The Connecticut Light and Power Company (CNLTP) 10-Q 2012 FY Quarterly report

________________________________________________________________________________

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

Commission File Number	Registrant; State of Incorporation; Address; and Telephone Number	I.R.S. Employer Identification No.
1-5324	NORTHEAST UTILITIES (a Massachusetts voluntary association) One Federal Street Building 111-4 Springfield, Massachusetts 01105 Telephone:  (413) 785-5871	04-2147929
0-00404	THE CONNECTICUT LIGHT AND POWER COMPANY (a Connecticut corporation) 107 Selden Street Berlin, Connecticut 06037-1616 Telephone:  (860) 665-5000	06-0303850
1-6392	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 registrants have 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 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, 2012
Northeast Utilities Common shares, $5.00 par value	313,604,078 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:
CL&P	The Connecticut Light and Power Company
HWP	HWP Company, formerly the Holyoke Water Power Company
NGS	Northeast Generation Services Company and subsidiaries
NSTAR LLC	NSTAR (Holding company)
NSTAR Electric	NSTAR Electric Company
NSTAR Gas	NSTAR Gas Company
NPT	Northern Pass Transmission LLC
NUTV	NU Transmission Ventures, Inc., the parent company of NPT and Renewable Properties, Inc.
NU or the Company	Northeast Utilities and subsidiaries
NU Enterprises	NU Enterprises, Inc., the parent company of Select Energy, NGS, NGS Mechanical, Select Energy Contracting, Inc. and E.S. Boulos Company
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:
DEEP	Connecticut Department of Energy and Environmental Protection
DOE	U.S. Department of Energy
DPU	Massachusetts Department of Public Utilities
EPA	U.S. Environmental Protection Agency
FERC	Federal Energy Regulatory Commission
MA DEP	Massachusetts Department of Environmental Protection
NHPUC	New Hampshire Public Utilities Commission
PURA	Connecticut Public Utilities Regulatory Authority
SEC	Securities and Exchange Commission
OTHER:
2011 Form 10-K	The Northeast Utilities and Subsidiaries 2011 combined Annual Report on Form 10-K as filed with the SEC
AOCI	Accumulated Other Comprehensive Income/(Loss)
AFUDC	Allowance For Funds Used During Construction
C&LM	Conservation and Load Management
CfD	Contract for Differences
Clean Air Project	The construction of a wet flue gas desulphurization system, known as “scrubber technology,” to reduce mercury emissions of the Merrimack coal-fired generation station in Bow, New Hampshire
CTA	Competitive Transition Assessment
CWIP	Construction work in progress
DOER	Massachusetts Department of Energy Resources
EPS	Earnings Per Share
ERISA	Employee Retirement Income Security Act of 1974
ES	Default Energy Service
Fitch	Fitch Ratings
FMCC	Federally Mandated Congestion Charge
FTR	Financial Transmission Rights
GAAP	Accounting principles generally accepted in the United States of America
GSC	Generation Service Charge
GSRP	Greater Springfield Reliability Project
GWh	Giga-watt Hours
HG&E	Holyoke Gas and Electric, a municipal department of the town of Holyoke, MA

i

HQ	Hydro-Québec, a corporation wholly owned by the Québec government, including its divisions that produce, transmit and distribute electricity in Québec, Canada
HVDC	High voltage direct current
Hydro Renewable Energy	Hydro Renewable Energy, Inc., a wholly owned subsidiary of Hydro-Québec
ISO-NE	ISO New England, Inc., the New England Independent System Operator
ISO-NE Tariff	ISO-NE FERC Transmission, Markets and Services Tariff
KV	Kilovolt
LOC	Letter of Credit
LRS	Supplier of last resort service
MGP	Manufactured Gas Plant
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
NPDES	National Pollutant Discharge Elimination System
NU Money Pool	Northeast Utilities Money Pool
NU supplemental benefit trust	The NU Trust Under Supplemental Executive Retirement Plan
PBOP	Postretirement Benefits Other Than Pension
PBOP Plan	Postretirement Benefits Other Than Pension Plan that provides certain retiree health care benefits, primarily medical and dental, and life insurance benefits
PCRBs	Pollution Control Revenue Bonds
Pension Plan	Single uniform noncontributory defined benefit retirement plan
PPA	Pension Protection Act
RECs	Renewable Energy Certificates
Regulatory ROE	The average cost of capital method for calculating the return on equity related to the distribution and generation business segment excluding the wholesale transmission segment
ROE	Return on Equity
RRB	Rate Reduction Bond or Rate Reduction Certificate
RSUs	Restricted share units
S&P	Standard & Poor's Financial Services LLC
SBC	Systems Benefits Charge
SCRC	Stranded Cost Recovery Charge
SERP	Supplemental Executive Retirement Plan
SS	Standard service
TCAM	Transmission Cost Adjustment Mechanism
TSA	Transmission Service Agreement
UI	The United Illuminating Company
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 SUBSIDIARY
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 (Unaudited)
Condensed Consolidated Balance Sheets – March 31, 2012 and December 31, 2011	1
Condensed Consolidated Statements of Income – Three Months Ended March 31, 2012 and 2011	3
Condensed Consolidated Statements of Comprehensive Income – Three Months Ended March 31, 2012 and 2011		4
Condensed Consolidated Statements of Cash Flows – Three Months Ended March 31, 2012 and 2011	5
The Connecticut Light and Power Company and Subsidiary (Unaudited)
Condensed Consolidated Balance Sheets – March 31, 2012 and December 31, 2011	7
Condensed Consolidated Statements of Income – Three Months Ended March 31, 2012 and 2011	9
Condensed Consolidated Statements of Comprehensive Income – Three Months Ended March 31, 2012 and 2011	10
Condensed Consolidated Statements of Cash Flows – Three Months Ended March 31, 2012 and 2011	11
Public Service Company of New Hampshire and Subsidiaries (Unaudited)
Condensed Consolidated Balance Sheets – March 31, 2012 and December 31, 2011	13
Condensed Consolidated Statements of Income – Three Months Ended March 31, 2012 and 2011	15
Condensed Consolidated Statements of Comprehensive Income – Three Months Ended March 31, 2012 and 2011	16
Condensed Consolidated Statements of Cash Flows  – Three Months Ended March 31, 2012 and 2011	17
Western Massachusetts Electric Company and Subsidiary (Unaudited)
Condensed Consolidated Balance Sheets – March 31, 2012 and December 31, 2011	19
Condensed Consolidated Statements of Income – Three Months Ended March 31, 2012 and 2011	21
Condensed Consolidated Statements of Comprehensive Income – Three Months Ended March 31, 2012 and 2011	22
Condensed Consolidated Statements of Cash Flows – Three Months Ended March 31, 2012 and 2011	23
Combined Notes to Condensed Consolidated Financial Statements	24

iii

ITEM 2– Management’s Discussion and Analysis of Financial Condition and Results of Operations for the following companies:
Northeast Utilities and Subsidiaries	44
The Connecticut Light and Power Company and Subsidiary	56
Public Service Company of New Hampshire and Subsidiaries	58
Western Massachusetts Electric Company and Subsidiary	60
ITEM 3 – Quantitative and Qualitative Disclosures About Market Risk	62
ITEM 4 – Controls and Procedures	62
PART II – OTHER INFORMATION
ITEM 1 – Legal Proceedings	63
ITEM 1A – Risk Factors	63
ITEM 2 – Unregistered Sales of Equity Securities and Use of Proceeds	63
ITEM 6 - Exhibits	64
SIGNATURES	67

iv

This Page Intentionally Left Blank

v

NORTHEAST UTILITIES AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
		March 31,		December 31,
(Thousands of Dollars)		2012		2011
ASSETS
Current Assets:
	Cash and Cash Equivalents	$	283,379	$	6,559
	Receivables, Net		485,770		488,002
	Unbilled Revenues		135,887		175,207
	Fuel, Materials and Supplies		219,091		248,958
	Regulatory Assets		241,902		255,144
	Marketable Securities		62,700		70,970
	Prepayments and Other Current Assets		94,737		112,632
Total Current Assets			1,523,466		1,357,472
Property, Plant and Equipment, Net			10,613,199		10,403,065
Deferred Debits and Other Assets:
	Regulatory Assets		3,214,208		3,267,710
	Goodwill		287,591		287,591
	Marketable Securities		74,050		60,311
	Derivative Assets		94,258		98,357
	Other Long-Term Assets		171,582		172,560
Total Deferred Debits and Other Assets			3,841,689		3,886,529
Total Assets		$	15,978,354	$	15,647,066
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)		2012		2011
LIABILITIES AND CAPITALIZATION
Current Liabilities:
Notes Payable to Banks		$	660,000	$	317,000
Long-Term Debt - Current Portion			267,286		331,582
Accounts Payable			412,884		633,282
Regulatory Liabilities			149,755		167,844
Derivative Liabilities			108,253		107,558
Other Current Liabilities			369,503		390,416
Total Current Liabilities			1,967,681		1,947,682
Rate Reduction Bonds			94,357		112,260
Deferred Credits and Other Liabilities:
Accumulated Deferred Income Taxes			1,923,266		1,868,316
Regulatory Liabilities			248,314		266,145
Derivative Liabilities			924,308		959,876
Accrued Pension, SERP and PBOP			1,241,433		1,326,037
Other Long-Term Liabilities			414,004		420,011
Total Deferred Credits and Other Liabilities			4,751,325		4,840,385
Capitalization:
Long-Term Debt			4,977,131		4,614,913
Noncontrolling Interest in Consolidated Subsidiary:
	Preferred Stock Not Subject to Mandatory Redemption		116,200		116,200
Equity:
	Common Shareholders' Equity:
	Common Shares		981,592		980,264
	Capital Surplus, Paid In		1,801,752		1,797,884
	Retained Earnings		1,698,553		1,651,875
	Accumulated Other Comprehensive Loss		(68,822)		(70,686)
	Treasury Stock		(344,774)		(346,667)
Common Shareholders' Equity			4,068,301		4,012,670
Noncontrolling Interests			3,359		2,956
Total Equity			4,071,660		4,015,626
Total Capitalization			9,164,991		8,746,739
Total Liabilities and Capitalization		$	15,978,354	$	15,647,066
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)			2012		2011
Operating Revenues			$	1,099,623	$	1,235,251
Operating Expenses:
	Fuel, Purchased and Net Interchange Power			398,013		474,109
	Other Operating Expenses			225,958		251,978
	Maintenance			69,826		67,764
	Depreciation			80,839		73,951
	Amortization of Regulatory Assets, Net			6,209		34,407
	Amortization of Rate Reduction Bonds			18,347		17,282
	Taxes Other Than Income Taxes			86,038		88,403
		Total Operating Expenses		885,230		1,007,894
Operating Income				214,393		227,357
Interest Expense:
	Interest on Long-Term Debt			59,968		57,399
	Interest on Rate Reduction Bonds			1,431		2,578
	Other Interest			5,048		(1,428)
		Interest Expense		66,447		58,549
Other Income, Net				8,773		10,313
Income Before Income Tax Expense				156,719		179,121
Income Tax Expense				55,964		63,537
Net Income				100,755		115,584
Net Income Attributable to Noncontrolling Interests				1,493		1,429
Net Income Attributable to Controlling Interests			$	99,262	$	114,155
Basic and Diluted Earnings Per Common Share			$	0.56	$	0.64
Dividends Declared Per Common Share			$	0.29	$	0.28
Weighted Average Common Shares Outstanding:
	Basic			178,055,716		177,188,207
	Diluted			178,437,453		177,480,996
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

3

NORTHEAST UTILITIES AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Unaudited)
		Three Months Ended March 31,
(Thousands of Dollars)		2012		2011
Net Income		$	100,755	$	115,584
Other Comprehensive Income, Net of Tax:
	Qualified Cash Flow Hedging Instruments		423		1,173
	Changes in Unrealized Gains/(Losses) on Other Securities		34		(5)
	Change in Funded Status of Pension, SERP and PBOP Benefit Plans		1,407		935
Other Comprehensive Income, Net of Tax			1,864		2,103
Comprehensive Income Attributable to Noncontrolling Interests			(1,493)		(1,429)
Comprehensive Income Attributable to Controlling Interests		$	101,126	$	116,258
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

4

NORTHEAST UTILITIES AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
			Three Months Ended March 31,
(Thousands of Dollars)			2012		2011
Operating Activities:
	Net Income		$	100,755	$	115,584
	Adjustments to Reconcile Net Income to Net Cash Flows
		Provided by Operating Activities:
		Bad Debt Expense		3,657		4,947
		Depreciation		80,839		73,951
		Deferred Income Taxes		52,474		52,429
		Pension, SERP and PBOP Expense		42,268		34,163
		Pension and PBOP Contributions		(98,910)		(5,932)
		Regulatory (Under)/Over Recoveries, Net		(28,352)		44,420
		Amortization of Regulatory Assets, Net		6,209		34,407
		Amortization of Rate Reduction Bonds		18,347		17,282
		Derivative Assets and Liabilities		(1,770)		(3,651)
		Other		(7,371)		(1,776)
	Changes in Current Assets and Liabilities:
		Receivables and Unbilled Revenues, Net		29,276		8,199
		Fuel, Materials and Supplies		30,108		42,990
		Taxes Receivable/Accrued, Net		11,758		18,312
		Accounts Payable		(190,232)		(29,278)
		Other Current Assets and Liabilities, Net		(40,240)		(33,281)
Net Cash Flows Provided by Operating Activities				8,816		372,766
Investing Activities:
	Investments in Property, Plant and Equipment			(304,294)		(236,689)
	Proceeds from Sales of Marketable Securities			40,947		38,646
	Purchases of Marketable Securities			(41,570)		(39,230)
	Other Investing Activities			2,448		328
Net Cash Flows Used in Investing Activities				(302,469)		(236,945)
Financing Activities:
	Cash Dividends on Common Shares			(52,104)		(48,588)
	Cash Dividends on Preferred Stock			(1,390)		(1,390)
	Increase/(Decrease) in Short-Term Debt			343,000		(78,000)
	Issuance of Long-Term Debt			300,000		-
	Retirements of Rate Reduction Bonds			(17,903)		(16,868)
	Other Financing Activities			(1,130)		989
Net Cash Flows Provided by/(Used in) Financing Activities				570,473		(143,857)
Net Increase/(Decrease) in Cash and Cash Equivalents				276,820		(8,036)
Cash and Cash Equivalents - Beginning of Period				6,559		23,395
Cash and Cash Equivalents - End of Period			$	283,379	$	15,359
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

5

This Page Intentionally Left Blank

6

THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARY
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
		March 31,		December 31,
(Thousands of Dollars)		2012		2011
ASSETS
Current Assets:
	Cash	$	3,837	$	1
	Receivables, Net		279,541		295,028
	Accounts Receivable from Affiliated Companies		3,146		1,548
	Unbilled Revenues		72,601		94,995
	Regulatory Assets		172,277		170,197
	Materials and Supplies		59,048		61,102
	Prepayments and Other Current Assets		51,917		53,920
Total Current Assets			642,367		676,791
Property, Plant and Equipment, Net			5,908,385		5,827,384
Deferred Debits and Other Assets:
	Regulatory Assets		2,070,122		2,103,830
	Derivative Assets		90,614		93,755
	Other Long-Term Assets		89,165		89,636
Total Deferred Debits and Other Assets			2,249,901		2,287,221
Total Assets		$	8,800,653	$	8,791,396
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

7

THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARY
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
			March 31,		December 31,
(Thousands of Dollars)			2012		2011
LIABILITIES AND CAPITALIZATION
Current Liabilities:
	Notes Payable to Banks		$	275,000	$	31,000
	Notes Payable to Affiliated Companies			9,275		58,525
	Long-Term Debt - Current Portion			-		62,000
	Accounts Payable			201,373		340,321
	Accounts Payable to Affiliated Companies			50,681		53,439
	Obligations to Third Party Suppliers			65,434		67,967
	Accrued Taxes			71,182		59,046
	Regulatory Liabilities			82,423		108,291
	Derivative Liabilities			97,483		95,881
	Other Current Liabilities			76,789		102,065
Total Current Liabilities				929,640		978,535
Deferred Credits and Other Liabilities:
	Accumulated Deferred Income Taxes			1,244,748		1,215,989
	Regulatory Liabilities			133,844		139,307
	Derivative Liabilities			898,850		935,849
	Accrued Pension, SERP and PBOP			259,814		260,571
	Other Long-Term Liabilities			206,550		215,640
Total Deferred Credits and Other Liabilities				2,743,806		2,767,356
Capitalization:
	Long-Term Debt			2,583,881		2,521,753
Preferred Stock Not Subject to Mandatory Redemption				116,200		116,200
	Common Stockholder's Equity:
		Common Stock		60,352		60,352
		Capital Surplus, Paid In		1,613,865		1,613,503
		Retained Earnings		755,048		735,948
		Accumulated Other Comprehensive Loss		(2,139)		(2,251)
	Common Stockholder's Equity			2,427,126		2,407,552
Total Capitalization				5,127,207		5,045,505
Total Liabilities and Capitalization			$	8,800,653	$	8,791,396
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

8

THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARY
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
			Three Months Ended March 31,
(Thousands of Dollars)			2012		2011
Operating Revenues			$	591,965	$	673,682
Operating Expenses:
	Fuel, Purchased and Net Interchange Power			223,835		255,369
	Other Operating Expenses			108,824		134,262
	Maintenance			42,788		40,782
	Depreciation			41,070		39,475
	Amortization of Regulatory Assets, Net			8,313		19,343
	Taxes Other Than Income Taxes			55,270		58,468
		Total Operating Expenses		480,100		547,699
Operating Income				111,865		125,983
Interest Expense:
	Interest on Long-Term Debt			31,521		33,328
	Other Interest			1,987		(3,575)
		Interest Expense		33,508		29,753
Other Income, Net				5,300		4,606
Income Before Income Tax Expense				83,657		100,836
Income Tax Expense				29,672		36,499
Net Income			$	53,985	$	64,337
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

9

THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARY
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Unaudited)
		Three Months Ended March 31,
(Thousands of Dollars)		2012		2011
Net Income		$	53,985	$	64,337
Other Comprehensive Income, Net of Tax:
	Qualified Cash Flow Hedging Instruments		111		111
	Changes in Unrealized Gains on Other Securities		1		-
Other Comprehensive Income, Net of Tax			112		111
Comprehensive Income		$	54,097	$	64,448
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

10

THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARY
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
			Three Months Ended March 31,
(Thousands of Dollars)			2012		2011
Operating Activities:
	Net Income		$	53,985	$	64,337
	Adjustments to Reconcile Net Income to Net Cash Flows
		(Used in)/Provided by Operating Activities:
		Bad Debt Expense		347		679
		Depreciation		41,070		39,475
		Deferred Income Taxes		32,460		28,592
		Pension, SERP and PBOP Expense, Net of PBOP Contributions		9,095		6,075
		Regulatory (Under)/Over Recoveries, Net		(39,726)		22,972
		Amortization of Regulatory Assets, Net		8,313		19,343
		Other		(6,746)		(20,129)
	Changes in Current Assets and Liabilities:
		Receivables and Unbilled Revenues, Net		28,685		16,187
		Taxes Receivable/Accrued, Net		16,551		57,078
		Accounts Payable		(146,676)		(14,135)
		Other Current Assets and Liabilities, Net		(44,484)		(15,511)
Net Cash Flows (Used in)/Provided by Operating Activities				(47,126)		204,963
Investing Activities:
	Investments in Property, Plant and Equipment			(108,842)		(106,829)
	Other Investing Activities			1,139		(45)
Net Cash Flows Used in Investing Activities				(107,703)		(106,874)
Financing Activities:
	Cash Dividends on Common Stock			(33,495)		(131,507)
	Cash Dividends on Preferred Stock			(1,390)		(1,390)
	Increase in Short-Term Debt			244,000		10,000
	(Decrease)/Increase in NU Money Pool Borrowings			(49,250)		18,950
	Other Financing Activities			(1,200)		(92)
Net Cash Flows Provided by/(Used in) Financing Activities				158,665		(104,039)
Net Increase/(Decrease) in Cash				3,836		(5,950)
Cash - Beginning of Period				1		9,762
Cash - End of Period			$	3,837	$	3,812
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

