The Connecticut Light and Power Company (CNLTP) 10-Q 2010 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, 2010
	OR
[  ]	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE      SECURITIES EXCHANGE ACT OF 1934
	For the transition period from ____________ to ____________

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

______________________________________________________________________________

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

Yes	No
ü

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

Yes	No
ü

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

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

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

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

Indicate the number of shares outstanding of each of the issuers' classes of common stock, as of the latest practicable date:

Company - Class of Stock	Outstanding as of October 31, 2010
Northeast Utilities Common shares, $5.00 par value	176,317,768 shares
The Connecticut Light and Power Company Common stock, $10.00 par value	6,035,205 shares
Public Service Company of New Hampshire Common stock, $1.00 par value	301 shares
Western Massachusetts Electric Company Common stock, $25.00 par value	434,653 shares

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

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

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

OTHER:
2009 Form 10-K	The Northeast Utilities and subsidiaries combined 2009 Annual Report on Form 10-K as filed with the SEC
2010 Healthcare Act	Patient Protection and Affordable Care Act
AFUDC	Allowance For Funds Used During Construction
AMI	Advanced metering infrastructure
ARO	Asset Retirement Obligation
C&LM	Conservation and Load Management
CERCLA	The federal Comprehensive Environmental Response, Compensation and Liability Act of 1980
CfD	Contract for Differences
CSC	Connecticut Siting Council
CTA	Competitive Transition Assessment
CWIP	Construction work in progress
CYAPC	Connecticut Yankee Atomic Power Company
EFSB	Massachusetts Energy Facilities Siting Board
EPS	Earnings Per Share
ERISA	Employee Retirement Income Security Act of 1974
ES	Default Energy Service
ESOP	Employee Stock Ownership Plan

i

FASB	Financial Accounting Standards Board
Fitch	Fitch Ratings
FMCC	Federally Mandated Congestion Charge
FTR	Financial Transmission Rights
GAAP	Accounting principles generally accepted in the United States of America
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
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
HQ Hydro Renewable Energy	H.Q. Hydro Renewable Energy, Inc., a wholly-owned subsidiary of Hydro-Québec
IPP	Independent Power Producers
ISO-NE	ISO New England, Inc., the New England Independent System Operator
KV	Kilovolt
KWh	Kilowatt-Hours
LNG	Liquefied natural gas
LOC	Letter of Credit
LRS	Last resort service
MA DEP	Massachusetts Department of Environmental Protection
MGP	Manufactured Gas Plant
MMBtu	One million British thermal units
Money Pool	Northeast Utilities Money Pool
Moody's	Moody's Investors Services, Inc.
MW	Megawatt
MWh	Megawatt-Hours
MYAPC	Maine Yankee Atomic Power Company
NEEWS	New England East-West Solution
Northern Pass	The high voltage direct current transmission line project from Canada to New Hampshire
NU supplemental benefit trust	The NU Trust Under Supplemental Executive Retirement Plan
NWPP	Northern Wood Power Project
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
PGA	Purchased Gas Adjustment
PPA	Pension Protection Act
Regulatory ROE	The average cost of capital method for calculating the return on equity related to the distribution and generation business segments excluding the wholesale transmission segment
ROE	Return on Equity
RMR	Reliability Must Run
RRB	Rate Reduction Bond or Rate Reduction Certificate
RSUs	Restricted share units
S&P	Standard & Poor's Financial Services LLC
SBC	Systems Benefits Charge
SCRC	Stranded Cost Recovery Charge
SERP	Supplemental Executive Retirement Plan
SS	Standard service
TCAM	Transmission Cost Adjustment Mechanism
TSA	Transmission Service Agreement
UI	The United Illuminating Company
VIE	Variable interest entity
WWL Project	The construction of a 16-mile gas pipeline between Waterbury and Wallingford, Connecticut and the increase of vaporization output of Yankee Gas' LNG plant
YAEC	Yankee Atomic Electric Company
Yankee Companies	Connecticut Yankee Atomic Power Company, Yankee Atomic Electric Company and Maine Yankee Atomic Power Company

ii

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

TABLE OF CONTENTS

	Page
PART I - FINANCIAL INFORMATION
ITEM 1 - Unaudited Condensed Consolidated Financial Statements for the Following Companies:
Northeast Utilities and Subsidiaries
Condensed Consolidated Balance Sheets (Unaudited) - September 30, 2010 and December 31, 2009	2
Condensed Consolidated Statements of Income (Unaudited) - Three and Nine Months Ended September 30, 2010 and 2009	4
Condensed Consolidated Statements of Cash Flows (Unaudited) - Nine Months Ended September 30, 2010 and 2009	5
The Connecticut Light and Power Company and Subsidiaries
Condensed Consolidated Balance Sheets (Unaudited) - September 30, 2010 and December 31, 2009	8
Condensed Consolidated Statements of Income (Unaudited) - Three and Nine Months Ended September 30, 2010 and 2009	10
Condensed Consolidated Statements of Cash Flows (Unaudited) - Nine Months Ended September 30, 2010 and 2009	11
Public Service Company of New Hampshire and Subsidiaries
Condensed Consolidated Balance Sheets (Unaudited) - September 30, 2010 and December 31, 2009	14
Condensed Consolidated Statements of Income (Unaudited) - Three and Nine Months Ended September 30, 2010 and 2009	16
Condensed Consolidated Statements of Cash Flows (Unaudited) - Nine Months Ended September 30, 2010 and 2009	17
Western Massachusetts Electric Company and Subsidiary
Condensed Consolidated Balance Sheets (Unaudited) - September 30, 2010 and December 31, 2009	20
Condensed Consolidated Statements of Income (Unaudited) - Three and Nine Months Ended September 30, 2010 and 2009	22
Condensed Consolidated Statements of Cash Flows (Unaudited) - Nine Months Ended September 30, 2010 and 2009	23
Combined Notes to Condensed Consolidated Financial Statements (Unaudited - all companies)	24
Report of Independent Registered Public Accounting Firm	52

iii

	Page
ITEM 2 - Management's Discussion and Analysis of Financial Condition and Results of Operations for the following companies:
Northeast Utilities and Subsidiaries		53
The Connecticut Light and Power Company and Subsidiaries		72
Public Service Company of New Hampshire and Subsidiaries		76
Western Massachusetts Electric Company and Subsidiary		79
ITEM 3 - Quantitative and Qualitative Disclosures About Market Risk		82
ITEM 4 - Controls and Procedures		82
PART II-OTHER INFORMATION
ITEM 1 - Legal Proceedings		83
ITEM 1A - Risk Factors		83
ITEM 2 - Unregistered Sales of Equity Securities and Use of Proceeds		84
ITEM 6 – Exhibits		85
SIGNATURES		87

iv

NORTHEAST UTILITIES AND SUBSIDIARIES

1

NORTHEAST UTILITIES AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
		September 30,		December 31,
(Thousands of Dollars)		2010		2009
ASSETS
Current Assets:
Cash and Cash Equivalents	$	41,179	$	26,952
Receivables, Net		526,280		512,770
Unbilled Revenues		151,923		229,326
Fuel, Materials and Supplies		247,254		277,085
Marketable Securities		79,969		66,236
Derivative Assets		10,651		31,785
Prepayments and Other Current Assets		178,739		123,700
Total Current Assets		1,235,995		1,267,854
Property, Plant and Equipment, Net		9,318,017		8,839,965
Deferred Debits and Other Assets:
Regulatory Assets		3,085,019		3,244,931
Goodwill		287,591		287,591
Marketable Securities		45,727		54,905
Derivative Assets		134,704		189,751
Other Long-Term Assets		190,535		172,682
Total Deferred Debits and Other Assets		3,743,576		3,949,860
Total Assets	$	14,297,588	$	14,057,679
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

2

NORTHEAST UTILITIES AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
		September 30,		December 31,
(Thousands of Dollars)		2010		2009
LIABILITIES AND CAPITALIZATION
Current Liabilities:
Notes Payable to Banks	$	156,000	$	100,313
Long-Term Debt - Current Portion		66,286		66,286
Accounts Payable		379,184		457,582
Obligations to Third Party Suppliers		71,995		44,978
Accrued Taxes		69,870		50,246
Accrued Interest		107,828		83,763
Derivative Liabilities		61,317		37,617
Other Current Liabilities		144,668		138,627
Total Current Liabilities		1,057,148		979,412
Rate Reduction Bonds		246,711		442,436
Deferred Credits and Other Liabilities:
Accumulated Deferred Income Taxes		1,546,255		1,380,143
Regulatory Liabilities		434,498		485,706
Derivative Liabilities		996,209		955,646
Accrued Pension		759,263		781,431
Other Long-Term Liabilities		781,246		845,868
Total Deferred Credits and Other Liabilities		4,517,471		4,448,794
Capitalization:
Long-Term Debt		4,635,960		4,492,935
Noncontrolling Interest in Consolidated Subsidiary:
Preferred Stock Not Subject to Mandatory Redemption		116,200		116,200
Equity:
Common Shareholders' Equity:
Common Shares		978,677		977,276
Capital Surplus, Paid In		1,772,959		1,762,097
Deferred Contribution Plan		-		(2,944)
Retained Earnings		1,368,956		1,246,543
Accumulated Other Comprehensive Loss		(40,979)		(43,467)
Treasury Stock		(356,950)		(361,603)
Common Shareholders' Equity		3,722,663		3,577,902
Noncontrolling Interest		1,435		-
Total Equity		3,724,098		3,577,902
Total Capitalization		8,476,258		8,187,037
Total Liabilities and Capitalization	$	14,297,588	$	14,057,679
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

3

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)	2010		2009		2010		2009
Operating Revenues	$	1,243,337	$	1,306,173	$	3,694,182	$	4,124,087
Operating Expenses:
Fuel, Purchased and Net Interchange Power		494,125		611,632		1,539,703		2,034,151
Other Operating Expenses		233,472		250,296		688,409		732,562
Maintenance		49,951		61,609		162,405		166,812
Depreciation		70,954		77,074		228,685		231,825
Amortization of Regulatory Assets, Net		50,341		10,542		50,908		19,194
Amortization of Rate Reduction Bonds		60,434		56,669		175,000		163,871
Taxes Other Than Income Taxes		84,427		75,798		244,431		216,651
Total Operating Expenses		1,043,704		1,143,620		3,089,541		3,565,066
Operating Income		199,633		162,553		604,641		559,021
Interest Expense:
Interest on Long-Term Debt		57,802		55,733		173,594		168,191
Interest on Rate Reduction Bonds		4,661		8,657		16,985		28,889
Other Interest		3,435		5,245		9,778		8,490
Interest Expense		65,898		69,635		200,357		205,570
Other Income, Net		10,118		9,490		19,726		26,081
Income Before Income Tax Expense		143,853		102,408		424,010		379,532
Income Tax Expense		41,918		36,230		161,126		130,047
Net Income		101,935		66,178		262,884		249,485
Net Income Attributable to Noncontrolling Interests		1,411		1,390		4,204		4,169
Net Income Attributable to Controlling Interests	$	100,524	$	64,788	$	258,680	$	245,316
Basic Earnings Per Common Share	$	0.57	$	0.37	$	1.47	$	1.43
Fully Diluted Earnings Per Common Share	$	0.57	$	0.37	$	1.46	$	1.43
Dividends Declared Per Common Share	$	0.26	$	0.24	$	0.77	$	0.71
Weighted Average Common Shares Outstanding:
Basic		176,752,714		175,358,776		176,557,889		170,958,396
Fully Diluted		177,012,278		175,995,506		176,762,088		171,532,913

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

4

NORTHEAST UTILITIES AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
		Nine Months Ended September 30,
(Thousands of Dollars)		2010		2009
Operating Activities:
Net Income	$	262,884	$	249,485
Adjustments to Reconcile Net Income to Net Cash Flows
Provided by Operating Activities:
Bad Debt Expense		24,632		31,519
Depreciation		228,685		231,825
Deferred Income Taxes		105,070		77,617
Pension and PBOP Expense, Net of PBOP Contributions		41,709		10,197
Pension Contribution		(45,000)		-
Regulatory Overrecoveries, Net		44,479		44,519
Amortization of Regulatory Assets, Net		50,908		19,194
Amortization of Rate Reduction Bonds		175,000		163,871
Derivative Assets and Liabilities		(9,228)		(18,519)
Other		(46,190)		(13,485)
Changes in Current Assets and Liabilities:
Receivables and Unbilled Revenues, Net		20,905		122,700
Fuel, Materials and Supplies		33,337		18,900
Taxes Receivable/Accrued		(12,904)		59,641
Other Current Assets		(6,379)		(7,490)
Accounts Payable		(59,601)		(242,179)
Other Current Liabilities		35,340		13,335
Net Cash Flows Provided by Operating Activities		843,647		761,130
Investing Activities:
Investments in Property and Plant		(677,579)		(634,446)
Proceeds from Sales of Marketable Securities		146,305		182,131
Purchases of Marketable Securities		(148,075)		(183,814)
Other Investing Activities		(10,412)		4,298
Net Cash Flows Used in Investing Activities		(689,761)		(631,831)
Financing Activities:
Issuance of Common Shares		-		388,529
Cash Dividends on Common Shares		(135,349)		(120,647)
Cash Dividends on Preferred Stock		(4,169)		(4,169)
Increase/(Decrease) in Short-Term Debt		55,687		(293,663)
Issuance of Long-Term Debt		145,000		312,000
Retirements of Long-Term Debt		(4,286)		(54,286)
Retirements of Rate Reduction Bonds		(195,724)		(183,208)
Other Financing Activities		(818)		(14,694)
Net Cash Flows (Used In)/Provided by Financing Activities		(139,659)		29,862
Net Increase in Cash and Cash Equivalents		14,227		159,161
Cash and Cash Equivalents - Beginning of Period		26,952		89,816
Cash and Cash Equivalents - End of Period	$	41,179	$	248,977
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

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6

THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES

7

THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
		September 30,		December 31,
(Thousands of Dollars)		2010		2009
ASSETS
Current Assets:
Cash	$	7,118	$	45
Receivables, Net		350,738		327,969
Accounts Receivable from Affiliated Companies		1,646		2,362
Notes Receivable from Affiliated Companies		-		97,775
Unbilled Revenues		91,434		140,632
Materials and Supplies		62,292		65,623
Derivative Assets		1,930		24,593
Prepayments and Other Current Assets		79,116		18,385
Total Current Assets		594,274		677,384
Property, Plant and Equipment, Net		5,487,899		5,340,561
Deferred Debits and Other Assets:
Regulatory Assets		1,965,529		2,068,778
Derivative Assets		118,761		183,231
Other Long-Term Assets		87,032		94,610
Total Deferred Debits and Other Assets		2,171,322		2,346,619
Total Assets	$	8,253,495	$	8,364,564
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

8

THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
		September 30,		December 31,
(Thousands of Dollars)		2010		2009
LIABILITIES AND CAPITALIZATION
Current Liabilities:
Notes Payable to Affiliated Companies	$	26,325	$	-
Long-Term Debt - Current Portion		62,000		62,000
Accounts Payable		178,654		242,853
Accounts Payable to Affiliated Companies		41,816		48,795
Obligations to Third Party Suppliers		65,907		39,609
Accrued Taxes		48,417		36,860
Accrued Interest		46,784		49,867
Derivative Liabilities		33,544		9,770
Other Current Liabilities		42,729		61,237
Total Current Liabilities		546,176		550,991
Rate Reduction Bonds		48,054		195,587
Deferred Credits and Other Liabilities:
Accumulated Deferred Income Taxes		994,504		901,527
Regulatory Liabilities		278,168		316,160
Derivative Liabilities		960,228		913,349
Accrued Pension		42,706		51,319
Other Long-Term Liabilities		396,850		425,887
Total Deferred Credits and Other Liabilities		2,672,456		2,608,242
Capitalization:
Long-Term Debt		2,520,914		2,520,361
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		1,602,412		1,601,792
Retained Earnings		689,744		714,210
Accumulated Other Comprehensive Loss		(2,813)		(3,171)
Common Stockholder's Equity		2,349,695		2,373,183
Total Capitalization		4,986,809		5,009,744
Total Liabilities and Capitalization	$	8,253,495	$	8,364,564
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

9

THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
	Three Months Ended September 30,				Nine Months Ended September 30,
(Thousands of Dollars)	2010		2009		2010		2009
Operating Revenues	$	789,249	$	859,283	$	2,292,146	$	2,598,723
Operating Expenses:
Fuel, Purchased and Net Interchange Power		334,230		419,620		987,604		1,317,159
Other Operating Expenses		127,779		149,302		382,884		419,887
Maintenance		21,056		31,215		75,715		86,113
Depreciation		38,100		46,519		133,568		140,000
Amortization of Regulatory Assets, Net		32,997		7,911		55,308		24,551
Amortization of Rate Reduction Bonds		43,778		40,976		125,985		117,725
Taxes Other Than Income Taxes		59,884		53,648		168,001		149,736
Total Operating Expenses		657,824		749,191		1,929,065		2,255,171
Operating Income		131,425		110,092		363,081		343,552
Interest Expense:
Interest on Long-Term Debt		33,656		33,514		100,918		99,486
Interest on Rate Reduction Bonds		1,529		4,455		6,805		15,342
Other Interest		1,496		2,838		4,692		1,420
Interest Expense		36,681		40,807		112,415		116,248
Other Income, Net		6,938		7,070		12,616		17,948
Income Before Income Tax Expense		101,682		76,355		263,282		245,252
Income Tax Expense		32,636		29,818		101,739		87,178
Net Income	$	69,046	$	46,537	$	161,543	$	158,074

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

10

THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
		Nine Months Ended September 30,
(Thousands of Dollars)		2010		2009
Operating Activities:
Net Income	$	161,543	$	158,074
Adjustments to Reconcile Net Income to Net Cash Flows
Provided by Operating Activities:
Bad Debt Expense		7,088		11,170
Depreciation		133,568		140,000
Deferred Income Taxes		49,636		34,458
Pension and PBOP Expense, Net of PBOP Contributions		388		(4,329)
Regulatory Overrecoveries, Net		57,696		51,378
Amortization of Regulatory Assets, Net		55,308		24,551
Amortization of Rate Reduction Bonds		125,985		117,725
Other		(38,073)		(25,452)
Changes in Current Assets and Liabilities:
Receivables and Unbilled Revenues, Net		2,653		52,715
Materials and Supplies		3,331		(6,205)
Taxes Receivable/Accrued		(13,016)		63,404
Other Current Assets		(16,990)		(15,395)
Accounts Payable		(55,383)		(121,852)
Other Current Liabilities		17,026		1,421
Net Cash Flows Provided by Operating Activities		490,760		481,663
Investing Activities:
Investments in Property and Plant		(274,193)		(331,644)
Decrease/(Increase) in NU Money Pool Lending		97,775		(89,975)
Other Investing Activities		205		1,630
Net Cash Flows Used in Investing Activities		(176,213)		(419,989)
Financing Activities:
Cash Dividends on Common Stock		(181,841)		(85,386)
Cash Dividends on Preferred Stock		(4,169)		(4,169)
Decrease in Short-Term Debt		-		(154,982)
Issuance of Long-Term Debt		-		312,000
Increase/(Decrease) in NU Money Pool Borrowings		26,325		(102,725)
Retirements of Rate Reduction Bonds		(147,533)		(137,859)
Capital Contributions from NU Parent		-		116,591
Other Financing Activities		(256)		(2,923)
Net Cash Flows Used in Financing Activities		(307,474)		(59,453)
Net Increase in Cash		7,073		2,221
Cash - Beginning of Period		45		-
Cash - End of Period	$	7,118	$	2,221
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

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PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES

13

PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
		September 30,		December 31,
(Thousands of Dollars)		2010		2009
ASSETS
Current Assets:
Cash	$	643	$	1,974
Receivables, Net		97,930		89,337
Accounts Receivable from Affiliated Companies		917		286
Unbilled Revenues		41,870		49,358
Taxes Receivable		7,534		22,600
Fuel, Materials and Supplies		102,765		127,447
Prepayments and Other Current Assets		14,591		36,387
Total Current Assets		266,250		327,389
Property, Plant and Equipment, Net		1,986,903		1,814,714
Deferred Debits and Other Assets:
Regulatory Assets		454,988		494,077
Other Long-Term Assets		88,853		61,011
Total Deferred Debits and Other Assets		543,841		555,088
Total Assets	$	2,796,994	$	2,697,191
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

14

PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
		September 30,		December 31,
(Thousands of Dollars)		2010		2009
LIABILITIES AND CAPITALIZATION
Current Liabilities:
Notes Payable to Affiliated Companies	$	26,600	$	26,700
Accounts Payable		92,886		109,521
Accounts Payable to Affiliated Companies		13,845		20,083
Accrued Interest		16,825		10,255
Derivative Liabilities		18,202		18,785
Other Current Liabilities		35,339		27,983
Total Current Liabilities		203,697		213,327
Rate Reduction Bonds		151,479		188,113
Deferred Credits and Other Liabilities:
Accumulated Deferred Income Taxes		315,948		275,669
Regulatory Liabilities		68,868		69,872
Derivative Liabilities		3,577		7,635
Accrued Pension		241,287		272,905
Other Long-Term Liabilities		96,175		105,970
Total Deferred Credits and Other Liabilities		725,855		732,051
Capitalization:
Long-Term Debt		836,337		836,255
Common Stockholder's Equity:
Common Stock		-		-
Capital Surplus, Paid In		544,000		420,169
Retained Earnings		336,230		307,988
Accumulated Other Comprehensive Loss		(604)		(712)
Common Stockholder's Equity		879,626		727,445
Total Capitalization		1,715,963		1,563,700
Total Liabilities and Capitalization	$	2,796,994	$	2,697,191
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

15

PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
	Three Months Ended September 30,				Nine Months Ended September 30,
(Thousands of Dollars)	2010		2009		2010		2009
Operating Revenues	$	276,976	$	275,135	$	773,866	$	845,719
Operating Expenses:
Fuel, Purchased and Net Interchange Power		94,137		120,437		281,161		395,156
Other Operating Expenses		53,133		55,038		172,332		176,242
Maintenance		20,933		22,327		62,560		58,701
Depreciation		17,454		15,567		49,443		46,128
Amortization of Regulatory Assets/(Liabilities), Net		14,513		3,157		(2,809)		(1,656)
Amortization of Rate Reduction Bonds		12,844		12,123		37,481		35,337
Taxes Other Than Income Taxes		14,191		12,361		40,616		34,374
Total Operating Expenses		227,205		241,010		640,784		744,282
Operating Income		49,771		34,125		133,082		101,437
Interest Expense:
Interest on Long-Term Debt		8,925		8,181		27,705		24,551
Interest on Rate Reduction Bonds		2,320		3,146		7,557		10,210
Other Interest		208		371		572		34
Interest Expense		11,453		11,698		35,834		34,795
Other Income, Net		3,667		2,239		5,882		6,469
Income Before Income Tax Expense		41,985		24,666		103,130		73,111
Income Tax Expense		13,231		8,463		36,950		22,843
Net Income	$	28,754	$	16,203	$	66,180	$	50,268

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

16

PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
		Nine Months Ended September 30,
(Thousands of Dollars)		2010		2009
Operating Activities:
Net Income	$	66,180	$	50,268
Adjustments to Reconcile Net Income to Net Cash Flows
Provided by Operating Activities:
Bad Debt Expense		7,237		7,014
Depreciation		49,443		46,128
Deferred Income Taxes		31,876		16,852
Pension and PBOP Expense, Net of PBOP Contributions		14,707		13,137
Pension Contribution		(45,000)		-
Regulatory Underrecoveries, Net		(5,450)		(10,316)
Amortization of Regulatory Liabilities, Net		(2,809)		(1,656)
Amortization of Rate Reduction Bonds		37,481		35,337
Insurance Proceeds		10,000		10,066
Other		(32,525)		(6,123)
Changes in Current Assets and Liabilities:
Receivables and Unbilled Revenues, Net		(8,973)		(6,937)
Fuel, Materials and Supplies		28,188		878
Taxes Receivable/Accrued		15,066		1,934
Other Current Assets		12,863		10,771
Accounts Payable		(11,599)		(77,433)
Other Current Liabilities		8,989		11,256
Net Cash Flows Provided by Operating Activities		175,674		101,176
Investing Activities:
Investments in Property and Plant		(217,954)		(169,434)
Decrease in NU Money Pool Lending		-		53,800
Other Investing Activities		(7,753)		(759)
Net Cash Flows Used in Investing Activities		(225,707)		(116,393)
Financing Activities:
Cash Dividends on Common Stock		(37,938)		(30,633)
(Decrease)/Increase in NU Money Pool Borrowings		(100)		12,700
Retirements of Rate Reduction Bonds		(36,635)		(34,515)
Capital Contributions from NU Parent		123,551		68,946
Other Financing Activities		(176)		(301)
Net Cash Flows Provided by Financing Activities		48,702		16,197
Net (Decrease)/Increase in Cash		(1,331)		980
Cash - Beginning of Period		1,974		195
Cash - End of Period	$	643	$	1,175
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

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18

WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY

19

WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
		September 30,		December 31,
(Thousands of Dollars)		2010		2009
ASSETS
Current Assets:
Cash	$	1	$	1
Receivables, Net		39,077		38,415
Accounts Receivable from Affiliated Companies		312		191
Unbilled Revenues		12,969		16,090
Materials and Supplies		9,192		8,314
Marketable Securities		38,424		28,261
Prepayments and Other Current Assets		4,034		5,966
Total Current Assets		104,009		97,238
Property, Plant and Equipment, Net		779,749		705,760
Deferred Debits and Other Assets:
Regulatory Assets		228,094		240,804
Marketable Securities		18,584		28,500
Other Long-Term Assets		38,224		29,498
Total Deferred Debits and Other Assets		284,902		298,802
Total Assets	$	1,168,660	$	1,101,800
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

20

WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
		September 30,		December 31,
(Thousands of Dollars)		2010		2009
LIABILITIES AND CAPITALIZATION
Current Liabilities:
Notes Payable to Affiliated Companies	$	10,200	$	136,100
Accounts Payable		40,027		36,680
Accounts Payable to Affiliated Companies		4,011		7,924
Other Current Liabilities		12,108		14,147
Total Current Liabilities		66,346		194,851
Rate Reduction Bonds		47,178		58,735
Deferred Credits and Other Liabilities:
Accumulated Deferred Income Taxes		218,250		211,391
Regulatory Liabilities		21,887		21,683
Other Long-Term Liabilities		58,207		62,858
Total Deferred Credits and Other Liabilities		298,344		295,932
Capitalization:
Long-Term Debt		400,249		305,475
Common Stockholder's Equity:
Common Stock		10,866		10,866
Capital Surplus, Paid In		248,105		145,400
Retained Earnings		97,632		90,549
Accumulated Other Comprehensive Loss		(60)		(8)
Common Stockholder's Equity		356,543		246,807
Total Capitalization		756,792		552,282
Total Liabilities and Capitalization	$	1,168,660	$	1,101,800
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

21

WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
	Three Months Ended September 30,				Nine Months Ended September 30,
(Thousands of Dollars)	2010		2009		2010		2009
Operating Revenues	$	103,719	$	96,622	$	296,400	$	309,823
Operating Expenses:
Fuel, Purchased and Net Interchange Power		39,922		42,403		120,274		151,936
Other Operating Expenses		27,314		19,022		73,607		64,503
Maintenance		4,915		5,196		14,825		13,437
Depreciation		5,838		5,609		17,658		16,758
Amortization of Regulatory Assets/(Liabilities), Net		2,735		(430)		445		(3,769)
Amortization of Rate Reduction Bonds		3,812		3,569		11,534		10,809
Taxes Other Than Income Taxes		4,319		4,104		12,483		10,518
Total Operating Expenses		88,855		79,473		250,826		264,192
Operating Income		14,864		17,149		45,574		45,631
Interest Expense:
Interest on Long-Term Debt		4,691		3,534		13,298		10,531
Interest on Rate Reduction Bonds		811		1,057		2,623		3,337
Other Interest		93		238		275		632
Interest Expense		5,595		4,829		16,196		14,500
Other Income, Net		747		160		1,512		1,095
Income Before Income Tax Expense		10,016		12,480		30,890		32,226
Income Tax Expense		2,679		3,971		12,645		11,764
Net Income	$	7,337	$	8,509	$	18,245	$	20,462

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

22

WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
		Nine Months Ended September 30,
(Thousands of Dollars)		2010		2009
Operating Activities:
Net Income	$	18,245	$	20,462
Adjustments to Reconcile Net Income to Net Cash Flows
Provided by Operating Activities:
Bad Debt Expense		5,602		5,858
Depreciation		17,658		16,758
Deferred Income Taxes		4,712		17,227
�� Pension and PBOP Expense, Net of PBOP Contributions		(524)		(6,840)
Regulatory (Underrecoveries)/Overrecoveries, Net		(8,696)		3,083
Amortization of Regulatory Assets/(Liabilities), Net		445		(3,769)
Amortization of Rate Reduction Bonds		11,534		10,809
Other		(4,437)		(3,580)
Changes in Current Assets and Liabilities:
Receivables and Unbilled Revenues, Net		(2,896)		4,633
Materials and Supplies		(878)		124
Taxes Receivable/Accrued		1,203		5,616
Other Current Assets		728		1,016
Accounts Payable		(9,900)		(27,176)
Other Current Liabilities		(2,109)		(5,720)
Net Cash Flows Provided by Operating Activities		30,687		38,501
Investing Activities:
Investments in Property and Plant		(77,710)		(63,726)
Proceeds from Sales of Marketable Securities		94,575		99,898
Purchases of Marketable Securities		(94,896)		(100,413)
Other Investing Activities		(754)		581
Net Cash Flows Used in Investing Activities		(78,785)		(63,660)
Financing Activities:
Cash Dividends on Common Stock		(11,162)		(14,652)
Increase in Short-Term Debt		-		45,227
Issuance of Long-Term Debt		95,000		-
(Decrease)/Increase in NU Money Pool Borrowings		(125,900)		4,600
Retirements of Rate Reduction Bonds		(11,557)		(10,833)
Capital Contributions from NU Parent		102,600		864
Other Financing Activities		(883)		(46)
Net Cash Flows Provided by Financing Activities		48,098		25,160
Net Increase in Cash		-		1
Cash - Beginning of Period		1		-
Cash - End of Period	$	1	$	1
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

23

NORTHEAST UTILITIES AND SUBSIDIARIES

THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES

WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)

1.

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

A.

Proposed Merger with NSTAR

On October 18, 2010, NU and NSTAR announced that each company's Board of Trustees unanimously approved a Definitive Merger Agreement (the "agreement") to create a combined company that will be called Northeast Utilities.  The transaction will be a merger of equals in a tax-free share for share transfer.  The combined company will provide electric and natural gas energy delivery service to approximately 3.5 million electric and natural gas customers through six regulated electric and natural gas utilities in Connecticut, Massachusetts and New Hampshire.

