The Connecticut Light and Power Company 10Q 2012 Q3 Quarterly report

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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 EndedSeptember 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 October 31, 2012
Northeast Utilities Common shares, $5.00 par value	313,943,203 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); also the term used for NSTAR LLC and its subsidiaries
NSTAR Electric	NSTAR Electric Company
NSTAR Electric & Gas	NSTAR Electric & Gas Corporation, a Northeast Utilities service company
NSTAR Gas	NSTAR Gas Company
NSTAR LLC	Post-merger parent company of NSTAR Electric, NSTAR Gas and other subsidiaries, and successor to NSTAR
NU Enterprises	NU Enterprises, Inc., the parent company of Select Energy, NGS, NGS Mechanical, Select Energy Contracting, Inc. and E.S. Boulos Company
NU or the Company	Northeast Utilities and subsidiaries
NU parent and other companies	NU parent and other companies is comprised of NU parent, NSTAR LLC, NSTAR Electric & Gas, NUSCO and other subsidiaries, including NU Enterprises, NSTAR Communications, Inc., HWP, RRR (a real estate subsidiary), the non-energy-related subsidiaries of Yankee (Yankee Energy Services Company and Yankee Energy Financial Services Company), and the consolidated operations of CYAPC and YAEC
NUSCO	Northeast Utilities Service Company
NUTV	NU Transmission Ventures, Inc., the parent company of NPT and Renewable Properties, Inc.
PSNH	Public Service Company of New Hampshire
Regulated companies	NU's Regulated companies, comprised of the electric distribution and transmission businesses of CL&P, NSTAR Electric, PSNH, and WMECO, the natural gas distribution businesses of Yankee Gas and NSTAR Gas, the generation activities of PSNH and WMECO, and NPT
RRR	The Rocky River Realty Company
Select Energy	Select Energy, Inc.
WMECO	Western Massachusetts Electric Company
YAEC	Yankee Atomic Electric Company
Yankee	Yankee Energy System, Inc.
Yankee Companies	CYAPC, YAEC and MYAPC
Yankee Gas	Yankee Gas 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 Share Purchase Plan
Fitch	Fitch Ratings
FMCC	Federally Mandated Congestion Charge
FTR	Financial Transmission Rights
GAAP	Accounting principles generally accepted in the United States of America
GSC	Generation Service Charge
GSRP	Greater Springfield Reliability Project
GWh	Gigawatt-Hours
HG&E	Holyoke Gas and Electric, a municipal department of the 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 – September 30, 2012 and December 31, 2011	1

Condensed Consolidated Statements of Income – Three and Nine Months Ended September 30, 2012 and 2011	3

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

Condensed Consolidated Statements of Cash Flows – Nine Months Ended September 30, 2012 and 2011	4

The Connecticut Light and Power Company and Subsidiary (Unaudited)

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

Condensed Consolidated Statements of Income – Three and Nine Months Ended September 30, 2012 and 2011	7

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

Condensed Consolidated Statements of Cash Flows – Nine Months Ended September 30, 2012 and 2011	8

NSTAR Electric Company and Subsidiaries (Unaudited)

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

Condensed Consolidated Statements of Income – Three and Nine Months Ended September 30, 2012 and 2011	11

Condensed Consolidated Statements of Cash Flows – Nine Months Ended September 30, 2012 and 2011	12

Public Service Company of New Hampshire and Subsidiaries (Unaudited)

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

Condensed Consolidated Statements of Income – Three and Nine Months Ended September 30, 2012 and 2011	15

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

Condensed Consolidated Statements of Cash Flows – Nine Months Ended September 30, 2012 and 2011	16

Western Massachusetts Electric Company and Subsidiary (Unaudited)

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

Condensed Consolidated Statements of Income – Three and Nine Months Ended September 30, 2012 and 2011	19

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

Condensed Consolidated Statements of Cash Flows – Nine Months Ended September 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		68

NSTAR Electric Company and Subsidiaries		71

Public Service Company of New Hampshire and Subsidiaries		74

Western Massachusetts Electric Company and Subsidiary		76

ITEM 3 – Quantitative and Qualitative Disclosures About Market Risk		78

ITEM 4 – Controls and Procedures		78

PART II – OTHER INFORMATION

ITEM 1 – Legal Proceedings		79

ITEM 1A – Risk Factors		80

ITEM 2 – Unregistered Sales of Equity Securities and Use of Proceeds		80

ITEM 5– Other Information		80

ITEM 6 –Exhibits		81

SIGNATURES		83

This Page Intentionally Left Blank


NORTHEAST UTILITIES AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)

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

ASSETS

Current Assets:
	Cash and Cash Equivalents	$	73,449	$	6,559
	Receivables, Net		773,415		488,002
	Unbilled Revenues		182,643		175,207
	Fuel, Materials and Supplies		267,281		248,958
	Regulatory Assets		647,615		255,144
	Marketable Securities		81,618		70,970
	Prepayments and Other Current Assets		112,965		112,632
Total Current Assets			2,138,986		1,357,472


Property, Plant and Equipment, Net			16,303,805		10,403,065

Deferred Debits and Other Assets:
	Regulatory Assets		5,008,034		3,267,710
	Goodwill		3,518,454		287,591
	Marketable Securities		394,207		60,311
	Derivative Assets		93,256		98,357
	Other Long-Term Assets		300,820		172,560
Total Deferred Debits and Other Assets			9,314,771		3,886,529



Total Assets		$	27,757,562	$	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)

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

LIABILITIES AND CAPITALIZATION

Current Liabilities:
Notes Payable		$	1,359,250	$	317,000
Long-Term Debt - Current Portion			879,746		331,582
Accounts Payable			542,691		633,282
Regulatory Liabilities			226,606		167,844
Derivative Liabilities			113,907		107,558
Other Current Liabilities			678,523		390,416
Total Current Liabilities			3,800,723		1,947,682

Rate Reduction Bonds			101,347		112,260

Deferred Credits and Other Liabilities:
Accumulated Deferred Income Taxes			3,429,538		1,868,316
Regulatory Liabilities			561,555		266,145
Derivative Liabilities			912,352		959,876
Accrued Pension, SERP and PBOP			2,015,649		1,326,037
Other Long-Term Liabilities			871,428		420,011
Total Deferred Credits and Other Liabilities			7,790,522		4,840,385

Capitalization:
Long-Term Debt			6,732,536		4,614,913

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

Equity:
	Common Shareholders' Equity:
	Common Shares		1,662,358		980,264
	Capital Surplus, Paid In		6,183,715		1,797,884
	Retained Earnings		1,735,690		1,651,875
	Accumulated Other Comprehensive Loss		(64,209)		(70,686)
	Treasury Stock		(340,688)		(346,667)
Common Shareholders' Equity			9,176,866		4,012,670
Noncontrolling Interests			-		2,956
Total Equity			9,176,866		4,015,626
Total Capitalization			16,064,970		8,746,739



Total Liabilities and Capitalization		$	27,757,562	$	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 September 30,				Nine Months Ended September 30,
(Thousands of Dollars, Except Share Information)			2012		2011		2012		2011

Operating Revenues			$	1,861,529	$	1,114,892	$	4,589,835	$	3,397,624

Operating Expenses:
	Purchased Power, Fuel and Transmission			602,751		406,237		1,540,110		1,285,483
	Operations and Maintenance			395,531		255,551		1,187,471		788,875
	Depreciation			144,475		75,196		369,798		222,784
	Amortization of Regulatory Assets, Net			43,835		36,163		74,851		86,653
	Amortization of Rate Reduction Bonds			43,044		17,680		102,144		52,047
	Energy Efficiency Programs			98,326		35,255		209,089		99,658
	Taxes Other Than Income Taxes			120,662		84,994		319,559		252,817
		Total Operating Expenses		1,448,624		911,076		3,803,022		2,788,317
Operating Income				412,905		203,816		786,813		609,307

Interest Expense:
	Interest on Long-Term Debt			86,459		57,461		233,352		171,905
	Interest on Rate Reduction Bonds			1,681		2,018		5,168		6,889
	Other Interest			2,221		4,453		7,336		5,922
		Interest Expense		90,361		63,932		245,856		184,716
Other Income, Net				4,324		1,430		14,904		19,077
Income Before Income Tax Expense				326,868		141,314		555,861		443,668
Income Tax Expense				117,360		49,883		199,379		157,934
Net Income				209,508		91,431		356,482		285,734
Net Income Attributable to Noncontrolling Interests				1,880		1,470		5,253		4,340
Net Income Attributable to Controlling Interest			$	207,628	$	89,961	$	351,229	$	281,394

Basic Earnings Per Common Share			$	0.66	$	0.51	$	1.33	$	1.59

Diluted Earnings Per Common Share			$	0.66	$	0.51	$	1.32	$	1.58

Dividends Declared Per Common Share			$	0.34	$	0.28	$	0.97	$	0.83

Weighted Average Common Shares Outstanding:
	Basic			314,806,441		177,497,862		264,636,636		177,344,481
	Diluted			315,805,796		177,835,348		265,353,377		177,647,694

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 September 30,				Nine Months Ended September 30,
(Thousands of Dollars)			2012		2011		2012		2011

Net Income			$	209,508	$	91,431	$	356,482	$	285,734
Other Comprehensive Income/(Loss), Net of Tax:
	Qualified Cash Flow Hedging Instruments			516		(10,678)		1,455		(14,600)
	Changes in Unrealized Gains on Other Securities			217		280		411		424
	Change in Funded Status of Pension, SERP and PBOP
		Benefit Plans		1,445		975		4,611		2,332
Other Comprehensive Income/(Loss), Net of Tax				2,178		(9,423)		6,477		(11,844)
Comprehensive Income Attributable to Noncontrolling
	Interests			(1,880)		(1,470)		(5,253)		(4,340)
Comprehensive Income Attributable to Controlling Interest			$	209,806	$	80,538	$	357,706	$	269,550

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)


			Nine Months Ended September 30,
(Thousands of Dollars)			2012		2011

Operating Activities:
	Net Income		$	356,482	$	285,734
	Adjustments to Reconcile Net Income to Net Cash Flows
		Provided by Operating Activities:
		Bad Debt Expense		24,249		12,435
		Depreciation		369,798		222,784
		Deferred Income Taxes		186,181		133,528
		Pension, SERP and PBOP Expense		160,209		103,106
		Pension and PBOP Contributions		(237,123)		(159,220)
		Regulatory Underrecoveries, Net		(26,236)		(24,245)
		Amortization of Regulatory Assets, Net		74,851		86,653
		Amortization of Rate Reduction Bonds		102,144		52,047
		Derivative Assets and Liabilities		(7,907)		(33,767)
		Other		(9,702)		(14,802)
	Changes in Current Assets and Liabilities:
		Receivables and Unbilled Revenues, Net		(27,677)		61,657
		Fuel, Materials and Supplies		32,887		(4,072)
		Taxes Receivable/Accrued, Net		26,302		109,410
		Accounts Payable		(208,308)		66,618
		Other Current Assets and Liabilities, Net		(20,145)		(9,419)
Net Cash Flows Provided by Operating Activities				796,005		888,447

Investing Activities:
	Investments in Property, Plant and Equipment			(1,081,750)		(749,060)
	Proceeds from Sales of Marketable Securities			232,911		116,463
	Purchases of Marketable Securities			(252,762)		(118,251)
	Proceeds from Sale of Assets			-		46,841
	Other Investing Activities			40,265		(5,849)
Net Cash Flows Used in Investing Activities				(1,061,336)		(709,856)

Financing Activities:
	Cash Dividends on Common Shares			(267,356)		(145,865)
	Cash Dividends on Preferred Stock			(5,149)		(4,169)
	Increase/(Decrease) in Short-Term Debt			654,250		(237,000)
	Issuance of Long-Term Debt			300,000		382,000
	Retirements of Long-Term Debt			(267,561)		(124,086)
	Retirements of Rate Reduction Bonds			(95,225)		(51,198)
	Other Financing Activities			13,262		(4,947)
Net Cash Flows Provided by/(Used in) Financing Activities				332,221		(185,265)
Net Increase/(Decrease) in Cash and Cash Equivalents				66,890		(6,674)
Cash and Cash Equivalents - Beginning of Period				6,559		23,395
Cash and Cash Equivalents - End of Period			$	73,449	$	16,721


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)

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

ASSETS

Current Assets:
	Cash	$	6,570	$	1
	Receivables, Net		322,159		295,028
	Accounts Receivable from Affiliated Companies		1,678		1,548
	Unbilled Revenues		75,246		94,995
	Regulatory Assets		186,594		170,197
	Materials and Supplies		61,704		61,102
	Prepayments and Other Current Assets		53,239		53,920
Total Current Assets			707,190		676,791

Property, Plant and Equipment, Net			6,069,033		5,827,384

Deferred Debits and Other Assets:
	Regulatory Assets		1,998,426		2,103,830
	Derivative Assets		91,989		93,755
	Other Long-Term Assets		92,712		89,636
Total Deferred Debits and Other Assets			2,183,127		2,287,221



Total Assets		$	8,959,350	$	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)

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

LIABILITIES AND CAPITALIZATION

Current Liabilities:
	Notes Payable		$	-	$	31,000
	Notes Payable to Affiliated Companies			372,800		58,525
	Long-Term Debt - Current Portion			241,400		62,000
	Accounts Payable			195,315		340,321
	Accounts Payable to Affiliated Companies			41,804		53,439
	Obligations to Third Party Suppliers			69,222		67,967
	Accrued Taxes			72,670		59,046
	Regulatory Liabilities			90,208		108,291
	Derivative Liabilities			97,536		95,881
	Other Current Liabilities			84,529		102,065
Total Current Liabilities				1,265,484		978,535

Deferred Credits and Other Liabilities:
	Accumulated Deferred Income Taxes			1,329,397		1,215,989
	Regulatory Liabilities			130,116		139,307
	Derivative Liabilities			891,160		935,849
	Accrued Pension, SERP and PBOP			245,860		260,571
	Other Long-Term Liabilities			198,083		215,640
Total Deferred Credits and Other Liabilities				2,794,616		2,767,356

Capitalization:
	Long-Term Debt			2,342,806		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		1,614,699		1,613,503
		Retained Earnings		767,097		735,948
		Accumulated Other Comprehensive Loss		(1,904)		(2,251)
	Common Stockholder's Equity			2,440,244		2,407,552
Total Capitalization				4,899,250		5,045,505



Total Liabilities and Capitalization			$	8,959,350	$	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 September 30,				Nine Months Ended September 30,
(Thousands of Dollars)			2012		2011		2012		2011

Operating Revenues			$	658,111	$	673,666	$	1,812,218	$	1,955,361

Operating Expenses:
	Purchased Power and Transmission			241,046		266,350		658,743		768,687
	Operations and Maintenance			141,913		130,714		480,286		403,125
	Depreciation			41,863		39,711		124,451		117,629
	Amortization of Regulatory Assets, Net			8,656		15,688		19,912		48,027
	Energy Efficiency Programs			25,237		24,914		68,205		69,629
	Taxes Other Than Income Taxes			59,687		58,552		168,667		169,745
		Total Operating Expenses		518,402		535,929		1,520,264		1,576,842
Operating Income				139,709		137,737		291,954		378,519

Interest Expense:
	Interest on Long-Term Debt			31,429		33,326		94,646		100,085
	Other Interest			2,162		1,893		6,223		(815)
		Interest Expense		33,591		35,219		100,869		99,270
Other Income/(Loss), Net				2,889		(2,356)		8,636		4,308
Income Before Income Tax Expense				109,007		100,162		199,721		283,557
Income Tax Expense				34,121		33,634		63,917		100,057
Net Income			$	74,886	$	66,528	$	135,804	$	183,500

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 September 30,				Nine Months Ended September 30,
(Thousands of Dollars)			2012		2011		2012		2011

Net Income			$	74,886	$	66,528	$	135,804	$	183,500
Other Comprehensive Income, Net of Tax:
	Qualified Cash Flow Hedging Instruments			111		111		333		333
	Changes in Unrealized Gains on Other Securities			8		10		14		15
Other Comprehensive Income, Net of Tax				119		121		347		348
Comprehensive Income			$	75,005	$	66,649	$	136,151	$	183,848

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)


			Nine Months Ended September 30,
(Thousands of Dollars)			2012		2011

Operating Activities:
	Net Income		$	135,804	$	183,500
	Adjustments to Reconcile Net Income to Net Cash Flows
		Provided by Operating Activities:
		Bad Debt Expense		1,420		2,115
		Depreciation		124,451		117,629
		Deferred Income Taxes		97,224		67,948
		Pension, SERP and PBOP Expense, Net of PBOP Contributions		18,394		10,473
		Regulatory Underrecoveries, Net		(13,804)		(49,525)
		Amortization of Regulatory Assets, Net		19,912		48,027
		Other		(12,121)		(22,435)
	Changes in Current Assets and Liabilities:
		Receivables and Unbilled Revenues, Net		(21,632)		26,164
		Materials and Supplies		(1,017)		(12,669)
		Taxes Receivable/Accrued, Net		21,410		64,779
		Accounts Payable		(173,107)		73,809
		Other Current Assets and Liabilities, Net		(48,733)		(23,245)
Net Cash Flows Provided by Operating Activities				148,201		486,570

Investing Activities:
	Investments in Property, Plant and Equipment			(332,323)		(305,595)
	Increase in Notes Receivable from Affiliate			-		(6,925)
	Proceeds from Sale of Assets			-		46,841
	Other Investing Activities			13,707		(6,693)
Net Cash Flows Used in Investing Activities				(318,616)		(272,372)

Financing Activities:
	Cash Dividends on Common Stock			(100,486)		(205,981)
	Cash Dividends on Preferred Stock			(4,169)		(4,169)
	Decrease in Short-Term Debt			(31,000)		-
	Increase/(Decrease) in Notes Payable to Affiliate			314,275		(6,225)
	Other Financing Activities			(1,636)		(349)
Net Cash Flows Provided by/(Used in) Financing Activities				176,984		(216,724)
Net Increase/(Decrease) in Cash				6,569		(2,526)
Cash - Beginning of Period				1		9,762
Cash - End of Period			$	6,570	$	7,236


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


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

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

ASSETS

Current Assets:
	Cash and Cash Equivalents	$	11,734	$	9,373
	Receivables, Net		248,648		232,828
	Accounts Receivable from Affiliated Companies		146,884		389,652
	Unbilled Revenues		50,465		40,380
	Regulatory Assets		337,575		323,871
	Prepayments and Other Current Assets		25,278		37,134
Total Current Assets			820,584		1,033,238

Property, Plant and Equipment, Net			4,628,823		4,447,258

Deferred Debits and Other Assets:
	Regulatory Assets		1,510,087		1,680,595
	Other Long-Term Assets		58,036		78,273
Total Deferred Debits and Other Assets			1,568,123		1,758,868



Total Assets		$	7,017,530	$	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)

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

LIABILITIES AND CAPITALIZATION

Current Liabilities:
	Notes Payable		$	261,000	$	141,500
	Long-Term Debt - Current Portion			1,650		400,688
	Accounts Payable			116,885		150,581
	Accounts Payable to Affiliated Companies			229,849		514,377
	Accumulated Deferred Income Taxes - Current Portion			84,411		101,819
	Regulatory Liabilities			84,476		41,579
	Other Current Liabilities			152,948		103,634
Total Current Liabilities				931,219		1,454,178

Rate Reduction Bonds				43,493		127,860

Deferred Credits and Other Liabilities:
	Accumulated Deferred Income Taxes			1,317,168		1,310,180
	Regulatory Liabilities			256,542		239,858
	Accrued Pension			375,422		357,685
	Payable to Affiliated Companies			70,569		75,905
	Other Long-Term Liabilities			180,395		195,606
Total Deferred Credits and Other Liabilities				2,200,096		2,179,234

Capitalization:
	Long-Term Debt			1,601,959		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		1,205,138		1,239,123
	Common Stockholder's Equity			2,197,763		2,231,748
Total Capitalization				3,842,722		3,478,092



Total Liabilities and Capitalization			$	7,017,530	$	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 September 30,				Nine Months Ended September 30,
(Thousands of Dollars)			2012		2011		2012		2011

Operating Revenues			$	693,653	$	724,686	$	1,784,755	$	1,854,507

Operating Expenses:
	Purchased Power and Transmission			222,753		262,118		622,265		717,180
	Operations and Maintenance			83,329		100,991		340,547		286,044
	Depreciation			42,494		40,399		127,692		123,556
	Amortization of Regulatory Assets, Net			41,888		27,065		87,912		56,734
	Amortization of Rate Reduction Bonds			22,581		22,581		67,742		67,742
	Energy Efficiency Programs			55,969		59,204		138,360		132,160
	Taxes Other Than Income Taxes			30,520		28,580		89,689		84,069
		Total Operating Expenses		499,534		540,938		1,474,207		1,467,485
Operating Income				194,119		183,748		310,548		387,022

Interest Expense:
	Interest on Long-Term Debt			22,386		22,548		66,953		67,724
	Interest on Rate Reduction Bonds			853		1,742		3,106		5,795
	Other Interest			(4,704)		(6,350)		(16,137)		(21,679)
		Interest Expense		18,535		17,940		53,922		51,840
Other Income/(Loss), Net				551		(419)		1,778		1,300
Income Before Income Tax Expense				176,135		165,389		258,404		336,482
Income Tax Expense				69,373		65,569		102,220		133,115
Net Income			$	106,762	$	99,820	$	156,184	$	203,367

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)


			Nine Months Ended September 30,
(Thousands of Dollars)			2012		2011

Operating Activities:
	Net Income		$	156,184	$	203,367
	Adjustments to Reconcile Net Income to Net Cash Flows
		Provided by Operating Activities:
		Bad Debt Expense		53,254		14,737
		Depreciation		127,692		123,556
		Deferred Income Taxes		(21,270)		5,063
		Pension, SERP and PBOP Expense		48,694		41,169
		Pension and PBOP Contributions		(47,300)		(90,500)
		Regulatory Overrecoveries, Net		62,075		112,554
		Amortization of Regulatory Assets, Net		87,912		56,734
		Amortization of Rate Reduction Bonds		67,742		67,742
		Other		(28,134)		3,096
	Changes in Current Assets and Liabilities:
		Receivables and Unbilled Revenues, Net		(61,528)		(72,112)
		Materials and Supplies		7,264		(4,670)
		Taxes Receivable/Accrued, Net		44,142		214,475
		Accounts Payable		(81,292)		(92,721)
		Other Current Assets and Liabilities, Net		17,130		(557)
Net Cash Flows Provided by Operating Activities				432,565		581,933

Investing Activities:
	Investments in Property, Plant and Equipment			(298,424)		(234,172)
	Other Investing Activities			25,609		41,971
Net Cash Flows Used in Investing Activities				(272,815)		(192,201)

