________________________________________________________________________________

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

FORM 10-Q

[X]	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE      SECURITIES EXCHANGE ACT OF 1934
	For the Quarterly Period Ended March 31, 2011
	OR
[  ]	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE      SECURITIES EXCHANGE ACT OF 1934
	For the transition period from ____________ to ____________

Commission File Number	Registrant; State of Incorporation; Address; and Telephone Number	I.R.S. Employer Identification No.
1-5324	NORTHEAST UTILITIES (a Massachusetts voluntary association) One Federal Street Building 111-4 Springfield, Massachusetts 01105 Telephone:  (413) 785-5871	04-2147929
0-00404	THE CONNECTICUT LIGHT AND POWER COMPANY (a Connecticut corporation) 107 Selden Street Berlin, Connecticut 06037-1616 Telephone:  (860) 665-5000	06-0303850
1-6392	PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE (a New Hampshire corporation) Energy Park 780 North Commercial Street Manchester, New Hampshire 03101-1134 Telephone:  (603) 669-4000	02-0181050
0-7624	WESTERN MASSACHUSETTS ELECTRIC COMPANY (a Massachusetts corporation) One Federal Street Building 111-4 Springfield, Massachusetts 01105 Telephone:  (413) 785-5871	04-1961130

______________________________________________________________________________

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

Yes	No
ü

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  

Yes	No
ü

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

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

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

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

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 April 30, 2011
Northeast Utilities Common shares, $5.00 par value	176,776,656 shares
The Connecticut Light and Power Company Common stock, $10.00 par value	6,035,205 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, 301 shares, and 434,653 shares of the outstanding common stock of The Connecticut Light and Power Company, Public Service Company of New Hampshire and Western Massachusetts Electric Company, respectively.  

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:
Boulos	E.S. Boulos Company
CL&P	The Connecticut Light and Power Company
HWP	HWP Company, formerly the Holyoke Water Power Company
NGS	Northeast Generation Services Company and subsidiaries
NPT	Northern Pass Transmission LLC, a jointly owned limited liability company, held by NU Transmission Ventures, Inc. and NSTAR Transmission Ventures, Inc. on a 75 percent and 25 percent basis, respectively
NU or the Company	Northeast Utilities and subsidiaries
NU Enterprises	NU Enterprises, Inc., the parent company of Select Energy, NGS, NGS Mechanical, Inc., Select Energy Contracting, Inc. and Boulos
NUSCO	Northeast Utilities Service Company
NU parent and other companies	NU parent and other companies is comprised of NU parent, NUSCO and other subsidiaries, including HWP, RRR (a real estate subsidiary), and the non-energy-related subsidiaries of Yankee (Yankee Energy Services Company, and Yankee Energy Financial Services Company)
PSNH	Public Service Company of New Hampshire
Regulated companies	NU's Regulated companies, comprised of the electric distribution and transmission segments of CL&P, PSNH and WMECO, the generation activities of PSNH and WMECO, Yankee Gas, a natural gas local distribution company, and NPT
RRR	The Rocky River Realty Company
Select Energy	Select Energy, Inc.
WMECO	Western Massachusetts Electric Company
Yankee	Yankee Energy System, Inc.
Yankee Gas	Yankee Gas Services Company
REGULATORS:
DOE	U.S. Department of Energy
EPA	U.S. Environmental Protection Agency
DPU	Massachusetts Department of Public Utilities
DPUC	Connecticut Department of Public Utility Control
FERC	Federal Energy Regulatory Commission
MA DEP	Massachusetts Department of Environmental Protection
NHPUC	New Hampshire Public Utilities Commission
SEC	Securities and Exchange Commission

OTHER:
2010 Form 10-K	The Northeast Utilities and subsidiaries combined 2010 Annual Report on Form 10-K as filed with the SEC
2010 Healthcare Act	Patient Protection and Affordable Care Act
2010 Tax Act	Tax Relief, Unemployment Insurance Reauthorization and Job Creation Act
AFUDC	Allowance For Funds Used During Construction
AMI	Advanced metering infrastructure
ARO	Asset Retirement Obligation
C&LM	Conservation and Load Management
CSC	Connecticut Siting Council
CTA	Competitive Transition Assessment
CWIP	Construction work in progress
EIA	Energy Independence Act
EPS	Earnings Per Share
ERISA	Employee Retirement Income Security Act of 1974
ES	Default Energy Service
ESOP	Employee Stock Ownership Plan
ESPP	Employee Stock Purchase Plan
FASB	Financial Accounting Standards Board
Fitch	Fitch Ratings
FMCC	Federally Mandated Congestion Charge
FTR	Financial Transmission Rights
GAAP	Accounting principles generally accepted in the United States of America
GHG	Greenhouse Gas
GSC	Generation Service Charge
GSRP	Greater Springfield Reliability Project
GWh	Giga-watt Hours
HG&E	Holyoke Gas and Electric, a municipal department of the town 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	H.Q. Hydro Renewable Energy, Inc., a wholly-owned subsidiary of Hydro-Québec
IPP	Independent Power Producers
ISO-NE	ISO New England, Inc., the New England Independent System Operator
KV	Kilovolt
KWh	Kilowatt-Hours
LNG	Liquefied natural gas
LOC	Letter of Credit
LRS	Last resort service
MGP	Manufactured Gas Plant
Money Pool	Northeast Utilities Money Pool
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
NU supplemental benefit trust	The NU Trust Under Supplemental Executive Retirement Plan
PBO	Projected Benefit Obligation
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 segments excluding the wholesale transmission segment
ROE	Return on Equity
RRB	Rate Reduction Bond or Rate Reduction Certificate
RSUs	Restricted share units
S&P	Standard & Poor's Financial Services LLC
SBC	Systems Benefits Charge
SCRC	Stranded Cost Recovery Charge
SERP	Supplemental Executive Retirement Plan
SS	Standard service
TCAM	Transmission Cost Adjustment Mechanism
TSA	Transmission Service Agreement
UI	The United Illuminating Company
VIE	Variable interest entity
WWL Project	The construction of a 16-mile gas pipeline between Waterbury and Wallingford, Connecticut and the increase of vaporization output of Yankee Gas' LNG plant
Yankee Companies	Connecticut Yankee Atomic Power Company, Yankee Atomic Electric Company and Maine Yankee Atomic Power Company

ii

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

TABLE OF CONTENTS

	Page
PART I - FINANCIAL INFORMATION
ITEM 1 - Unaudited Condensed Consolidated Financial Statements for the Following Companies:
Northeast Utilities and Subsidiaries
Condensed Consolidated Balance Sheets (Unaudited) - March 31, 2011 and December 31, 2010	1
Condensed Consolidated Statements of Income (Unaudited) - Three Months Ended March 31, 2011 and 2010	3
Condensed Consolidated Statements of Cash Flows (Unaudited) - Three Months Ended March 31, 2011 and 2010	4
The Connecticut Light and Power Company and Subsidiaries
Condensed Consolidated Balance Sheets (Unaudited) - March 31, 2011 and December 31, 2010	5
Condensed Consolidated Statements of Income (Unaudited) - Three Months Ended March 31, 2011 and 2010	7
Condensed Consolidated Statements of Cash Flows (Unaudited) - Three Months Ended March 31, 2011 and 2010	8
Public Service Company of New Hampshire and Subsidiaries
Condensed Consolidated Balance Sheets (Unaudited) - March 31, 2011 and December 31, 2010	9
Condensed Consolidated Statements of Income (Unaudited) - Three Months Ended March 31, 2011 and 2010	11
Condensed Consolidated Statements of Cash Flows (Unaudited) - Three Months Ended March 31, 2011 and 2010	12
Western Massachusetts Electric Company and Subsidiary
Condensed Consolidated Balance Sheets (Unaudited) - March 31, 2011 and December 31, 2010	13
Condensed Consolidated Statements of Income (Unaudited) - Three Months Ended March 31, 2011 and 2010	15
Condensed Consolidated Statements of Cash Flows (Unaudited) - Three Months Ended March 31, 2011 and 2010	16
Combined Notes to Condensed Consolidated Financial Statements (Unaudited - all companies)	17
Report of Independent Registered Public Accounting Firm	39

iii

	Page
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 and Subsidiaries		56
Public Service Company of New Hampshire and Subsidiaries		59
Western Massachusetts Electric Company and Subsidiary		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

iv

This Page Intentionally Left Blank

NORTHEAST UTILITIES AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
		March 31,		December 31,
(Thousands of Dollars)		2011		2010
ASSETS
Current Assets:
Cash and Cash Equivalents	$	15,359	$	23,395
Receivables, Net		540,127		523,644
Unbilled Revenues		166,505		208,834
Taxes Receivable		86,695		89,638
Fuel, Materials and Supplies		202,561		244,043
Regulatory Assets		221,029		238,699
Marketable Securities		79,337		78,306
Prepayments and Other Current Assets		95,352		100,441
Total Current Assets		1,406,965		1,507,000
Property, Plant and Equipment, Net		9,716,414		9,567,726
Deferred Debits and Other Assets:
Regulatory Assets		2,683,788		2,756,580
Goodwill		287,591		287,591
Marketable Securities		52,854		51,201
Derivative Assets		88,554		123,242
Other Long-Term Assets		182,366		179,261
Total Deferred Debits and Other Assets		3,295,153		3,397,875
Total Assets	$	14,418,532	$	14,472,601
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

1

NORTHEAST UTILITIES AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
		March 31,		December 31,
(Thousands of Dollars)		2011		2010
LIABILITIES AND CAPITALIZATION
Current Liabilities:
Notes Payable to Banks	$	189,000	$	267,000
Long-Term Debt - Current Portion		66,286		66,286
Accounts Payable		352,606		417,285
Obligations to Third Party Suppliers		76,509		74,659
Accrued Taxes		116,226		107,067
Accrued Interest		76,852		74,740
Regulatory Liabilities		114,216		99,403
Derivative Liabilities		84,836		71,501
Other Current Liabilities		130,656		167,206
Total Current Liabilities		1,207,187		1,345,147
Rate Reduction Bonds		164,704		181,572
Deferred Credits and Other Liabilities:
Accumulated Deferred Income Taxes		1,709,012		1,636,750
Regulatory Liabilities		313,256		339,655
Derivative Liabilities		885,680		909,668
Accrued Pension		810,265		802,195
Other Long-Term Liabilities		694,672		695,915
Total Deferred Credits and Other Liabilities		4,412,885		4,384,183
Capitalization:
Long-Term Debt		4,630,724		4,632,866
Noncontrolling Interest in Consolidated Subsidiary:
Preferred Stock Not Subject to Mandatory Redemption		116,200		116,200
Equity:
Common Shareholders' Equity:
Common Shares		979,876		978,909
Capital Surplus, Paid In		1,781,419		1,777,592
Retained Earnings		1,518,099		1,452,777
Accumulated Other Comprehensive Loss		(41,267)		(43,370)
Treasury Stock		(352,792)		(354,732)
Common Shareholders' Equity		3,885,335		3,811,176
Noncontrolling Interests		1,497		1,457
Total Equity		3,886,832		3,812,633
Total Capitalization		8,633,756		8,561,699
Total Liabilities and Capitalization	$	14,418,532	$	14,472,601
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)
	Three Months Ended March 31,
(Thousands of Dollars, Except Share Information)		2011		2010
Operating Revenues	$	1,235,251	$	1,339,420
Operating Expenses:
Fuel, Purchased and Net Interchange Power		474,109		603,349
Other Operating Expenses		251,978		248,273
Maintenance		67,764		45,637
Depreciation		73,951		78,656
Amortization of Regulatory Assets/(Liabilities), Net		34,407		(8,327)
Amortization of Rate Reduction Bonds		17,282		59,570
Taxes Other Than Income Taxes		88,403		85,599
Total Operating Expenses		1,007,894		1,112,757
Operating Income		227,357		226,663
Interest Expense:
Interest on Long-Term Debt		57,399		57,270
Interest on Rate Reduction Bonds		2,578		6,690
Other Interest		(1,428)		3,302
Interest Expense		58,549		67,262
Other Income, Net		10,313		8,057
Income Before Income Tax Expense		179,121		167,458
Income Tax Expense		63,537		79,857
Net Income		115,584		87,601
Net Income Attributable to Noncontrolling Interests		1,429		1,390
Net Income Attributable to Controlling Interests	$	114,155	$	86,211
Basic and Diluted Earnings Per Common Share	$	0.64	$	0.49
Dividends Declared Per Common Share	$	0.28	$	0.26
Weighted Average Common Shares Outstanding:
Basic		177,188,207		176,349,762
Diluted		177,480,996		176,537,472
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)
		Three Months Ended March 31,
(Thousands of Dollars)		2011		2010
Operating Activities:
Net Income	$	115,584	$	87,601
Adjustments to Reconcile Net Income to Net Cash Flows
Provided by Operating Activities:
Bad Debt Expense		4,947		9,556
Depreciation		73,951		78,656
Deferred Income Taxes		52,429		33,248
Pension and PBOP Expense, Net of PBOP Contributions		28,231		23,331
Regulatory Overrecoveries, Net		44,420		6,066
Amortization of Regulatory Assets/(Liabilities), Net		34,407		(8,327)
Amortization of Rate Reduction Bonds		17,282		59,570
Derivative Assets and Liabilities		(3,651)		(2,594)
Other		(1,776)		(41,434)
Changes in Current Assets and Liabilities:
Receivables and Unbilled Revenues, Net		8,199		(7,258)
Fuel, Materials and Supplies		42,990		48,431
Taxes Receivable/Accrued		18,312		4,639
Accounts Payable		(29,278)		(46,188)
Other Current Assets and Liabilities		(33,281)		(19,594)
Net Cash Flows Provided by Operating Activities		372,766		225,703
Investing Activities:
Investments in Property, Plant and Equipment		(236,689)		(202,487)
Proceeds from Sales of Marketable Securities		38,646		21,331
Purchases of Marketable Securities		(39,230)		(21,825)
Other Investing Activities		328		(478)
Net Cash Flows Used in Investing Activities		(236,945)		(203,459)
Financing Activities:
Cash Dividends on Common Shares		(48,588)		(45,088)
Cash Dividends on Preferred Stock		(1,390)		(1,390)
Decrease in Short-Term Debt		(78,000)		-
Issuance of Long-Term Debt		-		95,000
Retirements of Rate Reduction Bonds		(16,868)		(66,569)
Other Financing Activities		989		(1,137)
Net Cash Flows Used in Financing Activities		(143,857)		(19,184)
Net (Decrease)/Increase in Cash and Cash Equivalents		(8,036)		3,060
Cash and Cash Equivalents - Beginning of Period		23,395		26,952
Cash and Cash Equivalents - End of Period	$	15,359	$	30,012
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

4

THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
		March 31,		December 31,
(Thousands of Dollars)		2011		2010
ASSETS
Current Assets:
Cash	$	3,812	$	9,762
Receivables, Net		318,905		317,530
Accounts Receivable from Affiliated Companies		825		822
Unbilled Revenues		90,141		116,392
Taxes Receivable		3,288		48,360
Regulatory Assets		156,523		157,530
Materials and Supplies		65,224		63,811
Prepayments and Other Current Assets		38,027		27,466
Total Current Assets		676,745		741,673
Property, Plant and Equipment, Net		5,644,846		5,586,504
Deferred Debits and Other Assets:
Regulatory Assets		1,684,849		1,721,416
Derivative Assets		81,085		115,870
Other Long-Term Assets		98,971		89,729
Total Deferred Debits and Other Assets		1,864,905		1,927,015
Total Assets	$	8,186,496	$	8,255,192
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

5

THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
		March 31,		December 31,
(Thousands of Dollars)		2011		2010
LIABILITIES AND CAPITALIZATION
Current Liabilities:
Notes Payable to Banks	$	10,000	$	-
Notes Payable to Affiliated Companies		25,175		6,225
Long-Term Debt - Current Portion		62,000		62,000
Accounts Payable		172,154		204,868
Accounts Payable to Affiliated Companies		53,133		53,207
Obligations to Third Party Suppliers		69,685		68,692
Accrued Taxes		100,989		92,061
Accrued Interest		33,982		42,548
Regulatory Liabilities		72,301		75,716
Derivative Liabilities		63,272		46,781
Other Current Liabilities		50,764		46,209
Total Current Liabilities		713,455		698,307
Deferred Credits and Other Liabilities:
Accumulated Deferred Income Taxes		1,106,275		1,068,344
Regulatory Liabilities		179,208		206,394
Derivative Liabilities		862,070		883,091
Accrued Pension		41,093		42,486
Other Long-Term Liabilities		317,544		321,793
Total Deferred Credits and Other Liabilities		2,506,190		2,522,108
Capitalization:
Long-Term Debt		2,521,295		2,521,102
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		1,605,604		1,605,275
Retained Earnings		666,002		734,561
Accumulated Other Comprehensive Loss		(2,602)		(2,713)
Common Stockholder's Equity		2,329,356		2,397,475
Total Capitalization		4,966,851		5,034,777
Total Liabilities and Capitalization	$	8,186,496	$	8,255,192
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

6

THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
	Three Months Ended March 31,
(Thousands of Dollars)		2011		2010
Operating Revenues	$	673,682	$	794,980
Operating Expenses:
Fuel, Purchased and Net Interchange Power		255,369		362,820
Other Operating Expenses		134,262		134,813
Maintenance		40,782		21,838
Depreciation		39,475		47,525
Amortization of Regulatory Assets, Net		19,343		1,671
Amortization of Rate Reduction Bonds		-		43,283
Taxes Other Than Income Taxes		58,468		57,531
Total Operating Expenses		547,699		669,481
Operating Income		125,983		125,499
Interest Expense:
Interest on Long-Term Debt		33,328		33,632
Interest on Rate Reduction Bonds		-		3,032
Other Interest		(3,575)		1,863
Interest Expense		29,753		38,527
Other Income, Net		4,606		4,933
Income Before Income Tax Expense		100,836		91,905
Income Tax Expense		36,499		43,493
Net Income	$	64,337	$	48,412
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

7

THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
		Three Months Ended March 31,
(Thousands of Dollars)		2011		2010
Operating Activities:
Net Income	$	64,337	$	48,412
Adjustments to Reconcile Net Income to Net Cash Flows
Provided by Operating Activities:
Bad Debt Expense		679		2,832
Depreciation		39,475		47,525
Deferred Income Taxes		28,592		18,956
Pension and PBOP Expense, Net of PBOP Contributions		6,075		3,602
Regulatory Overrecoveries/(Underrecoveries), Net		22,972		(230)
Amortization of Regulatory Assets, Net		19,343		1,671
Amortization of Rate Reduction Bonds		-		43,283
Other		(20,129)		(21,431)
Changes in Current Assets and Liabilities:
Receivables and Unbilled Revenues, Net		16,187		8,773
Materials and Supplies		(1,412)		2,706
Taxes Receivable/Accrued		57,078		340
Accounts Payable		(14,135)		(25,350)
Other Current Assets and Liabilities		(14,099)		(7,250)
Net Cash Flows Provided by Operating Activities		204,963		123,839
Investing Activities:
Investments in Property, Plant and Equipment		(106,829)		(97,725)
Decrease in NU Money Pool Lending		-		63,100
Other Investing Activities		(45)		2,275
Net Cash Flows Used in Investing Activities		(106,874)		(32,350)
Financing Activities:
Cash Dividends on Common Stock		(131,507)		(35,849)
Cash Dividends on Preferred Stock		(1,390)		(1,390)
Increase in Short-Term Debt		10,000		-
Increase in NU Money Pool Borrowings		18,950		-
Retirements of Rate Reduction Bonds		-		(50,686)
Other Financing Activities		(92)		(82)
Net Cash Flows Used in Financing Activities		(104,039)		(88,007)
Net (Decrease)/Increase in Cash		(5,950)		3,482
Cash - Beginning of Period		9,762		45
Cash - End of Period	$	3,812	$	3,527
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

8

PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
		March 31,		December 31,
(Thousands of Dollars)		2011		2010
ASSETS
Current Assets:
Cash	$	3,348	$	2,559
Receivables, Net		93,281		105,070
Accounts Receivable from Affiliated Companies		898		858
Notes Receivable from Affiliated Companies		16,100		-
Unbilled Revenues		43,005		48,691
Taxes Receivable		2,056		12,564
Fuel, Materials and Supplies		101,540		116,074
Regulatory Assets		28,594		39,215
Prepayments and Other Current Assets		19,118		20,098
Total Current Assets		307,940		345,129
Property, Plant and Equipment, Net		2,088,560		2,053,281
Deferred Debits and Other Assets:
Regulatory Assets		376,982		395,203
Other Long-Term Assets		82,901		85,508
Total Deferred Debits and Other Assets		459,883		480,711
Total Assets	$	2,856,383	$	2,879,121
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

9

PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
		March 31,		December 31,
(Thousands of Dollars)		2011		2010
LIABILITIES AND CAPITALIZATION
Current Liabilities:
Notes Payable to Banks	$	20,000	$	30,000
Notes Payable to Affiliated Companies		-		47,900
Accounts Payable		53,986		85,324
Accounts Payable to Affiliated Companies		39,439		20,007
Accrued Interest		16,055		10,231
Regulatory Liabilities		13,666		8,365
Derivative Liabilities		9,835		12,834
Other Current Liabilities		39,810		36,726
Total Current Liabilities		192,791		251,387
Rate Reduction Bonds		125,549		138,247
Deferred Credits and Other Liabilities:
Accumulated Deferred Income Taxes		325,977		314,996
Regulatory Liabilities		57,881		58,631
Accrued Pension		264,550		261,096
Other Long-Term Liabilities		92,961		91,952
Total Deferred Credits and Other Liabilities		741,369		726,675
Capitalization:
Long-Term Debt		836,392		836,365
Common Stockholder's Equity:
Common Stock		-		-
Capital Surplus, Paid In		599,729		579,577
Retained Earnings		360,228		347,471
Accumulated Other Comprehensive Income/(Loss)		325		(601)
Common Stockholder's Equity		960,282		926,447
Total Capitalization		1,796,674		1,762,812
Total Liabilities and Capitalization	$	2,856,383	$	2,879,121
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

10

PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
	Three Months Ended March 31,
(Thousands of Dollars)		2011		2010
Operating Revenues	$	269,470	$	258,568
Operating Expenses:
Fuel, Purchased and Net Interchange Power		87,132		103,771
Other Operating Expenses		56,422		63,125
Maintenance		18,704		16,002
Depreciation		17,907		15,968
Amortization of Regulatory Assets/(Liabilities), Net		15,567		(5,694)
Amortization of Rate Reduction Bonds		13,135		12,391
Taxes Other Than Income Taxes		13,667		13,079
Total Operating Expenses		222,534		218,642
Operating Income		46,936		39,926
Interest Expense:
Interest on Long-Term Debt		8,624		9,512
Interest on Rate Reduction Bonds		1,893		2,721
Other Interest		(60)		179
Interest Expense		10,457		12,412
Other Income, Net		4,459		2,412
Income Before Income Tax Expense		40,938		29,926
Income Tax Expense		13,474		14,116
Net Income	$	27,464	$	15,810
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

11

PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
		Three Months Ended March 31,
(Thousands of Dollars)		2011		2010
Operating Activities:
Net Income	$	27,464	$	15,810
Adjustments to Reconcile Net Income to Net Cash Flows
Provided by Operating Activities:
Bad Debt Expense		1,850		2,496
Depreciation		17,907		15,968
Deferred Income Taxes		3,672		8,474
Pension and PBOP Expense, Net of PBOP Contributions		5,854		6,911
Regulatory Underrecoveries, Net		(1,271)		(2,073)
Amortization of Regulatory Assets/(Liabilities), Net		15,567		(5,694)
Amortization of Rate Reduction Bonds		13,135		12,391
Other		4,140		(15,719)
Changes in Current Assets and Liabilities:
Receivables and Unbilled Revenues, Net		10,077		378
Fuel, Materials and Supplies		16,043		14,971
Taxes Receivable/Accrued		18,971		6,275
Accounts Payable		(2,160)		(1,599)
Other Current Assets and Liabilities		8,361		14,085
Net Cash Flows Provided by Operating Activities		139,610		72,674
Investing Activities:
Investments in Property, Plant and Equipment		(57,718)		(54,139)
Increase in NU Money Pool Lending		(16,100)		-
Other Investing Activities		369		(2,760)
Net Cash Flows Used in Investing Activities		(73,449)		(56,899)
Financing Activities:
Cash Dividends on Common Stock		(14,707)		(12,645)
Decrease in Short-Term Debt		(10,000)		-
Decrease in NU Money Pool Borrowings		(47,900)		(14,300)
Capital Contributions from NU Parent		20,000		23,456
Retirements of Rate Reduction Bonds		(12,697)		(11,962)
Other Financing Activities		(68)		(51)
Net Cash Flows Used in Financing Activities		(65,372)		(15,502)
Net Increase in Cash		789		273
Cash - Beginning of Period		2,559		1,974
Cash - End of Period	$	3,348	$	2,247
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