Under the terms of the agreement, NSTAR shareholders would receive 1.312 NU common shares for each common share of NSTAR that they own (the "exchange ratio").  The exchange ratio is 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.  Following completion of the merger, the market capitalization of the combined company would be comprised of approximately 56 percent of NU shareholders and approximately 44 percent of former NSTAR shareholders.  It is anticipated that NU would issue approximately 137 million shares to the NSTAR shareholders as a result of the merger.  Following the closing of the merger, NU's first dividend per common share declared after the closing would be increased to a rate that is equivalent to NSTAR's last dividend per common share paid prior to the closing divided by the exchange ratio.

Completion of the merger is subject to various conditions, including, among others, approval by holders of two-thirds of the outstanding common shares of both companies, the expiration or termination of any applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, the effectiveness of the registration statement for the NU common shares to be issued to NSTAR shareholders in the merger, and receipt of all required regulatory approvals.  The companies anticipate that the regulatory approvals can be obtained in nine to twelve months.  The companies intend to seek shareholder approval of the merger in early 2011 and expect that the merger will close in the third quarter of 2011.

B.

Presentation

Certain information and footnote disclosures normally included in annual consolidated financial statements prepared in accordance with GAAP have been omitted pursuant to the rules and regulations of the SEC.  The accompanying unaudited condensed consolidated financial statements should be read in conjunction with the entirety of this combined Quarterly Report on Form 10-Q, the first and second quarter 2010 combined Quarterly Reports on Form 10-Q, and the combined 2009 Annual Report on Form 10-K of Northeast Utilities (NU or the Company), CL&P, PSNH, and WMECO, which was filed with the SEC (NU 2009 Form 10-K).  The accompanying unaudited condensed consolidated financial statements contain, in the opinion of management, all adjustments (including normal, recurring adjustments) necessary to present fairly NU's and the above companies' financial positions as of September 30, 2010 and December 31, 2009, the resu lts of operations for the three and nine months ended September 30, 2010 and 2009, and cash flows for the nine months ended September 30, 2010 and 2009.  The results of operations for the three months ended September 30, 2010 and 2009, and the results of operations and cash flows for the nine months ended September 30, 2010 and 2009, are not necessarily indicative of the results expected for a full year.  

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.

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

In accordance with accounting guidance on the consolidation of VIEs, the Company evaluates its variable interests to determine if it has a controlling financial interest in a VIE that would require consolidation.  The Company's variable interests outside of the consolidated group consist of contracts with developers of power plants that are required by regulation and provide for regulatory recovery of contract costs and benefits through customer rates.  The Company would consolidate a VIE if it had both the power to direct the activities of a VIE that most significantly impact the entity's economic performance and the obligation to absorb losses of, or receive benefits from, the entity that could potentially be significant to the VIE.  

For each variable interest in a power plant, NU evaluates the activities of that particular power plant that most significantly impact the VIE's economic performance to determine whether it has control over those activities.  NU's assessment of control includes an analysis of who operates and maintains the power plant including dispatch rights and who controls the activities of the power plant after the expiration of its power purchase agreement with NU.  NU also evaluates its exposure to potentially significant losses and benefits of the VIE.  As of September 30, 2010, NU held variable interests in VIEs through agreements with certain entities that are single power plant owners of renewable energy, peaking generation and other independent power producers.  NU does not control the activities that are economically significant to these VIEs or provide financial or other support to these VIEs.  NU does not have fina ncial exposure

24

because the costs and benefits of all of these arrangements are fully recoverable from, or refundable to, NU's customers.  As of September 30, 2010, NU was not identified as the primary beneficiary of, and therefore does not consolidate, any power plant VIEs.  The Company does not have any variable interests in a VIE that are material to the accompanying unaudited condensed consolidated financial statements.  

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.

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

NU evaluates events and transactions that occur after the balance sheet date but before financial statements are issued and recognizes in the financial statements the effects of all subsequent events that provide additional evidence about conditions that existed as of the balance sheet date and discloses but does not recognize in the financial statements subsequent events that provide evidence about the conditions that arose after the balance sheet date but before the financial statements are issued.  See Note 13, "Subsequent Events," for further information.  

C.

Fair Value Measurements

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

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

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

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

Level 3 - Quoted market prices are not available.  Fair value is derived from valuation techniques in which one or more significant inputs or assumptions are unobservable.  Where possible, valuation techniques incorporate observable market inputs that can be validated to external sources such as industry exchanges, including prices of energy and energy-related products.  Significant unobservable inputs are used in the valuations, including items such as energy and energy-related product prices in future years for which observable prices are not yet available, future contract quantities under full-requirements or supplemental sales contracts, and market volatilities.  Items valued using these valuation techniques are classified according to the lowest level for which there is at least one input that is significant to the valuation.  Therefore, an item may be classified in Level 3 even though the re may be some significant inputs that are readily observable.

Determination of Fair Value:  The valuation techniques and inputs used in NU's fair value measurements are described in Note 2, "Derivative Instruments," and Note 10, "Marketable Securities," to the unaudited condensed consolidated financial statements.  There were no changes to the valuation methodologies for derivative instruments or marketable securities as of September 30, 2010 and December 31, 2009.  

D.

Regulatory Accounting

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

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

25

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

	As of September 30, 2010		As of December 31, 2009
(Millions of Dollars)		NU		NU
Deferred Benefit Costs	$	1,078.1	$	1,132.1
Regulatory Assets Offsetting Derivative Liabilities		922.4		855.6
Securitized Assets		236.6		432.9
Income Taxes, Net		380.8		363.2
Unrecovered Contractual Obligations		133.4		149.5
Regulatory Tracker Deferrals		83.9		104.1
Storm Cost Deferral		62.3		60.0
Asset Retirement Obligations		45.2		42.9
Losses on Reacquired Debt		22.2		24.0
Deferred Environmental Remediation Costs		35.5		24.6
Other Regulatory Assets		84.6		56.0
Totals	$	3,085.0	$	3,244.9

	As of September 30, 2010						As of December 31, 2009
(Millions of Dollars)	CL&P		PSNH		WMECO		CL&P		PSNH		WMECO
Deferred Benefit Costs	$	477.3	$	142.6	$	98.9	$	502.4	$	154.2	$	104.9
Regulatory Assets Offsetting Derivative Liabilities		899.8		21.8		-		828.6		26.4		-
Securitized Assets		48.0		142.7		45.9		195.4		180.1		57.4
Income Taxes, Net		310.3		28.9		18.1		304.1		21.9		16.9
Unrecovered Contractual Obligations		105.6		-		27.8		118.0		-		31.5
Regulatory Tracker Deferrals		37.4		25.5		16.2		70.3		19.0		11.3
Storm Cost Deferral		4.7		42.3		15.3		-		50.8		9.2
Asset Retirement Obligations		25.5		14.4		3.0		23.8		14.0		2.8
Losses on Reacquired Debt		11.7		8.6		0.4		12.7		9.2		0.4
Deferred Environmental Remediation Costs		-		8.4		-		-		1.3		-
Other Regulatory Assets		45.2		19.8		2.5		13.5		17.2		6.4
Totals	$	1,965.5	$	455.0	$	228.1	$	2,068.8	$	494.1	$	240.8

Additionally, the Regulated companies had $45.3 million ($0.5 million for CL&P, $25 million for PSNH, and $11.9 million for WMECO) and $27.1 million ($9.9 million for CL&P and $9.1 million for WMECO) of regulatory costs as of September 30, 2010 and December 31, 2009, respectively, which were included in Other Long-Term Assets on the accompanying unaudited condensed consolidated balance sheets.  These amounts represent incurred costs that have not yet been approved for recovery by the applicable regulatory agency.  Management believes these costs are probable of recovery in future cost-of-service regulated rates.  

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

	As of September 30, 2010		As of December 31, 2009
(Millions of Dollars)		NU		NU
Cost of Removal	$	197.6	$	209.2
Regulatory Liabilities Offsetting Derivative Assets		25.7		109.4
Regulatory Tracker Deferrals		99.2		62.5
AFUDC Transmission Incentive		58.3		51.1
Pension and PBOP Liabilities - Yankee Gas Acquisition		13.1		15.0
Other Regulatory Liabilities		40.6		38.5
Totals	$	434.5	$	485.7

	As of September 30, 2010						As of December 31, 2009
(Millions of Dollars)	CL&P		PSNH		WMECO		CL&P		PSNH		WMECO
Cost of Removal	$	78.7	$	58.3	$	11.6	$	82.2	$	60.5	$	16.6
Regulatory Liabilities Offsetting   Derivative Assets		25.7		-		-		109.0		0.4		-
Regulatory Tracker Deferrals		88.1		7.4		3.7		56.0		4.4		2.1
AFUDC Transmission Incentive		54.7		-		3.6		50.4		-		0.7
WMECO Provision For Rate Refunds		-		-		2.0		-		-		2.0
Other Regulatory Liabilities		31.0		3.2		1.0		18.6		4.6		0.3
Totals	$	278.2	$	68.9	$	21.9	$	316.2	$	69.9	$	21.7

26

E.

Property, Plant and Equipment and Accumulated Depreciation

The following tables summarize the NU, CL&P, PSNH, and WMECO investments in utility plant as of September 30, 2010 and December 31, 2009:

	As of September 30, 2010		As of December 31, 2009
(Millions of Dollars)	NU		NU
Distribution - Electric	$	6,100.1	$	5,893.9
Distribution - Natural Gas		1,098.4		1,071.1
Transmission		3,286.4		3,219.2
Generation		680.0		660.1
Electric and Natural Gas Utility		11,164.9		10,844.3
Other(1)		282.1		265.6
Total Property, Plant and Equipment, Gross		11,447.0		11,109.9
Less:  Accumulated Depreciation
Electric and Natural Gas Utility		(2,844.5)		(2,721.3)
Other		(121.8)		(120.3)
Total Accumulated Depreciation		(2,966.3)		(2,841.6)
Property, Plant and Equipment, Net		8,480.7		8,268.3
Construction Work in Progress		837.3		571.7
Total Property, Plant and Equipment, Net	$	9,318.0	$	8,840.0

⁽¹⁾

These assets are primarily owned by RRR ($146.9 million and $143.8 million) and NUSCO ($122.3 million and $109 million) as of September 30, 2010 and December 31, 2009, respectively.  

	As of September 30, 2010						As of December 31, 2009
(Millions of Dollars)	CL&P		PSNH		WMECO		CL&P		PSNH		WMECO
Distribution	$	4,117.3	$	1,345.6	$	669.1	$	3,960.1	$	1,309.2	$	654.9
Transmission		2,605.2		459.7		221.5		2,573.2		450.2		195.7
Generation		-		680.0		-		-		660.1		-
Total Property, Plant and Equipment, Gross		6,722.5		2,485.3		890.6		6,533.3		2,419.5		850.6
Less:  Accumulated Depreciation		(1,501.1)		(832.7)		(227.5)		(1,426.6)		(805.5)		(218.2)
Property, Plant and Equipment, Net		5,221.4		1,652.6		663.1		5,106.7		1,614.0		632.4
Construction Work in Progress		266.5		334.3		116.6		233.9		200.7		73.4
Total Property, Plant and Equipment, Net	$	5,487.9	$	1,986.9	$	779.7	$	5,340.6	$	1,814.7	$	705.8

F.

Provision for Uncollectible Accounts

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

The provision for uncollectible accounts as of September 30, 2010 and December 31, 2009, which are included in Receivables, Net on the accompanying unaudited condensed consolidated balance sheets, were as follows:

(Millions of Dollars)	As of September 30, 2010		As of December 31, 2009
NU	$	55.2	$	55.3
CL&P		27.7		26.1
PSNH		6.5		5.1
WMECO		7.7		7.2

G.

Allowance for Funds Used During Construction

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

	For the Three Months Ended				For the Nine Months Ended
	September 30, 2010		September 30, 2009		September 30, 2010		September 30, 2009
(Millions of Dollars, except percentages)	NU		NU		NU		NU
AFUDC:
Borrowed Funds	$	2.8	$	1.2	$	6.9	$	4.7
Equity Funds		4.6		2.8		11.6		6.2
Totals	$	7.4	$	4.0	$	18.5	$	10.9
Average AFUDC Rates		7.3%		6.4%		7.1%		6.2%

27

	For the Three Months Ended
	September 30, 2010						September 30, 2009
(Millions of Dollars, except percentages)	CL&P		PSNH		WMECO		CL&P		PSNH		WMECO
AFUDC:
Borrowed Funds	$	0.7	$	1.8	$	0.1	$	0.4	$	0.8	$	-
Equity Funds		1.2		2.9		0.2		1.9		0.9		-
Totals	$	1.9	$	4.7	$	0.3	$	2.3	$	1.7	$	-
Average AFUDC Rates		8.1%		6.9%		8.3%		8.2%		6.1%		0.8%

	For the Nine Months Ended
	September 30, 2010						September 30, 2009
(Millions of Dollars, except percentages)	CL&P		PSNH		WMECO		CL&P		PSNH		WMECO
AFUDC:
Borrowed Funds	$	2.0	$	4.4	$	0.2	$	1.9	$	2.4	$	0.2
Equity Funds		3.7		7.1		0.4		3.5		2.5		-
Totals	$	5.7	$	11.5	$	0.6	$	5.4	$	4.9	$	0.2
Average AFUDC Rates		8.4%		6.7%		5.8%		6.8%		6.7%		2.0%

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

H.

Other Income, Net

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

	For the Three Months Ended				For the Nine Months Ended
	September 30, 2010		September 30, 2009		September 30, 2010		September 30, 2009
(Millions of Dollars)	NU		NU		NU		NU
Other Income:
Investment Income	$	4.3	$	5.1	$	2.3	$	8.2
Interest Income		1.0		0.4		3.0		4.4
AFUDC - Equity Funds		4.6		2.8		11.6		6.2
Energy Independence Act Incentives		0.9		0.5		3.1		4.9
Other		1.4		0.7		2.9		2.6
Total Other Income		12.2		9.5		22.9		26.3
Other Loss:
Other		(2.1)		-		(3.2)		(0.2)
Total Other Loss		(2.1)		-		(3.2)		(0.2)
Total Other Income, Net	$	10.1	$	9.5	$	19.7	$	26.1

	For the Three Months Ended
	September 30, 2010						September 30, 2009
(Millions of Dollars)	CL&P		PSNH		WMECO		CL&P		PSNH		WMECO
Other Income:
Investment Income	$	2.9	$	0.7	$	0.6	$	3.4	$	0.8	$	0.7
Interest Income		0.8		0.1		0.1		0.7		0.4		(0.6)
AFUDC - Equity Funds		1.2		2.9		0.2		1.9		0.9		-
Energy Independence Act Incentives		0.9		-		-		0.6		-		-
Other		1.2		-		-		0.5		0.1		0.1
Total Other Income		7.0		3.7		0.9		7.1		2.2		0.2
Other Loss:
Other		(0.1)		-		(0.2)		-		-		-
Total Other Loss		(0.1)		-		(0.2)		-		-		-
Total Other Income, Net	$	6.9	$	3.7	$	0.7	$	7.1	$	2.2	$	0.2

28

	For the Nine Months Ended
	September 30, 2010						September 30, 2009
(Millions of Dollars)	CL&P		PSNH		WMECO		CL&P		PSNH		WMECO
Other Income:
Investment Income	$	1.5	$	0.4	$	0.3	$	5.5	$	1.4	$	1.2
Interest Income		2.8		0.8		0.5		2.6		2.2		(0.4)
AFUDC - Equity Funds		3.7		7.1		0.4		3.5		2.5		-
Energy Independence Act Incentives		3.1		-		-		4.9		-		-
Other		1.6		0.1		0.3		1.5		0.4		0.4
Total Other Income		12.7		8.4		1.5		18.0		6.5		1.2
Other Loss:
Other		(0.1)		(2.5)		-		(0.1)		-		(0.1)
Total Other Loss		(0.1)		(2.5)		-		(0.1)		-		(0.1)
Total Other Income, Net	$	12.6	$	5.9	$	1.5	$	17.9	$	6.5	$	1.1

Other Income - Other includes equity in earnings, which relates to the Company's investments, including investments of CL&P, PSNH and WMECO, in the Yankee Companies and NU's investment in two regional transmission companies.  Equity in earnings was de minimis for NU, CL&P, PSNH and WMECO for both the three months ended September 30, 2010 and 2009, and $0.8 million and $1.4 million for NU (de minimis amounts for CL&P and PSNH in both periods and a de minimis amount and $0.1 million for WMECO) for the nine months ended September 30, 2010 and 2009, respectively.  Income tax expense associated with the equity in earnings was de minimis for NU, CL&P, PSNH and WMECO for the three months ended September 30, 2010 and 2009and a de minimis amount and $0.6 million for NU (de minimis amounts for CL&P, PSNH and WMECO) for the nine months ended September 30, 2010 and 2009, respectively.  

Dividends received from the Yankee Companies and the regional transmission companies investments were recorded as a reduction to NU's, including CL&P, PSNH and WMECO, investment.  Dividends received were de minimis for NU (zero for CL&P, PSNH, and WMECO) for both the three months ended September 30, 2010 and 2009.  Dividends received were $0.7 million and $3.4 million for NU (zero and $1.5 million for CL&P, zero and $0.2 million for PSNH and zero and $0.4 million for WMECO) for the nine months ended September 30, 2010 and September 30, 2009, respectively.  

Included in Other Loss - Other for NU and PSNH for the nine months ended September 30, 2010 is a $2.5 million write-off of carrying charges related to storm costs incurred during the December 2008 ice storm.  This write-off was part of the multi-year rate case settlement agreement that was effective July 1, 2010.

For both the three and nine months ended September 30, 2009, NU and WMECO's interest income included a $0.7 million tax refund adjustment.

I.

Special Deposits and Counterparty Deposits

NU, including CL&P, PSNH, and WMECO, records special deposits and counterparty deposits posted under master netting agreements as an offset to a derivative asset or liability if the related derivatives are recorded in a net position.  As of September 30, 2010, Select Energy had $4.3 million of collateral posted under master netting agreements and netted against the fair value of the derivatives.  As of December 31, 2009, CL&P and Select Energy had $0.5 million and $2.1 million, respectively, of collateral posted under master netting agreements and netted against the fair value of the derivatives.

Special deposits paid by Select Energy to unaffiliated counterparties and brokerage firms not subject to master netting agreements totaled $27.8 million and $28.1 million as of September 30, 2010 and December 31, 2009, respectively.  These amounts are included in Prepayments and Other Current Assets on the accompanying unaudited condensed consolidated balance sheets.  There were no counterparty deposits for Select Energy as of September 30, 2010 and December 31, 2009.  

NU, CL&P, PSNH and WMECO have established credit policies regarding counterparties to minimize overall credit risk.  These policies require an evaluation of potential counterparties, financial condition, collateral requirements and the use of standardized agreements that allow for the netting of positive and negative exposures associated with a single counterparty.  These evaluations result in established credit limits prior to entering into a contract.  As of September 30, 2010 and December 31, 2009, there were no counterparty deposits for these companies.  

J.

Income Taxes

2010 Federal Legislation:  On March 23, 2010, President Obama signed into law the 2010 Healthcare Act.  The 2010 Healthcare Act was amended by a Reconciliation Bill signed into law on March 30, 2010.  The 2010 Healthcare Act includes a provision that eliminated the tax deductibility of certain PBOP contributions equal to the amount of the federal subsidy received by companies like NU, which sponsor retiree health care benefit plans with a prescription drug benefit that is actuarially equivalent to Medicare Part D.  The tax deduction eliminated by this legislation represented a loss of previously recognized deferred income tax assets established through 2009 and as a result, these assets were written down by approximately $18 million in the first quarter of 2010.  Since the electric and natural gas distribution companies are cost-of-service and rate-regulated, a portion of the $18 million is able to be deferred and recovered through future rates.  For the nine months ended September 30, 2010, NU deferred approximately $15 million of recoverable write-downs related to these businesses and reduced 2010 earnings on a net basis by approximately $3 million of non-recoverable costs.  In addition, as a result of the elimination of the tax deduction in 2010, NU was not able to recognize approximately $2 million of net annual benefits.

29

On September 27, 2010, President Obama signed into law the Small Business Jobs and Credit Act of 2010, which extends the bonus depreciation provisions of the American Recovery and Reinvestment Act of 2009 to small and large businesses through 2010.  This extended stimulus will provide NU with cash flow benefits of approximately $100 million in 2010.

K.

Other Taxes

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

	For the Three Months Ended				For the Nine Months Ended
(Millions of Dollars)	September 30, 2010		September 30, 2009		September 30, 2010		September 30, 2009
NU	$	37.0	$	33.6	$	109.0	$	103.4
CL&P		35.1		31.7		97.3		90.4

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

L.

Common Shares

The following table sets forth the NU common shares and the shares of CL&P, PSNH and WMECO common stock authorized and issued and the respective par values as of September 30, 2010 and December 31, 2009:   

			Shares
			Authorized	Issued
		Per Share Par Value	As of September 30, 2010 and December 31, 2009	As of September 30, 2010	As of December 31, 2009
NU	$	5	225,000,000	195,735,427	195,455,214
CL&P	$	10	24,500,000	6,035,205	6,035,205
PSNH	$	1	100,000,000	301	301
WMECO	$	25	1,072,471	434,653	434,653

As of September 30, 2010 and December 31, 2009, 19,454,509 and 19,708,136 NU common shares were held as treasury shares, respectively.

M.

Restricted Cash

As of December 31, 2009, PSNH had $10 million of restricted cash held with a trustee related to insurance proceeds received on bondable property, which was included in Prepayments and Other Current Assets on the accompanying unaudited condensed consolidated balance sheet.  These funds were released from the trustee during the second quarter of 2010 and there was no restricted cash held as of September 30, 2010.  

N.

Supplemental Cash Flow Information

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

(Millions of Dollars)	As of September 30, 2010		As of December 31, 2009
NU	$	104.0	$	125.5
CL&P		27.5		48.2
PSNH		34.7		46.5
WMECO		19.0		10.3

The majority of the short-term borrowings of NU, including CL&P, PSNH, and WMECO, have original maturities of three months or less.  Accordingly, borrowings and repayments are shown net on the statement of cash flows.  In December 2008, NU parent borrowed $127 million under its revolving credit agreement that had original maturities in excess of 90 days.  These amounts were repaid in March 2009 and are included in the net activity for the nine months ended September 30, 2009 in the unaudited condensed consolidated statement of cash flows.  For the nine months ended September 30, 2010, NU, CL&P, PSNH, and WMECO had no such borrowings.

2.

DERIVATIVE INSTRUMENTS

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

Derivative contracts that are not recorded as normal under the applicable accounting guidance, are recorded at fair value as current or long-term derivative assets or liabilities.  Changes in fair values of NU Enterprises' derivatives are included in Net Income.  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

30

continue to be recovered from or refunded to customers in cost-of-service, regulated rates.  See below for discussion of "Derivatives not designated as hedges."

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

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

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

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

NU mitigates the risks associated with supply availability and volatility of natural gas prices through the use of storage facilities and long-term agreements to purchase natural gas supply for customers.  Yankee Gas enters into contracts to meet required demand levels throughout the heating season and manages supply risk through the use of options contracts.  

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

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

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

31

	As of September 30, 2010
	Derivatives Not Designed as Hedges
(Millions of Dollars)	Commodity and Capacity Contracts Required by Regulation		Commodity Sales Contract and Related Price and Supply Risk Management		Other Commodity Price and Supply Risk Management		Hedging Instruments-Interest Rate Risk Management		Collateral and Netting		Net Amount Recorded as Derivative Asset/(Liability)
Current Derivative Assets:
Level 2:
NU Parent	$	-	$	-	$	-	$	5.5	$	-	$	5.5
Level 3:
NU Enterprises		-		3.3		-		-		-		3.3
CL&P		0.9		-		1.0		-		-		1.9
Total Current Derivative Assets	$	0.9	$	3.3	$	1.0	$	5.5	$	-	$	10.7
Long-Term Derivative Assets:
Level 2:
NU Parent	$	-	$	-	$	-	$	9.7	$	-	$	9.7
Level 3:
NU Enterprises		-		6.2		-		-		-		6.2
CL&P(1)		202.5		-		-		-		(83.7)		118.8
Total Long-Term Derivative Assets	$	202.5	$	6.2	$	-	$	9.7	$	(83.7)	$	134.7
Current Derivative Liabilities:
Level 2:
PSNH	$	-	$	-	$	(18.2)	$	-	$	-	$	(18.2)
Level 3:
NU Enterprises(2)		-		(13.4)		-		-		4.3		(9.1)
CL&P(1)		(37.8)		-		(0.2)		-		4.5		(33.5)
Yankee Gas		-		-		(0.5)		-		-		(0.5)
Total Current Derivative Liabilities	$	(37.8)	$	(13.4)	$	(18.9)	$	-	$	8.8	$	(61.3)
Long-Term Derivative Liabilities:
Level 2:
PSNH	$	-	$	-	$	(3.6)	$	-	$	-	$	(3.6)
Level 3:
NU Enterprises(1)		-		(32.4)		-		-		0.4		(32.0)
CL&P		(960.2)		-		-		-		-		(960.2)
Yankee Gas		-		-		(0.4)		-		-		(0.4)
Total Long-Term Derivative Liabilities	$	(960.2)	$	(32.4)	$	(4.0)	$	-	$	0.4	$	(996.2)

32

	As of December 31, 2009
	Derivatives Not Designated as Hedges
(Millions of Dollars)	Commodity and Capacity Contracts Required by Regulation		Commodity Sales Contract and Related Price and Supply Risk Management		Other Commodity Price and Supply Risk Management		Hedging Instruments-Interest Rate Risk Management		Collateral and Netting		Net Amount Recorded as Derivative Asset/(Liability)
Current Derivative Assets:
Level 2:
NU Parent	$	-	$	-	$	-	$	6.7	$	-	$	6.7
Level 3:
CL&P		20.1		-		4.5		-		-		24.6
PSNH(3)		-		-		0.4		-		-		0.4
Yankee Gas		-		-		0.1		-		-		0.1
Total Current Derivative Assets	$	20.1	$	-	$	5.0	$	6.7	$	-	$	31.8
Long-Term Derivative Assets:
Level 2:
NU Parent	$	-	$	-	$	-	$	6.5	$	-	$	6.5
Level 3:
CL&P(1)		259.0		-		-		-		(75.8)		183.2
Total Long-Term Derivative Assets	$	259.0	$	-	$	-	$	6.5	$	(75.8)	$	189.7
Current Derivative Liabilities:
Level 2:
PSNH	$	-	$	-	$	(18.8)	$	-	$	-	$	(18.8)
Level 3:
NU Enterprises(2)		-		(13.0)		-		-		4.3		(8.7)
CL&P(4)		(10.3)		-		-		-		0.5		(9.8)
Yankee Gas		-		-		(0.4)		-		-		(0.4)
Total Current Derivative Liabilities	$	(10.3)	$	(13.0)	$	(19.2)	$	-	$	4.8	$	(37.7)
Long-Term Derivative Liabilities:
Level 2:
PSNH	$	-	$	-	$	(7.6)	$	-	$	-	$	(7.6)
Level 3:
NU Enterprises (1)		-		(41.1)		-		-		6.7		(34.4)
CL&P		(913.3)		-		-		-		-		(913.3)
Yankee Gas		-		-		(0.3)		-		-		(0.3)
Total Long-Term Derivative Liabilities	$	(913.3)	$	(41.1)	$	(7.9)	$	-	$	6.7	$	(955.6)

⁽¹⁾

Amounts in Collateral and Netting represent derivative contracts that are netted against the fair value of the gross derivative asset/liability.  

⁽²⁾

Collateral and Netting amounts as of September 30, 2010 for NU Enterprises current derivative liabilities represent cash collateral posted that is under master netting agreements.  As of December 31, 2009, Collateral and Netting included derivative assets of $2.2 million that are netted against the fair value of derivative liabilities and cash collateral of $2.1 million posted under master netting agreements.

⁽³⁾

On PSNH's accompanying unaudited condensed consolidated balance sheet, the current portion of the net derivative asset is shown in Prepayments and Other Current Assets.

⁽⁴⁾

Collateral and Netting amounts represent cash posted under master netting agreements.

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

The following provides additional information about the derivatives included in the tables above, including volumes and cash flow information.

Derivatives not designated as hedges

NU Enterprises' commodity sales contract and related price and supply risk management:  As of September 30, 2010 and December 31, 2009, NU Enterprises had approximately 0.4 million MWh of supply volumes remaining in its wholesale portfolio when expected sales to an agency that is comprised of municipalities are compared with contracted supply, both of which extend through 2013.

CL&P commodity and capacity contracts required by regulation:  As of September 30, 2010 and December 31, 2009, CL&P had contracts with two IPPs to purchase electricity monthly in amounts aggregating approximately 1.5 million MWh per year through March 2015 under one of these contracts and 0.1 million MWh per year through December 2020 under the second contract.  CL&P also has two capacity-related CfDs to increase energy supply in Connecticut relating to one generating project that has been modified and one

33

generating plant to be built.  The total capacity of these CfDs and two additional CfDs entered into by UI is expected to be approximately 787 MW.  CL&P has an agreement with UI, which is also accounted for as a derivative, under which they will share the costs and benefits of the four CfDs, with 80 percent allocated to CL&P and 20 percent to UI.  The four CfDs obligate the utilities to pay/receive monthly the difference between a set capacity price and the forward capacity market price that the projects receive in the ISO-NE capacity markets for periods of up to 15 years beginning in 2009.  

Commodity price and supply risk management:  As of September 30, 2010 and December 31, 2009, CL&P had 0.7 million and 2.7 million MWh, respectively, remaining under FTRs that extend through December 2010 and require monthly payments or receipts.  

PSNH has electricity procurement contracts with delivery dates through 2011 to purchase an aggregate amount of 0.6 million and 1 million MWh of power as of September 30, 2010 and December 31, 2009, respectively, that is used to serve customer load and manage price risk of its electricity delivery service obligations.  These contracts are settled monthly.  PSNH also has two energy call options that it received in exchange for assigning its transmission rights in a direct current transmission line.  The options give PSNH the right to purchase 0.1 million and 0.6 million MWh of electricity through December 2010 as of September 30, 2010 and December 31, 2009, respectively.  In addition, PSNH has entered into FTRs to manage the risk of congestion costs associated with its electricity delivery service.  As of September 30, 2010 and December 31, 2009, there were 0.1 million and 0.4 million MWh, respectively, r emaining under FTRs that extend through December 2010 and required monthly payments or receipts.  The purpose of the PSNH derivative contracts is to provide stable rates for customers by mitigating price uncertainties associated with the New England electricity spot market.  

