Eversource Energy (ES) 10-Q 2010 FY 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 EndedJune 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 July 30, 2010
Northeast Utilities Common shares, $5.00 par value	176,150,636 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
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, 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
CfD	Contract for Differences
CSC	Connecticut Siting Council
CTA	Competitive Transition Assessment
CWIP	Construction work in progress
EFSB	Massachusetts Energy Facilities Siting Board
EPS	Earnings Per Share
ES	Default Energy Service
ESOP	Employee Stock Ownership Plan
FASB	Financial Accounting Standards Board
Fitch	Fitch Ratings
First Quarter 2010 Form 10-Q	The Northeast Utilities and subsidiaries combined first quarter 2010 Quarterly Report on Form 10-Q
FMCC	Federally Mandated Congestion Charge
FTR	Financial Transmission Rights

i

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
IPP	Independent Power Producers
ISO-NE	ISO New England, Inc., the New England Independent System Operator
KV	Kilovolt
KWh	Kilowatt-Hours
LBCB	Lehman Brothers Commercial Bank, Inc.
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
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
NYMEX	New York Mercantile Exchange
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
RFP	Request for Proposal
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 Services Agreement
UI	The United Illuminating Company
VIE	Variable interest entity
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) - June 30, 2010 and December 31, 2009	2
Condensed Consolidated Statements of Income (Unaudited) - Three and Six Months Ended June 30, 2010 and 2009	4
Condensed Consolidated Statements of Cash Flows (Unaudited) - Six Months Ended June 30, 2010 and 2009	5
The Connecticut Light and Power Company and Subsidiaries
Condensed Consolidated Balance Sheets (Unaudited) - June 30, 2010 and December 31, 2009	8
Condensed Consolidated Statements of Income (Unaudited) - Three and Six Months Ended June 30, 2010 and 2009	10
Condensed Consolidated Statements of Cash Flows (Unaudited) - Six Months Ended June 30, 2010 and 2009	11
Public Service Company of New Hampshire and Subsidiaries
Condensed Consolidated Balance Sheets (Unaudited) - June 30, 2010 and December 31, 2009	14
Condensed Consolidated Statements of Income (Unaudited) - Three and Six Months Ended June 30, 2010 and 2009	16
Condensed Consolidated Statements of Cash Flows (Unaudited) - Six Months Ended June 30, 2010 and 2009	17
Western Massachusetts Electric Company and Subsidiary
Condensed Consolidated Balance Sheets (Unaudited) - June 30, 2010 and December 31, 2009	20
Condensed Consolidated Statements of Income (Unaudited) - Three and Six Months Ended June 30, 2010 and 2009	22
Condensed Consolidated Statements of Cash Flows (Unaudited) - Six Months Ended June 30, 2010 and 2009	23
Combined Notes to Condensed Consolidated Financial Statements (Unaudited - all companies)	24
Report of Independent Registered Public Accounting Firm	53

iii

	Page
ITEM 2 - Management's Discussion and Analysis of Financial Condition and Results of Operations for the following companies:
Northeast Utilities and Subsidiaries		54
The Connecticut Light and Power Company and Subsidiaries		73
Public Service Company of New Hampshire and Subsidiaries		77
Western Massachusetts Electric Company and Subsidiary		80
ITEM 3 - Quantitative and Qualitative Disclosures About Market Risk		83
ITEM 4 - Controls and Procedures		83
PART II-OTHER INFORMATION
ITEM 1 - Legal Proceedings		84
ITEM 1A - Risk Factors		84
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)
		June 30,		December 31,
(Thousands of Dollars)		2010		2009
ASSETS
Current Assets:
Cash and Cash Equivalents	$	88,775	$	26,952
Receivables, Net		495,640		512,770
Unbilled Revenues		178,838		229,326
Fuel, Materials and Supplies		226,200		277,085
Marketable Securities		72,684		66,236
Derivative Assets		28,887		31,785
Prepayments and Other Current Assets		121,835		123,700
Total Current Assets		1,212,859		1,267,854
Property, Plant and Equipment, Net		9,142,320		8,839,965
Deferred Debits and Other Assets:
Regulatory Assets		3,183,982		3,244,931
Goodwill		287,591		287,591
Marketable Securities		47,995		54,905
Derivative Assets		160,380		189,751
Other Long-Term Assets		194,596		172,682
Total Deferred Debits and Other Assets		3,874,544		3,949,860
Total Assets	$	14,229,723	$	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)
		June 30,		December 31,
(Thousands of Dollars)		2010		2009
LIABILITIES AND CAPITALIZATION
Current Liabilities:
Notes Payable to Banks	$	157,313	$	100,313
Long-Term Debt - Current Portion		66,286		66,286
Accounts Payable		390,046		457,582
Accrued Taxes		55,071		50,246
Accrued Interest		87,784		83,763
Derivative Liabilities		41,176		37,617
Other Current Liabilities		167,948		183,605
Total Current Liabilities		965,624		979,412
Rate Reduction Bonds		313,835		442,436
Deferred Credits and Other Liabilities:
Accumulated Deferred Income Taxes		1,456,537		1,380,143
Accumulated Deferred Investment Tax Credits		20,666		22,145
Regulatory Liabilities		444,957		485,706
Derivative Liabilities		1,009,849		955,646
Accrued Pension		799,762		781,431
Other Long-Term Liabilities		806,393		823,723
Total Deferred Credits and Other Liabilities		4,538,164		4,448,794
Capitalization:
Long-Term Debt		4,635,851		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		978,429		977,276
Capital Surplus, Paid In		1,767,904		1,762,097
Deferred Contribution Plan		-		(2,944)
Retained Earnings		1,313,848		1,246,543
Accumulated Other Comprehensive Loss		(41,805)		(43,467)
Treasury Stock		(359,392)		(361,603)
Common Shareholders' Equity		3,658,984		3,577,902
Noncontrolling Interest		1,065		-
Total Equity		3,660,049		3,577,902
Total Capitalization		8,412,100		8,187,037
Total Liabilities and Capitalization	$	14,229,723	$	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 June 30,				Six Months Ended June 30,
(Thousands of Dollars, Except Share Information)	2010		2009		2010		2009
Operating Revenues	$	1,111,426	$	1,224,431	$	2,450,845	$	2,817,914
Operating Expenses:
Fuel, Purchased and Net Interchange Power		442,230		583,599		1,045,578		1,422,519
Other Operating Expenses		206,664		234,821		454,937		482,266
Maintenance		66,817		56,367		112,454		105,203
Depreciation		79,075		77,768		157,731		154,751
Amortization of Regulatory Assets/(Liabilities), Net		8,893		(13,039)		566		8,652
Amortization of Rate Reduction Bonds		54,997		51,305		114,567		107,202
Taxes Other Than Income Taxes		74,406		54,424		160,005		140,853
Total Operating Expenses		933,082		1,045,245		2,045,838		2,421,446
Operating Income		178,344		179,186		405,007		396,468
Interest Expense:
Interest on Long-Term Debt		58,522		56,774		115,791		112,458
Interest on Rate Reduction Bonds		5,633		9,607		12,324		20,232
Other Interest (Note 1I)		3,042		(1,423)		6,343		3,245
Interest Expense		67,197		64,958		134,458		135,935
Other Income, Net		1,552		12,409		9,608		16,591
Income Before Income Tax Expense		112,699		126,637		280,157		277,124
Income Tax Expense		39,351		42,394		119,209		93,817
Net Income		73,348		84,243		160,948		183,307
Net Income Attributable to Noncontrolling Interests		1,402		1,389		2,792		2,779
Net Income Attributable to Controlling Interests	$	71,946	$	82,854	$	158,156	$	180,528
Basic and Fully Diluted Earnings Per Common Share	$	0.41	$	0.47	$	0.90	$	1.07
Dividends Declared Per Common Share	$	0.26	$	0.24	$	0.51	$	0.48
Weighted Average Common Shares Outstanding:
Basic		176,571,189		175,175,936		176,460,476		168,758,206
Fully Diluted		176,736,532		175,675,388		176,637,003		169,300,277
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)
		Six Months Ended June 30,
(Thousands of Dollars)		2010		2009
Operating Activities:
Net Income	$	160,948	$	183,307
Adjustments to Reconcile Net Income to Net Cash Flows
Provided by Operating Activities:
Bad Debt Expense		17,176		17,986
Depreciation		157,731		154,751
Deferred Income Taxes		37,850		73,202
Pension and PBOP Expense, Net of PBOP Contributions		25,529		13,052
Regulatory Overrecoveries, Net		21,569		20,732
Amortization of Regulatory Assets/(Liabilities), Net		566		8,652
Amortization of Rate Reduction Bonds		114,567		107,202
Allowance for Equity Funds Used During Construction		(6,934)		(3,366)
Derivative Assets and Liabilities		(5,640)		(19,243)
Other		(22,773)		1,164
Changes in Current Assets and Liabilities:
Receivables and Unbilled Revenues, Net		34,703		158,175
Fuel, Materials and Supplies		52,024		35,582
Taxes Receivable/(Accrued)		(3,856)		(8,244)
Other Current Assets		14,682		7,139
Accounts Payable		(53,480)		(211,445)
Other Current Liabilities		(10,883)		(30,309)
Net Cash Flows Provided by Operating Activities		533,779		508,337
Investing Activities:
Investments in Property and Plant		(442,404)		(420,894)
Proceeds from Sales of Marketable Securities		95,452		147,702
Purchases of Marketable Securities		(96,546)		(149,482)
Other Investing Activities		(4,369)		2,939
Net Cash Flows Used in Investing Activities		(447,867)		(419,735)
Financing Activities:
Issuance of Common Shares		-		387,411
Cash Dividends on Common Shares		(90,194)		(78,921)
Cash Dividends on Preferred Stock		(2,779)		(2,779)
Increase/(Decrease) in Short-Term Debt		57,000		(124,908)
Issuance of Long-Term Debt		145,000		312,000
Retirements of Long-Term Debt		(4,286)		(54,286)
Retirements of Rate Reduction Bonds		(128,600)		(120,326)
Financing Fees		(1,482)		(15,456)
Other Financing Activities		1,252		(5)
Net Cash Flows (Used in)/Provided by Financing Activities		(24,089)		302,730
Net Increase in Cash and Cash Equivalents		61,823		391,332
Cash and Cash Equivalents - Beginning of Period		26,952		89,816
Cash and Cash Equivalents - End of Period	$	88,775	$	481,148
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

5

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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)
		June 30,		December 31,
(Thousands of Dollars)		2010		2009
ASSETS
Current Assets:
Cash	$	8,999	$	45
Receivables, Net		321,297		327,969
Accounts Receivable from Affiliated Companies		2,255		2,362
Notes Receivable from Affiliated Companies		-		97,775
Unbilled Revenues		112,210		140,632
Materials and Supplies		60,855		65,623
Derivative Assets		19,757		24,593
Prepayments and Other Current Assets		13,432		18,385
Total Current Assets		538,805		677,384
Property, Plant and Equipment, Net		5,433,896		5,340,561
Deferred Debits and Other Assets:
Regulatory Assets		2,020,901		2,068,778
Derivative Assets		150,179		183,231
Other Long-Term Assets		83,900		94,610
Total Deferred Debits and Other Assets		2,254,980		2,346,619
Total Assets	$	8,227,681	$	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)
		June 30,		December 31,
(Thousands of Dollars)		2010		2009
LIABILITIES AND CAPITALIZATION
Current Liabilities:
Notes Payable to Affiliated Companies	$	15,625	$	-
Long-Term Debt - Current Portion		62,000		62,000
Accounts Payable		188,843		242,853
Accounts Payable to Affiliated Companies		46,723		48,795
Accrued Taxes		48,032		36,860
Accrued Interest		50,854		49,867
Derivative Liabilities		14,037		9,770
Other Current Liabilities		101,301		100,846
Total Current Liabilities		527,415		550,991
Rate Reduction Bonds		99,320		195,587
Deferred Credits and Other Liabilities:
Accumulated Deferred Income Taxes		940,535		901,527
Accumulated Deferred Investment Tax Credits		15,228		16,355
Regulatory Liabilities		285,590		316,160
Derivative Liabilities		972,480		913,349
Accrued Pension		46,764		51,319
Other Long-Term Liabilities		385,963		409,532
Total Deferred Credits and Other Liabilities		2,646,560		2,608,242
Capitalization:
Long-Term Debt		2,520,711		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		1,602,116		1,601,792
Retained Earnings		657,937		714,210
Accumulated Other Comprehensive Loss		(2,930)		(3,171)
Common Stockholder's Equity		2,317,475		2,373,183
Total Capitalization		4,954,386		5,009,744
Total Liabilities and Capitalization	$	8,227,681	$	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 June 30,				Six Months Ended June 30,
(Thousands of Dollars)	2010		2009		2010		2009
Operating Revenues	$	707,917	$	784,937	$	1,502,897	$	1,739,440
Operating Expenses:
Fuel, Purchased and Net Interchange Power		290,553		383,153		653,374		897,539
Other Operating Expenses		120,293		131,174		255,106		270,585
Maintenance		32,821		27,783		54,660		54,898
Depreciation		47,944		47,048		95,469		93,481
Amortization of Regulatory Assets, Net		20,640		3,633		22,311		16,640
Amortization of Rate Reduction Bonds		38,924		36,192		82,207		76,749
Taxes Other Than Income Taxes		50,585		37,899		108,114		96,088
Total Operating Expenses		601,760		666,882		1,271,241		1,505,980
Operating Income		106,157		118,055		231,656		233,460
Interest Expense:
Interest on Long-Term Debt		33,630		34,286		67,262		65,972
Interest on Rate Reduction Bonds		2,243		5,088		5,275		10,887
Other Interest (Note 1I)		1,334		(1,627)		3,197		(1,418)
Interest Expense		37,207		37,747		75,734		75,441
Other Income, Net		745		8,170		5,678		10,878
Income Before Income Tax Expense		69,695		88,478		161,600		168,897
Income Tax Expense		25,610		30,076		69,102		57,360
Net Income	$	44,085	$	58,402	$	92,498	$	111,537
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)
		Six Months Ended June 30,
(Thousands of Dollars)		2010		2009
Operating Activities:
Net Income	$	92,498	$	111,537
Adjustments to Reconcile Net Income to Net Cash Flows
Provided by Operating Activities:
Bad Debt Expense		5,494		4,927
Depreciation		95,469		93,481
Deferred Income Taxes		11,624		43,664
Regulatory Overrecoveries, Net		30,459		11,152
Amortization of Regulatory Assets/(Liabilities), Net		22,311		16,640
Amortization of Rate Reduction Bonds		82,207		76,749
Allowance for Equity Funds Used During Construction		(2,475)		(1,615)
Other		(23,367)		(15,420)
Changes in Current Assets and Liabilities:
Receivables and Unbilled Revenues, Net		15,679		90,947
Materials and Supplies		4,767		(4,232)
Taxes Receivable/(Accrued)		12,694		15,133
Other Current Assets		9,102		6,147
Accounts Payable		(38,735)		(106,597)
Other Current Liabilities		13,239		(5,497)
Net Cash Flows Provided by Operating Activities		330,966		337,016
Investing Activities:
Investments in Property and Plant		(191,667)		(226,892)
Decrease/(Increase) in NU Money Pool Lending		97,775		(162,488)
Other Investing Activities		1,463		(282)
Net Cash Flows Used in Investing Activities		(92,429)		(389,662)
Financing Activities:
Cash Dividends on Common Stock		(145,992)		(56,925)
Cash Dividends on Preferred Stock		(2,779)		(2,779)
Decrease in Short-Term Debt		-		(74,000)
Issuance of Long-Term Debt		-		312,000
Increase/(Decrease) in NU Money Pool Borrowings		15,625		(102,725)
Retirements of Rate Reduction Bonds		(96,267)		(89,875)
Capital Contributions from NU Parent		-		77,000
Other Financing Activities		(170)		(2,861)
Net Cash Flows (Used in)/Provided by Financing Activities		(229,583)		59,835
Net Increase in Cash		8,954		7,189
Cash - Beginning of Period		45		-
Cash - End of Period	$	8,999	$	7,189
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

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12

PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES

13

PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
		June 30,		December 31,
(Thousands of Dollars)		2010		2009
ASSETS
Current Assets:
Cash	$	11,285	$	1,974
Receivables, Net		83,914		89,337
Unbilled Revenues		46,703		49,358
Taxes Receivable		20,544		22,600
Fuel, Materials and Supplies		97,872		127,447
Prepayments and Other Current Assets		20,879		36,673
Total Current Assets		281,197		327,389
Property, Plant and Equipment, Net		1,937,877		1,814,714
Deferred Debits and Other Assets:
Regulatory Assets		483,982		494,077
Other Long-Term Assets		88,701		61,011
Total Deferred Debits and Other Assets		572,683		555,088
Total Assets	$	2,791,757	$	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)
		June 30,		December 31,
(Thousands of Dollars)		2010		2009
LIABILITIES AND CAPITALIZATION
Current Liabilities:
Notes Payable to Affiliated Companies	$	7,800	$	26,700
Accounts Payable		100,109		109,521
Accounts Payable to Affiliated Companies		21,311		20,083
Accrued Interest		10,296		10,255
Derivative Liabilities		18,020		18,785
Other Current Liabilities		20,807		27,983
Total Current Liabilities		178,343		213,327
Rate Reduction Bonds		163,546		188,113
Deferred Credits and Other Liabilities:
Accumulated Deferred Income Taxes		292,789		275,669
Regulatory Liabilities		67,708		69,872
Derivative Liabilities		5,907		7,635
Accrued Pension		281,518		272,905
Other Long-Term Liabilities		110,409		105,970
Total Deferred Credits and Other Liabilities		758,331		732,051
Capitalization:
Long-Term Debt		836,310		836,255
Common Stockholder's Equity:
Common Stock		-		-
Capital Surplus, Paid In		535,739		420,169
Retained Earnings		320,123		307,988
Accumulated Other Comprehensive Loss		(635)		(712)
Common Stockholder's Equity		855,227		727,445
Total Capitalization		1,691,537		1,563,700
Total Liabilities and Capitalization	$	2,791,757	$	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 June 30,				Six Months Ended June 30,
(Thousands of Dollars)	2010		2009		2010		2009
Operating Revenues	$	238,322	$	262,931	$	496,890	$	570,584
Operating Expenses:
Fuel, Purchased and Net Interchange Power		83,253		128,494		187,024		274,719
Other Operating Expenses		56,073		58,476		119,199		121,204
Maintenance		25,625		20,852		41,627		36,374
Depreciation		16,020		15,390		31,988		30,561
Amortization of Regulatory Liabilities, Net		(11,627)		(12,760)		(17,322)		(4,813)
Amortization of Rate Reduction Bonds		12,246		11,528		24,637		23,214
Taxes Other Than Income Taxes		13,348		9,769		26,426		22,013
Total Operating Expenses		194,938		231,749		413,579		503,272
Operating Income		43,384		31,182		83,311		67,312
Interest Expense:
Interest on Long-Term Debt		9,268		8,266		18,780		16,370
Interest on Rate Reduction Bonds		2,516		3,406		5,237		7,064
Other Interest (Note 1I)		185		(1,129)		364		(337)
Interest Expense		11,969		10,543		24,381		23,097
Other (Loss)/Income, Net		(197)		2,805		2,215		4,230
Income Before Income Tax Expense		31,218		23,444		61,145		48,445
Income Tax Expense		9,602		6,874		23,719		14,380
Net Income	$	21,616	$	16,570	$	37,426	$	34,065
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)
		Six Months Ended June 30,
(Thousands of Dollars)		2010		2009
Operating Activities:
Net Income	$	37,426	$	34,065
Adjustments to Reconcile Net Income to Net Cash Flows
Provided by Operating Activities:
Bad Debt Expense		4,282		3,210
Depreciation		31,988		30,561
Deferred Income Taxes		15,486		6,305
Pension and PBOP Expense, Net of PBOP Contributions		9,606		8,206
Regulatory (Underrecoveries)/Overrecoveries, Net		(5,459)		3,889
Amortization of Regulatory Assets/(Liabilities), Net		(17,322)		(4,813)
Amortization of Rate Reduction Bonds		24,637		23,214
Allowance for Equity Funds Used During Construction		(4,207)		(1,661)
Insurance Proceeds		10,000		10,066
Other		(16,850)		4,493
Changes in Current Assets and Liabilities:
Receivables and Unbilled Revenues, Net		3,338		5,876
Fuel, Materials and Supplies		30,714		4,427
Taxes Receivable/(Accrued)		2,057		(6,119)
Other Current Assets		2,599		1,284
Accounts Payable		(12,305)		(72,536)
Other Current Liabilities		(7,157)		(4,835)
Net Cash Flows Provided by Operating Activities		108,833		45,632
Investing Activities:
Investments in Property and Plant		(141,709)		(112,356)
Proceeds from Sales of Marketable Securities		1,564		4,133
Purchases of Marketable Securities		(1,620)		(4,161)
Decrease in NU Money Pool Lending		-		44,800
Other Investing Activities		(4,311)		833
Net Cash Flows Used in Investing Activities		(146,076)		(66,751)
Financing Activities:
Cash Dividends on Common Stock		(25,292)		(20,422)
Decrease in NU Money Pool Borrowings		(18,900)		-
Retirements of Rate Reduction Bonds		(24,568)		(23,168)
Capital Contributions from NU Parent		115,428		67,000
Other Financing Activities		(114)		(386)
Net Cash Flows Provided by Financing Activities		46,554		23,024
Net Increase in Cash		9,311		1,905
Cash - Beginning of Period		1,974		195
Cash - End of Period	$	11,285	$	2,100
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)
		June 30,		December 31,
(Thousands of Dollars)		2010		2009
ASSETS
Current Assets:
Cash	$	1	$	1
Receivables, Net		37,700		38,415
Notes Receivable from Affiliated Companies		22,000		-
Unbilled Revenues		15,283		16,090
Taxes Receivable		4,272		4,192
Materials and Supplies		9,080		8,314
Marketable Securities		35,747		28,261
Prepayments and Other Current Assets		1,939		1,965
Total Current Assets		126,022		97,238
Property, Plant and Equipment, Net		746,623		705,760
Deferred Debits and Other Assets:
Regulatory Assets		234,784		240,804
Marketable Securities		21,092		28,500
Other Long-Term Assets		35,893		29,498
Total Deferred Debits and Other Assets		291,769		298,802
Total Assets	$	1,164,414	$	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)
		June 30,		December 31,
(Thousands of Dollars)		2010		2009
LIABILITIES AND CAPITALIZATION
Current Liabilities:
Notes Payable to Affiliated Companies	$	-	$	136,100
Accounts Payable		39,854		36,680
Accounts Payable to Affiliated Companies		8,335		7,924
Accrued Interest		6,732		5,274
Other Current Liabilities		7,118		8,873
Total Current Liabilities		62,039		194,851
Rate Reduction Bonds		50,970		58,735
Deferred Credits and Other Liabilities:
Accumulated Deferred Income Taxes		217,723		211,391
Regulatory Liabilities		20,439		21,683
Other Long-Term Liabilities		60,143		62,858
Total Deferred Credits and Other Liabilities		298,305		295,932
Capitalization:
Long-Term Debt		400,206		305,475
Common Stockholder's Equity:
Common Stock		10,866		10,866
Capital Surplus, Paid In		248,054		145,400
Retained Earnings		94,016		90,549
Accumulated Other Comprehensive Loss		(42)		(8)
Common Stockholder's Equity		352,894		246,807
Total Capitalization		753,100		552,282
Total Liabilities and Capitalization	$	1,164,414	$	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 June 30,				Six Months Ended June 30,
(Thousands of Dollars)	2010		2009		2010		2009
Operating Revenues	$	92,473	$	95,120	$	192,680	$	213,201
Operating Expenses:
Fuel, Purchased and Net Interchange Power		36,720		46,298		80,352		109,533
Other Operating Expenses		23,067		22,817		46,293		45,481
Maintenance		5,367		5,135		9,909		8,241
Depreciation		5,868		5,621		11,821		11,149
Amortization of Regulatory Liabilities, Net		(721)		(4,009)		(2,290)		(3,339)
Amortization of Rate Reduction Bonds		3,827		3,586		7,722		7,240
Taxes Other Than Income Taxes		4,080		2,517		8,163		6,414
Total Operating Expenses		78,208		81,965		161,970		184,719
Operating Income		14,265		13,155		30,710		28,482
Interest Expense:
Interest on Long-Term Debt		4,726		3,554		8,607		6,997
Interest on Rate Reduction Bonds		874		1,112		1,811		2,280
Other Interest (Note 1I)		57		(233)		183		394
Interest Expense		5,657		4,433		10,601		9,671
Other Income, Net		161		1,089		765		935
Income Before Income Tax Expense		8,769		9,811		20,874		19,746
Income Tax Expense		3,520		4,004		9,966		7,793
Net Income	$	5,249	$	5,807	$	10,908	$	11,953
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)
		Six Months Ended June 30,
(Thousands of Dollars)		2010		2009
Operating Activities:
Net Income	$	10,908	$	11,953
Adjustments to Reconcile Net Income to Net Cash Flows
Provided by Operating Activities:
Bad Debt Expense		3,304		3,862
Depreciation		11,821		11,149
Deferred Income Taxes		5,061		12,249
Regulatory (Underrecoveries)/Overrecoveries, Net		(8,181)		4,139
Amortization of Regulatory Assets/(Liabilities), Net		(2,290)		(3,339)
Amortization of Rate Reduction Bonds		7,722		7,240
Other		(3,136)		(4,821)
Changes in Current Assets and Liabilities:
Receivables and Unbilled Revenues, Net		(1,762)		6,057
Materials and Supplies		(767)		39
Taxes Receivable/(Accrued)		(80)		(4,412)
Other Current Assets		495		(587)
Accounts Payable		605		(24,426)
Other Current Liabilities		(102)		(2,618)
Net Cash Flows Provided by Operating Activities		23,598		16,485
Investing Activities:
Investments in Property and Plant		(46,354)		(41,478)
Proceeds from Sales of Marketable Securities		69,196		78,334
Purchases of Marketable Securities		(69,350)		(79,635)
Increase in NU Money Pool Lending		(22,000)		-
Other Investing Activities		(170)		548
Net Cash Flows Used in Investing Activities		(68,678)		(42,231)
Financing Activities:
Cash Dividends on Common Stock		(7,441)		(11,101)
Increase in Short-Term Debt		-		45,227
Issuance of Long-Term Debt		95,000		-
Decrease in NU Money Pool Borrowings		(136,100)		100
Retirements of Rate Reduction Bonds		(7,765)		(7,282)
Capital Contributions from NU Parent		102,600		-
Other Financing Activities		(1,214)		(37)
Net Cash Flows Provided by Financing Activities		45,080		26,907
Net Increase in Cash		-		1,161
Cash - Beginning of Period		1		-
Cash - End of Period	$	1	$	1,161
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.

