files interim changes to its CGAC factor when the actual costs of natural gas supply vary from projections by more than 5 percent; and

·

A local distribution adjustment clause (LDAC) that collects energy efficiency program costs, environmental costs, PAM related costs, and costs associated with the residential assistance adjustment clause.  The LDAC is reset annually and provides for the recovery of certain costs applicable to both sales and transportation customers.

NSTAR Gas purchases financial contracts based on NYMEX natural gas futures in order to reduce cash flow variability associated with the purchase price for approximately one-third of its natural gas purchases.  These purchases are made under a program approved by the Massachusetts Department of Public Utilities in 2006.  This practice attempts to minimize the impact of fluctuations in prices to NSTAR Gas’ firm gas customers.  These financial contracts do not procure gas supply.  All costs incurred or benefits realized when these contracts are settled are included in the CGAC.

Sources and Availability of Natural Gas Supply

NSTAR Gas maintains a flexible resource portfolio consisting of natural gas supply contracts, transportation contracts on interstate pipelines, market area storage and peaking services.  NSTAR Gas purchases transportation, storage, and balancing services from Tennessee Gas Pipeline Company and Algonquin Gas Transmission Company, as well as other upstream pipelines that transport gas from major producing regions in the U.S., including Gulf Coast, Mid-continent, and Appalachian Shale supplies to the final delivery points in the NSTAR Gas service area.  NSTAR Gas purchases all of its natural gas supply from a firm portfolio management contract with a term of one year, which has a maximum quantity of approximately 139,500 MMBtu/day.

In addition to the firm transportation and natural gas supplies mentioned above, NSTAR Gas utilizes contracts for underground storage and LNG facilities to meet its winter peaking demands.  The LNG facilities, described below, are located within NSTAR Gas’ distribution system and are used to liquefy and store pipeline gas during the warmer months for vaporization and use during the heating season.  During the summer injection season, excess pipeline capacity and supplies are used to deliver and store natural gas in market area underground storage facilities located in the New York and Pennsylvania region.  Stored natural gas is withdrawn during the winter season to supplement flowing pipeline supplies in order to meet firm heating demand.  NSTAR Gas has firm underground storage contracts and total storage capacity entitlements of approximately 6.6 Bcf.

A portion of the storage of natural gas supply for NSTAR Gas during the winter heating season is provided by Hopkinton, a wholly-owned subsidiary of NSTAR LLC.  The facilities consist of an LNG liquefaction and vaporization plant and three above-ground cryogenic storage tanks in Hopkinton, Massachusetts having an aggregate capacity of 3.0 Bcf of liquefied natural gas.  NSTAR Gas also has access to facilities in Acushnet, Massachusetts that include additional storage capacity of 0.5 Bcf and additional vaporization capacity.

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Based on information currently available regarding projected growth in demand and estimates of availability of future supplies of pipeline natural gas, NSTAR Gas believes that participation in planned and anticipated pipeline expansion projects will be required in order for it to meet current and future sales growth opportunities.

YANKEE GAS SERVICES COMPANY

Yankee Gas operates the largest natural gas distribution system in Connecticut as measured by number of customers (approximately 212,000 customers in 71 cities and towns), and size of service territory (2,187 square miles).  Total throughput (sales and transportation) in 2012 was approximately 51 Bcf.  Yankee Gas provides firm natural gas sales service to retail customers who require a continuous natural gas supply throughout the year, such as residential customers who rely on gas for heating, hot water and cooking needs, and commercial and industrial customers who choose to purchase natural gas from Yankee Gas.  Yankee Gas also owns a 1.2 Bcf LNG facility in Waterbury, Connecticut, which is used primarily to assist it in meeting its supplier-of-last-resort obligations and also enables it to make economic purchases of natural gas, which typically occur during periods of low demand.

Retail natural gas service in Connecticut is partially unbundled: residential customers in Yankee Gas’ service territory buy gas supply and delivery only from Yankee Gas while commercial and industrial customers may choose their gas suppliers.  Yankee Gas offers firm transportation service to its commercial and industrial customers who purchase gas from sources other than Yankee Gas as well as interruptible transportation and interruptible gas sales service to those commercial and industrial customers that have the capability to switch from natural gas to an alternative fuel on short notice, for whom Yankee Gas can interrupt service during peak demand periods or at any other time to maintain distribution system integrity.  

Rates

Yankee Gas is subject to regulation by PURA, which has jurisdiction over, among other things, rates, accounting procedures, certain dispositions of property and plant, mergers and consolidations, issuances of long-term securities, standards of service, affiliate transactions, management efficiency and construction and operation of distribution, production and storage facilities.

Retail natural gas delivery and supply rates are established by the PURA and are comprised of:

·

A distribution charge consisting of a fixed customer charge and a demand and/or energy charge that collects the costs of building and expanding the natural gas infrastructure to deliver natural gas supply to its customers. This also includes collection of ongoing operating costs;

·

Purchased Gas Adjustment (PGA) clause, which allows Yankee Gas to recover the costs of the procurement of natural gas for its firm and seasonal customers.  Differences between actual natural gas costs and collection amounts on August 31st of each year are deferred and then recovered or returned to customers during the following year.  Carrying charges on outstanding balances are calculated using Yankee Gas' weighted average cost of capital in accordance with the directives of the PURA; and

·

Conservation Adjustment Mechanism (CAM), which allows 100 percent recovery of conservation costs through this mechanism, with a return.  The reconciliation process produces deferrals for future recovery or refund in future customer rates each year.

On June 29, 2011 PURA issued a final decision in Yankee Gas’ rate proceeding, which it amended in September 2011.  The final amended decision approved a regulatory ROE of 8.83 percent, based on a capital structure of 52.2 percent common equity and 47.8 percent debt, approved the inclusion in rates of costs associated with the WWL project, and also allowed for a substantial increase in annual spending for bare steel and cast iron pipe replacement, as requested by Yankee Gas.

Sources and Availability of Natural Gas Supply

PURA requires that Yankee Gas meet the needs of its firm customers under all weather conditions.  Specifically, Yankee Gas must structure its supply portfolio to meet firm customer needs under a design day scenario (defined as the coldest day in 30 years) and under a design year scenario (defined as the average of the four coldest years in the last 30 years).  Yankee Gas also owns a 1.2 Bcf LNG facility in Waterbury, Connecticut, which is used primarily to assist Yankee Gas in meeting its supplier-of-last-resort obligations and also enables Yankee Gas to make economic purchases of natural gas, typically in periods of low demand.  Yankee Gas’ on-system stored LNG and underground storage supplies help to meet consumption needs during the coldest days of winter.  Yankee Gas obtains its interstate capacity from the three interstate pipelines that directly serve Connecticut: the Algonquin, Tennessee and Iroquois Pipelines.  Yankee Gas has long-term firm contracts for capacity on TransCanada Pipelines Limited Pipeline, Vector Pipeline, L.P., Tennessee Gas Pipeline, Iroquois Gas Transmission Pipeline, Algonquin Pipeline, Union Gas Limited, Dominion Transmission, Inc., National Fuel Gas Supply Corporation, Transcontinental Gas Pipeline Company, and Texas Eastern Transmission, L.P. pipelines.  Based on information currently available regarding projected growth in demand and estimates of availability of future supplies of pipeline natural gas, Yankee Gas believes that its present sources of natural gas supply are adequate to meet existing load and allow for future growth in sales.  

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ELECTRIC TRANSMISSION SEGMENT

General

CL&P, NSTAR Electric, PSNH and WMECO, and most other New England utilities, generation owners and marketers are parties to a series of agreements that provide for coordinated planning and operation of the region's generation and transmission facilities and the rules by which they participate in the wholesale markets and acquire transmission services.  Under these arrangements, ISO-NE, a non-profit corporation whose board of directors and staff are independent of all market participants, has served since 2005 as the regional transmission organization of the New England transmission system.  ISO-NE works to ensure the reliability of the system, administers, subject to FERC approval, the independent system operator tariff, oversees the efficient and competitive functioning of the regional wholesale power market and determines which costs of all regional major transmission facilities are shared by consumers throughout New England.

Wholesale Transmission Rates

Wholesale transmission revenues are recovered through formula rates that are approved by the FERC.  Our transmission revenues are recovered from New England customers through charges that recover costs of transmission and other transmission-related services provided by all regional transmission owners, with a portion of those revenues collected from the distribution businesses of CL&P, NSTAR Electric, PSNH and WMECO.  These rates provide for the annual reconciliation and recovery or refund of estimated costs to actual costs.  The difference between estimated and actual costs is deferred for future recovery from, or refunded to, transmission customers.

FERC ROE Proceedings

Pursuant to a series of orders involving the ROE for regionally planned New England transmission projects, the FERC set the base ROE at 11.14 percent and approved incentives that increased the ROE to 12.64 percent for those projects that were in-service by the end of 2008.  Beginning in 2009, the ROE for all regional transmission investment approved by ISO-NE is 11.64 percent, which includes 50 basis points for joining a regional transmission organization.  In addition, certain projects were granted additional ROE incentives by FERC under its transmission incentive policy.  As a result, CL&P earns between 12.64 percent and 13.1 percent on its major transmission projects, NSTAR Electric earns between 11.64 percent and 12.64 percent on its major transmission projects, and WMECO earns 12.89 percent on the Massachusetts portion of GSRP.

On September 30, 2011, several New England state attorneys general, state regulatory commissions, consumer advocates and other parties filed a joint complaint with the FERC under Sections 206 and 306 of the Federal Power Act alleging that the base ROE used in calculating formula rates for transmission service under the ISO-NE Open Access Transmission Tariff by New England transmission owners, including CL&P, NSTAR Electric, PSNH and WMECO, is unjust and unreasonable.  The complainants asserted that the current 11.14 percent rate, which became effective in 2006, is excessive due to changes in the capital markets and are seeking an order to reduce the rate, which would be effective September 30, 2011 through December 31, 2012.  In response, the New England transmission owners filed testimony and analysis based on standard FERC methodology and precedent, demonstrating that the base ROE of 11.14 percent remained just and reasonable.

On May 3, 2012, the FERC issued an order establishing hearing and settlement procedures for the complaint.  The settlement proceedings were subsequently terminated, as the parties had reached an impasse in their efforts to reach a settlement.  In August 2012, the FERC trial judge assigned to the complaint established a schedule for the trial phase of the proceedings.  Complainant testimony supporting a base ROE of 9 percent was filed on October 1, 2012.  Additional testimony was filed on October 1, 2012 by a group of Massachusetts municipal electric companies, which recommended a base ROE of 8.2 percent.  The New England transmission owners filed testimony and analysis on November 20, 2012, demonstrating they believe that the current base ROE continues to be just and reasonable.  On January 18, 2013, the FERC trial staff filed testimony and analysis recommending a base ROE of 9.66 percent based on the midpoint of their analysis with a range of reasonableness of 6.82 percent to 12.51 percent.  The New England transmission owners criticized trial staff's analysis in responsive testimony filed on February 12, 2013.  Complainants' final testimony is due February 27, 2013.  Hearings on this complaint are scheduled for May 2013 and a trial judge’s recommended decision is due in September 2013. A decision from FERC commissioners is expected in 2014.  Refunds to customers, if any, as a result of a reduction in the NU transmission companies’ base ROE would be retroactive to October 1, 2011.

On December 27, 2012, several additional parties filed a separate complaint concerning the New England transmission owners' ROE with the FERC.  This new complaint seeks to reduce the New England transmission owner’s base transmission ROE effective January 1, 2013, and to consolidate this new complaint with the joint complaint filed on September 30, 2011.  The New England transmission owners have asked the FERC to reject this new complaint, and the FERC has not yet acted on it.

As of December 31, 2012, CL&P, NSTAR Electric, PSNH, and WMECO had approximately $2.1 billion of aggregate shareholder equity invested in their transmission facilities.  As a result, each 10 basis point change in the authorized base ROE would change annual consolidated earnings by an approximate $2.1 million.  We cannot at this time predict the ultimate outcome of this proceeding or the estimated impact on CL&P’s, NSTAR Electric’s, PSNH’s, or WMECO’s respective financial position, results of operations or cash flows.

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FERC Order No. 1000:  On October 25, 2012, ISO-NE and a majority of the New England transmission owners, including  CL&P, NSTAR Electric, PSNH and WMECO, made a comprehensive compliance filing as required by FERC Order No. 1000 and Order No. 1000-A, issued on July 21, 2011 and May 17, 2012, respectively.  The compliance filing first seeks to preserve the existing reliability planning process in New England, based on FERC’s previous approval of transmission owners’ rights under the Transmission Operating Agreement with ISO-NE, and the superiority of the current planning process, which has resulted in major transmission construction, large reliability benefits and reduction of market costs.  The filing also contains a new process for public policy transmission planning that incorporates opportunities for competing, non-incumbent projects and cost allocation among the supporting states.  In mid-January 2013, ISO-NE and the majority of New England transmission owners filed answers to various stakeholders that submitted protests to the compliance filing.  We cannot predict the final outcome or impact on us; however implementation of FERC’s goals in New England, including within our service territories, may expose us to competition for construction of transmission projects, additional regulatory considerations, and potential delay with respect to future transmission projects.

Transmission Projects

NEEWS:  GSRP, a project that involves the construction of 115 kV and 345 kV overhead lines by CL&P and WMECO from Ludlow, Massachusetts to Bloomfield, Connecticut, is the first, largest and most complicated project within the NEEWS family of projects.  The $718 million project is expected to be fully placed in service in late 2013.  As of December 31, 2012, the project was approximately 93 percent complete and we have placed $298 million in service.  

The Interstate Reliability Project, which includes CL&P’s construction of an approximately 40-mile, 345 kV overhead line from Lebanon, Connecticut to the Connecticut-Rhode Island border in Thompson, Connecticut where it will connect to transmission enhancements being constructed by National Grid, is our second major NEEWS project.  All siting applications have been filed by CL&P and National Grid.  On January 2, 2013, the Connecticut Siting Council issued a final decision and order approving the Connecticut portion of the project.  Decisions in Rhode Island and Massachusetts are expected between the end of 2013 and early 2014.  The $218 million project is expected to be placed in service in late 2015.  

Included as part of NEEWS are associated reliability related projects, approximately $70 million of which have been placed in service and approximately $30 million of which are in various phases of construction and will continue to go into service through 2013.  

Through December 31, 2012, CL&P and WMECO had capitalized $212 million and $518.1 million, respectively, in costs associated with NEEWS, of which $79.4 million and $183.4 million, respectively, were capitalized in 2012.    

Greater Hartford Central Connecticut Project (GHCC):  In August 2012, ISO-NE presented its preliminary needs analysis for the GHCC to the ISO-NE Planning Advisory Committee.  The results showed severe thermal overloads and voltage violations in each of the four study areas now and in the near future.  A combination of 345 kV and 115 kV transmission solutions are being considered to address these reliability concerns and a set of preferred solutions are expected to be identified by ISO-NE in 2013.  Approximately $300 million has been included in our five-year capital program for future projects being identified to enhance these reliability concerns, which have recently been confirmed by ISO-NE.

Cape Cod Reliability Projects:  Transmission projects serving Cape Cod in the Southeastern Massachusetts (SEMA) reliability region consist of an expansion and upgrade of NSTAR Electric's existing transmission infrastructure including construction of a new 345 kV transmission line that will cross the Cape Cod Canal (The Lower SEMA Transmission Project) as well as a new 115kV transmission line and other 115kV upgrades in the center of Cape Cod.  All regulatory and licensing and permitting is complete for the Lower SEMA Transmission Project.  Construction commenced in September 2012 and is expected to be completed by mid-2013.  The total estimated construction cost for the Cape Cod projects is approximately $150 million.

Northern Pass:  Northern Pass is NPT's planned HVDC transmission line from the Québec-New Hampshire border to Franklin, New Hampshire and an associated alternating current radial transmission line between Franklin and Deerfield, New Hampshire.  Northern Pass will interconnect at the Québec-New Hampshire border with a planned HQ HVDC transmission line.  Effective April 10, 2012, as a result of the merger, NUTV owned 100 percent of NPT.  NPT has identified a new route in the northern-most part of the project’s route where PSNH did not own any rights of way.  We expect to file the new route with the DOE in the first quarter of 2013, and we believe that NPT will be completed in early 2017.

We estimate the costs of the Northern Pass transmission project will be approximately $1.2 billion (including capitalized AFUDC).

Greater Boston Reliability and Boston Network Improvements:  As a result of continued analysis of the transmission needs to enhance system reliability and improve capacity in eastern Massachusetts, NSTAR Electric expects to implement a series of new transmission initiatives over the next five years.  We have included $479 million in our five-year capital program related to these initiatives.

Transmission Rate Base

Under our FERC-approved tariff, transmission projects generally enter rate base after they are placed in commercial operation.  At the end of 2012, our transmission rate base was approximately $4.2 billion, including approximately $2.2 billion at CL&P, $960 million at NSTAR Electric, $412 million at PSNH, and $620 million at WMECO.

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CAPITAL EXPENDITURES

We project capital expenditures of approximately $5 billion from 2013 through 2015.  Of the $5 billion, we expect to invest approximately $2.5 billion in our electric and natural gas distribution segments, including our generation businesses, and $2.3 billion in our electric transmission segment.  In addition, we project capital expenditures of approximately $1.6 billion from 2016 through 2017 in our electric transmission segment.

FINANCING

Our credit facilities and indentures require that NU parent and certain of its subsidiaries, including CL&P, NSTAR Electric, NSTAR Gas, NSTAR LLC, PSNH, WMECO and Yankee Gas, comply with certain financial and non-financial covenants as are customarily included in such agreements, including maintaining a ratio of consolidated debt to total capitalization of no more than 65 percent.  All such companies currently are, and expect to remain in compliance with these covenants.    

As of December 31, 2012, approximately $730 million of NU's long-term debt will be paid in the next 12 months, consisting of $550 million for NU parent, $55 million for WMECO, and $125 million for CL&P.  

NUCLEAR DECOMMISSIONING

General

CL&P, NSTAR Electric, PSNH, WMECO and several other New England electric utilities are stockholders in three inactive regional nuclear generation companies, CYAPC, MYAPC and YAEC (collectively, the Yankee Companies).  The Yankee Companies have completed the physical decommissioning of their respective generation facilities and are now engaged in the long-term storage of their spent nuclear fuel.  Each Yankee Company collects decommissioning and closure costs through wholesale FERC-approved rates charged under power purchase agreements with CL&P, NSTAR Electric, PSNH and WMECO and several other New England utilities.  These companies in turn recover these costs from their customers through state regulatory commission-approved retail rates.  

The ownership percentages of CL&P, NSTAR Electric, PSNH and WMECO in the Yankee Companies are set forth below:

	CL&P	NSTAR Electric	PSNH	WMECO	Total
CYAPC	34.5%	14.0%	5.0%	9.5%	63.0%
YAEC	24.5%	14.0%	7.0%	7.0%	52.5%
MYAPC	12.0%	4.0%	5.0%	3.0%	24.0%

Our share of the obligations to support the Yankee Companies under FERC-approved contracts is the same as the ownership percentages above.  As a result of the Merger, we consolidate the assets and obligations of CYAPC and YAEC on our consolidated balance sheet.

OTHER REGULATORY AND ENVIRONMENTAL MATTERS

General

We are regulated in virtually all aspects of our business by various federal and state agencies, including FERC, the SEC, and various state and/or local regulatory authorities with jurisdiction over the industry and the service areas in which each of our companies operates, including the PURA, which has jurisdiction over CL&P and Yankee Gas, the NHPUC, which has jurisdiction over PSNH, and the DPU, which has jurisdiction over NSTAR Electric, NSTAR Gas and WMECO.

Environmental Regulation

We are subject to various federal, state and local requirements with respect to water quality, air quality, toxic substances, hazardous waste and other environmental matters.  Additionally, major generation and transmission facilities may not be constructed or significantly modified without a review of the environmental impact of the proposed construction or modification by the applicable federal or state agencies.  PSNH owns approximately 1,200 MW of generation assets.  In 2011, PSNH’s Clean Air Project, the installation of a wet flue gas desulphurization system at its Merrimack coal station to reduce its mercury and sulfur dioxide emissions, was placed into service.  The Clean Air Project was fully operational by mid-2012 and is designed to capture more than 80 percent of the mercury in the coal from the coal burning stations and to reduce sulfur dioxide emissions by more than 90 percent, making Merrimack one of the cleanest coal-burning plants in the nation.  The final cost of the project was approximately $421 million.  Compliance with additional environmental laws and regulations, particularly air and water pollution control requirements, may cause changes in operations or require further investments in new equipment at existing facilities.  

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Water Quality Requirements

The Clean Water Act requires every “point source” discharger of pollutants into navigable waters to obtain a National Pollutant Discharge Elimination System (NPDES) permit from the EPA or state environmental agency specifying the allowable quantity and characteristics of its effluent. States may also require additional permits for discharges into state waters.  We are in the process of maintaining or renewing all required NPDES or state discharge permits in effect for our facilities.  In each of the last three years, the costs incurred by PSNH related to compliance with NPDES and state discharge permits have not been material.

On September 29, 2011, the EPA issued for public review and comment a draft renewal NPDES permit under the Clean Water Act for PSNH’s Merrimack Station.  The draft permit would require PSNH to install a closed-cycle cooling system at the station.  The EPA estimated that the net present value cost to install this system and operate it over a 20-year period would be approximately $112 million.  On October 27, 2011, the EPA extended the initial 60-day public review and comment period on the draft permit for an additional 90 days until February 28, 2012.  In its filed comments, PSNH stated that the data and studies supplied to the EPA demonstrates the fact that a closed-cycle cooling system is not warranted.  The EPA has no deadline to consider comments and to issue a final permit.  Merrimack Station can continue to operate under its current permit pending issuance of the final permit and subsequent resolution of appeals by PSNH and other parties. Due to the site specific characteristics of PSNH's other fossil fueled electric generating stations, we believe it is unlikely that there would be similar permit requirements imposed on them.

Air Quality Requirements

The Clean Air Act Amendments (CAAA), as well as New Hampshire law, impose stringent requirements on emissions of SO₂ and NO_X for the purpose of controlling acid rain and ground level ozone.  In addition, the CAAA address the control of toxic air pollutants.  Requirements for the installation of continuous emissions monitors and expanded permitting provisions also are included.

In December 2011, the EPA finalized the Mercury and Air Toxic Standards (MATS) that require the reduction of emissions of hazardous air pollutants from new and existing coal- and oil-fired electric generating units.  Previously referred to as the Utility MACT (maximum achievable control technology) rules, it establishes emission limits for mercury, arsenic and other hazardous air pollutants from coal and oil-fired units.  MATS is the first implementation of a nationwide emissions standard for hazardous air pollutants across all electric generating units and provides utility companies with up to five years to meet the requirements.  PSNH owns and operates approximately 1,000 MW of fossil fueled electric generating units subject to MATS, including the two units at Merrimack Station, Newington Station and the two coal units at Schiller Station. We believe the Clean Air Project at our Merrimack Station, together with existing equipment, will enable the facility to meet the MATS requirements.  A review of the potential impact of MATS on our other PSNH units is not yet complete.  Additional incremental controls may be required for the two coal fired units at Schiller Station.  To date, the financial impact of this potential control has not been determined.

NU’s carbon emission inventory accounts for and reports all direct carbon dioxide (CO₂) methane (CH₄) nitrous oxide (N₂O) sulfur hexafluoride (SF₆) emissions for operations of NU and its subsidiaries in carbon dioxide equivalents.  Total carbon emissions include those from sources owned or operated by NU (Scope 1) and those that are a consequence of NU’s activities, but occur from sources owned or controlled by others, such as emissions from purchased electricity and line loss during the transmission and distribution of electricity (Scope 2).  NU emissions expressed in thousand metric tons of carbon dioxide equivalent (CO₂-e) for NU and its system companies for 2009 through 2011 are shown below.

	2011	2010	2009
Total CO2-e emissions (excludes CO2  from biomass and biofuels)	2,984	3,976	3,390

Data was collected and calculated using the World Resource Institute greenhouse gas protocol tools except for stationary combustion emissions associated with electric generating units where more accurate Continuous Emissions Monitoring System data was available.  EPA reporting protocol was used for generation calculations where applicable.

Each of the states in which we do business also has Renewable Portfolio Standards (RPS) requirements, which generally require fixed percentages of our energy supply to come from renewable energy sources such as solar, hydropower, landfill gas, fuel cells and other similar sources.  

New Hampshire’s RPS provision requires increasing percentages of the electricity sold to retail customers to have direct ties to renewable sources.  In 2012, the total RPS obligation was 13 percent and it will ultimately reach 26.5 percent in 2025.  Energy suppliers, like PSNH, purchase RECs from producers that generate energy from a qualifying resource and use them to satisfy the RPS requirements.  PSNH also owns renewable sources and uses a portion of internally generated RECs and purchased RECs to meet its RPS obligations.  To the extent that PSNH is unable to purchase sufficient RECs, it makes up the difference between the RECs purchased and its total obligation by making an alternative compliance payment for each REC requirement for which PSNH is deficient.  The costs of both the RECs and alternative compliance payments are recovered by PSNH through its ES rates charged to customers.  

The RECs generated from PSNH’s Northern Wood Power Project, a wood-burning facility, are typically sold to other energy suppliers or load carrying entities and the net proceeds from the sale of these RECs are credited back to customers.

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Similarly, Connecticut's RPS statute requires increasing percentages of the electricity sold to retail customers to have direct ties to renewable sources.  In 2012, the total RPS obligation was 16 percent and will ultimately reach 27 percent in 2020.  CL&P is permitted to recover any costs incurred in complying with RPS from its customers through rates.

Massachusetts’ RPS program also requires electricity suppliers to meet renewable energy standards.  For 2012, the requirement was 16.6 percent, and will ultimately reach 27.1 percent in 2020.  NSTAR Electric and WMECO are permitted to recover any costs incurred in complying with RPS from its customers through rates.  WMECO also owns renewable solar generation resources.  The RECs generated from WMECO’s solar units are sold to other energy suppliers and the proceeds from these sales are credited back to customers.

Hazardous Materials Regulations

Prior to the last quarter of the 20th century when environmental best practices and laws were implemented, utility companies often disposed of residues from operations by depositing or burying them on-site or disposing of them at off-site landfills or other facilities.  Typical materials disposed of include coal gasification byproducts, fuel oils, ash, and other materials that might contain polychlorinated biphenyls or that otherwise might be hazardous.  It has since been determined that deposited or buried wastes, under certain circumstances, could cause groundwater contamination or create other environmental risks.  We have recorded a liability for what we believe, based upon currently available information, is our estimated environmental investigation and/or remediation costs for waste disposal sites for which we expect to bear legal liability.  We continue to evaluate the environmental impact of our former disposal practices.  Under federal and state law, government agencies and private parties can attempt to impose liability on us for these practices.  As of December 31, 2012, the liability recorded by us for our reasonably estimable and probable environmental remediation costs for known sites needing investigation and/or remediation, exclusive of recoveries from insurance or from third parties, was approximately $39.4 million, representing 77 sites.  These costs could be significantly higher if remediation becomes necessary or when additional information as to the extent of contamination becomes available.

The most significant liabilities currently relate to future clean-up costs at former MGP facilities.  These facilities were owned and operated by our predecessor companies from the mid-1800's to mid-1900's.  By-products from the manufacture of gas using coal resulted in fuel oils, hydrocarbons, coal tar, purifier wastes, metals and other waste products that may pose risks to human health and the environment.  We, through our subsidiaries, currently have partial or full ownership responsibilities at former MGP sites that have a reserve balance of $34.5 million of the total $39.4 million as of December 31, 2012.

HWP, a wholly owned subsidiary of NU, is continuing to evaluate additional potential remediation requirements at a river site in Massachusetts containing tar deposits associated with an MGP site that HWP sold to HG&E, a municipal electric utility, in 1902.  HWP is at least partially responsible for this site and has already conducted substantial investigative and remediation activities.  HWP's share of the remediation costs related to this site is not recoverable from customers.

Electric and Magnetic Fields

For more than twenty years, published reports have discussed the possibility of adverse health effects from electric and magnetic fields (EMF) associated with electric transmission and distribution facilities and appliances and wiring in buildings and homes.  Although weak health risk associations reported in some epidemiology studies remain unexplained, most researchers, as well as numerous scientific review panels, considering all significant EMF epidemiology and laboratory studies, have concluded that the available body of scientific information does not support the conclusion that EMF affects human health.

We have closely monitored research and government policy developments for many years and will continue to do so.  In accordance with recommendations of various regulatory bodies and public health organizations, we reduce EMF associated with new transmission lines by the use of designs that can be implemented without additional cost or at a modest cost.  We do not believe that other capital expenditures are appropriate to minimize unsubstantiated risks.

Global Climate Change and Greenhouse Gas Emission Issues

Global climate change and greenhouse gas emission issues have received an increased focus from state governments and the federal government.  The EPA initiated a rulemaking addressing greenhouse gas emissions and, on December 7, 2009, issued a finding that concluded that greenhouse gas emissions are “air pollution” that endanger public health and welfare and should be regulated.  The largest source of greenhouse gas emissions in the U.S. is the electricity generating sector.  The EPA has mandated greenhouse gas emission reporting beginning in 2011 for emissions for certain aspects of our business including stationary combustion, volume of gas supplied to large customers and fugitive emissions of SF₆ gas and methane.

We are continually evaluating the regulatory risks and regulatory uncertainty presented by climate change concerns.  Such concerns could potentially lead to additional rules and regulations that impact how we operate our business, both in terms of the generating facilities we own and operate as well as general utility operations.  These could include federal “cap and trade” laws, carbon taxes, fuel and energy taxes, or regulations requiring additional capital expenditures at our generating facilities.  We expect that any costs of these rules and regulations would be recovered from customers.

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Connecticut, New Hampshire and Massachusetts are each members of the Regional Greenhouse Gas Initiative (RGGI), a cooperative effort by nine northeastern and mid-Atlantic states, to develop a regional program for stabilizing and reducing CO₂ emissions from fossil fueled electric generating plants.  Because CO₂ allowances issued by any participating state are usable across all nine RGGI state programs, the individual state CO₂ trading programs, in the aggregate, form one regional compliance market for CO₂ emissions.  A regulated power plant must hold CO₂ allowances equal to its emissions to demonstrate compliance at the end of a three year compliance period that began in 2012.

PSNH anticipates that its generating units will emit between two million and four million tons of CO₂ per year, depending on the capacity factor and the utilization of the plant, excluding emissions from the operation of PSNH’s Northern Wood Power Project.  New Hampshire legislation provides up to 1.5 million banked CO₂ allowances per year for PSNH’s fossil fueled electric generating plants during the 2012 through 2014 compliance period.  PSNH expects to satisfy its remaining RGGI requirements by purchasing CO₂ allowances at auction or in the secondary market. The cost of complying with RGGI requirements is recoverable from PSNH customers.  Current legislation provides a portion of the RGGI auction proceeds in excess of $1 per allowance will be refunded to customers.

Because none of NU’s other subsidiaries, CL&P, NSTAR Electric or WMECO, currently owns any generating assets (other than two solar photovoltaic facilities owned by WMECO, which do not emit CO₂), none of them is required to acquire CO₂ allowances.  However, the CO₂ allowance costs borne by the generating facilities that are utilized by wholesale suppliers to satisfy energy supply requirements to CL&P, NSTAR Electric and WMECO will likely be included in the overall wholesale rates charged, which costs are then recoverable from customers.

Federal greenhouse gas legislation has stalled under the current administration.  Recently, climate change law has been discussed as an initiative that will be moved forward in the current Congress.  However, even without legislation, we can expect additional regulations from the EPA that could impact NU.  

FERC Hydroelectric Project Licensing

Federal Power Act licenses may be issued for hydroelectric projects for terms of 30 to 50 years as determined by the FERC.  Upon the expiration of an existing license, (i) the FERC may issue a new license to the existing licensee, (ii) the United States may take over the project, or (iii) the FERC may issue a new license to a new licensee, upon payment to the existing licensee of the lesser of the fair value or the net investment in the project, plus severance damages, less certain amounts earned by the licensee in excess of a reasonable rate of return.

PSNH owns nine hydroelectric generating stations with a current claimed capability representing winter rates of approximately 71 MW, eight of which are licensed by the FERC under long-term licenses that expire on varying dates from 2017 through 2047.  PSNH and its hydroelectric projects are subject to conditions set forth in such licenses, the Federal Power Act and related FERC regulations, including provisions related to the condemnation of a project upon payment of just compensation, amortization of project investment from excess project earnings, possible takeover of a project after expiration of its license upon payment of net investment and severance damages and other matters.  PSNH is currently involved with the early stages of relicensing at its Eastman Falls Hydro Station, which is comprised of two units, totaling 6.5 MW.

Licensed operating hydroelectric projects are not generally subject to decommissioning during the license term in the absence of a specific license provision that expressly permits the FERC to order decommissioning during the license term.  However, the FERC has taken the position that under appropriate circumstances it may order decommissioning of hydroelectric projects at relicensing or may require the establishment of decommissioning trust funds as a condition of relicensing.  The FERC may also require project decommissioning during a license term if a hydroelectric project is abandoned, the project license is surrendered or the license is revoked.  PSNH is not presently encountering any of these challenges.

EMPLOYEES

As of December 31, 2012, we employed a total of approximately 8,842 employees, excluding temporary employees, of which 1,787 were employed by CL&P, 1,204 were employed by PSNH, 348 were employed by WMECO, and 1,619 employees employed by NSTAR Electric & Gas Corporation provided services to NSTAR Electric.  Approximately 47.8 percent of our employees are members of the International Brotherhood of Electrical Workers, the Utility Workers Union of America or The United Steelworkers, and are covered by 13 collective bargaining agreements.

INTERNET INFORMATION

Our website address is www.nu.com.  We make available through our website a link to the SEC's EDGAR website (http://www.sec.gov/edgar/searchedgar/companysearch.html), at which site NU's, CL&P's, NSTAR Electric’s, PSNH's and WMECO's Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and any amendments to those reports may be reviewed.  Printed copies of these reports may be obtained free of charge by writing to our Investor Relations Department at Northeast Utilities, 56 Prospect Street, Hartford, CT 06103.

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Item 1A.

Risk Factors

In addition to the matters set forth under “Safe Harbor Statement Under the Private Securities Litigation Reform Act of 1995” included immediately prior to Item 1, Business, above, we are subject to a variety of significant risks.  Our susceptibility to certain risks, including those discussed in detail below, could exacerbate other risks.  These risk factors should be considered carefully in evaluating our risk profile.

The Merger may present certain material risks to the Company’s business and operations.

The Merger, described in Item 1, Business, may present certain risks to our business and operations including, among other things, risks that:

·

We may be unable to successfully integrate the businesses and workforces of NSTAR with our businesses and workforces;

·

Conditions, terms, obligations or restrictions relating to the Merger imposed on us by regulatory authorities may adversely affect our business and operations;

·

We may be unable to avoid potential liabilities and unforeseen increased expenses or delays associated with integration plans;

·

We may be unable to successfully manage the complex integration of systems, technology, networks and other assets in a manner that minimizes any adverse impact on customers, vendors, suppliers, employees and other constituencies;

·

We may experience inconsistencies in each companies’ standards, controls, procedures and policies.

Accordingly, there can be no assurance that the Merger will result in the realization of the full benefits of synergies, innovation and operational efficiencies that we currently expect, that these benefits will be achieved within the anticipated timeframe or that we will be able to fully and accurately measure any such synergies.

Cyber breaches, acts of war or terrorism, or grid disturbances could negatively impact our business.

Cyber intrusions targeting our information systems could impair our ability to properly manage our data, networks, systems and programs, adversely affect our business operations or lead to release of confidential customer information or critical operating information.  While we have implemented measures designed to prevent cyber-attacks and mitigate their effects should they occur, our systems are vulnerable to unauthorized access and cyber intrusions.  We cannot discount the possibility that a security breach may occur or quantify the potential impact of such an event.

Acts of war or terrorism could target our generation, transmission and distribution facilities or our data management systems.  Such actions could impair our ability to manage these facilities or operate our system effectively, resulting in loss of service to customers.  

Because our generation and transmission facilities are part of an interconnected regional grid, we face the risk of blackout due to a disruption on a neighboring interconnected system.  

Any such cyber breaches, acts of war or terrorism, or grid disturbances could result in a significant decrease in revenues, significant expense to repair system damage or security breaches, and liability claims, which could have a material adverse impact on our financial position, results of operations or cash flows.

Our goodwill is valued and recorded at an amount that, if impaired and written down, could adversely affect our future operating results and total capitalization.

We have a significant amount of goodwill on our consolidated balance sheet.  The carrying value of goodwill represents the fair value of an acquired business in excess of identifiable assets and liabilities as of the acquisition date.  As of December 31, 2012, goodwill totaled $3.5 billion, of which $3.2 billion was attributable to the acquisition of NSTAR in April 2012.  Total goodwill represented approximately 38 percent of our $9.2 billion of shareholders’ equity and approximately 12 percent of our total assets of $28.3 billion.  We perform an analysis of our goodwill balances to test for impairment on an annual basis or whenever events occur or circumstances change that would indicate a potential for impairment.  A determination that goodwill is deemed to be impaired would result in a non-cash charge that could materially adversely affect our results of operations and total capitalization.

Severe storms could cause significant damage to our electrical facilities requiring extensive capital expenditures, the recovery for which is subject to approval by regulators.

Severe weather, such as Tropical Storm Irene in August 2011, the October 29, 2011 snowstorm, Hurricane Sandy in October 2012, and the February 2013 blizzard, and other such major natural disasters, could cause widespread damage to our transmission and distribution facilities.  The resulting cost of repairing damage to our facilities and the potential disruption of our operations could exceed our financial reserves and insurance.  

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Tropical Storm Irene, the October 29, 2011 snowstorm, and Hurricane Sandy caused significant damage to our transmission and distribution systems.  As a result, along with previously deferred costs from other storms, we have recorded approximately $548 million (approximately $414 million at CL&P) for estimated restoration costs as regulatory assets as of December 31, 2012, subject to future recovery from customers.  If, upon review, any of our state regulatory authorities finds that our actions were imprudent, some of those restoration costs may not be recoverable from customers.  The inability to recover a significant amount of such costs could have an adverse effect on our financial position, results of operations and cash flows.

NU and its utility subsidiaries are exposed to significant reputational risks, which make them vulnerable to increased regulatory oversight or other sanctions.

Because utility companies, including our electric and natural gas utility subsidiaries, have large consumer customer bases, they are subject to adverse publicity focused on the reliability of their distribution services and the speed with which they are able to respond to electric outages, natural gas leaks and similar interruptions caused by storm damage or other unanticipated events.  Adverse publicity of this nature could harm the reputations of NU and its subsidiaries, and may make state legislatures, utility commissions and other regulatory authorities less likely to view NU and its subsidiaries in a favorable light, and may cause NU and its subsidiaries to be subject to less favorable legislative and regulatory outcomes or increased regulatory oversight.  Unfavorable regulatory outcomes can include more stringent laws and regulations governing our operations, such as reliability and customer service quality standards or vegetation management requirements, as well as fines, penalties or other sanctions or requirements.  The imposition of any of the foregoing could have a material adverse effect on business, results of operations, cash flow and financial condition of NU and each of its utility subsidiaries.

The actions of regulators can significantly affect our earnings, liquidity and business activities.

The rates that our Regulated companies charge their respective retail and wholesale customers are determined by their state utility commissions and by FERC.  These commissions also regulate the companies’ accounting, operations, the issuance of certain securities and certain other matters.  FERC also regulates their transmission of electric energy, the sale of electric energy at wholesale, accounting, issuance of certain securities and certain other matters.  The commissions’ policies and regulatory actions could have a material impact on the Regulated companies’ financial position, results of operations and cash flows.

Our transmission, distribution and generation systems may not operate as expected, and could require unplanned expenditures, which could adversely affect our financial position, results of operations and cash flows.

Our ability to properly operate our transmission, distribution and generation systems is critical to the financial performance of our business.  Our transmission, distribution and generation businesses face several operational risks, including the breakdown or failure of or damage to equipment or processes (especially due to age); labor disputes; disruptions in the delivery of electricity and natural gas, including impacts on us or our customers; increased capital expenditure requirements, including those due to environmental regulation; information security risk, such as a breach of our systems on which sensitive utility customer data and account information are stored; catastrophic events such as fires, explosions, or other similar occurrences; extreme weather conditions beyond equipment and plant design capacity; other unanticipated operations and maintenance expenses and liabilities; and potential claims for property damage or personal injuries beyond the scope of our insurance coverage.  The failure of our transmission, distribution and generation systems to operate as planned may result in increased capital costs, reduced earnings or unplanned increases in operation and maintenance costs.  At PSNH, outages at generating stations may be deemed imprudent by the NHPUC resulting in disallowance of replacement power costs.  Such costs that are not recoverable from our customers would have an adverse effect on our financial position, results of operations and cash flows.

Limits on our access to and increases in the cost of capital may adversely impact our ability to execute our business plan.

We use short-term debt and the long-term capital markets as a significant source of liquidity and funding for capital requirements not obtained from our operating cash flow.  If access to these sources of liquidity becomes constrained, our ability to implement our business strategy could be adversely affected.  In addition, higher interest rates would increase our cost of borrowing, which could adversely impact our results of operations.  A downgrade of our credit ratings or events beyond our control, such as a disruption in global capital and credit markets, could increase our cost of borrowing and cost of capital or restrict our ability to access the capital markets and negatively affect our ability to maintain and to expand our businesses.

Our counterparties may not meet their obligations to us or may elect to exercise their termination rights, which could adversely affect our earnings.

We are exposed to the risk that counterparties to various arrangements who owe us money, have contracted to supply us with energy, coal, or other commodities or services, or who work with us as strategic partners, including on significant capital projects, will not be able to perform their obligations, will terminate such arrangements or, with respect to our credit facilities, fail to honor their commitments.  Should any of these counterparties fail to perform their obligations or terminate such arrangements, we might be forced to replace the underlying commitment at higher market prices and/or have to delay the completion of, or cancel a capital project.  Should any lenders under our credit facilities fail to perform, the level of borrowing capacity under those arrangements could decrease. In any such events, our financial position, results of operations, or cash flows could be adversely affected.

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Difficulties in obtaining necessary rights of way, or siting, design or other approvals for major transmission projects, environmental concerns or actions of regulatory authorities, communities or strategic partners may cause delays or cancellation of such projects, which would adversely affect our earnings.

Various factors could result in increased costs or result in delays or cancellation of our transmission projects. These include the regulatory approval process, environmental and community concerns, design and siting issues, difficulties in obtaining required rights of way and actions of strategic partners.  Should any of these factors result in such delays or cancellations, our financial position, results of operations, and cash flows could be adversely affected.

Economic events or factors, changes in regulatory or legislative policy and/or regulatory decisions or construction of new generation may delay completion of or displace or result in the abandonment of our planned transmission projects or adversely affect our ability to recover our investments or result in lower than expected earnings.

Our transmission construction plans could be adversely affected by economic events or factors, new legislation, regulations, or judicial or regulatory interpretations of applicable law or regulations or regulatory decisions.  Any of such events could cause delays in, or the inability to complete or abandonment of, economic or reliability related projects, which could adversely affect our ability to achieve forecasted earnings or to recover our investments or result in lower than expected rates of return.  Recoverability of all such investments in rates may be subject to prudence review at the FERC.  While we believe that all of such costs have been and will be prudently incurred, we cannot predict the outcome of future reviews should they occur.

In addition, our transmission projects may be delayed or displaced by new generation facilities, which could result in reduced transmission capital investments, reduced earnings, and limited future growth prospects.

Many of our transmission projects are expected to help alleviate identified reliability issues and reduce customers' costs.  However, if, due to economic events or factors or further regulatory or other delays, the in-service date for one or more of these projects is delayed, there may be increased risk of failures in the electricity transmission system and supply interruptions or blackouts, which could have an adverse effect on our earnings.

The FERC has followed a policy of providing incentives designed to encourage the construction of new transmission facilities, including higher returns on equity and allowing facilities under construction to be placed in rate base.  Our projected earnings and growth could be adversely affected were FERC to reduce these incentives in the future below the levels presently anticipated.

Increases in electric and gas prices and/or a weak economy, can lead to changes in legislative and regulatory policy promoting energy efficiency, conservation, and self-generation and/or a reduction in our customers’ ability to pay their bills, which may adversely impact our business.

Energy consumption is significantly impacted by the general level of economic activity and cost of energy supply.  Economic downturns or periods of high energy supply costs typically can lead to the development of legislative and regulatory policy designed to promote reductions in energy consumption and increased energy efficiency and self-generation by customers.  This focus on conservation, energy efficiency and self-generation may result in a decline in electricity and gas sales in our service territories.  If any such declines were to occur without corresponding adjustments in rates, then our revenues would be reduced and our future growth prospects would be limited.

In addition, a period of prolonged economic weakness could impact customers’ ability to pay bills in a timely manner and increase customer bankruptcies, which may lead to increased bad debt expenses or other adverse effects on our financial position, results of operations or cash flows.

Changes in regulatory and/or legislative policy could negatively impact our transmission planning and cost allocation rules.

The existing FERC-approved New England transmission tariff allocates the costs of transmission facilities that provide regional benefits to all customers of participating transmission-owning utilities.  As new investment in regional transmission infrastructure occurs in any one state, its cost is shared across New England in accordance with a FERC approved formula found in the transmission tariff.  All New England transmission owners' agreement to this regional cost allocation is set forth in the Transmission Operating Agreement.  This agreement can be modified with the approval of a majority of the transmission owning utilities and approval by FERC.  In addition, other parties, such as state regulators, may seek certain changes to the regional cost allocation formula, which could have adverse effects on the rates our distribution companies charge their retail customers.  

FERC has issued rules requiring all regional transmission organizations and transmission owning utilities to make compliance changes to their tariffs and contracts in order to further encourage the construction of transmission for generation, including renewable generation.  This compliance will require ISO-NE and New England transmission owners to develop methodologies that allow for regional planning and cost allocation for transmission projects chosen in the regional plan that are designed to meet public policy goals such as reducing greenhouse gas emissions or encouraging renewable generation. Such compliance may also allow non-incumbent utilities and other entities to participate in the planning and construction of new projects in our service area and regionally.

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Changes in the Transmission Operating Agreement, the New England Transmission Tariff or legislative policy, or implementation of these new FERC planning rules, could adversely affect our transmission planning, our earnings and our prospects for growth.

Changes in regulatory or legislative policy or unfavorable outcomes in regulatory proceedings could jeopardize our full and/or timely recovery of costs incurred by our regulated distribution and generation businesses.

Under state law, our Regulated companies are entitled to charge rates that are sufficient to allow them an opportunity to recover their reasonable operating and capital costs, to attract needed capital and maintain their financial integrity, while also protecting relevant public interests.  Each of these companies prepares and submits periodic rate filings with their respective state regulatory commissions for review and approval.  There is no assurance that these state commissions will approve the recovery of all such costs incurred by our Regulated companies, such as for construction, operation and maintenance, as well as a return on investment on their respective regulated assets, including the construction costs incurred by PSNH for the Clean Air Project at its Merrimack Station.  PSNH’s expenditures for the project are subject to prudence review by the NHPUC.  The amount of costs incurred by the Regulated companies, coupled with increases in fuel and energy prices, could lead to consumer or regulatory resistance to the timely recovery of such costs, thereby adversely affecting our financial position, results of operations or cash flows.  

Additionally, state legislators may enact laws that significantly impact our Regulated companies’ revenues, including by mandating electric or gas rate relief and/or by requiring surcharges to customer bills to support state programs not related to the utilities or energy policy.  Such increases could pressure overall rates to our customers and our routine requests to regulators for rate relief.

In addition, CL&P, NSTAR Electric and WMECO procure energy for a substantial portion of their customers’ needs via requests for proposal on an annual, semi-annual or quarterly basis.  CL&P, NSTAR Electric and WMECO receive approval to recover the costs of these contracts from the PURA and DPU, respectively.  While both regulatory agencies have consistently approved the solicitation processes, results and recovery of costs, management cannot predict the outcome of future solicitation efforts or the regulatory proceedings related thereto.

PSNH meets most of its energy requirements through its own generation resources and fixed-price forward purchase contracts.  PSNH’s remaining energy needs are met primarily through spot market purchases.  Unplanned forced outages of its generating plants could increase the level of energy purchases needed by PSNH and therefore increase the market risk associated with procuring the energy to meet its requirements.  PSNH recovers these costs through its ES rate, subject to a prudence review by the NHPUC.  We cannot predict the outcome of future regulatory proceedings related to recovery of these costs.

Migration of customers from PSNH energy service to competitive energy suppliers may increase the cost to the remaining customers of energy produced by PSNH generation assets.

The competitiveness of PSNH’s ES rates are sensitive to the cost of fuels, most notably natural gas, and customer load.  Recently, PSNH’s ES rate has been higher than competitive energy prices offered to some customers. Further increases may occur as the costs associated with the Clean Air Project are fully phased into rates. Customers remaining on PSNH’s ES rate may experience an increase in cost due to the lower base over which to recover PSNH's fixed generation costs. Any such increase may in turn cause further migration and further impact PSNH’s ES rate.  This trend could lead to PSNH continuing to lose retail customers and increasing the burden of supporting the cost of its generation facilities on remaining customers and being unable to support the cost of its generation facilities through an ES rate.

Judicial or regulatory proceedings or changes in regulatory or legislative policy could jeopardize full recovery of costs incurred by PSNH in constructing the Clean Air Project.

Pursuant to New Hampshire law, PSNH placed the Clean Air Project in service at its Merrimack Station in Bow, New Hampshire. PSNH’s recovery of costs in constructing the project is subject to prudence review by the NHPUC.  A material prudence disallowance could adversely affect PSNH’s financial position, results of operations or cash flows.  While we believe we have prudently incurred all expenditures to date, we cannot predict the outcome of any prudence reviews.  Our projected earnings and growth could be adversely affected were the NHPUC to deny recovery of some or all of PSNH’s investment in the project.

The loss of key personnel or the inability to hire and retain qualified employees could have an adverse effect on our business, financial position and results of operations.

Our operations depend on the continued efforts of our employees.  Retaining key employees and maintaining the ability to attract new employees are important to both our operational and financial performance.  We cannot guarantee that any member of our management or any key employee at the NU parent or subsidiary level will continue to serve in any capacity for any particular period of time.  In addition, a significant portion of our workforce, including many workers with specialized skills maintaining and servicing the electrical infrastructure, will be eligible to retire over the next five to ten years.  Such highly skilled individuals cannot be quickly replaced due to the technically complex work they perform.  We have developed strategic workforce plans to identify key functions and proactively implement plans to assure a ready and qualified workforce, but cannot predict the impact of these plans on our ability to hire and retain key employees.

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Market performance or changes in assumptions require us to make significant contributions to our pension and other post-employment benefit plans.

We provide a defined benefit pension plan and other post-retirement benefits for a substantial number of employees, former employees and retirees.  Our future pension obligations, costs and liabilities are highly dependent on a variety of factors beyond our control.  These factors include estimated investment returns, interest rates, discount rates, health care cost trends, benefit changes, salary increases and the demographics of plan participants.  If our assumptions prove to be inaccurate, our future costs could increase significantly.  In 2008 and 2009, due to the financial crisis, the value of our pension assets declined.  As a result, we made a contribution of approximately $222 million in 2012 and expect to make an approximate $285 million contribution in 2013.  In addition, various factors, including underperformance of plan investments and changes in law or regulation, could increase the amount of contributions required to fund our pension plan in the future.  Additional large funding requirements, when combined with the financing requirements of our construction program, could impact the timing and amount of future equity and debt financings and negatively affect our financial position, results of operations or cash flows.  

Costs of compliance with environmental regulations, including climate change legislation, may increase and have an adverse effect on our business and results of operations.

Our subsidiaries' operations are subject to extensive federal, state and local environmental statutes, rules and regulations that govern, among other things, air emissions, water discharges and the management of hazardous and solid waste.  Compliance with these requirements requires us to incur significant costs relating to environmental monitoring, installation of pollution control equipment, emission fees, maintenance and upgrading of facilities, remediation and permitting.  The costs of compliance with existing legal requirements or legal requirements not yet adopted may increase in the future.  An increase in such costs, unless promptly recovered, could have an adverse impact on our business and our financial position, results of operations or cash flows.

In addition, global climate change issues have received an increased focus from federal and state governments, which could potentially lead to additional rules and regulations that impact how we operate our business, both in terms of the power plants we own and operate as well as general utility operations.  Although we would expect that any costs of these rules and regulations would be recovered from customers, their impact on energy use by customers and the ultimate impact on our business would be dependent upon the specific rules and regulations adopted and cannot be determined at this time.  The impact of these additional costs to customers could lead to a further reduction in energy consumption resulting in a decline in electricity and gas sales in our service territories, which would have an adverse impact on our business and financial position, results of operations or cash flows.

Any failure by us to comply with environmental laws and regulations, even if due to factors beyond our control, or reinterpretations of existing requirements, could also increase costs.  Existing environmental laws and regulations may be revised or new laws and regulations seeking to protect the environment may be adopted or become applicable to us.  Revised or additional laws could result in significant additional expense and operating restrictions on our facilities or increased compliance costs, which may not be fully recoverable in distribution company rates.  The cost impact of any such laws, rules or regulations would be dependent upon the specific requirements adopted and cannot be determined at this time.  For further information, see Item 1, Business - Other Regulatory and Environmental Matters, included in this Annual Report on Form 10-K.

As a holding company with no revenue-generating operations, NU parent’s liquidity is dependent on dividends from its subsidiaries, primarily the Regulated companies, its commercial paper program, and its ability to access the long-term debt and equity capital markets.

NU parent is a holding company and as such, has no revenue-generating operations of its own.  Its ability to meet its debt service obligations and to pay dividends on its common shares is largely dependent on the ability of its subsidiaries to pay dividends to or repay borrowings from NU parent, and/or NU parent’s ability to access its commercial paper program or the long-term debt and equity capital markets.  Prior to funding NU parent, the Regulated companies have financial obligations that must be satisfied, including among others, their operating expenses, debt service, preferred dividends (in the case of CL&P and NSTAR Electric), and obligations to trade creditors.  Additionally, the Regulated companies could retain their free cash flow to fund their capital expenditures in lieu of receiving equity contributions from NU parent.  Should the Regulated companies not be able to pay dividends or repay funds due to NU parent, or if NU parent cannot access its commercial paper programs or the long-term debt and equity capital markets, NU parent’s ability to pay interest, dividends and its own debt obligations would be restricted.

Item 1B.

Unresolved Staff Comments

We do not have any unresolved SEC staff comments.  

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Item 2. Properties
Transmission and Distribution System
As of December 31, 2012, NU and our electric operating subsidiaries owned the following:
	Electric	Electric
NU	Distribution	Transmission
Number of substations owned	557	60
Transformer capacity (in kVa)	41,504,000	17,827,000
Overhead lines (distribution in pole miles and
transmission in circuit miles)	51,988	3,835
Capacity range of overhead transmission lines (in kV)		69 to 345
Underground lines (distribution in conduit bank miles and
transmission in cable miles)	12,656	677
Capacity range of underground transmission lines (in kV)		69 to 345

		CL&P		NSTAR Electric		PSNH		WMECO
		Distribution	Transmission	Distribution	Transmission	Distribution	Transmission	Distribution	Transmission
Number of substations owned		212	19	138	20	163	13	44	8
Transformer capacity (in kVa)		18,487,000	3,117,000	11,374,000	9,575,000	7,626,000	3,868,000	4,017,000	1,267,000
Overhead lines (distribution in
	pole miles and transmission
	in circuit miles)	18,375	1,625	16,570	708	13,253	1,010	3,790	492
Capacity range of overhead
	transmission lines (in kV)		69 to 345		115 to 345		115 to 345		69 to 345
Underground lines (distribution
	in conduit bank miles and
	transmission in cable miles)	1,154	403	9,508	243	1,704	1	290	30
Capacity range of underground
	transmission lines (in kV)		69 to 345		115 to 345		115		115

				NSTAR
		NU	CL&P	Electric	PSNH	WMECO
Underground and overhead
	line transformers in service	683,514	337,727	130,787	167,523	47,477
Aggregate capacity (in kVa)		49,357,003	28,398,407	10,111,403	6,995,487	3,851,706

Electric Generating Plants

As of December 31, 2012, PSNH owned the following electric generating plants:  

Type of Plant	Number of Units	Year Installed	Claimed Capability* (kilowatts)
Total - Fossil-Steam Plants	5 units	1952-74	935,343
Total - Hydro	20 units	1901-83	68,994
Total - Internal Combustion	5 units	1968-70	101,869
Total - Biomass - Steam Plant	1 unit	1954-2006	42,594
Total PSNH Generating Plant	31 units		1,148,800

*

Claimed capability represents winter ratings as of December 31, 2012.  The combined nameplate capacity of the generating plants is approximately 1,200 MW.

As of December 31, 2012, WMECO owned the following electric generating plant:  

Type of Plant	Number of Sites	Year Installed	Claimed Capability** (kilowatts)
Total - Solar Fixed Tilt, Photovoltaic	2 sites	2010-11	4,100

** Claimed capability represents the direct current nameplate capacity of the plant.

CL&P did not own any electric generating plants during 2012.

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Natural Gas Distribution System

As of December 31, 2012, Yankee Gas owned 28 active gate stations, 203 district regulator stations, and 3,265 miles of natural gas main pipeline.  Yankee Gas also owns a 1.2 Bcf LNG facility in Waterbury, Connecticut.  

As of December 31, 2012, NSTAR Gas owned 21 active gate stations, 145 district regulator stations, and 3,185 miles of natural gas main pipeline.  NSTAR Gas and Hopkinton own a satellite vaporization plant and above ground cryogenic storage tanks.  In addition, Hopkinton owns a liquefaction and vaporization plant.  Combined, the tanks have an aggregate storage capacity equivalent to 3.5 Bcf of natural gas.

Franchises

CL&P.  Subject to the power of alteration, amendment or repeal by the General Assembly of Connecticut and subject to certain approvals, permits and consents of public authority and others prescribed by statute, CL&P has, subject to certain exceptions not deemed material, valid franchises free from burdensome restrictions to provide electric transmission and distribution services in the respective areas in which it is now supplying such service.

In addition to the right to provide electric transmission and distribution services as set forth above, the franchises of CL&P include, among others, limited rights and powers, as set forth under Connecticut law and the special acts of the General Assembly constituting its charter, to manufacture, generate, purchase and/or sell electricity at retail, including to provide Standard Service, Supplier of Last Resort service and backup service, to sell electricity at wholesale and to erect and maintain certain facilities on public highways and grounds, all subject to such consents and approvals of public authority and others as may be required by law. The franchises of CL&P include the power of eminent domain.  Connecticut law prohibits an electric distribution company from owning or operating generation assets.  However, under "An Act Concerning Energy Independence," enacted in 2005, CL&P is permitted to own up to 200 MW of peaking facilities if the PURA determines that such facilities will be more cost effective than other options for mitigating FMCC and Locational Installed Capacity (LICAP) costs.  In addition, under "An Act Concerning Electricity and Energy Efficiency," enacted in 2007, an electric distribution company, such as CL&P, is permitted to purchase an existing electric generating plant located in Connecticut that is offered for sale, subject to prior approval from the PURA and a determination by the PURA that such purchase is in the public interest.  Finally, Connecticut law also allows CL&P to submit a proposal to the DEEP to build, own or operate one or more generation facilities up to 10 MWs using Class 1 renewable energy.

NSTAR ELECTRIC AND NSTAR GAS.  Through their charters, which are unlimited in time, NSTAR Electric and NSTAR Gas have the right to engage in the business of delivering and selling electricity and natural gas within their respective service territories, and have powers incidental thereto and are entitled to all the rights and privileges of and subject to the duties imposed upon electric and natural gas companies under Massachusetts laws.  The locations in public ways for electric transmission and distribution lines and gas distribution pipelines are obtained from municipal and other state authorities who, in granting these locations, act as agents for the state. In some cases the actions of these authorities are subject to appeal to the DPU.  The rights to these locations are not limited in time and are subject to the action of these authorities and the legislature.  Under Massachusetts law, with the exception of municipal-owned utilities, no other entity may provide electric or gas delivery service to retail customers within NSTAR’s service territory without the written consent of NSTAR Electric and/or NSTAR Gas. This consent must be filed with the DPU and the municipality so affected.

The Massachusetts restructuring legislation defines service territories as those territories actually served on July 1, 1997 and following municipal boundaries to the extent possible.  The restructuring legislation further provides that until terminated by law or otherwise, distribution companies shall have the exclusive obligation to serve all retail customers within their service territories and no other person shall provide distribution service within such service territories without the written consent of such distribution companies.  Pursuant to the Massachusetts restructuring legislation, the DPU (then, the Department of Telecommunications and Energy) was required to define service territories for each distribution company, including NSTAR Electric.  The DPU subsequently determined that there were advantages to the exclusivity of service territories and issued a report to the Massachusetts Legislature recommending against, in this regard, any changes to the restructuring legislation.

PSNH.  The NHPUC, pursuant to statutory requirements, has issued orders granting PSNH exclusive franchises to distribute electricity in the respective areas in which it is now supplying such service.  

In addition to the right to distribute electricity as set forth above, the franchises of PSNH include, among others, rights and powers to manufacture, generate, purchase, and transmit electricity, to sell electricity at wholesale to other utility companies and municipalities and to erect and maintain certain facilities on certain public highways and grounds, all subject to such consents and approvals of public authority and others as may be required by law.  PSNH’s status as a public utility gives it the ability to petition the NHPUC for the right to exercise eminent domain for its transmission and distribution services in appropriate circumstances.  

PSNH is also subject to certain regulatory oversight by the Maine Public Utilities Commission and the Vermont Public Service Board.

WMECO.  WMECO is authorized by its charter to conduct its electric business in the territories served by it, and has locations in the public highways for transmission and distribution lines.  Such locations are granted pursuant to the laws of Massachusetts by the Department of Public Works of Massachusetts or local municipal authorities and are of unlimited duration, but the rights thereby granted are not vested.  Such locations are for specific lines only and for extensions of lines in public highways.  Further similar locations must

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be obtained from the Department of Public Works of Massachusetts or the local municipal authorities.  In addition, WMECO has been granted easements for its lines in the Massachusetts Turnpike by the Massachusetts Turnpike Authority and pursuant to state laws, has the power of eminent domain.  

The Massachusetts restructuring legislation applicable to NSTAR Electric (described above) is also applicable to WMECO.

Yankee Gas.  Yankee Gas holds valid franchises to sell gas in the areas in which Yankee Gas supplies gas service, which it acquired either directly or from its predecessors in interest.  Generally, Yankee Gas holds franchises to serve customers in areas designated by those franchises as well as in most other areas throughout Connecticut so long as those areas are not occupied and served by another gas utility under a valid franchise of its own or are not subject to an exclusive franchise of another gas utility.  Yankee Gas’ franchises are perpetual but remain subject to the power of alteration, amendment or repeal by the General Assembly of the State of Connecticut, the power of revocation by the PURA and certain approvals, permits and consents of public authorities and others prescribed by statute.  Generally, Yankee Gas’ franchises include, among other rights and powers, the right and power to manufacture, generate, purchase, transmit and distribute gas and to erect and maintain certain facilities on public highways and grounds, and the right of eminent domain, all subject to such consents and approvals of public authorities and others as may be required by law.

Item 3.

Legal Proceedings

1.

Yankee Companies v. U.S. Department of Energy

In 1998, the Yankee Companies (CYAPC, YAEC and MYAPC) filed separate complaints against the DOE in the Court of Federal Claims seeking monetary damages resulting from the DOE's failure to begin accepting spent nuclear fuel for disposal by January 31, 1998 pursuant to the terms of the 1983 spent fuel and high level waste disposal contracts between the Yankee Companies and the DOE (DOE Phase I Damages).  In a ruling released on October 4, 2006, the Court of Federal Claims held that the DOE was liable for damages to CYAPC for $34.2 million through 2001, YAEC for $32.9 million through 2001 and MYAPC for $75.8 million through 2002.  

In December 2006, the DOE appealed the ruling, and the Yankee Companies filed cross-appeals.  The Court of Appeals issued its decision on August 7, 2008, effectively agreeing with the trial court's findings as to the liability of the DOE but disagreeing with the method that the trial court used to calculate damages.  The Court of Appeals vacated the decision and remanded the case for new findings consistent with its decision.  

On September 7, 2010, the trial court issued its decision following remand, and judgment on the decision was entered on September 9, 2010.  The judgment awarded CYAPC $39.7 million, YAEC $21.2 million and MYAPC $81.7 million.  The DOE filed an appeal and the Yankee Companies cross-appealed on November 8, 2010.  Briefs were filed and oral arguments in the appeal of the remanded case occurred on November 7, 2011.  On May 18, 2012, the U.S. Court of Appeals for the Federal Circuit issued a unanimous panel decision in favor of the Yankee Companies upholding the trial court's awards to each company in the remanded cases, and increasing YAEC damages by approximately $17 million to cover certain wet pool operating expenses.  On August 1, 2012, the DOE filed a petition asking the U.S. Court of Appeals for the Federal Circuit to reconsider its unanimous panel decision in favor of the Yankee Companies upholding the trial court's awards to each company in the remanded cases.  On September 5, 2012, the U.S. Court of Appeals for the Federal Circuit denied the DOE’s petition.  The decisions became final and non-appealable and interest on the judgments began to accrue on or about December 5, 2012, as the DOE elected not to file a petition for certiorari with the U.S. Supreme Court.  In late January 2013, the proceeds from the DOE Phase 1 Damages claim were received by CYAPC, in the amount of $39.6 million; YAEC, in the amount of $38.3 million; and MYAPC, in the amount of $81.7 million.  The funds were transferred to each Yankee Company’s respective decommissioning trust.  The final application of the proceeds for the benefit of customers of CL&P, NSTAR Electric, PSNH and WMECO will be determined following rate proceedings to be filed by the Yankee Companies at FERC in the second quarter of 2013.  Final FERC determinations are expected by the end of the third quarter of 2013.

In December 2007, the Yankee Companies each filed subsequent lawsuits against the DOE seeking recovery of actual damages incurred in the years following 2001 and 2002 related to the alleged failure of the DOE to provide for a permanent facility to store spent nuclear fuel generated in years after 2001 for CYAPC and YAEC and after 2002 for MYAPC (DOE Phase II Damages).  On November 18, 2011, the court ordered the record closed in the YAEC case, and closed the record in the CYAPC and MYAPC cases subject to a limited opportunity of the government to reopen the records for further limited proceedings.  The record is now closed, all post-trial briefing has been completed, and the case is awaiting the court decision.

The methodology for applying any DOE Phase II Damages that may be recovered from the DOE for the benefit of customers of CL&P, NSTAR Electric, PSNH and WMECO will be addressed in the same FERC rate proceedings.

2.

Conservation Law Foundation v. PSNH

On July 21, 2011, the Conservation Law Foundation (CLF) filed a citizens suit under the provisions of the federal Clean Air Act against PSNH alleging permitting violations at the company’s Merrimack generating station.  The suit alleges that PSNH failed to have proper permits for replacement of the Unit 2 turbine at Merrimack, installation of activated carbon injection equipment for the unit, and violated a permit condition concerning operation of the electrostatic precipitators at the station.  The suit seeks injunctive relief, civil penalties, and costs.  CLF has pursued similar claims before the NHPUC, the N.H. Air Resources Council, and the N.H. Site Evaluation Committee, all of which have been denied.  PSNH believes this suit is without merit and intends to defend it vigorously.  On

26

September 27, 2012, the federal court dismissed portions of CLF’s suit pertaining to the installation of activated carbon injection and the electrostatic precipitators.  An additional motion to dismiss the remaining counts is still pending.

3.

Other Legal Proceedings

For further discussion of legal proceedings, see Item 1, Business:  "- Electric Distribution Segment," "- Natural Gas Distribution Segment" and  "- Electric Transmission Segment," for information about various state regulatory and rate proceedings, civil lawsuits related thereto, and information about proceedings relating to power, transmission and pricing issues; "- Nuclear Decommissioning" for information related to high-level nuclear waste; and "- Other Regulatory and Environmental Matters" for information about proceedings involving surface water and air quality requirements, toxic substances and hazardous waste, electric and magnetic fields, licensing of hydroelectric projects, and other matters. In addition, see Item 1A, Risk Factors, for general information about several significant risks.

EXECUTIVE OFFICERS OF THE REGISTRANT

The following table sets forth the executive officers of NU as of February 15, 2013.  All of the Company’s officers serve terms of one year and until their successors are elected and qualified:

Name	Age	Title
Jay S. Buth	43	Vice President, Controller and Chief Accounting Officer.
Gregory B. Butler	55	Senior Vice President, General Counsel and Secretary.
Christine M. Carmody*	50	Senior Vice President-Human Resources of NUSCO and NSTAR Electric & Gas.
James J. Judge	57	Executive Vice President and Chief Financial Officer.
Thomas J. May	65	President and Chief Executive Officer.
David R. McHale	52	Executive Vice President and Chief Administrative Officer.
Joseph R. Nolan, Jr.*	49	Senior Vice President-Corporate Relations of NUSCO and NSTAR Electric & Gas.
Leon J. Olivier	64	Executive Vice President and Chief Operating Officer.

* Deemed an executive officer of NU pursuant to Rule 3b-7 under the Securities Exchange Act of 1934.

Jay S. Buth.  Mr. Buth became Vice President, Controller and Chief Accounting Officer of NU, CL&P, NSTAR Electric, NSTAR Gas, PSNH, WMECO, Yankee Gas, NUSCO and NSTAR Electric & Gas upon completion of the Merger.  Previously, Mr. Buth was Vice President-Accounting and Controller of NU, CL&P, PSNH, WMECO, Yankee Gas and NUSCO from June 2009 through the completion of the Merger.  From June 2006 through January 2009, Mr. Buth was the Vice President and Controller for New Jersey Resources Corporation, an energy services holding company that provides natural gas and wholesale energy services, including transportation, distribution and asset management.

Gregory B. Butler.  Mr. Butler became Senior Vice President, General Counsel and Secretary of NU and Senior Vice President and General Counsel of NSTAR Electric, NSTAR Gas and NSTAR Electric & Gas upon completion of the Merger.  He has served as Senior Vice President and General Counsel of CL&P, PSNH, WMECO, Yankee Gas and NUSCO since March 9, 2006.  Mr. Butler was elected a Director of NSTAR Electric, NSTAR Gas and NSTAR Electric & Gas upon completion of the Merger.  He has served as a Director of NUSCO since November 27, 2012, and of CL&P, PSNH, WMECO and Yankee Gas since April 22, 2009.  Previously Mr. Butler served as Senior Vice President and General Counsel of NU from December 1, 2005 to April 2012.  Mr. Butler became a Trustee of the NSTAR Foundation effective upon completion of the Merger.  He has served as a Director of Northeast Utilities Foundation, Inc. since December 1, 2002.  

Christine M. Carmody.  Ms. Carmody became Senior Vice President-Human Resources of NUSCO upon completion of the Merger and of CL&P, PSNH, WMECO and Yankee Gas effective November 27, 2012.  She has served as Senior Vice President-Human Resources of NSTAR Electric, NSTAR Gas and NSTAR Electric & Gas since August 1, 2008.  Ms. Carmody was elected a Director of CL&P, PSNH, WMECO and Yankee Gas upon completion of the Merger, and of NSTAR Electric, NSTAR Gas, NUSCO and NSTAR Electric & Gas effective November 27, 2012.  Previously, Ms. Carmody served as Vice President-Organizational Effectiveness of NSTAR, NSTAR Electric, NSTAR Gas and NSTAR Electric & Gas from June 2006 to August 2008.  Ms. Carmody became a Director of Northeast Utilities Foundation, Inc. effective upon completion of the Merger.  She has served as a Trustee of the NSTAR Foundation since August 1, 2008.

James J. Judge.  Mr. Judge became Executive Vice President and Chief Financial Officer of NU, CL&P, NSTAR Electric, NSTAR Gas, PSNH, WMECO, Yankee Gas, NUSCO and NSTAR Electric & Gas upon completion of the Merger.  Mr. Judge was elected a Director of CL&P, PSNH, WMECO, Yankee Gas and NUSCO upon completion of the Merger.  He has served as a Director of NSTAR Electric, NSTAR Gas and NSTAR Electric & Gas since September 27, 1999.  Previously, Mr. Judge served as Senior Vice President and Chief Financial Officer of NSTAR, NSTAR Electric, NSTAR Gas and NSTAR Electric & Gas from 1999 until April 2012.  Mr. Judge became Treasurer and a Director of Northeast Utilities Foundation, Inc. effective upon completion of the Merger.  He has served as a Trustee of the NSTAR Foundation since December 12, 1995.  

Thomas J. May.  Mr. May became President and Chief Executive Officer and a Trustee of NU, Chairman and a Director of CL&P, NSTAR Electric, NSTAR Gas, PSNH, WMECO and Yankee Gas, and Chairman, President and Chief Executive Officer and a Director

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of NUSCO upon completion of the Merger.  He has been President and Chief Executive Officer of NSTAR Electric & Gas since January 1, 2002.  Mr. May has served as a Director of NSTAR Electric, NSTAR Gas and NSTAR Electric & Gas (or their predecessor companies) since September 27, 1999.  Previously, Mr. May served as Chairman, President and Chief Executive Officer and a Trustee of NSTAR, and as Chairman, President and Chief Executive Officer of NSTAR Electric, NSTAR Gas and NSTAR Electric & Gas until the closing of the Merger.  He served as Chairman, Chief Executive Officer and a Trustee since NSTAR was formed in 1999, and was elected President in 2002.  Mr. May became a Director of Northeast Utilities Foundation, Inc. upon completion of the Merger.  He has served as a Trustee of the NSTAR Foundation since August 18, 1987.  

David R. McHale.  Mr. McHale became Executive Vice President and Chief Administrative Officer of NU, CL&P, NSTAR Electric, NSTAR Gas, PSNH, WMECO, Yankee Gas, NUSCO and NSTAR Electric & Gas upon completion of the Merger.  Mr. McHale has served as a Director of NSTAR Electric, NSTAR Gas and NSTAR Electric & Gas since November 27, 2012, of PSNH, WMECO, Yankee Gas and NUSCO since January 1, 2005, and of CL&P since January 15, 2007.  Previously, Mr. McHale served as Executive Vice President and Chief Financial Officer of NU, CL&P, PSNH, WMECO, Yankee Gas and NUSCO from January 2009 to April 2012, and Senior Vice President and Chief Financial Officer of NU, CL&P, PSNH, WMECO, Yankee Gas and NUSCO from January 2005 to December 2008.  Mr. McHale became a Trustee of the NSTAR Foundation upon completion of the Merger.  He has served as a Director of Northeast Utilities Foundation, Inc. since January 1, 2005.

Joseph R. Nolan, Jr.  Mr. Nolan became Senior Vice President-Corporate Relations of NUSCO, NSTAR Electric & Gas, NSTAR Electric and NSTAR Gas upon completion of the Merger.  He became Senior Vice President-Corporate Relations of CL&P, PSNH, WMECO and Yankee Gas effective November 27, 2012.  Mr. Nolan was elected a Director of CL&P, PSNH, WMECO and Yankee Gas upon completion of the Merger, and of NSTAR Electric, NSTAR Gas, NUSCO and NSTAR Electric & Gas effective November 27, 2012.  Previously, Mr. Nolan served as Senior Vice President-Customer & Corporate Relations of NSTAR, NSTAR Electric, NSTAR Gas and NSTAR Electric and Gas from 2006 until the closing of the Merger.  Mr. Nolan became a Director of Northeast Utilities Foundation, Inc. upon completion of the Merger.  He has served as a Trustee of the NSTAR Foundation since October 1, 2000.  

Leon J. Olivier.  Mr. Olivier has served as Executive Vice President and Chief Operating Officer of NU and NUSCO since May 13, 2008, and of NSTAR Electric & Gas since the completion of the Merger.  He became Chief Executive Officer of NSTAR Electric and NSTAR Gas upon completion of the Merger.  Mr. Olivier has served as Chief Executive Officer of CL&P, PSNH, WMECO and Yankee Gas since January 15, 2007.  Mr. Olivier was elected a Director of NSTAR Electric, NSTAR Gas and NSTAR Electric & Gas effective November 27, 2012, of PSNH, WMECO and Yankee Gas effective January 17, 2005, and of CL&P effective September 10, 2001.  Previously, Mr. Olivier served as Executive Vice President-Operations of NU from February 13, 2007 to May 12, 2008.  Mr. Olivier became a Trustee of the NSTAR Foundation upon completion of the Merger.  He has served as a Director of Northeast Utilities Foundation, Inc. since April 1, 2006.  

Item 4.

Mine Safety Disclosures

Not applicable.

PART II

Item 5.

Market for the Registrants' Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

(a)

Market Information and (c) Dividends

NU.  Our common shares are listed on the New York Stock Exchange.  The ticker symbol is "NU," although it is frequently presented as "Noeast Util" and/or "NE Util" in various financial publications.  The high and low sales prices of our common shares and the dividends declared, for the past two years, by quarter, are shown below.

Year	Quarter	High		Low		Dividends Declared
2012	First	$	37.64	$	33.48	$	0.294
	Second		39.09		34.84		0.343
	Third		40.86		36.68		0.343
	Fourth		40.38		37.53		0.343
2011	First	$	35.13	$	31.19	$	0.275
	Second		36.47		33.31		0.275
	Third		35.87		30.02		0.275
	Fourth		36.40		30.80		0.275

Information with respect to dividend restrictions for us, CL&P, NSTAR Electric, PSNH, and WMECO is contained in Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations, under the caption "Liquidity" and Item 8, Financial Statements and Supplementary Data, in the Combined Notes to Consolidated Financial Statements, within this Annual Report on Form 10-K.   

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There is no established public trading market for the common stock of CL&P, NSTAR Electric, PSNH and WMECO.  All of the common stock of CL&P, NSTAR Electric, PSNH and WMECO is held solely by NU.

During 2012 and 2011, CL&P approved and paid $100.5 million and $243.2 million, respectively, of common stock dividends to NU.

Since April 10, 2012, NSTAR Electric approved and paid $159.9 million of common stock dividends to NSTAR LLC.

During 2012 and 2011, PSNH approved and paid $90.7 million and $58.8 million, respectively, of common stock dividends to NU.

During 2012 and 2011, WMECO approved and paid $9.4 million and $26.3 million, respectively, of common stock dividends to NU.

(b)

Holders

As of January 31, 2013, there were 49,487 registered common shareholders of our company on record.  As of the same date, there were a total of 332,767,098 common shares issued.

(c)

Securities Authorized for Issuance Under Equity Compensation Plans

For information regarding securities authorized for issuance under equity compensation plans, see Item 12, Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters, included in this Annual Report on Form 10-K.

(d)

Performance Graph

As allowed under Exchange Act Rule 14c-3 (17 CFR 240.14c-3), we provide the five-year cumulative performance graph annually, accompanying our Definitive Proxy Statement pursuant to section 14(a) of the Securities Exchange Act of 1934.   

(e)

Purchases of Equity Securities by the Issuer and Affiliated Purchasers

The following table discloses purchases of shares of our common stock made by us or on our behalf for the periods shown below.

Period	Total Number of Shares Purchased		Average Price Paid per Share	Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans and Programs (at month end)
October 1 - October 31, 2012	714,846	$	39.53	-	-
November 1 - November 30, 2012	21,159		38.48	-	-
December 1 - December 31, 2012	258,263		38.98	-	-
Total	994,268	$	39.37	-	-

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Item 6.			Selected Consolidated Financial Data
NU Selected Consolidated Financial Data (Unaudited)
(Thousands of Dollars, except percentages and common  share information)				2012 (a)			2011			2010			2009			2008
Balance Sheet Data:
	Property, Plant and Equipment, Net			$	16,605,010		$	10,403,065		$	9,567,726		$	8,839,965		$	8,207,876
	Total Assets				28,302,824			15,647,066			14,472,601			14,057,679			13,988,480
	Total Capitalization (b)				17,356,112			9,078,321			8,627,985			8,253,323			7,293,960
	Obligations Under Capital Leases (b)				11,071			12,358			12,236			12,873			13,397
Income Statement Data:
	Operating Revenues			$	6,273,787		$	4,465,657		$	4,898,167		$	5,439,430		$	5,800,095
	Net Income				533,077			400,513			394,107			335,592			266,387
	Net Income Attributable to Noncontrolling Interests				7,132			5,820			6,158			5,559			5,559
	Net Income Attributable to Controlling Interest			$	525,945		$	394,693		$	387,949		$	330,033		$	260,828
Common Share Data:
	Basic Earnings Per Common Share:
		Net Income Attributable to Controlling Interest		$	1.90		$	2.22		$	2.20		$	1.91		$	1.68
	Diluted Earnings Per Common Share:
		Net Income Attributable to Controlling Interest		$	1.89		$	2.22		$	2.19		$	1.91		$	1.67
	Weighted Average Common Shares Outstanding:
		Basic			277,209,819			177,410,167			176,636,086			172,567,928			155,531,846
		Diluted			277,993,631			177,804,568			176,885,387			172,717,246			155,999,240
	Dividends Declared Per Common Share			$	1.32		$	1.10		$	1.03		$	0.95		$	0.83
	Market Price - Closing (high) (c)			$	40.57		$	36.31		$	32.05		$	26.33		$	31.15
	Market Price - Closing (low) (c)			$	33.53		$	30.46		$	24.78		$	19.45		$	19.15
	Market Price - Closing (end of year) (c)			$	39.08		$	36.07		$	31.88		$	25.79		$	24.06
	Book Value Per Share (end of year)			$	29.41		$	22.65		$	21.60		$	20.37		$	19.38
	Tangible Book Value Per Share (end of year) (d)			$	18.21		$	21.03		$	19.97		$	18.74		$	17.54
	Rate of Return Earned on Average Common Equity (%) (e)				7.9			10.1			10.7			10.2			8.8
	Market-to-Book Ratio (end of year) (f)				1.3			1.6			1.5			1.3			1.2
Capitalization:
	Total Equity				53	%		44	%		44	%		44	%		41	%
	Preferred Stock, not subject to mandatory redemption				1			1			1			1			2
	Long-Term Debt (b)				46			55			55			55			57
					100	%		100	%		100	%		100	%		100	%
(a)		The 2012 results include the operations of NSTAR from the date of the merger, April 10, 2012, through December 31, 2012.
(b)		Includes portions due within one year, but excludes RRBs for Capitalization and Long-Term Debt.
(c)		Market price information reflects closing prices as reflected by the New York Stock Exchange.
(d)		Common Shareholders' Equity adjusted for goodwill and intangibles divided by total common shares outstanding.
(e)		Net Income Attributable to Controlling Interest divided by average Common Shareholders' Equity.
(f)		The closing market price divided by the book value per share.
CL&P Selected Consolidated Financial Data (Unaudited)
(Thousands of Dollars)				2012			2011			2010			2009			2008
Operating Revenues				$	2,407,449		$	2,548,387		$	2,999,102		$	3,424,538		$	3,558,361
Net Income					209,725			250,164			244,143			216,316			191,158
Cash Dividends on Common Stock					100,486			243,218			217,691			113,848			106,461
Property, Plant and Equipment, Net					6,152,959			5,827,384			5,586,504			5,340,561			5,089,124
Total Assets					9,142,088			8,791,396			8,255,192			8,364,564			8,336,118
Rate Reduction Bonds					-			-			-			195,587			378,195
Long-Term Debt (a)					2,862,790			2,583,753			2,583,102			2,582,361			2,270,414
Preferred Stock Not Subject to Mandatory Redemption					116,200			116,200			116,200			116,200			116,200
Obligations Under Capital Leases (a)					9,960			10,715			10,613			10,956			11,207
(a)		Includes portions due within one year, but excludes RRBs for Long-Term Debt.
See the Combined Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for a description of any accounting changes materially affecting the comparability of the information reflected in the tables above.

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NU Selected Consolidated Sales Statistics
		2012 (a)		2011		2010		2009		2008
Revenues:  (Thousands)
Residential	$	2,731,951	$	2,091,270	$	2,336,078	$	2,569,278	$	2,525,635
Commercial		1,563,709		1,201,091		1,303,841		1,462,786		1,607,224
Industrial		753,974		252,878		268,598		297,854		399,753
Wholesale		357,223		350,413		506,475		445,261		545,127
Streetlighting and Railroads		40,952		35,283		42,387		33,035		38,522
Miscellaneous and Eliminations		130,137		47,485		(29,878)		128,118		24,673
Total Electric		5,577,946		3,978,420		4,427,501		4,936,332		5,140,934
Natural Gas		572,857		430,799		434,277		449,571		577,390
Total - Regulated Companies		6,150,803		4,409,219		4,861,778		5,385,903		5,718,324
Other and Eliminations		122,984		56,438		36,389		53,527		81,771
Total	$	6,273,787	$	4,465,657	$	4,898,167	$	5,439,430	$	5,800,095
Regulated Companies - Sales:  (GWh)
Residential		19,719		14,766		14,913		14,412		14,509
Commercial		24,117		14,301		14,506		14,474		14,885
Industrial		5,462		4,418		4,481		4,423		5,149
Wholesale		2,154		1,020		3,423		4,183		3,576
Streetlighting and Railroads		420		327		330		336		340
Total		51,872		34,832		37,653		37,828		38,459
Regulated Companies - Customers:  (Average)
Residential		2,711,407		1,710,342		1,704,197		1,696,756		1,700,207
Commercial		355,385		193,505		192,266		189,265		190,067
Industrial		8,279		7,083		7,150		7,207		7,342
Streetlighting, Railroads and Wholesale		15,004		5,735		6,292		7,548		4,605
Total Electric		3,090,075		1,916,665		1,909,905		1,900,776		1,902,221
Natural Gas		483,770		207,753		205,885		206,438		204,834
Total		3,573,845		2,124,418		2,115,790		2,107,214		2,107,055
(a) The 2012 results include the operations of NSTAR from the date of the merger, April 10, 2012, through December 31, 2012.

CL&P Selected Consolidated Sales Statistics
		2012		2011		2010		2009		2008
Revenues:  (Thousands)
Residential	$	1,263,845	$	1,345,290	$	1,597,754	$	1,840,750	$	1,811,845
Commercial		711,337		732,968		821,872		935,586		1,042,077
Industrial		126,165		126,783		144,463		151,839		190,723
Wholesale		214,807		278,751		441,660		386,034		484,843
Streetlighting and Railroads		21,283		25,177		32,084		22,638		28,710
Miscellaneous		70,012		39,418		(38,731)		87,691		163
Total	$	2,407,449	$	2,548,387	$	2,999,102	$	3,424,538	$	3,558,361
Sales:  (GWh)
Residential		9,978		10,092		10,196		9,848		9,913
Commercial		9,414		9,525		9,716		9,705		9,993
Industrial		2,426		2,414		2,467		2,427		2,945
Wholesale		1,155		1,592		3,040		3,434		3,637
Streetlighting and Railroads		291		284		286		286		294
Total		23,264		23,907		25,705		25,700		26,782
Customers:  (Average)
Residential		1,103,397		1,100,740		1,096,576		1,093,229		1,094,991
Commercial		104,323		103,975		103,166		101,814		102,464
Industrial		3,301		3,331		3,359		3,381		3,613
Streetlighting, Railroads and Wholesale		4,266		4,260		4,366		5,307		2,883
Total		1,215,287		1,212,306		1,207,467		1,203,731		1,203,951

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Item 7.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis should be read in conjunction with our consolidated financial statements and related combined notes included in this Annual Report on Form 10-K.  References in this Annual Report to "NU," the "Company," "we," "us" and "our" refer to Northeast Utilities and its subsidiaries.  All per share amounts are reported on a diluted basis.  

Refer to the Glossary of Terms included in this Annual Report on Form 10-K for abbreviations and acronyms used throughout this Management's Discussion and Analysis of Financial Condition and Results of Operations.  

The only common equity securities that are publicly traded are common shares of NU.  The earnings and EPS of each business discussed below do not represent a direct legal interest in the assets and liabilities allocated to such business but rather represent a direct interest in our assets and liabilities as a whole.  EPS by business is a financial measure not recognized under GAAP that is calculated by dividing the Net Income Attributable to Controlling Interest of each business by the weighted average diluted NU common shares outstanding for the period.  The discussion below also includes non-GAAP financial measures referencing our 2012, 2011, and 2010 earnings and EPS excluding certain impacts related to NU's merger with NSTAR, a 2011 non-recurring charge at CL&P for the establishment of a reserve to provide bill credits to its residential customers and donations to charitable organizations, and certain non-recurring benefits from the settlement of tax issues in 2010.  We use these non-GAAP financial measures to evaluate and to provide details of earnings results by business and to more fully compare and explain our 2012, 2011 and 2010 results without including the impact of these non-recurring items.  Due to the nature and significance of these items on Net Income Attributable to Controlling Interest, we believe that the non-GAAP presentation is more representative of our financial performance and provides additional and useful information to readers of this report in analyzing historical and future performance by business.  These non-GAAP financial measures should not be considered as an alternative to reported Net Income Attributable to Controlling Interest or EPS determined in accordance with GAAP as an indicator of operating performance.

Reconciliations of the above non-GAAP financial measures to the most directly comparable GAAP measures of consolidated diluted EPS and Net Income Attributable to Controlling Interest are included under "Financial Condition and Business Analysis – Overview – Consolidated" in Management's Discussion and Analysis, herein.  

Financial Condition and Business Analysis

Merger with NSTAR:  

On April 10, 2012, NU and NSTAR completed our merger.  Pursuant to the terms and conditions of the Agreement and Plan of Merger, as amended (the Merger Agreement), NSTAR merged into NSTAR LLC, becoming a wholly-owned subsidiary of NU.  Unless otherwise noted, the results of NSTAR LLC and its subsidiaries, hereinafter referred to as "NSTAR," are included from the date of merger, April 10, 2012, through December 31, 2012 throughout this Management's Discussion and Analysis of Financial Condition and Results of Operations.

The transaction was structured as a merger of equals in a tax-free exchange of shares.  Pursuant to the Merger Agreement, NU issued to NSTAR shareholders 1.312 NU common shares for each issued and outstanding NSTAR common share.  As a result, NU issued approximately 136 million common shares to the NSTAR shareholders.  

Executive Summary

The following items in this executive summary are explained in more detail in this Annual Report:  

Results and Outlook:

·

We earned $525.9 million, or $1.89 per share, in 2012, compared with $394.7 million, or $2.22 per share, in 2011.  Excluding after-tax merger-related costs of $107.6 million, or $0.39 per share, we earned $633.5 million, or $2.28 per share, in 2012.  Excluding after-tax merger-related costs of $11.3 million, or $0.06 per share, and a non-recurring charge at CL&P of $17.9 million, or $0.10 per share, we earned $423.9 million, or $2.38 per share, in 2011.  The non-recurring 2011 charge at CL&P relates to the establishment of a reserve to provide bill credits to its residential customers and donations to charitable organizations (storm fund reserve).  Improved earnings results in 2012 were due primarily to the inclusion of NSTAR effective April 10, 2012 as well as higher transmission segment earnings as a result of increased investments in the transmission infrastructure.

·

The addition of NSTAR effective April 10, 2012 provided an earnings contribution of $182.9 million in 2012.  Due to the timing of the merger closing, NSTAR results for the first three months of 2012 are not reflected in NU’s 2012 results.

·

Our transmission segment earned $249.7 million, or $0.90 per share, in 2012, compared with $199.6 million, or $1.12 per share, in 2011.

·

Our electric distribution segment, which includes generation, earned $292.3 million, or $1.04 per share, in 2012, compared with $189.1 million, or $1.06 per share, in 2011.  The 2012 results include $51.1 million, or $0.19 per share, of after-tax merger settlement agreement costs and the 2011 results include the CL&P storm fund reserve.

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·

Our natural gas distribution segment earned $30.8 million, or $0.11 per share, in 2012, compared with $31.7 million, or $0.18 per share, in 2011.  The 2012 results include $2.1 million, or $0.01 per share, of after-tax merger settlement agreement costs.

·

NU parent and other companies recorded net losses of $46.9 million, or $0.16 per share, in 2012, compared with net losses of $25.7 million, or $0.14 per share, in 2011.  The 2012 and 2011 results include $54.4 million, or $0.19 per share, and $11.3 million, or $0.06 per share, respectively, of after-tax merger costs.

·

We project capital expenditures of approximately $5 billion from 2013 through 2015.  Of the $5 billion, we expect to invest approximately $2.5 billion in our electric and natural gas distribution segments, and $2.3 billion in our electric transmission segment.  In addition, we project capital expenditures of approximately $1.6 billion from 2016 through 2017 in our electric transmission segment.

Legislative, Regulatory, Policy and Other Items:

·

On June 15, 2012, Connecticut enacted the "Enhancing Emergency Preparedness and Response Act," which is intended to enhance the state’s emergency preparedness and response in the event of natural disasters.  Among numerous provisions, the bill required the PURA to establish emergency performance standards for utilities and allows the PURA to levy penalties for failure to meet those standards.  

·

On August 1, 2012, efforts to settle a complaint filed at FERC by various New England parties concerning the base ROE earned by New England transmission owners ended without a settlement.  Soon thereafter, litigation began before a FERC trial judge.  In the fourth quarter of 2012, additional testimony and complaints were filed.  On January 18, 2013, the FERC trial staff filed testimony and analysis recommending a base ROE of 9.66 percent based on the midpoint of their analysis with a range of reasonableness of 6.82 percent to 12.51 percent.  Hearings are scheduled for May 2013, a trial judge’s ruling is due in September 2013, and a FERC decision is expected in 2014.

·

On August 1, 2012, PURA issued a final decision in the investigation of CL&P’s performance related to both Tropical Storm Irene and the October 2011 snowstorm.  The decision concluded that CL&P was deficient and inadequate in its preparation, response, and communication to both storms, and identified certain penalties that could be imposed on CL&P during its next rate case.  However, PURA will consider and weigh the extent to which CL&P has taken steps to improve current practices in future storm response in determining any potential penalties.  We believe such steps to improve current storm preparation and response practices have been successfully executed in recent storms, and that CL&P's response to these 2011 storms was prudent and consistent with industry standards, and that it is probable that it will be able to recover its deferred costs.

·

On August 3, 2012, Massachusetts Governor Patrick signed into law "An Act Relative to Competitively Priced Electricity in the Commonwealth."  The Act establishes distribution rate case requirements for both electric and natural gas utility companies, as well as limiting settlement agreements, establishes new timing on rate case proceedings, and establishes requirements for all distribution companies to enter into additional long-term renewable energy distribution contracts.  

·

On August 6, 2012, Massachusetts Governor Patrick signed into law "An Act relative to emergency service response of public utility companies" to help improve utility companies’ emergency response and communication, as well as indicate how any assessed penalties will be provided to customers.  

·

On October 29, 2012, Hurricane Sandy caused extensive damage to our electric distribution system across all three states resulting in deferred storm restoration costs of $204 million.  Approximately 1.5 million of our 3.1 million electric distribution customers were without power during or following the storm.  We believe the storm restoration costs meet the criteria for specific cost recovery in each state in which we operate and, as a result, we do not expect the storm to have a material impact on our results of operations.

·

On December 11, 2012, in separate orders issued by the DPU, NSTAR Electric and WMECO received penalties of $4.1 million and $2 million, respectively, related to the investigation into the electric utilities’ responses to Tropical Storm Irene and the October 2011 snowstorm.  The DPU stated that NSTAR Electric failed to communicate and prioritize restoration efforts in both storms and WMECO failed to prioritize restoration efforts in the October snowstorm.  On December 28, 2012, NSTAR Electric and WMECO each filed appeals arguing the DPU penalties should be vacated.  While we believe NSTAR Electric and WMECO should ultimately prevail upon appeal, we are unable to conclusively state that a favorable outcome is probable.

·

On January 16, 2013, PURA approved the $300 million plan CL&P filed on July 9, 2012 to improve the resiliency of the CL&P electric distribution system.  The plan is consistent with the terms of the Connecticut settlement agreement among NU, NSTAR, and various Connecticut state agencies.

·

On February 8, 2013, a blizzard caused damage to the electric delivery systems of CL&P and NSTAR Electric.  We have estimated that approximately 71,000 and 350,000 of CL&P and NSTAR Electric's distribution customers, respectively, were without power during or following the storm.  We believe that this storm will cost between $100 million to $120 million, with approximately 90 percent of those costs relating to NSTAR Electric.  We expect the storm restoration costs to meet the criteria for specific cost

33

recovery in each state in which we operate and, as a result, we do not expect the storm to have a material impact on our results of operations.

·

On February 19, 2013, Connecticut issued a final comprehensive energy strategy (strategy).  The strategy includes a series of policy proposals that aim to expand energy choices, including natural gas, improve environmental conditions, create clean energy jobs, and enhance the quality of life for customers in the state.  Many of the recommendations in the strategy will require actions by the PURA and potentially the legislature.

·

NPT has identified a new route in the northern-most part of the project’s route where PSNH did not own any rights of way.  We expect to file the new route with the DOE in the first quarter of 2013, and we believe that NPT will be completed in early 2017.  We estimate the costs of the Northern Pass transmission project will be approximately $1.2 billion.  

Liquidity:

·

Cash and cash equivalents totaled $45.7 million as of December 31, 2012, compared with $6.6 million as of December 31, 2011, while cash capital expenditures totaled $1.5 billion in 2012, compared with $1.1 billion in 2011.

·

Cash flows provided by operating activities in 2012 totaled $1.05 billion, compared with operating cash flows of $901.1 million in 2011 (amounts are net of RRB payments).  The improved cash flows were due primarily to the addition of NSTAR, which contributed $450.8 million of operating cash flows (net of RRB payments) to NU since the date of the merger, April 10, 2012. Offsetting the favorable NSTAR cash flow impact was an increase in storm restoration costs, NUSCO Pension Plan cash contributions, 2012 customer bill credits and NU Parent merger transaction cost payments.

·

In 2012, we issued $850 million of new long-term debt consisting of $400 million by NSTAR Electric, $300 million by NU Parent, and $150 million by WMECO.  These new issuances were used primarily to repay $716.8 million of existing long-term debt, of which $663 million matured in 2012 ($400 million at NSTAR Electric and $263 million at NU Parent) and WMECO’s tax-exempt PCRBs of $53.8 million scheduled to mature in 2028.  Additionally, CL&P remarketed $62 million of tax-exempt PCRBs in April 2012 and redeemed $116.4 million of tax-exempt PCRBs in October 2012.  As of December 31, 2012, approximately $730 million of NU's current liabilities relate to long-term debt that will be paid in the next 12 months.  

·

On March 26, 2012, CL&P entered into a five-year $300 million unsecured revolving credit facility.  The credit facility is intended to finance short-term borrowings that CL&P incurred to fund costs of restoring power following Tropical Storm Irene and the October 2011 snowstorm.  As of December 31, 2012, CL&P had $89 million in borrowings outstanding under this credit facility.

·

On July 25, 2012, NU and certain of its subsidiaries jointly entered into a five-year $1.15 billion revolving credit facility, and NSTAR Electric entered into a five-year $450 million revolving credit facility.  The new facilities expire on July 25, 2017 and will be used primarily to backstop NU’s $1.15 billion commercial paper program and NSTAR Electric’s $450 million commercial paper program.  As of December 31, 2012, NU and NSTAR Electric had $1.15 billion and $276 million in borrowings outstanding under their respective commercial paper programs.

·

On January 15, 2013, CL&P issued $400 million of 2.5 percent first mortgage bonds that will mature on January 15, 2023.  The proceeds, net of issuance costs, were used to repay CL&P’s revolving credit facility borrowings of $89 million and $305.8 million of its commercial paper program borrowings.

·

On February 5, 2013, our Board of Trustees approved a common dividend payment of $0.3675 per share, payable March 28, 2013 to shareholders of record as of March 1, 2013.  The dividend represented an increase of 7.1 percent over the $0.343 per share quarterly dividend paid in December 2012.

34

Overview

Consolidated:  A summary of our earnings by business, which also reconciles the non-GAAP financial measures of consolidated non-GAAP earnings and EPS, as well as EPS by business, to the most directly comparable GAAP measures of consolidated Net Income Attributable to Controlling Interest and diluted EPS, for 2012, 2011 and 2010 is as follows:  

	For the Years Ended December 31,
	2012 (1)				2011				2010
(Millions of Dollars, Except Per Share Amounts)	Amount		Per Share		Amount		Per Share		Amount		Per Share
Net Income Attributable to Controlling Interest (GAAP)	$	525.9	$	1.89	$	394.7	$	2.22	$	387.9	$	2.19
Regulated Companies	$	626.0	$	2.25	$	438.3	$	2.46	$	384.0	$	2.16
NU Parent and Other Companies		7.5		0.03		(14.4)		(0.08)		(2.4)		(0.00)
Non-GAAP Earnings		633.5		2.28		423.9		2.38		381.6		2.16
Merger and Related Costs (after-tax)		(107.6)		(0.39)		(11.3)		(0.06)		(9.4)		(0.06)
Storm Fund Reserve		-		-		(17.9)		(0.10)		-		-
Non-Recurring Tax Settlements		-		-		-		-		15.7		0.09
Net Income Attributable to Controlling Interest (GAAP)	$	525.9	$	1.89	$	394.7	$	2.22	$	387.9	$	2.19

⁽¹⁾

Results include the operations of NSTAR from the date of merger, April 10, 2012, through December 31, 2012.  

The after-tax merger and related costs for 2012 consisted of the following charges:

·

Transaction and integration-related costs of $34 million at NU parent related to investment advisory fees, attorney fees, and consulting costs;

·

Change in control costs and other compensation costs of $13.5 million at NU parent and NSTAR;

·

A $23.6 million charge at CL&P related to the Connecticut settlement agreement, pursuant to which CL&P agreed to forego recovery of $40 million (pre-tax) of deferred storm restoration costs associated with Tropical Storm Irene and the October 2011 snowstorm;

·

A $14.8 million charge at CL&P for customer bill credits related to the Connecticut settlement agreement;

·

An aggregate of $12.8 million of charges at NSTAR Electric, NSTAR Gas, and WMECO for customer bill credits related to the Massachusetts settlement agreement; and

·

An $8.9 million charge at NU parent for the establishment of a fund to advance Connecticut energy goals related to the Connecticut settlement agreement.

Excluding the impacts of the 2012 and 2011 merger and related settlement agreement costs and the 2011 storm fund reserve, our 2012 earnings increased by $209.6 million, as compared to 2011, due primarily to the inclusion of NSTAR effective April 10, 2012, and higher transmission segment earnings as a result of increased investments in the transmission infrastructure.  On an earnings per share basis, the 2012 NSTAR earnings contribution of $182.9 million ($204.5 million in non-GAAP earnings) was partially offset by the issuance of approximately 136 million common shares to close the merger.  Offsetting these favorable earnings impacts were lower retail electric and firm natural gas sales due primarily to significantly milder weather in the first quarter of 2012, compared with the first quarter of 2011, higher pension and healthcare costs, higher depreciation and property taxes.

Regulated Companies:  Our Regulated companies consist of the electric distribution, natural gas distribution, and transmission segments.  Generation activities of PSNH and WMECO are included in our electric distribution segment.  A summary of our segment earnings for 2012, 2011 and 2010 is as follows:

	For the Years Ended December 31,
(Millions of Dollars)	2012 (1)		2011		2010
Net Income - Regulated Companies (GAAP)	$	572.8	$	420.4	$	384.0
Electric Distribution	$	343.4	$	207.0	$	173.5
Transmission		249.7		199.6		177.8
Natural Gas Distribution		32.9		31.7		32.7
Net Income - Regulated Companies (Non-GAAP)		626.0		438.3		384.0
Merger Settlement Agreement Costs (after-tax) (2)		(53.2)		-		-
Storm Fund Reserve (3)		-		(17.9)		-
Net Income - Regulated Companies (GAAP)	$	572.8	$	420.4	$	384.0

⁽¹⁾

Results include NSTAR Electric and NSTAR Gas earnings from the date of merger, April 10, 2012, through December 31, 2012.

⁽²⁾

Merger settlement agreement costs are attributable to the electric distribution segment ($51.1 million) and the natural gas distribution segment ($2.1 million).

⁽³⁾

The storm fund reserve is attributable to the electric distribution segment.

35

The higher 2012 transmission segment earnings, as compared to 2011, were due primarily to the inclusion of the NSTAR Electric transmission business and increased investments in the transmission infrastructure, including GSRP, which is under construction in western Massachusetts and northern Connecticut.  

Our electric distribution segment earned $292.3 million in 2012, compared with $189.1 million in 2011.  Excluding the impacts of the 2012 merger settlement agreement costs and the 2011 storm fund reserve, our electric distribution segment earned $343.4 million in 2012 and $207 million in 2011.  The higher earnings were due primarily to the addition of NSTAR Electric.  Excluding $10.9 million of after-tax merger settlement agreement costs, which related to customer bill credits, NSTAR Electric’s distribution business earned $150.2 million from April 10, 2012 through December 31, 2012.  For further information regarding NSTAR Electric’s earnings, see "Results of Operations – NSTAR Electric Company and Subsidiaries – Earnings Summary" in this Management's Discussion and Analysis of Financial Condition and Results of Operations.  Offsetting this favorable earnings impact was lower retail revenue, which was primarily the result of warmer than normal weather in the first quarter of 2012 as compared to colder than normal weather in the first quarter of 2011.  In addition, our electric distribution segment had higher pension and employee benefit costs, higher depreciation and property taxes, and the DPU October snowstorm penalty ($2 million pre-tax) imposed on WMECO in December 2012, partially offset by the favorable impacts of the CL&P and PSNH 2010 distribution rate case decisions.  As a result of these decisions, the CL&P rates increased effective July 1, 2011, which resulted in a full year favorable impact to earnings in 2012, while the PSNH rates increased effective July 1, 2012.

Our natural gas distribution segment earned $30.8 million in 2012, compared with $31.7 million in 2011.  Excluding the impact of the merger settlement agreement costs, our natural gas distribution segment earned $32.9 million in 2012.  The higher earnings were due primarily to the addition of NSTAR Gas’ results.  Excluding $2.1 million of after-tax merger settlement agreement costs, which related to customer bill credits, NSTAR Gas’ earnings were $6.6 million from April 10, 2012 through December 31, 2012.  Offsetting this favorable earnings impact was a decrease in total firm natural gas sales, which was primarily the result of warmer than normal weather in the first quarter of 2012 as compared to colder than normal weather in the first quarter of 2011, and higher pension expense, depreciation and property taxes.  These costs were partially offset by lower operations and maintenance costs as well as the favorable impact of the Yankee Gas 2011 rate case decision resulting in the additional increase to annualized rates effective July 1, 2012.

A summary of our retail electric GWh sales and percentage changes, as well as changes in CL&P, NSTAR Electric, PSNH and WMECO retail electric GWh sales, and our firm natural gas sales and percentage changes in million cubic feet, as well as changes in Yankee Gas and NSTAR Gas’ sales in million cubic feet, for 2012, as compared to 2011, is as follows:

	For the Year Ended December 31, 2012 Compared to 2011
	Sales (GWh)		Percentage
NU – Electric	2012 (1)	2011	Increase
Residential	19,719	14,766	33.5%
Commercial	24,117	14,301	68.6%
Industrial	5,462	4,418	23.6%
Other	420	327	28.6%
Total	49,718	33,812	47.0%

	For the Year Ended December 31, 2012 Compared to 2011
	CL&P	NSTAR Electric (2)	PSNH	WMECO
Electric	Percentage Increase/ (Decrease)	Percentage Increase/ (Decrease)	Percentage Increase/ (Decrease)	Percentage Increase/ (Decrease)
Residential	(1.1)%	0.2 %	(0.1)%	(1.0)%
Commercial	(1.2)%	(1.7)%	0.0 %	0.7 %
Industrial	0.5 %	(4.6)%	0.7 %	(0.9)%
Other	2.3 %	(12.2)%	(1.0)%	(5.7)%
Total	(0.9)%	(1.4)%	0.1 %	(0.3)%

⁽¹⁾

NU retail electric sales include the sales of NSTAR Electric from the date of merger, April 10, 2012, through December 31, 2012.

⁽²⁾

Results for NSTAR Electric represent its standalone retail electric sales for the year ended December 31, 2012 and 2011.

36

	For the Year Ended December 31, 2012 Compared to 2011
	Sales (million cubic feet)		Percentage
NU – Firm Natural Gas	2012 (1)	2011	Increase
Residential	22,535	13,508	66.8%
Commercial	27,906	17,175	62.5%
Industrial	19,453	16,197	20.1%
Total	69,894	46,880	49.1%
Total, Net of Special Contracts (2)	64,140	38,197	67.9%

	For the Year Ended December 31, 2012 Compared to 2011
	Yankee Gas	NSTAR Gas (3)
Firm Natural Gas	Percentage Increase/ (Decrease)	Percentage Decrease
Residential	(7.6)%	(10.7)%
Commercial	(3.5)%	(2.9)%
Industrial	(2.5)%	(0.4)%
Total	(4.3)%	(6.2)%
Total, Net of Special Contracts (2)	2.3 %

⁽¹⁾

NU firm natural gas sales include the sales of NSTAR Gas from the date of merger, April 10, 2012, through December 31, 2012.

⁽²⁾

Special contracts are unique to the customers who take service under such an arrangement and generally specify the amount of distribution revenue to be paid to Yankee Gas regardless of the customers’ usage.

⁽³⁾

NSTAR Gas’ sales data for the year ended December 31, 2012 compared to 2011 has been provided for comparative purposes only.

Weather and, to a lesser extent, fluctuations in fuel costs, conservation measures, and economic conditions affect sales to our customers.  Industrial sales are less sensitive to temperature variations than residential and commercial sales.  Weather impacts electric sales primarily during the summer and natural gas sales during the winter in our service territories (natural gas sales are more sensitive to temperature variations than electric sales).  Customer heating or cooling usage may not directly correlate with historical levels or with the level of degree-days that occur, particularly when weather patterns experienced are consistently colder or warmer.  In addition, our electric and natural gas businesses are sensitive to variations in daily weather, are highly influenced by New England’s seasonal weather variations, and are susceptible to damage from major storms and other natural events and disasters that could adversely affect our ability to provide energy.

Our consolidated retail electric and firm natural gas sales were higher in 2012, as compared to 2011, due to the inclusion of NSTAR Electric and NSTAR Gas sales, respectively, from the date of merger, April 10, 2012, through December 31, 2012.  

Actual retail electric sales for CL&P, NSTAR Electric and WMECO decreased in 2012, as compared to 2011, due primarily to the warmer than normal weather in the first quarter of 2012, as compared to colder than normal weather in the first quarter of 2011, while actual retail electric sales for PSNH were 0.1 percent higher than last year.  In 2012, heating degree days were 11 percent lower in Connecticut and western Massachusetts, 7 percent lower in the Boston metropolitan area, and 9 percent lower in New Hampshire, as compared to 2011.  On a weather normalized basis (based on 30-year average temperatures), the average NU combined consolidated total retail electric sales decreased 0.2 percent in 2012, as compared to 2011, assuming NSTAR Electric had been part of the NU combined electric distribution system for all periods under consideration.  We believe these decreases were due primarily to increased conservation efforts among all our customer classes and the continued installation of distributed generation at our commercial and industrial customers’ facilities.  For WMECO, the fluctuations in retail electric sales no longer impact earnings as the DPU approved a sales decoupling plan effective February 1, 2011.  Under this decoupling plan, WMECO now has an established annual level of baseline distribution delivery service revenues of $125.4 million that it is able to recover.  This effectively breaks the relationship between sales volume and revenues recognized.

Our firm natural gas sales are subject to many of the same influences as our retail electric sales, but have benefitted from lower natural gas prices and customer growth across all three customer classes.  In 2012, excluding the impact of NSTAR Gas sales, actual sales decreased, as compared to 2011, due primarily to the warmer than normal weather in the first quarter of 2012, as compared to colder than normal weather in the first quarter of 2011.  On a weather normalized basis, Yankee Gas’ 2012 sales increased due primarily to customer growth, lower cost of natural gas, the migration of interruptible customers switching to firm service rates, and the addition of gas-fired distributed generation in Yankee Gas’ service territory.

On a weather-normalized basis, the average NU combined consolidated total firm natural gas sales increased 2.7 percent in 2012, as compared to 2011, assuming NSTAR Gas had been part of the NU combined natural gas distribution system for all periods under consideration.

37

NU Parent and Other Companies:  NU parent and other companies (which includes our competitive businesses held by NU Enterprises and, from April 10, 2012, NSTAR LLC) recorded net losses of $46.9 million in 2012, compared with net losses of $25.7 million in 2011.  Excluding the impact of the 2012 and 2011 merger and related settlement agreement costs, NU parent and other companies recorded earnings of $7.5 million and net losses of $14.4 million, respectively.  The NU parent merger and related settlement agreement costs primarily included fees paid to investment advisors and attorneys, a charge for the establishment of a fund to advance Connecticut energy goals related to the Connecticut settlement agreement, and change in control costs and other compensation costs.  Excluding merger and related settlement agreement costs, improved results were due primarily to lower interest expense, a lower effective tax rate and the inclusion of NSTAR Communications.

Major Storm Restoration Costs:  A storm must meet certain criteria specific to each state and utility company to be declared a major storm.  Once a storm is declared major, all qualifying expenses incurred during storm restoration efforts, if deemed prudent, are deferred and recovered from customers in future periods.  In Connecticut, qualifying storm restoration costs must exceed $5 million for a storm to be declared as a major storm.  In Massachusetts, qualifying storm costs must exceed $1 million for NSTAR Electric and $300,000 for WMECO and an emergency response plan must be initiated for a storm to be declared a major storm.  In New Hampshire, (1) at least 10 percent of customers must be without power with at least 200 concurrent locations requiring repairs (trouble spots), or (2) at least 300 concurrent trouble spots must be reported for a storm to be declared a major storm.

On October 29, 2012, Hurricane Sandy caused extensive damage to our electric distribution system across all three states resulting in deferred storm restoration costs of $204 million ($159.9 million for CL&P, $27.8 million for NSTAR Electric, $12.1 million for PSNH, and $4.2 million for WMECO).  Approximately 1.5 million of our 3.1 million electric distribution customers were without power during or following the storm, with approximately 850,000 of those customers in Connecticut, approximately 472,000 in Massachusetts, and approximately 137,000 in New Hampshire.  We expect the storm restoration costs to meet the criteria for specific cost recovery in Connecticut, Massachusetts, and New Hampshire and, as a result, we do not expect the storm to have a material impact on the results of operations of CL&P, NSTAR Electric, PSNH or WMECO.  Each operating company will seek recovery of these deferred storm restoration costs through its applicable regulatory recovery process.

Liquidity

Consolidated:  Cash and cash equivalents totaled $45.7 million as of December 31, 2012, compared with $6.6 million as of December 31, 2011.  

On March 22, 2012, NU parent issued $300 million of 18-month floating rate Series D Senior Notes with a maturity date of September 20, 2013 and a coupon rate based on the three-month LIBOR rate plus a credit spread of 75 basis points, which resets every three months.  As of December 31, 2012, the interest rate on these notes was 1.059 percent.  The proceeds, net of issuance costs, were used to repay the NU parent $263 million Series A Senior Notes that matured on April 1, 2012, to repay short-term borrowings and for other general corporate purposes.  

On March 22, 2012, the FERC approved CL&P's application requesting to increase its total short-term borrowing capacity from a maximum of $450 million to a maximum of $600 million through December 31, 2013.

On March 26, 2012, CL&P entered into a five-year $300 million unsecured revolving credit facility.  The credit facility is intended to finance short-term borrowings that CL&P incurred to fund costs of restoring power following Tropical Storm Irene and the October 2011 snowstorm.  Under this new facility, CL&P can borrow either on a short-term or a long-term basis subject to any necessary regulatory approval, and may borrow at prime rates or LIBOR-based rates, plus an applicable margin based on the higher of S&P’s or Moody’s credit ratings.  As of December 31, 2012, CL&P had $89 million in borrowings outstanding under this credit facility.  The weighted-average interest rate on these borrowings as of December 31, 2012 was 3.325 percent.  

On April 2, 2012, CL&P remarketed $62 million of tax-exempt PCRBs that were subject to mandatory tender on that date.  The PCRBs, which mature on May 1, 2031, carry a coupon rate of 1.55 percent during the current three-year fixed-rate period, and are subject to mandatory tender for purchase on April 1, 2015.

On May 16, 2012, the FERC granted authorization to allow NSTAR Electric to issue total short-term debt securities in an aggregate principal amount not to exceed $655 million outstanding at any one time, effective October 23, 2012 through October 23, 2014.  

On July 25, 2012, NU, CL&P, NSTAR LLC, NSTAR Gas, PSNH, WMECO, and Yankee Gas jointly entered into a five-year $1.15 billion revolving credit facility.  The new facility replaced (1) the NSTAR LLC revolving credit facility of $175 million that served to backstop a commercial paper program utilized by NSTAR LLC and was scheduled to expire on December 31, 2012, (2) the NSTAR Gas revolving credit facility of $75 million that expired on June 8, 2012, and (3) the CL&P, PSNH, WMECO, and Yankee Gas joint $400 million and NU parent $500 million unsecured revolving credit facilities that were scheduled to expire on September 24, 2013.  The new facility expires on July 25, 2017.  We expect the new facility to be used primarily to backstop the $1.15 billion commercial paper program at NU, which commenced July 25, 2012.  As of December 31, 2012, NU had $1.15 billion in borrowings outstanding under this commercial paper program.  The weighted-average interest rate on these borrowings as of December 31, 2012 was 0.46 percent, which is generally based on money market rates.  As of December 31, 2012, there were inter-company loans of $987.5 million from NU to its subsidiaries ($405.1 million for CL&P, $63.3 million for PSNH, and $31.9 million for WMECO).  

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On July 25, 2012, NSTAR Electric entered into a five-year $450 million revolving credit facility.  This new facility serves to backstop NSTAR Electric’s existing $450 million commercial paper program.  The new facility expires on July 25, 2017.  This new facility replaced a prior $450 million NSTAR Electric revolving credit facility that was scheduled to expire on December 31, 2012.  As of December 31, 2012, NSTAR Electric had $276 million in short-term borrowings outstanding under its commercial paper program, leaving $174 million of available borrowing capacity.  The weighted-average interest rate on these borrowings as of December 31, 2012 was 0.31 percent, which is generally based on money market rates.

On July 31, 2012, the DPU approved NSTAR Electric's application for a new two-year financing plan that provides for the issuance of long-term debt securities in an aggregate amount not to exceed $600 million prior to December 31, 2013.

On October 1, 2012, CL&P redeemed at par four different series of tax-exempt PCRBs totaling $116.4 million.  The PCRBs carried coupons that ranged from 5.85 percent to 5.95 percent and maturity dates that ranged from 2016 through 2028.  On October 1, 2012, WMECO redeemed at par $53.8 million of tax-exempt PCRBs.  The PCRBs had a maturity date of 2028 and a coupon of 5.85 percent.  

On October 4, 2012, WMECO issued at a premium $150 million of senior unsecured notes at a yield of 2.673 percent that will mature on September 15, 2021.  The senior unsecured notes are part of the same series of WMECO’s existing 3.5 percent coupon Series F Notes that were initially issued in September 2011.  As a result, the aggregate principal amount of WMECO’s outstanding Series F Notes now totals $250 million.  

On October 15, 2012, NSTAR Electric issued at a discount $400 million of 2.375 percent Debentures at a yield of 2.406 percent that will mature on October 15, 2022.  The proceeds, net of issuance costs, were used to pay $400 million of 4.875 percent Debentures that matured on October 15, 2012.

On January 15, 2013, CL&P issued $400 million of 2.5 percent first mortgage bonds that will mature on January 15, 2023.  The proceeds, net of issuance costs, were used to repay CL&P’s revolving credit facility borrowings of $89 million and $305.8 million of its commercial paper program borrowings.

NU, CL&P, NSTAR Electric, PSNH and WMECO use their available capital resources to fund their respective construction expenditures, meet debt requirements, pay costs, including storm-related costs, pay dividends and fund other corporate obligations, such as pension contributions.  The current growth in NU’s transmission construction expenditures utilizes a significant amount of cash for projects that have a long-term return on investment and recovery period.  In addition, NU’s Regulated companies operate in an environment where recovery of its electric and natural gas distribution construction expenditures takes place over an extended period of time.  This impacts the timing of the revenue stream designed to fully recover the total investment plus a return on the equity portion of the cost and related financing costs.  These factors have resulted in NU’s current liabilities exceeding current assets by approximately $1.4 billion, $268 million, $198 million and $60 million at NU, CL&P, NSTAR Electric and WMECO, respectively, as of December 31, 2012.

As of December 31, 2012, approximately $730 million of NU's current liabilities relates to long-term debt that will be paid in the next 12 months, consisting of $550 million for NU parent, $55 million for WMECO, and $125 million for CL&P.  NU, with its strong credit ratings, has several options available in the financial markets to repay or refinance these maturities with the issuance of new long-term debt.  NU, CL&P, NSTAR Electric, and WMECO will reduce their short-term borrowings with cash received from operating cash flows or with the issuance of new long-term debt, as deemed appropriate given our capital requirements and maintenance of our credit rating and profile.  Management expects the future operating cash flows of NU and its subsidiaries, along with the access to financial markets, will be sufficient to meet any future operating requirements and capital investment forecasted opportunities.

Cash flows provided by operating activities in 2012 totaled $1.05 billion, compared with operating cash flows of $901.1 million in 2011 and $832.6 million in 2010 (all amounts are net of RRB payments, which are included in financing activities on the accompanying consolidated statements of cash flows).  The improved cash flows were due primarily to the addition of NSTAR, which contributed $450.8 million of operating cash flows (net of RRB payments) to NU since the date of the merger, April 10, 2012.  Offsetting the favorable NSTAR cash flow impact was an increase of $100.6 million in cash disbursements made in 2012, compared to 2011, associated with CL&P, PSNH and WMECO storm restoration costs related to Tropical Storm Irene, the October 2011 snowstorm, and Hurricane Sandy, NUSCO Pension Plan cash contributions of $197.4 million in 2012, compared to $143.6 million in 2011, a total of $28 million of bill credits in 2012 to customers of CL&P and WMECO related to the merger, and $27 million in bill credits provided to CL&P residential customers in 2012 related to the October 2011 snowstorm.  In addition, there were approximately $42 million of NU parent transaction cost payments related to the merger.  The improved cash flows from 2010 to 2011 were due primarily to the impact of the CL&P and PSNH 2010 distribution rate case decisions that were effective July 1, 2010, the WMECO distribution rate case decision that was effective February 1, 2011, and income tax refunds of $76.6 million in 2011 largely attributable to accelerated depreciation tax benefits, compared to income tax payments of $84.5 million in 2010.  Offsetting these benefits was $143.6 million of Pension Plan cash contributions in 2011, compared to $45 million in 2010, and approximately $157 million of cash disbursements made in 2011 associated with Tropical Storm Irene and the October snowstorm.  

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A summary of the current credit ratings and outlooks by Moody's, S&P and Fitch for senior unsecured debt of NU parent, NSTAR Electric, and WMECO and senior secured debt of CL&P and PSNH is as follows:

	Moody's		S&P		Fitch
	Current	Outlook	Current	Outlook	Current	Outlook
NU Parent	Baa2	Stable	BBB+	Stable	BBB+	Stable
CL&P	A3	Stable	A	Stable	A	Stable
NSTAR Electric	A2	Stable	A-	Stable	A+	Stable
PSNH	A3	Stable	A	Stable	A	Stable
WMECO	Baa2	Stable	A-	Stable	A-	Stable

On February 14, 2013, S&P revised its criteria for rating utility first mortgage bonds, resulting in one-level upgrades of CL&P and PSNH first mortgage bonds by S&P.  

We paid common dividends of $375 million in 2012, compared with $194.6 million in 2011.  This reflects an increase of approximately 17 percent in our common dividend beginning in the second quarter of 2012 following an increase of approximately 7 percent in the first quarter of 2012.  On February 5, 2013, our Board of Trustees approved a common dividend payment of $0.3675 per share, payable March 28, 2013 to shareholders of record as of March 1, 2013.  The dividend represented an increase of 7.1 percent over the $0.343 per share quarterly dividend paid in December 2012.

In 2012, CL&P, NSTAR LLC, PSNH, and WMECO paid $100.5 million, $141 million, $90.7 million, and $9.4 million, respectively, in common dividends to NU parent.  Since April 10, 2012, NSTAR Electric and NSTAR Gas have paid $159.9 million and $12 million, respectively, in common dividends to NSTAR LLC.  NU parent made equity contributions to CL&P and WMECO of $25 million and $50 million, respectively.  

Cash capital expenditures included on the accompanying consolidated statements of cash flows and described in this "Liquidity" section do not include amounts incurred on capital projects but not yet paid, cost of removal, AFUDC related to equity funds, and the capitalized portions of pension and PBOP expense or income.  A summary of our cash capital expenditures by company for the years ended December 31, 2012, 2011 and 2010 is as follows:

	For the Years Ended December 31,
(Millions of Dollars)	2012 (1)		2011		2010
CL&P	$	449.1	$	424.9	$	380.3
NSTAR Electric		324.3		N/A		N/A
PSNH		203.9		241.8		296.3
WMECO		264.2		238.0		115.2
Natural Gas		148.7		98.2		82.5
NPT		33.5		24.9		7.5
Other		48.6		48.9		72.7
Total	$	1,472.3	$	1,076.7	$	954.5

⁽¹⁾

Cash capital expenditures include NSTAR from the date of merger, April 10, 2012, through December 31, 2012.  

The increase in our cash capital expenditures was the result of the addition of NSTAR’s capital expenditures, effective April 10, 2012, and higher transmission segment cash capital expenditures of $113.8 million, primarily at WMECO and CL&P.

Business Development and Capital Expenditures

Consolidated:  Our consolidated capital expenditures, including amounts incurred but not paid, cost of removal, AFUDC, and the capitalized portions of pension and PBOP expense or income (all of which are non-cash factors), totaled $1.5 billion in 2012, $1.2 billion in 2011, and $1 billion in 2010.  These amounts included $43.1 million in 2012, $51.9 million in 2011, and $68.7 million in 2010, related to our corporate service companies, NUSCO and RRR.

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Transmission Business:  Transmission business capital expenditures increased by $189.6 million in 2012, compared with 2011, due primarily to increases at CL&P and WMECO related to the construction of GSRP and the addition of NSTAR Electric's capital expenditures since April 10, 2012.  A summary of transmission capital expenditures by company in 2012, 2011 and 2010 is as follows:  

	For the Years Ended December 31,
(Millions of Dollars)	2012 (1)		2011		2010
CL&P	$	182.5	$	128.6	$	107.2
NSTAR Electric		160.7		N/A		N/A
PSNH		55.7		68.1		49.1
WMECO		214.7		236.8		95.2
NPT		35.4		25.9		9.4
Total Transmission Segment	$	649.0	$	459.4	$	260.9

⁽¹⁾

Transmission capital expenditures include NSTAR Electric from the date of merger, April 10, 2012, through December 31, 2012.  

NEEWS:  GSRP, a project that involves the construction of 115 kV and 345 kV overhead lines by CL&P and WMECO from Ludlow, Massachusetts to Bloomfield, Connecticut, is the first, largest and most complicated project within the NEEWS family of projects.  The $718 million project is expected to be fully placed in service in late 2013.  As of December 31, 2012, the project was approximately 93 percent complete and we have placed $298 million in service.  

The Interstate Reliability Project, which includes CL&P’s construction of an approximately 40-mile, 345 kV overhead line from Lebanon, Connecticut to the Connecticut-Rhode Island border in Thompson, Connecticut where it will connect to transmission enhancements being constructed by National Grid, is our second major NEEWS project.  All siting applications have been filed by CL&P and National Grid.  On January 2, 2013, the Connecticut Siting Council issued a final decision and order approving the Connecticut portion of the project.  Decisions in Rhode Island and Massachusetts are expected between the end of 2013 and early 2014.  The $218 million project is expected to be placed in service in late 2015.  

Included as part of NEEWS are associated reliability related projects, approximately $70 million of which have been placed in service and approximately $30 million of which are in various phases of construction and will continue to go into service through 2013.  

Through December 31, 2012, CL&P and WMECO had capitalized $212 million and $518.1 million, respectively, in costs associated with NEEWS, of which $79.4 million and $183.4 million, respectively, were capitalized in 2012.    

Greater Hartford Central Connecticut Project (GHCC):  In August 2012, ISO-NE presented its preliminary needs analysis for the GHCC to the ISO-NE Planning Advisory Committee.  The results showed severe thermal overloads and voltage violations in each of the four study areas now and in the near future.  A combination of 345 kV and 115 kV transmission solutions are being considered to address these reliability concerns and a set of preferred solutions are expected to be identified by ISO-NE in 2013.  Approximately $300 million has been included in our five-year capital program for future projects being identified to enhance these reliability concerns, which have recently been confirmed by ISO-NE.

Cape Cod Reliability Projects:  Transmission projects serving Cape Cod in the Southeastern Massachusetts (SEMA) reliability region consist of an expansion and upgrade of NSTAR Electric's existing transmission infrastructure including construction of a new 345 kV transmission line that will cross the Cape Cod Canal (The Lower SEMA Transmission Project) as well as a new 115kV transmission line and other 115kV upgrades in the center of Cape Cod.  All regulatory and licensing and permitting is complete for the Lower SEMA Transmission Project.  Construction commenced in September 2012 and is expected to be completed by mid-2013.  The total estimated construction cost for the Cape Cod projects is approximately $150 million.

Northern Pass:  Northern Pass is NPT's planned HVDC transmission line from the Québec-New Hampshire border to Franklin, New Hampshire and an associated alternating current radial transmission line between Franklin and Deerfield, New Hampshire.  Northern Pass will interconnect at the Québec-New Hampshire border with a planned HQ HVDC transmission line.  Effective April 10, 2012, as a result of the merger, NUTV owned 100 percent of NPT.  NPT has identified a new route in the northern-most part of the project’s route where PSNH did not own any rights of way.  We expect to file the new route with the DOE in the first quarter of 2013, and we believe that NPT will be completed in early 2017.  

We estimate the costs of the Northern Pass transmission project will be approximately $1.2 billion (including capitalized AFUDC).  

Greater Boston Reliability and Boston Network Improvements:  As a result of continued analysis of the transmission needs to enhance system reliability and improve capacity in eastern Massachusetts, NSTAR Electric expects to implement a series of new transmission initiatives over the next five years.  We have included $479 million in our five-year capital program related to these initiatives.

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Distribution Business:  A summary of distribution capital expenditures by company for 2012, 2011 and 2010 is as follows:

	For the Year Ended December 31,
(Millions of Dollars)	2012 (1)		2011		2010
CL&P:
Basic Business	$	69.2	$	166.6	$	126.2
Aging Infrastructure		177.8		112.3		104.0
Load Growth		65.8		59.6		75.2
Total CL&P		312.8		338.5		305.4
NSTAR Electric:
Basic Business		47.3		N/A		N/A
Aging Infrastructure		111.5		N/A		N/A
Load Growth		17.4		N/A		N/A
Total NSTAR Electric		176.2		N/A		N/A
PSNH:
Basic Business		25.3		47.7		41.2
Aging Infrastructure		50.2		25.3		19.5
Load Growth		20.2		25.8		23.1
Total PSNH		95.7		98.8		83.8
WMECO:
Basic Business		12.7		24.2		17.5
Aging Infrastructure		18.5		11.5		10.5
Load Growth		6.5		6.1		5.1
Total WMECO		37.7		41.8		33.1
Total - Electric Distribution (excluding Generation)		622.4		479.1		422.3
Total - Natural Gas		162.9		102.8		94.6
Other Distribution		0.1		1.0		2.0
Total Electric and Natural Gas		785.4		582.9		518.9
PSNH Generation:
Clean Air Project		22.0		101.1		149.7
Other		7.9		23.7		27.4
Total PSNH Generation		29.9		124.8		177.1
WMECO Generation		0.7		11.7		10.1
Total Distribution Segment	$	816.0	$	719.4	$	706.1

⁽¹⁾

Distribution capital expenditures include NSTAR Electric and NSTAR Gas from the date of merger, April 10, 2012, through December 31, 2012.  

For the electric distribution business, basic business includes the relocation of plant, the purchase of meters, tools, vehicles, information technology, transformer replacements, and equipment facilities.  Aging infrastructure relates to reliability and the replacement of overhead lines, plant substations, underground cable replacement, and equipment failures.  Load growth includes requests for new business and capacity additions on distribution lines and substation overloads.  

Clean Air Project:  In June 2012, PSNH placed into service the last major elements of the Clean Air Project at Merrimack Station, a $421 million project that is utilizing wet scrubber technology to significantly reduce mercury and sulfur emissions from the station’s two coal units.  The scrubber has been operating since the end of September 2011 and has reduced mercury and sulfur emissions by more than 95 percent.

CL&P System Resiliency Plan:  On January 16, 2013, PURA approved the $300 million plan CL&P filed to improve the resiliency of its electric distribution system.  Consistent with the terms of the Connecticut settlement agreement, the plan includes vegetation management (both enhanced tree trimming and trimming on a shorter cycle), structural hardening (strengthening field structures through upgrades to the current structure design and material standards as well as upgrades to the poles and conductors), and electrical hardening (upgrading electrical distribution conductors and protective devices on overhead circuits).  CL&P expects to complete the plan in five years in two separate phases.  Phase 1 of the plan, which will be primarily focused on vegetation management, is estimated to cost $32 million in 2013 and $53 million in 2014.  Phase 2 of the plan is estimated to cost the remaining $215 million over the period from 2015 through 2017.

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Projected Capital Expenditures:  A summary of the projected capital expenditures for the Regulated companies' electric transmission business for 2013 through 2017 and for their distribution business for 2013 through 2015, including our corporate service companies' capital expenditures on behalf of the Regulated companies, is as follows:

	Year
(Millions of Dollars)	2013		2014		2015		2016		2017		2013-2017 Total
CL&P Transmission	$	193	$	243	$	157	$	135	$	89	$	817
NSTAR Electric Transmission		211		198		278		222		248		1,157
PSNH Transmission		92		147		102		63		15		419
WMECO Transmission		95		102		77		11		2		287
NPT		45		84		235		394		447		1,205
Total Transmission	$	636	$	774	$	849	$	825	$	801	$	3,885
Electric Distribution		670		648		635
Generation		30		30		34
Natural Gas		170		160		161
Total Distribution	$	870	$	838	$	830
Corporate Service Companies	$	84	$	62	$	55
Total	$	1,590	$	1,674	$	1,734

Actual capital expenditures could vary from the projected amounts for the companies and periods above.

FERC Regulatory Issues

FERC Base ROE Complaint:  On September 30, 2011, several New England state attorneys general, state regulatory commissions, consumer advocates and other parties filed a joint complaint with the FERC under Sections 206 and 306 of the Federal Power Act alleging that the base ROE used in calculating formula rates for transmission service under the ISO-NE Open Access Transmission Tariff by New England transmission owners, including CL&P, NSTAR Electric, PSNH and WMECO, is unjust and unreasonable.  The complainants asserted that the current 11.14 percent rate, which became effective in 2006, is excessive due to changes in the capital markets and are seeking an order to reduce the rate, which would be effective September 30, 2011 through December 31, 2012.  In response, the New England transmission owners filed testimony and analysis based on standard FERC methodology and precedent, demonstrating that the base ROE of 11.14 percent remained just and reasonable.

On May 3, 2012, the FERC issued an order establishing hearing and settlement procedures for the complaint.  The settlement proceedings were subsequently terminated, as the parties had reached an impasse in their efforts to reach a settlement.  In August 2012, the FERC trial judge assigned to the complaint established a schedule for the trial phase of the proceedings.  Complainant testimony supporting a base ROE of 9 percent was filed on October 1, 2012.  Additional testimony was filed on October 1, 2012 by a group of Massachusetts municipal electric companies, which recommended a base ROE of 8.2 percent.  The New England transmission owners filed testimony and analysis on November 20, 2012, demonstrating they believe that the current base ROE continues to be just and reasonable.  On January 18, 2013, the FERC trial staff filed testimony and analysis recommending a base ROE of 9.66 percent based on the midpoint of their analysis with a range of reasonableness of 6.82 percent to 12.51 percent.  Hearings on this complaint are scheduled for May 2013 and a trial judge’s recommended decision is due in September 2013.  A decision from FERC commissioners is expected in 2014.  Refunds to customers, if any, as a result of a reduction in the NU transmission companies’ base ROE would be retroactive to October 1, 2011.

On December 27, 2012, several additional parties filed a separate complaint concerning the New England transmission owners' base ROE with the FERC.  This new complaint seeks to reduce the New England transmission owner’s base transmission ROE effective January 1, 2013, and to consolidate this new complaint with the joint complaint filed on September 30, 2011.  The New England transmission owners have asked the FERC to reject this new complaint.  The FERC has not yet acted on this request.  

As of December 31, 2012, CL&P, NSTAR Electric, PSNH, and WMECO had approximately $2.1 billion of aggregate shareholder equity invested in their transmission facilities.  As a result, each 10 basis point change in the authorized base ROE would change annual consolidated earnings by an approximate $2.1 million.  We cannot at this time predict the ultimate outcome of this proceeding or the estimated impact on CL&P’s, NSTAR Electric’s, PSNH’s, or WMECO’s respective financial position, results of operations or cash flows.

FERC Order No. 1000:  On October 25, 2012, ISO-NE and a majority of the New England transmission owners, including  CL&P, NSTAR Electric, PSNH and WMECO, made a comprehensive compliance filing as required by FERC Order No. 1000 and Order No. 1000-A, issued on July 21, 2011 and May 17, 2012, respectively.  The compliance filing first seeks to preserve the existing reliability planning process in New England, based on FERC’s previous approval of transmission owners’ rights under the Transmission Operating Agreement with ISO-NE, and the superiority of the current planning process, which has resulted in major transmission construction, large reliability benefits and reduction of market costs.  The filing also contains a new process for public policy transmission planning that incorporates opportunities for competing, non-incumbent projects and cost allocation among the supporting states.  In mid-January 2013, ISO-NE and the majority of New England transmission owners filed answers to various stakeholders that submitted protests to the compliance filing.  We cannot predict the final outcome or impact on us; however implementation of FERC’s goals in New England, including within our service territories, may expose us to competition for construction of transmission projects, additional regulatory considerations, and potential delay with respect to future transmission projects.

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Regulatory Developments and Rate Matters

Federal:

EPA Proposed NPDES Permit:  PSNH maintains a NPDES permit consistent with requirements of the Clean Water Act for Merrimack Station.  In 1997, PSNH filed in a timely manner for a renewal of this permit.  As a result, the existing permit was administratively continued.  On September 29, 2011, the EPA issued a draft renewal NPDES permit for PSNH's Merrimack Station for public review and comment.  The proposed permit contains many significant conditions to future operation.  The proposed permit would require PSNH to install a closed-cycle cooling system (including cooling towers) at the station.  The EPA estimated that the net present value cost to install this system and operate it over a 20-year period would be approximately $112 million.

On October 27, 2011, the EPA extended the initial 60-day period for public review and comment on the draft permit for an additional 90 days until February 28, 2012.  PSNH and other electric utility groups filed thousands of pages of comments contesting EPA’s draft permit requirements.  PSNH stated that the data and studies supplied to the EPA demonstrate the fact that a closed-cycle cooling system is not warranted.  The EPA does not have a set deadline to consider comments and to issue a final permit.  Merrimack Station is permitted to continue to operate under its present permit pending issuance of the final permit and subsequent resolution of matters appealed by PSNH and other parties.  Due to the site specific characteristics of PSNH's other fossil generating stations, we believe it is unlikely that they would face similar permitting determinations.

Major Storms:

2013, 2012 and 2011 Major Storms:  On August 28, 2011, Tropical Storm Irene caused extensive damage to our distribution system.  Approximately 800,000 CL&P, PSNH and WMECO customers were without power at the peak of the outages, with approximately 670,000 of those customers in Connecticut.  Approximately 500,000 customer outages occurred on the NSTAR Electric distribution system in its aftermath.

On October 29, 2011, an unprecedented storm inundated our service territory with heavy snow causing significant damage to our distribution and transmission systems.  Approximately 1.2 million of CL&P, PSNH and WMECO’s electric distribution customers were without power at the peak of the outages, with 810,000 of those customers in Connecticut, 237,000 in New Hampshire, and 140,000 in western Massachusetts.  In terms of customer outages, this was the most severe storm in CL&P’s history, surpassing Tropical Storm Irene; the third most severe in PSNH’s history; and the most severe in WMECO's history.  The storm also caused approximately 200,000 customer outages on the NSTAR Electric distribution system.  

On October 29, 2012, Hurricane Sandy caused extensive damage to our electric distribution system across all three states.  Approximately 1.5 million of our 3.1 million electric distribution customers were without power during or following the storm, with approximately 850,000 of those customers in Connecticut, approximately 472,000 in Massachusetts, and approximately 137,000 in New Hampshire.

As of December 31, 2012, deferred storm restoration costs related to these major storms that are deferred for future recovery at CL&P, NSTAR Electric, PSNH, and WMECO were as follows:

(Millions of Dollars)	Tropical Storm Irene	October Snowstorm	Hurricane Sandy	Total
CL&P	$ 108.6	$ 173.0	$ 159.9	$ 441.5
NSTAR Electric	21.9	13.9	27.8	63.6
PSNH	6.8	15.5	12.1	34.4
WMECO	3.2	23.3	4.2	30.7
Total	$ 140.5	$ 225.7	$ 204.0	$ 570.2

On February 8, 2013, a blizzard caused damage to the electric delivery systems of CL&P and NSTAR Electric.  We have estimated that approximately 71,000 and 350,000 of CL&P and NSTAR Electric's distribution customers, respectively, were without power during or following the storm.  We believe that this storm will cost between $100 million to $120 million, with approximately 90 percent of those costs relating to NSTAR Electric.  Management expects the costs to meet the criteria for specific cost recovery in Connecticut and Massachusetts and, as a result, does not expect the storm to have a material impact on the results of operations of CL&P or NSTAR Electric.  Each operating company will seek recovery of these anticipated deferred storm costs through its applicable regulatory recovery process.

The magnitude of these storms’ restoration costs and damages met the criteria for cost deferral in Connecticut, New Hampshire, and Massachusetts and as a result, the storms had no material impact on the results of operations of CL&P, NSTAR Electric, PSNH and WMECO.  As covered by the Connecticut settlement agreement, CL&P agreed to forego recovery of $40 million (pre-tax) of the deferred storm restoration costs associated with Tropical Storm Irene and the October 2011 snowstorm.  We believe our response to all storms was prudent and therefore we believe it is probable that CL&P, NSTAR Electric, PSNH and WMECO will be allowed to recover the deferred storm restoration costs.  Each operating company will seek recovery of its estimated deferred storm restoration costs through its applicable regulatory recovery process.  

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Connecticut:

Standard Service and Last Resort Service Rates:  CL&P's residential and small commercial customers who do not choose competitive suppliers are served under SS rates, and large commercial and industrial customers who do not choose competitive suppliers are served under LRS rates.  Effective January 1, 2013, the PURA approved a decrease to CL&P’s total average SS rate of approximately 4.5 percent and an increase to CL&P’s total average LRS rate of approximately 15.3 percent.  The energy supply portion of the total average SS rate decreased from 8.443 cents per kWh to 7.68 cents per kWh while the energy supply portion of the total average LRS rate increased from 6.06 cents per kWh to 7.679 cents per kWh.  These changes were due primarily to the market conditions for the procurement of energy.  CL&P is fully recovering from customers the costs of its SS and LRS services.

CTA and SBC Reconciliation:  On December 12, 2012, PURA approved CL&P’s 2011 CTA and SBC reconciliation as filed on March 30, 2012, which compared CTA and SBC revenues to revenue requirements.  Prospectively, PURA has required CL&P to include only the billed revenues when filing its future CTA and SBC reconciliations.  This adjustment to the filing will have no impact to CL&P’s financial position, results of operations or cash flows.  CL&P will file its 2012 CTA and SBC reconciliation in March 2013.

FMCC Filing:  Semi-annually, CL&P files with PURA its FMCC filing, which reconciles actual FMCC revenues and charges and GSC revenues and expenses, for the six-month period under consideration.  The filing identifies a total net over or under recovery, which includes the remaining uncollected or non-refunded portions from previous filings.  On February 22, 2013, CL&P filed with PURA its semi-annual FMCC filing for the period July 1, 2012 through December 31, 2012.  This filing also reflects the January 1, 2012 through June 30, 2012 amounts as approved by PURA in the previous semi-annual filing.  The filing identified a total net over recovery of $7.9 million for the period.  PURA has not established a schedule for review of this filing, however, we do not expect the outcome of the PURA's review to have a material adverse impact on CL&P's financial position, results of operations or cash flows.

Conservation Adjustment Mechanism:  On November 7, 2012, CL&P filed an application with PURA for the establishment of a CAM.  The CAM would collect the costs associated with expanded energy efficiency programs beyond that already collected through the statutory charge and the revenues lost because of the expanded energy efficiency programs.

Procurement Fee Rate Proceedings:  In prior years, CL&P submitted to the PURA its proposed methodology to calculate the variable incentive portion of its transition service procurement fee, which was effective for the years 2004, 2005 and 2006, and requested approval of the pre-tax $5.8 million 2004 incentive fee.  At the time, CL&P had not recorded amounts related to the 2005 and 2006 procurement fee in earnings.  CL&P recovered the $5.8 million pre-tax amount, which was recorded in 2005 earnings, through a CTA reconciliation process.  On January 15, 2009, the PURA issued a final decision in this docket reversing its December 2005 draft decision and stated that CL&P was not eligible for the procurement incentive compensation for 2004.  A $5.8 million pre-tax charge (approximately $3.5 million net of tax) was recorded in the 2008 earnings of CL&P, and an obligation to refund the $5.8 million to customers was established as of December 31, 2008.  CL&P filed an appeal of this decision on February 26, 2009.  On February 4, 2010, the Connecticut Superior Court reversed the PURA decision.  The Court remanded the case back to the PURA for the correction of several specific errors.  On February 22, 2010, the PURA appealed the Connecticut Superior Court’s February 4, 2010 decision to the Connecticut Appellate Court, which then transferred the appeal to the Connecticut Supreme Court.  In lieu of a decision from the Connecticut Supreme Court, the parties involved, including CL&P, agreed to resolve all issues associated with the 2004, 2005 and 2006 procurement fee and settle the matter.  On October 2, 2012, the PURA issued a decision approving the parties’ joint settlement agreement.  As a result of the joint settlement agreement, CL&P is allowed to retain $11.5 million of procurement incentives for the years 2004, 2005 and 2006.

PURA Storm Review:  On August 1, 2012, PURA issued a final decision in the investigation of CL&P’s performance related to both Tropical Storm Irene and the October 2011 snowstorm.  The decision concluded that CL&P was deficient and inadequate in its preparation, response, and communication in both storms, and identified certain penalties that could be imposed on CL&P during its next rate case, including a reduction in allowed regulatory ROE and the disallowance of certain deferred storm restoration costs.  However, PURA will consider and weigh the extent to which CL&P has taken steps in its restructuring of storm management and the establishment of new practices for execution in future storm response in determining any potential penalties.  We believe such steps to improve current storm preparation and response practices have been successfully executed in recent storms.  At this time, we cannot estimate the impact on CL&P’s financial position, results of operations or cash flows.  We continue to believe that CL&P's response to these 2011 storms was prudent and consistent with industry standards, and that it is probable that it will be able to recover its deferred costs.

System Resiliency Plan:  On January 16, 2013, PURA approved the $300 million plan CL&P filed on July 9, 2012 to improve the resiliency of the CL&P electric distribution system.  For further information, see "Business Development and Capital Expenditures – Distribution Business" in this Management's Discussion and Analysis.

PURA Establishment of Performance Standards for Electric and Gas Companies Docket:  On November 1, 2012, PURA issued its report to the Connecticut legislature concerning specific standards for acceptable performance for electric and gas companies under emergency situations.  Emergency situations were defined as more than 10 percent of electric customers and 1 percent of gas customers being without service for more than 48 consecutive hours.  The performance standards the electric and gas companies, including CL&P and Yankee Gas, were directed to incorporate into their emergency response plans (ERP), and implement into their operations, include (1) the National Incident Management System and utilization of the Incident Command System, (2) scalable action and trigger points for various levels of outages, (3) a damage assessment model and mode of delivery, (4) guidelines for setting

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restoration priorities, (5) a description of how the utility will insure safety for the public and utility’s employees, (6) a storm matrix for various storm levels that identify the mutual aid and/or contractor resources necessary to restore customers within a prescribed period of time, (7) written communication protocols for timely and accurate information exchange between the EDC and a pre-determined list of state and local agencies and other utilities during emergency events, (8) training and drills/exercises to be conducted annually on a local level and every 3 years on a state-wide level, and (9) a written report to be filed with PURA within 60 days after the end of an event in order to assist in lessons learned and continual improvement.  Electric and gas companies, including CL&P and Yankee Gas, will be subject to penalties levied by PURA for failure to meet these performance standards.

Massachusetts:

Basic Service Rates:  Electric distribution companies in Massachusetts are required to obtain and resell power to retail customers through Basic Service for those customers who choose not to buy energy from a competitive energy supplier.  Basic Service rates are reset every six months (every three months for large commercial and industrial customers).  The price of Basic Service is intended to reflect the average competitive market price for electric power.  NSTAR Electric and WMECO fully recover their energy costs through DPU-approved regulatory rate mechanisms.

DPU Storm Penalties:  On December 11, 2012, in separate orders issued by the DPU, NSTAR Electric and WMECO received penalties related to the investigation into the electric utilities’ responses to Tropical Storm Irene and the October 2011 snowstorm.  The DPU ordered penalties of $4.1 million and $2 million for NSTAR Electric and WMECO, respectively, stating that NSTAR Electric failed to communicate and prioritize restoration efforts in both storms and WMECO failed to prioritize restoration efforts in the October snowstorm.  These penalties were ordered to be assessed in the form of customer credits in 2013.  On December 28, 2012, NSTAR Electric and WMECO each filed appeals with the SJC arguing the DPU penalties should be vacated.  In their filings, NSTAR Electric and WMECO stated that the DPU’s decision to assess the penalties was in error as the assessments were arbitrary and not supported by substantial evidence.  While we believe that NSTAR Electric and WMECO should ultimately prevail upon appeal, we are unable to conclusively state that a favorable outcome is probable.  Therefore, NSTAR Electric and WMECO recorded $4.1 million and $2 million, respectively, in pre-tax penalty charges as of December 31, 2012.

DPU Safety and Reliability Programs (CPSL):  Since 2006, NSTAR Electric has been recovering incremental costs related to the Double Pole Inspection, Replacement/Restoration and Transfer Program and the Underground Electric Safety Program, which included stray-voltage remediation, manhole inspections, repairs, and upgrades, in accordance with this DPU approved program.  Recovery of these CPSL costs is subject to review and approval by the DPU through a rate-reconciling mechanism.  From 2006 through December 31, 2011, cumulative costs associated with the CPSL program resulted in an incremental revenue requirement to customers of approximately $83 million.  These amounts included incremental operations and maintenance costs and the related revenue requirement for specific capital investments relative to the CPSL programs.

On May 28, 2010, the DPU issued an order on NSTAR Electric’s 2006 CPSL cost recovery filing (the May 2010 Order).  The May 2010 Order was the basis NSTAR Electric used for recognizing revenue for the CPSL programs.  On October 8, 2010, NSTAR Electric submitted a Compliance Filing with the DPU reconciling the cumulative CPSL program activity for the periods 2006 through 2009 in order to determine a proposed rate adjustment effective on January 1, 2011.  The DPU allowed the proposed rates for the CPSL programs to go into effect on that date, subject to final reconciliation of CPSL program costs through a future DPU proceeding.  NSTAR Electric updated the October 2010 filing with final activity through 2011 in February 2013.  

NSTAR Electric cannot predict the timing of any subsequent DPU order related to its CPSL filings for the period 2006 through 2011.  Therefore, NSTAR Electric continued to record its 2006 through 2011 revenues under the CPSL programs based on the May 2010 Order.  While we do not believe that any subsequent DPU order would result in revenue recognition that is materially different than the amounts already recognized, it is reasonably possible that an order could have a material impact on NSTAR Electric’s results of operations, financial position and cash flows.

The April 4, 2012 DPU-approved comprehensive merger settlement agreement with the Massachusetts Attorney General concerning the Merger stipulates that NSTAR Electric must incur a revenue requirement of at least $15 million per year for 2012 through 2015 in order to continue these programs.  CPSL revenues will end once NSTAR Electric has recovered its 2015-related CPSL costs.  Realization of these revenues is subject to maintaining certain performance metrics over the four-year period and DPU approval.  As of December 31, 2012, NSTAR Electric was in compliance with the performance metrics and has recognized the entire $15 million revenue requirement during 2012, which we believe is probable of approval from the DPU.

Basic Service Bad Debt Adder:  In accordance with a generic DPU order, electric utilities in Massachusetts recover the energy-related portion of bad debt costs in their Basic Service rates.  On February 7, 2007, NSTAR Electric filed its 2006 Basic Service reconciliation with the DPU proposing an adjustment related to the increase of its Basic Service bad debt charge-offs.  On June 28, 2007, the DPU issued an order approving the implementation of a revised Basic Service rate.  However, the DPU instructed NSTAR Electric to reduce distribution rates by an amount equal to the increase in its Basic Service bad debt charge-offs.  This adjustment to NSTAR Electric’s distribution rates would eliminate the fully reconciling nature of the Basic Service bad debt adder.

NSTAR Electric deferred the unrecovered costs associated with energy-related bad debt as a regulatory asset, which totaled approximately $34 million as of December 31, 2011, as NSTAR Electric had concluded that these costs were probable of recovery in future rates.  On June 18, 2010, NSTAR Electric filed an appeal of the DPU’s order with the SJC, which was heard by the SJC in

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December 2011.  On April 11, 2012, the SJC issued a procedural order waiving its standing 130-day rule for issuance of an order on the matter.  Due to the delay, NSTAR Electric concluded that while an ultimate outcome on the matter in its favor remained more likely than not, it could no longer be deemed probable.  As a result, NSTAR Electric recognized a reserve of $28 million ($17 million after-tax) as a charge to Operations and Maintenance in the first quarter of 2012 to reserve the related regulatory asset on its balance sheet.

On June 4, 2012, the SJC vacated the DPU's June 28, 2007 order and remanded the matter to the DPU for a "statement of reasons, including subsidiary findings, of its conclusion of law and relevant facts."  The continued uncertainty of the outcome of the DPU’s proceeding leaves NU and NSTAR Electric unable to conclude that it is probable that the previously reserved amount will ultimately be recovered and therefore NSTAR Electric will continue to maintain a reserve on this amount until the ultimate outcome is determined by the DPU.

Renewable Energy Contract:  On November 26, 2012, the DPU approved NSTAR Electric’s renewable energy contract with Cape Wind Associates, LLC, which has a term of 15 years, to purchase 129 MW of renewable energy from an offshore wind energy facility once it is constructed and placed in service.

New Hampshire:

Distribution Rates:  In 2012, PSNH filed for a step increase and a change in its accrual to its major storm reserve fund.  On June 27, 2012, the NHPUC approved an annualized distribution rate increase of $7.1 million, effective July 1, 2012, for the step increase.  Additionally, PSNH was allowed a $3.5 million increase in the annual accrual to its major storm reserve fund effective July 1, 2012.  

ES and SCRC Rates:  On December 12, 2012, PSNH filed an updated request to its September 28, 2012 preliminary request with the NHPUC to adjust its ES and SCRC rates effective with services rendered on and after January 1, 2013.  PSNH’s updated request proposed to increase the current ES billing rate to reflect projected costs for 2013 and to decrease the current SCRC billing rate to reflect the full amortization of RRBs at the end of April 2013.  The net impact to customers that purchase energy from PSNH is a net increase of 1.287 cents per kWh in total rates.  On December 28, 2012, the NHPUC approved the request.

ES Temporary Rates:  On November 22, 2011, the NHPUC opened a docket to review the Clean Air Project including the establishment of temporary rates for near-term recovery of Clean Air Project costs, a prudence review of PSNH's overall construction program, and establishment of permanent rates for recovery of prudently incurred Clean Air Project costs.  On April 10, 2012, the NHPUC issued an order authorizing temporary rates, effective April 16, 2012, which recover a significant portion of the Clean Air Project costs, including a return on equity.  The docket will continue for a comprehensive prudence review of the Clean Air Project and the establishment of a permanent rate.  The temporary rates will remain in effect until a permanent rate allowing full recovery of all prudently incurred costs is approved.  At that time, the NHPUC will reconcile recoveries collected under the temporary rates with final approved rates.   

The NHPUC had suspended the procedural schedule for the prudence review pending issuance of an order on preliminary substantive and procedural matters.  On December 24, 2012, the NHPUC issued an Order ruling on the requirement of PSNH to respond to a number of discovery requests that PSNH had objected to, and deciding that PSNH had legal authority to seek a variance from the Clean Air Project Mandate in the event of "economic infeasibility."  PSNH has sought rehearing of that December 24^th Order.  The NHPUC is considering PSNH’s rehearing request, and has again suspended the procedural schedule.  PSNH expects hearings to commence in this proceeding on or about the third quarter of 2013.  We cannot predict the outcome of the Clean Air Project prudence review, but believe all costs were incurred appropriately and are probable of recovery.

ES Filing:  On July 26, 2011, the NHPUC ordered PSNH to file a rate proposal that would mitigate the impact of customer migration expected to occur when the ES rate is higher than market prices.  On January 26, 2012, the NHPUC rejected the PSNH proposal and ordered PSNH to file a new proposal no later than June 30, 2012, addressing certain issues raised by the NHPUC.  On April 27, 2012, PSNH filed its proposed Alternative Default Energy Rate that addresses customer migration, with an effective date of July 1, 2012.  The proposal, if implemented, would result in no impact to earnings and would allow for an increased contribution to fixed costs for all ES customers.  On May 24, 2012, the NHPUC suspended the effectiveness of the proposed rates pending hearings.  Hearings were held on October and November 2012 and a final decision is expected in the first quarter of 2013.

Default ES Rate:  On January 18, 2013, the NHPUC opened a docket to investigate market conditions affecting PSNH’s energy service rate, how PSNH will maintain just and reasonable rates in light of those conditions, and any impact of PSNH’s generation ownership on the New Hampshire competitive electric market.  The NHPUC noted that this proceeding will not undertake to determine whether continued ownership and operation of generation is in PSNH’s retail customers’ economic interest.  No schedule or procedural process has been established for this proceeding.

Legislative and Policy Matters

Federal:  

Moving Ahead for Progress in the 21st Century Act:  On July 6, 2012, President Obama signed the "Moving Ahead for Progress in the 21^st Century" Act, which included provisions that impact how minimum required contributions to qualified pension plans are calculated.  The legislation allows NU to use a higher discount rate to calculate the plan's funded target liability, resulting in lower cash contribution

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requirements.  We have evaluated the impact of the legislation on future cash contributions to the NUSCO and NSTAR Pension Plans and will continue to follow our policy to fund these plans on an annual basis that is at least equal to the amounts that will satisfy the federal requirements, as amended by this legislation.

2013 Legislation:  On January 2, 2013, President Obama signed into law the "American Taxpayer Relief Act of 2012," which extends certain tax rules allowing the accelerated deduction of depreciation from the "American Recovery and Reinvestment Act of 2009" to businesses through 2013.  This extended stimulus is expected to provide us with cash flow benefits of between $200 million to $250 million in 2013 and 2014.  We are still evaluating the other provisions of this legislation, which are not expected to have a significant impact on our financial position, results of operations or cash flows.  

Connecticut:

Enhancing Emergency Preparedness and Response Act:  On June 15, 2012, Connecticut enacted the "Enhancing Emergency Preparedness and Response Act," which is intended to enhance the state’s emergency preparedness and response in the event of natural disasters.  Among numerous provisions, the bill requires the PURA to establish emergency performance standards for utilities and allows the PURA to levy penalties of up to 2.5 percent of annual distribution revenues for failure to meet performance standards.  For further information, see "Regulatory Developments and Rate Matters – Connecticut" in this Management's Discussion and Analysis.

Comprehensive Energy Strategy:  On February 19, 2013, Connecticut issued a final comprehensive energy strategy (strategy).  The strategy includes a series of policy proposals that aim to expand energy choices, improve environmental conditions, create clean energy jobs, and enhance the quality of life for customers in the state.  It also includes a seven-year initiative for expanding natural gas use with a goal of providing nearly 300,000 utility customers with access to natural gas, building an estimated 900 miles of new natural gas mains, and estimates of capital costs to be incurred by natural gas utility companies to connect customers on or near natural gas mains.  In addition to natural gas expansion, the strategy also calls for a significant expansion of energy efficiency investment in Connecticut, a review of Connecticut’s Renewable Energy Portfolio Standards (possibly including Canadian hydroelectric generation as a qualifying resource), and investment in alternative fuel transportation.  Many of the recommendations in the strategy will require actions by the PURA and potentially the legislature.  As such, the full impact of the strategy is not reflected in our electric distribution, transmission or natural gas business segments five-year capital program.

Massachusetts:

Energy Act:  On August 3, 2012, Massachusetts Governor Patrick signed into law "An Act Relative to Competitively Priced Electricity in the Commonwealth" (Energy Act).  The more significant provisions of the Energy Act impacting our Massachusetts operating companies and customers are as follows:

·

Requires electric utility companies to file a distribution rate case every five years and natural gas companies every 10 years, limiting those companies to one settlement agreement in a 10-year period;

·

Extends the distribution rate case review period to 10 months;

·

Requires all distribution companies, through a competitive bidding process and subject to DPU approval, to enter into additional cost-effective long-term renewable energy contracts with terms of 10 to 20 years.  Electric utility companies will be allowed a remuneration of 2.75 percent of the annual payments under the contracts to compensate them for accepting the financial obligation of the contracts;

·

Orders the DPU to open a proceeding for each electric and natural gas utility company to identify reconciliation factors and establish cost recovery from each customer class under cost-based criteria; and

·

Allows electric utility or distribution companies to construct, own and operate no more than 25 MW of solar generation facilities, a decrease from the initial allowance of up to 50 MW of solar generation facilities, subject to DPU approval, and requires that construction be completed prior to June 30, 2015.

Storm Response Act:  On August 6, 2012, Massachusetts Governor Patrick signed into law "an act relative to emergency service response of public utility companies" (Storm Response Act), to help improve utility companies’ emergency response and communication.  The Storm Response Act codified certain emergency response plan (ERP) provisions, which require utility companies to submit an annual ERP for DPU review and approval.  The ERP will describe storm or emergency responsibilities of utility company employees, customer communication processes and systems, and deployment of resources.  The Storm Response Act also requires that all future financial penalties levied on utility companies by the DPU for violation of DPU storm and emergency service performance standards will be provided to customers, and that transmission companies performing vegetation management activities within a right-of-way comply with certain notification provisions.  We are currently evaluating this act and its potential impacts on NSTAR Electric’s, NSTAR Gas’ and WMECO’s financial positions, results of operations and cash flows; however, we do not expect the impacts to be material.  

Critical Accounting Policies

The preparation of financial statements in conformity with GAAP requires management to make estimates, assumptions and, at times, difficult, subjective or complex judgments.  Changes in these estimates, assumptions and judgments, in and of themselves, could materially impact our financial position, results of operations or cash flows.  Our management communicates to and discusses with the Audit Committee of our Board of Trustees significant matters relating to critical accounting policies.  Our critical accounting policies are

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discussed below.  See the combined notes to our consolidated financial statements for further information concerning the accounting policies, estimates and assumptions used in the preparation of our consolidated financial statements.  

Regulatory Accounting:  The accounting policies of the Regulated companies conform to GAAP applicable to rate-regulated enterprises and reflect the effects of the rate-making process.

The application of accounting guidance applicable to rate-regulated enterprises results in recording regulatory assets and liabilities.  Regulatory assets represent the deferral of incurred costs that are probable of future recovery in customer rates.  In some cases, we record regulatory assets before approval for recovery has been received from the applicable regulatory commission.  We must use judgment to conclude that costs deferred as regulatory assets are probable of future recovery.  We base our conclusion on certain factors, including, but not limited to, regulatory precedent.  Regulatory liabilities represent revenues received from customers to fund expected costs that have not yet been incurred or probable future refunds to customers.

We use our best judgment when recording regulatory assets and liabilities; however, regulatory commissions can reach different conclusions about the recovery of costs, and those conclusions could have a material impact on our consolidated financial statements. We believe it is probable that the Regulated companies will recover the regulatory assets that have been recorded.  If we determined that we could no longer apply the accounting guidance applicable to rate-regulated enterprises to our operations, or that we could not conclude that it is probable that costs would be recovered or reflected in future rates, the costs would be charged to earnings in the period in which the determination is made.

For further information, see Note 3, "Regulatory Accounting," to the consolidated financial statements.  

Unbilled Revenues:  The determination of retail energy sales to residential, commercial and industrial customers is based on the reading of meters, which occurs regularly throughout the month.  Billed revenues are based on these meter readings and the majority of recorded annual revenues is based on actual billings.  Because customers are billed throughout the month based on pre-determined cycles rather than on a calendar month basis, an estimate of electricity or natural gas delivered to customers for which the customers have not yet been billed is calculated as of the balance sheet date.

Unbilled revenues represent an estimate of electricity or natural gas delivered to customers but not yet billed.  Unbilled revenues are included in Operating Revenues on the statement of income and are assets on the balance sheet that are reclassified to Accounts Receivable in the following month as customers are billed.  Such estimates are subject to adjustment when actual meter readings become available, when there is a change in estimates and under other circumstances.  

The Regulated companies estimate unbilled sales monthly using the daily load cycle method.  The daily load cycle method allocates billed sales to the current calendar month based on the daily load for each billing cycle.  The billed sales are subtracted from total month load, net of delivery losses, to estimate unbilled sales.  Unbilled revenues are estimated by first allocating unbilled sales to the respective customer classes, then applying an estimated rate by customer class to those sales.  The estimate of unbilled revenues is sensitive to numerous factors, such as energy demands, weather and changes in the composition of customer classes that can significantly impact the amount of revenues recorded.  

For further information, see Note 1K, "Summary of Significant Accounting Policies - Revenues," to the consolidated financial statements.  

Pension and PBOP:  NUSCO and NSTAR Electric sponsor pension plans covering certain of our employees.  In addition, NUSCO and NSTAR Electric & Gas sponsor PBOP plans to provide certain health care benefits, primarily medical and dental, and life insurance benefits to retired employees.  For each of these plans, the development of the benefit obligation, funded status and net periodic benefit cost is based on several significant assumptions.  We evaluate these assumptions at least annually and adjust them as necessary.  Changes in these assumptions could have a material impact on our financial position, results of operations or cash flows.  

Pre-tax net periodic benefit expense (excluding SERP) for the Pension Plans was $234.9 million, $127.7 million and $80.4 million for the years ended December 31, 2012, 2011 and 2010, respectively.  The pre-tax net periodic benefit expense for the PBOP Plans was $72.3 million, $43.6 million and $41.6 million for the years ended December 31, 2012, 2011 and 2010, respectively.  NSTAR pension and PBOP expense is included in NU consolidated amounts from the date of the merger, April 10, 2012, through December 31, 2012.

We develop key assumptions for purposes of measuring liabilities as of December 31^st and expenses for the subsequent year.  These assumptions include the long-term rate of return on plan assets, discount rate, compensation/progression rate, and health care cost trend rates and are discussed below.

Long-Term Rate of Return on Plan Assets:  In developing this assumption, we consider historical and expected returns and input from our actuaries and consultants.  Our expected long-term rate of return on assets is based on assumptions regarding target asset allocations and corresponding expected rates of return for each asset class.  We routinely review the actual asset allocations and periodically rebalance the investments to the targeted asset allocations when appropriate.  For the year ended December 31, 2012, our aggregate expected long-term rate of return assumptions of 8.25 percent on the NUSCO Pension and PBOP Plans and 7.30 percent for the NSTAR Pension and PBOP Plans were used to determine our Pension and PBOP expense.  For the forecasted 2013 pension

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and PBOP expense, our expected long-term rate of return of 8.25 percent for all plans was used, which reflects a change in target asset allocations within both the NUSCO and NSTAR Pension and PBOP Plans.

Discount Rate:  Payment obligations related to the Pension Plans and PBOP Plans are discounted at interest rates applicable to the expected timing of each plan’s cash flows.  The discount rate that is utilized in determining the pension and PBOP obligations is based on a yield-curve approach.  This approach is based on a population of bonds with an average rating of AA based on bond ratings by Moody’s, S&P and Fitch, and uses bonds with above median yields within that population.  The discount rates determined on this basis are 4.24 percent for the NUSCO Pension Plan, 4.13 percent for the NSTAR Pension Plan, 4.04 percent for the NUSCO PBOP Plans and 4.35 percent for the NSTAR PBOP Plan as of December 31, 2012.

Compensation/Progression Rate:  This assumption reflects the expected long-term salary growth rate, which impacts the estimated benefits that pension plan participants receive in the future.  We used a compensation/progression rate of 3.5 percent as of December 31, 2012 and 2011 for the NUSCO Pension Plan and 4 percent for the NSTAR Pension Plan as of December 31, 2012, which reflects our current expectation of future salary increases, including consideration of the levels of increases built into collective bargaining agreements.  

Actuarial Determination of Expense:  Pension and PBOP expense is determined by our actuaries and consists of service cost and prior service cost, interest cost based on the discounting of the obligations, amortization of actuarial gains and losses and amortization of the net transition obligation, offset by the expected return on plan assets.  Actuarial gains and losses represent differences between assumptions and actual information or updated assumptions.

We determine the expected return on plan assets for the NUSCO Pension and PBOP Plans by applying our assumed rate of return to a four-year rolling average of plan asset fair values, which reduces year-to-year volatility.  This calculation recognizes investment gains or losses over a four-year period from the years in which they occur.  Investment gains or losses for this purpose are the difference between the calculated expected return and the actual return or loss based on the change in the fair value of assets during the year.  As of December 31, 2012, investment gains and losses that remain to be reflected in the calculation of plan assets over the next four years were losses of $224.4 million and gains of $0.7 million for the NUSCO Pension Plan and PBOP Plans, respectively.  As investment gains and losses are reflected in the average plan asset fair values, they are subject to amortization with other unrecognized actuarial gains or losses.  The plans currently amortize unrecognized actuarial gains or losses as a component of pension and PBOP expense over the average future employee service period.  As of December 31, 2012, the net unrecognized actuarial losses on the NUSCO Pension and PBOP Plan liabilities were $1.1 billion and $176.5 million, respectively.  For the NSTAR Pension and PBOP Plans, the entire difference between the actual and expected return on plan assets as of December 31, 2012 is immediately reflected as a component of unrecognized actuarial gains or losses to be amortized over the estimated average future service period of the employees.  As of December 31, 2012, the net unrecognized actuarial losses on the NSTAR Pension and PBOP Plan liabilities were approximately $724 million and $176 million, respectively.

Forecasted Expenses and Expected Contributions:  Based upon the assumptions and methodologies discussed above, we estimate that the combined expense for the Pension and PBOP Plans will be $241 million and $46 million, respectively, in 2013.  Pension and PBOP expense for subsequent years will depend on future investment performance, changes in future discount rates and other assumptions, and various other factors related to the populations participating in the plans.  Pension and PBOP expense charged to earnings is net of the amounts capitalized.  

We expect to continue our policy to contribute to the NUSCO PBOP Plans at the amount of PBOP expense excluding any curtailments and the NSTAR PBOP Plan at an amount that approximates benefit payments.  NU's policy is to fund the Pension Plans annually in an amount at least equal to an amount that will satisfy the federal requirements. NU made contributions to the NUSCO Pension Plan totaling $197.4 million in 2012, of which $87.7 million was contributed by PSNH.  NSTAR Electric contributed $25 million to the NSTAR Pension Plan in 2012.  Our Pension Plan funded ratio (the value of plan assets divided by the funding target in accordance with the requirements and guidelines of the PPA) was 94.8 percent and 100.2 percent as of January 1, 2012 for the NUSCO Pension Plan and NSTAR Pension Plan, respectively.  We currently estimate that aggregate contributions of $285 million to the Pension Plans will be made in 2013.  Fluctuations in the average discount rate used to calculate expected contributions to the Pension Plans can have a significant impact on the amounts.  

Sensitivity Analysis:  The following represents the hypothetical increase to the Pension Plans’ (excluding SERP) and PBOP Plans’ reported annual cost as a result of a change in the following assumptions by 50 basis points:

	Pension Plan Cost				PBOP Plan Cost
(Millions of Dollars)	As of December 31,
Assumption Change		2012		2011	2012		2011
NU Consolidated
Lower long-term rate of return	$	15.0	$	10.3	$	3.1	$	1.3
Lower discount rate	$	22.0	$	14.2	$	6.7	$	2.3
Higher compensation increase	$	10.4	$	6.5		N/A		N/A
NSTAR Plans
Lower long-term rate of return	$	4.8		N/A	$	1.7		N/A
Lower discount rate	$	6.8		N/A	$	4.1		N/A
Higher compensation increase	$	3.6		N/A		N/A		N/A

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Changes in pension and PBOP costs would not impact net income for the NSTAR Plans as their expenses are fully recovered in rates, which reconcile each year relative to the change in costs.

Health Care Cost:  For the NUSCO PBOP Plans, the health care cost trend rate assumption is 7 percent, subsequently decreasing by 50 basis points per year to an ultimate rate of 5 percent in 2017.  For the NSTAR PBOP Plan, the health care cost trend rate is 7.10 percent, subsequently decreasing to an ultimate rate of 4.50 percent in 2024.  The effect of a hypothetical increase in the health care cost trend rate by one percentage point would be to have increased service and interest cost components of PBOP Plan expense by $8.9 million in 2012, with a $126.5 million impact on the postretirement benefit obligation.

See Note 10A, "Employee Benefits - Pension Benefits and Postretirement Benefits Other Than Pensions," to the consolidated financial statements for more information.

Goodwill:  We recorded approximately $3.2 billion of goodwill associated with the merger with NSTAR on April 10, 2012.  NU had existing goodwill of $0.3 billion related to Yankee Gas.  NU has identified its reporting units for purposes of allocating goodwill as Electric Distribution, Electric Transmission and Natural Gas Distribution.  Our reporting units for purposes of allocating and testing goodwill are consistent with our operating segments underlying our reportable segments.  Electric Distribution and Electric Transmission reporting units include values for the respective components of CL&P, NSTAR Electric, PSNH and WMECO.  The Natural Gas reporting unit includes the carrying values of NSTAR Gas and Yankee Gas.  

We are required to test goodwill balances for impairment at least annually by applying a fair value-based test that requires us to use estimates and judgment.  We have selected October 1^st of each year as the annual goodwill impairment testing date.  Goodwill impairment is deemed to exist if the carrying value of a reporting unit exceeds its estimated fair value and if the implied fair value of goodwill based on the estimated fair value of the reporting unit is less than the carrying amount of the goodwill.  If goodwill were deemed to be impaired, it would be written down in the current period to the extent of the impairment.  

We performed an impairment analysis as of October 1, 2012 for the Electric Distribution, Electric Transmission and Natural Gas Distribution reporting units.  We determined that the fair value of the reporting units substantially exceeded the carrying values and no impairment exists.  In performing the evaluation, we estimated the fair values of the reporting units and compared them to the carrying values of the reporting units, including goodwill.  We estimated the fair values of the reporting units using a discounted cash flow approach and a market approach that analyzed company information and market transactions.  This evaluation requires the input of several critical assumptions, including cash flow projections, operating cost escalation rates, rates of return, future growth rates, a risk-adjusted discount rate, long-term earnings and merger multiples of comparable companies.

We determine the discount rate using the capital asset pricing model methodology.  This methodology uses a weighted average cost of capital in which the ROE is developed using risk-free rates, equity premiums and a beta representing the reporting unit’s volatility relative to the overall market.  The resulting discount rate is intended to be comparable to a rate that would be applied by a market participant.  The discount rate may change from year to year as it is based on external market conditions.

The 2012 goodwill impairment analysis resulted in a significant excess of fair value of our reporting units over the carrying value.  The estimated fair value of our reporting units is sensitive to changes in assumptions, such as discount rates, peer company financial results, recent market transactions and forecasted cash flows.  

Income Taxes:  Income tax expense is estimated annually for each of the jurisdictions in which we operate.  This process involves estimating current and deferred income tax expense or benefit and the impact of temporary differences resulting from differing treatment of items for financial reporting and income tax return reporting purposes.  Such differences are the result of timing of the deduction for expenses, as well as any impact of permanent differences, non-tax deductible expenses, or other items, including items that directly impact our tax return as a result of a regulatory activity (flow-through items).  The temporary differences and flow-through items result in deferred tax assets and liabilities that are included in the consolidated balance sheets.  The income tax estimation process impacts all of our segments.  We record income tax expense quarterly using an estimated annualized effective tax rate.  

A reconciliation of expected tax expense at the statutory federal income tax rate to actual tax expense recorded is included in Note 11, "Income Taxes," to the consolidated financial statements.

We also account for uncertainty in income taxes, which applies to all income tax positions previously filed in a tax return and income tax positions expected to be taken in a future tax return that have been reflected on our balance sheets.  We follow generally accepted accounting principles to address the methodology to be used in recognizing, measuring and classifying the amounts associated with tax positions that are deemed to be uncertain, including related interest and penalties.  The determination of whether a tax position meets the recognition threshold under this guidance is based on facts and circumstances available to us.  Once a tax position meets the recognition threshold, the tax benefit is measured using a cumulative probability assessment.  Assigning probabilities in measuring a recognized tax position and evaluating new information or events in subsequent periods requires significant judgment and could change previous conclusions used to measure the tax position estimate.  New information or events may include tax examinations or appeals (including information gained from those examinations), developments in case law, settlements of tax positions, changes in tax law and regulations, rulings by taxing authorities and statute of limitation expirations.  Such information or events may have a significant impact on our financial position, results of operations and cash flows.  

51

Accounting for Environmental Reserves:  Environmental reserves are accrued when assessments indicate it is probable that a liability has been incurred and an amount can be reasonably estimated.  Adjustments made to estimates of environmental liabilities could have a significant impact on earnings.  We estimate these liabilities based on findings through various phases of the assessment, considering the most likely action plan from a variety of available remediation options (ranging from no action required to full site remediation and long-term monitoring), current site information from our site assessments, remediation estimates from third party engineering and remediation contractors, and our prior experience in remediating contaminated sites.  Our estimates incorporate currently enacted state and federal environmental laws and regulations and data released by the EPA and other organizations.  The estimates associated with each possible action plan are judgmental in nature partly because there are usually several different remediation options from which to choose.  Our estimates are subject to revision in future periods based on actual costs or new information from other sources, including the level of contamination at the site, the extent of our responsibility or the extent of remediation required, recently enacted laws and regulations or a change in cost estimates due to certain economic factors.  

For further information, see Note 12A, "Commitments and Contingencies - Environmental Matters," to the consolidated financial statements.

Fair Value Measurements:  We follow fair value measurement guidance that defines fair value as the price that would be received for the sale of an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (an exit price).  We have applied this guidance to our Company's derivative contracts that are recorded at fair value, marketable securities held in NU’s supplemental benefit trust and WMECO’s spent nuclear fuel trust, the marketable securities held in CYAPC's and YAEC's nuclear decommissioning trusts, our valuations of investments in our pension and PBOP plans, and nonrecurring fair value measurements of nonfinancial assets such as goodwill and AROs.  

Changes in fair value of the regulated company derivative contracts are recorded as Regulatory Assets or Liabilities, as we expect to recover the costs of these contracts in rates.  These valuations are sensitive to the prices of energy and energy-related products in future years for which markets have not yet developed and assumptions are made.  

We use quoted market prices when available to determine fair values of financial instruments.  If quoted market prices are not available, fair value is determined using quoted prices for similar instruments in active markets, quoted prices for identical or similar instruments that are not active and model-derived valuations.  When quoted prices in active markets for the same or similar instruments are not available, we value derivative contracts using models that incorporate both observable and unobservable inputs.  Significant unobservable inputs utilized in the models include energy and energy-related product prices for future years for long-dated derivative contracts, future contract quantities under full requirements and supplemental sales contracts, and market volatilities.  Discounted cash flow valuations incorporate estimates of premiums or discounts, reflecting risk adjusted profit that would be required by a market participant to arrive at an exit price, using available historical market transaction information.  Valuations of derivative contracts also reflect our estimates of nonperformance risk, including credit risk.  

For further information on market risk, see Item 7A, "Quantitative and Qualitative Disclosures about Market Risk," included in this Annual Report on Form 10-K.

For further information on derivative contracts and marketable securities, see Note 1I, "Summary of Significant Accounting Policies - Derivative Accounting," Note 5, "Derivative Instruments," and Note 6, "Marketable Securities," to the consolidated financial statements.

Other Matters

Accounting Standards Recently Adopted:  For information regarding new accounting standards, see Note 1C, "Summary of Significant Accounting Policies – Recently Adopted Accounting Standards," to the consolidated financial statements.

Contractual Obligations and Commercial Commitments:  Information regarding our contractual obligations and commercial commitments as of December 31, 2012 is summarized annually through 2017 and thereafter as follows:

NU
(Millions of Dollars)	2013		2014		2015		2016		2017		Thereafter		Total
Long-term debt maturities (a)	$	731.7	$	576.6	$	216.7	$	-	$	745.0	$	4,559.8	$	6,829.8
Estimated interest payments on existing debt (b)		320.2		298.7		277.1		271.8		267.8		2,099.5		3,535.1
Capital leases (c)		2.8		2.2		2.2		2.0		2.0		7.5		18.7
Operating leases (d)		22.4		16.6		14.1		11.2		8.6		23.3		96.2
Funding of pension obligations (d) (h)		145.0		175.0		247.9		269.3		261.1		109.0		1,207.3
Funding of other postretirement benefit obligations (d)		55.7		52.0		49.5		46.1		43.8		11.7		258.8
Estimated future annual long-term contractual costs (e)		717.7		683.9		572.8		501.9		432.9		2,897.5		5,806.7
Other purchase commitments (d) (g)		1,876.8		-		-		-		-		-		1,876.8
Total (f) (i)	$	3,872.3	$	1,805.0	$	1,380.3	$	1,102.3	$	1,761.2	$	9,708.3	$	19,629.4

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CL&P
(Millions of Dollars)	2013		2014		2015		2016		2017		Thereafter		Total
Long-term debt maturities (a)	$	125.0	$	150.0	$	162.0	$	-	$	250.0	$	1,540.3	$	2,227.3
Estimated interest payments on existing debt (b)		119.5		119.5		109.8		107.3		103.3		1,009.2		1,568.6
Capital leases (c)		2.2		2.0		2.0		1.9		2.0		7.3		17.4
Operating leases (d)		4.3		3.7		3.1		2.3		1.2		6.4		21.0
Funding of other postretirement benefit obligations (d)		8.1		7.0		6.2		5.0		4.3		3.6		34.2
Estimated future annual long-term contractual costs (e)		278.9		282.1		268.7		250.4		224.2		1,171.3		2,475.6
Other purchase commitments (d) (g)		751.4		-		-		-		-		-		751.4
Total (f) (i)	$	1,289.4	$	564.3	$	551.8	$	366.9	$	585.0	$	3,738.1	$	7,095.5

(a)

Long-term debt maturities exclude fees and interest due for spent nuclear fuel disposal costs, net unamortized premiums and discounts, and other fair value adjustments.  

(b)

Estimated interest payments on fixed-rate debt are calculated by multiplying the coupon rate on the debt by its scheduled notional amount outstanding for the period of measurement.  Estimated interest payments on floating-rate debt are calculated by multiplying the average of the 2012 floating-rate resets on the debt by its scheduled notional amount outstanding for the period of measurement.  This same rate is then assumed for the remaining life of the debt.  

(c)

The capital lease obligations include imputed interest for NU and CL&P.

(d)

Amounts are not included on our consolidated balance sheets.  

(e)

Other than the net mark-to-market changes on derivative contracts held by both the Regulated companies and NU Enterprises, these obligations are not included on our consolidated balance sheets.  

(f)

Does not include unrecognized tax benefits for NU and CL&P as of December 31, 2012, as we cannot make reasonable estimates of the periods or the potential amounts of cash settlement with the respective taxing authorities.  Also does not include an NU contingent commitment of approximately $40 million to an energy investment fund, which would be invested under certain conditions, as we cannot make reasonable estimates of the periods or the investment contributions.  

(g)

Amount represents open purchase orders, excluding those obligations that are included in the capital leases, operating leases and estimated future annual long-term contractual costs.  These payments are subject to change as certain purchase orders include estimates based on projected quantities of material and/or services that are provided on demand, the timing of which cannot be determined.  Because payment timing cannot be determined, we include all open purchase order amounts in 2013.  

(h)

These amounts represent NU's estimated minimum pension contributions to its qualified Pension Plan required under federal legislation.  Contributions in 2014 through 2017 and thereafter will vary depending on many factors, including the performance of existing plan assets, valuation of the plan's liabilities and long-term discount rates, and are subject to change.  

(i)

Excludes other long-term liabilities, including the unrecognized tax benefits described above, deferred contractual obligations, environmental reserves, employee medical insurance reserves ($17.4 million at NU and $11.3 million at CL&P), workers compensation and long-term disability insurance reserves ($50 million at NU and $19.9 million at CL&P) and the ARO liability reserves as we cannot make reasonable estimates of the timing of payments.   

For further information regarding our contractual obligations and commercial commitments, see Note 8, "Short-Term Debt," Note 9, "Long-Term Debt," Note 10A, "Employee Benefits - Pension Benefits and Postretirement Benefits Other Than Pensions," Note 12B, "Commitments and Contingencies - Long-Term Contractual Arrangements," and Note 13, "Leases," to the consolidated financial statements.

RRB amounts are non-recourse to us, have no required payments over the next five years and are not included in this table.  The Regulated companies' standard offer service contracts and default service contracts are also not included in this table.  

Web Site:  Additional financial information is available through our web site at www.nu.com.

53

RESULTS OF OPERATIONS – NORTHEAST UTILITIES AND SUBSIDIARIES

The following table provides the amounts and variances in operating revenues and expense line items for the consolidated statements of income for NU included in this Annual Report on Form 10-K for the years ended December 31, 2012, 2011, and 2010.  The year ended December 31, 2012 amounts include the operations of NSTAR from the date of the merger, April 10, 2012, through December 31, 2012:

Comparison of 2012 to 2011:

			Operating Revenues and Expenses
			For the Years Ended December 31,
(Millions of Dollars)			2012 (a)		2011		Increase/		Percent
							(Decrease)
Operating Revenues			$	6,273.8	$	4,465.7	$	1,808.1	40.5	%
Operating Expenses:
	Purchased Power, Fuel and Transmission			2,084.4		1,657.9		426.5	25.7
	Operations and Maintenance			1,583.1		1,095.4		487.7	44.5
	Depreciation			519.0		302.2		216.8	71.7
	Amortization of Regulatory Assets, Net			79.8		91.1		(11.3)	(12.4)
	Amortization of Rate Reduction Bonds			142.0		69.9		72.1	(b)
	Energy Efficiency Programs			313.1		131.4		181.7	(b)
	Taxes Other Than Income Taxes			434.2		323.6		110.6	34.2
		Total Operating Expenses		5,155.6		3,671.5		1,484.1	40.4
Operating Income			$	1,118.2	$	794.2	$	324.0	40.8	%
(a)		The 2012 results include the operations of NSTAR from the date of the merger, April 10, 2012, through December 31, 2012.
(b)		Percent greater than 100 percent not shown as it is not meaningful.

Operating Revenues
		For the Years Ended December 31,
(Millions of Dollars)		2012 (a)		2011		Increase		Percent
Electric Distribution		$	4,716.5	$	3,343.1	$	1,373.4	41.1	%
Natural Gas Distribution			572.9		430.8		142.1	33.0
	Total Distribution		5,289.4		3,773.9		1,515.5	40.2
Transmission			861.5		635.4		226.1	35.6
	Total Regulated Companies		6,150.9		4,409.3		1,741.6	39.5
Other and Eliminations			122.9		56.4		66.5	(b)
Total Operating Revenues		$	6,273.8	$	4,465.7	$	1,808.1	40.5	%
(a) The 2012 results include the operations of NSTAR from the date of the merger, April 10, 2012, through December 31, 2012.
(b) Percent greater than 100 percent not shown as it is not meaningful.

A summary of our retail electric sales and firm natural gas sales were as follows:
		For the Years Ended December 31,
		2012 (a)	2011	Increase	Percent
Retail Electric Sales in GWh		49,718	33,812	15,906	47.0	%
Firm Natural Gas Sales in Million Cubic Feet		69,894	46,880	23,014	49.1	%
(a) Includes the retail electric and firm natural gas sales of NSTAR from the date of the merger, April 10, 2012, through
	December 31, 2012.

Our Operating Revenues increased in 2012, as compared to 2011, due primarily to the addition of NSTAR, which included electric distribution revenues of approximately $1.7 billion, transmission revenues of approximately $50 million, natural gas revenues of approximately $200 million and other revenues of approximately $15 million, and the consolidation of CYAPC and YAEC revenues of approximately $40 million.  Excluding the impact of NSTAR's operations and the consolidation of CYAPC and YAEC, our Operating Revenues decreased due to the following:

·

Lower electric distribution segment revenues related to the portions that are included in regulatory commission approved tracking mechanisms that recover certain incurred costs and do not impact earnings.  The tracking mechanisms allow for rates to be changed periodically with overcollections refunded to customers or undercollections recovered from customers in future periods.  The tracked electric distribution revenues decreased due primarily to lower energy and supply-related costs ($241.8 million), lower CL&P CTA revenues ($46.3 million), lower wholesale revenues ($44.4 million), lower retail transmission revenues ($17.8 million), partially offset by higher CL&P FMCC delivery-related revenues ($82.4 million), higher SCRC revenues at PSNH ($34.2 million) and higher CL&P retail SBC revenues ($22.5 million).

54

·

A decrease in natural gas segment revenues due primarily to a 4.3 percent decrease in Yankee Gas' sales volume related to the warmer than normal weather in the heating season of 2012, as compared to the heating season of 2011.  In addition, there was a decrease in the cost of natural gas, which is fully recovered in revenues from sales to our customers.

Partially offset by:

·

Improved transmission segment revenues resulting from a higher level of investment in transmission infrastructure and the recovery of higher overall expenses, which are tracked and result in a related increase in revenues.  The increase in expenses is directly related to the increase in transmission plant, primarily at WMECO, including costs associated with higher property taxes, depreciation and operation and maintenance expenses.

·

An increase at PSNH related to the sale of oil to a third party ($20.8 million) in the second quarter of 2012, resulting in a benefit to customers through lower ES rates that does not impact earnings.

·

The portion of electric distribution segment revenues that impacts earnings increased $8.8 million due primarily to CL&P regulatory incentives of $11.5 million and C&LM incentives of $6.2 million at CL&P, partially offset by a decrease in retail electric sales related to the warmer than normal winter weather in 2012, as compared to the winter of 2011.

Purchased Power, Fuel and Transmission increased in 2012, as compared to 2011, due primarily to the following:

	2012 Increase/(Decrease)
(Millions of Dollars)	Compared to 2011
The addition of NSTAR's operations	$	640.0
Lower GSC supply costs, partially offset by higher CfD costs at CL&P		(124.3)
Lower natural gas costs and lower sales at Yankee Gas		(45.4)
Lower purchased transmission costs and lower Basic Service costs at WMECO		(25.4)
Lower purchased power costs, partially offset by higher transmission costs at PSNH		(8.6)
Other and eliminations		(9.8)
	$	426.5

Operations and Maintenance increased in 2012, as compared to 2011, due primarily to the addition of NSTAR's operations, which included operating expenses of $320.8 million and maintenance expense of $50.4 million.  Excluding the impact of NSTAR's operations, Operations and Maintenance increased due primarily to:

·

Higher NU parent and other companies' expenses ($70.1 million) that were due primarily to the increase in costs related to the completion of NU’s merger with NSTAR ($55.9 million) and higher costs at NU’s unregulated contracting business related to an increased level of work in 2012 ($16.3 million).

·

The establishment of a reserve related to major storm restoration costs ($40 million) at CL&P and bill credits to customers at CL&P and WMECO ($25 million and $3 million, respectively) as a result of the Connecticut and Massachusetts settlement agreements.  In addition, there were higher electric distribution business expenses ($31.6 million) mainly as a result of general and administrative expenses primarily related to higher pension costs.  

Partially offsetting these increases was the absence in 2012 of the storm fund reserve established in 2011 to provide bill credits to residential customers as a result of the October 2011 snowstorm and to provide contributions to certain Connecticut charitable organizations ($30 million) at CL&P, a decrease in the amortization of the regulatory deferral allowed in the 2010 rate case decision ($21.4 million) at CL&P and lower maintenance costs at PSNH’s generation business due to less planned outage maintenance in 2012 ($17.8 million).

