June 2009 Form 10-Q

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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 Ended June 30, 2009
	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

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 at July 31, 2009
Northeast Utilities Common shares, $5.00 par value	175,281,532 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 frequently used 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	Holyoke Water Power Company
NAESCO	North Atlantic Energy Service Corporation
NGC	Northeast Generation Company
NGS	Northeast Generation Services Company and subsidiaries
NU, NU Consolidated, or the Company	Northeast Utilities and subsidiaries
NU Enterprises	NU Enterprises, Inc. is the parent company of Select Energy, NGS, SECI and Boulos. For further information, see Note 11, "Segment Information," to the unaudited condensed consolidated financial statements.
NUSCO	Northeast Utilities Service Company
NU parent and other companies	NU parent and other companies is comprised of NU parent, NUSCO, HWP (through December 31, 2008) and other subsidiaries, including The Rocky River Realty Company and The Quinnehtuk Company (both real estate subsidiaries), Mode 1 Communications, Inc. (telecommunications) and the non-energy-related subsidiaries of Yankee (Yankee Energy Services Company, Yankee Energy Financial Services Company, and NorConn Properties, Inc.)
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 segment of PSNH, and Yankee Gas, a natural gas local distribution company. For further information, see Note 11, "Segment Information," to the unaudited condensed consolidated financial statements.
SECI	Select Energy Contracting, Inc.
Select Energy	Select Energy, Inc.
SESI	Select Energy Services, Inc.
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:

AFUDC	Allowance For Funds Used During Construction
CfD	Contract for Differences
CO₂	Carbon Dioxide
CTA	Competitive Transition Assessment
EPS	Earnings Per Share
ES	Default Energy Service
FASB	Financial Accounting Standards Board
FMCC	Federally Mandated Congestion Charges
FSP	FASB Staff Position
GAAP	Accounting principles generally accepted in the United States of America
GSC	Generation Service Charge
ISO-NE	New England Independent System Operator or ISO New England, Inc.
kWh	Kilowatt-Hours
KV	Kilovolt
LBCB	Lehman Brothers Commercial Bank, Inc.
LOC	Letter of Credit
MW	Megawatts
MWh	Megawatt-Hours
NEEWS	New England East-West Solutions
NU 2008 Form 10-K	The Northeast Utilities and Subsidiaries combined 2008 Annual Report on Form 10-K as filed with the SEC
NYMPA	New York Municipal Power Agency
PBOP	Postretirement Benefits Other Than Pensions
PCRBs	Pollution Control Revenue Bonds
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.
RGGI	The Regional Greenhouse Gas Initiative
ROE	Return on Equity
RRB	Rate Reduction Bonds
SBC	System Benefits Charge
SCRC	Stranded Cost Recovery Charge
SERP	Supplemental Executive Retirement Plan
SFAS	Statement of Financial Accounting Standards
UI	The United Illuminating Company

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, 2009 and December 31, 2008	2

Condensed Consolidated Statements of Income (Unaudited) - Three and Six Months Ended June 30, 2009 and 2008	4

Condensed Consolidated Statements of Cash Flows (Unaudited) - Six Months Ended June 30, 2009 and 2008	5

Combined Notes to Condensed Consolidated Financial Statements (Unaudited - all companies)	6

Report of Independent Registered Public Accounting Firm	34

The Connecticut Light and Power Company and Subsidiaries

Condensed Consolidated Balance Sheets (Unaudited) - June 30, 2009 and December 31, 2008	37

Condensed Consolidated Statements of Income (Unaudited) - Three and Six Months Ended June 30, 2009 and 2008	39

Condensed Consolidated Statements of Cash Flows (Unaudited) - Six Months Ended June 30, 2009 and 2008	40

Public Service Company of New Hampshire and Subsidiaries

Condensed Consolidated Balance Sheets (Unaudited) - June 30, 2009 and December 31, 2008	43

Condensed Consolidated Statements of Income (Unaudited) - Three and Six Months Ended June 30, 2009 and 2008	45

Condensed Consolidated Statements of Cash Flows (Unaudited) - Six Months Ended June 30, 2009 and 2008	46

Western Massachusetts Electric Company and Subsidiary

Condensed Consolidated Balance Sheets (Unaudited) - June 30, 2009 and December 31, 2008	49

Condensed Consolidated Statements of Income (Unaudited) - Three and Six Months Ended June 30, 2009 and 2008	51

Condensed Consolidated Statements of Cash Flows (Unaudited) - Six Months Ended June 30, 2009 and 2008	52

iii


	Page

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

Northeast Utilities and Subsidiaries		53

The Connecticut Light and Power Company and Subsidiaries		76

Public Service Company of New Hampshire and Subsidiaries		81

Western Massachusetts Electric Company and Subsidiary		84

ITEM 3 - Quantitative and Qualitative Disclosures About Market Risk		87

ITEM 4 - Controls and Procedures		88

PART II - OTHER INFORMATION

ITEM 1 - Legal Proceedings		90

ITEM 1A - Risk Factors		90

ITEM 2 - Unregistered Sales of Equity Securities and Use of Proceeds		91

ITEM 4 – Submission of Matters to a Vote of Security Holders		91

ITEM 6 - Exhibits		92

SIGNATURES		94

NORTHEAST UTILITIES AND SUBSIDIARIES


NORTHEAST UTILITIES AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
	June 30,	December 31,
(Thousands of Dollars)	2009	2008

ASSETS

Current Assets:
Cash and cash equivalents	$ 481,148	$ 89,816
Receivables, less provision for uncollectible
accounts of $46,382 in 2009 and $43,275 in 2008	557,587	698,755
Unbilled revenues	170,977	218,440
Fuel, materials and supplies	258,731	300,049
Marketable securities - current	61,837	78,452
Derivative assets - current	18,141	31,373
Prepayments and other	77,378	88,679
	1,625,799	1,505,564

Property, Plant and Equipment:
Electric utility	9,418,469	9,219,351
Gas utility	1,062,801	1,043,687
Other	283,809	290,156
	10,765,079	10,553,194
Less: Accumulated depreciation: $2,668,534 for electric
and gas utility and $148,615 for other in 2009;
$2,610,479 for electric and gas utility and
$159,639 for other in 2008	2,817,149	2,770,118
	7,947,930	7,783,076
Construction work in progress	521,463	424,800
	8,469,393	8,207,876

Deferred Debits and Other Assets:
Regulatory assets	3,262,467	3,502,606
Goodwill	287,591	287,591
Marketable securities - long-term	51,122	30,757
Derivative assets - long-term	224,917	241,814
Other	206,359	212,272
	4,032,456	4,275,040
















Total Assets	$ 14,127,648	$ 13,988,480


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


NORTHEAST UTILITIES AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
	June 30,	December 31,
(Thousands of Dollars)	2009	2008

LIABILITIES AND CAPITALIZATION

Current Liabilities:
Notes payable to banks	$ 493,989	$ 618,897
Long-term debt - current portion	66,286	54,286
Accounts payable	440,520	678,614
Accrued taxes	15,895	12,527
Accrued interest	80,986	69,818
Derivative liabilities - current	85,243	100,919
Other	136,570	168,401
	1,319,489	1,703,462

Rate Reduction Bonds	566,185	686,511

Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	1,310,756	1,223,461
Accumulated deferred investment tax credits	23,758	25,371
Deferred contractual obligations	179,483	193,016
Regulatory liabilities	546,397	592,540
Derivative liabilities - long-term	838,887	912,426
Accrued pension	738,191	740,930
Accrued postretirement benefits	228,533	240,371
Other	414,662	430,718
	4,280,667	4,358,833

Capitalization:
Long-Term Debt	4,343,264	4,103,162

Noncontrolling Interest in Consolidated Subsidiary:
Preferred stock not subject to mandatory redemption	116,200	116,200

Common Shareholders' Equity:
Common shares, $5 par value - authorized
225,000,000 shares; 195,346,832 shares issued
and 175,239,298 shares outstanding in 2009 and
176,212,275 shares issued and 155,834,361 shares
outstanding in 2008	976,734	881,061
Capital surplus, paid in	1,754,184	1,475,006
Deferred contribution plan - employee stock
ownership plan	(9,222)	(15,481)
Retained earnings	1,180,706	1,078,594
Accumulated other comprehensive loss	(38,956)	(37,265)
Treasury stock, 19,708,136 shares in 2009 and 2008	(361,603)	(361,603)
Common Shareholders' Equity	3,501,843	3,020,312
Total Capitalization	7,961,307	7,239,674



Total Liabilities and Capitalization	$ 14,127,648	$ 13,988,480




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


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

	Three Months Ended June 30,		Six Months Ended June 30,
(Thousands of Dollars, except share information)	2009	2008	2009	2008


Operating Revenues	$ 1,224,431	$ 1,325,345	$ 2,817,914	$ 2,845,312

Operating Expenses:
Operation -
Fuel, purchased and net interchange power	583,599	661,699	1,422,519	1,485,016
Other	234,821	237,203	482,266	523,084
Maintenance	56,367	70,896	105,203	127,605
Depreciation	77,768	68,321	154,751	136,075
Amortization of regulatory (liabilities)/assets, net	(13,039)	41,945	8,652	70,800
Amortization of rate reduction bonds	51,305	47,884	107,202	101,234
Taxes other than income taxes	54,424	59,278	140,853	131,107
Total operating expenses	1,045,245	1,187,226	2,421,446	2,574,921
Operating Income	179,186	138,119	396,468	270,391

Interest Expense:
Interest on long-term debt	56,774	46,449	112,458	89,222
Interest on rate reduction bonds	9,607	12,987	20,232	26,703
Other interest (Note 1I)	(1,423)	6,624	3,245	12,776
Interest expense, net	64,958	66,060	135,935	128,701
Other Income, Net	12,409	10,370	16,591	23,928
Income Before Income Tax Expense	126,637	82,429	277,124	165,618
Income Tax Expense	42,394	23,192	93,817	46,598
Net Income	84,243	59,237	183,307	119,020
Net Income Attributable to Noncontrolling Interests:
Preferred dividends of subsidiary	1,389	1,389	2,779	2,779
Net Income Attributable to Controlling Interests	$ 82,854	$ 57,848	$ 180,528	$ 116,241

Basic and Fully Diluted Earnings Per Common Share	$ 0.47	$ 0.37	$ 1.07	$ 0.75

Dividends Declared Per Common Share	$ 0.24	$ 0.20	$ 0.48	$ 0.40

Weighted Average Common Shares Outstanding:

Basic	175,175,936	155,476,492	168,758,206	155,381,302

Diluted	175,675,388	155,895,348	169,300,277	155,808,481




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


NORTHEAST UTILITIES AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
	Six Months Ended June 30,
(Thousands of Dollars)	2009	2008

Operating Activities:
Net income	$ 183,307	$ 119,020
Adjustments to reconcile to net cash flows
provided by operating activities:
Bad debt expense	17,986	13,163
Depreciation	154,751	136,075
Deferred income taxes	73,202	52,995
Pension and PBOP expense/(income), net of capitalized portion, and contributions	13,052	(6,855)
Allowance for equity funds used during construction	(3,366)	(15,082)
Regulatory refunds and underrecoveries	679	(128,830)
Amortization/(deferral) of recoverable energy costs	20,053	(6,046)
Amortization of regulatory assets, net	8,652	70,800
Amortization of rate reduction bonds	107,202	101,234
Deferred contractual obligations	(14,784)	(16,973)
Derivative assets and liabilities	(19,243)	(25,216)
Other	15,948	3,505
Changes in current assets and liabilities:
Receivables and unbilled revenues, net	158,175	35,760
Investments in securitizable assets	-	(25,787)
Fuel, materials and supplies	35,582	(17,946)
Other current assets	10,724	6,426
Accounts payable	(211,445)	(20,648)
Counterparty deposits and margin special deposits	(3,585)	59,110
Taxes receivable/accrued	(8,244)	(31,412)
Other current liabilities	(30,309)	(21,489)
Net cash flows provided by operating activities	508,337	281,804

