10-Q

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

FORM 10-Q

T	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE      SECURITIES EXCHANGE ACT OF 1934
	For the Quarterly Period Ended September 30, 2014
	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) 300 Cadwell Drive Springfield, Massachusetts 01104 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)
300 Cadwell Drive
Springfield, Massachusetts 01104
Telephone:  (413) 785-5871 04-1961130

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
T	£

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 registrants were required to submit and post such files).

Yes	No
T	£

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	T	£	£
The Connecticut Light and Power Company	£	£	T
NSTAR Electric Company	£	£	T
Public Service Company of New Hampshire	£	£	T
Western Massachusetts Electric Company	£	£	T

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

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

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 October 31, 2014
Northeast Utilities Common shares, $5.00 par value	316,799,371 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

Northeast Utilities 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.

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

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 Yankee Energy System, Inc.
HWP	HWP Company, formerly the Holyoke Water Power Company
MYAPC	Maine Yankee Atomic Power Company
NGS	Northeast Generation Services Company
NPT	Northern Pass Transmission LLC
NSTAR	Parent Company of NSTAR Electric, NSTAR Gas and other subsidiaries (prior to the merger with NU)
NSTAR Electric	NSTAR Electric Company
NSTAR Electric & Gas	NSTAR Electric & Gas Corporation, a former Northeast Utilities service company (effective January 1, 2014 merged into NUSCO)
NSTAR Gas	NSTAR Gas Company
NU Enterprises	NU Enterprises, Inc., the parent company of NGS, Select Energy, Select Energy Contracting, Inc., E.S. Boulos Company and NSTAR Communications, Inc.
NU or the Company	Northeast Utilities and subsidiaries
NU parent and other companies	NU parent and other companies is comprised of NU parent, NUSCO and other subsidiaries, which primarily include NU Enterprises, 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 (effective January 1, 2014 includes the operations of NSTAR Electric & Gas)
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:
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
FERC ALJ	FERC Administrative Law Judge
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
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 oxides
NU 2013 Form 10-K	The Northeast Utilities and Subsidiaries 2013 combined 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 Plans and non-qualified defined benefit retirement plans
Settlement Agreements	The comprehensive settlement agreements reached by NU and NSTAR with the Massachusetts Attorney General and the DOER on February 15, 2012 related to the merger of NU and NSTAR (Massachusetts settlement agreements) and the comprehensive settlement agreement reached by NU and NSTAR with both the Connecticut Attorney General and the Connecticut Office of Consumer Counsel on March 13, 2012 related to the merger of NU and NSTAR (Connecticut settlement agreement).
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
NSTAR ELECTRIC COMPANY AND SUBSIDIARY
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARY
WESTERN MASSACHUSETTS ELECTRIC COMPANY

TABLE OF CONTENTS

	Page
PART I - FINANCIAL INFORMATION
ITEM 1 - Unaudited Condensed Consolidated Financial Statements for the Following Companies:
Northeast Utilities and Subsidiaries (Unaudited)
Condensed Consolidated Balance Sheets	1
Condensed Consolidated Statements of Income	3
Condensed Consolidated Statements of Comprehensive Income	3
Condensed Consolidated Statements of Cash Flows	4
The Connecticut Light and Power Company (Unaudited)
Condensed Balance Sheets	5
Condensed Statements of Income	7
Condensed Statements of Comprehensive Income	7
Condensed Statements of Cash Flows	8
NSTAR Electric Company and Subsidiary (Unaudited)
Condensed Consolidated Balance Sheets	9
Condensed Consolidated Statements of Income	11
Condensed Consolidated Statements of Cash Flows	12
Public Service Company of New Hampshire and Subsidiary (Unaudited)
Condensed Consolidated Balance Sheets	13
Condensed Consolidated Statements of Income	15
Condensed Consolidated Statements of Comprehensive Income	15
Condensed Consolidated Statements of Cash Flows	16
Western Massachusetts Electric Company (Unaudited)
Condensed Balance Sheets	17
Condensed Statements of Income	19
Condensed Statements of Comprehensive Income	19
Condensed Statements of Cash Flows	20
Combined Notes to Condensed Consolidated Financial Statements (Unaudited)	21

ITEM 2 – Management's Discussion and Analysis of Financial Condition and Results of Operations for the Following Companies:
Northeast Utilities and Subsidiaries	40
The Connecticut Light and Power Company	54
NSTAR Electric Company and Subsidiary	57
Public Service Company of New Hampshire and Subsidiary	59
Western Massachusetts Electric Company	61
ITEM 3 – Quantitative and Qualitative Disclosures About Market Risk	63
ITEM 4 – Controls and Procedures	63
PART II – OTHER INFORMATION
ITEM 1 – Legal Proceedings	64
ITEM 1A – Risk Factors	64
ITEM 2 – Unregistered Sales of Equity Securities and Use of Proceeds	64
ITEM 6 – Exhibits	65
SIGNATURES	67

iii

NORTHEAST UTILITIES AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
		September 30,		December 31,
(Thousands of Dollars)		2014		2013
ASSETS
Current Assets:
	Cash and Cash Equivalents	$	41,706	$	43,364
	Receivables, Net		848,510		765,391
	Unbilled Revenues		181,284		224,982
	Fuel, Materials and Supplies		333,869		303,233
	Regulatory Assets		445,962		535,791
	Marketable Securities		114,722		92,427
	Prepayments and Other Current Assets		135,497		121,861
Total Current Assets			2,101,550		2,087,049
Property, Plant and Equipment, Net			18,254,610		17,576,186
Deferred Debits and Other Assets:
	Regulatory Assets		3,241,122		3,758,694
	Goodwill		3,519,401		3,519,401
	Marketable Securities		518,032		488,515
	Other Long-Term Assets		347,596		365,692
Total Deferred Debits and Other Assets			7,626,151		8,132,302
Total Assets		$	27,982,311	$	27,795,537
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

1

NORTHEAST UTILITIES AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
			September 30,		December 31,
(Thousands of Dollars)			2014		2013
LIABILITIES AND CAPITALIZATION
Current Liabilities:
	Notes Payable		$	1,046,961	$	1,093,000
	Long-Term Debt - Current Portion			245,583		533,346
	Accounts Payable			608,639		742,251
	Regulatory Liabilities			398,985		204,278
	Other Current Liabilities			629,508		702,776
Total Current Liabilities				2,929,676		3,275,651
Deferred Credits and Other Liabilities:
	Accumulated Deferred Income Taxes			4,257,996		4,029,026
	Regulatory Liabilities			509,889		502,984
	Derivative Liabilities			420,931		624,050
	Accrued Pension, SERP and PBOP			787,550		896,844
	Other Long-Term Liabilities			863,164		923,053
Total Deferred Credits and Other Liabilities				6,839,530		6,975,957
Capitalization:
	Long-Term Debt			8,166,985		7,776,833
	Noncontrolling Interest - Preferred Stock of Subsidiaries			155,568		155,568
	Equity:
	Common Shareholders' Equity:
		Common Shares		1,666,767		1,665,351
		Capital Surplus, Paid In		6,219,516		6,192,765
		Retained Earnings		2,351,421		2,125,980
		Accumulated Other Comprehensive Loss		(40,172)		(46,031)
		Treasury Stock		(306,980)		(326,537)
	Common Shareholders' Equity			9,890,552		9,611,528
Total Capitalization				18,213,105		17,543,929
Total Liabilities and Capitalization			$	27,982,311	$	27,795,537
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

2

NORTHEAST UTILITIES AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
				For the Three Months Ended September 30,				For the Nine Months Ended September 30,
(Thousands of Dollars, Except Share Information)				2014		2013		2014		2013
Operating Revenues				$	1,892,532	$	1,892,590	$	5,860,736	$	5,523,475
Operating Expenses:
	Purchased Power, Fuel and Transmission				716,631		645,881		2,318,993		1,881,992
	Operations and Maintenance				344,092		386,700		1,069,015		1,089,960
	Depreciation				153,210		149,105		456,224		463,635
	Amortization of Regulatory Assets/(Liabilities), Net				(22,531)		70,046		31,826		178,668
	Amortization of Rate Reduction Bonds				-		-		-		42,581
	Energy Efficiency Programs				118,693		106,097		360,228		306,010
	Taxes Other Than Income Taxes				141,527		135,499		421,862		391,846
			Total Operating Expenses		1,451,622		1,493,328		4,658,148		4,354,692
Operating Income					440,910		399,262		1,202,588		1,168,783
Interest Expense:
	Interest on Long-Term Debt				85,208		84,911		260,076		256,205
	Other Interest				4,530		2,565		12,132		(5,622)
		Interest Expense			89,738		87,476		272,208		250,583
Other Income, Net					11,860		8,945		19,054		21,655
Income Before Income Tax Expense					363,032		320,731		949,434		939,855
Income Tax Expense					126,539		109,351		345,858		325,442
Net Income					236,493		211,380		603,576		614,413
Net Income Attributable to Noncontrolling Interests					1,879		1,879		5,639		5,803
Net Income Attributable to Controlling Interest				$	234,614	$	209,501	$	597,937	$	608,610
Basic and Diluted Earnings Per Common Share				$	0.74	$	0.66	$	1.89	$	1.93
Dividends Declared Per Common Share				$	0.39	$	0.37	$	1.18	$	1.10
Weighted Average Common Shares Outstanding:
	Basic				316,340,691		315,291,346		315,941,904		315,191,752
	Diluted				317,554,925		316,218,239		317,186,490		316,061,131
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Unaudited)
Net Income				$	236,493	$	211,380	$	603,576	$	614,413
Other Comprehensive Income, Net of Tax:
	Qualified Cash Flow Hedging Instruments				509		509		1,528		1,539
	Changes in Unrealized Gains/(Losses) on Other    Securities				(216)		(38)		242		(810)
	Changes in Funded Status of Pension, SERP and    PBOP Benefit Plans				1,042		1,611		4,089		4,738
Other Comprehensive Income, Net of Tax					1,335		2,082		5,859		5,467
Comprehensive Income Attributable to    Noncontrolling Interests					(1,879)		(1,879)		(5,639)		(5,803)
Comprehensive Income Attributable to Controlling    Interest				$	235,949	$	211,583	$	603,796	$	614,077
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

3

NORTHEAST UTILITIES AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
			For the Nine Months Ended September 30,
(Thousands of Dollars)			2014		2013
Operating Activities:
	Net Income		$	603,576	$	614,413
	Adjustments to Reconcile Net Income to Net Cash Flows Provided by Operating Activities:
		Depreciation		456,224		463,635
		Deferred Income Taxes		64,755		334,225
		Pension, SERP and PBOP Expense		74,296		146,803
		Pension and PBOP Contributions		(74,681)		(338,301)
		Regulatory Overrecoveries, Net		290,111		66,239
		Amortization of Regulatory Assets, Net		31,826		178,668
		Amortization of Rate Reduction Bonds		-		42,581
		Proceeds from DOE Damages Claim, Net		132,138		-
		Other		(17,096)		3,158
	Changes in Current Assets and Liabilities:
		Receivables and Unbilled Revenues, Net		(66,463)		(98,432)
		Fuel, Materials and Supplies		(27,147)		(13,134)
		Taxes Receivable/Accrued, Net		26,533		(28,609)
		Accounts Payable		(69,448)		(112,512)
		Other Current Assets and Liabilities, Net		(20,607)		(81,766)
Net Cash Flows Provided by Operating Activities				1,404,017		1,176,968
Investing Activities:
	Investments in Property, Plant and Equipment			(1,117,493)		(1,073,759)
	Proceeds from Sales of Marketable Securities			388,352		487,729
	Purchases of Marketable Securities			(389,406)		(541,070)
	Decrease in Special Deposits			-		69,259
	Other Investing Activities			(4,669)		(1,137)
Net Cash Flows Used in Investing Activities				(1,123,216)		(1,058,978)
Financing Activities:
	Cash Dividends on Common Shares			(356,080)		(341,720)
	Cash Dividends on Preferred Stock			(5,639)		(5,802)
	Increase/(Decrease) in Notes Payable			6,000		(172,000)
	Issuance of Long-Term Debt			650,000		1,350,000
	Retirements of Long-Term Debt			(576,650)		(840,600)
	Retirements of Rate Reduction Bonds			-		(82,139)
	Other Financing Activities			(90)		(13,536)
Net Cash Flows Used in Financing Activities				(282,459)		(105,797)
Net (Decrease)/Increase in Cash and Cash Equivalents				(1,658)		12,193
Cash and Cash Equivalents - Beginning of Period				43,364		45,748
Cash and Cash Equivalents - End of Period			$	41,706	$	57,941
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

4

THE CONNECTICUT LIGHT AND POWER COMPANY
CONDENSED BALANCE SHEETS
(Unaudited)
		September 30,		December 31,
(Thousands of Dollars)		2014		2013
ASSETS
Current Assets:
	Cash	$	16,294	$	7,237
	Receivables, Net		369,492		319,670
	Accounts Receivable from Affiliated Companies		35,276		13,777
	Unbilled Revenues		87,806		92,401
	Regulatory Assets		116,531		150,943
	Materials and Supplies		47,086		54,606
	Accumulated Deferred Income Taxes		52,839		-
	Prepaid Property Taxes		47,429		13,962
	Prepayments and Other Current Assets		17,608		39,120
Total Current Assets			790,361		691,716
Property, Plant and Equipment, Net			6,700,798		6,451,259
Deferred Debits and Other Assets:
	Regulatory Assets		1,369,025		1,663,147
	Other Long-Term Assets		178,313		174,380
Total Deferred Debits and Other Assets			1,547,338		1,837,527
Total Assets		$	9,038,497	$	8,980,502
The accompanying notes are an integral part of these unaudited condensed financial statements.

5

THE CONNECTICUT LIGHT AND POWER COMPANY
CONDENSED BALANCE SHEETS
(Unaudited)
			September 30,		December 31,
(Thousands of Dollars)			2014		2013
LIABILITIES AND CAPITALIZATION
Current Liabilities:
	Notes Payable to NU Parent		$	105,400	$	287,300
	Long-Term Debt - Current Portion			162,000		150,000
	Accounts Payable			228,379		201,047
	Accounts Payable to Affiliated Companies			46,977		56,531
	Obligations to Third Party Suppliers			67,630		73,914
	Accrued Taxes			54,652		37,186
	Regulatory Liabilities			195,663		93,961
	Derivative Liabilities			86,759		92,233
	Other Current Liabilities			107,284		97,530
Total Current Liabilities				1,054,744		1,089,702
Deferred Credits and Other Liabilities:
	Accumulated Deferred Income Taxes			1,581,344		1,510,586
	Regulatory Liabilities			87,696		93,757
	Derivative Liabilities			418,137		617,072
	Accrued Pension, SERP and PBOP			63,756		95,895
	Other Long-Term Liabilities			143,838		163,588
Total Deferred Credits and Other Liabilities				2,294,771		2,480,898
Capitalization:
	Long-Term Debt			2,679,775		2,591,208
	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		1,804,228		1,682,047
		Retained Earnings		1,029,473		961,482
		Accumulated Other Comprehensive Loss		(1,046)		(1,387)
	Common Stockholder's Equity			2,893,007		2,702,494
Total Capitalization				5,688,982		5,409,902
Total Liabilities and Capitalization			$	9,038,497	$	8,980,502
The accompanying notes are an integral part of these unaudited condensed financial statements.

6

THE CONNECTICUT LIGHT AND POWER COMPANY
CONDENSED STATEMENTS OF INCOME
(Unaudited)
			For the Three Months Ended September 30,				For the Nine Months Ended September 30,
(Thousands of Dollars)			2014		2013			2014		2013
Operating Revenues			$	695,642	$	648,420	$	2,017,580	$	1,841,846
Operating Expenses:
	Purchased Power and Transmission			255,787		253,152		736,952		667,266
	Operations and Maintenance			127,285		127,104		368,562		359,759
	Depreciation			46,886		44,786		139,598		132,356
	Amortization of Regulatory Assets/(Liabilities), Net			13,098		(27)		62,644		11,223
	Energy Efficiency Programs			41,399		24,544		119,389		68,211
	Taxes Other Than Income Taxes			64,994		64,979		194,105		182,676
		Total Operating Expenses		549,449		514,538		1,621,250		1,421,491
Operating Income				146,193		133,882		396,330		420,355
Interest Expense:
	Interest on Long-Term Debt			34,743		32,845		102,290		98,163
	Other Interest			3,992		2,439		8,158		801
		Interest Expense		38,735		35,284		110,448		98,964
Other Income, Net				6,456		3,861		10,658		10,946
Income Before Income Tax Expense				113,914		102,459		296,540		332,337
Income Tax Expense				30,038		36,136		95,980		113,149
Net Income			$	83,876	$	66,323	$	200,560	$	219,188
The accompanying notes are an integral part of these unaudited condensed financial statements.
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME
(Unaudited)
Net Income			$	83,876	$	66,323	$	200,560	$	219,188
Other Comprehensive Income, Net of Tax:
	Qualified Cash Flow Hedging Instruments			111		111		333		333
	Changes in Unrealized Gains/(Losses) on Other    Securities			(7)		(1)		8		(27)
Other Comprehensive Income, Net of Tax				104		110		341		306
Comprehensive Income			$	83,980	$	66,433	$	200,901	$	219,494
The accompanying notes are an integral part of these unaudited condensed financial statements.

7

THE CONNECTICUT LIGHT AND POWER COMPANY
CONDENSED STATEMENTS OF CASH FLOWS
(Unaudited)
			For the Nine Months Ended September 30,
(Thousands of Dollars)			2014		2013
Operating Activities:
	Net Income		$	200,560	$	219,188
	Adjustments to Reconcile Net Income to Net Cash Flows Provided by Operating Activities:
		Depreciation		139,598		132,356
		Deferred Income Taxes		(14,400)		89,084
		Pension, SERP and PBOP Expense, Net of PBOP Contributions		8,050		16,182
		Regulatory Overrecoveries, Net		62,929		24,061
		Amortization of Regulatory Assets, Net		62,644		11,223
		Proceeds from DOE Damages Claim		68,610		-
		Other		(11,290)		(8,759)
	Changes in Current Assets and Liabilities:
		Receivables and Unbilled Revenues, Net		(87,922)		(44,523)
		Taxes Receivable/Accrued, Net		39,805		841
		Accounts Payable		16,984		(101,949)
		Other Current Assets and Liabilities, Net		(2,575)		(29,106)
Net Cash Flows Provided by Operating Activities				482,993		308,598
Investing Activities:
	Investments in Property, Plant and Equipment			(371,660)		(294,638)
	Other Investing Activities			(4,539)		2,013
Net Cash Flows Used in Investing Activities				(376,199)		(292,625)
Financing Activities:
	Cash Dividends on Common Stock			(128,400)		(114,000)
	Cash Dividends on Preferred Stock			(4,169)		(4,169)
	Issuance of Long-Term Debt			250,000		400,000
	Retirements of Long-Term Debt			(150,000)		(125,000)
	Decrease in Notes Payable to NU Parent			(181,900)		(62,200)
	Capital Contribution from NU Parent			120,000		-
	Decrease in Short-Term Debt			-		(89,000)
	Other Financing Activities			(3,268)		(6,352)
Net Cash Flows Used in Financing Activities				(97,737)		(721)
Net Increase in Cash				9,057		15,252
Cash - Beginning of Period				7,237		1
Cash - End of Period			$	16,294	$	15,253
The accompanying notes are an integral part of these unaudited condensed financial statements.

8

NSTAR ELECTRIC COMPANY AND SUBSIDIARY
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
		September 30,		December 31,
(Thousands of Dollars)		2014		2013
ASSETS
Current Assets:
	Cash and Cash Equivalents	$	11,040	$	8,021
	Receivables, Net		275,902		209,711
	Accounts Receivable from Affiliated Companies		47,215		27,264
	Unbilled Revenues		39,372		41,368
	Materials and Supplies		65,073		44,236
	Regulatory Assets		128,205		204,144
	Prepayments and Other Current Assets		11,267		36,710
Total Current Assets			578,074		571,454
Property, Plant and Equipment, Net			5,211,681		5,043,887
Deferred Debits and Other Assets:
	Regulatory Assets		998,030		1,235,156
	Other Long-Term Assets		62,644		60,624
Total Deferred Debits and Other Assets			1,060,674		1,295,780
Total Assets		$	6,850,429	$	6,911,121
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

9

NSTAR ELECTRIC COMPANY AND SUBSIDIARY
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
			September 30,		December 31,
(Thousands of Dollars)			2014		2013
LIABILITIES AND CAPITALIZATION
Current Liabilities:
	Notes Payable		$	159,500	$	103,500
	Long-Term Debt - Current Portion			4,700		301,650
	Accounts Payable			128,056		202,100
	Accounts Payable to Affiliated Companies			62,625		75,707
	Obligations to Third Party Suppliers			37,298		5,459
	Power Contract Obligations			35,783		30,842
	Renewable Portfolio Standards Compliance Obligations			34,905		39,686
	Accrued Taxes			42,338		7,946
	Accumulated Deferred Income Taxes			9,622		50,128
	Regulatory Liabilities			97,215		53,958
	Other Current Liabilities			62,436		39,936
Total Current Liabilities				674,478		910,912
Deferred Credits and Other Liabilities:
	Accumulated Deferred Income Taxes			1,425,306		1,466,835
	Regulatory Liabilities			266,524		253,108
	Accrued Pension, SERP and PBOP			142,249		118,010
	Payable to Affiliated Companies			-		64,172
	Other Long-Term Liabilities			112,853		142,214
Total Deferred Credits and Other Liabilities				1,946,932		2,044,339
Capitalization:
	Long-Term Debt			1,792,707		1,499,417
	Preferred Stock Not Subject to Mandatory Redemption			43,000		43,000
	Common Stockholder's Equity:
		Common Stock		-		-
		Capital Surplus, Paid In		993,163		992,625
		Retained Earnings		1,400,149		1,420,828
	Common Stockholder's Equity			2,393,312		2,413,453
Total Capitalization				4,229,019		3,955,870
Total Liabilities and Capitalization			$	6,850,429	$	6,911,121
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

10

NSTAR ELECTRIC COMPANY AND SUBSIDIARY
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
			For the Three Months Ended September 30,				For the Nine Months Ended September 30,
(Thousands of Dollars)			2014		2013			2014		2013
Operating Revenues			$	727,909	$	753,879	$	1,955,609	$	1,916,557
Operating Expenses:
	Purchased Power and Transmission			317,784		255,244		879,773		659,140
	Operations and Maintenance			79,705		97,069		244,610		277,261
	Depreciation			47,455		45,441		140,996		136,323
	Amortization of Regulatory Assets/(Liabilities), Net			(15,063)		72,740		(916)		173,289
	Amortization of Rate Reduction Bonds			-		-		-		15,054
	Energy Efficiency Programs			56,915		58,798		145,499		161,180
	Taxes Other Than Income Taxes			34,513		32,610		99,121		95,275
		Total Operating Expenses		521,309		561,902		1,509,083		1,517,522
Operating Income				206,600		191,977		446,526		399,035
Interest Expense:
	Interest on Long-Term Debt			17,996		19,860		58,485		59,261
	Other Interest			(658)		(1,324)		606		(7,612)
		Interest Expense		17,338		18,536		59,091		51,649
Other Income, Net				3,287		2,126		3,011		3,275
Income Before Income Tax Expense				192,549		175,567		390,446		350,661
Income Tax Expense				76,975		68,558		156,655		137,499
Net Income			$	115,574	$	107,009	$	233,791	$	213,162
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

11

NSTAR ELECTRIC COMPANY AND SUBSIDIARY
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
			For the Nine Months Ended September 30,
(Thousands of Dollars)			2014		2013
Operating Activities:
	Net Income		$	233,791	$	213,162
	Adjustments to Reconcile Net Income to Net Cash Flows Provided by Operating Activities:
		Depreciation		140,996		136,323
		Deferred Income Taxes		(39,399)		26,358
		Pension and PBOP Expense, Net of Contributions		(11,046)		(55,195)
		Regulatory Over/(Under) Recoveries, Net		155,357		(11,299)
		Amortization of Regulatory Assets, Net		(916)		173,289
		Amortization of Rate Reduction Bonds		-		15,054
		Proceeds from DOE Damages Claim		30,193		-
		Bad Debt Expense		15,250		19,012
		Other		(56,851)		(48,291)
	Changes in Current Assets and Liabilities:
		Receivables and Unbilled Revenues, Net		(47,770)		(80,575)
		Materials and Supplies		(20,837)		7,961
		Taxes Receivable/Accrued, Net		60,252		(6,345)
		Accounts Payable		(40,594)		6,856
		Accounts Receivable from/Payable to Affiliates, Net		66,758		(59,173)
		Other Current Assets and Liabilities, Net		32,340		(19,547)
Net Cash Flows Provided by Operating Activities				517,524		317,590
Investing Activities:
	Investments in Property, Plant and Equipment			(309,248)		(330,635)
	Decrease in Special Deposits			-		37,899
	Other Investing Activities			-		575
Net Cash Flows Used in Investing Activities				(309,248)		(292,161)
Financing Activities:
	Cash Dividends on Common Stock			(253,000)		(56,000)
	Cash Dividends on Preferred Stock			(1,470)		(1,633)
	Increase/(Decrease) in Notes Payable			56,000		(120,000)
	Issuance of Long-Term Debt			300,000		200,000
	Retirements of Long-Term Debt			(301,650)		(1,650)
	Retirements of Rate Reduction Bonds			-		(43,493)
	Other Financing Activities			(5,137)		(878)
Net Cash Flows Used in Financing Activities				(205,257)		(23,654)
Net Increase in Cash and Cash Equivalents				3,019		1,775
Cash and Cash Equivalents - Beginning of Period				8,021		13,695
Cash and Cash Equivalents - End of Period			$	11,040	$	15,470
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

12

PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARY
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
		September 30,		December 31,
(Thousands of Dollars)		2014		2013
ASSETS
Current Assets:
	Cash	$	2,750	$	130
	Receivables, Net		77,602		76,331
	Accounts Receivable from Affiliated Companies		6,271		90
	Unbilled Revenues		33,088		38,344
	Fuel, Materials and Supplies		141,381		128,736
	Regulatory Assets		102,473		92,194
	Prepayments and Other Current Assets		22,270		24,100
Total Current Assets			385,835		359,925
Property, Plant and Equipment, Net			2,560,635		2,467,556
Deferred Debits and Other Assets:
	Regulatory Assets		178,204		219,346
	Other Long-Term Assets		54,748		39,891
Total Deferred Debits and Other Assets			232,952		259,237
Total Assets		$	3,179,422	$	3,086,718
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

13

PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARY
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
			September 30,		December 31,
(Thousands of Dollars)			2014		2013
LIABILITIES AND CAPITALIZATION
Current Liabilities:
	Notes Payable to NU Parent		$	153,300	$	86,500
	Long-Term Debt - Current Portion			-		50,000
	Accounts Payable			58,801		82,920
	Accounts Payable to Affiliated Companies			22,932		22,040
	Regulatory Liabilities			29,165		20,643
	Accumulated Deferred Income Taxes			29,936		28,596
	Other Current Liabilities			38,725		51,729
Total Current Liabilities				332,859		342,428
Deferred Credits and Other Liabilities:
	Accumulated Deferred Income Taxes			566,298		500,166
	Regulatory Liabilities			50,614		51,723
	Accrued SERP and PBOP			14,320		15,272
	Other Long-Term Liabilities			46,874		46,247
Total Deferred Credits and Other Liabilities				678,106		613,408
Capitalization:
	Long-Term Debt			999,230		999,006
	Common Stockholder's Equity:
		Common Stock		-		-
		Capital Surplus, Paid In		702,923		701,911
		Retained Earnings		473,969		438,515
		Accumulated Other Comprehensive Loss		(7,665)		(8,550)
	Common Stockholder's Equity			1,169,227		1,131,876
Total Capitalization				2,168,457		2,130,882
Total Liabilities and Capitalization			$	3,179,422	$	3,086,718
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

14

PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARY
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
			For the Three Months Ended September 30,				For the Nine Months Ended September 30,
(Thousands of Dollars)			2014		2013		2014			2013
Operating Revenues			$	223,664	$	218,608	$	735,123	$	708,550
Operating Expenses:
	Purchased Power, Fuel and Transmission			64,397		46,668		247,992		197,765
	Operations and Maintenance			65,563		69,477		198,025		191,606
	Depreciation			24,568		22,919		73,247		68,433
	Amortization of Regulatory Assets/(Liabilities), Net			(9,734)		225		(17,565)		(1,745)
	Amortization of Rate Reduction Bonds			-		-		-		19,748
	Energy Efficiency Programs			3,766		3,990		10,897		11,036
	Taxes Other Than Income Taxes			18,702		18,706		53,051		52,640
		Total Operating Expenses		167,262		161,985		565,647		539,483
Operating Income				56,402		56,623		169,476		169,067
Interest Expense:
	Interest on Long-Term Debt			10,896		10,345		33,812		32,951
	Other Interest			128		521		183		1,230
		Interest Expense		11,024		10,866		33,995		34,181
Other Income, Net				461		792		1,673		2,454
Income Before Income Tax Expense				45,839		46,549		137,154		137,340
Income Tax Expense				17,603		18,196		52,199		52,797
Net Income			$	28,236	$	28,353	$	84,955	$	84,543
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Unaudited)
Net Income			$	28,236	$	28,353	$	84,955	$	84,543
Other Comprehensive Income, Net of Tax:
	Qualified Cash Flow Hedging Instruments			290		290		871		872
	Changes in Unrealized Gains/(Losses) on Other    Securities			(13)		(2)		14		(47)
	Changes in Funded Status of Pension, SERP and    PBOP Benefit Plans			-		-		-		(3)
Other Comprehensive Income, Net of Tax				277		288		885		822
Comprehensive Income			$	28,513	$	28,641	$	85,840	$	85,365
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

15

PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARY
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
			For the Nine Months Ended September 30,
(Thousands of Dollars)			2014		2013
Operating Activities:
	Net Income		$	84,955	$	84,543
	Adjustments to Reconcile Net Income to Net Cash Flows Provided by Operating Activities:
		Depreciation		73,247		68,433
		Deferred Income Taxes		67,827		57,066
		Pension, SERP and PBOP Expense		4,541		20,427
		Pension and PBOP Contributions		(1,637)		(112,964)
		Regulatory Over/(Under) Recoveries, Net		16,813		(1,346)
		Amortization of Regulatory Liabilities, Net		(17,565)		(1,745)
		Amortization of Rate Reduction Bonds		-		19,748
		Proceeds from DOE Damages Claim		14,453		-
		Other		7,930		7,165
	Changes in Current Assets and Liabilities:
		Receivables and Unbilled Revenues, Net		(7,467)		8,047
		Fuel, Materials and Supplies		(17,350)		(30,456)
		Taxes Receivable/Accrued, Net		(24,108)		5,103
		Accounts Payable		(9,297)		29,148
		Other Current Assets and Liabilities, Net		13,470		7,220
Net Cash Flows Provided by Operating Activities				205,812		160,389
Investing Activities:
	Investments in Property, Plant and Equipment			(170,127)		(155,676)
	(Increase)/Decrease in Special Deposits			(45)		22,039
	Other Investing Activities			(103)		(53)
Net Cash Flows Used in Investing Activities				(170,275)		(133,690)
Financing Activities:
	Cash Dividends on Common Stock			(49,500)		(51,000)
	Increase in Notes Payable to NU Parent			66,800		165,200
	Retirements of Long-Term Debt			(50,000)		(108,950)
	Retirements of Rate Reduction Bonds			-		(29,294)
	Other Financing Activities			(217)		456
Net Cash Flows Used in Financing Activities				(32,917)		(23,588)
Net Increase in Cash				2,620		3,111
Cash - Beginning of Period				130		2,493
Cash - End of Period			$	2,750	$	5,604
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

16

WESTERN MASSACHUSETTS ELECTRIC COMPANY
CONDENSED BALANCE SHEETS
(Unaudited)
		September 30,		December 31,
(Thousands of Dollars)		2014		2013
ASSETS
Current Assets:
	Cash	$	1,737	$	-
	Receivables, Net		50,835		49,018
	Accounts Receivable from Affiliated Companies		14,522		47,607
	Unbilled Revenues		12,664		16,562
	Taxes Receivable		11,504		432
	Regulatory Assets		38,907		43,024
	Marketable Securities		22,107		26,628
	Prepayments and Other Current Assets		6,688		10,479
Total Current Assets			158,964		193,750
Property, Plant and Equipment, Net			1,432,368		1,381,060
Deferred Debits and Other Assets:
	Regulatory Assets		109,690		146,088
	Marketable Securities		35,963		31,243
	Other Long-Term Assets		50,902		40,679
Total Deferred Debits and Other Assets			196,555		218,010
Total Assets		$	1,787,887	$	1,792,820
The accompanying notes are an integral part of these unaudited condensed financial statements.

17

WESTERN MASSACHUSETTS ELECTRIC COMPANY
CONDENSED BALANCE SHEETS
(Unaudited)
			September 30,		December 31,
(Thousands of Dollars)			2014		2013
LIABILITIES AND CAPITALIZATION
Current Liabilities:
	Notes Payable to NU Parent		$	13,200	$	-
	Long-Term Debt - Current Portion			50,000		-
	Accounts Payable			36,558		62,961
	Accounts Payable to Affiliated Companies			13,312		9,230
	Accrued Interest			2,839		7,525
	Regulatory Liabilities			43,462		19,858
	Accumulated Deferred Income Taxes			1,920		13,098
	Counterparty Deposits			626		7,688
	Other Current Liabilities			11,758		20,629
Total Current Liabilities				173,675		140,989
Deferred Credits and Other Liabilities:
	Accumulated Deferred Income Taxes			413,701		396,933
	Regulatory Liabilities			10,289		13,873
	Accrued SERP and PBOP			2,623		3,911
	Other Long-Term Liabilities			38,372		28,619
Total Deferred Credits and Other Liabilities				464,985		443,336
Capitalization:
	Long-Term Debt			578,686		629,389
	Common Stockholder's Equity:
		Common Stock		10,866		10,866
		Capital Surplus, Paid In		391,136		390,743
		Retained Earnings		171,800		181,014
		Accumulated Other Comprehensive Loss		(3,261)		(3,517)
	Common Stockholder's Equity			570,541		579,106
Total Capitalization				1,149,227		1,208,495
Total Liabilities and Capitalization			$	1,787,887	$	1,792,820
The accompanying notes are an integral part of these unaudited condensed financial statements.

18

WESTERN MASSACHUSETTS ELECTRIC COMPANY
CONDENSED STATEMENTS OF INCOME
(Unaudited)
			For the Three Months Ended September 30,				For the Nine Months Ended September 30,
(Thousands of Dollars)			2014		2013		2014		2013
Operating Revenues			$	118,145	$	121,795	$	363,843	$	361,763
Operating Expenses:
	Purchased Power and Transmission			43,926		38,797		130,977		111,095
	Operations and Maintenance			20,820		26,148		67,085		70,213
	Depreciation			10,506		9,426		31,144		27,707
	Amortization of Regulatory Liabilities, Net			(8,519)		(1,412)		(7,778)		(598)
	Amortization of Rate Reduction Bonds			-		-		-		7,780
	Energy Efficiency Programs			10,983		12,222		33,096		28,462
	Taxes Other Than Income Taxes			9,200		7,696		25,679		20,188
		Total Operating Expenses		86,916		92,877		280,203		264,847
Operating Income				31,229		28,918		83,640		96,916
Interest Expense:
	Interest on Long-Term Debt			6,029		5,814		18,195		17,846
	Other Interest			547		417		734		954
		Interest Expense		6,576		6,231		18,929		18,800
Other Income, Net				502		926		1,670		2,349
Income Before Income Tax Expense				25,155		23,613		66,381		80,465
Income Tax Expense				10,490		8,588		26,596		30,424
Net Income			$	14,665	$	15,025	$	39,785	$	50,041
The accompanying notes are an integral part of these unaudited condensed financial statements.

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME
(Unaudited)
Net Income		$	14,665	$	15,025	$	39,785	$	50,041
Other Comprehensive Income, Net of Tax:
	Qualified Cash Flow Hedging Instruments		85		85		254		254
	Changes in Unrealized Gains/(Losses) on Other    Securities		(2)		-		2		(8)
Other Comprehensive Income, Net of Tax			83		85		256		246
Comprehensive Income		$	14,748	$	15,110	$	40,041	$	50,287
The accompanying notes are an integral part of these unaudited condensed financial statements.

19

WESTERN MASSACHUSETTS ELECTRIC COMPANY
CONDENSED STATEMENTS OF CASH FLOWS
(Unaudited)
			For the Nine Months Ended September 30,
(Thousands of Dollars)			2014		2013
Operating Activities:
	Net Income		$	39,785	$	50,041
	Adjustments to Reconcile Net Income to Net Cash Flows Provided by Operating Activities:
		Depreciation		31,144		27,707
		Deferred Income Taxes		13,479		79,401
		Regulatory Overrecoveries, Net		33,630		11,685
		Amortization of Regulatory Liabilities, Net		(7,778)		(598)
		Amortization of Rate Reduction Bonds		-		7,780
		Proceeds from DOE Damages Claim		18,883		-
		Other		615		(544)
	Changes in Current Assets and Liabilities:
		Receivables and Unbilled Revenues, Net		36,075		(32,231)
		Taxes Receivable/Accrued, Net		(15,831)		16,412
		Accounts Payable		(12,847)		20,260
		Other Current Assets and Liabilities, Net		(16,551)		(9,857)
Net Cash Flows Provided by Operating Activities				120,604		170,056
Investing Activities:
	Investments in Property, Plant and Equipment			(82,546)		(127,352)
	Proceeds from Sales of Marketable Securities			58,788		53,552
	Purchases of Marketable Securities			(59,280)		(54,042)
	Other Investing Activities			-		7,401
Net Cash Flows Used in Investing Activities				(83,038)		(120,441)
Financing Activities:
	Cash Dividends on Common Stock			(49,000)		(30,000)
	Retirement of Long-Term Debt			-		(55,000)
	Increase in Notes Payable to NU Parent			13,200		47,900
	Retirement of Rate Reduction Bonds			-		(9,352)
	Other Financing Activities			(29)		(7)
Net Cash Flows Used in Financing Activities				(35,829)		(46,459)
Net Increase in Cash				1,737		3,156
Cash - Beginning of Period				-		1
Cash - End of Period			$	1,737	$	3,157
The accompanying notes are an integral part of these unaudited condensed financial statements.

20

NORTHEAST UTILITIES AND SUBSIDIARIES

THE CONNECTICUT LIGHT AND POWER COMPANY

NSTAR ELECTRIC COMPANY AND SUBSIDIARY

PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARY

WESTERN MASSACHUSETTS ELECTRIC COMPANY

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)

Refer to the Glossary of Terms included in this combined Quarterly Report on Form 10-Q for abbreviations and acronyms used throughout the combined notes to the unaudited condensed consolidated financial statements.

1.

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

A.

Basis of Presentation

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 consist of CL&P, NSTAR Electric, PSNH, WMECO, Yankee Gas and NSTAR Gas.  NU provides energy delivery service to approximately 3.6 million electric and natural gas customers through these six regulated utilities in Connecticut, Massachusetts and New Hampshire.

The unaudited condensed consolidated financial statements of NU, NSTAR Electric and PSNH include the accounts of each of their respective subsidiaries.  Intercompany transactions have been eliminated in consolidation.  The accompanying unaudited condensed consolidated financial statements of NU, NSTAR Electric and PSNH and the unaudited condensed financial statements of CL&P and WMECO are herein collectively referred to as the "financial statements."

The combined notes to the financial statements have been prepared pursuant to the rules and regulations of the SEC.  Certain information and footnote disclosures included in annual financial statements prepared in accordance with GAAP have been omitted pursuant to such rules and regulations.  The accompanying financial statements should be read in conjunction with the entirety of this combined Quarterly Report on Form 10-Q, the first and second quarter 2014 combined Quarterly Reports on Form 10-Q and the 2013 combined Annual Report on Form 10-K of NU, CL&P, NSTAR Electric, PSNH and WMECO, which were filed with the SEC.  The preparation of the 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 financial statements and the reported amounts of revenues and expenses during the reporting period.  Actual results could differ from those estimates.

The financial statements contain, in the opinion of management, all adjustments (including normal, recurring adjustments) necessary to present fairly NU's, CL&P's, NSTAR Electric's, PSNH's and WMECO's financial position as of September 30, 2014 and December 31, 2013, the results of operations and comprehensive income for the three and nine months ended September 30, 2014 and 2013, and the cash flows for the nine months ended September 30, 2014 and 2013.  The results of operations and comprehensive income for the three and nine months ended September 30, 2014 and 2013, and the cash flows for the nine months ended September 30, 2014 and 2013 are not necessarily indicative of the results expected for a full year.  

NU consolidates CYAPC and YAEC because CL&P's, NSTAR Electric's, PSNH's and WMECO's combined ownership interest in each of these entities is greater than 50 percent.  Intercompany transactions between CL&P, NSTAR Electric, PSNH and WMECO and the CYAPC and YAEC companies have been eliminated in consolidation of the NU financial statements.  For CL&P, NSTAR Electric, PSNH and WMECO, the investments in CYAPC and YAEC continue to be accounted for under the equity method.  

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 2, "Regulatory Accounting," for further information.

Certain reclassifications of prior period data were made in the accompanying balance sheets for NU, CL&P, NSTAR Electric and PSNH, and in the statements of income for NU, NSTAR Electric, PSNH and WMECO.  These reclassifications were made to conform to the current period presentation.

B.

Accounting Standards

Recently Adopted Accounting Standards:  On January 1, 2014, as required, NU prospectively adopted the Financial Accounting Standards Board's (FASB) final Accounting Standards Updates (ASU) that required presentation of certain unrecognized tax benefits as reductions to deferred tax assets.  Implementation of this guidance had an immaterial impact on the balance sheets and no impact on the results of operations or cash flows of NU, CL&P, NSTAR Electric, PSNH and WMECO.

Accounting Standards Issued but not Yet Adopted:  In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers, effective January 1, 2017, which amends existing revenue recognition guidance and is required to be applied retrospectively (either to each reporting period presented or cumulatively at the date of initial application).  Management is reviewing the requirements of the new ASU, however the ASU's impact is not expected to have a material impact on the financial statements of NU, CL&P, NSTAR Electric, PSNH and WMECO.

21

C.

Provision for Uncollectible Accounts

NU, including CL&P, NSTAR Electric, PSNH and WMECO, presents its receivables at estimated net realizable value by maintaining a provision for uncollectible accounts.  This provision is determined based upon a variety of factors, including the application of an estimated uncollectible percentage to each receivable aging category.  The estimate is based upon historical collection and write-off experience and management's assessment of collectibility from individual customers.  Management continuously assesses the collectibility of receivables, and adjusts collectibility estimates based on actual experience.  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 provision for uncollectible accounts, which is included in Receivables, Net on the balance sheets, was as follows:

(Millions of Dollars)	As of September 30, 2014		As of December 31, 2013
NU	$	181.4	$	171.3
CL&P		85.8		82.0
NSTAR Electric		42.3		41.7
PSNH		7.9		7.4
WMECO		11.1		10.0

D.

Fair Value Measurements

Fair value measurement guidance is applied to derivative contracts that are not elected or designated as "normal purchases or normal sales" (normal) and to the marketable securities held in trusts.  Fair value measurement guidance is also applied to investment valuations used to calculate the funded status of pension and PBOP plans and nonrecurring fair value measurements of nonfinancial assets such as goodwill and AROs, and is also used to estimate the fair value of preferred stock and long-term debt.

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 4, "Derivative Instruments," Note 5, "Marketable Securities," and Note 10, "Fair Value of Financial Instruments," to the financial statements.

E.

Other Income, Net

Items included within Other Income, Net on the statements of income primarily consist of investment income/(loss), interest income, AFUDC related to equity funds, and equity in earnings.  Investment income/(loss) primarily relates to debt and equity securities held in trust.  For further information, see Note 5, "Marketable Securities," to the financial statements.  

F.

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 statements of income as follows:

	For the Three Months Ended				For the Nine Months Ended
(Millions of Dollars)	September 30, 2014		September 30, 2013		September 30, 2014		September 30, 2013
NU	$	35.0	$	37.5	$	114.6	$	108.9
CL&P		32.5		35.5		99.0		97.3

Certain sales taxes are also collected by NU's companies that serve customers in Connecticut and Massachusetts as agents for state and local governments and are recorded on a net basis with no impact on the statements of income.   

22

G.	Supplemental Cash Flow Information
Non-cash investing activities include plant additions included in Accounts Payable as follows:

(Millions of Dollars)	As of September 30, 2014		As of September 30, 2013
NU	$	128.9	$	122.9
CL&P		52.2		36.6
NSTAR Electric		18.1		31.9
PSNH		21.0		16.9
WMECO		10.0		13.8

In the first nine months of 2014, as a result of damages awarded to the Yankee Companies for spent nuclear fuel lawsuits against the DOE described in Note 9C, "Commitments and Contingencies - Contractual Obligations - Yankee Companies," NU received total proceeds of $132.1 million, which were net of $80.6 million in proceeds CYAPC and YAEC returned to non-affiliated member companies.  

H.

Severance Benefits

NU recorded severance benefit expenses of $0.7 million and $6.5 million associated with the partial outsourcing of information technology functions and ongoing post-merger integration for the three and nine months ended September 30, 2014, respectively, and $9.2 million for the three and nine months ended September 30, 2013.  As of September 30, 2014 and December 31, 2013, the severance accrual totaled $6.4 million and $14.7 million, respectively, and was included in Other Current Liabilities on the balance sheets.

2.

REGULATORY ACCOUNTING

The rates charged to the customers of NU's Regulated companies are designed to collect each company's costs to provide service, including a return on investment.  Therefore, the accounting policies of the Regulated companies follow the application of accounting guidance for entities with rate-regulated operations and reflect the effects of the rate-making process.  

Management believes it is probable that each of the Regulated companies will recover their respective investments in long-lived assets, including regulatory assets.  If management were to determine that it could no longer apply the accounting guidance applicable to rate-regulated enterprises to any of the Regulated companies' operations, or that management could not conclude it is probable that costs would be recovered from customers 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:

	As of September 30, 2014		As of December 31, 2013
(Millions of Dollars)	NU		NU
Benefit Costs	$	1,113.2	$	1,240.2
Derivative Liabilities		427.5		638.0
Income Taxes, Net		623.2		626.2
Storm Restoration Costs		493.5		589.6
Goodwill-related		510.5		525.9
Regulatory Tracker Mechanisms		235.7		323.4
Contractual Obligations - Yankee Companies		124.6		154.2
Buy Out Agreements for Power Contracts		49.8		70.2
Other Regulatory Assets		109.1		126.8
Total Regulatory Assets		3,687.1		4,294.5
Less:  Current Portion		446.0		535.8
Total Long-Term Regulatory Assets	$	3,241.1	$	3,758.7

	As of September 30, 2014								As of December 31, 2013
			NSTAR								NSTAR
(Millions of Dollars)	CL&P		Electric		PSNH		WMECO		CL&P		Electric		PSNH		WMECO
Benefit Costs	$	242.2	$	318.1	$	78.1	$	44.3	$	297.7	$	496.7	$	100.6	$	57.3
Derivative Liabilities		421.1		4.3		-		-		630.4		7.7		-		-
Income Taxes, Net		427.4		83.3		38.3		35.3		415.5		84.0		40.3		43.7
Storm Restoration Costs		326.0		106.2		29.3		32.0		397.8		109.3		43.7		38.8
Goodwill-related		-		438.3		-		-		-		451.5		-		-
Regulatory Tracker Mechanisms		5.2		76.4		94.7		23.5		8.0		169.5		83.3		32.6
Buy Out Agreements for Power Contracts		-		45.4		4.4		-		-		64.7		5.5		-
Other Regulatory Assets		63.6		54.2		35.9		13.5		64.6		55.9		38.1		16.7
Total Regulatory Assets		1,485.5		1,126.2		280.7		148.6		1,814.0		1,439.3		311.5		189.1
Less:  Current Portion		116.5		128.2		102.5		38.9		150.9		204.1		92.2		43.0
Total Long-Term Regulatory Assets	$	1,369.0	$	998.0	$	178.2	$	109.7	$	1,663.1	$	1,235.2	$	219.3	$	146.1

Benefit Costs:  For information related to the Regulated companies' pension and other postretirement benefits, see Note 7, "Pension Benefits and Postretirement Benefits Other Than Pensions."

Storm Restoration Costs:  On March 12, 2014, the PURA approved recovery of $365 million of deferred storm restoration costs (with carrying charges) associated with five major storms that occurred in 2011 and 2012.  CL&P will recover these costs in its distribution rates over a six-year period beginning December 1, 2014.  Effective June 1, 2014, CL&P received $65.4 million of DOE Phase II Damages proceeds.  On June 17, 2014,

23

the PURA ordered CL&P to refund these proceeds to customers by offsetting the deferred storm restoration costs regulatory asset.  For further information on the DOE Phase II Damages proceeds received from the Yankee Companies, see Note 9C, "Commitments and Contingencies - Contractual Obligations - Yankee Companies," to the financial statements.

Regulatory Costs in Other Long-Term Assets:  The Regulated companies had $64.7 million ($3.2 million for CL&P, $36 million for NSTAR Electric, and $11.2 million for WMECO) and $65.1 million ($7.3 million for CL&P, $33.4 million for NSTAR Electric, and $10.1 million for WMECO) of additional regulatory costs as of September 30, 2014 and December 31, 2013, respectively, that were included in Other Long-Term Assets on the balance sheets.  These amounts represent incurred costs for which recovery has not yet been specifically approved by the applicable regulatory agency.  However, based on regulatory policies or past precedent on similar costs, management believes it is probable that these costs will ultimately be approved and recovered from customers in rates.

Regulatory Liabilities:  The components of regulatory liabilities are as follows:

	As of September 30, 2014		As of December 31, 2013
(Millions of Dollars)	NU		NU
Cost of Removal	$	439.1	$	435.1
Regulatory Tracker Mechanisms		339.9		151.2
AFUDC - Transmission		67.2		68.1
Other Regulatory Liabilities		62.7		52.9
Total Regulatory Liabilities		908.9		707.3
Less:  Current Portion		399.0		204.3
Total Long-Term Regulatory Liabilities	$	509.9	$	503.0

	As of September 30, 2014								As of December 31, 2013
			NSTAR								NSTAR
(Millions of Dollars)	CL&P		Electric		PSNH		WMECO		CL&P		Electric		PSNH		WMECO
Cost of Removal	$	22.5	$	260.7	$	49.2	$	-	$	29.1	$	250.0	$	49.7	$	-
Regulatory Tracker Mechanisms		196.4		67.3		25.9		43.9		95.6		21.9		21.6		21.1
AFUDC - Transmission		53.9		4.1		-		9.2		54.7		4.1		-		9.3
Other Regulatory Liabilities		10.6		31.6		4.7		0.7		8.4		31.1		1.0		3.4
Total Regulatory Liabilities		283.4		363.7		79.8		53.8		187.8		307.1		72.3		33.8
Less:  Current Portion		195.7		97.2		29.2		43.5		94.0		54.0		20.6		19.9
Total Long-Term Regulatory Liabilities	$	87.7	$	266.5	$	50.6	$	10.3	$	93.8	$	253.1	$	51.7	$	13.9

As a result of two FERC orders issued on June 19, 2014 in the pending base ROE complaint proceedings described in Note 9E, "Commitments and Contingencies – FERC Base ROE Complaints," in the second quarter of 2014 the Company had recorded a series of reserves at its electric subsidiaries to recognize the potential financial impact of these rulings.  As of September 30, 2014, the cumulative pre-tax reserves (excluding interest) totaled $76.1 million at NU, $42.9 million at CL&P, $15.6 million at NSTAR Electric, $5.9 million at PSNH and $11.7 million at WMECO.  As of December 31, 2013, as a result of the FERC ALJ initial decision in the third quarter of 2013, the Company had an aggregate pre-tax reserve (excluding interest) of $23.7 million at NU, $12.8 million at CL&P, $5.7 million at NSTAR Electric, $2.3 million at PSNH and $2.9 million at WMECO.  These reserves were recorded in each electric subsidiary's respective transmission regulatory tracker mechanism and as a reduction of Operating Revenues.

Effective June 1, 2014, as a result of damages awarded to the Yankee Companies for spent nuclear fuel lawsuits against the DOE described in Note 9C, "Commitments and Contingencies - Contractual Obligations - Yankee Companies," the Yankee Companies returned the DOE Phase II Damages proceeds to the member companies, including CL&P, NSTAR Electric, PSNH, and WMECO, for the benefit of their respective customers.  CL&P's refund obligation to customers of $65.4 million was recorded as an offset to the deferred storm restoration costs regulatory asset, as directed by PURA.  NSTAR Electric's, PSNH's and WMECO's refund obligation to customers of $29.1 million, $13.1 million and $18.1 million, respectively, was recorded as a regulatory liability in each electric subsidiary's respective regulatory tracker mechanisms. Refunds to customers for these DOE proceeds began in the third quarter of 2014.   

24

3.

PROPERTY, PLANT AND EQUIPMENT AND ACCUMULATED DEPRECIATION

The following tables summarize the investments in utility property, plant and equipment by asset category:

		As of September 30, 2014		As of December 31, 2013
(Millions of Dollars)		NU		NU
Distribution - Electric		$	12,306.6	$	11,950.2
Distribution - Natural Gas			2,494.5		2,425.9
Transmission			6,564.2		6,412.5
Generation			1,168.6		1,152.3
Electric and Natural Gas Utility			22,533.9		21,940.9
Other (1)			541.7		508.7
Property, Plant and Equipment, Gross			23,075.6		22,449.6
Less:  Accumulated Depreciation
	Electric and Natural Gas Utility		(5,687.0)		(5,387.0)
	Other		(216.3)		(196.2)
Total Accumulated Depreciation			(5,903.3)		(5,583.2)
Property, Plant and Equipment, Net			17,172.3		16,866.4
Construction Work in Progress			1,082.3		709.8
Total Property, Plant and Equipment, Net		$	18,254.6	$	17,576.2

⁽¹⁾

These assets represent unregulated property and are primarily comprised of building improvements, computer software, hardware and equipment and telecommunications assets at NU's unregulated companies.

	As of September 30, 2014								As of December 31, 2013
			NSTAR								NSTAR
(Millions of Dollars)	CL&P		Electric		PSNH		WMECO		CL&P		Electric		PSNH		WMECO
Distribution	$	5,104.8	$	4,812.4	$	1,654.5	$	774.8	$	4,930.7	$	4,694.7	$	1,608.2	$	756.6
Transmission		3,125.2		1,824.6		715.8		851.8		3,071.9		1,772.3		695.7		826.4
Generation		-		-		1,134.7		33.9		-		-		1,131.2		21.1
Property, Plant and    Equipment, Gross		8,230.0		6,637.0		3,505.0		1,660.5		8,002.6		6,467.0		3,435.1		1,604.1
Less:  Accumulated Depreciation		(1,908.2)		(1,726.7)		(1,069.4)		(291.8)		(1,804.1)		(1,631.3)		(1,021.8)		(271.5)
Property, Plant and Equipment, Net		6,321.8		4,910.3		2,435.6		1,368.7		6,198.5		4,835.7		2,413.3		1,332.6
Construction Work in Progress		379.0		301.4		125.0		63.7		252.8		208.2		54.3		48.5
Total Property, Plant and   Equipment, Net	$	6,700.8	$	5,211.7	$	2,560.6	$	1,432.4	$	6,451.3	$	5,043.9	$	2,467.6	$	1,381.1

4.

DERIVATIVE INSTRUMENTS

The Regulated companies purchase and procure energy and energy-related products, which are subject to price volatility, for their customers.  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 and nonderivative contracts.  

Many of the derivative contracts meet the definition of, and are designated as, normal and qualify for accrual accounting under the applicable accounting guidance.  The costs and benefits of derivative contracts that meet the definition of normal are recognized in Operating Expenses or Operating Revenues on the statements of income, as applicable, as electricity or natural gas is delivered.

Derivative contracts that are not designated as normal are recorded at fair value as current or long-term Derivative Assets or Derivative Liabilities on the balance sheets.  For the Regulated companies, regulatory assets or regulatory liabilities are recorded to offset the fair values of derivatives, as costs are recovered from, or refunded to, customers in their respective energy supply rates.  For NU's unregulated wholesale marketing contracts that expired on December 31, 2013, changes in fair values of derivatives were included in Net Income.  

25

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, on the balance sheets.  The following tables present the gross fair values of contracts categorized by risk type and the net amount recorded as current or long-term derivative asset or liability:

		As of September 30, 2014
		Commodity Supply and				Net Amount Recorded as
(Millions of Dollars)		Price Risk Management		Netting (1)		Derivative Asset/(Liability)
Current Derivative Assets:
Level 2:
	NU (1)	$	0.4	$	-	$	0.4
Level 3:
	NU (1)		17.4		(6.8)		10.6
	CL&P (1)		16.4		(6.8)		9.6
	NSTAR Electric		1.0		-		1.0
Long-Term Derivative Assets:
Level 3:
	NU (1)	$	96.0	$	(20.9)	$	75.1
	CL&P (1)		95.1		(20.9)		74.2
	NSTAR Electric		0.9		-		0.9
Current Derivative Liabilities:
Level 2:
	NU (1)	$	(2.4)	$	0.4	$	(2.0)
Level 3:
	NU		(88.3)		-		(88.3)
	CL&P		(86.8)		-		(86.8)
	NSTAR Electric		(1.5)		-		(1.5)
Long-Term Derivative Liabilities:
Level 3:
	NU	$	(420.9)	$	-	$	(420.9)
	CL&P		(418.1)		-		(418.1)
	NSTAR Electric		(2.8)		-		(2.8)

		As of December 31, 2013
		Commodity Supply and				Net Amount Recorded as
(Millions of Dollars)		Price Risk Management		Netting (1)		Derivative Asset/(Liability)
Current Derivative Assets:
Level 2:
	NU  (1)	$	1.9	$	(0.3)	$	1.6
Level 3:
	NU (1)		18.4		(9.8)		8.6
	CL&P (1)		17.1		(9.8)		7.3
	NSTAR Electric		1.2		-		1.2
Long-Term Derivative Assets:
Level 2:
	NU	$	0.2	$	-	$	0.2
Level 3:
	NU (1)		116.2		(42.2)		74.0
	CL&P (1)		113.6		(42.2)		71.4
Current Derivative Liabilities:
Level 3:
	NU	$	(93.7)	$	-	$	(93.7)
	CL&P		(92.2)		-		(92.2)
	NSTAR Electric		(1.5)		-		(1.5)
Long-Term Derivative Liabilities:
Level 3:
	NU	$	(624.1)	$	-	$	(624.1)
	CL&P		(617.1)		-		(617.1)
	NSTAR Electric		(7.0)		-		(7.0)

⁽¹⁾

Amounts represent derivative assets and liabilities that NU elected to record net on the balance sheets.  These amounts are subject to master netting agreements or similar agreements for which the right of offset exists.

For further information on the fair value of derivative contracts, see Note 1D, "Summary of Significant Accounting Policies - Fair Value Measurements," to the financial statements.

Derivatives At Fair Value with Offsetting Regulatory Amounts

Commodity Supply and Price Risk Management:  As required by regulation, CL&P, along with UI, has capacity-related contracts with generation facilities.  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 combined

26

capacity of these contracts is 787 MW.  The capacity contracts extend through 2026 and obligate both CL&P and UI 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 and a capacity-related contract to purchase up to 35 MW per year through 2019.

As of September 30, 2014 and December 31, 2013, NU had NYMEX future contracts in order to reduce variability associated with the purchase price of approximately 9.7 million and 9.1 million MMBtu of natural gas, respectively.

The following table presents the current change in fair value, primarily recovered through rates from customers, associated with NU's derivative contracts not designated as hedges:

		Amounts Recognized on Derivatives
		For the Three Months Ended September 30,				For the Nine Months Ended September 30,
(Millions of Dollars)		2014		2013		2014		2013
NU
Balance Sheets:
	Regulatory Assets and Liabilities	$	(15.7)	$	0.3	$	149.9	$	48.8
Statements of Income:
	Purchased Power, Fuel and Transmission		-		0.2		-		0.9

Valuation of Derivative Instruments

Derivative contracts classified as Level 2 in the fair value hierarchy relate to the financial contracts for natural gas futures.  Prices are obtained from broker quotes and are based on actual market activity.  The contracts are valued using NYMEX natural gas prices.  Valuations of these contracts also incorporate discount rates using the yield curve approach.  