Depreciation increased in 2012, as compared to 2011, due primarily to the addition of NSTAR's utility plant balances ($148.4 million) and an increase as a result of the consolidation of CYAPC and YAEC ($40.3 million).  Excluding the impact of NSTAR and the consolidation of CYAPC and YAEC, Depreciation increased due primarily to higher utility plant balances resulting from completed construction projects placed into service.

Amortization of Regulatory Assets, Net decreased in 2012, as compared to 2011, due primarily to a decrease in ES and TCAM amortization at PSNH ($46.9 million and $20.2 million, respectively), and higher CTA transition costs ($21.5 million) and lower CTA revenues ($46.3 million) at CL&P.  Partially offsetting these decreases was an increase related to the addition of NSTAR's operations ($87.5 million), lower SBC costs ($7.6 million) and higher retail SBC revenues ($22.5 million) at CL&P, and an increase in SCRC amortization at PSNH ($13.5 million).

Amortization of RRBs increased in 2012, as compared to 2011, due primarily to the addition of NSTAR Electric’s amortization ($67.7 million).

55

Energy Efficiency Programs increased in 2012, as compared to 2011, due primarily to the addition of NSTAR's operations ($169.4 million).  In addition, there was an increase in expenses at WMECO attributable to an increase in spending in accordance with DPU approved energy efficiency programs.  The increase in energy efficiency spending is recovered in rates and therefore does not impact earnings.

Taxes Other Than Income Taxes increased in 2012, as compared to 2011, due primarily to the addition of NSTAR's operations ($96.4 million).  In addition, there was an increase in property taxes as a result of an increase in Property, Plant and Equipment related to our regulated capital programs and an increase in the property tax rates.

Interest Expense
	For the Years Ended December 31,
					Increase/
(Millions of Dollars)	2012 (a)		2011		(Decrease)		Percent
Interest on Long-Term Debt	$	316.9	$	231.6	$	85.3	36.8	%
Interest on RRBs		6.2		8.6		(2.4)	(27.9)
Other Interest		6.8		10.2		(3.4)	(33.3)
	$	329.9	$	250.4	$	79.5	31.7	%

(a) The 2012 results include the operations of NSTAR from the date of the merger, April 10, 2012, through December 31, 2012.

Interest Expense increased in 2012, as compared to 2011, due primarily to the addition of NSTAR's operations ($70.6 million).  The additional increase in Interest on Long-Term Debt was a result of the $260 million in new long-term debt issuances in September 2011 and higher short-term borrowings resulting in higher interest expense.

Other Income, Net
	For the Years Ended December 31,
(Millions of Dollars)	2012 (a)		2011		Decrease		Percent
Other Income, Net	$	19.7	$	27.7	$	(8.0)	(28.9)	%

(a) The 2012 results include the operations of NSTAR from the date of the merger, April 10, 2012, through December 31, 2012.

Other Income, Net decreased in 2012, as compared to 2011, due primarily to lower AFUDC related to equity funds at PSNH as the Clean Air Project was placed into service in September 2011, partially offset by net gains on the NU supplemental benefit trust in 2012, compared to net losses in 2011.

Income Tax Expense
	For the Years Ended December 31,
(Millions of Dollars)	2012 (a)		2011		Increase		Percent
Income Tax Expense	$	274.9	$	171.0	$	103.9	60.8	%

(a) The 2012 results include the operations of NSTAR from the date of the merger, April 10, 2012, through December 31, 2012.

Income Tax Expense increased in 2012, as compared to 2011, due primarily to higher pre-tax earnings ($141.4 million), less favorable adjustments for prior year’s taxes ($21.3 million) and lower items that directly impact our tax return as a result of regulatory actions (flow-through items) ($3.4 million), partially offset by Connecticut and Massachusetts settlement agreement impacts ($41 million) and merger impacts ($19.9 million).

56

Comparison of 2011 to 2010:

			Operating Revenues and Expenses For the Years Ended December 31,
							Increase/
(Millions of Dollars)				2011		2010	(Decrease)				Percent
Operating Revenues			$	4,465.7	$	4,898.2		$	(432.5)	(8.8)		%
Operating Expenses:
	Purchased Power, Fuel and Transmission			1,657.9		2,034.5			(376.6)	(18.5)
	Operations and Maintenance			1,095.4		1,001.4			94.0	9.4
	Depreciation			302.2		300.7			1.5	0.5
	Amortization of Regulatory Assets, Net			91.1		90.1			1.0	1.1
	Amortization of Rate Reduction Bonds			69.9		232.9			(163.0)	(70.0)
	Energy Efficiency Programs			131.4		124.0			7.4	6.0
	Taxes Other Than Income Taxes			323.6		314.7			8.9	2.8
		Total Operating Expenses		3,671.5		4,098.3			(426.8)	(10.4)
Operating Income			$	794.2	$	799.9		$	(5.7)	(0.7)		%

Operating Revenues

		For the Years Ended December 31,
						Increase/
(Millions of Dollars)			2011		2010	(Decrease)				Percent
Electric Distribution		$	3,343.1	$	3,802.0		$	(458.9)	(12.1)		%
Natural Gas Distribution			430.8		434.3			(3.5)	(0.8)
	Total Distribution		3,773.9		4,236.3			(462.4)	(10.9)
Transmission			635.4		625.6			9.8	1.6
	Total Regulated Companies		4,409.3		4,861.9			(452.6)	(9.3)
Other and Eliminations			56.4		36.3			20.1	55.4
NU		$	4,465.7	$	4,898.2		$	(432.5)	(8.8)		%

A summary of our retail electric sales and firm natural gas sales were as follows:

	For the Years Ended December 31,
				Increase/
		2011	2010	(Decrease)		Percent
Retail Electric Sales in GWh		33,812	34,230		(418)	(1.2)	%
Firm Natural Gas Sales in Million Cubic Feet (1)		46,880	43,406		3,474	8.0	%

⁽¹⁾ The 2010 sales volumes for commercial customers have been adjusted to conform to current year presentation.  

Our Operating Revenues decreased in 2011, as compared to 2010, due primarily to:

·

Lower electric distribution segment revenues related to the portions that are included in regulatory commission approved tracking mechanisms that recover certain incurred costs and do not impact earnings.  The tracking mechanisms allow for rates to be changed periodically with overcollections refunded to customers or undercollections recovered from customers in future periods.  The tracked electric distribution revenues decreased due primarily to lower energy and supply-related costs ($365.3 million), lower CTA revenues and stranded cost recoveries ($175.3 million), lower wholesale revenues ($85.2 million) and lower retail other revenues ($37.9 million), partially offset by higher CL&P FMCC delivery-related revenues ($28.6 million), higher retail transmission revenues ($12.2 million) and higher other tracked revenues ($28.7 million).  

Partially offset by:

·

The portion of electric distribution segment revenues that impacts earnings increased $135.5 million due primarily to the rate case decisions that were effective during 2011.  

·

Improved transmission segment revenues resulting from a higher level of investment in transmission infrastructure and the recovery of higher overall expenses, which are tracked and result in a related increase in revenues.  The increase in expenses is directly related to the increase in transmission plant, including costs associated with higher property taxes, depreciation and operation and maintenance expenses.  These were partially offset by a refund to transmission wholesale customers, compared to a recovery from those customers in 2010.  The transmission rates provide for an annual reconciliation and recovery or refund of projected costs to actual costs.  The difference between projected costs and actual costs are recovered from, or refunded to, customers each year.

57

Purchased Power, Fuel and Transmission decreased in 2011, as compared to 2010, due primarily to the following:

		2011 Increase/(Decrease)
(Millions of Dollars)		Compared to 2010
Lower GSC supply costs and purchased power costs,
	partially offset by higher CfD and other costs at CL&P	$	(310.2)
Lower energy prices, a slight increase in ES customer
	migration to third party suppliers and lower retail sales for PSNH's
	remaining ES customers		(61.6)
Lower Basic Service costs at WMECO			(14.1)
Lower natural gas costs at Yankee Gas			(15.1)
Other and eliminations			24.4
		$	(376.6)

Operations and Maintenance increased in 2011, as compared to 2010, due primarily to:

·

Higher electric distribution expenses ($50.4 million) and higher natural gas expenses ($3.8 million), primarily related to CL&P’s establishment of a $30 million storm fund reserve to provide bill credits to its residential customers who remained without power after noon on Saturday, November 5, 2011, as a result of the October 2011 snowstorm and to provide contributions to certain Connecticut charitable organizations.  There were also higher boiler equipment and maintenance costs at PSNH’s generation business related to the absence in 2011 of insurance proceeds received in 2010 related to turbine damage, which reduced 2010 costs ($7.4 million).  In addition, there were higher pension costs and higher general and administrative expenses.  Partially offsetting these increases were lower costs that are recovered through distribution tracking mechanisms that have no earnings impact ($17.7 million), such as uncollectible expenses and customer Energy Independence Act incentives.  In addition, there were lower transmission segment expenses ($8.1 million).

·

The partial amortization in 2011 of the allowed regulatory deferral, which was recorded in maintenance expense in 2010, as a result of the June 30, 2010 CL&P rate case decision ($54.9 million).

·

Higher NU parent and other companies expenses ($27.3 million) due primarily to higher costs at NU’s unregulated electrical contracting business related to an increased level of work in 2011 ($19.6 million), partially offset by a decrease in costs related to NU's then pending merger with NSTAR ($2.1 million).

Depreciation increased in 2011, as compared to 2010, due primarily to higher depreciation rates being used at PSNH and WMECO in 2011 as a result of distribution rate case decisions that were effective during 2011 and higher utility plant balances resulting from completed construction projects placed into service.  Partially offsetting these increases was a lower depreciation rate being used at CL&P as a result of the distribution rate case decision that was effective July 1, 2010.  

Amortization of Regulatory Assets, Net increased in 2011, as compared to 2010, due primarily to lower CTA transition costs ($197.7 million) partially offset by lower retail CTA revenue ($154.6 million) at CL&P, the absence in 2011 of the impact from the 2010 Healthcare Act related to income taxes ($26 million) and increases in ES amortization ($11.4 million) and TCAM amortization ($5.9 million) at PSNH.  Partially offsetting these increases was lower amortization related to the previously deferred unrecovered stranded generation costs at CL&P ($38.2 million) and lower amortization of the SBC balance at CL&P ($29.7 million).

Amortization of Rate Reduction Bonds decreased in 2011, as compared to 2010, due to the maturity of CL&P’s RRBs in December 2010 and lower principal balances on the remaining PSNH and WMECO RRBs outstanding.

Energy Efficiency Programs increased in 2011, as compared to 2010, due primarily to an increase in expenses attributable to an increase in spending in accordance with DPU approved energy efficiency programs at WMECO.

Taxes Other Than Income Taxes increased in 2011, as compared to 2010, due primarily to an increase in property taxes as a result of an increase in Property, Plant and Equipment related to our capital program and an increase in the tax rate, offset by a decrease in the Connecticut Gross Earnings Tax due primarily to lower transmission segment revenues and lower CTA revenues in 2011, as compared to 2010.

Interest Expense
	For the Years Ended December 31,
					Increase/
(Millions of Dollars)	2011		2010		(Decrease)		Percent
Interest on Long-Term Debt	$	231.6	$	231.1	$	0.5	0.2	%
Interest on RRBs		8.6		20.6		(12.0)	(58.3)
Other Interest		10.2		(14.4)		24.6	(a)
	$	250.4	$	237.3	$	13.1	5.5	%

(a) Percent greater than 100 percent not shown since it is not meaningful.

58

Interest Expense increased in 2011, as compared to 2010, due primarily to higher Other Interest in 2011, as compared to 2010, due to the prior year inclusion of a tax-related benefit, partially offset by lower Interest on RRBs in 2011, as compared to 2010, resulting from the maturity of CL&P’s RRBs in December 2010 and lower principal balances on the remaining PSNH and WMECO RRBs outstanding.

Other Income, Net
	For the Years Ended December 31,
(Millions of Dollars)	2011		2010		Decrease		Percent
Other Income, Net	$	27.7	$	41.9	$	(14.2)	(33.9)	%

Other Income, Net decreased in 2011, as compared to 2010, due primarily to net losses on the NU supplemental benefit trust in 2011, compared to net gains in 2010, and the 2011 classification of C&LM and Energy Independence Act incentives; partially offset by higher AFUDC related to equity funds.

Income Tax Expense
	For the Years Ended December 31,
(Millions of Dollars)	2011		2010		Decrease		Percent
Income Tax Expense	$	171.0	$	210.4	$	(39.4)	(18.7)	%

Income Tax Expense decreased in 2011, as compared to 2010, due primarily to the absence in 2011 of the impact from the 2010 Healthcare Act ($25.2 million), adjustments for prior year's taxes including adjustments to reconcile estimated taxes accrued to actual amounts reflected in our filed tax returns (return to provision adjustments) ($16.3 million), lower flow-through items ($4.6 million) and lower pre-tax earnings ($2.1 million); partially offset by higher state income taxes ($9.6 million).

59

RESULTS OF OPERATIONS – THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARY

The following table provides the amounts and variances in operating revenues and expense line items for the consolidated statements of income for CL&P included in this Annual Report on Form 10-K for the years ended December 31, 2012, 2011, and 2010:

Comparison of 2012 to 2011:

			Operating Revenues and Expenses
			For the Years Ended December 31,
(Millions of Dollars)			2012		2011		Increase/		Percent
							(Decrease)
Operating Revenues			$	2,407.4	$	2,548.4	$	(141.0)	(5.5)	%
Operating Expenses:
	Purchased Power and Transmission			858.2		982.5		(124.3)	(12.7)
	Operations and Maintenance			635.7		580.7		55.0	9.5
	Depreciation			166.9		157.8		9.1	5.8
	Amortization of Regulatory Assets, Net			14.4		61.0		(46.6)	(76.4)
	Energy Efficiency Programs			89.3		90.3		(1.0)	(1.1)
	Taxes Other Than Income Taxes			215.9		212.9		3.0	1.4
		Total Operating Expenses		1,980.4		2,085.2		(104.8)	(5.0)
Operating Income			$	427.0	$	463.2	$	(36.2)	(7.8)	%

Operating Revenues
CL&P's retail sales were as follows:
	For the Years Ended December 31,
	2012	2011	Decrease	Percent
Retail Sales in GWh	22,109	22,315	(206)	(0.9)	%

CL&P's Operating Revenues decreased in 2012, as compared to 2011, due primarily to:

·

A $133.6 million decrease in distribution revenues related to the portions that are included in PURA approved tracking mechanisms that recover certain incurred costs and do not impact earnings.  The tracking mechanisms allow for rates to be changed periodically with overcollections refunded to customers or undercollections recovered from customers in future periods.  The tracked distribution revenues decreased due primarily to lower GSC and FMCC supply-related revenues ($150.8 million), lower CTA revenues ($46.3 million), lower wholesale revenues ($33.5 million), and lower retail transmission revenues ($4.3 million).  The lower GSC and FMCC supply-related revenues were due primarily to lower customer rates resulting from lower average supply prices and lower sales related to additional customer migration to third party electric suppliers in 2012.  Partially offsetting these decreases were higher FMCC delivery-related revenues ($82.4 million) and higher retail SBC revenues ($22.5 million).

Partially offset by:

·

A $7.6 million increase in the portion of distribution revenues that impacts earnings in 2012, compared to 2011, due primarily to regulatory incentives of $11.5 million and C&LM incentives of $6.2 million, partially offset by lower sales volume related to warmer than normal winter weather in 2012, as compared to the winter of 2011.

·

A $7.2 million increase in transmission revenues resulting from an increased level of investment in transmission infrastructure and the recovery of higher overall expenses, which are subject to tracking mechanisms or processes (tracked) and result in a related increase in revenues.  The increase in expenses is directly related to the increase in transmission plant, including costs associated with higher property taxes, depreciation and operation and maintenance expenses.

Purchased Power and Transmission decreased in 2012, as compared to 2011, due primarily to the following:

	2012 Increase/(Decrease)
(Millions of Dollars)	Compared to 2011
GSC Supply Costs	$	(112.0)
Deferred Fuel Costs		(33.4)
Transmission Costs		(26.8)
Purchased Power Contracts		(19.4)
CfD Costs		70.7
Other		(3.4)
	$	(124.3)

The decrease in GSC supply costs was due to lower average supply prices and lower sales.  The lower sales were due primarily to additional customer migration to third party electric suppliers.  These GSC supply costs are the contractual amounts CL&P must pay to

60

various suppliers that have been awarded the right to supply SS and LRS load through a competitive solicitation process.  These costs are included in PURA approved tracking mechanisms and do not impact earnings.

Operations and Maintenance increased in 2012, as compared to 2011, due primarily to the establishment of a reserve related to major storm restoration costs ($40 million) and a bill credit to customers ($25 million) in the second quarter of 2012 as a result of the Connecticut settlement agreement.  In addition, there were higher distribution business expenses as a result of higher general and administrative expenses primarily related to an increase in pension costs ($20.2 million) and higher routine distribution maintenance ($19.4 million).  There were also higher distribution costs related to customer Energy Independence Act incentives, which are tracked and fully recoverable through tracking mechanisms ($6.5 million).  Partially offsetting these increases was the absence in 2012 of the storm fund reserve established in 2011 to provide bill credits to residential customers as a result of the October 2011 snowstorm ($30 million) and a decrease in the amortization of the regulatory deferral allowed in the 2010 rate case decision ($21.4 million).

Depreciation increased in 2012, as compared to 2011, due primarily to higher utility plant balances resulting from completed construction projects placed into service related to CL&P’s capital programs.

Amortization of Regulatory Assets, Net decreased in 2012, as compared to 2011, due primarily to higher CTA transition costs ($21.5 million) and lower CTA revenues ($46.3 million).  Partially offsetting these impacts were lower SBC costs ($7.6 million) and higher retail SBC revenues ($22.5 million).

Interest Expense
	For the Years Ended December 31,
					Increase/
(Millions of Dollars)	2012		2011		(Decrease)		Percent
Interest on Long-Term Debt	$	124.9	$	131.9	$	(7.0)	(5.3)	%
Other Interest		8.2		0.8		7.4	(a)
	$	133.1	$	132.7	$	0.4	0.3	%

(a) Percent greater than 100 percent not shown since it is not meaningful.

Interest on Long-Term Debt decreased in 2012, as compared to 2011, due primarily to the refinancing of the PCRBs at a lower interest rate in October 2011.  Other Interest increased in 2012, as compared to 2011, due primarily to the absence of tax-related benefits recognized in 2011 and an increase in short-term borrowings resulting in higher interest expense.

Income Tax Expense

	For the Years Ended December 31,
(Millions of Dollars)	2012		2011		Increase		Percent
Income Tax Expense	$	94.4	$	90.0	$	4.4	4.9	%

Income Tax Expense increased in 2012, as compared to 2011, due primarily to less favorable adjustments for prior year’s taxes ($22.4 million), an increase to pre-tax earnings ($13.8 million), partially offset by Connecticut settlement agreement impacts ($26.6 million), and lower state tax and other impacts ($5.2 million).

61

Comparison of 2011 to 2010:

			Operating Revenues and Expenses For the Years Ended December 31,
(Millions of Dollars)			2011		2010		Increase/ (Decrease)		Percent
Operating Revenues			$	2,548.4	$	2,999.1	$	(450.7)	(15.0)	%
Operating Expenses:
	Purchased Power and Transmission			982.5		1,292.7		(310.2)	(24.0)
	Operations and Maintenance			580.7		494.2		86.5	17.5
	Depreciation			157.8		172.1		(14.3)	(8.4)
	Amortization of Regulatory Assets, Net			61.0		78.9		(17.9)	(22.7)
	Amortization of Rate Reduction Bonds			-		167.0		(167.0)	(100.0)
	Energy Efficiency Programs			90.3		92.3		(2.0)	(2.2)
	Taxes Other Than Income Taxes			212.9		214.2		(1.3)	(0.6)
		Total Operating Expenses		2,085.2		2,511.4		(426.2)	(17.0)
Operating Income			$	463.2	$	487.7	$	(24.5)	(5.0)	%

Operating Revenues

CL&P's retail sales were as follows:

	For the Years Ended December 31,
	2011		2010		Decrease		Percent
Retail Sales in GWh		22,315		22,666		(351)	(1.5)	%

CL&P's Operating Revenues decreased in 2011, as compared to 2010, due primarily to:

·

A $545.4 million decrease in distribution revenues related to the portions that are included in PURA approved tracking mechanisms that recover certain incurred costs and do not impact earnings.  The tracked distribution revenues decreased due primarily to lower GSC and FMCC supply-related revenues ($316.4 million), lower CTA revenues ($165.5 million), lower wholesale revenues ($81.7 million) and lower retail other revenues ($38.4 million).  The lower GSC and FMCC supply-related revenues were due primarily to lower customer rates resulting from lower average supply prices and additional customer migration to third party electric suppliers in 2011, as compared to 2010.  These lower revenues were partially offset by higher FMCC delivery-related revenues ($28.6 million) and higher retail transmission revenues ($14 million).  The tracking mechanisms allow for rates to be changed periodically with overcollections refunded to customers or undercollections recovered from customers in future periods.  

·

A $15.7 million decrease in transmission segment revenues was due primarily to a refund to transmission wholesale customers, compared to a recovery from those customers in 2010.  The transmission rates provide for an annual reconciliation and recovery or refund of projected costs to actual costs.  The difference between projected costs and actual costs are recovered from, or refunded to, customers each year.  This decrease was partially offset by increased transmission segment revenues due to a higher level of investment in the transmission infrastructure.

Partially offset by:

·

The portion of distribution revenues that impacts earnings increased $110.4 million in 2011, as compared to 2010, due primarily to the retail rate increase effective January 1, 2011.

Purchased Power and Transmission decreased in 2011, as compared to 2010, due primarily to the following:

	2011 Increase/(Decrease)
(Millions of Dollars)	Compared to 2010
GSC Supply Costs	$	(325.8)
Purchased Power Costs		(60.4)
CfD Costs		54.9
Transmission Costs		13.2
Deferred Fuel Costs		10.5
Other		(2.6)
	$	(310.2)

The decrease in GSC supply costs was due primarily to lower average supply prices and additional customer migration to third party electric suppliers in 2011, as compared to 2010.  These GSC supply costs are the contractual amounts CL&P must pay to various suppliers that have been awarded the right to supply SS and LRS load through a competitive solicitation process.  These costs are included in PURA approved tracking mechanisms and do not impact earnings.

Operations and Maintenance increased in 2011, as compared to 2010, as a result of higher distribution expenses ($60.4 million).  Included in these costs was the establishment of a $30 million storm fund reserve to provide bill credits to its residential customers who

62

remained without power after noon on Saturday, November 5, 2011, as a result of the October 2011 snowstorm and to provide contributions to certain Connecticut charitable organizations, higher general and administrative expenses, including higher pension costs.  In addition, there was an increase related to the partial amortization in 2011 of the allowed regulatory deferral, which was recorded in maintenance expense in 2010, as a result of the June 30, 2010 rate case decision ($54.9 million).  Partially offsetting these increases were lower costs that are recovered through distribution tracking mechanisms and have no earnings impact ($16.4 million) and lower transmission segment expenses ($7.4 million).

Depreciation decreased in 2011, as compared to 2010, due primarily to a lower depreciation rate being used as a result of the 2010 distribution rate case decision that was effective July 1, 2010, partially offset by higher utility plant balances resulting from completed construction projects placed into service.

Amortization of Regulatory Assets, Net decreased in 2011, as compared to 2010, due primarily to lower amortization related to the previously deferred unrecovered stranded generation costs ($38.2 million) and lower amortization of the SBC balance ($29.7 million).  Partially offsetting these decreases were lower CTA transition costs ($197.7 million), partially offset by lower retail CTA revenue ($154.6 million), and the absence in 2011 of the impact from the 2010 Healthcare Act related to income taxes ($12 million).

Amortization of Rate Reductions Bonds decreased in 2011, as compared to 2010, due to the maturity of RRBs in December 2010.

Taxes Other Than Income Taxes decreased in 2011, as compared to 2010, due primarily to a decrease in the Connecticut Gross Earnings Tax due primarily to lower transmission segment revenues and lower CTA revenues in 2011, as compared to 2010, partially offset by an increase in property taxes as a result of an increase in Property, Plant and Equipment related to CL&P’s capital program and an increase in the tax rate.

Interest Expense

	For the Years Ended December 31,
(Millions of Dollars)	2011		2010		Increase/ (Decrease)		Percent
Interest on Long-Term Debt	$	131.9	$	134.6	$	(2.7)	(2.0)	%
Interest on RRBs		-		7.5		(7.5)	(100.0)
Other Interest		0.8		(4.4)		5.2	(a)
	$	132.7	$	137.7	$	(5.0)	(3.6)	%

(a) Percent greater than 100 percent not shown since it is not meaningful

Interest Expense decreased in 2011, as compared to 2010, due primarily to the absence of Interest on RRBs in 2011, as CL&P's RRBs matured in December 2010, and lower Interest on Long-Term Debt in 2011 related to lower interest rates on the refinancing of the PCRBs.  Partially offsetting these decreases was higher Other Interest in 2011, as compared to 2010, due to the prior year inclusion of a tax-related benefit.

Other Income, Net

	For the Years Ended December 31,
(Millions of Dollars)	2011		2010			Decrease	Percent
Other Income, Net	$	9.7	$	26.7	$	(17.0)	(63.7)	%

Other Income, Net decreased in 2011, as compared to 2010, due primarily to net losses on the NU supplemental benefit trust in 2011, compared to net gains in 2010, as well as the 2011 classification of C&LM and Energy Independence Act incentives.

Income Tax Expense

	For the Years Ended December 31,
(Millions of Dollars)	2011		2010		Decrease		Percent
Income Tax Expense	$	90.0	$	132.4	$	(42.4)	(32.0)	%

Income Tax Expense decreased in 2011, as compared to 2010, due primarily to the absence in 2011 of the impact from the 2010 Healthcare Act ($13.2 million), adjustments for prior year’s taxes including return to provision ($16.7 million), a decrease in pre-tax earnings ($7.3 million) and lower flow-through and other impacts ($5.2 million).

LIQUIDITY

CL&P had cash flows provided by operating activities of $211.9 million in 2012, compared with cash flows provided by operating activities of $513.3 million in 2011.  The reduced cash flows were due primarily to $223.1 million of cash disbursements for storm restoration costs primarily associated with Tropical Storm Irene, the October 2011 snowstorm, and Hurricane Sandy made in 2012, as compared to approximately $132 million in 2011, $27 million in bill credits provided to residential customers in February 2012 related to the October 2011 snowstorm, $25 million in bill credits to customers associated with the Connecticut settlement agreement and changes in traditional working capital amounts principally due to the changes in the timing of payments of accounts payable and accrued liabilities. In addition, CL&P had lower recovery of its deferred operation and maintenance costs of $23.1 million in 2012, as

63

compared to 2011, a negative cash flow impact of $38.9 million resulting from changes in reserves for transmission refunds in 2012, as compared to 2011, and a decrease in income tax refunds of $14.6 million in 2012, as compared to 2011.

CL&P had cash flows provided by operating activities in 2011 of $513.3 million, compared with operating cash flows of $501.7 million in 2010 (2010 amount is net of RRB payments, which is included in financing activities).  The improved cash flows in 2011 were due primarily to the impact of the PURA July 1, 2010 distribution rate case decision, which increased CL&P’s customer rates effective January 1, 2011, and income tax receipts in 2011 of $27.5 million largely attributable to accelerated depreciation tax benefits, compared to income tax payments of $71.5 million in 2010.  Offsetting these benefits was approximately $132 million of cash disbursements for storm restoration costs associated with Tropical Storm Irene and the October 2011 snowstorm.  

Cash capital expenditures included on the accompanying consolidated statements of cash flows do not include amounts incurred on capital projects but not yet paid, cost of removal, the AFUDC related to equity funds, and the capitalized portions of pension and PBOP expense or income.  CL&P's cash capital expenditures totaled $449.1 million in 2012, compared with $424.9 million in 2011.  

On March 22, 2012, the FERC approved CL&P's application requesting to increase its total short-term borrowing capacity from a maximum of $450 million to a maximum of $600 million through December 31, 2013.

On March 26, 2012, CL&P entered into a five-year $300 million unsecured revolving credit facility.  The credit facility is intended to finance short-term borrowings that CL&P incurred to fund costs of restoring power following Tropical Storm Irene and the October 2011 snowstorm.  Under this new facility, CL&P can borrow either on a short-term or a long-term basis subject to any necessary regulatory approval, and may borrow at prime rates or LIBOR-based rates, plus an applicable margin based on the higher of S&P’s or Moody’s credit ratings.  As of December 31, 2012, CL&P had $89 million in borrowings outstanding under this credit facility.  The weighted-average interest rate on these borrowings as of December 31, 2012 was 3.325 percent.  

On April 2, 2012, CL&P remarketed $62 million of tax-exempt PCRBs that were subject to mandatory tender on that date.  The PCRBs, which mature on May 1, 2031, carry a coupon rate of 1.55 percent during the current three-year fixed-rate period, and are subject to mandatory tender for purchase on April 1, 2015.

On July 25, 2012, NU, CL&P, NSTAR LLC, NSTAR Gas, PSNH, WMECO, and Yankee Gas jointly entered into a five-year $1.15 billion revolving credit facility.  The new facility replaced (1) the NSTAR LLC revolving credit facility of $175 million that served to backstop a commercial paper program utilized by NSTAR LLC and was scheduled to expire on December 31, 2012, (2) the NSTAR Gas revolving credit facility of $75 million that expired on June 8, 2012, and (3) the CL&P, PSNH, WMECO, and Yankee Gas joint $400 million and NU parent $500 million unsecured revolving credit facilities that were scheduled to expire on September 24, 2013.  The new facility expires on July 25, 2017.  As of December 31, 2012, CL&P had $405.1 million in intercompany short-term borrowings under the NU commercial paper program.  The weighted average interest rate on these borrowings as of December 31, 2012 was 0.46 percent.

On October 1, 2012, CL&P redeemed at par four different series of tax-exempt PCRBs totaling $116.4 million.  The PCRBs carried coupons that ranged from 5.85 percent to 5.95 percent and maturities that ranged from 2016 through 2028.

On January 15, 2013, CL&P issued $400 million of 2.5 percent first mortgage bonds that will mature on January 15, 2023.  The proceeds, net of issuance costs, were used to repay CL&P’s revolving credit facility borrowings of $89 million and $305.8 million of its commercial paper program borrowings.

Financing activities in 2012 included $100.5 million in common stock dividends paid to NU parent, an increase in intercompany short-term borrowings of $346.6 million, and an increase in short-term notes payable of $58 million.

CL&P uses available capital resources to fund its construction expenditures, meet debt requirements, pay costs, including storm-related costs, pay dividends and fund its other obligations.  The current growth in CL&P’s transmission construction expenditures utilizes a significant amount of cash for projects that have a long-term return on investment and recovery period.  In addition, CL&P operates in an environment where recovery of its distribution construction expenditures takes place over an extended period of time.  As well, the future recovery of its deferred storm-related costs, which must be approved by the PURA, will take place over a six-year period for those costs deferred as a result of 2011 activity (as covered by the Connecticut Settlement Agreement) and over an extended period of time for those storm restoration costs incurred related to Hurricane Sandy.  This impacts the timing of the revenue stream designed to fully recover the total investment plus a return on the equity portion of the cost and related financing costs.  These factors have resulted in CL&P’s current liabilities exceeding current assets by approximately $268 million as of December 31, 2012.

As of December 31, 2012, $125 million of CL&P's current liabilities relates to long-term debt that will be paid in the next 12 months.  CL&P, with its strong credit ratings, has several options available in the financial markets to repay or refinance these maturities with the issuance of new long-term debt.  CL&P will reduce its short-term borrowings with cash received from operating cash flows or with the issuance of new long-term debt, as deemed appropriate given our capital requirements and maintenance of our credit rating and profile.  Management expects the future operating cash flows of CL&P, along with the access to financial markets, will be sufficient to meet any future operating requirements and capital investment forecasted opportunities.

64

RESULTS OF OPERATIONS – NSTAR ELECTRIC COMPANY AND SUBSIDIARIES

The following table provides the amounts and variances in operating revenues and expense line items for the consolidated statements of income for NSTAR Electric included in this Annual Report on Form 10-K for the years ended December 31, 2012, 2011, and 2010:

			Operating Revenues and Expenses
			For the Years Ended December 31,
(Millions of Dollars)			2012		2011		Increase/		Percent
							(Decrease)
Operating Revenues			$	2,301.0	$	2,403.1	$	(102.1)	(4.2)	%
Operating Expenses:
	Purchased Power and Transmission			788.3		905.2		(116.9)	(12.9)
	Operations and Maintenance			431.8		387.5		44.3	11.4
	Depreciation			171.1		163.4		7.7	4.7
	Amortization of Regulatory Assets, Net			117.7		83.0		34.7	41.8
	Amortization of Rate Reduction Bonds			90.3		90.3		-	-
	Energy Efficiency Programs			201.2		175.7		25.5	14.5
	Taxes Other Than Income Taxes			119.2		111.8		7.4	6.6
		Total Operating Expenses		1,919.6		1,916.9		2.7	0.1
Operating Income			$	381.4	$	486.2	$	(104.8)	(21.6)	%

Operating Revenues
NSTAR Electric's retail sales were as follows:
	For the Years Ended December 31,
	2012		2011		Decrease		Percent
Retail Sales in GWh		21,209		21,502		(293)	(1.4)	%

NSTAR Electric's Operating Revenues decreased in 2012, as compared to 2011, due primarily to:

·

A $104.7 million decrease in distribution revenues related to the portions that are included in DPU approved tracking mechanisms that recover certain incurred costs and do not impact earnings.  The tracking mechanisms allow for rates to be changed periodically with overcollections refunded to customers or undercollections recovered from customers in future periods.  This decrease primarily related to lower purchased power and transmission costs ($34.2 million), lower retail transmission revenues ($19.8 million), lower PAM revenues ($19.1 million), lower transition revenues ($14.7 million), partially offset by an increase in energy efficiency program revenues ($8.3 million).

Partially offset by:

·

A $2.8 million increase in transmission revenues resulting from an increased level of investment in transmission infrastructure and the recovery of higher overall expenses, which are tracked and result in a related increase in revenues.  The increase in expenses is directly related to the increase in transmission plant, including costs associated with higher property taxes, depreciation and operation and maintenance expenses.

Purchased Power and Transmission decreased in 2012, as compared to 2011, due primarily to the following:  

	2012 Increase/(Decrease)
(Millions of Dollars)	Compared to 2011
Basic Service Costs	$	(53.8)
Purchased Power Contracts		(45.5)
Transmission Costs		(29.6)
Deferred Fuel Costs		15.7
Other		(3.7)
	$	(116.9)

The decrease in Basic Service costs was due primarily to lower average supply prices and additional customer migration to third party electric suppliers and the decrease in purchased power contracts was due primarily to the expiration of certain contracts.  The decrease in transmission costs was due primarily to a lower transmission cost deferral that will be recovered in future periods.  The increase in deferred fuel costs was due primarily to lower average supply prices, as compared to the prices projected when Basic Service rates were set.  These costs are included in DPU approved tracking mechanisms and do not impact earnings.

65

Operations and Maintenance increased in 2012, as compared to 2011, due primarily to the cumulative adjustment recorded to establish a reserve against the regulatory asset related to Basic Service bad debt costs ($28 million).  In addition, first quarter 2012 adjustments were recognized for changes in accounting estimates related primarily to the allowance for doubtful accounts, workers’ compensation, employee medical benefits, and general liability claims ($18.7 million).  In addition, a bill credit to customers ($15 million) was recorded in the second quarter of 2012 as a result of the Massachusetts settlement agreement.  Also contributing to the increase in costs was an incident in March 2012 involving a substation fire in theBack Bay/Prudential area of Boston ($11.8 million).  These increases were partially offset by lower PAM-related amortizations ($23.1 million).

Amortization of Regulatory Assets, Net, increased in 2012, as compared to 2011, due primarily to higher amortization related to transition costs.

Energy Efficiency Programs increased in 2012, as compared to 2011, due primarily to the establishment of a reserve to reflect a billing adjustment made in the fourth quarter of 2012, and an increase in energy efficiency costs in accordance with the three-year program guidelines established by the DPU.  All costs are fully recovered through DPU tracking mechanisms and therefore do not impact earnings.

Interest Expense

	For the Years Ended December 31,
					Increase/
(Millions of Dollars)	2012		2011		(Decrease)		Percent
Interest on Long-Term Debt	$	87.1	$	90.0	$	(2.9)	(3.2)	%
Interest on RRBs		3.6		7.2		(3.6)	(50.0)
Other Interest		(20.6)		(27.8)		7.2	25.9
	$	70.1	$	69.4	$	0.7	1.0	%

Other Interest expense increased in 2012, as compared to 2011, due primarily to a reduction in regulatory interest income primarily from deferred transition costs ($5.9 million) and reduced interest income from legal matters ($3.2 million), partially offset by a decrease in the interest expense related to tax issues ($2 million) due to the receipt of a 2001 through 2007 tax settlement in June 2011.

Income Tax Expense

	For the Years Ended December 31,
(Millions of Dollars)	2012		2011		Decrease		Percent
Income Tax Expense	$	124.0	$	165.7	$	(41.7)	(25.2)	%

Income Tax Expense decreased in 2012, as compared to 2011, due primarily to lower pre-tax earnings ($33.6 million), Massachusetts settlement agreement impacts ($5.9 million) and merger impacts ($1.2 million).

EARNINGS SUMMARY

	For the Years Ended December 31,
(Millions of Dollars)		2012		2011		2010
Income Before Merger Settlement
Agreement Costs	$	201.1	$	252.5	$	248.6
Merger Settlement Agreement
Costs (after-tax)		(10.9)		-		-
Net Income	$	190.2	$	252.5	$	248.6

The after-tax merger settlement agreement costs in 2012 consisted of approximately $17.9 million (pre-tax) of charges for customer bill credits related to the Massachusetts settlement agreement, transaction and integration-related costs, and compensation costs.

Excluding the merger settlement agreement costs, NSTAR Electric’s 2012 earnings were $51.4 million lower than 2011 due primarily to the first quarter 2012 adjustments recorded to establish a reserve against the regulatory asset related to Basic Service bad debt costs ($17 million), and for changes in accounting estimates related primarily to the allowance for doubtful accounts, workers’ compensation, employee medical benefits, and general liability claims ($11.4 million).  Also contributing to the increase in costs was an incident in March 2012 involving a substation fire in theBack Bay/Prudential area of Boston ($7.2 million), a reserve recorded relating to lost base revenues based on developments during hearings in the merger proceeding ($3 million) and higher depreciation and property taxes ($17.3 million).  These factors are partially offset by higher transmission revenues due to an increased level of investment in transmission infrastructure ($6.2 million).

66

NSTAR Electric’s 2011 earnings were $252.5 million, compared to $248.6 million in 2010.  Major factors on an after-tax basis that contributed to the $3.9 million, increase include:

·

higher transmission revenues ($10.9 million);

·

higher lost base revenues and performance incentives related to the impacts of the Energy Efficiency Programs ($7 million); and

·

the absence in 2011 of the cumulative impact of a true-up adjustment resulting from a DPU order in May 2010 related to NSTAR Electric’s transition revenue for the years 2006 through 2009 ($3 million).

These increases were partially offset by:

·

lower distribution revenues (0.7 percent decrease in sales) due to cooler summer weather in 2011, as compared to the summer of 2010, and the impact of energy conservation programs ($5.4 million);

·

higher depreciation and property taxes ($7.3 million); and

·

higher operations and maintenance expenses ($8.8 million).  

CAPITAL EXPENDITURES

A summary of capital expenditures, including amounts incurred but not paid, cost of removal, AFUDC, and the capitalized portions of pension and PBOP expense or income, is as follows:

	For the Years Ended December 31,
(Millions of Dollars)		2012		2011		2010
Transmission	$	192.1	$	162.5	$	87.2
Distribution:
Basic Business		64.2		58.5		54.7
Aging Infrastructure		145.8		132.8		124.2
Load Growth		21.2		19.3		18.0
Total Distribution		231.2		210.6		196.9
Total	$	423.3	$	373.1	$	284.1

LIQUIDITY

NSTAR Electric had cash flows provided by operating activities of $506.9 million in 2012 and $662 million in 2011 (amounts are net of RRB payments, which are included in financing activities).  The decreased cash flows in 2012 were due primarily to the absence in 2012 of income tax refunds received during 2011.  In 2012, NSTAR Electric made income tax payments of $88.1 million, as compared to income tax refunds of $62.2 million in 2011.  In addition, NSTAR Electric provided $15 million in bill credits to its customers associated with the Massachusetts settlement agreement in 2012, and had regulatory undercollections of retail transmission revenues of $53 million in 2012, as compared to 2011.  Partially offsetting these negative cash flow impacts was a reduction in Pension Plan contributions of $100 million in 2012, as compared to 2011.

67

RESULTS OF OPERATIONS – PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES

The following table provides the amounts and variances in operating revenues and expense line items for the consolidated statements of income for PSNH included in this Annual Report on Form 10-K for the years ended December 31, 2012 and 2011:

			Operating Revenues and Expenses
			For the Years Ended December 31,
(Millions of Dollars)			2012		2011		Increase/		Percent
							(Decrease)
Operating Revenues			$	988.0	$	1,013.0	$	(25.0)	(2.5)	%
Operating Expenses:
	Purchased Power, Fuel and Transmission			319.3		327.9		(8.6)	(2.6)
	Operations and Maintenance			263.2		278.2		(15.0)	(5.4)
	Depreciation			87.6		76.1		11.5	15.1
	Amortization of Regulatory Assets/(Liabilities), Net			(24.1)		25.4		(49.5)	(a)
	Amortization of Rate Reduction Bonds			56.6		53.4		3.2	6.0
	Energy Efficiency Programs			14.2		12.9		1.3	10.1
	Taxes Other Than Income Taxes			66.1		59.0		7.1	12.0
		Total Operating Expenses		782.9		832.9		(50.0)	(6.0)
Operating Income			$	205.1	$	180.1	$	25.0	13.9	%
(a) Percent greater than 100 percent not shown as it is not meaningful.

Operating Revenues
PSNH's retail sales were as follows:
	For the Years Ended December 31,
	2012	2011	Increase	Percent
Retail Sales in GWh	7,821	7,815	6	0.1	%

PSNH's Operating Revenues decreased in 2012, as compared to 2011, due primarily to:

·

A $52.7 million decrease in distribution revenues related to the portions that are included in NHPUC approved tracking mechanisms that recover certain incurred costs and do not impact earnings.  The tracking mechanisms allow for rates to be changed periodically with overcollections refunded to customers or undercollections recovered from customers in future periods.  This decrease related primarily to lower purchased power and fuel costs ($88.3 million), lower wholesale revenues ($7.3 million) and lower retail transmission revenues ($5.8 million).  These lower revenues were partially offset by higher SCRC revenues ($34.2 million) and RECs ($9.5 million).  

Partially offset by:

·

An increase related to the sale of oil to a third party ($20.8 million) in the second quarter of 2012, resulting in a benefit to customers through lower ES rates that does not impact earnings.  

·

A $9.9 million increase in transmission revenues resulting from an increased level of investment in transmission infrastructure and the recovery of higher overall expenses, which are tracked and result in a related increase in revenues.  The increase in expenses is directly related to the increase in transmission plant, including costs associated with higher property taxes, depreciation and operation and maintenance expenses.

·

A $3.5 million increase in the portion of distribution revenues that impacts earnings in 2012, as compared to 2011, due primarily to the favorable impact of the 2010 rate case decision related to the additional increase to annualized rates that was effective July 1, 2012.

Purchased Power, Fuel and Transmission decreased in 2012, as compared to 2011, due primarily to a decrease in purchased power costs, partially offset by an increase in transmission costs.  The decrease in purchased power costs was due primarily to lower market prices in 2012, as compared to 2011, as well as an increase in ES customer migration to third party suppliers.

Operations and Maintenance decreased in 2012, as compared to 2011, as a result of lower maintenance costs at the generation business due to less planned outage maintenance in 2012 ($17.8 million), partially offset by higher distribution general and administrative costs ($3 million).

Depreciation increased in 2012, as compared to 2011, due primarily to higher utility plant balances resulting from completed construction projects placed into service related to PSNH's capital programs.

Amortization of Regulatory Assets/(Liabilities), Net decreased in 2012, as compared to 2011, due primarily to a decrease in ES and TCAM amortization ($46.9 million and $20.2 million, respectively), partially offset by an increase in SCRC amortization ($13.5 million).

68

Taxes Other Than Income Taxes increased in 2012, as compared to 2011, due primarily to an increase in property taxes as a result of an increase in Property, Plant and Equipment related to PSNH’s capital program and an increase in the property tax rates.

Interest Expense

	For the Years Ended December 31,
					Increase/
(Millions of Dollars)	2012		2011		(Decrease)		Percent
Interest on Long-Term Debt	$	46.2	$	36.8	$	9.4	25.5	%
Interest on RRBs		2.7		6.3		(3.6)	(57.1)
Other Interest		1.3		1.0		0.3	30.0
	$	50.2	$	44.1	$	6.1	13.8	%

Interest Expense increased in 2012, as compared to 2011, due primarily to an increase in Interest on Long-Term Debt, which was primarily the result of a reduction in AFUDC related to borrowed funds as the Clean Air Project was placed into service in September 2011 ($5.5 million).  The additional increase in Interest on Long-Term Debt was a result of the $160 million long-term debt issuance in September 2011.

Other Income, Net

	For the Years Ended December 31,
(Millions of Dollars)	2012		2011		Decrease		Percent
Other Income, Net	$	3.0	$	14.3	$	(11.3)	(79.0)	%

Other Income, Net decreased in 2012, as compared to 2011, due primarily to lower AFUDC related to equity funds as the Clean Air Project was placed into service in September 2011.

Income Tax Expense

	For the Years Ended December 31,
(Millions of Dollars)	2012		2011		Increase		Percent
Income Tax Expense	$	61.0	$	49.9	$	11.1	22.2	%

Income Tax Expense increased in 2012, as compared to 2011, due primarily to lower flow-through items ($4.1 million), higher state taxes ($3.8 million), an increase in pre-tax earnings ($2.7 million) and return to provision ($0.8 million).

LIQUIDITY

PSNH had cash flows provided by operating activities in 2012 of $174.2 million, compared with operating cash flows of $151.8 million in 2011 (amounts are net of RRB payments, which are included in financing activities).  The improved cash flows in 2012 were due primarily to a reduction in NU Pension Plan contributions of $24.9 million in 2012, as compared to 2011, the absence in 2012 of a cash flow hedge settlement creating a favorable cash flow impact of $18.1 million, and an increased reduction in coal and fuel inventories in 2012.  The reduction in fuel inventories in 2012 is primarily attributable to the sale of oil to a third party for $20.8 million.  Offsetting these positive cash flow impacts were income tax payments in 2012 of $14.7 million, as compared to income tax refunds in 2011 of $29.3 million.

69

RESULTS OF OPERATIONS – WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY

The following table provides the amounts and variances in operating revenues and expense line items for the consolidated statements of income for WMECO included in this Annual Report on Form 10-K for the years ended December 31, 2012 and  2011:

			Operating Revenues and Expenses
			For the Years Ended December 31,
(Millions of Dollars)			2012		2011		Increase/		Percent
							(Decrease)
Operating Revenues			$	441.2	$	417.3	$	23.9	5.7	%
Operating Expenses:
	Purchased Power and Transmission			136.1		161.5		(25.4)	(15.7)
	Operations and Maintenance			97.0		80.2		16.8	20.9
	Depreciation			30.0		26.5		3.5	13.2
	Amortization of Regulatory Assets, Net			0.4		4.5		(4.1)	(91.1)
	Amortization of Rate Reduction Bonds			17.6		16.5		1.1	6.7
	Energy Efficiency Programs			27.8		21.8		6.0	27.5
	Taxes Other Than Income Taxes			21.5		17.9		3.6	20.1
		Total Operating Expenses		330.4		328.9		1.5	0.5
Operating Income			$	110.8	$	88.4	$	22.4	25.3	%

Operating Revenues
WMECO's retail sales were as follows:
	For the Years Ended December 31,
	2012	2011	Decrease	Percent
Retail Sales in GWh	3,683	3,695	(12)	(0.3)	%

WMECO's Operating Revenues increased in 2012, as compared to 2011, due primarily to:

·

A $32.3 million increase in transmission revenues resulting from an increased level of investment in transmission infrastructure, primarily related to the NEEWS projects, and the recovery of higher overall expenses, which are tracked and result in a related increase in revenues.  The increase in expenses is directly related to the increase in transmission plant, including costs associated with higher property taxes, depreciation and operation and maintenance expenses.

·

An increase in the portion of distribution revenues that impacts earnings related to the absence in 2012 of the establishment of a reserve related to a wholesale billing adjustment in the third quarter of 2011 ($5 million).

Partially offset by:

·

A $5.2 million decrease in distribution revenues related to the portions that are included in DPU approved tracking mechanisms that recover certain incurred costs and do not impact earnings.  The tracking mechanisms allow for rates to be changed periodically with overcollections refunded to customers or undercollections recovered from customers in future periods.  Included in these amounts are Basic Service, pension, transition and energy efficiency program costs.  

Purchased Power and Transmission decreased in 2012, as compared to 2011, due primarily to lower purchased transmission costs ($14 million), lower Basic Service costs ($7 million) and lower purchased power costs ($3.4 million).

Operations and Maintenance increased in 2012, as compared to 2011, due to an increase in distribution business expenses primarily related to higher pension costs ($3.9 million), which are recovered through DPU approved tracking mechanisms and have no earnings impact.  There were also higher routine distribution overhead line maintenance costs ($2.7 million), higher transmission operating costs ($2 million) and higher uncollectible expenses ($1.9 million).  In addition, there was a bill credit to customers ($3 million) in the second quarter of 2012 as a result of the Massachusetts settlement agreement.  

Depreciation increased in 2012, as compared to 2011, due primarily to higher utility plant balances resulting from completed construction projects placed into service related to WMECO's capital programs.

Amortization of Regulatory Assets, Net decreased in 2012, as compared to 2011, due primarily to a decrease in amortization of the transition charge deferral.

Energy Efficiency Programs increased in 2012, as compared to 2011, due primarily to an increase in expenses attributable to an increase in spending in accordance with DPU approved energy efficiency programs.  The increase in energy efficiency spending is recovered in rates and therefore does not impact earnings.

Taxes Other Than Income Taxes increased in 2012, as compared to 2011, due primarily to an increase in property taxes as a result of an increase in Property, Plant and Equipment related to WMECO’s capital program and an increase in the property tax rates.

70

Interest Expense

	For the Years Ended December 31,
					Increase/
(Millions of Dollars)	2012		2011		(Decrease)		Percent
Interest on Long-Term Debt	$	23.5	$	20.0	$	3.5	17.5	%
Interest on RRBs		1.2		2.3		(1.1)	(47.8)
Other Interest		1.9		1.3		0.6	46.2
	$	26.6	$	23.6	$	3.0	12.7	%

Interest Expense increased in 2012, as compared to 2011, due primarily to higher Interest on Long-Term Debt resulting from a $100 million long-term debt issuance in September 2011 and a $150 million long-term debt issuance on October 4, 2012.

Income Tax Expense

	For the Years Ended December 31,
(Millions of Dollars)	2012		2011		Increase		Percent
Income Tax Expense	$	32.1	$	23.2	$	8.9	38.4	%

Income Tax Expense increased in 2012, as compared to 2011, due primarily to higher pre-tax earnings ($9.2 million) and higher state taxes ($2.4 million), partially offset by Massachusetts settlement agreement impacts ($1.2 million) and a regulatory decision that reduced a non-plant flow through difference ($1.3 million).

LIQUIDITY

WMECO had cash flows provided by operating activities in 2012 of $77 million, compared with operating cash flows of $108 million in 2011 (amounts are net of RRB payments, which are included in financing activities).  The reduced cash flows in 2012 were due primarily to unfavorable cash flow impacts of $6.6 million relating to C&LM and $16.1 million relating to the change in transmission regulatory tracking mechanisms.  In addition, WMECO paid $3 million in bill credits to customers in 2012 associated with the Massachusetts settlement agreement.  

71

Item 7A.

Quantitative and Qualitative Disclosures about Market Risk

Market Risk Information

Commodity Price Risk Management:  Our Regulated companies enter into energy contracts to serve our customers and the economic impacts of those contracts are passed on to our customers.  Accordingly, the Regulated companies have no exposure to loss of future earnings or fair values due to these market risk-sensitive instruments.  

The remaining unregulated wholesale portfolio held by Select Energy includes contracts that are market risk-sensitive, including a wholesale energy sales contract through December 31, 2013 with an agency comprised of municipalities and related purchase agreements.   We have not entered into any energy contracts for trading purposes.  As Select Energy's contract volumes are winding down, and as the wholesale energy sales contract is substantially hedged against price risks, we have limited exposure to commodity price risks.  For Select Energy's wholesale energy portfolio derivatives, we utilize the sensitivity analysis methodology to disclose quantitative information of the potential loss of future pre-tax earnings for one or more hypothetical changes in commodity price components.  A hypothetical 30 percent increase or decrease in forward energy, ancillary or capacity prices would not have a material impact on earnings.  The method we use to determine the fair value of these contracts includes discounting expected future cash flows using a LIBOR swap curve.  As such, the wholesale portfolio is also exposed to interest rate volatility.  This exposure is not modeled in sensitivity analyses, and we do not believe that such exposure is material.  

Other Risk Management Activities

We have implemented an Enterprise Risk Management methodology for identifying the principal risks of the Company.  Enterprise Risk Management involves the application of a well-defined, enterprise-wide methodology that enables our Risk and Capital Committee, comprised of our senior officers, to oversee the identification, management and reporting of the principal risks of the business.  Our management analyzes risks to determine materiality and other attributes such as likelihood and impact, velocity, and mitigation strategies.  Management broadly considers our business model, the utility industry, the global economy and the current environment to identify risks.

However, there can be no assurances that the Enterprise Risk Management process will identify or manage every risk or event that could impact our financial position, results of operations or cash flows.  The findings of this process are periodically discussed with our Board of Trustees.  

Interest Rate Risk Management:  As of December 31, 2012, approximately 91 percent of our long-term debt, including fees and interest due for spent nuclear fuel disposal costs, was at a fixed interest rate.  The remaining long-term debt is at variable interest rates and is subject to interest rate risk that could result in earnings volatility.  Assuming a one percentage point increase in our variable interest rate, annual interest expense would have increased by a pre-tax amount of $8.7 million.  

Credit Risk Management:  Credit risk relates to the risk of loss that we would incur as a result of non-performance by counterparties pursuant to the terms of our contractual obligations.  We serve a wide variety of customers and suppliers that include IPPs, industrial companies, gas and electric utilities, oil and gas producers, financial institutions, and other energy marketers.  Margin accounts exist within this diverse group, and we realize interest receipts and payments related to balances outstanding in these margin accounts.  This wide customer and supplier mix generates a need for a variety of contractual structures, products and terms that, in turn, require us to manage the portfolio of market risk inherent in those transactions in a manner consistent with the parameters established by our risk management process.

Our Regulated companies are subject to credit risk from certain long-term or high-volume supply contracts with energy marketing companies.  Our Regulated companies manage the credit risk with these counterparties in accordance with established credit risk practices and monitor contracting risks, including credit risk.  As of December 31, 2012, our Regulated companies did not hold cash collateral from counterparties.  As of December 31, 2012, NU had cash posted with ISO-NE related to energy purchase transactions.  In addition, Select Energy has also established written credit policies with regard to its counterparties to minimize overall credit risk on its remaining contracts.  These policies require collateral under certain circumstances (including cash in advance and parent guarantees), and the use of standardized agreements, which allow for the netting of positive and negative exposures associated with a single counterparty in the event of default.  

For further information on cash collateral deposited and posted with counterparties as well as any cash collateral netted against the fair value of the related derivative contracts, see Note 1G, "Summary of Significant Accounting Policies - Restricted Cash and Other Deposits," and Note 5, "Derivative Instruments," to the consolidated financial statements.

If the respective unsecured debt ratings of NU or its subsidiaries were reduced to below investment grade by either Moody’s or S&P, certain of NU’s contracts would require additional collateral in the form of cash to be provided to counterparties and independent system operators.  NU would have been and remains able to provide that collateral.

72

Item 8.

Financial Statements and Supplementary Data

NU
	Company Report on Internal Controls Over Financial Reporting
	Report of Independent Registered Public Accounting Firm
	Consolidated Financial Statements
CL&P
	Company Report on Internal Controls Over Financial Reporting
	Report of Independent Registered Public Accounting Firm
	Consolidated Financial Statements
NSTAR Electric
	Company Report on Internal Controls Over Financial Reporting
	Reports of Independent Registered Public Accounting Firms
	Consolidated Financial Statements
PSNH
	Company Report on Internal Controls Over Financial Reporting
	Report of Independent Registered Public Accounting Firm
	Consolidated Financial Statements
WMECO
	Company Report on Internal Controls Over Financial Reporting
	Report of Independent Registered Public Accounting Firm
	Consolidated Financial Statements

73

Company Report on Internal Controls Over Financial Reporting

Northeast Utilities

Management is responsible for the preparation, integrity, and fair presentation of the accompanying consolidated financial statements of Northeast Utilities and subsidiaries (NU or the Company) and of other sections of this annual report.  NU’s internal controls over financial reporting were audited by Deloitte & Touche LLP.

Management is responsible for establishing and maintaining adequate internal controls over financial reporting.  The Company’s internal control framework and processes have been designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.  There are inherent limitations of internal controls over financial reporting that could allow material misstatements due to error or fraud to occur and not be prevented or detected on a timely basis by employees during the normal course of business.  Additionally, internal controls over financial reporting may become inadequate in the future due to changes in the business environment.  

Under the supervision and with the participation of the principal executive officer and principal financial officer, NU conducted an evaluation of the effectiveness of internal controls over financial reporting based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).  Based on this evaluation under the framework in COSO, management concluded that internal controls over financial reporting were effective as of December 31, 2012.

Management has excluded from our assessment of and conclusion on the effectiveness of internal controls over financial reporting the internal controls of NSTAR LLC, acquired on April 10, 2012, which is included in the consolidated financial statements of the Company as of and for the year ended December 31, 2012, constituting $11.3 billion and $5.1 billion of total and net assets, respectively, as of December 31, 2012, and $1,957.8 million and $182.9 million of revenues and net income attributable to controlling interest, respectively, for the period from April 10, 2012 through December 31, 2012.

February 27, 2013

74

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Trustees and Shareholders of Northeast Utilities:

We have audited the accompanying consolidated balance sheets of Northeast Utilities and subsidiaries (the "Company") as of December 31, 2012 and 2011, and the related consolidated statements of income, comprehensive income, common shareholders’ equity, and cash flows for each of the three years in the period ended December 31, 2012.  Our audits also included the financial statement schedules listed in the Index at Item 15 of Part IV.  We also have audited the Company's internal control over financial reporting as of December 31, 2012, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.  The Company's management is responsible for these financial statements and financial statement schedules, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Company Report on Internal Controls Over Financial Reporting.  Our responsibility is to express an opinion on these financial statements and financial statement schedules and an opinion on the Company's internal control over financial reporting based on our audits.

As described in the Company Report on Internal Controls Over Financial Reporting, management excluded from its assessment the internal control over financial reporting at NSTAR LLC and its subsidiaries, the post-merger parent company of NSTAR and its subsidiaries, which was acquired on April 10, 2012 and whose financial statements constitute 55 percent and 40 percent of net and total assets, respectively, 31 percent of revenues, and 35 percent of net income of the consolidated financial statement amounts as of and for the year ended December 31, 2012.  Accordingly, our audit did not include the internal control over financial reporting at NSTAR LLC and its subsidiaries.  

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects.  Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation.  Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk.  Our audits also included performing such other procedures as we considered necessary in the circumstances.  We believe that our audits provide a reasonable basis for our opinions.

A company's internal control over financial reporting is a process designed by, or under the supervision of, the company's principal executive and principal financial officers, or persons performing similar functions, and effected by the company's board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.  A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis.  Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Northeast Utilities and subsidiaries as of December 31, 2012 and 2011, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2012, in conformity with accounting principles generally accepted in the United States of America.  Also, in our opinion, such financial statement schedules, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly, in all material respects, the information set forth therein.  Also, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2012, based on the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

As discussed in Note 2, "Merger of NU and NSTAR," to the consolidated financial statements, on April 10, 2012, the Company acquired NSTAR and its subsidiaries.

/s/  Deloitte & Touche LLP

Hartford, Connecticut

February 27, 2013

75

NORTHEAST UTILITIES AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
		As of December 31,
(Thousands of Dollars)		2012		2011
ASSETS
Current Assets:
	Cash and Cash Equivalents	$	45,748	$	6,559
	Receivables, Net		792,822		488,002
	Unbilled Revenues		216,040		175,207
	Fuel, Materials and Supplies		267,713		248,958
	Regulatory Assets		705,025		255,144
	Marketable Securities		91,975		70,970
	Prepayments and Other Current Assets		107,972		112,632
Total Current Assets			2,227,295		1,357,472
Property, Plant and Equipment, Net			16,605,010		10,403,065
Deferred Debits and Other Assets:
	Regulatory Assets		5,132,411		3,267,710
	Goodwill		3,519,401		287,591
	Marketable Securities		400,329		60,311
	Derivative Assets		90,612		98,357
	Other Long-Term Assets		327,766		172,560
Total Deferred Debits and Other Assets			9,470,519		3,886,529
Total Assets		$	28,302,824	$	15,647,066
The accompanying notes are an integral part of these consolidated financial statements.

76

NORTHEAST UTILITIES AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
		As of December 31,
(Thousands of Dollars)		2012		2011
LIABILITIES AND CAPITALIZATION
Current Liabilities:
Notes Payable		$	1,120,196	$	317,000
Long-Term Debt - Current Portion			763,338		331,582
Accounts Payable			764,350		633,282
Regulatory Liabilities			134,115		167,844
Derivative Liabilities			117,194		107,558
Other Current Liabilities			744,497		390,416
Total Current Liabilities			3,643,690		1,947,682
Rate Reduction Bonds			82,139		112,260
Deferred Credits and Other Liabilities:
Accumulated Deferred Income Taxes			3,463,347		1,868,316
Regulatory Liabilities			540,162		266,145
Derivative Liabilities			882,654		959,876
Accrued Pension, SERP and PBOP			2,130,497		1,326,037
Other Long-Term Liabilities			967,561		420,011
Total Deferred Credits and Other Liabilities			7,984,221		4,840,385
Capitalization:
Long-Term Debt			7,200,156		4,614,913
Noncontrolling Interest - Preferred Stock of Subsidiaries			155,568		116,200
Equity:
	Common Shareholders' Equity:
	Common Shares		1,662,547		980,264
	Capital Surplus, Paid In		6,183,267		1,797,884
	Retained Earnings		1,802,714		1,651,875
	Accumulated Other Comprehensive Loss		(72,854)		(70,686)
	Treasury Stock		(338,624)		(346,667)
Common Shareholders' Equity			9,237,050		4,012,670
Noncontrolling Interests			-		2,956
Total Equity			9,237,050		4,015,626
Total Capitalization			16,592,774		8,746,739
Commitments and Contingencies (Note 12)
Total Liabilities and Capitalization		$	28,302,824	$	15,647,066
The accompanying notes are an integral part of these consolidated financial statements.

77

NORTHEAST UTILITIES AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
			For the Years Ended December 31,
(Thousands of Dollars, Except Share Information)			2012		2011		2010
Operating Revenues			$	6,273,787	$	4,465,657	$	4,898,167
Operating Expenses:
	Purchased Power, Fuel and Transmission			2,084,364		1,657,914		2,034,501
	Operations and Maintenance			1,583,070		1,095,358		1,001,349
	Depreciation			519,010		302,192		300,737
	Amortization of Regulatory Assets, Net			79,762		91,080		90,054
	Amortization of Rate Reduction Bonds			142,019		69,912		232,871
	Energy Efficiency Programs			313,149		131,415		124,023
	Taxes Other Than Income Taxes			434,207		323,610		314,741
		Total Operating Expenses		5,155,581		3,671,481		4,098,276
Operating Income				1,118,206		794,176		799,891
Interest Expense:
	Interest on Long-Term Debt			316,987		231,630		231,089
	Interest on Rate Reduction Bonds			6,168		8,611		20,573
	Other Interest			6,790		10,184		(14,371)
		Interest Expense		329,945		250,425		237,291
Other Income, Net				19,742		27,715		41,916
Income Before Income Tax Expense				808,003		571,466		604,516
Income Tax Expense				274,926		170,953		210,409
Net Income				533,077		400,513		394,107
Net Income Attributable to Noncontrolling Interests				7,132		5,820		6,158
Net Income Attributable to Controlling Interest			$	525,945	$	394,693	$	387,949
Basic Earnings Per Common Share			$	1.90	$	2.22	$	2.20
Diluted Earnings Per Common Share			$	1.89	$	2.22	$	2.19
Weighted Average Common Shares Outstanding:
	Basic			277,209,819		177,410,167		176,636,086
	Diluted			277,993,631		177,804,568		176,885,387
The accompanying notes are an integral part of these consolidated financial statements.

78

NORTHEAST UTILITIES AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
			For the Years Ended December 31,
(Thousands of Dollars)			2012		2011		2010
Net Income			$	533,077	$	400,513	$	394,107
Other Comprehensive Income/(Loss), Net of Tax:
	Qualified Cash Flow Hedging Instruments			1,971		(14,177)		200
	Changes in Unrealized Gains on Other Securities			217		506		402
	Change in Funded Status of Pension, SERP and PBOP
		Benefit Plans		(4,356)		(13,645)		(505)
Other Comprehensive Income/(Loss), Net of Tax				(2,168)		(27,316)		97
Comprehensive Income Attributable to Noncontrolling Interests				(7,132)		(5,820)		(6,158)
Comprehensive Income Attributable to Controlling Interest			$	523,777	$	367,377	$	388,046
The accompanying notes are an integral part of these consolidated financial statements.

79

NORTHEAST UTILITIES AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDERS' EQUITY
							Accumulated		Total
				Capital	Deferred		Other		Common
		Common Shares		Surplus,	Contribution	Retained	Comprehensive	Treasury	Shareholders'
(Thousands of Dollars, Except Share Information)		Shares	Amount	Paid In	Plan	Earnings	Income/(Loss)	Stock	Equity
Balance as of January 1, 2010		175,620,024	$ 977,276	$ 1,762,097	$ (2,944)	$ 1,246,543	$ (43,467)	$ (361,603)	$ 3,577,902
	Net Income					394,107			394,107
	Dividends on Common Shares - $1.025 Per Share					(181,715)			(181,715)
	Dividends on Preferred Stock					(6,101)			(6,101)
	Issuance of Common Shares, $5 Par Value	326,526	1,633	5,745					7,378
	Allocation of Benefits - ESOP	127,054		439	2,944				3,383
	Long-Term Incentive Plan Activity			4,868					4,868
	Issuance of Treasury Shares to Fund ESOP	374,477		3,856				6,871	10,727
	Other Changes in Shareholders' Equity			587					587
	Net Income Attributable to Noncontrolling Interests					(57)			(57)
	Other Comprehensive Income						97		97
Balance as of December 31, 2010		176,448,081	978,909	1,777,592	-	1,452,777	(43,370)	(354,732)	3,811,176
	Net Income					400,513			400,513
	Dividends on Common Shares - $1.10 Per Share					(195,595)			(195,595)
	Dividends on Preferred Stock					(5,559)			(5,559)
	Issuance of Common Shares, $5 Par Value	271,030	1,355	4,496					5,851
	Long-Term Incentive Plan Activity			7,359					7,359
	Issuance of Treasury Shares to Fund ESOP	439,581		7,048				8,065	15,113
	Other Changes in Shareholders' Equity			1,389					1,389
	Net Income Attributable to Noncontrolling Interests					(261)			(261)
	Other Comprehensive Loss						(27,316)		(27,316)
Balance as of December 31, 2011		177,158,692	980,264	1,797,884	-	1,651,875	(70,686)	(346,667)	4,012,670
	Net Income					533,077			533,077
	Shares Issued in Connection with NSTAR Merger	136,048,595	680,243	4,358,027					5,038,270
	Other Equity Impacts of Merger with NSTAR			2,938		421			3,359
	Dividends on Common Shares - $1.32 Per Share					(375,527)			(375,527)
	Dividends on Preferred Stock					(7,029)			(7,029)
	Issuance of Common Shares, $5 Par Value	408,018	2,040	11,287					13,327
	Long-Term Incentive Plan Activity			(3,897)					(3,897)
	Issuance of Treasury Shares to Fund ESOP	438,329		8,454				8,043	16,497
	Other Changes in Shareholders' Equity			8,574					8,574
	Net Income Attributable to Noncontrolling Interests					(103)			(103)
	Other Comprehensive Loss						(2,168)		(2,168)
Balance as of December 31, 2012		314,053,634	$ 1,662,547	$ 6,183,267	$ -	$ 1,802,714	$ (72,854)	$ (338,624)	$ 9,237,050
The accompanying notes are an integral part of these consolidated financial statements.

80

NORTHEAST UTILITIES AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
			For the Years Ended December 31,
(Thousands of Dollars)			2012		2011		2010
Operating Activities:
	Net Income		$	533,077	$	400,513	$	394,107
	Adjustments to Reconcile Net Income to Net Cash Flows
		Provided by Operating Activities:
		Bad Debt Expense		36,275		16,420		31,352
		Depreciation		519,010		302,192		300,737
		Deferred Income Taxes		292,000		196,761		210,939
		Pension, SERP and PBOP Expense		218,540		133,000		103,861
		Pension and PBOP Contributions		(295,028)		(191,101)		(90,633)
		Regulatory (Under)/Over Recoveries, Net		(259,853)		(70,863)		26,289
		Amortization of Regulatory Assets, Net		79,762		91,080		90,054
		Amortization of Rate Reduction Bonds		142,019		69,912		232,871
		Derivative Assets and Liabilities		(10,455)		(35,441)		(11,812)
		Other		17,032		(29,751)		(72,151)
	Changes in Current Assets and Liabilities:
		Receivables and Unbilled Revenues, Net		(20,214)		17,570		(51,285)
		Fuel, Materials and Supplies		34,321		(11,033)		38,126
		Taxes Receivable/Accrued, Net		(5,450)		49,642		(82,103)
		Accounts Payable		(128,339)		18,916		(44,355)
		Other Current Assets and Liabilities, Net		8,532		12,569		17,466
Net Cash Flows Provided by Operating Activities				1,161,229		970,386		1,093,463
Investing Activities:
	Investments in Property, Plant and Equipment			(1,472,272)		(1,076,730)		(954,472)
	Proceeds from Sales of Marketable Securities			317,294		149,441		174,865
	Purchases of Marketable Securities			(348,629)		(151,972)		(177,204)
	Proceeds from Sale of Assets			-		46,841		-
	Other Investing Activities			35,683		13,833		(1,157)
Net Cash Flows Used in Investing Activities				(1,467,924)		(1,018,587)		(957,968)
Financing Activities:
	Cash Dividends on Common Shares			(375,047)		(194,555)		(180,542)
	Cash Dividends on Preferred Stock			(7,029)		(5,559)		(5,559)
	Increase in Short-Term Debt			825,000		50,000		166,687
	Issuance of Long-Term Debt			850,000		627,500		145,000
	Retirements of Long-Term Debt			(839,136)		(369,586)		(4,286)
	Retirements of Rate Reduction Bonds			(114,433)		(69,312)		(260,864)
	Other Financing Activities			6,529		(7,123)		512
Net Cash Flows Provided by/(Used in) Financing Activities				345,884		31,365		(139,052)
Net Increase/(Decrease) in Cash and Cash Equivalents				39,189		(16,836)		(3,557)
Cash and Cash Equivalents - Beginning of Year				6,559		23,395		26,952
Cash and Cash Equivalents - End of Year			$	45,748	$	6,559	$	23,395
The accompanying notes are an integral part of these consolidated financial statements.

81

Company Report on Internal Controls Over Financial Reporting

The Connecticut Light and Power Company

Management is responsible for the preparation, integrity, and fair presentation of the accompanying consolidated financial statements of The Connecticut Light and Power Company and subsidiary (CL&P or the Company) and of other sections of this annual report.  CL&P’s internal controls over financial reporting were audited by Deloitte & Touche LLP.

Management is responsible for establishing and maintaining adequate internal controls over financial reporting.  The Company’s internal control framework and processes have been designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.  There are inherent limitations of internal controls over financial reporting that could allow material misstatements due to error or fraud to occur and not be prevented or detected on a timely basis by employees during the normal course of business.  Additionally, internal controls over financial reporting may become inadequate in the future due to changes in the business environment.  

Under the supervision and with the participation of the principal executive officer and principal financial officer, CL&P conducted an evaluation of the effectiveness of internal controls over financial reporting based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).  Based on this evaluation under the framework in COSO, management concluded that internal controls over financial reporting were effective as of December 31, 2012.

February 27, 2013

82

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholder of The Connecticut Light and Power Company:

We have audited the accompanying consolidated balance sheets of The Connecticut Light and Power Company and subsidiary (the "Company") as of December 31, 2012 and 2011, and the related consolidated statements of income, comprehensive income, common stockholder’s equity, and cash flows for each of the three years in the period ended December 31, 2012.  Our audits also included the financial statement schedule listed in the Index at Item 15 of Part IV.  These financial statements and financial statement schedule are the responsibility of the Company's management.  Our responsibility is to express an opinion on the financial statements and financial statement schedule based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.  The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting.  Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting.  Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of The Connecticut Light and Power Company and subsidiary as of December 31, 2012 and 2011, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2012, in conformity with accounting principles generally accepted in the United States of America.  Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole present fairly in all material respects the information set forth therein.

/s/  Deloitte & Touche LLP

Hartford, Connecticut

February 27, 2013

83

THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARY
CONSOLIDATED BALANCE SHEETS
		As of December 31,
(Thousands of Dollars)		2012		2011
ASSETS
Current Assets:
	Cash	$	1	$	1
	Receivables, Net		284,787		295,028
	Accounts Receivable from Affiliated Companies		6,641		1,548
	Unbilled Revenues		85,353		94,995
	Regulatory Assets		185,858		170,197
	Materials and Supplies		64,603		61,102
	Prepayments and Other Current Assets		26,413		53,920
Total Current Assets			653,656		676,791
Property, Plant and Equipment, Net			6,152,959		5,827,384
Deferred Debits and Other Assets:
	Regulatory Assets		2,158,363		2,103,830
	Derivative Assets		90,612		93,755
	Other Long-Term Assets		86,498		89,636
Total Deferred Debits and Other Assets			2,335,473		2,287,221
Total Assets		$	9,142,088	$	8,791,396
The accompanying notes are an integral part of these consolidated financial statements.

84

THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARY
CONSOLIDATED BALANCE SHEETS
			As of December 31,
(Thousands of Dollars)			2012		2011
LIABILITIES AND CAPITALIZATION
Current Liabilities:
	Notes Payable		$	-	$	31,000
	Notes Payable to Affiliated Companies			99,296		58,525
	Long-Term Debt - Current Portion			125,000		62,000
	Accounts Payable			262,857		340,321
	Accounts Payable to Affiliated Companies			52,326		53,439
	Obligations to Third Party Suppliers			67,344		67,967
	Accrued Taxes			60,109		59,046
	Regulatory Liabilities			32,119		108,291
	Derivative Liabilities			96,931		95,881
	Other Current Liabilities			125,662		102,065
Total Current Liabilities				921,644		978,535
Deferred Credits and Other Liabilities:
	Accumulated Deferred Income Taxes			1,336,105		1,215,989
	Regulatory Liabilities			124,319		139,307
	Derivative Liabilities			865,571		935,849
	Accrued Pension, SERP and PBOP			304,696		260,571
	Other Long-Term Liabilities			197,434		215,640
Total Deferred Credits and Other Liabilities				2,828,125		2,767,356
Capitalization:
	Long-Term Debt			2,737,790		2,521,753
Preferred Stock Not Subject to Mandatory Redemption				116,200		116,200
	Common Stockholder's Equity:
		Common Stock		60,352		60,352
		Capital Surplus, Paid In		1,640,149		1,613,503
		Retained Earnings		839,628		735,948
		Accumulated Other Comprehensive Loss		(1,800)		(2,251)
	Common Stockholder's Equity			2,538,329		2,407,552
Total Capitalization				5,392,319		5,045,505
Commitments and Contingencies (Note 12)
Total Liabilities and Capitalization			$	9,142,088	$	8,791,396
The accompanying notes are an integral part of these consolidated financial statements.

85

THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF INCOME
			For the Years Ended December 31,
(Thousands of Dollars)			2012		2011		2010
Operating Revenues			$	2,407,449	$	2,548,387	$	2,999,102
Operating Expenses:
	Purchased Power and Transmission			858,231		982,514		1,292,733
	Operations and Maintenance			635,733		580,736		494,203
	Depreciation			166,853		157,747		172,167
	Amortization of Regulatory Assets, Net			14,372		61,025		78,870
	Amortization of Rate Reduction Bonds			-		-		167,021
	Energy Efficiency Programs			89,299		90,297		92,279
	Taxes Other Than Income Taxes			215,972		212,885		214,179
		Total Operating Expenses		1,980,460		2,085,204		2,511,452
Operating Income				426,989		463,183		487,650
Interest Expense:
	Interest on Long-Term Debt			124,894		131,918		134,553
	Interest on Rate Reduction Bonds			-		-		7,542
	Other Interest			8,233		809		(4,357)
		Interest Expense		133,127		132,727		137,738
Other Income, Net				10,300		9,741		26,669
Income Before Income Tax Expense				304,162		340,197		376,581
Income Tax Expense				94,437		90,033		132,438
Net Income			$	209,725	$	250,164	$	244,143
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Net Income			$	209,725	$	250,164	$	244,143
Other Comprehensive Income, Net of Tax:
	Qualified Cash Flow Hedging Instruments			444		445		444
	Changes in Unrealized Gains on Other
		Securities		7		17		14
Other Comprehensive Income, Net of Tax				451		462		458
Comprehensive Income			$	210,176	$	250,626	$	244,601
The accompanying notes are an integral part of these consolidated financial statements.

86

THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
						Accumulated	Total
				Capital		Other	Common
		Common Stock		Surplus,	Retained	Comprehensive	Stockholder's
(Thousands of Dollars, Except Stock Information)		Stock	Amount	Paid In	Earnings	Income/(Loss)	Equity
Balance as of January 1, 2010		6,035,205	$ 60,352	$ 1,601,792	$ 714,210	$ (3,171)	$ 2,373,183
	Net Income				244,143		244,143
	Dividends on Preferred Stock				(6,101)		(6,101)
	Dividends on Common Stock				(217,691)		(217,691)
	Allocation of Benefits - ESOP			919			919
	Capital Stock Expenses, Net			51			51
	Capital Contributions from NU Parent			2,513			2,513
	Other Comprehensive Income					458	458
Balance as of December 31, 2010		6,035,205	60,352	1,605,275	734,561	(2,713)	2,397,475
	Net Income				250,164		250,164
	Dividends on Preferred Stock				(5,559)		(5,559)
	Dividends on Common Stock				(243,218)		(243,218)
	Allocation of Benefits - ESOP			1,429			1,429
	Capital Stock Expenses, Net			51			51
	Capital Contributions from NU Parent			6,748			6,748
	Other Comprehensive Income					462	462
Balance as of December 31, 2011		6,035,205	60,352	1,613,503	735,948	(2,251)	2,407,552
	Net Income				209,725		209,725
	Dividends on Preferred Stock				(5,559)		(5,559)
	Dividends on Common Stock				(100,486)		(100,486)
	Allocation of Benefits - ESOP			1,595			1,595
	Capital Stock Expenses, Net			51			51
	Capital Contributions from NU Parent			25,000			25,000
	Other Comprehensive Income					451	451
Balance as of December 31, 2012		6,035,205	$ 60,352	$ 1,640,149	$ 839,628	$ (1,800)	$ 2,538,329
The accompanying notes are an integral part of these consolidated financial statements.

87

THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF CASH FLOWS
			For the Years Ended December 31,
(Thousands of Dollars)			2012		2011		2010
Operating Activities:
	Net Income		$	209,725	$	250,164	$	244,143
	Adjustments to Reconcile Net Income to Net Cash Flows
		Provided by Operating Activities:
		Bad Debt Expense		2,080		3,215		7,484
		Depreciation		166,853		157,747		172,167
		Deferred Income Taxes		140,993		112,620		115,069
		Pension, SERP and PBOP Expense, Net of PBOP Contributions		24,062		10,664		1,595
		Regulatory (Under)/Over Recoveries, Net		(100,505)		(82,502)		37,528
		Amortization of Regulatory Assets, Net		14,372		61,025		78,870
		Amortization of Rate Reduction Bonds		-		-		167,021
		Other		(31,032)		(36,928)		(55,515)
	Changes in Current Assets and Liabilities:
		Receivables and Unbilled Revenues, Net		(7,741)		14,610		1,895
		Materials and Supplies		(4,573)		(2,206)		3,377
		Taxes Receivable/Accrued, Net		15,702		2,719		(56,002)
		Accounts Payable		(190,240)		8,864		(35,976)
		Other Current Assets and Liabilities, Net		(27,803)		13,291		15,649
Net Cash Flows Provided by Operating Activities				211,893		513,283		697,305
Investing Activities:
	Investments in Property, Plant and Equipment			(449,137)		(424,865)		(380,304)
	Decrease in Notes Receivable to Affiliate			-		-		97,775
	Proceeds from Sale of Assets			-		46,841		-
	Other Investing Activities			32,009		16,001		5,385
Net Cash Flows Used in Investing Activities				(417,128)		(362,023)		(277,144)
Financing Activities:
	Cash Dividends on Common Stock			(100,486)		(243,218)		(217,691)
	Cash Dividends on Preferred Stock			(5,559)		(5,559)		(5,559)
	Increase in Short-Term Debt			58,000		31,000		-
	Increase in Notes Payable to Affiliate			346,575		52,300		6,225
	Issuance of Long-Term Debt			-		245,500		-
	Retirements of Long-Term Debt			(116,400)		(245,500)		-
	Capital Contributions from NU Parent			25,000		6,748		2,513
	Retirements of Rate Reduction Bonds			-		-		(195,587)
	Other Financing Activities			(1,895)		(2,292)		(345)
Net Cash Flows Provided by/(Used in) Financing Activities				205,235		(161,021)		(410,444)
Net (Decrease)/Increase in Cash				-		(9,761)		9,717
Cash - Beginning of Year				1		9,762		45
Cash - End of Year			$	1	$	1	$	9,762
The accompanying notes are an integral part of these consolidated financial statements.

88

Company Report on Internal Controls Over Financial Reporting

NSTAR Electric Company

Management is responsible for the preparation, integrity, and fair presentation of the accompanying consolidated financial statements of NSTAR Electric Company and subsidiaries (NSTAR Electric or the Company) and of other sections of this annual report.  NSTAR Electric’s internal controls over financial reporting were audited by Deloitte & Touche LLP.

Management is responsible for establishing and maintaining adequate internal controls over financial reporting.  The Company’s internal control framework and processes have been designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.  There are inherent limitations of internal controls over financial reporting that could allow material misstatements due to error or fraud to occur and not be prevented or detected on a timely basis by employees during the normal course of business.  Additionally, internal controls over financial reporting may become inadequate in the future due to changes in the business environment.  

Under the supervision and with the participation of the principal executive officer and principal financial officer, NSTAR Electric conducted an evaluation of the effectiveness of internal controls over financial reporting based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).  Based on this evaluation under the framework in COSO, management concluded that internal controls over financial reporting were effective as of December 31, 2012.

February 27, 2013

89

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholder of NSTAR Electric Company:

We have audited the accompanying consolidated balance sheet of NSTAR Electric Company and subsidiaries (the "Company") as of December 31, 2012 and the related consolidated statements of income, comprehensive income, common stockholder’s equity, and cash flows for the year then ended.  Our audit also included the financial statement schedule listed in the Index at Item 15 of Part IV.  These financial statements and financial statement schedule are the responsibility of the Company's management.  Our responsibility is to express an opinion on the financial statements and financial statement schedule based on our audit.  The consolidated financial statements and financial statement schedule of the Company for the years ended December 31, 2011 and 2010 were audited by other auditors whose report, dated February 7, 2012, expressed an unqualified opinion on those statements and included an explanatory paragraph relating to the merger agreement signed with Northeast Utilities.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.  The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting.  Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting.  Accordingly, we express no such opinion.  An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.  We believe that our audit provides a reasonable basis for our opinion.

In our opinion, such 2012 consolidated financial statements present fairly, in all material respects, the financial position of NSTAR Electric Company and subsidiaries as of December 31, 2012, and the results of their operations and their cash flows for the year then ended, in conformity with accounting principles generally accepted in the United States of America.  Also, in our opinion, such 2012 financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole presents fairly in all material respects the information set forth therein.

/s/  Deloitte & Touche LLP

Hartford, Connecticut

February 27, 2013

90

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Directors and Shareholder of NSTAR Electric Company:

In our opinion, the consolidated balance sheets, consolidated statements of income, common stockholder's equity, and cash flows present fairly, in all material respects, the financial position of NSTAR Electric Company and its subsidiaries at December 31, 2011 and the results of their operations and their cash flows for each of the two years in the period ended December 31, 2011 in conformity with accounting principles generally accepted in the United States of America.  In addition, in our opinion, the financial statement schedule for each of the two years in the period ended December 31, 2011 listed in the index appearing under Item 15(a)(2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements.  These financial statements and financial statement schedule are the responsibility of the Company’s management.  Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits.  We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement.  An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation.  We believe that our audits provide a reasonable basis for our opinion.

/s/  PricewaterhouseCoopers LLP

Boston, Massachusetts

February 7, 2012

91

NSTAR ELECTRIC COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
		As of December 31,
(Thousands of Dollars)		2012		2011
ASSETS
Current Assets:
	Cash and Cash Equivalents	$	13,695	$	9,373
	Receivables, Net		202,025		232,828
	Accounts Receivable from Affiliated Companies		160,176		389,652
	Unbilled Revenues		41,377		40,380
	Regulatory Assets		347,081		323,871
	Prepayments and Other Current Assets		28,086		34,479
Total Current Assets			792,440		1,030,583
Property, Plant and Equipment, Net			4,735,297		4,447,258
Deferred Debits and Other Assets:
	Regulatory Assets		1,444,870		1,680,595
	Other Long-Term Assets		87,382		81,890
Total Deferred Debits and Other Assets			1,532,252		1,762,485
Total Assets		$	7,059,989	$	7,240,326
The accompanying notes are an integral part of these consolidated financial statements.

92

NSTAR ELECTRIC COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
			As of December 31,
(Thousands of Dollars)			2012		2011
LIABILITIES AND CAPITALIZATION
Current Liabilities:
	Notes Payable		$	276,000	$	141,500
	Long-Term Debt - Current Portion			1,650		401,650
	Accounts Payable			168,611		150,581
	Accounts Payable to Affiliated Companies			247,061		514,377
	Accumulated Deferred Income Taxes - Current Portion			104,668		101,819
	Regulatory Liabilities			47,539		41,579
	Other Current Liabilities			144,433		103,634
Total Current Liabilities				989,962		1,455,140
Rate Reduction Bonds				43,493		127,860
Deferred Credits and Other Liabilities:
	Accumulated Deferred Income Taxes			1,321,026		1,310,180
	Regulatory Liabilities			244,224		239,858
	Accrued Pension			360,932		357,685
	Payable to Affiliated Companies			70,221		75,905
	Other Long-Term Liabilities			183,190		195,606
Total Deferred Credits and Other Liabilities				2,179,593		2,179,234
Capitalization:
	Long-Term Debt			1,600,911		1,203,344
Preferred Stock Not Subject to Mandatory Redemption				43,000		43,000
	Common Stockholder's Equity:
		Common Stock		-		-
		Capital Surplus, Paid In		992,625		992,625
		Retained Earnings		1,210,405		1,239,123
	Common Stockholder's Equity			2,203,030		2,231,748
Total Capitalization				3,846,941		3,478,092
Commitments and Contingencies (Note 12)
Total Liabilities and Capitalization			$	7,059,989	$	7,240,326
The accompanying notes are an integral part of these consolidated financial statements.

93

NSTAR ELECTRIC COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
			For the Years Ended December 31,
(Thousands of Dollars)			2012		2011		2010
Operating Revenues			$	2,300,997	$	2,403,053	$	2,366,201
Operating Expenses:
	Purchased Power and Transmission			788,252		905,226		1,031,351
	Operations and Maintenance			431,802		387,533		351,843
	Depreciation			171,070		163,368		158,574
	Amortization of Regulatory Assets, Net			117,682		82,979		19,071
	Amortization of Rate Reduction Bonds			90,322		90,322		104,481
	Energy Efficiency Programs			201,234		175,747		117,091
	Taxes Other Than Income Taxes			119,219		111,705		104,978
		Total Operating Expenses		1,919,581		1,916,880		1,887,389
Operating Income				381,416		486,173		478,812
Interest Expense:
	Interest on Long-Term Debt			87,100		90,040		90,630
	Interest on Rate Reduction Bonds			3,585		7,226		11,235
	Other Interest			(20,631)		(27,839)		(30,475)
		Interest Expense		70,054		69,427		71,390
Other Income, Net				2,846		1,434		3,173
Income Before Income Tax Expense				314,208		418,180		410,595
Income Tax Expense				123,966		165,686		162,020
Net Income			$	190,242	$	252,494	$	248,575
The accompanying notes are an integral part of these consolidated financial statements.

94

NSTAR ELECTRIC COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
						Total
				Capital		Common
		Common Stock		Surplus,	Retained	Stockholder's
(Thousands of Dollars, Except Stock Information)		Stock	Amount	Paid In	Earnings	Equity
Balance as of January 1, 2010		100	$ -	$ 992,625	$ 1,100,074	$ 2,092,699
	Net Income				248,575	248,575
	Dividends on Preferred Stock				(1,960)	(1,960)
	Dividends on Common Stock				(188,200)	(188,200)
Balance as of December 31, 2010		100	-	992,625	1,158,489	2,151,114
	Net Income				252,494	252,494
	Dividends on Preferred Stock				(1,960)	(1,960)
	Dividends on Common Stock				(169,900)	(169,900)
Balance as of December 31, 2011		100	-	992,625	1,239,123	2,231,748
	Net Income				190,242	190,242
	Dividends on Preferred Stock				(1,960)	(1,960)
	Dividends on Common Stock				(217,000)	(217,000)
Balance as of December 31, 2012		100	$ -	$ 992,625	$ 1,210,405	$ 2,203,030
The accompanying notes are an integral part of these consolidated financial statements.

95

NSTAR ELECTRIC COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
			For the Years Ended December 31,
(Thousands of Dollars)			2012		2011		2010
Operating Activities:
	Net Income		$	190,242	$	252,494	$	248,575
	Adjustments to Reconcile Net Income to Net Cash Flows
		Provided by Operating Activities:
		Bad Debt Expense		40,301		22,582		29,417
		Depreciation		171,070		163,368		158,574
		Deferred Income Taxes		4,264		72,006		41,612
		Pension, SERP and PBOP Expense		66,010		54,704		60,528
		Pension Contributions		(25,000)		(125,000)		(25,000)
		Regulatory (Under)/Over Recoveries, Net		(16,129)		68,353		95,532
		Amortization of Regulatory Assets, Net		117,682		82,979		19,071
		Amortization of Rate Reduction Bonds		90,322		90,322		104,481
		Other		(32,048)		539		(76,866)
	Changes in Current Assets and Liabilities:
		Receivables and Unbilled Revenues, Net		(10,496)		(26,041)		(37,132)
		Materials and Supplies		1,813		(12,968)		3,077
		Taxes Receivable/Accrued, Net		29,899		149,889		(20,270)
		Accounts Payable		(59,217)		(53,939)		37,661
		Other Current Assets and Liabilities, Net		22,568		7,040		(93,528)
Net Cash Flows Provided by Operating Activities				591,281		746,328		545,732
Investing Activities:
	Investments in Property, Plant and Equipment			(414,089)		(390,427)		(317,046)
	Other Investing Activities			3,460		3,363		26,382
Net Cash Flows Used in Investing Activities				(410,629)		(387,064)		(290,664)
Financing Activities:
	Cash Dividends on Common Stock			(217,000)		(169,900)		(188,200)
	Cash Dividends on Preferred Stock			(1,960)		(1,960)		(1,960)
	Increase/(Decrease) in Short-Term Debt			134,500		(86,000)		(113,500)
	Issuance of Long-Term Debt			400,000		-		300,000
	Retirements of Long-Term Debt			(401,650)		(16,650)		(126,648)
	Retirements of Rate Reduction Bonds			(84,367)		(84,346)		(119,014)
	Other Financing Activities			(5,853)		-		(7,854)
Net Cash Flows Used in Financing Activities				(176,330)		(358,856)		(257,176)
Net Increase/(Decrease) in Cash and Cash Equivalents				4,322		408		(2,108)
Cash and Cash Equivalents - Beginning of Year				9,373		8,965		11,073
Cash and Cash Equivalents - End of Year			$	13,695	$	9,373	$	8,965
The accompanying notes are an integral part of these consolidated financial statements.

96

Company Report on Internal Controls Over Financial Reporting

Public Service Company of New Hampshire

Management is responsible for the preparation, integrity, and fair presentation of the accompanying consolidated financial statements of Public Service Company of New Hampshire and subsidiaries (PSNH or the Company) and of other sections of this annual report.  PSNH’s internal controls over financial reporting were audited by Deloitte & Touche LLP.

Management is responsible for establishing and maintaining adequate internal controls over financial reporting.  The Company’s internal control framework and processes have been designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.  There are inherent limitations of internal controls over financial reporting that could allow material misstatements due to error or fraud to occur and not be prevented or detected on a timely basis by employees during the normal course of business.  Additionally, internal controls over financial reporting may become inadequate in the future due to changes in the business environment.  

Under the supervision and with the participation of the principal executive officer and principal financial officer, PSNH conducted an evaluation of the effectiveness of internal controls over financial reporting based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).  Based on this evaluation under the framework in COSO, management concluded that internal controls over financial reporting were effective as of December 31, 2012.

February 27, 2013

97

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholder of Public Service Company of New Hampshire:

We have audited the accompanying consolidated balance sheets of Public Service Company of New Hampshire and subsidiaries (the "Company") as of December 31, 2012 and 2011 and the related consolidated statements of income, comprehensive income, common stockholder’s equity, and cash flows for each of the three years in the period ended December 31, 2012.  Our audits also included the financial statement schedule listed in the Index at Item 15 of Part IV.  These financial statements and financial statement schedule are the responsibility of the Company's management.  Our responsibility is to express an opinion on the financial statements and financial statement schedule based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.  The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting.  Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting.  Accordingly, we express no such opinion.  An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.  We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Public Service Company of New Hampshire and subsidiaries as of December 31, 2012 and 2011, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2012, in conformity with accounting principles generally accepted in the United States of America.  Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole present fairly in all material respects the information set forth therein.

/s/  Deloitte & Touche LLP

Hartford, Connecticut

February 27, 2013

98

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99

PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
		As of December 31,
(Thousands of Dollars)		2012		2011
ASSETS
Current Assets:
	Cash	$	2,493	$	56
	Receivables, Net		87,164		87,545
	Accounts Receivable from Affiliated Companies		723		1,294
	Notes Receivable from Affiliated Companies		-		55,900
	Unbilled Revenues		39,982		45,403
	Taxes Receivable		17,177		7,424
	Fuel, Materials and Supplies		95,345		124,744
	Regulatory Assets		62,882		34,178
	Prepayments and Other Current Assets		22,205		27,837
Total Current Assets			327,971		384,381
Property, Plant and Equipment, Net			2,352,515		2,256,688
Deferred Debits and Other Assets:
	Regulatory Assets		351,059		393,941
	Other Long-Term Assets		83,052		81,531
Total Deferred Debits and Other Assets			434,111		475,472
Total Assets		$	3,114,597	$	3,116,541
The accompanying notes are an integral part of these consolidated financial statements.

100

PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
			As of December 31,
(Thousands of Dollars)			2012		2011
LIABILITIES AND CAPITALIZATION
Current Liabilities:
	Notes Payable to Affiliated Companies		$	63,300	$	-
	Accounts Payable			62,864		106,377
	Accounts Payable to Affiliated Companies			21,337		18,895
	Accrued Interest			9,317		9,670
	Regulatory Liabilities			23,002		24,500
	Renewable Portfolio Standards Compliance Obligations			17,383		12,089
	Other Current Liabilities			41,633		24,408
Total Current Liabilities				238,836		195,939
Rate Reduction Bonds				29,294		85,368
Deferred Credits and Other Liabilities:
	Accumulated Deferred Income Taxes			441,577		392,712
	Regulatory Liabilities			52,418		54,415
	Accrued Pension, SERP and PBOP			220,129		258,718
	Other Long-Term Liabilities			47,896		53,304
Total Deferred Credits and Other Liabilities				762,020		759,149
Capitalization:
	Long-Term Debt			997,932		997,722
	Common Stockholder's Equity:
		Common Stock		-		-
		Capital Surplus, Paid In		701,052		700,285
		Retained Earnings		395,118		388,910
		Accumulated Other Comprehensive Loss		(9,655)		(10,832)
	Common Stockholder's Equity			1,086,515		1,078,363
Total Capitalization				2,084,447		2,076,085
Commitments and Contingencies (Note 12)
Total Liabilities and Capitalization			$	3,114,597	$	3,116,541
The accompanying notes are an integral part of these consolidated financial statements.

101

PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
			For the Years Ended December 31,
(Thousands of Dollars)			2012		2011		2010
Operating Revenues			$	988,013	$	1,013,003	$	1,033,439
Operating Expenses:
	Purchased Power, Fuel and Transmission			319,253		327,905		389,538
	Operations and Maintenance			263,234		278,153		274,165
	Depreciation			87,602		76,167		67,237
	Amortization of Regulatory Assets/(Liabilities), Net			(24,086)		25,383		11,232
	Amortization of Rate Reduction Bonds			56,645		53,389		50,357
	Energy Efficiency Programs			14,245		12,917		12,038
	Taxes Other Than Income Taxes			66,025		58,985		52,686
		Total Operating Expenses		782,918		832,899		857,253
Operating Income				205,095		180,104		176,186
Interest Expense:
	Interest on Long-Term Debt			46,228		36,832		36,220
	Interest on Rate Reduction Bonds			2,687		6,276		9,660
	Other Interest			1,313		1,039		1,187
		Interest Expense		50,228		44,147		47,067
Other Income, Net				3,008		14,255		11,749
Income Before Income Tax Expense				157,875		150,212		140,868
Income Tax Expense				60,993		49,945		50,801
Net Income			$	96,882	$	100,267	$	90,067
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Net Income			$	96,882	$	100,267	$	90,067
Other Comprehensive Income/(Loss), Net of Tax:
	Qualified Cash Flow Hedging Instruments			1,162		(10,260)		87
	Changes in Unrealized Gains on Other Securities			13		29		24
	Changes in Funded Status of Pension, SERP and PBOP
		Benefit Plans		2		-		-
Other Comprehensive Income/(Loss), Net of Tax				1,177		(10,231)		111
Comprehensive Income			$	98,059	$	90,036	$	90,178
The accompanying notes are an integral part of these consolidated financial statements.

102

PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
						Accumulated	Total
				Capital		Other	Common
		Common Stock		Surplus,	Retained	Comprehensive	Stockholder's
(Thousands of Dollars, Except Stock Information)		Stock	Amount	Paid In	Earnings	Income/(Loss)	Equity
Balance as of January 1, 2010		301	$ -	$ 420,169	$ 307,988	$ (712)	$ 727,445
	Net Income				90,067		90,067
	Dividends on Common Stock				(50,584)		(50,584)
	Allocation of Benefits - ESOP			439			439
	Capital Contributions from NU Parent			158,969			158,969
	Other Comprehensive Income					111	111
Balance as of December 31, 2010		301	-	579,577	347,471	(601)	926,447
	Net Income				100,267		100,267
	Dividends on Common Stock				(58,828)		(58,828)
	Allocation of Benefits - ESOP			678			678
	Capital Contributions from NU Parent			120,030			120,030
	Other Comprehensive Loss					(10,231)	(10,231)
Balance as of December 31, 2011		301	-	700,285	388,910	(10,832)	1,078,363
	Net Income				96,882		96,882
	Dividends on Common Stock				(90,674)		(90,674)
	Allocation of Benefits - ESOP			767			767
	Other Comprehensive Income					1,177	1,177
Balance as of December 31, 2012		301	$ -	$ 701,052	$ 395,118	$ (9,655)	$ 1,086,515
The accompanying notes are an integral part of these consolidated financial statements.

103

PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
			For the Years Ended December 31,
(Thousands of Dollars)			2012		2011		2010
Operating Activities:
	Net Income		$	96,882	$	100,267	$	90,067
	Adjustments to Reconcile Net Income to Net Cash Flows
		Provided by Operating Activities:
		Bad Debt Expense		6,457		7,035		8,858
		Depreciation		87,602		76,167		67,237
		Deferred Income Taxes		58,552		75,628		39,225
		Pension, SERP and PBOP Expense		26,312		27,298		29,112
		Pension and PBOP Contributions		(96,880)		(121,178)		(53,689)
		Regulatory (Under)/Over Recoveries, Net		(183)		6,079		(2,834)
		Amortization of Regulatory Assets/(Liabilities), Net		(24,086)		25,383		11,232
		Amortization of Rate Reduction Bonds		56,645		53,389		50,357
		Settlements of Cash Flow Hedge Instruments		-		(18,072)		-
		Other		4,748		(20,958)		(31,590)
	Changes in Current Assets and Liabilities:
		Receivables and Unbilled Revenues, Net		(84)		7,833		(24,497)
		Fuel, Materials and Supplies		25,897		(9,873)		14,891
		Taxes Receivable/Accrued, Net		(9,752)		5,139		10,037
		Accounts Payable		(15,248)		(4,517)		(14,427)
		Other Current Assets and Liabilities, Net		13,436		(4,915)		1,294
Net Cash Flows Provided by Operating Activities				230,298		204,705		195,273
Investing Activities:
	Investments in Property, Plant and Equipment			(203,902)		(241,772)		(296,335)
	Decrease/(Increase) in Notes Receivable from Affiliate			55,900		(55,900)		-
	Other Investing Activities			4,065		2,089		(7,819)
Net Cash Flows Used in Investing Activities				(143,937)		(295,583)		(304,154)
Financing Activities:
	Cash Dividends on Common Stock			(90,674)		(58,828)		(50,584)
	(Decrease)/Increase in Short-Term Debt			-		(30,000)		30,000
	Issuance of Long-Term Debt			-		282,000		-
	Retirements of Long-Term Debt			-		(119,800)		-
	Increase/(Decrease) in Notes Payable to Affiliate			63,300		(47,900)		21,200
	Capital Contributions from NU Parent			-		120,030		158,969
	Retirements of Rate Reduction Bonds			(56,074)		(52,879)		(49,867)
	Other Financing Activities			(476)		(4,248)		(252)
Net Cash Flows (Used in)/Provided by Financing Activities				(83,924)		88,375		109,466
Net Increase/(Decrease) in Cash				2,437		(2,503)		585
Cash - Beginning of Year				56		2,559		1,974
Cash - End of Year			$	2,493	$	56	$	2,559
The accompanying notes are an integral part of these consolidated financial statements.

104

Company Report on Internal Controls Over Financial Reporting

Western Massachusetts Electric Company

Management is responsible for the preparation, integrity, and fair presentation of the accompanying consolidated financial statements of Western Massachusetts Electric Company and subsidiary (WMECO or the Company) and of other sections of this annual report.  WMECO’s internal controls over financial reporting were audited by Deloitte & Touche LLP.

Management is responsible for establishing and maintaining adequate internal controls over financial reporting.  The Company’s internal control framework and processes have been designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.  There are inherent limitations of internal controls over financial reporting that could allow material misstatements due to error or fraud to occur and not be prevented or detected on a timely basis by employees during the normal course of business.  Additionally, internal controls over financial reporting may become inadequate in the future due to changes in the business environment.  

Under the supervision and with the participation of the principal executive officer and principal financial officer, WMECO conducted an evaluation of the effectiveness of internal controls over financial reporting based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).  Based on this evaluation under the framework in COSO, management concluded that internal controls over financial reporting were effective as of December 31, 2012.

February 27, 2013

105

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholder of Western Massachusetts Electric Company:

We have audited the accompanying consolidated balance sheets of Western Massachusetts Electric Company and subsidiary (the "Company") as of December 31, 2012 and 2011 and the related consolidated statements of income, comprehensive income, common stockholder’s equity, and cash flows for each of the three years in the period ended December 31, 2012.  Our audits also included the financial statement schedule listed in the Index at Item 15 of Part IV.  These financial statements and financial statement schedule are the responsibility of the Company's management.  Our responsibility is to express an opinion on the financial statements and financial statement schedule based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.  The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting.  Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting.  Accordingly, we express no such opinion.  An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.  We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Western Massachusetts Electric Company and subsidiary as of December 31, 2012 and 2011, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2012, in conformity with accounting principles generally accepted in the United States of America.  Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole present fairly in all material respects the information set forth therein.

/s/  Deloitte & Touche LLP

Hartford, Connecticut

February 27, 2013

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WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY
CONSOLIDATED BALANCE SHEETS
		As of December 31,
(Thousands of Dollars)		2012		2011
ASSETS
Current Assets:
	Cash	$	1	$	1
	Receivables, Net		47,297		42,757
	Accounts Receivable from Affiliated Companies		164		633
	Notes Receivable from Affiliated Companies		-		11,000
	Unbilled Revenues		16,192		16,277
	Taxes Receivable		15,513		2,263
	Regulatory Assets		42,370		35,520
	Marketable Securities		27,352		26,335
	Prepayments and Other Current Assets		7,963		6,456
Total Current Assets			156,852		141,242
Property, Plant and Equipment, Net			1,290,498		1,077,833
Deferred Debits and Other Assets:
	Regulatory Assets		221,752		233,247
	Marketable Securities		30,342		30,794
	Other Long-Term Assets		23,625		19,777
Total Deferred Debits and Other Assets			275,719		283,818
Total Assets		$	1,723,069	$	1,502,893
The accompanying notes are an integral part of these consolidated financial statements.

108

WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY
CONSOLIDATED BALANCE SHEETS
			As of December 31,
(Thousands of Dollars)			2012		2011
LIABILITIES AND CAPITALIZATION
Current Liabilities:
	Notes Payable to Affiliated Companies		$	31,900	$	-
	Long-Term Debt - Current Portion			55,000		-
	Accounts Payable			68,141		111,566
	Accounts Payable to Affiliated Companies			7,103		10,626
	Accrued Interest			8,304		7,714
	Regulatory Liabilities			21,037		33,056
	Other Current Liabilities			24,909		13,041
Total Current Liabilities				216,394		176,003
Rate Reduction Bonds				9,352		26,892
Deferred Credits and Other Liabilities:
	Accumulated Deferred Income Taxes			303,111		244,511
	Regulatory Liabilities			9,686		16,597
	Accrued Pension, SERP and PBOP			36,099		29,546
	Other Long-Term Liabilities			40,148		47,498
Total Deferred Credits and Other Liabilities				389,044		338,152
Capitalization:
	Long-Term Debt			550,270		499,545
	Common Stockholder's Equity:
		Common Stock		10,866		10,866
		Capital Surplus, Paid In		390,412		340,115
		Retained Earnings		160,577		115,506
		Accumulated Other Comprehensive Loss		(3,846)		(4,186)
	Common Stockholder's Equity			558,009		462,301
Total Capitalization				1,108,279		961,846
Commitments and Contingencies (Note 12)
Total Liabilities and Capitalization			$	1,723,069	$	1,502,893
The accompanying notes are an integral part of these consolidated financial statements.

109

WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF INCOME
			For the Years Ended December 31,
(Thousands of Dollars)			2012		2011		2010
Operating Revenues			$	441,164	$	417,315	$	395,161
Operating Expenses:
	Purchased Power and Transmission			136,086		161,480		175,604
	Operations and Maintenance			97,031		80,241		87,088
	Depreciation			29,971		26,455		23,561
	Amortization of Regulatory Assets, Net			410		4,492		1,892
	Amortization of Rate Reduction Bonds			17,632		16,523		15,494
	Energy Efficiency Programs			27,802		21,804		16,336
	Taxes Other Than Income Taxes			21,458		17,957		16,529
		Total Operating Expenses		330,390		328,952		336,504
Operating Income				110,774		88,363		58,657
Interest Expense:
	Interest on Long-Term Debt			23,462		20,023		17,988
	Interest on Rate Reduction Bonds			1,229		2,335		3,372
	Other Interest			1,943		1,254		479
		Interest Expense		26,634		23,612		21,839
Other Income, Net				2,503		1,489		2,597
Income Before Income Tax Expense				86,643		66,240		39,415
Income Tax Expense				32,140		23,186		16,325
Net Income			$	54,503	$	43,054	$	23,090
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Net Income			$	54,503	$	43,054	$	23,090
Other Comprehensive Income/(Loss), Net of Tax:
	Qualified Cash Flow Hedging Instruments			338		(4,108)		(79)
	Changes in Unrealized Gains on Other Securities			2		5		4
Other Comprehensive Income/(Loss), Net of Tax				340		(4,103)		(75)
Comprehensive Income			$	54,843	$	38,951	$	23,015
The accompanying notes are an integral part of these consolidated financial statements.

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WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
						Accumulated	Total
				Capital		Other	Common
		Common Stock		Surplus,	Retained	Comprehensive	Stockholder's
(Thousands of Dollars, Except Stock Information)		Stock	Amount	Paid In	Earnings	Income/(Loss)	Equity
Balance as of January 1, 2010		434,653	$ 10,866	$ 145,400	$ 90,549	$ (8)	$ 246,807
	Net Income				23,090		23,090
	Dividends on Common Stock				(14,882)		(14,882)
	Allocation of Benefits - ESOP			165			165
	Capital Contributions from NU Parent			102,479			102,479
	Other Comprehensive Loss					(75)	(75)
Balance as of December 31, 2010		434,653	10,866	248,044	98,757	(83)	357,584
	Net Income				43,054		43,054
	Dividends on Common Stock				(26,305)		(26,305)
	Allocation of Benefits - ESOP			259			259
	Capital Contributions from NU Parent			91,812			91,812
	Other Comprehensive Loss					(4,103)	(4,103)
Balance as of December 31, 2011		434,653	10,866	340,115	115,506	(4,186)	462,301
	Net Income				54,503		54,503
	Dividends on Common Stock				(9,432)		(9,432)
	Allocation of Benefits - ESOP			297			297
	Capital Contributions from NU Parent			50,000			50,000
	Other Comprehensive Income					340	340
Balance as of December 31, 2012		434,653	$ 10,866	$ 390,412	$ 160,577	$ (3,846)	$ 558,009
The accompanying notes are an integral part of these consolidated financial statements.

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WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF CASH FLOWS
			For the Years Ended December 31,
(Thousands of Dollars)			2012		2011		2010
Operating Activities:
	Net Income		$	54,503	$	43,054	$	23,090
	Adjustments to Reconcile Net Income to Net Cash Flows
		Provided by Operating Activities:
		Bad Debt Expense		2,294		3,133		9,747
		Depreciation		29,971		26,455		23,561
		Deferred Income Taxes		53,942		23,056		10,963
		Regulatory (Under)/Over Recoveries, Net		(19,152)		3,328		(11,048)
		Amortization of Regulatory Assets, Net		410		4,492		1,892
		Amortization of Rate Reduction Bonds		17,632		16,523		15,494
		Settlement of Cash Flow Hedge Instrument		-		(6,859)		-
		Other		(6,248)		(3,719)		(7,567)
	Changes in Current Assets and Liabilities:
		Receivables and Unbilled Revenues, Net		(8,896)		(7,263)		(6,838)
		Materials and Supplies		(2,882)		331		4,650
		Taxes Receivable/Accrued, Net		(8,311)		5,084		(393)
		Accounts Payable		(19,297)		12,956		(92)
		Other Current Assets and Liabilities, Net		581		3,824		2,406
Net Cash Flows Provided by Operating Activities				94,547		124,395		65,865
Investing Activities:
	Investments in Property, Plant and Equipment			(264,175)		(237,996)		(115,178)
	Proceeds from Sales of Marketable Securities			79,769		125,157		114,191
	Purchases of Marketable Securities			(80,529)		(125,453)		(114,587)
	Decrease/(Increase) in Notes Receivable from Affiliate			11,000		(11,000)		-
	Other Investing Activities			(28)		(1,919)		(888)
Net Cash Flows Used in Investing Activities				(253,963)		(251,211)		(116,462)
Financing Activities:
	Cash Dividends on Common Stock			(9,432)		(26,305)		(14,882)
	Issuance of Long-Term Debt			150,000		100,000		95,000
	Retirements of Long-Term Debt			(53,800)		-		-
	Increase/(Decrease) in Notes Payable to Affiliate			31,900		(20,400)		(115,700)
	Retirements of Rate Reduction Bonds			(17,540)		(16,433)		(15,410)
	Capital Contributions from NU Parent			50,000		91,812		102,479
	Other Financing Activities			8,288		(1,858)		(890)
Net Cash Flows Provided by Financing Activities				159,416		126,816		50,597
Net Change in Cash				-		-		-
Cash - Beginning of Year				1		1		1
Cash - End of Year			$	1	$	1	$	1
The accompanying notes are an integral part of these consolidated financial statements.

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NORTHEAST UTILITIES AND SUBSIDIARIES

THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARY

NSTAR ELECTRIC COMPANY AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES

WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Refer to the Glossary of Terms included in this combined Annual Report on Form 10-K for abbreviations and acronyms used throughout the combined notes to the consolidated financial statements.

1.

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

A.

About NU, CL&P, NSTAR Electric, PSNH and WMECO

NU Consolidated:  NU is a public utility holding company primarily engaged through its wholly owned regulated utility subsidiaries in the energy delivery business.  NU's wholly owned regulated utility subsidiaries included CL&P, PSNH, WMECO and Yankee Gas prior to NU's merger with NSTAR.  On April 10, 2012, NU acquired 100 percent of the outstanding common shares of NSTAR, at which time NSTAR (through a successor, NSTAR LLC) became a direct wholly owned subsidiary of NU along with its regulated utility subsidiaries, NSTAR Electric and NSTAR Gas.  NU provides energy delivery service to approximately 3.5 million electric and natural gas customers through six regulated utilities in Connecticut, Massachusetts and New Hampshire.  See Note 2, "Merger of NU and NSTAR," for further information regarding the merger.

NU, CL&P, NSTAR Electric, PSNH and WMECO are reporting companies under the Securities Exchange Act of 1934.  NU is a public utility holding company under the Public Utility Holding Company Act of 2005.  Arrangements among the regulated electric companies and other NU companies, outside agencies and other utilities covering interconnections, interchange of electric power and sales of utility property are subject to regulation by the FERC.  The Regulated companies are subject to regulation of rates, accounting and other matters by the FERC and/or applicable state regulatory commissions (the PURA for CL&P and Yankee Gas, the DPU for NSTAR Electric, NSTAR Gas and WMECO, and the NHPUC as well as certain regulatory oversight by the Vermont Public Service Board and the Maine Public Utilities Commission for PSNH).

Regulated Companies:  CL&P, NSTAR Electric, PSNH and WMECO furnish franchised retail electric service in Connecticut, Massachusetts and New Hampshire.  NSTAR Gas is engaged in the distribution and sale of natural gas to customers within central and eastern Massachusetts.  Yankee Gas owns and operates Connecticut's largest natural gas distribution system.  CL&P, NSTAR Electric, PSNH and WMECO's results include the operations of their respective distribution and transmission businesses.  PSNH and WMECO's distribution results include the operations of their respective generation businesses.  NU also has a regulated subsidiary, NPT, which was formed to construct, own and operate the Northern Pass line, a new HVDC transmission line from Québec to New Hampshire that will interconnect with a new HVDC transmission line being developed by a transmission subsidiary of HQ.  

Other:  As of December 31, 2012, NU Enterprises’ primary business consisted of Select Energy’s remaining energy wholesale marketing contracts with a municipal authority that expires on December 31, 2013 and related purchase contracts and NGS’ operation and maintenance agreements as well as its subsidiary, E.S. Boulos Company, an electrical contractor based in Maine that NU Enterprises continues to own and manage.  NUSCO, NSTAR Electric & Gas, RRR, Renewable Properties, Inc. and Properties, Inc. provide support services to NU, including its regulated companies.  Harbor Electric Energy Company, a wholly-owned subsidiary of NSTAR Electric, provides distribution service and ongoing support to its only customer, the Massachusetts Water Resources Authority.  NSTAR also has unregulated subsidiaries in telecommunications (NSTAR Communications, Inc.) and natural gas liquefaction and storage services (Hopkinton).

B.

Basis of Presentation

The consolidated financial statements of NU, CL&P, NSTAR Electric, PSNH and WMECO include the accounts of each of their respective subsidiaries.  Intercompany transactions have been eliminated in consolidation.  

The preparation of the consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent liabilities as of the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period.  Actual results could differ from those estimates.

NSTAR Electric continues to maintain reporting requirements as an SEC registrant.  The information disclosed for NSTAR Electric represents its results of operations for each of the years ended December 31, 2012, 2011 and 2010 and the financial position as of December 31, 2012 and 2011, presented on a comparable basis.  NU did not apply "push-down accounting" to NSTAR Electric, whereby the adjustments of assets and liabilities to fair value and the resultant goodwill would be shown on the financial statements of the acquired subsidiary.  NU's consolidated financial information includes NSTAR LLC and its subsidiaries' results of operations from April 10, 2012 through December 31, 2012.  

On April 10, 2012, upon consummation of the merger with NSTAR, NSTAR Electric's ownership in CYAPC and YAEC combined with CL&P's, PSNH's and WMECO's respective ownership interests in CYAPC and YAEC totaled greater than 50 percent, requiring NU to

113

consolidate CYAPC and YAEC from April 10, 2012 and forward.  The investment in CYAPC and YAEC had previously been accounted for under the equity method by NU.  The consolidation of CYAPC and YAEC results in NU recording nuclear decommissioning trust marketable securities of $340.4 million, regulatory assets of $214 million, long-term debt associated with the long-term spent nuclear fuel disposal liabilities of $179.3 million, net accumulated deferred income tax liability of $56.4 million and asset retirement obligations related to decommissioning activity of $311.4 million as of December 31, 2012.  At the NU consolidated level, intercompany transactions between CL&P, NSTAR Electric, PSNH and WMECO and the CYAPC and YAEC companies have been eliminated in consolidation.  For CL&P, NSTAR Electric, PSNH and WMECO, the investment in CYAPC and YAEC continue to be accounted for under the equity method.   See Note 1J, "Summary of Significant Accounting Policies – Equity Method Investments," for further information.

NPT, a limited liability company, was formed to construct, own and operate the Northern Pass transmission project.  NPT and Hydro Renewable Energy entered into a TSA whereby NPT will sell to Hydro Renewable Energy electric transmission rights over the Northern Pass for a 40-year term at cost of service rates.  NPT will be required to maintain a capital structure of 50 percent debt and 50 percent equity.  On April 10, 2012, upon consummation of the merger with NSTAR, an NSTAR subsidiary that owned 25 percent of NPT was merged into NUTV, resulting in NUTV owning 100 percent of NPT.  Accordingly, 100 percent ownership of NPT was reflected in Common Shareholders' Equity as of December 31, 2012 on the accompanying consolidated balance sheet.  See Note 2, "Merger of NU and NSTAR," and Note 19, "Common Shareholders' Equity and Noncontrolling Interests," for further information.

NU's utility subsidiaries are subject to the application of accounting guidance for entities with rate-regulated operations that considers the effect of regulation resulting from differences in the timing of the recognition of certain revenues and expenses from those of other businesses and industries.  NU's utility subsidiaries' energy delivery business is subject to rate-regulation that is based on cost recovery and meets the criteria for application of rate-regulated accounting.  See Note 3, "Regulatory Accounting," for further information.

Certain prior year amounts in NSTAR Electric's accompanying consolidated balance sheet, statements of income and cash flows have been reclassified between line items for comparative purposes and in order to conform to NU's presentation.  The reclassifications did not affect NSTAR Electric's net income.  The NSTAR Electric consolidated statements of cash flows were revised to correct an error in the presentation of cash deposits related to the RRBs. The impact of this revision was an increase in investing cash inflows from Other Investing Activities in an amount of $1.7 million and $24.1 million and a corresponding increase to financing cash outflows from Retirements of Rate Reduction Bonds for the years ended December 31, 2011 and 2010, respectively.  These revisions had no impact on NSTAR Electric’s results of operations or cash balance and are not deemed material, individually or in the aggregate, to the previously issued consolidated financial statements.  

Certain changes in classification and corresponding reclassifications of prior year data were made in the accompanying consolidated balance sheets and statements of income for NU, CL&P, PSNH and WMECO and statements of cash flows for NU, CL&P and WMECO for comparative purposes to conform the current year presentation.  The consolidated statements of income reflect the reclassification of transmission expenses from Other Operating Expenses, as originally reported, to Purchased Power, Fuel and Transmission and the reclassification of energy efficiency expenses primarily from Other Operating Expenses, as originally reported, to Energy Efficiency Programs.  In addition, Other Operating Expenses and Maintenance, as originally reported, were combined and are reported in aggregate as Operations and Maintenance.  The reclassifications on the statements of income were as follows:

	Transmission Expense				Energy Efficiency Expense
	For the Years Ended December 31,				For the Years Ended December 31,
(Millions of Dollars)	2011		2010		2011		2010
NU	$	77.2	$	48.9	$	131.4	$	124.0
CL&P		52.6		39.4		90.3		92.3
PSNH		19.1		26.4		12.9		12.0
WMECO		15.9		18.3		21.8		16.3

Effective January 1, 2012, NSTAR Electric changed its estimates with respect to the allowance for doubtful accounts, incurred but not reported claims on medical benefits, general and workers' compensation liabilities and compensation accruals.  The total aggregate impact of these changes in estimates on NSTAR Electric's accompanying consolidated statements was a decrease to net income of $11.4 million, after-tax, for the year ended December 31, 2012.  

In accordance with accounting guidance on noncontrolling interests in consolidated financial statements, the Preferred Stock of CL&P and the Preferred Stock of NSTAR Electric, which are not owned by NU or its consolidated subsidiaries and are not subject to mandatory redemption, have been presented as noncontrolling interests in the accompanying consolidated financial statements of NU. The Preferred Stock of CL&P and the Preferred Stock of NSTAR Electric are considered to be temporary equity and have been classified between liabilities and permanent shareholders' equity on the accompanying consolidated balance sheets of NU, CL&P and NSTAR Electric due to a provision in the preferred stock agreements of both CL&P and NSTAR Electric that grant preferred stockholders the right to elect a majority of the CL&P and NSTAR Electric Board of Directors, respectively, should certain conditions exist, such as if preferred dividends are in arrears for a specified amount of time.  The Net Income reported in the accompanying consolidated statements of income and cash flows represents consolidated net income prior to apportionment to noncontrolling interests, which is represented by dividends on preferred stock of CL&P and NSTAR Electric.

NU evaluates events and transactions that occur after the balance sheet date but before financial statements are issued and recognizes in the financial statements the effects of all subsequent events that provide additional evidence about conditions that existed

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as of the balance sheet date and discloses, but does not recognize, in the financial statements subsequent events that provide evidence about the conditions that arose after the balance sheet date but before the financial statements are issued.  See Note 23, "Subsequent Events," for further information.

C.

Recently Adopted Accounting Standards

In the first quarter of 2012, NU adopted the Financial Accounting Standards Board’s (FASB) final Accounting Standards Update (ASU) on fair value measurement.  The ASU did not have an impact on NU’s financial position, results of operations or cash flows, but required additional financial statement disclosures related to fair value measurements.  For further information, see Note 5, "Derivative Instruments," to the consolidated financial statements.  

In the first quarter of 2012, NU adopted the FASB’s final ASU on testing goodwill for impairment.  The ASU provides the election to perform a qualitative assessment to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying value; if so, quantitative testing is required.  The ASU does not change existing guidance relating to when an entity should test goodwill for impairment or the methodology to be utilized in performing quantitative testing.  NU did not utilize the election provided by this ASU in its current year evaluation of goodwill.

In the first quarter of 2012, NU adopted the FASB’s final ASU on the presentation of comprehensive income.  The ASU does not change existing guidance on which items should be presented in other comprehensive income but requires other comprehensive income to be presented as part of a single continuous statement of comprehensive income or in a statement of other comprehensive income immediately following the statement of net income.  The ASU did not affect the calculation of net income, comprehensive income or EPS.  The ASU did not have an impact on NU’s financial position, results of operations or cash flows.

D.

Cash and Cash Equivalents

Cash and cash equivalents include cash on hand and short-term cash investments that are highly liquid in nature and have original maturities of three months or less.  At the end of each reporting period, any overdraft amounts are reclassified from Cash and Cash Equivalents to Accounts Payable on the accompanying consolidated balance sheets.

E.

Provision for Uncollectible Accounts

NU, including CL&P, NSTAR Electric, PSNH and WMECO, presents its receivables at net realizable value by maintaining a provision for uncollectible accounts receivables.  This provision is determined based upon a variety of factors, including applying an estimated uncollectible account percentage to each receivable aging category, based upon historical collection and write-off experience and management's assessment of collectibility from individual customers.  Management assesses the collectibility of receivables, and if circumstances change, collectibility estimates are adjusted accordingly.  Receivable balances are written off against the provision for uncollectible accounts when the accounts are terminated and these balances are deemed to be uncollectible.

The PURA allows CL&P and Yankee Gas to accelerate the recovery of accounts receivable balances attributable to qualified customers under financial or medical duress (uncollectible hardship accounts receivable) outstanding for greater than 90 days.  As a result of the January 2011 DPU rate case decision, WMECO is allowed to recover amounts associated with basic service and certain uncollectible hardship accounts receivable in rates.  As of December 31, 2012, CL&P, WMECO and Yankee Gas had uncollectible hardship accounts receivable reserves in the amount of $65.2 million, $4.7 million and $6.4 million, respectively, with the corresponding bad debt expense recorded as Regulatory Assets or Other Long-Term Assets as these amounts are probable of recovery.  As of December 31, 2011, these amounts totaled $68.6 million, $5.4 million and $6.8 million, respectively.  These amounts are reflected in the total provision for uncollectible accounts in the table below.

The provision for uncollectible accounts, which is included in Receivables, Net on the accompanying consolidated balance sheets, was as follows:

	As of December 31,
(Millions of Dollars)	2012		2011
NU  (2)	$	165.5	$	115.7
CL&P  (2)		77.6		83.5
NSTAR Electric (1)		44.1		27.1
PSNH		6.8		7.2
WMECO (2)		8.5		10.0

⁽¹⁾

NSTAR Electric amounts are not included in NU consolidated as of December 31, 2011.

⁽²⁾

NU, CL&P and WMECO balances as of December 31, 2011 have been reclassified to include the uncollectible hardship reserve in the total provision for uncollectible accounts.

F.

Fuel, Materials and Supplies and Allowance Inventory

Fuel, Materials and Supplies include natural gas, coal, biomass, oil and materials purchased primarily for construction or operation and maintenance purposes.  Natural gas inventory, coal, biomass, and oil are valued at their respective weighted average cost.  Materials and supplies are valued at the lower of average cost or market.

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PSNH is subject to federal and state laws and regulations that regulate emissions of air pollutants, including SO₂, CO₂, and NO_x related to its regulated generation units, and uses SO₂, CO₂, and NO_x emissions allowances.  At the end of each compliance period, PSNH is required to relinquish SO₂, CO₂, and NO_x emissions allowances corresponding to the actual respective emissions emitted by its generating units over the compliance period.  SO₂ and NO_x emissions allowances are obtained through an annual allocation from the federal and state regulators that are granted at no cost and through purchases from third parties.  CO₂ emissions allowances are acquired through auctions and through purchases from third parties.  

SO₂, CO₂, and NO_x emissions allowances are recorded within Fuel, Materials and Supplies and are classified on the balance sheet as short-term or long-term depending on the period in which they are expected to be utilized against actual emissions.  As of December 31, 2012 and 2011, PSNH had $0.4 million and $0.8 million, respectively, of short-term SO₂, CO₂, and NO_x emissions allowances classified as Fuel, Materials and Supplies on the accompanying consolidated balance sheets and $19.4 million and $19.4 million, respectively, of long-term SO₂ and CO₂ emissions allowances classified as Other Long-Term Assets on the accompanying consolidated balance sheets.  

SO₂, CO₂, and NO_x emissions allowances are charged to expense based on their weighted average cost as they are utilized against emissions volumes at PSNH's generating units.  PSNH recorded expenses of $0.4 million, $5.1 million and $6.6 million for the years ended December 31, 2012, 2011, and 2010, respectively, which were included in Purchased Power, Fuel and Transmission on the accompanying consolidated statements of income.  These costs are recovered from customers through energy supply revenues.   

G.

Restricted Cash and Other Deposits

As of December 31, 2012, NU, CL&P and PSNH had $3.3 million, $1.3 million and $1.7 million, respectively, of restricted cash, primarily relating to amounts held in escrow, insurance proceeds on bondable property at PSNH and amounts related to the sale of land, which were included in Prepayments and Other Current Assets on the accompanying consolidated balance sheets.  As of December 31, 2011, these amounts were $17.9 million, $9.4 million and $7 million for NU, CL&P and PSNH, respectively.

As of December 31, 2012, NU had $14.6 million of cash collateral posted not subject to master netting agreements, primarily with ISO-NE.  As of December 31, 2011, there was no cash posted with ISO-NE and $10.9 million posted with other counterparties.

As of December 31, 2012, NU, NSTAR Electric, PSNH and WMECO had $69.4 million, $42.2 million, $22 million and $5.1 million, respectively, on deposit related to subsidiaries used to facilitate the issuance of RRBs.  As of December 31, 2011, these amounts were $29.5 million, $40.9 million, $24.4 million and $5.1 million, respectively.  These amounts are included in Prepayments and Other Current Assets and Other Long-Term Assets on the accompanying consolidated balance sheets.  As of December 31, 2011, the NSTAR Electric amount was not included in NU consolidated.

H.

Fair Value Measurements

NU, including CL&P, NSTAR Electric, PSNH, and WMECO, applies fair value measurement guidance to derivative contracts recorded at fair value and to the marketable securities held in the NU supplemental benefit trust, WMECO's spent nuclear fuel trust and CYAPC's and YAEC's nuclear decommissioning trusts.  Fair value measurement guidance is also applied to investment valuations used to calculate the funded status of NU's Pension and PBOP Plans, including NSTAR Electric's Pension Plan, and nonrecurring fair value measurements of nonfinancial assets such as goodwill and AROs.  

Fair Value Hierarchy:  In measuring fair value, NU uses observable market data when available and minimizes the use of unobservable inputs.  Inputs used in fair value measurements are categorized into three fair value hierarchy levels for disclosure purposes.  The entire fair value measurement is categorized based on the lowest level of input that is significant to the fair value measurement.  NU evaluates the classification of assets and liabilities measured at fair value on a quarterly basis, and NU's policy is to recognize transfers between levels of the fair value hierarchy as of the end of the reporting period.  The three levels of the fair value hierarchy are described below:

Level 1 - Inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities as of the reporting date.  Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.  

Level 2 - Inputs are quoted prices for similar instruments in active markets, quoted prices for identical or similar instruments in markets that are not active, and model-derived valuations in which all significant inputs are observable.

Level 3 - Quoted market prices are not available.  Fair value is derived from valuation techniques in which one or more significant inputs or assumptions are unobservable.  Where possible, valuation techniques incorporate observable market inputs that can be validated to external sources such as industry exchanges, including prices of energy and energy-related products.  

Determination of Fair Value:  The valuation techniques and inputs used in NU's fair value measurements are described in Note 2, "Merger of NU and NSTAR," Note 5, "Derivative Instruments," Note 6, "Marketable Securities," Note 7, "Asset Retirement Obligations," and Note 14, "Fair Value of Financial Instruments," to the consolidated financial statements.

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I.

Derivative Accounting

Many of CL&P's, NSTAR Electric's, PSNH's and WMECO’s contracts for the purchase and sale of energy or energy-related products are derivatives, along with NU Enterprises' remaining wholesale marketing contracts and NSTAR Gas' NYMEX futures.  The accounting treatment for energy contracts entered into varies and depends on the intended use of the particular contract and on whether or not the contract is a derivative.  

The application of derivative accounting is complex and requires management judgment in the following respects: identification of derivatives and embedded derivatives, election and designation of the "normal purchases or normal sales" (normal) exception, identifying, electing and designating hedge relationships, assessing and measuring hedge effectiveness, and determining the fair value of derivatives.  All of these judgments can have a significant impact on the consolidated financial statements.   Any change in the fair value of derivatives related to the Regulated companies is offset by a regulatory asset or liability, as this change will be recovered from or refunded to customers in future rates.

The fair value of derivatives is based upon the contract terms and conditions and the underlying market price or fair value per unit.  When quantities are not specified in the contract, the Company determines whether the contract has a determinable quantity by using amounts referenced in default provisions and other relevant sections of the contract.  The fair value of derivative assets and liabilities with the same counterparty are offset and recorded as a net derivative asset or liability on the consolidated balance sheets.  

The judgment applied in the election of the normal exception (and resulting accrual accounting) includes the conclusion that it is probable at the inception of the contract and throughout its term that it will result in physical delivery of the underlying product and that the quantities will be used or sold by the business in the normal course of business.  If facts and circumstances change and management can no longer support this conclusion, then the normal exception and accrual accounting is terminated and fair value accounting is applied prospectively.  

The remaining wholesale marketing contracts that are marked-to-market derivative contracts are not considered to be held for trading purposes, and sales and purchase activity is reported on a net basis in Purchased Power, Fuel and Transmission on the accompanying consolidated statements of income.

For further information regarding derivative contracts of NU, CL&P, NSTAR Electric and WMECO and their accounting, see Note 5, "Derivative Instruments," to the consolidated financial statements.

J.

Equity Method Investments

Regional Decommissioned Nuclear Companies:  CL&P, NSTAR Electric, PSNH and WMECO own common stock in three regional nuclear generation companies (CYAPC, YAEC and MYAPC, collectively referred to as the Yankee Companies), each of which owned a single nuclear generating facility that has been decommissioned.  On April 10, 2012, upon consummation of the merger with NSTAR, NSTAR Electric's ownership in CYAPC and YAEC combined with CL&P's, PSNH's and WMECO's respective ownership interests in CYAPC and YAEC totaled greater than 50 percent, requiring NU to consolidate CYAPC and YAEC from April 10, 2012 and forward.  The investment in CYAPC and YAEC had previously been accounted for under the equity method of accounting by NU.  For CL&P, NSTAR Electric, PSNH and WMECO, the investment in CYAPC and YAEC continues to be accounted for under the equity method.  At the NU consolidated level, intercompany transactions between CL&P, NSTAR Electric, PSNH and WMECO and the CYAPC and YAEC companies have been eliminated in consolidation.

Ownership interests in the Yankee Companies as of December 31, 2012 and 2011 were as follows:

(Percent)	CYAPC	YAEC	MYAPC
CL&P	34.5	24.5	12.0
NSTAR Electric	14.0	14.0	4.0
PSNH	5.0	7.0	5.0
WMECO	9.5	7.0	3.0

The total carrying values of CL&P's, NSTAR Electric's, PSNH's and WMECO's ownership interests in CYAPC, YAEC and MYAPC, which are included in Other Long-Term Assets on their respective accompanying consolidated balance sheets are as follows:  

	As of December 31,
(Millions of Dollars)	2012		2011 (1)
CL&P	$	1.4	$	1.4
NSTAR Electric		0.6		0.6
PSNH		0.3		0.3
WMECO		0.4		0.4

⁽¹⁾

The NSTAR Electric carrying value was not included in NU consolidated as of December 31, 2011.

For further information on the Yankee Companies, see Note 12C, "Commitments and Contingencies - Deferred Contractual Obligations," to the consolidated financial statements.

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Other Investments:  As of December 31, 2012, NU had a 37.2 percent (14.5 percent of which related to NSTAR Electric) equity ownership interest in two companies that transmit electricity imported from the Hydro-Québec system in Canada.  Prior to the merger with NSTAR on April 10, 2012, NU had a 22.7 percent equity ownership interest in these companies.  These investments are accounted for under the equity method of accounting.  NU’s investment totaled $6 million and $4.6 million as of December 31, 2012 and 2011, respectively, and NSTAR Electric's investment totaled $2.3 million and $3 million as of December 31, 2012 and 2011, respectively.  The NSTAR Electric investment was not included in NU consolidated as of December 31, 2011.  As of December 31, 2012 and 2011, NU also had an equity ownership interest of $6.8 million and $4.2 million in an energy investment fund, respectively.  

Equity investments are included in Other Long-Term Assets on the accompanying consolidated balance sheets and net earnings related to these equity investments are included in Other Income, Net on the accompanying consolidated statements of income.  

K.

Revenues

Regulated Companies:  The Regulated companies' retail revenues are based on rates approved by the state regulatory commissions.  In general, rates can only be changed through formal proceedings with the state regulatory commissions.  The Regulated companies' rates are designed to recover their incurred costs, plus an allowed rate of return on certain unrecovered costs.  The Regulated companies also utilize regulatory commission-approved tracking mechanisms to recover certain costs on a fully-reconciling basis.  These tracking mechanisms require rates to be changed periodically, with overcollections refunded to customers or undercollections collected from customers in future periods.  Beginning in 2011, WMECO was allowed to establish a revenue decoupling mechanism to recover a pre-established level of baseline distribution delivery service revenues per year, independent of actual customer usage.  Such decoupling mechanisms effectively break the relationship between kWhs consumed by customers and revenues recognized.  

Energy purchases under derivative instruments are recorded in Purchased Power, Fuel, and Transmission, and sales of energy associated with these purchases are recorded in Operating Revenues.

Regulated Companies' Unbilled Revenues:  Because customers are billed throughout the month based on pre-determined cycles rather than on a calendar month basis, an estimate of electricity or natural gas delivered to customers for which the customers have not yet been billed is calculated as of the balance sheet date.  Unbilled revenues are included in Operating Revenues on the consolidated statements of income and are assets on the consolidated balance sheets.  Actual amounts billed to customers when meter readings become available may vary from the estimated amount.

The Regulated companies estimate unbilled sales monthly using the daily load cycle method.  The daily load cycle method allocates billed sales to the current calendar month based on the daily load for each billing cycle.  The billed sales are subtracted from total month load, net of delivery losses, to estimate unbilled sales.  Unbilled revenues are estimated by first allocating unbilled sales to the respective customer classes, then applying an estimated rate by customer class to those sales.  

Regulated Companies' Transmission Revenues - Wholesale Rates:   Wholesale transmission revenues are based on formula rates that are approved by the FERC.  Wholesale transmission revenues for CL&P, NSTAR Electric, PSNH, and WMECO are collected under the ISO New England Inc. Transmission, Markets and Services Tariff (ISO-NE Tariff).  The ISO-NE Tariff includes Regional Network Service (RNS) and Schedule 21 - NU rate schedules to recover fees for transmission and other services for CL&P, PSNH and WMECO and the Schedule 21 - NSTAR rate schedules recover fees and other services for NSTAR Electric.  The RNS rate, administered by ISO-NE and billed to all New England transmission users, including CL&P, NSTAR Electric, PSNH and WMECO's transmission businesses, is reset on June 1^st of each year and recovers the revenue requirements associated with transmission facilities that benefit the entire New England region.  The Schedule 21 - NU and Schedule 21 - NSTAR rates, administered by NU, recover the revenue requirements for local transmission facilities and other transmission costs not recovered under the RNS rate.  The Schedule 21 - NU rate is reset on January 1^st and June 1^st of each year, while the Schedule 21 - NSTAR rate is reset on June 1^st of each year.  The Schedule 21 - NU and Schedule 21 - NSTAR rate calculations recover total transmission revenue requirements net of revenues received from other sources (i.e., RNS, rentals, etc.), thereby ensuring that NU recovers all of CL&P's, NSTAR Electric’s, PSNH's and WMECO's regional and local revenue requirements as prescribed in the ISO-NE Tariff.  The RNS and Schedule 21 - NU and Schedule 21 - NSTAR rates provide for the annual reconciliation and recovery or refund of estimated (or projected) costs to actual costs.  The financial impacts of differences between actual and projected costs are deferred for future recovery from, or refunded to, transmission customers.

Regulated Companies' Transmission Revenues - Retail Rates:  A significant portion of the NU transmission segment revenue comes from ISO-NE charges to the distribution businesses of CL&P, NSTAR Electric, PSNH and WMECO, each of which recovers these costs through rates charged to their retail customers.  CL&P, NSTAR Electric, PSNH and WMECO each have a retail transmission cost tracking mechanism as part of their rates, which allows the electric distribution companies to charge their retail customers for transmission costs on a timely basis.

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L.

Operating Expenses

Costs related to fuel (and natural gas costs as it related to Yankee Gas and NSTAR Gas) included in Purchased Power, Fuel and Transmission on the accompanying consolidated statements of income were as follows:

	For the Years Ended December 31,
(Millions of Dollars)	2012 (1)		2011		2010
NU	$	346.8	$	307.9	$	391.6
PSNH		103.4		115.9		184.3
Yankee Gas		145.9		191.3		206.4
NSTAR Gas		97.2		N/A		N/A
(1) Includes the NSTAR Gas costs from the date of the merger, April 10, 2012, through December 31, 2012.

M.

Allowance for Funds Used During Construction

AFUDC represents the cost of borrowed and equity funds used to finance construction and is included in the cost of the Regulated companies' utility plant.  The portion of AFUDC attributable to borrowed funds is recorded as a reduction of Other Interest Expense, and the AFUDC related to equity funds is recorded as Other Income, Net on the accompanying consolidated statements of income.  AFUDC costs are recovered from customers over the service life of the related plant in the form of increased revenue collected as a result of higher depreciation expense.

NU		For the Years Ended December 31,
(Millions of Dollars, except percentages)		2012		2011		2010
AFUDC:
	Borrowed Funds	$	5.3	$	11.8	$	10.2
	Equity Funds		6.8		22.5		16.7
Total		$	12.1	$	34.3	$	26.9
Average AFUDC Rate			3.7%		7.3%		7.1%

		For the Years Ended December 31,
		2012								2011								2010
(Millions of Dollars,				NSTAR								NSTAR								NSTAR
except percentages)		CL&P		Electric(1)		PSNH		WMECO		CL&P		Electric(1)		PSNH		WMECO		CL&P		Electric(1)		PSNH		WMECO
AFUDC:
	Borrowed Funds	$	2.5	$	0.3	$	1.6	$	0.5	$	3.3	$	0.2	$	7.1	$	0.5	$	2.7	$	0.1	$	6.6	$	0.3
	Equity Funds		1.9		-		1.9		1.0		6.0		-		13.2		1.0		4.9		-		10.4		0.6
Total		$	4.4	$	0.3	$	3.5	$	1.5	$	9.3	$	0.2	$	20.3	$	1.5	$	7.6	$	0.1	$	17.0	$	0.9
Average AFUDC Rate			3.6%		0.4%		5.9%		6.8%		8.3%		0.3%		7.1%		7.4%		8.3%		0.3%		6.8%		6.4%

⁽¹⁾

NSTAR Electric amounts are included in NU consolidated from the date of the merger, April 10, 2012, through December 31, 2012.  NSTAR Electric amounts are not included in NU consolidated for the years ended December 31, 2011 and 2010.

The Regulated companies' average AFUDC rate is based on a FERC-prescribed formula that produces an average rate using the cost of a company's short-term financings as well as a company's capitalization (preferred stock, long-term debt and common equity).  The average rate is applied to average eligible CWIP amounts to calculate AFUDC.

N.

Other Income, Net

Items included within Other Income, Net on the accompanying consolidated statements of income primarily consist of investment income/(loss), interest income, AFUDC related to equity funds and equity in earnings.  For CL&P, NSTAR Electric, PSNH and WMECO, equity in earnings relate to investments in CYAPC, YAEC and MYAPC and also NSTAR Electric's investment in two regional transmission companies, which are all accounted for on the equity method.  On an NU consolidated basis, equity in earnings relate to the investment in MYAPC and NU's investment in two regional transmission companies.  

O.

Other Taxes

Gross receipts taxes levied by the state of Connecticut are collected by CL&P and Yankee Gas from their respective customers.  These gross receipts taxes are shown on a gross basis with collections in Operating Revenues and payments in Taxes Other Than Income Taxes on the accompanying consolidated statements of income as follows:

	For the Years Ended December 31,
(Millions of Dollars)	2012		2011		2010
NU	$	135.0	$	137.8	$	143.7
CL&P		120.7		121.6		128.0

Certain sales taxes are also collected by CL&P, NSTAR Electric, WMECO, Yankee Gas and NSTAR Gas from their respective customers as agents for state and local governments and are recorded on a net basis with no impact on the accompanying consolidated statements of income.   

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P.		Supplemental Cash Flow Information
NU			As of and For the Years Ended December 31,
(Millions of Dollars)			2012		2011		2010
Cash Paid/(Received) During the Year for:
	Interest, Net of Amounts Capitalized		$	356.5	$	256.3	$	258.3
	Income Taxes			(12.8)		(76.6)		84.5
Non-Cash Investing Activities:
	Plant Additions Included in Accounts Payable (As of)			160.6		168.5		127.9

		As of and For the Years Ended December 31,
		2012								2011								2010
				NSTAR								NSTAR								NSTAR
(Millions of Dollars)		CL&P		Electric (1)		PSNH		WMECO		CL&P		Electric (1)		PSNH		WMECO		CL&P		Electric (1)		PSNH		WMECO
Cash Paid/(Received) During
	the Year for:
	Interest, Net of Amounts
	Capitalized	$	129.4	$	94.6	$	49.8	$	25.8	$	136.6	$	96.1	$	49.3	$	22.1	$	142.2	$	95.8	$	51.4	$	20.2
	Income Taxes		(42.0)		88.1		14.7		(8.4)		(27.5)		(62.2)		(29.0)		(4.9)		71.5		147.6		1.6		5.0
Non-Cash Investing Activities:
	Plant Additions Included in
	Accounts Payable (As of)		42.8		50.0		16.8		30.0		32.7		34.3		51.1		61.3		46.2		16.7		35.8		21.2

⁽¹⁾

NSTAR Electric amounts are included in NU consolidated from the date of the merger, April 10, 2012, through December 31, 2012.  NSTAR Electric amounts are not included in NU consolidated for the years ended December 31, 2011 and 2010.

The merger of NU with NSTAR on April 10, 2012 represented a significant non-cash transaction.  Refer to Note 2, "Merger of NU and NSTAR," for further information on the purchase price of NSTAR.

Q.

Related Parties

NUSCO and NSTAR Electric & Gas, NU's service companies, provide centralized accounting, administrative, engineering, financial, information technology, legal, operational, planning, purchasing, and other services to NU's companies.  RRR, Renewable Properties, Inc. and Properties, Inc., three other NU subsidiaries, construct, acquire or lease some of the property and facilities used by NU's companies.

As of both December 31, 2012 and 2011, CL&P, PSNH and WMECO had long-term receivables from NUSCO in the amounts of $25 million, $3.8 million and $5.5 million, respectively, which were included in Other Long-Term Assets on the accompanying consolidated balance sheets.  These amounts related to the funding of investments held in trust by NUSCO in connection with certain postretirement benefits for CL&P, PSNH and WMECO employees and have been eliminated in consolidation on the NU financial statements.

NSTAR Electric’s consolidated balance sheets included $70.2 million and $75.9 million in Payable to Affiliated Companies as of December 31, 2012 and 2011, respectively.  These amounts related to payments received from affiliates as a result of NSTAR Electric’s role as the sponsor of the NSTAR Pension Plan.

Included in the CL&P, NSTAR Electric, PSNH and WMECO consolidated balance sheets as of December 31, 2012 and 2011 were Accounts Receivable from Affiliated Companies and Accounts Payable to Affiliated Companies relating to transactions between CL&P, NSTAR Electric, PSNH and WMECO and other subsidiaries that are wholly owned by NU.  These amounts have been eliminated in consolidation on the NU financial statements.

The NU Foundation is an independent not-for-profit charitable entity designed to fund initiatives or entities that emphasize economic development, workforce training and education, and a clean and healthy environment.  The NSTAR Foundation is an independent not-for-profit entity designed to support local charitable organizations in NSTAR’s service territory that improve the quality of life for its customers.  The Board of Directors of both the NU Foundation and NSTAR Foundation consist of certain NU officers.  The NU Foundation and the NSTAR Foundation are not included in the consolidated financial statements of NU as they are not-for-profit entities and the Company does not have title to the Foundations' assets and cannot receive contributions back from the Foundations.  

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2.

MERGER OF NU AND NSTAR

On April 10, 2012, NU acquired 100 percent of the outstanding common shares of NSTAR.  Pursuant to the terms and conditions of the Agreement and Plan of Merger, as amended, the "Merger Agreement," NSTAR merged into NSTAR LLC, becoming a wholly-owned subsidiary of NU.  

NSTAR LLC is a holding company engaged through its subsidiaries in the energy delivery business serving electric and natural gas distribution customers in Massachusetts.  The merger was structured as a merger of equals in a tax-free exchange of shares.  As part of the merger, NSTAR shareholders received 1.312 NU common shares for each NSTAR common share owned (the "exchange ratio") as of the acquisition date.  The exchange ratio was structured to result in a no-premium merger based on the average closing share price of each company's common shares for the 20 trading days preceding the announcement of the merger in October 2010.  NU issued approximately 136 million common shares to the NSTAR shareholders as a result of the merger, which brought the total common shares outstanding to approximately 314 million shares as of April 10, 2012.  

Purchase Price:  Pursuant to the merger, all of the NSTAR common shares were exchanged at the fixed exchange ratio of 1.312 NU common shares for each NSTAR common share.  The total consideration transferred in the merger was based on the closing price of NU common shares on April 9, 2012, the day prior to the date the merger was completed, and was calculated as follows:

NSTAR common shares outstanding as of April 9, 2012 (in thousands)*			103,696
Exchange ratio			1.312
NU common shares issued for NSTAR common shares outstanding (in thousands)			136,049
Closing price of NU common shares on April 9, 2012		$	36.79
Value of common shares issued (in millions)		$	5,005
Fair value of NU replacement stock-based compensation awards related to
	pre-merger service (in millions)		33
Total purchase price (in millions)		$	5,038

*

Includes 109 thousand shares related to NSTAR stock-based compensation awards that vested immediately prior to the merger  

Certain of NSTAR’s stock-based compensation awards, including deferred shares, performance shares and all outstanding stock options, were replaced with NU awards using the exchange ratio upon consummation of the merger.  In accordance with accounting guidance for business combinations, the portion of the fair value of these awards attributable to service provided prior to the merger is included in the purchase price as it represents consideration transferred in the merger.  See Note 10D, "Employee Benefits – Share-Based Payments," for further information.

Purchase Price Allocation:  The allocation of the total purchase price to the estimated fair values of the assets acquired and liabilities assumed has been determined based on the accounting guidance for fair value measurements, which defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date.  The allocation of the total purchase price includes adjustments to record the fair value of NSTAR’s unregulated telecommunications business, regulatory assets not earning a return, lease agreements, long-term debt and the preferred stock of NSTAR Electric.  The fair values of NSTAR's assets and liabilities were determined based on significant estimates and assumptions, including Level 3 inputs, that are judgmental in nature.  These estimates and assumptions include the timing and amounts of projected future cash flows and discount rates reflecting risk inherent in future cash flows.  

The excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed was recognized as goodwill.  The completed allocation of the purchase price is as follows:

(Billions of Dollars)
Current Assets	$	0.7
Property Plant and Equipment, Net		5.1
Goodwill		3.2
Other Long-Term Assets, excluding Goodwill		2.1
Current Liabilities		(1.3)
Long-Term Liabilities		(2.7)
Long-Term Debt and Other Long-Term Obligations		(2.1)
Total Purchase Price	$	5.0

The goodwill from the merger with NSTAR of $3.2 billion has been assigned to NU's reporting units based on relative fair values.  NU's reporting units consist of Electric Distribution, Electric Transmission and Natural Gas Distribution.  See the "Goodwill" section below for the allocation of goodwill to each reporting unit.   

Pro Forma Financial Information:  The following unaudited pro forma financial information reflects the pro forma combined results of operations of NU and NSTAR and reflects the amortization of purchase price adjustments assuming the merger had taken place on January 1, 2011.  The unaudited pro forma financial information has been presented for illustrative purposes only and is not necessarily indicative of the consolidated results of operations that would have been achieved or the future consolidated results of operations of NU.  

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	For the Years Ended December 31,
(Pro forma amounts in millions, except per share amounts)	2012		2011
Operating Revenues	$	7,004	$	7,361
Net Income Attributable to Controlling Interest		630		689
Basic EPS		2.00		2.20
Diluted EPS		1.99		2.19

Pro forma net income does not include potential cost savings associated with the merger.  Pro forma net income also excludes certain non-recurring merger costs and costs related to the Connecticut and Massachusetts settlement agreements described below, with the following aggregate after-tax impacts:

		For the Years Ended December 31,
(Millions of Dollars)		2012		2011
Transaction and Other Costs		$	32	$	19
Settlement Agreement Impacts			60		-
Total After-Tax Non-Recurring Costs Excluded from
	Pro Forma Net Income Attributable to Controlling Interest	$	92	$	19

Regulatory Approvals:  On February 15, 2012, NU and NSTAR reached comprehensive settlement agreements with the Massachusetts Attorney General and the DOER related to the merger.  The Attorney General settlement agreement covered a variety of rate-making and rate design issues, including a base distribution rate freeze through 2015 for NSTAR Electric, NSTAR Gas and WMECO and $15 million, $3 million and $3 million in the form of rate credits to their respective customers.  The settlement agreement reached with the DOER covered the same rate-making and rate design issues as the Attorney General's settlement agreement, as well as a variety of matters impacting the advancement of Massachusetts clean energy policy established by the Green Communities Act and Global Warming Solutions Act.  On April 4, 2012, the DPU approved the settlement agreements and the merger of NU and NSTAR.

On March 13, 2012, NU and NSTAR reached a comprehensive settlement agreement with both the Connecticut Attorney General and the Connecticut Office of Consumer Counsel related to the merger.  The settlement agreement covered a variety of matters, including a $25 million rate credit to CL&P customers, a CL&P base distribution rate freeze until December 1, 2014, and the establishment of a $15 million fund for energy efficiency and other initiatives to be disbursed at the direction of the DEEP.  In the agreement, CL&P agreed to forego rate recovery of $40 million of the deferred storm restoration costs associated with restoration activities following Tropical Storm Irene and the October 2011 snowstorm.  On April 2, 2012, the PURA approved the settlement agreement and the merger of NU and NSTAR.

The pre-tax financial impacts of the Connecticut and Massachusetts settlement agreements that were recognized by NU, CL&P, NSTAR Electric, and WMECO are summarized as follows:

(Millions of Dollars)	NU		CL&P		NSTAR Electric		WMECO
Customer Rate Credits	$	46	$	25	$	15	$	3
Storm Costs Deferral Reduction		40		40		-		-
Establishment of Energy Efficiency Fund		15		-		-		-
Total Pre-Tax Settlement Agreement Impacts	$	101	$	65	$	15	$	3

NSTAR Revenues and Net Income:  The impact of NSTAR on NU's accompanying consolidated statement of income includes operating revenues of $1,957.8 million and net income attributable to controlling interest of $182.9 million for the year ended December 31, 2012.

Goodwill:  In a business combination, the excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed is recognized as goodwill.  Goodwill is evaluated for impairment at least annually and more frequently if indicators of impairment arise.  In accordance with the accounting standards, if the fair value of a reporting unit is less than its carrying value (including goodwill), the goodwill is tested for impairment.  A loss is recognized if the implied fair value of a reporting unit's goodwill is less than the carrying value of its goodwill.  NU uses October 1^st as the annual goodwill impairment testing date.

On April 10, 2012, upon consummation of the merger with NSTAR, NU recorded approximately $3.2 billion of goodwill.  With the completion of the NSTAR merger, NU reviewed its management structure and determined that the reporting units for the purpose of testing goodwill for impairment are Electric Distribution, Electric Transmission and Natural Gas Distribution.  NU's reporting units are consistent with the operating segments underlying the reportable segments identified in Note 21, "Segment Information," to the consolidated financial statements.  Accordingly, the goodwill resulting from the NSTAR merger has been allocated to the Electric Distribution, Electric Transmission and Natural Gas Distribution reporting units based on the estimated fair values of the reporting units as of the merger date.

As of December 31, 2011, the only reporting unit that maintained goodwill was the natural gas reportable segment, related to the acquisition of the parent of Yankee Gas in 2000.  This goodwill is recorded at Yankee Gas.  The goodwill balance at Yankee Gas as of December 31, 2012 and 2011 was $0.3 billion.

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NU completed its impairment analysis of the NSTAR and Yankee Gas goodwill balances as of October 1, 2012 and determined that no impairment exists.  In completing this analysis, the fair value of the reporting units was estimated using a discounted cash flow methodology and a market method utilizing comparable company information and market transactions.

The allocation of goodwill to NU's reporting units is as follows:

		Electric		Electric		Natural Gas
		Distribution		Transmission		Distribution		Total
Balance as of December 31, 2011		$	-	$	-	$	0.3	$	0.3
	Merger with NSTAR		2.5		0.6		0.1		3.2
Balance as of December 31, 2012		$	2.5	$	0.6	$	0.4	$	3.5

3.

REGULATORY ACCOUNTING

On April 10, 2012, NSTAR's regulated utility subsidiaries, NSTAR Electric and NSTAR Gas, became subsidiaries of NU.  For NSTAR Electric, certain regulatory asset and liability balances as of December 31, 2011 have been reclassified to the current year presentation in order to align the reporting of regulatory activities subsequent to the closing of the merger.  

NU's Regulated companies continue to be rate-regulated on a cost-of-service basis; therefore, the accounting policies of the Regulated companies apply GAAP applicable to rate-regulated enterprises and reflect the effects of the rate-making process.  

Management believes it is probable that the Regulated companies will recover their respective investments in long-lived assets, including regulatory assets.  If management determined that it could no longer apply the accounting guidance applicable to rate-regulated enterprises to the Regulated companies' operations, or that management could not conclude it is probable that costs would be recovered in future rates, the costs would be charged to net income in the period in which the determination is made.

Regulatory Assets:  The components of regulatory assets are as follows:

NU	As of December 31,
(Millions of Dollars)	2012		2011
Benefit Costs	$	2,452.1	$	1,360.5
Regulatory Assets Offsetting Derivative Liabilities		885.6		939.6
Goodwill		537.6		-
Storm Restoration Costs		547.7		356.0
Income Taxes, Net		516.2		425.4
Securitized Assets		232.6		101.8
Contractual Obligations		217.6		100.9
Power Contracts Buy Out Agreements		92.9		8.6
Regulatory Tracker Deferrals		190.1		45.9
Asset Retirement Obligations		88.8		47.5
Other Regulatory Assets		76.2		136.6
Total Regulatory Assets	$	5,837.4	$	3,522.8
Less:  Current Portion	$	705.0	$	255.1
Total Long-Term Regulatory Assets	$	5,132.4	$	3,267.7

		As of December 31,
		2012								2011
				NSTAR								NSTAR
(Millions of Dollars)		CL&P		Electric		PSNH		WMECO		CL&P		Electric(1)		PSNH		WMECO
Benefit Costs		$	563.2	$	781.2	$	223.7	$	116.0	$	572.8	$	813.7	$	200.0	$	118.9
Regulatory Assets Offsetting
	Derivative Liabilities		866.2		14.9		-		3.0		932.0		3.4		-		7.3
Goodwill			-		461.5		-		-		-		478.9		-		-
Storm Restoration Costs			413.9		55.8		34.5		43.5		268.3		30.6		44.0		43.7
Income Taxes, Net			367.5		47.1		36.2		31.0		339.6		48.8		38.0		17.8
Securitized Assets			-		205.1		19.7		7.8		-		368.5		76.4		25.4
Contractual Obligations			64.0		22.8		-		14.9		80.9		30.8		-		20.0
Power Contracts Buy Out Agreements			-		85.9		7.0		-		-		109.5		8.6		-
Regulatory Tracker Deferrals			12.2		71.4		49.3		31.9		5.5		61.1		11.9		22.1
Asset Retirement Obligations			29.4		29.4		14.2		3.5		27.9		24.5		13.5		3.2
Other Regulatory Assets			27.9		16.9		29.4		12.6		47.0		34.7		35.7		10.3
Total Regulatory Assets		$	2,344.3	$	1,792.0	$	414.0	$	264.2	$	2,274.0	$	2,004.5	$	428.1	$	268.7
Less:  Current Portion		$	185.9	$	347.1	$	62.9	$	42.4	$	170.2	$	323.9	$	34.2	$	35.5
Total Long-Term Regulatory Assets		$	2,158.4	$	1,444.9	$	351.1	$	221.8	$	2,103.8	$	1,680.6	$	393.9	$	233.2

⁽¹⁾

NSTAR Electric amounts are not included in NU consolidated as of December 31, 2011.

Regulatory Costs Not Yet Approved:  Additionally, the Regulated companies had $69.9 million ($3.9 million for CL&P, $25.4 million for NSTAR Electric, $35.7 million for PSNH, and $1.4 million for WMECO) and $32.4 million ($5 million for CL&P, $22.4 million for PSNH,

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and $1.6 million for WMECO) of regulatory costs as of December 31, 2012 and 2011, respectively, which were included in Other Long-Term Assets on the accompanying consolidated balance sheets.  For comparative purposes, NSTAR Electric had $9.5 million of such regulatory costs as of December 31, 2011.  These amounts represent incurred costs that have not yet been approved for recovery by the applicable regulatory agency.  Management believes it is probable that recovery of these costs will ultimately be approved.

For PSNH, of the total December 31, 2012 regulatory costs not yet approved, $12.1 million related to costs incurred for the 2012 Hurricane Sandy storm and $22.3 million related to costs incurred for the 2011 Tropical Storm Irene and the October snowstorm restorations that met the NHPUC criteria for cost deferral.  As of December 31, 2011, the storm restoration costs incurred for the 2011 Tropical Storm Irene and the October snowstorm restorations totaled $21.7 million.  Refer to the "Storm Restoration Costs" section below for further discussion.  The NSTAR Electric balance as of December 31, 2012 and 2011 related to costs deferred in connection with the basic service bad debt adder.  See Note 12H, "Commitments and Contingencies – Basic Service Bad Debt Adder," for further information.

Equity Return on Regulatory Assets:  For rate-making purposes, the Regulated companies recover the carrying cost, including an allowed equity return, on certain regulatory assets.  This equity return, which is not recorded on the accompanying consolidated balance sheets, totaled $2.5 million and $3.5 million for CL&P and $21.8 million and $7.6 million for PSNH as of December 31, 2012 and 2011, respectively.  These carrying costs will be recovered in future rates.  

Regulatory Assets - The following provides further information about regulatory assets:

Benefit Costs:  NU's Pension, SERP and PBOP Plans are accounted for in accordance with accounting guidance on defined benefit pension and other postretirement plans.  Under this accounting guidance, the funded status of pension and other postretirement plans is recorded with an offset to Accumulated Other Comprehensive Income/(Loss) and is remeasured annually.  However, because the Regulated companies recover these costs from customers through rates, regulatory assets are recorded as an offset for the liability that is recognized for the funded status of the pension and postretirement plans.  Regulatory accounting was also applied to the portions of the NUSCO and NSTAR Electric & Gas costs that support the Regulated companies, as these amounts are also recoverable.  CL&P and PSNH do not collect carrying charges on these deferred benefit costs regulatory assets.  WMECO's deferred benefit costs regulatory assets are earning a return at the same rate as the assets included in rate base.  NSTAR Electric does not earn a return on the regulatory assets recorded to offset the funded status.  

NSTAR Electric and WMECO each recover their qualified pension and postretirement expenses through rate reconciling mechanisms that fully track the change in net pension and postretirement expenses each year.  CL&P and PSNH will recover benefit costs through rates as allowed by their applicable regulatory commissions.  NSTAR Electric earns a carrying charge on the excess cumulative benefit plan trust fund contributions it has made over what it has cumulatively recognized as net periodic benefit expense, net of deferred income taxes.  As of December 31, 2012 and 2011, these balances were $366.8 million and $428 million of the benefit costs regulatory asset, respectively.  

Regulatory Assets Offsetting Derivative Liabilities:  The regulatory assets offsetting derivative liabilities relate to the fair value of contracts used to purchase power and other related contracts that will be collected from customers in the future.  See Note 5, "Derivative Instruments," to the consolidated financial statements for further information.  These assets are excluded from rate base and are being recovered as the actual settlement occurs over the duration of the contracts.

Goodwill: Goodwill that originated from the merger that created NSTAR in 1999 is recoverable in rates over the remaining 27 year amortization period, without a carrying charge.  

Storm Restoration Costs:  The storm restoration cost deferrals relate to costs incurred at CL&P, NSTAR Electric, PSNH and WMECO for restorations that the Company expects to collect from customers. A storm must meet certain criteria to be declared a major storm with the criteria specific to each state jurisdiction and utility company.  Once a storm is declared major, all qualifying expenses incurred during storm restoration efforts, if deemed prudent, are deferred and recovered from customers in future periods. In Connecticut, qualifying storm restoration costs must exceed $5 million for a storm to be declared a major storm.  In Massachusetts, qualifying storm restoration costs must exceed $1 million for NSTAR Electric and $300,000 for WMECO and an emergency response plan must be initiated for a storm to be declared a major storm.  In New Hampshire, (1) at least 10 percent of customers must be without power with at least 200 concurrent locations requiring repairs (trouble spots), or (2) at least 300 concurrent trouble spots must be reported for a storm to be declared a major storm.

In 2011, Tropical Storm Irene and the October snowstorm each caused extensive damage to NU’s distribution system.  As of December 31, 2012 and 2011, CL&P had recorded total deferred storm restoration costs relating to Tropical Storm Irene and the October 2011 snowstorm as a regulatory asset of $281.6 million and $263.3 million, respectively.  The CL&P storm restoration cost regulatory asset balance includes a reserve of $40 million recorded in connection with the Connecticut settlement agreement.  See Note 2, "Merger of NU and NSTAR," for further information.  As of December 31, 2012 and 2011, NSTAR Electric had recorded total deferred storm restoration costs for these 2011 storms of $35.8 million and $35.8 million, respectively, and WMECO had recorded $26.5 million and $26.7 million, respectively, as regulatory assets.   PSNH recorded $22.3 million and $21.7 million for these 2011 storms in Other Long-Term Assets, as of December 31, 2012 and 2011, respectively, as previously described.

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On August 1, 2012, PURA issued a final decision in the investigation of CL&P’s performance related to both Tropical Storm Irene and the October 2011 snowstorm.  The decision concluded that CL&P was deficient and inadequate in its preparation, response, and communication to both storms, and identified certain penalties that could be imposed on CL&P during its next rate case, including a reduction in allowed regulatory ROE and the disallowance of certain deferred storm restoration costs.  However, PURA will consider and weigh the extent to which CL&P has taken steps in its restructuring of storm management and the establishment of new practices for execution in future storm response in determining any potential penalties.  CL&P believes such steps to improve current storm preparation and response practices have been successfully executed in recent storms.  At this time, management cannot estimate the impact on CL&P’s financial position, results of operations or cash flows.  CL&P continues to believe that its response to these 2011 storms was prudent, was consistent with industry standards, and that it is probable that it will be able to recover its deferred costs.

See Note 12E, "Commitments and Contingencies – DPU Penalties for 2011 Storm Responses," for a discussion of NSTAR Electric and WMECO's 2011 storm response.

On October 29, 2012, Hurricane Sandy caused extensive damage to NU’s electric distribution system across all three states.  The cost of restoration that was deferred for future recovery from customers and recorded as a regulatory asset as of December 31, 2012 for CL&P, NSTAR Electric, and WMECO totaled $159.9 million, $27.8 million and $4.2 million, respectively.  PSNH recorded $12.1 million in Other-Long Term Assets, as previously described.  Management believes its response to the storm damage was prudent and therefore believes it is probable that CL&P, NSTAR Electric, PSNH and WMECO will be allowed to recover these deferred storm restoration costs.   Accordingly, the storm did not have a material impact to the results of operations of CL&P, NSTAR Electric, PSNH or WMECO.  Each operating company will seek recovery of these deferred storm restoration costs through its applicable regulatory recovery process.

The PSNH storm restoration costs deferral as of December 31, 2012 and 2011 related to costs incurred for a major storm in December 2008 and the February 2010 wind storm, both of which were approved for recovery and are included in rate base.

Income Taxes, Net:  The tax effect of temporary book-tax differences (differences between the periods in which transactions affect income in the financial statements and the periods in which they affect the determination of taxable income, including those differences relating to uncertain tax positions) is accounted for in accordance with the rate-making treatment of the applicable regulatory commissions and accounting guidance for income taxes.  Differences in income taxes between the accounting guidance and the rate-making treatment of the applicable regulatory commissions are recorded as regulatory assets.  As these assets are offset by deferred income tax liabilities, no carrying charge is collected. For further information regarding income taxes, see Note 11, "Income Taxes," to the consolidated financial statements.  

Securitized Assets:  In March 2005, NSTAR Electric issued $674.5 million RRBs and used the majority of the proceeds from that issuance to effect purchase power contract buyouts.   The collateralized amounts reflected as securitized regulatory assets for NSTAR Electric as of December 31, 2012 and 2011 were $14.1 million and $98.4 million, respectively.   In April 2001, PSNH issued $525 million RRBs and used the majority of the proceeds from that issuance to buydown its power contracts with an affiliate, North Atlantic Energy Corporation.  In May 2001, WMECO issued $155 million RRBs and used the majority of the proceeds from that issuance to buyout an IPP contract.  These assets are not earning an equity return and are being recovered over the amortization period of their associated RRBs.  NSTAR Electric RRBs are scheduled to fully amortize by March 15, 2013, PSNH RRBs are scheduled to fully amortize by May 1, 2013, and WMECO RRBs are scheduled to fully amortize by June 1, 2013.

NSTAR Electric's remaining balance primarily includes other costs related to purchase power contract divestitures and certain costs related to NSTAR Electric’s former generation business that are recovered with a return through the transition charge and amounted to $186.1 million and $259.8 million as of December 31, 2012 and 2011, respectively.  These cost recoveries primarily occur through September 2016 for NSTAR Electric and are subject to adjustment by the DPU.

Contractual Obligations:  Under the terms of contracts with CYAPC, YAEC and MYAPC, CL&P, NSTAR Electric, PSNH and WMECO are responsible for their proportionate share of the remaining costs of the nuclear facilities, including decommissioning.  A portion of these amounts was recorded as contractual obligations regulatory assets. These obligations for CL&P are earning a return and are being recovered through the CTA.  Amounts for NSTAR Electric are being recovered without a return through the transition charge and are anticipated to be recovered by 2015.  Amounts for WMECO are being recovered without a return and are anticipated to be recovered by 2013, the scheduled completion date of stranded cost recovery.  Amounts for PSNH were fully recovered by 2006.  As a result of the April 10, 2012 merger with NSTAR and consolidation of CYAPC and YAEC, NU's regulatory asset balance also includes the regulatory assets of CYAPC and YAEC, which amounted to $214 million as of December 31, 2012.  At the NU consolidated level, intercompany transactions between CL&P, NSTAR Electric, PSNH and WMECO and the CYAPC and YAEC companies are eliminated in consolidation.

Power Contracts Buy Out Agreements:  NSTAR Electric's balance represents the recorded contract termination liability related to certain purchase power contract buy out agreements that NSTAR Electric executed in 2004 and their future recovery through NSTAR Electric’s transition charge. NSTAR Electric does not earn a return on this regulatory asset.  The contracts’ termination payments will occur over time and will be collected from customers through NSTAR Electric’s transition charge over the same time period. The cost recovery period of these terminated contracts is through September 2016.  PSNH's balance represents payments associated with the termination of various power purchase contracts that were recorded as regulatory assets and are amortized over the remaining life of the contracts.

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Regulatory Tracker Deferrals:  Regulatory tracker deferrals are approved rate mechanisms that allow utilities to recover costs in specific business segments through reconcilable tracking mechanisms that are reviewed at least annually by the applicable regulatory commission.  The reconciliation process produces deferrals for future recovery or refund, which can be either under or over-collections to be included in future customer rates each year.  Regulatory tracker deferrals are recorded as regulatory assets if costs are in excess of collections from customers and are recorded as regulatory liabilities if collections from customers are in excess of costs.  All material regulatory tracker deferrals that are in a regulatory asset position are earning a return.  The following regulatory reconciliation mechanisms were recorded as either regulatory assets or liabilities as of December 31, 2012 and 2011:

CL&P:  The PURA has established several reconciliation mechanisms, which allow CL&P to recover costs associated with the procurement of energy for SS and LRS, congestion and other costs associated with power market rules approved by the FERC or as approved by the PURA, C&LM programs, the retail transmission of energy, certain regulatory and energy public policy costs, such as hardship protection costs and transition period property taxes, and stranded costs, such as the amortization of regulatory assets and IPP over market costs.  As part of the CTA mechanism reconciliation process, CL&P had also established an obligation to refund the variable incentive portion of its transition service procurement fee, which totaled $26.3 million as of December 31, 2011 and was recorded as a regulatory liability.  During 2012, PURA issued a decision approving a joint settlement agreement submitted October 2, 2012, by CL&P, UI, and the Connecticut Consumer Counsel, in resolution of all issues associated with the procurement incentive for 2004, 2005 and 2006.  Under the joint settlement agreement, CL&P refunded to customers $5.7 million of funds collected and associated interest.  CL&P will be allowed to retain approximately $11.5 million of procurement incentive along with the remaining accrued interest that it was not required to refund to customers.

NSTAR Electric and WMECO:  Each company recovers certain of its costs on a fully reconciling basis through DPU-approved cost recovery mechanisms.  These rate mechanisms recover costs associated with the procurement of energy for basic service, the retail transmission of energy, costs associated with electric industry restructuring, pension and postretirement benefits, and energy efficiency programs.  Costs associated with industry restructuring include RRB debt service, nuclear decommissioning costs and above-market IPP costs.  In addition, WMECO recovers costs associated with its investments in renewable energy, such as solar projects and credits given to customers who generate renewable energy.

In the January 31, 2011 rate case, WMECO received approval for a revenue decoupling reconciliation mechanism, which provides assurance that WMECO will recover a DPU pre-established level of baseline distribution delivery service revenue to manage all other distribution operating expenses and earn a level of return on its capital investment.

PSNH:  The NHPUC permits PSNH to recover the costs of providing generation, restructuring costs as a result of deregulation, the retail transmission of energy, and the cost of C&LM programs through various reconciliation mechanisms.

Asset Retirement Obligations:  The costs associated with the depreciation of the Regulated companies' ARO assets and accretion of the ARO liabilities are recorded as regulatory assets in accordance with regulatory accounting guidance.  For CL&P, NSTAR Electric and WMECO, ARO assets, regulatory assets and liabilities offset and are excluded from rate base.  PSNH's ARO assets, regulatory assets and liabilities are included in rate base.  These costs are being recovered over the life of the underlying property, plant and equipment.

Other Regulatory Assets:  Other Regulatory Assets primarily include environmental remediation costs, losses associated with the reacquisition or redemption of long-term debt, and costs related to previously recognized lost tax benefits as a result of a provision in the 2010 Healthcare Act that eliminated the tax deductibility of actuarially equivalent Medicare Part D benefits for retirees, partially offset by purchase price adjustments recorded in connection with the merger with NSTAR reflected in regulatory assets.   

Regulatory Liabilities:  The components of regulatory liabilities are as follows:

NU	As of December 31,
(Millions of Dollars)	2012		2011
Cost of Removal	$	440.8	$	172.2
Regulatory Tracker Deferrals		95.1		139.1
AFUDC Transmission Incentive		70.0		67.0
Spent Nuclear Fuel Costs and Contractual Obligations		15.4		15.4
Other Regulatory Liabilities		53.0		40.2
Total Regulatory Liabilities	$	674.3	$	433.9
Less:  Current Portion	$	134.1	$	167.8
Total Long-Term Regulatory Liabilities	$	540.2	$	266.1

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		As of December 31,
		2012								2011
				NSTAR								NSTAR
(Millions of Dollars)		CL&P		Electric		PSNH		WMECO		CL&P		Electric (1)		PSNH		WMECO
Cost of Removal		$	44.2	$	240.3	$	51.2	$	-	$	63.8	$	235.8	$	53.2	$	7.2
Regulatory Tracker Deferrals			39.1		14.4		20.4		13.7		94.4		11.7		17.3		21.3
AFUDC Transmission Incentive			56.6		4.1		-		9.3		57.7		4.3		-		9.3
Spent Nuclear Fuel Costs and
	Contractual Obligations		15.4		-		-		-		15.4		-		-		-
Wholesale Transmission Overcollections			-		-		-		5.3		4.5		-		2.6		9.5
Other Regulatory Liabilities			1.1		32.9		3.8		2.4		11.8		29.7		5.8		2.4
Total Regulatory Liabilities		$	156.4	$	291.7	$	75.4	$	30.7	$	247.6	$	281.5	$	78.9	$	49.7
Less:  Current Portion		$	32.1	$	47.5	$	23.0	$	21.0	$	108.3	$	41.6	$	24.5	$	33.1
Total Long-Term Regulatory Liabilities		$	124.3	$	244.2	$	52.4	$	9.7	$	139.3	$	239.9	$	54.4	$	16.6

⁽¹⁾

NSTAR Electric amounts are not included in NU consolidated as of December 31, 2011.  

Cost of Removal:  NU's Regulated companies currently recover amounts in rates for future costs of removal of plant assets over the lives of the assets.  The estimated cost to remove utility assets from service is recognized as a component of depreciation expense and the cumulative amounts collected from customers but not yet expended is recognized as a regulatory liability.  Expended costs that exceed amounts collected from customers are recognized as regulatory assets, as they are probable of recovery in future rates.

AFUDC Transmission Incentive:  AFUDC was recorded on 100 percent of CL&P and WMECO's CWIP for their NEEWS projects through May 31, 2011, all of which was reserved as a regulatory liability to reflect rate base recovery for 100 percent of the CWIP as a result of FERC-approved transmission incentives.  Effective June 1, 2011, FERC approved changes to the ISO-NE Tariff in order to include 100 percent of the NEEWS CWIP in regional rate base.  As a result, CL&P and WMECO no longer record AFUDC on NEEWS CWIP.  NSTAR Electric recorded AFUDC on reliability-related projects over $5 million through December 31, 2012, 50 percent of which was reserved as a regulatory liability to reflect rate base recovery for 50 percent of the CWIP as a result of FERC-approved transmission incentives.

Spent Nuclear Fuel Costs and Contractual Obligations: CL&P and WMECO currently recover amounts in rates for costs of disposal of spent nuclear fuel and high-level radioactive waste for the period prior to the sale of their ownership shares in the Millstone nuclear power stations.  Collections in excess of these costs are recorded as regulatory liabilities.  CL&P has also established a regulatory liability for the overrecovery of its proportionate share of the remaining costs, including decommissioning, of the MYAPC nuclear facility.

Wholesale Transmission Overcollections: CL&P, NSTAR Electric, PSNH and WMECO's transmission rates recover total transmission revenue requirements, recovering all regional and local revenue requirements for providing transmission service.  These rates provide for annual reconciliations to actual costs and the difference between billed and actual costs is deferred.  Regulatory liabilities are recorded for collections in excess of costs.  Regulatory assets are recorded for costs in excess of collections, as they are probable of recovery in future rates.

Other Regulatory Liabilities:  Other Regulatory Liabilities primarily includes amounts that are subject to various rate reconciling mechanisms that, as of each period end date, would result in refunds to customers.

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4.

PROPERTY, PLANT AND EQUIPMENT AND ACCUMULATED DEPRECIATION

Utility property, plant and equipment is recorded at original cost.  Original cost includes materials, labor, construction overhead and AFUDC for regulated property.  The cost of repairs and maintenance, including planned major maintenance activities, is charged to Operating Expenses as incurred.  

The following tables summarize the NU, CL&P, NSTAR Electric, PSNH and WMECO investments in utility property, plant and equipment by asset category:

NU		As of December 31,
(Millions of Dollars)		2012		2011
Distribution – Electric		$	11,438.2	$	6,540.4
Distribution - Natural Gas			2,274.2		1,247.6
Transmission			5,541.1		3,541.9
Generation			1,146.6		1,096.0
Electric and Natural Gas Utility			20,400.1		12,425.9
Other (1)			429.3		305.1
Property, Plant and Equipment, Gross			20,829.4		12,731.0
Less:  Accumulated Depreciation
	Electric and Natural Gas Utility		(5,065.1)		(3,035.5)
	Other		(171.5)		(120.2)
Total Accumulated Depreciation			(5,236.6)		(3,155.7)
Property, Plant and Equipment, Net			15,592.8		9,575.3
Construction Work in Progress			1,012.2		827.8
Total Property, Plant and Equipment, Net		$	16,605.0	$	10,403.1

⁽¹⁾

These assets represent unregulated property and are primarily comprised of building improvements at RRR and software and equipment at NUSCO as of December 31, 2012 and 2011, and telecommunications equipment at NSTAR Communications, Inc. as of December 31, 2012.

	As of December 31,
	2012								2011
			NSTAR								NSTAR
(Millions of Dollars)	CL&P		Electric		PSNH		WMECO		CL&P		Electric(1)		PSNH		WMECO
Distribution	$	4,691.3	$	4,539.9	$	1,520.1	$	724.2	$	4,419.6	$	4,334.4	$	1,451.6	$	704.3
Transmission		2,796.1		1,529.7		599.2		583.7		2,689.1		1,386.9		546.4		297.4
Generation		-		-		1,125.5		21.1		-		-		1,074.8		21.2
Property, Plant and
Equipment, Gross		7,487.4		6,069.6		3,244.8		1,329.0		7,108.7		5,721.3		3,072.8		1,022.9
Less:  Accumulated Depreciation		(1,698.1)		(1,540.1)		(954.0)		(252.1)		(1,596.7)		(1,436.0)		(893.6)		(240.5)
Property, Plant and Equipment, Net		5,789.3		4,529.5		2,290.8		1,076.9		5,512.0		4,285.3		2,179.2		782.4
Construction Work in Progress		363.7		205.8		61.7		213.6		315.4		162.0		77.5		295.4
Total Property, Plant and
Equipment, Net	$	6,153.0	$	4,735.3	$	2,352.5	$	1,290.5	$	5,827.4	$	4,447.3	$	2,256.7	$	1,077.8

⁽¹⁾

NSTAR Electric amounts are not included in NU consolidated as of December 31, 2011.

Depreciation of utility assets is calculated on a straight-line basis using composite rates based on the estimated remaining useful lives of the various classes of property (estimated useful life for PSNH distribution).  The composite rates are subject to approval by the appropriate state regulatory agency.  The composite rates include a cost of removal component, which is collected from customers during the life of the property and is recognized as a regulatory liability.  Depreciation rates are applied to property from the time it is placed in service.

Upon retirement from service, the cost of the utility asset is charged to the accumulated provision for depreciation.  The actual incurred removal costs are applied against the related regulatory liability.  

The depreciation rates for the various classes of utility property, plant and equipment aggregate to composite rates as follows:

(Percent)	2012		2011		2010
NU		2.5		2.6		2.7
CL&P		2.5		2.4		2.7
NSTAR Electric		2.8		3.0		3.0
PSNH		3.0		2.9		2.8
WMECO		3.3		2.9		2.8

128

The following table summarizes average useful lives of depreciable assets:

	Average Depreciable Life
(Years)	NU		CL&P		NSTAR Electric		PSNH		WMECO
Distribution		42.1		41.8		33.9		33.8		30.2
Transmission		45.3		39.8		46.3		42.1		47.5
Generation		32.7		-		-		32.8		25.0
Other		16.7		-		-		-		-

5.

DERIVATIVE INSTRUMENTS

The Regulated companies purchase and procure energy and energy-related products for their customers, which are subject to price volatility.  The costs associated with supplying energy to customers are recoverable through customer rates.  The Regulated companies manage the risks associated with the price volatility of energy and energy-related products through the use of derivative contracts, many of which meet the definition of and are designated as "normal purchases or normal sales" (normal) under the applicable accounting guidance, and the use of nonderivative contracts.

Derivative contracts that are not recorded as normal are recorded at fair value as current or long-term derivative assets or liabilities.  For the Regulated companies, regulatory assets or liabilities are recorded for the changes in fair values of derivatives, as costs are, and management believes they will continue to be, recovered from or refunded in customers rates.  For NU's remaining unregulated wholesale marketing contracts, changes in fair values of derivatives are included in Net Income.  The costs and benefits of derivative contracts that meet the definition of normal are recognized in Operating Expenses or Operating Revenues on the accompanying consolidated statements of income, as applicable, as electricity or natural gas is delivered.

CL&P, NSTAR Electric and WMECO mitigate the risks associated with the price volatility of energy and energy-related products through the use of SS, LRS, and basic service contracts, which fix the price of electricity purchased for customers and are accounted for as normal.  CL&P, NSTAR Electric and WMECO have entered into derivative and nonderivative contracts for the purchase of energy and energy-related products and contracts that are derivatives.  NU also has NYMEX future contracts in order to reduce variability associated with the purchase price of approximately 11.5 million MMBtu of natural gas.  

The costs or benefits from all of the Regulated companies' derivative contracts are recoverable from or refundable to customers, and therefore, changes in fair value are recorded as Regulatory Assets or Regulatory Liabilities on the accompanying consolidated balance sheets.

NU, through Select Energy, has one remaining fixed price forward sales contract that expires on December 31, 2013 to serve electrical load that is part of its remaining unregulated wholesale energy marketing portfolio.  NU mitigates the price risk associated with this contract through the use of several forward purchase contracts.  The contracts are accounted for at fair value, and changes in their fair values are recorded in Purchased Power, Fuel and Transmission on the accompanying consolidated statements of income.  

The gross fair values of derivative assets and liabilities with the same counterparty are offset and reported as net Derivative Assets or Derivative Liabilities, with current and long-term portions, in the accompanying consolidated balance sheets.  Cash collateral posted or collected under master netting agreements is recorded as an offset to the derivative asset or liability.  The following tables present the gross fair values of contracts categorized by risk type and the net amounts recorded as current or long-term derivative asset or liability:

129

		As of December 31, 2012
		Commodity Supply and		Collateral		Net Amount Recorded as
(Millions of Dollars)		Price Risk Management		and Netting  (1)		Derivative Asset/(Liability) (2)
Current Derivative Assets:
Level 2:
	Other	$	0.2	$	-	$	0.2
Level 3:
	CL&P		17.7		(12.0)		5.7
	Other		5.5		-		5.5
Total Current Derivative Assets		$	23.4	$	(12.0)	$	11.4
Long-Term Derivative Assets:
Level 3:
	CL&P	$	159.7	$	(69.1)	$	90.6
Total Long-Term Derivative Assets		$	159.7	$	(69.1)	$	90.6
Current Derivative Liabilities:
Level 2:
	Other	$	(19.9)	$	0.6	$	(19.3)
Level 3:
	CL&P		(96.9)		-		(96.9)
	NSTAR Electric		(1.0)		-		(1.0)
Total Current Derivative Liabilities		$	(117.8)	$	0.6	$	(117.2)
Long-Term Derivative Liabilities:
Level 2:
	Other	$	(0.2)	$	-	$	(0.2)
Level 3:
	CL&P		(865.6)		-		(865.6)
	NSTAR Electric		(13.9)		-		(13.9)
	WMECO		(3.0)		-		(3.0)
Total Long-Term Derivative Liabilities		$	(882.7)	$	-	$	(882.7)

		As of December 31, 2011
		Commodity Supply and		Collateral		Net Amount Recorded as
(Millions of Dollars)		Price Risk Management		and Netting (1)		Derivative Asset/(Liability) (2)
Current Derivative Assets:
Level 3:
	CL&P	$	17.9	$	(11.6)	$	6.3
	Other		4.7		-		4.7
Total Current Derivative Assets (3)		$	22.6	$	(11.6)	$	11.0
Long-Term Derivative Assets:
Level 3:
	CL&P	$	174.2	$	(80.4)	$	93.8
	Other		4.6		-		4.6
Total Long-Term Derivative Assets		$	178.8	$	(80.4)	$	98.4
Current Derivative Liabilities:
Level 3:
	CL&P	$	(95.9)	$	-	$	(95.9)
	WMECO		(0.1)		-		(0.1)
	Other		(16.1)		4.5		(11.6)
Total Current Derivative Liabilities		$	(112.1)	$	4.5	$	(107.6)
Long-Term Derivative Liabilities:
Level 3:
	CL&P	$	(935.8)	$	-	$	(935.8)
	WMECO		(7.2)		-		(7.2)
	Other		(17.3)		0.4		(16.9)
Total Long-Term Derivative Liabilities (4)		$	(960.3)	$	0.4	$	(959.9)

⁽¹⁾

Amounts represent cash collateral posted under master netting agreements and the netting of derivative assets and liabilities.  See "Credit Risk" below for discussion of cash collateral posted under master netting agreements.

⁽²⁾

Current derivative assets are included in Prepayments and Other Current Assets on the accompanying consolidated balance sheets.  NSTAR Electric and WMECO derivative liabilities are included in Other Current Liabilities and Other Long-Term Liabilities on their accompanying consolidated balance sheets.  

130

⁽³⁾

In addition to the amounts reflected in the table, as of December 31, 2011, NU had $2.3 million of hedging instruments that were classified as Level 2 in the fair value hierarchy, which related to a fair value hedge that expired on April 2, 2012 and was included in Prepayments and Other Current Assets on the accompanying consolidated balance sheet.

⁽⁴⁾

As of December 31, 2011, NSTAR Electric had $3.4 million of derivative liabilities classified as Level 3 within the fair value hierarchy and included in Other Long-Term Liabilities on the accompanying NSTAR Electric consolidated balance sheet.  These amounts are not included in NU consolidated as of December 31, 2011.

The business activities of the Company that resulted in the recognition of derivative assets also create exposure to various counterparties.  As of December 31, 2012, NU and CL&P's derivative assets are exposed to counterparty credit risk.  Of these amounts, $96.5 million and $96.3 million, respectively, is contracted with investment grade entities and the remainder is contracted with multiple other counterparties.   

For further information on the fair value of derivative contracts, see Note 1H, "Summary of Significant Accounting Policies - Fair Value Measurements," and Note 1I, "Summary of Significant Accounting Policies - Derivative Accounting," to the consolidated financial statements.

Derivatives Not Designated as Hedges

Commodity Supply and Price Risk Management:  As required by regulation, CL&P has capacity-related contracts with generation facilities.  These contracts and similar UI contracts have an expected capacity of 787 MW.  CL&P has a sharing agreement with UI, with 80 percent of each contract allocated to CL&P and 20 percent allocated to UI.  The capacity contracts extend through 2026 and obligate the utilities to make or receive payments on a monthly basis to or from the generation facilities based on the difference between a set capacity price and the forward capacity market price received in the ISO-NE capacity markets.  In addition, CL&P has a contract to purchase 0.1 million MWh of energy per year through 2020.  

NSTAR Electric has a renewable energy contract to purchase 0.1 million MWh of energy per year through 2018.  NSTAR Electric also has a capacity related contract for up to 35 MW that extends through 2019.

WMECO has a renewable energy contract to purchase 0.1 million MWh of energy per year through 2028 with a facility that is expected to achieve commercial operation by November 2013.  

As of December 31, 2012 and 2011, NU had approximately 24 thousand MWh and 123 thousand MWh, respectively, of supply volumes remaining in its unregulated wholesale portfolio when expected sales are compared with supply contracts.

The following table presents the realized and unrealized gains/(losses) associated with NU’s derivative contracts not designated as hedges (See Level 3 tables in the "Valuations using significant unobservable inputs" section for CL&P, NSTAR Electric and WMECO gains and losses on derivative contracts):

Location of Amounts		Amounts Recognized on Derivatives
Recognized on Derivatives		For the Years Ended December 31,
(Millions of Dollars)		2012		2011		2010
NU
Balance Sheet:
	Regulatory Assets	$	(29.0)	$	(162.0)	$	(95.7)
Statement of Income:
	Purchased Power, Fuel and Transmission		(0.7)		0.5		2.7

Hedging Instruments  

Fair Value Hedge:  NU parent had a fixed to floating interest rate swap on its $263 million, fixed rate senior note that matured on April 1, 2012.  This interest rate swap qualified and was designated as a fair value hedge.  Prior to the settlement of the swap on April 2, 2012, $2.5 million of interest benefit was recorded in Net Income in the first quarter of 2012.  For the years ended December 31, 2011 and 2010, $10.5 million and $10.9 million of interest benefit was recorded in Net Income, respectively.