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

		Amount of Gain/(Loss) Recognized on Derivative Instrument
Derivatives Not Designated as Hedges	Location of Gain or Loss Recognized on Derivative	For the Three Months Ended				For the Nine Months Ended
		September 30, 2010		September 30, 2009		September 30, 2010		September 30, 2009
(Millions of Dollars)
NU Enterprises:
Commodity Sales Contract and   Related Price and Supply    Risk Management	Fuel, Purchased and Net   Interchange Power	$	1.2	$	(1.5)	$	1.7	$	6.4
Regulated Companies:
CL&P Energy and Capacity   Contracts Required by   Regulation	Regulatory Assets/Liabilities		(49.8)		(31.8)		(141.6)		18.3
Other Commodity Price and   Supply Risk Management:
CL&P	Regulatory Assets/Liabilities		(0.8)		(0.9)		(4.4)		(7.9)
PSNH	Regulatory Assets/Liabilities		(2.1)		(7.2)		(17.8)		(58.0)
Yankee Gas	Regulatory Assets/Liabilities		-		(0.4)		(0.5)		(2.5)

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

Derivatives designated as hedging instruments  

Interest Rate Risk Management:  To manage the interest rate risk characteristics of NU parent's fixed rate long-term debt, NU parent has a fixed to floating interest rate swap on its $263 million, 7.25 percent fixed rate senior notes maturing on April 1, 2012.  This interest rate swap qualifies and was designated as a fair value hedge and requires semi-annual cash settlements.  The changes in fair value of the swap and the interest component of the hedged long-term debt instrument are recorded in Interest Expense on the accompanying unaudited condensed consolidated statements of income.  There was no ineffectiveness recorded for the three or nine months ended September 30, 2010 and 2009.  The cumulative changes in fair values of the swap and the Long-Term Debt are recorded as a Derivative Asset/Liability and an adjustment to Long-Term Debt.  Interest receivable is recorded as a reduction of Interest E xpense and is included in Prepayments and Other Current Assets.  

34

For the three and nine months ended September 30, 2010 and 2009, the realized and unrealized gains/(losses) related to changes in fair value of the swap and Long-Term Debt as well as pre-tax Interest Expense, recorded in Net Income, were as follows:

	For the Three Months Ended
	September 30, 2010				September 30, 2009
(Millions of Dollars)	Swap		Hedged Debt		Swap		Hedged Debt
Changes in Fair Value	$	2.8	$	(2.8)	$	4.0	$	(4.0)
Interest Recorded in Net Income		-		2.9		-		2.7

	For the Nine Months Ended
	September 30, 2010				September 30, 2009
(Millions of Dollars)	Swap		Hedged Debt		Swap		Hedged Debt
Changes in Fair Value	$	10.2	$	(10.2)	$	0.8	$	(0.8)
Interest Recorded in Net Income		-		8.2		-		6.5

There were no cash flow hedges outstanding as of or during the three or nine months ended September 30, 2010 and 2009 and no ineffectiveness was recorded during these periods.  From time to time, NU, including CL&P, PSNH and WMECO, enters into forward starting interest rate swap agreements on proposed debt issuances that qualify and are designated as cash flow hedges.  Cash flow hedges are recorded at fair value, and the changes in the fair value of the effective portion of those contracts are recognized in Accumulated Other Comprehensive Income.  Cash flow hedges impact Net Income when hedge ineffectiveness is measured and recorded, when the forecasted transaction being hedged is improbable of occurring or when the transaction is settled.  When a cash flow hedge is terminated, the settlement amount is recorded in Accumulated Other Comprehensive Income and is amortized into Net Income over the term of the underlyi ng debt instrument.  

Pre-tax gains/(losses) amortized from Accumulated Other Comprehensive Income into Interest Expense on the accompanying unaudited condensed consolidated statements of income were as follows:

	For the Three Months Ended				For the Nine Months Ended
(Millions of Dollars)	September 30, 2010		September 30, 2009		September 30, 2010		September 30, 2009
CL&P	$	(0.2)	$	(0.2)	$	(0.6)	$	(0.6)
PSNH		-		-		(0.1)		(0.1)
WMECO		-		-		0.1		0.1
Other		0.1		0.1		0.3		0.3
NU	$	(0.1)	$	(0.1)	$	(0.3)	$	(0.3)

For further information, see Note 5, "Comprehensive Income," to the unaudited condensed consolidated financial statements.

Credit Risk

Certain derivative contracts that are accounted for at fair value, including PSNH's electricity procurement contracts and NU Enterprises' electricity sourcing contracts, contain credit risk contingent features.  These features require these companies or, in NU Enterprises' case, NU parent, to maintain investment grade credit ratings from the major rating agencies and to post cash or standby LOCs as collateral for contracts in a net liability position over specified credit limits.  NU parent provides standby LOCs under its revolving credit agreement for NU subsidiaries to post with counterparties.  The following summarizes the fair value of derivative contracts that are in a liability position and subject to credit risk contingent features and the fair value of cash collateral and standby LOCs posted with counterparties as of September 30, 2010 and December 31, 2009:

	As of September 30, 2010
(Millions of Dollars)	Fair Value Subject to Credit Risk Contingent Features		Cash Collateral Posted		Standby LOCs Posted
PSNH	$	(21.8)	$	-	$	29.0
NU Enterprises		(22.0)		4.3		-
NU	$	(43.8)	$	4.3	$	29.0

	As of December 31, 2009
(Millions of Dollars)	Fair Value Subject to Credit Risk Contingent Features		Cash Collateral Posted		Standby LOCs Posted
PSNH	$	(26.4)	$	-	$	25.0
NU Enterprises		(20.0)		2.1		-
NU	$	(46.4)	$	2.1	$	25.0

Additional collateral is required to be posted by NU Enterprises or PSNH, if the respective unsecured debt credit ratings of NU parent or PSNH are downgraded below investment grade.  As of September 30, 2010, no additional cash collateral would have been required to be posted if credit ratings had been downgraded below investment grade.  However, if the senior unsecured debt of NU parent had been downgraded to below investment grade, additional standby LOCs in the amount of $17.3 million would have been required to be posted on derivative contracts for Select Energy.  As of December 31, 2009, no additional cash collateral would have been required to be posted if credit ratings had been downgraded below investment grade.  However, if the senior unsecured debt of PSNH or NU

35

parent had been downgraded to below investment grade, additional standby LOCs in the amount of $1.8 million and $17.8 million would have been required to be posted on derivative contracts for PSNH and Select Energy, respectively.

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

Fair Value Measurements of Derivative Instruments:  

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

The derivative contracts classified as Level 3 in the tables below include NU Enterprises' Sales Contract and Related Price and Supply Risk Management contracts, the Regulated companies' Commodity and Capacity Contracts Required by Regulation (which include CL&P's CfDs and contracts with certain IPPs), and Other Commodity Price and Supply Risk Management contracts (PSNH and Yankee Gas physical options, and CL&P and PSNH FTRs.)  For Commodity and Capacity Contracts Required by Regulation and NU Enterprises' Commodity Sales contract, fair value is modeled using income techniques such as discounted cash flow approaches adjusted for assumptions relating to exit price.  Significant observable inputs for valuations of these contracts include energy and energy-related product prices for which quoted prices in an active market exist.  Significant unobservable inputs used in the valuations of these contracts include energy and energy-related product prices for future years for long-dated derivative contracts and future contract quantities under requirements and supplemental sales contracts.  Discounted cash flow valuations incorporate estimates of premiums or discounts that would be required by a market participant to arrive at an exit price, using available historical market transaction information.  Valuations of derivative contracts include assumptions regarding the timing and likelihood of scheduled payments and also reflect nonperformance risk, including credit, using the default probability approach based on the counterparty's credit rating for assets and the company's credit rating for liabilities.  

Other Commodity Price and Supply Risk Management contracts classified as Level 3 in the tables below are valued using income approaches including a Black-Scholes option pricing model.  Observable inputs used in valuing options include prices for energy and energy-related products for years for which quoted prices in an active market exist.  Unobservable inputs included in the valuation of options contracts include market volatilities related to future energy prices and the estimated likelihood that the option will be exercised.  FTRs are valued using broker quotes based on prices in an inactive market.

Valuations using significant unobservable inputs: The following tables present changes for the three and nine months ended September 30, 2010 and 2009 in the Level 3 category of derivative assets and derivative liabilities measured at fair value on a recurring basis.  The derivative assets and liabilities are presented on a net basis.  The Company classifies assets and liabilities in Level 3 of the fair value hierarchy when there is reliance on at least one significant unobservable input to the valuation model.  In addition to these unobservable inputs, the valuation models for Level 3 assets and liabilities typically also rely on a number of inputs that are observable either directly or indirectly.  Thus the gains and losses presented below include changes in fair value that are attributable to both observable and unobservable inputs.  There were no transfers into or out of Level 3 assets and liabili ties for the three or nine months ended September 30, 2010 or 2009:

	For the Three Months Ended September 30, 2010
	NU
(Millions of Dollars)	Commodity and Capacity Contracts Required By Regulation		Commodity Sales Contract and Related Price and Supply Risk Management		Other Commodity Price and Supply Risk Management		Total Level 3
Derivatives, Net:
Fair Value as of Beginning of Period	$	(818.3)	$	(39.5)	$	1.0	$	(856.8)
Net Realized/Unrealized Gains/(Losses) Included in:
Net Income(1)		-		1.2		-		1.2
Regulatory Assets/Liabilities		(49.8)		-		(0.9)		(50.7)
Purchases, Issuances and Settlements		(5.7)		2.4		(0.2)		(3.5)
Fair Value as of End of Period	$	(873.8)	$	(35.9)	$	(0.1)	$	(909.8)
Period Change in Unrealized Gains Included in  Net Income Relating to Items Held as of End of Period	$	-	$	1.0	$	-	$	1.0

36

	For the Three Months Ended September 30, 2010
	CL&P						PSNH
(Millions of Dollars)	Commodity and Capacity Contracts Required By Regulation		Other Commodity Price and Supply Risk Management		Total Level 3		Other Commodity Price and Supply Risk Management
Derivatives, Net:
Fair Value as of Beginning of Period	$	(818.3)	$	1.8	$	(816.5)	$	-
Net Realized/Unrealized Losses Included in:
Regulatory Assets/Liabilities		(49.8)		(0.8)		(50.6)		-
Purchases, Issuances and Settlements		(5.7)		(0.2)		(5.9)		-
Fair Value as of End of Period	$	(873.8)	$	0.8	$	(873.0)	$	-

	For the Nine Months Ended September 30, 2010
	NU
(Millions of Dollars)	Commodity and Capacity Contracts Required By Regulation		Commodity Sales Contract and Related Price and Supply Risk Management		Other Commodity Price and Supply Risk Management		Total Level 3
Derivatives, Net:
Fair Value as of Beginning of Period	$	(720.3)	$	(45.2)	$	4.3	$	(761.2)
Net Realized/Unrealized Gains/(Losses) Included in:
Net Income(1)		-		1.7		-		1.7
Regulatory Assets/Liabilities		(141.6)		-		(5.1)		(146.7)
Purchases, Issuances and Settlements		(11.9)		7.6		0.7		(3.6)
Fair Value as of End of Period	$	(873.8)	$	(35.9)	$	(0.1)	$	(909.8)
Period Change in Unrealized Gains Included in  Net Income Relating to Items Held as of End of Period	$	-	$	0.9	$	-	$	0.9

	For the Nine Months Ended September 30, 2010
	CL&P						PSNH
(Millions of Dollars)	Commodity and Capacity Contracts Required By Regulation		Other Commodity Price and Supply Risk Management		Total Level 3		Other Commodity Price and Supply Risk Management
Derivatives, Net:
Fair Value as of Beginning of Period	$	(720.3)	$	4.5	$	(715.8)	$	0.4
Net Realized/Unrealized Losses Included in:
Regulatory Assets/Liabilities		(141.6)		(4.4)		(146.0)		(0.2)
Purchases, Issuances and Settlements		(11.9)		0.7		(11.2)		(0.2)
Fair Value as of End of Period	$	(873.8)	$	0.8	$	(873.0)	$	-

	For the Three Months Ended September 30, 2009						For the Nine Months Ended September 30, 2009
(Millions of Dollars)	NU		CL&P		PSNH		NU		CL&P		PSNH
Derivatives, Net:
Fair Value as of Beginning of Period	$	(614.0)	$	(570.5)	$	1.3	$	(669.2)	$	(611.1)	$	4.1
Net Realized/Unrealized   Gains/(Losses) Included in:
Net Income(1)		(1.5)		-		-		6.4		-		-
Regulatory Assets/Liabilities		(33.4)		(32.7)		(0.3)		4.9		10.4		(3.0)
Purchases, Issuances and   Settlements		4.6		3.8		-		13.6		1.3		(0.1)
Fair Value as of End of Period	$	(644.3)	$	(599.4)	$	1.0	$	(644.3)	$	(599.4)	$	1.0
Period Change in Unrealized    Gains/(Losses) Included in Net      Income Relating to Items Held    as of End of Period	$	(1.4)	$	-	$	-	$	6.1	$	-	$	-

⁽¹⁾

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

37

3.

PENSION BENEFITS AND POSTRETIREMENT BENEFITS OTHER THAN PENSIONS

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

The components of net periodic expense/(income) for the Pension Plan, PBOP Plan and SERP for the three and nine months ended September 30, 2010 and 2009 are as follows:

	For the Three Months Ended September 30,
(Millions of Dollars)	Pension Benefits				PBOP Benefits				SERP Benefits
NU	2010		2009		2010		2009		2010		2009
Service Cost	$	12.6	$	11.3	$	2.1	$	1.8	$	0.2	$	0.2
Interest Cost		37.6		38.3		6.7		7.3		0.6		0.6
Expected Return on Plan Assets		(45.7)		(47.3)		(5.4)		(5.3)		-		-
Net Transition Obligation Cost		-		0.1		4.2		2.8		-		-
Prior Service Cost/(Credit)		2.4		2.4		(0.1)		-		-		-
Actuarial Loss		13.2		5.1		2.9		2.6		0.2		0.1
Total - Net Periodic Expense	$	20.1	$	9.9	$	10.4	$	9.2	$	1.0	$	0.9
CL&P - Net Periodic Expense/(Income)	$	2.1	$	(1.5)	$	4.2	$	3.8	$	0.1	$	-
PSNH - Net Periodic Expense	$	7.0	$	5.8	$	1.9	$	1.7	$	0.1	$	0.1
WMECO - Net Periodic Expense/(Income)	$	*	$	(0.7)	$	0.8	$	0.6	$	*	$	*

	For the Nine Months Ended September 30,
(Millions of Dollars)	Pension Benefits				PBOP Benefits				SERP Benefits
NU	2010		2009		2010		2009		2010		2009
Service Cost	$	37.7	$	33.8	$	6.3	$	5.4	$	0.5	$	0.6
Interest Cost		112.8		115.1		20.1		21.8		1.7		1.7
Expected Return on Plan Assets		(137.0)		(142.0)		(16.2)		(15.7)		-		-
Net Transition Obligation Cost		-		0.2		12.5		8.5		-		-
Prior Service Cost/(Credit)		7.3		7.3		(0.2)		-		-		0.1
Actuarial Loss		39.5		15.4		8.7		7.9		0.8		0.3
Total - Net Periodic Expense	$	60.3	$	29.8	$	31.2	$	27.9	$	3.0	$	2.7
CL&P - Net Periodic Expense/(Income)	$	6.4	$	(4.3)	$	12.7	$	11.6	$	0.3	$	0.2
PSNH - Net Periodic Expense	$	21.0	$	17.4	$	5.8	$	5.2	$	0.2	$	0.2
WMECO - Net Periodic Expense/(Income)	$	(0.1)	$	(2.2)	$	2.3	$	2.0	$	*	$	*

*A de minimis amount of net periodic expense was recorded for WMECO.

Not included in the Pension Plan, PBOP Plan and SERP amounts above for CL&P, PSNH and WMECO are related intercompany allocations as follows:

	For the Three Months Ended September 30,
	CL&P				PSNH				WMECO
(Millions of Dollars)	2010		2009		2010		2009		2010		2009
Pension Benefits	$	5.8	$	3.6	$	1.3	$	0.7	$	1.0	$	0.6
PBOP Benefits		2.0		1.8		0.5		0.4		0.3		0.3
SERP Benefits		0.5		0.5		0.1		0.1		0.1		0.1

	For the Nine Months Ended September 30,
	CL&P				PSNH				WMECO
(Millions of Dollars)	2010		2009		2010		2009		2010		2009
Pension Benefits	$	17.4	$	11.0	$	4.0	$	2.4	$	3.1	$	1.8
PBOP Benefits		6.0		5.5		1.5		1.3		1.0		0.9
SERP Benefits		1.5		1.4		0.4		0.3		0.3		0.2

38

A portion of the pension amounts is capitalized related to employees who are working on capital projects.  Amounts capitalized, including intercompany allocations, for NU, CL&P, PSNH and WMECO were as follows:  

	For the Three Months Ended September 30,				For the Nine Months Ended September 30,
(Millions of Dollars)	2010		2009		2010		2009
NU	$	4.4	$	1.5	$	13.2	$	4.6
CL&P		1.7		(0.1)		5.2		(0.2)
PSNH		2.0		1.4		6.1		4.3
WMECO		0.2		(0.2)		0.5		(0.5)

The amounts for the three and nine months ended September 30, 2009 for CL&P and WMECO offset capital costs, as pension income was recorded related to these capital projects. 

Contributions:Currently NU's policy is to annually fund the Pension Plan with an amount at least equal to what will satisfy the requirements of ERISA and the Internal Revenue Code.  NU's Pension Plan has historically been well funded, and a contribution has not been required to be made since 1991.  Due to the unfunded balance as of January 1, 2009, PSNH made a contribution to the plan of $45 million in the third quarter of 2010.  

4.

COMMITMENTS AND CONTINGENCIES

A.

Environmental Matters

NU, CL&P, PSNH and WMECO are subject to environmental laws and regulations intended to mitigate or remove the effect of past operations and improve or maintain the quality of the environment.  These laws and regulations require the removal or the remedy of the effect on the environment of the disposal or release of certain specified hazardous substances at current and former operating sites.  MGPs were operated several decades ago; the process of producing manufactured gas from coal resulted in certain byproducts in the environment that may pose a risk to human health and the environment.  MGP sites comprise the largest portion of the Company's environmental liabilities.

As of September 30, 2010, there were 31 environmental sites in the remediation or long-term monitoring phase (5 for CL&P, 11 for PSNH and 8 for WMECO).  As of September 30, 2010 and December 31, 2009, the environmental reserve for the sites in the remediation or long-term monitoring phase was $31.1 million and $18.4 million ($0.7 million and $0.5 million for CL&P, $10.2 million and $5.0 million for PSNH and $0.2 million and $0.2 million for WMECO), respectively, which represent management's best estimates of the liabilities for environmental costs.  These amounts are the best estimates within estimated ranges of losses from zero to $8.7 million ($0.2 million to $1 million for PSNH and zero to $8.7 million for WMECO).    

CERCLA Matters:  CERCLA and its amendments or state equivalents impose joint and several strict liabilities, regardless of fault, upon generators of hazardous substances resulting in removal and remediation costs and environmental damages.  Liabilities under these laws can be material and in some instances may be imposed without regard to fault or for past acts that may have been lawful at the time they occurred.  Of the total sites included in the remediation and long-term monitoring phase, 3 sites (2 for PSNH and one involving both CL&P and WMECO) are superfund sites under CERCLA for which the Company has been notified that it is a potentially responsible party but for which the site assessment and remediation are not being managed by the Company.  As of September 30, 2010, a liability of $0.6 million ($0.3 million for CL&P, $0.3 million for PSNH, and a de minimis amount for WMECO) accrued on these si tes represents management's best estimate of its potential remediation costs with respect to these superfund sites.

Environmental Matter Impacting Net Income:  

HWP is a subsidiary of NU that continues to investigate the extent of impacts and the potential need for additional remediation at a river site in Massachusetts containing tar deposits associated with a MGP site.  The MGP was sold to HG&E in 1902.  HWP shares responsibility for site remediation with HG&E and has already conducted substantial investigative and remediation activities.  As of September 30, 2010, the reserve for this environmental matter was $3.2 million and the cumulative charges to the reserve since it was first established were approximately $19.5 million.  HWP's share of the costs related to this site is not recoverable from customers.

In 2008, the MA DEP issued a letter to HWP and HG&E providing conditional authorization for additional investigatory and risk characterization activities and providing comments on HWP's previous reports and proposals for further investigations.  In that letter, the MA DEP also indicated that further removal of tar in certain areas was necessary.  This letter represented guidance rather than a mandate from the MA DEP.  HWP implemented several supplemental characterization studies to further delineate and assess tar deposits in conformity with the MA DEP's guidance letter.  

In April 2010, HWP delivered a report to the MA DEP describing the results of its site investigation studies and testing.  Subsequent discussions with the MA DEP focused on the course of action to achieve a resolution for the tar deposits.  From this meeting, MA DEP sent a letter of approval on HWP's proposed timeline for additional assessment activities.  These matters are subject to ongoing discussions with the MA DEP and are subject to change in the future.

For the three and nine months ended September 30, 2010, pre-tax charges of $1.6 million and $2.6 million, respectively, were recorded to reflect estimated costs associated with the site.  Based upon discussions with and the letter received from the MA DEP, a pre-tax charge of $1.6 million was recorded in the third quarter of 2010 to reflect estimated remaining costs associated with the site, primarily to

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complete additional studies.  For the three and nine months ended September 30, 2009, pre-tax charges associated with this site were zero and $1.1 million, respectively.  

The $3.2 million reserve balance as of September 30, 2010 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.  Management believes that the $3.2 million remaining in the reserve is at the low end of a range of probable costs for HWP to resolve this matter.

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, among other things, on the nature, extent and timing of additional investigation and remediation that may be required by the MA DEP.    

B.

Deferred Contractual Obligations

Spent Nuclear Fuel Litigation:In 1998, CYAPC, YAEC and MYAPC 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.  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 2007, the Yankee Companies each filed subsequent lawsuits against the DOE seeking recovery of actual damages incurred in the years following 2001/2002.

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.  Parties have 30 days to file motions for reconsideration and 60 days to file any appeals (a filing stops the clock on appeal periods).  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.  If no motions for reconsideration are filed, the deadline for filing appeals of the decision would be November 8, 2010.  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.

C.

Guarantees and Indemnifications

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

NU has also provided guarantees and various indemnifications on behalf of external parties as a result of the sale of SESI, formerly a subsidiary of NU Enterprises, with an aggregate fair value amount recorded of $0.3 million.  Other indemnifications in connection with the sale of SESI include specific indemnifications for estimated costs to complete or modify specific projects, indemnifications to lenders for payment of shortfalls in the event of early termination of government contracts, and surety bonds covering certain projects.  The maximum exposure on these items is either not specified or not material, and no amounts are recorded as liabilities.  NU parent also provided guarantees and various indemnifications on behalf of external parties as a result of the sales of NU Enterprises' former retail marketing business and competitive generation business.  These included indemnifications for compliance with t ax and environmental laws, and various claims for which the maximum exposure was not specified in the sale agreements.

Management does not anticipate a material impact to net income to result from these various guarantees and indemnifications.  The following table summarizes the NU, including CL&P, PSNH, and WMECO, maximum exposure as of September 30, 2010, in accordance with guidance on guarantor's accounting and disclosure requirements for guarantees and expiration dates:  

Subsidiary	Description	Maximum Exposure (in millions)		Expiration Dates
Various	Surety Bonds	$ 11.5		November 2010 - September  2011 (1)
PSNH and Select Energy	Letters Of Credit	$ 39.6		November 2010 - October 2011
RRR and NUSCO	Lease Payments for Real Estate and Vehicles	$ 22.8		2019-2024
NU Enterprises	Surety Bonds, Insurance Bonds and Performance Guarantees	$ 117.1	(2)	(2)

(1)

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

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(2)

The maximum exposure includes $68.7 million related to performance guarantees on Select Energy's wholesale purchase contracts, which expire in 2013, assuming purchase contracts guaranteed have no value; however, actual exposures vary with underlying commodity prices.  The maximum exposure also includes $17.5 million related to a performance guarantee of NGS obligations for which no maximum exposure is specified in the agreement.  The maximum exposure was calculated as of September 30, 2010 based on limits of NGS's liability contained in the underlying service contract and assumes that NGS will perform under that contract through its expiration in 2020.  Also included in the maximum exposure is $1.1 million related to insurance bonds at NGS with no expiration date that are billed annually on their anniversary date.  The remaining $29.8 million of maximum exposure relates to surety b onds covering ongoing projects at Boulos, which expire upon project completion.

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

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

5.

COMPREHENSIVE INCOME

Total comprehensive income for the three and nine months ended September 30, 2010 and 2009 is as follows:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2010		2009		2010		2009
(Millions of Dollars)	NU		NU		NU		NU
Net Income	$	101.9	$	66.2	$	262.9	$	249.5
Other Comprehensive Income/(Loss) Items, Net of Tax:
Qualified Cash Flow Hedging Instruments(1)		0.1		0.1		0.1		0.1
Changes in Unrealized Gains/(Losses) on Other Securities(2)		0.1		0.3		0.8		(0.7)
Change In Pension, SERP and PBOP Benefit Plans		0.6		0.8		1.6		0.1
Other Comprehensive Income/(Loss) Items		0.8		1.2		2.5		(0.5)
Total Comprehensive Income		102.7		67.4		265.4		249.0
Comprehensive Income Attributable to Noncontrolling Interests		(1.4)		(1.4)		(4.2)		(4.2)
Comprehensive Income Attributable to Controlling Interests	$	101.3	$	66.0	$	261.2	$	244.8

	Three Months Ended September 30, 2010						Three Months Ended September 30, 2009
(Millions of Dollars)	CL&P		PSNH		WMECO		CL&P		PSNH		WMECO
Net Income	$	69.0	$	28.8	$	7.3	$	46.5	$	16.2	$	8.5
Other Comprehensive Income Items, Net of Tax:
Qualified Cash Flow Hedging Instruments(1)		0.1		-		-		0.1		-		-
Other Comprehensive Income Items		0.1		-		-		0.1		-		-
Total Comprehensive Income	$	69.1	$	28.8	$	7.3	$	46.6	$	16.2	$	8.5

	Nine Months Ended September 30, 2010						Nine Months Ended September 30, 2009
(Millions of Dollars)	CL&P		PSNH		WMECO		CL&P		PSNH		WMECO
Net Income	$	161.5	$	66.2	$	18.2	$	158.1	$	50.3	$	20.5
Other Comprehensive Income/(Loss) Items, Net of Tax:
Qualified Cash Flow Hedging Instruments(1)		0.4		0.1		(0.1)		0.3		0.1		(0.1)
Change in Unrealized Losses on Other Securities(2)		-		-		-		-		(0.1)		(0.1)
Other Comprehensive Income/(Loss) Items		0.4		0.1		(0.1)		0.3		-		(0.2)
Total Comprehensive Income	$	161.9	$	66.3	$	18.1	$	158.4	$	50.3	$	20.3

⁽¹⁾

Hedged transactions impacting Net Income in the tables above represent amounts that were reclassified from Accumulated Other Comprehensive Income/(Loss) into Net Income in connection with the settlement of interest rate swap agreements and the amortization of the effects of interest rate hedges.  As of September 30, 2010, the balance included in Accumulated Other Comprehensive Income/(Loss) related to hedging activities was $4.3 million, $2.8 million, $0.6 million, and $0.1 million for NU, CL&P, PSNH and WMECO, respectively.  These amounts were $4.4 million, $3.2 million, $0.7 million and a de minimis amount as of December 31, 2009 for NU, CL&P, PSNH and WMECO, respectively.

⁽²⁾

Represents changes in unrealized gains/(losses) on securities held in the NU supplemental benefit trust.  For further information, see Note 10, "Marketable Securities," to the unaudited condensed consolidated financial statements.  

There were no forward starting interest rate swaps entered into for the three and nine months ended September 30, 2010 or September 30, 2009.  For NU, it is estimated that a charge of $0.2 million will be reclassified from Accumulated Other Comprehensive Income/(Loss) as a decrease to Net Income over the next 12 months as a result of amortization of interest rate swap agreements, which have been settled.  Included in this amount are estimated charges of $0.4 million and $0.1 million for CL&P and PSNH, respectively, and a benefit of $0.1 million for WMECO.  As of September 30, 2010, it is estimated that a pre-tax amount of $0.7 million included in the Accumulated Other Comprehensive Income/(Loss) balance will be reclassified as a decrease to Net Income over the next 12 months related to Pension Plan, SERP and PBOP Plan benefits adjustments for NU.

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6.

EARNINGS PER SHARE (NU)

EPS is computed based upon the monthly weighted average number of common shares outstanding, excluding unallocated ESOP shares, during each period.  Diluted EPS is computed on the basis of the monthly weighted average number of common shares outstanding plus the potential dilutive effect if certain securities are converted into common shares.  The computation of diluted EPS excludes the effect of the potential exercise of share awards when the average market price of the common shares is lower than the exercise price of the related awards during the period.  These outstanding share awards are not included in the computation of diluted EPS because the effect would have been antidilutive.  For the nine month periods ended September 30, 2010 and 2009, there were 2,104 and 18,012 share awards excluded from the computation, respectively, as these awards were antidilutive.  There were no antidilutive share awards outst anding for the three month periods ended September 30, 2010 and 2009.  

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

(Millions of Dollars, except for	For the Three Months Ended September 30,				For the Nine Months Ended September 30,
share information)	2010		2009		2010		2009
Net Income Attributable to Controlling Interests	$	100.5	$	64.8	$	258.7	$	245.3
Basic Weighted Average Common
Shares Outstanding		176,752,714		175,358,776		176,557,889		170,958,396
Dilutive Effect		259,564		636,730		204,199		574,517
Fully Diluted Weighted Average
Common Shares Outstanding		177,012,278		175,995,506		176,762,088		171,532,913
Basic EPS	$	0.57	$	0.37	$	1.47	$	1.43
Fully Diluted EPS	$	0.57	$	0.37	$	1.46	$	1.43

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

The dilutive effect of stock options is also calculated using the treasury stock method.  Assumed proceeds for stock options consist of remaining compensation cost to be recognized, cash proceeds that would be received upon exercise, and a theoretical tax benefit.  The theoretical tax benefit is calculated as the tax impact of the intrinsic value of the stock options (the difference between the market value of the average stock options outstanding for the period, using the average market price during the period, and the grant price).  

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

7.

SHORT-TERM DEBT

CL&P, PSNH, WMECO and Yankee Gas Credit Agreement:  On September 24, 2010, CL&P, PSNH, WMECO and Yankee Gas jointly entered into a three-year unsecured revolving credit facility in the amount of $400 million, which expires on September 24, 2013.  This facility replaced a five-year $400 million credit facility that was scheduled to expire on November 6, 2010.  CL&P and PSNH may draw up to $300 million each under this facility, with WMECO and Yankee Gas able to draw up to $200 million each, subject to the $400 million maximum aggregate borrowing limit.  This total commitment may be increased to $500 million at the request of the borrowers, subject to lender approval.  Under this facility, each company can borrow either on a short-term or a long-term basis subject to regulatory approval.  There were no borrowings outstanding under this facility as of September 30, 2010.  

NU Parent Credit Agreement:  On September 24, 2010, NU parent entered into a three-year unsecured revolving credit facility in the amount of $500 million, which expires on September 24, 2013.  This facility replaced a five-year $500 million credit facility that was scheduled to expire on November 6, 2010.  Subject to the amount of advances outstanding, LOCs can be issued for periods up to 364 days in the name of NU parent or any of its subsidiaries up to the total amount of the facility.  This total commitment may be increased to $600 million at the request of NU parent, subject to lender approval.