11

This Page Intentionally Left Blank

12

PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
		March 31,		December 31,
(Thousands of Dollars)		2012		2011
ASSETS
Current Assets:
	Cash	$	2,251	$	56
	Receivables, Net		89,551		87,545
	Accounts Receivable from Affiliated Companies		1,176		1,294
	Notes Receivable from Affiliated Companies		-		55,900
	Unbilled Revenues		39,304		45,403
	Fuel, Materials and Supplies		115,383		124,744
	Regulatory Assets		33,362		34,178
	Prepayments and Other Current Assets		15,066		35,261
Total Current Assets			296,093		384,381
Property, Plant and Equipment, Net			2,287,951		2,256,688
Deferred Debits and Other Assets:
	Regulatory Assets		375,122		393,941
	Other Long-Term Assets		79,954		81,531
Total Deferred Debits and Other Assets			455,076		475,472
Total Assets		$	3,039,120	$	3,116,541
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

13

PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
			March 31,		December 31,
(Thousands of Dollars)			2012		2011
LIABILITIES AND CAPITALIZATION
Current Liabilities:
	Notes Payable to Banks		$	45,000	$	-
	Notes Payable to Affiliated Companies			7,900		-
	Accounts Payable			74,374		106,377
	Accounts Payable to Affiliated Companies			16,489		18,895
	Accrued Interest			14,454		9,670
	Regulatory Liabilities			23,108		24,500
	Other Current Liabilities			42,139		36,497
Total Current Liabilities				223,464		195,939
Rate Reduction Bonds				71,905		85,368
Deferred Credits and Other Liabilities:
	Accumulated Deferred Income Taxes			405,834		392,712
	Regulatory Liabilities			54,212		54,415
	Accrued Pension, SERP and PBOP			172,802		258,718
	Other Long-Term Liabilities			55,935		53,304
Total Deferred Credits and Other Liabilities				688,783		759,149
Capitalization:
	Long-Term Debt			997,775		997,722
	Common Stockholder's Equity:
		Common Stock		-		-
		Capital Surplus, Paid In		700,452		700,285
		Retained Earnings		367,281		388,910
		Accumulated Other Comprehensive Loss		(10,540)		(10,832)
	Common Stockholder's Equity			1,057,193		1,078,363
Total Capitalization				2,054,968		2,076,085
Total Liabilities and Capitalization			$	3,039,120	$	3,116,541
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

14

PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
			Three Months Ended March 31,
(Thousands of Dollars)			2012		2011
Operating Revenues			$	242,997	$	269,470
Operating Expenses:
	Fuel, Purchased and Net Interchange Power			73,197		87,132
	Other Operating Expenses			56,999		56,422
	Maintenance			19,413		18,704
	Depreciation			21,208		17,907
	Amortization of Regulatory (Liabilities)/Assets, Net			(2,622)		15,567
	Amortization of Rate Reduction Bonds			13,930		13,135
	Taxes Other Than Income Taxes			15,486		13,667
		Total Operating Expenses		197,611		222,534
Operating Income				45,386		46,936
Interest Expense:
	Interest on Long-Term Debt			11,563		8,624
	Interest on Rate Reduction Bonds			1,016		1,893
	Other Interest			234		(60)
		Interest Expense		12,813		10,457
Other Income, Net				2,042		4,459
Income Before Income Tax Expense				34,615		40,938
Income Tax Expense				13,353		13,474
Net Income			$	21,262	$	27,464
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

15

PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Unaudited)
		Three Months Ended March 31,
(Thousands of Dollars)		2012		2011
Net Income		$	21,262	$	27,464
Other Comprehensive Income, Net of Tax:
	Qualified Cash Flow Hedging Instruments		290		926
	Changes in Unrealized Gains on Other Securities		2		-
Other Comprehensive Income, Net of Tax			292		926
Comprehensive Income		$	21,554	$	28,390
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

16

PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
			Three Months Ended March 31,
(Thousands of Dollars)			2012		2011
Operating Activities:
	Net Income		$	21,262	$	27,464
	Adjustments to Reconcile Net Income to Net Cash Flows
		Provided by Operating Activities:
		Bad Debt Expense		1,732		1,850
		Depreciation		21,208		17,907
		Deferred Income Taxes		8,908		3,672
		Pension, SERP and PBOP Expense		7,032		6,930
		Pension and PBOP Contributions		(89,012)		(1,076)
		Regulatory Over/(Under) Recoveries, Net		911		(1,271)
		Amortization of Regulatory (Liabilities)/Assets, Net		(2,622)		15,567
		Amortization of Rate Reduction Bonds		13,930		13,135
		Other		7,837		4,140
	Changes in Current Assets and Liabilities:
		Receivables and Unbilled Revenues, Net		2,480		10,077
		Fuel, Materials and Supplies		9,361		16,043
		Taxes Receivable/Accrued, Net		10,138		18,971
		Accounts Payable		(16,073)		(2,160)
		Other Current Assets and Liabilities, Net		18,869		8,361
Net Cash Flows Provided by Operating Activities				15,961		139,610
Investing Activities:
	Investments in Property, Plant and Equipment			(67,059)		(57,718)
	Decrease/(Increase) in NU Money Pool Lending			55,900		(16,100)
	Other Investing Activities			963		369
Net Cash Flows Used in Investing Activities				(10,196)		(73,449)
Financing Activities:
	Cash Dividends on Common Stock			(42,891)		(14,707)
	Increase/(Decrease) in Short-Term Debt			45,000		(10,000)
	Increase/(Decrease) in NU Money Pool Borrowings			7,900		(47,900)
	Capital Contributions from NU Parent			-		20,000
	Retirements of Rate Reduction Bonds			(13,463)		(12,697)
	Other Financing Activities			(116)		(68)
Net Cash Flows Used in Financing Activities				(3,570)		(65,372)
Net Increase in Cash				2,195		789
Cash - Beginning of Period				56		2,559
Cash - End of Period			$	2,251	$	3,348
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

17

This Page Intentionally Left Blank

18

WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
		March 31,		December 31,
(Thousands of Dollars)		2012		2011
ASSETS
Current Assets:
	Cash	$	126	$	1
	Receivables, Net		46,083		42,757
	Accounts Receivable from Affiliated Companies		1,975		633
	Notes Receivable from Affiliated Companies		-		11,000
	Unbilled Revenues		13,666		16,277
	Regulatory Assets		33,525		35,520
	Marketable Securities		13,953		26,335
	Prepayments and Other Current Assets		6,117		8,719
Total Current Assets			115,445		141,242
Property, Plant and Equipment, Net			1,152,976		1,077,833
Deferred Debits and Other Assets:
	Regulatory Assets		242,181		233,247
	Marketable Securities		43,443		30,794
	Other Long-Term Assets		21,155		19,777
Total Deferred Debits and Other Assets			306,779		283,818
Total Assets		$	1,575,200	$	1,502,893
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

19

WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
			March 31,		December 31,
(Thousands of Dollars)			2012		2011
LIABILITIES AND CAPITALIZATION
Current Liabilities:
	Notes Payable to Banks		$	65,000	$	-
	Notes Payable to Affiliated Companies			18,200		-
	Accounts Payable			86,599		111,566
	Accounts Payable to Affiliated Companies			9,314		10,626
	Regulatory Liabilities			30,389		33,056
	Other Current Liabilities			16,889		20,755
Total Current Liabilities				226,391		176,003
Rate Reduction Bonds				22,452		26,892
Deferred Credits and Other Liabilities:
	Accumulated Deferred Income Taxes			264,178		244,511
	Regulatory Liabilities			15,731		16,597
	Accrued Pension, SERP and PBOP			28,893		29,546
	Other Long-Term Liabilities			50,757		47,498
Total Deferred Credits and Other Liabilities				359,559		338,152
Capitalization:
	Long-Term Debt			499,594		499,545
	Common Stockholder's Equity:
		Common Stock		10,866		10,866
		Capital Surplus, Paid In		340,179		340,115
		Retained Earnings		120,260		115,506
		Accumulated Other Comprehensive Loss		(4,101)		(4,186)
	Common Stockholder's Equity			467,204		462,301
Total Capitalization				966,798		961,846
Total Liabilities and Capitalization			$	1,575,200	$	1,502,893
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

20

WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
			Three Months Ended March 31,
(Thousands of Dollars)			2012		2011
Operating Revenues			$	114,025	$	106,684
Operating Expenses:
	Fuel, Purchased and Net Interchange Power			39,504		40,204
	Other Operating Expenses			24,019		26,230
	Maintenance			4,724		4,771
	Depreciation			7,697		6,338
	Amortization of Regulatory Assets/(Liabilities), Net			121		(600)
	Amortization of Rate Reduction Bonds			4,418		4,146
	Taxes Other Than Income Taxes			4,882		4,543
		Total Operating Expenses		85,365		85,632
Operating Income				28,660		21,052
Interest Expense:
	Interest on Long-Term Debt			5,766		4,754
	Interest on Rate Reduction Bonds			415		684
	Other Interest			214		136
		Interest Expense		6,395		5,574
Other Income, Net				1,092		739
Income Before Income Tax Expense				23,357		16,217
Income Tax Expense				9,171		6,251
Net Income			$	14,186	$	9,966
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

21

WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Unaudited)
		Three Months Ended March 31,
(Thousands of Dollars)		2012		2011
Net Income		$	14,186	$	9,966
Other Comprehensive Income From Qualified
	Cash Flow Hedging Instruments,  Net of Tax		85		199
Comprehensive Income		$	14,271	$	10,165
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

22

WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
			Three Months Ended March 31,
(Thousands of Dollars)			2012		2011
Operating Activities:
	Net Income		$	14,186	$	9,966
	Adjustments to Reconcile Net Income to Net Cash Flows
		Provided by Operating Activities:
		Bad Debt Expense		739		1,337
		Depreciation		7,697		6,338
		Deferred Income Taxes		9,198		4,507
		Pension, SERP and PBOP Expense, Net of PBOP Contributions		1,766		1,096
		Regulatory (Under)/Over Recoveries, Net		(2,242)		7,620
		Amortization of Regulatory Assets/(Liabilities), Net		121		(600)
		Amortization of Rate Reduction Bonds		4,418		4,146
		Other		(1,810)		(1,370)
	Changes in Current Assets and Liabilities:
		Receivables and Unbilled Revenues, Net		(2,274)		(2,384)
		Taxes Receivable/Accrued, Net		1,051		10,019
		Accounts Payable		(21,870)		(4,584)
		Other Current Assets and Liabilities, Net		(5,885)		(4,519)
Net Cash Flows Provided by Operating Activities				5,095		31,572
Investing Activities:
	Investments in Property, Plant and Equipment			(85,011)		(33,037)
	Proceeds from Sales of Marketable Securities			31,579		32,414
	Purchases of Marketable Securities			(31,680)		(32,510)
	Decrease in NU Money Pool Lending			11,000		-
	Other Investing Activities			(169)		(333)
Net Cash Flows Used in Investing Activities				(74,281)		(33,466)
Financing Activities:
	Cash Dividends on Common Stock			(9,432)		(6,576)
	Increase in Short-Term Debt			65,000		10,000
	Increase in NU Money Pool Borrowings			18,200		3,000
	Retirements of Rate Reduction Bonds			(4,440)		(4,170)
	Other Financing Activities			(17)		(7)
Net Cash Flows Provided by Financing Activities				69,311		2,247
Net Increase in Cash				125		353
Cash - Beginning of Period				1		1
Cash - End of Period			$	126	$	354

The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

23

NORTHEAST UTILITIES AND SUBSIDIARIES

THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARY

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.

Presentation

Pursuant to the rules and regulations of the SEC, certain information and footnote disclosures normally included in annual consolidated financial statements prepared in accordance with GAAP have been omitted. 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 2011 combined Annual Report on Form 10-K of NU, CL&P, PSNH and WMECO, which was filed with the SEC (2011 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, 2012 and December 31, 2011, and the results of operations, comprehensive income and cash flows for the three months ended March 31, 2012 and 2011. The results of operations, comprehensive income and cash flows for the three months ended March 31, 2012 and 2011 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, 2012, NU and a subsidiary of NSTAR had formed, on a 75 percent and 25 percent basis, respectively, a limited liability company, NPT, to construct, own and operate the Northern Pass transmission project.  NPT and Hydro Renewable Energy entered into a TSA whereby NPT will sell to Hydro Renewable Energy electric transmission rights over the Northern Pass for a 40-year term at cost of service rates.  NPT will be required to maintain a capital structure of 50 percent debt and 50 percent equity.  NU determined, through its controlling financial interest in NPT, that it must consolidate NPT, as NU has the power to direct the activities of NPT, which most significantly impact its economic performance, including permitting and siting and operation and maintenance activities over the term of the TSA.  On April 10, 2012, upon consummation of the NU and NSTAR merger, an NSTAR subsidiary, which held 25 percent of NPT, was merged into NUTV, resulting in NUTV owning 100 percent of NPT.  See Note 2, "Merger of NU and NSTAR," to the unaudited condensed consolidated financial statements for further information regarding the merger.

Certain reclassifications of prior period data were made in the accompanying unaudited condensed consolidated balance sheets and 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 about the conditions that arose after the balance sheet date but before the financial statements are issued.  See Note 2, "Merger of NU and NSTAR," Note 10C, "Commitments and Contingencies – Exposure Regarding Complaint on FERC Base ROE," and Note 17, "Subsequent Events" to the unaudited condensed consolidated financial statements for further information.  

B.

Accounting Standards Recently Adopted

In the first quarter of 2012, NU adopted the Financial Accounting Standards Board’s (FASB) final Accounting Standards Update (ASU) on fair value measurement.  The ASU did not have an impact on NU’s financial position, results of operations or cash flows, but required additional financial statement disclosures related to fair value measurements.  For further information, see Note 5, “Derivative Instruments,” to the unaudited condensed consolidated financial statements.

In the first quarter of 2012, NU adopted the FASB’s final ASU on testing goodwill for impairment.  The ASU provides the election to perform a qualitative assessment to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying value; if so, quantitative testing is required.  The ASU does not change existing guidance relating to when an entity should test goodwill for impairment or the methodology to be utilized in performing quantitative testing.  NU has not and does not currently intend to utilize the election provided by this ASU.

In the first quarter of 2012, NU adopted the FASB’s final ASU on the presentation of comprehensive income.  The ASU does not change existing guidance on which items should be presented in other comprehensive income but requires other comprehensive income to be presented as part of a single continuous statement of comprehensive income or in a statement of other comprehensive

24

income immediately following the statement of net income.  The ASU did not affect the calculation of net income, comprehensive income or EPS.  The ASU did not have an impact on NU’s financial position, results of operations or cash flows.

C.

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 is included in Receivables, Net on the accompanying unaudited condensed consolidated balance sheets, is as follows:

(Millions of Dollars)	As of March 31, 2012		As of December 31, 2011
NU	$	34.8	$	34.9
CL&P		14.2		14.8
PSNH		7.9		7.2
WMECO		5.1		4.6

D.

Restricted Cash

As of March 31, 2012, NU, CL&P and PSNH had $18.3 million, $9.4 million, and $7.4 million, respectively, of restricted cash, primarily relating to amounts held in escrow related to property damage at CL&P and insurance proceeds on bondable property at PSNH, which were included in Prepayments and Other Current Assets on the accompanying unaudited condensed consolidated balance sheets.  As of December 31, 2011, these amounts for NU, CL&P and PSNH were $17.9 million, $9.4 million, and $7 million, respectively.

E.

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.

Fair Value Hierarchy:  In measuring fair value, NU uses observable market data when available and minimizes the use of unobservable inputs.  Inputs used in fair value measurements are categorized into three fair value hierarchy levels for disclosure purposes.  The entire fair value measurement is categorized based on the lowest level of input that is significant to the fair value measurement.  NU evaluates the classification of assets and liabilities measured at fair value on a quarterly basis, and NU's policy is to recognize transfers between levels of the fair value hierarchy as of the end of the reporting period.  The three levels of the fair value hierarchy are described below:

Level 1 - Inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities as of the reporting date.  Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.  

Level 2 - Inputs are quoted prices for similar instruments in active markets, quoted prices for identical or similar instruments in markets that are not active, and model-derived valuations in which all significant inputs are observable.

Level 3 - Quoted market prices are not available.  Fair value is derived from valuation techniques in which one or more significant inputs or assumptions are unobservable.  Where possible, valuation techniques incorporate observable market inputs that can be validated to external sources such as industry exchanges, including prices of energy and energy-related products.  

Determination of Fair Value:  The valuation techniques and inputs used in NU's fair value measurements are described in Note 5, "Derivative Instruments," Note 6, "Marketable Securities," and Note 11, "Fair Value of Financial Instruments," to the unaudited condensed consolidated financial statements.

F.

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.

NU		For the Three Months Ended
(Millions of Dollars, except percentages)		March 31, 2012		March 31, 2011
AFUDC:
	Borrowed Funds	$	1.4	$	3.2
	Equity Funds		2.8		5.5
Total		$	4.2	$	8.7
Average AFUDC Rate			6.6%		7.1%

25

		For the Three Months Ended						For the Three Months Ended
		March 31, 2012						March 31, 2011
(Millions of Dollars, except percentages)		CL&P		PSNH		WMECO		CL&P		PSNH		WMECO
AFUDC:
	Borrowed Funds	$	0.8	$	0.4	$	0.1	$	0.8	$	2.1	$	0.1
	Equity Funds		1.2		0.9		0.3		1.5		3.5		0.1
Total		$	2.0	$	1.3	$	0.4	$	2.3	$	5.6	$	0.2
Average AFUDC Rate			6.2%		7.5%		8.1%		8.1%		6.7%		7.3%

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.  

G.

Other Income, Net

The other income/(loss) items included within Other Income, Net on the accompanying unaudited condensed consolidated statements of income primarily consist of investment income/(loss), interest income, AFUDC related to equity funds and 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.  

H.

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, 2012		March 31, 2011
NU	$	35.0	$	38.7
CL&P		29.4		31.4

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.   

I. 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, 2012		As of December 31, 2011
NU	$	138.5	$	168.5
CL&P		36.6		32.7
PSNH		32.5		51.1
WMECO		56.6		61.3

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 accompanying unaudited condensed consolidated statements of cash flows.  

In February 2012, CL&P provided approximately $27 million of bill credits to its residential customers who remained without power after noon on November 5, 2011 as a result of the October 2011 snowstorm.  This disbursement is reflected as a use of cash and recorded in Other Current Assets and Liabilities, Net on the accompanying unaudited condensed consolidated statements of cash flows for the three months ended March 31, 2012 for CL&P and NU.

2.

MERGER OF NU AND NSTAR

On April 10, 2012, NU acquired 100 percent of the outstanding common shares of NSTAR and NSTAR (through a successor, NSTAR LLC) became a direct wholly-owned subsidiary of NU.  NSTAR is a holding company engaged through its subsidiaries in the energy delivery business serving electric and natural gas distribution customers in Massachusetts.  The merger was structured as a merger of equals in a tax-free exchange of shares.  As part of the merger, NSTAR shareholders received 1.312 NU common shares for each NSTAR common share owned (the "exchange ratio") as of the acquisition date.  The exchange ratio was structured to result in a no-premium merger based on the average closing share price of each company's common shares for the 20 trading days preceding the announcement of the merger in October 2010.  NU issued approximately 136 million common shares to the NSTAR shareholders as a result of the merger, which brought the total common shares outstanding to approximately 314 million shares.  

Effective as of the merger date, NU provides energy delivery service to approximately 3.5 million electric and natural gas customers through six regulated utilities in Connecticut, Massachusetts and New Hampshire.  