Cash Flow Hedges:  In 2011, PSNH and WMECO settled interest rate swaps associated with $280 million and $50 million, respectively, of long-term debt issuances and as a result PSNH and WMECO recorded pre-tax reductions of $18.2 million and $6.9 million, respectively, to AOCI that are being amortized over the remaining lives of the associated debt.  In addition, NU, CL&P, PSNH and WMECO continue to amortize interest rate swaps settled in prior years from AOCI into Interest Expense over the remaining life of the associated long-term debt. The pre-tax impact of cash flow hedging instruments on AOCI is as follows:

	Gains/(Losses) Recognized on		Gains/(Losses) Reclassified from AOCI
	Derivative Instruments		into Interest Expense
	For the Year Ended December 31,		For the Years Ended December 31,
(Millions of Dollars)	2011		2012		2011		2010
NU	$	(25.1)	$	(3.3)	$	(1.3)	$	(0.4)
CL&P		-		(0.7)		(0.7)		(0.7)
PSNH		(18.2)		(2.0)		(0.8)		(0.2)
WMECO		(6.9)		(0.5)		(0.1)		0.1

131

For further information, see Note 15, "Accumulated Other Comprehensive Income/(Loss)," to the consolidated financial statements.

Credit Risk

Certain of NU’s contracts contain credit risk contingent features.  These features require NU to maintain investment grade credit ratings from the major rating agencies and to post collateral for contracts in a net liability position over specified credit limits.  The following summarizes the fair value of derivative contracts that were in a net liability position and subject to credit risk contingent features, the fair value of cash collateral, and the additional collateral that would be required to be posted by NU if the unsecured debt credit ratings of NU parent were downgraded to below investment grade as of December 31, 2012 and 2011:

As of December 31, 2012

As of December 31, 2011

Additional Collateral

Additional Collateral

Fair Value Subject

Required if

Fair Value Subject

Required if

to Credit Risk

Cash

Downgraded Below

to Credit Risk

Cash

Downgraded Below

(Millions of Dollars)

Contingent Features

Collateral Posted

Investment Grade

Contingent Features

Collateral Posted

Investment Grade

NU

$

(15.3)

$

-

$

17.4

$

(23.5)

$

4.1

$

19.9

Fair Value Measurements of Derivative Instruments

Valuation of Derivative Instruments:  Derivative contracts classified as Level 2 in the fair value hierarchy relate to the financial contracts for natural gas futures and the remaining unregulated wholesale marketing sourcing contracts to purchase energy for periods in which prices are quoted in an active market.  Prices are obtained from broker quotes and are based on actual market activity.  The contracts are valued using the mid-point of the bid-ask spread.  Valuations of these contracts also incorporate discount rates using the yield curve approach.  

The fair value of derivative contracts classified as Level 3 utilize significant unobservable inputs.  The fair value is modeled using income techniques, such as discounted cash flow approaches adjusted for assumptions relating to exit price.  Significant observable inputs for valuations of these contracts include energy and energy-related product prices in future years for which quoted prices in an active market exist.  Fair value measurements categorized in Level 3 of the fair value hierarchy are prepared by individuals with expertise in valuation techniques, pricing of energy and energy-related products, and accounting requirements.  The future power and capacity prices for periods that are not quoted in an active market or established at auction are based on available market data and are escalated based on estimates of inflation to address the full time period of the contract.  

Valuations of derivative contracts using discounted cash flow methodology include assumptions regarding the timing and likelihood of scheduled payments and also reflect non-performance risk, including credit, using the default probability approach based on the counterparty's credit rating for assets and the company's credit rating for liabilities.   Valuations incorporate estimates of premiums or discounts that would be required by a market participant to arrive at an exit price, using historical market transactions adjusted for the terms of the contract.

The following is a summary of NU’s, including CL&P’s, NSTAR Electric’s and WMECO’s, Level 3 derivative contracts and the range of the significant unobservable inputs utilized in the valuations over the duration of the contracts:

	Range	Period Covered
Energy Prices:
NU	$43 - $90 per MWh	2018 - 2028
CL&P	$50 - $55 per MWh	2018 - 2020
WMECO	$43 - $90 per MWh	2018 - 2028
Capacity Prices:
NU	$1.40 - $10.53 per kW-Month	2016 - 2028
CL&P	$1.40 - $9.83 per kW-Month	2016 - 2026
NSTAR Electric	$1.40 - $3.39 per kW-Month	2016 - 2019
WMECO	$1.40 - $10.53 per kW-Month	2016 - 2028
Forward Reserve:
NU, CL&P	$0.35 - $0.90 per kW-Month	2013 - 2024
REC Prices:
NU	$25 - $85 per REC	2013 - 2028
NSTAR Electric	$25 - $71 per REC	2013 - 2018
WMECO	$25 - $85 per REC	2013 - 2028

Exit price premiums of 11 percent through 32 percent are also applied on these contracts and reflect the most recent market activity available for similar type contracts.

Significant increases or decreases in future power or capacity prices in isolation would decrease or increase, respectively, the fair value of the derivative liability.  Any increases in the risk premiums would increase the fair value of the derivative liabilities.  Changes in these fair values are recorded as a regulatory asset or liability and would not impact net income.  

132

Valuations using significant unobservable inputs:  The following tables present changes for the years ended December 31, 2012 and 2011, in the Level 3 category of derivative assets and derivative liabilities measured at fair value on a recurring basis.  The derivative assets and liabilities are presented on a net basis.  The fair value as of January 1, 2012 reflects a reclassification of remaining unregulated wholesale marketing sourcing contracts that had previously been presented as a portfolio along with the unregulated wholesale marketing sales contract as Level 3 under the highest and best use valuation premise.  These contracts are now classified within Level 2 of the fair value hierarchy.

(Millions of Dollars)		NU		CL&P		NSTAR Electric(1)		WMECO
Derivatives, Net:
Fair Value as of January 1, 2011		$	(840.2)	$	(806.1)	$	(2.4)	$	-
Net Realized/Unrealized Gains/(Losses) Included in:
	Net Income		0.5		-		-		-
	Regulatory Assets		(161.0)		(153.6)		(4.3)		(7.3)
Settlements			38.5		28.1		3.3		-
Fair Value as of December 31, 2011		$	(962.2)	$	(931.6)	$	(3.4)	$	(7.3)
Liabilities Assumed due to Merger with NSTAR			(5.4)		-		-		-
Transfer to Level 2			32.2		-		-		-
Net Realized/Unrealized Gains/(Losses) Included in:
	Net Income (2)		10.9		-		-		-
	Regulatory Assets		(29.2)		(21.6)		(15.2)		4.3
Settlements			75.1		87.0		3.7		-
Fair Value as of December 31, 2012		$	(878.6)	$	(866.2)	$	(14.9)	$	(3.0)

⁽¹⁾

NSTAR Electric amounts are included in NU consolidated from the date of the merger, April 10, 2012, through December 31, 2012.  NSTAR Electric amounts are not included in NU consolidated for the year ended December 31, 2011.

⁽²⁾

The Net Income impact for the year ended December 31, 2012 relates to the unregulated wholesale marketing sales contract and is offset by the gains/(losses) on the unregulated sourcing contracts classified as Level 2 in the fair value hierarchy, resulting in total net losses of $0.7 million.

6.

MARKETABLE SECURITIES (NU, WMECO)

NU maintains a supplemental benefit trust to fund certain of NU’s non-qualified executive retirement benefit obligations and WMECO maintains a spent nuclear fuel trust to fund WMECO’s prior period spent nuclear fuel liability, each of which hold marketable securities.  These trusts are not subject to regulatory oversight by state or federal agencies.  As of April 10, 2012, upon consummation of the merger with NSTAR and consolidation of CYAPC and YAEC, NU's marketable securities also includes legally restricted trusts for the decommissioning of nuclear power plants.

The Company elects to record mutual funds purchased by the NU supplemental benefit trust at fair value.  As such, any change in fair value of these mutual funds is reflected in Net Income.  These mutual funds, classified as Level 1 in the fair value hierarchy, totaled $47 million and $41.1 million as of December 31, 2012 and 2011, respectively, and are included in current Marketable Securities.  Net gains on these securities of $5.9 million and net losses of $1.1 million for the years ended December 31, 2012 and 2011, respectively, were recorded in Other Income, Net on the accompanying consolidated statements of income.  Dividend income is recorded when dividends are declared and is recorded in Other Income, Net on the accompanying consolidated statements of income.  All other marketable securities are accounted for as available-for-sale.  

Available-for-Sale Securities:  The following is a summary of NU's available-for-sale securities held in the NU supplemental benefit trust, WMECO's spent nuclear fuel trust and CYAPC and YAEC's nuclear decommissioning trusts.  These securities are recorded at fair value and included in current and long-term Marketable Securities on the accompanying consolidated balance sheets.

		As of December 31, 2012
				Pre-Tax		Pre-Tax
		Amortized		Unrealized		Unrealized
(Millions of Dollars)		Cost		Gains(1)		Losses(1)		Fair Value
NU
	Debt Securities (2)	$	266.6	$	13.3	$	(0.1)	$	279.8
	Equity Securities (2)		145.5		20.0		-		165.5
WMECO
	Debt Securities		57.7		0.1		(0.1)		57.7
		As of December 31, 2011
				Pre-Tax		Pre-Tax
		Amortized		Unrealized		Unrealized
(Millions of Dollars)		Cost		Gains(1)		Losses(1)		Fair Value
NU		$	88.4	$	2.0	$	(0.2)	$	90.2
WMECO			57.3		-		(0.2)		57.1

133

⁽¹⁾

Unrealized gains and losses on debt securities for the NU supplemental benefit trust and WMECO spent nuclear fuel trust are recorded in AOCI and Other Long-Term Assets, respectively, on the accompanying consolidated balance sheets.  

⁽²⁾

NU's December 31, 2012 amounts include CYAPC's and YAEC's marketable securities held in nuclear decommissioning trusts of $340.4 million, the majority of which are legally restricted and can only be used for the decommissioning of the nuclear power plants owned by these companies. Unrealized gains and losses for the nuclear decommissioning trusts are offset in Other Long-Term Liabilities on the accompanying consolidated balance sheet.  All of the equity securities accounted for as available-for-sale securities are held in these trusts.

Unrealized Losses and Other-than-Temporary Impairment:  There have been no significant unrealized losses, other-than-temporary impairments or credit losses for the NU supplemental benefit trust, the WMECO spent nuclear fuel trust, and in the trusts held by CYAPC and YAEC. Factors considered in determining whether a credit loss exists include the duration and severity of the impairment, adverse conditions specifically affecting the issuer, and the payment history, ratings and rating changes of the security.  For asset-backed debt securities, underlying collateral and expected future cash flows are also evaluated.

Realized Gains and Losses:  Realized gains and losses on available-for-sale securities are recorded in Other Income, Net for the NU supplemental benefit trust, Other Long-Term Assets for the WMECO spent nuclear fuel trust, and offset in Other Long-Term Liabilities for CYAPC and YAEC.  NU utilizes the specific identification basis method for the NU supplemental benefit trust securities and the average cost basis method for the WMECO spent nuclear fuel trust and the CYAPC and YAEC nuclear decommissioning trusts to compute the realized gains and losses on the sale of available-for-sale securities.   

Contractual Maturities:  As of December 31, 2012, the contractual maturities of available-for-sale debt securities are as follows:   

	NU				WMECO
	Amortized				Amortized
(Millions of Dollars)	Cost		Fair Value		Cost		Fair Value
Less than one year (1)	$	66.6	$	66.6	$	27.4	$	27.4
One to five years		57.3		58.7		17.5		17.5
Six to ten years		51.2		54.6		6.0		6.1
Greater than ten years		91.5		99.9		6.8		6.7
Total Debt Securities	$	266.6	$	279.8	$	57.7	$	57.7

⁽¹⁾

Amounts in the Less than one year NU category include securities in the nuclear decommissioning trusts, which are restricted and are classified in long-term Marketable Securities on the accompanying consolidated balance sheet.

Fair Value Measurements:  The following table presents the marketable securities recorded at fair value on a recurring basis by the level in which they are classified within the fair value hierarchy:

			NU				WMECO
			As of December 31,				As of December 31,
(Millions of Dollars)			2012		2011		2012		2011
Level 1:
	Mutual Funds and Equities		$	212.5	$	41.1	$	-	$	-
	Money Market Funds			40.2		1.8		5.2		0.1
Total Level 1			$	252.7	$	42.9	$	5.2	$	0.1
Level 2:
	U.S. Government Issued Debt Securities
		(Agency and Treasury)		69.9		11.1		18.7		8.0
	Corporate Debt Securities			33.0		16.5		7.0		9.1
	Asset-Backed Debt Securities			28.5		25.9		10.9		7.9
	Municipal Bonds			93.8		16.1		11.6		15.4
	Other Fixed Income Securities			14.4		18.8		4.3		16.6
Total Level 2			$	239.6	$	88.4	$	52.5	$	57.0
Total Marketable Securities			$	492.3	$	131.3	$	57.7	$	57.1

U.S. government issued debt securities are valued using market approaches that incorporate transactions for the same or similar bonds and adjustments for yields and maturity dates.  Corporate debt securities are valued using a market approach, utilizing recent trades of the same or similar instrument and also incorporating yield curves, credit spreads and specific bond terms and conditions.  Asset-backed debt securities include collateralized mortgage obligations, commercial mortgage backed securities, and securities collateralized by auto loans, credit card loans or receivables.  Asset-backed debt securities are valued using recent trades of similar instruments, prepayment assumptions, yield curves, issuance and maturity dates and tranche information.  Municipal bonds are valued using a market approach that incorporates reported trades and benchmark yields.  Other fixed income securities are valued using pricing models, quoted prices of securities with similar characteristics, and discounted cash flows.

134

7.

ASSET RETIREMENT OBLIGATIONS

In accordance with accounting guidance for conditional AROs, NU, including CL&P, NSTAR Electric, PSNH and WMECO, recognizes a liability for the fair value of an ARO on the obligation date if the liability's fair value can be reasonably estimated and is conditional on a future event.  Settlement dates and future costs are reasonably estimated when sufficient information becomes available.  Management has identified various categories of AROs, primarily certain assets containing asbestos and hazardous contamination and has performed fair value calculations, reflecting expected probabilities for settlement scenarios.

The fair value of an ARO is recorded as a liability in Other Long-Term Liabilities with a corresponding amount included in Property, Plant and Equipment, Net on the accompanying consolidated balance sheets.  As the Regulated companies are rate-regulated on a cost-of-service basis, these companies apply regulatory accounting guidance and the costs associated with the Regulated companies' AROs are included in Regulatory Assets as of December 31, 2012 and 2011.  The ARO assets are depreciated, and the ARO liabilities are accreted over the estimated life of the obligation with corresponding credits recorded as accumulated depreciation and ARO liabilities, respectively.  Both the depreciation and accretion were recorded as increases to Regulatory Assets on the accompanying consolidated balance sheets as of December 31, 2012 and 2011.  For further information, see Note 3, "Regulatory Accounting," to the consolidated financial statements.  

A reconciliation of the beginning and ending carrying amounts of Regulated companies’ ARO liabilities are as follows:

NU			As of December 31,
(Millions of Dollars)			2012		2011
Balance as of Beginning of Year			$	56.2	$	53.3
Liability Assumed Upon Consolidation of CYAPC and YAEC				284.2		-
Liability Assumed Upon Merger With NSTAR				35.9		-
Liabilities Incurred During the Year				1.5		2.1
Liabilities Settled During the Year				(7.2)		(0.8)
Accretion				20.2		3.5
Revisions in Estimated Cash Flows				21.4		(1.9)
Balance as of End of Year			$	412.2	$	56.2
	As of December 31,
	2012								2011
			NSTAR								NSTAR
(Millions of Dollars)	CL&P		Electric		PSNH		WMECO		CL&P		Electric(1)		PSNH		WMECO
Balance as of Beginning of Year	$	32.2	$	27.5	$	17.0	$	4.0	$	29.3	$	26.2	$	17.6	$	3.6
Liabilities Incurred During the Year		-		-		0.3		-		1.7		-		0.2		0.2
Liabilities Settled During the Year		(0.9)		(1.0)		-		-		(0.8)		-		-		-
Accretion		2.0		1.5		1.1		0.3		2.0		1.3		1.1		0.2
Revisions in Estimated Cash Flows		0.3		3.4		-		-		-		-		(1.9)		-
Balance as of End of Year	$	33.6	$	31.4	$	18.4	$	4.3	$	32.2	$	27.5	$	17.0	$	4.0
(1)NSTAR Electric amounts are not included in NU consolidated as of December 31, 2011.

The Liability Assumed Upon Consolidation of CYAPC and YAEC represents the CYAPC and YAEC ARO fair value as of the merger date.  The fair value of the ARO for CYAPC and YAEC includes uncertainties of the fuel off-load dates related to the DOE’s timing of performance regarding its obligation to dispose of the spent nuclear fuel and high level waste.  The incremental asset recorded as an offset to the ARO was fully depreciated since the plants have no remaining useful life.  Any changes in the assumptions used to calculate the fair value of the ARO are recorded as an offset to the related regulatory asset.  The assets held in the decommissioning trust are restricted for settling the asset retirement obligation and all other decommissioning obligations.  For further information on the regulatory asset established or the assets held in trust to support this obligation, see Note 3, "Regulatory Accounting," and Note 6, "Marketable Securities," to the consolidated financial statements.

8.

SHORT-TERM DEBT

Limits:  The amount of short-term borrowings that may be incurred by CL&P, NSTAR Electric and WMECO is subject to periodic approval by the FERC. On November 30, 2011, the FERC granted authorization to allow CL&P and WMECO to incur total short-term borrowings up to a maximum of $450 million and $300 million, respectively, effective January 1, 2012 through December 31, 2013.  On March 22, 2012, the FERC approved CL&P's application requesting to increase its total short-term borrowing capacity from a maximum of $450 million to a maximum of $600 million for the authorization period through December 31, 2013.  On May 16, 2012, the FERC granted authorization to allow NSTAR Electric to issue total short-term debt securities in an aggregate principal amount not to exceed $655 million outstanding at any one time, effective October 23, 2012 through October 23, 2014.  As a result of the NHPUC having jurisdiction over PSNH's short-term debt, PSNH is not currently required to obtain FERC approval for its short-term borrowings.  

135

PSNH is authorized by regulation of the NHPUC to incur short-term borrowings up to 10 percent of net fixed plant plus an additional $60 million until further ordered by the NHPUC.  As of December 31, 2012, PSNH's short-term debt authorization under the 10 percent of net fixed plant test plus $60 million totaled approximately $280 million.  

CL&P's certificate of incorporation contains preferred stock provisions restricting the amount of unsecured debt that CL&P may incur, including limiting unsecured indebtedness with a maturity of less than 10 years to 10 percent of total capitalization.  In November 2003, CL&P obtained from its preferred stockholders a waiver of such 10 percent limit for a ten-year period expiring in March 2014, provided that all unsecured indebtedness does not exceed 20 percent of total capitalization.  As of December 31, 2012, CL&P had $482 million of unsecured debt capacity available under this authorization.

Yankee Gas and NSTAR Gas are not required to obtain approval from any state or federal authority to incur short-term debt.

Credit Agreements and Commercial Paper Programs:  On July 25, 2012, NU, CL&P, NSTAR LLC, NSTAR Gas, PSNH, WMECO, and Yankee Gas jointly entered into a five-year $1.15 billion revolving credit facility.  The new facility replaced (1) the NSTAR LLC revolving credit facility of $175 million that served to backstop a commercial paper program utilized by NSTAR LLC and was scheduled to expire on December 31, 2012, (2) the NSTAR Gas revolving credit facility of $75 million that expired on June 8, 2012, and (3) the CL&P, PSNH, WMECO, and Yankee Gas joint three-year $400 million and NU parent three-year $500 million unsecured revolving credit facilities that were scheduled to expire on September 24, 2013.  The new facility expires on July 25, 2017.  Management expects the new facility to be used primarily to backstop the $1.15 billion commercial paper program at NU, which commenced July 25, 2012.  The commercial paper program allows NU parent to issue commercial paper as a form of short-term debt.  Under the terms of the agreement, NU parent may provide intercompany loans to its subsidiaries, including CL&P, PSNH and WMECO.

On July 25, 2012, NSTAR Electric entered into a five-year $450 million revolving credit facility.  This new facility serves to backstop NSTAR Electric’s existing $450 million commercial paper program.  The new facility expires on July 25, 2017.  This new facility replaced a prior $450 million NSTAR Electric revolving credit facility that was scheduled to expire on December 31, 2012.  

As of December 31, 2012, NU had $1.15 billion in short-term borrowings outstanding under its commercial paper program.  The weighted-average interest rate on these borrowings as of December 31, 2012 was 0.46 percent, which is generally based on money market rates.  As of December 31, 2012, there were inter-company loans of $987.5 million from NU to its subsidiaries ($405.1 million for CL&P, $63.3 million for PSNH, and $31.9 million for WMECO).  As of December 31, 2012, NSTAR Electric had $276 million in short-term borrowings outstanding under its commercial paper program, leaving $174 million of available borrowing capacity.  The weighted-average interest rate on these borrowings as of December 31, 2012 was 0.31 percent, which is generally based on money market rates.

As of December 31, 2011, CL&P and Yankee Gas had $31 million and $30 million, respectively, in short-term borrowings outstanding under the joint $400 million revolving credit facility with weighted average interest rates of 4.03 percent and 2.07 percent, respectively.  As of December 31, 2011, NU parent had $256 million in short-term borrowings outstanding under its $500 million revolving credit facility with a weighted average interest rate of 2.20 percent. As of December 31, 2011, there were also $17.9 million, $4 million and $5.4 million in LOCs outstanding under the NU parent credit facility for NU, CL&P and PSNH, respectively.  As of December 31, 2011, NSTAR Electric had $141.5 million in short-term borrowings outstanding under its existing commercial paper program with a weighted average interest rate of 0.16 percent.

Under the credit facilities, NU and its subsidiaries must comply with certain financial and non-financial covenants, including a consolidated debt to total capitalization ratio.  NU and its subsidiaries were in compliance with these covenants as of December 31, 2012 and 2011.  If NU or its subsidiaries were not in compliance with these covenants, an event of default would occur requiring all outstanding borrowings by such borrower to be repaid and additional borrowings by such borrower would not be permitted under the respective credit facility.  

Amounts outstanding under the commercial paper program are included in Notes Payable for NU and NSTAR Electric and classified in current liabilities on the accompanying consolidated balance sheet as management anticipates that all borrowings under these credit facilities will be outstanding for no more than 364 days at one time.  Intercompany loans from NU to PSNH and WMECO are included in Notes Payable to Affiliated Companies and classified in current liabilities on the accompanying consolidated balance sheet.  

On January 15, 2013, CL&P issued $400 million of Series A First and Refunding Mortgage Bonds with a coupon rate of 2.5 percent and a maturity date of January 15, 2023.  The proceeds, net of issuance costs, were used to pay short-term borrowings outstanding under the CL&P credit agreement and the NU commercial paper program.  As a result, as of December 31, 2012, CL&P's credit agreement borrowings of $89 million and intercompany loans related to the commercial paper program of $305.8 million have been classified as Long-Term Debt on the accompanying consolidated balance sheet.

CL&P Credit Agreement:  On March 26, 2012, CL&P entered into a five-year unsecured revolving credit facility in the amount of $300 million, which expires on March 26, 2017.  Under this facility, CL&P can borrow either on a short-term or a long-term basis subject to regulatory approval.  As of December 31, 2012, CL&P had $89 million in borrowings outstanding under this credit agreement with a weighted average interest rate of 3.325 percent.  

136

Under this facility, CL&P may borrow at prime rates or LIBOR-based rates, plus an applicable margin based on the higher of S&P’s or Moody’s credit ratings.  

In addition, CL&P must comply with certain financial and non-financial covenants, including a consolidated debt to total capitalization ratio.  CL&P was in compliance with these covenants as of December 31, 2012.  If CL&P was not in compliance with these covenants, an event of default would occur requiring all outstanding borrowings to be repaid and additional borrowings would not be permitted under this credit facility.

Working Capital: NU, CL&P, NSTAR Electric, PSNH and WMECO use their available capital resources to fund their respective construction expenditures, meet debt requirements, pay costs, including storm-related costs, pay dividends, and fund other corporate obligations, such as pension contributions.  The current growth in NU’s transmission construction expenditures utilizes a significant amount of cash for projects that have a long-term return on investment and recovery period.  In addition, NU’s Regulated companies operate in an environment where recovery of its electric and natural gas distribution construction expenditures takes place over an extended period of time.  This impacts the timing of the revenue stream designed to fully recover the total investment plus a return on the equity portion of the cost and related financing costs.  These factors have resulted in NU’s current liabilities exceeding current assets by approximately $1.4 billion, $268 million, $198 million and $60 million at NU, CL&P, NSTAR Electric and WMECO, respectively, as of December 31, 2012.

As of December 31, 2012, approximately $730 million of NU's current liabilities relates to long-term debt that will be paid in the next 12 months, consisting of $550 million for NU parent, $55 million for WMECO, and $125 million for CL&P.  Approximately $32 million relates to the amortization of the purchase accounting fair value adjustment that will be amortized in the next twelve months.  NU, with its strong credit ratings, has several options available in the financial markets to repay or refinance these maturities with the issuance of new long-term debt.  NU, CL&P, NSTAR Electric, and WMECO will reduce their short-term borrowings with cash received from operating cash flows or with the issuance of new long-term debt, as deemed appropriate given capital requirements and maintenance of NU's credit rating and profile.  Management expects the future operating cash flows of NU, CL&P, NSTAR Electric and WMECO along with the access to financial markets, will be sufficient to meet any future operating requirements and capital investment forecasted opportunities.

Money Pool:  As of December 31, 2011, NU parent, CL&P, PSNH, WMECO, Yankee Gas and certain of NU's other subsidiaries were members of the Money Pool.  Short-term borrowing needs of the member companies were met with available funds of other member companies, including funds borrowed by NU parent.  Investing and borrowing subsidiaries received or paid interest based on the average daily federal funds rate.  In NU's consolidated financial statements, Money Pool amounts payable to or receivable from members eliminated in consolidation.  As of December 31, 2011, Money Pool amounts were as follows:

	As of and for the Year Ended December 31, 2011
(Millions of Dollars, except percentages)	CL&P			PSNH			WMECO
Borrowings from/(Lendings to)	$	58.5		$	(55.9)		$	(11.0)
Weighted-Average Interest Rates		0.08	%		0.1	%		0.1	%

The net borrowings from/(lendings to) the Money Pool were recorded in Notes Payable to/Notes Receivable from Affiliated Companies on the accompanying consolidated balance sheets, respectively.  

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9.

LONG-TERM DEBT

Details of long-term debt outstanding for NU, including CL&P, NSTAR Electric, PSNH and WMECO are as follows:

CL&P		As of December 31,
(Millions of Dollars)		2012		2011
First Mortgage Bonds:
	7.875% 1994 Series D due 2024	$	139.8	$	139.8
	4.800% 2004 Series A due 2014		150.0		150.0
	5.750% 2004 Series B due 2034		130.0		130.0
	5.000% 2005 Series A due 2015		100.0		100.0
	5.625% 2005 Series B due 2035		100.0		100.0
	6.350% 2006 Series A due 2036		250.0		250.0
	5.375% 2007 Series A due 2017		150.0		150.0
	5.750% 2007 Series B due 2037		150.0		150.0
	5.750% 2007 Series C due 2017		100.0		100.0
	6.375% 2007 Series D due 2037		100.0		100.0
	5.650% 2008 Series A due 2018		300.0		300.0
	5.500% 2009 Series A due 2019		250.0		250.0
Total First Mortgage Bonds			1,919.8		1,919.8
Pollution Control Notes:
	5.85%-5.95%  Fixed Rate Tax Exempt due 2016-2028 (1)		-		116.4
	4.375% Fixed Rate Tax Exempt due 2028		120.5		120.5
	1.25% Fixed Rate Tax Exempt due 2028(2)		125.0		125.0
	1.55% Fixed Rate Tax Exempt due 2031(3)		62.0		62.0
Total Pollution Control Notes			307.5		423.9
Total First Mortgage Bonds and Pollution Control Notes			2,227.3		2,343.7
Fees and Interest due for Spent Nuclear Fuel Disposal Costs			244.3		244.1
CL&P Commercial Paper and Revolver Borrowings(4)			394.8		-
Less Amounts due Within One Year(2)			(125.0)		(62.0)
Unamortized Premiums and Discounts, Net			(3.6)		(4.0)
CL&P Long-Term Debt		$	2,737.8	$	2,521.8

138

NSTAR Electric		As of December 31,
(Millions of Dollars)		2012		2011 (5)
Debentures:
	4.875% due 2012 (6)	$	-	$	400.0
	4.875% due 2014		300.0		300.0
	2.375% due 2022 (6)		400.0		-
	5.625% due 2017		400.0		400.0
	5.75% due 2036		200.0		200.0
	5.50% due 2040		300.0		300.0
Total Debentures			1,600.0		1,600.0
Bonds:
	7.375% Tax Exempt Sewage Facility Revenue Bonds, due 2015		8.0		8.7
Less Amounts due Within One Year			(1.7)		(400.7)
Unamortized Premiums and Discounts, Net			(5.4)		(4.7)
NSTAR Electric Long-Term Debt		$	1,600.9	$	1,203.3

PSNH		As of December 31,
(Millions of Dollars)		2012		2011
First Mortgage Bonds:
	5.25% 2004 Series L due 2014	$	50.0	$	50.0
	5.60% 2005 Series M due 2035		50.0		50.0
	6.15% 2007 Series N due 2017		70.0		70.0
	6.00% 2008 Series O due 2018		110.0		110.0
	4.50% 2009 Series P due 2019		150.0		150.0
	4.05% 2011 Series Q due 2021		122.0		122.0
	3.20% 2011 Series R due 2021		160.0		160.0
Total First Mortgage Bonds			712.0		712.0
Pollution Control Revenue Bonds:
	4.75% - 5.45% Tax Exempt Series B and C due 2021		198.2		198.2
	Adjustable Rate Series A due 2021		89.3		89.3
Total Pollution Control Revenue Bonds			287.5		287.5
Unamortized Premiums and Discounts, Net			(1.6)		(1.8)
PSNH Long-Term Debt		$	997.9	$	997.7

WMECO		As of December 31,
(Millions of Dollars)		2012		2011
Pollution Control Revenue Bonds and Other Notes:
	5.85% Tax Exempt PCRBs 1993 Series A, due 2028 (7)	$	-	$	53.8
	5.00% Senior Notes Series A, due 2013		55.0		55.0
	5.90% Senior Notes Series B, due 2034		50.0		50.0
	5.24% Senior Notes Series C, due 2015		50.0		50.0
	6.70% Senior Notes Series D, due 2037		40.0		40.0
	5.10% Senior Notes Series E, due 2020		95.0		95.0
	3.50% Senior Notes Series F, due 2021 (8)		250.0		100.0
Total Pollution Control Revenue Bonds and Other Notes			540.0		443.8
Fees and Interest due for Spent Nuclear Fuel Disposal Costs			57.3		57.3
Less Amounts due Within One Year			(55.0)		-
Unamortized Premiums and Discounts, Net			8.0		(1.6)
WMECO Long-Term Debt		$	550.3	$	499.5

139

OTHER		As of December 31,
(Millions of Dollars)		2012			2011
Yankee Gas - First Mortgage Bonds:
	7.19% Series E due 2012	$	-	$	4.3
	8.48% Series B due 2022		20.0		20.0
	4.80% Series G due 2014		75.0		75.0
	5.26% Series H due 2019		50.0		50.0
	5.35% Series I due 2035		50.0		50.0
	6.90% Series J due 2018		100.0		100.0
	4.87% Series K due 2020		50.0		50.0
Total First Mortgage Bonds			345.0		349.3
Less Amounts due Within One Year			-		(4.3)
Unamortized Premium			0.8		0.9
Yankee Gas Long-Term Debt			345.8		345.9
NSTAR Gas - First Mortgage Bonds:
	9.95% Series J due 2020		25.0		N/A
	7.11% Series K due 2033		35.0		N/A
	7.04% Series M due 2017		25.0		N/A
	4.46% Series N due 2020		125.0		N/A
NSTAR Gas Long-Term Debt			210.0		N/A
Other - Notes and Debentures:
	7.25% Senior Notes Series A due 2012 (NU Parent) (9)		-		263.0
	5.65% Senior Notes Series C due 2013 (NU Parent)		250.0		250.0
	Variable Rate Senior Notes Series D due 2013 (NU Parent) (9)		300.0		-
	4.50% Debentures due 2019 (NSTAR  LLC)		350.0		N/A
	Spent Nuclear Fuel Obligation (CYAPC)		179.3		N/A
Total Other Long-Term Debt			1,079.3		513.0
Fair Value Adjustment (10)			259.9		2.3
Less Amounts due Within One Year			(550.0)		(263.0)
Less: Fair Value Adjustment - Current Portion(10)			(31.7)		(2.3)
Total NU Long-Term Debt		$	7,200.2	$	4,614.9

⁽¹⁾

On October 1, 2012, CL&P redeemed at par four different series of tax-exempt PCRBs totaling $116.4 million.   The PCRBs had maturity dates ranging from 2016 through 2028 and coupon rates of 5.85 percent through 5.95 percent.

⁽²⁾

The $125 million of tax-exempt PCRBs were issued with an initial fixed rate term period ending on September 2, 2013, and are subject to mandatory tender for purchase on September 3, 2013, at which time CL&P expects to remarket the PCRBs.

⁽³⁾

On April 2, 2012, CL&P remarketed $62 million of tax-exempt PCRBs for a three-year period.  The PCRBs, which mature on May 1, 2031, carry a coupon rate of 1.55 percent during the current three-year fixed rate period and are subject to mandatory tender for purchase on April 1, 2015.

⁽⁴⁾

On January 15, 2013, CL&P issued $400 million of 2.5 percent Series A First and Refunding Mortgage Bonds with a maturity date of January 15, 2023.  The proceeds, net of issuance expenses, were used to repay the amounts outstanding under the CL&P revolver and the NU commercial paper program.  As a result, these amounts have been classified as Long-Term Debt as of December 31, 2012.

⁽⁵⁾

NSTAR Electric amounts are not included in NU consolidated as of December 31, 2011.

⁽⁶⁾

On October 15, 2012, NSTAR Electric issued at a discount $400 million of 2.375 percent Debentures at a yield of 2.406 percent that will mature on October 15, 2022. The proceeds, net of issuance costs, were used to pay $400 million of 4.875 percent Debentures that matured on October 15, 2012.

⁽⁷⁾

On October 1, 2012, WMECO redeemed at par $53.8 million of tax-exempt PCRBs.  The PCRBs had a maturity date of 2028 and a coupon of 5.85 percent.  

⁽⁸⁾

On October 4, 2012, WMECO issued at a premium $150 million of senior unsecured notes at a yield of 2.673 percent that will mature on September 15, 2021.  The senior notes are part of the same series of WMECO’s existing 3.5 percent coupon Series F Senior Notes that were initially issued in September 2011.  As a result, the aggregate principal amount of WMECO’s outstanding Series F Senior Notes totaled $250 million.  

⁽⁹⁾

On March 22, 2012, NU parent issued $300 million of floating rate Series D Senior Notes with a maturity date of September 20, 2013.  The notes have a coupon rate based on the three-month LIBOR rate plus a credit spread of 0.75 percent and will reset quarterly.  The notes had an interest rate of 1.059 percent as of December 31, 2012.  The proceeds, net of issuance expenses, were used to repay at maturity the NU parent $263 million Series A Senior Notes that matured on April 1, 2012, to repay short-term borrowings outstanding under the NU parent Credit Agreement and for other general corporate purposes.  

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⁽¹⁰⁾

As of December 31, 2012, amount relates to the purchase price adjustment required to record the NSTAR long-term debt issuances at fair value on the date of the merger.  As of December 31, 2011, amount related to a fixed to floating interest rate swap on the $263 million NU parent note that matured on April 1, 2012.  The change in fair value of the interest component of the debt was recorded as an adjustment to Current Portion - Long Term Debt as of December 31, 2011 with an equal and offsetting adjustment to Current Derivative Assets.

Long-term debt maturities and cash sinking fund requirements on debt outstanding as of December 31, 2012 for the years 2013 through 2017 and thereafter, are shown below.  These amounts exclude fees and interest due for spent nuclear fuel disposal costs, net unamortized premiums and discounts, and other fair value adjustments as of December 31, 2012:

(Millions of Dollars)	NU		CL&P		NSTAR Electric		PSNH		WMECO
2013	$	731.7	$	125.0	$	1.7	$	-	$	55.0
2014		576.6		150.0		301.7		50.0		-
2015		216.7		162.0		4.7		-		50.0
2016		-		-		-		-		-
2017		745.0		250.0		400.0		70.0		-
Thereafter		4,559.8		1,540.3		899.9		879.5		435.0
Total	$	6,829.8	$	2,227.3	$	1,608.0	$	999.5	$	540.0

The utility plant of CL&P, PSNH, Yankee Gas and NSTAR Gas is subject to the lien of each company's respective first mortgage bond indenture.  NSTAR Electric, WMECO, NU Parent and NSTAR LLC debt is unsecured.  

The PSNH Series A and Series C tax-exempt bonds are currently callable at 100 percent and 101 percent of par, respectively.  The PSNH Series B tax-exempt bond will become callable in June 2013.  CL&P’s $125 million and $62 million tax-exempt PCRBs, which are subject to mandatory tender for purchase on September 3, 2013 and April 1, 2015, respectively, cannot be redeemed prior to their respective tender dates.  CL&P’s $120.5 million tax-exempt PCRBs will be subject to redemption at par on or after September 1, 2021.  All other long-term debt securities are subject to make-whole provisions.  

As of December 31, 2012, CL&P had $307.5 million of tax-exempt PCRBs outstanding.  CL&P’s obligation to repay each series of PCRBs is secured by first mortgage bonds. Each such series of first mortgage bonds contains similar terms and provisions as the applicable series of PCRBs.  If CL&P failed to meet its obligations under the PCRBs, then these first mortgage bonds would become outstanding.   

As of December 31, 2012, PSNH had $287.5 million in PCRBs outstanding.  PSNH's obligation to repay each series of PCRBs is secured by first mortgage bonds and bond insurance.  Each such series of first mortgage bonds contains similar terms and provisions as the applicable series of PCRBs.  If PSNH failed to meet its obligations under the PCRBs, then these first mortgage bonds would become outstanding.  The 2001 Series A PCRBs, in the aggregate principal amount of $89.3 million, bears interest at a rate that is periodically set pursuant to auctions.  PSNH is not obligated to purchase these PCRBs, which mature in 2021, from the remarketing agent.  The weighted average effective interest rate on PSNH's Series A variable-rate PCRBs was 0.20 percent in 2012 and 0.21 percent in 2011.  

NU's, including CL&P, NSTAR Electric, PSNH and WMECO, long-term debt agreements provide that NU and certain of its subsidiaries must comply with certain covenants as are customarily included in such agreements, including a minimum equity requirement for NSTAR Gas.  Under the minimum equity requirement, the outstanding long-term debt of NSTAR Gas must not exceed equity.  NU and these subsidiaries were in compliance with these covenants as of December 31, 2012 and 2011.   

Yankee Gas has certain long-term debt agreements that contain cross-default provisions applicable to all of Yankee Gas’ outstanding first mortgage bond series.  The cross-default provisions on Yankee Gas’ Series B Bonds would be triggered if Yankee Gas were to default on a payment due on indebtedness in excess of $2 million.  The cross-default provisions on all other series of Yankee Gas’ first mortgage bonds would be triggered if Yankee Gas were to default in a payment due on indebtedness in excess of $10 million.  No  other debt issuances contain cross-default provisions as of December 31, 2012.

Spent Nuclear Fuel Obligation:  Under the Nuclear Waste Policy Act of 1982, CL&P and WMECO must pay the DOE for the costs of disposal of spent nuclear fuel and high-level radioactive waste for the period prior to the sale of their ownership shares in the Millstone nuclear power stations.  

The DOE is responsible for the selection and development of repositories for, and the disposal of, spent nuclear fuel and high-level radioactive waste.  For nuclear fuel used to generate electricity prior to April 7, 1983 (Prior Period Spent Nuclear Fuel) for CL&P and WMECO, an accrual has been recorded for the full liability, and payment must be made by CL&P and WMECO to the DOE prior to the first delivery of spent fuel to the DOE.  After the sale of Millstone, CL&P and WMECO remained responsible for their share of the disposal costs associated with the Prior Period Spent Nuclear Fuel.  Until such payment to the DOE is made, the outstanding liability will continue to accrue interest at the 3-month Treasury bill yield rate.  In addition, as a result of consolidating CYAPC, NU has consolidated $179.3 million in additional spent nuclear fuel obligations, including interest, as of December 31, 2012.  Fees due to the DOE for the disposal of CL&P's and WMECO's Prior Period Spent Nuclear Fuel and CYAPC's and YAEC's spent nuclear fuel obligation include accumulated interest costs of $350 million and $219.3 million for NU ($177.8 million and $177.6 million for CL&P and $41.7 million and $41.7 million for WMECO) as of December 31, 2012 and 2011, respectively.

141

For further information, see Note 1B, "Summary of Significant Accounting Policies – Basis of Presentation," to the consolidated financial statements.

WMECO maintains a trust that holds marketable securities to fund amounts due to the DOE for the disposal of WMECO's Prior Period Spent Nuclear Fuel.  CYAPC also maintain trusts to fund amounts due to the DOE for the disposal of spent nuclear fuel.  For further information on these trusts, see Note 6, "Marketable Securities," to the consolidated financial statements.

10.

EMPLOYEE BENEFITS

A.

Pension Benefits and Postretirement Benefits Other Than Pensions

NUSCO sponsors a defined benefit retirement plan that covers most employees, including CL&P, PSNH, and WMECO employees, hired before 2006 (or as negotiated, for bargaining unit employees), referred to as the NUSCO Pension Plan. NSTAR Electric serves as plan sponsor for a defined benefit retirement plan that covers most employees of NSTAR Electric & Gas, hired before October 1, 2012, or as negotiated by bargaining unit employees, referred to as the NSTAR Pension Plan.  Both plans are subject to the provisions of ERISA, as amended by the PPA of 2006.  NUSCO and NSTAR Electric & Gas each maintain SERPs and other non-qualified defined benefit retirement plans (herein collectively referred to as the SERP Plans), which provide benefits in excess of Internal Revenue Code limitations to eligible current and retired participants that would have otherwise been provided under the Pension Plans.  

NUSCO and NSTAR Electric & Gas also sponsor defined benefit postretirement plans that provide certain retiree health care benefits, primarily medical and dental, and life insurance benefits to retiring employees that meet certain age and service eligibility requirements (NUSCO PBOP Plans and NSTAR PBOP Plan, respectively).  Under certain circumstances, eligible retirees are required to contribute to the costs of postretirement benefits.  The benefits provided under the NUSCO and NSTAR PBOP Plans are not vested and the Company has the right to modify any benefit provision subject to applicable laws at that time.

The funded status of the Pension, SERP and PBOP Plans is calculated based on the difference between the benefit obligation and the fair value of plan assets. The funded status of the Pension, SERP and PBOP Plans is recorded on the consolidated balance sheets as a liability with an offset to Accumulated Other Comprehensive Income/(Loss).  Pension, SERP and PBOP costs for the Regulated companies are recorded as Regulatory Assets as these amounts are recovered from customers.  Regulatory accounting was also applied to the portions of the NUSCO and NSTAR Electric & Gas costs that support the Regulated companies, as these costs are also recovered from customers.  Pension and PBOP costs for the unregulated companies are recorded on an after-tax basis to Accumulated Other Comprehensive Income/(Loss).  For further information, see Note 3, "Regulatory Accounting," and Note 15, "Accumulated Other Comprehensive Income/(Loss)," to the consolidated financial statements.  The SERP Plans do not have plan assets.

For the NUSCO Pension and PBOP Plans, the expected return on plan assets is calculated by applying the assumed rate of return to a four-year rolling average of plan asset fair values, which reduces year-to-year volatility.  Investment gains or losses for this purpose are the difference between the calculated expected return and the actual return. As investment gains and losses are reflected in the average plan asset fair values, they are subject to amortization with other unrecognized actuarial gains or losses. For the NSTAR Pension and PBOP Plans, the entire difference between the actual return and calculated expected return on plan assets is reflected as a component of unrecognized actuarial gain or loss. Unrecognized actuarial gains or losses are amortized as a component of Pension and PBOP expense over the estimated average future employee service period.

Pension and SERP Plans:  The funded status of each of the plans is recorded on the respective sponsor's balance sheet:  NUSCO (NUSCO Pension and NUSCO SERP), NSTAR Electric (NSTAR Pension) and NSTAR Electric & Gas (NSTAR SERP).  The NUSCO plans are accounted for under the multiple-employer approach while the NSTAR plans are accounted for under the multi-employer approach.  Accordingly, the balance sheet of NSTAR Electric reflects the full funded status of the NSTAR Pension Plan.

142

The following tables provide information on the Pension and SERP Plan benefit obligations, fair values of Pension Plan assets, and funded status:

	Pension and SERP
NU	As of December 31,
(Millions of Dollars)	2012		2011
Change in Benefit Obligation
Benefit Obligation as of Beginning of Year	$	(3,098.9)	$	(2,820.9)
Liabilities Assumed from Merger with NSTAR		(1,409.7)		-
Service Cost		(84.3)		(55.4)
Interest Cost		(198.3)		(153.3)
Actuarial Loss		(429.7)		(206.1)
Benefits Paid - Excluding Lump Sum Payments		187.7		134.4
Benefits Paid – SERP		4.2		2.4
SERP curtailment		6.2		-
Benefit Obligation as of End of Year	$	(5,022.8)	$	(3,098.9)
Change in Pension Plan Assets
Fair Value of Plan Assets as of Beginning of Year	$	2,005.9	$	1,977.6
Assets Assumed from Merger with NSTAR		984.7		-
Employer Contributions		222.4		143.6
Actual Return on Plan Assets		386.0		19.1
Benefits Paid - Excluding Lump Sum Payments		(187.7)		(134.4)
Fair Value of Plan Assets as of End of Year	$	3,411.3	$	2,005.9
Funded Status as of December 31st	$	(1,611.5)	$	(1,093.0)

	Pension and SERP
	As of December 31, 2012								As of December 31, 2011
			NSTAR								NSTAR
(Millions of Dollars)	CL&P		Electric (1)		PSNH		WMECO		CL&P		Electric (1),(2)		PSNH		WMECO
Change in Benefit Obligation
Benefit Obligation as of Beginning of Year	$	(1,043.8)	$	(1,346.2)	$	(497.9)	$	(215.8)	$	(964.3)	$	(1,184.6)	$	(448.7)	$	(196.6)
Service Cost		(21.8)		(30.3)		(11.8)		(4.1)		(19.5)		(26.0)		(10.6)		(3.9)
Interest Cost		(51.2)		(58.9)		(24.4)		(10.5)		(51.9)		(61.0)		(24.4)		(10.7)
Actuarial Loss		(117.4)		(63.6)		(61.3)		(24.0)		(64.0)		(138.0)		(33.2)		(15.4)
Benefits Paid - Excluding Lump Sum Payments		55.9		69.0		19.7		11.3		55.6		59.6		18.9		10.8
Benefits Paid - SERP		0.3		-		-		-		0.3		-		0.1		-
Curtailment and Settlement Payments		-		-		(0.3)		-		-		3.8		-		-
Benefit Obligation as of End of Year	$	(1,178.0)	$	(1,430.0)	$	(576.0)	$	(243.1)	$	(1,043.8)	$	(1,346.2)	$	(497.9)	$	(215.8)
Change in Pension Plan Assets
Fair Value of Plan Assets as of Beginning of Year	$	869.6	$	988.5	$	279.7	$	202.0	$	918.4	$	930.6	$	185.4	$	209.8
Employer Contributions		-		25.0		87.7		-		-		125.0		112.6		-
Actual Return/(Loss) on Plan Assets		123.9		124.6		38.9		27.8		6.8		(3.7)		0.6		3.0
Benefits Paid - Excluding Lump Sum Payments		(55.9)		(69.0)		(19.7)		(11.3)		(55.6)		(59.6)		(18.9)		(10.8)
Benefits Paid - Settlement Payments		-		-		-		-		-		(3.8)		-		-
Fair Value of Plan Assets as of End of Year	$	937.6	$	1,069.1	$	386.6	$	218.5	$	869.6	$	988.5	$	279.7	$	202.0
Funded Status as of December 31st	$	(240.4)	$	(360.9)	$	(189.4)	$	(24.6)	$	(174.2)	$	(357.7)	$	(218.2)	$	(13.8)
Pension and SERP benefits funded status includes the current portion of the SERP liability, which is included in Other Current Liabilities on the accompanying consolidated balance sheets.
Although the Company maintains a trust to support the SERP with marketable securities held in the NU supplemental benefit trust, the plan itself does not contain any assets.  For information regarding the investments in the NU supplemental benefit trust that are used to informally support the SERP liability, see Note 6, "Marketable Securities," to the consolidated financial statements.
(1) NSTAR Electric amounts do not include benefit obligations of the NSTAR SERP Plan.
(2) NSTAR Electric amounts are not included in NU consolidated as of December 31, 2011.

The accumulated benefit obligation for the Pension and SERP Plans is as follows:
		Pension and SERP
		As of December 31,
(Millions of Dollars)		2012		2011
NU		$	4,622.1	$	2,810.6
CL&P			1,061.8		938.4
NSTAR Electric (1)			1,353.1		1,271.3
PSNH			515.9		444.8
WMECO			221.3		195.5
(1)	NSTAR Electric amounts are not included in NU consolidated as of December 31, 2011 and do not include the accumulated benefit obligation for the SERP Plan.

143

The following actuarial assumptions were used in calculating the Pension and SERP Plans' year end funded status:

	Pension and SERP
	As of December 31,
	2012		2011
NUSCO Pension and SERP Plans
Discount Rate	4.24	%	5.03	%
Compensation/Progression Rate	3.50	%	3.50	%
NSTAR Pension and SERP Plans
Discount Rate	4.13	%	4.52	%
Compensation/Progression Rate	4.00	%	4.00	%

Pension and SERP Expense: For the NUSCO Plans, NU allocates net periodic pension expense to its subsidiaries based on the actual participant demographic data for each subsidiary's participants.  Benefit payments to participants and contributions are also tracked for each subsidiary.  The actual investment return in the trust each year is allocated to each of the subsidiaries annually in proportion to the investment return expected to be earned during the year.  For the NSTAR Pension Plan, the net periodic pension expense recorded at NSTAR Electric represents the full cost of the plan and then a portion of the costs are allocated to affiliated companies based on participant demographic data.  The components of net periodic benefit expense, the portion of pension amounts capitalized related to employees working on capital projects, and intercompany allocations not included in the net periodic benefit expense amounts for the Pension and SERP Plans were as follows:

		Pension and SERP
		For the Year Ended December 31, 2012
						NSTAR
(Millions of Dollars)		NU		CL&P		Electric (1)		PSNH		WMECO
Service Cost		$	84.3	$	21.8	$	30.3	$	11.8	$	4.1
Interest Cost			198.3		51.2		58.9		24.4		10.5
Expected Return on Plan Assets			(220.9)		(70.6)		(65.6)		(28.2)		(16.4)
Actuarial Loss			172.4		49.6		63.1		16.2		10.7
Prior Service Cost/(Credit)			7.9		3.6		(0.6)		1.5		0.8
Total Net Periodic Benefit Expense		$	242.0	$	55.6	$	86.1	$	25.7	$	9.7
Curtailments and Settlements		$	2.2	$	-	$	-	$	-	$	-
Related Intercompany Allocations			N/A	$	42.8	$	(12.3)	$	10.1	$	8.1
Capitalized Pension Expense		$	70.6	$	26.8	$	30.7	$	7.9	$	5.1
		Pension and SERP
		For the Year Ended December 31, 2011
						NSTAR
(Millions of Dollars)		NU		CL&P		Electric (1)		PSNH		WMECO
Service Cost		$	55.4	$	19.5	$	26.0	$	10.6	$	3.9
Interest Cost			153.3		51.9		61.0		24.4		10.7
Expected Return on Plan Assets			(170.8)		(76.6)		(71.4)		(19.8)		(17.7)
Actuarial Loss			84.2		33.4		48.6		10.7		7.1
Prior Service Cost/(Credit)			9.7		4.2		(0.7)		1.8		0.9
Total Net Periodic Benefit Expense		$	131.8	$	32.4	$	63.5	$	27.7	$	4.9
Related Intercompany Allocations			N/A	$	34.1	$	(10.2)	$	7.6	$	6.2
Capitalized Pension Expense		$	29.7	$	16.6	$	19.8	$	7.6	$	2.7
		Pension and SERP
		For the Year Ended December 31, 2010
						NSTAR
(Millions of Dollars)		NU		CL&P		Electric (1)		PSNH		WMECO
Service Cost		$	51.0	$	17.6	$	23.6	$	10.0	$	3.5
Interest Cost			152.6		52.2		61.8		24.1		10.7
Expected Return on Plan Assets			(182.6)		(85.8)		(62.8)		(14.7)		(19.5)
Actuarial Loss			53.5		20.7		50.4		7.2		4.3
Prior Service Cost/(Credit)			9.9		4.2		(0.7)		1.8		0.9
Total Net Periodic Benefit Expense/(Income)		$	84.4	$	8.9	$	72.3	$	28.4	$	(0.1)
Related Intercompany Allocations			N/A	$	25.2	$	(11.6)	$	6.0	$	4.5
Capitalized Pension Expense		$	16.9	$	3.8	$	24.5	$	6.9	$	-
(1)	NSTAR Electric amounts are included in NU consolidated from the date of the merger, April 10, 2012, through December 31, 2012.  NSTAR Electric amounts are not included in NU consolidated for the years ended December 31, 2011 and 2010.  NSTAR Electric's allocated expense associated with the NSTAR SERP was $3.6 million, $4.4 million and $3.9 million for the years ended December 31, 2012, 2011 and 2010, respectively, and are not included in the NSTAR Electric amounts in the tables above.

144

The following actuarial assumptions were used to calculate Pension and SERP expense amounts:

	Pension and SERP
	For the Years Ended December 31,
NUSCO Pension and SERP Plans	2012		2011		2010
Discount Rate	5.03	%	5.57	%	5.98	%
Expected Long-Term Rate of Return	8.25	%	8.25	%	8.75	%
Compensation/Progression Rate	3.50	%	3.50	%	4.00	%
NSTAR Pension and SERP Plans
Discount Rate	4.52	%	5.30	%	5.85	%
Expected Long-Term Rate of Return	7.30	%	8.00	%	8.00	%
Compensation/Progression Rate	4.00	%	4.00	%	4.00	%

The following is a summary of the changes in plan assets and benefit obligations recognized in Regulatory Assets and OCI as well as amounts in Regulatory Assets and OCI reclassified as net periodic benefit expense during the years presented:
	Amounts Reclassified To/From
	Regulatory Assets				OCI
(Millions of Dollars)	For the Years Ended December 31,
NU Pension and SERP Plans (1)	2012		2011		2012		2011
Actuarial Losses Arising During the Year	$	245.7	$	334.8	$	19.1	$	23.0
Actuarial Losses Reclassified as Net Periodic Benefit Expense		(164.6)		(79.4)		(7.8)		(4.8)
Prior Service Cost Reclassified as Net Periodic Benefit Expense		(7.7)		(9.4)		(0.2)		(0.3)
The following is a summary of the remaining Regulatory Assets and Accumulated Other Comprehensive Loss amounts that have not been recognized as components of net periodic benefit expense as of December 31, 2012 and 2011, and the amounts that are expected to be recognized as components in 2013:
		Regulatory Assets as of				Expected		AOCI as of			Expected
(Millions of Dollars)	December 31,					2013	December 31,				2013
NU Pension and SERP Plans (1)	2012		2011		Expense		2012		2011		Expense
Actuarial Loss	$	1,973.8	$	1,126.1	$	200.8	$	81.5	$	70.2	$	9.3
Prior Service Cost		21.2		29.3		3.9		1.2		1.4		0.2

⁽¹⁾

The NU consolidated amounts reflect the NSTAR Pension and SERP Plans from the date of the merger, April 10, 2012, through December 31, 2012.

NSTAR Electric continues to maintain reporting requirements as an SEC registrant. Included in the amounts above as of December 31, 2012 are $724 million of unrecognized actuarial losses included in Regulatory Assets for NSTAR Electric. For the year ended December 31, 2012, NSTAR Electric reclassified $62.8 million of actuarial losses and $0.6 million of prior service credit as net periodic benefit expense and $4.6 million of actuarial losses arose during the year.  As of December 31, 2011, NSTAR Electric had $782.3 million of unrecognized actuarial losses and $0.6 million of prior service credit included in Regulatory Assets.  For the year ended December 31, 2011, NSTAR Electric reclassified $48.4 million of actuarial losses and $0.7 million of prior service credit as net periodic benefit expense and $212 million of actuarial losses arose during the year.

PBOP Plans:  The NUSCO Plans are accounted for under the multiple-employer basis while the NSTAR Plan is accounted for under the multi-employer basis.  Accordingly, the funded status of the NUSCO PBOP Plans is allocated to its subsidiaries, including CL&P, PSNH and WMECO, while the NSTAR PBOP Plan is not reflected on the SEC registrant NSTAR Electric’s balance sheet.  

NU annually funds postretirement costs through tax deductible contributions to external trusts.

145

The following tables represent information on PBOP Plan benefit obligations, fair values of plan assets, and funded status:

		PBOP
		As of December 31,
				2012						2011
(Millions of Dollars)		NU (1)		CL&P		PSNH		WMECO		NU		CL&P		PSNH		WMECO
Change in Benefit Obligation
Benefit Obligation as of Beginning of Year		$	(520.9)	$	(198.9)	$	(99.2)	$	(42.9)	$	(489.9)	$	(190.2)	$	(89.9)	$	(41.7)
Liabilities Assumed from Merger with NSTAR			(770.6)		-		-		-		-		-		-		-
Service Cost			(15.7)		(3.0)		(2.0)		(0.6)		(9.2)		(2.9)		(1.9)		(0.6)
Interest Cost			(49.0)		(9.2)		(4.6)		(2.0)		(25.7)		(10.0)		(4.8)		(2.2)
Actuarial Gain/(Loss)			70.9		1.2		0.3		0.1		(30.1)		(8.5)		(8.4)		(1.0)
Federal Subsidy on Benefits Paid			(6.2)		(1.7)		(0.6)		(0.3)		(4.1)		(1.8)		(0.7)		(0.4)
Benefits Paid			58.2		14.8		5.9		3.2		38.1		14.5		6.5		3.0
Benefit Obligation as of End of Year		$	(1,233.3)	$	(196.8)	$	(100.2)	$	(42.5)	$	(520.9)	$	(198.9)	$	(99.2)	$	(42.9)
Change in Plan Assets
Fair Value of Plan Assets as of Beginning of Year		$	285.4	$	112.2	$	58.7	$	27.1	$	278.5	$	108.6	$	56.9	$	26.7
Assets Assumed from Merger with NSTAR			330.4		-		-		-		-		-		-		-
Actual Return on Plan Assets			78.8		15.0		7.5		3.5		(2.5)		(1.2)		(0.4)		(0.1)
Employer Contributions			72.7		19.8		9.2		3.6		47.5		19.3		8.7		3.5
Benefits Paid			(58.2)		(14.8)		(5.9)		(3.2)		(38.1)		(14.5)		(6.5)		(3.0)
Fair Value of Plan Assets as of End of Year		$	709.1	$	132.2	$	69.5	$	31.0	$	285.4	$	112.2	$	58.7	$	27.1
Funded Status as of December 31st		$	(524.2)	$	(64.6)	$	(30.7)	$	(11.5)	$	(235.5)	$	(86.7)	$	(40.5)	$	(15.8)
(1)	The NU consolidated results include NSTAR PBOP Plan activity from the date of the merger, April 10, 2012, through December 31, 2012.

The following actuarial assumptions were used in calculating the PBOP Plans' year end funded status:
	PBOP
	As of December 31,
	2012		2011
NUSCO PBOP Plans
Discount Rate	4.04	%	4.84	%
Health Care Cost Trend Rate	7.00	%	7.00	%
NSTAR PBOP Plan
Discount Rate	4.35	%	N/A
Health Care Cost Trend Rate	7.10	%	N/A

PBOP Expense:  For the NUSCO Plans, NU allocates net periodic postretirement benefits expense to its subsidiaries based on the actual participant demographic data for each subsidiary's participants.  Benefit payments to participants and contributions are also tracked for each subsidiary.  The actual investment return in the trust is allocated to each of the subsidiaries annually in proportion to the investment return expected to be earned during the year.  For the NSTAR Plan, NSTAR allocates the net periodic postretirement expenses to its subsidiaries based on actual participant demographic data for each of its subsidiaries.  The net periodic postretirement expense allocated to NSTAR Electric was $34.1 million, $26 million, and $33 million for the years ended December 31, 2012, 2011 and 2010, respectively.  

The components of net periodic postretirement benefit expense and intercompany allocations not included in the net periodic benefit expense amounts for the PBOP Plans were as follows:

			PBOP
		For the Years Ended December 31,
		2012								2011								2010
(Millions of Dollars)		NU (1)		CL&P		PSNH		WMECO		NU		CL&P		PSNH		WMECO		NU		CL&P		PSNH		WMECO
Service Cost		$	15.7	$	3.0	$	2.0	$	0.6	$	9.2	$	2.9	$	1.9	$	0.6	$	8.5	$	2.7	$	1.8	$	0.6
Interest Cost			49.0		9.2		4.6		2.0		25.7		10.0		4.8		2.2		26.8		10.5		5.0		2.3
Expected Return
	on Plan Assets		(39.2)		(9.1)		(4.6)		(2.1)		(21.6)		(8.7)		(4.3)		(2.0)		(21.7)		(8.7)		(4.3)		(2.1)
Actuarial Loss			36.0		7.5		3.6		1.2		19.0		7.2		3.2		1.1		16.7		6.3		2.7		0.9
Prior Service
	Cost/(Credit)		(1.4)		-		-		-		(0.3)		-		-		1.3		(0.3)		-		-		-
Net Transition
	Obligation Cost(2)		12.2		6.1		2.5		1.3		11.6		6.2		2.5		-		11.6		6.1		2.5		1.3
Total Net Periodic     Benefit Expense		$	72.3	$	16.7	$	8.1	$	3.0	$	43.6	$	17.6	$	8.1	$	3.2	$	41.6	$	16.9	$	7.7	$	3.0
Related Intercompany     Allocations			N/A	$	7.9	$	2.0	$	1.5		N/A	$	8.2	$	2.0	$	1.5		N/A	$	7.9	$	2.0	$	1.4
(1)	The NU consolidated results include NSTAR PBOP Plan expense from the date of the merger, April 10, 2012, through December 31, 2012.
(2)	The NUSCO PBOP Plans and NSTAR PBOP Plan transition obligation costs will be fully amortized in 2013.

146

The following actuarial assumptions were used to calculate PBOP expense amounts:
	PBOP
	For the Years Ended December 31,
	2012		2011		2010
NUSCO PBOP Plans
Discount Rate	4.84	%	5.28	%	5.73	%
Expected Long-Term Rate of Return	8.25	%	8.25	%	8.75	%
NSTAR PBOP Plan
Discount Rate	4.58	%	N/A		N/A
Expected Long-Term Rate of Return	7.30	%	N/A		N/A

The following is a summary of the changes in plan assets and benefit obligations recognized in Regulatory Assets and OCI as well as amounts in Regulatory Assets and OCI reclassified as net periodic benefit (expense)/income during the years presented:
		Amounts Reclassified To/From
	Regulatory Assets				OCI
(Millions of Dollars)	For the Years Ended December 31,
NU PBOP Plans (1)	2012		2011		2012		2011
Actuarial (Gains)/Losses Arising During the Year	$	(108.6)	$	50.2	$	(1.8)	$	4.0
Actuarial Losses Reclassified as Net Periodic Benefit Expense		(34.9)		(18.1)		(1.1)		(0.9)
Prior Service Credit Reclassified as Net Periodic Benefit Income		1.4		0.3		-		-
Transition Obligation Reclassified as Net Periodic Benefit Expense		(11.9)		(11.3)		(0.2)		(0.2)
The following is a summary of the remaining Regulatory Assets and Accumulated Other Comprehensive Loss amounts that have not been recognized as components of net periodic benefit expense as of December 31, 2012 and 2011, and the amounts that are expected to be recognized as components in 2013:
		Regulatory Assets as of			Expected			AOCI as of			Expected
(Millions of Dollars)	December 31,				2013			December 31,			2013
NU PBOP Plans (1)	2012		2011		Expense		2012		2011		Expense
Actuarial Loss	$	376.1	$	196.3	$	31.4	$	9.2	$	12.1	$	1.0
Prior Service Credit		(6.7)		(2.4)		(2.1)		-		-		-
Transition Obligation		-		11.4		-		-		0.2		-

⁽¹⁾

The NU consolidated amounts include the NSTAR PBOP Plan from the date of the merger, April 10, 2012, through December 31, 2012.

For the NUSCO PBOP Plans, the health care cost trend assumption is 7 percent, subsequently decreasing 50 basis points per year to an ultimate rate of 5 percent in 2017. For the NSTAR PBOP Plan, the health care cost trend assumption is 7.10 percent, subsequently decreasing to an ultimate rate of 4.50 percent in 2024.  

Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans.  The effect of changing the assumed health care cost trend rate by one percentage point for the year ended December 31, 2012 would have the following effects:

(Millions of Dollars)	One Percentage		One Percentage
NU PBOP Plans	Point Increase		Point Decrease
Effect on Postretirement Benefit Obligation	$	126.5	$	(101.7)
Effect on Total Service and Interest Cost Components		8.9		(6.9)

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Estimated Future Benefit Payments:  The following benefit payments, which reflect expected future service, are expected to be paid by the Pension, SERP and PBOP Plans:
(Millions of Dollars)	Pension
NU Consolidated	and SERP		PBOP
2013	$	238.0	$	63.5
2014		257.3		65.0
2015		252.4		66.8
2016		261.2		68.2
2017		270.6		69.6
2018-2022		1,510.2		366.3
NSTAR Pension Plan
2013	$	77.7		N/A
2014		79.6		N/A
2015		82.6		N/A
2016		83.2		N/A
2017		85.1		N/A
2018-2022		462.2		N/A

Contributions:  NU’s policy is to annually fund the NUSCO and NSTAR Pension Plans in an amount at least equal to an amount that will satisfy federal requirements.  NU contributed $197.4 million to the NUSCO Pension Plan in 2012, of which $87.7 million was contributed by PSNH.  NSTAR Electric contributed $25 million to the NSTAR Pension Plan for the year ended December 31, 2012.  Based on the current status of the NUSCO Pension Plan, NU anticipates making a contribution of approximately $203 million in 2013, of which $107 million is required to meet minimum federal funding requirements.  NSTAR Electric anticipates making a contribution of approximately $82 million in 2013 to the NSTAR Pension Plan, of which $38 million is required to meet minimum federal funding requirements.

For the PBOP Plans, it is NU’s policy to annually fund the NUSCO PBOP Plans in an amount equal to the PBOP Plans' postretirement benefit cost, excluding curtailment and termination benefits.  NU contributed $50 million to the NUSCO PBOP Plans in 2012 and expects to make $25.7 million in contributions in 2013.  NU contributes an amount that approximates annual benefit payments to the NSTAR PBOP Plan.  NU contributed $22.7 million to the NSTAR PBOP Plan for the period April 10, 2012 to December 31, 2012 and expects to make $30 million in contributions in 2013.  

Fair Value of Pension and PBOP Plan Assets:  Pension and PBOP funds are held in external trusts.  Trust assets, including accumulated earnings, must be used exclusively for Pension and PBOP payments.  NU's investment strategy for its Pension and PBOP Plans is to maximize the long-term rates of return on these plans' assets within an acceptable level of risk.  The investment strategy for each asset category includes a diversification of asset types, fund strategies and fund managers and establishes target asset allocations that are routinely reviewed and periodically rebalanced.  In 2012, PBOP assets were comprised of specific assets within the defined benefit pension plan trust (401(h) assets) as well as assets held in the PBOP Plans.  The investment policy and strategy of the 401(h) assets is consistent with those of the defined benefit pension plans, which are detailed below.  NU's expected long-term rates of return on Pension and PBOP Plan assets are based on these target asset allocation assumptions and related expected long-term rates of return.  In developing its expected long-term rate of return assumptions for the Pension and PBOP Plans, NU evaluated input from actuaries and consultants, as well as long-term inflation assumptions and historical returns.  For the year ended December 31, 2012, management has assumed long-term rates of return of 8.25 percent on NUSCO Pension and PBOP Plan assets and 7.30 percent on the NSTAR Pension and PBOP Plan assets.  These long-term rates of return are based on the assumed rates of return for the target asset allocations as follows:  

		As of December 31,
		2012 and 2011		2012		2011		2012
		NUSCO Pension and PBOP		NSTAR Pension Plan		NSTAR Pension Plan		NSTAR PBOP Plan
		Target	Assumed	Target	Assumed	Target	Assumed	Target	Assumed
		Asset	Rate	Asset	Rate	Asset	Rate	Asset	Rate
		Allocation	of Return	Allocation	of Return	Allocation	of Return	Allocation	of Return
Equity Securities:
	United States	24%	9%	25%	8.3%	22%	8.6%	25%	8.3%
	International	13%	9%	13%	8.6%	12%	8.9%	20%	8.6%
	Emerging Markets	3%	10%	5%	8.8%	5%	8.8%	5%	8.8%
	Private Equity	12%	13%	-	-	-	-	-	-
Debt Securities:
	Fixed Income	20%	5%	21%	4.6%	15%	4.4%	30%	4.6%
	High Yield Fixed Income	3.5%	7.5%	9%	6.5%	9%	6.2%	-	-
	Emerging Markets Debt	3.5%	7.5%	4%	6.4%	3%	6.8%	-	-
Real Estate and Other Assets		8%	7.5%	10%	7.9%	11%	7.7%	10%	7.9%
Hedge Funds		13%	7%	13%	8.4%	23%	8.6%	10%	8.4%

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The following table presents, by asset category, the Pension and PBOP Plan assets recorded at fair value on a recurring basis by the level in which they are classified within the fair value hierarchy:  

		NU Consolidated Pension Plans
		Fair Value Measurements as of December 31,
(Millions of Dollars)		2012								2011
Asset Category:		Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Equity Securities:
	United States (2)	$	336.5	$	302.8	$	270.6	$	909.9	$	218.7	$	14.8	$	259.4	$	492.9
	International (2)		42.0		362.6		52.1		456.7		20.0		221.9		-		241.9
	Emerging Markets (2)		-		135.3		-		135.3		-		66.6		-		66.6
	Private Equity		26.7		-		267.9		294.6		11.3		-		255.1		266.4
Fixed Income(3)			54.9		629.2		315.1		999.2		17.8		268.7		276.2		562.7
Real Estate and
	Other Assets		-		78.9		235.4		314.3		24.8		57.8		71.8		154.4
Hedge Funds			-		-		418.9		418.9		-		-		240.0		240.0
Total Master Trust Assets		$	460.1	$	1,508.8	$	1,560.0	$	3,528.9	$	292.6	$	629.8	$	1,102.5	$	2,024.9
	Less:  401(h) PBOP Assets (4)								(117.6)								(19.0)
Total Pension Assets								$	3,411.3							$	2,005.9
		NSTAR Pension Plan
		Fair Value Measurements as of December 31,
(Millions of Dollars)		2012								2011 (1) (5)
Asset Category:		Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Equity Securities:
	United States (2)	$	96.7	$	246.4	$	-	$	343.1	$	77.0	$	212.3	$	-	$	289.3
	International (2)		-		98.3		52.1		150.4		4.0		82.8		41.4		128.2
	Emerging Markets (2)		-		55.9		-		55.9		-		46.9		-		46.9
Fixed Income (3)			54.9		292.5		-		347.4		124.7		230.3		-		355.0
Real Estate			-		-		127.2		127.2		-		-		111.0		111.0
Hedge Funds			-		-		122.7		122.7		-		-		126.6		126.6
Total Master Trust Assets		$	151.6	$	693.1	$	302.0	$	1,146.7	$	205.7	$	572.3	$	279.0	$	1,057.0
	Less:  401(h) PBOP Assets (4)								(77.6)								(68.5)
Total Pension Assets								$	1,069.1							$	988.5
		NU Consolidated PBOP Plans
		Fair Value Measurements as of December 31,
(Millions of Dollars)		2012								2011
Asset Category:		Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Cash and Cash
	Equivalents	$	9.7	$	-	$	-	$	9.7	$	5.9	$	-	$	-	$	5.9
Equity Securities:
	United States (2)		116.3		57.7		36.3		210.3		116.9		-		10.7		127.6
	International (2)		68.0		29.7		-		97.7		29.6		-		-		29.6
	Emerging Markets (2)		7.7		14.0		-		21.7		4.6		-		-		4.6
Fixed Income (3)			-		137.7		32.1		169.8		-		44.3		26.0		70.3
Hedge Funds			-		-		39.6		39.6		-		-		16.1		16.1
Private Equity			-		-		11.3		11.3		-		-		5.1		5.1
Real Estate and Other
	Assets		-		4.7		26.7		31.4		-		4.7		2.5		7.2
Total		$	201.7	$	243.8	$	146.0	$	591.5	$	157.0	$	49.0	$	60.4	$	266.4
	Add:  401(h) PBOP Assets (4)								117.6								19.0
Total PBOP Assets								$	709.1							$	285.4

⁽¹⁾

The NSTAR Pension Plan amounts are not included in NU consolidated as of December 31, 2011.

⁽²⁾

United States, International and Emerging Markets equity securities classified as Level 2 include investments in commingled funds and unrealized gains/(losses) on holdings in equity index swaps.  Level 3 investments include hedge funds that are overlayed with equity index swaps and futures contracts and funds invested in equities that have redemption restrictions.  

⁽³⁾

Fixed Income investments classified as Level 3 investments include fixed income funds that invest in a variety of opportunistic fixed income strategies, and hedge funds that are overlayed with fixed income futures.  

⁽⁴⁾

The assets of the Pension Plans include a 401(h) account that has been allocated to provide health and welfare postretirement benefits under the PBOP Plans.

⁽⁵⁾

For NSTAR Electric, certain pension assets have been reclassified to the current year presentation in order to align the reporting of pension assets subsequent to the closing of the merger.

CL&P, PSNH and WMECO participate in the NUSCO Pension Plan and NUSCO PBOP Plans.  Each company participating in the plans is allocated a portion of the total plan assets.  As of December 31, 2012 and 2011, the NUSCO Pension Plan has total assets of $2,342.6 million and $2,005.9 million, respectively.  CL&P, PSNH and WMECO’s portion of these total plan assets were 40 percent, 17 percent and 9 percent, respectively, as of December 31, 2012, and 43 percent, 14 percent and 10 percent, respectively, as of December 31, 2011.  The NUSCO PBOP Plans had total plan assets of $334.9 million and $285.4 million as of December 31, 2012 and

149

2011, respectively.  CL&P, PSNH and WMECO’s share of these assets were 39 percent, 21 percent and 9 percent, respectively, as of both December 31, 2012 and 2011.

The Company values assets based on observable inputs when available.  Equity securities, exchange traded funds and futures contracts classified as Level 1 in the fair value hierarchy are priced based on the closing price on the primary exchange as of the balance sheet date.  Commingled funds included in Level 2 equity securities are recorded at the net asset value provided by the asset manager, which is based on the market prices of the underlying equity securities.  Swaps are valued using pricing models that incorporate interest rates and equity and fixed income index closing prices to determine a net present value of the cash flows.  Fixed income securities, such as government issued securities, corporate bonds and high yield bond funds, are included in Level 2 and are valued using pricing models, quoted prices of securities with similar characteristics or discounted cash flows.  The pricing models utilize observable inputs such as recent trades for the same or similar instruments, yield curves, discount margins and bond structures.  Hedge funds and investments in opportunistic fixed income funds are recorded at net asset value based on the values of the underlying assets.  The assets in the hedge funds and opportunistic fixed income funds are valued using observable inputs and are classified as Level 3 within the fair value hierarchy due to redemption restrictions.  Private Equity investments and Real Estate and Other Assets are valued using the net asset value provided by the partnerships, which are based on discounted cash flows of the underlying investments, real estate appraisals or public market comparables of the underlying investments.  These investments are classified as Level 3 due to redemption restrictions.  

Fair Value Measurements Using Significant Unobservable Inputs (Level 3):  The following tables present changes for the Level 3 category of Pension and PBOP Plan assets for the years ended December 31, 2012 and 2011:  

		NU Consolidated Pension Plans
		United								Real Estate
		States				Private		Fixed		and Other		Hedge
(Millions of Dollars)		Equity		International		Equity		Income		Assets		Funds		Total
Balance as of January 1, 2011		$	266.0	$	-	$	229.5	$	247.6	$	43.7	$	247.1	$	1,033.9
Actual Return/(Loss) on Plan Assets:
	Relating to Assets Still Held as of Year End		(6.6)		-		20.0		(1.5)		1.6		(7.1)		6.4
	Relating to Assets Distributed During the Year		-		-		19.5		(2.8)		0.3		-		17.0
Purchases, Sales and Settlements			-		-		(13.9)		32.9		26.2		-		45.2
Balance as of December 31, 2011		$	259.4	$	-	$	255.1	$	276.2	$	71.8	$	240.0	$	1,102.5
Assets Assumed from Merger with NSTAR			-		41.4		-		-		111.0		126.6		279.0
Actual Return/(Loss) on Plan Assets:
	Relating to Assets Still Held as of Year End		11.2		10.7		17.0		42.1		5.7		21.8		108.5
	Relating to Assets Distributed During the Year		-		-		15.0		0.7		7.6		(0.3)		23.0
Purchases, Sales and Settlements			-		-		(19.2)		(3.9)		39.3		30.8		47.0
Balance as of December 31, 2012		$	270.6	$	52.1	$	267.9	$	315.1	$	235.4	$	418.9	$	1,560.0

		NU Consolidated PBOP Plans
		United						Real Estate
		States		Private		Fixed		and Other			Hedge
(Millions of Dollars)		Equity		Equity		Income		Assets			Funds		Total
Balance as of January 1, 2011		$	10.1	$	0.3	$	23.4	$	-	$	16.4	$	50.2
Actual Return/(Loss) on Plan Assets:
	Relating to Assets Still Held as of Year End		0.6		0.6		0.2		(0.1)		(0.3)		1.0
Purchases, Sales and Settlements			-		4.2		2.4		2.6		-		9.2
Balance as of December 31, 2011		$	10.7	$	5.1	$	26.0	$	2.5	$	16.1	$	60.4
Assets Assumed from Merger with NSTAR			19.7		-		-		18.4		21.4		59.5
Actual Return on Plan Assets:
	Relating to Assets Still Held as of Year End		5.9		1.6		4.0		3.0		2.1		16.6
Purchases, Sales and Settlements			-		4.6		2.1		2.8		-		9.5
Balance as of December 31, 2012		$	36.3	$	11.3	$	32.1	$	26.7	$	39.6	$	146.0

		NSTAR Pension Plan
				Real Estate
				and Other
(Millions of Dollars)		International		Assets		Hedge Funds		Total
Balance as of January 1, 2011		$	45.1	$	86.8	$	157.9	$	289.8
Actual Return/(Loss) on Plan Assets:
	Relating to Assets Still Held as of Year End		(3.7)		8.7		(4.8)		0.2
	Relating to Assets Distributed During the Year		-		-		0.2		0.2
Purchases, Sales and Settlements			-		15.5		(26.7)		(11.2)
Balance as of December 31, 2011		$	41.4	$	111.0	$	126.6	$	279.0
Actual Return/(Loss) on Plan Assets:
	Relating to Assets Still Held as of Year End		10.7		9.9		5.6		26.2
	Relating to Assets Distributed During the Year		-		-		(0.3)		(0.3)
Purchases, Sales and Settlements			-		6.3		(9.2)		(2.9)
Balance as of December 31, 2012		$	52.1	$	127.2	$	122.7	$	302.0

150

B.

Defined Contribution Plans

NU maintains two defined contribution plans on behalf of eligible participants.  The NUSCO 401(k) Savings Plan covers eligible employees, including CL&P, PSNH, WMECO, and effective October 1, 2012, certain newly-hired NSTAR Electric & Gas employees.  The NSTAR 401(k) Savings Plan covers eligible employees of NSTAR Electric & Gas.  These defined contribution plans provide for employee and employer contributions up to statutory limits.

The NUSCO 401(k) Savings Plan matches employee contributions up to a maximum of three percent of eligible compensation with one percent invested in cash and two percent invested in the NU common share fund.  The NUSCO 401(k) Savings Plan also contains a K-Vantage feature (company contribution based on age and years of service), which covers the majority of NU non-represented employees hired on or after January 1, 2006 and certain NU bargaining unit employees, hired on or after January 1, 2007 or as subject to collective bargaining agreements.  In addition, all newly hired non-represented NSTAR Electric & Gas employees and certain represented NSTAR Electric & Gas employees are eligible to participate in the K-Vantage program effective October 1, 2012 and November 1, 2012, respectively.  Participants in the K-Vantage program are not eligible to actively participate in any NU defined benefit plan.

The NSTAR 401(k) Savings Plan matches employee contributions of 50 percent on up to the first 8 percent of eligible compensation.  All employer contributions are invested in the NU common share fund.

The total defined contribution plan matching contributions, including the K-Vantage program contributions, are as follows:

					NSTAR
(Millions of Dollars)	NU		CL&P		Electric(1)		PSNH		WMECO
2012	$	25.7	$	4.8	$	9.0	$	3.3	$	0.9
2011		17.4		4.5		8.7		3.1		0.9
2010		16.1		4.4		8.1		2.8		0.9

⁽¹⁾

NSTAR Electric amounts are included in NU consolidated from the date of the merger, April 10, 2012, through December 31, 2012.  NSTAR Electric amounts are not included in NU consolidated for the years ended December 31, 2011 and 2010.  

C.

Employee Stock Ownership Plan

NU maintains an ESOP for purposes of allocating shares to employees participating in the NUSCO 401(k) Savings Plan.  Allocations of NU common shares were made from NU treasury shares to satisfy the NUSCO 401(k) Savings Plan obligation to provide a portion of the matching contribution in NU common shares.

For treasury shares used to satisfy the 401(k) Savings Plan matching contributions, compensation expense is recognized equal to the fair value of shares that have been allocated to participants.  Any difference between the fair value and the average cost of the allocated treasury shares is charged or credited to Capital Surplus, Paid In.  For the years ended December 31, 2012, 2011 and 2010, NU recognized $8.9 million, $8.8 million and $8.5 million, respectively, of expense related to the ESOP.

D.

Share-Based Payments

Share-based compensation awards are recorded using the fair value-based method at the date of grant.  NU, CL&P, NSTAR Electric, PSNH and WMECO record compensation cost related to these awards, as applicable, for shares issued or sold to their respective employees and officers, as well as the allocation of costs associated with shares issued or sold to NU's service companies' employees and officers that support CL&P, NSTAR Electric, PSNH and WMECO.  

Upon consummation of the merger with NSTAR, the NSTAR 1997 Share Incentive Plan and the NSTAR 2007 Long-Term Incentive Plan were assumed by NU.  Share-based awards granted under the NSTAR Plans and held by NSTAR employees and officers were generally converted into outstanding NU share-based compensation awards with an estimated fair value of $53.2 million.  Refer to Note 2, "Merger of NU and NSTAR," for further information regarding the merger transaction.  Specifically, as of the merger closing, and as adjusted by the exchange ratio, (1) NU converted outstanding NSTAR stock options into 2,664,894 NU stock options valued at $30.5 million, (2) NU converted NSTAR deferred shares and NSTAR performance shares into 421,775 NU RSU’s valued at $15.5 million, and (3) NU converted NSTAR RSU retention awards into 195,619 NU RSU retention awards valued at $7.2 million.

NU Incentive Plan:  NU maintains long-term equity-based incentive plans under the NU Incentive Plan in which NU, CL&P, PSNH and WMECO employees, officers and board members are entitled to participate.  The NU Incentive Plan was approved in 2007, and authorized NU to grant up to 4,500,000 new shares for various types of awards, including RSUs and performance shares, to eligible employees, officers, and board members.  As of December 31, 2012 and 2011, NU had 2,502,512 and 2,685,615 common shares, respectively, available for issuance under the NU Incentive Plan.  In addition to the NU Incentive Plan, NU maintains an ESPP for eligible employees.  

NSTAR Incentive Plans:  Awards may continue to be granted following the merger under the NSTAR 2007 Long-Term Incentive Plan; however, no additional awards will be granted under the NSTAR 1997 Share Incentive Plan.  The aggregate number of common shares initially authorized for issuance under the NSTAR 2007 Long-Term Incentive Plan was 3,500,000.  As of December 31, 2012, there were 977,922 NU common shares available for issuance under the NSTAR 2007 Long-Term Incentive Plan.  

151

NU accounts for its various share-based plans as follows:

·

RSUs - NU records compensation expense, net of estimated forfeitures, on a straight-line basis over the requisite service period based upon the fair value of NU's common shares at the date of grant.  The par value of RSUs is reclassified to Common Stock from APIC as RSUs become issued as common shares.

·

Performance Shares - NU records compensation expense, net of estimated forfeitures, on a straight-line basis over the requisite service period.  Performance shares vest based upon the extent to which Company goals are achieved.  For the majority of performance shares, fair value is based upon the value of NU's common shares at the date of grant and compensation expense is recorded based upon the probable outcome of the achievement of Company targets.  For the remaining performance shares, vesting is based upon the achievement of the Company's share price as compared to an index of similar equity securities.  The fair value at the date of grant for these remaining performance shares was determined using a lattice model and compensation expense is recorded over the requisite service period.

·

Stock Options - Stock options issued under the NSTAR Incentive Plan that were outstanding immediately prior to the completion of the merger with NSTAR converted into fully vested options to acquire NU common shares, as adjusted by the exchange ratio.  The fair value of these awards on the merger date was included in the purchase price as it represented consideration transferred in the merger.  Accordingly, no compensation expense is recorded for these stock options.  Additionally, no compensation expense is recorded for stock options issued under the NU Incentive Plan as these stock options were fully vested prior to January 1, 2006.

·

ESPP Shares - For shares sold under the ESPP, no compensation expense is recorded, as the ESPP qualifies as a non-compensatory plan.  

RSUs:  NU granted RSUs under the annual Long-Term incentive programs that are subject to three-year graded vesting schedules for employees, and one-year graded vesting schedules for board members.  RSUs are paid in shares, reduced by amounts sufficient to satisfy withholdings for income taxes, subsequent to vesting.  A summary of RSU transactions is as follows:

			Weighted Average
	RSUs		Grant-Date
	(Units)		Fair Value
Outstanding as of January 1, 2010		1,037,912	$	24.07
Granted		258,174	$	26.03
Shares issued		(267,951)	$	25.05
Forfeited		(13,656)	$	24.26
Outstanding as of December 31, 2010		1,014,479	$	24.31
Granted		208,533	$	33.87
Shares issued		(244,782)	$	24.47
Forfeited		(18,310)	$	23.74
Outstanding as of December 31, 2011		959,920	$	26.36
Granted		614,930	$	33.04
Converted NSTAR Awards upon Merger		617,394	$	36.79
Converted from NU Performance Shares upon Merger		451,358	$	34.32
Shares issued		(363,779)	$	29.05
Forfeited		(96,504)	$	34.97
Outstanding as of December 31, 2012		2,183,319	$	31.99

As of December 31, 2012 and 2011, the number and weighted average grant-date fair value of unvested RSUs was 1,417,688 and $34.70 per share, and 403,108 and $28.70 per share, respectively.  The number and weighted average grant-date fair value of RSUs vested during 2012 was 471,323 and $30.20 per share, respectively.  As of December 31, 2012, 765,631 RSUs were fully vested and an additional 1,346,804 are expected to vest.  

152

Performance Shares:  NU had granted performance shares under the annual Long-Term Incentive programs that vested based upon the extent to which the Company achieved targets at the end of three-year performance measurement periods.  Performance shares are paid in shares, after the performance measurement period.  A summary of performance share transactions is as follows:

	Performance		Weighted Average
	Shares		Grant-Date
	(Units)		Fair Value
Outstanding as of January 1, 2010		99,086	$	23.93
Granted		149,520	$	25.24
Shares issued		-	$	-
Forfeited		(47)	$	23.96
Outstanding as of December 31, 2010		248,559	$	24.72
Granted		244,870	$	33.76
Shares issued		-	$	-
Forfeited		(10,296)	$	30.47
Outstanding as of December 31, 2011		483,133	$	29.18
Granted		225,935	$	35.09
Converted to RSUs upon Merger		(451,358)	$	34.32
Shares issued		(106,773)	$	24.52
Forfeited		-	$	-
Outstanding as of December 31, 2012		150,937	$	25.04

Upon closing of the merger with NSTAR, 451,358 performance shares under the NU 2011 and 2012 Long-Term Incentive Programs converted to RSUs according to the terms of these programs.  The remaining performance shares were measured based upon a modified performance period through the date of the merger, in accordance with the terms of the NU 2010 Incentive Program, with distribution in 2013.  

The total compensation cost and associated future income tax benefit recognized by NU, CL&P, NSTAR Electric, PSNH and WMECO for share-based compensation awards were as follows:

NU	For the Years Ended December 31,
(Millions of Dollars)	2012		2011		2010
Compensation Cost	$	25.8	$	12.3	$	10.5
Future Income Tax Benefit		10.2		4.9		4.2

		For the Years Ended December 31,
		2012								2011								2010
(Millions of Dollars)		CL&P		NSTAR Electric(1)		PSNH		WMECO		CL&P		NSTAR Electric(1)		PSNH		WMECO		CL&P		NSTAR Electric(1)		PSNH		WMECO
Compensation Cost		$	4.8	$	7.4	$	1.8	$	1.0	$	7.1	$	7.7	$	2.5	$	1.4	$	6.2	$	6.5	$	2.1	$	1.1
Future Income Tax
	Benefit		1.9		2.9		0.7		0.4		2.8		3.0		1.0		0.6		2.5		2.6		0.9		0.4

⁽¹⁾

NSTAR Electric amounts are included in NU consolidated from the date of the merger, April 10, 2012, through December 31, 2012. NSTAR Electric amounts are not included in NU consolidated for the years ended December 31, 2011 and 2010.  

As of December 31, 2012, there was $26.1 million of total unrecognized compensation cost related to nonvested share-based awards for NU, $5.3 million for CL&P, $10.6 million for NSTAR Electric, $1.8 million for PSNH and $1.1 million for WMECO.  This cost is expected to be recognized ratably over a weighted-average period of 1.90 years for NU, 2.03 years for CL&P, 1.76 years for NSTAR Electric and 1.84 years for PSNH and WMECO.

For the years ended December 31, 2012, 2011 and 2010, additional tax benefits totaling $8.5 million, $1.3 million and $0.9 million, respectively, increased cash flows from financing activities.

153

Stock Options:  Stock options were granted under the NU and NSTAR Incentive Plans.  Options currently outstanding expire ten years from the date of grant and are fully vested.  The weighted average remaining contractual lives for the options outstanding as of December 31, 2012 is 4.8 years.  A summary of stock option transactions is as follows:

		Weighted Average		Intrinsic Value
	Options	Exercise Price		(Millions)
Outstanding and Exercisable - January 1, 2010	225,216	$	18.96
Exercised	(112,617)	$	19.12	$	1.0
Forfeited and Cancelled	-	$	-
Outstanding and Exercisable - December 31, 2010	112,599	$	18.80
Exercised	(65,225)	$	18.81	$	1.0
Forfeited and Cancelled	-	$	-
Outstanding and Exercisable - December 31, 2011	47,374	$	18.78
Converted NSTAR Options upon Merger	2,664,894	$	23.99
Exercised	(1,166,511)	$	22.53	$	18.7
Forfeited and Cancelled	-	$	-
Outstanding and Exercisable - December 31, 2012	1,545,757	$	24.92	$	21.9

Cash received for options exercised during the year ended December 31, 2012 totaled $26.3 million.  The tax benefit realized from stock options exercised totaled $7.5 million for the year ended December 31, 2012.  

Employee Share Purchase Plan:  NU maintains an ESPP for eligible employees, which allows for NU common shares to be purchased by employees at the end of successive six-month offering periods at 95 percent of the closing market price on the last day of each six-month period.  Employees are permitted to purchase shares having a value not exceeding 25 percent of their compensation as of the beginning of the offering period up to a limit of $25,000 per annum.  The ESPP qualifies as a non-compensatory plan under accounting guidance for share-based payments, and no compensation expense is recorded for ESPP purchases.   

During 2012, employees purchased 39,422 shares at discounted prices of $33.01 and $37.89.  Employees purchased 35,476 shares in 2011 at discounted prices of $31.27 and $32.30.  As of December 31, 2012 and 2011, 857,280 and 896,702 shares, respectively, remained available for future issuance under the ESPP.

An income tax rate of 40 percent is used to estimate the tax effect on total share-based payments determined under the fair value-based method for all awards.  The Company generally settles stock option exercises and fully vested RSUs and performance shares with either the issuance of new common shares or the issuance of common shares purchased in the open market.

E.

Other Retirement Benefits

NU provides benefits for retirement and other benefits for certain current and past company officers of NU, including CL&P, PSNH and WMECO.  These benefits are accounted for on an accrual basis and expensed over the service lives of the employees.  The actuarially-determined liability for these benefits, which is included in Other Long-Term Liabilities on the accompanying consolidated balance sheets, as well as the related expense, were as follows:

NU	For the Years Ended December 31,
(Millions of Dollars)	2012		2011		2010
Actuarially-Determined Liability	$	54.6	$	52.8	$	49.9
Other Retirement Benefits Expense		4.7		4.7		4.2

	For the Years Ended December 31,
	2012						2011						2010
(Millions of Dollars)	CL&P		PSNH		WMECO		CL&P		PSNH		WMECO		CL&P		PSNH		WMECO
Actuarially-Determined Liability	$	0.4	$	2.5	$	0.2	$	1.2	$	2.5	$	0.2	$	0.4	$	2.4	$	0.2
Other Retirement Benefits Expense		2.6		1.0		0.5		2.6		1.0		0.5		2.3		0.9		0.4

154

11.

INCOME TAXES

The tax effect of temporary differences is accounted for in accordance with the rate-making treatment of the applicable regulatory commissions and relevant accounting authoritative literature.  The components of income tax expense are as follows:

NU	For the Years Ended December 31,
(Millions of Dollars)	2012		2011		2010
Current Income Taxes:
Federal	$	(30.9)	$	3.0	$	9.0
State		17.6		(26.0)		(6.5)
Total Current		(13.3)		(23.0)		2.5
Deferred Income Taxes, Net:
Federal		291.3		187.7		201.2
State		0.8		9.1		9.7
Total Deferred		292.1		196.8		210.9
Investment Tax Credits, Net		(3.9)		(2.8)		(3.0)
Income Tax Expense	$	274.9	$	171.0	$	210.4

		For the Years Ended December 31,
		2012								2011								2010
				NSTAR								NSTAR								NSTAR
(Millions of Dollars)		CL&P		Electric (1)		PSNH		WMECO		CL&P		Electric(1)		PSNH		WMECO		CL&P		Electric(1)		PSNH		WMECO
Current Income Taxes:
	Federal	$	(47.8)	$	93.5	$	(0.9)	$	(24.7)	$	13.9	$	64.9	$	(25.8)	$	0.1	$	20.7	$	94.8	$	6.1	$	3.1
	State		3.1		27.6		3.4		3.4		(34.4)		30.2		0.1		0.3		(1.1)		27.0		5.6		2.5
Total Current			(44.7)		121.1		2.5		(21.3)		(20.5)		95.1		(25.7)		0.4		19.6		121.8		11.7		5.6
Deferred Income
	Taxes, Net:
	Federal		141.5		11.4		46.5		51.2		106.4		74.8		67.7		22.1		108.1		41.7		37.6		11.0
	State		(0.5)		(7.1)		12.0		2.7		6.2		(2.8)		7.9		1.0		7.0		(0.1)		1.6		-
Total Deferred			141.0		4.3		58.5		53.9		112.6		72.0		75.6		23.1		115.1		41.6		39.2		11.0
Investment Tax
	Credits, Net		(1.9)		(1.4)		-		(0.5)		(2.1)		(1.4)		-		(0.3)		(2.3)		(1.4)		(0.1)		(0.3)
Income Tax Expense		$	94.4	$	124.0	$	61.0	$	32.1	$	90.0	$	165.7	$	49.9	$	23.2	$	132.4	$	162.0	$	50.8	$	16.3
(1)	NSTAR Electric amounts are included in NU consolidated from the date of the merger, April 10, 2012, through December 31, 2012.  NSTAR Electric amounts are not included in NU consolidated for the years ended December 31, 2011 and 2010.

A reconciliation between income tax expense and the expected tax expense at the statutory rate is as follows:
NU		For the Years Ended December 31,
(Millions of Dollars, except percentages)		2012		2011		2010
Income Before Income Tax Expense		$	808.0	$	571.5	$	604.5
Statutory Federal Income Tax Expense at 35%			282.8		200.0		211.6
Tax Effect of Differences:
	Depreciation		(10.8)		(14.2)		(9.5)
	Investment Tax Credit Amortization		(3.9)		(2.8)		(3.0)
	Other Federal Tax Credits		(3.8)		(3.5)		(3.8)
	State Income Taxes, Net of Federal Impact		4.4		22.1		12.5
	Medicare Subsidy		-		-		15.6
	Tax Asset Valuation Allowance/Reserve Adjustments		7.6		(33.1)		(10.5)
	Other, Net		(1.4)		2.5		(2.5)
Income Tax Expense		$	274.9	$	171.0	$	210.4
Effective Tax Rate			34.0%		29.9%		34.8%

155

		For the Years Ended December 31,
		2012								2011								2010
(Millions of Dollars,				NSTAR								NSTAR								NSTAR
	except percentages)	CL&P		Electric(1)		PSNH		WMECO		CL&P		Electric(1)		PSNH		WMECO		CL&P		Electric(1)		PSNH		WMECO
Income Before Income
	Tax Expense	$	304.2	$	314.2	$	157.9	$	86.6	$	340.2	$	418.2	$	150.2	$	66.2	$	376.6	$	410.6	$	140.9	$	39.4
Statutory Federal Income
	Tax Expense at 35%		106.5		110.0		55.3		30.3		119.1		146.4		52.6		23.2		131.8		143.7		49.3		13.8
Tax Effect of Differences:
	Depreciation		(9.0)		-		(0.3)		0.2		(8.1)		-		(4.4)		0.1		(6.1)		-		(3.2)		0.2
	Investment Tax Credit
	Amortization		(1.9)		(1.4)		-		(0.5)		(2.1)		(1.4)		-		(0.3)		(2.3)		(1.4)		(0.1)		(0.3)
	Other Federal Tax Credits		-		-		(3.8)		-		(0.1)		-		(3.4)		-		(0.1)		-		(3.6)		-
	State Income Taxes, Net
	of Federal Impact		0.1		13.4		10.0		4.0		4.0		17.9		5.2		0.9		8.5		17.4		4.7		1.6
	Medicare Subsidy		-		-		-		-		-		-		-		-		7.8		-		3.8		1.5
	Tax Asset Valuation
	Allowance/Reserve
	Adjustments		1.6		-		-		-		(22.3)		-		-		-		(4.7)		-		-		-
	Regulatory Decision Non-
	Plant flow through		-		-		-		(1.3)		-		-		-		-		-		-		-		-
	Other, Net		(2.9)		2.0		(0.2)		(0.6)		(0.5)		2.8		(0.1)		(0.7)		(2.5)		2.3		(0.1)		(0.5)
Income Tax Expense		$	94.4	$	124.0	$	61.0	$	32.1	$	90.0	$	165.7	$	49.9	$	23.2	$	132.4	$	162.0	$	50.8	$	16.3
Effective Tax Rate			31.0%		39.5%		38.6%		37.1%		26.5%		39.6%		33.2%		35.0%		35.2%		39.5%		36.1%		41.4%

NU, CL&P, NSTAR Electric, PSNH and WMECO file a consolidated federal income tax return and unitary, combined and separate state income tax returns.  These entities are also parties to a tax allocation agreement under which taxable subsidiaries do not pay any more taxes than they would have otherwise paid had they filed a separate company tax return, and subsidiaries generating tax losses, if any, are paid for their losses when utilized.

Deferred tax assets and liabilities are recognized for the future tax effects of temporary differences between the carrying amounts and the tax basis of assets and liabilities.  The tax effects of temporary differences that give rise to the net accumulated deferred tax obligations are as follows:

NU			As of December 31,
(Millions of Dollars)			2012		2011
Deferred Tax Assets:
	Employee Benefits		$	811.4	$	539.6
	Derivative Liabilities and Change in Fair Value of Energy Contracts			380.6		415.3
	Regulatory Deferrals			257.9		157.9
	Allowance for Uncollectible Accounts			64.2		45.4
	Tax Effect - Tax Regulatory Assets			17.2		15.5
	Federal Net Operating Loss Carryforwards			214.6		178.6
	Purchase Accounting Adjustment			146.4		-
	Other			242.4		204.2
Total Deferred Tax Assets				2,134.7		1,556.5
Less:  Valuation Allowance				4.2		4.6
Net Deferred Tax Assets			$	2,130.5	$	1,551.9
Deferred Tax Liabilities:
	Accelerated Depreciation and Other Plant-Related Differences		$	3,468.8	$	1,920.5
	Property Tax Accruals			89.6		58.9
	Regulatory Amounts:
		Other Regulatory Deferrals		1,561.1		1,135.0
		Tax Effect - Tax Regulatory Assets		217.2		184.6
		Goodwill - 1999 Merger		210.9		-
		Derivative Assets		36.2		39.1
		Securitized Contract Termination Costs		16.6		39.6
		Other		136.1		24.5
Total Deferred Tax Liabilities			$	5,736.5	$	3,402.2

156

			As of December 31,
			2012								2011
					NSTAR								NSTAR
(Millions of Dollars)			CL&P		Electric		PSNH		WMECO		CL&P		Electric (1)		PSNH		WMECO
Deferred Tax Assets:
	Derivative Liabilities and Change in
		Fair Value of Energy Contracts	$	375.9	$	5.8	$	-	$	(1.7)	$	412.2	$	1.3	$	-	$	2.9
	Allowance for Uncollectible Accounts			30.4		16.2		2.9		3.2		32.4		9.5		3.0		3.9
	Regulatory Deferrals			35.5		123.6		43.9		6.3		78.4		114.9		39.3		15.0
	Employee Benefits			141.2		116.3		64.8		16.3		121.4		115.3		87.9		13.3
	Tax Effect - Tax Regulatory Assets			5.2		6.0		1.7		1.7		6.4		6.9		1.6		6.5
	Federal Net Operating Loss Carryforwards			82.0		-		71.4		15.1		85.5		-		60.8		-
	Other			82.8		26.0		33.7		8.0		76.0		36.1		26.0		17.6
Total Deferred Tax Assets			$	753.0	$	293.9	$	218.4	$	48.9	$	812.3	$	284.0	$	218.6	$	59.2
Deferred Tax Liabilities:
	Accelerated Depreciation and Other
	Plant-Related Differences		$	1,194.7	$	1,079.3	$	476.5	$	261.3	$	1,046.9	$	987.8	$	423.8	$	194.9
	Property Tax Accruals			44.4		23.1		6.8		5.1		41.9		21.8		4.5		3.4
	Regulatory Amounts:
		Other Regulatory Deferrals		677.7		379.6		149.3		74.5		734.2		400.6		122.5		79.3
		Tax Effect - Tax Regulatory Assets		151.8		20.9		15.8		13.9		141.8		21.9		16.1		13.7
		Goodwill - 1999 Merger		-		181.0		-		-		-		187.8		-		-
		Derivative Assets		36.2		-		-		-		39.1		-		-		-
		Securitized Contract Termination Costs		-		5.5		7.9		3.3		-		41.3		29.7		10.0
		Other		10.1		30.2		14.1		2.3		8.2		34.8		14.0		1.1
Total Deferred Tax Liabilities			$	2,114.9	$	1,719.6	$	670.4	$	360.4	$	2,012.1	$	1,696.0	$	610.6	$	302.4
(1)		NSTAR Electric amounts are not included in NU consolidated as of December 31, 2011.

Carryforwards:  Amounts are as follows:
	As of December 31, 2012
					NSTAR						Year
(Millions of Dollars)	NU		CL&P		Electric		PSNH		WMECO		Expiration Begins
State Credit Carryforwards	$	110.2	$	75.2	$	-	$	-	$	-	2013
State Net Operating Loss Carryforward		74.9		-		-		-		-	2013
Federal Net Operating Loss Carryforward		606.9		234.3		-		204.0		43.3	2031
Federal Credit Carryforwards		3.8		-		-		3.8		-	2031
	As of December 31, 2011
					NSTAR						Year
(Millions of Dollars)	NU		CL&P		Electric		PSNH		WMECO		Expiration Begins
State Credit Carryforwards	$	101.4	$	68.6	$	-	$	-	$	-	2013
Federal Net Operating Loss Carryforward		510.2		244.2		-		173.8		-	2031
Federal Credit Carryforwards		6.6		-		-		3.4		3.2	2031

For 2012, the state net operating loss carryforward has been partially reserved by a valuation allowance of $0.3 million (net of federal income tax).

Unrecognized Tax Benefits:  A reconciliation of the activity in unrecognized tax benefits from January 1, 2010 to December 31, 2012, all of which would impact the effective tax rate, if recognized, is as follows:

						NSTAR
(Millions of Dollars)		NU		CL&P		Electric (1)
Balance as of January 1, 2010		$	124.3	$	89.0	$	13.8
	Gross Increases - Current Year		10.8		5.3		-
	Gross Increases - Prior Year		0.8		-		-
	Settlement		(34.3)		(13.5)		(13.8)
	Lapse of Statute of Limitations		(0.4)		-		-
Balance as of December 31, 2010			101.2		80.8		-
	Gross Increases - Current Year		8.0		1.4		-
	Gross Decreases - Prior Year		(35.7)		(35.7)		-
Balance as of December 31, 2011			73.5		46.5		-
	Gross Increases - Current Year		10.3		2.5		-
	Gross Increases - Prior Year		0.1		-		-
	Gross Decreases - Prior Year		(0.8)		-		-
Balance as of December 31, 2012		$	83.1	$	49.0	$	-

⁽¹⁾

NSTAR Electric amounts are not included in NU consolidated for the years ended December 31, 2011 and 2010.

Interest and Penalties:  Interest on uncertain tax positions is recorded and generally classified as a component of Other Interest Expense.  However, when resolution of uncertainties results in the Company receiving interest income, any related interest benefit is recorded in Other Income, Net on the accompanying consolidated statements of income.  No penalties have been recorded.  If

157

penalties are recorded in the future, then the estimated penalties would be classified as a component of Other Income, Net on the accompanying consolidated statements of income.  The amount of interest expense/(income) on uncertain tax positions recognized and the related accrued interest payable/(receivable) by company are as follows:

Other Interest	For the Years Ended December 31,						Accrued Interest	As of December 31,
Expense/(Income)	2012		2011		2010		Expense	2012		2011
(Millions of Dollars)							(Millions of Dollars)
NU	$	3.1	$	(2.8)	$	(24.8)	NU	$	10.1	$	7.1
CL&P		1.3		(3.7)		(7.4)	CL&P		4.0		2.7
NSTAR Electric (1)		-		2.0		(7.4)	NSTAR Electric (1)		-		0.7
PSNH		-		(0.6)		0.1	PSNH		-		-

⁽¹⁾

NSTAR Electric amounts are included in NU consolidated from the date of the merger, April 10, 2012, through December 31, 2012.  NSTAR Electric amounts are not included in NU consolidated for the years ended December 31, 2011 and 2010.

Tax Positions:  During 2012, NU did not resolve any of its uncertain tax positions.  

During 2011, NU recorded an after-tax benefit of $29.1 million related to various state tax settlements and certain other adjustments.  This benefit was recorded as a reduction to both interest expense and income tax expense (including NU and CL&P tax expense reductions of approximately $22.4 million).

During 2010, NU settled various tax matters including state obligations, which resulted in the recognition during the year of an after-tax gain of approximately $35 million.  This gain was recorded as a reduction to both interest expense and income tax expense (including NU and CL&P tax expense reductions of approximately $6 million and $4 million, respectively).  

Open Tax Years:  The following table summarizes NU, CL&P, NSTAR Electric, PSNH and WMECO's tax years that remain subject to examination by major tax jurisdictions as of December 31, 2012:  

Description	Tax Years
Federal	2012
Connecticut	2005-2012
Massachusetts	2009-2012
New Hampshire	2009-2012

Receipt of Federal Tax Refund:  During 2011, NSTAR Electric received a $166.8 million refund from the IRS relating to the 2001 through 2007 tax years.  The approved settlement and the receipt of the refund resolved all outstanding tax matters for these years.

NU is currently working to resolve the treatments and certain timing and other costs in the remaining open periods.  While tax audits are currently ongoing, it is reasonably possible that one or more of these open tax years could be resolved within the next twelve months.  Management estimates that potential resolutions of differences of a non-timing nature could result in a zero to $50 million decrease in unrecognized tax benefits by NU and a zero to $39 million decrease in unrecognized tax benefits by CL&P.  These estimated changes could have an impact on NU's and CL&P's 2013 earnings of zero to $6 million and zero to $16 million, respectively.  Other companies’ impacts are not expected to be material.  

2013 Federal Legislation:  On January 2, 2013, President Obama signed into law the "American Taxpayer Relief Act of 2012," which extends certain tax rules allowing the accelerated deduction of depreciation from the "American Recovery and Reinvestment Act of 2009" to businesses through 2013.  This extended stimulus is expected to provide cash flow benefits of approximately $200 million to $250 million in 2013 and 2014.  Management is still evaluating the other provisions of this legislation, which are not expected to have a significant impact on its future financial position, results of operations, or cash flows.

12.

COMMITMENTS AND CONTINGENCIES

A.

Environmental Matters

General:  NU, CL&P, NSTAR Electric, PSNH and WMECO are subject to environmental laws and regulations intended to mitigate or remove the effect of past operations and improve or maintain the quality of the environment.  These laws and regulations require the removal or the remedy of the effect on the environment of the disposal or release of certain specified hazardous substances at current and former operating sites.  NU, CL&P, NSTAR Electric, PSNH and WMECO have an active environmental auditing and training program and believe that they are substantially in compliance with all enacted laws and regulations.

Environmental reserves are accrued when assessments indicate it is probable that a liability has been incurred and an amount can be reasonably estimated.  The approach used estimates the liability based on the most likely action plan from a variety of available remediation options, including no action required or several different remedies ranging from establishing institutional controls to full site remediation and monitoring.

These estimates are subjective in nature as they take into consideration several different remediation options at each specific site.  The reliability and precision of these estimates can be affected by several factors, including new information concerning either the level of

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contamination at the site, the extent of NU, CL&P, NSTAR Electric, PSNH and WMECO's responsibility or the extent of remediation required, recently enacted laws and regulations or a change in cost estimates due to certain economic factors.

The amounts recorded as environmental liabilities included in Other Current Liabilities and Other Long-Term Liabilities on the accompanying consolidated balance sheets represent management's best estimate of the liability for environmental costs, and take into consideration site assessment, remediation and long-term monitoring costs.  The environmental liability also takes into account recurring costs of managing hazardous substances and pollutants, mandated expenditures to remediate previously contaminated sites and any other infrequent and non-recurring clean up costs.  A reconciliation of the activity in the environmental reserves is as follows:

(Millions of Dollars)	NU		CL&P		NSTAR Electric(1)		PSNH		WMECO
Balance as of December 31, 2010	$	37.1	$	2.8	$	0.9	$	9.1	$	0.3
Additions		1.6		0.4		0.4		0.1		0.1
Payments		(7.0)		(0.3)		-		(2.6)		(0.1)
Balance as of December 31, 2011		31.7		2.9		1.3		6.6		0.3
Liabilities Assumed with NSTAR Merger		11.8		-		-		-		-
Additions		4.7		1.3		0.7		0.2		0.5
Payments/Reductions		(8.8)		(0.5)		(0.3)		(1.9)		(0.2)
Balance as of December 31, 2012	$	39.4	$	3.7	$	1.7	$	4.9	$	0.6

⁽¹⁾

NSTAR Electric amounts are included in NU consolidated from the date of the merger, April 10, 2012 through December 31, 2012.  NSTAR Electric amounts are not included in NU consolidated for the years ended December 31, 2011 and 2010.

These liabilities are estimated on an undiscounted basis and do not assume that any amounts are recoverable from insurance companies or other third parties.  The environmental reserves include sites at different stages of discovery and remediation and do not include any unasserted claims.

It is possible that new information or future developments could require a reassessment of the potential exposure to related environmental matters.  As this information becomes available, management will continue to assess the potential exposure and adjust the reserves accordingly.  

The number of environmental sites and reserves related to these sites for which remediation or long-term monitoring, preliminary site work or site assessment are being performed are as follows:

	As of December 31, 2012				As of December 31, 2011
			Reserve				Reserve
	Number of Sites		(in millions)		Number of Sites		(in millions)
NU		77	$	39.4		59	$	31.7
CL&P		19		3.7		18		2.9
NSTAR Electric (1)		16		1.7		13		1.3
PSNH		16		4.9		18		6.6
WMECO		6		0.6		10		0.3

⁽¹⁾

The NSTAR Electric reserve balance and number of sites are not included in NU consolidated amounts as of December 31, 2011.

Included in the NU number of sites and reserve amounts above are former MGP sites that were operated several decades ago and manufactured gas from coal and other processes, which resulted in certain by-products remaining in the environment that may pose a potential risk to human health and the environment. The reserve balance related to these former MGP sites was $34.5 million and $28.9 million as of December 31, 2012 and 2011, respectively, and relates primarily to the natural gas business segment.

As of December 31, 2012, for 8 environmental sites (3 for CL&P, 2 for PSNH, and 1 for WMECO) that are included in the Company's reserve for environmental costs, the information known and nature of the remediation options at those sites allow for the Company to estimate the range of losses for environmental costs.  As of December 31, 2012, $2.6 million ($0.6 million for CL&P and $0.7 million for PSNH) had been accrued as a liability for these sites, which represent management's best estimates of the liabilities for environmental costs.  These amounts are the best estimates with estimated ranges of additional losses from zero million to $15.2 million (zero to $1.3 million for CL&P, zero to $4.1 million for PSNH, and zero to $8.6 million for WMECO).  

As of December 31, 2012, for 23 environmental sites (5 for CL&P,1 for NSTAR Electric, 4 for PSNH, and 3 for WMECO) included in the Company’s reserve for environmental costs, management cannot reasonably estimate the exposure to loss in excess of the reserve, or range of loss, as these sites are under investigation and/or there is significant uncertainty as to what remedial actions, if any, the Company may be required to undertake.  As of December 31, 2012, $17 million ($1.7 million for CL&P, $0.2 million for PSNH, and $0.5 million for WMECO) had been accrued as a liability for these sites.  As of December 31, 2012, for the remaining 46 environmental sites (11 for CL&P, 15 for NSTAR Electric, 10 for PSNH, and 2 for WMECO) included in the Company’s reserve for environmental costs, the $19.8 million accrual ($1.4 million for CL&P, $1.7 million for NSTAR Electric, $4 million for PSNH, and $0.1 million for WMECO) represents management’s best estimate of the liability and no additional loss is anticipated.

HWP:  HWP, a subsidiary of NU, continues to investigate the potential need for additional remediation at a river site in Massachusetts containing tar deposits associated with an MGP site that HWP sold to HG&E, a municipal utility, dating back to 1902.  HWP shares

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responsibility for site remediation with HG&E and has conducted substantial investigative and remediation activities.  The cumulative expense recorded to the reserve for this site since 1994 through December 31, 2012 was $19.5 million, of which $17.4 million had been spent, leaving $2.1 million in the reserve as of December 31, 2012.  For the years ended December 31, 2012 and 2011, there were no charges recorded to the reserve and for the year ended December 31, 2010, a pre-tax charge of $2.6 million was recorded to reflect estimated costs associated with the site.  HWP's share of the costs related to this site is not recoverable from customers.

In 2008, the MA DEP issued a letter to HWP and HG&E, representing guidance rather than a mandate, providing conditional authorization for additional investigatory and risk characterization activities and indicating that further removal of tar in certain areas was needed.  HWP implemented several supplemental studies to further delineate and assess tar deposits in conformity with the MA DEP's guidance letter.  In December 2012, the MADEP advised that all work to date with this site continues to meet regulatory expectations.

In 2010, HWP delivered a report to the MA DEP describing the results of its site investigation studies and testing.  Subsequent communications and discussions with the MA DEP have focused on the course of action to achieve resolution of these matters, and are ongoing.  

The $2.1 million reserve balance as of December 31, 2012 represents estimated costs that HWP considers probable over the remaining life of the project, including testing and related costs in the near term and field activities to be agreed upon with the MA DEP, further studies and long-term monitoring that are expected to be required by the MA DEP, and certain soft tar remediation activities.  Various factors could affect management's estimates and require an increase to the reserve, which would be reflected as a charge to Net Income.  Although a material increase to the reserve is not presently anticipated, management cannot reasonably estimate potential additional investigation or remediation costs because these costs would depend on, among other things, the nature, extent and timing of additional investigation and remediation that may be required by the MA DEP.    

CERCLA:  The federal Comprehensive Environmental Response, Compensation and Liability Act of 1980 (CERCLA) and its amendments or state equivalents impose joint and several strict liabilities, regardless of fault, upon generators of hazardous substances resulting in removal and remediation costs and environmental damages.  Liabilities under these laws can be material and in some instances may be imposed without regard to fault or for past acts that may have been lawful at the time they occurred.  Of the total sites included in the remediation and long-term monitoring phase, 10 sites (2 for CL&P, 4 for NSTAR Electric, 4 for PSNH and 1 for WMECO) are superfund sites under CERCLA for which the Company has been notified that it is a potentially responsible party but for which the site assessment and remediation are not being managed by the Company.  As of December 31, 2012, a liability of $1 million ($0.4 million for CL&P, $0.1 million for NSTAR Electric and $0.4 million for PSNH) accrued on these sites represents management's best estimate of its potential remediation costs with respect to these superfund sites.

Environmental Rate Recovery:  PSNH, NSTAR Gas and Yankee Gas have rate recovery mechanisms for environmental costs.  CL&P recovers a certain level of environmental costs currently in rates but does not have an environmental cost recovery tracking mechanism.  Accordingly, changes in CL&P's environmental reserves impact CL&P's Net Income.  WMECO does not have a separate regulatory mechanism to recover environmental costs from its customers, and changes in WMECO's environmental reserves impact WMECO's Net Income.  

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B.	Long-Term Contractual Arrangements
Estimated Future Annual Costs:  The estimated future annual costs of significant long-term contractual arrangements as of
December 31, 2012 are as follows:
NU
(Millions of Dollars)		2013		2014		2015		2016		2017		Thereafter		Total
Supply and Stranded Cost		$	270.3	$	228.5	$	209.6	$	182.1	$	143.5	$	576.7	$	1,610.7
Renewable Energy			95.2		184.3		185.5		160.2		161.6		1,800.4		2,587.2
Peaker CfDs			75.2		72.6		66.5		63.2		66.5		292.0		636.0
Natural Gas Procurement			138.6		125.5		80.3		69.9		39.0		154.7		608.0
Coal, Wood and Other			110.7		46.3		5.5		5.0		5.0		21.8		194.3
Transmission Support Commitments			27.7		26.7		25.4		21.5		17.3		51.9		170.5
Total		$	717.7	$	683.9	$	572.8	$	501.9	$	432.9	$	2,897.5	$	5,806.7
CL&P
(Millions of Dollars)		2013		2014		2015		2016		2017		Thereafter		Total
Supply and Stranded Cost		$	169.4	$	149.7	$	145.4	$	147.8	$	119.8	$	502.8	$	1,234.9
Renewable Energy			4.2		30.5		30.7		30.9		31.1		356.1		483.5
Peaker CfDs			75.2		72.6		66.5		63.2		66.5		292.0		636.0
Transmission Support Commitments			10.9		10.5		10.0		8.5		6.8		20.4		67.1
Yankee Billings			19.2		18.8		16.1		-		-		-		54.1
Total		$	278.9	$	282.1	$	268.7	$	250.4	$	224.2	$	1,171.3	$	2,475.6
NSTAR Electric
(Millions of Dollars)		2013		2014		2015		2016		2017		Thereafter		Total
Supply and Stranded Cost		$	32.0	$	36.4	$	36.3	$	16.0	$	5.6	$	42.6	$	168.9
Renewable Energy			85.6		84.8		84.9		48.9		48.9		251.8		604.9
Transmission Support Commitments			8.6		8.3		7.9		6.7		5.4		16.2		53.1
Yankee Billings			8.2		8.3		6.6		-		-		-		23.1
Total		$	134.4	$	137.8	$	135.7	$	71.6	$	59.9	$	310.6	$	850.0
PSNH
(Millions of Dollars)		2013		2014		2015		2016		2017		Thereafter		Total
Supply and Stranded Cost		$	68.9	$	42.4	$	27.9	$	18.3	$	18.1	$	31.3	$	206.9
Renewable Energy			5.0		59.8		60.6		70.9		71.9		1,081.9		1,350.1
Coal, Wood and Other			110.7		46.3		5.5		5.0		5.0		21.8		194.3
Transmission Support Commitments			5.9		5.7		5.4		4.5		3.7		11.0		36.2
Yankee Billings			3.6		3.3		2.3		-		-		-		9.2
Total		$	194.1	$	157.5	$	101.7	$	98.7	$	98.7	$	1,146.0	$	1,796.7
WMECO
(Millions of Dollars)		2013		2014		2015		2016		2017		Thereafter		Total
Renewable Energy		$	0.4	$	9.2	$	9.3	$	9.5	$	9.7	$	110.6	$	148.7
Transmission Support Commitments			2.3		2.2		2.1		1.8		1.4		4.3		14.1
Yankee Billings			5.3		5.2		4.4		-		-		-		14.9
Total		$	8.0	$	16.6	$	15.8	$	11.3	$	11.1	$	114.9	$	177.7

Supply and Stranded Cost:  CL&P, NSTAR Electric, PSNH and WMECO have various IPP contracts or purchase obligations for electricity, including payment obligations resulting from the buydown of electricity purchase contracts.  Such contracts extend through 2024 for CL&P, 2030 for NSTAR Electric and 2023 for PSNH.  

In addition, CL&P and UI have entered into four CfDs for a total of approximately 787 MW of capacity consisting of three generation projects and one demand response project.  The capacity CfDs extend through 2026 and obligate the utilities to pay the difference between a set price and the value that the projects receive in the ISO-NE markets.  The contracts have terms of up to 15 years beginning in 2009 and are subject to a sharing agreement with UI, whereby UI will share 20 percent of the costs and benefits of these contracts.  CL&P's portion of the costs and benefits of these contracts will be paid by or refunded to CL&P's customers.  The amounts of these payments are subject to changes in capacity and forward reserve prices that the projects receive in the ISO-NE capacity markets.  

The contractual obligations table does not include CL&P's SS or LRS, or NSTAR Electric’s or WMECO’s default service contracts, the amounts of which vary with customers' energy needs.  The contractual obligations table also does not include PSNH's short-term power supply management.  

Renewable Energy:  Renewable energy contracts include non-cancellable commitments under contracts of CL&P, NSTAR Electric, PSNH, and WMECO for the purchase of energy and capacity from renewable energy facilities.  Such contracts have terms extending for 15 years at CL&P, up to 40 years at NSTAR Electric, up to 30 years for PSNH and 15 years for WMECO.  

The table above does not include NSTAR Electric’s commitment to purchase 129MW of renewable energy from a wind facility to be

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constructed offshore and certain other CL&P and NSTAR Electric commitments for the purchase of renewable energy and related products that are contingent on the future construction of facilities.

Peaker CfDs:  In 2008, CL&P entered into three CfDs with developers of peaking generation units approved by the PURA (Peaker CfDs).  These units have a total of approximately 500 MW of peaking capacity.  As directed by the PURA, CL&P and UI have entered into a sharing agreement, whereby CL&P is responsible for 80 percent and UI for 20 percent of the net costs or benefits of these CfDs.  The Peaker CfDs pay the developer the difference between capacity, forward reserve and energy market revenues and a cost-of-service payment stream for 30 years.  The ultimate cost or benefit to CL&P under these contracts will depend on the costs of plant construction and operation and the prices that the projects receive for capacity and other products in the ISO-NE markets.  CL&P's portion of the amounts paid or received under the Peaker CfDs will be recoverable from or refunded to CL&P's customers.  

Natural Gas Procurement:  NU’s natural gas distribution businesses have long-term contracts for the purchase, transportation and storage of natural gas in the normal course of business as part of its portfolio of supplies.  These contracts extend through 2029.  

Coal, Wood and Other:  PSNH has entered into various arrangements for the purchase of wood, coal and the transportation services for fuel supply for its electric generating assets.  Also included in the table above is a contract for capacity on the Portland Natural Gas Transmission System (PNGTS) pipeline that extends through 2019.  The costs on this contract are not recoverable from customers.

Transmission Support Commitments:  Along with other New England utilities, CL&P, NSTAR Electric, PSNH and WMECO entered into agreements in 1985 to support transmission and terminal facilities that were built to import electricity from the Hydro-Québec system in Canada.  CL&P, NSTAR Electric, PSNH and WMECO are obligated to pay, over a 30-year period ending in 2020, their proportionate shares of the annual operation and maintenance expenses and capital costs of those facilities.  

The total costs incurred under these agreements in 2012, 2011, and 2010 were as follows:

NU	For the Years Ended December 31,
(Millions of Dollars)	2012		2011		2010
Supply and Stranded Cost	$	216.8	$	156.0	$	196.2
Renewable Energy		48.7		5.1		5.8
Peaker CfDs		59.3		40.2		10.0
Natural Gas Procurement		243.1		191.7		209.5
Coal, Wood and Other		105.2		113.2		171.1
Transmission Support Commitments		24.8		18.1		18.9

		For the Years Ended December 31,
		2012								2011								2010
				NSTAR								NSTAR								NSTAR
(Millions of Dollars)		CL&P		Electric(1)		PSNH		WMECO		CL&P		Electric(1)		PSNH		WMECO		CL&P		Electric(1)		PSNH		WMECO
Supply and
	Stranded Cost	$	158.2	$	36.3	$	30.5	$	0.9	$	114.9	$	80.9	$	40.8	$	0.3	$	151.3	$	146.3	$	42.6	$	2.3
Renewable Energy			-		60.2		4.1		-		-		61.8		5.1		-		-		52.7		5.8		-
Peaker CfDs			59.3		-		-		-		40.2		-		-		-		10.0		-		-		-
Coal, Wood and Other			-		-		105.2		-		-		-		113.2		-		-		-		171.1		-
Transmission Support
	Commitments		9.6		7.6		5.2		2.0		10.3		8.1		5.6		2.2		10.8		8.5		5.8		2.3

⁽¹⁾

NSTAR Electric amounts are included in NU consolidated from the date of the merger, April 10, 2012 through December 31, 2012.  NSTAR Electric amounts are not included in NU consolidated for the years ended December 31, 2011 and 2010.

C.

Deferred Contractual Obligations

CL&P, NSTAR Electric, PSNH and WMECO have decommissioning and plant closure cost obligations to the Yankee Companies, which have each completed the physical decommissioning of their respective nuclear facilities and are now engaged in the long-term storage of their spent fuel.  The Yankee Companies collect decommissioning and closure costs through wholesale, FERC-approved rates charged under power purchase agreements with several New England utilities, including CL&P, NSTAR Electric, PSNH and WMECO.  These companies in turn recover these costs from their customers through state regulatory commission-approved retail rates.  

CL&P, NSTAR Electric, PSNH and WMECO's percentage share of the obligations to support the Yankee Companies under FERC-approved rate tariffs is the same as their respective ownership percentages in the Yankee Companies.  For further information on the ownership percentages, see Note 1J, "Summary of Significant Accounting Policies - Equity Method Investments," to the consolidated financial statements.  

The Yankee Companies are currently collecting amounts that management believes are adequate to recover the remaining decommissioning and closure cost estimates for the respective plants.  Management believes CL&P, NSTAR Electric and WMECO will recover their shares of these decommissioning and closure obligations from their customers.  PSNH has already recovered its share of these costs from its customers.

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Spent Nuclear Fuel Litigation:  

DOE Phase I Damages - In 1998, CYAPC, YAEC and MYAPC (Yankee Companies) filed separate complaints against the DOE in the Court of Federal Claims seeking monetary damages resulting from the DOE's failure to begin accepting spent nuclear fuel for disposal by January 31, 1998 pursuant to the terms of the 1983 spent fuel and high level waste disposal contracts between the Yankee Companies and the DOE (DOE Phase I Damages).  In a ruling released on October 4, 2006, the Court of Federal Claims held that the DOE was liable for damages to CYAPC for $34.2 million through 2001, YAEC for $32.9 million through 2001 and MYAPC for $75.8 million through 2002.  

In December 2006, the DOE appealed the ruling, and the Yankee Companies filed cross-appeals.  The Court of Appeals issued its decision on August 7, 2008, effectively agreeing with the trial court's findings as to the liability of the DOE but disagreeing with the method that the trial court used to calculate damages.  The Court of Appeals vacated the decision and remanded the case for new findings consistent with its decision.  

On September 7, 2010, the trial court issued its decision following remand, and judgment on the decision was entered on September 9, 2010.  The judgment awarded CYAPC $39.7 million, YAEC $21.2 million and MYAPC $81.7 million.  The DOE filed an appeal and the Yankee Companies cross-appealed on November 8, 2010.  Briefs were filed and oral arguments in the appeal of the remanded case occurred on November 7, 2011.  On May 18, 2012, the U.S. Court of Appeals for the Federal Circuit issued a unanimous panel decision in favor of the Yankee Companies upholding the trial court's awards to each company in the remanded cases, and increasing YAEC damages by approximately $17 million to cover certain wet pool operating expenses.  On August 1, 2012, the DOE filed a petition asking the U.S. Court of Appeals for the Federal Circuit to reconsider its unanimous panel decision in favor of the Yankee Companies upholding the trial court's awards to each company in the remanded cases.  On September 5, 2012, the U.S. Court of Appeals for the Federal Circuit denied the DOE’s petition.  The decisions became final and non-appealable and interest on the judgments began to accrue on or about December 5, 2012, as the DOE elected not to file a petition for certiorari with the U.S. Supreme Court.

As a result of the April 10, 2012 merger with NSTAR and NU's consolidation of CYAPC and YAEC, the consolidated financial statements reflect an aggregate receivable from the DOE for CYAPC and YAEC's Phase I damages awards of $77.9 million as of December 31, 2012.

In January 2013, the proceeds from the DOE Phase I Damages Claim were received by CYAPC in the amount of $39.6 million, YAEC in the amount of $38.3 million, and MYAPC in the amount of $81.7 million.  The funds were transferred to each Yankee Company’s respective decommissioning trust.  The final application of the proceeds for the benefit of customers of CL&P, NSTAR Electric, PSNH and WMECO will be determined following rate proceedings to be filed by each Yankee Company at FERC in the second quarter of 2013.  Final FERC determinations are expected by the end of the third quarter of 2013.

DOE Phase II Damages - In December 2007, the Yankee Companies each filed subsequent lawsuits against the DOE seeking recovery of actual damages incurred in the years following 2001 and 2002 related to the alleged failure of the DOE to provide for a permanent facility to store spent nuclear fuel generated in years after 2001 for CYAPC and YAEC and after 2002 for MYAPC (DOE Phase II Damages).  On November 18, 2011, the court ordered the record closed in the YAEC case, and closed the record in the CYAPC and MYAPC cases subject to a limited opportunity of the government to reopen the records for further limited proceedings.  The record is now closed, all post-trial briefing has been completed, and the case is awaiting the court decision.

The methodology for applying any DOE Phase II Damages that may be recovered from the DOE for the benefit of customers of CL&P, NSTAR Electric, PSNH and WMECO will be addressed in the same FERC rate proceedings.

D.

Guarantees and Indemnifications

NU parent, or NSTAR LLC, as applicable, provides credit assurances on behalf of its subsidiaries, including CL&P, NSTAR Electric, PSNH and WMECO, in the form of guarantees in the normal course of business.  

NU provided guarantees and various indemnifications on behalf of external parties as a result of the sales of former subsidiaries of NU Enterprises, with maximum exposures either not specified or not material.  

NU also issued a guaranty for the benefit of Hydro Renewable Energy under which, beginning at the time the Northern Pass Transmission line goes into commercial operation, NU will guarantee the financial obligations of NPT under the TSA in an amount not to exceed $25 million.  NU's obligations under the guaranty expire upon the full, final and indefeasible payment of the guaranteed obligations.  

Management does not anticipate a material impact to Net Income as a result of these various guarantees and indemnifications.  

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The following table summarizes NU's guarantees of its subsidiaries, including CL&P, NSTAR Electric, PSNH and WMECO, as of December 31, 2012:  

		Maximum
		Exposure
Subsidiary	Description	(in millions)			Expiration Dates
Various	Surety Bonds	$	32.8		January 2013 - November 2015 (1)
Various	NE Hydro Companies' Long-Term Debt	$	5.6		Unspecified
NUSCO and RRR	Lease Payments for Vehicles and Real Estate	$	20.1		2019 and 2024
NU Enterprises	Surety Bonds, Insurance Bonds and Performance Guarantees	$	67.4	(2)	(2)

⁽¹⁾

Surety bond expiration dates reflect bond termination dates, the majority of which will be renewed or extended.  

⁽²⁾

The maximum exposure includes $13.5 million related to performance guarantees on wholesale purchase contracts, which expire December 31, 2013.  Also included in the maximum exposure is $1 million related to insurance bonds with no expiration date that are billed annually on their anniversary date.  The remaining $52.9 million of maximum exposure relates to surety bonds covering ongoing projects, which expire upon project completion.

Many of the underlying contracts that NU parent guarantees, as well as certain surety bonds, contain credit ratings triggers that would require NU parent to post collateral in the event that the unsecured debt credit ratings of NU, or NSTAR LLC, as applicable, are downgraded below investment grade.  

E.

DPU Penalties for 2011 Storm Responses (NSTAR Electric, WMECO)

On December 11, 2012, in separate orders issued by the DPU, NSTAR Electric and WMECO received penalties related to the investigation into the electric utilities’ responses to Tropical Storm Irene and the October 2011 snowstorm.  The DPU ordered penalties of $4.1 million and $2 million for NSTAR Electric and WMECO, respectively, stating that NSTAR Electric failed to communicate and prioritize restoration efforts in both storms and WMECO failed to prioritize restoration efforts in the October snowstorm.  These penalties were ordered to be assessed in the form of customer credits in 2013.  On December 28, 2012, NSTAR Electric and WMECO each filed appeals with the SJC arguing the DPU penalties should be vacated.  In their filings, NSTAR Electric and WMECO stated that the DPU’s decision to assess the penalties was in error as the assessments were arbitrary and not supported by substantial evidence. While we believe that NSTAR Electric and WMECO should ultimately prevail upon appeal, we are unable to conclusively state that a favorable outcome is probable.  Therefore, NSTAR Electric and WMECO recorded $4.1 million and $2 million, respectively, in pre-tax penalty charges as of December 31, 2012.

F.

FERC Base ROE Complaint

On September 30, 2011, several New England state attorneys general, state regulatory commissions, consumer advocates and other parties filed a joint complaint with the FERC under Sections 206 and 306 of the Federal Power Act alleging that the base ROE used in calculating formula rates for transmission service under the ISO-NE Open Access Transmission Tariff by New England transmission owners, including CL&P, NSTAR Electric, PSNH and WMECO, is unjust and unreasonable.  The complainants asserted that the current 11.14 percent rate, which became effective in 2006, is excessive due to changes in the capital markets and are seeking an order to reduce the rate, which would be effective September 30, 2011 through December 31, 2012.  In response, the New England transmission owners filed testimony and analysis based on standard FERC methodology and precedent, demonstrating that the base ROE of 11.14 percent remained just and reasonable.

On May 3, 2012, the FERC issued an order establishing hearing and settlement procedures for the complaint.  The settlement proceedings were subsequently terminated, as the parties had reached an impasse in their efforts to reach a settlement.  In August 2012, the FERC trial judge assigned to the complaint established a schedule for the trial phase of the proceedings.  Complainant testimony supporting a base ROE of 9 percent was filed on October 1, 2012.  Additional testimony was filed on October 1, 2012 by a group of Massachusetts municipal electric companies, which recommended a base ROE of 8.2 percent.  The New England transmission owners filed testimony and analysis on November 20, 2012, demonstrating they believe that the current base ROE continues to be just and reasonable.  On January 18, 2013, the FERC trial staff filed testimony and analysis recommending a base ROE of 9.66 percent based on the midpoint of their analysis with a range of reasonableness of 6.82 percent to 12.51 percent.  Hearings on this complaint are scheduled for May 2013 and a trial judge’s recommended decision is due in September 2013. A decision from FERC commissioners is expected in 2014.  Refunds to customers, if any, as a result of a reduction in the NU transmission companies’ base ROE would be retroactive to October 1, 2011.

On December 27, 2012, several additional parties filed a separate complaint concerning the New England transmission owners' ROE with the FERC.  This new complaint seeks to reduce the New England transmission owner’s base transmission ROE effective January 1, 2013, and to consolidate this new complaint with the joint complaint filed on September 30, 2011.  The New England transmission owners have asked the FERC to reject this new complaint.  The FERC has not yet acted on this request.

164

Management cannot at this time predict the ultimate outcome of this proceeding or the estimated impacts on CL&P’s, NSTAR Electric’s, PSNH’s, or WMECO’s respective financial position, results of operations or cash flows.

G.

DPU Safety and Reliability Programs - CPSL (NSTAR Electric)

Since 2006, NSTAR Electric has been recovering incremental costs related to the Double Pole Inspection, Replacement/Restoration and Transfer Program and the Underground Electric Safety Program, which included stray-voltage remediation, manhole inspections, repairs, and upgrades, in accordance with this DPU approved program.  Recovery of these CPSL costs is subject to review and approval by the DPU through a rate-reconciling mechanism.  From 2006 through December 31, 2011, cumulative costs associated with the CPSL program resulted in an incremental revenue requirement to customers of approximately $83 million.  These amounts included incremental operations and maintenance costs and the related revenue requirement for specific capital investments relative to the CPSL programs.

On May 28, 2010, the DPU issued an order on NSTAR Electric’s 2006 CPSL cost recovery filing (the May 2010 Order).  The May 2010 Order was the basis NSTAR Electric used for recognizing revenue for the CPSL programs.  On October 8, 2010, NSTAR Electric submitted a Compliance Filing with the DPU reconciling the cumulative CPSL program activity for the periods 2006 through 2009 in order to determine a proposed rate adjustment effective on January 1, 2011.  The DPU allowed the proposed rates for the CPSL programs to go into effect on that date, subject to final reconciliation of CPSL program costs through a future DPU proceeding.  NSTAR Electric updated the October 2010 filing with final activity through 2011 in February 2013.  

NSTAR Electric cannot predict the timing of any subsequent DPU order related to its CPSL filings for the period 2006 through 2011.  Therefore, NSTAR Electric continued to record its 2006 through 2011 revenues under the CPSL programs based on the May 2010 Order.  While we do not believe that any subsequent DPU order would result in revenue recognition that is materially different than the amounts already recognized, it is reasonably possible that an order could have a material impact on NSTAR Electric’s results of operations, financial position and cash flows.

The April 4, 2012 DPU-approved comprehensive settlement agreement with the Massachusetts Attorney General concerning the merger stipulates that NSTAR Electric must incur a revenue requirement of at least $15 million per year for 2012 through 2015 in order to continue these programs.  CPSL revenues will end once NSTAR Electric has recovered its 2015-related CPSL costs.  Realization of these revenues is subject to maintaining certain performance metrics over the four-year period and DPU approval.  As of December 31, 2012, NSTAR Electric was in compliance with the performance metrics and has recognized the entire $15 million revenue requirement during 2012, which we believe is probable of approval from the DPU.

H.

Basic Service Bad Debt Adder (NSTAR Electric)

In accordance with a generic DPU order, electric utilities in Massachusetts recover the energy-related portion of bad debt costs in their Basic Service rates.  On February 7, 2007, NSTAR Electric filed its 2006 Basic Service reconciliation with the DPU proposing an adjustment related to the increase of its Basic Service bad debt charge-offs.  On June 28, 2007, the DPU issued an order approving the implementation of a revised Basic Service rate.  However, the DPU instructed NSTAR Electric to reduce distribution rates by an amount equal to the increase in its Basic Service bad debt charge-offs.  This adjustment to NSTAR Electric’s distribution rates would eliminate the fully reconciling nature of the Basic Service bad debt adder.

NSTAR Electric deferred the unrecovered costs associated with energy-related bad debt as a regulatory asset, which totaled approximately $34 million as of December 31, 2011, as NSTAR Electric had concluded that these costs were probable of recovery in future rates.  On June 18, 2010, NSTAR Electric filed an appeal of the DPU’s order with the SJC, which was heard by the SJC in December 2011.  On April 11, 2012, the SJC issued a procedural order waiving its standing 130-day rule for issuance of an order on the matter.  Due to the delay, NSTAR Electric concluded that while an ultimate outcome on the matter in its favor remained "more likely than not," it could no longer be deemed "probable."  As a result, NSTAR Electric recognized a reserve of $28 million ($17 million after-tax) as a charge to Operations and Maintenance in the first quarter of 2012 to reserve the related regulatory asset on its balance sheet.

On June 4, 2012, the SJC vacated the DPU's June 28, 2007 order and remanded the matter to the DPU for a "statement of reasons, including subsidiary findings, of its conclusion of law and relevant facts."  The continued uncertainty of the outcome of the DPU’s proceeding leaves NU and NSTAR Electric unable to conclude that it is probable that the previously reserved amount will ultimately be recovered and therefore NSTAR Electric will continue to maintain a reserve on this amount until the ultimate outcome is determined by the DPU.

165

I.

Litigation and Legal Proceedings

NU, including CL&P, NSTAR Electric, PSNH and WMECO, are involved in legal, tax and regulatory proceedings regarding matters arising in the ordinary course of business, which involve management's assessment to determine the probability of whether a loss will occur and, if probable, its best estimate of probable loss.  The Company records and discloses losses when these losses are probable and reasonably estimable, discloses matters when losses are probable but not estimable or reasonably possible, and expenses legal costs related to the defense of loss contingencies as incurred.

13.

LEASES

NU, including CL&P, NSTAR Electric, PSNH and WMECO, has entered into lease agreements, some of which are capital leases, for the use of data processing and office equipment, vehicles and office space.  In addition, CL&P, PSNH and WMECO incur costs associated with leases entered into by NUSCO and RRR, which are included below in their respective operating lease rental expenses and future minimum rental payments.  These intercompany lease amounts are eliminated on an NU consolidated basis.  The provisions of the NU, CL&P, NSTAR Electric, PSNH, and WMECO lease agreements generally contain renewal options.  Certain lease agreements contain payments impacted by the commercial paper rate plus a credit spread or the consumer price index.

Operating lease rental payments charged to expense were as follows:

					NSTAR
(Millions of Dollars)	NU		CL&P		Electric (1)		PSNH		WMECO
2012	$	14.8	$	8.2	$	6.2	$	2.5	$	3.0
2011		8.4		8.3		19.8		2.1		2.8
2010		11.9		10.0		19.2		2.2		2.8

⁽¹⁾

NSTAR Electric amounts are included in NU consolidated from the date of the merger, April 10, 2012, through December 31, 2012.  NSTAR Electric amounts are not included in NU consolidated for the years ended December 31, 2011 and 2010.

Future minimum rental payments to external third parties excluding executory costs, such as property taxes, state use taxes, insurance, and maintenance, under long-term noncancelable leases, as of December 31, 2012 are as follows:

Capital Leases
(Millions of Dollars)	NU		CL&P		PSNH
2013	$	2.8	$	2.2	$	0.5
2014		2.2		2.0		0.2
2015		2.2		2.0		0.2
2016		2.0		1.9		0.1
2017		2.0		2.0		-
Thereafter		7.5		7.3		-
Future minimum lease payments		18.7		17.4		1.0
Less amount representing interest		7.6		7.4		0.1
Present value of future minimum lease payments	$	11.1	$	10.0	$	0.9

Operating Leases
(Millions of Dollars)	NU		CL&P		NSTAR Electric		PSNH		WMECO
2013	$	22.4	$	4.3	$	10.9	$	1.3	$	2.7
2014		16.6		3.7		8.2		1.0		1.1
2015		14.1		3.1		7.4		0.8		0.6
2016		11.2		2.3		6.1		0.6		0.3
2017		8.6		1.2		5.1		0.5		0.2
Thereafter		23.3		6.4		10.3		1.8		1.2
Future minimum lease payments	$	96.2	$	21.0	$	48.0	$	6.0	$	6.1

CL&P entered into certain contracts for the purchase of energy that qualify as leases.  These contracts do not have minimum lease payments and therefore are not included in the tables above.  However, such contracts have been included in the contractual obligations table in Note 12B, "Commitments and Contingencies - Long-Term Contractual Arrangements," to the consolidated financial statements.  

166

14.

FAIR VALUE OF FINANCIAL INSTRUMENTS

The following methods and assumptions were used to estimate the fair value of each of the following financial instruments:

Preferred Stock, Long-Term Debt and Rate Reduction Bonds:  The fair value of CL&P's and NSTAR Electric’s preferred stock is based upon pricing models that incorporate interest rates and other market factors, valuations or trades of similar securities and cash flow projections.  The fair value of fixed-rate long-term debt securities and RRBs is based upon pricing models that incorporate quoted market prices for those issues or similar issues adjusted for market conditions, credit ratings of the respective companies and treasury benchmark yields.  Adjustable rate securities are assumed to have a fair value equal to their carrying value.  The fair values provided in the tables below are classified as Level 2 within the fair value hierarchy.  Carrying amounts and estimated fair values are as follows:

		As of December 31,
		2012				2011
NU		Carrying		Fair		Carrying		Fair
(Millions of Dollars)		Amount		Value		Amount		Value
Preferred Stock Not
	Subject to Mandatory Redemption	$	155.6	$	152.2	$	116.2	$	105.1
Long-Term Debt			7,963.5		8,640.7		4,950.7		5,517.0
Rate Reduction Bonds			82.1		83.0		112.3		116.8

		As of December 31, 2012
		CL&P				NSTAR Electric				PSNH				WMECO
		Carrying		Fair		Carrying		Fair		Carrying		Fair		Carrying		Fair
(Millions of Dollars)		Amount		Value		Amount		Value		Amount		Value		Amount		Value
Preferred Stock Not
	Subject to Mandatory Redemption	$	116.2	$	110.0	$	43.0	$	42.2	$	-	$	-	$	-	$	-
Long-Term Debt			2,862.8		3,295.4		1,602.6		1,818.8		997.9		1,088.0		605.3		660.4
Rate Reduction Bonds			-		-		43.5		43.9		29.3		29.6		9.4		9.5
		As of December 31, 2011
		CL&P				NSTAR Electric (1)				PSNH				WMECO
		Carrying		Fair		Carrying		Fair		Carrying		Fair		Carrying		Fair
(Millions of Dollars)		Amount		Value		Amount		Value		Amount		Value		Amount		Value
Preferred Stock Not
	Subject to Mandatory Redemption	$	116.2	$	105.1	$	43.0	$	41.2	$	-	$	-	$	-	$	-
Long-Term Debt			2,587.8		2,987.1		1,605.1		1,816.1		999.5		1,075.2		501.1		539.8
Rate Reduction Bonds			-		-		127.9		131.2		85.4		88.8		26.9		28.1

⁽¹⁾

NSTAR Electric amounts are not included in NU consolidated as of December 31, 2011.

Derivative Instruments:  NU, including CL&P, NSTAR Electric and WMECO, holds various derivative instruments that are carried at fair value.  For further information, see Note 5, "Derivative Instruments," to the consolidated financial statements.  

Other Financial Instruments:  Investments in marketable securities are carried at fair value on the accompanying consolidated balance sheets.  For further information, see Note 1H, "Summary of Significant Accounting Policies - Fair Value Measurements," and Note 6, "Marketable Securities," to the consolidated financial statements.

The carrying value of other financial instruments included in current assets and current liabilities, including cash and cash equivalents and special deposits, approximates their fair value due to the short-term nature of these instruments.

15.

ACCUMULATED OTHER COMPREHENSIVE INCOME/(LOSS)

The accumulated balance for each component of other comprehensive income/(loss), net of tax, is as follows:

(Millions of Dollars)	As of December 31,
NU	2012		2011
Qualified Cash Flow Hedging Instruments	$	(16.4)	$	(18.4)
Unrealized Gains on Other Securities		1.3		1.1
Pension, SERP and PBOP Benefits		(57.8)		(53.4)
Accumulated Other Comprehensive Loss	$	(72.9)	$	(70.7)
CL&P
Qualified Cash Flow Hedging Instruments	$	(1.8)	$	(2.3)
PSNH
Qualified Cash Flow Hedging Instruments	$	(9.7)	$	(10.9)
WMECO
Qualified Cash Flow Hedging Instruments	$	(3.8)	$	(4.2)

167

Qualified cash flow hedging items impacting Net Income in the tables above represent amounts that were reclassified from Accumulated Other Comprehensive Income/(Loss) into Net Income for interest rate swap agreements.  For the year ended December 31, 2012, qualified cash flow hedging activity relates to the amortization of previously settled interest rate swap agreements.  For the year ended December 31, 2011, activity related to qualified cash flow hedging activity was as follows:

		For the Year Ended December 31, 2011
(Millions of Dollars)		NU			PSNH		WMECO
Balance as of January 1, 2011		$	(4.2)	$	(0.6)	$	(0.1)
	Hedged Transactions Recognized into Earnings		0.7		0.5		0.1
	Cash Flow Hedging Transactions Entered into for the Year		(14.9)		(10.8)		(4.2)
Net Change Associated with Hedging Transactions			(14.2)		(10.3)		(4.1)
Balance as of December 31, 2011		$	(18.4)	$	(10.9)	$	(4.2)
For further information regarding cash flow hedging transactions, see Note 5, "Derivative Instruments," to the consolidated financial statements.

The changes in the components of other comprehensive income/(loss) are reported net of the following income tax effects:
(Millions of Dollars)
NU	2012		2011		2010
Qualified Cash Flow Hedging Instruments	$	1.3	$	(9.5)	$	0.2
Change in Unrealized Gains on Other Securities		0.1		0.4		0.2
Pension, SERP and PBOP Benefits		(2.7)		(7.9)		-
Total	$	(1.3)	$	(17.0)	$	0.4
CL&P
Qualified Cash Flow Hedging Instruments	$	0.3	$	0.3	$	0.3
PSNH
Qualified Cash Flow Hedging Instruments	$	0.8	$	(7.0)	$	0.1
WMECO
Qualified Cash Flow Hedging Instruments	$	0.2	$	(2.7)	$	-

It is estimated that a charge of $2 million will be reclassified from Accumulated Other Comprehensive Income/(Loss) as a decrease to earnings over the next 12 months as a result of amortization of the interest rate swap agreements, which have been settled.  Included in this amount are estimated charges of $0.4 million, $1.2 million and $0.3 million for CL&P, PSNH and WMECO, respectively.  As of December 31, 2012, it is estimated that a pre-tax amount of $10.5 million included in the Accumulated Other Comprehensive Income/(Loss) balance will be reclassified as a decrease to Net Income over the next 12 months related to Pension, SERP and PBOP adjustments for NU.

16.

DIVIDEND RESTRICTIONS

NU parent's ability to pay dividends may be affected by certain state statutes, the ability of its subsidiaries to pay common dividends and the leverage restriction tied to its consolidated total debt to total capitalization ratio requirement in its revolving credit agreement.  

CL&P, NSTAR Electric, PSNH and WMECO are subject to Section 305 of the Federal Power Act that makes it unlawful for a public utility to make or pay a dividend from any funds "properly included in its capital account."  Management believes that this Federal Power Act restriction, as applied to CL&P, NSTAR Electric, PSNH and WMECO, would not be construed or applied by the FERC to prohibit the payment of dividends for lawful and legitimate business purposes from retained earnings.  In addition, certain state statutes may impose additional limitations on such companies and on Yankee Gas and NSTAR Gas.  Such state law restrictions do not restrict payment of dividends from retained earnings or net income.  CL&P, NSTAR Electric, PSNH, WMECO, Yankee Gas and NSTAR Gas also have revolving credit agreements that impose leverage restrictions including consolidated total debt to total capitalization ratio requirements.  The Retained Earnings balances subject to these leverage restrictions are $1.803 billion for NU, $839.6 million for CL&P, $1.210 billion for NSTAR Electric, $395.1 million for PSNH and $160.6 million for WMECO as of December 31, 2012.  PSNH is further required to reserve an additional amount under its FERC hydroelectric license conditions. As of December 31, 2012, approximately $12.3 million of PSNH's Retained Earnings is subject to restriction under its FERC hydroelectric license conditions.  As of December 31, 2012, NU, CL&P, NSTAR Electric, PSNH, WMECO, Yankee Gas and NSTAR Gas were in compliance with all such provisions of its credit agreements that may restrict the payment of dividends.  

168

17.

COMMON SHARES

The following table sets forth the NU common shares and the shares of CL&P, NSTAR Electric, PSNH and WMECO common stock authorized and issued as of December 31, 2012 and 2011 and the respective par values:  

	Shares
	Authorized					Issued
	Per Share		As of December 31,			As of December 31,
	Par Value		2012	2011		2012		2011
NU	$	5	380,000,000		380,000,000		332,509,383		196,052,770
CL&P	$	10	24,500,000		24,500,000		6,035,205		6,035,205
NSTAR Electric	$	1	100,000,000		100,000,000		100		100
PSNH	$	1	100,000,000		100,000,000		301		301
WMECO	$	25	1,072,471		1,072,471		434,653		434,653

As a result of the merger with NSTAR on April 10, 2012, NU issued approximately 136 million common shares to the NSTAR shareholders.

As of December 31, 2012 and 2011, 18,455,749 and 18,894,078 NU common shares were held as treasury shares, respectively.

18.

PREFERRED STOCK NOT SUBJECT TO MANDATORY REDEMPTION (CL&P, NSTAR Electric)

The preferred stock of CL&P and NSTAR Electric is not subject to mandatory redemption and is presented as a noncontrolling interest of a subsidiary in the accompanying consolidated financial statements of NU.

CL&P Preferred Stock:  CL&P's charter authorizes it to issue up to 9 million shares of preferred stock ($50 par value per share).  CL&P amended its charter on January 3, 2012 to remove references to various series of preferred stock, including the Class A preferred stock, which are no longer outstanding.  The issuance of additional preferred shares would be subject to approval by the PURA.  Preferred stockholders have liquidation rights equal to the par value of the preferred stock, which they would receive in preference to any distributions to any junior stock.  Were there to be a shortfall, all preferred stockholders would share ratably in available liquidation assets.  

NSTAR Electric Preferred Stock:  NSTAR Electric is authorized to issue 2,890,000 shares ($100 par value per share).  NSTAR Electric has two outstanding series of cumulative preferred stock.  Upon liquidation, holders of cumulative preferred stock are entitled to receive a liquidation preference before any distribution to holders of common stock.  The liquidation preference for each outstanding series of cumulative preferred stock is equal to the par value, plus accrued and unpaid dividends.  Were there to be a shortfall, holders of cumulative preferred stock would share ratably in available liquidation assets.

Details of preferred stock not subject to mandatory redemption are as follows (in millions except in redemption price and shares):

				Redemption Price		Shares Outstanding as of	As of December 31,
Series				Per Share		December 31, 2012 and 2011	2012		2011 (1)
CL&P
$	1.90		Series of 1947	$	52.50	163,912	$	8.2	$	8.2
$	2.00		Series of 1947	$	54.00	336,088		16.8		16.8
$	2.04		Series of 1949	$	52.00	100,000		5.0		5.0
$	2.20		Series of 1949	$	52.50	200,000		10.0		10.0
	3.90	%	Series of 1949	$	50.50	160,000		8.0		8.0
$	2.06		Series E of 1954	$	51.00	200,000		10.0		10.0
$	2.09		Series F of 1955	$	51.00	100,000		5.0		5.0
	4.50	%	Series of 1956	$	50.75	104,000		5.2		5.2
	4.96	%	Series of 1958	$	50.50	100,000		5.0		5.0
	4.50	%	Series of 1963	$	50.50	160,000		8.0		8.0
	5.28	%	Series of 1967	$	51.43	200,000		10.0		10.0
$	3.24		Series G of 1968	$	51.84	300,000		15.0		15.0
	6.56	%	Series of 1968	$	51.44	200,000		10.0		10.0
Total CL&P						2,324,000	$	116.2	$	116.2
NSTAR Electric(1)
	4.25	%	Series	$	103.625	180,000	$	18.0	$	18.0
	4.78	%	Series	$	102.80	250,000		25.0		25.0
Total NSTAR Electric						430,000	$	43.0	$	43.0
Fair Value Adjustment due to Merger with NSTAR								(3.6)		N/A
Total NU Consolidated Preferred Stock of Subsidiaries								155.6		116.2

⁽¹⁾

NSTAR Electric amounts are not included in NU consolidated as of December 31, 2011.

169

19.	COMMON SHAREHOLDERS' EQUITY AND NONCONTROLLING INTERESTS (NU)
A summary of the changes in Common Shareholders' Equity and Noncontrolling Interests of NU is as follows:
								Noncontrolling
		Common						Interest -
		Shareholders'		Noncontrolling		Total		Preferred Stock
(Millions of Dollars)		Equity		Interest		Equity		of Subsidiaries
Balance as of January 1, 2010		$	3,577.9	$	-	$	3,577.9	$	116.2
Net Income			394.1		-		394.1		-
Dividends on Common Shares			(181.7)		-		(181.7)		-
Dividends on Preferred Stock			(6.1)		-		(6.1)		(6.1)
Issuance of Common Shares			7.4		-		7.4		-
Contributions to NPT			-		1.4		1.4		-
Other Transactions, Net			19.6		-		19.6		-
Net Income Attributable to Noncontrolling Interests			(0.1)		0.1		-		6.1
Other Comprehensive Income (Note 15)			0.1		-		0.1		-
Balance as of December 31, 2010		$	3,811.2	$	1.5	$	3,812.7	$	116.2
Net Income			400.5		-		400.5		-
Dividends on Common Shares			(195.6)		-		(195.6)		-
Dividends on Preferred Stock			(5.6)		-		(5.6)		(5.6)
Issuance of Common Shares			5.9		-		5.9		-
Contributions to NPT			-		1.2		1.2		-
Other Transactions, Net			23.9		-		23.9		-
Net Income Attributable to Noncontrolling Interests			(0.3)		0.3		-		5.6
Other Comprehensive Loss (Note 15)			(27.3)		-		(27.3)		-
Balance as of December 31, 2011		$	4,012.7	$	3.0	$	4,015.7	$	116.2
Net Income			533.1		-		533.1		-
Purchase Price of NSTAR (1)			5,038.3		-		5,038.3		-
Other Equity Impacts of Merger with NSTAR (2)			3.4		(3.4)		-		39.4
Dividends on Common Shares			(375.5)		-		(375.5)		-
Dividends on Preferred Stock			(7.0)		-		(7.0)		(7.0)
Issuance of Common Shares			13.3		-		13.3		-
Contributions to NPT			-		0.3		0.3		-
Other Transactions, Net			21.1		-		21.1		-
Net Income Attributable to Noncontrolling Interests			(0.1)		0.1		-		7.0
Other Comprehensive Loss (Note 15)			(2.2)		-		(2.2)		-
Balance as of December 31, 2012		$	9,237.1	$	-	$	9,237.1	$	155.6

⁽¹⁾

On April 10, 2012, in connection with the consummation of the merger with NSTAR, NU issued approximately 136 million common shares to the NSTAR shareholders.  See Note 2, "Merger of NU and NSTAR," for further information.

⁽²⁾

The preferred stock of NSTAR Electric is not subject to mandatory redemption and has been presented as a noncontrolling interest in NSTAR Electric in the accompanying consolidated financial statements of NU.  In addition, upon completion of the merger, an NSTAR subsidiary that held 25 percent of NPT was merged into NUTV, resulting in NUTV owning 100 percent of NPT.  Accordingly, the noncontrolling interest balance was eliminated and 100 percent ownership of NPT is reflected in Common Shareholders' Equity as of December 31, 2012.  

For the years ended December 31, 2012, 2011 and 2010, there was no change in ownership of the common equity of CL&P and NSTAR Electric.  

20.

EARNINGS PER SHARE (NU)

Basic EPS is computed based upon the weighted average number of common shares outstanding during each period.  Diluted EPS is computed on the basis of the weighted average number of common shares outstanding plus the potential dilutive effect if certain securities are converted into common shares.  For the years ended December 31, 2012, 2011 and 2010, there were 4,266, 4,314 and 1,578 share awards, respectively, excluded from the computation as these awards were antidilutive.  

170

The following table sets forth the components of basic and diluted EPS:

		For the Years Ended December 31,
(Millions of Dollars, except share information)		2012		2011		2010
Net Income Attributable to Controlling Interest		$	525.9	$	394.7	$	387.9
Weighted Average Common Shares Outstanding:
	Basic		277,209,819		177,410,167		176,636,086
	Dilutive Effect		783,812		394,401		249,301
	Diluted		277,993,631		177,804,568		176,885,387
Basic EPS		$	1.90	$	2.22	$	2.20
Diluted EPS		$	1.89	$	2.22	$	2.19

On April 10, 2012, NU issued approximately 136 million common shares as a result of the merger with NSTAR, which are reflected in weighted average common shares outstanding as of December 31, 2012.

RSUs and performance shares are included in basic weighted average common shares outstanding as of the date that all necessary vesting conditions have been satisfied.  The dilutive effect of unvested RSUs and performance shares is calculated using the treasury stock method.  Assumed proceeds of these units under the treasury stock method consist of the remaining compensation cost to be recognized and a theoretical tax benefit.  The theoretical tax benefit is calculated as the tax impact of the intrinsic value of the units (the difference between the market value of the average units outstanding for the period, using the average market price during the period, and the grant date market value).  

The dilutive effect of stock options to purchase common shares is also calculated using the treasury stock method.  Assumed proceeds for stock options consist of cash proceeds that would be received upon exercise, and a theoretical tax benefit.  The theoretical tax benefit is calculated as the tax impact of the intrinsic value of the stock options (the difference between the market value of the average stock options outstanding for the period, using the average market price during the period, and the exercise price).  

21.

SEGMENT INFORMATION (NU)

Presentation:  NU is organized between the Electric Distribution, Electric Transmission and Natural Gas Distribution segments and Other based on a combination of factors, including the characteristics of each segments' products and services, the sources of operating revenues and expenses and the regulatory environment in which each segment operates.  These segments represented substantially all of NU's total consolidated revenues for the years ended December 31, 2012, 2011 and 2010.  Revenues from the sale of electricity and natural gas primarily are derived from residential, commercial and industrial customers and are not dependent on any single customer.  The Electric Distribution segment includes the generation activities of PSNH and WMECO.  

Other operations in the tables below primarily consists of 1) the equity in earnings of NU parent from its subsidiaries and intercompany interest income, both of which are eliminated in consolidation, and interest income and expense related to the cash and debt of NU parent and NSTAR LLC, respectively, 2) the revenues and expenses of NU's service companies, most of which are eliminated in consolidation, 3) the operations of CYAPC and YAEC, and 4) the results of other subsidiaries, which are comprised of NU Enterprises, NSTAR Communications, Inc., RRR (a real estate subsidiary), the non-energy-related subsidiaries of Yankee and the remaining operations of HWP.

Cash flows used for investments in plant included in the segment information below are cash capital expenditures that do not include amounts incurred but not paid, cost of removal, AFUDC related to equity funds, and the capitalized portions of pension and PBOP expense or income.   

As discussed in Note 1B, "Summary of Significant Accounting Policies – Basis of Presentation," certain reclassifications of prior year data were made in the accompanying consolidated statements of income for NU.  Accordingly, the corresponding items of segment information have been recast for all prior years for comparative purposes.

Effective in the third quarter of 2012, NU’s reportable segments are the combined Electric Distribution, Electric Transmission and Natural Gas Distribution segments, based upon the level at which NU’s chief operating decision maker assesses performance and makes decisions about the allocation of company resources.  Each of NU’s subsidiaries, including CL&P, NSTAR Electric, PSNH and WMECO, has one reportable segment.  Therefore, separate Transmission and Distribution information is not disclosed for CL&P, NSTAR Electric, PSNH or WMECO. NU’s operating segments and reporting units are consistent with its reportable business segments.

NSTAR amounts are included in NU consolidated from the date of the merger, April 10, 2012, through December 31, 2012.  

171

NU's segment information for the years ended December 31, 2012, 2011 and 2010 is as follows:

		For the Year Ended December 31, 2012
		Electric		Natural Gas
(Millions of Dollars)		Distribution		Distribution		Transmission		Other		Eliminations		Total
Operating Revenues		$	4,716.5	$	572.9	$	861.5	$	803.8	$	(680.9)	$	6,273.8
Depreciation and Amortization			(530.3)		(49.1)		(109.2)		(56.4)		4.2		(740.8)
Other Operating Expenses			(3,585.4)		(445.2)		(251.6)		(817.0)		684.4		(4,414.8)
Operating Income/(Loss)			600.8		78.6		500.7		(69.6)		7.7		1,118.2
Interest Expense			(165.6)		(31.3)		(96.7)		(43.6)		7.3		(329.9)
Interest Income			2.8		-		0.4		7.1		(7.1)		3.2
Other Income, Net			8.9		0.4		7.3		795.0		(795.1)		16.5
Income Tax (Expense)/Benefit			(150.2)		(16.9)		(159.2)		55.5		(4.1)		(274.9)
Net Income			296.7		30.8		252.5		744.4		(791.3)		533.1
Net Income Attributable
	to Noncontrolling Interests		(4.4)		-		(2.8)		-		-		(7.2)
Net Income Attributable
	to Controlling Interest	$	292.3	$	30.8	$	249.7	$	744.4	$	(791.3)	$	525.9
Total Assets (as of)		$	18,047.3	$	2,717.4	$	6,187.7	$	18,832.6	$	(17,482.2)	$	28,302.8
Cash Flows Used for
	Investments in Plant	$	611.7	$	148.7	$	663.6	$	48.3	$	-	$	1,472.3

		For the Year Ended December 31, 2011
		Electric		Natural Gas
(Millions of Dollars)		Distribution		Distribution		Transmission		Other		Eliminations		Total
Operating Revenues		$	3,343.1	$	430.8	$	635.4	$	541.3	$	(484.9)	$	4,465.7
Depreciation and Amortization			(337.2)		(27.7)		(84.0)		(16.8)		2.5		(463.2)
Other Operating Expenses			(2,637.4)		(333.5)		(188.2)		(534.1)		484.9		(3,208.3)
Operating Income/(Loss)			368.5		69.6		363.2		(9.6)		2.5		794.2
Interest Expense			(123.8)		(21.0)		(76.7)		(33.7)		4.8		(250.4)
Interest Income			3.7		-		0.5		5.3		(5.3)		4.2
Other Income, Net			11.6		1.3		10.7		455.2		(455.3)		23.5
Income Tax (Expense)/Benefit			(67.6)		(18.2)		(95.6)		14.3		(3.9)		(171.0)
Net Income			192.4		31.7		202.1		431.5		(457.2)		400.5
Net Income Attributable
	to Noncontrolling Interests		(3.3)		-		(2.5)		-		-		(5.8)
Net Income Attributable
	to Controlling Interest	$	189.1	$	31.7	$	199.6	$	431.5	$	(457.2)	$	394.7
Total Assets (as of)		$	9,653.1	$	1,511.3	$	3,792.9	$	6,618.0	$	(5,928.2)	$	15,647.1
Cash Flows Used for
	Investments in Plant	$	540.7	$	98.2	$	388.9	$	48.9	$	-	$	1,076.7

		For the Year Ended December 31, 2010
		Electric		Natural Gas
(Millions of Dollars)		Distribution		Distribution		Transmission		Other		Eliminations		Total
Operating Revenues		$	3,802.0	$	434.3	$	625.6	$	521.6	$	(485.3)	$	4,898.2
Depreciation and Amortization			(501.2)		(23.8)		(86.7)		(15.8)		3.8		(623.7)
Other Operating Expenses			(2,925.1)		(340.0)		(192.1)		(505.4)		488.0		(3,474.6)
Operating Income			375.7		70.5		346.8		0.4		6.5		799.9
Interest Expense			(133.4)		(17.9)		(73.2)		(17.4)		4.6		(237.3)
Interest Income			0.7		-		1.8		5.3		(6.3)		1.5
Other Income, Net			24.4		0.8		14.3		436.4		(435.5)		40.4
Income Tax (Expense)/Benefit			(90.3)		(20.7)		(109.3)		11.0		(1.1)		(210.4)
Net Income			177.1		32.7		180.4		435.7		(431.8)		394.1
Net Income Attributable
	to Noncontrolling Interests		(3.6)		-		(2.6)		-		-		(6.2)
Net Income Attributable
	to Controlling Interest	$	173.5	$	32.7	$	177.8	$	435.7	$	(431.8)	$	387.9
Cash Flows Used for
	Investments in Plant	$	560.1	$	82.5	$	239.2	$	72.7	$	-	$	954.5

172

22.

VARIABLE INTEREST ENTITIES

The Company's variable interests outside of the consolidated group are not material and consist of contracts that are required by regulation and provide for regulatory recovery of contract costs and benefits through customer rates.  NU, CL&P and NSTAR Electric hold variable interests in variable interest entities (VIEs) through agreements with certain entities that own single renewable energy or peaking generation power plants and with other independent power producers.  NU, CL&P and NSTAR Electric do not control the activities that are economically significant to these VIEs or provide financial or other support to these VIEs.  Therefore, NU, CL&P and NSTAR Electric do not consolidate any power plant VIEs.  

23.

SUBSEQUENT EVENTS (NU, CL&P, NSTAR Electric)

See Note 9, "Long-Term Debt" to the consolidated financial statements for information regarding the January 2013 long-term debt issuance for CL&P.

See Note 12C, "Commitments and Contingencies – Deferred Contractual Obligations" to the consolidated financial statements for information regarding the receipt of the DOE proceeds by the Yankee Companies in January 2013.

See Note 11, "Income Taxes," for discussion of the federal legislation enacted on January 2, 2013.

On February 8, 2013, a blizzard caused damage to the electric delivery systems of CL&P and NSTAR Electric.  Management believes that this storm will cost between $100 million to $120 million, with approximately 90 percent of those costs relating to NSTAR Electric.  Management expects the costs to meet the criteria for specific cost recovery in Connecticut and Massachusetts and, as a result, does not expect the storm to have a material impact on the results of operations of CL&P or NSTAR Electric.  Each operating company will seek recovery of these anticipated deferred storm costs through its applicable regulatory recovery process.

24.

QUARTERLY FINANCIAL DATA (UNAUDITED)

NU Consolidated Statements of Quarterly Financial Data	Quarter Ended (a)
(Millions of Dollars, except per share information)	March 31,		June 30,		September 30,		December 31,
2012 (1)
Operating Revenues	$	1,099.6	$	1,628.7	$	1,861.5	$	1,684.0
Operating Income		214.4		159.5		412.9		331.4
Net Income		100.8		46.2		209.5		176.6	(2)
Net Income Attributable to Controlling Interest		99.3		44.3		207.6		174.7
Basic and Diluted EPS	$	0.56	$	0.15	$	0.66	$	0.55

2011 (1)
Operating Revenues	$	1,235.3	$	1,047.5	$	1,114.9	$	1,068.0
Operating Income		227.4		178.1		203.8		184.9
Net Income		115.6		78.7		91.4		114.8
Net Income Attributable to Controlling Interest		114.2		77.3		90.0		113.2
Basic and Diluted EPS	$	0.64	$	0.44	$	0.51	$	0.64
(a)  The summation of quarterly EPS data may not equal annual data due to rounding.

CL&P Consolidated Statements of Quarterly Financial Data	Quarter Ended
(Millions of Dollars)	March 31,		June 30,		September 30,		December 31,
2012
Operating Revenues	$	592.0	$	562.1	$	658.1	$	595.2
Operating Income		111.9		40.4		139.7		135.0
Net Income		54.0		6.9		74.9		73.9
2011
Operating Revenues	$	673.7	$	608.0	$	673.7	$	593.0
Operating Income		126.0		114.8		137.7		84.7
Net Income		64.3		52.6		66.5		66.8

173

NSTAR Electric Consolidated Statements of
Quarterly Financial Data	Quarter Ended
(Millions of Dollars)	March 31,		June 30,		September 30,		December 31,
2012 (1)
Operating Revenues	$	556.5	$	534.6	$	693.7	$	516.2
Operating Income		22.5		93.9		194.1		70.9
Net Income		3.9		45.5		106.8		34.0	(2)
2011 (1)
Operating Revenues	$	577.5	$	552.3	$	724.7	$	548.6
Operating Income		87.7		115.6		183.7		99.2
Net Income		42.9		60.7		99.8		49.1

PSNH Consolidated Statements of Quarterly Financial Data	Quarter Ended
(Millions of Dollars)	March 31,		June 30,		September 30,		December 31,
2012
Operating Revenues	$	243.0	$	255.1	$	256.9	$	233.0
Operating Income		45.4		47.0		61.3		51.4
Net Income		21.3		21.2		27.2		27.2
2011
Operating Revenues	$	269.5	$	240.2	$	259.6	$	243.7
Operating Income		46.9		37.9		48.5		46.8
Net Income		27.5		21.7		25.6		25.5
WMECO Consolidated Statements of Quarterly Financial Data	Quarter Ended
(Millions of Dollars)	March 31,		June 30,		September 30,		December 31,
2012
Operating Revenues	$	114.0	$	106.8	$	112.5	$	107.9
Operating Income		28.7		25.1		28.1		28.9
Net Income		14.2		11.1		14.1		15.1
2011
Operating Revenues	$	106.7	$	98.4	$	104.5	$	107.7
Operating Income		21.1		18.5		19.8		29.0
Net Income		10.0		8.2		8.4		16.5

⁽¹⁾

NSTAR Electric amounts are included in NU consolidated from the date of the merger, April 10, 2012, through December 31, 2012.  NSTAR Electric amounts are not included in NU consolidated for the years ended December 31, 2011 and 2010.

⁽²⁾

NSTAR Electric's Net Income for the quarter ended December 31, 2012 decreased by $8.2 million, as compared to the quarter ended December 31, 2011, related to a pre-tax charge to establish a reserve of $13.7 million to reflect a billing adjustment, all of which related to prior year amounts.

174

Item 9.

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

No events that would be described in response to this item have occurred with respect to NU, CL&P, NSTAR Electric, PSNH or WMECO.

Item 9A.

Controls and Procedures

Management, on behalf of NU, CL&P, NSTAR Electric, PSNH and WMECO, is responsible for the preparation, integrity, and fair presentation of the accompanying Consolidated Financial Statements and other sections of this combined Annual Report on Form 10-K.  NU, CL&P, NSTAR Electric, PSNH and WMECO’s internal controls over financial reporting were audited by Deloitte & Touche LLP.  

Management, on behalf of NU, CL&P, NSTAR Electric, PSNH and WMECO, is responsible for establishing and maintaining adequate internal controls over financial reporting.  The internal control framework and processes have been designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with GAAP.  There are inherent limitations of internal controls over financial reporting that could allow material misstatements due to error or fraud to occur and not be prevented or detected on a timely basis by employees during the normal course of business.  Additionally, internal controls over financial reporting may become inadequate in the future due to changes in the business environment.  Under the supervision and with the participation of the principal executive officers and principal financial officer, an evaluation of the effectiveness of internal controls over financial reporting was conducted based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).  Based on this evaluation under the framework in COSO, management concluded that internal controls over financial reporting at NU, CL&P, NSTAR Electric, PSNH and WMECO were effective as of December 31, 2012.

Management, on behalf of NU, CL&P, NSTAR Electric, PSNH and WMECO, evaluated the design and operation of the disclosure controls and procedures as of December 31, 2012 to determine whether they are effective in ensuring that the disclosure of required information is made timely and in accordance with the Securities Exchange Act of 1934 and the rules and regulations of the SEC.  This evaluation was made under management's supervision and with management's participation, including the principal executive officers and principal financial officer as of the end of the period covered by this Annual Report on Form 10-K.  There are inherent limitations of disclosure controls and procedures, including the possibility of human error and the circumventing or overriding of the controls and procedures.  Accordingly, even effective disclosure controls and procedures can only provide reasonable assurance of achieving their control objectives.  The principal executive officers and principal financial officer have concluded, based on their review, that the disclosure controls and procedures of NU, CL&P, NSTAR Electric, PSNH and WMECO are effective to ensure that information required to be disclosed by us in reports filed under the Securities Exchange Act of 1934 (i) is recorded, processed, summarized, and reported within the time periods specified in SEC rules and regulations and (ii) is accumulated and communicated to management, including the principal executive officers and principal financial officer, as appropriate to allow timely decisions regarding required disclosures.

There have been no changes in internal controls over financial reporting for NU, CL&P, NSTAR Electric, PSNH and WMECO during the quarter ended December 31, 2012 that have materially affected, or are reasonably likely to materially affect, internal controls over financial reporting.

On April 10, 2012, NSTAR became a direct wholly owned subsidiary of NU.  NU is currently in the process of integrating NSTAR’s operations, and will be conducting control reviews pursuant to Section 404 of the Sarbanes-Oxley Act of 2002.  See Note 2, "Merger of NU and NSTAR," to the Combined Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K for additional information regarding the merger.

Item 9B.

Other Information

No information is required to be disclosed under this item as of December 31, 2012, as this information has been previously disclosed in applicable reports on Form 8-K during the fourth quarter of 2012.

175

PART III

Item 10.

Directors, Executive Officers and Corporate Governance

The information in Item 10 is provided as of February 15, 2013, except where otherwise indicated.

Certain information required by this Item 10 is omitted for NSTAR Electric, PSNH and WMECO pursuant to Instruction I(2)(c) to Form 10-K, Omission of Information by Certain Wholly Owned Subsidiaries.

NU

In addition to the information provided below concerning the executive officers of NU, incorporated herein by reference is the information to be contained in the sections captioned "Election of Trustees," "Governance of Northeast Utilities" and the related subsections, "Selection of Trustees," and "Section 16(a) Beneficial Ownership Reporting Compliance" of NU's definitive proxy statement for solicitation of proxies, expected to be filed with the SEC on or about March 21, 2013.  

NU and CL&P

Each member of CL&P’s Board of Directors is an employee of CL&P, NU or an affiliate.  Directors are elected annually to serve for one year until their successors are elected and qualified.  

Set forth below is certain information as of February 15, 2013 concerning CL&P’s Directors and NU’s and CL&P’s executive officers:  

Name	Age	Title
Thomas J. May	65	President and Chief Executive Officer of NU; Chairman of CL&P.
Leon J. Olivier	64	Executive Vice President and Chief Operating Officer of NU; Chief Executive Officer of the Regulated companies; Director of CL&P.
James J. Judge	57	Executive Vice President and Chief Financial Officer of NU and the Regulated companies; Director of CL&P.
Gregory B. Butler	55	Senior Vice President, General Counsel and Secretary of NU; Senior Vice President and General Counsel of the Regulated companies; Director of CL&P.
Christine M. Carmody 1	50	Senior Vice President-Human Resources of NUSCO, NSTAR Electric & Gas, and the Regulated companies; Director of CL&P.
William P. Herdegen III 2	58	President and Chief Operating Officer and a Director of CL&P.
David R. McHale	52	Executive Vice President and Chief Administrative Officer of NU and the Regulated companies; Director of CL&P.
James A. Muntz	55	Senior Vice President-Transmission of NU and the Regulated companies.
Joseph R. Nolan, Jr. 1	49	Senior Vice President-Corporate Relations NUSCO, NSTAR Electric & Gas, and the Regulated companies; Director of CL&P.
Jay S. Buth	43	Vice President, Controller and Chief Accounting Officer of NU and the Regulated companies.

¹

Deemed an executive officer of NU pursuant to Rule 3b-7 under the Securities Exchange Act of 1934.

²

Mr. Herdegen is the President and Chief Operating Officer and Director of CL&P and is therefore an executive officer solely of CL&P.

Thomas J. May.  Mr. May became President and Chief Executive Officer and a Trustee of NU, Chairman and a Director of CL&P, NSTAR Electric, NSTAR Gas, PSNH, WMECO and Yankee Gas, and Chairman, President and Chief Executive Officer and a Director of NUSCO upon completion of the Merger.  He has been President and Chief Executive Officer of NSTAR Electric & Gas since January 1, 2002.  Mr. May has served as a Director of NSTAR Electric, NSTAR Gas and NSTAR Electric & Gas (or their predecessor companies) since September 27, 1999.  Previously, Mr. May served as Chairman, President and Chief Executive Officer and a Trustee of NSTAR, and as Chairman, President and Chief Executive Officer of NSTAR Electric, NSTAR Gas and NSTAR Electric & Gas until the closing of the Merger.  He served as Chairman, Chief Executive Officer and a Trustee since NSTAR was formed in 1999, and was elected President in 2002.  Mr. May became a Director of Northeast Utilities Foundation, Inc. upon completion of the Merger.  He has served as a Trustee of the NSTAR Foundation since August 18, 1987.  

Leon J. Olivier.  Mr. Olivier has served as Executive Vice President and Chief Operating Officer of NU and NUSCO since May 13, 2008, and of NSTAR Electric & Gas since the completion of the Merger.  He became Chief Executive Officer of NSTAR Electric and NSTAR Gas upon completion of the Merger.  Mr. Olivier has served as Chief Executive Officer of CL&P, PSNH, WMECO and Yankee Gas since January 15, 2007.  Mr. Olivier was elected a Director of NSTAR Electric, NSTAR Gas and NSTAR Electric & Gas effective November 27, 2012, of PSNH, WMECO and Yankee Gas effective January 17, 2005, and of CL&P effective September 10, 2001.  Previously, Mr. Olivier served as Executive Vice President-Operations of NU from February 13, 2007 to May 12, 2008.  Mr. Olivier became a Trustee of the NSTAR Foundation upon completion of the Merger.  He has served as a Director of Northeast Utilities Foundation, Inc. since April 1, 2006.  

176

James J. Judge.  Mr. Judge became Executive Vice President and Chief Financial Officer of NU, CL&P, NSTAR Electric, NSTAR Gas, PSNH, WMECO, Yankee Gas, NUSCO and NSTAR Electric & Gas upon completion of the Merger.  Mr. Judge was elected a Director of CL&P, PSNH, WMECO, Yankee Gas and NUSCO upon completion of the Merger.  He has served as a Director of NSTAR Electric, NSTAR Gas and NSTAR Electric & Gas since September 27, 1999.  Previously, Mr. Judge served as Senior Vice President and Chief Financial Officer of NSTAR, NSTAR Electric, NSTAR Gas and NSTAR Electric & Gas from 1999 until April 2012.  Mr. Judge became Treasurer and a Director of Northeast Utilities Foundation, Inc. effective upon completion of the Merger.  He has served as a Trustee of the NSTAR Foundation since December 12, 1995.  

Gregory B. Butler.  Mr. Butler became Senior Vice President, General Counsel and Secretary of NU and Senior Vice President and General Counsel of NSTAR Electric, NSTAR Gas and NSTAR Electric & Gas upon completion of the Merger.  He has served as Senior Vice President and General Counsel of CL&P, PSNH, WMECO, Yankee Gas and NUSCO since March 9, 2006.  Mr. Butler was elected a Director of NSTAR Electric, NSTAR Gas and NSTAR Electric & Gas upon completion of the Merger.  He has served as a Director of NUSCO since November 27, 2012, and of CL&P, PSNH, WMECO and Yankee Gas since April 22, 2009.  Previously Mr. Butler served as Senior Vice President and General Counsel of NU from December 1, 2005 to April 2012.  Mr. Butler became a Trustee of the NSTAR Foundation effective upon completion of the Merger.  He has served as a Director of Northeast Utilities Foundation, Inc. since December 1, 2002.  

Christine M. Carmody.  Ms. Carmody became Senior Vice President-Human Resources of NUSCO upon completion of the Merger and of CL&P, PSNH, WMECO and Yankee Gas effective November 27, 2012.  She has served as Senior Vice President-Human Resources of NSTAR Electric, NSTAR Gas and NSTAR Electric & Gas since August 1, 2008.  Ms. Carmody was elected a Director of CL&P, PSNH, WMECO and Yankee Gas upon completion of the Merger, and of NSTAR Electric, NSTAR Gas, NUSCO and NSTAR Electric & Gas effective November 27, 2012.  Previously, Ms. Carmody served as Vice President-Organizational Effectiveness of NSTAR, NSTAR Electric, NSTAR Gas and NSTAR Electric & Gas from June 2006 to August 2008.  Ms. Carmody became a Director of Northeast Utilities Foundation, Inc. effective upon completion of the Merger.  She has served as a Trustee of the NSTAR Foundation since August 1, 2008.

William P. Herdegen III.  Mr. Herdegen has served as President and Chief Operating Officer of CL&P since September 11, 2012.  Previously, Mr. Herdegen served as Vice President of Transmission and Distribution Engineering and Operations for Kansas City Power & Light Company from 2008 until his retirement on September 7, 2012, as Vice President, Distribution and Customer Operations from 2005 to 2008, and as Vice President, Distribution Operations from 2001 to 2005.  Mr. Herdegen began his utility career at Commonwealth Edison, where he held various positions, including Vice President, Engineering, Construction and Maintenance, corporate project manager, operations manager, business unit supply manager, district manager, and field engineer.

David R. McHale.  Mr. McHale became Executive Vice President and Chief Administrative Officer of NU, CL&P, NSTAR Electric, NSTAR Gas, PSNH, WMECO, Yankee Gas, NUSCO and NSTAR Electric & Gas upon completion of the Merger.  Mr. McHale has served as a Director of NSTAR Electric, NSTAR Gas and NSTAR Electric & Gas since November 27, 2012, of PSNH, WMECO, Yankee Gas and NUSCO since January 1, 2005, and of CL&P since January 15, 2007.  Previously, Mr. McHale served as Executive Vice President and Chief Financial Officer of NU, CL&P, PSNH, WMECO, Yankee Gas and NUSCO from January 2009 to April 2012, and Senior Vice President and Chief Financial Officer of NU, CL&P, PSNH, WMECO, Yankee Gas and NUSCO from January 2005 to December 2008.  Mr. McHale became a Trustee of the NSTAR Foundation upon completion of the Merger.  He has served as a Director of Northeast Utilities Foundation, Inc. since January 1, 2005.

James A. Muntz.  Mr. Muntz has served as President – Transmission of NUSCO since November 1, 2008, Senior Vice President – Transmission of CL&P, PSNH and WMECO since June 19, 2007, and Senior Vice President – Transmission of NSTAR Electric & Gas since January 16, 2013.  He served as President and Chief Operating Officer of CL&P from November 18, 2011 to September 11, 2012.  Previously, Mr. Muntz served as Senior Vice President – Transmission of NUSCO from June 19, 2007 to October 31, 2008 and Vice President – Transmission Products of CL&P, PSNH and WMECO from January 17, 2005 to June 19, 2007.  Mr. Muntz has served as President of NPT since April 21, 2010.

Joseph R. Nolan, Jr.  Mr. Nolan became Senior Vice President-Corporate Relations of NUSCO, NSTAR Electric & Gas, NSTAR Electric and NSTAR Gas upon completion of the Merger.  He became Senior Vice President-Corporate Relations of CL&P, PSNH, WMECO and Yankee Gas effective November 27, 2012.  Mr. Nolan was elected a Director of CL&P, PSNH, WMECO and Yankee Gas upon completion of the Merger, and of NSTAR Electric, NSTAR Gas, NUSCO and NSTAR Electric & Gas effective November 27, 2012.  Previously, Mr. Nolan served as Senior Vice President-Customer & Corporate Relations of NSTAR, NSTAR Electric, NSTAR Gas and NSTAR Electric and Gas from 2006 until the closing of the Merger.  Mr. Nolan became a Director of Northeast Utilities Foundation, Inc. upon completion of the Merger.  He has served as a Trustee of the NSTAR Foundation since October 1, 2000.  

Jay S. Buth.  Mr. Buth became Vice President, Controller and Chief Accounting Officer of NU, CL&P, NSTAR Electric, NSTAR Gas, PSNH, WMECO, Yankee Gas, NUSCO and NSTAR Electric & Gas upon completion of the Merger.  Previously, Mr. Buth was Vice President-Accounting and Controller of NU, CL&P, PSNH, WMECO, Yankee Gas and NUSCO from June 2009 through the completion of the Merger.  From June 2006 through January 2009, Mr. Buth was the Vice President and Controller for New Jersey Resources Corporation, an energy services holding company that provides natural gas and wholesale energy services, including transportation, distribution and asset management.

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There are no family relationships between any director or executive officer and any other trustee, director or executive officer of NU or CL&P and none of the above executive officers or directors serves as an executive officer or director pursuant to any agreement or understanding with any other person. Our executive officers hold the offices set forth opposite their names until the next annual meeting of the Board of Trustees, in the case of NU, and the Board of Directors, in the case of CL&P, and until their successors have been elected and qualified.  

CL&P obtains audit services from the independent registered public accounting firm engaged by the Audit Committee of NU's Board of Trustees.  CL&P does not have its own audit committee or, accordingly, an audit committee financial expert.  CL&P relies on NU’s audit committee and audit committee experts.  

CODE OF ETHICS AND STANDARDS OF BUSINESS CONDUCT

Each of NU, CL&P, NSTAR Electric, PSNH and WMECO has adopted a Code of Ethics for Senior Financial Officers (Chief Executive Officer, Chief Financial Officer and Controller) and the Standards of Business Conduct, which are applicable to all Trustees, directors, officers, employees, contractors and agents of NU, CL&P, NSTAR Electric, PSNH and WMECO.  The Code of Ethics and the Standards of Business Conduct have both been posted on the NU web site and are available at www.nu.com/investors/corporate_gov/default.asp on the Internet.  Any amendments to or waivers from the Code of Ethics and Standards of Business Conduct for executive officers, directors or Trustees will be posted on the website.  Any such amendment or waiver would require the prior consent of the Board of Trustees or an applicable committee thereof.

Printed copies of the Code of Ethics and the Standards of Business Conduct are also available to any shareholder without charge upon written request mailed to:

Richard J. Morrison

Assistant Secretary

Northeast Utilities

P.O. Box 270

Hartford, CT 06141

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Item 11.

Executive Compensation

NU

The information required by this Item 11 for NU is incorporated herein by reference to certain information contained in NU’s definitive proxy statement for solicitation of proxies, which is expected to be filed with the SEC on or about March 21, 2013, under the sections captioned "Compensation Discussion and Analysis" plus the related subsections, and "Compensation Committee Report" plus the related subsections following such Report.

NSTAR ELECTRIC, PSNH and WMECO

Certain information required by this Item 11 has been omitted for NSTAR Electric, PSNH and WMECO pursuant to Instruction I(2)(c) to Form 10-K, Omission of Information by Certain Wholly Owned Subsidiaries.

CL&P

The information in this Item 11 relates solely to CL&P.

COMPENSATION DISCUSSION AND ANALYSIS

CL&P is a wholly-owned subsidiary of NU.  Its board of directors consists entirely of executive officers of NU system companies.  CL&P does not have a compensation committee, and the Compensation Committee of NU’s Board of Trustees determines compensation for the executive officers of CL&P, including their salaries, annual incentive awards and long-term incentive awards.  All of CL&P’s "Named Executive Officers," as defined below, also serve as officers of NU and one or more other subsidiaries of NU.  Compensation set by the Compensation Committee of NU (the "Committee") and set forth herein is for services rendered to NU and its subsidiaries by such officers in all capacities.

EXECUTIVE SUMMARY

On April 10, 2012, NU acquired all of the outstanding common shares of NSTAR and NSTAR became a direct wholly owned subsidiary of NU.  Immediately after the merger, the pre-merger shareholders of NU owned 56.3 percent of NU’s common shares, and the pre-merger NSTAR shareholders owned 43.7 percent of NU’s common shares.