Financing Activities:
	Cash Dividends on Common Stock			(188,700)		(141,600)
	Cash Dividends on Preferred Stock			(1,470)		(1,470)
	Increase/(Decrease) in Short-Term Debt			104,500		(145,000)
	Retirements of Long-Term Debt			(688)		(16,237)
	Retirements of Rate Reduction Bonds			(84,367)		(84,346)
	Other Financing Activities			13,336		-
Net Cash Flows Used in Financing Activities				(157,389)		(388,653)
Net Increase in Cash and Cash Equivalents				2,361		1,079
Cash and Cash Equivalents - Beginning of Period				9,373		8,964
Cash and Cash Equivalents - End of Period			$	11,734	$	10,043


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)

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

ASSETS

Current Assets:
	Cash	$	3,095	$	56
	Receivables, Net		97,815		87,545
	Accounts Receivable from Affiliated Companies		1,025		1,294
	Notes Receivable from Affiliated Companies		-		55,900
	Unbilled Revenues		34,701		45,403
	Fuel, Materials and Supplies		100,135		124,744
	Regulatory Assets		34,767		34,178
	Prepayments and Other Current Assets		21,018		35,261
Total Current Assets			292,556		384,381

Property, Plant and Equipment, Net			2,331,370		2,256,688

Deferred Debits and Other Assets:
	Regulatory Assets		322,896		393,941
	Other Long-Term Assets		74,261		81,531
Total Deferred Debits and Other Assets			397,157		475,472



Total Assets		$	3,021,083	$	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)

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

LIABILITIES AND CAPITALIZATION

Current Liabilities:
	Notes Payable to Affiliated Companies		$	44,200	$	-
	Accounts Payable			61,498		106,377
	Accounts Payable to Affiliated Companies			15,129		18,895
	Accrued Interest			14,205		9,670
	Regulatory Liabilities			18,373		24,500
	Renewable Portfolio Standards Compliance Obligations			13,273		12,089
	Other Current Liabilities			35,040		24,408
Total Current Liabilities				201,718		195,939

Rate Reduction Bonds				44,103		85,368

Deferred Credits and Other Liabilities:
	Accumulated Deferred Income Taxes			432,395		392,712
	Regulatory Liabilities			53,418		54,415
	Accrued Pension, SERP and PBOP			168,766		258,718
	Other Long-Term Liabilities			47,936		53,304
Total Deferred Credits and Other Liabilities				702,515		759,149

Capitalization:
	Long-Term Debt			997,879		997,722

	Common Stockholder's Equity:
		Common Stock		-		-
		Capital Surplus, Paid In		700,841		700,285
		Retained Earnings		383,961		388,910
		Accumulated Other Comprehensive Loss		(9,934)		(10,832)
	Common Stockholder's Equity			1,074,868		1,078,363
Total Capitalization				2,072,747		2,076,085



Total Liabilities and Capitalization			$	3,021,083	$	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 September 30,				Nine Months Ended September 30,
(Thousands of Dollars)			2012		2011		2012		2011

Operating Revenues			$	256,949	$	259,648	$	755,051	$	769,309

Operating Expenses:
	Purchased Power, Fuel and Transmission			76,008		77,698		239,173		247,072
	Operations and Maintenance			67,547		65,336		200,960		205,806
	Depreciation			22,264		18,403		65,282		54,432
	Amortization of Regulatory Assets/(Liabilities), Net			(6,356)		17,271		(6,179)		35,303
	Amortization of Rate Reduction Bonds			16,112		13,609		43,855		39,748
	Energy Efficiency Programs			4,030		3,730		10,824		9,571
	Taxes Other Than Income Taxes			16,046		15,133		47,406		44,034
		Total Operating Expenses		195,651		211,180		601,321		635,966
Operating Income				61,298		48,468		153,730		133,343

Interest Expense:
	Interest on Long-Term Debt			11,434		8,484		34,537		25,425
	Interest on Rate Reduction Bonds			564		1,468		2,366		5,038
	Other Interest			609		416		1,301		761
		Interest Expense		12,607		10,368		38,204		31,224
Other Income/(Loss), Net				(353)		3,293		2,237		12,112
Income Before Income Tax Expense				48,338		41,393		117,763		114,231
Income Tax Expense				21,106		15,759		48,037		39,468
Net Income			$	27,232	$	25,634	$	69,726	$	74,763

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 September 30,				Nine Months Ended September 30,
(Thousands of Dollars)			2012		2011		2012		2011

Net Income			$	27,232	$	25,634	$	69,726	$	74,763
Other Comprehensive Income/(Loss), Net of Tax:
	Qualified Cash Flow Hedging Instruments			291		(7,478)		872		(10,550)
	Changes in Unrealized Gains on Other Securities			13		16		24		24
	Change in Funded Status of Pension, SERP and PBOP
		Benefit Plans		(2)		-		2		-
Other Comprehensive Income/(Loss), Net of Tax				302		(7,462)		898		(10,526)
Comprehensive Income			$	27,534	$	18,172	$	70,624	$	64,237

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)


			Nine Months Ended September 30,
(Thousands of Dollars)			2012		2011

Operating Activities:
	Net Income		$	69,726	$	74,763
	Adjustments to Reconcile Net Income to Net Cash Flows
		Provided by Operating Activities:
		Bad Debt Expense		4,975		5,202
		Depreciation		65,282		54,432
		Deferred Income Taxes		39,108		51,809
		Pension, SERP and PBOP Expense		19,508		21,568
		Pension and PBOP Contributions		(94,169)		(99,780)
		Regulatory Overrecoveries, Net		1,718		2,581
		Amortization of Regulatory (Liabilities)/Assets, Net		(6,179)		35,303
		Amortization of Rate Reduction Bonds		43,855		39,748
		Settlement of Cash Flow Hedge Instruments		-		(18,072)
		Other		13,724		(15,501)
	Changes in Current Assets and Liabilities:
		Receivables and Unbilled Revenues, Net		(4,274)		9,332
		Fuel, Materials and Supplies		20,178		11,981
		Taxes Receivable/Accrued, Net		4,506		18,758
		Accounts Payable		(18,567)		(6,905)
		Other Current Assets and Liabilities, Net		18,358		14,613
Net Cash Flows Provided by Operating Activities				177,749		199,832

Investing Activities:
	Investments in Property, Plant and Equipment			(161,021)		(167,383)
	Decrease/(Increase) in Notes Receivable from Affiliate			55,900		(50,300)
	Other Investing Activities			2,500		1,026
Net Cash Flows Used in Investing Activities				(102,621)		(216,657)

Financing Activities:
	Cash Dividends on Common Stock			(74,675)		(44,121)
	Decrease in Short-Term Debt			-		(30,000)
	Issuance of Long-Term Debt			-		282,000
	Retirements of Long-Term Debt			-		(119,800)
	Increase/(Decrease) in Notes Payable to Affiliate			44,200		(47,900)
	Capital Contributions from NU Parent			-		20,000
	Retirements of Rate Reduction Bonds			(41,265)		(38,881)
	Other Financing Activities			(349)		(4,162)
Net Cash Flows (Used in)/Provided by Financing Activities				(72,089)		17,136
Net Increase in Cash				3,039		311
Cash - Beginning of Period				56		2,559
Cash - End of Period			$	3,095	$	2,870


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)

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

ASSETS

Current Assets:
	Cash	$	536	$	1
	Receivables, Net		50,950		42,757
	Accounts Receivable from Affiliated Companies		294		633
	Notes Receivable from Affiliated Companies		-		11,000
	Unbilled Revenues		13,261		16,277
	Regulatory Assets		34,839		35,520
	Marketable Securities		18,375		26,335
	Prepayments and Other Current Assets		6,700		8,719
Total Current Assets			124,955		141,242

Property, Plant and Equipment, Net			1,257,318		1,077,833

Deferred Debits and Other Assets:
	Regulatory Assets		213,928		233,247
	Marketable Securities		39,259		30,794
	Other Long-Term Assets		21,911		19,777
Total Deferred Debits and Other Assets			275,098		283,818



Total Assets		$	1,657,371	$	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)

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

LIABILITIES AND CAPITALIZATION

Current Liabilities:
	Notes Payable to Affiliated Companies		$	172,500	$	-
	Long-Term Debt - Current Portion			55,000		-
	Accounts Payable			61,508		111,566
	Accounts Payable to Affiliated Companies			7,042		10,626
	Regulatory Liabilities			22,479		33,056
	Other Current Liabilities			23,149		20,755
Total Current Liabilities				341,678		176,003

Rate Reduction Bonds				13,751		26,892

Deferred Credits and Other Liabilities:
	Accumulated Deferred Income Taxes			285,881		244,511
	Regulatory Liabilities			9,708		16,597
��	Accrued Pension, SERP and PBOP			25,516		29,546
	Other Long-Term Liabilities			43,382		47,498
Total Deferred Credits and Other Liabilities				364,487		338,152

Capitalization:
	Long-Term Debt			444,706		499,545

	Common Stockholder's Equity:
		Common Stock		10,866		10,866
		Capital Surplus, Paid In		340,329		340,115
		Retained Earnings		145,483		115,506
		Accumulated Other Comprehensive Loss		(3,929)		(4,186)
	Common Stockholder's Equity			492,749		462,301
Total Capitalization				937,455		961,846



Total Liabilities and Capitalization			$	1,657,371	$	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 September 30,				Nine Months Ended September 30,
(Thousands of Dollars)			2012		2011		2012		2011

Operating Revenues			$	112,470	$	104,515	$	333,331	$	309,589

Operating Expenses:
	Purchased Power and Transmission			32,028		41,246		105,297		124,440
	Operations and Maintenance			24,765		19,161		75,214		60,467
	Depreciation			7,464		6,681		22,154		19,644
	Amortization of Regulatory Assets, Net			1,021		2,810		634		3,538
	Amortization of Rate Reduction Bonds			4,352		4,071		13,127		12,299
	Energy Efficiency Programs			9,190		6,110		19,679		16,491
	Taxes Other Than Income Taxes			5,505		4,650		15,365		13,395
		Total Operating Expenses		84,325		84,729		251,470		250,274
Operating Income				28,145		19,786		81,861		59,315

Interest Expense:
	Interest on Long-Term Debt			5,783		4,913		17,454		14,389
	Interest on Rate Reduction Bonds			272		550		1,029		1,852
	Other Interest			714		529		1,550		785
		Interest Expense		6,769		5,992		20,033		17,026
Other Income/(Loss), Net				685		(722)		1,965		259
Income Before Income Tax Expense				22,061		13,072		63,793		42,548
Income Tax Expense				7,977		4,638		24,385		15,977
Net Income			$	14,084	$	8,434	$	39,408	$	26,571

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 September 30,				Nine Months Ended September 30,
(Thousands of Dollars)			2012		2011		2012		2011

Net Income			$	14,084	$	8,434	$	39,408	$	26,571
Other Comprehensive Income/(Loss), Net of Tax:
	Qualified Cash Flow Hedging Instruments			84		(3,248)		253		(4,193)
	Changes in Unrealized Gains on Other Securities			2		2		4		4
Other Comprehensive Income/(Loss), Net of Tax				86		(3,246)		257		(4,189)
Comprehensive Income			$	14,170	$	5,188	$	39,665	$	22,382

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)


			Nine Months Ended September 30,
(Thousands of Dollars)			2012		2011

Operating Activities:
	Net Income		$	39,408	$	26,571
	Adjustments to Reconcile Net Income to Net Cash Flows
		Provided by Operating Activities:
		Bad Debt Expense		1,522		2,352
		Depreciation		22,154		19,644
		Deferred Income Taxes		30,565		9,323
		Regulatory (Under)/Over Recoveries, Net		(8,733)		21,803
		Amortization of Regulatory Assets, Net		634		3,538
		Amortization of Rate Reduction Bonds		13,127		12,299
		Settlement of Cash Flow Hedge Instrument		-		(6,859)
		Other		233		(3,396)
	Changes in Current Assets and Liabilities:
		Receivables and Unbilled Revenues, Net		(10,482)		(7,804)
		Materials and Supplies		(2,333)		67
		Taxes Receivable/Accrued, Net		7,337		10,675
		Accounts Payable		(28,510)		4,294
		Other Current Assets and Liabilities, Net		(6,852)		(3,830)
Net Cash Flows Provided by Operating Activities				58,070		88,677

Investing Activities:
	Investments in Property, Plant and Equipment			(218,184)		(153,470)
	Proceeds from Sales of Marketable Securities			65,131		96,134
	Purchases of Marketable Securities			(65,664)		(96,312)
	Decrease/(Increase) in Notes Receivable from Affiliate			11,000		(70,700)
	Other Investing Activities			308		(1,664)
Net Cash Flows Used in Investing Activities				(207,409)		(226,012)

Financing Activities:
	Cash Dividends on Common Stock			(9,431)		��(19,729)
	Issuance of Long-Term Debt			-		100,000
	Increase/(Decrease) in Notes Payable to Affiliate			172,500		(20,400)
	Retirements of Rate Reduction Bonds			(13,141)		(12,318)
	Capital Contributions from NU Parent			-		91,812
	Other Financing Activities			(54)		(1,761)
Net Cash Flows Provided by Financing Activities				149,874		137,604
Net Increase in Cash				535		269
Cash - Beginning of Period				1		1
Cash - End of Period			$	536	$	270

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' results of operations from April 10, 2012 through September 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 nine months ended September 30, 2012 and 2011 and the financial position as of September 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 and second quarter 2012 combined Quarterly Reports 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 September 30, 2012 and December 31, 2011, the results of operations and comprehensive income for the three and nine months ended September 30, 2012 and 2011, and cash flows for the nine months ended September 30, 2012 and 2011. The results of operations and comprehensive income for the three and nine months ended September 30, 2012 and 2011 and the cash flows for the nine months ended September 30, 2012 and 2011 are not necessarily indicative of the results expected for a full year. The demand for electricity and natural gas 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 results in NU recording nuclear decommissioning trust marketable securities of $324.9 million, regulatory assets of $212.9 million, long-term debt associated with the long-term fuel disposal liabilities of $179.5 million, net accumulated deferred income tax liability of $58.8 million and asset retirement obligations related to decommissioning activity of $292.9 million as of September 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 September 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 balance sheets and statements of income for NU, CL&P, PSNH and WMECO and statements of cash flows for NU, CL&P and WMECO 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		Nine Months Ended		Three Months Ended		Nine Months Ended
(Millions of Dollars)	September 30, 2011		September 30, 2011		September 30, 2011		September 30, 2011
NU	$	6.3	$	71.1	$	35.3	$	99.7
CL&P		8.7		48.5		24.9		69.6
PSNH		(0.3)		12.7		3.7		9.6
WMECO		2.1		12.4		6.1		16.5

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 $11.4 million, after-tax, for the first quarter and first nine months 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 17, "Subsequent Events," for further information.

Recently Adopted Accounting Standards

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

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 and Special Deposits

As of September 30, 2012, NU, CL&P and PSNH had $10.3 million, $1.4 million, and $7.4 million, respectively, of restricted cash, primarily relating to amounts held in escrow, insurance proceeds on bondable property at PSNH, and amounts related to the sale of land and propane equipment, 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.

NU, CL&P, NSTAR Electric, and PSNH had $19.9 million, $2 million, $0.5 million and $3 million, respectively, of cash collateral posted not subject to master netting agreements, primarily with ISO-NE, as of September 30, 2012. There was no cash posted with ISO-NE and $10.9 million posted with other counterparties as of December 31, 2011.

Provision for Uncollectible Accounts

NU, including CL&P, NSTAR Electric, PSNH and WMECO, maintains a provision for uncollectible accounts 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 September 30, 2012		As of December 31, 2011⁽¹⁾
NU	$	91.7	$	34.9
CL&P		11.2		14.8
NSTAR Electric		45.1		27.1
PSNH		9.5		7.2
WMECO		3.5		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 Nine Months Ended
(Millions of Dollars)	September 30, 2012		September 30, 2011		September 30, 2012		September 30, 2011
NU	$	36.4	$	35.0	$	102.0	$	105.8
CL&P		34.4		33.0		91.5		93.2

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 September 30, 2012		As of September 30, 2011⁽¹⁾
NU	$	139.9	$	121.7
CL&P		45.9		22.1
NSTAR Electric		21.5		29.4
PSNH		20.1		32.4
WMECO		35.1		45.8

⁽¹⁾

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

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 nine months ended September 30, 2012 for CL&P and NU.

The merger of NU with NSTAR on April 10, 2012 represented a significant non-cash transaction. Refer to Note 2, "Merger of NU and NSTAR," for further information on the purchase price of NSTAR.

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 service provided prior to the merger 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 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

Goodwill Allocation: NU's reporting units consist of the combined Electric Distribution, Electric Transmission and Natural Gas Distribution. The preliminary estimate of goodwill from the merger with NSTAR of $3.2 billion has been assigned to NU's reporting units based on relative fair values. As of September 30, 2012, the preliminary allocation of goodwill to each reporting unit was $2.3 billion to Electric Distribution, $0.7 billion to Electric Transmission and $0.5 billion to Natural Gas Distribution, including $0.3 billion of pre-existing goodwill applicable to Yankee Gas. NU's reporting units are consistent with its reportable business segments.

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 September 30,				For the Nine Months Ended September 30,
(Pro forma amounts in millions, except per share amounts)	2012		2011		2012		2011
Operating Revenues	$	1,862	$	1,883	$	5,321	$	5,637
Net Income Attributable to Controlling Interest		208		190		455		518
Basic EPS		0.66		0.61		1.45		1.65
Diluted EPS		0.66		0.60		1.44		1.64

NU and NSTAR incurred non-recurring merger 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 September 30,				For the Nine Months Ended September 30,
(Millions of Dollars)		2012		2011		2012		2011
Transaction and Other Costs		$	1	$	1	$	31	$	17
Settlement Agreement Impacts			-		-		60		-
Total After-Tax Non-Recurring Costs Excluded
	from Net Income	$	1	$	1	$	91	$	17

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:


(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 on NU's accompanying unaudited condensed consolidated statements of income includes operating revenues of $736.2 million and net income attributable to controlling interest of $105 million for the three months ended September 30, 2012 and operating revenues of $1,337.6 million and net income attributable to controlling interest of $141 million for the nine months ended September 30, 2012.

REGULATORY ACCOUNTING

On April 10, 2012, NSTAR's regulated utility subsidiaries, NSTAR Electric and NSTAR Gas, became subsidiaries of NU. For NSTAR Electric, certain regulatory asset and liability balances as of December 31, 2011 have been reclassified to the current 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 in future rates, the costs would be charged to net income in the period in which the determination is made.

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


	As of September 30, 2012		As of December 31, 2011
(Millions of Dollars)	NU		NU
Deferred Benefit Costs	$	2,374.3	$	1,360.5
Regulatory Assets Offsetting Derivative Liabilities		908.9		939.6
Goodwill⁽²⁾		542.6		-
Income Taxes, Net		511.2		425.4
Storm Cost Deferrals		369.5		356.0
Securitized Assets		293.0		101.8
Unrecovered Contractual Obligations		215.8		100.9
Power Contracts Buy Out Agreements		99.3		8.6
Regulatory Tracker Deferrals		132.1		45.9
Asset Retirement Obligations		83.8		47.5
Losses on Reacquired Debt		39.5		24.5
Deferred Environmental Remediation Costs		57.5		38.5
Other Regulatory Assets		28.1		73.6
Total Regulatory Assets	$	5,655.6	$	3,522.8
Less: Current Portion	$	647.6	$	255.1
Total Long-Term Regulatory Assets	$	5,008.0	$	3,267.7


		As of September 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		$	516.7	$	811.9	$	178.1	$	107.6	$	572.8	$	813.7	$	200.0	$	118.9
Regulatory Assets Offsetting
	Derivative Liabilities		891.0		13.8		-		3.7		932.0		3.4		-		7.3
Goodwill⁽²⁾			-		465.9		-		-		-		478.9		-		-
Income Taxes, Net			364.1		47.5		36.0		30.2		339.6		48.8		38.0		17.8
Storm Cost Deferrals			255.7		36.9		36.7		40.2		268.3		30.6		44.0		43.7
Securitized Assets			-		246.5		34.2		12.3		-		368.5		76.4		25.4
Unrecovered Contractual Obligations			68.2		24.8		-		16.2		80.9		30.8		-		20.0
Power Contracts Buy Out Agreements			-		91.9		7.4		-		-		109.5		8.6		-
Regulatory Tracker Deferrals			18.9		55.5		21.9		23.1		5.5		61.1		11.9		22.1
Asset Retirement Obligations			29.7		25.8		14.0		3.5		27.9		24.5		13.5		3.2
Losses on Reacquired Debt			13.4		16.3		8.3		0.3		13.9		18.2		9.0		0.3
Deferred Environmental Remediation
	Costs		-		-		9.9		-		-		-		9.7		-
Other Regulatory Assets			27.3		10.9		11.2		11.6		33.1		16.5		17.0		10.0
Total Regulatory Assets		$	2,185.0	$	1,847.7	$	357.7	$	248.7	$	2,274.0	$	2,004.5	$	428.1	$	268.7
Less: Current Portion		$	186.6	$	337.6	$	34.8	$	34.8	$	170.2	$	323.9	$	34.2	$	35.5
Total Long-Term Regulatory Assets		$	1,998.4	$	1,510.1	$	322.9	$	213.9	$	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 the remaining 27 year amortization period.

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 standards, and that it is probable it will be able to recover its deferred

costs. As of September 30, 2012, CL&P had recorded total deferred storm costs relating to Tropical Storm Irene and the October 2011 snowstorm of $284.9 million. The storm cost deferral regulatory asset balance is net of a reserve of $40 million recorded in connection with the Connecticut settlement agreement. See Note 2, "Merger of NU and NSTAR," for further information.

On October 29, 2012, Hurricane Sandy caused extensive damage to NU’s electric distribution system across all three states. It is estimated that approximately 1.5 million of NU’s 3.1 million electric distribution customers were without power during or following the storm, with approximately 850,000 of those customers in Connecticut, approximately 472,000 in Massachusetts, and approximately 220,000 in New Hampshire. Restoration costs cannot be estimated at this time. Management expects the costs to meet the criteria for specific cost recovery in Connecticut, Massachusetts, and New Hampshire and, as a result, does not expect the storm to have a material impact to the results of operations of CL&P, NSTAR Electric, PSNH or WMECO. Each operating company will seek recovery of these anticipated deferred storm costs through its applicable regulatory recovery process.