26

Purchase Price:

Pursuant to the merger, all of the NSTAR common shares were exchanged at the fixed exchange ratio of 1.312 common shares of NU for each NSTAR common share.  The total consideration transferred in the merger was based on the closing price of NU common shares on April 9, 2012, the day prior to the date the merger was completed, and was calculated as follows:

NSTAR common shares outstanding as of April 9, 2012 (in thousands)*		103,696
Exchange ratio		1.312
NU common shares issued for NSTAR common shares outstanding (in thousands)		136,049
Closing price of NU common shares on April 9, 2012	$	36.79
Value of common shares issued (in millions)	$	5,005
Fair value of NU replacement stock-based compensation awards related to   pre-merger service (in millions)		33
Total purchase price (in millions)	$	5,038

*

Includes 109 thousand shares related to NSTAR stock-based compensation awards that vested immediately prior to the merger.

Certain of NSTAR’s stock-based compensation awards, including deferred shares, performance shares and all outstanding stock options, were replaced with NU awards upon consummation of the merger.  In accordance with accounting guidance for business combinations, a portion of the fair value of these awards is included in the purchase price as it represents consideration transferred in the merger.

The allocation of the total purchase price to the estimated fair values of the assets acquired and liabilities assumed was based on accounting guidance for fair value measurements, which defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date.  The excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed was recognized as goodwill.  The allocation of goodwill has not yet been completed.

The allocation of the total purchase price includes adjustments to record the fair value of NSTAR’s unregulated telecommunication business, regulatory assets not earning a return, lease agreements, long-term debt and the preferred stock of an NSTAR subsidiary.  All purchase price adjustments are preliminary and subject to change as additional information is obtained.  The preliminary allocation of the purchase price is as follows:

(Millions of Dollars)
Current Assets	$	746
Property Plant and Equipment, Net		5,150
Goodwill		3,231
Other Long-Term Assets, excluding Goodwill		2,131
Current Liabilities		(1,320)
Long-Term Liabilities		(2,721)
Long-Term Debt and Other Long-Term Obligations		(2,140)
Preferred Stock of Subsidiary		(39)
Total Purchase Price	$	5,038

Regulatory Approvals:

On February 15, 2012, NU and NSTAR reached comprehensive settlement agreements with the Massachusetts Attorney General and the DOER.  The settlement agreement reached with the Attorney General covered a variety of rate-making and rate design issues, including a base distribution rate freeze at least through 2015 for NSTAR Electric, NSTAR Gas and WMECO and $15 million, $3 million and $3 million in the form of rate credits to their respective customers.  The settlement agreement reached with the DOER covered the same rate-making and rate design issues as the Attorney General's settlement agreement, as well as a variety of matters impacting the advancement of Massachusetts clean energy policy established by the Green Communities Act and Global Warming Solutions Act.  On April 4, 2012, the DPU issued a decision approving the settlement agreements and the merger of NU and NSTAR.

On March 13, 2012, NU and NSTAR reached a comprehensive settlement agreement with both the Connecticut Attorney General and the Connecticut Office of Consumer Counsel.  The settlement agreement covered a variety of matters, including a $25 million rate credit to CL&P customers, a CL&P base distribution rate freeze until December 1, 2014, and the establishment of a $15 million fund for energy efficiency and other initiatives to be disbursed at the direction of the DEEP.  In the agreement, CL&P agreed to forego recovery of $40 million of the deferred storm costs associated with restoration activities following Tropical Storm Irene and the October 2011 snowstorm.  Subject to the PURA review, the remaining storm costs are to be recovered during the six-year period beginning December 1, 2014.  On April 2, 2012, the PURA issued a decision approving the settlement agreement and the merger of NU and NSTAR.

The financial impacts of the settlement agreements will be recognized by NU, CL&P, NSTAR Electric, NSTAR Gas, and WMECO in the second quarter of 2012 in connection with the completion of the merger.

27

Pro Forma Financial Information:

The following unaudited pro forma financial information reflects the consolidated results of operations of NU and reflects the amortization of purchase price adjustments assuming the merger had taken place on January 1, 2011.  The unaudited pro forma financial information has been presented for illustrative purposes only and is not necessarily indicative of the consolidated results of operations that would have been achieved or the future consolidated results of operations of NU.  The pro forma financial information does not include potential cost savings or non-recurring adjustments that will be recorded in the second quarter in connection with the merger.  This information is preliminary in nature and subject to change based on final purchase price adjustments.  

In the first quarters of 2012 and 2011, NU and NSTAR incurred non-recurring costs directly related to the merger that are not included in the pro forma earnings presented below.  The aggregate after-tax impacts of these costs were approximately $1.5 million ($1.1 million for NU) and $13 million ($8.3 million for NU) for the three months ended March 31, 2012 and 2011, respectively.  

	For the Three Months Ended March 31,
(Pro forma amounts in millions, except per share amounts)	2012		2011
Revenues	$	1,830	$	2,072
Net Income Attributable to Controlling Interests		108		185
Basic and Diluted Earnings per Share		0.34		0.59

3.

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.  If management determined that it could no longer apply the accounting guidance applicable to rate-regulated enterprises to the Regulated companies' operations, or that management could not conclude it is probable that costs would be recovered or reflected in future rates, the costs would be charged to net income in the period in which the determination is made.

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

	As of March 31, 2012		As of December 31, 2011
(Millions of Dollars)	NU		NU
Deferred Benefit Costs	$	1,322.2	$	1,360.5
Regulatory Assets Offsetting Derivative Liabilities		912.2		939.6
Securitized Assets		83.5		101.8
Income Taxes, Net		446.1		425.4
Unrecovered Contractual Obligations		95.4		100.9
Regulatory Tracker Deferrals		43.7		45.9
Storm Cost Deferrals		365.5		356.0
Asset Retirement Obligations		48.4		47.5
Losses on Reacquired Debt		24.2		24.5
Deferred Environmental Remediation Costs		37.6		38.5
Other Regulatory Assets		77.3		82.2
Total Regulatory Assets	$	3,456.1	$	3,522.8
Less:  Current Portion	$	241.9	$	255.1
Total Long-Term Regulatory Assets	$	3,214.2	$	3,267.7

	As of March 31, 2012						As of December 31, 2011
(Millions of Dollars)	CL&P		PSNH		WMECO		CL&P		PSNH		WMECO
Deferred Benefit Costs	$	556.5	$	194.1	$	115.5	$	572.8	$	200.0	$	118.9
Regulatory Assets Offsetting Derivative Liabilities		899.9		-		12.3		932.0		-		7.3
Securitized Assets		-		62.5		21.0		-		76.4		25.4
Income Taxes, Net		348.0		37.7		29.3		339.6		38.0		17.8
Unrecovered Contractual Obligations		76.7		-		18.7		80.9		-		20.0
Regulatory Tracker Deferrals		4.7		14.5		22.7		5.5		11.9		22.1
Storm Cost Deferrals		280.9		41.7		42.9		268.3		44.0		43.7
Asset Retirement Obligations		28.5		13.7		3.3		27.9		13.5		3.2
Losses on Reacquired Debt		13.9		8.8		0.3		13.9		9.0		0.3
Deferred Environmental Remediation Costs		-		9.8		-		-		9.7		-
Other Regulatory Assets		33.3		25.7		9.7		33.1		25.6		10.0
Total Regulatory Assets	$	2,242.4	$	408.5	$	275.7	$	2,274.0	$	428.1	$	268.7
Less:  Current Portion	$	172.3	$	33.4	$	33.5	$	170.2	$	34.2	$	35.5
Total Long-Term Regulatory Assets	$	2,070.1	$	375.1	$	242.2	$	2,103.8	$	393.9	$	233.2

Additionally, the Regulated companies had $32.6 million ($4.2 million for CL&P, $23.5 million for PSNH, and $1.6 million for WMECO) and $32.4 million ($5 million for CL&P, $22.4 million for PSNH, and $1.6 million for WMECO) of regulatory costs as of March 31, 2012 and December 31, 2011, 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.

28

As part of the settlement agreement NU and NSTAR reached with both the Connecticut Attorney General and the Connecticut Office of Consumer Counsel on March 13, 2012, in the second quarter of 2012, CL&P will record a reserve of $40 million associated with the deferred storm costs related to Tropical Storm Irene and the October 2011 snowstorm.  CL&P will file with PURA for recovery of the total deferred storm costs.  The total approved costs, which will reflect the $40 million reserve, will be collected over a six year period beginning December 1, 2014.  Management believes CL&P's, PSNH's and WMECO's response to the 2011 storms was prudent and therefore believes it is probable that they will be allowed to recover these remaining deferred storm costs.  See Note 2, “Merger of NU and NSTAR,” to the unaudited condensed consolidated financial statements for further information.

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

	As of March 31, 2012		As of December 31, 2011
(Millions of Dollars)	NU		NU
Cost of Removal	$	164.3	$	172.2
Regulatory Tracker Deferrals		112.9		139.1
AFUDC Transmission Incentive		66.7		67.0
Pension Liability - Yankee Gas Acquisition		9.4		10.0
Overrecovered Spent Nuclear Fuel Costs and Contractual Obligations		15.4		15.4
Wholesale Transmission Overcollections		9.0		9.6
Other Regulatory Liabilities		20.4		20.6
Total Regulatory Liabilities	$	398.1	$	433.9
Less:  Current Portion	$	149.8	$	167.8
Total Long-Term Regulatory Liabilities	$	248.3	$	266.1

		As of March 31, 2012						As of December 31, 2011
(Millions of Dollars)		CL&P		PSNH		WMECO		CL&P		PSNH		WMECO
Cost of Removal		$	57.1	$	52.8	$	6.2	$	63.8	$	53.2	$	7.2
Regulatory Tracker Deferrals			69.7		14.0		17.7		94.4		17.3		21.3
AFUDC Transmission Incentive			57.4		-		9.3		57.7		-		9.3
Overrecovered Spent Nuclear Fuel Costs and
	Contractual Obligations		15.4		-		-		15.4		-		-
Wholesale Transmission Overcollections			5.1		4.4		10.8		4.5		2.6		9.5
Other Regulatory Liabilities			11.5		6.1		2.1		11.8		5.8		2.4
Total Regulatory Liabilities		$	216.2	$	77.3	$	46.1	$	247.6	$	78.9	$	49.7
Less:  Current Portion		$	82.4	$	23.1	$	30.4	$	108.3	$	24.5	$	33.1
Total Long-Term Regulatory Liabilities		$	133.8	$	54.2	$	15.7	$	139.3	$	54.4	$	16.6

4.		PROPERTY, PLANT AND EQUIPMENT AND ACCUMULATED DEPRECIATION
The following tables summarize the NU, CL&P, PSNH and WMECO investments in utility property, plant and equipment:
			As of March 31, 2012		As of December 31, 2011
(Millions of Dollars)			NU		NU
Distribution - Electric			$	6,645.0	$	6,540.4
Distribution - Natural Gas				1,259.9		1,247.6
Transmission				3,590.7		3,541.9
Generation				1,132.0		1,096.0
Electric and Natural Gas Utility				12,627.6		12,425.9
Other (1)				308.4		305.1
Total Property, Plant and Equipment, Gross				12,936.0		12,731.0
Less:  Accumulated Depreciation
	Electric and Natural Gas Utility			(3,077.5)		(3,035.5)
	Other			(122.5)		(120.2)
Total Accumulated Depreciation				(3,200.0)		(3,155.7)
Property, Plant and Equipment, Net				9,736.0		9,575.3
Construction Work in Progress				877.2		827.8
Total Property, Plant and Equipment, Net			$	10,613.2	$	10,403.1

⁽¹⁾

These assets are primarily owned by RRR ($162.2 million and $161.5 million) and NUSCO ($134.1 million and $131.5 million) as of March 31, 2012 and December 31, 2011, respectively, and are mainly comprised of buildings and building improvements at RRR and software and equipment at NUSCO.  

29

	As of March 31, 2012						As of December 31, 2011
(Millions of Dollars)	CL&P		PSNH		WMECO		CL&P		PSNH		WMECO
Distribution	$	4,507.6	$	1,464.5	$	708.6	$	4,419.6	$	1,451.6	$	704.3
Transmission		2,693.7		548.1		337.7		2,689.1		546.4		297.4
Generation		-		1,110.8		21.2		-		1,074.8		21.2
Total Property, Plant and Equipment, Gross		7,201.3		3,123.4		1,067.5		7,108.7		3,072.8		1,022.9
Less:  Accumulated Depreciation		(1,618.7)		(905.4)		(243.3)		(1,596.7)		(893.6)		(240.5)
Property, Plant and Equipment, Net		5,582.6		2,218.0		824.2		5,512.0		2,179.2		782.4
Construction Work in Progress		325.8		70.0		328.8		315.4		77.5		295.4
Total Property, Plant and Equipment, Net	$	5,908.4	$	2,288.0	$	1,153.0	$	5,827.4	$	2,256.7	$	1,077.8

5.

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, and the use of nonderivative contracts.

CL&P and WMECO mitigate the risks associated with the price volatility of energy and energy-related products through the use of SS, LRS, and basic service contracts, which fix the price of electricity purchased for customers for periods of time ranging from three months to three years for CL&P and from three months to one year for WMECO 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 and WMECO has entered into a contract to purchase renewable energy that is a derivative.  While the risks managed by these contracts relate to capacity prices, regional congestion costs, and the development of renewable energy that are not specific to CL&P and WMECO, electric distribution companies, including CL&P and WMECO, are required to enter into these contracts.  The costs or benefits from these contracts are recoverable from or refundable to customers, and, therefore 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 contracts.  The contracts are accounted for at fair value, and changes in their fair values are recorded in Fuel, Purchased and Net Interchange Power 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.  

30

The gross fair values of derivative assets and liabilities with the same counterparty are offset and reported as net Derivative Assets or Derivative Liabilities, with current and long-term portions, in the accompanying unaudited condensed consolidated balance sheets.  Cash collateral posted or collected under master netting agreements is recorded as an offset to the derivative asset or liability.  The following tables present the gross fair values of contracts 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, 2012
		Derivatives Not
		Designated as Hedges
		Commodity
		and Capacity		Commodity						Net Amount
		Contracts		Supply and						Recorded as
		Required by		Price Risk		Hedging		Collateral		Derivative
(Millions of Dollars)		Regulation		Management		Instruments		and Netting (1)		Asset/(Liability) (2)
Current Derivative Assets:
Level 3:
	CL&P	$	17.7	$	0.3	$	-	$	(11.8)	$	6.2
	Other		-		6.7		-		-		6.7
Total Current Derivative Assets		$	17.7	$	7.0	$	-	$	(11.8)	$	12.9
Long-Term Derivative Assets:
Level 3:
	CL&P	$	166.5	$	-	$	-	$	(75.9)	$	90.6
	Other		-		3.7		-		-		3.7
Total Long-Term Derivative Assets		$	166.5	$	3.7	$	-	$	(75.9)	$	94.3
Current Derivative Liabilities:
Level 2:
	Other	$	-	$	(17.6)	$	-	$	7.5	$	(10.1)
Level 3:
	CL&P		(97.5)		-		-		-		(97.5)
	WMECO		(0.7)		-		-		-		(0.7)
Total Current Derivative Liabilities		$	(98.2)	$	(17.6)	$	-	$	7.5	$	(108.3)
Long-Term Derivative Liabilities:
Level 2:
	Other	$	-	$	(13.8)	$	-	$	-	$	(13.8)
Level 3:
	CL&P		(898.9)		-		-		-		(898.9)
	WMECO		(11.6)		-		-		-		(11.6)
Total Long-Term Derivative Liabilities		$	(910.5)	$	(13.8)	$	-	$	-	$	(924.3)

31

		As of December 31, 2011
		Derivatives Not Designated
		as Hedges
		Commodity
		and Capacity		Commodity						Net Amount
		Contracts		Supply and						Recorded as
		Required by		Price Risk		Hedging		Collateral		Derivative
(Millions of Dollars)		Regulation		Management		Instruments		and Netting (1)		Asset/(Liability) (2)
Current Derivative Assets:
Level 2:
	Other	$	-	$	-	$	2.3	$	-	$	2.3
Level 3:
	CL&P		17.5		0.4		-		(11.6)		6.3
	Other		-		4.7		-		-		4.7
Total Current Derivative Assets		$	17.5	$	5.1	$	2.3	$	(11.6)	$	13.3
Long-Term Derivative Assets:
Level 3:
	CL&P	$	174.2	$	-	$	-	$	(80.4)	$	93.8
	Other		-		4.6		-		-		4.6
Total Long-Term Derivative Assets		$	174.2	$	4.6	$	-	$	(80.4)	$	98.4
Current Derivative Liabilities:
Level 3:
	CL&P	$	(95.9)	$	-	$	-	$	-	$	(95.9)
	WMECO		(0.1)		-		-		-		(0.1)
	Other		-		(16.1)		-		4.5		(11.6)
Total Current Derivative Liabilities		$	(96.0)	$	(16.1)	$	-	$	4.5	$	(107.6)
Long-Term Derivative Liabilities:
Level 3:
	CL&P	$	(935.8)	$	-	$	-	$	-	$	(935.8)
	WMECO		(7.2)		-		-		-		(7.2)
	Other		-		(17.3)		-		0.4		(16.9)
Total Long-Term Derivative Liabilities		$	(943.0)	$	(17.3)	$	-	$	0.4	$	(959.9)

⁽¹⁾

Amounts represent cash collateral posted under master netting agreements and the netting of derivative assets and liabilities.  See "Credit Risk" below for discussion of cash collateral posted under master netting agreements.

⁽²⁾

Current derivative assets are included in Prepayments and Other Current Assets on the accompanying unaudited condensed consolidated balance sheets.  WMECO derivative liabilities are included in Other Current Liabilities and Other Long-Term Liabilities on the accompanying unaudited condensed consolidated balance sheets.

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

Derivatives not designated as hedges

Commodity and capacity contracts required by regulation:  CL&P has capacity-related contracts with generation facilities.  These contracts and similar UI contracts have an expected capacity of 787 MW.  CL&P has a sharing agreement with UI, with 80 percent of each contract allocated to CL&P and 20 percent allocated to UI.  The capacity contracts have terms up to 15 years and obligate the utilities to make or receive payments on a monthly basis to or from the generation facilities based on the difference between a set capacity price and the forward capacity market price received in the ISO-NE capacity markets.  The largest of these generation facilities achieved commercial operation in July 2011.  In addition, CL&P has a contract to purchase 0.1 million MWh of energy per year through 2020.

WMECO has a renewable energy contract to purchase 0.1 million MWh of energy per year through 2027 with a facility that is expected to achieve commercial operation by December 2012.

Commodity supply and price risk management:  As of March 31, 2012 and December 31, 2011, CL&P had 0.5 million and 0.6 million MWh, respectively, remaining under FTRs that extend through December 2012 and require monthly payments or receipts.

As of March 31, 2012 and December 31, 2011, NU had approximately 38 thousand MWh and 123 thousand MWh, respectively, of supply volumes remaining in its unregulated wholesale portfolio when expected sales are compared with supply contracts.  

32

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
		Location of Gain or Loss	For the Three Months Ended
(Millions of Dollars)		Recognized on Derivative	March 31, 2012		March 31, 2011
NU
Commodity and Capacity Contracts
	Required by Regulation	Regulatory Assets	$	6.1	$	(30.1)
Commodity Supply and Price Risk
	Management	Regulatory Assets		(0.1)		(0.3)
Commodity Supply and Price Risk		Fuel, Purchased and Net
	Management	Interchange Power		(0.8)		0.3
CL&P
Commodity and Capacity Contracts
	Required by Regulation	Regulatory Assets		11.1		(30.1)
Commodity Supply and Price Risk
	Management	Regulatory Assets		(0.2)		(1.0)
WMECO
Commodity and Capacity Contracts
	Required by Regulation	Regulatory Assets		(5.0)		-

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  

Fair Value Hedge:  To manage the balance of its fixed and floating rate debt, NU parent had a fixed to floating interest rate swap on its $263 million, fixed rate senior notes that matured on April 1, 2012.  This interest rate swap qualified and was designated as a fair value hedge and required semi-annual cash settlements.  The changes in fair value of the swap and the interest component of the hedged long-term debt instrument were recorded in Interest Expense on the accompanying unaudited condensed consolidated statements of income.  There was no ineffectiveness for the periods ended March 31, 2012 and 2011.  The cumulative changes in fair values of the swap and the Long-Term Debt were recorded as a Derivative Asset and as an adjustment to Long-Term Debt – Current Portion as of December 31, 2011.  As of April 2, 2012, the interest rate swap was settled.