This discussion describes NU’s material compensation policies and practices generally.  It also describes their application to the compensation awards and decisions made with respect to 2012 by both the pre-merger and post-merger compensation committees for the Named Executive Officers, as presented in the tables and narratives that follow.  While the following discussion focuses primarily on the 2012 information that is presented in the accompanying tables and narratives, it also addresses decisions that were taken in other periods to the extent that these decisions are relevant to the full understanding of the compensation decisions for 2012.

Summary of 2012 Performance

In 2012, NU completed one of the most significant mergers in the utility industry, creating one of the nation’s largest utilities, with four regulated electric and two regulated natural gas utilities serving 3.5 million customers in three states and a market capitalization of approximately $12.5 billion, the fifteenth largest in the utility industry.  Leading up to the merger, the executive team successfully built the foundation for the merged company to deliver positive financial results and refine NU’s operations to deliver excellent service for customers.  As a result of the merger, NU has become more diverse and better positioned to provide value to its customers and our shareholders.  

At the time of the announcement of the merger, NU identified the substantial financial, strategic and operational benefits it expected the merger to provide.  During 2012, the management of the newly combined company immediately came together as an efficient team to deliver those benefits.  The following is a summary of some of the most important accomplishments:

Financial Highlights

·

NU’s 2012 reported earnings of $2.28 per share exceeded its stretch earnings per share target of $2.27, despite the difficult environment resulting from the sluggish economy, mild winter weather and the effect of increases in pension and healthcare costs.

·

In completing the merger, NU negotiated multi-year rate settlements in Connecticut and Massachusetts that position NU to maintain its strong financial condition and achieve positive financial performance for its shareholders.

·

Reflecting the benefits of the merger, during 2012 NU achieved a total shareholder return of 12.1 percent, substantially outperforming the Edison Electric Institute (EEI) Index return of 2.1 percent and other major utility companies that have completed a significant merger in the past 18-24 months.  

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·

NU’s cumulative total shareholder returns of 67.7 percent, 48.9 percent, 260.9 percent and 399.1 percent over the past three-, five-, 10- and 15-year periods outperformed the industry and the market over these same periods.  NU also ranked in the top performing quartile of the EEI Index for each of the listed time periods.

Operational and Merger Effectiveness Highlights

·

NU implemented its "One Company" shared services operating model that allowed it to lower operating costs while improving customer service and enhancing emergency preparedness by effectively deploying the resources of the merged company.  

·

NU developed an enhanced $3.7 billion five-year transmission capital plan to better improve the efficiency of New England’s congested energy markets, improve reliability and increase revenues over the long-term compared to what either pre-merger company could have achieved on its own.

·

NU met or exceeded the Massachusetts-mandated electric and gas service targets, as measured by the Service Quality Index; and NU’s electric and gas systems improved the Months Between Interruptions, On-Time Gas System Response, System Average Interruption Duration, Customer Average Interruption Duration, Calls Answered Rate and Meters Read On Time metrics.

Achievement of the 2012 performance goals and the Committee’s assessment of NU and executive performance are fully described in the section captioned "2012 Annual Incentive Program."  Specific decisions regarding executive compensation based upon the Committee’s assessment of NU and executive performance and the market data described in this Compensation Discussion and Analysis (CD&A) are set forth below.

NAMED EXECUTIVE OFFICERS

The executive officers of CL&P listed in the Summary Compensation Table in this Item 11 whose compensation is discussed in this CD&A are CL&P’s Chief Executive Officer (CEO), Executive Vice President and Chief Financial Officer (CFO), and the three other most highly compensated executive officers other than CL&P’s CEO and CFO who were serving as executive officers at the end of 2012 (collectively, referred to as the "Named Executive Officers" or "NEOs").  Each Named Executive Officer of CL&P also serves as an executive officer of NU and one or more other subsidiaries of NU.  Compensation for such NEOs discussed in this CD&A was for all services provided by such individuals in all capacities to NU and its subsidiaries.  For 2012, CL&P’s Named Executive Officers are:

·

Leon J. Olivier, Chief Executive Officer of CL&P

·

David R. McHale, Executive Vice President and Chief Financial Officer until April 10, 2012; Executive Vice President and Chief Administrative Officer from April 10, 2012 to present

·

James J. Judge, Executive Vice President and Chief Financial Officer from April 10, 2012 to present

·

Thomas J. May, President and Chief Executive Officer of NU, and Chairman of CL&P, from April 10, 2012 to present

·

Gregory B. Butler, Senior Vice President, General Counsel and Secretary of NU; Senior Vice President and General Counsel of CL&P

·

James A. Muntz, Senior Vice President-Transmission of NU and CL&P

·

Charles W. Shivery, Chairman of CL&P, until April 10, 2012; Chairman of the Board of NU

SEC rules require that the Named Executive Officers also include (i) all individuals who served as principal executive officer and principal financial officer during 2012 and (ii) up to two additional individuals who would have been one of the three other most highly compensated executive officers if they had been serving as an executive officer at the end of 2012.  Therefore, each of the individuals named above is considered to be a Named Executive Officer for this Compensation Discussion and Analysis.  For the NEOs who came from NSTAR, Messrs. May and Judge, the disclosure pertains to compensation earned by each of them subsequent to the Merger.  While Mr. Muntz is considered to be a Named Executive Officer, his post-merger compensation is not subject to approval by the Committee, as he is not a senior executive officer as defined by NU’s post-merger Compensation Committee Charter.

OVERVIEW OF OUR COMPENSATION PROGRAM

The Role of the Compensation Committee.  The NU Board of Trustees has delegated to the Committee overall responsibility for establishing the compensation program for all executive officers, including the Named Executive Officers.  In this role, the Committee sets compensation policy and compensation levels, reviews and approves performance goals and evaluates executive performance.  Although this discussion and analysis refers principally to compensation for the Named Executive Officers, the same compensation principles and practices generally apply to all executive officers.  The compensation of the Chief Executive Officer is subject to the further review and approval of the independent Board members.

Elements of Compensation.  Total direct compensation is delivered primarily through a combination of three elements: base salary, annual cash incentive awards and long term equity-based incentive awards.  Compensation is also provided through certain retirement, perquisite, severance, and health and welfare benefit programs.  

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Compensation Objectives.  The objectives of NU’s compensation program are to attract and retain superior executive talent, to motivate our executives to achieve short-term and long-term performance goals set each year, and to provide base salary, performance-based annual incentive compensation and long-term incentive compensation opportunities that are competitive with the market.  With respect to incentive compensation, the Committee believes it is important to balance short-term goals, such as generating earnings, with longer-term goals, such as long-term value creation, maintaining a strong balance sheet, system reliability and great customer service.  NU’s compensation program utilizes performance-based compensation programs to reward individual and corporate performance and to link the interests of executives with its customers and shareholders.  The Committee continually increases expectations to incentivize executives and employees to achieve continuous improvement in discharging NU’s responsibilities to its customers to provide energy services reliably, safely, with respect for the environment and its employees, and at a reasonable cost, while providing an above-average return to its shareholders.

Setting Compensation Levels.  In order to ensure that NU achieves its goal of providing market-based compensation levels to attract and retain top quality management, the Committee provides executive officers with target compensation opportunities over time approximately equal to median compensation levels for executive officers of companies comparable to NU.  To achieve that goal, the Committee and its compensation consultant work together to determine the market values of executive officer compensation elements (base salaries, annual incentives and long-term incentives) as well as total compensation, using compensation data obtained from other companies.  The Committee reviews compensation data obtained from utility and general industry surveys and a group of peer utility companies.  The Committee then reviews the compensation elements for each executive officer with respect to the median of these market value benchmarks and considers individual performance, experience and internal pay equity to determine total compensation.  

Role of the Compensation Consultant.  NU’s post-merger Committee has retained Pay Governance LLC ("Pay Governance") as its independent compensation consultant.  Prior to the merger, the Committee had retained Semler Brossy Consulting Group LLC as its independent compensation consultant.  Pay Governance reports directly to the Committee and does not provide any other services to NU.  Pay Governance works cooperatively with NU’s management to develop analyses and proposals for presentation to the Committee.  The Committee generally relies on Pay Governance for peer group market data and information as to market practices and trends to assess the competitiveness of the compensation NU pays to its senior executive officers and to review the Committee’s proposed compensation decisions.  The Committee has assessed the independence of Pay Governance pursuant to SEC and New York Stock Exchange rules and concluded that it is independent and that no conflicts of interest exist that would prevent Pay Governance from independently advising the Committee.

Role of Management.  The role of management of NU and specifically the role of NU’s Chief Executive Officer and its Senior Vice President of Human Resources is to provide current compensation information to the compensation consultant and to provide analysis and recommendations on executive officer compensation to the Committee based on the market value of the position, individual performance, experience and internal pay equity.  Neither of these executives makes recommendations that affect their own compensation.

Set forth below is a description of the sources of the compensation data used by the Committee when reviewing pre-merger 2012 compensation:

·

Utility and general industry survey data.  The pre-merger Committee reviewed compensation information obtained from surveys of diverse groups of utility and general industry companies that represent NU’s market for executive officer talent.  The Committee used this information, which it obtained from Semler Brossy Consulting Group LLC, to determine base salaries and incentive opportunities.  Then the Committee reviewed the utility-specific executive officer positions as compared to utility-specific market values.  

·

Peer group data.  The pre-merger Committee also evaluated compensation data obtained from reviews of proxy statements from a group of peer utility companies.  In support of pre-merger executive pay decisions during 2012, the peer group consisted of utilities with annual revenues that ranged from $2.3 billion to $10.6 billion, with median annual revenues of $4.6 billion.  The Committee considered data only for those executive officer positions where there was a title match, which in 2012 included NU’s Chief Executive Officer, Chief Financial Officer, Chief Operating Officer and General Counsel positions.  For 2012, the pre-merger peer group consisted of the following 18 companies:

Alliant Energy Corporation	Integrys Energy Group Inc.	Pinnacle West Capital Corporation
Ameren Corporation	NiSource Inc.	Progress Energy, Inc.
CenterPoint Energy, Inc.	NSTAR	SCANA Corporation
CMS Energy Corporation	NV Energy, Inc.	TECO Energy, Inc.
DTE Energy Company	OGE Energy Corp.	Wisconsin Energy Corporation
Great Plains Energy Incorporated	Pepco Holdings, Inc.	Xcel Energy Inc.

The Committee periodically adjusts the target percentages of annual and long-term incentives based on the survey data and the recommendations of the compensation consultant to ensure that they are approximately equal to competitive median levels.  In February 2012, the Committee also used this peer group for performance comparisons under the 2012 – 2014 Long-Term Incentive Program.

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The Committee also determines perquisites to the extent they serve business purposes and sets supplemental benefits at levels that provide market-based compensation opportunities to the executive officers.  The Committee periodically reviews the general market for supplemental benefits and perquisites using utility and general industry survey data, sometimes including data obtained from companies in the peer group.  

Mix of Compensation Elements.  The target mix of compensation for NU’s Chief Executive Officer and the other Named Executive Officers is approximately equal to the competitive median market mix.  More senior positions involve increased responsibility for implementing our long-term business plans and strategies, and a greater proportion of total compensation is based on performance with a long-term focus.  

The Committee determines the compensation for each senior executive officer based on the relative authority, duties and responsibilities of each officer.  The responsibilities of NU’s CEO for the strategic direction and daily operations and management of the Northeast Utilities System companies, as President and Chief Executive Officer of NU and Chairman of each of the Regulated companies, are greater than the duties and responsibilities of the other executive officers.  As a result, the compensation of NU’s CEO is higher than the compensation of the other executive officers.  Assisted by the compensation consultant, the Committee regularly reviews market compensation data for executive officer positions similar to those held by the executive officers, including the CEO, and this market data continues to indicate that chief executive officers are typically paid significantly more than other executive officers.  For 2012, prior to the merger closing, target annual incentive and long-term incentive compensation opportunities for NU’s CEO were 100 percent and 300 percent of base salary respectively.  For the remaining Named Executive Officers, pre-merger target annual incentive compensation opportunities ranged from 50 percent to 65 percent of base salary and target long-term incentive compensation opportunities ranged from 100 percent to 150 percent of base salary.

The following table sets forth the contribution to 2012 pre-merger Total Direct Compensation (TDC) of each element of compensation, at target, reflected as a percentage of TDC, for the Named Executive Officers.  The amounts shown in this table are at target and therefore will not match the amounts appearing in the Summary Compensation Table.

	Percentage of TDC at Target
			Long-Term Incentives
Named Executive Officer	Base Salary	Annual Incentive(1)	Performance Units(1)	RSUs(2)	TDC
Charles W. Shivery	20	20	45	15	100
Thomas J. May (3)	—	—	—	—	—
David R. McHale	32	20	36	12	100
James J. Judge (3)	—	—	—	—	—
Leon J. Olivier	32	20	36	12	100
Gregory B. Butler	32	20	36	12	100
James A. Muntz	40	20	30	10	100
NEO average, excluding CEO	34	20	34.5	11.5	100

(1)

The annual incentive compensation element and performance units under the long-term incentive compensation element are performance-based.

(2)

Restricted Share Units ("RSUs") vest over three years contingent upon continued employment.

(3)

Messrs. May and Judge were not executive officers when targets were set in January 2012.

Analysis of Risk.  The Committee periodically assesses the potential risks that may be caused by the compensation programs and mitigates risks by rigorously analyzing the setting of goals and the minimum performance thresholds and ceilings for the incentive programs, continuously monitoring performance and enterprise risk, and retaining discretion with respect to actual payouts.  The Committee has the ability to reduce compensation amounts, set caps on incentive compensation and provides meaningful base compensation, all of which serve to reduce compensation risk.  In addition, the executives must comply with share ownership guidelines that more closely link their interests to those of shareholders, are subject to clawback of incentive compensation under certain circumstances, and are provided limited perquisites.

Results of NU’s Say on 2011 Pay Proposal.  NU provides its shareholders with the required opportunity to cast an annual advisory vote on executive compensation (a "say-on-pay" proposal).  At NU’s Annual Meeting of Shareholders held in October 2012, 95.77 percent of the votes cast on the say-on-pay proposal were voted to approve the compensation of the Named Executive Officers, as described in NU’s 2012 proxy statement.  The Committee will continue to consider the outcome of NU’s say-on-pay votes when making future compensation decisions for the Named Executive Officers.

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ELEMENTS OF 2012 COMPENSATION

Base Salary

Base salary is designed to attract and retain key executives by providing an element of total compensation competitive with that of other executives employed by companies of similar size and complexity in the utility and general industries.  In establishing base salary, the Committee relies on compensation data obtained from third-party surveys of companies and from an industry peer group to ensure that the compensation opportunities NU offers are capable of attracting and retaining executives with the experience and talent required to achieve our strategic objectives.  

When setting or adjusting base salaries, the Committee considers annual individual performance appraisals; market pay movement across industries (determined through market analysis); targeted market pay positioning for each executive officer; individual experience and years of service; strategic importance of a position; and internal equity.

Individuals who are performing well in strategic positions are likely to have their base salaries increased more significantly than other individuals.  From time-to-time, economic conditions and corporate performance have caused salary increases to be postponed.  The Committee prefers to reflect subpar corporate performance through the variable pay components.

In February 2012, the pre-merger Committee adjusted the base salaries of the Named Executive Officers (except for Mr. Shivery) by 3 percent to 3.5 percent.

Incentive Compensation

The annual incentive program and the long-term incentive program are provided under the Northeast Utilities Incentive Plan, which was approved by NU’s shareholders at the 2007 Annual Meeting of Shareholders and, with respect to the material terms of performance goals, was re-approved by NU’s shareholders at the 2012 Annual Meeting of Shareholders.  The annual incentive program provides cash compensation intended to reward performance under NU’s annual operating plans.  The long-term incentive program is designed to reward demonstrated performance and leadership, motivate future performance, align the interests of the executive officers with those of NU’s shareholders and retain the executive officers during the term of grants.  The annual and long-term programs are designed to strike a balance between the short and long-term objectives so that the programs work in tandem.  

2012 ANNUAL INCENTIVE PROGRAM

Target award levels under the Annual Incentive Program are expressed as a percentage of each Named Executive Officer’s base salary.  For each of the Named Executive Officers, target award levels throughout 2012 ranged from 50 percent to 100 percent of base salary.  Based on the Committee’s assessment, in its discretion, of the financial and operational performance of NU, as well as its assessment of each Named Executive Officer’s individual performance, awards under the Program may be made within a range of 0 percent to 200 percent of target.  The annual target award level set by the pre-merger Committee for NU’s CEO, Mr. Shivery and, following the completion of the merger by the post-merger Committee for NU’s CEO, Mr. May, was set at 100 percent of base pay for 2012.  The maximum possible award is 200 percent of base salary.

In early 2012, when completion of the Merger was still uncertain, the committees responsible for compensation at each of NU and NSTAR established goals under their respective annual incentive programs.  The principal financial goal set by the NSTAR Executive Personnel Committee was based on NSTAR earnings per share, which had been NSTAR’s long-standing principal financial metric.  The pre-merger NU Committee set a 2012 financial goal expressed in both Adjusted Net Income and Earnings Per Share.  In view of the fact that the Merger was completed in early April 2012, the Committee determined later in 2012 that it would need to exercise more discretion at the end of the year to determine the level of achievement for the purpose of 2012 annual incentive awards for the Named Executive Officers.  The Committee determined to be guided in its discretion by the earnings per share goal and the level of operational and merger effectiveness performance achieved by the post-merger combined management team.  While retaining discretion with respect to these measures, the Committee emphasized the need for the management team to also focus on meeting or exceeding the rigorous regulatory metrics established for NU, as well as the goals established by the NSTAR and NU compensation committees prior to the merger.

Later in 2012, the Committee met with Pay Governance, which provided the Committee with a competitive assessment analysis of our executive compensation levels.  Included in the analysis was a recommended change to the utility peer group that is used for the purposes of assisting the Committee in establishing and maintaining market-based compensation levels.  The change was made to better assess market competitiveness due to the larger size of the post-merger company.  The Committee adopted this recommendation.  The post-merger peer group consists of the 20 companies listed below, which have revenues of $3.3 billion to $14.9 billion, with median annual revenues of $8.6 billion, more in line with the revenues of post-merger NU:

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Alliant Energy Corporation	Edison International	Public Service Enterprise Group, Inc.
Ameren Corporation	Entergy Corporation	SCANA Corporation
CenterPoint Energy, Inc.	Integrys Energy Group, Inc.	Sempra Energy
Consolidated Edison Inc.	OGE Energy Corp.	TECO Energy, Inc.
CMS Energy Corp.	Pepco Holdings, Inc.	Wisconsin Energy Corp.
Dominion Resources, Inc.	PG&E Corp.	Xcel Energy Inc.
DTE Energy Company	PPL Corporation

In late 2012 and early 2013, prior to the actions taken by the Committee at its February 4, 2013 meeting, the Committee met three times to discuss post-merger compensation programs generally and to  assess the performance of NU and the management team.  As part of the compensation assessment, the Committee determined at its January 2013 meeting that it was appropriate to set the elements of target base and incentive compensation, including 2012 annual incentive payments, based on the median of the post-merger utility peer group.  With respect to annual incentive targets, adjustments were made to the targets of some of the senior executive officers, but not NU’s CEO, Mr. May, whose target remained at 100 percent of base salary.  The minimum annual incentive target for senior executive officers is now 45 percent of base salary.  The Committee also discussed performance weighting, and after consultation with Pay Governance, the Committee determined at its January 2013 meeting that in assessing 2012 performance for all executive officers, it would base 50 percent of the annual incentive award on its assessment of NU’s financial performance and 50 percent on its operational/merger effectiveness performance.

With respect to 2012 performance, management prepared a comprehensive review of NU’s performance for the year.  Based on that analysis, NU’s Chief Executive Officer recommended to the Committee payout levels for the senior executive officers based on NU’s overall financial and operational/merger effectiveness performance, along with his assessment of each executive officer’s individual performance.  Other than with respect to the earnings per share goal, in exercising its discretion to determine award levels for financial and operational/merger effectiveness performance results, the Committee did not use pre-determined or quantifiable formulas based on the degree of achievement of performance metrics.  The Committee used its discretion to consider a substantial number of financial and operational results, including its assessment of the difficulty of achieving those results. The Committee determined, based on its assessment of the various financial and operational/merger effectiveness performance results discussed below, to set the level of achievement of combined financial and operational/merger effectiveness performance results at 180 percent of target, reflecting the overall superior performance of NU and the executive team.

Financial Performance Factors Considered by the Committee

The Committee determined in its discretion that the financial performance of NU was outstanding and that the award for 2012 financial performance (weighted 50 percent) would be 200 percent of target.  The Committee considered the following financial results:

·

The completion of the transformational merger transaction, which reduces regulatory risks and provides both the potential for above-average growth and the foundation for improved customer service levels.

·

The price/earnings multiple applicable to NU’s common shares at year-end increased from slightly below the industry average at the time of the merger announcement to significantly above the average price/earnings multiple.  This premium price/earnings multiple resulted in the creation of approximately $1.3 billion in incremental shareholder value.

·

NU achieved earnings per share of $2.28, exceeding the stretch target despite the difficult environment noted above, through continuous performance improvement and cost reductions, while at the same time improving customer service performance.

·

Reflecting the benefits of the merger, during 2012 NU had top-tier total shareholder return of 12.1 percent, substantially outperforming the EEI Index return of 2.1 percent, and outperforming other major utility companies that have completed a significant merger in the past 18-24 months.  

·

NU implemented effective refinancing programs resulting in significant annualized interest cost savings of approximately $30 million.

·

NU’s credit rating at Standard & Poor’s improved to "A-," among the highest in the utility industry, as a result of NU’s more diverse operations, stronger financial condition and improved cash flows, providing the foundation for favorable financing opportunities in the future.  The industry average credit rating at Standard & Poor’s is "BBB."

·

NU achieved operations and maintenance cost reductions through successful integration activities, resulting in significant cost savings.

·

NU executed a robust $1.7 billion capital program targeted to improve system reliability while maintaining NU’s financial integrity.

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·

Cumulative total shareholder returns were 67.7 percent, 48.9 percent, 260.9 percent and 399.1 percent over the past three-five-10-and 15-year periods, significantly outperforming the industry and the market over those same periods.  NU also ranked in the top performing quartile of the EEI Index for each of the periods noted.

Operational and Merger Effectiveness Performance Factors Considered by the Committee

The Committee determined in its discretion that the operational and merger effectiveness performance of NU was excellent, and set the award for 2012 operational performance (weighted 50 percent) at 160 percent of target.  In doing so, the Committee considered the following results:

·

NU implemented a "One Company" shared services operating model that allowed us to lower operating costs while improving customer service and enhanced emergency preparedness by effectively deploying the resources of the merged company.  NU demonstrated the benefits of our One Company approach during restoration efforts from Superstorm Sandy, when it quickly deployed crews from Massachusetts and New Hampshire upon completion of restoration activities to the hard-hit Connecticut area.

·

NU developed an enhanced $3.7 billion five-year transmission capital plan to better improve the efficiency of New England’s congested energy markets, improve reliability and increase revenues over the long-term compared to what either predecessor company could have achieved on its own.

·

NU met or exceeded the Massachusetts-mandated electric and gas service targets, as measured by the Service Quality Index, and the electric and gas systems improved the Months Between Interruptions, On-Time Gas System Response, System Average Interruption Duration Index, Customer Average Interruption Duration, Calls Answered Rate and Meters Read On Time metrics.  NU’s  internal metric results were as follows:

o

Average months between service interruptions equaled 13.4 months, exceeding the target of 12.4 months

o

On-time response to gas customer emergency calls was 99.5 percent, exceeding the target of 99 percent

o

Electric service outage restoration time of 104.1 minutes was significantly better than the target of 111.6 minutes

o

99.2 percent of meters were read on time, exceeding the 99 percent target, and

o

88.2 percent of customer calls were answered within 30 seconds, exceeding the 85.6 percent target

·

NU’s natural gas distribution subsidiaries ranked numbers 1 and 2 as compared to their peer utilities in the J.D. Power Gas Customer Satisfaction survey.  

·

NU achieved a number of successful legal and regulatory outcomes, and our energy efficiency programs performed very effectively, meeting aggressive internal and state-wide savings targets.

·

NU significantly improved its safety performance in Days Away Restricted Duty (DART) and Preventable Motor Vehicle Accidents (PMVA) compared to target and prior year performance.  DART for 2012 was 1.85 accidents per 100 employees, compared to target of 2.07, while PMVAs for 2012 equaled 2.92 per million miles traveled compared to the target of 4.11.  All performance comparisons showed a double-digit rate of improvement.

Individual Performance Factors Considered by the Committee

Following the completion of the merger, the goal of the Committee for 2012 was to incentivize the newly combined company’s executives to come together as a highly effective, integrated team to achieve or exceed the adjusted earnings per share target and other financial, operational and merger effectiveness objectives.  While emphasizing the importance of the executives to work as a team, the Committee made annual incentive award payments based also on the assessment of each executive’s individual performance.  The Committee assessed the team performance of NU’s Chief Executive Officer and the Named Executive Officers to determine the individual incentive awards as disclosed in the Summary Compensation Table.  Based on the Committee’s review of NU’s overall performance, considered by the Committee to have been outstanding for the several reasons set forth above, the Committee approved annual incentive program payouts for the Named Executive Officers at levels that ranged from 173 percent to 185 percent of target.  These awards reflected the individual and team contributions of Mr. Shivery, Mr. May,  Mr. McHale,  Mr. Judge, Mr. Olivier,  Mr. Butler and Mr. Muntz in the overall performance of NU.

In arriving at Mr. May’s annual incentive payment of $2,100,000, which was 185 percent of target and reflective of his and NU’s outstanding performance, the Committee and NU’s Board considered the totality of NU’s excellent financial and operating/merger effectiveness performance and Mr. May’s strategic leadership in enabling NU to achieve its excellent performance, along with the success of the merger closing, Mr. May’s leadership in bringing the new executive team together, and his work with key stakeholders.

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PRE-MERGER LONG-TERM INCENTIVE PROGRAMS

General

Under the Long-Term Incentive Programs enacted prior to the Merger, the Committee recommended a long-term incentive target grant value for NU’s Chief Executive Officer as a percentage of base salary on the date of grant.  This recommendation was presented to NU’s Board of Trustees for approval.  The Committee also approved long-term incentive target grant values for each of the other NEOs as a percentage of base salary on the date of grant.  For the 2012 – 2014 Long-Term Incentive Program, adopted prior to the completion of the Merger, each grant, at target, consisted of 75 percent performance shares and 25 percent RSUs.

For the 2012 – 2014 program, the pre-merger Committee recommended to NU’s Board of Trustees a long-term incentive compensation target for NU’s Chief Executive Officer at 300 percent of base salary, which the Board approved.  The Committee established long-term incentive compensation targets at 100 percent to 150 percent of base salary for the remaining NEOs.

Up to and including 2012, of the Named Executive Officers, only Messrs. Shivery, McHale, Olivier, Butler and Muntz participated in the Northeast Utilities Long-Term Incentive Programs.  Messrs. May and Judge did not participate in these programs.  

Restricted Share Units (RSUs)

General

Each RSU granted under the long-term incentive program entitles the holder to receive one NU common share at the time of vesting.  All RSUs granted under the long-term incentive program provided for vesting in equal annual installments over three years.  RSU holders are eligible to receive reinvested dividend units on outstanding RSUs held by them to the same extent that dividends are declared and paid on our common shares.  Reinvested dividend units are accounted for as additional RSUs that accrue and are distributed with the common shares issued upon vesting and distribution of the underlying RSUs.  Common shares, including any additional common shares in respect of reinvested dividend units, are not issued for any RSUs that do not vest.

The Committee determined RSU grants for each officer participating in the long-term incentive program.  RSU grants are based on a percentage of base salary and measured in dollars.  The percentage used for each officer is based on the executive officer’s position in the Company and ranges from 5 percent to 75 percent of salary.  The Committee reserves the right to increase or decrease the RSU grant from target for each officer under special circumstances.  Based on input from NU’s Chief Executive Officer, the Committee determined the final RSU grants for each of the other executive officers, including the other NEOs.

All RSUs are granted on the date of the Committee meeting at which they are approved. RSU grants are subsequently converted from dollars into common share equivalents by dividing the value of each grant by the average closing price for NU common shares over a ten-day average price period prior to the date of the grant.

RSU Grants under the 2012 – 2014 Program

Under the pre-merger 2012 – 2014 program, the target RSU grant totaled approximately $2,567,632 for the 33 officers participating in the long-term incentive program.  The Committee did not adjust any officer’s RSU grant from target for the 2012 – 2014 program.  Accordingly, the final total RSU grant for officers, including NU’s Chief Executive Officer, was unchanged from target.  Using the ten-day average trading price and dividing the final total RSU grant by $34.52 resulted in an aggregate of 74,381 RSUs.  The following RSU grants at 100 percent of target were approved, reflected in RSUs: Mr. Shivery: 23,247; Mr. McHale: 6,051; Mr. Olivier: 6,369; Mr. Butler: 4,722; and Mr. Muntz: 3,073.  Upon his retirement, a portion of Mr. Shivery’s RSUs under this program vested pro rata based on 2012 employee service (and the remaining RSUs were forfeited).

Performance Units

General

Performance units are a performance-based component of the long-term incentive program.  A new three-year program commences every year.  To further strengthen the alignment of the performance elements with shareholders’ interests, the performance-based component of NU’s long-term incentive programs evolved from 100 percent performance cash in the 2008 – 2010 program to 100 percent performance shares beginning with the 2011 – 2013 program.

The pre-merger Committee approved the 2012 – 2014 program in early 2012.  Performance share grants are converted from dollars into common share equivalents by dividing the value of each grant by the prior ten-day average closing price for NU common shares.  During the three-year performance program period, the dividends that would have been paid with respect to the performance shares to holders of performance share grants are accounted for as additional common shares that accrue and are distributed with the common shares, if any, at the end of the program.  

Awards under the programs noted above are earned to the extent to which NU achieve goals in the four metrics described below during the three years of the program, except as reduced at the discretion of the Committee.  The Committee determines the actual awards, if

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any, only after the end of the final year in the respective program.  The four metrics used under the 2010 – 2012, 2011 – 2013 and 2012 – 2014 programs were

·

Cumulative Adjusted Net Income (20 percent)

·

Average adjusted return on equity ("ROE") (20 percent)

·

Average credit rating of NU (excluding the regulated utilities) (20 percent)

·

Relative total shareholder return of NU as compared to the return of the utility companies listed in the performance peer group (40 percent)

Before any amount is payable with respect to a metric, NU must achieve a minimum level of performance under that metric, so that in the event it does not achieve a minimum level of performance, no payment is made for that metric.  If NU achieves the minimum level of performance for any goal, then the resulting payout will equal 50 percent of the target for that goal.  If NU achieves the maximum level of performance for any goal, then the resulting payout will equal 150 percent of target for that goal.  

Set forth below are descriptions of each of the three long-term performance programs that were in effect during 2012.  

2010 – 2012 Performance Units

The Committee approved the 2010–2012 performance unit grants in early 2010, consisting of one-half performance cash and one-half performance shares.  Immediately prior to the completion of the Merger, the achievement of goals applicable to performance shares in the 2010 – 2012 program was measured up to the closing of the Merger.  The Committee determined that NU achieved goals under each of the four metrics during the 2010 – 2012 program on a pro-rata basis through April 10, 2012 and, accordingly, that awards under the program were payable at an overall level of 134 percent of target.  Payment was made following the end of 2012 (the end of the original performance period) conditioned upon continued employment through such date.  Performance shares outstanding immediately before the closing of the Merger attributable to the period from April 10, 2012 to December 31, 2012 were forfeited.  The pre-merger Committee granted to each executive officer whose performance shares were forfeited an award of RSUs with a value equal to the value of such forfeited performance units at target.

The table set forth below describes the goals under the 2010 – 2012 program and NU’s actual results during that period:

2010 – 2012 Program Goals
Goal	Minimum	Target	Maximum	Actual Results
Cumulative Adjusted Net Income ($ in millions)	$1,051.6	$1,168.4	$1,285.2	$907.6
Average Adjusted ROE	9.0%	9.9%	10.7%	10.2%
Average Credit Rating Points	1.2	1.7	2.2	1.8
Relative Total Shareholder Return (percentile)	40th	60th	80th	84th

As a result of NU’s financial performance during the shortened performance period, the Committee approved the following performance cash awards: Mr. Shivery: $1,182,674; Mr. McHale: $299,939; Mr. Olivier: $314,236; Mr. Butler: $232,534; and Mr. Muntz $152,343.  In addition, the Committee approved the following performance share awards: Mr. Shivery: 50,863 shares; Mr. McHale: 12,900 shares; Mr. Olivier: 13,514 shares; Mr. Butler: 10,000 shares; and Mr. Muntz: 6,553 shares.  In respect of performance units that were forfeited, the Committee approved the following RSU grants: Mr. Shivery: 19,405 RSUs; Mr. McHale: 4,922 RSUs; Mr. Olivier: 5,156 RSUs; Mr. Butler: 3,815 RSUs; and Mr. Muntz: 2,500 RSUs.  These awards were determined pursuant to formulas set forth in the 2010 – 2012 Long-Term Incentive Program and were not subject to the discretion of the Committee. Based upon applicable vesting schedules and due to his retirement, Mr. Shivery’s RSUs in respect of forfeited performance units fully vested.

2011 – 2013 Performance Shares

Under the 2011 – 2013 program, each performance grant consisted solely of a performance share grant.  As previously approved by the Committee, on April 10, 2012, upon completion of the Merger, all performance shares outstanding under the 2011 – 2013 program were converted to RSUs assuming a target level of performance.  These RSUs were made subject to the vesting schedule that applies to the RSU component already granted as part of the 2011 – 2013 program: Mr. Shivery: 76,530 RSUs; Mr. McHale: 19,338 RSUs; Mr. Olivier: 20,357 RSUs; Mr. Butler: 15,020 RSUs; and Mr. Muntz: 9,823 RSUs.  Based upon applicable vesting schedules and due to his retirement, Mr. Shivery’s RSUs under this program fully vested.

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2012 – 2014 Performance Shares

Under the 2012 – 2014 program, each performance grant also consisted solely of a performance share grant.  As previously approved by the Committee, on April 10, 2012, upon completion of the Merger, all performance shares outstanding under the 2012 – 2014 program were converted to RSUs assuming a target level of performance.  These RSUs were made subject to the vesting schedule that applies to the RSU component already granted as part of the 2012 – 2014 program: Mr. Shivery: 70,294 RSUs; Mr. McHale: 18,296 RSUs; Mr. Olivier: 19,259 RSUs; Mr. Butler: 14,279 RSUs; and Mr. Muntz: 9,293 RSUs. Upon his retirement, a portion of Mr. Shivery’s RSUs under this program vested pro rata based on 2012 employee service (and the remaining RSUs were forfeited).

OTHER

Retirement Benefits

Retirement Benefits for certain legacy NU employees, including Messrs. Shivery, McHale, Olivier, Butler and Muntz.  NU provides a qualified defined benefit pension plan for certain legacy NU employees, including Mr. Shivery, who retired in 2012, and Messrs. McHale, Olivier, Butler and Muntz, which is a final average pay plan subject to tax code limits.  Because of such limits, NU also maintains a supplemental non-qualified pension plan (Northeast Utilities Supplemental Plan) for certain legacy NU executives, including Messrs. Shivery, who retired in 2012, McHale, Butler and Muntz.  Benefits under this Plan are based on base pay over tax code limits, deferred base salary and certain annual and long-term incentives, which is consistent with the goal of providing a benefit that replaces a percentage of pre-retirement income.  This plan provides a make-whole benefit that compensates for benefits lost due to tax code limits, plus a target benefit that varies based on officer service.  The target benefit ensures that upon reaching 25 years of service, total retirement benefits will equal a target percentage of final average compensation.  The target benefit is available to those reaching age 60 with five years of employment with NU.  Mr. Butler is (and Mr. Shivery was, upon retirement) eligible for a 60% percent target benefit.  Mr. McHale (whose officer service began later) is eligible for a 50 percent target benefit.  

Mr. Olivier’s employment agreement provides retirement benefits similar to those of a previous employer instead of the Supplemental Plan benefits described above.  Under this agreement, he will receive a pension based on a prescribed formula if he meets certain eligibility requirements.  Mr. Shivery’s employment agreement provided for a special retirement benefit determined using the Supplemental Plan target benefit formula plus three years of service.  Messrs. McHale, Olivier and Butler are also eligible to receive certain taxable health and welfare benefits in certain circumstances.  Mr. Muntz’s employment agreement includes, depending on his age at termination of employment, a special annual retirement benefit calculated using certain service credits and offset amounts.   

Retirement Benefits for certain legacy NSTAR employees, including Messrs. May and Judge.  NU offers certain legacy NSTAR employees, including Messrs. May and Judge, the opportunity to participate in the NSTAR qualified defined benefit pension plan.  This is a final average pay plan subject to tax code limits.  Because of such limits, NU also maintains two supplemental non-qualified programs for these and certain other executives.  The plans make up for benefits barred by such limits and provide (together with the qualified pension plan) benefits for vested participants equal to 60 percent of pre-retirement compensation (reduced by the value of 50 percent of primary Social Security benefits).  Benefits are based on base salary and annual cash incentive payments, which is consistent with the goal of providing a retirement benefit that replaces a percentage of pre-retirement income.  

See the narrative accompanying the "Pension Benefits" table and accompanying notes for more detail on the above plans.

401K Plan

401(k) Plan Benefits for certain legacy NU employees, including Messrs. Shivery, McHale, Olivier, Butler and Muntz.  NU provides the Northeast Utilities qualified 401(k) savings plan for eligible legacy NU employees, including Messrs. Shivery, McHale, Olivier, Butler and Muntz.  Under this plan, NU matches up to 3 percent of base salary, one-third of which match is made in cash available for investment in various fund alternatives, and two-thirds of which is made in common shares (ESOP shares), subject to tax code limits.  

401(k) Plan Benefits for certain legacy NSTAR employees, including Messrs. May and Judge.  NU provides the NSTAR qualified 401(k) savings plan for certain eligible legacy NSTAR employees, including Messrs. May and Judge.  Under this plan, NU matches 50 percent of the first 8 percent of eligible base salary and annual cash incentive contributed, subject to tax code limits.   

Deferred Compensation

Deferred Compensation Plan Benefits for certain legacy NU executives, including Messrs. Shivery, McHale, Olivier, Butler and Muntz.  NU maintains an unfunded non-qualified deferred compensation plan for certain legacy NU executives, including Messrs. Shivery, McHale, Olivier, Butler and Muntz.  This plan permits deferral of up to 100 percent of base salary and annual incentives, which may be invested in the same deemed investments as the qualified plan (except Company shares).  NU matches deferrals up to a maximum of 3 percent of base salary in excess of the tax code limit of $250,000.  The match is deemed invested in NU common shares and generally vests in three years.  

Deferred Compensation Plan Benefits for certain legacy NSTAR executives, including Messrs. May and Judge.  NU maintains a non-qualified deferred compensation plan for eligible legacy NSTAR executives, including Messrs. May and Judge.  This plan permits deferral of up to 50 percent of base salary and all annual incentive payments and stock incentive awards.  Participants may establish

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investment measurements based on a wide range of publicly available individual securities and mutual funds.  The Company maintains a Rabbi Trust and replicates all investment elections with actual investments.

See the Non-qualified Deferred Compensation Table and accompanying notes for additional details on the above plans.

Perquisites

NU provides financial planning, health services, vehicle leasing, access to tickets to sporting events and limited perquisites that it believes are consistent with peer companies.  The current level of perquisites does not factor into decisions on total compensation.

CONTRACTUAL AGREEMENTS

NU maintains contractual agreements with all of the Named Executive Officers that provide for potential compensation in the event of certain terminations following a Change in Control.  The agreements are consistent with general industry practice, and NU believes they are necessary to attract and retain high quality executives and to ensure executive focus on NU’s business during the period leading up to a potential Change in Control.  With respect to the "double-trigger" agreements allowing voluntary termination for "good reason," NU believes this form of agreement provides executives with compensation in the event of a Change in Control, while still providing an incentive to remain employed for the transition period that follows.  

Our agreements with Messrs. McHale, Olivier, Butler and Muntz provide for compensation in the event of a Change in Control followed by involuntary termination of employment (other than for cause) or voluntary termination for "good reason" during the applicable period.  The 2012 merger did not constitute a change in control under the agreements with Messrs. Butler and McHale.  Mr. Shivery’s change of control provisions expired in 2011 when he reached age 65, and he retired in 2012.  These agreements are described more fully below under "Potential Payments Upon Termination or Change in Control."

For Messrs. May and Judge and other eligible legacy NSTAR executives, NU maintains Change in Control agreements.  Severance benefits are payable if, within 24 months following a change in control, the executive is involuntarily terminated (other than for cause) or voluntarily terminates employment for "good reason."  These agreements are described more fully below under "Potential Payments upon Termination or Change in Control."

SHARE OWNERSHIP GUIDELINES

On January 10, 2013, the Committee approved revised share ownership guidelines to further emphasize the importance of share ownership by certain executive officers.  The guidelines call for NU’s Chief Executive Officer to own common shares equal to six times base salary, the other senior executive officers to own a number of common shares equal to three times base salary and all other officers to own a number of common shares equal to one to two times base salary.

Executive Officer	Base Salary Multiple
Chief Executive Officer	6
Executive Vice Presidents / Senior Vice Presidents	3
Operating Company Presidents	2
Vice Presidents	1-1.5

NU requires that executive officers attain these ownership levels within five years.  All executive officers, including the Named Executive Officers, have satisfied the share ownership guidelines or are expected to satisfy them within the applicable timeframe.  Common shares, whether held of record, in street name, or in individual 401(k) accounts, and RSUs satisfy the guidelines.  Unexercised stock options and unvested performance shares do not count toward the ownership guidelines.

TAX AND ACCOUNTING CONSIDERATIONS

NU’s annual and long-term incentive plans were approved by shareholders and 2012 annual incentive and performance share awards under those plans were structured to qualify as performance-based compensation under Section 162(m) of the Internal Revenue Code.  However, NU believes that the availability of a tax deduction for other forms of compensation is secondary to the goal of providing market-based compensation to attract and retain highly qualified executives.  In addition, NU’s compensation program plans were amended in 2008 to comply with Section 409A of the Internal Revenue Code.  

NU has adopted the provisions of Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) Topic 718, Compensation-Stock Compensation.  In general, NU and the Committee do not take accounting considerations into account in structuring compensation arrangements.

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EQUITY GRANT PRACTICES

Equity awards noted in the compensation tables are made at the February meeting of the Compensation Committee (subject to the further approval of the Board of Trustees of the Chief Executive Officer’s award) when the Committee also determines base salary, annual and long term incentive compensation targets and annual incentive awards. The date of this meeting is chosen several months in advance, and therefore awards are not coordinated with the release of material non-public information.

SUMMARY COMPENSATION TABLE

The table below summarizes the total compensation paid or earned by CL&P’s NEOs, consisting of our principal executive officer (Mr. Olivier), principal financial officer (Mr. Judge) and former principal financial officer (Mr. McHale), the three other most highly compensated executive officers serving at the end of 2012 (Messrs. May, Butler and Muntz), and CL&P’s former Chairman, Mr. Shivery, who would have been one of the three other most highly compensated executive officers if he had been serving as CL&P’s Chairman at the end of 2012, determined in accordance with the applicable SEC disclosure rules.  The table provides information for 2011 and 2010 if the executive officer was included in the Summary Compensation Table for those years.  For Messrs. May and Judge, the disclosure pertains to each of their compensation subsequent to the Merger.  As explained in the footnotes below, the amounts reflect the economic benefit to each Named Executive Officer of the compensation item paid or accrued on his behalf for the fiscal year ended December 31, 2012.  The compensation shown for each Named Executive Officer was for all services in all capacities to NU and its subsidiaries.  All salaries, annual incentive amounts and long-term incentive amounts shown for each Named Executive Officer were paid for all services rendered to NU and its subsidiaries, including CL&P, in all capacities.

Name and Principal Position	Year	Salary ($) (4)	Bonus ($) (5)	Stock Awards ($) (6)	Option Awards ($) (7)	Non-Equity Incentive Plan Compensation ($) (8)	Change in Pension Value and Non- Qualified Deferred Compensation Earnings ($) (9)	All Other Compen-sation ($) (10)	Total ($)
Charles W. Shivery (1)	2012	475,327	—	3,245,316	—	1,753,067	798,572	9,506	6,281,788
Chairman of the Board of NU; former President and CEO of NU; former Chairman of CL&P	2011	1,063,270	—	5,780,091	—	1,552,500	1,158,298	31,898	9,586,057
	2010	1,035,000	—	1,905,964	—	3,757,050	1,525,310	31,050	8,254,374
Thomas J. May (2)	2012	822,414	—		—	2,100,000	1,232,395	52,220	4,207,029
President and CEO of NU; Chairman of CL&P
David R. McHale	2012	553,853	—	844,685	—	939,939	1,127,536	16,915	3,482,928
Executive Vice President and Chief Administrative Officer; former Executive Vice President and Chief Financial Officer	2011	537,721	—	810,080	—	393,750	798,025	16,132	2,555,708
	2010	525,000	—	2,484,707	—	1,036,017	934,059	15,750	4,995,533
James J. Judge (2)	2012	401,215	—		—	640,000	1,097,100	6,601	2,144,916
Executive Vice President and Chief Financial Officer
Leon J. Olivier	2012	583,043	—	889,147	—	974,236	887,046	17,491	3,350,963
Executive Vice President and Chief Operating Officer of NU; CEO of CL&P	2011	565,548	—	852,791	—	412,500	724,796	16,966	2,572,601
	2010	550,000	—	2,007,381	—	982,682	699,343	16,500	4,255,906
Gregory B. Butler	2012	431,885	—	659,226	—	727,534	764,758	7,500	2,590,903
Senior Vice President and General Counsel	2011	417,508	—	629,234	—	305,241	553,436	7,350	1,912,769
	2010	406,988	—	1,875,695	—	806,295	472,066	7,350	3,568,394
James A. Muntz (3)	2012	421,983	—	429,026	—	610,643	750,477	12,659	2,224,788
Senior Vice President – Transmission

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(1)

Mr. Shivery retired as President and CEO of NU and Chairman of CL&P upon the completion of the Merger on April 10, 2012.  Mr. Shivery currently serves as the non-executive Chairman of the Board of NU. The compensation information for Mr. Shivery includes his compensation as Chairman of the Board of NU for the period from April 10, 2012 through December 31, 2012.

(2)

Messrs. May and Judge became Named Executive Officers for NU and CL&P upon the completion of the Merger on April 10, 2012.  They were not executive officers of NU or CL&P in 2011 or 2010.  The compensation information for Messrs. May and Judge reflects compensation for the period from April 10, 2012 through December 31, 2012.

(3)

Mr. Muntz did not meet the requirements for inclusion in the Summary Compensation Table and was not a Named Executive Officer for 2011 or 2010.  Mr. Muntz became a Named Executive Officer in 2012.  

(4)

Includes amounts deferred in 2012 under the Deferral Plan, as follows: Mr. Olivier: $116,608, Mr. Muntz: $274,289, Mr. Shivery: $9,506; Mr. McHale: $9,415.  For more information, see the Executive Contributions in the Last Fiscal Year column of the Non-Qualified Deferred Compensation Plans Table.

(5)

No discretionary bonus awards were made to any of the Named Executive Officers in the fiscal years ended 2010, 2011 and 2012.

(6)

Reflects the aggregate grant date fair value of restricted share units (RSUs) and performance shares granted in each fiscal year, calculated in accordance with FASB ASC Topic 718.

In 2010, 2011 and 2012, certain Named Executive Officers were granted RSUs that vest in equal annual installments over three years as long-term incentive compensation.  NU deferred the distribution of common shares upon vesting of RSUs granted to Mr. Shivery until 2013, the calendar year after the year in which his employment terminated.  RSU holders are eligible to receive dividend equivalent units on outstanding RSUs held by them to the same extent that dividends are declared and paid on NU common shares.  Dividend equivalent units are accounted for as additional common shares that accrue and are distributed simultaneously with the common shares issued upon vesting of the underlying RSUs.

In 2012, certain Named Executive Officers were granted performance shares as long-term compensation.  These performance shares would have vested on December 31, 2014, based on the extent to which four performance conditions would have been achieved.  The grant date values for the performance shares, assuming achievement of the highest level of all four performance conditions, were as follows: Mr. Shivery: $3,650,993; Mr. McHale: $950,257; Mr. Olivier: $1,000,303; Mr. Butler: $741,642; and Mr. Muntz: $482,667.  However, as previously approved by the Committee, on April 10, 2012, upon completion of the Merger, all performance shares outstanding under the 2012 – 2014 program were converted to RSUs assuming a target level of performance.  These RSUs generally vest according to the schedule that applies to the RSU component already granted as part of the 2012 – 2014 program, except that a portion of Mr. Shivery’s RSUs vested upon his retirement pro rata based on 2012 employee service (and the remaining RSUs were forfeited): Mr. Shivery: 70,294 RSUs; Mr. McHale: 18,296 RSUs; Mr. Olivier: 19,259 RSUs; Mr. Butler: 14,279 RSUs; and Mr. Muntz: 9,293 RSUs.

(7)

NU did not grant stock options to any of the Named Executive Officers in 2012.  NU has not granted any stock options since 2002.

(8)

Includes payments to the Named Executive Officers under the 2012 Annual Incentive Program (Mr. Shivery: $570,393; Mr. May; $2,100,000; Mr. McHale: $640,000; Mr. Judge; $640,000; Mr. Olivier: $660,000; Mr. Butler: $495,000; and Mr. Muntz: $458,300).  Also includes performance cash payments under the 2010 – 2012 Long-Term Incentive Program (Mr. Shivery: $1,182,674; Mr. McHale: $299,939; Mr. Olivier: $314,236; Mr. Butler: $232,534; and Mr. Muntz: $152,343).  In April 2012, upon completion of the Merger, the achievement of goals applicable to performance units in the 2010 – 2012 program was measured up to the completion of the Merger.

(9)

Includes the actuarial increase in the present value from December 31, 2011 to December 31, 2012 of the Named Executive Officer’s accumulated benefits under all of the defined benefit pension plans determined using interest rate and mortality rate assumptions consistent with those appearing under the caption entitled "Management’s Discussion and Analysis and Results of Operations" in this Annual Report on Form 10-K.  The Named Executive Officer may not be fully vested in such amounts.  More information on this topic is set forth in the notes to the Pension Benefits table, appearing further below.  There were no above-market earnings on deferrals in 2012.

(10)

Includes matching contributions of $7,500 allocated by us to the account of each of the Named Executive Officers under the 401k Plan; and employer matching contributions under the Deferral Plan for the Named Executive Officers who made deferral elections in late 2011 for salary earned in 2012 (Mr. Olivier: $9,991; Mr. Muntz: $5,159; Mr. Shivery: $2,006; and Mr. McHale: $9,115).  Mr. Butler did not participate in the Deferral Plan in 2012.  For Mr. May, the value shown includes $58,742 attributable to a previously granted $6.155 million present value life insurance benefit; financial planning services valued at $6,400; health services valued at $6,400; and $8,779 paid by the Company for Company-leased vehicles.  These perquisites are made available to senior executives, however, none of the other Named Executive Officer received perquisites valued in the aggregate in excess of $10,000.

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GRANTS OF PLAN-BASED AWARDS DURING 2012

The Grants of Plan-Based Awards Table provides information on the range of potential payouts under all incentive plan awards during the fiscal year ended December 31, 2012.  The table also discloses the underlying stock awards and the grant date for equity-based awards.  NU has not granted any stock options since 2002.

		Estimated Future Payouts Under Non-Equity Incentive Plan Awards			Estimated Future Payouts Under Equity Incentive Plan Awards (1)
Name	Grant Date	Threshold ($)	Target ($)	Maximum ($)	Threshold ($)	Target (#)	Maximum (#)	All Other Stock Awards: Number of Shares of Stock or Units (#) (2)	Grant Date Fair Value of Stock and Option Awards ($) (3)
Charles W. Shivery
Annual Incentive (4)	2/14/2012	535,000	1,070,000	2,140,000	—	—	—	—	—
Long-Term Incentive (5)	2/14/2012	—	—	—	—	69,742	104,613	23,247	3,245,316
Thomas J. May
Annual Incentive (4)	—	—	—	—	—	—	—	—	—
Long-Term Incentive (5)	—	—	—	—	—	—	—	—	—
David R. McHale
Annual Incentive (4)	2/14/2012	180,002	360,005	720,009	—	—	—	—	—
Long-Term Incentive (5)	2/14/2012	—	—	—	—	18,152	27,228	6,051	844,685
James J. Judge
Annual Incentive (4)	—	—	—	—	—	—	—	—	—
Long-Term Incentive (5)	—	—	—	—	—	—	—	—	—
Leon J. Olivier
Annual Incentive (4)	2/14/2012	184,489	378,978	757,957	—	—	—	—	—
Long-Term Incentive (5)	2/14/2012	—	—	—	—	19,108	28,662	6,369	889,147
Gregory B. Butler
Annual Incentive (4)	2/14/2012	140,363	280,725	561,451	—	—	—	—	—
Long-Term Incentive (5)	2/14/2012	—	—	—	—	14,167	21,251	4,722	659,226
James A. Muntz
Annual Incentive (4)	2/14/2012	105,496	210,992	421,983	—	—	—	—	—
Long-Term Incentive (5)	2/14/2012	—	—	—	—	9,220	13,830	3,073	429,026

(1)

Reflects the number of performance shares granted to each of the Named Executive Officers on February 14, 2012 under the 2012 – 2014 Long-Term Incentive Program.  Performance shares were granted with a three-year Performance Period that would have ended on December 31, 2014.  However, upon the completion of the Merger, all performance shares outstanding under the 2012 — 2014 program were converted to RSUs assuming a target level of performance.  These RSUs will vest according to the schedule that applies to the RSU component already granted as part of the 2012 — 2014 program.  For Mr. Shivery, a pro rata portion of his converted RSUs (based on 2012 employee service) vested upon his retirement, and his remaining converted RSUs were forfeited.

(2)

Reflects the number of RSUs granted to each of the Named Executive Officers on February 14, 2012 under the 2012 – 2014 Long-Term Incentive Program.  RSUs generally vest in equal installments on February 25, 2013, 2014 and 2015.  NU will distribute common shares in respect to vested RSUs on a one-for-one basis immediately upon vesting, after reduction for applicable withholding taxes, except for Mr. Shivery.  For Mr. Shivery, a portion of his RSUs under this Program vested pro rata (based on 2012 employee service) and the remaining RSUs were forfeited.  Accordingly, Mr. Shivery became entitled to a distribution of such common shares (after reduction for applicable withholding taxes) in respect of vested RSUs in three approximately equal annual installments beginning in January 2013 (January of the calendar year after he retired).  Holders of RSUs are eligible to receive dividend equivalent units on outstanding RSUs held by them to the same extent that dividends are declared and paid on NU common shares.  Dividend equivalent units are accounted for as additional common shares that accrue and are distributed simultaneously with the common shares distributed in respect of the underlying RSUs.  The Annual Incentive Program does not include an equity component.

(3)

Reflects the grant-date fair value, determined in accordance with FASB ASC Topic 718, of: (i) RSUs and performance shares granted to the Named Executive Officers on February 14, 2012, under the 2012 – 2014 Long-Term Incentive Program.  The Annual Incentive Program does not include an equity component.

(4)

Amounts reflect the range of potential payouts, if any, under the 2012 Annual Incentive Program for each Named Executive Officer, as described in the Compensation Discussion and Analysis.  The payment in 2013 for performance in 2012 is set forth in the Non-Equity Incentive Plan Compensation column of the Summary Compensation Table.  The threshold payment under

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the Annual Incentive Program is 50 percent of target.  However, based on Adjusted Net Income and individual performance, the actual payment under the Annual Incentive Program could be zero.

(5)

Reflects the range of potential payouts, if any, pursuant to performance share awards under the 2012 – 2014 Long-Term Incentive Program, as described in the Compensation Discussion and Analysis.

EQUITY GRANTS OUTSTANDING AT DECEMBER 31, 2012

The following table sets forth option and RSU grants outstanding at the end of our fiscal year ended December 31, 2012 for each of the Named Executive Officers. All outstanding options were fully vested as of December 31, 2012.

	Option Awards (1)			Stock Awards (2)
Name	Number of Securities Underlying Unexercised Options Exercisable (#)	Option Exercise Price ($)	Option Expiration Date	Number of Shares or Units of Stock that have not Vested (#) (3)	Market Value of Shares or Units of Stock that have not Vested ($)(4)	Equity Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights That Have Not Vested (#)	Equity Incentive Plan Awards: Market or Payout Value of Unearned Shares, Units or Other Rights That Have Not Vested ($)
Charles W. Shivery	—	—	—	81,601	3,188,967	—	—
Thomas J. May	262,400	21.14	4/27/2016	—	—	—	—
	244,032	28.12	5/3/2017	—	—	—	—
	196,800	24.74	1/24/2018	—	—	—	—
	208,608	25.93	1/22/2019	—	—	—	—
	174,496	26.90	1/28/2020	168,373	6,580,017	—	—
David R. McHale	—	—	—	119,587	4,673,456	—	—
James J. Judge	—	—	—	108,720	4,248,778	—	—
Leon J. Olivier	—	—	—	104,951	4,101,485	—	—
Gregory B. Butler	—	—	—	91,120	3,560,970	—	—
James A. Muntz	—	—	—	36,893	1,441,778	—	—

(1)

Options held by Messrs. May and Judge were granted by NSTAR prior to the completion of the Merger and assumed by NU upon the completion of the Merger.

(2)

Awards and market values of awards appearing in the table and the accompanying notes have been rounded to whole units.

(3)

An additional 83,573 unvested RSUs vested on February 25, 2013 (Mr. McHale: 25,050; Mr. Olivier: 26,327; Mr. Butler: 19,475; and Mr. Muntz: 12,721).  An additional 57,344 unvested RSUs will vest on February 25, 2014 (Mr. McHale: 17,175; Mr. Olivier: 18,077; Mr. Butler: 13,370; and Mr. Muntz: 8,722).  An additional 27,893 unvested RSUs will vest on February 25, 2015 (Mr. McHale: 8,349; Mr. Olivier: 8,788; Mr. Butler: 6,516; and Mr. Muntz: 4,240).

In 2011, the NU Board of Trustees approved a special grant of 76,406 RSUs to Mr. Shivery to recognize the critical role he had in the successful leadership of NU through the close of the Merger, and the role he will play as NU’s non-executive Chairman of the Board during the post-merger integration period.  These RSUs, plus accrued dividend equivalents, totaled 81,601 RSUs at December 31, 2012. The RSUs will vest eighteen months after the completion of the Merger, coinciding with Mr. Shivery’s commitment to remain as NU’s non-executive Chairman of the Board through that date.  If Mr. Shivery dies or becomes disabled prior to the vesting date, then the RSUs will vest as of the date of death or disability.  If Mr. Shivery does not serve on the NU Board through eighteen months after the completion of the Merger, then the RSUs will be forfeited.

In connection with the Merger, in November 2010, NU and NSTAR each established retention pools in an aggregate amount of $10 million to be allocated to key employees, including some or all executive officers, to help ensure their continued dedication to each company both before and after completion of the Merger.  Awards were in the form of RSUs and generally vest subject to three years of continuous service following completion of the merger.  Full payment will also be made if an participating executive dies, becomes disabled, or is terminated by NU without "cause" before the end of the retention period, in which case the retention payment will be reduced by the amount of any cash severance payable to the executive upon or during the year following termination.  Awards granted to former NSTAR executive officers were assumed by NU upon the completion of the Merger.  An additional 242,853 unvested RSUs granted pursuant to the retention pools will vest subject to three years of continuous service following completion of the Merger (Mr. McHale: 69,012; Mr. Judge: 70,323; Mr. Olivier: 51,759; Mr. Butler: 51,759).  Mr. Muntz did not participate in this program.

Mr. Muntz’s total includes 11,210 unvested RSUs from a special grant in 2008.

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(4)

The market value of RSUs is determined by multiplying the number of RSUs by $39.08, the closing price per share of NU common shares on December 31, 2012, the last trading day of the year.

OPTIONS EXERCISED AND STOCK VESTED IN 2012

The following table reports amounts realized on equity compensation during the fiscal year ended December 31, 2012.  The Stock Awards columns report the vesting of RSU grants to the Named Executive Officers in 2012.

	Option Awards		Stock Awards
Name	Number of Shares Acquired on Exercise (#)	Value Realized on Exercise ($) (1)	Number of Shares Acquired on Vesting (#) (2)	Value Realized on Vesting ($) (3)
Charles W. Shivery	29,024	507,833	185,718	6,624,561
Thomas J. May	524,800	9,990,611	88,482	3,255,253
David R. McHale	—	—	14,381	512,970
James J. Judge	179,744	2,332,854	19,688	724,322
Leon J. Olivier	—	—	15,110	538,974
Gregory B. Butler	—	—	11,163	398,184
James A. Muntz	—	—	7,305	260,569

(1)

Represents the amounts realized upon option exercises, which is the difference between the option exercise price and the market price at the time of exercise.

(2)

Includes RSUs granted to the Named Executive Officers under our long-term incentive programs, including dividend reinvestments, as follows:

Name	2009 Program	2010 Program	2011 Program	2012 Program
Charles W. Shivery *	12,567	42,009	104,775	26,367
David R. McHale	3,079	2,727	8,575	—
Leon J. Olivier	3,226	2,856	9,028	—
Gregory B. Butler	2,387	2,113	6,663	—
James A. Muntz	1,564	1,385	4,356	—

*

Mr. Shivery’s unvested RSUs under the 2010 and 2011 Programs fully vested upon his retirement.  His unvested RSUs under the 2012 Program vested upon his retirement pro rata based on 2012 employee service(and his remaining RSUs under this program were forfeited).  

In all cases, the distribution of common shares is reduced by that number of shares valued in an amount sufficient to satisfy tax withholding obligations, which amount is distributed in cash.  Included in the value realized are values associated with deferred RSUs, which are also reported in the Registrant Contributions in Last Fiscal Year column of the Non-Qualified Deferred Compensation Table.

(3)

Values realized on vesting for Messrs. Shivery, McHale, Olivier, Butler and Muntz are based on $35.67 per share, the closing price of NU common shares on February 27, 2012.  Values realized by Messrs. May and Judge on vesting for awards are based on $36.79 per share, the closing price of NU common shares on April 9, 2012.

PENSION BENEFITS IN 2012

The Pension Benefits Table shows the estimated present value of accumulated retirement benefits payable to each Named Executive Officer upon retirement based on the assumptions described below.  The table distinguishes between benefits available under the Retirement Plans, the Supplemental Plans, and any additional benefits available under contractual agreements.  See the narrative above in the Compensation Discussion and Analysis under the heading "ELEMENTS OF 2012 COMPENSATION - OTHER- Retirement Benefits" and "ELEMENTS OF 2012 COMPENSATION - CONTRACTUAL AGREEMENTS" for more detail on benefits under these plans and our agreements.  

The values shown in the Pension Benefits Table for Messrs. Shivery, McHale, Butler and Muntz were calculated as of December 31, 2012, based on benefit payments in the form of a one-half spousal contingent annuitant option.  For Mr. Olivier, NU assumed a lump sum payment of his special retirement benefits under his agreement, and payment of his Retirement Plan benefit as a life annuity with a one-third spousal contingent annuitant option (the typical payment form under that Plan).  For Messrs. May and Judge, NU assumed a lump sum payment of benefits.  

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The values shown in this Table for Messrs. Shivery, McHale, Olivier, Butler and Muntz were based on benefit payments commencing at the earliest possible ages for retirement with unreduced benefits:  Mr. Shivery:  age 65, Mr. May:  age 60, Mr. McHale:  age 60, Mr. Judge:  age 60, Mr. Olivier:  age 60, Mr. Butler:  age 62, and Mr. Muntz:  age 65.  

In addition, NU determined benefits under the Retirement Plans using tax code limits in effect on December 31, 2012.  For Messrs. Shivery, McHale, Butler and Muntz, the values shown reflect actual 2012 salary and annual incentives earned in 2012 but paid in 2013 (per applicable Supplemental Plan rules).  For Messrs. May and Judge, the values shown reflect actual 2012 salary and annual incentives earned in 2011 but paid in 2012 (per applicable Supplemental Plan rules).  

The present value of benefits at retirement age were determined using the discount rate of 4.24 percent (4.13 percent for Messrs. May and Judge) under Statement of Financial Accounting Standards No. 87 for the 2012 fiscal year end measurement (as of December 31, 2012).  This present value assumes no pre-retirement mortality, turnover or disability.  However, for the postretirement period beginning at retirement age, NU used the RP2000 Combined Healthy mortality table as published by the Society of Actuaries projected to 2012 with projection scale AA (same table used for financial reporting under FAS 87).  Additional assumptions appear under the caption entitled "Management’s Discussion and Analysis and Results of Operations" in this Annual Report on Form 10-K.

Name	Plan Name	Number of Years Credited Service (#)	Present Value of Accumulated Benefit ($)	Payments During Last Fiscal Year ($)
Charles W. Shivery	Retirement Plan	9.9	430,006	32,670
	Supplemental Plan	9.9	8,202,235	823,860
	Supplemental Plan	12.9	2,611,215	—
Thomas J. May	Retirement Plan	36.5	2,363,362	—
	Supplemental Plan	20.0	8,429,400	—
	Supplemental Plan	36.5	12,262,137	—
David R. McHale	Retirement Plan	31.3	1,185,744	—
	Supplemental Plan	31.3	4,330,824	—
James Judge	Retirement Plan	35.3	2,285,615	—
	Supplemental Plan	20.0	3,885,648	—
	Supplemental Plan	35.3	1,930,576	—
Leon J. Olivier (1)	Retirement Plan	13.8	607,957	—
	Supplemental Plan	11.3	3,840,312	—
	Special Retirement Benefit	31.2	1,337,988	105,966
Gregory B. Butler	Retirement Plan	15.0	578,141	—
	Supplemental Plan	15.0	1,641,663	—
James A. Muntz (2)	Retirement Plan	11.1	326,101	—
	Supplemental Plan	11.1	792,692	—
	Special Retirement Benefit	32.1	1,721,837	—

(1)

Mr. Olivier was employed with Northeast Nuclear Energy Company, a subsidiary of NU, from October of 1998 through March of 2001.  In connection with this employment, he received a special retirement benefit that provided credit for service with his previous employer, Boston Edison Company (BECO), when calculating the value of his defined benefit pension, offset by the pension benefit provided by BECO.  The benefit, which commenced upon Mr. Olivier’s 55th birthday, provides an annuity of $105,966 per year in a form that provides no contingent annuitant benefit.  The present value of future payments under this benefit was calculated using the actuarial assumptions currently used by the Retirement Plan.  Mr. Olivier was rehired by NU from Entergy in September 2001.  Mr. Olivier’s current employment agreement provides for certain supplemental pension benefits in lieu of benefits under the Supplemental Plan, in order to provide a benefit similar to that provided by Entergy.  Under this arrangement, Mr. Olivier became eligible during 2011 to receive a special benefit, subject to reduction for termination prior to age 65, consisting of three percent of final average compensation for each of his first 15 years of service since September 10, 2001, plus one percent of final average compensation for each of the second 15 years of service.  Alternatively, if Mr. Olivier voluntarily terminates his employment with NU, he is eligible to receive upon retirement a lump sum payment of $2,050,000 in lieu of benefits under the Supplemental Plan and the benefit described in the preceding sentence.  These supplemental pension benefits will be offset by the value of any benefits he receives from the Retirement Plan.  Amounts reported in the table assume the termination of his employment with NU’s consent on December 31, 2012, and payment of the lump sum benefit of $3,214,047 offset by Retirement Plan benefits.

(2)

Mr. Muntz’s actual service with NU totaled 11 years at December 31, 2012.  However, Mr. Muntz’s employment agreement provides that upon reaching age 55 (which occurred in December 2012), he is entitled to a special annual retirement benefit in the event his employment terminates for any reason other than for cause.  This special annual benefit confers credit upon

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Mr. Muntz for 21 years of service with his previous employer, Exelon Corporation (Exelon), when calculating his pension, and offsets the resulting benefit by:  (i) an amount approximating his annual Exelon pension benefit, and (ii) the benefit otherwise payable from the Retirement and Supplemental Plans excluding such additional service credit.  This special annual benefit provides for an annuity payable at the same time and in the same form as his Retirement or Supplemental Plan benefit (as applicable).  

NONQUALIFIED DEFERRED COMPENSATION IN 2012

See the narrative above in the Compensation Discussion and Analysis under the heading “ELEMENTS OF 2012 COMPENSATION - OTHER- Deferred Compensation” for more detail on our non-qualified deferred compensation plans.  

Name	Executive Contributions in Last FY ($) (1)	Registrant Contributions in Last FY ($) (2)	Aggregate Earnings in Last FY ($)	Aggregate Withdrawals/ Distributions ($) (3)	Aggregate Balance at Last FYE ($) (4)
Charles W. Shivery	6,554,466	24,824	499,253	(1,473,906)	21,668,219
Thomas J. May	—	—	4,819,673	—	39,319,830
David R. McHale	9,415	9,115	10,433	—	158,561
James J. Judge	—	—	85,302	(1,784,441)	2,987,205
Leon J. Olivier	116,608	9,091	244,097	(19,197)	1,904,158
Gregory B. Butler	—	—	4,644	(15,940)	119,982
James A. Muntz	274,289	5,159	487,333	(657,621)	3,891,645

(1)

Includes deferrals under the Deferral Plans (Mr. Shivery: $6,554,466; Mr. McHale: $9,415; Mr. Olivier: $116,608; and Mr. Muntz: $274,289).  Named Executive Officers who participate in the Deferral Plans are provided with a variety of investment opportunities, which the individual can modify and reallocate at any time.  Contributions by the Named Executive Officer are vested at all times; however, the applicable employer matching contribution vests after three years and will be forfeited if the executive’s employment terminates, other than for retirement, death or disability, prior to vesting, but will become fully vested upon a change of control.  The amounts reported in this column for each Named Executive Officer are reflected as compensation to such Named Executive Officer in the Summary Compensation Table.

With respect to Mr. Shivery, other amounts relate to the value of RSUs automatically deferred under the terms of our long-term incentive programs, calculated using the closing prices of NU common shares on the applicable February 27 and April 10, 2012 vesting dates ($35.67 per share and $35.91 per share, respectively).  For more information, see the footnotes to the Options Exercised and Stock Vested table.  

(2)

Includes employer matching contributions made to the applicable Deferral Plan as of December 31, 2012 and posted on January 31, 2012, as reported in the All Other Compensation column of the Summary Compensation Table, except for Mr. Shivery, who received matching contributions through his retirement date (April 10, 2012): (Mr. Shivery: $24,824; Mr. McHale: $9,115; Mr. Olivier: $9,091; and Mr. Muntz: $5,159).  The employer matching contribution is deemed to be invested in common shares but is paid in cash at the time of distribution.  

(3)

Includes distributions to under the applicable Deferral Plan during fiscal year 2012 pursuant to their deferral elections, plus the value of previously vested deferred RSUs or other awards distributed in 2012 pursuant to deferral schedules, valued for Mr. Shivery at the closing price of NU common shares on his October 12, 2012 distribution date ($38.68 per share).   

(4)

Includes the total market value of Deferral Plan balances at December 31, 2012, plus the value of vested RSUs or other awards for which the distribution of common shares is currently deferred, based on $39.08, the closing price of NU common shares on December 31, 2012, the last trading day of the year.  The aggregate balances reflect a significant level of earnings on previously earned and deferred compensation.

POTENTIAL PAYMENTS UPON TERMINATION OR CHANGE OF CONTROL

Generally, a "change of control" means a change in ownership or control of NU effected through (i) the acquisition of 20 percent or more of the combined voting power of common shares or other voting securities (30 percent for Messrs. May and Judge, excluding certain defined transactions), (ii) the acquisition of more than 50 percent of common shares excluding certain defined transactions (for Messrs. May and Judge), (iii) a change in the majority of NU’s Board of Trustees, unless approved by a majority of the incumbent Trustees, (iv) certain reorganizations, mergers or consolidations where substantially all of the persons who were the beneficial owners of the outstanding common shares immediately prior to such business combination do not beneficially own more than 50 percent (75 percent for Mr. Olivier and Muntz) of the voting power of the resulting business entity (excluding in certain cases defined transactions), and (v) complete liquidation or dissolution of NU, or a sale or disposition of all or substantially all of the assets of NU other than, for Messrs.

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McHale and Butler, to an entity with respect to which following completion of the transaction more than 50 percent (75 percent for Messrs. Olivier and Muntz) of common shares or other voting securities is then owned by all or substantially all of the persons who were the beneficial owners of common shares and other voting securities immediately prior to such transaction.

In the event of a change of control, the Named Executive Officers are generally entitled to receive compensation and benefits following either involuntary termination of employment without "cause" or voluntary termination of employment for "good reason" within the applicable period (generally two years following change of control or shareholder approval thereof).  The Committee believes that termination for good reason is conceptually the same as termination "without cause" and, in the absence of this provision, potential acquirers would have an incentive to constructively terminate executives to avoid paying severance.  Termination for "cause" generally means termination due to a felony or certain other convictions; fraud, embezzlement, or theft in the course of employment; intentional, wrongful damage to company property; gross misconduct or gross negligence in the course of employment or gross neglect of duties harmful to the company; or a material breach of obligations under the agreement.  "Good reason" for termination generally exists after assignment of duties inconsistent with executive’s position, a material reduction in compensation or benefits, a transfer more than 50 miles from the executive’s pre-change of control principal business location (or for Messrs. May and Judge, a transfer outside the Greater Boston Metropolitan Area), or requiring business travel to a substantially greater extent than required pre-change of control (for Messrs. May and Judge).

The discussion and tables below show compensation payable to each Named Executive Officer, except for Mr. Shivery, in the event of: (i) termination for cause; (ii) voluntary termination; (iii) involuntary not-for-cause termination; (iv) termination in the event of disability; (v) death; and (vi) termination following change of control.  The amounts shown assume that each termination was effective as of December 31, 2012, the last business day of the fiscal year as required under SEC reporting requirements.

The summaries above do not purport to be complete and are qualified in their entirety by the actual terms and provisions of the agreements and plans, copies of which have been filed as exhibits to this Annual Report on Form 10-K.

Payments Upon Termination

Regardless of the manner in which the employment of a Named Executive Officer terminates, he is entitled to receive certain amounts earned during his term of employment.  Such amounts include:

·

Vested RSUs and certain other vested awards;

·

Amounts contributed and any vested matching contributions under the Deferral Plans;

·

Pay for unused vacation; and

·

Amounts accrued and vested under the Retirement, Supplemental and 401k Plans (except in the event of a termination for cause under the Supplemental Plans).

As a result, we do not include these amounts in the tables.

See the section above captioned “PENSION BENEFITS IN 2012” for information about the Retirement Plans, the Supplemental Plans and Other Special Benefits, and the section captioned “NONQUALIFIED DEFERRED COMPENSATION IN 2012.”

I.

Post-Employment Compensation:  Termination for Cause  

Type of Payment	May ($)	McHale ($)	Judge ($)	Olivier ($)	Butler ($)	Muntz ($)
Incentive Programs
Annual Incentives	―	―	―	―	―	―
Performance Cash	―	―	―	―	―	―
Performance Shares	―	―	―	―	―	―
RSUs
Pension and Deferred Compensation
Supplemental Plan	―	―	―	―	―	―
Special Retirement Benefit (1)	―	―	―	1,337,988	―	―
Deferral Plan	―	―	―	―	―	―
Other Benefits
Health and Welfare Cash Value	―	―	―	―	―	―
Perquisites	―	―	―	―	―	―
Separation Payments
Excise Tax & Gross-Up	―	―	―	―	―	―
Separation Payment for Non-Compete Agreement	―	―	―	―	―	―
Separation Payment for Liquidated Damages	―	―	―	―	―	―
Total	—	—	—	1,337,988	—	—

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(1)

Represents actuarial present values at year-end 2012 of amounts payable solely under Mr. Olivier’s employment agreement upon termination (which are in addition to amounts due under the Retirement and Supplemental Plans).  Under Mr. Olivier’s agreement, he would receive upon termination a lump sum payment of $2,050,000, offset by the value of Retirement Plan benefits.

II.

Post-Employment Compensation:  Voluntary Termination

Type of Payment	May ($)	McHale ($)	Judge ($)	Olivier ($)	Butler ($)	Muntz ($)
Incentive Programs
Annual Incentives (1)	2,100,000	640,000	640,000	660,000	495,000	458,300
Performance Cash (2)	―	299,939	―	314,236	232,534	152,343
Performance Shares (3)	―	376,184	―	394,122	291,615	191,101
RSUs (4)	―	―	―	1,498,818	1,118,806	723,846
Pension and Deferred Compensation
Supplemental Plan	―	―	―	―	―	―
Special Retirement Benefit (5)	―	―	―	1,337,988	―	1,721,834
Deferral Plan	―	―	―	―	―	―
Other Benefits
Health and Welfare Benefits	―	―	―	―	―	―
Perquisites	―	―	―	―	―	―
Separation Payments	―	―	―	―	―	―
Excise Tax & Gross-Up	―	―	―	―	―	―
Separation Payment for Non-Compete Agreement	―	―	―	―	―	―
Separation Payment for Liquidated Damages	―	―		―	―	―
Total	2,100,000	1,316,123	640,000	4,205,164	2,137,955	3,247,424

(1)

Represents actual 2012 annual incentive awards, determined as described in the Compensation Discussion and Analysis.

(2)

Represents actual performance cash awards under the 2010 – 2012 Long-Term Incentive Program for Messrs. McHale, Olivier, Butler and Muntz.  

(3)

Represents actual performance share awards under the 2010 – 2012 Long-Term Incentive Program for Messrs. McHale, Olivier, Butler and Muntz.  

(4)

Represents values of RSUs granted to Messrs. Olivier, Butler and Muntz under the NU long-term incentive programs that, at year-end 2012, were unvested under applicable vesting schedules.  Under these programs, RSUs vest pro rata based on credited service years and age at termination, and time worked during the vesting period.  The values were calculated by multiplying the number of RSUs by $39.08, the closing price of NU common shares on December 31, 2012, the last trading day of the year.  Excludes retention pool RSU grants, which would not vest upon voluntary termination.

(5)

Represents actuarial present values at year-end 2012 of amounts payable solely under employment agreements (which are in addition to amounts due under the Retirement and Supplemental Plans).  Under Mr. Olivier’s agreement, he would receive a lump sum payment of $2,050,000, offset by the value of Retirement Plan benefits.  Amounts shown are year-end 2012 present values payable upon termination.

198

III.

Post-Employment Compensation:  Involuntary Termination, Not for Cause  

Type of Payment	May ($)	McHale ($)	Judge ($)	Olivier ($)	Butler ($)	Muntz ($)
Incentive Programs
Annual Incentives (1)	2,100,000	640,000	640,000	660,000	495,000	458,300
Performance Cash (2)	―	299,939	―	314,236	232,534	152,343
Performance Shares (3)	―	376,184	―	394,122	291,615	191,101
RSUs (4)	―	―	―	1,498,818	1,118,806	723,846
Pension and Deferred Compensation
Supplemental Plan	―	―	―	―	―	―
Special Retirement Benefit (5)	―	2,338,441	―	1,337,988	1,944,265	1,721,834
Deferral Plan (6)	―	9,212	―	―	―	―
Other Benefits
Health and Welfare Benefits (7)	―	74,384	―	―	73,110	―
Perquisites (8)	―	7,000	―	―	7,000	―
Separation Payments
Excise Tax & Gross-Up	―	―	―	―	―	―
Separation Payment for Non-Compete Agreement (9)	―	919,005	―	―	717,275	―
Separation Payment for Liquidated Damages (10)	―	919,005	―	―	717,275	―
Total	2,100,000	5,583,170	640,000	4,205,164	5,596,880	3,247,424

(1)

Represents actual 2012 Named Executive Officer annual incentive awards, determined as described in the Compensation Discussion and Analysis.

(2)

Represents actual performance cash awards under the 2010 – 2012 Long-Term Incentive Program for Messrs. McHale, Olivier, Butler and Muntz.  

(3)

Represents actual performance share awards under the 2010-2012 Long-Term Incentive Program for Messrs. McHale, Olivier, Butler and Muntz.  

(4)

Represents values of RSUs under the NU long-term incentive programs that, at year-end 2012, were unvested under applicable vesting schedules.  Under these programs, RSUs vest pro rata based on credited service years and age at termination, and time worked during the vesting period.  Under the retention program, RSUs vest fully upon termination without cause and the value is reduced by separation payments.  The values were calculated by multiplying the number of RSUs by $39.08, the closing price of NU common shares on December 31, 2012, the last trading day of the year.  

(5)

Represents actuarial present values at year-end 2012 of amounts payable solely under employment agreements upon termination (which are in addition to amounts due under the Retirement and Supplemental Plans).  Mr. Olivier’s agreement provides for a lump sum payment of $3,101,153 offset by the value of Retirement Plan benefits.  Agreements with Messrs. McHale and Butler provide for two years age and service credit under the Supplemental Plan.

(6)

Represents value of Company matching contributions under the Deferral Plans that were unvested under applicable vesting schedules (other amounts in the Deferral Plans represent previously vested Company matching contributions, where applicable, and earned compensation contributed by executives).

(7)

Represents estimated cost to NU at year-end 2012 of providing post-employment welfare benefits beyond those available to non-executives upon involuntary termination.  The amount reported in the table for Messrs. McHale and Butler represents (a) the value of two years employer contributions toward active health, long-term disability, and life insurance benefits, plus (b)a payment to offset any taxes thereon (gross-up).  

(8)

Represents the cost to NU of reimbursing Messrs. McHale and Butler for two years of financial planning and tax preparation fees.  

(9)

Represents consideration for agreements not to compete with NU following termination.  Employment agreements with these executives provide for a lump-sum payment equal to the sum of their base salary plus annual incentive award.  These payments do not replace, offset or otherwise affect the calculation or payment of the annual incentive awards.

(10)

Represents severance payments in addition to any non-compete agreement payments described in the prior note.  

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IV.

Post-Employment Compensation:  Termination Upon Disability

Type of Payment	May ($)	McHale ($)	Judge ($)	Olivier ($)	Butler ($)	Muntz ($)
Incentive Programs
Annual Incentives (1)	2,100,000	640,000	640,000	660,000	495,000	458,300
Performance Cash (2)	―	299,939	―	314,236	232,534	152,343
Performance Shares (3)	―	376,184	―	394,122	291,615	191,101
RSUs and Other Awards (4)	6,580,017	1,425,486	4,248,778	1,498,818	1,118,806	723,846
Pension and Deferred Compensation
Supplemental Plan	―	―	―	―		―
Special Retirement Benefit (5)	―	―	―	1,337,988	―	1,721,834
Deferral Plan (6)	―	9,212	―	―	―	―
Other Benefits
Health and Welfare Benefits	―	―	―	―	―	―
Perquisites	―	―	―	―	―	―
Separation Payments
Excise Tax & Gross-Up	―	―	―	―	―	―
Separation Payment for Non-Compete Agreement	―	―	―	―	―	―
Separation Payment for Liquidated Damages	―	―	―	―	―	―
Total	8,680,017	2,750,821	4,888,778	4,205,164	2,137,955	3,247,424

(1)

Represents actual 2012 Named Executive Officer annual incentive awards, determined as described in the Compensation Discussion and Analysis.

(2)

Represents actual performance cash awards under the 2010 – 2012 Long-Term Incentive Program for Messrs. McHale, Olivier, Butler and Muntz.  

(3)

Represents actual performance share awards under the 2010-2012 Long-Term Incentive Program for Messrs. McHale, Olivier, Butler and Muntz.  

(4)

Represents values of RSUs and other awards under the NU long-term incentive programs and retention awards that, at year-end 2012, were unvested under applicable vesting schedules.  Under these programs and awards, upon termination due to disability, awards vest in full or on a prorated basis based on credited service years and age at termination, and time worked during the vesting period.  The values were calculated by multiplying the number of RSUs by $39.08, the closing price of NU common shares on December 31, 2012, the last trading day of the year.

(5)

Represents the actuarial present values at the end of 2012 of the amounts payable solely as the result of employment agreements upon termination (which are in addition to amounts payable under the Retirement and Supplemental Plans).  Under Mr. Olivier’s agreement, a disability termination results in a lump sum payment of $3,101,153, offset by the value of Retirement Plan benefits.  

(6)

Represents value of NU matching contributions under the Deferral Plans that were unvested under applicable vesting schedules (other amounts in the Deferral Plans represent previously vested NU matching contributions, where applicable, and earned compensation contributed by executives).

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V.

Post-Employment Compensation:  Death

Type of Payment	May ($)	McHale ($)	Judge ($)	Olivier ($)	Butler ($)	Muntz ($)
Incentive Programs
Annual Incentives (1)	2,100,000	640,000	640,000	660,000	495,000	458,300
Performance Cash (2)	―	299,939	―	314,236	232,534	152,343
Performance Shares (3)	―	376,184	―	394,122	291,615	191,101
RSUs and Other Awards (4)	6,580,017	1,425,486	4,248,778	1,498,818	1,118,806	723,846
Pension and Deferred Compensation
Supplemental Plan	―	―	―	―	―	―
Special Retirement Benefit (5)	―	―	―	1,337,988	―	1,721,834
Deferral Plan (6)	―	9,212	―	―	―	―
Other Benefits
Health and Welfare Benefits	―	―	―	―	―	―
Perquisites	―	―	―	―	―	―
Separation Payments
Excise Tax & Gross-Up	―	―	―	―	―	―
Separation Payment for Non-Compete Agreement	―	―	―	―	―	―
Separation Payment for Liquidated Damages	―	―	―	―	―	―
Total	8,680,017	2,750,821	4,888,778	4,205,164	2,137,955	3,247,424

(1)

Represents actual 2012 Named Executive Officer annual incentive awards, determined as described in the Compensation Discussion and Analysis.

(2)

Represents actual performance cash awards under the 2010 – 2012 Long-Term Incentive Program for Messrs. McHale, Olivier, Butler and Muntz.  

(3)

Represents actual performance share awards under the 2010-2012 Long-Term Incentive Program for Messrs. McHale, Olivier, Butler and Muntz.  

(4)

Represents values of RSUs and other awards under the NU long-term incentive programs and retention awards that, at year-end 2012, were unvested under applicable vesting schedules.  Under these programs and awards, upon termination due to death, awards vest in full or on a prorated basis based on credited service years and age at termination, and time worked during the vesting period.  The values were calculated by multiplying the number of RSUs by $39.08, the closing price of NU common shares on December 31, 2012, the last trading day of the year.

(5)

Represents the actuarial present values at the end of 2012 of the amounts payable to a surviving spouse solely under agreements (which are in addition to amounts due under the Retirement and Supplemental Plans).  Under Mr. Olivier’s agreement, this benefit would be a lump sum payment of $3,214,047, offset by the value of Retirement Plan benefits.  Under Mr. Muntz’s agreement, a lump sum payment (calculated as described in the Pension Benefits Table) would be payable to his estate upon death.  Pension amounts shown in the table are year-end 2012 present values of benefits immediately payable to the spouse or estate.  

(6)

Represents value of NU matching contributions under the Deferral Plans that were unvested under applicable vesting schedules (other amounts in the Deferral Plans represent previously vested NU matching contributions, where applicable, and earned compensation contributed by executives).

Payments Made Upon a Change of Control

The agreements with Messrs. May, McHale, Judge, and Butler a include change of control benefits.  Messrs. Olivier and Muntz participate in the Special Severance Program for Officers (SSP), which also provides change of control benefits.  The agreements and the SSP are binding on NU and on certain of its majority-owned subsidiaries, including CL&P.

Pursuant to the agreements and the SSP, if an involuntary non-"cause" termination of employment occurs following a change of control (see definition of "cause" above under the heading of "POTENTIAL PAYMENTS UPON TERMINATION OR CHANGE OF CONTROL"), or in the event of a voluntary termination for "good reason" (as described above under such heading), then the Named Executive Officers generally will receive the benefits listed below:  

·

For Messrs. McHale and Butler, a lump sum severance payment of two-times (one-times for Messrs. Olivier and Muntz, three-times for Messrs. May and Judge) the sum of the executive’s base salary plus annual incentive award for the relevant year (Base Compensation), plus for Messrs. McHale and Butler consideration for two year non-compete and non-solicitation covenants (one year covenants for Messrs. Olivier and Muntz) in the form of a lump sum payment equal to Base Compensation;  

201

·

Three years health benefits continuation (two years for Messrs. Olivier and Muntz);

·

For Messrs. McHale and Butler, three years additional age and service credit under the applicable Supplemental Plans (a lump sum payment equal to the value of such credit under those and the applicable qualified pension plan for Messrs. May and Judge);  

·

Automatic vesting and distribution of long-term performance awards (with performance units vesting at target) and certain other awards; and

·

A lump sum equal to any excise taxes incurred under the Internal Revenue Code due to receipt of change of control payments, plus an amount to offset any taxes incurred on such payments (gross-up), except for Messrs. Olivier and Muntz.  (NU has discontinued the practice of providing such gross-up payments in contractual agreements for newly elected executives.)  

With respect to the NSTAR merger, no compensation or benefits were payable to Mr. Shivery because his change of control provisions expired in 2011 when he reached age 65, and he retired in 2012.  For Messrs. McHale and Butler, the NSTAR merger did not constitute a change of control under their agreements.  For Messrs. Olivier and Muntz, no compensation or benefits will be payable unless employment terminates during the applicable change of control period in the circumstances described below.  For Messrs. May and Judge, under the terms of the NSTAR Long-Term Incentive Plan and their agreements, unvested 2010 NSTAR long-term performance awards immediately vested upon completion of the merger and automatically were converted to NU awards of equivalent economic value and terms (2011 and 2012 awards were converted but remained unvested and subject to their original vesting terms).  No other benefits will be payable to these executives unless employment terminates during the applicable period in the circumstances described below.

The above summaries do not purport to be complete and are qualified in their entirety by the actual terms and provisions of the agreements and plans, copies of which have been filed as exhibits to this Annual Report on Form 10-K.

VI.

Post-Employment Compensation:  Termination Following a Change of Control

Type of Payment	May ($)	McHale ($)	Judge ($)	Olivier ($)	Butler ($)	Muntz ($)
Incentive Programs
Annual Incentives (1)	2,100,000	640,000	640,000	660,000	495,000	458,300
Performance Cash (2)	―	223,835	―	234,504	173,533	113,689
Performance Shares (3)	―	280,734	―	294,121	217,623	142,613
RSUs and Other Awards (4)	6,580,017	1,976,823	1,500,555	4,106,603	1,548,779	1,441,778
Pension and Deferred Compensation
Supplemental Plan	―	―	―	―	―	―
Special Retirement Benefit (5)	840,385	3,507,662	2,062,839	1,337,988	2,916,397	1,721,834
Deferral Plan (6)	―	9,212	―	―	―	―
Other Benefits
Health and Welfare Benefits (7)	58,791	104,149	72,327	23,558	91,323	23,558
Perquisites (8)	38,400	8,500	19,200	―	8,500	―
Separation Payments
Excise Tax and Gross-Up (9)	―	4,202,053	―	―	2,905,876	―
Separation Payment for Non-Compete Agreement (10)	―	919,005	―	967,441	717,275	636,540
Separation Payment for Liquidated Damages (11)	9,405,000	1,838,011	3,369,000	967,441	1,434,550	636,540
Total	19,022,593	13,709,984	7,663,921	8,591,656	10,508,856	5,174,852

(1)

Represents actual 2012 annual incentive awards, determined as described in the Compensation Discussion and Analysis.

(2)

Represents actual performance cash awards under the 2010 – 2012 Long-Term Incentive Program for Messrs. McHale, Olivier, Butler and Muntz.  

(3)

Represents actual performance share awards under the 2010 – 2012 Long-Term Incentive Program for Messrs. McHale, Olivier, Butler and Muntz.  

(4)

Represents values of RSUs and other awards under the NU long-term incentive programs and retention awards that, at year-end 2012, were unvested under applicable vesting schedules.  Under these programs, upon termination in certain cases without cause or for good reason following a change of control, awards generally vest in full.  Retention awards vest in full in such circumstances, and the payout value is reduced by any separation payments as described in the notes below.  For Messrs. McHale, Judge, Olivier, and Butler, retention program grants are fully eliminated when offset by separation payments.  

202

The values were calculated by multiplying the number of shares subject to awards by $39.08, the closing price of NU common shares on December 31, 2012, the last trading day of the year.

(5)

Represents actuarial present value at year-end 2012 of amounts payable solely under of agreements (which are in addition to amounts payable under the Retirement and Supplemental Plans).  For Messrs. May, McHale, Judge and Butler, pension benefits were calculated by adding three years of service (and a lump sum of this benefit value is payable to Messrs. May, Judge and Butler).  Mr. Olivier’s agreement provides for a lump sum payment of $3,101,153, offset by his Retirement Plan benefit value.  Pension amounts shown in the table are present values at year-end 2012 of benefits payable upon termination as described with respect to the Pension Benefits Table above.

(6)

Represents value of NU matching contributions under the Deferral Plans that were unvested under applicable vesting schedules (other amounts in the Deferral Plans represent previously vested NU matching contributions, where applicable, and earned compensation contributed by executives).

(7)

Represents the cost to NU at year-end 2012 (estimated by our benefits consultants) of providing post-employment welfare benefits to Named Executive Officers beyond those benefits provided to non-executives upon involuntary termination.  The amounts shown in the table for Messrs. McHale and Butler represent (a) the value of three years employer contributions toward active health, long-term disability, and life insurance benefits, plus (b) a payment to offset any taxes on the value of these benefits (gross-up), less (c) the value of one year retiree health coverage at retiree rates.  The amounts reported in the table for Messrs. Olivier and Muntz represent (a) the value of two years employer contributions toward active health benefits, plus (b) a payment to offset any taxes on the value of these benefits (gross-up), less (c) the value of two years retiree health coverage at retiree rates.  For Messrs. May and Judge, amounts represent the value of three years continued welfare plan participation.

(8)

Represents cost of reimbursing financial planning and tax preparation fees for three years.

(9)

Represents payments made to offset costs to Messrs. McHale and Butler associated with certain excise taxes under Section 280G of the Internal Revenue Code.  Executives may be subject to certain excise taxes under Section 280G if they receive payments and benefits related to a termination following a Change of Control that exceed specified Internal Revenue Service limits.  Contractual agreements with the above executives provide for a grossed-up reimbursement of these excise taxes.  The amounts in the table are based on the Section 280G excise tax rate of 20 percent, the statutory federal income tax withholding rate of 35 percent, the Connecticut state income tax rate of 6.5 percent, and the Medicare tax rate of 1.45 percent.

(10)

Represents payments made under agreements or the SSP as consideration for agreement not to compete with NU following termination of employment equal to the sum of base salary plus relevant annual incentive award.  These payments do not replace, offset or otherwise affect the calculation or payment of the annual incentive awards.

(11)

Represents severance payments in addition to any non-compete agreement payments described in the prior note.  For Messrs. McHale, and Butler, this payment equals two-times the sum of base salary plus relevant annual incentive award (one-times the sum for Messrs. Olivier and Muntz, three-times the sum for Messrs. May and Judge).  These payments do not replace, offset or otherwise affect the calculation or payment of the annual incentive awards.

Charles W. Shivery

The following table sets forth the payments that Charles W. Shivery, NU’s former President and Chief Executive Officer and CL&P’s former Chairman, became entitled to receive due to his retirement on April 10, 2012.  

Post-Employment Compensation:  Charles W. Shivery

Payment	($)
Incentive Programs
Annual Incentive (1)	570,393
RSUs (2)	5,483,586
Retirement Benefits (3)
Qualified Retirement Plan	32,760
Supplemental Plan Payments	823,860
Other Benefits
Health and Welfare Cash Value (4)	11,052
Total	6,921,651

(1)

Represents the payout Mr. Shivery became eligible to receive under the 2012 Annual Incentive Program.

(2)

Consists of the value of unvested RSUs that vested upon Mr. Shivery’s retirement under the 2010 – 2012 Long-Term Incentive Program, the 2011 – 2013 Long-Term Incentive Program and the 2012 – 2014 Long-Term Incentive Program.  Under the 2012 – 2014 Program, 25,678 RSUs vested pro rata based on 2012 employee service and the remaining unvested RSUs were

203

forfeited.  The value realized on vesting is based on $35.91 per share, the closing price of NU common shares on April 10, 2012.  

All of these RSUs were previously awarded to Mr. Shivery based on his service as President and Chief Executive Officer of NU and Chairman of the Regulated companies, including CL&P, prior to retiring in 2012.    

On October 12, 2012, NU distributed to Mr. Shivery 19,753 of his vested RSUs under the 2010 – 2012 Long-Term Incentive program (19,753 RSUs) following a six-month delay required for deferred compensation paid to “key employees” under Section 409A of the Internal Revenue Code, and withheld 8,238 shares to satisfy Mr. Shivery’s tax obligations.  Mr. Shivery realized $778,867 in ordinary income as a result of this transaction.  Pursuant to previously established deferral schedules, Mr. Shivery’s remaining RSUs became distributable in installments in January of 2013, 2014 and 2015.

(3)

Pension values are the total accrued pension benefit payable as an annuity that pays 75 percent to his surviving spouse.  At the time of his retirement, Mr. Shivery began receiving his qualified retirement benefit.  In compliance with Section 409A of the Internal Revenue Code, the start of Mr. Shivery’s Supplemental Executive Retirement Plan (SERP) payments was delayed until six months after his retirement.  On November 1, 2012, NU paid six-months of Mr. Shivery’s SERP “target” benefit $418,024.  Mr. Shivery’s monthly SERP “target” benefits are $68,655.  Assumptions used in the calculation of this benefit are further discussed with respect to the Pension Benefits table.

(4)

Under the Retirement Plan, Mr. Shivery became eligible to receive health benefits upon retirement. Mr. Shivery did not receive any health and welfare benefits in excess of the benefits offered to all employees.

204

Item 12.

Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

NU

In addition to the information below under "Securities Authorized for Issuance Under Equity Compensation Plans," incorporated herein by reference is the information contained in the sections "Common Share Ownership of Certain Beneficial Owners" and "Common Share Ownership of Trustees and Management" of NU’s definitive proxy statement for solicitation of proxies, expected to be filed with the SEC on or about March 21, 2013.

NSTAR ELECTRIC, PSNH and WMECO

Certain information required by this Item 12 has been omitted for NSTAR Electric, PSNH and WMECO pursuant to Instruction I(2)(c) to Form 10-K, Omission of Information by Certain Wholly-Owned Subsidiaries.

CL&P

COMMON SHARE OWNERSHIP OF DIRECTORS AND MANAGEMENT

NU owns 100 percent of the outstanding common stock of CL&P.  The table below shows the number of NU’s common shares beneficially owned as of February 15, 2013, by each of CL&P’s directors and each Named Executive Officer of CL&P, as well as the number of common shares beneficially owned by all of CL&P’s directors and executive officers as a group.  The table also includes information about options, restricted share units and deferred shares credited to the accounts of CL&P’s directors and executive officers under certain compensation and benefit plans.  No equity securities of CL&P are owned by any of the Trustees, directors or executive officers of NU or CL&P.  The address for the shareholders listed below is c/o Northeast Utilities, Prudential Center, 800 Boylston Street, Boston, Massachusetts 02199 for Messrs. May, Judge and Nolan and Ms. Carmody; c/o Northeast Utilities, 56 Prospect Street, Hartford, Connecticut 06103-2818 for Messrs. Butler, McHale, Muntz, Olivier, and Shivery; and c/o Northeast Utilities, 107 Selden Street, Berlin, Connecticut 06037 for Mr. Herdegen.

Name of Beneficial Owner	Amount and Nature of Beneficial Ownership (1)(2)		Percent of Class
Thomas J. May, Chairman of the Regulated Companies	2,420,948	(3)	*
Leon J. Olivier, CEO, Director of the Regulated Companies	201,607	(3)(4)	*
James J. Judge, CFO, Director of the Regulated Companies	306,178	(3)	*
Gregory B. Butler, Senior Vice President and General Counsel, Director of the Regulated Companies	169,021	(3)(4)(5)	*
Christine M. Carmody, Director of the Regulated Companies	133,295	(3)	*
William P. Herdegen III, President and a Director of CL&P	23,554		*
David R. McHale, CAO, Director of the Regulated Companies	207,569	(3)(4)(6)	*
James A. Muntz, Senior Vice President - Transmission	72,029	(3)(4)	*
Joseph R. Nolan, Jr., Director of the Regulated Companies	164,853	(3)	*
Charles W. Shivery, Chairman of the Board of NU; Chairman of CL&P until April 10, 2012	637,871	(3)(7)	*
All directors and Executive Officers as a Group (11 persons)	4,357,131	(8)	*

*

Less than 1% of Northeast Utilities common shares outstanding.

⁽¹⁾

The persons named in the table have sole voting and investment power with respect to all shares beneficially owned by each of them, except as note below.

⁽²⁾

Includes common shares issuable upon exercise of outstanding stock options exercisable within the 60-day period after February 15, 2013, as follows: Ms. Carmody: 50,512; Mr. May: 1,086,336; and Mr Nolan: 38,923.  

Also includes restricted share units, deferred restricted share units and/or deferred shares, including dividend equivalents, as to which none of the individuals has voting or investment power, and phantom common shares, representing employer matching contributions distributable only in cash, held by executive officers who participate in the Northeast Utilities Deferred Compensation Plan for Executives as follows; Mr. Butler: 103,186 shares; Mr. Herdegen: 19,754 ; Mr. McHale: 136,212 shares; Mr. Muntz: 43,356 shares; Mr. Olivier: 124,668 shares; and Mr. Shivery: 366,356 shares.  Also includes restricted share units and/or unvested and vested deferred shares, as to which none of the individuals has voting or investment power, held by executive officers who participate in the NSTAR 2007 Long Term Incentive Plan, as follows:  Ms. Carmody:  54,405; Mr. Judge 180,961; Mr. May 978,769; and Mr. Nolan: 101,375.

Also includes unvested performance shares reported at target payouts, plus accumulated dividend equivalents, as to which none of the individuals has voting or investment power, as follows: Mr. Butler: 9,100 shares; Ms. Carmody:  4,500; Mr. Herdegen: 3,800 ; Mr. Judge:  13,100; Mr. May 52,000; Mr. McHale: 13,100 shares; Mr. Muntz: 5,600 shares; Mr. Nolan:  5,100 and Mr. Olivier: 13,800 shares.  Actual payouts of the performance shares, if any, at the conclusion of relevant performance periods will depend on the extent to which performance goals are satisfied.

205

⁽³⁾

Includes common shares held in the 401(k) Plan in the employer stock ownership plan account over which the holder has sole voting and investment power (Mr. Butler: 3,773 shares; Ms. Carmody: 5,703 shares; Mr. Judge:  21,201 shares; Mr. May 62,144 shares; Mr. McHale: 4,525 shares; Mr. Muntz: 146 shares; Mr. Nolan: 14,707 shares; Mr. Olivier: 2,303 shares; and Mr. Shivery: 2,382 shares).

⁽⁴⁾

Includes common shares held as units in the 401(k) Plan invested in the NU Common Shares Fund over which the holder has sole voting and investment power (Mr. Butler: 466 shares; Mr. McHale: 2,037 shares; Mr. Muntz: 2,005 shares; and Mr. Olivier: 246 shares).

⁽⁵⁾

Includes 52,496 shares owned jointly by Mr. Butler and his spouse with whom he shares voting and investment power.

⁽⁶⁾

Includes 119 shares held by Mr. McHale in the 401(k) Plan TRAESOP/PAYSOP account over which Mr. McHale has sole voting and investment power.

⁽⁷⁾

Includes 4,000 shares owned jointly by Mr. Shivery and his spouse with whom he shares voting and investment power.

⁽⁸⁾

Includes 1,175,771 common shares issuable upon exercise of outstanding stock options exercisable within the 60-day period after February 15, 2013, and 2,245,215 unissued common shares.  See note 2.

SECURITIES AUTHORIZED FOR ISSUANCE UNDER EQUITY COMPENSATION PLANS

The following table sets forth the number of NU common shares issuable under NU equity compensation plans, as well as their weighted exercise price, as of December 31, 2012, in accordance with the rules of the SEC:

Plan Category		Number of securities to be issued upon exercise of outstanding options, warrants and rights (a)	Weighted-average exercise price of outstanding options, warrants and rights (b)	Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a)) (c)
Equity compensation plans approved by security holders		3,880,013	$24.92	4,337,714
Equity compensation plans not approved by security holders (d)	—		—	—
Total	3,880,013		$24.92	4,337,714

(a)

Includes 1,545,757 common shares to be issued upon exercise of options, 2,183,319 common shares for distribution of restricted share units, and 150,937 performance shares issuable at target, all pursuant to the terms of our Incentive Plan.  

(b)

The weighted-average exercise price in Column (b) does not take into account restricted share units or performance shares, which have no exercise price.

(c)

Includes 857,280 common shares issuable under our Employee Share Purchase Plan II.

(d)

All of our current compensation plans under which equity securities of NU are authorized for issuance have been approved by shareholders of NU or the former shareholders of NSTAR, the predecessor of NSTAR LLC.

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Item 13.

Certain Relationships and Related Transactions, and Director Independence

NU

Incorporated herein by reference is the information contained in the sections captioned "Trustee Independence" and "Certain Relationships and Related Transactions" of NU’s definitive proxy statement for solicitation of proxies, expected to be filed with the SEC on or about March 21, 2013.

NSTAR ELECTRIC, PSNH and WMECO

Certain information required by this Item 13 has been omitted for NSTAR Electric, PSNH and WMECO pursuant to Instruction I(2)(c) to Form 10-K, Omission of Information by Certain Wholly-Owned Subsidiaries.

CL&P

NU’s Code of Ethics for Senior Financial Officers applies to the Senior Financial Officers (Chief Executive Officer, Chief Financial Officer and Controller) of NU, CL&P and certain other NU subsidiaries.  Under the Code, one’s position as a Senior Financial Officer in the company may not be used to improperly benefit such officer or his or her family or friends.  Under the Code, specific activities that may be considered conflicts of interest include, but are not limited to, directly or indirectly acquiring or retaining a significant financial interest in an organization that is a customer, vendor or competitor, or that seeks to do business with the company; serving, without proper safeguards, as an officer or director of, or working or rendering services for an organization that is a customer, vendor or competitor, or that seeks to do business with the company. Waivers of the provisions of the Code of Ethics for Trustees, executive officers or directors must be approved by NU’s Board of Trustees.  Any such waivers will be disclosed pursuant to legal requirements.

NU’s Standards of Business Conduct, which applies to all Trustees, directors, officers and employees of NU and its subsidiaries, including CL&P, contains a Conflict of Interest Policy that requires all such individuals to disclose any potential conflicts of interest.  Such individuals are expected to discuss their particular situations with management to ensure appropriate steps are in place to avoid a conflict of interest.  All disclosures must be reviewed and approved by management to ensure a particular situation does not adversely impact the individual’s primary job and role.

NU’s Related Party Transactions Policy is administered by the Corporate Governance Committee of NU’s Board of Trustees.  The Policy generally defines a "Related Party Transaction" as any transaction or series of transactions in which (i) NU or a subsidiary is a participant, (ii) the aggregate amount involved exceeds $120,000 and (iii) any "Related Party" has a direct or indirect material interest.  A "Related Party" is defined as any Trustee or nominee for Trustee, any executive officer, any shareholder owning more than 5 percent of NU's total outstanding shares, and any immediate family member of any such person.  Management submits to the Corporate Governance Committee for consideration any Related Party Transaction into which NU or a subsidiary proposes to enter.  The Corporate Governance Committee recommends to the NU Board of Trustees for approval only those transactions that are in NU’s best interests.  If management causes the company to enter into a Related Party Transaction prior to approval by the Corporate Governance Committee, the transaction will be subject to ratification by the NU Board of Trustees.  If the NU Board of Trustees determines not to ratify the transaction, then management will make all reasonable efforts to cancel or annul such transaction.

The directors of CL&P are employees of CL&P and/or other subsidiaries of NU, and thus are not considered independent.

Item 14.

Principal Accountant Fees and Services

NU

Incorporated herein by reference is the information contained in the section "Relationship with Independent Auditors" of NU’s definitive proxy statement for solicitation of proxies, expected to be filed with the SEC on or about March 21, 2013.

CL&P, NSTAR ELECTRIC, PSNH and WMECO

Pre-Approval of Services Provided by Principal Auditors

None of CL&P, NSTAR Electric, PSNH or WMECO is subject to the audit committee requirements of the SEC, the national securities exchanges or the national securities associations.  CL&P, NSTAR Electric, PSNH and WMECO obtain audit services from the independent auditor engaged by the Audit Committee of NU’s Board of Trustees.  NU’s Audit Committee has established policies and procedures regarding the pre-approval of services provided by the principal auditors.  Those policies and procedures delegate pre-approval of services to the NU Audit Committee Chair provided that such offices are held by Trustees who are "independent" within the meaning of the Sarbanes-Oxley Act of 2002 and that all such pre-approvals are presented to the NU Audit Committee at the next regularly scheduled meeting of the Committee.

207

The following relates to fees and services for the entire NU system, including NU, CL&P, NSTAR Electric, PSNH and WMECO.

Fees Paid to Principal Independent Registered Public Accountants

Northeast Utilities and its subsidiaries paid Deloitte & Touche LLP fees aggregating $4,459,500 and $4,366,359 for the years ended December 31, 2012 and 2011, respectively, comprised of the following:

1.

Audit Fees

The aggregate fees billed to Northeast Utilities and its subsidiaries by Deloitte & Touche LLP, the member firms of Deloitte Touche Tohmatsu and their respective affiliates (collectively, the Deloitte Entities), for audit services rendered for the years ended December 31, 2012 and 2011 totaled $4,356,000 and $2,956,000, respectively.  The audit fees were incurred for audits of Northeast Utilities’ annual consolidated financial statements and those of its subsidiaries (including NSTAR in 2012), reviews of financial statements included in Northeast Utilities’ Quarterly Reports on Form 10-Q and those of its subsidiaries, comfort letters, consents and other costs related to registration statements and financings.  The fees also included audits of internal controls over financial reporting as of December 31, 2012 and 2011, as well as auditing the implementation of new accounting standards and the accounting for new contracts.

2.

Audit Related Fees

The aggregate fees billed to us and our subsidiaries by the Deloitte Entities for audit related services rendered for the years ended December 31, 2012 and 2011 totaled $88,000 and $519,000, respectively.  2011 audit related fees were primarily for audit procedures related to the merger with NSTAR.

3.

Tax Fees

The aggregate fees billed to Northeast Utilities and its subsidiaries by the Deloitte Entities for tax services for the years ended December 31, 2012 and 2011 totaled $14,000 and $39,859, respectively.  These services related primarily to the reviews of tax returns and reviewing the tax impacts of proposed transactions in 2011.

4.

All Other Fees

The aggregate fees billed to us and our subsidiaries by the Deloitte Entities for services other than the services described above for the years ended December 31, 2012 and 2011 totaled $1,500 and $851,500, respectively.  All other fees in 2012 and 2011 included a license fee for access to an accounting research tool.  All other fees in 2011 consisted primarily of consulting services related to the Company's consideration of implementing enterprise resource planning systems.

The Audit Committee pre-approves all auditing services and permitted non-audit services (including the fees and terms thereof) to be performed for us by our independent registered public accountants, subject to the de minimis exceptions for non-audit services described in Section 10A(i)(1)(B) of the Securities Exchange Act of 1934, which are approved by the Audit Committee prior to the completion of the audit.  The Audit Committee may form and delegate its authority to subcommittees consisting of one or more members when appropriate, including the authority to grant pre-approvals of audit and permitted non-audit services, provided that decisions of such subcommittee to grant pre-approvals are presented to the full Audit Committee at its next scheduled meeting.  During 2012, all services described above were pre-approved by the Audit Committee.  

The Audit Committee has considered whether the provision by the Deloitte Entities of the non-audit services described above was allowed under Rule 2-01(c)(4) of Regulation S-X and was compatible with maintaining the independence of the registered public accountants and has concluded that the Deloitte Entities were and are independent of us in all respects.

208

PART IV

Item 15.

Exhibits and Financial Statement Schedules

(a)	1.	Financial Statements:
			The financial statements filed as part of this Annual Report on Form 10-K are set forth under Item 8, "Financial Statements and Supplementary Data."
	2.	Schedules
		I.	Financial Information of Registrant: Northeast Utilities (Parent) Balance Sheets as of December 31, 2012 and 2011	S-1
			Northeast Utilities (Parent) Statements of Income for the Years Ended December 31, 2012, 2011 and 2010	S-2
			Northeast Utilities (Parent) Statements of Comprehensive Income for the Years Ended December 31, 2012, 2011 and 2010	S-2
			Northeast Utilities (Parent) Statements of Cash Flows for the Years Ended December 31, 2012, 2011 and 2010	S-3
		II.	Valuation and Qualifying Accounts and Reserves for NU, CL&P, NSTAR Electric, PSNH and WMECO for 2012, 2011 and 2010	S-4
			All other schedules of the companies for which inclusion is required in the applicable regulations of the SEC are permitted to be omitted under the related instructions or are not applicable, and therefore have been omitted.
	3.		Exhibit Index	E-1

209

NORTHEAST UTILITIES

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

NORTHEAST UTILITIES
February 27, 2013	By:	/s/ Jay S. Buth
		Jay S. Buth
		Vice President, Controller and Chief Accounting Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.

POWER OF ATTORNEY

Each person whose signature appears below constitutes and appoints Gregory B. Butler, James J. Judge and Jay S. Buth and each of them, his or her true and lawful attorneys-in-fact and agents, with full power of substitution and resubstitution, for him or her and in his or her name, place and stead, in any and all capacities, to sign any and all amendments to this Annual Report on Form 10-K, and to file the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents, and each of them, full power and authority to do and perform each and every act and thing requisite and necessary to be done, as fully to all intents and purposes as he or she might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents or any of them, or their or his or her substitute or substitutes, may lawfully do or cause to be done by virtue hereof.

Signature	Title	Date
/s/ Thomas J. May	President and Chief Executive Officer	February 27, 2013
Thomas J. May	and a Trustee
	(Principal Executive Officer)
/s/ James J. Judge	Executive Vice President and Chief Financial Officer (Principal Financial Officer)	February 27, 2013
James J. Judge
/s/ Jay S. Buth	Vice President, Controller	February 27, 2013
Jay S. Buth	and Chief Accounting Officer
/s/ Charles W. Shivery	Chairman of the Board of Trustees	February 27, 2013
Charles W. Shivery
/s/ Richard H. Booth	Trustee	February 27, 2013
Richard H. Booth
/s/ John S. Clarkeson	Trustee	February 27, 2013
John S. Clarkeson
/s/ Cotton M. Cleveland	Trustee	February 27, 2013
Cotton M. Cleveland
/s/ Sanford Cloud, Jr.	Trustee	February 27, 2013
Sanford Cloud, Jr.

210

/s/ James S. DiStasio	Trustee	February 27, 2013
James S. DiStasio
/s/ Francis A. Doyle	Trustee	February 27, 2013
Francis A. Doyle
/s/ Charles K. Gifford	Trustee	February 27, 2013
Charles K. Gifford
/s/ Paul A. La Camera	Trustee	February 27, 2013
Paul A. La Camera
/s/ Kenneth R. Leibler	Trustee	February 27, 2013
Kenneth R. Leibler
/s/ William C. Van Faasen	Trustee	February 27, 2013
William C. Van Faasen
/s/ Frederica M. Williams	Trustee	February 27, 2013
Frederica M. Williams
/s/ Dennis R. Wraase	Trustee	February 27, 2013
Dennis R. Wraase

211

THE CONNECTICUT LIGHT AND POWER COMPANY

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

THE CONNECTICUT LIGHT AND POWER COMPANY
February 27, 2013	By:	/s/ Jay S. Buth
		Jay S. Buth
		Vice President, Controller and Chief Accounting Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.

POWER OF ATTORNEY

Each person whose signature appears below constitutes and appoints Gregory B. Butler, James J. Judge and Jay S. Buth and each of them, his or her true and lawful attorneys-in-fact and agents, with full power of substitution and resubstitution, for him or her and in his or her name, place and stead, in any and all capacities, to sign any and all amendments to this Annual Report on Form 10-K, and to file the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents, and each of them, full power and authority to do and perform each and every act and thing requisite and necessary to be done, as fully to all intents and purposes as he or she might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents or any of them, or their or his or her substitute or substitutes, may lawfully do or cause to be done by virtue hereof.

Signature	Title	Date
/s/ Thomas J. May	Chairman and a Director	February 27, 2013
Thomas J. May
/s/ Leon J. Olivier	Chief Executive Officer and a Director	February 27, 2013
Leon J. Olivier	(Principal Executive Officer)
/s/ James J. Judge	Executive Vice President and	February 27, 2013
James J. Judge	Chief Financial Officer and a Director
	(Principal Financial Officer)
/s/ Jay S. Buth	Vice President, Controller	February 27, 2013
Jay S. Buth	and Chief Accounting Officer
/s/ Gregory B. Butler	Senior Vice President and General Counsel	February 27, 2013
Gregory B. Butler	and a Director
/s/ Christine M. Carmody	Senior Vice President-Human Resources	February 27, 2013
Christine M. Carmody	and a Director
/s/ William P. Herdegen III	President and Chief Operating Officer	February 27, 2013
William P. Herdegen III	and a Director
/s/ David R. McHale	Executive Vice President and	February 27, 2013
David R. McHale	Chief Administrative Officer and a Director

212

/s/ Joseph R. Nolan, Jr.	Senior Vice President-Corporate Relations	February 27, 2013
Joseph R. Nolan, Jr.	and a Director

213

NSTAR ELECTRIC COMPANY

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

NSTAR ELECTRIC COMPANY
February 27, 2013	By:	/s/ Jay S. Buth
		Jay S. Buth
		Vice President, Controller and Chief Accounting Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.

POWER OF ATTORNEY

Each person whose signature appears below constitutes and appoints Gregory B. Butler, James J. Judge and Jay S. Buth and each of them, his or her true and lawful attorneys-in-fact and agents, with full power of substitution and resubstitution, for him or her and in his or her name, place and stead, in any and all capacities, to sign any and all amendments to this Annual Report on Form 10-K, and to file the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents, and each of them, full power and authority to do and perform each and every act and thing requisite and necessary to be done, as fully to all intents and purposes as he or she might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents or any of them, or their or his or her substitute or substitutes, may lawfully do or cause to be done by virtue hereof.

Signature	Title	Date
/s/ Thomas J. May	Chairman and a Director	February 27, 2013
Thomas J. May
/s/ Leon J. Olivier	Chief Executive Officer and a Director	February 27, 2013
Leon J. Olivier	(Principal Executive Officer)
/s/ James J. Judge	Executive Vice President and	February 27, 2013
James J. Judge	Chief Financial Officer and a Director
	(Principal Financial Officer)
/s/ Jay S. Buth	Vice President, Controller	February 27, 2013
Jay S. Buth	and Chief Accounting Officer
/s/ Gregory B. Butler	Senior Vice President and General Counsel	February 27, 2013
Gregory B. Butler	and a Director
/s/ Christine M. Carmody	Senior Vice President-Human Resources	February 27, 2013
Christine M. Carmody	and a Director
/s/ Craig A. Hallstrom	President and Chief Operating Officer	February 27, 2013
Craig A. Hallstrom	and a Director
/s/ David R. McHale	Executive Vice President and	February 27, 2013
David R. McHale	Chief Administrative Officer and a Director

214

/s/ Joseph R. Nolan, Jr.	Senior Vice President-Corporate Relations	February 27, 2013
Joseph R. Nolan, Jr.	and a Director

215

PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE
February 27, 2013	By:	/s/ Jay S. Buth
		Jay S. Buth
		Vice President, Controller and Chief Accounting Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.

POWER OF ATTORNEY

Each person whose signature appears below constitutes and appoints Gregory B. Butler, James J. Judge and Jay S. Buth and each of them, his or her true and lawful attorneys-in-fact and agents, with full power of substitution and resubstitution, for him or her and in his or her name, place and stead, in any and all capacities, to sign any and all amendments to this Annual Report on Form 10-K, and to file the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents, and each of them, full power and authority to do and perform each and every act and thing requisite and necessary to be done, as fully to all intents and purposes as he or she might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents or any of them, or their or his or her substitute or substitutes, may lawfully do or cause to be done by virtue hereof.

Signature	Title	Date
/s/ Thomas J. May	Chairman and a Director	February 27, 2013
Thomas J. May
/s/ Leon J. Olivier	Chief Executive Officer and a Director	February 27, 2013
Leon J. Olivier	(Principal Executive Officer)
/s/ James J. Judge	Executive Vice President and	February 27, 2013
James J. Judge	Chief Financial Officer and a Director
	(Principal Financial Officer)
/s/ Jay S. Buth	Vice President, Controller	February 27, 2013
Jay S. Buth	and Chief Accounting Officer
/s/ Gregory B. Butler	Senior Vice President and General Counsel	February 27, 2013
Gregory B. Butler	and a Director
/s/ Christine M. Carmody	Senior Vice President-Human Resources	February 27, 2013
Christine M. Carmody	and a Director
/s/ Gary A. Long	President and Chief Operating Officer	February 27, 2013
Gary A. Long	and a Director
/s/ David R. McHale	Executive Vice President and	February 27, 2013
David R. McHale	Chief Administrative Officer and a Director

216

/s/ Joseph R. Nolan, Jr.	Senior Vice President-Corporate Relations	February 27, 2013
Joseph R. Nolan, Jr.	and a Director

217

WESTERN MASSACHUSETTS ELECTRIC COMPANY

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

WESTERN MASSACHUSETTS ELECTRIC COMPANY
February 27, 2013	By:	/s/ Jay S. Buth
		Jay S. Buth
		Vice President, Controller and Chief Accounting Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.

POWER OF ATTORNEY

Each person whose signature appears below constitutes and appoints Gregory B. Butler, James J. Judge and Jay S. Buth  and each of them, his or her true and lawful attorneys-in-fact and agents, with full power of substitution and resubstitution, for him or her and in his or her name, place and stead, in any and all capacities, to sign any and all amendments to this Annual Report on Form 10-K, and to file the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents, and each of them, full power and authority to do and perform each and every act and thing requisite and necessary to be done, as fully to all intents and purposes as he or she might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents or any of them, or their or his or her substitute or substitutes, may lawfully do or cause to be done by virtue hereof.

Signature	Title	Date
/s/ Thomas J. May	Chairman and a Director	February 27, 2013
Thomas J. May
/s/ Leon J. Olivier	Chief Executive Officer and a Director	February 27, 2013
Leon J. Olivier	(Principal Executive Officer)
/s/ James J. Judge	Executive Vice President and	February 27, 2013
James J. Judge	Chief Financial Officer and a Director
	(Principal Financial Officer)
/s/ Jay S. Buth	Vice President, Controller	February 27, 2013
Jay S. Buth	and Chief Accounting Officer
/s/ Gregory B. Butler	Senior Vice President and General Counsel	February 27, 2013
Gregory B. Butler	and a Director
/s/ Christine M. Carmody	Senior Vice President-Human Resources	February 27, 2013
Christine M. Carmody	and a Director
/s/ Peter J. Clarke	President and Chief Operating Officer	February 27, 2013
Peter J. Clarke	and a Director
/s/ David R. McHale	Executive Vice President and	February 27, 2013
David R. McHale	Chief Administrative Officer and a Director

218

/s/ Joseph R. Nolan, Jr.	Senior Vice President-Corporate Relations	February 27, 2013
Joseph R. Nolan, Jr.	and a Director

219

SCHEDULE I
NORTHEAST UTILITIES (PARENT)
FINANCIAL INFORMATION OF REGISTRANT
BALANCE SHEETS
AS OF DECEMBER 31, 2012 AND 2011
(Thousands of Dollars)
				2012		2011
ASSETS
Current Assets:
	Cash			$	250	$	62
	Accounts Receivable				1		2,735
	Accounts Receivable from Affiliated Companies				11,173		1,749
	Notes Receivable from Affiliated Companies				1,025,000		113,200
	Taxes Receivable				11,220		5,308
	Prepayments and Other Current Assets				2,665		4,610
Total Current Assets					1,050,309		127,664
Deferred Debits and Other Assets:
	Investments in Subsidiary Companies, at Equity				9,874,692		4,566,865
	Notes Receivable from Affiliated Companies				25,000		62,500
	Accumulated Deferred Income Taxes				67,619		39,405
	Other Long-Term Assets				12,597		9,979
Total Deferred Debits and Other Assets					9,979,908		4,678,749
Total Assets				$	11,030,217	$	4,806,413
LIABILITIES AND CAPITALIZATION
Current Liabilities:
	Notes Payable			$	1,150,000	$	256,000
	Long-Term Debt - Current Portion				549,992		265,296
	Accounts Payable				9,854		266
	Accounts Payable to Affiliated Companies				27,559		141
	Accrued Taxes				7,509		-
	Accrued Interest				4,943		8,735
	Other				26,825		865
Total Current Liabilities					1,776,682		531,303
Deferred Credits and Other Liabilities:
	Other				16,485		9,511
Total Deferred Credits and Other Liabilities					16,485		9,511
Capitalization:
	Long-Term Debt				-		249,973
	Equity:
		Common Shareholders' Equity:
			Common Shares		1,662,547		980,264
			Capital Surplus, Paid in		6,183,267		1,797,884
			Retained Earnings		1,802,714		1,651,875
			Accumulated Other Comprehensive Loss		(72,854)		(70,686)
			Treasury Stock		(338,624)		(346,667)
		Common Shareholders' Equity			9,237,050		4,012,670
		Noncontrolling Interests			-		2,956
	Total Equity				9,237,050		4,015,626
Total Capitalization					9,237,050		4,265,599
Total Liabilities and Capitalization				$	11,030,217	$	4,806,413
See the Combined Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for a description of significant accounting matters related to NU parent, including NU common shares information as described in Note 17, "Common Shares," material obligations and guarantees as described in Note 12, "Commitments and Contingencies," and debt agreements as described in Note 8, "Short-Term Debt," and Note 9, "Long-Term Debt."

S-1

SCHEDULE I
NORTHEAST UTILITIES (PARENT)
FINANCIAL INFORMATION OF REGISTRANT
STATEMENTS OF INCOME
FOR THE YEARS ENDED DECEMBER 31, 2012, 2011 AND 2010
(Thousands of Dollars, Except Share Information)
			2012		2011		2010
Operating Revenues			$	-	$	-	$	-
Operating Expenses:
	Other			73,198		19,075		21,081
Operating Loss				(73,198)		(19,075)		(21,081)
Interest Expense				27,777		26,767		12,058
Other Income, Net:
	Equity in Earnings of Subsidiaries			567,529		422,408		396,333
	Other, Net			5,971		4,247		4,536
		Other Income, Net		573,500		426,655		400,869
Income Before Income Tax Benefit				472,525		380,813		367,730
Income Tax Benefit				(53,523)		(14,142)		(20,276)
Net Income				526,048		394,955		388,006
Net Income Attributable to Noncontrolling Interest				103		262		57
Net Income Attributable to Controlling Interest			$	525,945	$	394,693	$	387,949
Basic Earnings per Common Share			$	1.90	$	2.22	$	2.20
Diluted Earnings per Common Share			$	1.89	$	2.22	$	2.19
Weighted Average Common Shares Outstanding:
	Basic			277,209,819		177,410,167		176,636,086
	Diluted			277,993,631		177,804,568		176,885,387
STATEMENTS OF COMPREHENSIVE INCOME
Net Income			$	526,048	$	394,955	$	388,006
Other Comprehensive Income/(Loss), Net of Tax:
	Qualified Cash Flow Hedging Instruments			1,971		(14,177)		200
	Changes in Unrealized Gains on Other Securities			217		506		402
	Change in Funded Status of Pension, SERP and PBOP
		Benefit Plans		(4,356)		(13,645)		(505)
Other Comprehensive Income/(Loss), Net of Tax				(2,168)		(27,316)		97
Comprehensive Income Attributable to Noncontrolling Interest				(103)		(262)		(57)
Comprehensive Income Attributable to Controlling Interest			$	523,777	$	367,377	$	388,046
See the Combined Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for a description of significant accounting matters related to NU parent, including NU common shares information as described in Note 17, "Common Shares," material obligations and guarantees as described in Note 12, "Commitments and Contingencies," and debt agreements as described in Note 8, "Short-Term Debt," and Note 9, "Long-Term Debt."

S-2

SCHEDULE I
NORTHEAST UTILITIES (PARENT)
FINANCIAL INFORMATION OF REGISTRANT
STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 2012, 2011 and 2010
(Thousands of Dollars)
				2012		2011		2010
Operating Activities:
	Net Income			$	526,048	$	394,955	$	388,006
	Adjustments to Reconcile Net Income to Net Cash
		Flows Provided by Operating Activities:
			Equity in Earnings of Subsidiaries		(567,529)		(422,408)		(396,333)
			Cash Dividends Received from Subsidiaries		374,584		389,292		309,669
			Deferred Income Taxes		(25,933)		(15,934)		8,398
			Other		20,219		33,238		23,675
		Changes in Current Assets and Liabilities:
			Receivables, Including Affiliate Receivables		(6,689)		(436)		791
			Taxes Receivable/Accrued, Net		5,062		11,537		(28,394)
			Accounts Payable, Including Affiliate Payables		37,006		(183)		590
			Other Current Assets and Liabilities, Net		22,496		484		(12,656)
Net Cash Flows Provided by Operating Activities					385,264		390,545		293,746
Investing Activities:
	Capital Contributions to Subsidiaries				(81,431)		(233,349)		(313,560)
	Return of Investment in Subsidiaries				8,207		-		5,000
	Decrease in Money Pool Lending				2,200		400		83,300
	(Increase)/Decrease in Notes Receivable from Affiliated Companies				(876,500)		19,000		(29,687)
	Other Investing Activities				(860)		(2,585)		1,703
Net Cash Flows Used in Investing Activities					(948,384)		(216,534)		(253,244)
Financing Activities:
	Cash Dividends on Common Shares				(375,047)		(194,555)		(180,542)
	Issuance of Long-Term Debt				300,000		-		-
	Retirement of Long-Term Debt				(263,000)		-		-
	Increase in Short-Term Debt				894,000		19,000		136,687
	Other Financing Activities				7,355		1,338		2,399
Net Cash Flows Provided by/(Used in) Financing Activities					563,308		(174,217)		(41,456)
Net Increase/(Decrease) in Cash					188		(206)		(954)
Cash - Beginning of Year					62		268		1,222
Cash - End of Year				$	250	$	62	$	268
Supplemental Cash Flow Information:
Cash Paid/(Received) During the Year for:
	Interest			$	29,849	$	24,951	$	22,886
	Income Taxes			$	(33,614)	$	(10,833)	$	1,291
See the Combined Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for a description of significant accounting matters related to NU parent, including NU common shares information as described in Note 17, "Common Shares," material obligations and guarantees as described in Note 12, "Commitments and Contingencies," and debt agreements as described in Note 8, "Short-Term Debt," and Note 9, "Long-Term Debt."

S-3

SCHEDULE II
NORTHEAST UTILITIES AND SUBSIDIARIES
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
FOR THE YEARS ENDED DECEMBER 31, 2012, 2011 AND 2010
(Thousands of Dollars)
Column A		Column B		Column C						Column D		Column E
				Additions
				(1)		(2)		(3)
				Charged		Charged to		Impact
		Balance as		to Costs		Other		Related to		Deductions -		Balance
		of Beginning		and		Accounts -		Merger With		Describe		as of
Description:		of Year (a)		Expenses		Describe (b)		NSTAR		(c)		End of Year
NU:
Reserves Deducted from Assets -
Reserves for Uncollectible Accounts:
	2012	$	115,689	$	36,275	$	34,761	$	59,286	$	80,462	$	165,549
	2011		119,190		16,420		40,663		-		60,584		115,689
	2010		127,517		31,352		45,953		-		85,632		119,190
CL&P:
Reserves Deducted from Assets -
Reserves for Uncollectible Accounts:
	2012	$	83,475	$	2,080	$	27,084	$	-	$	35,068	$	77,571
	2011		82,173		3,215		33,911		-		35,824		83,475
	2010		80,586		7,484		41,639		-		47,536		82,173
NSTAR Electric:
Reserves Deducted from Assets -
Reserves for Uncollectible Accounts:
	2012	$	27,118	$	40,301	$	-	$	-	$	23,304	$	44,115
	2011		29,033		22,582		-		-		24,497		27,118
	2010		26,379		29,417		-		-		26,763		29,033
PSNH:
Reserves Deducted from Assets -
Reserves for Uncollectible Accounts:
	2012	$	7,190	$	6,457	$	2,481	$	-	$	9,368	$	6,760
	2011		6,824		7,035		1,334		-		8,003		7,190
	2010		5,086		8,858		1,017		-		8,137		6,824
WMECO:
Reserves Deducted from Assets -
Reserves for Uncollectible Accounts:
	2012	$	10,018	$	2,294	$	2,428	$	-	$	6,239	$	8,501
	2011		12,891		3,133		1,141		-		7,147		10,018
	2010		16,304		9,747		243		-		13,403		12,891
(a)	Prior year amounts have been reclassified to conform to current year presentation to include uncollectible hardship reserves.  As of December 31, 2011, CL&P, WMECO and Yankee Gas had uncollectible hardship accounts receivable reserves in the amount of $68.6 million, $5.4 million and $6.8 million, respectively.  As of December 31, 2010, CL&P, WMECO and Yankee Gas had uncollectible hardship accounts receivable reserves in the amount of $65 million, $6.9 million and $7.5 million, respectively.
(b)	Amounts relate to uncollectible amounts reserved for that are not charged to bad debt expense.  The PURA issued an order allowing CL&P and Yankee Gas to accelerate the recovery of uncollectible hardship accounts receivable outstanding for greater than 90 days.  As a result of the January 2011 DPU rate case decision, WMECO is allowed to recover amounts associated with basic service and certain uncollectible hardship receivables in rates.
(c)	Amounts written off, net of recoveries.

S-4

EXHIBIT INDEX

Each document described below is incorporated by reference by the registrant(s) listed to the files identified, unless designated with a (*), which exhibits are filed herewith.  Management contracts and compensation plans or arrangements are designated with a (+).

Exhibit

Number

Description

3.

Articles of Incorporation and By-Laws

(A)

Northeast Utilities

3.1

Declaration of Trust of NU, as amended through May 10, 2005 (Exhibit A.1, NU Form U-1 filed June 23, 2005, File No. 70-10315)

(B)

The Connecticut Light and Power Company

3.1

Certificate of Incorporation of CL&P, restated to March 22, 1994 (Exhibit 3.2.1, 1993 CL&P Form 10-K, File No. 000-00404)

3.1.1

Certificate of Amendment to Certificate of Incorporation of CL&P, dated December 26, 1996 (Exhibit 3.2.2, 1996 CL&P Form 10-K filed March 25, 1997, File No. 001-11419)

3.1.2

Certificate of Amendment to Certificate of Incorporation of CL&P, dated April 27, 1998 (Exhibit 3.2.3, 1998 CL&P Form 10-K filed March 23, 1999, File No. 000-00404)

3.1.3

Amended and Restated Certificate of Incorporation of CL&P, dated effective January 3, 2012 (Exhibit 3(i), CL&P Current Report on Form 8-K filed January 9, 2012, File No. 000-00404)

3.2

By-laws of CL&P, as amended to January 1, 1997 (Exhibit 3.2.3, 1996 CL&P Form 10-K filed March 25, 1997, File No. 001-11419)

(C)

NSTAR Electric Company

3.1

NSTAR Electric Company, fka  Boston Edison Company, Restated Articles of Organization (Exhibit 3.1, NSTAR Electric Form 10-Q for the Quarter Ended June 30, 1994 filed August 12, 1994, File No. 001-02301)

3.2

NSTAR Electric Company, fka  Boston Edison Company, Bylaws dated April 19, 1977, as amended January 22, 1987, January 28, 1988, May 24, 1988, November 22, 1989, July 22, 1999, September 20, 1999, January 2, 2007 and March 1, 2011 (Exhibit 3.2, NSTAR Electric 2011 Form 10-K filed February 7, 2012, File No. 001-02301)

(D)

Public Service Company of New Hampshire

3.1

Articles of Incorporation, as amended to May 16, 1991 (Exhibit 3.3.1, 1993 PSNH Form 10-K filed March 25, 1994, File No. 001-06392)

3.2

By-laws of PSNH, as in effect June 27, 2008 (Exhibit 3, PSNH Form 10-Q for the Quarter Ended June 30, 2008 filed August 7, 2008, File No. 001-06392)

(E)

Western Massachusetts Electric Company

3.1

Articles of Organization of WMECO, restated to February 23, 1995 (Exhibit 3.4.1, 1994 WMECO Form 10-K filed March 27, 1995, File No. 001-07624)

3.2

By-laws of WMECO, as amended to April 1, 1999 (Exhibit 3.1, WMECO Form 10-Q for the Quarter Ended June 30, 1999 filed August 13, 1999, File No. 000-07624)

3.2.1

By-laws of WMECO, as further amended to May 1, 2000 (Exhibit 3.1, WMECO Form 10-Q for the Quarter Ended June 30, 2000 filed August 11, 2000, File No. 000-07624)

E-1

4.

Instruments defining the rights of security holders, including indentures

(A)

Northeast Utilities

4.1

Indenture between NU and The Bank of New York as Trustee dated as of April 1, 2002 (Exhibit A-3, NU 35-CERT filed April 16, 2002, File No. 070-09535)

4.1.1

Third Supplemental Indenture between NU and The Bank of New York Trust Company N.A., as Trustee, dated as of June 1, 2008, relating to $250 million of Senior Notes, Series C, due 2013, (Exhibit 4.1, NU Current Report on Form 8-K filed June 10, 2008, File No. 001-05324)

4.1.2

Fourth Supplemental Indenture between NU and The Bank of New York Trust Company N.A., as Trustee, dated as of March 15, 2012, relating to $300 million of Senior Notes, Series D, due 2013, (Exhibit 4.1, NU Current Report on Form 8-K filed March 28, 2012, File No. 001-05324)

4.2

Credit Agreement, dated July 25, 2012, by and among NU, CL&P, NSTAR Gas, NSTAR LLC, PSNH, WMECO, Yankee Gas Services Company and the Banks named therein, pursuant to which Bank of America, N.A. serves as Administrative Agent  (Exhibit 4.1, NU Form 10-Q for the Quarter Ended September 30, 2012, filed November 7, 2012, File No. 001-05324)

(B)

The Connecticut Light and Power Company

4.1

Indenture of Mortgage and Deed of Trust between CL&P and Bankers Trust Company, Trustee, dated as of May 1, 1921 (Composite including all twenty-four amendments to May 1, 1967) (Exhibit 4.1.1, 1989 NU Form 10-K, File No. 001-05324)

4.1.1

Series D Supplemental Indentures to the Composite May 1, 1921 Indenture of Mortgage and Deed of Trust between CL&P and Bankers Trust Company, dated as of October 1, 1994 (Exhibit 4.2.16, 1994 CL&P Form 10-K filed March 27, 1995, File No. 001-11419)

4.1.2

Series A Supplemental Indenture between CL&P and Deutsche Bank Trust Company Americas, as Trustee, dated as of September 1, 2004 (Exhibit 99.2, CL&P Current Report on Form 8-K filed September 22, 2004, File No. 000-00404)

4.1.3

Series B Supplemental Indenture between CL&P and Deutsche Bank Trust Company Americas, as Trustee dated as of September 1, 2004 (Exhibit 99.5, CL&P Current Report on Form 8-K filed September 22, 2004, File No. 000-00404)

4.2

Composite Indenture of Mortgage and Deed of Trust between CL&P and Deutsche Bank Trust Company Americas f/k/a Bankers Trust Company, dated as of May 1, 1921, as amended and supplemented by seventy-three supplemental mortgages to and including Supplemental Mortgage dated as of April 1, 2005 (Exhibit 99.5, CL&P Current Report on Form 8-K filed April 13, 2005, File No. 000-00404)

4.2.1

Supplemental Indenture (2005 Series A Bonds and 2005 Series B Bonds) between CL&P and Deutsche Bank Trust Company Americas, as Trustee dated as of April 1, 2005 (Exhibit 99.2, CL&P Current Report on Form 8-K filed April 13, 2005, File No. 000-00404)

4.2.2

Supplemental Indenture (2006 Series A Bonds) between CL&P and Deutsche Bank Trust Company Americas, as Trustee dated as of June 1, 2006 (Exhibit 99.2, CL&P Current Report on Form 8-K filed June 7, 2006, File No. 000-00404)

4.2.3

Supplemental Indenture (2007 Series A Bonds and 2007 Series B Bonds) between CL&P and Deutsche Bank Trust Company Americas, as Trustee dated as of March 1, 2007 (Exhibit 99.2, CL&P Current Report on Form 8-K filed March 29, 2007, File No. 000-00404)

4.2.4

Supplemental Indenture (2007 Series C Bonds and 2007 Series D Bonds) between CL&P and Deutsche Bank Trust Company Americas, as Trustee dated as of September 1, 2007 (Exhibit 4, CL&P Current Report on Form 8-K filed September 19, 2007, File No. 000-00404)

4.2.5

Supplemental Indenture (2008 Series A Bonds) between CL&P and Deutsche Bank Trust Company Americas, as Trustee dated as of May 1, 2008  (Exhibit 4, CL&P Current Report on Form 8-K filed May 29, 2008, File No. 000-00404)

4.2.6

Supplemental Indenture (2009 Series A Bonds) between CL&P and Deutsche Bank Trust Company Americas, as Trustee dated as of February 1, 2009 (Exhibit 4, CL&P Current Report on Form 8-K filed February 19, 2009, File No. 000-00404)

E-2

4.2.7

Supplemental Indenture (2011 Series A and Series B Bonds) between CL&P and Deutsche Bank Trust Company Americas, as Trustee dated as of October 1, 2011 (Exhibit 4.1, CL&P Current Report on Form 8-K filed October 28, 2011, File No. 000-00404)

4.2.8

Supplemental Indenture (2013 Series A Bond) between CL&P and Deutsche Bank Trust Company Americas, as Trustee dated as of January 1, 2013 (Exhibit 4.1, CL&P Current Report on Form 8-K filed January 22, 2013, File No. 000-00404)

4.3

Amended and Restated Loan Agreement between Connecticut Development Authority and CL&P dated as of May 1, 1996 and Amended and Restated as of January 1, 1997 (Pollution Control Revenue Bond - 1996A Series) (Exhibit 4.2.24, 1996 CL&P Form 10-K filed March 25, 1997, File No. 001-11419)

4.3.1

First Amendment to Amended and Restated Loan Agreement, between the Connecticut Development Authority and CL&P dated as of October 1, 2008 (Pollution Control Revenue Bond-1996A Series) (Exhibit 10.1, CL&P Form 10-Q for the Quarter Ended September 30, 2008, filed November 10, 2008, File No. 000-00404)

4.4

Amended and Restated Indenture of Trust between Connecticut Development Authority and Fleet National Bank, the Trustee dated as of May 1, 1996 and Amended and Restated as of January 1, 1997 (Pollution Control Revenue Bond-1996A Series) (Exhibit 4.2.24.1, 1996 CL&P Form 10-K, filed March 25, 1997, File No. 001-11419)

4.4.1

First Amendment to Amended and Restated Indenture of Trust between Connecticut Development Authority and U.S. Bank National Association, as Trustee dated as of October 1, 2008 (Exhibit 10.2 CL&P Form 10-Q for the Quarter Ended September 30, 2008, filed November 10, 2008, File No. 000-00404)

4.5

Loan Agreement between Connecticut Development Authority and CL&P (Pollution Control Revenue Refunding Bonds – 2011A Series) dated as of October 1, 2011 (Exhibit 1.1, CL&P Current Report on Form 8-K filed October 28, 2011, File No. 000-00404)

4.6

Loan Agreement between Connecticut Development Authority and CL&P (Pollution Control Revenue Refunding Bonds – 2011B Series) dated as of October 1, 2011 (Exhibit 1.2, CL&P Current Report on Form 8-K filed October 28, 2011, File No. 000-00404)

4.7

Credit Agreement, dated March 26, 2012, by CL&P and the Banks named therein, pursuant to which Union Bank, N.A., serves as Administrative Agent (Exhibit 4.1, NU Form 10-Q for the Quarter Ended March 31, 2012, filed May 10, 2012, File No. 001-05324)

4.8

Credit Agreement, dated July 25, 2012, by and among NU, CL&P, NSTAR Gas, NSTAR LLC, PSNH, WMECO, Yankee Gas Services Company and the Banks named therein, pursuant to which Bank of America, N.A. serves as Administrative Agent  (Exhibit 4.1, NU Form 10-Q for the Quarter Ended September 30, 2012, filed November 7, 2012, File No. 001-05324)

(C)

NSTAR Electric Company

4.1

Indenture between Boston Edison Company and the Bank of New York (as successor to Bank of Montreal Trust Company)(Exhibit 4.1, NSTAR Electric Form 10-Q for the Quarter Ended September 30, 1988, File No. 001-02301)

4.1.1

A Form of 4.875% Debenture Due April 15, 2014 (Exhibit 4.3, Boston Edison Company Current  Report on Form 8-K filed April 15, 2004, File No. 001-02301)

4.1.2

A Form of 5.75% Debenture Due March 15, 2036 (Exhibit 99.2, Boston Edison Company Current  Report on Form 8-K filed March 17, 2006, File No. 001-02301)

4.1.3

A Form of 5.625% Debenture Due November 15, 2017 (Exhibit 99.2, NSTAR Electric Company Current Report on Form 8-K filed November 20, 2007 and filed February 17, 2009, File No. 001-02301)

4.1.4

A Form of 5.50% Debenture Due March 15, 2040 (Exhibit 99.2, NSTAR Electric Company Current Report on Form 8-K filed March 15, 2010, File No. 001-02301)

4.1.5

A Form of 2.375% Debenture due 2022. (Exhibit 4, NSTAR Electric Company Current Report on Form 8-K filed October 18, 2012, File No. 001-02301)

4.2

Credit Agreement, dated July 25, 2012, by and between NSTAR Electric and the Banks named therein, pursuant to which Barclays Bank PLC serves as Administrative Agent and Swing Line Lender (Exhibit 4.1, NU Form 10-Q for the Quarter Ended September 30, 2012, filed November 7, 2012, File No. 001-05324)

E-3

(D)

Public Service Company of New Hampshire

4.1

First Mortgage Indenture between PSNH and First Fidelity Bank, National Association, New Jersey, now First Union National Bank, Trustee, dated as of August 15, 1978 (Composite including all amendments effective June 1, 2011) (included as Exhibit C to the Eighteen Supplemental Indenture filed as Exhibit 4.1 to PSNH Current Report on Form 8-K filed June 2, 2011, File No. 001-06392)

4.1.1

Twelfth Supplemental Indenture between PSNH and First Union National Bank dated as of December 1, 2001 (Exhibit 4.3.1.2, 2001 PSNH Form 10-K filed March 22, 2002, File No. 001-06392)

4.1.2

Thirteenth Supplemental Indenture between PSNH and Wachovia Bank, National Association, successor to First Union National Bank, as successor to First Fidelity Bank, National Association, as Trustee dated as of July 1, 2004 (Exhibit 99.2, PSNH Current Report on Form 8-K filed October 5, 2004, File No. 001-06392)

4.1.3

Fourteenth Supplemental Indenture between PSNH and Wachovia Bank, National Association successor to First Union National Bank, as successor to First Fidelity Bank, National Association, as Trustee dated as of October 1, 2005 (Exhibit 99.2, PSNH Current Report on Form 8-K filed October 6, 2005, File No. 001-06392)

4.1.4

Fifteenth Supplemental Indenture between PSNH and Wachovia Bank, National Association successor to First Union National Bank, as successor to First Fidelity Bank, National Association, as Trustee dated as of September 1, 2007 (Exhibit 4.1, PSNH Current Report on Form 8-K filed September 25, 2007, File No. 001-06392)

4.1.5

Sixteenth Supplemental Indenture between PSNH and U.S. Bank National Association, Trustee, dated as of May 1, 2008 (Exhibit 4.1 to PSNH Current Report on Form 8-K filed May 29, 2008 (File No.001-06392)

4.1.6

Seventeenth Supplemental Indenture, between PSNH and U.S. Bank National Association, as Trustee dated as of December 1, 2009 (Exhibit 4.1, PSNH Current Report on Form 8-K filed December 15, 2009 (File No. 001-06392)

4.1.7

Eighteenth Supplemental Indenture, between PSNH and U.S. Bank National Association, as Trustee dated as of May 1, 2011 (Exhibit 4.1, PSNH Current Report on Form 8-K filed June 2, 2011 (File No. 001-06392)

4.1.8

Nineteenth Supplemental Indenture, between PSNH and U.S. Bank National Association, as Trustee dated as of September 1, 2011 (Exhibit 4.1, PSNH Current Report on Form 8-K filed September 16, 2011 (File No. 001-06392)

4.2

Series A Loan and Trust Agreement among Business Finance Authority of the State of New Hampshire and PSNH and State Street Bank and Trust Company, as Trustee (Tax Exempt Pollution Control Bonds) dated as of October 1, 2001 (Exhibit 4.3.4, 2001 NU Form 10-K filed March 22, 2002, File No. 001-05324)

4.3

Series B Loan and Trust Agreement among Business Finance Authority of the State of New Hampshire and PSNH and State Street Bank and Trust Company, as Trustee (Tax Exempt Pollution Control Bonds) dated as of October 1, 2001 (Exhibit 4.3.5, 2001 NU Form 10-K filed March 22, 2002, File No. 001-05324)

4.4

Series C Loan and Trust Agreement among Business Finance Authority of the State of New Hampshire and PSNH and State Street Bank and Trust Company, as Trustee (Tax Exempt Pollution Control Bonds) dated as of October 1, 2001 (Exhibit 4.3.6, 2001 NU Form 10-K filed March 22, 2002, File No. 001-05324)

4.5

Credit Agreement, dated July 25, 2012, by and among NU, CL&P, NSTAR Gas, NSTAR LLC, PSNH, WMECO, Yankee Gas Services Company and the Banks named therein, pursuant to which Bank of America, N.A. serves as Administrative Agent  (Exhibit 4.1, NU Form 10-Q for the Quarter Ended September 30, 2012, filed November 7, 2012, File No. 001-05324)

(E)

Western Massachusetts Electric Company

4.1

Loan Agreement between Connecticut Development Authority and WMECO, (Pollution Control Revenue Bonds - Series A, Tax Exempt Refunding) dated as of September 1, 1993 (Exhibit 4.4.13, 1993 WMECO Form 10-K filed March 25,1994, File No. 000-07624)

4.2

Indenture between WMECO and The Bank of New York, as Trustee, dated as of September 1, 2003 (Exhibit 99.2, WMECO Current Report on Form 8-K filed October 8, 2003, File No. 000-07624)

E-4

4.2.1

First Supplemental Indenture between WMECO and The Bank of New York, as Trustee, dated as of September 1, 2003 (Exhibit 99.3, WMECO Current Report on Form 8-K filed October 8, 2003, File No. 000-07624)

4.2.2

Second Supplemental Indenture between WMECO and The Bank of New York, as Trustee dated as of September 1, 2004 (Exhibit 4.1, WMECO Current Report on Form 8-K filed September 27, 2004, File No. 000-07624)

4.2.3

Third Supplemental Indenture between WMECO and The Bank of New York Trust, as Trustee, dated as of August 1, 2005 (Exhibit 4.1, WMECO Current Report on Form 8-K filed August 12, 2005, File No. 000-07624)

4.2.4

Fourth Supplemental Indenture between WMECO and The Bank of New York Trust, as Trustee, dated as of August 1, 2007 (Exhibit 4.1, WMECO Current Report on Form 8-K filed August 20, 2007, File No. 000-07624)

4.2.5

Fifth Supplemental Indenture between WMECO and The Bank of New York Trust Company, N.A., as Trustee, dated as of March 1, 2010 (Exhibit 4.1, WMECO Current Report on Form 8-K filed March 10, 2010, File No. 000-07624)

4.2.6

Sixth Supplemental Indenture between WMECO and The Bank of New York Trust Company, N.A., as Trustee, dated as of September 15, 2011 (Exhibit 4.1, WMECO Current Report on Form 8-K filed September 19, 2011, File No. 000-07624)

4.3

Credit Agreement, dated July 25, 2012, by and among NU, CL&P, NSTAR Gas, NSTAR LLC, PSNH, WMECO, Yankee Gas Services Company and the Banks named therein, pursuant to which Bank of America, N.A. serves as Administrative Agent  (Exhibit 4.1, NU Form 10-Q for the Quarter Ended September 30, 2012, filed November 7, 2012, File No. 001-05324)

10.

Material Contracts

(A)

NU

10.1

Lease between The Rocky River Realty Company and Northeast Utilities Service Company dated as of April 14, 1992 with respect to the Berlin, Connecticut headquarters (Exhibit 10.29.1, 1992 NU Form 10-K, File No. 001-05324)

10.2

Indenture of Mortgage and Deed of Trust between Yankee Gas Services Company and the Connecticut National Bank, as Trustee, dated July 1, 1989 (Exhibit 4.7, Yankee Energy System, Inc. Form 10-K for the year ended September 30, 1990, File No. 001-10721)

10.2.1

First Supplemental Indenture of Mortgage and Deed of Trust between Yankee Gas Services Company and The Connecticut National Bank, as Trustee, dated April 1, 1992 (Yankee Energy System, Inc. Registration Statement on Form S-3, dated October 2, 1992, File No. 33-52750)

10.2.2

Sixth Supplemental Indenture of Mortgage and Deed of Trust between Yankee Gas Services Company and The Bank of New York, as Successor Trustee to Fleet Bank (formerly The Connecticut National Bank) dated January 1, 2004 (Exhibit 10.5.6, 2004 NU Form 10-K filed March 17, 2005, File No. 001-05324)

10.2.3

Seventh Supplemental Indenture of Mortgage and Deed of Trust between Yankee Gas Services Company and The Bank of New York, as Successor Trustee to Fleet Bank (formerly The Connecticut National Bank) dated November 1, 2004 (Exhibit 10.5.7, 2004 NU Form 10-K filed March 17, 2005, File No. 001-05324)

10.2.4

Eighth Supplemental Indenture of Mortgage and Deed of Trust between Yankee Gas Services Company and The Bank of New York, as Successor Trustee to Fleet Bank (formerly the Connecticut National Bank) dated July 1, 2005 (Exhibit 10.5.8, NU Form 10-Q for the Quarter Ended June 30, 2005 filed August 8, 2005, File No. 001-05324)

10.2.5

Ninth Supplemental Indenture of Mortgage and Deed of Trust between Yankee Gas Services Company and The Bank of New York Mellon Trust Company, N.A., successor as Trustee to The Bank of New York, as successor to Fleet National Bank (formerly known as The Connecticut National Bank) dated as of October 1, 2008 (Exhibit 10-1, NU Form 10-Q for the Quarter Ended September 30, 2008 filed November 10, 2008, File No. 001-05324)

E-5

10.2.6

Tenth Supplemental Indenture of Mortgage and Deed of Trust between Yankee Gas Services Company and The Bank of New York Mellon Trust Company, N.A., successor as Trustee to The Bank of New York, as successor to Fleet National Bank (formerly known as The Connecticut National Bank), dated as of April 1, 2010 (Exhibit 10, NU Form 10-Q for the Quarter Ended March 31, 2010 filed May 7, 2010, File No. 001-05324)

10.3

Indenture dated as of January 12, 2000 between NSTAR LLC, successor to NSTAR, and Bank One Trust Company N.A. (Exhibit 4.1 to NSTAR Registration Statement on Form S-3, File No. 333-94735)

10.3.1

Form of 4.50% Debenture Due 2019 (Exhibit 99.2, NSTAR Form 8-K filed November 16, 2009, File No. 001-14768)

* +10.4

Northeast Utilities Board of Trustees' Compensation Arrangement Summary

  +10.5

Amended and Restated Northeast Utilities Deferred Compensation Plan for Trustees, effective January 1, 2009 (Exhibit  10.6, NU Form 10-Q for the Quarter Ended September 30, 2008 filed November 10, 2008, File No. 001-05324)

10.6

Transmission Service Agreement by and between Northern Pass Transmission LLC, as Owner and H.Q. Hydro Renewable Energy, Inc., as Purchaser dated October 4, 2010 (Exhibit 10.6, 2010 NU Form 10-K filed February 25, 2011, File No. 001-05324)

(D)

NU, CL&P, PSNH and WMECO

10.1

Form of Service Contract between each of NU, CL&P and WMECO and Northeast Utilities Service Company (NUSCO) dated as of July 1, 1966 (Exhibit 10.20, 1993 NU Form 10-K filed March 25, 1994, File No. 001-05324)

10.1.1

Form of Renewal of Service Contract (Exhibit 10.2, 2006 NU Form 10-K filed March 1, 2007, File No. 001-05324)

10.2

Agreements among New England Utilities with respect to the Hydro-Quebec interconnection projects (Exhibits 10(u) and 10(v); 10(w), 10(x), and 10(y), 1990 and 1988, respectively, Form 10-K of New England Electric System, File No. 001-03446)

10.3

Transmission Operating Agreement between the Initial Participating Transmission Owners, Additional Participating Transmission Owners and ISO New England, Inc. dated as of February 1, 2005 (Exhibit 10.29, 2004 NU Form 10-K filed March 17, 2005, File No. 001-05324)

10.3.1

Rate Design and Funds Disbursement Agreement among the Initial Participating Transmission Owners, Additional Participating Transmission Owners and ISO New England, Inc., effective June 30, 2006 (Exhibit 10.22.1, 2006 NU Form 10-K filed March 1, 2007, File No. 001-05324)

10.4

Northeast Utilities Service Company Transmission and Ancillary Service Wholesale Revenue Allocation Methodology among The Connecticut Light and Power Company, Western Massachusetts Electric Company, Public Service Company of New Hampshire, Holyoke Water Power Company and Holyoke Power and Electric Company Trustee dated as of January 1, 2008 (Exhibit 10.1, NU Form 10-Q for the Quarter Ended March 31, 2008 filed May 9, 2008, File No. 001-05324)

+10.5

Amended and Restated Employment Agreement with Gregory B. Butler, effective January 1, 2009 (Exhibit 10.7, 2008 NU Form 10-K filed February 27, 2009, File No. 001-05324)

+10.6

Amended and Restated Employment Agreement with David R. McHale, effective January 1, 2009 (Exhibit 10.8, 2008 NU Form 10-K filed February 27, 2009, File No. 001-05324)

+10.7

Amended and Restated Memorandum Agreement between Northeast Utilities and Leon J. Olivier effective January 1, 2009 (Exhibit 10.9, 2008 NU Form 10-K filed February 27, 2009, File No. 001-05324)

+10.8

Amendment and Restatement of Agreement between Northeast Utilities and James A. Muntz effective January 1, 2009 (Exhibit 10.17, 2012 NU Form 10-K filed February 24, 2012, File No. 001-05324)

+10.9

Amended and Restated Incentive Plan Effective January 1, 2009 (Exhibit 10.3, NU Form 10-Q for the Quarter Ended September 30, 2008 filed November 10, 2008, File No. 001-05324)

+10.10

Amended and Restated Supplemental Executive Retirement Plan for Officers of Northeast Utilities System Company effective January 1, 2009 (Exhibit 10.5, NU Form 10-Q for the Quarter Ended September 30, 2008 filed November 10, 2008, File No. 001-05324)

E-6

+10.11

Trust under Supplemental Executive Retirement Plan dated May 2, 1994 (Exhibit 10.33, 2002 NU Form 10-K filed March 21, 2003, File No. 001-05324)

 +10.11.1

First Amendment to Trust Under Supplemental Executive Retirement Plan, effective as of December 10, 2002 (Exhibit 10 (B) 10.19.1, 2003 NU Form 10-K filed March 12, 2004, File No. 001-05324)

 +10.11.2

Second Amendment to Trust Under Supplemental Executive Retirement Plan , effective as of November 12, 2008 (Exhibit 10.12.2, 2008 NU Form 10-K filed February 27, 2009, File No. 001-05324)

+10.12

Special Severance Program for Officers of NU System Companies as of January 1, 2009, (Exhibit 10.2, NU Form 10-Q for the Quarter Ended September 30, 2008 filed November 10, 2008, File No. 001-05324)

+10.13

Amended and Restated Northeast Utilities Deferred Compensation Plan for Executives effective as of January 1, 2009 (Exhibit 10.4 NU Form 10-Q for Quarter Ended September 30, 2008 filed November 10, 2008, File No. 001-05324)

+10.14

Northeast Utilities Retention Agreement (Exhibit 10.1, NU Registration Statement on Form S-4, filed November 22, 2010, File No. 333-170754)

10.15

Northeast Utilities System's Third Amended and Restated Tax Allocation Agreement dated as of April 10, 2012, (Exhibit 10.1 NU Form 10-Q for Quarter Ended June 30, 2012 filed August 7, 2012, File No. 001-05324)

(C)

NU and CL&P

10.1

CL&P Agreement Re: Connecticut NEEWS Projects by and between CL&P and The United Illuminating Company dated July 14, 2010 (Exhibit 10, CL&P Form 10-Q for the Quarter Ended June 30, 2010 filed August 6, 2010, File No. 000-00404)

(C)

NU and NSTAR Electric

10.1

NSTAR Electric Company Restructuring Settlement Agreement dated July 1997  

(Exhibit  10.12, Boston Edison 1997 Form 10-K filed March 30, 1998, File No. 001-02301)

10.2

Amended and Restated Power Purchase Agreement (NEA A PPA), dated August 19, 2004, by and between Boston Edison and Northeast Energy Associates L.P. (Exhibit 10.18, 2005 NSTAR Form 10-K filed February 21, 2006, File No. 001-14768)

10.3

Amended and Restated Power Purchase Agreement (NEA B PPA), dated August 19, 2004, by and between ComElectric and Northeast Energy Associates L. P. (Exhibit 10.19,  2005 NSTAR Form 10-K filed February 21, 2006, File No. 001-14768)

10.4

Amended and Restated Power Purchase Agreement (CECO 1 PPA), dated August 19, 2004 by and between ComElectric and Northeast Energy Associates L. P. (Exhibit 10.20, 2005 NSTAR Form 10-K filed February 21, 2006, File No.001-14768)

10.5

Amended and Restated Power Purchase Agreement (CECO 2 PPA), dated August 19, 2004 by and between ComElectric and Northeast Energy Associates L. P. (Exhibit 10.21, 2005 NSTAR Form 10-K filed February 21, 2006, File No. 001-14768)

10.6

The Bellingham Execution Agreement, dated August 19, 2004 between Boston Edison, ComElectric and Northeast Energy Associates L. P. (Exhibit 10.22, 2005 NSTAR Form 10-K filed February 21, 2006, File No. 001-14768)

10.7

Second Restated NEPOOL Agreement among NSTAR Electric and various other electric utilities operating in New England, dated August 16, 2004 (Exhibit 10.2.1.1, 2005 NSTAR Form 10-K filed February 21, 2006, File No. 001-14768)

10.8

Transmission Operating Agreement among NSTAR Electric and various electric transmission providers in New England and ISO New England Inc., dated February 1, 2005 (Exhibit 10.2.1.2, 2005 NSTAR Form 10-K filed February 21, 2006, File No. 001-14768)

10.9

Market Participants Service Agreement among NSTAR Electric and various other electric utilities operating in New England, NEPOOL and ISO New England Inc., dated February 1, 2005 (Exhibit 10.2.1.3, 2005 NSTAR Form 10-K filed February 21, 2006, File No. 001-14768)

E-7

10.10

Rate Design and Funds Disbursement Agreement among NSTAR Electric and various other electric transmission providers in New England, dated February 1, 2005 (Exhibit 10.2.1.4, 2005 NSTAR Form 10-K filed February 21, 2006, File No. 001-14768)

10.11

Participants Agreement among NSTAR Electric, various electric utilities operating in New England, NEPOOL and ISO-New England, Inc., dated February 1, 2005. (Exhibit 10.2.1.4, 2006 NSTAR Form 10-K filed February 16, 2007, File No. 001-14768)

+10.12

NSTAR Excess Benefit Plan, effective August  25, 1999 (Exhibit 10.1 1999 NSTAR Form 10-K/A filed September 29, 2000, File No. 001-14768)

+10.12.1

NSTAR Excess Benefit Plan, incorporating the NSTAR 409A Excess Benefit Plan, as amended and restated effective January 1, 2008, dated December 24, 2008 (Exhibit 10.1.1 2008 NSTAR Form 10-K filed February 9, 2009, File No. 001-14768)

+10.13

NSTAR Supplemental Executive Retirement Plan, effective August 25, 1999 (Exhibit 10.2,1999 NSTAR Form 10-K/A filed September 29, 2000, File No. 001-14768)

+10.13.1

NSTAR Supplemental Executive Retirement Plan, incorporating the NSTAR 409A Supplemental Executive Retirement Plan, as amended and restated effective January 1, 2008, dated December 24, 2008 (Exhibit 10.2.1, 2008 NSTAR Form 10-K filed February 9, 2009, File No. 001-14768)

+10.14

Special Supplemental Executive Retirement Agreement between Boston Edison Company and Thomas J. May dated March 13, 1999, regarding Key Executive Benefit Plan and Supplemental Executive Retirement Plan (Exhibit 10.3, 1999 NSTAR Form 10-K/A filed September 9, 2000, File No. 001-14768)

+10.15

Amended and Restated Change in Control Agreement by and between NSTAR and Thomas J. May dated November 15, 2007 (Exhibit 10.5, 2007 NSTAR Form 10-K filed February 11, 2008, File No. 001-14768)

+10.16

NSTAR Deferred Compensation Plan, (Restated Effective August 25, 1999) (Exhibit 10.10, 1999 NSTAR Form 10-K/A filed September 29, 2000, File No. 001-14768)

+10.16.1

NSTAR Deferred Compensation Plan, incorporating the NSTAR 409A Deferred Compensation Plan, as amended and restated effective January 1, 2008, dated December 24, 2008 (Exhibit 10.6.1, 2008 NSTAR Form 10-K filed February 9, 2009, File No. 001-14768)

+10.17

NSTAR 1997 Share Incentive Plan, as amended June 30, 1999 and assumed by NSTAR effective August 28, 2000, as amended January 24, 2002 (Exhibit 10.1, NU Registration Statement on Form S-8 filed on May 8, 2012)

+10.18

NSTAR 2007 Long Term Incentive Plan, effective May 3, 2007 (Exhibit 10.2, NU Registration Statement on Form S-8 filed on May 8, 2012)

+10.18.1

Deferred Common Share/Dividend Equivalent Award, Stock Option Grant, Option Certificate and Performance Share Award/Dividend Equivalent Award Agreement Under the NSTAR 2007 Long Term Incentive Plan, by and between NSTAR and Thomas J. May, dated January 24, 2008 (Exhibit 10.8.1, 2007 NSTAR Form 10-K filed February 11, 2008, File No. 001-14768)

+10.18.2

Deferred Common Share/Dividend Equivalent Award, Stock Option Grant, Option Certificate and Performance Share Award/Dividend Equivalent Award Agreement Under the NSTAR 2007 Long Term Incentive Plan, by and between NSTAR and James J. Judge, dated January 24, 2008 (Exhibit 10.8.2, 2007 NSTAR Form 10-K filed February 11, 2008, File No. 001-14768)

+10.18.3

Deferred Common Share/Dividend Equivalent Award, Stock Option Grant, Option Certificate and Performance Share Award/Dividend Equivalent Award Agreement Under the NSTAR 2007 Long Term Incentive Plan by and between NSTAR and NSTAR’s other Senior Vice Presidents and Vice Presidents, dated January 24, 2008 (in form) (Exhibit 10.8.6, 2007 NSTAR Form 10-K filed February 11, 2008, File No. 001-14768)

+10.19

Amended and Restated Change in Control Agreement by and between James J. Judge and NSTAR, dated November 15, 2007 (Exhibit 10.9, 2007 NSTAR Form 10-K filed February 11, 2008, File No. 001-14768)

+10.20

NSTAR Trustees’ Deferred Plan (Restated Effective August 25, 1999), dated October 20, 2000 (Exhibit 10.4, NSTAR Form 10-Q for the quarter ended September 30, 2000 filed November 14, 2000, File No. 001-14768)

E-8

10.20.1

NSTAR Trustees’ Deferred Plan, incorporating the 409A Trustees’ Deferred Plan, effective January 1, 2008, dated December 24, 2008 (Exhibit 10.10.1, 2008 NSTAR Form 10-K filed February 9, 2009, File No. 001-14768)

+10.21

Master Trust Agreement between NSTAR and State Street Bank and Trust Company (Rabbi Trust), effective August 25, 1999 (Exhibit 10.5, NSTAR Form 10-Q for the Quarter Ended September 30, 2000 filed November 14, 2000, File No. 001-14768)

+10.22

Amended and Restated Change in Control Agreement by and between NSTAR’s other Senior Vice Presidents and NSTAR (in form), dated November 15, 2007 (Exhibit 10.15, 2007 NSTAR Form 10-K filed February 11, 2008, File No. 001-14768)

+10.23

Amended and Restated Change in Control Agreement between NSTAR’s Vice Presidents and NSTAR (in form), dated November 15, 2007 (Exhibit 10.16, 2007 NSTAR Form 10-K filed February 11, 2008, File No. 001-14768)

+10.24

Currently effective Change in Control Agreement between NSTAR’s Vice Presidents and NSTAR (in form) (Exhibit 10.17, 2009 NSTAR Form 10-K filed February 25, 2010, File No. 001-14768)

+10.25

Executive Retention Award Agreement, dated November 19, 2010, by and between NSTAR and James J. Judge (Exhibit 99.2, NSTAR Current Report on Form 8-K filed November 22, 2010, File No. 001-14768)

10.26

MDTE Order approving Rate Settlement Agreement dated December 31, 2005 (Exhibit 99.2, NSTAR Current Report on Form 8-K filed January 4, 2006, File No. 001-14768)

(D)

NU and PSNH

10.1

PSNH Purchase and Sale Agreement with PSNH Funding LLC dated as of April 25, 2001 (Exhibit 10.57, 2001 NU Form 10-K filed March 22, 2002, File No. 001-05324)

10.2

PSNH Servicing Agreement with PSNH Funding LLC dated as of April 25, 2001 (Exhibit 10.58, 2001 NU Form 10-K filed March 22, 2002, File No. 001-05324)

(E)

NU and WMECO

10.1

Lease and Agreement by and between WMECO and Bank of New England, N.A., with BNE Realty Leasing Corporation of North Carolina dated as of December 15, 1988, (Exhibit 10.63, 1988 NU Form 10-K, File No. 001-05324)

10.2

WMECO Transition Property Purchase and Sale Agreement between WMECO Funding LLC and WMECO, dated as of May 17, 2001 (Exhibit 10.61, 2001 NU Form 10-K filed March 22, 2002, File No. 000-05324)

10.3

WMECO Transition Property Servicing Agreement between WMECO Funding LLC and WMECO, dated as of May 17, 2001 (Exhibit 10.62, 2001 NU Form 10-K filed March 22, 2002, File No. 000-05324)

*12.

Ratio of Earnings to Fixed Charges

(A)

Northeast Utilities

(B)

The Connecticut Light and Power Company

(C)

NSTAR Electric Company

(D)

Public Service Company of New Hampshire

(E)

Western Massachusetts Electric Company

*21.

Subsidiaries of the Registrant

E-9

*23.

Consents of Independent Registered Public Accounting Firms

23.1

Deloitte & Touche LLP

23.2

PricewaterhouseCoopers LLP

*31.

Rule 13a – 14(a)/15 d – 14(a) Certifications

(A)

Northeast Utilities

31

Certification of Thomas J. May, President and Chief Executive Officer of NU required by Rule 13a – 14(a)/15d – 14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated February 27, 2013

31.1

Certification of James J. Judge, Executive Vice President and Chief Financial Officer of NU required by Rule 13a – 14(a)/15d – 14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated February 27, 2013

(B)

The Connecticut Light and Power Company

31

Certification of Leon J. Olivier, Chief Executive Officer of CL&P required by Rule 13a – 14(a)/15d – 14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated February 27, 2013

31.1

Certification of James J. Judge, Executive Vice President and Chief Financial Officer of CL&P required by Rule 13a – 14(a)/15d – 14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated February 27, 2013

(C)

NSTAR Electric Company

31

Certification of Leon J. Olivier, Chief Executive Officer of NSTAR Electric Company, required by Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated February 27, 2013

31.1

Certification of James J. Judge, Executive Vice President and Chief Financial Officer of NSTAR Electric Company, required by Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated February 27, 2013

(D)

Public Service Company of New Hampshire

31

Certification of Leon J. Olivier, Chief Executive Officer of PSNH required by Rule 13a – 14(a)/15d – 14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated February 27, 2013

31.1

Certification of James J. Judge, Executive Vice President and Chief Financial Officer of PSNH required by Rule 13a – 14(a)/15d – 14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated February 27, 2013

(E)

Western Massachusetts Electric Company

31

Certification of Leon J. Olivier, Chief Executive Officer of WMECO required by Rule 13a – 14(a)/15d – 14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated February 27, 2013

31.1

Certification of James J. Judge, Executive Vice President and Chief Financial Officer of WMECO required by Rule 13a – 14(a)/15d – 14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated February 27, 2013

E-10

*32

18 U.S.C. Section 1350 Certifications

(A)

Northeast Utilities

32

Certification of Thomas J. May, President and Chief Executive Officer of Northeast Utilities and James J. Judge, Executive Vice President and Chief Financial Officer of Northeast Utilities, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, dated February 27, 2013

(B)

The Connecticut Light and Power Company

32

Certification of Leon J. Olivier, Chief Executive Officer of The Connecticut Light and Power Company and James J. Judge, Executive Vice President and Chief Financial Officer of The Connecticut Light and Power Company, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, dated February 27, 2013

(C)

NSTAR Electric Company

32

Certification of Leon J. Olivier, Chief Executive Officer of NSTAR Electric Company and James J. Judge, Executive Vice President and Chief Financial Officer of NSTAR Electric Company, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, dated February 27, 2013

(D)

Public Service Company of New Hampshire

32

Certification of Leon J. Olivier, Chief Executive Officer of Public Service Company of New Hampshire and James J. Judge, Executive Vice President and Chief Financial Officer of Public Service Company of New Hampshire, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, dated February 27, 2013

(E)

Western Massachusetts Electric Company

32

Certification of Leon J. Olivier, Chief Executive Officer of Western Massachusetts Electric Company and David R. McHale, Executive Vice President and Chief Financial Officer of Western Massachusetts Electric Company, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, dated February 27, 2013

*101.INS

XBRL Instance Document

*101.SCH

XBRL Taxonomy Extension Schema

*101.CAL

XBRL Taxonomy Extension Calculation

*101.DEF

XBRL Taxonomy Extension Definition

*101.LAB

XBRL Taxonomy Extension Labels

*101.PRE

XBRL Taxonomy Extension Presentation

E-11

EX-10.4

Exhibit 10.4

SUMMARY OF TRUSTEE COMPENSATION ARRANGEMENTS

Northeast Utilities (“NU”) pays each non-employee Trustee serving on January 1 an annual cash retainer in the amount of $100,000 for service on the Board during his or her term of office, including participation in all Board and Committee meetings.  In addition, Trustees holding the positions of Non-Executive Chairman of the Board, Lead Trustee, Chair of the Audit Committee, Chair of the Compensation Committee, Chair of the Corporate Governance Committee, and Chair of the Finance Committee on January 1 receive annual cash retainers in the amounts set forth below.  All cash retainers are payable in equal installments on the first business day of each calendar quarter.  

Retainer	Annual Amount
Non-Executive Chairman of the Board	$200,000
Lead Trustee	$25,000
Audit Committee Chair	$15,000
Compensation Committee Chair	$10,000
Corporate Governance Committee Chair	$10,000
Finance Committee Chair	$10,000

Each non-employee Trustee serving on January 1 also receives a grant under the Northeast Utilities Incentive Plan (the “Plan”), on the 10th business day of such year, of that number of Restricted Share Units (“RSUs”) resulting from dividing $100,000 by the average closing price of our common shares as reported on the New York Stock Exchange for the 10 trading days immediately preceding such date and rounding the resulting amount to the nearest whole RSU.  RSUs vest on the next business day following the grant, and distribution to the Trustee in equivalent common shares is deferred until the tenth business day of January in the year following retirement from Board service.  Any individual who is elected to serve as a Trustee after January 1 in any year receives an RSU grant prorated from the date of such election and granted on the first business day of the month following such election.  

On January 15, 2013, each non-employee Trustee was granted 2,545 RSUs under the Plan, all of which vested on January 16, 2013.

Share ownership guidelines set forth in NU’s Corporate Governance Guidelines require each Trustee to attain and hold 7,500 common shares and/or RSUs within five years after January 1 of the year following the date of their election to the Board.  All of the current Trustees exceed the share ownership guidelines or are expected to do so within the stated period.

Pursuant to the Northeast Utilities Deferred Compensation Plan for Trustees, prior to the beginning of each calendar year, each Trustee may irrevocably elect to defer receipt of all or a portion of their cash compensation.  Deferred funds are credited with interest at the rate set forth in Section 37-1 of the Connecticut General Statutes, which rate was 8% for all of 2012.  Deferred compensation is payable either in a lump sum or in one to five annual installments in accordance with the Trustee’s prior election.

In addition, NU pays travel-related expenses for spouses of Trustees who attend Board functions.  The Internal Revenue Service considers payment of travel expenses for a Trustee’s spouse to be imputed income to the individual Trustee.  Effective January 1, 2009, NU discontinued tax gross-up payments in connection with spousal travel expenses.

EX-12

Northeast Utilities										Exhibit 12
Ratio of Earnings to Fixed Charges
(Thousands of Dollars)
	For the Years Ended December 31,
		2012 (a)		2011		2010		2009		2008
Earnings, as defined:
Net income	$	533,077	$	400,513	$	394,107	$	335,592	$	266,387
Income tax expense		274,926		170,953		210,409		179,947		105,661
Equity in earnings of regional nuclear
generating and transmission companies		(1,154)		(671)		(1,429)		(1,762)		(1,637)
Dividends received from regional equity investees		733		940		1,488		3,794		1,017
Fixed charges, as below		353,616		275,948		263,393		296,764		304,374
Less: Interest capitalized (including AFUDC)		(5,261)		(11,758)		(10,165)		(5,929)		(17,797)
Preferred dividend security requirements of
consolidated subsidiaries		(11,715)		(9,265)		(10,170)		(9,265)		(9,265)
Total earnings, as defined	$	1,144,222	$	826,660	$	847,633	$	799,141	$	648,740
Fixed charges, as defined:
Interest on long-term debt (b)	$	316,987	$	231,630	$	231,089	$	224,712	$	193,883
Interest on rate reduction bonds		6,168		8,611		20,573		36,524		50,231
Other interest (c)		6,790		10,184		(14,371)		12,401		25,031
Rental interest factor		6,695		4,500		5,767		7,933		8,167
Preferred dividend security requirements of
consolidated subsidiaries		11,715		9,265		10,170		9,265		9,265
Interest capitalized (including AFUDC)		5,261		11,758		10,165		5,929		17,797
Total fixed charges, as defined	$	353,616	$	275,948	$	263,393	$	296,764	$	304,374
Ratio of Earnings to Fixed Charges		3.24		3.00		3.22		2.69		2.13
(a) The 2012 results include the operations of NSTAR from the date of the merger, April 10, 2012, through December 31, 2012.
(b) Interest on long-term debt includes amortized premiums, discounts and capitalized expenses related to indebtedness.
(c) For all years presented, other interest includes interest related to accounting for uncertain tax positions.

EX-12

The Connecticut Light and Power Company										Exhibit 12
Ratio of Earnings to Fixed Charges
(Thousands of Dollars)
	For the Years Ended December 31,
		2012		2011		2010		2009		2008
Earnings, as defined:
Net income	$	209,725	$	250,164	$	244,143	$	216,316	$	191,158
Income tax expense		94,437		90,033		132,438		118,847		77,852
Equity in earnings of regional nuclear
generating companies		(40)		(16)		(134)		(282)		(366)
Dividends received from regional equity investees		-		-		440		1,520		-
Fixed charges, as below		139,982		140,311		145,297		163,887		165,170
Less: Interest capitalized (including AFUDC)		(2,456)		(3,317)		(2,726)		(2,203)		(12,991)
Total earnings, as defined	$	441,648	$	477,175	$	519,458	$	498,085	$	420,823
Fixed charges, as defined:
Interest on long-term debt (a)	$	124,894	$	131,918	$	134,553	$	133,422	$	104,954
Interest on rate reduction bonds		-		-		7,542		19,061		29,129
Other interest (b)		8,233		809		(4,357)		3,334		12,163
Rental interest factor		4,399		4,267		4,833		5,867		5,933
Interest capitalized (including AFUDC)		2,456		3,317		2,726		2,203		12,991
Total fixed charges, as defined	$	139,982	$	140,311	$	145,297	$	163,887	$	165,170
Ratio of Earnings to Fixed Charges		3.16		3.40		3.58		3.04		2.55
(a) Interest on long-term debt includes amortized premiums, discounts and capitalized expenses related to indebtedness.
(b) For all years presented, other interest includes interest related to accounting for uncertain tax positions.

EX-12

NSTAR Electric Company										Exhibit 12
Ratio of Earnings to Fixed Charges
(Thousands of Dollars)
	For the Years Ended December 31,
		2012		2011		2010		2009		2008
Earnings, as defined:
Net income	$	190,242	$	252,494	$	248,575	$	240,691	$	223,897
Income tax expense		123,966		165,686		162,020		151,224		141,847
Equity in earnings of regional nuclear
generating and transmission companies		(412)		(501)		(836)		(891)		(820)
Dividends received from regional equity investees		286		676		669		1,661		416
Fixed charges, as below		72,364		76,219		77,902		84,826		103,661
Less: Interest capitalized (including AFUDC) (b)		(259)		(185)		(108)		76		(1,926)
Total earnings, as defined	$	386,187	$	494,389	$	488,222	$	477,587	$	467,075
Fixed charges, as defined:
Interest on long-term debt (a) (b)	$	87,100	$	90,040	$	90,630	$	83,261	$	76,793
Interest on rate reduction bonds (b)		3,585		7,226		11,235		18,833		27,076
Other interest (b) (c)		(20,631)		(27,839)		(30,475)		(24,519)		(9,789)
Rental interest factor		2,051		6,607		6,404		7,327		7,655
Interest capitalized (including AFUDC) (b)		259		185		108		(76)		1,926
Total fixed charges, as defined	$	72,364	$	76,219	$	77,902	$	84,826	$	103,661
Ratio of Earnings to Fixed Charges		5.34		6.49		6.27		5.63		4.51
(a) Interest on long-term debt includes amortized premiums, discounts and capitalized expenses related to indebtedness.
(b) Prior period amounts have been reclassified for comparative purposes and in order to conform to NU's presentation.
(c) For the years ended December 31, 2011, 2010, 2009 and 2008, other interest includes interest related to accounting for uncertain tax positions.

EX-12

Public Service Company of New Hampshire										Exhibit 12
Ratio of Earnings to Fixed Charges
(Thousands of Dollars)
	For the Years Ended December 31,
		2012		2011		2010		2009		2008
Earnings, as defined:
Net income	$	96,882	$	100,267	$	90,067	$	65,570	$	58,067
Income tax expense		60,993		49,945		50,801		31,990		21,996
Equity in earnings of regional nuclear
generating companies		(8)		(7)		(23)		(50)		(62)
Dividends received from regional equity investees		-		-		80		220		-
Fixed charges, as below		52,769		52,111		54,721		51,227		54,597
Less: Interest capitalized (including AFUDC)		(1,579)		(7,064)		(6,621)		(3,138)		(2,967)
Total earnings, as defined	$	209,057	$	195,252	$	189,025	$	145,819	$	131,631
Fixed charges, as defined:
Interest on long-term debt (a)	$	46,228	$	36,832	$	36,220	$	33,045	$	32,655
Interest on rate reduction bonds		2,687		6,276		9,660		13,128		15,969
Other interest (b)		1,313		1,039		1,187		316		1,539
Rental interest factor		962		900		1,033		1,600		1,467
Interest capitalized (including AFUDC)		1,579		7,064		6,621		3,138		2,967
Total fixed charges, as defined	$	52,769	$	52,111	$	54,721	$	51,227	$	54,597
Ratio of Earnings to Fixed Charges		3.96		3.75		3.45		2.85		2.41
(a) Interest on long-term debt includes amortized premiums, discounts and capitalized expenses related to indebtedness.
(b) For the years ended December 31, 2011, 2010 and 2009, other interest includes interest related to accounting for uncertain tax positions.

EX-12

Western Massachusetts Electric Company										Exhibit 12
Ratio of Earnings to Fixed Charges
(Thousands of Dollars)
	For the Years Ended December 31,
		2012		2011		2010		2009		2008
Earnings, as defined:
Net income	$	54,503	$	43,054	$	23,090	$	26,196	$	18,330
Income tax expense		32,140		23,186		16,325		14,923		10,545
Equity in earnings of regional nuclear
generating companies		(11)		(4)		(36)		(78)		(101)
Dividends received from regional equity investees		-		-		120		419		-
Fixed charges, as below		28,162		25,079		23,042		20,614		21,910
Less: Interest capitalized (including AFUDC)		(534)		(534)		(336)		(195)		(1,010)
Total earnings, as defined	$	114,260	$	90,781	$	62,205	$	61,879	$	49,674
Fixed charges, as defined:
Interest on long-term debt (a)	$	23,462	$	20,023	$	17,988	$	14,074	$	13,244
Interest on rate reduction bonds		1,229		2,335		3,372		4,335		5,133
Other interest (b)		1,943		1,254		479		877		1,256
Rental interest factor		994		933		867		1,133		1,267
Interest capitalized (including AFUDC)		534		534		336		195		1,010
Total fixed charges, as defined	$	28,162	$	25,079	$	23,042	$	20,614	$	21,910
Ratio of Earnings to Fixed Charges		4.06		3.62		2.70		3.00		2.27
(a) Interest on long-term debt includes amortized premiums, discounts and capitalized expenses related to indebtedness.
(b) For the years ended December 31, 2009 and 2008, other interest includes interest related to accounting for uncertain tax positions.

EX-21

Exhibit 21

Subsidiaries of the Registrants

				State of Incorporation
Northeast Utilities (a Massachusetts business trust)*				MA
	The Connecticut Light and Power Company*			CT
		CL&P Funding LLC		DE
	HWP Company			MA
	North Atlantic Energy Corporation			NH
	North Atlantic Energy Service Corporation			NH
	Northeast Nuclear Energy Company			CT
	Northeast Utilities Service Company			CT
	NSTAR LLC			MA
		Advanced Energy Systems, Inc.		MA
		Hopkinton LNG Corp.		MA
		NSTAR Gas Company		MA
		NSTAR Electric Company*		MA
			Harbor Electric Energy Company	MA
			BEC Funding II, LLC	DE
			CEC Funding, LLC	DE
		NSTAR Communications, Inc.		MA
		NSTAR Electric & Gas Corporation		MA
	NU Enterprises, Inc.			CT
		Select Energy Contracting, Inc.		MA
		Mode 1 Communications, Inc.		CT
		Northeast Generation Services Company		CT
			E. S. Boulos Company	CT
			NGS Mechanical, Inc.	CT
		Select Energy, Inc.		CT
	NU Transmission Ventures, Inc.			CT
		Northern Pass Transmission LLC		NH
		Renewable Properties, Inc.		NH
	Public Service Company of New Hampshire*			NH
		Properties, Inc.		NH
		PSNH Funding LLC		DE
		PSNH Funding LLC 2		DE
	The Rocky River Realty Company			CT
	Western Massachusetts Electric Company*			MA
		WMECO Funding LLC		DE
	Yankee Energy System, Inc.			CT
		Yankee Energy Financial Services Company		CT
		Yankee Energy Services Company		CT
		Yankee Gas Services Company		CT

*Indicates an SEC Registrant.  

EX-23.1

Exhibit 23.1

CONSENTS OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in: (i) the Registration Statement on Form S-3, No. 333-165579, as amended by Post-Effective Amendments Nos. 1 and 2, and its related prospectuses; (ii) the Registration Statement on Form S-3, No. 333-180330 and its related prospectus; and (iii) the Registration Statements on Form S-8, Nos. 333-63144, 333-121364, 333-142724, and 333-181258; of our report dated February 26, 2013, relating to the consolidated financial statements and the related financial statement schedules of Northeast Utilities and subsidiaries, and the effectiveness of Northeast Utilities and subsidiaries’ internal control over financial reporting (which report expresses an unqualified opinion and includes an explanatory paragraph relating to the acquisition of NSTAR and its subsidiaries on April 10, 2012), appearing in this Annual Report on Form 10-K of Northeast Utilities and subsidiaries for the year ended December 31, 2012.

We also consent to the incorporation by reference in Registration Statement on Form S-3, No. 333-165579-01, as amended by Post-Effective Amendments Nos.1 and 2, and its related prospectuses, of our report dated February 26, 2013, relating to the consolidated financial statements and the related consolidated financial statement schedule of The Connecticut Light and Power Company and subsidiary appearing in this Annual Report on Form 10-K of The Connecticut Light and Power Company and subsidiary for the year ended December 31, 2012.

We also consent to the incorporation by reference in Registration Statement on Form S-3, No. 333-165579-04, as amended by Post-Effective Amendments Nos.1 and 2, and its related prospectuses, of our report dated February 26, 2013, relating to the consolidated financial statements and the related consolidated financial statement schedule of NSTAR Electric Company and subsidiaries appearing in this Annual Report on Form 10-K of NSTAR Electric Company and subsidiaries for the year ended December 31, 2012.

We also consent to the incorporation by reference in Registration Statement on Form S-3, No. 333-165579-02, as amended by Post-Effective Amendments Nos.1 and 2, and its related prospectuses, of our report dated February 26, 2013, relating to the consolidated financial statements and the related consolidated financial statement schedule of Public Service Company of New Hampshire and subsidiaries appearing in this Annual Report on Form 10-K of Public Service Company of New Hampshire and subsidiaries for the year ended December 31, 2012.

We also consent to the incorporation by reference in Registration Statement on Form S-3, No. 333-165579-03, as amended by Post-Effective Amendments Nos.1 and 2, and its related prospectuses, of our report dated February 26, 2013, relating to the consolidated financial statements and the related consolidated financial statement schedule of Western Massachusetts Electric Company and subsidiary appearing in this Annual Report on Form 10-K of Western Massachusetts Electric Company and subsidiary for the year ended December 31, 2012.

/s / Deloitte & Touche LLP

Hartford, Connecticut
February 27, 2013

EX-23.2

Exhibit 23.2

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We hereby consent to the incorporation by reference in the Registration Statement on Form S-3 (No. 333-165579) of Northeast Utilities of our report dated February 7, 2012  relating to the financial statements and financial statement schedule of NSTAR Electric Company, which appears in this Form 10-K.

/s/  PricewaterhouseCoopers LLP

Boston, Massachusetts

February 27, 2013

EX-31

Exhibit 31

CERTIFICATION PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Thomas J. May, certify that:

1.

I have reviewed this Annual Report on Form 10-K of Northeast Utilities (the registrant);

2.

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.

The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)

Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)

Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)

Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)

Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5.

The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

(a)

All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

(b)

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date:  February 27, 2013

/s/	Thomas J. May
	Thomas J. May
	President and Chief Executive Officer
	(Principal Executive Officer)

EX-31.1

Exhibit 31.1

CERTIFICATION PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, James J. Judge, certify that:

1.

I have reviewed this Annual Report on Form 10-K of Northeast Utilities (the registrant);

2.

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.

The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)

Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)

Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)

Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)

Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5.

The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

(a)

All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

(b)

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date:  February 27, 2013

/s/	James J. Judge
	James J. Judge
	Executive Vice President and Chief Financial Officer
	(Principal Financial Officer)

EX-31

Exhibit 31

CERTIFICATION PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Leon J. Olivier, certify that:

1.

I have reviewed this Annual Report on Form 10-K of The Connecticut Light and Power Company (the registrant);

2.

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.

The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)

Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)

Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)

Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)

Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5.

The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

(a)

All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

(b)

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date:  February 27, 2013

/s/	Leon J. Olivier
	Leon J. Olivier
	Chief Executive Officer
	(Principal Executive Officer)

EX-31.1

Exhibit 31.1

CERTIFICATION PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, James J. Judge, certify that:

1.