Under this facility, NU parent can borrow either on a short-term or a long-term basis.  As of September 30, 2010, NU parent had $156 million in short-term borrowings outstanding under this facility.  The weighted-average interest rate on such borrowings outstanding under this credit facility as of September 30, 2010 was 2.16 percent.  There were $39.6 million ($37.6 million for PSNH) in LOCs outstanding as of September 30, 2010.  

Under these credit facilities, NU parent and CL&P, PSNH, WMECO and Yankee Gas may borrow at prime rates or variable rates, plus an applicable margin based upon the higher of S&P's or Moody's credit ratings assigned to the borrower.   

In addition, NU parent and CL&P, PSNH, WMECO and Yankee Gas must comply with certain financial and non-financial covenants, including a consolidated debt to total capitalization ratio.  NU parent and CL&P, PSNH, WMECO and Yankee Gas were in compliance with these covenants as of September 30, 2010.  If NU parent or CL&P, PSNH, WMECO or Yankee Gas were not in compliance with these covenants, an event of default would occur requiring all outstanding borrowings by such borrower to be repaid and additional borrowings by such borrower would not be permitted under the respective credit facility.  

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8.

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

On March 8, 2010, WMECO issued $95 million of Series E senior unsecured notes with a coupon rate of 5.1 percent and a maturity date of March 1, 2020.  The proceeds of these notes were used to repay short-term borrowings incurred in the ordinary course of business and to fund WMECO's ongoing capital investment programs.  The indenture under which the notes were issued requires WMECO to comply with certain covenants as are customarily included in such indentures.  

On April 1, 2010, CL&P remarketed $62 millionof PCRBs.  The PCRBs, which mature on May 1, 2031, carry a coupon rate of 1.4 percent during the current one-year fixed-rate period and are subject to a mandatory tender for purchase on April 1, 2011, after which CL&P can remarket the bonds.  

On April 22, 2010, Yankee Gas issued $50 million of Series K first mortgage bonds with a coupon rate of 4.87 percent and a maturity date of April 1, 2020.  The proceeds of these bonds were used to repay short-term borrowings incurred in the ordinary course of business and to fund ongoing capital investment programs. The indenture under which the bonds were issued requires Yankee Gas to comply with certain covenants as are customarily included in such indentures.  

NU, including CL&P, PSNH and WMECO, was in compliance with all its debt covenants as of September 30, 2010.  

9.

FAIR VALUE OF FINANCIAL INSTRUMENTS

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

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

	As of September 30, 2010				As of December 31, 2009
	NU				NU
(Millions of Dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Preferred Stock Not Subject   to Mandatory Redemption	$	116.2	$	96.0	$	116.2	$	86.8
Long-Term Debt -
First Mortgage Bonds		2,703.4		3,102.0		2,657.7		2,713.5
Other Long-Term Debt		1,988.9		2,067.5		1,893.6		1,938.0
Rate Reduction Bonds		246.7		271.5		442.4		487.3

		As of September 30, 2010
		CL&P				PSNH					WMECO
(Millions of Dollars)		Carrying Amount		Fair Value		Carrying Amount			Fair Value		Carrying Amount		Fair Value
Preferred Stock Not Subject   to Mandatory Redemption	$		116.2	$	96.0		$	-	$	-	$	-	$	-
Long-Term Debt -
First Mortgage Bonds			1,919.8		2,222.3			430.0		479.0		-		-
Other Long-Term Debt			667.7		672.1			407.3		415.5		401.0		426.3
Rate Reduction Bonds			48.1		57.3			151.5		163.2		47.2		51.0

		As of December 31, 2009
		CL&P				PSNH					WMECO
(Millions of Dollars)		Carrying Amount		Fair Value		Carrying Amount			Fair Value		Carrying Amount		Fair Value
Preferred Stock Not Subject  to Mandatory Redemption	$		116.2	$	86.8		$	-	$	-	$	-	$	-
Long-Term Debt -
First Mortgage Bonds			1,919.8		1,960.6			430.0		425.4		-		-
Other Long-Term Debt			667.4		673.4			407.3		408.6		305.9		304.9
Rate Reduction Bonds			195.6		220.1			188.1		203.5		58.7		63.7

The NU Other Long-term Debt includes $300.9 million and $300.6 million of fees and interest due for spent nuclear fuel disposal costs as of September 30, 2010 and December 31, 2009, respectively.  CL&P's portion of this obligation is $243.7 million and $243.5 million, and WMECO's portion of this obligation is $57.2 million and $57.1 million as of September 30, 2010 and December 31, 2009, respectively.  

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Derivative Instruments:  NU, including CL&P and PSNH, holds various derivative instruments that are carried at fair value.  For further information, see Note 2, "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 1C, "Summary of Significant Accounting Policies - Fair Value Measurements," and Note 10, "Marketable Securities," to the unaudited condensed consolidated financial statements.

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

10.

MARKETABLE SECURITIES (NU, WMECO)

The Company elected to record exchange traded funds and mutual funds purchased during 2009 in the NU supplemental benefit trust at fair value in order to reflect the economic effect of changes in fair value of all newly purchased equity securities in Net Income.  These equity securities, classified as Level 1 in the fair value hierarchy, totaled $38.5 million and $35.3 million as of September 30, 2010 and December 31, 2009, respectively and are included in current Marketable Securities.  Gains on these securities of $5.7 million and $3.2 million for the three and nine months ended September 30, 2010 and gains of $4.7 million and $5.2 million for the three and nine months ended September 30, 2009, were recorded in Other Income, Net on the accompanying unaudited condensed consolidated statements of income.  Dividend income is recorded when dividends are declared and are recorded in Other Income, Net on the accompanying unaudited condensed consolidated statements of income.  All other marketable securities are accounted for as available-for-sale.  

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

	As of September 30, 2010
(Millions of Dollars)	Amortized Cost		Pre-Tax Unrealized Gains(1)		Pre-Tax Unrealized Losses(1)		Fair Value
NU supplemental benefit trust
U.S. Government Issued Debt Securities   (Agency and Treasury)	$	11.3	$	0.3	$	-	$	11.6
Corporate Debt Securities		6.0		0.6		-		6.6
Asset Backed Debt Securities		5.9		0.4		-		6.3
Municipal Bonds		0.5		-		-		0.5
Money Market Funds and Other		4.9		0.3		-		5.2
Total NU Supplemental Benefit Trust	$	28.6	$	1.6	$	-	$	30.2

WMECO spent nuclear fuel trust
U.S. Government Issued Debt Securities   (Agency and Treasury)	$	6.1	$	-	$	-	$	6.1
Corporate Debt Securities		15.9		-		(0.1)		15.8
Asset Backed Debt Securities		5.0		-		(0.1)		4.9
Municipal Bonds		9.4		-		-		9.4
Money Market Funds and Other		20.8		-		-		20.8
Total WMECO Spent Nuclear Fuel Trust	$	57.2	$	-	$	(0.2)	$	57.0
Total NU	$	85.8	$	1.6	$	(0.2)	$	87.2

	As of December 31, 2009
(Millions of Dollars)	Amortized Cost		Pre-Tax Unrealized Gains(1)		Pre-Tax Unrealized Losses(1)		Fair Value
NU supplemental benefit trust
U.S. Government Issued Debt Securities   (Agency and Treasury)	$	12.8	$	0.3	$	(0.2)	$	12.9
Corporate Debt Securities		7.4		0.4		(0.1)		7.7
Asset Backed Debt Securities		5.2		0.1		(0.1)		5.2
Municipal Bonds		0.2		-		-		0.2
Money Market Funds and Other		3.0		-		-		3.0
Total NU Supplemental Benefit Trust	$	28.6	$	0.8	$	(0.4)	$	29.0

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	As of December 31, 2009
(Millions of Dollars)	Amortized Cost		Pre-Tax Unrealized Gains(1)		Pre-Tax Unrealized Losses(1)		Fair Value
WMECO spent nuclear fuel trust
U.S. Government Issued Debt Securities   (Agency and Treasury)	$	17.0	$	-	$	-	$	17.0
Corporate Debt Securities		17.4		0.1		(0.1)		17.4
Asset Backed Debt Securities		1.1		-		(0.2)		0.9
Municipal Bonds		10.6		-		-		10.6
Money Market Funds and Other		10.9		-		-		10.9
Total WMECO Spent Nuclear Fuel Trust	$	57.0	$	0.1	$	(0.3)	$	56.8
Total NU	$	85.6	$	0.9	$	(0.7)	$	85.8

⁽¹⁾

Unrealized gains and losses on debt securities for the NU supplemental benefit trust and WMECO spent nuclear fuel trust are recorded in Accumulated Other Comprehensive Income/(Loss) and Other Long-Term Assets, respectively, on the accompanying unaudited condensed consolidated balance sheets.  For information related to the change in unrealized gains and losses for the NU supplemental benefit trust included in Accumulated Other Comprehensive Income/(Loss), see Note 5, "Comprehensive Income," to the unaudited condensed consolidated financial statements.

Unrealized Losses and Other-than-Temporary Impairment:  As of September 30, 2010, unrealized losses of $0.2 million held in the WMECO spent nuclear fuel trust relate to securities in a continuous unrealized loss position for greater than 12 months.  As of December 31, 2009, there were unrealized losses of $0.1 million in the NU supplemental benefit trust that relate to securities in an unrealized loss position for less than 12 months.  There were $0.3 million in both the NU supplemental benefit trust and WMECO spent nuclear fuel trust that relate to securities that have been in an unrealized loss position for greater than 12 months.  The fair values of the securities in an unrealized loss position are not significant to the fair value of the NU supplemental benefit trust or the WMECO spent nuclear fuel trust for the periods ended September 30, 2010 or December 31, 2009.  

As of September 30, 2010 and December 31, 2009, there were no debt securities that the Company intends to sell or that management believes the Company will more likely than not be required to sell before recovery of amortized cost.  There were no credit losses for the NU Supplemental Benefit Trust or WMECO spent nuclear fuel trust for the nine months ended September 30, 2010.  Inception to date credit losses were de minimis for the NU supplemental benefit trust and $0.7 million for the WMECO spent nuclear fuel trust, which were recorded in Other Long-Term Assets.  Factors considered in determining whether a credit loss exists include the duration and severity of the impairment, adverse conditions specifically affecting the issuer, and the payment history, ratings and rating changes of the security.  For asset backed securities, underlying collateral and expected future cash flows are also evaluated.  All of the c orporate and asset-backed securities held in the NU supplemental benefit trust are rated investment grade.  All but two of the securities in the WMECO spent nuclear fuel trust are rated investment grade and credit losses have been recorded for those securities that are below investment grade.  

For information related to the change in unrealized gains included in Accumulated Other Comprehensive Income/(Loss), see Note 5, "Comprehensive Income," to the unaudited condensed consolidated financial statements.

Contractual Maturities:  As of September 30, 2010, the contractual maturities of available-for-sale debt securities are as follows:

		NU			WMECO
(Millions of Dollars)		Amortized Cost		Fair Value		Amortized Cost		Fair Value
Less than one year	$	41.5	$	41.5	$	38.5	$	38.4
One to five years		17.8		18.0		10.3		10.3
Six to ten years		4.8		5.3		-		-
Greater than ten years		21.7		22.4		8.4		8.3
Total Debt Securities	$	85.8	$	87.2	$	57.2	$	57.0

Sales of Securities:  For the three and nine months ended September 30, 2010 and 2009, realized gains and losses recognized on the sale of available-for-sale securities are as follows:

	Three Months Ended September 30, 2010						Nine Months Ended September 30, 2010
(Millions of Dollars)		Realized Gains		Realized Losses		Net Realized Gains		Realized Gains		Realized Losses		Net Realized Gains/(Losses)
NU	$	0.3	$	-	$	0.3	$	0.5	$	(0.2)	$	0.3
WMECO		-		-		-		-		(0.1)		(0.1)

	Three Months Ended September 30, 2009						Nine Months Ended September 30, 2009
(Millions of Dollars)		Realized Gains		Realized Losses		Net Realized Gains/(Losses)		Realized Gains		Realized Losses		Net Realized Gains/(Losses)
NU	$	5.0	$	(0.7)	$	4.3	$	13.3	$	(5.2)	$	8.1
WMECO		-		(0.7)		(0.7)		-		(0.7)		(0.7)

45

Realized gains and losses on available-for-sale-securities are recorded in Other Income, Net for the NU supplemental benefit trust and in Other Long-Term Assets for the WMECO spent nuclear fuel trust.  NU utilizes the specific identification basis method for the NU supplemental benefit trust securities and the average cost basis method for the WMECO spent nuclear fuel trust to compute the realized gains and losses on the sale of available-for-sale securities.  Proceeds from the sale of these securities, including proceeds from short-term investments, totaled $50.8 million and $146.3 million for the three and nine months ended September 30, 2010, respectively, and $34.4 million and $182.1 million for the three and nine months ended September 30, 2009, respectively.  WMECO's portion of these proceeds totaled $25.4 million and $94.6 million for the three and nine months ended September 30, 2010, respectively, and $21.6 millio n and $99.9 million for the three and nine months ended September 30, 2009, respectively.  Proceeds from the sales of securities are used to purchase new securities.

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

	NU				WMECO
(Millions of Dollars)	As of September 30, 2010		As of December 31, 2009		As of September 30, 2010		As of December 31, 2009
Level 1:
Exchange Traded Funds	$	35.1	$	32.0	$	-	$	-
High Yield Bond Fund		3.4		3.3		-		-
Money Market Funds		3.5		8.9		0.9		6.6
Total Level 1		42.0		44.2		0.9		6.6
Level 2:
U.S. Government Issued Debt Securities       (Agency and Treasury)		17.7		29.9		6.1		17.0
Corporate Debt Securities		22.4		25.1		15.8		17.4
Asset Backed Debt Securities		11.2		6.1		4.9		0.9
Municipal Bonds		9.9		10.8		9.4		10.6
Other Fixed Income Securities		22.5		5.0		19.9		4.3
Total Level 2		83.7		76.9		56.1		50.2
Total Marketable Securities	$	125.7	$	121.1	$	57.0	$	56.8

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

Not included in the tables above are $25.6 million and $11.6 million of cash equivalents as of September 30, 2010 and December 31, 2009, respectively, held by NU parent in an unrestricted money market account and included in Cash and Cash Equivalents on the accompanying unaudited condensed consolidated balance sheets of NU, which are classified as Level 1 in the fair value hierarchy.

11.

SEGMENT INFORMATION

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

The Regulated companies' segments include the distribution and transmission segments.  The distribution segment includes the natural gas distribution business (Yankee Gas) and 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, 2010 and 2009.  CL&P's, PSNH's and WMECO's complete unaudited condensed consolidated financial statements are included in this combined Quarterly Report on Form 10-Q.  Also included in this combined Quarterly Report on Form 10-Q is detailed information regarding CL&P's, PSNH's, and WMECO's transmission segments.

NU Enterprises is comprised of the following:  1) Select Energy (wholesale contracts), 2) Boulos, 3) NGS, 4) NGS Mechanical, 5) SECI, and 6) NU Enterprises parent.  As a result of the sale of NU Enterprises' retail marketing and competitive generation businesses, the financial information used by management was reduced to the remaining wholesale contracts, the operations of the remaining electrical contracting business and NU Enterprises parent.  The remaining operations of NU Enterprises have been aggregated and presented as one business for the three and nine months ended September 30, 2010 and 2009.

Other in the tables below primarily consists of 1) the results of NU parent, which includes other income related to the equity in earnings of NU parent's subsidiaries and interest income from the NU Money Pool, which are both eliminated in consolidation, and interest

46

income and expense related to the cash and debt of NU parent, respectively, 2) the revenues and expenses of NU's service companies, most of which are eliminated in consolidation, and 3) the results of other subsidiaries, which are comprised of RRR (a real estate subsidiary), the non-energy-related subsidiaries of Yankee (Yankee Energy Services Company and Yankee Energy Financial Services Company) and the remaining operations of HWP that were not exited as part of the sale of the competitive generation business in 2006 and the sale of its transmission business to WMECO in December 2008.  

Regulated companies' revenues from the sale of electricity and natural gas primarily are derived from residential, commercial and industrial customers and are not dependent on any single customer.

NU's segment information for the three and nine months ended September 30, 2010 and 2009 is as follows (some amounts may not agree between the financial statements and the segment schedules due to rounding):

	For the Three Months Ended September 30, 2010
	Regulated Companies
	Distribution
(Millions of Dollars)	Electric		Natural Gas		Transmission		NU Enterprises		Other		Eliminations		Total
Operating Revenues	$	1,010.5	$	59.6	$	159.4	$	20.9	$	110.8	$	(117.9)	$	1,243.3
Depreciation and Amortization		(150.0)		(6.6)		(22.0)		(0.1)		(4.2)		1.2		(181.7)
Other Operating Expenses		(751.3)		(52.5)		(50.5)		(18.1)		(110.3)		120.7		(862.0)
Operating Income		109.2		0.5		86.9		2.7		(3.7)		4.0		199.6
Interest Expense		(34.8)		(5.5)		(18.9)		(0.5)		(7.3)		1.1		(65.9)
Interest Income		0.6		-		0.4		-		1.3		(1.3)		1.0
Other Income/(Loss), Net		5.3		0.3		5.0		(1.3)		103.5		(103.7)		9.1
Income Tax (Expense)/Benefit		(20.9)		1.7		(27.6)		(0.8)		6.0		(0.3)		(41.9)
Net Income/(Loss)		59.4		(3.0)		45.8		0.1		99.8		(100.2)		101.9
Net Income Attributable   to Noncontrolling Interests		(0.8)		-		(0.6)		-		-		-		(1.4)
Net Income/(Loss) Attributable   to Controlling Interests	$	58.6	$	(3.0)	$	45.2	$	0.1	$	99.8	$	(100.2)	$	100.5

	For the Nine Months Ended September 30, 2010
	Regulated Companies
	Distribution
(Millions of Dollars)	Electric		Natural Gas		Transmission		NU Enterprises		Other		Eliminations		Total
Operating Revenues	$	2,895.0	$	304.9	$	467.2	$	62.4	$	327.3	$	(362.6)	$	3,694.2
Depreciation and Amortization		(364.7)		(17.2)		(63.9)		(0.3)		(11.4)		2.8		(454.7)
Other Operating Expenses		(2,249.0)		(244.3)		(142.8)		(46.5)		(314.8)		362.5		(2,634.9)
Operating Income		281.3		43.4		260.5		15.6		1.1		2.7		604.6
Interest Expense		(107.0)		(15.8)		(57.5)		(1.3)		(22.2)		3.4		(200.4)
Interest Income/(Loss)		(0.2)		-		1.8		-		4.0		(5.1)		0.5
Other Income/(Loss), Net		9.5		0.4		9.0		(0.3)		286.2		(285.5)		19.3
Income Tax (Expense)/Benefit		(66.5)		(11.9)		(84.8)		(6.3)		9.0		(0.6)		(161.1)
Net Income		117.1		16.1		129.0		7.7		278.1		(285.1)		262.9
Net Income Attributable   to Noncontrolling Interests		(2.5)		-		(1.7)		-		-		-		(4.2)
Net Income Attributable   to Controlling Interests	$	114.6	$	16.1	$	127.3	$	7.7	$	278.1	$	(285.1)	$	258.7
Total Assets (as of)	$	8,850.0	$	1,404.7	$	3,376.3	$	97.7	$	6,017.8	$	(5,448.9)	$	14,297.6
Cash Flows for Total   Investments in Plant	$	403.9	$	52.8	$	170.6	$	-	$	50.3	$	-	$	677.6

	For the Three Months Ended September 30, 2009
	Regulated Companies
	Distribution
(Millions of Dollars)	Electric		Natural Gas		Transmission		NU Enterprises		Other		Eliminations		Total
Operating Revenues	$	1,082.0	$	60.5	$	149.0	$	19.6	$	95.7	$	(100.6)	$	1,306.2
Depreciation and Amortization		(117.2)		(6.6)		(17.8)		(0.1)		(3.1)		0.5		(144.3)
Other Operating Expenses		(890.1)		(55.7)		(44.5)		(19.0)		(93.9)		103.9		(999.3)
Operating Income/(Loss)		74.7		(1.8)		86.7		0.5		(1.3)		3.8		162.6
Interest Expense		(38.1)		(5.5)		(19.2)		(0.5)		(7.7)		1.4		(69.6)
Interest Income		0.3		-		0.1		-		1.7		(1.7)		0.4
Other Income, Net		5.9		0.1		3.1		-		65.5		(65.6)		9.0
Income Tax (Expense)/Benefit		(15.0)		2.7		(27.3)		0.3		4.2		(1.1)		(36.2)
Net Income/(Loss)		27.8		(4.5)		43.4		0.3		62.4		(63.2)		66.2
Net Income Attributable   to Noncontrolling Interests		(0.8)		-		(0.6)		-		-		-		(1.4)
Net Income/(Loss) Attributable   to Controlling Interests	$	27.0	$	(4.5)	$	42.8	$	0.3	$	62.4	$	(63.2)	$	64.8

47

	For the Nine Months Ended September 30, 2009
	Regulated Companies
	Distribution
(Millions of Dollars)	Electric		Natural Gas		Transmission		NU Enterprises		Other		Eliminations		Total
Operating Revenues	$	3,335.2	$	332.5	$	418.9	$	61.3	$	295.9	$	(319.7)	$	4,124.1
Depreciation and Amortization		(332.8)		(20.0)		(53.1)		(0.3)		(10.5)		1.8		(414.9)
Other Operating Expenses		(2,756.8)		(271.3)		(120.8)		(40.6)		(283.4)		322.7		(3,150.2)
Operating Income		245.6		41.2		245.0		20.4		2.0		4.8		559.0
Interest Expense		(112.1)		(16.8)		(53.4)		(2.4)		(25.9)		5.0		(205.6)
Interest Income		3.5		-		0.8		-		6.1		(6.0)		4.4
Other Income, Net		15.7		0.2		5.6		-		274.7		(274.5)		21.7
Income Tax (Expense)/Benefit		(45.5)		(9.3)		(76.3)		(6.4)		9.5		(2.0)		(130.0)
Net Income		107.2		15.3		121.7		11.6		266.4		(272.7)		249.5
Net Income Attributable to   Noncontrolling Interests		(2.5)		-		(1.7)		-		-		-		(4.2)
Net Income Attributable to  Controlling Interests	$	104.7	$	15.3	$	120.0	$	11.6	$	266.4	$	(272.7)	$	245.3
Cash Flows for Total   Investment in Plant	$	374.1	$	39.1	$	190.5	$	-	$	30.7	$	-	$	634.4

The information related to the distribution and transmission segments for CL&P, PSNH and WMECO for the three and nine months ended September 30, 2010 and 2009 is as follows:

	CL&P - For the Three Months Ended
	September 30, 2010						September 30, 2009
(Millions of Dollars)	Distribution		Transmission		Total		Distribution		Transmission		Total
Operating Revenues	$	662.5	$	126.7	$	789.2	$	741.2	$	118.1	$	859.3
Depreciation and Amortization		(98.0)		(16.9)		(114.9)		(80.9)		(14.5)		(95.4)
Other Operating Expenses		(504.6)		(38.3)		(542.9)		(619.8)		(34.0)		(653.8)
Operating Income		59.9		71.5		131.4		40.5		69.6		110.1
Interest Expense		(21.0)		(15.7)		(36.7)		(24.3)		(16.5)		(40.8)
Interest Income		0.5		0.3		0.8		0.6		0.1		0.7
Other Income, Net		3.0		3.1		6.1		3.8		2.5		6.3
Income Tax Expense		(10.1)		(22.5)		(32.6)		(8.4)		(21.4)		(29.8)
Net Income	$	32.3	$	36.7	$	69.0	$	12.2	$	34.3	$	46.5

	CL&P - For the Nine Months Ended
	September 30, 2010						September 30, 2009
(Millions of Dollars)	Distribution		Transmission		Total		Distribution		Transmission		Total
Operating Revenues	$	1,917.8	$	374.3	$	2,292.1	$	2,258.5	$	340.2	$	2,598.7
Depreciation and Amortization		(264.4)		(50.4)		(314.8)		(238.5)		(43.8)		(282.3)
Other Operating Expenses		(1,505.9)		(108.3)		(1,614.2)		(1,881.7)		(91.1)		(1,972.8)
Operating Income		147.5		215.6		363.1		138.3		205.3		343.6
Interest Expense		(64.9)		(47.5)		(112.4)		(69.9)		(46.3)		(116.2)
Interest Income		1.4		1.4		2.8		1.9		0.7		2.6
Other Income, Net		4.1		5.6		9.7		11.1		4.2		15.3
Income Tax Expense		(31.4)		(70.3)		(101.7)		(23.9)		(63.3)		(87.2)
Net Income	$	56.7	$	104.8	$	161.5	$	57.5	$	100.6	$	158.1
Total Assets (as of)	$	5,664.7	$	2,588.8	$	8,253.5	$	5,782.7	$	2,487.8	$	8,270.5
Cash Flows for Total Investments   in Plant	$	192.4	$	81.8	$	274.2	$	209.9	$	121.7	$	331.6

	PSNH - For the Three Months Ended
	September 30, 2010						September 30, 2009
(Millions of Dollars)	Distribution		Transmission		Total		Distribution		Transmission		Total
Operating Revenues	$	256.1	$	20.9	$	277.0	$	254.7	$	20.4	$	275.1
Depreciation and Amortization		(42.3)		(2.5)		(44.8)		(28.4)		(2.4)		(30.8)
Other Operating Expenses		(173.7)		(8.7)		(182.4)		(202.6)		(7.6)		(210.2)
Operating Income		40.1		9.7		49.8		23.7		10.4		34.1
Interest Expense		(9.4)		(2.1)		(11.5)		(9.9)		(1.8)		(11.7)
Interest Income		0.1		-		0.1		0.4		-		0.4
Other Income, Net		3.1		0.5		3.6		1.5		0.4		1.9
Income Tax Expense		(10.4)		(2.8)		(13.2)		(5.0)		(3.5)		(8.5)
Net Income	$	23.5	$	5.3	$	28.8	$	10.7	$	5.5	$	16.2

48

	PSNH - For the Nine Months Ended
	September 30, 2010						September 30, 2009
(Millions of Dollars)	Distribution		Transmission		Total		Distribution		Transmission		Total
Operating Revenues	$	713.3	$	60.6	$	773.9	$	792.2	$	53.5	$	845.7
Depreciation and Amortization		(76.3)		(7.8)		(84.1)		(73.0)		(6.8)		(79.8)
Other Operating Expenses		(532.2)		(24.5)		(556.7)		(644.0)		(20.5)		(664.5)
Operating Income		104.8		28.3		133.1		75.2		26.2		101.4
Interest Expense		(29.5)		(6.3)		(35.8)		(30.0)		(4.8)		(34.8)
Interest Income/(Loss)		(1.9)		0.2		(1.7)		2.1		0.1		2.2
Other Income, Net		6.5		1.1		7.6		3.2		1.1		4.3
Income Tax Expense		(28.4)		(8.6)		(37.0)		(14.3)		(8.5)		(22.8)
Net Income	$	51.5	$	14.7	$	66.2	$	36.2	$	14.1	$	50.3
Total Assets (as of)	$	2,319.5	$	477.5	$	2,797.0	$	2,179.5	$	429.8	$	2,609.3
Cash Flows for Total Investments   in Plant	$	185.6	$	32.4	$	218.0	$	134.7	$	34.7	$	169.4

	WMECO - For the Three Months Ended
	September 30, 2010						September 30, 2009
(Millions of Dollars)	Distribution		Transmission		Total		Distribution		Transmission		Total
Operating Revenues	$	91.9	$	11.8	$	103.7	$	86.2	$	10.4	$	96.6
Depreciation and Amortization		(9.8)		(2.6)		(12.4)		(7.9)		(0.8)		(8.7)
Other Operating Expenses		(72.9)		(3.5)		(76.4)		(67.8)		(3.0)		(70.8)
Operating Income		9.2		5.7		14.9		10.5		6.6		17.1
Interest Expense		(4.5)		(1.1)		(5.6)		(4.0)		(0.8)		(4.8)
Interest Income/(Loss)		0.1		-		0.1		(0.6)		-		(0.6)
Other Income/(Loss), Net		(0.8)		1.4		0.6		0.7		0.1		0.8
Income Tax Expense		(0.3)		(2.4)		(2.7)		(1.7)		(2.3)		(4.0)
Net Income	$	3.7	$	3.6	$	7.3	$	4.9	$	3.6	$	8.5

	WMECO - For the Nine Months Ended
	September 30, 2010						September 30, 2009
(Millions of Dollars)	Distribution		Transmission		Total		Distribution		Transmission		Total
Operating Revenues	$	264.1	$	32.3	$	296.4	$	284.6	$	25.2	$	309.8
Depreciation and Amortization		(23.9)		(5.7)		(29.6)		(21.4)		(2.4)		(23.8)
Other Operating Expenses		(211.1)		(10.1)		(221.2)		(231.2)		(9.2)		(240.4)
Operating Income		29.1		16.5		45.6		32.0		13.6		45.6
Interest Expense		(12.6)		(3.6)		(16.2)		(12.2)		(2.3)		(14.5)
Interest Income/(Loss)		0.3		0.2		0.5		(0.4)		-		(0.4)
Other Income/(Loss), Net		(1.2)		2.1		0.9		1.3		0.3		1.6
Income Tax Expense		(6.7)		(5.9)		(12.6)		(7.2)		(4.6)		(11.8)
Net Income	$	8.9	$	9.3	$	18.2	$	13.5	$	7.0	$	20.5
Total Assets (as of)	$	868.7	$	300.0	$	1,168.7	$	859.8	$	212.9	$	1,072.7
Cash Flows for Total Investments  in Plant	$	26.0	$	51.7	$	77.7	$	29.6	$	34.1	$	63.7

49

12.

COMMON SHAREHOLDERS' EQUITY AND NONCONTROLLING INTERESTS (NU)

A summary of the changes in Common Shareholders' Equity and Noncontrolling Interests of NU for the three and nine months ended September 30, 2010 and 2009 is as follows:

	For the Three Months Ended September 30,
	2010								2009
(Millions of Dollars)	Common Shareholders' Equity		Noncontrolling Interest		Total Equity		Preferred Stock Not Subject to Mandatory Redemption		Total Equity		Preferred Stock Not Subject to Mandatory Redemption
Balance, Beginning of Period	$	3,658.9	$	1.1	$	3,660.0	$	116.2	$	3,501.8	$	116.2
Net Income		101.9		-		101.9		-		66.2		-
Dividends on Common Shares		(45.4)		-		(45.4)		-		(41.9)		-
Dividends on Preferred   Shares of CL&P		(1.4)		-		(1.4)		(1.4)		(1.4)		(1.4)
Issuance of Common Shares		1.1		-		1.1		-		-		-
Contributions to NPT		-		0.3		0.3		-		-		-
Other Transactions, Net		6.8		-		6.8		-		7.5		-
Net Income Attributable to   Noncontrolling Interests		-		-		-		1.4		-		1.4
Other Comprehensive Income   (Note 5)		0.8		-		0.8		-		1.2		-
Balance, End of Period	$	3,722.7	$	1.4	$	3,724.1	$	116.2	$	3,533.4	$	116.2

	For the Nine Months Ended September 30,
	2010								2009
(Millions of Dollars)	Common Shareholders' Equity		Noncontrolling Interest		Total Equity		Preferred Stock Not Subject to Mandatory Redemption		Total Equity		Preferred Stock Not Subject to Mandatory Redemption
Balance, Beginning of Period	$	3,577.9	$	-	$	3,577.9	$	116.2	$	3,020.3	$	116.2
Net Income		262.9		-		262.9		-		249.5		-
Dividends on Common Shares		(136.3)		-		(136.3)		-		(121.0)		-
Dividends on Preferred   Shares of CL&P		(4.2)		-		(4.2)		(4.2)		(4.2)		(4.2)
Issuance of Common Shares		6.5		-		6.5		-		388.5		-
Capital Stock Expenses, Net		-		-		-		-		(12.5)		-
Contributions to NPT		-		1.4		1.4		-		-		-
Other Transactions, Net		13.4		-		13.4		-		13.3		-
Net Income Attributable to   Noncontrolling Interests		-		-		-		4.2		-		4.2
Other Comprehensive   Income/(Loss) (Note 5)		2.5		-		2.5		-		(0.5)		-
Balance, End of Period	$	3,722.7	$	1.4	$	3,724.1	$	116.2	$	3,533.4	$	116.2

For the three and nine months ended September 30, 2010 and 2009, there was no change in NU parent's 100 percent ownership of the common equity of CL&P.  