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, were as follows:

	For the Three Months Ended
	March 31, 2012				March 31, 2011
(Millions of Dollars)	Swap		Hedged Debt		Swap		Hedged Debt
Changes in Fair Value	$	-	$	-	$	0.4	$	(0.4)
Interest Recorded in Net Income		-		2.5		-		2.7

Cash Flow Hedges:  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 AOCI. When a cash flow hedge is settled, the settlement amount is recorded in AOCI and is amortized into Net Income over the term of the underlying debt instrument.  Cash flow hedges also 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. NU, CL&P, PSNH and WMECO did not enter into any interest rate swap agreements for the three months ended March 31, 2012. In 2011, PSNH and WMECO entered into cash flow hedges related to a portion of their respective debt issuances.  PSNH entered into three forward starting swaps to fix the U.S. dollar LIBOR swap rate of 3.749 percent on $80 million of a $160 million long-term debt issuance, 2.804 percent on the remaining $80 million of the $160 million long-term debt issuance and 3.6 percent on $120 million of long-term debt issued to refinance outstanding PCRBs.  In May 2011, PSNH settled the swap associated with the $120 million refinancing of PCRBs and a $2.9 million pre-tax reduction in AOCI is being amortized over the life of the debt.  In September 2011, PSNH settled the two remaining swaps and a $15.3 million pre-tax reduction in AOCI is being amortized over the life of the debt.  WMECO entered into a forward starting swap to fix the U.S. dollar LIBOR swap rate of 3.7624 percent associated with $50 million of a $100 million long-term debt issuance.  In September 2011, WMECO settled the swap and a $6.9 million pre-tax reduction in AOCI is being amortized over the life of the debt.    

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

	Gains Recognized in AOCI		Losses Reclassified from AOCI
	on Derivative Instruments		into Interest Expense
	For the Three Months Ended		For the Three Months Ended
(Millions of Dollars)	March 31, 2011		March 31, 2012		March 31, 2011
NU	$	1.9	$	(0.7)	$	(0.1)
CL&P		-		(0.2)		(0.2)
PSNH		1.5		(0.5)		-
WMECO		0.4		(0.1)		-

33

The losses reclassified from AOCI represent the amortization of previously settled interest rate swap agreements for the periods ended March 31, 2012 and 2011.  For the three months ended March 31, 2012, these amounts represent the total change in AOCI related to cash flow hedging activity.  

The change in AOCI related to qualified cash flow hedging activities was 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)
	Cash Flow Hedging 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 Loss as of End of Period	$	(3.0)	$	0.3	$	0.1

Credit Risk

Certain of NU’s contracts relating to the remaining wholesale marketing sourcing contracts contain credit risk contingent features.  These features require NU 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 were in a liability position and subject to credit risk contingent features, the fair value of cash collateral and the additional collateral in the form of LOCs that would be required to be posted by NU if the unsecured debt credit ratings of NU parent were downgraded to below investment grade as of March 31, 2012 and December 31, 2011:  

As of March 31, 2012

As of December 31, 2011

Additional Standby

Additional Standby

Fair Value

LOCs Required if

Fair Value

LOCs Required if

Subject to Credit

Cash

Downgraded

Subject to Credit

Cash

Downgraded

Risk Contingent

Collateral

Below Investment

Risk Contingent

Collateral

Below Investment

(Millions of Dollars)

Features

Posted

Grade

Features

Posted

Grade

NU

$

(25.1)

$

7.5

$

17.4

$

(23.5)

$

4.1

$

19.9

Fair Value Measurements of Derivative Instruments:  

Valuation of Derivative Instruments:  Derivative contracts classified as Level 2 in the fair value hierarchy relate to the remaining wholesale marketing sourcing contracts to purchase energy for periods in which prices are quoted in an active market.  Prices are obtained from broker quotes and based on actual market activity.  The contracts are valued using the mid-point of the bid-ask spread.  Valuations of these contracts also incorporate discount rates using the yield curve approach.  

The derivative contracts classified as Level 3 utilize significant unobservable inputs and include the Regulated companies' Commodity and Capacity Contracts Required by Regulation and Commodity Supply and Price Risk Management contracts (primarily NU's remaining wholesale marketing sales contract).  For Commodity and Capacity Contracts Required by Regulation and NU's remaining unregulated wholesale marketing sales contract, fair value is modeled using income techniques, such as discounted cash flow approaches adjusted for assumptions relating to exit price.  Significant observable inputs for valuations of these contracts include energy and energy-related product prices in future years for which quoted prices in an active market exist.  Fair value measurements categorized in Level 3 of the fair value hierarchy are prepared by individuals with expertise in valuation techniques, pricing of energy and energy-related products, and accounting requirements.  NU does not engage in the purchase or sale of Level 3 derivative contracts.  For Commodity and Capacity Contracts Required by Regulation, the future power and capacity prices for periods that are not quoted in an active market or established at auction are based on available market data and are escalated based on estimates of inflation to address the full time period of the contract.  

Valuations of derivative contracts using discounted cash flow methodology include assumptions regarding the timing and likelihood of scheduled payments and also reflect non-performance risk, including credit, using the default probability approach based on the counterparty's credit rating for assets and the company's credit rating for liabilities.   Valuations incorporate estimates of premiums or discounts that would be required by a market participant to arrive at an exit price, using historical market transactions adjusted for the terms of the contract.   

34

The following is a summary of NU’s, including CL&P’s and WMECO’s Level 3 derivative contracts required by regulation and the range of the significant unobservable inputs utilized in the valuations over the duration of the contracts:

	Range	Period Covered
Energy Prices:
NU	$43 - $82 per MWh	2017 - 2027
CL&P	$49 - $55 per MWh	2017 - 2020
WMECO	$43 - $82 per MWh	2017 - 2027
Capacity Prices:
NU	$1.40 - $10.18 per kW-Month	2015 - 2027
CL&P	$1.40 - $9.50 per kW-Month	2015 - 2026
WMECO	$1.40 - $10.18 per kW-Month	2015 - 2027
Forward Reserve:
NU, CL&P	$0.75 - $1.00 per kW-Month	2012 - 2024
REC Prices:
NU, WMECO	$25 - $85 per REC	2012 - 2027

NU, CL&P and WMECO also apply an exit price premium of 15 percent through 32 percent on these contracts that extend through 2027.

Significant increases or decreases in future power or capacity prices in isolation would decrease or increase, respectively, the values of the derivative liability.   Any increases in the risk premiums would increase the fair value of the derivative liabilities.  Changes in the fair values of the commodity and capacity contracts required by regulation are recorded as a regulatory asset or liability and would not impact net income.

Valuations using significant unobservable inputs:  The following tables present changes for the three months ended March 31, 2012 and 2011 in the Level 3 category of derivative assets and derivative liabilities measured at fair value on a recurring basis.  The derivative assets and liabilities are presented on a net basis.  The fair value as of January 1, 2012 reflects a reclassification of remaining unregulated wholesale marketing sourcing contracts that had previously been presented as a portfolio along with the unregulated wholesale marketing sales contract as Level 3 under the highest and best use valuation premise. These contracts are now classified within Level 2 of the fair value hierarchy.

			As of March 31, 2012					As of March 31, 2011
		Commodity						Commodity
		and Capacity		Commodity				and Capacity		Commodity
		Contracts		Supply and				Contracts		Supply and
NU		Required By		Price Risk		Total		Required By		Price Risk		Total
(Millions of Dollars)		Regulation		Management		Level 3		Regulation		Management		Level 3
Derivatives, Net:
Fair Value as of Beginning of Period		$	(939.3)	$	(22.9)	$	(962.2)	$	(808.0)	$	(32.2)	$	(840.2)
Transfer to Level 2			-		32.2		32.2		-		-		-
Net Realized/Unrealized Gains/(Losses)   Included in:
	Net Income(1)		-		8.0		8.0		-		0.3		0.3
	Regulatory Assets		6.1		(0.1)		6.0		(30.1)		(1.1)		(31.2)
Settlements			21.0		(6.5)		14.5		(5.8)		4.2		(1.6)
Fair Value as of End of Period		$	(912.2)	$	10.7	$	(901.5)	$	(843.9)	$	(28.8)	$	(872.7)

		As of March 31, 2012									As of March 31, 2011
		CL&P						WMECO			CL&P
		Commodity						Commodity			Commodity
		and Capacity		Commodity				and Capacity			and Capacity		Commodity
		Contracts		Supply and				Contracts			Contracts		Supply and
		Required By		Price Risk				Required By			Required By		Price Risk
(Millions of Dollars)		Regulation		Management		Total Level 3		Regulation			Regulation		Management	Total Level 3
Derivatives, Net:
Fair Value as of Beginning of Period		$	(932.0)	$	0.4	$	(931.6)	$	(7.3)	$	(808.0)	$	1.9	$	(806.1)
Net Realized/Unrealized
	Gains/(Losses) Included in
	Regulatory Assets		11.1		(0.2)		10.9		(5.0)		(30.1)		(1.0)		(31.1)
Settlements			21.0		0.1		21.1		-		(5.8)		0.4		(5.4)
Fair Value as of End of Period		$	(899.9)	$	0.3	$	(899.6)	$	(12.3)	$	(843.9)	$	1.3	$	(842.6)

(1)

The gains included in Net Income for the period ended March 31, 2012 relate to the unregulated wholesale marketing sales contract and are offset by the losses on the unregulated sourcing contracts classified as Level 2 in the fair value hierarchy, resulting in a net loss of $0.8 million, which is included in Fuel, Purchased and Net Interchange Power for the three months ended March 31, 2012.  Included in the gain above is $4.4 million of unrealized gains related to items still held as of March 31, 2012.

35

These gains are offset by unrealized losses of $4.6 million on the contracts classified as Level 2 in the fair value hierarchy.  As of March 31, 2011, the total unrealized gains for the unregulated wholesale portfolio were $0.4 million.  

6.

MARKETABLE SECURITIES (NU, WMECO)

NU maintains a supplemental benefit trust to fund NU’s SERP and non-SERP obligations and WMECO maintains a spent nuclear fuel trust to fund WMECO’s prior period spent nuclear fuel liability, both of which hold marketable securities. These trusts are not subject to regulatory oversight by state or federal agencies.

The Company elects to record mutual funds purchased by the NU supplemental benefit trust at fair value.  As such, any change in fair value of these purchased equity securities is reflected in Net Income.  These equity securities, classified as Level 1 in the fair value hierarchy, totaled $44.3 million and $41.1 million as of March 31, 2012 and December 31, 2011, respectively, and are included in current Marketable Securities.  Net gains on these securities of $3.2 million and $1.9 million for the three months ended March 31, 2012 and 2011, 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 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 Marketable Securities on the accompanying unaudited condensed consolidated balance sheets.

	As of March 31, 2012
			Pre-Tax		Pre-Tax
	Amortized		Unrealized		Unrealized
(Millions of Dollars)	Cost		Gains(1)		Losses(1)		Fair Value
NU	$	90.5	$	2.1	$	(0.1)	$	92.5
WMECO		57.4		0.1		(0.1)		57.4
	As of December 31, 2011
			Pre-Tax		Pre-Tax
	Amortized		Unrealized		Unrealized
(Millions of Dollars)	Cost		Gains(1)		Losses(1)		Fair Value
NU	$	88.4	$	2.0	$	(0.2)	$	90.2
WMECO		57.3		-		(0.2)		57.1

⁽¹⁾

Unrealized gains and losses on debt securities for the NU supplemental benefit trust and WMECO spent nuclear fuel trust are recorded in AOCI and Other Long-Term Assets, respectively, on the accompanying unaudited condensed consolidated balance sheets.  

Unrealized Losses and Other-than-Temporary Impairment:  There have been no significant unrealized losses, other-than-temporary impairments or credit losses for the NU supplemental benefit trust 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 debt securities, underlying collateral and expected future cash flows are also evaluated.

Realized Gains and Losses:  Realized gains and losses on available-for-sale-securities, including any credit loss and any gains or losses on securities the company intends to sell or will be required to sell, 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.

Contractual Maturities:  As of March 31, 2012, the contractual maturities of available-for-sale debt securities are as follows:   

	NU				WMECO
	Amortized				Amortized
(Millions of Dollars)	Cost		Fair Value		Cost		Fair Value
Less than one year	$	18.4	$	18.4	$	13.9	$	14.0
One to five years		33.5		33.8		27.4		27.4
Six to ten years		12.0		12.5		6.6		6.6
Greater than ten years		26.6		27.8		9.5		9.4
Total Debt Securities	$	90.5	$	92.5	$	57.4	$	57.4

36

Fair Value Measurements:  The following table presents the marketable securities recorded at fair value on a recurring basis by the level in which they are classified within the fair value hierarchy:

			NU				WMECO
			As of		As of		As of		As of
(Millions of Dollars)			March 31, 2012		December 31, 2011		March 31, 2012		December 31, 2011
Level 1:
	Mutual Funds		$	44.3	$	41.1	$	-	$	-
	Money Market Funds			6.2		1.8		3.1		0.1
Total Level 1			$	50.5	$	42.9	$	3.1	$	0.1
Level 2:
	U.S. Government Issued Debt Securities
		(Agency and Treasury)		22.4		11.1		19.3		8.0
	Corporate Debt Securities			15.4		16.5		7.3		9.1
	Asset-Backed Debt Securities			22.9		25.9		5.1		7.9
	Municipal Bonds			13.6		16.1		12.8		15.4
	Other Fixed Income Securities			12.0		18.8		9.8		16.6
Total Level 2			$	86.3	$	88.4	$	54.3	$	57.0
Total Marketable Securities			$	136.8	$	131.3	$	57.4	$	57.1

U.S. government issued debt securities are valued using market approaches that incorporate transactions for the same or similar bonds and adjustments for yields and maturity dates.  Corporate debt securities are valued using a market approach, utilizing recent trades of the same or similar instrument and also incorporating yield curves, credit spreads and specific bond terms and conditions.  Asset-backed debt securities include collateralized mortgage obligations, commercial mortgage backed securities, and securities collateralized by auto loans, credit card loans or receivables.  Asset-backed debt securities are valued using recent trades of similar instruments, prepayment assumptions, yield curves, issuance and maturity dates and tranche information.  Municipal bonds are valued using a market approach that incorporates reported trades and benchmark yields.  Other fixed income securities are valued using pricing models, quoted prices of securities with similar characteristics, and discounted cash flows.

7.

SHORT-TERM DEBT

Limits:  The amount of short-term borrowings that may be incurred by CL&P and WMECO are subject to periodic approval by the FERC.  On November 30, 2011, the FERC granted authorization to allow CL&P to incur total short-term borrowings up to a maximum of $450 million effective January 1, 2012 through December 31, 2013.  On March 22, 2012, FERC approved CL&P's application requesting to increase its total short-term borrowing capacity from a maximum of $450 million to a maximum of $600 million for the authorization period through December 31, 2013.

CL&P Credit Agreement:  On March 26, 2012, CL&P entered into a five-year unsecured revolving credit facility in the amount of $300 million, which expires on March 26, 2017.  Under this facility, CL&P can borrow either on a short-term or a long-term basis subject to regulatory approval.  As of March 31, 2012, CL&P had $275 million in short-term borrowings outstanding under this credit facility, which was recorded in Notes Payable to Banks on the accompanying unaudited condensed consolidated balance sheet.

Under this facility, CL&P may borrow at prime rates or LIBOR-based rates, plus an applicable margin based on the higher of S&P’s or Moody’s credit ratings.  The weighted-average interest rate on the borrowings outstanding under this facility as of March 31, 2012 was 1.5 percent.  

In addition, CL&P must comply with certain financial and non-financial covenants, including a consolidated debt to total capitalization ratio.  CL&P was in compliance with these covenants as of March 31, 2012.  If CL&P was not in compliance with these covenants, an event of default would occur requiring all outstanding borrowings to be repaid and additional borrowings would not be permitted under this credit facility.  

8.

LONG-TERM DEBT

On March 22, 2012, NU parent issued $300 million of floating rate Series D Senior Notes with a maturity date of September 20, 2013.  The notes have a coupon rate based on the three-month LIBOR rate plus a credit spread of 0.75 percent and will reset quarterly.  The notes had an initial interest rate of 1.22 percent as of March 31, 2012.  The proceeds, net of issuance expenses, were used to repay at maturity the NU parent $263 million Series A Senior Notes that matured on April 1, 2012, to repay short-term borrowings outstanding under the NU parent Credit Agreement and for other general corporate purposes.  The indenture under which the bonds were issued requires NU to comply with certain covenants as are customarily included in such indentures.  

NU, including CL&P, PSNH and WMECO, was in compliance with all its debt covenants as of March 31, 2012.

37

9.

PENSION BENEFITS AND POSTRETIREMENT BENEFITSOTHER THAN PENSIONS

NUSCO sponsors a Pension Plan, which is subject to the provisions of ERISA, as amended by the PPA of 2006.  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 and PBOP Plans are as follows:

		For the Three Months Ended March 31, 2012
		Pension and SERP								PBOP
(Millions of Dollars)		NU		CL&P		PSNH		WMECO		NU		CL&P		PSNH		WMECO
Service Cost		$	15.3	$	5.4	$	2.9	$	1.1	$	2.3	$	0.8	$	0.5	$	0.2
Interest Cost			38.1		12.8		6.1		2.6		6.2		2.4		1.2		0.5
Expected Return on Plan Assets			(42.5)		(17.5)		(6.7)		(4.1)		(5.6)		(2.3)		(1.1)		(0.5)
Actuarial Loss			30.1		11.9		3.9		2.5		5.5		2.0		1.0		0.3
Prior Service Cost/(Credit)			2.1		0.9		0.4		0.2		(0.1)		-		-		-
Net Transition Obligation Cost			-		-		-		-		2.9		1.5		0.6		0.3
Total Net Periodic Benefit Expense		$	43.1	$	13.5	$	6.6	$	2.3	$	11.2	$	4.4	$	2.2	$	0.8
Related Intercompany
	Allocations		N/A	$	10.6	$	2.5	$	2.0		N/A	$	2.1	$	0.5	$	0.4
Capitalized Pension Expense		$	10.6	$	6.6	$	2.0	$	1.2
		For the Three Months Ended March 31, 2011
		Pension and SERP								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 Benefit 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
Capitalized Pension Expense		$	7.6	$	4.5	$	1.8	$	0.7

Contributions: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, as amended by the PPA of 2006, and the Internal Revenue Code.  Based on the current status of the Pension Plan, NU is required to make a contribution to the Pension Plan of approximately $197.3 million in 2012 to meet minimum funding requirements under the PPA.  Contributions are being made in installments and began in January 2012.  NU made contributions totaling $92 million ($87.7 million of which was contributed by PSNH) in the first quarter of 2012.  

10.

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 number of environmental sites and reserves related to these sites for which remediation or long-term monitoring, preliminary site work or site assessment are being performed, as well as the portion related to MGP sites are as follows:

	As of March 31, 2012						As of December 31, 2011
					Portion Related to						Portion Related to
			Reserve		MGP Sites				Reserve		MGP Sites
	Number of Sites		(in millions)		(in millions)		Number of Sites		(in millions)		(in millions)
NU		61	$	31.7	$	28.6		59	$	31.7	$	28.9
CL&P		19		3.3		1.5		18		2.9		1.5
PSNH		19		6.8		5.8		18		6.6		5.8
WMECO		10		0.3		0.1		10		0.3		0.1

MGP sites are 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.

38

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, 2012 was $19.5 million, of which $17.2 million had been spent, leaving $2.3 million in the reserve as of March 31, 2012.  There were no charges to the reserve for the three months ended March 31, 2012 or 2011.  HWP's share of the costs related to this site is not recoverable from customers.

