WESTERN MASSACHUSETTS ELECTRIC CO (Form: 10-Q, Received: 08/07/2012 17:18:14)

[F2Q12EDGAR002.GIF]

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

FORM 10-Q


[X]	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

	For the Quarterly Period Ended June 30, 2012
	OR
[ ]	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

	For the transition period from ____________ to ____________


Commission File Number	Registrant; State of Incorporation; Address; and Telephone Number	I.R.S. Employer Identification No.

1-5324	NORTHEAST UTILITIES (a Massachusetts voluntary association) One Federal Street Building 111-4 Springfield, Massachusetts 01105 Telephone: (413) 785-5871	04-2147929


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


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


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


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

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
NSTAR Electric Company			ü
Public Service Company of New Hampshire			ü
Western Massachusetts Electric Company			ü

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


	Yes	No

Northeast Utilities		ü
The Connecticut Light and Power Company		ü
NSTAR Electric Company		ü
Public Service Company of New Hampshire		ü
Western Massachusetts Electric Company		ü

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 July 31, 2012
Northeast Utilities Common shares, $5.00 par value	313,804,466 shares

The Connecticut Light and Power Company Common stock, $10.00 par value	6,035,205 shares

NSTAR Electric Company Common Stock, $1.00 par value	100 shares

Public Service Company of New Hampshire Common stock, $1.00 par value	301 shares

Western Massachusetts Electric Company Common stock, $25.00 par value	434,653 shares

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

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

GLOSSARY OF TERMS



The following is a glossary of abbreviations or acronyms that are found in this report.

CURRENT OR FORMER NU COMPANIES, SEGMENTS OR INVESTMENTS:

CL&P	The Connecticut Light and Power Company
CYAPC	Connecticut Yankee Atomic Power Company
HWP	HWP Company, formerly the Holyoke Water Power Company
MYAPC	Maine Yankee Atomic Power Company
NGS	Northeast Generation Services Company and subsidiaries
NPT	Northern Pass Transmission LLC
NSTAR	Parent Company of NSTAR Electric, NSTAR Gas and other subsidiaries (prior to the merger with NU)
NSTAR Electric	NSTAR Electric Company
NSTAR Electric & Gas	NSTAR Electric & Gas Corporation, a Northeast Utilities service company
NSTAR Gas	NSTAR Gas Company
NSTAR LLC	Post-merger parent company of NSTAR Electric, NSTAR Gas and other subsidiaries, and successor to NSTAR
NU Enterprises	NU Enterprises, Inc., the parent company of Select Energy, NGS, NGS Mechanical, Select Energy Contracting, Inc. and E.S. Boulos Company
NU or the Company	Northeast Utilities and subsidiaries
NU parent and other companies	NU parent and other companies is comprised of NU parent, NSTAR LLC, NSTAR Electric & Gas, NUSCO and other subsidiaries, including NU Enterprises, NSTAR Communications, Inc., HWP, RRR (a real estate subsidiary), the non-energy-related subsidiaries of Yankee (Yankee Energy Services Company and Yankee Energy Financial Services Company), and the consolidated operations of CYAPC and YAEC
NUSCO	Northeast Utilities Service Company
NUTV	NU Transmission Ventures, Inc., the parent company of NPT and Renewable Properties, Inc.
PSNH	Public Service Company of New Hampshire
Regulated companies	NU's Regulated companies, comprised of the electric distribution and transmission businesses of CL&P, NSTAR Electric, PSNH, and WMECO, the generation activities of PSNH and WMECO, NSTAR Gas, Yankee Gas, and NPT
RRR	The Rocky River Realty Company
Select Energy	Select Energy, Inc.
WMECO	Western Massachusetts Electric Company
YAEC	Yankee Atomic Electric Company
Yankee	Yankee Energy System, Inc.
Yankee Companies	CYAPC, YAEC and MYAPC
Yankee Gas	Yankee Gas Service Company
REGULATORS:
DEEP	Connecticut Department of Energy and Environmental Protection
DOE	U.S. Department of Energy
DOER	Massachusetts Department of Energy Resources
DPU	Massachusetts Department of Public Utilities
FERC	Federal Energy Regulatory Commission
ISO-NE	ISO New England, Inc., the New England Independent System Operator
MA DEP	Massachusetts Department of Environmental Protection
NHPUC	New Hampshire Public Utilities Commission
PURA	Connecticut Public Utilities Regulatory Authority
SEC	Securities and Exchange Commission
SJC	Supreme Judicial Court of Massachusetts
OTHER:
AFUDC	Allowance For Funds Used During Construction
AOCI	Accumulated Other Comprehensive Income/(Loss)
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
CPSL	Capital Projects Scheduling List
CTA	Competitive Transition Assessment


CWIP	Construction work in progress
EPS	Earnings Per Share
ERISA	Employee Retirement Income Security Act of 1974
ES	Default Energy Service
ESPP	Employee Stock Purchase Plan
Fitch	Fitch Ratings
FMCC	Federally Mandated Congestion Charge
FTR	Financial Transmission Rights
GAAP	Accounting principles generally accepted in the United States of America
GSC	Generation Service Charge
GSRP	Greater Springfield Reliability Project
GWh	Gigawatt-Hours
HG&E	Holyoke Gas and Electric, a municipal department of the town of Holyoke, MA
HQ	Hydro-Québec, a corporation wholly owned by the Québec government, including its divisions that produce, transmit and distribute electricity in Québec, Canada
HVDC	High voltage direct current
Hydro Renewable Energy	Hydro Renewable Energy, Inc., a wholly owned subsidiary of Hydro-Québec
ISO-NE Tariff	ISO-NE FERC Transmission, Markets and Services Tariff
kV	Kilovolt
kW	Kilowatt (equal to one thousand watts)
kWh	Kilowatt-Hours (the basic unit of electricity energy equal to one kilowatt of power supplied for one hour)
LOC	Letter of Credit
LRS	Supplier of last resort service
MGP	Manufactured Gas Plant
MMBtu	One million British thermal units
Moody's	Moody's Investors Services, Inc.
MW	Megawatt
MWh	Megawatt-Hours
NEEWS	New England East-West Solution
Northern Pass	The high voltage direct current transmission line project from Canada into New Hampshire
NU Money Pool	Northeast Utilities Money Pool
NU supplemental benefit trust	The NU Trust Under Supplemental Executive Retirement Plan
NU 2011 Form 10-K	The Northeast Utilities and Subsidiaries 2011 combined Annual Report on Form 10-K as filed with the SEC
NSTAR 2011 Form 10-K	NSTAR 2011 Annual Report on Form 10-K as filed with the SEC
NSTAR Electric 2011 Form 10-K	NSTAR Electric 2011 Annual Report on Form 10-K as filed with the SEC
PAM	Pension and PBOP Rate Adjustment Mechanism
PBOP	Postretirement Benefits Other Than Pension
PBOP Plan	Postretirement Benefits Other Than Pension Plan that provides certain retiree health care benefits, primarily medical and dental, and life insurance benefits
PCRBs	Pollution Control Revenue Bonds
Pension Plan	Single uniform noncontributory defined benefit retirement plan
PPA	Pension Protection Act
RECs	Renewable Energy Certificates
Regulatory ROE	The average cost of capital method for calculating the return on equity related to the distribution and generation business segment excluding the wholesale transmission segment
ROE	Return on Equity
RRB	Rate Reduction Bond or Rate Reduction Certificate
RSUs	Restricted share units
S&P	Standard & Poor's Financial Services LLC
SBC	Systems Benefits Charge
SCRC	Stranded Cost Recovery Charge
SERP	Supplemental Executive Retirement Plan
SIP	Simplified Incentive Plan
SS	Standard service
TCAM	Transmission Cost Adjustment Mechanism
TSA	Transmission Service Agreement
UI	The United Illuminating Company

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

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 – June 30, 2012 and December 31, 2011	1

Condensed Consolidated Statements of Income – Three and Six Months Ended June 30, 2012 and 2011	3

Condensed Consolidated Statements of Comprehensive Income – Three and Six Months Ended June 30, 2012 and 2011		3

Condensed Consolidated Statements of Cash Flows – Six Months Ended June 30, 2012 and 2011	4

The Connecticut Light and Power Company and Subsidiary (Unaudited)

Condensed Consolidated Balance Sheets – June 30, 2012 and December 31, 2011	5

Condensed Consolidated Statements of Income – Three and Six Months Ended June 30, 2012 and 2011	7

Condensed Consolidated Statements of Comprehensive Income – Three and Six Months Ended June 30, 2012 and 2011	7

Condensed Consolidated Statements of Cash Flows – Six Months Ended June 30, 2012 and 2011	8

NSTAR Electric Company and Subsidiaries (Unaudited)

Condensed Consolidated Balance Sheets – June 30, 2012 and December 31, 2011	9

Condensed Consolidated Statements of Income – Three and Six Months Ended June 30, 2012 and 2011	11

Condensed Consolidated Statements of Cash Flows – Six Months Ended June 30, 2012 and 2011	12

Public Service Company of New Hampshire and Subsidiaries (Unaudited)

Condensed Consolidated Balance Sheets – June 30, 2012 and December 31, 2011	13

Condensed Consolidated Statements of Income – Three and Six Months Ended June 30, 2012 and 2011	15

Condensed Consolidated Statements of Comprehensive Income – Three and Six Months Ended June 30, 2012 and 2011	15

Condensed Consolidated Statements of Cash Flows – Six Months Ended June 30, 2012 and 2011	16

Western Massachusetts Electric Company and Subsidiary (Unaudited)

Condensed Consolidated Balance Sheets – June 30, 2012 and December 31, 2011	17

Condensed Consolidated Statements of Income – Three and Six Months Ended June 30, 2012 and 2011	19

Condensed Consolidated Statements of Comprehensive Income – Three and Six Months Ended June 30, 2012 and 2011	19

Condensed Consolidated Statements of Cash Flows – Six Months Ended June 30, 2012 and 2011	20

Combined Notes to Condensed Consolidated Financial Statements	21

iii


	Page

ITEM 2 – Management’s Discussion and Analysis of Financial Condition and Results of Operations for the following companies:

Northeast Utilities and Subsidiaries	49

The Connecticut Light and Power Company and Subsidiary	67

NSTAR Electric Company and Subsidiaries	69

Public Service Company of New Hampshire and Subsidiaries	72

Western Massachusetts Electric Company and Subsidiary	74

ITEM 3 – Quantitative and Qualitative Disclosures About Market Risk	76

ITEM 4 – Controls and Procedures	77

PART II – OTHER INFORMATION

ITEM 1 – Legal Proceedings	78

ITEM 1A – Risk Factors	78

ITEM 2 – Unregistered Sales of Equity Securities and Use of Proceeds	78

ITEM 6 – Exhibits	79

SIGNATURES	81

This Page Intentionally Left Blank


NORTHEAST UTILITIES AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)

		June 30,		December 31,
(Thousands of Dollars)		2012		2011

ASSETS

Current Assets:
	Cash and Cash Equivalents	$	28,483	$	6,559
	Receivables, Net		661,910		488,002
	Unbilled Revenues		202,262		175,207
	Fuel, Materials and Supplies		262,562		248,958
	Regulatory Assets		624,397		255,144
	Marketable Securities		79,231		70,970
	Prepayments and Other Current Assets		95,160		112,632
Total Current Assets			1,954,005		1,357,472


Property, Plant and Equipment, Net			16,054,913		10,403,065

Deferred Debits and Other Assets:
	Regulatory Assets		5,201,154		3,267,710
	Goodwill		3,518,454		287,591
	Marketable Securities		372,302		60,311
	Derivative Assets		93,616		98,357
	Other Long-Term Assets		311,856		172,560
Total Deferred Debits and Other Assets			9,497,382		3,886,529



Total Assets		$	27,506,300	$	15,647,066



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


NORTHEAST UTILITIES AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)

		June 30,		December 31,
(Thousands of Dollars)		2012		2011

LIABILITIES AND CAPITALIZATION

Current Liabilities:
Notes Payable to Banks		$	1,248,500	$	317,000
Long-Term Debt - Current Portion			683,208		331,582
Accounts Payable			600,995		633,282
Regulatory Liabilities			203,767		167,844
Derivative Liabilities			113,188		107,558
Other Current Liabilities			640,809		390,416
Total Current Liabilities			3,490,467		1,947,682

Rate Reduction Bonds			160,133		112,260

Deferred Credits and Other Liabilities:
Accumulated Deferred Income Taxes			3,249,323		1,868,316
Regulatory Liabilities			551,690		266,145
Derivative Liabilities			946,621		959,876
Accrued Pension, SERP and PBOP			2,064,069		1,326,037
Other Long-Term Liabilities			884,317		420,011
Total Deferred Credits and Other Liabilities			7,696,020		4,840,385

Capitalization:
Long-Term Debt			6,936,473		4,614,913

Noncontrolling Interest - Preferred Stock of Subsidiaries			155,568		116,200

Equity:
	Common Shareholders' Equity:
	Common Shares		1,662,251		980,264
	Capital Surplus, Paid In		6,178,698		1,797,884
	Retained Earnings		1,635,709		1,651,875
	Accumulated Other Comprehensive Loss		(66,387)		(70,686)
	Treasury Stock		(342,632)		(346,667)
Common Shareholders' Equity			9,067,639		4,012,670
Noncontrolling Interests			-		2,956
Total Equity			9,067,639		4,015,626
Total Capitalization			16,159,680		8,746,739



Total Liabilities and Capitalization		$	27,506,300	$	15,647,066


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


NORTHEAST UTILITIES AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)

			Three Months Ended June 30,				Six Months Ended June 30,
(Thousands of Dollars, Except Share Information)			2012		2011		2012		2011

Operating Revenues			$	1,628,684	$	1,047,481	$	2,728,307	$	2,282,732

Operating Expenses:
	Purchased Power, Fuel and Transmission			542,014		382,542		937,358		879,246
	Operations and Maintenance			529,977		269,701		791,940		533,323
	Depreciation			144,485		73,637		225,324		147,588
	Amortization of Regulatory Assets, Net			25,590		16,992		31,016		50,491
	Amortization of Rate Reduction Bonds			40,752		17,086		59,100		34,367
	Energy Efficiency Programs			73,489		29,970		110,762		64,403
	Taxes Other Than Income Taxes			112,862		79,419		198,899		167,823
		Total Operating Expenses		1,469,169		869,347		2,354,399		1,877,241
Operating Income				159,515		178,134		373,908		405,491

Interest Expense:
	Interest on Long-Term Debt			86,925		57,044		146,892		114,444
	Interest on Rate Reduction Bonds			2,056		2,293		3,487		4,871
	Other Interest			66		2,897		5,116		1,468
		Interest Expense		89,047		62,234		155,495		120,783
Other Income, Net				1,806		7,334		10,580		17,647
Income Before Income Tax Expense				72,274		123,234		228,993		302,355
Income Tax Expense				26,055		44,515		82,019		108,052
Net Income				46,219		78,719		146,974		194,303
Net Income Attributable to Noncontrolling Interests				1,880		1,441		3,373		2,870
Net Income Attributable to Controlling Interest			$	44,339	$	77,278	$	143,601	$	191,433

Basic and Diluted Earnings Per Common Share			$	0.15	$	0.44	$	0.60	$	1.08

Dividends Declared Per Common Share			$	0.34	$	0.28	$	0.63	$	0.55

Weighted Average Common Shares Outstanding:
	Basic			301,047,753		177,347,374		239,551,735		177,267,791
	Diluted			301,816,884		177,626,992		240,127,169		177,553,995

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


NORTHEAST UTILITIES AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Unaudited)

			Three Months Ended June 30,				Six Months Ended June 30,
(Thousands of Dollars)			2012		2011		2012		2011

Net Income			$	46,219	$	78,719	$	146,974	$	194,303
Other Comprehensive Income/(Loss), Net of Tax:
	Qualified Cash Flow Hedging Instruments			516		(5,095)		939		(3,922)
	Changes in Unrealized Gains on Other Securities			160		149		194		144
	Change in Funded Status of Pension, SERP and PBOP
		Benefit Plans		1,759		422		3,166		1,357
Other Comprehensive Income/(Loss), Net of Tax				2,435		(4,524)		4,299		(2,421)
Comprehensive Income Attributable to Noncontrolling
	Interests			(1,880)		(1,441)		(3,373)		(2,870)
Comprehensive Income Attributable to Controlling Interest			$	46,774	$	72,754	$	147,900	$	189,012

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


NORTHEAST UTILITIES AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)


			Six Months Ended June 30,
(Thousands of Dollars)			2012		2011

Operating Activities:
	Net Income		$	146,974	$	194,303
	Adjustments to Reconcile Net Income to Net Cash Flows
		Provided by Operating Activities:
		Bad Debt Expense		13,384		9,374
		Depreciation		225,324		147,588
		Deferred Income Taxes		59,509		95,293
		Pension, SERP and PBOP Expense		97,378		69,654
		Pension and PBOP Contributions		(164,294)		(37,530)
		Regulatory (Under)/Over Recoveries, Net		(54,491)		41,612
		Amortization of Regulatory Assets, Net		31,016		50,491
		Amortization of Rate Reduction Bonds		59,100		34,367
		Derivative Assets and Liabilities		(5,090)		(9,272)
		Other		11,226		(7,192)
	Changes in Current Assets and Liabilities:
		Receivables and Unbilled Revenues, Net		83,395		80,696
		Fuel, Materials and Supplies		40,695		12,992
		Taxes Receivable/Accrued, Net		17,709		48,933
		Accounts Payable		(176,533)		(23,981)
		Other Current Assets and Liabilities, Net		(64,899)		(20,633)
Net Cash Flows Provided by Operating Activities				320,403		686,695

Investing Activities:
	Investments in Property, Plant and Equipment			(690,376)		(468,526)
	Proceeds from Sales of Marketable Securities			132,580		72,369
	Purchases of Marketable Securities			(143,225)		(73,564)
	Proceeds from Sale of Assets			-		46,841
	Other Investing Activities			11,274		(4,828)
Net Cash Flows Used in Investing Activities				(689,747)		(427,708)

Financing Activities:
	Cash Dividends on Common Shares			(159,708)		(97,207)
	Cash Dividends on Preferred Stock			(3,269)		(2,779)
	Increase/(Decrease) in Short-Term Debt			558,500		(130,000)
	Issuance of Long-Term Debt			300,000		122,000
	Retirements of Long-Term Debt			(267,699)		(124,086)
	Retirements of Rate Reduction Bonds			(36,439)		(34,320)
	Other Financing Activities			(117)		(883)
Net Cash Flows Provided by/(Used in) Financing Activities				391,268		(267,275)
Net Increase/(Decrease) in Cash and Cash Equivalents				21,924		(8,288)
Cash and Cash Equivalents - Beginning of Period				6,559		23,395
Cash and Cash Equivalents - End of Period			$	28,483	$	15,107


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


THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARY
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)

		June 30,		December 31,
(Thousands of Dollars)		2012		2011

ASSETS

Current Assets:
	Cash	$	4,523	$	1
	Receivables, Net		259,940		295,028
	Accounts Receivable from Affiliated Companies		973		1,548
	Unbilled Revenues		82,355		94,995
	Regulatory Assets		196,145		170,197
	Materials and Supplies		63,449		61,102
	Prepayments and Other Current Assets		21,535		53,920
Total Current Assets			628,920		676,791

Property, Plant and Equipment, Net			6,000,783		5,827,384

Deferred Debits and Other Assets:
	Regulatory Assets		2,025,569		2,103,830
	Derivative Assets		91,146		93,755
	Other Long-Term Assets		88,953		89,636
Total Deferred Debits and Other Assets			2,205,668		2,287,221



Total Assets		$	8,835,371	$	8,791,396



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


THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARY
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)

			June 30,		December 31,
(Thousands of Dollars)			2012		2011

LIABILITIES AND CAPITALIZATION

Current Liabilities:
	Notes Payable to Banks		$	330,000	$	31,000
	Notes Payable to Affiliated Companies			5,000		58,525
	Long-Term Debt - Current Portion			-		62,000
	Accounts Payable			193,582		340,321
	Accounts Payable to Affiliated Companies			44,666		53,439
	Obligations to Third Party Suppliers			62,459		67,967
	Accrued Taxes			91,297		59,046
	Regulatory Liabilities			88,373		108,291
	Derivative Liabilities			97,704		95,881
	Other Current Liabilities			87,763		102,065
Total Current Liabilities				1,000,844		978,535

Deferred Credits and Other Liabilities:
	Accumulated Deferred Income Taxes			1,241,020		1,215,989
	Regulatory Liabilities			130,573		139,307
	Derivative Liabilities			910,115		935,849
	Accrued Pension, SERP and PBOP			248,624		260,571
	Other Long-Term Liabilities			204,227		215,640
Total Deferred Credits and Other Liabilities				2,734,559		2,767,356

Capitalization:
	Long-Term Debt			2,584,036		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		1,614,307		1,613,503
		Retained Earnings		727,096		735,948
		Accumulated Other Comprehensive Loss		(2,023)		(2,251)
	Common Stockholder's Equity			2,399,732		2,407,552
Total Capitalization				5,099,968		5,045,505



Total Liabilities and Capitalization			$	8,835,371	$	8,791,396


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


THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARY
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)


			Three Months Ended June 30,				Six Months Ended June 30,
(Thousands of Dollars)			2012		2011		2012		2011

Operating Revenues			$	562,141	$	608,013	$	1,154,106	$	1,281,695

Operating Expenses:
	Purchased Power and Transmission			196,806		230,380		417,697		502,338
	Operations and Maintenance			205,471		136,669		338,373		272,411
	Depreciation			41,519		38,442		82,588		77,917
	Amortization of Regulatory Assets, Net			3,263		13,705		11,257		32,339
	Energy Efficiency Programs			20,995		21,291		42,968		44,715
	Taxes Other Than Income Taxes			53,706		52,727		108,978		111,193
		Total Operating Expenses		521,760		493,214		1,001,861		1,040,913
Operating Income				40,381		114,799		152,245		240,782

Interest Expense:
	Interest on Long-Term Debt			31,696		33,430		63,218		66,758
	Other Interest			2,075		868		4,060		(2,708)
		Interest Expense		33,771		34,298		67,278		64,050
Other Income, Net				447		2,058		5,747		6,663
Income Before Income Tax Expense				7,057		82,559		90,714		183,395
Income Tax Expense				124		29,924		29,796		66,423
Net Income			$	6,933	$	52,635	$	60,918	$	116,972

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


THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARY
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Unaudited)
		Three Months Ended June 30,				Six Months Ended June 30,
(Thousands of Dollars)		2012		2011		2012		2011

Net Income		$	6,933	$	52,635	$	60,918	$	116,972
Other Comprehensive Income, Net of Tax:
	Qualified Cash Flow Hedging Instruments		111		111		222		222
	Changes in Unrealized Gains on Other Securities		5		5		6		5
Other Comprehensive Income, Net of Tax			116		116		228		227
Comprehensive Income		$	7,049	$	52,751	$	61,146	$	117,199

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


THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARY
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)


			Six Months Ended June 30,
(Thousands of Dollars)			2012		2011

Operating Activities:
	Net Income		$	60,918	$	116,972
	Adjustments to Reconcile Net Income to Net Cash Flows
		Provided by Operating Activities:
		Bad Debt Expense		743		2,252
		Depreciation		82,588		77,917
		Deferred Income Taxes		30,874		60,425
		Pension, SERP and PBOP Expense, Net of PBOP Contributions		12,030		9,868
		Regulatory (Under)/Over Recoveries, Net		(19,596)		24,852
		Amortization of Regulatory Assets, Net		11,257		32,339
		Other		(12,821)		(17,752)
	Changes in Current Assets and Liabilities:
		Receivables and Unbilled Revenues, Net		38,253		34,192
		Materials and Supplies		(2,457)		(11,761)
		Taxes Receivable/Accrued, Net		39,985		31,797
		Accounts Payable		(170,151)		(12,078)
		Other Current Assets and Liabilities, Net		(24,122)		9,968
Net Cash Flows Provided by Operating Activities				47,501		358,991

Investing Activities:
	Investments in Property, Plant and Equipment			(220,712)		(201,966)
	Increase in NU Money Pool Lending			-		(24,125)
	Proceeds from Sale of Assets			-		46,841
	Other Investing Activities			3,460		(6,489)
Net Cash Flows Used in Investing Activities				(217,252)		(185,739)

Financing Activities:
	Cash Dividends on Common Stock			(66,991)		(168,744)
	Cash Dividends on Preferred Stock			(2,779)		(2,779)
	Increase in Short-Term Debt			299,000		-
	Decrease in NU Money Pool Borrowings			(53,525)		(6,225)
	Other Financing Activities			(1,432)		(188)
Net Cash Flows Provided by/(Used in) Financing Activities				174,273		(177,936)
Net Increase/(Decrease) in Cash				4,522		(4,684)
Cash - Beginning of Period				1		9,762
Cash - End of Period			$	4,523	$	5,078


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


NSTAR ELECTRIC COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)

		June 30,		December 31,
(Thousands of Dollars)		2012		2011

ASSETS

Current Assets:
	Cash and Cash Equivalents	$	9,044	$	9,373
	Receivables, Net		211,388		232,828
	Accounts Receivable from Affiliated Companies		48,254		389,652
	Unbilled Revenues		53,409		40,380
	Taxes Receivable		35,642		5,664
	Regulatory Assets		326,630		323,871
	Prepayments and Other Current Assets		21,588		31,470
Total Current Assets			705,955		1,033,238

Property, Plant and Equipment, Net			4,555,454		4,447,258

Deferred Debits and Other Assets:
	Regulatory Assets		1,594,571		1,680,595
	Other Long-Term Assets		75,516		78,273
Total Deferred Debits and Other Assets			1,670,087		1,758,868



Total Assets		$	6,931,496	$	7,239,364



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


NSTAR ELECTRIC COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)

			June 30,		December 31,
(Thousands of Dollars)			2012		2011

LIABILITIES AND CAPITALIZATION

Current Liabilities:
	Notes Payable to Banks		$	344,500	$	141,500
	Long-Term Debt - Current Portion			401,513		400,688
	Accounts Payable			114,308		150,581
	Accounts Payable to Affiliated Companies			146,858		514,377
	Accumulated Deferred Income Taxes - Current Portion			94,398		101,819
	Regulatory Liabilities			52,636		41,579
	Other Current Liabilities			103,606		103,634
Total Current Liabilities				1,257,819		1,454,178

Rate Reduction Bonds				84,312		127,860

Deferred Credits and Other Liabilities:
	Accumulated Deferred Income Taxes			1,300,332		1,310,180
	Regulatory Liabilities			253,766		239,858
	Accrued Pension			385,235		357,685
	Payable to Affiliated Companies			70,569		75,905
	Other Long-Term Liabilities			189,803		195,606
Total Deferred Credits and Other Liabilities				2,199,705		2,179,234

Capitalization:
	Long-Term Debt			1,201,871		1,203,344

Preferred Stock Not Subject to Mandatory Redemption				43,000		43,000

	Common Stockholder's Equity:
		Common Stock		-		-
		Capital Surplus, Paid In		992,625		992,625
		Retained Earnings		1,152,164		1,239,123
	Common Stockholder's Equity			2,144,789		2,231,748
Total Capitalization				3,389,660		3,478,092



Total Liabilities and Capitalization			$	6,931,496	$	7,239,364


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


NSTAR ELECTRIC COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)


			Three Months Ended June 30,				Six Months Ended June 30,
(Thousands of Dollars)			2012		2011		2012		2011

Operating Revenues			$	534,626	$	552,346	$	1,091,102	$	1,129,821

Operating Expenses:
	Purchased Power and Transmission			180,502		212,055		399,512		455,062
	Operations and Maintenance			109,038		87,823		257,218		185,053
	Depreciation			42,669		41,637		85,198		83,157
	Amortization of Regulatory Assets, Net			22,144		13,407		46,024		29,669
	Amortization of Rate Reduction Bonds			22,581		22,581		45,161		45,161
	Energy Efficiency Programs			35,487		32,865		82,391		72,956
	Taxes Other Than Income Taxes			28,308		26,423		59,169		55,489
		Total Operating Expenses		440,729		436,791		974,673		926,547
Operating Income				93,897		115,555		116,429		203,274

Interest Expense:
	Interest on Long-Term Debt			22,279		22,583		44,567		45,176
	Interest on Rate Reduction Bonds			927		1,839		2,253		4,053
	Other Interest			(5,597)		(8,082)		(11,433)		(15,329)
		Interest Expense		17,609		16,340		35,387		33,900
Other Income, Net				6		910		1,227		1,719
Income Before Income Tax Expense				76,294		100,125		82,269		171,093
Income Tax Expense				30,812		39,471		32,847		67,546
Net Income			$	45,482	$	60,654	$	49,422	$	103,547

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


NSTAR ELECTRIC COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)


			Six Months Ended June 30,
(Thousands of Dollars)			2012		2011

Operating Activities:
	Net Income		$	49,422	$	103,547
	Adjustments to Reconcile Net Income to Net Cash Flows
		Provided by Operating Activities:
		Bad Debt Expense		46,726		8,284
		Depreciation		85,198		83,157
		Deferred Income Taxes		(17,069)		3,413
		Pension, SERP and PBOP Expense, Net of Pension and PBOP Contributions		16,822		(31,298)
		Regulatory Overrecoveries, Net		16,371		70,319
		Amortization of Regulatory Assets, Net		46,024		29,669
		Amortization of Rate Reduction Bonds		45,161		45,161
		Other		(24,559)		8,807
	Changes in Current Assets and Liabilities:
		Receivables and Unbilled Revenues, Net		(19,555)		(33,830)
		Materials and Supplies		10,387		(4,673)
		Taxes Receivable/Accrued, Net		(29,978)		174,103
		Accounts Payable		(64,317)		(100,840)
		Other Current Assets and Liabilities, Net		(1,222)		4,125
Net Cash Flows Provided by Operating Activities				159,411		359,944

Investing Activities:
	Investments in Property, Plant and Equipment			(189,229)		(156,842)
	Other Investing Activities			7,242		20,641
Net Cash Flows Used in Investing Activities				(181,987)		(136,201)

Financing Activities:
	Cash Dividends on Common Stock			(135,400)		(113,300)
	Cash Dividends on Preferred Stock			(980)		(980)
	Increase/(Decrease) in Short-Term Debt			203,000		(64,500)
	Retirements of Long-Term Debt			(825)		(825)
	Retirements of Rate Reduction Bonds			(43,548)		(43,581)
Net Cash Flows Provided by/(Used in) Financing Activities				22,247		(223,186)
Net (Decrease)/Increase in Cash and Cash Equivalents				(329)		557
Cash and Cash Equivalents - Beginning of Period				9,373		8,964
Cash and Cash Equivalents - End of Period			$	9,044	$	9,521


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


PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)

		June 30,		December 31,
(Thousands of Dollars)		2012		2011

ASSETS

Current Assets:
	Cash	$	203	$	56
	Receivables, Net		83,335		87,545
	Accounts Receivable from Affiliated Companies		616		1,294
	Notes Receivable from Affiliated Companies		-		55,900
	Unbilled Revenues		43,630		45,403
	Fuel, Materials and Supplies		102,948		124,744
	Regulatory Assets		28,912		34,178
	Prepayments and Other Current Assets		37,235		35,261
Total Current Assets			296,879		384,381

Property, Plant and Equipment, Net			2,315,954		2,256,688

Deferred Debits and Other Assets:
	Regulatory Assets		347,498		393,941
	Other Long-Term Assets		76,466		81,531
Total Deferred Debits and Other Assets			423,964		475,472



Total Assets		$	3,036,797	$	3,116,541



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


PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)

			June 30,		December 31,
(Thousands of Dollars)			2012		2011

LIABILITIES AND CAPITALIZATION

Current Liabilities:
	Notes Payable to Banks		$	65,000	$	-
	Notes Payable to Affiliated Companies			13,500		-
	Accounts Payable			69,792		106,377
	Accounts Payable to Affiliated Companies			16,532		18,895
	Accrued Interest			9,517		9,670
	Regulatory Liabilities			23,121		24,500
	Other Current Liabilities			29,365		36,497
Total Current Liabilities				226,827		195,939

Rate Reduction Bonds				57,742		85,368

Deferred Credits and Other Liabilities:
	Accumulated Deferred Income Taxes			410,763		392,712
	Regulatory Liabilities			53,272		54,415
	Accrued Pension, SERP and PBOP			168,428		258,718
	Other Long-Term Liabilities			58,895		53,304
Total Deferred Credits and Other Liabilities				691,358		759,149

Capitalization:
	Long-Term Debt			997,827		997,722

	Common Stockholder's Equity:
		Common Stock		-		-
		Capital Surplus, Paid In		700,658		700,285
		Retained Earnings		372,621		388,910
		Accumulated Other Comprehensive Loss		(10,236)		(10,832)
	Common Stockholder's Equity			1,063,043		1,078,363
Total Capitalization				2,060,870		2,076,085



Total Liabilities and Capitalization			$	3,036,797	$	3,116,541


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


PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)

			Three Months Ended June 30,				Six Months Ended June 30,
(Thousands of Dollars)			2012		2011		2012		2011