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 quarter 2010 combined Quarterly Report 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 June 30, 2010 and December 31, 2009, the results of operations for the three and six months ended June 30, 2010 and 2009, and cash flows for the six months ended June 30, 2010 and 2009.  The results of operations for the three months ended June 30, 2010 and 2009, and the results of operations and cash flows for the six months ended June 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 June 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 financial exposure because the costs and benefits of all of these arrangements are fully recoverable from, or refundable to, NU’s customers.  As of June 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 interest in a VIE that is 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 for CL&P, PSNH, and WMECO and the statements of cash flows for NU, CL&P, PSNH and WMECO.  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 1C, "Summary of Significant Accounting Policies – Regulatory Accounting," for further information.  

24

B.

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 9, "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 June 30, 2010 and December 31, 2009.  

C.

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.  

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

	As of June 30, 2010		As of December 31, 2009
(Millions of Dollars)	NU		NU
Deferred Benefit Costs	$	1,099.9	$	1,132.1
Regulatory Assets Offsetting Derivative Liabilities		899.3		855.6
Securitized Assets		304.4		432.9
Income Taxes, Net		374.1		363.2
Unrecovered Contractual Obligations		138.8		149.5
Regulatory Tracker Deferrals		128.7		104.1
Storm Cost Deferral		63.9		60.0
Asset Retirement Obligations		44.5		42.9
Losses on Reacquired Debt		22.9		24.0
Regulatory Assets Offsetting Environmental Liabilities		36.1		24.6
Other Regulatory Assets		71.4		56.0
Totals	$	3,184.0	$	3,244.9

25

	As of June 30, 2010						As of December 31, 2009
(Millions of Dollars)	CL&P		PSNH		WMECO		CL&P		PSNH		WMECO
Deferred Benefit Costs	$	486.7	$	146.2	$	100.7	$	502.4	$	154.2	$	104.9
Regulatory Assets Offsetting Derivative Liabilities		874.5		23.9		-		828.6		26.4		-
Securitized Assets		99.2		155.5		49.7		195.4		180.1		57.4
Income Taxes, Net		308.7		26.6		17.1		304.1		21.9		16.9
Unrecovered Contractual Obligations		109.7		-		29.1		118.0		-		31.5
Regulatory Tracker Deferrals		67.7		37.7		19.8		70.3		19.0		11.3
Storm Cost Deferral		5.5		43.8		14.6		-		50.8		9.2
Asset Retirement Obligations		25.0		14.3		2.9		23.8		14.0		2.8
Losses on Reacquired Debt		12.1		8.8		0.4		12.7		9.2		0.4
Regulatory Assets Offsetting Environmental   Liabilities		-		8.5		-		-		1.3		-
Other Regulatory Assets		31.8		18.7		0.5		13.5		17.2		6.4
Totals	$	2,020.9	$	484.0	$	234.8	$	2,068.8	$	494.1	$	240.8

Additionally, the Regulated companies had $45.6 million ($0.4 million for CL&P, $25.7 million for PSNH, and $11.6 million for WMECO) and $27.1 million ($9.9 million for CL&P and $9.1 million for WMECO) of regulatory costs as of June 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.  

Of the total June 30, 2010 amount, $8.1 million ($5.3 million for PSNH and $2.8 million for WMECO) relates to the probable recovery in future rates of previously recognized tax benefits lost as a result of a provision in the 2010 Healthcare Act that eliminated the tax deductibility of actuarially equivalent Medicare Part D benefits for retirees.  On June 30, 2010, the DPUC issued a decision that rejected CL&P's request for the establishment of a regulatory asset that was recorded in Other Long-Term Assets in the first quarter of 2010 for the recovery of future tax benefits lost as a result of the 2010 Healthcare Act.  On July 14, 2010, CL&P filed with the DPUC a request to reconsider its ruling on this issue.  On July 28, 2010, the DPUC granted CL&P’s request for reconsideration of its decision and the DPUC allowed the creation of a regulatory asset by CL&P, subject to review in its next rate case .  As a result, NU has concluded that these costs are probable of recovery and has recorded regulatory assets of $16.3 million ($13.7 million for CL&P and $2.6 million for Yankee Gas) as of June 30, 2010, which are reflected in Other Regulatory Assets in the table above.

The $25.7 million at PSNH also includes $20.4 million of costs incurred for the February 2010 winter storm restorations that met the NHPUC specified criteria for deferral to a major storm cost reserve.  

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

	As of June 30, 2010		As of December 31, 2009
(Millions of Dollars)	NU		NU
Cost of Removal	$	205.0	$	209.2
Regulatory Liabilities Offsetting Derivative Assets		55.8		109.4
Regulatory Tracker Deferrals		76.5		62.5
AFUDC Transmission Incentive (Note 1F)		55.0		51.1
Pension and PBOP Liabilities - Yankee Gas Acquisition		13.8		15.0
Overrecovered Natural Gas Costs		5.4		7.1
Other Regulatory Liabilities		33.5		31.4
Totals	$	445.0	$	485.7

	As of June 30, 2010						As of December 31, 2009
(Millions of Dollars)	CL&P		PSNH		WMECO		CL&P		PSNH		WMECO
Cost of Removal	$	81.3	$	58.9	$	15.2	$	82.2	$	60.5	$	16.6
Regulatory Liabilities Offsetting   Derivative Assets		55.8		-		-		109.0		0.4		-
Regulatory Tracker Deferrals		70.7		5.4		0.4		56.0		4.4		2.1
AFUDC Transmission Incentive (Note 1F)		53.1		-		1.9		50.4		-		0.7
WMECO Provision For Rate Refunds		-		-		2.0		-		-		2.0
Other Regulatory Liabilities		24.7		3.4		0.9		18.6		4.6		0.3
Totals	$	285.6	$	67.7	$	20.4	$	316.2	$	69.9	$	21.7

26

D.

Property, Plant and Equipment and Accumulated Depreciation

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

	As of June 30, 2010		As of December 31, 2009
(Millions of Dollars)	NU		NU
Distribution - Electric	$	6,035.7	$	5,893.9
Distribution - Natural Gas		1,088.8		1,071.1
Transmission		3,270.7		3,219.2
Generation		678.0		660.1
Electric and Natural Gas Utility		11,073.2		10,844.3
Other(1)		279.2		265.6
Total Property, Plant and Equipment, Gross		11,352.4		11,109.9
Less:  Accumulated Depreciation
Electric and Natural Gas Utility		(2,798.6)		(2,721.3)
Other		(126.4)		(120.3)
Total Accumulated Depreciation		(2,925.0)		(2,841.6)
Property, Plant and Equipment, Net		8,427.4		8,268.3
Construction Work In Progress		714.9		571.7
Total Property, Plant and Equipment, Net	$	9,142.3	$	8,840.0

⁽¹⁾

These assets are primarily owned by RRR ($144.4 million and $143.8 million) and NUSCO ($122 million and $109 million) as of June 30, 2010 and December 31, 2009, respectively.  

	As of June 30, 2010						As of December 31, 2009
(Millions of Dollars)	CL&P		PSNH		WMECO		CL&P		PSNH		WMECO
Distribution	$	4,069.1	$	1,334.1	$	663.9	$	3,960.1	$	1,309.2	$	654.9
Transmission		2,603.0		460.3		207.4		2,573.2		450.2		195.7
Generation		-		678.0		-		-		660.1		-
Total Property, Plant and Equipment, Gross		6,672.1		2,472.4		871.3		6,533.3		2,419.5		850.6
Less:  Accumulated Depreciation		(1,474.7)		(820.9)		(224.9)		(1,426.6)		(805.5)		(218.2)
Property, Plant and Equipment, Net		5,197.4		1,651.5		646.4		5,106.7		1,614.0		632.4
Construction Work in Progress		236.5		286.4		100.2		233.9		200.7		73.4
Total Property, Plant and Equipment, Net	$	5,433.9	$	1,937.9	$	746.6	$	5,340.6	$	1,814.7	$	705.8

E.

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 these balances are deemed to be uncollectible and the accounts are terminated.  

The provision for uncollectible accounts as of June 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 June 30, 2010		As of December 31, 2009
NU	$	57.2	$	55.3
CL&P		28.3		26.1
PSNH		5.9		5.1
WMECO		7.7		7.2

F.

Allowance for Funds Used During Construction

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

27

	For the Three Months Ended				For the Six Months Ended
	June 30, 2010		June 30, 2009		June 30, 2010		June 30, 2009
(Millions of Dollars, except percentages)	NU		NU		NU		NU
AFUDC:
Borrowed Funds	$	2.3	$	1.4	$	4.2	$	3.5
Equity Funds		3.8		2.5		6.9		3.4
Totals	$	6.1	$	3.9	$	11.1	$	6.9
Average AFUDC Rates		7.0%		6.6%		6.8%		5.9%

	For the Three Months Ended
	June 30, 2010						June 30, 2009
(Millions of Dollars, except percentages)	CL&P		PSNH		WMECO		CL&P		PSNH		WMECO
AFUDC:
Borrowed Funds	$	0.7	$	1.5	$	0.1	$	0.6	$	0.7	$	-
Equity Funds		1.2		2.4		0.2		1.7		0.8		-
Totals	$	1.9	$	3.9	$	0.3	$	2.3	$	1.5	$	-
Average AFUDC Rates		8.0%		6.7%		6.7%		8.2%		6.1%		1.1%*

*The AFUDC rate applies to WMECO's portion of CWIP that is currently recovered in rate base, as further described below.

	For the Six Months Ended
	June 30, 2010						June 30, 2009
(Millions of Dollars, except percentages)	CL&P		PSNH		WMECO		CL&P		PSNH		WMECO
AFUDC:
Borrowed Funds	$	1.4	$	2.6	$	0.1	$	1.5	$	1.6	$	0.1
Equity Funds		2.5		4.2		0.2		1.6		1.7		-
Totals	$	3.9	$	6.8	$	0.3	$	3.1	$	3.3	$	0.1
Average AFUDC Rates		8.0%		6.5%		4.1%		5.7%		7.0%		2.5%

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.

G.

Other Income, Net

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

	For the Three Months Ended				For the Six Months Ended
	June 30, 2010		June 30, 2009		June 30, 2010		June 30, 2009
(Million of Dollars)	NU		NU		NU		NU
Other Income:
Investment Income	$	-	$	6.1	$	-	$	3.1
Interest Income		1.3		2.0		2.1		4.0
AFUDC - Equity Funds		3.8		2.5		6.9		3.4
Energy Independence Act Incentives		0.9		0.7		2.3		4.3
Other		2.2		1.1		2.9		2.0
Total Other Income		8.2		12.4		14.2		16.8
Other Loss:
Investment Losses		(4.0)		-		(2.0)		-
Other		(2.6)		-		(2.6)		(0.2)
Total Other Loss		(6.6)		-		(4.6)		(0.2)
Total Other Income, Net	$	1.6	$	12.4	$	9.6	$	16.6

28

	For the Three Months Ended												For the Six Months Ended
	June 30, 2010						June 30, 2009						June 30, 2010						June 30, 2009
(Millions of Dollars)	CL&P		PSNH		WMECO		CL&P		PSNH		WMECO		CL&P		PSNH		WMECO			CL&P		PSNH		WMECO
Other Income:
Investment Income	$	-	$	-	$	-	$	4.1	$	1.0	$	0.9	$	-	$	-	$	-	$	2.1	$	0.5	$	0.4
Interest Income		1.4		0.5		0.2		1.1		0.8		0.1		2.0		0.7		0.4		1.9		1.8		0.2
AFUDC - Equity Funds		1.2		2.4		0.2		1.7		0.8		-		2.5		4.2		0.2		1.6		1.7		-
Energy Independence     Act Incentives		0.9		-		-		0.7		-		-		2.3		-		-		4.3		-		-
Other		-		0.1		0.4		0.6		0.2		0.1		0.3		0.1		0.5		1.0		0.2		0.4
Total Other Income		3.5		3.0		0.8		8.2		2.8		1.1		7.1		5.0		1.1		10.9		4.2		1.0
Other Loss:
Investment Loss		(2.7)		(0.7)		(0.6)		-		-		-		(1.4)		(0.3)		(0.3)		-		-		(0.1)
Other		(0.1)		(2.5)		-		-		-		-		-		(2.5)		-		-		-		-
Total Other Loss		(2.8)		(3.2)		(0.6)		-		-		-		(1.4)		(2.8)		(0.3)		-		-		(0.1)
Total Other   Income/(Loss), Net	$	0.7	$	(0.2)	$	0.2	$	8.2	$	2.8	$	1.1	$	5.7	$	2.2	$	0.8	$	10.9	$	4.2	$	0.9

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 June 30, 2010 and 2009, and a de minimis amount and $1 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 six months ended June 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 and six months ended June 30, 2010 and 2009.  

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 $0.5 million (zero for CL&P, PSNH and WMECO) for both the three months ended June 30, 2010 and June 30, 2009, respectively.  Dividends received were $0.6 million and $3.3 million (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 six months ended June 30, 2010 and June 30, 2009, respectively.  

Included in Other Loss - Other for NU and PSNH for the three and six months ended June 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.

H.

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 June 30, 2010, Select Energy had $3.7 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 $27.2 million and $28.1 million as of June 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 June 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 June 30, 2010 and December 31, 2009, there were no counterparty deposits for these companies.  

I.

Income Taxes

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.  NU recorded approximately $18 million in charges to Income Tax Expense on the accompanying unaudited condensed consolidated statement of income for the three months ended March 31, 2010 as a result of the 2010 Healthcare Act.  This represented the loss of previously recognized accumulated deferred income tax assets.  Since the electric and natural gas distribution companies are cost-of-service and rate regulated, som e of these costs are able to be deferred and recovered through future rates.  As a result, NU recognized approximately $15 million in after-tax deferrals ($24.4 million pre-tax) in Other Long-Term Assets on the accompanying unaudited condensed consolidated balance sheet as of March 31, 2010 with an offset to Amortization of Regulatory (Liabilities)/Assets, Net on the accompanying unaudited condensed consolidated statement of income, which reflects the anticipated recovery in future rates of these previously recognized lost tax benefits.  Therefore, the write-down of existing tax assets resulting from this law change reduced 2010 earnings on a net basis by approximately  $3 million.  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 current period benefits.

29

Tax Positions:  In June 2009, the Internal Revenue Service completed its audit of NU federal tax years 2005 through 2007, bringing closure to, and effective settlement of, issues concerning the timing of certain deductions through 2007.  The audit closure reduced pre-tax interest expense by $5.4 million ($3.1 million for CL&P, $1.6 million for PSNH, and $0.5 million for WMECO), while the income tax expense impact resulted in a $1 million tax benefit.  

J.

Other Taxes

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

	For the Three Months Ended				For the Six Months Ended
(Millions of Dollars)	June 30, 2010		June 30, 2009		June 30, 2010		June 30, 2009
NU	$	33.1	$	30.8	$	72.0	$	69.8
CL&P		30.2		27.7		62.2		58.6

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

K.

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 June 30, 2010 and December 31, 2009:   

			Shares
			Authorized	Issued
		Per Share Par Value	As of June 30, 2010 and December 31, 2009	As of June 30, 2010	As of December 31, 2009
NU	$	5	225,000,000	195,685,837	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 June 30, 2010 and December 31, 2009, 19,587,635 and 19,708,136 NU common shares were held as treasury shares, respectively.

L.

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 June 30, 2010.

M.

Supplemental Cash Flow Information

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

(Millions of Dollars)	As of June 30, 2010		As of December 31, 2009
NU	$	109.9	$	125.5
CL&P		27.8		48.2
PSNH		50.2		46.5
WMECO		12.9		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 six-month period ended June 30, 2009 in the unaudited condensed consolidated statement of cash flows.  For the six month period ended June 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 standard or last resort 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.  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.  Manage ment believes any costs or benefits from these contracts are recoverable from or will be refunded to CL&P's customers, and, therefore any changes in fair value are recorded as Regulatory Assets and Regulatory Liabilities on the accompanying unaudited condensed consolidated balance sheets.

WMECO mitigates the risks associated with the volatility of the prices of energy and energy-related products in procuring energy supply for its customers through the use of 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 that include nonderivative contracts and contracts that are accounted for as normal.  Yankee Gas enters into contracts to meet required demand levels throughout the heating season and manages supply risk through the use of options contracts.  Management believes any costs or benefits from these contracts are recoverable from or will be refundable to Yankee Gas' 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 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 June 30, 2010
	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	$	-	$	-	$	-	$	7.3	$	-	$	7.3
Level 3:
NU Enterprises		-		1.8		-		-		-		1.8
CL&P		17.6		-		2.2		-		-		19.8
Total Current Derivative Assets	$	17.6	$	1.8	$	2.2	$	7.3	$	-	$	28.9
Long-Term Derivative Assets:
Level 2:
NU Parent	$	-	$	-	$	-	$	8.0	$	-	$	8.0
Level 3:
NU Enterprises		-		2.2		-		-		-		2.2
CL&P(1)		228.2		-		-		-		(78.0)		150.2
Total Long-Term Derivative Assets	$	228.2	$	2.2	$	-	$	8.0	$	(78.0)	$	160.4
Current Derivative Liabilities:
Level 2:
PSNH	$	-	$	-	$	(18.0)	$	-	$	-	$	(18.0)
Level 3:
NU Enterprises(2)		-		(12.4)		-		-		3.7		(8.7)
CL&P		(13.7)		-		(0.3)		-		-		(14.0)
Yankee Gas		-		-		(0.5)		-		-		(0.5)
Total Current Derivative Liabilities	$	(13.7)	$	(12.4)	$	(18.8)	$	-	$	3.7	$	(41.2)
Long-Term Derivative Liabilities:
Level 2:
PSNH	$	-	$	-	$	(5.9)	$	-	$	-	$	(5.9)
Level 3:
NU Enterprises(1)		-		(31.4)		-		-		0.3		(31.1)
CL&P		(972.5)		-		-		-		-		(972.5)
Yankee Gas		-		-		(0.3)		-		-		(0.3)
Total Long-Term Derivative Liabilities	$	(972.5)	$	(31.4)	$	(6.2)	$	-	$	0.3	$	(1,009.8)

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 June 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 1B, "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 June 30, 2010 and December 31, 2009, NU Enterprises had approximately 0.3 million MWh and 0.4 million MWh, respectively, 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 June 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 June 30, 2010 and December 31, 2009, CL&P had 1.5 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 0.7 million and 1 million MWh of power as of June 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 0.3 million and 0.6 million MWh of electricity through December 2010 as of June 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 June 30, 2010 and December 31, 2009, there were 0.2 million and 0.4 million MWh, respectively, remaining 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.  

As of June 30, 2010 and December 31, 2009, Yankee Gas had two peaking supply option contracts to purchase up to 17 thousand MMBtu of natural gas on up to 20 days per season to manage natural gas supply price risk related to winter load obligations.  One contract for three thousand MMBtu expires on October 31, 2010 and the other contract for 14 thousand MMBtu expires on April 1, 2012.  Demand fees on these contracts are paid annually and are included in Yankee Gas' PGA clause for recovery.  