The fair value of derivative contracts classified as Level 3 utilizes significant unobservable inputs.  The fair value is modeled using income techniques, such as discounted cash flow valuations 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 a 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 and NSTAR Electric's, Level 3 derivative contracts and the range of the significant unobservable inputs utilized in the valuations over the duration of the contracts:   

	As of September 30, 2014							As of December 31, 2013
		Range					Period Covered		Range					Period Covered
Energy Prices:
NU	$	66	-	68	per MWh		2018 - 2020	$	49	-	77	per MWh		2018 - 2029
CL&P	$	66	-	68	per MWh		2018 - 2020	$	56	-	58	per MWh		2018 - 2029
Capacity Prices:
NU	$	7.03	-	12.98		per kW-Month	2016 - 2026	$	5.07	-	11.82		per kW-Month	2017 - 2029
CL&P	$	7.03	-	12.98		per kW-Month	2018 - 2026	$	5.07	-	10.42		per kW-Month	2017 - 2026
NSTAR Electric	$	11.00	-	11.10		per kW-Month	2016 - 2019	$	5.07	-	7.38		per kW-Month	2017 - 2019
Forward Reserve:
NU, CL&P	$	5.80	-	9.50		per kW-Month	2014 - 2024	$	3.30	-	3.30		per kW-Month	2014 - 2024
REC Prices:
NU	$	41	-	70	per REC		2014 - 2018	$	36	-	87	per REC		2014 - 2029
NSTAR Electric	$	41	-	70	per REC		2014 - 2018	$	36	-	70	per REC		2014 - 2018

Exit price premiums of 8 percent through 25 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 energy 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.  

27

Valuations using significant unobservable inputs:  The following tables present changes 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.  

		For the Three Months Ended September 30,				For the Nine Months Ended September 30,
		2014		2013		2014		2013
(Millions of Dollars)		NU		NU		NU		NU
Derivatives, Net:
Fair Value as of Beginning of Period		$	(430.9)	$	(788.1)	$	(635.2)	$	(878.6)
Net Realized/Unrealized Gains Included in:
	Net Income		-		1.2		-		8.3
	Regulatory Assets and Liabilities		(13.6)		0.8		147.6		49.6
Settlements			21.0		21.3		64.1		55.9
Fair Value as of End of Period		$	(423.5)	$	(764.8)	$	(423.5)	$	(764.8)

	For the Three Months Ended September 30,
	2014				2013
(Millions of Dollars)	CL&P		NSTAR Electric		CL&P		NSTAR Electric
Derivatives, Net:
Fair Value as of Beginning of Period	$	(424.6)	$	(6.3)	$	(775.8)	$	(13.1)
Net Realized/Unrealized Gains/(Losses)   Included in Regulatory Assets and Liabilities		(15.0)		1.4		(1.2)		0.5
Settlements		18.5		2.5		21.7		1.0
Fair Value as of End of Period	$	(421.1)	$	(2.4)	$	(755.3)	$	(11.6)

	For the Nine Months Ended September 30,
	2014				2013
(Millions of Dollars)	CL&P		NSTAR Electric		CL&P		NSTAR Electric
Derivatives, Net:
Fair Value as of Beginning of Period	$	(630.6)	$	(7.3)	$	(866.2)	$	(14.9)
Net Realized/Unrealized Gains/(Losses)   Included in Regulatory Assets and Liabilities		149.4		0.9		45.1		0.6
Settlements		60.1		4.0		65.8		2.7
Fair Value as of End of Period	$	(421.1)	$	(2.4)	$	(755.3)	$	(11.6)

5.

MARKETABLE SECURITIES

NU maintains trusts to fund certain non-qualified executive benefits and WMECO maintains a spent nuclear fuel trust to fund WMECO's prior period spent nuclear fuel liability.  These trusts hold marketable securities.  These trusts are not subject to regulatory oversight by state or federal agencies.  In addition, CYAPC and YAEC maintain legally restricted trusts, each of which holds marketable securities, for settling the decommissioning obligations of their nuclear power plants.

In accordance with applicable accounting guidance, the Company elected to record mutual funds designated as available-for-sale at fair value and certain other equity investments as trading securities, with the changes in fair values recorded in Other Income, Net on the statements of income.  As of September 30, 2014, the mutual funds and equity investments were classified as Level 1 in the fair value hierarchy and totaled $58.2 million and $24.4 million, respectively.  As of December 31, 2013, the mutual funds were classified as Level 1 and totaled $57.2 million.  For the three months ended September 30, 2014 and 2013, net losses of $1.9 million and net gains of $3 million, respectively, were recorded in Other Income, Net.  For the nine months ended September 30, 2014 and 2013, net gains of $1.9 million and $7.3 million, respectively, were recorded in Other Income, Net.  Dividend income is recorded in Other Income, Net on the statements of income when dividends are declared.  All other marketable securities are accounted for as available-for-sale.  

Available-for-Sale Securities:  The following is a summary of NU's and WMECO's available-for-sale securities.  These securities are recorded at fair value and included in current and long-term Marketable Securities on the balance sheets.

		As of September 30, 2014
				Pre-Tax		Pre-Tax
		Amortized		Unrealized		Unrealized
(Millions of Dollars)		Cost		Gains		Losses		Fair Value
NU
	Debt Securities (1)	$	310.6	$	7.8	$	(0.2)	$	318.2
	Equity Securities (1)		160.9		71.1		-		232.0
WMECO
	Debt Securities (2)		58.1		0.1		(0.1)		58.1

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		As of December 31, 2013
				Pre-Tax		Pre-Tax
		Amortized		Unrealized		Unrealized
(Millions of Dollars)		Cost		Gains		Losses		Fair Value
NU
	Debt Securities (1)	$	299.2	$	2.5	$	(2.1)	$	299.6
	Equity Securities (1)		163.6		60.5		-		224.1
WMECO
	Debt Securities (2)		57.9		-		-		57.9

⁽¹⁾

NU's amounts include CYAPC's and YAEC's marketable securities held in nuclear decommissioning trusts of $447.7 million and $424 million as of September 30, 2014 and December 31, 2013, respectively, which are legally restricted and can only be used for the costs of 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 balance sheets, with no impact on the statements of income.  All of the equity securities accounted for as available-for-sale securities are held in the CYAPC and YAEC trusts.

⁽²⁾

Unrealized gains and losses on debt securities held by WMECO are recorded in Other Long-Term Assets on the balance sheets.  

Unrealized Losses and Other-than-Temporary Impairment:  There have been no significant unrealized losses, other-than-temporary impairments or credit losses for NU or WMECO.  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 NU's benefit trust, Other Long-Term Assets for WMECO, and offset in Other Long-Term Liabilities for CYAPC and YAEC.  NU utilizes the specific identification basis method for the NU benefit trust and the average cost basis method for the WMECO 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 September 30, 2014, 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)	$	47.6	$	47.6	$	21.9	$	22.1
One to five years		91.0		91.4		30.7		30.5
Six to ten years		65.6		67.5		1.4		1.4
Greater than ten years		106.4		111.7		4.1		4.1
Total Debt Securities	$	310.6	$	318.2	$	58.1	$	58.1

⁽¹⁾

Amounts in the Less than one year NU category include securities in the CYAPC and YAEC nuclear decommissioning trusts, which are restricted and are classified in long-term Marketable Securities on the balance sheets.

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				As of
(Millions of Dollars)		September 30, 2014		December 31, 2013		September 30, 2014		December 31, 2013
Level 1:
	Mutual Funds and Equities	$	314.6	$	281.3	$	-	$	-
	Money Market Funds		27.1		32.9		4.4		10.9
Total Level 1		$	341.7	$	314.2	$	4.4	$	10.9
Level 2:
	U.S. Government Issued Debt Securities    (Agency and Treasury)	$	56.5	$	61.4	$	-	$	6.8
	Corporate Debt Securities		61.2		53.6		14.1		15.1
	Asset-Backed Debt Securities		37.9		30.4		14.3		9.0
	Municipal Bonds		112.5		105.5		13.9		11.2
	Other Fixed Income Securities		23.0		15.8		11.4		4.9
Total Level 2		$	291.1	$	266.7	$	53.7	$	47.0
Total Marketable Securities		$	632.8	$	580.9	$	58.1	$	57.9

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.

29

6.

SHORT-TERM AND LONG-TERM DEBT

Credit Agreements and Commercial Paper Programs:  Effective July 23, 2014, NU parent, CL&P, PSNH, WMECO, NSTAR Gas and Yankee Gas extended the expiration date of their joint $1.45 billion revolving credit facility for one additional year to September 6, 2019.  The revolving credit facility is to be used primarily to backstop NU parent's $1.45 billion commercial paper program.  The commercial paper program allows NU parent to issue commercial paper as a form of short-term debt.  As of September 30, 2014 and December 31, 2013, NU had $964.5 million and $1.01 billion, respectively, in short-term borrowings outstanding under the NU parent commercial paper program, leaving $485.5 million and $435.5 million of available borrowing capacity as of September 30, 2014 and December 31, 2013, respectively.  The weighted-average interest rate on these borrowings as of September 30, 2014 and December 31, 2013 was 0.25 percent and 0.24 percent, respectively, which is generally based on A2/P2 rated commercial paper.  As of September 30, 2014, there were intercompany loans from NU of $105.4 million to CL&P, $153.3 million to PSNH and $13.2 million to WMECO.  As of December 31, 2013, there were intercompany loans from NU of $287.3 million to CL&P and $86.5 million to PSNH.  

Effective July 23, 2014, NSTAR Electric extended the expiration date of its $450 million revolving credit facility for one additional year to September 6, 2019.  This facility serves to backstop NSTAR Electric's existing $450 million commercial paper program.  As of September 30, 2014 and December 31, 2013, NSTAR Electric had $159.5 million and $103.5 million, respectively, in short-term borrowings outstanding under its commercial paper program, leaving $290.5 million and $346.5 million of available borrowing capacity as of September 30, 2014 and December 31, 2013, respectively.  The weighted-average interest rate on these borrowings as of September 30, 2014 and December 31, 2013 was 0.16 percent and 0.13 percent, respectively, which is generally based on A2/P1 rated commercial paper.

Amounts outstanding under the commercial paper programs are generally included in Notes Payable for NU and NSTAR Electric and classified in current liabilities on the balance sheets as all borrowings are outstanding for no more than 364 days at one time.  Intercompany loans from NU to CL&P, PSNH and WMECO are included in Notes Payable to NU Parent and classified in current liabilities on the balance sheets.

Long-Term Debt:  On January 2, 2014, Yankee Gas issued $100 million of 4.82 percent Series L First Mortgage Bonds, due to mature in 2044.  The proceeds, net of issuance costs, were used to repay the $75 million 4.80 percent Series G First Mortgage Bonds that matured on January 1, 2014 and to pay $25 million in short-term borrowings.  As the debt issuance refinanced short-term debt, the short-term debt was classified as Long-Term Debt on NU's balance sheet as of December 31, 2013.  

On March 7, 2014, NSTAR Electric issued $300 million of 4.40 percent debentures, due to mature in 2044.  The proceeds, net of issuance costs, were used to repay the $300 million of 4.875 percent debentures that matured on April 15, 2014.  

On April 24, 2014, CL&P issued $250 million of 4.30 percent 2014 Series A First Mortgage Bonds, due to mature in 2044.  The proceeds, net of issuance costs, were used to repay short-term borrowings.  

On July 15, 2014, PSNH repaid at maturity the $50 million of 5.25 percent Series L First Mortgage Bonds using short-term borrowings.

On September 15, 2014, CL&P repaid at maturity the $150 million of 4.80 percent 2004 Series A First Mortgage Bonds.

On October 14, 2014, PSNH issued $75 million of first mortgage bonds at a yield of 3.144 percent that will mature on November 1, 2023.  The first mortgage bonds are part of the same series of PSNH’s existing 3.50 percent Series S First Mortgage Bonds that were initially issued in November 2013.  As a result, the aggregate principal amount of PSNH’s outstanding Series S First Mortgage Bonds totals $325 million.  The proceeds, net of issuance costs, were used to repay short-term borrowings.  As the debt issuance refinanced short-term debt, the short-term debt was classified as Long-Term Debt on NU's balance sheet as of September 30, 2014.

On August 27, 2014, PURA approved CL&P's request to extend the authorization period for issuance of up to $366.4 million in long-term debt from December 31, 2014 to December 31, 2015.

7.

PENSION BENEFITS AND POSTRETIREMENT BENEFITS OTHER THAN PENSIONS

The components of net periodic benefit expense for the Pension, SERP and PBOP Plans are shown below.  The net periodic benefit expense less the capitalized portion of pension and PBOP amounts is included in Operations and Maintenance on the statements of income. Capitalized pension and PBOP amounts relate to employees working on capital projects and are included in Property, Plant and Equipment, Net. Intercompany allocations are not included in the CL&P, NSTAR Electric, PSNH and WMECO net periodic benefit expense amounts.

30

	Pension and SERP				Pension and SERP
	For the Three Months Ended				For the Nine Months Ended
	September 30, 2014		September 30, 2013		September 30, 2014		September 30, 2013
(Millions of Dollars)	NU		NU		NU		NU
Service Cost	$	19.1	$	25.6	$	60.7	$	76.7
Interest Cost		56.4		51.7		169.5		155.0
Expected Return on Plan Assets		(77.7)		(69.5)		(233.1)		(208.5)
Actuarial Loss		31.7		52.4		96.5		158.1
Prior Service Cost		1.1		1.1		3.3		3.0
Total Net Periodic Benefit Expense	$	30.6	$	61.3	$	96.9	$	184.3
Capitalized Pension Expense	$	8.3	$	18.3	$	26.7	$	54.9
	PBOP				PBOP
	For the Three Months Ended				For the Nine Months Ended
	September 30, 2014		September 30, 2013		September 30, 2014		September 30, 2013
(Millions of Dollars)	NU		NU		NU		NU
Service Cost	$	3.1	$	4.2	$	9.3	$	12.6
Interest Cost		12.4		11.8		37.1		35.4
Expected Return on Plan Assets		(15.8)		(13.9)		(47.4)		(41.6)
Actuarial Loss		3.0		6.5		9.1		19.5
Prior Service Credit		(0.7)		(0.5)		(2.1)		(1.5)
Total Net Periodic Benefit Expense	$	2.0	$	8.1	$	6.0	$	24.4
Capitalized PBOP Expense	$	1.1	$	2.6	$	1.9	$	7.6

	Pension and SERP
	For the Three Months Ended September 30, 2014								For the Three Months Ended September 30, 2013
			NSTAR								NSTAR
(Millions of Dollars)	CL&P		Electric		PSNH		WMECO		CL&P		Electric(1)		PSNH		WMECO
Service Cost	$	5.0	$	3.0	$	2.3	$	0.8	$	6.3	$	8.3		3.3	$	1.2
Interest Cost		12.5		10.3		5.7		2.5		12.1		14.5		5.8		2.5
Expected Return on Plan Assets		(18.7)		(15.7)		(9.3)		(4.4)		(18.4)		(21.1)		(9.2)		(4.3)
Actuarial Loss		8.2		5.9		2.8		1.7		13.9		14.4		5.4		2.9
Prior Service Cost		0.4		-		0.1		0.1		0.4		-		0.1		0.1
Total Net Periodic Benefit Expense	$	7.4	$	3.5	$	1.6	$	0.7	$	14.3	$	16.1	$	5.4	$	2.4
Intercompany Allocations	$	6.5	$	2.9	$	1.8	$	1.2	$	11.4	$	(2.1)	$	2.6	$	2.0
Capitalized Pension Expense	$	4.3	$	2.6	$	0.7	$	0.6	$	7.0	$	9.8	$	1.7	$	1.3
	Pension and SERP
	For the Nine Months Ended September 30, 2014								For the Nine Months Ended September 30, 2013
			NSTAR								NSTAR
(Millions of Dollars)	CL&P		Electric		PSNH		WMECO		CL&P		Electric(1)		PSNH		WMECO
Service Cost	$	15.2	$	10.6	$	7.4	$	2.7	$	18.7	$	24.8	$	9.8	$	3.5
Interest Cost		38.1		31.0		18.0		7.8		36.3		43.5		17.8		7.5
Expected Return on Plan Assets		(56.7)		(47.3)		(28.8)		(13.5)		(55.4)		(63.3)		(26.2)		(13.0)
Actuarial Loss		25.5		17.6		8.9		5.2		42.0		43.6		16.2		8.9
Prior Service Cost/(Credit)		1.4		-		0.5		0.3		1.4		(0.2)		0.4		0.3
Total Net Periodic Benefit Expense	$	23.5	$	11.9	$	6.0	$	2.5	$	43.0	$	48.4	$	18.0	$	7.2
Intercompany Allocations	$	20.8	$	6.7	$	6.0	$	3.9	$	33.6	$	(6.2)	$	7.8	$	6.0
Capitalized Pension Expense	$	13.6	$	5.5	$	2.4	$	2.0	$	21.0	$	21.6	$	5.6	$	3.9

	PBOP
	For the Three Months Ended September 30, 2014								For the Three Months Ended September 30, 2013
(Millions of Dollars)	CL&P			NSTAR Electric		PSNH		WMECO	CL&P		PSNH		WMECO
Service Cost	$	0.6	$	0.8	$	0.3	$	0.1	$	0.9	$	0.6	$	0.2
Interest Cost		2.0		4.9		1.1		0.4		2.0		1.0		0.4
Expected Return on Plan Assets		(2.6)		(6.5)		(1.4)		(0.6)		(2.5)		(1.3)		(0.6)
Actuarial Loss/(Gain)		1.0		(0.1)		0.6		0.1		1.8		0.9		0.3
Prior Service Credit		-		(0.5)		-		-		-		-		-
Total Net Periodic Benefit Expense/(Income)	$	1.0	$	(1.4)	$	0.6	$	0.0	$	2.2	$	1.2	$	0.3
Intercompany Allocations	$	0.9	$	0.3	$	0.2	$	0.2	$	1.7	$	0.4	$	0.3
Capitalized PBOP Expense/(Income)	$	0.5	$	(0.5)	$	0.2	$	-	$	1.3	$	0.4	$	0.3

31

	PBOP
	For the Nine Months Ended September 30, 2014								For the Nine Months Ended September 30, 2013
(Millions of Dollars)	CL&P			NSTAR Electric		PSNH		WMECO	CL&P		PSNH		WMECO
Service Cost	$	1.7	$	2.3	$	1.0	$	0.3	$	2.6	$	1.7	$	0.5
Interest Cost		6.0		14.6		3.2		1.3		5.9		3.1		1.3
Expected Return on Plan Assets		(7.9)		(19.5)		(4.1)		(1.7)		(7.6)		(3.9)		(1.7)
Actuarial Loss/(Gain)		3.2		(0.4)		1.7		0.3		5.6		2.7		0.8
Prior Service Credit		-		(1.4)		-		-		-		-		-
Total Net Periodic Benefit Expense/(Income)	$	3.0	$	(4.4)	$	1.8	$	0.2	$	6.5	$	3.6	$	0.9
Intercompany Allocations	$	3.1	$	0.4	$	0.8	$	0.6	$	5.3	$	1.2	$	1.0
Capitalized PBOP Expense/(Income)	$	1.5	$	(1.5)	$	0.6	$	0.1	$	3.7	$	1.1	$	0.7

⁽¹⁾

NSTAR Electric's pension amounts for the three and nine months ended September 30, 2013 do not include SERP expense.  

For the three and nine months ended September 30, 2013, the net periodic PBOP expense allocated to NSTAR Electric was $1.2 million and $3.5 million, respectively.

As of December 31, 2013, the funded status of the NSTAR Pension Plan was recorded on NSTAR Electric's balance sheet while the total SERP obligation and PBOP Plan funded status were recorded on NSTAR Electric & Gas' balance sheet.  As of December 31, 2013, all NSTAR employees were employed by NSTAR Electric & Gas.  On January 1, 2014, NSTAR Electric & Gas was merged into NUSCO and, concurrently, all employees were transferred to the company they predominately provide services for: NUSCO, NSTAR Electric or NSTAR Gas.  As a result of the employee transfers, the pension and PBOP assets and liabilities were attributed by participant and transferred to the respective company's balance sheets. This change had no impact on the income statement or net assets of NSTAR Electric or NU.

As of September 30, 2014, the liabilities associated with the Pension, SERP and PBOP plans for NSTAR Electric were $83.4 million for the Pension Plan, $3.6 million for the SERP Plans ($0.4 million of which is included in other current liabilities) and $55.6 million for the PBOP Plan.  As of December 31, 2013, the liability associated with the NSTAR Pension Plan for NSTAR Electric was $118 million.  

8.

INCOME TAXES

In the third quarter of 2014, the Company recorded a reduction to its state credit carryforwards of $11 million (CL&P $10.1 million), net of tax, as a result of an update to reflect the amounts expired.  Further, the Company decreased its valuation allowance reserve for state credits by $22.3 million (all at CL&P), net of tax, to reflect the expiration of state credits in its recently filed return and the latest available data.  These updates resulted in a net reduction in income tax expense of $11.3 million (CL&P $12.2 million).   

9.

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.

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 September 30, 2014				As of December 31, 2013
			Reserve				Reserve
	Number of Sites		(in millions)		Number of Sites		(in millions)
NU		65	$	34.7		68	$	35.4
CL&P		16		4.0		18		3.4
NSTAR Electric		13		1.1		12		1.2
PSNH		13		5.3		15		5.4
WMECO		4		0.5		5		0.4

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 $29.8 million and $31.4 million as of September 30, 2014 and December 31, 2013, respectively, and relates primarily to the natural gas business segment.

32

B.

Long-Term Contractual Arrangements

The following is an update to the current status of long-term contractual arrangements set forth in Note 12B of the NU 2013 Form 10-K.  

Renewable Energy:  Renewable energy contracts include non-cancelable commitments under contracts of CL&P, NSTAR Electric and WMECO for the purchase of energy and capacity from renewable energy facilities.

	October - December
(Millions of Dollars)	2014		2015		2016		2017		2018		Thereafter		Total
CL&P	$	20.0	$	60.7	$	66.1	$	67.0	$	67.7	$	717.0	$	998.5
NSTAR Electric		21.8		86.3		100.0		96.1		59.6		377.6		741.4
WMECO		-		-		2.4		2.4		2.4		28.9		36.1

C.

Contractual Obligations – Yankee Companies

Spent Nuclear Fuel Litigation – DOE Phase II Damages –  On November 15, 2013, the Court of Federal Claims issued an award to CYAPC for $126.3 million, YAEC for $73.3 million and MYAPC for $35.8 million for lawsuits against the DOE seeking recovery of actual damages incurred in the years following 2001 and 2002 (DOE Phase II Damages).  On January 14, 2014, the Yankee Companies received a letter from the U.S. Department of Justice stating that the DOE will not appeal the court's final judgment.

On March 28, 2014, CYAPC, YAEC and MYAPC received payment of $90 million, $73.3 million and $35.8 million, respectively, of the DOE Phase II Damages proceeds.  On April 24, 2014, CYAPC received payment of the remaining $36.3 million proceeds.  On April 28, 2014, the Yankee Companies made the required informational filing with FERC in accordance with the process and methodology outlined in the 2013 FERC order.  The Yankee Companies returned the DOE Phase II Damages proceeds to the member companies, including CL&P, NSTAR Electric, PSNH, and WMECO, for the benefit of their respective customers, on June 1, 2014.

As of September 30, 2014, CL&P's refund obligation to customers of $65.4 million was recorded as an offset to the deferred storm restoration costs regulatory asset, as directed by PURA.  NSTAR Electric's, PSNH's and WMECO's refund obligation to customers of $29.1 million, $13.1 million and $18.1 million, respectively, was recorded as a regulatory liability in each company's respective regulatory tracker mechanisms.  Refunds to customers for these DOE proceeds began in the third quarter of 2014.For further information, see Note 2, "Regulatory Accounting," to the financial statements.

DOE Phase III Damages – On August 15, 2013, the Yankee Companies each filed subsequent lawsuits against the DOE seeking recovery of actual damages incurred in the years 2009 through 2012.  Responsive pleading from the U.S. Department of Justice was filed on November 18, 2013, and discovery has begun.  

DOE Phase I Damages - Proceeds Received – On September 17, 2014, in accordance with the MYAPC refund plan, MYAPC returned a portion of the DOE Phase I Damages proceeds to the member companies, including CL&P, NSTAR Electric, PSNH, and WMECO, in the amount of $3.2 million, $1.1 million, $1.4 million and $0.8 million, respectively.  These amounts reduced receivables at CL&P, NSTAR Electric, PSNH and WMECO.

D.

Guarantees and Indemnifications

NU parent 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 and the termination of an unregulated business, with maximum exposures either not specified or not material.  

NU also issued a guaranty 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.  

The following table summarizes NU's guarantees of its subsidiaries, including CL&P, NSTAR Electric, PSNH and WMECO, as of September 30, 2014:  

		Maximum Exposure
Subsidiary	Description	(in millions)		Expiration Dates
Various	Surety Bonds	$	64.3	2014 - 2016 (1)
Various	New England Hydro Companies' Long-Term Debt	$	2.0	Unspecified
NUSCO and RRR	Lease Payments for Vehicles and Real Estate	$	15.3	2019 and 2024

⁽¹⁾

Surety bond expiration dates reflect termination dates, the majority of which will be renewed or extended.  

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 are downgraded.  

33

E.

FERC Base ROE Complaints

First Complaint: On September 30, 2011, a complaint was filed jointly at FERC under Sections 206 and 306 of the Federal Power Act (the "first complaint") by several New England state attorneys general, state regulatory commissions, consumer advocates and other parties (the "Complainants").  The Complainants alleged that the base ROE of 11.14 percent that has been utilized since 2006 in the calculation of formula rates for transmission service under the ISO-NE Open Access Transmission Tariff by NETOs, including CL&P, NSTAR Electric, PSNH and WMECO, was unjust and unreasonable and asserted that the rate was excessive due to changes in the capital markets.  Complainants sought an order to reduce the base ROE prospectively from the date of a final FERC order (the "FERC order date"), and for the 15-month period October 1, 2011 to December 31, 2012 (the "first complaint refund period"), and to require refunds.  The FERC set the case for trial before a FERC ALJ after settlement negotiations were unsuccessful in August 2012.

On August 6, 2013, the FERC ALJ issued an initial decision on the first complaint finding that the base ROE in effect during the first complaint refund period was not reasonable and recommended separate base ROEs for the first complaint refund period of 10.6 percent and for the period beginning when FERC issues its final decision (the "prospective period") of 9.7 percent, leaving policy considerations and additional adjustments to the FERC.  In the third quarter of 2013, the Company recorded a series of reserves at its electric subsidiaries to recognize the potential financial impact from the FERC ALJ's initial decision for the first complaint refund period.  See Cumulative Reserves below for further information on the reserves recorded in the third quarter of 2013.   

On June 19, 2014, FERC issued an order on the first complaint, partially affirming and partially reversing the FERC ALJ's initial decision.  FERC set a single tentative base ROE of 10.57 percent for the first complaint refund period and prospective period.  FERC also modified its traditional methodology by adopting a two-step discounted cash flow analysis that it utilizes to determine the ROEs of both natural gas and oil pipeline projects.  Using this methodology, FERC determined a new zone of reasonableness of 7.03 percent to 11.74 percent, and set the tentative base ROE halfway between the midpoint and the top of the zone of reasonableness.  FERC also stated that a utility's “total ROE, inclusive of transmission incentive ROE adders” should not exceed the top of the new zone of reasonableness produced by this methodology.  FERC instituted a paper hearing on the long-term growth rate portion of the methodology (the "paper hearing").  Rehearing requests on this new methodology were filed in July, and briefs were filed in August and September by the parties on the appropriate long-term growth rate.  In the second quarter of 2014, the Company recorded additional reserves at its electric subsidiaries to recognize the potential financial impact from the FERC’s June 19^th order.  See Cumulative Reserves below for further information on the reserves recorded in the second quarter of 2014.  

On October 16, 2014, the FERC issued an order in the paper hearing, which confirmed that the base ROE should be set at 10.57 percent and that a utility’s total or maximum ROE should not exceed the top of the new zone of reasonableness (11.74 percent).  The FERC ordered the NETOs to provide refunds to customers for the first complaint refund period, and set the new base ROE prospectively from the order date.  

Second Complaint: On December 27, 2012, a second complaint was filed jointly at FERC by several additional consumer groups and municipal parties (the "second complaint"), which challenged the NETOs' base ROE prospectively from the FERC order date and sought refunds for the 15-month period January 1, 2013 to March 31, 2014 (the "second complaint refund period").

On June 19, 2014, FERC issued an order finding that the second complaint raised issues of material fact.  On July 21, 2014, the NETOs filed a rehearing request in this proceeding.  On October 24, 2014, the FERC assigned the case for trial before a FERC ALJ after settlement negotiations were unsuccessful.  The FERC ALJ has set a trial date beginning June 8, 2015, and will issue an initial decision on or before October 26, 2015.  In the second quarter of 2014, the Company recorded reserves at its electric subsidiaries to recognize the potential financial impact from the FERC’s June 19^th order for the second complaint refund period.  See Cumulative Reserves below for further information on the reserves recorded in the second quarter of 2014.  

Third Complaint: On July 31, 2014, a third complaint was filed at FERC (the "third complaint") by most of the Complainants to the first and second complaints, claiming that the base ROE and incentive adders exceed the range of permissible ROEs, requesting FERC to reduce the NETO’s base ROE prospectively from the FERC order date, and seeking refunds for the 15-month period beginning August 1, 2014 (the "third complaint refund period").  FERC has taken no action on this complaint to date.  At this time, the Company cannot determine the outcome of this complaint.

Cumulative Reserves:  The following is a summary as of September 30, 2014 of the cumulative reserves (excluding interest) that the Company established in the third quarter of 2013 and the second quarter of 2014 to recognize the potential financial impacts of the first and second complaints.  Management is currently evaluating the impact of the October 16^th order on the previously established reserves.

	NU
		Third Quarter		Second Quarter
(Millions of Dollars)		2013		2014	Total
1st Complaint - Base ROE	$	23.7	$	1.2	$	24.9
2nd Complaint - Base ROE		-		27.4		27.4
Incentive ROE (1st and 2nd Complaint)		-		23.8		23.8
Cumulative Reserve	$	23.7	$	52.4	$	76.1

	CL&P						NSTAR Electric
		Third Quarter		Second Quarter				Third Quarter		Second Quarter
(Millions of Dollars)		2013		2014	Total			2013		2014	Total
1st Complaint - Base ROE	$	12.8	$	0.5	$	13.3	$	5.7	$	0.4	$	6.1
2nd Complaint - Base ROE		-		13.5		13.5		-		7.5		7.5
Incentive ROE (1st and 2nd Complaint)		-		16.1		16.1		-		2.0		2.0
Cumulative Reserve	$	12.8	$	30.1	$	42.9	$	5.7	$	9.9	$	15.6

34

	PSNH						WMECO
		Third Quarter		Second Quarter				Third Quarter		Second Quarter
(Millions of Dollars)		2013		2014	Total			2013		2014	Total
1st Complaint - Base ROE	$	2.3	$	0.1	$	2.4	$	2.9	$	0.2	$	3.1
2nd Complaint - Base ROE		-		2.7		2.7		-		3.7		3.7
Incentive ROE (1st and 2nd Complaint)		-		0.8		0.8		-		4.9		4.9
Cumulative Reserve	$	2.3	$	3.6	$	5.9	$	2.9	$	8.8	$	11.7

The aggregate after-tax charge to second quarter 2014 earnings resulting from the June 19, 2014 FERC orders totaled $32.1 million at NU, $18.5 million at CL&P, $6.1 million at NSTAR Electric, $2 million at PSNH and $5.5 million at WMECO.  In the third quarter of 2013, the aggregate after-tax charge to earnings totaled $14.3 million at NU, $7.7 million at CL&P, $3.4 million at NSTAR Electric, $1.4 million at PSNH and $1.8 million at WMECO.

F.

CPSL

Since 2006, NSTAR Electric has been recovering incremental costs related to the DPU-approved Safety and Reliability Programs.  From 2006 through 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).  In October 2010, NSTAR Electric filed a reconciliation of the cumulative CPSL program activity for the periods 2006 through 2009 with the DPU in order to determine a proposed rate adjustment.  The DPU allowed the proposed rates to go into effect January 1, 2011, subject to final reconciliation of CPSL program costs through a future DPU proceeding.  In February 2013, NSTAR Electric updated the October 2010 filing with final activity through 2011.  NSTAR Electric recorded its 2006 through 2011 revenues under the CPSL programs based on the May 2010 Order.  

NSTAR Electric cannot predict the timing of a final DPU order related to its CPSL filings for the period 2006 through 2011.  While management does not believe that any subsequent DPU order would result in revenues that are 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.

G.

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.  In 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.  The DPU issued an order approving the implementation of a revised Basic Service rate but 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.

In 2010, NSTAR Electric filed an appeal of the DPU's order with the SJC.  In 2012, the SJC vacated the DPU order and remanded the matter to the DPU for further review.  The DPU has not taken any action on the remand.

NSTAR Electric deferred approximately $34 million of costs associated with energy-related bad debt as a regulatory asset through 2011 as NSTAR Electric had concluded that it was probable that these costs would ultimately be recovered from customers.  Due to the delays and the duration of the proceedings, 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 related to the regulatory asset in 2012.  NSTAR Electric will continue to maintain the reserve until the proceeding has been concluded with the DPU.  

10.

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 and Long-Term Debt:  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 long-term debt securities 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.  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 September 30, 2014				As of December 31, 2013
	NU				NU
	Carrying		Fair		Carrying		Fair
(Millions of Dollars)	Amount		Value		Amount		Value
Preferred Stock Not   Subject to Mandatory Redemption	$	155.6	$	151.0	$	155.6	$	152.7
Long-Term Debt		8,412.6		8,876.3		8,310.2		8,443.1

	As of September 30, 2014
	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	$	110.1	$	43.0	$	40.9	$	-	$	-	$	-	$	-
Long-Term Debt		2,841.8		3,189.5		1,797.4		1,959.4		999.2		1,046.4		628.7		667.4

35

	As of December 31, 2013
	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	$	110.5	$	43.0	$	42.2	$	-	$	-	$	-	$	-
Long-Term Debt		2,741.2		2,952.8		1,801.1		1,888.0		1,049.0		1,073.9		629.4		640.1

Derivative Instruments:  Derivative instruments are carried at fair value.  For further information, see Note 4, "Derivative Instruments," to the financial statements.  

Other Financial Instruments:  Investments in marketable securities are carried at fair value. For further information, see Note 5, "Marketable Securities," to the 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.

See Note 1D, "Summary of Significant Accounting Policies - Fair Value Measurements," for the fair value measurement policy and the fair value hierarchy.

11.

ACCUMULATED OTHER COMPREHENSIVE INCOME/(LOSS)

The changes in accumulated other comprehensive income/(loss) by component, net of tax, is as follows:

	For the Nine Months Ended September 30, 2014								For the Nine Months Ended September 30, 2013
			Unrealized		Pension,						Unrealized		Pension,
	Qualified		Gains/(Losses)		SERP and				Qualified		Gains/(Losses)		SERP and
	Cash Flow		on Available-		PBOP				Cash Flow		on Available-		PBOP
	Hedging		for-Sale		Benefit				Hedging		for-Sale		Benefit
(Millions of Dollars)	Instruments		Securities		Plans		Total		Instruments		Securities		Plans		Total
AOCI as of Beginning of Period	$	(14.4)	$	0.4	$	(32.0)	$	(46.0)	$	(16.4)	$	1.3	$	(57.8)	$	(72.9)
OCI Before Reclassifications		-		0.2		1.2		1.4		-		(0.8)		-		(0.8)
Amounts Reclassified from AOCI		1.5		-		2.9		4.4		1.5		-		4.8		6.3
Net OCI		1.5		0.2		4.1		5.8		1.5		(0.8)		4.8		5.5
AOCI as of End of Period	$	(12.9)	$	0.6	$	(27.9)	$	(40.2)	$	(14.9)	$	0.5	$	(53.0)	$	(67.4)

NU's qualified cash flow hedging instruments represent interest rate swap agreements on debt issuances that were settled in prior years.  The settlement amount was recorded in AOCI and is being amortized into Net Income over the term of the underlying debt instrument.  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, which are not material to their respective financial statements.

The following table sets forth the amounts reclassified from AOCI by component and the impacted line item on the statements of income:

	For the Three Months Ended				For the Nine Months Ended
	September 30,				September 30,
	Amounts Reclassified				Amounts Reclassified				Statements of Income
	from AOCI				from AOCI				Line Item Impacted
(Millions of Dollars)	2014		2013		2014		2013
Qualified Cash Flow Hedging Instruments	$	(0.8)	$	(0.8)	$	(2.5)	$	(2.5)	Interest Expense
Tax Benefit		0.3		0.3		1.0		1.0	Income Tax Expense
Qualified Cash Flow Hedging Instruments, Net of Tax	$	(0.5)	$	(0.5)	$	(1.5)	$	(1.5)
Pension, SERP and PBOP Benefit Plan Costs:
Amortization of Actuarial Losses	$	(1.6)	$	(2.5)	$	(4.7)	$	(7.3)	Operations and Maintenance (1)
Amortization of Prior Service Cost		-		-		(0.1)		(0.1)	Operations and Maintenance (1)
Total Pension, SERP and PBOP Benefit Plan Costs		(1.6)		(2.5)		(4.8)		(7.4)
Tax Benefit		0.6		0.9		1.9		2.6	Income Tax Expense
Pension, SERP and PBOP Benefit Plan Costs, Net of Tax	$	(1.0)	$	(1.6)	$	(2.9)	$	(4.8)
Total Amounts Reclassified from AOCI, Net of Tax	$	(1.5)	$	(2.1)	$	(4.4)	$	(6.3)

⁽¹⁾

These amounts are included in the computation of net periodic Pension, SERP and PBOP costs.  See Note 7, "Pension Benefits and Postretirement Benefits Other Than Pensions," for further information.

36

12.

COMMON SHARES

The following table sets forth the NU common shares and the shares of common stock of CL&P, NSTAR Electric, PSNH and WMECO that were authorized and issued and the respective per share par values:  

	Shares
			Authorized as of
	Per Share		September 30, 2014 and	Issued as of
	Par Value		December 31, 2013	September 30, 2014	December 31, 2013
NU	$	5	380,000,000	333,353,446	333,113,492
CL&P	$	10	24,500,000	6,035,205	6,035,205
NSTAR Electric	$	1	100,000,000	100	100
PSNH	$	1	100,000,000	301	301
WMECO	$	25	1,072,471	434,653	434,653

As of September 30, 2014 and December 31, 2013, there were 16,730,815 and 17,796,672 NU common shares held as treasury shares, respectively.  As of September 30, 2014 and December 31, 2013, NU common shares outstanding were 316,622,631 and 315,273,559, respectively.

13.

COMMON SHAREHOLDERS' EQUITY AND NONCONTROLLING INTERESTS

A summary of the changes in Common Shareholders' Equity and Noncontrolling Interests of NU is as follows:

	For the Three Months Ended
	September 30, 2014				September 30, 2013
			Noncontrolling				Noncontrolling
			Interest -				Interest -
	Common		Preferred		Common		Preferred
	Shareholders'		Stock of		Shareholders'		Stock of
(Millions of Dollars)	Equity		Subsidiaries		Equity		Subsidiaries
Balance as of Beginning of Period	$	9,753.8	$	155.6	$	9,406.6	$	155.6
Net Income		236.5		-		211.4		-
Dividends on Common Shares		(124.2)		-		(114.9)		-
Dividends on Preferred Stock		(1.9)		(1.9)		(1.9)		(1.9)
Issuance of Common Shares		1.0		-		1.4		-
Other Transactions, Net		24.1		-		12.8		-
Net Income Attributable to Noncontrolling Interests		-		1.9		-		1.9
Other Comprehensive Income		1.3		-		2.1		-
Balance as of End of Period	$	9,890.6	$	155.6	$	9,517.5	$	155.6

	For the Nine Months Ended
	September 30, 2014				September 30, 2013
			Noncontrolling				Noncontrolling
			Interest -				Interest -
	Common		Preferred		Common		Preferred
	Shareholders'		Stock of		Shareholders'		Stock of
(Millions of Dollars)	Equity		Subsidiaries		Equity		Subsidiaries
Balance as of Beginning of Period	$	9,611.5	$	155.6	$	9,237.1	$	155.6
Net Income		603.6		-		614.4		-
Dividends on Common Shares		(372.2)		-		(346.9)		-
Dividends on Preferred Stock		(5.6)		(5.6)		(5.8)		(5.8)
Issuance of Common Shares		6.4		-		10.2		-
Other Transactions, Net		41.0		-		3.0		-
Net Income Attributable to Noncontrolling Interests		-		5.6		-		5.8
Other Comprehensive Income		5.9		-		5.5		-
Balance as of End of Period	$	9,890.6	$	155.6	$	9,517.5	$	155.6

37

14.

EARNINGS PER SHARE

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 of certain share-based compensation awards as if they were converted into common shares.  There were no antidilutive share awards outstanding for the three and nine months ended September 30, 2014 or for the three months ended September 30, 2013.  For the nine months ended September 30, 2013, there were 2,100 antidilutive share awards excluded from the computation.

The following table sets forth the components of basic and diluted EPS:

		For the Three Months Ended				For the Nine Months Ended
(Millions of Dollars, except share information)		September 30, 2014		September 30, 2013		September 30, 2014		September 30, 2013
Net Income Attributable to Controlling Interest		$	234.6	$	209.5	$	597.9	$	608.6
Weighted Average Common Shares Outstanding:
	Basic		316,340,691		315,291,346		315,941,904		315,191,752
	Dilutive Effect		1,214,234		926,893		1,244,586		869,379
	Diluted		317,554,925		316,218,239		317,186,490		316,061,131
Basic and Diluted EPS		$	0.74	$	0.66	$	1.89	$	1.93

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).  

15.

SEGMENT INFORMATION

Presentation:  NU is organized between the Electric Distribution, Electric Transmission and Natural Gas Distribution reportable 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 reportable segments represented substantially all of NU's total consolidated revenues for the three and nine months ended September 30, 2014 and 2013.  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 reportable segment includes the generation activities of PSNH and WMECO.  

The remainder of NU's operations is presented as Other in the tables below and 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 expense related to the debt of NU parent, 2) the revenues and expenses of NU's service company, most of which are eliminated in consolidation, 3) the operations of CYAPC and YAEC, and 4) the results of other unregulated subsidiaries, which are not part of its core business.

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 expense.   

NU's reportable segments are determined 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.  NU's operating segments and reporting units are consistent with its reportable business segments.

NU's segment information is as follows:

	For the Three Months Ended September 30, 2014
	Electric		Natural Gas
(Millions of Dollars)	Distribution		Distribution		Transmission		Other		Eliminations		Total
Operating Revenues	$	1,502.6	$	109.2	$	262.5	$	211.2	$	(193.0)	$	1,892.5
Depreciation and Amortization		(71.7)		(16.4)		(37.4)		(13.8)		8.6		(130.7)
Other Operating Expenses		(1,141.5)		(98.4)		(74.2)		(192.4)		185.6		(1,320.9)
Operating Income/(Loss)		289.4		(5.6)		150.9		5.0		1.2		440.9
Interest Expense		(49.2)		(8.5)		(24.5)		(8.6)		1.0		(89.8)
Other Income, Net		9.3		0.1		2.7		226.4		(226.6)		11.9
Net Income Attributable to Controlling Interest	$	153.4	$	(9.9)	$	88.1	$	228.3	$	(225.3)	$	234.6

38

	For the Nine Months Ended September 30, 2014
	Electric		Natural Gas
(Millions of Dollars)	Distribution		Distribution		Transmission		Other		Eliminations		Total
Operating Revenues	$	4,350.4	$	737.5	$	721.4	$	568.1	$	(516.7)	$	5,860.7
Depreciation and Amortization		(309.9)		(51.1)		(111.4)		(28.3)		12.7		(488.0)
Other Operating Expenses		(3,343.9)		(586.2)		(211.5)		(534.1)		505.6		(4,170.1)
Operating Income		696.6		100.2		398.5		5.7		1.6		1,202.6
Interest Expense		(143.8)		(25.6)		(78.8)		(27.2)		3.2		(272.2)
Other Income, Net		13.6		0.2		6.9		657.9		(659.5)		19.1
Net Income Attributable to Controlling Interest	$	349.1	$	44.2	$	206.8	$	653.4	$	(655.6)	$	597.9
Cash Flows Used for Investments in Plant	$	480.1	$	120.6	$	469.9	$	46.9	$	-	$	1,117.5

	For the Three Months Ended September 30, 2013
	Electric		Natural Gas
(Millions of Dollars)	Distribution		Distribution		Transmission		Other		Eliminations		Total
Operating Revenues	$	1,508.6	$	97.1	$	234.1	$	212.5	$	(159.7)	$	1,892.6
Depreciation and Amortization		(159.6)		(16.4)		(34.5)		(11.2)		2.6		(219.1)
Other Operating Expenses		(1,064.1)		(89.4)		(73.4)		(206.8)		159.5		(1,274.2)
Operating Income/(Loss)		284.9		(8.7)		126.2		(5.5)		2.4		399.3
Interest Expense		(44.3)		(8.6)		(26.6)		(9.2)		1.2		(87.5)
Other Income, Net		5.5		0.5		2.9		312.1		(312.1)		8.9
Net Income/(Loss) Attributable to    Controlling Interest	$	156.9	$	(10.4)	$	58.6	$	313.1	$	(308.7)	$	209.5

	For the Nine Months Ended September 30, 2013
	Electric		Natural Gas
(Millions of Dollars)	Distribution		Distribution		Transmission		Other		Eliminations		Total
Operating Revenues	$	4,104.4	$	613.0	$	721.5	$	650.4	$	(565.8)	$	5,523.5
Depreciation and Amortization		(488.7)		(50.5)		(100.9)		(52.0)		7.2		(684.9)
Other Operating Expenses		(2,952.4)		(483.6)		(199.1)		(599.0)		564.3		(3,669.8)
Operating Income/(Loss)		663.3		78.9		421.5		(0.6)		5.7		1,168.8
Interest Expense		(129.9)		(24.8)		(73.7)		(26.3)		4.1		(250.6)
Other Income, Net		12.6		0.7		8.5		866.2		(866.3)		21.7
Net Income Attributable to Controlling Interest	$	347.5	$	34.1	$	215.4	$	868.7	$	(857.1)	$	608.6
Cash Flows Used for Investments in Plant	$	501.9	$	91.2	$	458.2	$	22.5	$	-	$	1,073.8

The following table summarizes NU's segmented total assets:
	Electric		Natural Gas
(Millions of Dollars)	Distribution		Distribution		Transmission		Other		Eliminations		Total
As of September 30, 2014	$	16,702.3	$	2,801.1	$	7,404.5	$	12,270.2	$	(11,195.8)	$	27,982.3
As of December 31, 2013		17,260.0		2,759.7		6,745.8		11,842.4		(10,812.4)		27,795.5

39

NORTHEAST UTILITIES AND SUBSIDIARIES

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

The following discussion and analysis should be read in conjunction with our unaudited condensed consolidated financial statements and related combined notes included in this combined Quarterly Report on Form 10-Q, the First and Second Quarter 2014 Quarterly Reports on Form 10-Q, and the 2013 Annual Report on Form 10-K.  References in this Form 10-Q to "NU," the "Company," "we," "us," and "our" refer to Northeast Utilities and its consolidated subsidiaries.  All per share amounts are reported on a diluted basis.  The unaudited condensed consolidated financial statements of NU, NSTAR Electric and PSNH and the unaudited condensed financial statements of CL&P and WMECO are herein collectively referred to as the "financial statements."

Refer to the Glossary of Terms included in this combined Quarterly Report on Form 10-Q 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 third quarter and first nine months of 2014 and 2013 earnings and EPS excluding certain integration costs related to NU's merger with NSTAR.  We use these non-GAAP financial measures to evaluate and to provide details of earnings by business and to more fully compare and explain our third quarter and first nine months of 2014 and 2013 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" and "Financial Condition and Business Analysis – Overview – Regulated Companies" in Management's Discussion and Analysis of Financial Condition and Results of Operations, herein.  

Forward-Looking Statements:  From time to time we make statements concerning our expectations, beliefs, plans, objectives, goals, strategies, assumptions of future events, future 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:

^·

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

^·

actions or inaction of 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,

^·

fluctuations in weather patterns,

^·

changes in laws, regulations or regulatory policy,

^·

changes in levels or 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 Quarterly Report on Form 10-Q and in NU's 2013 Annual Report on Form 10-K.  This Quarterly Report on Form 10-Q and NU's 2013 Annual Report on Form 10-K also describe material contingencies and critical accounting policies in the accompanying Management's Discussion and

40

Analysis of Financial Condition and Results of Operations and Combined Notes to Condensed Consolidated Financial Statements (Unaudited).  We encourage you to review these items.

Financial Condition and Business Analysis

Executive Summary

The following items in this executive summary are explained in more detail in this combined Quarterly Report on Form 10-Q:  

Results:

·

We earned $234.6 million, or $0.74 per share, in the third quarter of 2014 and $597.9 million, or $1.89 per share, in the first nine months of 2014, compared with $209.5 million, or $0.66 per share, in the third quarter of 2013 and $608.6 million, or $1.93 per share, in the first nine months of 2013.  Excluding integration costs, we earned $237.6 million, or $0.75 per share, in the third quarter of 2014 and $611.3 million, or $1.93 per share, in the first nine months of 2014, compared with $216.5 million, or $0.69 per share, in the third quarter of 2013, and $619.2 million, or $1.96 per share, in the first nine months of 2013.

·

Our electric distribution segment, which includes generation, earned $153.4 million, or $0.48 per share, in the third quarter of 2014 and $349.1 million, or $1.10 per share, in the first nine months of 2014, compared with earnings of $156.9 million, or $0.50 per share, in the third quarter of 2013 and $347.5 million, or $1.10 per share, in the first nine months of 2013.  

·

Our transmission segment earned $88.1 million, or $0.28 per share, in the third quarter of 2014 and $206.8 million, or $0.65 per share, in the first nine months of 2014, compared with $58.6 million, or $0.18 per share, in the third quarter of 2013 and $215.4 million, or $0.68 per share, in the first nine months of 2013.  The increase in the third quarter of 2014, as compared to the same period in 2013, was due primarily to the absence of an after-tax reserve of $14.3 million recorded in the third quarter of 2013 for the FERC ALJ initial decision in the FERC base ROE complaint.  The decrease in the first nine months of 2014, as compared to the same period in 2013, was due primarily to the after-tax reserve of $32.1 million recorded for the June 2014 FERC ROE orders, as compared to the $14.3 million reserve recorded in the third quarter of 2013.

·

Our natural gas distribution segment had a net loss of $9.9 million, or $0.03 per share, in the third quarter of 2014 and earnings of $44.2 million, or $0.14 per share, in the first nine months of 2014, compared with a net loss of $10.4 million, or $0.03 per share, in the third quarter of 2013 and earnings of $34.1 million, or $0.11 per share, in the first nine months of 2013.  

·

NU parent and other companies earned $3 million, or $0.01 per share, in the third quarter of 2014 and had a net loss of $2.2 million in the first nine months of 2014, compared with earnings of $4.4 million, or $0.01 per share, in the third quarter of 2013 and $11.6 million, or $0.04 per share, in the first nine months of 2013.  Third quarter and first nine months 2014 results reflect $3 million and $13.4 million, respectively, of after-tax integration costs.  Third quarter and first nine months 2013 results reflect $7 million and $10.6 million, respectively, of after-tax integration costs.  

Legislative, Regulatory and Other Items:

·

On September 16, 2014, NU and Spectra Energy Corp announced Access Northeast, a natural gas pipeline expansion project.  Access Northeast will enhance the Algonquin and Maritimes pipeline systems using existing routes.  NU and Spectra Energy Corp will have equal ownership interest in the project.  The total project cost, subject to FERC approval, is expected to be approximately $3 billion and has an anticipated in-service date of November 2018.

·

On October 16, 2014, the FERC issued an order on the base ROE complaint filed by several parties in September 2011.  The FERC order confirmed that the base ROE should be set at 10.57 percent and that a utility's total or maximum ROE inclusive of transmission incentive ROE adders should not exceed the top of the new zone of reasonableness (11.74 percent).   

·

In October 2014, the NHPUC concluded its hearings in the Clean Air Project prudence review to determine the prudent costs of PSNH’s compliance with the law requiring scrubber installation.  The NHPUC is expected to issue a decision on this matter by the end of 2014.  

Liquidity:

·

Cash and cash equivalents totaled $41.7 million as of September 30, 2014, compared with $43.4 million as of December 31, 2013, while investments in property, plant and equipment totaled $1.1 billion in both the first nine months of 2014 and 2013.  

·

Cash flows provided by operating activities totaled $1.4 billion in the first nine months of 2014, compared with $1.2 billion in the first nine months of 2013.  The improved operating cash flows were due primarily to approximately $132 million in DOE Damages proceeds resulting from the spent nuclear fuel litigation received by CL&P, NSTAR Electric, PSNH and WMECO from the Yankee Companies, the absence of cash disbursements for major storm restoration costs and the decrease of approximately $264 million in Pension and PBOP Plan cash contributions, partially offset by changes in the timing of working capital items and higher income tax payments in 2014, as compared to the same period in 2013.

41

·

In the first nine months of 2014, we issued $650 million of new long-term debt consisting of $100 million by Yankee Gas on January 2, 2014, $300 million by NSTAR Electric on March 7, 2014, and $250 million by CL&P on April 24, 2014.  Proceeds from these new issuances were used to repay approximately $525 million of existing long-term debt with remaining proceeds used to pay short-term borrowings.  

·

In the first nine months of 2014, we had cash dividends on common shares of $356.1 million, compared with $341.7 million in the first nine months of 2013.  On September 30, 2014, we paid a common dividend of $0.3925 per share, which was approved by our Board of Trustees on September 2, 2014, to shareholders of record as of September 15, 2014.  

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 the third quarter and first nine months of 2014 and 2013 is as follows:  

	For the Three Months Ended September 30,								For the Nine Months Ended September 30,
(Millions of Dollars, Except	2014				2013				2014				2013
Per Share Amounts)	Amount		Per Share		Amount		Per Share		Amount		Per Share		Amount		Per Share
Net Income Attributable to   Controlling Interest (GAAP)	$	234.6	$	0.74	$	209.5	$	0.66	$	597.9	$	1.89	$	608.6	$	1.93
Regulated Companies	$	231.6	$	0.73	$	205.1	$	0.65	$	600.1	$	1.89	$	597.0	$	1.89
NU Parent and Other Companies		6.0		0.02		11.4		0.04		11.2		0.04		22.2		0.07
Non-GAAP Earnings		237.6		0.75		216.5		0.69		611.3		1.93		619.2		1.96
Integration Costs (after-tax)		(3.0)		(0.01)		(7.0)		(0.03)		(13.4)		(0.04)		(10.6)		(0.03)
Net Income Attributable to   Controlling Interest (GAAP)	$	234.6	$	0.74	$	209.5	$	0.66	$	597.9	$	1.89	$	608.6	$	1.93

Excluding the impact of integration costs, our third quarter 2014 earnings increased by $21.1 million, as compared to the third quarter of 2013.  The increase was due primarily to lower operations and maintenance costs that impact earnings, which were primarily driven by lower labor and other employee-related costs, including pension costs, and the absence of an after-tax reserve of $14.3 million recorded in the third quarter of 2013 for the FERC ALJ initial decision in the FERC base ROE complaint.  Partially offsetting these favorable earnings impacts were higher property taxes, higher depreciation expense and lower retail electric sales volumes as a result of cooler summer weather in 2014, as compared to the same period in 2013.  

Excluding the impact of integration costs, our first nine months 2014 earnings decreased by $7.9 million, as compared to the first nine months of 2013, due primarily to the absence in 2014 of a favorable impact from the resolution of a state income tax audit in the first quarter of 2013, net of the favorable impact of a reduction in valuation allowance for state credits in the third quarter of 2014.  Earnings were also unfavorably impacted by the after-tax reserve of $32.1 million related to the second quarter 2014 FERC ROE orders, as compared to the $14.3 million reserve related to the third quarter 2013 FERC ALJ initial decision in the FERC base ROE complaints.  For further information, see "FERC Regulatory Issues – FERC Base ROE Complaints" in this Management's Discussion and Analysis of Financial Condition and Results of Operations.  In addition, earnings decreased due to higher depreciation expense at our regulated companies, higher property taxes and lower retail electric sales volumes as a result of cooler summer weather in 2014, as compared to the same period in 2013.  Earnings were favorably impacted by lower operations and maintenance costs that impact earnings, which were primarily driven by lower labor and other employee-related costs, including pension costs, and lower storm restoration costs, as well as higher firm natural gas sales volumes as a result of the colder weather in the first quarter of 2014, as compared to the first quarter of 2013.

Regulated Companies:  Our Regulated companies consist of the electric distribution, transmission, and natural gas distribution segments.  Generation activities of PSNH and WMECO are included in our electric distribution segment.  A summary of our segment earnings and EPS for the third quarter and first nine months of 2014 and 2013 is as follows:

	For the Three Months Ended September 30,								For the Nine Months Ended September 30,
(Millions of Dollars, Except	2014				2013				2014				2013
Per Share Amounts)	Amount		Per Share		Amount		Per Share		Amount		Per Share		Amount		Per Share
Electric Distribution	$	153.4	$	0.48	$	156.9	$	0.50	$	349.1	$	1.10	$	347.5	$	1.10
Transmission		88.1		0.28		58.6		0.18		206.8		0.65		215.4		0.68
Natural Gas Distribution		(9.9)		(0.03)		(10.4)		(0.03)		44.2		0.14		34.1		0.11
Net Income - Regulated Companies	$	231.6	$	0.73	$	205.1	$	0.65	$	600.1	$	1.89	$	597.0	$	1.89

Our electric distribution segment earnings decreased $3.5 million in the third quarter of 2014, as compared to the third quarter of 2013, due primarily to a 4.5 percent decrease in retail electric sales volumes as a result of cooler summer weather in 2014, higher depreciation expense and higher property taxes, partially offset by lower operations and maintenance costs that impact earnings, which were primarily driven by lower labor and other employee-related costs, including pension costs, and lower vegetation management costs, all as compared to the same period in 2013.

Our electric distribution segment earnings increased $1.6 million in the first nine months of 2014, as compared to the first nine months of 2013, due primarily to lower operations and maintenance costs that impact earnings, which were primarily driven by lower labor and other employee-related costs, including pension costs, and lower storm restoration costs.  Partially offsetting these favorable earnings impacts were higher depreciation expense, higher property taxes, lower retail electric sales volumes as a result of cooler summer weather in 2014, and the absence in 2014 of regulatory interest income from stranded cost recoveries in 2013, all as compared to the same period in 2013.

42

Our transmission segment earnings increased $29.5 million in the third quarter of 2014, as compared to the third quarter of 2013, due primarily to the absence of the after-tax reserve of $14.3 million recorded in the third quarter of 2013 for the FERC ALJ initial decision in the FERC base ROE complaint, a decrease in transmission segment state income tax expense, which includes the reduction in valuation allowance for state credits, and a higher transmission rate base as a result of an increased investment in our transmission infrastructure.

Our transmission segment earnings decreased $8.6 million in the first nine months of 2014, as compared to the first nine months of 2013, due primarily to the after-tax reserve of $32.1 million recorded for the June 2014 FERC ROE orders, as compared to the $14.3 million reserve recorded in the third quarter of 2013 for the FERC ALJ initial decision in the FERC base ROE complaints.  These unfavorable impacts were partially offset by a decrease in transmission segment state income tax expense, which includes the reduction in valuation allowance for state credits, and a higher transmission rate base as a result of an increased investment in our transmission infrastructure.

Our natural gas distribution segment results improved by $0.5 million in the third quarter of 2014, as compared to the third quarter of 2013, due primarily to higher peak demand revenues and higher firm natural gas sales volumes resulting from additional natural gas heating customers.  

Our natural gas distribution segment earnings increased $10.1 million in the first nine months of 2014, as compared to the first nine months of 2013, due primarily to higher firm natural gas sales volumes and peak demand revenues resulting from colder weather in the first quarter of 2014 and additional natural gas heating customers.