Operating Revenues			$	255,105	$	240,191	$	498,102	$	509,661

Operating Expenses:
	Purchased Power, Fuel and Transmission			82,116		74,372		163,165		169,375
	Operations and Maintenance			68,435		76,281		133,413		140,469
	Depreciation			21,811		18,122		43,018		36,030
	Amortization of Regulatory Assets, Net			2,798		2,465		177		18,032
	Amortization of Rate Reduction Bonds			13,814		13,004		27,743		26,139
	Energy Efficiency Programs			3,213		2,774		6,794		5,840
	Taxes Other Than Income Taxes			15,872		15,234		31,360		28,902
		Total Operating Expenses		208,059		202,252		405,670		424,787
Operating Income				47,046		37,939		92,432		84,874

Interest Expense:
	Interest on Long-Term Debt			11,539		8,317		23,103		16,941
	Interest on Rate Reduction Bonds			786		1,676		1,802		3,570
	Other Interest			460		408		692		346
		Interest Expense		12,785		10,401		25,597		20,857
Other Income, Net				549		4,361		2,590		8,820
Income Before Income Tax Expense				34,810		31,899		69,425		72,837
Income Tax Expense				13,578		10,234		26,931		23,708
Net Income			$	21,232	$	21,665	$	42,494	$	49,129

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


PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Unaudited)

			Three Months Ended June 30,				Six Months Ended June 30,
(Thousands of Dollars)			2012		2011		2012		2011

Net Income			$	21,232	$	21,665	$	42,494	$	49,129
Other Comprehensive Income/(Loss), Net of Tax:
	Qualified Cash Flow Hedging Instruments			291		(3,998)		581		(3,072)
	Changes in Unrealized Gains on Other Securities			9		8		11		8
	Change in Funded Status of Pension, SERP and PBOP
		Benefit Plans		4		-		4		-
Other Comprehensive Income/(Loss), Net of Tax				304		(3,990)		596		(3,064)
Comprehensive Income			$	21,536	$	17,675	$	43,090	$	46,065

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


PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)


			Six Months Ended June 30,
(Thousands of Dollars)			2012		2011

Operating Activities:
	Net Income		$	42,494	$	49,129
	Adjustments to Reconcile Net Income to Net Cash Flows
		Provided by Operating Activities:
		Bad Debt Expense		3,378		3,303
		Depreciation		43,018		36,030
		Deferred Income Taxes		17,885		20,773
		Pension, SERP and PBOP Expense		13,168		14,406
		Pension and PBOP Contributions		(91,990)		(18,469)
		Regulatory Overrecoveries, Net		3,625		726
		Amortization of Regulatory Assets, Net		177		18,032
		Amortization of Rate Reduction Bonds		27,743		26,139
		Other		13,165		(2,545)
	Changes in Current Assets and Liabilities:
		Receivables and Unbilled Revenues, Net		3,283		12,844
		Fuel, Materials and Supplies		17,365		11,915
		Taxes Receivable/Accrued, Net		(3,776)		9,767
		Accounts Payable		(14,171)		(8,611)
		Other Current Assets and Liabilities, Net		(5,231)		(16,885)
Net Cash Flows Provided by Operating Activities				70,133		156,554

Investing Activities:
	Investments in Property, Plant and Equipment			(120,792)		(111,459)
	Decrease in NU Money Pool Lending			55,900		-
	Other Investing Activities			3,045		1,928
Net Cash Flows Used in Investing Activities				(61,847)		(109,531)

Financing Activities:
	Cash Dividends on Common Stock			(58,783)		(29,414)
	Increase/(Decrease) in Short-Term Debt			65,000		(8,000)
	Issuance of Long-Term Debt			-		122,000
	Retirements of Long-Term Debt			-		(119,800)
	Increase/(Decrease) in NU Money Pool Borrowings			13,500		(4,100)
	Capital Contributions from NU Parent			-		20,000
	Retirements of Rate Reduction Bonds			(27,626)		(26,052)
	Other Financing Activities			(230)		(1,803)
Net Cash Flows Used in Financing Activities				(8,139)		(47,169)
Net Increase/(Decrease) in Cash				147		(146)
Cash - Beginning of Period				56		2,559
Cash - End of Period			$	203	$	2,413


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


WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)

		June 30,		December 31,
(Thousands of Dollars)		2012		2011

ASSETS

Current Assets:
	Cash	$	1	$	1
	Receivables, Net		42,580		42,757
	Accounts Receivable from Affiliated Companies		82		633
	Notes Receivable from Affiliated Companies		-		11,000
	Unbilled Revenues		15,440		16,277
	Regulatory Assets		40,587		35,520
	Marketable Securities		18,461		26,335
	Prepayments and Other Current Assets		8,057		8,719
Total Current Assets			125,208		141,242

Property, Plant and Equipment, Net			1,216,370		1,077,833

Deferred Debits and Other Assets:
	Regulatory Assets		232,001		233,247
	Marketable Securities		39,032		30,794
	Other Long-Term Assets		20,902		19,777
Total Deferred Debits and Other Assets			291,935		283,818



Total Assets		$	1,633,513	$	1,502,893



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


WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)

			June 30,		December 31,
(Thousands of Dollars)			2012		2011

LIABILITIES AND CAPITALIZATION

Current Liabilities:
	Notes Payable to Banks		$	110,000	$	-
	Notes Payable to Affiliated Companies			5,400		-
	Accounts Payable			109,164		111,566
	Accounts Payable to Affiliated Companies			8,463		10,626
	Regulatory Liabilities			19,400		33,056
	Other Current Liabilities			27,033		20,755
Total Current Liabilities				279,460		176,003

Rate Reduction Bonds				18,079		26,892

Deferred Credits and Other Liabilities:
	Accumulated Deferred Income Taxes			265,871		244,511
	Regulatory Liabilities			13,643		16,597
	Accrued Pension, SERP and PBOP			26,556		29,546
	Other Long-Term Liabilities			51,748		47,498
Total Deferred Credits and Other Liabilities				357,818		338,152

Capitalization:
	Long-Term Debt			499,648		499,545

	Common Stockholder's Equity:
		Common Stock		10,866		10,866
		Capital Surplus, Paid In		340,259		340,115
		Retained Earnings		131,398		115,506
		Accumulated Other Comprehensive Loss		(4,015)		(4,186)
	Common Stockholder's Equity			478,508		462,301
Total Capitalization				978,156		961,846



Total Liabilities and Capitalization			$	1,633,513	$	1,502,893


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


WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)

			Three Months Ended June 30,				Six Months Ended June 30,
(Thousands of Dollars)			2012		2011		2012		2011

Operating Revenues			$	106,836	$	98,390	$	220,861	$	205,074

Operating Expenses:
	Purchased Power and Transmission			32,715		37,965		73,269		83,195
	Operations and Maintenance			27,847		20,556		50,449		41,306
	Depreciation			6,994		6,625		14,691		12,963
	Amortization of Regulatory (Liabilities)/ Assets, Net			(44)		1,526		(387)		728
	Amortization of Rate Reduction Bonds			4,358		4,082		8,776		8,228
	Energy Efficiency Programs			4,933		4,956		10,489		10,380
	Taxes Other Than Income Taxes			4,977		4,203		9,858		8,745
		Total Operating Expenses		81,780		79,913		167,145		165,545
Operating Income				25,056		18,477		53,716		39,529

Interest Expense:
	Interest on Long-Term Debt			5,905		4,722		11,671		9,476
	Interest on Rate Reduction Bonds			343		617		757		1,301
	Other Interest			621		121		836		257
		Interest Expense		6,869		5,460		13,264		11,034
Other Income, Net				188		242		1,280		981
Income Before Income Tax Expense				18,375		13,259		41,732		29,476
Income Tax Expense				7,237		5,088		16,408		11,339
Net Income			$	11,138	$	8,171	$	25,324	$	18,137

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


WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Unaudited)

		Three Months Ended June,				Six Months Ended June 30,
(Thousands of Dollars)		2012		2011		2012		2011

Net Income		$	11,138	$	8,171	$	25,324	$	18,137
Other Comprehensive Income/(Loss), Net of Tax:
	Qualified Cash Flow Hedging Instruments		84		(1,144)		169		(945)
	Changes in Unrealized Gains on Other Securities		2		2		2		2
Other Comprehensive Income/(Loss), Net of Tax:			86		(1,142)		171		(943)
Comprehensive Income		$	11,224	$	7,029	$	25,495	$	17,194

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


WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)


			Six Months Ended June 30,
(Thousands of Dollars)			2012		2011

Operating Activities:
	Net Income		$	25,324	$	18,137
	Adjustments to Reconcile Net Income to Net Cash Flows
		Provided by Operating Activities:
		Bad Debt Expense		790		1,860
		Depreciation		14,691		12,963
		Deferred Income Taxes		17,708		7,004
		Regulatory (Under)/Over Recoveries, Net		(17,645)		9,222
		Amortization of Regulatory (Liabilities)/Assets, Net		(387)		728
		Amortization of Rate Reduction Bonds		8,776		8,228
		Other		1,127		(2,034)
	Changes in Current Assets and Liabilities:
		Receivables and Unbilled Revenues, Net		694		405
		Materials and Supplies		(2,793)		(398)
		Taxes Receivable/Accrued, Net		533		9,523
		Accounts Payable		(433)		1,021
		Other Current Assets and Liabilities, Net		(4,541)		(281)
Net Cash Flows Provided by Operating Activities				43,844		66,378

Investing Activities:
	Investments in Property, Plant and Equipment			(152,687)		(76,898)
	Proceeds from Sales of Marketable Securities			45,516		57,746
	Purchases of Marketable Securities			(45,889)		(57,888)
	Decrease in NU Money Pool Lending			11,000		-
	Other Investing Activities			1,096		(792)
Net Cash Flows Used in Investing Activities				(140,964)		(77,832)

Financing Activities:
	Cash Dividends on Common Stock			(9,432)		(13,153)
	Increase in Short-Term Debt			110,000		20,000
	Increase in NU Money Pool Borrowings			5,400		7,700
	Retirements of Rate Reduction Bonds			(8,813)		(8,268)
	Capital Contributions from NU Parent			-		5,186
	Other Financing Activities			(35)		(11)
Net Cash Flows Provided by Financing Activities				97,120		11,454
Net Change in Cash				-		-
Cash - Beginning of Period				1		1
Cash - End of Period			$	1	$	1

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

NORTHEAST UTILITIES AND SUBSIDIARIES

THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARY

NSTAR ELECTRIC COMPANY AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES

WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY

COMBINED NOTES TO 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.

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

NU is a public utility holding company primarily engaged through its wholly owned regulated utility subsidiaries in the energy delivery business. NU's wholly owned regulated utility subsidiaries included CL&P, PSNH, WMECO and Yankee Gas prior to NU's merger with NSTAR. On April 10, 2012, NU acquired 100 percent of the outstanding common shares of NSTAR and NSTAR (through a successor, NSTAR LLC) became a direct wholly owned subsidiary of NU. NSTAR Electric and NSTAR Gas, NSTAR LLC's regulated utility subsidiaries, are now also wholly owned subsidiaries of NU. 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. NU's consolidated financial information includes NSTAR LLC and its subsidiaries' activity from April 10, 2012 through June 30, 2012. See Note 2, "Merger of NU and NSTAR," for further information regarding the merger.

NSTAR Electric continues to maintain reporting requirements as an SEC registrant. The information disclosed for NSTAR Electric represents the results of operations of the entity for the three and six months ended June 30, 2012 and 2011 and the financial position as of June 30, 2012 and December 31, 2011, presented on a comparable basis. NU did not apply “push-down accounting” to NSTAR Electric, whereby the adjustments of assets and liabilities to fair value and the resultant goodwill would be shown on the financial statements of the acquired subsidiary.

The combined notes to consolidated financial statements have been prepared pursuant to the rules and regulations of the SEC. Certain information and footnote disclosures included in annual consolidated financial statements prepared in accordance with GAAP have been omitted pursuant to such rules and regulations. The accompanying unaudited condensed consolidated financial statements should be read in conjunction with the entirety of this combined Quarterly Report on Form 10-Q, the first quarter 2012 combined Quarterly Report on Form 10-Q of NU, the first quarter 2012 Quarterly Report on Form 10-Q for NSTAR Electric, the 2011 combined Annual Report on Form 10-K of NU, CL&P, PSNH and WMECO (NU 2011 Form 10-K), the 2011 Annual Report on Form 10-K of NSTAR (NSTAR 2011 Form 10-K) and the 2011 Annual Report on Form 10-K of NSTAR Electric (NSTAR Electric 2011 Form 10-K), which were filed with the SEC.

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 June 30, 2012 and December 31, 2011, the results of operations and comprehensive income for the three and six months ended June 30, 2012 and 2011, and cash flows for the six months ended June 30, 2012 and 2011. The results of operations and comprehensive income for the three and six months ended June 30, 2012 and 2011 and the cash flows for the six months ended June 30, 2012 and 2011 are not necessarily indicative of the results expected for a full year. The demand for electricity is affected by weather conditions, economic conditions, and consumer conservation behavior. Electric energy sales and revenues are typically higher in the winter and summer months than in the spring and fall months. Natural gas sales and revenues are typically higher in the winter months than during other periods of the year.

The unaudited condensed consolidated financial statements of NU, CL&P, NSTAR Electric, 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.

On April 10, 2012, upon consummation of the merger with NSTAR, NSTAR Electric's ownership in CYAPC and YAEC combined with CL&P's, PSNH's and WMECO's respective ownership interests in CYAPC and YAEC totaled greater than 50 percent, requiring NU to consolidate CYAPC and YAEC. The investment in CYAPC and YAEC had previously been accounted for under the equity method by NU. The consolidation of CYAPC and YAEC resulted in NU recording nuclear decommissioning trust marketable securities of $304 million, regulatory assets of $234 million, long-term debt associated with the long-term fuel disposal liabilities of $179 million, net accumulated deferred income taxes of $60 million and asset retirement obligations related to decommissioning activity of $292 million as of June 30, 2012. At the NU consolidated level, intercompany transactions between CL&P, NSTAR Electric, PSNH and WMECO and CYAPC and YAEC have been eliminated in consolidation. For CL&P, NSTAR Electric, PSNH and WMECO, the investment in CYAPC and YAEC continue to be accounted for under the equity method.

On April 10, 2012, upon consummation of the merger with NSTAR, an NSTAR subsidiary that owned 25 percent of NPT was merged into NUTV, resulting in NUTV owning 100 percent of NPT. Accordingly, 100 percent ownership of NPT was reflected in Common

Shareholders' Equity as of June 30, 2012 on the accompanying unaudited condensed consolidated balance sheet. See Note 2, "Merger of NU and NSTAR," and Note 13, "Common Shareholders' Equity and Noncontrolling Interests," for further information.

Certain prior period amounts in NSTAR Electric's accompanying unaudited condensed consolidated balance sheet, statements of income and cash flows have been reclassified between line items for comparative purposes and in order to conform to NU's presentation. The reclassifications did not affect NSTAR Electric's net income.

Certain changes in classification and corresponding reclassifications of prior period data were made in the accompanying unaudited condensed consolidated statements of income for NU, CL&P, PSNH and WMECO and statements of cash flows for NU and PSNH to conform to current period presentation. The unaudited condensed consolidated statements of income reflect the reclassification of transmission expenses from Other Operating Expenses, as originally reported, to Purchased Power, Fuel and Transmission and the reclassification of energy efficiency expenses primarily from Other Operating Expenses, as originally reported, to Energy Efficiency Programs. In addition, Other Operating Expenses and Maintenance, as originally reported, were combined and are reported in aggregate as Operations and Maintenance. These reclassifications were made for comparative purposes to conform to the current period’s presentation. The reclassifications on the statements of income were as follows:


	Transmission Expense				Energy Efficiency Expense
	Three Months Ended		Six Months Ended		Three Months Ended		Six Months Ended
(Millions of Dollars)	June 30, 2011		June 30, 2011		June 30, 2011		June 30, 2011
NU	$	42.2	$	64.8	$	30.0	$	64.4
CL&P		23.2		39.8		21.3		44.7
PSNH		5.0		12.9		2.8		5.8
WMECO		5.3		10.4		5.0		10.4

Effective January 1, 2012, NSTAR Electric increased its estimates with respect to the allowance for doubtful accounts, incurred but not reported claims on medical benefits, general and workers' compensation liabilities and various compensation accruals. The total aggregate impact of these increases in estimates to NSTAR Electric's accompanying unaudited condensed consolidated statements was approximately $11.4 million, after-tax, for the first quarter of 2012.

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 10C, "Commitments and Contingencies – Deferred Contractual Obligations," and Note 17, "Subsequent Events," for further information.

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.”

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 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.

Restricted Cash

As of June 30, 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.

Provision for Uncollectible Accounts

NU, including CL&P, NSTAR Electric, 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 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 June 30, 2012		As of December 31, 2011 ⁽¹⁾
NU	$	93.1	$	34.9
CL&P		11.8		14.8
NSTAR Electric		44.7		27.1
PSNH		7.9		7.2
WMECO		3.7		4.6

⁽¹⁾

NSTAR Electric amounts are not included in NU consolidated as of December 31, 2011.

Fair Value Measurements

NU, including CL&P, NSTAR Electric, PSNH, and WMECO, applies fair value measurement guidance to derivative contracts recorded at fair value and to the marketable securities held in the NU supplemental benefit trust, WMECO's spent nuclear fuel trust and CYAPC's and YAEC's nuclear decommissioning trusts. Fair value measurement guidance is also applied to investment valuations used to calculate the funded status of NU's Pension and PBOP Plans, including NSTAR Electric's Pension Plan.

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."

Other Income, Net

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. For CL&P, NSTAR Electric, PSNH and WMECO, equity in earnings relate to investments in CYAPC, YAEC and MYAPC accounted for on the equity method. On an NU consolidated basis, equity in earnings relate to the investment in MYAPC and NU's investment in two regional transmission companies.

Other Taxes

Gross receipts taxes levied by the state of Connecticut are collected by CL&P and Yankee Gas from their respective customers. These gross receipts taxes are shown on a gross basis with collections in Operating Revenues and payments in Taxes Other Than Income Taxes on the accompanying unaudited condensed consolidated statements of income as follows:


	For the Three Months Ended				For the Six Months Ended
(Millions of Dollars)	June 30, 2012		June 30, 2011		June 30, 2012		June 30, 2011
NU	$	30.5	$	32.0	$	65.5	$	70.7
CL&P		27.7		28.8		57.1		60.2

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

Supplemental Cash Flow Information

Non-cash investing activities include plant additions included in Accounts Payable as follows:


(Millions of Dollars)	As of June 30, 2012		As of June 30, 2011
NU	$	166.3	$	109.4
CL&P		45.1		19.4
NSTAR Electric ⁽¹⁾		22.7		18.8
PSNH		25.7		29.6
WMECO		56.5		39.7

⁽¹⁾

NSTAR Electric amounts are not included in NU consolidated as of June 30, 2011.

Short-term borrowings of NU, including CL&P, NSTAR Electric, 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 six months ended June 30, 2012 for CL&P and NU.

Refer to Note 2, "Merger of NU and NSTAR," for details of the purchase price, which represents a significant non-cash transaction.

MERGER OF NU AND NSTAR

On April 10, 2012, NU acquired 100 percent of the outstanding common shares of NSTAR. Pursuant to the terms and conditions of the Agreement and Plan of Merger, as amended, the "Merger Agreement," NSTAR merged into NSTAR LLC, becoming a wholly-owned subsidiary of NU.

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

Purchase Price: Pursuant to the merger, all of the NSTAR common shares were exchanged at the fixed exchange ratio of 1.312 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 using the exchange ratio upon consummation of the merger. In accordance with accounting guidance for business combinations, the portion of the fair value of these awards attributable to pre-merger service is included in the purchase price as it represents consideration transferred in the merger. See Note 9B, "Employee Benefits – Share-Based Payments," for further information.

Purchase Price Allocation: The allocation of the total purchase price to the estimated fair values of the assets acquired and liabilities assumed has been determined based on the accounting guidance for fair value measurements, which defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The allocation of the total purchase price includes adjustments to record the fair value of NSTAR’s unregulated telecommunications business, regulatory assets not earning a return, lease agreements, long-term debt and the preferred stock of NSTAR Electric. The fair values of NSTAR's assets and liabilities were determined based on significant estimates and assumptions, including Level 3 inputs, that are judgmental in nature. These estimates and assumptions include the timing and amounts of projected future cash flows and discount rates reflecting risk inherent in future cash flows. All purchase price adjustments are preliminary and subject to change as additional information is obtained.

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 to NU's reporting units has not yet been completed. The preliminary allocation of the purchase price is as follows:


(Millions of Dollars)
Current Assets	$	754
Property Plant and Equipment, Net		5,155
Goodwill		3,231
Other Long-Term Assets, excluding Goodwill		2,115
Current Liabilities		(1,332)
Long-Term Liabilities		(2,723)
Long-Term Debt and Other Long-Term Obligations		(2,123)
Preferred Stock of Subsidiary		(39)
Total Purchase Price	$	5,038

Pro Forma Financial Information: The following unaudited pro forma financial information reflects the pro forma combined results of operations of NU and NSTAR and reflects the amortization of purchase price adjustments assuming the merger had taken place on January 1, 2011. The unaudited pro forma financial information has been presented for illustrative purposes only and is not necessarily indicative of the consolidated results of operations that would have been achieved or the future consolidated results of operations of NU. The pro forma financial information does not include potential cost savings or non-recurring costs. This information is preliminary in nature and subject to change.


(Pro forma amounts in millions, except per share amounts)	For the Three Months Ended June 30,				For the Six Months Ended June 30,
(Pro forma amounts in millions, except per share amounts)	2012		2011		2012		2011
Operating Revenues	$	1,629	$	1,691	$	3,459	$	3,754
Net Income Attributable to Controlling Interest		133		142		243		328
Basic EPS		0.42		0.45		0.77		1.05
Diluted EPS		0.42		0.45		0.77		1.04

NU and NSTAR incurred non-recurring transaction costs and costs related to the Connecticut and Massachusetts settlement agreements recorded in the second quarter of 2012 described below, with the following aggregate after-tax impacts not included in the pro forma earnings presented above:


		For the Three Months Ended June 30,				For the Six Months Ended June 30,
(Millions of Dollars)		2012		2011		2012		2011
Transaction and Other Costs		$	29	$	2	$	31	$	16
Settlement Agreement Impacts			60		-		60		-
Total After-Tax Non-Recurring Costs Excluded
	from Net Income	$	89	$	2	$	91	$	16

Regulatory Approvals: On February 15, 2012, NU and NSTAR reached comprehensive settlement agreements with the Massachusetts Attorney General and the DOER related to the merger. On April 4, 2012, the DPU approved the settlement agreements and the merger of NU and NSTAR. On March 13, 2012, NU and NSTAR reached a comprehensive settlement agreement with both the Connecticut Attorney General and the Connecticut Office of Consumer Counsel. On April 2, 2012, the PURA approved the settlement agreement and the merger of NU and NSTAR. The settlement agreements included base distribution rate freezes until December 1, 2014 for CL&P and through 2015 for NSTAR Electric, NSTAR Gas and WMECO.

See Note 10B, "Commitments and Contingencies – Long-Term Contractual Arrangements," for further information on commitments required under the settlement agreements.

The pre-tax financial impacts of the Connecticut and Massachusetts settlement agreements that were recognized by NU, CL&P, NSTAR Electric, and WMECO in the second quarter of 2012 are summarized as follows:


	For The Three and Six Months Ended June 30, 2012
(Millions of Dollars)	NU		CL&P		NSTAR Electric		WMECO
Customer Rate Credits	$	46	$	25	$	15	$	3
Storm Costs Deferral Reduction		40		40		-		-
Establishment of Energy Efficiency Fund		15		-		-		-
Total	$	101	$	65	$	15	$	3

NSTAR Revenues and Net Income: The impact of NSTAR LLC and its subsidiaries on the revenues and net income attributable to controlling interest of NU on the accompanying unaudited condensed consolidated statements of income for both the three and six months ended June 30, 2012 was an increase of $601.3 million and $35.9 million, respectively.

REGULATORY ACCOUNTING

On April 10, 2012, NSTAR LLC's regulated utility subsidiaries, NSTAR Electric and NSTAR Gas, became subsidiaries of NU. For NSTAR Electric, certain regulatory asset and liability balances as of December 31, 2011 have been reclassified to the current period presentation in order to align the reporting of regulatory activities subsequent to the closing of the merger. See Note F and Note C, "Regulatory Assets," and Note E and Note B, "Asset Retirement Obligations and Cost of Removal," of the NSTAR and NSTAR Electric 2011 Form 10-Ks, respectively, for further information on specific regulatory assets and liabilities.

NU's Regulated companies continue to be rate-regulated on a cost-of-service basis; therefore, the accounting policies of the Regulated companies apply GAAP applicable to rate-regulated enterprises and 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 June 30, 2012		As of December 31, 2011
(Millions of Dollars)	NU		NU
Deferred Benefit Costs	$	2,427.7	$	1,360.5
Regulatory Assets Offsetting Derivative Liabilities		941.2		939.6
Goodwill ⁽²⁾		547.7		-
Income Taxes, Net		502.9		425.4
Storm Cost Deferrals		363.4		356.0
Securitized Assets		364.4		101.8
Unrecovered Contractual Obligations		236.1		100.9
Power Contracts Buy Out Agreements		105.7		8.6
Regulatory Tracker Deferrals		119.2		45.9
Asset Retirement Obligations		82.4		47.5
Losses on Reacquired Debt		40.7		24.5
Deferred Environmental Remediation Costs		58.4		38.5
Other Regulatory Assets		35.8		73.6
Total Regulatory Assets	$	5,825.6	$	3,522.8
Less: Current Portion	$	624.4	$	255.1
Total Long-Term Regulatory Assets	$	5,201.2	$	3,267.7


		As of June 30, 2012								As of December 31, 2011
				NSTAR								NSTAR
(Millions of Dollars)		CL&P		Electric		PSNH		WMECO		CL&P		Electric ⁽¹⁾		PSNH		WMECO
Deferred Benefit Costs		$	533.6	$	819.5	$	184.1	$	111.2	$	572.8	$	813.7	$	200.0	$	118.9
Regulatory Assets Offsetting
	Derivative Liabilities		911.0		15.8		-		13.5		932.0		3.4		-		7.3
Goodwill ⁽²⁾			-		470.2		-		-		-		478.9		-		-
Income Taxes, Net			356.0		47.9		36.9		30.0		339.6		48.8		38.0		17.8
Storm Cost Deferrals			246.5		36.6		38.9		41.4		268.3		30.6		44.0		43.7
Securitized Assets			-		299.2		48.6		16.6		-		368.5		76.4		25.4
Unrecovered Contractual Obligations			72.4		26.8		-		17.4		80.9		30.8		-		20.0
Power Contracts Buy Out Agreements			-		97.9		7.8		-		-		109.5		8.6		-
Regulatory Tracker Deferrals			26.5		52.3		13.6		24.9		5.5		61.1		11.9		22.1
Asset Retirement Obligations			29.1		25.5		13.8		3.4		27.9		24.5		13.5		3.2
Losses on Reacquired Debt			13.7		16.9		8.5		0.3		13.9		18.2		9.0		0.3
Deferred Environmental Remediation
	Costs		-		-		9.9		-		-		-		9.7		-
Other Regulatory Assets			32.9		12.6		14.3		13.9		33.1		16.5		17.0		10.0
Total Regulatory Assets		$	2,221.7	$	1,921.2	$	376.4	$	272.6	$	2,274.0	$	2,004.5	$	428.1	$	268.7
Less: Current Portion		$	196.1	$	326.6	$	28.9	$	40.6	$	170.2	$	323.9	$	34.2	$	35.5
Total Long-Term Regulatory Assets		$	2,025.6	$	1,594.6	$	347.5	$	232.0	$	2,103.8	$	1,680.6	$	393.9	$	233.2

⁽¹⁾

NSTAR Electric amounts are not included in NU consolidated as of December 31, 2011.

⁽²⁾

Originated from the merger that created NSTAR in 1999, recoverable in rates over 40 years.

Storm Costs: On August 1, 2012, PURA issued a final decision in the investigation of CL&P’s performance related to both Tropical Storm Irene and the October 2011 snowstorm. The decision identified certain penalties that could be imposed on CL&P during its next rate case, including a reduction in allowed regulatory ROE and the disallowance of certain deferred storm restoration costs. However, PURA will consider and weigh the extent to which CL&P has taken steps in its restructuring of storm management and the establishment of new practices for execution in future storm response in determining any potential penalties. At this time, management cannot estimate the impact on CL&P’s financial position, results of operations or cash flows. CL&P continues to believe that its response to these events was prudent, is consistent with industry norms, and probable that it will be able to recover its deferred costs. As of June 30, 2012, CL&P had recorded total deferred storm costs relating to Tropical Storm Irene and the October 2011 snowstorm of

$283 million. The storm cost deferral regulatory asset balance also reflects a reserve of $40 million recorded in connection with the Connecticut settlement agreement. See Note 2, "Merger of NU and NSTAR," for further information.

Regulatory Costs Not Yet Approved: Additionally, the Regulated companies had $57.6 million ($5.2 million for CL&P, $23.2 million for NSTAR Electric, $23.5 million for PSNH and $2.3 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 June 30, 2012 and December 31, 2011, respectively, which were included in Other Long-Term Assets on the accompanying unaudited condensed consolidated balance sheets. For comparative purposes, NSTAR Electric had $9.5 million of such regulatory costs as of December 31, 2011. These amounts represent incurred costs that have not yet been approved for recovery by the applicable regulatory agency. Management believes it is probable that these costs will be recovered in future cost-of-service regulated rates.


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

	As of June 30, 2012		As of December 31, 2011
(Millions of Dollars)	NU		NU
Cost of Removal	$	454.4	$	172.2
Regulatory Tracker Deferrals		134.9		139.1
AFUDC Transmission Incentive		70.6		67.0
Overrecovered Spent Nuclear Fuel Costs and Contractual Obligations		15.4		15.4
Wholesale Transmission Overcollections		-		9.6
Other Regulatory Liabilities		80.2		30.6
Total Regulatory Liabilities	$	755.5	$	433.9
Less: Current Portion	$	203.8	$	167.8
Total Long-Term Regulatory Liabilities	$	551.7	$	266.1


		As of June 30, 2012								As of December 31, 2011
				NSTAR								NSTAR
(Millions of Dollars)		CL&P		Electric		PSNH		WMECO		CL&P		Electric ⁽¹⁾		PSNH		WMECO
Cost of Removal		$	52.0	$	240.5	$	51.9	$	4.1	$	63.8	$	235.8	$	53.2	$	7.2
Regulatory Tracker Deferrals			74.6		13.6		13.8		15.3		94.4		11.7		17.3		21.3
AFUDC Transmission Incentive			57.1		4.2		-		9.3		57.7		4.3		-		9.3
Overrecovered Spent Nuclear Fuel
	Costs and Contractual Obligations		15.4		-		-		-		15.4		-		-		-
Wholesale Transmission Overcollections			8.1		-		5.3		2.5		4.5		-		2.6		9.5
Other Regulatory Liabilities ⁽²⁾			11.8		48.1		5.4		1.8		11.8		29.7		5.8		2.4
Total Regulatory Liabilities		$	219.0	$	306.4	$	76.4	$	33.0	$	247.6	$	281.5	$	78.9	$	49.7
Less: Current Portion		$	88.4	$	52.6	$	23.1	$	19.4	$	108.3	$	41.6	$	24.5	$	33.1
Total Long-Term Regulatory Liabilities		$	130.6	$	253.8	$	53.3	$	13.6	$	139.3	$	239.9	$	54.4	$	16.6

⁽¹⁾

NSTAR Electric amounts are not included in NU consolidated as of December 31, 2011.

⁽²⁾

Other Regulatory Liabilities include amounts that are subject to various rate reconciling mechanisms that, as of each period end date, would result in refunds to customers.

PROPERTY, PLANT AND EQUIPMENT AND ACCUMULATED DEPRECIATION

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



		As of June 30, 2012		As of December 31, 2011
(Millions of Dollars)		NU		NU
Distribution – Electric		$	11,168.1	$	6,540.4
Distribution - Natural Gas			2,160.1		1,247.6
Transmission			5,061.1		3,541.9
Generation			1,147.3		1,096.0
Electric and Natural Gas Utility			19,536.6		12,425.9
Other ⁽¹⁾			420.2		305.1
Property, Plant and Equipment, Gross			19,956.8		12,731.0
Less: Accumulated Depreciation
	Electric and Natural Gas Utility		(4,910.2)		(3,035.5)
	Other		(160.8)		(120.2)
Total Accumulated Depreciation			(5,071.0)		(3,155.7)
Property, Plant and Equipment, Net			14,885.8		9,575.3
Construction Work in Progress			1,169.1		827.8
Total Property, Plant and Equipment, Net		$	16,054.9	$	10,403.1

⁽¹⁾

These assets are primarily comprised of building improvements at RRR and software and equipment at NUSCO as of June 30, 2012 and December 31, 2011, and telecommunications equipment at NSTAR Communications, Inc. as of June 30, 2012.