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	Location of Gain or Loss	For the Three Months Ended				For the Six Months Ended
Designated as Hedges	Recognized on Derivative	June 30, 2010		June 30, 2009		June 30, 2010		June 30, 2009
(Millions of Dollars)
NU Enterprises:
Commodity Sales Contract and   Related Price and Supply    Risk Management	Fuel, Purchased and Net   Interchange Power	$	0.7	$	2.4	$	0.5	$	7.8
Regulated Companies:
CL&P Energy and Capacity   Contracts Required by   Regulation	Regulatory Assets/Liabilities		(23.1)		61.2		(91.8)		50.2
Other Commodity Price and   Supply Risk Management:
CL&P	Regulatory Assets/Liabilities		(0.6)		(1.1)		(3.6)		(7.0)
PSNH	Regulatory Assets/Liabilities		1.9		(8.3)		(15.7)		(50.8)
Yankee Gas	Regulatory Assets/Liabilities		-		(1.2)		(0.4)		(2.1)

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 six months ended June 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 Expense and is i ncluded in Prepayments and Other Current Assets.  

34

For the three and six months ended June 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
	June 30, 2010				June 30, 2009
(Millions of Dollars)	Swap		Hedged Debt		Swap		Hedged Debt
Changes in Fair Value	$	3.5	$	(3.5)	$	(3.8)	$	3.8
Interest Recorded in Net Income		-		2.5		-		2.4

	For the Six Months Ended
	June 30, 2010				June 30, 2009
(Millions of Dollars)	Swap		Hedged Debt		Swap		Hedged Debt
Changes in Fair Value	$	7.4	$	(7.4)	$	(3.3)	$	3.3
Interest Recorded in Net Income		-		5.3		-		3.8

There were no cash flow hedges outstanding as of or during the three or six months ended June 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 Loss.  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 Loss and is amortized into Net Income over the term of the underlying debt in strument.  

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

	For the Three Months Ended				For the Six Months Ended
(Millions of Dollars)	June 30, 2010		June 30, 2009		June 30, 2010		June 30, 2009
CL&P	$	(0.2)	$	(0.2)	$	(0.4)	$	(0.4)
PSNH		-		-		(0.1)		(0.1)
WMECO		-		-		0.1		0.1
Other		0.1		0.1		0.2		0.2
NU	$	(0.1)	$	(0.1)	$	(0.2)	$	(0.2)

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, CL&P's bilateral agreements 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 June 30, 2010 and December 31, 2009:

	As of June 30, 2010
(Millions of Dollars)	Fair Value Subject to Credit Risk Contingent Features		Cash Collateral Posted		Standby LOCs Posted
PSNH	$	(23.9)	$	-	$	29.0
NU Enterprises		(21.0)		3.7		-
NU	$	(44.9)	$	3.7	$	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, CL&P or PSNH, respectively, if the respective unsecured debt credit ratings of NU parent, CL&P or PSNH are downgraded below investment grade.  As of June 30, 2010, no additional cash collateral

35

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 $17.5 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 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 1H, "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 (including 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 incl ude 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 six months ended June 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 liabilities for th e three or six months ended June 30, 2010 or 2009:

36

	For the Three Months Ended June 30, 2010
	NU
(Millions of Dollars)	Commodity and Capacity Contracts Required By Regulation		Commodity Sales Contracts 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	$	(792.9)	$	(42.6)	$	1.6	$	(833.9)
Net Realized/Unrealized Gains/(Losses) Included in:
Net Income(1)		-		0.7		-		0.7
Regulatory Assets/Liabilities		(23.1)		-		(0.6)		(23.7)
Purchases, Issuances and Settlements		(2.3)		2.4		-		0.1
Fair Value as of End of Period	$	(818.3)	$	(39.5)	$	1.0	$	(856.8)
Period Change in Unrealized Gains Included in  Net Income Relating to Items Held as of End of Period	$	-	$	0.5	$	-	$	0.5

	For the Three Months Ended June 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	$	(792.9)	$	2.4	$	(790.5)	$	-
Net Realized/Unrealized Losses Included in:
Regulatory Assets/Liabilities		(23.1)		(0.6)		(23.7)		-
Purchases, Issuances and Settlements		(2.3)		-		(2.3)		-
Fair Value as of End of Period	$	(818.3)	$	1.8	$	(816.5)	$	-

	For the Six Months Ended June 30, 2010
	NU
(Millions of Dollars)	Commodity and Capacity Contracts Required By Regulation		Commodity Sales Contracts 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)		-		0.5		-		0.5
Regulatory Assets/Liabilities		(91.8)		-		(4.2)		(96.0)
Purchases, Issuances and Settlements		(6.2)		5.2		0.9		(0.1)
Fair Value as of End of Period	$	(818.3)	$	(39.5)	$	1.0	$	(856.8)
Period Change in Unrealized Losses Included in  Net Income Relating to Items Held as of End of Period	$	-	$	(0.1)	$	-	$	(0.1)

	For the Six Months Ended June 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		(91.8)		(3.6)		(95.4)		(0.2)
Purchases, Issuances and Settlements		(6.2)		0.9		(5.3)		(0.2)
Fair Value as of End of Period	$	(818.3)	$	1.8	$	(816.5)	$	-

37

(Millions of Dollars)	For the Three Months Ended June 30, 2009						For the Six Months Ended June 30, 2009
Derivatives, Net:	NU		CL&P		PSNH		NU		CL&P		PSNH
Fair Value as of Beginning of Period	$	(680.3)	$	(633.3)	$	1.4	$	(669.2)	$	(611.1)	$	4.1
Net Realized/Unrealized   Gains/(Losses) Included in:
Net Income(1)		2.4		-		-		7.8		-		-
Regulatory Assets/Liabilities		58.8		60.1		(0.1)		38.3		43.2		(2.8)
Purchases, Issuances and   Settlements		5.1		2.7		-		9.1		(2.6)		-
Fair Value as of End of Period	$	(614.0)	$	(570.5)	$	1.3	$	(614.0)	$	(570.5)	$	1.3
Period Change in Unrealized Gains   Included in Net Income Relating to   Items Held as of End of Period	$	2.2	$	-	$	-	$	7.4	$	-	$	-

⁽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.  

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 the Employee Retirement Income Security Act.  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 six months ended June 30, 2010 and 2009 are as follows:

	For the Three Months Ended June 30,
NU	Pension Benefits				PBOP Benefits				SERP Benefits
(Millions of Dollars)	2010		2009		2010		2009		2010		2009
Service Cost	$	12.2	$	11.3	$	2.0	$	1.8	$	0.2	$	0.2
Interest Cost		37.7		38.3		6.7		7.2		0.6		0.6
Expected Return on Plan Assets		(45.7)		(47.3)		(5.5)		(5.3)		-		-
Net Transition Obligation Cost		-		6.8		2.9		2.4		-		-
Prior Service Cost		2.5		2.4		-		-		-		-
Actuarial Loss/(Gain)		13.6		(1.6)		4.4		3.2		0.2		0.1
Total - Net Periodic Expense	$	20.3	$	9.9	$	10.5	$	9.3	$	1.0	$	0.9
CL&P - Net Periodic Expense/(Income)	$	2.2	$	(1.4)	$	4.2	$	3.8	$	0.1	$	0.1
PSNH - Net Periodic Expense	$	7.0	$	5.8	$	2.0	$	1.7	$	0.1	$	0.1
WMECO - Net Periodic (Income)/Expense	$	*	$	(0.7)	$	0.8	$	0.7	$	*	$	*

	For the Six Months Ended June 30,
NU	Pension Benefits				PBOP Benefits				SERP Benefits
(Millions of Dollars)	2010		2009		2010		2009		2010		2009
Service Cost	$	25.1	$	22.5	$	4.3	$	3.6	$	0.4	$	0.4
Interest Cost		75.2		76.8		13.4		14.5		1.1		1.1
Expected Return on Plan Assets		(91.3)		(94.7)		(10.8)		(10.4)		-		-
Net Transition Obligation Cost		-		6.9		5.7		5.2		-		-
Prior Service Cost/(Credit)		4.9		4.9		(0.1)		-		-		0.1
Actuarial Loss		26.3		3.5		8.3		5.7		0.5		0.2
Total - Net Periodic Expense	$	40.2	$	19.9	$	20.8	$	18.6	$	2.0	$	1.8
CL&P - Net Periodic Expense/(Income)	$	4.3	$	(2.8)	$	8.5	$	7.8	$	0.2	$	0.2
PSNH - Net Periodic Expense	$	14.0	$	11.6	$	3.9	$	3.5	$	0.1	$	0.1
WMECO - Net Periodic (Income)/Expense	$	(0.1)	$	(1.4)	$	1.5	$	1.4	$	*	$	*

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

38

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 June 30,
	CL&P				PSNH				WMECO
(Millions of Dollars)	2010		2009		2010		2009		2010		2009
Pension Benefits	$	6.0	$	3.0	$	1.4	$	0.7	$	1.1	$	0.4
PBOP Benefits		2.1		2.0		0.5		0.5		0.4		0.3
SERP Benefits		0.5		0.5		0.1		0.1		0.1		0.1

	For the Six Months Ended June 30,
	CL&P				PSNH				WMECO
(Millions of Dollars)	2010		2009		2010		2009		2010		2009
Pension Benefits	$	11.6	$	6.7	$	2.7	$	1.5	$	2.1	$	1.0
PBOP Benefits		4.0		3.7		1.0		0.9		0.7		0.6
SERP Benefits		1.0		0.9		0.3		0.2		0.2		0.1

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 June 30,				For the Six Months Ended June 30,
(Millions of Dollars)	2010		2009		2010		2009
NU	$	4.4	$	1.5	$	8.8	$	3.1
CL&P		1.8		(0.1)		3.5		(0.1)
PSNH		2.1		1.5		4.1		2.9
WMECO		0.1		(0.2)		0.3		(0.3)

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

4.

COMMITMENTS AND CONTINGENCIES

A.

Environmental Matters (NU, PSNH)  

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.  MGP sites comprise the largest portion of the Company's environmental liabilities.  MGP sites are sites where the process of producing manufactured gas from coal created certain byproducts that may pose a risk to human health and the environment.

Environmental Matters Impacting Net Income:

HWP is a subsidiary of NU that remains in the process of evaluating additional potential remediation requirements at a river site in Massachusetts containing tar deposits associated with a MGP site which it sold to HG&E in 1902.  MGP sites are sites where the process of producing manufactured gas from coal created certain byproducts that may pose a risk to human health and the environment.  HWP shares responsibility for the site with HG&E and has already conducted substantial investigative and remediation activities.  HWP first established a reserve for this site in 1994.  

The MA DEP issued a letter in 2008 to HWP and HG&E providing conditional authorization for additional investigatory and risk characterization activities and providing detailed comments on HWP's 2007 reports and proposals for further investigations.  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 developed and implemented site characterization studies to further delineate tar deposits in conformity with the MA DEP's guidance letter.  On April 5, 2010, HWP delivered a report to the MA DEP describing the results to date of its site investigation studies and testing.  These matters are subject to ongoing discussions with the MA DEP and HG&E and are subject to change in the future.

Pre-tax charges of $1.1 million and $3 million were recorded in 2009 and 2008, respectively, to reflect the estimated costs of tar delineation and site characterization studies.  In the first quarter of 2010, a pre-tax charge of $1 million was recorded to reflect the estimated remaining costs to complete these studies and analyze and substantiate them for the MA DEP.  The cumulative expense recorded to the reserve for this environmental matter through June 30, 2010 was approximately $17.9 million, of which $16.5 million had been spent, leaving approximately $1.4 million in the reserve as of June 30, 2010, representing estimated costs for HWP to substantiate its studies and conduct certain soft tar remediation activities.  Management believes that the $1.4 million remaining in the reserve is at the low end of a range of probable costs for HWP and additional costs cannot be reasonably estimated at this time.

There are many factors that could affect management's estimates and require an increase to the reserve, which would be reflected as a charge to Net Income.  However, management cannot reasonably estimate potential additional investigation or remediation costs because they will depend on, among other things, the nature, extent and timing of additional investigation and remediation that may be required by the MA DEP.  These costs could be material to the financial statements.  HWP's share of the costs related to this site is not recoverable from customers.  

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Environmental Matters Not Impacting Net Income:

PSNH has conducted substantial investigative activities and evaluated remediation requirements in the Ashuelot River and Mill Creek in Keene, New Hampshire, which contains coal tar deposits.  Yankee Gas has conducted substantial investigative activities, evaluated remediation options, and developed remediation action plans for the Meriden and Bristol sites in Connecticut, which contain coal tar deposits.

In the first quarter of 2010, $7.5 million was recorded to PSNH's environmental reserve for the Keene sites to reflect estimated remediation activities approved by the New Hampshire Department of Environmental Services and expected to be performed in 2010 and 2011.  In the second quarter of 2010, $5.4 million was recorded to Yankee Gas' environmental reserve for the Meriden and Bristol sites to reflect estimated remediation activities necessary to achieve compliance with Connecticut Remediation Standard Regulations, which are expected to be performed in 2011.  As of June 30, 2010, the $12.9 million was recorded in Other Long-Term Liabilities with an offset recorded to Regulatory Assets on the accompanying unaudited condensed consolidated balance sheet because both PSNH and Yankee Gas have a regulatory rate recovery mechanism for environmental costs.  Management believes these costs are probable of recovery in future c ost-of-service regulated rates.

The cumulative cost recorded to NU's reserve for these environmental matters through June 30, 2010 was approximately $21 million ($13.6 million for PSNH and $7.4 million for Yankee Gas), of which $8.6 million ($6.8 million for PSNH and $1.8 million for Yankee Gas) had been spent, leaving approximately $12.4 million ($6.8 million for PSNH and $5.6 million for Yankee Gas) in the reserve as of June 30, 2010.  The $12.4 million remaining in the reserve is management's best estimate to complete the remediation activities.  

The amounts recorded as environmental liabilities included in Other Long-Term Liabilities on the accompanying consolidated balance sheets represent management’s best estimate of environmental costs, if reasonably estimable, and take into consideration site assessment and remediation costs.  A reconciliation of the activity in the environmental reserve as of June 30, 2010 and December 31, 2009 is as follows:

	NU		CL&P		PSNH		WMECO
Balance as of December 31, 2009	$	26.0	$	2.7	$	5.3	$	0.4
Additions		9.0		0.1		7.6		-
Payments		(1.0)		(0.1)		(0.1)		(0.1)
Balance as of March 31, 2010		34.0		2.7		12.8		0.3
Additions		5.5		0.2		-		0.1
Payments		(1.1)		(0.1)		(0.8)		(0.1)
Balance as of June 30, 2010	$	38.4	$	2.8	$	12.0	$	0.3

B.

Guarantees and Indemnifications

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

NU 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 tax and environmental laws, and various claims for which the maximum exposure was not specified in the sale agreements.

40

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 June 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 Date(s)
Various	Surety Bonds	$ 11.5		July 2010 - June 2011 (1)
PSNH and Select Energy	Letters Of Credit	$ 39.6		November 2010
RRR and NUSCO	Lease Payments for Real Estate and Vehicles	$ 22.7		2019-2024
NU Enterprises	Surety Bonds, Insurance Bonds and Performance Guarantees	$ 119.6	(2)	(2)

(1)

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

(2)

The maximum exposure includes $72.3 million related to performance guarantees on Select Energy's wholesale purchase contracts, which expire in 2013, assuming purchase contracts guaranteed have no value; however, actual exposures vary with underlying commodity prices.  The maximum exposure also includes $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 June 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 $28.7 million of maximum exposure relates to surety bonds covering ongoing projects at Boulos, which expire upon project completion.

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

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

5.

COMPREHENSIVE INCOME

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

	Three Months Ended June 30,				Six Months Ended June 30,
	2010		2009		2010		2009
(Millions of Dollars)		NU		NU		NU		NU
Net Income	$	73.3	$	84.2	$	160.9	$	183.3
Other Comprehensive Income/(Loss) Items, Net of Tax:
Qualified Cash Flow Hedging Instruments(1)		-		-		0.1		0.1
Changes in Unrealized Gains/(Losses) on Other Securities(2)		0.3		(1.0)		0.6		(1.1)
Change In Pension, SERP and PBOP Benefit Plans		0.6		(0.9)		1.0		(0.7)
Other Comprehensive Income/(Loss) Items		0.9		(1.9)		1.7		(1.7)
Total Comprehensive Income		74.2		82.3		162.6		181.6
Comprehensive Income Attributable to Noncontrolling Interests		(1.4)		(1.4)		(2.8)		(2.8)
Comprehensive Income Attributable to Controlling Interests	$	72.8	$	80.9	$	159.8	$	178.8

	Three Months Ended June 30, 2010						Three Months Ended June 30, 2009
(Millions of Dollars)	CL&P		PSNH		WMECO		CL&P		PSNH		WMECO
Net Income	$	44.1	$	21.6	$	5.2	$	58.4	$	16.6	$	5.8
Other Comprehensive Income/(Loss) Items, Net of Tax:
Qualified Cash Flow Hedging Instruments(1)		0.1		-		-		0.1		-		-
Change in Unrealized Losses on Other Securities(2)		-		-		-		-		(0.1)		(0.1)
Other Comprehensive Income/(Loss) Items		0.1		-		-		0.1		(0.1)		(0.1)
Total Comprehensive Income	$	44.2	$	21.6	$	5.2	$	58.5	$	16.5	$	5.7

41

	Six Months Ended June 30, 2010						Six Months Ended June 30, 2009
(Millions of Dollars)	CL&P		PSNH		WMECO		CL&P		PSNH		WMECO
Net Income	$	92.5	$	37.4	$	10.9	$	111.5	$	34.1	$	12.0
Other Comprehensive Income/(Loss) Items, Net of Tax:
Qualified Cash Flow Hedging Instruments(1)		0.2		0.1		-		0.2		-		-
Change in Unrealized Losses on Other Securities(2)		-		-		-		-		-		(0.2)
Other Comprehensive Income/(Loss) Items		0.2		0.1		-		0.2		-		(0.2)
Total Comprehensive Income	$	92.7	$	37.5	$	10.9	$	111.7	$	34.1	$	11.8

⁽¹⁾

Hedged transactions impacting Net income in the tables above represent amounts that were reclassified from Accumulated Other Comprehensive 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 June 30, 2010, the balance included in Accumulated Other Comprehensive Loss related to hedging activities was $4.3 million, $3 million, $0.7 million, and a de minimis amount 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 9, "Marketable Securities," to the unaudited condensed consolidated financial statements.  

There were no forward starting interest rate swaps entered into for the three and six months ended June 30, 2010 or June 30, 2009.  For NU, it is estimated that a charge of $0.2 million will be reclassified from Accumulated Other Comprehensive 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 June 30, 2010, it is estimated that a pre-tax amount of $0.7 million included in the Accumulated Other Comprehensive 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.

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 six month period ended June 30, 2010, there were 3,156 share awards excluded from the computation as these awards were antidilutive.  There were no antidilutive share awards outstanding for the three month period ended Ju ne 30, 2010.  For both the three and six month periods ended June 30, 2009, there were 54,036 share awards excluded from the computation, as these awards were antidilutive.  

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

(Millions of Dollars, except for		For the Three Months Ended June 30,				For the Six Months Ended June 30,
share information)		2010		2009		2010		2009
Net Income Attributable to Controlling Interests	$		71.9	$	82.9	$	158.2	$	180.5
Basic Weighted Average Common   Shares Outstanding			176,571,189		175,175,936		176,460,476		168,758,206
Dilutive Effect			165,343		499,452		176,527		542,071
Fully Diluted Weighted Average   Common Shares Outstanding			176,736,532		175,675,388		176,637,003		169,300,277
Basic and Fully Diluted EPS	$		0.41	$	0.47	$	0.90	$	1.07

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.  

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7.

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 June 30, 2010.  

8.

FAIR VALUE OF FINANCIAL INSTRUMENTS

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

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

	As of June 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	$	92.9	$	116.2	$	86.8
Long-Term Debt -
First Mortgage Bonds		2,703.4		3,027.2		2,657.7		2,713.5
Other Long-Term Debt		1,988.8		2,058.0		1,893.6		1,938.0
Rate Reduction Bonds		313.8		346.9		442.4		487.3

		As of June 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	$	92.9		$	-	$	-	$	-	$	-
Long-Term Debt -
First Mortgage Bonds			1,919.8		2,174.2			430.0		464.0		-		-
Other Long-Term Debt			667.6		672.9			407.3		414.4		401.0		418.0
Rate Reduction Bonds			99.3		116.4			163.5		175.5		51.0		55.1

		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 $300.8 million and $300.6 million of fees and interest due for spent nuclear fuel disposal costs as of June 30, 2010 and December 31, 2009, respectively.  CL&P's portion of this obligation is $243.6 million and $243.5 million as of June 30, 2010 and December 31, 2009, respectively.  WMECO's portion of this obligation is $57.2 million as of June 30, 2010 and $57.1 million as of December 31, 2009, respectively.

43

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 1B, "Summary of Significant Accounting Policies - Fair Value Measurements," and Note 9, "Marketable Securities," to the unaudited condensed consolidated financial statements.

NU parent holds a long-term government receivable related to SESI.  The carrying value of the receivable was $10.4 million and $8.8 million as of June 30, 2010 and December 31, 2009, respectively and is included in Other Long-Term Assets on the accompanying unaudited condensed consolidated balance sheets.  The fair value of this receivable was $11.3 million and $10.6 million as of June 30, 2010 and December 31, 2009, respectively, and was determined based on discounted cash flows over the weighted average life of the anticipated cash flow stream.  

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

9.

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 $32.8 million and $35.3 million as of June 30, 2010 and December 31, 2009, respectively.  Net losses on these securities of $4.2 million and $2.5 million for the three and six months ended June 30, 2010 and $0.5 million for the three and six months ended June 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 s ecurities 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 June 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)	$	12.9	$	0.4	$	-	$	13.3
Corporate Debt Securities		8.5		0.6		(0.1)		9.0
Asset Backed Debt Securities		6.2		0.4		-		6.6
Municipal Bonds		0.3		-		-		0.3
Money Market Funds and Other		1.9		-		-		1.9
Total NU Supplemental Benefit Trust	$	29.8	$	1.4	$	(0.1)	$	31.1

WMECO spent nuclear fuel trust
U.S. Government Issued Debt Securities   (Agency and Treasury)	$	6.0	$	-	$	-	$	6.0
Corporate Debt Securities		18.1		0.1		(0.2)		18.0
Money Market Funds and Other		18.3		-		-		18.3
Asset Backed Debt Securities		5.3		-		(0.1)		5.2
Municipal Bonds		9.3		-		-		9.3
Total WMECO Spent Nuclear Fuel Trust	$	57.0	$	0.1	$	(0.3)	$	56.8
Total NU	$	86.8	$	1.5	$	(0.4)	$	87.9

44

	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
Municipal Bonds		0.2		-		-		0.2
Asset Backed Debt Securities		5.2		0.1		(0.1)		5.2
Money Market Funds and Other		3.0		-		-		3.0
Total NU Supplemental Benefit Trust	$	28.6	$	0.8	$	(0.4)	$	29.0

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
Municipal Bonds		10.6		-		-		10.6
Asset Backed Debt Securities		1.1		-		(0.2)		0.9
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 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 Loss, see Note 5, "Comprehensive Income," to the unaudited condensed consolidated financial statements.

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

As of June 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.  Credit losses for the NU supplemental benefit trust were de minimis for the six months ended June 30, 2010 and were recorded in Other Income, Net on the accompanying unaudited condensed consolidated income statement. There were no credit losses for the WMECO spent nuclear fuel trust for the six months ended June 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 corporate 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 Loss, see Note 5, "Comprehensive Income," to the unaudited condensed consolidated financial statements.