The $2.3 million reserve balance as of March 31, 2012 represents estimated costs that HWP considers probable over the remaining life of the project, including testing and related costs in the near term and field activities to be agreed upon with the MA DEP, further studies and long-term monitoring that are expected to be required by the MA DEP, and certain soft tar remediation activities.  Various factors could affect management's estimates and require an increase to the reserve, which would be reflected as a charge to Net Income.  Although a material increase to the reserve is not presently anticipated, management cannot reasonably estimate potential additional investigation or remediation costs because these costs would depend on, among other things, the nature, extent and timing of additional investigation and remediation that may be required by the MA DEP.    

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 provided guarantees and various indemnifications on behalf of external parties as a result of the sales of former subsidiaries of NU Enterprises, with maximum exposures either not specified or not material.  

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

Management does not anticipate a material impact to Net Income 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, 2012:  

		Maximum
		Exposure
Subsidiary	Description	(in millions)			Expiration Dates
Various	Surety Bonds and Performance Guarantees	$	22.8		April 2012 - April 2013 (1)
Various	Letters of Credit	$	19.9		June 2012 - December 2012
NUSCO and RRR	Lease Payments for Vehicles and Real Estate	$	22.1		2019 and 2024
NU Enterprises	Surety Bonds, Insurance Bonds and Performance Guarantees	$	121.4	(2)	(2)

⁽¹⁾

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

⁽²⁾

The maximum exposure includes $50.4 million related to performance guarantees on wholesale marketing purchase contracts, which expire in 2013.  The maximum exposure also includes $14 million related to a performance guarantee for which no maximum exposure is specified in the agreement.  The maximum exposure was calculated as of March 31, 2012 based on limits of the liability contained in the underlying service contract and assumes that NU Enterprises will perform under that contract through its expiration in 2020.  Also included in the maximum exposure is $1.2 million related to insurance bonds with no expiration date that are billed annually on their anniversary date.  The remaining $55.8 million of maximum exposure relates to surety bonds covering ongoing projects, 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.  

C.

Exposure Regarding Complaint on FERC Base ROE

On September 30, 2011, several New England state attorneys general, state regulatory commissions, consumer advocates and other parties filed a joint complaint with the FERC under Sections 206 and 306 of the Federal Power Act alleging that the base ROE used in calculating formula rates for transmission service under the ISO-NE Open Access Transmission Tariff by New England transmission owners, including CL&P, NSTAR Electric, PSNH and WMECO, is unjust and unreasonable.  The complainants asserted that the current 11.14 percent rate, which became effective in 2006, is excessive due to changes in the capital markets and are seeking an order to reduce the rate to 9.2 percent, effective September 30, 2011.  In response, the New England transmission owners filed testimony and analysis based on standard FERC methodology and precedent justifying a base ROE of approximately 11.2 percent, thus demonstrating that the base ROE of 11.14 percent remained just and reasonable.

39

On May 3, 2012, the FERC issued an order establishing hearing and settlement procedures for the complaint.  In the order, FERC encouraged the parties to reach a settlement of the dispute before hearings commence.  One of the commissioners dissented,stating that the complaint should have been rejected based on the record and FERC precedent.  The FERC indicated that if a settlement was not reached, it would expect to render a final decision in the third quarter of 2013 with changes, if any, effective October 1, 2011.  Management cannot at this time predict what ROE will ultimately be established or its impact on CL&P’s, NSTAR Electric’s, PSNH’s, or WMECO’s respective financial position, results of operations or cash flows.

11.

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.  The fair values provided in the tables below are classified as Level 2 within the fair value hierarchy.  Carrying amounts and estimated fair values are as follows:

		As of March 31, 2012
		NU				CL&P				PSNH				WMECO
		Carrying		Fair		Carrying		Fair		Carrying		Fair		Carrying		Fair
(Millions of Dollars)		Amount		Value		Amount		Value		Amount		Value		Amount		Value
Preferred Stock Not
	Subject to Mandatory
	Redemption	$	116.2	$	106.9	$	116.2	$	106.9	$	-	$	-	$	-	$	-
Long-Term Debt			5,250.7		5,744.0		2,587.8		2,946.5		999.5		1,056.3		501.1		527.0
Rate Reduction Bonds			94.4		97.6		-		-		71.9		74.3		22.5		23.3
		As of December 31, 2011
		NU				CL&P				PSNH				WMECO
		Carrying		Fair		Carrying		Fair		Carrying		Fair		Carrying		Fair
(Millions of Dollars)		Amount		Value		Amount		Value		Amount		Value		Amount		Value
Preferred Stock Not
	Subject to Mandatory
	Redemption	$	116.2	$	105.1	$	116.2	$	105.1	$	-	$	-	$	-	$	-
Long-Term Debt			4,950.7		5,517.0		2,587.8		2,987.1		999.5		1,075.2		501.1		539.8
Rate Reduction Bonds			112.3		116.8		-		-		85.4		88.8		26.9		28.1

Derivative Instruments:  NU, including CL&P, PSNH and WMECO, holds various derivative instruments that are carried at fair value.  For further information, see Note 5, "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 1E, "Summary of Significant Accounting Policies - Fair Value Measurements," and Note 6, "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.

12.

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 as of March 31, 2012 and December 31, 2011 and the respective par values:  

	Shares
	Authorized			Issued
	Per Share		As of March 31, 2012
	Par Value		and December 31, 2011	As of March 31, 2012		As of December 31, 2011
NU	$	5	380,000,000		196,318,359		196,052,770
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, 2012 and December 31, 2011, 18,790,898 and 18,894,078 NU common shares were held as treasury shares, respectively.

On March 4, 2011, NU's shareholders approved an increase in authorized shares from 225,000,000 to 380,000,000 in connection with the consummation of the NU-NSTAR merger.

40

13.		COMMON SHAREHOLDERS' EQUITY AND NONCONTROLLING INTERESTS (NU)
A summary of the changes in Common Shareholders' Equity and Noncontrolling Interests of NU is as follows:
			For the Three Months Ended
			March 31, 2012								March 31, 2011
									Preferred Stock								Preferred Stock
			Common						Not Subject to		Common						Not Subject to
			Shareholders'		Noncontrolling		Total		Mandatory		Shareholders'		Noncontrolling		Total		Mandatory
(Millions of Dollars)			Equity		Interest		Equity		Redemption		Equity		Interest		Equity		Redemption
Balance as of Beginning of Period			$	4,012.7	$	3.0	$	4,015.7	$	116.2	$	3,811.2	$	1.5	$	3,812.7	$	116.2
Net Income				100.8		-		100.8		-		115.6		-		115.6		-
Dividends on Common Shares				(52.6)		-		(52.6)		-		(48.8)		-		(48.8)		-
Dividends on Preferred Stock				(1.4)		-		(1.4)		(1.4)		(1.4)		-		(1.4)		(1.4)
Issuance of Common Shares				6.2		-		6.2		-		4.2		-		4.2		-
Contributions to NPT				-		0.3		0.3		-		-		-		-		-
Other Transactions, Net				0.8		-		0.8		-		2.4		-		2.4		-
Net Income Attributable to
	Noncontrolling Interests			(0.1)		0.1		-		1.4		-		-		-		1.4
Other Comprehensive Income				1.9		-		1.9		-		2.1		-		2.1		-
Balance as of End of Period			$	4,068.3	$	3.4	$	4,071.7	$	116.2	$	3,885.3	$	1.5	$	3,886.8	$	116.2
For the three months ended March 31, 2012 and 2011, there was no change in NU parent's 100 percent ownership of the common equity of CL&P and 75 percent ownership of NPT.

14.

EARNINGS PER SHARE (NU)

Basic EPS is computed based upon the monthly weighted average number of common shares outstanding 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 shares.  There were no antidilutive share awards outstanding for the three months ended March 31, 2012 and 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)		2012		2011
Net Income Attributable to Controlling Interests		$	99.3	$	114.2
Weighted Average Common Shares Outstanding:
	Basic		178,055,716		177,188,207
	Dilutive Effect		381,737		292,789
	Diluted		178,437,453		177,480,996
Basic and Diluted EPS		$	0.56	$	0.64

RSUs and performance shares are included in basic weighted average common shares outstanding as of the date that all necessary vesting conditions have been satisfied.  The dilutive effect of unvested RSUs and performance shares is calculated using the treasury stock method.  Assumed proceeds of the units under the treasury stock method consist of the remaining compensation cost to be recognized and a theoretical tax benefit.  The theoretical tax benefit is calculated as the tax impact of the intrinsic value of the units (the difference between the market value of the average units outstanding for the period, using the average market price during the period, and the grant date market value).  

The dilutive effect of stock options to purchase common shares is also calculated using the treasury stock method.  Assumed proceeds for stock options consist of 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 exercise price).  

15.

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

41

companies' segments represented substantially all of NU's total consolidated revenues for the three months ended March 31, 2012 and 2011.

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, RRR (a real estate subsidiary), the non-energy-related subsidiaries of Yankee and the remaining operations of HWP.  

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, 2012 and 2011, with the distribution segment segregated between electric and natural gas, is as follows:

		For the Three Months Ended March 31, 2012
		Regulated Companies
		Distribution
(Millions of Dollars)		Electric		Natural Gas		Transmission		Other		Eliminations		Total
Operating Revenues		$	786.0	$	139.0	$	162.8	$	133.3	$	(121.5)	$	1,099.6
Depreciation and Amortization			(73.0)		(7.7)		(21.1)		(3.9)		0.3		(105.4)
Other Operating Expenses			(621.3)		(102.2)		(47.6)		(134.9)		126.2		(779.8)
Operating Income/(Loss)			91.7		29.1		94.1		(5.5)		5.0		214.4
Interest Expense			(33.0)		(5.4)		(19.7)		(9.4)		1.1		(66.4)
Interest Income			1.1		-		0.1		1.3		(1.3)		1.2
Other Income, Net			4.4		-		3.3		122.6		(122.7)		7.6
Income Tax Expense			(21.4)		(9.0)		(30.8)		6.0		(0.8)		(56.0)
Net Income			42.8		14.7		47.0		115.0		(118.7)		100.8
Net Income Attributable
	to Noncontrolling Interests		(0.8)		-		(0.7)		-		-		(1.5)
Net Income Attributable
	to Controlling Interests	$	42.0	$	14.7	$	46.3	$	115.0	$	(118.7)	$	99.3
Total Assets (as of)		$	9,553.3	$	1,498.2	$	3,900.7	$	7,261.7	$	(6,235.5)	$	15,978.4
Cash Flows Used for
	Investments in Plant	$	130.7	$	20.5	$	135.9	$	17.2	$	-	$	304.3

		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/(Loss)			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 Used for
	Investments in Plant	$	138.7	$	21.8	$	61.8	$	14.4	$	-	$	236.7

42

The information related to the distribution and transmission segments for CL&P, PSNH and WMECO for the three months ended March 31, 2012 and 2011 is included below.

		CL&P - For the Three Months Ended
		March 31, 2012						March 31, 2011
(Millions of Dollars)		Distribution		Transmission		Total		Distribution		Transmission		Total
Operating Revenues		$	474.7	$	117.3	$	592.0	$	549.9	$	123.8	$	673.7
Depreciation and Amortization			(33.4)		(16.0)		(49.4)		(41.5)		(17.3)		(58.8)
Other Operating Expenses			(396.2)		(34.5)		(430.7)		(451.8)		(37.1)		(488.9)
Operating Income			45.1		66.8		111.9		56.6		69.4		126.0
Interest Expense			(18.8)		(14.7)		(33.5)		(16.5)		(13.3)		(29.8)
Interest Income			0.6		0.1		0.7		0.6		0.1		0.7
Other Income, Net			2.7		1.9		4.6		1.4		2.5		3.9
Income Tax Expense			(8.0)		(21.7)		(29.7)		(12.8)		(23.7)		(36.5)
Net Income		$	21.6	$	32.4	$	54.0	$	29.3	$	35.0	$	64.3
Total Assets (as of)		$	6,141.6	$	2,659.1	$	8,800.7	$	5,563.7	$	2,622.8	$	8,186.5
Cash Flows Used for
	Investments in Plant	$	70.9	$	37.9	$	108.8	$	80.3	$	26.5	$	106.8

		PSNH - For the Three Months Ended
		March 31, 2012						March 31, 2011
(Millions of Dollars)		Distribution		Transmission		Total		Distribution		Transmission		Total
Operating Revenues		$	219.5	$	23.5	$	243.0	$	247.9	$	21.6	$	269.5
Depreciation and Amortization			(29.3)		(3.2)		(32.5)		(43.8)		(2.8)		(46.6)
Other Operating Expenses			(156.7)		(8.4)		(165.1)		(168.0)		(8.0)		(176.0)
Operating Income			33.5		11.9		45.4		36.1		10.8		46.9
Interest Expense			(10.6)		(2.2)		(12.8)		(8.7)		(1.8)		(10.5)
Interest Income			0.3		-		0.3		0.5		0.1		0.6
Other Income, Net			1.2		0.6		1.8		3.5		0.5		4.0
Income Tax Expense			(9.3)		(4.1)		(13.4)		(9.9)		(3.6)		(13.5)
Net Income		$	15.1	$	6.2	$	21.3	$	21.5	$	6.0	$	27.5
Total Assets (as of)		$	2,473.2	$	565.9	$	3,039.1	$	2,363.7	$	492.7	$	2,856.4
Cash Flows Used for
	Investments in Plant	$	47.6	$	19.5	$	67.1	$	46.1	$	11.6	$	57.7

		WMECO - For the Three Months Ended
		March 31, 2012						March 31, 2011
(Millions of Dollars)		Distribution		Transmission		Total		Distribution		Transmission		Total
Operating Revenues		$	91.9	$	22.1	$	114.0	$	93.9	$	12.8	$	106.7
Depreciation and Amortization			(10.3)		(1.9)		(12.2)		(6.6)		(3.3)		(9.9)
Other Operating Expenses			(68.5)		(4.6)		(73.1)		(72.6)		(3.1)		(75.7)
Operating Income			13.1		15.6		28.7		14.7		6.4		21.1
Interest Expense			(3.6)		(2.8)		(6.4)		(4.5)		(1.1)		(5.6)
Interest Income			0.1		-		0.1		0.1		-		0.1
Other Income/(Loss), Net			0.6		0.4		1.0		(1.0)		1.7		0.7
Income Tax Expense			(4.1)		(5.1)		(9.2)		(3.6)		(2.7)		(6.3)
Net Income		$	6.1	$	8.1	$	14.2	$	5.7	$	4.3	$	10.0
Total Assets (as of)		$	944.2	$	631.0	$	1,575.2	$	871.8	$	344.7	$	1,216.5
Cash Flows Used for
	Investments in Plant	$	12.2	$	72.8	$	85.0	$	12.2	$	20.8	$	33.0

16.

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 variable interest entities (VIEs) through agreements with certain entities that own single renewable energy or peaking generation power plants and with other independent power producers.  NU 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.  

17.

SUBSEQUENT EVENTS (NU, CL&P)

On April 2, 2012, CL&P remarketed $62 million of tax-exempt PCRBs for a three-year period.  Given the long-term nature of the remarketing, the $62 million has been classified as Long-Term Debt on the accompanying unaudited condensed consolidated balance sheets as of March 31, 2012.  The PCRBs, which mature on May 1, 2031, carry a coupon rate of 1.55 percent during the current three-year fixed-rate period and are subject to mandatory tender for purchase on April 1, 2015.

On April 2, 2012, NU repaid the NU parent $263 million 7.25 percent Series A Senior Notes that matured on April 1, 2012 with the proceeds from the issuance of the floating rate Series D Senior Notes issued on March 22, 2012.

On April 10, 2012, NU acquired 100 percent of the outstanding common stock of NSTAR and NSTAR (through a successor, NSTAR LLC) became a direct wholly-owned subsidiary of NU.  Refer to Note 2, "Merger of NU and NSTAR," for further information.

43

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 2011 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 excluding NSTAR and its 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 thisManagement's Discussion and Analysis of Financial Condition and Results of Operations.  

The only common equity securities that are publicly traded are common shares of NU.  The earnings and EPS of each business discussed below do not represent a direct legal interest in the assets and liabilities allocated to such business but rather represent a direct interest in our assets and liabilities as a whole.  EPS by business is a financial measure not recognized under GAAP that is calculated by dividing the Net Income Attributable to Controlling 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 2012 and 2011 earnings and EPS excluding expenses related to NU's merger with NSTAR.  We use this non-GAAP financial measure to more fully compare and explain the first quarter 2012 and 2011 results without including the impact of this non-recurring item.  Due to the nature and significance of this item on Net Income Attributable to Controlling Interests, 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 an alternative to reported Net Income Attributable to Controlling Interests or EPS determined in accordance with GAAP as an indicator of operating performance.

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

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 and taxing bodies,

·

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

·

changes in weather patterns,

·

changes in laws, regulations or regulatory policy,

·

changes in levels and timing of capital expenditures,

·

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

·

developments in legal or public policy doctrines,

·

technological developments,

·

changes in accounting standards and financial reporting regulations,

·

actions of rating agencies,

·

the effects and outcomes of our merger with NSTAR, and

·

other presently unknown or unforeseen factors.  

Other risk factors are detailed in our and NSTAR’s 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

44

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 2011 Form 10-K.  This Quarterly Report on Form 10-Q and our 2011 Form 10-K also describe material contingencies and critical accounting policies and estimates in the accompanyingManagement's Discussion and Analysis andCombined Notes to Consolidated Financial Statements.  We encourage you to review these items.

Financial Condition and Business Analysis

Merger with NSTAR:

On April 10, 2012, NU and NSTAR completed their previously announced merger.  Pursuant to the terms and conditions of the Agreement and Plan of Merger, dated as of October 16, 2010, as amended, by and among NU, NSTAR, NU Holding Energy 1 LLC, a wholly owned subsidiary of NU, and NU Holding Energy 2 LLC, a wholly owned subsidiary of NU, (as amended, the "Merger Agreement"), NU Holding Energy 1 LLC was merged with and into NSTAR, after which NSTAR was merged with and into NU Holding Energy 2 LLC with NU Holding Energy 2 LLC remaining a wholly owned subsidiary of NU.  In connection with the merger, the name of NU Holding Energy 2 LLC has been changed to NSTAR LLC.  Due to the timing of the consummation of the merger, NSTAR results are not reflected in NU’s first quarter 2012 results.  However, they will be reflected beginning with second quarter 2012 results.  Although the merger occurred on April 10, 2012, NU adopted an effective date of April 1, 2012 for accounting purposes.  The activity for the period from April 1, 2012 through April 9, 2012 was not material to the combined company.

The transaction was structured as a merger of equals in a tax-free exchange of shares.  Pursuant to the Merger Agreement, NU issued to NSTAR shareholders 1.312 NU common shares for each issued and outstanding NSTAR common share (the "exchange ratio").  As a result, NU had approximately 314 million shares outstanding as of April 30, 2012, compared with approximately 178 million shares outstanding as of March 31, 2012.  

The final merger approvals were issued on April 2, 2012 by the PURA and on April 4, 2012 by the DPU.  Both state regulatory approvals contained a number of conditions that were primarily the result of settlement agreements with state officials that had intervened in the merger approval processes.  For further information regarding those conditions, see "Regulatory Developments and Rate Matters – Regulatory Approvals for Merger with NSTAR," in thisManagement’s Discussion and Analysis.  

Consistent with the conditions in the Merger Agreement, on May 2, 2012, our Board of Trustees declared a quarterly common dividend of $0.343 per share, payable on June 29, 2012 to shareholders of record as of June 1, 2012.

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, 2012, compared with the same period in 2011:

·

We earned $99.3 million, or $0.56 per share, compared with $114.2 million, or $0.64 per share.  Excluding merger-related costs of $1.1 million, or less than $0.01 per share, we earned $100.4 million, or $0.56 per share, in the first quarter of 2012.  Lower results in the first quarter of 2012 were due primarily to much milder weather, compared with the first quarter of 2011, as well as higher pension and other employee-related costs.

·

Our Regulated companies earned $103 million, or $0.58 per share, compared with $122.9 million, or $0.69 per share.  