12

WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
		March 31,		December 31,
(Thousands of Dollars)		2011		2010
ASSETS
Current Assets:
Cash	$	354	$	1
Receivables, Net		41,287		37,585
Accounts Receivable from Affiliated Companies		1,009		505
Unbilled Revenues		15,285		16,578
Taxes Receivable		5		7,346
Materials and Supplies		3,717		3,664
Regulatory Assets		19,934		19,531
Marketable Securities		31,931		33,194
Prepayments and Other Current Assets		1,901		1,968
Total Current Assets		115,423		120,372
Property, Plant and Equipment, Net		850,611		817,146
Deferred Debits and Other Assets:
Regulatory Assets		195,319		207,584
Marketable Securities		25,173		23,860
Other Long-Term Assets		29,924		30,597
Total Deferred Debits and Other Assets		250,416		262,041
Total Assets	$	1,216,450	$	1,199,559
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

13

WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
		March 31,		December 31,
(Thousands of Dollars)		2011		2010
LIABILITIES AND CAPITALIZATION
Current Liabilities:
Notes Payable to Banks	$	10,000	$	-
Notes Payable to Affiliated Companies		23,400		20,400
Accounts Payable		45,748		48,344
Accounts Payable to Affiliated Companies		9,097		7,848
Accrued Interest		2,006		6,787
Regulatory Liabilities		10,514		7,959
Accumulated Deferred Income Taxes		5,324		5,902
Other Current Liabilities		12,411		9,842
Total Current Liabilities		118,500		107,082
Rate Reduction Bonds		39,155		43,325
Deferred Credits and Other Liabilities:
Accumulated Deferred Income Taxes		223,210		218,063
Regulatory Liabilities		17,265		15,048
Other Long-Term Liabilities		56,761		58,169
Total Deferred Credits and Other Liabilities		297,236		291,280
Capitalization:
Long-Term Debt		400,329		400,288
Common Stockholder's Equity:
Common Stock		10,866		10,866
Capital Surplus, Paid In		248,101		248,044
Retained Earnings		102,147		98,757
Accumulated Other Comprehensive Income/(Loss)		116		(83)
Common Stockholder's Equity		361,230		357,584
Total Capitalization		761,559		757,872
Total Liabilities and Capitalization	$	1,216,450	$	1,199,559
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

14

WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
	Three Months Ended March 31,
(Thousands of Dollars)		2011		2010
Operating Revenues	$	106,684	$	100,207
Operating Expenses:
Fuel, Purchased and Net Interchange Power		40,204		43,632
Other Operating Expenses		26,230		23,226
Maintenance		4,771		4,542
Depreciation		6,338		5,953
Amortization of Regulatory Liabilities, Net		(600)		(1,570)
Amortization of Rate Reduction Bonds		4,146		3,895
Taxes Other Than Income Taxes		4,543		4,084
Total Operating Expenses		85,632		83,762
Operating Income		21,052		16,445
Interest Expense:
Interest on Long-Term Debt		4,754		3,881
Interest on Rate Reduction Bonds		684		937
Other Interest		136		126
Interest Expense		5,574		4,944
Other Income, Net		739		604
Income Before Income Tax Expense		16,217		12,105
Income Tax Expense		6,251		6,446
Net Income	$	9,966	$	5,659
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

15

WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
		Three Months Ended March 31,
(Thousands of Dollars)		2011		2010
Operating Activities:
Net Income	$	9,966	$	5,659
Adjustments to Reconcile Net Income to Net Cash Flows
Provided by Operating Activities:
Bad Debt Expense		1,337		1,567
Depreciation		6,338		5,953
Deferred Income Taxes		4,507		2,935
Pension and PBOP Expense, Net of PBOP Contributions		1,096		565
Regulatory Overrecoveries/(Underrecoveries), Net		7,620		(2,748)
Amortization of Regulatory Liabilities, Net		(600)		(1,570)
Amortization of Rate Reduction Bonds		4,146		3,895
Other		(1,370)		(465)
Changes in Current Assets and Liabilities:
Receivables and Unbilled Revenues, Net		(2,384)		(1,768)
Materials and Supplies		(53)		(1,049)
Taxes Receivable/Accrued		10,019		(129)
Accounts Payable		(4,584)		(75)
Other Current Assets and Liabilities		(4,466)		(4,019)
Net Cash Flows Provided by Operating Activities		31,572		8,751
Investing Activities:
Investments in Property, Plant and Equipment		(33,037)		(19,111)
Proceeds from Sales of Marketable Securities		32,414		11,086
Purchases of Marketable Securities		(32,510)		(11,175)
Increase in NU Money Pool Lending		-		(5,700)
Other Investing Activities		(333)		(123)
Net Cash Flows Used in Investing Activities		(33,466)		(25,023)
Financing Activities:
Cash Dividends on Common Stock		(6,576)		(3,721)
Increase in Short-Term Debt		10,000		-
Issuance of Long-Term Debt		-		95,000
Increase/(Decrease) in NU Money Pool Borrowings		3,000		(136,100)
Retirements of Rate Reduction Bonds		(4,170)		(3,921)
Capital Contributions from NU Parent		-		66,143
Other Financing Activities		(7)		(1,129)
Net Cash Flows Provided by Financing Activities		2,247		16,272
Net Increase in Cash		353		-
Cash - Beginning of Period		1		1
Cash - End of Period	$	354	$	1
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

16

NORTHEAST UTILITIES AND SUBSIDIARIES

THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES

WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY

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.

Proposed Merger with NSTAR

On October 18, 2010, NU and NSTAR announced that each company's Board of Trustees unanimously approved a Merger Agreement (the "agreement"), under which NSTAR will become a direct wholly owned subsidiary of NU.  Shareholders of both NU and NSTAR approved the proposed merger at special meetings of shareholders held on March 4, 2011.  The transaction is structured as a merger of equals in a tax-free exchange.  The post-transaction company will provide electric and natural gas energy delivery service to approximately 3.5 million electric and natural gas customers through six regulated electric and natural gas utilities in Connecticut, Massachusetts and New Hampshire.

Under the terms of the agreement, NSTAR shareholders will receive 1.312 NU common shares for each NSTAR common share that they own (the "exchange ratio").  The exchange ratio was structured to result in a no premium merger based on the average closing share price of each company's common shares for the 20 trading days preceding the announcement.  Based on the number of NU common shares and NSTAR common shares estimated to be outstanding immediately prior to the closing of the merger, upon such closing NU shareholders will own approximately 56 percent of the post-transaction company and former NSTAR shareholders will own approximately 44 percent of the post-transaction company.  It is anticipated that NU will issue approximately 137 million common shares to the NSTAR shareholders as a result of the merger.  Subject to the conditions in the agreement, NU’s first quarterly dividend per common share declared after the completion of the merger will be increased to an amount that is equivalent, after adjusting for the exchange ratio, to NSTAR's last quarterly dividend paid prior to the closing.

At closing, NU will acquire NSTAR and, in accordance with accounting standards for business combinations, account for the transaction as an acquisition of NSTAR by NU.   

Completion of the merger is subject to various customary conditions, including, among others, receipt of all required regulatory approvals.  

B.

Presentation

Certain information and footnote disclosures normally included in annual consolidated financial statements prepared in accordance with GAAP have been omitted pursuant to the rules and regulations of the SEC.  The accompanying unaudited condensed consolidated financial statements should be read in conjunction with the entirety of this combined Quarterly Report on Form 10-Q and the combined 2010 Annual Report on Form 10-K of NU, CL&P, PSNH, and WMECO, which was filed with the SEC (NU 2010 Form 10-K).  The accompanying unaudited condensed consolidated financial statements contain, in the opinion of management, all adjustments (including normal, recurring adjustments) necessary to present fairly NU's and the above companies' financial positions as of March 31, 2011 and December 31, 2010 and the results of operations and cash flows for the three months ended March 31, 2011 and 2010.  The results of operations and cash flows for the three months ended March 31, 2011 and 2010 are not necessarily indicative of the results expected for a full year.  

The unaudited condensed consolidated financial statements of NU, CL&P, PSNH and WMECO include the accounts of all their respective subsidiaries.  Intercompany transactions have been eliminated in consolidation.  

The preparation of the unaudited condensed consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent liabilities as of the date of the unaudited condensed consolidated financial statements and the reported amounts of revenues and expenses during the reporting period.  Actual results could differ from those estimates.

As of March 31, 2011, NU, CL&P, PSNH and WMECO have adjusted the presentation of Regulatory Assets and Liabilities to reflect the current portions, and related deferred tax amounts, as current assets and liabilities on the unaudited condensed consolidated balance sheets.  Amounts as of December 31, 2010 have been reclassified to conform to the March 31, 2011 presentation.  For additional information, see Note 2, "Regulatory Accounting" to the unaudited condensed consolidated financial statements.

Certain other reclassifications of prior period data were made in the accompanying unaudited condensed consolidated statements of cash flows for all companies presented.  These reclassifications were made to conform to the current period's presentation.

NU evaluates events and transactions that occur after the balance sheet date but before financial statements are issued and recognizes in the financial statements the effects of all subsequent events that provide additional evidence about conditions that existed as of the balance sheet date and discloses but does not recognize in the financial statements subsequent events that provide evidence

17

about the conditions that arose after the balance sheet date but before the financial statements are issued.  NU did not identify any such events that required recognition or disclosure under this guidance.

C.

Restricted Cash

As of March 31, 2011, PSNH had $6.4 million of restricted cash held with a trustee related to insurance proceeds received on bondable property, which was included in Prepayments and Other Current Assets on the accompanying unaudited condensed consolidated balance sheet.  There was no restricted cash held as of December 31, 2010.  

D.

Provision for Uncollectible Accounts

NU, including CL&P, PSNH and WMECO, maintains a provision for uncollectible accounts to record receivables at an estimated net realizable value.  This provision is determined based upon a variety of factors, including applying an estimated uncollectible account percentage to each receivable aging category, based upon historical collection and write-off experience and management's assessment of collectibility from individual customers.  Management reviews at least quarterly the collectibility of the receivables, and if circumstances change, collectibility estimates are adjusted accordingly.  Receivable balances are written-off against the provision for uncollectible accounts when the accounts are terminated and these balances are deemed to be uncollectible.

The provision for uncollectible accounts, which are included in Receivables, Net on the accompanying unaudited condensed consolidated balance sheets, is as follows:

(Millions of Dollars)	As of March 31, 2011		As of December 31, 2010
NU	$	41.1	$	39.8
CL&P		16.4		17.2
PSNH		7.8		6.8
WMECO		6.9		6.0

E.

Special Deposits and Counterparty Deposits

NU, including CL&P, PSNH, and WMECO, records special deposits and counterparty deposits posted under master netting agreements as an offset to a derivative asset or liability if the related derivatives are recorded in a net position.  For further information, see Note 4, "Derivative Instruments," to the unaudited condensed consolidated financial statements.  

Special deposits paid by Select Energy to unaffiliated counterparties and brokerage firms not subject to master netting agreements totaled $20.3 million and $22.6 million as of March 31, 2011 and December 31, 2010, respectively.  These amounts are included in Prepayments and Other Current Assets on the accompanying unaudited condensed consolidated balance sheets.  There were no counterparty deposits for Select Energy as of March 31, 2011 and December 31, 2010.

NU, CL&P, PSNH and WMECO have established credit policies regarding counterparties to minimize overall credit risk.  These policies require an evaluation of potential counterparties, financial condition, collateral requirements and the use of standardized agreements that allow for the netting of positive and negative exposures associated with a single counterparty.  These evaluations result in established credit limits prior to entering into a contract.  As of March 31, 2011 and December 31, 2010, there were no counterparty deposits for these companies.

F.

Fair Value Measurements

NU, including CL&P, PSNH, and WMECO, applies fair value measurement guidance to all derivative contracts recorded at fair value and to the marketable securities held in the NU supplemental benefit trust and WMECO's spent nuclear fuel trust.  Fair value measurement guidance is also applied to investment valuations used to calculate the funded status of NU's Pension and PBOP plans and non-recurring fair value measurements of NU's non-financial assets and liabilities, such as AROs and Yankee Gas' goodwill.  

Fair Value Hierarchy:  In measuring fair value, NU uses observable market data when available and minimizes the use of unobservable inputs.  Unobservable inputs are needed to value certain derivative contracts due to complexities in the terms of the contracts.  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.  Significant unobservable inputs are used in the valuations, including items such as energy and energy-related product prices in future years for which observable prices are not yet available, future contract quantities under full-requirements or supplemental sales contracts, and market volatilities.  Items valued using these valuation techniques are

18

classified according to the lowest level for which there is at least one input that is significant to the valuation.  Therefore, an item may be classified in Level 3 even though there may be some significant inputs that are readily observable.

Determination of Fair Value:  The valuation techniques and inputs used in NU's fair value measurements are described in Note 4, "Derivative Instruments," and Note 5, "Marketable Securities," to the unaudited condensed consolidated financial statements.  There were no changes to the valuation methodologies for derivative instruments or marketable securities as of March 31, 2011 and December 31, 2010.  

G.

Revenues

Regulated Companies:  The Regulated companies’ retail revenues are based on rates approved by the state regulatory commissions.  In general, rates can only be changed through formal proceedings with the state regulatory commissions.  The Regulated companies also utilize regulatory commission-approved tracking mechanisms to recover certain costs as incurred and, for WMECO beginning in 2011, a revenue decoupling mechanism to recover a pre-established level of baseline distribution delivery service revenues of $125.6 million per year, independent of actual customer usage.  Such decoupling mechanisms separate, or decouple, KWhs delivered from actual revenues recognized in an effort to promote conservation of energy by WMECO customers.

H.

Allowance for Funds Used During Construction

AFUDC is included in the cost of the Regulated companies' utility plant and represents the cost of borrowed and equity funds used to finance construction.  The portion of AFUDC attributable to borrowed funds is recorded as a reduction of Other Interest Expense, and the AFUDC related to equity funds is recorded as Other Income, Net on the accompanying unaudited condensed consolidated statements of income.

	For the Three Months Ended
	March 31, 2011		March 31, 2010
(Millions of Dollars, except percentages)	NU		NU
AFUDC:
Borrowed Funds	$	3.2	$	1.9
Equity Funds		5.5		3.1
Total	$	8.7	$	5.0
Average AFUDC Rates		7.1%		6.5%

	For the Three Months Ended						For the Three Months Ended
	March 31, 2011						March 31, 2010
	CL&P		PSNH		WMECO		CL&P		PSNH		WMECO
AFUDC:
Borrowed Funds	$	0.8	$	2.1	$	0.1	$	0.7	$	1.2	$	-
Equity Funds		1.5		3.5		0.1		1.2		1.9		-
Total	$	2.3	$	5.6	$	0.2	$	1.9	$	3.1	$	-
Average AFUDC Rates		8.1%		6.7%		7.3%		8.0%		6.3%		0.4%

The Regulated companies' average AFUDC rate is based on a FERC-prescribed formula that produces an average rate using the cost of a company's short-term financings as well as a company's capitalization (preferred stock, long-term debt and common equity).  The average rate is applied to average eligible CWIP amounts to calculate AFUDC.  AFUDC is recorded on 100 percent of CL&P's and WMECO's CWIP for their NEEWS projects, all of which is being reserved as a regulatory liability to reflect current rate base recovery for 100 percent of the CWIP as a result of FERC-approved transmission incentives.

I.

Other Income, Net

The pre-tax components of other income/(loss) items are as follows:

	For the Three Months Ended
	March 31, 2011		March 31, 2010
(Millions of Dollars)	NU		NU
Other Income:
Investment Income	$	2.4	$	1.9
Interest Income		1.3		0.8
AFUDC - Equity Funds		5.5		3.1
EIA Incentives		0.1		1.3
Other		1.1		1.0
Total Other Income		10.4		8.1
Total Other Loss		(0.1)		-
Total Other Income, Net	$	10.3	$	8.1

19

	For the Three Months Ended
	March 31, 2011						March 31, 2010
(Millions of Dollars)	CL&P		PSNH		WMECO		CL&P		PSNH		WMECO
Other Income:
Investment Income	$	1.6	$	0.4	$	0.3	$	1.3	$	0.3	$	0.3
Interest Income		0.7		0.6		0.1		0.6		0.2		0.1
AFUDC - Equity Funds		1.5		3.5		0.1		1.2		1.9		-
EIA Incentives		0.1		-		-		1.3		-		-
Other		0.7		-		0.2		0.5		-		0.2
Total Other Income, Net	$	4.6	$	4.5	$	0.7	$	4.9	$	2.4	$	0.6

Other Income - Other includes equity in earnings, which relates to the Company's investments, including investments of CL&P, PSNH and WMECO, in the Yankee Companies and NU's investment in two regional transmission companies.  

The EIA incentives relate to incentives earned by Connecticut regulated companies from the construction of distributed generation, new large-scale generation and implementation of C&LM initiatives to reduce FMCC charges.

J.

Other Taxes

Certain excise taxes levied by state or local governments are collected by CL&P and Yankee Gas from their respective customers.  These excise taxes are shown on a gross basis with collections in revenues and payments in expenses.  Gross receipts taxes, franchise taxes and other excise taxes were included in Operating Revenues and Taxes Other Than Income Taxes on the accompanying unaudited condensed consolidated statements of income as follows:  

	For the Three Months Ended
(Millions of Dollars)	March 31, 2011		March 31, 2010
NU	$	38.7	$	34.2
CL&P		31.4		27.3

Certain sales taxes are also collected by CL&P, WMECO, and Yankee Gas from their respective customers as agents for state and local governments and are recorded on a net basis with no impact on the accompanying unaudited condensed consolidated statements of income.   

K.

Supplemental Cash Flow Information

Non-cash investing activities include capital expenditures incurred but not yet paid as follows:

(Millions of Dollars)	As of March 31, 2011		As of December 31, 2010
NU	$	91.9	$	127.9
CL&P		26.0		46.2
PSNH		25.8		35.8
WMECO		24.2		21.2

Short-term borrowings of NU, including CL&P, PSNH, and WMECO, have original maturities of three months or less.  Accordingly, borrowings and repayments are shown net on the statements of cash flows.  

2.

REGULATORY ACCOUNTING

The Regulated companies continue to be rate-regulated on a cost-of-service basis, therefore, the accounting policies of the Regulated companies conform to GAAP applicable to rate-regulated enterprises and historically reflect the effects of the rate-making process.  

Management believes it is probable that the Regulated companies will recover their respective investments in long-lived assets, including regulatory assets.  All material net regulatory assets are earning a return, except for the majority of deferred benefit cost assets, regulatory assets offsetting derivative liabilities, securitized regulatory assets and income tax regulatory assets, all of which are not in rate base.  Amortization and deferrals of regulatory assets/(liabilities) are primarily included on a net basis in Amortization of Regulatory Assets/(Liabilities), Net on the accompanying unaudited condensed consolidated statements of income.  

20

Regulatory Assets:  The components of regulatory assets are as follows:  

	As of March 31, 2011		As of December 31, 2010
(Millions of Dollars)		NU		NU
Deferred Benefit Costs	$	1,064.9	$	1,094.2
Regulatory Assets Offsetting Derivative Liabilities		854.3		859.7
Securitized Assets		154.4		171.7
Income Taxes, Net		406.2		401.5
Unrecovered Contractual Obligations		117.6		123.2
Regulatory Tracker Deferrals		50.9		70.3
Storm Cost Deferrals		57.1		60.1
Asset Retirement Obligations		46.1		45.3
Losses on Reacquired Debt		21.3		21.5
Deferred Environmental Remediation Costs		36.2		36.8
Deferred Operation and Maintenance Costs		18.6		29.5
Other Regulatory Assets		77.2		81.5
Total Regulatory Assets	$	2,904.8	$	2,995.3
Less:  Current Portion	$	221.0	$	238.7
Total Long-Term Regulatory Assets	$	2,683.8	$	2,756.6

	As of March 31, 2011						As of December 31, 2010
(Millions of Dollars)	CL&P		PSNH		WMECO		CL&P		PSNH		WMECO
Deferred Benefit Costs	$	459.1	$	148.2	$	93.4	$	471.8	$	152.6	$	96.0
Regulatory Assets Offsetting Derivative Liabilities		844.1		9.8		-		846.2		12.8		-
Securitized Assets		-		116.6		37.8		-		129.8		41.9
Income Taxes, Net		331.5		32.7		16.6		328.9		31.4		16.8
Unrecovered Contractual Obligations		93.6		-		24.0		97.9		-		25.3
Regulatory Tracker Deferrals		26.1		6.4		14.7		35.5		14.7		15.2
Storm Cost Deferrals		3.2		39.1		14.8		4.0		40.7		15.4
Asset Retirement Obligations		25.5		14.8		3.1		24.9		14.7		3.0
Losses on Reacquired Debt		11.3		8.2		0.4		11.2		8.4		0.4
Deferred Environmental Remediation Costs		-		9.7		-		-		9.7		-
Deferred Operation and Maintenance Costs		18.6		-		-		29.5		-		-
Other Regulatory Assets		28.3		20.1		10.4		29.0		19.6		13.1
Total Regulatory Assets	$	1,841.3	$	405.6	$	215.2	$	1,878.9	$	434.4	$	227.1
Less:  Current Portion	$	156.5	$	28.6	$	19.9	$	157.5	$	39.2	$	19.5
Total Long-Term Regulatory Assets	$	1,684.8	$	377.0	$	195.3	$	1,721.4	$	395.2	$	207.6

Additionally, the Regulated companies had $36.4 million ($0.6 million for CL&P, $26.9 million for PSNH, and $0.5 million for WMECO) and $37.5 million ($0.6 million for CL&P, $26.5 million for PSNH and $1.9 million for WMECO) of regulatory costs as of March 31, 2011 and December 31, 2010, respectively, which were included in Other Long-Term Assets on the accompanying unaudited condensed consolidated balance sheets.  These amounts represent incurred costs that have not yet been approved for recovery by the applicable regulatory agency.  Management believes these costs are probable of recovery in future cost-of-service regulated rates.  

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

	As of March 31, 2011		As of December 31, 2010
(Millions of Dollars)		NU		NU
Cost of Removal	$	192.9	$	194.8
Regulatory Liabilities Offsetting Derivative Assets		-		38.1
Regulatory Tracker Deferrals		117.8		95.1
AFUDC Transmission Incentive		65.8		62.1
Pension Liability - Yankee Gas Acquisition		11.9		12.5
Wholesale Transmission Overcollections		12.8		13.7
Other Regulatory Liabilities		26.3		22.8
Total Regulatory Liabilities	$	427.5	$	439.1
Less:  Current Portion	$	114.2	$	99.4
Total Long-Term Regulatory Liabilities	$	313.3	$	339.7

21

	As of March 31, 2011						As of December 31, 2010
(Millions of Dollars)	CL&P		PSNH		WMECO		CL&P		PSNH		WMECO
Cost of Removal	$	77.7	$	56.5	$	9.4	$	78.6	$	57.3	$	9.5
Regulatory Liabilities Offsetting   Derivative Assets		-		-		-		38.1		-		-
Regulatory Tracker Deferrals		84.2		11.6		7.3		79.4		6.6		4.8
AFUDC Transmission Incentive		58.0		-		7.8		56.5		-		5.6
Wholesale Transmission Overcollections		12.8		-		-		13.7		-		-
WMECO Provision For Rate Refunds		-		-		2.0		-		-		2.0
Other Regulatory Liabilities		18.8		3.5		1.3		15.8		3.1		1.1
Total Regulatory Liabilities	$	251.5	$	71.6	$	27.8	$	282.1	$	67.0	$	23.0
Less:  Current Portion	$	72.3	$	13.7	$	10.5	$	75.7	$	8.4	$	8.0
Total Long-Term Regulatory Liabilities	$	179.2	$	57.9	$	17.3	$	206.4	$	58.6	$	15.0

3.