13.

SUBSEQUENT EVENTS

On October 4, 2010, NPT and HQ Hydro Renewable Energy entered into a TSA in connection with the Northern Pass transmission project.  The Northern Pass is comprised of a planned HVDC transmission line from the Canadian border to Franklin, New Hampshire and an associated alternating current radial transmission line between Franklin and Deerfield, New Hampshire that will be constructed by NPT.  NU's current 75 percent share of the Northern Pass transmission project is expected to be approximately $830 million out of total expected costs of approximately $1.1 billion (including capitalized AFUDC and property taxes).  Northern Pass will interconnect at the U.S.-Canadian border with a planned HVDC transmission line that HQ TransÉnergie, the transmission division of HQ, will construct in Québec.  Consistent with the FERC's 2009 declaratory order, NPT will sell to HQ Hydro Renewable Energy 1,200 MW of firm electric transmission rig hts over the Northern Pass for a 40-year term pursuant to the TSA.

During October 2010, NU settled various tax matters, which resulted in closing out various uncertain tax positions and will result in a fourth quarter after-tax gain of approximately $33 million (approximately $15 million for CL&P).  This gain will be recorded as a benefit to both interest and income tax expense.  

In October 2010, NSTAR and the members of the NSTAR board of trustees (collectively "NSTAR defendants") and NU, along with NU Holding Energy 1 LLC and NU Holding Energy 2 LLC, two wholly-owned subsidiaries of NU (collectively "NU defendants") were named defendants in nine separate purported class action lawsuits filed in the Suffolk Superior Court (eight of the cases) and the United States District Court for the District of Massachusetts (one case).  The cases were brought on behalf of proposed classes consisting of holders of NSTAR common shares, excluding the defendants and their affiliates.  The complaints allege, among other things, that the individual NSTAR defendants breached their fiduciary duties by failing to maximize the value to be received by NSTAR's public shareholders, and that the NU defendants aided and abetted the individual NSTAR defendants' breaches of fiduciary duties.  The complaints seek, among ot her things, (a) to enjoin defendants from consummating the merger; (b) rescission of the merger, if completed and/or (c) granting the

50

class members any profits or benefits allegedly improperly received by defendants in connection with the merger.  NU believes the cases have no merit and will respond to these actions in due course and intends to defend the actions vigorously.  

51

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Trustees and Shareholders of Northeast Utilities:

We have reviewed the accompanying condensed consolidated balance sheet of Northeast Utilities and subsidiaries (the "Company") as of September 30, 2010, and the related condensed consolidated statements of income for the three-month and nine-month periods ended September 30, 2010 and 2009, and of cash flows for the nine-month periods ended September 30, 2010 and 2009.  These interim financial statements are the responsibility of the Company's management.

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

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

We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet and consolidated statement of capitalization of Northeast Utilities and subsidiaries as of December 31, 2009, and the related consolidated statements of income, comprehensive income, shareholders' equity, and cash flows for the year then ended (not presented herein); and in our report dated February 26, 2010, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying condensed consolidated balance sheet as of December 31, 2009 is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

/s/	Deloitte & Touche LLP
	Deloitte & Touche LLP

Hartford, Connecticut

November 5, 2010

52

NORTHEAST UTILITIES AND SUBSIDIARIES

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

The following discussion and analysis should be read in conjunction with our unaudited condensed consolidated financial statements and related combined notes included in this Quarterly Report on Form 10-Q, the First and Second Quarter 2010 Forms 10-Q, and the 2009 Form 10-K.  References in this Form 10-Q to "NU," the "Company," "we," "us" and "our" refer to Northeast Utilities and its consolidated subsidiaries.  All per share amounts are reported on a fully 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 or loss attributable to controlling interests of each business by the weighted average fully diluted NU common shares outstanding for the period.  We use this non-GAAP financial measure to evaluate earnings results and to provide details of earnings results and guidance by business.  We believe that this measurement is useful to investors to evaluate the actual and projected financial performance and contribution of our businesses.  This non-GAAP financial measure should not be considered as an alternative to our consolidated fully diluted 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 fully diluted EPS and Net Income Attributable to Controlling Interests are included under "Financial Condition and Business Analysis-Overview-Consolidated" and "Financial Condition and Business Analysis-Future Outlook" inManagement's Discussion and Analysis, herein.

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

·

actions or inaction by local, state and federal regulatory bodies

·

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

·

changes in weather patterns

·

changes in laws, regulations or regulatory policy

·

changes in levels and timing of capital expenditures

·

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

·

developments in legal or public policy doctrines

·

technological developments

·

changes in accounting standards and financial reporting regulations

·

fluctuations in the value of our remaining competitive contracts

·

actions of rating agencies

·

the effects and outcome of our pending merger with NSTAR, and

·

other presently unknown or unforeseen factors.  

Other risk factors are detailed in our reports filed with the SEC and updated from time to time, and we encourage you to consult such disclosures.

All such factors are difficult to predict, contain uncertainties that may materially affect our actual results and are beyond our control.  You should not place undue reliance on the forward-looking statements, each speaks only as of the date on which such statement is made, and we undertake no obligation to update any forward-looking statement or statements to reflect events or circumstances after the date on which such statement is made or to reflect the occurrence of unanticipated events.  New factors emerge from time to time and it is not possible for management to predict all of such factors, nor can management 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 a nd in our 2009 Form 10-K.  This Quarterly Report on Form 10-Q and our 2009 Form 10-K also describe material contingencies and critical accounting policies and estimates in the respectiveManagement's Discussion and Analysis andCombined Notes to Consolidated Financial Statements.  We encourage you to review these items.

53

Financial Condition and Business Analysis

Proposed Merger with NSTAR:  

On October 18, 2010, we and NSTAR announced that each company's Board of Trustees unanimously approved a Definitive Merger Agreement (the "agreement") to create a combined company that will be called Northeast Utilities.  The transaction will be a merger of equals in a tax-free share for share transfer.  The combined company will provide electric and natural gas energy delivery service to nearly 3.5 million electric and natural gas customers through six regulated electric and natural gas utilities in Connecticut, Massachusetts and New Hampshire, representing over half of all the customers in New England.

Under the terms of the agreement, NSTAR shareholders would receive 1.312 NU common shares for each common share of NSTAR that they own (the "exchange ratio").  The exchange ratio is 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.  Following completion of the merger, the market capitalization of the combined company would be comprised of approximately 56 percent of NU shareholders and approximately 44 percent of former NSTAR shareholders.  It is anticipated that we would issue approximately 137 million shares to the NSTAR shareholders as a result of the merger.  Following the closing of the merger, our first dividend per common share declared after the closing would be increased to a rate that is equivalent to NSTAR's last dividend per common share paid prior to the closing divided by the e xchange ratio.

Completion of the merger is subject to various conditions, including, among others, approval by holders of two-thirds of the outstanding common shares of both companies, the expiration or termination of any applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, the effectiveness of the registration statement for the NU common shares to be issued to NSTAR shareholders in the merger, and receipt of all required regulatory approvals.  The companies anticipate that the regulatory approvals can be obtained in nine to twelve months.  The companies intend to seek shareholder approval of the merger in early 2011 and expect that the merger will close in the third quarter of 2011.

Executive Summary

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

Revised Outlook:  

·

We now project consolidated 2010 earnings of between $2.10 per share and $2.20 per share, which includes a $0.09 per share non-recurring benefit associated with a settlement of tax issues in the fourth quarter and an approximate $0.07 per share charge related to expected merger costs we will expense in the fourth quarter.  Our non-GAAP projected 2010 consolidated earnings is also between $2.10 per share and $2.20 per share, including distribution segment earnings of between $1.10 per share and $1.20 per share, transmission segment earnings of approximately $1.00 per share, competitive businesses' earnings of approximately $0.05 per share, and net expenses at NU parent and other companies of approximately $0.05 per share, which excludes the previously mentioned $0.09 per share non-recurring tax benefit and the approximate $0.07 per share charge related to merger costs.  NU had previously projected consolidat ed earnings of between $1.95 per share and $2.05 per share.  We have raised our 2010 earnings guidance as a result of stronger third quarter sales due to warmer than normal summer weather, our continued control of operation and maintenance costs and significant progress in reducing our uncollectibles expense, as well as the settlement of various routine tax issues during the fourth quarter of 2010.

·

We project capital expenditures for 2011 through 2015 of approximately $6.6 billion.  During that time period, we expect Regulated company rate base to rise from approximately $7.4 billion at the end of 2010 to approximately $11.9 billion at the end of 2015.

Results:

·

We earned $100.5 million, or $0.57 per share, in the third quarter of 2010, and $258.7 million, or $1.46 per share, in the first nine months of 2010, compared with $64.8 million, or $0.37 per share, in the third quarter of 2009 and $245.3 million, or $1.43 per share, in the first nine months of 2009. Improved results in the third quarter of 2010 were due primarily to higher retail electric sales due to warmer than normal summer weather, our continued success in managing operation and maintenance costs, the impact of the 2010 distribution rate case decisions that were effective July 1, 2010, and increased earnings in the transmission segment.  Higher 2010 results were due primarily to the 2010 distribution rate case decisions, partially offset by the absence of the net benefit impact of approximately $16 million, or approximately $0.09 per share, from the resolution of various routine tax issues in t he first nine months of 2009 and a net after-tax charge of approximately $3 million, or approximately $0.02 per share, associated with the enactment of the 2010 Healthcare Act.  Retail electric sales were up 2.3 percent and firm natural gas sales were down 1.2 percent in the first nine months of 2010 compared with the first nine months of 2009.

·

Our Regulated companies earned $100.9 million, or $0.57 per share, in the third quarter of 2010 and $258 million, or $1.46 per share, in the first nine months of 2010, compared with earnings of $65.3 million, or $0.37 per share, in the third quarter of 2009 and $240 million, or $1.40 per share, in the first nine months of 2009.  

·

Earnings from the distribution segment of our Regulated companies (which also includes the generation businesses of PSNH and WMECO and the natural gas distribution business) totaled $55.7 million, or $0.31 per share, in the third quarter of 2010, and $130.7 million, or $0.74 per share, in the first nine months of 2010, compared with $22.5 million, or $0.13 per share, in the third

54

quarter of 2009 and $120 million, or $0.70 per share, in the first nine months of 2009.  Earnings from the transmission segment of our Regulated companies totaled $45.2 million, or $0.26 per share, in the third quarter of 2010 and $127.3 million, or $0.72 per share, in the first nine months of 2010, compared with $42.8 million, or $0.24 per share, in the third quarter of 2009 and $120 million, or $0.70 per share, in the first nine months of 2009.

·

Our competitive businesses, which are held by NU Enterprises, earned $0.1 million in the third quarter of 2010 and $7.7 million, or $0.04 per share, in the first nine months of 2010, compared with $0.3 million in the third quarter of 2009 and $11.6 million, or $0.07 per share, in the first nine months of 2009.  NU Enterprises recorded $0.5 million of after-tax mark-to-market gains in the first nine months of 2010, compared with $3.7 million of after-tax mark-to-market gains in the first nine months of 2009.

·

NU parent and other companies recorded net expenses of $0.5 million in the third quarter of 2010 and $7 million, or $0.04 per share, in the first nine months of 2010, compared with net expenses of $0.8 million in the third quarter of 2009 and $6.3 million, or $0.04 per share, in the first nine months of 2009.  The improved third quarter results were due to lower income tax expense and lower interest expense at NU parent, partially offset by a $1 million after-tax increase in the HWP environmental reserve.  The increase in expenses for the first nine months of 2010 was due primarily to a $0.9 million after-tax increase in the HWP environmental reserve and a $0.6 million net after-tax charge associated with the 2010 Healthcare Act, partially offset by lower interest expense at NU parent.

Strategy, Regulatory and Other Items:

·

On October 4, 2010, NPT and HQ Hydro Renewable Energy, entered into a TSA in connection with the Northern Pass transmission project.  The Northern Pass is comprised of a planned HVDC transmission line from the Canadian border to Franklin, New Hampshire and an associated alternating current radial transmission line between Franklin and Deerfield, New Hampshire that will be constructed by NPT, and is expected to cost approximately $1.1 billion.  Northern Pass will interconnect at the U.S.-Canadian border with a planned HVDC transmission line that HQ TransÉnergie, the transmission division of HQ, will construct in Québec.  Consistent with the FERC's 2009 declaratory order, NPT will sell to HQ Hydro Renewable Energy 1,200 MW of firm electric transmission rights over the Northern Pass for a 40-year term pursuant to the TSA.  NPT intends to file the TSA with the FERC during the fourth quarter of 2010, requesting that the FERC approve the TSA as a rate schedule.  Assuming permits are timely secured, the project is expected to enter into service in late 2015.  

Liquidity:

·

Cash capital expenditures totaled $677.6 million in the first nine months of 2010, compared with $634.4 million in the first nine months of 2009.  

·

Cash flows provided by operating activities totaled $647.9 million in the first nine months of 2010, compared with $577.9 million in the first nine months of 2009 (all amounts are net of RRB payments, which are included in financing activities).  The improved cash flows were due primarily to the absence in 2010 of costs incurred at PSNH and WMECO related to the major storm in December 2008 that were paid in the first quarter of 2009, offset by an increase in income tax payments of approximately $60 million largely attributable to the absence of bonus depreciation tax deductions and a $45 million contribution made in September 2010 into our Pension Plan.  We now project 2010 consolidated cash flows provided by operating activities, net of RRB payments, of $800 million to $850 million, which is approximately $100 million higher than our second quarter 2010 projection due primarily to the Small Business Jobs a nd Credit Act of 2010, which extended bonus depreciation tax deductions through 2010.   

·

Cash and cash equivalents totaled $41.2 million as of September 30, 2010, compared with $27 million as of December 31, 2009.  

·

On September 24, 2010, CL&P, PSNH, WMECO, and Yankee Gas jointly entered into a three-year $400 million unsecured revolving credit facility, replacing a similar five-year $400 million credit facility that was scheduled to terminate on November 6, 2010.  On September 24, 2010, NU parent entered into a three-year $500 million unsecured revolving credit facility, replacing a similar five-year $500 million credit facility that was scheduled to terminate on November 6, 2010.  Both new revolving credit facilities expire on September 24, 2013.  As of September 30, 2010, we had $704.4 million of aggregate borrowing availability on our revolving credit lines, compared with $702.8 million as of December 31, 2009.  

Overview

Consolidated:  We earned $100.5 million, or $0.57 per share, in the third quarter of 2010, and $258.7 million, or $1.46 per share, in the first nine months of 2010, compared with $64.8 million, or $0.37 per share, in the third quarter of 2009 and $245.3 million, or $1.43 per share, in the first nine months of 2009.  Improved results in the third quarter of 2010 were due primarily to higher retail electric sales due to warmer than normal summer weather, our continued success in managing operation and maintenance costs, the impact of the 2010 distribution rate case decisions that were effective July 1, 2010, and increased earnings in the transmission segment.  Higher 2010 results were due primarily to the 2010 distribution rate case decisions, partially offset by the absence of the net benefit impact of approximately $16 million, or approximately $0.09 per share, from the resolution of various routine tax issues in the first nine mon ths of 2009 and a net after-tax charge of approximately $3 million, or approximately $0.02 per share, associated with the enactment of the 2010 Healthcare Act.  Retail electric sales were up 2.3 percent and firm natural gas sales were down 1.2 percent in the first nine months of 2010 compared to the same period in 2009.

55

A summary of our earnings by business, which also reconciles the non-GAAP financial measures of consolidated non-GAAP earnings and EPS, as well as EPS by business, to the most directly comparable GAAP measures of consolidated Net Income Attributable to Controlling Interests and fully diluted EPS, for the third quarter and first nine months of 2010 and 2009 is as follows:

	For the Three Months Ended September 30,								For the Nine Months Ended September 30,
(Millions of Dollars, except	2010				2009				2010					2009
Per share amounts)	Amount		Per Share		Amount		Per Share		Amount		Per Share			Amount		Per Share
Net Income Attributable to   Controlling Interests (GAAP)	$	100.5	$	0.57	$	64.8	$	0.37	$	258.7	$	1.46		$	245.3	$	1.43
													&nbs p;
Regulated Companies	$	100.9	$	0.57	$	65.3	$	0.37	$	258.0	$	1.46		$	240.0	$	1.40
Competitive Businesses		0.1		-		0.3		-		7.7		0.04			11.6		0.07
NU Parent and Other Companies		(0.5)		-		(0.8)		-		(7.0)		(0.04)			(6.3)		(0.04)
Net Income Attributable to   Controlling Interests (GAAP)	$	100.5	$	0.57	$	64.8	$	0.37	$	258.7	$	1.46		$	245.3	$	1.43

Regulated Companies:  Our Regulated companies operate in two segments:  electric transmission and distribution, with natural gas distribution and PSNH and WMECO generation included in the distribution segment.  A summary of our Regulated companies' earnings by segment for the third quarter and first nine months of 2010 and 2009 is as follows:

	For the Three Months Ended September  30,				For the Nine Months Ended September 30,
(Millions of Dollars)	2010		2009		2010		2009
CL&P Transmission	$	36.1	$	33.7	$	103.1	$	98.9
PSNH Transmission		5.3		5.5		14.7		14.1
WMECO Transmission		3.7		3.6		9.4		7.0
NUTV		0.1		-		0.1		-
Total Transmission		45.2		42.8		127.3		120.0
CL&P Distribution		31.5		11.4		54.2		55.0
PSNH Distribution		23.4		10.7		51.5		36.2
WMECO Distribution		3.7		4.9		8.9		13.5
Yankee Gas		(2.9)		(4.5)		16.1		15.3
Total Distribution		55.7		22.5		130.7		120.0
Net Income - Regulated Companies	$	100.9	$	65.3	$	258.0	$	240.0

In both the third quarter and first nine months of 2010, greater transmission segment earnings reflected increased investment as we continued to build out our transmission infrastructure to meet the reliability needs of our customers and the region.  The 2010 results were also impacted by the absence of the benefit from the resolution of various routine tax issues in the first nine months of 2009, a charge associated with the 2010 Healthcare Act in the first quarter of 2010, and lower net gains realized in 2010 on the sale of securities in the NU supplemental benefit trust as compared to 2009.

CL&P's third quarter 2010 distribution segment earnings were $20.1 million higher than the same period in 2009 due primarily to the conclusion of the distribution rate case on June 30, 2010, which allows CL&P to defer operations and maintenance expenses for the last six months of 2010 in lieu of cash rate relief and provides new rates to begin on January 1, 2011.  CL&P's third quarter earnings also benefitted from lower depreciation expense as authorized in the distribution rate case, higher revenues due primarily to a 6.6 percent increase in retail electric sales, lower uncollectibles expense, and lower income taxes.  Partially offsetting these favorable impacts were higher employee benefit costs, property taxes, and interest expense.

For the first nine months of 2010, CL&P's distribution segment earnings were slightly lower than the same period in 2009.  The favorable factors mentioned above that affected earnings in the third quarter of 2010 were offset by unfavorable factors including higher employee benefit costs, property taxes, and interest expense, lower Energy Independence Act incentives, lower net gains realized in 2010 on the sale of securities in the NU supplemental benefit trust as compared to 2009, and the absence of the $7.9 million benefit from the resolution of routine tax issues in the first nine months of 2009.  For the 12 months ended September 30, 2010, CL&P's distribution segment regulatory ROE was 6.7 percent and for the full year 2010 we expect it to be approximately 7.5 percent.  

PSNH's third quarter 2010 distribution segment earnings were $12.7 million higher than the same period in 2009 due primarily to higher revenues resulting from the permanent distribution rate increase effective July 1, 2010 and a 6.9 percent increase in retail electric sales.  PSNH's expenses in the third quarter of 2010 were essentially the same as the third quarter of 2009.

For the first nine months of 2010, PSNH's distribution segment earnings were $15.3 million higher than the same period in 2009 due primarily to higher revenues as a result of distribution rate increases effective August 1, 2009 and July 1, 2010 and a 1.9 percent increase in retail electric sales, and the impact of the permanent distribution rate case settlement approved on June 28, 2010 allowing certain expenses to be recovered through non-distribution rate components retroactive to August 1, 2009.  These favorable impacts were partially offset by higher expenses, including employee benefit costs, depreciation, property taxes, and interest expense, higher income taxes in the first quarter associated with the 2010 Healthcare Act, lower net gains realized in 2010 on the sale of securities in the NU supplemental benefit trust as compared to 2009, and the absence of the benefit from the resolution of routine tax issues in the first nine months of 2009.  For the 12 months ended September 30, 2010, PSNH's distribution segment regulatory ROE was 9.2 percent (including generation) and for the full year 2010 we expect it to be close to the authorized levels.

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WMECO's third quarter 2010 distribution segment earnings were $1.2 million lower than the same period in 2009 due primarily to higher expenses including operating costs, uncollectibles expense, administrative and general costs, employee benefit costs, and depreciation, partially offset by higher revenues attributable to a 5.5 percent increase in retail electric sales.

For the first nine months of 2010, WMECO's distribution segment earnings were $4.6 million lower than the same period in 2009 due primarily to higher expenses including storm restoration costs, administrative and general costs, employee benefit costs, depreciation, and property taxes, the absence of the benefit from the resolution of various routine tax issues in the first nine months of 2009, and lower net gains realized in 2010 on the sale of securities in the NU supplemental benefit trust as compared to 2009.  For the 12 months ended September 30, 2010, WMECO's distribution segment regulatory ROE was 5.3 percent and for the full year 2010 we expect it to be approximately 5 percent.

Yankee Gas recorded a net loss of $2.9 million in the third quarter of 2010 compared to a net loss of $4.5 million for the same period in 2009.  The $1.6 million improvement is due primarily to lower uncollectibles expense and depreciation, partially offset by higher employee benefit costs and property taxes, and lower revenues.

For the first nine months of 2010, Yankee Gas' earnings were $0.8 million higher than the same period in 2009 due primarily to lower uncollectibles expense partially offset by lower revenues resulting from a 1.2 percent decline in firm natural gas sales attributable to warmer than normal temperatures during the heating season, higher employee benefit costs, higher property taxes, and the absence of the benefit from the resolution of various routine tax issues in the first nine months of 2009.  For the 12 months ended September 30, 2010, Yankee Gas' regulatory ROE was 6.6 percent and for the full year 2010 we expect it to be approximately 7.5 percent.

For the distribution segment of our Regulated companies, a summary of changes in CL&P, PSNH and WMECO retail electric GWh sales and Yankee Gas firm natural gas sales for the third quarter and first nine months of 2010 as compared to the same periods in 2009 on an actual and weather normalized basis (using a 30-year average) is as follows:

	For the Three Months Ended September 30, 2010 Compared to 2009
	Electric								Firm Natural Gas
	CL&P		PSNH		WMECO		Total		Yankee Gas
	Percentage Increase/ (Decrease)	Weather Normalized Percentage Decrease	Percentage Increase	Weather Normalized Percentage Increase/ (Decrease)	Percentage Increase/ (Decrease)	Weather Normalized Percentage Decrease	Percentage Increase/ (Decrease)	Weather Normalized Percentage Decrease	Percentage Increase/ (Decrease)	Weather Normalized Percentage Increase/ (Decrease)
Residential	12.2 %	(3.3)%	10.7 %	(2.1)%	11.6 %	(1.8)%	11.8 %	(2.9)%	(14.9)%	(13.8)%
Commercial	2.4 %	(6.1)%	4.2 %	(5.1)%	2.3 %	(5.4)%	2.8 %	(5.8)%	52.1 %	53.0 %
Industrial	1.7 %	(4.7)%	4.8 %	(5.0)%	0.1 %	(4.6)%	2.4 %	(4.8)%	0.4 %	0.4 %
Other	(0.1)%	(0.1)%	0.3 %	0.3 %	(12.4)%	(12.4)%	(0.9)%	(0.9)%	-	-
Total	6.6 %	(4.6)%	6.9 %	(3.9)%	5.5 %	(3.9)%	6.5 %	(4.4)%	9.9 %	10.4 %

	For the Nine Months Ended September 30, 2010 Compared to 2009
	Electric								Firm Natural Gas
	CL&P		PSNH		WMECO		Total		Yankee Gas
	Percentage Increase/ (Decrease)	Weather Normalized Percentage Decrease	Percentage Increase	Weather Normalized Percentage Increase/ (Decrease)	Percentage Increase/ (Decrease)	Weather Normalized Percentage Increase/ (Decrease)	Percentage Increase/ (Decrease)	Weather Normalized Percentage Decrease	Percentage Increase/ (Decrease)	Weather Normalized Percentage Increase
Residential	4.3 %	(1.4)%	3.0 %	(1.1)%	5.4 %	0.9 %	4.1 %	(1.1)%	(6.0)%	4.9 %
Commercial	0.6 %	(3.4)%	1.0 %	(2.9)%	1.3 %	(2.5)%	0.7 %	(3.2)%	2.2 %	11.9 %
Industrial	2.6 %	(0.9)%	1.8 %	(2.9)%	(0.2)%	(2.6)%	1.9 %	(1.8)%	(0.1)%	2.0 %
Other	(0.1)%	(0.1)%	1.9 %	1.9 %	(26.3)%	(26.3)%	(1.8)%	(1.8)%	-	-
Total	2.4 %	(2.2)%	1.9 %	(2.2)%	2.5 %	(1.3)%	2.3 %	(2.1)%	(1.2)%	6.1 %

A summary of our retail electric sales in GWh for CL&P, PSNH and WMECO and firm natural gas sales in million cubic feet for Yankee Gas for the third quarter and first nine months of 2010 and 2009 is as follows:  

	For the Three Months Ended September 30,
	Electric			Firm Natural Gas
	2010	2009	Percentage Increase/ (Decrease)	2010	2009	Percentage Increase/ (Decrease)
Residential	4,213	3,768	11.8 %	942	1,107	(14.9)%
Commercial	3,934	3,827	2.8 %	2,040	1,341	52.1 %
Industrial	1,218	1,190	2.4 %	3,049	3,038	0.4 %
Other	79	80	(0.9)%	-	-	-
Total	9,444	8,865	6.5 %	6,031	5,486	9.9 %

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	For the Nine Months Ended September 30,
	Electric			Firm Natural Gas
	2010	2009	Percentage Increase/ (Decrease)	2010	2009	Percentage Increase/ (Decrease)
Residential	11,329	10,883	4.1 %	8,705	9,263	(6.0)%
Commercial	11,010	10,929	0.7 %	9,926	9,708	2.2 %
Industrial	3,382	3,318	1.9 %	10,775	10,791	(0.1)%
Other	240	244	(1.8)%	-	-	-
Total	25,961	25,374	2.3 %	29,406	29,762	(1.2)%

Actual retail electric sales for all three electric companies were higher in the third quarter and for the first nine months of 2010 as compared to the same periods in 2009 due primarily to warmer than normal summer weather.  Third quarter 2010 cooling degree days in Connecticut and Western Massachusetts were 65 percent higher than last year and 36 percent above normal.  For the first nine months of 2010, cooling degree days in Connecticut and Western Massachusetts were 76 percent higher than last year and 42 percent above normal.  In New Hampshire, cooling degree days in the third quarter of 2010 were 91 percent higher than last year and 45 percent above normal, and for the first nine months of 2010, cooling degree days were 106 percent higher than last year and 42 percent above normal.

On a weather normalized basis, retail electric sales for all three electric companies were lower in the third quarter and for the first nine months of 2010 as compared to the same periods in 2009.  We believe the decrease in weather normalized residential sales is due in part to increased conservation efforts by our customers and ongoing economic conditions impacting our customers.  Our commercial and industrial sales continue to be impacted by additional installation of gas-fired distributed generation and utilization of C&LM programs.  Relatively weak employment growth and uncertainty in consumer confidence have also contributed to the lower commercial and industrial sales.

Our firm natural gas sales are subject to many of the same influences as our retail electric sales, but our firm natural gas sales have benefitted from a favorable price for natural gas and from the addition of gas-fired distributed generation in Yankee Gas' service territory.  Our firm natural gas sales in the third quarter of 2010 were higher than the same period in 2009 due to commercial and industrial customers switching from interruptible service to firm service, additional gas-fired distributed generation, and a large commercial customer who began to take service from Yankee Gas mid-way through the third quarter of 2009 and continues to take service throughout all of 2010.  On a year to date basis, firm natural gas sales in 2010 were lower than the same period in 2009 due to milder weather during the heating season.  Heating degree days in Connecticut were 18 percent lower than last year and 17 percent below normal.  

Our expense related to uncollectible receivable balances (our uncollectibles expense) is influenced by the economic conditions of our region.  Fluctuations in our uncollectibles expense are mitigated from an earnings perspective because a portion of the total uncollectibles expense for each of the electric distribution companies is allocated for recovery to the respective company's energy supply rate and recovered through its tariffs.  Additionally, for CL&P and Yankee Gas, write-offs of uncollectible receivable balances attributable to qualified customers under financial or medical duress (hardship customers) are fully recovered through their respective tariffs.  For the third quarter of 2010, our total uncollectibles expense was approximately $12.7 million lower than the same period in 2009.  Of the total $12.7 million improvement, $3.9 million was allocated for recovery to the energy supply rates as described a bove and $8.8 million impacted our earnings.  For the first nine months of 2010, our total uncollectibles expense was approximately $12.4 million lower than the same period in 2009.  Of the total $12.4 million improvement, $1.2 million was allocated for recovery to the energy supply rates and $11.2 million impacted our earnings.  In the second quarter of 2010, $1.4 million of PSNH's uncollectibles expense was reclassified to its energy supply rate.  This reclassification had no impact on PSNH's total uncollectibles expense, but it did contribute to the $11.2 million improvement impacting our earnings.  For the first nine months of 2010, the improvement in our uncollectibles expense as compared to 2009 is better than our expectations and we expect additional improvement in the fourth quarter of 2010.