Regulatory Costs Not Yet Approved: Additionally, the Regulated companies had $57 million ($4.1 million for CL&P, $24.4 million for NSTAR Electric, $23.4 million for PSNH and $1.6 million for WMECO) and $32.4 million ($5 million for CL&P, $22.4 million for PSNH and $1.6 million for WMECO) of regulatory costs as of September 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 September 30, 2012		As of December 31, 2011
(Millions of Dollars)	NU		NU
Cost of Removal	$	447.2	$	172.2
Regulatory Tracker Deferrals		171.2		139.1
AFUDC Transmission Incentive		70.2		67.0
Overrecovered Spent Nuclear Fuel Costs and Contractual Obligations		15.4		15.4
Wholesale Transmission Overcollections		1.6		9.6
Other Regulatory Liabilities⁽²⁾		82.6		30.6
Total Regulatory Liabilities	$	788.2	$	433.9
Less: Current Portion	$	226.6	$	167.8
Total Long-Term Regulatory Liabilities	$	561.6	$	266.1


		As of September 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		$	47.1	$	242.2	$	52.2	$	-	$	63.8	$	235.8	$	53.2	$	7.2
Regulatory Tracker Deferrals			86.3		43.7		16.3		18.2		94.4		11.7		17.3		21.3
AFUDC Transmission Incentive			56.8		4.1		-		9.3		57.7		4.3		-		9.3
Overrecovered Spent Nuclear Fuel
	Costs and Contractual Obligations		15.4		-		-		-		15.4		-		-		-
Wholesale Transmission Overcollections			3.0		-		-		2.6		4.5		-		2.6		9.5
Other Regulatory Liabilities⁽²⁾			11.7		51.0		3.3		2.1		11.8		29.7		5.8		2.4
Total Regulatory Liabilities		$	220.3	$	341.0	$	71.8	$	32.2	$	247.6	$	281.5	$	78.9	$	49.7
Less: Current Portion		$	90.2	$	84.5	$	18.4	$	22.5	$	108.3	$	41.6	$	24.5	$	33.1
Total Long-Term Regulatory Liabilities		$	130.1	$	256.5	$	53.4	$	9.7	$	139.3	$	239.9	$	54.4	$	16.6

⁽¹⁾

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

⁽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 September 30, 2012		As of December 31, 2011
(Millions of Dollars)		NU		NU
Distribution – Electric		$	11,275.0	$	6,540.4
Distribution - Natural Gas			2,198.4		1,247.6
Transmission			5,127.3		3,541.9
Generation			1,147.3		1,096.0
Electric and Natural Gas Utility			19,748.0		12,425.9
Other⁽¹⁾			432.9		305.1
Property, Plant and Equipment, Gross			20,180.9		12,731.0
Less: Accumulated Depreciation
	Electric and Natural Gas Utility		(4,990.4)		(3,035.5)
	Other		(166.6)		(120.2)
Total Accumulated Depreciation			(5,157.0)		(3,155.7)
Property, Plant and Equipment, Net			15,023.9		9,575.3
Construction Work in Progress			1,279.9		827.8
Total Property, Plant and Equipment, Net		$	16,303.8	$	10,403.1

⁽¹⁾

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


		As of September 30, 2012								As of December 31, 2011
				NSTAR								NSTAR
(Millions of Dollars)		CL&P		Electric		PSNH		WMECO		CL&P		Electric⁽¹⁾		PSNH		WMECO
Distribution		$	4,628.1	$	4,465.6	$	1,498.0	$	720.1	$	4,419.6	$	4,334.4	$	1,451.6	$	704.3
Transmission			2,736.3		1,438.2		570.7		361.8		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		7,364.4		5,903.8		3,194.8		1,103.1		7,108.7		5,721.3		3,072.8		1,022.9
Less: Accumulated Depreciation			(1,665.4)		(1,524.0)		(935.0)		(252.1)		(1,596.7)		(1,436.0)		(893.6)		(240.5)
Property, Plant and Equipment, Net			5,699.0		4,379.8		2,259.8		851.0		5,512.0		4,285.3		2,179.2		782.4
Construction Work in Progress			370.0		249.0		71.6		406.3		315.4		162.0		77.5		295.4
Total Property, Plant and
	Equipment, Net	$	6,069.0	$	4,628.8	$	2,331.4	$	1,257.3	$	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) under the applicable accounting guidance, and the use of nonderivative contracts.

Derivative contracts that are not recorded as normal are recorded at fair value as current or long-term derivative assets or liabilities. For the Regulated companies, regulatory assets or liabilities are recorded for the changes in fair values of derivatives, as 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. For NU's remaining unregulated wholesale marketing contracts, changes in fair values of derivatives are included in Net Income. The costs and benefits of derivative contracts that meet the definition of normal are recognized in Operating Expenses or Operating Revenues on the accompanying 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. As required by regulation, CL&P has entered into derivative and nonderivative contracts for the purchase of energy and energy-related products and contracts related to capacity. NSTAR Electric also has a capacity related contract that is a derivative. NSTAR Electric and WMECO have contracts to purchase renewable energy that are derivatives. CL&P has also entered into FTR contracts, which are accounted for as derivatives, to manage the risk of congestion costs associated with its SS and LRS contracts. NU also has NYMEX future contracts in order to reduce variability associated with the purchase price of approximately 9.1 million MMBtu of natural gas.

The costs or benefits from all of the Regulated companies' derivative contracts are recoverable from or refundable to customers, and therefore, changes in fair value are recorded as Regulatory Assets or Regulatory Liabilities on the accompanying 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 and the net amounts recorded as current or long-term derivative asset or liability, by primary underlying risk exposure or purpose:


		As of September 30, 2012
		Commodity Supply and		Collateral		Net Amount Recorded as
(Millions of Dollars)		Price Risk Management		and Netting⁽¹⁾		Derivative Asset/(Liability)⁽²⁾
Current Derivative Assets:
Level 2:
	PSNH	$	0.6	$	-	$	0.6
	Other		2.4		(0.3)		2.1
Level 3:
	CL&P		17.9		(12.1)		5.8
	Other		4.8		-		4.8
Total Current Derivative Assets		$	25.7	$	(12.4)	$	13.3

Long-Term Derivative Assets:
Level 3:
	CL&P	$	164.0	$	(72.0)	$	92.0
	Other		1.3		-		1.3
Total Long-Term Derivative Assets		$	165.3	$	(72.0)	$	93.3

Current Derivative Liabilities:
Level 2:
	Other	$	(17.5)	$	1.7	$	(15.8)
Level 3:
	CL&P		(97.5)		-		(97.5)
	NSTAR Electric		(0.6)		-		(0.6)
Total Current Derivative Liabilities		$	(115.6)	$	1.7	$	(113.9)

Long-Term Derivative Liabilities:
Level 2:
	Other	$	(4.3)	$	-	$	(4.3)
Level 3:
	CL&P		(891.2)		-		(891.2)
	NSTAR Electric		(13.2)		-		(13.2)
	WMECO		(3.7)		-		(3.7)
Total Long-Term Derivative Liabilities		$	(912.4)	$	-	$	(912.4)


		As of December 31, 2011
		Commodity Supply and		Collateral		Net Amount Recorded as
(Millions of Dollars)		Price Risk Management		and Netting⁽¹⁾		Derivative Asset/(Liability)⁽²⁾
Current Derivative Assets:
Level 3:
	CL&P	$	17.9	$	(11.6)	$	6.3
	Other		4.7		-		4.7
Total Current Derivative Assets⁽³⁾		$	22.6	$	(11.6)	$	11.0

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

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

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

⁽¹⁾

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

⁽²⁾

Current derivative assets are included in Prepayments and Other Current Assets on the accompanying 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.

⁽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 0.1 million 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 2028 with a facility that is expected to achieve commercial operation by November 2013.

As of September 30, 2012 and December 31, 2011, NU had approximately 38 thousand MWh and 123 thousand MWh, respectively, of supply volumes remaining in its unregulated wholesale portfolio when expected sales are compared with supply contracts.

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


		Amounts Recognized on Derivatives
Location of Amounts		For the Three Months Ended				For the Nine Months Ended
Recognized on Derivatives		September 30, 2012		September 30, 2011		September 30, 2012		September 30, 2011
(Millions of Dollars)
NU
Balance Sheet:
	Regulatory Assets	$	11.7	$	(47.7)	$	(25.0)	$	(92.8)
Statement of Income:
	Purchased Power, Fuel and Transmission		0.2		0.3		(0.8)		1.0

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 nine months ended September 30, 2011, $2.5 million and $7.9 million of interest benefit was recorded in Net Income, respectively.

Cash Flow Hedges: In 2011, PSNH and WMECO settled interest rate swaps associated with $280 million and $50 million, respectively, of long-term debt issuances and as a result PSNH and WMECO recorded pre-tax reductions of $18.2 million and $6.9 million, respectively, to AOCI that are being amortized over the remaining lives of the associated debt. NU reclassified $0.9 million and $2.4 million of pre-tax losses from AOCI into interest expense for the three and nine months ended September 30, 2012, respectively. These amounts were $0.4 million and $0.6 million for the three and nine months ended September 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 collateral for contracts in a net liability position over specified credit limits. The following summarizes the fair value of derivative contracts that were in a net liability position and subject to credit risk contingent features, the fair value of cash collateral, and the additional collateral that would be required to be posted by NU if the unsecured debt credit ratings of NU parent were downgraded to below investment grade as of September 30, 2012 and December 31, 2011:

As of September 30, 2012

As of December 31, 2011

Additional

Fair Value

Collateral Required

Fair Value

Collateral Required

Subject to Credit

Cash

If Downgraded

Subject to Credit

Cash

If Downgraded

Risk Contingent

Collateral

Below Investment

Risk Contingent

Collateral

Below Investment

(Millions of Dollars)

Features

Posted

Grade

Features

Posted

Grade

(15.8)

1.3

15.7

(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 - $90 per MWh	2017 - 2028
CL&P	$47 - $55 per MWh	2017 - 2020
WMECO	$41 - $90 per MWh	2017 - 2028

Capacity Prices:
NU	$1.40 - $10.53 per kW-Month	2016 - 2028
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 - $10.53 per kW-Month	2016 - 2028

Forward Reserve:
NU, CL&P	$0.35 - $0.90 per kW-Month	2013 - 2024

REC Prices:
NU	$25 - $85 per REC	2012 - 2028
NSTAR Electric	$25 - $63 per REC	2012 - 2017
WMECO	$25 - $85 per REC	2013 - 2028

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 nine months ended September 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 Nine Months Ended
		September 30, 2012		September 30, 2011		September 30, 2012		September 30, 2011
(Millions of Dollars)		NU		NU		NU		NU
Derivatives, Net:
Fair Value as of Beginning of Period		$	(932.1)	$	(886.2)	$	(962.2)	$	(840.2)
Increase due to Merger with NSTAR			-		-		(5.4)		-
Transfer to Level 2			-		-		32.2		-
Net Realized/Unrealized Gains/(Losses) Included in:
	Net Income⁽²⁾		(0.2)		0.3		7.2		1.0
	Regulatory Assets		8.5		(47.9)		(30.1)		(93.0)
Settlements			21.5		17.7		56.0		16.1
Fair Value as of End of Period		$	(902.3)	$	(916.1)	$	(902.3)	$	(916.1)


		For the Three Months Ended
		September 30, 2012						September 30, 2011
(Millions of Dollars)		CL&P		NSTAR Electric		WMECO		CL&P		NSTAR Electric⁽¹⁾
Derivatives, Net:
Fair Value as of Beginning of Period		$	(910.7)	$	(15.8)	$	(13.5)	$	(858.7)	$	(1.0)
Net Realized/Unrealized Gains/(Losses)
	Included in Regulatory Assets		(2.8)		1.4		9.8		(47.9)		(1.2)
Settlements			22.6		0.6		-		15.5		0.6
Fair Value as of End of Period		$	(890.9)	$	(13.8)	$	(3.7)	$	(891.1)	$	(1.6)

		For the Nine Months Ended
		September 30, 2012						September 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		(23.8)		(13.2)		3.6		(92.9)		(1.3)
Settlements			64.5		2.8		-		7.9		2.1
Fair Value as of End of Period		$	(890.9)	$	(13.8)	$	(3.7)	$	(891.1)	$	(1.6)

⁽¹⁾

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

⁽²⁾

The Net Income impact for the three and nine months ended September 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 gains of $0.2 million and losses of $0.8 million for the three and nine months ended September 30, 2012, respectively.

MARKETABLE SECURITIES (NU, WMECO)

NU maintains a supplemental benefit trust to fund certain of NU’s non-qualified benefit obligations and WMECO maintains a spent nuclear fuel trust to fund WMECO’s prior period spent nuclear fuel liability, each of which hold marketable securities. These trusts are not subject to regulatory oversight by state or federal agencies. As of April 10, 2012, upon consummation of the merger with NSTAR and consolidation of CYAPC and YAEC, NU's marketable securities also includes legally restricted trusts for the decommissioning of nuclear power plants.

The Company elects to record mutual funds purchased by the NU supplemental benefit trust at fair value. As such, any change in fair value of these mutual funds is reflected in Net Income. These mutual funds, classified as Level 1 in the fair value hierarchy, totaled $45.7 million and $41.1 million as of September 30, 2012 and December 31, 2011, respectively, and are included in current Marketable Securities. Net gains on these securities of $1.9 million and $4.6 million for the three months and nine months ended September 30, 2012, respectively and net losses of $7.1 million and $4.9 million for the three and nine months ended September 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 September 30, 2012
				Pre-Tax		Pre-Tax
		Amortized		Unrealized		Unrealized
(Millions of Dollars)		Cost		Gains⁽¹⁾		Losses⁽¹⁾		Fair Value
NU
	Debt Securities⁽²⁾	$	258.5	$	12.3	$	(0.1)	$	270.7
	Equity Securities⁽²⁾		142.3		19.7		(2.6)		159.4
WMECO
	Debt Securities		57.6		0.1		(0.1)		57.6

		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 September 30, 2012 amounts include CYAPC's and YAEC's marketable securities held in nuclear decommissioning trusts of $324.9 million, the majority of which are legally restricted and can only be used for the decommissioning of the nuclear power plants owned by these companies. Unrealized gains and losses for the nuclear decommissioning trusts are offset in Other Long-Term Liabilities on the accompanying 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, the WMECO spent nuclear fuel trust, and in the trusts held by CYAPC and YAEC.Factors considered in determining whether a credit loss exists include the duration and severity of the impairment, adverse conditions specifically affecting the issuer, and the payment history, ratings and rating changes of the security. For asset-backed debt securities, underlying collateral and expected future cash flows are also evaluated.

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

Contractual Maturities: As of September 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⁾	$	54.4	$	54.4	$	18.4	$	18.4
One to five years		60.2		61.6		25.3		25.3
Six to ten years		46.9		50.0		6.4		6.4
Greater than ten years		97.0		104.7		7.5		7.5
Total Debt Securities	$	258.5	$	270.7	$	57.6	$	57.6

⁽¹⁾

Amounts in the Less than one year category include securities in the nuclear decommissioning trusts, 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)			September 30, 2012		December 31, 2011		September 30, 2012		December 31, 2011
Level 1:
	Mutual Funds and Equity Securities		$	205.1	$	41.1	$	-	$	-
	Money Market Funds			40.5		1.8		4.7		0.1
Total Level 1			$	245.6	$	42.9	$	4.7	$	0.1
Level 2:
	U.S. Government Issued Debt Securities
		(Agency and Treasury)		59.8		11.1		18.7		8.0
	Corporate Debt Securities			32.2		16.5		7.0		9.1
	Asset-Backed Debt Securities			31.4		25.9		10.7		7.9
	Municipal Bonds			95.3		16.1		12.7		15.4
	Other Fixed Income Securities			11.5		18.8		3.8		16.6
Total Level 2			$	230.2	$	88.4	$	52.9	$	57.0
Total Marketable Securities			$	475.8	$	131.3	$	57.6	$	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

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.

The amount of short-term borrowings that may be incurred by NSTAR Electric is subject to periodic approval by the FERC. On May 16, 2012, the FERC granted authorization to allow NSTAR Electric to issue total short-term debt securities in an aggregate principal amount not to exceed $655 million outstanding at any one time, effective October 23, 2012 through October 23, 2014.

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 September 30, 2012, there were no borrowings under this facility.

Under this facility, CL&P may borrow at prime rates or LIBOR-based rates, plus an applicable margin based on the higher of S&P’s or Moody’s credit ratings.

In addition, CL&P must comply with certain financial and non-financial covenants, including a consolidated debt to total capitalization ratio. CL&P was in compliance with these covenants as of September 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.

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

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

As of September 30, 2012, NU had $1,098.3 million in short-term borrowings outstanding under its commercial paper program, leaving $51.8 million of available borrowing capacity. The weighted-average interest rate on these borrowings as of September 30, 2012 was 0.459 percent, which is generally based on money market rates. As of September 30, 2012, there were inter-company loans of $1,040.9 million from NU to the subsidiaries ($372.8 million for CL&P, $44.2 million for PSNH, and $172.5 million for WMECO). As of September 30, 2012, NSTAR Electric had $261 million in short-term borrowings outstanding under its commercial paper program, leaving $189 million of available borrowing capacity. The weighted-average interest rate on these borrowings as of September 30, 2012 was 0.349 percent, which is generally based on money market rates.

NU, CL&P, NSTAR Electric, PSNH and WMECO use their available capital resources to fund their respective construction expenditures, meet debt requirements to pay costs, including storm-related costs, and pay dividends and to fund other corporate obligations, such as pension contributions. The current growth in NU’s transmission construction expenditures utilizes a significant amount of cash for projects that have a long-term return on investment and recovery period. In addition, NU’s Regulated companies operate in an environment where recovery of its electric and gas distribution construction expenditures takes place over an extended period of time. This impacts the timing of the revenue stream designed to fully recover the total investment plus a return on the equity portion of the cost and related financing costs. These factors have resulted in NU’s current liabilities exceeding current assets by approximately $1.7 billion, $558 million, $111 million and $217 million at NU, CL&P, NSTAR Electric and WMECO, respectively, as of September 30, 2012.

As of September 30, 2012, approximately $880 million of NU's current liabilities relates to long-term debt that will be paid in the next 12 months. NU, with credit ratings among the highest in the industry, has several options available in the financial markets to repay or refinance these maturities with the issuance of new long-term debt. NU, CL&P, NSTAR Electric, and WMECO will reduce their short-term borrowings with cash received from operating cash flows or with the issuance of new long-term debt, as deemed appropriate given capital requirements and maintenance of NU's credit rating and profile. Management expects the future operating cash flows of NU and its subsidiaries, along with the access to financial markets, will be sufficient to meet any future operating requirements and capital investment forecasted opportunities.

LONG-TERM DEBT (NU, CL&P, NSTAR Electric, WMECO)

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 1.13 percent as of September 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 $179.5 million in additional spent nuclear fuel obligations as of September 30, 2012. 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 September 30, 2012.

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

Notes that were initially issued in September 2011. As a result, the aggregate principal amount of WMECO’s outstanding Series F Notes totaled $250 million.

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

EMPLOYEE BENEFITS

Pension Benefits and Postretirement Benefits Other Than Pensions

NUSCO sponsors a defined benefit retirement 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 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 to CL&P, NSTAR Electric, PSNH and WMECO not included in their respective net periodic benefit expense are as follows:


	Pension and SERP Plans
	For the Three Months Ended				For the Nine Months Ended
	September 30, 2012		September 30, 2011		September 30, 2012		September 30, 2011
(Millions of Dollars)	NU		NU		NU		NU
Service Cost	$	23.0	$	13.8	$	61.1	$	27.5
Interest Cost		53.3		38.3		144.7		76.5
Expected Return on Plan Assets		(59.5)		(42.7)		(161.3)		(85.8)
Actuarial Loss		47.4		21.1		125.0		42.1
Prior Service Cost		2.0		2.4		6.1		4.8
Total - Net Periodic Benefit Expense	$	66.2	$	32.9	$	175.6	$	65.1
Capitalized Pension Expense	$	19.2	$	7.8	$	49.5	$	23.5

	PBOP Plans and Group Welfare Benefit Plans
	For the Three Months Ended				For the Nine Months Ended
	September 30, 2012		September 30, 2011		September 30, 2012		September 30, 2011
(Millions of Dollars)	NU		NU		NU		NU
Service Cost	$	4.4	$	2.3	$	11.3	$	6.8
Interest Cost		14.3		6.4		34.4		19.3
Expected Return on Plan Assets		(11.1)		(5.4)		(28.1)		(16.2)
Actuarial Loss		10.3		4.8		25.5		14.3
Prior Service Credit		(0.5)		(0.1)		(0.9)		(0.2)
Net Transition Obligation Cost		3.1		2.9		9.0		8.7
Total - Net Periodic Benefit Expense	$	20.5	$	10.9	$	51.2	$	32.7


		Pension and SERP Plans
		For the Three Months Ended September 30, 2012								For the Three Months Ended September 30, 2011
				NSTAR								NSTAR
(Millions of Dollars)		CL&P		Electric⁽¹⁾		PSNH		WMECO		CL&P		Electric^{(1), (2)}		PSNH		WMECO
Service Cost		$	5.4	$	7.6	$	2.9	$	1.0	$	4.9	$	6.5	$	2.6	$	1.0
Interest Cost			12.9		14.7		6.1		2.6		13.0		15.2		6.1		2.7
Expected Return on Plan Assets			(17.7)		(16.4)		(7.2)		(4.1)		(19.1)		(17.8)		(5.0)		(4.4)
Actuarial Loss			12.6		15.7		4.2		2.7		8.2		12.2		2.6		1.7
Prior Service Cost/(Credit)			0.9		(0.1)		0.4		0.2		1.1		(0.2)		0.5		0.2
Total - Net Periodic Benefit Expense		$	14.1	$	21.5	$	6.4	$	2.4	$	8.1	$	15.9	$	6.8	$	1.2
Related Intercompany
	Allocations	$	10.7	$	(3.0)	$	2.4	$	2.1	$	8.5	$	(2.3)	$	1.9	$	1.6
Capitalized Pension Expense		$	6.8	$	8.4	$	1.9	$	1.3	$	4.5	$	4.9	$	2.1	$	0.7


		Pension and SERP Plans
		For the Nine Months Ended September 30, 2012								For the Nine Months Ended September 30, 2011
				NSTAR								NSTAR
(Millions of Dollars)		CL&P		Electric^{(1), (2)}		PSNH		WMECO		CL&P		Electric^{(1), (2)}		PSNH		WMECO
Service Cost		$	16.3	$	22.7	$	8.8	$	3.1	$	14.6	$	19.5	$	7.9	$	3.0
Interest Cost			38.5		44.2		18.3		7.9		39.1		45.7		18.4		8.1
Expected Return on Plan Assets			(52.8)		(49.2)		(21.1)		(12.3)		(57.4)		(53.5)		(15.0)		(13.2)
Actuarial Loss			37.0		47.3		12.1		8.0		24.8		36.5		7.8		5.1
Prior Service Cost/(Credit)			2.7		(0.4)		1.1		0.6		3.1		(0.6)		1.5		0.6
Total - Net Periodic Benefit Expense		$	41.7	$	64.6	$	19.2	$	7.3	$	24.2	$	47.6	$	20.6	$	3.6
Related Intercompany
	Allocations	$	32.0	$	(9.2)	$	7.5	$	6.0	$	25.0	$	(6.8)	$	5.7	$	4.6
Capitalized Pension Expense		$	20.2	$	23.6	$	5.8	$	3.7	$	13.4	$	14.7	$	5.9	$	2.1


		PBOP Plans
		For the Three Months Ended September 30, 2012						For the Three Months Ended September 30, 2011
(Millions of Dollars)		CL&P			PSNH		WMECO	CL&P		PSNH		WMECO
Service Cost		$	0.8	$	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)		(2.2)		(1.1)		(0.5)
Actuarial Loss			1.9		0.9		0.3		1.9		0.8		0.3
Net Transition Obligation Cost			1.5		0.6		0.3		1.5		0.6		0.3
Total - Net Periodic Benefit Expense		$	4.2	$	2.0	$	0.7	$	4.4	$	2.0	$	0.8
Related Intercompany
	Allocations	$	2.0	$	0.5	$	0.4	$	2.0	$	0.5	$	0.4

		PBOP Plans
		For the Nine Months Ended September 30, 2012						For the Nine Months Ended September 30, 2011
(Millions of Dollars)		CL&P		PSNH		WMECO		CL&P		PSNH		WMECO
Service Cost		$	2.2	$	1.5	$	0.4	$	2.2	$	1.4	$	0.4
Interest Cost			6.9		3.4		1.5		7.5		3.6		1.6
Expected Return on Plan Assets			(6.8)		(3.4)		(1.6)		(6.5)		(3.3)		(1.5)
Actuarial Loss			5.7		2.7		0.9		5.4		2.4		0.9
Net Transition Obligation Cost			4.6		1.9		1.1		4.6		1.9		1.0
Total - Net Periodic Benefit Expense		$	12.6	$	6.1	$	2.3	$	13.2	$	6.0	$	2.4
Related Intercompany
	Allocations	$	5.9	$	1.5	$	1.1	$	6.2	$	1.5	$	1.1

⁽¹⁾

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

⁽²⁾

NSTAR Electric’s pension expense for the nine months ended September 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 nine months ended September 30, 2012. The NSTAR Electric expenses are not included in the consolidated NU results for the three and nine months ended September 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 nine months ended September 30, 2012, the net periodic postretirement benefit costs allocated to NSTAR Electric were $8.5 million and $25.6 million, respectively, of which $9 million was incurred prior to the closing of NSTAR’s merger with NU. These amounts were $6.4 million and $19.2 million for the three and nine months ended September 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 for the nine months ended September 30, 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 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 $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 $35.2 million and $162.3 million ($87.7 million of which was contributed by PSNH in the first quarter of 2012) for the three and nine months ended September 30, 2012, respectively. NSTAR Electric made contributions to the NSTAR Electric Pension Plan of $18.7 million and $25 million for the three and nine months ended September 30, 2012. NSTAR Electric does not anticipate additional contributions to the pension plan for the remainder of 2012. The actual level of funding may differ from this estimate.