PROPERTY, PLANT AND EQUIPMENT AND ACCUMULATED DEPRECIATION

The following tables summarize the NU, CL&P, PSNH, and WMECO investments in utility plant:

	As of March 31, 2011		As of December 31, 2010
(Millions of Dollars)	NU		NU
Distribution - Electric	$	6,274.6	$	6,197.2
Distribution - Natural Gas		1,152.0		1,126.6
Transmission		3,403.3		3,378.0
Generation		714.8		697.1
Electric and Natural Gas Utility		11,544.7		11,398.9
Other (1)		302.9		305.5
Total Property, Plant and Equipment, Gross		11,847.6		11,704.4
Less:  Accumulated Depreciation
Electric and Natural Gas Utility		(2,903.2)		(2,862.3)
Other		(119.1)		(119.9)
Total Accumulated Depreciation		(3,022.3)		(2,982.2)
Property, Plant and Equipment, Net		8,825.3		8,722.2
Construction Work in Progress		891.1		845.5
Total Property, Plant and Equipment, Net	$	9,716.4	$	9,567.7

⁽¹⁾

These assets are primarily owned by RRR ($162.8 million and $166 million) and NUSCO ($127.2 million and $126.6 million) as of March 31, 2011 and December 31, 2010, respectively, and are mainly comprised of building improvements at RRR and software and equipment at NUSCO.  

	As of March 31, 2011						As of December 31, 2010
(Millions of Dollars)	CL&P		PSNH		WMECO		CL&P		PSNH		WMECO
Distribution	$	4,239.3	$	1,386.5	$	681.9	$	4,180.7	$	1,375.4	$	673.7
Transmission		2,676.2		478.2		248.9		2,668.4		476.1		233.5
Generation		-		705.3		9.5		-		687.7		9.4
Total Property, Plant and Equipment, Gross		6,915.5		2,570.0		940.3		6,849.1		2,539.2		916.6
Less:  Accumulated Depreciation		(1,528.7)		(849.7)		(232.4)		(1,508.7)		(837.3)		(228.5)
Property, Plant and Equipment, Net		5,386.8		1,720.3		707.9		5,340.4		1,701.9		688.1
Construction Work in Progress		258.0		368.3		142.7		246.1		351.4		129.0
Total Property, Plant and Equipment, Net	$	5,644.8	$	2,088.6	$	850.6	$	5,586.5	$	2,053.3	$	817.1

22

4.

DERIVATIVE INSTRUMENTS

The costs and benefits of derivative contracts that meet the definition of and are designated as "normal purchases or normal sales" (normal) are recognized in Operating Expenses or Operating Revenues on the accompanying unaudited condensed consolidated statements of income, as applicable, as electricity or natural gas is delivered.  

Derivative contracts that are not recorded as normal under the applicable accounting guidance are recorded at fair value as current or long-term derivative assets or liabilities.  For the Regulated companies, regulatory assets or liabilities are recorded for the changes in fair values of derivatives, as these contracts are part of current regulated operating costs, or have an allowed recovery mechanism, and management believes that these costs will continue to be recovered from or refunded to customers in cost-of-service, regulated rates.  Changes in fair values of NU's remaining unregulated wholesale marketing contracts are included in Net Income.  

The Regulated companies are exposed to the volatility of the prices of energy and energy-related products in procuring energy supply for their customers.  The costs associated with supplying energy to customers are recoverable through customer rates.  The Company manages the risks associated with the price volatility of energy and energy-related products through the use of derivative contracts, many of which are accounted for as normal (for WMECO all derivative contracts are accounted for as normal) and the use of nonderivative contracts.

CL&P mitigates the risks associated with the price volatility of energy and energy-related products through the use of SS or LRS contracts, which fix the price of electricity purchased for customers for periods of time ranging from three months to three years and are accounted for as normal.  CL&P has entered into derivatives, including FTR contracts, to manage the risk of congestion costs associated with its SS and LRS contracts.  As required by regulation, CL&P has also entered into derivative and nonderivative contracts for the purchase of energy and energy-related products and contracts related to capacity.  While the risks managed by these contracts are regional congestion costs and capacity price risks that are not specific to CL&P, Connecticut's electric distribution companies, including CL&P, are required to enter into these contracts.  Management believes any costs or benefits from these contracts are recoverable from or will be refunded to CL&P's customers, and, therefore any changes in fair value are recorded as Regulatory Assets and Regulatory Liabilities on the accompanying unaudited condensed consolidated balance sheets.

WMECO mitigates the risks associated with the volatility of the prices of energy and energy-related products in procuring energy supply for its customers through the use of basic service contracts, which fix the price of electricity purchased for customers for periods of time ranging from three months to three years and are accounted for as normal.  

PSNH mitigates the risks associated with the volatility of energy prices in procuring energy supply for its customers through its generation facilities and the use of derivative contracts, including energy forward contracts and FTRs.  PSNH enters into these contracts in order to stabilize electricity prices for customers by mitigating uncertainties associated with the New England spot market.  Management believes any costs or benefits from these contracts are recoverable from or will be refunded to PSNH's customers, and, therefore any changes in fair value are recorded as Regulatory Assets and Regulatory Liabilities on the accompanying unaudited condensed consolidated balance sheets.

NU, through Yankee Gas, mitigates the risks associated with supply availability and volatility of natural gas prices through the use of storage facilities and agreements to purchase natural gas supply for customers.  The costs associated with mitigating these risks are recoverable from customers, and, therefore any changes in fair value are recorded as Regulatory Assets and Regulatory Liabilities on the accompanying unaudited condensed consolidated balance sheets.  

NU, through Select Energy, has one remaining fixed price forward sales contract to serve electrical load that is part of its remaining unregulated wholesale energy marketing portfolio.  NU mitigates the price risk associated with this contract through the use of forward purchase and sales contracts.  The contracts are accounted for at fair value, and changes in their fair values are recorded in Operating Expenses on the accompanying unaudited condensed consolidated statements of income.  

NU is also exposed to interest rate risk associated with its long-term debt.  From time to time, various subsidiaries of the Company enter into forward starting interest rate swaps, accounted for as cash flow hedges, to mitigate the risk of changes in interest rates when they expect to issue long-term debt.  NU parent has also entered into an interest rate swap on fixed rate long-term debt in order to manage the balance of its fixed and floating rate debt.  This interest rate swap is accounted for as a fair value hedge.

23

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 appropriate current and long-term portions, in the accompanying unaudited condensed consolidated balance sheets.  The following tables present the gross fair values of contracts and the net amounts recorded as current or long-term derivative assets or liabilities, by primary underlying risk exposures or purpose:

	As of March 31, 2011
	Derivatives Not Designated as Hedges
(Millions of Dollars)	Commodity and Capacity Contracts Required by Regulation		Commodity Supply and Price Risk Management		Hedging Instruments		Collateral and Netting (1)		Net Amount Recorded as Derivative Asset/(Liability)
Current Derivative Assets:
Level 2:
PSNH	$	-	$	-	$	1.5	$	-	$	1.5
WMECO		-		-		0.4		-		0.4
Other		-		-		5.1		-		5.1
Level 3:
CL&P		11.1		1.5		-		(10.9)		1.7
Other		-		2.1		-		-		2.1
Total Current Derivative Assets	$	11.1	$	3.6	$	7.0	$	(10.9)	$	10.8
Long-Term Derivative Assets:
Level 2:
Other	$	-	$	-	$	4.4	$	-	$	4.4
Level 3:
CL&P		160.5		-		-		(79.4)		81.1
Other		-		3.1		-		-		3.1
Total Long-Term Derivative Assets	$	160.5	$	3.1	$	4.4	$	(79.4)	$	88.6
Current Derivative Liabilities:
Level 2:
PSNH	$	-	$	(9.8)	$	-	$	-	$	(9.8)
Level 3:
CL&P		(63.1)		(0.2)		-		-		(63.3)
Other		-		(11.7)		-		-		(11.7)
Total Current Derivative Liabilities	$	(63.1)	$	(21.7)	$	-	$	-	$	(84.8)
Long-Term Derivative Liabilities:
Level 3:
CL&P	$	(862.1)	$	-	$	-	$	-	$	(862.1)
Other		-		(23.9)		-		0.3		(23.6)
Total Long-Term Derivative Liabilities	$	(862.1)	$	(23.9)	$	-	$	0.3	$	(885.7)

24

	As of December 31, 2010
	Derivatives Not Designated as Hedges
(Millions of Dollars)	Commodity and Capacity Contracts Required by Regulation		Commodity Supply and Price Risk Management		Hedging Instruments		Collateral and Netting (1)		Net Amount Recorded as Derivative Asset/(Liability)
Current Derivative Assets:
Level 2:
Other	$	-	$	-	$	7.7	$	-	$	7.7
Level 3:
CL&P		5.8		2.1		-		-		7.9
Other		-		1.7		-		-		1.7
Total Current Derivative Assets	$	5.8	$	3.8	$	7.7	$	-	$	17.3
Long-Term Derivative Assets:
Level 2:
Other	$	-	$	-	$	4.1	$	-	$	4.1
Level 3:
CL&P		195.9		-		-		(80.0)		115.9
Other		-		3.2		-		-		3.2
Total Long-Term Derivative Assets	$	195.9	$	3.2	$	4.1	$	(80.0)	$	123.2
Current Derivative Liabilities:
Level 2:
PSNH	$	-	$	(12.8)	$	-	$	-	$	(12.8)
Level 3:
CL&P		(54.3)		(0.2)		-		7.7		(46.8)
Other		-		(12.4)		-		0.5		(11.9)
Total Current Derivative Liabilities	$	(54.3)	$	(25.4)	$	-	$	8.2	$	(71.5)
Long-Term Derivative Liabilities:
Level 3:
CL&P	$	(883.1)	$	-	$	-	$	-	$	(883.1)
Other		-		(26.8)		-		0.2		(26.6)
Total Long-Term Derivative Liabilities	$	(883.1)	$	(26.8)	$	-	$	0.2	$	(909.7)

(1)

Amounts represent cash collateral posted under master netting agreements and derivative contracts that are netted against the gross derivative asset/liability.  See "Credit Risk" below for discussion of cash collateral posted under master netting agreements.  

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

Derivatives not designated as hedges

CL&P commodity and capacity contracts required by regulation: CL&P has capacity related contracts and shares the costs and benefits of these and similar contracts with UI.  These contracts have an expected capacity of 787 MW.  CL&P has a sharing agreement with UI which is also accounted for as a derivative, with 80 percent allocated to CL&P and 20 percent allocated to UI.  The capacity contracts have terms up to 15 years and obligate the utilities to pay/receive monthly 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 MWh of energy through 2020.

Commodity supply and price risk management:  As of March 31, 2011 and December 31, 2010, CL&P had 1.3 million and 1.8 million MWh, respectively, remaining under FTRs that extend through December 2011 and require monthly payments or receipts.  

PSNH has electricity procurement contracts with delivery dates through 2011 to purchase an aggregate amount of 0.3 million and 0.4 million MWh of power as of March 31, 2011 and December 31, 2010, respectively.  In addition, PSNH has 0.1 million and 0.3 million MWh remaining under FTRs as of March 31, 2011 and December 31, 2010, respectively, that extend through December 2011 and require monthly payments or receipts.  

As of March 31, 2011 and December 31, 2010, NU had approximately 0.1 million and 0.3 million MWh, respectively, of supply volumes remaining in its unregulated wholesale portfolio when expected sales to an agency that is comprised of municipalities are compared with contracted supply, both of which extend through 2013.

25

The following table presents the realized and unrealized gains/(losses) associated with derivative contracts not designated as hedges:

		Amount of Gain/(Loss) Recognized on Derivative Instrument
Derivatives Not Designated as Hedges	Location of Gain or Loss Recognized on Derivative	For the Three Months Ended
		March 31, 2011		March 31, 2010
(Millions of Dollars)
NU
Commodity and Capacity Contracts Required by Regulation	Regulatory Assets/Liabilities		(30.1)		(68.7)
Commodity Supply and Price Risk Management	Regulatory Assets/Liabilities		(0.3)		(21.0)
Commodity Supply and Price Risk Management	Fuel, Purchased and Net   Interchange Power		0.3		(0.2)
CL&P
Commodity and Capacity Contracts Required by Regulation	Regulatory Assets/Liabilities		(30.1)		(68.7)
Commodity Supply and Price Risk Management	Regulatory Assets/Liabilities		(1.0)		(3.0)
PSNH
Commodity Supply and Price Risk Management	Regulatory Assets/Liabilities		0.8		(17.6)

For the Regulated companies, monthly settlement amounts are recorded as receivables or payables and as Operating Revenues or Fuel, Purchased and Net Interchange Power on the accompanying unaudited condensed consolidated financial statements.  Regulatory assets/liabilities are established with no impact to Net Income.

Hedging instruments  

Interest Rate Risk Management:  To manage the balance of its fixed and floating rate debt, NU parent has a fixed to floating interest rate swap on its $263 million, fixed rate senior notes maturing on April 1, 2012.  This interest rate swap qualifies and was designated as a fair value hedge and requires semi-annual cash settlements.  The changes in fair value of the swap and the interest component of the hedged long-term debt instrument are recorded in Interest Expense on the accompanying unaudited condensed consolidated statements of income.  There was no ineffectiveness recorded for the three months ended March 31, 2011 and 2010.  The cumulative changes in fair values of the swap and the Long-Term Debt are recorded as a Derivative Asset/Liability and an adjustment to Long-Term Debt.  Interest receivable is recorded as a reduction of Interest Expense and is included in Prepayments and Other Current Assets.  

The realized and unrealized gains/(losses) related to changes in fair value of the swap and Long-Term Debt as well as pre-tax Interest Expense, recorded in Net Income, were as follows:

	For the Three Months Ended
	March 31, 2011				March 31, 2010
(Millions of Dollars)	Swap		Hedged Debt		Swap		Hedged Debt
Changes in Fair Value	$	0.4	$	(0.4)	$	3.9	$	(3.9)
Interest Recorded in Net Income		-		2.7		-		2.8

In March 2011, PSNH and WMECO entered into cash flow hedges related to a portion of their planned debt issuances.  PSNH entered into two forward starting swaps to fix U.S. dollar LIBOR swap rates of 3.73 percent on $80 million of a planned $160 million long-term debt issuance and 3.60 percent on $120 million of planned refinancing of PCRBs.  WMECO entered into a forward starting swap to fix the U.S. dollar LIBOR swap rate of 3.75 percent associated with $50 million of a planned $100 million long-term debt issuance.  The cash flow hedges are expected to be settled in 2011.  Cash flow hedges are recorded at fair value, and the changes in the fair value of the effective portion of those contracts are recognized in Accumulated Other Comprehensive Income (AOCI).  Cash flow hedges impact Net Income when hedge ineffectiveness is measured and recorded, when the forecasted transaction being hedged is improbable of occurring or when the transaction is settled.  When a cash flow hedge is terminated, the settlement amount is recorded in AOCI and is amortized into Net Income over the term of the underlying debt instrument.  

The pre-tax impact of cash flow hedging instruments on AOCI is as follows:  

Derivatives in Cash Flow Hedging Relationships	Amount of Gain Recognized in AOCI on Derivative Instruments as of March 31, 2011		Amounts Reclassified from AOCI into Interest Expense for the Three Months Ended (1)
			March 31, 2011		March 31, 2010
NU	$	1.9	$	(0.1)	$	(0.1)
CL&P		-		(0.2)		(0.2)
PSNH		1.5		-		-
WMECO		0.4		-		-

⁽¹⁾

Amounts that were reclassified from AOCI for the periods ended March 31, 2011 and 2010, relate to interest rate swap agreements that have been previously settled.  

For further information, see Note 9, "Comprehensive Income," to the unaudited condensed consolidated financial statements.

26

Credit Risk

Certain derivative contracts that are accounted for at fair value, including PSNH's electricity procurement contracts and NU's sourcing contracts related to the remaining wholesale marketing contract, contain credit risk contingent features.  These features require these companies to maintain investment grade credit ratings from the major rating agencies and to post cash or standby LOCs as collateral for contracts in a net liability position over specified credit limits.  NU parent provides standby LOCs under its revolving credit agreement for NU subsidiaries to post with counterparties.  The following summarizes the fair value of derivative contracts that are in a liability position and subject to credit risk contingent features, the fair value of cash collateral and standby LOCs posted with counterparties and the additional collateral in the form of LOCs that would be required to be posted by NU or PSNH if the respective unsecured debt credit ratings of NU parent or PSNH were downgraded to below investment grade as of March 31, 2011 and December 31, 2010:

	As of March 31, 2011
(Million of Dollars)	Fair Value Subject to Credit Risk Contingent Features		Cash Collateral Posted		Standby LOCs Posted		Additional Standby LOCs Required if Downgraded Below Investment Grade
NU	$	(28.1)	$	-	$	14.0	$	18.0
PSNH		(9.8)		-		14.0		-

	As of December 31, 2010
(Million of Dollars)	Fair Value Subject to Credit Risk Contingent Features		Cash Collateral Posted		Standby LOCs Posted		Additional Standby LOCs Required if Downgraded Below Investment Grade
NU	$	(30.9)	$	0.5	$	24.0	$	18.5
PSNH		(12.8)		-		24.0		-

For further information, see Note 1E, "Summary of Significant Accounting Policies - Special Deposits and Counterparty Deposits," to the unaudited condensed consolidated financial statements.   

Fair Value Measurements of Derivative Instruments:  

Valuation of Derivative Instruments:  Derivative contracts classified as Level 2 in the fair value hierarchy include Commodity Supply and Price Risk Management contracts and Interest Rate Risk Management contracts.  Commodity Supply and Price Risk Management contracts include PSNH forward contracts to purchase energy for periods for which prices are quoted in an active market.  Prices are obtained from broker quotes and based on actual market activity.  The contracts are valued using the mid-point of the bid-ask spread.  Valuations of these contracts also incorporate discount rates using the yield curve approach.  Interest Rate Risk Management contracts represent interest rate swap agreements and are valued using a market approach provided by the swap counterparty using a discounted cash flow approach utilizing forward interest rate curves.

The derivative contracts classified as Level 3 in the tables below include the Regulated companies' Commodity and Capacity Contracts Required by Regulation, and Commodity Supply and Price Risk Management contracts (CL&P and PSNH FTRs and NU's remaining wholesale marketing portfolio).  For Commodity and Capacity Contracts Required by Regulation and NU's remaining unregulated wholesale marketing portfolio, fair value is modeled using income techniques such as discounted cash flow approaches adjusted for assumptions relating to exit price.  Significant observable inputs for valuations of these contracts include energy and energy-related product prices for which quoted prices in an active market exist.  Significant unobservable inputs used in the valuations of these contracts include energy and energy-related product prices for future years for long-dated derivative contracts and future contract quantities.  Discounted cash flow valuations incorporate estimates of premiums or discounts that would be required by a market participant to arrive at an exit price, using available historical market transaction information.  Valuations of derivative contracts include assumptions regarding the timing and likelihood of scheduled payments and also reflect nonperformance 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.  

The remaining contracts included in Commodity Supply and Price Risk Management and classified as Level 3 in the tables below are valued using broker quotes based on prices in an inactive market.

27

Valuations using significant unobservable inputs:  The following tables present changes for the three months ended March 31, 2011 and 2010 in the Level 3 category of derivative assets and derivative liabilities measured at fair value on a recurring basis.  The derivative assets and liabilities are presented on a net basis.  The Company classifies assets and liabilities in Level 3 of the fair value hierarchy when there is reliance on at least one significant unobservable input to the valuation model.  In addition to these unobservable inputs, the valuation models for Level 3 assets and liabilities typically also rely on a number of inputs that are observable either directly or indirectly.  Thus the gains and losses presented below include changes in fair value that are attributable to both observable and unobservable inputs.  There were no transfers into or out of Level 3 assets and liabilities for the three months ended March 31, 2011:

	For the Three Months Ended March 31, 2011
	NU
(Millions of Dollars)	Commodity and Capacity Contracts Required By Regulation		Commodity Supply and Price Risk Management		Total Level 3
Derivatives, Net:
Fair Value as of Beginning of Period	$	(808.0)	$	(32.2)	$	(840.2)
Net Realized/Unrealized Gains/(Losses) Included in:
Net Income (1)		-		0.3		0.3
Regulatory Assets/Liabilities		(30.1)		(1.1)		(31.2)
Settlements		(5.8)		4.2		(1.6)
Fair Value as of End of Period	$	(843.9)	$	(28.8)	$	(872.7)
Period Change in Unrealized Gains Included in  Net Income Relating to Items Held as of End of Period	$	-	$	0.4	$	0.4

	For the Three Months Ended March 31, 2011
	CL&P
(Millions of Dollars)	Commodity and Capacity Contracts Required By Regulation		Commodity Supply and Price Risk Management		Total Level 3
Derivatives, Net:
Fair Value as of Beginning of Period	$	(808.0)	$	1.9	$	(806.1)
Net Realized/Unrealized Losses Included in:
Regulatory Assets/Liabilities		(30.1)		(1.0)		(31.1)
Settlements		(5.8)		0.4		(5.4)
Fair Value as of End of Period	$	(843.9)	$	1.3	$	(842.6)

	For the Three Months Ended March 31, 2010
	NU
(Millions of Dollars)	Commodity and Capacity Contracts Required By Regulation		Commodity Supply and Price Risk Management		Total Level 3
Derivatives, Net:
Fair Value as of Beginning of Period	$	(720.3)	$	(40.9)	$	(761.2)
Net Realized/Unrealized Losses Included in:
Net Income (1)		-		(0.2)		(0.2)
Regulatory Assets/Liabilities		(68.7)		(3.6)		(72.3)
Settlements		(3.9)		3.7		(0.2)
Fair Value as of End of Period	$	(792.9)	$	(41.0)	$	(833.9)
Period Change in Unrealized Losses Included in  Net Income Relating to Items Held as of End of Period	$	-	$	(0.6)	$	(0.6)

28

	For the Three Months Ended March 31, 2010
	CL&P						PSNH
(Millions of Dollars)	Commodity and Capacity Contracts Required By Regulation		Commodity Supply and Price Risk Management		Total Level 3		Commodity Supply and Price Risk Management
Derivatives, Net:
Fair Value as of Beginning of Period	$	(720.3)	$	4.5	$	(715.8)	$	0.4
Net Realized/Unrealized Losses Included in:
Regulatory Assets/Liabilities		(68.7)		(3.0)		(71.7)		(0.2)
Settlements		(3.9)		0.9		(3.0)		(0.2)
Fair Value as of End of Period	$	(792.9)	$	2.4	$	(790.5)	$	-

⁽¹⁾

Realized and unrealized gains and losses on derivatives included in Net Income relate to NU's remaining wholesale marketing contracts and are reported in Fuel, Purchased and Net Interchange Power on the accompanying unaudited condensed consolidated statements of income.  

5.

MARKETABLE SECURITIES (NU, WMECO)

The Company elected to record mutual funds purchased in the NU supplemental benefit trust at fair value in order to reflect the economic effect of changes in fair value of all newly purchased equity securities in Net Income.  These equity securities, classified as Level 1 in the fair value hierarchy, totaled $44.1 million and $42.2 million as of March 31, 2011 and December 31, 2010, respectively, and are included in current Marketable Securities.  Gains on these securities of $1.9 million and $1.7 million for the three months ended March 31, 2011 and 2010, respectively, were recorded in Other Income, Net on the accompanying unaudited condensed consolidated statements of income.  Dividend income is recorded when dividends are declared and are recorded in Other Income, Net on the accompanying unaudited condensed consolidated statements of income.  All other marketable securities are accounted for as available-for-sale.  

Available-for-Sale Securities:  The following is a summary by security type of NU's available-for-sale securities held in the NU supplemental benefit trust and WMECO's spent nuclear fuel trust.  These securities are recorded at fair value and included in current and long-term portions of Marketable Securities on the accompanying unaudited condensed consolidated balance sheets.