A summary of our retail electric GWh sales volumes and percentage changes, as well as percentage changes in CL&P, NSTAR Electric, PSNH and WMECO retail electric GWh sales volumes, is as follows:

	For the Three Months Ended September 30, 2014 Compared to 2013			For the Nine Months Ended September 30, 2014 Compared to 2013
	Sales Volumes (GWh)			Sales Volumes (GWh)		Percentage
NU – Electric	2014	2013	PercentageDecrease	2014	2013	Increase/ (Decrease)
Residential	5,656	6,102	(7.3)%	16,306	16,625	(1.9)%
Commercial	7,382	7,616	(3.1)%	20,838	21,064	(1.1)%
Industrial	1,517	1,529	(0.8)%	4,295	4,265	0.7 %
Total	14,555	15,247	(4.5)%	41,439	41,954	(1.2)%

Percentage	For the Three Months Ended September 30, 2014 Compared to 2013				For the Nine Months Ended September 30, 2014 Compared to 2013
Increase/(Decrease) Electric	CL&P	NSTAR Electric	PSNH	WMECO	CL&P	NSTAR Electric	PSNH	WMECO
Residential	(8.2)%	(6.6)%	(5.2)%	(9.2)%	(2.0)%	(2.4)%	(0.3)%	(2.6)%
Commercial	(3.3)%	(2.9)%	(2.6)%	(4.3)%	(1.1)%	(1.2)%	(0.4)%	(1.7)%
Industrial	(1.3)%	2.2  %	(1.5)%	(3.5)%	1.9 %	(0.4)%	1.5 %	(3.0)%
Total	(5.3)%	(3.8)%	(3.4)%	(6.2)%	(1.2)%	(1.5)%	- %	(2.3)%

A summary of our firm natural gas sales volumes in million cubic feet and percentage changes, as well as percentage changes in Yankee Gas and NSTAR Gas, is as follows:

	For the Three Months Ended September 30, 2014 Compared to 2013			For the Nine Months Ended September 30, 2014 Compared to 2013
	Sales Volumes (million cubic feet)		Percentage	Sales Volumes (million cubic feet)
NU – Firm Natural Gas	2014	2013	Increase/ (Decrease)	2014	2013	Percentage Increase
Residential	2,487	2,407	3.3 %	27,468	24,392	12.6%
Commercial	4,565	4,673	(2.3)%	31,032	28,066	10.6%
Industrial	4,276	4,093	4.4 %	16,669	15,588	6.9%
Total	11,328	11,173	1.4 %	75,169	68,046	10.5%
Total, Net of Special Contracts (1)	10,200	10,155	0.4 %	71,645	64,815	10.5%

	For the Three Months Ended September 30, 2014 Compared to 2013		For the Nine Months Ended September 30, 2014 Compared to 2013
Percentage Increase/(Decrease)	Sales Volumes (million cubic feet)		Sales Volumes (million cubic feet)
Firm Natural Gas	Yankee Gas	NSTAR Gas	Yankee Gas	NSTAR Gas
Residential	(0.6)%	6.3 %	14.0%	11.6%
Commercial	1.7 %	(6.2)%	14.0%	7.5%
Industrial	4.6 %	4.0 %	7.3%	5.9%
Total	2.8 %	(0.5)%	11.8%	9.1%
Total, Net of Special Contracts (1)	1.3 %		12.1%

⁽¹⁾

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.

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Weather, fluctuations in energy supply costs, conservation measures (including company-sponsored energy efficiency programs), and economic conditions affect customer energy usage.  Industrial sales are less sensitive to temperature variations than residential and commercial sales.  In our service territories, weather impacts electric sales during the summer and electric and natural gas sales during the winter (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.

For the third quarter of 2014, our consolidated retail electric sales volumes, consisting of the retail electric sales volumes of CL&P, NSTAR Electric, PSNH, and WMECO, were lower, as compared to the same period in 2013, as a result of cooler summer weather in 2014.  The third quarter of 2014 cooling degree days were 12 percent lower in Connecticut and western Massachusetts, 15 percent lower in the Boston metropolitan area, and 24 percent lower in New Hampshire, as compared to the third quarter of 2013.  Weather-normalized retail electric sales volumes (based on 30-year average temperatures) decreased 2.3 percent in the third quarter of 2014, as compared to the third quarter of 2013.  We believe the decrease was due primarily to increased conservation efforts by our residential and commercial customer classes, which are driven by the energy efficiency programs sponsored by CL&P, NSTAR Electric and WMECO.

For the first nine months of 2014, our consolidated retail electric sales volumes were lower, as compared to the same period in 2013, due primarily to cooler summer weather in 2014, partially offset by colder weather in the first quarter of 2014.  The first nine months of 2014 cooling degree days were 14 percent lower in Connecticut and western Massachusetts, 16 percent lower in the Boston metropolitan area, and 24 percent lower in New Hampshire, as compared to the first nine months of 2013.  Weather-normalized retail electric sales volumes decreased 0.9 percent in the first nine months of 2014, as compared to the first nine months of 2013.  We believe the decrease was due primarily to an increase in customer conservation efforts as noted above.

For WMECO, fluctuations in retail electric sales volumes do not impact earnings due to the DPU-approved revenue decoupling mechanism.  Under this decoupling mechanism, WMECO has an overall fixed annual level of distribution delivery service revenues of $132.4  million, comprised of customer base rate revenues of $125.4 million and a baseline low income discount recovery of $7 million.  These two mechanisms effectively break 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.  In addition, they have benefitted from historically favorable natural gas prices and customer growth across both operating companies.  In the third quarter and first nine months of 2014, consolidated firm natural gas sales volumes, consisting of the firm natural gas sales volumes of Yankee Gas and NSTAR Gas, were higher, as compared to the third quarter and first nine months of 2013, due primarily to colder weather in the first quarter of 2014, as compared to the same period in 2013, and increased customer growth in the first nine months of 2014, as compared to the same period in 2013.  The third quarter and first nine months of 2014 weather-normalized NU consolidated total firm natural gas sales volumes increased 1 percent and 3.6 percent, respectively, as compared to the same periods in 2013.

NU Parent and Other Companies:  NU parent and other companies, which includes our unregulated businesses, earned $3 million and had a net loss of $2.2 million in the third quarter and first nine months of 2014, respectively, compared with earnings of $4.4 million and $11.6 million in the third quarter and first nine months of 2013, respectively.  Excluding the impact of integration costs, NU parent and other companies earned $6 million and $11.2 million in the third quarter and first nine months of 2014, respectively, compared with $11.4 million and $22.2 million in the third quarter and first nine months of 2013, respectively.  The earnings decrease for the first nine months of 2014 was due primarily to the absence in 2014 of the favorable impact from the resolution of the Connecticut state income tax audit, which provided a $5.8 million earnings benefit to the first nine months of 2013.  

Liquidity

Consolidated:  Cash and cash equivalents totaled $41.7 million as of September 30, 2014, compared with $43.4 million as of December 31, 2013.

On July 15, 2014, PSNH repaid at maturity the $50 million of 5.25 percent Series L First Mortgage Bonds using short-term borrowings.

On September 15, 2014, CL&P repaid at maturity the $150 million of 4.80 percent 2004 Series A First Mortgage Bonds.

On October 14, 2014, PSNH issued $75 million of first mortgage bonds at a yield of 3.144 percent that will mature on November 1, 2023.  The first mortgage bonds are part of the same series of PSNH’s existing 3.50 percent Series S First Mortgage Bonds that were initially issued in November 2013.  As a result, the aggregate principal amount of PSNH’s outstanding Series S First Mortgage Bonds totals $325 million.  The proceeds, net of issuance costs, were used to repay short-term borrowings.  

On August 27, 2014, PURA approved CL&P's request to extend the authorization period for issuance of up to $366.4 million in long-term debt from December 31, 2014 to December 31, 2015.

Effective July 23, 2014, NU parent, CL&P, PSNH, WMECO, NSTAR Gas and Yankee Gas extended the expiration date of their joint $1.45 billion revolving credit facility for one additional year to September 6, 2019.  The revolving credit facility is to be used primarily to backstop NU parent's $1.45 billion commercial paper program.  The commercial paper program allows NU parent to issue commercial paper as a form of short-term debt.  As of September 30, 2014 and December 31, 2013, NU had $964.5 million and $1.01 billion, respectively, in short-term borrowings outstanding under the NU parent commercial paper program, leaving $485.5 million and $435.5 million of available borrowing capacity as of September 30, 2014 and December 31, 2013, respectively.  The weighted-average interest rate on these borrowings as of September 30, 2014 and December 31, 2013 was 0.25 percent and 0.24 percent, respectively, which is generally based on A2/P2 rated commercial paper.  As of September 30, 2014, there were intercompany loans from NU of $105.4 million to CL&P, $153.3 million to PSNH and $13.2 million to WMECO.  As of December 31, 2013, there were intercompany loans from NU of $287.3 million to CL&P and $86.5 million to PSNH.  

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Effective July 23, 2014, NSTAR Electric extended the expiration date of its $450 million revolving credit facility for one additional year to September 6, 2019.  This facility serves to backstop NSTAR Electric's existing $450 million commercial paper program.  As of September 30, 2014 and December 31, 2013, NSTAR Electric had $159.5 million and $103.5 million, respectively, in short-term borrowings outstanding under its commercial paper program, leaving $290.5 million and $346.5 million of available borrowing capacity as of September 30, 2014 and December 31, 2013, respectively.  The weighted-average interest rate on these borrowings as of September 30, 2014 and December 31, 2013 was 0.16 percent and 0.13 percent, respectively, which is generally based on A2/P1 rated commercial paper.

Cash flows provided by operating activities totaled $1.4 billion in the first nine months of 2014, compared with $1.2 billion in the first nine months of 2013.  The improved operating cash flows were due primarily to approximately $132 million in DOE Damages proceeds resulting from the spent nuclear fuel litigation received by CL&P, NSTAR Electric, PSNH and WMECO from the Yankee Companies, the absence of cash disbursements for major storm restoration costs and the decrease of approximately $264 million in Pension and PBOP Plan cash contributions, partially offset by changes in the timing of working capital items and income tax payments of $256 million for the first nine months of 2014, compared to $34 million for the same period in 2013.  For further information on the spent nuclear fuel litigation, see Note 9C, "Commitments and Contingencies – Contractual Obligations – Yankee Companies," in this combined Quarterly Report on Form 10-Q.  

In the first nine months of 2014, we had cash dividends on common shares of $356.1 million, compared with $341.7 million in the first nine months of 2013.  On September 30, 2014, we paid a common dividend of $0.3925 per share, which was approved by our Board of Trustees on September 2, 2014, to shareholders of record as of September 15, 2014.

In the first nine months of 2014, CL&P, NSTAR Electric, PSNH, and WMECO paid $128.4 million, $253 million, $49.5 million, and $49 million, respectively, in common dividends to NU parent.  

Investments in Property, Plant and Equipment on the statements of cash flows 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 expense.  In the first nine months of 2014, investments for NU, CL&P, NSTAR Electric, PSNH, and WMECO were $1.1 billion, $371.7 million, $309.2 million, $170.1 million, and $82.5 million, respectively.  

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 expense (all of which are non-cash factors), totaled $1.1 billion in the first nine months of both 2014 and 2013.  These amounts included $40.9 million and $14.7 million in the first nine months of 2014 and 2013, respectively, related to our corporate service companies, NUSCO and RRR.

Access Northeast:  On September 16, 2014, NU and Spectra Energy Corp announced Access Northeast, a natural gas pipeline expansion project.  Access Northeast will enhance the Algonquin and Maritimes pipeline systems using existing routes and is expected to be capable of delivering approximately one billion cubic feet of natural gas per day to New England.  NU and Spectra Energy Corp will have equal ownership interest in the project with the option of additional investors joining in the future.  The total project cost, subject to FERC approval, is expected to be approximately $3 billion and has an anticipated in-service date of November 2018.

Transmission Business:  Overall, transmission business capital expenditures increased by $33.5 million in the first nine months of 2014, as compared to the first nine months of 2013.  A summary of transmission capital expenditures by company for the first nine months of 2014 and 2013 is as follows:

	For the Nine Months Ended September 30,
(Millions of Dollars)	2014		2013
CL&P	$	201.5	$	133.5
NSTAR Electric		111.1		140.0
PSNH		76.9		58.0
WMECO		50.1		62.0
NPT		19.4		32.0
Total Transmission Segment	$	459.0	$	425.5

NEEWS:  GSRP, the first, largest and most complicated project within the NEEWS family of projects was fully energized on November 20, 2013.  As of September 30, 2014, CL&P and WMECO had placed $640 million in service with minimal remaining close-out activities continuing throughout the remainder of 2014.

The Interstate Reliability Project (IRP) is the second major NEEWS project.  It 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 in Rhode Island and Massachusetts.  As of May 2014, all three states have issued siting approvals.  The Army Corps of Engineers issued its permit on the project (the last required project permit) in the first quarter of 2014.  Project construction is underway in all three states.  NU's portion of the cost is estimated to be $218 million and construction on its portion of the project was approximately 62 percent complete as of September 30, 2014.  

The Greater Hartford Central Connecticut Study (GHCC) includes the reassessment of the Central Connecticut Reliability Project and continues to make progress.  The final need results showed existing and worsening severe regional and local thermal overloads and voltage violations within each

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of the areas studied and across the interfaces of those areas.  These results were presented to the ISO-NE Planning Advisory Committee in November 2013.  On July 15, 2014, ISO-NE presented the preferred transmission solutions to its Planning Advisory Committee.  These solutions are comprised of many 115 kV upgrades that are expected to cost approximately $350 million and be placed in service from 2016 through 2018.  We expect to begin work on the initial solutions in late 2015 and complete GHCC-related work in 2018.

Included as part of NEEWS are several associated reliability related projects, $93.1 million of which have been placed in service.  As of the second quarter of 2014, all construction on the associated reliability related projects was completed.  

Through September 30, 2014, CL&P and WMECO capitalized $323.6 million and $573.6 million, respectively, in costs associated with NEEWS, of which $70.8 million and $6.6 million, respectively, were capitalized in the first nine months of 2014.  Included in the NEEWS amounts are costs for IRP, of which CL&P capitalized $140.9 million in costs through September 30, 2014, and $67.9 million related to costs capitalized in the first nine months of 2014.

Northern Pass:  Northern Pass is NU'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.  NPT received ISO-NE approval under Section I.3.9 of the ISO tariff in 2013.  By approving the project's Section I.3.9 application, ISO-NE determined that Northern Pass can reliably interconnect with the New England grid with no significant adverse effect on the reliability or operating characteristics of the regional energy grid and its participants.  The DOE continues to work on the draft Environmental Impact Statement (EIS) for Northern Pass.  This includes a review of our proposed route and various alternative routes.  We now expect the DOE to issue the draft EIS in March 2015.  We expect to file the state permit application in the second quarter of 2015 after receipt of the draft EIS.  The expected $1.4 billion project is subject to comprehensive federal and state public permitting processes and is now expected to be operational in the second half of 2018.

Greater Boston Reliability Solutions: As a result of continued analysis of the transmission needs to enhance system reliability and improve capacity in eastern Massachusetts, NSTAR Electric and PSNH expect to implement a series of new transmission initiatives over the next five years.  For a portion of these new transmission initiatives, ISO-NE and state regulators must decide between two alternative transmission solutions.  We expect ISO-NE to select the preferred solution in late 2014 or early 2015.  If ISO-NE selects our solution, which is the lower overall capital cost plan, then our investments are estimated to be $489 million.  If the alternate plan is chosen, then we still expect to invest approximately $356 million.  

Distribution Business:  A summary of distribution capital expenditures by company for the first nine months of 2014 and 2013 is as follows:

	For the Nine Months Ended September 30,
(Millions of Dollars)	2014		2013
CL&P:
Basic Business	$	70.2	$	42.7
Aging Infrastructure		81.1		116.6
Load Growth		49.7		56.9
Total CL&P		201.0		216.2
NSTAR Electric:
Basic Business		75.4		84.6
Aging Infrastructure		76.0		75.0
Load Growth		25.8		22.5
Total NSTAR Electric		177.2		182.1
PSNH:
Basic Business		33.1		13.7
Aging Infrastructure		24.2		32.2
Load Growth		21.4		18.3
Total PSNH		78.7		64.2
WMECO:
Basic Business		6.2		5.3
Aging Infrastructure		10.2		16.7
Load Growth		3.6		5.7
Total WMECO		20.0		27.7
Total - Electric Distribution (excluding Generation)		476.9		490.2
PSNH Generation		11.3		5.5
WMECO Generation		7.5		0.9
Total - Natural Gas		138.9		126.7
Total Electric and Natural Gas Distribution Segment	$	634.6	$	623.3

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

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FERC Regulatory Issues

FERC Base ROE Complaints:

First Complaint: On September 30, 2011, a complaint was filed jointly at FERC under Sections 206 and 306 of the Federal Power Act (the "first complaint") by several New England state attorneys general, state regulatory commissions, consumer advocates and other parties (the "Complainants").  The Complainants alleged that the base ROE of 11.14 percent that has been utilized since 2006 in the calculation of formula rates for transmission service under the ISO-NE Open Access Transmission Tariff by NETOs, including CL&P, NSTAR Electric, PSNH and WMECO, was unjust and unreasonable and asserted that the rate was excessive due to changes in the capital markets.  Complainants sought an order to reduce the base ROE prospectively from the date of a final FERC order (the "FERC order date"), and for the 15-month period October 1, 2011 to December 31, 2012 (the "first complaint refund period"), and to require refunds.  The FERC set the case for trial before a FERC ALJ after settlement negotiations were unsuccessful in August 2012.

On August 6, 2013, the FERC ALJ issued an initial decision on the first complaint finding that the base ROE in effect during the first complaint refund period was not reasonable and recommended separate base ROEs for the first complaint refund period of 10.6 percent and for the period beginning when FERC issues its final decision (the "prospective period") of 9.7 percent, leaving policy considerations and additional adjustments to the FERC.  In the third quarter of 2013, the Company recorded a series of reserves at its electric subsidiaries to recognize the potential financial impact from the FERC ALJ's initial decision for the first complaint refund period.  See Cumulative Reserves below for further information on the reserves recorded in the third quarter of 2013.   

On June 19, 2014, FERC issued an order on the first complaint, partially affirming and partially reversing the FERC ALJ's initial decision.  FERC set a single tentative base ROE of 10.57 percent for the first complaint refund period and prospective period.  FERC also modified its traditional methodology by adopting a two-step discounted cash flow analysis that it utilizes to determine the ROEs of both natural gas and oil pipeline projects.  Using this methodology, FERC determined a new zone of reasonableness of 7.03 percent to 11.74 percent, and set the tentative base ROE halfway between the midpoint and the top of the zone of reasonableness.  FERC also stated that a utility's “total ROE, inclusive of transmission incentive ROE adders” should not exceed the top of the new zone of reasonableness produced by this methodology.  FERC instituted a paper hearing on the long-term growth rate portion of the methodology (the "paper hearing").  Rehearing requests on this new methodology were filed in July, and briefs were filed in August and September by the parties on the appropriate long-term growth rate.  In the second quarter of 2014, the Company recorded additional reserves at its electric subsidiaries to recognize the potential financial impact from the FERC’s June 19^th order.  See Cumulative Reserves below for further information on the reserves recorded in the second quarter of 2014.  

On October 16, 2014, the FERC issued an order in the paper hearing, which confirmed that the base ROE should be set at 10.57 percent and that a utility’s total or maximum ROE should not exceed the top of the new zone of reasonableness (11.74 percent).  The FERC ordered the NETOs to provide refunds to customers for the first complaint refund period, and set the new base ROE prospectively from the order date.  

Second Complaint: On December 27, 2012, a second complaint was filed jointly at FERC by several additional consumer groups and municipal parties (the "second complaint"), which challenged the NETOs' base ROE prospectively from the FERC order date and sought refunds for the 15-month period January 1, 2013 to March 31, 2014 (the "second complaint refund period").

On June 19, 2014, FERC issued an order finding that the second complaint raised issues of material fact.  On July 21, 2014, the NETOs filed a rehearing request in this proceeding.  On October 24, 2014, the FERC assigned the case for trial before a FERC ALJ after settlement negotiations were unsuccessful.  The FERC ALJ has set a trial date beginning June 8, 2015, and will issue an initial decision on or before October 26, 2015.  In the second quarter of 2014, the Company recorded reserves at its electric subsidiaries to recognize the potential financial impact from the FERC’s June 19^th order for the second complaint refund period.  See Cumulative Reserves below for further information on the reserves recorded in the second quarter of 2014.  

Third Complaint: On July 31, 2014, a third complaint was filed at FERC (the "third complaint") by most of the complainants to the first and second complaints, claiming that the base ROE and incentive adders exceed the range of permissible ROEs, requesting FERC to reduce the NETO’s base ROE prospectively from the FERC order date, and seeking refunds for the 15-month period beginning August 1, 2014 (the "third complaint refund period").  FERC has taken no action on this complaint to date.  At this time, the Company cannot determine the outcome of this complaint.

Cumulative Reserves:  The following is a summary as of September 30, 2014 of the cumulative reserves (excluding interest) that the Company established in the third quarter of 2013 and the second quarter of 2014 to recognize the potential financial impacts of the first and second complaints.  Management is currently evaluating the impact of the October 16^th order on the previously established reserves.

	NU
		Third Quarter		Second Quarter
(Millions of Dollars)		2013		2014	Total
1st Complaint - Base ROE	$	23.7	$	1.2	$	24.9
2nd Complaint - Base ROE		-		27.4		27.4
Incentive ROE (1st and 2nd Complaint)		-		23.8		23.8
Cumulative Reserve	$	23.7	$	52.4	$	76.1

The aggregate after-tax charge to second quarter 2014 earnings resulting from the June 19, 2014 FERC orders totaled $32.1 million at NU, $18.5 million at CL&P, $6.1 million at NSTAR Electric, $2 million at PSNH and $5.5 million at WMECO.  In the third quarter of 2013, the aggregate after-tax charge to earnings totaled $14.3 million at NU, $7.7 million at CL&P, $3.4 million at NSTAR Electric, $1.4 million at PSNH and $1.8 million at WMECO.

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FERC Order No. 1000:  On August 15, 2014, the D.C. Circuit Court of Appeals upheld FERC's authority to order major changes to transmission planning and cost allocation in FERC Order No. 1000 and Order No. 1000-A, including transmission planning for public policy needs, and the requirement that utilities remove from their transmission tariffs their rights of first refusal to build transmission.  FERC has not yet ruled on the comprehensive compliance filings made in November of 2013 by the NETOs, including CL&P, NSTAR Electric, PSNH and WMECO.  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.  While the FERC Orders may bring new challenges, we believe there are also opportunities for us to compete for transmission reliability projects outside of our service territories.

Regulatory Developments and Rate Matters

The Regulated companies' distribution rates are set by their respective state regulatory commissions, and their tariffs include mechanisms for periodically adjusting their rates for the recovery of specific incurred costs.  Other than as described below, for the first nine months of 2014, changes made to the Regulated companies' rates did not have a material impact on their earnings, financial position, or cash flows.  For further information, see "Financial Condition and Business Analysis – Regulatory Developments and Rate Matters" included in Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations," of the NU 2013 Annual Report on Form 10-K.

Connecticut:

Distribution Rates:  On June 9, 2014, CL&P filed an application with the PURA to amend customer rates, effective December 1, 2014.  The application included an increase to base distribution rates, as well as increases for the annual recovery of previously approved 2011 and 2012 deferred storm restoration costs and previously approved electric system resiliency costs.  Hearings were held in late August through the end of September 2014, followed by the legal briefing process.  After the briefing process, CL&P updated its requested increase to reflect a reduction to the storm cost recovery amounts.  The reduction primarily relates to applying the impact of the $65.4 million DOE Phase II Damages proceeds received on June 1, 2014 to the total deferred storm restoration costs of $365 million, as ordered by PURA on June 17, 2014.  A final decision is expected in December 2014.  A summary of the annual increase in distribution rates requested in the initial application and the current request is as follows:

(Millions of Dollars)	Base Distribution Rate Increase		2011 and 2012 Storm Cost Recovery		System Resiliency Cost Recovery		Total Distribution Rate Increase
Initial Application	$	116.7	$	89.5	$	25.3	$	231.5
Adjustments		5.7		(16.2)		-		(10.5)
Current Request	$	122.4	$	73.3	$	25.3	$	221.0

Massachusetts:

DPU Storm Penalties:  In December 2012, in separate orders issued by the DPU, the DPU ordered penalties of $4.1 million and $2 million for NSTAR Electric and WMECO, respectively, related to the electric utilities’ responses to Tropical Storm Irene and the October 2011 snowstorm, which were refunded to their customers.  In December 2012, NSTAR Electric and WMECO each filed appeals with the SJC arguing the DPU penalties should be vacated.

On September 4, 2014, the SJC vacated $2 million of NSTAR Electric's $4.1 million penalties.  The SJC found that certain of the penalties were not supported by substantial evidence.  The remaining penalties, as well as the $2 million in penalties related to WMECO, were upheld.

New Hampshire:

Generation:  In 2013, the NHPUC opened a docket to investigate market conditions affecting PSNH's ES 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.  

On April 1, 2014, the NHPUC staff issued a "Preliminary Status Report Addressing the Economic Interest of PSNH's Retail Customers as it Relates to the Potential Divestiture of PSNH's Generating Plants," which included a consultant's analysis of the fair market value of PSNH generating assets and long-term power purchase contracts.  The consultant's analysis estimated the fair market value of PSNH's generation assets to be $225 million as of December 31, 2013 and compared that amount to a stated net book value of $660 million, implying potential "stranded costs" in excess of $400 million.  NHPUC staff made three recommendations: (1) that any further actions relating to PSNH's generating assets await a final decision in the Clean Air Project (scrubber) prudence proceeding; (2) that existing laws regarding divestiture, energy service, and cost recovery be harmonized; and (3) that ISO-NE provide input on the economic and reliability consequences of retirement of PSNH's coal- and oil-fired electric generating plants.

During its 2014 session, in response to the NHPUC staff report, the Legislature enacted changes to the laws governing divestiture of PSNH's generation assets, effective September 30, 2014.  The new law requires the NHPUC to initiate a proceeding before January 1, 2015, to determine whether all or some of PSNH's generation assets should be divested.  The NHPUC opened its docket DE 14-238 on September 16, 2014 and a Prehearing Conference was held on October 2, 2014.  A progress report from the NHPUC must be made by March 31, 2015.  The law also gives the NHPUC express authority to order the divestiture of all or some of PSNH's generation assets if the NHPUC finds it is in the economic interest of customers to do so.  The law also clarified the definition of "stranded costs" to include costs approved for recovery by the NHPUC in connection with the divestiture or retirement of PSNH's generation assets.  

In the event of generation asset divestiture or retirement, present law and the PSNH Restructuring Settlement Agreement approved in 2000 require that the NHPUC provide recovery of any stranded costs by PSNH.  We continue to believe generation investments and prudently-incurred costs are probable of recovery.

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Clean Air Project Prudence Proceeding:  The Clean Air Project, which involved the installation of wet scrubber technology at PSNH’s Merrimack coal-fired generation station in Bow, New Hampshire, was placed in service in September 2011.  In November 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.  In April 2012, the NHPUC issued an order authorizing temporary rates to recover a significant portion of the Clean Air Project costs.  The docket will remain open to conduct a comprehensive prudence review of the Clean Air Project and the establishment of permanent rates.  The temporary rates will remain in effect until permanent rates allowing full recovery of all prudently incurred costs are approved.  At that time, the NHPUC will reconcile recoveries collected under the temporary rates with approved permanent rates.

The NHPUC concluded its hearings in October 2014 to determine the prudent costs of PSNH’s compliance with the law requiring scrubber installation.  The NHPUC is expected to issue a decision on this matter by the end of 2014.  We continue to believe that we were prudent in the undertaking and completion of the Clean Air Project.  While we cannot predict with certainty the outcome of the Clean Air Project prudence review, we believe all costs were incurred appropriately and are probable of recovery.

Legislative and Policy Matters

Massachusetts:

Gas Replacement and Expansion:  On July 7, 2014, Massachusetts enacted "An Act Relative to Natural Gas Leaks" (the Act).  The Act establishes a uniform natural gas leak classification standard for all Massachusetts natural gas utilities and a program that accelerates the replacement of aging natural gas infrastructure.  The program will enable companies, including NSTAR Gas, to better manage the scheduling and costs of replacement.  The Act also calls for the DPU to authorize natural gas utilities to design and offer programs to customers that will increase the availability, affordability and feasibility of natural gas service for new customers.  

NSTAR Gas filed the Gas System Enhancement Program (GSEP) with the DPU on October 31, 2014.  The program accelerates the replacement of gas distribution facilities composed of leak prone materials to eliminate leak prone infrastructure in the system within 25 years.  The GSEP includes a new tariff that provides NSTAR Gas an opportunity to collect the costs for the program on an annual basis through a newly designed reconciling factor to be approved by the DPU.

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 that we believed were the most critical in nature were reported in the NU 2013 Form 10-K.  There have been no material changes with regard to these critical accounting policies.  

Other Matters

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

Contractual Obligations and Commercial Commitments:  Refer to Note 9B, "Commitments and Contingencies – Long-Term Contractual Arrangements," for discussion of material changes to contractual obligations.

Web Site:  Additional financial information is available through our web site at www.nu.com.  Information contained on the Company's website or that can be accessed through the website is not incorporated into and does not constitute a part of this Quarterly Report on Form 10-Q.

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RESULTS OF OPERATIONS – NORTHEAST UTILITIES AND SUBSIDIARIES

The following provides the amounts and variances in operating revenues and expense line items in the statements of income for NU for the three and nine months ended September 30, 2014 and 2013 included in this Quarterly Report on Form 10-Q:  

			For the Three Months Ended September 30,								For the Nine Months Ended September 30,
							Increase/								Increase/
(Millions of Dollars)			2014		2013		(Decrease)		Percent		2014		2013		(Decrease)		Percent
Operating Revenues			$	1,892.5	$	1,892.6	$	(0.1)	-	%	$	5,860.7	$	5,523.5	$	337.2	6.1	%
Operating Expenses:
	Purchased Power, Fuel and Transmission			716.6		645.9		70.7	10.9			2,319.0		1,882.0		437.0	23.2
	Operations and Maintenance			344.1		386.7		(42.6)	(11.0)			1,069.0		1,090.0		(21.0)	(1.9)
	Depreciation			153.2		149.1		4.1	2.7			456.2		463.6		(7.4)	(1.6)
	Amortization of Regulatory   Assets/(Liabilities), Net			(22.5)		70.0		(92.5)	(a)			31.8		178.7		(146.9)	(82.2)
	Amortization of Rate Reduction Bonds			-		-		-	-			-		42.6		(42.6)	(100.0)
	Energy Efficiency Programs			118.7		106.1		12.6	11.9			360.2		306.0		54.2	17.7
	Taxes Other Than Income Taxes			141.5		135.5		6.0	4.4			421.9		391.8		30.1	7.7
		Total Operating Expenses		1,451.6		1,493.3		(41.7)	(2.8)			4,658.1		4,354.7		303.4	7.0
Operating Income				440.9		399.3		41.6	10.4			1,202.6		1,168.8		33.8	2.9
Interest Expense				89.7		87.5		2.2	2.5			272.2		250.6		21.6	8.6
Other Income, Net				11.8		8.9		2.9	32.6			19.0		21.6		(2.6)	(12.0)
Income Before Income Tax Expense				363.0		320.7		42.3	13.2			949.4		939.8		9.6	1.0
Income Tax Expense				126.5		109.3		17.2	15.7			345.9		325.4		20.5	6.3
Net Income				236.5		211.4		25.1	11.9			603.5		614.4		(10.9)	(1.8)
Net Income Attributable to Noncontrolling   Interests				1.9		1.9		-	-			5.6		5.8		(0.2)	(3.4)
Net Income Attributable to Controlling Interest			$	234.6	$	209.5	$	25.1	12.0	%	$	597.9	$	608.6	$	(10.7)	(1.8)	%
Operating Revenues
			For the Three Months Ended September 30,								For the Nine Months Ended September 30,
							Increase/								Increase/
(Millions of Dollars)			2014		2013		(Decrease)		Percent		2014		2013		(Decrease)		Percent
Electric Distribution			$	1,502.6	$	1,508.6	$	(6.0)	(0.4)	%	$	4,350.4	$	4,104.4	$	246.0	6.0	%
Natural Gas Distribution				109.2		97.1		12.1	12.5			737.5		613.0		124.5	20.3
	Total Distribution			1,611.8		1,605.7		6.1	0.4			5,087.9		4,717.4		370.5	7.9
Transmission				262.5		234.1		28.4	12.1			721.4		721.5		(0.1)	-
	Total Regulated Companies			1,874.3		1,839.8		34.5	1.9			5,809.3		5,438.9		370.4	6.8
Other and Eliminations				18.2		52.8		(34.6)	(65.5)			51.4		84.6		(33.2)	(39.2)
Total Operating Revenues			$	1,892.5	$	1,892.6	$	(0.1)	-	%	$	5,860.7	$	5,523.5	$	337.2	6.1	%
(a)  Percent greater than 100 percent not shown as it is not meaningful.
A summary of our retail electric sales volumes and firm natural gas sales volumes were as follows:
			For the Three Months Ended September 30,								For the Nine Months Ended September 30,
							Increase/								Increase/
			2014		2013		(Decrease)		Percent		2014		2013		(Decrease)		Percent
Retail Electric Sales Volumes in GWh				14,555		15,247		(692)	(4.5)	%		41,439		41,954		(515)	(1.2)	%
Firm Natural Gas Sales Volumes in    Million Cubic Feet				11,328		11,173		155	1.4			75,169		68,046		7,123	10.5

Three Months Ended:

In the third quarter of 2014 compared to the third quarter of 2013, Operating Revenues remained essentially flat.  

Electric base distribution revenues decreased $22.6 million compared to the same period in 2013, reflecting a 4.5 percent decrease in retail electric sales volumes.  The decrease in sales volumes reflects the cooler summer weather in 2014 as well as the impact of our utility-sponsored energy efficiency programs.  There was an increase in revenues related to the higher costs associated with purchasing electricity and natural gas on behalf of our customers.  Fluctuations in these energy supply costs are recovered from customers in rates and have no impact on earnings.  Firm natural gas sales volumes increased 1.4 percent from the third quarter of 2013 as customer growth and economic conditions in our service territory have shown steady improvement over the past year.  

As noted above, our respective utility-sponsored energy efficiency programs have the impact of reducing both retail electric and firm natural gas sales.  CL&P and NSTAR Electric bill customers for lost base revenues related to reductions in sales volume as a result of their energy efficiency.  We recognized $15.8 million of lost base revenue in the third quarter of 2014 compared to $5.5 million during the same period of 2013.

Transmission revenues increased in the third quarter of 2014, as compared to the third quarter of 2013, as a result of the recovery of higher transmission expenses including ongoing investments in our transmission infrastructure.

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Nine Months Ended:

In the first nine months of 2014 compared to the first nine months of 2013, Operating Revenues increased $337.2 million.  

The most significant factor in the revenue increase was the overall impact of the recovery of costs associated with the procurement of energy supply.  The costs incurred to procure energy were significantly higher in 2014 than in 2013.  Our energy supply costs were impacted by higher natural gas transportation costs which, in addition to its impact on the cost of natural gas purchased on behalf of our retail natural gas customers, had an adverse impact on the cost of electric energy purchased for our retail electric customers.  Fluctuations in energy supply costs are recovered from customers in rates and have no impact on earnings.  

Firm base natural gas revenues increased $25.9 million reflecting an increase of approximately 10.5 percent in firm natural gas sales volumes.  The increase in sales volumes was driven primarily by the cold winter weather experienced throughout our service territories in the first quarter of 2014.  The winter was significantly colder than both normal and the same period last year throughout New England.  Weather-normalized total firm natural gas sales volumes (based on 30-year average temperatures) increased 3.6 percent in the first nine months of 2014, as compared to the same period in 2013, due primarily to residential and commercial customer growth.

In the first nine months of 2014, base electric distribution revenues decreased $16 million, compared to the first nine months of 2013.  This decrease reflects a 1.2 percent reduction in sales volumes.  The decrease in sales volumes reflects the cooler summer weather in 2014 as well as the impact of our utility-sponsored energy efficiency programs, partially offset by colder winter weather in the first quarter of 2014.  Weather-normalized retail electric sales volumes decreased 0.9 percent in the first nine months of 2014, as compared to the same period in 2013, reflecting the impact of our utility-sponsored energy efficiency programs.  

CL&P and NSTAR Electric bill customers for lost base revenues related to reductions in sales volume as a result of their energy efficiency.  We recognized $31.9 million of lost base revenue in the first nine months of 2014 compared to $14.6 million during the same period of 2013.

Transmission revenues remained essentially flat in the first nine months of 2014, as compared to the first nine months of 2013, due primarily to the impact of the reserve recorded in the second quarter of 2014 as a result of the June 2014 FERC ROE orders as compared to the reserve recorded in the third quarter of 2013 for the FERC ALJ initial decision in the FERC base ROE complaints.  For further information, see "FERC Regulatory Issues - FERC Base ROE Complaints" in this Management's Discussion and Analysis of Financial Condition and Results of Operations.

Purchased Power, Fuel and Transmission expense includes costs associated with purchasing electricity and natural gas on behalf of our customers.  These energy supply costs are recovered from customers in rates through cost tracking mechanisms, which have no impact on earnings (tracked costs).  Purchased Power, Fuel and Transmission increased for the three and nine months ended September 30, 2014, as compared to the same periods in 2013, due primarily to the following:

	Three Months Ended		Nine Months Ended
(Millions of Dollars)	Increase/(Decrease)		Increase/(Decrease)
Electric Distribution	$	87.9	$	366.0
Natural Gas Distribution		10.6		79.7
Transmission		-		(3.2)
Other and Eliminations		(27.8)		(5.5)
Total Purchased Power, Fuel and Transmission	$	70.7	$	437.0

The increase in purchased power at the electric and natural gas distribution businesses were driven by the higher costs associated with the procurement of energy supply.  Our energy supply costs were impacted by higher natural gas transportation costs which, in addition to its impact on the cost of natural gas purchased on behalf of our retail natural gas customers, had an adverse impact on the cost of electric energy purchased for our retail electric customers.  

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Operations and Maintenance expense includes tracked costs and costs that are recovered through base electric and natural gas distribution rates (and therefore impact earnings).  Operations and Maintenance decreased for the three and nine months ended September 30, 2014, as compared to the same periods in 2013, due primarily to the following:

	Three Months Ended		Nine Months Ended
(Millions of Dollars)	Increase/(Decrease)		Increase/(Decrease)
Base Electric Distribution:
Labor and other employee-related costs, including pension costs	$	(18.8)	$	(62.3)
Implementation of a new outage restoration program at CL&P		4.8		9.7
Vegetation management costs		(4.7)		(0.9)
Storm restoration costs		(1.6)		(10.1)
Other operations and maintenance		(4.1)		21.6
Total Base Electric Distribution		(24.4)		(42.0)
Total Base Natural Gas Distribution		(0.6)		2.3
Total Base Electric and Natural Gas Distribution		(25.0)		(39.7)
Total Tracked costs (Transmission and Electric and Natural Gas Distribution)		(3.6)		19.9
Total Distribution and Transmission		(28.6)		(19.8)
Other and eliminations:
Integration and severance costs		(7.0)		4.5
All other (including eliminations)		(7.0)		(5.7)
Total Operations and Maintenance	$	(42.6)	$	(21.0)

Depreciation increased for the three months ended September 30, 2014, as compared to the same period in 2013 due primarily to higher utility plant balances resulting from completed construction projects placed into service ($8.8 million), partially offset by a decrease in CYAPC and YAEC decommissioning costs, which do not impact earnings ($4.7 million).  For the nine months ended September 30, 2014, depreciation expense decreased due primarily to a decrease in the CYAPC and YAEC decommissioning costs, which do not impact earnings ($29.7 million), partially offset by an increase related to higher utility plant balances resulting from completed construction projects placed into service ($22.3 million).  

Amortization of Regulatory Assets/(Liabilities), Net, which are tracked costs, include certain regulatory-approved tracking mechanisms.  Fluctuations in these costs are recovered from customers in rates and have no impact on earnings.  Amortization of Regulatory Assets/(Liabilities), Net, decreased for the three and nine months ended September 30, 2014, as compared to the same periods in 2013, due primarily to the following:

	Three Months Ended		Nine Months Ended
(Millions of Dollars)	Increase/(Decrease)		Increase/(Decrease)
NSTAR Electric (primarily deferred transition costs)	$	(87.8)	$	(174.2)
PSNH (primarily default energy service charge)		(10.0)		(15.9)
CL&P (primarily energy supply and energy-related costs)		13.1		51.4
WMECO (primarily deferred transition costs)		(7.1)		(7.2)
Other		(0.7)		(1.0)
Total Amortization of Regulatory Assets/(Liabilities), Net	$	(92.5)	$	(146.9)

Amortization of Rate Reduction Bonds decreased for the nine months ended September 30, 2014, as compared to the same period in 2013, due to the maturity in 2013 of RRBs of NSTAR Electric, PSNH, and WMECO.

Energy Efficiency Programs, which are tracked costs, increased for the three and nine months ended September 30, 2014, as compared to the same periods in 2013, due primarily to an increase in energy efficiency costs in accordance with the three-year program guidelines established by the DPU at NSTAR Electric and WMECO and expanded energy conservation programs at CL&P in 2014 as a result of 2013 legislative action, partially offset by a decrease in the amortization of previously deferred costs at NSTAR Electric.  

Taxes Other Than Income Taxes increased for the three and nine months ended September 30, 2014, as compared to the same periods in 2013, due primarily to an increase in property taxes as a result of both an increase in utility plant balances and property tax rates, combined with a decrease and increase, respectively, in the Connecticut gross earnings tax for the three months and nine months ended, attributable to fluctuations in retail revenues.

Interest Expense increased for the three and nine months ended September 30, 2014, as compared to the same periods in 2013,  due primarily to the absence in 2014 of the favorable impact from the resolution of a Connecticut state income tax audit in the first quarter of 2013 ($8.8 million), lower interest income from a decrease in the recovery of previously deferred transition costs ($0.5 million and $8.2 million, respectively), and an increase in interest on long-term debt ($0.3 million and $3.9 million, respectively) as a result of new debt issuances in the first and second quarters of 2014.

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Other Income, Net increased for the three months ended September 30, 2014, as compared to the same period in 2013, due primarily to a gain on the sale of land ($4.5 million), and higher AFUDC related to equity funds ($3.8 million), partially offset by lower unrealized gains on assets supporting the deferred compensation plans ($3.1 million) and the absence in 2014 of an insurance policy claim received in 2013 ($2.6 million).  Other Income, Net decreased for the nine months ended September 30, 2014, as compared to the same period in 2013, due primarily to lower unrealized gains on the assets supporting the deferred compensation plans ($6.5 million), and the absence in 2014 of an insurance policy claim received in 2013 ($2.6 million), partially offset by higher AFUDC related to equity funds ($3.8 million), and a net gain on the sale of land ($4.5 million).

Income Tax Expense increased for the three months ended September 30, 2014, as compared to the same period in 2013, due primarily to higher pre-tax earnings ($14.9 million), and higher state taxes, which includes the reduction in valuation allowance for state credits, and various other impacts ($2.3 million).

Income Tax Expense increased for the nine months ended September 30, 2014, as compared to the same period in 2013, due primarily to higher pre-tax earnings ($6.5 million), and higher state taxes, which includes the reduction in valuation allowance for state credits, and various other impacts ($14 million).

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RESULTS OF OPERATIONS – THE CONNECTICUT LIGHT AND POWER COMPANY

The following  provides the amounts and variances in operating revenues and expense line items in the statements of income for CL&P for the three and nine months ended September 30, 2014 and 2013 included in this Quarterly Report on Form 10-Q:  

			For the Three Months Ended September 30,								For the Nine Months Ended September 30,
							Increase/								Increase/
(Millions of Dollars)			2014		2013		(Decrease)		Percent		2014		2013		(Decrease)		Percent
Operating Revenues			$	695.6	$	648.4	$	47.2	7.3	%	$	2,017.6	$	1,841.8	$	175.8	9.5	%
Operating Expenses:
	Purchased Power and Transmission			255.8		253.1		2.7	1.1			737.0		667.3		69.7	10.4
	Operations and Maintenance			127.2		127.1		0.1	0.1			368.6		359.7		8.9	2.5
	Depreciation			46.9		44.8		2.1	4.7			139.6		132.3		7.3	5.5
	Amortization of Regulatory Assets, Net			13.1		-		13.1	100.0			62.6		11.2		51.4	(a)
	Energy Efficiency Programs			41.4		24.5		16.9	69.0			119.4		68.2		51.2	75.1
	Taxes Other Than Income Taxes			65.0		65.0		-	-			194.1		182.7		11.4	6.2
		Total Operating Expenses		549.4		514.5		34.9	6.8			1,621.3		1,421.4		199.9	14.1
Operating Income				146.2		133.9		12.3	9.2			396.3		420.4		(24.1)	(5.7)
Interest Expense				38.7		35.3		3.4	9.6			110.4		99.0		11.4	11.5
Other Income, Net				6.4		3.9		2.5	64.1			10.6		10.9		(0.3)	(2.8)
Income Before Income Tax Expense				113.9		102.5		11.4	11.1			296.5		332.3		(35.8)	(10.8)
Income Tax Expense				30.0		36.2		(6.2)	(17.1)			95.9		113.1		(17.2)	(15.2)
Net Income			$	83.9	$	66.3	$	17.6	26.5	%	$	200.6	$	219.2	$	(18.6)	(8.5)	%
(a) Percent greater than 100 percent not shown as it is not meaningful.
Operating Revenues
CL&P's retail sales volumes were as follows:
			For the Three Months Ended September 30,								For the Nine Months Ended September 30,
			2014		2013		Decrease		Percent		2014		2013		Decrease		Percent
Retail Sales Volumes in GWh				5,791		6,119		(328)	(5.3)	%		16,790		16,993		(203)	(1.2)	%

CL&P's Operating Revenues increased in the third quarter of 2014, as compared to the same period of 2013.  The increase primarily reflects the overall impact of higher costs associated with the procurement of energy supply.  Our energy supply costs were impacted by higher natural gas transportation costs, which had an adverse impact on the cost of electric energy purchased for our retail customers.  Fluctuations in energy supply costs are recovered from customers in rates and have no impact on earnings.  The increase was also driven by a higher level of recovery related to CL&P's energy efficiency programs, which has no impact on earnings, as a result of 2013 legislative action.  Partially offsetting this increase was a decrease in retail sales volumes in the third quarter of 2014, as compared to the same period in 2013, as a result of cooler summer weather in 2014.

CL&P's Operating Revenues increased in the first nine months of 2014, as compared to the first nine months of 2013.  The increase primarily reflects the overall impact of higher costs associated with the procurement of energy supply.  The energy supply costs were impacted by higher natural gas transportation costs, which had an adverse impact on the cost of electric energy purchased for our retail customers.  Fluctuations in energy supply costs are recovered from customers in rates and have no impact on earnings.  The increase was also driven by a higher level of recovery related to CL&P's energy efficiency programs, which has no impact on earnings, as a result of 2013 legislative action.  Partially offsetting this increase was the impact of the reserve recorded in the second quarter of 2014 as a result of the June 2014 FERC ROE orders as compared to the reserve recorded in the third quarter of 2013 for the FERC ALJ initial decision in the FERC base ROE complaints.  For further information, see "FERC Regulatory Issues - FERC Base ROE Complaints" in this Management's Discussion and Analysis of Financial Condition and Results of Operations.

Purchased Power and Transmission expense includes costs associated with purchasing electricity on behalf of CL&P's customers.  These energy supply costs are recovered from customers in PURA-approved cost tracking mechanisms, which have no impact on earnings (tracked costs).  Purchased Power and Transmission increased for the three and nine months ended September 30, 2014, as compared to the same periods in 2013, due primarily to the following:

	Three Months Ended		Nine Months Ended
(Millions of Dollars)	Increase/(Decrease)		Increase/(Decrease)
Purchased Power Costs	$	42.4	$	111.2
Transmission Costs		(34.4)		(22.6)
Other		(5.3)		(18.9)
Total Purchased Power and Transmission	$	2.7	$	69.7

Included in Purchased Power are the costs associated with CL&P's generation services charge (GSC) and deferred energy costs.  The GSC 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 increase in purchased power was due primarily to higher average supply prices and increased load as a result of customers returning to standard offer from third party suppliers.  The decrease in transmission costs was the result of a decrease in the retail transmission cost deferral, which reflects the actual costs of transmission service compared to estimated amounts billed to customers.  

Operations and Maintenance expense includes tracked costs and costs that are recovered through base electric distribution rates (and therefore impact earnings).  Operations and Maintenance expenses were relatively flat in the third quarter of 2014, as compared to the same period in 2013.  

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Tracked costs, which have no earnings impact, increased $4.5 million, which was primarily attributable to higher hardship and other tracked bad debt expense.  This increase was offset by a decrease in costs that impact earnings of $4.4 million, which was primarily attributable to lower labor and other employee-related costs, including pension costs, and lower routine vegetation management costs, partially offset by an increase in costs for the implementation of a new outage restoration program that began in the second quarter of 2014.

Operations and Maintenance increased for the nine months ended September 30, 2014, as compared to the same period in 2013, driven by a $14.2 million increase in tracked costs, which have no earnings impact, which was primarily attributable to higher hardship and other tracked bad debt expense.  Partially offsetting this increase was a $5.3 million decrease in costs that impact earnings, which was primarily attributable to lower labor and other employee-related costs, including pension costs, and lower storm restoration costs, partially offset by an increase in costs for the implementation of a new outage restoration program that began in the second quarter of 2014.

Depreciation increased for the three and nine months ended September 30, 2014, as compared to the same periods in 2013, due primarily to higher utility plant balances resulting from completed construction projects placed into service.  

Amortization of Regulatory Assets, Net¸ increased for the three and nine months ended September 30, 2014, as compared to the same periods in 2013.  Fluctuations in energy supply and energy-related costs, which are the primary drivers in amortization, are recovered from customers in rates and have no impact on earnings.  

Energy Efficiency Programs, which are tracked costs, increased for the three and nine months ended September 30, 2014, as compared to the same periods in 2013, due primarily to expanded energy conservation programs in 2014 as a result of 2013 legislative action.

Taxes Other Than Income Taxes did not materially change for the three months ended September 30, 2014 and increased for the nine months ended September 30, 2014, as compared to the same periods in 2013, due primarily to an increase in property taxes as a result of both an increase in utility plant balances and property tax rates, and a decrease and increase, respectively, in the Connecticut gross earnings tax for the three months and nine months ended attributable to fluctuations in retail revenues.

Interest Expense increased for the three and nine months ended September 30, 2014, as compared to the same periods in 2013, due primarily to the absence in 2014 of the favorable impact from the resolution of a state income tax audit in the first quarter of 2013 ($6 million), an increase in interest on long-term debt ($1.9 million and $4.1 million, respectively) as a result of a new debt issuance in April 2014, and an increase in regulatory interest due to the refund of the DOE proceeds in the third quarter of 2014 ($1.2 million).

Other Income, Net increased for the three months ended September 30, 2014, as compared to the same period in 2013, due primarily to a gain on the sale of land ($4.5 million), higher AFUDC related to equity funds ($0.4 million), partially offset by lower unrealized gains on the assets supporting the deferred compensation plans ($2.4 million).

Income Tax Expense decreased for the three months ended September 30, 2014, as compared to the same period in 2013, due primarily to lower state tax expense, which includes the reduction in valuation allowance for state credits, and various other impacts ($10.2 million), partially offset by higher pre-tax earnings ($4 million).

Income Tax Expense decreased for the nine months ended September 30, 2014, as compared to the same period in 2013, due primarily to lower pre-tax earnings ($11.1 million) and lower state taxes, which includes the reduction in valuation allowance for state credits, and various other impacts ($6.1 million).

EARNINGS SUMMARY

CL&P's third quarter 2014 earnings were higher than the same period in 2013 due primarily to the absence of an after-tax reserve of $7.7 million recorded in the third quarter of 2013 for the FERC ALJ initial decision in the FERC base ROE complaints, lower income tax expense due to the reduction in valuation allowance, and a decrease in operations and maintenance costs attributable to lower employee-related costs.  Partially offsetting these favorable earnings impacts were lower retail electric sales volumes as a result of cooler summer weather in 2014, as compared to the same period in 2013, higher depreciation expense and higher property taxes.

For the nine months ended September 30, 2014, CL&P's earnings decreased, as compared to the same period in 2013, due primarily to the after-tax reserve recorded for the second quarter 2014 FERC ROE orders as compared to the reserve recorded in the third quarter 2013 for the FERC ALJ initial decision in the FERC base ROE complaints ($10.8 million increase), higher property tax expense and higher interest expense.  Partially offsetting these unfavorable earnings impacts were lower income tax expense due to the reduction in valuation allowance and a decrease in operations and maintenance costs primarily attributable to lower employee-related costs.

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LIQUIDITY

CL&P had cash flows provided by operating activities of $483 million in the first nine months of 2014, compared with $308.6 million in the first nine months of 2013.  The improved operating cash flows were due primarily to $68.6 million in DOE damages proceeds received in 2014 from the Yankee Companies associated with the spent nuclear fuel litigation, the absence of cash disbursements for major storm restoration costs, an increase in regulatory overrecoveries, partially offset by changes in working capital items, an unfavorable cash flow impact relating to income tax payments of $85.3 million in the first nine months of 2014, as compared to income tax payments of $41.2 million in the first nine months of 2013.

Investments in Property, Plant and Equipment on the statements of cash flows 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 expense.  In the first nine months of 2014, investments for CL&P were $371.7 million.

Effective July 23, 2014, NU parent and certain of its subsidiaries, including CL&P, extended the expiration date of their joint $1.45 billion revolving credit facility for one additional year to September 6, 2019.  The revolving credit facility is to be used primarily to backstop NU parent's $1.45 billion commercial paper program.  The commercial paper program allows NU parent to issue commercial paper as a form of short-term debt to its subsidiaries, including CL&P.  As of September 30, 2014 and December 31, 2013, there were intercompany loans from NU parent of $105.4 million and $287.3 million, respectively, to CL&P.

On September 15, 2014, CL&P repaid at maturity the $150 million of 4.80 percent 2004 Series A First Mortgage Bonds.

On August 27, 2014, PURA approved CL&P's request to extend the authorization period for issuance of up to $366.4 million in long-term debt from December 31, 2014 to December 31, 2015.

Financing activities in the first nine months of 2014 included $128.4 million in common stock dividends paid to NU parent.

56

RESULTS OF OPERATIONS – NSTAR ELECTRIC COMPANY AND SUBSIDIARY

The following provides the amounts and variances in operating revenues and expense line items in the statements of income for NSTAR Electric for the nine months ended September 30, 2014 and 2013 included in this Quarterly Report on Form 10-Q:  

			For the Nine Months Ended September 30,
(Millions of Dollars)			2014		2013		Increase/		Percent
							(Decrease)
Operating Revenues			$	1,955.6	$	1,916.6	$	39.0	2.0	%
Operating Expenses:
	Purchased Power and Transmission			879.8		659.1		220.7	33.5
	Operations and Maintenance			244.6		277.3		(32.7)	(11.8)
	Depreciation			141.0		136.3		4.7	3.4
	Amortization of Regulatory Assets/(Liabilities), Net			(0.9)		173.3		(174.2)	(a)
	Amortization of Rate Reduction Bonds			-		15.1		(15.1)	(100.0)
	Energy Efficiency Programs			145.5		161.2		(15.7)	(9.7)
	Taxes Other Than Income Taxes			99.1		95.3		3.8	4.0
		Total Operating Expenses		1,509.1		1,517.6		(8.5)	(0.6)
Operating Income				446.5		399.0		47.5	11.9
Interest Expense				59.1		51.6		7.5	14.5
Other Income, Net				3.0		3.3		(0.3)	(9.1)
Income Before Income Tax Expense				390.4		350.7		39.7	11.3
Income Tax Expense				156.6		137.5		19.1	13.9
Net Income			$	233.8	$	213.2	$	20.6	9.7	%
(a) Percent greater than 100 percent not shown as it is not meaningful.
Operating Revenues
NSTAR Electric's retail sales volumes were as follows:
			For the Nine Months Ended September 30,
			2014		2013		Decrease		Percent
Retail Sales Volumes in GWh				15,958		16,204		(246)	(1.5)	%

NSTAR Electric's Operating Revenues increased in the first nine months of 2014, as compared to the first nine months of 2013.  The increase primarily reflects the overall impact of higher costs associated with the procurement of energy supply.  Our energy supply costs were impacted by higher natural gas transportation costs, which had an adverse impact on the cost of electric energy purchased for our retail customers.  Fluctuations in energy supply costs are recovered from customers in rates and have no impact on earnings.  Partially offsetting this increase was the impact of the reserve recorded in the second quarter of 2014 as a result of the June 2014 FERC ROE orders as compared to the reserve recorded in the third quarter of 2013 for the FERC ALJ initial decision in the FERC base ROE complaints.  For further information, see "FERC Regulatory Issues - FERC Base ROE Complaints" in this Management's Discussion and Analysis of Financial Condition and Results of Operations.  Additionally, transition cost recovery revenues decreased during the period, reflecting the full collection in 2013 of previously deferred costs, as well as the full amortization of RRBs.  Base distribution revenues decreased in the first nine months of 2014, as compared to the same period in 2013, which was due primarily to cooler summer weather and customer savings due to the impact of energy efficiency programs.  NSTAR Electric is permitted to bill customers for lost base revenues related to reductions in sales volume as a result of their energy efficiency.  In the first nine months of 2014, including the impact from the recognition of lost base revenues, base distribution revenues were flat, compared to the first nine months of 2013.  

Purchased Power and Transmission expense includes costs associated with purchasing electricity on behalf of NSTAR Electric's customers.  These energy supply costs are recovered from customers in DPU-approved cost tracking mechanisms which have no impact on earnings (tracked costs).  Purchased Power and Transmission increased for the nine months ended September 30, 2014, as compared to the same period in 2013, due primarily to the following:  

(Millions of Dollars)	Increase
Purchased Power Costs	$	167.6
Transmission Costs		49.0
Other		4.1
Total Purchased Power and Transmission	$	220.7

The increase in purchased power was due primarily to higher energy supply prices.  The increase in transmission costs was due primarily to higher RNS expense.

Operations and Maintenance expense includes tracked costs and costs that are recovered through base electric distribution rates (and therefore impact earnings).  Operations and Maintenance decreased for the nine months ended September 30, 2014, as compared to the same period in 2013, driven by a $36.9 million reduction in costs that impact earnings, which was primarily attributable to lower labor and other employee-related costs.  Partially offsetting this decrease was a $4.2 million increase in tracked costs, which have no earnings impact, which was primarily attributable to an increased level of recovery of deferred storm costs.

Depreciation increased for the nine months ended September 30, 2014, as compared to the same period in 2013, due primarily to higher utility plant balances resulting from completed construction projects placed into service.  

57

Amortization of Regulatory Assets/(Liabilities), Net, reflects a decrease in the recovery of previously deferred tracked transition costs for the nine months ended September 30, 2014, as compared to the same period in 2013.  Fluctuations in these costs are recovered from customers in rates and have no impact on earnings.  

Amortization of Rate Reduction Bonds decreased for the nine months ended September 30, 2014, as compared to the same period in 2013, due to the maturity of the RRBs in March 2013.

Energy Efficiency Programs, which are tracked costs, decreased for the nine months ended September 30, 2014, as compared to the same period in 2013, due primarily to a decrease in the amortization of previously deferred costs.  This was partially offset by an increase in energy efficiency costs incurred in accordance with the three-year program guidelines established by the DPU.  

Taxes Other Than Income Taxes increased for the nine months ended September 30, 2014, as compared to the same period in 2013, due to an increase in property taxes as a result of both an increase in utility plant balances and property tax rates.

Interest Expense increased for the nine months ended September 30, 2014, as compared to the same period in 2013, due primarily to lower interest income from a decrease in the recovery of previously deferred transition costs ($8.7 million), partially offset by a decrease in interest on long-term debt ($0.8 million).

Income Tax Expense increased for the nine months ended September 30, 2014, as compared to the same period in 2013, due primarily to higher pre-tax earnings ($13.8 million) and higher state taxes ($5.3 million).

EARNINGS SUMMARY

For the nine months ended September 30, 2014, NSTAR Electric's earnings increased, as compared to the same period in 2013, due primarily to lower operations and maintenance costs primarily attributable to lower employee-related costs.  Partially offsetting the favorable earnings impact were the after-tax reserve recorded for the second quarter 2014 FERC ROE orders as compared to the reserve recorded in the third quarter 2013 for the FERC ALJ initial decision in the FERC base ROE complaints ($2.7 million increase), higher interest expense, higher depreciation expense and higher property tax expense.   