Share-Based Payments

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

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

NU Incentive Plan: NU maintains long-term equity-based incentive plans under the NU Incentive Plan in which NU, CL&P, PSNH and WMECO employees, officers and board members are entitled to participate. The NU Incentive Plan was approved in 2007, and authorized NU to grant up to 4,500,000 new shares for various types of awards, including RSUs and performance shares, to eligible employees, officers, and board members. As of September 30, 2012 and December 31, 2011, NU had 2,501,295 and 2,685,615 common shares, respectively, available for issuance under the NU Incentive Plan. In addition to the NU Incentive Plan, NU maintains an ESPP for eligible employees.

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

RSUs: NU 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		585,135	$	32.98
Converted NSTAR awards upon merger		617,394	$	36.79
Converted from NU performance shares upon merger		451,358	$	34.32
Shares issued		(304,014)	$	27.96
Forfeited		(95,156)	$	34.99
Outstanding as of September 30, 2012		2,214,637	$	32.07

As of September 30, 2012 and December 31, 2011, the number and weighted average grant-date fair value of unvested RSUs was 1,402,517 and $34.69 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 470,218 and $30.00 per share, respectively. As of September 30, 2012, 812,120 RSUs were fully vested and an additional 1,332,391 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		227,683	$	34.37
Converted to RSUs upon merger		(451,358)	$	34.32
Shares issued		(106,773)	$	24.52
Forfeited		-	$	-
Outstanding as of September 30, 2012		152,685	$	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 Nine Months Ended
(Millions of Dollars)	September 30, 2012		September 30, 2011		September 30, 2012		September 30, 2011
Compensation Cost Recognized	$	4.8	$	3.2	$	21.6	$	9.3
Associated Future Income Tax Benefit Recognized		1.9		1.3		8.7		3.7


	For the Three Months Ended
	September 30, 2012								September 30, 2011
(Millions of Dollars)	CL&P		NSTAR Electric		PSNH		WMECO		CL&P		NSTAR Electric⁽¹⁾		PSNH		WMECO
Compensation Cost Recognized	$	0.9	$	0.5	$	0.4	$	0.2	$	1.9	$	1.9	$	0.6	$	0.4
Associated Future Income Tax Benefit Recognized		0.4		0.2		0.1		0.1		0.8		0.8		0.3		0.1

	For the Nine Months Ended
	September 30, 2012								September 30, 2011
(Millions of Dollars)	CL&P		NSTAR Electric⁽¹⁾		PSNH		WMECO		CL&P		NSTAR Electric⁽¹⁾		PSNH		WMECO
Compensation Cost Recognized	$	3.9	$	5.4	$	1.5	$	0.8	$	5.4	$	5.8	$	1.9	$	1.0
Associated Future Income Tax Benefit Recognized		1.6		2.1		0.6		0.3		2.2		2.3		0.7		0.4

⁽¹⁾

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

As of September 30, 2012, there was $30.3 million of total unrecognized compensation cost related to nonvested share-based awards for NU, $6.2 million for CL&P, $8.6 million for NSTAR Electric, $2.1 million for PSNH and $1.3 million for WMECO. This cost is expected to be recognized ratably over a weighted-average period of 2.08 years for NU, 2.17 years for CL&P, 1.91 years for NSTAR Electric, 1.97 years for PSNH and 1.96 years for WMECO.

For the nine months ended September 30, 2012 and 2011, additional tax benefits totaling $3.9 million and $1.4 million, respectively, increased cash flows from financing activities.

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 September 30, 2012 is 4.4 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				$	23.99	$	34.1
Exercised		(405,551)				$	23.74	$	5.3
Forfeited and cancelled		-
Outstanding and Exercisable as of September 30, 2012		2,306,717	$ 18.45	-	$ 28.12	$	23.92	$	34.0

Cash received for options exercised during the nine months ended September 30, 2012 totaled $9.6 million. The tax benefit realized from stock options exercised totaled $2.1 million for the nine months ended September 30, 2012.

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

During 2012, employees purchased 39,422 shares at discounted prices of $33.01 and $37.89. Employees purchased 35,476 shares in 2011 at discounted prices of $31.27 and $32.30. As of September 30, 2012 and December 31, 2011, 857,280 and 896,702 shares, respectively, remained available for future issuance under the ESPP.

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


	As of September 30, 2012				As of December 31, 2011
			Reserve				Reserve
	Number of Sites		(in millions)		Number of Sites		(in millions)
NU		83	$	38.6		59	$	31.7
CL&P		18		3.2		18		2.9
NSTAR Electric⁽¹⁾		14		1.4		13		1.3
PSNH		19		5.2		18		6.6
WMECO		10		0.4		10		0.3

⁽¹⁾

The NSTAR Electric reserve balance and number of sites are not included in the NU consolidated balance as of December 31, 2011.

Included in the number of sites and reserve amounts above are former MGP sites that were operated several decades ago and manufactured gas from coal and other processes, which resulted in certain by-products remaining in the environment that may pose a potential risk to human health and the environment. The reserve balance for NU related to these former MGP sites was $34.2 million and $28.9 million as of September 30, 2012 and December 31, 2011, respectively, and relates primarily to the natural gas business segment.

HWP: HWP, a subsidiary of NU, continues to investigate the potential need for additional remediation at a river site in Massachusetts containing tar deposits associated with an MGP site that HWP sold to HG&E, a municipal utility, dating back to 1902. HWP shares responsibility for site remediation with HG&E and has conducted substantial investigative and remediation activities. The cumulative expense recorded to the reserve for this site since 1994 through September 30, 2012 was $19.5 million, of which $17.4 million had been spent, leaving $2.1 million in the reserve as of September 30, 2012. There were no charges to the reserve for the three or nine months ended September 30, 2012 or 2011. HWP's share of the costs related to this site is not recoverable from customers.

The $2.1 million reserve balance as of September 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 September 30, 2012 now incorporate commitments for NSTAR, which are as follows:


	October - December
(Millions of Dollars)	2012		2013		2014		2015		2016		Thereafter		Totals
Supply/Stranded Cost Contracts/Obligations	$	8.1	$	28.7	$	33.0	$	32.9	$	12.6	$	7.1	$	122.4
Renewable Energy Supply Contracts		16.8		87.3		86.6		87.9		52.1		252.8		583.5
Transmission Support Commitments		1.0		3.7		3.6		3.5		-		-		11.8
Natural Gas Procurement Contracts		54.3		54.0		47.5		24.7		21.6		78.5		280.6
Future Minimum Operating Lease Payments		3.2		11.5		8.4		7.3		5.7		12.2		48.3
Electric Interconnection Agreement		0.9		3.4		3.4		3.4		3.3		41.1		55.5
Totals	$	84.3	$	188.6	$	182.5	$	159.7	$	95.3	$	391.7	$	1,102.1

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 shore.

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. On August 1, 2012, the DOE filed a petition asking the U.S. Court of Appeals for the Federal Circuit to reconsider its unanimous panel decision in favor of the Yankee Companies upholding the trial court's awards to each company in the remanded cases. On September 5, 2012, the U.S. Court of Appeals for the

Federal Circuit denied the DOE’s petition. As a result, the decision becomes final and non-appealable unless, within 90 days, the DOE files a petition for certiorari with the U.S. Supreme Court. 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 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 September 30, 2012:


		Maximum
		Exposure
Subsidiary	Description	(in millions)			Expiration Dates

					October 2012 -
Various	Surety Bonds	$	33.2			November 2015 (1)

Various	NE Hydro Companies' Long-Term Debt	$	6.1			Unspecified

NUSCO and RRR	Lease Payments for Vehicles and Real Estate	$	21		2019 and 2024

NU Enterprises	Surety Bonds, Insurance Bonds and Performance Guarantees	$	111.2	(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 $40.3 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 September 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 $55.7 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.

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, effective September 30, 2011. In response, the New England transmission owners filed testimony and analysis based on standard FERC methodology and precedent, demonstrating that the base ROE of 11.14 percent remained just and reasonable.

On May 3, 2012, the FERC issued an order establishing hearing and settlement procedures for the complaint. The settlement proceedings were subsequently terminated, as the parties had reached an impasse in their efforts to reach a settlement. In August 2012, the FERC trial judge assigned to the complaint established a schedule for the trial phase of the proceedings. Complainant testimony was filed on October 1, 2012, which supported a base ROE of 9 percent. Additional testimony was filed on October 1, 2012 by a group of Massachusetts municipal electric companies, which recommended a base ROE of 8.2 percent. The New England Transmission owners are scheduled to file their testimony on November 20, 2012. Hearings are scheduled for May 2013 and a trial judge’s recommended decision is due in September 2013. A decision from FERC commissioners is expected in 2014. Changes, if any, to the NU transmission companies’ base ROE would be retroactive to October 1, 2011.

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 September 2012, cumulative costs associated with the CPSL program have resulted in an incremental revenue requirement to customers of approximately $95 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 year for 2012 through 2015 in order to continue these programs. CPSL revenues will end once NSTAR Electric has recovered its 2015-related CPSL costs. Realization of these revenues is subject to maintaining certain performance metrics and DPU approval.

Basic Service Bad Debt Adder (NSTAR Electric)

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

NSTAR Electric deferred the unrecovered costs associated with energy-related bad debt as a regulatory asset, which totaled approximately $34 million as of December 31, 2011, as NSTAR Electric had concluded that these costs were probable of recovery in future rates. On June 18, 2010, NSTAR Electric filed an appeal of the DPU’s order with the SJC, which was heard by the SJC in December 2011. On April 11, 2012, the SJC issued a procedural order waiving its standing 130-day rule for issuance of an order on the matter. Due to the delay, NSTAR Electric concluded that while an ultimate outcome on the matter in its favor remained "more likely than not," it could no longer be deemed "probable." As a result, 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 reserve the related regulatory asset on its balance sheet.

On June 4, 2012, the SJC vacated the DPU's June 28, 2007 order and remanded the matter to the DPU for a "statement of reasons, including subsidiary findings, of its conclusion of law and relevant facts." The continued uncertainty of the outcome of the DPU’s proceeding leaves NU and NSTAR Electric unable to conclude that it is probable that the previously reserved amount will ultimately be recovered and therefore 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 September 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	$	154.0	$	116.2	$	105.1
Long-Term Debt			7,612.3		8,378.5		4,950.7		5,517.0
Rate Reduction Bonds			101.3		103.0		112.3		116.8


		As of September 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	$	112.0	$	43.0	$	42.0	$	-	$	-	$	-	$	-
Long-Term Debt			2,584.2		3,063.0		1,603.6		1,846.4		997.9		1,098.0		499.7		564.3
Rate Reduction Bonds			-		-		43.5		44.3		44.1		44.6		13.8		14.0

		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 September 30, 2012 and December 31, 2011 and the respective par values:


	Shares
	Authorized				Issued
	Per Share		As of September 30, 2012
	Par Value		and December 31, 2011		As of September 30, 2012		As of December 31, 2011
NU	$	5		380,000,000		332,471,514		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 September 30, 2012 and December 31, 2011, 18,568,240 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
		September 30, 2012								September 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	$	9,067.6	$	-	$	9,067.6	$	155.6	$	3,915.1	$	1.8	$	3,916.9	$	116.2
Net Income			209.5		-		209.5		-		91.4		-		91.4		-
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			0.8		-		0.8		-		0.9		-		0.9		-
Contributions to NPT			-		-		-		-		-		0.6		0.6		-
Other Transactions, Net			6.3		-		6.3		-		8.5		-		8.5		-
Net Income Attributable to
	Noncontrolling Interests		-		-		-		1.9		-		0.1		0.1		1.4
Other Comprehensive
Income/(Loss)			2.2		-		2.2		-		(9.4)		-		(9.4)		-
Balance as of End of Period		$	9,176.9	$	-	$	9,176.9	$	155.6	$	3,956.2	$	2.5	$	3,958.7	$	116.2

		For the Nine Months Ended
		September 30, 2012								September 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			356.5		-		356.5		-		285.7		-		285.7		-
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			(267.8)		-		(267.8)		-		(146.6)		-		(146.6)		-
Dividends on Preferred Stock			(5.1)		-		(5.1)		(5.1)		(4.2)		-		(4.2)		(4.2)
Issuance of Common Shares			12.2		-		12.2		-		5.1		-		5.1		-
Contributions to NPT			-		0.3		0.3		-		-		0.9		0.9		-
Other Transactions, Net			20.3		-		20.3		-		16.8		-		16.8		-
Net Income Attributable to
	Noncontrolling Interests		(0.1)		0.1		-		5.1		-		0.1		0.1		4.2
Other Comprehensive
Income/(Loss)			6.5		-		6.5		-		(11.8)		-		(11.8)		-
Balance as of End of Period			9,176.9		-		9,176.9		155.6		3,956.2		2.5		3,958.7		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 September 30, 2012.

For the three and nine months ended September 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 weighted average number of common shares outstanding during each period. Diluted EPS is computed on the basis of the weighted average number of common shares outstanding plus the potential dilutive effect if certain securities are converted into common shares. For the nine months ended September 30, 2012, there were 5,688 share awards excluded from the computation as these awards were antidilutive. There were no antidilutive share awards outstanding for the three months ended September 30, 2012 or for the three and nine months ended September 30, 2011.


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

		For the Three Months Ended				For the Nine Months Ended
(Millions of Dollars, except share information)		September 30, 2012		September 30, 2011		September 30, 2012		September 30, 2011
Net Income Attributable to Controlling Interest		$	207.6	$	90.0	$	351.2	$	281.4

Weighted Average Common Shares Outstanding:
	Basic		314,806,441		177,497,862		264,636,636		177,344,481
	Dilutive Effect		999,355		337,486		716,741		303,213
	Diluted		315,805,796		177,835,348		265,353,377		177,647,694
Basic EPS		$	0.66	$	0.51	$	1.33	$	1.59
Diluted EPS		$	0.66	$	0.51	$	1.32	$	1.58

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 September 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 (NU)

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.

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 nine month periods ended September 30, 2012 and 2011. 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.

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

Cash flows used for investments in plant included in the segment information below are cash capital expenditures that do not include amounts incurred but not paid, cost of removal, AFUDC related to equity funds, and the capitalized portions of pension and PBOP expense or income.

As discussed in Note 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.

Effective in the third quarter of 2012, NU's reportable segments are the combined Electric Distribution, Electric Transmission and Natural Gas Distribution segments, based upon the level at which NU's chief operating decision maker assesses performance and makes decisions about the allocation of company resources. Each of NU's subsidiaries, including CL&P, NSTAR Electric, PSNH and WMECO, has one reportable segment. Therefore, separate Transmission and Distribution information is no longer disclosed for CL&P, PSNH or WMECO. NU's operating segments and reporting units are consistent with its reportable business segments.

NU's segment information for the three and nine months ended September 30, 2012 and 2011 is as follows:


		For the Three Months Ended September 30, 2012
		Regulated Companies
		Distribution
(Millions of Dollars)		Electric		Natural Gas		Transmission		Other		Eliminations		Total
Operating Revenues		$	1,483.7	$	91.3	$	235.6	$	219.5	$	(168.6)	$	1,861.5
Depreciation and Amortization			(172.6)		(12.6)		(29.7)		(17.5)		1.1		(231.3)
Other Operating Expenses			(1,027.4)		(77.2)		(66.3)		(216.8)		170.4		(1,217.3)
Operating Income/(Loss)			283.7		1.5		139.6		(14.8)		2.9		412.9
Interest Expense			(45.5)		(8.7)		(26.1)		(12.2)		2.1		(90.4)
Interest Income			(0.3)		-		0.1		2.2		(2.1)		(0.1)
Other Income, Net			2.6		0.2		1.9		324.9		(325.1)		4.5
Income Tax (Expense)/Benefit			(88.8)		2.6		(43.7)		13.8		(1.3)		(117.4)
Net Income/(Loss)			151.7		(4.4)		71.8		313.9		(323.5)		209.5
Net Income Attributable
	to Noncontrolling Interests		(1.2)		-		(0.7)		-		-		(1.9)
Net Income/(Loss) Attributable
	to Controlling Interest	$	150.5	$	(4.4)	$	71.1	$	313.9	$	(323.5)	$	207.6


		For the Nine Months Ended September 30, 2012
		Regulated Companies
		Distribution
(Millions of Dollars)		Electric		Natural Gas		Transmission		Other		Eliminations		Total
Operating Revenues		$	3,499.7	$	361.5	$	627.2	$	582.9	$	(481.5)	$	4,589.8
Depreciation and Amortization			(398.1)		(32.7)		(79.5)		(39.1)		2.6		(546.8)
Other Operating Expenses			(2,654.4)		(292.9)		(179.5)		(614.5)		485.1		(3,256.2)
Operating Income/(Loss)			447.2		35.9		368.2		(70.7)		6.2		786.8
Interest Expense			(123.4)		(22.9)		(71.9)		(32.7)		5.0		(245.9)
Interest Income			1.8		-		0.4		4.8		(4.8)		2.2
Other Income, Net			6.9		0.3		5.8		565.3		(565.5)		12.8
Income Tax (Expense)/Benefit			(117.2)		(5.0)		(119.3)		44.9		(2.8)		(199.4)
Net Income			215.3		8.3		183.2		511.6		(561.9)		356.5
Net Income Attributable
	to Noncontrolling Interests		(3.2)		-		(2.1)		-		-		(5.3)
Net Income Attributable
	to Controlling Interest	$	212.1	$	8.3	$	181.1	$	511.6	$	(561.9)	$	351.2
Cash Flows Used for
	Investments in Plant	$	461.3	$	105.9	$	476.0	$	38.6	$	-	$	1,081.8


		For the Three Months Ended September 30, 2011
		Regulated Companies
		Distribution
(Millions of Dollars)		Electric			Natural Gas		Transmission		Other		Eliminations		Total
Operating Revenues		$	878.6	��	$	59.6	$	159.1	$	142.3	$	(124.7)	$	1,114.9
Depreciation and Amortization			(98.7)			(7.2)		(19.5)		(4.4)		0.8		(129.0)
Other Operating Expenses			(666.8)			(52.3)		(46.7)		(135.7)		119.4		(782.1)
Operating Income			113.1			0.1		92.9		2.2		(4.5)		203.8
Interest Expense			(30.3)			(5.3)		(21.3)		(8.1)		1.1		(63.9)
Interest Income			0.9			-		0.1		1.3		(1.3)		1.0
Other Income/(Loss), Net			0.6			0.4		(1.1)		86.3		(85.8)		0.4
Income Tax (Expense)/Benefit			(25.5)			1.8		(28.5)		4.1		(1.8)		(49.9)
Net Income/(Loss)			58.8			(3.0)		42.1		85.8		(92.3)		91.4
Net Income Attributable
	to Noncontrolling Interests		(0.8)			-		(0.6)		-		-		(1.4)
Net Income/(Loss) Attributable
	to Controlling Interest	$	58.0		$	(3.0)	$	41.5	$	85.8	$	(92.3)	$	90.0


		For the Nine Months Ended September 30, 2011
		Regulated Companies
		Distribution
(Millions of Dollars)		Electric		Natural Gas		Transmission		Other		Eliminations		Total
Operating Revenues		$	2,564.7	$	318.1	$	469.4	$	403.5	$	(358.1)	$	3,397.6
Depreciation and Amortization			(266.3)		(20.2)		(64.3)		(12.7)		2.1		(361.4)
Other Operating Expenses			(1,993.1)		(251.5)		(139.2)		(397.4)		354.3		(2,426.9)
Operating Income/(Loss)			305.3		46.4		265.9		(6.6)		(1.7)		609.3
Interest Expense			(90.9)		(15.6)		(56.6)		(25.3)		3.7		(184.7)
Interest Income			2.7		-		0.4		4.0		(4.0)		3.1
Other Income, Net			7.1		1.2		7.0		321.2		(320.6)		15.9
Income Tax (Expense)/Benefit			(69.0)		(11.3)		(86.4)		11.9		(3.1)		(157.9)
Net Income			155.2		20.7		130.3		305.2		(325.7)		285.7
Net Income Attributable
	to Noncontrolling Interests		(2.4)		-		(1.9)		-		-		(4.3)
Net Income Attributable
	to Controlling Interest	$	152.8	$	20.7	$	128.4	$	305.2	$	(325.7)	$	281.4
Cash Flows Used for
	Investments in Plant	$	385.0	$	73.6	$	254.2	$	36.3	$	-	$	749.1

The following table summarizes NU's segmented total assets:


	Regulated Companies
NU	Distribution
(Millions of Dollars)	Electric		Natural Gas		Transmission		Other		Eliminations		Total
As of September 30, 2012	$	17,576.9	$	2,744.0	$	6,109.3	$	18,396.6	$	(17,069.2)	$	27,757.6
As of December 31, 2011		9,653.1		1,511.3		3,792.9		6,618.0		(5,928.2)		15,647.1

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

See Note 8, "Long-Term Debt," to the unaudited condensed consolidated financial statements for information regarding October 2012 long-term debt redemptions and issuances.