I have reviewed this Annual Report on Form 10-K of The Connecticut Light and Power Company (the registrant);

2.

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.

The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)

Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)

Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)

Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)

Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5.

The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

(a)

All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

(b)

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date:  February 27, 2013

/s/	James J. Judge
	James J. Judge
	Executive Vice President and Chief Financial Officer
	(Principal Financial Officer)

EX-31

Exhibit 31

CERTIFICATION PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Leon J. Olivier, certify that:

1.

I have reviewed this Annual Report Form 10-K of NSTAR Electric Company (the registrant);

2.

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.

The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)

Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)

Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)

Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)

Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5.

The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

(a)

All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

(b)

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date:  February 27, 2013

/s/	Leon J. Olivier
	Leon J. Olivier
	Chief Executive Officer
	(Principal Executive Officer)

EX-31.1

Exhibit 31.1

CERTIFICATION PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, James J. Judge, certify that:

1.

I have reviewed this Annual Report on Form 10-K of NSTAR Electric Company (the registrant);

2.

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.

The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)

Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)

Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)

Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)

Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5.

The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

(a)

All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

(b)

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date:  February 27, 2013

/s/	James J. Judge
	James J. Judge
	Executive Vice President and Chief Financial Officer
	(Principal Financial Officer)

EX-31

Exhibit 31

CERTIFICATION PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Leon J. Olivier, certify that:

1.

I have reviewed this Annual Report on Form 10-K of Public Service Company of New Hampshire (the registrant);

2.

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.

The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)

Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)

Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)

Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)

Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5.

The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

(a)

All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

(b)

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date:  February 27, 2013

/s/	Leon J. Olivier
	Leon J. Olivier
	Chief Executive Officer
	(Principal Executive Officer)

EX-31.1

Exhibit 31.1

CERTIFICATION PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, James J. Judge, certify that:

1.

I have reviewed this Annual Report on Form 10-K of Public Service Company of New Hampshire (the registrant);

2.

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.

The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)

Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)

Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)

Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)

Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5.

The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

(a)

All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

(b)

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date:  February 27, 2013

/s/	James J. Judge
	James J. Judge
	Executive Vice President and Chief Financial Officer
	(Principal Financial Officer)

EX-31

Exhibit 31

CERTIFICATION PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Leon J. Olivier, certify that:

1.

I have reviewed this Annual Report on Form 10-K of Western Massachusetts Electric Company (the registrant);

2.

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.

The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)

Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiary, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)

Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)

Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)

Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5.

The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

(a)

All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

(b)

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date:  February 27, 2013

/s/	Leon J. Olivier
	Leon J. Olivier
	Chief Executive Officer
	(Principal Executive Officer)

EX-31.1

Exhibit 31.1

CERTIFICATION PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, James J. Judge, certify that:

1.

I have reviewed this Annual Report on Form 10-K of Western Massachusetts Electric Company (the registrant);

2.

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.

The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)

Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiary, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)

Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)

Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)

Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5.

The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

(a)

All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

(b)

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date:  February 27, 2013

/s/	James J. Judge
	James J. Judge
	Executive Vice President and Chief Financial Officer
	(Principal Financial Officer)

EX-32

Exhibit 32

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of Northeast Utilities (the registrant) on Form 10-K for the period ending December 31, 2012 as filed with the Securities and Exchange Commission (the Report), we, Thomas J. May, President and Chief Executive Officer of the registrant, and James J. Judge, Executive Vice President and Chief Financial Officer of the registrant, certify, pursuant to 18 U.S.C. Sec. 1350, as adopted pursuant to Sec. 906 of the Sarbanes-Oxley Act of 2002, that:

1)

The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2)

The information contained in the Report fairly presents, in all material respects, the financial condition and result of operations of the registrant.

/s/	Thomas J. May
	Thomas J. May
	President and Chief Executive Officer

/s/	James J. Judge
	James J. Judge
	Executive Vice President and Chief Financial Officer

Date:  February 27, 2013

A signed original of this written statement required by Section 906, or other document authenticating, acknowledging, or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to the registrant and will be retained by the registrant and furnished to the Securities and Exchange Commission or its staff upon request.

EX-32

Exhibit 32

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of The Connecticut Light and Power Company (the registrant) on Form 10-K for the period ending December 31, 2012 as filed with the Securities and Exchange Commission (the Report), we, Leon J. Olivier, Chief Executive Officer of the registrant and James J. Judge, Executive Vice President and Chief Financial Officer of the registrant, certify, pursuant to 18 U.S.C. Sec. 1350, as adopted pursuant to Sec. 906 of the Sarbanes-Oxley Act of 2002, that:

1)

The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2)

The information contained in the Report fairly presents, in all material respects, the financial condition and result of operations of the registrant.

/s/	Leon J. Olivier
	Leon J. Olivier
	Chief Executive Officer

/s/	James J. Judge
	James J. Judge
	Executive Vice President and Chief Financial Officer

Date:  February 27, 2013

A signed original of this written statement required by Section 906, or other document authenticating, acknowledging, or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to the registrant and will be retained by the registrant and furnished to the Securities and Exchange Commission or its staff upon request.

EX-32

Exhibit 32

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of NSTAR Electric Company (the registrant) on Form 10-K for the period ending December 31, 2012 as filed with the Securities and Exchange Commission (the Report), we, Leon J. Olivier, Chief Executive Officer of the registrant, and James J. Judge, Executive Vice President and Chief Financial Officer of the registrant, certify, pursuant to 18 U.S.C. Sec. 1350, as adopted pursuant to Sec. 906 of the Sarbanes-Oxley Act of 2002, that:

1)

The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2)

The information contained in the Report fairly presents, in all material respects, the financial condition and result of operations of the registrant.

/s/	Leon J, Olivier
	Leon J. Olivier
	Chief Executive Officer

/s/	James J. Judge
	James J. Judge
	Executive Vice President and Chief Financial Officer

Date:  February 27, 2013

A signed original of this written statement required by Section 906, or other document authenticating, acknowledging, or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to the registrant and will be retained by the registrant and furnished to the Securities and Exchange Commission or its staff upon request.

EX-32

Exhibit 32

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of Public Service Company of New Hampshire (the registrant) on Form 10-K for the period ending December 31, 2012 as filed with the Securities and Exchange Commission (the Report), we, Leon J. Olivier, Chief Executive Officer of the registrant, and James J. Judge, Executive Vice President and Chief Financial Officer of the registrant, certify, pursuant to 18 U.S.C. Sec. 1350, as adopted pursuant to Sec. 906 of the Sarbanes-Oxley Act of 2002, that:

1)

The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2)

The information contained in the Report fairly presents, in all material respects, the financial condition and result of operations of the registrant.

/s/	Leon J. Olivier
	Leon J. Olivier
	Chief Executive Officer

/s/	James J. Judge
	James J. Judge
	Executive Vice President and Chief Financial Officer

Date:  February 27, 2013

A signed original of this written statement required by Section 906, or other document authenticating, acknowledging, or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to the registrant and will be retained by the registrant and furnished to the Securities and Exchange Commission or its staff upon request.

EX-32

Exhibit 32

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with this Annual Report of Western Massachusetts Electric Company (the registrant) on Form 10-K for the period ending December 31, 2012 as filed with the Securities and Exchange Commission (the Report), we, Leon J. Olivier, Chief Executive Officer of the registrant, and James J. Judge, Executive Vice President and Chief Financial Officer of the registrant, certify, pursuant to 18 U.S.C. Sec. 1350, as adopted pursuant to Sec. 906 of the Sarbanes-Oxley Act of 2002, that:

1)

The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2)

The information contained in the Report fairly presents, in all material respects, the financial condition and result of operations of the registrant.

/s/	Leon J. Olivier
	Leon J. Olivier
	Chief Executive Officer

/s/	James J. Judge
	James J. Judge
	Executive Vice President and Chief Financial Officer

Date:  February 27, 2013

A signed original of this written statement required by Section 906, or other document authenticating, acknowledging, or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to the registrant and will be retained by the registrant and furnished to the Securities and Exchange Commission or its staff upon request.

XML

Operating Expenses (Tables)

12 Months Ended

Dec. 31, 2012

Notes To Consolidated Financial Statements [Abstract]

Schedule of Fuel Costs [Table Text Block]

	For the Years Ended December 31,
(Millions of Dollars)	2012(1)		2011		2010
NU	$	346.8	$	307.9	$	391.6
PSNH		103.4		115.9		184.3
Yankee Gas		145.9		191.3		206.4
NSTAR Gas		97.2		N/A		N/A
(1) Includes the NSTAR Gas costs from the date of the merger, April 10, 2012, through December 31, 2012.

XML

SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES (Details) (USD $)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Valuation and Qualifying Accounts Disclosure [Line Items]
Valuation Allowances and Reserves, Beginning Balance	$ 115,689,000	$ 119,190,000	$ 127,517,000
Valuation Allowances and Reserves, Charged to Cost and Expense	36,275,000	16,420,000	31,352,000
Valuation Allowances and Reserves, Charged to Other Accounts	34,761,000	40,663,000	45,953,000
Valuation Allowances and Reserves, Deductions	80,462,000	60,584,000	85,632,000
Valuation Allowances and Reserves, Ending Balance	165,549,000	115,689,000	119,190,000
Uncollectible Hardship Accounts Receivable Reserves		68,600,000	65,000,000
Impact Related To Nstar Merger	59,286,000
The Connecticut Light And Power Company [Member]
Valuation and Qualifying Accounts Disclosure [Line Items]
Valuation Allowances and Reserves, Beginning Balance	83,475,000	82,173,000	80,586,000
Valuation Allowances and Reserves, Charged to Cost and Expense	2,080,000	3,215,000	7,484,000
Valuation Allowances and Reserves, Charged to Other Accounts	27,084,000	33,911,000	41,639,000
Valuation Allowances and Reserves, Deductions	35,068,000	35,824,000	47,536,000
Valuation Allowances and Reserves, Ending Balance	77,571,000	83,475,000	82,173,000
Public Service Company Of New Hampshire [Member]
Valuation and Qualifying Accounts Disclosure [Line Items]
Valuation Allowances and Reserves, Beginning Balance	7,190,000	6,824,000	5,086,000
Valuation Allowances and Reserves, Charged to Cost and Expense	6,457,000	7,035,000	8,858,000
Valuation Allowances and Reserves, Charged to Other Accounts	2,481,000	1,334,000	1,017,000
Valuation Allowances and Reserves, Deductions	9,368,000	8,003,000	8,137,000
Valuation Allowances and Reserves, Ending Balance	6,760,000	7,190,000	6,824,000
Western Massachusetts Electric Company [Member]
Valuation and Qualifying Accounts Disclosure [Line Items]
Valuation Allowances and Reserves, Beginning Balance	10,018,000	12,891,000	16,304,000
Valuation Allowances and Reserves, Charged to Cost and Expense	2,294,000	3,133,000	9,747,000
Valuation Allowances and Reserves, Charged to Other Accounts	2,428,000	1,141,000	243,000
Valuation Allowances and Reserves, Deductions	6,239,000	7,147,000	13,403,000
Valuation Allowances and Reserves, Ending Balance	8,501,000	10,018,000	12,891,000
Uncollectible Hardship Accounts Receivable Reserves		5,400,000	6,900,000
Yankee Gas Services Company [Member]
Valuation and Qualifying Accounts Disclosure [Line Items]
Uncollectible Hardship Accounts Receivable Reserves		6,800,000	7,500,000
NSTAR Electric Company [Member]
Valuation and Qualifying Accounts Disclosure [Line Items]
Valuation Allowances and Reserves, Beginning Balance	27,118,000	29,033,000	26,379,000
Valuation Allowances and Reserves, Charged to Cost and Expense	40,301,000	22,582,000	29,417,000
Valuation Allowances and Reserves, Charged to Other Accounts	0	0	0
Valuation Allowances and Reserves, Deductions	23,304,000	24,497,000	26,763,000
Valuation Allowances and Reserves, Ending Balance	$ 44,115,000	$ 27,118,000	$ 29,033,000

XML

Other Retirement Benefits (Tables)

12 Months Ended

Dec. 31, 2012

Notes To Consolidated Financial Statements [Abstract]

Schedule of Deferred Compensation Arrangement with Individual, Excluding Share-based Payments and Postretirement Benefits by Title of Individual and Type of Deferred Compensation [Table Text Block]

NU	For the Years Ended December 31,
(Millions of Dollars)	2012		2011		2010
Actuarially-Determined Liability	$	54.6	$	52.8	$	49.9
Other Retirement Benefits Expense		4.7		4.7		4.2

	For the Years Ended December 31,
	2012						2011						2010
(Millions of Dollars)	CL&P		PSNH		WMECO		CL&P		PSNH		WMECO		CL&P		PSNH		WMECO
Actuarially-Determined Liability	$	0.4	$	2.5	$	0.2	$	1.2	$	2.5	$	0.2	$	0.4	$	2.4	$	0.2
Other Retirement Benefits Expense		2.6		1.0		0.5		2.6		1.0		0.5		2.3		0.9		0.4

XML

ASSET RETIREMENT OBLIGATIONS (TABLE)

12 Months Ended

Dec. 31, 2012

Notes To Consolidated Financial Statements [Abstract]

Schedule of Change in Asset Retirement Obligation [Table Text Block]

NU			As of December 31,
(Millions of Dollars)			2012		2011
Balance as of Beginning of Year			$	56.2	$	53.3
Liability Assumed Upon Consolidation of CYAPC and YAEC				284.2		-
Liability Assumed Upon Merger With NSTAR				35.9		-
Liabilities Incurred During the Year				1.5		2.1
Liabilities Settled During the Year				(7.2)		(0.8)
Accretion				20.2		3.5
Revisions in Estimated Cash Flows				21.4		(1.9)
Balance as of End of Year			$	412.2	$	56.2
	As of December 31,
	2012								2011
			NSTAR								NSTAR
(Millions of Dollars)	CL&P		Electric		PSNH		WMECO		CL&P		Electric(1)		PSNH		WMECO
Balance as of Beginning of Year	$	32.2	$	27.5	$	17.0	$	4.0	$	29.3	$	26.2	$	17.6	$	3.6
Liabilities Incurred During the Year		-		-		0.3		-		1.7		-		0.2		0.2
Liabilities Settled During the Year		(0.9)		(1.0)		-		-		(0.8)		-		-		-
Accretion		2.0		1.5		1.1		0.3		2.0		1.3		1.1		0.2
Revisions in Estimated Cash Flows		0.3		3.4		-		-		-		-		(1.9)		-
Balance as of End of Year	$	33.6	$	31.4	$	18.4	$	4.3	$	32.2	$	27.5	$	17.0	$	4.0
(1)NSTAR Electric amounts are not included in NU consolidated as of December 31, 2011.

XML

Fuel, Materials and Supplies and Allowance Inventory (Details) (Public Service Company Of New Hampshire [Member], Emission Allowances [Member], USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Public Service Company Of New Hampshire [Member] | Emission Allowances [Member]
Other Inventory, Capitalized Costs	$ 0.4	$ 0.8
Other Inventory, Noncurrent	19.4	19.4
Amortization of Power Contracts Emission Credits	$ 0.4	$ 5.1	$ 6.6

XML

INCOME TAXES (Tables)

12 Months Ended

Dec. 31, 2012

Notes To Consolidated Financial Statements [Abstract]

Schedule of Components of Income Tax Expense (Benefit) [Table Text Block]

NU	For the Years Ended December 31,
(Millions of Dollars)	2012		2011		2010
Current Income Taxes:
Federal	$	(30.9)	$	3.0	$	9.0
State		17.6		(26.0)		(6.5)
Total Current		(13.3)		(23.0)		2.5
Deferred Income Taxes, Net:
Federal		291.3		187.7		201.2
State		0.8		9.1		9.7
Total Deferred		292.1		196.8		210.9
Investment Tax Credits, Net		(3.9)		(2.8)		(3.0)
Income Tax Expense	$	274.9	$	171.0	$	210.4

		For the Years Ended December 31,
		2012								2011								2010
				NSTAR								NSTAR								NSTAR
(Millions of Dollars)		CL&P		Electric (1)		PSNH		WMECO		CL&P		Electric(1)		PSNH		WMECO		CL&P		Electric(1)		PSNH		WMECO
Current Income Taxes:
	Federal	$	(47.8)	$	93.5	$	(0.9)	$	(24.7)	$	13.9	$	64.9	$	(25.8)	$	0.1	$	20.7	$	94.8	$	6.1	$	3.1
	State		3.1		27.6		3.4		3.4		(34.4)		30.2		0.1		0.3		(1.1)		27.0		5.6		2.5
Total Current			(44.7)		121.1		2.5		(21.3)		(20.5)		95.1		(25.7)		0.4		19.6		121.8		11.7		5.6
Deferred Income
	Taxes, Net:
	Federal		141.5		11.4		46.5		51.2		106.4		74.8		67.7		22.1		108.1		41.7		37.6		11.0
	State		(0.5)		(7.1)		12.0		2.7		6.2		(2.8)		7.9		1.0		7.0		(0.1)		1.6		-
Total Deferred			141.0		4.3		58.5		53.9		112.6		72.0		75.6		23.1		115.1		41.6		39.2		11.0
Investment Tax
	Credits, Net		(1.9)		(1.4)		0.0		(0.5)		(2.1)		(1.4)		-		(0.3)		(2.3)		(1.4)		(0.1)		(0.3)
Income Tax Expense		$	94.4	$	124.0	$	61.0	$	32.1	$	90.0	$	165.7	$	49.9	$	23.2	$	132.4	$	162.0	$	50.8	$	16.3
(1)	NSTAR Electric amounts are included in NU consolidated from the date of the merger, April 10, 2012, through December 31, 2012. NSTAR Electric amounts are not included in NU consolidated for the years ended December 31, 2011 and 2010.

Schedule of Effective Income Tax Rate Reconciliation [Table Text Block]

A reconciliation between income tax expense and the expected tax expense at the statutory rate is as follows:
NU		For the Years Ended December 31,
(Millions of Dollars, except percentages)		2012		2011		2010
Income Before Income Tax Expense		$	808.0	$	571.5	$	604.5
Statutory Federal Income Tax Expense at 35%			282.8		200.0		211.6
Tax Effect of Differences:
	Depreciation		(10.8)		(14.2)		(9.5)
	Investment Tax Credit Amortization		(3.9)		(2.8)		(3.0)
	Other Federal Tax Credits		(3.8)		(3.5)		(3.8)
	State Income Taxes, Net of Federal Impact		4.4		22.1		12.5
	Medicare Subsidy		0.0		-		15.6
	Tax Asset Valuation Allowance/Reserve Adjustments		7.6		(33.1)		(10.5)
	Other, Net		(1.4)		2.5		(2.5)
Income Tax Expense		$	274.9	$	171.0	$	210.4
Effective Tax Rate			34.0%		29.9%		34.8%

		For the Years Ended December 31,
		2012								2011								2010
(Millions of Dollars,				NSTAR								NSTAR								NSTAR
	except percentages)	CL&P		Electric(1)		PSNH		WMECO		CL&P		Electric(1)		PSNH		WMECO		CL&P		Electric(1)		PSNH		WMECO
Income Before Income
	Tax Expense	$	304.2	$	314.2	$	157.9	$	86.6	$	340.2	$	418.2	$	150.2	$	66.2	$	376.6	$	410.6	$	140.9	$	39.4
Statutory Federal Income
	Tax Expense at 35%		106.5		110.0		55.3		30.3		119.1		146.4		52.6		23.2		131.8		143.7		49.3		13.8
Tax Effect of Differences:
	Depreciation		(9.0)		0.0		(0.3)		0.2		(8.1)		0.0		(4.4)		0.1		(6.1)		0.0		(3.2)		0.2
	Investment Tax Credit
	Amortization		(1.9)		(1.4)		0.0		(0.5)		(2.1)		(1.4)		-		(0.3)		(2.3)		(1.4)		(0.1)		(0.3)
	Other Federal Tax Credits		0.0		0.0		(3.8)		0.0		(0.1)		0.0		(3.4)		0.0		(0.1)		0.0		(3.6)		-
	State Income Taxes, Net
	of Federal Impact		0.1		13.4		10.0		4.0		4.0		17.9		5.2		0.9		8.5		17.4		4.7		1.6
	Medicare Subsidy		0.0		0.0		0.0		0.0		-		0.0		-		-		7.8		0.0		3.8		1.5
	Tax Asset Valuation
	Allowance/Reserve
	Adjustments		1.6		0.0		0.0		0.0		(22.3)		0.0		-		-		(4.7)		0.0		-		-
	Regulatory Decision Non-
	Plant flow through		0.0		0.0		0.0		(1.3)		0.0		0.0		-		-		0.0		0.0		-		-
	Other, Net		(2.9)		2.0		(0.2)		(0.6)		(0.5)		2.8		(0.1)		(0.7)		(2.5)		2.3		(0.1)		(0.5)
Income Tax Expense		$	94.4	$	124.0	$	61.0	$	32.1	$	90.0	$	165.7	$	49.9	$	23.2	$	132.4	$	162.0	$	50.8	$	16.3
Effective Tax Rate			31.0%		39.5%		38.6%		37.1%		26.5%		39.6%		33.2%		35.0%		35.2%		39.5%		36.1%		41.4%

Schedule of Deferred Tax Assets and Liabilities [Table Text Block]

NU			As of December 31,
(Millions of Dollars)			2012		2011
Deferred Tax Assets:
	Employee Benefits		$	811.4	$	539.6
	Derivative Liabilities and Change in Fair Value of Energy Contracts			380.6		415.3
	Regulatory Deferrals			257.9		157.9
	Allowance for Uncollectible Accounts			64.2		45.4
	Tax Effect - Tax Regulatory Assets			17.2		15.5
	Federal Net Operating Loss Carryforwards			214.6		178.6
	Purchase Accounting Adjustment			146.4		-
	Other			242.4		204.2
Total Deferred Tax Assets				2,134.7		1,556.5
Less: Valuation Allowance				4.2		4.6
Net Deferred Tax Assets			$	2,130.5	$	1,551.9
Deferred Tax Liabilities:
	Accelerated Depreciation and Other Plant-Related Differences		$	3,468.8	$	1,920.5
	Property Tax Accruals			89.6		58.9
	Regulatory Amounts:
		Other Regulatory Deferrals		1,561.1		1,135.0
		Tax Effect - Tax Regulatory Assets		217.2		184.6
		Goodwill - 1999 Merger		210.9		-
		Derivative Assets		36.2		39.1
		Securitized Contract Termination Costs		16.6		39.6
		Other		136.1		24.5
Total Deferred Tax Liabilities			$	5,736.5	$	3,402.2

			As of December 31,
			2012								2011
					NSTAR								NSTAR
(Millions of Dollars)			CL&P		Electric		PSNH		WMECO		CL&P		Electric (1)		PSNH		WMECO
Deferred Tax Assets:
	Derivative Liabilities and Change in
		Fair Value of Energy Contracts	$	375.9	$	5.8	$	-	$	(1.7)	$	412.2	$	1.3	$	-	$	2.9
	Allowance for Uncollectible Accounts			30.4		16.2		2.9		3.2		32.4		9.5		3.0		3.9
	Regulatory Deferrals			35.5		123.6		43.9		6.3		78.4		114.9		39.3		15.0
	Employee Benefits			141.2		116.3		64.8		16.3		121.4		115.3		87.9		13.3
	Tax Effect - Tax Regulatory Assets			5.2		6.0		1.7		1.7		6.4		6.9		1.6		6.5
	Federal Net Operating Loss Carryforwards			82.0		-		71.4		15.1		85.5		-		60.8		-
	Other			82.8		26.0		33.7		8.0		76.0		36.1		26.0		17.6
Total Deferred Tax Assets			$	753.0	$	293.9	$	218.4	$	48.9	$	812.3	$	284.0	$	218.6	$	59.2
Deferred Tax Liabilities:
	Accelerated Depreciation and Other
	Plant-Related Differences		$	1,194.7	$	1,079.3	$	476.5	$	261.3	$	1,046.9	$	987.8	$	423.8	$	194.9
	Property Tax Accruals			44.4		23.1		6.8		5.1		41.9		21.8		4.5		3.4
	Regulatory Amounts:
		Other Regulatory Deferrals		677.7		379.6		149.3		74.5		734.2		400.6		122.5		79.3
		Tax Effect - Tax Regulatory Assets		151.8		20.9		15.8		13.9		141.8		21.9		16.1		13.7
		Goodwill - 1999 Merger		-		181.0		-		-		-		187.8		-		-
		Derivative Assets		36.2		-		-		-		39.1		-		-		-
		Securitized Contract Termination Costs		-		5.5		7.9		3.3		-		41.3		29.7		10.0
		Other		10.1		30.2		14.1		2.3		8.2		34.8		14.0		1.1
Total Deferred Tax Liabilities			$	2,114.9	$	1,719.6	$	670.4	$	360.4	$	2,012.1	$	1,696.0	$	610.6	$	302.4
(1)		NSTAR Electric amounts are not included in NU consolidated as of December 31, 2011.

Summary of Income Tax Contingencies [Table Text Block]

						NSTAR
(Millions of Dollars)		NU		CL&P		Electric (1)
Balance as of January 1, 2010		$	124.3	$	89.0	$	13.8
	Gross Increases - Current Year		10.8		5.3		-
	Gross Increases - Prior Year		0.8		-		-
	Settlement		(34.3)		(13.5)		(13.8)
	Lapse of Statute of Limitations		(0.4)		-		-
Balance as of December 31, 2010			101.2		80.8		-
	Gross Increases - Current Year		8.0		1.4		-
	Gross Decreases - Prior Year		(35.7)		(35.7)		-
Balance as of December 31, 2011			73.5		46.5		-
	Gross Increases - Current Year		10.3		2.5		-
	Gross Increases - Prior Year		0.1		-		-
	Gross Decreases - Prior Year		(0.8)		-		-
Balance as of December 31, 2012		$	83.1	$	49.0	$	-

Other Interest	For the Years Ended December 31,						Accrued Interest	As of December 31,
Expense/(Income)	2012		2011		2010		Expense	2012		2011
(Millions of Dollars)							(Millions of Dollars)
NU	$	3.1	$	(2.8)	$	(24.8)	NU	$	10.1	$	7.1
CL&P		1.3		(3.7)		(7.4)	CL&P		4.0		2.7
NSTAR Electric (1)		0.0		2.0		(7.4)	NSTAR Electric (1)		0.0		0.7
PSNH		0.0		(0.6)		0.1	PSNH		0.0		-

Summary of Operating Loss Carryforwards [Table Text Block]

Carryforwards: Amounts are as follows:
	As of December 31, 2012
					NSTAR						Year
(Millions of Dollars)	NU		CL&P		Electric		PSNH		WMECO		Expiration Begins
State Credit Carryforwards	$	110.2	$	75.2	$	0.0	$	0.0	$	0.0	2013
State Net Operating Loss Carryforward		74.9		0.0		0.0		0.0		0.0	2013
Federal Net Operating Loss Carryforward		606.9		234.3		0.0		204.0		43.3	2031
Federal Credit Carryforwards		3.8		0.0		0.0		3.8		0.0	2031
	As of December 31, 2011
					NSTAR						Year
(Millions of Dollars)	NU		CL&P		Electric		PSNH		WMECO		Expiration Begins
State Credit Carryforwards	$	101.4	$	68.6	$	0.0	$	0.0	$	0.0	2013
Federal Net Operating Loss Carryforward		510.2		244.2		0.0		173.8		0.0	2031
Federal Credit Carryforwards		6.6		0.0		0.0		3.4		3.2	2031

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Related Parties (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
The Connecticut Light And Power Company [Member]
Related Party Transaction [Line Items]
Long Term Receivable From Nusco	$ 25.0
NSTAR Electric Company [Member]
Related Party Transaction [Line Items]
Long Term Payable for Pension Payments Received From Affliates	70.2	75.9
Public Service Company Of New Hampshire [Member]
Related Party Transaction [Line Items]
Long Term Receivable From Nusco	3.8
Western Massachusetts Electric Company [Member]
Related Party Transaction [Line Items]
Long Term Receivable From Nusco	$ 5.5

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EARNINGS PER SHARE (Details) (USD $) In Thousands, except Share data, unless otherwise specified	0 Months Ended	3 Months Ended								12 Months Ended
	Apr. 09, 2012	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Earnings Per Share Basic And Diluted [Line Items]
Net Income Attributable to Controlling Interests		$ 174,700	$ 207,600	$ 44,300	$ 99,300	$ 113,200	$ 90,000	$ 77,300	$ 114,200	$ 525,945	$ 394,693	$ 387,949
Basic										277,209,819	177,410,167	176,636,086
Weighted Average Number Diluted Shares Outstanding Adjustment										783,812	394,401	249,301
Diluted										277,993,631	177,804,568	176,885,387
Earnings Per Share Basic And Diluted		$ 0.55	$ 0.66	$ 0.15	$ 0.56	$ 0.64	$ 0.51	$ 0.44	$ 0.64
Antidilutive Securities Excluded From Computation Of Earnings Per Share Amount										4,266	4,314	1,578
Basic Earnings Per Common Share										$ 1.90	$ 2.22	$ 2.20
Diluted Earnings Per Common Share										$ 1.89	$ 2.22	$ 2.19
Common Stock Issuance Merger With Nstar [Abstract]
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares	136,049,000

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DERIVATIVE INSTRUMENTS (Tables)

12 Months Ended

Dec. 31, 2012

Notes To Consolidated Financial Statements [Abstract]

Schedule Of Derivative Instruments In Statement Of Financial Position Fair Value Text Block

		As of December 31, 2012
		Commodity Supply and		Collateral		Net Amount Recorded as
(Millions of Dollars)		Price Risk Management		and Netting (1)		Derivative Asset/(Liability) (2)
Current Derivative Assets:
Level 2:
	Other	$	0.2	$	-	$	0.2
Level 3:
	CL&P		17.7		(12.0)		5.7
	Other		5.5		-		5.5
Total Current Derivative Assets		$	23.4	$	(12.0)	$	11.4
Long-Term Derivative Assets:
Level 3:
	CL&P	$	159.7	$	(69.1)	$	90.6
Total Long-Term Derivative Assets		$	159.7	$	(69.1)	$	90.6
Current Derivative Liabilities:
Level 2:
	Other	$	(19.9)	$	0.6	$	(19.3)
Level 3:
	CL&P		(96.9)		-		(96.9)
	NSTAR Electric		(1.0)		-		(1.0)
Total Current Derivative Liabilities		$	(117.8)	$	0.6	$	(117.2)
Long-Term Derivative Liabilities:
Level 2:
	Other	$	(0.2)	$	-	$	(0.2)
Level 3:
	CL&P		(865.6)		-		(865.6)
	NSTAR Electric		(13.9)		-		(13.9)
	WMECO		(3.0)		-		(3.0)
Total Long-Term Derivative Liabilities		$	(882.7)	$	-	$	(882.7)

		As of December 31, 2011
		Commodity Supply and		Collateral		Net Amount Recorded as
(Millions of Dollars)		Price Risk Management		and Netting (1)		Derivative Asset/(Liability) (2)
Current Derivative Assets:
Level 3:
	CL&P	$	17.9	$	(11.6)	$	6.3
	Other		4.7		-		4.7
Total Current Derivative Assets (3)		$	22.6	$	(11.6)	$	11.0
Long-Term Derivative Assets:
Level 3:
	CL&P	$	174.2	$	(80.4)	$	93.8
	Other		4.6		-		4.6
Total Long-Term Derivative Assets		$	178.8	$	(80.4)	$	98.4
Current Derivative Liabilities:
Level 3:
	CL&P	$	(95.9)	$	-	$	(95.9)
	WMECO		(0.1)		-		(0.1)
	Other		(16.1)		4.5		(11.6)
Total Current Derivative Liabilities		$	(112.1)	$	4.5	$	(107.6)
Long-Term Derivative Liabilities:
Level 3:
	CL&P	$	(935.8)	$	-	$	(935.8)
	WMECO		(7.2)		-		(7.2)
	Other		(17.3)		0.4		(16.9)
Total Long-Term Derivative Liabilities (4)		$	(960.3)	$	0.4	$	(959.9)

Schedule Of Derivative Instruments Gain Loss In Statement Of Financial Performance Text Block

Location of Amounts		Amounts Recognized on Derivatives
Recognized on Derivatives		For the Years Ended December 31,
(Millions of Dollars)		2012		2011		2010
NU
Balance Sheet:
	Regulatory Assets	$	(29.0)	$	(162.0)	$	(95.7)
Statement of Income:
	Purchased Power, Fuel and Transmission		(0.7)		0.5		2.7

Schedule Of Cash Flow Hedges Included In Accumulated Other Comprehensive Income Loss [Table Text Block]

	Gains/(Losses) Recognized on		Gains/(Losses) Reclassified from AOCI
	Derivative Instruments		into Interest Expense
	For the Year Ended December 31,		For the Years Ended December 31,
(Millions of Dollars)	2011		2012		2011		2010
NU	$	(25.1)	$	(3.3)	$	(1.3)	$	(0.4)
CL&P		-		(0.7)		(0.7)		(0.7)
PSNH		(18.2)		(2.0)		(0.8)		(0.2)
WMECO		(6.9)		(0.5)		(0.1)		0.1

		For the Year Ended December 31, 2011
(Millions of Dollars)		NU			PSNH		WMECO
Balance as of January 1, 2011		$	(4.2)	$	(0.6)	$	(0.1)
	Hedged Transactions Recognized into Earnings		0.7		0.5		0.1
	Cash Flow Hedging Transactions Entered into for the Year		(14.9)		(10.8)		(4.2)
Net Change Associated with Hedging Transactions			(14.2)		(10.3)		(4.1)
Balance as of December 31, 2011		$	(18.4)	$	(10.9)	$	(4.2)
For further information regarding cash flow hedging transactions, see Note 5, "Derivative Instruments," to the consolidated financial statements.

Schedule Of Credit Risk Contingent Features [Table Text Block]

As of December 31, 2012

As of December 31, 2011

Additional Collateral

Additional Collateral

Fair Value Subject

Required if

Fair Value Subject

Required if

to Credit Risk

Cash

Downgraded Below

to Credit Risk

Cash

Downgraded Below

(Millions of Dollars)

Contingent Features

Collateral Posted

Investment Grade

Contingent Features

Collateral Posted

Investment Grade

NU

$

(15.3)

$

-

$

17.4

$

(23.5)

$

4.1

$

19.9

Fairvalueinputsliabilitiesquantitativeinformationtabletextblock

	Range	Period Covered
Energy Prices:
NU	$43 - $90 per MWh	2018 - 2028
CL&P	$50 - $55 per MWh	2018 - 2020
WMECO	$43 - $90 per MWh	2018 - 2028
Capacity Prices:
NU	$1.40 - $10.53 per kW-Month	2016 - 2028
CL&P	$1.40 - $9.83 per kW-Month	2016 - 2026
NSTAR Electric	$1.40 - $3.39 per kW-Month	2016 - 2019
WMECO	$1.40 - $10.53 per kW-Month	2016 - 2028
Forward Reserve:
NU, CL&P	$0.35 - $0.90 per kW-Month	2013 - 2024
REC Prices:
NU	$25 - $85 per REC	2013 - 2028
NSTAR Electric	$25 - $71 per REC	2013 - 2018
WMECO	$25 - $85 per REC	2013 - 2028

(Millions of Dollars)		NU		CL&P		NSTAR Electric(1)		WMECO
Derivatives, Net:
Fair Value as of January 1, 2011		$	(840.2)	$	(806.1)	$	(2.4)	$	-
Net Realized/Unrealized Gains/(Losses) Included in:
	Net Income		0.5		-		-		-
	Regulatory Assets		(161.0)		(153.6)		(4.3)		(7.3)
Settlements			38.5		28.1		3.3		-
Fair Value as of December 31, 2011		$	(962.2)	$	(931.6)	$	(3.4)	$	(7.3)
Liabilities Assumed due to Merger with NSTAR			(5.4)		-		-		-
Transfer to Level 2			32.2		-		-		-
Net Realized/Unrealized Gains/(Losses) Included in:
	Net Income (2)		10.9		-		-		-
	Regulatory Assets		(29.2)		(21.6)		(15.2)		4.3
Settlements			75.1		87.0		3.7		-
Fair Value as of December 31, 2012		$	(878.6)	$	(866.2)	$	(14.9)	$	(3.0)

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SUBSEQUENT EVENTS

12 Months Ended

Dec. 31, 2012

Notes To Consolidated Financial Statements [Abstract]

Subsequent Events [Text Block]

23.SUBSEQUENT EVENTS (NU, CL&P, NSTAR Electric)

See Note 9, "Long-Term Debt" to the consolidated financial statements for information regarding the January 2013 long-term debt issuance for CL&P.

See Note 12C, "Commitments and Contingencies – Deferred Contractual Obligations" to the consolidated financial statements for information regarding the receipt of the DOE proceeds by the Yankee Companies in January 2013.

See Note 11, "Income Taxes," for discussion of the federal legislation enacted on January 2, 2013.

On February 8, 2013, a blizzard caused damage to the electric delivery systems of CL&P and NSTAR Electric. Management believes that this storm will cost between $100 million to $120 million, with approximately 90 percent of those costs relating to NSTAR Electric. Management expects the costs to meet the criteria for specific cost recovery in Connecticut and Massachusetts and, as a result, does not expect the storm to have a material impact on the results of operations of CL&P or NSTAR Electric. Each operating company will seek recovery of these anticipated deferred storm costs through its applicable regulatory recovery process.

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MERGER OF NU AND NSTAR (Details) (USD $)	0 Months Ended	12 Months Ended
	Apr. 09, 2012	Dec. 31, 2012	Dec. 31, 2011
Business Acquisition, Cost of Acquired Entity, Purchase Price [Abstract]
Number of NSTAR Shares Outstanding	103,696,000
Exchange Ratio	1.312
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares	136,049,000
Business Acquisition Share Price	$ 36.79
Business Acquisition Cost Of Acquired Entity Equity Interests Issued And Issuable	$ 5,005,000,000
Business Acquisition, Cost of Acquired Entity, Other Noncash Consideration	33,000,000
Business Acquisition, Cost of Acquired Entity, Purchase Price	5,038,000,000	5,000,000,000
Business Acquisition, Purchase Price Allocation [Abstract]
Business Acquisition, Purchase Price Allocation, Current Assets		700,000,000
Business Acquisition, Purchase Price Allocation, Property, Plant and Equipment		5,100,000,000
Business Acquisition, Purchase Price Allocation, Goodwill Amount		3,200,000,000
Business Acquisition, Purchase Price Allocation, Other Noncurrent Assets		2,100,000,000
Business Acquisition, Purchase Price Allocation, Current Liabilities		(1,300,000,000)
Business Acquisition, Purchase Price Allocation, Other Noncurrent Liabilities		(2,700,000,000)
Business Acquisition, Purchase Price Allocation, Noncurrent Liabilities, Long-term debt		(2,100,000,000)
Total Purchase Price	5,038,000,000	5,000,000,000
Business Acquisition, Pro Forma Information [Abstract]
Business Acquisition, Pro Forma Revenue		7,004,000,000	7,361,000,000
Business Acquisition, Pro Forma Net Income		630,000,000	689,000,000
Business Acquisition, Pro Forma Earnings Per Share, Basic		$ 2.00	$ 2.20
Business Acquisition, Pro Forma Earnings Per Share, Diluted		$ 1.99	$ 2.19
Customer Rate Credits for Business Combination		46,000,000
Storm Cost Deferral Reduction		40,000,000
Establishment of Energy Efficiency Fund		15,000,000
Total Pre-Tax Settlement Agreement Impacts		101,000,000
Business Combination After Tax Transaction Costs		32,000,000	19,000,000
After Tax Settlement Costs Incurred		60,000,000	0
After Tax Costs Transaction and Other Non Recurring Costs Excluded from Pro Forma Net Income		92,000,000	19,000,000
Business Combination, Description
Business Acquisition, Percentage of Voting Interests Acquired	100.00%
Common Stock, Shares, Outstanding	314,000,000
Business Acquisition, Number of Shares Awarded Vested Immediately Prior to Merger	109,000
Business Acquisition, Description of Settlement Agreements		Regulatory Approvals: On February 15, 2012, NU and NSTAR reached comprehensive settlement agreements with the Massachusetts Attorney General and the DOER related to the merger. The Attorney General settlement agreement covered a variety of rate-making and rate design issues, including a base distribution rate freeze through 2015 for NSTAR Electric, NSTAR Gas and WMECO and $15 million, $3 million and $3 million in the form of rate credits to their respective customers. The settlement agreement reached with the DOER covered the same rate-making and rate design issues as the Attorney General's settlement agreement, as well as a variety of matters impacting the advancement of Massachusetts clean energy policy established by the Green Communities Act and Global Warming Solutions Act. On April 4, 2012, the DPU approved the settlement agreements and the merger of NU and NSTAR. On March 13, 2012, NU and NSTAR reached a comprehensive settlement agreement with both the Connecticut Attorney General and the Connecticut Office of Consumer Counsel related to the merger. The settlement agreement covered a variety of matters, including a $25 million rate credit to CL&P customers, a CL&P base distribution rate freeze until December 1, 2014, and the establishment of a $15 million fund for energy efficiency and other initiatives to be disbursed at the direction of the DEEP. In the agreement, CL&P agreed to forego rate recovery of $40 million of the deferred storm restoration costs associated with restoration activities following Tropical Storm Irene and the October 2011 snowstorm. On April 2, 2012, the PURA approved the settlement agreement and the merger of NU and NSTAR.
Goodwill Roll Forward [Abstract]
Goodwill, Beginning Balance		287,591,000
GoodwillAcquiredDuringPeriod		3,200,000,000
Goodwill, Ending Balance		3,519,401,000	287,591,000
Electric Distribution Member
Goodwill Roll Forward [Abstract]
GoodwillAcquiredDuringPeriod		2,500,000,000
Goodwill, Ending Balance		2,500,000,000
Transmission [Member]
Goodwill Roll Forward [Abstract]
GoodwillAcquiredDuringPeriod		600,000,000
Goodwill, Ending Balance		600,000,000
Natural Gas Distribution [Member]
Goodwill Roll Forward [Abstract]
Goodwill, Beginning Balance		300,000,000
GoodwillAcquiredDuringPeriod		100,000,000
Goodwill, Ending Balance		400,000,000
NSTAR [Member]
Business Combination, Description
Revenues From Acquired Company		1,957,800,000
Net Income From Acquired Company		182,900,000
The Connecticut Light And Power Company [Member]
Business Acquisition, Pro Forma Information [Abstract]
Customer Rate Credits for Business Combination		25,000,000
Storm Cost Deferral Reduction		40,000,000
Total Pre-Tax Settlement Agreement Impacts		65,000,000
NSTAR Electric Company [Member]
Business Acquisition, Pro Forma Information [Abstract]
Customer Rate Credits for Business Combination		15,000,000
Total Pre-Tax Settlement Agreement Impacts		15,000,000
Western Massachusetts Electric Company [Member]
Business Acquisition, Pro Forma Information [Abstract]
Customer Rate Credits for Business Combination		3,000,000
Total Pre-Tax Settlement Agreement Impacts		$ 3,000,000

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Operating Expenses (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Fuel [Line Items]
Fuel Power Costs	$ 346.8	$ 307.9	$ 391.6
Public Service Company Of New Hampshire [Member]
Fuel [Line Items]
Fuel Power Costs	103.4	115.9	184.3
Yankee Gas Services Company [Member]
Fuel [Line Items]
Fuel Power Costs	145.9	191.3	206.4
NSTAR Gas Company [Member]
Fuel [Line Items]
Fuel Power Costs	$ 97.2

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Defined Contribution Plans (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Defined Contribution Plan, Cost Recognized	$ 25.7	$ 17.4	$ 16.1
The Connecticut Light And Power Company [Member]
Defined Contribution Plan, Cost Recognized	4.8	4.5	4.4
Western Massachusetts Electric Company [Member]
Defined Contribution Plan, Cost Recognized	0.9	0.9	0.9
Public Service Company Of New Hampshire [Member]
Defined Contribution Plan, Cost Recognized	3.3	3.1	2.8
NSTAR Electric Company [Member]
Defined Contribution Plan, Cost Recognized	$ 9.0	$ 8.7	$ 8.1

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Long-Term Contractual Arrangements (Tables)

12 Months Ended

Dec. 31, 2012

Notes To Consolidated Financial Statements [Abstract]

Long-term Purchase Commitment [Table Text Block]

B.	Long-Term Contractual Arrangements
Estimated Future Annual Costs: The estimated future annual costs of significant long-term contractual arrangements as of
December 31, 2012 are as follows:
NU
(Millions of Dollars)		2013		2014		2015		2016		2017		Thereafter		Total
Supply and Stranded Cost		$	270.3	$	228.5	$	209.6	$	182.1	$	143.5	$	576.7	$	1,610.7
Renewable Energy			95.2		184.3		185.5		160.2		161.6		1,800.4		2,587.2
Peaker CfDs			75.2		72.6		66.5		63.2		66.5		292.0		636.0
Natural Gas Procurement			138.6		125.5		80.3		69.9		39.0		154.7		608.0
Coal, Wood and Other			110.7		46.3		5.5		5.0		5.0		21.8		194.3
Transmission Support Commitments			27.7		26.7		25.4		21.5		17.3		51.9		170.5
Total		$	717.7	$	683.9	$	572.8	$	501.9	$	432.9	$	2,897.5	$	5,806.7
CL&P
(Millions of Dollars)		2013		2014		2015		2016		2017		Thereafter		Total
Supply and Stranded Cost		$	169.4	$	149.7	$	145.4	$	147.8	$	119.8	$	502.8	$	1,234.9
Renewable Energy			4.2		30.5		30.7		30.9		31.1		356.1		483.5
Peaker CfDs			75.2		72.6		66.5		63.2		66.5		292.0		636.0
Transmission Support Commitments			10.9		10.5		10.0		8.5		6.8		20.4		67.1
Yankee Billings			19.2		18.8		16.1		0.0		0.0		0.0		54.1
Total		$	278.9	$	282.1	$	268.7	$	250.4	$	224.2	$	1,171.3	$	2,475.6
NSTAR Electric
(Millions of Dollars)		2013		2014		2015		2016		2017		Thereafter		Total
Supply and Stranded Cost		$	32.0	$	36.4	$	36.3	$	16.0	$	5.6	$	42.6	$	168.9
Renewable Energy			85.6		84.8		84.9		48.9		48.9		251.8		604.9
Transmission Support Commitments			8.6		8.3		7.9		6.7		5.4		16.2		53.1
Yankee Billings			8.2		8.3		6.6		0.0		0.0		0.0		23.1
Total		$	134.4	$	137.8	$	135.7	$	71.6	$	59.9	$	310.6	$	850.0
PSNH
(Millions of Dollars)		2013		2014		2015		2016		2017		Thereafter		Total
Supply and Stranded Cost		$	68.9	$	42.4	$	27.9	$	18.3	$	18.1	$	31.3	$	206.9
Renewable Energy			5.0		59.8		60.6		70.9		71.9		1,081.9		1,350.1
Coal, Wood and Other			110.7		46.3		5.5		5.0		5.0		21.8		194.3
Transmission Support Commitments			5.9		5.7		5.4		4.5		3.7		11.0		36.2
Yankee Billings			3.6		3.3		2.3		0.0		0.0		0.0		9.2
Total		$	194.1	$	157.5	$	101.7	$	98.7	$	98.7	$	1,146.0	$	1,796.7
WMECO
(Millions of Dollars)		2013		2014		2015		2016		2017		Thereafter		Total
Renewable Energy		$	0.4	$	9.2	$	9.3	$	9.5	$	9.7	$	110.6	$	148.7
Transmission Support Commitments			2.3		2.2		2.1		1.8		1.4		4.3		14.1
Yankee Billings			5.3		5.2		4.4		0.0		0.0		0.0		14.9
Total		$	8.0	$	16.6	$	15.8	$	11.3	$	11.1	$	114.9	$	177.7

NU	For the Years Ended December 31,
(Millions of Dollars)	2012		2011		2010
Supply and Stranded Cost	$	216.8	$	156.0	$	196.2
Renewable Energy		48.7		5.1		5.8
Peaker CfDs		59.3		40.2		10.0
Natural Gas Procurement		243.1		191.7		209.5
Coal, Wood and Other		105.2		113.2		171.1
Transmission Support Commitments		24.8		18.1		18.9

		For the Years Ended December 31,
		2012								2011								2010
				NSTAR								NSTAR								NSTAR
(Millions of Dollars)		CL&P		Electric(1)		PSNH		WMECO		CL&P		Electric(1)		PSNH		WMECO		CL&P		Electric(1)		PSNH		WMECO
Supply and
	Stranded Cost	$	158.2	$	36.3	$	30.5	$	0.9	$	114.9	$	80.9	$	40.8	$	0.3	$	151.3	$	146.3	$	42.6	$	2.3
Renewable Energy			-		60.2		4.1		-		-		61.8		5.1		-		-		52.7		5.8		-
Peaker CfDs			59.3		-		-		-		40.2		-		-		-		10.0		-		-		-
Coal, Wood and Other			-		-		105.2		-		-		-		113.2		-		-		-		171.1		-
Transmission Support
	Commitments		9.6		7.6		5.2		2.0		10.3		8.1		5.6		2.2		10.8		8.5		5.8		2.3

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SCHEDULE I - Income Statements (Details) (USD $) In Thousands, except Share data, unless otherwise specified	3 Months Ended								12 Months Ended
	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Condensed Financial Statements, Captions [Line Items]
Operating Revenues	$ 1,684,000	$ 1,861,500	$ 1,628,700	$ 1,099,600	$ 1,068,000	$ 1,114,900	$ 1,047,500	$ 1,235,300	$ 6,273,787	$ 4,465,657	$ 4,898,167
Operating Expenses:
Operating Income	331,400	412,900	159,500	214,400	184,900	203,800	178,100	227,400	1,118,206	794,176	799,891
Total Interest Expense									329,945	250,425	237,291
Other Income [Abstract]
Other Income/(Loss), Net									19,742	27,715	41,916
Income Before Income Tax Expense									808,003	571,466	604,516
Income Tax Expense									274,926	170,953	210,409
Net Income	176,600	209,500	46,200	100,800	114,800	91,400	78,700	115,600	533,077	400,513	394,107
Net Income Attributable to Noncontrolling Interests									7,132	5,820	6,158
Net Income Attributable to Controlling Interests	174,700	207,600	44,300	99,300	113,200	90,000	77,300	114,200	525,945	394,693	387,949
Basic Earnings Per Common Share									$ 1.90	$ 2.22	$ 2.20
Diluted Earnings Per Common Share									$ 1.89	$ 2.22	$ 2.19
Weighted Average Common Shares Outstanding:
Basic									277,209,819	177,410,167	176,636,086
Diluted									277,993,631	177,804,568	176,885,387
Nu Parent [Member]
Condensed Financial Statements, Captions [Line Items]
Operating Revenues									0	0	0
Operating Expenses:
Other Operating Expenses									73,198	19,075	21,081
Operating Income									(73,198)	(19,075)	(21,081)
Total Interest Expense									27,777	26,767	12,058
Other Income [Abstract]
Equity In Earnings Of Subsidiaries									567,529	422,408	396,333
Other Income/(Loss), Net									5,971	4,247	4,536
Total Other Income									573,500	426,655	400,869
Income Before Income Tax Expense									472,525	380,813	367,730
Income Tax Expense									(53,523)	(14,142)	(20,276)
Net Income									526,048	394,955	388,006
Net Income Attributable to Noncontrolling Interests									103	262	57
Net Income Attributable to Controlling Interests									$ 525,945	$ 394,693	$ 387,949
Basic Earnings Per Common Share									$ 1.90	$ 2.22	$ 2.20
Diluted Earnings Per Common Share									$ 1.89	$ 2.22	$ 2.19
Weighted Average Common Shares Outstanding:
Basic									277,209,819	177,410,167	176,636,086
Diluted									277,993,631	177,804,568	176,885,387

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Other Taxes (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Excise And Sales Taxes	$ 135.0	$ 137.8	$ 143.7
The Connecticut Light And Power Company [Member]
Excise And Sales Taxes	$ 120.7	$ 121.6	$ 128.0

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SHORT TERM DEBT (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
Line of Credit Facility [Line Items]
Letters Of Credit Outstanding Under Line of Credit		$ 17.9
NU Money Pool [Abstract]
Line of Credit Facility, Description	CL&P Credit Agreement: On March 26, 2012, CL&P entered into a five-year unsecured revolving credit facility in the amount of $300 million, which expires on March 26, 2017. Under this facility, CL&P can borrow either on a short-term or a long-term basis subject to regulatory approval. As of December 31, 2012, CL&P had $89 million in borrowings outstanding under this credit agreement with a weighted average interest rate of 3.325 percent.
Short Term Debt Regulatory Limits	The amount of short-term borrowings that may be incurred by CL&P, NSTAR Electric and WMECO is subject to periodic approval by the FERC. On November 30, 2011, the FERC granted authorization to allow CL&P and WMECO to incur total short-term borrowings up to a maximum of $450 million and $300 million, respectively, effective January 1, 2012 through December 31, 2013. On March 22, 2012, the FERC approved CL&P's application requesting to increase its total short-term borrowing capacity from a maximum of $450 million to a maximum of $600 million for the authorization period through December 31, 2013. On May 16, 2012, the FERC granted authorization to allow NSTAR Electric to issue total short-term debt securities in an aggregate principal amount not to exceed $655 million outstanding at any one time, effective October 23, 2012 through October 23, 2014. As a result of the NHPUC having jurisdiction over PSNH's short-term debt, PSNH is not currently required to obtain FERC approval for its short-term borrowings. PSNH is authorized by regulation of the NHPUC to incur short-term borrowings up to 10 percent of net fixed plant plus an additional $60 million until further ordered by the NHPUC. As of December 31, 2012, PSNH's short-term debt authorization under the 10 percent of net fixed plant test plus $60 million totaled approximately $280 million. CL&P's certificate of incorporation contains preferred stock provisions restricting the amount of unsecured debt that CL&P may incur, including limiting unsecured indebtedness with a maturity of less than 10 years to 10 percent of total capitalization. In November 2003, CL&P obtained from its preferred stockholders a waiver of such 10 percent limit for a ten-year period expiring in March 2014, provided that all unsecured indebtedness does not exceed 20 percent of total capitalization. As of December 31, 2012, CL&P had $482 million of unsecured debt capacity available under this authorization.
CommercialPaper	1,150.0
Description of commercial paper program	On July 25, 2012, NU, CL&P, NSTAR LLC, NSTAR Gas, PSNH, WMECO, and Yankee Gas jointly entered into a five-year $1.15 billion revolving credit facility. The new facility replaced (1) the NSTAR LLC revolving credit facility of $175 million that served to backstop a commercial paper program utilized by NSTAR LLC and was scheduled to expire on December 31, 2012, (2) the NSTAR Gas revolving credit facility of $75 million that expired on June 8, 2012, and (3) the CL&P, PSNH, WMECO, and Yankee Gas joint three-year $400 million and NU parent three-year $500 million unsecured revolving credit facilities that were scheduled to expire on September 24, 2013. The new facility expires on July 25, 2017. Management expects the new facility to be used primarily to backstop the $1.15 billion commercial paper program at NU, which commenced July 25, 2012. The commercial paper program allows NU parent to issue commercial paper as a form of short-term debt. Under the terms of the agreement, NU parent may provide intercompany loans to its subsidiaries, including CL&P, PSNH and WMECO. On July 25, 2012, NSTAR Electric entered into a five-year $450 million revolving credit facility. This new facility serves to backstop NSTAR Electric’s existing $450 million commercial paper program. The new facility expires on July 25, 2017. This new facility replaced a prior $450 million NSTAR Electric revolving credit facility that was scheduled to expire on December 31, 2012. As of December 31, 2012, NU had $1.15 billion in short-term borrowings outstanding under its commercial paper program. The weighted-average interest rate on these borrowings as of December 31, 2012 was 0.46 percent, which is generally based on money market rates. As of December 31, 2012, there were inter-company loans of $987.5 million from NU to its subsidiaries ($405.1 million for CL&P, $63.3 million for PSNH, and $31.9 million for WMECO). As of December 31, 2012, NSTAR Electric had $276 million in short-term borrowings outstanding under its commercial paper program, leaving $174 million of available borrowing capacity. The weighted-average interest rate on these borrowings as of December 31, 2012 was 0.31 percent, which is generally based on money market rates.
Description of Working Capital	NU, CL&P, NSTAR Electric, PSNH and WMECO use their available capital resources to fund their respective construction expenditures, meet debt requirements, pay costs, including storm-related costs, pay dividends and fund other corporate obligations, such as pension contributions. The current growth in NU’s transmission construction expenditures utilizes a significant amount of cash for projects that have a long-term return on investment and recovery period. In addition, NU’s Regulated companies operate in an environment where recovery of its electric and natural gas distribution construction expenditures takes place over an extended period of time. This impacts the timing of the revenue stream designed to fully recover the total investment plus a return on the equity portion of the cost and related financing costs. These factors have resulted in NU’s current liabilities exceeding current assets by approximately $1.4 billion, $268 million, $198 million and $60 million at NU, CL&P, NSTAR Electric and WMECO, respectively, as of December 31, 2012. As of December 31, 2012, approximately $730 million of NU's current liabilities relates to long-term debt that will be paid in the next 12 months, consisting of $550 million for NU parent, $55 million for WMECO, and $125 million for CL&P. Approximately $32 million relates to the amortization of the purchase accounting fair value adjustment that will be amortized in the next twelve months. NU, with its strong credit ratings, has several options available in the financial markets to repay or refinance these maturities with the issuance of new long-term debt. NU, CL&P, NSTAR Electric, and WMECO will reduce their short-term borrowings with cash received from operating cash flows or with the issuance of new long-term debt, as deemed appropriate given capital requirements and maintenance of NU's credit rating and profile. Management expects the future operating cash flows of NU, CL&P, NSTAR Electric and WMECO along with the access to financial markets, will be sufficient to meet any future operating requirements and capital investment forecasted opportunities.
Description of ST debt reclassified to LT	On January 15, 2013, CL&P issued $400 million of Series A First and Refunding Mortgage Bonds with a coupon rate of 2.5 percent and a maturity date of January 15, 2023. The proceeds, net of issuance costs, were used to pay short-term borrowings outstanding under the CL&P credit agreement and the NU commercial paper program. As a result, as of December 31, 2012, CL&P's credit agreement borrowings of $89 million and intercompany loans related to the commercial paper program of $305.8 million have been classified as Long-Term Debt on the accompanying consolidated balance sheet.
The Connecticut Light And Power Company [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Amount Outstanding	89.0	31.0
Letters Of Credit Outstanding Under Line of Credit		4.0
NU Money Pool [Abstract]
Borrowings From Money Pool		58.5
Weighted Average Interest Rate on Money Pool Borrowings		0.08%
WeightedAverageDiscountRatePercent	3.33%	4.03%
Public Service Company Of New Hampshire [Member]
Line of Credit Facility [Line Items]
Letters Of Credit Outstanding Under Line of Credit		5.4
NU Money Pool [Abstract]
Borrowings From Money Pool		(55.9)
Weighted Average Interest Rate on Money Pool Borrowings		0.10%
Western Massachusetts Electric Company [Member]
NU Money Pool [Abstract]
Borrowings From Money Pool		(11.0)
Weighted Average Interest Rate on Money Pool Borrowings		0.10%
Nu Parent [Member]
NU Money Pool [Abstract]
WeightedAverageDiscountRatePercent	2.20%	0.46%
Yankee Gas Services Company [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Amount Outstanding		30.0
NU Money Pool [Abstract]
WeightedAverageDiscountRatePercent		2.07%
NSTAR Electric Company [Member]
NU Money Pool [Abstract]
CommercialPaper	$ 276.0	$ 141.5
WeightedAverageDiscountRatePercent	0.31%	0.16%

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PROPERTY, PLANT AND ACCUMULATED DEPRECIATION (Details) (USD $)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Public Utility Property Plant And Equipment [Line Items]
Public Utilities Property Plant And Equipment Distribution	$ 11,438,200,000	$ 6,540,400,000
Public Utilities Property Plant And Equipment Distribution Natural Gas	2,274,200,000	1,247,600,000
Public Utilities Property Plant And Equipment Transmission	5,541,100,000	3,541,900,000
Public Utilities Property Plant And Equipment Generation Or Processing	1,146,600,000	1,096,000,000
Public Utilities Property Plant And Equipment Electric And Natural Gas Utility Total	20,400,100,000	12,425,900,000
Public Utilities Property Plant And Equipment Other Property Plant And Equipment	429,300,000	305,100,000
Public Utilities Property Plant And Equipment Plant In Service	20,829,400,000	12,731,000,000
ElectricAndNaturalGasUtilityAccumulatedDepreciation	(5,065,100,000)	(3,035,500,000)
OtherAccumulatedDepreciation	(171,500,000)	(120,200,000)
Public Utilities, Property, Plant and Equipment, Accumulated Depreciation	(5,236,600,000)	(3,155,700,000)
Property Plant And Equipment Net Excluding Construction Work In Progress	15,592,800,000	9,575,300,000
Public Utilities Property Plant And Equipment Construction Work In Progress	1,012,200,000	827,800,000
Property, Plant and Equipment, Net	16,605,010,000	10,403,065,000
Public Utilities Property Plant and Equipment Depreciation Rates	2.50%	2.60%	2.70%
Distribution Average Depreciable Lives	42.1
Transmission Average Depreciable Lives	45.3
Generation Average Depreciable Lives	32.7
Other Average Depreciable Lives	16.7
The Connecticut Light And Power Company [Member]
Public Utility Property Plant And Equipment [Line Items]
Public Utilities Property Plant And Equipment Distribution	4,691,300,000	4,419,600,000
Public Utilities Property Plant And Equipment Transmission	2,796,100,000	2,689,100,000
Public Utilities Property Plant And Equipment Generation Or Processing	0	0
Public Utilities Property Plant And Equipment Plant In Service	7,487,400,000	7,108,700,000
Public Utilities, Property, Plant and Equipment, Accumulated Depreciation	(1,698,100,000)	(1,596,700,000)
Property Plant And Equipment Net Excluding Construction Work In Progress	5,789,300,000	5,512,000,000
Public Utilities Property Plant And Equipment Construction Work In Progress	363,700,000	315,400,000
Property, Plant and Equipment, Net	6,152,959,000	5,827,384,000
Public Utilities Property Plant and Equipment Depreciation Rates	2.50%	2.40%	2.70%
Distribution Average Depreciable Lives	41.8
Transmission Average Depreciable Lives	39.8
Generation Average Depreciable Lives	0
Other Average Depreciable Lives	0
Public Service Company Of New Hampshire [Member]
Public Utility Property Plant And Equipment [Line Items]
Public Utilities Property Plant And Equipment Distribution	1,520,100,000	1,451,600,000
Public Utilities Property Plant And Equipment Transmission	599,200,000	546,400,000
Public Utilities Property Plant And Equipment Generation Or Processing	1,125,500,000	1,074,800,000
Public Utilities Property Plant And Equipment Plant In Service	3,244,800,000	3,072,800,000
Public Utilities, Property, Plant and Equipment, Accumulated Depreciation	(954,000,000)	(893,600,000)
Property Plant And Equipment Net Excluding Construction Work In Progress	2,290,800,000	2,179,200,000
Public Utilities Property Plant And Equipment Construction Work In Progress	61,700,000	77,500,000
Property, Plant and Equipment, Net	2,352,515,000	2,256,688,000
Public Utilities Property Plant and Equipment Depreciation Rates	3.00%	2.90%	2.80%
Distribution Average Depreciable Lives	33.8
Transmission Average Depreciable Lives	42.1
Generation Average Depreciable Lives	32.8
Other Average Depreciable Lives	0
Western Massachusetts Electric Company [Member]
Public Utility Property Plant And Equipment [Line Items]
Public Utilities Property Plant And Equipment Distribution	724,200,000	704,300,000
Public Utilities Property Plant And Equipment Transmission	583,700,000	297,400,000
Public Utilities Property Plant And Equipment Generation Or Processing	21,100,000	21,200,000
Public Utilities Property Plant And Equipment Plant In Service	1,329,000,000	1,022,900,000
Public Utilities, Property, Plant and Equipment, Accumulated Depreciation	(252,100,000)	(240,500,000)
Property Plant And Equipment Net Excluding Construction Work In Progress	1,076,900,000	782,400,000
Public Utilities Property Plant And Equipment Construction Work In Progress	213,600,000	295,400,000
Property, Plant and Equipment, Net	1,290,498,000	1,077,833,000
Public Utilities Property Plant and Equipment Depreciation Rates	3.30%	2.90%	2.80%
Distribution Average Depreciable Lives	30.2
Transmission Average Depreciable Lives	47.5
Generation Average Depreciable Lives	25.0
Other Average Depreciable Lives	0
NSTAR Electric Company [Member]
Public Utility Property Plant And Equipment [Line Items]
Public Utilities Property Plant And Equipment Distribution	4,539,900,000	4,334,400,000
Public Utilities Property Plant And Equipment Transmission	1,529,700,000	1,386,900,000
Public Utilities Property Plant And Equipment Generation Or Processing	0	0
Public Utilities Property Plant And Equipment Plant In Service	6,069,600,000	5,721,300,000
ElectricAndNaturalGasUtilityAccumulatedDepreciation		(1,436,000,000)
Public Utilities, Property, Plant and Equipment, Accumulated Depreciation	(1,540,100,000)
Property Plant And Equipment Net Excluding Construction Work In Progress	4,529,500,000	4,285,300,000
Public Utilities Property Plant And Equipment Construction Work In Progress	205,800,000	162,000,000
Property, Plant and Equipment, Net	$ 4,735,297,000	$ 4,447,258,000
Public Utilities Property Plant and Equipment Depreciation Rates	2.80%	3.00%	3.00%
Distribution Average Depreciable Lives	33.9
Transmission Average Depreciable Lives	46.3
Generation Average Depreciable Lives	0
Other Average Depreciable Lives	0

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LONG-TERM DEBT (Details) (USD $)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
Debt Instrument [Line Items]
Long-Term Debt - Current Portion	$ 763,338,000	$ 331,582,000
Long-Term Debt	7,200,156,000	4,614,913,000
Maturities of Long-term Debt [Abstract]
Long-term Debt, Maturities, Repayments of Principal in Next Twelve Months	731,700,000
Long-term Debt, Maturities, Repayments of Principal in Year Two	576,600,000
Long-term Debt, Maturities, Repayments of Principal in Year Three	216,700,000
Long-term Debt, Maturities, Repayments of Principal in Year Four	0
Long-term Debt, Maturities, Repayments of Principal in Year Five	745,000,000
Long-term Debt, Maturities, Repayments of Principal after Year Five	4,559,800,000
LongTermDebtMaturitiesRepaymentsOfPrincipalTotal	6,829,800,000
Long-term Debt, Description	On March 22, 2012, NU parent issued $300 million of floating rate Series D Senior Notes with a maturity date of September 20, 2013. The notes have a coupon rate based on the three-month LIBOR rate plus a credit spread of 0.75 percent and will reset quarterly. The notes had an interest rate of 1.059 percent as of December 31, 2012. The proceeds, net of issuance expenses, were used to repay at maturity the NU parent $263 million Series A Senior Notes that matured on April 1, 2012, to repay short-term borrowings outstanding under the NU parent Credit Agreement and for other general corporate purposes.          As of December 31, 2012, amount relates to the purchase price adjustment required to record the NSTAR long-term debt issuances at fair value on the date of the merger. As of December 31, 2011, amount related to a fixed to floating interest rate swap on the $263 million NU parent note that matured on April 1, 2012. The change in fair value of the interest component of the debt was recorded as an adjustment to Current Portion - Long Term Debt as of December 31, 2011 with an equal and offsetting adjustment to Current Derivative Assets. .. Fees due to the DOE for the disposal of CL&P's and WMECO's Prior Period Spent Nuclear Fuel and CYAPC's and YAEC's spent nuclear fuel obligation include accumulated interest costs of $350 million and $219.3 million for NU ($177.8 million and $177.6 million for CL&P and $41.7 million and $41.7 million for WMECO) as of December 31, 2012 and 2011, respectively.
Total Other [Member]
Debt Instrument [Line Items]
Long-Term Debt	1,079,300,000	513,000,000
Series A due 2012 7.25% [Member]
Debt Instrument [Line Items]
Long-Term Debt		263,000,000
Series C due 2013 5.65% [Member]
Debt Instrument [Line Items]
Long-Term Debt	250,000,000	250,000,000
Debentures Due 2019 4.50% [Member]
Debt Instrument [Line Items]
Long-Term Debt	350,000,000
Spent Nuclear Fuel Obilgation CY [Member]
Debt Instrument [Line Items]
Long-Term Debt	179,300,000
Public Service Company Of New Hampshire [Member]
Debt Instrument [Line Items]
Long-Term Debt	997,932,000	997,722,000
Maturities of Long-term Debt [Abstract]
Long-term Debt, Maturities, Repayments of Principal in Next Twelve Months	0
Long-term Debt, Maturities, Repayments of Principal in Year Two	50,000,000
Long-term Debt, Maturities, Repayments of Principal in Year Three	0
Long-term Debt, Maturities, Repayments of Principal in Year Four	0
Long-term Debt, Maturities, Repayments of Principal in Year Five	70,000,000
Long-term Debt, Maturities, Repayments of Principal after Year Five	879,500,000
LongTermDebtMaturitiesRepaymentsOfPrincipalTotal	999,500,000
Long-term Debt, Description	The PSNH Series A and Series C tax-exempt bonds are currently callable at 100 percent and 101 percent of par, respectively. The PSNH Series B tax-exempt bond will become callable in June 2013. CL&P’s $125 million and $62 million tax-exempt PCRBs, which are subject to mandatory tender for purchase on September 3, 2013 and April 1, 2015, respectively, cannot be redeemed prior to their respective tender dates. CL&P’s $120.5 million tax-exempt PCRBs will be subject to redemption at par on or after September 1, 2021. All other long-term debt securities are subject to make-whole provisions. As of December 31, 2012, PSNH had $287.5 million in PCRBs outstanding. PSNH's obligation to repay each series of PCRBs is secured by first mortgage bonds and bond insurance. Each such series of first mortgage bonds contains similar terms and provisions as the applicable series of PCRBs. If PSNH failed to meet its obligations under the PCRBs, then these first mortgage bonds would become outstanding. The 2001 Series A PCRBs, in the aggregate principal amount of $89.3 million, bears interest at a rate that is periodically set pursuant to auctions. PSNH is not obligated to purchase these PCRBs, which mature in 2021, from the remarketing agent. The weighted average effective interest rate on PSNH's Series A variable-rate PCRBs was 0.20 percent in 2012 and 0.21 percent in 2011.
Public Service Company Of New Hampshire [Member] | Series L 2004 Due 2014 5.25% [Member]
Debt Instrument [Line Items]
Long-Term Debt	50,000,000	50,000,000
Public Service Company Of New Hampshire [Member] | Series M 2005 Due 2035 5.60% [Member]
Debt Instrument [Line Items]
Long-Term Debt	50,000,000	50,000,000
Public Service Company Of New Hampshire [Member] | Series N 2007 Due 2017 6.15% [Member]
Debt Instrument [Line Items]
Long-Term Debt	70,000,000	70,000,000
Public Service Company Of New Hampshire [Member] | Series O 2008 Due 2018 6.00% [Member]
Debt Instrument [Line Items]
Long-Term Debt	110,000,000	110,000,000
Public Service Company Of New Hampshire [Member] | Series P 2009 Due 2019 4.50% [Member]
Debt Instrument [Line Items]
Long-Term Debt	150,000,000	150,000,000
Public Service Company Of New Hampshire [Member] | Adjustablerateseriesadue 2021 [Member]
Debt Instrument [Line Items]
Long-Term Debt	89,300,000	89,300,000
Public Service Company Of New Hampshire [Member] | Total First Mortgage Bonds [Member]
Debt Instrument [Line Items]
Long-Term Debt	712,000,000	712,000,000
Public Service Company Of New Hampshire [Member] | Total Pollution Control Bonds [Member]
Debt Instrument [Line Items]
Long-Term Debt	287,500,000
Public Service Company Of New Hampshire [Member] | Unamortized Premiums and Discounts, Net [Member]
Debt Instrument [Line Items]
Long-Term Debt	(1,600,000)	(1,800,000)
Public Service Company Of New Hampshire [Member] | Series Q 4.05% 2011 Due 2021 [Member]
Debt Instrument [Line Items]
Long-Term Debt	122,000,000	122,000,000
Public Service Company Of New Hampshire [Member] | Series R 2011 3.30% due 2021 [Member]
Debt Instrument [Line Items]
Long-Term Debt	160,000,000	160,000,000
Public Service Company Of New Hampshire [Member] | Total Pollution Control Revenue Bonds [Member]
Debt Instrument [Line Items]
Long-Term Debt		287,500,000
Public Service Company Of New Hampshire [Member] | Tax Exempt Series B and C Due 2021 4.75% to 5.45% [Member]
Debt Instrument [Line Items]
Long-Term Debt	198,200,000	198,200,000
The Connecticut Light And Power Company [Member]
Debt Instrument [Line Items]
Long-Term Debt - Current Portion	125,000,000	62,000,000
Long-Term Debt	2,737,790,000	2,521,753,000
Maturities of Long-term Debt [Abstract]
Long-term Debt, Maturities, Repayments of Principal in Next Twelve Months	125,000,000
Long-term Debt, Maturities, Repayments of Principal in Year Two	150,000,000
Long-term Debt, Maturities, Repayments of Principal in Year Three	162,000,000
Long-term Debt, Maturities, Repayments of Principal in Year Four	0
Long-term Debt, Maturities, Repayments of Principal in Year Five	250,000,000
Long-term Debt, Maturities, Repayments of Principal after Year Five	1,540,300,000
LongTermDebtMaturitiesRepaymentsOfPrincipalTotal	2,227,300,000
Long-term Debt, Description	On October 1, 2012, CL&P redeemed at par four different series of tax-exempt PCRBs totaling $116.4 million. The PCRBs had maturity dates ranging from 2016 through 2028 and coupon rates of 5.85 percent through 5.95 percent. The $125 million of tax-exempt PCRBs were issued with an initial fixed rate term period ending on September 2, 2013, and are subject to mandatory tender for purchase on September 3, 2013, at which time CL&P expects to remarket the PCRBs. On April 2, 2012, CL&P remarketed $62 million of tax-exempt PCRBs for a three-year period. The PCRBs, which mature on May 1, 2031, carry a coupon rate of 1.55 percent during the current three-year fixed rate period and are subject to mandatory tender for purchase on April 1, 2015. On January 15, 2013, CL&P issued $400 million of 2.5 percent Series A First and Refunding Mortgage Bonds with a maturity date of January 15, 2023. The proceeds, net of issuance expenses, were used to repay the amounts outstanding under the CL&P revolver and the NU commercial paper program. As a result, these amounts have been classified as Long-Term Debt as of December 31, 2012. As of December 31, 2012, CL&P had $307.5 million of tax-exempt PCRBs outstanding. CL&P’s obligation to repay each series of PCRBs is secured by first mortgage bonds. Each such series of first mortgage bonds contains similar terms and provisions as the applicable series of PCRBs. If CL&P failed to meet its obligations under the PCRBs, then these first mortgage bonds would become outstanding
The Connecticut Light And Power Company [Member] | Series D 1994 Due 2024 7.875 % [Member]
Debt Instrument [Line Items]
Long-Term Debt	139,800,000	139,800,000
The Connecticut Light And Power Company [Member] | Series A 2004 Due 2014 4.800% [Member]
Debt Instrument [Line Items]
Long-Term Debt	150,000,000	150,000,000
The Connecticut Light And Power Company [Member] | Series B 2004 Due 2034 5.750% [Member]
Debt Instrument [Line Items]
Long-Term Debt	130,000,000	130,000,000
The Connecticut Light And Power Company [Member] | Series A 2005 Due 2015 5.000% [Member]
Debt Instrument [Line Items]
Long-Term Debt	100,000,000	100,000,000
The Connecticut Light And Power Company [Member] | Series B 2005 Due 2035 5.625% [Member]
Debt Instrument [Line Items]
Long-Term Debt	100,000,000	100,000,000
The Connecticut Light And Power Company [Member] | Series A 2006 Due 2036 6.350% [Member]
Debt Instrument [Line Items]
Long-Term Debt	250,000,000	250,000,000
The Connecticut Light And Power Company [Member] | Series A 2007 Due 2017 5.375% [Member]
Debt Instrument [Line Items]
Long-Term Debt	150,000,000	150,000,000
The Connecticut Light And Power Company [Member] | Series B 2007 Due 2037 5.750% [Member]
Debt Instrument [Line Items]
Long-Term Debt	150,000,000	150,000,000
The Connecticut Light And Power Company [Member] | Series D 2007 Due 2037 6.375% [Member]
Debt Instrument [Line Items]
Long-Term Debt	100,000,000	100,000,000
The Connecticut Light And Power Company [Member] | Series A 2008 Due 2018 5.650% [Member]
Debt Instrument [Line Items]
Long-Term Debt	300,000,000	300,000,000
The Connecticut Light And Power Company [Member] | Series A 2009 Due 2019 5.500% [Member]
Debt Instrument [Line Items]
Long-Term Debt	250,000,000	250,000,000
The Connecticut Light And Power Company [Member] | Fixed Rate 5.85% To 5.90% Due 2016 To 2022 [Member]
Debt Instrument [Line Items]
Long-Term Debt	0	116,400,000
The Connecticut Light And Power Company [Member] | One-Year Fixed Rate Tax Exempt Due 2031 [Member]
Debt Instrument [Line Items]
Long-Term Debt	62,000,000	62,000,000
The Connecticut Light And Power Company [Member] | Fees And Interest Due For Spent Nuclear Fuel Disposal Costs [Member]
Debt Instrument [Line Items]
Long-Term Debt	244,300,000	244,100,000
The Connecticut Light And Power Company [Member] | Total First Mortgage Bonds [Member]
Debt Instrument [Line Items]
Long-Term Debt	1,919,800,000	1,919,800,000
The Connecticut Light And Power Company [Member] | Total Pollution Control Bonds [Member]
Debt Instrument [Line Items]
Long-Term Debt	307,500,000	423,900,000
The Connecticut Light And Power Company [Member] | Total First Mortgage Bonds and Pollution Control Notes [Member]
Debt Instrument [Line Items]
Long-Term Debt	2,227,300,000	2,343,700,000
The Connecticut Light And Power Company [Member] | Unamortized Premiums and Discounts, Net [Member]
Debt Instrument [Line Items]
Long-Term Debt	(3,600,000)	(4,000,000)
The Connecticut Light And Power Company [Member] | Serires C 2007 5.750% Due 2017 [Member]
Debt Instrument [Line Items]
Long-Term Debt	100,000,000	100,000,000
The Connecticut Light And Power Company [Member] | Fixed Rate 4.375% due 2028 [Member]
Debt Instrument [Line Items]
Long-Term Debt	120,500,000	120,500,000
The Connecticut Light And Power Company [Member] | Fixed Rate 1.25% due 2028 [Member]
Debt Instrument [Line Items]
Long-Term Debt	125,000,000	125,000,000
The Connecticut Light And Power Company [Member] | Commerical Paper and Revolver Borrowings [Member]
Debt Instrument [Line Items]
Long-Term Debt	394,800,000
Western Massachusetts Electric Company [Member]
Debt Instrument [Line Items]
Long-Term Debt - Current Portion	55,000,000	0
Long-Term Debt	550,270,000	499,545,000
Maturities of Long-term Debt [Abstract]
Long-term Debt, Maturities, Repayments of Principal in Next Twelve Months	55,000,000
Long-term Debt, Maturities, Repayments of Principal in Year Two	0
Long-term Debt, Maturities, Repayments of Principal in Year Three	50,000,000
Long-term Debt, Maturities, Repayments of Principal in Year Four	0
Long-term Debt, Maturities, Repayments of Principal in Year Five	0
Long-term Debt, Maturities, Repayments of Principal after Year Five	435,000,000
LongTermDebtMaturitiesRepaymentsOfPrincipalTotal	540,000,000
Long-term Debt, Description	On October 1, 2012, WMECO redeemed at par $53.8 million of tax-exempt PCRBs. The PCRBs had a maturity date of 2028 and a coupon of 5.85 percent. On October 4, 2012, WMECO issued at a premium $150 million of senior unsecured notes at a yield of 2.673 percent that will mature on September 15, 2021. The senior notes are part of the same series of WMECO’s existing 3.5 percent coupon Series F Senior Notes that were initially issued in September 2011. As a result, the aggregate principal amount of WMECO’s outstanding Series F Senior Notes totaled $250 million.
Western Massachusetts Electric Company [Member] | Tax Exempt 1993 Series A 5.85% Due 2028 [Member]
Debt Instrument [Line Items]
Long-Term Debt		53,800,000
Western Massachusetts Electric Company [Member] | Senior Note Series A 5.00% Due 2013 [Member]
Debt Instrument [Line Items]
Long-Term Debt	55,000,000	55,000,000
Western Massachusetts Electric Company [Member] | Senior Notes Series B 5.90% Due 2034 [Member]
Debt Instrument [Line Items]
Long-Term Debt	50,000,000	50,000,000
Western Massachusetts Electric Company [Member] | Senior Notes Series C 5.24% Due 2015 [Member]
Debt Instrument [Line Items]
Long-Term Debt	50,000,000	50,000,000
Western Massachusetts Electric Company [Member] | Senior Notes Series D 6.70% Due 2037 [Member]
Debt Instrument [Line Items]
Long-Term Debt	40,000,000	40,000,000
Western Massachusetts Electric Company [Member] | Senior Notes Series E 5.10% Due 2020 [Member]
Debt Instrument [Line Items]
Long-Term Debt	95,000,000	95,000,000
Western Massachusetts Electric Company [Member] | Fees And Interest Due For Spent Nuclear Fuel Disposal Costs [Member]
Debt Instrument [Line Items]
Long-Term Debt	57,300,000	57,300,000
Western Massachusetts Electric Company [Member] | Unamortized Premiums and Discounts, Net [Member]
Debt Instrument [Line Items]
Long-Term Debt	8,000,000	(1,600,000)
Western Massachusetts Electric Company [Member] | Senior Notes Series F 3.50% due 2021 [Member]
Debt Instrument [Line Items]
Long-Term Debt	250,000,000	100,000,000
Western Massachusetts Electric Company [Member] | Total Pollution Control Notes and Other Notes [Member]
Debt Instrument [Line Items]
Long-Term Debt	540,000,000	443,800,000
Subsidiaries [Member] | Fair Value Adjustment [Member]
Debt Instrument [Line Items]
Long-Term Debt	259,900,000	2,300,000
Subsidiaries [Member] | FairValueAdjustmentMemberCurrentPortion [Member]
Debt Instrument [Line Items]
Long-Term Debt	31,700,000	2,300,000
Subsidiaries [Member] | Variable Rates Series D Due 2013 [Member]
Debt Instrument [Line Items]
Long-Term Debt	300,000,000
Yankee Gas Services Company [Member] | Total First Mortgage Bonds [Member]
Debt Instrument [Line Items]
Long-Term Debt	345,000,000	349,300,000
Yankee Gas Services Company [Member] | Unamortized Premiums and Discounts, Net [Member]
Debt Instrument [Line Items]
Long-Term Debt	800,000	900,000
Yankee Gas Services Company [Member] | Series B due 2022 8.48% [Member]
Debt Instrument [Line Items]
Long-Term Debt	20,000,000	20,000,000
Yankee Gas Services Company [Member] | Series E due 2012 7.19% [Member]
Debt Instrument [Line Items]
Long-Term Debt		4,300,000
Yankee Gas Services Company [Member] | Series G due 2014 4.80% [Member]
Debt Instrument [Line Items]
Long-Term Debt	75,000,000	75,000,000
Yankee Gas Services Company [Member] | Series H due 2019 5.26% [Member]
Debt Instrument [Line Items]
Long-Term Debt	50,000,000	50,000,000
Yankee Gas Services Company [Member] | Series I due 2035 5.35% [Member]
Debt Instrument [Line Items]
Long-Term Debt	50,000,000	50,000,000
Yankee Gas Services Company [Member] | Series J due 2018 6.90% [Member]
Debt Instrument [Line Items]
Long-Term Debt	100,000,000	100,000,000
Yankee Gas Services Company [Member] | Series K due 2020 4.87% [Member]
Debt Instrument [Line Items]
Long-Term Debt	50,000,000	50,000,000
NSTAR Gas Company [Member] | Total First Mortgage Bonds and Pollution Control Notes [Member]
Debt Instrument [Line Items]
Long-Term Debt	210,000,000
NSTAR Gas Company [Member] | Series J Due 202 9.95% [Member]
Debt Instrument [Line Items]
Long-Term Debt	25,000,000
NSTAR Gas Company [Member] | Series K Due 2033 7.11% [Member]
Debt Instrument [Line Items]
Long-Term Debt	35,000,000
NSTAR Gas Company [Member] | Series M Due 2017 7.04% [Member]
Debt Instrument [Line Items]
Long-Term Debt	25,000,000
NSTAR Gas Company [Member] | Series N Due 2020 4.46% [Member]
Debt Instrument [Line Items]
Long-Term Debt	125,000,000
NSTAR Electric Company [Member]
Debt Instrument [Line Items]
Long-Term Debt - Current Portion	1,650,000	401,650,000
Long-Term Debt	1,600,911,000	1,203,344,000
Maturities of Long-term Debt [Abstract]
Long-term Debt, Description	On October 15, 2012, NSTAR Electric issued at a discount $400 million of 2.375 percent Debentures at a yield of 2.406 percent that will mature on October 15, 2022. The proceeds, net of issuance costs, were used to pay $400 million of 4.875 percent Debentures that matured on October 15, 2012.
NSTAR Electric Company [Member] | Unamortized Premiums and Discounts, Net [Member]
Debt Instrument [Line Items]
Long-Term Debt	(5,400,000)	(4,700,000)
NSTAR Electric Company [Member] | Total Other [Member]
Debt Instrument [Line Items]
Long-Term Debt	1,600,000,000	1,600,000,000
NSTAR Electric Company [Member] | Due 2012 4.875% [Member]
Debt Instrument [Line Items]
Long-Term Debt	300,000,000	400,000,000
NSTAR Electric Company [Member] | Due 2014 4.875% [Member]
Debt Instrument [Line Items]
Long-Term Debt		300,000,000
NSTAR Electric Company [Member] | Due 2022 2.375% [Member]
Debt Instrument [Line Items]
Long-Term Debt	400,000,000
NSTAR Electric Company [Member] | Due 2017 5.625% [Member]
Debt Instrument [Line Items]
Long-Term Debt	400,000,000	400,000,000
NSTAR Electric Company [Member] | Due 2036 5.75% [Member]
Debt Instrument [Line Items]
Long-Term Debt	200,000,000	200,000,000
NSTAR Electric Company [Member] | Due 2040 5.5% [Member]
Debt Instrument [Line Items]
Long-Term Debt	300,000,000	300,000,000
NSTAR Electric Company [Member] | TaxExempt Sewage Facility Revenue Bonds Due 2015 [Member]
Debt Instrument [Line Items]
Long-Term Debt	$ 8,000,000	$ 8,700,000

XML

Supplemental Cash Flow Information (Details) (USD $)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Capital Expenditures Incurred But Not Yet Paid	$ 160,600,000	$ 168,500,000	$ 127,900,000
Interest Paid, Net of Amounts Capitalized	356,500,000	256,300,000	258,300,000
Income Taxes Paid	(12,800,000)	(76,600,000)	84,500,000
The Connecticut Light And Power Company [Member]
Capital Expenditures Incurred But Not Yet Paid	42,800,000	32,700,000	46,200,000
Interest Paid, Net of Amounts Capitalized	129,400,000	136,600,000	142,200,000
Income Taxes Paid	(42,000,000)	(27,500,000)	71,500,000
Public Service Company Of New Hampshire [Member]
Capital Expenditures Incurred But Not Yet Paid	16,800,000	51,100,000	35,800,000
Interest Paid, Net of Amounts Capitalized	49,800,000	49,300,000	51,400,000
Income Taxes Paid	14,700,000	(29,000,000)	1,600,000
Western Massachusetts Electric Company [Member]
Capital Expenditures Incurred But Not Yet Paid	30,000,000	61,300,000	21,200,000
Interest Paid, Net of Amounts Capitalized	25,800,000	22,100,000	20,200,000
Income Taxes Paid	(8,400,000)	(4,900,000)	5,000,000
NSTAR Electric Company [Member]
Capital Expenditures Incurred But Not Yet Paid	50,000,000	34,300,000	16,700,000
Interest Paid, Net of Amounts Capitalized	94,600,000	96,100,000	95,800,000
Income Taxes Paid	$ 88,100,000	$ (62,200,000)	$ 147,600,000

XML

Restricted Cash and Other Deposits (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Special Deposits [Line Items]
Rate Reduction Bond Deposits	$ 69.4	$ 29.5
Restricted Cash And Cash Equivalents	3.3	17.9
Cash Collateral Deposited	14.6	10.9
The Connecticut Light And Power Company [Member]
Special Deposits [Line Items]
Restricted Cash And Cash Equivalents	1.3	9.4
Public Service Company Of New Hampshire [Member]
Special Deposits [Line Items]
Rate Reduction Bond Deposits	22.0	24.4
Restricted Cash And Cash Equivalents	1.7	7.0
Western Massachusetts Electric Company [Member]
Special Deposits [Line Items]
Rate Reduction Bond Deposits	5.1	5.1
NSTAR Electric Company [Member]
Special Deposits [Line Items]
Rate Reduction Bond Deposits	$ 42.2	$ 40.9

XML

ACCUMULATED OTHER COMPREHENSIVE INCOME

12 Months Ended

Dec. 31, 2012

Notes To Consolidated Financial Statements [Abstract]

Comprehensive Income Note [Text Block]

15.       ACCUMULATED OTHER COMPREHENSIVE INCOME/(LOSS)

The accumulated balance for each component of other comprehensive income/(loss), net of tax, is as follows:

(Millions of Dollars)	As of December 31,
NU	2012		2011
Qualified Cash Flow Hedging Instruments	$	(16.4)	$	(18.4)
Unrealized Gains on Other Securities		1.3		1.1
Pension, SERP and PBOP Benefits		(57.8)		(53.4)
Accumulated Other Comprehensive Loss	$	(72.9)	$	(70.7)
CL&P
Qualified Cash Flow Hedging Instruments	$	(1.8)	$	(2.3)
PSNH
Qualified Cash Flow Hedging Instruments	$	(9.7)	$	(10.9)
WMECO
Qualified Cash Flow Hedging Instruments	$	(3.8)	$	(4.2)

Qualified cash flow hedging items impacting Net Income in the tables above represent amounts that were reclassified from Accumulated Other Comprehensive Income/(Loss) into Net Income for interest rate swap agreements. For the year ended December31, 2012, qualified cash flow hedging activity relates to the amortization of previously settled interest rate swap agreements. For the year ended December31, 2011,activity related to qualified cash flow hedging activity was as follows:

		For the Year Ended December 31, 2011
(Millions of Dollars)		NU			PSNH		WMECO
Balance as of January 1, 2011		$	(4.2)	$	(0.6)	$	(0.1)
	Hedged Transactions Recognized into Earnings		0.7		0.5		0.1
	Cash Flow Hedging Transactions Entered into for the Year		(14.9)		(10.8)		(4.2)
Net Change Associated with Hedging Transactions			(14.2)		(10.3)		(4.1)
Balance as of December 31, 2011		$	(18.4)	$	(10.9)	$	(4.2)
For further information regarding cash flow hedging transactions, see Note 5, "Derivative Instruments," to the consolidated financial statements.

The changes in the components of other comprehensive income/(loss) are reported net of the following income tax effects:
(Millions of Dollars)
NU	2012		2011		2010
Qualified Cash Flow Hedging Instruments	$	1.3	$	(9.5)	$	0.2
Change in Unrealized Gains on Other Securities		0.1		0.4		0.2
Pension, SERP and PBOP Benefits		(2.7)		(7.9)		-
Total	$	(1.3)	$	(17.0)	$	0.4
CL&P
Qualified Cash Flow Hedging Instruments	$	0.3	$	0.3	$	0.3
PSNH
Qualified Cash Flow Hedging Instruments	$	0.8	$	(7.0)	$	0.1
WMECO
Qualified Cash Flow Hedging Instruments	$	0.2	$	(2.7)	$	-

It is estimated that a charge of $2million will be reclassified from Accumulated Other Comprehensive Income/(Loss) as a decrease to earnings over the next 12 months as a result of amortization of the interest rate swap agreements, which have been settled. Included in this amount are estimated charges of $0.4million, $1.2 million and $0.3 million for CL&P, PSNH and WMECO, respectively. As of December 31, 2012, it is estimated that a pre-tax amount of $10.5million included in the Accumulated Other Comprehensive Income/(Loss) balance will be reclassified as a decrease to Net Income over the next 12 months related to Pension, SERP and PBOP adjustments for NU.

XML

LONG-TERM DEBT (TABLES)

12 Months Ended

Dec. 31, 2012

Notes To Consolidated Financial Statements [Abstract]

Schedule of Maturities of Long-term Debt [Table Text Block]

(Millions of Dollars)	NU		CL&P		NSTAR Electric		PSNH		WMECO
2013	$	731.7	$	125.0	$	1.7	$	-	$	55.0
2014		576.6		150.0		301.7		50.0		-
2015		216.7		162.0		4.7		-		50.0
2016		-		-		-		-		-
2017		745.0		250.0		400.0		70.0		-
Thereafter		4,559.8		1,540.3		899.9		879.5		435.0
Total	$	6,829.8	$	2,227.3	$	1,608.0	$	999.5	$	540.0

Schedule of Long-term Debt Instruments [Table Text Block]

CL&P		As of December 31,
(Millions of Dollars)		2012		2011
First Mortgage Bonds:
	7.875% 1994 Series D due 2024	$	139.8	$	139.8
	4.800% 2004 Series A due 2014		150.0		150.0
	5.750% 2004 Series B due 2034		130.0		130.0
	5.000% 2005 Series A due 2015		100.0		100.0
	5.625% 2005 Series B due 2035		100.0		100.0
	6.350% 2006 Series A due 2036		250.0		250.0
	5.375% 2007 Series A due 2017		150.0		150.0
	5.750% 2007 Series B due 2037		150.0		150.0
	5.750% 2007 Series C due 2017		100.0		100.0
	6.375% 2007 Series D due 2037		100.0		100.0
	5.650% 2008 Series A due 2018		300.0		300.0
	5.500% 2009 Series A due 2019		250.0		250.0
Total First Mortgage Bonds			1,919.8		1,919.8
Pollution Control Notes:
	5.85%-5.95% Fixed Rate Tax Exempt due 2016-2028 (1)		-		116.4
	4.375% Fixed Rate Tax Exempt due 2028		120.5		120.5
	1.25% Fixed Rate Tax Exempt due 2028(2)		125.0		125.0
	1.55% Fixed Rate Tax Exempt due 2031(3)		62.0		62.0
Total Pollution Control Notes			307.5		423.9
Total First Mortgage Bonds and Pollution Control Notes			2,227.3		2,343.7
Fees and Interest due for Spent Nuclear Fuel Disposal Costs			244.3		244.1
CL&P Commercial Paper and Revolver Borrowings(4)			394.8		-
Less Amounts due Within One Year(2)			(125.0)		(62.0)
Unamortized Premiums and Discounts, Net			(3.6)		(4.0)
CL&P Long-Term Debt		$	2,737.8	$	2,521.8
NSTAR Electric		As of December 31,
(Millions of Dollars)		2012		2011(5)
Debentures:
	4.875% due 2012(6)	$	-	$	400.0
	4.875% due 2014		300.0		300.0
	2.375% due 2022(6)		400.0		-
	5.625% due 2017		400.0		400.0
	5.75% due 2036		200.0		200.0
	5.50% due 2040		300.0		300.0
Total Debentures			1,600.0		1,600.0
Bonds:
	7.375% Tax Exempt Sewage Facility Revenue Bonds, due 2015		8.0		8.7
Less Amounts due Within One Year			(1.7)		(400.7)
Unamortized Premiums and Discounts, Net			(5.4)		(4.7)
NSTAR Electric Long-Term Debt		$	1,600.9	$	1,203.3
PSNH		As of December 31,
(Millions of Dollars)		2012		2011
First Mortgage Bonds:
	5.25% 2004 Series L due 2014	$	50.0	$	50.0
	5.60% 2005 Series M due 2035		50.0		50.0
	6.15% 2007 Series N due 2017		70.0		70.0
	6.00% 2008 Series O due 2018		110.0		110.0
	4.50% 2009 Series P due 2019		150.0		150.0
	4.05% 2011 Series Q due 2021		122.0		122.0
	3.20% 2011 Series R due 2021		160.0		160.0
Total First Mortgage Bonds			712.0		712.0
Pollution Control Revenue Bonds:
	4.75% - 5.45% Tax Exempt Series B and C due 2021		198.2		198.2
	Adjustable Rate Series A due 2021		89.3		89.3
Total Pollution Control Revenue Bonds			287.5		287.5
Unamortized Premiums and Discounts, Net			(1.6)		(1.8)
PSNH Long-Term Debt		$	997.9	$	997.7

WMECO		As of December 31,
(Millions of Dollars)		2012		2011
Pollution Control Revenue Bonds and Other Notes:
	5.85% Tax Exempt PCRBs 1993 Series A, due 2028 (7)	$	-	$	53.8
	5.00% Senior Notes Series A, due 2013		55.0		55.0
	5.90% Senior Notes Series B, due 2034		50.0		50.0
	5.24% Senior Notes Series C, due 2015		50.0		50.0
	6.70% Senior Notes Series D, due 2037		40.0		40.0
	5.10% Senior Notes Series E, due 2020		95.0		95.0
	3.50% Senior Notes Series F, due 2021 (8)		250.0		100.0
Total Pollution Control Revenue Bonds and Other Notes			540.0		443.8
Fees and Interest due for Spent Nuclear Fuel Disposal Costs			57.3		57.3
Less Amounts due Within One Year			(55.0)		-
Unamortized Premiums and Discounts, Net			8.0		(1.6)
WMECO Long-Term Debt		$	550.3	$	499.5
OTHER		As of December 31,
(Millions of Dollars)		2012			2011
Yankee Gas - First Mortgage Bonds:
	7.19% Series E due 2012	$	-	$	4.3
	8.48% Series B due 2022		20.0		20.0
	4.80% Series G due 2014		75.0		75.0
	5.26% Series H due 2019		50.0		50.0
	5.35% Series I due 2035		50.0		50.0
	6.90% Series J due 2018		100.0		100.0
	4.87% Series K due 2020		50.0		50.0
Total First Mortgage Bonds			345.0		349.3
Less Amounts due Within One Year			-		(4.3)
Unamortized Premium			0.8		0.9
Yankee Gas Long-Term Debt			345.8		345.9
NSTAR Gas - First Mortgage Bonds:
	9.95% Series J due 2020		25.0		N/A
	7.11% Series K due 2033		35.0		N/A
	7.04% Series M due 2017		25.0		N/A
	4.46% Series N due 2020		125.0		N/A
NSTAR Gas Long-Term Debt			210.0		N/A
Other - Notes and Debentures:
	7.25% Senior Notes Series A due 2012 (NU Parent) (9)		-		263.0
	5.65% Senior Notes Series C due 2013 (NU Parent)		250.0		250.0
	Variable Rate Senior Notes Series D due 2013 (NU Parent) (9)		300.0		-
	4.50% Debentures due 2019 (NSTAR LLC)		350.0		N/A
	Spent Nuclear Fuel Obligation (CYAPC)		179.3		N/A
Total Other Long-Term Debt			1,079.3		513.0
Fair Value Adjustment(10)			259.9		2.3
Less Amounts due Within One Year			(550.0)		(263.0)
Less: Fair Value Adjustment - Current Portion(10)			(31.7)		(2.3)
Total NU Long-Term Debt		$	7,200.2	$	4,614.9

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Supplemental Cash Flow Information (Tables)

12 Months Ended

Dec. 31, 2012

Notes To Consolidated Financial Statements [Abstract]

Schedule of Cash Flow, Supplemental Disclosures [Table Text Block]

P.		Supplemental Cash Flow Information
NU			As of and For the Years Ended December 31,
(Millions of Dollars)			2012		2011		2010
Cash Paid/(Received) During the Year for:
	Interest, Net of Amounts Capitalized		$	356.5	$	256.3	$	258.3
	Income Taxes			(12.8)		(76.6)		84.5
Non-Cash Investing Activities:
	Plant Additions Included in Accounts Payable (As of)			160.6		168.5		127.9

		As of and For the Years Ended December 31,
		2012								2011								2010
				NSTAR								NSTAR								NSTAR
(Millions of Dollars)		CL&P		Electric (1)		PSNH		WMECO		CL&P		Electric (1)		PSNH		WMECO		CL&P		Electric (1)		PSNH		WMECO
Cash Paid/(Received) During
	the Year for:
	Interest, Net of Amounts
	Capitalized	$	129.4	$	94.6	$	49.8	$	25.8	$	136.6	$	96.1	$	49.3	$	22.1	$	142.2	$	95.8	$	51.4	$	20.2
	Income Taxes		(42.0)		88.1		14.7		(8.4)		(27.5)		(62.2)		(29.0)		(4.9)		71.5		147.6		1.6		5.0
Non-Cash Investing Activities:
	Plant Additions Included in
	Accounts Payable (As of)		42.8		50.0		16.8		30.0		32.7		34.3		51.1		61.3		46.2		16.7		35.8		21.2

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Other Income, Net (Details) (USD $)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Component Of Other Income Nonoperating [Line Items]
Public Utilities Allowance For Funds Used During Construction Additions	$ 6,800,000	$ 22,500,000	$ 16,700,000
Other Income/(Loss), Net	19,742,000	27,715,000	41,916,000
The Connecticut Light And Power Company [Member]
Component Of Other Income Nonoperating [Line Items]
Public Utilities Allowance For Funds Used During Construction Additions	1,900,000	6,000,000	4,900,000
Other Income/(Loss), Net	10,300,000	9,741,000	26,669,000
Public Service Company Of New Hampshire [Member]
Component Of Other Income Nonoperating [Line Items]
Public Utilities Allowance For Funds Used During Construction Additions	1,900,000	13,200,000	10,400,000
Other Income/(Loss), Net	3,008,000	14,255,000	11,749,000
Western Massachusetts Electric Company [Member]
Component Of Other Income Nonoperating [Line Items]
Public Utilities Allowance For Funds Used During Construction Additions	1,000,000	1,000,000	600,000
Other Income/(Loss), Net	$ 2,503,000	$ 1,489,000	$ 2,597,000

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LEASES (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Operating Leased Assets [Line Items]
Capital Leases, Future Minimum Payments Due, Current	$ 2.8
Capital Leases, Future Minimum Payments Due in Two Years	2.2
Capital Leases, Future Minimum Payments Due in Three Years	2.2
Capital Leases, Future Minimum Payments Due in Four Years	2.0
Capital Leases, Future Minimum Payments Due in Five Years	2.0
Capital Leases, Future Minimum Payments Due Thereafter	7.5
Capital Leases, Future Minimum Payments Due	18.7
Capital Leases, Future Minimum Payments, Interest Included in Payments	7.6
Capital Leases, Future Minimum Payments, Present Value of Net Minimum Payments	11.1
Operating Leases, Rent Expense	14.8	8.4	11.9
Operating Leases, Future Minimum Payments Due, Current	22.4
Operating Leases, Future Minimum Payments, Due in Two Years	16.6
Operating Leases, Future Minimum Payments, Due in Three Years	14.1
Operating Leases, Future Minimum Payments, Due in Four Years	11.2
Operating Leases, Future Minimum Payments, Due in Five Years	8.6
Operating Leases, Future Minimum Payments, Due Thereafter	23.3
Operating Leases, Future Minimum Payments Due	96.2
The Connecticut Light And Power Company [Member]
Operating Leased Assets [Line Items]
Capital Leases, Future Minimum Payments Due, Current	2.2
Capital Leases, Future Minimum Payments Due in Two Years	2.0
Capital Leases, Future Minimum Payments Due in Three Years	2.0
Capital Leases, Future Minimum Payments Due in Four Years	1.9
Capital Leases, Future Minimum Payments Due in Five Years	2.0
Capital Leases, Future Minimum Payments Due Thereafter	7.3
Capital Leases, Future Minimum Payments Due	17.4
Capital Leases, Future Minimum Payments, Interest Included in Payments	7.4
Capital Leases, Future Minimum Payments, Present Value of Net Minimum Payments	10.0
Operating Leases, Rent Expense	8.2	8.3	10.0
Operating Leases, Future Minimum Payments Due, Current	4.3
Operating Leases, Future Minimum Payments, Due in Two Years	3.7
Operating Leases, Future Minimum Payments, Due in Three Years	3.1
Operating Leases, Future Minimum Payments, Due in Four Years	2.3
Operating Leases, Future Minimum Payments, Due in Five Years	1.2
Operating Leases, Future Minimum Payments, Due Thereafter	6.4
Operating Leases, Future Minimum Payments Due	21.0
Public Service Company Of New Hampshire [Member]
Operating Leased Assets [Line Items]
Capital Leases, Future Minimum Payments Due, Current	0.5
Capital Leases, Future Minimum Payments Due in Two Years	0.2
Capital Leases, Future Minimum Payments Due in Three Years	0.2
Capital Leases, Future Minimum Payments Due in Four Years	0.1
Capital Leases, Future Minimum Payments Due in Five Years	0
Capital Leases, Future Minimum Payments Due Thereafter	0
Capital Leases, Future Minimum Payments Due	1.0
Capital Leases, Future Minimum Payments, Interest Included in Payments	0.1
Capital Leases, Future Minimum Payments, Present Value of Net Minimum Payments	0.9
Operating Leases, Rent Expense	2.5	2.1	2.2
Operating Leases, Future Minimum Payments Due, Current	1.3
Operating Leases, Future Minimum Payments, Due in Two Years	1.0
Operating Leases, Future Minimum Payments, Due in Three Years	0.8
Operating Leases, Future Minimum Payments, Due in Four Years	0.6
Operating Leases, Future Minimum Payments, Due in Five Years	0.5
Operating Leases, Future Minimum Payments, Due Thereafter	1.8
Operating Leases, Future Minimum Payments Due	6.0
Western Massachusetts Electric Company [Member]
Operating Leased Assets [Line Items]
Operating Leases, Rent Expense	3.0	2.8	2.8
Operating Leases, Future Minimum Payments Due, Current	2.7
Operating Leases, Future Minimum Payments, Due in Two Years	1.1
Operating Leases, Future Minimum Payments, Due in Three Years	0.6
Operating Leases, Future Minimum Payments, Due in Four Years	0.3
Operating Leases, Future Minimum Payments, Due in Five Years	0.2
Operating Leases, Future Minimum Payments, Due Thereafter	1.2
Operating Leases, Future Minimum Payments Due	6.1
NSTAR Electric Company [Member]
Operating Leased Assets [Line Items]
Operating Leases, Rent Expense	6.2	19.8	19.2
Operating Leases, Future Minimum Payments Due, Current	10.9
Operating Leases, Future Minimum Payments, Due in Two Years	8.2
Operating Leases, Future Minimum Payments, Due in Three Years	7.4
Operating Leases, Future Minimum Payments, Due in Four Years	6.1
Operating Leases, Future Minimum Payments, Due in Five Years	5.1
Operating Leases, Future Minimum Payments, Due Thereafter	10.3
Operating Leases, Future Minimum Payments Due	$ 48.0

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Provision for Uncollectible Accounts (Tables)

12 Months Ended

Dec. 31, 2012

Notes To Consolidated Financial Statements [Abstract]

Schedule Of Accounts Notes Loans And Financing Receivable Text Block

	As of December 31,
(Millions of Dollars)	2012		2011
NU (2)	$	165.5	$	115.7
CL&P (2)		77.6		83.5
NSTAR Electric (1)		44.1		27.1
PSNH		6.8		7.2
WMECO (2)		8.5		10.0

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DEFINED CONTRIBUTION PLANS (TABLES)

12 Months Ended

Dec. 31, 2012

Notes To Consolidated Financial Statements [Abstract]

Schedule Of Defined Contribution Plans 401k [Table Text Block]

					NSTAR
(Millions of Dollars)	NU		CL&P		Electric(1)		PSNH		WMECO
2012	$	25.7	$	4.8	$	9.0	$	3.3	$	0.9
2011		17.4		4.5		8.7		3.1		0.9
2010		16.1		4.4		8.1		2.8		0.9

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QUARTERLY FINANCIAL DATA (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2012

Quarterly Financial Data [Abstract]

Schedule of Quarterly Financial Information [Table Text Block]

NU Consolidated Statements of Quarterly Financial Data	Quarter Ended (a)
(Millions of Dollars, except per share information)	March 31,		June 30,		September 30,		December 31,
2012 (1)
Operating Revenues	$	1,099.6	$	1,628.7	$	1,861.5	$	1,684.0
Operating Income		214.4		159.5		412.9		331.4
Net Income		100.8		46.2		209.5		176.6	(2)
Net Income Attributable to Controlling Interest		99.3		44.3		207.6		174.7
Basic and Diluted EPS	$	0.56	$	0.15	$	0.66	$	0.55
2011 (1)
Operating Revenues	$	1,235.3	$	1,047.5	$	1,114.9	$	1,068.0
Operating Income		227.4		178.1		203.8		184.9
Net Income		115.6		78.7		91.4		114.8
Net Income Attributable to Controlling Interest		114.2		77.3		90.0		113.2
Basic and Diluted EPS	$	0.64	$	0.44	$	0.51	$	0.64
(a) The summation of quarterly EPS data may not equal annual data due to rounding.
CL&P Consolidated Statements of Quarterly Financial Data	Quarter Ended
(Millions of Dollars)	March 31,		June 30,		September 30,		December 31,
2012
Operating Revenues	$	592.0	$	562.1	$	658.1	$	595.2
Operating Income		111.9		40.4		139.7		135.0
Net Income		54.0		6.9		74.9		73.9
2011
Operating Revenues	$	673.7	$	608.0	$	673.7	$	593.0
Operating Income		126.0		114.8		137.7		84.7
Net Income		64.3		52.6		66.5		66.8
NSTAR Electric Consolidated Statements of
Quarterly Financial Data	Quarter Ended
(Millions of Dollars)	March 31,		June 30,		September 30,		December 31,
2012 (1)
Operating Revenues	$	556.5	$	534.6	$	693.7	$	516.2
Operating Income		22.5		93.9		194.1		70.9
Net Income		3.9		45.5		106.8		34.0	(2)
2011 (1)
Operating Revenues	$	577.5	$	552.3	$	724.7	$	548.6
Operating Income		87.7		115.6		183.7		99.2
Net Income		42.9		60.7		99.8		49.1
PSNH Consolidated Statements of Quarterly Financial Data	Quarter Ended
(Millions of Dollars)	March 31,		June 30,		September 30,		December 31,
2012
Operating Revenues	$	243.0	$	255.1	$	256.9	$	233.0
Operating Income		45.4		47.0		61.3		51.4
Net Income		21.3		21.2		27.2		27.2
2011
Operating Revenues	$	269.5	$	240.2	$	259.6	$	243.7
Operating Income		46.9		37.9		48.5		46.8
Net Income		27.5		21.7		25.6		25.5
WMECO Consolidated Statements of Quarterly Financial Data	Quarter Ended
(Millions of Dollars)	March 31,		June 30,		September 30,		December 31,
2012
Operating Revenues	$	114.0	$	106.8	$	112.5	$	107.9
Operating Income		28.7		25.1		28.1		28.9
Net Income		14.2		11.1		14.1		15.1
2011
Operating Revenues	$	106.7	$	98.4	$	104.5	$	107.7
Operating Income		21.1		18.5		19.8		29.0
Net Income		10.0		8.2		8.4		16.5

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SCHEDULE I - Comprehensive Income (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended								12 Months Ended
	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Net Income	$ 176,600	$ 209,500	$ 46,200	$ 100,800	$ 114,800	$ 91,400	$ 78,700	$ 115,600	$ 533,077	$ 400,513	$ 394,107
Other Comprehensive Income Loss Net Of Tax Period Increase Decrease Abstract
Other Comprehensive Income (Loss), Derivatives Qualifying as Hedges, Net of Tax									1,971	(14,177)	200
Other Comprehensive Income (Loss), Available-for-sale Securities Adjustment, Net of Tax									217	506	402
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Adjustment, Net of Tax									(4,356)	(13,645)	(505)
Other Comprehensive Income (Loss), Net of Tax									(2,168)	(27,316)	97
Comprehensive Income Attributable to Noncontrolling Interests									7,132	5,820	6,158
Comprehensive Income									523,777	367,377	388,046
NSTAR Electric Company [Member]
Net Income	34,000	106,800	45,500	3,900	49,100	99,800	60,700	42,900	190,242	252,494	248,575
Nu Parent [Member]
Net Income									526,048	394,955	388,006
Other Comprehensive Income Loss Net Of Tax Period Increase Decrease Abstract
Other Comprehensive Income (Loss), Derivatives Qualifying as Hedges, Net of Tax									1,971	(14,177)	200
Other Comprehensive Income (Loss), Available-for-sale Securities Adjustment, Net of Tax									217	506	402
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Adjustment, Net of Tax									(4,356)	(13,645)	(505)
Other Comprehensive Income (Loss), Net of Tax									(2,168)	(27,316)	97
Comprehensive Income Attributable to Noncontrolling Interests									(103)	(262)	(57)
Comprehensive Income									$ 523,777	$ 367,377	$ 388,046

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ACCUMULATED OTHER COMPREHENSIVE INCOME (Tables)

12 Months Ended

Dec. 31, 2012

Notes To Consolidated Financial Statements [Abstract]

Schedule Of Accumulated Other Comprehensive Income Loss Table Text Block

(Millions of Dollars)	As of December 31,
NU	2012		2011
Qualified Cash Flow Hedging Instruments	$	(16.4)	$	(18.4)
Unrealized Gains on Other Securities		1.3		1.1
Pension, SERP and PBOP Benefits		(57.8)		(53.4)
Accumulated Other Comprehensive Loss	$	(72.9)	$	(70.7)
CL&P
Qualified Cash Flow Hedging Instruments	$	(1.8)	$	(2.3)
PSNH
Qualified Cash Flow Hedging Instruments	$	(9.7)	$	(10.9)
WMECO
Qualified Cash Flow Hedging Instruments	$	(3.8)	$	(4.2)

Schedule Of Comprehensive Income Loss [Table Text Block]

The changes in the components of other comprehensive income/(loss) are reported net of the following income tax effects:
(Millions of Dollars)
NU	2012		2011		2010
Qualified Cash Flow Hedging Instruments	$	1.3	$	(9.5)	$	0.2
Change in Unrealized Gains on Other Securities		0.1		0.4		0.2
Pension, SERP and PBOP Benefits		(2.7)		(7.9)		-
Total	$	(1.3)	$	(17.0)	$	0.4
CL&P
Qualified Cash Flow Hedging Instruments	$	0.3	$	0.3	$	0.3
PSNH
Qualified Cash Flow Hedging Instruments	$	0.8	$	(7.0)	$	0.1
WMECO
Qualified Cash Flow Hedging Instruments	$	0.2	$	(2.7)	$	-

Schedule Of Cash Flow Hedges Included In Accumulated Other Comprehensive Income Loss [Table Text Block]

	Gains/(Losses) Recognized on		Gains/(Losses) Reclassified from AOCI
	Derivative Instruments		into Interest Expense
	For the Year Ended December 31,		For the Years Ended December 31,
(Millions of Dollars)	2011		2012		2011		2010
NU	$	(25.1)	$	(3.3)	$	(1.3)	$	(0.4)
CL&P		-		(0.7)		(0.7)		(0.7)
PSNH		(18.2)		(2.0)		(0.8)		(0.2)
WMECO		(6.9)		(0.5)		(0.1)		0.1

		For the Year Ended December 31, 2011
(Millions of Dollars)		NU			PSNH		WMECO
Balance as of January 1, 2011		$	(4.2)	$	(0.6)	$	(0.1)
	Hedged Transactions Recognized into Earnings		0.7		0.5		0.1
	Cash Flow Hedging Transactions Entered into for the Year		(14.9)		(10.8)		(4.2)
Net Change Associated with Hedging Transactions			(14.2)		(10.3)		(4.1)
Balance as of December 31, 2011		$	(18.4)	$	(10.9)	$	(4.2)
For further information regarding cash flow hedging transactions, see Note 5, "Derivative Instruments," to the consolidated financial statements.

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MARKETABLE SECURITIES (Tables)

12 Months Ended

Dec. 31, 2012

Notes To Consolidated Financial Statements [Abstract]

Schedule Of Available For Sale Securities Reconciliation [Table TextBlock]

		As of December 31, 2012
				Pre-Tax		Pre-Tax
		Amortized		Unrealized		Unrealized
(Millions of Dollars)		Cost		Gains(1)		Losses(1)		Fair Value
NU
	Debt Securities (2)	$	266.6	$	13.3	$	(0.1)	$	279.8
	Equity Securities (2)		145.5		20.0		-		165.5
WMECO
	Debt Securities		57.7		0.1		(0.1)		57.7
		As of December 31, 2011
				Pre-Tax		Pre-Tax
		Amortized		Unrealized		Unrealized
(Millions of Dollars)		Cost		Gains(1)		Losses(1)		Fair Value
NU		$	88.4	$	2.0	$	(0.2)	$	90.2
WMECO			57.3		-		(0.2)		57.1

Investments Classified by Contractual Maturity Date [Table Text Block]

	NU				WMECO
	Amortized				Amortized
(Millions of Dollars)	Cost		Fair Value		Cost		Fair Value
Less than one year (1)	$	66.6	$	66.6	$	27.4	$	27.4
One to five years		57.3		58.7		17.5		17.5
Six to ten years		51.2		54.6		6.0		6.1
Greater than ten years		91.5		99.9		6.8		6.7
Total Debt Securities	$	266.6	$	279.8	$	57.7	$	57.7

Fair Value Heirarchy [Table Text Block]

			NU				WMECO
			As of December 31,				As of December 31,
(Millions of Dollars)			2012		2011		2012		2011
Level 1:
	Mutual Funds and Equities		$	212.5	$	41.1	$	-	$	-
	Money Market Funds			40.2		1.8		5.2		0.1
Total Level 1			$	252.7	$	42.9	$	5.2	$	0.1
Level 2:
	U.S. Government Issued Debt Securities
		(Agency and Treasury)		69.9		11.1		18.7		8.0
	Corporate Debt Securities			33.0		16.5		7.0		9.1
	Asset-Backed Debt Securities			28.5		25.9		10.9		7.9
	Municipal Bonds			93.8		16.1		11.6		15.4
	Other Fixed Income Securities			14.4		18.8		4.3		16.6
Total Level 2			$	239.6	$	88.4	$	52.5	$	57.0
Total Marketable Securities			$	492.3	$	131.3	$	57.7	$	57.1

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REGULATORY ACCOUNTING

12 Months Ended

Dec. 31, 2012

Notes To Consolidated Financial Statements [Abstract]

Public Utilities Disclosure [Text Block]

3.       REGULATORY ACCOUNTING

On April 10, 2012, NSTAR's regulated utility subsidiaries, NSTAR Electric and NSTAR Gas, became subsidiaries of NU. For NSTAR Electric, certain regulatory asset and liability balances as of December 31, 2011 have been reclassified to the current year presentation in order to align the reporting of regulatory activities subsequent to the closing of the merger.

NU's Regulated companies continue to be rate-regulated on a cost-of-service basis; therefore, the accounting policies of the Regulated companies apply GAAP applicable to rate-regulated enterprises and reflect the effects of the rate-making process.

Management believes it is probable that the Regulated companies will recover their respective investments in long-lived assets, including regulatory assets. If management determined that it could no longer apply the accounting guidance applicable to rate-regulated enterprises to the Regulated companies' operations, or that management could not conclude it is probable that costs would be recovered in future rates, the costs would be charged to net income in the period in which the determination is made.

Regulatory Assets: The components of regulatory assets are as follows:

NU	As of December 31,
(Millions of Dollars)	2012		2011
Benefit Costs	$	2,452.1	$	1,360.5
Regulatory Assets Offsetting Derivative Liabilities		885.6		939.6
Goodwill		537.6		-
Storm Restoration Costs		547.7		356.0
Income Taxes, Net		516.2		425.4
Securitized Assets		232.6		101.8
Contractual Obligations		217.6		100.9
Power Contracts Buy Out Agreements		92.9		8.6
Regulatory Tracker Deferrals		190.1		45.9
Asset Retirement Obligations		88.8		47.5
Other Regulatory Assets		76.2		136.6
Total Regulatory Assets	$	5,837.4	$	3,522.8
Less: Current Portion	$	705.0	$	255.1
Total Long-Term Regulatory Assets	$	5,132.4	$	3,267.7

		As of December 31,
		2012								2011
				NSTAR								NSTAR
(Millions of Dollars)		CL&P		Electric		PSNH		WMECO		CL&P		Electric(1)		PSNH		WMECO
Benefit Costs		$	563.2	$	781.2	$	223.7	$	116.0	$	572.8	$	813.7	$	200.0	$	118.9
Regulatory Assets Offsetting
	Derivative Liabilities		866.2		14.9		-		3.0		932.0		3.4		-		7.3
Goodwill			-		461.5		-		-		-		478.9		-		-
Storm Restoration Costs			413.9		55.8		34.5		43.5		268.3		30.6		44.0		43.7
Income Taxes, Net			367.5		47.1		36.2		31.0		339.6		48.8		38.0		17.8
Securitized Assets			-		205.1		19.7		7.8		-		368.5		76.4		25.4
Contractual Obligations			64.0		22.8		-		14.9		80.9		30.8		-		20.0
Power Contracts Buy Out Agreements			-		85.9		7.0		-		-		109.5		8.6		-
Regulatory Tracker Deferrals			12.2		71.4		49.3		31.9		5.5		61.1		11.9		22.1
Asset Retirement Obligations			29.4		29.4		14.2		3.5		27.9		24.5		13.5		3.2
Other Regulatory Assets			27.9		16.9		29.4		12.6		47.0		34.7		35.7		10.3
Total Regulatory Assets		$	2,344.3	$	1,792.0	$	414.0	$	264.2	$	2,274.0	$	2,004.5	$	428.1	$	268.7
Less: Current Portion		$	185.9	$	347.1	$	62.9	$	42.4	$	170.2	$	323.9	$	34.2	$	35.5
Total Long-Term Regulatory Assets		$	2,158.4	$	1,444.9	$	351.1	$	221.8	$	2,103.8	$	1,680.6	$	393.9	$	233.2

• NSTAR Electric amounts are not included in NU consolidated as of December 31, 2011.

Regulatory Costs Not Yet Approved:Additionally, the Regulated companies had $69.9million ($3.9million for CL&P, $25.4 million for NSTAR Electric, $35.7million for PSNH, and $1.4 million for WMECO) and $32.4 million ($5 million for CL&P, $22.4 million for PSNH, and $1.6 million for WMECO) of regulatory costs as of December 31, 2012 and 2011, respectively, which were included in Other Long-Term Assets on the accompanying consolidated balance sheets. For comparative purposes, NSTAR Electric had $9.5 million of such regulatory costs as of December 31, 2011. These amounts represent incurred costs that have not yet been approved for recovery by the applicable regulatory agency. Management believes it is probable that recovery of these costs will ultimately be approved.

For PSNH, of the total December 31, 2012 regulatory costs not yet approved, $12.1 million related to costs incurred for the 2012 Hurricane Sandy storm and $22.3 million related to costs incurred for the2011 Tropical Storm Irene and the October snowstorm restorations that met the NHPUC criteria for cost deferral. As of December 31, 2011, the storm restoration costs incurred for the 2011 Tropical Storm Irene and the October snowstorm restorations totaled $21.7 million. Refer to the "Storm Restoration Costs" section below for further discussion. The NSTAR Electric balance as of December 31, 2012 and 2011 related to costs deferred in connection with the basic service bad debt adder. See Note 12H, "Commitments and Contingencies – Basic Service Bad Debt Adder," for further information.

Equity Return on Regulatory Assets:For rate-making purposes, the Regulated companies recover the carrying cost, including an allowed equity return, on certain regulatory assets. Thisequity return, which is not recorded on the accompanying consolidated balance sheets, totaled $2.5 million and $3.5 million for CL&P and $21.8 million and $7.6 million for PSNH as of December 31, 2012 and 2011, respectively. These carrying costs will be recovered in future rates.

Regulatory Assets - The following provides further information about regulatory assets:

Benefit Costs: NU's Pension, SERPand PBOP Plans are accounted for in accordance with accounting guidance on defined benefit pension and other postretirement plans. Under this accounting guidance, the funded status of pension and other postretirementplans is recorded with an offset to Accumulated Other Comprehensive Income/(Loss) and is remeasured annually. However, because the Regulated companies recover these costs from customers through rates, regulatory assets are recorded as an offset for the liability that is recognized for the funded status of the pension and postretirement plans. Regulatory accounting was also applied to the portions of the NUSCO and NSTAR Electric & Gas costs that support the Regulated companies, as these amounts are also recoverable. CL&P and PSNH do not collect carrying charges on these deferred benefit costs regulatory assets. WMECO's deferred benefit costs regulatory assets are earning a return at the same rate as the assets included in rate base.NSTAR Electric does not earn a return on the regulatory assets recorded to offset the funded status.

NSTAR Electric and WMECO each recover their qualified pension and postretirement expenses through rate reconciling mechanisms that fully track the change in net pension and postretirement expenses each year. CL&P and PSNH will recover benefit costs through rates as allowed by their applicable regulatory commissions.NSTAR Electric earns a carrying charge on the excess cumulative benefit plan trust fund contributions it has made over what it has cumulatively recognized as net periodic benefit expense, net of deferred income taxes. As of December 31, 2012 and 2011, these balances were $366.8 million and $428 million of the benefit costs regulatory asset, respectively.

Regulatory Assets Offsetting Derivative Liabilities: The regulatory assets offsetting derivative liabilities relate to the fair value of contracts used to purchase power and other related contracts that will be collected from customers in the future. See Note 5, "Derivative Instruments," to the consolidated financial statements for further information.  These assets are excluded from rate base and are being recovered as the actual settlement occurs over the duration of the contracts.

Goodwill:Goodwill that originated from the merger that created NSTAR in 1999 is recoverable in rates over the remaining 27 year amortization period, without a carrying charge.

Storm Restoration Costs: The storm restoration cost deferrals relate to costs incurred at CL&P, NSTAR Electric, PSNH and WMECO for restorations that the Company expects to collect from customers. A storm must meet certain criteria to be declared a major storm with the criteria specific to each state jurisdiction and utility company. Once a storm is declared major, all qualifying expenses incurred during storm restoration efforts, if deemed prudent, are deferred and recovered from customers in future periods. In Connecticut, qualifying storm restoration costs must exceed $5 million for a storm to be declared a major storm. In Massachusetts, qualifying storm restoration costs must exceed $1 million for NSTAR Electric and $300,000 for WMECO and an emergency response plan must be initiated for a storm to be declared a major storm. In New Hampshire, (1) at least 10 percent of customers must be without power with at least 200 concurrent locations requiring repairs (trouble spots), or (2) at least 300 concurrent trouble spots must be reported for a storm to be declared a major storm.

In 2011, Tropical Storm Irene and the October snowstorm each caused extensive damage to NU's distribution system. As of December 31, 2012 and 2011, CL&P had recorded total deferred storm restoration costs relating to Tropical Storm Irene and the October 2011 snowstorm as a regulatory asset of $281.6 million and $263.3 million, respectively. The CL&P storm restoration cost regulatory asset balance includes a reserve of $40 million recorded in connection with the Connecticut settlement agreement. See Note 2, "Merger of NU and NSTAR," for further information. As of December 31, 2012 and 2011, NSTAR Electric had recorded total deferred storm restoration costs for these 2011 storms of $35.8 million and $35.8 million, respectively, and WMECO had recorded $26.5 million and $26.7 million, respectively, as regulatory assets. PSNH recorded $22.3 million and $21.7 million for these 2011 storms in Other Long-Term Assets, as of December 31, 2012 and 2011,respectively, as previously described.

On August 1, 2012, PURA issued a final decision in the investigation of CL&P's performance related to both Tropical Storm Irene and the October 2011 snowstorm. The decision concluded that CL&P was deficient and inadequate in its preparation, response, and communication to both storms, and identified certain penalties that could be imposed on CL&P during its next rate case, including a reduction in allowed regulatory ROE and the disallowance of certain deferred storm restoration costs. However, PURA will consider and weigh the extent to which CL&P has taken steps in its restructuring of storm management and the establishment of new practices for execution in future storm response in determining any potential penalties. CL&P believes such steps to improve current storm preparation and response practices have been successfully executed in recent storms. At this time, management cannot estimate the impact on CL&P's financial position, results of operations or cash flows. CL&P continues to believe that its response to these 2011 storms was prudent, was consistent with industry standards, and that it is probable that it will be able to recover its deferred costs.

See Note 12E, "Commitments and Contingencies – DPU Penalties for 2011 Storm Responses," for a discussion of NSTAR Electric and WMECO's 2011 storm response.

On October 29, 2012, Hurricane Sandy caused extensive damage to NU's electric distribution system across all three states. The cost of restoration that was deferred for future recovery from customers and recorded as a regulatory asset as of December 31, 2012 for CL&P, NSTAR Electric, and WMECO totaled $159.9million, $27.8 million and $4.2 million, respectively. PSNH recorded $12.1 million in Other-Long Term Assets, as previously described. Management believes its response to the storm damage was prudent and therefore believes it is probable that CL&P, NSTAR Electric, PSNH and WMECO will be allowed to recover these deferred storm restoration costs. Accordingly,the storm did not have a material impact to the results of operations of CL&P, NSTAR Electric, PSNH or WMECO.Each operating company will seek recovery of these deferred storm restoration costs through its applicable regulatory recovery process.

The PSNH storm restoration costs deferral as of December 31, 2012 and 2011 related to costs incurred for a major storm in December 2008 and the February 2010 wind storm, both of which were approved for recovery and are included in rate base.

Income Taxes, Net: The tax effect of temporary book-tax differences (differences between the periods in which transactions affect income in the financial statements and the periods in which they affect the determination of taxable income, including those differences relating to uncertain tax positions) is accounted for in accordance with the rate-making treatment of the applicable regulatory commissions and accounting guidance for income taxes. Differences in income taxes between the accounting guidance and the rate-making treatment of the applicable regulatory commissions are recorded as regulatory assets. As these assets are offset by deferred income tax liabilities, no carrying charge is collected. For further information regarding income taxes, see Note 11, "Income Taxes," to the consolidated financial statements.

Securitized Assets:In March 2005, NSTAR Electric issued $674.5 million RRBs and used the majority of the proceeds from that issuance to effect purchase power contract buyouts. The collateralized amounts reflected as securitized regulatory assets for NSTAR Electric as of December 31, 2012 and 2011 were $14.1 million and $98.4 million, respectively.In April 2001, PSNH issued $525 million RRBs and used the majority of the proceeds from that issuance to buydown its power contracts with an affiliate, North Atlantic Energy Corporation. In May 2001, WMECO issued $155 million RRBs and used the majority of the proceeds from that issuance to buyout an IPP contract. These assets are not earning an equity return and are being recovered over the amortization period of their associated RRBs. NSTAR Electric RRBs are scheduled to fully amortize by March 15, 2013, PSNH RRBs are scheduled to fully amortize by May 1, 2013, and WMECO RRBs are scheduled to fully amortize by June 1, 2013.

NSTAR Electric's remaining balanceprimarily includes other costs related to purchase power contract divestitures and certain costs related to NSTAR Electric's former generation business that are recovered with a return through the transition charge and amounted to $186.1 million and $259.8 million as of December 31, 2012 and 2011, respectively. These cost recoveries primarily occur through September 2016 for NSTAR Electric and are subject to adjustment by the DPU.

Contractual Obligations: Under the terms of contracts with CYAPC, YAEC and MYAPC, CL&P, NSTAR Electric, PSNH and WMECO are responsible for their proportionate share of the remaining costs of the nuclear facilities, including decommissioning. A portion of these amounts was recorded as contractual obligations regulatory assets. These obligations for CL&P are earning a return and are being recovered through the CTA. Amounts for NSTAR Electric are being recovered without a return through the transition charge and are anticipated to be recovered by 2015. Amounts for WMECO are being recovered without a return and are anticipated to be recovered by 2013, the scheduled completion date of stranded cost recovery. Amounts for PSNH were fully recovered by 2006. As aresult of the April 10, 2012 merger with NSTAR and consolidation of CYAPC and YAEC, NU's regulatory asset balance also includes the regulatory assets of CYAPC and YAEC, which amounted to $214 million as of December 31, 2012. At the NU consolidated level, intercompany transactions between CL&P, NSTAR Electric, PSNH and WMECO and the CYAPC and YAEC companies are eliminated in consolidation.

Power Contracts Buy Out Agreements:NSTAR Electric's balance represents the recorded contract termination liability related to certain purchase power contract buy out agreements that NSTAR Electric executed in 2004 and their future recovery through NSTAR Electric's transition charge. NSTAR Electric does not earn a return on this regulatory asset. The contracts' termination payments will occur over time and will be collected from customers through NSTAR Electric's transition charge over the same time period. The cost recovery period of these terminated contracts is through September 2016.PSNH's balance represents payments associated with the termination of various power purchase contracts that were recorded as regulatory assets and are amortized over the remaining life of the contracts.

Regulatory Tracker Deferrals: Regulatory tracker deferrals are approved rate mechanisms that allow utilities to recover costs in specific business segments through reconcilable tracking mechanisms that are reviewed at least annually by the applicable regulatory commission. The reconciliation process produces deferrals for future recovery or refund, which can be either under or over-collections to be included in future customer rates each year. Regulatory tracker deferrals are recorded as regulatory assets if costs are in excess of collections from customers and are recorded as regulatory liabilities if collections from customers are in excess of costs. All material regulatory tracker deferrals that are in a regulatory asset positionare earning a return. The following regulatory reconciliation mechanisms were recorded as either regulatory assets or liabilities as of December 31, 2012 and 2011:

CL&P: The PURA has established several reconciliation mechanisms, which allow CL&P to recover costs associated with the procurement of energy for SS and LRS, congestion and other costs associated with power market rules approved by the FERC or as approved by the PURA, C&LM programs, the retail transmission of energy, certain regulatory and energy public policy costs, such as hardship protection costs and transition period property taxes, and stranded costs, such as the amortization of regulatory assets and IPP over market costs. As part of the CTA mechanism reconciliation process, CL&P had also established an obligation to refund the variable incentive portion of its transition service procurement fee, which totaled $26.3 million as of December 31, 2011 and was recorded as a regulatory liability. During 2012, PURA issued a decision approving a joint settlement agreement submitted October 2, 2012, by CL&P, UI, and the Connecticut Consumer Counsel, in resolution of all issues associated with the procurement incentive for 2004, 2005 and 2006. Under the joint settlement agreement, CL&P refunded to customers $5.7 million of funds collected and associated interest. CL&P will be allowed to retain approximately $11.5 million of procurement incentive along with the remaining accrued interest that it was not required to refund to customers.

NSTAR Electric and WMECO: Each company recovers certain of its costs on a fully reconciling basis through DPU-approved cost recovery mechanisms. These rate mechanisms recover costs associated with the procurement of energy for basic service, the retail transmission of energy, costs associated with electric industry restructuring, pension and postretirement benefits, and energy efficiency programs. Costs associated with industry restructuring include RRB debt service, nuclear decommissioning costs and above-market IPP costs. In addition, WMECO recovers costs associated with its investments in renewable energy, such as solar projects and credits given to customers who generate renewable energy.

In the January 31, 2011 rate case, WMECO received approval for a revenue decoupling reconciliation mechanism, which provides assurance that WMECO will recover a DPU pre-established level of baseline distribution delivery service revenue to manage all other distribution operating expenses and earn a level of return on its capital investment.

PSNH: The NHPUC permits PSNH to recover the costs of providing generation, restructuring costs as a result of deregulation, the retail transmission of energy, and the cost of C&LM programs through various reconciliation mechanisms.

Asset Retirement Obligations: The costs associated with the depreciation of the Regulated companies' ARO assets and accretion of the ARO liabilities are recorded as regulatory assets in accordance with regulatory accounting guidance. For CL&P, NSTAR Electric and WMECO, ARO assets, regulatory assets and liabilities offset and are excluded from rate base. PSNH's ARO assets, regulatory assets and liabilities are included in rate base. These costs are being recovered over the life of the underlying property, plant and equipment.

Other Regulatory Assets: Other Regulatory Assets primarily include environmental remediation costs, losses associated with the reacquisition or redemption of long-term debt, and costs related to previously recognized lost tax benefits as a result of a provision in the 2010 Healthcare Act that eliminated the tax deductibility of actuarially equivalent Medicare Part D benefits for retirees, partially offset by purchase price adjustments recorded in connection with the merger with NSTAR reflected in regulatory assets.

Regulatory Liabilities: The components of regulatory liabilities are as follows:

NU	As of December 31,
(Millions of Dollars)	2012		2011
Cost of Removal	$	440.8	$	172.2
Regulatory Tracker Deferrals		95.1		139.1
AFUDC Transmission Incentive		70.0		67.0
Spent Nuclear Fuel Costs and Contractual Obligations		15.4		15.4
Other Regulatory Liabilities		53.0		40.2
Total Regulatory Liabilities	$	674.3	$	433.9
Less: Current Portion	$	134.1	$	167.8
Total Long-Term Regulatory Liabilities	$	540.2	$	266.1

		As of December 31,
		2012										2011
				NSTAR									NSTAR
(Millions of Dollars)		CL&P		Electric		PSNH		WMECO		CL&P			Electric (1)		PSNH		WMECO
Cost of Removal		$	44.2	$	240.3	$	51.2	$	-	$	63.8		$	235.8	$	53.2	$	7.2
Regulatory Tracker Deferrals			39.1		14.4		20.4		13.7		94.4			11.7		17.3		21.3
AFUDC Transmission Incentive			56.6		4.1		-		9.3		57.7			4.3		-		9.3
Spent Nuclear Fuel Costs and
	Contractual Obligations		15.4		-		-		-		15.4			-		-		-
Wholesale Transmission Overcollections			-		-		-		5.3		4.5			-		2.6		9.5
Other Regulatory Liabilities			1.1		32.9		3.8		2.4		11.8			29.7		5.8		2.4
Total Regulatory Liabilities		$	156.4	$	291.7	$	75.4	$	30.7	$	247.6		$	281.5	$	78.9	$	49.7
Less: Current Portion		$	32.1	$	47.5	$	23.0	$	21.0	$	108.3		$	41.6	$	24.5	$	33.1
Total Long-Term Regulatory Liabilities		$	124.3	$	244.2	$	52.4	$	9.7	$	139.3		$	239.9	$	54.4	$	16.6

(1)NSTAR Electric amounts are not included in NU consolidated as of December 31, 2011.

Cost of Removal: NU's Regulated companies currently recover amounts in rates for future costs of removal of plant assets over the lives of the assets. The estimated cost to remove utility assets from service is recognized as a component of depreciation expense and the cumulative amounts collected from customers but not yet expended is recognized as a regulatory liability. Expended costs that exceed amounts collected from customers are recognized as regulatory assets, as they are probable of recovery in future rates.

AFUDC Transmission Incentive:AFUDC was recorded on 100 percent of CL&P and WMECO's CWIP for their NEEWS projects through May 31, 2011, all of which was reserved as a regulatory liability to reflect rate base recovery for 100 percent of the CWIP as a result of FERC-approved transmission incentives. Effective June 1, 2011, FERC approved changes to the ISO-NE Tariff in order to include 100 percent of the NEEWS CWIP in regional rate base. As a result, CL&P and WMECO no longer record AFUDC on NEEWS CWIP. NSTAR Electric recorded AFUDC on reliability-related projects over $5 million through December 31, 2012, 50 percent of which was reserved as a regulatory liability to reflect rate base recovery for 50 percent of the CWIP as a result of FERC-approved transmission incentives.

Spent Nuclear Fuel Costs and Contractual Obligations: CL&P and WMECO currently recover amounts in rates for costs of disposal of spent nuclear fuel and high-level radioactive waste for the period prior to the sale of their ownership shares in the Millstone nuclear power stations. Collections in excess of these costs are recorded as regulatory liabilities. CL&P has also established a regulatory liability for the overrecovery of its proportionate share of the remaining costs, including decommissioning, of the MYAPC nuclear facility.

Wholesale Transmission Overcollections:CL&P, NSTAR Electric, PSNH and WMECO's transmission rates recover total transmission revenue requirements, recovering all regional and local revenue requirements for providing transmission service. These rates provide for annual reconciliations to actual costs and the difference between billed and actual costs is deferred. Regulatory liabilitiesare recorded for collections in excess of costs. Regulatory assets are recorded for costs in excess of collections, as they are probable of recovery in future rates.

Other Regulatory Liabilities: Other Regulatory Liabilities primarily includes amounts that are subject to various rate reconciling mechanisms that, as of each period end date, would result in refunds to customers.

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COMMON SHARES (Tables)

12 Months Ended

Dec. 31, 2012

Notes To Consolidated Financial Statements [Abstract]

Schedule of Stock by Class [Text Block]

17.       COMMON SHARES

The following table sets forth the NU common shares and the shares of CL&P, NSTAR Electric, PSNH and WMECO common stock authorized and issued as of December 31, 2012 and 2011and the respective par values:

	Shares
	Authorized					Issued
	Per Share		As of December 31,			As of December 31,
	Par Value		2012	2011		2012		2011
NU	$	5	380,000,000		380,000,000		332,509,383		196,052,770
CL&P	$	10	24,500,000		24,500,000		6,035,205		6,035,205
NSTAR Electric	$	1	100,000,000		100,000,000		100		100
PSNH	$	1	100,000,000		100,000,000		301		301
WMECO	$	25	1,072,471		1,072,471		434,653		434,653

As a result of the merger with NSTAR on April 10, 2012, NU issued approximately 136 million common shares to the NSTAR shareholders.

As of December 31, 2012 and 2011,18,455,749and 18,894,078 NU common shares were held as treasury shares, respectively.

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MERGER OF NU AND NSTAR (Tables)

12 Months Ended

Dec. 31, 2012

Notes To Consolidated Financial Statements [Abstract]

Schedule of Business Acquisitions by Acquisition Equity Interest Issued or Issuable [Table Text Block]

NSTAR common shares outstanding as of April 9, 2012 (in thousands)*			103,696
Exchange ratio			1.312
NU common shares issued for NSTAR common shares outstanding (in thousands)			136,049
Closing price of NU common shares on April 9, 2012		$	36.79
Value of common shares issued (in millions)		$	5,005
Fair value of NU replacement stock-based compensation awards related to
	pre-merger service (in millions)		33
Total purchase price (in millions)		$	5,038

Schedule of Purchase Price Allocation

(Billions of Dollars)
Current Assets	$	0.7
Property Plant and Equipment, Net		5.1
Goodwill		3.2
Other Long-Term Assets, excluding Goodwill		2.1
Current Liabilities		(1.3)
Long-Term Liabilities		(2.7)
Long-Term Debt and Other Long-Term Obligations		(2.1)
Total Purchase Price	$	5.0

Business Acquisition, Pro Forma Information

	For the Years Ended December 31,
(Pro forma amounts in millions, except per share amounts)	2012		2011
Operating Revenues	$	7,004	$	7,361
Net Income Attributable to Controlling Interest		630		689
Basic EPS		2.00		2.20
Diluted EPS		1.99		2.19

Business Acquisition, Integration, Restructuring and Other Related Costs [Text Block]

		For the Years Ended December 31,
(Millions of Dollars)		2012		2011
Transaction and Other Costs		$	32	$	19
Settlement Agreement Impacts			60		-
Total After-Tax Non-Recurring Costs Excluded from
	Pro Forma Net Income Attributable to Controlling Interest	$	92	$	19

(Millions of Dollars)	NU		CL&P		NSTAR Electric		WMECO
Customer Rate Credits	$	46	$	25	$	15	$	3
Storm Costs Deferral Reduction		40		40		-		-
Establishment of Energy Efficiency Fund		15		-		-		-
Total Pre-Tax Settlement Agreement Impacts	$	101	$	65	$	15	$	3

Schedule Of Goodwill Text Block

		Electric		Electric		Natural Gas
		Distribution		Transmission		Distribution		Total
Balance as of December 31, 2011		$	0.0	$	0.0	$	0.3	$	0.3
	Merger with NSTAR		2.5		0.6		0.1		3.2
Balance as of December 31, 2012		$	2.5	$	0.6	$	0.4	$	3.5

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COMMON SHARESHOLDERS' EQUITY AND NONCONTROLLING INTERESTS (NU)

12 Months Ended

Dec. 31, 2012

Notes To Consolidated Financial Statements [Abstract]

Stockholders' Equity Note Disclosure [Text Block]

19.	COMMON SHAREHOLDERS' EQUITY AND NONCONTROLLING INTERESTS (NU)
A summary of the changes in Common Shareholders' Equity and Noncontrolling Interests of NU is as follows:
								Noncontrolling
		Common						Interest -
		Shareholders'		Noncontrolling		Total		Preferred Stock
(Millions of Dollars)		Equity		Interest		Equity		of Subsidiaries
Balance as of January 1, 2010		$	3,577.9	$	-	$	3,577.9	$	116.2
Net Income			394.1		-		394.1		-
Dividends on Common Shares			(181.7)		-		(181.7)		-
Dividends on Preferred Stock			(6.1)		-		(6.1)		(6.1)
Issuance of Common Shares			7.4		-		7.4		-
Contributions to NPT			-		1.4		1.4		-
Other Transactions, Net			19.6		-		19.6		-
Net Income Attributable to Noncontrolling Interests			(0.1)		0.1		-		6.1
Other Comprehensive Income (Note 15)			0.1		-		0.1		-
Balance as of December 31, 2010		$	3,811.2	$	1.5	$	3,812.7	$	116.2
Net Income			400.5		-		400.5		-
Dividends on Common Shares			(195.6)		-		(195.6)		-
Dividends on Preferred Stock			(5.6)		-		(5.6)		(5.6)
Issuance of Common Shares			5.9		-		5.9		-
Contributions to NPT			-		1.2		1.2		-
Other Transactions, Net			23.9		-		23.9		-
Net Income Attributable to Noncontrolling Interests			(0.3)		0.3		-		5.6
Other Comprehensive Loss (Note 15)			(27.3)		-		(27.3)		-
Balance as of December 31, 2011		$	4,012.7	$	3.0	$	4,015.7	$	116.2
Net Income			533.1		-		533.1		-
Purchase Price of NSTAR (1)			5,038.3		-		5,038.3		-
Other Equity Impacts of Merger with NSTAR (2)			3.4		(3.4)		-		39.4
Dividends on Common Shares			(375.5)		-		(375.5)		-
Dividends on Preferred Stock			(7.0)		-		(7.0)		(7.0)
Issuance of Common Shares			13.3		-		13.3		-
Contributions to NPT			-		0.3		0.3		-
Other Transactions, Net			21.1		-		21.1		-
Net Income Attributable to Noncontrolling Interests			(0.1)		0.1		-		7.0
Other Comprehensive Loss (Note 15)			(2.2)		-		(2.2)		-
Balance as of December 31, 2012		$	9,237.1	$	0.0	$	9,237.1	$	155.6

• On April 10, 2012, in connection with the consummation of the merger with NSTAR, NU issued approximately 136 million common shares to the NSTAR shareholders.See Note 2, "Merger of NU and NSTAR," for further information.
• The preferred stock of NSTAR Electric is not subject to mandatory redemption and has been presented as a noncontrolling interest in NSTAR Electric in the accompanying consolidated financial statements of NU. In addition, upon completion of the merger, an NSTAR subsidiary that held 25 percent of NPT was merged into NUTV, resulting in NUTV owning 100 percent of NPT. Accordingly, the noncontrolling interest balance was eliminated and 100 percent ownership of NPT is reflected in Common Shareholders' Equity as of December 31, 2012.

For the years ended December 31, 2012, 2011 and 2010, there was no change in ownership of the common equity of CL&P and NSTAR Electric.

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PREFFERED STOCK NOT SUBJECT TO MANDATORY REDEMPTION

12 Months Ended

Dec. 31, 2012

Notes To Consolidated Financial Statements [Abstract]

Preferred Stock Text Block

18.       PREFERRED STOCK NOT SUBJECT TO MANDATORY REDEMPTION (CL&P, NSTAR Electric)

The preferred stock of CL&P and NSTAR Electric is not subject to mandatory redemption and is presented as a noncontrolling interest of a subsidiary in the accompanying consolidated financial statements of NU.

CL&P Preferred Stock:CL&P's charter authorizes it to issue up to 9 million shares of preferred stock ($50 par value per share). CL&P amended its charter on January 3, 2012 to remove references to various series of preferred stock, including the Class A preferred stock, which are no longer outstanding. The issuance of additional preferred shares would be subject to approval by the PURA. Preferred stockholders have liquidation rights equal to the par value of the preferred stock, which they would receive in preference to any distributions to any junior stock. Were there to be a shortfall, all preferred stockholders would share ratably in available liquidation assets.

NSTAR Electric Preferred Stock:NSTAR Electric is authorized to issue 2,890,000 shares ($100 par value per share).NSTAR Electric has two outstanding series of cumulative preferred stock. Upon liquidation, holders of cumulative preferred stock are entitled to receive a liquidation preference before any distribution to holders of common stock. The liquidation preference for each outstanding series of cumulative preferred stock is equal to the par value, plus accrued and unpaid dividends. Were there to be a shortfall, holders of cumulative preferred stock would share ratably in available liquidation assets.

Details of preferred stock not subject to mandatory redemption are as follows (in millions except in redemption price and shares):

				Redemption Price		Shares Outstanding as of	As of December 31,
Series				Per Share		December 31, 2012 and 2011	2012		2011
CL&P
$	1.90		Series of 1947	$	52.50	163,912	$	8.2	$	8.2
$	2.00		Series of 1947	$	54.00	336,088		16.8		16.8
$	2.04		Series of 1949	$	52.00	100,000		5.0		5.0
$	2.20		Series of 1949	$	52.50	200,000		10.0		10.0
	3.90	%	Series of 1949	$	50.50	160,000		8.0		8.0
$	2.06		Series E of 1954	$	51.00	200,000		10.0		10.0
$	2.09		Series F of 1955	$	51.00	100,000		5.0		5.0
	4.50	%	Series of 1956	$	50.75	104,000		5.2		5.2
	4.96	%	Series of 1958	$	50.50	100,000		5.0		5.0
	4.50	%	Series of 1963	$	50.50	160,000		8.0		8.0
	5.28	%	Series of 1967	$	51.43	200,000		10.0		10.0
$	3.24		Series G of 1968	$	51.84	300,000		15.0		15.0
	6.56	%	Series of 1968	$	51.44	200,000		10.0		10.0
Total CL&P						2,324,000	$	116.2	$	116.2
NSTAR Electric(1)
	4.25	%	Series	$	103.625	180,000	$	18.0	$	18.0
	4.78	%	Series	$	102.80	250,000		25.0		25.0
Total NSTAR Electric						430,000	$	43.0	$	43.0
Fair Value Adjustment due to Merger with NSTAR								(3.6)		N/A
Total NU Consolidated Preferred Stock of Subsidiaries								155.6		116.2

• NSTAR Electric amounts are not included in NU consolidated as of December 31, 2011.

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DIVIDEND RESTRICTIONS (Details)	12 Months Ended
	Dec. 31, 2012
Line of Credit Facility, Dividend Restrictions	CL&P, NSTAR Electric, PSNH and WMECO are subject to Section 305 of the Federal Power Act that makes it unlawful for a public utility to make or pay a dividend from any funds "properly included in its capital account." Management believes that this Federal Power Act restriction, as applied to CL&P, NSTAR Electric, PSNH and WMECO, would not be construed or applied by the FERC to prohibit the payment of dividends for lawful and legitimate business purposes from retained earnings. In addition, certain state statutes may impose additional limitations on such companies and on Yankee Gas and NSTAR Gas. Such state law restrictions do not restrict payment of dividends from retained earnings or net income. CL&P, NSTAR Electric, PSNH, WMECO, Yankee Gas and NSTAR Gas also have revolving credit agreements that impose leverage restrictions including consolidated total debt to total capitalization ratio requirements. The Retained Earnings balances subject to these leverage restrictions are $1.803 billion for NU, $839.6 million for CL&P, $1.210 billion for NSTAR Electric, $395.1 million for PSNH and $160.6 million for WMECO as of December 31, 2012.
Public Service Company Of New Hampshire [Member]
Statutory Dividend Payment Restrictions Disclosure	PSNH is further required to reserve an additional amount under its FERC hydroelectric license conditions. As of December 31, 2012, approximately $12.3 million of PSNH's Retained Earnings is subject to restriction under its FERC hydroelectric license conditions.

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Environmental Matters (Tablels)

12 Months Ended

Dec. 31, 2012

Notes To Consolidated Financial Statements [Abstract]

Schedule Of Environmental Loss Contingencies By Site Text Block

(Millions of Dollars)	NU		CL&P		NSTAR Electric(1)		PSNH		WMECO
Balance as of December 31, 2010	$	37.1	$	2.8	$	0.9	$	9.1	$	0.3
Additions		1.6		0.4		0.4		0.1		0.1
Payments		(7.0)		(0.3)		-		(2.6)		(0.1)
Balance as of December 31, 2011		31.7		2.9		1.3		6.6		0.3
Liabilities Assumed with NSTAR Merger		11.8		-		-		-		-
Additions		4.7		1.3		0.7		0.2		0.5
Payments/Reductions		(8.8)		(0.5)		(0.3)		(1.9)		(0.2)
Balance as of December 31, 2012	$	39.4	$	3.7	$	1.7	$	4.9	$	0.6

	As of December 31, 2012				As of December 31, 2011
			Reserve				Reserve
	Number of Sites		(in millions)		Number of Sites		(in millions)
NU		77	$	39.4		59	$	31.7
CL&P		19		3.7		18		2.9
NSTAR Electric (1)		16		1.7		13		1.3
PSNH		16		4.9		18		6.6
WMECO		6		0.6		10		0.3

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REGULATORY ACCOUNTING (Tables)

12 Months Ended

Dec. 31, 2012

Notes To Consolidated Financial Statements [Abstract]

Schedule Of Regulatory Assets Text Block

NU	As of December 31,
(Millions of Dollars)	2012		2011
Benefit Costs	$	2,452.1	$	1,360.5
Regulatory Assets Offsetting Derivative Liabilities		885.6		939.6
Goodwill		537.6		-
Storm Restoration Costs		547.7		356.0
Income Taxes, Net		516.2		425.4
Securitized Assets		232.6		101.8
Contractual Obligations		217.6		100.9
Power Contracts Buy Out Agreements		92.9		8.6
Regulatory Tracker Deferrals		190.1		45.9
Asset Retirement Obligations		88.8		47.5
Other Regulatory Assets		76.2		136.6
Total Regulatory Assets	$	5,837.4	$	3,522.8
Less: Current Portion	$	705.0	$	255.1
Total Long-Term Regulatory Assets	$	5,132.4	$	3,267.7

		As of December 31,
		2012								2011
				NSTAR								NSTAR
(Millions of Dollars)		CL&P		Electric		PSNH		WMECO		CL&P		Electric(1)		PSNH		WMECO
Benefit Costs		$	563.2	$	781.2	$	223.7	$	116.0	$	572.8	$	813.7	$	200.0	$	118.9
Regulatory Assets Offsetting
	Derivative Liabilities		866.2		14.9		-		3.0		932.0		3.4		-		7.3
Goodwill			-		461.5		-		-		-		478.9		-		-
Storm Restoration Costs			413.9		55.8		34.5		43.5		268.3		30.6		44.0		43.7
Income Taxes, Net			367.5		47.1		36.2		31.0		339.6		48.8		38.0		17.8
Securitized Assets			-		205.1		19.7		7.8		-		368.5		76.4		25.4
Contractual Obligations			64.0		22.8		-		14.9		80.9		30.8		-		20.0
Power Contracts Buy Out Agreements			-		85.9		7.0		-		-		109.5		8.6		-
Regulatory Tracker Deferrals			12.2		71.4		49.3		31.9		5.5		61.1		11.9		22.1
Asset Retirement Obligations			29.4		29.4		14.2		3.5		27.9		24.5		13.5		3.2
Other Regulatory Assets			27.9		16.9		29.4		12.6		47.0		34.7		35.7		10.3
Total Regulatory Assets		$	2,344.3	$	1,792.0	$	414.0	$	264.2	$	2,274.0	$	2,004.5	$	428.1	$	268.7
Less: Current Portion		$	185.9	$	347.1	$	62.9	$	42.4	$	170.2	$	323.9	$	34.2	$	35.5
Total Long-Term Regulatory Assets		$	2,158.4	$	1,444.9	$	351.1	$	221.8	$	2,103.8	$	1,680.6	$	393.9	$	233.2

Schedule Of Regulatory Liabilities Text Block

NU	As of December 31,
(Millions of Dollars)	2012		2011
Cost of Removal	$	440.8	$	172.2
Regulatory Tracker Deferrals		95.1		139.1
AFUDC Transmission Incentive		70.0		67.0
Spent Nuclear Fuel Costs and Contractual Obligations		15.4		15.4
Other Regulatory Liabilities		53.0		40.2
Total Regulatory Liabilities	$	674.3	$	433.9
Less: Current Portion	$	134.1	$	167.8
Total Long-Term Regulatory Liabilities	$	540.2	$	266.1

		As of December 31,
		2012										2011
				NSTAR									NSTAR
(Millions of Dollars)		CL&P		Electric		PSNH		WMECO		CL&P			Electric (1)		PSNH		WMECO
Cost of Removal		$	44.2	$	240.3	$	51.2	$	-	$	63.8		$	235.8	$	53.2	$	7.2
Regulatory Tracker Deferrals			39.1		14.4		20.4		13.7		94.4			11.7		17.3		21.3
AFUDC Transmission Incentive			56.6		4.1		-		9.3		57.7			4.3		-		9.3
Spent Nuclear Fuel Costs and
	Contractual Obligations		15.4		-		-		-		15.4			-		-		-
Wholesale Transmission Overcollections			-		-		-		5.3		4.5			-		2.6		9.5
Other Regulatory Liabilities			1.1		32.9		3.8		2.4		11.8			29.7		5.8		2.4
Total Regulatory Liabilities		$	156.4	$	291.7	$	75.4	$	30.7	$	247.6		$	281.5	$	78.9	$	49.7
Less: Current Portion		$	32.1	$	47.5	$	23.0	$	21.0	$	108.3		$	41.6	$	24.5	$	33.1
Total Long-Term Regulatory Liabilities		$	124.3	$	244.2	$	52.4	$	9.7	$	139.3		$	239.9	$	54.4	$	16.6

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EARNINGS PER SHARE

12 Months Ended

Dec. 31, 2012

Notes To Consolidated Financial Statements [Abstract]

Earnings Per Share [Text Block]

20.       EARNINGS PER SHARE (NU)

Basic EPS is computed based upon the weighted average number of common shares outstanding during each period. Diluted EPS is computed on the basis of the weighted average number of common shares outstanding plus the potential dilutive effect if certain securities are converted into common shares. For the years ended December 31, 2012, 2011 and 2010, there were 4,266, 4,314 and 1,578share awards, respectively, excluded from the computation as these awards were antidilutive.

The following table sets forth the components of basic and diluted EPS:

		For the Years Ended December 31,
(Millions of Dollars, except share information)		2012		2011		2010
Net Income Attributable to Controlling Interest		$	525.9	$	394.7	$	387.9
Weighted Average Common Shares Outstanding:
	Basic		277,209,819		177,410,167		176,636,086
	Dilutive Effect		783,812		394,401		249,301
	Diluted		277,993,631		177,804,568		176,885,387
Basic EPS		$	1.90	$	2.22	$	2.20
Diluted EPS		$	1.89	$	2.22	$	2.19

On April 10, 2012, NU issued approximately 136 million common shares as a result of the merger with NSTAR, which are reflected in weighted average common shares outstanding as of December 31, 2012.

RSUs and performance shares are included in basic weighted average common shares outstanding as of the date that all necessary vesting conditions have been satisfied. The dilutive effect of unvested RSUs and performance shares is calculated using the treasury stock method. Assumed proceeds of these units under the treasury stock method consist of the remaining compensation cost to be recognized and a theoretical tax benefit. The theoretical tax benefit is calculated as the tax impact of the intrinsic value of the units (the difference between the market value of the average units outstanding for the period, using the average market price during the period, and the grant date market value).

The dilutive effect of stock options to purchase common shares is also calculated using the treasury stock method. Assumed proceeds for stock options consist of cash proceeds that would be received upon exercise, and a theoretical tax benefit. The theoretical tax benefit is calculated as the tax impact of the intrinsic value of the stock options (the difference between the market value of the average stock options outstanding for the period, using the average market price during the period, and the exercise price).

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SEGMENT INFORMATION

12 Months Ended

Dec. 31, 2012

Notes To Consolidated Financial Statements [Abstract]

Segment Reporting Disclosure [Text Block]

21.SEGMENT INFORMATION (NU)

Presentation: NU is organized between the Electric Distribution, Electric Transmission and Natural Gas Distribution segments and Other based on a combination of factors, including the characteristics of each segments' products and services, the sources of operating revenues and expenses and the regulatory environment in which each segment operates. These segments represented substantially all of NU's total consolidated revenues for the years endedDecember 31, 2012, 2011 and 2010. Revenues from the sale of electricity and natural gas primarily are derived from residential, commercial and industrial customers and are not dependent on any single customer. The Electric Distribution segment includes the generation activities of PSNH and WMECO.

Other operations in the tables below primarily consists of 1) the equity in earnings of NU parent from its subsidiaries and intercompany interest income, both of which are eliminated in consolidation, and interest income and expense related to the cash and debt of NU parent and NSTAR LLC, respectively, 2) the revenues and expenses of NU's service companies, most of which are eliminated in consolidation, 3) the operations of CYAPC and YAEC, and 4) the results of other subsidiaries, which are comprised of NU Enterprises, NSTAR Communications, Inc., RRR (a real estate subsidiary), the non-energy-related subsidiaries of Yankee and the remaining operations of HWP.

Cash flows used for investments in plant included in the segment information below are cash capital expenditures that do not include amounts incurred but not paid, cost of removal, AFUDC related to equity funds, and the capitalized portions of pension and PBOP expense or income.

As discussed in Note 1B, “Summary of Significant Accounting Policies – Basis of Presentation,” certain reclassifications of prioryear data were made in the accompanying consolidated statements of income for NU. Accordingly, the corresponding items of segment information have been recast for all prior years for comparative purposes.

Effective in the third quarter of 2012, NU's reportable segments are the combined Electric Distribution, Electric Transmission and Natural Gas Distribution segments, based upon the level at which NU's chief operating decision maker assesses performance and makes decisions about the allocation of company resources. Each of NU's subsidiaries, including CL&P, NSTAR Electric, PSNH and WMECO, has one reportable segment. Therefore, separate Transmission and Distribution information is not disclosed for CL&P, NSTAR Electric, PSNH or WMECO. NU's operating segments and reporting units are consistent with its reportable business segments.

NSTAR amounts are included in NU consolidated from the date of the merger, April 10, 2012, through December 31, 2012.

NU's segment information for the years endedDecember 31, 2012, 2011 and 2010 is as follows:

		For the Year Ended December 31, 2012
		Electric		Natural Gas
(Millions of Dollars)		Distribution		Distribution		Transmission		Other		Eliminations		Total
Operating Revenues		$	4,716.5	$	572.9	$	861.5	$	803.8	$	(680.9)	$	6,273.8
Depreciation and Amortization			(530.3)		(49.1)		(109.2)		(56.4)		4.2		(740.8)
Other Operating Expenses			(3,585.4)		(445.2)		(251.6)		(817.0)		684.4		(4,414.8)
Operating Income/(Loss)			600.8		78.6		500.7		(69.6)		7.7		1,118.2
Interest Expense			(165.6)		(31.3)		(96.7)		(43.6)		7.3		(329.9)
Interest Income			2.8		-		0.4		7.1		(7.1)		3.2
Other Income, Net			8.9		0.4		7.3		795.0		(795.1)		16.5
Income Tax (Expense)/Benefit			(150.2)		(16.9)		(159.2)		55.5		(4.1)		(274.9)
Net Income			296.7		30.8		252.5		744.4		(791.3)		533.1
Net Income Attributable
	to Noncontrolling Interests		(4.4)		-		(2.8)		-		-		(7.2)
Net Income Attributable
	to Controlling Interest	$	292.3	$	30.8	$	249.7	$	744.4	$	(791.3)	$	525.9
Total Assets (as of)		$	18,047.3	$	2,717.4	$	6,187.7	$	18,832.6	$	(17,482.2)	$	28,302.8
Cash Flows Used for
	Investments in Plant	$	611.7	$	148.7	$	663.6	$	48.3	$	-	$	1,472.3

		For the Year Ended December 31, 2011
		Electric		Natural Gas
(Millions of Dollars)		Distribution		Distribution		Transmission		Other		Eliminations		Total
Operating Revenues		$	3,343.1	$	430.8	$	635.4	$	541.3	$	(484.9)	$	4,465.7
Depreciation and Amortization			(337.2)		(27.7)		(84.0)		(16.8)		2.5		(463.2)
Other Operating Expenses			(2,637.4)		(333.5)		(188.2)		(534.1)		484.9		(3,208.3)
Operating Income/(Loss)			368.5		69.6		363.2		(9.6)		2.5		794.2
Interest Expense			(123.8)		(21.0)		(76.7)		(33.7)		4.8		(250.4)
Interest Income			3.7		-		0.5		5.3		(5.3)		4.2
Other Income, Net			11.6		1.3		10.7		455.2		(455.3)		23.5
Income Tax (Expense)/Benefit			(67.6)		(18.2)		(95.6)		14.3		(3.9)		(171.0)
Net Income			192.4		31.7		202.1		431.5		(457.2)		400.5
Net Income Attributable
	to Noncontrolling Interests		(3.3)		-		(2.5)		-		-		(5.8)
Net Income Attributable
	to Controlling Interest	$	189.1	$	31.7	$	199.6	$	431.5	$	(457.2)	$	394.7
Total Assets (as of)		$	9,653.1	$	1,511.3	$	3,792.9	$	6,618.0	$	(5,928.2)	$	15,647.1
Cash Flows Used for
	Investments in Plant	$	540.7	$	98.2	$	388.9	$	48.9	$	-	$	1,076.7

		For the Year Ended December 31, 2010
		Electric		Natural Gas
(Millions of Dollars)		Distribution		Distribution		Transmission		Other		Eliminations		Total
Operating Revenues		$	3,802.0	$	434.3	$	625.6	$	521.6	$	(485.3)	$	4,898.2
Depreciation and Amortization			(501.2)		(23.8)		(86.7)		(15.8)		3.8		(623.7)
Other Operating Expenses			(2,925.1)		(340.0)		(192.1)		(505.4)		488.0		(3,474.6)
Operating Income			375.7		70.5		346.8		0.4		6.5		799.9
Interest Expense			(133.4)		(17.9)		(73.2)		(17.4)		4.6		(237.3)
Interest Income			0.7		-		1.8		5.3		(6.3)		1.5
Other Income, Net			24.4		0.8		14.3		436.4		(435.5)		40.4
Income Tax (Expense)/Benefit			(90.3)		(20.7)		(109.3)		11.0		(1.1)		(210.4)
Net Income			177.1		32.7		180.4		435.7		(431.8)		394.1
Net Income Attributable
	to Noncontrolling Interests		(3.6)		-		(2.6)		-		-		(6.2)
Net Income Attributable
	to Controlling Interest	$	173.5	$	32.7	$	177.8	$	435.7	$	(431.8)	$	387.9
Cash Flows Used for
	Investments in Plant	$	560.1	$	82.5	$	239.2	$	72.7	$	-	$	954.5

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MERGER OF NU AND NSTAR

12 Months Ended

Dec. 31, 2012

Notes To Consolidated Financial Statements [Abstract]

Business Combination Disclosure

2.       MERGER OF NU AND NSTAR

On April 10, 2012, NU acquired 100 percent of the outstanding common shares of NSTAR. Pursuant to the terms and conditions of the Agreement and Plan of Merger, as amended, the "Merger Agreement," NSTAR merged into NSTAR LLC, becoming a wholly-owned subsidiary of NU.

NSTAR LLC is a holding company engaged through its subsidiaries in the energy delivery business serving electric and natural gas distribution customers in Massachusetts. The merger was structured as a merger of equals in a tax-free exchange of shares. As part of the merger, NSTAR shareholders received 1.312 NU common shares for each NSTAR common share owned (the "exchange ratio") as of the acquisition date. The exchange ratio was structured to result in a no-premium merger based on the average closing share price of each company's common shares for the 20 trading days preceding the announcement of the merger in October 2010. NU issued approximately 136 million common shares to the NSTAR shareholders as a result of the merger, which brought the total common shares outstanding to approximately 314 million shares as of April 10, 2012.

Purchase Price: Pursuant to the merger, all of the NSTAR common shares were exchanged at the fixed exchange ratio of 1.312 NU common shares for each NSTAR common share. The total consideration transferred in the merger was based on the closing price of NU common shares on April 9, 2012, the day prior to the date the merger was completed, and was calculated as follows:

NSTAR common shares outstanding as of April 9, 2012 (in thousands)*			103,696
Exchange ratio			1.312
NU common shares issued for NSTAR common shares outstanding (in thousands)			136,049
Closing price of NU common shares on April 9, 2012		$	36.79
Value of common shares issued (in millions)		$	5,005
Fair value of NU replacement stock-based compensation awards related to
	pre-merger service (in millions)		33
Total purchase price (in millions)		$	5,038

*       Includes 109 thousand shares related to NSTAR stock-based compensation awards that vested immediately prior to the merger.

Certain of NSTAR's stock-based compensation awards, including deferred shares, performance shares and all outstanding stock options, were replaced with NU awards using the exchange ratio upon consummation of the merger. In accordance with accounting guidance for business combinations, the portion of the fair value of these awards attributable to service provided prior to the merger is included in the purchase price as it represents consideration transferred in the merger. See Note 10D, "Employee Benefits – Share-Based Payments," for further information.

Purchase Price Allocation: The allocation of the total purchase price to the estimated fair values of the assets acquired and liabilities assumed has been determined based on the accounting guidance for fair value measurements, which defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The allocation of the total purchase price includes adjustments to record the fair value of NSTAR's unregulated telecommunications business, regulatory assets not earning a return, lease agreements, long-term debt and the preferred stock of NSTAR Electric. The fair values of NSTAR's assets and liabilities were determined based on significant estimates and assumptions, including Level 3 inputs, that are judgmental in nature. These estimates and assumptions include the timing and amounts of projected future cash flows and discount rates reflecting risk inherent in future cash flows.

The excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed was recognized as goodwill. Thecompleted allocation of the purchase price is as follows:

(Billions of Dollars)
Current Assets	$	0.7
Property Plant and Equipment, Net		5.1
Goodwill		3.2
Other Long-Term Assets, excluding Goodwill		2.1
Current Liabilities		(1.3)
Long-Term Liabilities		(2.7)
Long-Term Debt and Other Long-Term Obligations		(2.1)
Total Purchase Price	$	5.0

The goodwill from the merger with NSTAR of $3.2 billion has been assigned to NU's reporting units based on relative fair values. NU's reporting units consist of Electric Distribution, Electric Transmission and Natural Gas Distribution. See the "Goodwill" section below for the allocation of goodwill to each reporting unit.

Pro Forma Financial Information: The following unaudited pro forma financial information reflects the pro forma combined results of operations of NU and NSTAR and reflects the amortization of purchase price adjustments assuming the merger had taken place on January 1, 2011. The unaudited pro forma financial information has been presented for illustrative purposes only and is not necessarily indicative of the consolidated results of operations that would have been achieved or the future consolidated results of operations of NU.

	For the Years Ended December 31,
(Pro forma amounts in millions, except per share amounts)	2012		2011
Operating Revenues	$	7,004	$	7,361
Net Income Attributable to Controlling Interest		630		689
Basic EPS		2.00		2.20
Diluted EPS		1.99		2.19

Pro forma net income does not include potential cost savings associated with the merger. Pro forma net income also excludes certainnon-recurring merger costs and costs related to the Connecticut and Massachusetts settlement agreements described below, with the following aggregate after-tax impacts:

		For the Years Ended December 31,
(Millions of Dollars)		2012		2011
Transaction and Other Costs		$	32	$	19
Settlement Agreement Impacts			60		-
Total After-Tax Non-Recurring Costs Excluded from
	Pro Forma Net Income Attributable to Controlling Interest	$	92	$	19

Regulatory Approvals: On February 15, 2012, NU and NSTAR reached comprehensive settlement agreements with the Massachusetts Attorney General and the DOER related to the merger. The Attorney General settlement agreement covered a variety of rate-making and rate design issues, including a base distribution rate freeze through 2015 for NSTAR Electric, NSTAR Gas and WMECO and $15 million, $3 million and $3 million in the form of rate credits to their respective customers. The settlement agreement reached with the DOER covered the same rate-making and rate design issues as the Attorney General's settlement agreement, as well as a variety of matters impacting the advancement of Massachusetts clean energy policy established by the Green Communities Act and Global Warming Solutions Act. On April 4, 2012, the DPU approved the settlement agreements and the merger of NU and NSTAR.

On March 13, 2012, NU and NSTAR reached a comprehensive settlement agreement with both the Connecticut Attorney General and the Connecticut Office of Consumer Counsel related to the merger. The settlement agreement covered a variety of matters, including a $25 million rate credit to CL&P customers, a CL&P base distribution rate freeze until December 1, 2014, and the establishment of a $15 million fund for energy efficiency and other initiatives to be disbursed at the direction of the DEEP. In the agreement, CL&P agreed to forego rate recovery of $40 million of the deferred storm restoration costs associated with restoration activities following Tropical Storm Irene and the October 2011 snowstorm. On April 2, 2012, the PURA approved the settlement agreement and the merger of NU and NSTAR.

The pre-tax financial impacts of the Connecticut and Massachusetts settlement agreements that were recognized by NU, CL&P, NSTAR Electric, and WMECO are summarized as follows:

(Millions of Dollars)	NU		CL&P		NSTAR Electric		WMECO
Customer Rate Credits	$	46	$	25	$	15	$	3
Storm Costs Deferral Reduction		40		40		-		-
Establishment of Energy Efficiency Fund		15		-		-		-
Total Pre-Tax Settlement Agreement Impacts	$	101	$	65	$	15	$	3

NSTAR Revenues and Net Income: The impact of NSTAR on NU's accompanying consolidated statement of income includes operating revenues of $1,957.8million and net income attributable to controlling interest of $182.9million for the year ended December31, 2012.

Goodwill:In a business combination, the excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed is recognized as goodwill. Goodwill is evaluated for impairment at least annually and more frequently if indicators of impairment arise. In accordance with the accounting standards, if the fair value of a reporting unit is less than its carrying value (including goodwill), the goodwill is tested for impairment. A loss is recognized if the implied fair value of a reporting unit's goodwill is less than the carrying value of its goodwill. NU uses October 1st as the annual goodwill impairment testing date.

On April 10, 2012, upon consummation of the merger with NSTAR, NU recorded approximately $3.2 billion of goodwill. With the completion of the NSTAR merger, NU reviewed its management structure and determinedthat the reporting units for the purpose of testing goodwill for impairment are Electric Distribution, Electric Transmission and Natural Gas Distribution. NU's reporting units are consistent with the operating segments underlying the reportable segments identified in Note 21, "Segment Information," to the consolidated financial statements. Accordingly, the goodwill resulting from the NSTAR merger has been allocated to the Electric Distribution, Electric Transmission and Natural Gas Distribution reporting unitsbased on the estimatedfair values of the reporting units as of the merger date.

As of December 31, 2011, the only reporting unit that maintained goodwill was the natural gas reportable segment, related to the acquisition of the parent of Yankee Gas in 2000. This goodwill is recorded at Yankee Gas. The goodwill balance at Yankee Gas as of December 31, 2012 and 2011was $0.3billion.

NU completed its impairment analysis of the NSTAR and Yankee Gas goodwill balances as of October 1, 2012 and determined that no impairment exists. In completing this analysis, the fair value of the reporting units was estimated using a discounted cash flow methodology and a market method utilizing comparable company information and market transactions.

The allocation of goodwill to NU's reporting units is as follows:

		Electric		Electric		Natural Gas
		Distribution		Transmission		Distribution		Total
Balance as of December 31, 2011		$	0.0	$	0.0	$	0.3	$	0.3
	Merger with NSTAR		2.5		0.6		0.1		3.2
Balance as of December 31, 2012		$	2.5	$	0.6	$	0.4	$	3.5

XML

VARIABLE INTEREST ENTITIES

12 Months Ended

Dec. 31, 2012

Notes To Consolidated Financial Statements [Abstract]

Schedule Of Variable Interest Entities Text Block

22.VARIABLE INTEREST ENTITIES

The Company's variable interests outside of the consolidated group are not material and consist of contracts that are required by regulation and provide for regulatory recovery of contract costs and benefits through customer rates. NU, CL&P and NSTAR Electric hold variable interests in variable interest entities (VIEs) through agreements with certain entities that own single renewable energy or peaking generation power plants and with other independent power producers. NU, CL&P and NSTAR Electric do not control the activities that are economically significant to these VIEs or provide financial or other support to these VIEs. Therefore, NU, CL&P and NSTAR Electric do not consolidate any power plant VIEs.

XML

Fair Value Measurements (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
Fair Value Assets Measured On Recurring Basis Unobservable Input Reconciliation [Line Items]
Beginning Balance	$ (962.2)	$ (840.2)
DerivativeLiabilityRecordedAtMergerDateLevel3	(5.4)
us-gaap_FairValueMeasurementWithUnobservableInputsReconciliationLiabilityTransfersOutOfLevel3	32.2
Net Realized/Unrealized Gains Losses included in Net Income	10.9	0.5
Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Asset Liability Gain Loss Included In Reg Asset Liability	(29.2)	(161.0)
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Liability, Settlements	75.1	38.5
Ending Balance	(878.6)	(962.2)
The Connecticut Light And Power Company [Member]
Fair Value Assets Measured On Recurring Basis Unobservable Input Reconciliation [Line Items]
Beginning Balance	(931.6)	(806.1)
Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Asset Liability Gain Loss Included In Reg Asset Liability	(21.6)	(153.6)
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Liability, Settlements	87.0	28.1
Ending Balance	(866.2)	(931.6)
Western Massachusetts Electric Company [Member]
Fair Value Assets Measured On Recurring Basis Unobservable Input Reconciliation [Line Items]
Beginning Balance	(7.3)	0
Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Asset Liability Gain Loss Included In Reg Asset Liability	4.3	(7.3)
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Liability, Settlements	0
Ending Balance	(3.0)	(7.3)
NSTAR Electric Company [Member]
Fair Value Assets Measured On Recurring Basis Unobservable Input Reconciliation [Line Items]
Beginning Balance	(3.4)	(2.4)
Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Asset Liability Gain Loss Included In Reg Asset Liability	(15.2)	(4.3)
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Liability, Settlements	3.7	3.3
Ending Balance	$ (14.9)	$ (3.4)

XML

Allowance for Funds Used During Construction (Tables)

12 Months Ended

Dec. 31, 2012

Notes To Consolidated Financial Statements [Abstract]

Schedule Of Allowance For Funds Used During Construction [Table Text Block]

NU		For the Years Ended December 31,
(Millions of Dollars, except percentages)		2012		2011		2010
AFUDC:
	Borrowed Funds	$	5.3	$	11.8	$	10.2
	Equity Funds		6.8		22.5		16.7
Total		$	12.1	$	34.3	$	26.9
Average AFUDC Rate			3.7%		7.3%		7.1%

		For the Years Ended December 31,
		2012								2011								2010
(Millions of Dollars,				NSTAR								NSTAR								NSTAR
except percentages)		CL&P		Electric(1)		PSNH		WMECO		CL&P		Electric(1)		PSNH		WMECO		CL&P		Electric(1)		PSNH		WMECO
AFUDC:
	Borrowed Funds	$	2.5	$	0.3	$	1.6	$	0.5	$	3.3	$	0.2	$	7.1	$	0.5	$	2.7	$	0.1	$	6.6	$	0.3
	Equity Funds		1.9		-		1.9		1.0		6.0		-		13.2		1.0		4.9		-		10.4		0.6
Total		$	4.4	$	0.3	$	3.5	$	1.5	$	9.3	$	0.2	$	20.3	$	1.5	$	7.6	$	0.1	$	17.0	$	0.9
Average AFUDC Rate			3.6%		0.4%		5.9%		6.8%		8.3%		0.3%		7.1%		7.4%		8.3%		0.3%		6.8%		6.4%

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Share-Based Payments (Tables)

12 Months Ended

Dec. 31, 2012

Notes To Consolidated Financial Statements [Abstract]

Disclosure of Share-based Compensation Arrangements by Share-based Payment Award [Table Text Block]

			Weighted Average
	RSUs		Grant-Date
	(Units)		Fair Value
Outstanding as of January 1, 2010		1,037,912	$	24.07
Granted		258,174	$	26.03
Shares issued		(267,951)	$	25.05
Forfeited		(13,656)	$	24.26
Outstanding as of December 31, 2010		1,014,479	$	24.31
Granted		208,533	$	33.87
Shares issued		(244,782)	$	24.47
Forfeited		(18,310)	$	23.74
Outstanding as of December 31, 2011		959,920	$	26.36
Granted		614,930	$	33.04
Converted NSTAR Awards upon Merger		617,394	$	36.79
Converted from NU Performance Shares upon Merger		451,358	$	34.32
Shares issued		(363,779)	$	29.05
Forfeited		(96,504)	$	34.97
Outstanding as of December 31, 2012		2,183,319	$	31.99

	Performance		Weighted Average
	Shares		Grant-Date
	(Units)		Fair Value
Outstanding as of January 1, 2010		99,086	$	23.93
Granted		149,520	$	25.24
Shares issued		-	$	-
Forfeited		(47)	$	23.96
Outstanding as of December 31, 2010		248,559	$	24.72
Granted		244,870	$	33.76
Shares issued		-	$	-
Forfeited		(10,296)	$	30.47
Outstanding as of December 31, 2011		483,133	$	29.18
Granted		225,935	$	35.09
Converted to RSUs upon Merger		(451,358)	$	34.32
Shares issued		(106,773)	$	24.52
Forfeited		-	$	-
Outstanding as of December 31, 2012		150,937	$	25.04

NU	For the Years Ended December 31,
(Millions of Dollars)	2012		2011		2010
Compensation Cost	$	25.8	$	12.3	$	10.5
Future Income Tax Benefit		10.2		4.9		4.2

		For the Years Ended December 31,
		2012								2011								2010
(Millions of Dollars)		CL&P		NSTAR Electric(1)		PSNH		WMECO		CL&P		NSTAR Electric(1)		PSNH		WMECO		CL&P		NSTAR Electric(1)		PSNH		WMECO
Compensation Cost		$	4.8	$	7.4	$	1.8	$	1.0	$	7.1	$	7.7	$	2.5	$	1.4	$	6.2	$	6.5	$	2.1	$	1.1
Future Income Tax
	Benefit		1.9		2.9		0.7		0.4		2.8		3.0		1.0		0.6		2.5		2.6		0.9		0.4

		Weighted Average		Intrinsic Value
	Options	Exercise Price		(Millions)
Outstanding and Exercisable - January 1, 2010	225,216	$	18.96
Exercised	(112,617)	$	19.12	$	1.0
Forfeited and Cancelled	-	$	-
Outstanding and Exercisable - December 31, 2010	112,599	$	18.80
Exercised	(65,225)	$	18.81	$	1.0
Forfeited and Cancelled	-	$	-
Outstanding and Exercisable - December 31, 2011	47,374	$	18.78
Converted NSTAR Options upon Merger	2,664,894	$	23.99
Exercised	(1,166,511)	$	22.53	$	18.7
Forfeited and Cancelled	-	$	-
Outstanding and Exercisable - December 31, 2012	1,545,757	$	24.92	$	21.9

XML

Equity Method Investments (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
The Connecticut Light And Power Company [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investments	$ 1,400	$ 1,400
NSTAR Electric Company [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investments	600	600
Western Massachusetts Electric Company [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investments	400	400
Public Service Company Of New Hampshire [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investments	300	300
CYAPC [Member] | The Connecticut Light And Power Company [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage	34.50%
CYAPC [Member] | NSTAR Electric Company [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage	14.00%
CYAPC [Member] | Western Massachusetts Electric Company [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage	9.50%
CYAPC [Member] | Public Service Company Of New Hampshire [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage	5.00%
YAEC [Member] | The Connecticut Light And Power Company [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage	24.50%
YAEC [Member] | NSTAR Electric Company [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage	14.00%
YAEC [Member] | Western Massachusetts Electric Company [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage	7.00%
YAEC [Member] | Public Service Company Of New Hampshire [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage	7.00%
MYAPC [Member] | The Connecticut Light And Power Company [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage	12.00%
MYAPC [Member] | NSTAR Electric Company [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage	4.00%
MYAPC [Member] | Western Massachusetts Electric Company [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage	3.00%
MYAPC [Member] | Public Service Company Of New Hampshire [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage	5.00%
Regional Transmission Company [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investments	6,000	4,600
Equity Method Investment, Ownership Percentage	37.20%	22.70%
Regional Transmission Company [Member] | NSTAR Electric Company [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investments	2,300	3,000
Equity Method Investment, Ownership Percentage	14.50%
Energy Investment Fund [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investments	$ 6,800	$ 4,200

XML

CONSOLIDATED BALANCE SHEETS (USD $) In Thousands, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Current Assets:
Cash	$ 45,748	$ 6,559
Receivables, Net	792,822	488,002
Unbilled Revenues	216,040	175,207
Fuel, Materials and Supplies	267,713	248,958
Regulatory Assets Current	705,025	255,144
Marketable Securities - Current	91,975	70,970
Prepayments and Other Current Assets	107,972	112,632
Total Current Assets	2,227,295	1,357,472
Property, Plant and Equipment, Net	16,605,010	10,403,065
Deferred Debits and Other Assets:
Regulatory Assets Long Term	5,132,411	3,267,710
Goodwill	3,519,401	287,591
Marketable Securities	400,329	60,311
Derivative Assets Noncurrent	90,612	98,357
Other Long-Term Assets	327,766	172,560
Total Deferred Debits and Other Assets	9,470,519	3,886,529
Total Assets	28,302,824	15,647,066
Current Liabilities:
Notes Payable to Banks	1,120,196	317,000
Long-Term Debt - Current Portion	763,338	331,582
Accounts Payable - Current	764,350	633,282
Regulatory Liability Current	134,115	167,844
Derivative Liabilities - Current	117,194	107,558
Other Liabilities - Current	744,497	390,416
Total Current Liabilities	3,643,690	1,947,682
Rate Reduction Bonds	82,139	112,260
Deferred Credits and Other Liabilities:
Accumulated Deferred Income Taxes	3,463,347	1,868,316
Regulatory Liabilities Long-Term	540,162	266,145
Long-Term Derivative Liabilities	882,654	959,876
Accrued Pension, PBOP and SERP	2,130,497	1,326,037
Other Long-Term Liabilities	967,561	420,011
Total Deferred Credits and Other Liabilities	7,984,221	4,840,385
Capitalization:
Long-Term Debt	7,200,156	4,614,913
Noncontrolling Interest in Consolidated Subsidiary:
Temporary Equity, Carrying Amount, Attributable to Noncontrolling Interest	155,568	116,200
Common Shareholders' Equity:
Common Stock	1,662,547	980,264
Capital Surplus, Paid In	6,183,267	1,797,884
Retained Earnings	1,802,714	1,651,875
Accumulated Other Comprehensive Loss	(72,854)	(70,686)
Treasury Stock	(338,624)	(346,667)
Noncontrolling Interest	0	2,956
Common Shareholders' Equity	9,237,050	4,012,670
Total Equity	9,237,050	4,015,626
Total Capitalization	16,592,774	8,746,739
Total Liabilities and Capitalization	28,302,824	15,647,066
The Connecticut Light And Power Company [Member]
Current Assets:
Cash	1	1
Receivables, Net	284,787	295,028
Accounts Receivable from Affiliated Companies	6,641	1,548
Unbilled Revenues	85,353	94,995
Regulatory Assets Current	185,858	170,197
Materials and Supplies	64,603	61,102
Prepayments and Other Current Assets	26,413	53,920
Total Current Assets	653,656	676,791
Property, Plant and Equipment, Net	6,152,959	5,827,384
Deferred Debits and Other Assets:
Regulatory Assets Long Term	2,158,363	2,103,830
Derivative Assets Noncurrent	90,612	93,755
Other Long-Term Assets	86,498	89,636
Total Deferred Debits and Other Assets	2,335,473	2,287,221
Total Assets	9,142,088	8,791,396
Current Liabilities:
Notes Payable to Banks	0	31,000
Notes Payable To Affiliated Companies	99,296	58,525
Long-Term Debt - Current Portion	125,000	62,000
Accounts Payable - Current	262,857	340,321
Accounts Payable to Affiliated Companies	52,326	53,439
Obligations to Third Party Suppliers	67,344	67,967
Accrued Taxes	60,109	59,046
Regulatory Liability Current	32,119	108,291
Derivative Liabilities - Current	96,931	95,881
Other Liabilities - Current	125,662	102,065
Total Current Liabilities	921,644	978,535
Deferred Credits and Other Liabilities:
Accumulated Deferred Income Taxes	1,336,105	1,215,989
Regulatory Liabilities Long-Term	124,319	139,307
Long-Term Derivative Liabilities	865,571	935,849
Accrued Pension, PBOP and SERP	304,696	260,571
Other Long-Term Liabilities	197,434	215,640
Total Deferred Credits and Other Liabilities	2,828,125	2,767,356
Capitalization:
Long-Term Debt	2,737,790	2,521,753
Noncontrolling Interest in Consolidated Subsidiary:
Temporary Equity, Carrying Amount, Attributable to Noncontrolling Interest	116,200	116,200
Common Shareholders' Equity:
Common Stock	60,352	60,352
Capital Surplus, Paid In	1,640,149	1,613,503
Retained Earnings	839,628	735,948
Accumulated Other Comprehensive Loss	(1,800)	(2,251)
Common Shareholders' Equity	2,538,329	2,407,552
Total Capitalization	5,392,319	5,045,505
Total Liabilities and Capitalization	9,142,088	8,791,396
Public Service Company Of New Hampshire [Member]
Current Assets:
Cash	2,493	56
Receivables, Net	87,164	87,545
Accounts Receivable from Affiliated Companies	723	1,294
Notes Receivable from Affiliated Companies	0	55,900
Unbilled Revenues	39,982	45,403
Taxes Receivable	17,177	7,424
Fuel, Materials and Supplies	95,345	124,744
Regulatory Assets Current	62,882	34,178
Prepayments and Other Current Assets	22,205	27,837
Total Current Assets	327,971	384,381
Property, Plant and Equipment, Net	2,352,515	2,256,688
Deferred Debits and Other Assets:
Regulatory Assets Long Term	351,059	393,941
Other Long-Term Assets	83,052	81,531
Total Deferred Debits and Other Assets	434,111	475,472
Total Assets	3,114,597	3,116,541
Current Liabilities:
Notes Payable To Affiliated Companies	63,300	0
Accounts Payable - Current	62,864	106,377
Accounts Payable to Affiliated Companies	21,337	18,895
Accrued Interest	9,317	9,670
Regulatory Liability Current	23,002	24,500
Other Liabilities - Current	41,633	24,408
Renewable Portfolio Standards Compliance Obligation	17,383	12,089
Total Current Liabilities	238,836	195,939
Rate Reduction Bonds	29,294	85,368
Deferred Credits and Other Liabilities:
Accumulated Deferred Income Taxes	441,577	392,712
Regulatory Liabilities Long-Term	52,418	54,415
Accrued Pension, PBOP and SERP	220,129	258,718
Other Long-Term Liabilities	47,896	53,304
Total Deferred Credits and Other Liabilities	762,020	759,149
Capitalization:
Long-Term Debt	997,932	997,722
Common Shareholders' Equity:
Common Stock	0	0
Capital Surplus, Paid In	701,052	700,285
Retained Earnings	395,118	388,910
Accumulated Other Comprehensive Loss	(9,655)	(10,832)
Common Shareholders' Equity	1,086,515	1,078,363
Total Capitalization	2,084,447	2,076,085
Total Liabilities and Capitalization	3,114,597	3,116,541
Western Massachusetts Electric Company [Member]
Current Assets:
Cash	1	1
Receivables, Net	47,297	42,757
Accounts Receivable from Affiliated Companies	164	633
Notes Receivable from Affiliated Companies	0	11,000
Unbilled Revenues	16,192	16,277
Taxes Receivable	15,513	2,263
Regulatory Assets Current	42,370	35,520
Marketable Securities - Current	27,352	26,335
Prepayments and Other Current Assets	7,963	6,456
Total Current Assets	156,852	141,242
Property, Plant and Equipment, Net	1,290,498	1,077,833
Deferred Debits and Other Assets:
Regulatory Assets Long Term	221,752	233,247
Marketable Securities	30,342	30,794
Other Long-Term Assets	23,625	19,777
Total Deferred Debits and Other Assets	275,719	283,818
Total Assets	1,723,069	1,502,893
Current Liabilities:
Notes Payable To Affiliated Companies	31,900	0
Long-Term Debt - Current Portion	55,000	0
Accounts Payable - Current	68,141	111,566
Accounts Payable to Affiliated Companies	7,103	10,626
Accrued Interest	8,304	7,714
Regulatory Liability Current	21,037	33,056
Other Liabilities - Current	24,909	13,041
Total Current Liabilities	216,394	176,003
Rate Reduction Bonds	9,352	26,892
Deferred Credits and Other Liabilities:
Accumulated Deferred Income Taxes	303,111	244,511
Regulatory Liabilities Long-Term	9,686	16,597
Accrued Pension, PBOP and SERP	36,099	29,546
Other Long-Term Liabilities	40,148	47,498
Total Deferred Credits and Other Liabilities	389,044	338,152
Capitalization:
Long-Term Debt	550,270	499,545
Common Shareholders' Equity:
Common Stock	10,866	10,866
Capital Surplus, Paid In	390,412	340,115
Retained Earnings	160,577	115,506
Accumulated Other Comprehensive Loss	(3,846)	(4,186)
Common Shareholders' Equity	558,009	462,301
Total Capitalization	1,108,279	961,846
Total Liabilities and Capitalization	1,723,069	1,502,893
NSTAR Electric Company [Member]
Current Assets:
Cash	13,695	9,373
Receivables, Net	202,025	232,828
Accounts Receivable from Affiliated Companies	160,176	389,652
Unbilled Revenues	41,377	40,380
Regulatory Assets Current	347,081	323,871
Prepayments and Other Current Assets	28,086	34,479
Total Current Assets	792,440	1,030,583
Property, Plant and Equipment, Net	4,735,297	4,447,258
Deferred Debits and Other Assets:
Regulatory Assets Long Term	1,444,870	1,680,595
Other Long-Term Assets	87,382	81,890
Total Deferred Debits and Other Assets	1,532,252	1,762,485
Total Assets	7,059,989	7,240,326
Current Liabilities:
Notes Payable to Banks	276,000	141,500
Long-Term Debt - Current Portion	1,650	401,650
Accounts Payable - Current	168,611	150,581
Accounts Payable to Affiliated Companies	247,061	514,377
Deferred Tax Liabilities Current	104,668	101,819
Regulatory Liability Current	47,539	41,579
Other Liabilities - Current	144,433	103,634
Total Current Liabilities	989,962	1,455,140
Rate Reduction Bonds	43,493	127,860
Deferred Credits and Other Liabilities:
Accumulated Deferred Income Taxes	1,321,026	1,310,180
Regulatory Liabilities Long-Term	244,224	239,858
Accrued Pension, PBOP and SERP	360,932	357,685
Other Long-Term Liabilities	183,190	195,606
DueToRelatedPartiesNoncurrent	70,221	75,905
Total Deferred Credits and Other Liabilities	2,179,593	2,179,234
Capitalization:
Long-Term Debt	1,600,911	1,203,344
Noncontrolling Interest in Consolidated Subsidiary:
Temporary Equity, Carrying Amount, Attributable to Noncontrolling Interest	43,000	43,000
Common Shareholders' Equity:
Common Stock	0	0
Capital Surplus, Paid In	992,625	992,625
Retained Earnings	1,210,405	1,239,123
Common Shareholders' Equity	2,203,030	2,231,748
Total Capitalization	3,846,941	3,478,092
Total Liabilities and Capitalization	$ 7,059,989	$ 7,240,326

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PROPERTY, PLANT AND ACCUMULATED DEPRECIATION (Tables)

12 Months Ended

Dec. 31, 2012

Notes To Consolidated Financial Statements [Abstract]

Schedule of Public Utility Property, Plant, and Equipment [Text Block]

4.PROPERTY, PLANT AND EQUIPMENT AND ACCUMULATED DEPRECIATION

Utility property, plant and equipment is recorded at original cost. Original cost includes materials, labor, construction overhead and AFUDC for regulated property. The cost of repairs and maintenance, including planned major maintenance activities, is charged to Operating Expenses as incurred.