	As of March 31, 2011
(Millions of Dollars)	Amortized Cost		Pre-Tax Unrealized Gains (1)		Pre-Tax Unrealized Losses (1)		Fair Value
NU Supplemental Benefit Trust
U.S. Government Issued Debt Securities   (Agency and Treasury)	$	11.3	$	0.2	$	(0.1)	$	11.4
Corporate Debt Securities		6.9		0.4		-		7.3
Asset Backed Debt Securities		6.6		0.3		-		6.9
Municipal Bonds		0.6		-		-		0.6
Money Market Funds and Other		4.5		0.3		-		4.8
Total NU Supplemental Benefit Trust	$	29.9	$	1.2	$	(0.1)	$	31.0

WMECO Spent Nuclear Fuel Trust
Corporate Debt Securities	$	8.3	$	-	$	-	$	8.3
Asset Backed Debt Securities		4.6		-		(0.1)		4.5
Municipal Bonds		19.9		-		-		19.9
Money Market Funds and Other		24.4		-		-		24.4
Total WMECO Spent Nuclear Fuel Trust	$	57.2	$	-	$	(0.1)	$	57.1
Total NU	$	87.1	$	1.2	$	(0.2)	$	88.1

29

	As of December 31, 2010
(Millions of Dollars)	Amortized Cost		Pre-Tax Unrealized Gains (1)		Pre-Tax Unrealized Losses (1)		Fair Value
NU Supplemental Benefit Trust
U.S. Government Issued Debt Securities   (Agency and Treasury)	$	11.7	$	0.2	$	(0.1)	$	11.8
Corporate Debt Securities		6.5		0.5		(0.1)		6.9
Asset Backed Debt Securities		6.5		0.4		-		6.9
Municipal Bonds		0.7		-		-		0.7
Money Market Funds and Other		3.7		0.2		-		3.9
Total NU Supplemental Benefit Trust	$	29.1	$	1.3	$	(0.2)	$	30.2

WMECO Spent Nuclear Fuel Trust
U.S. Government Issued Debt Securities   (Agency and Treasury)	$	6.0	$	-	$	-	$	6.0
Corporate Debt Securities		15.6		-		-		15.6
Asset Backed Debt Securities		4.8		-		(0.1)		4.7
Municipal Bonds		15.4		-		-		15.4
Money Market Funds and Other		15.4		-		-		15.4
Total WMECO Spent Nuclear Fuel Trust	$	57.2	$	-	$	(0.1)	$	57.1
Total NU	$	86.3	$	1.3	$	(0.3)	$	87.3

⁽¹⁾

Unrealized gains and losses on debt securities for the NU supplemental benefit trust and WMECO spent nuclear fuel trust are recorded in Accumulated Other Comprehensive Income/(Loss) and Other Long-Term Assets, respectively, on the accompanying unaudited condensed consolidated balance sheets.  For information related to the change in unrealized gains and losses for the NU supplemental benefit trust included in Accumulated Other Comprehensive Income/(Loss), see Note 9, "Comprehensive Income," to the unaudited condensed consolidated financial statements.

Unrealized Losses and Other-than-Temporary Impairment:  There have not been significant unrealized losses, other-than-temporary impairments or credit losses for the NU supplemental benefit trust or WMECO spent nuclear fuel trust.  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 securities, underlying collateral and expected future cash flows are also evaluated.  All but one of the corporate and asset backed securities held in the NU supplemental benefit trust are rated investment grade.  All but one of the securities in the WMECO spent nuclear fuel trust are rated investment grade and credit losses have been recorded for those securities that are below investment grade.  

Contractual Maturities:  As of March 31, 2011, the contractual maturities of available-for-sale debt securities are as follows:

		NU			WMECO
(Millions of Dollars)		Amortized Cost		Fair Value		Amortized Cost		Fair Value
Less than one year	$	35.2	$	35.2	$	32.0	$	31.9
One to five years		12.4		12.6		6.2		6.2
Six to ten years		7.3		7.7		2.0		2.0
Greater than ten years		32.2		32.6		17.0		17.0
Total Debt Securities	$	87.1	$	88.1	$	57.2	$	57.1

Sales of Securities:  Gross realized gains and losses recognized on the sale of available-for-sale securities are as follows:

	For the Three Months Ended
	March 31, 2011				March 31, 2010
(Millions of Dollars)		Gross Realized Gains		Gross Realized Losses		Gross Realized Gains		Gross Realized Losses
NU	$	-	$	(0.1)	$	0.1	$	-

Realized gains and losses on available-for-sale-securities are recorded in Other Income, Net for the NU supplemental benefit trust and in Other Long-Term Assets for the WMECO spent nuclear fuel trust.  NU utilizes the specific identification basis method for the NU supplemental benefit trust securities and the average cost basis method for the WMECO spent nuclear fuel trust to compute the realized gains and losses on the sale of available-for-sale securities.  

30

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
(Millions of Dollars)	As of March 31, 2011		As of December 31, 2010		As of March 31, 2011		As of December 31, 2010
Level 1:
Mutual Funds	$	44.1	$	42.2	$	-	$	-
Money Market Funds		2.3		1.8		0.2		0.3
Total Level 1	$	46.4	$	44.0	$	0.2	$	0.3
Level 2:
U.S. Government Issued Debt Securities       (Agency and Treasury)		11.4		17.8		-		6.0
Corporate Debt Securities		15.6		22.5		8.3		15.6
Asset Backed Debt Securities		11.4		11.6		4.5		4.7
Municipal Bonds		20.5		16.1		19.9		15.4
Other Fixed Income Securities		26.9		17.5		24.2		15.1
Total Level 2	$	85.8	$	85.5	$	56.9	$	56.8
Total Marketable Securities	$	132.2	$	129.5	$	57.1	$	57.1

U.S. Government issued debt securities are valued using market approaches that incorporate transactions for the same or similar bonds and adjustments for yields and maturity dates.  Corporate debt securities are valued using a market approach, utilizing recent trades of the same or similar instrument and also incorporating yield curves, credit spreads and specific bond terms and conditions.  Municipal bonds are valued using a market approach that incorporates reported trades and benchmark yields.  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.  Other fixed income securities are valued using pricing models, quoted prices of securities with similar characteristics, and discounted cash flows.

Not included in the tables above are $0.1 million and $0.6 million of cash equivalents as of March 31, 2011 and December 31, 2010, respectively, held by NU in an unrestricted money market account and included in Cash and Cash Equivalents on the accompanying unaudited condensed consolidated balance sheets of NU, which are classified as Level 1 in the fair value hierarchy.

6.

PENSION BENEFITS AND POSTRETIREMENT BENEFITS OTHER THAN PENSIONS

NUSCO sponsors a Pension Plan, which is subject to the provisions of ERISA.  The Pension Plan covers nonbargaining unit employees (and bargaining unit employees, as negotiated) of NU, including CL&P, PSNH, and WMECO, hired before 2006 (or as negotiated, for bargaining unit employees).  In addition, NU maintains a SERP, which provides benefits to eligible participants who are officers of NU.  This plan provides benefits that would have been provided to these employees under the Pension Plan if certain Internal Revenue Code limitations were not imposed.  On behalf of NU's retirees, NUSCO also sponsors plans that provide certain retiree health care benefits, primarily medical and dental, and life insurance benefits through a PBOP Plan.  

The components of net periodic benefit expense, the portion of pension amounts capitalized related to employees working on capital projects, and intercompany allocations not included in the net periodic benefit expense amounts for the Pension Plan (including the SERP), and PBOP Plan are as follows:

	For the Three Months Ended March 31, 2011
	Pension								PBOP
(Millions of Dollars)	NU		CL&P		PSNH		WMECO		NU		CL&P		PSNH		WMECO
Service Cost	$	13.7	$	4.8	$	2.6	$	1.0	$	2.4	$	0.7	$	0.5	$	0.1
Interest Cost		38.2		13.1		6.2		2.7		6.4		2.5		1.2		0.6
Expected Return on Plan Assets		(43.1)		(19.2)		(5.3)		(4.4)		(5.4)		(2.1)		(1.1)		(0.5)
Actuarial Loss		21.0		8.4		2.6		1.7		4.5		1.7		0.7		0.3
Prior Service Cost/(Credit)		2.4		1.0		0.5		0.2		(0.1)		-		-		-
Net Transition Obligation Cost		-		-		-		-		2.9		1.5		0.6		0.3
Total - Net Periodic Expense	$	32.2	$	8.1	$	6.6	$	1.2	$	10.7	$	4.3	$	1.9	$	0.8
Related Intercompany   Allocations		N/A	$	8.3	$	2.0	$	1.6		N/A	$	2.1	$	0.4	$	0.5
Amount Capitalized	$	7.6	$	4.5	$	1.8	$	0.7	$	-	$	-	$	-	$	-

31

	For the Three Months Ended March 31, 2010
	Pension								PBOP
(Millions of Dollars)	NU		CL&P		PSNH		WMECO		NU		CL&P		PSNH		WMECO
Service Cost	$	13.2	$	4.5	$	2.5	$	0.9	$	2.2	$	0.7	$	0.5	$	0.2
Interest Cost		38.0		13.0		6.1		2.7		6.7		2.6		1.2		0.6
Expected Return on Plan Assets		(45.6)		(21.5)		(3.5)		(4.9)		(5.4)		(2.1)		(1.1)		(0.5)
Actuarial Loss		12.8		5.1		1.8		1.1		4.0		1.5		0.7		0.2
Prior Service Cost/(Credit)		2.5		1.0		0.4		0.2		(0.1)		-		-		-
Net Transition Obligation Cost		-		-		-		-		2.9		1.5		0.6		0.3
Total - Net Periodic Expense	$	20.9	$	2.1	$	7.3	$	-	$	10.3	$	4.2	$	1.9	$	0.8
Related Intercompany   Allocations		N/A	$	6.1	$	1.4	$	1.1		N/A	$	1.9	$	0.5	$	0.3
Amount Capitalized	$	4.4	$	1.7	$	2.0	$	0.2	$	-	$	-	$	-	$	-

Contributions: Currently NU's policy is to annually fund the Pension Plan in an amount at least equal to an amount that will satisfy the requirements of ERISA and the Internal Revenue Code.  Due to the underfunded balance as of January 1, 2010, NU is required to make an additional contribution to the Pension Plan of approximately $145 million in 2011, which will be made in quarterly installments beginning in April 2011, to meet current minimum funding requirements.    

7.

COMMITMENTS AND CONTINGENCIES

A.

Environmental Matters

General:  NU, CL&P, 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, 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 environmental reserve as of March 31, 2011 and December 31, 2010 related to sites in the remediation or long-term monitoring phase is as follows:

	As of March 31, 2011			As of December 31, 2010
	Number of Sites		Reserve	Number of Sites		Reserve
			(in millions)			(in millions)
NU	33	$	28.7	33	$	30.3
CL&P	6		0.9	6		0.8
PSNH	12		8.8	12		8.8
WMECO	8		0.2	8		0.2

The majority of the accrual for sites in remediation or long-term monitoring relate to MGP sites that were operated several decades ago and produced manufacturing gas from coal, which resulted in certain byproducts in the environment that may pose a risk to human health and the environment.  

HWP:  HWP, a subsidiary of NU, continues to investigate the potential need for additional remediation at a river site in Massachusetts containing tar deposits associated with an MGP site that HWP sold to HG&E, a municipal utility, in 1902.  HWP shares responsibility for site remediation with HG&E and has conducted substantial investigative and remediation activities.  The cumulative expense recorded to the reserve for this site since 1994 through March 31, 2011 was $19.5 million, of which $16.7 million had been spent, leaving $2.8 million in the reserve as of March 31, 2011.  For the three months ended March 31, 2010, a pre-tax charge of $1 million was recorded to reflect estimated costs associated with the site.  HWP's share of the costs related to this site is not recoverable from customers.

The $2.8 million reserve balance as of March 31, 2011 represents estimated costs that HWP considers probable over the remaining life of the project, including testing and related costs in the near term and field activities to be agreed upon with the MA DEP, further studies and long-term monitoring that are expected to be required by the MA DEP, and certain soft tar remediation activities.  Various factors could affect management's estimates and require an increase to the reserve, which would be reflected as a charge to Net Income.  Although a material increase to the reserve is not presently anticipated, management cannot reasonably estimate potential additional investigation or remediation costs because these costs would depend on, among other things, the nature, extent and timing of additional investigation and remediation that may be required by the MA DEP.    

B.

Guarantees and Indemnifications

NU parent provides credit assurances on behalf of its subsidiaries, including CL&P, PSNH and WMECO, in the form of guarantees and LOCs in the normal course of business.  

NU issued a guaranty for the benefit of Hydro Renewable Energy under which, beginning at the time the Northern Pass Transmission line goes into commercial operation, NU will guarantee the financial obligations of NPT under the TSA in an amount not to exceed $18.8 million.  NU's obligations under the guaranty expire upon the full, final and indefeasible payment of the guaranteed obligations.  NU also provided guarantees and various indemnifications on behalf of external parties as a result of the sales of former subsidiaries of

32

NU Enterprises, with maximum exposures either not specified or not material.  Management does not anticipate a material impact to Net Income to result from these various guarantees and indemnifications.  

The following table summarizes NU's guarantees of its subsidiaries, including CL&P, PSNH, and WMECO, as of March 31, 2011:  

Subsidiary	Description	Maximum Exposure (in millions)		Expiration Dates
Various	Surety Bonds and Performance Guarantees	$ 17.5		2011-2015 (1)
PSNH and Select Energy	Letters of Credit	$ 26.1		October 2011 - November 2011
RRR and NUSCO	Lease Payments for Real Estate and Vehicles	$ 21.2		2019-2024
NU Enterprises	Surety Bonds, Insurance Bonds and Performance Guarantees	$ 113.8	(2)	(2)

(1)

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

(2)

The maximum exposure includes $58.3 million related to performance guarantees on Select Energy's wholesale purchase contracts, which expire in 2013 assuming purchase contracts guaranteed have no value; however, actual exposures vary with underlying commodity prices.  The maximum exposure also includes $15.7 million related to a performance guarantee of NGS obligations for which no maximum exposure is specified in the agreement.  The maximum exposure was calculated as of March 31, 2011 based on limits of NGS's liability contained in the underlying service contract and assumes that NGS will perform under that contract through its expiration in 2020.  Also included in the maximum exposure is $1.2 million related to insurance bonds at NGS with no expiration date that are billed annually on their anniversary date.  The remaining $38.6 million of maximum exposure relates to surety bonds covering ongoing projects at Boulos, which expire upon project completion.

CL&P, PSNH and WMECO do not guarantee the performance of third parties.  

Many of the underlying contracts that NU parent guarantees, as well as certain surety bonds, contain credit ratings triggers that would require NU parent to post collateral in the event that the unsecured debt credit ratings of NU are downgraded below investment grade.  

8.

FAIR VALUE OF FINANCIAL INSTRUMENTS

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

Preferred Stock, Long-Term Debt and Rate Reduction Bonds:  The fair value of CL&P's preferred stock is based upon pricing models that incorporate interest rates and other market factors, valuations or trades of similar securities and cash flow projections.  The fair value of fixed-rate long-term debt securities and RRBs is based upon pricing models that incorporate quoted market prices for those issues or similar issues adjusted for market conditions, credit ratings of the respective companies and treasury benchmark yields.  Adjustable rate securities are assumed to have a fair value equal to their carrying value.  Carrying amounts and estimated fair values are as follows:

	As of March 31, 2011
	NU				CL&P				PSNH				WMECO
(Millions of Dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value		Carrying Amount		Fair Value		Carrying Amount		Fair Value
Preferred Stock Not  Subject to Mandatory   Redemption	$	116.2	$	93.5	$	116.2	$	93.5	$	-	$	-	$	-	$	-
Long-Term Debt -
First Mortgage Bonds		2,703.4		2,949.8		1,919.8		2,105.0		430.0		460.1		-		-
Other Long-Term Debt		1,989.1		2,028.1		667.8		661.1		407.3		403.3		401.0		418.8
Rate Reduction Bonds		164.7		175.2		-		-		125.5		133.4		39.2		41.8

33

	As of December 31, 2010
	NU				CL&P				PSNH				WMECO
(Millions of Dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value		Carrying Amount		Fair Value		Carrying Amount		Fair Value
Preferred Stock Not  Subject to Mandatory   Redemption	$	116.2	$	93.7	$	116.2	$	93.7	$	-	$	-	$	-	$	-
Long-Term Debt -
First Mortgage Bonds		2,703.4		2,998.7		1,919.8		2,148.3		430.0		462.8		-		-
Other Long-Term Debt		1,989.0		2,045.1		667.7		668.4		407.3		408.6		401.0		417.0
Rate Reduction Bonds		181.6		193.3		-		-		138.2		146.9		43.3		46.4

Derivative Instruments:  NU, including CL&P and PSNH, holds various derivative instruments that are carried at fair value.  For further information, see Note 4, "Derivative Instruments," to the unaudited condensed consolidated financial statements.  

Other Financial Instruments:  Investments in marketable securities are carried at fair value on the accompanying unaudited condensed consolidated balance sheets.  For further information, see Note 1F, "Summary of Significant Accounting Policies - Fair Value Measurements," and Note 5, "Marketable Securities," to the unaudited condensed consolidated financial statements.

The carrying value of other financial instruments included in current assets and current liabilities, including cash and cash equivalents and special deposits, approximates their fair value due to the short-term nature of these instruments.

9.

COMPREHENSIVE INCOME

Total comprehensive income is as follows:

	For the Three Months Ended
	March 31, 2011		March 31, 2010
(Millions of Dollars)	NU		NU
Net Income	$	115.6	$	87.6
Other Comprehensive Income, Net of Tax:
Qualified Cash Flow Hedging Instruments		1.2		-
Changes in Unrealized Gains on Other Securities (1)		-		0.2
Change in Funded Status of Pension, SERP and PBOP Benefit Plans		0.9		0.5
Other Comprehensive Income, Net of Tax		2.1		0.7
Total Comprehensive Income		117.7		88.3
Comprehensive Income Attributable to Noncontrolling Interests		1.4		1.4
Comprehensive Income Attributable to Controlling Interests	$	116.3	$	86.9

	For the Three Months Ended March 31, 2011						For the Three Months Ended March 31, 2010
(Millions of Dollars)	CL&P		PSNH		WMECO		CL&P		PSNH		WMECO
Net Income	$	64.3	$	27.5	$	10.0	$	48.4	$	15.8	$	5.7
Other Comprehensive Income, Net of Tax:
Qualified Cash Flow Hedging Instruments		0.1		0.9		0.2		0.1		-		-
Other Comprehensive Income, Net of Tax		0.1		0.9		0.2		0.1		-		-
Total Comprehensive Income	$	64.4	$	28.4	$	10.2	$	48.5	$	15.8	$	5.7

⁽¹⁾

Represents changes in unrealized gains on securities held in the NU supplemental benefit trust.  For further information, see Note 5, "Marketable Securities," to the unaudited condensed consolidated financial statements.  

Qualified cash flow hedging instruments for the three months ended March 31, 2011 are as follows:

	For the Three Months Ended March 31, 2011
(Millions of Dollars)	NU		PSNH		WMECO
Balance as of Beginning of Period	$	(4.2)	$	(0.6)	$	(0.1)
Hedged Transactions Recognized into Earnings		-		-		-
Change in Fair Value of Interest Rate Swap Agreements		-		-		-
Cash Flow Transactions Entered into for the Period		1.2		0.9		0.2
Net Change Associated with Hedging Transactions		1.2		0.9		0.2
Total Fair Value Adjustments Included in Accumulated   Other Comprehensive Income	$	(3.0)	$	0.3	$	0.1

For further information regarding cash flow hedging transactions, see Note 4, "Derivative Instruments," to the unaudited condensed consolidated financial statements.

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10.

COMMON SHARES

The following table sets forth the NU common shares and the shares of CL&P, PSNH and WMECO common stock authorized and issued and the respective par values as of March 31, 2011 and December 31, 2010:   

			Shares
			Authorized	Issued
		Per Share Par Value	As of March 31, 2011 and December 31, 2010	As of March 31, 2011	As of December 31, 2010
NU	$	5	225,000,000	195,975,189	195,781,740
CL&P	$	10	24,500,000	6,035,205	6,035,205
PSNH	$	1	100,000,000	301	301
WMECO	$	25	1,072,471	434,653	434,653

As of March 31, 2011 and December 31, 2010, 19,227,908 and 19,333,659 NU common shares were held as treasury shares, respectively.

11.

COMMON SHAREHOLDERS' EQUITY AND NONCONTROLLING INTERESTS (NU)

A summary of the changes in Common Shareholders' Equity and Noncontrolling Interests of NU for the three months ended March 31, 2011 and 2010 is as follows:

	For the Three Months Ended March 31,
	2011								2010
(Millions of Dollars)	Common Shareholders' Equity		Noncontrolling Interest		Total Equity		Preferred Stock Not Subject to Mandatory Redemption		Total Equity		Preferred Stock Not Subject to Mandatory Redemption
Balance, Beginning of Period	$	3,811.2	$	1.5	$	3,812.7	$	116.2	$	3,577.9	$	116.2
Net Income		115.6		-		115.6		-		87.6		-
Dividends on Common Shares		(48.8)		-		(48.8)		-		(45.5)		-
Dividends on Preferred Stock		(1.4)		-		(1.4)		(1.4)		(1.4)		(1.4)
Issuance of Common Shares		4.2		-		4.2		-		5.2		-
Contributions to NPT		-		-		-		-		-		-
Other Transactions, Net		2.4		-		2.4		-		0.7		-
Net Income Attributable to   Noncontrolling Interests		-		-		-		1.4		-		1.4
Other Comprehensive Income   (Note 9)		2.1		-		2.1		-		0.7		-
Balance, End of Period	$	3,885.3	$	1.5	$	3,886.8	$	116.2	$	3,625.2	$	116.2

For the three months ended March 31, 2011 and 2010, there was no change in NU parent's 100 percent ownership of the common equity of CL&P.  

12.

EARNINGS PER SHARE (NU)

EPS is computed based upon the monthly weighted average number of common shares outstanding, excluding unallocated ESOP shares, during each period.  Diluted EPS is computed on the basis of the monthly weighted average number of common shares outstanding plus the potential dilutive effect if certain securities are converted into common stock.  The computation of diluted EPS excludes the effect of the potential exercise of share awards when the average market price of the common shares is lower than the exercise price of the related awards during the period.  These outstanding share awards are not included in the computation of diluted EPS because the effect would have been antidilutive.  For the three months ended March 31, 2010, there were 6,311 share awards excluded from the computation, as these awards were antidilutive.  There were no antidilutive share awards outstanding for the three months ended March 31, 2011.  

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

	For the Three Months Ended March 31,
(Millions of Dollars, except share information)	2011		2010
Net Income Attributable to Controlling Interests	$	114.2	$	86.2
Weighted Average Common Shares Outstanding:
Basic		177,188,207		176,349,762
Dilutive Effect		292,789		187,710
Diluted		177,480,996		176,537,472
Basic and Diluted EPS	$	0.64	$	0.49

RSUs and performance shares are included in basic common shares outstanding as of the date that all necessary vesting conditions have been satisfied.  The dilutive effect of outstanding RSUs and performance shares for which common shares have not been issued is calculated using the treasury stock method.  Assumed proceeds of the units under the treasury stock method consist of the remaining

35

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 is also calculated using the treasury stock method.  Assumed proceeds for stock options consist of remaining compensation cost to be recognized, 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 grant price).  

Allocated ESOP shares are included in basic common shares outstanding in the above table.  

13.

SEGMENT INFORMATION

Presentation:  NU is organized between the Regulated companies' segments and Other based on a combination of factors, including the characteristics of each business' products and services, the sources of operating revenues and expenses and the regulatory environment in which each segment operates.  Cash flows for total investments in plant included in the segment information below are cash capital expenditures that do not include amounts incurred but not paid, cost of removal, AFUDC related to equity funds, and the capitalized portions of pension and PBOP expense or income.  