45

Contractual Maturities:  As of June 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	$	39.9	$	39.9	$	35.8	$	35.7
One to five years		18.1		18.3		12.0		12.0
Six to ten years		4.9		5.2		-		-
Greater than ten years		23.9		24.5		9.2		9.1
Total Debt Securities	$	86.8	$	87.9	$	57.0	$	56.8

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

	Three Months Ended June 30, 2010						Six Months Ended June 30, 2010
(Millions of Dollars)		Realized Gains		Realized Losses		Net Realized Gains		Realized Gains		Realized Losses		Net Realized Gains/(Losses)
NU	$	0.1	$	(0.1)	$	-	$	0.2	$	(0.2)	$	-
WMECO		-		-		-		-		(0.1)		(0.1)

	Three Months Ended June 30, 2009						Six Months Ended June 30, 2009
(Millions of Dollars)		Realized Gains		Realized Losses		Net Realized Gains/(Losses)		Realized Gains		Realized Losses		Net Realized Gains/(Losses)
NU	$	5.7	$	(0.4)	$	5.3	$	6.3	$	(1.4)	$	4.9
WMECO		-		(0.1)		(0.1)		-		(0.1)		(0.1)

Realized gains and losses on available-for-sale-securities are recorded in Other Income, Net for the NU supplemental benefit trust and in Other Long-Term Assets for the WMECO spent nuclear fuel trust.  NU utilizes the specific identification basis method for the NU supplemental benefit trust securities and the average cost basis method for the WMECO spent nuclear fuel trust to compute the realized gains and losses on the sale of available-for-sale securities.  Proceeds from the sale of these securities, including proceeds from short-term investments, totaled $74.1 million and $95.5 million for the three and six months ended June 30, 2010 and $94.8 million and $147.7 million for the three and six months ended June 30, 2009, respectively.  WMECO's portion of these proceeds totaled $58 million and $69.2 million for the three and six months ended June 30, 2010, respectively, and $42.6 million and $78.3 million for the three an d six months ended June 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
	As of June 30, 2010		As of December 31, 2009		As of June 30, 2010		As of December 31, 2009
Level 1:
Exchange Traded Funds	$	29.5	$	32.0	$	-	$	-
High Yield Bond Fund		3.1		3.3		-		-
Money Market Funds		1.4		8.9		0.2		6.6
Total Level 1		34.0		44.2		0.2		6.6
Level 2:
U.S. Government Issued Debt Securities       (Agency and Treasury)		19.3		29.9		6.0		17.0
Corporate Debt Securities		27.0		25.1		18.0		17.4
Asset Backed Securities		11.8		6.1		5.2		0.9
Municipal Bonds		9.6		10.8		9.3		10.6
Other Fixed Income Securities		19.0		5.0		18.1		4.3
Total Level 2		86.7		76.9		56.6		50.2
Total Marketable Securities	$	120.7	$	121.1	$	56.8	$	56.8

U.S. Treasury and Agency bonds are valued using market approaches that incorporate transactions for the same or similar bonds and adjustments for yields and maturity dates.  Corporate bonds 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 securities include collateralized mortgage obligations, commercial mortgage-backed securities, and securities collateralized by auto loans, credit card loans or receivables.  Asset-backed securities are valued using recent trades of similar instruments, prepayment assumptions, yield curves, issuance and maturity dates and tranche information.  Other bonds are valued using pricing models, quoted prices of securities with simi lar characteristics, and discounted cash flows.

Not included in the tables above are $56.6 million and $11.6 million of cash equivalents as of June 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.

46

10.

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.  The Regulated companies' segments represented approximately 99 percent of NU's total consolidated revenues for the three and six month periods ended June 30, 2010 and 2009.  PSNH's distribution segment includes its generation activities.  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 six months ended June 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 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 six months ended June 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 June 30, 2010
	Regulated Companies
	Distribution
(Millions of Dollars)	Electric		Natural Gas		Transmission		NU Enterprises		Other		Eliminations		Total
Operating Revenues	$	884.5	$	73.5	$	154.2	$	22.2	$	111.6	$	(134.6)	$	1,111.4
Depreciation and Amortization		(111.6)		(7.0)		(21.6)		(0.1)		(3.4)		0.7		(143.0)
Other Operating Expenses		(696.3)		(62.0)		(45.4)		(14.9)		(102.2)		130.7		(790.1)
Operating Income		76.6		4.5		87.2		7.2		6.0		(3.2)		178.3
Interest Expense		(35.7)		(5.5)		(19.1)		(0.5)		(7.6)		1.2		(67.2)
Interest (Loss)/Income		(1.5)		-		1.2		-		1.4		(2.3)		(1.2)
Other (Loss)/Income, Net		(0.5)		0.1		1.5		1.1		71.0		(70.4)		2.8
Income Tax (Expense)/Benefit		(10.5)		0.4		(28.3)		(2.5)		1.5		-		(39.4)
Net Income/(Loss)		28.4		(0.5)		42.5		5.3		72.3		(74.7)		73.3
Net Income/(Loss)     Attributable to Noncontrolling  Interests		(0.8)		-		(0.6)		-		-		-		(1.4)
Net Income/(Loss)   Attributable to Controlling   Interests	$	27.6	$	(0.5)	$	41.9	$	5.3	$	72.3	$	(74.7)	$	71.9

47

	For the Six Months Ended June 30, 2010
	Regulated Companies
	Distribution
(Millions of Dollars)	Electric		Natural Gas		Transmission		NU Enterprises		Other		Eliminations		Total
Operating Revenues	$	1,884.5	$	245.2	$	307.9	$	41.5	$	216.4	$	(244.7)	$	2,450.8
Depreciation and Amortization		(214.7)		(10.6)		(41.8)		(0.2)		(7.1)		1.6		(272.8)
Other Operating Expenses		(1,497.8)		(191.7)		(92.4)		(28.3)		(204.5)		241.7		(1,773.0)
Operating Income		172.0		42.9		173.7		13.0		4.8		(1.4)		405.0
Interest Expense		(72.2)		(10.4)		(38.5)		(0.9)		(14.8)		2.4		(134.4)
Interest (Loss)/Income		(0.8)		-		1.4		-		2.7		(3.7)		(0.4)
Other Income, Net		4.2		0.1		3.9		1.0		182.8		(182.0)		10.0
Income Tax (Expense)/Benefit		(45.6)		(13.6)		(57.2)		(5.5)		2.9		(0.2)		(119.2)
Net Income		57.6		19.0		83.3		7.6		178.4		(184.9)		161.0
Net Income Attributable to   Noncontrolling Interests		(1.6)		-		(1.2)		-		-		-		(2.8)
Net Income Attributable to  Controlling Interests	$	56.0	$	19.0	$	82.1	$	7.6	$	178.4	$	(184.9)	$	158.2
Total Assets (as of)	$	8,860.1	$	1,370.8	$	3,327.7	$	93.9	$	5,951.5	$	(5,374.3)	$	14,229.7
Cash Flows for Total   Investments in Plant	$	267.9	$	28.0	$	113.1	$	-	$	33.4	$	-	$	442.4

	For the Three Months Ended June 30, 2009
	Regulated Companies
	Distribution
(Millions of Dollars)	Electric		Gas		Transmission		NU Enterprises		Other		Eliminations		Total
Operating Revenues	$	1,007.2	$	70.2	$	135.8	$	21.0	$	93.0	$	(102.8)	$	1,224.4
Depreciation and Amortization		(88.4)		(6.7)		(17.9)		(0.1)		(3.1)		0.2		(116.0)
Other Operating Expenses		(837.5)		(57.9)		(36.8)		(11.8)		(92.1)		106.9		(929.2)
Operating Income/(Loss)		81.3		5.6		81.1		9.1		(2.2)		4.3		179.2
Interest Expense		(36.2)		(5.0)		(16.5)		(0.6)		(8.2)		1.5		(65.0)
Interest Income		1.5		-		0.6		-		1.9		(2.0)		2.0
Other Income, Net		6.7		0.1		3.2		-		91.8		(91.3)		10.5
Income Tax (Expense)/Benefit		(14.9)		(0.1)		(26.0)		(3.0)		1.9		(0.3)		(42.4)
Net Income		38.4		0.6		42.4		5.5		85.2		(87.8)		84.3
Net Income Attributable to  Noncontrolling Interests		(0.8)		-		(0.6)		-		-		-		(1.4)
Net Income Attributable to   Controlling Interests	$	37.6	$	0.6	$	41.8	$	5.5	$	85.2	$	(87.8)	$	82.9

	For the Six Months Ended June 30, 2009
	Regulated Companies
	Distribution
(Millions of Dollars)	Electric		Gas		Transmission		NU Enterprises		Other		Eliminations		Total
Operating Revenues	$	2,253.2	$	272.0	$	269.9	$	41.7	$	200.2	$	(219.1)	$	2,817.9
Depreciation and Amortization		(215.6)		(13.4)		(35.2)		(0.3)		(6.5)		0.4		(270.6)
Other Operating Expenses		(1,866.7)		(215.6)		(76.3)		(21.6)		(190.4)		219.8		(2,150.8)
Operating Income		170.9		43.0		158.4		19.8		3.3		1.1		396.5
Interest Expense		(74.0)		(11.3)		(34.2)		(1.8)		(18.1)		3.5		(135.9)
Interest Income		3.2		-		0.7		0.1		4.3		(4.3)		4.0
Other Income, Net		9.6		0.1		2.5		-		209.1		(208.8)		12.5
Income Tax (Expense)/Benefit		(30.5)		(12.0)		(49.0)		(6.8)		5.4		(0.9)		(93.8)
Net Income		79.2		19.8		78.4		11.3		204.0		(209.4)		183.3
Net Income Attributable to  Noncontrolling Interests		(1.6)		-		(1.2)		-		-		-		(2.8)
Net Income Attributable to  Controlling Interests	$	77.6	$	19.8	$	77.2	$	11.3	$	204.0	$	(209.4)	$	180.5
Cash Flows for Total   Investments in Plant	$	259.8	$	25.4	$	121.0	$	-	$	14.7	$	-	$	420.9

48

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

	CL&P - For the Three Months Ended June 30, 2010
(Millions of Dollars)	Distribution		Transmission		Total
Operating Revenues	$	584.0	$	123.9	$	707.9
Depreciation and Amortization		(90.7)		(16.8)		(107.5)
Other Operating Expenses		(460.0)		(34.2)		(494.2)
Operating Income		33.3		72.9		106.2
Interest Expense		(21.5)		(15.7)		(37.2)
Interest Income		0.5		0.9		1.4
Other Loss/(Income), Net		(1.2)		0.5		(0.7)
Income Tax Expense		(1.9)		(23.7)		(25.6)
Net Income	$	9.2	$	34.9	$	44.1

	CL&P - For the Six Months Ended June 30, 2010
(Millions of Dollars)	Distribution		Transmission		Total
Operating Revenues	$	1,255.2	$	247.7	$	1,502.9
Depreciation and Amortization		(166.5)		(33.5)		(200.0)
Other Operating Expenses		(1,001.2)		(70.0)		(1,071.2)
Operating Income		87.5		144.2		231.7
Interest Expense		(43.9)		(31.8)		(75.7)
Interest Income		0.9		1.1		2.0
Other Income, Net		1.1		2.5		3.6
Income Tax Expense		(21.3)		(47.8)		(69.1)
Net Income	$	24.3	$	68.2	$	92.5
Total Assets (as of)	$	5,675.0	$	2,552.7	$	8,227.7
Cash Flows for Total Investments in Plant	$	132.4	$	59.3	$	191.7

	CL&P – For the Three Months Ended June 30, 2009
(Millions of Dollars)	Distribution		Transmission		Total
Operating Revenues	$	673.4	$	111.5	$	784.9
Depreciation and Amortization		(72.1)		(14.8)		(86.9)
Other Operating Expenses		(552.3)		(27.6)		(579.9)
Operating Income		49.0		69.1		118.1
Interest Expense		(23.1)		(14.6)		(37.7)
Interest Income		0.6		0.5		1.1
Other Income, Net		4.4		2.6		7.0
Income Tax Expense		(8.2)		(21.9)		(30.1)
Net Income	$	22.7	$	35.7	$	58.4

	CL&P - For the Six Months Ended June 30, 2009
(Millions of Dollars)	Distribution		Transmission		Total
Operating Revenues	$	1,517.3	$	222.1	$	1,739.4
Depreciation and Amortization		(157.6)		(29.3)		(186.9)
Other Operating Expenses		(1,261.9)		(57.1)		(1,319.0)
Operating Income		97.8		135.7		233.5
Interest Expense		(45.6)		(29.8)		(75.4)
Interest Income		1.3		0.6		1.9
Other Income, Net		7.3		1.6		8.9
Income Tax Expense		(15.6)		(41.8)		(57.4)
Net Income	$	45.2	$	66.3	$	111.5
Cash Flows For Total Investments in Plant	$	149.0	$	77.9	$	226.9

	PSNH - For the Three Months Ended June 30, 2010
(Millions of Dollars)	Distribution		Transmission		Total
Operating Revenues	$	218.2	$	20.1	$	238.3
Depreciation and Amortization		(14.0)		(2.6)		(16.6)
Other Operating Expenses		(170.0)		(8.3)		(178.3)
Operating Income		34.2		9.2		43.4
Interest Expense		(9.9)		(2.1)		(12.0)
Interest (Loss)/Income		(2.2)		0.2		(2.0)
Other Income, Net		1.6		0.2		1.8
Income Tax Expense		(6.8)		(2.8)		(9.6)
Net Income	$	16.9	$	4.7	$	21.6

49

	PSNH - For the Six Months Ended June 30, 2010
(Millions of Dollars)	Distribution		Transmission		Total
Operating Revenues	$	457.1	$	39.8	$	496.9
Depreciation and Amortization		(34.0)		(5.3)		(39.3)
Other Operating Expenses		(358.5)		(15.8)		(374.3)
Operating Income		64.6		18.7		83.3
Interest Expense		(20.2)		(4.2)		(24.4)
Interest (Loss)/Income		(1.9)		0.1		(1.8)
Other Income, Net		3.5		0.5		4.0
Income Tax Expense		(17.9)		(5.8)		(23.7)
Net Income	$	28.1	$	9.3	$	37.4
Total Assets (as of)	$	2,316.2	$	475.6	$	2,791.8
Cash Flows for Total Investments in Plant	$	122.8	$	18.9	$	141.7

	PSNH - For the Three Months Ended June 30, 2009
(Millions of Dollars)	Distribution		Transmission		Total
Operating Revenues	$	246.2	$	16.7	$	262.9
Depreciation and Amortization		(11.9)		(2.3)		(14.2)
Other Operating Expenses		(211.3)		(6.2)		(217.5)
Operating Income		23.0		8.2		31.2
Interest Expense		(9.2)		(1.3)		(10.5)
Interest Income		0.8		0.1		0.9
Other Income, Net		1.4		0.5		1.9
Income Tax Expense		(4.1)		(2.8)		(6.9)
Net Income	$	11.9	$	4.7	$	16.6

	PSNH - For the Six Months Ended June 30, 2009
(Millions of Dollars)	Distribution		Transmission		Total
Operating Revenues	$	537.5	$	33.1	$	570.6
Depreciation and Amortization		(44.5)		(4.5)		(49.0)
Other Operating Expenses		(441.4)		(12.9)		(454.3)
Operating Income		51.6		15.7		67.3
Interest Expense		(20.2)		(2.9)		(23.1)
Interest Income		1.7		0.1		1.8
Other Income, Net		1.8		0.7		2.5
Income Tax Expense		(9.4)		(5.0)		(14.4)
Net Income	$	25.5	$	8.6	$	34.1
Cash Flows for Total Investments in Plant	$	89.2	$	23.2	$	112.4

	WMECO - For the Three Months Ended June 30, 2010
(Millions of Dollars)	Distribution		Transmission		Total
Operating Revenues	$	82.3	$	10.2	$	92.5
Depreciation and Amortization		(6.9)		(2.1)		(9.0)
Other Operating Expenses		(66.3)		(2.9)		(69.2)
Operating Income		9.1		5.2		14.3
Interest Expense		(4.4)		(1.3)		(5.7)
Interest Income		0.1		0.1		0.2
Other (Loss)/Income, Net		(0.8)		0.7		(0.1)
Income Tax Expense		(1.7)		(1.8)		(3.5)
Net Income	$	2.3	$	2.9	$	5.2

	WMECO - For the Six Months Ended June 30, 2010
(Millions of Dollars)	Distribution		Transmission		Total
Operating Revenues	$	172.3	$	20.4	$	192.7
Depreciation and Amortization		(14.3)		(3.0)		(17.3)
Other Operating Expenses		(138.1)		(6.6)		(144.7)
Operating Income		19.9		10.8		30.7
Interest Expense		(8.1)		(2.5)		(10.6)
Interest Income		0.2		0.2		0.4
Other (Loss)/Income, Net		(0.4)		0.8		0.4
Income Tax Expense		(6.4)		(3.6)		(10.0)
Net Income	$	5.2	$	5.7	$	10.9
Total Assets (as of)	$	874.2	$	290.2	$	1,164.4
Cash Flows for Total Investments in Plant	$	12.8	$	33.6	$	46.4

50

	WMECO - For the Three Months Ended June 30, 2009
(Millions of Dollars)	Distribution		Transmission		Total
Operating Revenues	$	87.5	$	7.6	$	95.1
Depreciation and Amortization		(4.4)		(0.8)		(5.2)
Other Operating Expenses		(73.7)		(3.0)		(76.7)
Operating Income		9.4		3.8		13.2
Interest Expense		(3.8)		(0.6)		(4.4)
Interest Income		0.1		-		0.1
Other Income, Net		0.7		0.2		0.9
Income Tax Expense		(2.6)		(1.4)		(4.0)
Net Income	$	3.8	$	2.0	$	5.8

	WMECO - For the Six Months Ended June 30, 2009
(Millions of Dollars)	Distribution		Transmission		Total
Operating Revenues	$	198.5	$	14.7	$	213.2
Depreciation and Amortization		(13.5)		(1.6)		(15.1)
Other Operating Expenses		(163.4)		(6.2)		(169.6)
Operating Income		21.6		6.9		28.5
Interest Expense		(8.3)		(1.4)		(9.7)
Interest Income		0.1		0.1		0.2
Other Income, Net		0.7		0.1		0.8
Income Tax Expense		(5.5)		(2.3)		(7.8)
Net Income	$	8.6	$	3.4	$	12.0
Cash Flows for Total Investments in Plant	$	21.6	$	19.9	$	41.5

11.

COMMON SHAREHOLDERS' EQUITY AND NONCONTROLLING INTERESTS (NU)

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

	For the Three Months Ended June 30,
	2010								2009
	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	$	3,625.2	$	-	$	3,625.2	$	116.2	$	3,456.1	$	116.2
Net Income		73.3		-		73.3		-		84.2		-
Dividends on Common Shares		(45.4)		-		(45.4)		-		(41.8)		-
Dividends on Preferred   Shares of CL&P		(1.4)		-		(1.4)		(1.4)		(1.4)		(1.4)
Issuance of Common Shares		0.2		-		0.2		-		0.1		-
Contributions to NPT		-		1.1		1.1		-		-		-
Other Transactions, Net		6.1		-		6.1		-		6.5		-
Net Income Attributable to   Noncontrolling Interests		-		-		-		1.4		-		1.4
Other Comprehensive Income   (Note 5)		0.9		-		0.9		-		(1.9)		-
Balance, End of Period	$	3,658.9	$	1.1	$	3,660.0	$	116.2	$	3,501.8	$	116.2

51

	For the Six Months Ended June 30,
	2010								2009
	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		160.9		-		160.9		-		183.3		-
Dividends on Common Shares		(90.9)		-		(90.9)		-		(79.1)		-
Dividends on Preferred   Shares of CL&P		(2.8)		-		(2.8)		(2.8)		(2.8)		(2.8)
Issuance of Common Shares		5.4		-		5.4		-		387.4		-
Capital Stock Expenses, Net		-		-		-		-		(12.5)		-
Contributions to NPT		-		1.1		1.1		-		-		-
Other Transactions, Net		6.7		-		6.7		-		6.9		-
Net Income Attributable to   Noncontrolling Interests		-		-		-		2.8		-		2.8
Other Comprehensive Income   (Note 5)		1.7		-		1.7		-		(1.7)		-
Balance, End of Period	$	3,658.9	$	1.1	$	3,660.0	$	116.2	$	3,501.8	$	116.2

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

52

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 June 30, 2010, and the related condensed consolidated statements of income for the three-month and six-month periods ended June 30, 2010 and 2009, and of cash flows for the six-month periods ended June 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

August 6, 2010

53

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 Quarter 2010 Form 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, 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.

54

Financial Condition and Business Analysis

Executive Summary

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

Results and Outlook:

·

We earned $71.9 million, or $0.41 per share, in the second quarter of 2010, and $158.2 million, or $0.90 per share, in the first half of 2010, compared with $82.9 million, or $0.47 per share, in the second quarter of 2009 and $180.5 million, or $1.07 per share, in the first half of 2009.  Lower 2010 results reflect the absence of the net benefit of $11.1 million, or $0.06 per share, from the resolution of various routine tax issues in the second quarter of 2009.  The first half 2010 results also reflect a first quarter net after-tax charge of $3 million, or $0.02 per share, associated with the 2010 Healthcare Act.  

·

Our Regulated companies earned $69 million, or $0.39 per share, in the second quarter of 2010 and $157.1 million, or $0.89 per share, in the first half of 2010, compared with earnings of $80 million, or $0.46 per share, in the second quarter of 2009 and $174.6 million, or $1.03 per share, in the first half of 2009.  

·

Earnings from the distribution segment of our Regulated companies (which also includes the generation business of PSNH and the natural gas distribution business) totaled $27.1 million, or $0.15 per share, in the second quarter of 2010, and $75 million, or $0.43 per share, in the first half of 2010, compared with $38.2 million, or $0.22 per share, in the second quarter of 2009 and $97.4 million, or $0.57 per share, in the first half of 2009.  Earnings from the transmission segment of our Regulated companies totaled $41.9 million, or $0.24 per share, in the second quarter of 2010 and $82.1 million, or $0.46 per share, in the first half of 2010, compared with $41.8 million, or $0.24 per share, in the second quarter of 2009 and $77.2 million, or $0.46 per share, in the first half of 2009.  The decrease in distribution segment results was due primarily to the absence in 2010 of the benefit from the resolution of various routine tax issues.  The higher transmission segment results were due to an increased investment in this segment as we continued to build out our transmission infrastructure to meet the reliability needs of our customers and the region, partially offset by the absence in 2010 of the benefit from the resolution of various routine tax issues.  

·

Our competitive businesses, which are held by NU Enterprises, earned $5.3 million, or $0.03 per share, in the second quarter of 2010 and $7.6 million, or $0.04 per share, in the first half of 2010, compared with $5.5 million, or $0.03 per share, in the second quarter of 2009 and $11.3 million, or $0.07 per share, in the first half of 2009.  NU Enterprises recorded $0.1 million of after-tax mark-to-market losses in the first half of 2010, compared with $4.6 million of after-tax mark-to-market gains in the first half of 2009.