		As of June 30, 2012								As of December 31, 2011
				NSTAR								NSTAR
(Millions of Dollars)		CL&P		Electric		PSNH		WMECO		CL&P		Electric ⁽¹⁾		PSNH		WMECO
Distribution		$	4,590.2	$	4,418.7	$	1,481.6	$	713.8	$	4,419.6	$	4,334.4	$	1,451.6	$	704.3
Transmission			2,707.5		1,424.8		558.2		352.6		2,689.1		1,386.9		546.4		297.4
Generation			-		-		1,126.1		21.2		-		-		1,074.8		21.2
Property, Plant and
	Equipment, Gross		7,297.7		5,843.5		3,165.9		1,087.6		7,108.7		5,721.3		3,072.8		1,022.9
Less: Accumulated Depreciation			(1,640.8)		(1,498.8)		(916.7)		(247.3)		(1,596.7)		(1,436.0)		(893.6)		(240.5)
Property, Plant and Equipment, Net			5,656.9		4,344.7		2,249.2		840.3		5,512.0		4,285.3		2,179.2		782.4
Construction Work in Progress			343.9		210.8		66.8		376.1		315.4		162.0		77.5		295.4
Total Property, Plant and
	Equipment, Net	$	6,000.8	$	4,555.5	$	2,316.0	$	1,216.4	$	5,827.4	$	4,447.3	$	2,256.7	$	1,077.8

⁽¹⁾

NSTAR Electric amounts are not included in NU consolidated as of December 31, 2011.

DERIVATIVE INSTRUMENTS

The Regulated companies purchase and procure energy and energy-related products for their customers, which are subject to price volatility. The costs associated with supplying energy to customers are recoverable through customer rates. The Company manages the risks associated with the price volatility of energy and energy-related products through the use of derivative contracts, many of which meet the definition of and are designated as "normal purchases or normal sales," (normal), and the use of nonderivative contracts.

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 costs and benefits of derivative contracts that meet the definition of 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.

CL&P, NSTAR Electric and WMECO mitigate the risks associated with the price volatility of energy and energy-related products through the use of SS, LRS, and basic service contracts, which fix the price of electricity purchased for customers and are accounted for as normal. CL&P 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. NSTAR Electric and WMECO have contracts to purchase renewable energy that are derivatives. NSTAR Electric also has a capacity related contract. 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, NSTAR Electric and WMECO, electric distribution companies are required to enter into these contracts. NU also has NYMEX future contracts in order to reduce variability associated with the purchase price of approximately 6.2 million MMBtu of natural gas.

The costs or benefits from all of these derivative contracts are recoverable from or refundable to customers, and, therefore changes in fair value are recorded as Regulatory Assets or Regulatory Liabilities on the accompanying 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 Purchased Power, Fuel and Transmission on the accompanying unaudited condensed consolidated statements of income.

The gross fair values of derivative assets and liabilities with the same counterparty are offset and reported as net Derivative Assets or Derivative Liabilities, with current and long-term portions, in the accompanying 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, including capacity contracts required by regulation, and the net amounts recorded as current or long-term derivative liability or asset, by primary underlying risk exposure or purpose:


		As of June 30, 2012
			Commodity				Net Amount
			Supply and				Recorded as
			Price Risk		Collateral		Derivative
(Millions of Dollars)			Management		and Netting ⁽¹⁾		Asset/(Liability) ⁽²⁾
Current Derivative Assets:
Level 2:
	PSNH		$	1.0	$	-	$	1.0
Level 3:
	CL&P			18.1		(12.1)		6.0
	Other			5.8		-		5.8
Total Current Derivative Assets			$	24.9	$	(12.1)	$	12.8

Long-Term Derivative Assets:
Level 2:
	Other		$	0.5	$	(0.1)	$	0.4
Level 3:
	CL&P			167.2		(76.1)		91.1
	Other			2.1		-		2.1
Total Long-Term Derivative Assets			$	169.8	$	(76.2)	$	93.6

Current Derivative Liabilities:
Level 2:
	Other		$	(18.5)	$	4.6	$	(13.9)
Level 3:
	CL&P			(97.7)		-		(97.7)
	NSTAR Electric			(0.7)		-		(0.7)
	WMECO			(0.9)		-		(0.9)
Total Current Derivative Liabilities			$	(117.8)	$	4.6	$	(113.2)

Long-Term Derivative Liabilities:
Level 2:
	Other		$	(8.8)	$	-	$	(8.8)
Level 3:
	CL&P			(910.1)		-		(910.1)
	NSTAR Electric			(15.1)		-		(15.1)
	WMECO			(12.6)		-		(12.6)
Total Long-Term Derivative Liabilities			$	(946.6)	$	-	$	(946.6)


		As of December 31, 2011

			Commodity				Net Amount
			Supply and				Recorded as
			Price Risk		Collateral		Derivative
(Millions of Dollars)			Management		and Netting ⁽¹⁾		Asset/(Liability) ⁽²⁾
Current Derivative Assets:
Level 3:
	CL&P		$	17.9	$	(11.6)	$	6.3
	Other			4.7		-		4.7
Total Current Derivative Assets ⁽³⁾			$	22.6	$	(11.6)	$	11.0

Long-Term Derivative Assets:
Level 3:
	CL&P		$	174.2	$	(80.4)	$	93.8
	Other			4.6		-		4.6
Total Long-Term Derivative Assets			$	178.8	$	(80.4)	$	98.4

Current Derivative Liabilities:
Level 3:
	CL&P		$	(95.9)	$	-	$	(95.9)
	WMECO			(0.1)		-		(0.1)
	Other			(16.1)		4.5		(11.6)
Total Current Derivative Liabilities			$	(112.1)	$	4.5	$	(107.6)

Long-Term Derivative Liabilities:
Level 3:
	CL&P		$	(935.8)	$	-	$	(935.8)
	WMECO			(7.2)		-		(7.2)
	Other			(17.3)		0.4		(16.9)
Total Long-Term Derivative Liabilities ⁽⁴⁾			$	(960.3)	$	0.4	$	(959.9)

⁽¹⁾

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

⁽²⁾

Current derivative assets are included in Prepayments and Other Current Assets on the accompanying unaudited condensed consolidated balance sheets. NSTAR Electric and WMECO derivative liabilities are included in Other Current Liabilities and Other Long-Term Liabilities on their accompanying unaudited condensed consolidated balance sheets. The NSTAR Electric amounts are not included in NU consolidated as of December 31, 2011.

⁽³⁾

In addition to the amounts reflected in the table, as of December 31, 2011, NU had $2.3 million of hedging instruments that were classified as Level 2 in the fair value hierarchy, which related to a fair value hedge that expired on April 2, 2012 and was included in Prepayments and Other Current Assets on the accompanying unaudited condensed consolidated balance sheet.

⁽⁴⁾

As of December 31, 2011, NSTAR Electric had $3.4 million of derivative liabilities classified as Level 3 within the fair value hierarchy and included in Other Long-Term Liabilities on the accompanying NSTAR Electric unaudited condensed consolidated balance sheet. These amounts are not included in NU consolidated as of December 31, 2011.

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

Derivatives not designated as hedges

Commodity supply and price risk management: As required by regulation, CL&P has capacity-related contracts with generation facilities. These contracts and similar UI contracts have an expected capacity of 787 MW. CL&P has a sharing agreement with UI, with 80 percent of each contract allocated to CL&P and 20 percent allocated to UI. The capacity contracts 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. In addition, CL&P has a contract to purchase 0.1 million MWh of energy per year through 2020.

NSTAR Electric has a renewable energy contract to purchase approximately 60 thousand MWh of energy per year through 2017. NSTAR Electric also has a capacity related contract for approximately 25 MW to 35 MW that extends through 2019.

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.

As of June 30, 2012 and December 31, 2011, NU had approximately 37 thousand MWh and 123 thousand MWh, respectively, of supply volumes remaining in its unregulated wholesale portfolio when expected sales are compared with supply contracts.

The following table presents the realized and unrealized gains/(losses) associated with NU’s derivative contracts not designated as hedges (See Level 3 tables below for CL&P, NSTAR Electric and WMECO gains and losses on derivative contracts):

Amounts Recognized on Derivative

Location of Amount

For the Three Months Ended

For the Six Months Ended

Recognized on Derivative

June 30, 2012

June 30, 2011

June 30, 2012

June 30, 2011

(Millions of Dollars)

Balance Sheet:

Regulatory Assets

(40.8)

(14.7)

(33.5)

(45.2)

Statement of Income:

Purchased Power, Fuel and Transmission

(0.2)

0.5

(1.0)

0.8

Hedging instruments

Fair Value Hedge: NU parent had a fixed to floating interest rate swap on its $263 million, fixed rate senior note that matured on April 1, 2012. This interest rate swap qualified and was designated as a fair value hedge. Prior to the settlement of the swap on April 2, 2012, $2.5 million of interest benefit was recorded in net income in the first quarter of 2012. For the three and six months ended June 30, 2011, $2.7 million and $5.4 million of interest benefit was recorded in net income, respectively.

Cash Flow Hedges: In 2011, PSNH and WMECO settled interest rate swaps associated with $280 million and $50 million, respectively, of long-term debt issuances and as a result PSNH and WMECO recorded pre-tax reductions of $18.2 million and $6.9 million, respectively, to AOCI that are being amortized over the remaining lives of the associated debt. NU reclassified $0.7 million and $1.6 million of losses from AOCI into interest expense for the three and six months ended June 30, 2012, respectively. These amounts were $0.1 million and $0.2 million for the three and six months ended June 30, 2011, respectively.

Credit Risk

Certain of NU’s contracts contain credit risk contingent features. These features require NU to maintain investment grade credit ratings from the major rating agencies and to post cash or standby LOCs as collateral for contracts in a net liability position over specified credit limits. The following summarizes the fair value of derivative contracts that were in a 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 June 30, 2012 and December 31, 2011:

As of June 30, 2012

As of December 31, 2011

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

(21.1)

4.3

17.3

(23.5)

4.1

19.9

Fair Value Measurements of Derivative Instruments

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

The fair value of derivative contracts classified as Level 3 utilize significant unobservable inputs. The fair value is modeled using income techniques, such as discounted cash flow approaches adjusted for assumptions relating to exit price. Significant observable inputs for valuations of these contracts include energy and energy-related product prices in future years for which quoted prices in an active market exist. Fair value measurements categorized in Level 3 of the fair value hierarchy are prepared by individuals with expertise in valuation techniques, pricing of energy and energy-related products, and accounting requirements. The future power and capacity prices for periods that are not quoted in an active market or established at auction are based on available market data and are escalated based on estimates of inflation to address the full time period of the contract.

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

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


	Range	Period Covered
Energy Prices:
NU	$41 - $78 per MWh	2017 - 2027
CL&P	$47 - $52 per MWh	2017 - 2020
WMECO	$41 - $78 per MWh	2017 - 2027

Capacity Prices:
NU	$1.40 - $10.18 per kW-Month	2016 - 2027
CL&P	$1.40 - $9.51 per kW-Month	2016 - 2026
NSTAR Electric	$1.40 - $10.18 per kW-Month	2016 - 2027
WMECO	$1.40 - $10.18 per kW-Month	2016 - 2027

Forward Reserve:
NU, CL&P	$0.50 per kW-Month	2012 - 2024

REC Prices:
NU	$25 - $84 per REC	2012 - 2027
NSTAR Electric	$25 - $60 per REC	2012 - 2017
WMECO	$25 - $84 per REC	2012 - 2027

Exit price premiums of 10 percent through 32 percent are also applied on these contracts.

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

Valuations using significant unobservable inputs: The following tables present changes for the three and six months ended June 30, 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.


		For the Three Months Ended				For the Six Months Ended
		June 30, 2012		June 30, 2011		June 30, 2012		June 30, 2011
(Millions of Dollars)		NU		NU		NU		NU
Derivatives, Net:
Fair Value as of Beginning of Period		$	(901.5)	$	(872.7)	$	(962.2)	$	(840.2)
Increase due to Merger with NSTAR			(5.4)		-		(5.4)		-
Transfer to Level 2			-		-		32.2		-
Net Realized/Unrealized Gains/(Losses) Included in:
	Net Income ⁽²⁾		(0.7)		0.5		7.4		0.8
	Regulatory Assets		(42.6)		(13.9)		(35.4)		(45.2)
Settlements			18.1		(0.1)		31.3		(1.6)
Fair Value as of End of Period		$	(932.1)	$	(886.2)	$	(932.1)	$	(886.2)


		For the Three Months Ended
		June 30, 2012						June 30, 2011
(Millions of Dollars)		CL&P		NSTAR Electric		WMECO		CL&P		NSTAR Electric ⁽¹⁾
Derivatives, Net:
Fair Value as of Beginning of Period		$	(899.6)	$	(5.4)	$	(12.3)	$	(842.6)	$	(2.1)
Net Realized/Unrealized Gains/(Losses)
	Included in Regulatory Assets		(31.8)		(9.6)		(1.2)		(13.9)		1.9
Settlements			20.7		(0.8)		-		(2.2)		(0.8)
Fair Value as of End of Period		$	(910.7)	$	(15.8)	$	(13.5)	$	(858.7)	$	(1.0)

		For the Six Months Ended
		June 30, 2012						June 30, 2011
(Millions of Dollars)		CL&P		NSTAR Electric ⁽¹⁾		WMECO		CL&P		NSTAR Electric ⁽¹⁾
Derivatives, Net:
Fair Value as of Beginning of Period		$	(931.6)	$	(3.4)	$	(7.3)	$	(806.1)	$	(2.4)
Net Realized/Unrealized Gains/(Losses)
	Included in Regulatory Assets		(21.0)		(10.2)		(6.2)		(45.1)		3.0
Settlements			41.9		(2.2)		-		(7.5)		(1.6)
Fair Value as of End of Period		$	(910.7)	$	(15.8)	$	(13.5)	$	(858.7)	$	(1.0)

⁽¹⁾

NSTAR Electric amounts are included in NU consolidated from the date of the merger, April 10, 2012, through June 30, 2012.

⁽²⁾

The Net Income impact for the three and six months ended June 30, 2012 relate to the unregulated wholesale marketing sales contract and are offset by the gains/(losses) on the unregulated sourcing contracts classified as Level 2 in the fair value hierarchy, resulting in total losses of $0.2 million and $1 million for the three and six months ended June 30, 2012, respectively.

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, each of which hold marketable securities. These trusts are not subject to regulatory oversight by state or federal agencies. As of April 10, 2012, upon consummation of the merger with NSTAR and consolidation of CYAPC and YAEC, NU's marketable securities also includes legally restricted trusts for the decommissioning of nuclear power plants.

The Company elects to record mutual funds purchased by the NU supplemental benefit trust at fair value. As such, any change in fair value of these mutual funds is reflected in Net Income. These mutual funds, classified as Level 1 in the fair value hierarchy, totaled $43.8 million and $41.1 million as of June 30, 2012 and December 31, 2011, respectively, and are included in current Marketable Securities. Net losses on these securities of $0.5 million for the three months ended June 30, 2012 and net gains on these securities of $2.7 million for the six months ended June 30, 2012 and net gains of $0.3 million and $2.2 million for the three and six months ended June 30, 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, WMECO's spent nuclear fuel trust and CYAPC and YAEC's nuclear decommissioning trusts. These securities are recorded at fair value and included in current and long-term Marketable Securities on the accompanying unaudited condensed consolidated balance sheets.


		As of June 30, 2012
				Pre-Tax		Pre-Tax
		Amortized		Unrealized		Unrealized
(Millions of Dollars)		Cost		Gains ⁽¹⁾		Losses ⁽¹⁾		Fair Value
NU
	Debt Securities ⁽²⁾	$	256.1	$	10.9	$	(0.3)	$	266.7
	Equity Securities ⁽²⁾		134.6		12.0		(5.6)		141.0
WMECO
	Debt Securities		57.5		0.1		(0.1)		57.5

		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.

⁽²⁾

NU's June 30, 2012 amounts include CYAPC's and YAEC's marketable securities held in nuclear decommissioning trusts of $304 million, the majority of which are legally restricted and can only be used for the decommissioning of the nuclear power plants owned by these companies. Unrealized gains and losses for the nuclear decommissioning trusts are offset against the spent nuclear fuel obligation recorded in Other Long-Term Liabilities on the accompanying unaudited condensed consolidated balance sheet. All of the equity securities accounted for as available-for-sale securities are held in these trusts.

Unrealized Losses and Other-than-Temporary Impairment: There have been no significant unrealized losses, other-than-temporary impairments or credit losses for the NU supplemental benefit trust 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 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 and the CYAPC and YAEC nuclear decommissioning trusts to compute the realized gains and losses on the sale of available-for-sale securities.

Contractual Maturities : As of June 30, 2012, the contractual maturities of available-for-sale debt securities are as follows:


	NU				WMECO
	Amortized				Amortized
(Millions of Dollars)	Cost		Fair Value		Cost		Fair Value
Less than one year ⁽¹⁾	$	52.9	$	52.9	$	18.5	$	18.5
One to five years		53.8		55.0		23.2		23.2
Six to ten years		51.9		54.9		6.0		6.1
Greater than ten years		97.5		103.9		9.8		9.7
Total Debt Securities	$	256.1	$	266.7	$	57.5	$	57.5

⁽¹⁾

Amounts in the Less than one year category include securities in the nuclear decommissioning trust, which are restricted and are classified in long-term Marketable Securities on the accompanying unaudited condensed consolidated balance sheet.

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


			NU				WMECO
			As of		As of		As of		As of
(Millions of Dollars)			June 30, 2012		December 31, 2011		June 30, 2012		December 31, 2011
Level 1:
	Mutual Funds and Equity Securities		$	184.8	$	41.1	$	-	$	-
	Money Market Funds			36.3		1.8		3.8		0.1
Total Level 1			$	221.1	$	42.9	$	3.8	$	0.1
Level 2:
	U.S. Government Issued Debt Securities
		(Agency and Treasury)		59.5		11.1		18.7		8.0
	Corporate Debt Securities			31.4		16.5		6.2		9.1
	Asset-Backed Debt Securities			27.4		25.9		6.5		7.9
	Municipal Bonds			96.4		16.1		15.5		15.4
	Other Fixed Income Securities			15.7		18.8		6.8		16.6
Total Level 2			$	230.4	$	88.4	$	53.7	$	57.0
Total Marketable Securities			$	451.5	$	131.3	$	57.5	$	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.

SHORT-TERM DEBT (CL&P)

Limits: The amount of short-term borrowings that may be incurred by CL&P 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 June 30, 2012, CL&P had $300 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 June 30, 2012 was 1.59 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 June 30, 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.

LONG-TERM DEBT (NU, CL&P)

On March 22, 2012, NU parent issued $300 million of floating rate Series D Senior Notes with a maturity date of September 20, 2013. The notes have a coupon rate based on the three-month LIBOR rate plus a credit spread of 0.75 percent and will reset quarterly. The notes had an interest rate of 1.22 percent as of June 30, 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.

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

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

In addition, as a result of consolidating CYAPC and YAEC, NU has consolidated $179 million in additional spent nuclear fuel obligations. The spent nuclear fuel obligation is payable to the DOE at any time prior to the first delivery to the DOE of spent nuclear

fuel and radio-active waste used to generate electricity prior to April 7, 1983. Until payment is made to the DOE, the outstanding liability will continue to accrue interest at the 3-month Treasury bill yield rate.

NU, including CL&P, NSTAR Electric, PSNH and WMECO, was in compliance with all its debt covenants as of June 30, 2012.

EMPLOYEE BENEFITS

Pension Benefits and Postretirement Benefits Other Than Pensions

NUSCO sponsors a Pension Plan that covers nonbargaining unit employees (and bargaining unit employees, as negotiated), including CL&P, PSNH, and WMECO employees, hired before 2006 (or as negotiated, for bargaining unit employees) and NSTAR Electric serves as plan sponsor for a defined benefit retirement plan that covers substantially all employees of NSTAR Electric & Gas, which is a Northeast Utilities service company. Both plans are subject to the provisions of ERISA, as amended by the PPA of 2006. NU and NSTAR Electric & Gas each maintain SERPs and other non-qualified defined benefit plans, which provide benefits in excess of Internal Revenue Code limitations to eligible current and retired participants that would have otherwise been provided under the Pension Plans. Amounts related to these plans are included with the Pension Plans in the tables below.

NUSCO and NSTAR Electric & Gas also sponsor plans that provide certain retiree health care benefits, primarily medical and dental, and life insurance benefits through PBOP Plans and Group Welfare Benefit Plans to employees that meet certain age and service eligibility requirements. Under certain circumstances, eligible retirees are required to contribute to the costs of postretirement benefits.

The funded status of each of the plans is recorded on the respective sponsor's balance sheet: NUSCO (NUSCO pension, NUSCO PBOP and NUSCO SERP), NSTAR Electric (NSTAR pension) and NSTAR Electric & Gas (NSTAR SERP and PBOP). The NUSCO plans are accounted for under the multiple-employer approach, and therefore, the funded status of the NUSCO plans is allocated to and recorded on the balance sheets of CL&P, PSNH and WMECO. The NSTAR plans were accounted for under the multi-employer approach prior to the merger and NU continues to account for these plans under the multi-employer approach. Under multi-employer accounting, the funded status is recorded on the plan sponsor's balance sheet and other subsidiaries that participate in the plan record any unpaid contributions to the plan on their respective balance sheets. Accordingly, the balance sheet of NSTAR Electric reflects the full funded status of the NSTAR Electric Pension Plan and does not reflect the funded status of the NSTAR PBOP or SERP plans.

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


	Pension and SERP Plans
	For the Three Months Ended				For the Six Months Ended
	June 30, 2012		June 30, 2011		June 30, 2012			June 30, 2011
(Millions of Dollars)	NU		NU		NU			NU
Service Cost	$	22.8	$	14.0	$		38.1	$	27.7
Interest Cost		53.2		38.3			91.3		76.5
Expected Return on Plan Assets		(59.4)		(42.2)			(101.9)		(85.3)
Actuarial Loss		47.4		21.1			77.4		42.1
Prior Service Cost		2.0		2.4			4.1		4.8
Total - Net Periodic Benefit Expense	$	66.0	$	33.6	$		109.0	$	65.8
Capitalized Pension Expense	$	19.7	$	8.0	$		30.3	$	15.7

	PBOP Plans and Group Welfare Benefit Plans
	For the Three Months Ended					For the Six Months Ended
	June 30, 2012		June 30, 2011			June 30, 2012		June 30, 2011
(Millions of Dollars)	NU		NU			NU		NU
Service Cost	$	4.5	$	2.1		$	6.8	$	4.5
Interest Cost		13.9		6.5			20.1		12.9
Expected Return on Plan Assets		(11.3)		(5.4)			(17.0)		(10.8)
Actuarial Loss		9.7		5.0			15.2		9.5
Prior Service Credit		(0.4)		-			(0.4)		(0.1)
Net Transition Obligation Cost		3.1		2.9			5.9		5.8
Total - Net Periodic Benefit Expense	$	19.5	$	11.1		$	30.6	$	21.8



		Pension and SERP Plans
		For the Three Months Ended June 30, 2012								For the Three Months Ended June 30, 2011
				NSTAR								NSTAR
(Millions of Dollars)		CL&P		Electric ⁽¹⁾		PSNH		WMECO		CL&P		Electric ^{(1), (2)}		PSNH		WMECO
Service Cost		$	5.4	$	7.3	$	2.9	$	1.1	$	4.9	$	6.1	$	2.7	$	1.0
Interest Cost			12.9		14.7		6.1		2.6		13.0		15.3		6.1		2.7
Expected Return on Plan Assets			(17.7)		(16.3)		(7.2)		(4.1)		(19.1)		(18.4)		(4.7)		(4.4)
Actuarial Loss			12.6		15.9		4.1		2.7		8.2		12.5		2.6		1.7
Prior Service Cost/(Credit)			0.9		(0.1)		0.4		0.2		1.0		(0.2)		0.5		0.2
Total - Net Periodic Benefit Expense		$	14.1	$	21.5	$	6.3	$	2.5	$	8.0	$	15.3	$	7.2	$	1.2
Related Intercompany
	Allocations	$	10.7	$	(3.0)	$	2.4	$	2.0	$	8.7	$	(2.0)	$	1.9	$	1.6
Capitalized Pension Expense		$	6.8	$	8.9	$	1.9	$	1.2	$	4.4	$	4.9	$	2.0	$	2.7

		Pension and SERP Plans
		For the Six Months Ended June 30, 2012								For the Six Months Ended June 30, 2011
				NSTAR								NSTAR
(Millions of Dollars)		CL&P		Electric ^{(1), (2)}		PSNH		WMECO		CL&P		Electric ^{(1), (2)}		PSNH		WMECO
Service Cost		$	10.9	$	15.1	$	5.8	$	2.1	$	9.7	$	13.0	$	5.3	$	2.0
Interest Cost			25.6		29.5		12.2		5.3		26.1		30.5		12.3		5.4
Expected Return on Plan Assets			(35.2)		(32.8)		(13.9)		(8.2)		(38.3)		(35.7)		(10.0)		(8.8)
Actuarial Loss			24.5		31.6		8.0		5.2		16.6		24.3		5.2		3.4
Prior Service Cost/(Credit)			1.8		(0.3)		0.8		0.4		2.0		(0.4)		1.0		0.4
Total - Net Periodic Benefit Expense		$	27.6	$	43.1	$	12.9	$	4.8	$	16.1	$	31.7	$	13.8	$	2.4
Related Intercompany
	Allocations	$	21.3	$	(6.2)	$	5.0	$	4.0	$	16.5	$	(4.5)	$	3.8	$	3.0
Capitalized Pension Expense		$	13.4	$	15.2	$	3.9	$	2.4	$	8.9	$	9.9	$	3.9	$	1.4


		PBOP Plans
		For the Three Months Ended June 30, 2012						For the Three Months Ended June 30, 2011
(Millions of Dollars)		CL&P			PSNH		WMECO	CL&P		PSNH		WMECO
Service Cost		$	0.7	$	0.5	$	0.1	$	0.7	$	0.5	$	0.2
Interest Cost			2.3		1.1		0.5		2.5		1.2		0.5
Expected Return on Plan Assets			(2.3)		(1.1)		(0.5)		(2.1)		(1.1)		(0.5)
Actuarial Loss			1.8		0.8		0.3		1.9		0.9		0.3
Net Transition Obligation Cost			1.5		0.6		0.3		1.5		0.6		0.3
Total - Net Periodic Benefits Expense		$	4.0	$	1.9	$	0.7	$	4.5	$	2.1	$	0.8
Related Intercompany
	Allocations	$	1.9	$	0.5	$	0.4	$	2.0	$	0.5	$	0.9

		PBOP Plans
		For the Six Months Ended June 30, 2012						For the Six Months Ended June 30, 2011
(Millions of Dollars)		CL&P		PSNH		WMECO		CL&P		PSNH		WMECO
Service Cost		$	1.4	$	1.0	$	0.3	$	1.4	$	1.0	$	0.3
Interest Cost			4.6		2.3		1.0		5.0		2.4		1.1
Expected Return on Plan Assets			(4.5)		(2.3)		(1.1)		(4.3)		(2.2)		(1.0)
Actuarial Loss			3.8		1.8		0.6		3.6		1.6		0.6
Net Transition Obligation Cost			3.0		1.2		0.7		3.1		1.2		0.6
Total - Net Periodic Benefits Expense		$	8.3	$	4.0	$	1.5	$	8.8	$	4.0	$	1.6
Related Intercompany
	Allocations	$	4.1	$	1.0	$	0.8	$	4.1	$	1.0	$	1.7

⁽¹⁾

NSTAR Electric’s pension amounts do not include SERP expense.

⁽²⁾

NSTAR Electric’s pension expense for the six months ended June 30, 2012 included $21.6 million of costs incurred prior to the closing of NSTAR’s merger with NU. These amounts are not included in NU’s net periodic benefit costs for the six months ended June 30, 2012. The NSTAR Electric expenses are not included in the consolidated NU results for the three and six months ended June 30, 2011.

NSTAR Electric PBOP Expense: NSTAR Electric participates in a PBOP Plan sponsored by NSTAR Electric & Gas. NSTAR Electric recognizes unpaid contributions that are due to NSTAR Electric & Gas as a liability on the accompanying unaudited condensed consolidated balance sheets. The funded status of the PBOP plan is reflected on NU’s accompanying unaudited condensed consolidated balance sheet. However, the funded status of the PBOP plan is not reflected on NSTAR Electric’s accompanying unaudited condensed consolidated balance sheets. For the three and six months ended June 30, 2012, the net periodic postretirement benefits costs allocated to NSTAR Electric were $8 million and $17 million, respectively, of which $9 million was incurred prior to the closing of NSTAR’s merger with NU. These amounts were $5.1 million and $12.8 million for the three and six months ended June 30, 2011, respectively. These amounts are fully recovered from customers in cost-of-service regulated rates.

Curtailment Expense (SERP): NU recorded curtailment expense of $1.8 million for the NUSCO SERP in the second quarter of 2012 to reflect charges related to organization changes that occurred as a result of the merger.

Contributions: NU’s policy is to annually fund the Pension Plans sponsored by NUSCO and NSTAR Electric 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 NUSCO Pension Plan, NU is required to make a contribution to the NUSCO 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 $35.1 million and $127.1 million ($87.7 million of which was contributed by PSNH in the first quarter of 2012) for the three and six months ended June 30, 2012, respectively. NSTAR Electric currently anticipates making contributions to the NSTAR Electric Pension Plan of approximately $25 million in 2012, of which $6.3 million was contributed in the second quarter of 2012. NSTAR Electric did not contribute to the Plan in the first quarter of 2012. The actual level of funding may differ from this estimate.

Share-Based Payments

In accordance with accounting guidance for share-based payments, share-based compensation awards are recorded using the fair value-based method at the date of grant. NU, CL&P, NSTAR Electric, PSNH and WMECO record compensation cost related to these awards, as applicable, for shares issued or sold to NU, CL&P, NSTAR Electric, PSNH and WMECO employees and officers, as well as the allocation of costs associated with shares issued or sold to NU's service companies' employees and officers that support CL&P, NSTAR Electric, PSNH and WMECO.

Upon consummation of the merger of NU and NSTAR, the NSTAR 1997 Share Incentive Plan and the NSTAR 2007 Long-Term Incentive Plan were assumed by NU. Share-based awards granted under the NSTAR Plans and held by NSTAR employees and officers were generally converted into outstanding NU share-based compensation awards with the estimated fair value of $53.2 million. Refer to Note 2, "Merger of NU and NSTAR," for further information regarding the merger transaction. Specifically, as of the merger closing, and as adjusted by the exchange ratio, (1) NU converted outstanding NSTAR stock options into 2,664,894 NU stock options valued at $30.5 million, (2) NU converted NSTAR Deferred Shares and NSTAR Performance Shares into 421,775 NU RSU’s valued at $15.5 million, and (3) NU converted NSTAR RSU Retention Awards into 195,619 NU RSU Retention Awards valued at $7.2 million.

NU Incentive Plan: NU maintains long-term equity-based incentive plans under the NU Incentive Plan in which NU, CL&P, PSNH and WMECO employees, officers and board members are entitled to participate. The NU Incentive Plan was approved in 2007, and authorized NU to grant up to 4,500,000 new shares for various types of awards, including RSUs and performance shares, to eligible employees, officers, and board members. As of June 30, 2012 and December 31, 2011, NU had 2,530,024 and 2,685,615 common shares, respectively, available for issuance under the NU Incentive Plan. In addition to the NU Incentive Plan, NU maintains an ESPP for all eligible employees.

NSTAR Incentive Plans : Awards may continue to be granted following the merger under the NSTAR 2007 Long-Term Incentive Plan; however, no additional awards will be granted under the NSTAR 1997 Share Incentive Plan. The aggregate number of common shares initially authorized for issuance under the NSTAR 2007 Long-Term Incentive Plan was 3,500,000. As of June 30, 2012 and December 31, 2011, there were 977,922 and 988,729 common shares, respectively, available for issuance under the NSTAR 2007 Long-Term Incentive Plan.

NU accounts for its various share-based plans as follows:

For grants of RSUs, NU records compensation expense, net of estimated forfeitures, on a straight-line basis over the vesting period based upon the fair value of NU's common shares at the date of grant. The par value of RSUs is reclassified to Common Stock from APIC as RSUs become issued as common shares.

For grants of performance shares, NU records compensation expense, net of estimated forfeitures, on a straight-line basis over the vesting period. Performance shares vest based upon the extent to which Company goals are achieved. For the majority of performance shares, fair value is based upon the value of NU's common shares at the date of grant and compensation expense is recorded based upon the probable outcome of the achievement of Company targets. For the remaining performance shares, vesting is based upon the achievement of the Company's share price as compared to an index of similar equity securities. The fair value at the date of grant for these remaining performance shares was determined using a lattice model and compensation expense is recorded over the vesting period.

For shares sold under the ESPP, no compensation expense is recorded, as the ESPP qualifies as a non-compensatory plan.

For the six months ended June 30, 2012 and 2011, additional tax benefits totaling $2.8 million and $1.1 million, respectively, increased cash flows from financing activities.

RSUs: NU has granted RSUs under the 2004 through 2012 incentive programs that are subject to three-year graded vesting schedules for employees, and one-year graded vesting schedules for board members. RSUs are paid in shares, reduced by amounts sufficient to satisfy withholdings, subsequent to vesting. A summary of RSU transactions is as follows:


			Weighted Average
	RSUs		Grant-Date
RSUs	(Units)		Fair Value
Outstanding as of December 31, 2011		959,920	$	26.36
Granted		538,724	$	32.72
Converted NSTAR awards upon merger		617,394	$	36.79
Converted from NU performance shares upon merger		451,358	$	34.32
Shares issued		(300,460)	$	27.90
Forfeited		(76,361)	$	34.77
Outstanding as of June 30, 2012		2,190,575	$	31.97

As of June 30, 2012 and December 31, 2011, the number and weighted average grant-date fair value of unvested RSUs was 1,380,118 and $34.62 per share, and 403,108 and $28.70 per share, respectively. The number and weighted average grant-date fair value of RSUs vested during 2012 was 459,274 and $30.02 per share, respectively. As of June 30, 2012, 805,038 RSUs were fully vested and an additional 1,311,112 are expected to vest.