On October 29, 2012, Hurricane Sandy caused extensive damage to NU’s electric distribution system across all three states. For further information on Hurricane Sandy’s impact on NU, see Note 3, "Regulatory Accounting," to the unaudited condensed consolidated financial statements.

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 and Second Quarter 2012 Quarterly Reports 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 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 thisManagement's Discussion and Analysis of Financial Condition and Results of Operations.

The only common equity securities that are publicly traded are common shares of NU. The earnings and EPS of each business discussed below do not represent a direct legal interest in the assets and liabilities allocated to such business but rather represent a direct interest in our assets and liabilities as a whole. EPS by business is a financial measure not recognized under GAAP that is calculated by dividing the Net Income Attributable to Controlling Interest of each business by the weighted average diluted NU common shares outstanding for the period. The discussion below also includes non-GAAP financial measures referencing our third quarter and first nine months of 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 by business and to more fully compare and explain our third quarter and first nine months 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 these items on Net Income Attributable to Controlling Interest, we believe that the non-GAAP presentation is more representative of our financial performance and provides additional and useful information to readers of this report in analyzing historical and future performance by business. These non-GAAP financial measures should not be considered as an alternative to reported Net Income Attributable to Controlling Interest or EPS determined in accordance with GAAP as an indicator of operating performance.

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

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

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

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

changes in weather patterns,

changes in laws, regulations or regulatory policy,

changes in levels and timing of capital expenditures,

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

developments in legal or public policy doctrines,

technological developments,

changes in accounting standards and financial reporting regulations,

actions of rating agencies,

the possibility that expected merger synergies will not be realized or will not be realized within the expected time period, 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 accompanyingManagement's Discussion and Analysis andCombined 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, the results of NSTAR LLC and its subsidiaries, hereinafter referred to as "NSTAR," are included from the date of merger, April 10, 2012, through September 30, 2012 throughout thisManagement'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.

Executive Summary

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

Results and Outlook:

We earned $207.6 million, or $0.66 per share, in the third quarter of 2012, and $351.2 million, or $1.32 per share, in the first nine months of 2012, compared with $90 million, or $0.51 per share, in the third quarter of 2011 and $281.4 million, or $1.58 per share, in the first nine months of 2011. Excluding after-tax merger-related costs of $12.9 million, or $0.04 per share, we earned $220.5 million, or $0.70 per share, in the third quarter of 2012. Excluding after-tax merger and related settlement costs of $105.5 million, or $0.40 per share, we earned $456.7 million, or $1.72 per share, in the first nine months of 2012. The third quarter and first nine months of 2012 earnings improved due primarily to the inclusion of NSTAR effective April 10, 2012 as well as higher transmission segment earnings as a result of increased investments in the transmission infrastructure.

The addition of NSTAR effective April 10, 2012 provided an earnings contribution of $105 million in the third quarter of 2012 and $141 million from April through September 2012. Due to the timing of the merger closing, NSTAR results for the first three months of 2012 are not reflected in NU’s results for the first nine months of 2012.

Our transmission segment earned $71.1 million, or $0.23 per share, in the third quarter of 2012 and $181.1 million, or $0.68 per share, in the first nine months of 2012, compared with $41.5 million, or $0.23 per share, in the third quarter of 2011 and $128.4 million, or $0.72 per share, in the first nine months of 2011.

Our electric distribution segment earned $150.5 million, or $0.48 per share, in the third quarter of 2012 and $212.1 million, or $0.80 per share, in the first nine months of 2012, compared with earnings of $58 million, or $0.33 per share, in the third quarter of 2011, and $152.8 million, or $0.86 per share, in the first nine months of 2011. Third quarter and the first nine months of 2012 results reflect $0.2 million and $51 million, respectively, of after-tax merger and related settlement costs.

Our natural gas distribution segment recorded net losses of $4.4 million, or $0.02 per share, in the third quarter of 2012 and earned $8.3 million, or $0.03 per share, in the first nine months of 2012, compared with net losses of $3 million, or $0.02 per share, in the third quarter of 2011 and earnings of $20.7 million, or $0.12 per share, in the first nine months of 2011. First nine months of 2012 results reflect $2.1 million of after-tax merger and related settlement costs.

NU parent and other companies recorded net losses of $9.6 million, or $0.03 per share, in the third quarter of 2012 and $50.3 million, or $0.19 per share, in the first nine months of 2012, compared with net losses of $ 6.5 million, or $0.03 per share, in the third quarter of 2011 and $20.5 million, or $0.12 per share, in the first nine months of 2011. Third quarter and the first nine months of 2012 results reflect $12.7 million and $52.4 million, respectively, of after-tax merger and related settlement costs.

We project capital expenditures of approximately $7 billion from 2012 through 2015, including approximately $1.7 billion in 2012. Of the $7 billion, we expect to invest approximately $3.5 billion in our electric and natural gas distribution segments, including our generation businesses, and $3.2 billion in our electric transmission segment. In addition, we project capital expenditures of approximately $1.2 billion from 2016 through 2017 in our electric transmission segment.

Legislative, Regulatory, Policy and Other Items:

On August 1, 2012, efforts to settle a complaint filed at FERC by various New England parties concerning the base ROE earned by New England transmission owners ended without a settlement. Soon thereafter, litigation began before a FERC trial judge. On October 1, 2012, the complainants filed additional testimony recommending that the base ROE be lowered from the current 11.14

percent to 9 percent. Certain Massachusetts municipal electric companies were admitted late to the case, and filed testimony recommending a base ROE of 8.2 percent. The trial judge’s ruling is due in September 2013 and a FERC decision is expected in 2014.

On August 3, 2012, Massachusetts Governor Patrick signed into law "An Act Relative to Competitively Priced Electricity in the Commonwealth." The Act (1) requires electric utility companies to file a distribution rate case every five years and natural gas companies every 10 years, limiting those companies to one settlement agreement in a 10-year period, (2) extends the distribution rate case review period to 10 months, and (3) requires all distribution companies to enter into additional cost-effective long-term renewable energy distribution contracts with remuneration of 2.75 percent to each utility company of annual contract payments.

On August 6, 2012, Massachusetts Governor Patrick signed into law "An Act relative to emergency service response of public utility companies" to help improve utility companies’ emergency response and communication. The Act (1) codifies certain emergency response plan provisions, which require utility companies to submit plans for DPU review and approval, (2) requires that all future financial penalties levied to utilities by the DPU relating to violation of storm and emergency service performance standards will be provided to customers, and (3) requires transmission companies to notify appropriate parties before performing vegetation management activities within a right-of-way.

On October 5, 2012, Connecticut announced a draft comprehensive energy strategy. The draft includes a series of policy proposals, which aim to expand energy choices, including natural gas, lower utility bills for Connecticut residents and businesses, improve environmental conditions, create clean energy jobs, and enhance the state’s quality of life. The draft is subject to public comment and is expected to be finalized by the end of 2012. Many of the recommendations in the draft will require actions by the PURA and potentially the legislature.

Liquidity:

Cash and cash equivalents totaled $73.4 million as of September 30, 2012, compared with $6.6 million as of December 31, 2011, while cash capital expenditures totaled $1.1 billion in the first nine months of 2012, compared with $749.1 million in the first nine months of 2011.

Cash flows provided by operating activities totaled $700.8 million in the first nine months of 2012, compared with $837.2 million in the first nine months of 2011 (amounts are net of RRB payments). The reduced cash flows were due primarily to $187.7 millionof 2012 cash disbursements for storm costs primarily related to Tropical Storm Irene and the October 2011 snowstorm, $187.3 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 approximately $34 million of transaction cost payments related to the merger.

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

On November 1, 2012, our Board of Trustees approved a common dividend payment of $0.343 per share, payable December 31, 2012 to shareholders of record as of November 30, 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 third quarter and first nine months of 2012 and 2011 is as follows:


	For the Three Months Ended September 30,								For the Nine Months Ended September 30,
(Millions of Dollars, Except	2012				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)	$	207.6	$	0.66	$	90.0	$	0.51	$	351.2	$	1.32	$	281.4	$	1.58
Regulated Companies	$	217.4	$	0.69	$	96.5	$	0.54	$	454.6	$	1.71	$	301.9	$	1.70
NU Parent and Other Companies		3.1		0.01		(5.9)		(0.03)		2.1		0.01		(10.4)		(0.06)
Non-GAAP Earnings		220.5		0.70		90.6		0.51		456.7		1.72		291.5		1.64
Merger and Related Costs (after-tax)		(12.9)		(0.04)		(0.6)		-		(105.5)		(0.40)		(10.1)		(0.06)
Net Income Attributable to Controlling Interest (GAAP)	$	207.6	$	0.66	$	90.0	$	0.51	$	351.2	$	1.32	$	281.4	$	1.58

⁽¹⁾

Results include the operations of NSTAR from the date of merger, April 10, 2012, through September 30, 2012.

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

Transaction and integration-related costs of $33.2 million at NU parent related to investment advisory fees, attorney fees, and consulting costs;

Change in control costs and other compensation costs of $12.2 million at NU parent and NSTAR;

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

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

Excluding the impact of merger-related costs, earnings increased by $129.9 million in the third quarter of 2012 due primarily to the inclusion of NSTAR effective April 10, 2012, higher transmission segment earnings as a result of increased investments in the transmission infrastructure, and higher retail electric sales. On an earnings per share basis, the earnings contribution of $105 million in the third quarter of 2012 from NSTAR was partially offset by the issuance of 136 million common shares to close the merger. Offsetting these favorable earnings impacts were higher operations and maintenance expenses, including higher pension and healthcare expenses, higher vegetation management costs and storm restoration costs, depreciation, property tax expense, and higher interest expense as a result of new long-term debt issued in September 2011.

Excluding the impact of merger and related settlement costs, earnings increased by $165.2 million in the first nine months of 2012 due primarily to the inclusion of NSTAR effective April 10, 2012 and higher transmission segment earnings. On an earnings per share basis, the earnings contribution of $141 million from April 2012 through September 2012 from NSTAR was partially offset by the impact of the issuance of 136 million common shares to close the merger. Offsetting these favorable impacts were lower retail electric and firm natural gas sales due primarily to significantly milder weather in the first quarter of 2012, compared with the same period in 2011, higher pension expense, increased costs in utility 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. Generation activities of PSNH and WMECO are included in our electric distribution segment. A summary of our segment earnings for the third quarter and first nine months of 2012 and 2011 is as follows:


	For the Three Months Ended September 30,				For the Nine Months Ended September 30,
(Millions of Dollars)	2012		2011		2012		2011
Electric Distribution⁽¹⁾	$	150.7	$	58.0	$	263.1	$	152.8
Transmission⁽¹⁾		71.1		41.5		181.1		128.4
Natural Gas Distribution⁽¹⁾		(4.4)		(3.0)		10.4		20.7
Total Regulated Companies		217.4		96.5		454.6		301.9
Merger and Related Costs (after-tax)		(0.2)		-		(53.1)		-
Net Income – Regulated Companies	$	217.2	$	96.5	$	401.5	$	301.9

⁽¹⁾

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

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

Excluding the $0.2 million and $51 million of after-tax merger and related settlement costs in the third quarter and first nine months of 2012, respectively, the higher electric distribution segment earnings in the third quarter and first nine months of 2012 as compared to the same periods in 2011 were due primarily to the addition of the NSTAR Electric distribution business results. Excluding $0.2 million of after-tax merger-related costs, NSTAR Electric’s distribution business earned $90.4 million in the third quarter of 2012 and excluding $10.8 million of after-tax merger and related settlement costs, primarily related to customer bill credits, NSTAR Electric’s distribution business earned $132.3 million in the second and third quarters of 2012. For further information regarding NSTAR Electric’s third quarter and first nine months of 2012 earnings, as compared to the same periods in 2011, see "Results of Operations – NSTAR Electric Company and Subsidiaries – Earnings Summary" in thisManagement's Discussion and Analysis of Financial Condition and Results of Operations.

Excluding the merger-related costs and the addition in 2012 of NSTAR Electric’s distribution business results, our third quarter 2012 electric distribution segment earnings were $2.3 million higher than the same period of 2011 due primarily to higher retail electric sales at our electric companies, the favorable impact of PSNH’s 2010 distribution rate case decision related to the additional increase to annualized rates that was effective July 1, 2012, and the absence of a $5.3 million pre-tax charge to establish a reserve related to a WMECO wholesale billing adjustment in the third quarter of 2011. Partially offsetting this increase was higher operation and maintenance expenses, including pension expense, vegetation management and storm restoration costs, and higher income tax expense.

Excluding the merger and related settlement costs and the addition in 2012 of NSTAR Electric’s distribution business results, our first nine months of 2012 electric distribution segment earnings were $22 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. In addition, our distribution segment had higher pension expense and an increase in system maintenance, higher storm restoration costs and vegetation management costs, higher depreciation and property taxes, and higher income tax expense, partially offset by the absence of a $5.3 million pre-tax charge to establish a reserve related to a WMECO wholesale billing adjustment in the third quarter of 2011 and the favorable impacts of CL&P’s 2010 distribution rate case decision on rates effective July 1, 2011 and PSNH's 2010 distribution rate case decision on rates effective July 1, 2012.

Excluding the $2.1 million after-tax merger-related costs recognized in the second quarter of 2012 and the addition of NSTAR Gas’ results (losses of $2.3 million and $2.1 million in the third quarter and for the first nine months of 2012, respectively) our natural gas distribution segment earnings were $0.9 million higher and $8.2 million lower in the third quarter of 2012 and for the first nine months of 2012, respectively, when compared to the same periods of 2011. The third quarter earnings improvement was due primarily to the favorable impacts of the Yankee Gas 2011 rate case decision related to the additional increase to annualized rates that was effective July 1, 2012, partially offset by higher depreciation and property tax expense. The first nine months of 2012 earnings were lower than the same period of 2011 due primarily to a decrease in total firm natural gas sales, which was primarily the result of warmer than normal weather in the first half of 2012 as compared to the first half of 2011, and higher depreciation and property tax expense. These costs were partially offset by lower operations and maintenance costs as well as the favorable impacts of the Yankee Gas 2011 rate case decision related to the additional increase to annualized rates that was effective July 1, 2012.

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


	For the Three Months Ended September 30, 2012 Compared to 2011			For the Nine Months Ended September 30, 2012 Compared to 2011
	Sales (GWh)		Percentage	Sales (GWh)		Percentage
NU – Electric	2012⁽¹⁾	2011	Increase	2012⁽¹⁾	2011	Increase
Residential	6,217	4,041	53.8%	14,640	11,393	28.5%
Commercial	7,614	3,928	93.9%	17,611	10,934	61.1%
Industrial	1,563	1,199	30.3%	4,068	3,352	21.3%
Other	107	78	37.0%	289	238	21.3%
Total	15,501	9,246	67.7%	36,608	25,917	41.3%

⁽¹⁾

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


	For the Three Months Ended September 30, 2012 Compared to 2011				For the Nine Months Ended September 30, 2012 Compared to 2011
	CL&P	NSTAR Electric⁽²⁾	PSNH	WMECO	CL&P	NSTAR Electric⁽²⁾	PSNH	WMECO
Electric	Percentage Increase/ (Decrease)	Percentage Increase/ (Decrease)	Percentage Increase/ (Decrease)	Percentage Increase/ (Decrease)	Percentage Increase/ (Decrease)	Percentage Decrease	Percentage Increase/ (Decrease)	Percentage Increase/ (Decrease)
Residential	4.1 %	4.4 %	2.2 %	2.2 %	(2.5)%	(0.3)%	(1.4)%	(2.8)%
Commercial	(1.8)%	0.7 %	1.5 %	(0.2)%	(2.2)%	(1.6)%	(0.5)%	0.7 %
Industrial	0.8 %	(8.6)%	0.8 %	0.5 %	0.5 %	(5.9)%	1.0 %	(0.7)%
Other	3.1 %	0.6 %	(2.5)%	(3.4)%	2.6 %	(11.8)%	(0.6)%	(5.4)%
Total	1.2 %	1.3 %	1.7 %	0.9 %	(2.0)%	(1.5)%	(0.6)%	(1.0)%

⁽²⁾

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


	For the Three Months Ended September 30, 2012 Compared to 2011			For the Nine Months Ended September 30, 2012 Compared to 2011
	Sales (million cubic feet)		Percentage	Sales (million cubic feet)		Percentage
NU – Firm Natural Gas	2012⁽³⁾	2011	Increase	2012⁽³⁾	2011	Increase
Residential	2,413	805	199.7%	11,787	9,599	22.8%
Commercial	4,230	2,172	94.8%	16,768	12,570	33.4%
Industrial	4,053	3,374	20.1%	13,847	12,046	15.0%
Total	10,696	6,351	68.4%	42,402	34,215	23.9%
Total, Net of Special Contracts⁽⁴⁾	9,462	4,204	125.1%	37,708	27,593	36.7%

⁽³⁾

NU firm natural gas results include the sales of NSTAR Gas from the date of merger, April 10, 2012, through September 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 September 30, 2012 Compared to 2011		For the Nine Months Ended September 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	18.5 %	8.9 %	(15.6)%	(18.7)%
Commercial	(1.3)%	3.0 %	(9.6)%	(9.5)%
Industrial	(5.4)%	(11.1)%	(2.9)%	(4.6)%
Total	(1.0)%	1.7 %	(8.9)%	(13.0)%
Total, Net of Special Contracts⁽⁶⁾	20.2 %		(4.1)%

⁽⁵⁾

NSTAR Gas’ sales data for the three and nine months ended September 30, 2012 compared to 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. Industrial sales are less sensitive to temperature variations than residential and commercial sales. Weather impacts electric sales primarily during the summer and natural gas sales during the winter season in our service territories (natural gas sales are more sensitive to temperature variations than electric sales). Customer heating or cooling usage may not directly correlate with historical levels or with the level of degree-days that occur, particularly when weather patterns experienced are consistently colder or warmer. In addition, our electric and natural gas businesses are sensitive to variations in daily weather, are highly influenced by New England’s seasonal weather variations, and are susceptible to damage from major storms and other natural events and disasters that could adversely affect our ability to provide energy.

For the third quarter and first nine months 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 September 30, 2012.

For the third quarter of 2012, actual and weather normalized (based on 30-year average temperatures) retail electric sales for each of our four electric companies increased, as compared to the same period in 2011. Cooling degree days were 2 percent higher than last year in Connecticut and western Massachusetts and 6 percent higher than last year in New Hampshire. On a weather normalized basis, the average NU combined consolidated total retail electric sales increased 1.1 percent in the third quarter of 2012, as compared to the third quarter of 2011, assuming NSTAR Electric had been part of the NU combined electric distribution system for all periods under consideration. We believe these increases were due in part to an increase in the number of residential and commercial

customers and the impact of lower prices of electricity, partially offset by increased conservation efforts amongst all our customer classes. For WMECO, the fluctuations in retail electric sales no longer impact earnings as the DPU approved a sales decoupling plan effective February 1, 2011. Under this decoupling plan, WMECO now has an established annual level of baseline distribution delivery service revenues of $125.4 million that it is able to recover. This effectively breaks the relationship between sales volume and revenues recognized.

For the first nine months of 2012, actual retail electric sales for each of our four electric companies 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 were 21 percent lower than last year in Connecticut and western Massachusetts, 19 percent lower than last year in the Boston metropolitan area, and 16 percent lower than last year in New Hampshire. On a weather normalized basis, the average NU combined consolidated total retail electric sales decreased 0.3 percent in the first nine months of 2012, as compared to the first nine months 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 the third quarter and first nine months 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 September 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 nine months 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 first nine months of 2012, as compared to the same period in 2011, were 21 percent lower in Connecticut. On a weather normalized basis, Yankee Gas’ first nine months of 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 were unchanged in the third quarter of 2012, as compared to the third 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 2.9 percent in the first nine months of 2012, as compared to the first nine months 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 losses of $9.6 million in the third quarter of 2012, compared with $6.5 million in net losses in the third quarter of 2011. Excluding merger-related costs of $12.7 million and $0.6 million in the third quarter of 2012 and 2011, respectively, NU parent and other companies recorded net income of $3.1 million and net losses of $5.9 million, respectively. NU parent and other companies recorded net losses of $50.3 million in the first nine months of 2012, compared with $20.5 million in the first nine months of 2011. Excluding merger and related settlement costs of $52.4 million and $10.1 million in the first nine months of 2012 and 2011, respectively, NU parent and other companies recorded net income of $2.1 million and net losses of $10.4 million. 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 inclusion of NSTAR Communications, Inc., the wholly owned unregulated business of NSTAR.

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

On October 29, 2012, Hurricane Sandy caused extensive damage to our electric distribution system across all three states. We estimate that approximately 1.5 million of our 3.1 million electric distribution customers were without power during or following the storm, with approximately 850,000 of those customers in Connecticut, approximately 472,000 in Massachusetts, and approximately 220,000 in New Hampshire. Restoration costs cannot be estimated at this time. We expect the costs to meet the criteria for specific cost recovery in Connecticut, Massachusetts, and New Hampshire and, as a result, we do not expect the storm to have a material impact to the results of operations of CL&P, NSTAR Electric, PSNH or WMECO. Each operating company will seek recovery of these anticipated deferred storm costs through its applicable regulatory recovery process.

Liquidity

Consolidated: Cash and cash equivalents totaled $73.4 million as of September 30, 2012, compared with $6.6 million as of December 31, 2011.

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. As of September 30, 2012, there were no borrowings under this credit facility.

NU, CL&P, NSTAR Electric, PSNH and WMECO use their available capital resources to fund their respective construction expenditures, meet debt requirements, to pay costs, including storm-related costs, and dividends and to fund other corporate obligations, such as pension contributions. The current growth in NU’s transmission construction expenditures utilizes a significant amount of cash for projects that have a long-term return on investment and recovery period. In addition, NU’s Regulated companies operate in an environment where recovery of its electric and gas distribution construction expenditures takes place over an extended period of time. This impacts the timing of the revenue stream designed to fully recover the total investment plus a return on the equity portion of the cost and related financing costs. These factors have resulted in NU’s current liabilities exceeding current assets by approximately $1.7 billion, $558 million, $111 million and $217 million at NU, CL&P, NSTAR Electric and WMECO, respectively, as of September 30, 2012.

As of September 30, 2012, approximately $880 million of NU's current liabilities relates to long-term debt that will be paid in the next 12 months. NU, with credit ratings among the highest in the industry, has several options available in the financial markets to repay or refinance these maturities with the issuance of new long-term debt. NU, CL&P, NSTAR Electric, and WMECO will reduce their short-term borrowings with cash received from operating cash flows or with the issuance of new long-term debt, as deemed appropriate given our capital requirements and maintenance of our credit rating and profile. Management expects the future operating cash flows of NU and its subsidiaries, along with the access to financial markets, will be sufficient to meet any future operating requirements and capital investment forecasted opportunities.