·

NU parent and other companies recorded net expenses of $2.4 million, or $0.01 per share, in the second quarter of 2010 and $6.5 million, or $0.03 per share, in the first half of 2010, compared with net expenses of $2.6 million, or $0.02 per share, in the second quarter of 2009 and $5.4 million, or $0.03 per share, in the first half of 2009.  The improved second quarter results were due to the absence in 2010 of a $0.7 million after-tax HWP environmental reserve increase.  The lower first half results were due primarily to a $0.6 million after-tax charge associated with the 2010 Healthcare Act and the absence in 2010 of its share of the benefit from the resolution of various routine tax issues.  

·

Economic factors, moderate weather, and higher operating costs, including higher storm restoration activity, have been pressuring our distribution segment returns over the past 12 months.  However, the constructive resolution of CL&P and PSNH’s distribution rate cases at the end of June, as well as the impacts of strong cost management and prospects for improving sales, will provide us with improved results over the next several quarters.  

·

We now project consolidated 2010 earnings of between $1.95 per share and $2.05 per share, including distribution segment earnings of between $1.00 per share and $1.10 per share, transmission segment earnings of approximately $0.95 per share, competitive business earnings of approximately $0.05 per share, and net expenses at NU parent and other companies of approximately $0.05 per share.  Previously, NU had projected consolidated earnings of between $1.80 per share and $2.00 per share.  We revised our 2010 earnings guidance due in part to the constructive resolution of the CL&P and PSNH distribution rate cases, the impact of significantly warmer than expected weather on electric distribution sales, an improvement in uncollectible expense trends, and improved results at the transmission segment and our competitive businesses for the first half of 2010, partially offset by a much higher level of storm acti vity in 2010 as compared with 2009.

Strategy, Regulatory and Other Items:

·

On June 30, 2010, the DPUC issued a final decision in a distribution rate case, which was filed by CL&P in January 2010, that approved rate increases of $63.4 million effective July 1, 2010 and an incremental $38.5 million effective July 1, 2011.  The decision approved CL&P’s proposal to defer implementation of the first increase by six months until January 1, 2011 and maintained CL&P’s authorized distribution segment regulatory ROE of 9.4 percent.  

55

·

On June 28, 2010, the NHPUC approved the joint settlement reached in April 2010 among PSNH, the NHPUC staff and the Office of Consumer Advocate regarding a distribution rate case PSNH had filed on June 30, 2009 with the NHPUC.  The settlement allowed PSNH to raise distribution rates by $45.5 million on an annualized basis, effective July 1, 2010.  It also approved distribution rate adjustments projected to be a decrease of $2.9 million and increases of $9.5 million and $11.1 million on July 1 of each of the three subsequent years, respectively.  The $45.5 million increase was in addition to the $25.6 million temporary increase that became effective August 1, 2009.  The $45.5 million increase includes $13.7 million to reconcile the difference between the temporary rates and the permanent rates back to August 1, 2009.  Another provision of the settlement was that the authorized electric di stribution business regulatory ROE continues at the previously allowed level of 9.67 percent.  

·

Connecticut Governor M. Jodi Rell approved the Connecticut Legislature's state budget for the 2010-2011 fiscal year.  To fund a revenue gap, the 2010-2011 budget now calls for the issuance of $703 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 utility companies.  On June 1, 2010, the DPUC initiated a docket to approve financing orders for the state’s electric distribution companies, including CL&P, in accordance with Public Act 10-179.  The DPUC must issue a financing order by October 1, 2010.

·

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 of its deferred December 2008 major storm costs, and recovery of its hardship receivable costs.  A decision is expected by January 31, 2011.

Liquidity:

·

Cash capital expenditures totaled $442.4 million in the first half of 2010, compared with $420.9 million in the first half of 2009.  We continue to project total capital expenditures of approximately $1.1 billion in 2010.  

·

Cash flows provided by operating activities totaled $405.2 million in the first half of 2010, compared with $388 million in the first half 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 a $40 million increase in income tax payments largely attributable to the absence of certain tax deductions related to accelerated depreciation amounts, which expired at the end of 2009.  We project consolidated cash flows provided by operating activities, net of RRB payments, of approximately $700 million in 2010, which is $50 million higher than our first quarter 2010 projection due primarily to the expected third quarter sales increase as a result of the significantly warmer than expected weather and modest improvements in economic conditions in our region that we expect will benefit our cash flows over the second half of 2010.  

·

On July 9, 2010, following the CL&P and PSNH rate case decisions, Moody’s announced that it had reaffirmed the ratings and "stable" outlooks of NU parent, CL&P and PSNH.  On July 27, 2010, S&P reaffirmed all of its ratings and "stable" outlooks associated with NU and its subsidiaries.

·

Cash and cash equivalents totaled $88.8 million as of June 30, 2010, compared with $27 million as of December 31, 2009.  As of June 30, 2010, we had $647.1 million of aggregate borrowing availability on our revolving credit lines, compared with $702.8 million as of December 31, 2009.  

Overview

Consolidated:  We earned $71.9 million, or $0.41 per share, in the second quarter of 2010, and $158.2 million, or $0.90 per share in the first half of 2010, compared with $82.9 million, or $0.47 per share, in the second quarter of 2009 and $180.5 million, or $1.07 per share, in the first half of 2009.  Lower 2010 results reflect the absence of the net benefit impact of $11.1 million, or $0.06 per share, from the resolution of various routine tax issues in the second quarter of 2009 and $14 million of pre-tax storm restoration costs in the first half of 2010 ($8 million in the second quarter of 2010).  The first half 2010 results also reflect a first quarter net after-tax charge of $3 million, or $0.02 per share, associated with the 2010 Healthcare Act, offset by the impact of the PSNH permanent distribution rate case settlement approved on June 28, 2010, which allowed certain expenses to be recovered through non-distribution rate c omponents retroactive to August 1, 2009.  Retail electric sales were unchanged and firm natural gas sales were down 3.7 percent in the first half of 2010 compared with the first half of 2009.

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 second quarter and first half of 2010 and 2009 is as follows:

56

	For the Three Months Ended June 30,								For the Six Months Ended June 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)	$	71.9	$	0.41	$	82.9	$	0.47	$	158.2	$	0.90	$	180.5	$	1.07
Regulated Companies	$	69.0	$	0.39	$	80.0	$	0.46	$	157.1	$	0.89	$	174.6	$	1.03
Competitive Businesses		5.3		0.03		5.5		0.03		7.6		0.04		11.3		0.07
NU Parent and Other Companies		(2.4)		(0.01)		(2.6)		(0.02)		(6.5)		(0.03)		(5.4)		(0.03)
Net Income Attributable to   Controlling Interests (GAAP)	$	71.9	$	0.41	$	82.9	$	0.47	$	158.2	$	0.90	$	180.5	$	1.07

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

	For the Three Months Ended June 30,				For the Six Months Ended June 30,
(Millions of Dollars)	2010		2009		2010		2009
CL&P Transmission	$	34.3	$	35.1	$	67.1	$	65.2
PSNH Transmission		4.6		4.7		9.3		8.6
WMECO Transmission		3.0		2.0		5.7		3.4
Total Transmission		41.9		41.8		82.1		77.2
CL&P Distribution		8.4		21.9		22.7		43.6
PSNH Distribution		16.9		11.9		28.1		25.4
WMECO Distribution		2.3		3.8		5.2		8.6
Yankee Gas		(0.5)		0.6		19.0		19.8
Total Distribution		27.1		38.2		75.0		97.4
Net Income - Regulated Companies	$	69.0	$	80.0	$	157.1	$	174.6

Greater transmission segment earnings in both the second quarter and first half of 2010 reflected increased investment as we continued to build out our transmission infrastructure to meet the reliability needs of our customers and the region, partially offset by the absence of the benefit from the resolution of various routine tax issues in the second quarter of 2009, a charge associated with the 2010 Healthcare Act in the first quarter of 2010, and net losses realized on the sale of securities in the NU supplemental benefit trust.  

CL&P’s second quarter 2010 distribution segment earnings were $8.4 million, which is approximately $13.5 million lower than the same period in 2009.  The decline in earnings was due primarily to the absence of the $5.1 million benefit from the resolution of routine tax issues in the second quarter of 2009, higher expenses including storm restoration costs, pension and healthcare costs, and property taxes and net losses realized on the sale of securities in the NU supplemental benefit trust.  Partially offsetting these impacts was higher revenue attributable to warmer weather and a 6.1 percent increase in retail electric sales.

For the first half of 2010, CL&P’s distribution segment earnings were $20.9 million lower than the same period in 2009 due primarily to the same unfavorable factors that affected earnings in the second quarter mentioned above, the absence of an $8.4 million benefit from the resolution of routine tax issues in the first half of 2009, coupled with lower revenues and lower Energy Independence Act incentives, partially offset by lower operations and maintenance costs.  For the 12 months ended June 30, 2010, CL&P’s distribution segment regulatory ROE was approximately 5.4 percent and for the full year 2010, we expect it to be between 7.5 percent and 8 percent.

PSNH’s second quarter 2010 distribution segment earnings were $5 million higher than the same period in 2009 due primarily to higher revenues resulting from a temporary distribution rate increase effective August 1, 2009, a 4.6 percent increase in retail electric sales, and the impact of the permanent distribution rate case settlement approved on June 28, 2010, which allowed certain expenses to be recovered through non-distribution rate components retroactive to August 1, 2009.  These favorable impacts were partially offset by the absence of the benefit from the resolution of the various routine tax issues in the second quarter of 2009, higher expenses including pension and healthcare costs, amortization, and property taxes, and net losses realized on the sale of securities in the NU supplemental benefit trust.

For the first half of 2010, PSNH’s distribution segment earnings were $2.7 million higher than the same period in 2009 due primarily to higher revenues as a result of the August 1, 2009 distribution rate increase and the impact of the permanent distribution rate case settlement, partially offset by higher pension and healthcare costs and property taxes, the absence of the benefit from the resolution of routine tax issues in the second quarter of 2009, higher income tax expense in the first quarter associated with the 2010 Healthcare Act, and net losses realized on the sale of securities in the NU supplemental benefit trust.  For the 12 months ended June 30, 2010, PSNH’s distribution segment regulatory ROE was 7.7 percent (including generation) and for the full year 2010, we expect it to be close to the authorized levels.

WMECO’s second quarter 2010 distribution segment earnings were $1.5 million lower than the same period in 2009 due primarily to higher expenses including storm restoration costs, employee benefit costs and property taxes, the absence of the benefit from the resolution of routine tax issues in the second quarter of 2009, and net losses realized on the sale of securities in the NU supplemental benefit trust, partially offset by higher revenues attributable to warmer weather and a 7.1 percent increase in retail electric sales.

57

WMECO’s distribution segment earnings for the first half of 2010 were $3.4 million lower than the same period in 2009 due primarily to higher expenses including storm restoration costs, employee benefit costs, administrative and general costs, depreciation, and property taxes, the absence of the benefit from the resolution of the various routine tax issues in the second quarter of 2009, and net losses realized on the sale of securities in the NU supplemental benefit trust.  For the 12 months ended June 30, 2010, WMECO’s distribution segment regulatory ROE was 6.6 percent and for the full year 2010, we expect it to be approximately 5 percent.

Yankee Gas recorded a net loss of $0.5 million in the second quarter of 2010, which is $1.1 million lower than the $0.6 million of earnings in the second quarter of 2009.  The decline in earnings was due primarily to a 4.3 percent decline in firm natural gas sales attributable to warmer than normal temperatures in April, the absence of the benefit from the resolution of routine tax issues in the second quarter of 2009, higher operations costs and pension and healthcare costs, partially offset by lower uncollectibles expense and depreciation.

For the first half of 2010, Yankee Gas’ earnings were $0.8 million lower than the same period in 2009 due primarily to lower revenues resulting from a 3.7 percent decline in firm natural gas sales attributable to warmer than normal temperatures during the heating season.  In addition, the 2010 earnings were lower due to higher operations costs, pension and healthcare costs, amortization, and the absence of the benefit from the resolution of the various routine tax issues in the second quarter of 2009, partially offset by lower uncollectibles expense, depreciation, and interest expense.  For the 12 months ended June 30, 2010, Yankee Gas’ regulatory ROE was 6.5 percent and for the full year 2010, we expect it to be approximately 8 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 second quarter and first half of 2010 as compared to the same period in 2009 on an actual and weather normalized basis (using a 30-year average) is as follows:

	For the Three Months Ended June 30, 2010 Compared to 2009
	Electric								Firm Natural Gas
	CL&P		PSNH		WMECO		Total		Yankee Gas
	Percentage Increase	Weather Normalized Percentage Increase/ (Decrease)	Percentage Increase	Weather Normalized Percentage Increase	Percentage Increase	Weather Normalized Percentage Increase	Percentage Increase	Weather Normalized Percentage Increase	Percentage Decrease	Weather Normalized Percentage Increase/ (Decrease)
Residential	9.3 %	1.7 %	5.6%	1.0 %	9.4 %	3.8 %	8.5 %	1.8 %	(2.2)%	10.4 %
Commercial	4.2 %	-	3.7%	0.3 %	7.1 %	3.1 %	4.3 %	0.4 %	(4.5)%	4.9 %
Industrial	2.3 %	(1.0)%	5.0%	1.3 %	3.5 %	1.1 %	3.3 %	-	(5.2)%	(3.6)%
Other	11.4 %	11.4 %	0.2%	0.2 %	2.6 %	2.6 %	10.1 %	10.1 %	-	-
Total	6.1 %	0.7 %	4.6%	0.7 %	7.1 %	3.0 %	5.9 %	1.0 %	(4.3)%	2.2 %

	For the Six Months Ended June 30, 2010 Compared to 2009
	Electric								Firm Natural Gas
	CL&P		PSNH		WMECO		Total		Yankee Gas
	Percentage Increase/ (Decrease)	Weather Normalized Percentage Increase/ (Decrease)	Percentage Increase/ (Decrease)	Weather Normalized Percentage Increase/ (Decrease)	Percentage Increase/ (Decrease)	Weather Normalized Percentage Increase/ (Decrease)	Percentage Increase/ (Decrease)	Weather Normalized Percentage Decrease	Percentage Decrease	Weather Normalized Percentage Increase
Residential	-	(0.3)%	(1.0)%	(0.6)%	2.2 %	2.4 %	-	(0.1)%	(4.8)%	7.4 %
Commercial	(0.4)%	(2.0)%	(0.7)%	(1.8)%	0.7 %	(0.8)%	(0.4)%	(1.8)%	(5.7)%	5.2 %
Industrial	3.1 %	1.3 %	0.2 %	(1.7)%	(0.3)%	(1.5)%	1.7 %	-	(0.3)%	2.6 %
Other	-	-	2.6 %	2.6 %	(31.5)%	(31.5)%	(2.3)%	(2.3)%	-	-
Total	0.2 %	(0.9)%	(0.7)%	(1.3)%	0.9 %	0.1 %	-	(0.8)%	(3.7)%	5.1 %

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 second quarter and first half of 2010 and 2009 is as follows:  

	For the Three Months Ended June 30,
	Electric			Firm Natural Gas
	2010	2009	Percentage Increase	2010	2009	Percentage Decrease
Residential	3,220	2,967	8.5 %	1,659	1,695	(2.2)%
Commercial	3,620	3,469	4.3 %	2,004	2,099	(4.5)%
Industrial	1,156	1,119	3.3 %	3,269	3,448	(5.2)%
Other	72	67	10.1 %	-	-	-
Total	8,068	7,622	5.9 %	6,932	7,242	(4.3)%

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	For the Six Months Ended June 30,
	Electric			Firm Natural Gas
	2010	2009	Percentage Increase/(Decrease)	2010	2009	Percentage Decrease
Residential	7,116	7,116	-	7,763	8,156	(4.8)%
Commercial	7,076	7,102	(0.4)%	7,886	8,366	(5.7)%
Industrial	2,164	2,128	1.7 %	7,726	7,754	(0.3)%
Other	160	164	(2.3)%	-	-	-
Total	16,516	16,510	-	23,375	24,276	(3.7)%

Actual retail electric sales for all three electric companies were greater in the second quarter of 2010 as compared to the same period in 2009, due primarily to warmer than normal temperatures.  Cooling degree days in Connecticut and Western Massachusetts were 128 percent higher than last year and 76 percent above normal.  Cooling degree days in New Hampshire were 216 percent higher than last year and 41 percent above normal.  Weather normalized retail electric sales increased by one percent in the second quarter of 2010 as compared to the same period in 2009, due primarily to what we believe could be signs of improvement in our region's economy.

For the first half of 2010, total retail electric sales were unchanged from the same period in 2009, but the results vary by electric company and customer class.  While our customers continue to be impacted by the economic conditions of our region and nation, we see potential signs of improvement that are starting to emerge.  In addition to the primary economic drivers of employment levels, manufacturing hours, and new housing permits, our electric sales are also impacted by additional installation of gas-fired distributed generation and utilization of C&LM programs.  For the past several quarters, our commercial and industrial sales have been negatively impacted by such measures.

Firm natural gas sales in the second quarter and first half of 2010 were lower than the same periods in 2009 due to milder weather.  On a weather normalized basis, firm natural gas sales were 2.2 percent and 5.1 percent higher in the second quarter and first half of 2010 than the same periods in 2009, respectively.  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 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, however, from an earnings perspective because a portion of the total uncollectibles expense for each of the electric distribution companies is allocated 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 (or hardship customers) are fully recovered through their respective tariffs.  For the second quarter and first half of 2010, our total uncollectibles expense was approximately $5.1 million lower and $0.3 million higher than the same periods in 2009, respectively.  With regards to the portion of the uncollectibles expense that impacts our earnings as it is not allocated to an energy supply rate, the expense for the first half of 2010 was $2.4 million lower than the same period in 2009 with $1.9 million relating to Yankee Gas.  In addition, $1.4 million of PSNH’s uncollectibles expense was reclassified to its energy supply rate in the second quarter of 2010, which in turn contributed to the overall improvement of $2.4 million in the non-allocated portion of uncollectibles expense but it had no impact on our total uncollectibles expense.  For the first half of 2010, our uncollectibles expense was better than our expectations and we continue to expect our 2010 uncollectibles expense that impacts earnings to be significantly lower than it was in 2009.

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 $5.3 million, or $0.03 per share, in the second quarter of 2010 and $7.6 million, or $0.04 per share, in the first half of 2010, compared with $5.5 million, or $0.03 per share, in the second quarter of 2009, and $11.3 million, or $0.07 per share, in the first half of 2009.  In the second quarter of 2010, NU Enterprises recorded $0.3 million of after-tax mark-to-market gains, compared with gains of $1.3 million in the second quarter of 2009.  NU Enterprises recorded $0.1 million of after-tax mark-to-market losses in the first half of 2010, compared with after-tax mark-to-market gains of $4.6 million in the first half of 2009.  

NU Parent and Other Companies:  NU parent and other companies recorded net expenses of $2.4 million, or $0.01 per share, in the second quarter of 2010 and $6.5 million, or $0.03 per share, in the first half of 2010, compared with net expenses of $2.6 million, or $0.02 per share, in the second quarter of 2009 and $5.4 million, or $0.03 per share, in the first half of 2009.  The improved second quarter results were due to the absence in 2010 of a $0.7 million after-tax HWP environmental reserve increase that was recorded in 2009.  The lower first half results were due primarily to a $0.6 million after-tax charge associated with the 2010 Healthcare Act and the absence in 2010 of a $1.3 million benefit from the resolution of various routine tax issues, 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:  

	Previously Reported 2010 EPS Range				Revised 2010 EPS Range
(Approximate amounts)		Low		High		Low		High
Fully Diluted EPS (GAAP)	$	1.80	$	2.00	$	1.95	$	2.05
Regulated Companies:
Distribution Segment	$	0.95	$	1.05	$	1.00	$	1.10
Transmission Segment		0.90		0.95		0.95		0.95
Total Regulated Companies		1.85		2.00		1.95		2.05
Competitive Businesses		-		0.05		0.05		0.05
NU Parent and Other Companies		(0.05)		(0.05)		(0.05)		(0.05)
Fully Diluted EPS (GAAP)	$	1.80	$	2.00	$	1.95	$	2.05

We revised our 2010 earnings guidance due in part to the constructive resolution of the CL&P and PSNH distribution rate cases, the impact of significantly warmer than expected weather on electric distribution sales, an improvement in uncollectible expense trends, and improved results at the transmission segment and our competitive businesses for the first half of 2010, partially offset by a much higher level of storm activity in 2010 as compared with 2009.  

Economic factors, moderate weather, and higher operating costs including higher storm restoration activity have been pressuring our distribution segment returns over the past 12 months.  However, the constructive resolution of CL&P and PSNH’s distribution rate cases at the end of June, as well as the impacts of strong cost management and prospects for improving sales, will provide us with improved results over the next several quarters.  

Long-Term Growth Rate:  We continue to project that we will achieve a compound average annual EPS growth rate for the five-year period from 2010 to 2014 of between 6 percent and 9 percent using 2009 EPS of $1.91 as the base level.  We believe this growth will be achieved if our capital program is completed in accordance with our plans, distribution rate case orders enable us to earn the assumed level of regulatory ROEs, and FERC's current transmission policies remain consistent and enable us to achieve projected transmission ROEs.  In addition to the assumptions above, there are certain items that will likely impact this earnings growth rate.  These items include, but are not limited to, sales levels; operating expense levels, including maintenance, pension and uncollectibles expense; and lower margins that NU Enterprises could earn on Select Energy’s remaining contracts.  

Liquidity

Consolidated:  Cash and cash equivalents totaled $88.8 million as of June 30, 2010, compared with $27 million as of December 31, 2009.  

On April 1, 2010, CL&P remarketed $62 million of tax-exempt PCRBs that were subject to a mandatory tender on April 1, 2010.  The PCRBs, which mature on May 1, 2031, carry a coupon rate of 1.4 percent and have a mandatory tender on April 1, 2011, at which time CL&P expects to remarket the bonds.

On April 22, 2010, Yankee Gas issued $50 million of privately placed first mortgage bonds with a coupon rate of 4.87 percent and a maturity date of April 1, 2020.  The proceeds from this bond issuance were used to repay short-term borrowings incurred in the ordinary course of business and to fund ongoing capital investment programs.  

On May 3, 2010, PSNH filed a petition with the NHPUC requesting authority to issue long-term debt through 2012 to be used to refinance PSNH’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.  PSNH has requested authority to issue up to $500 million and asked that the NHPUC issue an order by September 30, 2010.

On June 3, 2010, WMECO filed a petition with the DPU requesting authority to issue up to $500 million in long-term debt through 2012 to be used to refinance WMECO’s short-term debt previously incurred in the ordinary course of business, to finance capital expenditures, to provide working capital and to pay issuance costs.  WMECO has requested that the DPU issue an order by September 30, 2010.

On July 12, 2010, CL&P filed an application with the DPUC 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 has requested that the DPUC issue a decision by November 1, 2010.

We anticipate no additional long-term debt issuances for NU in 2010.