LIQUIDITY

NSTAR Electric had cash flows provided by operating activities of $517.5 million in the first nine months of 2014, compared with $317.6 million in the first nine months of 2013.  The improved operating cash flows were due primarily to the absence of cash disbursements for major storm restoration costs associated with the February 2013 blizzard, collections of accounts receivable from affiliated companies, $30.2 million in DOE Damages proceeds in 2014 from the Yankee Companies associated with the spent nuclear fuel litigation and the absence of Pension Plan cash contributions in the first nine months of 2014, as compared to contributions of $82 million in the first nine months of 2013.  These favorable cash flow impacts were partially offset by the absence of costs recovered in rates related to the RRBs that were fully amortized in the first quarter of 2013 and an increase in income taxes paid.

Effective July 23, 2014, NSTAR Electric extended the expiration date of its $450 million revolving credit facility for one additional year to September 6, 2019.  This facility serves to backstop NSTAR Electric's existing $450 million commercial paper program.  As of September 30, 2014 and December 31, 2013, NSTAR Electric had $159.5 million and $103.5 million, respectively, in short-term borrowings outstanding under its commercial paper program, leaving $290.5 million and $346.5 million, respectively, of available borrowing capacity.  The weighted-average interest rate on these borrowings as of September 30, 2014 and December 31, 2013 was 0.16 percent and 0.13 percent, respectively, which is generally based on A2/P1 rated commercial paper.  

58

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

The following provides the amounts and variances in operating revenues and expense line items in the statements of income for PSNH for the nine months ended September 30, 2014 and 2013 included in this Quarterly Report on Form 10-Q:  

			For the Nine Months Ended September 30,
								Increase/
(Millions of Dollars)			2014		2013			(Decrease)		Percent
Operating Revenues			$	735.1	$		708.6	$	26.5	3.7	%
Operating Expenses:
	Purchased Power, Fuel and Transmission			248.0			197.8		50.2	25.4
	Operations and Maintenance			198.0			191.6		6.4	3.3
	Depreciation			73.2			68.4		4.8	7.0
	Amortization of Regulatory Assets/(Liabilities), Net			(17.6)			(1.7)		(15.9)	(a)
	Amortization of Rate Reduction Bonds			-			19.7		(19.7)	(100.0)
	Energy Efficiency Programs			10.9			11.0		(0.1)	(0.9)
	Taxes Other Than Income Taxes			53.1			52.7		0.4	0.8
		Total Operating Expenses		565.6			539.5		26.1	4.8
Operating Income				169.5			169.1		0.4	0.2
Interest Expense				34.0			34.2		(0.2)	(0.6)
Other Income, Net				1.7			2.4		(0.7)	(29.2)
Income Before Income Tax Expense				137.2			137.3		(0.1)	(0.1)
Income Tax Expense				52.2			52.8		(0.6)	(1.1)
Net Income			$	85.0	$		84.5	$	0.5	0.6	%
(a) Percent greater than 100 percent not shown as it is not meaningful.
Operating Revenues
PSNH's retail sales volumes were as follows:
			For the Nine Months Ended September 30,
			2014		2013			Decrease		Percent
Retail Sales Volumes in GWh				5,970		5,971			(1)	-	%

PSNH's Operating Revenues increased in the first nine months of 2014, as compared to the first nine months of 2013, due primarily to the overall impact of higher costs associated with the procurement of energy supply.  The energy supply costs were impacted by higher natural gas transportation costs, which had an adverse impact on the cost of electric energy purchased for our retail customers.  Fluctuations in energy supply costs are recovered from customers in rates and therefore have no impact on earnings.  Also reflected in the revenue increase were increases of $6.7 million related to NHPUC-approved distribution rate increases effective July 1, 2013 and increases in transmission revenues as a result of the recovery of higher transmission expenses including ongoing investments in our transmission infrastructure, partially offset by the impact of the reserve recorded in the second quarter of 2014 as a result of the June 2014 FERC ROE orders as compared to the reserve recorded in the third quarter of 2013 for the FERC ALJ initial decision in the FERC base ROE complaints.  For further information, see "FERC Regulatory Issues - FERC Base ROE Complaints" in this Management's Discussion and Analysis of Financial Condition and Results of Operations.  

Purchased Power, Fuel and Transmission expense includes costs associated with PSNH's generation of electricity as well as purchasing electricity on behalf of its customers.  These energy supply costs are recovered from customers in NHPUC-approved cost tracking mechanisms, which have no impact on earnings (tracked costs).  Purchased Power, Fuel and Transmission increased for the nine months ended September 30, 2014, as compared to the same period in 2013, due primarily to the following:

(Millions of Dollars)	Increase/(Decrease)
Generation Fuel Costs	$	43.0
Transmission Costs		12.3
Purchased Power Costs		(11.5)
Other		6.4
Total Purchased Power, Fuel and Transmission	$	50.2

The increase in generation fuel costs was due primarily to an increase in the amount of electricity generated by PSNH facilities.  The decrease in purchased power costs was a result of purchasing less power due to increased PSNH generation. The increase in transmission costs was as a result of an increase in the retail transmission cost deferral, which reflects the actual costs of transmission service compared to estimated amounts billed to customers.

Operations and Maintenance expense includes tracked costs and costs that are recovered through base electric distribution rates (and therefore impact earnings).  Operations and Maintenance increased for the nine months ended September 30, 2014, as compared to the same period in 2013, driven by a $6.2 million increase in tracked costs, which have no earnings impact, which was primarily attributable to higher operations and maintenance costs at the generation business due to the timing of planned outages, partially offset by lower labor and other employee-related costs, including pension costs.

Depreciation increased for the nine months ended September 30, 2014, as compared to the same period in 2013, due primarily to higher utility plant balances resulting from completed construction projects placed into service.  

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Amortization of Regulatory Assets/(Liabilities), Net, reflects a decrease in the recovery of the default energy service charge and other amortizations for the nine months ended September 30, 2014, as compared to the same period in 2013.  Fluctuations in these costs are recovered from customers in rates and have no impact on earnings.  

Amortization of Rate Reduction Bonds decreased for the nine months ended September 30, 2014, as compared to the same period in 2013, due to the maturity of the RRBs in May 2013.

Income Tax Expense decreased for the nine months ended September 30, 2014, as compared to the same period in 2013, due primarily to various tax impacts ($0.6 million).

EARNINGS SUMMARY

For the nine months ended September 30, 2014, PSNH's earnings increased, as compared to the same period in 2013, due primarily to higher distribution retail revenues, which were favorably impacted by the PSNH annualized distribution rate increases effective July 1, 2013.  Partially offsetting this favorable earnings impact were the after-tax reserve recorded for the second quarter 2014 FERC ROE orders as compared to the reserve recorded in the third quarter 2013 for the FERC ALJ initial decision in the FERC base ROE complaints ($0.6 million increase), and higher depreciation expense.  

LIQUIDITY

PSNH had cash flows provided by operating activities of $205.8 million in the first nine months of 2014, compared with $160.4 million in the first nine months of 2013.  The improved cash flows were due primarily to $14.5 million in DOE Damages proceeds in 2014 from the Yankee Companies associated with the spent nuclear fuel litigation, the absence of $108.3 million in Pension Plan cash contributions in the first nine months of 2014, and the favorable impact of the 2010 rate case settlement related to the additional increase to annualized rates that was effective July 1, 2013.  These favorable cash flow impacts were partially offset by changes in working capital amounts, income tax payments of $9 million in the first nine months of 2014, compared with income tax refunds of $8.7 million in the first nine months of 2013, and the absence of costs recovered in rates related to the RRBs that were fully amortized in the second quarter of 2013.

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RESULTS OF OPERATIONS – WESTERN MASSACHUSETTS ELECTRIC COMPANY

The following provides the amounts and variances in operating revenues and expense line items in the statements of income for WMECO for the nine months ended September 30, 2014 and 2013 included in this Quarterly Report on Form 10-Q:  

			For the Nine Months Ended September 30,
							Increase/
(Millions of Dollars)			2014		2013		(Decrease)		Percent
Operating Revenues			$	363.8	$	361.8	$	2.0	0.6	%
Operating Expenses:
	Purchased Power and Transmission			131.0		111.1		19.9	17.9
	Operations and Maintenance			67.1		70.2		(3.1)	(4.4)
	Depreciation			31.1		27.7		3.4	12.3
	Amortization of Regulatory Liabilities, Net			(7.8)		(0.6)		(7.2)	(a)
	Amortization of Rate Reduction Bonds			-		7.8		(7.8)	(100.0)
	Energy Efficiency Programs			33.1		28.5		4.6	16.1
	Taxes Other Than Income Taxes			25.7		20.2		5.5	27.2
		Total Operating Expenses		280.2		264.9		15.3	5.8
Operating Income				83.6		96.9		(13.3)	(13.7)
Interest Expense				18.9		18.8		0.1	0.5
Other Income, Net				1.7		2.3		(0.6)	(26.1)
Income Before Income Tax Expense				66.4		80.4		(14.0)	(17.4)
Income Tax Expense				26.6		30.4		(3.8)	(12.5)
Net Income			$	39.8	$	50.0	$	(10.2)	(20.4)	%
(a)  Percent greater than 100 percent not shown as it is not meaningful.
Operating Revenues
WMECO's retail sales volumes were as follows:
			For the Nine Months Ended September 30,
			2014		2013		Decrease		Percent
Retail Sales Volumes in GWh				2,721		2,786		(65)	(2.3)	%

WMECO's Operating Revenues increased in the first nine months of 2014, as compared to the first nine months of 2013, due primarily to a higher level of recovery related to WMECO's energy supply and energy efficiency programs.  These revenues are fully reconciled to the related costs.  Therefore this increase in revenues had no material impact on earnings.  There was also a $3.9 million increase in revenues that impacts earnings due to the reversal of a previously established wholesale billing adjustment.  Partially offsetting this increase was the impact of the reserve recorded in the second quarter of 2014 as a result of the June 2014 FERC ROE orders as compared to the reserve recorded in the third quarter of 2013 for the FERC ALJ initial decision in the FERC base ROE complaints.  For further information, see "FERC Regulatory Issues - FERC Base ROE Complaints" in this Management's Discussion and Analysis of Financial Condition and Results of Operations.  Additionally, transition cost recovery revenues decreased due to the refund to customers of proceeds received from the Yankee Companies resulting from the spent nuclear fuel litigation.  Fluctuations in WMECO's kWh sales have no impact on earnings, as its revenues are decoupled from sales volumes and changes in revenues are primarily related to changes in its cost tracking mechanisms.  

Purchased Power and Transmission expense includes costs associated with purchasing electricity on behalf of WMECO's customers.  These energy supply costs are recovered from customers in DPU-approved cost tracking mechanisms, which have no impact on earnings (tracked costs).  Purchased Power and Transmission increased for the nine months ended September 30, 2014, as compared to the same period in 2013, due primarily to an increase in purchased power due primarily to higher average supply prices and increased load as a result of customers returning to basic service from third party suppliers ($10.7 million) and an increase in transmission costs as a result of an increase in the retail transmission cost deferral ($9.2 million), which reflects the actual costs of transmission service compared to estimated amounts billed to customers.  

Operations and Maintenance expense includes tracked costs and costs that are recovered through base electric distribution rates (and therefore impact earnings).  Operations and Maintenance decreased for the nine months ended September 30, 2014, as compared to the same period in 2013, driven by a $3.1 million decrease in tracked costs, which have no earnings impact, which was primarily attributable to lower labor and other employee-related costs, including pension costs.  Costs that impact earnings were flat for the nine months ended September 30, 2014, as compared to the same period in 2013.

Depreciation increased for the nine months ended September 30, 2014, as compared to the same period in 2013, due primarily to higher utility plant balances resulting from completed construction projects placed into service.  

Amortization of Regulatory Liabilities, Net, reflects a decrease in the recovery of transition costs primarily due to the refund of the DOE proceeds to customers for the nine months ended September 30, 2014, as compared to the same period in 2013.  Fluctuations in these costs are recovered from customers in rates and have no impact on earnings.   

Amortization of Rate Reduction Bonds decreased for the nine months ended September 30, 2014, as compared to same period in 2013, due to the maturity of the RRBs in June 2013.

Energy Efficiency Programs, which are tracked costs, increased for the nine months ended September 30, 2014, as compared to the same period in 2013, due primarily to an increase in energy efficiency costs in accordance with the three-year program guidelines established by the DPU.

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Taxes Other Than Income Taxes increased for the nine months ended September 30, 2014, as compared to the same period in 2013, due primarily to an increase in property taxes as a result of both an increase in utility plant balances and property tax rates.

Income Tax Expense decreased for the nine months ended September 30, 2014, as compared to the same period in 2013, due primarily to lower pre-tax earnings ($4.9 million), partially offset by various other tax impacts ($1.1 million).

EARNINGS SUMMARY

For the nine months ended September 30, 2014, WMECO's earnings decreased, as compared to the same period in 2013, due primarily to the after-tax reserve recorded for the second quarter 2014 FERC ROE orders as compared to the reserve recorded in the third quarter 2013 for the FERC ALJ initial decision in the FERC base ROE complaints ($3.7 million increase), higher depreciation expense and higher property tax expense.  Partially offsetting these unfavorable earnings impacts were the reversal of a previously established wholesale billing adjustment and an increase in generation earnings.

LIQUIDITY

WMECO had cash flows provided by operating activities of $120.6 million in the first nine months of 2014, compared with $170.1 million in the first nine months of 2013.  The decrease in operating cash flows was due primarily to income tax payments of $26.5 million in the first nine months of 2014, compared with income tax payments of $16.9 million in the first nine months of 2013, changes in working capital items, and the absence of costs recovered in rates related to the RRBs that were fully amortized in the second quarter of 2013, partially offset by the receipt of $18.9 million in DOE Damages proceeds received in 2014 from the Yankee Companies associated with the spent nuclear fuel litigation, and an increase in regulatory overrecoveries.

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ITEM 3.

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.  NU's Energy Supply Risk Committee, comprised of senior officers, reviews and approves all large scale energy related transactions entered into by its Regulated companies.

Other Risk Management Activities

Interest Rate Risk Management:  We manage our interest rate risk exposure in accordance with our written policies and procedures by maintaining a mix of fixed and variable rate long-term debt.  

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 transact with 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.

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.  

We have provided additional disclosures regarding interest rate risk management and credit risk management in Part II, Item 7A, "Quantitative and Qualitative Disclosures about Market Risk," in NU's 2013 Form 10-K, which is incorporated herein by reference. There have been no additional risks identified and no material changes with regard to the items previously disclosed in the NU 2013 Form 10-K.

ITEM 4.

CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

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 September 30, 2014 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 Quarterly Report on Form 10-Q.  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.

Changes in Internal Control over Financial Reporting

During the third quarter of 2014, we implemented a new general ledger system resulting in a material change in internal controls over financial reporting.  This new system, which went live effective August 1, 2014, standardized the financial systems for the merged companies and allows for a common set of accounting processes, practices and data structures across all operating companies.  Pre-implementation testing and post-implementation reviews were conducted by management to ensure that internal controls surrounding the system implementation process, the applications, and the closing process were properly designed to prevent material financial statement errors.  Such procedures included the review of required documents, user acceptance testing, change management procedures, access controls, data migration strategies and reconciliations, application interface testing and other standard application controls.  

Except as described above, there have been no other changes in internal controls over financial reporting for NU, CL&P, NSTAR Electric, PSNH and WMECO during the quarter ended September 30, 2014 that have materially affected, or are reasonably likely to materially affect, internal controls over financial reporting.

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PART II.  OTHER INFORMATION

ITEM 1.

LEGAL PROCEEDINGS

We are parties to various legal proceedings.  We have identified these legal proceedings in Part I, Item 3, "Legal Proceedings," and elsewhere in our 2013 Form 10-K, which disclosures are incorporated herein by reference.  There have been no additional material legal proceedings identified and no material changes with regard to the legal proceedings previously disclosed in our 2013 Form 10-K.

ITEM 1A.

RISK FACTORS

We are subject to a variety of significant risks in addition to the matters set forth under "Forward-Looking Statements," in Item 2, "Management's Discussion and Analysis of Financial Condition and Results of Operations," of this Quarterly Report on Form 10-Q.  We have identified a number of these risk factors in Part I, Item 1A, "Risk Factors," in our 2013 Form 10-K, which risk factors are incorporated herein by reference.  These risk factors should be considered carefully in evaluating our risk profile.  There have been no additional risk factors identified and no material changes with regard to the risk factors previously disclosed in our 2013 Form 10-K.

ITEM 2.

UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

The following table discloses purchases of our common shares made by us or on our behalf for the periods shown below.  The common shares purchased consist of open market purchases made by the Company or an independent agent.  These share transactions related to the Company's Long-Term Incentive Plans.

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)
July 1 – July 31, 2014	-	$	-	-	-
August 1 – August 31, 2014	34,452		45.37	-	-
September 1 – September 30, 2014	5,248		45.37	-	-
Total	39,700	$	45.37	-	-

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ITEM 6.

EXHIBITS

Each document described below is filed herewith, unless designated with an asterisk (*), which exhibits are incorporated by reference by the registrant under whose name the exhibit appears.

	Exhibit No.	Description
	Listing of Exhibits (NU)
	12	Ratio of Earnings to Fixed Charges
	31	Certification of Thomas J. May, Chairman, 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 November 7, 2014
	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 November 7, 2014
	32	Certification of Thomas J. May, Chairman, President and Chief Executive Officer of NU, and James J. Judge, Executive Vice President and Chief Financial Officer of NU, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, dated November 7, 2014
	Listing of Exhibits (CL&P)
*	3.1	By-laws of CL&P, amended and restated as in effect September 29, 2014 (Exhibit 3.1, CL&P Current Report on Form 8-K filed October 2, 2014, File No. 000-00404)
*	4.1	Supplemental Indenture (2014 Series A Bond) between CL&P and Deutsche Bank Trust Company Americas, as Trustee dated as of April 1, 2014 (Exhibit 4.1, CL&P Current Report on Form 8-K filed April 29, 2014, File No. 000-00404)
	12	Ratio of Earnings to Fixed Charges
	31	Certification of Werner J. Schweiger, 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 November 7, 2014
	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 November 7, 2014
	32	Certification of Werner J. Schweiger, Chief Executive Officer of CL&P, and James J. Judge, Executive Vice President and Chief Financial Officer of CL&P, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, dated November 7, 2014
	Listing of Exhibits (NSTAR Electric)
*	3.1	By-laws of NSTAR Electric, amended and restated as in effect September 29, 2014 (Exhibit 3.1, NSTAR Electric Company Current Report on Form 8-K filed October 2, 2014, File No. 001-02301)
	12	Ratio of Earnings to Fixed Charges
	31	Certification of Werner J. Schweiger, Chief Executive Officer of NSTAR Electric, 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 November 7, 2014
	31.1	Certification of James J. Judge, Executive Vice President and Chief Financial Officer of NSTAR Electric, 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 November 7, 2014
	32	Certification of Werner J. Schweiger, Chief Executive Officer of NSTAR Electric, and James J. Judge, Executive Vice President and Chief Financial Officer of NSTAR Electric, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, dated November 7, 2014

65

	Listing of Exhibits (PSNH)
	3.1	By-laws of PSNH, amended and restated as in effect September 29, 2014
*	4.1	Twenty-First Supplemental Indenture, between PSNH and U.S. Bank National Association, as Trustee dated as of October 1, 2014 (Exhibit 4.1, PSNH Current Report on Form 8-K filed October 17, 2014, File No. 001-06392)
	12	Ratio of Earnings to Fixed Charges
	31	Certification of Werner J. Schweiger, 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 November 7, 2014
	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 November 7, 2014
	32	Certification of Werner J. Schweiger, Chief Executive Officer of PSNH, and James J. Judge, Executive Vice President and Chief Financial Officer of PSNH, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, dated November 7, 2014
	Listing of Exhibits (WMECO)
	3.1	By-laws of WMECO, amended and restated as in effect September 29, 2014
	12	Ratio of Earnings to Fixed Charges
	31	Certification of Werner J. Schweiger, 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 November 7, 2014
	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 November 7, 2014
	32	Certification of Werner J. Schweiger, Chief Executive Officer of WMECO, and James J. Judge, Executive Vice President and Chief Financial Officer of WMECO, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, dated November 7, 2014

Listing of Exhibits (NU, CL&P, NSTAR Electric, PSNH, WMECO)
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

66

SIGNATURE

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
November 7, 2014	By:	/s/ Jay S. Buth
		Jay S. Buth
		Vice President, Controller and Chief Accounting Officer

SIGNATURE

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
November 7, 2014	By:	/s/ Jay S. Buth
		Jay S. Buth
		Vice President, Controller and Chief Accounting Officer

SIGNATURE

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
November 7, 2014	By:	/s/ Jay S. Buth
		Jay S. Buth
		Vice President, Controller and Chief Accounting Officer

67

SIGNATURE

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
November 7, 2014	By:	/s/ Jay S. Buth
		Jay S. Buth
		Vice President, Controller and Chief Accounting Officer

SIGNATURE

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
November 7, 2014	By:	/s/ Jay S. Buth
		Jay S. Buth
		Vice President, Controller and Chief Accounting Officer

68

EX-12

Northeast Utilities and Subsidiaries												Exhibit 12
Ratio of Earnings to Fixed Charges
(Unaudited)
	Nine Months
	Ended
	September 30,		For the Years Ended December 31,
(Thousands of Dollars)	2014		2013		2012 (a)		2011		2010		2009
Earnings, as defined:
Net income	$	603,576	$	793,689	$	533,077	$	400,513	$	394,107	$	335,592
Income tax expense		345,858		426,941		274,926		170,953		210,409		179,947
Equity in earnings of regional nuclear      generating and transmission companies		(72)		(1,318)		(1,154)		(671)		(1,429)		(1,762)
Dividends received from regional equity investees		-		582		733		940		1,488		3,794
Fixed charges, as below		290,886		362,403		353,616		275,948		263,393		296,764
Less: Interest capitalized (including AFUDC)		(4,151)		(4,062)		(5,261)		(11,758)		(10,165)		(5,929)
Preferred dividend security requirements of      consolidated subsidiaries		(9,398)		(12,803)		(11,715)		(9,265)		(10,170)		(9,265)
Total earnings, as defined	$	1,226,699	$	1,565,432	$	1,144,222	$	826,660	$	847,633	$	799,141
Fixed charges, as defined:
Interest on long-term debt (b)	$	260,076	$	340,970	$	316,987	$	231,630	$	231,089	$	224,712
Interest on rate reduction bonds		-		422		6,168		8,611		20,573		36,524
Other interest (c)		12,132		(2,693)		6,790		10,184		(14,371)		12,401
Rental interest factor		5,129		6,839		6,695		4,500		5,767		7,933
Preferred dividend security requirements of   consolidated subsidiaries		9,398		12,803		11,715		9,265		10,170		9,265
Interest capitalized (including AFUDC)		4,151		4,062		5,261		11,758		10,165		5,929
Total fixed charges, as defined	$	290,886	$	362,403	$	353,616	$	275,948	$	263,393	$	296,764
Ratio of Earnings to Fixed Charges		4.22		4.32		3.24		3.00		3.22		2.69
(a) NSTAR amounts were included in NU beginning April 10, 2012.
(b) Interest on long-term debt includes amortized premiums, discounts and capitalized expenses related to indebtedness.
(c) For all periods presented, other interest includes interest related to accounting for uncertain tax positions.

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 Quarterly Report on Form 10-Q 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:  November 7, 2014

/s/	Thomas J. May
	Thomas J. May
	Chairman, 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 Quarterly Report on Form 10-Q 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:  November 7, 2014

/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 this Quarterly Report on Form 10-Q of Northeast Utilities (the registrant) for the period ending September 30, 2014 as filed with the Securities and Exchange Commission (the Report), we, Thomas J. May, Chairman, 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 results of operations of the registrant.

/s/	Thomas J. May
	Thomas J. May
	Chairman, President and Chief Executive Officer

/s/	James J. Judge
	James J. Judge
	Executive Vice President and Chief Financial Officer

Date:  November 7, 2014

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-12

The Connecticut Light and Power Company												Exhibit 12
Ratio of Earnings to Fixed Charges
(Unaudited)
	Nine Months
	Ended
	September 30,		For the Years Ended December 31,
(Thousands of Dollars)	2014		2013		2012		2011		2010		2009
Earnings, as defined:
Net income	$	200,560	$	279,412	$	209,725	$	250,164	$	244,143	$	216,316
Income tax expense		95,980		141,663		94,437		90,033		132,438		118,847
Equity in earnings of regional nuclear      generating companies		(22)		(67)		(40)		(16)		(134)		(282)
Dividends received from regional equity investees		-		289		-		-		440		1,520
Fixed charges, as below		114,770		139,929		139,982		140,311		145,297		163,887
Less: Interest capitalized (including AFUDC)		(1,299)		(2,249)		(2,456)		(3,317)		(2,726)		(2,203)
Total earnings, as defined	$	409,989	$	558,977	$	441,648	$	477,175	$	519,458	$	498,085
Fixed charges, as defined:
Interest on long-term debt (a)	$	102,290	$	130,620	$	124,894	$	131,918	$	134,553	$	133,422
Interest on rate reduction bonds		-		-		-		-		7,542		19,061
Other interest (b)		8,158		3,030		8,233		809		(4,357)		3,334
Rental interest factor		3,023		4,030		4,399		4,267		4,833		5,867
Interest capitalized (including AFUDC)		1,299		2,249		2,456		3,317		2,726		2,203
Total fixed charges, as defined	$	114,770	$	139,929	$	139,982	$	140,311	$	145,297	$	163,887
Ratio of Earnings to Fixed Charges		3.57		3.99		3.16		3.40		3.58		3.04
(a) Interest on long-term debt includes amortized premiums, discounts and capitalized expenses related to indebtedness.
(b) For the years ended December 31, 2013, 2012, 2011, 2010 and 2009, other interest includes interest related to accounting for uncertain tax positions.

EX-31

Exhibit 31

CERTIFICATION PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Werner J. Schweiger, certify that:

1.

I have reviewed this Quarterly Report on Form 10-Q 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:  November 7, 2014

/s/	Werner J. Schweiger
	Werner J. Schweiger
	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 Quarterly Report on Form 10-Q 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:  November 7, 2014

/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 this Quarterly Report on Form 10-Q of The Connecticut Light and Power Company (the registrant) for the period ending September 30, 2014 as filed with the Securities and Exchange Commission (the Report), we, Werner J. Schweiger, 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 results of operations of the registrant.

/s/	Werner J. Schweiger
	Werner J. Schweiger
	Chief Executive Officer

/s/	James J. Judge
	James J. Judge
	Executive Vice President and Chief Financial Officer

Date:  November 7, 2014

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-12

NSTAR Electric Company and Subsidiary												Exhibit 12
Ratio of Earnings to Fixed Charges
(Unaudited)
	Nine Months
	Ended
	September 30,		For the Years Ended December 31,
(Thousands of Dollars)	2014		2013		2012		2011		2010		2009
Earnings, as defined:
Net income	$	233,791	$	268,546	$	190,242	$	252,494	$	248,575	$	240,691
Income tax expense		156,655		172,866		123,966		165,686		162,020		151,224
Equity in earnings of regional nuclear      generating and transmission companies		(32)		(550)		(412)		(501)		(836)		(891)
Dividends received from regional equity investees		-		344		286		676		669		1,661
Fixed charges, as below		62,261		73,115		72,364		76,219		77,902		84,826
Less: Interest capitalized (including AFUDC)		(1,504)		(511)		(259)		(185)		(108)		76
Total earnings, as defined	$	451,171	$	513,810	$	386,187	$	494,389	$	488,222	$	477,587
Fixed charges, as defined:
Interest on long-term debt (a)	$	58,485	$	79,088	$	87,100	$	90,040	$	90,630	$	83,261
Interest on rate reduction bonds		-		399		3,585		7,226		11,235		18,833
Other interest (b)		606		(9,104)		(20,631)		(27,839)		(30,475)		(24,519)
Rental interest factor		1,666		2,221		2,051		6,607		6,404		7,327
Interest capitalized (including AFUDC)		1,504		511		259		185		108		(76)
Total fixed charges, as defined	$	62,261	$	73,115	$	72,364	$	76,219	$	77,902	$	84,826
Ratio of Earnings to Fixed Charges		7.25		7.03		5.34		6.49		6.27		5.63
(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-31

Exhibit 31

CERTIFICATION PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Werner J. Schweiger, certify that:

1.

I have reviewed this Quarterly Report on Form 10-Q 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:  November 7, 2014

/s/	Werner J. Schweiger
	Werner J. Schweiger
	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 Quarterly Report on Form 10-Q 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:  November 7, 2014

/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 this Quarterly Report on Form 10-Q of NSTAR Electric Company (the registrant) for the period ending September 30, 2014 as filed with the Securities and Exchange Commission (the Report), we, Werner J. Schweiger, 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 results of operations of the registrant.

/s/	Werner J. Schweiger
	Werner J. Schweiger
	Chief Executive Officer

/s/	James J. Judge
	James J. Judge
	Executive Vice President and Chief Financial Officer

Date:  November 7, 2014

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-3.1

Exhibit 3.1

PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE

BYLAWS

As Amended and Restated

Effective September 29, 2014

TABLE OF CONTENTS

ARTICLE I – MEETINGS OF STOCKHOLDERS	1
Section 1.  Meetings of Stockholders	1
Section 2.  Annual Meeting	1
Section 3.  Special Meetings	1
Section 4.  Notice	1
Section 5.  Quorum	1
Section 6.  Record Date	1
Section 7.  Action Without Meeting	1
ARTICLE II – DIRECTORS	2
Section 1.  Number and Election	2
Section 2.  Vacancies	2
Section 3.  Employ Agents and Employees	2
Section 4.  Directors Compensation	2
Section 5.  Removal	2
ARTICLE III – MEETINGS OF DIRECTORS	2
Section 1.  Regular Meeting	2
Section 2.  Other Regular Meetings	2
Section 3.  Special Meetings	3
Section 4.  Notice	3
Section 5.  Quorum	3
Section 6.  Action at a Meeting	3
Section 7.  Action Without a Meeting	3
Section 8.  Telephone Conference Meeting	3
ARTICLE IV – OFFICERS	3
Section 1.  Required Officers	3
Section 2.  Chairman	3
Section 3.  President	4
Section 4.  Vice President	4
Section 5.  Secretary	4
Section 6.  Treasurer	4
Section 7.  Other Officers	4
Section 8.  Powers	4
Section 9.  Removal	4
ARTICLE V – COMMITTEES	5
ARTICLE VI – STOCK CERTIFICATES	5
ARTICLE VII – CORPORATE SEAL	5
ARTICLE VIII – FISCAL YEAR	5
ARTICLE IX – INDEMNIFICATION	5
ARTICLE X – AMENDMENTS	7

PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE

BYLAWS

ARTICLE I

MEETINGS OF STOCKHOLDERS

Section 1.  Meetings of Stockholders.  Each meeting of the stockholders, annual or special, shall be held on such day and time, and at such place within or without the State of New Hampshire as may be designated by the Board of Directors, by the Chairman or by the President.

Section 2.  Annual Meeting.  The Annual Meeting of Stockholders for the election of Directors and for the transaction of such other business as may properly be brought before the meeting shall be held by June 30 each year on the day and time designated by the Board of Directors, the Chairman or the President.  In the event that no date for the annual meeting is established or said meeting has not been held on the date so fixed or determined, a special meeting in lieu of the annual meeting may be held with all of the force and effect of an annual meeting.

Section 3.  Special Meetings.  Special meetings of the stockholders may be called by the President or by the Directors, and shall be called by the Secretary, or in case of the death, absence, incapacity or refusal of the Secretary, by any other officer, upon written application of one or more stockholders who hold at least ten percent (10%) of the capital stock entitled to vote thereat.

Section 4.  Notice.  Notice of the date, time and place of any annual or special meeting of stockholders, stating the purposes of the meeting, shall be given by the Secretary at least ten (10) nor more than sixty (60) days before the meeting to each stockholder entitled to vote thereat, by leaving such notice with him or her or at his or her residence or usual place of business, or by mailing it, postage prepaid, and addressed to such stockholder at his or her address as it appears in the records  of the corporation.  Whenever notice of a meeting is required to be given a stockholder, a written waiver thereof, executed before or after the meeting by such stockholder and filed with the records of the meeting, shall be deemed equivalent to such notice.

Section 5.  Quorum.  At all meetings of stockholders, a majority in interest of all stock  issued, outstanding and entitled to vote at a meeting shall constitute a quorum and each share of stock entitled to vote, and represented in person or by proxy, shall be entitled to one vote.

Section 6.  Record Date.  The Board of Directors may fix a date as the record date for the purpose of determining stockholders entitled to notice of and to vote at any meeting of stockholders or any adjournment thereof, such date in any case to be not earlier than the date following the date such action fixing the record date is taken by the Board of Directors and not more than seventy (70) days immediately preceding the date of such meeting of stockholders.  Only stockholders of record on such record date shall be entitled to such notice and to vote at such meeting or any adjournment thereof, notwithstanding the transfer of any shares of stock on the books of the corporation after any such record date so fixed.

Section 7.  Action Without Meeting.  Any action required or permitted to be taken at any meeting of the stockholders may be taken without a meeting if all stockholders entitled to vote on the

matter consent to the action in writing and the written consents are filed with the records of the meetings of stockholders.  Such consents shall be treated for all purposes as a vote at a meeting.

ARTICLE II

DIRECTORS

Section 1.  Number and Election.  The business, property and affairs of the Company shall be managed by a Board of not less than three Directors, except that whenever there shall be fewer than three stockholders, the number of Directors may be less than three but in no event less than the number of stockholders.  The number of positions on the Board of Directors for any year shall be the number fixed from time to time by resolution of the stockholders or of the Board of Directors.  The Directors so elected shall continue in office until their successors have been elected and qualified, except that a Director shall cease to be in office upon his or her death, resignation, lawful removal or court order decreeing that he or she is no longer a Director in office.

Section 2.  Vacancies.  The Board of Directors shall have power to fill vacancies that may occur in the Board, or any other office, by death, resignation or otherwise, by a majority vote of the remaining members of the Board, and the person so chosen shall hold the office until  the  next  Annual Meeting of Stockholders and until his or her successor shall be elected and qualified.

Section 3.  Employ Agents and Employees.  The Board of Directors shall have power to employ such and so many agents and/or employees as the interests of the Company may require, and to fix the compensation and define the duties of all of the officers, agents, and employees of the Company.  All the officers, agents, and employees of the Company shall be subject to the order of the Board, shall hold their offices at the pleasure of the Board, and may be removed at any time by the Board at its discretion.

Section 4.  Directors Compensation.  The Board of Directors shall have power to fix from time to time the compensation of the Directors and the method of payment thereof.

Section 5.  Removal.  Any one or more Directors may be removed from office at any time with or without any showing of cause by affirmative vote of the holders of a majority of the Company's issued and outstanding stock entitled to vote.  Any Director may be removed from office for cause by vote of a majority of the Directors then in office.

ARTICLE III

MEETINGS OF DIRECTORS

Section 1.  Regular Meeting.  A regular meeting of the Board of Directors shall be held annually, without notice, as soon as convenient following the Annual Meeting of Stockholders, for the election of officers and the transaction of other business.

Section 2.  Other Regular Meetings.  All other regular meetings of the Board of Directors may be held at such time and place within or without the State of New Hampshire, as the Board may from time to time determine.  

2

Section 3.  Special Meetings.  Special meetings of the Board may be held at any place, within or without the State of New Hampshire, upon call of the Chairman (if there be one) or the President, or, in the event of the absence or inability of either to act, of a Vice President, or upon the written request of a majority of Directors.

Section 4.  Notice.  Oral or written notice of the time and place of each special meeting of the Board of Directors shall be given to each Director personally, by telephone, voice mail or other electronic means, or by mail or other delivery method at his or her last-known post office address, at least twenty-four hours, or a shorter time if deemed necessary by the President, prior to the time of the meeting, provided that any Director may waive such notice in writing, before or after the meeting, or by attendance at such meeting without objecting to the holding of such meeting.  Meetings may be held without notice if all the Directors are present.

Section 5.  Quorum.  A majority of the Directors then in office shall constitute a quorum.  If a quorum is not present, the Directors in attendance may adjourn the meeting from time to time until a quorum is present.  In the event of such an adjournment, notice of the adjourned meeting shall be given to all Directors.

Section 6.  Action at a Meeting.  Except as otherwise provided by these Bylaws, the action of a majority of the Directors present at a meeting at which a quorum is present at the time of the action shall be the action of the Board of Directors.

Section 7.  Action Without a Meeting.  Action to be taken by the Board of Directors may be taken without a meeting if each Director signs a consent describing the action taken or to be taken and delivers it to the Company.  Action taken by such consent is the act of the Board of Directors when one or more consents signed by all the Directors are delivered to the Secretary and filed with the minutes of the Company.  A consent signed under this section has the effect of action taken at a meeting of the Board of Directors and may be described as such in any document.

Section 8.  Telephone Conference Meeting.  The Board of Directors may permit any or all Directors to participate in a regular or special meeting by, or conduct the meeting through the use of, any means of communication by which all Directors participating may simultaneously hear each other during the meeting.  A Director participating in a meeting by this means is deemed to be present in person at the meeting.  

ARTICLE IV

OFFICERS

Section 1.  Required Officers.  At its annual meeting the Board of Directors shall elect a President, a Secretary and a Treasurer, and, if the Board shall so determine, a Chairman, each of whom shall hold office until the next annual election of officers and until his or her successor shall have been elected and qualified or until his or her earlier resignation or removal.  The Board may also elect at such annual meeting or at any regular or special meeting, such other officers as may be required for the prompt and orderly transaction of the business of the Company.  

Section 2.  Chairman.  The Chairman, if such office shall be filled by the Board, shall, when present, preside at all meetings of said Board and of the stockholders, unless the Board shall determine otherwise, and shall have such other authority and shall perform such additional duties as

3

may be assigned to him or her from time to time by the Board of Directors.  If the Chairman shall be absent or unable to perform the duties of his or her office, the Chief Executive Officer, if such position has been filled by the Board, shall perform the duties of the Chairman.

Section 3.  President.  The President shall be responsible for the general supervision, direction and control of the business and affairs of the Company, subject to the direction of the Chief Executive Officer, if such position has been filled by the Board.  If the Board has not elected either a Chairman or a Chief Executive Officer, or if such officer shall be absent or unable to perform the duties of his or her office, the President shall preside at meetings of the Board of Directors and of the stockholders, though the President need not be a Director.  The President shall have such other authority and shall perform such additional duties as may be assigned to him or her from time to time by the Board of Directors.

Section 4.  Vice President.  The Vice President, if such office shall be filled by the Board, shall have such powers and duties as may be assigned to him or her from time to time by the Board of Directors or the President.  An Executive Vice President, if elected by the Board, shall be designated by the Board to exercise the powers and perform the duties of the President in  the absence of the President or if the President is unable to perform the duties of the office.  The Board of Directors may also designate one or more of such Vice Presidents as Senior Vice Presidents.

Section 5.  Secretary.  The Secretary shall keep the minutes of all meetings of the stockholders and of the Board of Directors.  He or she shall give notice of all meetings of the stockholders and of the Board. He or she shall record all votes taken at such meetings and shall have such additional powers and duties as may be assigned to him or her from time to time by the Board of Directors, the Chairman, the President or by law.

 The Secretary shall have the custody of the Corporate Seal of the Company and shall affix the same to all instruments requiring a seal except as otherwise provided in these Bylaws.  

Section 6.  Treasurer.  The Treasurer shall have charge of all receipts and disbursements of the Company, and shall be the custodian of the Company's funds.  The Treasurer shall sign all checks, notes, drafts and similar instruments, except as otherwise provided by the  Board  of Directors, and shall have such additional powers and duties as may be assigned to him or her from time to time by the Board of Directors, the Chairman, the President or by law.

Section 7.  Other Officers.  Any other officer shall have such powers and duties as may be prescribed by the Board of Directors or by another officer pursuant to Board authorization.

Section 8.  Powers.  In addition to such powers and duties as these Bylaws and the Board of Directors may prescribe, and except as may be otherwise provided by the Board, each officer shall have the powers and perform the duties which by law and general usage relate to his or her particular office.  The Board of Directors may from time to time modify the powers and duties of any officer or delegate the powers or duties of any officer to any other officer or agent, notwithstanding any other provision of these Bylaws.

Section 9.  Removal.  Any officer may be removed, with or without cause, at any time by the Board of Directors in its discretion.

4

ARTICLE V

COMMITTEES

The Board of Directors by the affirmative vote of a majority of Directors then in office, may appoint such committees as it may deem proper, which committees shall have and may exercise all such authority of the Board of Directors as shall be provided in such resolution, subject to those powers expressly reserved to the Board of Directors under law.  Committees shall keep full records of their proceedings, and shall report the same to the next regular meeting of the Board, or when called upon by the Board.

ARTICLE VI

STOCK CERTIFICATES

The Board of Directors may authorize by resolution the issuance of some or all of any or all classes and series of Company shares without certificates.  The authorization shall not affect shares already represented by certificates until they are surrendered to the Company.  If the Board entitles any stockholders of a class or series to receive a certificate representing such shares, all other holders of shares of such class or series shall be entitled to the same.  All stock certificates representing shares of stock shall be signed by the Chairman, the President or any Vice President and by the Treasurer or any Assistant Treasurer.  Such signatures may be by facsimiles if the certificate is signed by a transfer agent, or by a registrar, other than a director, officer or employee of the Company.  

ARTICLE VII

CORPORATE SEAL

The corporate seal of the Company shall be circular in form with the name of the Company inscribed therein, and shall be in such other form as the Board of Directors may determine from time to time.

ARTICLE VIII

FISCAL YEAR

The fiscal year of the Company shall be the calendar year unless otherwise determined by the Board.

ARTICLE IX

INDEMNIFICATION

The corporation shall indemnify, to the fullest extent permitted by applicable law, each person made or threatened to be made a party to any threatened, pending or completed action, suit or proceeding, whether civil, criminal, administrative or investigative, by reason of the fact that such person or such person's testator or intestate is or was a director or officer of the corporation, or is or was serving, at the request of the corporation, for another corporation, partnership, joint venture, trust, employee benefit plan or other enterprise in any capacity while he or she was such a director or

5

officer, (hereinafter referred to as "Indemnified Person"), against expenses, including attorneys' fees, judgments, fines, penalties and amounts paid in settlement, actually and reasonably incurred in connection with such action or proceeding, or any appeal therein.

The corporation shall advance or promptly reimburse upon request any Indemnified Person for all expenses, including attorneys' fees, actually and reasonably incurred in defending any action or proceeding in advance of the final disposition thereof upon receipt of any undertaking then required by applicable law by or on behalf of such Indemnified Person.

Determinations with respect to indemnification and reimbursement of a person (unless ordered by a court) shall be made:  (1) by the Board acting (a) by majority vote or action of a disinterested quorum of directors; or (b) if such quorum is not obtainable, as directed by a majority vote or action of a committee of the Board, duly designated to act in the matter by a majority vote or action of the full Board (in which designation directors who are parties may participate), consisting solely of two or more directors not at the time parties to such proceeding; or (2) by independent legal counsel, selected by the Board or a committee thereof by vote or action as set forth in clauses (a) and (b) of clause (1), or if the requisite quorum of the full Board cannot be obtained therefor and such committee cannot be established, by a majority vote or action of the full Board (in which selection directors who are parties may participate); or (3) by a majority vote of the holders of the outstanding stock at the time entitled to vote for directors, voting as a single class; or (4) by any other method of determination selected by the Board (in which selection directors who are parties may participate).  

Nothing herein shall limit or affect any right of any Indemnified Person otherwise than hereunder to indemnification or expenses, including attorneys' fees, under any statute, rule, regulation, certificate of incorporation, Bylaw, insurance policy, contract or otherwise.

Anything in these Bylaws to the contrary notwithstanding, no elimination of this Bylaw, and no amendment of this Bylaw adversely affecting the right of any Indemnified Person to indemnification or advancement or reimbursement of expenses hereunder, shall be effective until the 60th day following the taking of such action, and no elimination of or amendment to this Bylaw shall thereafter deprive any Indemnified Person of his or her rights hereunder arising out of alleged or actual occurrences, acts or failures to act occurring prior to such 60th day.  Upon taking any such action the corporation shall promptly notify all Indemnified Parties, which notification shall be sufficient if mailed, postage prepaid, to each such Indemnified Person at their last known address.

The corporation shall not, except by elimination or amendment of this Bylaw in a manner consistent with the preceding paragraph and Article X of these Bylaws, and except by making any determination required by the New Hampshire Business Corporation Act take any  corporate action or enter into any agreement which prohibits, or otherwise limits the rights of any Indemnified Person to, indemnification in accordance with the provisions of this Bylaw.  The indemnification of any Indemnified Person provided by this Bylaw shall be deemed to be a contract between the corporation and such Indemnified Person and shall continue after such Indemnified Person has ceased to be a director or officer of the corporation and shall inure to the benefit of such Indemnified Person's heirs, executors, administrators and legal representatives.  If the corporation fails timely to make any payment pursuant to the indemnification and advancement or reimbursement of expenses provisions of this Article IX and an Indemnified Person commences an action or proceeding to recover such payment, the corporation in addition shall reimburse such Indemnified Person for the legal fees and other expenses of such action or proceeding if the Indemnified Party shall prevail in such action or proceeding.

6

In case any provision in this Bylaw shall be determined at any time to be unenforceable in any respect, the other provisions shall not in any way be affected or impaired thereby.

For purposes of this Bylaw, the corporation shall be deemed to have requested an Indemnified Person to serve an employee benefit plan where the performance by such Indemnified Person of his or her duties to the corporation also imposes duties on, or otherwise involves services by, such Indemnified Person to the plan or participants or beneficiaries of the plan.  Such Indemnified Person shall be indemnified against excise taxes assessed on him or her with respect to an employee benefit plan pursuant to applicable law.  For purposes of this Article IX of these Bylaws, the term "corporation" shall include any legal successor to the corporation, including any corporation which acquires all or substantially all of the assets of the corporation in one or more transactions.  

ARTICLE X

AMENDMENTS

These Bylaws may be altered, amended or repealed by vote of a majority of stock  present and voting thereon at any meeting of the stockholders called for such purpose where a quorum is present or by written consent in lieu of a meeting, or by a vote of a majority of the Board of Directors at any meeting of the Board of Directors called for the purpose or by unanimous written consent of the Board, except with respect to any provision which by law, the Articles of Incorporation or the Bylaws requires action by the stockholders.

7

EX-12

Public Service Company of New Hampshire and Subsidiary												Exhibit 12
Ratio of Earnings to Fixed Charges
(Unaudited)
	Nine Months
	Ended
	September 30,		For the Years Ended December 31,
(Thousands of Dollars)	2014			2013		2012		2011		2010		2009
Earnings, as defined:
Net income	$	84,955	$	111,397	$	96,882	$	100,267	$	90,067	$	65,570
Income tax expense		52,199		71,101		60,993		49,945		50,801		31,990
Equity in earnings of regional nuclear      generating companies		(5)		(12)		(8)		(7)		(23)		(50)
Dividends received from regional equity investees		-		42		-		-		80		220
Fixed charges, as below		34,966		47,318		52,769		52,111		54,721		51,227
Less: Interest capitalized (including AFUDC)		(489)		(500)		(1,579)		(7,064)		(6,621)		(3,138)
Total earnings, as defined	$	171,626	$	229,346	$	209,057	$	195,252	$	189,025	$	145,819
Fixed charges, as defined:
Interest on long-term debt (a)	$	33,812	$	44,370	$	46,228	$	36,832	$	36,220	$	33,045
Interest on rate reduction bonds		-		(154)		2,687		6,276		9,660		13,128
Other interest (b)		183		1,960		1,313		1,039		1,187		316
Rental interest factor		482		642		962		900		1,033		1,600
Interest capitalized (including AFUDC)		489		500		1,579		7,064		6,621		3,138
Total fixed charges, as defined	$	34,966	$	47,318	$	52,769	$	52,111	$	54,721	$	51,227
Ratio of Earnings to Fixed Charges		4.91		4.85		3.96		3.75		3.45		2.85
(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-31

Exhibit 31

CERTIFICATION PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Werner J. Schweiger, certify that:

1.

I have reviewed this Quarterly Report on Form 10-Q 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:  November 7, 2014

/s/	Werner J. Schweiger
	Werner J. Schweiger
	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 Quarterly Report on Form 10-Q 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:  November 7, 2014

/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 this Quarterly Report on Form 10-Q of Public Service Company of New Hampshire (the registrant) for the period ending September 30, 2014 as filed with the Securities and Exchange Commission (the Report), we, Werner J. Schweiger, 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 results of operations of the registrant.

/s/	Werner J. Schweiger
	Werner J. Schweiger
	Chief Executive Officer

/s/	James J. Judge
	James J. Judge
	Executive Vice President and Chief Financial Officer

Date:  November 7, 2014

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-3.1

Exhibit 3.1

WESTERN MASSACHUSETTS ELECTRIC COMPANY

BYLAWS

As Amended and Restated

Effective September 29, 2014

TABLE OF CONTENTS

ARTICLE I – MEETINGS OF STOCKHOLDERS	1
Section 1.  Meetings of Stockholders	1
Section 2.  Annual Meeting	1
Section 3.  Special Meetings	1
Section 4.  Notice	1
Section 5.  Quorum	1
Section 6.  Record Date	1
Section 7.  Action Without Meeting	2
ARTICLE II – DIRECTORS	2
Section 1.  Number and Election	2
Section 2.  Vacancies	2
Section 3.  Employ Agents and Employees	2
Section 4.  Directors Compensation	2
Section 5.  Removal	2
ARTICLE III – MEETINGS OF DIRECTORS	2
Section 1.  Regular Meeting	2
Section 2.  Other Regular Meetings	3
Section 3.  Special Meetings	3
Section 4.  Notice	3
Section 5.  Quorum	3
Section 6.  Action at a Meeting	3
Section 7.  Action Without a Meeting	3
Section 8.  Telephone Conference Meeting	3
ARTICLE IV – OFFICERS	3
Section 1.  Required Officers	3
Section 2.  Chairman	4
Section 3.  President	4
Section 4.  Vice President	4
Section 5.  Secretary and Clerk	4
Section 6.  Treasurer	4
Section 7.  Other Officers	4
Section 8.  Powers	4
Section 9.  Removal	5
ARTICLE V – COMMITTEES	5
ARTICLE VI – STOCK CERTIFICATES	5
ARTICLE VII – CORPORATE SEAL	5
ARTICLE VIII – FISCAL YEAR	6
ARTICLE IX – INDEMNIFICATION	6
ARTICLE X – AMENDMENTS	8

WESTERN MASSACHUSETTS ELECTRIC COMPANY

BYLAWS

ARTICLE I

MEETINGS OF STOCKHOLDERS

Section 1.  Meetings of Stockholders.  Each meeting of the stockholders, annual or special, shall be held on such day and time, and at such place within the Commonwealth of Massachusetts, or to the extent permitted by the Articles of Organization elsewhere in the United States, as may be designated by the Board of Directors, by the Chairman or by the President.

Section 2.  Annual Meeting.  The Annual Meeting of Stockholders for the election of Directors and for the transaction of such other business as may properly be brought before the meeting shall be held by June 30 each year on the day and time designated by the Board of Directors, the Chairman or the President.  In the event that no date for the annual meeting is established or said meeting has not been held on the date so fixed or determined, a special meeting in lieu of the annual meeting may be held with all of the force and effect of an annual meeting.

Section 3.  Special Meetings.  Special meetings of the stockholders may be called by the President or by the Directors, and shall be called by the Secretary and Clerk, or in case of the death, absence, incapacity or refusal of the Secretary and Clerk, by any other officer, upon written application of one or more stockholders who hold at least ten percent (10%) of the capital stock entitled to vote thereat.

Section 4.  Notice.  Notice of the date, time and place of any annual or special meeting of stockholders, stating the purposes of the meeting, shall be given by the Secretary and Clerk at least seven (7) days before the meeting to each stockholder entitled to vote thereat, by leaving such notice with him or her or at his or her residence or usual place of business, or by mailing it, postage prepaid, and addressed to such stockholder at his or her address as it appears in the records of the corporation.  Whenever notice of a meeting is required to be given a stockholder, a written waiver thereof, executed before or after the meeting by such stockholder and filed with the records of the meeting, shall be deemed equivalent to such notice.

Section 5.  Quorum.    At all meetings of stockholders, a majority in interest of all stock issued, outstanding and entitled to vote at a meeting shall constitute a quorum and each  share  of  stock entitled to vote, and represented in person or by proxy, shall be entitled to one vote.

Section 6.  Record Date.   The Board of Directors may fix a date as the record date for the purpose of determining stockholders entitled to notice of and to vote at any meeting of stockholders or any adjournment thereof, such date in any case to be not earlier than the date following the date such action fixing the record date is taken by the Board of Directors and not more than sixty (60) days immediately preceding the date of such meeting of stockholders.  Only stockholders of record on such record date shall be entitled to such notice and to vote at such meeting or any adjournment thereof, notwithstanding the transfer of any shares of stock on the books of the corporation after any such record date so fixed.

Section 7.  Action Without Meeting.  Any action required or permitted to be taken at any meeting of the stockholders may be taken without a meeting if all stockholders entitled to vote on the matter consent to the action in writing and the written consents are filed with the records of the meetings of stockholders.  Such consents shall be treated for all purposes as a vote at a meeting.

ARTICLE II

DIRECTORS

Section 1.  Number and Election.  The business, property and affairs of the Company shall be managed by a Board of not less than three Directors, except that whenever there shall be fewer than three stockholders, the number of Directors may be less than three but in no event less than the number of stockholders.  The number of positions on the Board of Directors for any year shall be the number fixed from time to time by resolution of the stockholders or of the Board of Directors.  The Directors so elected shall continue in office until their successors have been elected and qualified, except that a Director shall cease to be in office upon his or her death, resignation, lawful removal or court order decreeing that he or she is no longer a Director in office.

Section 2.  Vacancies.  The Board of Directors shall have power to fill vacancies that may occur in the Board, or any other office, by death, resignation or otherwise, by a majority vote of the remaining members of the Board, and the person so chosen shall hold the office until  the  next Annual Meeting of Stockholders and until his or her successor shall be elected and qualified.

Section 3.  Employ Agents and Employees.  The Board of Directors shall have power to employ such and so many agents and/or employees as the interests of the Company may require, and to fix the compensation and define the duties of all of the officers, agents, and employees of the Company.  All the officers, agents, and employees of the Company shall be subject to the order of the Board, shall hold their offices at the pleasure of the Board, and may be removed at any time by the Board at its discretion.

Section 4.  Directors Compensation.  The Board of Directors shall have power to fix from time to time the compensation of the Directors and the method of payment thereof.

Section 5.  Removal.  Any one or more Directors may be removed from office at any time with or without any showing of cause by affirmative vote of the holders of a majority of the Company's issued and outstanding stock entitled to vote.  Any Director may be removed from office for cause by vote of a majority of the Directors then in office, but only after a reasonable notice and opportunity to be heard by the Board has been given.

ARTICLE III

MEETINGS OF DIRECTORS

Section 1.  Regular Meeting.  A regular meeting of the Board of Directors shall be held annually, without notice, as soon as convenient following the Annual Meeting of Stockholders, for the election of officers and the transaction of other business.

2

Section 2.  Other Regular Meetings.  All other regular meetings of the Board of Directors may be held at such time and place within or without the Commonwealth of Massachusetts, as the Board may from time to time determine.  

Section 3.  Special Meetings.  Special meetings of the Board may be held at any place, within or without the Commonwealth of Massachusetts, upon call of the Chairman (if there be one) or the President, or, in the event of the absence or inability of either to act, of a Vice President, or upon the written request of a majority of Directors.

Section 4.  Notice.  Oral or written notice of the time and place of each special meeting of the Board of Directors shall be given to each Director personally, by telephone, voice mail or other electronic means, or by mail or other delivery method at his or her last-known post office address, at least twenty-four hours, or a shorter time if deemed necessary by the President, prior to the time of the meeting, provided that any Director may waive such notice in writing, before or after the meeting, or by attendance at such meeting without objecting to the holding of such meeting.  Meetings may be held without notice if all the Directors are present.

Section 5.  Quorum.  A majority of the Directors then in office shall constitute a quorum.  If a quorum is not present, the Directors in attendance may adjourn the meeting from time to time until a quorum is present.  In the event of such an adjournment, notice of the adjourned meeting shall be given to all Directors.

Section 6.  Action at a Meeting.  Except as otherwise provided by these Bylaws, the action of a majority of the Directors present at a meeting at which a quorum is present at the time of the action shall be the action of the Board of Directors.

Section 7.  Action Without a Meeting.  Action to be taken by the Board of Directors may be taken without a meeting if each Director signs a consent describing the action taken or to be taken and delivers it to the Company.  Action taken by such consent is the act of the Board of Directors when one or more consents signed by all the Directors are delivered to the Secretary and Clerk and filed with the minutes of the Company.  A consent signed under this section has the effect of action taken at a meeting of the Board of Directors and may be described as such in any document.  

Section 8.  Telephone Conference Meeting.  The Board of Directors may permit any or all Directors to participate in a regular or special meeting by, or conduct the meeting through the use of, any means of communication by which all Directors participating may simultaneously hear each other during the meeting.  A Director participating in a meeting by this means is deemed to be present in person at the meeting.

ARTICLE IV

OFFICERS

Section 1.  Required Officers.  At its annual meeting the Board of Directors shall elect a President, a Secretary and Clerk and a Treasurer, and, if the Board shall so determine, a Chairman, each of whom shall hold office until the next annual election of officers and until his or her successor shall have been elected and qualified or until his or her earlier resignation or removal, subject to the provisions of Article IV, Section 9.  The Board may also elect at such annual meeting or at any

3

regular or special meeting, such other officers as may be required for the prompt and orderly transaction of the business of the Company.

Section 2.  Chairman.  The Chairman, if such office shall be filled by the Board, shall, when present, preside at all meetings of said Board and of the stockholders, unless the Board shall determine otherwise, and shall have such other authority and shall perform such additional duties as may be assigned to him or her from time to time by the Board of Directors. If the Chairman shall be absent or unable to perform the duties of his or her office, the Chief Executive Officer, if such position has been filled by the Board, shall perform the duties of the Chairman.

Section 3.  President.  The President shall be responsible for the general supervision, direction and control of the business and affairs of the Company, subject to the direction of the Chief Executive Officer, if such position has been filled by the Board.  If the Board has not elected either a Chairman or a Chief Executive Officer, or if such officer shall be absent or unable to perform the duties of his or her office, the President shall preside at meetings of the Board of Directors and of the stockholders, though the President need not be a Director.  The President shall have such other authority and shall perform such additional duties as may be assigned to him or her from time to time by the Board of Directors.

Section 4.  Vice President.  The Vice President, if such office shall be filled by the Board, shall have such powers and duties as may be assigned to him or her from time to time by the Board of Directors or the President.  An Executive Vice President, if elected by the Board, shall be designated by the Board to exercise the powers and perform the duties of the President in  the  absence of the President or if the President is unable to perform the duties of the office.  The Board of Directors may also designate one or more of such Vice Presidents as Senior Vice Presidents.

Section 5.  Secretary and Clerk.  The Secretary and Clerk shall be a resident of Massachusetts, unless the corporation shall have a registered agent appointed pursuant to the laws of the Commonwealth.  He or she shall keep the minutes of all meetings of the stockholders and of the Board of Directors.  He or she shall give notice of all meetings of the stockholders and of the Board. He or she shall record all votes taken at such meetings and shall have such additional powers and duties as may be assigned to him or her from time to time by the Board of Directors, the Chairman, the President or by law.

 The Secretary and Clerk shall have the custody of the Corporate Seal of the Company and shall affix the same to all instruments requiring a seal except as otherwise provided in these Bylaws.

Section 6.  Treasurer.  The Treasurer shall have charge of all receipts and disbursements of the Company, and shall be the custodian of the Company's funds.  The Treasurer shall sign all checks, notes, drafts and similar instruments, except as otherwise provided by the  Board  of Directors, and shall have such additional powers and duties as may be assigned to him or her from time to time by the Board of Directors, the Chairman, the President or by law.