The Regulated companies' segments include the electric distribution segment, the natural gas distribution segment and the electric transmission segment.  The electric distribution segment includes the generation activities of PSNH and WMECO.  The Regulated companies' segments represented substantially all of NU's total consolidated revenues for the three month periods ended March 31, 2011 and 2010.

Other in the tables below primarily consists of 1) the results of NU parent, which includes other income related to the equity in earnings of NU parent's subsidiaries and interest income from the NU Money Pool, which are both eliminated in consolidation, and interest income and expense related to the cash and debt of NU parent, respectively, 2) the revenues and expenses of NU's service companies, most of which are eliminated in consolidation, and 3) the results of other subsidiaries, which are comprised of NU Enterprises (NU's competitive businesses which primarily consist of Select Energy's remaining wholesale marketing contracts, an electrical contracting business and other operating and maintenance services contracts),  RRR (a real estate subsidiary), the non-energy-related subsidiaries of Yankee (Yankee Energy Services Company and Yankee Energy Financial Services Company) and the remaining operations of HWP that were not exited as part of the sale of the competitive generation business in 2006 and the sale of its transmission business to WMECO in December 2008.  

Regulated companies' 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.

NU's segment information for the three months ended March 31, 2011 and 2010, with the distribution segment segregated between electric and natural gas, is as follows (some amounts may not agree between the financial statements and the segment schedules due to rounding):

	For the Three Months Ended March 31, 2011
	Regulated Companies
	Distribution
(Millions of Dollars)	Electric		Natural Gas		Transmission		Other		Eliminations		Total
Operating Revenues	$	891.6	$	180.2	$	158.2	$	130.4	$	(125.1)	$	1,235.3
Depreciation and Amortization		(91.9)		(6.8)		(23.4)		(4.3)		0.8		(125.6)
Other Operating Expenses		(692.2)		(133.5)		(48.3)		(135.0)		126.7		(882.3)
Operating Income		107.5		39.9		86.5		(8.9)		2.4		227.4
Interest Expense		(29.5)		(5.2)		(16.3)		(8.6)		1.1		(58.5)
Interest Income		1.1		-		0.2		1.3		(1.3)		1.3
Other Income, Net		3.7		0.4		4.8		149.5		(149.5)		8.9
Income Tax Expense		(26.3)		(12.6)		(29.9)		5.7		(0.4)		(63.5)
Net Income		56.5		22.5		45.3		139.0		(147.7)		115.6
Net Income Attributable   to Noncontrolling Interests		(0.8)		-		(0.6)		-		-		(1.4)
Net Income Attributable   to Controlling Interests	$	55.7	$	22.5	$	44.7	$	139.0	$	(147.7)	$	114.2
Total Assets (as of)	$	8,796.1	$	1,437.3	$	3,476.9	$	6,275.0	$	(5,566.8)	$	14,418.5
Cash Flows for Total   Investments in Plant	$	138.7	$	21.8	$	61.8	$	14.4	$	-	$	236.7

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	For the Three Months Ended March 31, 2010
	Distribution
(Millions of Dollars)	Electric		Natural Gas		Transmission		Other		Eliminations		Total
Operating Revenues	$	1,000.0	$	171.7	$	153.7	$	124.1	$	(110.1)	$	1,339.4
Depreciation and Amortization		(103.1)		(3.6)		(20.3)		(3.8)		1.0		(129.8)
Other Operating Expenses		(801.4)		(129.7)		(47.0)		(115.8)		111.0		(982.9)
Operating Income		95.5		38.4		86.4		4.5		1.9		226.7
Interest Expense		(36.5)		(4.9)		(19.5)		(7.6)		1.2		(67.3)
Interest Income		0.8		-		0.1		1.3		(1.4)		0.8
Other Income, Net		4.5		-		2.6		111.7		(111.5)		7.3
Income Tax Expense		(35.2)		(13.9)		(28.9)		(1.6)		(0.3)		(79.9)
Net Income		29.1		19.6		40.7		108.3		(110.1)		87.6
Net Income Attributable   to Noncontrolling Interests		(0.8)		-		(0.6)		-		-		(1.4)
Net Income Attributable   to Controlling Interests	$	28.3	$	19.6	$	40.1	$	108.3	$	(110.1)	$	86.2
Total Assets (as of)	$	8,795.7	$	1,364.9	$	3,331.1	$	5,928.6	$	(5,314.9)	$	14,105.4
Cash Flows for Total   Investments in Plant	$	115.7	$	12.9	$	55.6	$	18.3	$	-	$	202.5

The information related to the distribution and transmission segments for CL&P, PSNH and WMECO for the three months ended March 31, 2011 and 2010 is as follows:

	CL&P - For the Three Months Ended
	March 31, 2011						March 31, 2010
(Millions of Dollars)	Distribution		Transmission		Total		Distribution		Transmission		Total
Operating Revenues	$	549.9	$	123.8	$	673.7	$	671.2	$	123.8	$	795.0
Depreciation and Amortization		(41.5)		(17.3)		(58.8)		(75.8)		(16.7)		(92.5)
Other Operating Expenses		(451.8)		(37.1)		(488.9)		(541.3)		(35.7)		(577.0)
Operating Income		56.6		69.4		126.0		54.1		71.4		125.5
Interest Expense		(16.5)		(13.3)		(29.8)		(22.4)		(16.1)		(38.5)
Interest Income		0.6		0.1		0.7		0.5		0.1		0.6
Other Income, Net		1.4		2.5		3.9		2.2		2.1		4.3
Income Tax Expense		(12.8)		(23.7)		(36.5)		(19.4)		(24.1)		(43.5)
Net Income	$	29.3	$	35.0	$	64.3	$	15.0	$	33.4	$	48.4
Total Assets (as of)	$	5,563.7	$	2,622.8	$	8,186.5	$	5,664.8	$	2,605.5	$	8,270.3
Cash Flows for Total Investments  in Plant	$	80.3	$	26.5	$	106.8	$	63.8	$	33.9	$	97.7

	PSNH - For the Three Months Ended
	March 31, 2011						March 31, 2010
(Millions of Dollars)	Distribution		Transmission		Total		Distribution		Transmission		Total
Operating Revenues	$	247.9	$	21.6	$	269.5	$	238.9	$	19.7	$	258.6
Depreciation and Amortization		(43.8)		(2.8)		(46.6)		(20.1)		(2.6)		(22.7)
Other Operating Expenses		(168.0)		(8.0)		(176.0)		(188.4)		(7.6)		(196.0)
Operating Income		36.1		10.8		46.9		30.4		9.5		39.9
Interest Expense		(8.7)		(1.8)		(10.5)		(10.3)		(2.1)		(12.4)
Interest Income		0.5		0.1		0.6		0.2		-		0.2
Other Income, Net		3.5		0.5		4.0		1.8		0.4		2.2
Income Tax Expense		(9.9)		(3.6)		(13.5)		(11.0)		(3.1)		(14.1)
Net Income	$	21.5	$	6.0	$	27.5	$	11.1	$	4.7	$	15.8
Total Assets (as of)	$	2,363.7	$	492.7	$	2,856.4	$	2,285.0	$	450.4	$	2,735.4
Cash Flows for Total Investments  in Plant	$	46.1	$	11.6	$	57.7	$	45.7	$	8.4	$	54.1

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	WMECO - For the Three Months Ended
	March 31, 2011						March 31, 2010
(Millions of Dollars)	Distribution		Transmission		Total		Distribution		Transmission		Total
Operating Revenues	$	93.9	$	12.8	$	106.7	$	90.0	$	10.2	$	100.2
Depreciation and Amortization		(6.6)		(3.3)		(9.9)		(7.3)		(1.0)		(8.3)
Other Operating Expenses		(72.6)		(3.1)		(75.7)		(71.8)		(3.7)		(75.5)
Operating Income		14.7		6.4		21.1		10.9		5.5		16.4
Interest Expense		(4.5)		(1.1)		(5.6)		(3.7)		(1.2)		(4.9)
Interest Income		0.1		-		0.1		0.1		-		0.1
Other Income, Net		(1.0)		1.7		0.7		0.4		0.1		0.5
Income Tax Expense		(3.6)		(2.7)		(6.3)		(4.7)		(1.7)		(6.4)
Net Income	$	5.7	$	4.3	$	10.0	$	3.0	$	2.7	$	5.7
Total Assets (as of)	$	871.8	$	344.7	$	1,216.5	$	851.8	$	271.6	$	1,123.4
Cash Flows for Total Investments  in Plant	$	12.2	$	20.8	$	33.0	$	6.2	$	12.9	$	19.1

14.

VARIABLE INTEREST ENTITIES

The Company's variable interests outside of the consolidated group are not material and consist of contracts that are required by regulation and provide for regulatory recovery of contract costs and benefits through customer rates.  NU holds variable interests in VIEs through agreements with certain entities that own single renewable energy or peaking generation power plants and with other independent power producers.  NU does not control the activities that are economically significant to these VIEs or provide financial or other support to these VIEs.  Therefore, NU does not consolidate any power plant VIEs.  

38

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Trustees and Shareholders of Northeast Utilities:

We have reviewed the accompanying condensed consolidated balance sheet of Northeast Utilities and subsidiaries (the "Company") as of March 31, 2011 and the related condensed consolidated statements of income and of cash flows for the three-month periods ended March 31, 2011 and 2010.  These interim financial statements are the responsibility of the Company’s management.

We conducted our reviews in accordance with the standards of the Public Company Accounting Oversight Board (United States).  A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters.  It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board (United States), the objective of which is the expression of an opinion regarding the financial statements taken as a whole.  Accordingly, we do not express such an opinion.

Based on our reviews, we are not aware of any material modifications that should be made to such condensed consolidated interim financial statements for them to be in conformity with accounting principles generally accepted in the United States of America.

We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet and consolidated statement of capitalization of Northeast Utilities and subsidiaries as of December 31, 2010, and the related consolidated statements of income, comprehensive income, common shareholders’ equity, and cash flows for the year then ended (not presented herein); and in our report dated February 25, 2011, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying condensed consolidated balance sheet as of December 31, 2010 is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

/s/	Deloitte & Touche LLP
	Deloitte & Touche LLP

Hartford, Connecticut

May 6, 2011

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 Quarterly Report on Form 10-Q and the 2010 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.

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 or loss attributable to controlling interests of each business by the weighted average diluted NU common shares outstanding for the period.  We use this non-GAAP financial measure to evaluate earnings results and to provide details of earnings results and guidance by business.  We believe that this measurement is useful to investors to evaluate the actual and projected financial performance and contribution of our businesses.  This non-GAAP financial measure should not be considered as an alternative to our consolidated diluted EPS determined in accordance with GAAP as an indicator of operating performance.

The discussion below also includes a non-GAAP financial measure referencing our first quarter 2011 earnings and EPS excluding expenses related to NU's proposed merger with NSTAR.  We use this non-GAAP financial measure to more fully compare and explain the first quarter 2011 and 2010 results without including the impact of this non-recurring item.  Due to the nature and significance of this item on Net Income, management believes that this non-GAAP presentation is more representative of our performance and provides additional and useful information to readers of this report in analyzing historical and future performance.  This non-GAAP financial measure should not be considered as alternatives to reported Net Income Attributable to Controlling Interests or EPS determined in accordance with GAAP as indicators 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 Interests are included under "Financial Condition and Business Analysis-Overview-Consolidated" and "Financial Condition and Business Analysis-Future Outlook" in Management's Discussion and Analysis, herein.  All forward-looking information for 2011 and thereafter provided in this Management’s Discussion and Analysis assumes we will operate on a stand-alone basis, excluding the impacts of the proposed merger with NSTAR, unless otherwise indicated.  

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

·

actions or inaction by local, state and federal regulatory bodies

·

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

·

changes in weather patterns

·

changes in laws, regulations or regulatory policy

·

changes in levels and timing of capital expenditures

·

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

·

developments in legal or public policy doctrines

·

technological developments

·

changes in accounting standards and financial reporting regulations

·

fluctuations in the value of our remaining competitive contracts

·

actions of rating agencies

·

The expected timing and likelihood of completion of the proposed merger with NSTAR, including the timing, receipt and terms and conditions of any required governmental and regulatory approvals of the proposed merger that could reduce anticipated benefits or cause the parties to abandon the merger, the diversion of management's time and attention from our ongoing business during this time period, as well as the ability to successfully integrate the businesses, and the risk that the credit ratings of the combined company or its subsidiaries may be different from what the companies expect and

·

other presently unknown or unforeseen factors.  

40

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 management to predict all of such factors, nor can it 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 our 2010 Form 10-K.  This Quarterly Report on Form 10-Q and our 2010 Form 10-K also describe material contingencies and critical accounting policies and estimates in the accompanying Management's Discussion and Analysis and Combined Notes to Consolidated Financial Statements.  We encourage you to review these items.

Financial Condition and Business Analysis

Proposed Merger with NSTAR:  

On October 18, 2010, we and NSTAR announced that each company's Board of Trustees unanimously approved a Merger Agreement (the "agreement"), under which NSTAR will become a direct wholly owned subsidiary of NU.  The transaction is structured as a merger of equals in a tax-free exchange.  The post-transaction company will provide electric and natural gas energy delivery service to approximately 3.5 million electric and natural gas customers through six regulated electric and natural gas utilities in Connecticut, Massachusetts and New Hampshire.  On March 4, 2011, NU shareholders approved the agreement, approved an increase to the number of NU common shares authorized for issuance by 155 million common shares to 380 million authorized common shares and fixed the number of trustees at 14.  NSTAR shareholders approved the agreement on March 4, 2011.

Under the terms of the agreement, NSTAR shareholders will receive 1.312 NU common shares for each NSTAR common share that they own (the "exchange ratio").  The exchange ratio was structured to result in a no premium merger based on the average closing share price of each company's common shares for the 20 trading days preceding the announcement.  Based on the number of NU common shares and NSTAR common shares estimated to be outstanding immediately prior to the closing of the merger, upon such closing, NU shareholders will own approximately 56 percent of the post-transaction company and former NSTAR shareholders will own approximately 44 percent of the post-transaction company.  It is anticipated that we will issue approximately 137 million common shares to the NSTAR shareholders as a result of the merger.  

Subject to the conditions in the agreement, our first quarterly dividend per common share declared after the completion of the merger will be increased to an amount that is equivalent, after adjusting for the exchange ratio, to NSTAR's last quarterly dividend paid prior to the closing.  Based on the last quarterly dividend paid by NSTAR, and assuming there are no changes to such dividend prior to the closing of the merger, this anticipated amount will be approximately $0.325 per share, or approximately $1.30 per share on an annualized basis, as compared to our current annualized dividend rate of approximately $1.10 per share.

Completion of the merger is subject to various customary conditions, including, among others, receipt of all required regulatory approvals.  The companies anticipate that the regulatory approvals can be obtained to permit the merger to close in the second half of 2011.  For further information regarding regulatory approvals on the proposed merger, see "Regulatory Developments and Rate Matters – Regulatory Approvals on Proposed Merger with NSTAR" in this Management's Discussion and Analysis.  

Executive Summary

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

Results:

The earnings discussion below is for the three months ended March 31, 2011, compared with the same period in 2010:

·

We earned $114.2 million, or $0.64 per share, compared with $86.2 million, or $0.49 per share.  Excluding merger-related costs of $8.3 million, or $0.05 per share, we earned $122.5 million, or $0.69 per share, in the first quarter of 2011.  The improved 2011 results were attributable primarily to the impact of recent electric distribution rate case decisions as well as colder than normal weather, increased transmission segment earnings and increased sales in our firm natural gas business.

·

Our Regulated companies earned $122.9 million, or $0.69 per share, compared with $88 million, or $0.50 per share.  

·

The distribution segment of our Regulated companies earned $78.2 million, or $0.44 per share, compared with $47.9 million, or $0.27 per share.  The transmission segment of our Regulated companies earned $44.7 million, or $0.25 per share, compared with $40.1 million, or $0.23 per share.  

·

NU parent and other companies recorded net expenses of $8.7 million, or $0.05 per share, compared with net expenses of $1.8 million, or $0.01 per share.  The 2011 results include after-tax expenses of $8.3 million, or $0.05 per share, related to NU’s proposed merger with NSTAR.  

41

Outlook:  

·

We affirmed consolidated 2011 earnings of between $2.25 per share and $2.40 per share, excluding projected after-tax merger-related costs of approximately $0.20 per share.  This projection includes distribution segment earnings of between $1.25 per share and $1.35 per share, transmission segment earnings of between $1.05 per share and $1.10 per share, and net expenses at NU parent and other companies of approximately $0.05 per share.

Strategy, Regulatory and Other Items:

·

A final DPUC decision in the Yankee Gas rate application filed on January 7, 2011 is expected in June 2011.  Yankee Gas is requesting an increase (as adjusted) to distribution rates of $29.1 million effective July 1, 2011 and by an additional $10.3 million effective July 1, 2012.

·

In February 2011, WMECO began site work on portions of the GSRP component of our NEEWS project.  We expect to receive our required permits in the third quarter of 2011, which will allow major overhead line construction to commence.  CL&P is expected to begin construction on the Connecticut overhead section of GSRP in early 2012.  

·

PSNH's Clean Air Project is expected to cost approximately $430 million and should be fully complete by mid-2012.  The project is currently ahead of schedule and we believe a significant portion could be operational by the end of 2011.    

Liquidity:

Except as otherwise noted, cash flow data discussed below is for the three months ended March 31, 2011, compared with the same period in 2010:

·

Cash capital expenditures totaled $236.7 million, compared with $202.5 million.

·

Cash flows provided by operating activities totaled $355.9 million, compared with $159.1 million (amounts are net of RRB payments).  The 2011 improved cash flows were due primarily to the impact of the recent electric distribution rate case decisions and a decrease in income tax payments largely attributable to the accelerated depreciation provisions of the 2010 Tax Act.  

·

Cash and cash equivalents totaled $15.4 million as of March 31, 2011, compared with $23.4 million as of December 31, 2010.  

Overview

Consolidated:  We earned $114.2 million, or $0.64 per share, in the first quarter of 2011, compared with $86.2 million, or $0.49 per share, in the first quarter of 2010.  Excluding merger-related costs of $8.3 million, or $0.05 per share, we earned $122.5 million, or $0.69 per share, in the first quarter of 2011.  Improved results in the first quarter of 2011 were due primarily to the impact of the CL&P and PSNH 2010 distribution rate case decisions that were effective July 1, 2010 and the WMECO distribution rate case decision that was effective February 1, 2011, colder first quarter weather in 2011, increased earnings in the transmission segment, continued cost management efforts, and the absence of a net after-tax charge of approximately $3 million, or approximately $0.02 per share, taken in the first quarter of 2010 associated with the enactment of the 2010 Healthcare Act.  These benefits were partially offset by pension costs and property taxes.  Retail electric sales were up 3 percent and firm natural gas sales were up 16.9 percent in the first quarter of 2011 compared to the same period in 2010.

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 Interests and diluted EPS, for the first quarters of 2011 and 2010 is as follows:

	For the Three Months Ended March 31,
(Millions of Dollars, Except Per Share Amounts)	2011				2010
	Amount		Per Share		Amount		Per Share
Net Income Attributable to Controlling Interests (GAAP)	$	114.2	$	0.64	$	86.2	$	0.49
Regulated Companies	$	122.9	$	0.69	$	88.0	$	0.50
NU Parent and Other Companies		(0.4)		-		(1.8)		(0.01)
Non-GAAP Earnings		122.5		0.69		86.2		0.49
Merger-Related Costs (after-tax)		(8.3)		(0.05)		-		-
Net Income Attributable to Controlling Interests (GAAP)	$	114.2	$	0.64	$	86.2	$	0.49

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Regulated Companies:  Our Regulated companies consist of the distribution and electric transmission segments, with the Yankee Gas natural gas distribution segment and PSNH and WMECO generation activities included in the distribution segment.A summary of our Regulated companies' earnings by segment for the first quarters of 2011 and 2010 is as follows:

	For the Three Months Ended March 31,
(Millions of Dollars)	2011		2010
CL&P Transmission	$	34.4	$	32.7
PSNH Transmission		6.0		4.7
WMECO Transmission		4.2		2.7
NPT		0.1		-
Total Transmission	$	44.7	$	40.1
CL&P Distribution		28.5		14.3
PSNH Distribution		21.5		11.1
WMECO Distribution		5.7		2.9
Yankee Gas		22.5		19.6
Total Distribution	$	78.2	$	47.9
Net Income - Regulated Companies	$	122.9	$	88.0

The higher first quarter 2011 transmission segment earnings primarily reflect increased investment in transmission infrastructure to meet the reliability needs of our customers and the region, and the absence of a $0.8 million after-tax charge taken in the first quarter of 2010 associated with the 2010 Healthcare Act.   

CL&P’s first quarter 2011 distribution segment earnings were $14.2 million higher than the same period in 2010 due primarily to the impact of the DPUC distribution rate case decision that was effective July 1, 2010, and a 3.3 percent increase in retail electric sales, partially offset by higher expenses including pension, healthcare, system maintenance and vegetation management costs, and property taxes.  For the twelve months ended March 31, 2011, CL&P’s distribution segment regulatory ROE was 8.8 percent, and for 2011, we expect it to be approximately 9 percent.

PSNH’s first quarter 2011 distribution segment earnings were $10.4 million higher than the same period in 2010 due primarily to the impact of the distribution rate increase effective July 1, 2010 and a 2.7 percent increase in retail electric sales, higher AFUDC earnings related to the Clean Air Project capital expenditures, and the absence of $1 million of income tax expense taken in the first quarter of 2010 attributable to the 2010 Healthcare Act.  For the twelve months ended March 31, 2011, PSNH’s distribution segment regulatory ROE was 11.1 percent and for 2011, we expect it to be approximately 9 percent.

WMECO’s first quarter 2011 distribution segment earnings were $2.8 million higher than the same period in 2010 due primarily to the impact of the DPU distribution rate case decision effective February 1, 2011 that included an annualized rate increase of $16.8 million and sales decoupling, and slightly higher retail electric sales in January 2011 before decoupling took effect.  For the twelve months ended March 31, 2011, WMECO’s distribution segment regulatory ROE was 5.9 percent and for 2011, we expect it to be approximately 9 percent.

Yankee Gas’ first quarter 2011 earnings were $2.9 million higher than the same period in 2010 due primarily to a 16.9 percent increase in total firm natural gas sales, and lower uncollectibles expense, partially offset by higher expenses including employee benefits, system maintenance, depreciation and amortization costs, property taxes, and interest expense.  For the twelve months ended March 31, 2011, Yankee Gas’ regulatory ROE was 9.3 percent.  We anticipate the DPUC will issue a decision in June 2011 on Yankee Gas’ request to raise its distribution rates effective July 1, 2011.  Yankee Gas’ request includes a recommendation to maintain its authorized regulatory ROE of 10.1 percent.

For the distribution segment of our Regulated companies, a summary of changes in CL&P, PSNH and WMECO retail electric GWh sales as well as total sales and percentage changes and Yankee Gas firm natural gas sales and percentage changes in million cubic feet for the first quarter of 2011 as compared to the same period in 2010 on an actual and weather normalized basis (using a 30-year average) is as follows:

	For the Three Months Ended March 31, 2011 Compared to 2010
	CL&P		PSNH		WMECO		Total
	Percentage Increase/ (Decrease)	Weather Normalized Percentage Increase/ (Decrease)	Percentage Increase/ (Decrease)	Weather Normalized Percentage Increase/ (Decrease)	Percentage Increase/ (Decrease)	Weather Normalized Percentage Increase/ (Decrease)	Sales (GWh)		Percentage Increase/ (Decrease)	Weather Normalized Percentage Increase/ (Decrease)
Residential	6.1%	(0.3)%	4.9%	0.7%	5.6%	0.4%	4,123	3,896	5.8%	-
Commercial	0.6%	(0.9)%	1.4%	0.1%	(2.5)%	(3.4)%	3,473	3,456	0.5%	(0.9)%
Industrial	1.6%	1.6%	0.3%	0.3%	2.9%	2.9%	1,022	1,008	1.4%	1.4%
Other	(1.1)%	(1.1)%	(5.5)%	(5.5)%	1.0%	1.0%	87	88	(1.3)%	(1.3)%
Total	3.3%	(0.4)%	2.7%	0.4%	2.0%	(0.6)%	8,705	8,448	3.0%	(0.2)%

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	For the Three Months Ended March 31, 2011 Compared to 2010
	Firm Natural Gas
	Sales (million cubic feet) (1)		Percentage Increase	Weather Normalized Percentage Increase/ (Decrease)
Residential	6,780	6,104	11.1%	(4.8)%
Commercial	7,623	6,027	26.5%	9.5 %
Industrial	4,981	4,458	11.7%	5.7 %
Total	19,384	16,589	16.9%	3.2 %
Total Net of Special Contracts	16,940	14,247	18.9%	3.0 %

⁽¹⁾

The 2010 sales volume for commercial customers has been adjusted to conform to current year presentation.  