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Cash flows provided by operating activities in the first half of 2010 totaled $405.2 million, compared with operating cash flows of $388 million in the first half 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 $24 million reduction in coal inventory levels at the PSNH generation business as ordered by the NHPUC.  Offsetting these favorable cash flow impacts was a $40 million increase in income tax payments largely attributable to the absence of bonus depreciation tax deductions under the American Recovery and Reinvestment Act of 2009 in the first hal f of 2010.  Bonusdepreciation tax deductions expired at the end of 2009.  There is no significant cash flow impact relating to the decrease in receivables and unbilled revenues and the increase in accounts payable relating to customer migration to third party energy suppliers as these amounts offset one another.

We project consolidated cash flows provided by operating activities of approximately $700 million in 2010, net of RRB payments, which is $50 million higher than our first quarter 2010 projection due primarily to the expected third quarter sales increase as a result of the significantly warmer than expected weather and modest improvements in economic conditions in our region that we expect will benefit our cash flows over the second half of 2010.  The projection for 2010 operating cash flows reflects a cash contribution to our Pension Plan in the third quarter of 2010 of approximately $45 million, the majority of which will be funded by PSNH.  This contribution will be the first contribution to our Pension Plan in approximately 20 years.

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

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

On July 9, 2010, following the CL&P and PSNH rate case decisions, Moody’s announced that it had reaffirmed the ratings and “stable” outlooks of NU parent, CL&P and PSNH.  On July 27, 2010, S&P reaffirmed all of its ratings and "stable" outlooks associated with NU and its subsidiaries.

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 June 30, 2010, Select Energy, under its remaining contracts, would have been required to provide additional cash or LOCs in an aggregate amount of $26.7 million to various unaffiliated counterparties and additional cash or LOCs in the aggregate amount of $1.9 million to independent system operators.  NU parent would have been and remains able to provide that collateral on behalf of Select Energy.  

If the unsecured debt ratings of PSNH were to be reduced by either Moody's or S&P, certain supply contracts could require PSNH to post additional collateral in the form of cash or LOCs with various unaffiliated counterparties.  As of June 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 $90.2 million in the first half of 2010, compared with $78.9 million in the first half 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 July 12, 2010, our Board of Trustees declared a quarterly common dividend of $0.25625 per share, payable on September 30, 2010 to shareholders of record as of September 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 half of 2010, CL&P, PSNH, WMECO, and Yankee Gas paid $146 million, $25.3 million, $7.4 million, and $18.8 million, respectively, in common dividends to NU parent.  In the first half of 2010, NU parent made equity contributions to PSNH and WMECO of $115.4 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 half of 2010 and 2009 is as follows:

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	For the Six Months Ended June 30,
(Millions of Dollars)		2010		2009
CL&P	$	191.7	$	226.9
PSNH		141.7		112.4
WMECO		46.4		41.5
Yankee Gas		28.0		25.4
Other		34.6		14.7
Totals	$	442.4	$	420.9

The increase in our cash capital expenditures was the result of higher distribution segment capital expenditures of $10.9 million, particularly at PSNH, and an increase in Other of $19.9 million primarily related to technology and facility projects at NUSCO, one of our corporate service companies.

As a result of LBCB's refusal in 2008 to continue to fund its commitment of approximately $56 million under our revolving credit agreements, our aggregate borrowing capacity under those credit facilities was reduced from $900 million to $844 million.  This borrowing capacity, when combined with our access to other funding sources, provides us with adequate liquidity.  

NU parent’s revolving credit agreement, in a nominal aggregate amount of $500 million, $482.3 million excluding the commitment of LBCB, expires on November 6, 2010.  As of June 30, 2010, NU parent had $39.6 million of LOCs issued for the benefit of certain subsidiaries (primarily PSNH) and $157.3 million of borrowings outstanding under this facility.  The weighted-average interest rate on these short-term borrowings as of June 30, 2010 was 0.75 percent, which is based on a variable rate plus an applicable margin based on NU parent's credit ratings.  NU parent had $285.4 million of borrowing availability on this facility as of June 30, 2010, excluding LBCB's commitment, as compared to $341 million of availability as of December 31, 2009.  

The Regulated companies maintain a joint revolving credit agreement in a nominal aggregate amount of $400 million, $361.8 million excluding the commitment of LBCB, which also expires on November 6, 2010.  There were no borrowings outstanding under this facility as of June 30, 2010 or December 31, 2009, and the entire $361.8 million was available.  The Regulated companies had $361.8 million of aggregate borrowing availability on this facility as of June 30, 2010and December 31, 2009, excluding LBCB's commitment and subject to each individual company's borrowing limits.  

In August 2010, we expect to commence the renewal of our revolving credit agreements.  We anticipate extending the facilities for at least three years and that costs associated with the new facilities will be higher than those associated with the existing revolving credit agreements due to changes in credit market conditions.

Impact of Financial Market Conditions:  While the impact of continued financial market volatility and the extent and impacts of the economic environment cannot be predicted, we are confident that we currently have sufficient operating flexibility and access to funding sources to maintain adequate liquidity.  The credit ratings outlooks for NU parent and its Regulated companies are all stable.  Our companies have a low risk of calls for collateral due to our business model, and we have no long-term debt maturing until April 2012.  An estimated cash contribution to our Pension Plan of approximately $45 million is expected to be made in the third quarter of 2010, and we continue to project capital expenditures for 2010 of approximately $1.1 billion.  

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 $454.4 million in the first half of 2010, compared with $415.3 million in the first half of 2009.  These amounts included $29.8 million and $18 million in the first half 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 ($418 million for CL&P, $344 million for PSNH, and $145 million for WMECO) in 2010, which includes planned spending of approximately $48 million for our corporate service companies.  

Transmission Segment:  We now expect transmission segment capital expenditures to total approximately $257 million ($113 million for CL&P, $44 million for PSNH, and $92 million for WMECO) in 2010.  Transmission segment capital expenditures decreased by $14.4 million in the first half 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 Northern Pass Transmission for the Northern Pass project.  A summary of transmission segment capital expenditures by company in the first half of 2010 and 2009 is as follows:

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	For the Six Months Ended June 30,
(Millions of Dollars)		2010		2009
CL&P	$	51.2	$	75.4
PSNH		21.9		27.3
WMECO		37.4		24.9
Northern Pass Project Costs*		2.7		-
Totals	$	113.2	$	127.6

*

Since the inception of the Northern Pass project, we have incurred a total of $4.4 million in costs, $1.7 million of which was recognized in the second half of 2009.

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.  In October 2009, ISO-NE affirmed the need and need date for GSRP.  On March 16, 2010, the CSC approved the 12-mile section of GSRP that CL&P plans to build in Connecticut.  The CSC approval did not significantly change the project as it was originally proposed and is not expected to have a material impact on the overall cost of GSRP.  The CSC has begun reviewing CL&P development and management plans for the project.  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 route for the line.  We do not expect the appeal to have a material impact on the timing of construction.

Hearings on the 23-mile Massachusetts portion before the state’s EFSB were completed in February 2010, and briefs were filed by the parties on March 26, 2010.  We expect the EFSB to reach a tentative decision in September 2010 and a final decision shortly thereafter.  GSRP, which involves the construction of 115 KV and 345 KV lines from Ludlow, Massachusetts to Bloomfield, Connecticut, is the largest and most complicated project within NEEWS, and is expected to cost $714 million if built according to our preferred route configuration.  Following decisions from the state siting boards and receipt of other required permits, we expect to commence construction in late 2010 or early 2011 and to place the project in service in 2013.  

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 line from Lebanon, Connecticut to the Connecticut-Rhode Island border where it would connect with enhancements National Grid USA is designing.  We currently expect that CL&P's share of the costs of this project will be $250 million.  Municipal consultations concluded in November 2008, and CL&P plans to file its siting application with Connecticut regulators in early 2011 following the completion of ISO-NE’s reassessment of the need date and issuance of its regional system plan.  We currently expect the project to be placed in service by the end of 2014.  

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 connection to move power across the state of Connecticut.  The timing of this project is expected to be six to twelve months behind the Interstate Reliability Project.  This project is currently expected to cost $315 million.  

ISO-NE is currently performing an evaluation of projects in its regional system plan, including the other components of NEEWS, and assessing the presently estimated need dates for these projects.  We expect ISO-NE’s view on need dates for the second and third major NEEWS projects to be updated in the next version of the regional system plan, a draft of which we expect to see during the third quarter of 2010.

Included as part of NEEWS are $211 million of associated reliability related expenditures for projects, over $50 million of which are moving forward through the siting and construction phases and are expected to be completed in advance of the three major projects.  These include a $15 million line separation project under construction in Manchester, Connecticut and a line separation project from West Springfield to Agawam, Massachusetts that we now estimate will cost $26 million.  We expect to commence work on this project later this year and complete it in 2011.  On July 20, 2010 the CSC approved a new 345 KV line segment, 2.7 miles in length, from Manchester Substation to the Meekville Junction area, with associated 345 KV additions at Manchester Substation.  This project will change an existing 3-terminal circuit into two 2-terminal circuits resulting in improved reliability during contingency events and reducing t he need to run out-of-merit generation when the line is out for maintenance.  Construction is expected to begin in late 2010 following receipt of environmental permits.

On July 15, 2010, CL&P and UI filed a joint application with the DPUC 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 transmission assets as they come into commercial operation.  Following regulatory approval, UI will have the right to invest a minimum of $25 million up to the greater of $60 million or an amount equal to 8.4 percent of CL&P’s costs for the Connecticut portions of these projects, which are expected to cost approximately $711 million.  As assets come into commercial operation, CL&P will transfer title to transmission assets such as poles and wires to UI in proportion to its investments.  CL&P will continue to maintain these porti ons of the transmission system once they are in operation pursuant to an operating and maintenance agreement with UI.  The impact of the UI transaction is reflected in our five-year rate base forecast.

We currently expect that CL&P's and WMECO's total capital expenditures for NEEWS will be $1.49 billion.  Our current capital expenditure and rate base forecasts assume that all NEEWS projects are completed by the end of 2014.  However, the timing and amount of our projected annual capital spending could be affected if receipt of siting approvals is delayed or if the need dates for these

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projects change through ISO-NE's regional system planning process.  During the siting approval process, state regulators may require changes in configuration (including placing some lines underground) to address local concerns that could increase construction costs.  Our current design for NEEWS does not contemplate any underground lines.  Building any lines underground, particularly 345 KV lines, would increase total costs of the project beyond those reflected above.  Since inception of NEEWS through June 30, 2010, CL&P and WMECO have capitalized approximately $82.2 million and $94.5 million, respectively, in costs associated with NEEWS, of which $14.7 million and $20.2 million, respectively, were capitalized in the first half of 2010.  

NUTV and NSTAR Transmission Ventures, Inc., a subsidiary of NSTAR, have jointly formed a limited liability company, Northern Pass Transmission, to construct, own and operate the Northern Pass line, a new HVDC transmission line from Québec to New Hampshire that will interconnect with a new HVDC transmission line being developed by HQ-Trans-Energie, the transmission subsidiary of Hydro-Québec.  NUTV holds a 75 percent interest in Northern Pass Transmission with NSTAR holding the remaining 25 percent.  Under the proposed arrangement with HQ, Northern Pass Transmission would sell to a new HQ subsidiary 1,200 MW of firm electric transmission service over the Northern Pass line; in turn, the HQ subsidiary will sell and deliver this same amount of electric power from HQ's low-carbon energy resources to New England.

We continue to make progress in the design of the Northern Pass line.  We are finalizing the terms and conditions of the TSA with HQ.  The TSA establishes risk allocation and cost recovery for the project and is subject to FERC approval.  We expect to file the project design with ISO-NE for technical review and the TSA with the FERC in the third quarter of 2010.  There are a number of additional state and federal permits that will be required to site the Northern Pass line, and we anticipate filing those applications over the next six to eighteen months, after appropriate data collection and application preparation.  We are continuing our early engineering work on the line as well as gathering the required data and conducting environmental studies required for construction authorizations and permits.  

We expect to begin significant public communications and outreach efforts in the New Hampshire communities where new facilities are expected to be located over the balance of this year and into 2011.  Assuming timely regulatory review and siting approvals, we could begin construction of the line in late 2012 or early 2013, which could have power flowing in the second half of 2015.  Our current estimate for our share of the project cost is $675 million.  We expect to produce a more refined estimate after executing the TSA.  

In addition, we are continuing discussions with HQ on the potential for one or more power purchase agreements for power transmitted over the Northern Pass line.  The terms of any power purchase agreements will be subject to state regulatory approval.  We anticipate filing these power purchase agreements subsequent to filing the TSA.

Distribution Segment:  Distribution segment capital expenditures increased by $41.7 million in the first half of 2010, as compared with the same period in 2009.  A summary of distribution segment capital expenditures by company for the first half of 2010 and 2009 is as follows:

		For the Six Months Ended June 30,
(Millions of Dollars)		2010		2009
CL&P:
Basic business	$	54.4	$	47.7
Aging infrastructure		39.5		47.9
Load growth		41.8		38.0
Total CL&P		135.7		133.6
PSNH:
Basic business		18.8		24.9
Aging infrastructure		8.3		7.8
Load growth		11.1		13.0
Total PSNH		38.2		45.7
WMECO:
Basic business		7.7		8.5
Aging infrastructure		4.5		5.7
Load growth		1.4		2.6
Total WMECO		13.6		16.8
Totals – Electric Distribution (excluding Generation)		187.5		196.1
Yankee Gas		28.8		23.8
Other		0.2		0.2
Total Distribution		216.5		220.1
PSNH Generation:
Clean air project		81.3		42.8
Other		12.9		6.8
Total PSNH Generation		94.2		49.6
WMECO Generation		0.7		-
Total Distribution Segment	$	311.4	$	269.7

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.

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PSNH's Clean Air Project is a $457 million 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 under budget and the project is expected to be completed in mid-2012.  Since inception of the project, PSNH has capitalized $228.1 million associated with this project, of which $81.3 million was capitalized in the first half of 2010.  Construction of the project was approximately 63 percent complete as of June 30, 2010.  

In April 2010, Yankee Gas commenced its WWL Project, the construction of a 16-mile gas pipeline between Waterbury and Wallingford, Connecticut and the increase of vaporization output of its LNG plant, which is estimated to cost $67 million.  The first phase of the WWL project, which will provide a new interconnection between the Cheshire, Connecticut area and the distribution system in Wallingford, Connecticut, will cost approximately $16 million and is expected to be completed in November 2010.  The second phase, which involves expanding the vaporization capacity of the LNG facility and connecting it to the Cheshire area distribution system, should be completed in November 2011.  Since inception of the project, Yankee Gas has capitalized $8.2 million associated with this project, $7.4 million of which was capitalized in the first half of 2010.  Construction of the project was approximately 18 percent complete as of J une 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 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.  To date, most discussions have been conceptual in nature and therefore we have not yet included any capital expenditures associated with potential projects in our five-year capital pro gram.    

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 an additional $50 million.

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.  WMECO began construction of 1.8 MW of the 6 MW at a site in Pittsfield, Massachusetts in May 2010 and is expected to complete it later this year at a cost of approximately $10 million.  Site assessments for WMECO's next projects that will fulfill the program's currently authorized scope of 6 MW are nearly complete.

Transmission Rate Matters and FERC Regulatory Issues

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 June 30, 2010, NU was in a total underrecovery position of $5.6 million ($1.2 million for CL&P, $4.1 million for PSNH, and $0.3 million for WMECO), which will be collected from customers in June 2011.

FERC ROE Decision:  On March 24, 2008, the FERC issued a rehearing order confirming its initial decision setting the base ROE for transmission projects for the New England transmission owners.  Including a final adjustment, the order provides a base ROE of 11.14 percent for the period beginning November 1, 2006.  The order also affirmed the FERC's earlier decision granting a 100 basis point adder for transmission projects that are part of the ISO-NE Regional System Plan and are "completed and on line" by December 31, 2008.  In addition, while not an issue in this rehearing, the initial order increasing the ROE by 50 additional points for transmission owners joining a Regional Transmission Organization (RTO) and giving the RTO operational control of the basis transmission facilities still stands.  This order was appealed to the D.C. Circuit Court of Appeals by numerous state regulators a nd consumer advocates.  In January 2010, the Court unanimously rejected the claims on appeal, confirming FERC’s award of the 100 basis point adder.  Subsequent rehearing by the Court was denied in April 2010, and state regulators did not seek further review by the U.S. Supreme Court within the 90 day review period, thereby concluding the case.  

On May 16, 2008, CL&P filed an application with the FERC to receive ROE incentives for its Middletown-Norwalk project and to seek a waiver of the "completed and on line" date of December 31, 2008 to earn incentives, pursuant to the FERC’s March 24, 2008 order on rehearing.  Alternatively, CL&P requested the FERC to find that this project met the nexus test requirements for incentives under the FERC’s guidelines for new projects, and requested an additional 50 basis point adder for advanced technology used in the project.  

In July 2008, the FERC granted the waiver request and approved the 100 basis point ROE incentive for the entire Middletown-Norwalk project.  The FERC also found that the project met the nexus test and granted an additional 50 basis point adder for the advanced technology aspects of the 24-mile underground portion of the project.  The 50 basis point adder results in a total ROE for the underground portion of the Middletown-Norwalk project of 13.1 percent, which represents the overall ROE limit established by the FERC.  The Connecticut state regulators sought review of these incentives by the D.C. Circuit Court of Appeals, but withdrew their appeal in May 2010, thereby concluding the case.  

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Legislative Matters

2010 Connecticut Legislation:  On May 5, 2010, the Connecticut Legislature passed senate bill 493, which would have reorganized the DPUC, launched a significant solar generation initiative, allowed distribution companies to manage a portfolio that would have provided some of their standard service supply and implemented reduced distribution rates for low-income customers.  The bill was vetoed by Governor Rell on May 25, 2010 and the legislature did not overturn her veto.

In addition, the Connecticut Legislature approved a state budget for the 2010-2011 fiscal year, which now calls for the issuance of $703 million of economic recovery revenue bonds that would be amortized over eight years.  The principal amount of the bonds represents a reduction from the original amount of $956 million because the 2009-2010 fiscal year state budget finished with a surplus.  This amount will continue to change as it is refined by the state.  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.  The specifics of these adjustments will be determi ned by the DPUC.  On June 1, 2010, the DPUC initiated a docket to approve financing orders for the state’s electric distribution companies, including CL&P, in accordance with Public Act 10-179.  The DPUC must issue a financing order by October 1, 2010.

Regulatory Developments and Rate Matters

Connecticut - CL&P:

Distribution Rates:  On January 8, 2010, CL&P filed an application with the DPUC to raise distribution rates by $133.4 million (later revised to $129 million), or 3.4 percent over current revenues, to be effective July 1, 2010, and by an additional $44.2 million (later revised to $41.4 million), or 1.1 percent over current revenues, to be effective July 1, 2011.  Among other items, CL&P sought an increase in its authorized ROE from 9.4 percent to 10.5 percent.  On June 30, 2010, the DPUC issued a final order in the rate case, which approved rate increases of $63.4 million effective July 1, 2010 and an incremental $38.5 million effective July 1, 2011.  The 2010 increase was deferred from customer bills until January 1, 2011 to coincide with the decline in revenue requirements associated with the final amortization in December 2010 of CL&P’s 2001 RRBs, which more than offsets the revenue requirem ents associated with the January 1, 2011 distribution rate increase.  While from an earnings perspective CL&P will benefit from the rate increases on July 1, 2010 and July 1, 2011, the cash flow benefits will be evident in early 2011 when customers’ bills reflect the increased rates.  Customer bills will reflect one distribution rate increase totaling approximately $110 million annually on January 1, 2011, which should allow CL&P to recover all of the revenue requirements due as a result of the two approved rate increases.  Coupled with an anticipated reduction in power supply costs of at least 10 percent, we do not expect customers will see a bill increase as a result of the distribution rate increase.

The DPUC’s rate case decision maintained CL&P’s authorized distribution ROE of 9.4 percent, raised the equity component in capital structure modestly to 49.2 percent, but disallowed CL&P’s revenue decoupling mechanism and pension tracker proposals.  The decision also approved, in full, CL&P’s capital spending plan of $310 million, $331 million, and $314 million in 2010, 2011, and 2012, respectively, and amortized an expected depreciation reserve imbalance by returning $74 million to customers over 7 years and an additional $306 million over 35 years.  The final decision rejected CL&P’s request for the establishment of a $13.7 million ($8.2 million net of tax) regulatory asset that was recorded in the first quarter of 2010 for the recovery of future tax benefits lost as a result of a provision in the 2010 Healthcare Act.  On July 14, 2010, CL&P filed with the DPUC a request to re consider its ruling on this issue.  On July 28, 2010, the DPUC granted CL&P’s request for reconsideration of its decision and the DPUC allowed the creation of a regulatory asset by CL&P, subject to review in its next rate case.  As a result, NU has concluded that these costs are probable of recovery and has maintained these amounts as regulatory assets as of June 30, 2010.  

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.  Effective April 1, 2010, the DPUC approved a decrease to CL&P’s total average LRS rate of approximately 11.3 percent.  The energy supply portion of the total average LRS rate decreased from 9.662 cents per KWh to 8.055 cents per KWh.  Effective July 1, 2010, the DPUC approved a slight increase to CL&P’s total average SS rates of approximately 0.3 percent and a decrease to CL&P’s total average LRS rate of approximately 12.2 percent.  The energy supply portion of the total average SS rate did not change while the energy supply portion of the total average LRS rate decreased from 8.055 cents per KWh to 6.476 cents per KWh.  CL&P is fully recovering from customers the costs of its SS and LRS services.

New Hampshire:

Distribution Rates, ES, SCRC, and TCAM Filings:  On June 28, 2010, the NHPUC approved the joint settlement of PSNH's permanent rate case, effective July 1, 2010, submitted by PSNH, the NHPUC staff and the Office of Consumer Advocate.  Under the settlement, the settling parties agreed to a net distribution rate increase of $45.5 million on an annualized basis to be effective July 1, 2010, and annualized distribution rate adjustments projected to be a decrease of $2.9 million and increases of $9.5 million and $11.1 million on July 1 of each of the three subsequent years, respectively.  The $45.5 million increase is in addition to the $25.6 million temporary increase that became effective August 1, 2009.  The $45.5 million increase includes $13.7 million to reconcile the difference between the temporary rates and the permanent rates back to August 1, 2009.  The projected decrease of $2.9 million on July& nbsp;1, 2011 reflects primarily the end of the one year recovery of the $13.7 million reconciliation on that date.  PSNH also agreed not to file a new distribution rate request that would be effective prior to July 1, 2015.  During the term of the settlement, PSNH’s ability to propose changes to its permanent distribution rate level will be limited to situations where its 12-month distribution ROE falls below 7 percent for

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two consecutive quarters or certain specified external events occur, as described in the settlement.  The settlement also provides that the authorized regulatory ROE on distribution only plant will continue at the previously allowed level of 9.67 percent.

During the second quarter of 2010, PSNH filed with the NHPUC requests for changes in its ES rate, SCRC rate and TCAM rate to be effective July 1, 2010.  PSNH subsequently proposed a minor change to the filed SCRC rate.  On June 28, 2010, the NHPUC issued orders approving the ES and TCAM rates as filed, and the SCRC rate as modified by PSNH.  The combined result of the permanent distribution rate increase and the approved ES, SCRC, and TCAM rate changes was a net increase, effective July 1, 2010, of approximately six percent in rates billed to customers who purchase energy from PSNH.  