Performance Shares: NU had granted performance shares under the annual Long-Term Incentive programs that vested based upon the extent to which the Company achieved targets at the end of three-year performance measurement periods. Performance shares are paid in shares, after the performance measurement period. A summary of performance share transactions is as follows:


	Performance		Weighted Average
	Shares		Grant-Date
Performance Shares	(Units)		Fair Value
Outstanding as of December 31, 2011		483,133	$	29.18
Granted		226,326	$	34.46
Converted to RSUs upon merger		(451,358)	$	34.32
Shares issued		(106,773)	$	24.52
Forfeited		-	$	-
Outstanding as of June 30, 2012		151,328	$	25.04

Upon closing of the merger with NSTAR, 451,358 performance shares under the NU 2011 and 2012 Long-Term Incentive Programs converted to RSUs according to the terms of these programs. The remaining performance shares were measured based upon a modified performance period through the date of the merger, in accordance with the terms of the NU 2010 Incentive Program with distribution in 2013.

The total compensation cost recognized by NU, CL&P, NSTAR Electric, PSNH and WMECO for share-based compensation awards was as follows:


NU	For the Three Months Ended				For the Six Months Ended
(Millions of Dollars)	June 30, 2012		June 30, 2011		June 30, 2012		June 30, 2011
Compensation Cost Recognized	$	12.8	$	3.0	$	16.4	$	6.1
Associated Future Income Tax Benefit Recognized		5.1		1.2		6.6		2.4


	For the Three Months Ended
	June 30, 2012								June 30, 2011
(Millions of Dollars)	CL&P		NSTAR Electric		PSNH		WMECO		CL&P		NSTAR Electric ⁽¹⁾		PSNH		WMECO
Compensation Cost Recognized	$	0.9	$	2.8	$	0.3	$	0.2	$	1.7	$	1.9	$	0.6	$	0.3
Associated Future Income Tax Benefit Recognized		0.4		1.1		0.1		0.1		0.7		0.7		0.2		0.1

	For the Six Months Ended
	June 30, 2012								June 30, 2011
(Millions of Dollars)	CL&P		NSTAR Electric ⁽¹⁾		PSNH		WMECO		CL&P		NSTAR Electric ⁽¹⁾		PSNH		WMECO
Compensation Cost Recognized	$	3.0	$	4.9	$	1.1	$	0.6	$	3.5	$	3.8	$	1.2	$	0.7
Associated Future Income Tax Benefit Recognized		1.2		1.9		0.4		0.3		1.4		1.5		0.5		0.3

⁽¹⁾

NSTAR Electric amounts are not included in NU consolidated for the three and six months ended June 30, 2011. NSTAR Electric amounts are included in NU consolidated from the date of the merger, April 10, 2012, through June 30, 2012.

As of June 30, 2012, there was $34.9 million of total unrecognized compensation cost related to nonvested share-based awards for NU, $6.8 million for CL&P, $9.8 million for NSTAR Electric, $2.5 million for PSNH and $1.5 million for WMECO. This cost is expected to be recognized ratably over a weighted-average period of 2.37 years for NU, 2.17 years for CL&P, 2.41 years for NSTAR Electric, and 2.15 years for PSNH and WMECO.

Stock Options: Awards are available for grant under the NU Incentive Plan and the NSTAR 2007 Long-Term Incentive Plan. Options currently outstanding expire ten years from the date of grant and the fair value of each stock option grant was estimated using the Black-Scholes option pricing model. The weighted average remaining contractual lives for the options outstanding as of June 30, 2012 is 4.7 years . A summary of stock option transactions is as follows:


			Exercise Price Per Share
						Weighted		Intrinsic Value
	Options		Range			Average		(Millions)
Outstanding and Exercisable as of December 31, 2011		47,374	$ 18.58	-	$ 18.90	$	18.78
Converted NSTAR Options upon merger		2,664,894	$ 16.47	-	$ 28.12	$	23.99
Exercised		(340,607)				$	23.84	$	4.3
Forfeited and cancelled		-
Outstanding and Exercisable as of June 30, 2012		2,371,661	$ 18.45	-	$ 28.12	$	23.90	$	35.4

Cash received for options exercised during the six months ended June 30, 2012 totaled $8.1 million. The tax benefit realized from stock options exercised totaled $1.8 million for the six months ended June 30, 2012.

Employee Share Purchase Plan: NU maintains an ESPP for all eligible employees, which allows for NU common shares to be purchased by employees at the end of successive six-month offering periods at 95 percent of the closing market price on the last day of each six-month period. Employees are permitted to purchase shares having a value not exceeding 25 percent of their compensation as of the beginning of the offering period up to a limit of $25,000 per annum. The ESPP qualifies as a non-compensatory plan under accounting guidance for share-based payments, and no compensation expense is recorded for ESPP purchases.

During 2012, employees purchased 20,555 shares at a discounted price of $33.01. Employees purchased 35,476 shares in 2011 at discounted prices of $31.27 and $32.30. As of June 30, 2012 and December 31, 2011, 876,147 and 896,702 shares, respectively, remained available for future issuance under the ESPP.

An income tax rate of 40 percent is used to estimate the tax effect on total share-based payments determined under the fair value-based method for all awards. The Company generally settles stock option exercises and fully vested RSUs and performance shares with the issuance of new common shares.

10.

COMMITMENTS AND CONTINGENCIES

Environmental Matters

General: NU, CL&P, NSTAR Electric, PSNH and WMECO are subject to environmental laws and regulations intended to mitigate or remove the effect of past operations and improve or maintain the quality of the environment. These laws and regulations require the removal or the remedy of the effect on the environment of the disposal or release of certain specified hazardous substances at current and former operating sites. NU, CL&P, NSTAR Electric, PSNH and WMECO have an active environmental auditing and training program and believe that they are substantially in compliance with all enacted laws and regulations.

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


	As of June 30, 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		83	$	41.8	$	37.4		59	$	31.7	$	28.9
CL&P		19		3.2		1.5		18		2.9		1.5
NSTAR Electric ⁽¹⁾		13		1.4		-		13		1.3		-
PSNH		19		6.5		5.5		18		6.6		5.8
WMECO		10		0.3		0.1		10		0.3		0.1

⁽¹⁾ The NSTAR Electric balance is not included in the NU consolidated balance as of December 31, 2011.

MGP sites were operated several decades ago and manufactured gas from coal, which resulted in certain byproducts in the environment that may pose a risk to human health and the environment.

HWP: HWP, a subsidiary of NU, continues to investigate the potential need for additional remediation at a river site in Massachusetts containing tar deposits associated with an MGP site that HWP sold to HG&E, a municipal utility, in 1902. HWP shares responsibility for site remediation with HG&E and has conducted substantial investigative and remediation activities. The cumulative expense recorded to the reserve for this site since 1994 through June 30, 2012 was $19.5 million, of which $17.3 million had been spent, leaving $2.2 million in the reserve as of June 30, 2012. There were no charges to the reserve for the three or six months ended June 30, 2012 or 2011. HWP's share of the costs related to this site is not recoverable from customers.

The $2.2 million reserve balance as of June 30, 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.

Long-Term Contractual Arrangements

For information regarding long-term contractual obligations as of December 31, 2011, see Note 12B, "Commitments and Contingencies – Long-Term Contractual Arrangements," of the NU 2011 Form 10-K, Note P, "Commitments and Contingencies," of the NSTAR 2011 Form 10-K and Note K, "Commitments and Contingencies," of the NSTAR Electric 2011 Form 10-K.

Estimated Future Annual Costs: As a result of the merger, the NU estimated future annual costs of significant long-term contractual arrangements as of June 30, 2012 now incorporate commitments for NSTAR LLC and its subsidiaries, which are as follows:


	July - December
(Millions of Dollars)	2012		2013		2014		2015		2016		Thereafter		Totals
Supply/Stranded Cost Contracts/Obligations	$	16.3	$	28.7	$	33.0	$	32.9	$	12.6	$	7.1	$	130.6
Renewable Energy Supply Contracts		33.7		87.3		86.6		87.9		52.1		252.8		600.4
Transmission Support Commitments		1.9		3.7		3.6		3.5		-		-		12.7
Natural Gas Procurement Contracts		108.5		54.0		47.5		24.7		21.6		78.5		334.8
Future Minimum Operating Lease Payments		6.4		11.5		8.4		7.3		5.7		12.2		51.5
Electric Interconnection Agreement		1.7		3.4		3.4		3.4		3.3		41.1		56.3
Totals	$	168.5	$	188.6	$	182.5	$	159.7	$	95.3	$	391.7	$	1,186.3

Merger-Related Commitments: The preceding table does not include the commitments made in connection with the Connecticut and Massachusetts settlement agreements, including NSTAR Electric's commitment to enter into a 15-year agreement to purchase 129 MW of renewable energy from a wind facility to be constructed off the shores of Cape Cod, Massachusetts.

Deferred Contractual Obligations

CL&P, NSTAR Electric, PSNH and WMECO have decommissioning and plant closure cost obligations to the Yankee Companies, which have each completed the physical decommissioning of their respective nuclear facilities and are now engaged in the long-term storage of their spent fuel. The Yankee Companies collect decommissioning and closure costs through wholesale, FERC-approved rates charged under power purchase agreements with several New England utilities, including CL&P, NSTAR Electric, PSNH and WMECO. These companies in turn recover these costs from their customers through state regulatory commission-approved retail rates.

CL&P, NSTAR Electric, PSNH and WMECO's percentage share of the obligations to support the Yankee Companies under FERC-approved rate tariffs is the same as their respective ownership percentages in the Yankee Companies.

The Yankee Companies are currently collecting amounts that management believes are adequate to recover the remaining decommissioning and closure cost estimates for the respective plants. Management believes CL&P, NSTAR Electric and WMECO will recover their shares of these decommissioning and closure obligations from their customers. PSNH has already recovered its share of these costs from its customers.

Spent Nuclear Fuel Litigation:

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

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

On September 7, 2010, the trial court issued its decision following remand, and judgment on the decision was entered on September 9, 2010. The judgment awarded CYAPC $39.7 million, YAEC $21.2 million and MYAPC $81.7 million. The DOE filed an appeal and the Yankee Companies cross-appealed on November 8, 2010. Briefs were filed and oral arguments in the appeal of the remanded case occurred on November 7, 2011. On May 18, 2012, the U.S. Court of Appeals for the Federal Circuit issued a unanimous panel decision in favor of the Yankee Companies upholding the trial court's awards to each company in the remanded cases, and increasing YAEC damages by approximately $17 million to cover certain wet pool operating expenses. The DOE had 45 days (or until July 2, 2012) to request reconsideration of the decision or file a request for additional time, and 90 days to file a petition for certiorari to the U.S. Supreme Court. The DOE has filed for an extension of time, and motions are pending to argue the matter; accordingly, the 90 day period for filing of a petition for certiorari to the U.S. Supreme Court has not yet begun. Interest on the judgments does not start to accrue until all appeals have been decided and/or all appeal periods have expired without appeals being filed. The application of any damages, which are ultimately recovered to benefit customers, is established in the Yankee Companies' FERC-approved rate settlement agreements, although implementation will be subject to the final determination of the FERC.

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

The refund to CL&P, NSTAR Electric, PSNH and WMECO of any damages that may be recovered from the DOE will be realized through the Yankee Companies' FERC-approved rate settlement agreements, subject to final determination of the FERC. CL&P, NSTAR Electric, PSNH and WMECO cannot at this time determine the timing or amount of any ultimate recovery the Yankee Companies may obtain from the DOE on this matter. However, NU believes that any net settlement proceeds it receives would be incorporated into FERC-approved recoveries, which would be passed on to its customers through reduced charges.

Guarantees and Indemnifications

NU parent, or NSTAR LLC, as applicable, provides credit assurances on behalf of its subsidiaries, including CL&P, NSTAR Electric, PSNH and WMECO, in the form of guarantees 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 $25 million. NU's obligations under the guaranty expire upon the full, final and indefeasible payment of the guaranteed obligations.

Management does not anticipate a material impact to Net Income to result from these various guarantees and indemnifications.

The following table summarizes NU's guarantees of its subsidiaries, including CL&P, NSTAR Electric, PSNH, and WMECO, as of June 30, 2012:


		Maximum
		Exposure
Subsidiary	Description	(in millions)			Expiration Dates

Various	Surety Bonds	$	35.0		July 2012 - Nov 2015 (1)

Various	Letters of Credit	$	19.5		Oct 2012 - Dec 2012

Various	NE Hydro Companies' Long-Term Debt	$	6.6		Unspecified

NUSCO and RRR	Lease Payments for Vehicles and Real Estate	$	21.9		2019 and 2024

NU Enterprises	Surety Bonds, Insurance Bonds and Performance Guarantees	$	109.4	(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 $45.4 million related to performance guarantees on wholesale 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 June 30, 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 $48.8 million of maximum exposure relates to surety bonds covering ongoing projects, which expire upon project completion.

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

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.

On May 3, 2012, the FERC issued an order establishing hearing and settlement procedures for the complaint. On August 1, 2012, the settlement judge recommended that FERC terminate the settlement proceedings, as the parties had reached an impasse in their efforts to reach a settlement. The FERC expects 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.

DPU Safety and Reliability Programs - CPSL (NSTAR Electric)

NSTAR Electric recovers incremental costs related to the Double Pole Inspection Program, Replacement/Restoration and Transfer Program and the Underground Electric Safety Program, which includes stray-voltage remediation, manhole inspections, repairs, and upgrades, in accordance with this DPU approved program. Recovery of these CPSL costs is subject to review and approval by the DPU through a rate-reconciling mechanism. From 2006 through June 2012, cumulative costs associated with the CPSL program have resulted in an incremental revenue requirement to customers of approximately $90 million. These amounts include incremental operations and maintenance costs and the related revenue requirement for specific capital investment relative to the CPSL programs.

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

NSTAR Electric cannot predict the timing of any subsequent DPU order related to its CPSL filings for the period 2006 through 2009, or any period thereafter. Therefore, NSTAR Electric continues to record its revenues under the CPSL programs based on the May 2010 Order. Should any subsequent DPU order be different than the conclusion of the May 2010 Order, it could have a material impact on NSTAR Electric’s results of operations, financial position and cash flows.

The comprehensive settlement agreement with the Massachusetts Attorney General stipulates a revenue requirement of up to $15 million per annum for 2012 through 2015 in order to continue these programs. CPSL revenues will end once NSTAR Electric has recovered its 2015-related CPSL costs. Realization of these revenues is subject to maintaining certain performance metrics and DPU approval.

Basic Service Bad Debt Adder (NSTAR Electric)

On July 1, 2005, in response to a generic DPU order that required electric utilities in Massachusetts to recover the energy-related portion of bad debt costs in their Basic Service rates, NSTAR Electric increased its Basic Service rates and reduced its distribution rates for those bad debt costs. In furtherance of this generic DPU order, NSTAR Electric included a bad debt cost recovery mechanism as a component of its 2005 Rate Settlement Agreement. This recovery mechanism (bad debt adder) allows NSTAR Electric to recover its Basic Service bad debt costs on a fully reconciling basis. These rates were implemented, effective January 1, 2006, as part of the 2005 Rate Settlement Agreement.

On February 7, 2007, NSTAR Electric filed its 2006 Basic Service reconciliation with the DPU proposing an adjustment related to the increase of its Basic Service bad debt charge-offs. This proposed rate adjustment was anticipated to be implemented effective July 1, 2007. On June 28, 2007, the DPU issued an order approving the implementation of a revised Basic Service rate. However, the DPU instructed NSTAR Electric to reduce distribution rates by an amount equal to the increase in its Basic Service bad debt charge-offs. Such action would result in a further reduction to distribution rates from the adjustment NSTAR Electric made when it implemented the Settlement Agreement. This adjustment to NSTAR Electric’s distribution rates would eliminate the fully reconciling nature of the Basic Service bad debt adder.

NSTAR Electric continued to defer the costs associated with these amounts as a regulatory asset, which totaled approximately $34 million as of December 31, 2011, as NSTAR Electric had concluded that these costs were probable of recovery in future rates. On June 18, 2010, NSTAR Electric filed an appeal of the DPU’s order with the SJC, which was heard by the SJC in December 2011. On April 11, 2012, the SJC issued a procedural order waiving its standing 130-day rule for issuance of an order on the matter. This delay by the SJC caused NSTAR Electric to reassess its position as to the outcome. Due to the delay, NSTAR Electric concluded that while an ultimate outcome on the matter in its favor remained "more likely than not", it could no longer be deemed "probable". As a result, as of March 31, 2012, NSTAR Electric recognized a reserve of $28 million ($17 million after-tax) as a charge to Operations and Maintenance in the first quarter of 2012 to fully reserve the related regulatory asset on its balance sheet.

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

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 and NSTAR Electric’s preferred stock is based upon pricing models that incorporate interest rates and other market factors, valuations or trades of similar securities and cash flow projections. The fair value of fixed-rate long-term debt securities and RRBs is based upon pricing models that incorporate quoted market prices for those issues or similar issues adjusted for market conditions, credit ratings of the respective companies and treasury

benchmark yields. Adjustable rate securities are assumed to have a fair value equal to their carrying value. The fair values provided in the tables below are classified as Level 2 within the fair value hierarchy. Carrying amounts and estimated fair values are as follows:


		As of June 30, 2012				As of December 31, 2011
		NU				NU
		Carrying		Fair		Carrying		Fair
(Millions of Dollars)		Amount		Value		Amount		Value
Preferred Stock Not
	Subject to Mandatory
	Redemption	$	155.6	$	153.1	$	116.2	$	105.1
Long-Term Debt			7,619.7		8,302.7		4,950.7		5,517.0
Rate Reduction Bonds			160.1		163.6		112.3		116.8


		As of June 30, 2012
		CL&P				NSTAR Electric				PSNH				WMECO
		Carrying		Fair		Carrying		Fair		Carrying		Fair		Carrying		Fair
(Millions of Dollars)		Amount		Value		Amount		Value		Amount		Value		Amount		Value
Preferred Stock Not
	Subject to Mandatory
	Redemption	$	116.2	$	110.1	$	43.0	$	43.0	$	-	$	-	$	-	$	-
Long-Term Debt			2,584.0		3,029.3		1,603.4		1,842.0		997.8		1,089.0		499.6		550.1
Rate Reduction Bonds			-		-		84.3		85.8		57.7		59.2		18.1		18.6

		As of December 31, 2011
		CL&P				NSTAR Electric ⁽¹⁾				PSNH				WMECO
		Carrying		Fair		Carrying		Fair		Carrying		Fair		Carrying		Fair
(Millions of Dollars)		Amount		Value		Amount		Value		Amount		Value		Amount		Value
Preferred Stock Not
	Subject to Mandatory
	Redemption	$	116.2	$	105.1	$	43.0	$	41.2	$	-	$	-	$	-	$	-
Long-Term Debt			2,587.8		2,987.1		1,605.1		1,816.1		999.5		1,075.2		501.1		539.8
Rate Reduction Bonds			-		-		127.9		131.2		85.4		88.8		26.9		28.1

⁽¹⁾

NSTAR Electric amounts are not included in NU consolidated as of December 31, 2011.

Derivative Instruments: NU, including CL&P, NSTAR Electric, 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."

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, NSTAR Electric, PSNH and WMECO common stock authorized and issued as of June 30, 2012 and December 31, 2011 and the respective par values:


	Shares
	Authorized				Issued
	Per Share		As of June 30, 2012
	Par Value		and December 31, 2011		As of June 30, 2012		As of December 31, 2011
NU	$	5		380,000,000		332,450,199		196,052,770
CL&P	$	10		24,500,000		6,035,205		6,035,205
NSTAR Electric	$	1		100,000,000		100		100
PSNH	$	1		100,000,000		301		301
WMECO	$	25		1,072,471		434,653		434,653

As a result of the merger with NSTAR on April 10, 2012, NU issued approximately 136 million common shares to the NSTAR shareholders.

As of June 30, 2012 and December 31, 2011, 18,674,189 and 18,894,078 NU common shares were held as treasury shares, respectively.

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
		June 30, 2012								June 30, 2011
								Noncontrolling								Noncontrolling
		Common						Interest -		Common						Interest -
		Shareholders'		Noncontrolling		Total		Preferred Stock		Shareholders'		Noncontrolling		Total		Preferred Stock
(Millions of Dollars)		Equity		Interest		Equity		of Subsidiaries		Equity		Interest		Equity		of Subsidiaries
Balance as of Beginning
	of Period	$	4,068.3	$	3.4	$	4,071.7	$	116.2	$	3,885.3	$	1.5	$	3,886.8	$	116.2
Net Income			46.2		-		46.2		-		78.7		-		78.7		-
Purchase Price of NSTAR ⁽¹⁾			5,038.3		-		5,038.3		-		-		-		-		-
Other Impacts of Merger with
	NSTAR ⁽²⁾		3.4		(3.4)		-		39.4		-		-		-		-
Dividends on Common Shares			(107.6)		-		(107.6)		-		(48.9)		-		(48.9)		-
Dividends on Preferred Stock			(1.9)		-		(1.9)		(1.9)		(1.4)		-		(1.4)		(1.4)
Issuance of Common Shares			5.2		-		5.2		-		-		-		-		-
Contributions to NPT			-		-		-		-		-		0.3		0.3		-
Other Transactions, Net			13.3		-		13.3		-		6.0		-		6.0		-
Net Income Attributable to
	Noncontrolling Interests		-		-		-		1.9		-		-		-		1.4
Other Comprehensive Income			2.4		-		2.4		-		(4.6)		-		(4.6)		-
Balance as of End of Period		$	9,067.6	$	-	$	9,067.6	$	155.6	$	3,915.1	$	1.8	$	3,916.9	$	116.2

		For the Six Months Ended
		June 30, 2012								June 30, 2011
								Noncontrolling								Noncontrolling
		Common						Interest -		Common						Interest -
		Shareholders'		Noncontrolling		Total		Preferred Stock		Shareholders'		Noncontrolling		Total		Preferred Stock
(Millions of Dollars)		Equity		Interest		Equity		of Subsidiaries		Equity		Interest		Equity		of Subsidiaries
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			147.0		-		147.0		-		194.3		-		194.3		-
Purchase Price of NSTAR ⁽¹⁾			5,038.3		-		5,038.3		-		-		-		-		-
Other Impacts of Merger with
	NSTAR ⁽²⁾		3.4		(3.4)		-		39.4		-		-		-		-
Dividends on Common Shares			(160.2)		-		(160.2)		-		(97.7)		-		(97.7)		-
Dividends on Preferred Stock			(3.3)		-		(3.3)		(3.3)		(2.8)		-		(2.8)		(2.8)
Issuance of Common Shares			11.4		-		11.4		-		4.2		-		4.2		-
Contributions to NPT			-		0.3		0.3		-		-		0.3		0.3		-
Other Transactions, Net			14.1		-		14.1		-		8.3		-		8.3		-
Net Income Attributable to
	Noncontrolling Interests		(0.1)		0.1		-		3.3		-		-		-		2.8
Other Comprehensive Income			4.3		-		4.3		-		(2.4)		-		(2.4)		-
Balance as of End of Period		$	9,067.6	$	-	$	9,067.6	$	155.6	$	3,915.1	$	1.8	$	3,916.9	$	116.2

⁽¹⁾

On April 10, 2012, in connection with the consummation of the merger with NSTAR, NU issued approximately 136 million common shares to the NSTAR shareholders. See Note 2, "Merger of NU and NSTAR," for further information.

⁽²⁾

The preferred stock of NSTAR Electric is not subject to mandatory redemption and has been presented as a noncontrolling interest in NSTAR Electric in the accompanying unaudited condensed consolidated financial statements of NU. In addition, upon completion of the merger, an NSTAR subsidiary that held 25 percent of NPT was merged into NUTV, resulting in NUTV owning 100 percent of NPT. Accordingly, the noncontrolling interest balance was eliminated and 100 percent ownership of NPT is reflected in Common Shareholders' Equity as of June 30, 2012.

For the three and six months ended June 30, 2012, there was no change in NU parent's 100 percent ownership of the common equity of CL&P.

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. For the three and six months ended June 30, 2012, there were 17,065 and 8,533, respectively, share awards excluded from the computation as these awards were antidilutive. There were no antidilutive share awards outstanding for the three and six months ended June 30, 2011.


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

		For the Three Months Ended				For the Six Months Ended
(Millions of Dollars, except share information)		June 30, 2012		June 30, 2011		June 30, 2012		June 30, 2011
Net Income Attributable to Controlling Interest		$	44.3	$	77.3	$	143.6	$	191.4

Weighted Average Common Shares Outstanding:
	Basic		301,047,753		177,347,374		239,551,735		177,267,791
	Dilutive Effect		769,131		279,618		575,434		286,204
	Diluted		301,816,884		177,626,992		240,127,169		177,553,995
Basic and Diluted EPS		$	0.15	$	0.44	$	0.60	$	1.08

On April 10, 2012, NU issued approximately 136 million common shares as a result of the merger with NSTAR, which are reflected in weighted average common shares outstanding as of June 30, 2012.

RSUs and performance shares are included in basic weighted average common shares outstanding as of the date that all necessary vesting conditions have been satisfied. The dilutive effect of unvested RSUs and performance shares is calculated using the treasury stock method. Assumed proceeds of 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 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 operations 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 used for investments in plant included in the segment information below are cash capital expenditures that do not include amounts incurred but not paid, cost of removal, AFUDC related to equity funds, and the capitalized portions of pension and PBOP expense or income.

The Regulated companies' segments include the electric distribution segment, the natural gas distribution segment and the electric transmission segment. The electric distribution segment includes the generation activities of PSNH and WMECO. The Regulated companies' segments represented substantially all of NU's total consolidated revenues for the three and six month periods ended June 30, 2012 and 2011.

Other operations in the tables below primarily consists of 1) the results of NU parent and NSTAR LLC, which includes other income related to the equity in earnings of NU parent and NSTAR LLC's subsidiaries, respectively, and interest income from the NU Money Pool, which are eliminated in consolidation, and interest income and expense related to the cash and debt of NU parent and NSTAR LLC, respectively, 2) the revenues and expenses of NU's service companies, most of which are eliminated in consolidation, 3) the operations of CYAPC and YAEC, and 4) the results of other subsidiaries, which are comprised of NU Enterprises, NSTAR Communications, Inc., RRR (a real estate subsidiary), the non-energy-related subsidiaries of Yankee and the remaining operations of HWP.

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.

As discussed in Note 1A, "Summary of Significant Accounting Policies – Basis of Presentation," certain reclassifications of prior period data were made in the accompanying unaudited condensed consolidated statements of income for NU. Accordingly, the corresponding items of segment information have been recast for all prior periods for comparative purposes.

NU's segment information for the three and six months ended June 30, 2012 and 2011, with the distribution segment segregated between electric and natural gas, is as follows:


		For the Three Months Ended June 30, 2012
		Regulated Companies
		Distribution
(Millions of Dollars)		Electric		Natural Gas		Transmission		Other		Eliminations		Total
Operating Revenues		$	1,229.9	$	133.5	$	228.7	$	230.2	$	(193.6)	$	1,628.7
Depreciation and Amortization			(153.3)		(12.4)		(28.6)		(17.7)		1.2		(210.8)
Other Operating Expenses			(1,004.8)		(115.8)		(65.5)		(263.0)		190.7		(1,258.4)
Operating Income/(Loss)			71.8		5.3		134.6		(50.5)		(1.7)		159.5
Interest Expense			(44.8)		(8.8)		(26.2)		(11.1)		1.9		(89.0)
Interest Income			1.0		-		0.1		1.4		(1.4)		1.1
Other Income/(Loss), Net			(0.2)		0.1		0.7		117.9		(117.8)		0.7
Income Tax (Expense)/Benefit			(6.9)		1.3		(44.8)		25.0		(0.7)		(26.1)
Net Income/(Loss)			20.9		(2.1)		64.4		82.7		(119.7)		46.2
Net Income Attributable
	to Noncontrolling Interests		(1.2)		-		(0.7)		-		-		(1.9)
Net Income/(Loss) Attributable
	to Controlling Interest	$	19.7	$	(2.1)	$	63.7	$	82.7	$	(119.7)	$	44.3


		For the Six Months Ended June 30, 2012
		Regulated Companies
		Distribution
(Millions of Dollars)		Electric		Natural Gas		Transmission		Other		Eliminations		Total
Operating Revenues		$	2,016.0	$	272.5	$	391.6	$	363.4	$	(315.2)	$	2,728.3
Depreciation and Amortization			(225.4)		(20.1)		(49.8)		(21.6)		1.5		(315.4)
Other Operating Expenses			(1,627.0)		(218.0)		(113.2)		(397.8)		317.0		(2,039.0)
Operating Income/(Loss)			163.6		34.4		228.6		(56.0)		3.3		373.9
Interest Expense			(77.9)		(14.3)		(45.8)		(20.4)		2.9		(155.5)
Interest Income			2.1		-		0.3		2.6		(2.7)		2.3
Other Income, Net			4.2		0.1		3.9		240.5		(240.4)		8.3
Income Tax (Expense)/Benefit			(28.3)		(7.6)		(75.6)		31.0		(1.5)		(82.0)
Net Income			63.7		12.6		111.4		197.7		(238.4)		147.0
Net Income Attributable
	to Noncontrolling Interests		(2.0)		-		(1.4)		-		-		(3.4)
Net Income Attributable
	to Controlling Interest	$	61.7	$	12.6	$	110.0	$	197.7	$	(238.4)	$	143.6
Cash Flows for Total
	Investments in Plant	$	305.7	$	59.7	$	297.2	$	27.8	$	-	$	690.4


		For the Three Months Ended June 30, 2011
		Regulated Companies
		Distribution
(Millions of Dollars)		Electric		Natural Gas		Transmission		Other		Eliminations		Total
Operating Revenues		$	794.4	$	78.4	$	152.1	$	130.8	$	(108.2)	$	1,047.5
Depreciation and Amortization			(76.5)		(6.3)		(21.4)		(3.9)		0.4		(107.7)
Other Operating Expenses			(633.2)		(65.7)		(44.2)		(126.8)		108.2		(761.7)
Operating Income			84.7		6.4		86.5		0.1		0.4		178.1
Interest Expense			(31.0)		(5.2)		(19.1)		(8.5)		1.6		(62.2)
Interest Income			0.6		-		0.1		1.5		(1.5)		0.7
Other Income, Net			2.8		0.4		3.3		85.4		(85.3)		6.6
Income Tax (Expense)/Benefit			(17.2)		(0.4)		(28.0)		2.0		(0.9)		(44.5)
Net Income			39.9		1.2		42.8		80.5		(85.7)		78.7
Net Income Attributable
	to Noncontrolling Interests		(0.8)		-		(0.6)		-		-		(1.4)
Net Income Attributable
	to Controlling Interest	$	39.1	$	1.2	$	42.2	$	80.5	$	(85.7)	$	77.3


		For the Six Months Ended June 30, 2011
		Regulated Companies
		Distribution
(Millions of Dollars)		Electric		Natural Gas		Transmission		Other		Eliminations		Total
Operating Revenues		$	1,686.0	$	258.6	$	310.3	$	261.2	$	(233.4)	$	2,282.7
Depreciation and Amortization			(167.5)		(13.1)		(44.8)		(8.3)		1.3		(232.4)
Other Operating Expenses			(1,326.3)		(199.2)		(92.5)		(261.7)		234.9		(1,644.8)
Operating Income/(Loss)			192.2		46.3		173.0		(8.8)		2.8		405.5
Interest Expense			(60.6)		(10.4)		(35.4)		(17.1)		2.7		(120.8)
Interest Income			1.9		-		0.3		2.7		(2.8)		2.1
Other Income, Net			6.6		0.8		8.1		234.9		(234.8)		15.6
Income Tax (Expense)/Benefit			(43.6)		(13.0)		(57.9)		7.8		(1.4)		(108.1)
Net Income			96.5		23.7		88.1		219.5		(233.5)		194.3
Net Income Attributable
	to Noncontrolling Interests		(1.7)		-		(1.2)		-		-		(2.9)
Net Income Attributable
	to Controlling Interest	$	94.8	$	23.7	$	86.9	$	219.5	$	(233.5)	$	191.4
Cash Flows Used for
	Investments in Plant	$	251.1	$	45.4	$	146.0	$	26.0	$	-	$	468.5


The information related to the distribution and transmission segments for CL&P, PSNH and WMECO for the three and six months
ended June 30, 2012 and 2011 is as follows:

	For the Three Months Ended
	June 30, 2012						June 30, 2011
(Millions of Dollars)	Distribution		Transmission		Total		Distribution		Transmission		Total
CL&P
Operating Revenues	$	442.2	$	119.9	$	562.1	$	489.9	$	118.1	$	608.0
Net Income/(Loss)		(27.2)		34.1		6.9		19.8		32.8		52.6
PSNH
Operating Revenues		229.4		25.7		255.1		219.1		21.1		240.2
Net Income		14.7		6.5		21.2		16.0		5.7		21.7
WMECO
Operating Revenues		81.6		25.2		106.8		85.4		13.0		98.4
Net Income		1.4		9.7		11.1		4.0		4.2		8.2


	For the Six Months Ended
	June 30, 2012						June 30, 2011
(Millions of Dollars)	Distribution		Transmission		Total		Distribution		Transmission		Total
CL&P
Operating Revenues	$	916.9	$	237.2	$	1,154.1	$	1,039.8	$	241.9	$	1,281.7
Net Income/(Loss)		(5.5)		66.4		60.9		49.2		67.8		117.0
PSNH
Operating Revenues		448.9		49.2		498.1		467.0		42.7		509.7
Net Income		29.9		12.6		42.5		37.5		11.6		49.1
WMECO
Operating Revenues		173.6		47.3		220.9		179.3		25.8		205.1
Net Income		7.5		17.8		25.3		9.7		8.4		18.1

The following tables summarize NU, CL&P, PSNH and WMECO's segmented total assets:


	Regulated Companies
NU	Distribution
(Millions of Dollars)	Electric		Natural Gas		Transmission		Other		Eliminations		Total
As of June 30, 2012	$	15,161.3	$	2,432.7	$	5,327.7	$	20,614.1	$	(16,029.5)	$	27,506.3
As of December 31, 2011		9,653.1		1,511.3		3,792.9		6,618.0		(5,928.2)		15,647.1

	As of June 30, 2012						As of December 31, 2011
(Millions of Dollars)	Distribution		Transmission		Total		Distribution		Transmission		Total
CL&P	$	6,137.5	$	2,697.9	$	8,835.4	$	6,161.0	$	2,630.4	$	8,791.4
PSNH		2,451.5		585.3		3,036.8		2,551.3		565.2		3,116.5
WMECO		943.3		690.2		1,633.5		942.6		560.3		1,502.9

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, CL&P and NSTAR Electric hold variable interests in variable interest entities (VIEs) through agreements with certain entities that own single renewable energy or peaking generation power plants and with other independent power producers. NU, CL&P and NSTAR Electric do not control the activities that are economically significant to these VIEs or provide financial or other support to these VIEs. Therefore, NU, CL&P and NSTAR Electric do not consolidate any power plant VIEs.