First quarter 2011 actual retail electric sales for all three electric companies were higher than the same period in 2010 due primarily to significantly colder weather as compared to the first quarter of 2010.  Heating degree days in Connecticut and western Massachusetts were 18.6 percent higher than last year and 5.9 percent above normal.  In New Hampshire, heating degree days were 17.7 percent higher than last year and 5.1 percent above normal.  For WMECO, the fluctuations in retail electric sales no longer impact earnings as the DPU approved a sales decoupling plan effective February 1, 2011.  Under this decoupling plan, WMECO now has an established level of baseline distribution delivery service revenues of $125.6 million that it is able to recover, which effectively breaks the relationship between KWhs consumed by customers and revenues recognized.  This decoupling plan is designed to encourage WMECO to promote conservation by its customers with no impact to its revenues.  

On a weather normalized basis, retail electric sales in the first quarter of 2011 as compared to 2010 varied by electric company and by customer class.  Our combined first quarter 2011 retail electric sales decreased by 0.2 percent as compared to the first quarter of 2010.  Overall, we believe our customers continue to be impacted by the effects of a weak economic recovery and continue to increase their conservation efforts.  Our industrial sales did, however, increase in the first quarter of 2011 for all three electric companies due in part to improvements in manufacturing employment and hours worked.  Fluctuations in industrial sales have a relatively small impact on earnings as most of the industrial revenues are recovered through non-volumetric charges.

Our firm natural gas sales are subject to many of the same influences as our retail electric sales, but have benefitted from a favorable price for natural gas and the addition of gas-fired distributed generation in Yankee Gas’ service territory.  Actual firm natural gas sales in the first quarter of 2011 were 16.9 percent higher than the same period in 2010, or 3.2 percent higher on a weather normalized basis.  In addition, commercial and industrial sales benefitted from the migration of interruptible customers switching to firm rates.

Our expense related to uncollectible receivable balances (our uncollectibles expense) is influenced by the economic conditions of our region.  Fluctuations in our uncollectibles expense are mitigated from an earnings perspective because a portion of the total uncollectibles expense for each of the electric distribution companies is allocated for recovery to the respective company’s energy supply rate and recovered through its tariffs.  Additionally, for CL&P and Yankee Gas, write-offs of uncollectible receivable balances attributable to qualified customers under financial or medical duress (hardship customers) are fully recovered through their respective tariffs.  For the first quarter of 2011, our total pre-tax uncollectibles expense that impacts earnings was $3.6 million as compared to $7.9 million in the first quarter of 2010.  The improvement in 2011 uncollectibles expense was due in part to continued enhanced accounts receivable collection efforts.

NU Parent and Other Companies:  NU parent and other companies (which includes our competitive businesses held by NU Enterprises) recorded net expenses of $8.7 million, or $0.05 per share, in the first quarter of 2011, compared with net expenses of $1.8 million, or $0.01 per share, in the first quarter of 2010.  First quarter 2011 results include after-tax expenses of $8.3 million, or $0.05 per share, associated with the proposed merger with NSTAR.  

Future Outlook

EPS Guidance:  Following is a summary of our affirmed projected 2011 EPS by business, which also reconciles consolidated diluted EPS to the non-GAAP financial measure of EPS by business.  Non-GAAP EPS by business also excludes a $0.20 per share charge related to projected non-recurring merger costs we expect to incur relating to financial advisor costs, legal, accounting and consulting fees, which will affect NU parent and other companies' results.  The number of outstanding NU common shares used to calculate this guidance was approximately 177 million shares.

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	2011 EPS Range
(Approximate amounts)		Low		High
Diluted EPS (GAAP)	$	2.05	$	2.20
Regulated Companies:
Distribution Segment	$	1.25	$	1.35
Transmission Segment		1.05		1.10
Total Regulated Companies		2.30		2.45
NU Parent and Other Companies		(0.05)		(0.05)
Non-GAAP EPS	$	2.25	$	2.40
Merger-Related Costs		(0.20)		(0.20)
Diluted EPS (GAAP)	$	2.05	$	2.20

This projection reflects operations on a stand-alone basis in 2011, although our proposed merger with NSTAR is expected to close in the second half of 2011.  We have included the impacts of the CL&P, PSNH, and WMECO electric distribution rate case decisions received as well as an anticipated reasonable outcome in the Yankee Gas rate case decision expected in June 2011 in the assumptions used to develop our 2011 earnings guidance.  The 2011 distribution and transmission earnings guidance reflects the impact of a higher rate base as well as $1.2 billion of projected capital expenditures in 2011.  

Liquidity

Consolidated:  Cash and cash equivalents totaled $15.4 million as of March 31, 2011, compared with $23.4 million as of December 31, 2010.  

On March 3, 2011, the NHPUC approved PSNH’s application requesting authority to issue long-term debt securities for the purpose of refinancing certain series of PCRBs totaling $209 million.  PSNH plans to issue approximately $120 million of taxable fixed rate long-term debt in the second quarter of 2011 to refinance its tax-exempt 1992 Series D and 1993 Series E PCRBs with maturity dates of May 1, 2021 and coupon rates of 6 percent.  

On January 28, 2011, the DPU authorized WMECO to issue up to $330 million in long-term debt through December 31, 2012 to be used to refinance WMECO’s short-term debt previously incurred in the ordinary course of business, to finance capital expenditures, to provide working capital and to pay issuance costs.  

On April 1, 2011, CL&P remarketed $62 million of tax-exempt secured PCRBs that were subject to mandatory tender.  The PCRBs, which mature on May 1, 2031, now carry a coupon rate of 1.25 percent, compared with 1.4 percent for the previous 12-month period ended March 31, 2010, and have a mandatory tender on April 1, 2012, at which time CL&P expects to remarket the bonds.

We expect to issue approximately $260 million of long-term debt in the second half of 2011, comprised of $160 million by PSNH, excluding the refinancing of its PCRBs referenced above, and $100 million by WMECO.  

Cash flows provided by operating activities in the first quarter of 2011 totaled $355.9 million, compared with operating cash flows of $159.1 million in the first quarter of 2010 (all amounts are net of RRB payments, which are included in financing activities on the accompanying unaudited condensed consolidated statements of cash flows).  The improved cash flows were due primarily to the impact of the CL&P and PSNH 2010 distribution rate case decisions that were effective July 1, 2010 (the CL&P July 1, 2010 rate case increase was deferred from customer bills until January 1, 2011), the WMECO distribution rate case decision that was effective February 1, 2011 and a decrease in income tax payments largely attributable to accelerated depreciation tax benefits.  Offsetting these benefits were payments made in the first quarter of 2011 for merger-related costs.

We now project 2011 cash flows provided by operating activities of approximately $900 million to $950 million, net of RRB payments.  The decrease from our previously announced operating cash flow range of $950 million to $1 billion is due primarily to a decrease in the cash flow benefits from the accelerated depreciation provisions of the 2010 Tax Act, which is now expected to result in a cash flow benefit of approximately $200 million in 2011, rather than the $250 million we had previously announced.  

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

	Moody's		S&P		Fitch
	Current	Outlook	Current	Outlook	Current	Outlook
NU parent	Baa2	Stable	BBB-	Watch-Positive	BBB	Watch-Positive
CL&P	A2	Stable	BBB+	Watch-Positive	A-	Positive
PSNH	A3	Stable	BBB+	Watch-Positive	A-	Stable
WMECO	Baa2	Stable	BBB	Watch-Positive	BBB+	Stable

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On April 18, 2011, Fitch raised PSNH's senior secured rating to "A-" from "BBB+" to better reflect the firm's notching policy for senior secured debt.  On the same day, Fitch raised its outlook on CL&P to "positive" from "stable" in part to reflect improved cash flow metrics.

If the senior unsecured debt ratings of NU parent were to be reduced to below investment grade level by either Moody's or S&P, a number of Select Energy's supply contracts would require Select Energy to post additional collateral in the form of cash or LOCs.  If such an event had occurred as of March 31, 2011, Select Energy would have been required to provide additional cash or LOCs in an aggregate amount of $23.5 million to various unaffiliated counterparties and additional cash or LOCs in the aggregate amount of $5.9 million to independent system operators.  NU parent would have been and remains able to provide that collateral on behalf of Select Energy.  

If the unsecured debt ratings of PSNH were to be reduced by either Moody's or S&P, certain supply contracts could require PSNH to post additional collateral in the form of cash or LOCs with various unaffiliated counterparties.  As of March 31, 2011, if the unsecured debt ratings of PSNH had been reduced by one level or to below investment grade, PSNH had an adequate amount of collateral posted and would not have been required to post additional amounts.

We paid common dividends of $48.6 million in the first quarter of 2011, compared with $45.1 million in the first quarter of 2010.  The increase reflects an approximately 7.3 percent increase in our common dividend rate that took effect in the first quarter of 2011.  On April 12, 2011, our Board of Trustees declared a quarterly common dividend of $0.275 per share, payable on June 30, 2011 to shareholders of record as of June 1, 2011, which equates to $1.10 per share dividend on an annualized basis.

Assuming completion of our proposed merger with NSTAR and subject to the conditions in the merger agreement, our first quarterly dividend per common share declared after the completion of the proposed merger will be increased to an amount that is equivalent, after adjusting for the exchange ratio, to NSTAR's last quarterly dividend paid prior to the closing.  Based on the last quarterly dividend paid by NSTAR of $0.425 per share, and assuming there are no changes to such dividend prior to the closing of the merger, that would result in NU’s quarterly dividend being increased by 18 percent to approximately $0.325 per share, or approximately $1.30 per share on an annualized basis.

In the first quarter of 2011, CL&P, PSNH, WMECO, and Yankee Gas paid $131.5 million, $14.7 million, $6.6 million, and $38.2 million, respectively, in common dividends to NU parent.  In the first quarter of 2011, NU parent made an equity contribution to PSNH of $20 million and made no equity contributions to CL&P, WMECO and Yankee Gas.

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

	For the Three Months Ended March 31,
(Millions of Dollars)		2011		2010
CL&P	$	106.8	$	97.7
PSNH		57.7		54.1
WMECO		33.0		19.1
Yankee Gas		21.8		12.9
NPT		2.9		0.3
Other		14.5		18.4
Totals	$	236.7	$	202.5

The increase in our cash capital expenditures was the result of higher distribution segment capital expenditures of $31.9 million, primarily at CL&P and Yankee Gas, and an increase in the transmission segment cash capital expenditures of $6.3 million, primarily at WMECO.  

As of March 31, 2011, NU parent had $26.1 million of LOCs issued for the benefit of certain subsidiaries (primarily PSNH) and $149 million of short-term borrowings outstanding under its three-year $500 million unsecured revolving credit facility.  The weighted-average interest rate on these short-term borrowings as of March 31, 2011 was 2.15 percent, which is based on a variable rate plus an applicable margin based on NU parent's credit ratings.  NU parent had $324.9 million of borrowing availability on this facility as of March 31, 2011.

CL&P, PSNH, WMECO, and Yankee Gas maintain a joint three-year unsecured revolving credit facility in a nominal aggregate amount of $400 million.  As of March 31, 2011, CL&P, PSNH, and WMECO had short-term borrowings outstanding under this facility of $10 million, $20 million, and $10 million, respectively, leaving $360 million of aggregate borrowing capacity available.  The weighted-average interest rate on these short-term borrowings as of March 31, 2011 was 2.06 percent, which is based on a variable rate plus an applicable margin based on CL&P, PSNH, and WMECO’s respective credit ratings.

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Business Development and Capital Expenditures

Consolidated:  Our consolidated capital expenditures, including amounts incurred but not paid, cost of removal, AFUDC, and the capitalized portions of pension and PBOP expense or income (all of which are non-cash factors), totaled $221.1 million in the first quarter of 2011, compared with $182.7 million in the first quarter of 2010.  These amounts included $12.3 million and $12.5 million in the first quarter of 2011 and 2010, respectively, related to our corporate service companies, NUSCO and RRR.

Regulated Companies:  Capital expenditures for the Regulated companies are expected to total approximately $1.2 billion ($474 million for CL&P, $284 million for PSNH, and $287 million for WMECO) in 2011, which includes planned spending of approximately $32 million for our corporate service companies.  

Transmission Segment:  Transmission segment capital expenditures increased by $16.2 million in the first quarter of 2011, as compared with the same period in 2010, due primarily to increases at WMECO related to GSRP.  A summary of transmission segment capital expenditures by company in the first quarters of 2011 and 2010 is as follows:  

	For the Three Months Ended March 31,
(Millions of Dollars)		2011		2010
CL&P	$	23.5	$	28.2
PSNH		10.3		7.1
WMECO		30.6		15.4
NPT		3.3		0.8
Totals	$	67.7	$	51.5

NEEWS:  GSRP, which involves the construction of 115 KV and 345 KV lines from Ludlow, Massachusetts to Bloomfield, Connecticut, is the first and largest component of our NEEWS project.  As we have previously reported, we commenced substation construction on GSRP in December 2010 and began site work on the Massachusetts overhead section in February 2011.  Major overhead line construction should begin in the third quarter of 2011 when we expect to receive our Army Corps of Engineers and Massachusetts environmental permits.  We expect the cost of GSRP to be $795 million and to place the project in service in late 2013.  In June 2010, residents living near the proposed Connecticut route of GSRP appealed the CSC approval in New Britain Superior Court, claiming that the CSC acted improperly by approving an overhead route for the line.  This appeal was dismissed in March 2011 in favor of CL&P.  On April 13, 2011, the decision to dismiss the appeal was appealed to the Connecticut State Appellate Court.  We do not expect the appeal to have a material impact on the timing of construction, which we expect to begin on the overhead section in Connecticut in early 2012.

The Interstate Reliability Project, which includes CL&P’s construction of an approximately 40-mile, 345 KV all overhead line from Lebanon, Connecticut to the Connecticut-Rhode Island border, is our second major NEEWS project.  In August 2010, ISO-NE reaffirmed the need for a slightly modified Interstate Reliability Project, which is expected to be placed in service in late 2015.  This in-service date assumes that all siting applications are filed in late 2011, with approvals received in late 2013 and construction commencing in late 2013 or early 2014.  

Following ISO-NE’s reaffirmation of the need for Interstate Reliability Project, ISO-NE approved a new CL&P project designed to eliminate a special protection system at a generating station in Connecticut.  As a result, approximately $50 million of work included in the Interstate Reliability Project's original $301 million estimated cost will be deferred and studied as part of the Central Connecticut Reliability Project study discussed below.  We now expect the cost of the Interstate Reliability Project to be approximately $251 million.  CL&P will add approximately $25 million to its transmission capital program related to the special protection system removal project.  The net impact on the five-year transmission capital program is a decrease of approximately $25 million and an acceleration of $25 million of expenditures from 2014 into 2011 and 2012.  

The Central Connecticut Reliability Project, which involves construction of a new 345 KV all overhead line from Bloomfield, Connecticut to Watertown, Connecticut, is the third major part of NEEWS.  In March 2011, ISO-NE announced that it would review the Central Connecticut Reliability Project along with other central Connecticut projects and expects to have preliminary need results in late 2011.  We estimate the cost of this project to be approximately $338 million and will refine this cost and schedule after ISO-NE completes its review.  

Included as part of NEEWS are expenditures for associated reliability related projects, all of which have received siting approval and most of which are under construction.  These projects began going into service in 2010 and will continue to go into service through 2013.  

Since inception of NEEWS through March 31, 2011, CL&P and WMECO have capitalized approximately $104.4 million and $164.4 million, respectively, in costs associated with NEEWS, of which $5.7 million and $27.5 million, respectively, were capitalized in the first quarter of 2011.

CL&P and WMECO include 100 percent of the NEEWS CWIP in their local rate base.  Concurrently, for regional ratemaking purposes, CL&P and WMECO record AFUDC on the NEEWS CWIP balance in order to recognize the fact that regional customers are not paying for the carrying costs on the NEEWS CWIP and will therefore be charged for the AFUDC when the NEEWS project construction is complete and placed in service.  Once the NEEWS project is completed and included in regional rates, CL&P and WMECO will recover the AFUDC from regional customers over the life of the asset and provide a revenue credit to the local customers.  On April 1, 2011, CL&P and WMECO (along with National Grid USA on behalf of New England Power Company) filed an application with the FERC

47

requesting changes to the ISO-NE Tariff  in order to include 100 percent of the NEEWS CWIP in regional rate base effective June 1, 2011.  If approved, CL&P and WMECO will cease accruing AFUDC on NEEWS CWIP, and NU’s local customers will receive appropriate credits for the return on CWIP they have paid.  Included in the total cost estimate of the NEEWS projects is approximately $160 million of AFUDC that was originally expected to be recorded from June 1, 2011 until the completion of the NEEWS projects.  An order from the FERC on this matter is expected in late May 2011.  

Northern Pass:  On October 4, 2010, NPT and Hydro Renewable Energy entered into a TSA in connection with the Northern Pass transmission project.  Northern Pass is comprised of a planned HVDC transmission line that will be constructed by NPT 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 HVDC transmission line that HQ TransÉnergie, the transmission division of HQ, will construct in Québec.  

Under the terms of the TSA, which was accepted by the FERC without modification in February 2011, NPT will sell to Hydro Renewable Energy 1,200 MW of firm electric transmission rights over the Northern Pass for a 40-year term and charge cost-based rates.  The projected cost-of-service calculation includes an ROE of 12.56 percent through the construction phase of the project, and upon commercial operation, the ROE will be equal to the ISO-NE regional rates base ROE (currently 11.14 percent) plus 1.42 percent.  The TSA rates will be based on a deemed capital structure for NPT of 50 percent debt and 50 percent equity.  During the development and the construction phases under the TSA, NPT will be recording non-cash AFUDC earnings.  On April 3, 2011, the FERC issued an order in the NPT proceeding accepting various rehearing requests.

In October 2010, NPT filed the Northern Pass project design with ISO-NE for technical approval and filed a presidential permit application with the DOE, which seeks permission to construct and maintain facilities that cross the Québec-New Hampshire border and connect to HQ TransÉnergie's facilities in Québec.  The DOE held seven meetings in New Hampshire in mid-March 2011 seeking public comment on NPT.  In response to concerns raised at these meetings, in April 2011, NPT revised its application to request an additional 60 days for the public comment period to allow NPT to review other routes and withdrew certain proposed alternative routes.  NPT anticipates filing additional state and federal permit and siting applications in 2011.  Assuming timely regulatory review and siting approvals, NPT expects to commence construction of Northern Pass in 2013 and complete the line with power flowing in late 2015.  

On March 30, 2011, the New Hampshire House of Representatives approved House Bill 648, which would preclude non-reliability projects, such as Northern Pass, from using eminent domain to acquire property for construction of transmission lines.  This legislation is pending in the New Hampshire Senate.  If passed, this legislation could make it more difficult for NPT to obtain the property required for the project.  We believe that we will be able to acquire the necessary property for the project.  

We currently estimate that NU's 75 percent share of the Northern Pass transmission project will be approximately $830 million and NSTAR’s 25 percent share of the Northern Pass transmission project will be approximately $280 million, for a combined total expected cost of approximately $1.1 billion (including capitalized AFUDC).

Other:  CL&P and the Connecticut Transmission Municipal Electric Energy Cooperative (CTMEEC), a non-profit municipal joint action transmission entity formed by several Connecticut municipal electric utilities, have received approval from the DPUC and the FERC for CL&P to transfer to CTMEEC a segment of high voltage transmission lines built by CL&P in the town of Wallingford, Connecticut.  This segment of lines is projected to have a net book value of $42.3 million at the anticipated time of closing on May 31, 2011.  CL&P will continue to operate and maintain the lines for CTMEEC.  The transaction does not include the transfer of land or equipment not related to electric transmission service.  The transaction will not impact our five-year capital plan and is already reflected in CL&P’s transmission rate base forecasts.  

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Distribution Segment:  Distribution segment capital expenditures increased by $22.4 million in the first quarter of 2011, as compared with the same period in 2010, due primarily to expenditures related to CL&P and the Yankee Gas WWL Project, partially offset by lower expenditures for the PSNH Clean Air Project.  A summary of distribution segment capital expenditures by company for the first quarters of 2011 and 2010 is as follows:

		For the Three Months Ended March 31,
(Millions of Dollars)		2011		2010
CL&P:
Basic Business	$	34.4	$	24.0
Aging Infrastructure		23.8		15.5
Load Growth		15.1		17.8
Total CL&P		73.3		57.3
PSNH:
Basic Business		6.9		5.3
Aging Infrastructure		4.7		4.0
Load Growth		5.6		5.1
Total PSNH		17.2		14.4
WMECO:
Basic Business		4.0		3.2
Aging Infrastructure		2.4		2.1
Load Growth		1.4		-
Total WMECO		7.8		5.3
Totals - Electric Distribution (excluding Generation)		98.3		77.0
Yankee Gas		16.0		7.0
Other		0.4		-
Total Distribution		114.7		84.0
PSNH Generation:
Clean Air Project		24.4		32.0
Other		1.7		2.7
Total PSNH Generation		26.1		34.7
WMECO Generation		0.3		-
Total Distribution Segment	$	141.1	$	118.7

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

PSNH's Clean Air Project is a wet scrubber project under construction at its Merrimack coal station, the cost of which will be recovered through PSNH's ES rates under New Hampshire law.  We expect the project to cost approximately $430 million, including capitalized interest and equity returns, and the project should be fully complete by mid-2012.  The project is currently ahead of schedule and we believe a significant portion could be operational by the end of 2011.  Since inception of the project, PSNH has capitalized $320.9 million associated with this project, of which $24.4 million was capitalized in the first quarter of 2011.  Construction of the project was approximately 82 percent complete as of March 31, 2011.

On August 12, 2009, the DPU approved a stipulation agreement between WMECO and the Massachusetts Attorney General concerning WMECO's proposal, under the Massachusetts Green Communities Act, to install 6 MW of solar energy generation in its service territory at an estimated cost of $41 million by the end of 2012.  In October 2010, WMECO completed construction of a 1.8 MW solar generation facility on a site in Pittsfield, Massachusetts.  The full cost of this project was approximately $9.4 million, all of which WMECO has capitalized as of December 31, 2010.  On January 17, 2011, WMECO announced its selection of a site in Springfield, Massachusetts that could be capable of accommodating up to 4.2 MW of solar generation.  WMECO is also evaluating a 12-acre brownfield site (also located in Springfield) that is capable of accommodating up to 2.2 MW of solar generation.  The major permitting activities for both sites are complete and WMECO believes the 12-acre brownfield site is a more likely candidate for completion during 2011.  Final evaluation and approvals for the brownfield site are underway and, assuming their favorable and timely completion, WMECO would expect to begin construction during the second quarter of 2011.  WMECO is continuing its evaluation of sites suitable for fulfilling the remainder of the 6 MW authorized scope.  

In April 2010, Yankee Gas commenced construction of its WWL Project, a 16-mile natural gas pipeline between Waterbury and Wallingford, Connecticut and the increase of vaporization output of its LNG plant.  The project is expected to cost $57.6 million.  Construction during 2010, which cost $26.6 million, included the completion of Phase I, a seven-mile segment of pipeline connecting the Cheshire and Wallingford distribution systems, and four miles of Phase II.  The remainder of the Phase II pipeline construction (approximately five miles) and the expansion of the vaporization capacity of the LNG facility are expected to be completed by the fourth quarter of 2011.  Construction of the project was 55 percent complete as of March 31, 2011 and is currently on schedule.  Approximately $2.6 million of WWL Project expenditures were capitalized in the first three months of 2011.  