Investing Activities:
Investments in property and plant	(420,894)	(625,133)
Proceeds from sales of marketable securities	147,702	128,778
Purchases of marketable securities	(149,482)	(130,105)
Rate reduction bond escrow and other deposits	(411)	9,010
Other investing activities	3,350	2,385
Net cash flows used in investing activities	(419,735)	(615,065)

Financing Activities:
Issuance of common shares	387,411	4,562
Cash dividends on common shares	(78,921)	(62,574)
Cash dividends on preferred stock of subsidiary	(2,779)	(2,779)
(Decrease)/increase in short-term debt	(124,908)	8,000
Issuance of long-term debt	312,000	660,000
Retirements of long-term debt	(54,286)	(154,286)
Retirements of rate reduction bonds	(120,326)	(115,177)
Financing fees	(15,456)	(6,265)
Other financing activities	(5)	(1,196)
Net cash flows provided by financing activities	302,730	330,285
Net increase/(decrease) in cash and cash equivalents	391,332	(2,976)
Cash and cash equivalents - beginning of period	89,816	15,104
Cash and cash equivalents - end of period	$ 481,148	$ 12,128

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

NORTHEAST UTILITIES AND SUBSIDIARIES

THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES

WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (All Companies)

Presentation

Certain information and footnote disclosures normally included in annual consolidated financial statements prepared in accordance with accounting principles generally accepted in the United States of America have been omitted pursuant to the rules and regulations of the Securities and Exchange Commission (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 2009 combined Quarterly Report on Form 10-Q, and the combined Annual Report of Northeast Utilities (NU, NU Consolidated, or the Company), The Connecticut Light and Power Company (CL&P), Public Service Company of New Hampshire (PSNH), and Western Massachusetts Electric Company (WMECO), which was filed with the SEC as part of the Northeast Utilities and subsidiaries combined 2008 Annual Report on Form 10-K (NU 2008 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 position as of June 30, 2009 and December 31, 2008, the results of operations for the three and six months ended June 30, 2009 and 2008, and cash flows for the six months ended June 30, 2009 and 2008. The results of operations for the three months ended June 30, 2009 and 2008, and the results of operations and cash flows for the six months ended June 30, 2009 and 2008, are not necessarily indicative of the results expected for a full year.

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

The preparation of the unaudited condensed consolidated financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent liabilities at 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 included in the accompanying unaudited condensed consolidated balance sheets for PSNH and WMECO and the unaudited condensed consolidated statements of cash flows for all companies presented have been made to conform with the current period's presentation.

In accordance with the Financial Accounting Standards Board (FASB) Statement of Financial Accounting Standards (SFAS) No. 160, "Noncontrolling Interests in Consolidated Financial Statements – an amendment of ARB No. 51," the Preferred stock of CL&P, which is not owned by NU or its consolidated subsidiaries and is not subject to mandatory redemption, has been presented as a noncontrolling interest in CL&P in the accompanying unaudited condensed consolidated financial statements of NU. The Preferred stock of CL&P is considered to be temporary equity and has been classified between liabilities and permanent shareholders' equity on the accompanying unaudited condensed consolidated balance sheets of NU and CL&P due to a provision in CL&P's certificate of incorporation that grants preferred stockholders the right to elect a majority of CL&P's board of directors while certain conditions exist, such as if preferred dividends are in arrears for one year. In accordance with SFAS No. 160, the Net income reported in the accompanying unaudited condensed consolidated statements of income and cash flows represents consolidated net income prior to apportionment to noncontrolling interests, which is represented by dividends on preferred stock of CL&P.

Pursuant to SFAS No. 160, the included presentation and disclosure requirements have been applied retrospectively to the unaudited condensed consolidated balance sheet as of December 31, 2008, the unaudited condensed consolidated statements of income for the three and six months ended June 30, 2008, the unaudited condensed consolidated statement of cash flows for the six months ended June 30, 2008, and to consolidated comprehensive income for the three and six months ended June 30, 2008 included in Note 6, "Comprehensive Income," to the unaudited condensed consolidated financial statements. For the six months ended June 30, 2009 and 2008, there was no change in NU parent's 100 percent ownership interest in common equity of CL&P.

Accounting Standards Issued But Not Yet Adopted

In June 2009, the FASB issued SFAS No. 167, "Amendments to FASB Interpretation No. 46(R)" (SFAS No. 167). SFAS No. 167 amends FASB Interpretation No. 46(R) (FIN 46(R)), "Consolidation of Variable Interest Entities - an interpretation of ARB No. 51," to require an enterprise to perform an analysis to determine whether the enterprise's variable interest or interests give it a controlling financial interest in a variable interest entity (VIE). This analysis identifies the primary beneficiary of a VIE as the enterprise that has both of the following characteristics: (a) the power to direct the activities of a VIE that most significantly impact the entity's economic performance and (b) the obligation to absorb losses of or receive benefits from the entity that could potentially be significant to the VIE. SFAS No. 167 amends FIN 46(R) to eliminate the quantitative approach for determining the primary beneficiary of a VIE, which was based on identifying which party absorbs the majority of the entity's expected losses, receives a majority of the entity's expected residual returns, or both. SFAS No. 167 is effective as of January 1, 2010, for interim and annual reporting periods beginning in 2010. Earlier application is prohibited. NU and its subsidiaries do not currently consolidate any VIEs with which the companies are associated, and management does not expect to change the accounting for these VIEs as a result of implementing SFAS No. 167.

Accounting Standards Recently Adopted

On January 1, 2009, NU and its subsidiaries, including CL&P, PSNH and WMECO, adopted SFAS No. 157, "Fair Value Measurements," for nonrecurring fair value measurements of nonfinancial assets and liabilities, including asset retirement obligations (AROs) and goodwill and other impairment analyses. NU adopted SFAS No. 157 for fair value measurements of financial assets and liabilities effective January 1, 2008. Implementation of SFAS No. 157 for nonfinancial assets and liabilities did not affect the accompanying unaudited condensed consolidated financial statements. Application of SFAS No. 157 to Yankee Gas Services Company (Yankee Gas) goodwill, which is tested for impairment as of October 1^st of each year, is not expected to have a material effect on the Company's financial position or results of operations because the market participant perspective required to be considered in fair value measurements is incorporated in Yankee Gas' goodwill impairment analysis.

In the second quarter of 2009, NU and its subsidiaries adopted FASB Staff Position (FSP) FAS 115-2, "Recognition and Presentation of Other-Than-Temporary Impairments," which changes the indicators for determining if unrealized losses on debt securities (the excess of amortized cost over fair value) should be recorded in Net income as other-than-temporary impairments. Beginning in the second quarter of 2009, other-than-temporary impairments of debt securities in NU's Trust Under Supplemental Executive Retirement Plan (supplemental benefit trust) are reflected in the Company's unaudited condensed consolidated statement of income if the Company either intends to sell the security or would more likely than not be required to sell the security before recovery to its amortized cost, or if the Company does not expect to recover the amortized cost as a result of a credit loss. For securities that the Company does not intend to sell and it is not more likely than not that it will be required to sell before recovery, only the credit loss component of an impairment is recognized in Net income, and the remainder is recognized in Accumulated other comprehensive income/(loss). NU recorded an after-tax cumulative effect of a change in accounting principle of $0.7 million as an increase to the April 1, 2009 balance of Retained earnings with an offset to Accumulated other comprehensive income/(loss) relating to the reversal of unrealized losses previously recorded in Net income on debt securities held in the supplemental benefit trust for which did not meet the criteria described above. The FSP had no impact on investments in WMECO's spent nuclear fuel trust as unrealized losses including impairments are recorded in Deferred debits and other assets - other on the accompanying unaudited condensed consolidated balance sheet due to the regulatory accounting treatment of this trust. As a result of adopting FSP FAS 115-2, Net income for both the three and six months ended June 30, 2009 is $0.3 million higher than it would otherwise have been with no effect on reported Earnings per share.

In the second quarter of 2009, NU and its subsidiaries, including CL&P, PSNH and WMECO, adopted FSP FAS 157-4, "Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions that Are Not Orderly," which provides guidance for estimating fair value when the volume and level of activity for an asset or liability have significantly decreased and requires additional disclosures related to fair value measurements (refer to Note 1D, "Summary of Significant Accounting Policies - Fair Value Measurements," and Note 3, "Fair Value Measurements," to the unaudited condensed consolidated financial statements). Implementation of this guidance did not affect the companies' valuation of their assets or liabilities that are measured at fair value.

SFAS No. 165, "Subsequent Events," incorporates into FASB authoritative literature accounting guidance that originated as auditing standards about events or transactions that occur after the balance sheet date but before financial statements are issued. SFAS No. 165 retains the auditing standard requirements to recognize in the financial statements the effects of all subsequent events that provide additional evidence about conditions that existed at the balance sheet date and to disclose but not recognize subsequent events that provide evidence about conditions that arose after the balance sheet date but before the financial statements are issued. The reporting entity is required to disclose the date through which it has evaluated subsequent events. SFAS No. 165 was issued and implemented in the second quarter of 2009. In preparing the accompanying unaudited condensed consolidated financial statements, NU has evaluated events subsequent to June 30, 2009 through the issuance of the financial statements on August 7, 2009 and has not identified any events for disclosure.

Fair Value Measurements

Fair Value Hierarchy: In measuring fair value the Company 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 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. 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 there 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 as follows:

Derivative instruments: Many of the Company's derivative positions that are recorded at fair value are classified as Level 3 within the fair value hierarchy and are valued using models that incorporate both observable and unobservable inputs. Fair value is modeled using techniques such as discounted cash flow approaches adjusted for assumptions relating to exit price and the Black-Scholes option pricing model, incorporating the terms of the contracts. Significant unobservable inputs used in the valuations include energy and energy-related product prices for future years for long-dated derivative contracts, future contract quantities under full requirements and supplemental sales contracts, and market volatilities. 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 also reflect nonperformance risk, including credit. The derivative contracts classified as Level 3 include NU Enterprises, Inc. (NU Enterprises) remaining wholesale marketing contract and its related supply contracts, CL&P's contracts for differences (CfDs), CL&P's contracts with certain independent power producers (IPPs), PSNH and Yankee Gas physical options and CL&P and PSNH financial transmission rights (FTRs).

Other derivative contracts recorded at fair value are classified as Level 2 within the fair value hierarchy. An active market for the same or similar contracts exists for these contracts, which include PSNH forward contracts to purchase energy and interest rate swap agreements. For these contracts, valuations are based on quoted prices in the market and include some modeling using market-based assumptions.

For further information on derivative contracts, see Note 2, "Derivative Instruments," to the unaudited condensed consolidated financial statements.

Marketable securities: NU and WMECO hold in trust marketable securities, which include equity securities, mutual funds and cash equivalents, and fixed maturity securities.

Equity securities, mutual funds and cash equivalents are classified as Level 1 in the fair value hierarchy. These investments are traded in active markets and quoted prices for identical investments are available and used in NU's fair value measurements.

Fixed maturity securities classified as Level 2 within the fair value hierarchy include U.S. Treasury securities, corporate bonds, collateralized mortgage obligations, U.S. pass-through bonds, asset-backed securities, commercial mortgage-backed securities, and commercial paper. The fair value of these instruments is estimated using pricing models, quoted prices of securities with similar characteristics or discounted cash flows. The pricing models utilize observable inputs such as recent trades for the same or similar instruments, yield curves, discount margins and bond structures.

For further information see Note 3, "Fair Value Measurements," and Note 10, "Marketable Securities," to the unaudited condensed consolidated financial statements.

There were no changes to the valuation methodologies for derivative instruments or marketable securities for the three or six months ended June 30, 2009.

Regulatory Accounting

The accounting policies of the regulated companies, as defined below, conform to accounting principles generally accepted in the United States of America applicable to rate-regulated enterprises and historically reflect the effects of the rate-making process in accordance with SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation."