Section 7.  Other Officers.  Any other officer shall have such powers and duties as may be prescribed by the Board of Directors or by another officer pursuant to Board authorization.

Section 8.  Powers.  In addition to such powers and duties as these Bylaws and the Board of Directors may prescribe, and except as may be otherwise provided by the Board, each officer shall have the powers and perform the duties which by law and general usage relate to his or her particular office.  The Board of Directors may from time to time modify the powers and duties of any officer or

4

delegate the powers or duties of any officer to any other officer or agent, notwithstanding any other provision of these Bylaws.

Section 10.  Removal.  Any officer may be removed, with or without cause, at  any time by the Board of Directors in its discretion, but an officer may be removed for cause only after a reasonable notice and opportunity to be heard by the Board has been given.

ARTICLE V

COMMITTEES

The Board of Directors by the affirmative vote of a majority of Directors then in office, may appoint such committees as it may deem proper, which committees shall have and may exercise all such authority of the Board of Directors as shall be provided in such resolution, subject to those powers expressly reserved to the Board of Directors under law.  Committees shall keep full records of their proceedings, and shall report the same to the next regular meeting of the Board, or when called upon by the Board.

ARTICLE VI

STOCK CERTIFICATES

The Board of Directors may authorize by resolution the issuance of some or all of any or all classes and series of Company shares without certificates.  The authorization shall not affect shares already represented by certificates until they are surrendered to the Company.  If the Board entitles any stockholders of a class or series to receive a certificate representing such shares, all other holders of shares of such class or series shall be entitled to the same.  All stock certificates representing shares of stock shall be signed by the Chairman, the President or any Vice President and by the Treasurer or any Assistant Treasurer.  Such signatures may be by facsimiles if the certificate is signed by a transfer agent, or by a registrar, other than a director, officer or employee of the Company.  

ARTICLE VII

CORPORATE SEAL

The corporate seal of the Company shall be circular in form with the name of the Company inscribed therein, and shall be in such other form as the Board of Directors may determine from time to time.

5

ARTICLE VIII

FISCAL YEAR

The fiscal year of the Company shall be the calendar year unless otherwise determined by the Board.

ARTICLE IX

INDEMNIFICATION

The corporation shall indemnify each of its directors and officers against any loss, liability or expense, including amounts paid in satisfaction of judgments, in compromise or as fines and penalties, and counsel fees, imposed upon or reasonably incurred by him in connection with the defense or disposition of any action, suit or other proceeding, whether civil or criminal, including but not limited to derivative suits (to the extent permitted by law), in which he may be involved or with which he may be threatened, while in office or employment or thereafter, by reason of his being or having been such a director or officer, except with respect to any matter as to which indemnification is forbidden by applicable law or as to which he shall have been adjudicated in such action, suit or proceeding not to have acted in good faith in the reasonable belief that his action was in the best interests of the corporation, or, to the extent that such matter relates to service with respect to an employee benefit plan, as in the best interests of the participants or beneficiaries of such plan.  As to any matter disposed of by a compromise payment by such director or officer, pursuant to a consent decree or otherwise, no indemnification either for said payment or for any other expenses shall be provided unless such compromise shall be approved as in the best interests of the corporation, after notice that it involves such indemnification, (a) by a disinterested majority of the directors then in office, (b) by a majority of the disinterested directors then in office, provided that there has been obtained an opinion in writing of independent legal counsel to the effect that such director or officer appears to have acted in good faith in the reasonable belief that his action was in the best interests of the corporation, or (c) by the vote, at a meeting duly called and held, of the holders of a majority of the shares outstanding and entitled to vote thereon, exclusive of any shares owned by any interested director or officer.

In discharging his duties any director or officer, when acting in good faith, shall be fully entitled to rely upon such information, opinions, reports or records, including financial statements, books of account and other financial records, in each case presented or prepared by, or under the supervision of, (a) one or more officers or employees of the corporation (or of another organization in which he serves as contemplated by this Article IX) whom the director or officer reasonably believes to be reliable and competent in the matters presented, (b) counsel, public accountants or other persons as to matters which the director or officer reasonably believes to be within such person's professional or expert competence, or (c) in the case of a director, a duly constituted committee of the board of directors (or similar governing body of such other organization) upon which he does not serve as to matters within its delegated authority, which committee the director reasonably believes to merit confidence, but he shall not be considered to be acting in good  faith  if  he has knowledge concerning the matter in question that would cause such reliance to be unwarranted.  The fact that a director or officer so relied shall be a complete defense to any claim asserted against him, except as expressly provided by statute, by reason of his being or having been a director or officer of the corporation (or such other organization).

6

No director or officer shall be liable for any act, omission, step or conduct taken or had in good faith, which (whether by condition or otherwise) is required, authorized or approved by any order or orders issued pursuant to any Federal, state or municipal statute, regulation or other lawful authority regulating the company by reason of its being a public utility company or being affiliated with public utility holding companies or by reason of its or their activities as such, or any amendments to any thereof.  In any action, suit or proceeding based on any act, omission, step or conduct, as in this paragraph described, the provisions hereof shall be brought to the attention of the court or regulatory body.  In the event that the foregoing provisions of this paragraph are found by the court or regulatory body not to constitute a valid defense on the grounds of not being applicable to the particular class of plaintiff, each such director or officer shall be reimbursed for, or indemnified against, all loss, liability and expense incurred by him or imposed on him, in connection with, or arising out of, any such action, suit or proceeding based on any act, omission, step or conduct taken or had in good faith as in this paragraph described; provided, however, that as to any matter disposed of by a compromise payment by such director or officer, pursuant to a consent decree or otherwise, no indemnification either for said payment or for any other expenses shall be provided unless such compromise shall be provided as in the best interest of the corporation as heretofore provided in this Article IX.  Such loss, liability and expense shall include, but shall not be limited to, judgments, court costs and attorneys' fees.

Expenses incurred with respect to the defense or disposition of any action, suit or proceeding heretofore referred to in this Article IX shall be advanced by the corporation prior to the final disposition of such action, suit or proceeding, upon receipt of an undertaking by or on behalf of the recipient to repay such amount if it is ultimately determined that he is not entitled to indemnification, which undertaking shall be accepted without reference to the financial ability of  the  recipient  to make such repayment.  If in an action, suit or proceeding brought by or in right of the corporation, a director or officer is held not liable, whether because relieved of liability under the first paragraph of this Article IX or he shall be deemed to have been entitled to indemnification for expenses incurred in defense of said action, suit or proceeding.

As used in this Article IX:

(i)  The term "officer" includes (a) persons who serve at the request of the corporation as director or officer of another organization and (b) officers of the corporation and its affiliates who serve in any capacity with respect to benefit plans for the corporation's employees.

(ii)  An "interested" director or officer is one against whom in such capacity the proceeding in question or another proceeding on the same or similar grounds is then pending.

Nothing contained in this Article IX shall limit the power of the corporation to indemnify directors or officers for expenses incurred in suits, actions, or other proceedings initiated by such director or officer.  The rights provided in this Article IX shall not be exclusive of or affect any other right to which any director or officer may be entitled and such rights shall inure to the benefit of his successors, heirs, executors, administrators and other legal representatives.  Such other rights shall include all powers, immunities and rights of reimbursement allowable under the laws of The Commonwealth of Massachusetts.

Article IX shall only be amended or repealed by a vote of the majority of stock present and voting thereon at any meeting of the stockholders called for such purpose where a quorum is present or by written consent in lieu of a meeting.  No amendment to or repeal of this Article IX shall apply

7

to have any effect upon the liability, exoneration or indemnification of any director or officer for or with respect to any acts or omissions of the director or officer occurring prior to such amendment or repeal.

ARTICLE X

AMENDMENTS

These Bylaws may be altered, amended or repealed by vote  of  a  majority of stock present and voting thereon at any meeting of the stockholders called for such purpose where a quorum is present or by written consent in lieu of a meeting, or if the Articles of Organization so provide, by a vote of a majority of the Board of Directors at any meeting of the Board of Directors called for the purpose or by unanimous written consent of the Board, except with respect to  any  provision which by law, the Articles of Organization or the Bylaws requires action by the stockholders.  Notice of any making, amending or repealing of any bylaw by the Board of Directors, stating the substance of such change, shall be given to all stockholders entitled to vote on amending the Bylaws, not later than the time of giving notice of the next meeting of stockholders.  Any bylaw adopted by the Directors may be amended or repealed by the stockholders.

8

EX-12

Western Massachusetts Electric Company												Exhibit 12
Ratio of Earnings to Fixed Charges
(Unaudited)
	Nine Months
	Ended
	September 30,		For the Years Ended December 31,
(Thousands of Dollars)	2014		2013		2012		2011		2010		2009
Earnings, as defined:
Net income	$	39,785	$	60,438	$	54,503	$	43,054	$	23,090	$	26,196
Income tax expense		26,596		37,368		32,140		23,186		16,325		14,923
Equity in earnings of regional nuclear      generating companies		(6)		(18)		(11)		(4)		(36)		(78)
Dividends received from regional equity investees		-		80		-		-		120		419
Fixed charges, as below		20,276		26,316		28,162		25,079		23,042		20,614
Less: Interest capitalized (including AFUDC)		(622)		(498)		(534)		(534)		(336)		(195)
Total earnings, as defined	$	86,029	$	123,686	$	114,260	$	90,781	$	62,205	$	61,879
Fixed charges, as defined:
Interest on long-term debt (a)	$	18,195	$	23,625	$	23,462	$	20,023	$	17,988	$	14,074
Interest on rate reduction bonds		-		177		1,229		2,335		3,372		4,335
Other interest (b)		734		1,049		1,943		1,254		479		877
Rental interest factor		725		967		994		933		867		1,133
Interest capitalized (including AFUDC)		622		498		534		534		336		195
Total fixed charges, as defined	$	20,276	$	26,316	$	28,162	$	25,079	$	23,042	$	20,614
Ratio of Earnings to Fixed Charges		4.24		4.70		4.06		3.62		2.70		3.00
(a) Interest on long-term debt includes amortized premiums, discounts and capitalized expenses related to indebtedness.
(b) For the year ended December 31, 2009, other interest includes interest related to accounting for uncertain tax positions.

EX-31

Exhibit 31

CERTIFICATION PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Werner J. Schweiger, certify that:

1.

I have reviewed this Quarterly Report on Form 10-Q 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 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:  November 7, 2014

/s/	Werner J. Schweiger
	Werner J. Schweiger
	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 Quarterly Report on Form 10-Q 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 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:  November 7, 2014

/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 this Quarterly Report on Form 10-Q of Western Massachusetts Electric Company (the registrant) for the period ending September 30, 2014 as filed with the Securities and Exchange Commission (the Report), we, Werner J. Schweiger, 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 results of operations of the registrant.

/s/	Werner J. Schweiger
	Werner J. Schweiger
	Chief Executive Officer

/s/	James J. Judge
	James J. Judge
	Executive Vice President and Chief Financial Officer

Date:  November 7, 2014

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.

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SEGMENT INFORMATION (Tables)

9 Months Ended

Sep. 30, 2014

Segment Reporting Information [Line Items]

Schedule Of Segment Reporting Information By Segment Text Block

	For the Three Months Ended September 30, 2014
	Electric		Natural Gas
(Millions of Dollars)	Distribution		Distribution		Transmission		Other		Eliminations		Total
Operating Revenues	$	1,502.6	$	109.2	$	262.5	$	211.2	$	(193.0)	$	1,892.5
Depreciation and Amortization		(71.7)		(16.4)		(37.4)		(13.8)		8.6		(130.7)
Other Operating Expenses		(1,141.5)		(98.4)		(74.2)		(192.4)		185.6		(1,320.9)
Operating Income/(Loss)		289.4		(5.6)		150.9		5.0		1.2		440.9
Interest Expense		(49.2)		(8.5)		(24.5)		(8.6)		1.0		(89.8)
Other Income, Net		9.3		0.1		2.7		226.4		(226.6)		11.9
Net Income Attributable to Controlling Interest	$	153.4	$	(9.9)	$	88.1	$	228.3	$	(225.3)	$	234.6
	For the Nine Months Ended September 30, 2014
	Electric		Natural Gas
(Millions of Dollars)	Distribution		Distribution		Transmission		Other		Eliminations		Total
Operating Revenues	$	4,350.4	$	737.5	$	721.4	$	568.1	$	(516.7)	$	5,860.7
Depreciation and Amortization		(309.9)		(51.1)		(111.4)		(28.3)		12.7		(488.0)
Other Operating Expenses		(3,343.9)		(586.2)		(211.5)		(534.1)		505.6		(4,170.1)
Operating Income		696.6		100.2		398.5		5.7		1.6		1,202.6
Interest Expense		(143.8)		(25.6)		(78.8)		(27.2)		3.2		(272.2)
Other Income, Net		13.6		0.2		6.9		657.9		(659.5)		19.1
Net Income Attributable to Controlling Interest	$	349.1	$	44.2	$	206.8	$	653.4	$	(655.6)	$	597.9
Cash Flows Used for Investments in Plant	$	480.1	$	120.6	$	469.9	$	46.9	$	-	$	1,117.5

	For the Three Months Ended September 30, 2013
	Electric		Natural Gas
(Millions of Dollars)	Distribution		Distribution		Transmission		Other		Eliminations		Total
Operating Revenues	$	1,508.6	$	97.1	$	234.1	$	212.5	$	(159.7)	$	1,892.6
Depreciation and Amortization		(159.6)		(16.4)		(34.5)		(11.2)		2.6		(219.1)
Other Operating Expenses		(1,064.1)		(89.4)		(73.4)		(206.8)		159.5		(1,274.2)
Operating Income/(Loss)		284.9		(8.7)		126.2		(5.5)		2.4		399.3
Interest Expense		(44.3)		(8.6)		(26.6)		(9.2)		1.2		(87.5)
Other Income, Net		5.5		0.5		2.9		312.1		(312.1)		8.9
Net Income/(Loss) Attributable to Controlling Interest	$	156.9	$	(10.4)	$	58.6	$	313.1	$	(308.7)	$	209.5
	For the Nine Months Ended September 30, 2013
	Electric		Natural Gas
(Millions of Dollars)	Distribution		Distribution		Transmission		Other		Eliminations		Total
Operating Revenues	$	4,104.4	$	613.0	$	721.5	$	650.4	$	(565.8)	$	5,523.5
Depreciation and Amortization		(488.7)		(50.5)		(100.9)		(52.0)		7.2		(684.9)
Other Operating Expenses		(2,952.4)		(483.6)		(199.1)		(599.0)		564.3		(3,669.8)
Operating Income/(Loss)		663.3		78.9		421.5		(0.6)		5.7		1,168.8
Interest Expense		(129.9)		(24.8)		(73.7)		(26.3)		4.1		(250.6)
Other Income, Net		12.6		0.7		8.5		866.2		(866.3)		21.7
Net Income Attributable to Controlling Interest	$	347.5	$	34.1	$	215.4	$	868.7	$	(857.1)	$	608.6
Cash Flows Used for Investments in Plant	$	501.9	$	91.2	$	458.2	$	22.5	$	-	$	1,073.8
The following table summarizes NU's segmented total assets:
	Electric		Natural Gas
(Millions of Dollars)	Distribution		Distribution		Transmission		Other		Eliminations		Total
As of September 30, 2014	$	16,702.3	$	2,801.1	$	7,404.5	$	12,270.2	$	(11,195.8)	$	27,982.3
As of December 31, 2013		17,260.0		2,759.7		6,745.8		11,842.4		(10,812.4)		27,795.5

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Long-Term Contractual Arrangements (Details) (Renewable Energy Contracts [Member], USD $) In Millions, unless otherwise specified	Sep. 30, 2014
The Connecticut Light And Power Company [Member]
Long-term Purchase Commitment [Line Items]
Unrecorded Unconditional Purchase Obligation, Due within One Year	$ 20.0
Unrecorded Unconditional Purchase Obligation, Due within Two Years	60.7
Unrecorded Unconditional Purchase Obligation, Due within Three Years	66.1
Unrecorded Unconditional Purchase Obligation, Due within Four Years	67.0
Unrecorded Unconditional Purchase Obligation, Due within Five Years	67.7
Unrecorded Unconditional Purchase Obligation, Due after Five Years	717.0
Unrecorded Unconditional Purchase Obligation, Total	998.5
NSTAR Electric Company [Member]
Long-term Purchase Commitment [Line Items]
Unrecorded Unconditional Purchase Obligation, Due within One Year	21.8
Unrecorded Unconditional Purchase Obligation, Due within Two Years	86.3
Unrecorded Unconditional Purchase Obligation, Due within Three Years	100.0
Unrecorded Unconditional Purchase Obligation, Due within Four Years	96.1
Unrecorded Unconditional Purchase Obligation, Due within Five Years	59.6
Unrecorded Unconditional Purchase Obligation, Due after Five Years	377.6
Unrecorded Unconditional Purchase Obligation, Total	741.4
Western Massachusetts Electric Company [Member]
Long-term Purchase Commitment [Line Items]
Unrecorded Unconditional Purchase Obligation, Due within One Year	0
Unrecorded Unconditional Purchase Obligation, Due within Two Years	0
Unrecorded Unconditional Purchase Obligation, Due within Three Years	2.4
Unrecorded Unconditional Purchase Obligation, Due within Four Years	2.4
Unrecorded Unconditional Purchase Obligation, Due within Five Years	2.4
Unrecorded Unconditional Purchase Obligation, Due after Five Years	28.9
Unrecorded Unconditional Purchase Obligation, Total	$ 36.1

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Fair Value Measurements (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Fair Value Assets Measured On Recurring Basis Unobservable Input Reconciliation [Line Items]
Beginning Balance	$ (430.9)	$ (788.1)	$ (635.2)	$ (878.6)
Net Realized/Unrealized Gains Losses included in Net Income	0	1.2		8.3
Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Asset Liability Gain Loss Included In Reg Asset Liability	(13.6)	0.8	147.6	49.6
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Liability, Settlements	21.0	21.3	64.1	55.9
Ending Balance	(423.5)	(764.8)	(423.5)	(764.8)
The Connecticut Light And Power Company [Member]
Fair Value Assets Measured On Recurring Basis Unobservable Input Reconciliation [Line Items]
Beginning Balance	(424.6)	(775.8)	(630.6)	(866.2)
Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Asset Liability Gain Loss Included In Reg Asset Liability	(15.0)	(1.2)	149.4	45.1
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Liability, Settlements	18.5	21.7	60.1	65.8
Ending Balance	(421.1)	(755.3)	(421.1)	(755.3)
NSTAR Electric Company [Member]
Fair Value Assets Measured On Recurring Basis Unobservable Input Reconciliation [Line Items]
Beginning Balance	(6.3)	(13.1)	(7.3)	(14.9)
Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Asset Liability Gain Loss Included In Reg Asset Liability	1.4	0.5	0.9	0.6
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Liability, Settlements	2.5	1.0	4.0	2.7
Ending Balance	$ (2.4)	$ (11.6)	$ (2.4)	$ (11.6)

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Contractual Obligations with Yankee Companies (Details) (USD $) In Millions, unless otherwise specified	9 Months Ended
	Sep. 30, 2014	Jun. 30, 2014	Dec. 31, 2013
Loss Contingency, Information about Litigation Matters [Abstract]
Court of Federal Claims Ruling To CYAPC			$ 126.3
Court Of Federal Claims Ruling To YAEC			73.3
Court Of Federal Claims Ruling To MYAPC			35.8
Connecticut Yankee Proceeds Received	90.0	36.3
Yankee Atomic Proceeds Received	73.3
Maine Yankee Proceeds Received	$ 35.8
Refund Obligation To Customers	As of September 30, 2014, CL&P's refund obligation to customers of $65.4 million was recorded as an offset to the deferred storm restoration costs regulatory asset, as directed by PURA. NSTAR Electric's, PSNH's and WMECO's refund obligation to customers of $29.1 million, $13.1 million and $18.1 million, respectively, was recorded as a regulatory liability in each company's respective regulatory tracker mechanisms. Refunds to customers for these DOE proceeds began in the third quarter of 2014. For further information, see Note 2, "Regulatory Accounting," to the financial statements.
MYAPC Phase One Damages Proceeds To Member Companies	DOE Phase I Damages - Proceeds Received – On September 17, 2014, in accordance with the MYAPC refund plan, MYAPC returned a portion of the DOE Phase I Damages proceeds to the member companies, including CL&P, NSTAR Electric, PSNH, and WMECO, in the amount of $3.2 million, $1.1 million, $1.4 million and $0.8 million, respectively. These amounts reduced receivables at CL&P, NSTAR Electric, PSNH and WMECO.

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PROPERTY, PLANT AND ACCUMULATED DEPRECIATION (Details) (USD $)	Sep. 30, 2014	Dec. 31, 2013
Public Utility Property Plant And Equipment [Line Items]
Public Utilities Property Plant And Equipment Distribution	$ 12,306,600,000	$ 11,950,200,000
Public Utilities Property Plant And Equipment Distribution Natural Gas	2,494,500,000	2,425,900,000
Public Utilities Property Plant And Equipment Transmission	6,564,200,000	6,412,500,000
Public Utilities Property Plant And Equipment Generation Or Processing	1,168,600,000	1,152,300,000
Public Utilities Property Plant And Equipment Electric And Natural Gas Utility Total	22,533,900,000	21,940,900,000
Public Utilities Property Plant And Equipment Other Property Plant And Equipment	541,700,000	508,700,000
Public Utilities Property Plant And Equipment Plant In Service	23,075,600,000	22,449,600,000
Electric And Natural Gas Utility Accumulated Depreciation	(5,687,000,000)	(5,387,000,000)
Other Accumulated Depreciation	(216,300,000)	(196,200,000)
Public Utilities, Property, Plant and Equipment, Accumulated Depreciation	(5,903,300,000)	(5,583,200,000)
Property Plant And Equipment Net Excluding Construction Work In Progress	17,172,300,000	16,866,400,000
Public Utilities Property Plant And Equipment Construction Work In Progress	1,082,300,000	709,800,000
Property, Plant and Equipment, Net	18,254,610,000	17,576,186,000
The Connecticut Light And Power Company [Member]
Public Utility Property Plant And Equipment [Line Items]
Public Utilities Property Plant And Equipment Distribution	5,104,800,000	4,930,700,000
Public Utilities Property Plant And Equipment Transmission	3,125,200,000	3,071,900,000
Public Utilities Property Plant And Equipment Generation Or Processing	0	0
Public Utilities Property Plant And Equipment Plant In Service	8,230,000,000	8,002,600,000
Public Utilities, Property, Plant and Equipment, Accumulated Depreciation	(1,908,200,000)	(1,804,100,000)
Property Plant And Equipment Net Excluding Construction Work In Progress	6,321,800,000	6,198,500,000
Public Utilities Property Plant And Equipment Construction Work In Progress	379,000,000	252,800,000
Property, Plant and Equipment, Net	6,700,798,000	6,451,259,000
NSTAR Electric Company [Member]
Public Utility Property Plant And Equipment [Line Items]
Public Utilities Property Plant And Equipment Distribution	4,812,400,000	4,694,700,000
Public Utilities Property Plant And Equipment Transmission	1,824,600,000	1,772,300,000
Public Utilities Property Plant And Equipment Generation Or Processing	0	0
Public Utilities Property Plant And Equipment Plant In Service	6,637,000,000	6,467,000,000
Public Utilities, Property, Plant and Equipment, Accumulated Depreciation	(1,726,700,000)	(1,631,300,000)
Property Plant And Equipment Net Excluding Construction Work In Progress	4,910,300,000	4,835,700,000
Public Utilities Property Plant And Equipment Construction Work In Progress	301,400,000	208,200,000
Property, Plant and Equipment, Net	5,211,681,000	5,043,887,000
Public Service Company Of New Hampshire [Member]
Public Utility Property Plant And Equipment [Line Items]
Public Utilities Property Plant And Equipment Distribution	1,654,500,000	1,608,200,000
Public Utilities Property Plant And Equipment Transmission	715,800,000	695,700,000
Public Utilities Property Plant And Equipment Generation Or Processing	1,134,700,000	1,131,200,000
Public Utilities Property Plant And Equipment Plant In Service	3,505,000,000	3,435,100,000
Public Utilities, Property, Plant and Equipment, Accumulated Depreciation	(1,069,400,000)	(1,021,800,000)
Property Plant And Equipment Net Excluding Construction Work In Progress	2,435,600,000	2,413,300,000
Public Utilities Property Plant And Equipment Construction Work In Progress	125,000,000	54,300,000
Property, Plant and Equipment, Net	2,560,635,000	2,467,556,000
Western Massachusetts Electric Company [Member]
Public Utility Property Plant And Equipment [Line Items]
Public Utilities Property Plant And Equipment Distribution	774,800,000	756,600,000
Public Utilities Property Plant And Equipment Transmission	851,800,000	826,400,000
Public Utilities Property Plant And Equipment Generation Or Processing	33,900,000	21,100,000
Public Utilities Property Plant And Equipment Plant In Service	1,660,500,000	1,604,100,000
Public Utilities, Property, Plant and Equipment, Accumulated Depreciation	(291,800,000)	(271,500,000)
Property Plant And Equipment Net Excluding Construction Work In Progress	1,368,700,000	1,332,600,000
Public Utilities Property Plant And Equipment Construction Work In Progress	63,700,000	48,500,000
Property, Plant and Equipment, Net	$ 1,432,368,000	$ 1,381,060,000

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Other Contingencies (Tables)

9 Months Ended

Sep. 30, 2014

Notes To Consolidated Financial Statements [Abstract]

Schedule Of Loss Contingencies By Contingency [Table Text Block]

	NU
		Third Quarter		Second Quarter
(Millions of Dollars)		2013		2014	Total
1st Complaint - Base ROE	$	23.7	$	1.2	$	24.9
2nd Complaint - Base ROE		-		27.4		27.4
Incentive ROE (1st and 2nd Complaint)		-		23.8		23.8
Cumulative Reserve	$	23.7	$	52.4	$	76.1
	CL&P						NSTAR Electric
		Third Quarter		Second Quarter				Third Quarter		Second Quarter
(Millions of Dollars)		2013		2014	Total			2013		2014	Total
1st Complaint - Base ROE	$	12.8	$	0.5	$	13.3	$	5.7	$	0.4	$	6.1
2nd Complaint - Base ROE		-		13.5		13.5		-		7.5		7.5
Incentive ROE (1st and 2nd Complaint)		-		16.1		16.1		-		2.0		2.0
Cumulative Reserve	$	12.8	$	30.1	$	42.9	$	5.7	$	9.9	$	15.6
	PSNH						WMECO
		Third Quarter		Second Quarter				Third Quarter		Second Quarter
(Millions of Dollars)		2013		2014	Total			2013		2014	Total
1st Complaint - Base ROE	$	2.3	$	0.1	$	2.4	$	2.9	$	0.2	$	3.1
2nd Complaint - Base ROE		-		2.7		2.7		-		3.7		3.7
Incentive ROE (1st and 2nd Complaint)		-		0.8		0.8		-		4.9		4.9
Cumulative Reserve	$	2.3	$	3.6	$	5.9	$	2.9	$	8.8	$	11.7

XML

Other Contingencies (Details) (USD $) In Millions, unless otherwise specified	Sep. 30, 2014	Jun. 30, 2014	Sep. 30, 2013
FERC ROE Reserve - First Complaint - Base ROE [Member]
Loss Contingencies Line Items
Loss Contingency Estimate Of Possible Loss	$ 24.9	$ 1.2	$ 23.7
FERC ROE Reserve - First Complaint - Base ROE [Member] | The Connecticut Light And Power Company [Member]
Loss Contingencies Line Items
Loss Contingency Estimate Of Possible Loss	13.3	0.5	12.8
FERC ROE Reserve - First Complaint - Base ROE [Member] | NSTAR Electric Company [Member]
Loss Contingencies Line Items
Loss Contingency Estimate Of Possible Loss	6.1	0.4	5.7
FERC ROE Reserve - First Complaint - Base ROE [Member] | Public Service Company Of New Hampshire [Member]
Loss Contingencies Line Items
Loss Contingency Estimate Of Possible Loss	2.4	0.1	2.3
FERC ROE Reserve - First Complaint - Base ROE [Member] | Western Massachusetts Electric Company [Member]
Loss Contingencies Line Items
Loss Contingency Estimate Of Possible Loss	3.1	0.2	2.9
FERC ROE Reserve - Second Complaint - Base ROE [Member]
Loss Contingencies Line Items
Loss Contingency Estimate Of Possible Loss	27.4	27.4
FERC ROE Reserve - Second Complaint - Base ROE [Member] | The Connecticut Light And Power Company [Member]
Loss Contingencies Line Items
Loss Contingency Estimate Of Possible Loss	13.5	13.5
FERC ROE Reserve - Second Complaint - Base ROE [Member] | NSTAR Electric Company [Member]
Loss Contingencies Line Items
Loss Contingency Estimate Of Possible Loss	7.5	7.5
FERC ROE Reserve - Second Complaint - Base ROE [Member] | Public Service Company Of New Hampshire [Member]
Loss Contingencies Line Items
Loss Contingency Estimate Of Possible Loss	2.7	2.7
FERC ROE Reserve - Second Complaint - Base ROE [Member] | Western Massachusetts Electric Company [Member]
Loss Contingencies Line Items
Loss Contingency Estimate Of Possible Loss	3.7	3.7
FERC ROE Reserve - Incentive - First and Second Complaint [Member]
Loss Contingencies Line Items
Loss Contingency Estimate Of Possible Loss	23.8	23.8
FERC ROE Reserve - Incentive - First and Second Complaint [Member] | The Connecticut Light And Power Company [Member]
Loss Contingencies Line Items
Loss Contingency Estimate Of Possible Loss	16.1	16.1
FERC ROE Reserve - Incentive - First and Second Complaint [Member] | NSTAR Electric Company [Member]
Loss Contingencies Line Items
Loss Contingency Estimate Of Possible Loss	2.0	2.0
FERC ROE Reserve - Incentive - First and Second Complaint [Member] | Public Service Company Of New Hampshire [Member]
Loss Contingencies Line Items
Loss Contingency Estimate Of Possible Loss	0.8	0.8
FERC ROE Reserve - Incentive - First and Second Complaint [Member] | Western Massachusetts Electric Company [Member]
Loss Contingencies Line Items
Loss Contingency Estimate Of Possible Loss	4.9	4.9
FERC ROE Reserve - Cumulative [Member]
Loss Contingencies Line Items
Loss Contingency Estimate Of Possible Loss	76.1	52.4	23.7
FERC ROE Reserve - Cumulative [Member] | The Connecticut Light And Power Company [Member]
Loss Contingencies Line Items
Loss Contingency Estimate Of Possible Loss	42.9	30.1	12.8
FERC ROE Reserve - Cumulative [Member] | NSTAR Electric Company [Member]
Loss Contingencies Line Items
Loss Contingency Estimate Of Possible Loss	15.6	9.9	5.7
FERC ROE Reserve - Cumulative [Member] | Public Service Company Of New Hampshire [Member]
Loss Contingencies Line Items
Loss Contingency Estimate Of Possible Loss	5.9	3.6	2.3
FERC ROE Reserve - Cumulative [Member] | Western Massachusetts Electric Company [Member]
Loss Contingencies Line Items
Loss Contingency Estimate Of Possible Loss	11.7	8.8	2.9
FERC ROE Reserve - Cumulative - After Tax Charge [Member]
Loss Contingencies Line Items
Loss Contingency Estimate Of Possible Loss		32.1	14.3
FERC ROE Reserve - Cumulative - After Tax Charge [Member] | The Connecticut Light And Power Company [Member]
Loss Contingencies Line Items
Loss Contingency Estimate Of Possible Loss		18.5	7.7
FERC ROE Reserve - Cumulative - After Tax Charge [Member] | NSTAR Electric Company [Member]
Loss Contingencies Line Items
Loss Contingency Estimate Of Possible Loss		6.1	3.4
FERC ROE Reserve - Cumulative - After Tax Charge [Member] | Public Service Company Of New Hampshire [Member]
Loss Contingencies Line Items
Loss Contingency Estimate Of Possible Loss		2.0	1.4
FERC ROE Reserve - Cumulative - After Tax Charge [Member] | Western Massachusetts Electric Company [Member]
Loss Contingencies Line Items
Loss Contingency Estimate Of Possible Loss		$ 5.5	$ 1.8

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REGULATORY ACCOUNTING (Tables)

9 Months Ended

Sep. 30, 2014

Notes To Consolidated Financial Statements [Abstract]

Schedule Of Regulatory Assets Text Block

	As of September 30, 2014		As of December 31, 2013
(Millions of Dollars)	NU		NU
Benefit Costs	$	1,113.2	$	1,240.2
Derivative Liabilities		427.5		638.0
Income Taxes, Net		623.2		626.2
Storm Restoration Costs		493.5		589.6
Goodwill-related		510.5		525.9
Regulatory Tracker Mechanisms		235.7		323.4
Contractual Obligations - Yankee Companies		124.6		154.2
Buy Out Agreements for Power Contracts		49.8		70.2
Other Regulatory Assets		109.1		126.8
Total Regulatory Assets		3,687.1		4,294.5
Less: Current Portion		446.0		535.8
Total Long-Term Regulatory Assets	$	3,241.1	$	3,758.7

	As of September 30, 2014								As of December 31, 2013
			NSTAR								NSTAR
(Millions of Dollars)	CL&P		Electric		PSNH		WMECO		CL&P		Electric		PSNH		WMECO
Benefit Costs	$	242.2	$	318.1	$	78.1	$	44.3	$	297.7	$	496.7	$	100.6	$	57.3
Derivative Liabilities		421.1		4.3		-		-		630.4		7.7		-		-
Income Taxes, Net		427.4		83.3		38.3		35.3		415.5		84.0		40.3		43.7
Storm Restoration Costs		326.0		106.2		29.3		32.0		397.8		109.3		43.7		38.8
Goodwill-related		-		438.3		-		-		-		451.5		-		-
Regulatory Tracker Mechanisms		5.2		76.4		94.7		23.5		8.0		169.5		83.3		32.6
Buy Out Agreements for Power Contracts		-		45.4		4.4		-		-		64.7		5.5		-
Other Regulatory Assets		63.6		54.2		35.9		13.5		64.6		55.9		38.1		16.7
Total Regulatory Assets		1,485.5		1,126.2		280.7		148.6		1,814.0		1,439.3		311.5		189.1
Less: Current Portion		116.5		128.2		102.5		38.9		150.9		204.1		92.2		43.0
Total Long-Term Regulatory Assets	$	1,369.0	$	998.0	$	178.2	$	109.7	$	1,663.1	$	1,235.2	$	219.3	$	146.1

Schedule Of Regulatory Liabilities Text Block

	As of September 30, 2014		As of December 31, 2013
(Millions of Dollars)	NU		NU
Cost of Removal	$	439.1	$	435.1
Regulatory Tracker Mechanisms		339.9		151.2
AFUDC - Transmission		67.2		68.1
Other Regulatory Liabilities		62.7		52.9
Total Regulatory Liabilities		908.9		707.3
Less: Current Portion		399.0		204.3
Total Long-Term Regulatory Liabilities	$	509.9	$	503.0

	As of September 30, 2014								As of December 31, 2013
			NSTAR								NSTAR
(Millions of Dollars)	CL&P		Electric		PSNH		WMECO		CL&P		Electric		PSNH		WMECO
Cost of Removal	$	22.5	$	260.7	$	49.2	$	-	$	29.1	$	250.0	$	49.7	$	-
Regulatory Tracker Mechanisms		196.4		67.3		25.9		43.9		95.6		21.9		21.6		21.1
AFUDC - Transmission		53.9		4.1		-		9.2		54.7		4.1		-		9.3
Other Regulatory Liabilities		10.6		31.6		4.7		0.7		8.4		31.1		1.0		3.4
Total Regulatory Liabilities		283.4		363.7		79.8		53.8		187.8		307.1		72.3		33.8
Less: Current Portion		195.7		97.2		29.2		43.5		94.0		54.0		20.6		19.9
Total Long-Term Regulatory Liabilities	$	87.7	$	266.5	$	50.6	$	10.3	$	93.8	$	253.1	$	51.7	$	13.9

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SHORT TERM AND LONG TERM DEBT (Details) (USD $)	9 Months Ended	12 Months Ended
	Sep. 30, 2014	Dec. 31, 2013
Line of Credit Facility [Line Items]
Line of Credit Facility, Remaining Borrowing Capacity	$ 485,500,000	$ 435,500,000
Line of Credit Facility, Amount Outstanding	964,500,000	1,010,000,000
Short-term Debt, Weighted Average Interest Rate	0.25%	0.24%
Description of commercial paper program	Effective July 23, 2014, NU parent, CL&P, PSNH, WMECO, NSTAR Gas and Yankee Gas extended the expiration date of their joint $1.45 billion revolving credit facility for one additional year to September 6, 2019. The revolving credit facility is to be used primarily to backstop NU parent's $1.45 billion commercial paper program. The commercial paper program allows NU parent to issue commercial paper as a form of short-term debt. As of September 30, 2014 and December 31, 2013, NU had $964.5 million and $1.01 billion, respectively, in short-term borrowings outstanding under the NU parent commercial paper program, leaving $485.5 million and $435.5 million of available borrowing capacity as of September 30, 2014 and December 31, 2013, respectively. The weighted-average interest rate on these borrowings as of September 30, 2014 and December 31, 2013 was 0.25 percent and 0.24 percent, respectively, which is generally based on A2/P2 rated commercial paper. As of September 30, 2014, there were intercompany loans from NU of $105.4 million to CL&P, $153.3 million to PSNH and $13.2 million to WMECO. As of December 31, 2013, there were intercompany loans from NU of $287.3 million to CL&P and $86.5 million to PSNH. Effective July 23, 2014, NSTAR Electric extended the expiration date of its $450 million revolving credit facility for one additional year to September 6, 2019. This facility serves to backstop NSTAR Electric's existing $450 million commercial paper program. As of September 30, 2014 and December 31, 2013, NSTAR Electric had $159.5 million and $103.5 million, respectively, in short-term borrowings outstanding under its commercial paper program, leaving $290.5 million and $346.5 million of available borrowing capacity as of September 30, 2014 and December 31, 2013, respectively. The weighted-average interest rate on these borrowings as of September 30, 2014 and December 31, 2013 was 0.16 percent and 0.13 percent, respectively, which is generally based on A2/P1 rated commercial paper.
Notes Payable	1,046,961,000	1,093,000,000
Long-term Debt, Description	On January 2, 2014, Yankee Gas issued $100 million of 4.82 percent Series L First Mortgage Bonds, due to mature in 2044. The proceeds, net of issuance costs, were used to repay the $75 million 4.80 percent Series G First Mortgage Bonds that matured on January 1, 2014 and to pay $25 million in short-term borrowings. As the debt issuance refinanced short-term debt, the short-term debt was classified as Long-Term Debt on NU's balance sheet as of December 31, 2013. On March 7, 2014, NSTAR Electric issued $300 million of 4.40 percent debentures, due to mature in 2044. The proceeds, net of issuance costs, were used to repay the $300 million of 4.875 percent debentures that matured on April 15, 2014. On April 24, 2014, CL&P issued $250 million of 4.30 percent 2014 Series A First Mortgage Bonds, due to mature in 2044. The proceeds, net of issuance costs, were used to repay short-term borrowings. On July 15, 2014, PSNH repaid at maturity the $50 million of 5.25 percent Series L First Mortgage Bonds using short-term borrowings. On September 15, 2014, CL&P repaid at maturity the $150 million of 4.80 percent 2004 Series A First Mortgage Bonds. On October 14, 2014, PSNH issued $75 million of first mortgage bonds at a yield of 3.144 percent that will mature on November 1, 2023. The first mortgage bonds are part of the same series of PSNH’s existing 3.50 percent Series S First Mortgage Bonds that were initially issued in November 2013. As a result, the aggregate principal amount of PSNH’s outstanding Series S First Mortgage Bonds totals $325 million. The proceeds, net of issuance costs, were used to repay short-term borrowings. As the debt issuance refinanced short-term debt, the short-term debt was classified as Long-Term Debt on NU's balance sheet as of September 30, 2014.
The Connecticut Light And Power Company [Member]
Line of Credit Facility [Line Items]
Notes Payable To Affiliated Companies	105,400,000	287,300,000
NSTAR Electric Company [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Remaining Borrowing Capacity	290,500,000	346,500,000
Line of Credit Facility, Amount Outstanding	159,500,000	103,500,000
WeightedAverageDiscountRatePercent	0.16%	0.13%
Notes Payable	159,500,000	103,500,000
Public Service Company Of New Hampshire [Member]
Line of Credit Facility [Line Items]
Notes Payable To Affiliated Companies	153,300,000	86,500,000
Western Massachusetts Electric Company [Member]
Line of Credit Facility [Line Items]
Notes Payable To Affiliated Companies	$ 13,200,000	$ 0

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Other Taxes (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Excise And Sales Taxes	$ 35.0	$ 37.5	$ 114.6	$ 108.9
The Connecticut Light And Power Company [Member]
Excise And Sales Taxes	$ 32.5	$ 35.5	$ 99.0	$ 97.3

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COMMON SHARESHOLDERS' EQUITY AND NONCONTROLLING INTERESTS (NU) (Tables)

9 Months Ended

Sep. 30, 2014

Notes To Consolidated Financial Statements [Abstract]

Minority Interest Disclosure Text Block

13.	COMMON SHAREHOLDERS' EQUITY AND NONCONTROLLING INTERESTS
A summary of the changes in Common Shareholders' Equity and Noncontrolling Interests of NU is as follows:
		For the Three Months Ended
		September 30, 2014				September 30, 2013
				Noncontrolling				Noncontrolling
				Interest -				Interest -
		Common		Preferred		Common		Preferred
		Shareholders'		Stock of		Shareholders'		Stock of
(Millions of Dollars)		Equity		Subsidiaries		Equity		Subsidiaries
Balance as of Beginning of Period		$	9,753.8	$	155.6	$	9,406.6	$	155.6
Net Income			236.5		-		211.4		-
Dividends on Common Shares			(124.2)		-		(114.9)		-
Dividends on Preferred Stock			(1.9)		(1.9)		(1.9)		(1.9)
Issuance of Common Shares			1.0		-		1.4		-
Other Transactions, Net			24.1		-		12.8		-
Net Income Attributable to Noncontrolling Interests			-		1.9		-		1.9
Other Comprehensive Income			1.3		-		2.1		-
Balance as of End of Period		$	9,890.6	$	155.6	$	9,517.5	$	155.6
		For the Nine Months Ended
		September 30, 2014				September 30, 2013
				Noncontrolling				Noncontrolling
				Interest -				Interest -
		Common		Preferred		Common		Preferred
		Shareholders'		Stock of		Shareholders'		Stock of
(Millions of Dollars)		Equity		Subsidiaries		Equity		Subsidiaries
Balance as of Beginning of Period		$	9,611.5	$	155.6	$	9,237.1	$	155.6
Net Income			603.6		-		614.4		-
Dividends on Common Shares			(372.2)		-		(346.9)		-
Dividends on Preferred Stock			(5.6)		(5.6)		(5.8)		(5.8)
Issuance of Common Shares			6.4		-		10.2		-
Other Transactions, Net			41.0		-		3.0		-
Net Income Attributable to Noncontrolling Interests			-		5.6		-		5.8
Other Comprehensive Income			5.9		-		5.5		-
Balance as of End of Period		$	9,890.6	$	155.6	$	9,517.5	$	155.6

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INCOME TAXES (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Deferred Income Tax Expense (Benefit), Continuing Operations [Abstract]
Total Deferred Income Taxes			$ 64,755	$ 334,225
Income Tax Expense	126,539	109,351	345,858	325,442
Income Tax Expense (Benefit), Continuing Operations, Income Tax Reconciliation [Abstract]
Income Before Income Tax Expense	363,032	320,731	949,434	939,855
Income Tax Expense	126,539	109,351	345,858	325,442
The Connecticut Light And Power Company [Member]
Deferred Income Tax Expense (Benefit), Continuing Operations [Abstract]
Total Deferred Income Taxes			(14,400)	89,084
Income Tax Expense	30,038	36,136	95,980	113,149
Income Tax Expense (Benefit), Continuing Operations, Income Tax Reconciliation [Abstract]
Income Before Income Tax Expense	113,914	102,459	296,540	332,337
Income Tax Expense	30,038	36,136	95,980	113,149
Other Tax Disclosures [Abstract]
Other Information Pertaining To Income Taxes			In the third quarter of 2014, the Company recorded a reduction to its state credit carryforwards of $11 million (CL&P $10.1 million), net of tax, as a result of an update to reflect the amounts expired. Further, the Company decreased its valuation allowance reserve for state credits by $22.3 million (all at CL&P), net of tax, to reflect the expiration of state credits in its recently filed return and the latest available data. These updates resulted in a net reduction in income tax expense of $11.3 million (CL&P $12.2 million).
NSTAR Electric Company [Member]
Deferred Income Tax Expense (Benefit), Continuing Operations [Abstract]
Total Deferred Income Taxes			(39,399)	26,358
Income Tax Expense	76,975	68,558	156,655	137,499
Income Tax Expense (Benefit), Continuing Operations, Income Tax Reconciliation [Abstract]
Income Before Income Tax Expense	192,549	175,567	390,446	350,661
Income Tax Expense	76,975	68,558	156,655	137,499
Public Service Company Of New Hampshire [Member]
Deferred Income Tax Expense (Benefit), Continuing Operations [Abstract]
Total Deferred Income Taxes			67,827	57,066
Income Tax Expense	17,603	18,196	52,199	52,797
Income Tax Expense (Benefit), Continuing Operations, Income Tax Reconciliation [Abstract]
Income Before Income Tax Expense	45,839	46,549	137,154	137,340
Income Tax Expense	17,603	18,196	52,199	52,797
Western Massachusetts Electric Company [Member]
Deferred Income Tax Expense (Benefit), Continuing Operations [Abstract]
Total Deferred Income Taxes			13,479	79,401
Income Tax Expense	10,490	8,588	26,596	30,424
Income Tax Expense (Benefit), Continuing Operations, Income Tax Reconciliation [Abstract]
Income Before Income Tax Expense	25,155	23,613	66,381	80,465
Income Tax Expense	$ 10,490	$ 8,588	$ 26,596	$ 30,424

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COMMON SHAREHOLDER EQUIT AND NCI (Details) (USD $)	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Shareholders' Equity, Beginning Balance			$ 9,611,528,000
Net Income	236,493,000	211,380,000	603,576,000	614,413,000
Dividends on Common Shares			0
Issuance of Common Shares			0
Other Transcations, Net	0		0
Net Income Attributable to Noncontrolling Interests	1,879,000	1,879,000	5,639,000	5,803,000
Other Comprehensive Income (Loss), Net of Tax	1,335,000	2,082,000	5,859,000	5,467,000
Shareholders' Equity, Ending Balance	9,890,552,000		9,890,552,000
Common Shareholders Equity [Member]
Shareholders' Equity, Beginning Balance	9,753,800,000	9,406,600,000	9,611,500,000	9,237,100,000
Net Income	236,500,000	211,400,000	603,600,000	614,400,000
Dividends on Common Shares	(124,200,000)	(114,900,000)	(372,200,000)	(346,900,000)
Dividends on Preferred Stock	(1,900,000)	(1,900,000)	(5,600,000)	(5,800,000)
Issuance of Common Shares	1,000,000	1,400,000	6,400,000	10,200,000
Other Transcations, Net	24,100,000	12,800,000	41,000,000	3,000,000
Net Income Attributable to Noncontrolling Interests			0	0
Other Comprehensive Income (Loss), Net of Tax	1,300,000	2,100,000	5,900,000	5,500,000
Shareholders' Equity, Ending Balance	9,890,600,000	9,517,500,000	9,890,600,000	9,517,500,000
Noncontrolling Interest Member
Net Income				0
Dividends on Common Shares				0
Issuance of Common Shares				0
Other Transcations, Net				0
Preferred Stock Member
Shareholders' Equity, Beginning Balance	155,600,000	155,600,000	155,600,000	155,600,000
Net Income			0
Dividends on Preferred Stock	(1,900,000)	(1,900,000)	(5,600,000)	(5,800,000)
Net Income Attributable to Noncontrolling Interests	1,900,000	1,900,000	5,600,000	5,800,000
Shareholders' Equity, Ending Balance	$ 155,600,000	$ 155,600,000	$ 155,600,000	$ 155,600,000

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DERIVATIVE INSTURMENTS (Details) (USD $)	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013	Dec. 31, 2013
Derivative Instrument Detail Abstract
Derivative Liabilities, Noncurrent	$ (420,931,000)		$ (420,931,000)		$ (624,050,000)
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, along with UI, has capacity-related contracts with generation facilities. 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 combined capacity of these contracts is 787 MW. The capacity contracts extend through 2026 and obligate both CL&P and UI 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 and a capacity-related contract to purchase up to 35 MW per year through 2019. As of September 30, 2014 and December 31, 2013, NU had NYMEX future contracts in order to reduce variability associated with the purchase price of approximately 9.7 million and 9.1 million MMBtu of natural gas, respectively.
Derivative Instruments Not Designated As Hedging Instruments Gain Loss Net Abstract
Derivative Gain Loss On Derivative Net		200,000		900,000
Derivative Instruments Gain Loss Recognized In Regulatory Asset Liability	(15,700,000)	300,000	149,900,000	48,800,000
FairValueInputsQuantitativeInformation[Abstract]
FairValueInputsExitPricePremium			Exit price premiums of 8 percent through 25 percent are also applied on these contracts and reflect the most recent market activity available for similar type contracts.
The Connecticut Light And Power Company [Member]
Derivative Instrument Detail Abstract
Derivative Liabilities - Current	(86,759,000)		(86,759,000)		(92,233,000)
Derivative Liabilities, Noncurrent	(418,137,000)		(418,137,000)		(617,072,000)
Fair Value Inputs Level 2 [Member]
Derivative Instrument Detail Abstract
Derivative Assets - Current	400,000		400,000		1,600,000
Derivative Liabilities - Current	(2,000,000)		(2,000,000)
Derivative Assets Noncurrent					200,000
Fair Value Inputs Level 3 [Member]
Derivative Instrument Detail Abstract
Derivative Assets - Current	10,600,000		10,600,000		8,600,000
Derivative Liabilities - Current	(88,300,000)		(88,300,000)		(93,700,000)
Derivative Liabilities, Noncurrent	(420,900,000)		(420,900,000)		(624,100,000)
Derivative Assets Noncurrent	75,100,000		75,100,000		74,000,000
Fair Value Inputs Level 3 [Member] | MinimumMember
FairValueInputsQuantitativeInformation[Abstract]
FairValueInputsCapacityPrices	7.03		7.03		5.07
FairValueInputsEnergyPrices	66		66		49
FairValueInputsRenewableEnergyCreditPrices	41		41		36
FairValueInputsForwardReserve	5.80		5.80		3.30
Fair Value Inputs Level 3 [Member] | MaximumMember
FairValueInputsQuantitativeInformation[Abstract]
FairValueInputsCapacityPrices	12.98		12.98		11.82
FairValueInputsEnergyPrices	68		68		77
FairValueInputsRenewableEnergyCreditPrices	70		70		87
FairValueInputsForwardReserve	9.50		9.50		3.30
Fair Value Inputs Level 3 [Member] | The Connecticut Light And Power Company [Member]
Derivative Instrument Detail Abstract
Derivative Assets - Current	9,600,000		9,600,000		7,300,000
Derivative Liabilities - Current	(86,800,000)		(86,800,000)		(92,200,000)
Derivative Liabilities, Noncurrent	(418,100,000)		(418,100,000)		(617,100,000)
Derivative Assets Noncurrent	74,200,000		74,200,000		71,400,000
Fair Value Inputs Level 3 [Member] | The Connecticut Light And Power Company [Member] | MinimumMember
FairValueInputsQuantitativeInformation[Abstract]
FairValueInputsCapacityPrices	7.03		7.03		5.07
FairValueInputsEnergyPrices	66		66		56
FairValueInputsForwardReserve	5.80		5.80		3.30
Fair Value Inputs Level 3 [Member] | The Connecticut Light And Power Company [Member] | MaximumMember
FairValueInputsQuantitativeInformation[Abstract]
FairValueInputsCapacityPrices	12.98		12.98		10.42
FairValueInputsEnergyPrices	68		68		58
FairValueInputsForwardReserve	9.50		9.50		3.30
Fair Value Inputs Level 3 [Member] | NSTAR Electric Company [Member]
Derivative Instrument Detail Abstract
Derivative Assets - Current	1,000,000		1,000,000		1,200,000
Derivative Liabilities - Current	(1,500,000)		(1,500,000)		(1,500,000)
Derivative Liabilities, Noncurrent	(2,800,000)		(2,800,000)		(7,000,000)
Derivative Assets Noncurrent	900,000		900,000
Fair Value Inputs Level 3 [Member] | NSTAR Electric Company [Member] | MinimumMember
FairValueInputsQuantitativeInformation[Abstract]
FairValueInputsCapacityPrices	11.00		11.00		5.07
FairValueInputsRenewableEnergyCreditPrices	41		41		36
Fair Value Inputs Level 3 [Member] | NSTAR Electric Company [Member] | MaximumMember
FairValueInputsQuantitativeInformation[Abstract]
FairValueInputsCapacityPrices	11.10		11.10		7.38
FairValueInputsRenewableEnergyCreditPrices	70		70		70
Netting And Collateral [Member] | Fair Value Inputs Level 2 [Member]
Derivative Instrument Detail Abstract
Derivative Assets - Current	0		0		(300,000)
Derivative Liabilities - Current	400,000		400,000
Netting And Collateral [Member] | Fair Value Inputs Level 3 [Member]
Derivative Instrument Detail Abstract
Derivative Assets - Current	(6,800,000)		(6,800,000)		(9,800,000)
Derivative Assets Noncurrent	(20,900,000)		(20,900,000)		(42,200,000)
Netting And Collateral [Member] | Fair Value Inputs Level 3 [Member] | The Connecticut Light And Power Company [Member]
Derivative Instrument Detail Abstract
Derivative Assets - Current	(6,800,000)		(6,800,000)		(9,800,000)
Derivative Assets Noncurrent	(20,900,000)		(20,900,000)		(42,200,000)
Commodity [Member] | Fair Value Inputs Level 2 [Member]
Derivative Instrument Detail Abstract
Derivative Assets - Current	400,000		400,000		1,900,000
Derivative Liabilities - Current	(2,400,000)		(2,400,000)
Derivative Assets Noncurrent					200,000
Commodity [Member] | Fair Value Inputs Level 3 [Member]
Derivative Instrument Detail Abstract
Derivative Assets - Current	17,400,000		17,400,000		18,400,000
Derivative Liabilities - Current	(88,300,000)		(88,300,000)		(93,700,000)
Derivative Liabilities, Noncurrent	(420,900,000)		(420,900,000)		(624,100,000)
Derivative Assets Noncurrent	96,000,000		96,000,000		116,200,000
Commodity [Member] | Fair Value Inputs Level 3 [Member] | The Connecticut Light And Power Company [Member]
Derivative Instrument Detail Abstract
Derivative Assets - Current	16,400,000		16,400,000		17,100,000
Derivative Liabilities - Current	(86,800,000)		(86,800,000)		(92,200,000)
Derivative Liabilities, Noncurrent	(418,100,000)		(418,100,000)		(617,100,000)
Derivative Assets Noncurrent	95,100,000		95,100,000		113,600,000
Commodity [Member] | Fair Value Inputs Level 3 [Member] | NSTAR Electric Company [Member]
Derivative Instrument Detail Abstract
Derivative Assets - Current	1,000,000		1,000,000		1,200,000
Derivative Liabilities - Current	(1,500,000)		(1,500,000)		(1,500,000)
Derivative Liabilities, Noncurrent	(2,800,000)		(2,800,000)		(7,000,000)
Derivative Assets Noncurrent	$ 900,000		$ 900,000

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DERIVATIVE INSTRUMENTS

9 Months Ended

Sep. 30, 2014

Notes To Consolidated Financial Statements [Abstract]

Derivative Instruments and Hedging Activities Disclosure [Text Block]

4.       DERIVATIVE INSTRUMENTS

The Regulated companies purchase and procure energy and energy-related products, which are subject to price volatility, for their customers. 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 and nonderivative contracts.

Many of the derivative contracts meet the definition of, and are designated as, normal and qualify for accrual accounting under the applicable accounting guidance. The costs and benefits of derivative contracts that meet the definition of normal are recognized in Operating Expenses or Operating Revenues on the statements of income, as applicable, as electricity or natural gas is delivered.

Derivative contracts that are not designated as normal are recorded at fair value as current or long-term Derivative Assets or Derivative Liabilities on the balance sheets. For the Regulated companies, regulatory assets or regulatory liabilities are recorded to offset the fair values of derivatives, as costs are recovered from, or refunded to, customers in their respective energy supply rates. For NU's unregulated wholesale marketing contracts that expired on December 31, 2013, changes in fair values of derivatives were included in Net 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, on the balance sheets. The following tables present the gross fair values of contracts categorized by risk type and the net amount recorded as current or long-term derivative asset or liability:

		As of September 30, 2014
		Commodity Supply and				Net Amount Recorded as
(Millions of Dollars)		Price Risk Management		Netting (1)		Derivative Asset/(Liability)
Current Derivative Assets:
Level 2:
	NU (1)	$	0.4	$	-	$	0.4
Level 3:
	NU (1)		17.4		(6.8)		10.6
	CL&P (1)		16.4		(6.8)		9.6
	NSTAR Electric		1.0		-		1.0
Long-Term Derivative Assets:
Level 3:
	NU (1)	$	96.0	$	(20.9)	$	75.1
	CL&P (1)		95.1		(20.9)		74.2
	NSTAR Electric		0.9		-		0.9
Current Derivative Liabilities:
Level 2:
	NU (1)	$	(2.4)	$	0.4	$	(2.0)
Level 3:
	NU		(88.3)		-		(88.3)
	CL&P		(86.8)		-		(86.8)
	NSTAR Electric		(1.5)		-		(1.5)
Long-Term Derivative Liabilities:
Level 3:
	NU	$	(420.9)	$	-	$	(420.9)
	CL&P		(418.1)		-		(418.1)
	NSTAR Electric		(2.8)		-		(2.8)

		As of December 31, 2013
		Commodity Supply and				Net Amount Recorded as
(Millions of Dollars)		Price Risk Management		Netting (1)		Derivative Asset/(Liability)
Current Derivative Assets:
Level 2:
	NU (1)	$	1.9	$	(0.3)	$	1.6
Level 3:
	NU (1)		18.4		(9.8)		8.6
	CL&P (1)		17.1		(9.8)		7.3
	NSTAR Electric		1.2		-		1.2
Long-Term Derivative Assets:
Level 2:
	NU	$	0.2	$	-	$	0.2
Level 3:
	NU (1)		116.2		(42.2)		74.0
	CL&P (1)		113.6		(42.2)		71.4
Current Derivative Liabilities:
Level 3:
	NU	$	(93.7)	$	-	$	(93.7)
	CL&P		(92.2)		-		(92.2)
	NSTAR Electric		(1.5)		-		(1.5)
Long-Term Derivative Liabilities:
Level 3:
	NU	$	(624.1)	$	-	$	(624.1)
	CL&P		(617.1)		-		(617.1)
	NSTAR Electric		(7.0)		-		(7.0)

Amounts represent derivative assets and liabilities that NU elected to record net on the balance sheets. These amounts are subject to master netting agreements or similar agreements for which the right of offset exists.

For further information on the fair value of derivative contracts, see Note 1D, "Summary of Significant Accounting Policies -Fair Value Measurements," to the financial statements.

Derivatives At Fair Value with Offsetting Regulatory Amounts

Commodity Supply and Price Risk Management: As required by regulation, CL&P, along with UI, has capacity-related contracts with generation facilities. 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 combined capacity of these contracts is 787 MW. The capacity contracts extend through 2026 and obligate both CL&P and UI 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 and a capacity-related contract to purchase up to 35 MW per year through 2019.

As of September 30, 2014 and December 31, 2013, NU had NYMEX future contracts in order to reduce variability associated with the purchase price of approximately 9.7 million and 9.1million MMBtu of natural gas, respectively.

The following table presents the current change in fair value, primarily recovered through rates from customers, associated with NU's derivative contracts not designated as hedges:

		Amounts Recognized on Derivatives
		For the Three Months Ended September 30,				For the Nine Months Ended September 30,
(Millions of Dollars)		2014		2013		2014		2013
NU
Balance Sheets:
	Regulatory Assets and Liabilities	$	(15.7)	$	0.3	$	149.9	$	48.8
Statements of Income:
	Purchased Power, Fuel and Transmission		-		0.2		-		0.9

Valuation of Derivative Instruments

Derivative contracts classified as Level 2 in the fair value hierarchy relate to the financial contracts for natural gas futures. Prices are obtained from broker quotes and are based on actual market activity. The contracts are valued using NYMEX natural gas prices. Valuations of these contracts also incorporate discount rates using the yield curve approach.