The following tables summarize the NU, CL&P, NSTAR Electric, PSNH and WMECO investments in utility property, plant and equipment by asset category:

NU		As of December 31,
(Millions of Dollars)		2012		2011
Distribution - Electric		$	11,438.2	$	6,540.4
Distribution - Natural Gas			2,274.2		1,247.6
Transmission			5,541.1		3,541.9
Generation			1,146.6		1,096.0
Electric and Natural Gas Utility			20,400.1		12,425.9
Other (1)			429.3		305.1
Property, Plant and Equipment, Gross			20,829.4		12,731.0
Less: Accumulated Depreciation
	Electric and Natural Gas Utility		(5,065.1)		(3,035.5)
	Other		(171.5)		(120.2)
Total Accumulated Depreciation			(5,236.6)		(3,155.7)
Property, Plant and Equipment, Net			15,592.8		9,575.3
Construction Work in Progress			1,012.2		827.8
Total Property, Plant and Equipment, Net		$	16,605.0	$	10,403.1

(1)These assets represent unregulated property and are primarily comprised of building improvements at RRR and software and equipment at NUSCO as of December 31, 2012 and 2011, and telecommunications equipment at NSTAR Communications, Inc. as of December 31, 2012.

	As of December 31,
	2012								2011
			NSTAR								NSTAR
(Millions of Dollars)	CL&P		Electric		PSNH		WMECO		CL&P		Electric(1)		PSNH		WMECO
Distribution	$	4,691.3	$	4,539.9	$	1,520.1	$	724.2	$	4,419.6	$	4,334.4	$	1,451.6	$	704.3
Transmission		2,796.1		1,529.7		599.2		583.7		2,689.1		1,386.9		546.4		297.4
Generation		-		-		1,125.5		21.1		-		-		1,074.8		21.2
Property, Plant and
Equipment, Gross		7,487.4		6,069.6		3,244.8		1,329.0		7,108.7		5,721.3		3,072.8		1,022.9
Less: Accumulated Depreciation		(1,698.1)		(1,540.1)		(954.0)		(252.1)		(1,596.7)		(1,436.0)		(893.6)		(240.5)
Property, Plant and Equipment, Net		5,789.3		4,529.5		2,290.8		1,076.9		5,512.0		4,285.3		2,179.2		782.4
Construction Work in Progress		363.7		205.8		61.7		213.6		315.4		162.0		77.5		295.4
Total Property, Plant and
Equipment, Net	$	6,153.0	$	4,735.3	$	2,352.5	$	1,290.5	$	5,827.4	$	4,447.3	$	2,256.7	$	1,077.8

(1)NSTAR Electric amounts are not included in NU consolidated as of December 31, 2011.

Depreciation of utility assets is calculated on a straight-line basisusing composite rates based on the estimated remaining useful lives of the various classes of property (estimated useful life forPSNH distribution). The composite rates are subject to approval by the appropriate state regulatory agency. The composite ratesinclude a cost of removal component, which is collected from customers during the life of the property and is recognized as a regulatory liability. Depreciation rates are applied to property from the time it is placed in service.

Upon retirement from service, the cost of the utility asset is charged to the accumulated provision for depreciation. The actual incurred removal costs are applied against the related regulatory liability.

The depreciation rates for the various classes of utility property, plant and equipment aggregate to composite rates as follows:

(Percent)	2012		2011		2010
NU		2.5		2.6		2.7
CL&P		2.5		2.4		2.7
NSTAR Electric		2.8		3.0		3.0
PSNH		3.0		2.9		2.8
WMECO		3.3		2.9		2.8

The following table summarizes average useful lives of depreciable assets:
	Average Depreciable Life
(Years)	NU		CL&P		NSTAR Electric		PSNH		WMECO
Distribution		42.1		41.8		33.9		33.8		30.2
Transmission		45.3		39.8		46.3		42.1		47.5
Generation		32.7		-		-		32.8		25.0
Other		16.7		-		-		-		-

Schedule of Plant Average Depreciable Lives [Table Text Block]

The following table summarizes average useful lives of depreciable assets:
	Average Depreciable Life
(Years)	NU		CL&P		NSTAR Electric		PSNH		WMECO
Distribution		42.1		41.8		33.9		33.8		30.2
Transmission		45.3		39.8		46.3		42.1		47.5
Generation		32.7		-		-		32.8		25.0
Other		16.7		-		-		-		-

Schedule Of Plant Depreciation Rates [Table Text Block]

(Percent)	2012		2011		2010
NU		2.5		2.6		2.7
CL&P		2.5		2.4		2.7
NSTAR Electric		2.8		3.0		3.0
PSNH		3.0		2.9		2.8
WMECO		3.3		2.9		2.8

XML

Guarantees and Indemnifications (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012
Guarantee Of Financial Obligations Of Npt [Member]
Guarantee Obligations [Line Items]
Guarantee Obligations Maximum Exposure	$ 25.0
Various Subsidiary Surety Bonds And Performance Guarantees Expiring Between 2013 And 2015 [Member]
Guarantee Obligations [Line Items]
Guarantee Obligations Maximum Exposure	32.8
Guarantee Of Rocky River Reality And Nusco Lease Payments For Real Estate And Vehicles Expiring 2019 Through 2024 [Member]
Guarantee Obligations [Line Items]
Guarantee Obligations Maximum Exposure	20.1
Guarantee Of Nuei Surety Bonds Insurance Bonds And Performance Guarantees [Member]
Guarantee Obligations [Line Items]
Guarantee Obligations Maximum Exposure	67.4
Guarantee Of Ngs Insurance Bond [Member]
Guarantee Obligations [Line Items]
Guarantee Obligations Maximum Exposure	1.0
Guarantee Of Es Boulos Surety Bonds Expiring Upon Project Completion [Member]
Guarantee Obligations [Line Items]
Guarantee Obligations Maximum Exposure	52.9
Guarantee Of Select Energy Wholesale Purchase Contracts [Member]
Guarantee Obligations [Line Items]
Guarantee Obligations Maximum Exposure	13.5
Guarantee Of Debt Of Ne Hydros [Member]
Guarantee Obligations [Line Items]
Guarantee Obligations Maximum Exposure	$ 5.6

XML

CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDERS EQUITY (USD $) In Thousands, except Share data, unless otherwise specified	12 Months Ended				12 Months Ended				12 Months Ended				12 Months Ended				12 Months Ended				12 Months Ended				12 Months Ended								12 Months Ended				12 Months Ended				12 Months Ended				12 Months Ended								12 Months Ended				12 Months Ended				12 Months Ended				12 Months Ended								12 Months Ended				12 Months Ended				12 Months Ended				12 Months Ended												12 Months Ended				12 Months Ended
	Dec. 31, 2012 Common Stock [Member]	Dec. 31, 2011 Common Stock [Member]	Dec. 31, 2010 Common Stock [Member]	Dec. 31, 2009 Common Stock [Member]	Dec. 31, 2012 Additional Paid-in Capital [Member]	Dec. 31, 2011 Additional Paid-in Capital [Member]	Dec. 31, 2010 Additional Paid-in Capital [Member]	Dec. 31, 2009 Additional Paid-in Capital [Member]	Dec. 31, 2010 Deferred Contribution Plan [Member]	Dec. 31, 2012 Deferred Contribution Plan [Member]	Dec. 31, 2011 Deferred Contribution Plan [Member]	Dec. 31, 2009 Deferred Contribution Plan [Member]	Dec. 31, 2012 Retained Earnings [Member]	Dec. 31, 2011 Retained Earnings [Member]	Dec. 31, 2010 Retained Earnings [Member]	Dec. 31, 2009 Retained Earnings [Member]	Dec. 31, 2012 Accumulated Other Comprehensive Income (Loss) [Member]	Dec. 31, 2011 Accumulated Other Comprehensive Income (Loss) [Member]	Dec. 31, 2010 Accumulated Other Comprehensive Income (Loss) [Member]	Dec. 31, 2009 Accumulated Other Comprehensive Income (Loss) [Member]	Dec. 31, 2012 Treasury Stock [Member]	Dec. 31, 2011 Treasury Stock [Member]	Dec. 31, 2010 Treasury Stock [Member]	Dec. 31, 2009 Treasury Stock [Member]	Dec. 31, 2012 Common Shareholders Equity [Member]	Dec. 31, 2011 Common Shareholders Equity [Member]	Dec. 31, 2010 Common Shareholders Equity [Member]	Dec. 31, 2009 Common Shareholders Equity [Member]	Dec. 31, 2012 The Connecticut Light And Power Company [Member] Common Stock [Member]	Dec. 31, 2011 The Connecticut Light And Power Company [Member] Common Stock [Member]	Dec. 31, 2010 The Connecticut Light And Power Company [Member] Common Stock [Member]	Dec. 31, 2009 The Connecticut Light And Power Company [Member] Common Stock [Member]	Dec. 31, 2012 The Connecticut Light And Power Company [Member] Additional Paid-in Capital [Member]	Dec. 31, 2011 The Connecticut Light And Power Company [Member] Additional Paid-in Capital [Member]	Dec. 31, 2010 The Connecticut Light And Power Company [Member] Additional Paid-in Capital [Member]	Dec. 31, 2009 The Connecticut Light And Power Company [Member] Additional Paid-in Capital [Member]	Dec. 31, 2012 The Connecticut Light And Power Company [Member] Retained Earnings [Member]	Dec. 31, 2011 The Connecticut Light And Power Company [Member] Retained Earnings [Member]	Dec. 31, 2010 The Connecticut Light And Power Company [Member] Retained Earnings [Member]	Dec. 31, 2009 The Connecticut Light And Power Company [Member] Retained Earnings [Member]	Dec. 31, 2012 The Connecticut Light And Power Company [Member] Accumulated Other Comprehensive Income (Loss) [Member]	Dec. 31, 2011 The Connecticut Light And Power Company [Member] Accumulated Other Comprehensive Income (Loss) [Member]	Dec. 31, 2010 The Connecticut Light And Power Company [Member] Accumulated Other Comprehensive Income (Loss) [Member]	Dec. 31, 2009 The Connecticut Light And Power Company [Member] Accumulated Other Comprehensive Income (Loss) [Member]	Dec. 31, 2012 The Connecticut Light And Power Company [Member] Common Shareholders Equity [Member]	Dec. 31, 2011 The Connecticut Light And Power Company [Member] Common Shareholders Equity [Member]	Dec. 31, 2010 The Connecticut Light And Power Company [Member] Common Shareholders Equity [Member]	Dec. 31, 2009 The Connecticut Light And Power Company [Member] Common Shareholders Equity [Member]	Dec. 31, 2012 Public Service Company Of New Hampshire [Member] Common Stock [Member]	Dec. 31, 2011 Public Service Company Of New Hampshire [Member] Common Stock [Member]	Dec. 31, 2010 Public Service Company Of New Hampshire [Member] Common Stock [Member]	Dec. 31, 2009 Public Service Company Of New Hampshire [Member] Common Stock [Member]	Dec. 31, 2012 Public Service Company Of New Hampshire [Member] Additional Paid-in Capital [Member]	Dec. 31, 2011 Public Service Company Of New Hampshire [Member] Additional Paid-in Capital [Member]	Dec. 31, 2010 Public Service Company Of New Hampshire [Member] Additional Paid-in Capital [Member]	Dec. 31, 2009 Public Service Company Of New Hampshire [Member] Additional Paid-in Capital [Member]	Dec. 31, 2012 Public Service Company Of New Hampshire [Member] Retained Earnings [Member]	Dec. 31, 2011 Public Service Company Of New Hampshire [Member] Retained Earnings [Member]	Dec. 31, 2010 Public Service Company Of New Hampshire [Member] Retained Earnings [Member]	Dec. 31, 2009 Public Service Company Of New Hampshire [Member] Retained Earnings [Member]	Dec. 31, 2012 Public Service Company Of New Hampshire [Member] Accumulated Other Comprehensive Income (Loss) [Member]	Dec. 31, 2011 Public Service Company Of New Hampshire [Member] Accumulated Other Comprehensive Income (Loss) [Member]	Dec. 31, 2010 Public Service Company Of New Hampshire [Member] Accumulated Other Comprehensive Income (Loss) [Member]	Dec. 31, 2009 Public Service Company Of New Hampshire [Member] Accumulated Other Comprehensive Income (Loss) [Member]	Dec. 31, 2012 Public Service Company Of New Hampshire [Member] Common Shareholders Equity [Member]	Dec. 31, 2011 Public Service Company Of New Hampshire [Member] Common Shareholders Equity [Member]	Dec. 31, 2010 Public Service Company Of New Hampshire [Member] Common Shareholders Equity [Member]	Dec. 31, 2009 Public Service Company Of New Hampshire [Member] Common Shareholders Equity [Member]	Dec. 31, 2012 Western Massachusetts Electric Company [Member] Common Stock [Member]	Dec. 31, 2011 Western Massachusetts Electric Company [Member] Common Stock [Member]	Dec. 31, 2010 Western Massachusetts Electric Company [Member] Common Stock [Member]	Dec. 31, 2009 Western Massachusetts Electric Company [Member] Common Stock [Member]	Dec. 31, 2012 Western Massachusetts Electric Company [Member] Additional Paid-in Capital [Member]	Dec. 31, 2011 Western Massachusetts Electric Company [Member] Additional Paid-in Capital [Member]	Dec. 31, 2010 Western Massachusetts Electric Company [Member] Additional Paid-in Capital [Member]	Dec. 31, 2009 Western Massachusetts Electric Company [Member] Additional Paid-in Capital [Member]	Dec. 31, 2012 Western Massachusetts Electric Company [Member] Retained Earnings [Member]	Dec. 31, 2011 Western Massachusetts Electric Company [Member] Retained Earnings [Member]	Dec. 31, 2010 Western Massachusetts Electric Company [Member] Retained Earnings [Member]	Dec. 31, 2009 Western Massachusetts Electric Company [Member] Retained Earnings [Member]	Dec. 31, 2012 Western Massachusetts Electric Company [Member] Accumulated Other Comprehensive Income (Loss) [Member]	Dec. 31, 2011 Western Massachusetts Electric Company [Member] Accumulated Other Comprehensive Income (Loss) [Member]	Dec. 31, 2010 Western Massachusetts Electric Company [Member] Accumulated Other Comprehensive Income (Loss) [Member]	Dec. 31, 2009 Western Massachusetts Electric Company [Member] Accumulated Other Comprehensive Income (Loss) [Member]	Dec. 31, 2012 Western Massachusetts Electric Company [Member] Common Shareholders Equity [Member]	Dec. 31, 2011 Western Massachusetts Electric Company [Member] Common Shareholders Equity [Member]	Dec. 31, 2010 Western Massachusetts Electric Company [Member] Common Shareholders Equity [Member]	Dec. 31, 2009 Western Massachusetts Electric Company [Member] Common Shareholders Equity [Member]	Dec. 31, 2012 NSTAR Electric Company [Member] Common Stock [Member]	Dec. 31, 2011 NSTAR Electric Company [Member] Common Stock [Member]	Dec. 31, 2010 NSTAR Electric Company [Member] Common Stock [Member]	Dec. 31, 2009 NSTAR Electric Company [Member] Common Stock [Member]	Dec. 31, 2012 NSTAR Electric Company [Member] Additional Paid-in Capital [Member]	Dec. 31, 2011 NSTAR Electric Company [Member] Additional Paid-in Capital [Member]	Dec. 31, 2010 NSTAR Electric Company [Member] Additional Paid-in Capital [Member]	Dec. 31, 2009 NSTAR Electric Company [Member] Additional Paid-in Capital [Member]	Dec. 31, 2012 NSTAR Electric Company [Member] Retained Earnings [Member]	Dec. 31, 2011 NSTAR Electric Company [Member] Retained Earnings [Member]	Dec. 31, 2010 NSTAR Electric Company [Member] Retained Earnings [Member]	Dec. 31, 2009 NSTAR Electric Company [Member] Retained Earnings [Member]	Dec. 31, 2012 NSTAR Electric Company [Member] Common Shareholders Equity [Member]	Dec. 31, 2011 NSTAR Electric Company [Member] Common Shareholders Equity [Member]	Dec. 31, 2010 NSTAR Electric Company [Member] Common Shareholders Equity [Member]	Dec. 31, 2009 NSTAR Electric Company [Member] Common Shareholders Equity [Member]
Common Stock, Shares, Outstanding	314,053,634	177,158,692	176,448,081	175,620,024																									6,035,205	6,035,205	6,035,205	6,035,205																	301	301	301	301																	434,653	434,653	434,653	434,653																	100	100	100	100
Common Stock, Value, Outstanding	$ 1,662,547	$ 980,264	$ 978,909	$ 977,276	$ 6,183,267	$ 1,797,884	$ 1,777,592	$ 1,762,097	$ 0	$ 0	$ 0	$ (2,944)	$ 1,802,714	$ 1,651,875	$ 1,452,777	$ 1,246,543	$ (72,854)	$ (70,686)	$ (43,370)	$ (43,467)	$ (338,624)	$ (346,667)	$ (354,732)	$ (361,603)	$ 9,237,050	$ 4,012,670	$ 3,811,176	$ 3,577,902	$ 60,352	$ 60,352	$ 60,352	$ 60,352	$ 1,640,149	$ 1,613,503	$ 1,605,275	$ 1,601,792	$ 839,628	$ 735,948	$ 734,561	$ 714,210	$ (1,800)	$ (2,251)	$ (2,713)	$ (3,171)	$ 2,538,329	$ 2,407,552	$ 2,397,475	$ 2,373,183	$ 0	$ 0	$ 0	$ 0	$ 701,052	$ 700,285	$ 579,577	$ 420,169	$ 395,118	$ 388,910	$ 347,471	$ 307,988	$ (9,655)	$ (10,832)	$ (601)	$ (712)	$ 1,086,515	$ 1,078,363	$ 926,447	$ 727,445	$ 10,866	$ 10,866	$ 10,866	$ 10,866	$ 390,412	$ 340,115	$ 248,044	$ 145,400	$ 160,577	$ 115,506	$ 98,757	$ 90,549	$ (3,846)	$ (4,186)	$ (83)	$ (8)	$ 558,009	$ 462,301	$ 357,584	$ 246,807	$ 0	$ 0	$ 0	$ 0	$ 992,625	$ 992,625	$ 992,625	$ 992,625	$ 1,210,405	$ 1,239,123	$ 1,158,489	$ 1,100,074	$ 2,203,030	$ 2,231,748	$ 2,151,114	$ 2,092,699
Net Income													533,077	400,513	394,107										533,077	400,513	394,107										209,725	250,164	244,143						209,725	250,164	244,143										96,882	100,267	90,067						96,882	100,267	90,067										54,503	43,054	23,090						54,503	43,054	23,090										190,242	252,494	248,575		190,242	252,494	248,575
Dividends on Common Shares													(375,527)	(195,595)	(181,715)										(375,527)	(195,595)	(181,715)										(100,486)	(243,218)	(217,691)						(100,486)	(243,218)	(217,691)										(90,674)	(58,828)	(50,584)						(90,674)	(58,828)	(50,584)										(9,432)	(26,305)	(14,882)						(9,432)	(26,305)	(14,882)										(217,000)	(169,900)	(188,200)		(217,000)	(169,900)	(188,200)
Issuance of Common Shares	2,040	1,355	1,633		11,287	4,496	5,745																		13,327	5,851	7,378
Stock Issued During Period, Shares, New Issues	408,018	271,030	326,526
Dividends, Preferred Stock													(7,029)	(5,559)	(6,101)										(7,029)	(5,559)	(6,101)										(5,559)	(5,559)	(6,101)						(5,559)	(5,559)	(6,101)																																																		(1,960)	(1,960)	(1,960)		(1,960)	(1,960)	(1,960)
Stock Issued During Period, Value, Employee Stock Ownership Plan							439		2,944																		3,383						1,595	1,429	919										1,595	1,429	919						767	678	439										767	678	439						297	259	165										297	259	165
Stock Issued During Period, Shares, Employee Stock Ownership Plan			127,054
Long-Term Incentive Plan Activity					(3,897)	7,359	4,868																		(3,897)	7,359	4,868
Other Comprehensive Income (Loss), Net of Tax																	(2,168)	(27,316)	97						(2,168)	(27,316)	97														451	462	458		451	462	458														1,177	(10,231)	111		1,177	(10,231)	111														340	(4,103)	(75)		340	(4,103)	(75)
Stock Issued During Period, Value, Treasury Stock Reissued					8,454	7,048	3,856														8,043	8,065	6,871		16,497	15,113	10,727
Stock Issued During Period, Shares, Treasury Stock Reissued	438,329	439,581	374,477
Payments of Stock Issuance Costs																																	51	51	51										51	51	51
Net Income Attributable to Noncontrolling Interests													(103)	(261)	(57)										(103)	(261)	(57)
Capital Contributions from NU Parent																																	25,000	6,748	2,513										25,000	6,748	2,513							120,030	158,969											120,030	158,969						50,000	91,812	102,479										50,000	91,812	102,479
SharesIssuedInConnectionWithNstarMerger	136,048,595
SharesIssuedValueInConectionWithNstarMerger	680,243				4,358,027																				5,038,270
OtherChangesInShareholdersEquity					8,574	1,389	587																		8,574	1,389	587
OtherEquityImpactsOfMergerWithNstar					$ 2,938								$ 421												$ 3,359

XML

Long-Term Contractual Arrangements (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Long-term Purchase Commitment [Line Items]
Unrecorded Unconditional Purchase Obligation, Due within One Year	$ 717.7
Unrecorded Unconditional Purchase Obligation, Due within Two Years	683.9
Unrecorded Unconditional Purchase Obligation, Due within Three Years	572.8
Unrecorded Unconditional Purchase Obligation, Due within Four Years	501.9
Unrecorded Unconditional Purchase Obligation, Due within Five Years	432.9
Unrecorded Unconditional Purchase Obligation, Due after Five Years	2,897.5
Unrecorded Unconditional Purchase Obligation, Total	5,806.7
Supply And Stranded Costs Obligations Incurred	216.8	156.0	196.2
Natural Gas Procurement Costs Incurred	243.1	191.7	209.5
Fuel Costs Incurred	105.2	113.2	171.1
Transmission Support Commitment Costs Incurred	24.8	18.1	18.9
Peaker CfD Expense Incurred	59.3	40.2	10.0
Renewable Energy Costs Incurred	48.7	5.1	5.8
Supply And Stranded Cost Obligations [Member]
Long-term Purchase Commitment [Line Items]
Unrecorded Unconditional Purchase Obligation, Due within One Year	270.3
Unrecorded Unconditional Purchase Obligation, Due within Two Years	228.5
Unrecorded Unconditional Purchase Obligation, Due within Three Years	209.6
Unrecorded Unconditional Purchase Obligation, Due within Four Years	182.1
Unrecorded Unconditional Purchase Obligation, Due within Five Years	143.5
Unrecorded Unconditional Purchase Obligation, Due after Five Years	576.7
Unrecorded Unconditional Purchase Obligation, Total	1,610.7
Renewable Energy Contracts [Member]
Long-term Purchase Commitment [Line Items]
Unrecorded Unconditional Purchase Obligation, Due within One Year	95.2
Unrecorded Unconditional Purchase Obligation, Due within Two Years	184.3
Unrecorded Unconditional Purchase Obligation, Due within Three Years	185.5
Unrecorded Unconditional Purchase Obligation, Due within Four Years	160.2
Unrecorded Unconditional Purchase Obligation, Due within Five Years	161.6
Unrecorded Unconditional Purchase Obligation, Due after Five Years	1,800.4
Unrecorded Unconditional Purchase Obligation, Total	2,587.2
Peaker Contracts For Differences [Member]
Long-term Purchase Commitment [Line Items]
Unrecorded Unconditional Purchase Obligation, Due within One Year	75.2
Unrecorded Unconditional Purchase Obligation, Due within Two Years	72.6
Unrecorded Unconditional Purchase Obligation, Due within Three Years	66.5
Unrecorded Unconditional Purchase Obligation, Due within Four Years	63.2
Unrecorded Unconditional Purchase Obligation, Due within Five Years	66.5
Unrecorded Unconditional Purchase Obligation, Due after Five Years	292.0
Unrecorded Unconditional Purchase Obligation, Total	636.0
Natural Gas Procurement Contracts [Member]
Long-term Purchase Commitment [Line Items]
Unrecorded Unconditional Purchase Obligation, Due within One Year	138.6
Unrecorded Unconditional Purchase Obligation, Due within Two Years	125.5
Unrecorded Unconditional Purchase Obligation, Due within Three Years	80.3
Unrecorded Unconditional Purchase Obligation, Due within Four Years	69.9
Unrecorded Unconditional Purchase Obligation, Due within Five Years	39.0
Unrecorded Unconditional Purchase Obligation, Due after Five Years	154.7
Unrecorded Unconditional Purchase Obligation, Total	608.0
Wood, Coal And Transporation Contracts [Member]
Long-term Purchase Commitment [Line Items]
Unrecorded Unconditional Purchase Obligation, Due within One Year	110.7
Unrecorded Unconditional Purchase Obligation, Due within Two Years	46.3
Unrecorded Unconditional Purchase Obligation, Due within Three Years	5.5
Unrecorded Unconditional Purchase Obligation, Due within Four Years	5.0
Unrecorded Unconditional Purchase Obligation, Due within Five Years	5.0
Unrecorded Unconditional Purchase Obligation, Due after Five Years	21.8
Unrecorded Unconditional Purchase Obligation, Total	194.3
Transmission Support Commitments [Member]
Long-term Purchase Commitment [Line Items]
Recorded Unconditional Purchase Obligation Due within One Year	27.7
Recorded Unconditional Purchase Obligation Due in Second Year	26.7
Recorded Unconditional Purchase Obligation Due in Third Year	25.4
Recorded Unconditional Purchase Obligation Due in Fourth Year	21.5
Recorded Unconditional Purchase Obligation Due in Fifth Year	17.3
Recorded Unconditional Purchase Obligation Due after Fifth Year	51.9
Recorded Unconditional Purchase Obligation, Total	170.5
The Connecticut Light And Power Company [Member]
Long-term Purchase Commitment [Line Items]
Unrecorded Unconditional Purchase Obligation, Due within One Year	278.9
Unrecorded Unconditional Purchase Obligation, Due within Two Years	282.1
Unrecorded Unconditional Purchase Obligation, Due within Three Years	268.7
Unrecorded Unconditional Purchase Obligation, Due within Four Years	250.4
Unrecorded Unconditional Purchase Obligation, Due within Five Years	224.2
Unrecorded Unconditional Purchase Obligation, Due after Five Years	1,171.3
Unrecorded Unconditional Purchase Obligation, Total	2,475.6
Supply And Stranded Costs Obligations Incurred	158.2	114.9	151.3
Transmission Support Commitment Costs Incurred	9.6	10.3	10.8
Peaker CfD Expense Incurred	59.3	40.2	10.0
The Connecticut Light And Power Company [Member] | Supply And Stranded Cost Obligations [Member]
Long-term Purchase Commitment [Line Items]
Unrecorded Unconditional Purchase Obligation, Due within One Year	169.4
Unrecorded Unconditional Purchase Obligation, Due within Two Years	149.7
Unrecorded Unconditional Purchase Obligation, Due within Three Years	145.4
Unrecorded Unconditional Purchase Obligation, Due within Four Years	147.8
Unrecorded Unconditional Purchase Obligation, Due within Five Years	119.8
Unrecorded Unconditional Purchase Obligation, Due after Five Years	502.8
Unrecorded Unconditional Purchase Obligation, Total	1,234.9
The Connecticut Light And Power Company [Member] | Renewable Energy Contracts [Member]
Long-term Purchase Commitment [Line Items]
Unrecorded Unconditional Purchase Obligation, Due within One Year	4.2
Unrecorded Unconditional Purchase Obligation, Due within Two Years	30.5
Unrecorded Unconditional Purchase Obligation, Due within Three Years	30.7
Unrecorded Unconditional Purchase Obligation, Due within Four Years	30.9
Unrecorded Unconditional Purchase Obligation, Due within Five Years	31.1
Unrecorded Unconditional Purchase Obligation, Due after Five Years	356.1
Unrecorded Unconditional Purchase Obligation, Total	483.5
The Connecticut Light And Power Company [Member] | Peaker Contracts For Differences [Member]
Long-term Purchase Commitment [Line Items]
Unrecorded Unconditional Purchase Obligation, Due within One Year	75.2
Unrecorded Unconditional Purchase Obligation, Due within Two Years	72.6
Unrecorded Unconditional Purchase Obligation, Due within Three Years	66.5
Unrecorded Unconditional Purchase Obligation, Due within Four Years	63.2
Unrecorded Unconditional Purchase Obligation, Due within Five Years	66.5
Unrecorded Unconditional Purchase Obligation, Due after Five Years	292.0
Unrecorded Unconditional Purchase Obligation, Total	636.0
The Connecticut Light And Power Company [Member] | Transmission Support Commitments [Member]
Long-term Purchase Commitment [Line Items]
Recorded Unconditional Purchase Obligation Due within One Year	10.9
Recorded Unconditional Purchase Obligation Due in Second Year	10.5
Recorded Unconditional Purchase Obligation Due in Third Year	10.0
Recorded Unconditional Purchase Obligation Due in Fourth Year	8.5
Recorded Unconditional Purchase Obligation Due in Fifth Year	6.8
Recorded Unconditional Purchase Obligation Due after Fifth Year	20.4
Recorded Unconditional Purchase Obligation, Total	67.1
The Connecticut Light And Power Company [Member] | Yankee Companies Billings [Member]
Long-term Purchase Commitment [Line Items]
Recorded Unconditional Purchase Obligation Due within One Year	19.2
Recorded Unconditional Purchase Obligation Due in Second Year	18.8
Recorded Unconditional Purchase Obligation Due in Third Year	16.1
Recorded Unconditional Purchase Obligation Due in Fourth Year	0
Recorded Unconditional Purchase Obligation Due in Fifth Year	0
Recorded Unconditional Purchase Obligation Due after Fifth Year	0
Recorded Unconditional Purchase Obligation, Total	54.1
Public Service Company Of New Hampshire [Member]
Long-term Purchase Commitment [Line Items]
Unrecorded Unconditional Purchase Obligation, Due within One Year	194.1
Unrecorded Unconditional Purchase Obligation, Due within Two Years	157.5
Unrecorded Unconditional Purchase Obligation, Due within Three Years	101.7
Unrecorded Unconditional Purchase Obligation, Due within Four Years	98.7
Unrecorded Unconditional Purchase Obligation, Due within Five Years	98.7
Unrecorded Unconditional Purchase Obligation, Due after Five Years	1,146.0
Unrecorded Unconditional Purchase Obligation, Total	1,796.7
Supply And Stranded Costs Obligations Incurred	30.5	40.8	42.6
Fuel Costs Incurred	105.2	113.2	171.1
Transmission Support Commitment Costs Incurred	5.2	5.6	5.8
Renewable Energy Costs Incurred	4.1	5.1	5.8
Public Service Company Of New Hampshire [Member] | Supply And Stranded Cost Obligations [Member]
Long-term Purchase Commitment [Line Items]
Unrecorded Unconditional Purchase Obligation, Due within One Year	68.9
Unrecorded Unconditional Purchase Obligation, Due within Two Years	42.4
Unrecorded Unconditional Purchase Obligation, Due within Three Years	27.9
Unrecorded Unconditional Purchase Obligation, Due within Four Years	18.3
Unrecorded Unconditional Purchase Obligation, Due within Five Years	18.1
Unrecorded Unconditional Purchase Obligation, Due after Five Years	31.3
Unrecorded Unconditional Purchase Obligation, Total	206.9
Public Service Company Of New Hampshire [Member] | Renewable Energy Contracts [Member]
Long-term Purchase Commitment [Line Items]
Unrecorded Unconditional Purchase Obligation, Due within One Year	5.0
Unrecorded Unconditional Purchase Obligation, Due within Two Years	59.8
Unrecorded Unconditional Purchase Obligation, Due within Three Years	60.6
Unrecorded Unconditional Purchase Obligation, Due within Four Years	70.9
Unrecorded Unconditional Purchase Obligation, Due within Five Years	71.9
Unrecorded Unconditional Purchase Obligation, Due after Five Years	1,081.9
Unrecorded Unconditional Purchase Obligation, Total	1,350.1
Public Service Company Of New Hampshire [Member] | Wood, Coal And Transporation Contracts [Member]
Long-term Purchase Commitment [Line Items]
Unrecorded Unconditional Purchase Obligation, Due within One Year	110.7
Unrecorded Unconditional Purchase Obligation, Due within Two Years	46.3
Unrecorded Unconditional Purchase Obligation, Due within Three Years	5.5
Unrecorded Unconditional Purchase Obligation, Due within Four Years	5.0
Unrecorded Unconditional Purchase Obligation, Due within Five Years	5.0
Unrecorded Unconditional Purchase Obligation, Due after Five Years	21.8
Unrecorded Unconditional Purchase Obligation, Total	194.3
Public Service Company Of New Hampshire [Member] | Transmission Support Commitments [Member]
Long-term Purchase Commitment [Line Items]
Recorded Unconditional Purchase Obligation Due within One Year	5.9
Recorded Unconditional Purchase Obligation Due in Second Year	5.7
Recorded Unconditional Purchase Obligation Due in Third Year	5.4
Recorded Unconditional Purchase Obligation Due in Fourth Year	4.5
Recorded Unconditional Purchase Obligation Due in Fifth Year	3.7
Recorded Unconditional Purchase Obligation Due after Fifth Year	11.0
Recorded Unconditional Purchase Obligation, Total	36.2
Public Service Company Of New Hampshire [Member] | Yankee Companies Billings [Member]
Long-term Purchase Commitment [Line Items]
Recorded Unconditional Purchase Obligation Due within One Year	3.6
Recorded Unconditional Purchase Obligation Due in Second Year	3.3
Recorded Unconditional Purchase Obligation Due in Third Year	2.3
Recorded Unconditional Purchase Obligation Due in Fourth Year	0
Recorded Unconditional Purchase Obligation Due in Fifth Year	0
Recorded Unconditional Purchase Obligation Due after Fifth Year	0
Recorded Unconditional Purchase Obligation, Total	9.2
Western Massachusetts Electric Company [Member]
Long-term Purchase Commitment [Line Items]
Unrecorded Unconditional Purchase Obligation, Due within One Year	8.0
Unrecorded Unconditional Purchase Obligation, Due within Two Years	16.6
Unrecorded Unconditional Purchase Obligation, Due within Three Years	15.8
Unrecorded Unconditional Purchase Obligation, Due within Four Years	11.3
Unrecorded Unconditional Purchase Obligation, Due within Five Years	11.1
Unrecorded Unconditional Purchase Obligation, Due after Five Years	114.9
Unrecorded Unconditional Purchase Obligation, Total	177.7
Supply And Stranded Costs Obligations Incurred	0.9	0.3	2.3
Transmission Support Commitment Costs Incurred	2.0	2.2	2.3
Western Massachusetts Electric Company [Member] | Renewable Energy Contracts [Member]
Long-term Purchase Commitment [Line Items]
Unrecorded Unconditional Purchase Obligation, Due within One Year	0.4
Unrecorded Unconditional Purchase Obligation, Due within Two Years	9.2
Unrecorded Unconditional Purchase Obligation, Due within Three Years	9.3
Unrecorded Unconditional Purchase Obligation, Due within Four Years	9.5
Unrecorded Unconditional Purchase Obligation, Due within Five Years	9.7
Unrecorded Unconditional Purchase Obligation, Due after Five Years	110.6
Unrecorded Unconditional Purchase Obligation, Total	148.7
Western Massachusetts Electric Company [Member] | Transmission Support Commitments [Member]
Long-term Purchase Commitment [Line Items]
Recorded Unconditional Purchase Obligation Due within One Year	2.3
Recorded Unconditional Purchase Obligation Due in Second Year	2.2
Recorded Unconditional Purchase Obligation Due in Third Year	2.1
Recorded Unconditional Purchase Obligation Due in Fourth Year	1.8
Recorded Unconditional Purchase Obligation Due in Fifth Year	1.4
Recorded Unconditional Purchase Obligation Due after Fifth Year	4.3
Recorded Unconditional Purchase Obligation, Total	14.1
Western Massachusetts Electric Company [Member] | Yankee Companies Billings [Member]
Long-term Purchase Commitment [Line Items]
Recorded Unconditional Purchase Obligation Due within One Year	5.3
Recorded Unconditional Purchase Obligation Due in Second Year	5.2
Recorded Unconditional Purchase Obligation Due in Third Year	4.4
Recorded Unconditional Purchase Obligation Due in Fourth Year	0
Recorded Unconditional Purchase Obligation Due in Fifth Year	0
Recorded Unconditional Purchase Obligation Due after Fifth Year	0
Recorded Unconditional Purchase Obligation, Total	14.9
NSTAR Electric Company [Member]
Long-term Purchase Commitment [Line Items]
Unrecorded Unconditional Purchase Obligation, Due within One Year	134.4
Unrecorded Unconditional Purchase Obligation, Due within Two Years	137.8
Unrecorded Unconditional Purchase Obligation, Due within Three Years	135.7
Unrecorded Unconditional Purchase Obligation, Due within Four Years	71.6
Unrecorded Unconditional Purchase Obligation, Due within Five Years	59.9
Unrecorded Unconditional Purchase Obligation, Due after Five Years	310.6
Unrecorded Unconditional Purchase Obligation, Total	850.0
Supply And Stranded Costs Obligations Incurred	36.3	80.9	146.3
Transmission Support Commitment Costs Incurred	7.6	8.1	8.5
Renewable Energy Costs Incurred	60.2	61.8	52.7
NSTAR Electric Company [Member] | Supply And Stranded Cost Obligations [Member]
Long-term Purchase Commitment [Line Items]
Unrecorded Unconditional Purchase Obligation, Due within One Year	32.0
Unrecorded Unconditional Purchase Obligation, Due within Two Years	36.4
Unrecorded Unconditional Purchase Obligation, Due within Three Years	36.3
Unrecorded Unconditional Purchase Obligation, Due within Four Years	16.0
Unrecorded Unconditional Purchase Obligation, Due within Five Years	5.6
Unrecorded Unconditional Purchase Obligation, Due after Five Years	42.6
Unrecorded Unconditional Purchase Obligation, Total	168.9
NSTAR Electric Company [Member] | Renewable Energy Contracts [Member]
Long-term Purchase Commitment [Line Items]
Unrecorded Unconditional Purchase Obligation, Due within One Year	85.6
Unrecorded Unconditional Purchase Obligation, Due within Two Years	84.8
Unrecorded Unconditional Purchase Obligation, Due within Three Years	84.9
Unrecorded Unconditional Purchase Obligation, Due within Four Years	48.9
Unrecorded Unconditional Purchase Obligation, Due within Five Years	48.9
Unrecorded Unconditional Purchase Obligation, Due after Five Years	251.8
Unrecorded Unconditional Purchase Obligation, Total	604.9
NSTAR Electric Company [Member] | Transmission Support Commitments [Member]
Long-term Purchase Commitment [Line Items]
Unrecorded Unconditional Purchase Obligation, Due within One Year	8.6
Unrecorded Unconditional Purchase Obligation, Due within Two Years	8.3
Unrecorded Unconditional Purchase Obligation, Due within Three Years	7.9
Unrecorded Unconditional Purchase Obligation, Due within Four Years	6.7
Unrecorded Unconditional Purchase Obligation, Due within Five Years	5.4
Unrecorded Unconditional Purchase Obligation, Due after Five Years	16.2
Unrecorded Unconditional Purchase Obligation, Total	53.1
NSTAR Electric Company [Member] | Yankee Companies Billings [Member]
Long-term Purchase Commitment [Line Items]
Recorded Unconditional Purchase Obligation Due within One Year	8.2
Recorded Unconditional Purchase Obligation Due in Second Year	8.3
Recorded Unconditional Purchase Obligation Due in Third Year	6.6
Recorded Unconditional Purchase Obligation Due in Fourth Year	0
Recorded Unconditional Purchase Obligation Due in Fifth Year	0
Recorded Unconditional Purchase Obligation Due after Fifth Year	0
Recorded Unconditional Purchase Obligation, Total	$ 23.1

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LEASES (Tables)

12 Months Ended

Dec. 31, 2012

Notes To Consolidated Financial Statements [Abstract]

Schedule of Rent Expense [Table Text Block]

					NSTAR
(Millions of Dollars)	NU		CL&P		Electric (1)		PSNH		WMECO
2012	$	14.8	$	8.2	$	6.2	$	2.5	$	3.0
2011		8.4		8.3		19.8		2.1		2.8
2010		11.9		10.0		19.2		2.2		2.8

Schedule of Future Minimum Lease Payments for Capital Leases [Table Text Block]

Capital Leases
(Millions of Dollars)	NU		CL&P		PSNH
2013	$	2.8	$	2.2	$	0.5
2014		2.2		2.0		0.2
2015		2.2		2.0		0.2
2016		2.0		1.9		0.1
2017		2.0		2.0		0.0
Thereafter		7.5		7.3		0.0
Future minimum lease payments		18.7		17.4		1.0
Less amount representing interest		7.6		7.4		0.1
Present value of future minimum lease payments	$	11.1	$	10.0	$	0.9

Schedule of Future Minimum Rental Payments for Operating Leases [Table Text Block]

Operating Leases
(Millions of Dollars)	NU		CL&P		NSTAR Electric		PSNH		WMECO
2013	$	22.4	$	4.3	$	10.9	$	1.3	$	2.7
2014		16.6		3.7		8.2		1.0		1.1
2015		14.1		3.1		7.4		0.8		0.6
2016		11.2		2.3		6.1		0.6		0.3
2017		8.6		1.2		5.1		0.5		0.2
Thereafter		23.3		6.4		10.3		1.8		1.2
Future minimum lease payments	$	96.2	$	21.0	$	48.0	$	6.0	$	6.1

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ACCUMULATED OTHER COMPREHENSIVE INCOME (Details) (USD $)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Accumulated Other Comprehensive Income (Loss), Net of Tax [Abstract]
AOCI Qualified Cash Flow Hedging Instruments	$ (16,400,000)	$ (18,400,000)	$ (4,200,000)
AOCI Unrealized Gains/Losses on Other Securities	1,300,000	1,100,000
AOCI Pension, SERP and PBOP Benefits	(57,800,000)	(53,400,000)
Accumulated Other Comprehensive Loss	(72,854,000)	(70,686,000)
Other Comprehensive Income Derivatives Qualifying As Hedges Net Of Tax Period Increase Decrease [Abstract]
Beginning Balance - Accumulated Other Comprehensive Income Loss Cumulative Changes In Net Gain Loss From Cash Flow Hedges Effect Net Of Tax	(18,400,000)	(4,200,000)
Other Comprehensive Income (Loss), Reclassification Adjustment on Derivatives Included in Net Income, Net of Tax		700,000
Cash Flow Transactions Entered into for the Period		(14,900,000)
Other Comprehensive Income (Loss), Derivatives Qualifying as Hedges, Net of Tax	1,971,000	(14,177,000)	200,000
Ending Balance - Accumulated Other Comprehensive Income Loss Cumulative Changes In Net Gain Loss From Cash Flow Hedges Effect Net Of Tax	(16,400,000)	(18,400,000)	(4,200,000)
Other Comprehensive Income (Loss), Tax, Portion Attributable to Parent [Abstract]
Other Comprehensive Income (Loss), Derivatives Qualifying as Hedges, Tax	1,300,000	(9,500,000)	200,000
Other Comprehensive Income (Loss), Available-for-sale Securities, Tax	100,000	400,000	200,000
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Tax	(2,700,000)	(7,900,000)	0
Other Comprehensive Income (Loss), Tax, Portion Attributable to Parent	(1,300,000)	(17,000,000)	400,000
Cash Flow Hedge Loss To Be Reclassified Within Twelve Months	(2,000,000)
Pension Serp And Pbop Gain Loss To Be Reclassified Within Twelve Months	(10,500,000)
The Connecticut Light And Power Company [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Abstract]
AOCI Qualified Cash Flow Hedging Instruments	(1,800,000)	(2,300,000)
Accumulated Other Comprehensive Loss	(1,800,000)	(2,251,000)
Other Comprehensive Income Derivatives Qualifying As Hedges Net Of Tax Period Increase Decrease [Abstract]
Beginning Balance - Accumulated Other Comprehensive Income Loss Cumulative Changes In Net Gain Loss From Cash Flow Hedges Effect Net Of Tax	(2,300,000)
Other Comprehensive Income (Loss), Derivatives Qualifying as Hedges, Net of Tax	444,000	445,000	444,000
Ending Balance - Accumulated Other Comprehensive Income Loss Cumulative Changes In Net Gain Loss From Cash Flow Hedges Effect Net Of Tax	(1,800,000)	(2,300,000)
Other Comprehensive Income (Loss), Tax, Portion Attributable to Parent [Abstract]
Other Comprehensive Income (Loss), Derivatives Qualifying as Hedges, Tax	300,000	300,000	300,000
Cash Flow Hedge Loss To Be Reclassified Within Twelve Months	(400,000)
Public Service Company Of New Hampshire [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Abstract]
AOCI Qualified Cash Flow Hedging Instruments	(9,700,000)	(10,900,000)	(600,000)
Accumulated Other Comprehensive Loss	(9,655,000)	(10,832,000)
Other Comprehensive Income Derivatives Qualifying As Hedges Net Of Tax Period Increase Decrease [Abstract]
Beginning Balance - Accumulated Other Comprehensive Income Loss Cumulative Changes In Net Gain Loss From Cash Flow Hedges Effect Net Of Tax	(10,900,000)	(600,000)
Other Comprehensive Income (Loss), Reclassification Adjustment on Derivatives Included in Net Income, Net of Tax		500,000
Cash Flow Transactions Entered into for the Period		(10,800,000)
Other Comprehensive Income (Loss), Derivatives Qualifying as Hedges, Net of Tax	1,162,000	(10,260,000)	87,000
Ending Balance - Accumulated Other Comprehensive Income Loss Cumulative Changes In Net Gain Loss From Cash Flow Hedges Effect Net Of Tax	(9,700,000)	(10,900,000)	(600,000)
Other Comprehensive Income (Loss), Tax, Portion Attributable to Parent [Abstract]
Other Comprehensive Income (Loss), Derivatives Qualifying as Hedges, Tax	800,000	(7,000,000)	100,000
Cash Flow Hedge Loss To Be Reclassified Within Twelve Months	(1,200,000)
Western Massachusetts Electric Company [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Abstract]
AOCI Qualified Cash Flow Hedging Instruments	(3,800,000)	(4,200,000)	(100,000)
Accumulated Other Comprehensive Loss	(3,846,000)	(4,186,000)
Other Comprehensive Income Derivatives Qualifying As Hedges Net Of Tax Period Increase Decrease [Abstract]
Beginning Balance - Accumulated Other Comprehensive Income Loss Cumulative Changes In Net Gain Loss From Cash Flow Hedges Effect Net Of Tax	(4,200,000)	(100,000)
Other Comprehensive Income (Loss), Reclassification Adjustment on Derivatives Included in Net Income, Net of Tax		100,000
Cash Flow Transactions Entered into for the Period		(4,200,000)
Other Comprehensive Income (Loss), Derivatives Qualifying as Hedges, Net of Tax	338,000	(4,108,000)	(79,000)
Ending Balance - Accumulated Other Comprehensive Income Loss Cumulative Changes In Net Gain Loss From Cash Flow Hedges Effect Net Of Tax	(3,800,000)	(4,200,000)	(100,000)
Other Comprehensive Income (Loss), Tax, Portion Attributable to Parent [Abstract]
Other Comprehensive Income (Loss), Derivatives Qualifying as Hedges, Tax	200,000	(2,700,000)	0
Cash Flow Hedge Loss To Be Reclassified Within Twelve Months	$ (300,000)

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SIGNIFCANT ACCOUNTING POLICIES (Policies)

12 Months Ended

Dec. 31, 2012

Notes To Consolidated Financial Statements [Abstract]

Organization Consolidation And Presentation Of Financial Statements Disclosure Text Block

The consolidated financial statements of NU, CL&P, NSTAR Electric, PSNH and WMECO include the accounts of each of their respective subsidiaries. Intercompany transactions have been eliminated in consolidation.

The preparation of the consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent liabilities as of the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

NSTAR Electric continues to maintain reporting requirements as an SEC registrant. The information disclosed for NSTAR Electric represents its results of operations for each of the years ended December 31, 2012, 2011 and 2010 and the financial position as of December 31, 2012 and 2011, presented on a comparable basis. NU did not apply "push-down accounting" to NSTAR Electric, whereby the adjustments of assets and liabilities to fair value and the resultant goodwill would be shown on the financial statements of the acquired subsidiary. NU's consolidated financial information includes NSTAR LLC and its subsidiaries' results of operations from April 10, 2012 through December 31, 2012.

On April 10, 2012, upon consummation of the merger with NSTAR, NSTAR Electric's ownership in CYAPC and YAEC combined with CL&P's, PSNH's and WMECO's respective ownership interests in CYAPC and YAEC totaled greater than 50 percent, requiring NU to consolidate CYAPC and YAEC from April 10, 2012 and forward. The investment in CYAPC and YAEC had previously been accounted for under the equity method by NU. The consolidation of CYAPC and YAEC results in NU recording nuclear decommissioning trust marketable securities of $340.4 million, regulatory assets of $214 million, long-term debt associated with the long-term spent nuclear fuel disposal liabilities of $179.3 million, net accumulated deferred income tax liability of $56.4 million and asset retirement obligations related to decommissioning activity of $311.4 million as of December 31, 2012. At the NU consolidated level, intercompany transactions between CL&P, NSTAR Electric, PSNH and WMECO and the CYAPC and YAEC companies have been eliminated in consolidation. For CL&P, NSTAR Electric, PSNH and WMECO, the investment in CYAPC and YAEC continue to be accounted for under the equity method. See Note 1J, "Summary of Significant Accounting Policies – Equity Method Investments," for further information.

NPT, a limited liability company, was formed to construct, own and operate the NorthernPass transmission project. NPT and Hydro Renewable Energy entered into a TSA whereby NPT will sell to Hydro Renewable Energy electric transmission rights over the NorthernPass for a 40-year term at cost of service rates. NPT will be required to maintain a capital structure of 50 percent debt and 50 percent equity. On April 10, 2012, upon consummation of the merger with NSTAR, an NSTAR subsidiary that owned 25 percent of NPTwas merged into NUTV, resulting in NUTV owning 100 percent of NPT. Accordingly, 100 percent ownership of NPT was reflected in Common Shareholders' Equity as of December 31, 2012 on the accompanying consolidated balance sheet. See Note 2, "Merger of NU and NSTAR," and Note 19, "Common Shareholders' Equity and Noncontrolling Interests," for further information.

NU's utility subsidiaries are subject to the application of accounting guidance for entities with rate-regulated operations that considers the effect of regulation resulting from differences in the timing of the recognition of certain revenues and expenses from those of other businesses and industries. NU's utility subsidiaries' energy delivery business is subject to rate-regulation that is based on cost recovery and meets the criteria for application of rate-regulated accounting. See Note 3, "Regulatory Accounting," for further information.

Certain prior year amounts in NSTAR Electric's accompanying consolidated balance sheet, statements of income and cash flows have been reclassified between line items for comparative purposes and in order to conform to NU's presentation. The reclassifications did not affect NSTAR Electric's net income.The NSTAR Electric consolidated statements of cash flows were revised tocorrect an error in the presentation of cash deposits related to the RRBs.
The impact of this revision was an increase in investing cash inflows fromOther Investing Activities in an amount of $1.7 million and $24.1 millionand a corresponding increase to financing cash outflows from Retirements of
Rate Reduction Bonds for the years ended December 31, 2011 and 2010, respectively. These revisions had no impact on NSTAR Electric's resultsof operations or cash balance and are not deemed material, individually or
in the aggregate, to the previously issued consolidated financialstatements.

Certain changes in classification and corresponding reclassifications of prior year data were made in the accompanying consolidated balance sheets and statements of income for NU, CL&P, PSNH and WMECO and statements of cash flows for NU, CL&P and WMECO for comparative purposes to conform the current year presentation. The consolidated statements of income reflect the reclassification of transmission expenses from Other Operating Expenses, as originally reported, to Purchased Power, Fuel and Transmission and the reclassification of energy efficiency expenses primarily from Other Operating Expenses, as originally reported, to Energy Efficiency Programs. In addition, Other Operating Expenses and Maintenance, as originally reported, were combined and are reported in aggregate as Operations and Maintenance. The reclassifications on the statements of income were as follows:

In accordance with accounting guidance on noncontrolling interests in consolidated financial statements, the Preferred Stock of CL&P and the Preferred Stock of NSTAR Electric, which are not owned by NU or its consolidated subsidiaries and are not subject to mandatory redemption, have been presented as noncontrolling interests in the accompanying consolidated financial statements of NU.  The Preferred Stock of CL&P and the Preferred Stock of NSTAR Electricare considered to be temporary equity and have been classified between liabilities and permanent shareholders' equity on the accompanying consolidated balance sheets of NU, CL&P and NSTAR Electric due to a provision in thepreferred stock agreements of both CL&P and NSTAR Electric that grant preferred stockholders the right to elect a majority of theCL&P and NSTAR Electric Board of Directors, respectively, should certain conditions exist, such as if preferred dividends are in arrears for a specified amount of time.  The Net Income reported in the accompanying consolidated statements of income and cash flows represents consolidated net income prior to apportionment to noncontrolling interests, which is represented by dividends on preferred stock of CL&P and NSTAR Electric.

Subsequent Events Policy Policy Text Block

NU evaluates events and transactions that occur after the balance sheet date but before financial statements are issued and recognizes in the financial statements the effects of all subsequent events that provide additional evidence about conditions that existed as of the balance sheet date and discloses, but does not recognize, in the financial statements subsequent events that provide evidence about the conditions that arose after the balance sheet date but before the financial statements are issued. See Note 23, "Subsequent Events," for further information.

Receivables Policy Text Block

NU, including CL&P, NSTAR Electric, PSNH and WMECO, presents its receivables at net realizable value by maintaining a provision for uncollectible accounts receivables. This provision is determined based upon a variety of factors, including applying an estimated uncollectible account percentage to each receivable aging category, based upon historical collection and write-off experience and management's assessment of collectibility from individual customers. Management assesses the collectibility of receivables, and if circumstances change, collectibility estimates are adjusted accordingly. Receivable balances are written off against the provision for uncollectible accounts when the accounts are terminated and these balances are deemed to be uncollectible.

Fair Value Of Financial Instruments Policy

H.       Fair Value Measurements

NU, including CL&P, NSTAR Electric, PSNH, and WMECO, applies fair value measurement guidance to derivative contracts recorded at fair value and to the marketable securities held in the NU supplemental benefit trust, WMECO's spent nuclear fuel trust and CYAPC's and YAEC's nuclear decommissioning trusts. Fair value measurement guidance is also applied to investment valuations used to calculate the funded status of NU's Pension and PBOP Plans, including NSTAR Electric's Pension Plan, and nonrecurring fair value measurements of nonfinancial assets such as goodwill and AROs.

Fair Value Hierarchy: In measuring fair value, NU uses observable market data when available and minimizes the use of unobservable inputs. Inputs used in fair value measurements are categorized into three fair value hierarchy levels for disclosure purposes. The entire fair value measurement is categorized based on the lowest level of input that is significant to the fair value measurement. NU evaluates the classification of assets and liabilities measured at fair value on a quarterly basis, and NU's policy is to recognize transfers between levels of the fair value hierarchy as of the end of the reporting period. The three levels of the fair value hierarchy are described below:

Level 1 - Inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities as of the reporting date.  Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

Level 2 - Inputs are quoted prices for similar instruments in active markets, quoted prices for identical or similar instruments in markets that are not active, and model-derived valuations in which all significant inputs are observable.

Level 3 - Quoted market prices are not available. Fair value is derived from valuation techniques in which one or more significant inputs or assumptions are unobservable. Where possible, valuation techniques incorporate observable market inputs that can be validated to external sources such as industry exchanges, including prices of energy and energy-related products.

Determination of Fair Value: The valuation techniques and inputs used in NU's fair value measurements are described in Note 2, "Merger of NU and NSTAR," Note 5, "Derivative Instruments," Note 6, "Marketable Securities,"Note 7, "Asset Retirement Obligations," and Note 14, "Fair Value of Financial Instruments," to the consolidated financial statements.

Certain of NSTAR's stock-based compensation awards, including deferred shares, performance shares and all outstanding stock options, were replaced with NU awards using the exchange ratio upon consummation of the merger. In accordance with accounting guidance for business combinations, the portion of the fair value of these awards attributable to service provided prior to the merger is included in the purchase price as it represents consideration transferred in the merger. See Note 10D, "Employee Benefits – Share-Based Payments," for further information.

Purchase Price Allocation: The allocation of the total purchase price to the estimated fair values of the assets acquired and liabilities assumed has been determined based on the accounting guidance for fair value measurements, which defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The allocation of the total purchase price includes adjustments to record the fair value of NSTAR's unregulated telecommunications business, regulatory assets not earning a return, lease agreements, long-term debt and the preferred stock of NSTAR Electric. The fair values of NSTAR's assets and liabilities were determined based on significant estimates and assumptions, including Level 3 inputs, that are judgmental in nature. These estimates and assumptions include the timing and amounts of projected future cash flows and discount rates reflecting risk inherent in future cash flows.

The following methods and assumptions were used to estimate the fair value of each of the following financial instruments:

Preferred Stock, Long-Term Debt and Rate Reduction Bonds:The fair value of CL&P's and NSTAR Electric's preferred stock is based upon pricing models that incorporate interest rates and other market factors, valuations or trades of similar securities and cash flow projections. The fair value of fixed-rate long-term debt securities and RRBs is based upon pricing models that incorporate quoted market prices for those issues or similar issues adjusted for market conditions, credit ratings of the respective companies and treasury benchmark yields. Adjustable rate securities are assumed to have a fair value equal to their carrying value. The fair values provided in the tables below are classified as Level 2 within the fair value hierarchy.

Utility Revenue And Expense Recognition Policy

Regulated Companies' Unbilled Revenues: Because customers are billed throughout the month based on pre-determined cycles rather than on a calendar month basis, an estimate of electricity or natural gas delivered to customers for which the customers have not yet been billed is calculated as of the balance sheet date. Unbilled revenues are included in Operating Revenues on the consolidated statements of income and are assets on the consolidated balance sheets. Actual amounts billed to customers when meter readings become available may vary from the estimated amount.

The Regulated companies estimate unbilled sales monthly using the daily load cycle method. The daily load cycle method allocates billed sales to the current calendar month based on the daily load for each billing cycle. The billed sales are subtracted from total month load, net of delivery losses, to estimate unbilled sales. Unbilled revenues are estimated by first allocating unbilled sales to the respective customer classes, then applying an estimated rate by customer class to those sales.

Allowance For Funds Used During Construction Policy

M.       Allowance for Funds Used During Construction

AFUDC represents the cost of borrowed and equity funds used to finance construction and is included in the cost of the Regulated companies' utility plant. The portion of AFUDC attributable to borrowed funds is recorded as a reduction of Other Interest Expense, and the AFUDC related to equity funds is recorded as Other Income, Net on the accompanying consolidated statements of income. AFUDC costs are recovered from customers over the service life of the related plant in the form of increased revenue collected as a result of higher depreciation expense.

The Regulated companies' average AFUDC rate is based on a FERC-prescribed formula that produces an average rate using the cost of a company's short-term financings as well as a company's capitalization (preferred stock, long-term debt and common equity). The average rate is applied to average eligible CWIP amounts to calculate AFUDC.

Other Taxes Policy

Gross receipts taxes levied by the state of Connecticut are collected by CL&P and Yankee Gas from their respective customers. These gross receipts taxes are shown on a gross basis with collections in Operating Revenues and payments in Taxes Other Than Income Taxes on the accompanying consolidated statements of income as follows: Certain sales taxes are also collected by CL&P, NSTAR Electric, WMECO, Yankee Gas and NSTAR Gas from their respective customers as agents for state and local governments and are recorded on a net basis with no impact on the accompanying consolidated statements of income.

Public Utilities Policy Text Block

NU's Regulated companies continue to be rate-regulated on a cost-of-service basis; therefore, the accounting policies of the Regulated companies apply GAAP applicable to rate-regulated enterprises and reflect the effects of the rate-making process.

Management believes it is probable that the Regulated companies will recover their respective investments in long-lived assets, including regulatory assets. If management determined that it could no longer apply the accounting guidance applicable to rate-regulated enterprises to the Regulated companies' operations, or that management could not conclude it is probable that costs would be recovered in future rates, the costs would be charged to net income in the period in which the determination is made.

Derivatives Policy Text Block

I.       Derivative Accounting

Many of CL&P's, NSTAR Electric's, PSNH's and WMECO's contracts for the purchase and sale of energy or energy-related products are derivatives, along with NU Enterprises' remaining wholesale marketing contracts and NSTAR Gas' NYMEX futures. The accounting treatment for energy contracts entered into varies and depends on the intended use of the particular contract and on whether or not the contract is a derivative.

The application of derivative accounting is complex and requires management judgment in the following respects: identification of derivatives and embedded derivatives, election and designation of the "normal purchases or normal sales" (normal) exception, identifying, electing and designating hedge relationships, assessing and measuring hedge effectiveness, and determining the fair value of derivatives. All of these judgmentscan have a significant impact on the consolidated financial statements. Any change in the fair value of derivatives related to the Regulated companies is offset by a regulatory asset or liability, as this change will be recovered from or refunded to customers in future rates.

The fair value of derivatives is based upon the contract terms and conditions and the underlying market price or fair value per unit. When quantities are not specified in the contract, the Company determines whether the contract has a determinable quantity by using amounts referenced in default provisions and other relevant sections of the contract. The fair value of derivative assets and liabilities with the same counterparty are offset and recorded as a net derivative asset or liability on the consolidated balance sheets.

The judgment applied in the election of the normal exception (and resulting accrual accounting) includes the conclusion that it is probable at the inception of the contract and throughout its term that it will result in physical delivery of the underlying product and that the quantities will be used or sold by the business in the normal course of business. If facts and circumstances change and management can no longer support this conclusion, then the normal exception and accrual accounting is terminated and fair value accounting is applied prospectively.

The remaining wholesale marketing contracts that are marked-to-market derivative contracts are not considered to be held for trading purposes, and sales and purchase activity is reported on a net basis in Purchased Power, Fuel and Transmission on the accompanying consolidated statements of income.

For further information regarding derivative contracts of NU, CL&P, NSTAR Electricand WMECO and their accounting, see Note 5, "Derivative Instruments," to the consolidated financial statements.

5.       DERIVATIVE INSTRUMENTS

The Regulated companies purchase and procure energy and energy-related products for their customers, which are subject to price volatility. The costs associated with supplying energy to customers are recoverable through customer rates. The Regulated companies manage the risks associated with the price volatility of energy and energy-related products through the use of derivative contracts, many of which meet the definition of and are designated as "normal purchases or normal sales" (normal) under the applicable accounting guidance, and the use of nonderivative contracts.

Derivative contracts that are not recorded as normal are recorded at fair value as current or long-term derivative assets or liabilities. For the Regulated companies, regulatory assets or liabilities are recorded for the changes in fair values of derivatives, as costs are, and management believes they will continue to be, recovered from or refunded incustomers rates. For NU's remaining unregulated wholesale marketing contracts, changes in fair values of derivatives are included in Net Income. The costs and benefits of derivative contracts that meet the definition of normal are recognized in Operating Expenses or Operating Revenues on the accompanying consolidated statements of income, as applicable, as electricity or natural gas is delivered.

CL&P, NSTAR Electric and WMECO mitigate the risks associated with the price volatility of energy and energy-related products through the use of SS, LRS, and basic service contracts, which fix the price of electricity purchased for customers and are accounted for as normal. CL&P, NSTAR Electric and WMECO haveentered into derivative and nonderivative contracts for the purchase of energy and energy-related products and contracts that are derivatives. NU also has NYMEX future contracts in order to reduce variability associated with the purchase price of approximately 11.5millionMMBtu of natural gas.

The costs or benefits from all of the Regulated companies' derivative contracts are recoverable from or refundable to customers, and therefore, changes in fair value are recorded as Regulatory Assets or Regulatory Liabilities on the accompanying consolidated balance sheets.

NU, through Select Energy, has one remaining fixed price forward sales contract that expires on December 31, 2013 to serve electrical load that is part of its remaining unregulated wholesale energy marketing portfolio. NU mitigates the price risk associated with this contract through the use of several forward purchase contracts. The contracts are accounted for at fair value, and changes in their fair values are recorded in Purchased Power, Fuel and Transmission on the accompanying consolidated statements of income.

The gross fair values of derivative assets and liabilities with the same counterparty are offset and reported as net Derivative Assets or Derivative Liabilities, with current and long-term portions, in the accompanying consolidated balance sheets. Cash collateral posted or collected under master netting agreements is recorded as an offset to the derivative asset or liability.

Fair Value Measurements of Derivative Instruments

Valuation of Derivative Instruments:Derivative contracts classified as Level 2 in the fair value hierarchy relate to the financial contracts for natural gas futures and the remaining unregulated wholesale marketing sourcing contracts to purchase energy for periods in which prices are quoted in an active market. Prices are obtained from broker quotes and are based on actual market activity. The contracts are valued using the mid-point of the bid-ask spread. Valuations of these contracts also incorporate discount rates using the yield curve approach.

The fair value of derivative contracts classified as Level 3 utilize significant unobservable inputs. The fair value is modeled using income techniques, such as discounted cash flow approaches adjusted for assumptions relating to exit price. Significant observable inputs for valuations of these contracts include energy and energy-related product prices in future years for which quoted prices in an active market exist. Fair value measurements categorized in Level 3 of the fair value hierarchy are prepared by individuals with expertise in valuation techniques, pricing of energy and energy-related products, and accounting requirements. The future power and capacity prices for periods that are not quoted in an active market or established at auction are based on available market data and are escalated based on estimates of inflation to address the full time period of the contract.

Valuations of derivative contracts using discounted cash flow methodology include assumptions regarding the timing and likelihood of scheduled payments and also reflect non-performance risk, including credit, using the default probability approach based on the counterparty's credit rating for assets and the company's credit rating for liabilities. Valuations incorporate estimates of premiums or discounts that would be required by a market participant to arrive at an exit price, using historical market transactions adjusted for the terms of the contract.

Marketable Securities Policy

6.       MARKETABLE SECURITIES (NU, WMECO)

NU maintains a supplemental benefit trust to fund certain of NU's non-qualified executive retirement benefit obligations and WMECO maintains a spent nuclear fuel trust to fund WMECO's prior period spent nuclear fuel liability, each of which hold marketable securities. These trusts are not subject to regulatory oversight by state or federal agencies. As of April 10, 2012, upon consummation of the merger with NSTAR and consolidation of CYAPC and YAEC, NU's marketable securities also includes legally restricted trusts for the decommissioning of nuclear power plants.

The Company elects to record mutual funds purchased by the NU supplemental benefit trust at fair value. As such, any change in fair value of these mutual funds is reflected in Net Income. These mutual funds, classified as Level 1 in the fair value hierarchy, totaled $47million and $41.1 million as of December31, 2012 and 2011, respectively, and are included in current Marketable Securities. Net gains on these securities of $5.9million and net losses of $1.1million for the years ended December 31, 2012 and 2011, respectively, were recorded in Other Income, Net on the accompanying consolidated statements of income. Dividend income is recorded when dividends are declared and is recorded in Other Income, Net on the accompanying consolidated statements of income. All other marketable securities are accounted for as available-for-sale.

U.S. government issued debt securities are valued using market approaches that incorporate transactions for the same or similar bonds and adjustments for yields and maturity dates. Corporate debt securities are valued using a market approach, utilizing recent trades of the same or similar instrument and also incorporating yield curves, credit spreads and specific bond terms and conditions. Asset-backed debt securities include collateralized mortgage obligations, commercial mortgage backed securities, and securities collateralized by auto loans, credit card loans or receivables. Asset-backed debt securities are valued using recent trades of similar instruments, prepayment assumptions, yield curves, issuance and maturity dates and tranche information. Municipal bonds are valued using a market approach that incorporates reported trades and benchmark yields. Other fixed income securities are valued using pricing models, quoted prices of securities with similar characteristics, and discounted cash flows.

Environmental Costs Policy

Environmental Matters

General: NU, CL&P, NSTAR Electric, PSNH and WMECO are subject to environmental laws and regulations intended to mitigate or remove the effect of past operations and improve or maintain the quality of the environment. These laws and regulations require the removal or the remedy of the effect on the environment of the disposal or release of certain specified hazardous substances at current and former operating sites. NU, CL&P, NSTAR Electric, PSNH and WMECO have an active environmental auditing and training program and believe that they are substantially in compliance with all enacted laws and regulations.

These liabilities are estimated on an undiscounted basis and do not assume that any amounts are recoverable from insurance companies or other third parties. The environmental reserves includesites at different stages of discovery and remediation and do not include any unasserted claims.

It is possible that new information or future developments could require a reassessment of the potential exposure to related environmental matters. As this information becomes available, management will continue to assess the potential exposure and adjust the reserves accordingly.

Earnings Per Share Policy Text Block

RSUs and performance shares are included in basic weighted average common shares outstanding as of the date that all necessary vesting conditions have been satisfied. The dilutive effect of unvested RSUs and performance shares is calculated using the treasury stock method. Assumed proceeds of these units under the treasury stock method consist of the remaining compensation cost to be recognized and a theoretical tax benefit. The theoretical tax benefit is calculated as the tax impact of the intrinsic value of the units (the difference between the market value of the average units outstanding for the period, using the average market price during the period, and the grant date market value).

The dilutive effect of stock options to purchase common shares is also calculated using the treasury stock method. Assumed proceeds for stock options consist of cash proceeds that would be received upon exercise, and a theoretical tax benefit. The theoretical tax benefit is calculated as the tax impact of the intrinsic value of the stock options (the difference between the market value of the average stock options outstanding for the period, using the average market price during the period, and the exercise price).

Segment Reporting Policy Policy Text Block

SEGMENT INFORMATION (NU)

Presentation: NU is organized between the Electric Distribution, Electric Transmission and Natural Gas Distribution segments and Other based on a combination of factors, including the characteristics of each segments' products and services, the sources of operating revenues and expenses and the regulatory environment in which each segment operates. These segments represented substantially all of NU's total consolidated revenues for the years endedDecember 31, 2012, 2011 and 2010. Revenues from the sale of electricity and natural gas primarily are derived from residential, commercial and industrial customers and are not dependent on any single customer. The Electric Distribution segment includes the generation activities of PSNH and WMECO.

Other operations in the tables below primarily consists of 1) the equity in earnings of NU parent from its subsidiaries and intercompany interest income, both of which are eliminated in consolidation, and interest income and expense related to the cash and debt of NU parent and NSTAR LLC, respectively, 2) the revenues and expenses of NU's service companies, most of which are eliminated in consolidation, 3) the operations of CYAPC and YAEC, and 4) the results of other subsidiaries, which are comprised of NU Enterprises, NSTAR Communications, Inc., RRR (a real estate subsidiary), the non-energy-related subsidiaries of Yankee and the remaining operations of HWP.

Cash flows used for investments in plant included in the segment information below are cash capital expenditures that do not include amounts incurred but not paid, cost of removal, AFUDC related to equity funds, and the capitalized portions of pension and PBOP expense or income.

As discussed in Note 1B, “Summary of Significant Accounting Policies – Basis of Presentation,” certain reclassifications of prioryear data were made in the accompanying consolidated statements of income for NU. Accordingly, the corresponding items of segment information have been recast for all prior years for comparative purposes.

Consolidation Variable Interest Entity Policy

VARIABLE INTEREST ENTITIES

The Company's variable interests outside of the consolidated group are not material and consist of contracts that are required by regulation and provide for regulatory recovery of contract costs and benefits through customer rates. NU, CL&P and NSTAR Electric hold variable interests in variable interest entities (VIEs) through agreements with certain entities that own single renewable energy or peaking generation power plants and with other independent power producers. NU, CL&P and NSTAR Electric do not control the activities that are economically significant to these VIEs or provide financial or other support to these VIEs. Therefore, NU, CL&P and NSTAR Electric do not consolidate any power plant VIEs.

Cash and Cash Equivalents, Policy [Policy Text Block]

D.       Cash and Cash Equivalents

Cash and cash equivalents include cash on hand and short-term cash investments that are highly liquid in nature and have original maturities of three months or less. At the end of each reporting period, any overdraft amounts are reclassified from Cash and Cash Equivalents to Accounts Payable on the accompanying consolidated balance sheets.

Asset Retirement Obligations, Policy [Policy Text Block]

The Liability Assumed Upon Consolidation of CYAPC and YAEC represents theCYAPC and YAEC ARO fair value as of the merger date. The fair value of the ARO for CYAPC and YAEC includes uncertainties of the fuel off-load dates related to the DOE's timing of performance regarding its obligation to dispose of the spent nuclear fuel and high level waste. The incremental asset recorded as an offset to the ARO was fully depreciated since the plants have no remaining useful life. Any changes in the assumptions used to calculate the fair value of the ARO are recorded as an offset to the related regulatory asset.The assets held in the decommissioning trust are restricted for settling the asset retirement obligation and all other decommissioning obligations. For further information on the regulatory asset established or the assets held in trust to support this obligation, see Note 3, “Regulatory Accounting,” and Note 6, “Marketable Securities,” to the consolidated financial statements.

Goodwill and Intangible Assets, Policy [Policy Text Block]

The goodwill from the merger with NSTAR of $3.2 billion has been assigned to NU's reporting units based on relative fair values. NU's reporting units consist of Electric Distribution, Electric Transmission and Natural Gas Distribution. See the "Goodwill" section below for the allocation of goodwill to each reporting unit.

Goodwill:In a business combination, the excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed is recognized as goodwill. Goodwill is evaluated for impairment at least annually and more frequently if indicators of impairment arise. In accordance with the accounting standards, if the fair value of a reporting unit is less than its carrying value (including goodwill), the goodwill is tested for impairment. A loss is recognized if the implied fair value of a reporting unit's goodwill is less than the carrying value of its goodwill. NU uses October 1st as the annual goodwill impairment testing date.

On April 10, 2012, upon consummation of the merger with NSTAR, NU recorded approximately $3.2 billion of goodwill. With the completion of the NSTAR merger, NU reviewed its management structure and determinedthat the reporting units for the purpose of testing goodwill for impairment are Electric Distribution, Electric Transmission and Natural Gas Distribution. NU's reporting units are consistent with the operating segments underlying the reportable segments identified in Note 21, "Segment Information," to the consolidated financial statements. Accordingly, the goodwill resulting from the NSTAR merger has been allocated to the Electric Distribution, Electric Transmission and Natural Gas Distribution reporting unitsbased on the estimatedfair values of the reporting units as of the merger date.

As of December 31, 2011, the only reporting unit that maintained goodwill was the natural gas reportable segment, related to the acquisition of the parent of Yankee Gas in 2000. This goodwill is recorded at Yankee Gas. The goodwill balance at Yankee Gas as of December 31, 2012 and 2011was $0.3billion.

NU completed its impairment analysis of the NSTAR and Yankee Gas goodwill balances as of October 1, 2012 and determined that no impairment exists. In completing this analysis, the fair value of the reporting units was estimated using a discounted cash flow methodology and a market method utilizing comparable company information and market transactions.

Pension And Other Postretirement Plans Policy

A.Pension Benefits and Postretirement Benefits Other Than Pensions

NUSCO sponsors a defined benefit retirement plan that covers most employees, including CL&P, PSNH, and WMECO employees, hired before 2006 (or as negotiated, for bargaining unit employees), referred to as the NUSCO Pension Plan. NSTAR Electric serves as plan sponsor for a defined benefit retirement plan that covers most employeesof NSTAR Electric & Gas, hired before October 1, 2012, or as negotiated by bargaining unit employees, referred to as the NSTAR Pension Plan. Both plans are subject to the provisions of ERISA, as amended by the PPA of 2006. NUSCO and NSTAR Electric & Gas each maintain SERPs and other non-qualified defined benefit retirement plans (herein collectively referred to as the SERP Plans), which provide benefits in excess of Internal Revenue Code limitations to eligible current and retired participants that would have otherwise been provided under the Pension Plans.

NUSCO and NSTAR Electric & Gas also sponsor defined benefit postretirement plans that provide certain retiree health care benefits, primarily medical and dental, and life insurance benefits to retiring employees that meet certain age and service eligibility requirements (NUSCO PBOP Plans and NSTAR PBOP Plan, respectively). Under certain circumstances, eligible retirees are required to contribute to the costs of postretirement benefits. The benefits provided under the NUSCO and NSTAR PBOP Plans are not vested and the Company has the right to modify any benefit provision subject to applicable laws at that time.

The funded status of the Pension, SERP and PBOP Plans is calculated based on the difference between the benefit obligation and the fair value of plan assets. The funded status of the Pension, SERP and PBOP Plans is recorded on the consolidated balance sheets as a liability with an offset to Accumulated Other Comprehensive Income/(Loss). Pension, SERP and PBOP costs for the Regulated companies are recorded as Regulatory Assets as these amounts are recovered from customers. Regulatory accounting was also applied to the portions of the NUSCO and NSTAR Electric & Gas costs that support the Regulated companies, as these costs are also recovered from customers. Pension and PBOP costs for the unregulated companies are recorded on an after-tax basis to Accumulated Other Comprehensive Income/(Loss). For further information, see Note3, "Regulatory Accounting," and Note15, "Accumulated Other Comprehensive Income/(Loss)," to the consolidated financial statements. The SERP Plans do not have plan assets.

For the NUSCO Pension and PBOP Plans, the expected return on plan assets is calculated by applying the assumed rate of return to a four-year rolling average of plan asset fair values, which reduces year-to-year volatility. Investment gains or losses for this purpose are the difference between the calculated expected return and the actual return. As investment gains and losses are reflected in the average plan asset fair values, they are subject to amortization with other unrecognized actuarial gains or losses. For the NSTAR Pension and PBOP Plans, the entire difference between the actual return and calculated expected return on plan assets is reflected as a component of unrecognized actuarial gain or loss. Unrecognized actuarial gains or losses are amortized as a component of Pension and PBOP expense over the estimated average future employee service period.

Pension and SERPPlans:The funded status of each of the plans is recorded on the respective sponsor's balance sheet: NUSCO (NUSCO Pension and NUSCO SERP), NSTAR Electric (NSTAR Pension) and NSTAR Electric & Gas (NSTAR SERP). The NUSCO plans are accounted for under the multiple-employer approachwhile the NSTAR plans are accounted for under the multi-employer approach. Accordingly, the balance sheet of NSTAR Electric reflects the full funded status of the NSTAR Pension Plan.

Pension and SERPExpense: For the NUSCO Plans, NU allocates net periodic pension expense to its subsidiaries based on the actual participant demographic data for each subsidiary's participants. Benefit payments to participants and contributions are also tracked for each subsidiary. The actual investment return in the trust each year is allocated to each of the subsidiaries annually in proportion to the investment return expected to be earned during the year.For the NSTARPension Plan, the net periodic pension expense recorded at NSTAR Electric represents the full cost of the plan and then a portion of the costs are allocated to affiliated companies based on participant demographic data.

PBOP Expense: For the NUSCO Plans, NU allocates net periodic postretirement benefits expense to its subsidiaries based on the actual participant demographic data for each subsidiary's participants. Benefit payments to participants and contributions are also tracked for each subsidiary. The actual investment return in the trust is allocated to each of the subsidiaries annually in proportion to the investment return expected to be earned during the year. For the NSTAR Plan, NSTAR allocates the net periodic postretirement expenses to its subsidiaries based on actual participant demographic data for each of its subsidiaries.

Contributions: NU's policy is to annually fund the NUSCO and NSTAR Pension Plans in an amount at least equal to an amount that will satisfy federal requirements. NU contributed $197.4 million to the NUSCO Pension Plan in 2012, of which $87.7 million was contributed by PSNH. NSTAR Electric contributed $25 million to the NSTAR Pension Plan for the year ended December 31, 2012. Based on the current status of the NUSCO Pension Plan, NUanticipates making a contribution of approximately $203million in 2013, of which $107 million is required to meet minimum federalfunding requirements. NSTAR Electric anticipates making a contribution of approximately $82 million in 2013 to the NSTAR Pension Plan, of which $38 million is required to meet minimum federal funding requirements.

For the PBOP Plans, it is NU's policy to annually fund the NUSCO PBOP Plans in an amount equal to the PBOP Plans' postretirement benefit cost, excluding curtailment and termination benefits. NU contributed $50 million to the NUSCO PBOP Plans in 2012 and expects to make $25.7 million in contributions in 2013. NU contributes an amount that approximates annual benefit payments to the NSTAR PBOP Plan. NU contributed $22.7 million to the NSTAR PBOP Plan for the period April 10, 2012 to December 31, 2012 and expects to make $30 million in contributions in 2013.

Fair Value of Pension and PBOP Plan Assets: Pension and PBOP funds are held in external trusts. Trust assets, including accumulated earnings, must be used exclusively for Pension and PBOP payments. NU's investment strategy for its Pension and PBOP Plans is to maximize the long-term rates of return on these plans' assets within an acceptable level of risk. The investment strategy for each asset category includes a diversification of asset types, fund strategies and fund managers and establishes target asset allocations that are routinely reviewed and periodically rebalanced. In 2012, PBOP assets were comprised of specific assets within the defined benefit pension plan trust (401(h) assets) as well as assets held in the PBOP Plans. The investment policy and strategy of the 401(h) assets is consistent with those of the defined benefit pension plans, which are detailed below. NU's expected long-term rates of return on Pension and PBOP Plan assets are based on these target asset allocation assumptions and related expected long-term rates of return. In developing its expected long-term rate of return assumptions for the Pension and PBOP Plans, NU evaluated input from actuaries and consultants, as well as long-term inflation assumptions and historical returns. For the year ended December 31, 2012, management has assumed long-term rates of return of 8.25 percenton NUSCO Pension and PBOP Plan assets and 7.30 percent on the NSTAR Pensionand PBOP Plan assets.

The Company values assets based on observable inputs when available. Equity securities, exchange traded funds and futures contracts classified as Level 1 in the fair value hierarchy are priced based on the closing price on the primary exchange as of the balance sheet date. Commingled funds included in Level 2 equity securities are recorded at the net asset value provided by the asset manager, which is based on the market prices of the underlying equity securities. Swaps are valued using pricing models that incorporate interest rates and equity and fixed income index closing prices to determine a net present value of the cash flows. Fixed income securities, such as government issued securities, corporate bonds and high yield bond funds, are included in Level 2 and are valued using pricing models, quoted prices of securities with similar characteristics or discounted cash flows. The pricing models utilize observable inputs such as recent trades for the same or similar instruments, yield curves, discount margins and bond structures. Hedge funds and investments in opportunistic fixed income funds are recorded at net asset value based on the values of the underlying assets. The assets in the hedge funds and opportunistic fixed income funds are valued using observable inputs and are classified as Level 3 within the fair value hierarchy due to redemption restrictions. Private Equity investments and Real Estate and Other Assets are valued using the net asset value provided by the partnerships, which are based on discounted cash flows of the underlying investments, real estate appraisals or public market comparablesof the underlying investments. These investments are classified as Level 3 due to redemption restrictions.

Property, Plant and Equipment, Depreciation Methods

Utility property, plant and equipment is recorded at original cost. Original cost includes materials, labor, construction overhead and AFUDC for regulated property. The cost of repairs and maintenance, including planned major maintenance activities, is charged to Operating Expenses as incurred. Depreciation of utility assets is calculated on a straight-line basis using composite rates based on the estimated remaining useful lives of the various classes of property (estimated useful life for PSNH distribution). The composite rates are subject to approval by the appropriate state regulatory agency. The composite rates include a cost of removal component, which is collected from customers during the life of the property and is recognized as a regulatory liability. Depreciation rates are applied to property from the time it is placed in service. Upon retirement from service, the cost of the utility asset is charged to the accumulated provision for depreciation. The actual incurred removal costs are applied against the related regulatory liability.

Income Tax, Policy [Policy Text Block]

11.       INCOME TAXES

The tax effect of temporary differences is accounted for in accordance with the rate-making treatment of the applicable regulatory commissions and relevant accounting authoritative literature.

Deferred tax assets and liabilities are recognized for the future tax effects of temporary differences between the carrying amounts and the tax basis of assets and liabilities.

Interest and Penalties: Interest on uncertain tax positions is recorded and generally classified as a component of Other Interest Expense. However, when resolution of uncertainties results in the Company receiving interest income, any related interest benefit is recorded in Other Income, Net on the accompanying consolidated statements of income. No penalties have been recorded. If penalties are recorded in the future, then the estimated penalties would be classified as a component of Other Income, Net on the accompanying consolidated statements of income.

Member of Group Filing Consolidated Return, Policy [Policy Text Block]

NU, CL&P, NSTAR Electric, PSNH and WMECO file a consolidated federal income tax return and unitary, combined and separate state income tax returns. These entities are also parties to a tax allocation agreement under which taxable subsidiaries do not pay any more taxes than they would have otherwise paid had they filed a separate company tax return, and subsidiaries generating tax losses, if any, are paid for their losses when utilized.

Share-based Compensation, Option and Incentive Plans Policy [Policy Text Block]

D.       Share-Based Payments

Share-based compensation awards are recorded using the fair value-based method at the date of grant. NU, CL&P, NSTAR Electric, PSNH and WMECO record compensation cost related to these awards, as applicable, for shares issued or sold to their respective employees and officers, as well as the allocation of costs associated with shares issued or sold to NU's service companies' employees and officers that support CL&P, NSTAR Electric, PSNH and WMECO.

Upon consummation of the merger with NSTAR, the NSTAR 1997 Share Incentive Plan and the NSTAR 2007 Long-Term Incentive Plan were assumed by NU. Share-based awards granted under the NSTAR Plans and held by NSTAR employees and officers were generally converted into outstanding NU share-based compensation awards with an estimated fair value of $53.2 million. Refer to Note2, "Merger of NU and NSTAR," for further information regarding the merger transaction. Specifically, as of the merger closing, and as adjusted by the exchange ratio, (1) NU converted outstanding NSTAR stock options into 2,664,894 NU stock options valued at $30.5 million, (2) NU converted NSTAR deferred shares and NSTAR performance shares into 421,775 NU RSU's valued at $15.5 million, and (3) NU converted NSTAR RSU retention awards into 195,619 NU RSU retention awards valued at $7.2 million.

NU Incentive Plan: NU maintains long-term equity-based incentive plans under the NU Incentive Plan in which NU, CL&P, PSNH and WMECO employees, officers and board members are entitled to participate. The NU Incentive Plan was approved in 2007, and authorized NU to grant up to 4,500,000 new shares for various types of awards, including RSUs and performance shares, to eligible employees, officers, and board members. As of December 31, 2012 and 2011, NU had 2,502,512and 2,685,615common shares, respectively, available for issuance under the NU Incentive Plan. In addition to the NU Incentive Plan, NU maintains an ESPP for eligible employees.

NSTAR Incentive Plans: Awards may continue to be granted following the merger under the NSTAR 2007 Long-Term Incentive Plan; however, no additional awards will be granted under the NSTAR 1997 Share Incentive Plan. The aggregate number of common shares initially authorized for issuance under the NSTAR 2007 Long-Term Incentive Plan was 3,500,000. As of December 31, 2012, there were 977,922NU common shares available for issuance under the NSTAR 2007 Long-Term Incentive Plan.

NU accounts for its various share-based plans as follows:

• RSUs - NU records compensation expense, net of estimated forfeitures, on a straight-line basis over the requisite service period based upon the fair value of NU's common shares at the date of grant. The par value of RSUs is reclassified to Common Stock from APIC as RSUs become issued as common shares.
• Performance Shares - NU records compensation expense, net of estimated forfeitures, on a straight-line basis over the requisite service period. Performance shares vest based upon the extent to which Company goals are achieved. For the majority of performance shares, fair value is based upon the value of NU's common shares at the date of grant and compensation expense is recorded based upon the probable outcome of the achievement of Company targets. For the remaining performance shares, vesting is based upon the achievement of the Company's share price as compared to an index of similar equity securities. The fair value at the date of grant for these remaining performance shares was determined using a lattice model and compensation expense is recorded over the requisite service period.
• Stock Options - Stock options issued under the NSTAR Incentive Plan that were outstandingimmediately prior to the completion of the merger with NSTARconverted into fully vested options to acquire NU common shares, as adjusted by the exchange ratio. The fair value of these awards on the merger date was included in the purchase price as it represented consideration transferred in the merger. Accordingly, no compensation expense is recorded for these stock options. Additionally, no compensation expense is recorded for stock options issued under the NU Incentive Plan as these stock options were fully vested prior to January 1, 2006.
• ESPP Shares - For shares sold under the ESPP, no compensation expense is recorded, as the ESPP qualifies as a non-compensatory plan.

RSUs:NU granted RSUs under theannual Long-Term incentive programs that are subject to three-year graded vesting schedules for employees, and one-year graded vesting schedules for board members. RSUs are paid in shares, reduced by amounts sufficient to satisfy withholdings for income taxes, subsequent to vesting. A summary of RSU transactions is as follows:

As of December 31, 2012 and 2011, the number and weighted average grant-date fair value of unvested RSUs was 1,417,688 and $34.70 per share, and 403,108and $28.70per share, respectively. The number and weighted average grant-date fair value of RSUs vested during 2012 was 471,323 and $30.20per share, respectively. As of December 31, 2012, 765,631RSUs were fully vested and an additional 1,346,804are expected to vest.

Performance Shares: NU had granted performance shares under the annual Long-Term Incentive programs that vested based upon the extent to which the Company achieved targets at the end of three-year performance measurement periods. Performance shares are paid in shares, after the performance measurement period. A summary of performance share transactions is as follows:

Upon closing of the merger with NSTAR, 451,358 performance shares under the NU 2011 and 2012 Long-Term Incentive Programs converted to RSUs according to the terms of these programs. The remaining performance shares were measured based upon a modified performance period through the date of the merger, in accordance with the terms of the NU 2010 Incentive Program, with distribution in 2013.

Stock Options:Stock options were granted under the NU and NSTAR Incentive Plans. Options currently outstanding expire ten years from the date of grant and are fully vested. The weighted average remaining contractual lives for the options outstanding as of December 31, 2012 is 4.8 years. A summary of stock option transactions is as follows:

Employee Share Purchase Plan: NU maintains an ESPP for eligible employees, which allows for NU common shares to be purchased by employees at the end of successive six-month offering periods at 95 percent of the closing market price on the last day of each six-month period. Employees are permitted to purchase shares having a value not exceeding 25 percent of their compensation as of the beginning of the offering period up to a limit of $25,000 per annum. The ESPP qualifies as a non-compensatory plan under accounting guidance for share-based payments, and no compensation expense is recorded for ESPP purchases.

Employee Stock Ownership Plan (ESOP), Policy [Policy Text Block]

NU maintains an ESOP for purposes of allocating shares to employees participating in the NUSCO 401(k) Savings Plan.

Allocations of NU common shares were made from NU treasury shares to satisfy the NUSCO 401(k) Savings Plan obligation to provide a portion of the matching contribution in NU common shares

For treasury shares used to satisfy the 401(k) Savings Plan matching contributions, compensation expense is recognized equal to the fair value of shares that have been allocated to participants. Any difference between the fair value and the average cost of the allocated treasury shares is charged or credited to Capital Surplus, Paid In.

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EARNINGS PER SHARE (Tables)

12 Months Ended

Dec. 31, 2012

Notes To Consolidated Financial Statements [Abstract]

Schedule Of Earnings Per Share Basic And Diluted [Table Text Block]

		For the Years Ended December 31,
(Millions of Dollars, except share information)		2012		2011		2010
Net Income Attributable to Controlling Interest		$	525.9	$	394.7	$	387.9
Weighted Average Common Shares Outstanding:
	Basic		277,209,819		177,410,167		176,636,086
	Dilutive Effect		783,812		394,401		249,301
	Diluted		277,993,631		177,804,568		176,885,387
Basic EPS		$	1.90	$	2.22	$	2.20
Diluted EPS		$	1.89	$	2.22	$	2.19

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COMMITMENTS AND CONTINGENCIES

12 Months Ended

Dec. 31, 2012

Notes To Consolidated Financial Statements [Abstract]

Commitments and Contingencies Disclosure [Text Block]

12.       COMMITMENTS AND CONTINGENCIES

A.Environmental Matters

General: NU, CL&P, NSTAR Electric, PSNH and WMECO are subject to environmental laws and regulations intended to mitigate or remove the effect of past operations and improve or maintain the quality of the environment. These laws and regulations require the removal or the remedy of the effect on the environment of the disposal or release of certain specified hazardous substances at current and former operating sites. NU, CL&P, NSTAR Electric, PSNH and WMECO have an active environmental auditing and training program and believe that they are substantially in compliance with all enacted laws and regulations.

Environmental reserves are accrued when assessments indicate it is probable that a liability has been incurred and an amount can be reasonably estimated. The approach used estimates the liability based on the most likely action plan from a variety of available remediation options, including no action required or several different remedies ranging from establishing institutional controls to full site remediation and monitoring.

These estimates are subjective in nature as they take into consideration several different remediation options at each specific site. The reliability and precision of these estimates can be affected by several factors, including new information concerning either the level of contamination at the site, the extent of NU, CL&P, NSTAR Electric, PSNH and WMECO's responsibility or the extent of remediation required, recently enacted laws and regulations or a change in cost estimates due to certain economic factors.

The amounts recorded as environmental liabilities included in Other Current Liabilities and Other Long-Term Liabilities on the accompanying consolidated balance sheets represent management's best estimate of the liability for environmental costs, and take into consideration site assessment, remediation and long-term monitoring costs. The environmental liability also takes into account recurring costs of managing hazardous substances and pollutants, mandated expenditures to remediate previously contaminated sites and any other infrequent and non-recurring clean up costs. A reconciliation of the activity in the environmental reserves is as follows:

(Millions of Dollars)	NU		CL&P		NSTAR Electric(1)		PSNH		WMECO
Balance as of December 31, 2010	$	37.1	$	2.8	$	0.9	$	9.1	$	0.3
Additions		1.6		0.4		0.4		0.1		0.1
Payments		(7.0)		(0.3)		-		(2.6)		(0.1)
Balance as of December 31, 2011		31.7		2.9		1.3		6.6		0.3
Liabilities Assumed with NSTAR Merger		11.8		-		-		-		-
Additions		4.7		1.3		0.7		0.2		0.5
Payments/Reductions		(8.8)		(0.5)		(0.3)		(1.9)		(0.2)
Balance as of December 31, 2012	$	39.4	$	3.7	$	1.7	$	4.9	$	0.6

(1)NSTAR Electric amounts are included in NU consolidated from the date of the merger, April 10, 2012 through December 31, 2012. NSTAR Electric amounts are not included in NU consolidated for the years ended December 31, 2011 and 2010.

These liabilities are estimated on an undiscounted basis and do not assume that any amounts are recoverable from insurance companies or other third parties. The environmental reserves includesites at different stages of discovery and remediation and do not include any unasserted claims.

It is possible that new information or future developments could require a reassessment of the potential exposure to related environmental matters. As this information becomes available, management will continue to assess the potential exposure and adjust the reserves accordingly.

The number of environmental sites and reserves related to these sites for which remediation or long-term monitoring, preliminary site work or site assessment are being performedare as follows:

	As of December 31, 2012				As of December 31, 2011
			Reserve				Reserve
	Number of Sites		(in millions)		Number of Sites		(in millions)
NU		77	$	39.4		59	$	31.7
CL&P		19		3.7		18		2.9
NSTAR Electric (1)		16		1.7		13		1.3
PSNH		16		4.9		18		6.6
WMECO		6		0.6		10		0.3

• The NSTAR Electric reserve balance and number of sites are not included in NU consolidated amounts as of December 31, 2011.

Included in the NU number of sites and reserve amounts above are former MGP sites that were operated several decades ago and manufactured gas from coal and other processes, which resulted in certain by-products remaining in the environment that may pose a potential risk to human health and the environment. The reserve balance related to these former MGP sites was $34.5 million and $28.9 million as of December 31, 2012 and 2011, respectively, and relates primarily to the natural gas business segment.

As of December 31, 2012, for 8 environmental sites (3 for CL&P, 2 for PSNH, and 1 for WMECO) that are included in the Company's reserve for environmental costs, the information known and nature of the remediation options at those sites allow for the Company to estimate the range of losses for environmental costs. As of December 31, 2012, $2.6 million ($0.6 million for CL&P and $0.7million for PSNH) had been accrued as a liability for these sites, which represent management's best estimates of the liabilities for environmental costs. These amounts are the best estimates with estimated ranges of additional losses from zero million to $15.2 million (zero to $1.3 million for CL&P, zero to $4.1 million for PSNH, and zero to $8.6 million for WMECO).

As of December 31, 2012, for 23 environmental sites (5 for CL&P,1 for NSTAR Electric,4 for PSNH, and 3 for WMECO) included in the Company's reserve for environmental costs, management cannot reasonably estimate the exposure to loss in excess of the reserve, or range of loss, as these sites are under investigation and/or there is significant uncertainty as to what remedial actions, if any, the Company may be required to undertake. As of December 31, 2012, $17 million ($1.7 million for CL&P,$0.2 million for PSNH, and $0.5 million for WMECO) had been accrued as a liability for these sites. As of December 31, 2012, for the remaining 46environmental sites (11 for CL&P,15for NSTAR Electric, 10 for PSNH, and 2 for WMECO) included in the Company's reserve for environmental costs, the $19.8 million accrual ($1.4 million for CL&P, $1.7 million for NSTAR Electric, $4 million for PSNH, and $0.1 million for WMECO) represents management's best estimate of the liability and no additional loss is anticipated.

HWP: HWP, a subsidiary of NU, continues to investigate the potential need for additional remediation at a river site in Massachusetts containing tar deposits associated with an MGP site that HWP sold to HG&E, a municipal utility, dating back to 1902. HWP shares responsibility for site remediation with HG&E and has conducted substantial investigative and remediation activities. The cumulative expense recorded to the reserve for this site since 1994 through December 31, 2012 was $19.5million, of which $17.4million had been spent, leaving $2.1million in the reserve as of December 31, 2012. For theyears ended December 31, 2012 and 2011, there were no charges recorded to the reserve and for the year ended December 31, 2010,a pre-tax charge of $2.6 millionwas recorded to reflect estimated costs associated with the site. HWP's share of the costs related to this site is not recoverable from customers.

In 2008, the MA DEP issued a letter to HWP and HG&E, representing guidance rather than a mandate, providing conditional authorization for additional investigatory and risk characterization activities and indicating that further removal of tar in certain areas was needed. HWP implemented several supplemental studies to further delineate and assess tar deposits in conformity with the MA DEP's guidance letter. In December 2012, the MADEP advised that all work to date with this site continues to meet regulatory expectations.

In 2010, HWP delivered a report to the MA DEP describing the results of its site investigation studies and testing. Subsequent communications and discussions with the MA DEP have focused on the course of action to achieve resolution of these matters, and are ongoing.

The $2.1 million reserve balance as of December 31, 2012 represents estimated costs that HWP considers probable over the remaining life of the project, including testing and related costs in the near term and field activities to be agreed upon with the MA DEP, further studies and long-term monitoring that are expected to be required by the MA DEP, and certain soft tar remediation activities. Various factors could affect management's estimates and require an increase to the reserve, which would be reflected as a charge to Net Income. Although a material increase to the reserve is not presently anticipated, management cannot reasonably estimate potential additional investigation or remediation costs because these costs would depend on, among other things, the nature, extent and timing of additional investigation and remediation that may be required by the MA DEP.

CERCLA: The federal Comprehensive Environmental Response, Compensation and Liability Act of 1980 (CERCLA) and its amendments or state equivalents impose joint and several strict liabilities, regardless of fault, upon generators of hazardous substances resulting in removal and remediation costs and environmental damages.  Liabilities under these laws can be material and in some instances may be imposed without regard to fault or for past acts that may have been lawful at the time they occurred.  Of the total sites included in the remediation and long-term monitoring phase, 10 sites (2 for CL&P,4 for NSTAR Electric, 4 for PSNH and 1 for WMECO) are superfund sites under CERCLA for which the Company has been notified that it is a potentially responsible party but for which the site assessment and remediation are not being managed by the Company.  As of December 31, 2012, a liability of $1 million ($0.4 million for CL&P, $0.1 million for NSTAR Electric and $0.4 million for PSNH) accrued on these sites represents management's best estimate of its potential remediation costs with respect to these superfund sites.

Environmental Rate Recovery: PSNH,NSTAR Gas and Yankee Gas have rate recovery mechanisms for environmental costs. CL&P recovers a certain level of environmental costs currently in rates but does not have an environmental cost recovery tracking mechanism. Accordingly, changes in CL&P's environmental reserves impact CL&P's Net Income. WMECO does not have a separate regulatory mechanism to recover environmental costs from its customers, and changes in WMECO's environmental reserves impact WMECO's Net Income.

B.	Long-Term Contractual Arrangements
Estimated Future Annual Costs: The estimated future annual costs of significant long-term contractual arrangements as of
December 31, 2012 are as follows:
NU
(Millions of Dollars)		2013		2014		2015		2016		2017		Thereafter		Total
Supply and Stranded Cost		$	270.3	$	228.5	$	209.6	$	182.1	$	143.5	$	576.7	$	1,610.7
Renewable Energy			95.2		184.3		185.5		160.2		161.6		1,800.4		2,587.2
Peaker CfDs			75.2		72.6		66.5		63.2		66.5		292.0		636.0
Natural Gas Procurement			138.6		125.5		80.3		69.9		39.0		154.7		608.0
Coal, Wood and Other			110.7		46.3		5.5		5.0		5.0		21.8		194.3
Transmission Support Commitments			27.7		26.7		25.4		21.5		17.3		51.9		170.5
Total		$	717.7	$	683.9	$	572.8	$	501.9	$	432.9	$	2,897.5	$	5,806.7
CL&P
(Millions of Dollars)		2013		2014		2015		2016		2017		Thereafter		Total
Supply and Stranded Cost		$	169.4	$	149.7	$	145.4	$	147.8	$	119.8	$	502.8	$	1,234.9
Renewable Energy			4.2		30.5		30.7		30.9		31.1		356.1		483.5
Peaker CfDs			75.2		72.6		66.5		63.2		66.5		292.0		636.0
Transmission Support Commitments			10.9		10.5		10.0		8.5		6.8		20.4		67.1
Yankee Billings			19.2		18.8		16.1		0.0		0.0		0.0		54.1
Total		$	278.9	$	282.1	$	268.7	$	250.4	$	224.2	$	1,171.3	$	2,475.6
NSTAR Electric
(Millions of Dollars)		2013		2014		2015		2016		2017		Thereafter		Total
Supply and Stranded Cost		$	32.0	$	36.4	$	36.3	$	16.0	$	5.6	$	42.6	$	168.9
Renewable Energy			85.6		84.8		84.9		48.9		48.9		251.8		604.9
Transmission Support Commitments			8.6		8.3		7.9		6.7		5.4		16.2		53.1
Yankee Billings			8.2		8.3		6.6		0.0		0.0		0.0		23.1
Total		$	134.4	$	137.8	$	135.7	$	71.6	$	59.9	$	310.6	$	850.0
PSNH
(Millions of Dollars)		2013		2014		2015		2016		2017		Thereafter		Total
Supply and Stranded Cost		$	68.9	$	42.4	$	27.9	$	18.3	$	18.1	$	31.3	$	206.9
Renewable Energy			5.0		59.8		60.6		70.9		71.9		1,081.9		1,350.1
Coal, Wood and Other			110.7		46.3		5.5		5.0		5.0		21.8		194.3
Transmission Support Commitments			5.9		5.7		5.4		4.5		3.7		11.0		36.2
Yankee Billings			3.6		3.3		2.3		0.0		0.0		0.0		9.2
Total		$	194.1	$	157.5	$	101.7	$	98.7	$	98.7	$	1,146.0	$	1,796.7
WMECO
(Millions of Dollars)		2013		2014		2015		2016		2017		Thereafter		Total
Renewable Energy		$	0.4	$	9.2	$	9.3	$	9.5	$	9.7	$	110.6	$	148.7
Transmission Support Commitments			2.3		2.2		2.1		1.8		1.4		4.3		14.1
Yankee Billings			5.3		5.2		4.4		0.0		0.0		0.0		14.9
Total		$	8.0	$	16.6	$	15.8	$	11.3	$	11.1	$	114.9	$	177.7

Supply and Stranded Cost: CL&P, NSTAR Electric, PSNH and WMECO have various IPP contracts or purchase obligations for electricity, including payment obligations resulting from the buydown of electricity purchase contracts. Such contracts extend through 2024 for CL&P, 2030 for NSTAR Electric and 2023 for PSNH.

In addition, CL&P and UI have entered into four CfDs for a total of approximately 787 MW of capacity consisting of three generation projects and one demand response project. The capacity CfDs extend through 2026 and obligate the utilities to pay the difference between a set price and the value that the projects receive in the ISO-NE markets. The contracts have terms of up to 15 years beginning in 2009 and are subject to a sharing agreement with UI, whereby UI will share 20 percent of the costs and benefits of these contracts. CL&P's portion of the costs and benefits of these contracts will be paid by or refunded to CL&P's customers. The amounts of these payments are subject to changes in capacity and forward reserve prices that the projects receive in the ISO-NE capacity markets.

The contractual obligations table does not include CL&P's SS or LRS, or NSTAR Electric's or WMECO's default service contracts, the amounts of which vary with customers' energy needs. The contractual obligations table also does not include PSNH's short-term power supply management.

Renewable Energy:Renewable energy contracts include non-cancellable commitments under contracts of CL&P, NSTAR Electric, PSNH, and WMECO for the purchase of energy and capacity from renewable energy facilities. Such contracts have terms extending for 15 years at CL&P, up to 40 years at NSTAR Electric, up to 30 years for PSNH and 15 years for WMECO.

The table above does not include NSTAR Electric's commitment to purchase 129MW of renewable energy from a wind facility to be constructed offshore and certain other CL&P and NSTAR Electric commitments for the purchase of renewable energy and related products that are contingent on the future construction of facilities.

PeakerCfDs: In 2008, CL&P entered into three CfDs with developers of peaking generation units approved by the PURA (PeakerCfDs). These units have a total of approximately 500 MW of peaking capacity. As directed by the PURA, CL&P and UI have entered into a sharing agreement, whereby CL&P is responsible for 80 percent and UI for 20 percent of the net costs or benefits of these CfDs. The PeakerCfDs pay the developer the difference between capacity, forward reserve and energy market revenues and a cost-of-service payment stream for 30 years. The ultimate cost or benefit to CL&P under these contracts will depend on the costs of plant construction and operation and the prices that the projects receive for capacity and other products in the ISO-NE markets. CL&P's portion of the amounts paid or received under the PeakerCfDs will be recoverable from or refunded to CL&P's customers.

Natural Gas Procurement:NU'snatural gas distribution businesses have long-term contracts for the purchase, transportation and storage of natural gas in the normal course of business as part of its portfolio of supplies. These contracts extend through 2029.

Coal, Wood and Other: PSNH has entered into various arrangements for the purchase of wood, coal and the transportation services for fuel supply for its electric generating assets.Also included in the table above is a contract for capacity on the Portland Natural Gas Transmission System (PNGTS) pipeline that extends through 2019. The costs on this contract are not recoverable from customers.

Transmission Support Commitments: Along with other New England utilities, CL&P, NSTAR Electric, PSNH and WMECO entered into agreements in 1985 to support transmission and terminal facilities that were built to import electricity from the Hydro-Québec system in Canada. CL&P, NSTAR Electric, PSNH and WMECO are obligated to pay, over a 30-year period ending in 2020, their proportionate shares of the annual operation and maintenance expenses and capital costs of those facilities.

The total costs incurred under these agreements in 2012, 2011, and 2010 were as follows:

NU	For the Years Ended December 31,
(Millions of Dollars)	2012		2011		2010
Supply and Stranded Cost	$	216.8	$	156.0	$	196.2
Renewable Energy		48.7		5.1		5.8
Peaker CfDs		59.3		40.2		10.0
Natural Gas Procurement		243.1		191.7		209.5
Coal, Wood and Other		105.2		113.2		171.1
Transmission Support Commitments		24.8		18.1		18.9

		For the Years Ended December 31,
		2012								2011								2010
				NSTAR								NSTAR								NSTAR
(Millions of Dollars)		CL&P		Electric(1)		PSNH		WMECO		CL&P		Electric(1)		PSNH		WMECO		CL&P		Electric(1)		PSNH		WMECO
Supply and
	Stranded Cost	$	158.2	$	36.3	$	30.5	$	0.9	$	114.9	$	80.9	$	40.8	$	0.3	$	151.3	$	146.3	$	42.6	$	2.3
Renewable Energy			-		60.2		4.1		-		-		61.8		5.1		-		-		52.7		5.8		-
Peaker CfDs			59.3		-		-		-		40.2		-		-		-		10.0		-		-		-
Coal, Wood and Other			-		-		105.2		-		-		-		113.2		-		-		-		171.1		-
Transmission Support
	Commitments		9.6		7.6		5.2		2.0		10.3		8.1		5.6		2.2		10.8		8.5		5.8		2.3

(1)NSTAR Electric amounts are included in NU consolidated from the date of the merger, April 10, 2012 through December 31, 2012. NSTAR Electric amounts are not included in NU consolidated for the years ended December 31, 2011 and 2010.

C.       Deferred Contractual Obligations

CL&P, NSTAR Electric, PSNH and WMECO have decommissioning and plant closure cost obligations to the Yankee Companies, which have each completed the physical decommissioning of their respective nuclear facilities and are now engaged in the long-term storage of their spent fuel. The Yankee Companies collect decommissioning and closure costs through wholesale, FERC-approved rates charged under power purchase agreements with several New England utilities, including CL&P, NSTAR Electric, PSNH and WMECO. These companies in turn recover these costs from their customers through state regulatory commission-approved retail rates.

CL&P, NSTAR Electric, PSNH and WMECO's percentage share of the obligations to support the Yankee Companies under FERC-approved rate tariffs is the same as their respective ownership percentages in the Yankee Companies. For further information on the ownership percentages, see Note 1J, "Summary of Significant Accounting Policies - Equity Method Investments," to the consolidated financial statements.

The Yankee Companies are currently collecting amounts that management believes are adequate to recover the remaining decommissioning and closure cost estimates for the respective plants. Management believes CL&P, NSTAR Electric and WMECO will recover their shares of these decommissioning and closure obligations from their customers. PSNH has already recovered its share of these costs from its customers.

Spent Nuclear Fuel Litigation:

DOE Phase I Damages - In 1998, CYAPC, YAEC and MYAPC (Yankee Companies) filed separate complaints against the DOE in the Court of Federal Claims seeking monetary damages resulting from the DOE's failure to begin accepting spent nuclear fuel for disposal by January 31, 1998 pursuant to the terms of the 1983 spent fuel and high level waste disposal contracts between the Yankee Companies and the DOE (DOE Phase I Damages). In a ruling released on October 4, 2006, the Court of Federal Claims held that the DOE was liable for damages to CYAPC for $34.2 million through 2001, YAEC for $32.9 million through 2001 and MYAPC for $75.8 million through 2002.

In December 2006, the DOE appealed the ruling, and the Yankee Companies filed cross-appeals. The Court of Appeals issued its decision on August 7, 2008, effectively agreeing with the trial court's findings as to the liability of the DOE but disagreeing with the method that the trial court used to calculate damages. The Court of Appeals vacated the decision and remanded the case for new findings consistent with its decision.

On September 7, 2010, the trial court issued its decision following remand, and judgment on the decision was entered on September 9, 2010. The judgment awarded CYAPC $39.7 million, YAEC $21.2 million and MYAPC $81.7 million. The DOE filed an appeal and the Yankee Companies cross-appealed on November 8, 2010. Briefs were filed and oral arguments in the appeal of the remanded case occurred on November 7, 2011. On May 18, 2012, the U.S. Court of Appeals for the Federal Circuit issued a unanimous panel decision in favor of the Yankee Companies upholding the trial court's awards to each company in the remanded cases, and increasing YAEC damages by approximately $17 million to cover certain wet pool operating expenses. On August 1, 2012, the DOE filed a petition asking the U.S. Court of Appeals for the Federal Circuit to reconsider its unanimous panel decision in favor of the Yankee Companies upholding the trial court's awards to each company in the remanded cases. On September 5, 2012, the U.S. Court of Appeals for the Federal Circuit denied the DOE's petition. The decisions became final and non-appealable and interest on the judgments began to accrue on or about December 5, 2012, as the DOE elected not to file a petition for certiorari with the U.S. Supreme Court.

As a result of the April 10, 2012 merger with NSTAR and NU's consolidation of CYAPC and YAEC, the consolidated financial statements reflect an aggregate receivable from the DOE for CYAPC and YAEC's Phase I damages awards of $77.9million as of December 31, 2012.

In January 2013, the proceeds from the DOE Phase I Damages Claim were received by CYAPC in the amount of $39.6 million, YAEC in the amount of $38.3 million, and MYAPC in the amount of $81.7 million. The funds were transferred to each Yankee Company's respective decommissioning trust. The final application of the proceeds for the benefit of customers of CL&P, NSTAR Electric, PSNH and WMECO will be determined following rate proceedings to be filed by each Yankee Company at FERC in the second quarter of 2013. Final FERC determinations are expected by the end of the third quarter of 2013.

DOE Phase II Damages - In December 2007, the Yankee Companies each filed subsequent lawsuits against the DOE seeking recovery of actual damages incurred in the years following 2001 and 2002 related to the alleged failure of the DOE to provide for a permanent facility to store spent nuclear fuel generated in years after 2001 for CYAPC and YAEC and after 2002 for MYAPC (DOE Phase II Damages). On November 18, 2011, the court ordered the record closed in the YAEC case, and closed the record in the CYAPC and MYAPC cases subject to a limited opportunity of the governmentto reopen the records for further limited proceedings. The record is now closed, all post-trial briefing has been completed, and the case is awaiting the court decision.

The methodology for applying any DOE Phase II Damages that may be recovered from the DOE for the benefit of customers of CL&P, NSTAR Electric, PSNH and WMECO will be addressed in the same FERC rate proceedings.

D.       Guarantees and Indemnifications

NUparent, or NSTAR LLC, as applicable, provides credit assurances on behalf of its subsidiaries, including CL&P, NSTAR Electric, PSNH and WMECO, in the form of guarantees in the normal course of business.

NU provided guarantees and various indemnifications on behalf of external parties as a result of the sales of former subsidiaries of NU Enterprises, with maximum exposures either not specified or not material.

NU also issued a guaranty for the benefit of Hydro Renewable Energy under which, beginning at the time the Northern Pass Transmission line goes into commercial operation, NU will guarantee the financial obligations of NPT under the TSA in an amount not to exceed $25million. NU's obligations under the guaranty expire upon the full, final and indefeasible payment of the guaranteed obligations.

Management does not anticipate a material impact to Net Income as a result of these various guarantees and indemnifications.

The following table summarizes NU's guarantees of its subsidiaries, including CL&P, NSTAR Electric, PSNH and WMECO, as of December 31, 2012:

		Maximum
		Exposure
Subsidiary	Description	(in millions)			Expiration Dates
Various	Surety Bonds	$	32.8		January 2013 - November 2015 (1)
Various	NE Hydro Companies' Long-Term Debt	$	5.6		Unspecified
NUSCO and RRR	Lease Payments for Vehicles and Real Estate	$	20.1		2019 and 2024
NU Enterprises	Surety Bonds, Insurance Bonds and Performance Guarantees	$	67.4	(2)	(2)

(1)       Surety bond expiration dates reflect bond termination dates, the majority of which will be renewed or extended.

(2)       The maximum exposure includes $13.5million related to performance guarantees on wholesale purchase contracts, which expire December 31, 2013. Also included in the maximum exposure is $1million related to insurance bonds with no expiration date that are billed annually on their anniversary date. The remaining $52.9million of maximum exposure relates to surety bonds covering ongoing projects, which expire upon project completion.

Many of the underlying contracts that NU parent guarantees, as well as certain surety bonds, contain credit ratings triggers that would require NU parent to post collateral in the event that the unsecured debt credit ratings of NU, or NSTAR LLC, as applicable, are downgraded below investment grade.

E.DPU Penalties for 2011 Storm Responses (NSTAR Electric, WMECO)

On December 11, 2012, in separate orders issued by the DPU, NSTAR Electric and WMECO received penalties related to the investigation into the electric utilities' responses to Tropical Storm Irene and the October 2011 snowstorm.  The DPU ordered penalties of $4.1 million and $2 million for NSTAR Electric and WMECO, respectively, stating that NSTAR Electric failed to communicate and prioritize restoration efforts in both storms and WMECO failed to prioritize restoration efforts in the October snowstorm.  These penalties were ordered to be assessed in the form of customer credits in 2013.  On December 28, 2012, NSTAR Electric and WMECO each filed appeals with the SJC arguing the DPU penalties should be vacated. In their filings, NSTAR Electric and WMECO stated that the DPU's decision to assess the penalties was in error as the assessments were arbitrary and not supported by substantial evidence.  While we believe that NSTAR Electric and WMECO should ultimately prevail upon appeal, we are unable to conclusively state that a favorable outcome is probable. Therefore, NSTAR Electric and WMECO recorded $4.1 million and $2 million, respectively, in pre-tax penalty charges as of December 31, 2012.

F. FERC Base ROE Complaint

On September 30, 2011, several New England state attorneys general, state regulatory commissions, consumer advocates and other parties filed a joint complaint with the FERC under Sections 206 and 306 of the Federal Power Act alleging that the base ROE used in calculating formula rates for transmission service under the ISO-NE Open Access Transmission Tariff by New England transmission owners, including CL&P, NSTAR Electric, PSNH and WMECO, is unjust and unreasonable. The complainants asserted that the current 11.14 percent rate, which became effective in 2006, is excessive due to changes in the capital markets and are seeking an order to reduce the rate, which would be effective September 30, 2011 through December 31, 2012. In response, the New England transmission owners filed testimony and analysis based on standard FERC methodology and precedent, demonstrating that the base ROE of 11.14 percent remained just and reasonable.

On May 3, 2012, the FERC issued an order establishing hearing and settlement procedures for the complaint. The settlement proceedings were subsequently terminated, as the parties had reached an impasse in their efforts to reach a settlement. In August 2012, the FERC trial judge assigned to the complaint established a schedule for the trial phase of the proceedings. Complainant testimony supporting a base ROE of 9 percent was filed on October 1, 2012. Additional testimony was filed on October 1, 2012 by a group of Massachusetts municipal electric companies, which recommended a base ROE of 8.2 percent. The New England transmission owners filed testimony and analysis on November 20, 2012, demonstrating they believe that the current base ROE continues to be just and reasonable. On January 18, 2013, the FERC trial staff filed testimony and analysis recommending a base ROE of 9.66 percent based on the midpoint of their analysis with a range of reasonableness of 6.82 percent to 12.51 percent. Hearings on this complaint are scheduled for May 2013 and a trial judge's recommended decision is due in September 2013. A decision from FERC commissioners is expected in 2014. Refunds to customers, if any, as a result of a reduction in the NU transmission companies' base ROE would be retroactive to October 1, 2011.

On December 27, 2012, several additional parties filed a separate complaint concerning the New England transmission owners' ROE with the FERC. This new complaint seeks to reduce the New England transmission owner's base transmission ROE effective January 1, 2013, and to consolidate this new complaint with the joint complaint filed on September 30, 2011. The New England transmission owners have asked the FERC to reject this new complaint. The FERC has not yet acted on this request.

Management cannot at this time predict the ultimate outcome of this proceeding or the estimated impacts on CL&P's, NSTAR Electric's, PSNH's, or WMECO's respective financial position, results of operations or cash flows.

G.       DPU Safety and Reliability Programs - CPSL (NSTAR Electric)

Since 2006, NSTAR Electric has been recovering incremental costs related to the Double Pole Inspection, Replacement/Restoration and Transfer Program and the Underground Electric Safety Program, which included stray-voltage remediation, manhole inspections, repairs, and upgrades, in accordance with this DPU approved program. Recovery of these CPSL costs is subject to review and approval by the DPU through a rate-reconciling mechanism. From 2006 through December 31, 2011, cumulative costs associated with the CPSL program resulted in an incremental revenue requirement to customers of approximately $83 million. These amounts included incremental operations and maintenance costs and the related revenue requirement for specific capital investments relative to the CPSL programs.

On May 28, 2010, the DPU issued an order on NSTAR Electric's 2006 CPSL cost recovery filing (the May 2010 Order). The May 2010 Order was the basis NSTAR Electric used for recognizing revenue for the CPSL programs. On October 8, 2010, NSTAR Electric submitted a Compliance Filing with the DPU reconciling the cumulative CPSL program activity for the periods 2006 through 2009 in order to determine a proposed rate adjustment effective on January 1, 2011. The DPU allowed the proposed rates for the CPSL programs to go into effect on that date, subject to final reconciliation of CPSL program costs through a future DPU proceeding. NSTAR Electric updated the October 2010 filing with final activity through 2011 in February 2013.

NSTAR Electric cannot predict the timing of any subsequent DPU order related to its CPSL filings for the period 2006 through 2011. Therefore, NSTAR Electric continued to record its 2006 through 2011 revenues under the CPSL programs based on the May 2010 Order. While we do not believe that any subsequent DPU order would result in revenue recognition that is materially different than the amounts already recognized, it is reasonably possible that an order could have a material impact on NSTAR Electric's results of operations, financial position and cash flows.

The April 4, 2012 DPU-approved comprehensive settlement agreement with the Massachusetts Attorney General concerning the merger stipulates that NSTAR Electric must incur a revenue requirement of at least $15 million per year for 2012 through 2015 in order to continue these programs. CPSL revenues will end once NSTAR Electric has recovered its 2015-related CPSL costs. Realization of these revenues is subject to maintaining certain performance metrics over the four-year period and DPU approval. As of December 31, 2012, NSTAR Electric was in compliance with the performance metrics and has recognized the entire $15 million revenue requirement during 2012, which we believe is probable of approval from the DPU.

H.       Basic Service Bad Debt Adder (NSTAR Electric)

In accordance with a generic DPU order, electric utilities in Massachusetts recover the energy-related portion of bad debt costs in their Basic Service rates. On February 7, 2007, NSTAR Electric filed its 2006 Basic Service reconciliation with the DPU proposing an adjustment related to the increase of its Basic Service bad debt charge-offs. On June 28, 2007, the DPU issued an order approving the implementation of a revised Basic Service rate. However, the DPU instructed NSTAR Electric to reduce distribution rates by an amount equal to the increase in its Basic Service bad debt charge-offs. This adjustment to NSTAR Electric's distribution rates would eliminate the fully reconciling nature of the Basic Service bad debt adder.

NSTAR Electric deferred the unrecovered costs associated with energy-related bad debt as a regulatory asset, which totaled approximately $34 million as of December 31, 2011, as NSTAR Electric had concluded that these costs were probable of recovery in future rates. On June 18, 2010, NSTAR Electric filed an appeal of the DPU's order with the SJC, which was heard by the SJC in December 2011. On April 11, 2012, the SJC issued a procedural order waiving its standing 130-day rule for issuance of an order on the matter. Due to the delay, NSTAR Electric concluded that while an ultimate outcome on the matter in its favor remained "more likely than not," it could no longer be deemed "probable." As a result, NSTAR Electric recognized a reserve of $28 million ($17 million after-tax) as a charge to Operations and Maintenance in the first quarter of 2012 to reserve the related regulatory asset on its balance sheet.

On June 4, 2012, the SJC vacated the DPU's June 28, 2007 order and remanded the matter to the DPU for a "statement of reasons, including subsidiary findings, of its conclusion of law and relevant facts." The continued uncertainty of the outcome of the DPU's proceeding leaves NU and NSTAR Electric unable to conclude that it is probable that the previously reserved amount will ultimately be recovered and therefore NSTAR Electric will continue to maintain a reserve on this amount until the ultimate outcome is determined by the DPU.

I.       Litigation and Legal Proceedings

NU, including CL&P, NSTAR Electric, PSNH and WMECO, are involved in legal, tax and regulatory proceedings regarding matters arising in the ordinary course of business, which involve management's assessment to determine the probability of whether a loss will occur and, if probable, its best estimate of probable loss. The Company records and discloses losses when these losses are probable and reasonably estimable, discloses matters when losses are probable but not estimable or reasonably possible, and expenses legal costs related to the defense of loss contingencies as incurred.

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Basis of Presentation (Tables)

12 Months Ended

Dec. 31, 2012

Notes To Consolidated Financial Statements [Abstract]

Schedule of Reclassification Adjustments [Table Text Block]

	Transmission Expense				Energy Efficiency Expense
	For the Years Ended December 31,				For the Years Ended December 31,
(Millions of Dollars)	2011		2010		2011		2010
NU	$	77.2	$	48.9	$	131.4	$	124.0
CL&P		52.6		39.4		90.3		92.3
PSNH		19.1		26.4		12.9		12.0
WMECO		15.9		18.3		21.8		16.3

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FAIR VALUE OF FINANCIAL INSTRUMENTS (Details) (USD $)	Dec. 31, 2012	Dec. 31, 2011
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Temporary Equity, Carrying Amount, Attributable to Noncontrolling Interest	$ 155,568,000	$ 116,200,000
Rate Reduction Bonds	82,139,000	112,260,000
Carrying Reported Amount Fair Value Disclosure [Member]
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Temporary Equity, Carrying Amount, Attributable to Noncontrolling Interest	155,600,000	116,200,000
Rate Reduction Bonds	82,100,000	112,300,000
Other Long Term Debt	7,963,500,000	4,950,700,000
Estimate Of Fair Value Fair Value Disclosure [Member]
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Temporary Equity, Carrying Amount, Attributable to Noncontrolling Interest	152,200,000	105,100,000
Rate Reduction Bonds	83,000,000	116,800,000
Other Long Term Debt	8,640,700,000	5,517,000,000
The Connecticut Light And Power Company [Member]
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Temporary Equity, Carrying Amount, Attributable to Noncontrolling Interest	116,200,000	116,200,000
The Connecticut Light And Power Company [Member] | Carrying Reported Amount Fair Value Disclosure [Member]
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Temporary Equity, Carrying Amount, Attributable to Noncontrolling Interest	116,200,000	116,200,000
Other Long Term Debt	2,862,800,000	2,587,800,000
The Connecticut Light And Power Company [Member] | Estimate Of Fair Value Fair Value Disclosure [Member]
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Temporary Equity, Carrying Amount, Attributable to Noncontrolling Interest	110,000,000	105,100,000
Other Long Term Debt	3,295,400,000	2,987,100,000
Public Service Company Of New Hampshire [Member]
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Rate Reduction Bonds	29,294,000	85,368,000
Public Service Company Of New Hampshire [Member] | Carrying Reported Amount Fair Value Disclosure [Member]
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Rate Reduction Bonds	29,300,000	85,400,000
Other Long Term Debt	997,900,000	999,500,000
Public Service Company Of New Hampshire [Member] | Estimate Of Fair Value Fair Value Disclosure [Member]
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Rate Reduction Bonds	29,600,000	88,800,000
Other Long Term Debt	1,088,000,000	1,075,200,000
Western Massachusetts Electric Company [Member]
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Rate Reduction Bonds	9,352,000	26,892,000
Western Massachusetts Electric Company [Member] | Carrying Reported Amount Fair Value Disclosure [Member]
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Rate Reduction Bonds	9,400,000	26,900,000
Other Long Term Debt	605,300,000	501,100,000
Western Massachusetts Electric Company [Member] | Estimate Of Fair Value Fair Value Disclosure [Member]
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Rate Reduction Bonds	9,500,000	28,100,000
Other Long Term Debt	660,400,000	539,800,000
NSTAR Electric Company [Member]
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Temporary Equity, Carrying Amount, Attributable to Noncontrolling Interest	43,000,000	43,000,000
Rate Reduction Bonds	43,493,000	127,860,000
NSTAR Electric Company [Member] | Carrying Reported Amount Fair Value Disclosure [Member]
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Temporary Equity, Carrying Amount, Attributable to Noncontrolling Interest	43,000,000	43,000,000
Rate Reduction Bonds	43,500,000	127,900,000
Other Long Term Debt	1,602,600,000	1,605,100,000
NSTAR Electric Company [Member] | Estimate Of Fair Value Fair Value Disclosure [Member]
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Temporary Equity, Carrying Amount, Attributable to Noncontrolling Interest	42,200,000	41,200,000
Rate Reduction Bonds	43,900,000	131,200,000
Other Long Term Debt	$ 1,818,800,000	$ 1,816,100,000

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FAIR VALUE OF FINANCIAL INSTRUMENTS

12 Months Ended

Dec. 31, 2012

Notes To Consolidated Financial Statements [Abstract]

Fair Value Disclosures [Text Block]

14.       FAIR VALUE OF FINANCIAL INSTRUMENTS

The following methods and assumptions were used to estimate the fair value of each of the following financial instruments:

Preferred Stock, Long-Term Debt and Rate Reduction Bonds:The fair value of CL&P's and NSTAR Electric's preferred stock is based upon pricing models that incorporate interest rates and other market factors, valuations or trades of similar securities and cash flow projections. The fair value of fixed-rate long-term debt securities and RRBs is based upon pricing models that incorporate quoted market prices for those issues or similar issues adjusted for market conditions, credit ratings of the respective companies and treasury benchmark yields. Adjustable rate securities are assumed to have a fair value equal to their carrying value. The fair values provided in the tables below are classified as Level 2 within the fair value hierarchy. Carrying amounts and estimated fair values are as follows:

		As of December 31,
		2012				2011
NU		Carrying		Fair		Carrying		Fair
(Millions of Dollars)		Amount		Value		Amount		Value
Preferred Stock Not
	Subject to Mandatory Redemption	$	155.6	$	152.2	$	116.2	$	105.1
Long-Term Debt			7,963.5		8,640.7		4,950.7		5,517.0
Rate Reduction Bonds			82.1		83.0		112.3		116.8

		As of December 31, 2012
		CL&P				NSTAR Electric				PSNH				WMECO
		Carrying		Fair		Carrying		Fair		Carrying		Fair		Carrying		Fair
(Millions of Dollars)		Amount		Value		Amount		Value		Amount		Value		Amount		Value
Preferred Stock Not
	Subject to Mandatory Redemption	$	116.2	$	110.0	$	43.0	$	42.2	$	-	$	-	$	-	$	-
Long-Term Debt			2,862.8		3,295.4		1,602.6		1,818.8		997.9		1,088.0		605.3		660.4
Rate Reduction Bonds			-		-		43.5		43.9		29.3		29.6		9.4		9.5
		As of December 31, 2011
		CL&P				NSTAR Electric (1)				PSNH				WMECO
		Carrying		Fair		Carrying		Fair		Carrying		Fair		Carrying		Fair
(Millions of Dollars)		Amount		Value		Amount		Value		Amount		Value		Amount		Value
Preferred Stock Not
	Subject to Mandatory Redemption	$	116.2	$	105.1	$	43.0	$	41.2	$	-	$	-	$	-	$	-
Long-Term Debt			2,587.8		2,987.1		1,605.1		1,816.1		999.5		1,075.2		501.1		539.8
Rate Reduction Bonds			-		-		127.9		131.2		85.4		88.8		26.9		28.1

• NSTAR Electric amounts are not included in NU consolidated as of December 31, 2011.

Derivative Instruments: NU, including CL&P, NSTAR Electric and WMECO, holds various derivative instruments that are carried at fair value. For further information, see Note 5, "Derivative Instruments," to the consolidated financial statements.

Other Financial Instruments: Investments in marketable securities are carried at fair value on the accompanying consolidated balance sheets. For further information, see Note 1H, "Summary of Significant Accounting Policies - Fair Value Measurements," and Note 6, "Marketable Securities," to the consolidated financial statements.

The carrying value of other financial instruments included in current assets and current liabilities, including cash and cash equivalents and special deposits, approximates their fair value due to the short-term nature of these instruments.

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Basis of Presentation (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Reclassification of Transmission Expense		$ 77.2	$ 48.9
Reclassification of Energy Expense		131.4	124.0
Description of Consolidation of Yankee Companies	On April 10, 2012, upon consummation of the merger with NSTAR, NSTAR Electric's ownership in CYAPC and YAEC combined with CL&P's, PSNH's and WMECO's respective ownership interests in CYAPC and YAEC totaled greater than 50 percent, requiring NU to consolidate CYAPC and YAEC from April 10, 2012 and forward. The investment in CYAPC and YAEC had previously been accounted for under the equity method by NU. The consolidation of CYAPC and YAEC results in NU recording nuclear decommissioning trust marketable securities of $340.4 million, regulatory assets of $214 million, long-term debt associated with the long-term spent nuclear fuel disposal liabilities of $179.3 million, net accumulated deferred income tax liability of $56.4 million and asset retirement obligations related to decommissioning activity of $311.4 million as of December 31, 2012. At the NU consolidated level, intercompany transactions between CL&P, NSTAR Electric, PSNH and WMECO and the CYAPC and YAEC companies have been eliminated in consolidation. For CL&P, NSTAR Electric, PSNH and WMECO, the investment in CYAPC and YAEC continue to be accounted for under the equity method. See Note 1J, "Summary of Significant Accounting Policies – Equity Method Investments," for further information.
Immaterial Error Correction	The NSTAR Electric consolidated statements of cash flows were revised to correct an error in the presentation of cash deposits related to the RRBs.The impact of this revision was an increase in investing cash inflows from Other Investing Activities in an amount of $1.7 million and $24.1 million and a corresponding increase to financing cash outflows from Retirements ofRate Reduction Bonds for the years ended December 31, 2011 and 2010, respectively. These revisions had no impact on NSTAR Electric’s results of operations or cash balance and are not deemed material, individually orin the aggregate, to the previously issued consolidated financial statements.
The Connecticut Light And Power Company [Member]
Reclassification of Transmission Expense		52.6	39.4
Reclassification of Energy Expense		90.3	92.3
Public Service Company Of New Hampshire [Member]
Reclassification of Transmission Expense		19.1	26.4
Reclassification of Energy Expense		12.9	12.0
Western Massachusetts Electric Company [Member]
Reclassification of Transmission Expense		15.9	18.3
Reclassification of Energy Expense		$ 21.8	$ 16.3
NSTAR Electric Company [Member]
Description of Change in Estimate	Effective January 1, 2012, NSTAR Electric changed its estimates with respect to the allowance for doubtful accounts, incurred but not reported claims on medical benefits, general and workers' compensation liabilities and compensation accruals. The total aggregate impact of these changes in estimates on NSTAR Electric's accompanying consolidated statements was a decrease to net income of $11.4 million, after-tax, for the year ended December 31, 2012.

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SCHEDULE I - Balance Sheets (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Current Assets:
Cash	$ 45,748	$ 6,559	$ 23,395	$ 26,952
Receivables, Net	792,822	488,002
Prepayments and Other Current Assets	107,972	112,632
Total Current Assets	2,227,295	1,357,472
Deferred Debits and Other Assets:
Derivative Assets Noncurrent	90,612	98,357
Other Long-Term Assets	327,766	172,560
Total Deferred Debits and Other Assets	9,470,519	3,886,529
Total Assets	28,302,824	15,647,066
Current Liabilities:
Notes Payable to Banks	1,120,196	317,000
Long-Term Debt - Current Portion	763,338	331,582
Accounts Payable - Current	764,350	633,282
Other Liabilities - Current	744,497	390,416
Total Current Liabilities	3,643,690	1,947,682
Deferred Credits and Other Liabilities:
Other Long-Term Liabilities	967,561	420,011
Total Deferred Credits and Other Liabilities	7,984,221	4,840,385
Capitalization:
Long-Term Debt	7,200,156	4,614,913
Common Shareholders' Equity:
Common Stock	1,662,547	980,264
Capital Surplus, Paid In	6,183,267	1,797,884
Retained Earnings	1,802,714	1,651,875
Accumulated Other Comprehensive Loss	72,854	70,686
Treasury Stock	(338,624)	(346,667)
Common Shareholders' Equity	9,237,050	4,012,670
Noncontrolling Interest	0	2,956
Total Equity	9,237,050	4,015,626
Total Capitalization	16,592,774	8,746,739
Total Liabilities and Capitalization	28,302,824	15,647,066
Nu Parent [Member]
Current Assets:
Cash	250	62	268	1,222
Notes Receivable from Affiliated Companies	1,025,000	113,200
Receivables, Net	1	2,735
Accounts Receivable from Affiliated Companies	11,173	1,749
Taxes Receivable	11,220	5,308
Prepayments and Other Current Assets	2,665	4,610
Total Current Assets	1,050,309	127,664
Deferred Debits and Other Assets:
Equity Method Investments	9,874,692	4,566,865
Notes Receivable, Related Parties, Noncurrent	25,000	62,500
Deferred Tax Assets, Net, Noncurrent	67,619	39,405
Other Long-Term Assets	12,597	9,979
Total Deferred Debits and Other Assets	9,979,908	4,678,749
Total Assets	11,030,217	4,806,413
Current Liabilities:
Notes Payable to Banks	1,150,000	256,000
Long-Term Debt - Current Portion	549,992	265,296
Accounts Payable - Current	9,854	266
Accounts Payable to Affiliated Companies	27,559	141
Accrued Taxes	7,509	0
Accrued Interest	4,943	8,735
Other Liabilities - Current	26,825	865
Total Current Liabilities	1,776,682	531,303
Deferred Credits and Other Liabilities:
Other Long-Term Liabilities	16,485	9,511
Total Deferred Credits and Other Liabilities	16,485	9,511
Capitalization:
Long-Term Debt	0	249,973
Common Shareholders' Equity:
Common Stock	1,662,547	980,264
Capital Surplus, Paid In	6,183,267	1,797,884
Retained Earnings	1,802,714	1,651,875
Accumulated Other Comprehensive Loss	(72,854)	(70,686)
Treasury Stock	(338,624)	(346,667)
Common Shareholders' Equity	9,237,050	4,012,670
Noncontrolling Interest	0	2,956
Total Equity	9,237,050	4,015,626
Total Capitalization	9,237,050	4,265,599
Total Liabilities and Capitalization	$ 11,030,217	$ 4,806,413

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

12 Months Ended

Dec. 31, 2012

Notes To Consolidated Financial Statements [Abstract]

Significant Accounting Policies [Text Block]

NORTHEAST UTILITIES AND SUBSIDIARIES

THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARY

NSTAR ELECTRIC COMPANY AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES

WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Refer to the Glossary of Terms included in this combined Annual Report on Form 10-K for abbreviations and acronyms used throughout the combined notes to the consolidated financial statements.

1.       SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

A.       About NU, CL&P, NSTAR Electric, PSNH and WMECO

NU Consolidated:NU is a public utility holding company primarily engaged through its wholly owned regulated utility subsidiaries in the energy delivery business. NU's wholly owned regulated utility subsidiaries included CL&P, PSNH, WMECO and Yankee Gas prior to NU's merger with NSTAR. On April 10, 2012, NU acquired 100 percent of the outstanding common shares of NSTAR,at which time NSTAR (through a successor, NSTAR LLC) became a direct wholly owned subsidiary of NU along with its regulated utility subsidiaries, NSTAR Electric and NSTAR Gas. NU provides energy delivery service to approximately 3.5 million electric and natural gas customers through six regulated utilities in Connecticut, Massachusetts and New Hampshire. See Note2, "Merger of NU and NSTAR," for further information regarding the merger.

NU, CL&P, NSTAR Electric, PSNH and WMECO are reporting companies under the Securities Exchange Act of 1934. NU is a public utility holding company under the Public Utility Holding Company Act of 2005. Arrangements among the regulated electric companies and other NU companies, outside agencies and other utilities covering interconnections, interchange of electric power and sales of utility property are subject to regulation by the FERC. The Regulated companies are subject to regulation of rates, accounting and other matters by the FERC and/or applicable state regulatory commissions (the PURA for CL&P and Yankee Gas, the DPU for NSTAR Electric, NSTAR Gas and WMECO,and the NHPUC as well as certain regulatory oversight by the Vermont Public Service Board and the Maine Public Utilities Commission for PSNH).

Regulated Companies: CL&P, NSTAR Electric, PSNH and WMECO furnish franchised retail electric service in Connecticut, Massachusetts and New Hampshire. NSTAR Gas is engaged in the distribution and sale of natural gas to customers within central and eastern Massachusetts.Yankee Gas owns and operates Connecticut's largest natural gas distribution system. CL&P, NSTAR Electric, PSNH and WMECO's results include the operations of their respective distribution and transmission businesses. PSNH and WMECO's distribution results include the operations of their respective generation businesses. NU also has a regulated subsidiary, NPT, which was formed to construct, own and operate the Northern Pass line, a new HVDC transmission line from Québec to New Hampshire that will interconnect with a new HVDC transmission line being developed by a transmission subsidiary of HQ.

Other: As of December 31, 2012, NU Enterprises' primary business consisted of Select Energy'sremaining energy wholesale marketing contractswith a municipal authority that expires on December 31, 2013 and related purchase contracts and NGS' operation and maintenance agreements as well as its subsidiary, E.S. Boulos Company, an electrical contractor based in Maine that NU Enterprises continues to own and manage. NUSCO,NSTAR Electric & Gas, RRR, Renewable Properties, Inc. and Properties, Inc. provide support services to NU, including its regulated companies. Harbor Electric Energy Company, a wholly-owned subsidiary ofNSTAR Electric, provides distribution service and ongoing support to its only customer, the Massachusetts Water Resources Authority. NSTAR also has unregulated subsidiaries in telecommunications (NSTAR Communications, Inc.) and natural gas liquefaction and storage services (Hopkinton).

B.       Basis of Presentation

The consolidated financial statements of NU, CL&P, NSTAR Electric, PSNH and WMECO include the accounts of each of their respective subsidiaries. Intercompany transactions have been eliminated in consolidation.

The preparation of the consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent liabilities as of the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

NSTAR Electric continues to maintain reporting requirements as an SEC registrant. The information disclosed for NSTAR Electric represents its results of operations for each of the years ended December 31, 2012, 2011 and 2010 and the financial position as of December 31, 2012 and 2011, presented on a comparable basis. NU did not apply "push-down accounting" to NSTAR Electric, whereby the adjustments of assets and liabilities to fair value and the resultant goodwill would be shown on the financial statements of the acquired subsidiary. NU's consolidated financial information includes NSTAR LLC and its subsidiaries' results of operations from April 10, 2012 through December 31, 2012.

On April 10, 2012, upon consummation of the merger with NSTAR, NSTAR Electric's ownership in CYAPC and YAEC combined with CL&P's, PSNH's and WMECO's respective ownership interests in CYAPC and YAEC totaled greater than 50 percent, requiring NU to consolidate CYAPC and YAEC from April 10, 2012 and forward. The investment in CYAPC and YAEC had previously been accounted for under the equity method by NU. The consolidation of CYAPC and YAEC results in NU recording nuclear decommissioning trust marketable securities of $340.4 million, regulatory assets of $214 million, long-term debt associated with the long-term spent nuclear fuel disposal liabilities of $179.3 million, net accumulated deferred income tax liability of $56.4 million and asset retirement obligations related to decommissioning activity of $311.4 million as of December 31, 2012. At the NU consolidated level, intercompany transactions between CL&P, NSTAR Electric, PSNH and WMECO and the CYAPC and YAEC companies have been eliminated in consolidation. For CL&P, NSTAR Electric, PSNH and WMECO, the investment in CYAPC and YAEC continue to be accounted for under the equity method. See Note 1J, "Summary of Significant Accounting Policies – Equity Method Investments," for further information.

NPT, a limited liability company, was formed to construct, own and operate the NorthernPass transmission project. NPT and Hydro Renewable Energy entered into a TSA whereby NPT will sell to Hydro Renewable Energy electric transmission rights over the NorthernPass for a 40-year term at cost of service rates. NPT will be required to maintain a capital structure of 50 percent debt and 50 percent equity. On April 10, 2012, upon consummation of the merger with NSTAR, an NSTAR subsidiary that owned 25 percent of NPTwas merged into NUTV, resulting in NUTV owning 100 percent of NPT. Accordingly, 100 percent ownership of NPT was reflected in Common Shareholders' Equity as of December 31, 2012 on the accompanying consolidated balance sheet. See Note 2, "Merger of NU and NSTAR," and Note 19, "Common Shareholders' Equity and Noncontrolling Interests," for further information.

NU's utility subsidiaries are subject to the application of accounting guidance for entities with rate-regulated operations that considers the effect of regulation resulting from differences in the timing of the recognition of certain revenues and expenses from those of other businesses and industries. NU's utility subsidiaries' energy delivery business is subject to rate-regulation that is based on cost recovery and meets the criteria for application of rate-regulated accounting. See Note 3, "Regulatory Accounting," for further information.

Certain prior year amounts in NSTAR Electric's accompanying consolidated balance sheet, statements of income and cash flows have been reclassified between line items for comparative purposes and in order to conform to NU's presentation. The reclassifications did not affect NSTAR Electric's net income.The NSTAR Electric consolidated statements of cash flows were revised tocorrect an error in the presentation of cash deposits related to the RRBs.
The impact of this revision was an increase in investing cash inflows fromOther Investing Activities in an amount of $1.7 million and $24.1 millionand a corresponding increase to financing cash outflows from Retirements of
Rate Reduction Bonds for the years ended December 31, 2011 and 2010, respectively. These revisions had no impact on NSTAR Electric's resultsof operations or cash balance and are not deemed material, individually or
in the aggregate, to the previously issued consolidated financialstatements.

Certain changes in classification and corresponding reclassifications of prior year data were made in the accompanying consolidated balance sheets and statements of income for NU, CL&P, PSNH and WMECO and statements of cash flows for NU, CL&P and WMECO for comparative purposes to conform the current year presentation. The consolidated statements of income reflect the reclassification of transmission expenses from Other Operating Expenses, as originally reported, to Purchased Power, Fuel and Transmission and the reclassification of energy efficiency expenses primarily from Other Operating Expenses, as originally reported, to Energy Efficiency Programs. In addition, Other Operating Expenses and Maintenance, as originally reported, were combined and are reported in aggregate as Operations and Maintenance. The reclassifications on the statements of income were as follows:

	Transmission Expense				Energy Efficiency Expense
	For the Years Ended December 31,				For the Years Ended December 31,
(Millions of Dollars)	2011		2010		2011		2010
NU	$	77.2	$	48.9	$	131.4	$	124.0
CL&P		52.6		39.4		90.3		92.3
PSNH		19.1		26.4		12.9		12.0
WMECO		15.9		18.3		21.8		16.3

Effective January 1, 2012, NSTAR Electric changed its estimates with respect to the allowance for doubtful accounts, incurred but not reported claims on medical benefits, general and workers' compensation liabilities and compensation accruals. The total aggregate impact of these changes in estimates on NSTAR Electric's accompanying consolidated statements was a decrease to net income of $11.4 million, after-tax, for the year ended December 31, 2012.

In accordance with accounting guidance on noncontrolling interests in consolidated financial statements, the Preferred Stock of CL&P and the Preferred Stock of NSTAR Electric, which are not owned by NU or its consolidated subsidiaries and are not subject to mandatory redemption, have been presented as noncontrolling interests in the accompanying consolidated financial statements of NU.  The Preferred Stock of CL&P and the Preferred Stock of NSTAR Electricare considered to be temporary equity and have been classified between liabilities and permanent shareholders' equity on the accompanying consolidated balance sheets of NU, CL&P and NSTAR Electric due to a provision in thepreferred stock agreements of both CL&P and NSTAR Electric that grant preferred stockholders the right to elect a majority of theCL&P and NSTAR Electric Board of Directors, respectively, should certain conditions exist, such as if preferred dividends are in arrears for a specified amount of time.  The Net Income reported in the accompanying consolidated statements of income and cash flows represents consolidated net income prior to apportionment to noncontrolling interests, which is represented by dividends on preferred stock of CL&P and NSTAR Electric.

NU evaluates events and transactions that occur after the balance sheet date but before financial statements are issued and recognizes in the financial statements the effects of all subsequent events that provide additional evidence about conditions that existed as of the balance sheet date and discloses, but does not recognize, in the financial statements subsequent events that provide evidence about the conditions that arose after the balance sheet date but before the financial statements are issued. See Note 23, "Subsequent Events," for further information.

C.       Recently Adopted Accounting Standards

In the first quarter of 2012, NU adopted the Financial Accounting Standards Board's (FASB) final Accounting Standards Update (ASU) on fair value measurement. The ASU did not have an impact on NU's financial position, results of operations or cash flows, but required additional financial statement disclosures related to fair value measurements. For further information, see Note 5, "Derivative Instruments," to the consolidated financial statements.

In the first quarter of 2012, NU adopted the FASB's final ASU on testing goodwill for impairment. The ASU provides the election to perform a qualitative assessment to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying value; if so, quantitative testing is required. The ASU does not change existing guidance relating to when an entity should test goodwill for impairment or the methodology to be utilized in performing quantitative testing. NU did not utilize the election provided by this ASU in its current year evaluation of goodwill.

In the first quarter of 2012, NU adopted the FASB's final ASU on the presentation of comprehensive income. The ASU does not change existing guidance on which items should be presented in other comprehensive income but requires other comprehensive income to be presented as part of a single continuous statement of comprehensive income or in a statement of other comprehensive income immediately following the statement of net income. The ASU did not affect the calculation of net income, comprehensive income or EPS.The ASU did not have an impact on NU's financial position, results of operations or cash flows.

D.       Cash and Cash Equivalents

Cash and cash equivalents include cash on hand and short-term cash investments that are highly liquid in nature and have original maturities of three months or less. At the end of each reporting period, any overdraft amounts are reclassified from Cash and Cash Equivalents to Accounts Payable on the accompanying consolidated balance sheets.

E.Provision for Uncollectible Accounts

NU, including CL&P, NSTAR Electric, PSNH and WMECO, presents its receivables at net realizable value by maintaining a provision for uncollectible accounts receivables. This provision is determined based upon a variety of factors, including applying an estimated uncollectible account percentage to each receivable aging category, based upon historical collection and write-off experience and management's assessment of collectibility from individual customers. Management assesses the collectibility of receivables, and if circumstances change, collectibility estimates are adjusted accordingly. Receivable balances are written off against the provision for uncollectible accounts when the accounts are terminated and these balances are deemed to be uncollectible.

The PURA allows CL&P and Yankee Gas to accelerate the recovery of accounts receivable balances attributable to qualified customers under financial or medical duress (uncollectible hardship accounts receivable) outstanding for greater than 90 days. As a result of the January 2011 DPU rate case decision, WMECO is allowed to recover amounts associated with basic service and certain uncollectible hardship accounts receivable in rates. As of December 31, 2012, CL&P, WMECO and Yankee Gas had uncollectible hardship accounts receivable reserves in the amount of $65.2 million, $4.7million and $6.4 million, respectively, with the corresponding bad debt expense recorded as Regulatory Assets or Other Long-Term Assets as these amounts are probable of recovery. As of December 31, 2011, these amounts totaled $68.6 million, $5.4million and $6.8million, respectively. These amounts are reflected in the total provision for uncollectible accounts in the table below.

The provision for uncollectible accounts, which is included in Receivables, Net on the accompanying consolidated balance sheets, wasas follows:

	As of December 31,
(Millions of Dollars)	2012		2011
NU (2)	$	165.5	$	115.7
CL&P (2)		77.6		83.5
NSTAR Electric (1)		44.1		27.1
PSNH		6.8		7.2
WMECO (2)		8.5		10.0

(1)NSTAR Electric amounts are not included in NU consolidated as of December 31, 2011.

(2)NU, CL&P and WMECO balances as of December 31, 2011 have been reclassified to include the uncollectible hardship reserve in the total provision for uncollectible accounts.

F.       Fuel, Materials and Supplies and Allowance Inventory

Fuel, Materials and Supplies include natural gas, coal, biomass, oil and materials purchased primarily for construction or operation and maintenance purposes. Natural gas inventory, coal, biomass, and oil are valued at their respective weighted average cost. Materials and supplies are valued at the lower of average cost or market.

PSNH is subject to federal and state laws and regulations that regulate emissions of air pollutants, including SO2, CO2, and NOx related to its regulated generation units, and uses SO2, CO2, and NOx emissions allowances. At the end of each compliance period, PSNH is required to relinquish SO2, CO2, and NOx emissions allowances corresponding to the actual respective emissions emitted by its generating units over the compliance period. SO2 and NOx emissions allowances are obtained through an annual allocation from the federal and state regulators that are granted at no cost and through purchases from third parties. CO2 emissions allowances are acquired through auctions and through purchases from third parties.

SO2, CO2, and NOx emissions allowances are recorded within Fuel, Materials and Supplies and are classified on the balance sheet as short-term or long-term depending on the period in which they are expected to be utilized against actual emissions. As of December 31, 2012 and 2011, PSNH had $0.4 million and $0.8 million, respectively, of short-term SO2, CO2, and NOx emissions allowances classified as Fuel, Materials and Supplies on the accompanying consolidated balance sheets and $19.4 million and $19.4 million, respectively, of long-term SO2 and CO2 emissions allowances classified as Other Long-Term Assets on the accompanying consolidated balance sheets.

SO2, CO2, and NOx emissions allowances are charged to expense based on their weighted average cost as they are utilized against emissions volumes at PSNH's generating units. PSNH recorded expenses of $0.4 million, $5.1 million and $6.6million for the years ended December 31, 2012, 2011, and 2010, respectively, which were included in Purchased Power, Fuel and Transmission on the accompanying consolidated statements of income. These costs are recovered from customers through energy supply revenues.

G.Restricted Cash and Other Deposits

As of December 31, 2012, NU, CL&P and PSNH had $3.3million, $1.3 million and $1.7million, respectively, of restricted cash, primarily relating to amounts held in escrow, insurance proceeds on bondable property at PSNH and amounts related to the sale of land, which were included in Prepayments and Other Current Assets on the accompanying consolidated balance sheets. As of December 31, 2011,these amounts were $17.9 million, $9.4 million and $7 million for NU, CL&P and PSNH, respectively.

As of December 31, 2012, NU had $14.6million of cash collateral posted not subject to master netting agreements, primarily with ISO-NE. As of December 31, 2011, there was no cash posted with ISO-NE and $10.9 million posted with other counterparties.

As of December 31, 2012,NU, NSTAR Electric, PSNH and WMECO had $69.4 million, $42.2 million, $22 million and $5.1 million, respectively, on deposit related to subsidiaries used to facilitate the issuance of RRBs.As of December 31, 2011, these amounts were $29.5 million, $40.9 million, $24.4 million and $5.1 million, respectively. These amounts are included in Prepayments and Other Current Assets and Other Long-Term Assets on the accompanying consolidated balance sheets.As of December 31, 2011, the NSTAR Electric amount was not included in NU consolidated.

H.       Fair Value Measurements

NU, including CL&P, NSTAR Electric, PSNH, and WMECO, applies fair value measurement guidance to derivative contracts recorded at fair value and to the marketable securities held in the NU supplemental benefit trust, WMECO's spent nuclear fuel trust and CYAPC's and YAEC's nuclear decommissioning trusts. Fair value measurement guidance is also applied to investment valuations used to calculate the funded status of NU's Pension and PBOP Plans, including NSTAR Electric's Pension Plan, and nonrecurring fair value measurements of nonfinancial assets such as goodwill and AROs.

Fair Value Hierarchy: In measuring fair value, NU uses observable market data when available and minimizes the use of unobservable inputs. Inputs used in fair value measurements are categorized into three fair value hierarchy levels for disclosure purposes. The entire fair value measurement is categorized based on the lowest level of input that is significant to the fair value measurement. NU evaluates the classification of assets and liabilities measured at fair value on a quarterly basis, and NU's policy is to recognize transfers between levels of the fair value hierarchy as of the end of the reporting period. The three levels of the fair value hierarchy are described below:

Level 1 - Inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities as of the reporting date.  Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

Level 2 - Inputs are quoted prices for similar instruments in active markets, quoted prices for identical or similar instruments in markets that are not active, and model-derived valuations in which all significant inputs are observable.

Level 3 - Quoted market prices are not available. Fair value is derived from valuation techniques in which one or more significant inputs or assumptions are unobservable. Where possible, valuation techniques incorporate observable market inputs that can be validated to external sources such as industry exchanges, including prices of energy and energy-related products.

Determination of Fair Value: The valuation techniques and inputs used in NU's fair value measurements are described in Note 2, "Merger of NU and NSTAR," Note 5, "Derivative Instruments," Note 6, "Marketable Securities,"Note 7, "Asset Retirement Obligations," and Note 14, "Fair Value of Financial Instruments," to the consolidated financial statements.

I.       Derivative Accounting

Many of CL&P's, NSTAR Electric's, PSNH's and WMECO's contracts for the purchase and sale of energy or energy-related products are derivatives, along with NU Enterprises' remaining wholesale marketing contracts and NSTAR Gas' NYMEX futures. The accounting treatment for energy contracts entered into varies and depends on the intended use of the particular contract and on whether or not the contract is a derivative.

The application of derivative accounting is complex and requires management judgment in the following respects: identification of derivatives and embedded derivatives, election and designation of the "normal purchases or normal sales" (normal) exception, identifying, electing and designating hedge relationships, assessing and measuring hedge effectiveness, and determining the fair value of derivatives. All of these judgmentscan have a significant impact on the consolidated financial statements. Any change in the fair value of derivatives related to the Regulated companies is offset by a regulatory asset or liability, as this change will be recovered from or refunded to customers in future rates.

The fair value of derivatives is based upon the contract terms and conditions and the underlying market price or fair value per unit. When quantities are not specified in the contract, the Company determines whether the contract has a determinable quantity by using amounts referenced in default provisions and other relevant sections of the contract. The fair value of derivative assets and liabilities with the same counterparty are offset and recorded as a net derivative asset or liability on the consolidated balance sheets.

The judgment applied in the election of the normal exception (and resulting accrual accounting) includes the conclusion that it is probable at the inception of the contract and throughout its term that it will result in physical delivery of the underlying product and that the quantities will be used or sold by the business in the normal course of business. If facts and circumstances change and management can no longer support this conclusion, then the normal exception and accrual accounting is terminated and fair value accounting is applied prospectively.

The remaining wholesale marketing contracts that are marked-to-market derivative contracts are not considered to be held for trading purposes, and sales and purchase activity is reported on a net basis in Purchased Power, Fuel and Transmission on the accompanying consolidated statements of income.

For further information regarding derivative contracts of NU, CL&P, NSTAR Electricand WMECO and their accounting, see Note 5, "Derivative Instruments," to the consolidated financial statements.

J.       Equity Method Investments

Regional Decommissioned Nuclear Companies: CL&P, NSTAR Electric, PSNH and WMECO own common stock in three regional nuclear generation companies (CYAPC, YAEC and MYAPC, collectively referred to as the Yankee Companies), each of which owned a single nuclear generating facility that has been decommissioned. On April 10, 2012, upon consummation of the merger with NSTAR, NSTAR Electric's ownership in CYAPC and YAEC combined with CL&P's, PSNH's and WMECO's respective ownership interests in CYAPC and YAEC totaled greater than 50 percent, requiring NU to consolidate CYAPC and YAEC from April 10, 2012 and forward. The investment in CYAPC and YAEC had previously been accounted for under the equity method of accounting by NU. For CL&P, NSTAR Electric, PSNH and WMECO, the investment in CYAPC and YAEC continues to be accounted for under the equity method. At the NU consolidated level, intercompany transactions between CL&P, NSTAR Electric, PSNH and WMECO and the CYAPC and YAEC companies have been eliminated in consolidation.

Ownership interests in the Yankee Companies as of December 31, 2012 and 2011were as follows:

(Percent)	CYAPC	YAEC	MYAPC
CL&P	34.5	24.5	12.0
NSTAR Electric	14.0	14.0	4.0
PSNH	5.0	7.0	5.0
WMECO	9.5	7.0	3.0

The total carrying values of CL&P's, NSTAR Electric's, PSNH's and WMECO's ownership interests in CYAPC, YAEC and MYAPC, which are included in Other Long-Term Assets on their respective accompanying consolidated balance sheets are as follows:

	As of December 31,
(Millions of Dollars)	2012		2011 (1)
CL&P	$	1.4	$	1.4
NSTAR Electric		0.6		0.6
PSNH		0.3		0.3
WMECO		0.4		0.4

(1)The NSTAR Electric carrying value was not included in NU consolidated as of December 31, 2011.

For further information on the Yankee Companies, see Note 12C, "Commitments and Contingencies - Deferred Contractual Obligations," to the consolidated financial statements.

Other Investments: As of December 31, 2012, NU had a 37.2 percent (14.5 percent of which related to NSTAR Electric) equity ownership interest in two companies that transmit electricity imported from the Hydro-Québec system in Canada. Prior to the merger with NSTAR on April 10, 2012, NU had a 22.7 percent equity ownership interest in these companies. These investments are accounted for under the equity method of accounting. NU's investment totaled $6 million and $4.6 million as of December 31, 2012 and 2011, respectively, and NSTAR Electric's investment totaled $2.3 million and $3 million as of December31, 2012 and 2011, respectively. The NSTAR Electric investment was not included in NU consolidated as of December 31, 2011. As of December 31, 2012 and 2011, NUalso had an equity ownershipinterest of $6.8million and $4.2 million in an energy investment fund, respectively.

Equity investments are included in Other Long-Term Assets on the accompanying consolidated balance sheets and net earnings related to these equity investments are included in Other Income, Net on the accompanying consolidated statements of income.

K.       Revenues

Regulated Companies: The Regulated companies' retail revenues are based on rates approved by the state regulatory commissions. In general, rates can only be changed through formal proceedings with the state regulatory commissions. The Regulated companies' rates are designed to recover their incurred costs, plus an allowed rate of return on certain unrecovered costs. The Regulated companies also utilize regulatory commission-approved tracking mechanisms to recover certain costs on a fully-reconciling basis. These tracking mechanisms require rates to be changed periodically, with overcollections refunded to customers or undercollections collected from customers in future periods. Beginning in 2011, WMECO was allowed to establish a revenue decoupling mechanism to recover a pre-established level of baseline distribution delivery service revenues per year, independent of actual customer usage. Such decoupling mechanisms effectively break the relationship between kWhs consumed by customers and revenues recognized.

Energy purchases under derivative instruments are recorded in Purchased Power, Fuel, and Transmission, and sales of energy associated with these purchases are recorded in Operating Revenues.

Regulated Companies' Unbilled Revenues: Because customers are billed throughout the month based on pre-determined cycles rather than on a calendar month basis, an estimate of electricity or natural gas delivered to customers for which the customers have not yet been billed is calculated as of the balance sheet date. Unbilled revenues are included in Operating Revenues on the consolidated statements of income and are assets on the consolidated balance sheets. Actual amounts billed to customers when meter readings become available may vary from the estimated amount.

The Regulated companies estimate unbilled sales monthly using the daily load cycle method. The daily load cycle method allocates billed sales to the current calendar month based on the daily load for each billing cycle. The billed sales are subtracted from total month load, net of delivery losses, to estimate unbilled sales. Unbilled revenues are estimated by first allocating unbilled sales to the respective customer classes, then applying an estimated rate by customer class to those sales.

Regulated Companies' Transmission Revenues - Wholesale Rates:   Wholesale transmission revenues are based on formula rates that are approved by the FERC. Wholesale transmission revenues for CL&P, NSTAR Electric, PSNH, and WMECO are collected under the ISO New England Inc. Transmission, Markets and Services Tariff (ISO-NE Tariff). The ISO-NE Tariff includes Regional Network Service (RNS) and Schedule 21 - NU rate schedules to recover fees for transmission and other services for CL&P, PSNH and WMECO and the Schedule 21 - NSTAR rate schedules recover fees and other services for NSTAR Electric. The RNS rate, administered by ISO-NE and billed to all New England transmission users, including CL&P, NSTAR Electric, PSNH and WMECO's transmission businesses, is reset on June 1st of each year and recovers the revenue requirements associated with transmission facilities that benefit the entire New England region. The Schedule 21 - NU and Schedule 21 - NSTAR rates, administered by NU, recover the revenue requirements for local transmission facilities and other transmission costs not recovered under the RNS rate. The Schedule 21-NU rate is reset on January 1st and June 1st of each year, while the Schedule 21-NSTAR rate is reset on June 1st of each year. The Schedule 21 - NU and Schedule 21 - NSTAR rate calculations recover total transmission revenue requirements net of revenues received from other sources (i.e., RNS, rentals, etc.), thereby ensuring that NU recovers all of CL&P's, NSTAR Electric's, PSNH's and WMECO's regional and local revenue requirements as prescribed in the ISO-NE Tariff. The RNS and Schedule 21 - NU and Schedule 21 - NSTAR rates provide for the annual reconciliation and recovery or refund of estimated (or projected) costs to actual costs. The financial impacts of differences between actual and projected costs are deferred for future recovery from, or refunded to, transmission customers.

Regulated Companies' Transmission Revenues - Retail Rates: A significant portion of the NU transmission segment revenue comes from ISO-NE charges to the distribution businesses of CL&P, NSTAR Electric, PSNH and WMECO, each of which recovers these costs through rates charged to their retail customers. CL&P, NSTAR Electric, PSNH and WMECO each have a retail transmission cost tracking mechanism as part of their rates, which allows the electric distribution companies to charge their retail customers for transmission costs on a timely basis.

L.       Operating Expenses

Costs related to fuel (and natural gas costs as it related to Yankee Gas and NSTAR Gas) included in Purchased Power, Fuel and Transmission on the accompanying consolidated statements of income were as follows:

	For the Years Ended December 31,
(Millions of Dollars)	2012(1)		2011		2010
NU	$	346.8	$	307.9	$	391.6
PSNH		103.4		115.9		184.3
Yankee Gas		145.9		191.3		206.4
NSTAR Gas		97.2		N/A		N/A
(1) Includes the NSTAR Gas costs from the date of the merger, April 10, 2012, through December 31, 2012.

M.       Allowance for Funds Used During Construction

AFUDC represents the cost of borrowed and equity funds used to finance construction and is included in the cost of the Regulated companies' utility plant. The portion of AFUDC attributable to borrowed funds is recorded as a reduction of Other Interest Expense, and the AFUDC related to equity funds is recorded as Other Income, Net on the accompanying consolidated statements of income. AFUDC costs are recovered from customers over the service life of the related plant in the form of increased revenue collected as a result of higher depreciation expense.

NU		For the Years Ended December 31,
(Millions of Dollars, except percentages)		2012		2011		2010
AFUDC:
	Borrowed Funds	$	5.3	$	11.8	$	10.2
	Equity Funds		6.8		22.5		16.7
Total		$	12.1	$	34.3	$	26.9
Average AFUDC Rate			3.7%		7.3%		7.1%

		For the Years Ended December 31,
		2012								2011								2010
(Millions of Dollars,				NSTAR								NSTAR								NSTAR
except percentages)		CL&P		Electric(1)		PSNH		WMECO		CL&P		Electric(1)		PSNH		WMECO		CL&P		Electric(1)		PSNH		WMECO
AFUDC:
	Borrowed Funds	$	2.5	$	0.3	$	1.6	$	0.5	$	3.3	$	0.2	$	7.1	$	0.5	$	2.7	$	0.1	$	6.6	$	0.3
	Equity Funds		1.9		-		1.9		1.0		6.0		-		13.2		1.0		4.9		-		10.4		0.6
Total		$	4.4	$	0.3	$	3.5	$	1.5	$	9.3	$	0.2	$	20.3	$	1.5	$	7.6	$	0.1	$	17.0	$	0.9
Average AFUDC Rate			3.6%		0.4%		5.9%		6.8%		8.3%		0.3%		7.1%		7.4%		8.3%		0.3%		6.8%		6.4%

• NSTAR Electric amounts are included in NU consolidated from the date of the merger, April 10, 2012, through December 31, 2012. NSTAR Electric amounts are not included in NU consolidated for the years ended December 31, 2011 and 2010.

The Regulated companies' average AFUDC rate is based on a FERC-prescribed formula that produces an average rate using the cost of a company's short-term financings as well as a company's capitalization (preferred stock, long-term debt and common equity). The average rate is applied to average eligible CWIP amounts to calculate AFUDC.

N.Other Income, Net

Items included within Other Income, Net on the accompanying consolidated statements of income primarily consist of investment income/(loss), interest income, AFUDC related to equity funds and equity in earnings.For CL&P, NSTAR Electric, PSNH and WMECO, equity in earnings relate to investments in CYAPC, YAEC and MYAPC and also NSTAR Electric's investment in two regional transmission companies, which are all accounted for on the equity method. On an NU consolidated basis, equity in earnings relate to the investment in MYAPC and NU's investment in two regional transmission companies.

O.Other Taxes

Gross receipts taxes levied by the state of Connecticut are collected by CL&P and Yankee Gas from their respective customers. These gross receipts taxes are shown on a gross basis with collections in Operating Revenues and payments in Taxes Other Than Income Taxes on the accompanying consolidated statements of income as follows:

	For the Years Ended December 31,
(Millions of Dollars)	2012		2011		2010
NU	$	135.0	$	137.8	$	143.7
CL&P		120.7		121.6		128.0

Certain sales taxes are also collected by CL&P, NSTAR Electric, WMECO, Yankee Gas and NSTAR Gas from their respective customers as agents for state and local governments and are recorded on a net basis with no impact on the accompanying consolidated statements of income.

P.		Supplemental Cash Flow Information
NU			As of and For the Years Ended December 31,
(Millions of Dollars)			2012		2011		2010
Cash Paid/(Received) During the Year for:
	Interest, Net of Amounts Capitalized		$	356.5	$	256.3	$	258.3
	Income Taxes			(12.8)		(76.6)		84.5
Non-Cash Investing Activities:
	Plant Additions Included in Accounts Payable (As of)			160.6		168.5		127.9

		As of and For the Years Ended December 31,
		2012								2011								2010
				NSTAR								NSTAR								NSTAR
(Millions of Dollars)		CL&P		Electric (1)		PSNH		WMECO		CL&P		Electric (1)		PSNH		WMECO		CL&P		Electric (1)		PSNH		WMECO
Cash Paid/(Received) During
	the Year for:
	Interest, Net of Amounts
	Capitalized	$	129.4	$	94.6	$	49.8	$	25.8	$	136.6	$	96.1	$	49.3	$	22.1	$	142.2	$	95.8	$	51.4	$	20.2
	Income Taxes		(42.0)		88.1		14.7		(8.4)		(27.5)		(62.2)		(29.0)		(4.9)		71.5		147.6		1.6		5.0
Non-Cash Investing Activities:
	Plant Additions Included in
	Accounts Payable (As of)		42.8		50.0		16.8		30.0		32.7		34.3		51.1		61.3		46.2		16.7		35.8		21.2

• NSTAR Electric amounts are included in NU consolidated from the date of the merger, April 10, 2012, through December 31, 2012. NSTAR Electric amounts are not included in NU consolidated for the years ended December 31, 2011 and 2010.

The merger of NU with NSTAR on April 10, 2012 represented a significant non-cash transaction. Refer to Note 2, "Merger of NU and NSTAR," for further information on the purchase price of NSTAR.

Q.       Related Parties

NUSCO and NSTAR Electric & Gas, NU's service companies, provide centralized accounting, administrative, engineering, financial, information technology, legal, operational, planning, purchasing, and other services to NU's companies. RRR, Renewable Properties, Inc. and Properties, Inc., three other NU subsidiaries, construct, acquire or lease some of the property and facilities used by NU's companies.

As of both December 31, 2012and 2011, CL&P, PSNH and WMECO had long-term receivables from NUSCO in the amounts of $25million, $3.8million and $5.5million, respectively, which were included in Other Long-Term Assets on the accompanying consolidated balance sheets. These amounts related to the funding of investments held in trust by NUSCO in connection with certain postretirement benefits for CL&P, PSNH and WMECO employees and have been eliminated in consolidation on the NU financial statements.

NSTAR Electric's consolidated balance sheets included $70.2million and $75.9 million in Payable to Affiliated Companies as of December 31, 2012 and 2011, respectively. These amounts related to payments received from affiliates as a result of NSTAR Electric's role as the sponsor of the NSTAR Pension Plan.

Included in the CL&P, NSTAR Electric, PSNH and WMECO consolidated balance sheets as of December 31, 2012 and 2011 were Accounts Receivable from Affiliated Companies and Accounts Payable to Affiliated Companies relating to transactions between CL&P, NSTAR Electric, PSNH and WMECO and other subsidiaries that are whollyowned by NU. These amounts have been eliminated in consolidation on the NU financial statements.

The NU Foundation is an independent not-for-profit charitable entity designed to fund initiatives or entities that emphasize economic development, workforce training and education, and a clean and healthy environment. The NSTAR Foundation is an independent not-for-profit entity designed to support local charitable organizations in NSTAR's service territory that improve the quality of life for its customers.The Board of Directors of both the NU Foundation and NSTAR Foundation consist of certain NU officers. The NU Foundation and the NSTAR Foundation are not included in the consolidated financial statements of NU as they are not-for-profit entities and the Company does not have title to the Foundations' assets and cannot receive contributions back from the Foundations.

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CONSOLIDATED STATEMENTS OF INCOME (USD $) In Thousands, except Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Operating Revenues	$ 6,273,787	$ 4,465,657	$ 4,898,167
Operating Expenses:
Purchased Power and Transmission	2,084,364	1,657,914	2,034,501
Operations and Maintenance	1,583,070	1,095,358	1,001,349
Depreciation	519,010	302,192	300,737
Amortization of Regulatory Assets/(Liabilities), Net	79,762	91,080	90,054
Amortization of Rate Reduction Bonds	142,019	69,912	232,871
Energy Efficiency Programs	313,149	131,415	124,023
Taxes Other Than Income Taxes	434,207	323,610	314,741
Total Operating Expenses	5,155,581	3,671,481	4,098,276
Operating Income	1,118,206	794,176	799,891
Interest Expense:
Interest on Long-Term Debt	316,987	231,630	231,089
Interest on Rate Reduction Bonds	6,168	8,611	20,573
Other Interest	6,790	10,184	(14,371)
Total Interest Expense	329,945	250,425	237,291
Other Income/(Loss), Net	19,742	27,715	41,916
Income Before Income Tax Expense	808,003	571,466	604,516
Income Tax Expense	274,926	170,953	210,409
Net Income	533,077	400,513	394,107
Net Income Attributable to Noncontrolling Interests	7,132	5,820	6,158
Net Income Attributable to Controlling Interests	525,945	394,693	387,949
Diluted Earnings Per Common Share	$ 1.89	$ 2.22	$ 2.19
Basic Earnings Per Common Share	$ 1.90	$ 2.22	$ 2.20
Weighted Average Common Shares Outstanding:
Basic	277,209,819	177,410,167	176,636,086
Diluted	277,993,631	177,804,568	176,885,387
The Connecticut Light And Power Company [Member]
Operating Revenues	2,407,449	2,548,387	2,999,102
Operating Expenses:
Purchased Power and Transmission	858,231	982,514	1,292,733
Operations and Maintenance	635,733	580,736	494,203
Depreciation	166,853	157,747	172,167
Amortization of Regulatory Assets/(Liabilities), Net	14,372	61,025	78,870
Amortization of Rate Reduction Bonds	0	0	167,021
Energy Efficiency Programs	89,299	90,297	92,279
Taxes Other Than Income Taxes	215,972	212,885	214,179
Total Operating Expenses	1,980,460	2,085,204	2,511,452
Operating Income	426,989	463,183	487,650
Interest Expense:
Interest on Long-Term Debt	124,894	131,918	134,553
Interest on Rate Reduction Bonds	0	0	7,542
Other Interest	8,233	809	(4,357)
Total Interest Expense	133,127	132,727	137,738
Other Income/(Loss), Net	10,300	9,741	26,669
Income Before Income Tax Expense	304,162	340,197	376,581
Income Tax Expense	94,437	90,033	132,438
Net Income	209,725	250,164	244,143
Public Service Company Of New Hampshire [Member]
Operating Revenues	988,013	1,013,003	1,033,439
Operating Expenses:
Purchased Power and Transmission	319,253	327,905	389,538
Operations and Maintenance	263,234	278,153	274,165
Depreciation	87,602	76,167	67,237
Amortization of Regulatory Assets/(Liabilities), Net	(24,086)	25,383	11,232
Amortization of Rate Reduction Bonds	56,645	53,389	50,357
Energy Efficiency Programs	14,245	12,917	12,038
Taxes Other Than Income Taxes	66,025	58,985	52,686
Total Operating Expenses	782,918	832,899	857,253
Operating Income	205,095	180,104	176,186
Interest Expense:
Interest on Long-Term Debt	46,228	36,832	36,220
Interest on Rate Reduction Bonds	2,687	6,276	9,660
Other Interest	1,313	1,039	1,187
Total Interest Expense	50,228	44,147	47,067
Other Income/(Loss), Net	3,008	14,255	11,749
Income Before Income Tax Expense	157,875	150,212	140,868
Income Tax Expense	60,993	49,945	50,801
Net Income	96,882	100,267	90,067
Western Massachusetts Electric Company [Member]
Operating Revenues	441,164	417,315	395,161
Operating Expenses:
Purchased Power and Transmission	136,086	161,480	175,604
Operations and Maintenance	97,031	80,241	87,088
Depreciation	29,971	26,455	23,561
Amortization of Regulatory Assets/(Liabilities), Net	410	4,492	1,892
Amortization of Rate Reduction Bonds	17,632	16,523	15,494
Energy Efficiency Programs	27,802	21,804	16,336
Taxes Other Than Income Taxes	21,458	17,957	16,529
Total Operating Expenses	330,390	328,952	336,504
Operating Income	110,774	88,363	58,657
Interest Expense:
Interest on Long-Term Debt	23,462	20,023	17,988
Interest on Rate Reduction Bonds	1,229	2,335	3,372
Other Interest	1,943	1,254	479
Total Interest Expense	26,634	23,612	21,839
Other Income/(Loss), Net	2,503	1,489	2,597
Income Before Income Tax Expense	86,643	66,240	39,415
Income Tax Expense	32,140	23,186	16,325
Net Income	54,503	43,054	23,090
NSTAR Electric Company [Member]
Operating Revenues	2,300,997	2,403,053	2,366,201
Operating Expenses:
Purchased Power and Transmission	788,252	905,226	1,031,351
Operations and Maintenance	431,802	387,533	351,843
Depreciation	171,070	163,368	158,574
Amortization of Regulatory Assets/(Liabilities), Net	117,682	82,979	19,071
Amortization of Rate Reduction Bonds	90,322	90,322	104,481
Energy Efficiency Programs	201,234	175,747	117,091
Taxes Other Than Income Taxes	119,219	111,705	104,978
Total Operating Expenses	1,919,581	1,916,880	1,887,389
Operating Income	381,416	486,173	478,812
Interest Expense:
Interest on Long-Term Debt	87,100	90,040	90,630
Interest on Rate Reduction Bonds	3,585	7,226	11,235
Other Interest	(20,631)	(27,839)	(30,475)
Total Interest Expense	70,054	69,427	71,390
Other Income/(Loss), Net	2,846	1,434	3,173
Income Before Income Tax Expense	314,208	418,180	410,595
Income Tax Expense	123,966	165,686	162,020
Net Income	$ 190,242	$ 252,494	$ 248,575

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DEFINED CONTRIBUTION PLANS

12 Months Ended

Dec. 31, 2012

Notes To Consolidated Financial Statements [Abstract]

Compensation and Employee Benefit Plans [Text Block]

B.       Defined Contribution Plans

NU maintains two defined contribution plans on behalf of eligible participants. The NUSCO 401(k) Savings Plan covers eligible employees, including CL&P, PSNH, WMECO, and effective October 1, 2012, certain newly-hiredNSTAR Electric & Gas employees. The NSTAR 401(k) Savings Plan covers eligible employees of NSTAR Electric & Gas. These defined contribution plans provide for employee and employer contributions up to statutory limits.

The NUSCO 401(k) Savings Plan matches employee contributions up to a maximum of three percent of eligible compensation with one percent invested in cash and two percent invested in the NU common share fund. The NUSCO 401(k) Savings Plan also contains a K-Vantage feature (company contribution based on age and years of service), which covers the majority of NU non-represented employees hired on or after January 1, 2006 and certain NU bargaining unit employees, hired on or after January 1, 2007 or as subject to collective bargaining agreements. In addition, all newly hired non-represented NSTAR Electric & Gas employees and certain represented NSTAR Electric & Gas employees are eligible to participate in the K-Vantage program effective October 1, 2012 and November 1, 2012, respectively. Participants in the K-Vantage program are not eligible to actively participate in any NU defined benefit plan.

The NSTAR 401(k) Savings Plan matches employee contributions of 50 percent on up to the first 8 percent of eligible compensation. All employer contributions are invested in the NU common share fund.

The total defined contribution plan matching contributions, including the K-Vantage program contributions, are as follows:

					NSTAR
(Millions of Dollars)	NU		CL&P		Electric(1)		PSNH		WMECO
2012	$	25.7	$	4.8	$	9.0	$	3.3	$	0.9
2011		17.4		4.5		8.7		3.1		0.9
2010		16.1		4.4		8.1		2.8		0.9

• NSTAR Electric amounts are included in NU consolidated from the date of the merger, April 10, 2012, through December 31, 2012. NSTAR Electric amounts are not included in NU consolidated for the years ended December 31, 2011 and 2010.