·

The distribution segment of our Regulated companies earned $56.7 million, or $0.32 per share, compared with $78.2 million, or $0.44 per share.  The transmission segment of our Regulated companies earned $46.3 million, or $0.26 per share, compared with $44.7 million, or $0.25 per share.  

·

NU parent and other companies recorded net expenses of $3.7 million, or $0.02 per share, compared with net expenses of $8.7 million, or $0.05 per share.  Excluding merger-related costs of $1.1 million, or less than $0.01 per share, NU parent and other companies recorded net expenses of $2.6 million, or $0.02 per share, in the first quarter of 2012.  

Legislative, Regulatory and Other Items:

·

On March 5, 2012, New Hampshire enacted a bill that prohibits the use of eminent domain for the development of any "non-reliability" electric transmission projects, such as Northern Pass.  Notwithstanding the passage of this law, we believe that NPT will be able to acquire the necessary rights along an acceptable route.  

·

On April 10, 2012, the NHPUC issued an order approving temporary ES rates, effective April 16, 2012 for PSNH, which include a significant portion of the Clean Air Project costs.  The temporary ES rates will remain in effect until a permanent ES rate allowing full recovery is approved.  At that time, the NHPUC will reconcile the recoveries collected under the temporary rates with final approved rates.  

45

·

On May 3, 2012, the FERC established hearing and settlement procedures for the September 30, 2011 complaint alleging that the base ROE used in calculating formula rates for transmission service by New England transmission owners is unjust and unreasonable.  The FERC indicated that if a settlement was not reached, it would expect to render a final decision in the third quarter of 2013.

Liquidity:

·

Cash and cash equivalents totaled $283.4 million as of March 31, 2012, compared with $6.6 million as of December 31, 2011, while cash capital expenditures totaled $304.3 million for the first quarter of 2012, compared with $236.7 million for the first quarter of 2011.  

·

Cash flows used in operating activities totaled $9.1 million in the first quarter of 2012, compared with cash flows provided by operating activities of $355.9 million in the first quarter of 2011 (amounts are net of RRB payments).  The reduced cash flows in the first quarter of 2012 compared to the first quarter of 2011 were due primarily to approximately $153 million of cash disbursements for storm costs primarily related to Tropical Storm Irene and the October 2011 snowstorm, a $92 million Pension Plan cash contribution, approximately $27 million in bill credits provided to CL&P residential customers in February 2012, and negative cash flow impacts associated with undercollections in the first quarter of 2012 of CL&P's FMCC and transmission regulatory tracking mechanisms of $12.9 million and $22.1 million, respectively, as compared to the same period of 2011.  

·

On March 22, 2012, NU parent issued $300 million of 18-month floating rate Series D Senior Notes with a maturity date of September 20, 2013.  The proceeds were used primarily to repay the NU parent $263 million Series A Senior Notes that matured on April 1, 2012.  

·

On March 26, 2012, CL&P entered into a five-year $300 million unsecured revolving credit facility, which expires on March 26, 2017.  The credit facility is intended to finance short-term borrowings CL&P has incurred to fund costs of restoring power following Tropical Storm Irene and the October 2011 snowstorm.  As of March 31, 2012, CL&P had $275 million in short-term borrowings outstanding under this credit facility.  

·

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

Overview

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

	For the Three Months Ended March 31,
	2012				2011
(Millions of Dollars, except per share amounts)	Amount		Per Share		Amount		Per Share
Net Income Attributable to Controlling Interests (GAAP)	$	99.3	$	0.56	$	114.2	$	0.64
Regulated Companies	$	103.0	$	0.58	$	122.9	$	0.69
NU Parent and Other Companies		(2.6)		(0.02)		(0.4)		-
Non-GAAP Earnings		100.4		0.56		122.5		0.69
Merger-Related Costs		(1.1)		-		(8.3)		(0.05)
Net Income Attributable to Controlling Interests (GAAP)	$	99.3	$	0.56	$	114.2	$	0.64

Lower results in the first quarter of 2012 were due primarily tomuch milder weather, compared with the first quarter of 2011, as well as higher pension and other employee-related costs, partially offset by higher transmission segment earnings.

46

Regulated Companies:  Our Regulated companies consist of the electric distribution and 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 2012 and 2011 is as follows:

	For the Three Months Ended March 31,
(Millions of Dollars)	2012		2011
CL&P Transmission	$	31.8	$	34.4
PSNH Transmission		6.2		6.0
WMECO Transmission		8.1		4.2
NPT		0.2		0.1
Total Transmission		46.3		44.7
CL&P Distribution		20.8		28.5
PSNH Distribution		15.1		21.5
WMECO Distribution		6.1		5.7
Yankee Gas		14.7		22.5
Total Distribution		56.7		78.2
Net Income - Regulated Companies	$	103.0	$	122.9

The higher first quarter 2012 transmission segment earnings as compared to 2011 were due primarily to a higher level of investment in transmission infrastructure, including GSRP, which is under construction in western Massachusetts and northern Connecticut.  

CL&P’s first quarter 2012 distribution segment earnings were $7.7 million lower than the same period of 2011 due primarily to lower retail revenue, which was the result of warmer than normal weather in the first quarter of 2012 as compared to colder than normal weather in the first quarter of 2011 with a 6 percent decrease in retail electric sales.  In addition, CL&P had higher pension and employee healthcare costs and an increase in system maintenance and tree trimming costs, partially offset by the favorable impacts of the 2010 distribution rate case decision.  For the twelve months ended March 31, 2012, CL&P’s distribution segment regulatory ROE was 8.9 percent.

PSNH’s first quarter 2012 distribution segment earnings were $6.4 million lower than the same period of 2011 due primarily to lower retail revenue, which was the result of warmer than normal weather in the first quarter of 2012, as compared to colder than normal weather in the first quarter of 2011.  The weather contributed to a 2.4 percent decrease in retail electric sales for the comparative period.  In addition, PSNH had higher operating expenses, including depreciation and municipal taxes, and higher income tax expense.  PSNH also had lower generation business earnings due to the Clean Air Project being placed into service in September 2011, which resulted in AFUDC no longer being accrued on the Project.  Temporary rates authorizing PSNH to include a significant portion of the Clean Air Project's costs in rates, including a return on equity, took effect on April 16, 2012 and will remain in effect until a permanent rate allowing full recovery of all prudently incurred costs is approved.  For the twelve months ended March 31, 2012, PSNH’s distribution segment regulatory ROE was 8.8 percent.

WMECO’s first quarter 2012 distribution segment earnings were $0.4 million higher than the same period of 2011 due primarily to lower operating costs, including storm costs and uncollectible expense.  As WMECO’s distribution rates are "decoupled" from the actual consumption, fluctuations in retail electric sales no longer impact earnings.  For further information on decoupling, see the retail electric sales discussion below.  For the twelve months ended March 31, 2012, WMECO’s distribution segment regulatory ROE was 8.9 percent.

Yankee Gas’ first quarter 2012 earnings were $7.8 million lower than the same period of 2011 due primarily to a 13.2 percent decrease in total firm natural gas sales, which was the result of warmer than normal weather in the first quarter of 2012 as compared to colder than normal weather in the first quarter of 2011, higher expenses, including pension, property taxes, and depreciation.  For the twelve months ended March 31, 2012, Yankee Gas’ regulatory ROE was 7.2 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 2012, as compared to the same period in 2011, on an actual and weather normalized basis (using a 30-year average), is as follows:

	For the Three Months March 31, 2012 Compared to 2011
	CL&P		PSNH		WMECO		Total Electric
Electric	Percentage Increase/ (Decrease)	Weather Normalized Percentage Increase/ (Decrease)	Percentage Increase/ (Decrease)	Weather Normalized Percentage Increase	Percentage Increase/ (Decrease)	Weather Normalized Percentage Increase/ (Decrease)	Sales (GWh)		Percentage Increase/ (Decrease)	Weather Normalized Percentage Increase/ (Decrease)
Residential	(9.3)%	0.4 %	(4.5)%	0.3%	(8.0)%	(0.8)%	3,787	4,123	(8.1)%	0.2 %
Commercial	(3.6)%	(0.4)%	(1.2)%	0.7%	0.8 %	2.4 %	3,381	3,473	(2.6)%	0.1 %
Industrial	(0.8)%	(1.0)%	0.6 %	0.4%	(2.9)%	(3.0)%	1,015	1,022	(0.7)%	(0.9)%
Other	2.3 %	2.3%	1.6 %	1.6%	(15.0)%	(15.0)%	88	87	1.2 %	1.2 %
Total	(6.0)%	(0.1)%	(2.4)%	0.5%	(4.0)%	(0.1)%	8,271	8,705	(5.0)%	0.1 %

47

	For the Three Months Ended March 31, 2012 Compared to 2011
Firm Natural Gas	Sales (million cubic feet)		Percentage Increase/ (Decrease)	Weather Normalized Percentage Increase
Residential	5,375	6,780	(20.7)%	1.6%
Commercial	6,382	7,623	(16.3)%	3.2%
Industrial	5,062	4,981	1.6 %	12.2%
Total	16,819	19,384	(13.2)%	5.0%
Total, Net of Special Contracts(1)	14,744	16,940	(13.0)%	8.1%

⁽¹⁾

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

Actual retail electric sales for all three electric companies were lower in the first quarter 2012, compared to the same period of 2011, due primarily to the warmer than normal weather in the first quarter of 2012, as compared to colder than normal weather in the first quarter of 2011.  In 2012, heating degree days in Connecticut and western Massachusetts were 23.4 percent lower than last year and in New Hampshire, heating degree days were 19.2 percent lower than last year.  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 kilowatt-hours consumed by customers and revenues recognized.

On a weather-normalized basis, retail electric sales in the first quarter of 2012 as compared to the same period in 2011 varied by electric company and by customer class.  Weather adjusted residential sales for both CL&P and PSNH increased, as compared to last year.  We believe these increases were due to improved household income and favorable customer growth, as compared to last year.  WMECO residential sales were subject to the same influences as CL&P and PSNH but WMECO's customers also faced higher electricity prices resulting in lower residential sales.  Weather adjusted commercial sales for CL&P were lower in 2012 due in part to the continued installation of gas-fired distributed generation.  Weather adjusted commercial sales for both PSNH and WMECO increased, as compared to last year, due primarily to favorable customer growth.  We believe the weather adjusted industrial sales for CL&P and WMECO decreased compared to last year due in part to weak manufacturing employment in Connecticut and western Massachusetts.  PSNH industrial sales increased, as compared to last year, due in part to growth among their largest manufacturing customers.  Residential, commercial and industrial sales across all three electric companies continue to be negatively impacted by the utilization of company sponsored conservation programs.

Our firm natural gas sales are subject to many of the same influences as our retail electric sales, but have benefitted from migration of interruptible customers switching to firm service rates and the addition of gas-fired distributed generation in Yankee Gas' service territory.  Actual firm natural gas sales in 2012 were 13.2 percent lower than last year due to the unseasonably warm weather in the first three months of 2012.  On a weather normalized basis, actual firm natural gas sales in 2012 were 5 percent higher than last year due in part to lower natural gas prices and customer growth across all three classes.

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 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 2012, our total pre-tax uncollectibles expense that impacts earnings was $2.5 million as compared to $3.6 million in the first quarter of 2011.  The improvement in 2012 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 $3.7 million, or $0.02 per share, in the first quarter of 2012, compared with net expenses of $8.7 million, or $0.05 per share, in the first quarter of 2011.  Excluding merger-related costs of $1.1 million, or less than $0.01 per share, and $8.3 million, or $0.05 per share, in the first quarter of 2012 and 2011, respectively, NU parent and other companies recorded net expenses of $2.6 million, or $0.02 per share, and $0.4 million, or less than $0.01 per share, in such periods.

Future Outlook

We are not providing merged company guidance for 2012 at this time.  However, following are a number of non-recurring charges that will be recorded in the second quarter of 2012 related to the Connecticut and Massachusetts settlement agreements:

·

$40 million of pre-tax charges at CL&P, related to the Connecticut settlement agreement, for a commitment not to recover certain costs of restoring power following the October 2011 snowstorm and Tropical Storm Irene in August 2011;

·

$25 million of pre-tax charges at CL&P for rate credits related to the Connecticut settlement agreement;

·

$15 million of pre-tax charges at NU for the establishment of a fund to advance Connecticut energy goals related to the Connecticut settlement agreement; and

·

$21 million of total pre-tax charges at NSTAR Electric, NSTAR Gas, and WMECO for rate credits related to the Massachusetts settlement agreement.   

48

In addition, approximately $56.2 million of non-recurring merger-related costs will be recorded in the second quarter of 2012.

Liquidity

Consolidated:  Cash and cash equivalents totaled $283.4 million as of March 31, 2012, compared with $6.6 million as of December 31, 2011.  

On March 22, 2012, NU parent issued $300 million of 18-month floating rate Series D Senior Notes with a maturity date of September 20, 2013 and a coupon rate based on the three-month LIBOR rate plus a credit spread of 75 basis points, which will reset every three months.  As of March 31, 2012, the initial three-month interest rate was 1.22 percent.  The proceeds, net of issuance expenses, were used to repay the NU parent $263 million Series A Senior Notes that matured on April 1, 2012, to repay short-term borrowings and for other general corporate purposes.  

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

On March 26, 2012, CL&P entered into a five-year $300 million unsecured revolving credit facility, which expires on March 26, 2017.  The credit facility is intended to finance short-term borrowings CL&P has incurred to fund costs of restoring power following Tropical Storm Irene and the October 2011 snowstorm.  Under this new facility, CL&P can borrow either on a short-term or a long-term basis subject to any necessary regulatory approval and may borrow at prime rates or LIBOR-based rates, plus an applicable margin based on the higher of S&P’s or Moody’s credit ratings.  As of March 31, 2012, CL&P had $275 million in short-term borrowings outstanding under this credit facility.  The weighted-average interest rate on these borrowings as of March 31, 2012 was 1.5 percent.  

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

Cash flows used in operating activities in the first quarter of 2012 totaled $9.1 million, compared with cash flows provided by operating activities of $355.9 million in the first quarter of 2011 (all amounts are net of RRB payments, which are included in financing activities on the accompanying unaudited condensed consolidated statements of cash flows).  The reduced cash flows were due primarily to approximately $153 millionof first quarter 2012 cash disbursements for storm costs primarily related to Tropical Storm Irene and the October 2011 snowstorm, a $92 million first quarter 2012 Pension Plan cash contribution, approximately $27 million in bill credits provided to CL&P residential customers in February 2012, and negative cash flow impacts associated with undercollections on the FMCC and transmission regulatory tracking mechanisms at CL&P of $12.9 million and $22.1 million, respectively, in the first quarter of 2012, as compared to the same period of 2011.  

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+	Stable	BBB+	Stable
CL&P	A3	Stable	A-	Stable	A	Stable
PSNH	A3	Stable	A-	Stable	A	Stable
WMECO	Baa2	Stable	A-	Stable	A-	Stable

All three rating agencies completed reviews of their ratings on NU and the various operating companies prior to the merger effective date.  S&P upgraded NU parent, CL&P, PSNH and WMECO corporate credit ratings by one notch.  As a result, all corporate credit ratings are now "A-" with "stable" outlooks.  As a result of the change, NU parent senior unsecured debt was upgraded one notch to BBB+ and CL&P and WMECO senior unsecured notes were raised by one notch to A-.  

Fitch raised the issuer ratings on NU parent, CL&P, PSNH and WMECO by one notch.  Moody’s lowered its ratings on CL&P by one notch while other ratings were confirmed.  

We paid common dividends of $52.1 million in the first quarter of 2012, compared with $48.6 million in the first quarter of 2011.  This reflects an increase of approximately 6.8 percent in our common dividend beginning in the first quarter of 2012.  On February 14, 2012, our Board of Trustees declared a quarterly common dividend of $0.29375 per share, payable on March 30, 2012 to shareholders of record as of March 1, 2012, which equates to $1.175 per share on an annualized basis.  On May 2, 2012, our Board of Trustees declared a quarterly common dividend of $0.343 per share, payable on June 29, 2012 to shareholders of record as of June 1, 2012, which equates to $1.372 per share on an annualized basis.  The 16.8 percent increase in the common dividend, compared with the March 30, 2012 dividend, is consistent with the Merger Agreement, which required NU’s first quarterly common dividend paid after the merger to be at least equal to NSTAR’s most recent common dividend, after adjusting for the exchange ratio.  NSTAR paid a common dividend of $0.45 per share on March 30, 2012.

In the first quarter of 2012, CL&P, PSNH, WMECO, and Yankee Gas paid $33.5 million, $42.9 million, $9.4 million, and $18.3 million, respectively, in common dividends to NU parent.

49

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 2012 and 2011 is as follows:

	For the Three Months Ended March 31,
(Millions of Dollars)	2012		2011
CL&P	$	108.8	$	106.8
PSNH		67.1		57.7
WMECO		85.0		33.0
Yankee Gas		20.4		21.8
NPT		5.7		2.9
Other		17.3		14.5
Total	$	304.3	$	236.7

The increase in our cash capital expenditures was the result of higher transmission segment cash capital expenditures of $74.1 million, primarily at WMECO.

As of March 31, 2012, NU parent had $19.9 million of LOCs issued for the benefit of certain subsidiaries (including $4 million for CL&P and $5.4 million for PSNH) and $260 million of short-term borrowings outstanding under its $500 million unsecured revolving credit facility.  The weighted-average interest rate on these short-term borrowings as of March 31, 2012 was 2.15 percent, based on a variable rate plus an applicable margin based on NU parent's credit ratings.  NU parent had $220.1 million of borrowing availability on this facility as of March 31, 2012.

CL&P, PSNH, WMECO, and Yankee Gas are parties to a joint unsecured revolving credit facility in a nominal aggregate amount of $400 million.  As of March 31, 2012, PSNH, WMECO, and Yankee Gas had short-term borrowings outstanding under this facility of $45 million, $65 million, and $15 million, respectively, leaving $275 million of aggregate borrowing capacity available.  The weighted-average interest rate on these short-term borrowings as of March 31, 2012 was 2.03 percent, which is based on a variable rate plus an applicable margin based on the companies’ respective credit ratings.

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 $306.5 million in the first quarter of 2012, compared with $221.1 million in the first quarter of 2011.  These amounts included $11.6 million and $12.3 million in the first quarter of 2012 and 2011, respectively, related to our corporate service companies, NUSCO and RRR.

Transmission Segment:  Transmission segment capital expenditures increased by $69.1 million in the first quarter of 2012, as compared with the same period in 2011, due primarily to increases at CL&P and WMECO related to the construction of GSRP.  A summary of transmission segment capital expenditures by company in the first quarters of 2012 and 2011 is as follows:  

	For the Three Months Ended March 31,
(Millions of Dollars)	2012		2011
CL&P	$	40.2	$	23.5
PSNH		15.1		10.3
WMECO		74.6		30.6
NPT		6.9		3.3
Totals	$	136.8	$	67.7

NEEWS: GSRP, a project that involves the construction of 115 KV and 345 KV overhead lines from Ludlow, Massachusetts to Bloomfield, Connecticut, is the first, largest and most complicated project within the NEEWS family of projects.  The $718 million project is expected to be placed in service in late 2013.  As of March 31, 2012, the project was approximately 63 percent complete.  

The Interstate Reliability Project, which includes CL&P’s construction of an approximately 40-mile, 345 KV overhead line from Lebanon, Connecticut to the Connecticut-Rhode Island border in Thompson, Connecticut where it will connect to transmission enhancements being constructed by National Grid, is our second major NEEWS project.  The $218 million project is expected to be placed in service late 2015.  

The Central Connecticut Reliability Project, which involves construction of a new $301 million 345 KV overhead line from Bloomfield, Connecticut to Watertown, Connecticut, is the third major part of NEEWS.  

Included as part of NEEWS are associated reliability related projects, currently estimated to cost $86 million, 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.  

50

Through March 31, 2012, CL&P and WMECO had capitalized $155.8 million and $399.4 million, respectively, in costs associated with NEEWS, of which $23.2 million and $64.7 million, respectively, were capitalized in the first quarter of 2012.  The total expected cost of NU’s share of NEEWS is approximately $1.3 billion, of which $646 million and $616 million relate to CL&P and WMECO, respectively.  