The fair value of derivative contracts classified as Level 3 utilizes significant unobservable inputs. The fair value is modeled using income techniques, such as discounted cash flow valuations 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 a 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 and NSTAR Electric's, Level 3 derivative contracts and the range of the significant unobservable inputs utilized in the valuations over the duration of the contracts:

	As of September 30, 2014							As of December 31, 2013
		Range					Period Covered		Range					Period Covered
Energy Prices:
NU	$	66	-	68	per MWh		2018 - 2020	$	49	-	77	per MWh		2018 - 2029
CL&P	$	66	-	68	per MWh		2018 - 2020	$	56	-	58	per MWh		2018 - 2029
Capacity Prices:
NU	$	7.03	-	12.98		per kW-Month	2016 - 2026	$	5.07	-	11.82		per kW-Month	2017 - 2029
CL&P	$	7.03	-	12.98		per kW-Month	2018 - 2026	$	5.07	-	10.42		per kW-Month	2017 - 2026
NSTAR Electric	$	11.00	-	11.10		per kW-Month	2016 - 2019	$	5.07	-	7.38		per kW-Month	2017 - 2019
Forward Reserve:
NU, CL&P	$	5.80	-	9.50		per kW-Month	2014 - 2024	$	3.30	-	3.30		per kW-Month	2014 - 2024
REC Prices:
NU	$	41	-	70	per REC		2014 - 2018	$	36	-	87	per REC		2014 - 2029
NSTAR Electric	$	41	-	70	per REC		2014 - 2018	$	36	-	70	per REC		2014 - 2018

Exit price premiums of 8 percent through 25 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 energy 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 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.

		For the Three Months Ended September 30,				For the Nine Months Ended September 30,
		2014		2013		2014		2013
(Millions of Dollars)		NU		NU		NU		NU
Derivatives, Net:
Fair Value as of Beginning of Period		$	(430.9)	$	(788.1)	$	(635.2)	$	(878.6)
Net Realized/Unrealized Gains Included in:
	Net Income		-		1.2		-		8.3
	Regulatory Assets and Liabilities		(13.6)		0.8		147.6		49.6
Settlements			21.0		21.3		64.1		55.9
Fair Value as of End of Period		$	(423.5)	$	(764.8)	$	(423.5)	$	(764.8)

	For the Three Months Ended September 30,
	2014				2013
(Millions of Dollars)	CL&P		NSTAR Electric		CL&P		NSTAR Electric
Derivatives, Net:
Fair Value as of Beginning of Period	$	(424.6)	$	(6.3)	$	(775.8)	$	(13.1)
Net Realized/Unrealized Gains/(Losses) Included in Regulatory Assets and Liabilities		(15.0)		1.4		(1.2)		0.5
Settlements		18.5		2.5		21.7		1.0
Fair Value as of End of Period	$	(421.1)	$	(2.4)	$	(755.3)	$	(11.6)
	For the Nine Months Ended September 30,
	2014				2013
(Millions of Dollars)	CL&P		NSTAR Electric		CL&P		NSTAR Electric
Derivatives, Net:
Fair Value as of Beginning of Period	$	(630.6)	$	(7.3)	$	(866.2)	$	(14.9)
Net Realized/Unrealized Gains/(Losses) Included in Regulatory Assets and Liabilities		149.4		0.9		45.1		0.6
Settlements		60.1		4.0		65.8		2.7
Fair Value as of End of Period	$	(421.1)	$	(2.4)	$	(755.3)	$	(11.6)

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EARNINGS PER SHARE (Details) (USD $) In Thousands, except Share data, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Notes To Consolidated Financial Statements [Abstract]
Net Income Attributable to Controlling Interests	$ 234,614	$ 209,501	$ 597,937	$ 608,610
Basic	316,340,691	315,291,346	315,941,904	315,191,752
Weighted Average Number Diluted Shares Outstanding Adjustment	1,214,234	926,893	1,244,586	869,379
Diluted	317,554,925	316,218,239	317,186,490	316,061,131
Earnings Per Share Basic And Diluted	$ 0.74	$ 0.66	$ 1.89	$ 1.93
Antidilutive Securities Excluded From Computation Of Earnings Per Share Amount	0	0	0	2,100

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Supplemental Cash Flow Information (Details) (USD $) In Millions, unless otherwise specified	9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013
Capital Expenditures Incurred But Not Yet Paid	$ 128.9	$ 122.9
The Connecticut Light And Power Company [Member]
Capital Expenditures Incurred But Not Yet Paid	52.2	36.6
NSTAR Electric Company [Member]
Capital Expenditures Incurred But Not Yet Paid	18.1	31.9
Public Service Company Of New Hampshire [Member]
Capital Expenditures Incurred But Not Yet Paid	21.0	16.9
Western Massachusetts Electric Company [Member]
Capital Expenditures Incurred But Not Yet Paid	$ 10.0	$ 13.8

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Pension Benefits and Postretirement Benefits Other Than Pensions (Tables)

9 Months Ended

Sep. 30, 2014

Notes To Consolidated Financial Statements [Abstract]

Schedule Of Net Benefit Costs [Table Text Block]

	Pension and SERP				Pension and SERP
	For the Three Months Ended				For the Nine Months Ended
	September 30, 2014		September 30, 2013		September 30, 2014		September 30, 2013
(Millions of Dollars)	NU		NU		NU		NU
Service Cost	$	19.1	$	25.6	$	60.7	$	76.7
Interest Cost		56.4		51.7		169.5		155.0
Expected Return on Plan Assets		(77.7)		(69.5)		(233.1)		(208.5)
Actuarial Loss		31.7		52.4		96.5		158.1
Prior Service Cost		1.1		1.1		3.3		3.0
Total Net Periodic Benefit Expense	$	30.6	$	61.3	$	96.9	$	184.3
Capitalized Pension Expense	$	8.3	$	18.3	$	26.7	$	54.9
	PBOP				PBOP
	For the Three Months Ended				For the Nine Months Ended
	September 30, 2014		September 30, 2013		September 30, 2014		September 30, 2013
(Millions of Dollars)	NU		NU		NU		NU
Service Cost	$	3.1	$	4.2	$	9.3	$	12.6
Interest Cost		12.4		11.8		37.1		35.4
Expected Return on Plan Assets		(15.8)		(13.9)		(47.4)		(41.6)
Actuarial Loss		3.0		6.5		9.1		19.5
Prior Service Credit		(0.7)		(0.5)		(2.1)		(1.5)
Total Net Periodic Benefit Expense	$	2.0	$	8.1	$	6.0	$	24.4
Capitalized PBOP Expense	$	1.1	$	2.6	$	1.9	$	7.6

	Pension and SERP
	For the Three Months Ended September 30, 2014								For the Three Months Ended September 30, 2013
			NSTAR								NSTAR
(Millions of Dollars)	CL&P		Electric		PSNH		WMECO		CL&P		Electric(1)		PSNH		WMECO
Service Cost	$	5.0	$	3.0	$	2.3	$	0.8	$	6.3	$	8.3		3.3	$	1.2
Interest Cost		12.5		10.3		5.7		2.5		12.1		14.5		5.8		2.5
Expected Return on Plan Assets		(18.7)		(15.7)		(9.3)		(4.4)		(18.4)		(21.1)		(9.2)		(4.3)
Actuarial Loss		8.2		5.9		2.8		1.7		13.9		14.4		5.4		2.9
Prior Service Cost		0.4		-		0.1		0.1		0.4		-		0.1		0.1
Total Net Periodic Benefit Expense	$	7.4	$	3.5	$	1.6	$	0.7	$	14.3	$	16.1	$	5.4	$	2.4
Intercompany Allocations	$	6.5	$	2.9	$	1.8	$	1.2	$	11.4	$	(2.1)	$	2.6	$	2.0
Capitalized Pension Expense	$	4.3	$	2.6	$	0.7	$	0.6	$	7.0	$	9.8	$	1.7	$	1.3
	Pension and SERP
	For the Nine Months Ended September 30, 2014								For the Nine Months Ended September 30, 2013
			NSTAR								NSTAR
(Millions of Dollars)	CL&P		Electric		PSNH		WMECO		CL&P		Electric(1)		PSNH		WMECO
Service Cost	$	15.2	$	10.6	$	7.4	$	2.7	$	18.7	$	24.8	$	9.8	$	3.5
Interest Cost		38.1		31.0		18.0		7.8		36.3		43.5		17.8		7.5
Expected Return on Plan Assets		(56.7)		(47.3)		(28.8)		(13.5)		(55.4)		(63.3)		(26.2)		(13.0)
Actuarial Loss		25.5		17.6		8.9		5.2		42.0		43.6		16.2		8.9
Prior Service Cost/(Credit)		1.4		-		0.5		0.3		1.4		(0.2)		0.4		0.3
Total Net Periodic Benefit Expense	$	23.5	$	11.9	$	6.0	$	2.5	$	43.0	$	48.4	$	18.0	$	7.2
Intercompany Allocations	$	20.8	$	6.7	$	6.0	$	3.9	$	33.6	$	(6.2)	$	7.8	$	6.0
Capitalized Pension Expense	$	13.6	$	5.5	$	2.4	$	2.0	$	21.0	$	21.6	$	5.6	$	3.9

	PBOP
	For the Three Months Ended September 30, 2014								For the Three Months Ended September 30, 2013
(Millions of Dollars)	CL&P			NSTAR Electric		PSNH		WMECO	CL&P		PSNH		WMECO
Service Cost	$	0.6	$	0.8	$	0.3	$	0.1	$	0.9	$	0.6	$	0.2
Interest Cost		2.0		4.9		1.1		0.4		2.0		1.0		0.4
Expected Return on Plan Assets		(2.6)		(6.5)		(1.4)		(0.6)		(2.5)		(1.3)		(0.6)
Actuarial Loss/(Gain)		1.0		(0.1)		0.6		0.1		1.8		0.9		0.3
Prior Service Credit		-		(0.5)		-		-		-		-		-
Total Net Periodic Benefit Expense/(Income)	$	1.0	$	(1.4)	$	0.6	$	0.0	$	2.2	$	1.2	$	0.3
Intercompany Allocations	$	0.9	$	0.3	$	0.2	$	0.2	$	1.7	$	0.4	$	0.3
Capitalized PBOP Expense/(Income)	$	0.5	$	(0.5)	$	0.2	$	-	$	1.3	$	0.4	$	0.3
	PBOP
	For the Nine Months Ended September 30, 2014								For the Nine Months Ended September 30, 2013
(Millions of Dollars)	CL&P			NSTAR Electric		PSNH		WMECO	CL&P		PSNH		WMECO
Service Cost	$	1.7	$	2.3	$	1.0	$	0.3	$	2.6	$	1.7	$	0.5
Interest Cost		6.0		14.6		3.2		1.3		5.9		3.1		1.3
Expected Return on Plan Assets		(7.9)		(19.5)		(4.1)		(1.7)		(7.6)		(3.9)		(1.7)
Actuarial Loss/(Gain)		3.2		(0.4)		1.7		0.3		5.6		2.7		0.8
Prior Service Credit		-		(1.4)		-		-		-		-		-
Total Net Periodic Benefit Expense/(Income)	$	3.0	$	(4.4)	$	1.8	$	0.2	$	6.5	$	3.6	$	0.9
Intercompany Allocations	$	3.1	$	0.4	$	0.8	$	0.6	$	5.3	$	1.2	$	1.0
Capitalized PBOP Expense/(Income)	$	1.5	$	(1.5)	$	0.6	$	0.1	$	3.7	$	1.1	$	0.7

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MARKETABLE SECURITIES (Tables)

9 Months Ended

Sep. 30, 2014

Notes To Consolidated Financial Statements [Abstract]

Schedule Of Available For Sale Securities Reconciliation [Table TextBlock]

		As of September 30, 2014
				Pre-Tax		Pre-Tax
		Amortized		Unrealized		Unrealized
(Millions of Dollars)		Cost		Gains		Losses		Fair Value
NU
	Debt Securities (1)	$	310.6	$	7.8	$	(0.2)	$	318.2
	Equity Securities (1)		160.9		71.1		-		232.0
WMECO
	Debt Securities (2)		58.1		0.1		(0.1)		58.1
		As of December 31, 2013
				Pre-Tax		Pre-Tax
		Amortized		Unrealized		Unrealized
(Millions of Dollars)		Cost		Gains		Losses		Fair Value
NU
	Debt Securities (1)	$	299.2	$	2.5	$	(2.1)	$	299.6
	Equity Securities (1)		163.6		60.5		-		224.1
WMECO
	Debt Securities (2)		57.9		-		-		57.9

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)	$	47.6	$	47.6	$	21.9	$	22.1
One to five years		91.0		91.4		30.7		30.5
Six to ten years		65.6		67.5		1.4		1.4
Greater than ten years		106.4		111.7		4.1		4.1
Total Debt Securities	$	310.6	$	318.2	$	58.1	$	58.1

Fair Value Heirarchy [Table Text Block]

		NU				WMECO
		As of				As of
(Millions of Dollars)		September 30, 2014		December 31, 2013		September 30, 2014		December 31, 2013
Level 1:
	Mutual Funds and Equities	$	314.6	$	281.3	$	-	$	-
	Money Market Funds		27.1		32.9		4.4		10.9
Total Level 1		$	341.7	$	314.2	$	4.4	$	10.9
Level 2:
	U.S. Government Issued Debt Securities (Agency and Treasury)	$	56.5	$	61.4	$	-	$	6.8
	Corporate Debt Securities		61.2		53.6		14.1		15.1
	Asset-Backed Debt Securities		37.9		30.4		14.3		9.0
	Municipal Bonds		112.5		105.5		13.9		11.2
	Other Fixed Income Securities		23.0		15.8		11.4		4.9
Total Level 2		$	291.1	$	266.7	$	53.7	$	47.0
Total Marketable Securities		$	632.8	$	580.9	$	58.1	$	57.9

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Guarantees and Indemnifications (Details) (USD $) In Millions, unless otherwise specified	Sep. 30, 2014
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 2014 And 2016 [Member]
Guarantee Obligations [Line Items]
Guarantee Obligations Maximum Exposure	64.3
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	15.3
Guarantee Of Debt Of Ne Hydros [Member]
Guarantee Obligations [Line Items]
Guarantee Obligations Maximum Exposure	$ 2.0

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Severance Benefits (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended	9 Months Ended
	Sep. 30, 2014	Sep. 30, 2014	Sep. 30, 2013	Dec. 31, 2013
Notes To Consolidated Financial Statements [Abstract]
Description Of Postemployment Benefits		Severance Benefits NU recorded severance benefit expenses of $0.7 million and $6.5 million associated with the partial outsourcing of information technology functions and ongoing post-merger integration for the three and nine months ended September 30, 2014, respectively, and $9.2 million for the three and nine months ended September 30, 2013. As of September 30, 2014 and December 31, 2013, the severance accrual totaled $6.4 million and $14.7 million, respectively, and was included in Other Current Liabilities on the balance sheets.
Postemployment Benefits Period Expense	$ 0.7	$ 6.5	$ 9.2
Postemployment Benefits Liability Current And Noncurrent	$ 6.4	$ 6.4		$ 14.7

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Environmental Matters (Tables)

9 Months Ended

Sep. 30, 2014

Notes To Consolidated Financial Statements [Abstract]

Schedule Of Environmental Loss Contingencies By Site Text Block

	As of September 30, 2014				As of December 31, 2013
			Reserve				Reserve
	Number of Sites		(in millions)		Number of Sites		(in millions)
NU		65	$	34.7		68	$	35.4
CL&P		16		4.0		18		3.4
NSTAR Electric		13		1.1		12		1.2
PSNH		13		5.3		15		5.4
WMECO		4		0.5		5		0.4

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Long-Term Contractual Arrangements (Tables)

9 Months Ended

Sep. 30, 2014

Notes To Consolidated Financial Statements [Abstract]

Long-term Purchase Commitment [Table Text Block]

	October - December
(Millions of Dollars)	2014		2015		2016		2017		2018		Thereafter		Total
CL&P	$	20.0	$	60.7	$	66.1	$	67.0	$	67.7	$	717.0	$	998.5
NSTAR Electric		21.8		86.3		100.0		96.1		59.6		377.6		741.4
WMECO		-		-		2.4		2.4		2.4		28.9		36.1

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PROPERTY, PLANT AND ACCUMULATED DEPRECIATION

9 Months Ended

Sep. 30, 2014

Notes To Consolidated Financial Statements [Abstract]

Property Plant And Equipment Disclosure [Text Block]

3.       PROPERTY, PLANT AND EQUIPMENT AND ACCUMULATED DEPRECIATION

The following tables summarize the investments in utility property, plant and equipment by asset category:

		As of September 30, 2014		As of December 31, 2013
(Millions of Dollars)		NU		NU
Distribution - Electric		$	12,306.6	$	11,950.2
Distribution - Natural Gas			2,494.5		2,425.9
Transmission			6,564.2		6,412.5
Generation			1,168.6		1,152.3
Electric and Natural Gas Utility			22,533.9		21,940.9
Other (1)			541.7		508.7
Property, Plant and Equipment, Gross			23,075.6		22,449.6
Less: Accumulated Depreciation
	Electric and Natural Gas Utility		(5,687.0)		(5,387.0)
	Other		(216.3)		(196.2)
Total Accumulated Depreciation			(5,903.3)		(5,583.2)
Property, Plant and Equipment, Net			17,172.3		16,866.4
Construction Work in Progress			1,082.3		709.8
Total Property, Plant and Equipment, Net		$	18,254.6	$	17,576.2

(1)These assets represent unregulated property and are primarily comprised of building improvements,computer software, hardware and equipment and telecommunications assets at NU's unregulated companies.

	As of September 30, 2014								As of December 31, 2013
			NSTAR								NSTAR
(Millions of Dollars)	CL&P		Electric		PSNH		WMECO		CL&P		Electric		PSNH		WMECO
Distribution	$	5,104.8	$	4,812.4	$	1,654.5	$	774.8	$	4,930.7	$	4,694.7	$	1,608.2	$	756.6
Transmission		3,125.2		1,824.6		715.8		851.8		3,071.9		1,772.3		695.7		826.4
Generation		-		-		1,134.7		33.9		-		-		1,131.2		21.1
Property, Plant and Equipment, Gross		8,230.0		6,637.0		3,505.0		1,660.5		8,002.6		6,467.0		3,435.1		1,604.1
Less: Accumulated Depreciation		(1,908.2)		(1,726.7)		(1,069.4)		(291.8)		(1,804.1)		(1,631.3)		(1,021.8)		(271.5)
Property, Plant and Equipment, Net		6,321.8		4,910.3		2,435.6		1,368.7		6,198.5		4,835.7		2,413.3		1,332.6
Construction Work in Progress		379.0		301.4		125.0		63.7		252.8		208.2		54.3		48.5
Total Property, Plant and Equipment, Net	$	6,700.8	$	5,211.7	$	2,560.6	$	1,432.4	$	6,451.3	$	5,043.9	$	2,467.6	$	1,381.1

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Guarantees and Indemnifications (Tables)

9 Months Ended

Sep. 30, 2014

Notes To Consolidated Financial Statements [Abstract]

Schedule Of Guarantee Obligations Text Block

		Maximum Exposure
Subsidiary	Description	(in millions)		Expiration Dates
Various	Surety Bonds	$	64.3	2014 - 2016 (1)
Various	New England Hydro Companies' Long-Term Debt	$	2.0	Unspecified
NUSCO and RRR	Lease Payments for Vehicles and Real Estate	$	15.3	2019 and 2024

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Basis of Presentation (Details)	9 Months Ended
	Sep. 30, 2014
Description of Consolidation of Yankee Companies	NU consolidates CYAPC and YAEC because CL&P's, NSTAR Electric's, PSNH's and WMECO's combined ownership interest in each of these entities is greater than 50 percent. Intercompany transactions between CL&P, NSTAR Electric, PSNH and WMECO and the CYAPC and YAEC companies have been eliminated in consolidation of the NU financial statements. For CL&P, NSTAR Electric, PSNH and WMECO, the investments in CYAPC and YAEC continue to be accounted for under the equity method.

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Environmental Matters (Details) (USD $) In Millions, unless otherwise specified	9 Months Ended	12 Months Ended
	Sep. 30, 2014	Dec. 31, 2013
Site Contingency [Line Items]
Environmental Site Quantity	65	68
Accrual for Environmental Loss Contingencies [Roll Forward]
Beginning Balance	$ 35.4
Ending Balance	34.7	35.4
MGP Site accrual [Member]
Accrual for Environmental Loss Contingencies [Roll Forward]
Ending Balance	29.8	31.4
The Connecticut Light And Power Company [Member]
Site Contingency [Line Items]
Environmental Site Quantity	16	18
Accrual for Environmental Loss Contingencies [Roll Forward]
Beginning Balance	3.4
Ending Balance	4.0	3.4
NSTAR Electric Company [Member]
Site Contingency [Line Items]
Environmental Site Quantity	13	12
Accrual for Environmental Loss Contingencies [Roll Forward]
Beginning Balance	1.2
Ending Balance	1.1	1.2
Public Service Company Of New Hampshire [Member]
Site Contingency [Line Items]
Environmental Site Quantity	13	15
Accrual for Environmental Loss Contingencies [Roll Forward]
Beginning Balance	5.4
Ending Balance	5.3	5.4
Western Massachusetts Electric Company [Member]
Site Contingency [Line Items]
Environmental Site Quantity	4	5
Accrual for Environmental Loss Contingencies [Roll Forward]
Beginning Balance	0.4
Ending Balance	$ 0.5	$ 0.4

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CONSOLIDATED BALANCE SHEETS (USD $) In Thousands, unless otherwise specified	Sep. 30, 2014	Dec. 31, 2013
Current Assets:
Cash	$ 41,706	$ 43,364
Receivables, Net	848,510	765,391
Unbilled Revenues	181,284	224,982
Fuel, Materials and Supplies	333,869	303,233
Regulatory Assets Current	445,962	535,791
Marketable Securities - Current	114,722	92,427
Prepayments and Other Current Assets	135,497	121,861
Total Current Assets	2,101,550	2,087,049
Property, Plant and Equipment, Net	18,254,610	17,576,186
Deferred Debits and Other Assets:
Regulatory Assets Long Term	3,241,122	3,758,694
Goodwill	3,519,401	3,519,401
Marketable Securities	518,032	488,515
Other Long-Term Assets	347,596	365,692
Total Deferred Debits and Other Assets	7,626,151	8,132,302
Total Assets	27,982,311	27,795,537
Current Liabilities:
Notes Payable	1,046,961	1,093,000
Long-Term Debt - Current Portion	245,583	533,346
Accounts Payable - Current	608,639	742,251
Regulatory Liability Current	398,985	204,278
Other Liabilities - Current	629,508	702,776
Total Current Liabilities	2,929,676	3,275,651
Deferred Credits and Other Liabilities:
Accumulated Deferred Income Taxes	4,257,996	4,029,026
Regulatory Liabilities Long-Term	509,889	502,984
Long-Term Derivative Liabilities	420,931	624,050
Accrued Pension, PBOP and SERP	787,550	896,844
Other Long-Term Liabilities	863,164	923,053
Total Deferred Credits and Other Liabilities	6,839,530	6,975,957
Capitalization:
Long-Term Debt	8,166,985	7,776,833
Noncontrolling Interest in Consolidated Subsidiary:
Temporary Equity, Carrying Amount, Attributable to Noncontrolling Interest	155,568	155,568
Common Shareholders' Equity:
Common Stock	1,666,767	1,665,351
Capital Surplus, Paid In	6,219,516	6,192,765
Retained Earnings	2,351,421	2,125,980
Accumulated Other Comprehensive Loss	(40,172)	(46,031)
Treasury Stock	(306,980)	(326,537)
Common Shareholders' Equity	9,890,552	9,611,528
Total Capitalization	18,213,105	17,543,929
Total Liabilities and Capitalization	27,982,311	27,795,537
The Connecticut Light And Power Company [Member]
Current Assets:
Cash	16,294	7,237
Receivables, Net	369,492	319,670
Accounts Receivable from Affiliated Companies	35,276	13,777
Unbilled Revenues	87,806	92,401
Regulatory Assets Current	116,531	150,943
Materials and Supplies	47,086	54,606
Accumulated Deferred Income Tax Asset	52,839
Prepaid Taxes	47,429	13,962
Prepayments and Other Current Assets	17,608	39,120
Total Current Assets	790,361	691,716
Property, Plant and Equipment, Net	6,700,798	6,451,259
Deferred Debits and Other Assets:
Regulatory Assets Long Term	1,369,025	1,663,147
Other Long-Term Assets	178,313	174,380
Total Deferred Debits and Other Assets	1,547,338	1,837,527
Total Assets	9,038,497	8,980,502
Current Liabilities:
Notes Payable To Affiliated Companies	105,400	287,300
Long-Term Debt - Current Portion	162,000	150,000
Accounts Payable - Current	228,379	201,047
Accounts Payable to Affiliated Companies	46,977	56,531
Obligations to Third Party Suppliers	67,630	73,914
Accrued Taxes	54,652	37,186
Regulatory Liability Current	195,663	93,961
Derivative Liabilities - Current	86,759	92,233
Other Liabilities - Current	107,284	97,530
Total Current Liabilities	1,054,744	1,089,702
Deferred Credits and Other Liabilities:
Accumulated Deferred Income Taxes	1,581,344	1,510,586
Regulatory Liabilities Long-Term	87,696	93,757
Long-Term Derivative Liabilities	418,137	617,072
Accrued Pension, PBOP and SERP	63,756	95,895
Other Long-Term Liabilities	143,838	163,588
Total Deferred Credits and Other Liabilities	2,294,771	2,480,898
Capitalization:
Long-Term Debt	2,679,775	2,591,208
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	1,804,228	1,682,047
Retained Earnings	1,029,473	961,482
Accumulated Other Comprehensive Loss	(1,046)	(1,387)
Common Shareholders' Equity	2,893,007	2,702,494
Total Capitalization	5,688,982	5,409,902
Total Liabilities and Capitalization	9,038,497	8,980,502
NSTAR Electric Company [Member]
Current Assets:
Cash	11,040	8,021
Receivables, Net	275,902	209,711
Accounts Receivable from Affiliated Companies	47,215	27,264
Unbilled Revenues	39,372	41,368
Fuel, Materials and Supplies	65,073	44,236
Regulatory Assets Current	128,205	204,144
Prepayments and Other Current Assets	11,267	36,710
Total Current Assets	578,074	571,454
Property, Plant and Equipment, Net	5,211,681	5,043,887
Deferred Debits and Other Assets:
Regulatory Assets Long Term	998,030	1,235,156
Other Long-Term Assets	62,644	60,624
Total Deferred Debits and Other Assets	1,060,674	1,295,780
Total Assets	6,850,429	6,911,121
Current Liabilities:
Notes Payable	159,500	103,500
Long-Term Debt - Current Portion	4,700	301,650
Accounts Payable - Current	128,056	202,100
Accounts Payable to Affiliated Companies	62,625	75,707
Obligations to Third Party Suppliers	37,298
Power Contract Obligation	35,783	30,842
Renewable Portfolio Standards Compliance Obligation	34,905	39,686
Accrued Taxes	42,338	7,946
Deferred Tax Liabilities Current	9,622	50,128
Regulatory Liability Current	97,215	53,958
Other Liabilities - Current	62,436	39,936
Total Current Liabilities	674,478	910,912
Deferred Credits and Other Liabilities:
Accumulated Deferred Income Taxes	1,425,306	1,466,835
Regulatory Liabilities Long-Term	266,524	253,108
Accrued Pension, PBOP and SERP	142,249	118,010
Other Long-Term Liabilities	112,853	142,214
Due To Related Parties Noncurrent	0	64,172
Total Deferred Credits and Other Liabilities	1,946,932	2,044,339
Capitalization:
Long-Term Debt	1,792,707	1,499,417
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	993,163	992,625
Retained Earnings	1,400,149	1,420,828
Common Shareholders' Equity	2,393,312	2,413,453
Total Capitalization	4,229,019	3,955,870
Total Liabilities and Capitalization	6,850,429	6,911,121
Public Service Company Of New Hampshire [Member]
Current Assets:
Cash	2,750	130
Receivables, Net	77,602	76,331
Accounts Receivable from Affiliated Companies	6,271	90
Unbilled Revenues	33,088	38,344
Fuel, Materials and Supplies	141,381	128,736
Regulatory Assets Current	102,473	92,194
Prepayments and Other Current Assets	22,270	24,100
Total Current Assets	385,835	359,925
Property, Plant and Equipment, Net	2,560,635	2,467,556
Deferred Debits and Other Assets:
Regulatory Assets Long Term	178,204	219,346
Other Long-Term Assets	54,748	39,891
Total Deferred Debits and Other Assets	232,952	259,237
Total Assets	3,179,422	3,086,718
Current Liabilities:
Notes Payable To Affiliated Companies	153,300	86,500
Long-Term Debt - Current Portion	0	50,000
Accounts Payable - Current	58,801	82,920
Accounts Payable to Affiliated Companies	22,932	22,040
Deferred Tax Liabilities Current	29,936	28,596
Regulatory Liability Current	29,165	20,643
Other Liabilities - Current	38,725	51,729
Total Current Liabilities	332,859	342,428
Deferred Credits and Other Liabilities:
Accumulated Deferred Income Taxes	566,298	500,166
Regulatory Liabilities Long-Term	50,614	51,723
Other Postretirement Benefit Plan Liability	14,320	15,272
Other Long-Term Liabilities	46,874	46,247
Total Deferred Credits and Other Liabilities	678,106	613,408
Capitalization:
Long-Term Debt	999,230	999,006
Common Shareholders' Equity:
Common Stock	0	0
Capital Surplus, Paid In	702,923	701,911
Retained Earnings	473,969	438,515
Accumulated Other Comprehensive Loss	(7,665)	(8,550)
Common Shareholders' Equity	1,169,227	1,131,876
Total Capitalization	2,168,457	2,130,882
Total Liabilities and Capitalization	3,179,422	3,086,718
Western Massachusetts Electric Company [Member]
Current Assets:
Cash	1,737	0
Receivables, Net	50,835	49,018
Accounts Receivable from Affiliated Companies	14,522	47,607
Unbilled Revenues	12,664	16,562
Taxes Receivable	11,504	432
Regulatory Assets Current	38,907	43,024
Marketable Securities - Current	22,107	26,628
Prepayments and Other Current Assets	6,688	10,479
Total Current Assets	158,964	193,750
Property, Plant and Equipment, Net	1,432,368	1,381,060
Deferred Debits and Other Assets:
Regulatory Assets Long Term	109,690	146,088
Marketable Securities	35,963	31,243
Other Long-Term Assets	50,902	40,679
Total Deferred Debits and Other Assets	196,555	218,010
Total Assets	1,787,887	1,792,820
Current Liabilities:
Notes Payable To Affiliated Companies	13,200	0
Long-Term Debt - Current Portion	50,000
Accounts Payable - Current	36,558	62,961
Accounts Payable to Affiliated Companies	13,312	9,230
Accrued Interest	2,839	7,525
Deferred Tax Liabilities Current	1,920	13,098
Regulatory Liability Current	43,462	19,858
Counterparty Deposit	626	7,688
Other Liabilities - Current	11,758	20,629
Total Current Liabilities	173,675	140,989
Deferred Credits and Other Liabilities:
Accumulated Deferred Income Taxes	413,701	396,933
Regulatory Liabilities Long-Term	10,289	13,873
Other Postretirement Benefit Plan Liability	2,623	3,911
Other Long-Term Liabilities	38,372	28,619
Total Deferred Credits and Other Liabilities	464,985	443,336
Capitalization:
Long-Term Debt	578,686	629,389
Common Shareholders' Equity:
Common Stock	10,866	10,866
Capital Surplus, Paid In	391,136	390,743
Retained Earnings	171,800	181,014
Accumulated Other Comprehensive Loss	(3,261)	(3,517)
Common Shareholders' Equity	570,541	579,106
Total Capitalization	1,149,227	1,208,495
Total Liabilities and Capitalization	$ 1,787,887	$ 1,792,820

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REGULATORY ACCOUNTING (Details) (USD $)	9 Months Ended
	Sep. 30, 2014	Dec. 31, 2013
Regulatory Asset [Line Items]
Regulatory Assets, Total	$ 3,687,100,000	$ 4,294,500,000
Regulatory Assets Current	445,962,000	535,791,000
Regulatory Assets Long Term	3,241,122,000	3,758,694,000
Regulatory Assets And Liabilities Other Disclosures Abstract
Amount of Regulatory Costs Not yet Approved	64,700,000	65,100,000
Description Of Regulatory Costs Recently Approved	Storm Restoration Costs: On March 12, 2014, the PURA approved recovery of $365 million of deferred storm restoration costs (with carrying charges) associated with five major storms that occurred in 2011 and 2012. CL&P will recover these costs in its distribution rates over a six-year period beginning December 1, 2014. Effective June 1, 2014, CL&P received $65.4 million of DOE Phase II Damages proceeds. On June 17, 2014, the PURA ordered CL&P to refund these proceeds to customers by offsetting the deferred storm restoration costs regulatory asset. For further information on the DOE Phase II Damages proceeds received from the Yankee Companies, see Note 9C, "Commitments and Contingencies - Contractual Obligations - Yankee Companies," to the financial statements.
Description of Regulatory Assets and Liabilities	As a result of two FERC orders issued on June 19, 2014 in the pending base ROE complaint proceedings described in Note 9E, "Commitments and Contingencies – FERC Base ROE Complaints," in the second quarter of 2014 the Company had recorded a series of reserves at its electric subsidiaries to recognize the potential financial impact of these rulings. As of September 30, 2014, the cumulative pre-tax reserves (excluding interest) totaled $76.1 million at NU, $42.9 million at CL&P, $15.6 million at NSTAR Electric, $5.9 million at PSNH and $11.7 million at WMECO. As of December 31, 2013, as a result of the FERC ALJ initial decision in the third quarter of 2013, the Company had an aggregate pre-tax reserve (excluding interest) of $23.7 million at NU, $12.8 million at CL&P, $5.7 million at NSTAR Electric, $2.3 million at PSNH and $2.9 million at WMECO. These reserves were recorded in each electric subsidiary's respective transmission regulatory tracker mechanism and as a reduction of Operating Revenues. Effective June 1, 2014, as a result of damages awarded to the Yankee Companies for spent nuclear fuel lawsuits against the DOE described in Note 9C, "Commitments and Contingencies - Contractual Obligations - Yankee Companies," the Yankee Companies returned the DOE Phase II Damages proceeds to the member companies, including CL&P, NSTAR Electric, PSNH, and WMECO, for the benefit of their respective customers. CL&P's refund obligation to customers of $65.4 million was recorded as an offset to the deferred storm restoration costs regulatory asset, as directed by PURA. NSTAR Electric's, PSNH's and WMECO's refund obligation to customers of $29.1 million, $13.1 million and $18.1 million, respectively, was recorded as a regulatory liability in each electric subsidiary's respective regulatory tracker mechanisms. Refunds to customers for these DOE proceeds began in the third quarter of 2014.
Regulatory Liabilities [Line Items]
Regulatory Liabilities, Total	908,900,000	707,300,000
Regulatory Liability Current	398,985,000	204,278,000
Regulatory Liabilities Long-Term	509,889,000	502,984,000
Cost Of Removal [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities, Total	439,100,000	435,100,000
Regulatory Tracker Deferrals Regulatory Liabilities [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities, Total	339,900,000	151,200,000
AFUDC Transmission Incentive [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities, Total	67,200,000	68,100,000
Other Regulatory Liabilities [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities, Total	62,700,000	52,900,000
The Connecticut Light And Power Company [Member]
Regulatory Asset [Line Items]
Regulatory Assets, Total	1,485,500,000	1,814,000,000
Regulatory Assets Current	116,531,000	150,943,000
Regulatory Assets Long Term	1,369,025,000	1,663,147,000
Regulatory Assets And Liabilities Other Disclosures Abstract
Amount of Regulatory Costs Not yet Approved	3,200,000	7,300,000
Regulatory Liabilities [Line Items]
Regulatory Liabilities, Total	283,400,000	187,800,000
Regulatory Liability Current	195,663,000	93,961,000
Regulatory Liabilities Long-Term	87,696,000	93,757,000
The Connecticut Light And Power Company [Member] | Cost Of Removal [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities, Total	22,500,000	29,100,000
The Connecticut Light And Power Company [Member] | Regulatory Tracker Deferrals Regulatory Liabilities [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities, Total	196,400,000	95,600,000
The Connecticut Light And Power Company [Member] | AFUDC Transmission Incentive [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities, Total	53,900,000	54,700,000
The Connecticut Light And Power Company [Member] | Other Regulatory Liabilities [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities, Total	10,600,000	8,400,000
NSTAR Electric Company [Member]
Regulatory Asset [Line Items]
Regulatory Assets, Total	1,126,200,000	1,439,300,000
Regulatory Assets Current	128,205,000	204,144,000
Regulatory Assets Long Term	998,030,000	1,235,156,000
Regulatory Assets And Liabilities Other Disclosures Abstract
Amount of Regulatory Costs Not yet Approved	36,000,000	33,400,000
Regulatory Liabilities [Line Items]
Regulatory Liabilities, Total	363,700,000	307,100,000
Regulatory Liability Current	97,215,000	53,958,000
Regulatory Liabilities Long-Term	266,524,000	253,108,000
NSTAR Electric Company [Member] | Cost Of Removal [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities, Total	260,700,000	250,000,000
NSTAR Electric Company [Member] | Regulatory Tracker Deferrals Regulatory Liabilities [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities, Total	67,300,000	21,900,000
NSTAR Electric Company [Member] | AFUDC Transmission Incentive [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities, Total	4,100,000	4,100,000
NSTAR Electric Company [Member] | Other Regulatory Liabilities [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities, Total	31,600,000	31,100,000
Public Service Company Of New Hampshire [Member]
Regulatory Asset [Line Items]
Regulatory Assets, Total	280,700,000	311,500,000
Regulatory Assets Current	102,473,000	92,194,000
Regulatory Assets Long Term	178,204,000	219,346,000
Regulatory Assets And Liabilities Other Disclosures Abstract
Amount of Regulatory Costs Not yet Approved	0	0
Regulatory Liabilities [Line Items]
Regulatory Liabilities, Total	79,800,000	72,300,000
Regulatory Liability Current	29,165,000	20,643,000
Regulatory Liabilities Long-Term	50,614,000	51,723,000
Public Service Company Of New Hampshire [Member] | Cost Of Removal [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities, Total	49,200,000	49,700,000
Public Service Company Of New Hampshire [Member] | Regulatory Tracker Deferrals Regulatory Liabilities [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities, Total	25,900,000	21,600,000
Public Service Company Of New Hampshire [Member] | Other Regulatory Liabilities [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities, Total	4,700,000	1,000,000
Western Massachusetts Electric Company [Member]
Regulatory Asset [Line Items]
Regulatory Assets, Total	148,600,000	189,100,000
Regulatory Assets Current	38,907,000	43,024,000
Regulatory Assets Long Term	109,690,000	146,088,000
Regulatory Assets And Liabilities Other Disclosures Abstract
Amount of Regulatory Costs Not yet Approved	11,200,000	10,100,000
Regulatory Liabilities [Line Items]
Regulatory Liabilities, Total	53,800,000	33,800,000
Regulatory Liability Current	43,462,000	19,858,000
Regulatory Liabilities Long-Term	10,289,000	13,873,000
Western Massachusetts Electric Company [Member] | Cost Of Removal [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities, Total	0	0
Western Massachusetts Electric Company [Member] | Regulatory Tracker Deferrals Regulatory Liabilities [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities, Total	43,900,000	21,100,000
Western Massachusetts Electric Company [Member] | AFUDC Transmission Incentive [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities, Total	9,200,000	9,300,000
Western Massachusetts Electric Company [Member] | Other Regulatory Liabilities [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities, Total	700,000	3,400,000
Benefit Costs [Member]
Regulatory Asset [Line Items]
Regulatory Assets, Total	1,113,200,000	1,240,200,000
Benefit Costs [Member] | The Connecticut Light And Power Company [Member]
Regulatory Asset [Line Items]
Regulatory Assets, Total	242,200,000	297,700,000
Benefit Costs [Member] | NSTAR Electric Company [Member]
Regulatory Asset [Line Items]
Regulatory Assets, Total	318,100,000	496,700,000
Benefit Costs [Member] | Public Service Company Of New Hampshire [Member]
Regulatory Asset [Line Items]
Regulatory Assets, Total	78,100,000	100,600,000
Benefit Costs [Member] | Western Massachusetts Electric Company [Member]
Regulatory Asset [Line Items]
Regulatory Assets, Total	44,300,000	57,300,000
Regulatory Assets Offsetting Derivative Liabilities [Member]
Regulatory Asset [Line Items]
Regulatory Assets, Total	427,500,000	638,000,000
Regulatory Assets Offsetting Derivative Liabilities [Member] | The Connecticut Light And Power Company [Member]
Regulatory Asset [Line Items]
Regulatory Assets, Total	421,100,000	630,400,000
Regulatory Assets Offsetting Derivative Liabilities [Member] | NSTAR Electric Company [Member]
Regulatory Asset [Line Items]
Regulatory Assets, Total	4,300,000	7,700,000
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	0	0
Deferred Income Tax Charges Member
Regulatory Asset [Line Items]
Regulatory Assets, Total	623,200,000	626,200,000
Deferred Income Tax Charges Member | The Connecticut Light And Power Company [Member]
Regulatory Asset [Line Items]
Regulatory Assets, Total	427,400,000	415,500,000
Deferred Income Tax Charges Member | NSTAR Electric Company [Member]
Regulatory Asset [Line Items]
Regulatory Assets, Total	83,300,000	84,000,000
Deferred Income Tax Charges Member | Public Service Company Of New Hampshire [Member]
Regulatory Asset [Line Items]
Regulatory Assets, Total	38,300,000	40,300,000
Deferred Income Tax Charges Member | Western Massachusetts Electric Company [Member]
Regulatory Asset [Line Items]
Regulatory Assets, Total	35,300,000	43,700,000
Storm Restoration Costs [Member]
Regulatory Asset [Line Items]
Regulatory Assets, Total	493,500,000	589,600,000
Storm Restoration Costs [Member] | The Connecticut Light And Power Company [Member]
Regulatory Asset [Line Items]
Regulatory Assets, Total	326,000,000	397,800,000
Storm Restoration Costs [Member] | NSTAR Electric Company [Member]
Regulatory Asset [Line Items]
Regulatory Assets, Total	106,200,000	109,300,000
Storm Restoration Costs [Member] | Public Service Company Of New Hampshire [Member]
Regulatory Asset [Line Items]
Regulatory Assets, Total	29,300,000	43,700,000
Storm Restoration Costs [Member] | Western Massachusetts Electric Company [Member]
Regulatory Asset [Line Items]
Regulatory Assets, Total	32,000,000	38,800,000
Goodwill Regulatory Asset [Member]
Regulatory Asset [Line Items]
Regulatory Assets, Total	510,500,000	525,900,000
Goodwill Regulatory Asset [Member] | NSTAR Electric Company [Member]
Regulatory Asset [Line Items]
Regulatory Assets, Total	438,300,000	451,500,000
Regulatory Tracker Deferrals Regulatory Assets [Member]
Regulatory Asset [Line Items]
Regulatory Assets, Total	235,700,000	323,400,000
Regulatory Tracker Deferrals Regulatory Assets [Member] | The Connecticut Light And Power Company [Member]
Regulatory Asset [Line Items]
Regulatory Assets, Total	5,200,000	8,000,000
Regulatory Tracker Deferrals Regulatory Assets [Member] | NSTAR Electric Company [Member]
Regulatory Asset [Line Items]
Regulatory Assets, Total	76,400,000	169,500,000
Regulatory Tracker Deferrals Regulatory Assets [Member] | Public Service Company Of New Hampshire [Member]
Regulatory Asset [Line Items]
Regulatory Assets, Total	94,700,000	83,300,000
Regulatory Tracker Deferrals Regulatory Assets [Member] | Western Massachusetts Electric Company [Member]
Regulatory Asset [Line Items]
Regulatory Assets, Total	23,500,000	32,600,000
Unrecovered Contractual Obligations [Member]
Regulatory Asset [Line Items]
Regulatory Assets, Total	124,600,000	154,200,000
Power Contracts Buy Out Agreements [Member]
Regulatory Asset [Line Items]
Regulatory Assets, Total	49,800,000	70,200,000
Power Contracts Buy Out Agreements [Member] | NSTAR Electric Company [Member]
Regulatory Asset [Line Items]
Regulatory Assets, Total	45,400,000	64,700,000
Power Contracts Buy Out Agreements [Member] | Public Service Company Of New Hampshire [Member]
Regulatory Asset [Line Items]
Regulatory Assets, Total	4,400,000	5,500,000
Other Regulatory Assets [Member]
Regulatory Asset [Line Items]
Regulatory Assets, Total	109,100,000	126,800,000
Other Regulatory Assets [Member] | The Connecticut Light And Power Company [Member]
Regulatory Asset [Line Items]
Regulatory Assets, Total	63,600,000	64,600,000
Other Regulatory Assets [Member] | NSTAR Electric Company [Member]
Regulatory Asset [Line Items]
Regulatory Assets, Total	54,200,000	55,900,000
Other Regulatory Assets [Member] | Public Service Company Of New Hampshire [Member]
Regulatory Asset [Line Items]
Regulatory Assets, Total	35,900,000	38,100,000
Other Regulatory Assets [Member] | Western Massachusetts Electric Company [Member]
Regulatory Asset [Line Items]
Regulatory Assets, Total	$ 13,500,000	$ 16,700,000

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

9 Months Ended

Sep. 30, 2014

Notes To Consolidated Financial Statements [Abstract]

Significant Accounting Policies [Text Block]

NORTHEAST UTILITIES AND SUBSIDIARIES

THE CONNECTICUT LIGHT AND POWER COMPANY

NSTAR ELECTRIC COMPANY AND SUBSIDIARY

PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARY

WESTERN MASSACHUSETTS ELECTRIC COMPANY

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)

Refer to the Glossary of Terms included in this combined Quarterly Report on Form 10-Q for abbreviations and acronyms used throughout the combined notes to the unaudited condensed consolidatedfinancial statements.

1.       SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

A.       Basis of Presentation

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 consist of CL&P, NSTAR Electric, PSNH, WMECO, Yankee Gas and NSTAR Gas. NU provides energy delivery service to approximately 3.6 million electric and natural gas customers through these six regulated utilities in Connecticut, Massachusetts and New Hampshire.

The unaudited condensed consolidated financial statements of NU, NSTAR Electric and PSNH include the accounts of each of their respective subsidiaries. Intercompany transactions have been eliminated in consolidation. The accompanying unaudited condensed consolidated financial statements of NU, NSTAR Electric and PSNH and the unaudited condensed financial statements of CL&P and WMECO are herein collectively referred to as the"financial statements."

The combined notes to the financial statements have been prepared pursuant to the rules and regulations of the SEC. Certain information and footnote disclosures included in annual financial statements prepared in accordance with GAAP have been omitted pursuant to such rules and regulations. The accompanying financial statements should be read in conjunction with the entirety of this combined Quarterly Report on Form 10-Q, the first and second quarter 2014 combined Quarterly Reports on Form 10-Q and the 2013 combined Annual Report on Form 10-K of NU, CL&P, NSTAR Electric, PSNH and WMECO, which were filed with the SEC. The preparation of the 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 financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

The financial statements contain, in the opinion of management, all adjustments (including normal, recurring adjustments) necessary to present fairly NU's, CL&P's, NSTAR Electric's, PSNH's and WMECO's financial position as of September 30, 2014 and December 31, 2013, the results of operations and comprehensive income for the three and nine months ended September 30, 2014 and 2013, and the cash flows for the nine months ended September 30, 2014 and 2013. The results of operations and comprehensive income for the three and nine months ended September 30, 2014 and 2013, and the cash flows for the nine months ended September 30, 2014 and 2013 are not necessarily indicative of the results expected for a full year.

NU consolidates CYAPC and YAEC because CL&P's, NSTAR Electric's, PSNH's and WMECO's combined ownership interest in each of these entities is greater than 50 percent. Intercompany transactions between CL&P, NSTAR Electric, PSNH and WMECO and the CYAPC and YAEC companies have been eliminated in consolidation of the NU financial statements. For CL&P, NSTAR Electric, PSNH and WMECO, the investments in CYAPC and YAEC continue to be accounted for under the equity method.

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 2, "Regulatory Accounting," for further information.

Certain reclassifications of prior period data were made in the accompanying balance sheets for NU, CL&P, NSTAR Electric and PSNH, and in the statements of income for NU, NSTAR Electric, PSNH and WMECO. These reclassifications were made to conform to the current period presentation.

B.       Accounting Standards

Recently Adopted Accounting Standards: On January 1, 2014, as required, NU prospectively adopted the Financial Accounting Standards Board's (FASB) final Accounting Standards Updates (ASU) that required presentation of certain unrecognized tax benefits as reductions to deferred tax assets. Implementation of this guidance had an immaterial impact on the balance sheets and no impact on the results of operations or cash flows of NU, CL&P, NSTAR Electric, PSNH and WMECO.

Accounting Standards Issued but not Yet Adopted: In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers, effective January 1, 2017, which amends existing revenue recognition guidance and is required to be applied retrospectively (either to each reporting period presented or cumulatively at the date of initial application). Management is reviewing the requirements of the new ASU, however the ASU's impact is not expected to have a material impact on the financial statements of NU, CL&P, NSTAR Electric, PSNH and WMECO.

C.Provision for Uncollectible Accounts

NU, including CL&P, NSTAR Electric, PSNH and WMECO, presents its receivables at estimated net realizable value by maintaining a provision for uncollectible accounts. This provision is determined based upon a variety of factors, including the application of an estimated uncollectible percentage to each receivable aging category. The estimate is based upon historical collection and write-off experience and management's assessment of collectibility from individual customers. Management continuously assesses the collectibility of receivables, and adjustscollectibility estimates based on actual experience. 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 provision for uncollectible accounts, which is included in Receivables, Net on the balance sheets, was as follows:

(Millions of Dollars)	As of September 30, 2014		As of December 31, 2013
NU	$	181.4	$	171.3
CL&P		85.8		82.0
NSTAR Electric		42.3		41.7
PSNH		7.9		7.4
WMECO		11.1		10.0

D.       Fair Value Measurements

Fair value measurement guidance is applied to derivative contracts that are not elected or designated as "normal purchases or normal sales" (normal) and to the marketable securities held in trusts. Fair value measurement guidance is also applied to investment valuations used to calculate the funded status of pension and PBOP plans and nonrecurring fair value measurements of nonfinancial assets such as goodwill and AROs, and is also used to estimate the fair value of preferred stock and long-term debt.

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 4, "Derivative Instruments," Note 5, "Marketable Securities," and Note 10, "Fair Value of Financial Instruments," to thefinancial statements.

E.       Other Income, Net

Items included within Other Income, Net on the statements of income primarily consist of investment income/(loss), interest income, AFUDC related to equity funds, and equity in earnings. Investment income/(loss) primarily relates to debt and equity securities held in trust. For further information, see Note 5, "Marketable Securities," to the financial statements.

F.       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 statements of income as follows:

	For the Three Months Ended				For the Nine Months Ended
(Millions of Dollars)	September 30, 2014		September 30, 2013		September 30, 2014		September 30, 2013
NU	$	35.0	$	37.5	$	114.6	$	108.9
CL&P		32.5		35.5		99.0		97.3

Certain sales taxes are also collected by NU's companies that serve customers in Connecticut and Massachusetts as agents for state and local governments and are recorded on a net basis with no impact on the statements of income.

G.	Supplemental Cash Flow Information
Non-cash investing activities include plant additions included in Accounts Payable as follows:
(Millions of Dollars)		As of September 30, 2014		As of September 30, 2013
NU		$	128.9	$	122.9
CL&P			52.2		36.6
NSTAR Electric			18.1		31.9
PSNH			21.0		16.9
WMECO			10.0		13.8

In the first nine months of 2014, as a result of damages awarded to the Yankee Companies for spent nuclear fuel lawsuits against the DOE described in Note 9C, "Commitments and Contingencies - Contractual Obligations - Yankee Companies," NU received total proceeds of $132.1 million, which were net of $80.6 million in proceeds CYAPC and YAEC returned to non-affiliated member companies.

H.Severance Benefits

NU recorded severance benefit expenses of $0.7million and $6.5million associated with the partial outsourcing of information technology functions and ongoing post-merger integration for the three and nine months ended September 30, 2014, respectively, and $9.2 million for the three and nine months ended September 30, 2013. As of September 30, 2014 and December 31, 2013, the severance accrual totaled $6.4million and $14.7 million, respectively, and was included in Other Current Liabilities on the balance sheets.

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ACCUMULATED OTHER COMPREHENSIVE INCOME (Details) (USD $)	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Accumulated Other Comprehensive Income Loss Net Of Tax RollForward [Abstract]
AOCI Beginning Balance			$ (46,031,000)	$ (72,900,000)
Other Comprehensive Income Before Reclassifications, Net of Tax			1,400,000	(800,000)
Reclassification From OCI, Net Of Tax			4,400,000	6,300,000
Other Comprehensive Income (Loss), Net of Tax, Total	1,335,000	2,082,000	5,859,000	5,467,000
AOCI Ending Balance	(40,172,000)	(67,400,000)	(40,172,000)	(67,400,000)
Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Abstract]
Total Interest Expense	(89,738,000)	(87,476,000)	(272,208,000)	(250,583,000)
Income Tax Expense	(126,539,000)	(109,351,000)	(345,858,000)	(325,442,000)
Net Income Attributable to Controlling Interests	234,614,000	209,501,000	597,937,000	608,610,000
The Connecticut Light And Power Company [Member]
Accumulated Other Comprehensive Income Loss Net Of Tax RollForward [Abstract]
AOCI Beginning Balance			(1,387,000)
Other Comprehensive Income (Loss), Net of Tax, Total	104,000	110,000	341,000	306,000
AOCI Ending Balance	(1,046,000)		(1,046,000)
Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Abstract]
Total Interest Expense	(38,735,000)	(35,284,000)	(110,448,000)	(98,964,000)
Income Tax Expense	(30,038,000)	(36,136,000)	(95,980,000)	(113,149,000)
Public Service Company Of New Hampshire [Member]
Accumulated Other Comprehensive Income Loss Net Of Tax RollForward [Abstract]
AOCI Beginning Balance			(8,550,000)
Other Comprehensive Income (Loss), Net of Tax, Total	277,000	288,000	885,000	822,000
AOCI Ending Balance	(7,665,000)		(7,665,000)
Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Abstract]
Total Interest Expense	(11,024,000)	(10,866,000)	(33,995,000)	(34,181,000)
Income Tax Expense	(17,603,000)	(18,196,000)	(52,199,000)	(52,797,000)
Western Massachusetts Electric Company [Member]
Accumulated Other Comprehensive Income Loss Net Of Tax RollForward [Abstract]
AOCI Beginning Balance			(3,517,000)
Other Comprehensive Income (Loss), Net of Tax, Total	83,000	85,000	256,000	246,000
AOCI Ending Balance	(3,261,000)		(3,261,000)
Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Abstract]
Total Interest Expense	(6,576,000)	(6,231,000)	(18,929,000)	(18,800,000)
Income Tax Expense	(10,490,000)	(8,588,000)	(26,596,000)	(30,424,000)
Qualified Cash Flow Hedging Instruments [Member]
Accumulated Other Comprehensive Income Loss Net Of Tax RollForward [Abstract]
AOCI Beginning Balance			(14,400,000)	(16,400,000)
Reclassification From OCI, Net Of Tax			1,500,000	1,500,000
Other Comprehensive Income (Loss), Net of Tax, Total			1,500,000	1,500,000
AOCI Ending Balance	(12,900,000)	(14,900,000)	(12,900,000)	(14,900,000)
Unrealized Gains Losses on Available for Sale Securities [Member]
Accumulated Other Comprehensive Income Loss Net Of Tax RollForward [Abstract]
AOCI Beginning Balance			400,000	1,300,000
Other Comprehensive Income Before Reclassifications, Net of Tax			200,000	(800,000)
Other Comprehensive Income (Loss), Net of Tax, Total			200,000	(800,000)
AOCI Ending Balance	600,000	500,000	600,000	500,000
Pension, SERP and PBOP Benefit Plans [Member]
Accumulated Other Comprehensive Income Loss Net Of Tax RollForward [Abstract]
AOCI Beginning Balance			(32,000,000)	(57,800,000)
Other Comprehensive Income Before Reclassifications, Net of Tax			1,200,000
Reclassification From OCI, Net Of Tax			2,900,000	4,800,000
Other Comprehensive Income (Loss), Net of Tax, Total			4,100,000	4,800,000
AOCI Ending Balance	(27,900,000)	(53,000,000)	(27,900,000)	(53,000,000)
Reclassification out of Accumulated Other Comprehensive Income [Member]
Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Abstract]
Net Income Attributable to Controlling Interests	(1,500,000)	(2,100,000)	(4,400,000)	(6,300,000)
Reclassification out of Accumulated Other Comprehensive Income [Member] | Qualified Cash Flow Hedging Instruments [Member]
Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Abstract]
Total Interest Expense	(800,000)	(800,000)	(2,500,000)	(2,500,000)
Income Tax Expense	300,000	300,000	1,000,000	1,000,000
Net Income Attributable to Controlling Interests	(500,000)	(500,000)	(1,500,000)	(1,500,000)
Reclassification out of Accumulated Other Comprehensive Income [Member] | Pension, SERP and PBOP Benefit Plans [Member]
Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Abstract]
OCI Reclassification Adjustment for Net Actuarial Gain (Loss), before Tax	(1,600,000)	(2,500,000)	(4,700,000)	(7,300,000)
OCI Reclassification Adjustment for Amortization of Prior Service Cost, before tax	0	0	(100,000)	(100,000)
OCI Reclassification Adjustment for Pension, SERP and PBOP Plans, before Tax	(1,600,000)	(2,500,000)	(4,800,000)	(7,400,000)
Income Tax Expense	600,000	900,000	1,900,000	2,600,000
Net Income Attributable to Controlling Interests	$ (1,000,000)	$ (1,600,000)	$ (2,900,000)	$ (4,800,000)

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ACCUMULATED OTHER COMPREHENSIVE INCOME (Tables)

9 Months Ended

Sep. 30, 2014

Notes To Consolidated Financial Statements [Abstract]

Schedule Of Accumulated Other Comprehensive Income Loss Table Text Block

	For the Nine Months Ended September 30, 2014								For the Nine Months Ended September 30, 2013
			Unrealized		Pension,						Unrealized		Pension,
	Qualified		Gains/(Losses)		SERP and				Qualified		Gains/(Losses)		SERP and
	Cash Flow		on Available-		PBOP				Cash Flow		on Available-		PBOP
	Hedging		for-Sale		Benefit				Hedging		for-Sale		Benefit
(Millions of Dollars)	Instruments		Securities		Plans		Total		Instruments		Securities		Plans		Total
AOCI as of Beginning of Period	$	(14.4)	$	0.4	$	(32.0)	$	(46.0)	$	(16.4)	$	1.3	$	(57.8)	$	(72.9)
OCI Before Reclassifications		-		0.2		1.2		1.4		-		(0.8)		-		(0.8)
Amounts Reclassified from AOCI		1.5		-		2.9		4.4		1.5		-		4.8		6.3
Net OCI		1.5		0.2		4.1		5.8		1.5		(0.8)		4.8		5.5
AOCI as of End of Period	$	(12.9)	$	0.6	$	(27.9)	$	(40.2)	$	(14.9)	$	0.5	$	(53.0)	$	(67.4)

	For the Three Months Ended				For the Nine Months Ended
	September 30,				September 30,
	Amounts Reclassified				Amounts Reclassified				Statements of Income
	from AOCI				from AOCI				Line Item Impacted
(Millions of Dollars)	2014		2013		2014		2013
Qualified Cash Flow Hedging Instruments	$	(0.8)	$	(0.8)	$	(2.5)	$	(2.5)	Interest Expense
Tax Benefit		0.3		0.3		1.0		1.0	Income Tax Expense
Qualified Cash Flow Hedging Instruments, Net of Tax	$	(0.5)	$	(0.5)	$	(1.5)	$	(1.5)
Pension, SERP and PBOP Benefit Plan Costs:
Amortization of Actuarial Losses	$	(1.6)	$	(2.5)	$	(4.7)	$	(7.3)	Operations and Maintenance (1)
Amortization of Prior Service Cost		-		-		(0.1)		(0.1)	Operations and Maintenance (1)
Total Pension, SERP and PBOP Benefit Plan Costs		(1.6)		(2.5)		(4.8)		(7.4)
Tax Benefit		0.6		0.9		1.9		2.6	Income Tax Expense
Pension, SERP and PBOP Benefit Plan Costs, Net of Tax	$	(1.0)	$	(1.6)	$	(2.9)	$	(4.8)
Total Amounts Reclassified from AOCI, Net of Tax	$	(1.5)	$	(2.1)	$	(4.4)	$	(6.3)

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Provision for Uncollectible Accounts (Tables)

9 Months Ended

Sep. 30, 2014

Notes To Consolidated Financial Statements [Abstract]

Schedule Of Accounts Notes Loans And Financing Receivable Text Block

(Millions of Dollars)	As of September 30, 2014		As of December 31, 2013
NU	$	181.4	$	171.3
CL&P		85.8		82.0
NSTAR Electric		42.3		41.7
PSNH		7.9		7.4
WMECO		11.1		10.0

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COMMON SHARES (Tables)

9 Months Ended

Sep. 30, 2014

Notes To Consolidated Financial Statements [Abstract]

Schedule of Stock by Class [Text Block]

12.       COMMON SHARES

The following table sets forth the NU common shares and the shares of common stock of CL&P, NSTAR Electric, PSNH and WMECO that were authorized and issued and the respective per share par values:

	Shares
			Authorized as of
	Per Share		September 30, 2014 and	Issued as of
	Par Value		December 31, 2013	September 30, 2014	December 31, 2013
NU	$	5	380,000,000	333,353,446	333,113,492
CL&P	$	10	24,500,000	6,035,205	6,035,205
NSTAR Electric	$	1	100,000,000	100	100
PSNH	$	1	100,000,000	301	301
WMECO	$	25	1,072,471	434,653	434,653

As of September30, 2014 and December31, 2013, there were 16,730,815 and 17,796,672 NU common shares held as treasury shares, respectively. As of September30, 2014 and December31, 2013, NU common shares outstanding were 316,622,631 and 315,273,559, respectively.