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COMMON SHAREHOLDER EQUIT AND NCI (Details) (USD $)	3 Months Ended								12 Months Ended
	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Shareholders' Equity, Beginning Balance				$ 4,012,670,000					$ 4,012,670,000
Net Income	176,600,000	209,500,000	46,200,000	100,800,000	114,800,000	91,400,000	78,700,000	115,600,000	533,077,000	400,513,000	394,107,000
Net Income Attributable to Noncontrolling Interests									7,132,000	5,820,000	6,158,000
Other Comprehensive Income (Loss), Net of Tax									(2,168,000)	(27,316,000)	97,000
Shareholders' Equity, Ending Balance	9,237,050,000				4,012,670,000				9,237,050,000	4,012,670,000
Common Shareholders Equity [Member]
Shareholders' Equity, Beginning Balance				4,012,700,000				3,811,200,000	4,012,700,000	3,811,200,000	3,577,900,000
Net Income									533,077,000	400,513,000	394,107,000
Dividends on Common Shares									(375,527,000)	(195,595,000)	(181,715,000)
Dividends, Preferred Stock									(7,029,000)	(5,559,000)	(6,101,000)
Issuance of Common Shares									13,327,000	5,851,000	7,378,000
Other Transcations, Net									21,100,000	23,900,000	19,600,000
Net Income Attributable to Noncontrolling Interests									(103,000)	(261,000)	(57,000)
Other Comprehensive Income (Loss), Net of Tax									(2,168,000)	(27,316,000)	97,000
Shareholders' Equity, Ending Balance	9,237,100,000				4,012,700,000				9,237,100,000	4,012,700,000	3,811,200,000
Purchase Price of NSTAR									5,038,300,000
Other Impacts of Merger with NSTAR									3,400,000
Noncontrolling Interest Member
Shareholders' Equity, Beginning Balance				3,000,000				1,500,000	3,000,000	1,500,000
Contributions To Northern Pass Trans									300,000	1,200,000	1,400,000
Net Income Attributable to Noncontrolling Interests									100,000	300,000	100,000
Shareholders' Equity, Ending Balance	0				3,000,000				0	3,000,000	1,500,000
Other Impacts of Merger with NSTAR									(3,400,000)
Total Equity [Member]
Shareholders' Equity, Beginning Balance				4,015,700,000				3,812,700,000	4,015,700,000	3,812,700,000	3,577,900,000
Net Income									533,100,000	400,500,000	394,100,000
Dividends on Common Shares									(375,500,000)	(195,600,000)	(181,700,000)
Dividends, Preferred Stock									(7,000,000)	(5,600,000)	(6,100,000)
Issuance of Common Shares									13,300,000	5,900,000	7,400,000
Contributions To Northern Pass Trans									300,000	1,200,000	1,400,000
Other Transcations, Net									21,100,000	23,900,000	19,600,000
Net Income Attributable to Noncontrolling Interests									0
Other Comprehensive Income (Loss), Net of Tax									(2,200,000)	(27,300,000)	100,000
Shareholders' Equity, Ending Balance	9,237,100,000				4,015,700,000				9,237,100,000	4,015,700,000	3,812,700,000
Purchase Price of NSTAR									5,038,300,000
Preferred Stock Member
Shareholders' Equity, Beginning Balance				116,200,000				116,200,000	116,200,000	116,200,000	116,200,000
Dividends, Preferred Stock									(7,000,000)	(5,600,000)	(6,100,000)
Net Income Attributable to Noncontrolling Interests									7,000,000	5,600,000	6,100,000
Shareholders' Equity, Ending Balance	155,600,000				116,200,000				155,600,000	116,200,000	116,200,000
Other Impacts of Merger with NSTAR									$ 39,400,000

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Environmental Matters (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
Site Contingency [Line Items]
Environmental Site Quantity	77	59
Range Of Potential Loss On Enivornmental Sites	As of December 31, 2012, for 8 environmental sites (3 for CL&P, 2 for PSNH, and 1 for WMECO) that are included in the Company's reserve for environmental costs, the information known and nature of the remediation options at those sites allow for the Company to estimate the range of losses for environmental costs. As of December 31, 2012, $2.6 million ($0.6 million for CL&P and $0.7 million for PSNH) had been accrued as a liability for these sites, which represent management's best estimates of the liabilities for environmental costs. These amounts are the best estimates with estimated ranges of additional losses from zero million to $15.2 million (zero to $1.3 million for CL&P, zero to $4.1 million for PSNH, and zero to $8.6 million for WMECO). As of December 31, 2012, for 23 environmental sites (5 for CL&P,1 for NSTAR Electric, 4 for PSNH, and 3 for WMECO) included in the Company’s reserve for environmental costs, management cannot reasonably estimate the exposure to loss in excess of the reserve, or range of loss, as these sites are under investigation and/or there is significant uncertainty as to what remedial actions, if any, the Company may be required to undertake. As of December 31, 2012, $17 million ($1.7 million for CL&P, $0.2 million for PSNH, and $0.5 million for WMECO) had been accrued as a liability for these sites. As of December 31, 2012, for the remaining 46 environmental sites (11 for CL&P, 15 for NSTAR Electric, 10 for PSNH, and 2 for WMECO) included in the Company’s reserve for environmental costs, the $19.8 million accrual ($1.4 million for CL&P, $1.7 million for NSTAR Electric, $4 million for PSNH, and $0.1 million for WMECO) represents management’s best estimate of the liability and no additional loss is anticipated.
Superfund Site Information	CERCLA: The federal Comprehensive Environmental Response, Compensation and Liability Act of 1980 (CERCLA) and its amendments or state equivalents impose joint and several strict liabilities, regardless of fault, upon generators of hazardous substances resulting in removal and remediation costs and environmental damages.  Liabilities under these laws can be material and in some instances may be imposed without regard to fault or for past acts that may have been lawful at the time they occurred.  Of the total sites included in the remediation and long-term monitoring phase, 10 sites (2 for CL&P, 4 for NSTAR Electric, 4 for PSNH and 1 for WMECO) are superfund sites under CERCLA for which the Company has been notified that it is a potentially responsible party but for which the site assessment and remediation are not being managed by the Company.  As of December 31, 2012, a liability of $1 million ($0.4 million for CL&P, $0.1 million for NSTAR Electric and $0.4 million for PSNH) accrued on these sites represents management's best estimate of its potential remediation costs with respect to these superfund sites.
Accrual for Environmental Loss Contingencies [Roll Forward]
Beginning Balance	$ 31.7	$ 37.1
Environmental Liability assumed in merger	11.8
Accrual For Environmental Loss Contingencies Provision For New Losses	4.7	1.6
Accrual for Environmental Loss Contingencies, Payments	(8.8)	(7.0)
Ending Balance	39.4	31.7
Accrual For Environmental Loss Contingencies Component Amount	2.1
Site Contingency [Abstract]
Cumulative Payments Environmental Loss Contingencies	17.4
Cumulative Environmental Remediation Expense	19.5
The Connecticut Light And Power Company [Member]
Site Contingency [Line Items]
Environmental Site Quantity	19	18
Accrual for Environmental Loss Contingencies [Roll Forward]
Beginning Balance	2.9	2.8
Accrual For Environmental Loss Contingencies Provision For New Losses	1.3	0.4
Accrual for Environmental Loss Contingencies, Payments	(0.5)	(0.3)
Ending Balance	3.7	2.9
Public Service Company Of New Hampshire [Member]
Site Contingency [Line Items]
Environmental Site Quantity	16	18
Accrual for Environmental Loss Contingencies [Roll Forward]
Beginning Balance	6.6	9.1
Accrual For Environmental Loss Contingencies Provision For New Losses	0.2	0.1
Accrual for Environmental Loss Contingencies, Payments	(1.9)	(2.6)
Ending Balance	4.9	6.6
Western Massachusetts Electric Company [Member]
Site Contingency [Line Items]
Environmental Site Quantity	6	10
Accrual for Environmental Loss Contingencies [Roll Forward]
Beginning Balance	0.3	0.3
Accrual For Environmental Loss Contingencies Provision For New Losses	0.5	0.1
Accrual for Environmental Loss Contingencies, Payments	(0.2)	(0.1)
Ending Balance	0.6	0.3
NSTAR Electric Company [Member]
Site Contingency [Line Items]
Environmental Site Quantity	16	13
Accrual for Environmental Loss Contingencies [Roll Forward]
Beginning Balance	1.3	0.9
Accrual For Environmental Loss Contingencies Provision For New Losses	0.7	0.4
Accrual for Environmental Loss Contingencies, Payments	(0.3)	0
Ending Balance	$ 1.7	$ 1.3

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Share-Based Payments (Details) (USD $)	0 Months Ended	12 Months Ended
	Apr. 09, 2012	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Employee Service Share-based Compensation, Aggregate Disclosures [Abstract]
Excess Tax Benefit from Share-based Compensation, Financing Activities		$ 8,500,000	$ 1,300,000	$ 900,000
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized		4,500,000
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Available for Grant		2,502,512	2,685,615
AllocatedShareBasedCompensationExpense		25,800,000	12,300,000	10,500,000
Employee Service Share-based Compensation, Tax Benefit from Compensation Expense		10,200,000	4,900,000	4,200,000
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized		26,100,000
Description Of Compensation Cost Not Yet Recognized Period For Recognition		This cost is expected to be recognized ratably over a weighted-average period of 1.90 years for NU, 2.03 years for CL&P, 1.76 years for NSTAR Electric and 1.84 years for PSNH and WMECO.
Employee Service Share Based Compensation Awards Other Than Options Disclosures [Abstract]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period		471,323
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Weighted Average Grant Date Fair Value		$ 30.20
Share-based Compensation Arrangement By Share-based Payment Award, Equity Instruments Other Than Options, NSTAR Deferred And Performance Awards Converted Upon Merger	421,775
Share-based Compensation Arrangement By Share-based Payment Award Equity Instruments Other Than Options NSTAR Deferred And Performance Awards Converted Upon Merger, Value	15.5
Share-based Compensation Arrangement By Share-based Payment Award, Equity Instruments Other Than Options, NSTAR RSU Retention Awards Converted To NU RSU's Upon Merger	195,619
Share-based Compensation Arrangement By Share-based Payment Award, Equity Instruments Other Than Options, NSTAR RSU Retention Awards Converted To NU RSU's Upon Merger, Value	7.2
Employee Service Share Based Compensation Stock Option Disclosures [Abstract]
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Number		1,545,757	47,374	112,599	225,216
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercises in Period		(1,166,511)	(65,225)	(112,617)
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Exercise Price		$ 24.92	$ 18.78	$ 18.80	$ 18.96
ShareBasedCompensationArrangementsByShareBasedPaymentAwardOptionsExercisesInPeriodWeightedAverageExercisePrice		$ 22.53	$ 18.81	$ 19.12
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercises in Period, Total Intrinsic Value		18,700,000	1,000,000	1,000,000
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Intrinsic Value		21,900,000
Employee Service Share-based Compensation, Cash Received from Exercise of Stock Options		26,300,000
Employee Service Share-based Compensation, Tax Benefit Realized from Exercise of Stock Options		7,500,000
Share-based Compensation Arrangement By Share-based Payment Award, Options, Converted NSTAR Options Upon Merger	2,664,894
Share-based Compensation Arrangement By Share-based Payment Award, Options, Converted NSTAR Options Upon Merger, Weighted Average Exercise Price	$ 23.99
Share-based Compensation Arrangement By Share-based Payment Award, Options, Converted NSTAR Options Upon Merger, Total Value	30.5
Employee Service Share Based Compensation E S P P Disclosures [Abstract]
Stock Issued During Period, Shares, Employee Stock Purchase Plans		39,422	35,476
Employee Stock Purchase Plan Shares Remaining For Future Issuance		857,280	896,702
ESPP Discounted Purchase Price First Six Months		33.01	31.27
ESPP Discounted Purchase Price Second Six Months		37.89	32.30
Deferred Compensation Liability, Classified, Noncurrent [Abstract]
Deferred Compensation Cash-based Arrangements, Liability, Classified, Noncurrent		54,600,000	52,800,000	49,900,000
Deferred Compensation Cash-based Arrangements, Expense Pertaining to Deferred Benefits		4,700,000	4,700,000	4,200,000
The Connecticut Light And Power Company [Member]
Employee Service Share-based Compensation, Aggregate Disclosures [Abstract]
AllocatedShareBasedCompensationExpense		4,800,000	7,100,000	6,200,000
Employee Service Share-based Compensation, Tax Benefit from Compensation Expense		1,900,000	2,800,000	2,500,000
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized		5,300,000
Deferred Compensation Liability, Classified, Noncurrent [Abstract]
Deferred Compensation Cash-based Arrangements, Liability, Classified, Noncurrent		400,000	1,200,000	400,000
Deferred Compensation Cash-based Arrangements, Expense Pertaining to Deferred Benefits		2,600,000	2,600,000	2,300,000
Public Service Company Of New Hampshire [Member]
Employee Service Share-based Compensation, Aggregate Disclosures [Abstract]
AllocatedShareBasedCompensationExpense		1,800,000	2,500,000	2,100,000
Employee Service Share-based Compensation, Tax Benefit from Compensation Expense		700,000	1,000,000	900,000
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized		1,800,000
Deferred Compensation Liability, Classified, Noncurrent [Abstract]
Deferred Compensation Cash-based Arrangements, Liability, Classified, Noncurrent		2,500,000	2,500,000	2,400,000
Deferred Compensation Cash-based Arrangements, Expense Pertaining to Deferred Benefits		1,000,000	1,000,000	900,000
Western Massachusetts Electric Company [Member]
Employee Service Share-based Compensation, Aggregate Disclosures [Abstract]
AllocatedShareBasedCompensationExpense		1,000,000	1,400,000	1,100,000
Employee Service Share-based Compensation, Tax Benefit from Compensation Expense		400,000	600,000	400,000
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized		1,100,000
Deferred Compensation Liability, Classified, Noncurrent [Abstract]
Deferred Compensation Cash-based Arrangements, Liability, Classified, Noncurrent		200,000	200,000	200,000
Deferred Compensation Cash-based Arrangements, Expense Pertaining to Deferred Benefits		500,000	500,000	400,000
NSTAR Electric Company [Member]
Employee Service Share-based Compensation, Aggregate Disclosures [Abstract]
AllocatedShareBasedCompensationExpense		7,400,000	7,700,000	6,500,000
Employee Service Share-based Compensation, Tax Benefit from Compensation Expense		2,900,000	3,000,000	2,600,000
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized		$ 10,600,000
NSTAR [Member]
Employee Service Share-based Compensation, Aggregate Disclosures [Abstract]
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized		3,500,000
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Available for Grant		977,922
Restricted Stock Units (RSUs) [Member]
Employee Service Share Based Compensation Awards Other Than Options Disclosures [Abstract]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period		614,930	208,533	258,174
Share-based Compensation Arrangement by Share-based Payment Award, Shares Issued in Period		(363,779)	(244,782)	(267,951)
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeited in Period		(96,504)	(18,310)	(13,656)
Share Based Compensation Arrangement By Share Based Payment Award Equity Instruments Other Than Options Ending Balance		2,183,319	959,920	1,014,479	1,037,912
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value		$ 33.04	$ 33.87	$ 26.03
Share Based Compensation Arrangement By Share Based Payment Award Equity Instruments Other Than Options Issued In Period Weighted Average Grant Date Fair Value		$ 29.05	$ 24.47	$ 25.05
ShareBasedCompensationArrangementByShareBasedPaymentAwardEquityInstrumentsOtherThanOptionsForfeituresWeightedAverageGrantDateFairValue		$ 34.97	$ 23.74	$ 24.26
Share Based Compensation Arrangement By Share Based Payment Award Equity Instruments Other Than Options Weighted Average Grant Date Fair Value Ending Balance		$ 31.99	$ 26.36	$ 24.31	$ 24.07
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number		1,417,688	403,108
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value		$ 34.70	$ 28.70
Share Based Compensation Arrangement By Share Based Payment Award Vested Outstanding Number		765,631
Share Based Compensation Arrangement By Share Based Payment Award Expected To Vest		1,346,804
Share-based Compensation Arrangement By Share-based Payment Award Equity Instruments Other Than Options NSTAR Awards Converted To NU RSU's Upon Merger	617,394
Share-based Compensation Arrangement By Share-based Payment Award, Equity Instruments Other Than Options, NSTAR Awards Converted To NU RSU's Upon Merger, Weighted Average Grant Date Fair Value	$ 36.79
Employee Service Share Based Compensation Performance Share Disclosures [Abstract]
Share-based Compensation Arrangement By Share-based Payment Award, Performance Shares Converted To RSU's Upon Merger	451,358
Share-based Compensation Arrangement By Share-based Payment Award, Performance Shares Converted To RSU's Upon Merger, Weighted Average Grant-Date Fair Value	$ 34.32
Performance Shares [Member]
Employee Service Share Based Compensation Awards Other Than Options Disclosures [Abstract]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period		225,935	244,870	149,520
Share-based Compensation Arrangement by Share-based Payment Award, Shares Issued in Period		(106,773)
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeited in Period			(10,296)	(47)
Share Based Compensation Arrangement By Share Based Payment Award Equity Instruments Other Than Options Ending Balance		150,937	483,133	248,559	99,086
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value		$ 35.09	$ 33.76	$ 25.24
Share Based Compensation Arrangement By Share Based Payment Award Equity Instruments Other Than Options Issued In Period Weighted Average Grant Date Fair Value		$ 24.52
ShareBasedCompensationArrangementByShareBasedPaymentAwardEquityInstrumentsOtherThanOptionsForfeituresWeightedAverageGrantDateFairValue			$ 30.47	$ 23.96
Share Based Compensation Arrangement By Share Based Payment Award Equity Instruments Other Than Options Weighted Average Grant Date Fair Value Ending Balance		$ 25.04	$ 29.18	$ 24.72	$ 23.93
Employee Service Share Based Compensation Performance Share Disclosures [Abstract]
Share-based Compensation Arrangement By Share-based Payment Award, Performance Shares Converted To RSU's Upon Merger	(451,358)
Share-based Compensation Arrangement By Share-based Payment Award, Performance Shares Converted To RSU's Upon Merger, Weighted Average Grant-Date Fair Value	$ 34.32

XML

DOCUMENT AND ENTITY INFORMATION (USD $)	12 Months Ended
	Dec. 31, 2012	Jan. 31, 2013	Jun. 30, 2012
Document And Entity [Line Items]
Entity Registrant Name	NORTHEAST UTILITIES
Document Period End Date	Dec. 31, 2012
Document Type	10-K
Entity Central Index Key	0000072741
Current Fiscal Year End Date	--12-31
Entity Common Stock, Shares Outstanding		314,338,271
Entity Public Float			$ 12,177,646,948
Entity Filer Category	Large Accelerated Filer
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No
Entity Well-known Seasoned Issuer	Yes
Document Fiscal Year Focus	2012
Document Fiscal Period Focus	FY
Amendment Flag	false
The Connecticut Light And Power Company [Member]
Document And Entity [Line Items]
Entity Registrant Name	The Connecticut Light and Power Company
Entity Central Index Key	0000023426
Current Fiscal Year End Date	--12-31
Entity Filer Category	Non-accelerated Filer
Public Service Company Of New Hampshire [Member]
Document And Entity [Line Items]
Entity Registrant Name	Public Service Company of New Hampshire
Entity Central Index Key	0000315256
Current Fiscal Year End Date	--12-31
Entity Filer Category	Non-accelerated Filer
Western Massachusetts Electric Company [Member]
Document And Entity [Line Items]
Entity Registrant Name	Western Massachusetts Electric Company
Entity Central Index Key	0000106170
Current Fiscal Year End Date	--12-31
Entity Filer Category	Non-accelerated Filer
NSTAR Electric Company [Member]
Document And Entity [Line Items]
Entity Registrant Name	NSTAR Electric Company
Entity Central Index Key	0000013372
Current Fiscal Year End Date	--12-31
Entity Filer Category	Non-accelerated Filer

XML

EMPLOYEE STOCK OWNERSHIP PLAN

12 Months Ended

Dec. 31, 2012

Notes To Consolidated Financial Statements [Abstract]

Shareholders' Equity and Share-based Payments [Text Block]

C.       Employee Stock Ownership Plan

NU maintains an ESOP for purposes of allocating shares to employees participating in the NUSCO 401(k) Savings Plan. Allocations of NU common shares were made from NU treasury shares to satisfy the NUSCO 401(k) Savings Plan obligation to provide a portion of the matching contribution in NU common shares.

For treasury shares used to satisfy the 401(k) Savings Plan matching contributions, compensation expense is recognized equal to the fair value of shares that have been allocated to participants. Any difference between the fair value and the average cost of the allocated treasury shares is charged or credited to Capital Surplus, Paid In. For the years ended December 31, 2012, 2011 and 2010, NU recognized $8.9million, $8.8 million and $8.5 million, respectively, of expense related to the ESOP.

D.       Share-Based Payments

Share-based compensation awards are recorded using the fair value-based method at the date of grant. NU, CL&P, NSTAR Electric, PSNH and WMECO record compensation cost related to these awards, as applicable, for shares issued or sold to their respective employees and officers, as well as the allocation of costs associated with shares issued or sold to NU's service companies' employees and officers that support CL&P, NSTAR Electric, PSNH and WMECO.

Upon consummation of the merger with NSTAR, the NSTAR 1997 Share Incentive Plan and the NSTAR 2007 Long-Term Incentive Plan were assumed by NU. Share-based awards granted under the NSTAR Plans and held by NSTAR employees and officers were generally converted into outstanding NU share-based compensation awards with an estimated fair value of $53.2 million. Refer to Note2, "Merger of NU and NSTAR," for further information regarding the merger transaction. Specifically, as of the merger closing, and as adjusted by the exchange ratio, (1) NU converted outstanding NSTAR stock options into 2,664,894 NU stock options valued at $30.5 million, (2) NU converted NSTAR deferred shares and NSTAR performance shares into 421,775 NU RSU's valued at $15.5 million, and (3) NU converted NSTAR RSU retention awards into 195,619 NU RSU retention awards valued at $7.2 million.

NU Incentive Plan: NU maintains long-term equity-based incentive plans under the NU Incentive Plan in which NU, CL&P, PSNH and WMECO employees, officers and board members are entitled to participate. The NU Incentive Plan was approved in 2007, and authorized NU to grant up to 4,500,000 new shares for various types of awards, including RSUs and performance shares, to eligible employees, officers, and board members. As of December 31, 2012 and 2011, NU had 2,502,512and 2,685,615common shares, respectively, available for issuance under the NU Incentive Plan. In addition to the NU Incentive Plan, NU maintains an ESPP for eligible employees.

NSTAR Incentive Plans: Awards may continue to be granted following the merger under the NSTAR 2007 Long-Term Incentive Plan; however, no additional awards will be granted under the NSTAR 1997 Share Incentive Plan. The aggregate number of common shares initially authorized for issuance under the NSTAR 2007 Long-Term Incentive Plan was 3,500,000. As of December 31, 2012, there were 977,922NU common shares available for issuance under the NSTAR 2007 Long-Term Incentive Plan.

NU accounts for its various share-based plans as follows:

• RSUs - NU records compensation expense, net of estimated forfeitures, on a straight-line basis over the requisite service period based upon the fair value of NU's common shares at the date of grant. The par value of RSUs is reclassified to Common Stock from APIC as RSUs become issued as common shares.
• Performance Shares - NU records compensation expense, net of estimated forfeitures, on a straight-line basis over the requisite service period. Performance shares vest based upon the extent to which Company goals are achieved. For the majority of performance shares, fair value is based upon the value of NU's common shares at the date of grant and compensation expense is recorded based upon the probable outcome of the achievement of Company targets. For the remaining performance shares, vesting is based upon the achievement of the Company's share price as compared to an index of similar equity securities. The fair value at the date of grant for these remaining performance shares was determined using a lattice model and compensation expense is recorded over the requisite service period.
• Stock Options - Stock options issued under the NSTAR Incentive Plan that were outstandingimmediately prior to the completion of the merger with NSTARconverted into fully vested options to acquire NU common shares, as adjusted by the exchange ratio. The fair value of these awards on the merger date was included in the purchase price as it represented consideration transferred in the merger. Accordingly, no compensation expense is recorded for these stock options. Additionally, no compensation expense is recorded for stock options issued under the NU Incentive Plan as these stock options were fully vested prior to January 1, 2006.
• ESPP Shares - For shares sold under the ESPP, no compensation expense is recorded, as the ESPP qualifies as a non-compensatory plan.

RSUs:NU granted RSUs under theannual Long-Term incentive programs that are subject to three-year graded vesting schedules for employees, and one-year graded vesting schedules for board members. RSUs are paid in shares, reduced by amounts sufficient to satisfy withholdings for income taxes, subsequent to vesting. A summary of RSU transactions is as follows:

			Weighted Average
	RSUs		Grant-Date
	(Units)		Fair Value
Outstanding as of January 1, 2010		1,037,912	$	24.07
Granted		258,174	$	26.03
Shares issued		(267,951)	$	25.05
Forfeited		(13,656)	$	24.26
Outstanding as of December 31, 2010		1,014,479	$	24.31
Granted		208,533	$	33.87
Shares issued		(244,782)	$	24.47
Forfeited		(18,310)	$	23.74
Outstanding as of December 31, 2011		959,920	$	26.36
Granted		614,930	$	33.04
Converted NSTAR Awards upon Merger		617,394	$	36.79
Converted from NU Performance Shares upon Merger		451,358	$	34.32
Shares issued		(363,779)	$	29.05
Forfeited		(96,504)	$	34.97
Outstanding as of December 31, 2012		2,183,319	$	31.99

As of December 31, 2012 and 2011, the number and weighted average grant-date fair value of unvested RSUs was 1,417,688 and $34.70 per share, and 403,108and $28.70per share, respectively. The number and weighted average grant-date fair value of RSUs vested during 2012 was 471,323 and $30.20per share, respectively. As of December 31, 2012, 765,631RSUs were fully vested and an additional 1,346,804are expected to vest.

Performance Shares: NU had granted performance shares under the annual Long-Term Incentive programs that vested based upon the extent to which the Company achieved targets at the end of three-year performance measurement periods. Performance shares are paid in shares, after the performance measurement period. A summary of performance share transactions is as follows:

	Performance		Weighted Average
	Shares		Grant-Date
	(Units)		Fair Value
Outstanding as of January 1, 2010		99,086	$	23.93
Granted		149,520	$	25.24
Shares issued		-	$	-
Forfeited		(47)	$	23.96
Outstanding as of December 31, 2010		248,559	$	24.72
Granted		244,870	$	33.76
Shares issued		-	$	-
Forfeited		(10,296)	$	30.47
Outstanding as of December 31, 2011		483,133	$	29.18
Granted		225,935	$	35.09
Converted to RSUs upon Merger		(451,358)	$	34.32
Shares issued		(106,773)	$	24.52
Forfeited		-	$	-
Outstanding as of December 31, 2012		150,937	$	25.04

Upon closing of the merger with NSTAR, 451,358 performance shares under the NU 2011 and 2012 Long-Term Incentive Programs converted to RSUs according to the terms of these programs. The remaining performance shares were measured based upon a modified performance period through the date of the merger, in accordance with the terms of the NU 2010 Incentive Program, with distribution in 2013.

The total compensation cost and associated future income tax benefit recognized by NU, CL&P, NSTAR Electric, PSNH and WMECO for share-based compensation awards were as follows:

NU	For the Years Ended December 31,
(Millions of Dollars)	2012		2011		2010
Compensation Cost	$	25.8	$	12.3	$	10.5
Future Income Tax Benefit		10.2		4.9		4.2

		For the Years Ended December 31,
		2012								2011								2010
(Millions of Dollars)		CL&P		NSTAR Electric(1)		PSNH		WMECO		CL&P		NSTAR Electric(1)		PSNH		WMECO		CL&P		NSTAR Electric(1)		PSNH		WMECO
Compensation Cost		$	4.8	$	7.4	$	1.8	$	1.0	$	7.1	$	7.7	$	2.5	$	1.4	$	6.2	$	6.5	$	2.1	$	1.1
Future Income Tax
	Benefit		1.9		2.9		0.7		0.4		2.8		3.0		1.0		0.6		2.5		2.6		0.9		0.4

• NSTAR Electric amounts are included in NU consolidated from the date of the merger, April 10, 2012, through December 31, 2012. NSTAR Electric amounts are not included in NU consolidated for the years ended December 31, 2011 and 2010.

As of December 31, 2012, there was $26.1million of total unrecognized compensation cost related to nonvested share-based awards for NU, $5.3million for CL&P, $10.6million for NSTAR Electric, $1.8 million for PSNH and $1.1million for WMECO. This cost is expected to be recognized ratably over a weighted-average period of 1.90 years for NU, 2.03 years for CL&P, 1.76 years for NSTAR Electric and1.84 years for PSNH and WMECO.

For the years ended December 31, 2012, 2011 and 2010, additional tax benefits totaling $8.5million, $1.3 million and $0.9million, respectively, increased cash flows from financing activities.

Stock Options:Stock options were granted under the NU and NSTAR Incentive Plans. Options currently outstanding expire ten years from the date of grant and are fully vested. The weighted average remaining contractual lives for the options outstanding as of December 31, 2012 is 4.8 years. A summary of stock option transactions is as follows:

		Weighted Average		Intrinsic Value
	Options	Exercise Price		(Millions)
Outstanding and Exercisable - January 1, 2010	225,216	$	18.96
Exercised	(112,617)	$	19.12	$	1.0
Forfeited and Cancelled	-	$	-
Outstanding and Exercisable - December 31, 2010	112,599	$	18.80
Exercised	(65,225)	$	18.81	$	1.0
Forfeited and Cancelled	-	$	-
Outstanding and Exercisable - December 31, 2011	47,374	$	18.78
Converted NSTAR Options upon Merger	2,664,894	$	23.99
Exercised	(1,166,511)	$	22.53	$	18.7
Forfeited and Cancelled	-	$	-
Outstanding and Exercisable - December 31, 2012	1,545,757	$	24.92	$	21.9

Cash received for options exercised during the year ended December 31, 2012 totaled $26.3 million. The tax benefit realized from stock options exercised totaled $7.5million for the year ended December 31, 2012.

Employee Share Purchase Plan: NU maintains an ESPP for eligible employees, which allows for NU common shares to be purchased by employees at the end of successive six-month offering periods at 95 percent of the closing market price on the last day of each six-month period. Employees are permitted to purchase shares having a value not exceeding 25 percent of their compensation as of the beginning of the offering period up to a limit of $25,000 per annum. The ESPP qualifies as a non-compensatory plan under accounting guidance for share-based payments, and no compensation expense is recorded for ESPP purchases.

During 2012, employees purchased 39,422 shares at discounted prices of $33.01and $37.89. Employees purchased 35,476 shares in 2011 at discounted prices of $31.27 and $32.30. As of December 31, 2012 and 2011, 857,280 and 896,702shares, respectively, remained available for future issuance under the ESPP.

An income tax rate of 40 percent is used to estimate the tax effect on total share-based payments determined under the fair value-based method for all awards. The Company generally settles stock option exercises and fully vested RSUs and performance shares with either the issuance of new common shares or the issuance of common shares purchased in the open market.

XML

REGULATORY ACCOUNTING (Details) (USD $)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
Regulatory Asset [Line Items]
Regulatory Assets Current	$ 705,025,000	$ 255,144,000
Regulatory Assets Long Term	5,132,411,000	3,267,710,000
Regulatory Assets, Total	5,837,400,000	3,522,800,000
Regulatory Assets And Liabilities Other Disclosures Abstract
Description of Regulatory Costs Not yet Approved	Regulatory Costs Not Yet Approved: Additionally, the Regulated companies had $69.9 million ($3.9 million for CL&P, $25.4 million for NSTAR Electric, $35.7 million for PSNH, and $1.4 million for WMECO) and $32.4 million ($5 million for CL&P, $22.4 million for PSNH, and $1.6 million for WMECO) of regulatory costs as of December 31, 2012 and 2011, respectively, which were included in Other Long-Term Assets on the accompanying consolidated balance sheets. For comparative purposes, NSTAR Electric had $9.5 million of such regulatory costs as of December 31, 2011. These amounts represent incurred costs that have not yet been approved for recovery by the applicable regulatory agency. Management believes it is probable that recovery of these costs will ultimately be approved. For PSNH, of the total December 31, 2012 regulatory costs not yet approved, $12.1 million related to costs incurred for the 2012 Hurricane Sandy storm and $22.3 million related to costs incurred for the 2011 Tropical Storm Irene and the October snowstorm restorations that met the NHPUC criteria for cost deferral. As of December 31, 2011, the storm restoration costs incurred for the 2011 Tropical Storm Irene and the October snowstorm restorations totaled $21.7 million. Refer to the "Storm Restoration Costs" section below for further discussion. The NSTAR Electric balance as of December 31, 2012 and 2011 related to costs deferred in connection with the basic service bad debt adder. See Note 12H, "Commitments and Contingencies – Basic Service Bad Debt Adder," for further information.
Description of Regulatory Assets and Liabilities	Regulatory Assets - The following provides further information about regulatory assets: Benefit Costs: NU's Pension, SERP and PBOP Plans are accounted for in accordance with accounting guidance on defined benefit pension and other postretirement plans. Under this accounting guidance, the funded status of pension and other postretirement plans is recorded with an offset to Accumulated Other Comprehensive Income/(Loss) and is remeasured annually. However, because the Regulated companies recover these costs from customers through rates, regulatory assets are recorded as an offset for the liability that is recognized for the funded status of the pension and postretirement plans. Regulatory accounting was also applied to the portions of the NUSCO and NSTAR Electric & Gas costs that support the Regulated companies, as these amounts are also recoverable. CL&P and PSNH do not collect carrying charges on these deferred benefit costs regulatory assets. WMECO's deferred benefit costs regulatory assets are earning a return at the same rate as the assets included in rate base. NSTAR Electric does not earn a return on the regulatory assets recorded to offset the funded status. NSTAR Electric and WMECO each recover their qualified pension and postretirement expenses through rate reconciling mechanisms that fully track the change in net pension and postretirement expenses each year. CL&P and PSNH will recover benefit costs through rates as allowed by their applicable regulatory commissions. NSTAR Electric earns a carrying charge on the excess cumulative benefit plan trust fund contributions it has made over what it has cumulatively recognized as net periodic benefit expense, net of deferred income taxes. As of December 31, 2012 and 2011, these balances were $366.8 million and $428 million of the benefit costs regulatory asset, respectively. Regulatory Assets Offsetting Derivative Liabilities: The regulatory assets offsetting derivative liabilities relate to the fair value of contracts used to purchase power and other related contracts that will be collected from customers in the future. See Note 5, "Derivative Instruments," to the consolidated financial statements for further information.  These assets are excluded from rate base and are being recovered as the actual settlement occurs over the duration of the contracts. Goodwill: Goodwill that originated from the merger that created NSTAR in 1999 is recoverable in rates over the remaining 27 year amortization period, without a carrying charge. Storm Restoration Costs: The storm restoration cost deferrals relate to costs incurred at CL&P, NSTAR Electric, PSNH and WMECO for restorations that the Company expects to collect from customers. A storm must meet certain criteria to be declared a major storm with the criteria specific to each state jurisdiction and utility company. Once a storm is declared major, all qualifying expenses incurred during storm restoration efforts, if deemed prudent, are deferred and recovered from customers in future periods. In Connecticut, qualifying storm restoration costs must exceed $5 million for a storm to be declared a major storm. In Massachusetts, qualifying storm restoration costs must exceed $1 million for NSTAR Electric and $300,000 for WMECO and an emergency response plan must be initiated for a storm to be declared a major storm. In New Hampshire, (1) at least 10 percent of customers must be without power with at least 200 concurrent locations requiring repairs (trouble spots), or (2) at least 300 concurrent trouble spots must be reported for a storm to be declared a major storm. In 2011, Tropical Storm Irene and the October snowstorm each caused extensive damage to NU’s distribution system. As of December 31, 2012 and 2011, CL&P had recorded total deferred storm restoration costs relating to Tropical Storm Irene and the October 2011 snowstorm as a regulatory asset of $281.6 million and $263.3 million, respectively. The CL&P storm restoration cost regulatory asset balance includes a reserve of $40 million recorded in connection with the Connecticut settlement agreement. See Note 2, "Merger of NU and NSTAR," for further information. As of December 31, 2012 and 2011, NSTAR Electric had recorded total deferred storm restoration costs for these 2011 storms of $35.8 million and $35.8 million, respectively, and WMECO had recorded $26.5 million and $26.7 million, respectively, as regulatory assets. PSNH recorded $22.3 million and $21.7 million for these 2011 storms in Other Long-Term Assets, as of December 31, 2012 and 2011, respectively, as previously described. On August 1, 2012, PURA issued a final decision in the investigation of CL&P’s performance related to both Tropical Storm Irene and the October 2011 snowstorm. The decision concluded that CL&P was deficient and inadequate in its preparation, response, and communication to both storms, and identified certain penalties that could be imposed on CL&P during its next rate case, including a reduction in allowed regulatory ROE and the disallowance of certain deferred storm restoration costs. However, PURA will consider and weigh the extent to which CL&P has taken steps in its restructuring of storm management and the establishment of new practices for execution in future storm response in determining any potential penalties. CL&P believes such steps to improve current storm preparation and response practices have been successfully executed in recent storms. At this time, management cannot estimate the impact on CL&P’s financial position, results of operations or cash flows. CL&P continues to believe that its response to these 2011 storms was prudent, was consistent with industry standards, and that it is probable that it will be able to recover its deferred costs. See Note 12E, "Commitments and Contingencies – DPU Penalties for 2011 Storm Responses," for a discussion of NSTAR Electric and WMECO's 2011 storm response. On October 29, 2012, Hurricane Sandy caused extensive damage to NU’s electric distribution system across all three states. The cost of restoration that was deferred for future recovery from customers and recorded as a regulatory asset as of December 31, 2012 for CL&P, NSTAR Electric, and WMECO totaled $159.9 million, $27.8 million and $4.2 million, respectively. PSNH recorded $12.1 million in Other-Long Term Assets, as previously described. Management believes its response to the storm damage was prudent and therefore believes it is probable that CL&P, NSTAR Electric, PSNH and WMECO will be allowed to recover these deferred storm restoration costs. Accordingly, the storm did not have a material impact to the results of operations of CL&P, NSTAR Electric, PSNH or WMECO. Each operating company will seek recovery of these deferred storm restoration costs through its applicable regulatory recovery process. The PSNH storm restoration costs deferral as of December 31, 2012 and 2011 related to costs incurred for a major storm in December 2008 and the February 2010 wind storm, both of which were approved for recovery and are included in rate base. Income Taxes, Net: The tax effect of temporary book-tax differences (differences between the periods in which transactions affect income in the financial statements and the periods in which they affect the determination of taxable income, including those differences relating to uncertain tax positions) is accounted for in accordance with the rate-making treatment of the applicable regulatory commissions and accounting guidance for income taxes. Differences in income taxes between the accounting guidance and the rate-making treatment of the applicable regulatory commissions are recorded as regulatory assets. As these assets are offset by deferred income tax liabilities, no carrying charge is collected. For further information regarding income taxes, see Note 11, "Income Taxes," to the consolidated financial statements. Securitized Assets: In March 2005, NSTAR Electric issued $674.5 million RRBs and used the majority of the proceeds from that issuance to effect purchase power contract buyouts. The collateralized amounts reflected as securitized regulatory assets for NSTAR Electric as of December 31, 2012 and 2011 were $14.1 million and $98.4 million, respectively. In April 2001, PSNH issued $525 million RRBs and used the majority of the proceeds from that issuance to buydown its power contracts with an affiliate, North Atlantic Energy Corporation. In May 2001, WMECO issued $155 million RRBs and used the majority of the proceeds from that issuance to buyout an IPP contract. These assets are not earning an equity return and are being recovered over the amortization period of their associated RRBs. NSTAR Electric RRBs are scheduled to fully amortize by March 15, 2013, PSNH RRBs are scheduled to fully amortize by May 1, 2013, and WMECO RRBs are scheduled to fully amortize by June 1, 2013. NSTAR Electric's remaining balance primarily includes other costs related to purchase power contract divestitures and certain costs related to NSTAR Electric’s former generation business that are recovered with a return through the transition charge and amounted to $186.1 million and $259.8 million as of December 31, 2012 and 2011, respectively. These cost recoveries primarily occur through September 2016 for NSTAR Electric and are subject to adjustment by the DPU. Contractual Obligations: Under the terms of contracts with CYAPC, YAEC and MYAPC, CL&P, NSTAR Electric, PSNH and WMECO are responsible for their proportionate share of the remaining costs of the nuclear facilities, including decommissioning. A portion of these amounts was recorded as contractual obligations regulatory assets. These obligations for CL&P are earning a return and are being recovered through the CTA. Amounts for NSTAR Electric are being recovered without a return through the transition charge and are anticipated to be recovered by 2015. Amounts for WMECO are being recovered without a return and are anticipated to be recovered by 2013, the scheduled completion date of stranded cost recovery. Amounts for PSNH were fully recovered by 2006. As a result of the April 10, 2012 merger with NSTAR and consolidation of CYAPC and YAEC, NU's regulatory asset balance also includes the regulatory assets of CYAPC and YAEC, which amounted to $214 million as of December 31, 2012. At the NU consolidated level, intercompany transactions between CL&P, NSTAR Electric, PSNH and WMECO and the CYAPC and YAEC companies are eliminated in consolidation. Power Contracts Buy Out Agreements: NSTAR Electric's balance represents the recorded contract termination liability related to certain purchase power contract buy out agreements that NSTAR Electric executed in 2004 and their future recovery through NSTAR Electric’s transition charge. NSTAR Electric does not earn a return on this regulatory asset. The contracts’ termination payments will occur over time and will be collected from customers through NSTAR Electric’s transition charge over the same time period. The cost recovery period of these terminated contracts is through September 2016. PSNH's balance represents payments associated with the termination of various power purchase contracts that were recorded as regulatory assets and are amortized over the remaining life of the contracts. Regulatory Tracker Deferrals: Regulatory tracker deferrals are approved rate mechanisms that allow utilities to recover costs in specific business segments through reconcilable tracking mechanisms that are reviewed at least annually by the applicable regulatory commission. The reconciliation process produces deferrals for future recovery or refund, which can be either under or over-collections to be included in future customer rates each year. Regulatory tracker deferrals are recorded as regulatory assets if costs are in excess of collections from customers and are recorded as regulatory liabilities if collections from customers are in excess of costs. All material regulatory tracker deferrals that are in a regulatory asset position are earning a return. The following regulatory reconciliation mechanisms were recorded as either regulatory assets or liabilities as of December 31, 2012 and 2011: CL&P: The PURA has established several reconciliation mechanisms, which allow CL&P to recover costs associated with the procurement of energy for SS and LRS, congestion and other costs associated with power market rules approved by the FERC or as approved by the PURA, C&LM programs, the retail transmission of energy, certain regulatory and energy public policy costs, such as hardship protection costs and transition period property taxes, and stranded costs, such as the amortization of regulatory assets and IPP over market costs. As part of the CTA mechanism reconciliation process, CL&P had also established an obligation to refund the variable incentive portion of its transition service procurement fee, which totaled $26.3 million as of December 31, 2011 and was recorded as a regulatory liability. During 2012, PURA issued a decision approving a joint settlement agreement submitted October 2, 2012, by CL&P, UI, and the Connecticut Consumer Counsel, in resolution of all issues associated with the procurement incentive for 2004, 2005 and 2006. Under the joint settlement agreement, CL&P refunded to customers $5.7 million of funds collected and associated interest. CL&P will be allowed to retain approximately $11.5 million of procurement incentive along with the remaining accrued interest that it was not required to refund to customers. NSTAR Electric and WMECO: Each company recovers certain of its costs on a fully reconciling basis through DPU-approved cost recovery mechanisms. These rate mechanisms recover costs associated with the procurement of energy for basic service, the retail transmission of energy, costs associated with electric industry restructuring, pension and postretirement benefits, and energy efficiency programs. Costs associated with industry restructuring include RRB debt service, nuclear decommissioning costs and above-market IPP costs. In addition, WMECO recovers costs associated with its investments in renewable energy, such as solar projects and credits given to customers who generate renewable energy. In the January 31, 2011 rate case, WMECO received approval for a revenue decoupling reconciliation mechanism, which provides assurance that WMECO will recover a DPU pre-established level of baseline distribution delivery service revenue to manage all other distribution operating expenses and earn a level of return on its capital investment. PSNH: The NHPUC permits PSNH to recover the costs of providing generation, restructuring costs as a result of deregulation, the retail transmission of energy, and the cost of C&LM programs through various reconciliation mechanisms. Asset Retirement Obligations: The costs associated with the depreciation of the Regulated companies' ARO assets and accretion of the ARO liabilities are recorded as regulatory assets in accordance with regulatory accounting guidance. For CL&P, NSTAR Electric and WMECO, ARO assets, regulatory assets and liabilities offset and are excluded from rate base. PSNH's ARO assets, regulatory assets and liabilities are included in rate base. These costs are being recovered over the life of the underlying property, plant and equipment. Other Regulatory Assets: Other Regulatory Assets primarily include environmental remediation costs, losses associated with the reacquisition or redemption of long-term debt, and costs related to previously recognized lost tax benefits as a result of a provision in the 2010 Healthcare Act that eliminated the tax deductibility of actuarially equivalent Medicare Part D benefits for retirees, partially offset by purchase price adjustments recorded in connection with the merger with NSTAR reflected in regulatory assets. Cost of Removal: NU's Regulated companies currently recover amounts in rates for future costs of removal of plant assets over the lives of the assets. The estimated cost to remove utility assets from service is recognized as a component of depreciation expense and the cumulative amounts collected from customers but not yet expended is recognized as a regulatory liability. Expended costs that exceed amounts collected from customers are recognized as regulatory assets, as they are probable of recovery in future rates. AFUDC Transmission Incentive: AFUDC was recorded on 100 percent of CL&P and WMECO's CWIP for their NEEWS projects through May 31, 2011, all of which was reserved as a regulatory liability to reflect rate base recovery for 100 percent of the CWIP as a result of FERC-approved transmission incentives. Effective June 1, 2011, FERC approved changes to the ISO-NE Tariff in order to include 100 percent of the NEEWS CWIP in regional rate base. As a result, CL&P and WMECO no longer record AFUDC on NEEWS CWIP. NSTAR Electric recorded AFUDC on reliability-related projects over $5 million through December 31, 2012, 50 percent of which was reserved as a regulatory liability to reflect rate base recovery for 50 percent of the CWIP as a result of FERC-approved transmission incentives. Spent Nuclear Fuel Costs and Contractual Obligations: CL&P and WMECO currently recover amounts in rates for costs of disposal of spent nuclear fuel and high-level radioactive waste for the period prior to the sale of their ownership shares in the Millstone nuclear power stations. Collections in excess of these costs are recorded as regulatory liabilities. CL&P has also established a regulatory liability for the overrecovery of its proportionate share of the remaining costs, including decommissioning, of the MYAPC nuclear facility. Wholesale Transmission Overcollections: CL&P, NSTAR Electric, PSNH and WMECO's transmission rates recover total transmission revenue requirements, recovering all regional and local revenue requirements for providing transmission service. These rates provide for annual reconciliations to actual costs and the difference between billed and actual costs is deferred. Regulatory liabilities are recorded for collections in excess of costs. Regulatory assets are recorded for costs in excess of collections, as they are probable of recovery in future rates. Other Regulatory Liabilities: Other Regulatory Liabilities primarily includes amounts that are subject to various rate reconciling mechanisms that, as of each period end date, would result in refunds to customers.
Description Of Accumulated Equity Return	Equity Return on Regulatory Assets: For rate-making purposes, the Regulated companies recover the carrying cost, including an allowed equity return, on certain regulatory assets. This equity return, which is not recorded on the accompanying consolidated balance sheets, totaled $2.5 million and $3.5 million for CL&P and $21.8 million and $7.6 million for PSNH as of December 31, 2012 and 2011, respectively. These carrying costs will be recovered in future rates.
Regulatory Liabilities [Line Items]
Regulatory Liability Current	134,115,000	167,844,000
Regulatory Liabilities Long-Term	540,162,000	266,145,000
Regulatory Liabilities, Total	674,300,000	433,900,000
Cost Of Removal [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities, Total	440,800,000	172,200,000
Regulatory Tracker Deferrals Regulatory Liabilities [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities, Total	95,100,000	139,100,000
AFUDC Transmission Incentive [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities, Total	70,000,000	67,000,000
Overrecovered Spent Nuclear Fuel Costs And Contractual Obligations [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities, Total	15,400,000	15,400,000
Other Regulatory Liabilities [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities, Total	53,000,000	40,200,000
The Connecticut Light And Power Company [Member]
Regulatory Asset [Line Items]
Regulatory Assets Current	185,858,000	170,197,000
Regulatory Assets Long Term	2,158,363,000	2,103,830,000
Regulatory Assets, Total	2,344,300,000	2,274,000,000
Regulatory Liabilities [Line Items]
Regulatory Liability Current	32,119,000	108,291,000
Regulatory Liabilities Long-Term	124,319,000	139,307,000
Regulatory Liabilities, Total	156,400,000	247,600,000
The Connecticut Light And Power Company [Member] | Cost Of Removal [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities, Total	44,200,000	63,800,000
The Connecticut Light And Power Company [Member] | Regulatory Tracker Deferrals Regulatory Liabilities [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities, Total	39,100,000	94,400,000
The Connecticut Light And Power Company [Member] | AFUDC Transmission Incentive [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities, Total	56,600,000	57,700,000
The Connecticut Light And Power Company [Member] | Overrecovered Spent Nuclear Fuel Costs And Contractual Obligations [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities, Total	15,400,000	15,400,000
The Connecticut Light And Power Company [Member] | Wholesale Transmission Overcollections [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities, Total	0	4,500,000
The Connecticut Light And Power Company [Member] | Other Regulatory Liabilities [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities, Total	1,100,000	11,800,000
NSTAR Electric Company [Member]
Regulatory Asset [Line Items]
Regulatory Assets Current	347,081,000	323,871,000
Regulatory Assets Long Term	1,444,870,000	1,680,595,000
Regulatory Assets, Total	1,792,000,000	2,004,500,000
Regulatory Liabilities [Line Items]
Regulatory Liability Current	47,539,000	41,579,000
Regulatory Liabilities Long-Term	244,224,000	239,858,000
Regulatory Liabilities, Total	291,700,000	281,500,000
NSTAR Electric Company [Member] | Cost Of Removal [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities, Total	240,300,000	235,800,000
NSTAR Electric Company [Member] | Regulatory Tracker Deferrals Regulatory Liabilities [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities, Total	14,400,000	11,700,000
NSTAR Electric Company [Member] | AFUDC Transmission Incentive [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities, Total	4,100,000	4,300,000
NSTAR Electric Company [Member] | Other Regulatory Liabilities [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities, Total	32,900,000	29,700,000
Public Service Company Of New Hampshire [Member]
Regulatory Asset [Line Items]
Regulatory Assets Current	62,882,000	34,178,000
Regulatory Assets Long Term	351,059,000	393,941,000
Regulatory Assets, Total	414,000,000	428,100,000
Regulatory Liabilities [Line Items]
Regulatory Liability Current	23,002,000	24,500,000
Regulatory Liabilities Long-Term	52,418,000	54,415,000
Regulatory Liabilities, Total	75,400,000	78,900,000
Public Service Company Of New Hampshire [Member] | Cost Of Removal [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities, Total	51,200,000	53,200,000
Public Service Company Of New Hampshire [Member] | Regulatory Tracker Deferrals Regulatory Liabilities [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities, Total	20,400,000	17,300,000
Public Service Company Of New Hampshire [Member] | AFUDC Transmission Incentive [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities, Total	0	0
Public Service Company Of New Hampshire [Member] | Wholesale Transmission Overcollections [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities, Total	0	2,600,000
Public Service Company Of New Hampshire [Member] | Other Regulatory Liabilities [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities, Total	3,800,000	5,800,000
Western Massachusetts Electric Company [Member]
Regulatory Asset [Line Items]
Regulatory Assets Current	42,370,000	35,520,000
Regulatory Assets Long Term	221,752,000	233,247,000
Regulatory Assets, Total	264,200,000	268,700,000
Regulatory Liabilities [Line Items]
Regulatory Liability Current	21,037,000	33,056,000
Regulatory Liabilities Long-Term	9,686,000	16,597,000
Regulatory Liabilities, Total	30,700,000	49,700,000
Western Massachusetts Electric Company [Member] | Cost Of Removal [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities, Total	0	7,200,000
Western Massachusetts Electric Company [Member] | Regulatory Tracker Deferrals Regulatory Liabilities [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities, Total	13,700,000	21,300,000
Western Massachusetts Electric Company [Member] | AFUDC Transmission Incentive [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities, Total	9,300,000	9,300,000
Western Massachusetts Electric Company [Member] | Wholesale Transmission Overcollections [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities, Total	5,300,000	9,500,000
Western Massachusetts Electric Company [Member] | Other Regulatory Liabilities [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities, Total	2,400,000	2,400,000
Benefit Costs [Member]
Regulatory Asset [Line Items]
Regulatory Assets, Total	2,452,100,000	1,360,500,000
Benefit Costs [Member] | The Connecticut Light And Power Company [Member]
Regulatory Asset [Line Items]
Regulatory Assets, Total	563,200,000	572,800,000
Benefit Costs [Member] | NSTAR Electric Company [Member]
Regulatory Asset [Line Items]
Regulatory Assets, Total	781,200,000	813,700,000
Benefit Costs [Member] | Public Service Company Of New Hampshire [Member]
Regulatory Asset [Line Items]
Regulatory Assets, Total	223,700,000	200,000,000
Benefit Costs [Member] | Western Massachusetts Electric Company [Member]
Regulatory Asset [Line Items]
Regulatory Assets, Total	116,000,000	118,900,000
Regulatory Assets Offsetting Derivative Liabilities [Member]
Regulatory Asset [Line Items]
Regulatory Assets, Total	885,600,000	939,600,000
Regulatory Assets Offsetting Derivative Liabilities [Member] | The Connecticut Light And Power Company [Member]
Regulatory Asset [Line Items]
Regulatory Assets, Total	866,200,000	932,000,000
Regulatory Assets Offsetting Derivative Liabilities [Member] | NSTAR Electric Company [Member]
Regulatory Asset [Line Items]
Regulatory Assets, Total	14,900,000	3,400,000
Regulatory Assets Offsetting Derivative Liabilities [Member] | Public Service Company Of New Hampshire [Member]
Regulatory Asset [Line Items]
Regulatory Assets, Total	0	0
Regulatory Assets Offsetting Derivative Liabilities [Member] | Western Massachusetts Electric Company [Member]
Regulatory Asset [Line Items]
Regulatory Assets, Total	3,000,000	7,300,000
Goodwill [Member]
Regulatory Asset [Line Items]
Regulatory Assets, Total	537,600,000
Goodwill [Member] | NSTAR Electric Company [Member]
Regulatory Asset [Line Items]
Regulatory Assets, Total	461,500,000	478,900,000
Storm Restoration Costs [Member]
Regulatory Asset [Line Items]
Regulatory Assets, Total	547,700,000	356,000,000
Storm Restoration Costs [Member] | The Connecticut Light And Power Company [Member]
Regulatory Asset [Line Items]
Regulatory Assets, Total	413,900,000	268,300,000
Storm Restoration Costs [Member] | NSTAR Electric Company [Member]
Regulatory Asset [Line Items]
Regulatory Assets, Total	55,800,000	30,600,000
Storm Restoration Costs [Member] | Public Service Company Of New Hampshire [Member]
Regulatory Asset [Line Items]
Regulatory Assets, Total	34,500,000	44,000,000
Storm Restoration Costs [Member] | Western Massachusetts Electric Company [Member]
Regulatory Asset [Line Items]
Regulatory Assets, Total	43,500,000	43,700,000
Deferred Income Tax Charges Member
Regulatory Asset [Line Items]
Regulatory Assets, Total	516,200,000	425,400,000
Deferred Income Tax Charges Member | The Connecticut Light And Power Company [Member]
Regulatory Asset [Line Items]
Regulatory Assets, Total	367,500,000	339,600,000
Deferred Income Tax Charges Member | NSTAR Electric Company [Member]
Regulatory Asset [Line Items]
Regulatory Assets, Total	47,100,000	48,800,000
Deferred Income Tax Charges Member | Public Service Company Of New Hampshire [Member]
Regulatory Asset [Line Items]
Regulatory Assets, Total	36,200,000	38,000,000
Deferred Income Tax Charges Member | Western Massachusetts Electric Company [Member]
Regulatory Asset [Line Items]
Regulatory Assets, Total	31,000,000	17,800,000
Securitized Assets [Member]
Regulatory Asset [Line Items]
Regulatory Assets, Total	232,600,000	101,800,000
Securitized Assets [Member] | The Connecticut Light And Power Company [Member]
Regulatory Asset [Line Items]
Regulatory Assets, Total	0	0
Securitized Assets [Member] | NSTAR Electric Company [Member]
Regulatory Asset [Line Items]
Regulatory Assets, Total	205,100,000	368,500,000
Securitized Assets [Member] | Public Service Company Of New Hampshire [Member]
Regulatory Asset [Line Items]
Regulatory Assets, Total	19,700,000	76,400,000
Securitized Assets [Member] | Western Massachusetts Electric Company [Member]
Regulatory Asset [Line Items]
Regulatory Assets, Total	7,800,000	25,400,000
Unrecovered Contractual Obligations [Member]
Regulatory Asset [Line Items]
Regulatory Assets, Total	217,600,000	100,900,000
Unrecovered Contractual Obligations [Member] | The Connecticut Light And Power Company [Member]
Regulatory Asset [Line Items]
Regulatory Assets, Total	64,000,000	80,900,000
Unrecovered Contractual Obligations [Member] | NSTAR Electric Company [Member]
Regulatory Asset [Line Items]
Regulatory Assets, Total	22,800,000	30,800,000
Unrecovered Contractual Obligations [Member] | Public Service Company Of New Hampshire [Member]
Regulatory Asset [Line Items]
Regulatory Assets, Total	0	0
Unrecovered Contractual Obligations [Member] | Western Massachusetts Electric Company [Member]
Regulatory Asset [Line Items]
Regulatory Assets, Total	14,900,000	20,000,000
Power Contracts Buy Out Agreements [Member]
Regulatory Asset [Line Items]
Regulatory Assets, Total	92,900,000	8,600,000
Power Contracts Buy Out Agreements [Member] | NSTAR Electric Company [Member]
Regulatory Asset [Line Items]
Regulatory Assets, Total	85,900,000	109,500,000
Power Contracts Buy Out Agreements [Member] | Public Service Company Of New Hampshire [Member]
Regulatory Asset [Line Items]
Regulatory Assets, Total	7,000,000	8,600,000
Regulatory Tracker Deferrals Regulatory Assets [Member]
Regulatory Asset [Line Items]
Regulatory Assets, Total	190,100,000	45,900,000
Regulatory Tracker Deferrals Regulatory Assets [Member] | The Connecticut Light And Power Company [Member]
Regulatory Asset [Line Items]
Regulatory Assets, Total	12,200,000	5,500,000
Regulatory Tracker Deferrals Regulatory Assets [Member] | NSTAR Electric Company [Member]
Regulatory Asset [Line Items]
Regulatory Assets, Total	71,400,000	61,100,000
Regulatory Tracker Deferrals Regulatory Assets [Member] | Public Service Company Of New Hampshire [Member]
Regulatory Asset [Line Items]
Regulatory Assets, Total	49,300,000	11,900,000
Regulatory Tracker Deferrals Regulatory Assets [Member] | Western Massachusetts Electric Company [Member]
Regulatory Asset [Line Items]
Regulatory Assets, Total	31,900,000	22,100,000
Asset Retirement Obligation Costs Member
Regulatory Asset [Line Items]
Regulatory Assets, Total	88,800,000	47,500,000
Asset Retirement Obligation Costs Member | The Connecticut Light And Power Company [Member]
Regulatory Asset [Line Items]
Regulatory Assets, Total	29,400,000	27,900,000
Asset Retirement Obligation Costs Member | NSTAR Electric Company [Member]
Regulatory Asset [Line Items]
Regulatory Assets, Total	29,400,000	24,500,000
Asset Retirement Obligation Costs Member | Public Service Company Of New Hampshire [Member]
Regulatory Asset [Line Items]
Regulatory Assets, Total	14,200,000	13,500,000
Asset Retirement Obligation Costs Member | Western Massachusetts Electric Company [Member]
Regulatory Asset [Line Items]
Regulatory Assets, Total	3,500,000	3,200,000
Other Regulatory Assets [Member]
Regulatory Asset [Line Items]
Regulatory Assets, Total	76,200,000	136,600,000
Other Regulatory Assets [Member] | The Connecticut Light And Power Company [Member]
Regulatory Asset [Line Items]
Regulatory Assets, Total	27,900,000	47,000,000
Other Regulatory Assets [Member] | NSTAR Electric Company [Member]
Regulatory Asset [Line Items]
Regulatory Assets, Total	16,900,000	34,700,000
Other Regulatory Assets [Member] | Public Service Company Of New Hampshire [Member]
Regulatory Asset [Line Items]
Regulatory Assets, Total	29,400,000	35,700,000
Other Regulatory Assets [Member] | Western Massachusetts Electric Company [Member]
Regulatory Asset [Line Items]
Regulatory Assets, Total	$ 12,600,000	$ 10,300,000

XML

Employee Stock Ownership Plan (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Employee Stock Ownership Plan (ESOP) Disclosures [Line Items]
Employee Stock Ownership Plan (ESOP), Compensation Expense	$ 8.9	$ 8.8	$ 8.5

XML

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Net Income	$ 533,077	$ 400,513	$ 394,107
Other Comprehensive Income Loss Net Of Tax Period Increase Decrease Abstract
Other Comprehensive Income (Loss), Derivatives Qualifying as Hedges, Net of Tax	1,971	(14,177)	200
Other Comprehensive Income (Loss), Available-for-sale Securities Adjustment, Net of Tax	217	506	402
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Adjustment, Net of Tax	(4,356)	(13,645)	(505)
Other Comprehensive Income (Loss), Net of Tax, Total	(2,168)	(27,316)	97
Comprehensive Income Attributable to Noncontrolling Interests	(7,132)	(5,820)	(6,158)
Comprehensive Income	523,777	367,377	388,046
The Connecticut Light And Power Company [Member]
Net Income	209,725	250,164	244,143
Other Comprehensive Income Loss Net Of Tax Period Increase Decrease Abstract
Other Comprehensive Income (Loss), Derivatives Qualifying as Hedges, Net of Tax	444	445	444
Other Comprehensive Income (Loss), Available-for-sale Securities Adjustment, Net of Tax	7	17	14
Other Comprehensive Income (Loss), Net of Tax, Total	451	462	458
Comprehensive Income	210,176	250,626	244,601
Public Service Company Of New Hampshire [Member]
Net Income	96,882	100,267	90,067
Other Comprehensive Income Loss Net Of Tax Period Increase Decrease Abstract
Other Comprehensive Income (Loss), Derivatives Qualifying as Hedges, Net of Tax	1,162	(10,260)	87
Other Comprehensive Income (Loss), Available-for-sale Securities Adjustment, Net of Tax	13	29	24
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Adjustment, Net of Tax	2
Other Comprehensive Income (Loss), Net of Tax, Total	1,177	(10,231)	111
Comprehensive Income	98,059	90,036	90,178
Western Massachusetts Electric Company [Member]
Net Income	54,503	43,054	23,090
Other Comprehensive Income Loss Net Of Tax Period Increase Decrease Abstract
Other Comprehensive Income (Loss), Derivatives Qualifying as Hedges, Net of Tax	338	(4,108)	(79)
Other Comprehensive Income (Loss), Available-for-sale Securities Adjustment, Net of Tax	2	5	4
Other Comprehensive Income (Loss), Net of Tax, Total	340	(4,103)	(75)
Comprehensive Income	54,843	38,951	23,015
NSTAR Electric Company [Member]
Net Income	$ 190,242	$ 252,494	$ 248,575

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MARKETABLE SECURITIES

12 Months Ended

Dec. 31, 2012

Notes To Consolidated Financial Statements [Abstract]

Marketable Securities [Text Block]

NU maintains a supplemental benefit trust to fund certain of NU's non-qualified executive retirement benefit obligations and WMECO maintains a spent nuclear fuel trust to fund WMECO's prior period spent nuclear fuel liability, each of which hold marketable securities. These trusts are not subject to regulatory oversight by state or federal agencies. As of April 10, 2012, upon consummation of the merger with NSTAR and consolidation of CYAPC and YAEC, NU's marketable securities also includes legally restricted trusts for the decommissioning of nuclear power plants.

The Company elects to record mutual funds purchased by the NU supplemental benefit trust at fair value. As such, any change in fair value of these mutual funds is reflected in Net Income. These mutual funds, classified as Level 1 in the fair value hierarchy, totaled $47million and $41.1 million as of December31, 2012 and 2011, respectively, and are included in current Marketable Securities. Net gains on these securities of $5.9million and net losses of $1.1million for the years ended December 31, 2012 and 2011, respectively, were recorded in Other Income, Net on the accompanying consolidated statements of income. Dividend income is recorded when dividends are declared and is recorded in Other Income, Net on the accompanying consolidated statements of income. All other marketable securities are accounted for as available-for-sale.

Available-for-Sale Securities: The following is a summary of NU's available-for-sale securities held in the NU supplemental benefit trust, WMECO's spent nuclear fuel trust and CYAPC and YAEC's nuclear decommissioning trusts. These securities are recorded at fair value and included in current and long-term Marketable Securities on the accompanying consolidated balance sheets.

		As of December 31, 2012
				Pre-Tax		Pre-Tax
		Amortized		Unrealized		Unrealized
(Millions of Dollars)		Cost		Gains(1)		Losses(1)		Fair Value
NU
	Debt Securities (2)	$	266.6	$	13.3	$	(0.1)	$	279.8
	Equity Securities (2)		145.5		20.0		-		165.5
WMECO
	Debt Securities		57.7		0.1		(0.1)		57.7
		As of December 31, 2011
				Pre-Tax		Pre-Tax
		Amortized		Unrealized		Unrealized
(Millions of Dollars)		Cost		Gains(1)		Losses(1)		Fair Value
NU		$	88.4	$	2.0	$	(0.2)	$	90.2
WMECO			57.3		-		(0.2)		57.1

• Unrealized gains and losses on debt securities for the NU supplemental benefit trust and WMECO spent nuclear fuel trust are recorded in AOCI and Other Long-Term Assets, respectively, on the accompanying consolidated balance sheets.

(2)       NU's December 31, 2012 amounts include CYAPC's and YAEC's marketable securities held in nuclear decommissioning trusts of $340.4million, the majority of which are legally restricted and can only be used for the decommissioning of the nuclear power plants owned by these companies. Unrealized gains and losses for the nuclear decommissioning trusts are offset in Other Long-Term Liabilities on the accompanying consolidated balance sheet. All of the equity securities accounted for as available-for-sale securities are held in these trusts.

Unrealized Losses and Other-than-Temporary Impairment: There have been no significant unrealized losses, other-than-temporary impairments or credit losses for the NU supplemental benefit trust, the WMECO spent nuclear fuel trust, and in the trusts held by CYAPC and YAEC.Factors considered in determining whether a credit loss exists include the duration and severity of the impairment, adverse conditions specifically affecting the issuer, and the payment history, ratings and rating changes of the security. For asset-backed debt securities, underlying collateral and expected future cash flows are also evaluated.

Realized Gains and Losses: Realized gains and losses on available-for-sale securities are recorded in Other Income, Net for the NU supplemental benefit trust, Other Long-Term Assets for the WMECO spent nuclear fuel trust, and offset in Other Long-Term Liabilities for CYAPC and YAEC. NU utilizes the specific identification basis method for the NU supplemental benefit trust securities and the average cost basis method for the WMECO spent nuclear fuel trust and the CYAPC and YAEC nuclear decommissioning trusts to compute the realized gains and losses on the sale of available-for-sale securities.

Contractual Maturities: As of December 31, 2012, the contractual maturities of available-for-sale debt securities are as follows:

	NU				WMECO
	Amortized				Amortized
(Millions of Dollars)	Cost		Fair Value		Cost		Fair Value
Less than one year (1)	$	66.6	$	66.6	$	27.4	$	27.4
One to five years		57.3		58.7		17.5		17.5
Six to ten years		51.2		54.6		6.0		6.1
Greater than ten years		91.5		99.9		6.8		6.7
Total Debt Securities	$	266.6	$	279.8	$	57.7	$	57.7

(1)       Amounts in the Less than one year NU category include securities in the nuclear decommissioning trusts, which are restricted and are classified in long-term Marketable Securities on the accompanying consolidated balance sheet.

Fair Value Measurements: The following table presents the marketable securities recorded at fair value on a recurring basis by the level in which they are classified within the fair value hierarchy:

			NU				WMECO
			As of December 31,				As of December 31,
(Millions of Dollars)			2012		2011		2012		2011
Level 1:
	Mutual Funds and Equities		$	212.5	$	41.1	$	-	$	-
	Money Market Funds			40.2		1.8		5.2		0.1
Total Level 1			$	252.7	$	42.9	$	5.2	$	0.1
Level 2:
	U.S. Government Issued Debt Securities
		(Agency and Treasury)		69.9		11.1		18.7		8.0
	Corporate Debt Securities			33.0		16.5		7.0		9.1
	Asset-Backed Debt Securities			28.5		25.9		10.9		7.9
	Municipal Bonds			93.8		16.1		11.6		15.4
	Other Fixed Income Securities			14.4		18.8		4.3		16.6
Total Level 2			$	239.6	$	88.4	$	52.5	$	57.0
Total Marketable Securities			$	492.3	$	131.3	$	57.7	$	57.1

U.S. government issued debt securities are valued using market approaches that incorporate transactions for the same or similar bonds and adjustments for yields and maturity dates. Corporate debt securities are valued using a market approach, utilizing recent trades of the same or similar instrument and also incorporating yield curves, credit spreads and specific bond terms and conditions. Asset-backed debt securities include collateralized mortgage obligations, commercial mortgage backed securities, and securities collateralized by auto loans, credit card loans or receivables. Asset-backed debt securities are valued using recent trades of similar instruments, prepayment assumptions, yield curves, issuance and maturity dates and tranche information. Municipal bonds are valued using a market approach that incorporates reported trades and benchmark yields. Other fixed income securities are valued using pricing models, quoted prices of securities with similar characteristics, and discounted cash flows.

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DERIVATIVE INSTRUMENTS

12 Months Ended

Dec. 31, 2012

Notes To Consolidated Financial Statements [Abstract]

Derivative Instruments and Hedging Activities Disclosure [Text Block]

5.       DERIVATIVE INSTRUMENTS

The Regulated companies purchase and procure energy and energy-related products for their customers, which are subject to price volatility. The costs associated with supplying energy to customers are recoverable through customer rates. The Regulated companies manage the risks associated with the price volatility of energy and energy-related products through the use of derivative contracts, many of which meet the definition of and are designated as "normal purchases or normal sales" (normal) under the applicable accounting guidance, and the use of nonderivative contracts.

Derivative contracts that are not recorded as normal are recorded at fair value as current or long-term derivative assets or liabilities. For the Regulated companies, regulatory assets or liabilities are recorded for the changes in fair values of derivatives, as costs are, and management believes they will continue to be, recovered from or refunded incustomers rates. For NU's remaining unregulated wholesale marketing contracts, changes in fair values of derivatives are included in Net Income. The costs and benefits of derivative contracts that meet the definition of normal are recognized in Operating Expenses or Operating Revenues on the accompanying consolidated statements of income, as applicable, as electricity or natural gas is delivered.

CL&P, NSTAR Electric and WMECO mitigate the risks associated with the price volatility of energy and energy-related products through the use of SS, LRS, and basic service contracts, which fix the price of electricity purchased for customers and are accounted for as normal. CL&P, NSTAR Electric and WMECO haveentered into derivative and nonderivative contracts for the purchase of energy and energy-related products and contracts that are derivatives. NU also has NYMEX future contracts in order to reduce variability associated with the purchase price of approximately 11.5millionMMBtu of natural gas.

The costs or benefits from all of the Regulated companies' derivative contracts are recoverable from or refundable to customers, and therefore, changes in fair value are recorded as Regulatory Assets or Regulatory Liabilities on the accompanying consolidated balance sheets.

NU, through Select Energy, has one remaining fixed price forward sales contract that expires on December 31, 2013 to serve electrical load that is part of its remaining unregulated wholesale energy marketing portfolio. NU mitigates the price risk associated with this contract through the use of several forward purchase contracts. The contracts are accounted for at fair value, and changes in their fair values are recorded in Purchased Power, Fuel and Transmission on the accompanying consolidated statements of income.

The gross fair values of derivative assets and liabilities with the same counterparty are offset and reported as net Derivative Assets or Derivative Liabilities, with current and long-term portions, in the accompanying consolidated balance sheets. Cash collateral posted or collected under master netting agreements is recorded as an offset to the derivative asset or liability. The following tables present the gross fair values of contracts categorized by risk type and the net amounts recorded as current or long-term derivative asset or liability:

		As of December 31, 2012
		Commodity Supply and		Collateral		Net Amount Recorded as
(Millions of Dollars)		Price Risk Management		and Netting (1)		Derivative Asset/(Liability) (2)
Current Derivative Assets:
Level 2:
	Other	$	0.2	$	-	$	0.2
Level 3:
	CL&P		17.7		(12.0)		5.7
	Other		5.5		-		5.5
Total Current Derivative Assets		$	23.4	$	(12.0)	$	11.4
Long-Term Derivative Assets:
Level 3:
	CL&P	$	159.7	$	(69.1)	$	90.6
Total Long-Term Derivative Assets		$	159.7	$	(69.1)	$	90.6
Current Derivative Liabilities:
Level 2:
	Other	$	(19.9)	$	0.6	$	(19.3)
Level 3:
	CL&P		(96.9)		-		(96.9)
	NSTAR Electric		(1.0)		-		(1.0)
Total Current Derivative Liabilities		$	(117.8)	$	0.6	$	(117.2)
Long-Term Derivative Liabilities:
Level 2:
	Other	$	(0.2)	$	-	$	(0.2)
Level 3:
	CL&P		(865.6)		-		(865.6)
	NSTAR Electric		(13.9)		-		(13.9)
	WMECO		(3.0)		-		(3.0)
Total Long-Term Derivative Liabilities		$	(882.7)	$	-	$	(882.7)

		As of December 31, 2011
		Commodity Supply and		Collateral		Net Amount Recorded as
(Millions of Dollars)		Price Risk Management		and Netting (1)		Derivative Asset/(Liability) (2)
Current Derivative Assets:
Level 3:
	CL&P	$	17.9	$	(11.6)	$	6.3
	Other		4.7		-		4.7
Total Current Derivative Assets (3)		$	22.6	$	(11.6)	$	11.0
Long-Term Derivative Assets:
Level 3:
	CL&P	$	174.2	$	(80.4)	$	93.8
	Other		4.6		-		4.6
Total Long-Term Derivative Assets		$	178.8	$	(80.4)	$	98.4
Current Derivative Liabilities:
Level 3:
	CL&P	$	(95.9)	$	-	$	(95.9)
	WMECO		(0.1)		-		(0.1)
	Other		(16.1)		4.5		(11.6)
Total Current Derivative Liabilities		$	(112.1)	$	4.5	$	(107.6)
Long-Term Derivative Liabilities:
Level 3:
	CL&P	$	(935.8)	$	-	$	(935.8)
	WMECO		(7.2)		-		(7.2)
	Other		(17.3)		0.4		(16.9)
Total Long-Term Derivative Liabilities (4)		$	(960.3)	$	0.4	$	(959.9)

       Amounts represent cash collateral posted under master netting agreements and the netting of derivative assets and liabilities. See "Credit Risk" below for discussion of cash collateral posted under master netting agreements.

(2)       Current derivative assets are included in Prepayments and Other Current Assets on the accompanying consolidated balance sheets. NSTAR Electric and WMECO derivative liabilities are included in Other Current Liabilities and Other Long-Term Liabilities on their accompanying consolidated balance sheets.

(3)In addition to the amounts reflected in the table, as of December 31, 2011, NU had $2.3 million of hedging instruments that were classified as Level 2 in the fair value hierarchy, which related to a fair value hedge that expired on April 2, 2012 and was included in Prepayments and Other Current Assets on the accompanying consolidated balance sheet.

(4)       As of December 31, 2011, NSTAR Electric had $3.4 million of derivative liabilities classified as Level 3 within the fair value hierarchy and included in Other Long-Term Liabilities on the accompanying NSTAR Electric consolidated balance sheet. These amounts are not included in NU consolidated as of December 31, 2011.

The business activities of the Company that resulted in the recognition of derivative assets also create exposure to various counterparties. As of December 31, 2012, NU and CL&P's derivative assets are exposed to counterparty credit risk. Of these amounts, $96.5million and $96.3million, respectively, is contracted with investment grade entities and the remainder is contracted with multiple other counterparties.

For further information on the fair value of derivative contracts, see Note 1H, "Summary of Significant Accounting Policies -Fair Value Measurements," and Note 1I, "Summary of Significant Accounting Policies - Derivative Accounting," to the consolidated financial statements.

Derivatives Not Designated as Hedges

Commodity Supply and Price Risk Management: As required by regulation, CL&P has capacity-related contracts with generation facilities. These contracts and similar UI contracts have an expected capacity of 787 MW. CL&P has a sharing agreement with UI, with 80 percent of each contract allocated to CL&P and 20 percent allocated to UI. The capacity contracts extend through 2026 and obligate the utilities to make or receive payments on a monthly basis to or from the generation facilities based on the difference between a set capacity price and the forward capacity market price received in the ISO-NE capacity markets. In addition, CL&P has a contract to purchase 0.1 million MWh of energy per year through 2020.

NSTAR Electric has a renewable energy contract to purchase 0.1 million MWh of energy per year through 2018. NSTAR Electric also has a capacity related contract for up to 35 MW that extends through 2019.

WMECO has a renewable energy contract to purchase 0.1 million MWh of energy per year through 2028 with a facility that is expected to achieve commercial operation by November 2013.

As of December 31, 2012 and 2011, NU had approximately 24 thousand MWh and 123 thousand MWh, respectively, of supply volumes remaining in its unregulated wholesale portfolio when expected sales are compared with supply contracts.

The following table presents the realized and unrealized gains/(losses) associated with NU's derivative contracts not designated as hedges (See Level 3 tables in the "Valuations using significant unobservable inputs" section for CL&P, NSTAR Electric and WMECO gains and losses on derivative contracts):

Location of Amounts		Amounts Recognized on Derivatives
Recognized on Derivatives		For the Years Ended December 31,
(Millions of Dollars)		2012		2011		2010
NU
Balance Sheet:
	Regulatory Assets	$	(29.0)	$	(162.0)	$	(95.7)
Statement of Income:
	Purchased Power, Fuel and Transmission		(0.7)		0.5		2.7

Hedging Instruments

Fair Value Hedge: NU parent had a fixed to floating interest rate swap on its $263 million, fixed rate senior note that matured on April 1, 2012. This interest rate swap qualified and was designated as a fair value hedge. Prior to the settlement of the swap on April 2, 2012, $2.5 million of interest benefit was recorded in Net Income in the first quarter of 2012. For the years ended December 31, 2011 and 2010, $10.5million and $10.9million of interest benefit was recorded in Net Income, respectively.

Cash Flow Hedges:In 2011, PSNH and WMECO settled interest rate swaps associated with $280 million and $50 million, respectively, of long-term debt issuances and as a result PSNH and WMECO recorded pre-tax reductions of $18.2 million and $6.9 million, respectively, to AOCI that are being amortized over the remaining lives of the associated debt.In addition, NU, CL&P, PSNH and WMECO continue to amortize interest rate swaps settled in prior years from AOCI into Interest Expense over the remaining life of the associated long-term debt. The pre-tax impact of cash flow hedging instruments on AOCI is as follows:

	Gains/(Losses) Recognized on		Gains/(Losses) Reclassified from AOCI
	Derivative Instruments		into Interest Expense
	For the Year Ended December 31,		For the Years Ended December 31,
(Millions of Dollars)	2011		2012		2011		2010
NU	$	(25.1)	$	(3.3)	$	(1.3)	$	(0.4)
CL&P		-		(0.7)		(0.7)		(0.7)
PSNH		(18.2)		(2.0)		(0.8)		(0.2)
WMECO		(6.9)		(0.5)		(0.1)		0.1

For further information, see Note 15, "Accumulated Other Comprehensive Income/(Loss)," to the consolidated financial statements.

Credit Risk

Certain of NU's contracts contain credit risk contingent features. These features require NU to maintain investment grade credit ratings from the major rating agencies and to post collateral for contracts in a net liability position over specified credit limits. The following summarizes the fair value of derivative contracts that were in a net liability position and subject to credit risk contingent features, the fair value of cash collateral, and the additional collateral that would be required to be posted by NU if the unsecured debt credit ratings of NU parent were downgraded to below investment grade as of December31, 2012 and2011

As of December 31, 2012

As of December 31, 2011

Additional Collateral

Additional Collateral

Fair Value Subject

Required if

Fair Value Subject

Required if

to Credit Risk

Cash

Downgraded Below

to Credit Risk

Cash

Downgraded Below

(Millions of Dollars)

Contingent Features

Collateral Posted

Investment Grade

Contingent Features

Collateral Posted

Investment Grade

NU

$

(15.3)

$

-

$

17.4

$

(23.5)

$

4.1

$

19.9

Fair Value Measurements of Derivative Instruments

Valuation of Derivative Instruments:Derivative contracts classified as Level 2 in the fair value hierarchy relate to the financial contracts for natural gas futures and the remaining unregulated wholesale marketing sourcing contracts to purchase energy for periods in which prices are quoted in an active market. Prices are obtained from broker quotes and are based on actual market activity. The contracts are valued using the mid-point of the bid-ask spread. Valuations of these contracts also incorporate discount rates using the yield curve approach.

The fair value of derivative contracts classified as Level 3 utilize significant unobservable inputs. The fair value is modeled using income techniques, such as discounted cash flow approaches adjusted for assumptions relating to exit price. Significant observable inputs for valuations of these contracts include energy and energy-related product prices in future years for which quoted prices in an active market exist. Fair value measurements categorized in Level 3 of the fair value hierarchy are prepared by individuals with expertise in valuation techniques, pricing of energy and energy-related products, and accounting requirements. The future power and capacity prices for periods that are not quoted in an active market or established at auction are based on available market data and are escalated based on estimates of inflation to address the full time period of the contract.

Valuations of derivative contracts using discounted cash flow methodology include assumptions regarding the timing and likelihood of scheduled payments and also reflect non-performance risk, including credit, using the default probability approach based on the counterparty's credit rating for assets and the company's credit rating for liabilities. Valuations incorporate estimates of premiums or discounts that would be required by a market participant to arrive at an exit price, using historical market transactions adjusted for the terms of the contract.

The following is a summary of NU's, including CL&P's, NSTAR Electric's and WMECO's, Level 3 derivative contracts and the range of the significant unobservable inputs utilized in the valuations over the duration of the contracts:

	Range	Period Covered
Energy Prices:
NU	$43 - $90 per MWh	2018 - 2028
CL&P	$50 - $55 per MWh	2018 - 2020
WMECO	$43 - $90 per MWh	2018 - 2028
Capacity Prices:
NU	$1.40 - $10.53 per kW-Month	2016 - 2028
CL&P	$1.40 - $9.83 per kW-Month	2016 - 2026
NSTAR Electric	$1.40 - $3.39 per kW-Month	2016 - 2019
WMECO	$1.40 - $10.53 per kW-Month	2016 - 2028
Forward Reserve:
NU, CL&P	$0.35 - $0.90 per kW-Month	2013 - 2024
REC Prices:
NU	$25 - $85 per REC	2013 - 2028
NSTAR Electric	$25 - $71 per REC	2013 - 2018
WMECO	$25 - $85 per REC	2013 - 2028

Exit price premiums of 11 percent through 32 percent are also applied on these contracts and reflect the most recent market activity available for similar type contracts.

Significant increases or decreases in future power or capacity prices in isolation would decrease or increase, respectively, the fair value of the derivative liability. Any increases in the risk premiums would increase the fair value of the derivative liabilities. Changes in these fair values are recorded as a regulatory asset or liability and would not impact net income.

Valuations using significant unobservable inputs: The following tables present changes for the years ended December 31, 2012 and 2011, in the Level 3 category of derivative assets and derivative liabilities measured at fair value on a recurring basis. The derivative assets and liabilities are presented on a net basis. The fair value as of January 1, 2012 reflects a reclassification of remaining unregulated wholesale marketing sourcing contracts that had previously been presented as a portfolio along with the unregulated wholesale marketing sales contract as Level 3 under the highest and best use valuation premise. These contracts are now classified within Level 2 of the fair value hierarchy.

(Millions of Dollars)		NU		CL&P		NSTAR Electric(1)		WMECO
Derivatives, Net:
Fair Value as of January 1, 2011		$	(840.2)	$	(806.1)	$	(2.4)	$	-
Net Realized/Unrealized Gains/(Losses) Included in:
	Net Income		0.5		-		-		-
	Regulatory Assets		(161.0)		(153.6)		(4.3)		(7.3)
Settlements			38.5		28.1		3.3		-
Fair Value as of December 31, 2011		$	(962.2)	$	(931.6)	$	(3.4)	$	(7.3)
Liabilities Assumed due to Merger with NSTAR			(5.4)		-		-		-
Transfer to Level 2			32.2		-		-		-
Net Realized/Unrealized Gains/(Losses) Included in:
	Net Income (2)		10.9		-		-		-
	Regulatory Assets		(29.2)		(21.6)		(15.2)		4.3
Settlements			75.1		87.0		3.7		-
Fair Value as of December 31, 2012		$	(878.6)	$	(866.2)	$	(14.9)	$	(3.0)

• NSTAR Electric amounts are included in NU consolidated from the date of the merger, April 10, 2012, through December 31, 2012. NSTAR Electric amounts are not included in NU consolidated for the year ended December 31, 2011.
• The Net Income impact for the year ended December 31, 2012 relates to the unregulated wholesale marketing sales contract and is offset by the gains/(losses) on the unregulated sourcing contracts classified as Level 2 in the fair value hierarchy, resulting in total net losses of $0.7 million

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LEASES

12 Months Ended

Dec. 31, 2012

Notes To Consolidated Financial Statements [Abstract]

Leases of Lessee Disclosure [Text Block]

LEASES

NU, including CL&P, NSTAR Electric, PSNH and WMECO, has entered into lease agreements, some of which are capital leases, for the use of data processing and office equipment, vehicles and office space. In addition, CL&P, PSNH and WMECO incur costs associated with leases entered into by NUSCO and RRR, which are included below in their respective operating lease rental expenses and future minimum rental payments. These intercompany lease amounts are eliminated on an NU consolidated basis.The provisions of the NU, CL&P, NSTAR Electric, PSNH, and WMECO lease agreements generally contain renewal options. Certain lease agreements contain payments impacted by the commercial paper rate plus a credit spread or the consumer price index.

Operating lease rental payments charged to expense were as follows:

					NSTAR
(Millions of Dollars)	NU		CL&P		Electric (1)		PSNH		WMECO
2012	$	14.8	$	8.2	$	6.2	$	2.5	$	3.0
2011		8.4		8.3		19.8		2.1		2.8
2010		11.9		10.0		19.2		2.2		2.8

• NSTAR Electric amounts are included in NU consolidated from the date of the merger, April 10, 2012, through December 31, 2012. NSTAR Electric amounts are not included in NU consolidated for the years ended December 31, 2011 and 2010.

Future minimum rental payments to external third parties excluding executory costs, such as property taxes, state use taxes, insurance, and maintenance, under long-term noncancelable leases, as of December 31, 2012 are as follows:

Capital Leases
(Millions of Dollars)	NU		CL&P		PSNH
2013	$	2.8	$	2.2	$	0.5
2014		2.2		2.0		0.2
2015		2.2		2.0		0.2
2016		2.0		1.9		0.1
2017		2.0		2.0		0.0
Thereafter		7.5		7.3		0.0
Future minimum lease payments		18.7		17.4		1.0
Less amount representing interest		7.6		7.4		0.1
Present value of future minimum lease payments	$	11.1	$	10.0	$	0.9

Operating Leases
(Millions of Dollars)	NU		CL&P		NSTAR Electric		PSNH		WMECO
2013	$	22.4	$	4.3	$	10.9	$	1.3	$	2.7
2014		16.6		3.7		8.2		1.0		1.1
2015		14.1		3.1		7.4		0.8		0.6
2016		11.2		2.3		6.1		0.6		0.3
2017		8.6		1.2		5.1		0.5		0.2
Thereafter		23.3		6.4		10.3		1.8		1.2
Future minimum lease payments	$	96.2	$	21.0	$	48.0	$	6.0	$	6.1

CL&Pentered into certain contracts for the purchase of energy that qualify as leases. These contracts do not have minimum lease payments and therefore are not included in the tables above. However, such contracts have been included in the contractual obligations table in Note 12B, "Commitments and Contingencies - Long-Term Contractual Arrangements," to the consolidated financial statements.

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SHARE-BASED PAYMENTS

12 Months Ended

Dec. 31, 2012

Notes To Consolidated Financial Statements [Abstract]

Shareholders' Equity and Share-based Payments [Text Block]

C.       Employee Stock Ownership Plan

NU maintains an ESOP for purposes of allocating shares to employees participating in the NUSCO 401(k) Savings Plan. Allocations of NU common shares were made from NU treasury shares to satisfy the NUSCO 401(k) Savings Plan obligation to provide a portion of the matching contribution in NU common shares.

For treasury shares used to satisfy the 401(k) Savings Plan matching contributions, compensation expense is recognized equal to the fair value of shares that have been allocated to participants. Any difference between the fair value and the average cost of the allocated treasury shares is charged or credited to Capital Surplus, Paid In. For the years ended December 31, 2012, 2011 and 2010, NU recognized $8.9million, $8.8 million and $8.5 million, respectively, of expense related to the ESOP.

D.       Share-Based Payments

Share-based compensation awards are recorded using the fair value-based method at the date of grant. NU, CL&P, NSTAR Electric, PSNH and WMECO record compensation cost related to these awards, as applicable, for shares issued or sold to their respective employees and officers, as well as the allocation of costs associated with shares issued or sold to NU's service companies' employees and officers that support CL&P, NSTAR Electric, PSNH and WMECO.

Upon consummation of the merger with NSTAR, the NSTAR 1997 Share Incentive Plan and the NSTAR 2007 Long-Term Incentive Plan were assumed by NU. Share-based awards granted under the NSTAR Plans and held by NSTAR employees and officers were generally converted into outstanding NU share-based compensation awards with an estimated fair value of $53.2 million. Refer to Note2, "Merger of NU and NSTAR," for further information regarding the merger transaction. Specifically, as of the merger closing, and as adjusted by the exchange ratio, (1) NU converted outstanding NSTAR stock options into 2,664,894 NU stock options valued at $30.5 million, (2) NU converted NSTAR deferred shares and NSTAR performance shares into 421,775 NU RSU's valued at $15.5 million, and (3) NU converted NSTAR RSU retention awards into 195,619 NU RSU retention awards valued at $7.2 million.

NU Incentive Plan: NU maintains long-term equity-based incentive plans under the NU Incentive Plan in which NU, CL&P, PSNH and WMECO employees, officers and board members are entitled to participate. The NU Incentive Plan was approved in 2007, and authorized NU to grant up to 4,500,000 new shares for various types of awards, including RSUs and performance shares, to eligible employees, officers, and board members. As of December 31, 2012 and 2011, NU had 2,502,512and 2,685,615common shares, respectively, available for issuance under the NU Incentive Plan. In addition to the NU Incentive Plan, NU maintains an ESPP for eligible employees.

NSTAR Incentive Plans: Awards may continue to be granted following the merger under the NSTAR 2007 Long-Term Incentive Plan; however, no additional awards will be granted under the NSTAR 1997 Share Incentive Plan. The aggregate number of common shares initially authorized for issuance under the NSTAR 2007 Long-Term Incentive Plan was 3,500,000. As of December 31, 2012, there were 977,922NU common shares available for issuance under the NSTAR 2007 Long-Term Incentive Plan.

NU accounts for its various share-based plans as follows:

• RSUs - NU records compensation expense, net of estimated forfeitures, on a straight-line basis over the requisite service period based upon the fair value of NU's common shares at the date of grant. The par value of RSUs is reclassified to Common Stock from APIC as RSUs become issued as common shares.
• Performance Shares - NU records compensation expense, net of estimated forfeitures, on a straight-line basis over the requisite service period. Performance shares vest based upon the extent to which Company goals are achieved. For the majority of performance shares, fair value is based upon the value of NU's common shares at the date of grant and compensation expense is recorded based upon the probable outcome of the achievement of Company targets. For the remaining performance shares, vesting is based upon the achievement of the Company's share price as compared to an index of similar equity securities. The fair value at the date of grant for these remaining performance shares was determined using a lattice model and compensation expense is recorded over the requisite service period.
• Stock Options - Stock options issued under the NSTAR Incentive Plan that were outstandingimmediately prior to the completion of the merger with NSTARconverted into fully vested options to acquire NU common shares, as adjusted by the exchange ratio. The fair value of these awards on the merger date was included in the purchase price as it represented consideration transferred in the merger. Accordingly, no compensation expense is recorded for these stock options. Additionally, no compensation expense is recorded for stock options issued under the NU Incentive Plan as these stock options were fully vested prior to January 1, 2006.
• ESPP Shares - For shares sold under the ESPP, no compensation expense is recorded, as the ESPP qualifies as a non-compensatory plan.

RSUs:NU granted RSUs under theannual Long-Term incentive programs that are subject to three-year graded vesting schedules for employees, and one-year graded vesting schedules for board members. RSUs are paid in shares, reduced by amounts sufficient to satisfy withholdings for income taxes, subsequent to vesting. A summary of RSU transactions is as follows:

			Weighted Average
	RSUs		Grant-Date
	(Units)		Fair Value
Outstanding as of January 1, 2010		1,037,912	$	24.07
Granted		258,174	$	26.03
Shares issued		(267,951)	$	25.05
Forfeited		(13,656)	$	24.26
Outstanding as of December 31, 2010		1,014,479	$	24.31
Granted		208,533	$	33.87
Shares issued		(244,782)	$	24.47
Forfeited		(18,310)	$	23.74
Outstanding as of December 31, 2011		959,920	$	26.36
Granted		614,930	$	33.04
Converted NSTAR Awards upon Merger		617,394	$	36.79
Converted from NU Performance Shares upon Merger		451,358	$	34.32
Shares issued		(363,779)	$	29.05
Forfeited		(96,504)	$	34.97
Outstanding as of December 31, 2012		2,183,319	$	31.99

As of December 31, 2012 and 2011, the number and weighted average grant-date fair value of unvested RSUs was 1,417,688 and $34.70 per share, and 403,108and $28.70per share, respectively. The number and weighted average grant-date fair value of RSUs vested during 2012 was 471,323 and $30.20per share, respectively. As of December 31, 2012, 765,631RSUs were fully vested and an additional 1,346,804are expected to vest.

Performance Shares: NU had granted performance shares under the annual Long-Term Incentive programs that vested based upon the extent to which the Company achieved targets at the end of three-year performance measurement periods. Performance shares are paid in shares, after the performance measurement period. A summary of performance share transactions is as follows:

	Performance		Weighted Average
	Shares		Grant-Date
	(Units)		Fair Value
Outstanding as of January 1, 2010		99,086	$	23.93
Granted		149,520	$	25.24
Shares issued		-	$	-
Forfeited		(47)	$	23.96
Outstanding as of December 31, 2010		248,559	$	24.72
Granted		244,870	$	33.76
Shares issued		-	$	-
Forfeited		(10,296)	$	30.47
Outstanding as of December 31, 2011		483,133	$	29.18
Granted		225,935	$	35.09
Converted to RSUs upon Merger		(451,358)	$	34.32
Shares issued		(106,773)	$	24.52
Forfeited		-	$	-
Outstanding as of December 31, 2012		150,937	$	25.04

Upon closing of the merger with NSTAR, 451,358 performance shares under the NU 2011 and 2012 Long-Term Incentive Programs converted to RSUs according to the terms of these programs. The remaining performance shares were measured based upon a modified performance period through the date of the merger, in accordance with the terms of the NU 2010 Incentive Program, with distribution in 2013.

The total compensation cost and associated future income tax benefit recognized by NU, CL&P, NSTAR Electric, PSNH and WMECO for share-based compensation awards were as follows:

NU	For the Years Ended December 31,
(Millions of Dollars)	2012		2011		2010
Compensation Cost	$	25.8	$	12.3	$	10.5
Future Income Tax Benefit		10.2		4.9		4.2

		For the Years Ended December 31,
		2012								2011								2010
(Millions of Dollars)		CL&P		NSTAR Electric(1)		PSNH		WMECO		CL&P		NSTAR Electric(1)		PSNH		WMECO		CL&P		NSTAR Electric(1)		PSNH		WMECO
Compensation Cost		$	4.8	$	7.4	$	1.8	$	1.0	$	7.1	$	7.7	$	2.5	$	1.4	$	6.2	$	6.5	$	2.1	$	1.1
Future Income Tax
	Benefit		1.9		2.9		0.7		0.4		2.8		3.0		1.0		0.6		2.5		2.6		0.9		0.4

• NSTAR Electric amounts are included in NU consolidated from the date of the merger, April 10, 2012, through December 31, 2012. NSTAR Electric amounts are not included in NU consolidated for the years ended December 31, 2011 and 2010.

As of December 31, 2012, there was $26.1million of total unrecognized compensation cost related to nonvested share-based awards for NU, $5.3million for CL&P, $10.6million for NSTAR Electric, $1.8 million for PSNH and $1.1million for WMECO. This cost is expected to be recognized ratably over a weighted-average period of 1.90 years for NU, 2.03 years for CL&P, 1.76 years for NSTAR Electric and1.84 years for PSNH and WMECO.

For the years ended December 31, 2012, 2011 and 2010, additional tax benefits totaling $8.5million, $1.3 million and $0.9million, respectively, increased cash flows from financing activities.

Stock Options:Stock options were granted under the NU and NSTAR Incentive Plans. Options currently outstanding expire ten years from the date of grant and are fully vested. The weighted average remaining contractual lives for the options outstanding as of December 31, 2012 is 4.8 years. A summary of stock option transactions is as follows:

		Weighted Average		Intrinsic Value
	Options	Exercise Price		(Millions)
Outstanding and Exercisable - January 1, 2010	225,216	$	18.96
Exercised	(112,617)	$	19.12	$	1.0
Forfeited and Cancelled	-	$	-
Outstanding and Exercisable - December 31, 2010	112,599	$	18.80
Exercised	(65,225)	$	18.81	$	1.0
Forfeited and Cancelled	-	$	-
Outstanding and Exercisable - December 31, 2011	47,374	$	18.78
Converted NSTAR Options upon Merger	2,664,894	$	23.99
Exercised	(1,166,511)	$	22.53	$	18.7
Forfeited and Cancelled	-	$	-
Outstanding and Exercisable - December 31, 2012	1,545,757	$	24.92	$	21.9

Cash received for options exercised during the year ended December 31, 2012 totaled $26.3 million. The tax benefit realized from stock options exercised totaled $7.5million for the year ended December 31, 2012.

Employee Share Purchase Plan: NU maintains an ESPP for eligible employees, which allows for NU common shares to be purchased by employees at the end of successive six-month offering periods at 95 percent of the closing market price on the last day of each six-month period. Employees are permitted to purchase shares having a value not exceeding 25 percent of their compensation as of the beginning of the offering period up to a limit of $25,000 per annum. The ESPP qualifies as a non-compensatory plan under accounting guidance for share-based payments, and no compensation expense is recorded for ESPP purchases.

During 2012, employees purchased 39,422 shares at discounted prices of $33.01and $37.89. Employees purchased 35,476 shares in 2011 at discounted prices of $31.27 and $32.30. As of December 31, 2012 and 2011, 857,280 and 896,702shares, respectively, remained available for future issuance under the ESPP.

An income tax rate of 40 percent is used to estimate the tax effect on total share-based payments determined under the fair value-based method for all awards. The Company generally settles stock option exercises and fully vested RSUs and performance shares with either the issuance of new common shares or the issuance of common shares purchased in the open market.

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MARKETABLE SECURITIES (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
Schedule Of Available For Sale Securities [Line Items]
Fair Value Of Securities Under Fair Value Option	$ 47.0	$ 41.1
Fair Value, Option, Changes in Fair Value, Gain (Loss)	5.9	(1.1)
Investments, Debt and Equity Securities [Abstract]
Marketable Securities, Restricted	340.4
Available For Sale Securities Debt Maturities Fair Value Abstract
Available For Sale Securities Debt Maturities After Five Through Ten Years Fair Value	54.6
Available For Sale Securities Debt Maturities After Ten Years Fair Value	99.9
Available For Sale Securities Debt Maturities After One Year Through Five Years Fair Value	58.7
Available For Sale Securities Debt Maturities Within One Year Fair Value	66.6
Available For Sale Securities Debt Maturities Fair Value	279.8
Available For Sale Securities Debt Maturities Amortized Cost Abstract
Available For Sale Securities Debt Maturities After One Through Five Years Amortized Cost	57.3
Available For Sale Securities Debt Maturities Within One Year Amortized Cost	66.6
Available For Sale Securities Debt Maturities After Ten Years Amortized Cost	91.5
Available For Sale Securities Debt Maturities After Five Through Ten Years Amortized Cost	51.2
Available For Sale Securities Debt Maturities Amortized Cost	266.6
Fair Value Assets And Liabilities Measured On Recurring Basis Abstract
Investments Fair Value Disclosure	492.3	131.3
Western Massachusetts Electric Company [Member]
Available For Sale Securities Debt Maturities Fair Value Abstract
Available For Sale Securities Debt Maturities After Five Through Ten Years Fair Value	6.1
Available For Sale Securities Debt Maturities After Ten Years Fair Value	6.7
Available For Sale Securities Debt Maturities After One Year Through Five Years Fair Value	17.5
Available For Sale Securities Debt Maturities Within One Year Fair Value	27.4
Available For Sale Securities Debt Maturities Fair Value	57.7
Available For Sale Securities Debt Maturities Amortized Cost Abstract
Available For Sale Securities Debt Maturities After One Through Five Years Amortized Cost	17.5
Available For Sale Securities Debt Maturities Within One Year Amortized Cost	27.4
Available For Sale Securities Debt Maturities After Ten Years Amortized Cost	6.8
Available For Sale Securities Debt Maturities After Five Through Ten Years Amortized Cost	6.0
Available For Sale Securities Debt Maturities Amortized Cost	57.7
Fair Value Assets And Liabilities Measured On Recurring Basis Abstract
Investments Fair Value Disclosure	57.7	57.1
Fair Value Inputs Level 1 Member
Fair Value Assets And Liabilities Measured On Recurring Basis Abstract
Investments Fair Value Disclosure	252.7	42.9
Fair Value Inputs Level 1 Member | Western Massachusetts Electric Company [Member]
Fair Value Assets And Liabilities Measured On Recurring Basis Abstract
Investments Fair Value Disclosure	5.2	0.1
Fair Value Inputs Level 2 [Member]
Fair Value Assets And Liabilities Measured On Recurring Basis Abstract
Investments Fair Value Disclosure	239.6	88.4
Fair Value Inputs Level 2 [Member] | Western Massachusetts Electric Company [Member]
Fair Value Assets And Liabilities Measured On Recurring Basis Abstract
Investments Fair Value Disclosure	52.5	57.0
US Government Debt Securities Member | Fair Value Inputs Level 2 [Member]
Fair Value Assets And Liabilities Measured On Recurring Basis Abstract
Investments Fair Value Disclosure	69.9	11.1
US Government Debt Securities Member | Fair Value Inputs Level 2 [Member] | Western Massachusetts Electric Company [Member]
Fair Value Assets And Liabilities Measured On Recurring Basis Abstract
Investments Fair Value Disclosure	18.7	8.0
Corporate Bond Securities Member | Fair Value Inputs Level 2 [Member]
Fair Value Assets And Liabilities Measured On Recurring Basis Abstract
Investments Fair Value Disclosure	33.0	16.5
Corporate Bond Securities Member | Fair Value Inputs Level 2 [Member] | Western Massachusetts Electric Company [Member]
Fair Value Assets And Liabilities Measured On Recurring Basis Abstract
Investments Fair Value Disclosure	7.0	9.1
Asset Backed Securities Member | Fair Value Inputs Level 2 [Member]
Fair Value Assets And Liabilities Measured On Recurring Basis Abstract
Investments Fair Value Disclosure	28.5	25.9
Asset Backed Securities Member | Fair Value Inputs Level 2 [Member] | Western Massachusetts Electric Company [Member]
Fair Value Assets And Liabilities Measured On Recurring Basis Abstract
Investments Fair Value Disclosure	10.9	7.9
Municipal Bonds Member | Fair Value Inputs Level 2 [Member]
Fair Value Assets And Liabilities Measured On Recurring Basis Abstract
Investments Fair Value Disclosure	93.8	16.1
Municipal Bonds Member | Fair Value Inputs Level 2 [Member] | Western Massachusetts Electric Company [Member]
Fair Value Assets And Liabilities Measured On Recurring Basis Abstract
Investments Fair Value Disclosure	11.6	15.4
Other Debt Securities Member | Fair Value Inputs Level 2 [Member]
Fair Value Assets And Liabilities Measured On Recurring Basis Abstract
Investments Fair Value Disclosure	14.4	18.8
Other Debt Securities Member | Fair Value Inputs Level 2 [Member] | Western Massachusetts Electric Company [Member]
Fair Value Assets And Liabilities Measured On Recurring Basis Abstract
Investments Fair Value Disclosure	4.3	16.6
Cash And Cash Equivalents Member | Fair Value Inputs Level 1 Member
Fair Value Assets And Liabilities Measured On Recurring Basis Abstract
Investments Fair Value Disclosure	40.2	1.8
Cash And Cash Equivalents Member | Fair Value Inputs Level 1 Member | Western Massachusetts Electric Company [Member]
Fair Value Assets And Liabilities Measured On Recurring Basis Abstract
Investments Fair Value Disclosure	5.2	0.1
Mutual Funds [Member] | Fair Value Inputs Level 1 Member
Fair Value Assets And Liabilities Measured On Recurring Basis Abstract
Investments Fair Value Disclosure	212.5	41.1
Debt Securities
Investments, Debt and Equity Securities [Abstract]
Available For Sale Securities Fair Value Disclosure	279.8	90.2
Available-for-sale Securities, Gross Unrealized Gains	13.3	2.0
Available-for-sale Securities, Gross Unrealized Losses	(0.1)	(0.2)
Available For Sale Securities Amortized Cost	266.6	88.4
Debt Securities | Western Massachusetts Electric Company [Member]
Investments, Debt and Equity Securities [Abstract]
Available For Sale Securities Fair Value Disclosure	57.7	57.1
Available-for-sale Securities, Gross Unrealized Gains	0.1
Available-for-sale Securities, Gross Unrealized Losses	(0.1)	(0.2)
Available For Sale Securities Amortized Cost	57.7	57.3
Equity Securities
Investments, Debt and Equity Securities [Abstract]
Available For Sale Securities Fair Value Disclosure	165.5
Available-for-sale Securities, Gross Unrealized Gains	20.0
Available For Sale Securities Amortized Cost	$ 145.5

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LONG-TERM DEBT

12 Months Ended

Dec. 31, 2012

Notes To Consolidated Financial Statements [Abstract]

Long-term Debt [Text Block]

9.LONG-TERM DEBT

Details of long-term debt outstanding for NU, including CL&P, NSTAR Electric, PSNH and WMECO are as follows:

CL&P		As of December 31,
(Millions of Dollars)		2012		2011
First Mortgage Bonds:
	7.875% 1994 Series D due 2024	$	139.8	$	139.8
	4.800% 2004 Series A due 2014		150.0		150.0
	5.750% 2004 Series B due 2034		130.0		130.0
	5.000% 2005 Series A due 2015		100.0		100.0
	5.625% 2005 Series B due 2035		100.0		100.0
	6.350% 2006 Series A due 2036		250.0		250.0
	5.375% 2007 Series A due 2017		150.0		150.0
	5.750% 2007 Series B due 2037		150.0		150.0
	5.750% 2007 Series C due 2017		100.0		100.0
	6.375% 2007 Series D due 2037		100.0		100.0
	5.650% 2008 Series A due 2018		300.0		300.0
	5.500% 2009 Series A due 2019		250.0		250.0
Total First Mortgage Bonds			1,919.8		1,919.8
Pollution Control Notes:
	5.85%-5.95% Fixed Rate Tax Exempt due 2016-2028 (1)		-		116.4
	4.375% Fixed Rate Tax Exempt due 2028		120.5		120.5
	1.25% Fixed Rate Tax Exempt due 2028(2)		125.0		125.0
	1.55% Fixed Rate Tax Exempt due 2031(3)		62.0		62.0
Total Pollution Control Notes			307.5		423.9
Total First Mortgage Bonds and Pollution Control Notes			2,227.3		2,343.7
Fees and Interest due for Spent Nuclear Fuel Disposal Costs			244.3		244.1
CL&P Commercial Paper and Revolver Borrowings(4)			394.8		-
Less Amounts due Within One Year(2)			(125.0)		(62.0)
Unamortized Premiums and Discounts, Net			(3.6)		(4.0)
CL&P Long-Term Debt		$	2,737.8	$	2,521.8
NSTAR Electric		As of December 31,
(Millions of Dollars)		2012		2011(5)
Debentures:
	4.875% due 2012(6)	$	-	$	400.0
	4.875% due 2014		300.0		300.0
	2.375% due 2022(6)		400.0		-
	5.625% due 2017		400.0		400.0
	5.75% due 2036		200.0		200.0
	5.50% due 2040		300.0		300.0
Total Debentures			1,600.0		1,600.0
Bonds:
	7.375% Tax Exempt Sewage Facility Revenue Bonds, due 2015		8.0		8.7
Less Amounts due Within One Year			(1.7)		(400.7)
Unamortized Premiums and Discounts, Net			(5.4)		(4.7)
NSTAR Electric Long-Term Debt		$	1,600.9	$	1,203.3
PSNH		As of December 31,
(Millions of Dollars)		2012		2011
First Mortgage Bonds:
	5.25% 2004 Series L due 2014	$	50.0	$	50.0
	5.60% 2005 Series M due 2035		50.0		50.0
	6.15% 2007 Series N due 2017		70.0		70.0
	6.00% 2008 Series O due 2018		110.0		110.0
	4.50% 2009 Series P due 2019		150.0		150.0
	4.05% 2011 Series Q due 2021		122.0		122.0
	3.20% 2011 Series R due 2021		160.0		160.0
Total First Mortgage Bonds			712.0		712.0
Pollution Control Revenue Bonds:
	4.75% - 5.45% Tax Exempt Series B and C due 2021		198.2		198.2
	Adjustable Rate Series A due 2021		89.3		89.3
Total Pollution Control Revenue Bonds			287.5		287.5
Unamortized Premiums and Discounts, Net			(1.6)		(1.8)
PSNH Long-Term Debt		$	997.9	$	997.7

WMECO		As of December 31,
(Millions of Dollars)		2012		2011
Pollution Control Revenue Bonds and Other Notes:
	5.85% Tax Exempt PCRBs 1993 Series A, due 2028 (7)	$	-	$	53.8
	5.00% Senior Notes Series A, due 2013		55.0		55.0
	5.90% Senior Notes Series B, due 2034		50.0		50.0
	5.24% Senior Notes Series C, due 2015		50.0		50.0
	6.70% Senior Notes Series D, due 2037		40.0		40.0
	5.10% Senior Notes Series E, due 2020		95.0		95.0
	3.50% Senior Notes Series F, due 2021 (8)		250.0		100.0
Total Pollution Control Revenue Bonds and Other Notes			540.0		443.8
Fees and Interest due for Spent Nuclear Fuel Disposal Costs			57.3		57.3
Less Amounts due Within One Year			(55.0)		-
Unamortized Premiums and Discounts, Net			8.0		(1.6)
WMECO Long-Term Debt		$	550.3	$	499.5
OTHER		As of December 31,
(Millions of Dollars)		2012			2011
Yankee Gas - First Mortgage Bonds:
	7.19% Series E due 2012	$	-	$	4.3
	8.48% Series B due 2022		20.0		20.0
	4.80% Series G due 2014		75.0		75.0
	5.26% Series H due 2019		50.0		50.0
	5.35% Series I due 2035		50.0		50.0
	6.90% Series J due 2018		100.0		100.0
	4.87% Series K due 2020		50.0		50.0
Total First Mortgage Bonds			345.0		349.3
Less Amounts due Within One Year			-		(4.3)
Unamortized Premium			0.8		0.9
Yankee Gas Long-Term Debt			345.8		345.9
NSTAR Gas - First Mortgage Bonds:
	9.95% Series J due 2020		25.0		N/A
	7.11% Series K due 2033		35.0		N/A
	7.04% Series M due 2017		25.0		N/A
	4.46% Series N due 2020		125.0		N/A
NSTAR Gas Long-Term Debt			210.0		N/A
Other - Notes and Debentures:
	7.25% Senior Notes Series A due 2012 (NU Parent) (9)		-		263.0
	5.65% Senior Notes Series C due 2013 (NU Parent)		250.0		250.0
	Variable Rate Senior Notes Series D due 2013 (NU Parent) (9)		300.0		-
	4.50% Debentures due 2019 (NSTAR LLC)		350.0		N/A
	Spent Nuclear Fuel Obligation (CYAPC)		179.3		N/A
Total Other Long-Term Debt			1,079.3		513.0
Fair Value Adjustment(10)			259.9		2.3
Less Amounts due Within One Year			(550.0)		(263.0)
Less: Fair Value Adjustment - Current Portion(10)			(31.7)		(2.3)
Total NU Long-Term Debt		$	7,200.2	$	4,614.9

• On October 1, 2012, CL&P redeemed at par four different series of tax-exempt PCRBs totaling $116.4 million. The PCRBs had maturity dates ranging from 2016 through 2028 and coupon rates of 5.85 percent through 5.95 percent.
• The $125 million of tax-exempt PCRBs were issued with an initial fixed rate term period ending on September 2, 2013, and are subject to mandatory tender for purchase on September 3, 2013, at which time CL&P expects to remarket the PCRBs.
• On April 2, 2012, CL&P remarketed $62 million of tax-exempt PCRBs for a three-year period. The PCRBs, which mature on May 1, 2031, carry a coupon rate of 1.55 percent during the current three-year fixed rate period and are subject to mandatory tender for purchase on April 1, 2015.
• On January 15, 2013, CL&P issued $400 million of 2.5 percent Series A First and Refunding Mortgage Bonds with a maturity date of January 15, 2023. The proceeds, net of issuance expenses, were used to repay the amounts outstanding under the CL&P revolver and the NU commercial paper program. As a result, these amounts have been classified as Long-Term Debt as of December 31, 2012.
• NSTAR Electricamounts are not included in NU consolidated as of December 31, 2011.
• On October 15, 2012, NSTAR Electric issued at a discount $400 million of 2.375 percent Debentures at a yield of 2.406 percent that will mature on October 15, 2022. The proceeds, net of issuance costs, were used to pay $400 million of 4.875 percent Debentures that matured on October 15, 2012.
• On October 1, 2012, WMECO redeemed at par $53.8 million of tax-exempt PCRBs. The PCRBs had a maturity date of 2028 and a coupon of 5.85 percent.
• On October 4, 2012, WMECO issued at a premium $150 million of senior unsecured notes at a yield of 2.673 percent that will mature on September 15, 2021. The senior notes are part of the same series of WMECO's existing 3.5 percent coupon Series F Senior Notes that were initially issued in September 2011. As a result, the aggregate principal amount of WMECO's outstanding Series F Senior Notestotaled $250 million.
• On March 22, 2012, NU parent issued $300 million of floating rate Series D Senior Notes with a maturity date of September 20, 2013. The notes have a coupon rate based on the three-month LIBOR rate plus a credit spread of 0.75 percent and will reset quarterly. The notes had an interest rate of 1.059percentas of December 31, 2012. The proceeds, net of issuance expenses, were used to repay at maturity the NU parent $263 million SeriesA Senior Notes that matured on April 1, 2012, to repay short-term borrowings outstanding under the NU parent Credit Agreement and for other general corporate purposes.
• As of December 31, 2012, amount relates to the purchase price adjustment required to record the NSTAR long-term debt issuances at fair value on the date of the merger. As of December 31, 2011, amount related to a fixed to floating interest rate swap on the $263 million NU parent note that matured on April 1, 2012. The change in fair value of the interest component of the debt was recorded as an adjustment to Current Portion - Long Term Debt as of December 31, 2011 with an equal and offsetting adjustment to Current Derivative Assets.

Long-term debt maturities and cash sinking fund requirements on debt outstanding as of December31, 2012 for the years 2013 through 2017 and thereafter, are shown below. These amounts exclude fees and interest due for spent nuclear fuel disposal costs, net unamortized premiums and discounts,and other fair value adjustments as of December 31, 2012:

(Millions of Dollars)	NU		CL&P		NSTAR Electric		PSNH		WMECO
2013	$	731.7	$	125.0	$	1.7	$	-	$	55.0
2014		576.6		150.0		301.7		50.0		-
2015		216.7		162.0		4.7		-		50.0
2016		-		-		-		-		-
2017		745.0		250.0		400.0		70.0		-
Thereafter		4,559.8		1,540.3		899.9		879.5		435.0
Total	$	6,829.8	$	2,227.3	$	1,608.0	$	999.5	$	540.0

The utility plant of CL&P, PSNH, Yankee Gas and NSTAR Gas is subject to the lien of each company's respective first mortgage bond indenture.NSTAR Electric, WMECO, NU Parent and NSTAR LLC debt is unsecured.

The PSNH Series A and Series C tax-exempt bonds are currently callable at 100 percent and 101 percent of par, respectively. The PSNH Series B tax-exempt bond will become callable in June 2013. CL&P's $125 million and $62 million tax-exempt PCRBs, which are subject to mandatory tender for purchase on September3, 2013 and April1, 2015, respectively, cannot be redeemed prior to their respective tender dates. CL&P's $120.5 million tax-exempt PCRBs will be subject to redemption at par on or after September1, 2021. All other long-term debt securities are subject to make-whole provisions.

As of December 31, 2012, CL&P had $307.5 million of tax-exempt PCRBs outstanding. CL&P's obligation to repay each series of PCRBs is secured by first mortgage bonds. Each such series of first mortgage bonds contains similar terms and provisions as the applicable series of PCRBs. If CL&P failed to meet its obligations under the PCRBs, then these first mortgage bonds would become outstanding.

As of December 31, 2012, PSNH had $287.5 million in PCRBs outstanding. PSNH's obligation to repay each series of PCRBs is secured by first mortgage bonds and bond insurance. Each such series of first mortgage bonds contains similar terms and provisions as the applicable series of PCRBs. If PSNH failed to meet its obligations under the PCRBs, then these first mortgage bonds would become outstanding. The 2001 Series A PCRBs, in the aggregate principal amount of $89.3 million, bears interest at a rate that is periodically set pursuant to auctions. PSNH is not obligated to purchase these PCRBs, which mature in 2021, from the remarketing agent. The weighted average effective interest rate on PSNH's Series A variable-rate PCRBs was 0.20 percent in 2012and 0.21 percent in 2011.

NU's, including CL&P, NSTAR Electric, PSNH and WMECO, long-term debt agreements provide that NU and certain of its subsidiaries must comply with certain covenants as are customarily included in such agreements, including a minimum equity requirement for NSTAR Gas. Under the minimum equity requirement, the outstanding long-term debt of NSTAR Gas must not exceed equity. NU and these subsidiaries were in compliance with these covenants as of December31, 2012 and 2011.

Yankee Gas has certain long-term debt agreements that contain cross-default provisions applicable to all of Yankee Gas' outstanding first mortgage bond series. The cross-default provisions on Yankee Gas' Series B Bonds would be triggered if Yankee Gas were to default on a payment due on indebtedness in excess of $2 million. The cross-default provisions on all other series of Yankee Gas' first mortgage bonds would be triggered if Yankee Gas were to default in a payment due on indebtedness in excess of $10 million. No otherdebt issuances contain cross-default provisions as of December 31, 2012.

Spent Nuclear Fuel Obligation: Under the Nuclear Waste Policy Act of 1982, CL&P and WMECO must pay the DOE for the costs of disposal of spent nuclear fuel and high-level radioactive waste for the period prior to the sale of their ownership shares in the Millstone nuclear power stations.

The DOE is responsible for the selection and development of repositories for, and the disposal of, spent nuclear fuel and high-level radioactive waste. For nuclear fuel used to generate electricity prior to April7, 1983 (Prior Period Spent Nuclear Fuel) for CL&P and WMECO, an accrual has been recorded for the full liability, and payment must be made by CL&P and WMECO to the DOE prior to the first delivery of spent fuel to the DOE. After the sale of Millstone, CL&P and WMECO remained responsible for their share of the disposal costs associated with the Prior Period Spent Nuclear Fuel. Until such payment to the DOE is made, the outstanding liability will continue to accrue interest at the 3-month Treasury bill yield rate. In addition, as a result of consolidating CYAPC, NU has consolidated $179.3 millionin additional spent nuclear fuel obligations, including interest, as of December31, 2012.Fees due to the DOE for the disposal of CL&P's and WMECO's Prior Period Spent Nuclear Fuel and CYAPC's and YAEC's spent nuclear fuel obligation include accumulated interest costs of $350million and $219.3million for NU ($177.8million and $177.6 million for CL&P and $41.7million and $41.7million for WMECO) as of December 31, 2012 and 2011, respectively.

For further information, see Note 1B, “Summary of Significant Accounting Policies–Basis of Presentation,” to the consolidated financial statements.

WMECO maintains a trust that holds marketable securities to fund amounts due to the DOE for the disposal of WMECO's Prior Period Spent Nuclear Fuel. CYAPC also maintain trusts to fund amounts due to the DOE for the disposal of spent nuclear fuel. For further information on these trusts, see Note 6, "Marketable Securities," to the consolidated financial statements.

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FAIR VALUE OF FINANCIAL INSTRUMENTS (Tables)

12 Months Ended

Dec. 31, 2012

Notes To Consolidated Financial Statements [Abstract]

Fair Value By Balance Sheet Grouping Text Block

		As of December 31,
		2012				2011
NU		Carrying		Fair		Carrying		Fair
(Millions of Dollars)		Amount		Value		Amount		Value
Preferred Stock Not
	Subject to Mandatory Redemption	$	155.6	$	152.2	$	116.2	$	105.1
Long-Term Debt			7,963.5		8,640.7		4,950.7		5,517.0
Rate Reduction Bonds			82.1		83.0		112.3		116.8

		As of December 31, 2012
		CL&P				NSTAR Electric				PSNH				WMECO
		Carrying		Fair		Carrying		Fair		Carrying		Fair		Carrying		Fair
(Millions of Dollars)		Amount		Value		Amount		Value		Amount		Value		Amount		Value
Preferred Stock Not
	Subject to Mandatory Redemption	$	116.2	$	110.0	$	43.0	$	42.2	$	-	$	-	$	-	$	-
Long-Term Debt			2,862.8		3,295.4		1,602.6		1,818.8		997.9		1,088.0		605.3		660.4
Rate Reduction Bonds			-		-		43.5		43.9		29.3		29.6		9.4		9.5
		As of December 31, 2011
		CL&P				NSTAR Electric (1)				PSNH				WMECO
		Carrying		Fair		Carrying		Fair		Carrying		Fair		Carrying		Fair
(Millions of Dollars)		Amount		Value		Amount		Value		Amount		Value		Amount		Value
Preferred Stock Not
	Subject to Mandatory Redemption	$	116.2	$	105.1	$	43.0	$	41.2	$	-	$	-	$	-	$	-
Long-Term Debt			2,587.8		2,987.1		1,605.1		1,816.1		999.5		1,075.2		501.1		539.8
Rate Reduction Bonds			-		-		127.9		131.2		85.4		88.8		26.9		28.1

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SCHEDULE I - Cash Flows (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended								12 Months Ended
	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Operating Activities:
Net Income	$ 176,600	$ 209,500	$ 46,200	$ 100,800	$ 114,800	$ 91,400	$ 78,700	$ 115,600	$ 533,077	$ 400,513	$ 394,107
Adjustments to Reconcile Net Income to Net Cash Flows Provided by Operating Activities:
Deferred Income Tax Expense (Benefit)									292,000	196,761	210,939
Other Noncash Income (Expense)									17,032	(29,751)	(72,151)
Changes in Current Assets and Liabilities:
Receivables and Unbilled Revenues, Net									20,214	(17,570)	51,285
Change in Accounts Payable									(128,339)	18,916	(44,355)
Taxes Receivable/(Accrued)									5,450	(49,642)	82,103
Other Current Assets and Liabilities									(8,532)	(12,569)	(17,466)
Net Cash Flows Provided by Operating Activities									1,161,229	970,386	1,093,463
Investing Activities:
Other Investing Activities									(35,683)	(13,833)	1,157
Net Cash Flows Used in Investing Activities									(1,467,924)	(1,018,587)	(957,968)
Financing Activities:
Cash Dividends on Common Stock									375,047	194,555	180,542
Increase/(Decrease) in Short-Term Debt									825,000	50,000	166,687
Issuance of Long-Term Debt									850,000	627,500	145,000
Retirements of Long-Term Debt									839,136	369,586	4,286
Other Financing Activities									6,529	(7,123)	512
Net Cash Flows Provided by/(Used in) Financing Activities									345,884	31,365	(139,052)
Supplemental Cash Flow Information [Abstract]
Interest Paid, Net of Amounts Capitalized									356,500	256,300	258,300
Income Taxes Paid									(12,800)	(76,600)	84,500
Net Increase/(Decrease) in Cash									39,189	(16,836)	(3,557)
Cash - Beginning of Year				6,559				23,395	6,559	23,395	26,952
Cash - End of Year	45,748				6,559				45,748	6,559	23,395
Nu Parent [Member]
Operating Activities:
Net Income									526,048	394,955	388,006
Adjustments to Reconcile Net Income to Net Cash Flows Provided by Operating Activities:
Equity In Earnings of Subsidiaries									(567,529)	(422,408)	(396,333)
Cash Dividends Paid to Parent Company by Consolidated Subsidiaries									374,584	389,292	309,669
Deferred Income Tax Expense (Benefit)									(25,933)	(15,934)	8,398
Other Noncash Income (Expense)									20,219	33,238	23,675
Changes in Current Assets and Liabilities:
Receivables and Unbilled Revenues, Net									(6,689)	(436)	791
Change in Accounts Payable									37,006	(183)	590
Other Current Assets and Liabilities									22,496	484	(12,656)
Net Cash Flows Provided by Operating Activities									385,264	390,545	293,746
Investing Activities:
Capital Contributions To Subsidiaries									(81,431)	(233,349)	(313,560)
Return Of Investment In Subsidiaries									8,207	0	5,000
(Increase) Decrease in Due from Related Parties									2,200	400	83,300
(Increase) Decrease In Notes Receivable From Affiliated Company									(876,500)	19,000	(29,687)
Other Investing Activities									(860)	(2,585)	1,703
Net Cash Flows Used in Investing Activities									(948,384)	(216,534)	(253,244)
Financing Activities:
Cash Dividends on Common Stock									375,047	194,555	180,542
Increase/(Decrease) in Short-Term Debt									894,000	19,000	136,687
Issuance of Long-Term Debt									300,000	0	0
Retirements of Long-Term Debt									(263,000)	0	0
Other Financing Activities									7,355	1,338	2,399
Net Cash Flows Provided by/(Used in) Financing Activities									563,308	(174,217)	(41,456)
Supplemental Cash Flow Information [Abstract]
Interest Paid, Net of Amounts Capitalized									29,849	24,951	22,886
Income Taxes Paid									(33,614)	(10,833)	1,291
Net Increase/(Decrease) in Cash									188	(206)	(954)
Cash - Beginning of Year				62				268	62	268	1,222
Cash - End of Year	$ 250				$ 62				$ 250	$ 62	$ 268

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ASSET RETIREMENT OBLIGATIONS

12 Months Ended

Dec. 31, 2012

Notes To Consolidated Financial Statements [Abstract]

Asset Retirement Obligation Disclosure [Text Block]

7.       ASSET RETIREMENT OBLIGATIONS

In accordance with accounting guidance for conditional AROs, NU, including CL&P, NSTAR Electric, PSNH and WMECO, recognizes a liability for the fair value of an ARO on the obligation date if the liability's fair value can be reasonably estimated and is conditional on a future event. Settlement dates and future costs are reasonably estimated when sufficient information becomes available. Management has identified various categories of AROs, primarily certain assets containing asbestos and hazardous contamination and has performed fair value calculations, reflecting expected probabilities for settlement scenarios.

The fair value of an ARO is recorded as a liability in Other Long-Term Liabilities with a corresponding amount included in Property, Plant and Equipment, Net on the accompanying consolidated balance sheets. As the Regulated companies are rate-regulated on a cost-of-service basis, these companies apply regulatory accounting guidance and the costs associated with the Regulated companies' AROs are included in Regulatory Assets as of December 31, 2012 and 2011. The ARO assets are depreciated, and the ARO liabilities are accreted over the estimated life of the obligation with corresponding credits recorded as accumulated depreciation and ARO liabilities, respectively. Both the depreciation and accretion were recorded as increases to Regulatory Assets on the accompanying consolidated balance sheets as of December 31, 2012and 2011.For further information, see Note 3, "Regulatory Accounting," to the consolidated financial statements.

A reconciliation of the beginning and ending carrying amounts of Regulated companies' ARO liabilities are as follows:

NU			As of December 31,
(Millions of Dollars)			2012		2011
Balance as of Beginning of Year			$	56.2	$	53.3
Liability Assumed Upon Consolidation of CYAPC and YAEC				284.2		-
Liability Assumed Upon Merger With NSTAR				35.9		-
Liabilities Incurred During the Year				1.5		2.1
Liabilities Settled During the Year				(7.2)		(0.8)
Accretion				20.2		3.5
Revisions in Estimated Cash Flows				21.4		(1.9)
Balance as of End of Year			$	412.2	$	56.2
	As of December 31,
	2012								2011
			NSTAR								NSTAR
(Millions of Dollars)	CL&P		Electric		PSNH		WMECO		CL&P		Electric(1)		PSNH		WMECO
Balance as of Beginning of Year	$	32.2	$	27.5	$	17.0	$	4.0	$	29.3	$	26.2	$	17.6	$	3.6
Liabilities Incurred During the Year		-		-		0.3		-		1.7		-		0.2		0.2
Liabilities Settled During the Year		(0.9)		(1.0)		-		-		(0.8)		-		-		-
Accretion		2.0		1.5		1.1		0.3		2.0		1.3		1.1		0.2
Revisions in Estimated Cash Flows		0.3		3.4		-		-		-		-		(1.9)		-
Balance as of End of Year	$	33.6	$	31.4	$	18.4	$	4.3	$	32.2	$	27.5	$	17.0	$	4.0
(1)NSTAR Electric amounts are not included in NU consolidated as of December 31, 2011.

The Liability Assumed Upon Consolidation of CYAPC and YAEC represents theCYAPC and YAEC ARO fair value as of the merger date. The fair value of the ARO for CYAPC and YAEC includes uncertainties of the fuel off-load dates related to the DOE's timing of performance regarding its obligation to dispose of the spent nuclear fuel and high level waste. The incremental asset recorded as an offset to the ARO was fully depreciated since the plants have no remaining useful life. Any changes in the assumptions used to calculate the fair value of the ARO are recorded as an offset to the related regulatory asset.The assets held in the decommissioning trust are restricted for settling the asset retirement obligation and all other decommissioning obligations. For further information on the regulatory asset established or the assets held in trust to support this obligation, see Note 3, “Regulatory Accounting,” and Note 6, “Marketable Securities,” to the consolidated financial statements.

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SHORT TERM DEBT

12 Months Ended

Dec. 31, 2012

Notes To Consolidated Financial Statements [Abstract]

Short Term Debt Text Block

8.       SHORT-TERM DEBT

Limits:  The amount of short-term borrowings that may be incurred by CL&P, NSTAR Electric and WMECO is subject to periodic approval by the FERC. On November 30, 2011, the FERC granted authorization to allow CL&P and WMECO to incur total short-term borrowings up to a maximum of $450 million and $300 million, respectively, effective January 1, 2012 through December 31, 2013. On March 22, 2012, the FERC approved CL&P's application requesting to increase its total short-term borrowing capacity from a maximum of $450 million to a maximum of $600 million for the authorization period through December 31, 2013.On May 16, 2012, the FERC granted authorization to allow NSTAR Electric to issue total short-term debt securities in an aggregate principal amount not to exceed $655 million outstanding at any one time, effective October 23, 2012 through October 23, 2014.As a result of the NHPUC having jurisdiction over PSNH's short-term debt, PSNH is not currently required to obtain FERC approval for its short-term borrowings.

PSNH is authorized by regulation of the NHPUC to incur short-term borrowings up to 10 percent of net fixed plant plus an additional $60 million until further ordered by the NHPUC. As of December 31, 2012, PSNH's short-term debt authorization under the 10 percent of net fixed plant test plus $60 million totaled approximately $280 million.

CL&P's certificate of incorporation contains preferred stock provisions restricting the amount of unsecured debt that CL&P may incur, including limiting unsecured indebtedness with a maturity of less than 10 years to 10 percent of total capitalization. In November 2003, CL&P obtained from its preferred stockholders a waiver of such 10 percent limit for a ten-year period expiring in March 2014, provided that all unsecured indebtedness does not exceed 20 percent of total capitalization. As of December 31, 2012, CL&P had $482 million of unsecured debt capacity available under this authorization.

Yankee Gas and NSTAR Gas are not required to obtain approval from any state or federal authority to incur short-term debt.

Credit Agreements and Commercial Paper Programs:On July 25, 2012, NU, CL&P, NSTAR LLC, NSTAR Gas, PSNH, WMECO, and Yankee Gas jointly entered into a five-year $1.15 billion revolving credit facility. The new facility replaced (1) the NSTAR LLC revolving credit facility of $175 million that served to backstop a commercial paper program utilized by NSTAR LLC and was scheduled to expire on December 31, 2012, (2) the NSTAR Gas revolving credit facility of $75 million that expired on June 8, 2012, and (3) the CL&P, PSNH, WMECO, and Yankee Gas joint three-year $400 million and NU parent three-year $500 million unsecured revolving credit facilities that were scheduled to expire on September 24, 2013. The new facility expires on July 25, 2017. Management expects the new facility to be used primarily to backstop the $1.15 billion commercial paper program at NU, which commenced July 25, 2012. The commercial paper program allows NU parent to issue commercial paper as a form of short-term debt. Under the terms of the agreement, NU parent may provide intercompany loans to its subsidiaries, including CL&P, PSNH and WMECO.

On July 25, 2012, NSTAR Electric entered into a five-year $450 million revolving credit facility. This new facility serves to backstop NSTAR Electric's existing $450 million commercial paper program. The new facility expires on July 25, 2017. This new facility replaced a prior $450 million NSTAR Electric revolving credit facility that was scheduled to expire on December 31, 2012.

As of December 31, 2012, NU had $1.15 billion in short-term borrowings outstanding under its commercial paper program. The weighted-average interest rate on these borrowings as of December 31, 2012 was 0.46 percent, which is generally based on money market rates. As of December 31, 2012, there were inter-company loans of $987.5 million from NU to its subsidiaries ($405.1 million for CL&P, $63.3 million for PSNH, and $31.9 million for WMECO). As of December 31, 2012, NSTAR Electric had $276 million in short-term borrowings outstanding under its commercial paper program, leaving $174 million of available borrowing capacity. The weighted-average interest rate on these borrowings as of December 31, 2012 was 0.31 percent, which is generally based on money market rates.

As of December 31, 2011, CL&P and Yankee Gas had $31 million and $30 million, respectively, in short-term borrowings outstanding under the joint $400 million revolving credit facility with weighted average interest rates of 4.03 percent and 2.07 percent, respectively. As of December 31, 2011, NU parent had $256 million in short-term borrowings outstanding under its $500 million revolving credit facility with a weighted average interest rate of 2.20 percent. As of December 31, 2011, there were also $17.9 million, $4 million and $5.4 million in LOCs outstanding under the NU parent credit facility for NU, CL&P and PSNH, respectively. As of December 31, 2011, NSTAR Electric had $141.5 million in short-term borrowingsoutstanding under its existing commercial paper program with a weighted average interest rate of 0.16 percent.

Under the credit facilities, NU and its subsidiariesmust comply with certain financial and non-financial covenants, including a consolidated debt to total capitalization ratio.  NU and its subsidiarieswere in compliance with these covenants as of December 31, 2012 and 2011. If NU or its subsidiaries were not in compliance with these covenants, an event of default would occur requiring all outstanding borrowings by such borrower to be repaid and additional borrowings by such borrower would not be permitted under the respective credit facility.

Amounts outstanding under the commercial paper program are included inNotes Payable forNU and NSTAR Electric and classified in current liabilities on the accompanying consolidated balance sheet as management anticipates that all borrowings under these credit facilities will be outstanding for no more than 364 days at one time. Intercompany loans from NU to PSNH and WMECO are included in Notes Payable to Affiliated Companies and classified in current liabilities on the accompanying consolidated balance sheet.

On January 15, 2013, CL&P issued $400 million of Series A First and Refunding Mortgage Bonds with a coupon rate of 2.5 percent and a maturity date of January 15, 2023. The proceeds, net of issuance costs, were used to pay short-term borrowings outstanding under the CL&P credit agreement and the NU commercial paper program. As a result, as of December 31, 2012, CL&P's credit agreement borrowings of $89 million and intercompany loans related to the commercial paper program of $305.8 million have been classified as Long-Term Debt on the accompanying consolidated balance sheet.

CL&P Credit Agreement: On March 26, 2012, CL&P entered into a five-year unsecured revolving credit facility in the amount of $300 million, which expires on March 26, 2017. Under this facility, CL&P can borrow either on a short-term or a long-term basis subject to regulatory approval. As of December 31, 2012, CL&P had $89 million in borrowings outstanding under this credit agreement with a weighted average interest rate of 3.325 percent.

Under this facility, CL&P may borrow at prime rates or LIBOR-based rates, plus an applicable margin based on the higher of S&P's or Moody's credit ratings.

In addition, CL&P must comply with certain financial and non-financial covenants, including a consolidated debt to total capitalization ratio. CL&P was in compliance with these covenants as of December 31, 2012. If CL&P was not in compliance with these covenants, an event of default would occur requiring all outstanding borrowings to be repaid and additional borrowings would not be permitted under this credit facility.

Working Capital:NU, CL&P, NSTAR Electric, PSNH and WMECO use their available capital resources to fund their respective construction expenditures, meet debt requirements, pay costs, including storm-related costs, pay dividends and fund other corporate obligations, such as pension contributions.The current growth in NU's transmission construction expenditures utilizes a significant amount of cash for projects that have a long-term return on investment and recovery period. In addition, NU's Regulated companies operate in an environment where recovery of its electric and natural gas distribution construction expenditures takes place over an extended period of time. This impacts the timing of the revenue stream designed to fully recover the total investment plus a return on the equity portion of the cost and related financing costs. These factors have resulted in NU's current liabilities exceeding current assets by approximately $1.4 billion, $268 million, $198million and $60 million at NU, CL&P, NSTAR Electric and WMECO, respectively, as of December 31, 2012.

As of December 31, 2012, approximately $730 million of NU's current liabilities relates to long-term debt that will be paid in the next 12 months, consisting of $550 million for NU parent, $55 million for WMECO, and $125 million for CL&P. Approximately $32 million relates to the amortization of the purchase accounting fair value adjustment that will be amortized in the next twelve months. NU, with its strong credit ratings, has several options available in the financial markets to repay or refinance these maturities with the issuance of new long-term debt. NU, CL&P, NSTAR Electric, and WMECO will reduce their short-term borrowings with cash received from operating cash flows or with the issuance of new long-term debt, as deemed appropriate given capital requirements and maintenance of NU's credit rating and profile. Management expects the future operating cash flows of NU, CL&P, NSTAR Electric and WMECO along with the access to financial markets, will be sufficient to meet any future operating requirements and capital investment forecasted opportunities.

Money Pool: As of December 31, 2011, NU parent, CL&P, PSNH, WMECO, Yankee Gas and certain of NU's other subsidiaries were members of the Money Pool. Short-term borrowing needs of the member companies were met with available funds of other member companies, including funds borrowed by NU parent. Investing and borrowing subsidiaries received or paid interest based on the average daily federal funds rate.  In NU's consolidated financial statements, Money Pool amounts payable to or receivable from members eliminated in consolidation. As of December31, 2011, Money Pool amounts were as follows:

	As of and for the Year Ended December 31, 2011
(Millions of Dollars, except percentages)	CL&P			PSNH			WMECO
Borrowings from/(Lendings to)	$	58.5		$	(55.9)		$	(11.0)
Weighted-Average Interest Rates		0.08	%		0.1	%		0.1	%

The net borrowings from/(lendings to)the Money Pool were recorded in Notes Payable to/Notes Receivable from Affiliated Companies on the accompanying consolidated balance sheets, respectively.

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PENSION BENEFITS AND POSTRETIREMENT BENEFITS OTHER THAN PENSIONS

12 Months Ended

Dec. 31, 2012

Notes To Consolidated Financial Statements [Abstract]

Pension and Other Postretirement Benefits Disclosure [Text Block]

10.       EMPLOYEE BENEFITS

A.Pension Benefits and Postretirement Benefits Other Than Pensions

NUSCO sponsors a defined benefit retirement plan that covers most employees, including CL&P, PSNH, and WMECO employees, hired before 2006 (or as negotiated, for bargaining unit employees), referred to as the NUSCO Pension Plan. NSTAR Electric serves as plan sponsor for a defined benefit retirement plan that covers most employeesof NSTAR Electric & Gas, hired before October 1, 2012, or as negotiated by bargaining unit employees, referred to as the NSTAR Pension Plan. Both plans are subject to the provisions of ERISA, as amended by the PPA of 2006. NUSCO and NSTAR Electric & Gas each maintain SERPs and other non-qualified defined benefit retirement plans (herein collectively referred to as the SERP Plans), which provide benefits in excess of Internal Revenue Code limitations to eligible current and retired participants that would have otherwise been provided under the Pension Plans.

NUSCO and NSTAR Electric & Gas also sponsor defined benefit postretirement plans that provide certain retiree health care benefits, primarily medical and dental, and life insurance benefits to retiring employees that meet certain age and service eligibility requirements (NUSCO PBOP Plans and NSTAR PBOP Plan, respectively). Under certain circumstances, eligible retirees are required to contribute to the costs of postretirement benefits. The benefits provided under the NUSCO and NSTAR PBOP Plans are not vested and the Company has the right to modify any benefit provision subject to applicable laws at that time.

The funded status of the Pension, SERP and PBOP Plans is calculated based on the difference between the benefit obligation and the fair value of plan assets. The funded status of the Pension, SERP and PBOP Plans is recorded on the consolidated balance sheets as a liability with an offset to Accumulated Other Comprehensive Income/(Loss). Pension, SERP and PBOP costs for the Regulated companies are recorded as Regulatory Assets as these amounts are recovered from customers. Regulatory accounting was also applied to the portions of the NUSCO and NSTAR Electric & Gas costs that support the Regulated companies, as these costs are also recovered from customers. Pension and PBOP costs for the unregulated companies are recorded on an after-tax basis to Accumulated Other Comprehensive Income/(Loss). For further information, see Note3, "Regulatory Accounting," and Note15, "Accumulated Other Comprehensive Income/(Loss)," to the consolidated financial statements. The SERP Plans do not have plan assets.

For the NUSCO Pension and PBOP Plans, the expected return on plan assets is calculated by applying the assumed rate of return to a four-year rolling average of plan asset fair values, which reduces year-to-year volatility. Investment gains or losses for this purpose are the difference between the calculated expected return and the actual return. As investment gains and losses are reflected in the average plan asset fair values, they are subject to amortization with other unrecognized actuarial gains or losses. For the NSTAR Pension and PBOP Plans, the entire difference between the actual return and calculated expected return on plan assets is reflected as a component of unrecognized actuarial gain or loss. Unrecognized actuarial gains or losses are amortized as a component of Pension and PBOP expense over the estimated average future employee service period.

Pension and SERPPlans:The funded status of each of the plans is recorded on the respective sponsor's balance sheet: NUSCO (NUSCO Pension and NUSCO SERP), NSTAR Electric (NSTAR Pension) and NSTAR Electric & Gas (NSTAR SERP). The NUSCO plans are accounted for under the multiple-employer approachwhile the NSTAR plans are accounted for under the multi-employer approach. Accordingly, the balance sheet of NSTAR Electric reflects the full funded status of the NSTAR Pension Plan.

The following tablesprovide information on the Pension and SERPPlan benefit obligations, fair values of Pension Plan assets, and funded status:

	Pension and SERP
NU	As of December 31,
(Millions of Dollars)	2012		2011
Change in Benefit Obligation
Benefit Obligation as of Beginning of Year	$	(3,098.9)	$	(2,820.9)
Liabilities Assumed from Merger with NSTAR		(1,409.7)		-
Service Cost		(84.3)		(55.4)
Interest Cost		(198.3)		(153.3)
Actuarial Loss		(429.7)		(206.1)
Benefits Paid - Excluding Lump Sum Payments		187.7		134.4
Benefits Paid - SERP		4.2		2.4
SERP curtailment		6.2		-
Benefit Obligation as of End of Year	$	(5,022.8)	$	(3,098.9)
Change in Pension Plan Assets
Fair Value of Plan Assets as of Beginning of Year	$	2,005.9	$	1,977.6
Assets Assumed from Merger with NSTAR		984.7		-
Employer Contributions		222.4		143.6
Actual Return on Plan Assets		386.0		19.1
Benefits Paid - Excluding Lump Sum Payments		(187.7)		(134.4)
Fair Value of Plan Assets as of End of Year	$	3,411.3	$	2,005.9
Funded Status as of December 31st	$	(1,611.5)	$	(1,093.0)

	Pension and SERP
	As of December 31, 2012								As of December 31, 2011
			NSTAR								NSTAR
(Millions of Dollars)	CL&P		Electric (1)		PSNH		WMECO		CL&P		Electric (1),(2)		PSNH		WMECO
Change in Benefit Obligation
Benefit Obligation as of Beginning of Year	$	(1,043.8)	$	(1,346.2)	$	(497.9)	$	(215.8)	$	(964.3)	$	(1,184.6)	$	(448.7)	$	(196.6)
Service Cost		(21.8)		(30.3)		(11.8)		(4.1)		(19.5)		(26.0)		(10.6)		(3.9)
Interest Cost		(51.2)		(58.9)		(24.4)		(10.5)		(51.9)		(61.0)		(24.4)		(10.7)
Actuarial Loss		(117.4)		(63.6)		(61.3)		(24.0)		(64.0)		(138.0)		(33.2)		(15.4)
Benefits Paid - Excluding Lump Sum Payments		55.9		69.0		19.7		11.3		55.6		59.6		18.9		10.8
Benefits Paid - SERP		0.3		-		-		-		0.3		-		0.1		-
Curtailment and Settlement Payments		-		-		(0.3)		-		-		3.8		-		-
Benefit Obligation as of End of Year	$	(1,178.0)	$	(1,430.0)	$	(576.0)	$	(243.1)	$	(1,043.8)	$	(1,346.2)	$	(497.9)	$	(215.8)
Change in Pension Plan Assets
Fair Value of Plan Assets as of Beginning of Year	$	869.6	$	988.5	$	279.7	$	202.0	$	918.4	$	930.6	$	185.4	$	209.8
Employer Contributions		-		25.0		87.7		-		-		125.0		112.6		-
Actual Return/(Loss) on Plan Assets		123.9		124.6		38.9		27.8		6.8		(3.7)		0.6		3.0
Benefits Paid - Excluding Lump Sum Payments		(55.9)		(69.0)		(19.7)		(11.3)		(55.6)		(59.6)		(18.9)		(10.8)
Benefits Paid - Settlement Payments		-		-		-		-		-		(3.8)		-		-
Fair Value of Plan Assets as of End of Year	$	937.6	$	1,069.1	$	386.6	$	218.5	$	869.6	$	988.5	$	279.7	$	202.0
Funded Status as of December 31st	$	(240.4)	$	(360.9)	$	(189.4)	$	(24.6)	$	(174.2)	$	(357.7)	$	(218.2)	$	(13.8)
Pension and SERP benefits funded status includes the current portion of the SERP liability, which is included in Other Current Liabilities on the accompanying consolidated balance sheets.
Although the Company maintains a trust to support the SERP with marketable securities held in the NU supplemental benefit trust, the plan itself does not contain any assets. For information regarding the investments in the NU supplemental benefit trust that are used to informally support the SERP liability, see Note 6, "Marketable Securities," to the consolidated financial statements.
(1) NSTAR Electric amounts do not include benefit obligations of the NSTAR SERP Plan.
(2) NSTAR Electric amounts are not included in NU consolidated as of December 31, 2011.

The accumulated benefit obligation for the Pension and SERP Plans is as follows:
		Pension and SERP
		As of December 31,
(Millions of Dollars)		2012		2011
NU		$	4,622.1	$	2,810.6
CL&P			1,061.8		938.4
NSTAR Electric (1)			1,353.1		1,271.3
PSNH			515.9		444.8
WMECO			221.3		195.5
(1)	NSTAR Electric amounts are not included in NU consolidated as of December 31, 2011 and do not include the accumulated benefit obligation for the SERP Plan.
The following actuarial assumptions were used in calculating the Pension and SERP Plans' year end funded status:

	Pension and SERP
	As of December 31,
	2012		2011
NUSCO Pension and SERP Plans
Discount Rate	4.24	%	5.03	%
Compensation/Progression Rate	3.50	%	3.50	%
NSTAR Pension and SERP Plans
Discount Rate	4.13	%	4.52	%
Compensation/Progression Rate	4.00	%	4.00	%

Pension and SERPExpense: For the NUSCO Plans, NU allocates net periodic pension expense to its subsidiaries based on the actual participant demographic data for each subsidiary's participants. Benefit payments to participants and contributions are also tracked for each subsidiary. The actual investment return in the trust each year is allocated to each of the subsidiaries annually in proportion to the investment return expected to be earned during the year.For the NSTARPension Plan, the net periodic pension expense recorded at NSTAR Electric represents the full cost of the plan and then a portion of the costs are allocated to affiliated companies based on participant demographic data.The components of net periodic benefit expense, the portion of pension amounts capitalized related to employees working on capital projects, and intercompany allocations not included in the net periodic benefit expense amounts for the Pension and SERP Planswere as follows:

		Pension and SERP
		For the Year Ended December 31, 2012
						NSTAR
(Millions of Dollars)		NU		CL&P		Electric (1)		PSNH		WMECO
Service Cost		$	84.3	$	21.8	$	30.3	$	11.8	$	4.1
Interest Cost			198.3		51.2		58.9		24.4		10.5
Expected Return on Plan Assets			(220.9)		(70.6)		(65.6)		(28.2)		(16.4)
Actuarial Loss			172.4		49.6		63.1		16.2		10.7
Prior Service Cost/(Credit)			7.9		3.6		(0.6)		1.5		0.8
Total Net Periodic Benefit Expense		$	242.0	$	55.6	$	86.1	$	25.7	$	9.7
Curtailments and Settlements		$	2.2	$	-	$	-	$	-	$	-
Related Intercompany Allocations			N/A	$	42.8	$	(12.3)	$	10.1	$	8.1
Capitalized Pension Expense		$	70.6	$	26.8	$	30.7	$	7.9	$	5.1
		Pension and SERP
		For the Year Ended December 31, 2011
						NSTAR
(Millions of Dollars)		NU		CL&P		Electric (1)		PSNH		WMECO
Service Cost		$	55.4	$	19.5	$	26.0	$	10.6	$	3.9
Interest Cost			153.3		51.9		61.0		24.4		10.7
Expected Return on Plan Assets			(170.8)		(76.6)		(71.4)		(19.8)		(17.7)
Actuarial Loss			84.2		33.4		48.6		10.7		7.1
Prior Service Cost/(Credit)			9.7		4.2		(0.7)		1.8		0.9
Total Net Periodic Benefit Expense		$	131.8	$	32.4	$	63.5	$	27.7	$	4.9
Related Intercompany Allocations			N/A	$	34.1	$	(10.2)	$	7.6	$	6.2
Capitalized Pension Expense		$	29.7	$	16.6	$	19.8	$	7.6	$	2.7
		Pension and SERP
		For the Year Ended December 31, 2010
						NSTAR
(Millions of Dollars)		NU		CL&P		Electric (1)		PSNH		WMECO
Service Cost		$	51.0	$	17.6	$	23.6	$	10.0	$	3.5
Interest Cost			152.6		52.2		61.8		24.1		10.7
Expected Return on Plan Assets			(182.6)		(85.8)		(62.8)		(14.7)		(19.5)
Actuarial Loss			53.5		20.7		50.4		7.2		4.3
Prior Service Cost/(Credit)			9.9		4.2		(0.7)		1.8		0.9
Total Net Periodic Benefit Expense/(Income)		$	84.4	$	8.9	$	72.3	$	28.4	$	(0.1)
Related Intercompany Allocations			N/A	$	25.2	$	(11.6)	$	6.0	$	4.5
Capitalized Pension Expense		$	16.9	$	3.8	$	24.5	$	6.9	$	-
(1)	NSTAR Electric amounts are included in NU consolidated from the date of the merger, April 10, 2012, through December 31, 2012. NSTAR Electric amounts are not included in NU consolidated for the years ended December 31, 2011 and 2010. NSTAR Electric's allocated expense associated with the NSTAR SERP was $3.6 million, $4.4 million and $3.9 million for the years ended December 31, 2012, 2011 and 2010, respectively, and are not included in the NSTAR Electric amounts in the tables above.
The following actuarial assumptions were used to calculate Pension and SERP expense amounts:

	Pension and SERP
	For the Years Ended December 31,
NUSCO Pension and SERP Plans	2012		2011		2010
Discount Rate	5.03	%	5.57	%	5.98	%
Expected Long-Term Rate of Return	8.25	%	8.25	%	8.75	%
Compensation/Progression Rate	3.50	%	3.50	%	4.00	%
NSTAR Pension and SERP Plans
Discount Rate	4.52	%	5.30	%	5.85	%
Expected Long-Term Rate of Return	7.30	%	8.00	%	8.00	%
Compensation/Progression Rate	4.00	%	4.00	%	4.00	%

The following is a summary of the changes in plan assets and benefit obligations recognized in Regulatory Assets and OCI as well as amounts in Regulatory Assets and OCI reclassified as net periodic benefit expense during the years presented:
	Amounts Reclassified To/From
	Regulatory Assets				OCI
(Millions of Dollars)	For the Years Ended December 31,
NU Pension and SERP Plans (1)	2012		2011		2012		2011
Actuarial Losses Arising During the Year	$	245.7	$	334.8	$	19.1	$	23.0
Actuarial Losses Reclassified as Net Periodic Benefit Expense		(164.6)		(79.4)		(7.8)		(4.8)
Prior Service Cost Reclassified as Net Periodic Benefit Expense		(7.7)		(9.4)		(0.2)		(0.3)
The following is a summary of the remaining Regulatory Assets and Accumulated Other Comprehensive Loss amounts that have not been recognized as components of net periodic benefit expense as of December 31, 2012 and 2011, and the amounts that are expected to be recognized as components in 2013:
		Regulatory Assets as of				Expected		AOCI as of			Expected
(Millions of Dollars)	December 31,					2013	December 31,				2013
NU Pension and SERP Plans (1)	2012		2011		Expense		2012		2011		Expense
Actuarial Loss	$	1,973.8	$	1,126.1	$	200.8	$	81.5	$	70.2	$	9.3
Prior Service Cost		21.2		29.3		3.9		1.2		1.4		0.2

(1)The NU consolidated amounts reflect the NSTAR Pension and SERPPlans from the date of the merger, April10, 2012, through December 31, 2012.

NSTAR Electric continues to maintain reporting requirements as an SEC registrant. Included in the amounts above as of December 31, 2012 are $724 million of unrecognized actuarial losses included in Regulatory Assets for NSTAR Electric. For the year ended December 31, 2012, NSTAR Electric reclassified $62.8 million of actuarial losses and $0.6 million of prior service creditas net periodic benefit expense and $4.6 million of actuarial losses arose during the year. As of December 31, 2011, NSTAR Electric had $782.3 million of unrecognized actuarial losses and $0.6 million of prior service creditincluded in Regulatory Assets. For the year ended December 31, 2011, NSTAR Electric reclassified $48.4 million of actuarial losses and $0.7 million of prior service credit as net periodic benefit expense and $212 million of actuarial losses arose during the year.

PBOP Plans: The NUSCO Plans are accounted for under the multiple-employer basis while the NSTAR Plan is accounted for under the multi-employer basis. Accordingly, the funded status of the NUSCO PBOP Plans is allocated to its subsidiaries, including CL&P, PSNH and WMECO, while the NSTAR PBOP Plan is not reflected on the SEC registrant NSTAR Electric's balance sheet.

NU annually funds postretirement costs through tax deductible contributions to external trusts.

The following tables represent information on PBOP Plan benefit obligations, fair values of plan assets, and funded status:

		PBOP
		As of December 31,
				2012						2011
(Millions of Dollars)		NU (1)		CL&P		PSNH		WMECO		NU		CL&P		PSNH		WMECO
Change in Benefit Obligation
Benefit Obligation as of Beginning of Year		$	(520.9)	$	(198.9)	$	(99.2)	$	(42.9)	$	(489.9)	$	(190.2)	$	(89.9)	$	(41.7)
Liabilities Assumed from Merger with NSTAR			(770.6)		-		-		-		-		-		-		-
Service Cost			(15.7)		(3.0)		(2.0)		(0.6)		(9.2)		(2.9)		(1.9)		(0.6)
Interest Cost			(49.0)		(9.2)		(4.6)		(2.0)		(25.7)		(10.0)		(4.8)		(2.2)
Actuarial Gain/(Loss)			70.9		1.2		0.3		0.1		(30.1)		(8.5)		(8.4)		(1.0)
Federal Subsidy on Benefits Paid			(6.2)		(1.7)		(0.6)		(0.3)		(4.1)		(1.8)		(0.7)		(0.4)
Benefits Paid			58.2		14.8		5.9		3.2		38.1		14.5		6.5		3.0
Benefit Obligation as of End of Year		$	(1,233.3)	$	(196.8)	$	(100.2)	$	(42.5)	$	(520.9)	$	(198.9)	$	(99.2)	$	(42.9)
Change in Plan Assets
Fair Value of Plan Assets as of Beginning of Year		$	285.4	$	112.2	$	58.7	$	27.1	$	278.5	$	108.6	$	56.9	$	26.7
Assets Assumed from Merger with NSTAR			330.4		-		-		-		-		-		-		-
Actual Return on Plan Assets			78.8		15.0		7.5		3.5		(2.5)		(1.2)		(0.4)		(0.1)
Employer Contributions			72.7		19.8		9.2		3.6		47.5		19.3		8.7		3.5
Benefits Paid			(58.2)		(14.8)		(5.9)		(3.2)		(38.1)		(14.5)		(6.5)		(3.0)
Fair Value of Plan Assets as of End of Year		$	709.1	$	132.2	$	69.5	$	31.0	$	285.4	$	112.2	$	58.7	$	27.1
Funded Status as of December 31st		$	(524.2)	$	(64.6)	$	(30.7)	$	(11.5)	$	(235.5)	$	(86.7)	$	(40.5)	$	(15.8)
(1)	The NU consolidated results include NSTAR PBOP Plan activity from the date of the merger, April 10, 2012, through December 31, 2012.

The following actuarial assumptions were used in calculating the PBOP Plans' year end funded status:
	PBOP
	As of December 31,
	2012		2011
NUSCO PBOP Plans
Discount Rate	4.04	%	4.84	%
Health Care Cost Trend Rate	7.00	%	7.00	%
NSTAR PBOP Plan
Discount Rate	4.35	%	N/A
Health Care Cost Trend Rate	7.10	%	N/A

PBOP Expense: For the NUSCO Plans, NU allocates net periodic postretirement benefits expense to its subsidiaries based on the actual participant demographic data for each subsidiary's participants. Benefit payments to participants and contributions are also tracked for each subsidiary. The actual investment return in the trust is allocated to each of the subsidiaries annually in proportion to the investment return expected to be earned during the year. For the NSTAR Plan, NSTAR allocates the net periodic postretirement expenses to its subsidiaries based on actual participant demographic data for each of its subsidiaries. The net periodic postretirement expense allocated to NSTAR Electric was $34.1 million, $26 million, and $33 million for the years ended December 31, 2012, 2011 and 2010, respectively.

The components of net periodic postretirement benefit expenseand intercompany allocations not included in the net periodic benefit expense amounts for the PBOP Plans were as follows

			PBOP
		For the Years Ended December 31,
		2012								2011								2010
(Millions of Dollars)		NU (1)		CL&P		PSNH		WMECO		NU		CL&P		PSNH		WMECO		NU		CL&P		PSNH		WMECO
Service Cost		$	15.7	$	3.0	$	2.0	$	0.6	$	9.2	$	2.9	$	1.9	$	0.6	$	8.5	$	2.7	$	1.8	$	0.6
Interest Cost			49.0		9.2		4.6		2.0		25.7		10.0		4.8		2.2		26.8		10.5		5.0		2.3
Expected Return
	on Plan Assets		(39.2)		(9.1)		(4.6)		(2.1)		(21.6)		(8.7)		(4.3)		(2.0)		(21.7)		(8.7)		(4.3)		(2.1)
Actuarial Loss			36.0		7.5		3.6		1.2		19.0		7.2		3.2		1.1		16.7		6.3		2.7		0.9
Prior Service
	Cost/(Credit)		(1.4)		-		-		-		(0.3)		-		-		1.3		(0.3)		-		-		-
Net Transition
	Obligation Cost(2)		12.2		6.1		2.5		1.3		11.6		6.2		2.5		-		11.6		6.1		2.5		1.3
Total Net Periodic Benefit Expense		$	72.3	$	16.7	$	8.1	$	3.0	$	43.6	$	17.6	$	8.1	$	3.2	$	41.6	$	16.9	$	7.7	$	3.0
Related Intercompany Allocations			N/A	$	7.9	$	2.0	$	1.5		N/A	$	8.2	$	2.0	$	1.5		N/A	$	7.9	$	2.0	$	1.4
(1)	The NU consolidated results include NSTAR PBOP Plan expense from the date of the merger, April 10, 2012, through December 31, 2012.
(2)	The NUSCO PBOP Plans and NSTAR PBOP Plan transition obligation costs will be fully amortized in 2013.

The following actuarial assumptions were used to calculate PBOP expense amounts:
	PBOP
	For the Years Ended December 31,
	2012		2011		2010
NUSCO PBOP Plans
Discount Rate	4.84	%	5.28	%	5.73	%
Expected Long-Term Rate of Return	8.25	%	8.25	%	8.75	%
NSTAR PBOP Plan
Discount Rate	4.58	%	N/A		N/A
Expected Long-Term Rate of Return	7.30	%	N/A		N/A

The following is a summary of the changes in plan assets and benefit obligations recognized in Regulatory Assets and OCI as well as amounts in Regulatory Assets and OCI reclassified as net periodic benefit (expense)/income during the years presented:
		Amounts Reclassified To/From
	Regulatory Assets				OCI
(Millions of Dollars)	For the Years Ended December 31,
NU PBOP Plans (1)	2012		2011		2012		2011
Actuarial (Gains)/Losses Arising During the Year	$	(108.6)	$	50.2	$	(1.8)	$	4.0
Actuarial Losses Reclassified as Net Periodic Benefit Expense		(34.9)		(18.1)		(1.1)		(0.9)
Prior Service Credit Reclassified as Net Periodic Benefit Income		1.4		0.3		-		-
Transition Obligation Reclassified as Net Periodic Benefit Expense		(11.9)		(11.3)		(0.2)		(0.2)
The following is a summary of the remaining Regulatory Assets and Accumulated Other Comprehensive Loss amounts that have not been recognized as components of net periodic benefit expense as of December 31, 2012 and 2011, and the amounts that are expected to be recognized as components in 2013:
		Regulatory Assets as of			Expected			AOCI as of			Expected
(Millions of Dollars)	December 31,				2013			December 31,			2013
NU PBOP Plans (1)	2012		2011		Expense		2012		2011		Expense
Actuarial Loss	$	376.1	$	196.3	$	31.4	$	9.2	$	12.1	$	1.0
Prior Service Credit		(6.7)		(2.4)		(2.1)		-		-		-
Transition Obligation		-		11.4		-		-		0.2		-

• The NU consolidated amounts include the NSTAR PBOP Plan from the date of the merger, April 10, 2012, through December31, 2012.

For the NUSCO PBOPPlans, the health care cost trend assumption is 7 percent, subsequently decreasing 50 basis points per year to an ultimate rate of 5 percent in 2017. For the NSTAR PBOPPlan, the health care cost trend assumption is 7.10 percent, subsequently decreasing to an ultimate rate of 4.50 percent in 2024.

Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. The effect of changing the assumed health care cost trend rate by one percentage point for the year ended December 31, 2012 would have the following effects:

(Millions of Dollars)	One Percentage		One Percentage
NU PBOP Plans	Point Increase		Point Decrease
Effect on Postretirement Benefit Obligation	$	126.5	$	(101.7)
Effect on Total Service and Interest Cost Components		8.9		(6.9)

Estimated Future Benefit Payments: The following benefit payments, which reflect expected future service, are expected to be paid by the Pension, SERP and PBOP Plans:
(Millions of Dollars)	Pension
NU Consolidated	and SERP		PBOP
2013	$	238.0	$	63.5
2014		257.3		65.0
2015		252.4		66.8
2016		261.2		68.2
2017		270.6		69.6
2018-2022		1,510.2		366.3
NSTAR Pension Plan
2013	$	77.7		N/A
2014		79.6		N/A
2015		82.6		N/A
2016		83.2		N/A
2017		85.1		N/A
2018-2022		462.2		N/A

Contributions: NU's policy is to annually fund the NUSCO and NSTAR Pension Plans in an amount at least equal to an amount that will satisfy federal requirements. NU contributed $197.4 million to the NUSCO Pension Plan in 2012, of which $87.7 million was contributed by PSNH. NSTAR Electric contributed $25 million to the NSTAR Pension Plan for the year ended December 31, 2012. Based on the current status of the NUSCO Pension Plan, NUanticipates making a contribution of approximately $203million in 2013, of which $107 million is required to meet minimum federalfunding requirements. NSTAR Electric anticipates making a contribution of approximately $82 million in 2013 to the NSTAR Pension Plan, of which $38 million is required to meet minimum federal funding requirements.

For the PBOP Plans, it is NU's policy to annually fund the NUSCO PBOP Plans in an amount equal to the PBOP Plans' postretirement benefit cost, excluding curtailment and termination benefits. NU contributed $50 million to the NUSCO PBOP Plans in 2012 and expects to make $25.7 million in contributions in 2013. NU contributes an amount that approximates annual benefit payments to the NSTAR PBOP Plan. NU contributed $22.7 million to the NSTAR PBOP Plan for the period April 10, 2012 to December 31, 2012 and expects to make $30 million in contributions in 2013.

Fair Value of Pension and PBOP Plan Assets: Pension and PBOP funds are held in external trusts. Trust assets, including accumulated earnings, must be used exclusively for Pension and PBOP payments. NU's investment strategy for its Pension and PBOP Plans is to maximize the long-term rates of return on these plans' assets within an acceptable level of risk. The investment strategy for each asset category includes a diversification of asset types, fund strategies and fund managers and establishes target asset allocations that are routinely reviewed and periodically rebalanced. In 2012, PBOP assets were comprised of specific assets within the defined benefit pension plan trust (401(h) assets) as well as assets held in the PBOP Plans. The investment policy and strategy of the 401(h) assets is consistent with those of the defined benefit pension plans, which are detailed below. NU's expected long-term rates of return on Pension and PBOP Plan assets are based on these target asset allocation assumptions and related expected long-term rates of return. In developing its expected long-term rate of return assumptions for the Pension and PBOP Plans, NU evaluated input from actuaries and consultants, as well as long-term inflation assumptions and historical returns. For the year ended December 31, 2012, management has assumed long-term rates of return of 8.25 percenton NUSCO Pension and PBOP Plan assets and 7.30 percent on the NSTAR Pensionand PBOP Plan assets.These long-term rates of return are based on the assumed rates of return for the target asset allocations as follows:

		As of December 31,
		2012 and 2011		2012		2011		2012
		NUSCO Pension and PBOP		NSTAR Pension Plan		NSTAR Pension Plan		NSTAR PBOP Plan
		Target	Assumed	Target	Assumed	Target	Assumed	Target	Assumed
		Asset	Rate	Asset	Rate	Asset	Rate	Asset	Rate
		Allocation	of Return	Allocation	of Return	Allocation	of Return	Allocation	of Return
Equity Securities:
	United States	24%	9%	25%	8.3%	22%	8.6%	25%	8.3%
	International	13%	9%	13%	8.6%	12%	8.9%	20%	8.6%
	Emerging Markets	3%	10%	5%	8.8%	5%	8.8%	5%	8.8%
	Private Equity	12%	13%	-	-	-	-	-	-
Debt Securities:
	Fixed Income	20%	5%	21%	4.6%	15%	4.4%	30%	4.6%
	High Yield Fixed Income	3.5%	7.5%	9%	6.5%	9%	6.2%	-	-
	Emerging Markets Debt	3.5%	7.5%	4%	6.4%	3%	6.8%	-	-
Real Estate and Other Assets		8%	7.5%	10%	7.9%	11%	7.7%	10%	7.9%
Hedge Funds		13%	7%	13%	8.4%	23%	8.6%	10%	8.4%

The following table presents, by asset category, the Pension and PBOP Plan assets recorded at fair value on a recurring basis by the level in which they are classified within the fair value hierarchy:

		NU Consolidated Pension Plans
		Fair Value Measurements as of December 31,
(Millions of Dollars)		2012								2011
Asset Category:		Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Equity Securities:
	United States (2)	$	336.5	$	302.8	$	270.6	$	909.9	$	218.7	$	14.8	$	259.4	$	492.9
	International (2)		42.0		362.6		52.1		456.7		20.0		221.9		-		241.9
	Emerging Markets(2)		-		135.3		-		135.3		-		66.6		-		66.6
	Private Equity		26.7		-		267.9		294.6		11.3		-		255.1		266.4
Fixed Income(3)			54.9		629.2		315.1		999.2		17.8		268.7		276.2		562.7
Real Estate and
	Other Assets		-		78.9		235.4		314.3		24.8		57.8		71.8		154.4
Hedge Funds			-		-		418.9		418.9		-		-		240.0		240.0
Total Master Trust Assets		$	460.1	$	1,508.8	$	1,560.0	$	3,528.9	$	292.6	$	629.8	$	1,102.5	$	2,024.9
	Less: 401(h) PBOP Assets(4)								(117.6)								(19.0)
Total Pension Assets								$	3,411.3							$	2,005.9
		NSTAR Pension Plan
		Fair Value Measurements as of December 31,
(Millions of Dollars)		2012								2011(1) (5)
Asset Category:		Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Equity Securities:
	United States (2)	$	96.7	$	246.4	$	-	$	343.1	$	77.0	$	212.3	$	-	$	289.3
	International(2)		-		98.3		52.1		150.4		4.0		82.8		41.4		128.2
	Emerging Markets(2)		-		55.9		-		55.9		-		46.9		-		46.9
Fixed Income(3)			54.9		292.5		-		347.4		124.7		230.3		-		355.0
Real Estate			-		-		127.2		127.2		-		-		111.0		111.0
Hedge Funds			-		-		122.7		122.7		-		-		126.6		126.6
Total Master Trust Assets		$	151.6	$	693.1	$	302.0	$	1,146.7	$	205.7	$	572.3	$	279.0	$	1,057.0
	Less: 401(h) PBOP Assets(4)								(77.6)								(68.5)
Total Pension Assets								$	1,069.1							$	988.5
		NU Consolidated PBOP Plans
		Fair Value Measurements as of December 31,
(Millions of Dollars)		2012								2011
Asset Category:		Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Cash and Cash
	Equivalents	$	9.7	$	-	$	-	$	9.7	$	5.9	$	-	$	-	$	5.9
Equity Securities:
	United States(2)		116.3		57.7		36.3		210.3		116.9		-		10.7		127.6
	International(2)		68.0		29.7		-		97.7		29.6		-		-		29.6
	Emerging Markets(2)		7.7		14.0		-		21.7		4.6		-		-		4.6
Fixed Income (3)			-		137.7		32.1		169.8		-		44.3		26.0		70.3
Hedge Funds			-		-		39.6		39.6		-		-		16.1		16.1
Private Equity			-		-		11.3		11.3		-		-		5.1		5.1
Real Estate and Other
	Assets		-		4.7		26.7		31.4		-		4.7		2.5		7.2
Total		$	201.7	$	243.8	$	146.0	$	591.5	$	157.0	$	49.0	$	60.4	$	266.4
	Add: 401(h) PBOP Assets(4)								117.6								19.0
Total PBOP Assets								$	709.1							$	285.4

##SR

• The NSTARPension Plan amounts are not included in NU consolidated as of December 31, 2011.
• United States, International and Emerging Marketsequity securities classified as Level 2 include investments in commingled funds and unrealized gains/(losses) on holdings in equity index swaps. Level 3 investments include hedge funds that are overlayed with equity index swaps and futures contracts and funds invested in equities that have redemption restrictions.
• Fixed Income investments classified as Level 3 investments include fixed income funds that invest in a variety of opportunistic fixed income strategies, and hedge funds that are overlayed with fixed income futures.
• The assets of the Pension Plans include a 401(h) account that has been allocated to provide health and welfare postretirement benefits under the PBOP Plans.
• For NSTAR Electric, certain pension assets have been reclassified to the current year presentation in order to align the reporting of pension assets subsequent to the closing of the merger.

CL&P, PSNH and WMECO participate in the NUSCO Pension Plan and NUSCO PBOP Plans. Each company participating in the plans is allocated a portion of the total plan assets. As of December 31, 2012 and 2011, the NUSCO Pension Plan has total assets of $2,342.6 million and $2,005.9 million, respectively.CL&P, PSNH and WMECO's portion of these total plan assets were 40 percent, 17 percent and 9 percent, respectively,as of December 31, 2012, and 43 percent, 14 percent and 10percent, respectively,as of December 31, 2011.The NUSCO PBOP Plans had total plan assets of $334.9 million and $285.4 million as of December 31, 2012 and 2011, respectively. CL&P, PSNH and WMECO's share of these assets were 39 percent, 21 percent and 9 percent, respectively,as of both December 31, 2012 and 2011.

The Company values assets based on observable inputs when available. Equity securities, exchange traded funds and futures contracts classified as Level 1 in the fair value hierarchy are priced based on the closing price on the primary exchange as of the balance sheet date. Commingled funds included in Level 2 equity securities are recorded at the net asset value provided by the asset manager, which is based on the market prices of the underlying equity securities. Swaps are valued using pricing models that incorporate interest rates and equity and fixed income index closing prices to determine a net present value of the cash flows. Fixed income securities, such as government issued securities, corporate bonds and high yield bond funds, are included in Level 2 and are valued using pricing models, quoted prices of securities with similar characteristics or discounted cash flows. The pricing models utilize observable inputs such as recent trades for the same or similar instruments, yield curves, discount margins and bond structures. Hedge funds and investments in opportunistic fixed income funds are recorded at net asset value based on the values of the underlying assets. The assets in the hedge funds and opportunistic fixed income funds are valued using observable inputs and are classified as Level 3 within the fair value hierarchy due to redemption restrictions. Private Equity investments and Real Estate and Other Assets are valued using the net asset value provided by the partnerships, which are based on discounted cash flows of the underlying investments, real estate appraisals or public market comparablesof the underlying investments. These investments are classified as Level 3 due to redemption restrictions.