Northern Pass:  On October 4, 2010, NPT and Hydro Renewable Energy, a subsidiary of HQ, entered into a TSA in connection with the Northern Pass transmission project, which will be constructed by NPT.  Northern Pass is a planned HVDC transmission line from the Québec-New Hampshire border to Franklin, New Hampshire and an associated alternating current radial transmission line between Franklin and Deerfield, New Hampshire.  Northern Pass will interconnect at the Québec-New Hampshire border with a planned HQ HVDC transmission line.  On April 10, 2012, upon consummation of the NU and NSTAR merger, an NSTAR subsidiary, which owned 25 percent of NPT, was merged into NUTV, resulting in NUTV owning 100 percent of NPT.  

We estimate the costs of the Northern Pass transmission project will be approximately $1.1 billion (including capitalized AFUDC).  Through March 31, 2012, we capitalized $43.9 million in costs associated with NPT.

On March 5, 2012, New Hampshire enacted a bill that prohibits the use of eminent domain for the development of any "non-reliability" electric transmission projects, such as Northern Pass.  Notwithstanding the passage of this law, we believe that NPT will be able to acquire the necessary rights along an acceptable route.  NPT continues to secure properties needed to construct the northernmost 40 miles of the project where PSNH does not currently own a right-of-way.  We expect construction to begin in 2014 and the project to be completed in late 2016.  Given the ultimate design needs of the project, along with siting and permit requirements, which will vary depending upon the route ultimately selected, there is a possibility for further delay in commencement of construction.

Distribution Segment:  A summary of distribution segment capital expenditures by company for the first quarters of 2012 and 2011 is as follows:

	For the Three Months Ended March 31,
(Millions of Dollars)		2012		2011
CL&P:
Basic Business	$	38.2	$	34.4
Aging Infrastructure		34.1		23.8
Load Growth		24.8		15.1
Total CL&P		97.1		73.3
PSNH:
Basic Business		7.4		6.9
Aging Infrastructure		7.0		4.7
Load Growth		4.2		5.6
Total PSNH		18.6		17.2
WMECO:
Basic Business		5.2		4.0
Aging Infrastructure		2.1		2.4
Load Growth		2.2		1.4
Total WMECO		9.5		7.8
Total - Electric Distribution (excluding Generation)		125.2		98.3
Yankee Gas		16.3		16.0
Other		0.3		0.4
Total Distribution		141.8		114.7
PSNH Generation:
Clean Air Project		13.4		24.4
Other		2.8		1.7
Total PSNH Generation		16.2		26.1
WMECO Generation		0.1		0.3
Total Distribution Segment	$	158.1	$	141.1

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.  

Transmission Rate Matters and FERC Regulatory Issues

Transmission - Wholesale Rates:  The transmission rates billed to our retail customers recover our total transmission revenue requirements, ensuring that we recover all regional and local revenue requirements for providing transmission service.  These rates provide for annual reconciliations to actual costs.  The difference between billed and actual costs is deferred for future recovery from, or refund to, customers.  As of March 31, 2012, we were in a total net overrecovery position of $22.2 million, of which the transmission segments of CL&P, PSNH and WMECO were $11.8 million, $(0.3) million and $10.7 million, respectively.  Overrecoveries of $33.2 million will be refunded to customers in June 2012, of which the transmission segments of CL&P, PSNH and WMECO were $20.2 million, $1.7 million, and $11.3 million, respectively.

51

FERC Base ROE Complaint:  On September 30, 2011, several New England state attorneys general, state regulatory commissions, consumer advocates and other parties filed a joint complaint with the FERC under Sections 206 and 306 of the Federal Power Act alleging that the base ROE used in calculating formula rates for transmission service under the ISO-NE Open Access Transmission Tariff by New England transmission owners, including CL&P, NSTAR Electric, PSNH and WMECO, is unjust and unreasonable.  The complainants asserted that the current 11.14 percent rate, which became effective in 2006, is excessive due to changes in the capital markets and are seeking an order to reduce the rate to 9.2 percent, effective September 30, 2011.  In response, the New England transmission owners filed testimony and analysis based on standard FERC methodology and precedent justifying a base ROE of approximately 11.2 percent, thus demonstrating that the base ROE of 11.14 percent remained just and reasonable.

On May 3, 2012, the FERC issued an order establishing hearing and settlement procedures for the complaint.  In the order, FERC encouraged the parties to reach a settlement of the dispute before hearings commence.  One of the commissioners dissented, stating that the complaint should have been rejected based on the record and FERC precedent.  The FERC indicated that if a settlement was not reached, it would expect to render a final decision in the third quarter of 2013 with changes, if any, effective October 1, 2011.  

As of March 31, 2012, CL&P, NSTAR Electric PSNH, and WMECO had approximately $2 billion of aggregate shareholder equity invested in their transmission facilities.  As a result, each 10 basis point change in the authorized base ROE would change annual consolidated earnings by an approximate $2 million.  We cannot at this time predict what ROE will ultimately be established or its impact on CL&P’s, NSTAR Electric’s, PSNH’s, or WMECO’s respective financial position, results of operations or cash flows.  

Legislative Matters

2012 New Hampshire Legislation:  On March 5, 2012, New Hampshire enacted a bill that prohibits the use of eminent domain for the development of any "non-reliability" electric transmission projects, such as Northern Pass.  For further information regarding the impacts to NPT, see "Business Development and Capital Expenditures – Transmission Segment – Northern Pass" in thisManagement's Discussion and Analysis.

Regulatory Developments and Rate Matters

CL&P, PSNH, WMECO and Yankee Gas' rates are set by the respective state regulatory commissions and include provisions allowing for rate change mechanisms that are adjusted periodically.  Other than as described below, for the first quarter ended March 31, 2012, changes made to the CL&P, PSNH and WMECO rates did not have a material impact on their earnings, financial position, or cash flows.  For further information, see "Regulatory Developments and Rate Matters" included in our 2011 Form 10-K.

Regulatory Approvals for Merger with NSTAR:

Massachusetts:  On February 15, 2012, NU and NSTAR reached comprehensive settlement agreements with the Massachusetts Attorney General and the DOER.  The settlement agreement reached with the Attorney General covered a variety of rate-making and rate design issues, including (1) a total of $21 million of rate credits to be provided to retail customers of NSTAR Electric ($15 million), NSTAR Gas ($3 million) and WMECO ($3 million) in May 2012, (2) a base distribution rate freeze at least through 2015 for WMECO, NSTAR Electric and NSTAR Gas, except for exogenous events and existing tracking mechanisms, (3) NSTAR Electric will be able to recover $38 million of 2011 major storm costs, subject to DPU prudency review, during the five-year period beginning January 1, 2014, (4) NSTAR Electric will continue funding its Safety and Reliability program, and (5) NSTAR Electric will continue to recover lost base revenues associated with energy conservation.  The settlement agreement reached with the DOER covered the same rate-making and rate design issues as the Attorney General’s settlement agreement as well as a variety of matters impacting the advancement of Massachusetts clean energy goals established by the Green Communities Act and Global Warming Solutions Act, including the agreement of NSTAR Electric to sign a 15-year renewable power contract with Cape Wind Associates, LLC to purchase 129 MW of electricity generated from wind power and to issue a request for proposals for 10 MW of qualified solar energy generation contracts.  On April 4, 2012, the DPU approved the merger with the conditions outlined in the settlement agreements.

Connecticut:  On March 13, 2012, NU and NSTAR reached a comprehensive settlement agreement with both the Connecticut Attorney General and the Connecticut Office of Consumer Counsel, which covered numerous items, including (1) CL&P to provide a $25 million rate credit to retail customers in May 2012, (2) a base distribution rate freeze at CL&P until December 1, 2014, except for exogenous events and existing rate reconciling mechanisms, (3) CL&P agreeing to forego recovery of $40 million of storm costs related to Tropical Storm Irene and the October 2011 snowstorm, (4) CL&P agreeing to file with PURA for recovery of the total deferred storm costs, such that the total approved costs, which will reflect the $40 million reserve, will be collected over a six year period beginning December 1, 2014; and (5) the establishment of a $15 million fund to advance state energy goals.  CL&P also agreed to propose a $300 million distribution system resiliency program, $100 million of which is expected to be invested in the two-year period 2013 and 2014.  Revenue requirements associated with the resiliency program would be recovered with a full return through a tracking charge on customer bills, only $25 million of which could be recovered during the rate freeze.  On April 2, 2012, the PURA approved the merger with the conditions outlined in the settlement agreement.

Connecticut – CL&P:

Distribution Rates: PURA is currently conducting an investigation into CL&P’s performance related to both Tropical Storm Irene and the October 2011 snowstorm.  Hearings began in late April and a final decision is due at the end of June 2012.

52

New Hampshire:

Distribution Rates:  On April 27, 2012, PSNH filed a request with the NHPUC to increase distribution rates approximately $10.6 million effective July 1, 2012.  The increase consists of a $7 million increase associated with an increase in net plant additions, a $3.5 million increase associated with the current level of storm cost recoveries in rates, and a $0.1 million increase associated with consulting fees incurred in the review of PSNH's uncollectible expense.  All three of these requests are consistent with the 2010 rate case settlement.  Hearings are scheduled for June 21, 2012 with an order expected by June 29, 2012.

ES and SCRC Filings:  On July 26, 2011, the NHPUC ordered PSNH to file a rate proposal that would mitigate the impact of customer migration expected to occur when the ES rate is higher than market prices.  On January 26, 2012, the NHPUC rejected the PSNH proposal and ordered PSNH to file a new proposal no later than June 30, 2012, addressing certain issues raised by the NHPUC.  On April 27, 2012, PSNH filed its proposed Alternative Default Energy Rate that addresses customer migration, with an effective date of July 1, 2012.  A hearing is scheduled for June 20, 2012.

On May 2, 2012, PSNH filed for new ES and SCRC rates effective July 1, 2012.  The filing will be updated in late June with revised market prices and a hearing is scheduled for June 19, 2012.

On November 22, 2011, the NHPUC opened a docket to review the Clean Air Project including the establishment of temporary rates for near-term recovery of Clean Air Project costs, a prudence review of PSNH's overall construction program, and establishment of permanent rates for recovery of prudently incurred Clean Air Project costs.  On April 10, 2012, the NHPUC issued an order authorizing temporary rates, effective April 16, 2012, which allow recovery of a significant portion of the Clean Air Project costs, including a return on equity.  The order also called for the development of a formal schedule for a comprehensive prudence review of the Clean Air Project and the establishment of a permanent rate.  The temporary rates will remain in effect until a permanent rate allowing full recovery of all prudently incurred costs is approved.  At that time, the NHPUC will reconcile recoveries collected under the temporary rates with final approved rates.  PSNH believes that its actions related to Clean Air Project construction will be deemed prudent.  The project is expected to be completed for $422 million, approximately $35 million below budget, and is currently reducing mercury emissions well beyond state requirements.

ES and SCRC Reconciliation:  On an annual basis, PSNH files with the NHPUC an ES/SCRC cost reconciliation filing for the preceding year.  On May 1, 2012, PSNH filed its 2011 ES/SCRC reconciliation with the NHPUC, whose evaluation includes a prudence review of PSNH's generation and power purchase activities. 

Critical Accounting Policies

The preparation of financial statements in conformity with GAAP requires management to make estimates, assumptions and at times difficult, subjective or complex judgments.  Changes in these estimates, assumptions and judgments, in and of themselves, could materially impact our financial position, results of operations or cash flows.  Our management communicates to and discusses with 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 2011 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 10A, "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:  Except for the Massachusetts and Connecticut settlement agreements, as described in "Regulatory Developments and Rate Matters – Regulatory Approvals for Merger with NSTAR"in this Management’s Discussion and Analysis,there have been no additional material contractual obligations identified and no material changes with regard to the contractual obligations and commercial commitments previously disclosed in our 2011 Form 10-K.

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

53

RESULTS OF OPERATIONS – NORTHEAST UTILITIES AND SUBSIDIARIES

The following table provides the amounts and variances in operating revenues and expense line items for the unaudited condensed consolidated statements of income for NU included in this Quarterly Report on Form 10-Q for the three months ended March 31, 2012 and 2011:

			Operating Revenues and Expenses
			For the Three Months Ended March 31,
(Millions of Dollars)			2012		2011		Increase/		Percent
							(Decrease)
Operating Revenues			$	1,099.6	$	1,235.3	$	(135.7)	(11.0)	%
Operating Expenses:
	Fuel, Purchased and Net Interchange Power			398.0		474.1		(76.1)	(16.1)
	Other Operating Expenses			226.0		252.0		(26.0)	(10.3)
	Maintenance			69.8		67.8		2.0	2.9
	Depreciation			80.8		73.9		6.9	9.3
	Amortization of Regulatory Assets, Net			6.2		34.4		(28.2)	(82.0)
	Amortization of Rate Reduction Bonds			18.4		17.3		1.1	6.4
	Taxes Other Than Income Taxes			86.0		88.4		(2.4)	(2.7)
		Total Operating Expenses		885.2		1,007.9		(122.7)	(12.2)
Operating Income			$	214.4	$	227.4	$	(13.0)	(5.7)	%

Operating Revenues
		For the Three Months Ended March 31,
						Increase/
		2012		2011		(Decrease)		Percent
Electric Distribution		$	786.0	$	891.6	$	(105.6)	(11.8)	%
Natural Gas Distribution			139.0		180.2		(41.2)	(22.9)
	Total Distribution		925.0		1,071.8		(146.8)	(13.7)
Transmission			162.8		158.2		4.6	2.9
	Total Regulated Companies		1,087.8		1,230.0		(142.2)	(11.6)
Other and Eliminations			11.8		5.3		6.5	(a)
Total Operating Revenues		$	1,099.6	$	1,235.3	$	(135.7)	(11.0)	%
(a) Percent greater than 100 percent not shown as it is not meaningful.

A summary of our retail electric sales and firm natural gas sales were as follows:
		For the Three Months Ended March 31,
		2012	2011	Decrease	Percent
Retail Electric Sales in GWh		8,271	8,705	(434)	(5.0)	%
Firm Natural Gas Sales in Million Cubic Feet		16,819	19,384	(2,565)	(13.2)	%
Firm Natural Gas Sales (Net of Special Contracts)
	in Million Cubic Feet	14,744	16,940	(2,196)	(13.0)	%

Our Operating Revenues decreased in the first quarter of 2012, as compared to the first quarter of 2011, 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 ($67.6 million), lower retail transmission revenues ($24.6 million), lower wholesale revenues ($16 million) and lower CTA revenues ($11.6 million), partially offset by higher CL&P FMCC delivery-related revenues ($24.9 million) and higher retail SBC revenues ($5.8 million).  The tracking mechanisms allow for rates to be changed periodically with overcollections refunded to customers or undercollections recovered from customers in future periods.

·

A decrease in natural gas revenues was due primarily to a 13.2 percent decrease in sales volume related to the warmer than normal weather in the first quarter of 2012, as compared to the first quarter of 2011.  In addition, there was a decrease in the cost of fuel, which is fully recovered in revenues from sales to our customers.

·

The portion of electric distribution revenues that impacts earnings decreased $12.4 million due primarily to a 5 percent decrease in retail electric sales related to the warmer than normal weather in the first quarter of 2012, as compared to the first quarter of 2011.

·

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

54

Fuel, Purchased and Net Interchange Power decreased in the first quarter of 2012, as compared to the first quarter of 2011, due primarily to the following:

(Millions of Dollars)		Increase/(Decrease)
Lower GSC supply costs and deferred fuel costs at CL&P,
	partially offset by higher CfD costs	$	(31.6)
Lower energy prices and lower ES customer sales at PSNH			(13.9)
Lower natural gas costs and lower sales at Yankee Gas			(32.2)
Other			1.6
		$	(76.1)

Other Operating Expensesdecreased in the first quarter of 2012, as compared to the first quarter of 2011, due primarily to:  

·

Lower costs that are recovered through distribution tracking mechanisms and have no earnings impact ($21.4 million), primarily related to lower retail transmission expenses.

·

Lower NU parent and other companies expenses ($2 million) that were due primarily to lower costs related NU’s merger with NSTAR ($10.1 million), partially offset by higher costs at NU’s unregulated contracting business related to an increased level of work in 2012 ($6.1 million).

Maintenanceincreased in the first quarter of 2012, as compared to the first quarter of 2011, due primarily to an increase in distribution vegetation management costs ($9.5 million), an increase in routine distribution overhead line expenses ($6.5 million) and an increase in routine transmission line costs ($2.3 million).  Partially offsetting these increases was a deferral of storm costs in the first quarter of 2012 related to the 2011 major storms ($10.1 million) and a decrease in the amortization of the allowed regulatory deferral as a result of the June 30, 2010 rate case decision ($8.9 million).  

Depreciationincreased in the first quarter of 2012, as compared to the first quarter of 2011, due primarily to higher utility plant balances resulting from completed construction projects placed into service, such as the PSNH Clean Air Project.  

Amortization of Regulatory Assets, Net decreased in the first quarter of 2012, as compared to the first quarter of 2011, due primarily to decreases in the ES ($7.1 million), the TCAM ($6.8 million) and the SCRC ($5.7 million) amortizations at PSNH and higher CTA transition costs ($5.4 million) and lower retail CTA revenue ($11.6 million) at CL&P.  Partially offsetting these decreases were lower SBC costs ($2.4 million) and higher retail SBC revenues ($5.8 million) at CL&P in the first quarter of 2012, as compared to the first quarter of 2011.

Interest Expense
	For the Three Months Ended March 31,
					Increase/
(Millions of Dollars)	2012		2011		(Decrease)		Percent
Interest on Long-Term Debt	$	60.0	$	57.4	$	2.6	4.5	%
Interest on RRBs		1.4		2.5		(1.1)	(44.0)
Other Interest		5.0		(1.4)		6.4	(a)
	$	66.4	$	58.5	$	7.9	13.5	%
(a) Percent greater than 100 percent not shown since it is not meaningful.

Interest Expense increased in the first quarter of 2012, as compared to the first quarter of 2011, due primarily to the absence in 2012 of a tax-related benefit, higher Interest on Long-Term Debt and higher interest related to an increased level of short-term borrowings under the revolving credit facilities in 2012, as compared to the same period in 2011.

Income Tax Expense
	For the Three Months Ended March 31,
(Millions of Dollars)	2012		2011		Decrease		Percent
Income Tax Expense	$	56.0	$	63.5	$	(7.5)	(11.8)	%

Income Tax Expense decreased in the first quarter of 2012, as compared to the first quarter of 2011, due primarily to lower pre-tax earnings ($9.5 million), partially offset by lower items that directly impact our tax return as a result of regulatory actions (“flow-through” items) and other impacts ($2 million).

55

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

The following table provides the amounts and variances in operating revenues and expense line items for the 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, 2012 and 2011:

			Operating Revenues and Expenses
			For the Three Months Ended March 31,
(Millions of Dollars)			2012		2011		Increase/		Percent
							(Decrease)
Operating Revenues			$	592.0	$	673.7	$	(81.7)	(12.1)	%
Operating Expenses:
	Fuel, Purchased and Net Interchange Power			223.8		255.4		(31.6)	(12.4)
	Other Operating Expenses			108.8		134.2		(25.4)	(18.9)
	Maintenance			42.8		40.8		2.0	4.9
	Depreciation			41.1		39.5		1.6	4.1
	Amortization of Regulatory Assets, Net			8.3		19.3		(11.0)	(57.0)
	Taxes Other Than Income Taxes			55.3		58.5		(3.2)	(5.5)
		Total Operating Expenses		480.1		547.7		(67.6)	(12.3)
Operating Income			$	111.9	$	126.0	$	(14.1)	(11.2)	%

Operating Revenues
CL&P's retail sales were as follows:
	For the Three Months Ended March 31,
	2012	2011	Decrease	Percent
Retail Sales in GWh	5,427	5,776	(349)	(6.0)	%

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

·

A $60.6 million decrease in distribution revenues related to the portions that are included in PURA approved tracking mechanisms that recover certain incurred costs and do not impact earnings.  The tracked distribution revenues decreased due primarily to lower GSC and FMCC supply-related revenues ($53.6 million), lower retail transmission revenues ($15.6 million), lower CTA revenues ($11.6 million) and lower wholesale revenues ($10 million).  The lower GSC and FMCC supply-related revenues were due primarily to lower customer rates resulting from lower average supply prices for SS customers and additional customer migration to third party electric suppliers.  These lower revenues were partially offset by higher FMCC delivery-related revenues ($24.9 million) and higher retail SBC revenues ($5.8 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 portion of distribution revenues that impacts earnings decreased by $10.6 million due primarily to a 6 percent decrease in retail sales related to the warmer than normal weather in the first quarter of 2012, as compared to the first quarter of 2011.