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Supplemental Cash Flow Information (Tables)

9 Months Ended

Sep. 30, 2014

Notes To Consolidated Financial Statements [Abstract]

Schedule of Cash Flow, Supplemental Disclosures [Table Text Block]

G.	Supplemental Cash Flow Information
Non-cash investing activities include plant additions included in Accounts Payable as follows:
(Millions of Dollars)		As of September 30, 2014		As of September 30, 2013
NU		$	128.9	$	122.9
CL&P			52.2		36.6
NSTAR Electric			18.1		31.9
PSNH			21.0		16.9
WMECO			10.0		13.8

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REGULATORY ACCOUNTING

9 Months Ended

Sep. 30, 2014

Notes To Consolidated Financial Statements [Abstract]

Public Utilities Disclosure [Text Block]

2.       REGULATORY ACCOUNTING

The rates charged to the customers of NU's Regulated companies are designed to collect each company's costs to provide service, including a return on investment. Therefore, the accounting policies of the Regulated companies follow the application of accounting guidance for entities with rate-regulated operations and reflect the effects of the rate-making process.

Management believes it is probable that each of the Regulated companies will recover their respective investments in long-lived assets, including regulatory assets. If management were to determine that it could no longer apply the accounting guidance applicable to rate-regulated enterprises to any of the Regulated companies' operations, or that management could not conclude it is probable that costs would be recovered from customers 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:

	As of September 30, 2014		As of December 31, 2013
(Millions of Dollars)	NU		NU
Benefit Costs	$	1,113.2	$	1,240.2
Derivative Liabilities		427.5		638.0
Income Taxes, Net		623.2		626.2
Storm Restoration Costs		493.5		589.6
Goodwill-related		510.5		525.9
Regulatory Tracker Mechanisms		235.7		323.4
Contractual Obligations - Yankee Companies		124.6		154.2
Buy Out Agreements for Power Contracts		49.8		70.2
Other Regulatory Assets		109.1		126.8
Total Regulatory Assets		3,687.1		4,294.5
Less: Current Portion		446.0		535.8
Total Long-Term Regulatory Assets	$	3,241.1	$	3,758.7

	As of September 30, 2014								As of December 31, 2013
			NSTAR								NSTAR
(Millions of Dollars)	CL&P		Electric		PSNH		WMECO		CL&P		Electric		PSNH		WMECO
Benefit Costs	$	242.2	$	318.1	$	78.1	$	44.3	$	297.7	$	496.7	$	100.6	$	57.3
Derivative Liabilities		421.1		4.3		-		-		630.4		7.7		-		-
Income Taxes, Net		427.4		83.3		38.3		35.3		415.5		84.0		40.3		43.7
Storm Restoration Costs		326.0		106.2		29.3		32.0		397.8		109.3		43.7		38.8
Goodwill-related		-		438.3		-		-		-		451.5		-		-
Regulatory Tracker Mechanisms		5.2		76.4		94.7		23.5		8.0		169.5		83.3		32.6
Buy Out Agreements for Power Contracts		-		45.4		4.4		-		-		64.7		5.5		-
Other Regulatory Assets		63.6		54.2		35.9		13.5		64.6		55.9		38.1		16.7
Total Regulatory Assets		1,485.5		1,126.2		280.7		148.6		1,814.0		1,439.3		311.5		189.1
Less: Current Portion		116.5		128.2		102.5		38.9		150.9		204.1		92.2		43.0
Total Long-Term Regulatory Assets	$	1,369.0	$	998.0	$	178.2	$	109.7	$	1,663.1	$	1,235.2	$	219.3	$	146.1

Benefit Costs: For information related to the Regulated companies' pension and other postretirement benefits, see Note 7, "Pension Benefits and Postretirement Benefits Other Than Pensions."

Storm Restoration Costs: On March 12, 2014, the PURA approved recovery of $365 million of deferred storm restoration costs (with carrying charges) associated with five major storms that occurred in 2011 and 2012. CL&P will recover thesecosts in its distribution rates over a six-year period beginning December 1, 2014. Effective June 1, 2014, CL&P received $65.4 million of DOE Phase II Damages proceeds. On June 17, 2014, the PURA ordered CL&P to refund these proceeds to customers by offsetting the deferred storm restoration costs regulatory asset. For further information on the DOE Phase II Damages proceeds received from the Yankee Companies, see Note 9C, "Commitments and Contingencies - Contractual Obligations - Yankee Companies," to the financial statements.

Regulatory Costs in Other Long-Term Assets:The Regulated companies had $64.7million ($3.2million for CL&P, $36million for NSTAR Electric, and $11.2million for WMECO) and $65.1million ($7.3million for CL&P, $33.4 million for NSTAR Electric, and $10.1 million for WMECO) of additional regulatory costs as of September 30, 2014 and December 31, 2013, respectively, that were included in Other Long-Term Assets on the balance sheets. These amounts represent incurred costs for which recovery has not yet been specifically approved by the applicable regulatory agency. However, based on regulatory policies or past precedent on similar costs, management believes it is probable that these costs will ultimately be approved and recovered from customers in rates.

Regulatory Liabilities: The components of regulatory liabilities are as follows:

	As of September 30, 2014		As of December 31, 2013
(Millions of Dollars)	NU		NU
Cost of Removal	$	439.1	$	435.1
Regulatory Tracker Mechanisms		339.9		151.2
AFUDC - Transmission		67.2		68.1
Other Regulatory Liabilities		62.7		52.9
Total Regulatory Liabilities		908.9		707.3
Less: Current Portion		399.0		204.3
Total Long-Term Regulatory Liabilities	$	509.9	$	503.0

	As of September 30, 2014								As of December 31, 2013
			NSTAR								NSTAR
(Millions of Dollars)	CL&P		Electric		PSNH		WMECO		CL&P		Electric		PSNH		WMECO
Cost of Removal	$	22.5	$	260.7	$	49.2	$	-	$	29.1	$	250.0	$	49.7	$	-
Regulatory Tracker Mechanisms		196.4		67.3		25.9		43.9		95.6		21.9		21.6		21.1
AFUDC - Transmission		53.9		4.1		-		9.2		54.7		4.1		-		9.3
Other Regulatory Liabilities		10.6		31.6		4.7		0.7		8.4		31.1		1.0		3.4
Total Regulatory Liabilities		283.4		363.7		79.8		53.8		187.8		307.1		72.3		33.8
Less: Current Portion		195.7		97.2		29.2		43.5		94.0		54.0		20.6		19.9
Total Long-Term Regulatory Liabilities	$	87.7	$	266.5	$	50.6	$	10.3	$	93.8	$	253.1	$	51.7	$	13.9

As a result of two FERC orders issued on June 19, 2014 in the pending base ROE complaint proceedings described in Note 9E, "Commitments and Contingencies – FERC Base ROE Complaints,"in the second quarter of 2014 the Company had recorded a series of reserves at its electric subsidiaries to recognize the potential financial impact of these rulings. As of September 30, 2014, the cumulative pre-tax reserves (excluding interest) totaled $76.1 million at NU, $42.9million at CL&P, $15.6million at NSTAR Electric, $5.9million at PSNH and $11.7million at WMECO.As of December31, 2013, as a result of the FERC ALJ initial decision in the third quarter of 2013, the Company had an aggregate pre-tax reserve (excluding interest)of $23.7million at NU, $12.8 million at CL&P, $5.7 million at NSTAR Electric, $2.3 million at PSNH and $2.9 million at WMECO. These reserves were recorded in each electric subsidiary's respective transmission regulatory tracker mechanism and as a reduction of Operating Revenues.

Effective June 1, 2014, as a result of damages awarded to the Yankee Companies for spent nuclear fuel lawsuits against the DOE described in Note 9C, "Commitments and Contingencies - Contractual Obligations - Yankee Companies," the Yankee Companies returned the DOE Phase II Damages proceeds to the member companies, including CL&P, NSTAR Electric, PSNH, and WMECO, for the benefit of their respective customers. CL&P's refund obligation to customers of $65.4 million was recorded as an offset to the deferred storm restoration costs regulatory asset, as directed by PURA. NSTAR Electric's, PSNH's and WMECO's refund obligation to customers of $29.1 million, $13.1 million and $18.1 million, respectively, was recorded as a regulatory liability in each electric subsidiary's respective regulatory tracker mechanisms.Refunds to customers for these DOE proceeds began in the third quarter of 2014.

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CONSOLIDATED STATEMENTS OF INCOME (USD $) In Thousands, except Share data, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Operating Revenues	$ 1,892,532	$ 1,892,590	$ 5,860,736	$ 5,523,475
Operating Expenses:
Purchased Power and Transmission	716,631	645,881	2,318,993	1,881,992
Operations and Maintenance	344,092	386,700	1,069,015	1,089,960
Depreciation	153,210	149,105	456,224	463,635
Amortization of Regulatory Assets/(Liabilities), Net	(22,531)	70,046	31,826	178,668
Amortization of Rate Reduction Bonds	0	0	0	42,581
Energy Efficiency Programs	118,693	106,097	360,228	306,010
Taxes Other Than Income Taxes	141,527	135,499	421,862	391,846
Total Operating Expenses	1,451,622	1,493,328	4,658,148	4,354,692
Operating Income	440,910	399,262	1,202,588	1,168,783
Interest Expense:
Interest on Long-Term Debt	85,208	84,911	260,076	256,205
Other Interest	4,530	2,565	12,132	(5,622)
Total Interest Expense	89,738	87,476	272,208	250,583
Other Income/(Loss), Net	11,860	8,945	19,054	21,655
Income Before Income Tax Expense	363,032	320,731	949,434	939,855
Income Tax Expense	126,539	109,351	345,858	325,442
Net Income	236,493	211,380	603,576	614,413
Net Income Attributable to Noncontrolling Interests	1,879	1,879	5,639	5,803
Net Income Attributable to Controlling Interests	234,614	209,501	597,937	608,610
Earnings Per Share Basic And Diluted	$ 0.74	$ 0.66	$ 1.89	$ 1.93
Common Stock Dividends Per Share Declared	$ 0.39	$ 0.37	$ 1.18	$ 1.10
Weighted Average Common Shares Outstanding:
Basic	316,340,691	315,291,346	315,941,904	315,191,752
Diluted	317,554,925	316,218,239	317,186,490	316,061,131
The Connecticut Light And Power Company [Member]
Operating Revenues	695,642	648,420	2,017,580	1,841,846
Operating Expenses:
Purchased Power and Transmission	255,787	253,152	736,952	667,266
Operations and Maintenance	127,285	127,104	368,562	359,759
Depreciation	46,886	44,786	139,598	132,356
Amortization of Regulatory Assets/(Liabilities), Net	13,098	(27)	62,644	11,223
Energy Efficiency Programs	41,399	24,544	119,389	68,211
Taxes Other Than Income Taxes	64,994	64,979	194,105	182,676
Total Operating Expenses	549,449	514,538	1,621,250	1,421,491
Operating Income	146,193	133,882	396,330	420,355
Interest Expense:
Interest on Long-Term Debt	34,743	32,845	102,290	98,163
Other Interest	3,992	2,439	8,158	801
Total Interest Expense	38,735	35,284	110,448	98,964
Other Income/(Loss), Net	6,456	3,861	10,658	10,946
Income Before Income Tax Expense	113,914	102,459	296,540	332,337
Income Tax Expense	30,038	36,136	95,980	113,149
Net Income	83,876	66,323	200,560	219,188
NSTAR Electric Company [Member]
Operating Revenues	727,909	753,879	1,955,609	1,916,557
Operating Expenses:
Purchased Power and Transmission	317,784	255,244	879,773	659,140
Operations and Maintenance	79,705	97,069	244,610	277,261
Depreciation	47,455	45,441	140,996	136,323
Amortization of Regulatory Assets/(Liabilities), Net	(15,063)	72,740	(916)	173,289
Amortization of Rate Reduction Bonds	0	0	0	15,054
Energy Efficiency Programs	56,915	58,798	145,499	161,180
Taxes Other Than Income Taxes	34,513	32,610	99,121	95,275
Total Operating Expenses	521,309	561,902	1,509,083	1,517,522
Operating Income	206,600	191,977	446,526	399,035
Interest Expense:
Interest on Long-Term Debt	17,996	19,860	58,485	59,261
Other Interest	(658)	(1,324)	606	(7,612)
Total Interest Expense	17,338	18,536	59,091	51,649
Other Income/(Loss), Net	3,287	2,126	3,011	3,275
Income Before Income Tax Expense	192,549	175,567	390,446	350,661
Income Tax Expense	76,975	68,558	156,655	137,499
Net Income	115,574	107,009	233,791	213,162
Public Service Company Of New Hampshire [Member]
Operating Revenues	223,664	218,608	735,123	708,550
Operating Expenses:
Purchased Power and Transmission	64,397	46,668	247,992	197,765
Operations and Maintenance	65,563	69,477	198,025	191,606
Depreciation	24,568	22,919	73,247	68,433
Amortization of Regulatory Assets/(Liabilities), Net	(9,734)	225	(17,565)	(1,745)
Amortization of Rate Reduction Bonds	0	0	0	19,748
Energy Efficiency Programs	3,766	3,990	10,897	11,036
Taxes Other Than Income Taxes	18,702	18,706	53,051	52,640
Total Operating Expenses	167,262	161,985	565,647	539,483
Operating Income	56,402	56,623	169,476	169,067
Interest Expense:
Interest on Long-Term Debt	10,896	10,345	33,812	32,951
Other Interest	128	521	183	1,230
Total Interest Expense	11,024	10,866	33,995	34,181
Other Income/(Loss), Net	461	792	1,673	2,454
Income Before Income Tax Expense	45,839	46,549	137,154	137,340
Income Tax Expense	17,603	18,196	52,199	52,797
Net Income	28,236	28,353	84,955	84,543
Western Massachusetts Electric Company [Member]
Operating Revenues	118,145	121,795	363,843	361,763
Operating Expenses:
Purchased Power and Transmission	43,926	38,797	130,977	111,095
Operations and Maintenance	20,820	26,148	67,085	70,213
Depreciation	10,506	9,426	31,144	27,707
Amortization of Regulatory Assets/(Liabilities), Net	(8,519)	(1,412)	(7,778)	(598)
Amortization of Rate Reduction Bonds	0	0	0	7,780
Energy Efficiency Programs	10,983	12,222	33,096	28,462
Taxes Other Than Income Taxes	9,200	7,696	25,679	20,188
Total Operating Expenses	86,916	92,877	280,203	264,847
Operating Income	31,229	28,918	83,640	96,916
Interest Expense:
Interest on Long-Term Debt	6,029	5,814	18,195	17,846
Other Interest	547	417	734	954
Total Interest Expense	6,576	6,231	18,929	18,800
Other Income/(Loss), Net	502	926	1,670	2,349
Income Before Income Tax Expense	25,155	23,613	66,381	80,465
Income Tax Expense	10,490	8,588	26,596	30,424
Net Income	$ 14,665	$ 15,025	$ 39,785	$ 50,041

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COMMON SHARES

9 Months Ended

Sep. 30, 2014

Notes To Consolidated Financial Statements [Abstract]

Schedule of Stock by Class [Text Block]

12.       COMMON SHARES

The following table sets forth the NU common shares and the shares of common stock of CL&P, NSTAR Electric, PSNH and WMECO that were authorized and issued and the respective per share par values:

	Shares
			Authorized as of
	Per Share		September 30, 2014 and	Issued as of
	Par Value		December 31, 2013	September 30, 2014	December 31, 2013
NU	$	5	380,000,000	333,353,446	333,113,492
CL&P	$	10	24,500,000	6,035,205	6,035,205
NSTAR Electric	$	1	100,000,000	100	100
PSNH	$	1	100,000,000	301	301
WMECO	$	25	1,072,471	434,653	434,653

As of September30, 2014 and December31, 2013, there were 16,730,815 and 17,796,672 NU common shares held as treasury shares, respectively. As of September30, 2014 and December31, 2013, NU common shares outstanding were 316,622,631 and 315,273,559, respectively.

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DOCUMENT AND ENTITY INFORMATION (USD $)	9 Months Ended
	Sep. 30, 2014	Oct. 31, 2014
Document And Entity [Line Items]
Entity Registrant Name	NORTHEAST UTILITIES
Document Period End Date	Sep. 30, 2014
Document Type	10-Q
Entity Central Index Key	0000072741
Current Fiscal Year End Date	--12-31
Entity Common Stock, Shares Outstanding		316,799,371
Entity Public Float	$ 14,947,688,864
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	2014
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

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COMMON SHARESHOLDERS' EQUITY AND NONCONTROLLING INTERESTS (NU)

9 Months Ended

Sep. 30, 2014

Notes To Consolidated Financial Statements [Abstract]

Stockholders' Equity Note Disclosure [Text Block]

13.	COMMON SHAREHOLDERS' EQUITY AND NONCONTROLLING INTERESTS
A summary of the changes in Common Shareholders' Equity and Noncontrolling Interests of NU is as follows:
		For the Three Months Ended
		September 30, 2014				September 30, 2013
				Noncontrolling				Noncontrolling
				Interest -				Interest -
		Common		Preferred		Common		Preferred
		Shareholders'		Stock of		Shareholders'		Stock of
(Millions of Dollars)		Equity		Subsidiaries		Equity		Subsidiaries
Balance as of Beginning of Period		$	9,753.8	$	155.6	$	9,406.6	$	155.6
Net Income			236.5		-		211.4		-
Dividends on Common Shares			(124.2)		-		(114.9)		-
Dividends on Preferred Stock			(1.9)		(1.9)		(1.9)		(1.9)
Issuance of Common Shares			1.0		-		1.4		-
Other Transactions, Net			24.1		-		12.8		-
Net Income Attributable to Noncontrolling Interests			-		1.9		-		1.9
Other Comprehensive Income			1.3		-		2.1		-
Balance as of End of Period		$	9,890.6	$	155.6	$	9,517.5	$	155.6
		For the Nine Months Ended
		September 30, 2014				September 30, 2013
				Noncontrolling				Noncontrolling
				Interest -				Interest -
		Common		Preferred		Common		Preferred
		Shareholders'		Stock of		Shareholders'		Stock of
(Millions of Dollars)		Equity		Subsidiaries		Equity		Subsidiaries
Balance as of Beginning of Period		$	9,611.5	$	155.6	$	9,237.1	$	155.6
Net Income			603.6		-		614.4		-
Dividends on Common Shares			(372.2)		-		(346.9)		-
Dividends on Preferred Stock			(5.6)		(5.6)		(5.8)		(5.8)
Issuance of Common Shares			6.4		-		10.2		-
Other Transactions, Net			41.0		-		3.0		-
Net Income Attributable to Noncontrolling Interests			-		5.6		-		5.8
Other Comprehensive Income			5.9		-		5.5		-
Balance as of End of Period		$	9,890.6	$	155.6	$	9,517.5	$	155.6

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CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Net Income	$ 236,493	$ 211,380	$ 603,576	$ 614,413
Other Comprehensive Income Loss Net Of Tax Period Increase Decrease Abstract
Other Comprehensive Income (Loss), Derivatives Qualifying as Hedges, Net of Tax	509	509	1,528	1,539
Other Comprehensive Income (Loss), Available-for-sale Securities Adjustment, Net of Tax	(216)	(38)	242	(810)
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Adjustment, Net of Tax	1,042	1,611	4,089	4,738
Other Comprehensive Income (Loss), Net of Tax, Total	1,335	2,082	5,859	5,467
Comprehensive Income Attributable to Noncontrolling Interests	(1,879)	(1,879)	(5,639)	(5,803)
Comprehensive Income	235,949	211,583	603,796	614,077
The Connecticut Light And Power Company [Member]
Net Income	83,876	66,323	200,560	219,188
Other Comprehensive Income Loss Net Of Tax Period Increase Decrease Abstract
Other Comprehensive Income (Loss), Derivatives Qualifying as Hedges, Net of Tax	111	111	333	333
Other Comprehensive Income (Loss), Available-for-sale Securities Adjustment, Net of Tax	(7)	(1)	8	(27)
Other Comprehensive Income (Loss), Net of Tax, Total	104	110	341	306
Comprehensive Income	83,980	66,433	200,901	219,494
NSTAR Electric Company [Member]
Net Income	115,574	107,009	233,791	213,162
Public Service Company Of New Hampshire [Member]
Net Income	28,236	28,353	84,955	84,543
Other Comprehensive Income Loss Net Of Tax Period Increase Decrease Abstract
Other Comprehensive Income (Loss), Derivatives Qualifying as Hedges, Net of Tax	290	290	871	872
Other Comprehensive Income (Loss), Available-for-sale Securities Adjustment, Net of Tax	(13)	(2)	14	(47)
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Adjustment, Net of Tax	0	0	0	(3)
Other Comprehensive Income (Loss), Net of Tax, Total	277	288	885	822
Comprehensive Income	28,513	28,641	85,840	85,365
Western Massachusetts Electric Company [Member]
Net Income	14,665	15,025	39,785	50,041
Other Comprehensive Income Loss Net Of Tax Period Increase Decrease Abstract
Other Comprehensive Income (Loss), Derivatives Qualifying as Hedges, Net of Tax	85	85	254	254
Other Comprehensive Income (Loss), Available-for-sale Securities Adjustment, Net of Tax	(2)	0	2	(8)
Other Comprehensive Income (Loss), Net of Tax, Total	83	85	256	246
Comprehensive Income	$ 14,748	$ 15,110	$ 40,041	$ 50,287

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PENSION BENEFITS AND POSTRETIREMENT BENEFITS OTHER THAN PENSIONS

9 Months Ended

Sep. 30, 2014

Notes To Consolidated Financial Statements [Abstract]

Pension and Other Postretirement Benefits Disclosure [Text Block]

7.Pension Benefits and Postretirement Benefits Other than Pensions

The components of net periodic benefit expense for the Pension, SERP and PBOP Plans are shown below. The net periodic benefit expense less the capitalized portion of pension and PBOP amounts is included in Operations and Maintenance on the statements of income. Capitalized pension and PBOP amounts relate to employees working on capital projects and are included in Property, Plant and Equipment, Net. Intercompany allocations are not included in the CL&P, NSTAR Electric, PSNH and WMECO net periodic benefit expense amounts.

	Pension and SERP				Pension and SERP
	For the Three Months Ended				For the Nine Months Ended
	September 30, 2014		September 30, 2013		September 30, 2014		September 30, 2013
(Millions of Dollars)	NU		NU		NU		NU
Service Cost	$	19.1	$	25.6	$	60.7	$	76.7
Interest Cost		56.4		51.7		169.5		155.0
Expected Return on Plan Assets		(77.7)		(69.5)		(233.1)		(208.5)
Actuarial Loss		31.7		52.4		96.5		158.1
Prior Service Cost		1.1		1.1		3.3		3.0
Total Net Periodic Benefit Expense	$	30.6	$	61.3	$	96.9	$	184.3
Capitalized Pension Expense	$	8.3	$	18.3	$	26.7	$	54.9
	PBOP				PBOP
	For the Three Months Ended				For the Nine Months Ended
	September 30, 2014		September 30, 2013		September 30, 2014		September 30, 2013
(Millions of Dollars)	NU		NU		NU		NU
Service Cost	$	3.1	$	4.2	$	9.3	$	12.6
Interest Cost		12.4		11.8		37.1		35.4
Expected Return on Plan Assets		(15.8)		(13.9)		(47.4)		(41.6)
Actuarial Loss		3.0		6.5		9.1		19.5
Prior Service Credit		(0.7)		(0.5)		(2.1)		(1.5)
Total Net Periodic Benefit Expense	$	2.0	$	8.1	$	6.0	$	24.4
Capitalized PBOP Expense	$	1.1	$	2.6	$	1.9	$	7.6

	Pension and SERP
	For the Three Months Ended September 30, 2014								For the Three Months Ended September 30, 2013
			NSTAR								NSTAR
(Millions of Dollars)	CL&P		Electric		PSNH		WMECO		CL&P		Electric(1)		PSNH		WMECO
Service Cost	$	5.0	$	3.0	$	2.3	$	0.8	$	6.3	$	8.3		3.3	$	1.2
Interest Cost		12.5		10.3		5.7		2.5		12.1		14.5		5.8		2.5
Expected Return on Plan Assets		(18.7)		(15.7)		(9.3)		(4.4)		(18.4)		(21.1)		(9.2)		(4.3)
Actuarial Loss		8.2		5.9		2.8		1.7		13.9		14.4		5.4		2.9
Prior Service Cost		0.4		-		0.1		0.1		0.4		-		0.1		0.1
Total Net Periodic Benefit Expense	$	7.4	$	3.5	$	1.6	$	0.7	$	14.3	$	16.1	$	5.4	$	2.4
Intercompany Allocations	$	6.5	$	2.9	$	1.8	$	1.2	$	11.4	$	(2.1)	$	2.6	$	2.0
Capitalized Pension Expense	$	4.3	$	2.6	$	0.7	$	0.6	$	7.0	$	9.8	$	1.7	$	1.3
	Pension and SERP
	For the Nine Months Ended September 30, 2014								For the Nine Months Ended September 30, 2013
			NSTAR								NSTAR
(Millions of Dollars)	CL&P		Electric		PSNH		WMECO		CL&P		Electric(1)		PSNH		WMECO
Service Cost	$	15.2	$	10.6	$	7.4	$	2.7	$	18.7	$	24.8	$	9.8	$	3.5
Interest Cost		38.1		31.0		18.0		7.8		36.3		43.5		17.8		7.5
Expected Return on Plan Assets		(56.7)		(47.3)		(28.8)		(13.5)		(55.4)		(63.3)		(26.2)		(13.0)
Actuarial Loss		25.5		17.6		8.9		5.2		42.0		43.6		16.2		8.9
Prior Service Cost/(Credit)		1.4		-		0.5		0.3		1.4		(0.2)		0.4		0.3
Total Net Periodic Benefit Expense	$	23.5	$	11.9	$	6.0	$	2.5	$	43.0	$	48.4	$	18.0	$	7.2
Intercompany Allocations	$	20.8	$	6.7	$	6.0	$	3.9	$	33.6	$	(6.2)	$	7.8	$	6.0
Capitalized Pension Expense	$	13.6	$	5.5	$	2.4	$	2.0	$	21.0	$	21.6	$	5.6	$	3.9

	PBOP
	For the Three Months Ended September 30, 2014								For the Three Months Ended September 30, 2013
(Millions of Dollars)	CL&P			NSTAR Electric		PSNH		WMECO	CL&P		PSNH		WMECO
Service Cost	$	0.6	$	0.8	$	0.3	$	0.1	$	0.9	$	0.6	$	0.2
Interest Cost		2.0		4.9		1.1		0.4		2.0		1.0		0.4
Expected Return on Plan Assets		(2.6)		(6.5)		(1.4)		(0.6)		(2.5)		(1.3)		(0.6)
Actuarial Loss/(Gain)		1.0		(0.1)		0.6		0.1		1.8		0.9		0.3
Prior Service Credit		-		(0.5)		-		-		-		-		-
Total Net Periodic Benefit Expense/(Income)	$	1.0	$	(1.4)	$	0.6	$	0.0	$	2.2	$	1.2	$	0.3
Intercompany Allocations	$	0.9	$	0.3	$	0.2	$	0.2	$	1.7	$	0.4	$	0.3
Capitalized PBOP Expense/(Income)	$	0.5	$	(0.5)	$	0.2	$	-	$	1.3	$	0.4	$	0.3
	PBOP
	For the Nine Months Ended September 30, 2014								For the Nine Months Ended September 30, 2013
(Millions of Dollars)	CL&P			NSTAR Electric		PSNH		WMECO	CL&P		PSNH		WMECO
Service Cost	$	1.7	$	2.3	$	1.0	$	0.3	$	2.6	$	1.7	$	0.5
Interest Cost		6.0		14.6		3.2		1.3		5.9		3.1		1.3
Expected Return on Plan Assets		(7.9)		(19.5)		(4.1)		(1.7)		(7.6)		(3.9)		(1.7)
Actuarial Loss/(Gain)		3.2		(0.4)		1.7		0.3		5.6		2.7		0.8
Prior Service Credit		-		(1.4)		-		-		-		-		-
Total Net Periodic Benefit Expense/(Income)	$	3.0	$	(4.4)	$	1.8	$	0.2	$	6.5	$	3.6	$	0.9
Intercompany Allocations	$	3.1	$	0.4	$	0.8	$	0.6	$	5.3	$	1.2	$	1.0
Capitalized PBOP Expense/(Income)	$	1.5	$	(1.5)	$	0.6	$	0.1	$	3.7	$	1.1	$	0.7

• NSTAR Electric's pension amounts for the three and nine months ended September 30, 2013 do not include SERP expense.

For the three and nine months ended September 30, 2013, the net periodic PBOP expense allocated to NSTAR Electric was $1.2million and $3.5million, respectively.

As of December 31, 2013, the funded status of the NSTAR Pension Plan was recorded on NSTAR Electric's balance sheet while the total SERP obligation and PBOP Plan funded status were recorded on NSTAR Electric & Gas' balance sheet. As of December 31, 2013, all NSTAR employees were employed by NSTAR Electric & Gas. On January 1, 2014, NSTAR Electric & Gas was merged into NUSCO and, concurrently, all employees were transferred to the company they predominately provide services for: NUSCO, NSTAR Electric or NSTAR Gas. As a result of the employee transfers, the pension and PBOP assets and liabilitieswereattributed by participant and transferred to the respective company's balance sheets.This change had no impact on the income statement or net assets of NSTAR Electric or NU.

As of September 30, 2014, the liabilities associated with the Pension, SERP and PBOP plans for NSTAR Electric were $83.4million for the Pension Plan, $3.6million for the SERP Plans ($0.4 million of which is included in other current liabilities) and $55.6million for the PBOP Plan. As of December31, 2013, the liability associated with the NSTAR Pension Plan for NSTAR Electric was $118 million.

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SHORT TERM AND LONG TERM DEBT

9 Months Ended

Sep. 30, 2014

Notes To Consolidated Financial Statements [Abstract]

Debt Disclosure

6.SHORT-TERM AND LONG-TERM DEBT

Credit Agreements and Commercial Paper Programs:Effective July 23, 2014, NU parent, CL&P, PSNH, WMECO, NSTAR Gas and Yankee Gas extended the expiration date of their joint $1.45 billion revolving credit facilityfor one additional year to September 6, 2019. The revolving credit facility is to be used primarily to backstop NU parent's $1.45 billion commercial paper program. The commercial paper program allows NU parent to issue commercial paper as a form of short-term debt. As of September 30, 2014 and December 31, 2013, NU had $964.5million and $1.01 billion, respectively, in short-term borrowings outstanding under the NU parent commercial paper program, leaving $485.5million and $435.5million of available borrowing capacity as of September 30, 2014 and December 31, 2013, respectively. The weighted-average interest rate on these borrowings as of September 30, 2014 and December 31, 2013 was 0.25percent and 0.24 percent, respectively, which is generally based on A2/P2 rated commercial paper. As of September 30, 2014, there were intercompany loans from NU of $105.4million to CL&P, $153.3million to PSNH and $13.2million to WMECO. As of December 31, 2013, there were intercompany loans from NU of $287.3 million to CL&P and $86.5 million to PSNH.

Effective July 23, 2014, NSTAR Electric extended the expiration date of its $450 million revolving credit facility forone additional year to September 6, 2019.This facility serves to backstop NSTAR Electric's existing $450 million commercial paper program.As of September 30, 2014 and December 31, 2013, NSTAR Electric had $159.5million and $103.5 million, respectively, in short-term borrowings outstanding under its commercial paper program, leaving $290.5million and$346.5 million of available borrowing capacity as of September 30, 2014 and December31, 2013, respectively. The weighted-average interest rate on these borrowings as ofSeptember 30, 2014 and December 31, 2013 was 0.16percent and 0.13percent,respectively, which is generally based on A2/P1 rated commercial paper.

Amounts outstanding under the commercial paper programs are generally included in Notes Payable for NU and NSTAR Electric and classified in current liabilities on the balance sheets as all borrowings are outstanding for no more than 364 days at one time. Intercompany loans from NU to CL&P, PSNH and WMECO are included in Notes Payable to NU Parent and classified in current liabilities on the balance sheets.

Long-Term Debt: On January 2, 2014, Yankee Gas issued $100 million of 4.82 percent Series L First Mortgage Bonds, due to mature in 2044. The proceeds, net of issuance costs, were used to repay the $75 million 4.80 percent Series G First Mortgage Bonds that matured on January 1, 2014 and to pay $25 million in short-term borrowings. As the debt issuance refinanced short-term debt, the short-term debt was classified as Long-Term Debt on NU's balance sheet as of December 31, 2013.

On March 7, 2014, NSTAR Electric issued $300 million of 4.40 percent debentures, due to mature in 2044. The proceeds, net of issuance costs, were used to repay the $300 million of 4.875 percent debentures that matured on April 15, 2014.

On April 24, 2014, CL&P issued $250 million of 4.30 percent 2014 Series A First Mortgage Bonds, due to mature in 2044. The proceeds, net of issuance costs, were used to repay short-term borrowings.

On July 15, 2014, PSNH repaid at maturity the $50 million of 5.25 percent Series L First Mortgage Bondsusing short-term borrowings.

On September 15, 2014, CL&P repaid at maturity the $150 million of 4.80 percent 2004 Series A First Mortgage Bonds.

On October 14, 2014, PSNH issued $75 million of first mortgage bonds at a yield of 3.144 percent that will mature on November 1, 2023. The first mortgage bonds are part of the same series of PSNH's existing 3.50 percent Series S First Mortgage Bonds that were initially issued in November 2013. As a result, the aggregate principal amount of PSNH's outstanding Series S First Mortgage Bonds totals $325 million.The proceeds, net of issuance costs, were used to repay short-term borrowings. As the debt issuance refinanced short-term debt, the short-term debt was classified as Long-Term Debt on NU's balance sheet as of September 30, 2014.

On August 27, 2014, PURA approved CL&P's request to extend the authorization period for issuance of up to $366.4 million in long-term debt from December 31, 2014 to December 31, 2015.

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Other Taxes (Tables)

9 Months Ended

Sep. 30, 2014

Notes To Consolidated Financial Statements [Abstract]

State Of Connecticut Gross Earnings Taxes [Table Text Block]

	For the Three Months Ended				For the Nine Months Ended
(Millions of Dollars)	September 30, 2014		September 30, 2013		September 30, 2014		September 30, 2013
NU	$	35.0	$	37.5	$	114.6	$	108.9
CL&P		32.5		35.5		99.0		97.3

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EARNINGS PER SHARE

9 Months Ended

Sep. 30, 2014

Notes To Consolidated Financial Statements [Abstract]

Earnings Per Share [Text Block]

14.       EARNINGS PER SHARE

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 of certain share-based compensation awardsas if they were converted into common shares. There were no antidilutive share awards outstanding forthe threeand nine months ended September 30, 2014 or for the three months ended September 30, 2013.For thenine months ended September 30,2013, there were 2,100antidilutive share awards excluded from the computation.

The following table sets forth the components of basic and diluted EPS:

		For the Three Months Ended				For the Nine Months Ended
(Millions of Dollars, except share information)		September 30, 2014		September 30, 2013		September 30, 2014		September 30, 2013
Net Income Attributable to Controlling Interest		$	234.6	$	209.5	$	597.9	$	608.6
Weighted Average Common Shares Outstanding:
	Basic		316,340,691		315,291,346		315,941,904		315,191,752
	Dilutive Effect		1,214,234		926,893		1,244,586		869,379
	Diluted		317,554,925		316,218,239		317,186,490		316,061,131
Basic and Diluted EPS		$	0.74	$	0.66	$	1.89	$	1.93

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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FAIR VALUE OF FINANCIAL INSTRUMENTS

9 Months Ended

Sep. 30, 2014

Notes To Consolidated Financial Statements [Abstract]

Fair Value Disclosures [Text Block]

10.       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 and Long-Term Debt: 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 long-term debt securities 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. 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 September 30, 2014				As of December 31, 2013
	NU				NU
	Carrying		Fair		Carrying		Fair
(Millions of Dollars)	Amount		Value		Amount		Value
Preferred Stock Not Subject to Mandatory Redemption	$	155.6	$	151.0	$	155.6	$	152.7
Long-Term Debt		8,412.6		8,876.3		8,310.2		8,443.1

	As of September 30, 2014
	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	$	110.1	$	43.0	$	40.9	$	-	$	-	$	-	$	-
Long-Term Debt		2,841.8		3,189.5		1,797.4		1,959.4		999.2		1,046.4		628.7		667.4
	As of December 31, 2013
	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	$	110.5	$	43.0	$	42.2	$	-	$	-	$	-	$	-
Long-Term Debt		2,741.2		2,952.8		1,801.1		1,888.0		1,049.0		1,073.9		629.4		640.1

Derivative Instruments: Derivative instruments are carried at fair value. For further information, see Note 4, "Derivative Instruments," to the financial statements.

Other Financial Instruments: Investments in marketable securities are carried at fair value. For further information, see Note5, "Marketable Securities," to the 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.

See Note 1D, "Summary of Significant Accounting Policies - Fair Value Measurements," for the fair value measurement policy and the fair value hierarchy.

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COMMON SHARES (Details) (USD $)	Sep. 30, 2014	Dec. 31, 2013
Class Of Stock [Line Items]
Common Stock Par Or Stated Value Per Share	$ 5	$ 5
Common Stock Shares Authorized	380,000,000	380,000,000
Common Stock Shares Issued	333,353,446	333,113,492
Treasury Stock Shares	16,730,815	17,796,672
Common Stock, Shares, Outstanding	316,622,631	315,273,559
The Connecticut Light And Power Company [Member]
Class Of Stock [Line Items]
Common Stock Par Or Stated Value Per Share	$ 10	$ 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	$ 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	$ 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	$ 25
Common Stock Shares Authorized	1,072,471	1,072,471
Common Stock Shares Issued	434,653	434,653

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INCOME TAXES

9 Months Ended

Sep. 30, 2014

Notes To Consolidated Financial Statements [Abstract]

Income Tax Disclosure [Text Block]

8.INCOME TAXES

In the third quarter of 2014, the Company recorded a reduction to its state credit carryforwards of $11 million (CL&P $10.1 million), net of tax, as a result of an update to reflect the amounts expired. Further, the Company decreased its valuation allowance reserve for state credits by $22.3 million (all at CL&P), net of tax, to reflect the expiration of state credits in its recently filed return and the latest available data. These updates resulted in a net reduction in income tax expense of $11.3 million (CL&P $12.2 million).

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COMMITMENTS AND CONTINGENCIES

9 Months Ended

Sep. 30, 2014

Notes To Consolidated Financial Statements [Abstract]

Commitments and Contingencies Disclosure [Text Block]

9.       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.

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 September 30, 2014				As of December 31, 2013
			Reserve				Reserve
	Number of Sites		(in millions)		Number of Sites		(in millions)
NU		65	$	34.7		68	$	35.4
CL&P		16		4.0		18		3.4
NSTAR Electric		13		1.1		12		1.2
PSNH		13		5.3		15		5.4
WMECO		4		0.5		5		0.4

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 $29.8million and $31.4million as of September 30, 2014 and December31, 2013, respectively, and relates primarily to the natural gas business segment.

B.Long-Term Contractual Arrangements

The following is an update to the current status of long-term contractual arrangements set forth in Note 12B of the NU 2013 Form 10-K.

Renewable Energy:Renewable energy contracts include non-cancelable commitments under contracts of CL&P, NSTAR Electric and WMECO for the purchase of energy and capacity from renewable energy facilities.

	October - December
(Millions of Dollars)	2014		2015		2016		2017		2018		Thereafter		Total
CL&P	$	20.0	$	60.7	$	66.1	$	67.0	$	67.7	$	717.0	$	998.5
NSTAR Electric		21.8		86.3		100.0		96.1		59.6		377.6		741.4
WMECO		-		-		2.4		2.4		2.4		28.9		36.1

C.Contractual Obligations – Yankee Companies

Spent Nuclear Fuel Litigation – DOE Phase II Damages– On November 15, 2013, the Court of Federal Claims issued an award to CYAPC for $126.3 million, YAEC for $73.3 million and MYAPC for $35.8 million for lawsuits against the DOE seeking recovery of actual damages incurred in the years following 2001 and 2002 (DOE Phase II Damages). On January 14, 2014, the Yankee Companies received a letter from the U.S. Department of Justice stating that the DOE will not appeal the court's final judgment.

On March 28, 2014, CYAPC, YAEC and MYAPC received payment of $90 million, $73.3 million and $35.8 million, respectively, of theDOE Phase II Damages proceeds. On April 24, 2014, CYAPC received payment of the remaining $36.3 million proceeds.On April 28, 2014, the Yankee Companies made the required informational filing with FERC in accordance with the process and methodology outlined in the 2013 FERC order. The Yankee Companies returned the DOE Phase II Damages proceeds to the member companies, including CL&P, NSTAR Electric, PSNH, and WMECO, for the benefit of their respective customers, on June 1, 2014.

As of September 30, 2014, CL&P's refund obligation to customers of $65.4 millionwas recorded as an offset to the deferred storm restoration costs regulatory asset, as directed by PURA. NSTAR Electric's, PSNH's and WMECO's refund obligation to customers of $29.1 million, $13.1 million and $18.1 million, respectively, was recorded as a regulatory liability in each company's respective regulatory tracker mechanisms. Refunds to customers for these DOE proceeds began in the third quarter of 2014.For further information, see Note 2, "Regulatory Accounting," to the financial statements.

DOE Phase III Damages – On August 15, 2013, the Yankee Companies each filed subsequent lawsuits against the DOE seeking recovery of actual damages incurred in the years 2009 through 2012. Responsive pleading from the U.S. Department of Justice was filed on November 18, 2013, and discovery has begun.

DOE Phase I Damages- Proceeds Received – On September 17, 2014, in accordance with the MYAPC refund plan, MYAPC returned a portion of the DOE Phase I Damages proceeds to the member companies, including CL&P, NSTAR Electric, PSNH, and WMECO, in the amount of $3.2 million, $1.1 million, $1.4 million and $0.8 million, respectively. These amounts reduced receivables at CL&P, NSTAR Electric, PSNH and WMECO.

D.       Guarantees and Indemnifications

NUparent 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 and the termination of an unregulated business, with maximum exposures either not specified or not material.

NU also issued a guaranty 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.

The following table summarizes NU's guarantees of its subsidiaries, including CL&P, NSTAR Electric, PSNH and WMECO, as of September 30, 2014:

		Maximum Exposure
Subsidiary	Description	(in millions)		Expiration Dates
Various	Surety Bonds	$	64.3	2014 - 2016 (1)
Various	New England Hydro Companies' Long-Term Debt	$	2.0	Unspecified
NUSCO and RRR	Lease Payments for Vehicles and Real Estate	$	15.3	2019 and 2024

(1)       Surety bond expiration dates reflect termination dates, the majority of which will be renewed or extended.

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 NUare downgraded.

E.FERC Base ROE Complaints

First Complaint: On September 30, 2011, a complaint was filed jointly at FERC under Sections 206 and 306 of the Federal Power Act (the "first complaint") by several New England state attorneys general, state regulatory commissions, consumer advocates and other parties (the "Complainants"). The Complainants alleged that the base ROE of 11.14 percent that has been utilized since 2006 in the calculation of formula rates for transmission service under the ISO-NE Open Access Transmission Tariff by NETOs, including CL&P, NSTAR Electric, PSNH and WMECO, was unjust and unreasonable and asserted that the rate was excessive due to changes in the capital markets. Complainants sought an order to reduce the base ROE prospectively from the date of a final FERC order (the "FERC order date"), and for the 15-month period October 1, 2011 to December 31, 2012 (the "first complaint refund period"), and to require refunds. The FERC set the case for trial before a FERC ALJ after settlement negotiations were unsuccessful in August 2012.

On August 6, 2013, the FERC ALJ issued an initial decision on the first complaint finding that the base ROE in effect during the first complaint refund period was not reasonable and recommended separate base ROEs for the first complaint refund period of 10.6 percent and for the period beginning when FERC issues its final decision (the "prospective period") of 9.7 percent, leaving policy considerations and additional adjustments to the FERC. In the third quarter of 2013, the Company recorded a series of reserves at its electric subsidiaries to recognize the potential financial impact from the FERC ALJ's initial decision for the first complaint refund period. See Cumulative Reserves below for further information on the reserves recorded in the third quarter of 2013.

On June 19, 2014, FERC issued an order on the first complaint, partially affirming and partially reversing the FERC ALJ's initial decision. FERC set a single tentative base ROE of 10.57 percent for the first complaint refund period and prospective period. FERC also modified its traditional methodology by adopting a two-step discounted cash flow analysis that it utilizes to determine the ROEs of both natural gas and oil pipeline projects. Using this methodology, FERC determined a new zone of reasonableness of 7.03 percent to 11.74 percent, and set the tentative base ROE halfway between the midpoint and the top of the zone of reasonableness. FERC also stated that a utility's “total ROE, inclusive of transmission incentive ROE adders” should not exceed the top of the new zone of reasonableness produced by this methodology. FERC instituted a paper hearing on the long-term growth rate portion of the methodology (the "paper hearing"). Rehearing requests on this new methodology were filed in July, and briefs were filed in August and September by the parties on the appropriate long-term growth rate. In the second quarter of 2014, the Company recorded additional reserves at its electric subsidiaries to recognize the potential financial impact from the FERC's June 19th order. See Cumulative Reserves below for further information on the reserves recorded in the second quarter of 2014.

On October 16, 2014, the FERC issued an order in the paper hearing, which confirmed that the base ROE should be set at 10.57 percent and that a utility's total or maximum ROE should not exceed the top of the new zone of reasonableness (11.74 percent). The FERC ordered the NETOs to provide refunds to customers for the first complaint refund period, and set the new base ROE prospectively from the order date.

Second Complaint: On December 27, 2012, a second complaint was filed jointly at FERC by several additional consumer groups and municipal parties (the "second complaint"), which challenged the NETOs' base ROE prospectively from the FERC order date and sought refunds for the 15-month period January 1, 2013 to March 31, 2014 (the "second complaint refund period").

On June 19, 2014, FERC issued an order finding that the second complaint raised issues of material fact. On July 21, 2014, the NETOs filed a rehearing request in this proceeding. On October 24, 2014, the FERC assigned the case for trial before a FERC ALJ after settlement negotiations were unsuccessful. The FERC ALJ has set a trial date beginning June 8, 2015, and will issue an initial decision on or before October 26, 2015. In the second quarter of 2014, the Company recorded reserves at its electric subsidiaries to recognize the potential financial impact from the FERC's June 19th order for the second complaint refund period. See Cumulative Reserves below for further information on the reserves recorded in the second quarter of 2014.

Third Complaint: On July 31, 2014, a third complaint was filed at FERC (the "third complaint") by most of the Complainants to the first and second complaints, claiming that the base ROE and incentive adders exceed the range of permissible ROEs, requesting FERC to reduce the NETO's base ROE prospectively from the FERC order date, and seeking refunds for the 15-month period beginning August 1, 2014 (the "third complaint refund period"). FERC has taken no action on this complaint to date. At this time, the Company cannot determine the outcome of this complaint.

Cumulative Reserves: The following is a summary as of September 30, 2014 of the cumulative reserves (excluding interest) that the Company established in the third quarter of 2013 and the second quarter of 2014 to recognize the potential financial impacts of the first and second complaints. Management is currently evaluating the impact of the October 16th order on the previously established reserves.

	NU
		Third Quarter		Second Quarter
(Millions of Dollars)		2013		2014	Total
1st Complaint - Base ROE	$	23.7	$	1.2	$	24.9
2nd Complaint - Base ROE		-		27.4		27.4
Incentive ROE (1st and 2nd Complaint)		-		23.8		23.8
Cumulative Reserve	$	23.7	$	52.4	$	76.1
	CL&P						NSTAR Electric
		Third Quarter		Second Quarter				Third Quarter		Second Quarter
(Millions of Dollars)		2013		2014	Total			2013		2014	Total
1st Complaint - Base ROE	$	12.8	$	0.5	$	13.3	$	5.7	$	0.4	$	6.1
2nd Complaint - Base ROE		-		13.5		13.5		-		7.5		7.5
Incentive ROE (1st and 2nd Complaint)		-		16.1		16.1		-		2.0		2.0
Cumulative Reserve	$	12.8	$	30.1	$	42.9	$	5.7	$	9.9	$	15.6
	PSNH						WMECO
		Third Quarter		Second Quarter				Third Quarter		Second Quarter
(Millions of Dollars)		2013		2014	Total			2013		2014	Total
1st Complaint - Base ROE	$	2.3	$	0.1	$	2.4	$	2.9	$	0.2	$	3.1
2nd Complaint - Base ROE		-		2.7		2.7		-		3.7		3.7
Incentive ROE (1st and 2nd Complaint)		-		0.8		0.8		-		4.9		4.9
Cumulative Reserve	$	2.3	$	3.6	$	5.9	$	2.9	$	8.8	$	11.7

The aggregate after-tax charge to second quarter 2014 earnings resulting from the June 19, 2014 FERC orders totaled $32.1 million at NU, $18.5 million at CL&P, $6.1 million at NSTAR Electric, $2 million at PSNH and $5.5 million at WMECO. In the third quarter of 2013, the aggregate after-tax charge to earnings totaled $14.3 million at NU, $7.7 million at CL&P, $3.4 million at NSTAR Electric, $1.4 million at PSNH and $1.8 million at WMECO.

F.        CPSL

Since 2006, NSTAR Electric has been recovering incremental costs related to the DPU-approved Safety and Reliability Programs. From 2006 through 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). In October 2010, NSTAR Electric filed a reconciliation of the cumulative CPSL program activity for the periods 2006 through 2009 with the DPU in order to determine a proposed rate adjustment. The DPU allowed the proposed rates to go into effect January 1, 2011, subject to final reconciliation of CPSL program costs through a future DPU proceeding. In February 2013, NSTAR Electric updated the October 2010 filing with final activity through 2011. NSTAR Electric recorded its 2006 through 2011 revenues under the CPSL programs based on the May 2010 Order.

NSTAR Electric cannot predict the timing of a final DPU order related to its CPSL filings for the period 2006 through 2011. While management does not believe that any subsequent DPU order would result in revenues that are 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.

G.       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. In 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. The DPU issued an order approving the implementation of a revised Basic Service rate but 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.

In 2010, NSTAR Electric filed an appeal of the DPU's order with the SJC. In 2012, the SJC vacated the DPU order and remanded the matter to the DPU for further review. The DPU has not taken any action on the remand.

NSTAR Electric deferred approximately $34 million of costs associated with energy-related bad debt as a regulatory asset through 2011 as NSTAR Electric had concluded that it was probable that these costs would ultimately be recovered from customers. Due to the delays and the duration of the proceedings, 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 related to the regulatory asset in 2012. NSTAR Electric will continue to maintain the reserve until the proceeding has been concluded with the DPU.

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ACCUMULATED OTHER COMPREHENSIVE INCOME

9 Months Ended

Sep. 30, 2014

Notes To Consolidated Financial Statements [Abstract]

Comprehensive Income Note [Text Block]

11.       ACCUMULATED OTHER COMPREHENSIVE INCOME/(LOSS)

The changes in accumulated other comprehensive income/(loss) by component, net of tax, is as follows:

	For the Nine Months Ended September 30, 2014								For the Nine Months Ended September 30, 2013
			Unrealized		Pension,						Unrealized		Pension,
	Qualified		Gains/(Losses)		SERP and				Qualified		Gains/(Losses)		SERP and
	Cash Flow		on Available-		PBOP				Cash Flow		on Available-		PBOP
	Hedging		for-Sale		Benefit				Hedging		for-Sale		Benefit
(Millions of Dollars)	Instruments		Securities		Plans		Total		Instruments		Securities		Plans		Total
AOCI as of Beginning of Period	$	(14.4)	$	0.4	$	(32.0)	$	(46.0)	$	(16.4)	$	1.3	$	(57.8)	$	(72.9)
OCI Before Reclassifications		-		0.2		1.2		1.4		-		(0.8)		-		(0.8)
Amounts Reclassified from AOCI		1.5		-		2.9		4.4		1.5		-		4.8		6.3
Net OCI		1.5		0.2		4.1		5.8		1.5		(0.8)		4.8		5.5
AOCI as of End of Period	$	(12.9)	$	0.6	$	(27.9)	$	(40.2)	$	(14.9)	$	0.5	$	(53.0)	$	(67.4)

NU's qualified cash flow hedging instruments represent interest rate swap agreements on debt issuances that were settled in prior years. The settlement amount was recorded in AOCI and is being amortized into Net Income over the term of the underlying debt instrument.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, which are not material to their respective financial statements.

The following table sets forth the amounts reclassified from AOCI by component and the impacted line item on the statements of income:

	For the Three Months Ended				For the Nine Months Ended
	September 30,				September 30,
	Amounts Reclassified				Amounts Reclassified				Statements of Income
	from AOCI				from AOCI				Line Item Impacted
(Millions of Dollars)	2014		2013		2014		2013
Qualified Cash Flow Hedging Instruments	$	(0.8)	$	(0.8)	$	(2.5)	$	(2.5)	Interest Expense
Tax Benefit		0.3		0.3		1.0		1.0	Income Tax Expense
Qualified Cash Flow Hedging Instruments, Net of Tax	$	(0.5)	$	(0.5)	$	(1.5)	$	(1.5)
Pension, SERP and PBOP Benefit Plan Costs:
Amortization of Actuarial Losses	$	(1.6)	$	(2.5)	$	(4.7)	$	(7.3)	Operations and Maintenance (1)
Amortization of Prior Service Cost		-		-		(0.1)		(0.1)	Operations and Maintenance (1)
Total Pension, SERP and PBOP Benefit Plan Costs		(1.6)		(2.5)		(4.8)		(7.4)
Tax Benefit		0.6		0.9		1.9		2.6	Income Tax Expense
Pension, SERP and PBOP Benefit Plan Costs, Net of Tax	$	(1.0)	$	(1.6)	$	(2.9)	$	(4.8)
Total Amounts Reclassified from AOCI, Net of Tax	$	(1.5)	$	(2.1)	$	(4.4)	$	(6.3)

• These amounts are included in the computation of net periodic Pension, SERP and PBOP costs. See Note 7, "Pension Benefits and Postretirement Benefits Other Than Pensions," for further information.