The transmission and distribution segments of CL&P, PSNH (including its generation business) and WMECO, along with Yankee Gas' distribution segment (collectively, regulated companies), continue to be rate-regulated on a cost-of-service basis. Management believes it is probable that NU's regulated companies will recover their respective investments in long-lived assets, including regulatory assets. All material net regulatory assets are earning an equity return, except for securitized regulatory assets, the majority of deferred benefit costs and regulatory assets offsetting regulated company derivative liabilities, which are not supported by equity. Amortization and deferrals of regulatory assets/(liabilities) are included on a net basis in Amortization of regulatory (liabilities)/assets, net on the accompanying unaudited condensed consolidated statements of income.

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


	As of June 30, 2009		As of December 31, 2008
(Millions of Dollars)	NU Consolidated		NU Consolidated
Deferred benefit costs	$	1,104.2	$	1,140.9
Regulatory assets offsetting derivative liabilities		784.1		844.2
Securitized assets		557.2		677.4
Income taxes, net		359.9		355.4
Unrecovered contractual obligations		159.2		169.1
CL&P undercollections		72.8		75.2
Other regulatory assets		225.1		240.4
Totals	$	3,262.5	$	3,502.6


	As of June 30, 2009						As of December 31, 2008
(Millions of Dollars)	CL&P		PSNH		WMECO		CL&P		PSNH		WMECO
Deferred benefit costs	$	521.2	$	136.2	$	110.5	$	537.7	$	142.9	$	113.5
Regulatory assets offsetting derivative liabilities		702.1		81.9		-		751.9		92.1		-
Securitized assets		288.0		204.4		64.7		377.8		227.6		72.0
Income taxes, net		308.3		20.7		17.2		306.8		16.1		20.7
Unrecovered contractual obligations		125.2		-		34.0		132.6		-		36.5
CL&P undercollections		72.8		-		-		75.2		-		-
WMECO recoverable nuclear costs		-		-		2.9		-		-		5.0
Other regulatory assets		83.2		69.2		20.1		92.1		71.2		20.7
Totals	$	2,100.8	$	512.4	$	249.4	$	2,274.1	$	549.9	$	268.4

Additionally, the regulated companies had $56.9 million ($47.9 million for PSNH, $8.2 million for CL&P, and $0.8 million for WMECO) and $68.3 million ($62.7 million for PSNH and $5.6 million for CL&P) of regulatory costs as of June 30, 2009 and December 31, 2008, respectively, which were included in Deferred debits and other assets - other 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 recoverable in future cost-of-service regulated rates. Of these amounts, $47.9 million and $62.7 million as of June 30, 2009 and December 31, 2008, respectively, related to costs incurred at PSNH for the December 2008 storm restorations that met the New Hampshire Public Utilities Commission (NHPUC) specified criteria for deferral to a major storm cost reserve. The decrease in PSNH deferred storm costs is primarily a result of insurance proceeds received during the second quarter of 2009, which were used to reduce the storm costs deferral.

Included in NU's other regulatory assets are the regulatory assets associated with the implementation of FIN 47, "Accounting for Conditional Asset Retirement Obligations - an interpretation of FASB Statement No. 143," totaling $44.2 million ($24.4 million for CL&P, $14.2 million for PSNH, and $2.9 million for WMECO) as of June 30, 2009 and $42.3 million ($23.1 million for CL&P, $13.9 million for PSNH, and $2.8 million for WMECO) as of December 31, 2008. Of these amounts, $12.3 million and $12 million, respectively, related to PSNH have been approved for future recovery. Management believes that recovery of the remaining FIN 47 regulatory assets is probable.

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


	As of June 30, 2009		As of December 31, 2008
(Millions of Dollars)	NU Consolidated		NU Consolidated
Cost of removal	$	218.7	$	226.0
Regulatory liabilities offsetting derivative assets		128.4		137.8
CL&P overcollections		46.0		69.5
CL&P AFUDC transmission incentive		48.5		47.6
PSNH ES deferral		30.7		33.0
Pension and PBOP liabilities - Yankee Gas acquisition		16.3		17.6
Overrecovered gas costs		16.6		16.9
Other regulatory liabilities		41.2		44.1
Totals	$	546.4	$	592.5


	As of June 30, 2009						As of December 31, 2008
(Millions of Dollars)	CL&P		PSNH		WMECO		CL&P		PSNH		WMECO
Cost of removal	$	87.9	$	62.6	$	17.4	$	91.2	$	64.7	$	19.2
Regulatory liabilities offsetting derivative assets		126.9		1.5		-		131.3		4.6		-
CL&P overcollections		46.0		-		-		69.5		-		-
CL&P AFUDC transmission incentive		48.5		-		-		47.6		-		-
PSNH ES deferral		-		30.7		-		-		33.0		-
WMECO provision for rate refunds		-		-		1.3		-		-		1.3
WMECO transition charge overcollections		-		-		-		-		-		5.7
WMECO pension/PBOP tracker		-		-		1.2		-		-		2.0
Other regulatory liabilities		25.2		10.0		3.0		23.9		9.1		1.6
Totals	$	334.5	$	104.8	$	22.9	$	363.5	$	111.4	$	29.8

Allowance for Funds Used During Construction

Allowance for funds used during construction (AFUDC) is included in the cost of the regulated companies' utility plant and represents the cost of borrowed and equity funds used to finance construction. The portion of AFUDC attributable to borrowed funds is recorded as a reduction of Other interest expense, and the AFUDC related to equity funds is recorded as Other income, net on the accompanying unaudited condensed consolidated statements of income.


	For the Three Months Ended				For the Six Months Ended
	June 30, 2009		June 30, 2008		June 30, 2009		June 30, 2008
(Millions of Dollars, except percentages)	NU Consolidated		NU Consolidated		NU Consolidated		NU Consolidated
Borrowed funds	$	1.4	$	4.4	$	3.5	$	9.1
Equity funds		2.5		6.8		3.4		15.1
Totals	$	3.9	$	11.2	$	6.9	$	24.2
Average AFUDC rates		6.6%		7.9%		5.9%		8.1%


	For the Three Months Ended
	June 30, 2009						June 30, 2008
(Millions of Dollars, except percentages)	CL&P		PSNH		WMECO		CL&P		PSNH		WMECO
Borrowed funds	$	0.6	$	0.7	$	-	$	3.3	$	0.8	$	0.2
Equity funds		1.7		0.8		-		5.8		0.9		0.2
Totals	$	2.3	$	1.5	$	-	$	9.1	$	1.7	$	0.4
Average AFUDC rates		8.2%		6.1%		1.1%*		8.4%		6.9%		6.0%

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


	For the Six Months Ended
	June 30, 2009						June 30, 2008
(Millions of Dollars, except percentages)	CL&P		PSNH		WMECO		CL&P		PSNH		WMECO
Borrowed funds	$	1.5	$	1.6	$	0.1	$	6.7	$	1.6	$	0.4
Equity funds		1.6		1.7		-		12.4		2.2		0.4
Totals	$	3.1	$	3.3	$	0.1	$	19.1	$	3.8	$	0.8
Average AFUDC rates		5.7%		7.0%		2.5%		8.4%		7.5%		7.0%

The regulated companies' average AFUDC rate is based on a Federal Energy Regulatory Commission (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 New England East-West Solutions (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.

Other Income, Net

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


NU Consolidated	For the Three Months Ended				For the Six Months Ended
(Million of Dollars)	June 30, 2009		June 30, 2008		June 30, 2009		June 30, 2008
Other Income:
Interest income	$	2.0	$	-	$	4.0	$	-
Investment income		6.6		2.0		4.1		3.9
AFUDC - equity funds		2.5		6.8		3.4		15.1
Energy Independence Act incentives		0.7		3.4		4.3		8.9
Conservation and load management incentives		0.4		-		0.5		-
Other		0.2		0.2		0.5		0.4
Total Other Income		12.4		12.4		16.8		28.3
Other Loss:
Investment write-downs		-		(1.2)		-		(3.8)
Conservation and load management costs		-		(0.8)		-		(0.4)
Rental expense		-		-		(0.2)		(0.2)
Total Other Loss		-		(2.0)		(0.2)		(4.4)
Total Other Income, Net	$	12.4	$	10.4	$	16.6	$	23.9


CL&P	For the Three Months Ended				For the Six Months Ended
(Millions of Dollars)	June 30, 2009		June 30, 2008		June 30, 2009		June 30, 2008
Other Income:
Interest income	$	1.1	$	-	$	1.9	$	-
Investment income		4.2		1.9		2.2		3.3
AFUDC - equity funds		1.7		5.8		1.6		12.4
Energy Independence Act incentives		0.7		3.4		4.3		8.9
Conservation and load management incentives		0.3		-		0.3		-
Other		0.2		0.2		0.6		0.3
Total Other Income		8.2		11.3		10.9		24.9
Other Loss:
Investment write-downs		-		(0.8)		-		(2.6)
Conservation and load management costs		-		(0.9)		-		(0.6)
Total Other Loss		-		(1.7)		-		(3.2)
Total Other Income, Net	$	8.2	$	9.6	$	10.9	$	21.7


PSNH	For the Three Months Ended				For the Six Months Ended
(Millions of Dollars)	June 30, 2009		June 30, 2008		June 30, 2009		June 30, 2008
Other Income:
Interest income	$	0.9	$	-	$	1.8	$	-
Investment income		1.0		0.6		0.6		0.9
AFUDC - equity funds		0.8		0.9		1.7		2.2
Other		0.1		-		0.1		0.1
Total Other Income		2.8		1.5		4.2		3.2
Investment write-downs		-		(0.2)		-		(0.6)
Total Other Income, Net	$	2.8	$	1.3	$	4.2	$	2.6


WMECO	For the Three Months Ended				For the Six Months Ended
(Millions of Dollars)	June 30, 2009		June 30, 2008		June 30, 2009		June 30, 2008
Other Income:
Interest income	$	0.1	$	-	$	0.2	$	-
Investment income		0.9		0.4		0.5		0.6
AFUDC - equity funds		-		0.2		-		0.4
Conservation and load management incentives		0.1		0.1		0.2		0.2
Other		-		-		0.1		-
Total Other Income		1.1		0.7		1.0		1.2
Other Loss:
Investment write-downs		-		(0.2)		-		(0.5)
Rental expense		-		-		(0.1)		-
Total other loss		-		(0.2)		(0.1)		(0.5)
Total Other Income, Net	$	1.1	$	0.5	$	0.9	$	0.7

Consolidated investment income for the three and six months ended June 30, 2009 includes realized gains of $5.6 million ($3.4 million for CL&P, $0.8 million for PSNH, and $0.8 million for WMECO) from the sale of equity securities in NU's supplemental benefit trust in June 2009. Investment income also includes equity in earnings of regional nuclear generating and transmission companies of $0.5 million and $0.3 million for NU ($0.1 million in both periods for CL&P and de minimis amounts for PSNH and WMECO) for the three months ended June 30, 2009 and 2008, respectively, and $1 million in both periods for NU ($0.2 million in both periods for CL&P, $0.1 million in both periods for WMECO and a de minimis amount for PSNH) for the six months ended June 30, 2009 and 2008, respectively. Equity in earnings relates to the Company's investments, including CL&P, PSNH and WMECO's investments, in Connecticut Yankee Atomic Power Company (CYAPC), Maine Yankee Atomic Power Company, and Yankee Atomic Electric Company and NU's investments in two regional transmission companies.

Special Deposits and Counterparty Deposits

To the extent NU Enterprises, a wholly owned subsidiary of NU, through its wholly owned subsidiary Select Energy, Inc. (Select Energy), requires collateral from counterparties, or the counterparties require collateral from Select Energy, cash is held on deposit by Select Energy or with unaffiliated counterparties and brokerage firms as a part of the total collateral required based on Select Energy's position in transactions with the counterparty. Select Energy's right to use cash collateral is determined by the terms of the related agreements. Key factors affecting the unrestricted status of a portion of this cash collateral include the financial standing of Select Energy and of NU as its credit supporter.

NU and its subsidiaries record special deposits and counterparty deposits in accordance with FSP FIN 39-1, "Amendment of FASB Interpretation No. 39," which requires NU to net collateral amounts posted under a master netting agreement if the related derivatives are recorded in a net position. As of June 30, 2009, CL&P had $1 million of collateral posted under master netting agreements and netted against the fair value of the derivatives. As of December 31, 2008, NU and its subsidiaries, including CL&P, PSNH and WMECO, had no special deposits or counterparty collateral posted under master netting agreements netted against the fair value of derivatives.