17.

SUBSEQUENT EVENTS

On July 25, 2012, NU, NSTAR LLC, NSTAR Gas, CL&P, PSNH, WMECO, and Yankee Gas jointly entered into a five-year $1.15 billion revolving credit facility. The new facility replaced (1) the NSTAR LLC revolving credit facility of $175 million that served to backstop a commercial paper program utilized by NSTAR LLC and was scheduled to expire on December 31, 2012, (2) the NSTAR Gas revolving credit facility of $75 million that expired on June 8, 2012, and (3) the CL&P, PSNH, WMECO, and Yankee Gas joint three-year $400 million and NU parent three-year $500 million unsecured revolving credit facilities that were scheduled to expire on September 24, 2013. The new facility expires on July 25, 2017. Management expects the new facility to be used primarily to backstop the $1.15 billion commercial paper program at NU, which commenced July 25, 2012.

On July 25, 2012, NSTAR Electric entered into a five-year $450 million revolving credit facility. This new facility serves to backstop NSTAR Electric’s existing $450 million commercial paper program. This new facility replaced a prior $450 million NSTAR Electric revolving credit facility that was scheduled to expire on December 31, 2012.

NORTHEAST UTILITIES AND SUBSIDIARIES

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

The following discussion and analysis should be read in conjunction with our unaudited condensed consolidated financial statements and related combined notes included in this combined Quarterly Report on Form 10-Q, the NU First Quarter 2012 Quarterly Report on Form 10-Q, the NSTAR Electric First Quarter 2012 Quarterly Report on Form 10-Q, the NU 2011 Form 10-K, the NSTAR 2011 Form 10-K, and the NSTAR Electric 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, including NSTAR LLC and its subsidiaries for periods beginning after April 10, 2012. All per share amounts are reported on a diluted basis.

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

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

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

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 outcome of our merger with NSTAR, and

other presently unknown or unforeseen factors.

Other risk factors are detailed in NU’s 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 us to predict all of such factors, nor can we assess the impact of each such factor on the business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statements. For more information, see Item 1A , Risk Factors, included in this Quarterly Report on Form 10-Q, and in NU’s 2011 Form

10-K, NSTAR’s 2011 Form 10-K, and NSTAR Electric’s 2011 Form 10-K. This Quarterly Report on Form 10-Q, NU’s 2011 Form 10-K, NSTAR’s 2011 Form 10-K, and NSTAR Electric’s 2011 Form 10-K also describe material contingencies and critical accounting policies and estimates in the accompanying Management's Discussion and Analysis and Combined Notes to Condensed 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 merger. Pursuant to the terms and conditions of the Agreement and Plan of Merger, as amended, the "Merger Agreement," NSTAR merged into NSTAR LLC, becoming a wholly-owned subsidiary of NU. Unless otherwise noted, NSTAR LLC and its subsidiaries' results are included from the date of merger, April 10, 2012, through June 30, 2012 throughout this Management's Discussion and Analysis .

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

Executive Summary

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

Results:

We earned $44.3 million, or $0.15 per share, in the second quarter of 2012, and $143.6 million, or $0.60 per share, in the first half of 2012, compared with $77.3 million, or $0.44 per share, in the second quarter of 2011 and $191.4 million, or $1.08 per share, in the first half of 2011. Excluding merger and related settlement costs of $91.5 million, or $0.30 per share, we earned $135.8 million, or $0.45 per share, in the second quarter of 2012. Excluding merger and related settlement costs of $92.6 million, or $0.38 per share, we earned $236.2 million, or $0.98 per share, in the first half of 2012. The second quarter and first half 2012 earnings improved due primarily to the addition of NSTAR LLC and its subsidiaries' business operations effective April 10, 2012 as well as higher transmission segment earnings as a result of an increased investment in the transmission infrastructure.

The addition of NSTAR LLC and its subsidiaries’ business operations effective April 10, 2012 provided an earnings contribution of $35.9 million in the second quarter and first half of 2012. However, as a result of the impact of the issuance of 136 million common shares to close the merger, there was no contribution to EPS in the second quarter and first half of 2012.

Our transmission segment earned $63.7 million, or $0.21 per share, in the second quarter of 2012 and $110 million, or $0.45 per share, in the first half of 2012, compared with $42.2 million, or $0.24 per share, in the second quarter of 2011 and $86.9 million, or $0.49 per share, in the first half of 2011.

Our electric distribution segment earned $19.7 million, or $0.07 per share, in the second quarter of 2012 and $61.7 million, or $0.26 per share, in the first half of 2012, compared with earnings of $39.1 million, or $0.22 per share, in the second quarter of 2011, and $94.8 million, or $0.54 per share, in the first half of 2011. Second quarter and first half 2012 results reflect $50.8 million of after-tax merger and related settlement costs.

Our natural gas distribution segment recorded net expenses of $2.1 million, or $0.01 per share, in the second quarter of 2012 and earned $12.6 million, or $0.05 per share, in the first half of 2012, compared with earnings of $1.2 million, or $0.01 per share, in the second quarter of 2011 and $23.7 million, or $0.13 per share, in the first half of 2011. Second quarter and first half 2012 results reflect $2.1 million of after-tax merger and related settlement costs.

NU parent and other companies recorded net expenses of $37 million, or $0.12 per share, in the second quarter of 2012 and $40.7 million, or $0.16 per share, in the first half of 2012, compared with net expenses of $5.2 million, or $0.03 per share, in the second quarter of 2011 and $14 million, or $0.08 per share, in the first half of 2011. Second quarter and first half 2012 results reflect $38.6 million and $39.7 million, respectively, of after-tax merger and related settlement costs.

Legislative, Regulatory and Other Items:

On June 4, 2012, the SJC vacated the DPU's order reducing NSTAR Electric's distribution rates by an amount equal to the increase in NSTAR Electric’s Basic Service bad debt charge-offs, and remanded the matter to the DPU for a "statement of reasons, including subsidiary findings, of its conclusion of law and relevant facts." The continued uncertainty of the outcome leaves us unable to conclude if the $28 million fully reserved amount recognized in the first quarter of 2012 is probable of recovery and therefore will continue to maintain a reserve on this amount until the ultimate outcome is determined by the DPU.

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

On July 9, 2012, consistent with the terms of the Connecticut settlement agreement among NU, NSTAR, and various Connecticut state agencies, CL&P filed with PURA for approval to spend up to $300 million to improve the resiliency of the CL&P electric distribution system.

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

Liquidity:

Cash and cash equivalents totaled $28.5 million as of June 30, 2012, compared with $6.6 million as of December 31, 2011, while cash capital expenditures totaled $690.4 million in the first half of 2012, compared with $468.5 million in the first half of 2011.

Cash flows provided by operating activities totaled $284 million in the first half of 2012, compared with $652.4 million in the first half of 2011 (amounts are net of RRB payments). The reduced cash flows were due primarily to approximately $176.8 million of first half 2012 cash disbursements for storm costs primarily related to Tropical Storm Irene and the October 2011 snowstorm, $133.4 million of 2012 Pension Plan cash contributions, a total of $46 million of bill credits in the second quarter of 2012 to customers of CL&P, NSTAR Electric, NSTAR Gas and WMECO related to the Connecticut and Massachusetts settlement agreements, $27 million in bill credits provided to CL&P residential customers in February 2012 related to the October 2011 snowstorm, and $29.1 million of transaction cost payments related to the close of the merger.

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

On July 25, 2012, NU, NSTAR LLC, NSTAR Gas, CL&P, PSNH, WMECO, and Yankee Gas jointly entered into a five-year $1.15 billion revolving credit facility and NSTAR Electric entered into a five-year $450 million revolving credit facility. The first facility replaced (1) the NSTAR LLC revolving credit facility of $175 million that served to backstop a commercial paper program utilized by NSTAR LLC and was scheduled to expire on December 31, 2012, (2) the NSTAR Gas revolving credit facility of $75 million that expired on June 8, 2012, and (3) the CL&P, PSNH, WMECO, and Yankee Gas joint three-year $400 million and NU parent three-year $500 million unsecured revolving credit facilities that were scheduled to expire on September 24, 2013. The NSTAR Electric facility replaced a prior $450 million revolving credit facility that was scheduled to expire on December 31, 2012. The new facilities expire on July 25, 2017. We expect the new facilities to be used primarily to backstop NU’s $1.15 billion commercial paper program, which commenced July 25, 2012, and NSTAR Electric’s existing $450 million commercial paper program.

On July 17, 2012, our Board of Trustees approved a common dividend payment of $0.343 per share, payable September 28, 2012, to our shareholders of record as of August 31, 2012.

Overview

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


	For the Three Months Ended June 30,								For the Six Months Ended June 30,
(Millions of Dollars, Except	2012 ⁽¹⁾				2011				2012 ⁽¹⁾				2011
Per Share Amounts)	Amount		Per Share		Amount		Per Share		Amount		Per Share		Amount		Per Share
Net Income Attributable to Controlling Interest (GAAP)	$	44.3	$	0.15	$	77.3	$	0.44	$	143.6	$	0.60	$	191.4	$	1.08
Regulated Companies	$	134.2	$	0.44	$	82.5	$	0.47	$	237.2	$	0.98	$	205.4	$	1.16
NU Parent and Other Companies		1.6		0.01		(4.0)		(0.03)		(1.0)		-		(4.5)		(0.03)
Non-GAAP Earnings		135.8		0.45		78.5		0.44		236.2		0.98		200.9		1.13
Merger and Related Costs (after-tax)		(91.5)		(0.30)		(1.2)		-		(92.6)		(0.38)		(9.5)		(0.05)
Net Income Attributable to Controlling Interest (GAAP)	$	44.3	$	0.15	$	77.3	$	0.44	$	143.6	$	0.60	$	191.4	$	1.08

⁽¹⁾

Results include the operations of NSTAR LLC and its subsidiaries from the date of merger, April 10, 2012, through June 30, 2012.

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

Transaction and integration-related costs of $21.1 million at NU parent related to investment advisory fees, attorney fees, and consulting costs;

Change in control costs and other compensation costs of $11.4 million at NU parent and NSTAR LLC and its subsidiaries;

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

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

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

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

Excluding the impact of merger and related settlement costs, earnings improved in the second quarter of 2012 due primarily to the addition of NSTAR LLC and its subsidiaries' business operations effective April 10, 2012, as well as higher transmission segment earnings as a result of an increased investment in the transmission infrastructure. The earnings contribution of $35.9 million in the second quarter of 2012 from inclusion of NSTAR LLC and its subsidiaries' business operations were impacted by the issuance of 136 million common shares to close the merger. This resulted in no contribution to second quarter 2012 EPS. Offsetting these favorable earnings impacts were lower retail electric sales in the second quarter of 2012, as compared to the same period in 2011, higher operations and maintenance expenses, including higher pension expense, vegetation management costs and storm restoration costs, and higher interest expense as a result of new debt issued in September 2011.

Excluding the impact of merger and related settlement costs, earnings improved in the first half of 2012 due primarily to the addition of NSTAR LLC and its subsidiaries' business operations effective April 10, 2012 as well as higher transmission segment earnings. The earnings contribution of $35.9 million in the first half of 2012 from NSTAR LLC and its subsidiaries resulted in no contribution to first half 2012 EPS as a result of the impact of the issuance of 136 million common shares to close the merger. Offsetting these favorable impacts were lower retail electric sales due primarily to much milder weather in the first quarter of 2012, compared with the same period in 2011, higher pension expense, increased costs in system maintenance and vegetation management, and higher interest expense.

Regulated Companies: Our Regulated companies consist of the electric distribution, natural gas distribution, and transmission segments, with the PSNH and WMECO generation activities included in the electric distribution segment. A summary of our segment earnings by operating company for the second quarter and first half of 2012 and 2011 is as follows:


	For the Three Months Ended June 30,				For the Six Months Ended June 30,
(Millions of Dollars)	2012		2011		2012		2011
CL&P Transmission	$	33.5	$	32.2	$	65.3	$	66.6
NSTAR Electric Transmission ⁽¹⁾		13.6		N/A		13.6		N/A
PSNH Transmission		6.5		5.6		12.6		11.6
WMECO Transmission		9.7		4.2		17.8		8.4
NPT		0.4		0.2		0.7		0.3
Total Transmission		63.7		42.2		110.0		86.9
CL&P Distribution		10.5		19.1		31.3		47.6
NSTAR Electric Distribution ⁽¹⁾		42.0		N/A		42.0		N/A
PSNH Distribution		14.8		16.0		29.9		37.5
WMECO Distribution		3.2		4.0		9.3		9.7
Total Electric Distribution		70.5		39.1		112.5		94.8
NSTAR Gas ⁽¹⁾		0.1		N/A		0.1		N/A
Yankee Gas		(0.1)		1.2		14.6		23.7
Total Natural Gas Distribution		-		1.2		14.7		23.7
Total Regulated Companies		134.2		82.5		237.2		205.4
Merger and Related Costs (after-tax)		(52.9)		-		(52.9)		-
Net Income – Regulated Companies	$	81.3	$	82.5	$	184.3	$	205.4

⁽¹⁾

Results include the operations of NSTAR Electric and NSTAR Gas from the date of merger, April 10, 2012, through June 30, 2012.

The higher second quarter and first half of 2012 transmission segment earnings as compared to the same periods in 2011 were due primarily to the addition of the NSTAR Electric transmission business results and a higher level of investment in transmission infrastructure, including GSRP, which is under construction in western Massachusetts and northern Connecticut.

Excluding $38.4 million of after-tax merger and related settlement costs, which were customer bill credits and the $40 million pre-tax storm cost reserve, CL&P’s second quarter 2012 distribution segment earnings were $8.6 million lower than the same period of 2011 due primarily to higher operations and maintenance expenses, including higher pension expense, higher vegetation management costs and higher storm restoration costs and lower retail revenue. Partially offsetting these costs was the favorable impact of the 2010 distribution rate case decision related to the additional increase to annualized rates that was effective July 1, 2011.

Excluding the $38.4 million of after-tax merger and related settlement costs, CL&P’s first half 2012 distribution segment earnings were $16.3 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 3.8 percent decrease in first half 2012 retail electric sales for the comparative period in 2011. In addition, CL&P had higher pension expense and an

increase in system maintenance and vegetation management costs, partially offset by the favorable impacts of the 2010 distribution rate case decision related to the additional increase to annualized rates that was effective July 1, 2011. For the twelve months ended June 30, 2012, CL&P’s distribution segment regulatory ROE was 8 percent.

Excluding $10.6 million of after-tax merger and related settlement costs, primarily related to customer bill credits, NSTAR Electric’s distribution segment earned $42 million in the second quarter of 2012. For further information regarding NSTAR Electric’s second quarter and first half 2012 earnings, as compared the same periods in 2011, see "Results of Operations – NSTAR Electric Company and Subsidiaries – Earnings Summary" in this Management's Discussion and Analysis of Financial Condition and Results of Operations.

PSNH’s second quarter 2012 distribution segment earnings were $1.2 million lower than the same period of 2011 due primarily to higher income tax expense and lower retail revenue.

PSNH’s first half 2012 distribution segment earnings were $7.6 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 1.9 percent decrease in first half 2012 retail electric sales for the comparative period in 2011. In addition, PSNH had higher operating expenses, including depreciation and property taxes, and higher income tax expense, partially offset by lower storm restoration costs, and lower maintenance expense. For the twelve months ended June 30, 2012, PSNH’s distribution segment regulatory ROE was 8.7 percent.

Excluding $1.8 million of after-tax customer bill credits, WMECO’s second quarter 2012 distribution segment earnings were $0.8 million lower than the same period of 2011 due primarily to higher operations and maintenance expenses, including lower capitalized costs and higher vegetation management costs, as well as higher interest expense. Partially offsetting these costs were lower storm costs and lower uncollectible expense.

Excluding the $1.8 million of after-tax customer bill credits, WMECO’s first half 2012 distribution segment earnings were $0.4 million lower than the same period of 2011 due primarily to higher depreciation and amortization expense, higher income tax expense, higher interest expense, higher vegetation management costs and higher employee health care expense. Partially offsetting these costs were lower storm costs and lower uncollectible expense. As WMECO’s distribution rates are "decoupled" from the actual consumption of electricity by customers, 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 June 30, 2012, WMECO’s distribution segment regulatory ROE was 8.7 percent.

Excluding $2.1 million of after-tax merger and related settlement costs, primarily related to customer bill credits, NSTAR Gas earned $0.1 million in the second quarter of 2012.

Yankee Gas’ second quarter 2012 earnings were $1.3 million lower than the same period of 2011 due primarily to a 5 percent decrease in total firm natural gas sales and higher depreciation and property tax expense. These costs were partially offset by lower operations and maintenance costs.

Yankee Gas’ first half 2012 earnings were $9.1 million lower than the same period of 2011 due primarily to a 10.7 percent decrease in total firm natural gas sales, which was primarily the result of warmer than normal weather in the first quarter of 2012 as compared to colder than normal weather in the first quarter of 2011, and higher property tax and depreciation expense. These costs were partially offset by lower operations and maintenance costs. For the twelve months ended June 30, 2012, Yankee Gas’ regulatory ROE was 6.6 percent.

For the distribution segment of our Regulated companies, a summary of NU retail electric GWh sales and percentage changes, as well as changes in CL&P, NSTAR Electric, PSNH and WMECO retail electric GWh sales, and NU firm natural gas sales and percentage changes in million cubic feet for the second quarter and first half of 2012, as compared to the same periods in 2011, on an actual and weather normalized basis (using a 30-year average), is as follows:


	For the Three Months Ended June 30, 2012 Compared to 2011			For the Six Months Ended June 30, 2012 Compared to 2011
	Sales (GWh)		Percentage	Sales (GWh)		Percentage
NU - Electric	2012 ⁽¹⁾	2011	Increase	2012 ⁽¹⁾	2011	Increase
Residential	4,636	3,228	43.6%	8,423	7,351	14.6%
Commercial	6,615	3,534	87.2%	9,996	7,007	42.7%
Industrial	1,490	1,131	31.7%	2,505	2,153	16.3%
Other	95	73	28.5%	182	160	13.7%
Total	12,836	7,966	61.1%	21,106	16,671	26.6%

⁽¹⁾

NU total retail electric sales results include the sales of NSTAR Electric from the date of merger, April 10, 2012, through June 30, 2012.


	For the Three Months Ended June 30, 2012 Compared to 2011				For the Six Months Ended June 30, 2012 Compared to 2011
	CL&P	NSTAR Electric ⁽²⁾	PSNH	WMECO	CL&P	NSTAR Electric ⁽²⁾	PSNH	WMECO
Electric	Percentage Increase/ (Decrease)	Percentage Decrease	Percentage Increase/ (Decrease)	Percentage Increase/ (Decrease)	Percentage Increase/ (Decrease)	Percentage Decrease	Percentage Increase/ (Decrease)	Percentage Increase/ (Decrease)
Residential	(2.3)%	(1.3)%	(1.9)%	(2.2)%	(6.2)%	(3.1)%	(3.3)%	(5.5)%
Commercial	(1.2)%	(0.9)%	(2.1)%	1.7 %	(2.4)%	(2.9)%	(1.7)%	1.3 %
Industrial	1.3%	(1.9)%	1.6 %	0.1 %	0.3 %	(4.4)%	1.1 %	(1.3)%
Other	2.5%	(37.4)%	(1.4)%	5.7 %	2.4 %	(17.3)%	0.3 %	(6.4)%
Total	(1.3)%	(1.3)%	(1.3)%	(0.1)%	(3.8)%	(3.2)%	(1.9)%	(2.1)%

⁽²⁾

Results for NSTAR Electric represent its standalone retail electric sales for the three and six months ended June 30, 2012 and 2011.


	For the Three Months Ended June 30, 2012 Compared to 2011			For the Six Months Ended June 30, 2012 Compared to 2011
NU – Firm Natural Gas	Sales (million cubic feet)		Percentage	Sales (million cubic feet)		Percentage
	2012 ⁽³⁾	2011	Increase	2012 ⁽³⁾	2011	Increase
Residential	4,000	2,014	98.6%	9,375	8,794	6.6%
Commercial	6,155	2,775	121.8%	12,536	10,399	20.6%
Industrial	4,732	3,691	28.2%	9,795	8,671	13.0%
Total	14,887	8,480	75.6%	31,706	27,864	13.8%
Total, Net of Special Contracts ⁽⁴⁾	13,502	6,450	109.3%	28,246	23,390	20.8%

⁽³⁾

NU firm natural gas results include the sales of NSTAR Gas from the date of merger, April 10, 2012, through June 30, 2012.

⁽⁴⁾

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.


	For the Three Months Ended June 30, 2012 Compared to 2011		For the Six Months Ended June 30, 2012 Compared to 2011
	Yankee Gas	NSTAR Gas ⁽⁵⁾	Yankee Gas	NSTAR Gas ⁽⁵⁾
Firm Natural Gas	Percentage Increase/ (Decrease)	Percentage Increase/ (Decrease)	Percentage Decrease	Percentage Decrease
Residential	(12.2)%	(16.7)%	(18.8)%	(21.4)%
Commercial	2.3 %	(4.4)%	(11.3)%	(11.5)%
Industrial	(6.6)%	14.4 %	(1.9)%	(2.4)%
Total	(5.0)%	(6.0)%	(10.7)%	(15.2)%
Total, Net of Special Contracts ⁽⁶⁾	3.4 %		(8.5)%

⁽⁵⁾

NSTAR Gas’ sales data for the three and six months ended June 30, 2012, as compared to the three and six months ended June 30, 2011, has been provided for comparative purposes only.

⁽⁶⁾

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

For the second quarter and first half of 2012, our consolidated retail electric sales were higher, as compared to the same periods in 2011, due to the inclusion of NSTAR Electric sales from the date of merger, April 10, 2012 through June 30, 2012.

For the second quarter of 2012, actual and weather normalized retail electric sales for each of our four electric companies decreased, as compared to the same period in 2011. Cooling degree days were 13.7 percent higher than last year in Connecticut and western Massachusetts, 4.1 percent lower than last year in the Boston area, and 1.7 percent lower than last year in New Hampshire. On a weather normalized basis, the average NU combined consolidated total retail electric sales decreased 1.9 percent in the second quarter of 2012, as compared to the second quarter of 2011, assuming NSTAR Electric had been part of the NU combined electric distribution system for all periods under consideration. We believe these decreases were due primarily to increased conservation efforts amongst all our customer classes and the continued installation of distributed generation at our commercial and industrial customers’ facilities.

For WMECO, the fluctuations in retail electric sales no longer impact earnings as the DPU approved a sales decoupling plan effective February 1, 2011. Under this decoupling plan, WMECO now has an established level of baseline distribution delivery service revenues of $125.6 million that it is able to recover. This effectively breaks the relationship between sales volume and revenues recognized. Weather normalized commercial sales for WMECO increased due in part to favorable customer growth.

For the first half of 2012, actual and weather normalized retail electric sales for each of our four electric companies decreased, as compared to the same period in 2011. Actual sales decreased 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. Heating degree days were 22 percent lower than last year in Connecticut and western Massachusetts, 19.8 percent lower than last year in the Boston area, and 17.8 percent lower than last year in New Hampshire. On a weather normalized basis , the average NU combined consolidated total retail electric sales decreased 1 percent in the first half of 2012, as compared to the first half of 2011, assuming NSTAR Electric had been part of the NU combined electric distribution system for all periods under consideration. Our first half 2012 sales were affected by the same influences impacting our second quarter 2012 retail electric sales.

For the second quarter and first half of 2012, our consolidated firm natural gas sales were higher, as compared to the same periods in 2011, due to the inclusion of NSTAR Gas sales from the date of merger, April 10, 2012 through June 30, 2012.

Our firm natural gas sales are subject to many of the same influences as our retail electric sales, but have benefitted from lower natural gas prices and customer growth across all three customer classes. In the first half of 2012, absent the NSTAR Gas sales impacts, actual sales decreased, as compared to the same period in 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. Heating degree days in the second quarter and first half of 2012, as compared to the same periods in 2011, were 15.5 percent and 22 percent lower in Connecticut, respectively. On a weather normalized basis, Yankee Gas’ first half 2012 sales increased due primarily to the migration of interruptible customers switching to firm service rates and the addition of gas-fired distributed generation in Yankee Gas’ service territory.

On a weather normalized basis, the average NU combined consolidated total firm natural gas sales decreased 0.4 percent in the second quarter of 2012, as compared to the second quarter of 2011, assuming NSTAR Gas had been part of the NU combined natural gas distribution system for all periods under consideration. Under the same assumptions, the average NU combined consolidated total firm natural gas sales increased 3.5 percent in the first half of 2012, as compared to the first half of 2011.

NU Parent and Other Companies: NU parent and other companies (which includes our competitive businesses held by NU Enterprises and, from April 10, 2012, NSTAR LLC) recorded net expenses of $37 million in the second quarter of 2012, compared with net expenses of $5.2 million in the second quarter of 2011. Excluding merger and related settlement costs of $38.6 million and $1.2 million in the second quarter of 2012 and 2011, respectively, NU parent and other companies recorded net income of $1.6 million and net expenses of $4 million, respectively. NU parent and other companies recorded net expenses of $40.7 million in the first half of 2012, compared with net expenses of $14 million in the first half of 2011. Excluding merger and related settlement costs of $39.7 million and $9.5 million in the first half of 2012 and 2011, respectively, NU parent and other companies recorded first half net expenses of $1 million in 2012 and $4.5 million in 2011. NU parent merger and related settlement costs primarily included fees paid to investment advisors and attorneys, a charge for the establishment of a fund to advance Connecticut energy goals related to the Connecticut settlement agreement, and change in control costs and other compensation costs. Excluding merger and related settlement costs, improved results were due primarily to lower interest costs and the addition of the business operations of NSTAR Communications, Inc., the wholly owned unregulated business of NSTAR LLC.

Liquidity

Consolidated: Cash and cash equivalents totaled $28.5 million as of June 30, 2012, compared with $6.6 million as of December 31, 2011.

On July 25, 2012, NU, NSTAR LLC, NSTAR Gas, CL&P, PSNH, WMECO, and Yankee Gas jointly entered into a five-year $1.15 billion revolving credit facility. The new facility replaced (1) the NSTAR LLC revolving credit facility of $175 million that served to backstop a commercial paper program utilized by NSTAR LLC and was scheduled to expire on December 31, 2012, (2) the NSTAR Gas revolving credit facility of $75 million that expired on June 8, 2012, and (3) the CL&P, PSNH, WMECO, and Yankee Gas joint three-year $400 million and NU parent three-year $500 million unsecured revolving credit facilities that were scheduled to expire on September 24, 2013. The new facility expires on July 25, 2017. We expect the new facility to be used primarily to backstop the $1.15 billion commercial paper program at NU, which commenced July 25, 2012.

On July 25, 2012, NSTAR Electric entered into a five-year $450 million revolving credit facility. This new facility serves to backstop NSTAR Electric’s existing $450 million commercial paper program. The new facility expires on July 25, 2017. This new facility replaced a prior $450 million NSTAR Electric revolving credit facility that was scheduled to expire on December 31, 2012.

CL&P has a separate five-year $300 million unsecured revolving credit facility that expires on March 26, 2017 and will remain outstanding. As of June 30, 2012, CL&P had $300 million in short-term borrowings outstanding under this credit facility. The weighted-average interest rate on these borrowings as of June 30, 2012 was 1.59 percent.

On July 31, 2012, the DPU approved NSTAR Electric's application for a new two-year financing plan that provides for the issuance of long-term debt securities in an aggregate amount not to exceed $600 million prior to December 31, 2013. NSTAR Electric intends to use the proceeds of such issuances for the payment of capital expenditures incurred for extensions, additions and improvements to plant and properties, for repayment of short-term debt, to refinance its existing $400 million, 4.875 percent Debentures, due October 15, 2012, or for working capital purposes.

On May 16, 2012, FERC approved NSTAR Electric’s application requesting authorization to issue short-term debt securities in the form of commercial paper, lines of credit, or revolving credit facilities in an aggregate principal amount not to exceed $655 million outstanding.

As of June 30, 2012, NU parent had $19.5 million of LOCs issued for the benefit of certain subsidiaries (including $4 million for CL&P and $5 million for PSNH) and $255 million of short-term borrowings outstanding under its former $500 million unsecured revolving credit facility, leaving $225.5 million available. The weighted-average interest rate on these short-term borrowings as of June 30, 2012 was 2.03 percent, based on a variable rate plus an applicable margin based on NU parent's credit ratings. As of June 30, 2012, CL&P, PSNH, WMECO, and Yankee Gas had short-term borrowings outstanding under their former $400 million revolving credit facility of $30 million, $65 million, $110 million, and $30 million, respectively, leaving $165 million of aggregate borrowing capacity available. The weighted-average interest rate on these short-term borrowings as of June 30, 2012 was 2.11 percent, which is based on a variable rate plus an applicable margin based on the companies’ respective credit ratings. As of June 30, 2012, NSTAR LLC had $114 million in short-term borrowings outstanding on its commercial paper program, leaving $61 million of borrowing capacity available. The weighted-average interest rate on these borrowings as of June 30, 2012 was 0.45 percent, which is generally based on money market rates. As of June 30, 2012, NSTAR Electric had $344.5 million in short-term borrowings outstanding on its commercial paper program, leaving $105.5 million of borrowing capacity available. The weighted-average interest rate on these borrowings as of June 30, 2012 was 0.36 percent, which is generally based on money market rates.

Cash flows provided by operating activities in the first half of 2012 totaled $284 million, compared with cash flows provided by operating activities of $652.4 million in the first half 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 $176.8 million of first half 2012 cash disbursements for storm costs primarily related to Tropical Storm Irene and the October 2011 snowstorm, $133.4 million of 2012 Pension Plan cash contributions, as compared to NU's Pension Plan contribution of $19.2 million in the first half of 2011, a total of $46 million of bill credits in the second quarter of 2012 to customers of CL&P, NSTAR Electric, NSTAR Gas and WMECO, $27 million in bill credits provided to CL&P residential customers in February 2012 related to the October 2011 snowstorm, $29.1 million of transaction cost payments related to the close of the merger, and negative cash flow impacts associated with undercollections on the FMCC and transmission regulatory tracking mechanisms at CL&P of $20.3 million and $38.4 million, respectively, in the first half 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, NSTAR Electric, and WMECO and senior secured debt of CL&P and PSNH is as follows:

Moody's

S&P

Fitch

Current

Outlook

Current

Outlook

Current

Outlook

NU Parent

Baa2

Stable

BBB+

Stable

BBB+

Stable

CL&P

Stable

A-

Stable

NSTAR Electric

Stable

A-

Stable

A+

Stable

PSNH

Stable

A-

Stable

WMECO

Baa2

Stable

A-

Stable

A-

Stable

We paid common dividends of $159.7 million in the first half of 2012, compared with $97.2 million in the first half of 2011. This reflects an increase of approximately 17 percent in our common dividend beginning in the second quarter of 2012 following an increase of approximately 7 percent in the first quarter of 2012. On July 17, 2012, our Board of Trustees approved a common dividend payment of $0.343 per share, payable September 28, 2012, to our shareholders of record as of August 31, 2012.

In the first half of 2012, CL&P, NSTAR LLC, PSNH, WMECO, and Yankee Gas paid $67 million, $46.6 million, $58.8 million, $9.4 million, and $18.3 million, respectively, in common dividends to NU parent. In the second quarter of 2012, NSTAR Electric and NSTAR Gas paid $78.3 million and $4 million, respectively, in common dividends to NSTAR LLC.