Competitive Businesses:  NU Enterprises, which continues to manage to completion Select Energy's remaining wholesale marketing contracts and to manage its electrical contracting business and other operating and maintenance services contracts, earned $0.1 million in the third quarter of 2010 and $7.7 million, or $0.04 per share, in the first nine months of 2010, compared with $0.3 million in the third quarter of 2009, and $11.6 million, or $0.07 per share, in the first nine months of 2009.  In the third quarter of 2010, NU Enterprises recorded $0.6 million of after-tax mark-to-market gains, compared with after-tax mark-to-market losses of $0.9 million in the third quarter of 2009.  NU Enterprises recorded $0.5 million of after-tax mark-to-market gains in the first nine months of 2010, compared with after-tax mark-to-market gains of $3.7 million in the first nine months of 2009.  

NU Parent and Other Companies:  NU parent and other companies recorded net expenses of $0.5 million in the third quarter of 2010 and $7 million, or $0.04 per share, in the first nine months of 2010, compared with net expenses of $0.8 million in the third quarter of 2009 and $6.3 million, or $0.04 per share, in the first nine months of 2009.  The improved third quarter results were due tolower income tax expense and lower interest expense at NU parent, partially offset by a $1 million after-tax increase in the HWP environmental reserve.  The increase in expenses for the first nine months of 2010 was due primarily to a $0.9 million after-tax increase in the HWP environmental reserve and a $0.6 million net after-tax charge associated with the 2010 Healthcare Act, partially offset by lower interest expense at NU parent.

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Future Outlook

EPS Guidance:  Following is a summary of our previously reported and revised projected 2010 EPS by business, which also reconciles consolidated fully diluted EPS to the non-GAAP financial measure of EPS by business.  Non-GAAP EPS by business also excludes certain non-recurring benefits from the settlement of tax issues ($0.09 per share) and the anticipated merger costs expected in the fourth quarter ($0.07 per share), both of which impact NU parent.  Our projected consolidated EPS under GAAP is the same as our non-GAAP EPS by business, which excludes the two items noted above, as follows:

	Previously Reported 2010 EPS Range				Revised 2010 EPS Range
(Approximate amounts)		Low		High		Low		High
Fully Diluted EPS (GAAP)	$	1.95	$	2.05	$	2.10	$	2.20
Regulated Companies:
Distribution Segment	$	1.00	$	1.10	$	1.10	$	1.20
Transmission Segment		0.95		0.95		1.00		1.00
Total Regulated Companies		1.95		2.05		2.10		2.20
Competitive Businesses		0.05		0.05		0.05		0.05
NU Parent and Other Companies		(0.05)		(0.05)		(0.05)		(0.05)
Fully Diluted EPS (Non-GAAP)	$	1.95	$	2.05	$	2.10	$	2.20

We have raised our 2010 earnings guidance as a result of stronger third quarter sales due to warmer than normal summer weather, our continued control of operation and maintenance costs and significant progress in reducing our uncollectibles expense, as well as the settlement of various routine tax issues during the fourth quarter of 2010.  The projected non-GAAP results exclude a $0.09 per share non-recurring benefit associated with the settlement of tax issues and an approximate $0.07 per share charge related to expected merger costs we will expense, both of which will affect NU Parent and Other Companies' results in the fourth quarter of 2010.  

Long-Term Growth Rate:  We project that we will achieve a compound average annual EPS growth rate for the five-year period from 2011 to 2015 of between 6 percent and 9 percent using 2009 EPS of $1.91 per share as the base level.  Assuming completion of the proposed merger with NSTAR in the third quarter of 2011, we expect to achieve an EPS growth rate at the high end of the range between 6 percent and 9 percent.

Liquidity

Consolidated:  Cash and cash equivalents totaled $41.2 million as of September 30, 2010, compared with $27 million as of December 31, 2009.  

On November 1, 2010, the DPUC approved CL&P's application requesting authority to issue up to $900 million in long-term debt through 2014 to be used to refinance CL&P's short-term debt previously incurred in the ordinary course of business, to finance capital expenditures, to provide working capital and to pay issuance costs.  

On September 24, 2010, CL&P, PSNH, WMECO, and Yankee Gas jointly entered into a three-year $400 million unsecured revolving credit facility, which expires on September 24, 2013.  This facility replaced a similar five-year $400 million credit facility that was scheduled to expire on November 6, 2010.  CL&P and PSNH may draw up to $300 million each under this facility, with WMECO and Yankee Gas able to draw up to $200 million each, subject to the $400 million maximum aggregate borrowing limit.  This total commitment may be increased to $500 million at the request of the borrowers, subject to lender approval.  Under this facility, each company can borrow either on a short-term or a long-term basis subject to regulatory approval.  As of September 30, 2010, there were no borrowings outstanding under this facility.  

On September 24, 2010, NU parent entered into a three-year $500 million unsecured revolving credit facility, which expires on September 24, 2013.  This facility replaced a similar five-year $500 million credit facility that was scheduled to expire on November 6, 2010.  Like the previous facility, the new revolving credit facility allows NU parent to borrow up to $500 million at any one time on a short-term or long-term basis.  The facility also allows for the issuance of LOCs up to $500 million in the aggregate (subject to the amount of borrowings outstanding) on behalf of NU or any of its subsidiaries for periods up to 364 days.  This total commitment may be increased to $600 million at the request of NU parent, subject to lender approval.  As of September 30, 2010, NU parent had $39.6 million of LOCs issued for the benefit of certain subsidiaries (primarily PSNH) and $156 million of short-term borrowings o utstanding, leaving $304.4 million of borrowing availability under this facility.  The weighted-average interest rate on these short-term borrowings as of September 30, 2010 was 2.16 percent, which is based on a variable rate plus an applicable margin based on NU parent's credit ratings.

We anticipate no additional long-term debt issuances for NU or its subsidiaries for the remainder of 2010.  As a result of the proposed merger with NSTAR, we intend to re-examine our financing needs for 2011.  We have annual sinking fund requirements of $4.3 million continuing in 2011 through 2012, the mandatory tender of $62 million of tax-exempt PCRBs by CL&P on April 1, 2011, at which time CL&P expects to remarket the bonds in the ordinary course, and no debt maturities until April 1, 2012.  As a result of the proposed merger with NSTAR, we no longer expect to undertake the previously planned $300 million NU common equity issuance nor issue any additional equity in the foreseeable future.  

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Cash flows provided by operating activities in the first nine months of 2010 totaled $647.9 million, compared with operating cash flows of $577.9 million in the first nine months of 2009 (all amounts are net of RRB payments, which are included in financing activities on the accompanying unaudited condensed consolidated statements of cash flows).  The improved cash flows were due primarily to the absence in 2010 of costs incurred at PSNH and WMECO related to the major storm in December 2008 that were paid in the first quarter of 2009 and a decrease in Fuel, Materials and Supplies attributable to a $27.2 million reduction in coal inventory levels at the PSNH generation business as ordered by the NHPUC.  Offsetting these favorable cash flow impacts was an increase in income tax payments of approximately $60 million largely attributable to the absence of bonus depreciation tax deductions under the American Recovery and Reinv estment Act of 2009 in the first nine months of 2010 and a $45 million contribution made into our Pension Plan in September 2010.  

Although bonusdepreciation tax deductions expired at the end of 2009, on September 27, 2010, President Obama signed into law the Small Business Jobs and Credit Act of 2010 that included an extension of these tax deductions through 2010.  As a result, our 2010 cash flows from operations are projected to increase by approximately $100 million.  We now project 2010 cash flows from operations (after RRB payments) of $800 million to $850 million, up from our previous projection of approximately $700 million.  During 2011, we expect to make contributions of approximately $200 million into our Pension Plan, which are tax deductible.

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

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

On October 18, 2010, following the announcement of the proposed merger of NU and NSTAR, Moody's announced that it had reaffirmed the ratings and "stable" outlooks of NU parent, CL&P, PSNH and WMECO and S&P announced that it had placed NU parent, CL&P, PSNH and WMECO's ratings outlooks on creditwatch with "positive" implications.  On October 19, 2010, also due to the proposed merger announcement, Fitch announced that it had reaffirmed the ratings and "stable" outlooks of CL&P, PSNH and WMECO and placed NU parent's ratings outlook on creditwatch with "positive" implications.  Assuming completion of the proposed merger with NSTAR, we expect our credit ratings will improve.

If the senior unsecured debt ratings of NU parent were to be reduced to below investment grade level by either Moody's or S&P, a number of Select Energy's supply contracts would require Select Energy to post additional collateral in the form of cash or LOCs.  If such an event had occurred as of September 30, 2010, Select Energy, under its remaining contracts, would have been required to provide additional cash or LOCs in an aggregate amount of $26.5 million to various unaffiliated counterparties and additional cash or LOCs in the aggregate amount of $2.1 million to independent system operators.  NU parent would have been and remains able to provide that collateral on behalf of Select Energy.  

If the unsecured debt ratings of PSNH were to be reduced by either Moody's or S&P, certain supply contracts could require PSNH to post additional collateral in the form of cash or LOCs with various unaffiliated counterparties.  As of September 30, 2010, if the unsecured debt ratings of PSNH had been reduced by one level or to below investment grade, PSNH had an adequate amount of collateral posted and would not have been required to post additional amounts.  

We paid common dividends of $135.3 million in the first nine months of 2010, compared with $120.6 million in the first nine months of 2009.  The increase reflects a 7.9 percent increase in our common dividend rate that took effect in the first quarter of 2010, as well as a higher number of shares outstanding as a result of the March 2009 issuance of nearly 19 million common shares.  On October 12, 2010, our Board of Trustees declared a quarterly common dividend of $0.25625 per share, payable on December 31, 2010 to shareholders of record as of December 1, 2010.

In general, the Regulated companies pay approximately 60 percent of their earnings to NU parent in the form of common dividends.  In the first nine months of 2010, CL&P, PSNH, WMECO, and Yankee Gas paid $181.8 million, $37.9 million, $11.2 million, and $18.8 million, respectively, in common dividends to NU parent.  In the first nine months of 2010, NU parent made equity contributions to PSNH and WMECO of $123.6 million and $102.6 million, respectively.

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 2010 and 2009 is as follows:

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	For the Nine Months Ended September 30,
(Millions of Dollars)		2010		2009
CL&P	$	274.2	$	331.6
PSNH		218.0		169.4
WMECO		77.7		63.7
Yankee Gas		52.8		39.1
Other		54.9		30.6
Totals	$	677.6	$	634.4

The increase in our cash capital expenditures was the result of higher distribution segment capital expenditures of $43.5 million, particularly at PSNH, and an increase in Other of $24.3 million primarily related to technology and facility projects at NUSCO, one of our corporate service companies.  These increases were offset by a $19.9 million decrease in transmission segment capital expenditures primarily related to 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 $711 million in the first nine months of 2010, compared with $650.6 million in the first nine months of 2009.  These amounts included $46.2 million and $34.4 million in the first nine months of 2010 and 2009, respectively, related to our corporate service companies.  

Regulated Companies:  Capital expenditures for the Regulated companies are expected to total approximately $1.1 billion ($413 million for CL&P, $325 million for PSNH, and $140 million for WMECO) in 2010, which includes planned spending of approximately $69 million for our corporate service companies.  

Transmission Segment:  We expect transmission segment capital expenditures to total approximately $251 million ($102 million for CL&P, $45 million for PSNH, and $94 million for WMECO) in 2010.  Transmission segment capital expenditures decreased by $18.2 million in the first nine months of 2010, as compared with the same period in 2009, due primarily to reductions in expenditures at CL&P and PSNH, partially offset by increases at WMECO and capital expenditures incurred by NPT for the Northern Pass project.  A summary of transmission segment capital expenditures by company in the first nine months of 2010 and 2009 is as follows:

	For the Nine Months Ended September 30,
(Millions of Dollars)		2010		2009
CL&P	$	76.7	$	112.9
PSNH		33.0		41.8
WMECO		64.7		44.3
NPT		6.4		-
Totals	$	180.8	$	199.0

We have updated our cost estimates for our NEEWS projects from $1.49 billion to $1.52 billion (approximately $1.45 billion reflecting the impact of the UI investment of approximately $69 million as discussed below).  The new estimates reflect scope refinements and final siting requirements for GSRP as well as increased costs related to new in-service dates for both the Interstate Reliability Project (from 2014 to 2015) and the Central Connecticut Reliability Project (from 2015 to 2016), and disposition of related projects which are either underway (approximately $84 million) or incorporated into the major NEEWS projects.  As these projects are completed and put in service, actual costs may differ from these estimates.

In October 2008, CL&P and WMECO made state siting filings in Connecticut and Massachusetts, respectively, for the first and largest component of our NEEWS project, the GSRP.  On March 16, 2010, the CSC approved the 12-mile section of GSRP that CL&P plans to build in Connecticut.  On October 21, 2010, the CSC approved CL&P's development and management plans for the project that were filed in July 2010.  On September 28, 2010, the EFSB approved the 23-mile section of GSRP that WMECO plans to build in Massachusetts.  We plan to commence construction later this year and to place the project in service in late 2013.  We have increased the expected cost of this project from $714 million to $795 million.  In June 2010, residents living near the proposed Connecticut route of the GSRP appealed the CSC approval in New Britain Superior Court, claiming that the CSC acted improperly by approving an overhead r oute for the line.  We do not expect the appeal to have a material impact on the timing of construction.  

Our second major NEEWS project is the Interstate Reliability Project, which is being designed and built in coordination with National Grid USA.  CL&P's share of this project includes an approximately 40-mile, 345 KV all overhead line from Lebanon, Connecticut to the Connecticut-Rhode Island border where it would connect with enhancements National Grid USA is designing in Rhode Island and Massachusetts.  In August 2010, ISO-NE reaffirmed the need for the Interstate Reliability Project, which is now expected to be placed in service in late 2015.  This in-service date assumes that siting applications are filed in all three states in mid/late 2011, with orders received in mid/late 2013 and construction commencing in late 2013 or early 2014.  We have increased CL&P's expected share of the costs of this project from $251 million to $301 million.  

The third major part of NEEWS is the Central Connecticut Reliability Project, which involves construction of a new line from Bloomfield, Connecticut to Watertown, Connecticut.  This line would provide another 345 KV all overhead connection to move power across the state of Connecticut.  The timing of this project is expected to be twelve months behind the Interstate Reliability Project.  We have

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increased the expected cost of this project from $313 million to $338 million.  ISO-NE continues to reassess the need for the Central Connecticut Reliability Project and we expect that ISO-NE will conclude its evaluation by mid-2011.

Included as part of NEEWS are $84 million (which changed from our previous estimate of $212 million as a result of incorporating these costs into the three major projects), of associated reliability related expenditures for projects, all of which have received siting approval and most have construction underway.  The in-service dates for these projects range from later this year through 2013.

Since inception of NEEWS through September 30, 2010, CL&P and WMECO have capitalized approximately $94.9 million and $112.6 million, respectively, in costs associated with NEEWS, of which $27.4 million and $38.3 million, respectively, were capitalized in the first nine months of 2010.  

On October 4, 2010, NPT and HQ Hydro Renewable Energy entered into a TSA in connection with the Northern Pass transmission project.  Northern Pass is comprised of a planned HVDC transmission line from the Canadian border to Franklin, New Hampshire and an associated alternating current radial transmission line between Franklin and Deerfield, New Hampshire that will be constructed by NPT.  Northern Pass will interconnect at the U.S.-Canadian border with a planned HVDC transmission line that HQ TransÉnergie, the transmission division of HQ, will construct in Québec.  Consistent with the FERC's 2009 declaratory order, NPT will sell to HQ Hydro Renewable Energy 1,200 MW of firm electric transmission rights over the Northern Pass for a 40-year term pursuant to the TSA.

NPT intends to file the TSA with the FERC during the fourth quarter of 2010, requesting that the FERC approve the TSA as a rate schedule.  On October 13, 2010, NPT filed the Northern Pass project design with ISO-NE for technical approval.  On October 14, 2010, NPT filed a presidential permit application with the DOE, which seeks permission to construct and maintain facilities that cross the U.S. border and connect to facilities in Canada.  NPT anticipates filing additional state and federal permit and siting applications in 2011.  Assuming timely regulatory review and siting approvals, NPT expects to commence construction of the Northern Pass in 2013, with power flowing across the line in late 2015.

NPT will charge HQ Hydro Renewable Energy cost-based rates under the TSA using a FERC-approved formula rate.  The projected cost-of-service calculation includes an ROE of 12.56 percent through the construction phase of the project, and upon commercial operation, the ROE will be tied to the ISO-NE regional rate base ROE (currently 11.14 percent) plus 1.42 percent.  The TSA rates will be based on a deemed capital structure for NPT of 50 percent debt and 50 percent equity.  NPT and HQ are obligated under the TSA to use commercially reasonable efforts to enter into arrangements for construction financing.  During the development phase and the construction phase under the TSA, NPT will be recording non-cash AFUDC earnings.

We currently estimate that NU's current 75 percent share of the Northern Pass transmission project is expected to be approximately $830 million out of total expected costs of approximately $1.1 billion (including capitalized AFUDC and property taxes).

On October 13, 2010, the DPUC approved a joint application filed by CL&P and UI in July 2010 seeking approval for UI's investment in and ownership of certain transmission assets associated with CL&P's portion of the NEEWS projects.  Under the terms of an agreement between UI and CL&P, UI has the option to make quarterly payments to CL&P in exchange for ownership of specific Connecticut based NEEWS transmission assets as they come into commercial operation.  Following FERC approval, UI will have the right to invest up to $69 million or an amount equal to 8.4 percent of CL&P's costs for the Connecticut portion of these projects, which are expected to cost approximately $828 million in the aggregate.  The impact of the UI transaction is reflected in our five-year capital expenditures and rate base forecasts.  

Distribution Segment:  Distribution segment capital expenditures increased by $66.8 million in the first nine months of 2010, as compared with the same period in 2009.  A summary of distribution segment capital expenditures by company for the first nine months of 2010 and 2009 is as follows:

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		For the Nine Months Ended September 30,
(Millions of Dollars)		2010		2009
CL&P:
Basic business	$	80.0	$	81.5
Aging infrastructure		66.8		67.5
Load growth		59.7		54.8
Total CL&P		206.5		203.8
PSNH:
Basic business		27.8		34.0
Aging infrastructure		12.6		12.6
Load growth		16.1		18.8
Total PSNH		56.5		65.4
WMECO:
Basic business		12.9		12.2
Aging infrastructure		7.3		9.3
Load growth		4.4		3.1
Total WMECO		24.6		24.6
Totals - Electric Distribution (excluding Generation)		287.6		293.8
Yankee Gas		58.3		39.2
Other		0.3		0.3
Total Distribution		346.2		333.3
PSNH Generation:
Clean air project		115.5		70.7
Other		16.5		13.2
Total PSNH Generation		132.0		83.9
WMECO Generation		5.8		-
Total Distribution Segment	$	484.0	$	417.2

For the electric distribution business, basic business includes the relocation of plant, the purchase of meters, tools, vehicles, and information technology.  Aging infrastructure relates to the planned replacement of overhead lines, plant substations, transformer replacements, and underground cable replacement.  Load growth includes requests for new business and capacity additions on distribution lines and substation overloads.  For the natural gas business, basic business includes the relocation of conflicting natural gas facilities due to municipal and state road work and the purchase of meters, tools, and information technology.  Aging infrastructure relates to the planned replacement of natural gas facilities.  Load growth includes requests for new natural gas service, new service mains and new distributed generation service.

PSNH's Clean Air Project is a wet scrubber project at its Merrimack coal station, the cost of which will be recovered through PSNH's ES rates under New Hampshire law.  Construction costs are below their original budget of $457 million and the project is expected to be completed in mid-2012.  We currently expect the project to cost approximately $430 million, including capitalized interest and equity returns.  Since inception of the project, PSNH has capitalized $262.4 million associated with this project, of which $115.6 million was capitalized in the first nine months of 2010.  Construction of the project was approximately 73 percent complete as of September 30, 2010.  

On August 12, 2009, the DPU approved a stipulation agreement between WMECO and the Massachusetts Attorney General concerning WMECO's proposal, under the Massachusetts Green Communities Act, to install 6 MW of solar energy generation in its service territory at an estimated cost of $41 million by the end of 2012.  In October 2010, WMECO completed construction of a 1.8 MW project at a site in Pittsfield, Massachusetts and is expected to receive final acceptance of the project later this year.  Since inception of the program, WMECO has capitalized approximately $6.4 million of the total estimated cost of $9.4 million on this first project as of September 30, 2010.  WMECO has identified a second site in Massachusetts where it plans to construct an additional solar generation facility, subject to final approvals.

In April 2010, Yankee Gas commenced construction of its WWL Project, a 16-mile gas pipeline between Waterbury and Wallingford, Connecticut and the increase of vaporization output of its LNG plant, of which the expected cost has decreased from $67 million to $63 million.  Construction in 2010, which included construction of a segment of pipeline connecting the Cheshire and Wallingford distribution systems, cost approximately $18 million and was completed in the fourth quarter of 2010.  The remainder of the pipeline construction and the expansion of the vaporization capacity of the LNG facility is expected to be completed in the fourth quarter of 2011.  Since inception of the project, Yankee Gas has capitalized $19.6 million associated with this project, $18.8 million of which was capitalized in the first nine months of 2010.  Construction of the project was approximately 37 percent complete as of September 30, 2010 and is currently on schedule and on budget.

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

Over the past two years, we have participated in discussions and continue to discuss with other utilities, policymakers, and prospective developers of renewable energy projects in the New England region regarding a framework whereby renewable power projects built in rural areas of northern New England could be connected to the electric load centers of New England.  We believe there are significant

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opportunities for developers to build wind and biomass projects in northern New England that could help the region meet its renewable portfolio standards.  We believe that a collaborative approach among project developers and transmission owners is necessary to be able to construct needed projects and bring their electrical output into the market.  We have not yet included any capital expenditures associated with potential projects in our five-year capital program.  

We continue to consider various energy related investments that could complement our earnings profile.  In 2010, we committed to invest approximately $3 million in an energy investment fund that seeks to invest in clean and renewable energy projects primarily in the United States and Canada.  Under certain conditions, we would invest up to an additional $50 million.

On March 31, 2010, CL&P filed with the DPUC an AMI and dynamic pricing plan that included a cost benefit analysis.  CL&P concluded that a full deployment of AMI meters accompanied by dynamic pricing options for all CL&P customers would be cost beneficial under a set of reasonable assumptions, identified as the "base case scenario."  Under the base case scenario, capital expenditures associated with the installation of the meters are estimated at $296 million.  Under CL&P's proposal, installation of meters is proposed to begin in late 2012 and continue through 2016.  The DPUC has announced a procedural review schedule that began in late October 2010 and is scheduled to end in February 2011.

Projected Capital Expenditures and Rate Base Estimates:  A summary of the projected capital expenditures for the Regulated companies' transmission segment and the distribution and generation segment by company for 2010 and 2011 through 2015, including our corporate service companies' capital expenditures on behalf of the Regulated companies, is as follows:

	Year
(Millions of Dollars)	2010		2011		2012		2013		2014		2015		2011-2015 Totals
CL&P transmission	$	102	$	139	$	194	$	169	$	229	$	280	$	1,011
PSNH transmission		45		54		75		58		45		56		288
WMECO transmission		94		219		260		161		75		7		722
NPT		10		33		84		199		348		158		822
Subtotal transmission	$	251	$	445	$	613	$	587	$	697	$	501	$	2,843
CL&P distribution:
Basic business	$	116	$	137	$	139	$	129	$	214	$	266	$	885
Aging infrastructure		121		124		112		119		122		125		602
Load growth		74		73		67		69		75		77		361
Total CL&P distribution		311		334		318		317		411		468		1,848
PSNH distribution:
Basic business		48		50		48		49		52		53		252
Aging infrastructure		24		26		28		40		41		35		170
Load growth		25		38		41		39		40		45		203
Total PSNH distribution		97		114		117		128		133		133		625
WMECO distribution:
Basic business		17		15		15		16		16		17		79
Aging infrastructure		12		30		32		32		33		33		160
Load growth		5		7		10		9		9		9		44
Total WMECO distribution		34		52		57		57		58		59		283
Subtotal electric distribution	$	442	$	500	$	492	$	502	$	602	$	660	$	2,756
PSNH generation:
Clean air project	$	154	$	77	$	35	$	20	$	-	$	-	$	132
Other		29		32		16		33		29		29		139
Total PSNH generation		183		109		51		53		29		29		271
WMECO generation		12		20		9		5		5		5		44
Subtotal generation	$	195	$	129	$	60	$	58	$	34	$	34	$	315
Yankee Gas distribution:
Basic business	$	32	$	34	$	31	$	30	$	31	$	33	$	159
Aging infrastructure		24		28		49		50		50		52		229
Load growth		17		16		19		46		47		34		162
WWL project		27		35		-		-		-		-		35
Total Yankee Gas distribution	$	100	$	113	$	99	$	126	$	128	$	119	$	585
Corporate service companies	$	69	$	26	$	19	$	36	$	34	$	26	$	141
Totals	$	1,057	$	1,213	$	1,283	$	1,309	$	1,495	$	1,340	$	6,640

 
Yankee Gas determines the amount of capital spending by category based on business needs and opportunities.  Future capital spending will likely be affected by price differences between the cost of natural gas with respect to home heating oil, natural gas supply, new home construction, road reconstruction, regulatory mandates and business requirements.  

Actual capital expenditures could vary from the projected amounts for the companies and periods above.  Economic conditions in the northeast could impact the timing of our major transmission projects.  Most of these capital investment projections, including those for NPT, assume timely regulatory approval, which in some cases requires extensive review.  Delays in or denials of those approvals could reduce the levels of expenditures, associated rate base, and anticipated EPS growth.

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Based on the 2010 through 2015 projected capital expenditures, the 2010 through 2015 projected transmission, distribution and generation rate base as of December 31 of each year are as follows:

	Year
(Millions of Dollars)	2010		2011		2012		2013		2014		2015
CL&P transmission	$	2,196	$	2,180	$	2,253	$	2,303	$	2,457	$	2,609
PSNH transmission		329		365		421		425		522		558
WMECO transmission		220		426		651		730		831		795
NPT		-		-		-		-		-		830
Total transmission		2,745		2,971		3,325		3,458		3,810		4,792
CL&P distribution		2,322		2,490		2,717		2,898		3,154		3,434
PSNH distribution		826		896		996		1,079		1,137		1,207
WMECO distribution		423		457		483		508		531		555
Total electric distribution		3,571		3,843		4,196		4,485		4,822		5,196
PSNH generation		394		400		793		805		797		779
WMECO generation		10		28		33		34		35		36
Total generation		404		428		826		839		832		815
Yankee Gas distribution		714		803		864		926		986		1,094
Totals	$	7,434	$	8,045	$	9,211	$	9,708	$	10,450	$	11,897

Transmission Rate Matters

Transmission - Wholesale Rates:  NU's transmission rates recover total transmission revenue requirements, ensuring that we recover all regional and local revenue requirements.  These rates provide for annual true-ups to actual costs.  The financial impacts of differences between actual and projected costs are deferred for future recovery from, or refund to, customers.  As of September 30, 2010, NU was in a total overrecovery position of $33.6 million ($30.3 million for CL&P, $2.1 million for PSNH, and $1.2 million for WMECO), which will be refunded to customers in June 2011.

Legislative Matters

2010 Federal Legislation:On September 27, 2010, President Obama signed into law the Small Business Jobs and Credit Act of 2010, which extends the bonus depreciation provisions of the American Recovery and Reinvestment Act of 2009 to small and large businesses through 2010.  This extended stimulus will provide NU with cash flow benefits of approximately $100 million in 2010.

2010 Connecticut Legislation:  In May 2010, the Connecticut Legislature approved a state budget for the 2010-2011 fiscal year, which now calls for the issuance by the state of Connecticut of $646.6 million of economic recovery revenue bonds that would be amortized over eight years.  These bonds would be repaid through a charge on customer bills of CL&P and other Connecticut electric distribution companies.  For CL&P, the revenue to pay interest and principal on the bonds would come from a continuation of a portion of its CTA, which would otherwise end at the end of this year, and the diversion of about one-third of the annual funding for C&LM programs beginning in April 2012.  On September 29, 2010, the DPUC approved a financing order for the bonds.  We expect those bonds to be issued in mid-2011.  Unlike the RRBs issued in 2001, the revenues, interest expense and amortization expense asso ciated with these bonds will not be reflected on CL&P's financial statements.

Regulatory Developments and Rate Matters

Connecticut - CL&P:

Standard Service and Last Resort Service Rates:  CL&P's residential and small commercial customers who do not choose competitive suppliers are served under SS rates, and large commercial and industrial customers who do not choose competitive suppliers are served under LRS rates.  CL&P is fully recovering from customers the costs of its SS and LRS services.  CL&P estimates that on January 1, 2011, SS rates (for customers with a peak demand less than 500 KW) are expected to decrease from 11.3 cents per KWh to approximately 9.6 cents per KWh and LRS rates (for customers with a peak demand of 500 KW or greater) are expected to increase from 7.1 cents per KWh to approximately 7.3 cents per KWh.

CTA and SBC Reconciliation:  On March 31, 2010, CL&P filed with the DPUC its 2009 CTA and SBC reconciliation, which compared CTA and SBC revenues charged to customers to revenue requirements and allows for full recovery of revenue requirements.  For the 12 months ended December 31, 2009, total CTA revenue requirements exceeded CTA revenues by $46.9 million.  For the 12 months ended December 31, 2009, the SBC revenues exceeded SBC revenue requirements by $23.7 million.  

On October 28, 2010, a draft decision in the 2009 CTA and SBC docket was issued approving the 2009 CTA and SBC reconciliations as filed.  The draft decision stated that the CTA and SBC rates will need to be reset effective January 1, 2011 based on current projections.  However, the draft decision also stated that the DPUC will review the CTA and SBC balances later in 2010 to determine if further rate changes may be warranted, once CL&P provides additional information in its request for rate adjustments effective January 1, 2011.

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FMCC Filing:  On February 5, 2010, CL&P filed with the DPUC its semi-annual filing, which reconciled actual FMCC revenues and charges and GSC revenues and expenses, for the period July 1, 2009 through December 31, 2009, and also included the previously filed revenues and expenses for the January 1, 2009 through June 30, 2009 period.  The filing identified a total net underrecovery of $6.5 million, which includes the remaining uncollected portions from previous filings.  On October 25, 2010, the DPUC issued a draft decision accepting CL&P's calculations of GSC, bypassable FMCC and nonbypassable FMCC revenues and expenses for the period July 1, 2009 through December 31, 2009.  A final decision is expected on November 10, 2010.  On August 5, 2010, CL&P filed with the DPUC its semi-annual FMCC filing for the period January 1, 2010 through June 30, 2010.  The filing identified a total net underrecovery of $7 million for the period, which includes the remaining uncollected portions from previous filings.  A hearing schedule has been established and a decision is expected in the fourth quarter of 2010.  We do not expect the outcome of the DPUC's review of either of the above filings to have a material adverse impact on CL&P's earnings, financial position or cash flows.