Special deposits paid by Select Energy to unaffiliated counterparties and brokerage firms not subject to master netting agreements totaled $28.3 million and $26.3 million as of June 30, 2009 and December 31, 2008, respectively. These amounts are recorded as Current assets and are included in Prepayments and other on the accompanying unaudited condensed consolidated balance sheets. There were no counterparty deposits for Select Energy as of June 30, 2009 and December 31, 2008.

NU consolidated, 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, 2009 and December 31, 2008, there were no counterparty deposits for these companies.

Income Taxes

Tax Positions: In June 2009, the Internal Revenue Service (IRS) 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. Management estimates that resolution of this audit decreases NU's unrecognized tax benefits by approximately $32 million ($16 million for CL&P, $12 million for PSNH, and $3 million for WMECO).

NU is currently working to resolve all open tax years. It is reasonably possible that one or more of these open tax years could be resolved within the next twelve months. Management estimates that potential resolutions could result in a zero to $34 million decrease in unrecognized tax benefits on an NU consolidated basis (zero to $15 million at CL&P).

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. For the three and six months ended June 30, 2009, NU gross receipts taxes, franchise taxes and other excise taxes of $30.8 million and $69.8 million, respectively, ($27.7 million and $58.6 million, respectively, for CL&P) were included in Operating revenues and Taxes other than income taxes on the accompanying unaudited condensed consolidated statements of income. For the three and six months ended June 30, 2008, these amounts totaled $27.4 million and $58.4 million, respectively ($23.3 million and $47 million, respectively, for CL&P). 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.

DERIVATIVE INSTRUMENTS (NU, NU Enterprises, CL&P, PSNH, Yankee Gas)

Derivative contracts that meet the definition of and are designated as "normal purchases or normal sales" (normal) are recognized in Operating revenues or Operating expenses, as applicable, as electricity or natural gas is delivered.

Derivative contracts that are not designated as hedging instruments or as normal 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, including CL&P, PSNH and Yankee Gas, regulatory assets or liabilities are recorded for the changes in fair values of derivatives, as these contracts are part of current regulated operating costs, or have an allowed recovery mechanism, and management believes that these costs will continue to be recovered from or refunded to customers in cost-of-service, regulated rates.

CL&P, PSNH, WMECO and Yankee Gas are exposed to the volatility of the prices of energy and energy related products in procuring energy supply for their customers. The costs associated with supplying energy to customers are recoverable through customer rates. The Company manages the risks associated with the price volatility of energy and energy related products through the use of derivative contracts, many of which are accounted for as normal, and the use of non-derivative 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 standard offer and last resort service contracts. As required by regulation, CL&P has also entered into derivative and non-derivative 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. The derivative contracts not accounted for as normal are accounted for at fair value. Management believes any costs or benefits from these contracts are recoverable from, or refunded to, CL&P's customers, therefore any changes in fair value are recorded as Regulatory assets and Regulatory liabilities.

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. The derivative contracts not accounted for as normal are accounted for at fair value. Management believes any costs or benefits from these contracts are recoverable from, or refunded to, PSNH's customers, therefore any changes in fair value are recorded as Regulatory assets and Regulatory liabilities.

Yankee Gas 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 gas supply for customers that include non-derivative contracts and contracts that are accounted for as normal. Yankee Gas also manages price risk through the use of options contracts. The derivative contracts not accounted for as normal are accounted for at fair value, and because management believes any costs or benefits from these contracts are recoverable from or refundable to Yankee Gas' customers, any changes in fair value are recorded as Regulatory assets and Regulatory liabilities.

NU Enterprises, through Select Energy, has one remaining fixed price forward sales contract that was entered into as part of its wholesale energy marketing business. NU Enterprises mitigates the price risk associated with this contract through the use of forward purchase contracts. NU Enterprises' derivative contracts are accounted for at fair value, and changes in their fair values are recorded in Operating expenses.

The Company is also exposed to interest rate risk associated with its long-term debt. From time to time, the Company enters into forward starting interest rate swaps, accounted for as cash flow hedges, to mitigate the risk of changes in interest rates when it expects 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. The interest rate swap mitigating the interest rate risk associated with the fixed rate long-term debt 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 net as current or long-term Derivative assets or Derivative liabilities 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:


	As of June 30, 2009
(Millions of Dollars)	Gross Asset		Gross Liability		Net Amount Recorded as Derivative Asset			Gross Asset		Gross Liability		Cash Collateral Posted		Net Amount Recorded as Derivative Liability
Derivatives not designated as hedging instruments
NU Enterprises:
Commodity sales contract and related price and supply risk management:
Current	$	-	$	-	$	-		$	3.1	$	(9.9)	$	-	$	(6.8)
Long-Term		-		-		-			2.7		(40.6)		-		(37.9)
Regulated Companies:
CL&P commodity and capacity contracts required by regulation:
Current		10.6		(4.0)		6.6	⁽¹⁾		-		(7.4)		-		(7.4)
Long-Term		262.1		(45.5)		216.6	⁽¹⁾		-		(787.0)		-		(787.0)
Commodity price and supply risk management:
CL&P:
Current		4.6		-		4.6			-		(3.9)		1.0		(2.9)
PSNH:
Current ⁽²⁾		0.4		-		0.4			-		(67.7)		-		(67.7)
Long-Term ⁽²⁾		1.1		-		1.1			-		(14.3)		-		(14.3)
Yankee Gas:
Current		-		-		-			-		(0.4)		-		(0.4)
Long-Term		-		-		-			-		0.3		-		0.3
Derivatives designated as hedging instruments
Interest rate risk management:
Current ⁽³⁾		6.5		-		6.5			-		-		-		-
Long-Term		7.2		-		7.2			-		-		-		-

⁽¹⁾

Fair value amounts of $(4.0) million current and $100.2 million long-term that relate to a sharing agreement are recorded in Derivative assets.

⁽²⁾

On PSNH's accompanying unaudited condensed consolidated balance sheet, the current portion of the net derivative asset is shown in Prepayments and other and the long-term portion is shown in Deferred debits and other assets - other.

⁽³⁾

Amount does not include interest receivable of $2.4 million as of June 30, 2009 recorded in Prepayments and other on the accompanying unaudited condensed consolidated balance sheet.

For further information on the fair value of derivative contracts, see Note 3, "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 hedging instruments

NU Enterprises' energy sales contract and related price risk management: As of June 30, 2009, NU Enterprises had approximately 0.4 million megawatt-hours (MWh) of supply contract volumes remaining in its wholesale sales contract portfolio that expires in 2013 and that includes a contract to sell electricity to the New York Municipal Power Agency (NYMPA) (an agency that is comprised of municipalities), net of sourcing contracts to purchase electricity with delivery dates through 2013.

CL&P energy and capacity contracts required by regulation: CL&P has 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 two generating projects to be built or modified. The total capacity of these CfDs and two additional CfDs of The United Illuminating Company (UI) is expected to be approximately 787 megawatts (MW). CL&P has an agreement with UI, which is also accounted for as a derivative, under which it 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 New England Independent System Operator (ISO-NE) capacity markets for periods of up to 15 years beginning in 2009.

CL&P, PSNH and Yankee Gas energy and natural gas price risk management: As of June 30, 2009, CL&P had 1.2 million MWh

and 0.9 million MWh remaining under FTRs and bilateral basis swaps, respectively, that expire by December 31, 2009 and require monthly payments or receipts.

PSNH has electricity procurement contracts with delivery dates through 2011 to purchase an aggregate amount of 2.4 million MWh of power 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 0.9 million MWh of electricity through December 2010. In addition, PSNH has entered into FTRs to manage the risk of congestion costs associated with its electricity delivery service. As of June 30, 2009, there were 0.8 million MWh remaining under FTRs that expire in 2009 and require 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.

Yankee Gas has 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 3 thousand MMBtu expires on October 31, 2009, and the other contract for 14 thousand MMBtu expires on April 1, 2012. Demand fees on these contracts are settled annually or seasonally and are included in Yankee Gas' Purchased Gas Adjustment for recovery.

The following table presents the realized and unrealized gains/(losses) associated with derivative contracts not designated as hedging instruments for the three and six months ended June 30, 2009:


		Amount of Gain/(Loss) Recognized on Derivative Instrument
Derivatives Not Designated as Hedging Instruments	Location of Gain or Loss Recognized on Derivative	Three Months Ended June 30, 2009	Six Months Ended June 30, 2009
NU Enterprises:		(Millions of Dollars)
Energy sales contract and energy price risk management	Fuel, purchased and net interchange power	$ 2.4	$ 7.8
Regulated Companies:
CL&P energy and capacity contracts required by regulation	Regulatory assets/liabilities	61.2	50.2
Commodity price and supply risk management:
CL&P	Regulatory assets/liabilities	(1.1)	(7.0)
PSNH	Regulatory assets/liabilities	(8.3)	(50.8)
Yankee Gas	Regulatory assets/liabilities	(1.2)	(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. Regulatory assets/liabilities are established through Amortization of regulatory assets/liabilities, net, with no impact to Net income.

Derivatives designated as hedging instruments

Interest Rate Risk Management: To manage the interest rate risk characteristics of the Company's fixed rate long-term debt, NU 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 qualified and was designated as a fair value hedge and requires semi-annual payments/receipts. The changes in fair value of the swap and the interest component of the hedged long-term debt instrument are recorded in interest expense. There was no ineffectiveness recorded for the three and six months ended June 30, 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 included in Prepayments and other.

For the three and six months ended June 30, 2009, the realized and unrealized gains/(losses) related to changes in fair value of the swap and Long-term debt as well as Interest expense, recorded in Net income, were as follows:


	Swap				Hedged Debt
(Millions of Dollars) Income Statement Classification	Three Months Ended June 30, 2009		Six Months Ended June 30, 2009		Three Months Ended June 30, 2009		Six Months Ended June 30, 2009
Change in fair value	$	(3.8)	$	(3.3)	$	3.8	$	3.3
Interest recorded in Net income		-		-		2.4		3.8

There were no cash flow hedges outstanding as of, or during the three and six month periods ended, June 30, 2009 and no ineffectiveness was recorded during those periods. From time to time, NU and its subsidiaries, including CL&P, PSNH and WMECO, enter into forward starting interest rate swap agreements on proposed debt issuances that qualify and are designated as cash flow hedges. Cash flow hedges are recorded at fair value, and the changes in the fair value of the effective portion of those contracts are recognized in Accumulated other comprehensive income/(loss). Cash flow hedges impact Net income when hedge ineffectiveness is measured and recorded or when the forecasted transaction being hedged is improbable of occurring. When a cash flow hedge is terminated, the settlement amount is recorded in Accumulated other comprehensive income/(loss) and is amortized into Net income over the term of the underlying debt instrument.