ES and SCRC Reconciliation:  On an annual basis, PSNH files with the NHPUC an ES/SCRC reconciliation filing for the preceding year.  On April 30, 2010, PSNH filed its 2009 ES/SCRC reconciliation with the NHPUC, whose evaluation includes a prudence review of PSNH's generation activities.  During 2009 ES costs exceeded ES revenues by $45.9 million, as a result of refunding the 2008 ES regulatory obligation to customers through a lower ES rate in 2009.  During 2009, SCRC revenues exceeded SCRC costs by $6.4 million.  As of December 31, 2009 PSNH had an ES regulatory asset and an SCRC regulatory asset of $4.4 million and $3.9 million, respectively, for costs that are included in the 2010 ES/SCRC rate calculations for recovery from customers.  The reconciliation docket is ongoing and the NHPUC has scheduled hearings in early December 2010.  We do not expect the outcome of the NHPUC review to have a material adverse impact on PSNH’s earnings, financial position or cash flows.  

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, but has not established a procedural schedule for the appeal.  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 $228.1 million since inception of the project through June 30, 2010 as of which date construction was approxima tely 63 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.  A decision is expected by January 31, 2011.

Second Quarter 2010 Major Storms:  In May 2010, two severe storms struck portions of the western Massachusetts region damaging the distribution systems and causing extensive power outages in WMECO’s service territories.  WMECO estimates that the cost of restoration was approximately $6.2 million.  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.  

Basic Service Rates:  Effective April 1, 2010, the basic service rate for medium and large commercial and industrial customers decreased to 8.528 cents per KWh to reflect the basic service solicitation conducted by WMECO in February 2010.  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.

Transition Cost Reconciliations: On July 2, 2009, WMECO filed its 2008 cost reconciliation for transition, transmission, basic/default service, basic/default service adder, and capital projects scheduling list.  The briefing period ended on December 28, 2009.  The DPU issued a decision on April 12, 2010.  The decision did not have a material adverse impact on WMECO's earnings, financial position or cash flows.

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.  There is no date set for when the DPU will render its final decision.  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.

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NU Enterprises

NU Enterprises continues to manage to completion its remaining wholesale marketing contracts and to manage its electrical contracting business and other operating and maintenance services contracts.

Off-Balance Sheet Arrangements

Letters of Credit:  NU parent provides standby LOCs for the benefit of its subsidiaries under its revolving credit agreement.  PSNH posts such LOCs as collateral with counterparties and ISO-NE.  As of June 30, 2010, PSNH had posted $37.6 million in such NU parent LOCs, which includes $5 million with ISO-NE.  In addition, Select Energy had posted $2 million NU parent LOCs with ISO-NE as of June 30, 2010.

Competitive Businesses:  We have various guarantees and indemnification obligations outstanding on behalf of former subsidiaries in connection with the exit from our competitive businesses.  See Note 4B, "Commitments and Contingencies - Guarantees and Indemnifications," to the unaudited condensed consolidated financial statements for information regarding the maximum exposure and amounts recorded under these guarantees and indemnification obligations.

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

Contractual Obligations and Commercial Commitments:  There have been no additional contractual obligations identified and no material changes with regard to the contractual obligations and commercial commitments previously disclosed in our 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 variances in income statement line items for the unaudited condensed consolidated statements of income for NU included in this Quarterly Report on Form 10-Q for the three and six months ended June 30, 2010:

	Income Statement Variances (Millions of Dollars) 2010 over/(under) 2009
	Second Quarter		Percent		Six Months		Percent
Operating Revenues	$	(113)	(9)	%	$	(367)	(13)	%
Operating Expenses:
Fuel, Purchased and Net Interchange Power		(141)	(24)			(377)	(26)
Other Operating Expenses		(28)	(12)			(27)	(6)
Maintenance		10	19			7	7
Depreciation		1	2			3	2
Amortization of Regulatory Assets/(Liabilities), Net		22	(a)			(8)	(93)
Amortization of Rate Reduction Bonds		4	7			7	7
Taxes Other Than Income Taxes		20	37			19	14
Total Operating Expenses		(112)	(11)			(376)	(16)
Operating Income		(1)	-			9	2
Interest Expense		2	3			(1)	(1)
Other Income, Net		(11)	(87)			(7)	(42)
Income Before Income Tax Expense		(14)	(11)			3	1
Income Tax Expense		(3)	(7)			25	27
Net Income		(11)	(13)			(22)	(12)
Net Income Attributable to Noncontrolling Interests		-	-			-	-
Net Income Attributable to Controlling Interests	$	(11)	(13)	%	$	(22)	(12)	%

(a)

Percent greater than 100 not shown since not meaningful.

Comparison of the Second Quarter of 2010 to the Second Quarter of 2009

Operating Revenues

	For the Three Months Ended June 30,
(Millions of Dollars)	2010		2009		Variance
Electric Distribution	$	884	$	1,007	$	(123)
Gas Distribution		74		70		4
Total Distribution		958		1,077		(119)
Transmission		154		136		18
Regulated Companies		1,112		1,213		(101)
Competitive Businesses		22		21		1
Other & Eliminations		(23)		(10)		(13)
NU	$	1,111	$	1,224	$	(113)

Operating Revenues decreased $113 million in 2010 due primarily to lower distribution revenues from the Regulated companies ($119 million) mainly as a result of the recovery of a lower level of electric distribution fuel expenses passed through to customers through regulatory tracking mechanisms.  

Electric distribution revenues decreased $123 million due primarily to a decrease in the portion of electric distribution revenues that does not impact earnings ($137 million), partially offset by an increase in the component of revenues that impacts earnings ($14 million).  The portion of electric distribution segment revenues that impacts earnings increased $14 million due primarily to higher retail electric sales and PSNH's rate changes effective in August 2009.  Retail electric sales for the Regulated companies increased 5.9 percent.  Gas distribution revenues increased $4 million due primarily to increased recovery of fuel costs, partially offset by lower sales volumes.  Firm natural gas sales decreased 4.3 percent in the second quarter of 2010 compared with the same period of 2009.

The $137 million decrease in electric distribution revenues that does not impact earnings consists of the portions of distribution revenues that are included in regulatory commission approved tracking mechanisms that recover certain incurred costs ($105 million) and revenues that are eliminated in consolidation of the Regulated companies ($32 million).  The distribution revenues tracking components decreased $105 million due primarily to lower recovery of generation service and related congestion charges ($124 million) and lower CL&P delivery-related FMCC ($14 million), partially offset by higher retail transmission revenues ($21 million) and higher transition costs recoveries ($16 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.

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Transmission segment revenues increased $18 million due primarily to the return on a higher transmission investment base and the return of higher overall expenses, which are tracked and result in a related increase in revenues, resulting from an increase in transmission plant, such as higher property taxes, depreciation and operation and maintenance expenses.  

Fuel, Purchased and Net Interchange Power

Fuel, Purchased and Net Interchange Power expenses decreased $141 million in 2010 due primarily to lower costs at the Regulated companies ($143 million), partially offset by higher competitive business expenses ($2 million).  Fuel and purchased power expense for the Regulated companies decreased at CL&P ($93 million) due to lower GSC supply costs, a decrease in deferred fuel costs and lower other purchased power costs, at PSNH ($45 million) due to an increased level of migration of ES customers to competitive electric suppliers, partially offset by higher retail sales, and at WMECO ($9 million) due to lower basic/default service supply costs, partially offset by higher expense at Yankee Gas ($3 million) due primarily to higher gas prices, partially offset by lower sales volumes due to warmer weather.  Competitive businesses’ expenses increased due primarily to lower Select Energy mark-to-market gains in 2010.

Other Operating Expenses

Other Operating Expenses decreased $28 million in 2010 due primarily to lower Regulated companies' distribution and transmission segment expenses ($27 million) and lower competitive businesses' expenses ($1 million).

Lower Regulated companies' distribution and transmission segment expenses of $27 million were due primarily to lower costs that are recovered through distribution tracking mechanisms that have no earnings impact ($16 million), such as retail transmission and customer service expenses, and lower other operating costs ($14 million), partially offset by higher electric distribution segment expenses ($3 million), including higher pension costs.

Maintenance

Maintenance expenses increased $10 million in 2010 due primarily to higher Regulated companies' distribution expenses ($7 million) and higher transmission line expenses ($4 million).  Distribution expenses were higher due primarily to vegetation management work ($5 million) and higher PSNH generation expenses ($3 million) mainly as a result of planned maintenance outages at Merrimack Station.

Depreciation

Depreciation expenses increased $1 million in 2010 due primarily to higher transmission and distribution plant balances resulting from completed construction projects placed into service.

Amortization of Regulatory Assets/(Liabilities), Net

Amortization of Regulatory Assets/(Liabilities), Net increased $22 million in 2010 due primarily to higher retail CTA revenue ($8 million) and lower CTA transition costs ($7 million) at CL&P and higher amortization at WMECO ($3 million) due primarily to the recovery of the stranded generation and purchase power contracts previously deferred.

Amortization of Rate Reduction Bonds

Amortization of RRBs expenses increased $4 million in 2010, which corresponded to the reduction in principal of the RRBs.  

Taxes Other Than Income Taxes

Taxes Other Than Income Taxes expenses increased $20 million in 2010 due primarily to the absence of the 2009 benefit from the resolution of various routine tax issues ($8 million), higher property taxes ($6 million), higher Connecticut gross earnings tax ($3 million), and higher payroll related taxes ($2 million).  

Interest Expense

Interest Expense increased $2 million in 2010 due primarily to higher other interest ($4 million) mostly due to the absence of the 2009 benefit from the resolution of various routine tax issues and higher long-term debt interest ($2 million) resulting from the issuance of new long-term debt in 2009 and 2010, partially offset by lower RRB interest resulting from lower principal balances outstanding ($4 million).

Other Income, Net

Other Income, Net decreased $11 million in 2010 due primarily to the absence of investment income recorded in 2009 and higher investment losses due primarily to the results from NU’s supplemental benefit trust ($10 million) and a write-down of PSNH storm reserves ($3 million), partially offset by higher AFUDC equity income ($1 million).  

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Income Tax Expense

Income Tax Expense decreased $3 million in 2010 due primarily to the absence of resolving various routine tax audits in 2009 ($3 million).     

Comparison of the First Six Months of 2010 to the First Six Months of 2009

Operating Revenues

	For the Six Months Ended June 30,
(Millions of Dollars)	2010		2009		Variance
Electric Distribution	$	1,885	$	2,253	$	(368)
Gas Distribution		245		272		(27)
Total Distribution		2,130		2,525		(395)
Transmission		308		270		38
Regulated Companies		2,438		2,795		(357)
Competitive Businesses		41		42		(1)
Other & Eliminations		(28)		(19)		(9)
NU	$	2,451	$	2,818	$	(367)

Operating Revenues decreased $367 million in 2010 due primarily to lower electric distribution revenues from the Regulated companies ($368 million) mainly as a result of the recovery of a lower level of electric distribution fuel and other expenses passed through to customers through regulatory tracking mechanisms.  

Electric distribution revenues decreased $368 million due primarily to a decrease in the portion of electric distribution revenues that does not impact earnings ($372 million), partially offset by an increase in the component of revenues that impacts earnings ($3 million).  The portion of electric distribution segment revenues that impacts earnings increased $3 million due primarily to PSNH’s rate changes effective August 2009.  Gas distribution revenues decreased $27 million due primarily to decreased recovery of fuel costs primarily as a result of lower sales volumes.  Firm natural gas sales decreased 3.7 percent in the first six months of 2010 compared with the same period of 2009.

The $372 million decrease in electric distribution revenues that does not impact earnings consists of the portions of distribution revenues that are included in regulatory commission approved tracking mechanisms that recover certain incurred costs ($330 million) and revenues that are eliminated in consolidation of the Regulated companies ($42 million).  The distribution revenues tracking components decreased $330 million due primarily to lower recovery of generation service and related congestion charges ($334 million), lower CL&P delivery-related FMCC ($31 million) and lower wholesale revenues ($9 million), partially offset by higher retail transmission revenues ($28 million) and higher transition costs recoveries ($23 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.

Transmission segment revenues increased $38 million due primarily to the return on a higher transmission investment base and the return of higher overall expenses, which are tracked and result in a related increase in revenues, resulting from an increase in transmission plant, such as higher property taxes, depreciation and operation and maintenance expenses.  

Fuel, Purchased and Net Interchange Power

Fuel, Purchased and Net Interchange Power expenses decreased $377 million in 2010 due primarily to lower costs at the Regulated companies ($386 million), partially offset by higher competitive business expenses ($9 million).  Fuel and purchased power expense for the Regulated companies decreased at CL&P ($244 million) due to lower GSC supply costs and other purchased power costs, at PSNH ($88 million) due to an increased level of migration of ES customers to competitive electric suppliers and lower retail sales, at WMECO ($29 million) due to lower basic/default service supply costs, and at Yankee Gas ($25 million) due primarily to a decrease in purchased gas commodity pricing and a decrease in sales due to warmer weather.  Competitive businesses’ expenses increased due to Select Energy mark-to-market losses in 2010, as compared to a gain in 2009 related to the remaining wholesale obligations.

Other Operating Expenses

Other Operating Expenses decreased $27 million in 2010 due primarily to lower Regulated companies' distribution and transmission segment expenses ($26 million) and lower competitive businesses' expenses ($3 million), partially offset by higher NU parent and other companies expenses ($2 million).

Lower Regulated companies' distribution and transmission segment expenses of $26 million were due primarily to lower costs that are recovered through distribution tracking mechanisms that have no earnings impact ($25 million), such as retail transmission and customer service expenses, and lower other operating costs ($10 million), partially offset by higher electric distribution segment expenses ($8 million), including higher pension costs and storm restoration costs.  

Maintenance

Maintenance expenses increased $7 million in 2010 due primarily to higher transmission line expenses ($6 million) and higher Regulated companies' distribution expenses ($1 million) including storm restoration expenses.  Distribution expenses were higher due primarily to higher PSNH generation expenses ($3 million) mainly as a result of planned maintenance outages at Merrimack Station, partially offset by vegetation management work ($1 million) and lower repair and maintenance of transformers ($1 million).  

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Depreciation

Depreciation expenses increased $3 million in 2010 due primarily to higher transmission ($2 million) and distribution ($2 million) plant balances resulting from completed construction projects placed into service.

Amortization of Regulatory Assets/(Liabilities), Net

Amortization of Regulatory Assets/(Liabilities), Net decreased $8 million in 2010 due primarily to 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) and a decrease in net deferrals associated with the ES tracking mechanism ($11 million) at PSNH, partially offset by higher retail CTA revenue ($9 million), lower CTA transition costs ($4 million) and lower SBC expenses ($4 million) at CL&P and higher amortization of storm restoration costs related to the recovery of 2008 ice storm expenses ($2 million) and an increase in net deferrals associated with the TCAM ($1 million) and SCRC ($1 million) tracking mechanisms at PSNH.  

Amortization of Rate Reduction Bonds

Amortization of RRBs expenses increased $7 million in 2010, which corresponded to the reduction in principal of the RRBs.  

Taxes Other Than Income Taxes

Taxes Other Than Income Taxes expenses increased $19 million in 2010 due primarily to higher property taxes ($11 million) and the absence of the 2009 benefit from the resolution of various routine tax issues ($8 million).  

Interest Expense

Interest Expense decreased $1 million in 2010 due primarily to lower RRB interest resulting from lower principal balances outstanding ($8 million), partially offset by higher long-term debt interest ($3 million) resulting from the issuance of new long-term debt in 2009 and 2010 and higher other interest ($3 million) mostly due to the absence of the 2009 benefit from the resolution of various routine tax issues.

Other Income, Net

Other Income, Net decreased $7 million in 2010 due primarily to the absence of investment income recorded in 2009 and higher investment losses due primarily to the results from NU’s supplemental benefit trust ($5 million), a write-down of PSNH storm reserves ($3 million), lower CL&P Energy Independence Act incentives ($2 million), and lower interest income ($2 million), partially offset by higher AFUDC equity income ($4 million), as a result of higher eligible CWIP balances and lower short-term debt at CL&P.  

Income Tax Expense

Income Tax Expense increased $25 million due primarily to the impacts of the 2010 Healthcare Act, including $18 million from the write-down of deferred tax assets, $9 million from deferred tax on establishing the related regulatory asset, and lower 2010 Medicare tax benefits, partially offset by lower pre-tax earnings ($1 million).   

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

The components of significant income statement variances, higher/(lower) in comparison to the previous year, are provided in the table below.

	Income Statement Variances (Millions of Dollars) 2010 over/(under) 2009
	Second Quarter		Percent		Six Months		Percent
Operating Revenues	$	(77)	(10)	%	$	(237)	(14)	%
Operating Expenses:
Fuel, Purchased and Net Interchange Power		(93)	(24)			(244)	(27)
Other Operating Expenses		(11)	(8)			(16)	(6)
Maintenance		5	18			-	-
Depreciation		1	2			2	2
Amortization of Regulatory Assets, Net		17	(a)			6	34
Amortization of Rate Reduction Bonds		3	8			5	7
Taxes Other Than Income Taxes		13	33			12	13
Total Operating Expenses		(65)	(10)			(235)	(16)
Operating Income		(12)	(10)			(2)	(1)
Interest Expense		(1)	(1)			-	-
Other Income, Net		(7)	(91)			(5)	(48)
Income Before Income Tax Expense		(18)	(21)			(7)	(4)
Income Tax Expense		(4)	(15)			12	20
Net Income	$	(14)	(25)	%	$	(19)	(17)	%

(a)

Percent greater than 100 not shown since not meaningful.

Comparison of the Second Quarter of 2010 to the Second Quarter of 2009

Operating Revenues

Operating Revenues decreased $77 million in 2010 due to lower distribution segment revenues ($89 million), partially offset by higher transmission segment revenues ($12 million).

The distribution segment revenues decreased $89 million due primarily to a decrease in the portion of distribution revenues that does not impact earnings ($93 million).  The portion of revenues that impacts earnings increased $4 million primarily as a result of higher retail sales.  The 2010 retail sales as compared to the same period in 2009 increased 6.1 percent.

The $93 million decrease in distribution segment revenues that does not impact earnings was due primarily to a decrease in the portions of retail revenues that are included in DPUC approved tracking mechanisms that track the recovery of certain incurred costs through CL&P's tariffs ($68 million) and transmission segment intracompany billings to the distribution segment that are eliminated in consolidation ($26 million).  The distribution revenues included in DPUC approved tracking mechanisms decreased $68 million due primarily to a decrease in revenues associated with the recovery of GSC and supply-related FMCC ($82 million) and delivery-related FMCC ($14 million), partially offset by higher retail transmission revenues ($13 million), higher transition costs recoveries ($9 million), and higher wholesale revenues as a result of increased market revenue related to CL&P’s IPP purchased generation output to ISO-NE due to a increase in the market price of energy ($3 million).  The lower GSC and supply-related FMCC revenue was 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 significantly lowered the delivery-related FMCC rate in the second quarter of 2010 as compared to 2009.  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.

Transmission segment revenues increased $12 million due primarily to the return on a higher transmission investment base and the return of higher overall expenses, which are tracked and result in a related increase in revenues, resulting from an increase in transmission plant, such as higher property taxes, depreciation, and operation and maintenance expenses.  

Fuel, Purchased and Net Interchange Power

Fuel, Purchased and Net Interchange Power expense decreased $93 million in 2010 due primarily to lower GSC supply costs ($60 million),  a decrease in deferred fuel costs ($23 million) and lower other purchased power costs ($10 million), all of which are included in DPUC approved tracking mechanisms.  The $60 million 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

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competitive solicitation process.  The $23 million decrease in deferred fuel costs was due primarily to a smaller net overrecovery in the second quarter of 2010 as compared to 2009.  

Other Operating Expenses

Other Operating Expenses decreased $11 million in 2010 as a result of lower costs that are recovered through distribution tracking mechanisms and have no earnings impact ($19 million) such as retail transmission ($13 million) and certain customer services expenses ($4 million), partially offset by higher distribution segment expenses ($9 million), including higher pension costs.

Maintenance

Maintenance expenses increased $5 million in 2010 due primarily to higher transmission segment expenses ($3 million) and repair and maintenance of distribution lines ($2 million) including storm restoration expenses.  

Depreciation

Depreciation expense increased $1 million in 2010 due primarily to higher utility plant balances resulting from completed construction projects placed into service.

Amortization of Regulatory Assets, Net

Amortization of Regulatory Assets, Net, increased $17 million in 2010 due primarily to higher retail CTA revenue ($8 million), lower CTA transition costs ($7 million), and lower SBC expenses ($1 million).  

Amortization of Rate Reduction Bonds

Amortization of RRBs increased $3 million in 2010, which corresponded to the reduction in principal of the RRBs.  

Taxes Other Than Income Taxes

Taxes Other Than Income Taxes increased $13 million in 2010 due primarily to the absence of the 2009 benefit from the resolution of various routine tax issues ($4 million), higher property taxes ($3 million), higher CT gross earnings tax ($3 million) recoverable in rates mainly as a result of higher transmission revenues that are subject to gross earnings tax, and higher payroll related taxes ($1 million).  

Interest Expense

Interest Expense decreased $1 million in 2010 due primarily to lower RRB interest resulting from lower principal balances outstanding ($3 million), and long-term debt interest ($1 million) resulting from the remarketed $62 million of PCRBs in April 2010, partially offset by higher other interest ($3 million) mostly due to the absence of the 2009 benefit from the resolution of various routine tax issues.

Other Income, Net

Other Income, Net decreased $7 million in 2010 due primarily to the absence of investment income recorded in 2009 and higher investment losses due primarily to the results from NU’s supplemental benefit trust.

Income Tax Expense

Income Tax Expense decreased $4 million in 2010 due primarily to lower pre-tax earnings ($3 million) and the absence of resolving various routine tax audits in 2009 ($1 million).

Comparison of the First Six Months of 2010 to the First Six Months of 2009

Operating Revenues

Operating Revenues decreased $237 million in 2010 due to lower distribution segment revenues ($262 million), partially offset by higher transmission segment revenues ($26 million).

The distribution segment revenues decreased $262 million due primarily to a decrease in the portion of distribution revenues that does not impact earnings ($255 million).  The portion of revenues that impacts earnings decreased $7 million primarily as a result of unfavorable price variances.  The 2010 retail sales as compared to the same period in 2009 increased 0.2 percent.

The $255 million decrease in distribution segment revenues that does not impact earnings was due primarily to a decrease in the portions of retail revenues that are included in DPUC approved tracking mechanisms that track the recovery of certain incurred costs through CL&P's tariffs ($223 million) and transmission segment intracompany billings to the distribution segment that are eliminated in consolidation ($32 million).  The distribution revenues included in DPUC approved tracking mechanisms decreased $223 million due primarily to a decrease in revenues associated with the recovery of GSC and supply-related FMCC ($220 million), and delivery-related FMCC ($31 million), partially offset by higher retail transmission revenues ($17 million), and higher transition costs recoveries ($11 million).  The lower GSC and supply-related FMCC revenue was due primarily to lower customer rates resulting from lower average supply prices a nd 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 significantly lowered the delivery-related FMCC rate in the first half of 2010 as compared to 2009.  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.