Cash flows provided by operating activities in the first nine months of 2012 totaled $700.8 million, compared with cash flows provided by operating activities of $837.2 million in the first nine months 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 $187.7 millionof 2012 cash disbursements for storm costs primarily related to Tropical Storm Irene and the October 2011 snowstorm, as compared to payments of approximately $75 million in the first nine months of 2011, $187.3 million of 2012 Pension Plan cash contributions, as compared to NU's Pension Plan contribution of $124.4 million in the first nine months 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, and $27 million in bill credits provided to CL&P residential customers in February 2012 related to the October 2011 snowstorm. In addition, there were approximately $34 million of transaction cost payments related to the merger and net income tax payments of $4.6 million in the first nine months of 2012, as compared to net income tax refunds of $76.1 million in the first nine months 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 $267.4 million in the first nine months of 2012, compared with $145.9 million in the first nine months 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 November 1, 2012, our Board of Trustees approved a common dividend payment of $0.343 per share, payable December 31, 2012 to shareholders of record as of November 30, 2012.

In the first nine months of 2012, CL&P, NSTAR LLC, PSNH, and WMECO paid $100.5 million, $105.7 million, $74.7 million, and $9.4 million, respectively, in common dividends to NU parent. In the second and third quarters of 2012, NSTAR Electric and NSTAR Gas paid $131.6 million and $8 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 nine months of 2012 and 2011 is as follows:


	For the Nine Months Ended September 30,
(Millions of Dollars)		2012		2011
CL&P	$	332.3	$	305.6
NSTAR Electric⁽¹⁾		205.3		N/A
PSNH		161.0		167.4
WMECO		218.2		153.5
Natural Gas⁽¹⁾		105.9		73.6
NPT		20.5		12.7
Other		38.6		36.3
Total	$	1,081.8	$	749.1

⁽¹⁾

Cash capital expenditures include NSTAR from the date of merger, April 10, 2012, through September 30, 2012.

The increase in our cash capital expenditures was the result of the addition of NSTAR’s capital expenditures in the second and third quarters of 2012 and higher transmission segment cash capital expenditures of $132.2 million, primarily at WMECO and CL&P.

Business Development and Capital Expenditures

Consolidated: Our consolidated capital expenditures, including amounts incurred but not paid, cost of removal, AFUDC, and the capitalized portions of pension and PBOP expense or income (all of which are non-cash factors), totaled $1.1 billion in the first nine months of 2012, compared with $822.5 million in the first nine months of 2011. These amounts included $30.9 million and $38.4 million in the first nine months of 2012 and 2011, respectively, related to our corporate service companies, NUSCO and RRR.

Transmission Business: Transmission business capital expenditures increased by $189.7 million in the first nine months 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 and third quarters of 2012. A summary of transmission capital expenditures by company in the first nine months of 2012 and 2011 is as follows:


	For the Nine Months Ended September 30,
(Millions of Dollars)	2012		2011
CL&P	$	148.2	$	78.3
NSTAR Electric⁽¹⁾		79.4		N/A
PSNH		44.5		38.4
WMECO		179.3		153.3
NPT		21.8		13.5
Total Transmission Segment	$	473.2	$	283.5

⁽¹⁾

Transmission capital expenditures for NSTAR Electric are from the date of merger, April 10, 2012, through September 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 September 30, 2012, the project was approximately 85 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. Connecticut Siting Council hearings were completed in the summer of 2012 and a CSC decision is expected in early 2013. Decisions in Rhode Island and Massachusetts are 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, now referred to as the "Greater Hartford Central Connecticut Project" (GHCC) due to the expanded scope of ISO-NE’s reassessment, is the third major part of NEEWS. ISO-NE presented its preliminary needs analysis for the GHCC to the ISO-NE Planning Advisory Committee in August 2012. The results showed severe thermal overloads and voltage violations in each of the four study areas now and in the near future. A combination of 345 kV and 115 kV transmission solutions are being considered to correct these reliability concerns and a set of preferred solutions are expected to be identified in 2013. At this time, we expect that in aggregate the cost and timing of those projects to be similar to what was initially forecast for CCRP, which was $301 million.

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

Through September 30, 2012, CL&P and WMECO had capitalized $206.3 million and $488.7 million, respectively, in costs associated with NEEWS, of which $73.7 million and $154 million, respectively, were capitalized in the first nine months 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.

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

Northern Pass: Northern Pass is NPT's planned HVDC transmission line from the Québec-New Hampshire border to Franklin, New Hampshire and an associated alternating current radial transmission line between Franklin and Deerfield, New Hampshire. Northern Pass will interconnect at the Québec-New Hampshire border with a planned HQ HVDC transmission line. Effective April 10, 2012, as a result of the merger, NUTV owned 100 percent of NPT.

We estimate the costs of the Northern Pass transmission project will be approximately $1.1 billion (including capitalized AFUDC). Through September 30, 2012, we capitalized $58.8 million in costs associated with Northern Pass.

NPT continues to secure rights 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 shortly and file the new route with the DOE by year end 2012, which should support construction beginning in late 2014, with the project to be completed by the end of 2016 or early 2017.

Greater Boston Reliability and Boston Network Improvements: As a result of continued analysis of the transmission needs to enhance system reliability and improve capacity in eastern Massachusetts, NSTAR Electric will likely need to implement a series of new transmission initiatives over the next five years. We have included approximately $500 million in our five-year capital program related to these initiatives.

Distribution Business: A summary of distribution capital expenditures by company for the first nine months of 2012 and 2011 is as follows:


	For the Nine Months Ended September 30,
(Millions of Dollars)		2012		2011
CL&P:
Basic Business	$	55.5	$	117.9
Aging Infrastructure		133.2		81.6
Load Growth		57.8		41.3
Total CL&P		246.5		240.8
NSTAR Electric:
Basic Business		31.9		N/A
Aging Infrastructure		76.6		N/A
Load Growth		7.3		N/A
Total NSTAR Electric⁽¹⁾		115.8		N/A
PSNH:
Basic Business		16.1		28.3
Aging Infrastructure		33.3		18.0
Load Growth		14.0		16.9
Total PSNH		63.4		63.2
WMECO:
Basic Business		10.4		15.2
Aging Infrastructure		13.8		7.8
Load Growth		4.9		5.1
Total WMECO		29.1		28.1
Total - Electric Distribution (excluding Generation)		454.8		332.1
Total - Natural Gas⁽¹⁾		111.9		74.1
Other Distribution		0.2		0.6
Total Electric and Natural Gas		566.9		406.8
PSNH Generation:
Clean Air Project		22.2		74.1
Other		6.8		13.6
Total PSNH Generation		29.0		87.7
WMECO Generation		0.5		6.1
Total Distribution Segment	$	596.4	$	500.6

⁽¹⁾

Distribution capital expenditures for NSTAR Electric and NSTAR Gas are from the date of merger, April 10, 2012, through September 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, CL&P filed a $300 million plan with the PURA to improve the resiliency of its 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 conductors), 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 on the plan is expected in late December 2012.

Projected Capital Expenditures: A summary of the projected capital expenditures for the Regulated companies' electric transmission business for 2012 through 2017 and for their distribution business (including generation) for 2012 through 2015, including our corporate service companies' capital expenditures on behalf of the Regulated companies, is as follows:


	Year
(Millions of Dollars)	2012		2013		2014		2015		2016		2017		2013-2017 Total
CL&P Transmission	$	200	$	170	$	243	$	157	$	135	$	89	$	794
NSTAR Electric Transmission⁽¹⁾		206		178		198		278		222		248		1,124
PSNH Transmission		56		120		147		102		63		15		447
WMECO Transmission		222		110		102		77		11		2		302
NPT		34		49		238		309		447		-		1,043
Total Transmission	$	718	$	627	$	928	$	923	$	878	$	354	$	3,710
Electric Distribution⁽¹⁾		665		662		648		635
Generation		51		61		50		44
Natural Gas⁽¹⁾		173		163		160		161
Total Distribution	$	889	$	886	$	858	$	840
Corporate Service Companies	$	104	$	62	$	62	$	55
Total	$	1,711	$	1,575	$	1,848	$	1,818

⁽¹⁾

Results include capital expenditures for NSTAR Electric and NSTAR Gas for the full year 2012 and have been provided for comparative purposes only.

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

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 September 30, 2012, we were in a total net underrecovery position of $11.9 million, of which the transmission businesses of CL&P and WMECO were in an overrecovery position of $5.6 million, $3 million, respectively, and NSTAR Electric and PSNH were in an underrecovery position of $19.5 million and $1 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, effective September 30, 2011. In response, the New England transmission owners filed testimony and analysis based on standard FERC methodology and precedent, demonstrating that the base ROE of 11.14 percent remained just and reasonable.

On May 3, 2012, the FERC issued an order establishing hearing and settlement procedures for the complaint. The settlement proceedings were subsequently terminated, as the parties had reached an impasse in their efforts to reach a settlement. In August 2012, the FERC trial judge assigned to the complaint established a schedule for the trial phase of the proceedings. Complainant testimony was filed on October 1, 2012, which supported a base ROE of 9 percent. Additional testimony was filed on October 1, 2012 by a group of Massachusetts municipal electric companies, which recommended a base ROE of 8.2 percent. The New England Transmission owners are scheduled to file their testimony November 20, 2012. Hearings are scheduled for May 2013 and a trial judge’s recommended decision is due in September 2013. A decision from FERC commissioners is expected in 2014. Changes, if any, to the NU transmission companies’ base ROE would be retroactive to October 1, 2011.

As of September 30, 2012, CL&P, NSTAR Electric, PSNH, and WMECO had approximately $2.1 billion of aggregate shareholder equity invested in their transmission facilities. As a result, each 10 basis point change in the authorized base ROE would change annual consolidated earnings by an approximate $2.1 million. We cannot at this time predict the ultimate outcome of this proceeding or its impact on CL&P’s, NSTAR Electric’s, PSNH’s, or WMECO’s respective financial position, results of operations or cash flows.

FERC Order No. 1000: On October 25, 2012, ISO-NE and a majority of the New England transmission owners, including CL&P, NSTAR Electric, PSNH and WMECO, made a comprehensive compliance filing as required by FERC Order No. 1000 and Order No. 1000-A, issued on July 21, 2011 and May 17, 2012, respectively. The compliance filing seeks to satisfy FERC’s goals of improving transmission planning coordination, developing explicit cost allocation procedures for transmission projects and including in regional tariffs those transmission needs which are driven by public policy requirements. The filing also explains how the existing reliability planning process in New England has led to the addition of a multitude of transmission projects in service over the past decade, due in large part to the right and obligation of the New England transmission owners under the Transmission Operating Agreement with ISO-NE, approved by the FERC in 2004, to build projects to satisfy identified reliability needs in the region. ISO-NE and the New England transmission owners have requested that FERC continue to recognize the respective rights and obligations under the Transmission Operating Agreement and leave the region’s reliability planning process intact. We cannot predict the final outcome or impact on us, however implementation in New England, including within our service territories, may expose us to competition for construction of transmission projects, additional regulatory considerations and potential delay with respect to future transmission projects.

Regulatory Developments and Rate Matters

The Regulated companies' distribution rates are set by their respective state regulatory commissions, and their tariffs include mechanisms for periodically adjusting their rates. Other than as described below, for the third quarter ended September 30, 2012, changes made to the Regulated companies’ rates did not have a material impact on their earnings, financial position, or cash flows. For further information, see "Financial Condition and Business Analysis – Regulatory Developments and Rate Matters" included in Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations," of the NU 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 standards, and probable that it will be able to recover its deferred costs.

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 natural 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 was 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, 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 Business" in thisManagement'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 September 2012, cumulative costs associated with the CPSL program have resulted in an incremental revenue requirement to customers of approximately $95 million. These amounts include incremental operations and maintenance costs and the related revenue requirement for specific capital investment relative to the CPSL programs.

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

Distribution Rates: In the fourth quarter of each year, NSTAR Electric files rate adjustments for effect on the following January 1^st. These rate adjustments include several fully reconciling cost recovery items. There are proceedings involving the reconciliation of cost recovery items that remain outstanding at the DPU. NSTAR Electric cannot predict the timing or the ultimate outcome of these filings.

New Hampshire:

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. A hearing was held on October 18, 2012, but was not completed. Hearings will continue on November 26, 2012 with a final decision expected by the end of 2012.

On September 28, 2012, PSNH filed a preliminary request with the NHPUC to adjust its ES and SCRC rates effective with services rendered on and after January 1, 2013. PSNH’s request proposed to increase the current ES billing rate to reflect projected market costs for 2013 and to decrease the current SCRC billing rate to reflect the full amortization of RRBs at the end of April 2013. The net impact to customers that purchase energy from PSNH is a net increase of 0.77 cents per kWh in total rates. PSNH expects to file an updated rate proposal in early December 2012 prior to a hearing to be held with the NHPUC.

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 a comprehensive prudence review of the Clean Air Project and the establishment of a permanent rate. The temporary rates will remain in effect until a permanent rate allowing full recovery of all prudently incurred costs is approved. At that time, the NHPUC will reconcile recoveries collected under the temporary rates with final approved rates. The NHPUC has suspended the procedural schedule for the prudence review pending issuance of an order on preliminary substantive and procedural matters. It is estimated that such an order will be issued in late November 2012, at which time a new procedural schedule will be established. 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. On September 6, 2012, a consultant for the NHPUC filed a report with the NHPUC concluding that PSNH had effectively managed the Clean Air Project.

Legislative and Policy Matters

Connecticut: On October 5, 2012, Connecticut announced a draft comprehensive energy strategy ("draft"). The draft includes a series of policy proposals, which aim to expand energy choices, lower utility bills for Connecticut residents and businesses, improve environmental conditions, create clean energy jobs, and enhance the state’s quality of life. It also includes a seven-year initiative for expanding natural gas use with a goal of providing nearly 300,000 utility customers with access to natural gas, building an estimated 900 miles of new natural gas mains, and estimates of capital costs to be incurred by natural gas utility companies to connect customers on or near natural gas mains. In addition to natural gas expansion, the draft also calls for a significant expansion of energy efficiency investment in Connecticut, a review of Connecticut’s Renewable Energy Portfolio Standards (possibly including Canadian hydroelectric generation as a qualifying resource), and investment in alternative fuel transportation. The draft is subject to public comment and is expected to be finalized by the end of 2012. Many of the recommendations in the draft will require actions by the PURA and potentially the legislature. As such, the full impact of the draft energy strategy is not reflected in our electric distribution, transmission or natural gas business segment capital investment projections discussed above.

2012 Massachusetts Legislation:

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

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

Extends the distribution rate case review period to 10 months;

Requires all distribution companies, through a competitive bidding process and subject to DPU approval, to enter into additional cost-effective long-term renewable energy contracts with terms of 10 to 20 years, not to exceed four percent of annual load. Electric utility companies will be allowed a remuneration of 2.75 percent of the annual payments under the contracts to compensate them for accepting the financial obligation of the contracts;

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

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

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

Critical Accounting Policies

The preparation of financial statements in conformity with GAAP requires management to make estimates, assumptions and at times difficult, subjective or complex judgments. Changes in these estimates, assumptions and judgments, in and of themselves, could materially impact our financial position, results of operations or cash flows. Our management communicates to and discusses with 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 and Second Quarter 2012 Quarterly Reports 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 atwww.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 nine months ended September 30, 2012 and 2011. The nine months ended September 30, 2012 amounts include the operations of NSTAR from the date of the merger, April 10, 2012, through September 30, 2012.


			Operating Revenues and Expenses								Operating Revenues and Expenses
			For the Three Months Ended September 30,								For the Nine Months Ended September 30,
(Millions of Dollars)			2012		2011				Percent		2012^(a)		2011		Increase/		Percent
(Millions of Dollars)			2012		2011		Increase		Percent		2012^(a)		2011		(Decrease)		Percent
Operating Revenues			$	1,861.5	$	1,114.9	$	746.6	67.0	%	$	4,589.8	$	3,397.6	$	1,192.2	35.1	%
Operating Expenses:
	Purchased Power, Fuel and Transmission			602.8		406.2		196.6	48.4			1,540.1		1,285.4		254.7	19.8
	Operations and Maintenance			395.5		255.6		139.9	54.7			1,187.4		788.9		398.5	50.5
	Depreciation			144.5		75.2		69.3	92.2			369.8		222.8		147.0	66.0
	Amortization of Regulatory Assets, Net			43.8		36.2		7.6	21.0			74.9		86.7		(11.8)	(13.6)
	Amortization of Rate Reduction Bonds			43.0		17.7		25.3	(b)			102.1		52.0		50.1	96.3
	Energy Efficiency Programs			98.3		35.2		63.1	(b)			209.1		99.7		109.4	(b)
	Taxes Other Than Income Taxes			120.7		85.0		35.7	42.0			319.6		252.8		66.8	26.4
		Total Operating Expenses		1,448.6		911.1		537.5	59.0			3,803.0		2,788.3		1,014.7	36.4
Operating Income			$	412.9	$	203.8	$	209.1	(b)	%	$	786.8	$	609.3	$	177.5	29.1	%

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



Operating Revenues
		For the Three Months Ended September 30,								For the Nine Months Ended September 30,
(Millions of Dollars)		2012		2011		Increase		Percent		2012^(a)		2011		Increase		Percent
Electric Distribution		$	1,483.7	$	878.6	$	605.1	68.9	%	$	3,499.7	$	2,564.7	$	935.0	36.5	%
Natural Gas Distribution			91.3		59.6		31.7	53.2			361.5		318.1		43.4	13.6
	Total Distribution		1,575.0		938.2		636.8	67.9			3,861.2		2,882.8		978.4	33.9
Transmission			235.6		159.1		76.5	48.1			627.2		469.4		157.8	33.6
	Total Regulated Companies		1,810.6		1,097.3		713.3	65.0			4,488.4		3,352.2		1,136.2	33.9
Other and Eliminations			50.9		17.6		33.3	(b)			101.4		45.4		56.0	(b)
Total Operating Revenues		$	1,861.5	$	1,114.9	$	746.6	67.0	%	$	4,589.8	$	3,397.6	$	1,192.2	35.1	%

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


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

	For the Three Months Ended September 30,					For the Nine Months Ended September 30,
	2012	2011	Increase	Percent		2012^(a)	2011	Increase	Percent
Retail Electric Sales in GWh	15,501	9,246	6,255	67.7	%	36,608	25,917	10,691	41.3	%
Firm Natural Gas Sales in Million Cubic Feet	10,696	6,351	4,345	68.4	%	42,402	34,215	8,187	23.9	%

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

Our Operating Revenues increased for the three months ended September 30, 2012, as compared to the same period in 2011, due primarily to the addition of NSTAR, which included electric distribution revenues of $634.5 million, transmission revenues of $59.1 million, natural gas revenues of $37.6 million, other revenues of $5 million, and an increase as a result of the consolidation of CYAPC and YAEC of $13.8 million. Absent the impact of NSTAR's operations and the consolidation of CYAPC and YAEC, our Operating Revenues decreased due to the following:

Lower electric distribution segment revenues related to the portions that are included in regulatory commission approved tracking mechanisms that recover certain incurred costs and do not impact earnings. The tracking mechanisms allow for rates to be changed periodically with overcollections refunded to customers or undercollections recovered from customers in future periods. The tracked electric distribution revenues decreased due primarily to lower energy and supply-related costs ($71.9 million), lower wholesale revenues ($11.8 million) and lower CTA revenues ($10.8 million), partially offset by higher CL&P FMCC delivery-related revenues ($20.3 million), higher SCRC revenues at PSNH ($17.1 million), higher retail transmission revenues ($12.1 million), and higher retail SBC revenues ($6.8 million).

Partially offset by:

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

The portion of electric distribution segment revenues that impacts earnings increased $9 million due primarily to an increase in retail electric sales resulting from warmer than normal weather, as compared to the same period in 2011.

Our Operating Revenues increased for the nine months ended September 30, 2012, as compared to the same period in 2011, due primarily to the addition of NSTAR, which included electric distribution revenues of $1.1 billion, transmission revenues of $118 million, natural gas revenues of $98.9 million, other revenues of $10.4 million, and in increase as a result of the consolidation of CYAPC and YAEC of $27.5 million. Absent the impact of NSTAR's operations and the consolidation of CYAPC and YAEC, our Operating Revenues decreased due to the following:

Lower electric distribution segment revenues related to the portions that are included in regulatory commission approved tracking mechanisms that recover certain incurred costs and do not impact earnings. The tracking mechanisms allow for rates to be changed periodically with overcollections refunded to customers or undercollections recovered from customers in future periods. The tracked electric distribution revenues decreased due primarily to lower energy and supply-related costs ($185 million), lower wholesale revenues ($42.8 million), lower CTA revenues ($33.1 million), lower retail transmission revenues ($30 million), partially offset by higher CL&P FMCC delivery-related revenues ($68.8 million), higher SCRC revenues at PSNH ($18.6 million) and higher retail SBC revenues ($18.2 million).

A decrease in natural gas segment revenues due primarily to an 8.9 percent decrease in Yankee Gas' sales volume related to the warmer than normal weather in the heating season of 2012, as compared to heating season 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 $8.1 million due primarily to a decrease in retail electric sales related to the warmer than normal weather in the heating season of 2012, as compared to the heating season 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 a third party ($20.8 million) in the second quarter of 2012, resulting in a benefit to customers through lower ES rates that does not impact earnings.

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


	Three Months Ended		Nine Months Ended
(Millions of Dollars)	Increase/(Decrease)		Increase/(Decrease)
The addition of NSTAR's operations	$	232.2	$	438.7
Lower GSC supply costs, partially offset by higher CfD costs at CL&P		(25.4)		(110.0)
Lower natural gas costs and lower sales at Yankee Gas		(6.2)		(45.2)
Lower purchased transmission costs and lower Basic Service costs at WMECO		(9.2)		(19.1)
Lower purchased power costs, partially offset by higher transmission costs at PSNH		(1.7)		(8.0)
Other and eliminations		6.9		(1.7)
	$	196.6	$	254.7

Operations and Maintenanceincreased for the three months ended September 30, 2012, as compared to the same period in 2011, due primarily to the addition of NSTAR's operations, which included operating expenses of $93.1 million and maintenance expense of $11.8 million. Absent the impact of NSTAR's operations, Operations and Maintenance increased due primarily to:

Higher NU parent and other companies' expenses ($21.2 million) that were due primarily to higher merger and related settlement costs.

Higher distribution business expenses mainly as a result of general and administrative expenses primarily related to higher pension costs and higher distribution vegetation management and maintenance costs.

Operations and Maintenanceincreased for the nine months ended September 30, 2012, as compared to the same period in 2011, due primarily to the addition of NSTAR's operations, which included operating expenses of $216 million and maintenance expense of $32.7 million. Absent the impact of NSTAR's operations, Operations and Maintenance increased due primarily to:

Higher NU parent and other companies' expenses ($71.4 million) that were due primarily to higher costs related to the completion of NU’s merger with NSTAR ($56.1 million) and higher costs at NU’s unregulated contracting business related to an increased level of work in 2012 ($16.8 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 and higher vegetation management costs.