For the three and six months ended June 30, 2009, pre-tax gains/(losses) amortized from Accumulated other comprehensive income/(loss) into Interest expense were as follows:


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

For further information, see Note 6, "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, to maintain investment grade credit ratings from the major rating agencies and to post cash or standby letters of credit (LOCs) as collateral for contracts in a net liability position over specified credit limits. NU provides standby LOCs under its revolving credit agreement for its 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, 2009:


(Millions of Dollars)	Fair Value Subject to Credit Risk Contingent Features		Cash Collateral Posted		Standby LOCs Posted
CL&P	$	(1.0)	$	1.0	$	-
PSNH		(81.8)		-		71.0
NU Enterprises		(36.1)		28.3		-
NU Consolidated	$	(118.9)	$	29.3	$	71.0

Additional collateral is required to be posted by NU Enterprises, CL&P or PSNH, respectively, if NU parent's, CL&P's or PSNH's respective credit ratings are downgraded below investment grade. As of June 30, 2009, no additional cash collateral would be required to be posted if credit ratings were downgraded below investment grade. However, if PSNH's or NU parent's senior unsecured debt were downgraded to below investment grade, additional standby LOCs in the amount of $23 million and $15.2 million would be 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 (All Companies)

The following tables present the amounts of assets and liabilities recorded at fair value on a recurring basis by the level in which they are classified within the fair value hierarchy:


	As of June 30, 2009
(Millions of Dollars)	Total NU		CL&P		PSNH		WMECO		NU Enterprises		Yankee Gas		NU Parent
Derivative Assets:
Level 1	$	-	$	-	$	-	$	-	$	-	$	-	$	-
Level 2		13.7		-		-		-		-		-		13.7
Level 3		229.3		227.8		1.5		-		-		-		-
Total	$	243.0	$	227.8	$	1.5	$	-	$	-	$	-	$	13.7
Derivative Liabilities:
Level 1	$	-	$	-	$	-	$	-	$	-	$	-	$	-
Level 2		(81.8)		-		(81.8)		-		-		-		-
Level 3		(843.3)		(798.3)		(0.2)		-		(44.7)		(0.1)		-
Cash collateral posted		1.0		1.0		-		-		-		-		-
Total	$	(924.1)	$	(797.3)	$	(82.0)	$	-	$	(44.7)	$	(0.1)	$	-
Marketable Securities:
Level 1:
Mutual funds	$	27.2	$	-	$	-	$	-	$	-	$	-	$	27.2
Money market and other		5.9		-		-		1.1		-		-		4.8
Total Level 1		33.1		-		-		1.1		-		-		32.0
Level 2:
U.S. government issued debt securities (agency and treasury)		31.9		-		-		17.0		-		-		14.9
Corporate debt securities		27.4		-		-		21.6		-		-		5.8
Asset backed securities		4.8		-		-		1.2		-		-		3.6
Municipal bonds		11.0		-		-		11.0		-		-		-
Other		4.8		-		-		4.4		-		-		0.4
Total Level 2		79.9		-		-		55.2		-		-		24.7
Total	$	113.0	$	-	$	-	$	56.3	$	-	$	-	$	56.7


	As of December 31, 2008
(Millions of Dollars)	Total NU		CL&P		PSNH		WMECO		NU Enterprises		Yankee Gas		NU Parent
Derivative Assets:
Level 1	$	-	$	-	$	-	$	-	$	-	$	-	$	-
Level 2		20.8		-		-		-		-		-		20.8
Level 3		252.4		245.8		4.7		-		-		1.9		-
Total	$	273.2	$	245.8	$	4.7	$	-	$	-	$	1.9	$	20.8
Derivative Liabilities:
Level 1	$	-	$	-	$	-	$	-	$	-	$	-	$	-
Level 2		(91.7)		-		(91.7)		-		-		-		-
Level 3		(921.6)		(856.9)		(0.6)		-		(63.9)		(0.2)		-
Total	$	(1,013.3)	$	(856.9)	$	(92.3)	$	-	$	(63.9)	$	(0.2)	$	-
Marketable Securities:
Level 1	$	42.1	$	-	$	-	$	10.3	$	-	$	-	$	31.8
Level 2		67.1		-		-		45.4		-		-		21.7
Level 3		-		-		-		-		-		-		-
Total	$	109.2	$	-	$	-	$	55.7	$	-	$	-	$	53.5

Not included in the tables above are $458.6 million and $81.6 million of cash equivalents held by NU parent as of June 30, 2009 and December 31, 2008, respectively, which are included in cash and cash equivalents on the accompanying unaudited condensed consolidated balance sheets and are classified as Level 1 in the fair value hierarchy.

The following tables present changes for the three and six months ended June 30, 2009 and 2008 in the Level 3 category of assets and liabilities measured at fair value on a recurring basis. This category includes derivative assets and liabilities, which 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 the three and six months ended June 30, 2009 and 2008.


	For the Three Months Ended June 30, 2009
(Millions of Dollars)	Total NU		CL&P		PSNH		NU Enterprises		Yankee Gas
Derivatives, Net:
Fair value as of March 31, 2009	$	(680.3)	$	(633.3)	$	1.4	$	(49.2)	$	0.8
Net realized/unrealized gains/(losses) included in:
Net income ⁽¹⁾		2.4		-		-		2.4		-
Regulatory assets/liabilities		58.8		60.1		(0.1)		-		(1.2)
Purchases, issuances and settlements		5.1		2.7		-		2.1		0.3
Fair value as of June 30, 2009	$	(614.0)	$	(570.5)	$	1.3	$	(44.7)	$	(0.1)
Quarterly change in unrealized gains included in Net income relating to items held as of June 30, 2009	$	2.2	$	-	$	-	$	2.2	$	-


	For the Three Months Ended June 30, 2008
(Millions of Dollars)	Total NU		CL&P		PSNH		NU Enterprises		Yankee Gas
Derivatives, Net:
Fair value as of March 31, 2008	$	(488.5)	$	(430.3)	$	22.8	$	(81.1)	$	0.1
Net realized/unrealized gains included in:
Net income ⁽¹⁾		1.2		-		-		1.2		-
Regulatory assets/liabilities		228.7		209.1		18.1		-		1.5
Purchases, issuances and settlements		(18.4)		(23.7)		-		5.3		-
Fair value as of June 30, 2008	$	(277.0)	$	(244.9)	$	40.9	$	(74.6)	$	1.6
Quarterly change in unrealized losses included in Net income relating to items held as of June 30, 2008	$	(2.3)	$	-	$	-	$	(2.3)	$	-


	For the Six Months Ended June 30, 2009
(Millions of Dollars)	Total NU		CL&P		PSNH		NU Enterprises		Yankee Gas
Derivatives, Net:
Fair value as of January 1, 2009	$	(669.2)	$	(611.1)	$	4.1	$	(63.9)	$	1.7
Net realized/unrealized gains/(losses) included in:
Net income ⁽¹⁾		7.8		-		-		7.8		-
Regulatory assets/liabilities		38.3		43.2		(2.8)		-		(2.1)
Purchases, issuances and settlements		9.1		(2.6)		-		11.4		0.3
Fair value as of June 30, 2009	$	(614.0)	$	(570.5)	$	1.3	$	(44.7)	$	(0.1)
Period change in unrealized gains included in Net income relating to items held as of June 30, 2009	$	7.4	$	-	$	-	$	7.4	$	-


	For the Six Months Ended June 30, 2008
(Millions of Dollars)	Total NU		CL&P		PSNH		NU Enterprises		Yankee Gas
Derivatives, Net:
Fair value as of January 1, 2008 ⁽²⁾	$	(511.1)	$	(426.9)	$	15.7	$	(100.1)	$	0.2
Net realized/unrealized gains included in:
Net income ⁽¹⁾		4.8		-		-		4.8		-
Regulatory assets/liabilities		245.5		218.9		25.2		-		1.4
Purchases, issuances and settlements		(16.2)		(36.9)		-		20.7		-
Fair value as of June 30, 2008	$	(277.0)	$	(244.9)	$	40.9	$	(74.6)	$	1.6
Period change in unrealized losses included in Net income relating to items held as of June 30, 2008	$	(1.5)	$	-	$	-	$	(1.5)	$	-

⁽¹⁾

Realized and unrealized gains and losses on derivatives included in Net income relate to the remaining Select Energy wholesale marketing contracts and are reported in Fuel, purchased and net interchange power on the accompanying unaudited condensed consolidated statements of income.

⁽²⁾

Amounts as of January 1, 2008 reflect fair values after initial adoption of SFAS No. 157. As a result of implementing SFAS No. 157, the Company recorded an increase to derivative liabilities and a pre-tax charge of $6.1 million as of January 1, 2008 related to NU Enterprises' remaining derivative contracts. The Company also recorded changes in fair value of CL&P's CfD and IPP contracts, resulting in increases to CL&P's Derivative liabilities of approximately $590 million, with an offset to Regulatory assets and a decrease to CL&P's Derivative assets of approximately $30 million with an offset to Regulatory liabilities.

PENSION BENEFITS AND POSTRETIREMENT BENEFITS OTHER THAN PENSIONS (All Companies)

Northeast Utilities Service Company (NUSCO), a subsidiary of NU, sponsors a single uniform noncontributory defined benefit retirement plan (Pension Plan), which is subject to the provisions of the Employee Retirement Income Security Act (ERISA). The Pension Plan covers non-bargaining unit employees (and bargaining unit employees, as negotiated) of NU and its subsidiaries hired before 2006 (or as negotiated, for bargaining unit employees). On behalf of its retirees, NUSCO also sponsors plans that provide certain retiree health care benefits, primarily medical and dental, and life insurance benefits through a post-retirement benefits other than pension plan (PBOP Plan). In addition, NU maintains a Supplemental Executive Retirement Plan (SERP), which provides benefits to eligible participants who are officers of NU or its subsidiaries. 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, 2009 and 2008 are as follows:


	For the Three Months Ended June 30,
NU Consolidated	Pension Benefits				PBOP Benefits				SERP Benefits
(Millions of Dollars)	2009		2008		2009		2008		2009		2008
Service cost	$	11.3	$	11.1	$	1.8	$	1.8	$	0.2	$	0.2
Interest cost		38.3		35.9		7.2		7.0		0.6		0.5
Expected return on plan assets		(47.3)		(50.0)		(5.3)		(5.3)		-		-
Net transition obligation cost		6.8		-		2.4		2.9		-		-
Prior service cost/(credit)		2.4		2.5		-		(0.1)		-		-
Actuarial loss		(1.6)		1.1		3.2		2.7		0.1		0.1
Total - net periodic expense	$	9.9	$	0.6	$	9.3	$	9.0	$	0.9	$	0.8

CL&P - net periodic (income)/expense	$	(1.4)	$	(5.3)	$	3.8	$	3.9	$	0.1	$	0.1
PSNH - net periodic expense	$	5.8	$	4.5	$	1.7	$	1.8	$	0.1	$	0.1
WMECO - net periodic (income)/expense	$	(0.7)	$	(1.5)	$	0.7	$	0.7		*		*


	For the Six Months Ended June 30,
NU Consolidated	Pension Benefits				PBOP Benefits				SERP Benefits
(Millions of Dollars)	2009		2008		2009		2008		2009		2008
Service cost	$	22.5	$	21.8	$	3.6	$	3.6	$	0.4	$	0.3
Interest cost		76.8		72.1		14.5		14.1		1.1		1.0
Expected return on plan assets		(94.7)		(100.1)		(10.4)		(10.5)		-		-
Net transition obligation cost		6.9		0.1		5.2		5.8		-		-
Prior service cost/(credit)		4.9		4.9		-		(0.2)		0.1		0.1
Actuarial loss		3.5		2.5		5.7		5.3		0.2		0.1
Total - net periodic expense	$	19.9	$	1.3	$	18.6	$	18.1	$	1.8	$	1.5

CL&P - net periodic (income)/expense	$	(2.8)	$	(10.7)	$	7.8	$	7.9	$	0.2	$	0.2
PSNH - net periodic expense	$	11.6	$	9.0	$	3.5	$	3.5	$	0.1	$	0.1
WMECO - net periodic (income)/expense	$	(1.4)	$	(3.0)	$	1.4	$	1.4		*		*

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

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


	For the Three Months Ended June 30,
	CL&P				PSNH				WMECO
(Millions of Dollars)	2009		2008		2009		2008		2009		2008
Pension Benefits	$	3.0	$	1.9	$	0.7	$	0.4	$	0.4	$	0.4
PBOP Benefits		2.0		1.7		0.5		0.4		0.3		0.3
SERP Benefits		0.5		0.4		0.1		0.1		0.1		*


	For the Six Months Ended June 30,
	CL&P				PSNH				WMECO
(Millions of Dollars)	2009		2008		2009		2008		2009		2008
Pension Benefits	$	6.7	$	4.0	$	1.5	$	0.8	$	1.0	$	0.7
PBOP Benefits		3.7		3.4		0.9		0.7		0.6		0.5
SERP Benefits		0.9		0.8		0.2		0.2		0.1		*

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

A portion of the pension amounts is capitalized related to current employees who are working on capital projects. Amounts capitalized for NU Consolidated, 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)	2009		2008		2009		2008
NU Consolidated	$	1.5	$	1.3	$	3.1	$	2.7
CL&P		(0.1)		(2.2)		(0.1)		(4.4)
PSNH		1.5		1.2		2.9		2.3
WMECO		(0.2)		(0.5)		(0.3)		(1.1)

The amounts for the three and six months ended June 30, 2009 and 2008 for CL&P and WMECO offset capital costs, as pension income was recorded.