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 half of 2012 and 2011 is as follows:


	For the Six Months Ended June 30,
(Millions of Dollars)		2012		2011
CL&P	$	220.7	$	202.0
NSTAR Electric ⁽¹⁾		94.5		N/A
PSNH		120.8		111.5
WMECO		152.7		76.9
NSTAR Gas ⁽¹⁾		21.4		N/A
Yankee Gas		38.3		45.4
NPT		14.2		6.8
Other		27.8		25.9
Total	$	690.4	$	468.5

⁽¹⁾

Cash capital expenditures include NSTAR LLC and its subsidiaries from the date of merger, April 10, 2012, through June 30, 2012.

The increase in our cash capital expenditures was the result of the addition of NSTAR LLC and its subsidiaries’ capital expenditures in the second quarter of 2012 and higher transmission segment cash capital expenditures of $120 million, primarily at WMECO.

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 $714 million in the first half of 2012, compared with $500.1 million in the first half of 2011. These amounts included $20 million and $24.4 million in the first half of 2012 and 2011, respectively, related to our corporate service companies, NUSCO and RRR.

Transmission Segment : Transmission segment capital expenditures increased by $137.3 million in the first half 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 and the addition of NSTAR Electric's capital expenditures in the second quarter of 2012. A summary of transmission segment capital expenditures by company in the first half of 2012 and 2011 is as follows:


	For the Six Months Ended June 30,
(Millions of Dollars)	2012		2011
CL&P	$	91.1	$	49.6
NSTAR Electric ⁽¹⁾		29.2		N/A
PSNH		30.1		22.7
WMECO		136.4		83.8
NPT		14.5		8.0
Totals	$	301.3	$	164.1

⁽¹⁾

Transmission capital expenditures for NSTAR Electric are from the date of merger, April 10, 2012, through June 30, 2012.

NEEWS: GSRP, a project that involves the construction of CL&P and WMECO's 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 June 30, 2012, the project was approximately 75 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. All siting applications have been filed by CL&P and National Grid with the approvals expected by the end of 2013. The $218 million project is expected to be placed in service in late 2015.

The Central Connecticut Reliability Project, which involves CL&P's construction of a new $301 million 345 kV overhead line from Bloomfield, Connecticut to Watertown, Connecticut, is the third major part of NEEWS. ISO-NE continues to review its needs analysis for the central Connecticut and greater Hartford areas, and an updated preliminary study is expected in August 2012.

Included as part of NEEWS are associated reliability related projects, of which $41 million have been placed in service and $58 million are in various phases of construction and will continue to go into service through 2013.

Through June 30, 2012, CL&P and WMECO had capitalized $181.8 million and $452.8 million, respectively, in costs associated with NEEWS, of which $49.2 million and $118.1 million, respectively, were capitalized in the first half of 2012. The total expected cost of NU’s share of NEEWS is approximately $1.3 billion, of which $660 million and $616 million relate to CL&P and WMECO, respectively.

Lower SEMA: The Lower Southeastern Massachusetts (SEMA) Transmission Project consists of an expansion and upgrade of NSTAR Electric's existing transmission infrastructure, and construction of a new 345 kV transmission line that will cross the Cape Cod Canal. On April 27, 2012, the Massachusetts Energy Facilities Siting Board issued its final decision approving the project. Construction on the approximately $110 million project is expected to commence in the second half of 2012 and is expected to be completed by mid-2013.

Northern Pass: Northern Pass is NPT's planned HVDC transmission line from the Québec-New Hampshire border to Franklin, New Hampshire and an associated alternating current radial transmission line between Franklin and Deerfield, New Hampshire. Northern Pass will interconnect at the Québec-New Hampshire border with a planned HQ HVDC transmission line. On April 10, 2012, upon consummation of the merger with NSTAR, an NSTAR subsidiary that owned 25 percent of NPT was merged into NUTV, resulting in NUTV owning 100 percent of NPT.

We estimate the costs of the Northern Pass transmission project will be approximately $1.1 billion (including capitalized AFUDC). Through June 30, 2012, we capitalized $51.5 million in costs associated with Northern Pass.

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 to finalize the 40-mile route in the third quarter of 2012 and file the new route with the DOE in the fourth quarter of 2012, which should support construction to begin in the second half of 2014 and the project to be completed by the end of 2016. However, should the process of securing the properties continue beyond the third quarter of 2012, the project would be expected to be complete in early 2017.

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


	For the Six Months Ended June 30,
(Millions of Dollars)		2012		2011
CL&P:
Basic Business	$	44.1	$	64.5
Aging Infrastructure		95.2		55.5
Load Growth		42.7		29.9
Total CL&P		182.0		149.9
NSTAR Electric:
Basic Business		14.9		N/A
Aging Infrastructure		42.2		N/A
Load Growth		2.0		N/A
Total NSTAR Electric ⁽¹⁾		59.1		N/A
PSNH:
Basic Business		10.3		16.9
Aging Infrastructure		23.2		12.4
Load Growth		9.6		11.2
Total PSNH		43.1		40.5
WMECO:
Basic Business		7.5		8.3
Aging Infrastructure		8.4		4.9
Load Growth		3.6		3.4
Total WMECO		19.5		16.6
Total - Electric Distribution (excluding Generation)		303.7		207.0
NSTAR Gas ⁽¹⁾		20.0		N/A
Yankee Gas		40.9		45.4
Total - Gas Distribution		60.9		45.4
Other Distribution		0.4		0.5
Total Electric and Gas Distribution		365.0		252.9
PSNH Generation:
Clean Air Project		22.2		50.8
Other		5.1		7.3
Total PSNH Generation		27.3		58.1
WMECO Generation		0.3		0.6
Total Distribution Segment	$	392.6	$	311.6

⁽¹⁾

Distribution capital expenditures for NSTAR Electric and NSTAR Gas are from the date of merger, April 10, 2012, through June 30, 2012.

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

Clean Air Project: In June 2012, PSNH placed into service the last major elements of the Clean Air Project at Merrimack Station, a $422 million project that is utilizing wet scrubber technology to significantly reduce mercury and sulfur emissions from the station’s two coal units. The scrubber has been operating since the end of September 2011 and has reduced mercury and sulfur emissions by more than 95 percent.

CL&P System Resiliency Plan: On July 9, 2012, consistent with the terms of the Connecticut settlement agreement among NU, NSTAR and various Connecticut state agencies, CL&P filed a $300 million plan with the PURA to improve the resiliency of the CL&P

electric distribution system. The plan includes vegetation management (both enhanced tree trimming and trimming on a shorter cycle), structural hardening (strengthening field structures through upgrades to the current structure design and material standards as well as upgrades to the poles and wires), and electrical hardening (upgrading electrical distribution conductors and protective device on overhead circuits). CL&P expects to complete the plan in five years in two separate phases. Phase 1 of the plan, which will be primarily focused on vegetation management, is estimated to cost $32 million in 2013 and $53 million in 2014. Phase 2 of the plan is estimated to cost the remaining $215 million over the period from 2015 through 2017. A PURA decision is expected by the fourth quarter of 2012. CL&P is evaluating the impact of the plan on its previously disclosed distribution capital budget through 2016.

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 June 30, 2012, we were in a total net underrecovery position of $51.6 million, of which the transmission segments of CL&P, NSTAR Electric, PSNH and WMECO were $20 million, $18 million, $6.7 million and $6.9 million, respectively.

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.

As of June 30, 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

Federal: On July 6, 2012, President Obama signed the "Moving Ahead for Progress in the 21 ^st Century" Act, which included provisions that could impact how minimum required contributions to pension plans are calculated. The legislation allows NU to use a higher discount rate to calculate the plan's funded target liability, resulting in lower cash contribution requirements. The legislation could have a significant impact on the amount of cash contributions required to be made in 2013 and 2014. NU is currently evaluating the impact that the legislation will have on future cash contributions to the NUSCO and NSTAR Electric pension plans.

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

Regulatory Developments and Rate Matters

CL&P, NSTAR Electric, PSNH, WMECO, NSTAR Gas, and Yankee Gas' distribution rates are set by their respective state regulatory commissions, and their tariffs include mechanisms for periodically adjusting their rates. Other than as described below, for the second quarter ended June 30, 2012, changes made to the CL&P, NSTAR Electric, PSNH, WMECO, NSTAR Gas, and Yankee Gas rates did not have a material impact on their earnings, financial position, or cash flows. For further information, see "Financial Condition and Business Analysis – Regulatory Developments and Rate Matters" included in Item 7, " Management's Discussion and Analysis of Financial Condition and Results of Operations," of the NU 2011 Form 10-K, "Rate and Regulatory Proceedings" included in Item 7, " Management's Discussion and Analysis of Financial Condition and Results of Operations," of the NSTAR 2011 Form 10-K, and "Rate and Regulatory Proceedings" included in Item 7, " Management's Discussion and Analysis of Financial Condition and Results of Operations," of the NSTAR Electric 2011 Form 10-K.

Connecticut – CL&P:

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

Distribution Rates: On June 1, 2012, PURA opened a docket to examine the energy Procurement Plan developed by DEEP’s new procurement manager. The Procurement Plan authorizes CL&P to self-manage 20 percent of its 2013 standard service load. The percentage of self-managed load may change subsequent to 2013 based on CL&P's performance. PURA has not developed a schedule for its review and approval of the Procurement Plan.

PURA Emergency and Preparedness Response Docket: On June 19, 2012, pursuant to Connecticut's "Enhancing Emergency Preparedness and Response Act," PURA opened a docket to establish standards for electric and gas distribution companies, including:

Reviewing current practices concerning service restoration after an emergency;

Reviewing the adequacy of infrastructure, facilities and equipment;

Reviewing coordination efforts between each electric distribution company and any telecom, community antenna television companies, cable franchise or competitive video service providers, including coordinated planning before any emergency;

Reviewing tree trimming policies;

Establishing standards for acceptable performance in an emergency in which more than 10 percent of any utility's customers are without service for more than 48 consecutive hours;

Determining any other standards for acceptable performance to ensure the reliability in any emergency, to prevent and minimize any service outages or disruptions lasting more than 48 consecutive hours and affecting more than 10 percent of any utility's customers and to facilitate restoration of services;

Determining any other policy, practice or information that is relevant to ensure the reliability of utility's services in an emergency and to prevent, minimize and restore any long-term service outages or disruptions caused by emergency; and

Identifying any recommendations concerning legislative changes necessary to implement standards.

A report is due to the Connecticut legislature detailing the standards established as a result of this docket by November 1, 2012.

CL&P System Resiliency Plan: On July 9, 2012, consistent with the terms of the Connecticut settlement agreement among NU, NSTAR, and various Connecticut state agencies, CL&P filed with PURA for approval to spend up to $300 million to improve the resiliency of the CL&P electric distribution system. For further information, see "Business Development and Capital Expenditures – Distribution Segment" in this Management's Discussion and Analysis.

Massachusetts – NSTAR Electric:

DPU Safety and Reliability Programs (CPSL): NSTAR Electric recovers incremental costs related to the Double Pole Inspection Program, Replacement/Restoration and Transfer Program and the Underground Electric Safety Program, which includes stray-voltage remediation, manhole inspections, repairs, and upgrades, in accordance with this DPU approved program. Recovery of these CPSL costs is subject to review and approval by the DPU through a rate-reconciling mechanism. From 2006 through June 2012, cumulative costs associated with the CPSL program have resulted in an incremental revenue requirement to customers of approximately $90 million. These amounts include incremental operations and maintenance costs and the related revenue requirement for specific capital investment relative to the CPSL programs.

NSTAR Electric cannot predict the timing of any subsequent DPU order related to its CPSL filings for the period 2006 through 2009, or any period thereafter. Therefore, NSTAR Electric continues to record its revenues under the CPSL programs based on the May 2010 Order. Should any subsequent DPU order be different than the conclusion of the May 2010 Order it could have a material impact on NSTAR Electric’s results of operations, financial position and cash flows.

Basic Service Bad Debt Adder: On July 1, 2005, in response to a generic DPU order that required electric utilities in Massachusetts to recover the energy-related portion of bad debt costs in their Basic Service rates, NSTAR Electric increased its Basic Service rates and reduced its distribution rates for those bad debt costs. In furtherance of this generic DPU order, NSTAR Electric included a bad debt

cost recovery mechanism as a component of its 2005 Rate Settlement Agreement. This recovery mechanism (bad debt adder) allows NSTAR Electric to recover its Basic Service bad debt costs on a fully reconciling basis. These rates were implemented, effective January 1, 2006, as part of its 2005 Rate Settlement Agreement.

NSTAR Electric continued to defer the costs associated with these amounts as a regulatory asset, which totaled approximately $34 million as of December 31, 2011, as NSTAR Electric had concluded that these costs were probable of recovery in future rates. On June 18, 2010, NSTAR Electric filed an appeal of the DPU’s order with the SJC, which was heard by the SJC in December 2011. On April 11, 2012, the SJC issued a procedural order waiving its standing 130-day rule for issuance of an order on the matter. This delay by the SJC caused NSTAR Electric to reassess its position as to the outcome. Due to the delay, NSTAR Electric concluded that while an ultimate outcome on the matter in its favor remained "more likely than not," it could no longer be deemed "probable." As a result, as of March 31, 2012, NSTAR Electric recognized a reserve of $28 million ($17 million after-tax) as a charge to Operations and Maintenance in the first quarter of 2012 to fully reserve the related regulatory asset on its balance sheet.

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

Distribution Rates: In the fourth quarter of each year, NSTAR Electric files proposed distribution rate adjustments for effect on the following January 1 ^st . These rate adjustments include a SIP rate factor and several other fully reconciling cost recovery items. Consistent with previous filings, the 2011 filings include a combination of actual and forecasted data for 2011 that NSTAR Electric will update during 2012 with year-end data to allow a final investigation and reconciliation. There are several case years that remain outstanding at the DPU. These cases are pending decisions at the DPU, and NSTAR Electric cannot predict the timing or the ultimate outcome of these filings.

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 over the current level of major 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 allowable under the 2010 rate case settlement. On June 27, 2012, the NHPUC approved these distribution rate increases, effective July 1, 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. The proposal, if implemented, would result in no impact to earnings and would allow for an increased contribution to fixed costs for all ES customers. On May 24, 2012, the NHPUC suspended the effectiveness of the proposed rates pending hearings. The NHPUC issued a procedural schedule with hearings scheduled for October 2012.

On June 12, 2012, PSNH filed for new ES and SCRC rates effective July 1, 2012. PSNH proposed to decrease the current ES rate by 0.82 cents per kWh, which included one-half of an ES over recovery, with the remainder of this overrecovery being returned during 2013. The NHPUC Staff and the Office of Consumer Advocate recommended returning the entire overrecovery over the remaining months of 2012. The NHPUC agreed with this recommendation and ordered PSNH to decrease the current ES billing rate of 8.75 cents per kWh to 7.11 cents per kWh effective July 1, 2012. The NHPUC approved the SCRC rate as proposed.

On November 22, 2011, the NHPUC opened a docket to review the Clean Air Project including the establishment of temporary rates for near-term recovery of Clean Air Project costs, a prudence review of PSNH's overall construction program, and establishment of permanent rates for recovery of prudently incurred Clean Air Project costs. On April 10, 2012, the NHPUC issued an order authorizing temporary rates, effective April 16, 2012, which recover a significant portion of the Clean Air Project costs, including a return on equity. The 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 in early 2013. At that time, the NHPUC will reconcile recoveries collected under the temporary rates with final approved rates. Hearings in the case are currently scheduled for January 2013. PSNH believes that its actions related to Clean Air Project construction will be deemed prudent. The project was completed for $422 million, approximately $35 million below budget, and has reduced mercury and sulfur emissions by more than 95 percent.

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. A proposed procedural schedule has been approved by the NHPUC with a hearing scheduled for the fourth quarter of 2012.

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 NU’s 2011 Form 10-K, NSTAR’s 2011 Form 10-K, and NSTAR Electric’s 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," for discussion of the HWP environmental remediation contingency.

Contractual Obligations and Commercial Commitments: There have been no material contractual obligations identified and no material changes with regard to the contractual obligations and commercial commitments previously disclosed in the NU First Quarter 2012 Quarterly Report on Form 10-Q, NSTAR Electric's First Quarter 2012 Quarterly Report on Form 10-Q, NU 2011 Form 10-K, NSTAR 2011 Form 10-K, and the NSTAR Electric 2011 Form 10-K.

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

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 and six months ended June 30, 2012 and 2011. The 2012 amounts include the operations of NSTAR LLC and its subsidiaries from the date of the merger, April 10, 2012, through June 30, 2012.


			Operating Revenues and Expenses								Operating Revenues and Expenses
			For the Three Months Ended June 30,								For the Six Months Ended June 30,
(Millions of Dollars)			2012 ^(a)		2011		Increase/		Percent		2012 ^(a)		2011		Increase/		Percent
(Millions of Dollars)			2012 ^(a)		2011		(Decrease)		Percent		2012 ^(a)		2011		(Decrease)		Percent
Operating Revenues			$	1,628.7	$	1,047.5	$	581.2	55.5	%	$	2,728.3	$	2,282.7	$	445.6	19.5	%
Operating Expenses:
	Purchased Power, Fuel and Transmission			542.0		382.6		159.4	41.7			937.4		879.2		58.2	6.6
	Operations and Maintenance			529.9		269.7		260.2	96.5			791.9		533.3		258.6	48.5
	Depreciation			144.5		73.6		70.9	96.3			225.3		147.6		77.7	52.6
	Amortization of Regulatory Assets, Net			25.6		17.0		8.6	50.6			31.0		50.5		(19.5)	(38.6)
	Amortization of Rate Reduction Bonds			40.8		17.1		23.7	(b)			59.1		34.4		24.7	71.8
	Energy Efficiency Programs			73.5		30.0		43.5	(b)			110.8		64.4		46.4	72.0
	Taxes Other Than Income Taxes			112.9		79.4		33.5	42.2			198.9		167.8		31.1	18.5
		Total Operating Expenses		1,469.2		869.4		599.8	69.0			2,354.4		1,877.2		477.2	25.4
Operating Income			$	159.5	$	178.1	$	(18.6)	(10.4)	%	$	373.9	$	405.5	$	(31.6)	(7.8)	%

(a) The 2012 results include the operations of NSTAR LLC from the date of the merger, April 10, 2012, through June 30, 2012.
(b) Percent greater than 100 percent not shown as it is not meaningful.



Operating Revenues
		For the Three Months Ended June 30,								For the Six Months Ended June 30,
		2012 ^(a)		2011		Increase		Percent		2012 ^(a)		2011		Increase		Percent
Electric Distribution		$	1,229.9	$	794.4	$	435.5	54.8	%	$	2,016.0	$	1,686.0	$	330.0	19.6	%
Natural Gas Distribution			133.5		78.4		55.1	70.3			272.5		258.6		13.9	5.4
	Total Distribution		1,363.4		872.8		490.6	56.2			2,288.5		1,944.6		343.9	17.7
Transmission			228.7		152.1		76.6	50.4			391.6		310.3		81.3	26.2
	Total Regulated Companies		1,592.1		1,024.9		567.2	55.3			2,680.1		2,254.9		425.2	18.9
Other and Eliminations			36.6		22.6		14.0	61.9			48.2		27.8		20.4	73.4
Total Operating Revenues		$	1,628.7	$	1,047.5	$	581.2	55.5	%	$	2,728.3	$	2,282.7	$	445.6	19.5	%

(a) The 2012 results include the operations of NSTAR LLC from the date of the merger, April 10, 2012, through June 30, 2012.


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

	For the Three Months Ended June 30,					For the Six Months Ended June 30,
	2012 ^(a)	2011	Increase	Percent		2012 ^(a)	2011	Increase	Percent
Retail Electric Sales in GWh	12,836	7,966	4,870	61.1	%	21,106	16,671	4,435	26.6	%
Firm Natural Gas Sales in Million Cubic Feet	14,887	8,480	6,407	75.6	%	31,706	27,864	3,842	13.8	%

(a) Includes the retail electric sales and the firm natural gas sales of NSTAR Electric and NSTAR Gas, respectively, from the date of the merger, April 10, 2012, through June 30, 2012.

Our Operating Revenues increased for the three months ended June 30, 2012, as compared to the same period in 2011, due primarily to the addition of NSTAR LLC and its subsidiaries’ operations, which included electric distribution segment revenues of $476.7 million, transmission segment revenues of $57.9 million, natural gas segment revenues of $61.3 million and other revenues of $5.4 million. Absent the impact of NSTAR LLC’s operations, our Operating Revenues decreased due to the following:

Lower electric distribution segment revenues related to the portions that are included in regulatory commission approved tracking mechanisms that recover certain incurred costs and do not impact earnings. The tracked electric distribution revenues decreased due primarily to lower energy and supply-related costs ($45.6 million), lower retail transmission revenues ($17.5 million), lower wholesale revenues ($15 million) and lower CTA revenues ($10.7 million), partially offset by higher CL&P FMCC delivery-related revenues ($23.5 million) and higher retail SBC revenues ($5.6 million). The tracking mechanisms allow for rates to be changed periodically with overcollections refunded to customers or undercollections recovered from customers in future periods.

Partially offset by:

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

An increase at PSNH related to the sale of oil to an external buyer ($20.8 million), resulting in a benefit to customers through the form of lower ES rates and does not impact earnings.

Our Operating Revenues increased for the first half of 2012, as compared to the same period in 2011, due primarily to the addition of NSTAR LLC and its subsidiaries’ operations, which included electric distribution segment revenues of $476.7 million, transmission segment revenues of $57.9 million, natural gas segment revenues of $61.3 million and other revenues of $5.4 million. Absent the impact of NSTAR LLC’s operations, our Operating Revenues decreased due to the following:

Lower electric distribution segment revenues related to the portions that are included in regulatory commission approved tracking mechanisms that recover certain incurred costs and do not impact earnings. The tracked electric distribution revenues decreased due primarily to lower energy and supply-related costs ($113.1 million), lower retail transmission revenues ($42.1 million), lower wholesale revenues ($31.1 million) and lower CTA revenues ($22.3 million), partially offset by higher CL&P FMCC delivery-related revenues ($48.5 million) and higher retail SBC revenues ($11.4 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 segment revenues was due primarily to a 10.7 percent decrease in Yankee Gas' 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 segment revenues that impacts earnings decreased $16 million due primarily to a 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.

Partially offset by:

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

An increase at PSNH related to the sale of oil to an external buyer ($20.8 million), resulting in a benefit to customers through the form of lower ES rates and does not impact earnings.

Purchase Power, Fuel and Transmission increased for the three and six months ended June 30, 2012, as compared to the same periods in 2011, due primarily to the following:


		Three Months Ended		Six Months Ended
(Millions of Dollars)		Increase/(Decrease)		Increase/(Decrease)
The addition of NSTAR LLC and its subsidiaries’ operations		$	206.5	$	206.5
Lower GSC supply costs, purchased transmission costs and deferred fuel
	costs, partially offset by higher CfD costs at CL&P		(33.6)		(84.6)
Lower natural gas costs and lower sales at Yankee Gas			(6.8)		(39.0)
Lower purchased transmission costs at WMECO			(5.3)		(9.9)
Lower purchased power and fuel costs, partially offset by higher
	purchased transmission costs at PSNH		7.8		(6.2)
Other and eliminations			(9.1)		(8.6)
		$	159.5	$	58.2

Operations and Maintenance increased for the three months ended June 30, 2012, as compared to the same period in 2011, due primarily to the addition of NSTAR LLC and its subsidiaries’ operations in the second quarter of 2012 that resulted in an increase of operating expenses of $122.9 million and maintenance expense of $20.9 million. Absent the impact of NSTAR LLC’s operations, Operations and Maintenance increased due primarily to:

Higher NU parent and other companies expenses ($53 million) that were due primarily to higher merger and related settlement costs ($46.1 million), which included fees paid to investment advisors and attorneys, a charge for the establishment of a fund to advance Connecticut energy goals related to the Connecticut settlement agreement, and change in control costs and other compensation costs. In addition, there were higher costs at NU’s unregulated contracting business related to an increased level of work in 2012 ($8.5 million).

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

Operations and Maintenance increased for the first half of 2012, as compared to the same period in 2011, due primarily to the addition of NSTAR LLC and its subsidiaries’ operations in the second quarter of 2012 that resulted in an increase of operating expenses of $122.9 million and maintenance expense of $20.9 million. Absent the impact of NSTAR LLC’s operations, Operations and Maintenance increased due primarily to:

Higher NU parent and other companies expenses ($50.3 million) that were due primarily to higher costs related to the completion of NU’s merger with NSTAR ($36.2 million) and higher costs at NU’s unregulated contracting business related to an increased level of work in 2012 ($14.6 million).

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

Depreciation increased for the three and six months ended June 30, 2012, as compared to the same periods in 2011, due primarily to the addition of NSTAR LLC and its subsidiaries’ plant balances in the second quarter of 2012 ($48.9 million) and an increase of $13.7 million in the second quarter of 2012 as a result of the consolidation of CYAPC and YAEC. Absent the impact of NSTAR LLC and the consolidation of CYAPC and YEAC, Depreciation increased due primarily to higher utility plant balances resulting from completed construction projects placed into service ($8.2 million and $15.1 million, respectively).

Amortization of Regulatory Assets, Net increased for the three months ended June 30, 2012, as compared to the same period in 2011, due primarily to the addition of NSTAR LLC and its subsidiaries’ operations in the second quarter of 2012 ($19.2 million). Absent the impact of NSTAR LLC, Amortization of Regulatory Assets, Net decreased due primarily to higher CTA transition costs ($4.6 million) and lower retail CTA revenue ($10.8 million), partially offset by lower SBC costs ($1.2 million) and higher retail SBC revenues ($5.6 million) at CL&P.

Amortization of Regulatory Assets, Net decreased for the first half of 2012, as compared to the same period in 2011, due primarily to the addition of NSTAR LLC and its subsidiaries’ operations in the second quarter of 2012 ($19.2 million). Absent the impact of NSTAR LLC, Amortization of Regulatory Assets, Net decreased due primarily to higher CTA transition costs ($10 million) and lower retail CTA revenue ($22.3 million) at CL&P and a decrease in TCAM and SCRC amortization ($17.6 million and $14 million, respectively) at PSNH. Partially offsetting these decreases were lower SBC costs ($3.6 million) and higher retail SBC revenues ($11.4 million) at CL&P and an increase in ES amortization at PSNH ($11.4 million).

Amortization of RRBs increased for the three and six months ended June 30, 2012, as compared to the same periods in 2011, due primarily to the addition of NSTAR Electric’s amortization in the second quarter of 2012 ($22.6 million).

Energy Efficiency Programs increased for the three and six months ended June 30, 2012, as compared to the same periods in 2011, due primarily to the addition of NSTAR LLC and its subsidiaries’ operations in the second quarter of 2012 ($41.7 million).

Taxes Other Than Income Taxes increased for the three and six months ended June 30, 2012, as compared to the same periods in 2011, due primarily to the addition of NSTAR LLC and its subsidiaries’ operations in the second quarter of 2012 ($31 million).


Interest Expense
	For the Three Months Ended June 30,								For the Six Months Ended June 30,
					Increase/								Increase/
(Millions of Dollars)	2012 ^(a)		2011		(Decrease)		Percent		2012 ^(a)		2011		(Decrease)		Percent
Interest on Long-Term Debt	$	86.9	$	57.0	$	29.9	52.5	%	$	146.9	$	114.4	$	32.5	28.4	%
Interest on RRBs		2.1		2.3		(0.2)	(8.7)			3.5		4.9		(1.4)	(28.6)
Other Interest		-		2.9		(2.9)	(100.0)			5.1		1.5		3.6	(b)
	$	89.0	$	62.2	$	26.8	43.1	%	$	155.5	$	120.8	$	34.7	28.7	%

(a) The 2012 results include the operations of NSTAR LLC from the date of the merger, April 10, 2012, through June 30, 2012.
(b) Percent greater than 100 percent not shown as it is not meaningful.

Interest Expense increased for the three and six months ended June 30, 2012, as compared to the same periods in 2011, due primarily to the addition of NSTAR LLC and its subsidiaries’ operations in the second quarter of 2012 ($23.9 million).


Other Income, Net
	For the Three Months Ended June 30,								For the Six Months Ended June 30,
(Millions of Dollars)	2012 ^(a)		2011		Decrease		Percent		2012 ^(a)		2011		Decrease		Percent
Other Income, Net	$	1.8	$	7.3	$	(5.5)	(75.3)	%	$	10.6	$	17.6	$	(7.0)	(39.8)	%

(a)

The 2012 results include the operations of NSTAR LLC from the date of the merger, April 10, 2012, through June 30, 2012.

Other Income, Net decreased for the three and six months ended June 30, 2012, as compared to the same periods in 2011, due primarily to lower AFUDC related to equity funds at PSNH, as the Clean Air Project was placed into service in September 2011.


Income Tax Expense
	For the Three Months Ended June 30,								For the Six Months Ended June 30,
(Millions of Dollars)	2012 ^(a)		2011		Decrease		Percent		2012 ^(a)		2011		Decrease		Percent
Income Tax Expense	$	26.1	$	44.5	$	(18.4)	(41.3)	%	$	82.0	$	108.1	$	(26.1)	(24.1)	%

(a) The 2012 results include the operations of NSTAR LLC from the date of the merger, April 10, 2012, through June 30, 2012.

Income Tax Expense decreased for the three months ended June 30, 2012, as compared to the same period in 2011, due primarily to Connecticut and Massachusetts settlement agreement impacts ($41 million) and merger impacts ($14.5 million), partially offset by higher pre-tax earnings ($33.4 million) and higher state taxes ($2 million).

Income Tax Expense decreased for the six months ended June 30, 2012, as compared to the same period in 2011, due primarily to Connecticut and Massachusetts settlement agreement impacts ($41 million) and merger impacts ($14.6 million), partially offset by higher pre-tax earnings ($23.9 million) and lower items that directly impact our tax return as a result of regulatory actions (“flow through” items) ($3.3 million).

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 and six months ended June 30, 2012 and 2011:


			Operating Revenues and Expenses								Operating Revenues and Expenses
			For the Three Months Ended June 30,								For the Six Months Ended June 30,
(Millions of Dollars)			2012		2011		Increase/		Percent		2012		2011		Increase/		Percent
(Millions of Dollars)			2012		2011		(Decrease)		Percent		2012		2011		(Decrease)		Percent
Operating Revenues			$	562.1	$	608.0	$	(45.9)	(7.5)	%	$	1,154.1	$	1,281.7	$	(127.6)	(10.0)	%
Operating Expenses:
	Purchased Power and Transmission			196.8		230.4		(33.6)	(14.6)			417.7		502.3		(84.6)	(16.8)
	Operations and Maintenance			205.4		136.7		68.7	50.3			338.4		272.4		66.0	24.2
	Depreciation			41.5		38.4		3.1	8.1			82.6		77.9		4.7	6.0
	Amortization of Regulatory Assets, Net			3.3		13.7		(10.4)	(75.9)			11.2		32.4		(21.2)	(65.4)
	Energy Efficiency Programs			21.0		21.3		(0.3)	(1.4)			43.0		44.7		(1.7)	(3.8)
	Taxes Other Than Income Taxes			53.7		52.7		1.0	1.9			109.0		111.2		(2.2)	(2.0)
		Total Operating Expenses		521.7		493.2		28.5	5.8			1,001.9		1,040.9		(39.0)	(3.7)
Operating Income			$	40.4	$	114.8	$	(74.4)	(64.8)	%	$	152.2	$	240.8	$	(88.6)	(36.8)	%


Operating Revenues
CL&P's retail sales were as follows:

	For the Three Months Ended June 30,					For the Six Months Ended June 30,
	2012	2011	Decrease	Percent		2012	2011	Decrease	Percent
Retail Sales in GWh	5,181	5,250	(69)	(1.3)	%	10,608	11,026	(418)	(3.8)	%

CL&P's Operating Revenues decreased for the three and six months ended June 30, 2012, as compared to the same periods in 2011, due primarily to:

A $42.1 million and $102.8 million decrease, respectively, 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 ($36.8 million and $90.4 million, respectively), lower wholesale revenues ($13.5 million and $23.4 million, respectively), lower CTA revenues ($10.7 million and $22.3 million, respectively) and lower retail transmission revenues ($9.5 million and $25.2 million, respectively). The lower GSC and FMCC supply-related revenues were due primarily to lower customer rates resulting from lower average supply prices and lower sales related to additional customer migration to third party electric suppliers in 2012. These lower revenues were partially offset by higher FMCC delivery-related revenues ($23.5 million and $48.5 million, respectively) and higher SBC revenues ($5.6 million and $11.4 million, respectively). The tracking mechanisms allow for rates to be changed periodically with overcollections refunded to customers or undercollections recovered from customers in future periods.

A $12 million decrease in the portion of distribution revenues that impacts earnings for the first half of 2012, compared to the same period in 2011, due primarily to lower sales volume related to the warmer than normal weather in the first quarter of 2012, as compared to the first quarter of 2011.