New Hampshire:

ES and SCRC Filings:  On September 21, 2010, PSNH filed petitions with the NHPUC requesting changes in both its ES and SCRC annual rates for the period January 1, 2011 through December 31, 2011.  Consistent with previous annual rate filings, PSNH is requesting that the NHPUC review and approve the underlying data in these filings, not a specific ES or SCRC rate at this time.  PSNH expects to petition the NHPUC using updated information in early December 2010 for specific 2011 ES and SCRC rates.

Merrimack Clean Air Project:  On July 7, 2009, the New Hampshire Site Evaluation Committee determined that PSNH's Clean Air Project to install wet scrubber technology at its Merrimack Station was not subject to the Committee's review as a "sizeable" addition to a power plant under state law.  That Committee upheld its decision in an order dated January 15, 2010, denying requests for rehearing.  This order was appealed on February 23, 2010.  On April 15, 2010, the New Hampshire Supreme Court determined that it would accept the appeal.  The Court has set a briefing schedule, but has not determined when it will hear oral argument. We do not believe that the appeal will have a material impact on the timing or costs of the project.  PSNH is continuing with construction of this project and has capitalized $262.4 million since inception of the project through September 30, 2010 as of which dat e construction was approximately 73 percent complete.

Massachusetts:  

Distribution Rates:  On July 16, 2010, WMECO filed an application with the DPU, requesting approval of a $28.4 million increase in distribution rates and a decoupling plan to be effective February 1, 2011.  Among other items, WMECO is seeking a distribution segment regulatory ROE of 10.5 percent, recovery over five years of its remaining deferred December 2008 major storm costs of approximately $13 million, recovery of its hardship receivable costs, and a capital investment recovery mechanism.  WMECO also proposed raising the annual capital spending plan from approximately $35 million annually to approximately $50 million annually.  Evidentiary hearings in the case commenced on September 27, 2010 and are scheduled through October 29, 2010.  The briefing schedule will be set at the conclusion of hearings.  A decision is expected by January 31, 2011.

Basic Service Rates:  Effective July 1, 2010, the rates for all basic service customers decreased to reflect the basic service solicitations conducted by WMECO in May 2010.  Basic service rates for residential customers decreased to 7.647 cents per KWh, rates for small commercial and industrial customers decreased to 8.44 cents per KWh and rates for large commercial and industrial customers decreased to 7.052 cents per KWh.  Effective October 1, 2010, the basic service rate for medium and large commercial and industrial customers increased to 8.051 cents per KWh to reflect the basic service solicitation conducted by WMECO in July 2010.  

Transition Cost Reconciliation:  On May 12, 2010, WMECO filed its 2009 cost reconciliation for transition, transmission, basic/default service, basic/default service adder, and capital projects scheduling list.  A public hearing was held on July 12, 2010.  An evidentiary hearing is scheduled for November 12, 2010 and the briefing period is scheduled to end on November 30, 2010.  We do not expect the outcome of the DPU's review of this filing to have a material adverse impact on WMECO's earnings, financial position or cash flows.  

Pension Factor Reconciliation Filing:  On July 2, 2009, WMECO filed the 2008 reconciliation for its pension factor revenues and expenses.  An evidentiary hearing was held on March 26, 2010 and the briefing period ended on May 20, 2010.  On August 31, 2010, the DPU issued an approval order.  The order did not have a material adverse impact on WMECO's earnings, financial position or cash flows.

Off-Balance Sheet Arrangements

There were no off-balance sheet arrangements identified and no material changes with regard to what was previously disclosed in our 2009 Form 10-K.

Critical Accounting Policies and Estimates Update

The preparation of financial statements in conformity with GAAP requires management to make estimates, assumptions and at times difficult, subjective or complex judgments.  Changes in these estimates, assumptions and judgments, in and of themselves, could materially impact our financial position, results of operations or cash flows.  Our management communicates to and discusses with our Audit Committee of the Board of Trustees all critical accounting policies and estimates.  The accounting policies and estimates that we believed were the most critical in nature were reported in our 2009 Form 10-K.  There have been no material changes with regard to these critical accounting policies and estimates.  

Other Matters

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Contractual Obligations and Commercial Commitments:  Refer to Note 4B, "Commitments and Contingencies – Deferred Contractual Obligations," to the unaudited condensed consolidated financial statements and also Part II, Item 1, "Legal Proceedings," for discussion of recent changes with regard to the CYAPC, YAEC, and MYAPC litigation against the DOE.  

Other than as set forth above, there have been no additional contractual obligations identified and no material changes with regard to the contractual obligations and commercial commitments previously disclosed in our 2009 Form 10-K.

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

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RESULTS OF OPERATIONS – NORTHEAST UTILITIES AND SUBSIDIARIES

The following table provides the amounts and variances in operating revenues and expense line items for the unaudited condensed consolidated statements of income for NU included in this Quarterly Report on Form 10-Q for the three and nine months ended September 30, 2010 and 2009:

	Operating Revenues and Expenses Three Months Ended September 30,								Operating Revenues and Expenses Nine Months Ended September 30,
(Millions of Dollars)	2010		2009		Increase/ (Decrease)		Percent		2010		2009		Increase/ (Decrease)		Percent
Operating Revenues	$	1,243.3	$	1,306.2	$	(62.9)	(5)	%	$	3,694.2	$	4,124.1	$	(429.9)	(10)	%
Operating Expenses:
Fuel, Purchased and Net      Interchange Power		494.1		611.6		(117.5)	(19)			1,539.7		2,034.2		(494.5)	(24)
Other Operating Expenses		233.5		250.3		(16.8)	(7)			688.4		732.6		(44.2)	(6)
Maintenance		50.0		61.6		(11.6)	(19)			162.4		166.8		(4.4)	(3)
Depreciation		71.0		77.1		(6.1)	(8)			228.7		231.8		(3.1)	(1)
Amortization of Regulatory Assets, Net		50.3		10.5		39.8	(a)			51.0		19.2		31.8	(a)
Amortization of Rate Reduction Bonds		60.4		56.7		3.7	7			175.0		163.9		11.1	7
Taxes Other Than Income Taxes		84.4		75.8		8.6	11			244.4		216.6		27.8	13
Total Operating Expenses		1,043.7		1,143.6		(99.9)	(9)			3,089.6		3,565.1		(475.5)	(13)
Operating Income	$	199.6	$	162.6	$	37.0	23	%	$	604.6	$	559.0	$	45.6	8	%

(a)

Percent greater than 100 percent not shown since not meaningful.

Operating Revenues

	Three Months Ended September 30,								Nine Months Ended September 30,
(Millions of Dollars)	2010		2009		Increase/ (Decrease)		Percent		2010		2009		Increase/ (Decrease)		Percent
Electric Distribution	$	1,010.5	$	1,082.0	$	(71.4)	(7)	%	$	2,895.0	$	3,335.2	$	(440.2)	(13)	%
Natural Gas Distribution		59.6		60.5		(0.9)	(1)			304.9		332.5		(27.6)	(8)
Total Distribution		1,070.1		1,142.5		(72.3)	(6)			3,199.9		3,667.7		(467.8)	(13)
Transmission		159.4		149.0		10.4	7			467.2		418.9		48.3	12
Total Regulated Companies		1,229.5		1,291.5		(61.9)	(5)			3,667.1		4,086.6		(419.5)	(10)
Competitive Businesses		20.9		19.6		1.3	7			62.4		61.3		1.1	2
Other and Eliminations		(7.1)		(4.9)		(2.3)	(47)			(35.3)		(23.8)		(11.5)	(49)
NU	$	1,243.3	$	1,306.2	$	(62.9)	(5)	%	$	3,694.2	$	4,124.1	$	(429.9)	(10)	%

A summary of our Regulated companies retail electric sales and firm natural gas sales for the third quarter and first nine months of 2010 were as follows:

	Three Months Ended September 30,					Nine Months Ended September 30,
	2010	2009	Increase/ (Decrease)	Percent		2010	2009	Increase/ (Decrease)	Percent
Retail Electric Sales in GWh	9,444	8,865	579	6.5	%	25,961	25,374	587	2.3	%
Firm Natural Gas Sales in Million Cubic Feet	6,031	5,486	545	9.9		29,406	29,762	(356)	(1.2)

Our Operating Revenues decreased for the three months ended September 30, 2010 as compared to the same period in 2009 due primarily to:

·

Lower electric distribution revenues related to the portions that are included in regulatory commission approved tracking mechanisms that recover certain incurred costs and do not impact earnings.  The tracked electric distribution revenues decreased due primarily to lower recovery of generation service and related congestion charges ($116 million) and lower CL&P delivery-related FMCC ($4 million), partially offset by higher retail transmission revenues ($24 million), higher transition cost recoveries ($16 million), higher wholesale revenues ($9 million) and higher C&LM collections ($4 million).  The tracking mechanisms allow for rates to be changed periodically with overcollections refunded to customers or undercollections recovered from customers in future periods.  In addition, Regulated companies revenues that eliminate in consolidation decreased by $28 million.

·

The portion of electric distribution revenues that impacts earnings increased $23 million due primarily to higher retail electric sales and PSNH's rate changes effective in July 2010.  Retail electric sales for the regulated companies increased 6.5 percent and firm natural gas sales increased 9.9 percent in the third quarter of 2010 compared with the same period in 2009.

·

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

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Our Operating Revenues decreased for the nine months ended September 30, 2010 as compared to the same period in 2009 due primarily to:

·

Lower electric distribution revenues related to the portions that are included in regulatory commission approved tracking mechanisms that recover certain incurred costs and do not impact earnings.  The tracked electric distribution revenues decreased due primarily to lower recovery of generation service and related congestion charges ($450 million) and lower CL&P delivery-related FMCC ($36 million), partially offset by higher retail transmission revenues ($51 million) and higher transition cost recoveries ($38 million).  The tracking mechanisms allow for rates to be changed periodically with overcollections refunded to customers or undercollections recovered from customers in future periods.  In addition, Regulated companies revenues that eliminate in consolidation decreased by $70 million.

·

The portion of electric distribution revenues that impacts earnings increased $27 million due primarily to higher retail electric sales and PSNH's rate changes effective in July 2010.  Retail electric sales for the Regulated companies increased 2.3 percent.  Natural gas distribution revenues decreased $28 million due primarily to decreased recovery of fuel costs and lower sales volumes.  Firm natural gas sales decreased 1.2 percent in the first nine months of 2010 compared with the same period in 2009.  

·

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

Fuel, Purchased and Net Interchange Power

Fuel, Purchased and Net Interchange Power expenses decreased for the three and nine months ended September 30, 2010 as compared to the same periods in 2009 due primarily to the following:

	September 30, 2010 Increase/(Decrease) as compared to September 30, 2009
(Millions of Dollars)	Three Months Ended	Nine Months Ended
Lower GSC supply costs, deferred fuel costs and other   purchased power costs at CL&P	$ (85.4)	$ (329.6)
An increased level of ES customer migration to third party  electric suppliers, partially offset by higher retail sales at PSNH	(26.3)	(114.0)
Lower basic/default service supply costs, partially offset by   higher expense at WMECO	(2.5)	(31.6)
Higher gas prices, partially offset by lower sales volumes at   Yankee Gas due to mild weather	(0.8)	(25.5)
Increased competitive businesses' expenses due primarily to   lower Select Energy mark-to-market gains in the first nine   months of 2010	(2.5)	6.2
	$ (117.5)	$ (494.5)

Other Operating Expenses

Other Operating Expenses decreased for the three months ended September 30, 2010 as compared to the same period in 2009 due primarily to lower Regulated companies' distribution and transmission segment expenses ($20 million), partially offset by higher competitive businesses' expenses ($2 million) and higher NU parent and other companies expenses ($2 million).

Lower Regulated companies' distribution and transmission segment expenses of $20 million were due primarily to lower costs that are recovered through distribution tracking mechanisms that have no earnings impact ($23 million), such as retail transmission, RMR and customer service expenses, and lower other operating costs ($2 million), partially offset by higher electric distribution segment expenses ($5 million), including higher pension costs and higher transmission segment expenses ($3 million).

Other Operating Expenses decreased for the nine months ended September 30, 2010 as compared to the same period in 2009 due primarily to lower Regulated companies' distribution and transmission segment expenses ($47 million) and lower competitive businesses' expenses ($1 million), partially offset by higher NU parent and other companies expenses ($3 million).

Lower Regulated companies' distribution and transmission segment expenses of $47 million were due primarily to lower costs that are recovered through distribution tracking mechanisms that have no earnings impact ($48 million), such as retail transmission, RMR and customer service expenses, and lower other operating costs ($12 million), partially offset by higher electric distribution segment expenses ($13 million), including higher pension costs and storm restoration costs and higher transmission segment expenses ($4 million).

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Maintenance

Maintenance expenses decreased for the three and nine months ended September 30, 2010 as compared to the same periods in 2009 due primarily to lower Regulated companies' distribution expenses ($13 million and $11 million, respectively), partially offset by higher transmission line expenses ($1 million and $7 million, respectively).  Distribution expenses were lower due primarily to lower overhead line expenses ($10 million and $9 million, respectively) and vegetation management work ($1 million and $2 million, respectively).

Depreciation

Depreciation expense decreased for the three and nine months ended September 30, 2010 as compared to the same periods in 2009 due primarily to a lower depreciation rate being used at CL&P as a result of the distribution rate case decision that was effective July 1, 2010.  

Amortization of Regulatory Assets, Net

Amortization of Regulatory Assets, Net increased for the three months ended September 30, 2010 due primarily to higher amortization at CL&P ($25 million) resulting from a higher recovery of transition costs, higher amortization at PSNH ($11 million), and higher amortization at WMECO ($3 million).

Amortization of Regulatory Assets, Net increased for the nine months ended September 30, 2010 due primarily to a higher recovery of CTA costs at CL&P ($35 million) and previously deferred unrecovered stranded generation costs at WMECO ($14 million), higher PSNH amortization on the SCRC tracking mechanism ($4 million) and higher CL&P amortization of the SBC balance ($3 million), partially offset by the impact of the 2010 Healthcare Act related to the write-off of previously recorded deferred tax assets that we believe are probable of recovery in future electric and natural gas distribution rates ($24 million).  

Taxes Other Than Income Taxes

	September 30, 2010 Increase/(Decrease) as compared to September 30, 2009
(Millions of Dollars)	Three Months Ended		Nine Months Ended
Connecticut Gross Earnings Tax	$	3.5	$	6.4
Property Taxes		4.6		10.6
Employee-related		0.3		1.8
Sales Taxes and Other		0.2		9.0
	$	8.6	$	27.8

The increase in Taxes Other Than Income Taxes was due primarily to an increase in property taxes as a result of an increase in Property, Plant and Equipment related to our capital programs.  The Connecticut Gross Earnings Tax increased primarily as a result of an increase in the transmission segment revenues in 2010 as compared to 2009.  The increase in Sales Taxes and Other was due primarily to the absence in 2010 of a Connecticut state sales and use tax refund.  

Interest Expense  

	Three Months Ended September 30,								Nine Months Ended September 30,
(Millions of Dollars)	2010		2009		Increase/ (Decrease)		Percent		2010		2009		Increase/ (Decrease)		Percent
Interest on Long-Term Debt	$	57.8	$	55.7	$	2.1	4	%	$	173.6	$	168.2	$	5.4	3	%
Interest on RRBs		4.7		8.7		(4.0)	(46)			17.0		28.9		(11.9)	(41)
Other Interest		3.4		5.2		(1.8)	(35)			9.8		8.5		1.3	15
	$	65.9	$	69.6	$	(3.7)	(5)	%	$	200.4	$	205.6	$	(5.2)	(3)	%

Interest Expense decreased for the three and nine months ended September 30, 2010 as compared to the same periods in 2009 due primarily to lower Interest on RRBs resulting from lower principal balances outstanding.

Other Income, Net

	Three Months Ended September 30,								Nine Months Ended September 30,
(Millions of Dollars)	2010		2009		Increase/ (Decrease)		Percent		2010		2009		Increase/ (Decrease)		Percent
Other Income, Net	$	10.1	$	9.5	$	0.6	6	%	$	19.7	$	26.1	$	(6.4)	(25)	%

Other Income, Net decreased for the nine months ended September 30, 2010 as compared to the same period in 2009 due primarily to lower investment and interest income ($7 million), lower Energy Independence Act incentives ($2 million), and higher rental expense ($2 million), offset by higher AFUDC related to equity funds ($5 million).

Income Tax Expense

	Three Months Ended September 30,								Nine Months Ended September 30,
(Millions of Dollars)	2010		2009		Increase/ (Decrease)		Percent		2010		2009		Increase/ (Decrease)		Percent
Income Tax Expense	$	41.9	$	36.2	$	5.7	16	%	$	161.1	$	130.0	$	31.1	24	%

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Income Tax Expense for the three months ended September 30, 2010 as compared to 2009 increased due primarily to higher pre-tax earnings ($15 million), partially offset by lower impacts related to items that directly impact our tax return as a result of a regulatory activity ("flow-through") and other impacts ($7 million) and the reconciliation of actual tax expense filed in the tax return to the estimated tax expense ("return to provision adjustments") ($2 million).  

Income Tax Expense for the nine months ended September 30, 2010 as compared to 2009 increased due primarily to the impacts of the 2010 Healthcare Act ($29 million) and higher pre-tax earnings ($14 million), partially offset by lower flow-through items and other impacts ($10 million) and return to provision adjustments ($2 million).

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

The following table provides the amounts and variances in operating revenues and expense line items for the unaudited condensed consolidated statements of income for CL&P included in this Quarterly Report on Form 10-Q for the three and nine months ended September 30, 2010 and 2009:

	Operating Revenues and Expenses Three Months Ended September 30,								Operating Revenues and Expenses Nine Months Ended September 30,
(Millions of Dollars)	2010		2009		Increase/ (Decrease)		Percent		2010		2009		Increase/ (Decrease)		Percent
Operating Revenues	$	789.2	$	859.3	$	(70.1)	(8)	%	$	2,292.1	$	2,598.7	$	(306.6)	(12)	%
Operating Expenses:
Fuel, Purchased and Net      Interchange Power		334.2		419.6		(85.4)	(20)			987.6		1,317.2		(329.6)	(25)
Other Operating Expenses		127.8		149.3		(21.5)	(14)			382.9		419.9		(37.0)	(9)
Maintenance		21.1		31.2		(10.1)	(32)			75.7		86.1		(10.4)	(12)
Depreciation		38.1		46.5		(8.4)	(18)			133.5		140.0		(6.5)	(5)
Amortization of Regulatory Assets, Net		33.0		7.9		25.1	(a)			55.3		24.5		30.8	(a)
Amortization of Rate Reduction Bonds		43.8		41.0		2.8	7			126.0		117.7		8.3	7
Taxes Other Than Income Taxes		59.8		53.7		6.1	11			168.0		149.7		18.3	12
Total Operating Expenses		657.8		749.2		(91.4)	(12)			1,929.0		2,255.1		(326.1)	(14)
Operating Income	$	131.4	$	110.1	$	21.3	19	%	$	363.1	$	343.6	$	19.5	6	%

(a)

Percent greater than 100 percent not shown since not meaningful.

Operating Revenues

CL&P's retail electric sales for the third quarter and first nine months of 2010 were as follows:

	Three Months Ended September 30,					Nine Months Ended September 30,
	2010	2009	Increase/ (Decrease)	Percent		2010	2009	Increase/ (Decrease)	Percent
Retail Electric Sales in GWh	6,293	5,903	390	6.6	%	17,221	16,814	407	2.4	%

CL&P's Operating Revenues decreased for the three months ended September 30, 2010 as compared to the same period in 2009 due primarily to:

·

Lower electric distribution revenues related to the portions that are included in DPUC approved tracking mechanisms that track and recover certain incurred costs and do not impact earnings.  The tracked electric distribution revenues decreased due primarily to lower GSC and supply-related FMCC revenues ($96 million) and lower delivery-related FMCC revenues ($4 million).  The lower GSC and supply-related FMCC revenues were due primarily to lower customer rates resulting from lower average supply prices and additional customer migration to third party suppliers in 2010 as compared to 2009.  The lower delivery-related FMCC revenues was due primarily to changes in projections for certain delivery-related FMCC costs for 2010 that lowered the average rate charged to customers.  These lower revenues were partially offset by higher retail transmission revenues ($12 million), higher transition cost recover ies ($9 million) and higher wholesale revenues ($9 million).  The tracking mechanisms allow for rates to be changed periodically with overcollections refunded to customers or undercollections recovered from customers in future periods.  In addition, transmission segment intracompany billings to the distribution segment that are eliminated in consolidation decreased by $19 million.

·

The portion of electric distribution revenues that impacts earnings increased $4 million due primarily to a 6.6 percent increase in retail electric sales, offset by unfavorable price variance for the three months ended September 30, 2010 compared to the same period in 2009.  

·

Improved transmission segment revenues ($9 million) resulting from a higher level of investment in this segment and the return of higher overall expenses, which are tracked and result in a related increase in revenues.  The increase in expenses is directly related to the increase in transmission plant, including costs associated with higher property taxes, depreciation and operation and maintenance expenses. 

CL&P's Operating Revenues decreased for the nine months ended September 30, 2010 as compared to the same period in 2009 due primarily to:

·

Lower electric distribution revenues related to the portions that are included in DPUC approved tracking mechanisms that track and recover certain incurred costs and do not impact earnings.  The tracked electric distribution revenues decreased due primarily to lower GSC and supply-related FMCC revenues ($316 million) and lower delivery-related FMCC revenues ($36 million).  The lower GSC and supply-related FMCC revenue were due primarily to lower customer rates resulting from lower average supply prices and additional customer migration to third party suppliers in 2010 as compared to 2009.  The lower delivery-related FMCC revenue was due primarily to changes in projections for certain delivery-related FMCC costs for 2010 that lowered the average rate charged to customers.  These lower revenues were partially offset by higher retail transmission revenues ($29 million), higher transition cost recover ies ($21 million) and higher wholesale revenues ($9 million).  The tracking mechanisms allow for rates to be changed periodically with overcollections refunded to customers or undercollections

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recovered from customers in future periods.  In addition, transmission segment intracompany billings to the distribution segment that are eliminated in consolidation decreased by $51 million.

·

The portion of electric distribution revenues that impacts earnings decreased $3 million due primarily to an unfavorable price variance offset by a 2.4 percent increase in retail electric sales for the nine months ended September 30, 2010 as compared to the same period in 2009.  

·

Improved transmission segment revenues ($34 million) resulting from a higher level of investment in this segment and the return of higher overall expenses, which are tracked and result in a related increase in revenues.  The increase in expenses is directly related to the increase in transmission plant, including costs associated with higher property taxes, depreciation and operation and maintenance expenses. 

Fuel, Purchased and Net Interchange Power

Fuel, Purchased and Net Interchange Power decreased for the three and nine months ended September 30, 2010 as compared to the same periods in 2009 due primarily to the following:

	September 30, 2010 Increase/(Decrease) as compared to September 30, 2009
(Millions of Dollars)	Three Months Ended	Nine Months Ended
GSC supply costs	$ (68.6)	$ (297.3)
Deferred fuel costs	(10.5)	(10.1)
Other purchased power costs	(6.3)	(22.2)
	$ (85.4)	$ (329.6)

The decrease in GSC supply costs was due primarily to lower average supply prices and additional customer migration to third-party suppliers in 2010 as compared to 2009.  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.  The decrease in deferred fuel costs was due primarily to a smaller net overrecovery in 2010 as compared to 2009.  These costs are included in DPUC approved tracking mechanisms and do not impact earnings.  

Other Operating Expenses

Other Operating Expenses decreased for the three months ended September 30, 2010 as compared to the same period in 2009 as a result of lower costs that are recovered through distribution tracking mechanisms and have no earnings impact ($27 million) including RMR ($22 million) and retail transmission ($8 million), partially offset by higher distribution segment expenses ($3 million) mainly as a result of higher administrative and general expenses, including higher pension costs, and higher transmission segment expenses ($2 million).

Other Operating Expenses decreased for the nine months ended September 30, 2010 as compared to the same period in 2009 as a result of lower costs that are recovered through distribution tracking mechanisms and have no earnings impact ($54 million) including RMR ($25 million), retail transmission ($24 million), and certain customer services expenses ($9 million), partially offset by higher distribution segment expenses ($15 million) mainly as a result of higher administrative and general expenses, including higher pension costs, and higher transmission segment expenses ($3 million).

Maintenance

Maintenance expenses decreased for the three and nine months ended September 30, 2010 as compared to the same period in 2009 due primarily to lower distribution overhead line expenses ($12 million and $17 million, respectively).  These lower costs were offset by higher transmission segment expenses ($1 million and $5 million, respectively) and an increase in vegetation management work ($1 million and $1 million, respectively).

Depreciation

Depreciation expense decreased for the three and nine months ended September 30, 2010 as compared to the same periods in 2009 due primarily to a lower depreciation rate being used as a result of the distribution rate case decision that was effective July 1, 2010.  

Amortization of Regulatory Assets, Net

Amortization of Regulatory Assets, Net, increased for the three and nine months ended September 30, 2010 as compared to the same periods in 2009 due primarily to higher retail CTA revenue ($8 million and $17 million, respectively) and lower CTA transition costs ($14 million and $18 million, respectively).  Partially offsetting these increases was a deferral of previously written-off deferred tax assets related to the 2010 Healthcare Act that we believe are probable of recovery in future electric distribution rates.

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Taxes Other Than Income Taxes

	September 30, 2010 Increase/(Decrease) as compared to September 30, 2009
(Millions of Dollars)	Three Months Ended		Nine Months Ended
Connecticut Gross Earnings Tax	$	3.5	$	7.7
Property Taxes		2.7		4.6
Employee-related		0.1		0.8
Sales Taxes and Other		(0.2)		5.2
	$	6.1	$	18.3

The increase in Taxes Other Than Income Taxes was due primarily to an increase in property taxes as a result of an increase in Property, Plant and Equipment related to CL&P's capital programs.  The increase in the Connecticut Gross Earnings Tax was due primarily to the increase in the transmission segment revenues in 2010 as compared to 2009.  The increase in Sales Tax and Other was due primarily to the absence in 2010 of a Connecticut state sales and use tax refund.  

Interest Expense

	Three Months Ended September 30,								Nine Months Ended September 30,
(Millions of Dollars)	2010		2009		Increase/ (Decrease)		Percent		2010		2009		Increase/ (Decrease)		Percent
Interest on Long-Term Debt	$	33.7	$	33.5	$	0.2	1	%	$	100.9	$	99.5	$	1.4	1	%
Interest on RRBs		1.5		4.5		(3.0)	(67)			6.8		15.3		(8.5)	(56)
Other Interest		1.5		2.8		(1.3)	(46)			4.7		1.4		3.3	(a)
Total Interest Expense	$	36.7	$	40.8	$	(4.1)	(10)	%	$	112.4	$	116.2	$	(3.8)	(3)	%

(a)

Percent greater than 100 percent not shown since not meaningful.

Interest Expense decreased for the three and nine months ended September 30, 2010 as compared to the same periods in 2009 due primarily to lower Interest on RRBs resulting from lower principal balances outstanding.  

Other Income, Net

	Three Months Ended September 30,								Nine Months Ended September 30,
(Millions of Dollars)	2010		2009		Increase/ (Decrease)		Percent		2010		2009		Increase/ (Decrease)		Percent
Other Income, Net	$	6.9	$	7.1	$	(0.2)	(3)	%	$	12.6	$	17.9	$	(5.3)	(30)	%

Other Income, Net decreased for the nine months ended September 30, 2010 as compared to the same period in 2009 due primarily to lower investment income ($4 million) and Energy Independence Act incentives ($2 million).

Income Tax Expense

	Three Months Ended September 30,								Nine Months Ended September 30,
(Millions of Dollars)	2010		2009		Increase/ (Decrease)		Percent		2010		2009		Increase/ (Decrease)		Percent
Income Tax Expense	$	32.6	$	29.8	$	2.8	9	%	$	101.7	$	87.2	$	14.5	17	%

Income Tax Expense increased for the three months ended September 30, 2010 as compared to the same period in 2009 due primarily to higher pre-tax earnings ($9 million), partially offset by lower flow-through impacts ($4 million) and return to provision adjustments ($2 million).

Income Tax Expense increased for the nine months ended September 30, 2010 as compared to the same period in 2009 due primarily to the impacts of the 2010 Healthcare Act ($16 million) and higher pre-tax earnings ($5 million); partially offset by lower flow-through impacts ($3 million) and return to provision adjustments ($2 million).

LIQUIDITY

CL&P had cash flows provided by operating activities in the first nine month of 2010 of $343.2 million, compared with operating cash flows of $343.8 million in the first nine months of 2009 (amounts are net of RRB payments, which are included in financing activities). The slight decrease in cash flows was due primarily to an increase in income tax payments of approximately $33 million largely attributable to the absence of bonus depreciation tax deductions under the American Recovery and Reinvestment Act of 2009 in the first nine months of 2010.  Offsetting the higher tax payments was a decrease in payments made related to CL&P's accounts payable in support of its operating activities.   

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Although bonusdepreciation tax deductions expired at the end of 2009, on September 27, 2010, President Obama signed into law the Small Business Jobs and Credit Act of 2010 that included an extension of these tax deductions through 2010.  As a result, CL&P's 2010 cash flows from operations are projected to increase by approximately $40 million.  CL&P now projects 2010 cash flows from operations (after RRB payments) of approximately $460 million, up from its previous projection of approximately $425 million.  

On September 24, 2010, CL&P, together with PSNH, WMECO, and Yankee Gas, entered into a three-year $400 million unsecured revolving credit facility, which expires on September 24, 2013.  This facility replaced a similar 5-year $400 million credit facility that was scheduled to expire on November 6, 2010.  CL&P may draw up to $300 million under this facility, subject to the $400 million maximum aggregate borrowing limit, either on a short-term or a long-term basis subject to regulatory approval.  As of September 30, 2010, CL&P had no borrowings under this facility.  Other financing activities for the nine months ended September 30, 2010 included $181.8 million in common dividends paid to NU parent.  

On November 1, 2010, the DPUC approved CL&P's application requesting authority to issue up to $900 million in long-term debt through 2014 to be used to refinance CL&P's short-term debt previously incurred in the ordinary course of business, to finance capital expenditures, to provide working capital and to pay issuance costs.  

CL&P anticipates no additional long-term debt issuances for the remainder of 2010.  

Cash capitalexpenditures 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 $274.2 million for the nine months ended September 30, 2010, compared with $331.6 million for the nine months ended September 30, 2009.