Fair Value Measurements Using Significant Unobservable Inputs (Level 3): The following tables present changes for the Level 3 category of Pension and PBOP Plan assets for the years ended December 31, 2012 and 2011:

		NU Consolidated Pension Plans
		United								Real Estate
		States				Private		Fixed		and Other		Hedge
(Millions of Dollars)		Equity		International		Equity		Income		Assets		Funds		Total
Balance as of January 1, 2011		$	266.0	$	-	$	229.5	$	247.6	$	43.7	$	247.1	$	1,033.9
Actual Return/(Loss) on Plan Assets:
	Relating to Assets Still Held as of Year End		(6.6)		-		20.0		(1.5)		1.6		(7.1)		6.4
	Relating to Assets Distributed During the Year		-		-		19.5		(2.8)		0.3		-		17.0
Purchases, Sales and Settlements			-		-		(13.9)		32.9		26.2		-		45.2
Balance as of December 31, 2011		$	259.4	$	-	$	255.1	$	276.2	$	71.8	$	240.0	$	1,102.5
Assets Assumed from Merger with NSTAR			-		41.4		-		-		111.0		126.6		279.0
Actual Return/(Loss) on Plan Assets:
	Relating to Assets Still Held as of Year End		11.2		10.7		17.0		42.1		5.7		21.8		108.5
	Relating to Assets Distributed During the Year		-		-		15.0		0.7		7.6		(0.3)		23.0
Purchases, Sales and Settlements			-		-		(19.2)		(3.9)		39.3		30.8		47.0
Balance as of December 31, 2012		$	270.6	$	52.1	$	267.9	$	315.1	$	235.4	$	418.9	$	1,560.0
		NU Consolidated PBOP Plans
		United						Real Estate
		States		Private		Fixed		and Other			Hedge
(Millions of Dollars)		Equity		Equity		Income		Assets			Funds		Total
Balance as of January 1, 2011		$	10.1	$	0.3	$	23.4	$	-	$	16.4	$	50.2
Actual Return/(Loss) on Plan Assets:
	Relating to Assets Still Held as of Year End		0.6		0.6		0.2		(0.1)		(0.3)		1.0
Purchases, Sales and Settlements			-		4.2		2.4		2.6		-		9.2
Balance as of December 31, 2011		$	10.7	$	5.1	$	26.0	$	2.5	$	16.1	$	60.4
Assets Assumed from Merger with NSTAR			19.7		-		-		18.4		21.4		59.5
Actual Return on Plan Assets:
	Relating to Assets Still Held as of Year End		5.9		1.6		4.0		3.0		2.1		16.6
Purchases, Sales and Settlements			-		4.6		2.1		2.8		-		9.5
Balance as of December 31, 2012		$	36.3	$	11.3	$	32.1	$	26.7	$	39.6	$	146.0
		NSTAR Pension Plan
				Real Estate
				and Other
(Millions of Dollars)		International		Assets		Hedge Funds		Total
Balance as of January 1, 2011		$	45.1	$	86.8	$	157.9	$	289.8
Actual Return/(Loss) on Plan Assets:
	Relating to Assets Still Held as of Year End		(3.7)		8.7		(4.8)		0.2
	Relating to Assets Distributed During the Year		-		-		0.2		0.2
Purchases, Sales and Settlements			-		15.5		(26.7)		(11.2)
Balance as of December 31, 2011		$	41.4	$	111.0	$	126.6	$	279.0
Actual Return/(Loss) on Plan Assets:
	Relating to Assets Still Held as of Year End		10.7		9.9		5.6		26.2
	Relating to Assets Distributed During the Year		-		-		(0.3)		(0.3)
Purchases, Sales and Settlements			-		6.3		(9.2)		(2.9)
Balance as of December 31, 2012		$	52.1	$	127.2	$	122.7	$	302.0

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COMMON SHARESHOLDERS' EQUITY AND NONCONTROLLING INTERESTS (NU) (Tables)

12 Months Ended

Dec. 31, 2012

Notes To Consolidated Financial Statements [Abstract]

Minority Interest Disclosure Text Block

19.	COMMON SHAREHOLDERS' EQUITY AND NONCONTROLLING INTERESTS (NU)
A summary of the changes in Common Shareholders' Equity and Noncontrolling Interests of NU is as follows:
								Noncontrolling
		Common						Interest -
		Shareholders'		Noncontrolling		Total		Preferred Stock
(Millions of Dollars)		Equity		Interest		Equity		of Subsidiaries
Balance as of January 1, 2010		$	3,577.9	$	-	$	3,577.9	$	116.2
Net Income			394.1		-		394.1		-
Dividends on Common Shares			(181.7)		-		(181.7)		-
Dividends on Preferred Stock			(6.1)		-		(6.1)		(6.1)
Issuance of Common Shares			7.4		-		7.4		-
Contributions to NPT			-		1.4		1.4		-
Other Transactions, Net			19.6		-		19.6		-
Net Income Attributable to Noncontrolling Interests			(0.1)		0.1		-		6.1
Other Comprehensive Income (Note 15)			0.1		-		0.1		-
Balance as of December 31, 2010		$	3,811.2	$	1.5	$	3,812.7	$	116.2
Net Income			400.5		-		400.5		-
Dividends on Common Shares			(195.6)		-		(195.6)		-
Dividends on Preferred Stock			(5.6)		-		(5.6)		(5.6)
Issuance of Common Shares			5.9		-		5.9		-
Contributions to NPT			-		1.2		1.2		-
Other Transactions, Net			23.9		-		23.9		-
Net Income Attributable to Noncontrolling Interests			(0.3)		0.3		-		5.6
Other Comprehensive Loss (Note 15)			(27.3)		-		(27.3)		-
Balance as of December 31, 2011		$	4,012.7	$	3.0	$	4,015.7	$	116.2
Net Income			533.1		-		533.1		-
Purchase Price of NSTAR (1)			5,038.3		-		5,038.3		-
Other Equity Impacts of Merger with NSTAR (2)			3.4		(3.4)		-		39.4
Dividends on Common Shares			(375.5)		-		(375.5)		-
Dividends on Preferred Stock			(7.0)		-		(7.0)		(7.0)
Issuance of Common Shares			13.3		-		13.3		-
Contributions to NPT			-		0.3		0.3		-
Other Transactions, Net			21.1		-		21.1		-
Net Income Attributable to Noncontrolling Interests			(0.1)		0.1		-		7.0
Other Comprehensive Loss (Note 15)			(2.2)		-		(2.2)		-
Balance as of December 31, 2012		$	9,237.1	$	0.0	$	9,237.1	$	155.6

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ASSET RETIREMENT OBLIGATIONS (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Asset Retirement Obligation, Beginning Balance	$ 56.2	$ 53.3
Liability Assumed Upon Consolidation of CYAPC and YAEC	284.2
Liability Assumed Upon Merger With Nstar	35.9
Asset Retirement Obligation, Liabilities Incurred		2.1
Asset Retirement Obligation, Liabilities Settled	(7.2)	(0.8)
Asset Retirement Obligation, Accretion Expense	20.2	3.5
Asset Retirement Obligation, Revision of Estimate	21.4	(1.9)
Asset Retirement Obligation, Ending Balance	412.2	56.2
The Connecticut Light And Power Company [Member]
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Asset Retirement Obligation, Beginning Balance	32.2	29.3
Asset Retirement Obligation, Liabilities Incurred		1.7
Asset Retirement Obligation, Liabilities Settled	(0.9)	(0.8)
Asset Retirement Obligation, Accretion Expense	2.0	2.0
Asset Retirement Obligation, Revision of Estimate	0.3
Asset Retirement Obligation, Ending Balance	33.6	32.2
Public Service Company Of New Hampshire [Member]
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Asset Retirement Obligation, Beginning Balance	17.0	17.6
Asset Retirement Obligation, Liabilities Incurred	0.3	0.2
Asset Retirement Obligation, Accretion Expense	1.1	1.1
Asset Retirement Obligation, Revision of Estimate		(1.9)
Asset Retirement Obligation, Ending Balance	18.4	17.0
Western Massachusetts Electric Company [Member]
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Asset Retirement Obligation, Beginning Balance	4.0	3.6
Asset Retirement Obligation, Liabilities Incurred		0.2
Asset Retirement Obligation, Accretion Expense	0.3	0.2
Asset Retirement Obligation, Ending Balance	4.3	4.0
NSTAR Electric Company [Member]
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Asset Retirement Obligation, Beginning Balance	27.5	26.2
Asset Retirement Obligation, Liabilities Settled	(1.0)
Asset Retirement Obligation, Accretion Expense	1.5	1.3
Asset Retirement Obligation, Ending Balance	$ 31.4	$ 27.5

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SEGMENT INFORMATION (Tables)

12 Months Ended

Dec. 31, 2012

Segment Reporting Information [Line Items]

Schedule Of Segment Reporting Information By Segment Text Block

		For the Year Ended December 31, 2012
		Electric		Natural Gas
(Millions of Dollars)		Distribution		Distribution		Transmission		Other		Eliminations		Total
Operating Revenues		$	4,716.5	$	572.9	$	861.5	$	803.8	$	(680.9)	$	6,273.8
Depreciation and Amortization			(530.3)		(49.1)		(109.2)		(56.4)		4.2		(740.8)
Other Operating Expenses			(3,585.4)		(445.2)		(251.6)		(817.0)		684.4		(4,414.8)
Operating Income/(Loss)			600.8		78.6		500.7		(69.6)		7.7		1,118.2
Interest Expense			(165.6)		(31.3)		(96.7)		(43.6)		7.3		(329.9)
Interest Income			2.8		-		0.4		7.1		(7.1)		3.2
Other Income, Net			8.9		0.4		7.3		795.0		(795.1)		16.5
Income Tax (Expense)/Benefit			(150.2)		(16.9)		(159.2)		55.5		(4.1)		(274.9)
Net Income			296.7		30.8		252.5		744.4		(791.3)		533.1
Net Income Attributable
	to Noncontrolling Interests		(4.4)		-		(2.8)		-		-		(7.2)
Net Income Attributable
	to Controlling Interest	$	292.3	$	30.8	$	249.7	$	744.4	$	(791.3)	$	525.9
Total Assets (as of)		$	18,047.3	$	2,717.4	$	6,187.7	$	18,832.6	$	(17,482.2)	$	28,302.8
Cash Flows Used for
	Investments in Plant	$	611.7	$	148.7	$	663.6	$	48.3	$	-	$	1,472.3

		For the Year Ended December 31, 2011
		Electric		Natural Gas
(Millions of Dollars)		Distribution		Distribution		Transmission		Other		Eliminations		Total
Operating Revenues		$	3,343.1	$	430.8	$	635.4	$	541.3	$	(484.9)	$	4,465.7
Depreciation and Amortization			(337.2)		(27.7)		(84.0)		(16.8)		2.5		(463.2)
Other Operating Expenses			(2,637.4)		(333.5)		(188.2)		(534.1)		484.9		(3,208.3)
Operating Income/(Loss)			368.5		69.6		363.2		(9.6)		2.5		794.2
Interest Expense			(123.8)		(21.0)		(76.7)		(33.7)		4.8		(250.4)
Interest Income			3.7		-		0.5		5.3		(5.3)		4.2
Other Income, Net			11.6		1.3		10.7		455.2		(455.3)		23.5
Income Tax (Expense)/Benefit			(67.6)		(18.2)		(95.6)		14.3		(3.9)		(171.0)
Net Income			192.4		31.7		202.1		431.5		(457.2)		400.5
Net Income Attributable
	to Noncontrolling Interests		(3.3)		-		(2.5)		-		-		(5.8)
Net Income Attributable
	to Controlling Interest	$	189.1	$	31.7	$	199.6	$	431.5	$	(457.2)	$	394.7
Total Assets (as of)		$	9,653.1	$	1,511.3	$	3,792.9	$	6,618.0	$	(5,928.2)	$	15,647.1
Cash Flows Used for
	Investments in Plant	$	540.7	$	98.2	$	388.9	$	48.9	$	-	$	1,076.7

		For the Year Ended December 31, 2010
		Electric		Natural Gas
(Millions of Dollars)		Distribution		Distribution		Transmission		Other		Eliminations		Total
Operating Revenues		$	3,802.0	$	434.3	$	625.6	$	521.6	$	(485.3)	$	4,898.2
Depreciation and Amortization			(501.2)		(23.8)		(86.7)		(15.8)		3.8		(623.7)
Other Operating Expenses			(2,925.1)		(340.0)		(192.1)		(505.4)		488.0		(3,474.6)
Operating Income			375.7		70.5		346.8		0.4		6.5		799.9
Interest Expense			(133.4)		(17.9)		(73.2)		(17.4)		4.6		(237.3)
Interest Income			0.7		-		1.8		5.3		(6.3)		1.5
Other Income, Net			24.4		0.8		14.3		436.4		(435.5)		40.4
Income Tax (Expense)/Benefit			(90.3)		(20.7)		(109.3)		11.0		(1.1)		(210.4)
Net Income			177.1		32.7		180.4		435.7		(431.8)		394.1
Net Income Attributable
	to Noncontrolling Interests		(3.6)		-		(2.6)		-		-		(6.2)
Net Income Attributable
	to Controlling Interest	$	173.5	$	32.7	$	177.8	$	435.7	$	(431.8)	$	387.9
Cash Flows Used for
	Investments in Plant	$	560.1	$	82.5	$	239.2	$	72.7	$	-	$	954.5

XML

PREFFERED STOCK NOT SUBJECT TO MANDATORY REDEMPTION (DETAILS) (USD $)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Class Of Stock [Line Items]
Preferred Stock, Value, Outstanding	$ 155,600,000	$ 116,200,000
Cash Dividends on Preferred Stock	7,029,000	5,559,000	5,559,000
The Connecticut Light And Power Company [Member]
Class Of Stock [Line Items]
Preferred Stock, Shares Outstanding	2,324,000
Preferred Stock, Value, Outstanding	116,200,000	116,200,000
Cash Dividends on Preferred Stock	5,559,000	5,559,000	5,559,000
Preferred Stock Authorized Description	The preferred stock of CL&P and NSTAR Electric is not subject to mandatory redemption and is presented as a noncontrolling interest of a subsidiary in the accompanying consolidated financial statements of NU. CL&P Preferred Stock: CL&P's charter authorizes it to issue up to 9 million shares of preferred stock ($50 par value per share).
NSTAR Electric Company [Member]
Class Of Stock [Line Items]
Preferred Stock, Shares Outstanding	430,000
Preferred Stock, Value, Outstanding	43,000,000	43,000,000
Cash Dividends on Preferred Stock	1,960,000	1,960,000	1,960,000
Preferred Stock Authorized Description	NSTAR Electric is authorized to issue 2,890,000 shares ($100 par value per share).
Series 1947 $1.90 [Member] | The Connecticut Light And Power Company [Member]
Class Of Stock [Line Items]
Preferred Stock, Shares Outstanding	163,912
Preferred Stock, Redemption Price Per Share	$ 52.50
Preferred Stock, Value, Outstanding	8,200,000	8,200,000
Series 1947 $2.00 [Member] | The Connecticut Light And Power Company [Member]
Class Of Stock [Line Items]
Preferred Stock, Shares Outstanding	336,088
Preferred Stock, Redemption Price Per Share	$ 54.00
Preferred Stock, Value, Outstanding	16,800,000	16,800,000
Series 1949 $2.04 [Member] | The Connecticut Light And Power Company [Member]
Class Of Stock [Line Items]
Preferred Stock, Shares Outstanding	100,000
Preferred Stock, Redemption Price Per Share	$ 52.00
Preferred Stock, Value, Outstanding	5,000,000	5,000,000
Series 1949 $2.20 [Member] | The Connecticut Light And Power Company [Member]
Class Of Stock [Line Items]
Preferred Stock, Shares Outstanding	200,000
Preferred Stock, Redemption Price Per Share	$ 52.50
Preferred Stock, Value, Outstanding	10,000,000	10,000,000
Series 1949 3.90% [Member] | The Connecticut Light And Power Company [Member]
Class Of Stock [Line Items]
Preferred Stock, Shares Outstanding	160,000
Preferred Stock, Redemption Price Per Share	$ 50.50
Preferred Stock, Value, Outstanding	8,000,000	8,000,000
Series E 1954 $2.06 [Member] | The Connecticut Light And Power Company [Member]
Class Of Stock [Line Items]
Preferred Stock, Shares Outstanding	200,000
Preferred Stock, Redemption Price Per Share	$ 51.00
Preferred Stock, Value, Outstanding	10,000,000	10,000,000
Series F 1955 $2.09 [Member] | The Connecticut Light And Power Company [Member]
Class Of Stock [Line Items]
Preferred Stock, Shares Outstanding	100,000
Preferred Stock, Redemption Price Per Share	$ 51.00
Preferred Stock, Value, Outstanding	5,000,000	5,000,000
Series 1956 4.5% [Member] | The Connecticut Light And Power Company [Member]
Class Of Stock [Line Items]
Preferred Stock, Shares Outstanding	104,000
Preferred Stock, Redemption Price Per Share	$ 50.75
Preferred Stock, Value, Outstanding	5,200,000	5,200,000
Series 1958 4.96% [Member] | The Connecticut Light And Power Company [Member]
Class Of Stock [Line Items]
Preferred Stock, Shares Outstanding	100,000
Preferred Stock, Redemption Price Per Share	$ 50.50
Preferred Stock, Value, Outstanding	5,000,000	5,000,000
Series 1963 4.5% [Member] | The Connecticut Light And Power Company [Member]
Class Of Stock [Line Items]
Preferred Stock, Shares Outstanding	160,000
Preferred Stock, Redemption Price Per Share	$ 50.50
Preferred Stock, Value, Outstanding	8,000,000	8,000,000
Series 1967 5.28% [Member] | The Connecticut Light And Power Company [Member]
Class Of Stock [Line Items]
Preferred Stock, Shares Outstanding	200,000
Preferred Stock, Redemption Price Per Share	$ 51.43
Preferred Stock, Value, Outstanding	10,000,000	10,000,000
Series G of 1968 $3.24 [Member] | The Connecticut Light And Power Company [Member]
Class Of Stock [Line Items]
Preferred Stock, Shares Outstanding	300,000
Preferred Stock, Redemption Price Per Share	$ 51.84
Preferred Stock, Value, Outstanding	15,000,000	15,000,000
Series 1968 6.56% [Member] | The Connecticut Light And Power Company [Member]
Class Of Stock [Line Items]
Preferred Stock, Shares Outstanding	200,000
Preferred Stock, Redemption Price Per Share	$ 51.44
Preferred Stock, Value, Outstanding	10,000,000	10,000,000
Preferred Stock 4.25% [Member] | NSTAR Electric Company [Member]
Class Of Stock [Line Items]
Preferred Stock, Shares Outstanding	180,000
Preferred Stock, Redemption Price Per Share	$ 103.625
Preferred Stock, Value, Outstanding	18,000,000	18,000,000
Preferred Stock 4.78% [Member] | NSTAR Electric Company [Member]
Class Of Stock [Line Items]
Preferred Stock, Shares Outstanding	250,000
Preferred Stock, Redemption Price Per Share	$ 102.80
Preferred Stock, Value, Outstanding	$ 25,000,000	$ 25,000,000

XML

PREFFERED STOCK (TABLES)

12 Months Ended

Dec. 31, 2012

Notes To Consolidated Financial Statements [Abstract]

Schedule of Preferred Stock [Text Block]

				Redemption Price		Shares Outstanding as of	As of December 31,
Series				Per Share		December 31, 2012 and 2011	2012		2011
CL&P
$	1.90		Series of 1947	$	52.50	163,912	$	8.2	$	8.2
$	2.00		Series of 1947	$	54.00	336,088		16.8		16.8
$	2.04		Series of 1949	$	52.00	100,000		5.0		5.0
$	2.20		Series of 1949	$	52.50	200,000		10.0		10.0
	3.90	%	Series of 1949	$	50.50	160,000		8.0		8.0
$	2.06		Series E of 1954	$	51.00	200,000		10.0		10.0
$	2.09		Series F of 1955	$	51.00	100,000		5.0		5.0
	4.50	%	Series of 1956	$	50.75	104,000		5.2		5.2
	4.96	%	Series of 1958	$	50.50	100,000		5.0		5.0
	4.50	%	Series of 1963	$	50.50	160,000		8.0		8.0
	5.28	%	Series of 1967	$	51.43	200,000		10.0		10.0
$	3.24		Series G of 1968	$	51.84	300,000		15.0		15.0
	6.56	%	Series of 1968	$	51.44	200,000		10.0		10.0
Total CL&P						2,324,000	$	116.2	$	116.2
NSTAR Electric(1)
	4.25	%	Series	$	103.625	180,000	$	18.0	$	18.0
	4.78	%	Series	$	102.80	250,000		25.0		25.0
Total NSTAR Electric						430,000	$	43.0	$	43.0
Fair Value Adjustment due to Merger with NSTAR								(3.6)		N/A
Total NU Consolidated Preferred Stock of Subsidiaries								155.6		116.2

XML

INCOME TAXES (Details) (USD $)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Current Income Tax Expense (Benefit), Continuing Operations [Abstract]
Current Federal Tax Expense (Benefit)	$ (30,900,000)	$ 3,000,000	$ 9,000,000
Current State and Local Tax Expense (Benefit)	17,600,000	(26,000,000)	(6,500,000)
Total Current Income Tax Expense (Benefit)	(13,300,000)	(23,000,000)	2,500,000
Deferred Income Tax Expense (Benefit), Continuing Operations [Abstract]
Deferred Federal Income Tax Expense (Benefit)	291,300,000	187,700,000	201,200,000
Deferred State and Local Income Tax Expense (Benefit)	800,000	9,100,000	9,700,000
Total Deferred Income Taxes	292,000,000	196,761,000	210,939,000
Investment Tax Credit	(3,900,000)	(2,800,000)	(3,000,000)
Income Tax Expense	274,926,000	170,953,000	210,409,000
Income Tax Expense (Benefit), Continuing Operations, Income Tax Reconciliation [Abstract]
Income Before Income Tax Expense	808,003,000	571,466,000	604,516,000
Income Tax Reconciliation, Income Tax Expense (Benefit), at Federal Statutory Income Tax Rate	282,800,000	200,000,000	211,600,000
Tax Effect Of Differences [Abstract]
Income Tax Reconciliation, Nondeductible Expense, Depreciation	(10,800,000)	(14,200,000)	(9,500,000)
Investment Tax Credit	(3,900,000)	(2,800,000)	(3,000,000)
Income Tax Reconciliation, Tax Credits, Other	(3,800,000)	(3,500,000)	(3,800,000)
Income Tax Reconciliation, State and Local Income Taxes	4,400,000	22,100,000	12,500,000
Medicare Subsidy	0	0	15,600,000
Tax Asset Valuation Allowance / Reserve Adjustments	7,600,000	(33,100,000)	(10,500,000)
Income Tax Reconciliation, Other Adjustments	(1,400,000)	2,500,000	(2,500,000)
Income Tax Expense	274,926,000	170,953,000	210,409,000
Effective Income Tax Rate, Continuing Operations	34.00%	29.90%	34.80%
Deferred Tax Liabilities [Abstract]
Deferred Tax Liabilities Resulting From Property Tax Accruals And Other	89,600,000	58,900,000
Deferred Tax Liabilities, Property, Plant and Equipment	3,468,800,000	1,920,500,000
Deferred Tax Liabilities, Regulatory Amounts [Abstract]
Deferred Tax Liabilities Regulatory Assets Securitized Contract Termination Costs	16,600,000	39,600,000
Deferred Tax Liabilities Regulatory Assets Other Regulatory Deferrals	1,561,100,000	1,135,000,000
Deferred Tax Liabilities Regulatory Assets Tax Effect Tax Regulatory Assets	217,200,000	184,600,000
Deferred Tax Liabilities Regulatory Assets Derivative Assets	36,200,000	39,100,000
Goodwill Deferred Tax Liability	210,900,000	0
Deferred Tax Liabilities, Other	136,100,000	24,500,000
Deferred Tax Liabilities, Total	5,736,500,000	3,402,200,000
Deferred Tax Assets, Net [Abstract]
Deferred Tax Assets, Derivative Instruments	380,600,000	415,300,000
Deferred Tax Assets, Regulatory Assets and Liabilities	257,900,000	157,900,000
Deferred Tax Assets Employee Benefits	811,400,000	539,600,000
Deferred Tax Assets Tax Effect Tax Regulatory Assets	17,200,000	15,500,000
Deferred Tax Assets, Other	242,400,000	204,200,000
Deferred Tax Assets, Gross	2,134,700,000	1,556,500,000
Deferred Tax Assets, Valuation Allowance	4,200,000	4,600,000
Deferred Tax Assets, Net	2,130,500,000	1,551,900,000
Deferred Tax Assets, Tax Deferred Expense, Reserves and Accruals, Allowance for Doubtful Accounts	64,200,000	45,400,000
Deferred Tax Assets, Operating Loss Carryforwards	214,600,000	178,600,000
Purchase Accounting Deferred Tax Asset	146,400,000	0
Operating Loss Carryforwards and Tax Credit Carryforwards [Abstract]
Operating Loss Carryforwards	606,900,000	510,200,000
Operating Loss Carryforwards, Valuation Allowance	300,000
Tax Credit Carryforward, Amount	3,800,000	6,600,000
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Unrecognized Tax Benefits, Beginning Balance	73,500,000	101,200,000	124,300,000
Unrecognized Tax Benefits, Increases Resulting from Prior Period Tax Positions	100,000		800,000
Unrecognized Tax Benefits, Decreases Resulting from Prior Period Tax Positions	(800,000)	(35,700,000)
Unrecognized Tax Benefits, Increases Resulting from Current Period Tax Positions	10,300,000	8,000,000	10,800,000
Unrecognized Tax Benefits, Decreases Resulting from Settlements with Taxing Authorities			(34,300,000)
Unrecognized Tax Benefits, Reductions Resulting from Lapse of Applicable Statute of Limitations			(400,000)
Unrecognized Tax Benefits, Ending Balance	83,100,000	73,500,000	101,200,000
Unrecognized Tax Benefits, Income Tax Penalties and Interest Expense and Accrued Interest [Abstract]
Unrecognized Tax Benefits, Interest on Income Taxes Expense	3,100,000	(2,800,000)	(24,800,000)
Unrecognized Tax Benefits, Interest on Income Taxes Accrued	10,100,000	7,100,000
Tax Positions [Abstract]
State Tax Settlements In 2011	29,100,000
State Tax Settlements Tax Expense Reductions in 2011	22,400,000
State Tax Settlements In 2010	35,000,000
State Tax Settlements Tax Expense Reductions In 2010	6,000,000
Nstar Electric 2011 Federal Tax Refund	166,800,000
Tax Years [Abstract]
Significant Change in Unrecognized Tax Benefits is Reasonably Possible, Estimated Range of Change, Upper Bound	50,000,000
Significant Change in Unrecognized Tax Benefits is Reasonably Possible, Other Information	These estimated changes could have an impact on NU's and CL&P's 2013 earnings of zero to $6 million and zero to $16 million, respectively.  Other companies’ impacts are not expected to be material.
State and Local Jurisdiction [Member]
Operating Loss Carryforwards and Tax Credit Carryforwards [Abstract]
Operating Loss Carryforwards	74,900,000
Tax Credit Carryforward, Amount	110,200,000	101,400,000
The Connecticut Light And Power Company [Member]
Current Income Tax Expense (Benefit), Continuing Operations [Abstract]
Current Federal Tax Expense (Benefit)	(47,800,000)	13,900,000	20,700,000
Current State and Local Tax Expense (Benefit)	3,100,000	(34,400,000)	(1,100,000)
Total Current Income Tax Expense (Benefit)	(44,700,000)	(20,500,000)	19,600,000
Deferred Income Tax Expense (Benefit), Continuing Operations [Abstract]
Deferred Federal Income Tax Expense (Benefit)	141,500,000	106,400,000	108,100,000
Deferred State and Local Income Tax Expense (Benefit)	(500,000)	6,200,000	7,000,000
Total Deferred Income Taxes	140,993,000	112,620,000	115,069,000
Investment Tax Credit	(1,900,000)	(2,100,000)	(2,300,000)
Income Tax Expense	94,437,000	90,033,000	132,438,000
Income Tax Expense (Benefit), Continuing Operations, Income Tax Reconciliation [Abstract]
Income Before Income Tax Expense	304,162,000	340,197,000	376,581,000
Income Tax Reconciliation, Income Tax Expense (Benefit), at Federal Statutory Income Tax Rate	106,500,000	119,100,000	131,800,000
Tax Effect Of Differences [Abstract]
Income Tax Reconciliation, Nondeductible Expense, Depreciation	(9,000,000)	(8,100,000)	(6,100,000)
Investment Tax Credit	(1,900,000)	(2,100,000)	(2,300,000)
Income Tax Reconciliation, Tax Credits, Other	0	(100,000)	(100,000)
Income Tax Reconciliation, State and Local Income Taxes	100,000	4,000,000	8,500,000
Medicare Subsidy	0	0	7,800,000
Tax Asset Valuation Allowance / Reserve Adjustments	1,600,000	(22,300,000)	(4,700,000)
Income Tax Reconciliation, Other Adjustments	(2,900,000)	(500,000)	(2,500,000)
Income Tax Expense	94,437,000	90,033,000	132,438,000
Effective Income Tax Rate, Continuing Operations	31.00%	26.50%	35.20%
Deferred Tax Liabilities [Abstract]
Deferred Tax Liabilities Resulting From Property Tax Accruals And Other	44,400,000	41,900,000
Deferred Tax Liabilities, Property, Plant and Equipment	1,194,700,000	1,046,900,000
Deferred Tax Liabilities, Regulatory Amounts [Abstract]
Deferred Tax Liabilities Regulatory Assets Securitized Contract Termination Costs	0	0
Deferred Tax Liabilities Regulatory Assets Other Regulatory Deferrals	677,700,000	734,200,000
Deferred Tax Liabilities Regulatory Assets Tax Effect Tax Regulatory Assets	151,800,000	141,800,000
Deferred Tax Liabilities Regulatory Assets Derivative Assets	36,200,000	39,100,000
Goodwill Deferred Tax Liability	0	0
Deferred Tax Liabilities, Other	10,100,000	8,200,000
Deferred Tax Liabilities, Total	2,114,900,000	2,012,100,000
Deferred Tax Assets, Net [Abstract]
Deferred Tax Assets, Derivative Instruments	375,900,000	412,200,000
Deferred Tax Assets, Regulatory Assets and Liabilities	35,500,000	78,400,000
Deferred Tax Assets Employee Benefits	141,200,000	121,400,000
Deferred Tax Assets Tax Effect Tax Regulatory Assets	5,200,000	6,400,000
Deferred Tax Assets, Other	82,800,000	76,000,000
Deferred Tax Assets, Gross	753,000,000	812,300,000
Deferred Tax Assets, Tax Deferred Expense, Reserves and Accruals, Allowance for Doubtful Accounts	30,400,000	32,400,000
Deferred Tax Assets, Operating Loss Carryforwards	82,000,000	85,500,000
Operating Loss Carryforwards and Tax Credit Carryforwards [Abstract]
Operating Loss Carryforwards	234,300,000	244,200,000
Tax Credit Carryforward, Amount	0	0
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Unrecognized Tax Benefits, Beginning Balance	46,500,000	80,800,000	89,000,000
Unrecognized Tax Benefits, Increases Resulting from Prior Period Tax Positions	0		0
Unrecognized Tax Benefits, Decreases Resulting from Prior Period Tax Positions	0	(35,700,000)
Unrecognized Tax Benefits, Increases Resulting from Current Period Tax Positions	2,500,000	1,400,000	5,300,000
Unrecognized Tax Benefits, Decreases Resulting from Settlements with Taxing Authorities			(13,500,000)
Unrecognized Tax Benefits, Reductions Resulting from Lapse of Applicable Statute of Limitations			0
Unrecognized Tax Benefits, Ending Balance	49,000,000	46,500,000	80,800,000
Unrecognized Tax Benefits, Income Tax Penalties and Interest Expense and Accrued Interest [Abstract]
Unrecognized Tax Benefits, Interest on Income Taxes Expense	1,300,000	(3,700,000)	(7,400,000)
Unrecognized Tax Benefits, Interest on Income Taxes Accrued	4,000,000	2,700,000
Tax Positions [Abstract]
State Tax Settlements Tax Expense Reductions In 2010	4,000,000
Tax Years [Abstract]
Significant Change in Unrecognized Tax Benefits is Reasonably Possible, Estimated Range of Change, Upper Bound	39,000,000
The Connecticut Light And Power Company [Member] | State and Local Jurisdiction [Member]
Operating Loss Carryforwards and Tax Credit Carryforwards [Abstract]
Operating Loss Carryforwards	0
Tax Credit Carryforward, Amount	75,200,000	68,600,000
Public Service Company Of New Hampshire [Member]
Current Income Tax Expense (Benefit), Continuing Operations [Abstract]
Current Federal Tax Expense (Benefit)	(900,000)	(25,800,000)	6,100,000
Current State and Local Tax Expense (Benefit)	3,400,000	100,000	5,600,000
Total Current Income Tax Expense (Benefit)	2,500,000	(25,700,000)	11,700,000
Deferred Income Tax Expense (Benefit), Continuing Operations [Abstract]
Deferred Federal Income Tax Expense (Benefit)	46,500,000	67,700,000	37,600,000
Deferred State and Local Income Tax Expense (Benefit)	12,000,000	7,900,000	1,600,000
Total Deferred Income Taxes	58,552,000	75,628,000	39,225,000
Investment Tax Credit	0	0	(100,000)
Income Tax Expense	60,993,000	49,945,000	50,801,000
Income Tax Expense (Benefit), Continuing Operations, Income Tax Reconciliation [Abstract]
Income Before Income Tax Expense	157,875,000	150,212,000	140,868,000
Income Tax Reconciliation, Income Tax Expense (Benefit), at Federal Statutory Income Tax Rate	55,300,000	52,600,000	49,300,000
Tax Effect Of Differences [Abstract]
Income Tax Reconciliation, Nondeductible Expense, Depreciation	(300,000)	(4,400,000)	(3,200,000)
Investment Tax Credit	0	0	(100,000)
Income Tax Reconciliation, Tax Credits, Other	(3,800,000)	(3,400,000)	(3,600,000)
Income Tax Reconciliation, State and Local Income Taxes	10,000,000	5,200,000	4,700,000
Medicare Subsidy	0	0	3,800,000
Tax Asset Valuation Allowance / Reserve Adjustments	0	0	0
Income Tax Reconciliation, Other Adjustments	(200,000)	(100,000)	(100,000)
Income Tax Expense	60,993,000	49,945,000	50,801,000
Effective Income Tax Rate, Continuing Operations	38.60%	33.20%	36.10%
Deferred Tax Liabilities [Abstract]
Deferred Tax Liabilities Resulting From Property Tax Accruals And Other	6,800,000	4,500,000
Deferred Tax Liabilities, Property, Plant and Equipment	476,500,000	423,800,000
Deferred Tax Liabilities, Regulatory Amounts [Abstract]
Deferred Tax Liabilities Regulatory Assets Securitized Contract Termination Costs	7,900,000	29,700,000
Deferred Tax Liabilities Regulatory Assets Other Regulatory Deferrals	149,300,000	122,500,000
Deferred Tax Liabilities Regulatory Assets Tax Effect Tax Regulatory Assets	15,800,000	16,100,000
Deferred Tax Liabilities Regulatory Assets Derivative Assets	0	0
Goodwill Deferred Tax Liability	0	0
Deferred Tax Liabilities, Other	14,100,000	14,000,000
Deferred Tax Liabilities, Total	670,400,000	610,600,000
Deferred Tax Assets, Net [Abstract]
Deferred Tax Assets, Derivative Instruments	0	0
Deferred Tax Assets, Regulatory Assets and Liabilities	43,900,000	39,300,000
Deferred Tax Assets Employee Benefits	64,800,000	87,900,000
Deferred Tax Assets Tax Effect Tax Regulatory Assets	1,700,000	1,600,000
Deferred Tax Assets, Other	33,700,000	26,000,000
Deferred Tax Assets, Gross	218,400,000	218,600,000
Deferred Tax Assets, Tax Deferred Expense, Reserves and Accruals, Allowance for Doubtful Accounts	2,900,000	3,000,000
Deferred Tax Assets, Operating Loss Carryforwards	71,400,000	60,800,000
Operating Loss Carryforwards and Tax Credit Carryforwards [Abstract]
Operating Loss Carryforwards	204,000,000	173,800,000
Tax Credit Carryforward, Amount	3,800,000	3,400,000
Unrecognized Tax Benefits, Income Tax Penalties and Interest Expense and Accrued Interest [Abstract]
Unrecognized Tax Benefits, Interest on Income Taxes Expense	0	(600,000)	100,000
Unrecognized Tax Benefits, Interest on Income Taxes Accrued	0	0
Public Service Company Of New Hampshire [Member] | State and Local Jurisdiction [Member]
Operating Loss Carryforwards and Tax Credit Carryforwards [Abstract]
Operating Loss Carryforwards	0
Tax Credit Carryforward, Amount	0	0
Western Massachusetts Electric Company [Member]
Current Income Tax Expense (Benefit), Continuing Operations [Abstract]
Current Federal Tax Expense (Benefit)	(24,700,000)	100,000	3,100,000
Current State and Local Tax Expense (Benefit)	3,400,000	300,000	2,500,000
Total Current Income Tax Expense (Benefit)	(21,300,000)	400,000	5,600,000
Deferred Income Tax Expense (Benefit), Continuing Operations [Abstract]
Deferred Federal Income Tax Expense (Benefit)	51,200,000	22,100,000	11,000,000
Deferred State and Local Income Tax Expense (Benefit)	2,700,000	1,000,000	0
Total Deferred Income Taxes	53,942,000	23,056,000	10,963,000
Investment Tax Credit	(500,000)	(300,000)	(300,000)
Income Tax Expense	32,140,000	23,186,000	16,325,000
Income Tax Expense (Benefit), Continuing Operations, Income Tax Reconciliation [Abstract]
Income Before Income Tax Expense	86,643,000	66,240,000	39,415,000
Income Tax Reconciliation, Income Tax Expense (Benefit), at Federal Statutory Income Tax Rate	30,300,000	23,200,000	13,800,000
Tax Effect Of Differences [Abstract]
Income Tax Reconciliation, Nondeductible Expense, Depreciation	200,000	100,000	200,000
Investment Tax Credit	(500,000)	(300,000)	(300,000)
Income Tax Reconciliation, Tax Credits, Other	0	0	0
Income Tax Reconciliation, State and Local Income Taxes	4,000,000	900,000	1,600,000
Medicare Subsidy	0	0	1,500,000
Tax Asset Valuation Allowance / Reserve Adjustments	0	0	0
Income Tax Reconciliation, Other Adjustments	(1,900,000)	(700,000)	(500,000)
Income Tax Expense	32,140,000	23,186,000	16,325,000
Effective Income Tax Rate, Continuing Operations	37.10%	35.00%	41.40%
Deferred Tax Liabilities [Abstract]
Deferred Tax Liabilities Resulting From Property Tax Accruals And Other	5,100,000	3,400,000
Deferred Tax Liabilities, Property, Plant and Equipment	261,300,000	194,900,000
Deferred Tax Liabilities, Regulatory Amounts [Abstract]
Deferred Tax Liabilities Regulatory Assets Securitized Contract Termination Costs	3,300,000	10,000,000
Deferred Tax Liabilities Regulatory Assets Other Regulatory Deferrals	74,500,000	79,300,000
Deferred Tax Liabilities Regulatory Assets Tax Effect Tax Regulatory Assets	13,900,000	13,700,000
Deferred Tax Liabilities Regulatory Assets Derivative Assets	0	0
Goodwill Deferred Tax Liability	0	0
Deferred Tax Liabilities, Other	2,300,000	1,100,000
Deferred Tax Liabilities, Total	360,400,000	302,400,000
Deferred Tax Assets, Net [Abstract]
Deferred Tax Assets, Derivative Instruments	(1,700,000)	2,900,000
Deferred Tax Assets, Regulatory Assets and Liabilities	6,300,000	15,000,000
Deferred Tax Assets Employee Benefits	16,300,000	13,300,000
Deferred Tax Assets Tax Effect Tax Regulatory Assets	1,700,000	6,500,000
Deferred Tax Assets, Other	8,000,000	17,600,000
Deferred Tax Assets, Gross	48,900,000	59,200,000
Deferred Tax Assets, Tax Deferred Expense, Reserves and Accruals, Allowance for Doubtful Accounts	3,200,000	3,900,000
Deferred Tax Assets, Operating Loss Carryforwards	15,100,000	0
Operating Loss Carryforwards and Tax Credit Carryforwards [Abstract]
Operating Loss Carryforwards	43,300,000	0
Tax Credit Carryforward, Amount	0	3,200,000
Western Massachusetts Electric Company [Member] | State and Local Jurisdiction [Member]
Operating Loss Carryforwards and Tax Credit Carryforwards [Abstract]
Operating Loss Carryforwards	0
Tax Credit Carryforward, Amount	0	0
NSTAR Electric Company [Member]
Current Income Tax Expense (Benefit), Continuing Operations [Abstract]
Current Federal Tax Expense (Benefit)	93,500,000	64,900,000	94,800,000
Current State and Local Tax Expense (Benefit)	27,600,000	30,200,000	27,000,000
Total Current Income Tax Expense (Benefit)	121,100,000	95,100,000	121,800,000
Deferred Income Tax Expense (Benefit), Continuing Operations [Abstract]
Deferred Federal Income Tax Expense (Benefit)	11,400,000	74,800,000	41,700,000
Deferred State and Local Income Tax Expense (Benefit)	(7,100,000)	(2,800,000)	(100,000)
Total Deferred Income Taxes	4,264,000	72,006,000	41,612,000
Investment Tax Credit	(1,400,000)	(1,400,000)	(1,400,000)
Income Tax Expense	123,966,000	165,686,000	162,020,000
Income Tax Expense (Benefit), Continuing Operations, Income Tax Reconciliation [Abstract]
Income Before Income Tax Expense	314,208,000	418,180,000	410,595,000
Income Tax Reconciliation, Income Tax Expense (Benefit), at Federal Statutory Income Tax Rate	110,000,000	146,400,000	143,700,000
Tax Effect Of Differences [Abstract]
Income Tax Reconciliation, Nondeductible Expense, Depreciation	0	0	0
Investment Tax Credit	(1,400,000)	(1,400,000)	(1,400,000)
Income Tax Reconciliation, Tax Credits, Other	0	0	0
Income Tax Reconciliation, State and Local Income Taxes	13,400,000	17,900,000	17,400,000
Medicare Subsidy	0	0	0
Tax Asset Valuation Allowance / Reserve Adjustments	0	0	0
Income Tax Reconciliation, Other Adjustments	2,000,000	2,800,000	2,300,000
Income Tax Expense	123,966,000	165,686,000	162,020,000
Effective Income Tax Rate, Continuing Operations	39.50%	39.60%	39.50%
Deferred Tax Liabilities [Abstract]
Deferred Tax Liabilities Resulting From Property Tax Accruals And Other	23,100,000	21,800,000
Deferred Tax Liabilities, Property, Plant and Equipment	1,079,300,000	987,800,000
Deferred Tax Liabilities, Regulatory Amounts [Abstract]
Deferred Tax Liabilities Regulatory Assets Securitized Contract Termination Costs	5,500,000	41,300,000
Deferred Tax Liabilities Regulatory Assets Other Regulatory Deferrals	379,600,000	400,600,000
Deferred Tax Liabilities Regulatory Assets Tax Effect Tax Regulatory Assets	20,900,000	21,900,000
Deferred Tax Liabilities Regulatory Assets Derivative Assets	0	0
Goodwill Deferred Tax Liability	181,000,000	187,800,000
Deferred Tax Liabilities, Other	30,200,000	34,800,000
Deferred Tax Liabilities, Total	1,719,600,000	1,696,000,000
Deferred Tax Assets, Net [Abstract]
Deferred Tax Assets, Derivative Instruments	5,800,000	1,300,000
Deferred Tax Assets, Regulatory Assets and Liabilities	123,600,000	114,900,000
Deferred Tax Assets Employee Benefits	116,300,000	115,300,000
Deferred Tax Assets Tax Effect Tax Regulatory Assets	6,000,000	6,900,000
Deferred Tax Assets, Other	26,000,000	36,100,000
Deferred Tax Assets, Gross	293,900,000	284,000,000
Deferred Tax Assets, Tax Deferred Expense, Reserves and Accruals, Allowance for Doubtful Accounts	16,200,000	9,500,000
Deferred Tax Assets, Operating Loss Carryforwards	0	0
Operating Loss Carryforwards and Tax Credit Carryforwards [Abstract]
Operating Loss Carryforwards	0	0
Tax Credit Carryforward, Amount	0	0
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Unrecognized Tax Benefits, Beginning Balance	0	0	13,800,000
Unrecognized Tax Benefits, Increases Resulting from Prior Period Tax Positions	0		0
Unrecognized Tax Benefits, Decreases Resulting from Prior Period Tax Positions	0	0
Unrecognized Tax Benefits, Increases Resulting from Current Period Tax Positions	0	0	0
Unrecognized Tax Benefits, Decreases Resulting from Settlements with Taxing Authorities			(13,800,000)
Unrecognized Tax Benefits, Reductions Resulting from Lapse of Applicable Statute of Limitations			0
Unrecognized Tax Benefits, Ending Balance	0	0	0
Unrecognized Tax Benefits, Income Tax Penalties and Interest Expense and Accrued Interest [Abstract]
Unrecognized Tax Benefits, Interest on Income Taxes Expense	0	2,000,000	(7,400,000)
Unrecognized Tax Benefits, Interest on Income Taxes Accrued	0	700,000
NSTAR Electric Company [Member] | State and Local Jurisdiction [Member]
Operating Loss Carryforwards and Tax Credit Carryforwards [Abstract]
Operating Loss Carryforwards	0
Tax Credit Carryforward, Amount	$ 0	$ 0

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QUARTERLY FINANCIAL DATA (Unaudited)

12 Months Ended

Dec. 31, 2012

Quarterly Financial Data [Abstract]

Quarterly Financial Information [Text Block]

QUARTERLY FINANCIAL DATA (UNAUDITED)

NU Consolidated Statements of Quarterly Financial Data	Quarter Ended (a)
(Millions of Dollars, except per share information)	March 31,		June 30,		September 30,		December 31,
2012 (1)
Operating Revenues	$	1,099.6	$	1,628.7	$	1,861.5	$	1,684.0
Operating Income		214.4		159.5		412.9		331.4
Net Income		100.8		46.2		209.5		176.6	(2)
Net Income Attributable to Controlling Interest		99.3		44.3		207.6		174.7
Basic and Diluted EPS	$	0.56	$	0.15	$	0.66	$	0.55
2011 (1)
Operating Revenues	$	1,235.3	$	1,047.5	$	1,114.9	$	1,068.0
Operating Income		227.4		178.1		203.8		184.9
Net Income		115.6		78.7		91.4		114.8
Net Income Attributable to Controlling Interest		114.2		77.3		90.0		113.2
Basic and Diluted EPS	$	0.64	$	0.44	$	0.51	$	0.64
(a) The summation of quarterly EPS data may not equal annual data due to rounding.
CL&P Consolidated Statements of Quarterly Financial Data	Quarter Ended
(Millions of Dollars)	March 31,		June 30,		September 30,		December 31,
2012
Operating Revenues	$	592.0	$	562.1	$	658.1	$	595.2
Operating Income		111.9		40.4		139.7		135.0
Net Income		54.0		6.9		74.9		73.9
2011
Operating Revenues	$	673.7	$	608.0	$	673.7	$	593.0
Operating Income		126.0		114.8		137.7		84.7
Net Income		64.3		52.6		66.5		66.8
NSTAR Electric Consolidated Statements of
Quarterly Financial Data	Quarter Ended
(Millions of Dollars)	March 31,		June 30,		September 30,		December 31,
2012 (1)
Operating Revenues	$	556.5	$	534.6	$	693.7	$	516.2
Operating Income		22.5		93.9		194.1		70.9
Net Income		3.9		45.5		106.8		34.0	(2)
2011 (1)
Operating Revenues	$	577.5	$	552.3	$	724.7	$	548.6
Operating Income		87.7		115.6		183.7		99.2
Net Income		42.9		60.7		99.8		49.1
PSNH Consolidated Statements of Quarterly Financial Data	Quarter Ended
(Millions of Dollars)	March 31,		June 30,		September 30,		December 31,
2012
Operating Revenues	$	243.0	$	255.1	$	256.9	$	233.0
Operating Income		45.4		47.0		61.3		51.4
Net Income		21.3		21.2		27.2		27.2
2011
Operating Revenues	$	269.5	$	240.2	$	259.6	$	243.7
Operating Income		46.9		37.9		48.5		46.8
Net Income		27.5		21.7		25.6		25.5
WMECO Consolidated Statements of Quarterly Financial Data	Quarter Ended
(Millions of Dollars)	March 31,		June 30,		September 30,		December 31,
2012
Operating Revenues	$	114.0	$	106.8	$	112.5	$	107.9
Operating Income		28.7		25.1		28.1		28.9
Net Income		14.2		11.1		14.1		15.1
2011
Operating Revenues	$	106.7	$	98.4	$	104.5	$	107.7
Operating Income		21.1		18.5		19.8		29.0
Net Income		10.0		8.2		8.4		16.5

(1)NSTAR Electric amounts are included in NU consolidated from the date of the merger, April 10, 2012, through December 31, 2012. NSTAR Electric amounts are not included in NU consolidated for the years ended December 31, 2011 and 2010.

(2)NSTAR Electric's Net Income for the quarter ended December 31, 2012 decreased by $8.2 million, as compared to the quarter ended December 31, 2011, related to a pre-tax charge to establish a reserve of $13.7 million to reflect a billing adjustment, all of which related to prior year amounts.

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Pension Benefits and Postretirement Benefits Other Than Pensions (Tables)

12 Months Ended

Dec. 31, 2012

Notes To Consolidated Financial Statements [Abstract]

Schedule Of Net Benefit Costs [Table Text Block]

		Pension and SERP
		For the Year Ended December 31, 2012
						NSTAR
(Millions of Dollars)		NU		CL&P		Electric (1)		PSNH		WMECO
Service Cost		$	84.3	$	21.8	$	30.3	$	11.8	$	4.1
Interest Cost			198.3		51.2		58.9		24.4		10.5
Expected Return on Plan Assets			(220.9)		(70.6)		(65.6)		(28.2)		(16.4)
Actuarial Loss			172.4		49.6		63.1		16.2		10.7
Prior Service Cost/(Credit)			7.9		3.6		(0.6)		1.5		0.8
Total Net Periodic Benefit Expense		$	242.0	$	55.6	$	86.1	$	25.7	$	9.7
Curtailments and Settlements		$	2.2	$	-	$	-	$	-	$	-
Related Intercompany Allocations			N/A	$	42.8	$	(12.3)	$	10.1	$	8.1
Capitalized Pension Expense		$	70.6	$	26.8	$	30.7	$	7.9	$	5.1
		Pension and SERP
		For the Year Ended December 31, 2011
						NSTAR
(Millions of Dollars)		NU		CL&P		Electric (1)		PSNH		WMECO
Service Cost		$	55.4	$	19.5	$	26.0	$	10.6	$	3.9
Interest Cost			153.3		51.9		61.0		24.4		10.7
Expected Return on Plan Assets			(170.8)		(76.6)		(71.4)		(19.8)		(17.7)
Actuarial Loss			84.2		33.4		48.6		10.7		7.1
Prior Service Cost/(Credit)			9.7		4.2		(0.7)		1.8		0.9
Total Net Periodic Benefit Expense		$	131.8	$	32.4	$	63.5	$	27.7	$	4.9
Related Intercompany Allocations			N/A	$	34.1	$	(10.2)	$	7.6	$	6.2
Capitalized Pension Expense		$	29.7	$	16.6	$	19.8	$	7.6	$	2.7
		Pension and SERP
		For the Year Ended December 31, 2010
						NSTAR
(Millions of Dollars)		NU		CL&P		Electric (1)		PSNH		WMECO
Service Cost		$	51.0	$	17.6	$	23.6	$	10.0	$	3.5
Interest Cost			152.6		52.2		61.8		24.1		10.7
Expected Return on Plan Assets			(182.6)		(85.8)		(62.8)		(14.7)		(19.5)
Actuarial Loss			53.5		20.7		50.4		7.2		4.3
Prior Service Cost/(Credit)			9.9		4.2		(0.7)		1.8		0.9
Total Net Periodic Benefit Expense/(Income)		$	84.4	$	8.9	$	72.3	$	28.4	$	(0.1)
Related Intercompany Allocations			N/A	$	25.2	$	(11.6)	$	6.0	$	4.5
Capitalized Pension Expense		$	16.9	$	3.8	$	24.5	$	6.9	$	-
(1)	NSTAR Electric amounts are included in NU consolidated from the date of the merger, April 10, 2012, through December 31, 2012. NSTAR Electric amounts are not included in NU consolidated for the years ended December 31, 2011 and 2010. NSTAR Electric's allocated expense associated with the NSTAR SERP was $3.6 million, $4.4 million and $3.9 million for the years ended December 31, 2012, 2011 and 2010, respectively, and are not included in the NSTAR Electric amounts in the tables above.
The following actuarial assumptions were used to calculate Pension and SERP expense amounts:

			PBOP
		For the Years Ended December 31,
		2012								2011								2010
(Millions of Dollars)		NU (1)		CL&P		PSNH		WMECO		NU		CL&P		PSNH		WMECO		NU		CL&P		PSNH		WMECO
Service Cost		$	15.7	$	3.0	$	2.0	$	0.6	$	9.2	$	2.9	$	1.9	$	0.6	$	8.5	$	2.7	$	1.8	$	0.6
Interest Cost			49.0		9.2		4.6		2.0		25.7		10.0		4.8		2.2		26.8		10.5		5.0		2.3
Expected Return
	on Plan Assets		(39.2)		(9.1)		(4.6)		(2.1)		(21.6)		(8.7)		(4.3)		(2.0)		(21.7)		(8.7)		(4.3)		(2.1)
Actuarial Loss			36.0		7.5		3.6		1.2		19.0		7.2		3.2		1.1		16.7		6.3		2.7		0.9
Prior Service
	Cost/(Credit)		(1.4)		-		-		-		(0.3)		-		-		1.3		(0.3)		-		-		-
Net Transition
	Obligation Cost(2)		12.2		6.1		2.5		1.3		11.6		6.2		2.5		-		11.6		6.1		2.5		1.3
Total Net Periodic Benefit Expense		$	72.3	$	16.7	$	8.1	$	3.0	$	43.6	$	17.6	$	8.1	$	3.2	$	41.6	$	16.9	$	7.7	$	3.0
Related Intercompany Allocations			N/A	$	7.9	$	2.0	$	1.5		N/A	$	8.2	$	2.0	$	1.5		N/A	$	7.9	$	2.0	$	1.4
(1)	The NU consolidated results include NSTAR PBOP Plan expense from the date of the merger, April 10, 2012, through December 31, 2012.
(2)	The NUSCO PBOP Plans and NSTAR PBOP Plan transition obligation costs will be fully amortized in 2013.

Schedule of Defined Benefit Plans Disclosures [Table Text Block]

The accumulated benefit obligation for the Pension and SERP Plans is as follows:
		Pension and SERP
		As of December 31,
(Millions of Dollars)		2012		2011
NU		$	4,622.1	$	2,810.6
CL&P			1,061.8		938.4
NSTAR Electric (1)			1,353.1		1,271.3
PSNH			515.9		444.8
WMECO			221.3		195.5
(1)	NSTAR Electric amounts are not included in NU consolidated as of December 31, 2011 and do not include the accumulated benefit obligation for the SERP Plan.
The following actuarial assumptions were used in calculating the Pension and SERP Plans' year end funded status:

Schedule of Amounts Recognized in Other Comprehensive Income (Loss) [Table Text Block]

The following is a summary of the changes in plan assets and benefit obligations recognized in Regulatory Assets and OCI as well as amounts in Regulatory Assets and OCI reclassified as net periodic benefit expense during the years presented:
	Amounts Reclassified To/From
	Regulatory Assets				OCI
(Millions of Dollars)	For the Years Ended December 31,
NU Pension and SERP Plans (1)	2012		2011		2012		2011
Actuarial Losses Arising During the Year	$	245.7	$	334.8	$	19.1	$	23.0
Actuarial Losses Reclassified as Net Periodic Benefit Expense		(164.6)		(79.4)		(7.8)		(4.8)
Prior Service Cost Reclassified as Net Periodic Benefit Expense		(7.7)		(9.4)		(0.2)		(0.3)
The following is a summary of the remaining Regulatory Assets and Accumulated Other Comprehensive Loss amounts that have not been recognized as components of net periodic benefit expense as of December 31, 2012 and 2011, and the amounts that are expected to be recognized as components in 2013:
		Regulatory Assets as of				Expected		AOCI as of			Expected
(Millions of Dollars)	December 31,					2013	December 31,				2013
NU Pension and SERP Plans (1)	2012		2011		Expense		2012		2011		Expense
Actuarial Loss	$	1,973.8	$	1,126.1	$	200.8	$	81.5	$	70.2	$	9.3
Prior Service Cost		21.2		29.3		3.9		1.2		1.4		0.2

Schedule of Amounts Recognized in Balance Sheet [Table Text Block]

The following is a summary of the changes in plan assets and benefit obligations recognized in Regulatory Assets and OCI as well as amounts in Regulatory Assets and OCI reclassified as net periodic benefit (expense)/income during the years presented:
		Amounts Reclassified To/From
	Regulatory Assets				OCI
(Millions of Dollars)	For the Years Ended December 31,
NU PBOP Plans (1)	2012		2011		2012		2011
Actuarial (Gains)/Losses Arising During the Year	$	(108.6)	$	50.2	$	(1.8)	$	4.0
Actuarial Losses Reclassified as Net Periodic Benefit Expense		(34.9)		(18.1)		(1.1)		(0.9)
Prior Service Credit Reclassified as Net Periodic Benefit Income		1.4		0.3		-		-
Transition Obligation Reclassified as Net Periodic Benefit Expense		(11.9)		(11.3)		(0.2)		(0.2)
The following is a summary of the remaining Regulatory Assets and Accumulated Other Comprehensive Loss amounts that have not been recognized as components of net periodic benefit expense as of December 31, 2012 and 2011, and the amounts that are expected to be recognized as components in 2013:
		Regulatory Assets as of			Expected			AOCI as of			Expected
(Millions of Dollars)	December 31,				2013			December 31,			2013
NU PBOP Plans (1)	2012		2011		Expense		2012		2011		Expense
Actuarial Loss	$	376.1	$	196.3	$	31.4	$	9.2	$	12.1	$	1.0
Prior Service Credit		(6.7)		(2.4)		(2.1)		-		-		-
Transition Obligation		-		11.4		-		-		0.2		-

Schedule of Assumptions Used [Table Text Block]

	Pension and SERP
	As of December 31,
	2012		2011
NUSCO Pension and SERP Plans
Discount Rate	4.24	%	5.03	%
Compensation/Progression Rate	3.50	%	3.50	%
NSTAR Pension and SERP Plans
Discount Rate	4.13	%	4.52	%
Compensation/Progression Rate	4.00	%	4.00	%

	Pension and SERP
	For the Years Ended December 31,
NUSCO Pension and SERP Plans	2012		2011		2010
Discount Rate	5.03	%	5.57	%	5.98	%
Expected Long-Term Rate of Return	8.25	%	8.25	%	8.75	%
Compensation/Progression Rate	3.50	%	3.50	%	4.00	%
NSTAR Pension and SERP Plans
Discount Rate	4.52	%	5.30	%	5.85	%
Expected Long-Term Rate of Return	7.30	%	8.00	%	8.00	%
Compensation/Progression Rate	4.00	%	4.00	%	4.00	%

The following actuarial assumptions were used in calculating the PBOP Plans' year end funded status:
	PBOP
	As of December 31,
	2012		2011
NUSCO PBOP Plans
Discount Rate	4.04	%	4.84	%
Health Care Cost Trend Rate	7.00	%	7.00	%
NSTAR PBOP Plan
Discount Rate	4.35	%	N/A
Health Care Cost Trend Rate	7.10	%	N/A

The following actuarial assumptions were used to calculate PBOP expense amounts:
	PBOP
	For the Years Ended December 31,
	2012		2011		2010
NUSCO PBOP Plans
Discount Rate	4.84	%	5.28	%	5.73	%
Expected Long-Term Rate of Return	8.25	%	8.25	%	8.75	%
NSTAR PBOP Plan
Discount Rate	4.58	%	N/A		N/A
Expected Long-Term Rate of Return	7.30	%	N/A		N/A

• The NU consolidated amounts include the NSTAR PBOP Plan from the date of the merger, April 10, 2012, through December31, 2012.

For the NUSCO PBOPPlans, the health care cost trend assumption is 7 percent, subsequently decreasing 50 basis points per year to an ultimate rate of 5 percent in 2017. For the NSTAR PBOPPlan, the health care cost trend assumption is 7.10 percent, subsequently decreasing to an ultimate rate of 4.50 percent in 2024.

Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. The effect of changing the assumed health care cost trend rate by one percentage point for the year ended December 31, 2012 would have the following effects:

Schedule of Effect of One-Percentage-Point Change in Assumed Health Care Cost Trend Rates [Table Text Block]

(Millions of Dollars)	One Percentage		One Percentage
NU PBOP Plans	Point Increase		Point Decrease
Effect on Postretirement Benefit Obligation	$	126.5	$	(101.7)
Effect on Total Service and Interest Cost Components		8.9		(6.9)

Schedule of Expected Benefit Payments [Table Text Block]

Estimated Future Benefit Payments: The following benefit payments, which reflect expected future service, are expected to be paid by the Pension, SERP and PBOP Plans:
(Millions of Dollars)	Pension
NU Consolidated	and SERP		PBOP
2013	$	238.0	$	63.5
2014		257.3		65.0
2015		252.4		66.8
2016		261.2		68.2
2017		270.6		69.6
2018-2022		1,510.2		366.3
NSTAR Pension Plan
2013	$	77.7		N/A
2014		79.6		N/A
2015		82.6		N/A
2016		83.2		N/A
2017		85.1		N/A
2018-2022		462.2		N/A

Schedule of Benefit Obligations in Excess of Fair Value of Plan Assets [Table Text Block]

	Pension and SERP
NU	As of December 31,
(Millions of Dollars)	2012		2011
Change in Benefit Obligation
Benefit Obligation as of Beginning of Year	$	(3,098.9)	$	(2,820.9)
Liabilities Assumed from Merger with NSTAR		(1,409.7)		-
Service Cost		(84.3)		(55.4)
Interest Cost		(198.3)		(153.3)
Actuarial Loss		(429.7)		(206.1)
Benefits Paid - Excluding Lump Sum Payments		187.7		134.4
Benefits Paid - SERP		4.2		2.4
SERP curtailment		6.2		-
Benefit Obligation as of End of Year	$	(5,022.8)	$	(3,098.9)
Change in Pension Plan Assets
Fair Value of Plan Assets as of Beginning of Year	$	2,005.9	$	1,977.6
Assets Assumed from Merger with NSTAR		984.7		-
Employer Contributions		222.4		143.6
Actual Return on Plan Assets		386.0		19.1
Benefits Paid - Excluding Lump Sum Payments		(187.7)		(134.4)
Fair Value of Plan Assets as of End of Year	$	3,411.3	$	2,005.9
Funded Status as of December 31st	$	(1,611.5)	$	(1,093.0)

	Pension and SERP
	As of December 31, 2012								As of December 31, 2011
			NSTAR								NSTAR
(Millions of Dollars)	CL&P		Electric (1)		PSNH		WMECO		CL&P		Electric (1),(2)		PSNH		WMECO
Change in Benefit Obligation
Benefit Obligation as of Beginning of Year	$	(1,043.8)	$	(1,346.2)	$	(497.9)	$	(215.8)	$	(964.3)	$	(1,184.6)	$	(448.7)	$	(196.6)
Service Cost		(21.8)		(30.3)		(11.8)		(4.1)		(19.5)		(26.0)		(10.6)		(3.9)
Interest Cost		(51.2)		(58.9)		(24.4)		(10.5)		(51.9)		(61.0)		(24.4)		(10.7)
Actuarial Loss		(117.4)		(63.6)		(61.3)		(24.0)		(64.0)		(138.0)		(33.2)		(15.4)
Benefits Paid - Excluding Lump Sum Payments		55.9		69.0		19.7		11.3		55.6		59.6		18.9		10.8
Benefits Paid - SERP		0.3		-		-		-		0.3		-		0.1		-
Curtailment and Settlement Payments		-		-		(0.3)		-		-		3.8		-		-
Benefit Obligation as of End of Year	$	(1,178.0)	$	(1,430.0)	$	(576.0)	$	(243.1)	$	(1,043.8)	$	(1,346.2)	$	(497.9)	$	(215.8)
Change in Pension Plan Assets
Fair Value of Plan Assets as of Beginning of Year	$	869.6	$	988.5	$	279.7	$	202.0	$	918.4	$	930.6	$	185.4	$	209.8
Employer Contributions		-		25.0		87.7		-		-		125.0		112.6		-
Actual Return/(Loss) on Plan Assets		123.9		124.6		38.9		27.8		6.8		(3.7)		0.6		3.0
Benefits Paid - Excluding Lump Sum Payments		(55.9)		(69.0)		(19.7)		(11.3)		(55.6)		(59.6)		(18.9)		(10.8)
Benefits Paid - Settlement Payments		-		-		-		-		-		(3.8)		-		-
Fair Value of Plan Assets as of End of Year	$	937.6	$	1,069.1	$	386.6	$	218.5	$	869.6	$	988.5	$	279.7	$	202.0
Funded Status as of December 31st	$	(240.4)	$	(360.9)	$	(189.4)	$	(24.6)	$	(174.2)	$	(357.7)	$	(218.2)	$	(13.8)
Pension and SERP benefits funded status includes the current portion of the SERP liability, which is included in Other Current Liabilities on the accompanying consolidated balance sheets.
Although the Company maintains a trust to support the SERP with marketable securities held in the NU supplemental benefit trust, the plan itself does not contain any assets. For information regarding the investments in the NU supplemental benefit trust that are used to informally support the SERP liability, see Note 6, "Marketable Securities," to the consolidated financial statements.
(1) NSTAR Electric amounts do not include benefit obligations of the NSTAR SERP Plan.
(2) NSTAR Electric amounts are not included in NU consolidated as of December 31, 2011.

		PBOP
		As of December 31,
				2012						2011
(Millions of Dollars)		NU (1)		CL&P		PSNH		WMECO		NU		CL&P		PSNH		WMECO
Change in Benefit Obligation
Benefit Obligation as of Beginning of Year		$	(520.9)	$	(198.9)	$	(99.2)	$	(42.9)	$	(489.9)	$	(190.2)	$	(89.9)	$	(41.7)
Liabilities Assumed from Merger with NSTAR			(770.6)		-		-		-		-		-		-		-
Service Cost			(15.7)		(3.0)		(2.0)		(0.6)		(9.2)		(2.9)		(1.9)		(0.6)
Interest Cost			(49.0)		(9.2)		(4.6)		(2.0)		(25.7)		(10.0)		(4.8)		(2.2)
Actuarial Gain/(Loss)			70.9		1.2		0.3		0.1		(30.1)		(8.5)		(8.4)		(1.0)
Federal Subsidy on Benefits Paid			(6.2)		(1.7)		(0.6)		(0.3)		(4.1)		(1.8)		(0.7)		(0.4)
Benefits Paid			58.2		14.8		5.9		3.2		38.1		14.5		6.5		3.0
Benefit Obligation as of End of Year		$	(1,233.3)	$	(196.8)	$	(100.2)	$	(42.5)	$	(520.9)	$	(198.9)	$	(99.2)	$	(42.9)
Change in Plan Assets
Fair Value of Plan Assets as of Beginning of Year		$	285.4	$	112.2	$	58.7	$	27.1	$	278.5	$	108.6	$	56.9	$	26.7
Assets Assumed from Merger with NSTAR			330.4		-		-		-		-		-		-		-
Actual Return on Plan Assets			78.8		15.0		7.5		3.5		(2.5)		(1.2)		(0.4)		(0.1)
Employer Contributions			72.7		19.8		9.2		3.6		47.5		19.3		8.7		3.5
Benefits Paid			(58.2)		(14.8)		(5.9)		(3.2)		(38.1)		(14.5)		(6.5)		(3.0)
Fair Value of Plan Assets as of End of Year		$	709.1	$	132.2	$	69.5	$	31.0	$	285.4	$	112.2	$	58.7	$	27.1
Funded Status as of December 31st		$	(524.2)	$	(64.6)	$	(30.7)	$	(11.5)	$	(235.5)	$	(86.7)	$	(40.5)	$	(15.8)
(1)	The NU consolidated results include NSTAR PBOP Plan activity from the date of the merger, April 10, 2012, through December 31, 2012.

Schedule of Effect of Significant Unobservable Inputs, Changes in Plan Assets [Table Text Block]

		NU Consolidated Pension Plans
		United								Real Estate
		States				Private		Fixed		and Other		Hedge
(Millions of Dollars)		Equity		International		Equity		Income		Assets		Funds		Total
Balance as of January 1, 2011		$	266.0	$	-	$	229.5	$	247.6	$	43.7	$	247.1	$	1,033.9
Actual Return/(Loss) on Plan Assets:
	Relating to Assets Still Held as of Year End		(6.6)		-		20.0		(1.5)		1.6		(7.1)		6.4
	Relating to Assets Distributed During the Year		-		-		19.5		(2.8)		0.3		-		17.0
Purchases, Sales and Settlements			-		-		(13.9)		32.9		26.2		-		45.2
Balance as of December 31, 2011		$	259.4	$	-	$	255.1	$	276.2	$	71.8	$	240.0	$	1,102.5
Assets Assumed from Merger with NSTAR			-		41.4		-		-		111.0		126.6		279.0
Actual Return/(Loss) on Plan Assets:
	Relating to Assets Still Held as of Year End		11.2		10.7		17.0		42.1		5.7		21.8		108.5
	Relating to Assets Distributed During the Year		-		-		15.0		0.7		7.6		(0.3)		23.0
Purchases, Sales and Settlements			-		-		(19.2)		(3.9)		39.3		30.8		47.0
Balance as of December 31, 2012		$	270.6	$	52.1	$	267.9	$	315.1	$	235.4	$	418.9	$	1,560.0
		NU Consolidated PBOP Plans
		United						Real Estate
		States		Private		Fixed		and Other			Hedge
(Millions of Dollars)		Equity		Equity		Income		Assets			Funds		Total
Balance as of January 1, 2011		$	10.1	$	0.3	$	23.4	$	-	$	16.4	$	50.2
Actual Return/(Loss) on Plan Assets:
	Relating to Assets Still Held as of Year End		0.6		0.6		0.2		(0.1)		(0.3)		1.0
Purchases, Sales and Settlements			-		4.2		2.4		2.6		-		9.2
Balance as of December 31, 2011		$	10.7	$	5.1	$	26.0	$	2.5	$	16.1	$	60.4
Assets Assumed from Merger with NSTAR			19.7		-		-		18.4		21.4		59.5
Actual Return on Plan Assets:
	Relating to Assets Still Held as of Year End		5.9		1.6		4.0		3.0		2.1		16.6
Purchases, Sales and Settlements			-		4.6		2.1		2.8		-		9.5
Balance as of December 31, 2012		$	36.3	$	11.3	$	32.1	$	26.7	$	39.6	$	146.0
		NSTAR Pension Plan
				Real Estate
				and Other
(Millions of Dollars)		International		Assets		Hedge Funds		Total
Balance as of January 1, 2011		$	45.1	$	86.8	$	157.9	$	289.8
Actual Return/(Loss) on Plan Assets:
	Relating to Assets Still Held as of Year End		(3.7)		8.7		(4.8)		0.2
	Relating to Assets Distributed During the Year		-		-		0.2		0.2
Purchases, Sales and Settlements			-		15.5		(26.7)		(11.2)
Balance as of December 31, 2011		$	41.4	$	111.0	$	126.6	$	279.0
Actual Return/(Loss) on Plan Assets:
	Relating to Assets Still Held as of Year End		10.7		9.9		5.6		26.2
	Relating to Assets Distributed During the Year		-		-		(0.3)		(0.3)
Purchases, Sales and Settlements			-		6.3		(9.2)		(2.9)
Balance as of December 31, 2012		$	52.1	$	127.2	$	122.7	$	302.0

Schedule of Allocation of Plan Assets [Table Text Block]

		As of December 31,
		2012 and 2011		2012		2011		2012
		NUSCO Pension and PBOP		NSTAR Pension Plan		NSTAR Pension Plan		NSTAR PBOP Plan
		Target	Assumed	Target	Assumed	Target	Assumed	Target	Assumed
		Asset	Rate	Asset	Rate	Asset	Rate	Asset	Rate
		Allocation	of Return	Allocation	of Return	Allocation	of Return	Allocation	of Return
Equity Securities:
	United States	24%	9%	25%	8.3%	22%	8.6%	25%	8.3%
	International	13%	9%	13%	8.6%	12%	8.9%	20%	8.6%
	Emerging Markets	3%	10%	5%	8.8%	5%	8.8%	5%	8.8%
	Private Equity	12%	13%	-	-	-	-	-	-
Debt Securities:
	Fixed Income	20%	5%	21%	4.6%	15%	4.4%	30%	4.6%
	High Yield Fixed Income	3.5%	7.5%	9%	6.5%	9%	6.2%	-	-
	Emerging Markets Debt	3.5%	7.5%	4%	6.4%	3%	6.8%	-	-
Real Estate and Other Assets		8%	7.5%	10%	7.9%	11%	7.7%	10%	7.9%
Hedge Funds		13%	7%	13%	8.4%	23%	8.6%	10%	8.4%

		NU Consolidated Pension Plans
		Fair Value Measurements as of December 31,
(Millions of Dollars)		2012								2011
Asset Category:		Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Equity Securities:
	United States (2)	$	336.5	$	302.8	$	270.6	$	909.9	$	218.7	$	14.8	$	259.4	$	492.9
	International (2)		42.0		362.6		52.1		456.7		20.0		221.9		-		241.9
	Emerging Markets(2)		-		135.3		-		135.3		-		66.6		-		66.6
	Private Equity		26.7		-		267.9		294.6		11.3		-		255.1		266.4
Fixed Income(3)			54.9		629.2		315.1		999.2		17.8		268.7		276.2		562.7
Real Estate and
	Other Assets		-		78.9		235.4		314.3		24.8		57.8		71.8		154.4
Hedge Funds			-		-		418.9		418.9		-		-		240.0		240.0
Total Master Trust Assets		$	460.1	$	1,508.8	$	1,560.0	$	3,528.9	$	292.6	$	629.8	$	1,102.5	$	2,024.9
	Less: 401(h) PBOP Assets(4)								(117.6)								(19.0)
Total Pension Assets								$	3,411.3							$	2,005.9
		NSTAR Pension Plan
		Fair Value Measurements as of December 31,
(Millions of Dollars)		2012								2011(1) (5)
Asset Category:		Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Equity Securities:
	United States (2)	$	96.7	$	246.4	$	-	$	343.1	$	77.0	$	212.3	$	-	$	289.3
	International(2)		-		98.3		52.1		150.4		4.0		82.8		41.4		128.2
	Emerging Markets(2)		-		55.9		-		55.9		-		46.9		-		46.9
Fixed Income(3)			54.9		292.5		-		347.4		124.7		230.3		-		355.0
Real Estate			-		-		127.2		127.2		-		-		111.0		111.0
Hedge Funds			-		-		122.7		122.7		-		-		126.6		126.6
Total Master Trust Assets		$	151.6	$	693.1	$	302.0	$	1,146.7	$	205.7	$	572.3	$	279.0	$	1,057.0
	Less: 401(h) PBOP Assets(4)								(77.6)								(68.5)
Total Pension Assets								$	1,069.1							$	988.5
		NU Consolidated PBOP Plans
		Fair Value Measurements as of December 31,
(Millions of Dollars)		2012								2011
Asset Category:		Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Cash and Cash
	Equivalents	$	9.7	$	-	$	-	$	9.7	$	5.9	$	-	$	-	$	5.9
Equity Securities:
	United States(2)		116.3		57.7		36.3		210.3		116.9		-		10.7		127.6
	International(2)		68.0		29.7		-		97.7		29.6		-		-		29.6
	Emerging Markets(2)		7.7		14.0		-		21.7		4.6		-		-		4.6
Fixed Income (3)			-		137.7		32.1		169.8		-		44.3		26.0		70.3
Hedge Funds			-		-		39.6		39.6		-		-		16.1		16.1
Private Equity			-		-		11.3		11.3		-		-		5.1		5.1
Real Estate and Other
	Assets		-		4.7		26.7		31.4		-		4.7		2.5		7.2
Total		$	201.7	$	243.8	$	146.0	$	591.5	$	157.0	$	49.0	$	60.4	$	266.4
	Add: 401(h) PBOP Assets(4)								117.6								19.0
Total PBOP Assets								$	709.1							$	285.4

##SR

XML

INCOME TAXES

12 Months Ended

Dec. 31, 2012

Notes To Consolidated Financial Statements [Abstract]

Income Tax Disclosure [Text Block]

11.       INCOME TAXES

The tax effect of temporary differences is accounted for in accordance with the rate-making treatment of the applicable regulatory commissions and relevant accounting authoritative literature. The components of income tax expense are as follows:

NU	For the Years Ended December 31,
(Millions of Dollars)	2012		2011		2010
Current Income Taxes:
Federal	$	(30.9)	$	3.0	$	9.0
State		17.6		(26.0)		(6.5)
Total Current		(13.3)		(23.0)		2.5
Deferred Income Taxes, Net:
Federal		291.3		187.7		201.2
State		0.8		9.1		9.7
Total Deferred		292.1		196.8		210.9
Investment Tax Credits, Net		(3.9)		(2.8)		(3.0)
Income Tax Expense	$	274.9	$	171.0	$	210.4

		For the Years Ended December 31,
		2012								2011								2010
				NSTAR								NSTAR								NSTAR
(Millions of Dollars)		CL&P		Electric (1)		PSNH		WMECO		CL&P		Electric(1)		PSNH		WMECO		CL&P		Electric(1)		PSNH		WMECO
Current Income Taxes:
	Federal	$	(47.8)	$	93.5	$	(0.9)	$	(24.7)	$	13.9	$	64.9	$	(25.8)	$	0.1	$	20.7	$	94.8	$	6.1	$	3.1
	State		3.1		27.6		3.4		3.4		(34.4)		30.2		0.1		0.3		(1.1)		27.0		5.6		2.5
Total Current			(44.7)		121.1		2.5		(21.3)		(20.5)		95.1		(25.7)		0.4		19.6		121.8		11.7		5.6
Deferred Income
	Taxes, Net:
	Federal		141.5		11.4		46.5		51.2		106.4		74.8		67.7		22.1		108.1		41.7		37.6		11.0
	State		(0.5)		(7.1)		12.0		2.7		6.2		(2.8)		7.9		1.0		7.0		(0.1)		1.6		-
Total Deferred			141.0		4.3		58.5		53.9		112.6		72.0		75.6		23.1		115.1		41.6		39.2		11.0
Investment Tax
	Credits, Net		(1.9)		(1.4)		0.0		(0.5)		(2.1)		(1.4)		-		(0.3)		(2.3)		(1.4)		(0.1)		(0.3)
Income Tax Expense		$	94.4	$	124.0	$	61.0	$	32.1	$	90.0	$	165.7	$	49.9	$	23.2	$	132.4	$	162.0	$	50.8	$	16.3
(1)	NSTAR Electric amounts are included in NU consolidated from the date of the merger, April 10, 2012, through December 31, 2012. NSTAR Electric amounts are not included in NU consolidated for the years ended December 31, 2011 and 2010.

A reconciliation between income tax expense and the expected tax expense at the statutory rate is as follows:
NU		For the Years Ended December 31,
(Millions of Dollars, except percentages)		2012		2011		2010
Income Before Income Tax Expense		$	808.0	$	571.5	$	604.5
Statutory Federal Income Tax Expense at 35%			282.8		200.0		211.6
Tax Effect of Differences:
	Depreciation		(10.8)		(14.2)		(9.5)
	Investment Tax Credit Amortization		(3.9)		(2.8)		(3.0)
	Other Federal Tax Credits		(3.8)		(3.5)		(3.8)
	State Income Taxes, Net of Federal Impact		4.4		22.1		12.5
	Medicare Subsidy		0.0		-		15.6
	Tax Asset Valuation Allowance/Reserve Adjustments		7.6		(33.1)		(10.5)
	Other, Net		(1.4)		2.5		(2.5)
Income Tax Expense		$	274.9	$	171.0	$	210.4
Effective Tax Rate			34.0%		29.9%		34.8%

		For the Years Ended December 31,
		2012								2011								2010
(Millions of Dollars,				NSTAR								NSTAR								NSTAR
	except percentages)	CL&P		Electric(1)		PSNH		WMECO		CL&P		Electric(1)		PSNH		WMECO		CL&P		Electric(1)		PSNH		WMECO
Income Before Income
	Tax Expense	$	304.2	$	314.2	$	157.9	$	86.6	$	340.2	$	418.2	$	150.2	$	66.2	$	376.6	$	410.6	$	140.9	$	39.4
Statutory Federal Income
	Tax Expense at 35%		106.5		110.0		55.3		30.3		119.1		146.4		52.6		23.2		131.8		143.7		49.3		13.8
Tax Effect of Differences:
	Depreciation		(9.0)		0.0		(0.3)		0.2		(8.1)		0.0		(4.4)		0.1		(6.1)		0.0		(3.2)		0.2
	Investment Tax Credit
	Amortization		(1.9)		(1.4)		0.0		(0.5)		(2.1)		(1.4)		-		(0.3)		(2.3)		(1.4)		(0.1)		(0.3)
	Other Federal Tax Credits		0.0		0.0		(3.8)		0.0		(0.1)		0.0		(3.4)		0.0		(0.1)		0.0		(3.6)		-
	State Income Taxes, Net
	of Federal Impact		0.1		13.4		10.0		4.0		4.0		17.9		5.2		0.9		8.5		17.4		4.7		1.6
	Medicare Subsidy		0.0		0.0		0.0		0.0		-		0.0		-		-		7.8		0.0		3.8		1.5
	Tax Asset Valuation
	Allowance/Reserve
	Adjustments		1.6		0.0		0.0		0.0		(22.3)		0.0		-		-		(4.7)		0.0		-		-
	Regulatory Decision Non-
	Plant flow through		0.0		0.0		0.0		(1.3)		0.0		0.0		-		-		0.0		0.0		-		-
	Other, Net		(2.9)		2.0		(0.2)		(0.6)		(0.5)		2.8		(0.1)		(0.7)		(2.5)		2.3		(0.1)		(0.5)
Income Tax Expense		$	94.4	$	124.0	$	61.0	$	32.1	$	90.0	$	165.7	$	49.9	$	23.2	$	132.4	$	162.0	$	50.8	$	16.3
Effective Tax Rate			31.0%		39.5%		38.6%		37.1%		26.5%		39.6%		33.2%		35.0%		35.2%		39.5%		36.1%		41.4%

NU, CL&P, NSTAR Electric, PSNH and WMECO file a consolidated federal income tax return and unitary, combined and separate state income tax returns. These entities are also parties to a tax allocation agreement under which taxable subsidiaries do not pay any more taxes than they would have otherwise paid had they filed a separate company tax return, and subsidiaries generating tax losses, if any, are paid for their losses when utilized.

Deferred tax assets and liabilities are recognized for the future tax effects of temporary differences between the carrying amounts and the tax basis of assets and liabilities. The tax effects of temporary differences that give rise to the net accumulated deferred tax obligations are as follows:

NU			As of December 31,
(Millions of Dollars)			2012		2011
Deferred Tax Assets:
	Employee Benefits		$	811.4	$	539.6
	Derivative Liabilities and Change in Fair Value of Energy Contracts			380.6		415.3
	Regulatory Deferrals			257.9		157.9
	Allowance for Uncollectible Accounts			64.2		45.4
	Tax Effect - Tax Regulatory Assets			17.2		15.5
	Federal Net Operating Loss Carryforwards			214.6		178.6
	Purchase Accounting Adjustment			146.4		-
	Other			242.4		204.2
Total Deferred Tax Assets				2,134.7		1,556.5
Less: Valuation Allowance				4.2		4.6
Net Deferred Tax Assets			$	2,130.5	$	1,551.9
Deferred Tax Liabilities:
	Accelerated Depreciation and Other Plant-Related Differences		$	3,468.8	$	1,920.5
	Property Tax Accruals			89.6		58.9
	Regulatory Amounts:
		Other Regulatory Deferrals		1,561.1		1,135.0
		Tax Effect - Tax Regulatory Assets		217.2		184.6
		Goodwill - 1999 Merger		210.9		-
		Derivative Assets		36.2		39.1
		Securitized Contract Termination Costs		16.6		39.6
		Other		136.1		24.5
Total Deferred Tax Liabilities			$	5,736.5	$	3,402.2

			As of December 31,
			2012								2011
					NSTAR								NSTAR
(Millions of Dollars)			CL&P		Electric		PSNH		WMECO		CL&P		Electric (1)		PSNH		WMECO
Deferred Tax Assets:
	Derivative Liabilities and Change in
		Fair Value of Energy Contracts	$	375.9	$	5.8	$	-	$	(1.7)	$	412.2	$	1.3	$	-	$	2.9
	Allowance for Uncollectible Accounts			30.4		16.2		2.9		3.2		32.4		9.5		3.0		3.9
	Regulatory Deferrals			35.5		123.6		43.9		6.3		78.4		114.9		39.3		15.0
	Employee Benefits			141.2		116.3		64.8		16.3		121.4		115.3		87.9		13.3
	Tax Effect - Tax Regulatory Assets			5.2		6.0		1.7		1.7		6.4		6.9		1.6		6.5
	Federal Net Operating Loss Carryforwards			82.0		-		71.4		15.1		85.5		-		60.8		-
	Other			82.8		26.0		33.7		8.0		76.0		36.1		26.0		17.6
Total Deferred Tax Assets			$	753.0	$	293.9	$	218.4	$	48.9	$	812.3	$	284.0	$	218.6	$	59.2
Deferred Tax Liabilities:
	Accelerated Depreciation and Other
	Plant-Related Differences		$	1,194.7	$	1,079.3	$	476.5	$	261.3	$	1,046.9	$	987.8	$	423.8	$	194.9
	Property Tax Accruals			44.4		23.1		6.8		5.1		41.9		21.8		4.5		3.4
	Regulatory Amounts:
		Other Regulatory Deferrals		677.7		379.6		149.3		74.5		734.2		400.6		122.5		79.3
		Tax Effect - Tax Regulatory Assets		151.8		20.9		15.8		13.9		141.8		21.9		16.1		13.7
		Goodwill - 1999 Merger		-		181.0		-		-		-		187.8		-		-
		Derivative Assets		36.2		-		-		-		39.1		-		-		-
		Securitized Contract Termination Costs		-		5.5		7.9		3.3		-		41.3		29.7		10.0
		Other		10.1		30.2		14.1		2.3		8.2		34.8		14.0		1.1
Total Deferred Tax Liabilities			$	2,114.9	$	1,719.6	$	670.4	$	360.4	$	2,012.1	$	1,696.0	$	610.6	$	302.4
(1)		NSTAR Electric amounts are not included in NU consolidated as of December 31, 2011.

Carryforwards: Amounts are as follows:
	As of December 31, 2012
					NSTAR						Year
(Millions of Dollars)	NU		CL&P		Electric		PSNH		WMECO		Expiration Begins
State Credit Carryforwards	$	110.2	$	75.2	$	0.0	$	0.0	$	0.0	2013
State Net Operating Loss Carryforward		74.9		0.0		0.0		0.0		0.0	2013
Federal Net Operating Loss Carryforward		606.9		234.3		0.0		204.0		43.3	2031
Federal Credit Carryforwards		3.8		0.0		0.0		3.8		0.0	2031
	As of December 31, 2011
					NSTAR						Year
(Millions of Dollars)	NU		CL&P		Electric		PSNH		WMECO		Expiration Begins
State Credit Carryforwards	$	101.4	$	68.6	$	0.0	$	0.0	$	0.0	2013
Federal Net Operating Loss Carryforward		510.2		244.2		0.0		173.8		0.0	2031
Federal Credit Carryforwards		6.6		0.0		0.0		3.4		3.2	2031

For 2012, the state net operating loss carryforward has been partially reserved by a valuation allowance of $0.3 million (net of federal income tax).

Unrecognized Tax Benefits: A reconciliation of the activity in unrecognized tax benefits from January 1, 2010 to December 31, 2012, all of which would impact the effective tax rate, if recognized, is as follows:

						NSTAR
(Millions of Dollars)		NU		CL&P		Electric (1)
Balance as of January 1, 2010		$	124.3	$	89.0	$	13.8
	Gross Increases - Current Year		10.8		5.3		-
	Gross Increases - Prior Year		0.8		-		-
	Settlement		(34.3)		(13.5)		(13.8)
	Lapse of Statute of Limitations		(0.4)		-		-
Balance as of December 31, 2010			101.2		80.8		-
	Gross Increases - Current Year		8.0		1.4		-
	Gross Decreases - Prior Year		(35.7)		(35.7)		-
Balance as of December 31, 2011			73.5		46.5		-
	Gross Increases - Current Year		10.3		2.5		-
	Gross Increases - Prior Year		0.1		-		-
	Gross Decreases - Prior Year		(0.8)		-		-
Balance as of December 31, 2012		$	83.1	$	49.0	$	-

• NSTAR Electric amounts are not included in NU consolidated for the years ended December 31, 2011 and 2010.

Interest and Penalties: Interest on uncertain tax positions is recorded and generally classified as a component of Other Interest Expense. However, when resolution of uncertainties results in the Company receiving interest income, any related interest benefit is recorded in Other Income, Net on the accompanying consolidated statements of income. No penalties have been recorded. If penalties are recorded in the future, then the estimated penalties would be classified as a component of Other Income, Net on the accompanying consolidated statements of income. The amount of interest expense/(income) on uncertain tax positions recognized and the related accrued interest payable/(receivable) by company are as follows:

Other Interest	For the Years Ended December 31,						Accrued Interest	As of December 31,
Expense/(Income)	2012		2011		2010		Expense	2012		2011
(Millions of Dollars)							(Millions of Dollars)
NU	$	3.1	$	(2.8)	$	(24.8)	NU	$	10.1	$	7.1
CL&P		1.3		(3.7)		(7.4)	CL&P		4.0		2.7
NSTAR Electric (1)		0.0		2.0		(7.4)	NSTAR Electric (1)		0.0		0.7
PSNH		0.0		(0.6)		0.1	PSNH		0.0		-

(1)NSTAR Electric amounts are included in NU consolidated from the date of the merger, April 10, 2012, through December 31, 2012. NSTAR Electric amounts are not included in NU consolidated for the years ended December 31, 2011 and 2010.

Tax Positions: During 2012, NU did not resolve any of its uncertain tax positions.

During 2011, NU recorded an after-tax benefit of $29.1 million related to various state tax settlements and certain other adjustments. This benefit was recorded as a reduction to both interest expense and income tax expense (including NU and CL&P tax expense reductions of approximately $22.4 million).

During 2010, NU settled various tax matters including state obligations, which resulted in the recognition during the year of an after-tax gain of approximately $35 million. This gain was recorded as a reduction to both interest expense and income tax expense (including NU and CL&P tax expense reductions of approximately $6 million and $4 million, respectively).

Open Tax Years: The following table summarizes NU, CL&P, NSTAR Electric, PSNH and WMECO's tax years that remain subject to examination by major tax jurisdictions as of December 31, 2012:

Description	Tax Years
Federal	2012
Connecticut	2005-2012
Massachusetts	2009-2012
New Hampshire	2009-2012

Receipt of Federal Tax Refund:During 2011, NSTAR Electric received a $166.8 million refund from the IRS relating to the 2001 through 2007 tax years. The approved settlement and the receipt of the refund resolved all outstanding tax matters for these years.

NU is currently working to resolve the treatments and certain timing and other costs in the remaining open periods. While tax audits are currently ongoing, it is reasonably possible that one or more of these open tax years could be resolved within the next twelve months.  Management estimates that potential resolutions of differences of a non-timing nature could result in a zero to $50million decrease in unrecognized tax benefits by NU and a zero to $39 million decrease in unrecognized tax benefits by CL&P. These estimated changes could have an impact on NU's and CL&P's 2013 earnings of zero to $6 million and zero to $16 million, respectively.  Other companies' impacts are not expected to be material.

2013 Federal Legislation:On January 2, 2013, President Obama signed into law the “American Taxpayer Relief Act of 2012,” which extends certain tax rules allowing the accelerated deduction of depreciation from the “American Recovery and Reinvestment Act of 2009” to businesses through 2013. This extended stimulus is expected to provide cash flow benefits of approximately $200 million to $250 million in 2013 and 2014. Management is still evaluating the other provisions of this legislation, which are not expected to have a significant impact on its future financial position, results of operations, or cash flows.

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DIVIDEND RESTRICTIONS

12 Months Ended

Dec. 31, 2012

Notes To Consolidated Financial Statements [Abstract]

Schedule of Dividend Payment Restrictions [Table Text Block]

16.       DIVIDEND RESTRICTIONS

NU parent's ability to pay dividends may be affected by certain state statutes, the ability of its subsidiaries to pay common dividends and the leverage restriction tied to its consolidated total debt to total capitalization ratio requirement in its revolving credit agreement.

CL&P, NSTAR Electric, PSNH and WMECO are subject to Section 305 of the Federal Power Act that makes it unlawful for a public utility to make or pay a dividend from any funds "properly included in its capital account." Management believes that this Federal Power Act restriction, as applied to CL&P, NSTAR Electric, PSNH and WMECO, would not be construed or applied by the FERC to prohibit the payment of dividends for lawful and legitimate business purposes from retained earnings. In addition, certain state statutes may impose additional limitations on such companies and on Yankee Gas and NSTAR Gas. Such state law restrictions do not restrict payment of dividends from retained earnings or net income. CL&P, NSTAR Electric, PSNH, WMECO, Yankee Gas and NSTAR Gas also have revolving credit agreements that impose leverage restrictions including consolidated total debt to total capitalization ratio requirements. The Retained Earnings balances subject to these leverage restrictions are $1.803billion for NU, $839.6 million for CL&P, $1.210 billion for NSTAR Electric, $395.1 million for PSNH and $160.6million for WMECO as of December 31, 2012.PSNH is further required to reserve an additional amount under its FERC hydroelectric license conditions. As of December 31, 2012, approximately $12.3million of PSNH's Retained Earnings is subject to restriction under its FERC hydroelectric license conditions.As of December 31, 2012, NU, CL&P, NSTAR Electric, PSNH, WMECO, Yankee Gas and NSTAR Gas were in compliance with all such provisions of its credit agreements that may restrict the payment of dividends

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Deferred Contractual Obligations & Other (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012
Loss Contingency, Information about Litigation Matters [Abstract]
Court of Federal Claims Ruling To CYAPC	$ 34.2
Court Of Federal Claims Ruling To YAEC	32.9
Court Of Federal Claims Ruling To MYAPC	75.8
Trial Court Ruling To CYAPC	39.7
Trial Court Ruling To YAEC	21.2
Trial Court Ruling To MYAPC	81.7
Receivable from DOE at Year End 2012	77.9
Connecticut Yankee Proceeds Received	39.6
Yankee Atomic Proceeds Received	38.3
Maine Yankee Proceeds Received	81.7
NSTAR Electric DPU Storm Penalty	4.1
WMECO DPU Storm Penalty	2.0
Cumulative CPSL Costs 2006 To 2011	83.0
CPSL Revenue Requirement For 2012 To 2015	15.0
Bad Debt Service Adder As Of 2011	34.0
Pre Tax NSTAR Electric Bad Debt Adder Reserve Recorded In 2012	28.0
Post Tax NSTAR Electric Bad Debt Adder Reserve In 2012	$ 17.0

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SHORT TERM DEBT (TABLES)

12 Months Ended

Dec. 31, 2012

Notes To Consolidated Financial Statements [Abstract]

Schedule of Short-term Debt [Table Text Block]

	As of and for the Year Ended December 31, 2011
(Millions of Dollars, except percentages)	CL&P			PSNH			WMECO
Borrowings from/(Lendings to)	$	58.5		$	(55.9)		$	(11.0)
Weighted-Average Interest Rates		0.08	%		0.1	%		0.1	%

XML

SEGMENT INFORMATION (Details) (USD $)	3 Months Ended								12 Months Ended
	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Segment Reporting Information [Line Items]
Operating Revenues	$ 1,684,000,000	$ 1,861,500,000	$ 1,628,700,000	$ 1,099,600,000	$ 1,068,000,000	$ 1,114,900,000	$ 1,047,500,000	$ 1,235,300,000	$ 6,273,787,000	$ 4,465,657,000	$ 4,898,167,000
Depreciation And Amortization									(740,800,000)	(463,200,000)	(623,700,000)
Operating Expenses									(4,414,800,000)	(3,208,300,000)	(3,474,600,000)
Operating Income	331,400,000	412,900,000	159,500,000	214,400,000	184,900,000	203,800,000	178,100,000	227,400,000	1,118,206,000	794,176,000	799,891,000
Total Interest Expense									(329,945,000)	(250,425,000)	(237,291,000)
Other Income/(Loss), Net									19,742,000	27,715,000	41,916,000
Income Tax Expense									(274,926,000)	(170,953,000)	(210,409,000)
Net Income	176,600,000	209,500,000	46,200,000	100,800,000	114,800,000	91,400,000	78,700,000	115,600,000	533,077,000	400,513,000	394,107,000
Net Income Attributable to Noncontrolling Interests									(7,132,000)	(5,820,000)	(6,158,000)
Net Income Attributable to Controlling Interests	174,700,000	207,600,000	44,300,000	99,300,000	113,200,000	90,000,000	77,300,000	114,200,000	525,945,000	394,693,000	387,949,000
Total Assets	28,302,824,000				15,647,066,000				28,302,824,000	15,647,066,000
Investments in Property, Plant and Equipment									1,472,272,000	1,076,730,000	954,472,000
The Connecticut Light And Power Company [Member]
Segment Reporting Information [Line Items]
Operating Revenues	595,200,000	658,100,000	562,100,000	592,000,000	593,000,000	673,700,000	608,000,000	673,700,000	2,407,449,000	2,548,387,000	2,999,102,000
Operating Income	135,000,000	139,700,000	40,400,000	111,900,000	84,700,000	137,700,000	114,800,000	126,000,000	426,989,000	463,183,000	487,650,000
Total Interest Expense									(133,127,000)	(132,727,000)	(137,738,000)
Other Income/(Loss), Net									10,300,000	9,741,000	26,669,000
Income Tax Expense									(94,437,000)	(90,033,000)	(132,438,000)
Net Income	73,900,000	74,900,000	6,900,000	54,000,000	66,800,000	66,500,000	52,600,000	64,300,000	209,725,000	250,164,000	244,143,000
Total Assets	9,142,088,000				8,791,396,000				9,142,088,000	8,791,396,000
Investments in Property, Plant and Equipment									449,137,000	424,865,000	380,304,000
Public Service Company Of New Hampshire [Member]
Segment Reporting Information [Line Items]
Operating Revenues	233,000,000	256,900,000	255,100,000	243,000,000	243,700,000	259,600,000	240,200,000	269,500,000	988,013,000	1,013,003,000	1,033,439,000
Operating Income	51,400,000	61,300,000	47,000,000	45,400,000	46,800,000	48,500,000	37,900,000	46,900,000	205,095,000	180,104,000	176,186,000
Total Interest Expense									(50,228,000)	(44,147,000)	(47,067,000)
Other Income/(Loss), Net									3,008,000	14,255,000	11,749,000
Income Tax Expense									(60,993,000)	(49,945,000)	(50,801,000)
Net Income	27,200,000	27,200,000	21,200,000	21,300,000	25,500,000	25,600,000	21,700,000	27,500,000	96,882,000	100,267,000	90,067,000
Total Assets	3,114,597,000				3,116,541,000				3,114,597,000	3,116,541,000
Investments in Property, Plant and Equipment									203,902,000	241,772,000	296,335,000
Western Massachusetts Electric Company [Member]
Segment Reporting Information [Line Items]
Operating Revenues	107,900,000	112,500,000	106,800,000	114,000,000	107,700,000	104,500,000	98,400,000	106,700,000	441,164,000	417,315,000	395,161,000
Operating Income	28,900,000	28,100,000	25,100,000	28,700,000	29,000,000	19,800,000	18,500,000	21,100,000	110,774,000	88,363,000	58,657,000
Total Interest Expense									(26,634,000)	(23,612,000)	(21,839,000)
Other Income/(Loss), Net									2,503,000	1,489,000	2,597,000
Income Tax Expense									(32,140,000)	(23,186,000)	(16,325,000)
Net Income	15,100,000	14,100,000	11,100,000	14,200,000	16,500,000	8,400,000	8,200,000	10,000,000	54,503,000	43,054,000	23,090,000
Total Assets	1,723,069,000				1,502,893,000				1,723,069,000	1,502,893,000
Investments in Property, Plant and Equipment									264,175,000	237,996,000	115,178,000
Electric Distribution Member
Segment Reporting Information [Line Items]
Operating Revenues									4,716,500,000	3,343,100,000	3,802,000,000
Depreciation And Amortization									(530,300,000)	(337,200,000)	(501,200,000)
Operating Expenses									(3,585,400,000)	(2,637,400,000)	(2,925,100,000)
Operating Income									600,800,000	368,500,000	375,700,000
Total Interest Expense									(165,600,000)	(123,800,000)	(133,400,000)
Interest Income									2,800,000	3,700,000	700,000
Other Income/(Loss), Net									8,900,000	11,600,000	24,400,000
Income Tax Expense									(150,200,000)	(67,600,000)	(90,300,000)
Net Income									296,700,000	192,400,000	177,100,000
Net Income Attributable to Noncontrolling Interests									(4,400,000)	(3,300,000)	(3,600,000)
Net Income Attributable to Controlling Interests									292,300,000	189,100,000	173,500,000
Total Assets	18,047,300,000				9,653,100,000				18,047,300,000	9,653,100,000
Investments in Property, Plant and Equipment									611,700,000	540,700,000	560,100,000
Natural Gas Distribution [Member]
Segment Reporting Information [Line Items]
Operating Revenues									572,900,000	430,800,000	434,300,000
Depreciation And Amortization									(49,100,000)	(27,700,000)	(23,800,000)
Operating Expenses									(445,200,000)	(333,500,000)	(340,000,000)
Operating Income									78,600,000	69,600,000	70,500,000
Total Interest Expense									(31,300,000)	(21,000,000)	(17,900,000)
Interest Income									0	0	0
Other Income/(Loss), Net									400,000	1,300,000	800,000
Income Tax Expense									(16,900,000)	(18,200,000)	(20,700,000)
Net Income									30,800,000	31,700,000	32,700,000
Net Income Attributable to Noncontrolling Interests									0	0	0
Net Income Attributable to Controlling Interests									30,800,000	31,700,000	32,700,000
Total Assets	2,717,400,000				1,511,300,000				2,717,400,000	1,511,300,000
Investments in Property, Plant and Equipment									148,700,000	98,200,000	82,500,000
Transmission [Member]
Segment Reporting Information [Line Items]
Operating Revenues									861,500,000	635,400,000	625,600,000
Depreciation And Amortization									(109,200,000)	(84,000,000)	(86,700,000)
Operating Expenses									(251,600,000)	(188,200,000)	(192,100,000)
Operating Income									500,700,000	363,200,000	346,800,000
Total Interest Expense									(96,700,000)	(76,700,000)	(73,200,000)
Interest Income									400,000	500,000	1,800,000
Other Income/(Loss), Net									7,300,000	10,700,000	14,300,000
Income Tax Expense									(159,200,000)	(95,600,000)	(109,300,000)
Net Income									252,500,000	202,100,000	180,400,000
Net Income Attributable to Noncontrolling Interests									(2,800,000)	(2,500,000)	(2,600,000)
Net Income Attributable to Controlling Interests									249,700,000	199,600,000	177,800,000
Total Assets	6,187,700,000				3,792,900,000				6,187,700,000	3,792,900,000
Investments in Property, Plant and Equipment									663,600,000	388,900,000	239,200,000
Other Segment [Member]
Segment Reporting Information [Line Items]
Operating Revenues									803,800,000	541,300,000	521,600,000
Depreciation And Amortization									(56,400,000)	(16,800,000)	(15,800,000)
Operating Expenses									(817,000,000)	(534,100,000)	(505,400,000)
Operating Income									(69,600,000)	(9,600,000)	400,000
Total Interest Expense									(43,600,000)	(33,700,000)	(17,400,000)
Interest Income									7,100,000	5,300,000	5,300,000
Other Income/(Loss), Net									795,000,000	455,200,000	436,400,000
Income Tax Expense									55,500,000	14,300,000	11,000,000
Net Income									744,400,000	431,500,000	435,700,000
Net Income Attributable to Noncontrolling Interests									0	0	0
Net Income Attributable to Controlling Interests									744,400,000	431,500,000	435,700,000
Total Assets	18,832,600,000				6,618,000,000				18,832,600,000	6,618,000,000
Investments in Property, Plant and Equipment									48,300,000	48,900,000	72,700,000
Eliminations Segment [Member]
Segment Reporting Information [Line Items]
Operating Revenues									(680,900,000)	(484,900,000)	(485,300,000)
Depreciation And Amortization									4,200,000	2,500,000	3,800,000
Operating Expenses									684,400,000	484,900,000	488,000,000
Operating Income									7,700,000	2,500,000	6,500,000
Total Interest Expense									7,300,000	4,800,000	4,600,000
Interest Income									(7,100,000)	(5,300,000)	(6,300,000)
Other Income/(Loss), Net									(795,100,000)	(455,300,000)	(435,500,000)
Income Tax Expense									(4,100,000)	(3,900,000)	(1,100,000)
Net Income									(791,300,000)	(457,200,000)	(431,800,000)
Net Income Attributable to Noncontrolling Interests									0	0	0
Net Income Attributable to Controlling Interests									(791,300,000)	(457,200,000)	(431,800,000)
Total Assets	(17,482,200,000)				(5,928,200,000)				(17,482,200,000)	(5,928,200,000)
Investments in Property, Plant and Equipment									0	0	0
Total [Member]
Segment Reporting Information [Line Items]
Operating Revenues									6,273,800,000	4,465,700,000	4,898,200,000
Operating Income									1,118,200,000	794,200,000	799,900,000
Total Interest Expense									(329,900,000)	(250,400,000)	(237,300,000)
Interest Income									3,200,000	4,200,000	1,500,000
Other Income/(Loss), Net									16,500,000	23,500,000	40,400,000
Income Tax Expense									(274,900,000)	(171,000,000)	(210,400,000)
Net Income									533,100,000	400,500,000	394,100,000
Net Income Attributable to Noncontrolling Interests									(7,200,000)	(5,800,000)	(6,200,000)
Net Income Attributable to Controlling Interests									525,900,000	394,700,000	387,900,000
Total Assets	28,302,800,000				15,647,100,000				28,302,800,000	15,647,100,000
Investments in Property, Plant and Equipment									$ 1,472,300,000	$ 1,076,700,000	$ 954,500,000

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Other Taxes (Tables)

12 Months Ended

Dec. 31, 2012

Notes To Consolidated Financial Statements [Abstract]

State Of Connecticut Gross Earnings Taxes [Table Text Block]

	For the Years Ended December 31,
(Millions of Dollars)	2012		2011		2010
NU	$	135.0	$	137.8	$	143.7
CL&P		120.7		121.6		128.0

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QUARTERLY FINANCIAL DATA (UNAUDITED) (Details) (USD $) In Thousands, except Per Share data, unless otherwise specified	3 Months Ended								12 Months Ended
	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Operating Revenues	$ 1,684,000	$ 1,861,500	$ 1,628,700	$ 1,099,600	$ 1,068,000	$ 1,114,900	$ 1,047,500	$ 1,235,300	$ 6,273,787	$ 4,465,657	$ 4,898,167
Operating Income	331,400	412,900	159,500	214,400	184,900	203,800	178,100	227,400	1,118,206	794,176	799,891
Net Income	176,600	209,500	46,200	100,800	114,800	91,400	78,700	115,600	533,077	400,513	394,107
Net Income Attributable to Controlling Interests	174,700	207,600	44,300	99,300	113,200	90,000	77,300	114,200	525,945	394,693	387,949
Basic Earnings Per Common Share									$ 1.90	$ 2.22	$ 2.20
Diluted Earnings Per Common Share									$ 1.89	$ 2.22	$ 2.19
Earnings Per Share Basic And Diluted	$ 0.55	$ 0.66	$ 0.15	$ 0.56	$ 0.64	$ 0.51	$ 0.44	$ 0.64
Quantifying Prior Year Misstatements Corrected in Current Year Financial Statements [Abstract]
Immaterial Error Correction									The NSTAR Electric consolidated statements of cash flows were revised to correct an error in the presentation of cash deposits related to the RRBs.The impact of this revision was an increase in investing cash inflows from Other Investing Activities in an amount of $1.7 million and $24.1 million and a corresponding increase to financing cash outflows from Retirements ofRate Reduction Bonds for the years ended December 31, 2011 and 2010, respectively. These revisions had no impact on NSTAR Electric’s results of operations or cash balance and are not deemed material, individually orin the aggregate, to the previously issued consolidated financial statements.
The Connecticut Light And Power Company [Member]
Operating Revenues	595,200	658,100	562,100	592,000	593,000	673,700	608,000	673,700	2,407,449	2,548,387	2,999,102
Operating Income	135,000	139,700	40,400	111,900	84,700	137,700	114,800	126,000	426,989	463,183	487,650
Net Income	73,900	74,900	6,900	54,000	66,800	66,500	52,600	64,300	209,725	250,164	244,143
Public Service Company Of New Hampshire [Member]
Operating Revenues	233,000	256,900	255,100	243,000	243,700	259,600	240,200	269,500	988,013	1,013,003	1,033,439
Operating Income	51,400	61,300	47,000	45,400	46,800	48,500	37,900	46,900	205,095	180,104	176,186
Net Income	27,200	27,200	21,200	21,300	25,500	25,600	21,700	27,500	96,882	100,267	90,067
Western Massachusetts Electric Company [Member]
Operating Revenues	107,900	112,500	106,800	114,000	107,700	104,500	98,400	106,700	441,164	417,315	395,161
Operating Income	28,900	28,100	25,100	28,700	29,000	19,800	18,500	21,100	110,774	88,363	58,657
Net Income	15,100	14,100	11,100	14,200	16,500	8,400	8,200	10,000	54,503	43,054	23,090
NSTAR Electric Company [Member]
Operating Revenues	516,200	693,700	534,600	556,500	548,600	724,700	552,300	577,500	2,300,997	2,403,053	2,366,201
Operating Income	70,900	194,100	93,900	22,500	99,200	183,700	115,600	87,700	381,416	486,173	478,812
Net Income	$ 34,000	$ 106,800	$ 45,500	$ 3,900	$ 49,100	$ 99,800	$ 60,700	$ 42,900	$ 190,242	$ 252,494	$ 248,575

XML

CONSOLIDATED STATEMENT OF CASH FLOWS (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Operating Activities:
Net Income	$ 533,077	$ 400,513	$ 394,107
Adjustments to Reconcile Net Income to Net Cash Flows Provided by Operating Activities:
Bad Debt Expense	36,275	16,420	31,352
Depreciation	519,010	302,192	300,737
Deferred Income Tax Expense (Benefit)	292,000	196,761	210,939
Pension and PBOP Expense, Net of PBOP Contributions	218,540	133,000	103,861
Pension and Other Postretirement Benefit Contributions	(295,028)	(191,101)	(90,633)
Regulatory (Underrecoveries)/Overrecoveries, Net	(259,853)	(70,863)	26,289
Amortization of Regulatory Assets/(Liabilities), Net	79,762	91,080	90,054
Amortization of Rate Reduction Bonds	142,019	69,912	232,871
Changes in Derivative Assets and Liabilities	(10,455)	(35,441)	(11,812)
Other Noncash Income (Expense)	17,032	(29,751)	(72,151)
Changes in Current Assets and Liabilities:
Receivables and Unbilled Revenues, Net	(20,214)	17,570	(51,285)
Inventory	34,321	(11,033)	38,126
Taxes Receivable/(Accrued)	(5,450)	49,642	(82,103)
Change in Accounts Payable	(128,339)	18,916	(44,355)
Other Current Assets and Liabilities	8,532	12,569	17,466
Net Cash Flows Provided by Operating Activities	1,161,229	970,386	1,093,463
Investing Activities:
Investments in Property, Plant and Equipment	(1,472,272)	(1,076,730)	(954,472)
Proceeds from Sales of Marketable Securities	317,294	149,441	174,865
Purchases of Marketable Securities	(348,629)	(151,972)	(177,204)
Proceeds From Sale Of Property Plant And Equipment	0	46,841	0
Other Investing Activities	35,683	13,833	(1,157)
Net Cash Flows Used in Investing Activities	(1,467,924)	(1,018,587)	(957,968)
Financing Activities:
Cash Dividends on Common Stock	(375,047)	(194,555)	(180,542)
Cash Dividends on Preferred Stock	(7,029)	(5,559)	(5,559)
Increase/(Decrease) in Short-Term Debt	825,000	50,000	166,687
Issuance of Long-Term Debt	850,000	627,500	145,000
Retirements of Long-Term Debt	(839,136)	(369,586)	(4,286)
Retirements of Rate Reduction Bonds	(114,433)	(69,312)	(260,864)
Other Financing Activities	6,529	(7,123)	512
Net Cash Flows Provided by/(Used in) Financing Activities	345,884	31,365	(139,052)
Net Increase/(Decrease) in Cash	39,189	(16,836)	(3,557)
Cash - Beginning of Year	6,559	23,395	26,952
Cash - End of Year	45,748	6,559	23,395
The Connecticut Light And Power Company [Member]
Operating Activities:
Net Income	209,725	250,164	244,143
Adjustments to Reconcile Net Income to Net Cash Flows Provided by Operating Activities:
Bad Debt Expense	2,080	3,215	7,484
Depreciation	166,853	157,747	172,167
Deferred Income Tax Expense (Benefit)	140,993	112,620	115,069
Pension and PBOP Expense, Net of PBOP Contributions	24,062	10,664	1,595
Regulatory (Underrecoveries)/Overrecoveries, Net	(100,505)	(82,502)	37,528
Amortization of Regulatory Assets/(Liabilities), Net	14,372	61,025	78,870
Amortization of Rate Reduction Bonds	0	0	167,021
Other Noncash Income (Expense)	(31,032)	(36,928)	(55,515)
Changes in Current Assets and Liabilities:
Receivables and Unbilled Revenues, Net	(7,741)	14,610	1,895
Inventory	(4,573)	(2,206)	3,377
Taxes Receivable/(Accrued)	15,702	2,719	(56,002)
Change in Accounts Payable	(190,240)	8,864	(35,976)
Other Current Assets and Liabilities	(27,803)	13,291	15,649
Net Cash Flows Provided by Operating Activities	211,893	513,283	697,305
Investing Activities:
Investments in Property, Plant and Equipment	(449,137)	(424,865)	(380,304)
(Increase) Decrease In Notes Receivable From Affiliated Company	0	0	97,775
Proceeds From Sale Of Property Plant And Equipment	0	46,841	0
Other Investing Activities	32,009	16,001	5,385
Net Cash Flows Used in Investing Activities	(417,128)	(362,023)	(277,144)
Financing Activities:
Cash Dividends on Common Stock	(100,486)	(243,218)	(217,691)
Cash Dividends on Preferred Stock	(5,559)	(5,559)	(5,559)
Increase/(Decrease) in Short-Term Debt	58,000	31,000	0
Issuance of Long-Term Debt	0	245,500	0
Increase/(Decrease) in Notes Payable to Affiliate	346,575	52,300	6,225
Retirements of Long-Term Debt	(116,400)	(245,500)	0
Retirements of Rate Reduction Bonds	0	0	(195,587)
Capital Contributions from NU Parent	25,000	6,748	2,513
Other Financing Activities	(1,895)	(2,292)	(345)
Net Cash Flows Provided by/(Used in) Financing Activities	205,235	(161,021)	(410,444)
Net Increase/(Decrease) in Cash	0	(9,761)	9,717
Cash - Beginning of Year	1	9,762	45
Cash - End of Year	1	1	9,762
Public Service Company Of New Hampshire [Member]
Operating Activities:
Net Income	96,882	100,267	90,067
Adjustments to Reconcile Net Income to Net Cash Flows Provided by Operating Activities:
Bad Debt Expense	6,457	7,035	8,858
Depreciation	87,602	76,167	67,237
Deferred Income Tax Expense (Benefit)	58,552	75,628	39,225
Pension and PBOP Expense, Net of PBOP Contributions	26,312	27,298	29,112
Pension and Other Postretirement Benefit Contributions	(96,880)	(121,178)	(53,689)
Regulatory (Underrecoveries)/Overrecoveries, Net	(183)	6,079	(2,834)
Amortization of Regulatory Assets/(Liabilities), Net	(24,086)	25,383	11,232
Amortization of Rate Reduction Bonds	56,645	53,389	50,357
Changes in Derivative Assets and Liabilities	0	(18,072)	0
Other Noncash Income (Expense)	4,748	(20,958)	(31,590)
Changes in Current Assets and Liabilities:
Receivables and Unbilled Revenues, Net	(84)	7,833	(24,497)
Inventory	25,897	(9,873)	14,891
Taxes Receivable/(Accrued)	(9,752)	5,139	10,037
Change in Accounts Payable	(15,248)	(4,517)	(14,427)
Other Current Assets and Liabilities	13,436	(4,915)	1,294
Net Cash Flows Provided by Operating Activities	230,298	204,705	195,273
Investing Activities:
Investments in Property, Plant and Equipment	(203,902)	(241,772)	(296,335)
(Increase) Decrease In Notes Receivable From Affiliated Company	55,900	(55,900)	0
Other Investing Activities	4,065	2,089	(7,819)
Net Cash Flows Used in Investing Activities	(143,937)	(295,583)	(304,154)
Financing Activities:
Cash Dividends on Common Stock	(90,674)	(58,828)	(50,584)
Increase/(Decrease) in Short-Term Debt	0	(30,000)	30,000
Issuance of Long-Term Debt	0	282,000	0
Increase/(Decrease) in Notes Payable to Affiliate	63,300	(47,900)	21,200
Retirements of Long-Term Debt	0	(119,800)	0
Retirements of Rate Reduction Bonds	(56,074)	(52,879)	(49,867)
Capital Contributions from NU Parent	0	120,030	158,969
Other Financing Activities	(476)	(4,248)	(252)
Net Cash Flows Provided by/(Used in) Financing Activities	(83,924)	88,375	109,466
Net Increase/(Decrease) in Cash	2,437	(2,503)	585
Cash - Beginning of Year	56	2,559	1,974
Cash - End of Year	2,493	56	2,559
Western Massachusetts Electric Company [Member]
Operating Activities:
Net Income	54,503	43,054	23,090
Adjustments to Reconcile Net Income to Net Cash Flows Provided by Operating Activities:
Bad Debt Expense	2,294	3,133	9,747
Depreciation	29,971	26,455	23,561
Deferred Income Tax Expense (Benefit)	53,942	23,056	10,963
Regulatory (Underrecoveries)/Overrecoveries, Net	(19,152)	3,328	(11,048)
Amortization of Regulatory Assets/(Liabilities), Net	410	4,492	1,892
Amortization of Rate Reduction Bonds	17,632	16,523	15,494
Changes in Derivative Assets and Liabilities	0	(6,859)	0
Other Noncash Income (Expense)	(6,248)	(3,719)	(7,567)
Changes in Current Assets and Liabilities:
Receivables and Unbilled Revenues, Net	(8,896)	(7,263)	(6,838)
Inventory	(2,882)	331	4,650
Taxes Receivable/(Accrued)	(8,311)	5,084	(393)
Change in Accounts Payable	(19,297)	12,956	(92)
Other Current Assets and Liabilities	581	3,824	2,406
Net Cash Flows Provided by Operating Activities	94,547	124,395	65,865
Investing Activities:
Investments in Property, Plant and Equipment	(264,175)	(237,996)	(115,178)
Proceeds from Sales of Marketable Securities	79,769	125,157	114,191
Purchases of Marketable Securities	(80,529)	(125,453)	(114,587)
(Increase) Decrease In Notes Receivable From Affiliated Company	11,000	(11,000)	0
Other Investing Activities	(28)	(1,919)	(888)
Net Cash Flows Used in Investing Activities	(253,963)	(251,211)	(116,462)
Financing Activities:
Cash Dividends on Common Stock	(9,432)	(26,305)	(14,882)
Issuance of Long-Term Debt	150,000	100,000	95,000
Increase/(Decrease) in Notes Payable to Affiliate	31,900	(20,400)	(115,700)
Retirements of Long-Term Debt	(53,800)	0	0
Retirements of Rate Reduction Bonds	(17,540)	(16,433)	(15,410)
Capital Contributions from NU Parent	50,000	91,812	102,479
Other Financing Activities	8,288	(1,858)	(890)
Net Cash Flows Provided by/(Used in) Financing Activities	159,416	126,816	50,597
Net Increase/(Decrease) in Cash	0	0	0
Cash - Beginning of Year	1	1	1
Cash - End of Year	1	1	1
NSTAR Electric Company [Member]
Operating Activities:
Net Income	190,242	252,494	248,575
Adjustments to Reconcile Net Income to Net Cash Flows Provided by Operating Activities:
Bad Debt Expense	40,301	22,582	29,417
Depreciation	171,070	163,368	158,574
Deferred Income Tax Expense (Benefit)	4,264	72,006	41,612
Pension and PBOP Expense, Net of PBOP Contributions	66,010	54,704	60,528
Pension Contribution	(25,000)	(125,000)	(25,000)
Regulatory (Underrecoveries)/Overrecoveries, Net	(16,129)	68,353	95,532
Amortization of Regulatory Assets/(Liabilities), Net	117,682	82,979	19,071
Amortization of Rate Reduction Bonds	90,322	90,322	104,481
Other Noncash Income (Expense)	(32,048)	539	(76,866)
Changes in Current Assets and Liabilities:
Receivables and Unbilled Revenues, Net	(10,496)	(26,041)	(37,132)
Inventory	1,813	(12,968)	3,077
Taxes Receivable/(Accrued)	29,899	149,889	(20,270)
Change in Accounts Payable	(59,217)	(53,939)	37,661
Other Current Assets and Liabilities	22,568	7,040	(93,528)
Net Cash Flows Provided by Operating Activities	591,281	746,328	545,732
Investing Activities:
Investments in Property, Plant and Equipment	(414,089)	(390,427)	(317,046)
Other Investing Activities	3,460	3,363	26,382
Net Cash Flows Used in Investing Activities	(410,629)	(387,064)	(290,664)
Financing Activities:
Cash Dividends on Common Stock	(217,000)	(169,900)	(188,200)
Cash Dividends on Preferred Stock	(1,960)	(1,960)	(1,960)
Increase/(Decrease) in Short-Term Debt	134,500	(86,000)	(113,500)
Issuance of Long-Term Debt	400,000	0	300,000
Retirements of Long-Term Debt	(401,650)	(16,650)	(126,648)
Retirements of Rate Reduction Bonds	(84,367)	(84,346)	(119,014)
Other Financing Activities	(5,853)	0	(7,854)
Net Cash Flows Provided by/(Used in) Financing Activities	(176,330)	(358,856)	(257,176)
Net Increase/(Decrease) in Cash	4,322	408	(2,108)
Cash - Beginning of Year	9,373	8,965	11,073
Cash - End of Year	$ 13,695	$ 9,373	$ 8,965

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PENSION BENEFITS AND POSTRETIREMENT BENEFITS OTHER THAN PENSIONS (Details) (USD $)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Defined Benefit Plan, Amounts Recognized in Balance Sheet [Abstract]
Accrued Pension, PBOP and SERP	$ 2,130,497,000	$ 1,326,037,000
Defined Benefit Plan, Estimated Future Benefit Payments [Abstract]
Description of allocation of assets to subsidiaries	CL&P, PSNH and WMECO participate in the NUSCO Pension Plan and NUSCO PBOP Plans. Each company participating in the plans is allocated a portion of the total plan assets. As of December 31, 2012 and 2011, the NUSCO Pension Plan has total assets of $2,342.6 million and $2,005.9 million, respectively. CL&P, PSNH and WMECO’s portion of these total plan assets were 40 percent, 17 percent and 9 percent, respectively, as of December 31, 2012, and 43 percent, 14 percent and 10 percent, respectively, as of December 31, 2011. The NUSCO PBOP Plans had total plan assets of $334.9 million and $285.4 million as of December 31, 2012 and 2011, respectively. CL&P, PSNH and WMECO’s share of these assets were 39 percent, 21 percent and 9 percent, respectively, as of both December 31, 2012 and 2011.
Pension Plans Defined Benefit Member
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
us-gaap_DefinedBenefitPlanBusinessCombinationsAndAcquisitionsBenefitObligation	(1,409,700,000)
Benefit Obligation Beginning Balance	(3,098,900,000)	(2,820,900,000)
Defined Benefit Plan Service Cost	(84,300,000)	(55,400,000)	(51,000,000)
Defined Benefit Plan Interest Cost	(198,300,000)	(153,300,000)	(152,600,000)
Defined Benefit Plan, Actuarial Net (Gains) Losses	(429,700,000)	(206,100,000)
Defined Benefit Plan, Benefits Paid	187,700,000	134,400,000
Defined Benefit Plan, Payments SERP	4,200,000	2,400,000
Defined Benefit Plan Benefits Paid Lump Sum		(134,400,000)
Benefit Obligation Ending Balance	(5,022,800,000)	(3,098,900,000)	(2,820,900,000)
DefinedBenefitPlanSettlementsBenefitObligation	6,200,000
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Defined Benefit Plan Service Cost	84,300,000	55,400,000	51,000,000
Defined Benefit Plan Interest Cost	198,300,000	153,300,000	152,600,000
Defined Benefit Plan, Expected Return on Plan Assets	(220,900,000)	(170,800,000)	(182,600,000)
Defined Benefit Plan, Amortization of Gains (Losses)	172,400,000	84,200,000	53,500,000
Defined Benefit Plan Amortization Of Prior Service Cost Credit	7,900,000	9,700,000	9,900,000
Defined Benefit Plan Net Periodic Benefit Cost	242,000,000	131,800,000	84,400,000
Amount Capitalized Pension Expense	70,600,000	29,700,000	16,900,000
us-gaap_DefinedBenefitPlanRecognizedNetGainLossDueToSettlementsAndCurtailments	2,200,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, Business Combinations and Acquisitions, Plan Assets	984,700,000
Fair Value of Plan Assets Beginning Balance	2,005,900,000	1,977,600,000
Defined Benefit Plan, Actual Return on Plan Assets	386,000,000	19,100,000
Defined Benefit Plan, Contributions by Employer	222,400,000	143,600,000
Defined Benefit Plan, Benefits Paid	(187,700,000)	(134,400,000)
Defined Benefit Plan Benefits Paid Lump Sum		134,400,000
Fair Value of Plan Assets Ending Balance	3,411,300,000	2,005,900,000	1,977,600,000
Defined Benefit Plan, Amounts Recognized in Balance Sheet [Abstract]
Defined Benefit Plan, Funded Status of Plan	(1,611,500,000)	(1,093,000,000)
Defined Benefit Plan, Accumulated Benefit Obligation	4,622,100,000	2,810,600,000
Level 3 Rollforwards
Fair Value of Plan Assets Beginning Balance	2,005,900,000	1,977,600,000
Fair Value of Plan Assets Ending Balance	3,411,300,000	2,005,900,000	1,977,600,000
Defined Benefit Plan, Amounts Recognized in Other Comprehensive Income (Loss) [Abstract]
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net Unamortized Gain (Loss) Arising During Period, before Tax	19,100,000	23,000,000
Other Comprehensive Income (Loss), Reclassification, Pension and Other Postretirement Benefit Plans, Net Gain (Loss) Recognized in Net Periodic Benefit Cost, before Tax	(7,800,000)	(4,800,000)
Other Comprehensive Income (Loss), Amortization, Pension and Other Postretirement Benefit Plans, Net Prior Service Cost Recognized in Net Periodic Benefit Cost, before Tax	(200,000)	(300,000)
RegulatoryAssetDefinedBenefitPlansNetUnamortizedGainLossArisingDuringPeriodBeforeTax	245,700,000	334,800,000
RegulatoryAssetReclassificationOfDefinedBenefitPlansNetGainLossRecognizedInNetPeriodicBenefitCostBeforeTax	(164,600,000)	(79,400,000)
RegulatoryAssetAmortizationOfDefinedBenefitPlanNetPriorServiceCostCreditRecognizedInNetPeriodicBenefitCostBeforeTax	(7,700,000)	(9,400,000)
Pension and Other Postretirement Benefit Plans, Accumulated Other Comprehensive Income (Loss), before Tax [Abstract]
ension and Other Postretirement Benefit Plans, Accumulated Other Comprehensive Income (Loss), Net Gains (Losses), before Tax	81,500,000	70,200,000
Pension and Other Postretirement Benefit Plans, Accumulated Other Comprehensive Income (Loss), Net Prior Service Cost (Credit), before Tax	1,200,000	1,400,000
DefinedBenefitPlanRegulatoryAssetIncomeNetGainsLossesBeforeTax	1,973,800,000	1,126,100,000
DefinedBenefitPlanRegulatoryAssetNetPriorServiceCostCreditBeforeTax	21,200,000	29,300,000
Pension and Other Postretirement Benefit Plans, Amounts that Will be Amortized from Accumulated Other Comprehensive Income (Loss) in Next Fiscal Year [Abstract]
Defined Benefit Plan, Amortization of Net Gains (Losses)	9,300,000
Defined Benefit Plan, Amortization of Net Prior Service Cost (Credit)	200,000
RegulatoryAssetDefinedBenefitPlanAmortizationOfNetGainsLosses	200,800,000
RegulatoryAssetDefinedBenefitPlanAmortizationOfNetPriorServiceCostCredit	3,900,000
Defined Benefit Plan, Estimated Future Benefit Payments [Abstract]
Defined Benefit Plan, Expected Future Benefit Payments, Next Twelve Months	238,000,000
Defined Benefit Plan, Expected Future Benefit Payments in Year Two	257,300,000
Defined Benefit Plan, Expected Future Benefit Payments in Year Three	252,400,000
Defined Benefit Plan, Expected Future Benefit Payments, Year Four	261,200,000
Defined Benefit Plan, Expected Future Benefit Payments in Year Five	270,600,000
Defined Benefit Plan, Expected Future Benefit Payments in Five Fiscal Years Thereafter	1,510,200,000
DescriptionOfDefinedContributionPensionAndOtherPostretirementPlans	NU’s policy is to annually fund the NUSCO and NSTAR Pension Plans in an amount at least equal to an amount that will satisfy federal requirements. NU contributed $197.4 million to the NUSCO Pension Plan in 2012, of which $87.7 million was contributed by PSNH. NSTAR Electric contributed $25 million to the NSTAR Pension Plan for the year ended December 31, 2012. Based on the current status of the NUSCO Pension Plan, NU anticipates making a contribution of approximately $203 million in 2013, of which $107 million is required to meet minimum federal funding requirements. NSTAR Electric anticipates making a contribution of approximately $82 million in 2013 to the NSTAR Pension Plan, of which $38 million is required to meet minimum federal funding requirements.
Pension Plans Defined Benefit Member | Fair Value Inputs Level 1 Member
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets Ending Balance	460,100,000	292,600,000
Level 3 Rollforwards
Fair Value of Plan Assets Ending Balance	460,100,000	292,600,000
Pension Plans Defined Benefit Member | Fair Value Inputs Level 2 [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets Ending Balance	1,508,800,000	629,800,000
Level 3 Rollforwards
Fair Value of Plan Assets Ending Balance	1,508,800,000	629,800,000
Pension Plans Defined Benefit Member | Fair Value Inputs Level 3 [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets Beginning Balance	1,102,500,000	1,033,900,000
Fair Value of Plan Assets Ending Balance	1,560,000,000	1,102,500,000
Level 3 Rollforwards
Fair Value of Plan Assets Beginning Balance	1,102,500,000	1,033,900,000
Defined Benefit Plan, Actual Return on Plan Assets Still Held	108,500,000	6,400,000
Defined Benefit Plan, Actual Return on Plan Assets Sold During Period	23,000,000	17,000,000
Defined Benefit Plan, Purchases, Sales, and Settlements	47,000,000	45,200,000
Fair Value of Plan Assets Ending Balance	1,560,000,000	1,102,500,000
Level3PlanAssetsAssumedinMerger	279,000,000
Pension Plans Defined Benefit Member | United States Equity Securities [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets Ending Balance	909,900,000	492,900,000
Level 3 Rollforwards
Fair Value of Plan Assets Ending Balance	909,900,000	492,900,000
Pension Plans Defined Benefit Member | United States Equity Securities [Member] | Fair Value Inputs Level 1 Member
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets Ending Balance	336,500,000	218,700,000
Level 3 Rollforwards
Fair Value of Plan Assets Ending Balance	336,500,000	218,700,000
Pension Plans Defined Benefit Member | United States Equity Securities [Member] | Fair Value Inputs Level 2 [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets Ending Balance	302,800,000	14,800,000
Level 3 Rollforwards
Fair Value of Plan Assets Ending Balance	302,800,000	14,800,000
Pension Plans Defined Benefit Member | United States Equity Securities [Member] | Fair Value Inputs Level 3 [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets Beginning Balance	259,400,000	266,000,000
Fair Value of Plan Assets Ending Balance	270,600,000	259,400,000
Level 3 Rollforwards
Fair Value of Plan Assets Beginning Balance	259,400,000	266,000,000
Defined Benefit Plan, Actual Return on Plan Assets Still Held	11,200,000	(6,600,000)
Fair Value of Plan Assets Ending Balance	270,600,000	259,400,000
Pension Plans Defined Benefit Member | International Equity Securities [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets Ending Balance	456,700,000	241,900,000
Level 3 Rollforwards
Fair Value of Plan Assets Ending Balance	456,700,000	241,900,000
Pension Plans Defined Benefit Member | International Equity Securities [Member] | Fair Value Inputs Level 1 Member
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets Ending Balance	42,000,000	20,000,000
Level 3 Rollforwards
Fair Value of Plan Assets Ending Balance	42,000,000	20,000,000
Pension Plans Defined Benefit Member | International Equity Securities [Member] | Fair Value Inputs Level 2 [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets Ending Balance	362,600,000	221,900,000
Level 3 Rollforwards
Fair Value of Plan Assets Ending Balance	362,600,000	221,900,000
Pension Plans Defined Benefit Member | International Equity Securities [Member] | Fair Value Inputs Level 3 [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets Ending Balance	52,100,000
Level 3 Rollforwards
Defined Benefit Plan, Actual Return on Plan Assets Still Held	10,700,000
Fair Value of Plan Assets Ending Balance	52,100,000
Level3PlanAssetsAssumedinMerger	41,400,000
Pension Plans Defined Benefit Member | Emergining Markets Equity Securities [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets Ending Balance	135,300,000	66,600,000
Level 3 Rollforwards
Fair Value of Plan Assets Ending Balance	135,300,000	66,600,000
Pension Plans Defined Benefit Member | Emergining Markets Equity Securities [Member] | Fair Value Inputs Level 2 [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets Ending Balance	135,300,000	66,600,000
Level 3 Rollforwards
Fair Value of Plan Assets Ending Balance	135,300,000	66,600,000
Pension Plans Defined Benefit Member | Private Equity Funds [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets Ending Balance	294,600,000	266,400,000
Level 3 Rollforwards
Fair Value of Plan Assets Ending Balance	294,600,000	266,400,000
Pension Plans Defined Benefit Member | Private Equity Funds [Member] | Fair Value Inputs Level 1 Member
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets Ending Balance	26,700,000	11,300,000
Level 3 Rollforwards
Fair Value of Plan Assets Ending Balance	26,700,000	11,300,000
Pension Plans Defined Benefit Member | Private Equity Funds [Member] | Fair Value Inputs Level 3 [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets Beginning Balance	255,100,000	229,500,000
Fair Value of Plan Assets Ending Balance	267,900,000	255,100,000
Level 3 Rollforwards
Fair Value of Plan Assets Beginning Balance	255,100,000	229,500,000
Defined Benefit Plan, Actual Return on Plan Assets Still Held	17,000,000	20,000,000
Defined Benefit Plan, Actual Return on Plan Assets Sold During Period	15,000,000	19,500,000
Defined Benefit Plan, Purchases, Sales, and Settlements	(19,200,000)	(13,900,000)
Fair Value of Plan Assets Ending Balance	267,900,000	255,100,000
Pension Plans Defined Benefit Member | Fixed Income Debt Securities [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets Ending Balance	999,200,000	562,700,000
Level 3 Rollforwards
Fair Value of Plan Assets Ending Balance	999,200,000	562,700,000
Pension Plans Defined Benefit Member | Fixed Income Debt Securities [Member] | Fair Value Inputs Level 1 Member
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets Ending Balance	54,900,000	17,800,000
Level 3 Rollforwards
Fair Value of Plan Assets Ending Balance	54,900,000	17,800,000
Pension Plans Defined Benefit Member | Fixed Income Debt Securities [Member] | Fair Value Inputs Level 2 [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets Ending Balance	629,200,000	268,700,000
Level 3 Rollforwards
Fair Value of Plan Assets Ending Balance	629,200,000	268,700,000
Pension Plans Defined Benefit Member | Fixed Income Debt Securities [Member] | Fair Value Inputs Level 3 [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets Beginning Balance	276,200,000	247,600,000
Fair Value of Plan Assets Ending Balance	315,100,000	276,200,000
Level 3 Rollforwards
Fair Value of Plan Assets Beginning Balance	276,200,000	247,600,000
Defined Benefit Plan, Actual Return on Plan Assets Still Held	42,100,000	(1,500,000)
Defined Benefit Plan, Actual Return on Plan Assets Sold During Period	700,000	(2,800,000)
Defined Benefit Plan, Purchases, Sales, and Settlements	(3,900,000)	32,900,000
Fair Value of Plan Assets Ending Balance	315,100,000	276,200,000
Pension Plans Defined Benefit Member | Hedge Funds [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets Ending Balance	418,900,000	240,000,000
Level 3 Rollforwards
Fair Value of Plan Assets Ending Balance	418,900,000	240,000,000
Pension Plans Defined Benefit Member | Hedge Funds [Member] | Fair Value Inputs Level 3 [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets Beginning Balance	240,000,000	247,100,000
Fair Value of Plan Assets Ending Balance	418,900,000	240,000,000
Level 3 Rollforwards
Fair Value of Plan Assets Beginning Balance	240,000,000	247,100,000
Defined Benefit Plan, Actual Return on Plan Assets Still Held	21,800,000	(7,100,000)
Defined Benefit Plan, Actual Return on Plan Assets Sold During Period	(300,000)
Defined Benefit Plan, Purchases, Sales, and Settlements	30,800,000
Fair Value of Plan Assets Ending Balance	418,900,000	240,000,000
Level3PlanAssetsAssumedinMerger	126,600,000
Pension Plans Defined Benefit Member | Real Estate [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets Ending Balance	314,300,000	154,400,000
Level 3 Rollforwards
Fair Value of Plan Assets Ending Balance	314,300,000	154,400,000
Pension Plans Defined Benefit Member | Real Estate [Member] | Fair Value Inputs Level 1 Member
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets Ending Balance	0	24,800,000
Level 3 Rollforwards
Fair Value of Plan Assets Ending Balance	0	24,800,000
Pension Plans Defined Benefit Member | Real Estate [Member] | Fair Value Inputs Level 2 [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets Ending Balance	78,900,000	57,800,000
Level 3 Rollforwards
Fair Value of Plan Assets Ending Balance	78,900,000	57,800,000
Pension Plans Defined Benefit Member | Real Estate [Member] | Fair Value Inputs Level 3 [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets Beginning Balance	71,800,000	43,700,000
Fair Value of Plan Assets Ending Balance	235,400,000	71,800,000
Level 3 Rollforwards
Fair Value of Plan Assets Beginning Balance	71,800,000	43,700,000
Defined Benefit Plan, Actual Return on Plan Assets Still Held	5,700,000	1,600,000
Defined Benefit Plan, Actual Return on Plan Assets Sold During Period	7,600,000	300,000
Defined Benefit Plan, Purchases, Sales, and Settlements	39,300,000	26,200,000
Fair Value of Plan Assets Ending Balance	235,400,000	71,800,000
Level3PlanAssetsAssumedinMerger	111,000,000
Pension Plans Defined Benefit Member | Assetsrelatedto401h [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets Ending Balance	117,600,000	19,000,000
Level 3 Rollforwards
Fair Value of Plan Assets Ending Balance	117,600,000	19,000,000
Other Postretirement Benefit Plans Defined Benefit Member
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
us-gaap_DefinedBenefitPlanBusinessCombinationsAndAcquisitionsBenefitObligation	(770,600,000)
Benefit Obligation Beginning Balance	(520,900,000)	(489,900,000)
Defined Benefit Plan Service Cost	(15,700,000)	(9,200,000)	(8,500,000)
Defined Benefit Plan Interest Cost	(49,000,000)	(25,700,000)	(26,800,000)
Defined Benefit Plan, Actuarial Net (Gains) Losses	70,900,000	(30,100,000)
Defined Benefit Plan, Benefits Paid	58,200,000	38,100,000
Defined Benefit Plan, Gross Prescription Drug Subsidy Receipts Received	(6,200,000)	(4,100,000)
Benefit Obligation Ending Balance	(1,233,300,000)	(520,900,000)	(489,900,000)
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Defined Benefit Plan Service Cost	15,700,000	9,200,000	8,500,000
Defined Benefit Plan Interest Cost	49,000,000	25,700,000	26,800,000
Defined Benefit Plan, Expected Return on Plan Assets	(39,200,000)	(21,600,000)	(21,700,000)
Defined Benefit Plan, Amortization of Gains (Losses)	36,000,000	19,000,000	16,700,000
Defined Benefit Plan Amortization Of Transition Obligations Assets	12,200,000	11,600,000	11,600,000
Defined Benefit Plan Amortization Of Prior Service Cost Credit	(1,400,000)	(300,000)	(300,000)
Defined Benefit Plan Net Periodic Benefit Cost	72,300,000	43,600,000	41,600,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, Business Combinations and Acquisitions, Plan Assets	330,400,000
Fair Value of Plan Assets Beginning Balance	285,400,000	278,500,000
Defined Benefit Plan, Actual Return on Plan Assets	78,800,000	(2,500,000)
Defined Benefit Plan, Contributions by Employer	72,700,000	47,500,000
Defined Benefit Plan, Benefits Paid	(58,200,000)	(38,100,000)
Fair Value of Plan Assets Ending Balance	709,100,000	285,400,000	278,500,000
Defined Benefit Plan, Amounts Recognized in Balance Sheet [Abstract]
Defined Benefit Plan, Funded Status of Plan	(524,200,000)	(235,500,000)
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract]
Defined Benefit Plan, Description of Direction and Pattern of Change for Assumed Health Care Cost Trend Rate	The NU consolidated amounts include the NSTAR PBOP Plan from the date of the merger, April 10, 2012, through December 31, 2012. For the NUSCO PBOP Plans, the health care cost trend assumption is 7 percent, subsequently decreasing 50 basis points per year to an ultimate rate of 5 percent in 2017. For the NSTAR PBOP Plan, the health care cost trend assumption is 7.10 percent, subsequently decreasing to an ultimate rate of 4.50 percent in 2024.
Defined Benefit Plan, Effect of One-Percentage Point Change in Assumed Health Care Cost Trend Rates [Abstract]
Defined Benefit Plan, Effect of One Percentage Point Increase on Accumulated Postretirement Benefit Obligation	126,500,000
Defined Benefit Plan, Effect of One Percentage Point Decrease on Accumulated Postretirement Benefit Obligation	(101,700,000)
Defined Benefit Plan, Effect of One Percentage Point Increase on Service and Interest Cost Components	8,900,000
Defined Benefit Plan, Effect of One Percentage Point Decrease on Service and Interest Cost Components	(6,900,000)
Level 3 Rollforwards
Fair Value of Plan Assets Beginning Balance	285,400,000	278,500,000
Fair Value of Plan Assets Ending Balance	709,100,000	285,400,000	278,500,000
Defined Benefit Plan, Amounts Recognized in Other Comprehensive Income (Loss) [Abstract]
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net Unamortized Gain (Loss) Arising During Period, before Tax	(1,800,000)	4,000,000
Other Comprehensive Income (Loss), Reclassification, Pension and Other Postretirement Benefit Plans, Net Gain (Loss) Recognized in Net Periodic Benefit Cost, before Tax	(1,100,000)	(900,000)
Other Comprehensive Income (Loss), Reclassification, Pension and Other Postretirement Benefit Plans, Net Transition Asset (Obligation), Recognized in Net Periodic Benefit Cost, before Tax	(200,000)	(200,000)
RegulatoryAssetDefinedBenefitPlansNetUnamortizedGainLossArisingDuringPeriodBeforeTax	(108,600,000)	50,200,000
RegulatoryAssetReclassificationOfDefinedBenefitPlansNetGainLossRecognizedInNetPeriodicBenefitCostBeforeTax	(34,900,000)	(18,100,000)
RegulatoryAssetAmortizationOfDefinedBenefitPlanNetPriorServiceCostCreditRecognizedInNetPeriodicBenefitCostBeforeTax	1,400,000	300,000
RegulatoryAssetReclassificationOfDefinedBenefitPlanNetTransitionAssetObligationRecognizedInNetPeriodicBenefitCostBeforeTax	11,900,000	(11,300,000)
Pension and Other Postretirement Benefit Plans, Accumulated Other Comprehensive Income (Loss), before Tax [Abstract]
ension and Other Postretirement Benefit Plans, Accumulated Other Comprehensive Income (Loss), Net Gains (Losses), before Tax	9,200,000
Pension and Other Postretirement Benefit Plans, Accumulated Other Comprehensive Income (Loss), Net Prior Service Cost (Credit), before Tax		12,100,000
Pension and Other Postretirement Benefit Plans, Accumulated Other Comprehensive Income (Loss), Net Transition Assets (Obligations), before Tax		200,000
DefinedBenefitPlanRegulatoryAssetIncomeNetGainsLossesBeforeTax	376,100,000	196,300,000
DefinedBenefitPlanRegulatoryAssetNetPriorServiceCostCreditBeforeTax	(6,700,000)	(2,400,000)
DefinedBenefitPlanRegulatoryAssetNetTransitionAssetsObligationsBeforeTax		11,400,000
Pension and Other Postretirement Benefit Plans, Amounts that Will be Amortized from Accumulated Other Comprehensive Income (Loss) in Next Fiscal Year [Abstract]
Defined Benefit Plan, Amortization of Net Gains (Losses)	1,000,000
RegulatoryAssetDefinedBenefitPlanAmortizationOfNetGainsLosses	31,400,000
RegulatoryAssetDefinedBenefitPlanAmortizationOfNetPriorServiceCostCredit	(2,100,000)
Defined Benefit Plan, Estimated Future Benefit Payments [Abstract]
Defined Benefit Plan, Expected Future Benefit Payments, Next Twelve Months	63,500,000
Defined Benefit Plan, Expected Future Benefit Payments in Year Two	65,000,000
Defined Benefit Plan, Expected Future Benefit Payments in Year Three	66,800,000
Defined Benefit Plan, Expected Future Benefit Payments, Year Four	68,200,000
Defined Benefit Plan, Expected Future Benefit Payments in Year Five	69,600,000
Defined Benefit Plan, Expected Future Benefit Payments in Five Fiscal Years Thereafter	366,300,000
DescriptionOfDefinedContributionPensionAndOtherPostretirementPlans	For the PBOP Plans, it is NU’s policy to annually fund the NUSCO PBOP Plans in an amount equal to the PBOP Plans' postretirement benefit cost, excluding curtailment and termination benefits. NU contributed $50 million to the NUSCO PBOP Plans in 2012 and expects to make $25.7 million in contributions in 2013. NU contributes an amount that approximates annual benefit payments to the NSTAR PBOP Plan. NU contributed $22.7 million to the NSTAR PBOP Plan for the period April 10, 2012 to December 31, 2012 and expects to make $30 million in contributions in 2013.
Other Postretirement Benefit Plans Defined Benefit Member | Fair Value Inputs Level 1 Member
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets Ending Balance	201,700,000	157,000,000
Level 3 Rollforwards
Fair Value of Plan Assets Ending Balance	201,700,000	157,000,000
Other Postretirement Benefit Plans Defined Benefit Member | Fair Value Inputs Level 2 [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets Ending Balance	243,800,000	49,000,000
Level 3 Rollforwards
Fair Value of Plan Assets Ending Balance	243,800,000	49,000,000
Other Postretirement Benefit Plans Defined Benefit Member | Fair Value Inputs Level 3 [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets Beginning Balance	60,400,000	50,200,000
Fair Value of Plan Assets Ending Balance	146,000,000	60,400,000
Level 3 Rollforwards
Fair Value of Plan Assets Beginning Balance	60,400,000	50,200,000
Defined Benefit Plan, Actual Return on Plan Assets Still Held	16,600,000	1,000,000
Defined Benefit Plan, Purchases, Sales, and Settlements	9,500,000	9,200,000
Fair Value of Plan Assets Ending Balance	146,000,000	60,400,000
Level3PlanAssetsAssumedinMerger	59,500,000
Other Postretirement Benefit Plans Defined Benefit Member | United States Equity Securities [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets Ending Balance	210,300,000	127,600,000
Level 3 Rollforwards
Fair Value of Plan Assets Ending Balance	210,300,000	127,600,000
Other Postretirement Benefit Plans Defined Benefit Member | United States Equity Securities [Member] | Fair Value Inputs Level 1 Member
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets Ending Balance	116,300,000	116,900,000
Level 3 Rollforwards
Fair Value of Plan Assets Ending Balance	116,300,000	116,900,000
Other Postretirement Benefit Plans Defined Benefit Member | United States Equity Securities [Member] | Fair Value Inputs Level 2 [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets Ending Balance	57,700,000
Level 3 Rollforwards
Fair Value of Plan Assets Ending Balance	57,700,000
Other Postretirement Benefit Plans Defined Benefit Member | United States Equity Securities [Member] | Fair Value Inputs Level 3 [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets Beginning Balance	10,700,000	10,100,000
Fair Value of Plan Assets Ending Balance	36,300,000	10,700,000
Level 3 Rollforwards
Fair Value of Plan Assets Beginning Balance	10,700,000	10,100,000
Defined Benefit Plan, Actual Return on Plan Assets Still Held	5,900,000	600,000
Defined Benefit Plan, Purchases, Sales, and Settlements	0	0
Fair Value of Plan Assets Ending Balance	36,300,000	10,700,000
Level3PlanAssetsAssumedinMerger	19,700,000
Other Postretirement Benefit Plans Defined Benefit Member | International Equity Securities [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets Ending Balance	97,700,000	29,600,000
Level 3 Rollforwards
Fair Value of Plan Assets Ending Balance	97,700,000	29,600,000
Other Postretirement Benefit Plans Defined Benefit Member | International Equity Securities [Member] | Fair Value Inputs Level 1 Member
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets Ending Balance	68,000,000	29,600,000
Level 3 Rollforwards
Fair Value of Plan Assets Ending Balance	68,000,000	29,600,000
Other Postretirement Benefit Plans Defined Benefit Member | International Equity Securities [Member] | Fair Value Inputs Level 2 [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets Ending Balance	29,700,000
Level 3 Rollforwards
Fair Value of Plan Assets Ending Balance	29,700,000
Other Postretirement Benefit Plans Defined Benefit Member | Emergining Markets Equity Securities [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets Ending Balance	21,700,000	4,600,000
Level 3 Rollforwards
Fair Value of Plan Assets Ending Balance	21,700,000	4,600,000
Other Postretirement Benefit Plans Defined Benefit Member | Emergining Markets Equity Securities [Member] | Fair Value Inputs Level 1 Member
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets Ending Balance	7,700,000	4,600,000
Level 3 Rollforwards
Fair Value of Plan Assets Ending Balance	7,700,000	4,600,000
Other Postretirement Benefit Plans Defined Benefit Member | Emergining Markets Equity Securities [Member] | Fair Value Inputs Level 2 [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets Ending Balance	14,000,000
Level 3 Rollforwards
Fair Value of Plan Assets Ending Balance	14,000,000
Other Postretirement Benefit Plans Defined Benefit Member | Private Equity Funds [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets Ending Balance	11,300,000	5,100,000
Level 3 Rollforwards
Fair Value of Plan Assets Ending Balance	11,300,000	5,100,000
Other Postretirement Benefit Plans Defined Benefit Member | Private Equity Funds [Member] | Fair Value Inputs Level 3 [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets Beginning Balance	5,100,000	(300,000)
Fair Value of Plan Assets Ending Balance	11,300,000	5,100,000
Level 3 Rollforwards
Fair Value of Plan Assets Beginning Balance	5,100,000	(300,000)
Defined Benefit Plan, Actual Return on Plan Assets Still Held	1,600,000	(600,000)
Defined Benefit Plan, Purchases, Sales, and Settlements	4,600,000	4,200,000
Fair Value of Plan Assets Ending Balance	11,300,000	5,100,000
Other Postretirement Benefit Plans Defined Benefit Member | Fixed Income Debt Securities [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets Ending Balance	169,800,000	70,300,000
Level 3 Rollforwards
Fair Value of Plan Assets Ending Balance	169,800,000	70,300,000
Other Postretirement Benefit Plans Defined Benefit Member | Fixed Income Debt Securities [Member] | Fair Value Inputs Level 2 [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets Ending Balance	137,700,000	44,300,000
Level 3 Rollforwards
Fair Value of Plan Assets Ending Balance	137,700,000	44,300,000
Other Postretirement Benefit Plans Defined Benefit Member | Fixed Income Debt Securities [Member] | Fair Value Inputs Level 3 [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets Beginning Balance	26,000,000	23,400,000
Fair Value of Plan Assets Ending Balance	32,100,000	26,000,000
Level 3 Rollforwards
Fair Value of Plan Assets Beginning Balance	26,000,000	23,400,000
Defined Benefit Plan, Actual Return on Plan Assets Still Held	4,000,000	200,000
Defined Benefit Plan, Purchases, Sales, and Settlements	2,100,000	2,400,000
Fair Value of Plan Assets Ending Balance	32,100,000	26,000,000
Other Postretirement Benefit Plans Defined Benefit Member | Hedge Funds [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets Ending Balance	39,600,000	16,100,000
Level 3 Rollforwards
Fair Value of Plan Assets Ending Balance	39,600,000	16,100,000
Other Postretirement Benefit Plans Defined Benefit Member | Hedge Funds [Member] | Fair Value Inputs Level 3 [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets Beginning Balance	16,100,000	16,400,000
Fair Value of Plan Assets Ending Balance	39,600,000	16,100,000
Level 3 Rollforwards
Fair Value of Plan Assets Beginning Balance	16,100,000	16,400,000
Defined Benefit Plan, Actual Return on Plan Assets Still Held	2,100,000	(300,000)
Fair Value of Plan Assets Ending Balance	39,600,000	16,100,000
Level3PlanAssetsAssumedinMerger	21,400,000
Other Postretirement Benefit Plans Defined Benefit Member | Real Estate [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets Ending Balance	31,400,000	7,200,000
Level 3 Rollforwards
Fair Value of Plan Assets Ending Balance	31,400,000	7,200,000
Other Postretirement Benefit Plans Defined Benefit Member | Real Estate [Member] | Fair Value Inputs Level 2 [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets Ending Balance	4,700,000	4,700,000
Level 3 Rollforwards
Fair Value of Plan Assets Ending Balance	4,700,000	4,700,000
Other Postretirement Benefit Plans Defined Benefit Member | Real Estate [Member] | Fair Value Inputs Level 3 [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets Beginning Balance	2,500,000
Fair Value of Plan Assets Ending Balance	26,700,000	2,500,000
Level 3 Rollforwards
Fair Value of Plan Assets Beginning Balance	2,500,000
Defined Benefit Plan, Actual Return on Plan Assets Still Held	3,000,000	(100,000)
Defined Benefit Plan, Purchases, Sales, and Settlements	2,800,000	2,600,000
Fair Value of Plan Assets Ending Balance	26,700,000	2,500,000
Level3PlanAssetsAssumedinMerger	18,400,000
Other Postretirement Benefit Plans Defined Benefit Member | Cash And Cash Equivalents Member
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets Ending Balance	9,700,000	5,900,000
Level 3 Rollforwards
Fair Value of Plan Assets Ending Balance	9,700,000	5,900,000
Other Postretirement Benefit Plans Defined Benefit Member | Cash And Cash Equivalents Member | Fair Value Inputs Level 1 Member
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets Ending Balance	9,700,000	5,900,000
Level 3 Rollforwards
Fair Value of Plan Assets Ending Balance	9,700,000	5,900,000
Other Postretirement Benefit Plans Defined Benefit Member | Assetsrelatedto401h [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets Ending Balance	117,600,000	19,000,000
Level 3 Rollforwards
Fair Value of Plan Assets Ending Balance	117,600,000	19,000,000
NUSCO Pension Plan [Member]
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract]
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate	4.24%	5.03%
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Rate of Compensation Increase	3.50%	3.50%
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate	5.03%	5.57%	5.98%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase	3.50%	3.50%	4.00%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Return on Assets	8.25%	8.25%	8.75%
Nstar pbop Plans [Member]
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract]
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate	4.35%
Health Care Trend Assumption Used In Funded Status	7.10%
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate	4.58%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Return on Assets	7.30%
Nstar pbop Plans [Member] | United States Equity Securities [Member]
Defined Benefit Plan, Assets, Target Allocations [Abstract]
Assumed Rate of Return on Defined Benefit Plan Assets	8.30%
Target Allocation	25.00%
Nstar pbop Plans [Member] | International Equity Securities [Member]
Defined Benefit Plan, Assets, Target Allocations [Abstract]
Assumed Rate of Return on Defined Benefit Plan Assets	8.60%
Target Allocation	20.00%
Nstar pbop Plans [Member] | Emergining Markets Equity Securities [Member]
Defined Benefit Plan, Assets, Target Allocations [Abstract]
Assumed Rate of Return on Defined Benefit Plan Assets	8.80%
Target Allocation	5.00%
Nstar pbop Plans [Member] | Fixed Income Debt Securities [Member]
Defined Benefit Plan, Assets, Target Allocations [Abstract]
Assumed Rate of Return on Defined Benefit Plan Assets	4.60%
Target Allocation	30.00%
Nstar pbop Plans [Member] | Hedge Funds [Member]
Defined Benefit Plan, Assets, Target Allocations [Abstract]
Assumed Rate of Return on Defined Benefit Plan Assets	8.40%
Target Allocation	10.00%
Nstar pbop Plans [Member] | Real Estate [Member]
Defined Benefit Plan, Assets, Target Allocations [Abstract]
Assumed Rate of Return on Defined Benefit Plan Assets	7.90%
Target Allocation	10.00%
NUSCO PBOP Plan [Member]
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract]
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate	4.04%	4.84%
Health Care Trend Assumption Used In Funded Status	7.00%	7.00%
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate	4.84%	5.28%	5.73%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Return on Assets	8.25%	8.25%	8.75%
NUSCOPensionandPBOP [Member] | United States Equity Securities [Member]
Defined Benefit Plan, Assets, Target Allocations [Abstract]
Assumed Rate of Return on Defined Benefit Plan Assets	9.00%
Target Allocation	24.00%
NUSCOPensionandPBOP [Member] | International Equity Securities [Member]
Defined Benefit Plan, Assets, Target Allocations [Abstract]
Assumed Rate of Return on Defined Benefit Plan Assets	9.00%
Target Allocation	13.00%
NUSCOPensionandPBOP [Member] | Emergining Markets Equity Securities [Member]
Defined Benefit Plan, Assets, Target Allocations [Abstract]
Assumed Rate of Return on Defined Benefit Plan Assets	10.00%
Target Allocation	3.00%
NUSCOPensionandPBOP [Member] | Private Equity Funds [Member]
Defined Benefit Plan, Assets, Target Allocations [Abstract]
Assumed Rate of Return on Defined Benefit Plan Assets	13.00%
Target Allocation	12.00%
NUSCOPensionandPBOP [Member] | Fixed Income Debt Securities [Member]
Defined Benefit Plan, Assets, Target Allocations [Abstract]
Assumed Rate of Return on Defined Benefit Plan Assets	5.00%
Target Allocation	20.00%
NUSCOPensionandPBOP [Member] | High Yield Fixed Income Debt Securities [Member]
Defined Benefit Plan, Assets, Target Allocations [Abstract]
Assumed Rate of Return on Defined Benefit Plan Assets	7.50%
Target Allocation	3.50%
NUSCOPensionandPBOP [Member] | Emerging Markets Debt Securities [Member]
Defined Benefit Plan, Assets, Target Allocations [Abstract]
Assumed Rate of Return on Defined Benefit Plan Assets	7.50%
Target Allocation	3.50%
NUSCOPensionandPBOP [Member] | Hedge Funds [Member]
Defined Benefit Plan, Assets, Target Allocations [Abstract]
Assumed Rate of Return on Defined Benefit Plan Assets	7.00%
Target Allocation	13.00%
NUSCOPensionandPBOP [Member] | Real Estate [Member]
Defined Benefit Plan, Assets, Target Allocations [Abstract]
Assumed Rate of Return on Defined Benefit Plan Assets	7.50%
Target Allocation	8.00%
The Connecticut Light And Power Company [Member]
Defined Benefit Plan, Amounts Recognized in Balance Sheet [Abstract]
Accrued Pension, PBOP and SERP	304,696,000	260,571,000
The Connecticut Light And Power Company [Member] | Pension Plans Defined Benefit Member
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Benefit Obligation Beginning Balance	(1,043,800,000)	(964,300,000)
Defined Benefit Plan Service Cost	(21,800,000)	(19,500,000)	(17,600,000)
Defined Benefit Plan Interest Cost	(51,200,000)	(51,900,000)	(52,200,000)
Defined Benefit Plan, Actuarial Net (Gains) Losses	(117,400,000)	(64,000,000)
Defined Benefit Plan, Benefits Paid	55,900,000	55,600,000
Defined Benefit Plan, Payments SERP	300,000	300,000
Benefit Obligation Ending Balance	(1,178,000,000)	(1,043,800,000)	(964,300,000)
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Defined Benefit Plan Service Cost	21,800,000	19,500,000	17,600,000
Defined Benefit Plan Interest Cost	51,200,000	51,900,000	52,200,000
Defined Benefit Plan, Expected Return on Plan Assets	(70,600,000)	(76,600,000)	(85,800,000)
Defined Benefit Plan, Amortization of Gains (Losses)	49,600,000	33,400,000	20,700,000
Defined Benefit Plan Amortization Of Prior Service Cost Credit	3,600,000	4,200,000	4,200,000
Defined Benefit Plan Net Periodic Benefit Cost	55,600,000	32,400,000	8,900,000
Related Intercompany Allocationsof Defined Benefit Expense	42,800,000	34,100,000	25,200,000
Amount Capitalized Pension Expense	26,800,000	16,600,000	3,800,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets Beginning Balance	869,600,000	918,400,000
Defined Benefit Plan, Actual Return on Plan Assets	123,900,000	6,800,000
Defined Benefit Plan, Contributions by Employer		0
Defined Benefit Plan, Benefits Paid	(55,900,000)	(55,600,000)
Fair Value of Plan Assets Ending Balance	937,600,000	869,600,000	918,400,000
Defined Benefit Plan, Amounts Recognized in Balance Sheet [Abstract]
Defined Benefit Plan, Funded Status of Plan	(240,400,000)	(174,200,000)
Defined Benefit Plan, Accumulated Benefit Obligation	1,061,800,000	938,400,000
Level 3 Rollforwards
Fair Value of Plan Assets Beginning Balance	869,600,000	918,400,000
Fair Value of Plan Assets Ending Balance	937,600,000	869,600,000	918,400,000
The Connecticut Light And Power Company [Member] | Other Postretirement Benefit Plans Defined Benefit Member
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Benefit Obligation Beginning Balance	(198,900,000)	(190,200,000)
Defined Benefit Plan Service Cost	(3,000,000)	(2,900,000)	(2,700,000)
Defined Benefit Plan Interest Cost	(9,200,000)	(10,000,000)	(10,500,000)
Defined Benefit Plan, Actuarial Net (Gains) Losses	1,200,000	(8,500,000)
Defined Benefit Plan, Benefits Paid	14,800,000	14,500,000
Defined Benefit Plan, Gross Prescription Drug Subsidy Receipts Received	(1,700,000)	(1,800,000)
Benefit Obligation Ending Balance	(196,800,000)	(198,900,000)	(190,200,000)
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Defined Benefit Plan Service Cost	3,000,000	2,900,000	2,700,000
Defined Benefit Plan Interest Cost	9,200,000	10,000,000	10,500,000
Defined Benefit Plan, Expected Return on Plan Assets	(9,100,000)	(8,700,000)	(8,700,000)
Defined Benefit Plan, Amortization of Gains (Losses)	7,500,000	7,200,000	6,300,000
Defined Benefit Plan Amortization Of Transition Obligations Assets	6,100,000	6,200,000	6,100,000
Defined Benefit Plan Net Periodic Benefit Cost	16,700,000	17,600,000	16,900,000
Related Intercompany Allocationsof Defined Benefit Expense	7,900,000	8,200,000	7,900,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets Beginning Balance	112,200,000	108,600,000
Defined Benefit Plan, Actual Return on Plan Assets	15,000,000	(1,200,000)
Defined Benefit Plan, Contributions by Employer	19,800,000	19,300,000
Defined Benefit Plan, Benefits Paid	(14,800,000)	(14,500,000)
Fair Value of Plan Assets Ending Balance	132,200,000	112,200,000	108,600,000
Defined Benefit Plan, Amounts Recognized in Balance Sheet [Abstract]
Defined Benefit Plan, Funded Status of Plan	(64,600,000)	(86,700,000)
Level 3 Rollforwards
Fair Value of Plan Assets Beginning Balance	112,200,000	108,600,000
Fair Value of Plan Assets Ending Balance	132,200,000	112,200,000	108,600,000
Public Service Company Of New Hampshire [Member]
Defined Benefit Plan, Amounts Recognized in Balance Sheet [Abstract]
Accrued Pension, PBOP and SERP	220,129,000	258,718,000
Public Service Company Of New Hampshire [Member] | Pension Plans Defined Benefit Member
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Benefit Obligation Beginning Balance	(497,900,000)	(448,700,000)
Defined Benefit Plan Service Cost	(11,800,000)	(10,600,000)	(10,000,000)
Defined Benefit Plan Interest Cost	(24,400,000)	(24,400,000)	(24,100,000)
Defined Benefit Plan, Actuarial Net (Gains) Losses	(61,300,000)	(33,200,000)
Defined Benefit Plan, Benefits Paid	19,700,000	18,900,000
Defined Benefit Plan, Payments SERP	0	100,000
Benefit Obligation Ending Balance	(576,000,000)	(497,900,000)	(448,700,000)
DefinedBenefitPlanSettlementsBenefitObligation	(300,000)
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Defined Benefit Plan Service Cost	11,800,000	10,600,000	10,000,000
Defined Benefit Plan Interest Cost	24,400,000	24,400,000	24,100,000
Defined Benefit Plan, Expected Return on Plan Assets	(28,200,000)	(19,800,000)	(14,700,000)
Defined Benefit Plan, Amortization of Gains (Losses)	16,200,000	10,700,000	7,200,000
Defined Benefit Plan Amortization Of Prior Service Cost Credit	1,500,000	1,800,000	1,800,000
Defined Benefit Plan Net Periodic Benefit Cost	25,700,000	27,700,000	28,400,000
Related Intercompany Allocationsof Defined Benefit Expense	10,100,000	7,600,000	6,000,000
Amount Capitalized Pension Expense	7,900,000	7,600,000	6,900,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets Beginning Balance	279,700,000	185,400,000
Defined Benefit Plan, Actual Return on Plan Assets	38,900,000	600,000
Defined Benefit Plan, Contributions by Employer	87,700,000	112,600,000
Defined Benefit Plan, Benefits Paid	(19,700,000)	(18,900,000)
Fair Value of Plan Assets Ending Balance	386,600,000	279,700,000	185,400,000
Defined Benefit Plan, Amounts Recognized in Balance Sheet [Abstract]
Defined Benefit Plan, Funded Status of Plan	(189,400,000)	(218,200,000)
Defined Benefit Plan, Accumulated Benefit Obligation	515,900,000	444,800,000
Level 3 Rollforwards
Fair Value of Plan Assets Beginning Balance	279,700,000	185,400,000
Fair Value of Plan Assets Ending Balance	386,600,000	279,700,000	185,400,000
Public Service Company Of New Hampshire [Member] | Other Postretirement Benefit Plans Defined Benefit Member
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Benefit Obligation Beginning Balance	(99,200,000)	(89,900,000)
Defined Benefit Plan Service Cost	(2,000,000)	(1,900,000)	(1,800,000)
Defined Benefit Plan Interest Cost	(4,600,000)	(4,800,000)	(5,000,000)
Defined Benefit Plan, Actuarial Net (Gains) Losses	300,000	(8,400,000)
Defined Benefit Plan, Benefits Paid	5,900,000	6,500,000
Defined Benefit Plan, Gross Prescription Drug Subsidy Receipts Received	(600,000)	(700,000)
Benefit Obligation Ending Balance	(100,200,000)	(99,200,000)	(89,900,000)
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Defined Benefit Plan Service Cost	2,000,000	1,900,000	1,800,000
Defined Benefit Plan Interest Cost	4,600,000	4,800,000	5,000,000
Defined Benefit Plan, Expected Return on Plan Assets	(4,600,000)	(4,300,000)	(4,300,000)
Defined Benefit Plan, Amortization of Gains (Losses)	3,600,000	3,200,000	2,700,000
Defined Benefit Plan Amortization Of Transition Obligations Assets	2,500,000	2,500,000	2,500,000
Defined Benefit Plan Net Periodic Benefit Cost	8,100,000	8,100,000	7,700,000
Related Intercompany Allocationsof Defined Benefit Expense	2,000,000	2,000,000	2,000,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets Beginning Balance	58,700,000	56,900,000
Defined Benefit Plan, Actual Return on Plan Assets	7,500,000	(400,000)
Defined Benefit Plan, Contributions by Employer	9,200,000	8,700,000
Defined Benefit Plan, Benefits Paid	(5,900,000)	(6,500,000)
Fair Value of Plan Assets Ending Balance	69,500,000	58,700,000	56,900,000
Defined Benefit Plan, Amounts Recognized in Balance Sheet [Abstract]
Defined Benefit Plan, Funded Status of Plan	(30,700,000)	(40,500,000)
Level 3 Rollforwards
Fair Value of Plan Assets Beginning Balance	58,700,000	56,900,000
Fair Value of Plan Assets Ending Balance	69,500,000	58,700,000	56,900,000
Western Massachusetts Electric Company [Member]
Defined Benefit Plan, Amounts Recognized in Balance Sheet [Abstract]
Accrued Pension, PBOP and SERP	36,099,000	29,546,000
Defined Benefit Plan, Accumulated Benefit Obligation	221,300,000	195,500,000
Western Massachusetts Electric Company [Member] | Pension Plans Defined Benefit Member
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Benefit Obligation Beginning Balance	(215,800,000)	(196,600,000)
Defined Benefit Plan Service Cost	(4,100,000)	(3,900,000)	(3,500,000)
Defined Benefit Plan Interest Cost	(10,500,000)	(10,700,000)	(10,700,000)
Defined Benefit Plan, Actuarial Net (Gains) Losses	(24,000,000)	(15,400,000)
Defined Benefit Plan, Benefits Paid	11,300,000	10,800,000
Defined Benefit Plan, Payments SERP	0
Benefit Obligation Ending Balance	(243,100,000)	(215,800,000)	(196,600,000)
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Defined Benefit Plan Service Cost	4,100,000	3,900,000	3,500,000
Defined Benefit Plan Interest Cost	10,500,000	10,700,000	10,700,000
Defined Benefit Plan, Expected Return on Plan Assets	(16,400,000)	(17,700,000)	(19,500,000)
Defined Benefit Plan, Amortization of Gains (Losses)	10,700,000	7,100,000	4,300,000
Defined Benefit Plan Amortization Of Prior Service Cost Credit	800,000	900,000	900,000
Defined Benefit Plan Net Periodic Benefit Cost	9,700,000	4,900,000	(100,000)
Related Intercompany Allocationsof Defined Benefit Expense	8,100,000	6,200,000	4,500,000
Amount Capitalized Pension Expense	5,100,000	2,700,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets Beginning Balance	202,000,000	209,800,000
Defined Benefit Plan, Actual Return on Plan Assets	27,800,000	3,000,000
Defined Benefit Plan, Benefits Paid	(11,300,000)	(10,800,000)
Fair Value of Plan Assets Ending Balance	218,500,000	202,000,000	209,800,000
Defined Benefit Plan, Amounts Recognized in Balance Sheet [Abstract]
Defined Benefit Plan, Funded Status of Plan	(24,600,000)	(13,800,000)
Level 3 Rollforwards
Fair Value of Plan Assets Beginning Balance	202,000,000	209,800,000
Fair Value of Plan Assets Ending Balance	218,500,000	202,000,000	209,800,000
Western Massachusetts Electric Company [Member] | Other Postretirement Benefit Plans Defined Benefit Member
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Benefit Obligation Beginning Balance	(42,900,000)	(41,700,000)
Defined Benefit Plan Service Cost	(600,000)	(600,000)	(600,000)
Defined Benefit Plan Interest Cost	(2,000,000)	(2,200,000)	(2,300,000)
Defined Benefit Plan, Actuarial Net (Gains) Losses	100,000	(1,000,000)
Defined Benefit Plan, Benefits Paid	3,200,000	3,000,000
Defined Benefit Plan, Gross Prescription Drug Subsidy Receipts Received	(300,000)	(400,000)
Benefit Obligation Ending Balance	(42,500,000)	(42,900,000)	(41,700,000)
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Defined Benefit Plan Service Cost	600,000	600,000	600,000
Defined Benefit Plan Interest Cost	2,000,000	2,200,000	2,300,000
Defined Benefit Plan, Expected Return on Plan Assets	(2,100,000)	(2,000,000)	(2,100,000)
Defined Benefit Plan, Amortization of Gains (Losses)	1,200,000	1,100,000	900,000
Defined Benefit Plan Amortization Of Transition Obligations Assets	1,300,000	0	1,300,000
Defined Benefit Plan Amortization Of Prior Service Cost Credit		1,300,000
Defined Benefit Plan Net Periodic Benefit Cost	3,000,000	3,200,000	3,000,000
Related Intercompany Allocationsof Defined Benefit Expense	1,500,000	1,500,000	1,400,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets Beginning Balance	27,100,000	26,700,000
Defined Benefit Plan, Actual Return on Plan Assets	3,500,000	(100,000)
Defined Benefit Plan, Contributions by Employer	3,600,000	3,500,000
Defined Benefit Plan, Benefits Paid	(3,200,000)	(3,000,000)
Fair Value of Plan Assets Ending Balance	31,000,000	27,100,000	26,700,000
Defined Benefit Plan, Amounts Recognized in Balance Sheet [Abstract]
Defined Benefit Plan, Funded Status of Plan	(11,500,000)	(15,800,000)
Level 3 Rollforwards
Fair Value of Plan Assets Beginning Balance	27,100,000	26,700,000
Fair Value of Plan Assets Ending Balance	31,000,000	27,100,000	26,700,000
NSTAR Electric Company [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, Contributions by Employer	25,000,000	125,000,000
Defined Benefit Plan, Amounts Recognized in Balance Sheet [Abstract]
Accrued Pension, PBOP and SERP	360,932,000	357,685,000
Defined Benefit Plan, Accumulated Benefit Obligation	1,353,100,000	1,271,300,000
Defined Benefit Plan, Amounts Recognized in Other Comprehensive Income (Loss) [Abstract]
Other Comprehensive Income (Loss), Reclassification, Pension and Other Postretirement Benefit Plans, Net Transition Asset (Obligation), Recognized in Net Periodic Benefit Cost, before Tax	62,800,000
RegulatoryAssetDefinedBenefitPlansNetUnamortizedGainLossArisingDuringPeriodBeforeTax	4,600,000
RegulatoryAssetAmortizationOfDefinedBenefitPlanNetPriorServiceCostCreditRecognizedInNetPeriodicBenefitCostBeforeTax	(600,000)
Pension and Other Postretirement Benefit Plans, Accumulated Other Comprehensive Income (Loss), before Tax [Abstract]
DefinedBenefitPlanRegulatoryAssetIncomeNetGainsLossesBeforeTax	782,300,000
DefinedBenefitPlanRegulatoryAssetNetPriorServiceCostCreditBeforeTax	600,000
Defined Benefit Plan, Estimated Future Benefit Payments [Abstract]
Pension Contribution	25,000,000	125,000,000	25,000,000
NSTAR Electric Company [Member] | Pension Plans Defined Benefit Member
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Benefit Obligation Beginning Balance	(1,346,200,000)	(1,184,600,000)
Defined Benefit Plan Service Cost	(30,300,000)	(26,000,000)	(23,600,000)
Defined Benefit Plan Interest Cost	(58,900,000)	(61,000,000)	(61,800,000)
Defined Benefit Plan, Actuarial Net (Gains) Losses	(63,600,000)	(138,000,000)
Defined Benefit Plan, Benefits Paid	69,000,000	59,600,000
Defined Benefit Plan, Payments SERP		3,800,000
Benefit Obligation Ending Balance	(1,430,000,000)	(1,346,200,000)	(1,184,600,000)
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Defined Benefit Plan Service Cost	30,300,000	26,000,000	23,600,000
Defined Benefit Plan Interest Cost	58,900,000	61,000,000	61,800,000
Defined Benefit Plan, Expected Return on Plan Assets	(65,600,000)	(71,400,000)	(62,800,000)
Defined Benefit Plan, Amortization of Gains (Losses)	63,100,000	48,600,000	50,400,000
Defined Benefit Plan Amortization Of Prior Service Cost Credit	(600,000)	(700,000)	(700,000)
Defined Benefit Plan Net Periodic Benefit Cost	86,100,000	63,500,000	72,300,000
Related Intercompany Allocationsof Defined Benefit Expense	(12,300,000)	(10,200,000)	(11,600,000)
Amount Capitalized Pension Expense	30,700,000	19,800,000	24,500,000
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets Beginning Balance	988,500,000	930,600,000
Defined Benefit Plan, Actual Return on Plan Assets	124,600,000	(3,700,000)
Defined Benefit Plan, Benefits Paid	(69,000,000)	(59,600,000)
Fair Value of Plan Assets Ending Balance	1,069,100,000	988,500,000	930,600,000
Defined Benefit Plan, Amounts Recognized in Balance Sheet [Abstract]
Defined Benefit Plan, Funded Status of Plan	(360,900,000)	(357,700,000)
Level 3 Rollforwards
Fair Value of Plan Assets Beginning Balance	988,500,000	930,600,000
Fair Value of Plan Assets Ending Balance	1,069,100,000	988,500,000	930,600,000
Defined Benefit Plan, Estimated Future Benefit Payments [Abstract]
Defined Benefit Plan, Expected Future Benefit Payments, Next Twelve Months	77,700,000
Defined Benefit Plan, Expected Future Benefit Payments in Year Two	79,600,000
Defined Benefit Plan, Expected Future Benefit Payments in Year Three	82,600,000
Defined Benefit Plan, Expected Future Benefit Payments, Year Four	83,200,000
Defined Benefit Plan, Expected Future Benefit Payments in Year Five	85,100,000
Defined Benefit Plan, Expected Future Benefit Payments in Five Fiscal Years Thereafter	462,200,000
NSTAR Electric Company [Member] | Pension Plans Defined Benefit Member | Fair Value Inputs Level 1 Member
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets Ending Balance	151,600,000	205,700,000
Level 3 Rollforwards
Fair Value of Plan Assets Ending Balance	151,600,000	205,700,000
NSTAR Electric Company [Member] | Pension Plans Defined Benefit Member | Fair Value Inputs Level 2 [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets Ending Balance	693,100,000	572,300,000
Level 3 Rollforwards
Fair Value of Plan Assets Ending Balance	693,100,000	572,300,000
NSTAR Electric Company [Member] | Pension Plans Defined Benefit Member | Fair Value Inputs Level 3 [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets Beginning Balance	279,000,000	289,800,000
Fair Value of Plan Assets Ending Balance	302,000,000	279,000,000
Level 3 Rollforwards
Fair Value of Plan Assets Beginning Balance	279,000,000	289,800,000
Defined Benefit Plan, Actual Return on Plan Assets Still Held	26,200,000
Defined Benefit Plan, Actual Return on Plan Assets Sold During Period	(300,000)	200,000
Defined Benefit Plan, Purchases, Sales, and Settlements	(2,900,000)	(11,200,000)
Fair Value of Plan Assets Ending Balance	302,000,000	279,000,000
NSTAR Electric Company [Member] | Pension Plans Defined Benefit Member | United States Equity Securities [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets Ending Balance	343,100,000	289,300,000
Level 3 Rollforwards
Fair Value of Plan Assets Ending Balance	343,100,000	289,300,000
NSTAR Electric Company [Member] | Pension Plans Defined Benefit Member | United States Equity Securities [Member] | Fair Value Inputs Level 1 Member
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets Ending Balance	96,700,000	77,000,000
Level 3 Rollforwards
Fair Value of Plan Assets Ending Balance	96,700,000	77,000,000
NSTAR Electric Company [Member] | Pension Plans Defined Benefit Member | United States Equity Securities [Member] | Fair Value Inputs Level 2 [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets Ending Balance	246,400,000	212,300,000
Level 3 Rollforwards
Fair Value of Plan Assets Ending Balance	246,400,000	212,300,000
NSTAR Electric Company [Member] | Pension Plans Defined Benefit Member | International Equity Securities [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets Ending Balance	150,400,000	128,200,000
Level 3 Rollforwards
Fair Value of Plan Assets Ending Balance	150,400,000	128,200,000
NSTAR Electric Company [Member] | Pension Plans Defined Benefit Member | International Equity Securities [Member] | Fair Value Inputs Level 1 Member
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets Ending Balance		4,000,000
Level 3 Rollforwards
Fair Value of Plan Assets Ending Balance		4,000,000
NSTAR Electric Company [Member] | Pension Plans Defined Benefit Member | International Equity Securities [Member] | Fair Value Inputs Level 2 [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets Ending Balance	98,300,000	82,800,000
Level 3 Rollforwards
Fair Value of Plan Assets Ending Balance	98,300,000	82,800,000
NSTAR Electric Company [Member] | Pension Plans Defined Benefit Member | International Equity Securities [Member] | Fair Value Inputs Level 3 [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets Beginning Balance	41,400,000	45,100,000
Fair Value of Plan Assets Ending Balance	52,100,000	41,400,000
Level 3 Rollforwards
Fair Value of Plan Assets Beginning Balance	41,400,000	45,100,000
Defined Benefit Plan, Actual Return on Plan Assets Still Held	10,700,000
Defined Benefit Plan, Actual Return on Plan Assets Sold During Period		(3,700,000)
Fair Value of Plan Assets Ending Balance	52,100,000	41,400,000
NSTAR Electric Company [Member] | Pension Plans Defined Benefit Member | Emergining Markets Equity Securities [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets Ending Balance	55,900,000	46,900,000
Level 3 Rollforwards
Fair Value of Plan Assets Ending Balance	55,900,000	46,900,000
NSTAR Electric Company [Member] | Pension Plans Defined Benefit Member | Emergining Markets Equity Securities [Member] | Fair Value Inputs Level 2 [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets Ending Balance	55,900,000	46,900,000
Level 3 Rollforwards
Fair Value of Plan Assets Ending Balance	55,900,000	46,900,000
NSTAR Electric Company [Member] | Pension Plans Defined Benefit Member | Fixed Income Debt Securities [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets Ending Balance	347,400,000	355,000,000
Level 3 Rollforwards
Fair Value of Plan Assets Ending Balance	347,400,000	355,000,000
NSTAR Electric Company [Member] | Pension Plans Defined Benefit Member | Fixed Income Debt Securities [Member] | Fair Value Inputs Level 1 Member
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets Ending Balance	54,900,000	124,700,000
Level 3 Rollforwards
Fair Value of Plan Assets Ending Balance	54,900,000	124,700,000
NSTAR Electric Company [Member] | Pension Plans Defined Benefit Member | Fixed Income Debt Securities [Member] | Fair Value Inputs Level 2 [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets Ending Balance	292,500,000	230,300,000
Level 3 Rollforwards
Fair Value of Plan Assets Ending Balance	292,500,000	230,300,000
NSTAR Electric Company [Member] | Pension Plans Defined Benefit Member | Hedge Funds [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets Ending Balance	122,700,000	126,600,000
Level 3 Rollforwards
Fair Value of Plan Assets Ending Balance	122,700,000	126,600,000
NSTAR Electric Company [Member] | Pension Plans Defined Benefit Member | Hedge Funds [Member] | Fair Value Inputs Level 3 [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets Beginning Balance	126,600,000	157,900,000
Fair Value of Plan Assets Ending Balance	122,700,000	126,600,000
Level 3 Rollforwards
Fair Value of Plan Assets Beginning Balance	126,600,000	157,900,000
Defined Benefit Plan, Actual Return on Plan Assets Still Held	5,600,000	(4,800,000)
Defined Benefit Plan, Actual Return on Plan Assets Sold During Period	(300,000)	200,000
Defined Benefit Plan, Purchases, Sales, and Settlements	(9,200,000)	(26,700,000)
Fair Value of Plan Assets Ending Balance	122,700,000	126,600,000
NSTAR Electric Company [Member] | Pension Plans Defined Benefit Member | Real Estate [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets Ending Balance	127,200,000	111,000,000
Level 3 Rollforwards
Fair Value of Plan Assets Ending Balance	127,200,000	111,000,000
NSTAR Electric Company [Member] | Pension Plans Defined Benefit Member | Real Estate [Member] | Fair Value Inputs Level 3 [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets Beginning Balance	111,000,000	86,800,000
Fair Value of Plan Assets Ending Balance	127,200,000	111,000,000
Level 3 Rollforwards
Fair Value of Plan Assets Beginning Balance	111,000,000	86,800,000
Defined Benefit Plan, Actual Return on Plan Assets Still Held	9,900,000	8,700,000
Defined Benefit Plan, Purchases, Sales, and Settlements	6,300,000	15,500,000
Fair Value of Plan Assets Ending Balance	127,200,000	111,000,000
NSTAR Electric Company [Member] | Pension Plans Defined Benefit Member | Assetsrelatedto401h [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair Value of Plan Assets Ending Balance	77,600,000	68,500,000
Level 3 Rollforwards
Fair Value of Plan Assets Ending Balance	77,600,000	68,500,000
NSTAR Electric Company [Member] | Supplemental Employee Retirement Plans, Defined Benefit [Member]
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Defined Benefit Plan Net Periodic Benefit Cost	$ 3,600,000	$ 4,400,000	$ 3,900,000
NSTAR Electric Company [Member] | NSTAR Pension Plan [Member]
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract]
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate	4.13%	4.52%
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Rate of Compensation Increase	4.00%	4.00%
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate	4.52%	5.30%	5.85%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase	4.00%	4.00%	4.00%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Return on Assets	7.30%	8.00%	8.00%
NSTAR Electric Company [Member] | NSTAR Pension Plan [Member] | United States Equity Securities [Member]
Defined Benefit Plan, Assets, Target Allocations [Abstract]
Assumed Rate of Return on Defined Benefit Plan Assets	8.30%	9.00%
Target Allocation	25.00%	22.00%
NSTAR Electric Company [Member] | NSTAR Pension Plan [Member] | International Equity Securities [Member]
Defined Benefit Plan, Assets, Target Allocations [Abstract]
Assumed Rate of Return on Defined Benefit Plan Assets	8.60%	9.00%
Target Allocation	13.00%	12.00%
NSTAR Electric Company [Member] | NSTAR Pension Plan [Member] | Emergining Markets Equity Securities [Member]
Defined Benefit Plan, Assets, Target Allocations [Abstract]
Assumed Rate of Return on Defined Benefit Plan Assets	8.80%
Target Allocation	5.00%	5.00%
NSTAR Electric Company [Member] | NSTAR Pension Plan [Member] | Fixed Income Debt Securities [Member]
Defined Benefit Plan, Assets, Target Allocations [Abstract]
Assumed Rate of Return on Defined Benefit Plan Assets	4.60%	4.40%
Target Allocation	21.00%	15.00%
NSTAR Electric Company [Member] | NSTAR Pension Plan [Member] | High Yield Fixed Income Debt Securities [Member]
Defined Benefit Plan, Assets, Target Allocations [Abstract]
Assumed Rate of Return on Defined Benefit Plan Assets	6.50%	6.20%
Target Allocation	9.00%	9.00%
NSTAR Electric Company [Member] | NSTAR Pension Plan [Member] | Emerging Markets Debt Securities [Member]
Defined Benefit Plan, Assets, Target Allocations [Abstract]
Assumed Rate of Return on Defined Benefit Plan Assets	6.40%	6.80%
Target Allocation	4.00%	3.00%
NSTAR Electric Company [Member] | NSTAR Pension Plan [Member] | Hedge Funds [Member]
Defined Benefit Plan, Assets, Target Allocations [Abstract]
Assumed Rate of Return on Defined Benefit Plan Assets	8.40%	8.60%
Target Allocation	13.00%	23.00%
NSTAR Electric Company [Member] | NSTAR Pension Plan [Member] | Real Estate [Member]
Defined Benefit Plan, Assets, Target Allocations [Abstract]
Assumed Rate of Return on Defined Benefit Plan Assets	7.90%	7.70%
Target Allocation	10.00%	11.00%

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PROPERTY, PLANT AND ACCUMULATED DEPRECIATION

12 Months Ended

Dec. 31, 2012

Notes To Consolidated Financial Statements [Abstract]

Schedule of Public Utility Property, Plant, and Equipment [Text Block]

4.PROPERTY, PLANT AND EQUIPMENT AND ACCUMULATED DEPRECIATION

Utility property, plant and equipment is recorded at original cost. Original cost includes materials, labor, construction overhead and AFUDC for regulated property. The cost of repairs and maintenance, including planned major maintenance activities, is charged to Operating Expenses as incurred.

The following tables summarize the NU, CL&P, NSTAR Electric, PSNH and WMECO investments in utility property, plant and equipment by asset category:

NU		As of December 31,
(Millions of Dollars)		2012		2011
Distribution - Electric		$	11,438.2	$	6,540.4
Distribution - Natural Gas			2,274.2		1,247.6
Transmission			5,541.1		3,541.9
Generation			1,146.6		1,096.0
Electric and Natural Gas Utility			20,400.1		12,425.9
Other (1)			429.3		305.1
Property, Plant and Equipment, Gross			20,829.4		12,731.0
Less: Accumulated Depreciation
	Electric and Natural Gas Utility		(5,065.1)		(3,035.5)
	Other		(171.5)		(120.2)
Total Accumulated Depreciation			(5,236.6)		(3,155.7)
Property, Plant and Equipment, Net			15,592.8		9,575.3
Construction Work in Progress			1,012.2		827.8
Total Property, Plant and Equipment, Net		$	16,605.0	$	10,403.1

(1)These assets represent unregulated property and are primarily comprised of building improvements at RRR and software and equipment at NUSCO as of December 31, 2012 and 2011, and telecommunications equipment at NSTAR Communications, Inc. as of December 31, 2012.

	As of December 31,
	2012								2011
			NSTAR								NSTAR
(Millions of Dollars)	CL&P		Electric		PSNH		WMECO		CL&P		Electric(1)		PSNH		WMECO
Distribution	$	4,691.3	$	4,539.9	$	1,520.1	$	724.2	$	4,419.6	$	4,334.4	$	1,451.6	$	704.3
Transmission		2,796.1		1,529.7		599.2		583.7		2,689.1		1,386.9		546.4		297.4
Generation		-		-		1,125.5		21.1		-		-		1,074.8		21.2
Property, Plant and
Equipment, Gross		7,487.4		6,069.6		3,244.8		1,329.0		7,108.7		5,721.3		3,072.8		1,022.9
Less: Accumulated Depreciation		(1,698.1)		(1,540.1)		(954.0)		(252.1)		(1,596.7)		(1,436.0)		(893.6)		(240.5)
Property, Plant and Equipment, Net		5,789.3		4,529.5		2,290.8		1,076.9		5,512.0		4,285.3		2,179.2		782.4
Construction Work in Progress		363.7		205.8		61.7		213.6		315.4		162.0		77.5		295.4
Total Property, Plant and
Equipment, Net	$	6,153.0	$	4,735.3	$	2,352.5	$	1,290.5	$	5,827.4	$	4,447.3	$	2,256.7	$	1,077.8

(1)NSTAR Electric amounts are not included in NU consolidated as of December 31, 2011.

Depreciation of utility assets is calculated on a straight-line basisusing composite rates based on the estimated remaining useful lives of the various classes of property (estimated useful life forPSNH distribution). The composite rates are subject to approval by the appropriate state regulatory agency. The composite ratesinclude a cost of removal component, which is collected from customers during the life of the property and is recognized as a regulatory liability. Depreciation rates are applied to property from the time it is placed in service.

Upon retirement from service, the cost of the utility asset is charged to the accumulated provision for depreciation. The actual incurred removal costs are applied against the related regulatory liability.

The depreciation rates for the various classes of utility property, plant and equipment aggregate to composite rates as follows:

(Percent)	2012		2011		2010
NU		2.5		2.6		2.7
CL&P		2.5		2.4		2.7
NSTAR Electric		2.8		3.0		3.0
PSNH		3.0		2.9		2.8
WMECO		3.3		2.9		2.8

The following table summarizes average useful lives of depreciable assets:
	Average Depreciable Life
(Years)	NU		CL&P		NSTAR Electric		PSNH		WMECO
Distribution		42.1		41.8		33.9		33.8		30.2
Transmission		45.3		39.8		46.3		42.1		47.5
Generation		32.7		-		-		32.8		25.0
Other		16.7		-		-		-		-

XML

Guarantees and Indemnifications (Tables)

12 Months Ended

Dec. 31, 2012

Notes To Consolidated Financial Statements [Abstract]

Schedule Of Guarantee Obligations Text Block

		Maximum
		Exposure
Subsidiary	Description	(in millions)			Expiration Dates
Various	Surety Bonds	$	32.8		January 2013 - November 2015 (1)
Various	NE Hydro Companies' Long-Term Debt	$	5.6		Unspecified
NUSCO and RRR	Lease Payments for Vehicles and Real Estate	$	20.1		2019 and 2024
NU Enterprises	Surety Bonds, Insurance Bonds and Performance Guarantees	$	67.4	(2)	(2)

XML

DERIVATIVE INSTURMENTS (Details) (USD $)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Derivative Instrument Detail Abstract
Derivative Liabilities - Current	$ (117,194,000)	$ (107,558,000)
Derivative Liabilities, Noncurrent	(882,654,000)	(959,876,000)
Derivative Assets Noncurrent	90,612,000	98,357,000
Current Derivative Assets Consolidated	11,400,000	11,000,000
Derivative Assets Subject to Credit Risk with investment grade counterparty	96,500,000
Other Derivatives Not Designated As Hedging Instruments At Fair Value Net Total Abstract
Description of Derivative Activity Volume	As of December 31, 2012 and 2011, NU had approximately 24 thousand MWh and 123 thousand MWh, respectively, of supply volumes remaining in its unregulated wholesale portfolio when expected sales are compared with supply contracts.
Effect Of Fair Value Hedges On Results Of Operations [Abstract]
Notional Amount Of Fair Value Hedge Instruments		263,000,000
Interest Realized In Earnings On Fair Value Hedge	2,500,000	10,500,000	10,900,000
Cash Flow Hedges Derivative Instruments At Fair Value Net [Abstract]
Other Comprehensive Income (Loss), Derivatives Qualifying as Hedges, before Tax	(25,100,000)
Cash Flow Hedge Gain Loss Reclassified To Interest Expense Net	(3,300,000)	(1,300,000)	(400,000)
Cash Flow Hedge Loss To Be Reclassified Within Twelve Months	(2,000,000)
Description Of Cash Flow Hedge Activity		In 2011, PSNH and WMECO settled interest rate swaps associated with $280 million and $50 million, respectively, of long-term debt issuances and as a result PSNH and WMECO recorded pre-tax reductions of $18.2 million and $6.9 million, respectively, to AOCI that are being amortized over the remaining lives of the associated debt. In addition, NU, CL&P, PSNH and WMECO continue to amortize interest rate swaps settled in prior years from AOCI into Interest Expense over the remaining life of the associated long-term debt.
Derivative Credit Risk Related Contingent Features Abstract
Derivative Net Liability Position Aggregate Fair Value	(15,300,000)	(23,500,000)
Collateral Already Posted Aggregate Fair Value		4,100,000
Additional Collateral Aggregate Fair Value	17,400,000	19,900,000
MinimumMember
FairValueInputsQuantitativeInformation[Abstract]
FairValueInputsCapacityPrices	1.4
FairValueInputsEnergyPrices	43
FairValueInputsRenewableEnergyCreditPrices	25
FairValueInputsForwardReserve	0.35
FairValueInputsExitPricePremium	0.1
MaximumMember
FairValueInputsQuantitativeInformation[Abstract]
FairValueInputsCapacityPrices	10.53
FairValueInputsEnergyPrices	90
FairValueInputsRenewableEnergyCreditPrices	85
FairValueInputsForwardReserve	0.9
FairValueInputsExitPricePremium	0.32
The Connecticut Light And Power Company [Member]
Derivative Instrument Detail Abstract
Derivative Liabilities - Current	(96,931,000)	(95,881,000)
Derivative Liabilities, Noncurrent	(865,571,000)	(935,849,000)
Derivative Assets Noncurrent	90,612,000	93,755,000
Derivative Assets Subject to Credit Risk with investment grade counterparty	96,300,000
Cash Flow Hedges Derivative Instruments At Fair Value Net [Abstract]
Other Comprehensive Income (Loss), Derivatives Qualifying as Hedges, before Tax	0
Cash Flow Hedge Gain Loss Reclassified To Interest Expense Net	(700,000)	(700,000)	(700,000)
Cash Flow Hedge Loss To Be Reclassified Within Twelve Months	(400,000)
The Connecticut Light And Power Company [Member] | MinimumMember
FairValueInputsQuantitativeInformation[Abstract]
FairValueInputsCapacityPrices	1.4
FairValueInputsEnergyPrices	50
FairValueInputsForwardReserve	0.35
The Connecticut Light And Power Company [Member] | MaximumMember
FairValueInputsQuantitativeInformation[Abstract]
FairValueInputsCapacityPrices	9.83
FairValueInputsEnergyPrices	55
FairValueInputsForwardReserve	0.9
Public Service Company Of New Hampshire [Member]
Cash Flow Hedges Derivative Instruments At Fair Value Net [Abstract]
Other Comprehensive Income (Loss), Derivatives Qualifying as Hedges, before Tax	(18,200,000)
Cash Flow Hedge Gain Loss Reclassified To Interest Expense Net	(2,000,000)	(800,000)	(200,000)
Cash Flow Hedge Loss To Be Reclassified Within Twelve Months	(1,200,000)
Western Massachusetts Electric Company [Member]
Other Derivatives Not Designated As Hedging Instruments At Fair Value Net Total Abstract
Description of Derivative Activity Volume	WMECO has a renewable energy contract to purchase 0.1 million MWh of energy per year through 2028 with a facility that is expected to achieve commercial operation by November 2013.
Cash Flow Hedges Derivative Instruments At Fair Value Net [Abstract]
Other Comprehensive Income (Loss), Derivatives Qualifying as Hedges, before Tax	(6,900,000)
Cash Flow Hedge Gain Loss Reclassified To Interest Expense Net	(500,000)	(100,000)	100,000
Cash Flow Hedge Loss To Be Reclassified Within Twelve Months	(300,000)
Western Massachusetts Electric Company [Member] | MinimumMember
FairValueInputsQuantitativeInformation[Abstract]
FairValueInputsCapacityPrices	1.4
FairValueInputsEnergyPrices	43
FairValueInputsRenewableEnergyCreditPrices	25
Western Massachusetts Electric Company [Member] | MaximumMember
FairValueInputsQuantitativeInformation[Abstract]
FairValueInputsCapacityPrices	10.53
FairValueInputsEnergyPrices	90
FairValueInputsRenewableEnergyCreditPrices	85
NSTAR Electric Company [Member]
Other Derivatives Not Designated As Hedging Instruments At Fair Value Net Total Abstract
Description of Derivative Activity Volume	NSTAR Electric has a renewable energy contract to purchase 0.1 million MWh of energy per year through 2018. NSTAR Electric also has a capacity related contract for up to 35 MW that extends through 2019.
NSTAR Electric Company [Member] | MinimumMember
FairValueInputsQuantitativeInformation[Abstract]
FairValueInputsCapacityPrices	1.4
FairValueInputsRenewableEnergyCreditPrices	25
NSTAR Electric Company [Member] | MaximumMember
FairValueInputsQuantitativeInformation[Abstract]
FairValueInputsCapacityPrices	3.39
FairValueInputsRenewableEnergyCreditPrices	71
Fair Value Inputs Level 2 [Member] | Subsidiaries [Member]
Derivative Instrument Detail Abstract
Derivative Assets - Current	200,000
Derivative Liabilities - Current	(19,300,000)
Derivative Liabilities, Noncurrent	(200,000)
Fair Value Inputs Level 3 [Member] | The Connecticut Light And Power Company [Member]
Derivative Instrument Detail Abstract
Derivative Assets - Current	5,700,000	6,300,000
Derivative Liabilities - Current	(96,900,000)	(95,900,000)
Derivative Liabilities, Noncurrent	(865,600,000)	(935,800,000)
Derivative Assets Noncurrent	90,600,000	93,800,000
Fair Value Inputs Level 3 [Member] | Western Massachusetts Electric Company [Member]
Derivative Instrument Detail Abstract
Derivative Liabilities - Current		(100,000)
Derivative Liabilities, Noncurrent	(3,000,000)	(7,200,000)
Fair Value Inputs Level 3 [Member] | Subsidiaries [Member]
Derivative Instrument Detail Abstract
Derivative Assets - Current	5,500,000	4,700,000
Derivative Liabilities - Current		(11,600,000)
Derivative Liabilities, Noncurrent		(16,900,000)
Derivative Assets Noncurrent		4,600,000
Fair Value Inputs Level 3 [Member] | NSTAR Electric Company [Member]
Derivative Instrument Detail Abstract
Derivative Liabilities - Current	(1,000,000)
Derivative Liabilities, Noncurrent	(13,900,000)
Netting And Collateral [Member]
Derivative Instrument Detail Abstract
Derivative Assets - Current	(12,000,000)	(11,600,000)
Derivative Liabilities - Current	600,000	4,500,000
Derivative Liabilities, Noncurrent	0	400,000
Derivative Assets Noncurrent	(69,100,000)	(80,400,000)
Netting And Collateral [Member] | Fair Value Inputs Level 2 [Member] | Subsidiaries [Member]
Derivative Instrument Detail Abstract
Derivative Liabilities - Current	600,000
Netting And Collateral [Member] | Fair Value Inputs Level 3 [Member] | The Connecticut Light And Power Company [Member]
Derivative Instrument Detail Abstract
Derivative Assets - Current	(12,000,000)	(11,600,000)
Derivative Liabilities, Noncurrent	0
Derivative Assets Noncurrent	(69,100,000)	(80,400,000)
Netting And Collateral [Member] | Fair Value Inputs Level 3 [Member] | Subsidiaries [Member]
Derivative Instrument Detail Abstract
Derivative Assets - Current	0
Derivative Liabilities - Current		4,500,000
Derivative Liabilities, Noncurrent		400,000
Designated As Hedging Instrument [Member] | Fair Value Inputs Level 2 [Member]
Derivative Instrument Detail Abstract
Derivative Assets - Current		2,300,000
Commodity [Member]
Derivative Instrument Detail Abstract
Derivative Assets - Current	23,400,000	22,600,000
Derivative Liabilities - Current	(117,800,000)	(112,100,000)
Derivative Liabilities, Noncurrent	(882,700,000)	(960,300,000)
Derivative Assets Noncurrent	159,700,000	178,800,000
Derivative Instruments Not Designated As Hedging Instruments Gain Loss Net Abstract
Derivative Instruments Gain Loss Recognized In Income Net	(700,000)	500,000	2,700,000
Derivative Instruments Gain Loss Recognized In Regulatory Asset Liability	(29,000,000)	(162,000,000)	(95,700,000)
Commodity [Member] | The Connecticut Light And Power Company [Member]
Other Derivatives Not Designated As Hedging Instruments At Fair Value Net Total Abstract
Description of Derivative Activity Volume	Commodity Supply and Price Risk Management: As required by regulation, CL&P has capacity-related contracts with generation facilities. These contracts and similar UI contracts have an expected capacity of 787 MW. CL&P has a sharing agreement with UI, with 80 percent of each contract allocated to CL&P and 20 percent allocated to UI. The capacity contracts extend through 2026 and obligate the utilities to make or receive payments on a monthly basis to or from the generation facilities based on the difference between a set capacity price and the forward capacity market price received in the ISO-NE capacity markets. In addition, CL&P has a contract to purchase 0.1 million MWh of energy per year through 2020.
Commodity [Member] | Fair Value Inputs Level 2 [Member] | Subsidiaries [Member]
Derivative Instrument Detail Abstract
Derivative Assets - Current	200,000
Derivative Liabilities - Current	(19,900,000)
Derivative Liabilities, Noncurrent	(200,000)
Commodity [Member] | Fair Value Inputs Level 3 [Member] | The Connecticut Light And Power Company [Member]
Derivative Instrument Detail Abstract
Derivative Assets - Current	17,700,000	17,900,000
Derivative Liabilities - Current	(96,900,000)	(95,900,000)
Derivative Liabilities, Noncurrent	(865,600,000)	(935,800,000)
Derivative Assets Noncurrent	159,700,000	174,200,000
Commodity [Member] | Fair Value Inputs Level 3 [Member] | Western Massachusetts Electric Company [Member]
Derivative Instrument Detail Abstract
Derivative Liabilities - Current		(100,000)
Derivative Liabilities, Noncurrent	(3,000,000)	(7,200,000)
Commodity [Member] | Fair Value Inputs Level 3 [Member] | Subsidiaries [Member]
Derivative Instrument Detail Abstract
Derivative Assets - Current	5,500,000	4,700,000
Derivative Liabilities - Current		(16,100,000)
Derivative Liabilities, Noncurrent		(17,300,000)
Derivative Assets Noncurrent		4,600,000
Commodity [Member] | Fair Value Inputs Level 3 [Member] | NSTAR Electric Company [Member]
Derivative Instrument Detail Abstract
Derivative Liabilities - Current	(1,000,000)
Derivative Liabilities, Noncurrent	$ (13,900,000)	$ (3,400,000)

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SUBSEQUENT EVENTS (Details)	12 Months Ended
	Dec. 31, 2012
Notes To Consolidated Financial Statements [Abstract]
Subsequent Event, Description	See Note 9, "Long-Term Debt" to the consolidated financial statements for information regarding the January 2013 long-term debt issuance for CL&P. See Note 12C, "Commitments and Contingencies – Deferred Contractual Obligations" to the consolidated financial statements for information regarding the receipt of the DOE proceeds by the Yankee Companies in January 2013. See Note 11, "Income Taxes," for discussion of the federal legislation enacted on January 2, 2013. On February 8, 2013, a blizzard caused damage to the electric delivery systems of CL&P and NSTAR Electric. Management believes that this storm will cost between $100 million to $120 million, with approximately 90 percent of those costs relating to NSTAR Electric. Management expects the costs to meet the criteria for specific cost recovery in Connecticut and Massachusetts and, as a result, does not expect the storm to have a material impact on the results of operations of CL&P or NSTAR Electric. Each operating company will seek recovery of these anticipated deferred storm costs through its applicable regulatory recovery process.

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Provision for Uncollectible Accounts (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Accounts Notes And Loans Receivable [Line Items]
Allowance For Doubtful Accounts Receivable Current	$ 165.5	$ 115.7
The Connecticut Light And Power Company [Member]
Accounts Notes And Loans Receivable [Line Items]
Allowance For Doubtful Accounts Receivable Current	77.6	83.5
Uncollectible Hardship Accounts Receivable Reserve	65.2	68.6
Public Service Company Of New Hampshire [Member]
Accounts Notes And Loans Receivable [Line Items]
Allowance For Doubtful Accounts Receivable Current	6.8	7.2
Western Massachusetts Electric Company [Member]
Accounts Notes And Loans Receivable [Line Items]
Allowance For Doubtful Accounts Receivable Current	8.5	10.0
Uncollectible Hardship Accounts Receivable Reserve	4.7	5.4
Yankee Gas Services Company [Member]
Accounts Notes And Loans Receivable [Line Items]
Uncollectible Hardship Accounts Receivable Reserve	6.4	6.8
NSTAR Electric Company [Member]
Accounts Notes And Loans Receivable [Line Items]
Allowance For Doubtful Accounts Receivable Current	$ 44.1	$ 27.1

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COMMON SHARES

12 Months Ended

Dec. 31, 2012

Notes To Consolidated Financial Statements [Abstract]

Schedule of Stock by Class [Text Block]

17.       COMMON SHARES

The following table sets forth the NU common shares and the shares of CL&P, NSTAR Electric, PSNH and WMECO common stock authorized and issued as of December 31, 2012 and 2011and the respective par values:

	Shares
	Authorized					Issued
	Per Share		As of December 31,			As of December 31,
	Par Value		2012	2011		2012		2011
NU	$	5	380,000,000		380,000,000		332,509,383		196,052,770
CL&P	$	10	24,500,000		24,500,000		6,035,205		6,035,205
NSTAR Electric	$	1	100,000,000		100,000,000		100		100
PSNH	$	1	100,000,000		100,000,000		301		301
WMECO	$	25	1,072,471		1,072,471		434,653		434,653

As a result of the merger with NSTAR on April 10, 2012, NU issued approximately 136 million common shares to the NSTAR shareholders.

As of December 31, 2012 and 2011,18,455,749and 18,894,078 NU common shares were held as treasury shares, respectively.

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Allowance for Funds Used During Construction (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Allowance For Funds Used During Construction [Line Items]
Public Utilities Allowance For Funds Used During Construction Capitalized Interest	$ 5.3	$ 11.8	$ 10.2
Public Utilities Allowance For Funds Used During Construction Additions	6.8	22.5	16.7
Public Utilities Allowance For Funds Used During Construction Capitalized Total	12.1	34.3	26.9
Public Utilities Allowance For Funds Used During Construction Rate	3.70%	7.30%	7.10%
The Connecticut Light And Power Company [Member]
Allowance For Funds Used During Construction [Line Items]
Public Utilities Allowance For Funds Used During Construction Capitalized Interest	2.5	3.3	2.7
Public Utilities Allowance For Funds Used During Construction Additions	1.9	6.0	4.9
Public Utilities Allowance For Funds Used During Construction Capitalized Total	4.4	9.3	7.6
Public Utilities Allowance For Funds Used During Construction Rate	3.60%	8.30%	8.30%
Public Service Company Of New Hampshire [Member]
Allowance For Funds Used During Construction [Line Items]
Public Utilities Allowance For Funds Used During Construction Capitalized Interest	1.6	7.1	6.6
Public Utilities Allowance For Funds Used During Construction Additions	1.9	13.2	10.4
Public Utilities Allowance For Funds Used During Construction Capitalized Total	3.5	20.3	17.0
Public Utilities Allowance For Funds Used During Construction Rate	5.90%	7.10%	6.80%
Western Massachusetts Electric Company [Member]
Allowance For Funds Used During Construction [Line Items]
Public Utilities Allowance For Funds Used During Construction Capitalized Interest	0.5	0.5	0.3
Public Utilities Allowance For Funds Used During Construction Additions	1.0	1.0	0.6
Public Utilities Allowance For Funds Used During Construction Capitalized Total	1.5	1.5	0.9
Public Utilities Allowance For Funds Used During Construction Rate	6.80%	7.40%	6.40%
NSTAR Electric Company [Member]
Allowance For Funds Used During Construction [Line Items]
Public Utilities Allowance For Funds Used During Construction Capitalized Interest	0.3	0.2	0.1
Public Utilities Allowance For Funds Used During Construction Capitalized Total	$ 0.3	$ 0.2	$ 0.1
Public Utilities Allowance For Funds Used During Construction Rate	0.40%	0.30%	0.30%

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Equity Method Investments (Tables)

12 Months Ended

Dec. 31, 2012

Notes To Consolidated Financial Statements [Abstract]

Schedule of Equity Method Investments [Table Text Block]

(Percent)	CYAPC	YAEC	MYAPC
CL&P	34.5	24.5	12.0
NSTAR Electric	14.0	14.0	4.0
PSNH	5.0	7.0	5.0
WMECO	9.5	7.0	3.0

	As of December 31,
(Millions of Dollars)	2012		2011 (1)
CL&P	$	1.4	$	1.4
NSTAR Electric		0.6		0.6
PSNH		0.3		0.3
WMECO		0.4		0.4

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OTHER RETIREMENT BENEFITS

12 Months Ended

Dec. 31, 2012

Notes To Consolidated Financial Statements [Abstract]

Compensation Related Costs, General [Text Block]

E.       Other Retirement Benefits

NU provides benefits for retirement and other benefits for certain current and past company officers of NU, including CL&P, PSNH and WMECO. These benefits are accounted for on an accrual basis and expensed over the service lives of the employees. The actuarially-determined liability for these benefits, which is included in Other Long-Term Liabilities on the accompanying consolidated balance sheets, as well as the related expense, were as follows:

NU	For the Years Ended December 31,
(Millions of Dollars)	2012		2011		2010
Actuarially-Determined Liability	$	54.6	$	52.8	$	49.9
Other Retirement Benefits Expense		4.7		4.7		4.2

	For the Years Ended December 31,
	2012						2011						2010
(Millions of Dollars)	CL&P		PSNH		WMECO		CL&P		PSNH		WMECO		CL&P		PSNH		WMECO
Actuarially-Determined Liability	$	0.4	$	2.5	$	0.2	$	1.2	$	2.5	$	0.2	$	0.4	$	2.4	$	0.2
Other Retirement Benefits Expense		2.6		1.0		0.5		2.6		1.0		0.5		2.3		0.9		0.4

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COMMON SHARES (Details) (USD $)	0 Months Ended
	Apr. 09, 2012	Dec. 31, 2012	Dec. 31, 2011
Class Of Stock [Line Items]
Common Stock Par Or Stated Value Per Share		$ 5
Common Stock Shares Authorized		380,000,000	380,000,000
Common Stock Shares Issued		332,509,383	196,052,770
Treasury Stock Shares		18,455,749	18,894,078
Common Stock Issuance Merger With Nstar [Abstract]
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares	136,049,000
The Connecticut Light And Power Company [Member]
Class Of Stock [Line Items]
Common Stock Par Or Stated Value Per Share		$ 10
Common Stock Shares Authorized		24,500,000	24,500,000
Common Stock Shares Issued		6,035,205	6,035,205
NSTAR Electric Company [Member]
Class Of Stock [Line Items]
Common Stock Par Or Stated Value Per Share		$ 1
Common Stock Shares Authorized		100,000,000	100,000,000
Common Stock Shares Issued		100	100
Public Service Company Of New Hampshire [Member]
Class Of Stock [Line Items]
Common Stock Par Or Stated Value Per Share		$ 1
Common Stock Shares Authorized		100,000,000	100,000,000
Common Stock Shares Issued		301	301
Western Massachusetts Electric Company [Member]
Class Of Stock [Line Items]
Common Stock Par Or Stated Value Per Share		$ 25
Common Stock Shares Authorized		1,072,471	1,072,471
Common Stock Shares Issued		434,653	434,653