Purchased Power and Transmission decreased for the three and six months ended June 30, 2012, as compared to the same periods in 2011, due primarily to the following:


	Three Months Ended		Six Months Ended
(Millions of Dollars)	Increase/(Decrease)		Increase/(Decrease)
GSC Supply Costs	$	(31.0)	$	(73.2)
Transmission Costs		(13.4)		(32.9)
Deferred Fuel Costs		(7.6)		(21.2)
Purchased Power Contracts		(8.0)		(8.8)
CfD Costs		27.1		53.8
Other		(0.7)		(2.3)
	$	(33.6)	$	(84.6)

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

Operations and Maintenance increased for the three and six months ended June 30, 2012, as compared to the same periods in 2011, due primarily to the establishment of a reserve related to major storm costs ($40 million) and a bill credit to customers ($25 million) in the second quarter of 2012 as a result of the Connecticut settlement agreement . In addition, there were higher distribution business expenses mainly as a result of general and administrative expenses related to higher pension costs ($7.2 million and $14 million, respectively) higher vegetation management costs ($6.3 million and $8.2 million, respectively) and higher routine distribution

maintenance ($7.1 million for the six months). Partially offsetting these increases was a decrease in the amortization of the allowed regulatory deferral as a result of the June 30, 2010 rate case decision ($8.9 million and $17.7 million, respectively).

Amortization of Regulatory Assets, Net decreased for the three and six months ended June 30, 2012, as compared to the same periods in 2011, due primarily to higher CTA transition costs ($4.6 million and $10 million, respectively) and lower retail CTA revenue ($10.8 million and $22.3 million, respectively). Partially offsetting these impacts were lower SBC costs ($1.2 million and $3.6 million, respectively) and higher retail SBC revenues ($5.6 million and $11.4 million, respectively).


Income Tax Expense
	For the Three Months Ended June 30,								For the Six Months Ended June 30,
(Millions of Dollars)	2012		2011		Decrease		Percent		2012		2011		Decrease		Percent
Income Tax Expense	$	0.1	$	29.9	$	(29.8)	(99.7)	%	$	29.8	$	66.4	$	(36.6)	(55.1)	%

Income Tax Expense decreased for the three and six months ended June 30, 2012, as compared to the same periods in 2011, due primarily to Connecticut settlement agreement impacts ($26.6 million), lower pre-tax earnings ($3.5 million and $8.1 million, respectively), and lower state income taxes and other impacts ($1.9 million for the six months).

LIQUIDITY

CL&P had cash flows provided by operating activities of $47.5 million in the first six months of 2012, compared with cash flows provided by operating activities of $359 million in the first six months of 2011. The reduced cash flows were due primarily to $154.4 million of cash disbursements for storm costs associated with Tropical Storm Irene and the October 2011 snowstorm made in the first six months of 2012, $27 million in bill credits provided to residential customers in February 2012 related to the October 2011 snowstorm, $25 million in bill credits to customers associated with the Connecticut settlement agreement, and negative cash flow impacts associated with under collections on the FMCC and transmission regulatory tracking mechanisms of $20.3 million and $38.4 million, respectively, in the first six months of 2012, as compared to the same period in 2011. In addition, CL&P recovered $4.3 million of its deferred operation and maintenance costs in the first six months of 2012, compared to $23.4 million in the first six months of 2011. Offsetting these negative cash flow impacts were intercompany income tax settlements with affiliates in the first six months of 2012 of $32.6 million, compared to intercompany income tax settlements with affiliates of $18.8 million in the first six months 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 $220.7 million in the first six months of 2012, compared with $202 million in the first six months of 2011.

CL&P was a party to a joint unsecured revolving credit facility in a nominal aggregate amount of $400 million. As of June 30 2012, CL&P had $30 million in short-term borrowings outstanding under this former revolving credit facility. The weighted-average interest rate on these borrowings as of June 30, 2012 was 2.03 percent.

On July 25, 2012, NU, NSTAR LLC, NSTAR Gas, CL&P, PSNH, WMECO, and Yankee Gas jointly entered into a five-year $1.15 billion revolving credit facility. The new facility replaced (1) the NSTAR LLC revolving credit facility of $175 million that served to backstop a commercial paper program utilized by NSTAR LLC and was scheduled to expire on December 31, 2012, (2) the NSTAR Gas revolving credit facility of $75 million that expired on June 8, 2012, and (3) the CL&P, PSNH, WMECO, and Yankee Gas joint three-year $400 million and NU parent three-year $500 million unsecured revolving credit facilities that were scheduled to expire on September 24, 2013. The new facility expires on July 25, 2017. We expect the new facility to be used primarily to backstop the $1.15 billion commercial paper program at NU, which commenced July 25, 2012.

CL&P has a separate five-year $300 million unsecured revolving credit facility that expires on March 26, 2017 and will remain outstanding. As of June 30, 2012, CL&P had $300 million in short-term borrowings outstanding under this credit facility. The weighted average interest rate on these borrowings as of June 30, 2012 was 1.59 percent.

Financing activities in the first six months of 2012 included $67 million in common stock dividends paid to NU parent, an increase in short-term borrowings of $299 million, and $53.5 million in repayments to the NU Money Pool.

RESULTS OF OPERATIONS – NSTAR ELECTRIC COMPANY AND SUBSIDIARIES

The following table provides the amounts and variances in operating revenues and expense line items for the unaudited condensed consolidated statements of income for NSTAR Electric included in this Quarterly Report on Form 10-Q for the three and six months ended June 30, 2012 and 2011:


			Operating Revenues and Expenses								Operating Revenues and Expenses
			For the Three Months Ended June 30,								For the Six Months Ended June 30,
(Millions of Dollars)			2012		2011		Increase/		Percent		2012		2011		Increase/		Percent
(Millions of Dollars)			2012		2011		(Decrease)		Percent		2012		2011		(Decrease)		Percent
Operating Revenues			$	534.6	$	552.3	$	(17.7)	(3.2)	%	$	1,091.1	$	1,129.8	$	(38.7)	(3.4)	%
Operating Expenses:
	Purchased Power and Transmission			180.5		212.1		(31.6)	(14.9)			399.5		455.1		(55.6)	(12.2)
	Operations and Maintenance			109.0		87.8		21.2	24.1			257.2		185.0		72.2	39.0
	Depreciation			42.7		41.6		1.1	2.6			85.2		83.1		2.1	2.5
	Amortization of Regulatory Assets, Net			22.1		13.4		8.7	64.9			46.0		29.7		16.3	54.9
	Amortization of Rate Reduction Bonds			22.6		22.6		-	-			45.2		45.2		-	-
	Energy Efficiency Programs			35.5		32.9		2.6	7.9			82.4		73.0		9.4	12.9
	Taxes Other Than Income Taxes			28.3		26.3		2.0	7.6			59.2		55.4		3.8	6.9
		Total Operating Expenses		440.7		436.7		4.0	0.9			974.7		926.5		48.2	5.2
Operating Income			$	93.9	$	115.6	$	(21.7)	(18.8)	%	$	116.4	$	203.3	$	(86.9)	(42.7)	%


Operating Revenues
NSTAR Electric's retail sales were as follows:

	For the Three Months Ended June 30,					For the Six Months Ended June 30,
	2012	2011	Decrease	Percent		2012	2011	Decrease	Percent
Retail Sales in GWh	4,964	5,028	(64)	(1.3)	%	10,054	10,382	(328)	(3.2)	%

NSTAR Electric's Operating Revenues decreased for the three and six months ended June 30, 2012, as compared to the same periods in 2011, due primarily to:

A $21.6 million and $41.2 million decrease, respectively, in the 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. This decrease primarily related to lower purchased power and transmission costs related to lower customer retail sales ($2.2 million and $2.3 million, respectively), and lower retail transmission revenues ($4.9 million and $10.8 million, respectively). 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 the portion of distribution revenues that impacts earnings due primarily to a 1.3 percent and 3.2 percent decrease, respectively, in retail sales, partially offset by a positive annual inflation rate adjustment.

Partially offset by:

A $7.6 million and $11.8 million, respectively, improvement in transmission revenues resulting from a higher level of investment in transmission infrastructure and the recovery of higher overall expenses, which are tracked and result in a related increase in revenues. The increase in expenses is directly related to the increase in transmission plant, including costs associated with higher property taxes, depreciation and operation and maintenance expenses.

Purchased Power and Transmission decreased for the three and six months ended June 30, 2012, as compared to the same periods in 2011, due primarily to the following:


(Millions of Dollars)	Three Months Ended		Six Months Ended
Purchased Power Contracts	$	(15.6)	$	(28.6)
Transmission Costs		(11.3)		(20.7)
Basic Service Supply Costs		(9.8)		(9.4)
Deferred Fuel Costs		7.0		4.0
Other		(1.9)		(0.9)
	$	(31.6)	$	(55.6)

The decrease in Basic Service supply costs was due primarily to lower average supply prices and additional customer migration to third party electric suppliers, the decrease in transmission costs was due primarily to higher transmission cost deferrals, and the decrease in purchased power contracts was due primarily to the expiration of certain contracts. These costs are included in DPU approved tracking mechanisms and do not impact earnings.

Operations and Maintenance increased for the three months ended June 30, 2012, as compared to the same period in 2011, due primarily to a bill credit to customers ($15 million) in the second quarter of 2012 as a result of the Massachusetts settlement agreement, an increase in distribution maintenance and vegetation management costs ($4.1 million), transmission operating and maintenance expenses ($3.3 million), labor and labor-related costs ($1.2 million) and bad debt costs ($1.5 million).

Operations and Maintenance increased for the first half of 2012, as compared to the same period in 2011, due primarily to the cumulative adjustment recorded to establish a reserve against the regulatory asset related to Basic Service bad debt costs ($28 million). Also, first quarter 2012 adjustments were recognized for changes in accounting estimates related primarily to the allowance for doubtful accounts, workers’ compensation, employee medical benefits, and general liability claims ($18.7 million). In addition, a bill credit to customers ($15 million) was recorded in the second quarter of 2012 as a result of the Massachusetts settlement agreement. Also contributing to the increase in costs was an incident in March 2012 involving a substation fire in the Back Bay/Prudential area of Boston ($10.1 million), and higher transmission operating and maintenance expenses ($3.3 million). These increases were partially offset by lower storm-related expense ($0.7 million).

Amortization of Regulatory Assets, Net , increased for the three and six months ended June 30, 2012, as compared to the same periods in 2011, due primarily to higher deferred transition expense related to expired contract termination liabilities of buy-out agreements for certain purchase power contracts that NSTAR Electric entered into in a prior period, which are recovered through the transition charge.

Energy Efficiency Programs increased for the three and six months ended June 30, 2012, as compared to the same periods in 2011. The increase in energy efficiency costs is in accordance with the three-year program guidelines established by the DPU. The costs are fully recovered through a DPU tracking mechanism.


Other Income, Net
	For the Three Months Ended June 30,								For the Six Months Ended June 30,
(Millions of Dollars)	2012		2011		Decrease		Percent		2012		2011		Decrease		Percent
Other Income, Net	$	-	$	0.9	$	(0.9)	(100.0)	%	$	1.2	$	1.7	$	(0.5)	(29.4)	%

Other Income, Net decreased for the three and six months ended June 30, 2012, as compared to the same periods of 2011, due primarily to both lower cash surrender values and proceeds from executive life insurance policies and lower equity investment earnings.


Income Tax Expense
	For the Three Months Ended June 30,								For the Six Months Ended June 30,
(Millions of Dollars)	2012		2011		Decrease		Percent		2012		2011		Decrease		Percent
Income Tax Expense	$	30.8	$	39.5	$	(8.7)	(22.0)	%	$	32.8	$	67.5	$	(34.7)	(51.4)	%

Income Tax Expense decreased for the three and six months ended June 30, 2012, as compared to the same periods in 2011, due primarily to lower pre-tax earnings ($2.6 million and $28.1 million, respectively), Massachusetts settlement agreement impacts ($5.9 million) and merger impacts ($0.9 million).

EARNINGS SUMMARY


	For the Three Months Ended June 30,				For the Six Months Ended June 30,
(Millions of Dollars)	2012		2011		2012		2011
Income Before Merger and Related Costs	$	56.1	$	60.7	$	60.0	$	103.5
Merger and Related Costs (after-tax)		(10.6)		-		(10.6)		-
Net Income	$	45.5	$	60.7	$	49.4	$	103.5

The after-tax merger and related settlement costs for the second quarter and first half of 2012 consisted of approximately $15 million (pre-tax) of charges for customer bill credits related to the Massachusetts settlement agreement, transaction and integration-related costs, and compensation costs.

Excluding the merger and related settlement costs, NSTAR Electric’s second quarter 2012 earnings were $4.6 million lower than the same period of 2011 due primarily to higher transmission-related operations and maintenance expenses, higher distribution maintenance and vegetation management costs, higher labor and labor-related costs and higher bad debt expense. Partially offsetting these costs was a favorable impact in the transmission business earnings due primarily to higher revenues.

Excluding the merger and related settlement costs, NSTAR Electric’s first half 2012 earnings were $43.5 million lower than the same period of 2011 due primarily to the first quarter 2012 adjustment recorded to establish a reserve against the regulatory asset related to Basic Service bad debt costs ($17 million), and the first quarter 2012 adjustments recognized for changes in accounting estimates related primarily to the allowance for doubtful accounts, workers’ compensation, employee medical benefits, and general liability claims ($11.4 million). Also contributing to the increase in costs was an incident in March 2012 involving a substation fire in the Back Bay/Prudential area of Boston ($6.1 million), a reserve recorded relating to lost base revenues based on developments during hearings in the merger proceeding ($3 million), lower retail electric sales due to warmer than normal weather, and higher transmission operating and maintenance expenses ($2.1 million). These costs were partially offset by the timing of maintenance and lower storm-related expenses as well as higher transmission revenues.

CAPITAL EXPENDITURES


	For the Six Months Ended June 30,
(Millions of Dollars)		2012		2011
Transmission	$	60.5	$	45.1
Distribution:
Basic Business		28.3		33.3
Aging Infrastructure		82.8		62.6
Load Growth		3.2		9.7
Total Distribution		114.3		105.6
Total Capital Expenditures	$	174.8	$	150.7

LIQUIDITY

NSTAR Electric had cash flows provided by operating activities in the first half of 2012 of $115.9 million, compared with operating cash flows of $316.4 million in the first half of 2011 (amounts are net of RRB payments, which are included in financing activities). The decreased cash flows in 2012 were due primarily to the absence in the first six months of 2012 of income tax refunds received during the same period of 2011. For the first six months of 2012, NSTAR Electric made income tax payments of $79.9 million, as compared to income tax refunds of $117.3 million in the first six months of 2011. NSTAR Electric also provided $15 million in bill credits to its customers in connection with the Massachusetts settlement agreement in the first six months of 2012. Offsetting these negative cash flow impacts was a reduction in Pension Plan contributions during the first six months of 2012, as compared to the same period in 2011, of approximately $44 million.

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, AFUDC related to equity funds, and the capitalized portion of pension expense. NSTAR Electric's cash capital expenditures totaled $189.2 million for the six months ended June 30, 2012, compared with $156.8 million for the six months ended June 30, 2011.

Financing activities for the six months ended June 30, 2012 included $135.4 million in common dividends paid to NSTAR in the first quarter of 2012 and NSTAR LLC in the second quarter of 2012, and an increase in short-term debt borrowings of $203 million.

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 and six months ended June 30, 2012 and 2011.


			Operating Revenues and Expenses								Operating Revenues and Expenses
			For the Three Months Ended June 30,								For the Six Months Ended June 30,
(Millions of Dollars)			2012		2011		Increase/		Percent		2012		2011		Increase/		Percent
(Millions of Dollars)			2012		2011		(Decrease)		Percent		2012		2011		(Decrease)		Percent
Operating Revenues			$	255.1	$	240.2	$	14.9	6.2	%	$	498.1	$	509.7	$	(11.6)	(2.3)	%
Operating Expenses:
	Purchased Power, Fuel and Transmission			82.2		74.4		7.8	10.5			163.2		169.4		(6.2)	(3.7)
	Operations and Maintenance			68.4		76.3		(7.9)	(10.4)			133.4		140.5		(7.1)	(5.1)
	Depreciation			21.8		18.1		3.7	20.4			43.0		36.0		7.0	19.4
	Amortization of Regulatory Assets, Net			2.8		2.5		0.3	12.0			0.2		18.0		(17.8)	(98.9)
	Amortization of Rate Reduction Bonds			13.8		13.0		0.8	6.2			27.7		26.1		1.6	6.1
	Energy Efficiency Programs			3.2		2.8		0.4	14.3			6.8		5.9		0.9	15.3
	Taxes Other Than Income Taxes			15.9		15.2		0.7	4.6			31.4		28.9		2.5	8.7
		Total Operating Expenses		208.1		202.3		5.8	2.9			405.7		424.8		(19.1)	(4.5)
Operating Income			$	47.0	$	37.9	$	9.1	24.0	%	$	92.4	$	84.9	$	7.5	8.8	%


Operating Revenues
PSNH's retail sales were as follows:	For the Three Months Ended June 30,					For the Six Months Ended June 30,
	2012	2011	Decrease	Percent		2012	2011	Decrease	Percent
Retail Sales in GWh	1,824	1,849	(25)	(1.3)	%	3,761	3,833	(72)	(1.9)	%

PSNH's Operating Revenues increased for the three months ended June 30, 2012, as compared to the same period in 2011, due primarily to:

An increase related to the sale of oil to an external buyer ($20.8 million), resulting in a benefit to customers through lower ES rates that does not impact earnings.

A $4.7 million improvement in transmission revenues resulting from a higher level of investment in transmission infrastructure and the recovery of higher overall expenses, which are tracked and result in a related increase in revenues. The increase in expenses is directly related to the increase in transmission plant, including costs associated with higher property taxes, depreciation and operation and maintenance expenses.

Partially offset by:

A $7.6 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 power and fuel costs ($9.4 million) related to a slight increase in ES customer migration to third party electric suppliers and lower ES customer retail sales, and lower retail transmission revenues ($6.3 million). These lower revenues were offset by higher revenues related to RECs ($4.4 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 $1.3 million decrease in the portion of distribution revenues that impacts earnings due primarily to a 1.3 percent decrease in retail sales.

PSNH's Operating Revenues decreased for the first half of 2012, as compared to the same period in 2011, due primarily to:

A $32.2 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 power and fuel costs ($24.7 million) related to a slight increase in ES customer migration to third party electric suppliers and lower ES customer retail sales, lower retail transmission revenues ($12.7 million), and lower wholesale revenues ($5.3 million). These lower revenues were offset by higher revenues related to renewable energy certificates ($5.1 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 $3.6 million decrease in the portion of distribution revenues that impacts earnings due primarily to a 1.9 percent decrease in retail sales.

Partially offset by:

An increase related to the sale of oil to an external buyer ($20.8 million), resulting in a benefit to customers through lower ES rates that does not impact earnings.

A $6.5 million improvement in transmission revenues resulting from a higher level of investment in transmission infrastructure and the recovery of higher overall expenses, which are tracked and result in a related increase in revenues. The increase in expenses is

directly related to the increase in transmission plant, including costs associated with higher property taxes, depreciation and operation and maintenance expenses.

Purchased Power, Fuel and Transmission increased for the three months ended June 30, 2012, as compared to the same period in 2011, due primarily to an increase in purchased transmission costs, an increase in costs related to RECs, and an increase related to the sale of oil to an external buyer. Partially offsetting these increases was a decrease in purchased power and fuel costs, due primarily to an increase in ES customer migration to third party electric suppliers and lower ES customer retail sales.

Purchased Power, Fuel and Transmission decreased for the six months ended June 30, 2012, as compared to the same period in 2011, due primarily to a decrease in purchased power and fuel costs due primarily to an increase in ES customer migration to third party electric suppliers and lower ES customer retail sales, partially offset by an increase in purchased transmission costs, an increase in costs related to RECs and an increase related to the sale of oil to an external buyer.

Operations and Maintenance decreased for the three and six months ended June 30, 2012, as compared to the same periods in 2011, as a result of lower maintenance costs at the generation business due to less planned outage maintenance in 2012 ($8.4 million and $7.9 million, respectively).

Depreciation increased for the three and six months ended June 30, 2012, as compared to the same periods in 2011, due primarily to higher utility plant balances resulting from completed construction projects placed into service related to PSNH's capital programs.

Amortization of Regulatory Assets, Net decreased for the six months ended June 30, 2012, as compared to the same period in 2011, due primarily to a decrease in TCAM amortization ($17.6 million) and a decrease in SCRC amortization ($14 million), partially offset by an increase in ES amortization ($11.4 million).


Interest Expense
	For the Three Months Ended June 30,								For the Six Months Ended June 30,
					Increase/								Increase/
(Millions of Dollars)	2012		2011		(Decrease)		Percent		2012		2011		(Decrease)		Percent
Interest on Long-Term Debt	$	11.5	$	8.3	$	3.2	38.6	%	$	23.1	$	17.0	$	6.1	35.9	%
Interest on RRBs		0.8		1.7		(0.9)	(52.9)			1.8		3.6		(1.8)	(50.0)
Other Interest		0.5		0.4		0.1	25.0			0.7		0.3		0.4	(a)
	$	12.8	$	10.4	$	2.4	23.1	%	$	25.6	$	20.9	$	4.7	22.5	%

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

Interest Expense increased for the three and six months ended June 30, 2012, as compared to the same periods 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 June 30,								For the Six Months Ended June 30,
(Millions of Dollars)	2012		2011		Decrease		Percent		2012		2011		Decrease		Percent
Other Income, Net	$	0.5	$	4.4	$	(3.9)	(88.6)	%	$	2.6	$	8.8	$	(6.2)	(70.5)	%

Other Income, Net decreased for the three and six months ended June, 30 2012, as compared to the same periods in 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 June 30,								For the Six Months Ended June 30,
(Millions of Dollars)	2012		2011		Increase		Percent		2012		2011		Increase		Percent
Income Tax Expense	$	13.6	$	10.2	$	3.4	33.3	%	$	26.9	$	23.7	$	3.2	13.5	%

Income Tax Expense increased for the three and six months ended June 30, 2012, as compared to the same periods in 2011, due primarily to higher second quarter pre-tax earnings ($1.1 million), lower flow-through items ($1.1 million and $2.6 million, respectively), and higher state taxes and other impacts ($1.2 million and $1 million, respectively).

LIQUIDITY

PSNH had cash flows provided by operating activities of $42.5 million in the first six months of 2012, compared with operating cash flows of $130.5 million in the first six months 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, PSNH made approximately $7.7 million of 2012 cash disbursements for storm costs associated with Tropical Storm Irene and the October 2011 snowstorm and had income tax payments of $13.7 million in the first six months of 2012, compared to income tax refunds of $6.4 million in the first six months of 2011 . Offsetting the negative cash flow impacts were reduced coal and fuel inventories in the first six months of 2012 creating a positive cash flow impact of $17.7 million, as compared to reduced coal and fuel inventories in the first six months of 2011 creating a positive cash flow impact of $9.6 million. The reduction of fuel inventories in the first six months of 2012 is primarily attributable to the sale of oil to an external buyer for $20.8 million.

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 and six months ended June 30, 2012 and 2011:


			Operating Revenues and Expenses								Operating Revenues and Expenses
			For the Three Months Ended June 30,								For the Six Months Ended June 30,
(Millions of Dollars)			2012		2011		Increase/		Percent		2012		2011		Increase/		Percent
(Millions of Dollars)			2012		2011		(Decrease)		Percent		2012		2011		(Decrease)		Percent
Operating Revenues			$	106.8	$	98.4	$	8.4	8.5	%	$	220.9	$	205.1	$	15.8	7.7	%
Operating Expenses:
	Purchased Power and Transmission			32.7		38.0		(5.3)	(13.9)			73.3		83.2		(9.9)	(11.9)
	Operations and Maintenance			27.7		20.5		7.2	35.1			50.4		41.3		9.1	22.0
	Depreciation			7.0		6.6		0.4	6.1			14.7		13.0		1.7	13.1
	Amortization of Regulatory (Liabilities)/
		Assets, Net		-		1.5		(1.5)	(100.0)			(0.4)		0.7		(1.1)	(a)
	Amortization of Rate Reduction Bonds			4.4		4.1		0.3	7.3			8.8		8.2		0.6	7.3
	Energy Efficiency Programs			4.9		5.0		(0.1)	(2.0)			10.5		10.4		0.1	1.0
	Taxes Other Than Income Taxes			5.0		4.2		0.8	19.0			9.9		8.8		1.1	12.5
		Total Operating Expenses		81.7		79.9		1.8	2.3			167.2		165.6		1.6	1.0
Operating Income			$	25.1	$	18.5	$	6.6	35.7	%	$	53.7	$	39.5	$	14.2	35.9	%

(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 June 30,					For the Six Months Ended June 30,
	2012	2011	Decrease	Percent		2012	2011	Decrease	Percent
Retail Sales in GWh	870	871	(1)	(0.1)	%	1,781	1,819	(38)	(2.1)	%

WMECO's Operating Revenues increased for the three and six months ended June 30, 2012, as compared to the same periods in 2011, due primarily to:

A $12.2 million and $21.5 million, respectively, improvement in transmission revenues resulting from a higher level of investment in transmission infrastructure, primarily related to the NEEWS project, 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.

Partially offset by:

A $1.2 million and $2.3 million decrease, respectively, in the 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. Included in these amounts are pension, C&LM collections and other items that have DPU tracking mechanisms. 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.

Purchased Power and Transmission decreased for the three and six months ended June 30, 2012, as compared to the same periods in 2011, due primarily to lower purchased transmission costs.

Operations and Maintenance increased for the three and six months ended June 30, 2012, as compared to the same periods in 2011, due primarily to a bill credit to customers ($3 million) in the second quarter of 2012 as a result of the Massachusetts settlement agreement. In addition, there were higher pension costs ($1.2 million and $2.2 million, respectively), which are recovered through distribution tracking mechanisms and have no earnings impact, and higher routine distribution maintenance costs ($2.1 million and $0.7 million, respectively).


Interest Expense
	For the Three Months Ended June 30,								For the Six Months Ended June 30,
					Increase/								Increase/
(Millions of Dollars)	2012		2011		(Decrease)		Percent		2012		2011		(Decrease)		Percent
Interest on Long-Term Debt	$	5.9	$	4.7	$	1.2	25.5	%	$	11.7	$	9.5	$	2.2	23.2	%
Interest on RRBs		0.3		0.6		(0.3)	(50.0)			0.8		1.3		(0.5)	(38.5)
Other Interest		0.7		0.2		0.5	(a)			0.8		0.2		0.6	(a)
	$	6.9	$	5.5	$	1.4	25.5	%	$	13.3	$	11.0	$	2.3	20.9	%

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

Interest Expense increased for the three and six months ended June 30, 2012, as compared to the same periods in 2011, due primarily to higher Interest on Long-Term Debt resulting from a $100 million debt issuance in September 2011.


Income Tax Expense
	For the Three Months Ended June 30,								For the Six Months Ended June 30,
(Millions of Dollars)	2012		2011		Increase		Percent		2012		2011		Increase		Percent
Income Tax Expense	$	7.2	$	5.1	$	2.1	41.2	%	$	16.4	$	11.3	$	5.1	45.1	%

Income Tax Expense increased for the three and six months ended June 30, 2012, as compared to the same periods in 2011, due primarily to higher pre-tax earnings ($3.2 million and $6 million, respectively), partially offset by Massachusetts settlement agreement impacts ($1.2 million).

LIQUIDITY

WMECO had cash flows provided by operating activities of $35 million in the first six months of 2012, compared with operating cash flows of $58.1 million in the first six months of 2011 (amounts are net of RRB payments, which are included in financing activities). The reduced cash flows were due primarily to $14.7 million of 2012 cash disbursements for storm costs attributable to Tropical Storm Irene and the October 2011 snowstorm, negative cash flow impacts associated with under collections on transmission regulatory tracking mechanisms of $17.9 million in the first six months of 2012, as compared to the same period in 2011, and $3 million in bill credits to its customers associated with the Massachusetts settlement agreement.

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 37 thousand remaining MWh of supply contract volumes, net of related sales volumes.

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 June 30, 2012, NU would have been required to provide additional cash or LOCs. 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 NU's 2011 Form 10-K and in the NSTAR 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 these 2011 Form 10-Ks.

ITEM 4.

CONTROLS AND PROCEDURES

Management, on behalf of NU, CL&P, NSTAR Electric, PSNH and WMECO, evaluated the design and operation of the disclosure controls and procedures as of June 30, 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, NSTAR Electric, PSNH and WMECO are effective to ensure that information required to be disclosed by us in reports filed under the Securities Exchange Act of 1934 (i) is recorded, processed, summarized, and reported within the time periods specified in SEC rules and regulations and (ii) is accumulated and communicated to management, including the principal executive officers and principal financial officer, as appropriate to allow timely decisions regarding required disclosures.

There have been no changes in internal controls over financial reporting for NU, CL&P, NSTAR Electric, PSNH and WMECO during the quarter ended June 30, 2012, other than changes resulting from the merger with NSTAR as discussed below, that have materially affected, or are reasonably likely to materially affect, internal controls over financial reporting.

On April 10, 2012, NSTAR became a direct wholly owned subsidiary of NU. NU is currently in the process of integrating NSTAR's operations, processes, and internal controls. See Note 2, "Merger of NU and NSTAR," to the Combined Notes to the Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q for additional information regarding the merger.

PART II. OTHER INFORMATION

ITEM 1.

LEGAL PROCEEDINGS

We are parties to various material legal proceedings. We have identified these legal proceedings in Part I, Item 3, "Legal Proceedings," and elsewhere in NU's 2011 Form 10-K, NSTAR's 2011 Form 10-K and NSTAR Electric's 2011 Form 10-K, which disclosures are incorporated herein by reference. There have been no additional material legal proceedings identified and no material changes with regard to the legal proceedings previously disclosed in 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 NU's 2011 Form 10-K, NSTAR's 2011 Form 10-K and NSTAR Electric's 2011 Form 10-K, which risk factors are incorporated herein by reference. These risk factors should be considered carefully in evaluating our risk profile. Other than as set forth below, there have been no additional risk factors identified and no material changes with regard to the risk factors previously disclosed in those filings.

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

We have a significant amount of goodwill on our consolidated balance sheet. The carrying value of goodwill represents the fair value of an acquired business in excess of identifiable assets and liabilities as of the acquisition date. As of June 30, 2012, goodwill totaled $3.5 billion, of which $3.2 billion was attributable to the acquisition of NSTAR in April 2012. Total goodwill represented approximately 38 percent of our $9.1 billion of shareholders’ equity, and approximately 13 percent of our total assets of $27.5 billion. We perform an analysis of our goodwill balances to test for impairment on an annual basis or whenever events occur or circumstances change that would indicate a potential for impairment. A determination that goodwill is deemed to be impaired would result in a non-cash charge that could materially adversely affect our results of operations and total capitalization.

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 June 30, 2012.

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, CL&P, NSTAR Electric, PSNH and WMECO)

*10.1

Northeast Utilities System's Third and Restated Tax Allocation Agreement dated as of April 10, 2012

Listing of Exhibits (NU)

*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 August 7, 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 August 7, 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 August 7, 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

Listing of Exhibits (CL&P)

*12

Ratio of Earnings to Fixed Charges

*31

Certification of Leon J. Olivier, Chief Executive Officer of The Connecticut Light and Power Company, required by Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated August 7, 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 August 7, 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 August 7, 2012

Listing of Exhibits (NSTAR Electric)

*12

Ratio of Earnings to Fixed Charges

*31

Certification of Leon J. Olivier, Chief Executive Officer of NSTAR Electric Company, required by Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated August 7, 2012

*31.1

Certification of James J. Judge, Executive Vice President and Chief Financial Officer of NSTAR Electric Company, required by Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated August 7, 2012

*32

Certification of Leon J. Olivier, Chief Executive Officer of NSTAR Electric Company and James J. Judge, Executive Vice President and Chief Financial Officer of NSTAR Electric Company, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, dated August 7, 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 August 7, 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 August 7, 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 August 7, 2012

Listing of Exhibits (WMECO)

*12

Ratio of Earnings to Fixed Charges

*31

Certification of Leon J. Olivier, Chief Executive Officer of Western Massachusetts Electric Company, required by Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated August 7, 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 August 7, 2012

*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 August 7, 2012

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: August 7, 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: August 7, 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.


		NSTAR ELECTRIC COMPANY
		(Registrant)




Date: August 7, 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.


		PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE
		(Registrant)




Date: August 7, 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: August 7, 2012	By	/s/ Jay S. Buth
		Jay S. Buth
		Vice President, Controller and
		Chief Accounting Officer
		(Principal Accounting Officer)

EXHIBIT 10.1

THIRD AMENDED AND RESTATED

TAX ALLOCATION AGREEMENT

This Third Amended and Restated Tax Allocation Agreement, dated as of April 10, 2012, is made by and among Northeast Utilities (the "Parent Company") and The Connecticut Light and Power Company, Western Massachusetts Electric Company, HWP Company (f/n/a Holyoke Water Power Company), Northeast Utilities Service Company, Northeast Nuclear Energy Company, The Rocky River Realty Company, Public Service Company of New Hampshire, Properties, Inc., North Atlantic Energy Corporation, North Atlantic Energy Service Corporation, Select Energy Contracting, Inc., NU Enterprises, Inc., Northeast Generation Services Company, ES Boulos Company, NGS Mechanical, Inc., Mode 1 Communications, Inc., Select Energy, Inc., Yankee Energy System, Inc., Yankee Gas Services Company, Yankee Energy Financial Services Company, Yankee Energy Services Company, Renewable Properties, Inc., CL&P Funding LLC, The Connecticut Steam Company, Electric Power Incorporated, The Nutmeg Power Company, PSNH Funding LLC 2, PSNH Funding LLC, WMECO Funding LLC, NU Transmission Ventures, Inc., Northern Pass Transmission LLC, NSTAR LLC (f/n/a NU Holding Energy 2 LLC), NSTAR Electric Company, Harbor Electric Energy Company, BEC Funding II LLC, CEC Funding LLC, NSTAR Gas Company, NSTAR Electric and Gas Corporation, Advanced Energy Systems Inc., Hopkinton LNG Corp., NSTAR Communications, Inc. and any other entities that become a member of the Parent Company's affiliated group and execute a duplicate copy of this Agreement or consent to be included in the Parent Company's consolidated federal income tax return (hereinafter collectively "subsidiaries" and singly "subsidiary"). These subsidiaries join in the annual filing of a consolidated federal income tax return with the Parent Company.