COMMITMENTS AND CONTINGENCIES

Regulatory Developments and Rate Matters (CL&P, PSNH, WMECO)

Connecticut:

C2 Prudency Audit: Pursuant to the decision in CL&P's 2007 rate case, the Connecticut Department of Public Utility Control (DPUC) has hired a consulting firm to perform a prudency audit of certain costs incurred in the implementation of a new customer service system (C2) at CL&P. The audit began on December 1, 2008 and is near completion. The DPUC intends to open a docket to review the findings of the audit after completion. Management continues to believe that its C2 expenses were prudent and will be recovered in rates. Management does not expect the outcome of the DPUC's review of this audit to have a material adverse impact on CL&P's earnings, financial position or cash flows.

Environmental Matters (HWP)

Holyoke Water Power Company (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 manufactured gas plant (MGP) site, which it sold to Holyoke Gas and Electric (HG&E), a municipal electric utility, in 1902. HWP is at least partially responsible for this site, and has already conducted substantial investigative and remediation activities. HWP first established a reserve for this site in 1994. In the second quarter of 2009, a pre-tax charge of $1.1 million was recorded to reflect the estimated cost of additional tar delineation and site characterization studies that are considered to be probable and estimable as of June 30, 2009. The cumulative expense recorded to this reserve through June 30, 2009 was approximately $17 million, of which $14.5 million had been spent, leaving approximately $2.5 million in the reserve as of June 30, 2009.

The Massachusetts Department of Environmental Protection (MA DEP) issued a letter on April 3, 2008 to HWP and HG&E, which share responsibility for the site, providing conditional authorization for additional investigatory and risk characterization activities and providing detailed comments on HWP's 2007 reports and proposals for further investigations. MA DEP also indicated that further removal of tar in certain areas was necessary prior to commencing many of the additional studies and evaluation. This letter represents guidance from the MA DEP, rather than mandates. HWP has developed and implemented site characterization studies to further delineate tar deposits in conformity with MA DEP's guidance letter, including estimated costs and schedules. These matters are subject to ongoing discussions with MA DEP and HG&E and may change from time to time.

At this time, management believes that the $2.5 million remaining in the reserve is at the low end of a range of probable and estimable costs of approximately $2.5 million to $3.2 million and will be sufficient for HWP to conduct the additional tar delineation and site characterization studies, evaluate its approach to this matter and conduct certain soft tar remediation. The additional studies are expected to occur throughout 2009.

There are many outcomes that could affect management's estimates and require an increase to the reserve, or range of costs, and a reserve increase would be reflected as a charge to pre-tax Net income. However, management cannot reasonably estimate the range of additional investigation and remediation costs because they will depend on, among other things, the level and extent of the remaining tar that may be required to be remediated, the extent of HWP's responsibility and the related scope and timing, all of which are difficult to estimate because of a number of uncertainties at this time. Further developments may require a material increase to this reserve.

HWP's share of the remediation costs related to this site is not recoverable from customers.

Guarantees and Indemnifications (All Companies)

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 sales of Select Energy Services, Inc. (SESI), NU Enterprises' retail marketing business and its competitive generation business. As of June 30, 2009, the aggregate fair value amount recorded for these guarantees and indemnifications totaled $0.3 million and is included in Current liabilities - Other on the accompanying unaudited condensed consolidated balance sheets. The following table summarizes NU and its subsidiaries' maximum exposure as of June 30, 2009, in accordance with FIN 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others," and expiration dates:


Company	Description	Maximum Exposure (in millions)		Expiration Date(s)
On behalf of external parties:

Ameresco Select, Inc.	General indemnifications in connection with the sale of SESI including completeness and accuracy of information provided, compliance with laws, and various claims	Not Specified	(1)	None

	Specific indemnifications in connection with the sale of SESI for estimated costs to complete or modify specific projects (2)	Not Specified	(1)	Through project completion

	Indemnifications to lenders for payment of shortfalls in the event of early termination of government contracts (3)	$1.0		2017-2018

	Surety bonds covering certain projects	$0.4		Through project completion

Hess Corporation	General indemnifications in connection with the sale of the retail marketing business including compliance with laws, completeness and accuracy of information provided and various claims	Not Specified	(1)	None

Energy Capital Partners	General indemnifications in connection with the sale of Northeast Generation Company (NGC) and the generating assets of Mt. Tom including compliance with tax and environmental laws, and various claims	Not Specified	(1)	November 2009

On behalf of subsidiaries:

CL&P	Surety bonds	$2.6		September 2009 -April 2010 (4)

PSNH	Surety bonds	$3.9		July 2009 - May 2010 (4)
	Letters of credit	$85.0		2009-2010

WMECO	Surety bonds	$4.5		May-June 2010 (4)

HWP	Surety bonds	$1.0		May 2010 (4)

NAESCO (North Atlantic Energy Service Corporation)	Surety bonds	$1.6		May 2010 (4)

Rocky River Realty Company	Lease payments for real estate	$10.9		2024

NUSCO	Lease payments for fleet of vehicles	$6.7		None
	Surety bonds	$0.7		May 2010 (4)
	Lease payments for real estate	$2.1		2019

E.S. Boulos Company (Boulos)	Surety bonds covering ongoing projects	$26.6		Through project completion

Northeast Generation Services Company (NGS)	Performance guarantee and insurance bonds	$20.4	(5)	2020 (5)


Select Energy	Performance guarantees for wholesale contracts	$17.2	(6)	2013
	Letters of credit	$2.0		January 2010

Other - CYAPC	Surety bonds	$0.3		April 2010 (4)

(1)

There is no specified maximum exposure included in the related sale agreements.

(2)

The fair value for amounts recorded for these indemnifications was $0.2 million as of June 30, 2009.

(3)

The fair value for amounts recorded for these indemnifications was $0.1 million as of June 30, 2009.

(4)

Surety bond expiration dates reflect bond termination dates (which may be renewed or extended) for specified term bonds and/or bill-to dates for bonds with no fixed term.

(5)

Included in the maximum exposure is $19.2 million related to a performance guarantee of NGS obligations for which there is no specified maximum exposure in the agreement. The maximum exposure is calculated as of June 30, 2009 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. The remaining $1.2 million of maximum exposure relates to insurance bonds with no expiration date that are billed annually on their anniversary date.

(6)

Maximum exposure is as of June 30, 2009; however, exposures vary with underlying commodity prices and for certain contracts are essentially unlimited.

CL&P, PSNH and WMECO have no guarantees of the performance of third parties.

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

COMPREHENSIVE INCOME (NU, CL&P, PSNH, WMECO)

Total comprehensive income, which includes all comprehensive income/(loss) items, net of tax and by category, for the three and six months ended June 30, 2009 and 2008 is as follows:


	Three Months Ended June 30,				Six Months Ended June 30,
	2009		2008		2009		2008
(Millions of Dollars)	NU Consolidated		NU Consolidated		NU Consolidated		NU Consolidated
Net income	$	84.2	$	59.2	$	183.3	$	119.0
Comprehensive income/(loss) items:
Qualified cash flow hedging instruments		-		12.9		0.1		(5.8)
Change in unrealized (losses)/gains on other securities ⁽¹⁾		(1.0)		(0.1)		(1.1)		(0.8)
Pension, SERP and PBOP benefits		(0.9)		0.9		(0.7)		2.1
Net change in comprehensive income/(loss) items		(1.9)		13.7		(1.7)		(4.5)
Total comprehensive income		82.3		72.9		181.6		114.5
Comprehensive income attributable to noncontrolling interests		(1.4)		(1.4)		(2.8)		(2.8)
Comprehensive income attributable to controlling interests	$	80.9	$	71.5	$	178.8	$	111.7


	Three Months Ended June 30, 2009						Three Months Ended June 30, 2008
	CL&P		PSNH		WMECO		CL&P		PSNH		WMECO
Net income	$	58.4	$	16.6	$	5.8	$	46.3	$	13.7	$	3.3
Comprehensive income/(loss) items:
Qualified cash flow hedging instruments		0.1		-		-		4.9		1.7		-
Change in unrealized (losses)/gains on other securities ⁽¹⁾		-		(0.1)		(0.1)		-		-		(0.2)
Pension, SERP and PBOP benefits		-		-		-		-		-		-
Net change in comprehensive income/(loss) items		0.1		(0.1)		(0.1)		4.9		1.7		(0.2)
Total comprehensive income	$	58.5	$	16.5	$	5.7	$	51.2	$	15.4	$	3.1


	Six Months Ended June 30, 2009						Six Months Ended June 30, 2008
	CL&P		PSNH		WMECO		CL&P		PSNH		WMECO
Net income	$	111.5	$	34.1	$	12.0	$	92.3	$	30.4	$	9.6
Comprehensive income/(loss) items:
Qualified cash flow hedging instruments		0.2		-		-		(3.6)		(1.5)		-
Change in unrealized (losses)/gains on other securities⁽¹⁾		-		-		(0.2)		-		-		(0.1)
Pension, SERP and PBOP benefits		-		-		-		-		-		-
Net change in comprehensive income/(loss) items		0.2		-		(0.2)		(3.6)		(1.5)		(0.1)
Total comprehensive income	$	111.7	$	34.1	$	11.8	$	88.7	$	28.9	$	9.5

⁽¹⁾

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

Fair value adjustments included in Accumulated other comprehensive income/(loss) for qualified cash flow hedging instruments are as follows:


NU Consolidated (Millions of Dollars, Net of Tax)	For the Six Months Ended June 30, 2009		For the Twelve Months Ended December 31, 2008
Balance at beginning of period	$	(4.6)	$	2.3
Hedged transactions recognized into Net income		0.1		0.4
Change in fair value of interest rate swap agreements		-		(7.0)
Cash flow transactions entered into for period		-		(0.3)
Net change associated with hedging transactions		0.1		(6.9)
Total fair value adjustments included in Accumulated other comprehensive loss	$	(4.5)	$	(4.6)


	Six Months Ended June 30, 2009						Twelve Months Ended December 31, 2008
(Millions of Dollars, Net of Tax)	CL&P		PSNH		WMECO		CL&P		PSNH		WMECO
Balance at beginning of period	$	(3.6)	$	(0.8)	$	0.1	$	(0.3)	$	0.6	$	0.2
Hedged transactions recognized into Net income		0.2		-		-		0.4		0.2		(0.1)
Change in fair value of interest rate swap agreements		-		-		-		(3.7)		(1.4)		-
Cash flow transactions entered into for period		-		-		-		-		(0.2)		-
Net change associated with hedging transactions		0.2		-		-		(3.3)		(1.4)		(0.1)
Total fair value adjustments included in Accumulated other comprehensive (loss)/income	$	(3.4)	$	(0.8)	$	0.1	$	(3.6)	$	(0.8)	$	0.1

Hedged transactions recognized into Net income in the tables above represent amounts that were reclassified from Accumulated other comprehensive income/(loss) into Net income in connection with the consummation of interest rate swap agreements and the amortization of existing interest rate hedges.

There were no forward starting interest rate swaps entered into for the three and six months ended June 30, 2009. For NU consolidated, it is estimated that a charge of $0.2 million will be reclassified from Accumulated other comprehensive income/(loss) as a decrease to Net income over the next 12 months as a result of amortization of the 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, 2009, 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 consolidated.

EARNINGS PER SHARE (NU)

Earnings per share (EPS) is computed based upon the monthly weighted average number of common shares outstanding, excluding unallocated Employee Stock Ownership Plan (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 stock. 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 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. There were no antidilutive share awards outstanding for the three- and six-month periods ended June 30, 2008. The weighted average common shares outstanding as of June 30, 2009 include the impact of the issuance of approximately 19 million common shares on March 20, 2009.