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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, 2010 and 2009:

	Operating Revenues and Expenses Three Months Ended September 30,								Operating Revenues and Expenses Nine Months Ended September 30,
(Millions of Dollars)	2010		2009		Increase/ (Decrease)		Percent		2010		2009		Increase/ (Decrease)		Percent
Operating Revenues	$	277.0	$	275.1	$	1.9	1	%	$	773.9	$	845.7	$	(71.8)	(8)	%
Operating Expenses:
Fuel, Purchased and Net      Interchange Power		94.1		120.4		(26.3)	(22)			281.2		395.2		(114.0)	(29)
Other Operating Expenses		53.1		55.0		(1.9)	(3)			172.3		176.3		(4.0)	(2)
Maintenance		21.0		22.3		(1.3)	(6)			62.6		58.7		3.9	7
Depreciation		17.5		15.6		1.9	12			49.4		46.1		3.3	7
Amortization of Regulatory Assets/     (Liabilities), Net		14.5		3.2		11.3	(a)			(2.8)		(1.7)		(1.1)	(65)
Amortization of Rate Reduction Bonds		12.8		12.1		0.7	6			37.5		35.3		2.2	6
Taxes Other Than Income Taxes		14.2		12.4		1.8	15			40.6		34.4		6.2	18
Total Operating Expenses		227.2		241.0		(13.8)	(6)			640.8		744.3		(103.5)	(14)
Operating Income	$	49.8	$	34.1	$	15.7	46	%	$	133.1	$	101.4	$	31.7	31	%

(a)

Percent greater than 100 percent not shown since not meaningful.

Operating Revenues

PSNH's retail electric sales for the third quarter and first nine months of 2010 were as follows:

	Three Months Ended September 30,					Nine Months Ended September 30,
	2010	2009	Increase/ (Decrease)	Percent		2010	2009	Increase/ (Decrease)	Percent
Retail Electric Sales in GWh	2,147	2,009	138	6.9	%	5,934	5,822	112	1.9	%

PSNH's Operating Revenues increased for the three months ended September 30, 2010 as compared to the same period in 2009 due primarily to:

·

An $18 million increase related to the distribution retail rate increase effective in July 2010 that impacted earnings and higher sales volume.  Offsetting this increase was a decrease of $17 million of distribution segment revenues that did not impact earnings.  Of this decrease, $18 million related to lower recovery of purchased fuel and power costs and $7 million related to lower transmission segment intracompany billings to the distribution segment that are eliminated in consolidation, offset by higher retail transmission revenues ($10 million) and an increase in the SCRC ($4 million).  The tracking mechanisms allow for rates to be changed periodically with overcollections refunded to customers and undercollections to be recovered from customers in future periods.

PSNH's Operating Revenues decreased for the nine months ended September 30, 2010 as compared to the same period in 2009 due primarily to:

·

A $108 million decrease in distribution segment revenues that did not impact earnings.  Of this decrease, $106 million related to lower recovery of purchased fuel and power costs and $13 million in lower transmission segment intracompany billings to the distribution segment that are eliminated in consolidation, offset by higher retail transmission revenues ($19 million) and an increase in the SCRC ($11 million).  The tracking mechanisms allow for rates to be changed periodically with overcollections refunded to customers and undercollections to be recovered from customers in future periods.

·

A $28 million increase in distribution segment revenues that impacts earnings primarily as a result of the retail rate increase effective in July 2010 and higher sales volume.

·

A $7 million improvement in transmission segment revenues resulting from a higher level of investment in this segment and the return of higher overall expenses, which are tracked and result in a related increase in revenues.  The increase in expenses are directly related to the increase in transmission plant, including costs associated with higher property taxes, depreciation and operation and maintenance expenses.

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Fuel, Purchased and Net Interchange Power

Fuel, Purchased and Net Interchange Power decreased for the three and nine months ended September 30, 2010 as compared to the same periods in 2009 due primarily to an increased level of ES customer migration to third party electric suppliers, partially offset by higher retail sales.  

Other Operating Expenses

Other Operating Expenses decreased for the three months ended September 30, 2010 as compared to the same period in 2009 due primarily to lower distribution segment expenses ($1 million) and lower costs that are recovered through distribution tracking mechanisms and have no earnings impact ($1 million).

Other Operating Expenses decreased for the nine months ended September 30, 2010 as compared to the same period in 2009 due primarily to lower distribution segment expenses ($7 million), mainly as a result of the rate case decision changing the collection of certain expenses to be tracked through the TCAM and lower administrative and general expenses, partially offset by higher costs that are recovered through distribution tracking mechanisms and have no earnings impact ($3 million).

Maintenance

Maintenance expenses decreased for the three months September 30, 2010 as compared to the same period in 2009 due primarily to lower boiler equipment and maintenance costs ($3 million) and a decrease in vegetation management work ($1 million), offset by higher distribution overhead line expenses ($2 million).

Maintenance expenses increased for the nine months ended September 30, 2010 as compared to the same period in 2009 due primarily to higher distribution overhead line expenses ($7 million), offset by a decrease in vegetation management work ($2 million).

Depreciation

Depreciation expense increased for the three and nine months ended September 30, 2010 as compared to the same periods in 2009 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

Amortization of Regulatory Assets/(Liabilities), Net increased for the three months ended September 30, 2010 compared to the same period in 2009 due primarily to an increase in net deferrals associated with the ES tracking mechanism, including net NWPP accruals ($5 million), and decreases in the TCAM ($5 million) and SCRC ($2 million) tracking mechanism deferrals.

Amortization of Regulatory Assets/(Liabilities), Net decreased for the nine months ended September 30, 2010 as compared to the same period in 2009 due primarily to a net decrease in NWPP accruals ($4 million), an increase in the ES deferral ($1 million) and the deferral of income tax write-offs associated with the 2010 Healthcare Act ($5 million), offset by decreases in the TCAM ($6 million) and SCRC ($4 million) tracking mechanism deferrals.

Taxes Other Than Income Taxes

	September 30, 2010 Increase/(Decrease) as compared to September 30, 2009
(Millions of Dollars)	Three Months Ended		Nine Months Ended
Property Taxes	$	1.8	$	4.3
Employee-related		0.1		0.6
Sales Taxes and Other		(0.1)		1.3
	$	1.8	$	6.2

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

Interest Expense

	Three Months Ended September 30,								Nine Months Ended September 30,
(Millions of Dollars)	2010		2009		Increase/ (Decrease)		Percent		2010		2009		Increase/ (Decrease)		Percent
Interest on Long-Term Debt	$	9.0	$	8.2	$	0.8	10	%	$	27.7	$	24.6	$	3.1	13	%
Interest on RRBs		2.3		3.1		(0.8)	(26)			7.5		10.2		(2.7)	(26)
Other Interest		0.2		0.4		(0.2)	(50)			0.6		-		0.6	(a)
	$	11.5	$	11.7	$	(0.2)	(2)	%	$	35.8	$	34.8	$	1.0	3	%

Interest Expense increased for the nine months ended September 30, 2010 as compared to the same period in 2009 due primarily to higher Interest on Long-Term Debt resulting from the $150 million debt issuance in December 2009, offset by lower Interest on RRBs resulting from lower principal balances outstanding.  

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Other Income, Net

	Three Months Ended September 30,								Nine Months Ended September 30,
(Millions of Dollars)	2010		2009		Increase/ (Decrease)		Percent		2010		2009		Increase/ (Decrease)		Percent
Other Income, Net	$	3.7	$	2.2	$	1.5	68	%	$	5.9	$	6.5	$	(0.6)	(9)	%

Other Income, Net increased for the three months ended September 30, 2010 as compared to the same period in 2009 due to an increase in AFUDC related to equity funds.  

Income Tax Expense

	Three Months Ended September 30,								Nine Months Ended September 30,
(Millions of Dollars)	2010		2009		Increase/ (Decrease)		Percent		2010		2009		Increase/ (Decrease)		Percent
Income Tax Expense	$	13.2	$	8.5	$	4.7	55	%	$	37.0	$	22.8	$	14.2	62	%

Income Tax Expense increased for the three months ended September 30, 2010 as compared to the same period in 2009 due primarily to higher pre-tax earnings.

Income Tax Expense increased for the nine months ended September 30, 2010 as compared to the same period in 2009 due primarily to higher pre-tax earnings ($8 million) and the impacts of the 2010 Healthcare Act ($6 million).

LIQUIDITY

PSNH had cash flows provided by operating activities in the first nine months of 2010 of $139 million, compared with operating cash flows of $66.7 million in the first nine months of 2009 (amounts are net of RRB payments, which are included in financing activities). The improved cash flows were due primarily to the absence in 2010 of costs related to the major storm in December 2008 that were paid in the first quarter of 2009 and a decrease in Fuel, Materials and Supplies attributable to a $27.2 million reduction in coal inventory levels at the generation business as ordered by the NHPUC.  Offsetting these favorable cash flow impacts was a $45 million contribution made in the third quarter of 2010 into the NU Pension Plan and payments made relating to the February 2010 severe storm for which the costs were deferred.  PSNH expects to develop a recovery plan for these 2010 storm costs, net of any insurance payments PSNH would rec eive, through a previously agreed upon cooperative effort between PSNH, the NHPUC Staff, and the Office of Consumer Advocate as outlined in the joint settlement of PSNH's distribution rate case that was effective July 1, 2010.

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RESULTS OF OPERATIONS – WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY

The following table provides the amounts and variances in operating revenues and expense line items for the unaudited condensed consolidated statements of income for WMECO included in this Quarterly Report on Form 10-Q for the three and nine months ended September 30, 2010 and 2009:

	Operating Revenues and Expenses Three Months Ended September 30,								Operating Revenues and Expenses Nine Months Ended September 30,
(Millions of Dollars)	2010		2009		Increase/ (Decrease)		Percent		2010		2009		Increase/ (Decrease)		Percent
Operating Revenues	$	103.7	$	96.6	$	7.1	7	%	$	296.4	$	309.8	$	(13.4)	(4)	%
Operating Expenses:
Fuel, Purchased and Net      Interchange Power		39.9		42.4		(2.5)	(6)			120.3		151.9		(31.6)	(21)
Other Operating Expenses		27.3		19.0		8.3	44			73.6		64.5		9.1	14
Maintenance		5.0		5.2		(0.2)	(4)			14.8		13.4		1.4	10
Depreciation		5.8		5.6		0.2	4			17.7		16.8		0.9	5
Amortization of Regulatory Assets/     (Liabilities), Net		2.7		(0.4)		3.1	(a)			0.4		(3.7)		4.1	(a)
Amortization of Rate Reduction Bonds		3.8		3.6		0.2	6			11.5		10.8		0.7	6
Taxes Other Than Income Taxes		4.3		4.1		0.2	5			12.5		10.5		2.0	19
Total Operating Expenses		88.8		79.5		9.3	12			250.8		264.2		(13.4)	(5)
Operating Income	$	14.9	$	17.1	$	(2.2)	(13)	%	$	45.6	$	45.6	$	-	-	%

(a)

Percent greater than 100 percent not shown since not meaningful.

Operating Revenues

WMECO's retail electric sales for the third quarter and first nine months of 2010 were as follows:

	Three Months Ended September 30,					Nine Months Ended September 30,
	2010	2009	Increase/ (Decrease)	Percent		2010	2009	Increase/ (Decrease)	Percent
Retail Electric Sales in GWh	1,009	957	52	5.5	%	2,818	2,749	69	2.5	%

WMECO's Operating Revenues increased for the three months ended September 30, 2010 as compared to the same period in 2009 due primarily to:

·

A $6 million increase related to distribution segment revenues that did not impact earnings and was included in DPU approved tracking mechanisms that track the recovery of certain incurred costs through WMECO's tariffs.  A $3 million increase related to C&LM collections, $2 million of these distribution segment revenues related to higher transition cost recoveries and $1 million related to higher retail transmission revenues.  Offsetting these increases was a lower recovery of energy supply costs of $2 million.  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.  In addition, transmission segment intracompany billings to the distribution segment that are eliminated in consolidation increased by $2 million.  

·

A $1 million increase that impacted earnings relating to a 5.5 percent increase in the retail electric sales for the three months ended September 30, 2010 as compared to the same period in 2009.  

·

A $1 million improvement in transmission segment revenues resulting from a higher level of investment in this segment and the return of higher overall expenses, which are tracked and result in a related increase in revenues.  The increase in expenses are directly related to the increase in transmission plant, including costs associated with higher property taxes, depreciation and operation and maintenance expenses.

WMECO's Operating Revenues decreased for the nine months ended September 30, 2010 as compared to the same period in 2009 due primarily to:

·

A decrease of $21 million related to distribution segment revenues that did not impact earnings and was included in DPU approved tracking mechanisms that track the recovery of certain incurred costs through WMECO's tariffs.  A decrease of $29 million related to a lower recovery of energy supply costs and a decrease of $6 million related to transmission segment intracompany billings to the distribution segment that are eliminated in consolidation.  Offsetting these decreases were increases in retail transmission revenues, C&LM collections and transition cost recoveries of $3 million, $3 million and $6 million, respectively.  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.

·

A $7 million improvement in transmission segment revenues resulting from a higher level of investment in this segment and the return of higher overall expenses, which are tracked and result in a related increase in revenues.  The increase in expenses are directly related to the increase in transmission plant, including costs associated with higher property taxes, depreciation and operation and maintenance expenses.

79

Fuel, Purchased and Net Interchange Power

Fuel, Purchased and Net Interchange Power decreased in 2010 due primarily to lower basic/default service supply costs.  The basic/default service supply costs are the contractual amounts we must pay to various suppliers that serve this load after winning a competitive solicitation process.  These costs decreased due primarily to lower supplier contract rates, partially offset by increased load volumes.  

Other Operating Expenses

Other Operating Expenses increased $8 million for the three months ended September 30, 2010 as compared to the same period in 2009 as a result of higher costs that are recovered through distribution tracking mechanisms and have no earnings impact ($4 million), such as certain customer service expenses, and higher distribution segment expenses ($3 million) resulting from higher administrative and general expenses, including pension costs.

Other Operating Expenses increased $9 million for the nine months ended September 30, 2010 as compared to the same period in 2009 as a result of higher distribution segment expenses ($5 million) resulting from higher administrative and general expenses, including pension costs, higher costs that are recovered through distribution tracking mechanisms and have no earnings impact ($3 million), and higher transmission segment expenses ($1 million).

Maintenance

Maintenance expenses increased for the nine months ended September 30, 2010 as compared to the same period in 2009 due primarily to higher overhead lines expenses including higher storm restoration expenses.  

Amortization of Regulatory Assets/(Liabilities), Net

Amortization of Regulatory Assets/(Liabilities), Net, increased for the three and nine months ended September 30, 2010 as compared to the same periods in 2009 due primarily to the recovery of the previously deferred unrecovered stranded generation costs.  

Taxes Other Than Income Taxes

	September 30, 2010 Increase/(Decrease) as compared to September 30, 2009
(Millions of Dollars)	Three Months Ended		Nine Months Ended
Property Taxes	$	(0.2)	$	1.1
Employee-related		0.1		0.3
Sales Taxes and Other		0.3		0.6
	$	0.2	$	2.0

The increase in Taxes Other Than Income Taxes for the nine months ended September 30, 2010 as compared to the same period in 2009 was due primarily to an increase in property taxes as a result of an increase in Property, Plant and Equipment related to WMECO's capital programs.  

Interest Expense

	Three Months Ended September 30,								Nine Months Ended September 30,
(Millions of Dollars)	2010		2009		Increase/ (Decrease)		Percent		2010		2009		Increase/ (Decrease)		Percent
Interest on Long-Term Debt	$	4.7	$	3.5	$	1.2	34	%	$	13.3	$	10.5	$	2.8	27	%
Interest on RRBs		0.8		1.1		(0.3)	(27)			2.6		3.3		(0.7)	(21)
Other Interest		0.1		0.2		(0.1)	(50)			0.3		0.7		(0.4)	(57)
	$	5.6	$	4.8	$	0.8	17	%	$	16.2	$	14.5	$	1.7	12	%

Interest Expense increased for the nine months ended September 30, 2010 as compared to the same period in 2009 due primarily to higher Interest on Long-Term Debt resulting from the $95 million debt issuance in March 2010, offset by lower Interest on RRBs resulting from lower principal balances outstanding.  

Other Income, Net

	Three Months Ended September 30,								Nine Months Ended September 30,
(Millions of Dollars)	2010		2009		Increase/ (Decrease)		Percent		2010		2009		Increase/ (Decrease)		Percent
Other Income, Net	$	0.7	$	0.2	$	0.5	(a)	%	$	1.5	$	1.1	$	0.4	36	%

(a)

Percent greater than 100 percent not shown since not meaningful.

Income Tax Expense

	Three Months Ended September 30,								Nine Months Ended September 30,
(Millions of Dollars)	2010		2009		Increase/ (Decrease)		Percent		2010		2009		Increase/ (Decrease)		Percent
Income Tax Expense	$	2.7	$	4.0	$	(1.3)	(33)	%	$	12.6	$	11.8	$	0.8	7	%

80

Income Tax Expense decreased for the three months ended September 30, 2010 as compared to the same period in 2009 due primarily to lower pre-tax earnings.

Income Tax Expense increased for the nine months ended September 30, 2010 as compared to the same period in 2009 due primarily to the impacts of the 2010 Healthcare Act ($3 million) partially offset by lower pre-tax earnings and flow-through impacts ($2 million).

LIQUIDITY

WMECO had cash flows provided by operating activities in the first nine months of 2010 of $19.1 million, compared with cash flows provided by operating activities of $27.7 million in the first nine months of 2009 (amounts are net of RRB payments, which are included in financing activities).  The decreased cash flows in 2010 were due primarily to an increase in income tax payments of approximately $4.5 million largely attributable to the absence of bonus depreciation tax deductions under the American Recovery and Reinvestment Act of 2009 in the first nine months of 2010.  Offsetting the unfavorable cash flow impact is the absence in 2010 of costs related to the major storm in December 2008 that were paid in the first quarter of 2009.  These costs were deferred and are expected to be recovered from customers.  WMECO filed a distribution rate case on July 16, 2010, which includes a request for more timely recovery of the December 2008 storm costs.  In addition, WMECO incurred and paid costs related to two major storms in May 2010.  WMECO expects the costs associated with these major storms will be recoverable through a combination of customer-funded reserves that are established for the purpose of recovering major storm costs and current distribution revenues.  The deferral of these major storms costs in 2010 created an unfavorable cash flow impact to WMECO's regulatory underrecoveries of approximately $6.1 million.

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ITEM 3.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Market Risk Information

Commodity Price Risk Management:  Our Regulated companies enter into energy contracts to serve our customers and the economic impacts of those contracts are passed on to our customers.  Accordingly, the Regulated companies have no exposure to loss of future earnings or fair values due to these market risk-sensitive instruments.  The wholesale portfolio held by Select Energy includes contracts that are market-risk sensitive, including a wholesale energy sales contract through 2013 with an agency comprised of municipalities with approximately 0.4 million remaining MWh of supply contract volumes, net of related sales volumes.  Select Energy also has a non-derivative energy contract that expires in mid-2012 to purchase output from a generation facility, which is also exposed to market price volatility.  As Select Energy's contract volumes are winding down, and as the wholesale energy sales contract is s ubstantially hedged against price risks, we have limited exposure to commodity price risks.  We have no energy contracts entered into for trading purposes.

Sensitivity analysis provides a presentation of the potential loss of future pre-tax earnings and fair values from our market risk-sensitive contracts due to one or more hypothetical changes in commodity price components, or other similar price changes.  We have provided this analysis in Part II, Item 7A, "Quantitative and Qualitative Disclosures about Market Risk," in our 2009 Form 10-K, which disclosures are incorporated herein by reference.  There have been no additional market or commodity price risks identified and no material changes with regard to the sensitivity analysis previously disclosed in our 2009 Form 10-K.

Other Risk Management Activities

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

Credit Risk Management: Credit risk relates to the risk of loss that we would incur as a result of non-performance by counterparties pursuant to the terms of our contractual obligations.  We serve a wide variety of customers and suppliers that include IPPs, industrial companies, gas and electric utilities, oil and gas producers, financial institutions, and other energy marketers.  Margin accounts exist within this diverse group, and we realize interest receipts and payments related to balances outstanding in these margin accounts.  This wide customer and supplier mix generates a need for a variety of contractual structures, products and terms that, in turn, require us to manage the portfolio of market risk inherent in those transactions in a manner consistent with the parameters established by our risk management process.

We have provided additional disclosures regarding interest rate risk management and credit risk management in Part II, Item 7A, "Quantitative and Qualitative Disclosures about Market Risk," in our 2009 Form 10-K, which are incorporated herein by reference. There have been no additional risks identified and no material changes with regard to the items previously disclosed in our 2009 Form 10-K.

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

ITEM 4.

CONTROLS AND PROCEDURES

Management, on behalf of NU, CL&P, PSNH and WMECO, evaluated the design and operation of the disclosure controls and procedures as of September 30, 2010 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. &n bsp;The principal executive officers and principal financial officer have concluded, based on their review, that the disclosure controls and procedures of NU, CL&P, PSNH and WMECO are effective to ensure that information required to be disclosed by us in reports filed under the Securities Exchange Act of 1934 (i) is recorded, processed, summarized, and reported within the time periods specified in SEC rules and regulations and (ii) is accumulated and communicated to management, including the principal executive officers and principal financial officer, as appropriate to allow timely decisions regarding required disclosures.

There have been no changes in internal controls over financial reporting for NU, CL&P, PSNH and WMECO during the quarter ended September 30, 2010 that have materially affected, or are reasonably likely to materially affect, internal controls over financial reporting.  

82

PART II.  OTHER INFORMATION

ITEM 1.

LEGAL PROCEEDINGS

We are parties to various legal proceedings.  We have identified these legal proceedings in Part I, Item 3, "Legal Proceedings," and elsewhere in our 2009 Form 10-K, which disclosures are incorporated herein by reference.  Other than as set forth below, there have been no additional legal proceedings identified and no material changes with regard to the legal proceedings previously disclosed in our 2009 Form 10-K.

Litigation Relating To The Merger

In October 2010, NSTAR and the members of the NSTAR board of trustees (collectively "NSTAR defendants") and NU, along with NU Holding Energy 1 LLC and NU Holding Energy 2 LLC, two wholly-owned subsidiaries of NU (collectively "NU defendants") were named defendants in nine separate purported class action lawsuits filed in the Suffolk Superior Court (eight of the cases) and the United States District Court for the District of Massachusetts (one case):  Breene v. NSTAR, et al.;Glickman v. NSTAR, et al.;Silver v. May, et al.;Fitzpatrick v. NSTAR, et al.;Ferkauf v. NSTAR, et al.;Alten-Mangels v. NSTAR, et al.;Himmel v. NSTAR, et al.;Orlando v. NSTAR, et al.; andKeuriam v. NSTAR,et al.  The cases were brought on behalf of proposed classes consisting of holders of NSTAR common shares, excluding the defendants and their affiliates.   The complaints allege, among other things, that the individual NSTAR defendants breached their fiduciary duties by failing to maximize the value to be received by NSTAR's public shareholders, and that the NU defendants aided and abetted the individual NSTAR defendants' breaches of fiduciary duties.  The complaints seek, among other things, (a) to enjoin defendants from consummating the merger; (b) rescission of the merger, if completed and/or (c) granting the class members any profits or benefits allegedly improperly received by defendants in connection with the merger.  NU believes the cases have no merit and will respond to these actions in due course and intends to defend the actions vigorously.

Yankee Companies v. U.S. Department of Energy

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.

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 September 7, 2010, the trial court issued its decision following remand and on September 9, 2010, judgment on the decision was entered.  The judgment awarded CYAPC $39.7 million, YAEC $21.2 million, and MYAPC $81.7 million.  Parties have 30 days to file motions for reconsideration and 60 days to file any appeals (a filing stops the clock on appeal periods).  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.  If no motions for reconsideration are filed, the deadline for filing appeals of the decision would be November 8, 2010.  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.

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 Part 1, Item 2, "Management's Discussion and Analysis of Financial Condition and Results of Operations," of this Quarterly Report on Form 10-Q.  We have identified a number of these risk factors in Item 1A, "Risk Factors," in our 2009 Form 10-K, which risk factors are incorporated herein by reference.  These risk factors should be considered carefully in evaluating our risk profile.  The risk factors discussed below are related to our pending merger with NSTAR (the "Merger").  They should be read in conjunction with and supplement the risk factors disclosed in our 2009 Form 10-K.

We may be unable to satisfy the conditions or obtain the approvals required to complete the Merger or such approvals may contain material restrictions or conditions.

The Merger is subject to numerous conditions, including approval of the shareholders of both NU and NSTAR, the approval of various government agencies and the expiration or termination of the Hart Scott Rodino Act waiting period.  Governmental agencies may not approve the Merger or such approvals may impose conditions on the completion, or require changes to the terms of the Merger, including restrictions on the business, operations or financial performance of the combined company, which could be adverse to the company's interests.  These conditions or changes could also delay or increase the cost of the Merger or limit the net income or financial prospects of the combined company.

83

We will be subject to business uncertainties and contractual restrictions while the Merger is pending.

The work required to complete the Merger may place a significant burden on management and internal resources.  Management's attention and other company resources may be focused on the Merger instead of on day-to-day management activities, including pursuing other opportunities beneficial to NU.  In addition, while the Merger is pending our business operations are restricted by the Agreement and Plan of Merger to ordinary course of business activities consistent with past practice, which may cause us to forgo otherwise beneficial business opportunities.

We may lose management personnel and other key employees and be unable to attract and retain such personnel and employees.

Uncertainties about the effect of the Merger on management personnel and employees may impair our ability to attract, retain and motivate key personnel until the Merger is completed and for a period of time thereafter, which could affect our financial performance.

The Merger may not be completed, which may have an adverse effect on our share price and future business and financial results and we could face litigation concerning the Merger, whether or not the Merger is consummated.

Failure to complete the Merger could negatively affect NU's share price, as well as our future business and financial results.  In addition, purported class actions have been brought against us, NSTAR and others on behalf of holders of NSTAR common shares.  If these actions or similar actions that may be brought are successful, the costs of completing the Merger could increase, or the Merger could be delayed or prevented.  We cannot make any assurances that we will succeed in any litigation brought in connection with the Merger.  See Item 1, Part II,Legal Proceedings, in this Quarterly Report on Form 10-Q for discussion of pending litigation related to the Merger.  

If the Merger is not completed, we may be required to pay NSTAR, under specified circumstances set forth in the Merger Agreement, a termination fee of $135 million plus up to $35 million of certain expenses incurred by NSTAR.  In addition, we must pay our own costs related to the Merger including, among others, legal, accounting, advisory, financing fees, filing and printing costs, whether the Merger is completed or not.  Further, if the Merger is not completed, we could be subject to litigation related to the failure to complete the Merger or other factors, which may adversely affect our business, financial results and share price.

If completed, the Merger may not achieve its intended results.

We entered into the Merger Agreement with the expectation that the Merger would result in various benefits.  If the Merger is completed, achieving the anticipated benefits will be subject to a number of uncertainties, including whether our businesses can be integrated in an efficient and effective manner.  Failure to achieve these anticipated benefits could adversely affect our business, financial results and share price.   

ITEM 2.

UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

There were no purchases made by or on behalf of NU or any "affiliated purchaser" (as defined in Rule 10b-18(a)(3) under the Securities Exchange Act of 1934) of NU common shares during the quarter ended September 30, 2010.

84

ITEM 6.

EXHIBITS

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

Exhibit No.

Description

Listing of Exhibits (NU)

*10

Credit Agreement, dated as of September 24, 2010, among Northeast Utilities, the Banks named therein, Union Bank, N.A., as Administrative Agent, and Barclays Bank PLC, Citibank, N.A., JPMorgan Chase Bank, N.A. and Union Bank, N.A., as Fronting Banks

*12

Ratio of Earnings to Fixed Charges

*15

Deloitte & Touche LLP Letter Regarding Unaudited Financial Information

*31

Certification of Charles W. Shivery, Chairman, President and Chief Executive Officer of Northeast Utilities, required by Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated November 5, 2010

*31.1

Certification of David R. McHale, Executive Vice President and Chief Financial Officer of Northeast Utilities, required by Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated November 5, 2010

*32

Certification of Charles W. Shivery, Chairman, President and Chief Executive Officer of Northeast Utilities and David R. McHale, Executive Vice President and Chief Financial Officer of Northeast Utilities, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, dated November 5, 2010

*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)

*10

Credit Agreement dated as of September 24, 2010, among The Connecticut Light and Power Company, Western Massachusetts Electric Company, Yankee Gas Services Company and Public Service Company of New Hampshire, the Banks named therein, and Citibank, N.A. as Administrative Agent

*12

Ratio of Earnings to Fixed Charges

*31

Certification of Leon J. Olivier, Chief Executive Officer of The Connecticut Light and Power Company, required by Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated November 5, 2010

*31.1

Certification of David R. McHale, Executive Vice President and Chief Financial Officer of The Connecticut Light and Power Company, required by Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated November 5, 2010

*32

Certification of Leon J. Olivier, Chief Executive Officer of The Connecticut Light and Power Company and David R. McHale, Executive Vice President and Chief Financial Officer of The Connecticut Light and Power Company, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, dated November 5, 2010

85

Listing of Exhibits (PSNH)

*10

Credit Agreement dated as of September 24, 2010, among The Connecticut Light and Power Company, Western Massachusetts Electric Company, Yankee Gas Services Company and Public Service Company of New Hampshire, the Banks named therein, and Citibank, N.A. as Administrative Agent

*12

Ratio of Earnings to Fixed Charges

*31

Certification of Leon J. Olivier, Chief Executive Officer of Public Service Company of New Hampshire, required by Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated November 5, 2010

*31.1

Certification of David R. McHale, Executive Vice President and Chief Financial Officer of Public Service Company of New Hampshire, required by Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated November 5, 2010

*32

Certification of Leon J. Olivier, Chief Executive Officer of Public Service Company of New Hampshire and David R. McHale, Executive Vice President and Chief Financial Officer of Public Service Company of New Hampshire, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, dated November 5, 2010

Listing of Exhibits (WMECO)

*10

Credit Agreement dated as of September 24, 2010, among The Connecticut Light and Power Company, Western Massachusetts Electric Company, Yankee Gas Services Company and Public Service Company of New Hampshire, the Banks named therein, and Citibank, N.A. as Administrative Agent

*12

Ratio of Earnings to Fixed Charges

*31

Certification of Leon J. Olivier, Chief Executive Officer of Western Massachusetts Electric Company, required by Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated November 5, 2010

*31.1

Certification of David R. McHale, Executive Vice President and Chief Financial Officer of Western Massachusetts Electric Company, required by Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated November 5, 2010

*32

Certification of Leon J. Olivier, Chief Executive Officer of Western Massachusetts Electric Company and David R. McHale, Executive Vice President and Chief Financial Officer of Western Massachusetts Electric Company, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, dated November 5, 2010

86

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 5, 2010	By	/s/ David R. McHale
		David R. McHale
		Executive Vice President and Chief Financial Officer
		(for the Registrant and as Principal Financial Officer)

SIGNATURE

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

		THE CONNECTICUT LIGHT AND POWER COMPANY
		(Registrant)
Date:  November 5, 2010	By	/s/ David R. McHale
		David R. McHale
		Executive Vice President and Chief Financial Officer
		(for the Registrant and as Principal Financial Officer)

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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 5, 2010	By	/s/ David R. McHale
		David R. McHale
		Executive Vice President and Chief Financial Officer
		(for the Registrant and as Principal Financial Officer)

SIGNATURE

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

		WESTERN MASSACHUSETTS ELECTRIC COMPANY
		(Registrant)
Date:  November 5, 2010	By	/s/ David R. McHale
		David R. McHale
		Executive Vice President and Chief Financial Officer
		(for the Registrant and as Principal Financial Officer)

88