Fuel, Purchased and Net Interchange Powerdecreased in the first quarter of 2012, as compared to the first quarter of 2011, due primarily to the following:

(Millions of Dollars)	Increase/(Decrease)
GSC Supply Costs	$	(42.1)
CfD Costs		26.8
Deferred Fuel Costs		(13.6)
Other		(2.7)
	$	(31.6)

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

Other Operating Expensesdecreased in the first quarter of 2012, as compared to the first quarter of 2011, as a result of lower costs that are recovered through distribution tracking mechanisms and have no earnings impact ($20.8 million), primarily related to lower retail transmission expenses ($18.7 million) and lower transmission segment expenses ($2.3 million).

Maintenanceincreased in the first quarter of 2012, as compared to the first quarter of 2011, due primarily to an increase in distribution vegetation management costs ($9.1 million), an increase in routine distribution overhead line expenses ($8 million) and an increase in routine transmission line costs ($1.2 million).  Partially offsetting these increases was a deferral of storm costs in the first quarter of 2012 related to the 2011 major storms ($9.3 million) and a decrease in the amortization of the allowed regulatory deferral as a result of the June 30, 2010 rate case decision ($8.9 million).  

56

Amortization of Regulatory Assets, Net decreased in the first quarter of 2012, as compared to the first quarter of 2011, due primarily to higher CTA transition costs ($5.4 million) and lower retail CTA revenue ($11.6 million).  Partially offsetting these decreases were lower SBC costs ($2.4 million) and higher retail SBC revenues ($5.8 million) in the first quarter of 2012, as compared to the first quarter of 2011.

Interest Expense
	For the Three Months Ended March 31,
					Increase/
(Millions of Dollars)	2012		2011		(Decrease)		Percent
Interest on Long-Term Debt	$	31.5	$	33.3	$	(1.8)	(5.4)	%
Other Interest		2.0		(3.5)		5.5	(a)
	$	33.5	$	29.8	$	3.7	12.4	%
(a) Percent greater than 100 percent not shown since it is not meaningful.

Interest Expense increased in the first quarter of 2012, as compared to the first quarter of 2011, due primarily to the absence in 2012 of a tax-related benefit and an increase in interest expense related to a higher level of borrowings under the revolving credit facility in 2012, partially offset by a reduction in Interest on Long-Term Debt related to the October 2011 refinancing of the $245.5 million PCRBs.

Income Tax Expense
	For the Three Months Ended March 31,
(Millions of Dollars)	2012		2011		Decrease		Percent
Income Tax Expense	$	29.7	$	36.5	$	(6.8)	(18.6)	%

Income Tax Expense decreased in the first quarter of 2012, as compared to the first quarter of 2011, due primarily to lower pre-tax earnings ($6 million) and lower state income taxes ($1.2 million).

LIQUIDITY

CL&P had cash flows used in operating activities of $47.1 million in the first quarter of 2012, compared with cash flows provided by operating activities of $205 million in the first quarter of 2011.  The reduced cash flows were due primarily to $132 million of first quarter 2012 cash disbursements for storm costs associated with Tropical Storm Irene and the October 2011 snowstorm, approximately $27 million in bill credits provided to CL&P residential customers in February 2012, and negative cash flow impacts associated with under collections on the FMCC and transmission regulatory tracking mechanisms of $12.9 million and $22.1 million, respectively, in the first quarter of 2012, as compared to the same period in 2011.  In addition, CL&P recovered $2.2 million of its deferred operation and maintenance costs in the first quarter of 2012, compared to $11.7 million in the first quarter of 2011, and had income tax refunds in the first quarter of 2012 of $9.2 million, compared to income tax refunds of $40 million in the first quarter of 2011.

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 $108.8 million in the first quarter of 2012, compared with $106.8 million in the first quarter of 2011.  

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

On March 26, 2012, CL&P entered into a five-year $300 million unsecured revolving credit facility, which expires on March 26, 2017.  The credit facility is intended to finance short-term borrowings CL&P has incurred to fund costs of restoring power following Tropical Storm Irene and the October 2011 snowstorm.  Under this new facility, CL&P can borrow either on a short-term or a long-term basis subject to any necessary regulatory approval and may borrow at prime rates or LIBOR-based rates, plus an applicable margin based on the higher of S&P’s or Moody’s credit ratings.  As of March 31, 2012, CL&P had $275 million in short-term borrowings outstanding under this credit facility.  The weighted-average interest rate on these borrowings as of March 31, 2012 was 1.5 percent.  

CL&P is a party to a joint unsecured revolving credit facility in a nominal aggregate amount of $400 million.  As of March 31, 2012, CL&P had no borrowings outstanding under this credit facility.

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

Financing activities in the first quarter of 2012 included $33.5 million in common stock dividends paid to NU parent, an increase in short-term borrowings of $244 million and $49.3 million in repayments to the NU Money Pool.

57

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, 2012 and 2011:

			Operating Revenues and Expenses
			For the Three Months Ended March 31,
(Millions of Dollars)			2012		2011		Increase/		Percent
							(Decrease)
Operating Revenues			$	243.0	$	269.5	$	(26.5)	(9.8)	%
Operating Expenses:
	Fuel, Purchased and Net Interchange Power			73.2		87.1		(13.9)	(16.0)
	Other Operating Expenses			57.0		56.5		0.5	0.9
	Maintenance			19.4		18.7		0.7	3.7
	Depreciation			21.2		17.9		3.3	18.4
	Amortization of Regulatory (Liabilities)/Assets, Net			(2.6)		15.6		(18.2)	(a)
	Amortization of Rate Reduction Bonds			13.9		13.1		0.8	6.1
	Taxes Other Than Income Taxes			15.5		13.7		1.8	13.1
		Total Operating Expenses		197.6		222.6		(25.0)	(11.2)
Operating Income			$	45.4	$	46.9	$	(1.5)	(3.2)	%
(a) Percent greater than 100 percent not shown as it is not meaningful.

Operating Revenues
PSNH's retail sales were as follows:
	For the Three Months Ended March 31,
	2012	2011	Decrease	Percent
Retail Sales in GWh	1,937	1,984	(47)	(2.4)	%

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

·

A $24.7 million decrease in distribution revenues related to the portions that are included in NHPUC approved tracking mechanisms that recover certain incurred costs and do not impact earnings.  This decrease primarily related to lower purchased fuel and power costs ($15.4 million), mostly related to lower energy prices and lower ES customer retail sales.  In addition, there were lower retail transmission revenues ($6.4 million) and lower wholesale revenues ($5.3 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.

·

The portion of distribution revenues that impacts earnings decreased $2.3 million due primarily to a 2.4 percent decrease in retail sales related to the warmer than normal weather in the first quarter of 2012, as compared to the first quarter of 2011.

Fuel, Purchased and Net Interchange Powerdecreased in the first quarter of 2012, as compared to the first quarter of 2011, due primarily to lower energy prices, lower ES customer retail sales and an increase in the level of ES customer migration to third party electric suppliers.  

Depreciationincreased in the first quarter of 2012, as compared to the first quarter of 2011, due primarily to higher utility plant balances resulting from completed construction projects placed into service, such as the Clean Air Project.

Amortization of Regulatory (Liabilities)/Assets, Netdecreased in the first quarter of 2012, as compared to the first quarter of 2011, due primarily to decreases in the ES ($7.1 million), the TCAM ($6.8 million) and the SCRC ($5.7 million) amortizations.  

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

Interest Expense
	For the Three Months Ended March 31,
					Increase/
(Millions of Dollars)	2012		2011		(Decrease)		Percent
Interest on Long-Term Debt	$	11.6	$	8.6	$	3.0	34.9	%
Interest on RRBs		1.0		1.9		(0.9)	(47.4)
Other Interest		0.2		-		0.2	(a)
	$	12.8	$	10.5	$	2.3	21.9	%
(a) Percent greater than 100 percent not shown as it is not meaningful.

58

Interest Expense increased in the first quarter of 2012, as compared to the first quarter of 2011, due primarily to an increase in Interest on Long-Term Debt, which was the result of a reduction in AFUDC related to borrowed funds as the Clean Air Project was placed into service in September 2011.

Other Income, Net
	For the Three Months Ended March 31,
(Millions of Dollars)	2012		2011		Decrease		Percent
Other Income, Net	$	2.0	$	4.5	$	(2.5)	(55.6)	%

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

Income Tax Expense
	For the Three Months Ended March 31,
(Millions of Dollars)	2012		2011		Decrease		Percent
Income Tax Expense	$	13.4	$	13.5	$	(0.1)	(0.7)	%

Income Tax Expense decreased in the first quarter of 2012, as compared to the first quarter of 2011, due primarily to lower pre-tax earnings ($1.9 million), offset by lower flow-through items and other impacts ($1.8 million).

LIQUIDITY

PSNH had cash flows provided by operating activities of $2.5 million in the first quarter of 2012, compared with operating cash flows of $126.9 million in the first quarter of 2011 (amounts are net of RRB payments, which are included in financing activities).  The reduced cash flows were due primarily to a contribution into the NU Pension Plan of $87.7 million made in the first quarter of 2012.  Also, in the first quarter of 2012, PSNH made approximately $6.2 million of cash disbursements for storm costs associated with Tropical Storm Irene and the October 2011 snowstorm and had income tax refunds in the first quarter of 2012 of $5.2 million, compared to the income tax refunds of $9.1 million in the first quarter of 2011.  In addition, PSNH reduced coal pile inventories in the first quarter of 2012 creating a positive cash flow impact of $9.4 million, as compared to reduced coal and fuel inventories in the first quarter of 2011 creating a positive cash flow impact of $16 million.

59

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, 2012 and 2011:

			Operating Revenues and Expenses
			For the Three Months Ended March 31,
(Millions of Dollars)			2012		2011		Increase/		Percent
							(Decrease)
Operating Revenues			$	114.0	$	106.7	$	7.3	6.8	%
Operating Expenses:
	Fuel, Purchased and Net Interchange Power			39.5		40.2		(0.7)	(1.7)
	Other Operating Expenses			24.0		26.2		(2.2)	(8.4)
	Maintenance			4.7		4.8		(0.1)	(2.1)
	Depreciation			7.7		6.3		1.4	22.2
	Amortization of Regulatory Assets/(Liabilities), Net			0.1		(0.6)		0.7	(a)
	Amortization of Rate Reduction Bonds			4.4		4.2		0.2	4.8
	Taxes Other Than Income Taxes			4.9		4.5		0.4	8.9
		Total Operating Expenses		85.3		85.6		(0.3)	(0.4)
Operating Income			$	28.7	$	21.1	$	7.6	36.0	%
(a) Percent greater than 100 percent not shown as it is not meaningful.

Operating Revenues
WMECO's retail sales were as follows:
	For the Three Months Ended March 31,
	2012	2011	Decrease	Percent
Retail Sales in GWh	911	948	(37)	(4.0)	%

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

·

A $9.3 million improvement in transmission segment revenues resulting from a higher level of investment in this segment and the recovery of higher overall expenses, which are tracked and result in a related increase in revenues.  The increase in expenses is directly related to the increase in transmission plant, including costs associated with higher property taxes, depreciation and operation and maintenance expenses.

·

Amounts related to distribution revenues that do not impact earnings and are included in DPU approved tracking mechanisms, which track the recovery of certain incurred costs, decreased by $1.1 million in the first quarter of 2012, compared to the first quarter of 2011.  Included in these amounts are pension, C&LM collections and other trackers.  The tracking mechanisms allow for rates to be changed periodically with overcollections refunded to customers or undercollections to be recovered from customers in future periods.

Other Operating Expensesdecreased in the first quarter of 2012, as compared to the first quarter of 2011, as a result of lower distribution costs that are recovered through DPU approved tracking mechanisms and have no earnings impact.  The decrease primarily related to lower retail transmission expenses ($3.9 million), partially offset by higher pension costs and bad debt expense.

Depreciationincreased in the first quarter of 2012, as compared to the first quarter of 2011, due primarily to a higher depreciation rate being used 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.

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

Income Tax Expense
	For the Three Months Ended March 31,
(Millions of Dollars)	2012		2011		Increase		Percent
Income Tax Expense	$	9.2	$	6.3	$	2.9	46.0	%

Income Tax Expense increased in the first quarter of 2012, as compared to the first quarter of 2011, due primarily to higher pre-tax earnings ($2.5 million).

60

LIQUIDITY

WMECO had cash flows provided by operating activities of $0.7 million in the first quarter of 2012, compared with operating cash flows of $27.4 million in the first quarter of 2011 (amounts are net of RRB payments, which are included in financing activities).  The reduced cash flows were due primarily to $14.4 million of first quarter 2012 cash disbursements for storm costs attributable to Tropical Storm Irene and the October 2011 snowstorm and income tax refunds in the first quarter of 2012 of $0.8 million, compared with income tax refunds of $8.1 million received in the first quarter of 2011.  

61

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 38 thousand remaining MWh of supply contract volumes, net of related sales volumes.  Select Energy also has a non-derivative energy contract that expires on May 31, 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.  For Select Energy’s wholesale energy portfolio derivatives, we utilize the sensitivity analysis methodology to disclose quantitative information for our commodity price risks.  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.  A hypothetical 30 percent increase or decrease in forward energy, ancillary or capacity prices would not have a material impact on earnings.

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 independent power producers, industrial companies, gas and electric utilities, oil and gas producers, financial institutions, and other energy marketers.  Margin accounts exist within this diverse group, and we realize interest receipts and payments related to balances outstanding in these margin accounts.  This wide customer and supplier mix generates a need for a variety of contractual structures, products and terms that, in turn, require us to manage the portfolio of market risk inherent in those transactions in a manner consistent with the parameters established by our risk management process.

If the respective unsecured debt ratings of NU parent were reduced to below investment grade by either Moody’s or S&P, certain of NU’s contracts would require additional collateral in the form of cash or LOCs to be provided to counterparties and independent system operators.  If such an event occurred as of March 31, 2012, NU would have been required to provide additional cash or LOCs in an aggregate amount of $23.5 million.  NU would have been and remains able to provide that collateral.

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 5, "Derivative Instruments," to the unaudited condensed consolidated financial statements.  

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 2011 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 2011 Form 10-K.

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, 2012 to determine whether they are effective in ensuring that the disclosure of required information is made timely and in accordance with the Securities Exchange Act of 1934 and the rules and regulations of the SEC.  This evaluation was made under management's supervision and with management's participation, including the principal executive officers and principal financial officer as of the end of the period covered by this 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, 2012 that have materially affected, or are reasonably likely to materially affect, internal controls over financial reporting.  

62

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 2011 Form 10-K, which disclosures are incorporated herein by reference.  There have been no additional legal proceedings identified and no material changes with regard to the legal proceedings previously disclosed in those filings.  

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 2011 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 those filings.

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, 2012.

63

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)

4.1

Fourth Supplemental Indenture between NU and The Bank of New York Mellon Trust Company, N.A., as Trustee, dated March 15, 2012, relating to $300,000,000 Floating Rate Senior Note, Series D, Due 2013, (Exhibit 4.1, NU Current Report on Form 8-K filed on March 28, 2012, File No. 001-5324)

10.1

Settlement Agreement entered into by and among NSTAR Electric Company, NSTAR Gas Company, NSTAR, Western Massachusetts Electric Company, Northeast Utilities, the Attorney General of the Commonwealth of Massachusetts and the Massachusetts Department of Energy Resources, dated February 15, 2012 (Exhibit 10.1, NU Current Report on Form 8-K filed on February 15, 2012, File No. 001-5324)

10.2

Settlement Agreement entered into by and among NSTAR Electric Company, NSTAR Gas Company, Western Massachusetts Electric Company, and the Massachusetts Department of Energy Resources, dated February 15, 2012 (Exhibit 10.2, NU Current Report on Form 8-K filed on February 15, 2012, File No. 001-5324)

10.3

Settlement Agreement, dated March 13, 2012, entered into by and among Northeast Utilities, NSTAR, the Attorney General of the State of Connecticut and the State of Connecticut, Office of Consumer Counsel  (Exhibit 10.1, NU Current Report on Form 8-K filed on March 13, 2012, File No. 001-5324)

*12

Ratio of Earnings to Fixed Charges

*31

Certification of Thomas J. May, 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 9, 2012

*31.1

Certification of James J. Judge, 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 9, 2012

*32

Certification of Thomas J. May, President and Chief Executive Officer of Northeast Utilities and James J. Judge, Executive Vice President and Chief Financial Officer of Northeast Utilities, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, dated May 9, 2012

*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

64

Listing of Exhibits (CL&P)

*4.1

Credit Agreement, dated March 26, 2012, between CL&P, the Banks named therein and Union Bank, N.A. as Administrative Agent

10.1

Settlement Agreement, dated March 13, 2012, entered into by and among Northeast Utilities, NSTAR, the Attorney General of the State of Connecticut and the State of Connecticut, Office of Consumer Counsel  (Exhibit 10.1, CL&P Current Report on Form 8-K filed on March 13, 2012, File No. 000-0404)

*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 9, 2012

*31.1

Certification of James J. Judge, 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 9, 2012

*32

Certification of Leon J. Olivier, Chief Executive Officer of The Connecticut Light and Power Company and James J. Judge, Executive Vice President and Chief Financial Officer of The Connecticut Light and Power Company, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, dated May 9, 2012

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 9, 2012

*31.1

Certification of James J. Judge, 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 9, 2012

*32

Certification of Leon J. Olivier, Chief Executive Officer of Public Service Company of New Hampshire and James J. Judge, Executive Vice President and Chief Financial Officer of Public Service Company of New Hampshire, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, dated May 9, 2012

Listing of Exhibits (WMECO)

10.1

Settlement Agreement entered into by and among NSTAR Electric Company, NSTAR Gas Company, NSTAR, Western Massachusetts Electric Company, Northeast Utilities, the Attorney General of the Commonwealth of Massachusetts and the Massachusetts Department of Energy Resources, dated February 15, 2012 (Exhibit 10.1, WMECO Current Report on Form 8-K filed on February 15, 2012, File No. 001-7624)

10.2

Settlement Agreement entered into by and among NSTAR Electric Company, NSTAR Gas Company, Western Massachusetts Electric Company, and the Massachusetts Department of Energy Resources, dated February 15, 2012 (Exhibit 10.2, WMECO Current Report on Form 8-K filed on February 15, 2012, File No. 001-7624)

*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 9, 2012

*31.1

Certification of James J. Judge, 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 9, 2012

65

*32

Certification of Leon J. Olivier, Chief Executive Officer of Western Massachusetts Electric Company and James J. Judge, 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 9, 2012

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 9, 2012	By	/s/ Jay S. Buth
		Jay S. Buth
		Vice President, Controller and
		Chief Accounting Officer
		(Principal Accounting 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 9, 2012	By	/s/ Jay S. Buth
		Jay S. Buth
		Vice President, Controller and
		Chief Accounting Officer
		(Principal Accounting 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 9, 2012	By	/s/ Jay S. Buth
		Jay S. Buth
		Vice President, Controller and
		Chief Accounting Officer
		(Principal Accounting 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 9, 2012	By	/s/ Jay S. Buth
		Jay S. Buth
		Vice President, Controller and
		Chief Accounting Officer
		(Principal Accounting Officer)

68