Depreciationincreased for the three and nine months ended September 30, 2012, as compared to the same periods in 2011, due primarily to the addition of NSTAR's plant balances ($47.5 million and $96.4 million, respectively) and an increase as a result of the consolidation of CYAPC and YAEC ($13.7 million and $27.4 million, respectively). Absent the impact of NSTAR and the consolidation of CYAPC and YAEC, Depreciation increased due primarily to higher utility plant balances resulting from completed construction projects placed into service.

Amortization of Regulatory Assets, Net increased for the three months ended September 30, 2012, as compared to the same period in 2011, due primarily to the addition of NSTAR's operations ($40.1 million). Absent the impact of NSTAR, Amortization of Regulatory Assets, Net decreased due primarily to a decrease in ES amortization at PSNH ($34.9 million), higher CTA transition costs ($1.9 million) and lower CTA revenues ($10.8 million) at CL&P, partially offset by an increase in SCRC amortization at PSNH ($11.8 million), lower SBC costs ($3.8 million) and higher retail SBC revenues ($6.8 million) at CL&P.

Amortization of Regulatory Assets, Net decreased for the nine months ended September 30, 2012, as compared to the same period in 2011, due primarily to a decrease in ES and TCAM amortization at PSNH ($23.9 million and $18.5 million, respectively), higher CTA transition costs ($12 million) and lower CTA revenues ($33.1 million) at CL&P. Partially offsetting these decreases was an increase related to the addition of NSTAR's operations ($59.3 million) and lower SBC costs ($7.4 million) and higher retail SBC revenues ($18.2 million) at CL&P.

Amortization of RRBs increased for the three and nine months ended September 30, 2012, as compared to the same periods in 2011, due primarily to the addition of NSTAR Electric’s amortization ($22.6 million and $45.2 million, respectively).

Energy Efficiency Programs increased for the three and nine months ended September 30, 2012, as compared to the same periods in 2011, due primarily to the addition of NSTAR's operations ($58 million and $99.7 million, respectively).

Taxes Other Than Income Taxes increased for the three and nine months ended September 30, 2012, as compared to the same periods in 2011, due primarily to the addition of NSTAR's operations ($32.6 million and $63.6 million, respectively).


Interest Expense
	For the Three Months Ended September 30,								For the Nine Months Ended September 30,
					Increase/								Increase/
(Millions of Dollars)	2012		2011		(Decrease)		Percent		2012^(a)		2011		(Decrease)		Percent
Interest on Long-Term Debt	$	86.5	$	57.5	$	29.0	50.4	%	$	233.4	$	171.9	$	61.5	35.8	%
Interest on RRBs		1.7		2.0		(0.3)	(15.0)			5.2		6.9		(1.7)	(24.6)
Other Interest		2.2		4.4		(2.2)	(50.0)			7.3		5.9		1.4	23.7
	$	90.4	$	63.9	$	26.5	41.5	%	$	245.9	$	184.7	$	61.2	33.1	%

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

Interest Expense increased for the three and nine months ended September 30, 2012, as compared to the same periods in 2011, due primarily to the addition of NSTAR's operations ($24.6 million and $48.4 million, respectively). The additional increase in Interest on Long-Term Debt was a result of the $260 million new long-term debt issuances in September 2011.


Other Income, Net
	For the Three Months Ended September 30,								For the Nine Months Ended September 30,
(Millions of Dollars)	2012		2011		Increase		Percent		2012^(a)		2011		Decrease		Percent
Other Income, Net	$	4.3	$	1.4	$	2.9	(b)	%	$	14.9	$	19.1	$	(4.2)	(22.0)	%

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

Other Income, Net increased for the three months ended September 30, 2012, as compared to the same period in 2011, due primarily to net gains on the NU supplemental benefit trust in 2012, compared to net losses in 2011.

Other Income, Net decreased for the nine months ended September 30, 2012, as compared to the same period 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, partially offset by net gains on the NU supplemental benefit trust in 2012, compared to net losses in 2011.


Income Tax Expense
	For the Three Months Ended September 30,								For the Nine Months Ended September 30,
(Millions of Dollars)	2012		2011		Increase		Percent		2012^(a)		2011		Increase		Percent
Income Tax Expense	$	117.4	$	49.9	$	67.5	(b)	%	$	199.4	$	157.9	$	41.5	26.3	%

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

Income Tax Expense increased for the three and nine months ended September 30, 2012, as compared to the same periods in 2011, due primarily to the higher pre-tax earnings ($71.4 million and $94.4 million, respectively), higher state taxes ($5.1 million and $6.2 million, respectively) and lower items that directly impact our tax return as a result of regulatory actions (“flow through” items) ($4 million for the nine months ended), partially offset by PURA and DPU settlement impacts ($41 million for the nine months ended) and merger impacts ($8.3 million and $22.9 million, respectively).

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 nine months ended September 30, 2012 and 2011:


			Operating Revenues and Expenses								Operating Revenues and Expenses
			For the Three Months Ended September 30,								For the Nine Months Ended September 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			$	658.1	$	673.7	$	(15.6)	(2.3)	%	$	1,812.2	$	1,955.4	$	(143.2)	(7.3)	%
Operating Expenses:
	Purchased Power and Transmission			241.0		266.4		(25.4)	(9.5)			658.7		768.7		(110.0)	(14.3)
	Operations and Maintenance			141.9		130.7		11.2	8.6			480.3		403.1		77.2	19.2
	Depreciation			41.9		39.7		2.2	5.5			124.5		117.6		6.9	5.9
	Amortization of Regulatory Assets, Net			8.7		15.7		(7.0)	(44.6)			19.9		48.0		(28.1)	(58.5)
	Energy Efficiency Programs			25.2		24.9		0.3	1.2			68.2		69.7		(1.5)	(2.2)
	Taxes Other Than Income Taxes			59.7		58.6		1.1	1.9			168.6		169.8		(1.2)	(0.7)
		Total Operating Expenses		518.4		536.0		(17.6)	(3.3)			1,520.2		1,576.9		(56.7)	(3.6)
Operating Income			$	139.7	$	137.7	$	2.0	1.5	%	$	292.0	$	378.5	$	(86.5)	(22.9)	%


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

	For the Three Months Ended September 30,					For the Nine Months Ended September 30,
	2012	2011	Increase	Percent		2012	2011	Decrease	Percent
Retail Sales in GWh	6,235	6,159	76	1.2	%	16,843	17,185	(342)	(2.0)	%

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

A $19.7 million and $122.5 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 tracking mechanisms allow for rates to be changed periodically with overcollections refunded to customers or undercollections recovered from customers in future periods. The tracked distribution revenues decreased due primarily to lower GSC and FMCC supply-related revenues ($35.9 million and $126.3 million, respectively), lower CTA revenues ($10.8 million and $33.1 million, respectively), lower wholesale revenues ($10 million and $33.4 million, respectively), and lower retail transmission revenues ($14.6 million for the nine months ended). The lower GSC and FMCC supply-related revenues were due primarily to lower customer rates resulting from lower average supply prices and lower sales related to additional customer migration to third party electric suppliers in 2012. Partially offsetting these decreases were higher FMCC delivery-related revenues ($20.3 million and $68.8 million, respectively), higher retail SBC revenues ($6.8 million and $18.2 million, respectively) and higher retail transmission revenues ($10.6 million for the three months ended).

An $8.2 million decrease in the portion of distribution revenues that impacts earnings for the nine months ended September 30, 2012, compared to the same period in 2011, due primarily to lower sales volume related to the warmer than normal weather in the heating season of 2012, as compared to the heating season of 2011.

Partially offset by:

Higher transmission revenues ($5.6 million for the three months ended) resulting from an increased level of investment in transmission infrastructure and the recovery of higher overall expenses, which are subject to tracking mechanisms or processes (tracked) and result in a related increase in revenues. The increase in expenses is directly related to the increase in transmission plant, including costs associated with higher property taxes, depreciation and operation and maintenance expenses.

A $3.8 million increase in the portion of distribution revenues that impacts earnings for the three months ended September 30, 2012, as compared to the same period in 2011, due primarily to higher sales volume resulting from warmer than normal weather, as compared to the same period in 2011.

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


	Three Months Ended		Nine Months Ended
(Millions of Dollars)	Increase/(Decrease)		Increase/(Decrease)
GSC Supply Costs	$	(25.0)	$	(98.2)
Transmission Costs		4.5		(28.4)
Deferred Fuel Costs		(7.2)		(28.5)
Purchased Power Contracts		(5.0)		(13.8)
CfD Costs		8.8		62.7
Other		(1.5)		(3.8)
	$	(25.4)	$	(110.0)

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 nine months ended September 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($5.3 million and $15.4 million, respectively) and higher vegetation management costs ($5 million and $13.2 million, respectively). There were also higher distribution costs related to customer EIA incentives, which are tracked and fully recoverable through tracking mechanisms ($4.8 million and $5.1 million, respectively). Partially offsetting these increases was a decrease in the amortization of the regulatory deferral allowed in the 2010 rate case decision ($1.9 million and $19.6 million, respectively).

Amortization of Regulatory Assets, Net decreased for the three and nine months ended September 30, 2012, as compared to the same periods in 2011, due primarily to higher CTA transition costs ($1.9 million and $12 million, respectively) and lower CTA revenues ($10.8 million and $33.1 million, respectively). Partially offsetting these impacts were lower SBC costs ($3.8 million and $7.4 million, respectively) and higher retail SBC revenues ($6.8 million and $18.2 million, respectively).


Interest Expense
	For the Three Months Ended September 30,								For the Nine Months Ended September 30,
					Increase/								Increase/
(Millions of Dollars)	2012		2011		(Decrease)		Percent		2012		2011		(Decrease)		Percent
Interest on Long-Term Debt	$	31.4	$	33.3	$	(1.9)	(5.7)	%	$	94.7	$	100.1	$	(5.4)	(5.4)	%
Other Interest		2.2		1.9		0.3	15.8			6.2		(0.8)		7.0	(a)
	$	33.6	$	35.2	$	(1.6)	(4.5)	%	$	100.9	$	99.3	$	1.6	1.6	%

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

Interest on Long-Term Debt decreased for the three and nine months ended September 30, 2012, as compared to the same periods in 2011, due primarily to the refinancing of the PCRBs at a lower interest rate in October 2011.

Other Interest increased for the nine months ended September 30, 2012, as compared to the same period in 2011, due primarily to the resolution in 2011 of state tax matters concerning the calculation of interest on outstanding amounts, which resulted in a reduction to Other Interest in 2011. In addition, there were higher short-term borrowings resulting in higher interest expense.


Other Income/(Loss), Net
	For the Three Months Ended September 30,								For the Nine Months Ended September 30,
(Millions of Dollars)	2012		2011		Increase		Percent		2012		2011		Increase		Percent
Other Income/(Loss), Net	$	2.9	$	(2.4)	$	5.3	(a)	%	$	8.6	$	4.3	$	4.3	100.0	%

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

Other Income/(Loss), Net increased for the three and nine months ended September 30, 2012, as compared to the same periods in 2011, due primarily to net gains on the NU supplemental benefit trust in 2012, compared to net losses in 2011.


Income Tax Expense
	For the Three Months Ended September 30,								For the Nine Months Ended September 30,
(Millions of Dollars)	2012		2011		Increase		Percent		2012		2011		Decrease		Percent
Income Tax Expense	$	34.1	$	33.6	$	0.5	1.5	%	$	63.9	$	100.1	$	(36.2)	(36.2)	%

Income Tax Expense increased for the three months ended September 30, 2012, as compared to the same period in 2011, due primarily to higher pre-tax earnings ($2.7 million), partially offset by lower state income taxes and other impacts ($2.2 million).

Income Tax Expense decreased for the nine months ended September 30, 2012, as compared to the same period in 2011, due primarily to Connecticut settlement agreement impacts ($26.6 million), lower pre-tax earnings ($6.3 million) and lower state income taxes and other impacts ($3.3 million).

LIQUIDITY

CL&P had cash flows provided by operating activities of $148.2 million in the first nine months of 2012, compared with cash flows provided by operating activities of $486.6 million in the first nine months of 2011. The reduced cash flows were due primarily to $164.3 million of cash disbursements for storm costs primarily associated with Tropical Storm Irene and the October 2011 snowstorm made in the first nine months of 2012, as compared to approximately $64 million in the first nine months of 2011, $27 million in bill credits provided to residential customers in February 2012 related to the October 2011 snowstorm, $25 million in bill credits to customers associated with the Connecticut settlement agreement, and negative cash flow impacts associated with an increase in accounts receivable primarily attributable to an increase in regional network service transmission receivables from ISO-New England. In addition, CL&P had lower recovery of its deferred operation and maintenance costs in the first nine months of 2012, compared to the first nine months of 2011, creating a negative cash flow impact of $21 million. Offsetting these negative cash flow impacts was an increase in intercompany income tax settlements in the first nine months of 2012 compared to the first nine months of 2011, creating a positive cash flow impact of $19.1 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, the AFUDC related to equity funds, and the capitalized portions of pension and PBOP expense or income. CL&P's cash capital expenditures totaled $332.3 million in the first nine months of 2012, compared with $305.6 million in the first nine months of 2011.

On July 25, 2012, NU, CL&P, NSTAR LLC, NSTAR Gas, PSNH, WMECO, and Yankee Gas jointly entered into a five-year $1.15 billion revolving credit facility. The new facility replaced (1) the NSTAR LLC revolving credit facility of $175 million that served to backstop a commercial paper program utilized by NSTAR LLC and was scheduled to expire on December 31, 2012, (2) the NSTAR Gas revolving credit facility of $75 million that expired on June 8, 2012, and (3) the CL&P, PSNH, WMECO, and Yankee Gas joint three-year $400 million and NU parent three-year $500 million unsecured revolving credit facilities that were scheduled to expire on September 24, 2013. The new facility expires on July 25, 2017. As of September 30, 2012, CL&P had $372.8 million in intercompany short-term borrowings under the NU commercial paper program. The weighted average interest rate on these borrowings as of September 30, 2012 was 0.458 percent.

CL&P has a separate five-year $300 million unsecured revolving credit facility that expires on March 26, 2017. CL&P had no borrowings outstanding under this facility as of September 30, 2012.

Financing activities in the first nine months of 2012 included $100.5 million in common stock dividends paid to NU parent, an increase in intercompany short-term borrowings of $314.3 million, and a decrease in short-term notes payable to banks of $31 million.

CL&P uses available capital resources to fund its construction expenditures, meet debt requirements, to pay costs, including storm-related costs, and dividends and to fund its other obligations. The current growth in CL&P’s transmission construction expenditures utilizes a significant amount of cash for projects that have a long-term return on investment and recovery period. In addition, CL&P operates in an environment where recovery of its distribution construction expenditures takes place over an extended period of time. As well, the future recovery of its deferred storm-related costs, which must be approved by the PURA, will take place over a six-year period for those costs deferred as a result of 2011 activity (as covered by the Connecticut Settlement Agreement) and over an extended period of time for those storm costs incurred related to Hurricane Sandy. This impacts the timing of the revenue stream designed to fully recover the total investment plus a return on the equity portion of the cost and related financing costs. These factors have resulted in CL&P’s current liabilities exceeding current assets by approximately $558 million as of September 30, 2012.

As of September 30, 2012, approximately $241 million of CL&P's current liabilities relates to long-term debt that will be paid in the next 12 months. CL&P, with credit ratings among the highest in the industry, has several options available in the financial markets to repay or refinance these maturities with the issuance of new long-term debt. CL&P will reduce their short-term borrowings with cash received from operating cash flows or with the issuance of new long-term debt, as deemed appropriate given our capital requirements and maintenance of our credit rating and profile. Management expects the future operating cash flows of CL&P, along with the access to financial markets, will be sufficient to meet any future operating requirements and capital investment forecasted opportunities.

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 nine months ended September 30, 2012 and 2011:


			Operating Revenues and Expenses								Operating Revenues and Expenses
			For the Three Months Ended September 30,								For the Nine Months Ended September 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			$	693.7	$	724.7	$	(31.0)	(4.3)	%	$	1,784.8	$	1,854.5	$	(69.7)	(3.8)	%
Operating Expenses:
	Purchased Power and Transmission			222.8		262.1		(39.3)	(15.0)			622.3		717.2		(94.9)	(13.2)
	Operations and Maintenance			83.3		101.0		(17.7)	(17.5)			340.6		286.0		54.6	19.1
	Depreciation			42.5		40.4		2.1	5.2			127.7		123.6		4.1	3.3
	Amortization of Regulatory Assets, Net			41.9		27.1		14.8	54.6			87.9		56.7		31.2	55.0
	Amortization of Rate Reduction Bonds			22.6		22.6		-	-			67.7		67.7		-	-
	Energy Efficiency Programs			56.0		59.2		(3.2)	(5.4)			138.4		132.2		6.2	4.7
	Taxes Other Than Income Taxes			30.5		28.6		1.9	6.6			89.7		84.1		5.6	6.7
		Total Operating Expenses		499.6		541.0		(41.4)	(7.7)			1,474.3		1,467.5		6.8	0.5
Operating Income			$	194.1	$	183.7	$	10.4	5.7	%	$	310.5	$	387.0	$	(76.5)	(19.8)	%


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

	For the Three Months Ended September 30,					For the Nine Months Ended September 30,
	2012	2011	Increase	Percent		2012	2011	Decrease	Percent
Retail Sales in GWh	6,136	6,056	80	1.3	%	16,189	16,439	(250)	(1.5)	%

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

A $29.2 million and $66.2 million decrease, respectively, in distribution revenues related to the portions that are included in DPU approved tracking mechanisms that recover certain incurred costs and do not impact earnings. The tracking mechanisms allow for rates to be changed periodically with overcollections refunded to customers or undercollections recovered from customers in future periods. This decrease primarily related to lower purchased power and transmission costs ($11.6 million and $13.9 million, respectively), lower retail transmission revenues ($3 million and $13.8 million, respectively) and lower PAM revenues ($5.8 million and $14 million, respectively).

Partially offset by:

A $2.8 million and $18.1 million increase, respectively, in transmission revenues resulting from an increased level of investment in transmission infrastructure and the recovery of higher overall expenses, which are tracked and result in a related increase in revenues. The increase in expenses is directly related to the increase in transmission plant, including costs associated with higher property taxes, depreciation and operation and maintenance expenses.

A $7.4 million increase in the portion of distribution revenues that impacts earnings due primarily to a 1.3 percent increase in retail sales and a positive annual inflation rate adjustment for the three months ended September 30, 2012, as compared to the same period in 2011.

Purchased Powerand Transmission decreased for the three and nine months ended September 30, 2012, as compared to the same periods in 2011, due primarily to the following:


	Three Months Ended		Nine Months Ended
(Millions of Dollars)	Increase/(Decrease)		Increase/(Decrease)
Purchased Power Contracts	$	(14.2)	$	(42.7)
Basic Service Costs		(30.3)		(39.7)
Transmission Costs		(10.8)		(31.5)
Deferred Fuel Costs		17.7		21.7
Other		(1.7)		(2.7)
	$	(39.3)	$	(94.9)

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

Operations and Maintenance decreased for the three months ended September 30, 2012, as compared to the same period in 2011, due primarily to a decrease in vegetation management costs ($6.3 million), contractor expense ($2.3 million), labor-related costs ($1.6 million), rights of way clearing costs ($1.6 million), and storm-related costs ($1.4 million).

Operations and Maintenance increased for the nine months ended September 30, 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). In addition, first quarter 2012 adjustments were recognized for changes in accounting estimates related primarily to the allowance for doubtful accounts, workers’ compensation, employee medical benefits, and general liability claims ($18.7 million). In addition, a bill credit to customers ($15 million) was recorded in the second quarter of 2012 as a result of the Massachusetts settlement agreement. Also contributing to the increase in costs was an incident in March 2012 involving a substation fire in theBack Bay/Prudential area of Boston ($11.8 million). These increases were partially offset by lower storm-related expense ($2.1 million).

Amortization of Regulatory Assets, Net, increased for the three and nine months ended September 30, 2012, as compared to the same periods in 2011, due primarily to higher amortization related to transition costs.

Energy Efficiency Programsdecreased for the three months ended September 30, 2012, as compared to the same period in 2011, due primarily to the timing of the recovery of energy efficiency spending, compared to energy efficiency revenues during the period.

Energy Efficiency Programs increased for the nine months ended September 30, 2012, as compared to the same period in 2011, due primarily to an increase in energy efficiency costs in accordance with the three-year program guidelines established by the DPU. The costs are fully recovered through DPU tracking mechanisms.


Interest Expense
	For the Three Months Ended September 30,								For the Nine Months Ended September 30,
					Increase/								Increase/
(Millions of Dollars)	2012		2011		(Decrease)		Percent		2012		2011		Decrease		Percent
Interest on Long-Term Debt	$	22.4	$	22.5	$	(0.1)	(0.4)	%	$	66.9	$	67.7	$	(0.8)	(1.2)	%
Interest on RRBs		0.8		1.7		(0.9)	(52.9)			3.1		5.8		(2.7)	(46.6)
Other Interest		(4.7)		(6.3)		1.6	25.4			(16.1)		(21.7)		5.6	25.8
	$	18.5	$	17.9	$	0.6	3.4	%	$	53.9	$	51.8	$	2.1	4.1	%

Other Interest increased for the three and nine months ended September 30, 2012, as compared to the same periods in 2011, due primarily to a reduction in regulatory interest income primarily from deferred transition costs ($1.4 million and $4 million, respectively) and reduced interest income from legal matters ($3.2 million for the nine months ended), partially offset by a decrease in the interest expense related to tax issues ($1.9 million for the nine months ended), due to the receipt of a 2001 through 2007 tax settlement in June 2011.


Other Income/(Loss), Net
	For the Three Months Ended September 30,								For the Nine Months Ended September 30,
(Millions of Dollars)	2012		2011		Increase		Percent		2012		2011		Increase		Percent
Other Income/(Loss), Net	$	0.5	$	(0.4)	$	0.9	(a)	%	$	1.8	$	1.3	$	0.5	38.5	%

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

Other Income/(Loss), Net increased for the three and nine months ended September 30, 2012, as compared to the same periods of 2011, due primarily to higher cash surrender values from executive life insurance policies.


Income Tax Expense
	For the Three Months Ended September 30,								For the Nine Months Ended September 30,
(Millions of Dollars)	2012		2011		Increase		Percent		2012		2011		Decrease		Percent
Income Tax Expense	$	69.4	$	65.6	$	3.8	5.8	%	$	102.2	$	133.1	$	(30.9)	(23.2)	%

Income Tax Expense increased for the three months ended September 30, 2012, as compared to the same period in 2011, due primarily to higher pre-tax earnings ($4.3 million).

Income Tax Expense decreased for the nine months ended September 30, 2012, as compared to the same period in 2011, due primarily to lower pre-tax earnings ($23.7 million), Massachusetts settlement agreement impacts ($5.9 million) and merger impacts ($1 million).