Transmission segment revenues increased $26 million due primarily to the return on a higher transmission investment base and the return of higher overall expenses, which are tracked and result in a related increase in revenues, resulting from an increase in transmission plant, such as 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 expense decreased $244 million in 2010 due primarily to lower GSC supply costs ($229 million) and other purchased power costs ($16 million), all of which are included in DPUC approved tracking mechanisms.  The $229 million decrease in GSC supply costs was due primarily to lower average supply prices and additional customer migration to third-party suppliers in the first half of 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.    

Other Operating Expenses

Other Operating Expenses decreased $16 million in 2010 as a result of lower costs that are recovered through distribution tracking mechanisms and have no earnings impact ($28 million) such as retail transmission ($16 million) and certain customer services expenses ($10 million), partially offset by higher distribution segment expenses ($12 million), including higher pension and storm restoration costs.

Depreciation

Depreciation expense increased $2 million in 2010 due primarily to higher utility plant balances resulting from completed construction projects placed into service.

Amortization of Regulatory Assets, Net

Amortization of Regulatory Assets, Net, increased $6 million in 2010 due primarily to higher retail CTA revenue ($9 million), lower SBC expenses ($5 million), and lower CTA transition costs ($4 million), partially offset by the impact of the 2010 Healthcare Act related to income taxes ($14 million).  

Amortization of Rate Reduction Bonds

Amortization of RRBs increased $5 million in 2010, which corresponded to the reduction in principal of the RRBs.  

Taxes Other Than Income Taxes

Taxes Other Than Income Taxes increased $12 million in 2010 due primarily to the absence of the benefit from the 2009 resolution of various routine tax issues ($4 million), higher CT gross earnings tax ($4 million) recoverable in rates mainly as a result of higher transmission revenues that are subject to gross earnings tax, higher property taxes ($2 million), and higher payroll related taxes ($1 million).  

Other Income, Net

Other Income, Net decreased $5 million in 2010 due primarily to the absence of investment income recorded in 2009 and higher investment losses due primarily to the results from NU’s supplemental benefit trust ($3 million) and lower CL&P Energy Independence Act incentives ($2 million).  

Income Tax Expense

Income Tax Expense increased $12 million due primarily to the impacts of the 2010 Healthcare Act; including $9 million from the write down of deferred tax assets, $6 million from deferred tax on establishing the related regulatory asset, and lower 2010 Medicare tax benefits, partially offset by lower other pre-tax earnings ($3 million).

LIQUIDITY

CL&P had cash flows provided by operating activities in the first half of 2010 of $234.7 million, compared with operating cash flows of $247.1 million in the first half of 2009 (amounts are net of RRB payments, which are included in financing activities).  The decrease in cash flows was due primarily to a $22 million increase in income tax payments largely attributable to the absence of bonus depreciation tax deductions under the American Recovery and Reinvestment Act of 2009 in the first half of 2010.  Bonus depreciation tax deductions expired at the end of 2009.  Offsetting the higher tax payments was a decrease in payments made related to our accounts payable in support of our operating activities.  There is no significant cash flow impact relating to the decrease in receivables and unbilled revenues and the increase in accounts payable relating to customer migration to third party energy suppliers as these amo unts offset one another.  We project cash flows provided by operating activities at CL&P of approximately $425 million in 2010, net of RRB payments, which is $25 million higher than our first quarter 2010 projection due primarily to the expected third quarter sales increase as a result of the significantly warmer than expected weather and modest improvements in economic conditions in Connecticut that we expect will benefit our cash flows over the second half of 2010.

As of June 30, 2010, CL&P had no borrowings under the $400 million credit facility it shares with the other Regulated companies, under which it can borrow up to $200 million.  Other financing activities for the six months ended June 30, 2010 included $146 million in common dividends paid to NU parent.  

On April 1, 2010, CL&P remarketed $62 million of tax-exempt PCRBs that were subject to a mandatory tender on April 1, 2010.  The PCRBs, which mature on May 1, 2031, carry a coupon rate of 1.4 percent and have a mandatory tender on April 1, 2011, at which time CL&P expects to remarket the bonds.

On July 12, 2010, CL&P filed an application with the DPUC 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 has requested that the DPUC issue a decision by November 1, 2010.

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Cash capital expenditures included on the accompanying unaudited condensed consolidated statements of cash flows do not include amounts incurred on capital projects but not yet paid, cost of removal, the AFUDC related to equity funds, and the capitalized portions of pension and PBOP expense or income.  CL&P's cash capital expenditures totaled $191.7 million for the six months ended June 30, 2010, compared with $226.9 million for the six months ended June 30, 2009.  We project capital expenditures at CL&P of $441 million in 2010 (including non-cash factors).  

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

The components of significant income statement variances, higher/(lower) in comparison to the previous year, are provided in the table below.

	Income Statement Variances (Millions of Dollars) 2010 over/(under) 2009
	Second Quarter		Percent		Six Months		Percent
Operating Revenues	$	(25)	(9)	%	$	(74)	(13)	%
Operating Expenses:
Fuel, Purchased and Net Interchange Power		(45)	(35)			(88)	(32)
Other Operating Expenses		(3)	(4)			(2)	(2)
Maintenance		5	23			5	14
Depreciation		1	4			2	5
Amortization of Regulatory Liabilities, Net		1	9			(12)	(a)
Amortization of Rate Reduction Bonds		1	6			1	6
Taxes Other Than Income Taxes		3	37			4	20
Total Operating Expenses		(37)	(16)			(90)	(18)
Operating Income		12	39			16	24
Interest Expense		1	14			2	6
Other (Loss)/Income, Net		(3)	(a)			(2)	(48)
Income Before Income Tax Expense		8	33			12	26
Income Tax Expense		3	40			9	65
Net Income	$	5	30	%	$	3	10	%

(a)

Percent greater than 100 not shown since not meaningful.  

Comparison of the Second Quarter of 2010 to the Second Quarter of 2009

Operating Revenues

Operating Revenues decreased $25 million in 2010 due to lower distribution segment revenues ($28 million), partially offset by higher transmission segment revenues ($3 million).

The distribution segment revenues decreased $28 million due primarily to a decrease in the portion of distribution revenues that does not impact earnings ($37 million), partially offset by an increase in the component of revenues that impacts earnings ($9 million).  The portion of revenues that impacts earnings increased $9 million primarily as a result of the retail rate increase effective in August 2009 and higher retail sales volumes.  Retail sales increased 4.6 percent in 2010 compared to the same period in 2009.  

The $37 million decrease in the portion of distribution segment revenues that does not impact earnings was due primarily to a decrease in the portions of retail revenues that are included in NHPUC approved tracking mechanisms that track the recovery of certain incurred costs through PSNH’s tariffs ($33 million) and transmission segment intracompany billings to the distribution segment that are eliminated in consolidation ($4 million).  The distribution revenues included in NHPUC approved tracking mechanisms decreased $33 million due primarily to lower recovery of purchased fuel and power costs ($33 million), lower wholesale revenue ($7 million) and lower Northern Wood Power Plant renewable energy certificate revenues ($2 million), partially offset by higher retail transmission revenues ($6 million) and an increase in the SCRC ($5 million).  The tracking mechanisms allow for rates to be changed periodically with overcollect ions refunded to customers or undercollections to be recovered from customers in future periods.

Transmission segment revenues increased $3 million due primarily to the return on a higher transmission investment base and the return of higher overall expenses, which are tracked and result in a related increase in revenues, resulting from an increase in transmission plant, such as higher property taxes, depreciation and operation and maintenance expenses.

Fuel, Purchased and Net Interchange Power

Fuel, Purchased and Net Interchange Power costs decreased $45 million in 2010 due primarily to an increased level of migration of ES customers to competitive electric suppliers, partially offset by higher retail sales.

Other Operating Expenses

Other Operating Expenses decreased $3 million in 2010 due primarily to lower distribution segment expenses ($7 million), mainly as a result of the rate case decision which changed the collection of Hydro-Quebec expenses to be tracked through the TCAM mechanism ($4 million) and lower administrative and general expenses ($2 million), including lower regulatory assessments, partially offset by higher generation and retail transmission expenses that are recovered through distribution tracking mechanisms and have no earnings impact ($5 million).

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Maintenance

Maintenance expenses increased $5 million in 2010 due primarily to higher generation maintenance expenses, which are recovered through distribution tracking mechanisms ($3 million), mainly as the result of planned maintenance outages at Merrimack Station, and higher distribution and transmission line expenses.

Depreciation

Depreciation expense increased $1 million in 2010 due primarily to higher utility plant balances resulting from completed construction projects placed into service in the transmission and distribution segments.

Amortization of Regulatory Liabilities, Net

Amortization of Regulatory Liabilities, Net expense increased $1 million in 2010 due primarily to higher amortization of storm restoration costs related to the recovery of 2008 ice storm expenses.  

Amortization of Rate Reduction Bonds

Amortization of RRBs expense increased $1 million in 2010, which corresponded to the reduction in principal of the RRBs.  

Taxes Other Than Income Taxes

Taxes Other Than Income Taxes expenses increased $3 million in 2010 due primarily to higher property taxes as a result of higher net plant balances and increased local municipal tax rates ($2 million) and the absence of the 2009 benefit from the resolution of various routine tax issues ($1 million).

Interest Expense, Net

Interest Expense, Net increased $1 million due primarily to higher interest on long-term debt ($1 million), mainly resulting from the $150 million bond issuance in December 2009, and higher other interest ($1 million), mainly related to the absence of the 2009 benefit from the resolution of various routine tax issues, partially offset by lower RRB interest resulting from lower principal balances outstanding ($1 million).

Other (Loss)/Income, Net

Other (Loss)/Income, Net, decreased $3 million in 2010 due primarily to the write-down of a storm regulatory asset based on the NHPUC rate case decision ($3 million) and the absence of investment income recorded in 2009 and higher investment losses due primarily to unfavorable results from NU’s supplemental benefit trust ($2 million), partially offset by higher AFUDC equity income ($2 million) as a result of higher eligible CWIP balances.

Income Tax Expense

Income Tax Expense increased $3 million in 2010 due primarily to higher pre-tax earnings.  

Comparison of the First Six Months of 2010 to the First Six Months of 2009

Operating Revenues

Operating Revenues decreased $74 million in 2010 due to lower distribution segment revenues ($80 million), partially offset by higher transmission segment revenues ($7 million).

The distribution segment revenues decreased $80 million due primarily to a decrease in the portion of distribution revenues that does not impact earnings ($91 million), partially offset by an increase in the component of revenues that impacts earnings ($11 million).  The portion of revenues that impacts earnings increased $11 million primarily as a result of the retail rate increase effective in August 2009, partially offset by lower retail sales volumes.  Retail sales decreased 0.7 percent in 2010 compared to the same period in 2009.  

The $91 million decrease in the portion of distribution segment revenues that does not impact earnings was due primarily to a decrease in the portions of retail revenues that are included in NHPUC approved tracking mechanisms that track the recovery of certain incurred costs through PSNH’s tariffs ($85 million) and transmission segment intracompany billings to the distribution segment that are eliminated in consolidation ($6 million).  The distribution revenues included in NHPUC approved tracking mechanisms decreased $85 million due primarily to lower recovery of purchased fuel and power costs ($87 million), lower wholesale revenue ($8 million) and lower Northern Wood Power Plant renewable energy certificate revenues ($5 million), partially offset by higher retail transmission revenues ($10 million) and an increase in the SCRC ($7 million).  The tracking mechanisms allow for rates to be changed periodically with overcollec tions refunded to customers or undercollections to be recovered from customers in future periods.

Transmission segment revenues increased $7 million due primarily to the return on a higher transmission investment base and the return of higher overall expenses, which are tracked and result in a related increase in revenues, resulting from an increase in transmission plant, such as 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 costs decreased $88 million in 2010 due primarily to an increased level of migration of ES customers to competitive electric suppliers and lower retail sales.

Other Operating Expenses

Other Operating Expenses decreased $2 million in 2010 due primarily to lower distribution segment expenses ($6 million), mainly as a result of the rate case decision which changed the collection of Hydro-Québec expenses to be tracked through the TCAM mechanism ($4 million) and lower administrative and general expenses ($1 million), partially offset by higher generation and retail transmission expenses that are recovered through distribution tracking mechanisms and have no earnings impact ($4 million).

Maintenance

Maintenance expenses increased $5 million in 2010 due primarily to higher generation maintenance expenses, which are recovered through distribution tracking mechanisms ($3 million), mainly as a result of planned maintenance outages at Merrimack Station, and higher distribution expenses ($2 million).  

Depreciation

Depreciation expense increased $2 million in 2010 due primarily to higher utility plant balances resulting from completed construction projects placed into service in the transmission and distribution segments.

Amortization of Regulatory Liabilities, Net

Amortization of Regulatory Liabilities, Net expense decreased $12 million in 2010 due primarily to a decrease in net deferrals associated with the ES tracking mechanism ($11 million) and the impact of the 2010 Healthcare Act related to income taxes ($5 million), partially offset by higher amortization of storm restoration costs related to the recovery of 2008 ice storm expenses ($2 million) and an increase in net deferrals associated with the TCAM ($1 million) and SCRC ($1 million) tracking mechanisms.

Amortization of Rate Reduction Bonds

Amortization of RRBs expense increased $1 million in 2010, which corresponded to the reduction in principal of the RRBs.  

Taxes Other Than Income Taxes

Taxes Other Than Income Taxes expenses increased $4 million in 2010 due primarily to higher property taxes as a result of higher net plant balances and increased local municipal tax rates ($2 million) and the absence of the 2009 benefit from the resolution of various routine tax issues ($1 million).

Interest Expense, Net

Interest Expense, Net increased $2 million due primarily to higher interest on long-term debt ($2 million), mainly resulting from the $150 million bond issuance in December 2009, and higher other interest ($1 million), mainly related to the absence of the 2009 benefit from the resolution of various routine tax issues, partially offset by lower RRB interest resulting from lower principal balances outstanding ($2 million).

Other (Loss)/Income, Net

Other (Loss)/Income, Net, decreased $2 million in 2010 due primarily to the write-down of a storm regulatory asset based on the NHPUC rate case decision ($3 million), the absence of investment income recorded in 2009 and higher investment losses due primarily to unfavorable results from NU’s supplemental benefit trust ($1 million) and lower interest income ($1 million), partially offset by higher AFUDC equity income ($3 million) as a result of higher eligible CWIP balances.

Income Tax Expense

Income Tax Expense increased $9 million in 2010 due primarily to the impacts of the 2010 Healthcare Act, including $4 million from the write-down of deferred tax assets and $2 million from deferred tax on establishing the related regulatory asset, and $3 million due to higher pre-tax earnings.  

LIQUIDITY

PSNH had cash flows provided by operating activities in the first half of 2010 of $84.3 million, compared with operating cash flows of $22.5 million in the first half 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 $24 million reduction in coal inventory levels at the generation business as ordered by the NHPUC.  Offsetting these favorable cash flow impacts were payments made relating to the February 2010 severe storm for which the costs were deferred.  We expect to recover these costs through a combination of insurance proceeds, customer-funded reserves that are established for the purpose of recovering major storm restoration costs, and current distribution revenues.  

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RESULTS OF OPERATIONS – WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY

The components of significant income statement variances, higher/(lower) in comparison to the previous year, are provided in the table below.

	Income Statement Variances (Millions of Dollars) 2010 over/(under) 2009
	Second Quarter		Percent		Six Months		Percent
Operating Revenues	$	(3)	(3)	%	$	(21)	(10)	%
Operating Expenses:
Fuel, Purchased and Net Interchange Power		(9)	(21)			(29)	(27)
Other Operating Expenses		-	-			1	2
Maintenance		-	-			2	20
Depreciation		-	-			-	-
Amortization of Regulatory Liabilities, Net		3	82			1	31
Amortization of Rate Reduction Bonds		-	-			-	-
Taxes Other Than Income Taxes		2	62			2	27
Total Operating Expenses		(4)	(5)			(23)	(12)
Operating Income		1	8			2	8
Interest Expense		1	28			1	10
Other Income, Net		(1)	(85)			-	-
Income Before Income Tax Expense		(1)	(11)			1	6
Income Tax Expense		-	-			2	28
Net Income	$	(1)	(10)	%	$	(1)	(9)	%

Comparison of the Second Quarter of 2010 to the Second Quarter of 2009

Operating Revenues

Operating Revenues decreased $3 million in 2010 due to lower distribution segment revenues ($5 million), partially offset by higher transmission segment revenues ($3 million).

The distribution segment revenues decreased $5 million due primarily to a decrease in the portion of distribution revenues that does not impact earnings ($7 million), partially offset by an increase in the component of revenues that impacts earnings ($2 million).  The 2010 retail sales as compared to the same period in 2009 increased 7.1 percent.

The $7 million distribution segment revenues decrease that does not impact earnings was due primarily to a decrease in the portions of retail revenues that are included in DPU approved tracking mechanisms that track the recovery of certain incurred costs through WMECO's tariffs ($4 million) and transmission segment intracompany billings to the distribution segment that are eliminated in consolidation ($2 million).  The distribution revenues included in DPU approved tracking mechanisms decreased $4 million due primarily to lower recovery of energy supply costs ($8 million), partially offset by higher transition cost recoveries ($2 million) and higher retail transmission ($1 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.

Transmission segment revenues increased $3 million due primarily to the return on a higher transmission investment base and the return of higher overall expenses, which are tracked and result in a related increase in revenues, resulting from an increase in transmission plant, such as higher property taxes, depreciation, and operation and maintenance expenses.

Fuel, Purchased and Net Interchange Power

Fuel, Purchased and Net Interchange Power expense decreased $9 million 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.  

Amortization of Regulatory Liabilities, Net

Amortization of Regulatory Liabilities, Net, increased $3 million in 2010 due primarily to the recovery of the stranded generation and purchase power contracts previously deferred.

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Taxes Other Than Income Taxes

Taxes Other Than Income Taxes expenses increased $2 million in 2010 due primarily to the absence of the 2009 benefit from the resolution of various routine tax issues ($1 million) and higher property taxes ($1 million).

Interest Expense, Net

Interest Expense, Net increased $1 million in 2010 due primarily to higher long-term debt interest, mainly resulting from the $95 million debt issuance in March 2010.  

Other Income, Net

Other Income, Net, decreased $1 million in 2010 due primarily to the absence of investment income recorded in 2009 and higher investment losses due primarily to results from NU’s supplemental benefit trust.

Comparison of the First Six Months of 2010 to the First Six Months of 2009

Operating Revenues

Operating Revenues decreased $21 million in 2010 due to lower distribution segment revenues ($26 million), partially offset by higher transmission segment revenues ($6 million).

The distribution segment revenues decreased $26 million due primarily to a decrease in the portion of distribution revenues that does not impact earnings ($26 million).  The 2010 retail sales as compared to the same period in 2009 increased 0.9 percent.

The $26 million distribution segment revenues decrease that does not impact earnings was due primarily to a decrease in the portions of retail revenues that are included in DPU approved tracking mechanisms that track the recovery of certain incurred costs through WMECO's tariffs ($22 million) and transmission segment intracompany billings to the distribution segment that are eliminated in consolidation ($4 million).  The distribution revenues included in DPU approved tracking mechanisms decreased $22 million due primarily to lower recovery of energy supply costs ($27 million), partially offset by higher transition cost recoveries ($4 million) and retail transmission ($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.

Transmission segment revenues increased $6 million due primarily to the return on a higher transmission investment base and the return of higher overall expenses, which are tracked and result in a related increase in revenues, resulting from an increase in transmission plant, such as higher property taxes, depreciation, and operation and maintenance expenses.

Fuel, Purchased and Net Interchange Power

Fuel, Purchased and Net Interchange Power expense decreased $29 million 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 $1 million in 2010 as a result of higher distribution segment expenses ($2 million) mainly as a result of higher administrative and general expenses, including higher pension costs, partially offset by lower retail transmission and other costs that are recovered through distribution tracking mechanisms and have no earnings impact ($2 million).

Maintenance

Maintenance expenses increased $2 million in 2010 due primarily to higher overhead lines expenses including higher storm restoration expenses.  

Amortization of Regulatory Liabilities, Net

Amortization of Regulatory Liabilities, Net, increased $1 million in 2010 due primarily to the recovery of the stranded generation and purchase power contracts previously deferred.  

Taxes Other Than Income Taxes

Taxes Other Than Income Taxes expenses increased $2 million in 2010 due primarily to the absence of the 2009 benefit from the resolution of various routine tax issues ($1 million) and higher property taxes ($1 million).

Interest Expense, Net

Interest Expense, Net increased $1 million in 2010 due primarily to higher long-term debt interest, mainly resulting from the $95 million debt issuance in March 2010.

Income Tax Expense

Income Tax Expense increased $2 million in 2010 due primarily to the impacts of the 2010 Healthcare Act.

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LIQUIDITY

WMECO had cash flows provided by operating activities in the first half of 2010 of $15.8 million, compared with cash flows provided by operating activities of $9.2 million in the first half of 2009 (amounts are net of RRB payments, which are included in financing activities).  The improved cash flows in 2010 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.  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.  Offsetting this favorable cash flow impact was a $3 million increase in income tax payments largely attributable to the absence of bonus depreciation tax deductions under the American Recovery and Reinvestment Act of 2009 in the first quarter of 2010.  Bonus depreciation tax deductions expired at the end of 2009.  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.  

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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 0.3 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 1H, "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 June 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.  T he 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 June 30, 2010 that have materially affected, or are reasonably likely to materially affect, internal controls over financial reporting.

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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.  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.

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.  There have been no additional risk factors identified and no material changes with regard to the risk factors previously disclosed in our 2009 Form 10-K.

ITEM 2.

UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

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

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ITEM 6.

EXHIBITS

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

Exhibit No.

Description

Listing of Exhibits (NU)

*12

Ratio of Earnings to Fixed Charges

*15

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 August 6, 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 August 6, 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 August 6, 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

Agreement Re: Connecticut NEEWS Projects By and Between CL&P and The United Illuminating Company dated July 14, 2010

*12

Ratio of Earnings to Fixed Charges

*31

Certification of Leon J. Olivier, Chief Executive Officer of The Connecticut Light and Power Company, required by Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated August 6, 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 August 6, 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 August 6, 2010

85

Listing of Exhibits (PSNH)

*12

Ratio of Earnings to Fixed Charges

*31

Certification of Leon J. Olivier, Chief Executive Officer of Public Service Company of New Hampshire, required by Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated August 6, 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 August 6, 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 August 6, 2010

Listing of Exhibits (WMECO)

*12

Ratio of Earnings to Fixed Charges

*31

Certification of Leon J. Olivier, Chief Executive Officer of Western Massachusetts Electric Company, required by Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated August 6, 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 August 6, 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 August 6, 2010

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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.  

		NORTHEAST UTILITIES
		(Registrant)
Date:  August 6, 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:  August 6, 2010	By	/s/ David R. McHale
		David R. McHale
		Executive Vice President and Chief Financial Officer
		(for the Registrant and as Principal Financial Officer)

87

SIGNATURE

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

		PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE
		(Registrant)
Date:  August 6, 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:  August 6, 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