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


	For the Three Months Ended June 30,				For the Six Months Ended June 30,
(Millions of Dollars, Except for Share Information)	2009		2008		2009		2008
Net income attributable to controlling interests	$	82.9	$	57.8	$	180.5	$	116.2
Basic common shares outstanding (average)		175,175,936		155,476,492		168,758,206		155,381,302
Dilutive effect		499,452		418,856		542,071		427,179
Fully diluted common shares outstanding (average)		175,675,388		155,895,348		169,300,277		155,808,481
Basic and Fully Diluted EPS	$	0.47	$	0.37	$	1.07	$	0.75

Restricted share units (RSUs) are included in basic common shares outstanding when RSUs have vested and common shares are issued. The dilutive effect of outstanding RSUs for which common shares have not been issued is calculated using the treasury stock method. Assumed proceeds of RSUs 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 RSUs (the difference between the market value of RSUs 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 and the grant price).

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

LONG-TERM DEBT (CL&P, Yankee Gas)

On February 13, 2009, CL&P issued $250 million of Series A first mortgage bonds with a coupon rate of 5.5 percent and a maturity date of February 1, 2019. The proceeds from this issuance were used to repay short-term debt and to fund CL&P's ongoing capital investment programs. The indenture under which the bonds were issued requires CL&P to comply with certain covenants as are customarily included in such indenture. CL&P is in compliance with these covenants as of June 30, 2009.

On April 2, 2009, CL&P completed the remarketing and reissuance of $62 million of pollution control revenue bonds (PCRBs) it had elected to acquire in October 2008. The PCRBs, which mature on May 1, 2031, carry a coupon of 5.25 percent during the current fixed-rate period and are subject to a mandatory tender for purchase on April 1, 2010, after which CL&P can remarket the bonds.

On April 1, 2009, through borrowings from the NU Money Pool, Yankee Gas retired $50 million of first mortgage bonds carrying a coupon of 6.2 percent that were issued in January 1999.

FAIR VALUE OF FINANCIAL INSTRUMENTS (All Companies)

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 rate reduction bonds 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, 2009
	NU Consolidated
(Millions of Dollars)	Carrying Amount		Fair Value
Preferred stock not subject to mandatory redemption	$	116.2	$	83.0
Long-term debt -
First mortgage bonds		2,507.7		2,535.9
Other long-term debt		1,893.4		1,870.3
Rate reduction bonds		566.2		613.0


	As of June 30, 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	$	83.0	$	-	$	-	$	-	$	-
Long-term debt -
First mortgage bonds		1,919.9		1,942.5		280.0		282.7		-		-
Other long-term debt		667.2		666.5		407.3		395.8		305.9		295.8
Rate reduction bonds		288.3		314.2		212.0		228.2		65.9		70.7

Consolidated other long-term debt includes $300.4 million of fees and interest due for spent nuclear fuel disposal costs as of June 30, 2009. CL&P and WMECO's portions of this obligation is $243.3 million and $57.1 million, respectively.

Derivative Instruments: NU and its subsidiaries hold 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 3, "Fair Value Measurements," and Note 10, "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 $8.8 million as of June 30, 2009 and is included in Deferred debits and other assets-Other on the accompanying unaudited condensed consolidated balance sheets. The fair value of this receivable was $10.8 million as of June 30, 2009 and was determined based on discounted cash flows.

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

10.

MARKETABLE SECURITIES (NU, WMECO)

The Company elected the fair value option for exchange traded mutual funds purchased in the second quarter in the supplemental benefit trust in order to reflect in Net income the economic effect of changes in fair value of all newly purchased equity securities. These equity securities, classified as Level 1 in the fair value hierarchy, totaled $27.2 million as of June 30, 2009. Gains on these securities of $0.5 million were recorded in Other income, net on the accompanying unaudited condensed consolidated statements of income for the three and six months ended June 30, 2009. All other marketable securities are accounted for as available-for-sale.

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


	As of June 30, 2009
(Millions of Dollars)	Amortized Cost		Pre-Tax Gross Unrealized Gains ⁽¹⁾		Pre-Tax Gross Unrealized Losses ⁽¹⁾		Fair Value
Supplemental benefit trust
U.S. government issued debt securities (Agency and Treasury)	$	14.6	$	0.4	$	(0.1)	$	14.9
Corporate debt securities		5.8		0.2		(0.2)		5.8
Asset backed debt securities		3.8		-		(0.2)		3.6
Other		5.0		0.2		-		5.2
Total supplemental benefit trust	$	29.2	$	0.8	$	(0.5)	$	29.5


WMECO spent nuclear fuel trust
U.S. government issued debt securities (Agency and Treasury)	$	17.0	$	-	$	-	$	17.0
Corporate debt securities		21.8		-		(0.2)		21.6
Asset backed debt securities		1.5		-		(0.3)		1.2
Municipal bonds		11.0		-		-		11.0
Other		5.5		-		-		5.5
Total WMECO spent nuclear fuel trust	$	56.8	$	-	$	(0.5)	$	56.3
Total NU Consolidated	$	86.0	$	0.8	$	(1.0)	$	85.8

⁽¹⁾

Unrealized gains and losses on debt securities for the supplemental benefit trust and WMECO spent nuclear fuel trust are recorded in Accumulated other comprehensive income/(loss) and Deferred debits and other assets - Other, respectively. For information related to the change in unrealized gains and losses for the supplemental benefit trust included in Accumulated other comprehensive income/(loss), see Note 6, "Comprehensive Income," to the unaudited condensed consolidated financial statements.

Unrealized Losses and Other-than-Temporary Impairment: Gross unrealized losses and fair values of debt securities that have been in a continuous unrealized loss position for less than 12 months and 12 months or greater are as follows:


	As of June 30, 2009
	Less than 12 Months				12 Months or Greater				Total
(Millions of Dollars)	Fair Value		Pre-Tax Gross Unrealized Losses		Fair Value		Pre-Tax Gross Unrealized Losses		Fair Value		Pre-Tax Gross Unrealized Losses
Supplemental benefit trust
U.S. government issued debt securities (Agency and Treasury)	$	4.5	$	(0.1)	$	-	$	-	$	4.5	$	(0.1)
Corporate debt securities		-		-		1.8		(0.2)		1.8		(0.2)
Asset backed debt securities		-		-		2.0		(0.2)		2.0		(0.2)
Total supplemental benefit trust	$	4.5	$	(0.1)	$	3.8	$	(0.4)	$	8.3	$	(0.5)


WMECO spent nuclear fuel trust
Corporate debt securities	$	13.8	$	(0.2)	$	-	$	-	$	13.8	$	(0.2)
Asset backed debt securities		0.5		(0.3)		-		-		0.5		(0.3)
Total WMECO spent nuclear fuel trust	$	14.3	$	(0.5)	$	-	$	-	$	14.3	$	(0.5)
Total NU Consolidated	$	18.8	$	(0.6)	$	3.8	$	(0.4)	$	22.6	$	(1.0)

As of June 30, 2009, there are no debt securities that the Company intends to sell or that management believes the Company will more likely than not be required to sell before recovery of amortized cost, there were no credit losses in the supplemental benefit trust, and credit losses of approximately $0.7 million were recorded in Deferred debits and other assets - Other in the WMECO spent nuclear fuel trust. Factors considered in determining whether a credit loss exists include the duration and severity of the impairment, adverse conditions specifically affecting the issuer, and the payment history, ratings and rating changes of the security. For asset backed securities, underlying collateral and expected future cash flows are also evaluated. The Company's corporate and asset-backed securities are rated above investment grade.

Contractual Maturities: As of June 30, 2009, the contractual maturities of available-for-sale debt securities are as follows:


		NU Consolidated			WMECO
(Millions of Dollars)		Amortized Cost		Estimated Fair Value		Amortized Cost		Estimated Fair Value
Less than one year	$	34.6	$	34.6	$	29.7	$	29.6
One to five years		20.6		20.7		15.0		15.0
Six to ten years		6.6		6.7		1.2		1.2
Greater than ten years		24.2		23.8		10.9		10.5
Total debt securities	$	86.0	$	85.8	$	56.8	$	56.3

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


	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 Consolidated	$	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 supplemental benefit trust and in Deferred debits and other assets - Other for the WMECO spent nuclear fuel trust. NU utilizes the specific identification basis method for the 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 $94.8 million and $147.7 million for the three and six months ended June 30, 2009, respectively, including $42.6 million and $78.3 million, respectively, for WMECO.

11.

SEGMENT INFORMATION (All Companies)

Presentation: NU is organized between the regulated companies and NU Enterprises businesses 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 business 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, including the electric distribution and transmission segments, as well as the gas distribution segment (Yankee Gas), represented approximately 99 percent of NU's total consolidated revenues for the three- and six-month periods ended June 30, 2009 and 2008. 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. PSNH's distribution segment includes generation activities. 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) NGS, 3) Boulos, 4) NGS Mechanical, and 5) NU Enterprises parent.

Other in the segment tables 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 Rocky River Realty Company and The Quinnehtuk Company (real estate subsidiaries), Mode 1 Communications, Inc., the results of the non-energy-related subsidiaries of Yankee Energy System, Inc. (Yankee Energy Services Company, Yankee Energy Financial Services Company and NorConn Properties, Inc.) and the remaining operations of HWP that were not exited as part of the sale of the competitive generation business and the sale of its transmission business to WMECO in December 2008.

NU's segment information for the three and six months ended June 30, 2009 and 2008 is as follows (certain amounts presented in the financial statements may differ from amounts presented in the segment schedules due to rounding):


	For the Three Months Ended June 30, 2009
	Regulated Companies
	Distribution (1)
(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, net of AFUDC		(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 (1)
(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, net of AFUDC		(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		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
Total assets	$	8,923.3	$	1,334.7	$	3,055.9	$	91.2	$	6,124.4	$	(5,401.9)	$	14,127.6
Cash flows for total investments in plant (2)	$	259.8	$	25.4	$	121.0	$	-	$	14.7	$	-	$	420.9


	For the Three Months Ended June 30, 2008
	Regulated Companies
	Distribution (1)
(Millions of Dollars)	Electric		Gas		Transmission		NU Enterprises		Other		Eliminations		Total
Operating revenues	$	1,098.7	$	113.0	$	101.4	$	30.0	$	100.2	$	(118.0)	$	1,325.3
Depreciation and amortization		(136.9)		(6.6)		(11.6)		(0.1)		(3.1)		0.2		(158.1)
Other operating expenses		(889.0)		(103.3)		(33.4)		(25.1)		(95.4)		117.1		(1,029.1)
Operating income		72.8		3.1		56.4		4.8		1.7		(0.7)		138.1
Interest expense, net of AFUDC		(41.6)		(4.9)		(11.8)		(1.3)		(9.1)		2.6		(66.1)
Interest income		1.0		-		1.6		0.2		2.3		(3.6)		1.5
Other income, net		1.6		-		7.2		-		36.4		(36.3)		8.9
Income tax (expense)/benefit		(6.3)		0.8		(17.7)		(1.5)		1.9		(0.4)		(23.2)
Net income/(loss)		27.5		(1.0)		35.7		2.2		33.2		(38.4)		59.2
Net income/(loss) attributable to noncontrolling interests		(0.9)		-		(0.5)		-		-		-		(1.4)
Net income/(loss) attributable to controlling interests	$	26.6	$	(1.0)	$	35.2	$	2.2	$	33.2	$	(38.4)	$	57.8


	For the Six Months Ended June 30, 2008
	Regulated Companies
	Distribution (1)
(Millions of Dollars)	Electric		Gas		Transmission		NU Enterprises		Other		Eliminations		Total
Operating revenues	$	2,296.8	$	312.6	$	196.3	$	63.9	$	200.1	$	(224.4)	$	2,845.3
Depreciation and amortization		(265.8)		(13.0)		(22.3)		(0.3)		(7.1)		0.4		(308.1)
Other operating expenses		(1,870.7)		(261.6)		(65.1)		(54.3)		(236.1)		221.0		(2,266.8)
Operating income/(loss)		160.3		38.0		108.9		9.3		(43.1)		(3.0)		270.4
Interest expense, net of AFUDC		(83.2)		(10.1)		(22.2)		(3.0)		(15.0)		4.8		(128.7)
Interest income		1.9		-		2.0		0.6		4.0		(5.8)		2.7
Other income, net		8.4		0.1		12.6		-		110.4		(110.3)		21.2
Income tax (expense)/benefit		(23.8)		(10.4)		(32.6)		(2.8)		24.0		(1.0)		(46.6)
Net income		63.6		17.6		68.7		4.1		80.3		(115.3)		119.0
Net income attributable to noncontrolling interests		(1.8)		-		(1.0)		-		-		-		(2.8)
Net income attributable to controlling interests	$	61.8	$	17.6	$	67.7	$	4.1	$	80.3	$	(115.3)	$	116.2
Cash flows for total investments in plant (2)	$	205.5	$	23.4	$	383.6	$	-	$	12.6	$	-	$	625.1

(1)

Includes PSNH's generation activities.