EARNINGS SUMMARY


	For the Three Months Ended September 30,				For the Nine Months Ended September 30,
(Millions of Dollars)	2012		2011		2012		2011
Income Before Merger and Related Costs	$	107.0	$	99.9	$	167.0	$	204.0
Merger and Related Costs (after-tax)		(0.2)		(0.1)		(10.8)		(0.6)
Net Income	$	106.8	$	99.8	$	156.2	$	203.4

The after-tax merger and related settlement costs for the nine months ended September 30, 2012 consisted of approximately $17.7 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 third quarter 2012 earnings were $7.1 million higher than the same period of 2011 due primarily to a lower level of operations and maintenance costs, including lower vegetation management costs, lower storm-related costs, lower distribution maintenance costs, and lower labor-related costs. Also impacting earnings were higher transmission revenues related to an increased level of investment in transmission infrastructure. Partially offsetting these impacts was a higher level of depreciation and municipal property tax expense due primarily to the increase in infrastructure.

Excluding the merger and related settlement costs, NSTAR Electric’s earnings for the nine months ended September 30, 2012 were $37 million lower than the same period in 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 theBack Bay/Prudential area of Boston ($7.2 million), a reserve recorded relating to lost base revenues based on developments during hearings in the merger proceeding ($3 million), also impacting is the timing of maintenance ($3.6 million), and higher depreciation and property taxes ($5.9 million). These factors are partially offset by higher transmission revenues due to an increased level of investment in transmission infrastructure ($8.8 million).

CAPITAL EXPENDITURES

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


	For the Nine Months Ended September 30,
(Millions of Dollars)		2012		2011
Transmission	$	110.7	$	80.7
Distribution:
Basic Business		40.8		55.1
Aging Infrastructure		119.1		77.1
Load Growth		11.1		22.1
Total Distribution		171.0		154.3
Total Capital Expenditures	$	281.7	$	235.0

LIQUIDITY

NSTAR Electric had cash flows provided by operating activities in the first nine months of 2012 of $348.2 million, compared with operating cash flows of $497.6 million in the first nine months 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 nine months of 2012 of income tax refunds received during the same period of 2011. For the first nine months of 2012, NSTAR Electric made income tax payments of $78 million, as compared to income tax refunds of $94.1 million in the first nine 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 nine months of 2012. Offsetting these negative cash flow impacts was a reduction in Pension Plan contributions during the first nine months of 2012, as compared to the same period in 2011, of approximately $43 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 $298.4 million for the nine months ended September 30, 2012, compared with $234.2 million for the nine months ended September 30, 2011.

Financing activities for the nine months ended September 30, 2012 included $188.7 million in common dividends paid to NSTAR in the first quarter of 2012 and NSTAR LLC in the second and third quarter of 2012, and an increase in short-term debt borrowings of $119.5 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 nine months ended September 30, 2012 and 2011:


			Operating Revenues and Expenses								Operating Revenues and Expenses
			For the Three Months Ended September 30,								For the Nine Months Ended September 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			$	256.9	$	259.6	$	(2.7)	(1.0)	%	$	755.0	$	769.3	$	(14.3)	(1.9)	%
Operating Expenses:
	Purchased Power, Fuel and Transmission			76.0		77.7		(1.7)	(2.2)			239.1		247.1		(8.0)	(3.2)
	Operations and Maintenance			67.5		65.3		2.2	3.4			201.0		205.8		(4.8)	(2.3)
	Depreciation			22.3		18.4		3.9	21.2			65.3		54.4		10.9	20.0
	Amortization of Regulatory Assets/
		(Liabilities), Net		(6.3)		17.3		(23.6)	(a)			(6.2)		35.3		(41.5)	(a)
	Amortization of Rate Reduction Bonds			16.1		13.6		2.5	18.4			43.9		39.8		4.1	10.3
	Energy Efficiency Programs			4.0		3.7		0.3	8.1			10.8		9.6		1.2	12.5
	Taxes Other Than Income Taxes			16.0		15.1		0.9	6.0			47.4		44.0		3.4	7.7
		Total Operating Expenses		195.6		211.1		(15.5)	(7.3)			601.3		636.0		(34.7)	(5.5)
Operating Income			$	61.3	$	48.5	$	12.8	26.4	%	$	153.7	$	133.3	$	20.4	15.3	%

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


Operating Revenues
PSNH's retail sales were as follows:
	For the Three Months Ended September 30,					For the Nine Months Ended September 30,
	2012	2011	Increase	Percent		2012	2011	Decrease	Percent
Retail Sales in GWh	2,127	2,091	36	1.7	%	5,888	5,924	(36)	(0.6)	%

PSNH's Operating Revenues decreased for the three and nine months ended September 30, 2012, as compared to the same periods in 2011, due primarily to:

An $8.2 million and $40.4 million decrease, respectively, in distribution revenues related to the portions that are included in NHPUC approved tracking mechanisms that recover certain incurred costs and do not impact earnings. The tracking mechanisms allow for rates to be changed periodically with overcollections refunded to customers or undercollections recovered from customers in future periods. This decrease primarily related to lower purchased power and fuel costs ($33 million and $57.7 million, respectively),lower retail transmission revenues ($9.3 million for the nine months ended) and lower wholesale revenues ($5.9 million for the nine months ended). These lower revenues were offset by higher SCRC revenues ($17.1 million and $18.6 million, respectively), retail transmission revenues ($3.4 million for the three months ended) and RECs ($2.2 million and $7.3 million, respectively).

Partially offset by:

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

A $2.3 million and $8.8 million, respectively, increase in transmission revenues resulting from an increased level of investment in transmission infrastructure and the recovery of higher overall expenses, which are tracked and result in a related increase in revenues. The increase in expenses is directly related to the increase in transmission plant, including costs associated with higher property taxes, depreciation and operation and maintenance expenses.

A $5 million increase in the portion of distribution revenues that impacts earnings for the three months ended September 30, 2012, as compared to the same period in 2011, due primarily to the favorable impact of the 2010 rate case decision related to the additional increase to annualized rates that was effective July 1, 2012 and higher sales volume resulting from warmer than normal weather in 2012, as compared to the same period in 2011.

Purchased Power, Fuel and Transmission decreased for the three and nine months ended September 30, 2012, as compared to the same period in 2011, due primarily to a decrease in purchased power costs, partially offset by an increase in purchased transmission costs. The decrease in purchased power costs was primarily due to an increase in ES customer migration to third party suppliers.

Operations and Maintenance increased for the three months ended September 30, 2012, as compared to the same period in 2011, as a result of higher routine distribution maintenance expense ($4.1 million) and higher distribution vegetation management costs ($1.3 million), partially offset by a decrease in allocated distribution overhead costs ($2.7 million).

Operations and Maintenance decreased for the nine months ended September 30, 2012, as compared to the same period in 2011, as a result of lower maintenance costs at the generation business due to less planned outage maintenance in 2012 ($9.2 million), partially offset by higher routine distribution maintenance ($2.6 million) and higher distribution vegetation management costs ($2 million).

Depreciation increased for the three and nine months ended September 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/(Liabilities), Net decreased for the three months ended September 30, 2012, as compared to the same period in 2011, due primarily to a decrease in ES amortization ($34.9 million), partially offset by an increase in SCRC and TCAM amortization ($11.8 million and $1.2 million, respectively).

Amortization of Regulatory Assets/(Liabilities), Net decreased for the nine months ended September 30, 2012, as compared to the same period in 2011, due primarily to a decrease in ES and TCAM amortization ($23.9 million and $18.5 million, respectively).


Interest Expense
	For the Three Months Ended September 30,								For the Nine Months Ended September 30,
					Increase/								Increase/
(Millions of Dollars)	2012		2011		(Decrease)		Percent		2012		2011		(Decrease)		Percent
Interest on Long-Term Debt	$	11.4	$	8.5	$	2.9	34.1	%	$	34.5	$	25.4	$	9.1	35.8	%
Interest on RRBs		0.6		1.5		(0.9)	(60.0)			2.4		5.0		(2.6)	(52.0)
Other Interest		0.6		0.4		0.2	50.0			1.3		0.8		0.5	62.5
	$	12.6	$	10.4	$	2.2	21.2	%	$	38.2	$	31.2	$	7.0	22.4	%

Interest Expense increased for the three and nine months ended September 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 ($1.6 million and $5.2 million, respectively). The additional increase in Interest on Long-Term Debt was a result of the $160 million long-term debt issuance in September 2011.


Other Income/(Loss), Net
	For the Three Months Ended September 30,								For the Nine Months Ended September 30,
(Millions of Dollars)	2012		2011		Decrease		Percent		2012		2011		Decrease		Percent
Other Income/(Loss), Net	$	(0.4)	$	3.3	$	(3.7)	(a)	%	$	2.2	$	12.1	$	(9.9)	(81.8)	%

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

Other Income/(Loss), Net decreased for the three and nine months ended September 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 September 30,								For the Nine Months Ended September 30,
(Millions of Dollars)	2012		2011		Increase		Percent		2012		2011		Increase		Percent
Income Tax Expense	$	21.1	$	15.8	$	5.3	33.5	%	$	48.0	$	39.5	$	8.5	21.5	%

Income Tax Expense increased for the three and nine months ended September 30, 2012, as compared to the same periods in 2011, due primarily to lower flow-through items ($1.3 million and $3.4 million, respectively), higher pre-tax earnings ($2.4 million and $1.5 million, respectively), higher state taxes ($0.2 million and $2 million, respectively) and provision to return ($0.8 million and $0.8 million, respectively).

LIQUIDITY

PSNH had cash flows provided by operating activities of $136.5 million in the first nine months of 2012, compared with operating cash flows of $161 million in the first nine months of 2011 (amounts are net of RRB payments, which are included in financing activities). The reduced cash flows were due primarily to $8.7 million of 2012 cash disbursements for storm costs associated with Tropical Storm Irene and the October 2011 snowstorm and income tax payments of $9.3 million in the first nine months of 2012, compared to income tax refunds of $29.9 million in the first nine months of 2011. Offsetting the negative cash flow impacts were reduced coal and fuel inventories in the first nine months of 2012 creating a positive cash flow impact of $23.1 million, as compared to reduced coal and fuel inventories in the first nine months of 2011 creating a positive cash flow impact of $9.5 million. The reduction of fuel inventories in the first nine months of 2012 is primarily attributable to the sale of oil to a third party 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 nine months ended September 30, 2012 and 2011:


			Operating Revenues and Expenses								Operating Revenues and Expenses
			For the Three Months Ended September 30,								For the Nine Months Ended September 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			$	112.5	$	104.5	$	8.0	7.7	%	$	333.3	$	309.6	$	23.7	7.7	%
Operating Expenses:
	Purchased Power and Transmission			32.0		41.2		(9.2)	(22.3)			105.3		124.4		(19.1)	(15.4)
	Operations and Maintenance			24.8		19.2		5.6	29.2			75.2		60.5		14.7	24.3
	Depreciation			7.5		6.7		0.8	11.9			22.1		19.6		2.5	12.8
	Amortization of Regulatory Assets, Net			1.0		2.8		(1.8)	(64.3)			0.6		3.6		(3.0)	(83.3)
	Amortization of Rate Reduction Bonds			4.4		4.1		0.3	7.3			13.1		12.3		0.8	6.5
	Energy Efficiency Programs			9.2		6.1		3.1	50.8			19.7		16.5		3.2	19.4
	Taxes Other Than Income Taxes			5.5		4.6		0.9	19.6			15.4		13.4		2.0	14.9
		Total Operating Expenses		84.4		84.7		(0.3)	(0.4)			251.4		250.3		1.1	0.4
Operating Income			$	28.1	$	19.8	$	8.3	41.9	%	$	81.9	$	59.3	$	22.6	38.1	%


Operating Revenues
WMECO's retail sales were as follows:

	For the Three Months Ended September 30,					For the Nine Months Ended September 30,
	2012	2011	Increase	Percent		2012	2011	Decrease	Percent
Retail Sales in GWh	1,008	999	9	0.9	%	2,788	2,817	(29)	(1.0)	%

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

An $8.5 million and $30 million increase, respectively, in transmission revenues resulting from an increased 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.

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

Partially offset by:

A $3.2 million and $4.7 million decrease, respectively, in distribution revenues related to the portions that are included in DPU approved tracking mechanisms that recover certain incurred costs and do not impact earnings. The tracking mechanisms allow for rates to be changed periodically with overcollections refunded to customers or undercollections to be recovered from customers in future periods. Included in these amounts are Basic Service costs, pension and C&LM collections.

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

Operations and Maintenance increased for the three and nine months ended September 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 ($1.1 million and $3.3 million, respectively), which are recovered through DPU approved tracking mechanisms and have no earnings impact, higher uncollectible expenses ($1.3 million and $2.5 million, respectively) and higher routine distribution maintenance costs ($1.2 million and $1.6 million, respectively).

Amortization of Regulatory Assets, Net decreased for the three and nine months ended September 30, 2012, as compared to the same periods in 2011, due primarily to a decrease in amortization of the transition charge deferral.

Energy Efficiency Programsincreased for the three and nine months ended September 30, 2012, as compared to the same periods in 2011, due primarily to an increase in expenses attributable to an increase in spending in accordance with DPU approved energy efficiency programs.


Interest Expense
	For the Three Months Ended September 30,								For the Nine Months Ended September 30,
					Increase/								Increase/
(Millions of Dollars)	2012		2011		(Decrease)		Percent		2012		2011		(Decrease)		Percent
Interest on Long-Term Debt	$	5.8	$	4.9	$	0.9	18.4	%	$	17.5	$	14.4	$	3.1	21.5	%
Interest on RRBs		0.3		0.6		(0.3)	(50.0)			1.0		1.9		(0.9)	(47.4)
Other Interest		0.7		0.5		0.2	40.0			1.5		0.7		0.8	(a)
	$	6.8	$	6.0	$	0.8	13.3	%	$	20.0	$	17.0	$	3.0	17.6	%

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

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


Other Income/(Loss), Net
	For the Three Months Ended September 30,								For the Nine Months Ended September 30,
(Millions of Dollars)	2012		2011		Increase		Percent		2012		2011		Increase		Percent
Other Income/(Loss), Net	$	0.7	$	(0.7)	$	1.4	(a)	%	$	2.0	$	0.3	$	1.7	(a)	%

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


Income Tax Expense
	For the Three Months Ended September 30,								For the Nine Months Ended September 30,
(Millions of Dollars)	2012		2011		Increase		Percent		2012		2011		Increase		Percent
Income Tax Expense	$	8.0	$	4.6	$	3.4	73.9	%	$	24.4	$	16.0	$	8.4	52.5	%

Income Tax Expense increased for the three and nine months ended September 30, 2012, as compared to the same periods in 2011, due primarily to higher pre-tax earnings ($3.5 million and $9.5 million, respectively), partially offset by Massachusetts settlement agreement impacts ($1.2 million for the nine months ended) and a regulatory decision that reduced a non-plant flow through difference ($1 million for the nine months ended).

LIQUIDITY

WMECO had cash flows provided by operating activities of $44.9 million in the first nine months of 2012, compared with operating cash flows of $76.4 million in the first nine 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 $28.8 million in the first nine months of 2012, as compared to the same period in 2011, and $3 million in bill credits to customers associated with the Massachusetts settlement agreement. Offsetting these negative cash flow impacts was the absence in 2012 of $6.9 million of cash disbursements associated with a cash flow hedge settlement in the first nine months of 2011 and intercompany income tax settlements with affiliates in the first nine months of 2012 of $9.4 million, compared to intercompany income tax settlements with affiliates of $3.5 million in the first nine months of 2011.

ITEM 3.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Market Risk Information

Commodity Price Risk Management: Our Regulated companies enter into energy contracts to serve our customers and the economic impacts of those contracts are passed on to our customers. Accordingly, the Regulated companies have no exposure to loss of future earnings or fair values due to these market risk-sensitive instruments. The remaining unregulated wholesale portfolio held by Select Energy includes contracts that are market risk-sensitive, including a wholesale energy sales contract through 2013 with an agency comprised of municipalities with approximately 38 thousand remaining MWh of supply contract volumes, net of related sales volumes.

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 to be provided to counterparties and independent system operators. If such an event occurred as of September 30, 2012, NU would have been required to provide additional collateral. 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 September 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 September 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. Other than as described below, there have been no additional material legal proceedings identified and no material changes with regard to the legal proceedings previously disclosed in those filings.

Yankee Companies v. U.S. Department of Energy

The Yankee Companies (YAEC, MYAPC, and CYAPC) commenced litigation in 1998 against the DOE charging that the federal government breached contracts it entered into with each company in 1983 under the Nuclear Waste Policy Act of 1982 to begin removing spent nuclear fuel from the respective nuclear plants no later than January 31, 1998 in return for payments by each company into the Nuclear Waste Fund. The funds for those payments were collected from regional electric customers. The Yankee Companies initially claimed damages for incremental spent nuclear fuel storage, security, construction and other costs through 2010.

In 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 decision and the Yankee Companies filed cross-appeals. The Court of Appeals disagreed with the trial court’s method of calculation of the amount of the DOE’s liability, among other things, and vacated the decision of the Court of Federal Claims and remanded the case to make new findings consistent with its decision. On September 7, 2010, the trial court issued its decision following remand, and judgment on the decision was entered on September 9, 2010. The judgment awarded CYAPC $39.7 million, YAEC $21.2 million and MYAPC $81.7 million. The DOE filed an appeal and the Yankee Companies cross-appealed on November 8, 2010. Briefs were filed and oral arguments in the appeal of the remanded case occurred on November 7, 2011. On May 18, 2012, the U.S. Court of Appeals for the Federal Circuit issued a unanimous panel decision in favor of the Yankee Companies upholding the trial court’s awards to each company in the remanded cases, and increasing YAEC damages by approximately $17 million to cover certain wet pool operating expenses. On August 1, 2012, the DOE filed a petition asking the U.S. Court of Appeals for the Federal Circuit to reconsider its unanimous panel decision in favor of the Yankee Companies upholding the trial court’s awards to each company in the remanded cases. On September 5, 2012, the U.S. Court of Appeals for the Federal Circuit denied the DOE’s petition. As a result, the decision becomes final and non-appealable unless, within 90 days, the DOE files a petition for certiorari with the U.S. Supreme Court. 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.

In December 2007, the Yankee Companies filed a second round of lawsuits against the DOE seeking recovery of actual damages incurred in the years following 2001 and 2002. On November 18, 2011, the court ordered the record closed in the YAEC case, and closed the record in the CYAPC and MYAPC cases subject to a limited opportunity of the government to reopen the records for further limited proceedings. The record was closed and the parties’ post-trial briefs were filed during the first quarter of 2012, and the case is now with the court for a decision.

Connecticut MGP Cost Recovery

In September 2006, CL&P and Yankee Gas (the NU Companies) filed a complaint against UGI Utilities, Inc. (UGI) in the U.S. District Court for the District of Connecticut seeking past and future remediation costs related to historic MGP operations on thirteen sites currently or formerly owned by the NU Companies (Yankee Gas is responsible for ten of the sites, CL&P for two of the sites, and both companies share responsibility for one site) in a number of different locations throughout the State of Connecticut. The NU Companies allege that UGI controlled operations of the plants at various times throughout the period 1883 to 1941, when UGI was forced to divest its interests. Investigations and remediation activity and expenditures at the sites are ongoing. A trial was held in April 2009.

On May 22, 2009, the court granted judgment in favor of the NU Companies with respect to the Waterbury-North site (a Yankee Gas site), and granted judgment in favor of UGI with respect to the remaining sites. Judgment was entered on March 31, 2010. The Phase II trial, which determined what portion of the remediation costs at the Yankee Gas Waterbury-North site are attributable to UGI, was held in August and September, 2011. On March 30, 2012, the Court issued a Memorandum of Decision allocating between 3.4 percent and 34 percent of remediation costs to UGI depending on the location of contamination on the Waterbury North site. Yankee Gas has requested reimbursement from UGI for approximately $81,000 for costs incurred to date. The parties are discussing this request and future reimbursements. Any recovery would flow back to Yankee Gas customers.

Conservation Law Foundation v. PSNH

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

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

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 and the second quarter 2012 combined Quarterly Report on Form 10-Q of NU, which risk factors are incorporated herein by reference. These risk factors should be considered carefully in evaluating our risk profile. There have been no additional risk factors identified and no material changes with regard to the risk factors previously disclosed in those filings.

ITEM 2.

UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

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


Period	Total Number of Shares Purchased		Average Price Paid per Share	Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans and Programs (at month end)
July 1 - July 31, 2012	4,601	$	39.42	-	-
August 1 - August 31, 2012	11,378		39.02	-	-
September 1 - September 30, 2012	142,755		38.16	-	-
Total	158,734	$	38.26	-	-

ITEM 5.

OTHER INFORMATION

Date of 2013 Annual Meeting of Shareholders

The Northeast Utilities 2013 Annual Meeting of Shareholders has been scheduled for May 1, 2013, which date is more than thirty days prior to the anniversary date of the 2012 annual meeting of shareholders.

In accordance with Rule 14a-5(f) under the Securities Exchange Act of 1934, as amended (the "Exchange Act") and other applicable rules of the Securities and Exchange Commission (“SEC”), the Company has determined that proposals to be considered for inclusion in the Company’s proxy statement for the 2013 Annual Meeting pursuant to Rule 14a-8 under the Exchange Act must be received by the Company at the address set forth below no later than November 21, 2012, and must satisfy the conditions established by the SEC. Written notice of proposals of shareholders to be considered at the 2013 Annual Meeting without inclusion in next year’s proxy statement must be received on or before February 5, 2013. If a notice is received after February 5, 2013, then the notice will be considered untimely and the proxies held by management may provide the discretion to vote against such proposal, even though the proposal is not discussed in the proxy statement. Northeast Utilities considers these dates to be reasonable deadlines for submission of proposals before we begin to print and mail our proxy materials for the 2013 Annual Meeting of Shareholders.

Shareholder proposals should be addressed to: Richard J. Morrison, Assistant Secretary, Northeast Utilities, Post Office Box 270, Hartford, Connecticut 06141-0270.

ITEM 6.

EXHIBITS

Exhibit No.

Description

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

4.1

Credit Agreement, dated July 25, 2012, by and among NU, CL&P, NSTAR Gas, NSTAR LLC, PSNH, WMECO, Yankee Gas Services Company and the Banks named therein, pursuant to which Bank of America, N.A. serves as Administrative Agent

Listing of Exhibits (NU)

4.1

Form of Commercial Paper Dealer Agreement, dated as of July 25, 2012, by and between NU and the Dealer

Ratio of Earnings to Fixed Charges

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 November 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 November 7, 2012

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 November 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)

Ratio of Earnings to Fixed Charges

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 November 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 November 7, 2012

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 November 7, 2012

Listing of Exhibits (NSTAR Electric)

4.1

Credit Agreement, dated July 25, 2012, by and between NSTAR Electric and the Banks named therein, pursuant to which Barclays Bank PLC serves as Administrative Agent and Swing Line Lender

Ratio of Earnings to Fixed Charges

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 November 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 November 7, 2012

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 November 7, 2012

Listing of Exhibits (PSNH)

Ratio of Earnings to Fixed Charges

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 November 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 November 7, 2012

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 November 7, 2012

Listing of Exhibits (WMECO)

Ratio of Earnings to Fixed Charges

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 November 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 November 7, 2012

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

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The Connecticut Light and Power Company (CNLTP) 10-Q2012 Q3 Quarterly report

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