For purposes of this Agreement, the following terms shall have the meanings specified below:

“Associate” means any member company of the Parent Company’s affiliated group that is included in the Parent Company’s consolidated federal income tax return, including the Parent Company.

“Associates” means all of the member companies of the Parent Company’s affiliated group that are included in the Parent Company’s consolidated federal income tax return, including the Parent Company.

“ Code ” means the Internal Revenue Code of 1986, as amended from time to time (and any corresponding provisions of succeeding law).

"Consolidated tax" means the aggregate tax liability for a tax year, being the tax shown on the consolidated return and any adjustments thereto thereafter determined. The consolidated tax will be the refund if the consolidated return shows a negative tax.

"Corporate tax credit" is a negative separate return tax of an Associate for a tax year, equal to the amount by which the consolidated tax is reduced by including a net corporate

taxable loss or other net tax benefit of such associate company in the consolidated tax return.

"Corporate Taxable Income" is the income or loss of an Associate for a tax year, computed as though such company had filed a separate return on the same basis as used in the consolidated return, except that dividend income from Associates shall be disregarded, and other intercompany transactions eliminated in the consolidated return shall be given appropriate effect. It shall be further adjusted to allow for applicable rights accrued to the Associate, on the basis of other tax years, but carryovers or carrybacks shall not be taken into account if the Associate has been paid a corporate tax credit therefor. Corporate Taxable Income shall be adjusted in an appropriate and reasonable manner to reflect deductions of an Associate that are unable to be used due to reductions, limitations, phase-outs and expirations imposed by the Code or the Regulations by the consolidated tax group. If an Associate is a member of the Parent Company consolidated tax group for only part of a tax year, that period will be deemed to be its tax year for all purposes. Basis shall be determined under Treas. Reg. Section 1.1502-31 or 1.1502-32 and earnings and profits shall be determined under Treas. Reg. Section 1.1502-33. Items attributable to a consolidated return year but not allowable on a separate company basis shall be excluded in determining Corporate Taxable Income to the extent such items were previously taken into account to reduce consolidated taxable income.

“Regulations” mean the Income Tax Regulations, including Temporary Regulations, promulgated under the Code, as such regulations are amended from time to time.

"Separate return tax" is the tax on the Corporate Taxable Income of an Associate computed as though such company were not a member of a consolidated group.

In consideration of the mutual benefits and obligations provided for herein, the parties to this Agreement hereby agree that the consolidated tax of the Associates shall be allocated as follows:

1. PARENT COMPANY. Except as expressly set forth herein, the Parent Company shall be treated in the same manner as the other Associates for purposes of this Agreement.

2. ALLOCATION OF CONSOLIDATED FEDERAL TAX. The consolidated tax, exclusive of capital gains taxes (see paragraph (3)), and the alternative minimum tax (see paragraph (7)), and before the application or recapture of any credits (see paragraph (4)) and the results of any special benefits (see paragraph (5)), shall be allocated among the Associates based on their Corporate Taxable Income, computed without regard to net capital gains or losses. Subject to the limitation provided in paragraph (10), such consolidated tax allocated to an Associate, which may be either positive or negative, shall be equal to the Corporate Taxable Income of the Associate (after elimination of capital gains and losses) multiplied times the highest effective corporate federal income tax rate set forth in Section 11 of the Code. However, no Associate shall receive a negative allocation greater (in absolute value) than the amount by which its loss has reduced the consolidated tax liability. Conversely, an Associate shall receive a negative allocation for any loss or deduction it cannot use currently to the extent such loss or deduction reduces

the consolidated tax liability. If the consolidated tax liability is greater than the aggregate tax on the corporate taxable income of the Associates ("separate return tax"), then no subsidiary shall receive an allocation greater than its separate return tax, and the Parent Company shall be liable for the excess of the consolidated tax over the sum of the separate return taxes of the subsidiaries, subject to recovery in later years from subsequent consolidated tax benefits.

3. ALLOCATION OF CAPITAL GAINS TAXES. The portion of the consolidated tax attributable to net capital gains and losses shall be allocated directly to the Associate giving rise to such items. The effects of netting capital gains and losses in the current year shall follow the principles of paragraph (2). The effects of capital loss carrybacks or carryforwards shall follow the principles of paragraph (6).

4. ALLOCATION OF GENERAL BUSINESS CREDITS. General business credits arising in a particular year shall be allocated among the Associates giving rise to such credits by multiplying the amount of consolidated general business credits for such year utilized by a fraction, the numerator of which is the amount of general business credit of the Associate for such year and the denominator of which is the total amount of general business credit of all Associates for such year. If the consolidated group is in a credit carryforward situation, the utilized credit shall be allocated based on the vintages that comprise the utilized credit. For purposes of the consolidated return, the credits utilized are determined on a first-in first-out basis with all credits generated by all subsidiaries in the earliest year utilized first before credits generated in a subsequent year can be utilized. For purposes of allocating the credits pursuant to this agreement, and in accordance with the separate return limitation of paragraph (10), the credits utilized shall be determined on a first-in first-out basis with the credits generated by Associates allocated positive taxes in paragraphs (2) and (3) utilized first, for all available vintages, before credits generated by Associates allocated negative taxes in paragraphs (2) and (3) are utilized. If the vintages of credits utilized pursuant to this agreement differ from those utilized according to the consolidated return for an Associate, then the vintages of credits utilized pursuant to this agreement shall be exchanged among the affected Associates. General business credits that are lost due to reductions, limitations and expirations imposed by the Code or the regulations thereunder shall be allocated in an appropriate and reasonable manner.

5. ALLOCATION OF SPECIAL BENEFITS. Any special benefits, such as the effects of Section 1341 of the Code, shall be allocated directly to the subsidiaries giving rise to them.

6. ALLOCATION OF A NET OPERATING LOSS. Should the Parent Company's affiliated group generate a net operating loss for a tax year, each Associate shall first receive an allocation of consolidated tax, which may be either positive or negative, as provided in paragraph (2); provided, however, a negative allocation of the consolidated tax shall be made to an Associate only to the extent that corporate taxable income of such Associate reduces consolidated tax for such tax year. The current consolidated net operating loss shall then be apportioned to each Associate with a taxable loss and carried back or forward to year(s) when the consolidated net operating loss can be utilized. The consolidated reduction in tax resulting from the carryback or carryforward of the net operating loss shall be apportioned to each loss Associate in accordance with

paragraphs (2) through (5). For purposes of the consolidated return, the utilization of net operating losses carried back or carried over is determined on a first-in first-out basis with all net operating losses generated by all Associates in the earliest year utilized first before net operating losses generated in a subsequent year can be utilized. For purposes of allocating the net operating losses pursuant to this Agreement, and in accordance with the separate return limitation of Paragraph (10), the net operating losses utilized shall be determined on a first-in first-out basis with the net operating losses generated by Associates allocated positive taxes in Paragraphs (2) and (3) utilized first, for all available vintages, before net operating losses generated by Associates allocated negative taxes in Paragraphs (2) and (3) are utilized. If the vintages of net operating losses utilized pursuant to this Agreement differ from those utilized according to the consolidated return for an Associate , then the vintages of net operating losses utilized pursuant to this Agreement shall be exchanged among the affected Associates. Net operating loss carryovers that are lost due to reductions, limitations and expirations imposed by the Code or the Regulations shall be allocated in an appropriate and reasonable manner.

7. ALLOCATION OF ALTERNATIVE MINIMUM TAX OR CREDIT. Any portion of the consolidated tax that is attributable to alternative minimum tax ("Consolidated AMT") shall be allocated in a positive amount to each subsidiary with "tentative minimum tax," as defined in Section 55(b)(1) of the Code (determined following the principles used to compute each Associate’s separate return tax), which for purposes of this Agreement can be positive or negative ("Separate Return Tentative Minimum Tax"), in excess of the "regular tax," as defined in Section 55(c) of the Code (determined following the principles used to compute each Associate’s separate return tax), allocated to such Associate in accordance with this Agreement (except paragraph (10)), which for purposes of this Agreement can be positive or negative ("Separate Return Regular Tax"). Consolidated AMT shall be allocated to each such Associate by multiplying Consolidated AMT by a fraction the numerator of which is the amount by which the Associate’s Separate Return Tentative Minimum Tax exceeds such Associate’s Separate Return Regular Tax and the denominator of which is the sum of the amounts by which the Separate Return Tentative Minimum Tax of the Associates to which an allocation of Consolidated AMT is made exceeds the Separate Return Regular Tax allocated to such Associates. If the regular tax portion of the consolidated tax is reduced by reason of a "minimum tax credit," as defined in Section 53 of the Code, the benefit of such minimum tax credit shall be allocated to the Associates that (by having an alternative minimum tax liability allocated to them in a prior year) generated such minimum tax credit, with the earliest liabilities being allocated such minimum credit first. The allocation of any "alternative tax net operating loss deduction," as defined by Section 56(d) of the Code, shall follow the principles of paragraph (6).

8. OTHER FEDERAL TAXES, BENEFITS AND CREDITS. Taxes, tax benefits and credits against consolidated tax that are not specifically addressed herein and for which allocation under paragraph (2) is not appropriate shall be allocated following the principles set forth in paragraphs (3) through (7) in order to allocate the material effects of such tax, tax benefit or credit to the Associate to which it is applicable.

9. PAYMENTS FOR ALLOCATIONS. Any Associate with a net positive allocation shall pay the Parent Company the net amount allocated in the amounts and on the dates indicated by the Parent Company, while any Associate with a net negative allocation

shall receive payment from the Parent Company in the amount of its negative allocation on the same dates indicated by the Parent Company. The payment made to an Associate with a negative allocation should equal the amount by which the consolidated tax is reduced by including the Associate's net corporate tax loss in the consolidated tax return. The Parent Company shall pay to the Internal Revenue Service the consolidated group's net current federal income tax liability from the net of the receipts and payments.

10. SEPARATE RETURN LIMITATION. No subsidiary shall be allocated a federal income tax which is greater than the federal income tax computed as if such subsidiary had always filed a separate return. If the federal income tax otherwise allocated to a subsidiary under this Agreement is greater than the federal income tax computed as if such subsidiary had always filed a separate return, the Parent Company shall be liable for such excess, subject to recovery in later years from subsequent consolidated tax benefits.

11. STATE TAX LIABILITIES.

(a) Generally any current state income tax liability or benefit associated with a state income tax return involving more than one subsidiary shall be allocated to such subsidiaries doing business in such state following the principles set forth herein for current federal income taxes. For purposes of allocating any current state income tax liability that is determined on the basis of unitary reporting and that is associated with a state income tax return involving more than one subsidiary ("Unitary Tax Liability”), any such current Unitary Tax Liability shall be allocated, first, to subsidiaries with a positive income tax liability with respect to such state determined following the principles used to compile the subsidiary’s separate return tax (“Separate Unitary Return Tax”) in an amount equal to each such subsidiary’s Separate Unitary Return Tax. The Unitary Tax Difference is the current Unitary Tax Liability less the aggregate Separate Unitary Return Tax of the subsidiaries with positive Separate Unitary Return Tax. If the Unitary Tax Difference is positive, then that amount shall be allocated to the Parent Company. If the Unitary Tax Difference is negative, then that amount shall be allocated in a negative amount to each subsidiary that provided tax credits used by the group to lower the Unitary Tax Liability greater than the amount of tax credits used in calculating the subsidiaries Separate Unitary Return Tax, then in a negative amount to each subsidiary having negative Separate Unitary Return Tax in an amount equal to the lesser of the Unitary Tax Difference or the sum of the Separate Unitary Return Tax of all subsidiaries with negative Separate Unitary Return Tax multiplied by a fraction (A) the numerator of which is the Separate Unitary Return Tax of the subsidiary and (B) the denominator of which is the sum of the Separate Unitary Return Tax of the subsidiaries having negative Separate Unitary Return Tax, and finally allocated in a negative amount to the Parent Company.

(b) Payments of positive and negative allocations of state income tax liabilities and of net current state income tax liabilities of the Parent Company and the subsidiaries shall follow the principles set forth in paragraph (9).

12. FILING TAX RETURNS. The Parent Company shall prepare and file the consolidated federal income tax return for the subsidiaries that are parties to this Agreement. The Parent Company shall act as the sole agent for each subsidiary with respect to the payment of any liability shown on the federal income tax return and for all

other purposes required by Treas. Reg. 1.1502-77(a). The Parent Company or designated subsidiary may act as an agent for each subsidiary doing business in a state with respect to the payment of any liability shown on the state income tax returns of such state.

13. ADJUSTMENT OF TAX LIABILITY. In the event that the consolidated federal or state income tax liability for any year is redetermined subsequent to the allocation of the consolidated tax liability reported for that tax year, the redetermined tax liability shall be allocated pursuant to this Agreement as if the adjustments and modifications related to the redetermination had been a part of the original return. In the case of a negotiated adjustment not involving an item-by-item modification of the consolidated return, the amount of the adjustment shall be distributed in an appropriate and reasonable manner. Any interest or penalties associated with the underpayment or overpayment of tax shall be allocated based on the allocation of the underlying underpayment or overpayment of tax.

14. EFFECTIVE DATE. This Agreement amends and restates the prior Amended and Restated Tax Allocation Agreement relating to the allocation of federal and state income tax liability dated January 1, 1990, as amended by the First Amendment thereto dated October 26, 1998 and the Second Amendment thereto dated March 1, 2000, and as further amended by the Second Amended and Restated Tax Allocation Agreement dated September 21, 2005. This Agreement shall be effective for allocation of the current federal and state income tax liabilities of the consolidated group for taxable years beginning on or after January 1, 2012 and all subsequent years until this Agreement is further amended in writing by each such company which is or becomes a party to this Agreement. For any party to this Agreement that became a member of the Parent Company's affiliated group after January 1, 2012, this Agreement shall be effective as of the date such subsidiary became a member of the affiliated group. If at any time any other company becomes a member of the Parent Company's affiliated group, the parties hereto agree that such new member may become a party to this Agreement by (i) executing a duplicate copy of this Agreement or (ii) consenting to be included in a consolidated federal income tax return that includes the Parent Company. If at any time any company ceases to be a member of the Parent Company's affiliated group, such company shall no longer be a party to this Agreement, but such company shall continue to be bound by this Agreement as to the taxable year in which such company leaves the Parent Company's affiliated group and all prior taxable years in which such company was a member of the Parent Company's affiliated group.

15. REGULATORY FILINGS. The Parent Company will make any necessary filings with any regulatory commissions that the Parent Company deems necessary or appropriate.

16. GOVERNING LAW. This Agreement shall be construed and enforced in accordance with the laws of the State of Connecticut.

17. COUNTERPARTS. This Agreement may be executed in one or more counterparts all of which taken together shall constitute one and the same instrument.

18. MISCELLANEOUS. This Agreement contains the complete agreement among the parties and supersedes any prior understandings, agreements or representations by or

among the parties, written or oral, which may have related to the subject matter hereof in any way. No term or provision of this Agreement shall be construed to confer a benefit upon, or grant a privilege or right to, any person other than the parties hereto.

[ Signature Page to follow ]

The above procedures for apportioning the consolidated annual net current federal and state income tax liability and expense of Northeast Utilities and its subsidiaries have been duly authorized and agreed to by each of the below listed members of the consolidated group as evidenced by the signature of a duly authorized officer of each company:

NORTHEAST UTILITIES

THE CONNECTICUT LIGHT AND POWER COMPANY

WESTERN MASSACHUSETTS ELECTRIC COMPANY

HWP COMPANY (f/n/a HOLYOKE WATER POWER COMPANY)

NORTHEAST UTILITIES SERVICE COMPANY

NORTHEAST NUCLEAR ENERGY COMPANY

THE ROCKY RIVER REALTY COMPANY

PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE

NORTH ATLANTIC ENERGY CORPORATION

NORTH ATLANTIC ENERGY SERVICE CORPORATION

PROPERTIES, INC.

SELECT ENERGY CONTRACTING, INC.

NU ENTERPRISES, INC.

NORTHEAST GENERATION SERVICES COMPANY

E. S. BOULOS COMPANY

NGS MECHANICAL, INC.

MODE 1 COMMUNICATIONS, INC.

SELECT ENERGY, INC.

YANKEE ENERGY SYSTEM, INC.

YANKEE GAS SERVICES COMPANY

YANKEE ENERGY FINANCIAL SERVICES COMPANY

YANKEE ENERGY SERVICES COMPANY

RENEWABLE PROPERTIES,INC.

CL&P FUNDING LLC

THE CONNECTICUT STEAM COMPANY

ELECTRIC POWER INCORPORATED

THE NUTMEG POWER COMPANY

PSNH FUNDING LLC2

PSNH FUNDING LLC

WMECO FUNDING LLC

NU TRANSMISSION VENTURES, INC.

NORTHERN PASS TRANSMISSION LLC

NSTAR LLC (f/n/a NU HOLDING ENERGY 2 LLC)

NSTAR ELECTRIC COMPANY

HARBOR ELECTRIC ENERGY COMPANY

BEC FUNDING II LLC

CEC FUNDING LLC

NSTAR GAS COMPANY

NSTAR ELECTRIC AND GAS CORPORATION

ADVANCED ENERGY SYSTEMS, INC.

HOPKINTON LNG CORP.

NSTAR COMMUNICATIONS, INC.

By: /S/ JAY BUTH

Name: Jay Buth

Title: Vice President, Controller and

Chief Accounting Officer

Northeast Utilities Service Company,

as Agent for the above Companies


Northeast Utilities												Exhibit 12
Ratio of Earnings to Fixed Charges
(Unaudited)

(Thousands of Dollars)		Six Months
		Ended	For the Years Ended December 31,
		June 30, 2012		2011		2010		2009		2008		2007
Earnings, as defined:
Net income	$	146,974	$	400,513	$	394,107	$	335,592	$	266,387	$	251,455
Income tax expense		82,019		170,953		210,409		179,947		105,661		109,420
Equity in earnings of regional nuclear
generating and transmission companies		(584)		(671)		(1,429)		(1,762)		(1,637)		(3,983)
Dividends received from regional equity investees		677		940		1,488		3,794		1,017		4,542
Fixed charges, as below		167,823		275,948		263,393		296,764		304,374		275,611
Less: Interest capitalized (including AFUDC)		(2,863)		(11,758)		(10,165)		(5,929)		(17,797)		(17,568)
Less: Preferred dividend security requirements of
consolidated subsidiaries		(5,448)		(9,265)		(10,170)		(9,265)		(9,265)		(9,265)
Total earnings, as defined	$	388,598	$	826,660	$	847,633	$	799,141	$	648,740	$	610,212

Fixed charges, as defined:
Interest on long-term debt (a)	$	146,892	$	231,630	$	231,089	$	224,712	$	193,883	$	162,841
Interest on rate reduction bonds		3,487		8,611		20,573		36,524		50,231		61,580
Other interest (b)		5,116		10,184		(14,371)		12,401		25,031		15,824
Rental interest factor		4,017		4,500		5,767		7,933		8,167		8,533
Preferred dividend security requirements of
consolidated subsidiaries		5,448		9,265		10,170		9,265		9,265		9,265
Interest capitalized (including AFUDC)		2,863		11,758		10,165		5,929		17,797		17,568
Total fixed charges, as defined	$	167,823	$	275,948	$	263,393	$	296,764	$	304,374	$	275,611

Ratio of Earnings to Fixed Charges		2.32		3.00		3.22		2.69		2.13		2.21


(a) Interest on long-term debt includes amortized premiums, discounts and capitalized expenses related to indebtedness.

(b) For all periods presented, other interest includes interest related to accounting for uncertain tax positions.

Exhibit 31

CERTIFICATION PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Thomas J. May, certify that:

I have reviewed this quarterly report on Form 10-Q of Northeast Utilities (the registrant);

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)

Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)

Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)

Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)

Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

(a)

All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

(b)

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: August 7, 2012


/s/	Thomas J. May
	Thomas J. May
	President and Chief Executive Officer
	(Principal Executive Officer)

Exhibit 31.1

CERTIFICATION PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, James J. Judge, certify that:

I have reviewed this quarterly report on Form 10-Q of Northeast Utilities (the registrant);

(a)

(b)

(c)

(d)

(a)

(b)

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: August 7, 2012


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

Exhibit 32

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the quarterly report of Northeast Utilities (the registrant) on Form 10-Q for the period ending June 30, 2012 as filed with the Securities and Exchange Commission (the Report), we, Thomas J. May, President and Chief Executive Officer of the registrant, and James J. Judge, Executive Vice President and Chief Financial Officer of the registrant, certify, pursuant to 18 U.S.C. Sec. 1350, as adopted pursuant to Sec. 906 of the Sarbanes-Oxley Act of 2002, that:

The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

The information contained in the Report fairly presents, in all material respects, the financial condition and result of operations of the registrant.


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


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

Date: August 7, 2012

A signed original of this written statement required by Section 906, or other document authenticating, acknowledging, or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to the registrant and will be retained by the registrant and furnished to the Securities and Exchange Commission or its staff upon request.


The Connecticut Light and Power Company												Exhibit 12
Ratio of Earnings to Fixed Charges
(Unaudited)

(Thousands of Dollars)		Six Months
		Ended	For the Years Ended December 31,
		June 30, 2012		2011		2010		2009		2008		2007
Earnings, as defined:
Net income	$	60,918	$	250,164	$	244,143	$	216,316	$	191,158	$	133,564
Income tax expense		29,796		90,033		132,438		118,847		77,852		52,353
Equity in earnings of regional nuclear
generating companies		(20)		(16)		(134)		(282)		(366)		(1,901)
Dividends received from regional equity investees		-		-		440		1,520		-		2,596
Fixed charges, as below		70,923		140,311		145,297		163,887		165,170		155,557
Less: Interest capitalized (including AFUDC)		(1,511)		(3,317)		(2,726)		(2,203)		(12,991)		(10,924)
Total earnings, as defined	$	160,106	$	477,175	$	519,458	$	498,085	$	420,823	$	331,245

Fixed charges, as defined:
Interest on long-term debt (a)	$	63,218	$	131,918	$	134,553	$	133,422	$	104,954	$	84,292
Interest on rate reduction bonds		-		-		7,542		19,061		29,129		37,728
Other interest (b)		4,060		809		(4,357)		3,334		12,163		16,413
Rental interest factor		2,134		4,267		4,833		5,867		5,933		6,200
Interest capitalized (including AFUDC)		1,511		3,317		2,726		2,203		12,991		10,924
Total fixed charges, as defined	$	70,923	$	140,311	$	145,297	$	163,887	$	165,170	$	155,557


Ratio of Earnings to Fixed Charges		2.26		3.40		3.58		3.04		2.55		2.13


(a) Interest on long-term debt includes amortized premiums, discounts and capitalized expenses related to indebtedness.

(b) For all periods presented, other interest includes interest related to accounting for uncertain tax positions.

E xhibit 31

CERTIFICATION PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Leon J. Olivier, certify that:

I have reviewed this quarterly report on Form 10-Q of The Connecticut Light and Power Company (the registrant);

(a)

Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiary, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)

(c)

(d)

(a)

(b)

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: August 7, 2012


/s/	Leon J. Olivier
	Leon J. Olivier
	Chief Executive Officer
	(Principal Executive Officer)

Exhibit 31.1

CERTIFICATION PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, James J. Judge, certify that:

I have reviewed this quarterly report on Form 10-Q of The Connecticut Light and Power Company (the registrant);

(a)

Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiary, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)

(c)

(d)

(a)

(b)

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: August 7, 2012


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

Exhibit 32

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the quarterly report of The Connecticut Light and Power Company (the registrant) on Form 10-Q for the period ending June 30, 2012 as filed with the Securities and Exchange Commission (the Report), we, Leon J. Olivier, Chief Executive Officer of the registrant, and James J. Judge, Executive Vice President and Chief Financial Officer of the registrant, certify, pursuant to 18 U.S.C. Sec. 1350, as adopted pursuant to Sec. 906 of the Sarbanes-Oxley Act of 2002, that:

The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

The information contained in the Report fairly presents, in all material respects, the financial condition and result of operations of the registrant.


/s/	Leon J. Olivier
	Leon J. Olivier
	Chief Executive Officer


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

Date: August 7, 2012


NSTAR Electric Company		Exhibit 12
Ratio of Earnings to Fixed Charges
(Unaudited)

(Thousands of Dollars)		Six Months
		Ended
		June 30, 2012
Earnings, as defined:
Net income	$	49,422
Income tax expense		32,847
Equity in earnings of regional nuclear
generating companies		(199)
Dividends received from regional equity investees		264
Fixed charges, as below		38,519
Less: Interest capitalized (including AFUDC)		171
Total earnings, as defined	$	121,024

Fixed charges, as defined:
Interest on long-term debt (a)	$	44,567
Interest on rate reduction bonds		2,253
Other interest		(11,433)
Rental interest factor		3,303
Interest capitalized (including AFUDC)		(171)
Total fixed charges, as defined	$	38,519


Ratio of Earnings to Fixed Charges		3.14


(a) Interest on long-term debt includes amortized premiums, discounts and capitalized expenses related to indebtedness.

E xhibit 31

CERTIFICATION PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Leon J. Olivier, certify that:

I have reviewed this quarterly report on Form 10-Q of NSTAR Electric Company (the registrant);

(a)

(b)

(c)

(d)

(a)

(b)

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: August 7, 2012


/s/	Leon J. Olivier
	Leon J. Olivier
	Chief Executive Officer
	(Principal Executive Officer)

Exhibit 31.1

CERTIFICATION PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, James J. Judge, certify that:

I have reviewed this quarterly report on Form 10-Q of NSTAR Electric Company (the registrant);

(a)

(b)

(c)

(d)

(a)

(b)

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: August 7, 2012


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

Exhibit 32

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the quarterly report of NSTAR Electric Company (the registrant) on Form 10-Q for the period ending June 30, 2012 as filed with the Securities and Exchange Commission (the Report), we, Leon J. Olivier, Chief Executive Officer of the registrant, and James J. Judge, Executive Vice President and Chief Financial Officer of the registrant, certify, pursuant to 18 U.S.C. Sec. 1350, as adopted pursuant to Sec. 906 of the Sarbanes-Oxley Act of 2002, that:

The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

The information contained in the Report fairly presents, in all material respects, the financial condition and result of operations of the registrant.


/s/	Leon J. Olivier
	Leon J. Olivier
	Chief Executive Officer


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

Date: August 7, 2012


Public Service Company of New Hampshire												Exhibit 12
Ratio of Earnings to Fixed Charges
(Unaudited)

(Thousands of Dollars)		Six Months
		Ended	For the Years Ended December 31,
		June 30, 2012		2011		2010		2009		2008		2007
Earnings, as defined:
Net income	$	42,494	$	100,267	$	90,067	$	65,570	$	58,067	$	54,434
Income tax expense		26,931		49,945		50,801		31,990		21,996		22,794
Equity in earnings of regional nuclear
generating companies		(4)		(7)		(23)		(50)		(62)		(343)
Dividends received from regional equity investees		-		-		80		220		-		521
Fixed charges, as below		26,838		52,111		54,721		51,227		54,597		50,637
Less: Interest capitalized (including AFUDC)		(791)		(7,064)		(6,621)		(3,138)		(2,967)		(2,985)
Total earnings, as defined	$	95,468	$	195,252	$	189,025	$	145,819	$	131,631	$	125,058

Fixed charges, as defined:
Interest on long-term debt (a)	$	23,103	$	36,832	$	36,220	$	33,045	$	32,655	$	26,029
Interest on rate reduction bonds		1,802		6,276		9,660		13,128		15,969		18,013
Other interest (b)		692		1,039		1,187		316		1,539		2,243
Rental interest factor		450		900		1,033		1,600		1,467		1,367
Interest capitalized (including AFUDC)		791		7,064		6,621		3,138		2,967		2,985
Total fixed charges, as defined	$	26,838	$	52,111	$	54,721	$	51,227	$	54,597	$	50,637


Ratio of Earnings to Fixed Charges		3.56		3.75		3.45		2.85		2.41		2.47


(a) Interest on long-term debt includes amortized premiums, discounts and capitalized expenses related to indebtedness.

(b) For the years ended December 31, 2011, 2010 and 2009, other interest includes interest related to accounting for uncertain tax positions.

Exhibit 31

CERTIFICATION PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Leon J. Olivier, certify that:

I have reviewed this quarterly report on Form 10-Q of Public Service Company of New Hampshire (the registrant);

(a)

(b)

(c)

(d)

(a)

(b)

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: August 7, 2012


/s/	Leon J. Olivier
	Leon J. Olivier
	Chief Executive Officer
	(Principal Executive Officer)

Exhibit 31.1

CERTIFICATION PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, James J. Judge, certify that:

I have reviewed this quarterly report on Form 10-Q of Public Service Company of New Hampshire (the registrant);

(a)

(b)

(c)

(d)

(a)

(b)

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: August 7, 2012


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

Exhibit 32

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the quarterly report of Public Service Company of New Hampshire (the registrant) on Form 10-Q for the period ending June 30, 2012 as filed with the Securities and Exchange Commission (the Report), we, Leon J. Olivier, Chief Executive Officer of the registrant, and James J. Judge, Executive Vice President and Chief Financial Officer of the registrant, certify, pursuant to 18 U.S.C. Sec. 1350, as adopted pursuant to Sec. 906 of the Sarbanes-Oxley Act of 2002, that:

The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

The information contained in the Report fairly presents, in all material respects, the financial condition and result of operations of the registrant.


/s/	Leon J. Olivier
	Leon J. Olivier
	Chief Executive Officer


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

Date: August 7, 2012


Western Massachusetts Electric Company												Exhibit 12
Ratio of Earnings to Fixed Charges
(Unaudited)

(Thousands of Dollars)		Six Months
		Ended	For the Years Ended December 31,
		June 30, 2012		2011		2010		2009		2008		2007
Earnings, as defined:
Net income	$	25,324	$	43,054	$	23,090	$	26,196	$	18,330	$	23,604
Income tax expense		16,408		23,186		16,325		14,923		10,545		14,586
Equity in earnings of regional nuclear
generating companies		(5)		(4)		(36)		(78)		(101)		(526)
Dividends received from regional equity investees		-		-		120		419		-		701
Fixed charges, as below		14,008		25,079		23,042		20,614		21,910		22,162
Less: Interest capitalized (including AFUDC)		(277)		(534)		(336)		(195)		(1,010)		(983)
Total earnings, as defined	$	55,458	$	90,781	$	62,205	$	61,879	$	49,674	$	59,544

Fixed charges, as defined:
Interest on long-term debt (a)	$	11,671	$	20,023	$	17,988	$	14,074	$	13,244	$	11,577
Interest on rate reduction bonds		757		2,335		3,372		4,335		5,133		5,839
Other interest (b)		836		1,254		479		877		1,256		2,430
Rental interest factor		467		933		867		1,133		1,267		1,333
Interest capitalized (including AFUDC)		277		534		336		195		1,010		983
Total fixed charges, as defined	$	14,008	$	25,079	$	23,042	$	20,614	$	21,910	$	22,162


Ratio of Earnings to Fixed Charges		3.96		3.62		2.70		3.00		2.27		2.69


(a) Interest on long-term debt includes amortized premiums, discounts and capitalized expenses related to indebtedness.

(b) For the years ended December 31, 2009 and 2008, other interest includes interest related to accounting for uncertain tax positions.

Exhibit 31

CERTIFICATION PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Leon J. Olivier, certify that:

I have reviewed this quarterly report on Form 10-Q of Western Massachusetts Electric Company (the registrant);

(a)

Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiary, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)

(c)

(d)

(a)

(b)

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: August 7, 2012


/s/	Leon J. Olivier
	Leon J. Olivier
	Chief Executive Officer
	(Principal Executive Officer)

Exhibit 31.1

CERTIFICATION PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, James J. Judge, certify that:

I have reviewed this quarterly report on Form 10-Q of Western Massachusetts Electric Company (the registrant);

(a)

Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiary, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)

(c)

(d)

(a)

(b)

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: August 7, 2012


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

Exhibit 32

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with this quarterly report of Western Massachusetts Electric Company (the registrant) on Form 10-Q for the period ending June 30, 2012 as filed with the Securities and Exchange Commission (the Report), we, Leon J. Olivier, Chief Executive Officer of the registrant, and James J. Judge, Executive Vice President and Chief Financial Officer of the registrant, certify, pursuant to 18 U.S.C. Sec. 1350, as adopted pursuant to Sec. 906 of the Sarbanes-Oxley Act of 2002, that:

The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

The information contained in the Report fairly presents, in all material respects, the financial condition and result of operations of the registrant.


/s/	Leon J. Olivier
	Leon J. Olivier
	Chief Executive Officer


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

Date: August 7, 2012