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Strategic Initiatives:  We continue to evaluate a number of development projects that will benefit our customers, some of which are detailed below.  

Over the past three years, we have participated in discussions with other utilities, policymakers, and prospective developers of renewable energy projects in the New England region regarding a framework whereby renewable power projects built in rural areas of northern New England could be connected to the electric load centers of New England.  We believe there are significant opportunities for developers to build wind and biomass projects in northern New England that could help the region meet its renewable portfolio standards.  We believe that a collaborative approach among project developers and transmission owners is necessary to be able to construct needed projects and bring their electrical output into the market.  We have not yet included any capital expenditures associated with potential projects in our five-year capital program and these discussions are continuing.  

On March 31, 2010, CL&P filed with the DPUC an AMI and dynamic pricing plan that included a cost benefit analysis.  CL&P concluded that a full deployment of AMI meters accompanied by dynamic pricing options for all CL&P customers would be cost beneficial under a set of reasonable assumptions, identified as the "base case scenario."  Under the base case scenario, capital expenditures associated with the installation of the meters are now estimated at $257 million, down from our previously announced estimate of $296 million.  Under CL&P's proposal, installation of meters would begin after national interoperability standards are promulgated, which is expected to be in late 2012.  Installation will take approximately four years.  The DPUC procedural review began in late October 2010.  CL&P expects the DPUC to issue a decision on the proposal in the next several months.  

Transmission Rate Matters

Transmission - Wholesale Rates:  NU's transmission rates recover total transmission revenue requirements, ensuring that we recover all regional and local revenue requirements.  These rates provide for annual true-ups to actual costs.  The financial impacts of differences between billed and actual costs are deferred for future recovery from, or refund to, customers.  As of March 31, 2011, NU was in a total overrecovery position of $47.3 million ($40.8 million for CL&P, $3.1 million for PSNH, and $3.4 million for WMECO), of which $41.6 million ($38.2 million for CL&P, $2.9 million for PSNH and $0.5 million for WMECO) will be refunded to customers in June 2011.

Legislative Matters

2010 Connecticut Legislation:   In May 2010, the Connecticut Legislature approved a state budget for the 2010-2011 fiscal year, which calls for the issuance by the state of Connecticut of up to $760 million of economic recovery revenue bonds that would be repaid over eight years.  On September 29, 2010, the DPUC approved a financing order for the bonds.  A lawsuit filed by a state senator against the DPUC seeks to prevent the issuance of these bonds.  By order dated December 21, 2010, the trial court dismissed the state senator’s suit on jurisdictional grounds, and the state senator appealed that order to the Connecticut Appellate Court, which then transferred the case to the Connecticut Supreme Court.  Arguments before the Connecticut Supreme Court were held in March 2011, but no decision has yet been issued.  In addition, several bills have been introduced by the state senator and other state lawmakers to rescind the law authorizing these bonds.  The revenues, interest expense and amortization expense associated with these bonds, should they be issued, will not be reflected on CL&P’s financial statements.

Regulatory Developments and Rate Matters

Regulatory Approvals on Proposed Merger with NSTAR:

Federal:  On January 4, 2011, we received approval from the FCC, and on February 10, 2011, the applicable Hart-Scott-Rodino waiting period expired.  On January 7, 2011, NU and NSTAR filed an application with the FERC, requesting approval of the merger by May 10, 2011.  An application was filed with the Nuclear Regulatory Commission in December 2010.  

Massachusetts:  On November 24, 2010, NU and NSTAR filed a joint petition requesting the DPU’s approval of their proposed merger.  On March 10, 2011, the DPU issued an order that modified the standard of review to be applied in the review of mergers involving Massachusetts utilities from a "no net harm" standard to a "net benefits" standard, meaning that the companies must demonstrate that the proposed transaction provides benefits that outweigh the costs.  Applicable state law provides that mergers of Massachusetts utilities and their respective holding companies must be "consistent with the public interest."  The order states that the DPU will continue to flexibly apply the factors established by case law and statute.  NU and NSTAR filed supplemental testimony and a net benefit analysis with the DPU on April 8, 2011, indicating the merger could save the combined company up to $780 million over the first 10 years following the merger and provide other customer benefits.  We used October 1, 2011 in the development of our net benefit study that we filed with the DPU.  Evidentiary hearings are scheduled to begin on July 6, 2011.  We expect a ruling from the DPU in the second half of 2011.

Connecticut:  In November 2010, the DPUC issued a draft decision stating that it lacked jurisdiction over the merger.  In December 2010, the Connecticut Office of Consumer Counsel, supported by the Connecticut Attorney General, petitioned the DPUC to reconsider its draft decision.  In January 2011, the DPUC issued an Administrative Order stating that it would hold a hearing to determine if it had jurisdiction over the merger.  Oral arguments surrounding the draft decision were held in February 2011 and the DPUC held a public information session in March 2011.  No date has been established for a final decision.  In addition, legislation proposing to give the DPUC jurisdiction over certain types of transactions, including the merger, received a joint favorable recommendation from the Connecticut Joint Legislative Energy and Technology Committee in March 2011.

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New Hampshire:  On April 5, 2011, the NHPUC issued an order finding that it does not have jurisdiction over the merger.

Maine:  We have asked Maine regulators alternatively to waive jurisdiction over the merger or to approve the merger.  Although neither NU nor NSTAR subsidiaries serve any retail customers in Maine, PSNH owns transmission assets in the state that are subject to the jurisdiction of the Maine Public Utilities Commission.  On April 15, 2011, a Hearing Examiner issued a report rejecting the waiver request, but approving the merger contingent upon approval by the FERC.  The Maine Public Utilities Commission will deliberate on the Hearing Examiner’s report on May 10, 2011.

Federal:

EPA Proposed Air Toxic Standard:  On March 16, 2011, the EPA issued a proposed rule that would reduce emissions of hazardous air pollutants from new and existing coal- and oil- fired electric generating units.  The proposed rule would establish emission limits for mercury, arsenic and other hazardous air pollutants from coal- and oil-fired units.  The proposed rule is the first to implement a nationwide emissions standard for hazardous air pollutants across all electric generating units, providing them up to four years to meet the requirements.  PSNH owns and operates approximately 1,200 MW of electric generating units, most of which use fossil fuels subject to this proposed rule, including the Merrimack, Newington and Schiller stations.  We believe the Clean Air Project at our Merrimack coal station, in addition to existing technology, positions the facility to meet the minimum requirements in the proposed rule.  A review of the potential impact of this proposal on our other PSNH units is not yet complete.  The EPA is expected to hold public hearings on the proposal, but hearings have not yet been scheduled.  The EPA expects the proposed ruling will be finalized in late 2011.

Connecticut - CL&P:

Standard Service and Last Resort Service Rates:  CL&P's residential and small commercial customers who do not choose competitive suppliers are served under SS rates, and large commercial and industrial customers who do not choose competitive suppliers are served under LRS rates.  CL&P is fully recovering from customers the costs of its SS and LRS services.  Effective January 1, 2011, the DPUC approved a decrease to CL&P’s total average SS rate of approximately 7.8 percent and a slight increase to CL&P’s total average LRS rate of approximately 0.8 percent.  The energy supply portion of the total average SS rate decreased from 11.282 cents per KWh to 9.732 cents per KWh while the energy supply portion of the total average LRS rate increased from 7.062 cents per KWh to 7.193 cents per KWh.  Effective April 1, 2011, the DPUC approved a slight decrease to CL&P’s total average LRS rate of approximately 0.1 percent that included a decrease in the energy supply portion of the rate from 7.193 cents per KWh to 7.181 cents per KWh.  

CTA and SBC Reconciliation:   On March 31, 2011, CL&P filed with the DPUC its 2010 CTA and SBC reconciliation, which compared CTA and SBC revenues to revenue requirements.  For the 12 months ended December 31, 2010, total CTA revenue requirements exceeded CTA revenues by $4.5 million.  For the 12 months ended December 31, 2010, the SBC revenues exceeded SBC revenue requirements by $19.8 million.  We expect a decision in this docket from the DPUC by the end of 2011 and we do not expect the outcome to have a material adverse impact on CL&P’s financial position, results of operations or cash flows.  

FMCC Filing:  On February 4, 2011, CL&P filed with the DPUC its semi-annual filing, which reconciled actual FMCC revenues and charges and GSC revenues and expenses, for the period July 1, 2010 through December 31, 2010, and also included the previously filed revenues and expenses for the January 1, 2010 through June 30, 2010 period.  The filing identified a total net overrecovery of $0.3 million, which includes the remaining uncollected portions from previous filings.  DPUC hearings and a decision on this filing are expected to take place during the second quarter of 2011.  We do not expect the outcome of the DPUC's review of this filing to have a material adverse impact on CL&P's financial position, results of operations or cash flows.

Connecticut - Yankee Gas

Distribution Rates:  On January 7, 2011, Yankee Gas filed an application with the DPUC to increase its distribution rates by $32.8 million to be effective July 1, 2011, and by an additional $13 million to be effective July 1, 2012.  Among other items, Yankee Gas requested to maintain its current authorized regulatory ROE of 10.1 percent, that $57.6 million of costs associated with the WWL Project be placed into rates, and that an increase from $15 million to $40 million in capital funding to replace bare steel and cast iron pipe throughout its natural gas distribution system be authorized.  On March 25, 2011, primarily as a result of the accelerated depreciation provisions of the 2010 Tax Act, Yankee Gas filed a revision to its application in which it lowered its first year rate increase request to $29.1 million and its second year request to $10.3 million.  Hearings concluded on April 19, 2011 with briefs and reply briefs filed thereafter.  A final decision on Yankee Gas’ rate application is due on June 22, 2011.

New Hampshire:

Distribution Rates:  In March 2011, PSNH filed to collect certain exogenous costs, step increases, and storm costs, as permitted by the 2010 rate case settlement.  Together with the scheduled termination of recoupment charges, also from the rate case settlement, PSNH's proposed rate change effective July 1, 2011 is a $3.6 million decrease.

ES and SCRC Reconciliation:  On an annual basis, PSNH files with the NHPUC an ES/SCRC cost reconciliation filing for the preceding year.  On April 29, 2011, the NHPUC approved a settlement between PSNH and the NHPUC staff regarding PSNH’s 2009 ES/SCRC reconciliation filing.  The settlement did not have a material impact on PSNH's financial position, results of operations or cash flows.  On May 2, 2011, PSNH filed its 2010 ES/SCRC reconciliation with the NHPUC, whose evaluation includes a prudence review of PSNH's generation and power purchase activities.  As of December 31, 2010, PSNH had an ES regulatory asset of $14.7 million, which is being

51

recovered from customers in 2011.  As of December 31, 2010, PSNH had an SCRC regulatory obligation of $2.4 million, which is being refunded to customers in 2011.    

Merrimack Clean Air Project:  On July 7, 2009, the New Hampshire Site Evaluation Committee determined that PSNH's Clean Air Project to install wet scrubber technology at its Merrimack Station was not subject to the Committee's review as a "sizeable" addition to a power plant under state law.  That Committee upheld its decision in an order dated January 15, 2010, denying requests for rehearing.  This order was appealed on February 23, 2010.  On April 15, 2010, the New Hampshire Supreme Court determined that it would accept the appeal.  Briefs have been filed and the Court held oral arguments in March 2011.  We do not believe that the appeal will have a material impact on the timing or costs of the project.  

Massachusetts:  

Distribution Rates:  On July 16, 2010, WMECO filed an application with the DPU, requesting approval of a $28.4 million increase in distribution rates and a decoupling plan to be effective February 1, 2011.  Among other items, WMECO sought a distribution segment regulatory ROE of 10.5 percent, recovery over five years of its remaining deferred December 2008 and 2010 major storm costs and recovery of its hardship receivable costs.  On January 31, 2011, the DPU issued a final decision approving an annualized rate increase of $16.8 million effective February 1, 2011, an authorized distribution segment regulatory ROE of 9.6 percent, a decoupling plan with no inflation adjustment, recovery of certain 2008 and 2010 major storm costs over five years, and recovery of certain hardship receivable costs.  

Basic Service Rates:  Effective January 1, 2011, the rates for all basic service customers changed to reflect the basic service solicitations conducted by WMECO in November 2010.  Fixed basic service rates for residential customers decreased to 6.993 cents per KWh, rates for small commercial and industrial customers decreased to 8.006 cents per KWh and rates for large commercial and industrial customers decreased to 7.405 cents per KWh.  The fixed price increased by 0.063 cents per KWh for street lighting customers to 5.822 cents per KWh.  Effective April 1, 2011, the rates for medium and large commercial and industrial customers decreased to 6.958 cents per kWh.  

Critical Accounting Policies and Estimates Update

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 our Audit Committee of the Board of Trustees all critical accounting policies and estimates.  The accounting policies and estimates that we believed were the most critical in nature were reported in our 2010 Form 10-K.  There have been no material changes with regard to these critical accounting policies and estimates.  

Other Matters

Environmental Matters:  Refer to Note 7A, "Commitments and Contingencies – Environmental Matters," to the unaudited condensed consolidated financial statements for discussion of the HWP environmental remediation contingency.

Contractual Obligations and Commercial Commitments:  There have been no additional contractual obligations identified and no material changes with regard to the contractual obligations and commercial commitments previously disclosed in our 2010 Form 10-K.

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

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RESULTS OF OPERATIONS – NORTHEAST UTILITIES AND SUBSIDIARIES

The following table provides the amounts and variances in operating revenues and expense line items for the unaudited condensed consolidated statements of income for NU included in this Quarterly Report on Form 10-Q for the three months ended March 31, 2011 and 2010:

	Revenues and Expenses For the Three Months Ended March 31,
(Millions of Dollars)	2011		2010		Increase/ (Decrease)		Percent
Operating Revenues	$	1,235.3	$	1,339.4	$	(104.1)	(7.8)	%
Operating Expenses:
Fuel, Purchased and Net Interchange Power		474.1		603.3		(129.2)	(21.4)
Other Operating Expenses		252.0		248.2		3.8	1.5
Maintenance		67.8		45.6		22.2	48.7
Depreciation		73.9		78.7		(4.8)	(6.1)
Amortization of Regulatory Assets/(Liabilities), Net		34.4		(8.3)		42.7	(a)
Amortization of Rate Reduction Bonds		17.3		59.6		(42.3)	(71.0)
Taxes Other Than Income Taxes		88.4		85.6		2.8	3.3
Total Operating Expenses		1,007.9		1,112.7		(104.8)	(9.4)
Operating Income	$	227.4	$	226.7	$	0.7	0.3	%

(a)

Percent greater than 100 percent not shown as it is not meaningful.

Operating Revenues

	For the Three Months Ended March 31,
(Millions of Dollars)	2011		2010		Increase/ (Decrease)		Percent
Electric Distribution	$	891.6	$	1,000.0	$	(108.4)	(10.8)	%
Natural Gas Distribution		180.2		171.7		8.5	5.0
Total Distribution		1,071.8		1,171.7		(99.9)	(8.5)
Transmission		158.2		153.7		4.5	2.9
Total Regulated Companies		1,230.0		1,325.4		(95.4)	(7.2)
Other and Eliminations		5.3		14.0		(8.7)	(62.1)
NU	$	1,235.3	$	1,339.4	$	(104.1)	(7.8)	%

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

	For the Three Months Ended March 31,
	2011	2010	Increase	Percent
Retail Electric Sales in GWh	8,705	8,448	257	3.0	%
Firm Natural Gas Sales in Million Cubic Feet	19,384	16,589	2,795	16.9	%
Firm Natural Gas Sales (Net of Special  Contracts) in Million Cubic Feet	16,940	14,247	2,693	18.9	%

Our Operating Revenues decreased in the first quarter of 2011, as compared to the first quarter of 2010, due primarily to:

·

Lower electric distribution revenues related to the portions that are included in regulatory commission approved tracking mechanisms that recover certain incurred costs and do not impact earnings.  The tracked electric distribution revenues decreased due primarily to lower energy and supply-related costs ($110 million), lower CL&P CTA revenues ($39 million) and lower wholesale revenues ($17 million), partially offset by higher retail transmission revenues ($17 million).  The tracking mechanisms allow for rates to be changed periodically with overcollections refunded to customers or undercollections recovered from customers in future periods.  In addition, Regulated companies' revenues that eliminate in consolidation decreased by $11 million.

·

The portion of electric distribution revenues that impacts earnings increased $55 million due primarily to Regulated companies’ rate case decisions that were effective during the first quarter of 2011 and a 3 percent increase in retail electric sales volume related to colder than normal weather in the first quarter of 2011.  An increase in natural gas revenues was due primarily to an increase in sales volume related to the colder than normal weather in 2011.  Firm natural gas sales increased 16.9 percent in the first quarter of 2011 compared to the first quarter of 2010.  Offsetting these benefits was a decrease in cost of fuel.  These fuel costs are fully recovered in revenues from sales to our customers.  

·

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

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Fuel, Purchased and Net Interchange Power

Fuel, Purchased and Net Interchange Power decreased in the first quarter of 2011, as compared to the first quarter of 2010, due primarily to the following:

(Millions of Dollars)
Lower GSC supply costs and purchased power contract costs,   partially offset by higher other costs at CL&P	$ (107.4)
An increased level of ES customer migration to third party  electric suppliers, partially offset by higher retail sales at   PSNH	(16.7)
Lower basic service supply costs at WMECO	(3.4)
Decrease in expenses due primarily to higher unregulated   business wholesale contract mark-to-market gains and other	(1.7)
	$ (129.2)

Maintenance

Maintenance increased in the first quarter of 2011, as compared to the first quarter of 2010, due primarily to the partial amortization in 2011 of the allowed regulatory deferral, which was recorded in maintenance expense in 2010, as a result of the June 30, 2010 CL&P rate case decision ($11 million) and higher distribution segment routine overhead line expenses ($14 million) primarily related to storm costs that did not meet the minimum requirement for regulatory deferral, offset by lower maintenance costs at PSNH’s generation business ($2 million).

Depreciation

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

Amortization of Regulatory Assets/(Liabilities), Net

Amortization of Regulatory Assets/(Liabilities), Net, increased in the first quarter of 2011, as compared to the first quarter of 2010, due primarily to the absence in 2011 of the impact of the 2010 Healthcare Act related to income taxes ($24 million), lower CTA transition costs ($57 million) partially offset by lower retail CTA revenue ($37 million) at CL&P and increases in ES amortization ($14 million) and TCAM ($3 million) at PSNH.  Partially offsetting these increases was lower amortization related to the previously deferred unrecovered stranded generation costs related to income taxes at CL&P ($10 million).

Amortization of Rate Reduction Bonds

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

Interest Expense  

	For the Three Months Ended March 31,
(Millions of Dollars)	2011		2010		Increase/ (Decrease)		Percent
Interest on Long-Term Debt	$	57.4	$	57.3	$	0.1	0.2	%
Interest on RRBs		2.5		6.7		(4.2)	(62.7)
Other Interest		(1.4)		3.3		(4.7)	(a)
	$	58.5	$	67.3	$	(8.8)	(13.1)	%

(a)

Percent greater than 100 percent not shown as it is not meaningful.  

Interest Expense decreased in the first quarter of 2011, as compared to the first quarter of 2010, due primarily to various tax matters in the first quarter of 2011, which resulted in a reduction in Other Interest.  There was also lower Interest on RRBs resulting from the maturity of CL&P’s RRBs in December 2010 and lower principal balances on the remaining PSNH and WMECO RRBs outstanding.

Other Income, Net

	For the Three Months Ended March 31,
(Millions of Dollars)	2011		2010		Increase		Percent
Other Income, Net	$	10.3	$	8.1	$	2.2	27.2	%

Other Income, Net increased in the first quarter of 2011, as compared to the first quarter of 2010, due primarily to higher AFUDC related to equity funds ($2 million) and higher investment and interest income ($1 million), offset by lower EIA incentives ($1 million).

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Income Tax Expense

	For the Three Months Ended March 31,
(Millions of Dollars)	2011		2010		Decrease		Percent
Income Tax Expense	$	63.5	$	79.9	$	(16.4)	(20.5)	%

Income Tax Expense decreased in the first quarter of 2011, as compared to the first quarter of 2010, due primarily to the absence in 2011 of the impact of the 2010 Healthcare Act ($27 million) and an increase in the items that directly impact our tax return as a result of regulatory requirements ("flow-through" items) ($2 million), partially offset by higher pre-tax earnings ($15 million).  

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

The following table provides the amounts and variances in operating revenues and expense line items for the unaudited condensed consolidated statements of income for CL&P included in this Quarterly Report on Form 10-Q for the three months ended March 31, 2011 and 2010:

	Revenues and Expenses For the Three Months Ended March 31,
(Millions of Dollars)	2011		2010		Increase/ (Decrease)		Percent
Operating Revenues	$	673.7	$	795.0	$	(121.3)	(15.3)	%
Operating Expenses:
Fuel, Purchased and Net Interchange Power		255.4		362.8		(107.4)	(29.6)
Other Operating Expenses		134.2		134.9		(0.7)	(0.5)
Maintenance		40.8		21.8		19.0	87.2
Depreciation		39.5		47.5		(8.0)	(16.8)
Amortization of Regulatory Assets, Net		19.3		1.7		17.6	(a)
Amortization of Rate Reduction Bonds		-		43.3		(43.3)	(100.0)
Taxes Other Than Income Taxes		58.5		57.5		1.0	1.7
Total Operating Expenses		547.7		669.5		(121.8)	(18.2)
Operating Income	$	126.0	$	125.5	$	0.5	0.4	%

(a)

Percent greater than 100 percent not shown as it is not meaningful.

Operating Revenues

CL&P's retail electric sales were as follows:

	For the Three Months Ended March 31,
	2011	2010	Increase	Percent
Retail Electric Sales in GWh	5,776	5,591	185	3.3	%

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

·

A $160 million decrease in electric distribution revenues related to the portions that are included in DPUC approved tracking mechanisms that track and recover certain incurred costs that do not impact earnings.  The tracked electric distribution revenues decreased due primarily to lower GSC and supply-related FMCC revenues ($97 million), lower CTA revenues ($39 million), lower wholesale revenues ($18 million) and lower retail other revenues ($9 million).  In addition, transmission segment intracompany billings to the distribution segment that are eliminated in consolidation decreased distribution revenues by $7 million.  These lower revenues were partially offset by higher retail transmission revenues ($11 million).  The tracking mechanisms allow for rates to be changed periodically with overcollections refunded to customers or undercollections recovered from customers in future periods.  The lower GSC and supply-related FMCC revenues were due primarily to lower customer rates resulting from lower average supply prices and additional customer migration to third party electric suppliers in the first quarter of 2011, as compared to the first quarter of 2010.

·

The portion of electric distribution revenues that impacts earnings increased $38 million due primarily to the retail rate increase effective January 1, 2011 and higher sales volume related to the colder than normal weather in the first quarter of 2011.  Retail electric sales volume increased 3.3 percent in the first quarter of 2011, as compared to the first quarter of 2010.  

Fuel, Purchased and Net Interchange Power

Fuel, Purchased and Net Interchange Power decreased in the first quarter of 2011, as compared to the first quarter of 2010, due primarily to the following:

(Millions of Dollars)	Increase/(Decrease)
GSC Supply Costs	$ (102.0)
Purchased Power Contract Costs	(18.2)
Deferred Fuel Costs	9.5
Other	3.3
	$ (107.4)

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

56

Maintenance

Maintenance increased in the first quarter of 2011, as compared to the first quarter of 2010, due primarily to the partial amortization in 2011 of the allowed regulatory deferral, which was recorded in maintenance expense in 2010, as a result of the June 30, 2010 rate case decision ($11 million) and higher distribution segment routine overhead line expenses ($7 million) primarily related to storm costs that did not meet the minimum requirement for regulatory deferral.

Depreciation

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

Amortization of Regulatory Assets, Net

Amortization of Regulatory Assets, Net, increased in the first quarter of 2011, as compared to the first quarter of 2010, due primarily to lower CTA transition costs ($57 million) partially offset by lower retail CTA revenue ($37 million), and the absence in 2011 of the impact of the 2010 Healthcare Act related to income taxes ($14 million).  Partially offsetting these increases is lower amortization related to the previously deferred unrecovered stranded generation costs related to income taxes ($10 million) and lower amortization of the SBC balance ($4 million).