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SEGMENT INFORMATION (Details) (USD $)	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013	Dec. 31, 2013
Segment Reporting Information [Line Items]
Operating Revenues	$ 1,892,532,000	$ 1,892,590,000	$ 5,860,736,000	$ 5,523,475,000
Operating Income	440,910,000	399,262,000	1,202,588,000	1,168,783,000
Total Interest Expense	(89,738,000)	(87,476,000)	(272,208,000)	(250,583,000)
Other Income/(Loss), Net	11,860,000	8,945,000	19,054,000	21,655,000
Income Tax Expense	(126,539,000)	(109,351,000)	(345,858,000)	(325,442,000)
Net Income	236,493,000	211,380,000	603,576,000	614,413,000
Net Income Attributable to Noncontrolling Interests	(1,879,000)	(1,879,000)	(5,639,000)	(5,803,000)
Net Income Attributable to Controlling Interests	234,614,000	209,501,000	597,937,000	608,610,000
Total Assets	27,982,311,000		27,982,311,000		27,795,537,000
Investments in Property, Plant and Equipment			1,117,493,000	1,073,759,000
Electric Distribution Member
Segment Reporting Information [Line Items]
Operating Revenues	1,502,600,000	1,508,600,000	4,350,400,000	4,104,400,000
Depreciation And Amortization	(71,700,000)	(159,600,000)	(309,900,000)	(488,700,000)
Operating Expenses, Other	(1,141,500,000)	(1,064,100,000)	(3,343,900,000)	(2,952,400,000)
Operating Income	289,400,000	284,900,000	696,600,000	663,300,000
Total Interest Expense	(49,200,000)	(44,300,000)	(143,800,000)	(129,900,000)
Other Income/(Loss), Net	9,300,000	5,500,000	13,600,000	12,600,000
Net Income Attributable to Controlling Interests	153,400,000	156,900,000	349,100,000	347,500,000
Total Assets	16,702,300,000		16,702,300,000		17,260,000,000
Investments in Property, Plant and Equipment			480,100,000	501,900,000
Natural Gas Distribution [Member]
Segment Reporting Information [Line Items]
Operating Revenues	109,200,000	97,100,000	737,500,000	613,000,000
Depreciation And Amortization	(16,400,000)	(16,400,000)	(51,100,000)	(50,500,000)
Operating Expenses, Other	(98,400,000)	(89,400,000)	(586,200,000)	(483,600,000)
Operating Income	(5,600,000)	(8,700,000)	100,200,000	78,900,000
Total Interest Expense	(8,500,000)	(8,600,000)	(25,600,000)	(24,800,000)
Other Income/(Loss), Net	100,000	500,000	200,000	700,000
Net Income Attributable to Controlling Interests	(9,900,000)	(10,400,000)	44,200,000	34,100,000
Total Assets	2,801,100,000		2,801,100,000		2,759,700,000
Investments in Property, Plant and Equipment			120,600,000	91,200,000
Transmission [Member]
Segment Reporting Information [Line Items]
Operating Revenues	262,500,000	234,100,000	721,400,000	721,500,000
Depreciation And Amortization	(37,400,000)	(34,500,000)	(111,400,000)	(100,900,000)
Operating Expenses, Other	(74,200,000)	(73,400,000)	(211,500,000)	(199,100,000)
Operating Income	150,900,000	126,200,000	398,500,000	421,500,000
Total Interest Expense	(24,500,000)	(26,600,000)	(78,800,000)	(73,700,000)
Other Income/(Loss), Net	2,700,000	2,900,000	6,900,000	8,500,000
Net Income Attributable to Controlling Interests	88,100,000	58,600,000	206,800,000	215,400,000
Total Assets	7,404,500,000		7,404,500,000		6,745,800,000
Investments in Property, Plant and Equipment			469,900,000	458,200,000
Other Segment [Member]
Segment Reporting Information [Line Items]
Operating Revenues	211,200,000	212,500,000	568,100,000	650,400,000
Depreciation And Amortization	(13,800,000)	(11,200,000)	(28,300,000)	(52,000,000)
Operating Expenses, Other	(192,400,000)	(206,800,000)	(534,100,000)	(599,000,000)
Operating Income	5,000,000	(5,500,000)	5,700,000	(600,000)
Total Interest Expense	(8,600,000)	(9,200,000)	(27,200,000)	(26,300,000)
Other Income/(Loss), Net	226,400,000	312,100,000	657,900,000	866,200,000
Net Income Attributable to Controlling Interests	228,300,000	313,100,000	653,400,000	868,700,000
Total Assets	12,270,200,000		12,270,200,000		11,842,400,000
Investments in Property, Plant and Equipment			46,900,000	22,500,000
Eliminations Segment [Member]
Segment Reporting Information [Line Items]
Operating Revenues	(193,000,000)	(159,700,000)	(516,700,000)	(565,800,000)
Depreciation And Amortization	8,600,000	2,600,000	12,700,000	7,200,000
Operating Expenses, Other	185,600,000	159,500,000	505,600,000	564,300,000
Operating Income	1,200,000	2,400,000	1,600,000	5,700,000
Total Interest Expense	1,000,000	1,200,000	3,200,000	4,100,000
Other Income/(Loss), Net	(226,600,000)	(312,100,000)	(659,500,000)	(866,300,000)
Net Income Attributable to Controlling Interests	(225,300,000)	(308,700,000)	(655,600,000)	(857,100,000)
Total Assets	(11,195,800,000)		(11,195,800,000)		(10,812,400,000)
Investments in Property, Plant and Equipment			0	0
Total [Member]
Segment Reporting Information [Line Items]
Operating Revenues	1,892,500,000	1,892,600,000	5,860,700,000	5,523,500,000
Depreciation And Amortization	(130,700,000)	(219,100,000)	(488,000,000)	(684,900,000)
Operating Expenses, Other	(1,320,900,000)	(1,274,200,000)	(4,170,100,000)	(3,669,800,000)
Operating Income	440,900,000	399,300,000	1,202,600,000	1,168,800,000
Total Interest Expense	(89,800,000)	(87,500,000)	(272,200,000)	(250,600,000)
Other Income/(Loss), Net	11,900,000	8,900,000	19,100,000	21,700,000
Net Income Attributable to Controlling Interests	234,600,000	209,500,000	597,900,000	608,600,000
Total Assets	27,982,300,000		27,982,300,000		27,795,500,000
Investments in Property, Plant and Equipment			$ 1,117,500,000	$ 1,073,800,000

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FAIR VALUE OF FINANCIAL INSTRUMENTS (Tables)

9 Months Ended

Sep. 30, 2014

Notes To Consolidated Financial Statements [Abstract]

Fair Value By Balance Sheet Grouping Text Block

	As of September 30, 2014				As of December 31, 2013
	NU				NU
	Carrying		Fair		Carrying		Fair
(Millions of Dollars)	Amount		Value		Amount		Value
Preferred Stock Not Subject to Mandatory Redemption	$	155.6	$	151.0	$	155.6	$	152.7
Long-Term Debt		8,412.6		8,876.3		8,310.2		8,443.1

	As of September 30, 2014
	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	$	110.1	$	43.0	$	40.9	$	-	$	-	$	-	$	-
Long-Term Debt		2,841.8		3,189.5		1,797.4		1,959.4		999.2		1,046.4		628.7		667.4
	As of December 31, 2013
	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	$	110.5	$	43.0	$	42.2	$	-	$	-	$	-	$	-
Long-Term Debt		2,741.2		2,952.8		1,801.1		1,888.0		1,049.0		1,073.9		629.4		640.1

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PENSION BENEFITS AND POSTRETIREMENT BENEFITS OTHER THAN PENSIONS (Details) (USD $)	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013	Dec. 31, 2013
Defined Benefit Plan, Amounts Recognized in Balance Sheet [Abstract]
Accrued Pension, PBOP and SERP	$ 787,550,000		$ 787,550,000		$ 896,844,000
Pension Plans Defined Benefit Member
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Defined Benefit Plan Service Cost	19,100,000	25,600,000	60,700,000	76,700,000
Defined Benefit Plan Interest Cost	56,400,000	51,700,000	169,500,000	155,000,000
Defined Benefit Plan, Expected Return on Plan Assets	(77,700,000)	(69,500,000)	(233,100,000)	(208,500,000)
Defined Benefit Plan, Amortization of Gains (Losses)	31,700,000	52,400,000	96,500,000	158,100,000
Defined Benefit Plan Amortization Of Prior Service Cost Credit	1,100,000	1,100,000	3,300,000	3,000,000
Defined Benefit Plan Net Periodic Benefit Cost	30,600,000	61,300,000	96,900,000	184,300,000
Amount Capitalized Defined Benefit Expense	8,300,000	18,300,000	26,700,000	54,900,000
PBOP Plan
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Defined Benefit Plan Service Cost	3,100,000	4,200,000	9,300,000	12,600,000
Defined Benefit Plan Interest Cost	12,400,000	11,800,000	37,100,000	35,400,000
Defined Benefit Plan, Expected Return on Plan Assets	(15,800,000)	(13,900,000)	(47,400,000)	(41,600,000)
Defined Benefit Plan, Amortization of Gains (Losses)	3,000,000	6,500,000	9,100,000	19,500,000
Defined Benefit Plan Amortization Of Prior Service Cost Credit	(700,000)	(500,000)	(2,100,000)	(1,500,000)
Defined Benefit Plan Net Periodic Benefit Cost	2,000,000	8,100,000	6,000,000	24,400,000
Amount Capitalized Defined Benefit Expense	1,100,000	2,600,000	1,900,000	7,600,000
The Connecticut Light And Power Company [Member]
Defined Benefit Plan, Amounts Recognized in Balance Sheet [Abstract]
Accrued Pension, PBOP and SERP	63,756,000		63,756,000		95,895,000
The Connecticut Light And Power Company [Member] | Pension Plans Defined Benefit Member
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Defined Benefit Plan Service Cost	5,000,000	6,300,000	15,200,000	18,700,000
Defined Benefit Plan Interest Cost	12,500,000	12,100,000	38,100,000	36,300,000
Defined Benefit Plan, Expected Return on Plan Assets	(18,700,000)	(18,400,000)	(56,700,000)	(55,400,000)
Defined Benefit Plan, Amortization of Gains (Losses)	8,200,000	13,900,000	25,500,000	42,000,000
Defined Benefit Plan Amortization Of Prior Service Cost Credit	400,000	400,000	1,400,000	1,400,000
Defined Benefit Plan Net Periodic Benefit Cost	7,400,000	14,300,000	23,500,000	43,000,000
Related Intercompany Allocationsof Defined Benefit Expense	6,500,000	11,400,000	20,800,000	33,600,000
Amount Capitalized Defined Benefit Expense	4,300,000	7,000,000	13,600,000	21,000,000
The Connecticut Light And Power Company [Member] | PBOP Plan
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Defined Benefit Plan Service Cost	600,000	900,000	1,700,000	2,600,000
Defined Benefit Plan Interest Cost	2,000,000	2,000,000	6,000,000	5,900,000
Defined Benefit Plan, Expected Return on Plan Assets	(2,600,000)	(2,500,000)	(7,900,000)	(7,600,000)
Defined Benefit Plan, Amortization of Gains (Losses)	1,000,000	1,800,000	3,200,000	5,600,000
Defined Benefit Plan Amortization Of Prior Service Cost Credit			0
Defined Benefit Plan Net Periodic Benefit Cost	1,000,000	2,200,000	3,000,000	6,500,000
Related Intercompany Allocationsof Defined Benefit Expense	900,000	1,700,000	3,100,000	5,300,000
Amount Capitalized Defined Benefit Expense	500,000	1,300,000	1,500,000	3,700,000
NSTAR Electric Company [Member]
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Defined Benefit Plan Net Periodic Benefit Cost		1,200,000
Defined Benefit Plan, Amounts Recognized in Balance Sheet [Abstract]
Accrued Pension, PBOP and SERP	142,249,000		142,249,000		118,010,000
NSTAR Electric Company [Member] | Pension Plans Defined Benefit Member
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Defined Benefit Plan Service Cost	3,000,000	8,300,000	10,600,000	24,800,000
Defined Benefit Plan Interest Cost	10,300,000	14,500,000	31,000,000	43,500,000
Defined Benefit Plan, Expected Return on Plan Assets	(15,700,000)	(21,100,000)	(47,300,000)	(63,300,000)
Defined Benefit Plan, Amortization of Gains (Losses)	5,900,000	14,400,000	17,600,000	43,600,000
Defined Benefit Plan Amortization Of Prior Service Cost Credit	0	0	0	(200,000)
Defined Benefit Plan Net Periodic Benefit Cost	3,500,000	16,100,000	11,900,000	48,400,000
Related Intercompany Allocationsof Defined Benefit Expense	2,900,000	(2,100,000)	6,700,000	(6,200,000)
Amount Capitalized Defined Benefit Expense	2,600,000	9,800,000	5,500,000	21,600,000
Defined Benefit Plan, Amounts Recognized in Balance Sheet [Abstract]
Defined Benefit Plan, Funded Status of Plan		83,400,000		83,400,000	118,000,000
NSTAR Electric Company [Member] | PBOP Plan
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Defined Benefit Plan Service Cost	800,000		2,300,000
Defined Benefit Plan Interest Cost	4,900,000		14,600,000
Defined Benefit Plan, Expected Return on Plan Assets	(6,500,000)		(19,500,000)
Defined Benefit Plan, Amortization of Gains (Losses)	(100,000)		(400,000)
Defined Benefit Plan Amortization Of Prior Service Cost Credit	(500,000)		(1,400,000)
Defined Benefit Plan Net Periodic Benefit Cost	(1,400,000)	1,200,000	(4,400,000)	3,500,000
Related Intercompany Allocationsof Defined Benefit Expense	300,000		400,000
Amount Capitalized Defined Benefit Expense	(500,000)		(1,500,000)
Defined Benefit Plan, Amounts Recognized in Balance Sheet [Abstract]
Defined Benefit Plan, Funded Status of Plan	55,600,000		55,600,000
NSTAR Electric Company [Member] | Supplemental Employee Retirement Plans, Defined Benefit [Member]
Defined Benefit Plan, Amounts Recognized in Balance Sheet [Abstract]
Pension and Other Postretirement Defined Benefit Plans, Current Liabilities	(400,000)		(400,000)
Defined Benefit Plan, Funded Status of Plan	3,600,000		3,600,000
Public Service Company Of New Hampshire [Member] | Pension Plans Defined Benefit Member
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Defined Benefit Plan Service Cost	2,300,000	3,300,000	7,400,000	9,800,000
Defined Benefit Plan Interest Cost	5,700,000	5,800,000	18,000,000	17,800,000
Defined Benefit Plan, Expected Return on Plan Assets	(9,300,000)	(9,200,000)	(28,800,000)	(26,200,000)
Defined Benefit Plan, Amortization of Gains (Losses)	2,800,000	5,400,000	8,900,000	16,200,000
Defined Benefit Plan Amortization Of Prior Service Cost Credit	100,000	100,000	500,000	400,000
Defined Benefit Plan Net Periodic Benefit Cost	1,600,000	5,400,000	6,000,000	18,000,000
Related Intercompany Allocationsof Defined Benefit Expense	1,800,000	2,600,000	6,000,000	7,800,000
Amount Capitalized Defined Benefit Expense	700,000	1,700,000	2,400,000	5,600,000
Public Service Company Of New Hampshire [Member] | PBOP Plan
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Defined Benefit Plan Service Cost	300,000	600,000	1,000,000	1,700,000
Defined Benefit Plan Interest Cost	1,100,000	1,000,000	3,200,000	3,100,000
Defined Benefit Plan, Expected Return on Plan Assets	(1,400,000)	(1,300,000)	(4,100,000)	(3,900,000)
Defined Benefit Plan, Amortization of Gains (Losses)	600,000	900,000	1,700,000	2,700,000
Defined Benefit Plan Amortization Of Prior Service Cost Credit			0
Defined Benefit Plan Net Periodic Benefit Cost	600,000	1,200,000	1,800,000	3,600,000
Related Intercompany Allocationsof Defined Benefit Expense	200,000	400,000	800,000	1,200,000
Amount Capitalized Defined Benefit Expense	200,000	400,000	600,000	1,100,000
Western Massachusetts Electric Company [Member] | Pension Plans Defined Benefit Member
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Defined Benefit Plan Service Cost	800,000	1,200,000	2,700,000	3,500,000
Defined Benefit Plan Interest Cost	2,500,000	2,500,000	7,800,000	7,500,000
Defined Benefit Plan, Expected Return on Plan Assets	(4,400,000)	(4,300,000)	(13,500,000)	(13,000,000)
Defined Benefit Plan, Amortization of Gains (Losses)	1,700,000	2,900,000	5,200,000	8,900,000
Defined Benefit Plan Amortization Of Prior Service Cost Credit	100,000	100,000	300,000	300,000
Defined Benefit Plan Net Periodic Benefit Cost	700,000	2,400,000	2,500,000	7,200,000
Related Intercompany Allocationsof Defined Benefit Expense	1,200,000	2,000,000	3,900,000	6,000,000
Amount Capitalized Defined Benefit Expense	600,000	1,300,000	2,000,000	3,900,000
Western Massachusetts Electric Company [Member] | PBOP Plan
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Defined Benefit Plan Service Cost	100,000	200,000	300,000	500,000
Defined Benefit Plan Interest Cost	400,000	400,000	1,300,000	1,300,000
Defined Benefit Plan, Expected Return on Plan Assets	(600,000)	(600,000)	(1,700,000)	(1,700,000)
Defined Benefit Plan, Amortization of Gains (Losses)	100,000	300,000	300,000	800,000
Defined Benefit Plan Amortization Of Prior Service Cost Credit			0
Defined Benefit Plan Net Periodic Benefit Cost	0	300,000	200,000	900,000
Related Intercompany Allocationsof Defined Benefit Expense	200,000	300,000	600,000	1,000,000
Amount Capitalized Defined Benefit Expense	$ 0	$ 300,000	$ 100,000	$ 700,000

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SIGNIFCANT ACCOUNTING POLICIES (Policies)

9 Months Ended

Sep. 30, 2014

Notes To Consolidated Financial Statements [Abstract]

Organization Consolidation And Presentation Of Financial Statements Disclosure Text Block

A.       Basis of Presentation

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 consist of CL&P, NSTAR Electric, PSNH, WMECO, Yankee Gas and NSTAR Gas. NU provides energy delivery service to approximately 3.6 million electric and natural gas customers through these six regulated utilities in Connecticut, Massachusetts and New Hampshire.

The unaudited condensed consolidated financial statements of NU, NSTAR Electric and PSNH include the accounts of each of their respective subsidiaries. Intercompany transactions have been eliminated in consolidation. The accompanying unaudited condensed consolidated financial statements of NU, NSTAR Electric and PSNH and the unaudited condensed financial statements of CL&P and WMECO are herein collectively referred to as the"financial statements."

The combined notes to the financial statements have been prepared pursuant to the rules and regulations of the SEC. Certain information and footnote disclosures included in annual financial statements prepared in accordance with GAAP have been omitted pursuant to such rules and regulations. The accompanying financial statements should be read in conjunction with the entirety of this combined Quarterly Report on Form 10-Q, the first and second quarter 2014 combined Quarterly Reports on Form 10-Q and the 2013 combined Annual Report on Form 10-K of NU, CL&P, NSTAR Electric, PSNH and WMECO, which were filed with the SEC. The preparation of the 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 financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

The financial statements contain, in the opinion of management, all adjustments (including normal, recurring adjustments) necessary to present fairly NU's, CL&P's, NSTAR Electric's, PSNH's and WMECO's financial position as of September 30, 2014 and December 31, 2013, the results of operations and comprehensive income for the three and nine months ended September 30, 2014 and 2013, and the cash flows for the nine months ended September 30, 2014 and 2013. The results of operations and comprehensive income for the three and nine months ended September 30, 2014 and 2013, and the cash flows for the nine months ended September 30, 2014 and 2013 are not necessarily indicative of the results expected for a full year.

NU consolidates CYAPC and YAEC because CL&P's, NSTAR Electric's, PSNH's and WMECO's combined ownership interest in each of these entities is greater than 50 percent. Intercompany transactions between CL&P, NSTAR Electric, PSNH and WMECO and the CYAPC and YAEC companies have been eliminated in consolidation of the NU financial statements. For CL&P, NSTAR Electric, PSNH and WMECO, the investments in CYAPC and YAEC continue to be accounted for under the equity method.

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 2, "Regulatory Accounting," for further information.

Certain reclassifications of prior period data were made in the accompanying balance sheets for NU, CL&P, NSTAR Electric and PSNH, and in the statements of income for NU, NSTAR Electric, PSNH and WMECO. These reclassifications were made to conform to the current period presentation.

Receivables Policy Text Block

NU, including CL&P, NSTAR Electric, PSNH and WMECO, presents its receivables at estimated net realizable value by maintaining a provision for uncollectible accounts. This provision is determined based upon a variety of factors, including the application of an estimated uncollectible percentage to each receivable aging category. The estimate is based upon historical collection and write-off experience and management's assessment of collectibility from individual customers. Management continuously assesses the collectibility of receivables, and adjustscollectibility estimates based on actual experience. 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

Fair value measurement guidance is applied to derivative contracts that are not elected or designated as "normal purchases or normal sales" (normal) and to the marketable securities held in trusts. Fair value measurement guidance is also applied to investment valuations used to calculate the funded status of pension and PBOP plans and nonrecurring fair value measurements of nonfinancial assets such as goodwill and AROs, and is also used to estimate the fair value of preferred stock and long-term debt.

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.

The following methods and assumptions were used to estimate the fair value of each of the following financial instruments:

Preferred Stock and Long-Term Debt: 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 long-term debt securities 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. The fair values provided in the tables below are classified as Level 2 within the fair value hierarchy.

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 statements of income Certain sales taxes are also collected by NU's companies that serve customers in Connecticut and Massachusetts as agents for state and local governments and are recorded on a net basis with no impact on the statements of income.

Public Utilities Policy Text Block

The rates charged to the customers of NU's Regulated companies are designed to collect each company's costs to provide service, including a return on investment. Therefore, the accounting policies of the Regulated companies follow the application of accounting guidance for entities with rate-regulated operations and reflect the effects of the rate-making process.

Management believes it is probable that each of the Regulated companies will recover their respective investments in long-lived assets, including regulatory assets. If management were to determine that it could no longer apply the accounting guidance applicable to rate-regulated enterprises to any of the Regulated companies' operations, or that management could not conclude it is probable that costs would be recovered from customers in future rates, the costs would be charged to net income in the period in which the determination is made.

Derivatives Policy Text Block

4.       DERIVATIVE INSTRUMENTS

The Regulated companies purchase and procure energy and energy-related products, which are subject to price volatility, for their customers. 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 and nonderivative contracts.

Many of the derivative contracts meet the definition of, and are designated as, normal and qualify for accrual accounting under the applicable accounting guidance. The costs and benefits of derivative contracts that meet the definition of normal are recognized in Operating Expenses or Operating Revenues on the statements of income, as applicable, as electricity or natural gas is delivered.

Derivative contracts that are not designated as normal are recorded at fair value as current or long-term Derivative Assets or Derivative Liabilities on the balance sheets. For the Regulated companies, regulatory assets or regulatory liabilities are recorded to offset the fair values of derivatives, as costs are recovered from, or refunded to, customers in their respective energy supply rates. For NU's unregulated wholesale marketing contracts that expired on December 31, 2013, changes in fair values of derivatives were included in Net 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, on the balance sheets. The following tables present the gross fair values of contracts categorized by risk type and the net amount recorded as current or long-term derivative asset or liability:

Marketable Securities Policy

5.       MARKETABLE SECURITIES

NU maintains trusts to fund certain non-qualified executive benefits and WMECO maintains a spent nuclear fuel trust to fund WMECO's prior period spent nuclear fuel liability. These trusts hold marketable securities.These trusts are not subject to regulatory oversight by state or federal agencies. In addition, CYAPC and YAEC maintain legally restricted trusts, each of which holds marketable securities, for settling the decommissioning obligations of their nuclear power plants.

In accordance with applicable accounting guidance, the Company elected to record mutual funds designated as available-for-saleat fair value and certain other equity investments as trading securities, with the changes in fair values recorded in Other Income, Net on the statements of income. As of September 30, 2014, the mutual funds and equity investments were classified as Level 1 in the fair value hierarchy and totaled $58.2 million and $24.4 million, respectively. As of December 31, 2013, the mutual funds were classified as Level 1 and totaled $57.2 million. For the three months ended September 30, 2014 and 2013, net losses of $1.9 million and net gains of $3 million, respectively, were recorded in Other Income, Net. For the nine months ended September 30, 2014 and 2013, net gains of $1.9 million and $7.3 million, respectively, were recorded in Other Income, Net. Dividend income is recorded in Other Income, Net on the statements of income when dividends are declared. All other marketable securities are accounted for as available-for-sale.

Available-for-Sale Securities: The following is a summary of NU's and WMECO's available-for-sale securities. These securities are recorded at fair value and included in current and long-term Marketable Securities on the balance sheets.

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.

Earnings Per Share Policy Text Block

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 of certain share-based compensation awardsas if they were converted into common shares.

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

Presentation: NU is organized between the Electric Distribution, Electric Transmission and Natural Gas Distribution reportable 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 reportable segments represented substantially all of NU's total consolidated revenues for the three and ninemonths endedSeptember 30, 2014 and2013. 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 reportable segment includes the generation activities of PSNH and WMECO.

The remainder of NU's operations is presented as Other in the tables below and 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 expense related to the debt of NU parent, 2) the revenues and expenses of NU's service company, most of which are eliminated in consolidation, 3) the operations of CYAPC and YAEC, and 4) the results of other unregulated subsidiaries, which are not part of its core business.

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, andthe capitalized portions of pension expense.

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PROPERTY, PLANT AND ACCUMULATED DEPRECIATION (Tables)

9 Months Ended

Sep. 30, 2014

Notes To Consolidated Financial Statements [Abstract]

Schedule of Public Utility Property, Plant, and Equipment [Text Block]

		As of September 30, 2014		As of December 31, 2013
(Millions of Dollars)		NU		NU
Distribution - Electric		$	12,306.6	$	11,950.2
Distribution - Natural Gas			2,494.5		2,425.9
Transmission			6,564.2		6,412.5
Generation			1,168.6		1,152.3
Electric and Natural Gas Utility			22,533.9		21,940.9
Other (1)			541.7		508.7
Property, Plant and Equipment, Gross			23,075.6		22,449.6
Less: Accumulated Depreciation
	Electric and Natural Gas Utility		(5,687.0)		(5,387.0)
	Other		(216.3)		(196.2)
Total Accumulated Depreciation			(5,903.3)		(5,583.2)
Property, Plant and Equipment, Net			17,172.3		16,866.4
Construction Work in Progress			1,082.3		709.8
Total Property, Plant and Equipment, Net		$	18,254.6	$	17,576.2

	As of September 30, 2014								As of December 31, 2013
			NSTAR								NSTAR
(Millions of Dollars)	CL&P		Electric		PSNH		WMECO		CL&P		Electric		PSNH		WMECO
Distribution	$	5,104.8	$	4,812.4	$	1,654.5	$	774.8	$	4,930.7	$	4,694.7	$	1,608.2	$	756.6
Transmission		3,125.2		1,824.6		715.8		851.8		3,071.9		1,772.3		695.7		826.4
Generation		-		-		1,134.7		33.9		-		-		1,131.2		21.1
Property, Plant and Equipment, Gross		8,230.0		6,637.0		3,505.0		1,660.5		8,002.6		6,467.0		3,435.1		1,604.1
Less: Accumulated Depreciation		(1,908.2)		(1,726.7)		(1,069.4)		(291.8)		(1,804.1)		(1,631.3)		(1,021.8)		(271.5)
Property, Plant and Equipment, Net		6,321.8		4,910.3		2,435.6		1,368.7		6,198.5		4,835.7		2,413.3		1,332.6
Construction Work in Progress		379.0		301.4		125.0		63.7		252.8		208.2		54.3		48.5
Total Property, Plant and Equipment, Net	$	6,700.8	$	5,211.7	$	2,560.6	$	1,432.4	$	6,451.3	$	5,043.9	$	2,467.6	$	1,381.1

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MARKETABLE SECURITIES (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended																																							9 Months Ended	12 Months Ended	9 Months Ended	12 Months Ended	9 Months Ended	12 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013	Dec. 31, 2013	Sep. 30, 2014 Western Massachusetts Electric Company [Member]	Dec. 31, 2013 Western Massachusetts Electric Company [Member]	Sep. 30, 2014 Fair Value Inputs Level 1 Member	Dec. 31, 2013 Fair Value Inputs Level 1 Member	Sep. 30, 2014 Fair Value Inputs Level 1 Member Western Massachusetts Electric Company [Member]	Dec. 31, 2013 Fair Value Inputs Level 1 Member Western Massachusetts Electric Company [Member]	Sep. 30, 2014 Fair Value Inputs Level 2 [Member]	Dec. 31, 2013 Fair Value Inputs Level 2 [Member]	Sep. 30, 2014 Fair Value Inputs Level 2 [Member] Western Massachusetts Electric Company [Member]	Dec. 31, 2013 Fair Value Inputs Level 2 [Member] Western Massachusetts Electric Company [Member]	Sep. 30, 2014 US Government Debt Securities Member Fair Value Inputs Level 2 [Member]	Dec. 31, 2013 US Government Debt Securities Member Fair Value Inputs Level 2 [Member]	Sep. 30, 2014 US Government Debt Securities Member Fair Value Inputs Level 2 [Member] Western Massachusetts Electric Company [Member]	Dec. 31, 2013 US Government Debt Securities Member Fair Value Inputs Level 2 [Member] Western Massachusetts Electric Company [Member]	Sep. 30, 2014 Corporate Bond Securities Member Fair Value Inputs Level 2 [Member]	Dec. 31, 2013 Corporate Bond Securities Member Fair Value Inputs Level 2 [Member]	Sep. 30, 2014 Corporate Bond Securities Member Fair Value Inputs Level 2 [Member] Western Massachusetts Electric Company [Member]	Dec. 31, 2013 Corporate Bond Securities Member Fair Value Inputs Level 2 [Member] Western Massachusetts Electric Company [Member]	Sep. 30, 2014 Asset Backed Securities Member Fair Value Inputs Level 2 [Member]	Dec. 31, 2013 Asset Backed Securities Member Fair Value Inputs Level 2 [Member]	Sep. 30, 2014 Asset Backed Securities Member Fair Value Inputs Level 2 [Member] Western Massachusetts Electric Company [Member]	Dec. 31, 2013 Asset Backed Securities Member Fair Value Inputs Level 2 [Member] Western Massachusetts Electric Company [Member]	Sep. 30, 2014 Municipal Bonds Member Fair Value Inputs Level 2 [Member]	Dec. 31, 2013 Municipal Bonds Member Fair Value Inputs Level 2 [Member]	Sep. 30, 2014 Municipal Bonds Member Fair Value Inputs Level 2 [Member] Western Massachusetts Electric Company [Member]	Dec. 31, 2013 Municipal Bonds Member Fair Value Inputs Level 2 [Member] Western Massachusetts Electric Company [Member]	Sep. 30, 2014 Other Debt Securities Member Fair Value Inputs Level 2 [Member]	Dec. 31, 2013 Other Debt Securities Member Fair Value Inputs Level 2 [Member]	Sep. 30, 2014 Other Debt Securities Member Fair Value Inputs Level 2 [Member] Western Massachusetts Electric Company [Member]	Dec. 31, 2013 Other Debt Securities Member Fair Value Inputs Level 2 [Member] Western Massachusetts Electric Company [Member]	Sep. 30, 2014 Cash And Cash Equivalents Member Fair Value Inputs Level 1 Member	Dec. 31, 2013 Cash And Cash Equivalents Member Fair Value Inputs Level 1 Member	Sep. 30, 2014 Cash And Cash Equivalents Member Fair Value Inputs Level 1 Member Western Massachusetts Electric Company [Member]	Dec. 31, 2013 Cash And Cash Equivalents Member Fair Value Inputs Level 1 Member Western Massachusetts Electric Company [Member]	Sep. 30, 2014 Mutual Funds [Member] Fair Value Inputs Level 1 Member	Dec. 31, 2013 Mutual Funds [Member] Fair Value Inputs Level 1 Member	Sep. 30, 2014 Debt Securities	Dec. 31, 2013 Debt Securities	Sep. 30, 2014 Debt Securities Western Massachusetts Electric Company [Member]	Dec. 31, 2013 Debt Securities Western Massachusetts Electric Company [Member]	Sep. 30, 2014 Equity Securities	Dec. 31, 2013 Equity Securities
Schedule Of Available For Sale Securities [Line Items]
Fair Value Of Securities Under Fair Value Option	$ 58.2		$ 58.2		$ 57.2
Investments, Debt and Equity Securities [Abstract]
Available For Sale Securities Fair Value Disclosure																																										318.2	299.6	58.1	57.9	232.0	224.1
Available-for-sale Securities, Gross Unrealized Gains																																										7.8	2.5	0.1	0	71.1	60.5
AvailableForSaleSecuritiesGrossUnrealizedLoss																																										(0.2)	(2.1)	(0.1)	0
Available For Sale Securities Amortized Cost																																										310.6	299.2	58.1	57.9	160.9	163.6
Marketable Securities, Restricted	447.7		447.7		424.0
Available For Sale Securities Debt Maturities Fair Value Abstract
Available For Sale Securities Debt Maturities After Five Through Ten Years Fair Value	67.5		67.5			1.4
Available For Sale Securities Debt Maturities After Ten Years Fair Value	111.7		111.7			4.1
Available For Sale Securities Debt Maturities After One Year Through Five Years Fair Value	91.4		91.4			30.5
Available For Sale Securities Debt Maturities Within One Year Fair Value	47.6		47.6			22.1
Available For Sale Securities Debt Maturities Fair Value	318.2		318.2			58.1
Available For Sale Securities Debt Maturities Amortized Cost Abstract
Available For Sale Securities Debt Maturities After One Through Five Years Amortized Cost	91.0		91.0			30.7
Available For Sale Securities Debt Maturities Within One Year Amortized Cost	47.6		47.6			21.9
Available For Sale Securities Debt Maturities After Ten Years Amortized Cost	106.4		106.4			4.1
Available For Sale Securities Debt Maturities After Five Through Ten Years Amortized Cost	65.6		65.6			1.4
Available For Sale Securities Debt Maturities Amortized Cost	310.6		310.6			58.1
Fair Value Assets And Liabilities Measured On Recurring Basis Abstract
Investments Fair Value Disclosure	632.8		632.8		580.9	58.1	57.9	341.7	314.2	4.4	10.9	291.1	266.7	53.7	47.0	56.5	61.4	0	6.8	61.2	53.6	14.1	15.1	37.9	30.4	14.3	9.0	112.5	105.5	13.9	11.2	23.0	15.8	11.4	4.9	27.1	32.9	4.4	10.9	314.6	281.3
TradingSecuritiesEquity	24.4		24.4
IncreaseDecreaseInTradingSecurities	$ (1.9)	$ 3.0	$ 1.9	$ 7.3

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Provision for Uncollectible Accounts (Details) (USD $) In Millions, unless otherwise specified	Sep. 30, 2014	Dec. 31, 2013
Accounts Notes And Loans Receivable [Line Items]
Allowance For Doubtful Accounts Receivable Current	$ 181.4	$ 171.3
The Connecticut Light And Power Company [Member]
Accounts Notes And Loans Receivable [Line Items]
Allowance For Doubtful Accounts Receivable Current	85.8	82.0
NSTAR Electric Company [Member]
Accounts Notes And Loans Receivable [Line Items]
Allowance For Doubtful Accounts Receivable Current	42.3	41.7
Public Service Company Of New Hampshire [Member]
Accounts Notes And Loans Receivable [Line Items]
Allowance For Doubtful Accounts Receivable Current	7.9	7.4
Western Massachusetts Electric Company [Member]
Accounts Notes And Loans Receivable [Line Items]
Allowance For Doubtful Accounts Receivable Current	$ 11.1	$ 10.0

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CONSOLIDATED STATEMENT OF CASH FLOWS (USD $) In Thousands, unless otherwise specified	9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013
Operating Activities:
Net Income	$ 603,576	$ 614,413
Adjustments to Reconcile Net Income to Net Cash Flows Provided by Operating Activities:
Depreciation	456,224	463,635
Deferred Income Tax Expense (Benefit)	64,755	334,225
Pension, SERP and PBOP Expense	74,296	146,803
Pension and PBOP Contributions	(74,681)	(338,301)
Regulatory Over/(Under) Recoveries, Net	290,111	66,239
Amortization of Regulatory Assets/(Liabilities), Net	31,826	178,668
Amortization of Rate Reduction Bonds	0	42,581
Proceeds from DOE Damages Claim, Net	132,138
Other Noncash Income (Expense)	(17,096)	3,158
Changes in Current Assets and Liabilities:
Receivables and Unbilled Revenues, Net	(66,463)	(98,432)
Increase Decrease in Fuel, Materials and Supplies	(27,147)	(13,134)
Taxes Receivable/(Accrued)	26,533	(28,609)
Accounts Payable	(69,448)	(112,512)
Other Current Assets and Liabilities	(20,607)	(81,766)
Net Cash Flows Provided by Operating Activities	1,404,017	1,176,968
Investing Activities:
Investments in Property, Plant and Equipment	(1,117,493)	(1,073,759)
Proceeds from Sales of Marketable Securities	388,352	487,729
Purchases of Marketable Securities	(389,406)	(541,070)
Decrease In Restricted Cash	0	69,259
Other Investing Activities	(4,669)	(1,137)
Net Cash Flows Used in Investing Activities	(1,123,216)	(1,058,978)
Financing Activities:
Cash Dividends on Common Stock	(356,080)	(341,720)
Cash Dividends on Preferred Stock	(5,639)	(5,802)
Increase/(Decrease) in Short-Term Debt	6,000	(172,000)
Issuance of Long-Term Debt	650,000	1,350,000
Retirements of Long-Term Debt	(576,650)	(840,600)
Retirements of Rate Reduction Bonds	0	(82,139)
Other Financing Activities	(90)	(13,536)
Net Cash Flows Provided by/(Used in) Financing Activities	(282,459)	(105,797)
Net Increase/(Decrease) in Cash	(1,658)	12,193
Cash - Beginning of Year	43,364	45,748
Cash - End of Year	41,706	57,941
The Connecticut Light And Power Company [Member]
Operating Activities:
Net Income	200,560	219,188
Adjustments to Reconcile Net Income to Net Cash Flows Provided by Operating Activities:
Depreciation	139,598	132,356
Deferred Income Tax Expense (Benefit)	(14,400)	89,084
Pension, SERP and PBOP Expense, Net of Contributions	8,050	16,182
Regulatory Over/(Under) Recoveries, Net	62,929	24,061
Amortization of Regulatory Assets/(Liabilities), Net	62,644	11,223
Proceeds from DOE Damages Claim	68,610	0
Other Noncash Income (Expense)	(11,290)	(8,759)
Changes in Current Assets and Liabilities:
Receivables and Unbilled Revenues, Net	(87,922)	(44,523)
Taxes Receivable/(Accrued)	39,805	841
Accounts Payable	16,984	(101,949)
Other Current Assets and Liabilities	(2,575)	(29,106)
Net Cash Flows Provided by Operating Activities	482,993	308,598
Investing Activities:
Investments in Property, Plant and Equipment	(371,660)	(294,638)
Other Investing Activities	(4,539)	2,013
Net Cash Flows Used in Investing Activities	(376,199)	(292,625)
Financing Activities:
Cash Dividends on Common Stock	(128,400)	(114,000)
Cash Dividends on Preferred Stock	(4,169)	(4,169)
Increase/(Decrease) in Short-Term Debt	0	(89,000)
Issuance of Long-Term Debt	250,000	400,000
Increase/(Decrease) in Notes Payable to Affiliate	(181,900)	(62,200)
Retirements of Long-Term Debt	(150,000)	(125,000)
Capital Contributions from NU Parent	120,000
Other Financing Activities	(3,268)	(6,352)
Net Cash Flows Provided by/(Used in) Financing Activities	(97,737)	(721)
Net Increase/(Decrease) in Cash	9,057	15,252
Cash - Beginning of Year	7,237	1
Cash - End of Year	16,294	15,253
NSTAR Electric Company [Member]
Operating Activities:
Net Income	233,791	213,162
Adjustments to Reconcile Net Income to Net Cash Flows Provided by Operating Activities:
Bad Debt Expense	15,250	19,012
Depreciation	140,996	136,323
Deferred Income Tax Expense (Benefit)	(39,399)	26,358
Pension, SERP and PBOP Expense, Net of Contributions	(11,046)	(55,195)
Regulatory Over/(Under) Recoveries, Net	155,357	(11,299)
Amortization of Regulatory Assets/(Liabilities), Net	(916)	173,289
Amortization of Rate Reduction Bonds	0	15,054
Proceeds from DOE Damages Claim	30,193
Other Noncash Income (Expense)	(56,851)	(48,291)
Changes in Current Assets and Liabilities:
Receivables and Unbilled Revenues, Net	(47,770)	(80,575)
Increase Decrease in Fuel, Materials and Supplies	(20,837)	7,961
Taxes Receivable/(Accrued)	60,252	(6,345)
Accounts Payable	(40,594)	6,856
Other Current Assets and Liabilities	32,340	(19,547)
Accounts Payable Related Parties	66,758	(59,173)
Net Cash Flows Provided by Operating Activities	517,524	317,590
Investing Activities:
Investments in Property, Plant and Equipment	(309,248)	(330,635)
Decrease In Restricted Cash	0	37,899
Other Investing Activities	0	575
Net Cash Flows Used in Investing Activities	(309,248)	(292,161)
Financing Activities:
Cash Dividends on Common Stock	(253,000)	(56,000)
Cash Dividends on Preferred Stock	(1,470)	(1,633)
Increase/(Decrease) in Short-Term Debt	56,000	(120,000)
Issuance of Long-Term Debt	300,000	200,000
Retirements of Long-Term Debt	(301,650)	(1,650)
Retirements of Rate Reduction Bonds		(43,493)
Other Financing Activities	(5,137)	(878)
Net Cash Flows Provided by/(Used in) Financing Activities	(205,257)	(23,654)
Net Increase/(Decrease) in Cash	3,019	1,775
Cash - Beginning of Year	8,021	13,695
Cash - End of Year	11,040	15,470
Public Service Company Of New Hampshire [Member]
Operating Activities:
Net Income	84,955	84,543
Adjustments to Reconcile Net Income to Net Cash Flows Provided by Operating Activities:
Depreciation	73,247	68,433
Deferred Income Tax Expense (Benefit)	67,827	57,066
Pension, SERP and PBOP Expense	4,541	20,427
Pension and PBOP Contributions	(1,637)	(112,964)
Regulatory Over/(Under) Recoveries, Net	16,813	(1,346)
Amortization of Regulatory Assets/(Liabilities), Net	(17,565)	(1,745)
Amortization of Rate Reduction Bonds	0	19,748
Proceeds from DOE Damages Claim	14,453
Other Noncash Income (Expense)	7,930	7,165
Changes in Current Assets and Liabilities:
Receivables and Unbilled Revenues, Net	(7,467)	8,047
Increase Decrease in Fuel, Materials and Supplies	(17,350)	(30,456)
Taxes Receivable/(Accrued)	(24,108)	5,103
Accounts Payable	(9,297)	29,148
Other Current Assets and Liabilities	13,470	7,220
Net Cash Flows Provided by Operating Activities	205,812	160,389
Investing Activities:
Investments in Property, Plant and Equipment	(170,127)	(155,676)
Decrease In Restricted Cash	(45)	22,039
Other Investing Activities	(103)	(53)
Net Cash Flows Used in Investing Activities	(170,275)	(133,690)
Financing Activities:
Cash Dividends on Common Stock	(49,500)	(51,000)
Increase/(Decrease) in Notes Payable to Affiliate	66,800	165,200
Retirements of Long-Term Debt	(50,000)	(108,950)
Retirements of Rate Reduction Bonds	0	(29,294)
Other Financing Activities	(217)	456
Net Cash Flows Provided by/(Used in) Financing Activities	(32,917)	(23,588)
Net Increase/(Decrease) in Cash	2,620	3,111
Cash - Beginning of Year	130	2,493
Cash - End of Year	2,750	5,604
Western Massachusetts Electric Company [Member]
Operating Activities:
Net Income	39,785	50,041
Adjustments to Reconcile Net Income to Net Cash Flows Provided by Operating Activities:
Depreciation	31,144	27,707
Deferred Income Tax Expense (Benefit)	13,479	79,401
Regulatory Over/(Under) Recoveries, Net	33,630	11,685
Amortization of Regulatory Assets/(Liabilities), Net	(7,778)	(598)
Amortization of Rate Reduction Bonds	0	7,780
Proceeds from DOE Damages Claim	18,883
Other Noncash Income (Expense)	615	(544)
Changes in Current Assets and Liabilities:
Receivables and Unbilled Revenues, Net	36,075	(32,231)
Taxes Receivable/(Accrued)	(15,831)	16,412
Accounts Payable	(12,847)	20,260
Other Current Assets and Liabilities	(16,551)	(9,857)
Net Cash Flows Provided by Operating Activities	120,604	170,056
Investing Activities:
Investments in Property, Plant and Equipment	(82,546)	(127,352)
Proceeds from Sales of Marketable Securities	58,788	53,552
Purchases of Marketable Securities	(59,280)	(54,042)
Other Investing Activities	0	7,401
Net Cash Flows Used in Investing Activities	(83,038)	(120,441)
Financing Activities:
Cash Dividends on Common Stock	(49,000)	(30,000)
Increase/(Decrease) in Notes Payable to Affiliate	13,200	47,900
Retirements of Long-Term Debt		(55,000)
Retirements of Rate Reduction Bonds	0	(9,352)
Other Financing Activities	(29)	(7)
Net Cash Flows Provided by/(Used in) Financing Activities	(35,829)	(46,459)
Net Increase/(Decrease) in Cash	1,737	3,156
Cash - Beginning of Year	0	1
Cash - End of Year	$ 1,737	$ 3,157

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MARKETABLE SECURITIES

9 Months Ended

Sep. 30, 2014

Notes To Consolidated Financial Statements [Abstract]

Marketable Securities [Text Block]

5.       MARKETABLE SECURITIES

NU maintains trusts to fund certain non-qualified executive benefits and WMECO maintains a spent nuclear fuel trust to fund WMECO's prior period spent nuclear fuel liability. These trusts hold marketable securities.These trusts are not subject to regulatory oversight by state or federal agencies. In addition, CYAPC and YAEC maintain legally restricted trusts, each of which holds marketable securities, for settling the decommissioning obligations of their nuclear power plants.

In accordance with applicable accounting guidance, the Company elected to record mutual funds designated as available-for-saleat fair value and certain other equity investments as trading securities, with the changes in fair values recorded in Other Income, Net on the statements of income. As of September 30, 2014, the mutual funds and equity investments were classified as Level 1 in the fair value hierarchy and totaled $58.2 million and $24.4 million, respectively. As of December 31, 2013, the mutual funds were classified as Level 1 and totaled $57.2 million. For the three months ended September 30, 2014 and 2013, net losses of $1.9 million and net gains of $3 million, respectively, were recorded in Other Income, Net. For the nine months ended September 30, 2014 and 2013, net gains of $1.9 million and $7.3 million, respectively, were recorded in Other Income, Net. Dividend income is recorded in Other Income, Net on the statements of income when dividends are declared. All other marketable securities are accounted for as available-for-sale.

Available-for-Sale Securities: The following is a summary of NU's and WMECO's available-for-sale securities. These securities are recorded at fair value and included in current and long-term Marketable Securities on the balance sheets.

		As of September 30, 2014
				Pre-Tax		Pre-Tax
		Amortized		Unrealized		Unrealized
(Millions of Dollars)		Cost		Gains		Losses		Fair Value
NU
	Debt Securities (1)	$	310.6	$	7.8	$	(0.2)	$	318.2
	Equity Securities (1)		160.9		71.1		-		232.0
WMECO
	Debt Securities (2)		58.1		0.1		(0.1)		58.1
		As of December 31, 2013
				Pre-Tax		Pre-Tax
		Amortized		Unrealized		Unrealized
(Millions of Dollars)		Cost		Gains		Losses		Fair Value
NU
	Debt Securities (1)	$	299.2	$	2.5	$	(2.1)	$	299.6
	Equity Securities (1)		163.6		60.5		-		224.1
WMECO
	Debt Securities (2)		57.9		-		-		57.9

(1)NU's amounts include CYAPC's and YAEC's marketable securities held in nuclear decommissioning trusts of $447.7 million and $424million as of September 30, 2014 and December 31, 2013, respectively, which are legally restricted and can only be used for the costs of 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 balance sheets, with no impact on the statements of income. All of the equity securities accounted for as available-for-sale securities are held in the CYAPC and YAEC trusts.

• Unrealized gains and losses on debt securities held by WMECO are recorded in Other Long-Term Assets on the balance sheets.

Unrealized Losses and Other-than-Temporary Impairment: There have been no significant unrealized losses, other-than-temporary impairments or credit losses for NU or WMECO.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 NU's benefit trust, Other Long-Term Assets for WMECO, and offset in Other Long-Term Liabilities for CYAPC and YAEC. NU utilizes the specific identification basis method for the NU benefit trust and the average cost basis method for the WMECO 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 September 30, 2014, 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)	$	47.6	$	47.6	$	21.9	$	22.1
One to five years		91.0		91.4		30.7		30.5
Six to ten years		65.6		67.5		1.4		1.4
Greater than ten years		106.4		111.7		4.1		4.1
Total Debt Securities	$	310.6	$	318.2	$	58.1	$	58.1

(1)       Amounts in the Less than one year NU category include securities in the CYAPC and YAEC nuclear decommissioning trusts, which are restricted and are classified in long-term Marketable Securities on the balance sheets.

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				As of
(Millions of Dollars)		September 30, 2014		December 31, 2013		September 30, 2014		December 31, 2013
Level 1:
	Mutual Funds and Equities	$	314.6	$	281.3	$	-	$	-
	Money Market Funds		27.1		32.9		4.4		10.9
Total Level 1		$	341.7	$	314.2	$	4.4	$	10.9
Level 2:
	U.S. Government Issued Debt Securities (Agency and Treasury)	$	56.5	$	61.4	$	-	$	6.8
	Corporate Debt Securities		61.2		53.6		14.1		15.1
	Asset-Backed Debt Securities		37.9		30.4		14.3		9.0
	Municipal Bonds		112.5		105.5		13.9		11.2
	Other Fixed Income Securities		23.0		15.8		11.4		4.9
Total Level 2		$	291.1	$	266.7	$	53.7	$	47.0
Total Marketable Securities		$	632.8	$	580.9	$	58.1	$	57.9

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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FAIR VALUE OF FINANCIAL INSTRUMENTS (Details) (USD $)	Sep. 30, 2014	Dec. 31, 2013
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Temporary Equity, Carrying Amount, Attributable to Noncontrolling Interest	$ 155,568,000	$ 155,568,000
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	155,600,000
Other Long Term Debt	8,412,600,000	8,310,200,000
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	151,000,000	152,700,000
Other Long Term Debt	8,876,300,000	8,443,100,000
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	2,841,800,000	2,741,200,000
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	110,100,000	110,500,000
Other Long Term Debt	3,189,500,000	2,952,800,000
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
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
Other Long Term Debt	1,797,400,000	1,801,100,000
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	40,900,000	42,200,000
Other Long Term Debt	1,959,400,000	1,888,000,000
Public Service Company Of New Hampshire [Member] | Carrying Reported Amount Fair Value Disclosure [Member]
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Other Long Term Debt	999,200,000	1,049,000,000
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]
Other Long Term Debt	1,046,400,000	1,073,900,000
Western Massachusetts Electric Company [Member] | Carrying Reported Amount Fair Value Disclosure [Member]
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Other Long Term Debt	628,700,000	629,400,000
Western Massachusetts Electric Company [Member] | Estimate Of Fair Value Fair Value Disclosure [Member]
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items]
Other Long Term Debt	$ 667,400,000	$ 640,100,000

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DERIVATIVE INSTRUMENTS (Tables)

9 Months Ended

Sep. 30, 2014

Notes To Consolidated Financial Statements [Abstract]

Schedule Of Derivative Instruments In Statement Of Financial Position Fair Value Text Block

		As of September 30, 2014
		Commodity Supply and				Net Amount Recorded as
(Millions of Dollars)		Price Risk Management		Netting (1)		Derivative Asset/(Liability)
Current Derivative Assets:
Level 2:
	NU (1)	$	0.4	$	-	$	0.4
Level 3:
	NU (1)		17.4		(6.8)		10.6
	CL&P (1)		16.4		(6.8)		9.6
	NSTAR Electric		1.0		-		1.0
Long-Term Derivative Assets:
Level 3:
	NU (1)	$	96.0	$	(20.9)	$	75.1
	CL&P (1)		95.1		(20.9)		74.2
	NSTAR Electric		0.9		-		0.9
Current Derivative Liabilities:
Level 2:
	NU (1)	$	(2.4)	$	0.4	$	(2.0)
Level 3:
	NU		(88.3)		-		(88.3)
	CL&P		(86.8)		-		(86.8)
	NSTAR Electric		(1.5)		-		(1.5)
Long-Term Derivative Liabilities:
Level 3:
	NU	$	(420.9)	$	-	$	(420.9)
	CL&P		(418.1)		-		(418.1)
	NSTAR Electric		(2.8)		-		(2.8)

		As of December 31, 2013
		Commodity Supply and				Net Amount Recorded as
(Millions of Dollars)		Price Risk Management		Netting (1)		Derivative Asset/(Liability)
Current Derivative Assets:
Level 2:
	NU (1)	$	1.9	$	(0.3)	$	1.6
Level 3:
	NU (1)		18.4		(9.8)		8.6
	CL&P (1)		17.1		(9.8)		7.3
	NSTAR Electric		1.2		-		1.2
Long-Term Derivative Assets:
Level 2:
	NU	$	0.2	$	-	$	0.2
Level 3:
	NU (1)		116.2		(42.2)		74.0
	CL&P (1)		113.6		(42.2)		71.4
Current Derivative Liabilities:
Level 3:
	NU	$	(93.7)	$	-	$	(93.7)
	CL&P		(92.2)		-		(92.2)
	NSTAR Electric		(1.5)		-		(1.5)
Long-Term Derivative Liabilities:
Level 3:
	NU	$	(624.1)	$	-	$	(624.1)
	CL&P		(617.1)		-		(617.1)
	NSTAR Electric		(7.0)		-		(7.0)

Schedule Of Derivative Instruments Gain Loss In Statement Of Financial Performance Text Block

		Amounts Recognized on Derivatives
		For the Three Months Ended September 30,				For the Nine Months Ended September 30,
(Millions of Dollars)		2014		2013		2014		2013
NU
Balance Sheets:
	Regulatory Assets and Liabilities	$	(15.7)	$	0.3	$	149.9	$	48.8
Statements of Income:
	Purchased Power, Fuel and Transmission		-		0.2		-		0.9

Rollforward Of Net Derivative Asset Liabilities Valued Using Unobservable Inputs [Table Text Block]

		For the Three Months Ended September 30,				For the Nine Months Ended September 30,
		2014		2013		2014		2013
(Millions of Dollars)		NU		NU		NU		NU
Derivatives, Net:
Fair Value as of Beginning of Period		$	(430.9)	$	(788.1)	$	(635.2)	$	(878.6)
Net Realized/Unrealized Gains Included in:
	Net Income		-		1.2		-		8.3
	Regulatory Assets and Liabilities		(13.6)		0.8		147.6		49.6
Settlements			21.0		21.3		64.1		55.9
Fair Value as of End of Period		$	(423.5)	$	(764.8)	$	(423.5)	$	(764.8)

	For the Three Months Ended September 30,
	2014				2013
(Millions of Dollars)	CL&P		NSTAR Electric		CL&P		NSTAR Electric
Derivatives, Net:
Fair Value as of Beginning of Period	$	(424.6)	$	(6.3)	$	(775.8)	$	(13.1)
Net Realized/Unrealized Gains/(Losses) Included in Regulatory Assets and Liabilities		(15.0)		1.4		(1.2)		0.5
Settlements		18.5		2.5		21.7		1.0
Fair Value as of End of Period	$	(421.1)	$	(2.4)	$	(755.3)	$	(11.6)
	For the Nine Months Ended September 30,
	2014				2013
(Millions of Dollars)	CL&P		NSTAR Electric		CL&P		NSTAR Electric
Derivatives, Net:
Fair Value as of Beginning of Period	$	(630.6)	$	(7.3)	$	(866.2)	$	(14.9)
Net Realized/Unrealized Gains/(Losses) Included in Regulatory Assets and Liabilities		149.4		0.9		45.1		0.6
Settlements		60.1		4.0		65.8		2.7
Fair Value as of End of Period	$	(421.1)	$	(2.4)	$	(755.3)	$	(11.6)

Fairvalueinputsliabilitiesquantitativeinformationtabletextblock

	As of September 30, 2014							As of December 31, 2013
		Range					Period Covered		Range					Period Covered
Energy Prices:
NU	$	66	-	68	per MWh		2018 - 2020	$	49	-	77	per MWh		2018 - 2029
CL&P	$	66	-	68	per MWh		2018 - 2020	$	56	-	58	per MWh		2018 - 2029
Capacity Prices:
NU	$	7.03	-	12.98		per kW-Month	2016 - 2026	$	5.07	-	11.82		per kW-Month	2017 - 2029
CL&P	$	7.03	-	12.98		per kW-Month	2018 - 2026	$	5.07	-	10.42		per kW-Month	2017 - 2026
NSTAR Electric	$	11.00	-	11.10		per kW-Month	2016 - 2019	$	5.07	-	7.38		per kW-Month	2017 - 2019
Forward Reserve:
NU, CL&P	$	5.80	-	9.50		per kW-Month	2014 - 2024	$	3.30	-	3.30		per kW-Month	2014 - 2024
REC Prices:
NU	$	41	-	70	per REC		2014 - 2018	$	36	-	87	per REC		2014 - 2029
NSTAR Electric	$	41	-	70	per REC		2014 - 2018	$	36	-	70	per REC		2014 - 2018

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EARNINGS PER SHARE (Tables)

9 Months Ended

Sep. 30, 2014

Notes To Consolidated Financial Statements [Abstract]

Schedule Of Earnings Per Share Basic And Diluted [Table Text Block]

		For the Three Months Ended				For the Nine Months Ended
(Millions of Dollars, except share information)		September 30, 2014		September 30, 2013		September 30, 2014		September 30, 2013
Net Income Attributable to Controlling Interest		$	234.6	$	209.5	$	597.9	$	608.6
Weighted Average Common Shares Outstanding:
	Basic		316,340,691		315,291,346		315,941,904		315,191,752
	Dilutive Effect		1,214,234		926,893		1,244,586		869,379
	Diluted		317,554,925		316,218,239		317,186,490		316,061,131
Basic and Diluted EPS		$	0.74	$	0.66	$	1.89	$	1.93

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SEGMENT INFORMATION

9 Months Ended

Sep. 30, 2014

Notes To Consolidated Financial Statements [Abstract]

Segment Reporting Disclosure [Text Block]

15.SEGMENT INFORMATION

Presentation: NU is organized between the Electric Distribution, Electric Transmission and Natural Gas Distribution reportable 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 reportable segments represented substantially all of NU's total consolidated revenues for the three and ninemonths endedSeptember 30, 2014 and2013. 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 reportable segment includes the generation activities of PSNH and WMECO.

The remainder of NU's operations is presented as Other in the tables below and 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 expense related to the debt of NU parent, 2) the revenues and expenses of NU's service company, most of which are eliminated in consolidation, 3) the operations of CYAPC and YAEC, and 4) the results of other unregulated subsidiaries, which are not part of its core business.

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, andthe capitalized portions of pension expense.

NU's reportable segments are determined 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. NU's operating segments and reporting units are consistent with its reportable business segments.

NU's segment information is as follows:

	For the Three Months Ended September 30, 2014
	Electric		Natural Gas
(Millions of Dollars)	Distribution		Distribution		Transmission		Other		Eliminations		Total
Operating Revenues	$	1,502.6	$	109.2	$	262.5	$	211.2	$	(193.0)	$	1,892.5
Depreciation and Amortization		(71.7)		(16.4)		(37.4)		(13.8)		8.6		(130.7)
Other Operating Expenses		(1,141.5)		(98.4)		(74.2)		(192.4)		185.6		(1,320.9)
Operating Income/(Loss)		289.4		(5.6)		150.9		5.0		1.2		440.9
Interest Expense		(49.2)		(8.5)		(24.5)		(8.6)		1.0		(89.8)
Other Income, Net		9.3		0.1		2.7		226.4		(226.6)		11.9
Net Income Attributable to Controlling Interest	$	153.4	$	(9.9)	$	88.1	$	228.3	$	(225.3)	$	234.6
	For the Nine Months Ended September 30, 2014
	Electric		Natural Gas
(Millions of Dollars)	Distribution		Distribution		Transmission		Other		Eliminations		Total
Operating Revenues	$	4,350.4	$	737.5	$	721.4	$	568.1	$	(516.7)	$	5,860.7
Depreciation and Amortization		(309.9)		(51.1)		(111.4)		(28.3)		12.7		(488.0)
Other Operating Expenses		(3,343.9)		(586.2)		(211.5)		(534.1)		505.6		(4,170.1)
Operating Income		696.6		100.2		398.5		5.7		1.6		1,202.6
Interest Expense		(143.8)		(25.6)		(78.8)		(27.2)		3.2		(272.2)
Other Income, Net		13.6		0.2		6.9		657.9		(659.5)		19.1
Net Income Attributable to Controlling Interest	$	349.1	$	44.2	$	206.8	$	653.4	$	(655.6)	$	597.9
Cash Flows Used for Investments in Plant	$	480.1	$	120.6	$	469.9	$	46.9	$	-	$	1,117.5

	For the Three Months Ended September 30, 2013
	Electric		Natural Gas
(Millions of Dollars)	Distribution		Distribution		Transmission		Other		Eliminations		Total
Operating Revenues	$	1,508.6	$	97.1	$	234.1	$	212.5	$	(159.7)	$	1,892.6
Depreciation and Amortization		(159.6)		(16.4)		(34.5)		(11.2)		2.6		(219.1)
Other Operating Expenses		(1,064.1)		(89.4)		(73.4)		(206.8)		159.5		(1,274.2)
Operating Income/(Loss)		284.9		(8.7)		126.2		(5.5)		2.4		399.3
Interest Expense		(44.3)		(8.6)		(26.6)		(9.2)		1.2		(87.5)
Other Income, Net		5.5		0.5		2.9		312.1		(312.1)		8.9
Net Income/(Loss) Attributable to Controlling Interest	$	156.9	$	(10.4)	$	58.6	$	313.1	$	(308.7)	$	209.5
	For the Nine Months Ended September 30, 2013
	Electric		Natural Gas
(Millions of Dollars)	Distribution		Distribution		Transmission		Other		Eliminations		Total
Operating Revenues	$	4,104.4	$	613.0	$	721.5	$	650.4	$	(565.8)	$	5,523.5
Depreciation and Amortization		(488.7)		(50.5)		(100.9)		(52.0)		7.2		(684.9)
Other Operating Expenses		(2,952.4)		(483.6)		(199.1)		(599.0)		564.3		(3,669.8)
Operating Income/(Loss)		663.3		78.9		421.5		(0.6)		5.7		1,168.8
Interest Expense		(129.9)		(24.8)		(73.7)		(26.3)		4.1		(250.6)
Other Income, Net		12.6		0.7		8.5		866.2		(866.3)		21.7
Net Income Attributable to Controlling Interest	$	347.5	$	34.1	$	215.4	$	868.7	$	(857.1)	$	608.6
Cash Flows Used for Investments in Plant	$	501.9	$	91.2	$	458.2	$	22.5	$	-	$	1,073.8
The following table summarizes NU's segmented total assets:
	Electric		Natural Gas
(Millions of Dollars)	Distribution		Distribution		Transmission		Other		Eliminations		Total
As of September 30, 2014	$	16,702.3	$	2,801.1	$	7,404.5	$	12,270.2	$	(11,195.8)	$	27,982.3
As of December 31, 2013		17,260.0		2,759.7		6,745.8		11,842.4		(10,812.4)		27,795.5