Amortization of Rate Reduction Bonds

Amortization of RRBs decreased in the first quarter of 2011, as compared to the first quarter of 2010, due to the maturity of RRBs in December 2010.

Interest Expense

	For the Three Months Ended March 31,
(Millions of Dollars)	2011		2010		Decrease		Percent
Interest on Long-Term Debt	$	33.3	$	33.6	$	(0.3)	(0.9)	%
Interest on RRBs		-		3.0		(3.0)	(100.0)
Other Interest		(3.5)		1.9		(5.4)	(a)
	$	29.8	$	38.5	$	(8.7)	(22.6)	%

(a)

Percent greater than 100 percent not shown as it is not meaningful.

Interest Expense decreased in the first quarter of 2011, as compared to the first quarter of 2010, due primarily to various tax matters in the first quarter of 2011, which resulted in a reduction in Other Interest and the absence of Interest on RRBs in 2011 as CL&P's RRBs matured in December 2010.

Other Income, Net

	For the Three Months Ended March 31,
(Millions of Dollars)	2011		2010		Decrease		Percent
Other Income, Net	$	4.6	$	4.9	$	(0.3)	(6.1)	%

Other Income, Net decreased in the first quarter of 2011, as compared to the first quarter of 2010, due primarily to lower EIA incentives ($1 million), offset by higher AFUDC related to equity funds and higher investment and interest income ($1 million).

Income Tax Expense

	For the Three Months Ended March 31,
(Millions of Dollars)	2011		2010		Decrease		Percent
Income Tax Expense	$	36.5	$	43.5	$	(7.0)	(16.1)	%

Income Tax Expense decreased in the first quarter of 2011, as compared to the first quarter of 2010, due primarily to the absence in 2011 of the impact of the 2010 Healthcare Act ($15 million), partially offset by higher pre-tax earnings ($7 million).  

LIQUIDITY

CL&P had cash flows provided by operating activities in the first quarter of 2011 of $205 million, compared with operating cash flows of $73.2 million in the first quarter of 2010 (first quarter 2010 amounts are net of RRB payments, which are included in financing activities).  The increase in cash flows in 2011 was due primarily to a decrease in income tax payments largely attributable to accelerated depreciation tax benefits.  Further increasing CL&P’s cash flows from operations was the impact of the DPUC June 30, 2010 rate case decision, which increased CL&P’s customer rates effective January 1, 2011.  We continue to project cash flows provided by operating activities at CL&P of between $600 million and $650 million in 2011.  The increase over 2010 is due primarily to the cash flow benefits from the 2010 Tax Act.

As of March 31, 2011, CL&P had short-term borrowings of $10 million under the $400 million joint unsecured revolving credit facility it maintains with PSNH, WMECO and Yankee Gas, under which CL&P can borrow up to $300 million.  The weighted-average interest rate on the short-term borrowings as of March 31, 2011 was 2.025 percent, which is based on a variable rate plus an applicable margin

57

based on CL&P’s credit ratings.  Other financing activities for the three months ended March 31, 2011 included $19 million in NU Money Pool borrowings, offset by $131.5 million in common dividends paid to NU parent.  

On April 1, 2011, CL&P remarketed $62 million of tax-exempt secured PCRBs that were subject to a mandatory tender.  The PCRBs, which mature on May 1, 2031, now carry a coupon rate of 1.25 percent, compared with 1.4 percent for the previous 12 month period ending March 31, 2010, and have a mandatory tender on April 1, 2012, at which time CL&P expects to remarket the bonds.

Cash capital expenditures included on the accompanying unaudited condensed consolidated statements of cash flows do not include amounts incurred on capital projects but not yet paid, cost of removal, the AFUDC related to equity funds, and the capitalized portions of pension and PBOP expense or income.  CL&P's cash capital expenditures totaled $106.8 million for the three months ended March 31, 2011, compared with $97.7 million for the three months ended March 31, 2010.  

58

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

The following table provides the amounts and variances in operating revenues and expense line items for the unaudited condensed consolidated statements of income for PSNH included in this Quarterly Report on Form 10-Q for the three months ended March 31, 2011 and 2010:

	Revenues and Expenses For the Three Months Ended March 31,
(Millions of Dollars)	2011		2010		Increase/ (Decrease)		Percent
Operating Revenues	$	269.5	$	258.6	$	10.9	4.2	%
Operating Expenses:
Fuel, Purchased and Net Interchange Power		87.1		103.8		(16.7)	(16.1)
Other Operating Expenses		56.5		63.1		(6.6)	(10.5)
Maintenance		18.7		16.0		2.7	16.9
Depreciation		17.9		16.0		1.9	11.9
Amortization of Regulatory Assets/(Liabilities), Net		15.6		(5.7)		21.3	(a)
Amortization of Rate Reduction Bonds		13.1		12.4		0.7	5.6
Taxes Other Than Income Taxes		13.7		13.1		0.6	4.6
Total Operating Expenses		222.6		218.7		3.9	1.8
Operating Income	$	46.9	$	39.9	$	7.0	17.5	%

(a)

Percent greater than 100 percent not shown as it is not meaningful.

Operating Revenues

PSNH's retail electric sales were as follows:

	For the Three Months Ended March 31,
	2011	2010	Increase	Percent
Retail Electric Sales in GWh	1,984	1,932	52	2.7	%

PSNH's Operating Revenues increased in the first quarter of 2011, as compared to the first quarter of 2010, due primarily to:

·

A $4 million decrease in distribution revenues that did not impact earnings.  Of this decrease, $8 million related to a lower recovery of purchased fuel and power costs, mostly related to ES customer migration to third party electric suppliers.  These lower revenues were offset by higher retail transmission revenues ($6 million) and higher wholesale revenues ($2 million).  The tracking mechanisms allow for rates to be changed periodically with overcollections refunded to customers and undercollections to be recovered from customers in future periods.  In addition, transmission segment intracompany billings to the distribution segment that are eliminated in consolidation decreased distribution revenues by $4 million.  

·

The portion of electric distribution revenues that impacts earnings increased $13 million due primarily to the retail rate increase effective July 1, 2010 and higher sales volume related to the colder than normal weather in the first quarter of 2011.  Retail electric sales volume increased 2.7 percent in the first quarter of 2011 compared to the first quarter of 2010.

·

A $2 million improvement in transmission segment revenues resulting from a higher level of investment in this segment and the return of higher overall expenses, which are tracked and result in a related increase in revenues.  The increase in expenses is directly related to the increase in transmission plant, including costs associated with higher property taxes, depreciation and operation and maintenance expenses.  

Fuel, Purchased and Net Interchange Power

Fuel, Purchased and Net Interchange Power decreased in the first quarter of 2011, as compared to the first quarter of 2010, due primarily to an increased level of ES customer migration to third party electric suppliers, partially offset by higher retail sales.  

Other Operating Expenses

Other Operating Expenses decreased in the first quarter of 2011, as compared to the first quarter of 2010, as a result of lower distribution segment expenses ($5 million), mainly as a result of lower administrative and general expenses ($2 million) and lower retail transmission expenses ($1 million).  

Maintenance

Maintenance increased in the first quarter of 2011, as compared to the first quarter of 2010, due primarily to higher distribution segment routine overhead line expenses ($6 million) primarily related to storm costs that did not meet the minimum requirement for regulatory deferral, offset by lower generation maintenance costs ($2 million) and lower vegetation management costs ($1 million).

59

Depreciation

Depreciation increased in the first quarter of 2011, as compared to the first quarter of 2010, due primarily to a higher depreciation rate being used at PSNH as a result of the distribution rate case decision that was effective July 1, 2010 and higher utility plant balances resulting from completed construction projects placed into service related to PSNH's capital programs.

Amortization of Regulatory Assets/(Liabilities), Net

Amortization of Regulatory Assets/(Liabilities), Net increased in the first quarter of 2011, as compared to the first quarter of 2010, due primarily to increases in ES amortization ($14 million) and the TCAM ($3 million) and the absence in 2011 of the impact of the 2010 Healthcare Act related to income taxes ($5 million).  

Interest Expense

	For the Three Months Ended March 31,
(Millions of Dollars)	2011		2010		Decrease		Percent
Interest on Long-Term Debt	$	8.6	$	9.5	$	(0.9)	(9.5)	%
Interest on RRBs		1.9		2.7		(0.8)	(29.6)
Other Interest		-		0.2		(0.2)	(100.0)
	$	10.5	$	12.4	$	(1.9)	(15.3)	%

Interest Expense decreased in the first quarter of 2011, as compared to first quarter of 2010 due primarily to lower Interest on Long-Term Debt due to higher AFUDC borrowed funds related to PSNH's Clean Air Project and lower Interest on RRBs resulting from lower principal balances outstanding.   

Other Income, Net

	For the Three Months Ended March 31,
(Millions of Dollars)	2011		2010		Increase		Percent
Other Income, Net	$	4.5	$	2.4	$	2.1	87.5	%

Other Income, Net increased in the first quarter of 2011, as compared to the first quarter of 2010, due primarily to higher AFUDC equity funds related to PSNH's Clean Air Project ($2 million).

Income Tax Expense

	For the Three Months Ended March 31,
(Millions of Dollars)	2011		2010		Decrease		Percent
Income Tax Expense	$	13.5	$	14.1	$	(0.6)	(4.3)	%

Income Tax Expense decreased in the first quarter of 2011, as compared to the first quarter of 2010, due primarily to the absence in 2011 of the impact of the 2010 Healthcare Act ($6 million), partially offset by higher pre-tax earnings ($5 million).  

LIQUIDITY

PSNH had cash flows provided by operating activities in the first quarter of 2011 of $126.9 million, compared with operating cash flows of $60.7 million in the first quarter of 2010 (amounts are net of RRB payments, which are included in financing activities).  The increase in cash flows in 2011 was due primarily to the impact of the NHPUC June 28, 2010 rate case settlement, which increased PSNH customer rates effective July 1, 2010.  Further increasing PSNH’s cash flows from operations was a decrease in income tax payments largely attributable to accelerated depreciation tax benefits.  In addition, PSNH recognized benefits within the ES tracking mechanism where such revenues exceeded costs in the first quarter of 2011 creating a favorable cash flow impact.

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RESULTS OF OPERATIONS – WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY

The following table provides the amounts and variances in operating revenues and expense line items for the unaudited condensed consolidated statements of income for WMECO included in this Quarterly Report on Form 10-Q for the three months ended March 31, 2011 and 2010:

	Revenues and Expenses For the Three Months Ended March 31,
(Millions of Dollars)	2011		2010		Increase/ (Decrease)		Percent
Operating Revenues	$	106.7	$	100.2	$	6.5	6.5	%
Operating Expenses:
Fuel, Purchased and Net Interchange Power		40.2		43.6		(3.4)	(7.8)
Other Operating Expenses		26.2		23.3		2.9	12.4
Maintenance		4.8		4.5		0.3	6.7
Depreciation		6.3		6.0		0.3	5.0
Amortization of Regulatory Liabilities, Net		(0.6)		(1.6)		1.0	62.5
Amortization of Rate Reduction Bonds		4.2		3.9		0.3	7.7
Taxes Other Than Income Taxes		4.5		4.1		0.4	9.8
Total Operating Expenses		85.6		83.8		1.8	2.1
Operating Income	$	21.1	$	16.4	$	4.7	28.7	%

Operating Revenues

WMECO's retail electric sales were as follows:

	For the Three Months Ended March 31,
	2011	2010	Increase	Percent
Retail Electric Sales in GWh	948	930	18	2.0	%

WMECO's Operating Revenues increased in the first quarter of 2011, as compared to the first quarter of 2010, due primarily to:

·

Amounts related to distribution revenues that did not impact earnings and are included in DPU approved tracking mechanisms that track the recovery of certain incurred costs through WMECO's tariffs decreased slightly in the first quarter of 2011 compared to the first quarter of 2010.  Included in these amounts are C&LM collections, pension and other trackers.  These tracking mechanisms allow for rates to be changed periodically with overcollections refunded to customers or undercollections to be recovered from customers in future periods.

·

The portion of electric distribution revenues that impacts earnings increased $4 million due primarily to the retail rate increase effective February 1, 2011.  Retail electric sales volume increased 2 percent in the first quarter of 2011 compared to the first quarter of 2010, but the impact on distribution revenues was immaterial due to the DPU's approval of a sales and revenue decoupling plan that was also effective February 1, 2011.

·

A $3 million improvement in transmission segment revenues resulting from a higher level of investment in this segment and the return of higher overall expenses, which are tracked and result in a related increase in revenues.  The increase in expenses is directly related to the increase in transmission plant, including costs associated with higher property taxes, depreciation and operation and maintenance expenses.  

Fuel, Purchased and Net Interchange Power

Fuel, Purchased and Net Interchange Power decreased in the first quarter of 2011, as compared to the first quarter of 2010, due primarily to lower basic service supply costs partially offset by a decrease in the deferral of excess basic service expense over basic service revenue.  The basic service supply costs are the contractual amounts WMECO must pay to various suppliers that serve this load after winning a competitive solicitation process.  To the extent these costs do not match revenues collected from customers, the DPU allows the difference to be deferred for future collection or refunded to customers.  The basic service supply costs decreased due primarily to lower supplier contract rates, partially offset by increased load volumes.

Other Operating Expenses

Other Operating Expenses increased in the first quarter of 2011, as compared to the first quarter of 2010, as a result of higher distribution segment expenses resulting from higher costs that are recovered through distribution tracking mechanisms and have no earnings impact primarily related to an increase in C&LM expenses attributable to the Massachusetts Green Communities Act ($3 million).

Maintenance

Maintenance increased in the first quarter of 2011, as compared to the first quarter of 2010, due primarily to higher distribution segment routine overhead line expenses, offset by lower transmission segment routine overhead line expenses.  

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Depreciation

Depreciation increased in the first quarter of 2011, as compared to the first quarter of 2010, due primarily to higher depreciation rate being used at WMECO as a result of the distribution rate case decision that was effective February 1, 2011 and higher utility plant balances resulting from completed construction projects placed into service related to WMECO's capital programs.

Amortization of Regulatory Liabilities, Net

Amortization of Regulatory Liabilities, Net, increased in the first quarter of 2011, as compared to the first quarter of 2010, due primarily to the absence in 2011 of the impact of the 2010 Healthcare Act related to income taxes and an adjustment related to the low income discount recovery deferral as a result of the rate case decision effective February 1, 2011.

Taxes Other Than Income Taxes

The increase in Taxes Other Than Income Taxes was due primarily to an increase in property taxes as a result of an increase in Property, Plant and Equipment related to WMECO's capital programs.

Interest Expense

	For the Three Months Ended March 31,
(Millions of Dollars)	2011		2010		Increase/ (Decrease)		Percent
Interest on Long-Term Debt	$	4.8	$	3.9	$	0.9	23.1	%
Interest on RRBs		0.7		0.9		(0.2)	(22.2)
Other Interest		0.1		0.1		-	-
	$	5.6	$	4.9	$	0.7	14.3	%

Interest Expense increased in the first quarter of 2011, as compared to the first quarter of 2010, due primarily to higher Interest on Long-Term Debt as a result of $95 million in new long-term debt issued in March 2010, offset by lower Interest on RRBs resulting from lower principal balances outstanding.

Other Income, Net

	For the Three Months Ended March 31,
(Millions of Dollars)	2011		2010		Increase		Percent
Other Income, Net	$	0.7	$	0.6	$	0.1	16.7	%

Other Income, Net increased in the first quarter of 2011, as compared to the first quarter of 2010 due to higher AFUDC related to equity funds.

LIQUIDITY

WMECO had cash flows provided by operating activities in the first quarter of 2011 of $27.4 million, compared with cash flows provided by operating activities of $4.8 million in the first quarter of 2010 (amounts are net of RRB payments, which are included in financing activities).  The increase in cash flows in 2011 was due primarily to a decrease in income tax payments largely attributable to accelerated depreciation tax benefits.  Further increasing WMECO’s cash flows from operations was the impact of the DPU rate case decision, which increased WMECO customer rates effective February 1, 2011.

62

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.  The remaining unregulated wholesale portfolio held by Select Energy includes contracts that are market risk-sensitive, including a wholesale energy sales contract through 2013 with an agency comprised of municipalities with approximately 0.1 million remaining MWh of supply contract volumes, net of related sales volumes.  Select Energy also has a non-derivative energy contract that expires in mid-2012 to purchase output from a generation facility, which is also exposed to market price volatility.  As Select Energy's contract volumes are winding down, and as the wholesale energy sales contract is substantially hedged against price risks, we have limited exposure to commodity price risks.  We have not entered into any energy contracts for trading purposes.

Sensitivity analysis provides a presentation of the potential loss of future pre-tax earnings and fair values from our market risk-sensitive contracts due to one or more hypothetical changes in commodity price components, or other similar price changes.  We have provided this analysis in Part II, Item 7A, "Quantitative and Qualitative Disclosures about Market Risk," in our 2010 Form 10-K, which disclosures are incorporated herein by reference.  There have been no additional market or commodity price risks identified and no material changes with regard to the sensitivity analysis previously disclosed in our 2010 Form 10-K.  

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 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.

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 our 2010 Form 10-K, which are incorporated herein by reference. There have been no additional risks identified and no material changes with regard to the items previously disclosed in our 2010 Form 10-K.

For further information on cash collateral deposited and posted with counterparties as well as any cash collateral netted against the fair value of the related derivative contracts, see Note 1E, "Summary of Significant Accounting Policies - Special Deposits and Counterparty Deposits," and Note 4, "Derivative Instruments," to the unaudited condensed consolidated financial statements.  Additional quantitative and qualitative disclosures about market risk are set forth in Part I, Item 2, "Management's Discussion and Analysis of Financial Condition and Results of Operations," included in this Quarterly Report on Form 10-Q.

ITEM 4.

CONTROLS AND PROCEDURES

Management, on behalf of NU, CL&P, PSNH and WMECO, evaluated the design and operation of the disclosure controls and procedures as of March 31, 2011 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, PSNH and WMECO are effective to ensure that information required to be disclosed by us in reports filed under the Securities Exchange Act of 1934 (i) is recorded, processed, summarized, and reported within the time periods specified in SEC rules and regulations and (ii) is accumulated and communicated to management, including the principal executive officers and principal financial officer, as appropriate to allow timely decisions regarding required disclosures.

There have been no changes in internal controls over financial reporting for NU, CL&P, PSNH and WMECO during the quarter ended March 31, 2011 that have materially affected, or are reasonably likely to materially affect, internal controls over financial reporting.  

63

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 2010 Form 10-K, which disclosures are incorporated herein by reference.  Other than as set forth below, there have been no additional legal proceedings identified and no material changes with regard to the legal proceedings previously disclosed in our 2010 Form 10-K.

Litigation Related to the Proposed Merger with NSTAR

In October 2010, NSTAR, the members of the NSTAR board of trustees, NU, and two wholly-owned NU subsidiaries, NU Holding Energy 1 LLC and NU Holding Energy 2 LLC, were named defendants in eight lawsuits (since consolidated) filed in the Superior Court for Suffolk County, Massachusetts, and one lawsuit filed in federal court in the Eastern District of Massachusetts. The lawsuits, each of which was brought by a single shareholder, purported to be brought on behalf of classes of NSTAR shareholders opposed to the terms of the merger agreement and sought, among other things, to enjoin defendants from consummating the merger and either rescission of the merger, to the extent it is completed, or monetary damages.  On February 11, 2011, Plaintiffs moved for preliminary injunction in the Massachusetts lawsuits seeking to enjoin the March 4, 2011 special meeting of NSTAR shareholders scheduled to vote on the merger.  On March 2, 2011, the court denied the Plaintiffs’ motion and the special meetings of NU and NSTAR shareholders went forward as scheduled.  Subsequent to the approval of the merger by shareholders of NU and NSTAR at the March 4, 2011 special meetings, the parties filed a joint motion for voluntary dismissal without prejudice of the Massachusetts lawsuits, which was granted by the court on March 8, 2011.  On March 9, 2011, the Plaintiff filed a Notice of Voluntary Dismissal of the federal lawsuit, effectively terminating all shareholder litigation relating to the merger.  

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 Item 1A, "Risk Factors," in our 2010 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 2010 Form 10-K.

ITEM 2.

UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

There were no purchases made by or on behalf of NU or any "affiliated purchaser" (as defined in Rule 10b-18(a)(3) under the Securities Exchange Act of 1934) of NU common shares during the quarter ended March 31, 2011.

64

ITEM 6.

EXHIBITS

Each document described below is incorporated by reference by the registrant(s) listed to the files identified, unless designated with a (*), which exhibits are filed herewith.  

Exhibit No.

Description

Listing of Exhibits (NU)

*12

Ratio of Earnings to Fixed Charges

15

Independent Registered Public Accounting Firm Letter Regarding Unaudited Financial Information

*15.1

Deloitte & Touche LLP

*15.2

PricewaterhouseCoopers LLP

*31

Certification of Charles W. Shivery, Chairman, President and Chief Executive Officer of Northeast Utilities, 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 May 6, 2011

*31.1

Certification of David R. McHale, Executive Vice President and Chief Financial Officer of Northeast Utilities, 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 May 6, 2011

*32

Certification of Charles W. Shivery, Chairman, President and Chief Executive Officer of Northeast Utilities and David R. McHale, Executive Vice President and Chief Financial Officer of Northeast Utilities, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, dated May 6, 2011

*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

Listing of Exhibits (CL&P)

*12

Ratio of Earnings to Fixed Charges

*31

Certification of Leon J. Olivier, Chief Executive Officer of The Connecticut Light and Power Company, required by Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated May 6, 2011

*31.1

Certification of David R. McHale, Executive Vice President and Chief Financial Officer of The Connecticut Light and Power Company, required by Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated May 6, 2011

*32

Certification of Leon J. Olivier, Chief Executive Officer of The Connecticut Light and Power Company and David R. McHale, Executive Vice President and Chief Financial Officer of The Connecticut Light and Power Company, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, dated May 6, 2011

65

Listing of Exhibits (PSNH)

*12

Ratio of Earnings to Fixed Charges

*31

Certification of Leon J. Olivier, Chief Executive Officer of Public Service Company of New Hampshire, 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 May 6, 2011

*31.1

Certification of David R. McHale, Executive Vice President and Chief Financial Officer of Public Service Company of New Hampshire, 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 May 6, 2011

*32

Certification of Leon J. Olivier, Chief Executive Officer of Public Service Company of New Hampshire and David R. McHale, Executive Vice President and Chief Financial Officer of Public Service Company of New Hampshire, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, dated May 6, 2011

Listing of Exhibits (WMECO)

*12

Ratio of Earnings to Fixed Charges

*31

Certification of Leon J. Olivier, Chief Executive Officer of Western Massachusetts Electric Company, required by Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated May 6, 2011

*31.1

Certification of David R. McHale, Executive Vice President and Chief Financial Officer of Western Massachusetts Electric Company, required by Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated May 6, 2011

*32

Certification of Leon J. Olivier, Chief Executive Officer of Western Massachusetts Electric Company and David R. McHale, Executive Vice President and Chief Financial Officer of Western Massachusetts Electric Company, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, dated May 6, 2011

66

SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.  

		NORTHEAST UTILITIES
		(Registrant)
Date:  May 6, 2011	By	/s/ David R. McHale
		David R. McHale
		Executive Vice President and Chief Financial Officer
		(for the Registrant and as Principal Financial Officer)

SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.  

		THE CONNECTICUT LIGHT AND POWER COMPANY
		(Registrant)
Date:  May 6, 2011	By	/s/ David R. McHale
		David R. McHale
		Executive Vice President and Chief Financial Officer
		(for the Registrant and as Principal Financial Officer)

67

SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.

		PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE
		(Registrant)
Date:  May 6, 2011	By	/s/ David R. McHale
		David R. McHale
		Executive Vice President and Chief Financial Officer
		(for the Registrant and as Principal Financial Officer)

SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.  

		WESTERN MASSACHUSETTS ELECTRIC COMPANY
		(Registrant)
Date:  May 6, 2011	By	/s/ David R. McHale
		David R. McHale
		Executive Vice President and Chief Financial Officer
		(for the Registrant and as Principal Financial Officer)

68