(2)

Cash flows for total investments in plant included in the segment information above 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 information related to the distribution and transmission segments for CL&P, PSNH and WMECO for the three and six months ended June 30, 2009 and 2008 is as follows:


	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, net of AFUDC		(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, net of AFUDC		(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
Total assets	$	5,854.6	$	2,470.1	$	8,324.7
Cash flows for total investments in plant (2)	$	149.0	$	77.9	$	226.9


	CL&P - For the Three Months Ended June 30, 2008
(Millions of Dollars)	Distribution		Transmission		Total
Operating revenues	$	741.7	$	80.2	$	821.9
Depreciation and amortization		(120.8)		(9.2)		(130.0)
Other operating expenses		(579.4)		(22.9)		(602.3)
Operating income		41.5		48.1		89.6
Interest expense, net of AFUDC		(26.3)		(10.1)		(36.4)
Interest income		0.7		1.0		1.7
Other income, net		1.5		6.4		7.9
Income tax expense		(1.7)		(14.9)		(16.6)
Net income	$	15.7	$	30.5	$	46.2


	CL&P - For the Six Months Ended June 30, 2008
(Millions of Dollars)	Distribution		Transmission		Total
Operating revenues	$	1,553.8	$	153.6	$	1,707.4
Depreciation and amortization		(208.8)		(17.6)		(226.4)
Other operating expenses		(1,255.0)		(46.6)		(1,301.6)
Operating income		90.0		89.4		179.4
Interest expense, net of AFUDC		(52.6)		(18.8)		(71.4)
Interest income		1.3		1.4		2.7
Other income, net		7.9		11.2		19.1
Income tax expense		(11.1)		(26.4)		(37.5)
Net income	$	35.5	$	56.8	$	92.3
Cash flows for total investments in plant (2)	$	119.4	$	322.6	$	442.0


	PSNH - For the Three Months Ended June 30, 2009
(Millions of Dollars)	Distribution (1)		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, net of AFUDC		(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 (1)		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, net of AFUDC		(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
Total assets	$	2,206.5	$	406.8	$	2,613.3
Cash flows for total investments in plant (2)	$	89.2	$	23.2	$	112.4


	PSNH - For the Three Months Ended June 30, 2008
(Millions of Dollars)	Distribution (1)		Transmission		Total
Operating revenues	$	259.2	$	14.8	$	274.0
Depreciation and amortization		(4.5)		(1.8)		(6.3)
Other operating expenses		(230.7)		(7.0)		(237.7)
Operating income		24.0		6.0		30.0
Interest expense, net of AFUDC		(10.9)		(1.2)		(12.1)
Interest income		0.2		0.4		0.6
Other income, net		0.2		0.5		0.7
Income tax expense		(3.4)		(2.1)		(5.5)
Net income	$	10.1	$	3.6	$	13.7


	PSNH - For the Six Months Ended June 30, 2008
(Millions of Dollars)	Distribution (1)		Transmission		Total
Operating revenues	$	535.9	$	29.9	$	565.8
Depreciation and amortization		(34.7)		(3.4)		(38.1)
Other operating expenses		(450.5)		(12.3)		(462.8)
Operating income		50.7		14.2		64.9
Interest expense, net of AFUDC		(21.8)		(2.3)		(24.1)
Interest income		0.3		0.4		0.7
Other income, net		0.6		1.3		1.9
Income tax expense		(8.2)		(4.8)		(13.0)
Net income	$	21.6	$	8.8	$	30.4
Cash flows for total investments in plant (2)	$	71.6	$	47.6	$	119.2


	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, net of AFUDC		(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, net of AFUDC		(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
Total assets	$	873.4	$	186.0	$	1,059.4
Cash flows for total investments in plant (2)	$	21.6	$	19.9	$	41.5


	WMECO - For the Three Months Ended June 30, 2008
(Millions of Dollars)	Distribution		Transmission		Total
Operating revenues	$	97.8	$	6.4	$	104.2
Depreciation and amortization		(11.6)		(0.7)		(12.3)
Other operating expenses		(79.0)		(3.3)		(82.3)
Operating income		7.2		2.4		9.6
Interest expense, net of AFUDC		(4.4)		(0.4)		(4.8)
Interest income		0.2		0.2		0.4
Other income, net		-		0.1		0.1
Income tax expense		(1.3)		(0.7)		(2.0)
Net income	$	1.7	$	1.6	$	3.3


	WMECO - For the Six Months Ended June 30, 2008
(Millions of Dollars)	Distribution		Transmission		Total
Operating revenues	$	207.3	$	12.7	$	220.0
Depreciation and amortization		(22.4)		(1.3)		(23.7)
Other operating expenses		(165.4)		(6.1)		(171.5)
Operating income		19.5		5.3		24.8
Interest expense, net of AFUDC		(8.8)		(1.2)		(10.0)
Interest income		0.3		0.3		0.6
Other income, net		-		0.2		0.2
Income tax expense		(4.5)		(1.5)		(6.0)
Net income	$	6.5	$	3.1	$	9.6
Cash flows for total investments in plant (2)	$	14.6	$	13.3	$	27.9

(1)

Includes PSNH's generation activities.

(2)

12.

COMMON SHAREHOLDERS' EQUITY AND NONCONTROLLING INTEREST (NU)

A summary of the changes in common shareholders' equity and noncontrolling interest of NU for the three and six months ended June 30, 2009 and 2008 is as follows:


	For the Three Months Ended June 30,
	2009				2008
(Millions of Dollars)	Common Shareholders' Equity		Noncontrolling Interest		Common Shareholders' Equity		Noncontrolling Interest
Balance, beginning of period	$	3,456.1	$	116.2	$	2,926.8	$	116.2
Net income		84.2		-		59.2		-
Dividends on common shares		(41.8)		-		(64.5)		-
Dividends on preferred shares of CL&P		(1.4)		(1.4)		(1.4)		(1.4)
Issuance of common shares		0.1		-		0.5		-
Other transactions, net		6.5		-		5.2		-
Net income attributable to noncontrolling interests		-		1.4		-		1.4
Other comprehensive (loss)/income (Note 6)		(1.9)		-		13.7		-
Balance, end of period	$	3,501.8	$	116.2	$	2,939.5	$	116.2


	For the Six Months Ended June 30,
	2009				2008
(Millions of Dollars)	Common Shareholders' Equity		Noncontrolling Interest		Common Shareholders' Equity		Noncontrolling Interest
Balance, beginning of period	$	3,020.3	$	116.2	$	2,913.8	$	116.2
Net income		183.3		-		119.0		-
Dividends on common shares		(79.1)		-		(95.7)		-
Dividends on preferred shares of CL&P		(2.8)		(2.8)		(2.8)		(2.8)
Issuance of common shares		387.4		-		4.6		-
Capital stock expenses, net		(12.5)		-		-		-
Other transactions, net		6.9		-		5.1		-
Net income attributable to noncontrolling interests		-		2.8		-		2.8
Other comprehensive loss (Note 6)		(1.7)		-		(4.5)		-
Balance, end of period	$	3,501.8	$	116.2	$	2,939.5	$	116.2

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, 2009, and the related condensed consolidated statements of income for the three-month and six-month periods ended June 30, 2009 and 2008, and of cash flows for the six-month periods ended June 30, 2009 and 2008. 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, 2008, and the related consolidated statements of income, comprehensive income, shareholders' equity, and cash flows for the year then ended prior to retrospective adjustment for the adoption of Financial Accounting Standards Board ("FASB") Statement No. 160, Noncontrolling Interests in Consolidated Financial Statements an amendment of ARB No. 51, (not presented herein); and in our report dated February 27, 2009 (which report included an explanatory paragraph related to the adoption of FASB Statement No. 157, Fair Value Measurements, as of January 1, 2008), we expressed an unqualified opinion on those consolidated financial statements. We also audited the adjustments described in Note 1 that were applied to retrospectively adjust the December 31, 2008 consolidated balance sheet of Northeast Utilities and subsidiaries (not presented herein). In our opinion, such adjustments are appropriate and have been properly applied to the previously issued consolidated balance sheet in deriving the accompanying retrospectively adjusted condensed consolidated balance sheet as of December 31, 2008.


/s/	Deloitte & Touche LLP
	Deloitte & Touche LLP

Hartford, Connecticut

August 7, 2009

This Page Intentionally Left Blank

THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES


THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
	June 30,	December 31,
(Thousands of Dollars)	2009	2008

ASSETS

Current Assets:
Cash	$ 7,189	$ -
Receivables, less provision for uncollectible
accounts of $24,367 in 2009 and $23,956 in 2008	341,046	416,304
Accounts receivable from affiliated companies	1,975	11,215
Notes receivable from affiliated companies	162,488	-
Unbilled revenues	105,316	127,844
Materials and supplies	63,607	70,676
Derivative assets - current	11,189	30,478
Prepayments and other	8,545	15,685
	701,355	672,202

Property, Plant and Equipment:
Electric utility	6,337,026	6,244,705
Less: Accumulated depreciation	1,372,518	1,346,062
	4,964,508	4,898,643
Construction work in progress	241,795	190,481
	5,206,303	5,089,124

Deferred Debits and Other Assets:
Regulatory assets	2,100,759	2,274,088
Derivative assets - long-term	216,564	215,288
Other	99,716	85,416
	2,417,039	2,574,792












Total Assets	$ 8,324,697	$ 8,336,118



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


THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
	June 30,	December 31,
(Thousands of Dollars)	2009	2008

LIABILITIES AND CAPITALIZATION

Current Liabilities:
Notes payable to banks	$ 113,973	$ 187,973
Notes payable to affiliated companies	-	102,725
Long-term debt - current portion	62,000	-
Accounts payable	234,774	353,584
Accounts payable to affiliated companies	37,277	57,053
Accrued taxes	47,410	24,839
Accrued interest	47,740	37,567
Derivative liabilities - current	10,344	8,873
Other	84,920	92,444
	638,438	865,058

Rate Reduction Bonds	288,320	378,195

Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	866,696	811,405
Accumulated deferred investment tax credits	17,580	18,805
Deferred contractual obligations	123,513	132,687
Regulatory liabilities	334,517	363,547
Derivative liabilities - long-term	787,016	848,106
Accrued pension	76,734	89,254
Accrued postretirement benefits	92,560	98,587
Other	205,924	215,620
	2,504,540	2,578,011
Capitalization:
Long-Term Debt	2,519,975	2,270,414

Preferred Stock Not Subject to Mandatory Redemption	116,200	116,200
Common Stockholder's Equity:
Common stock, $10 par value - authorized
24,500,000 shares; 6,035,205 shares outstanding
in 2009 and 2008	60,352	60,352
Capital surplus, paid in	1,531,135	1,454,198
Retained earnings	669,134	617,276
Accumulated other comprehensive loss	(3,397)	(3,586)
Common Stockholder's Equity	2,257,224	2,128,240
Total Capitalization	4,893,399	4,514,854




Total Liabilities and Capitalization	$ 8,324,697	$ 8,336,118


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


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)	2009	2008	2009	2008


Operating Revenues	$ 784,937	$ 821,875	$ 1,739,440	$ 1,707,374

Operating Expenses:
Operation -
Fuel, purchased and net interchange power	383,153	398,085	897,539	891,893
Other	131,174	132,329	270,585	261,372
Maintenance	27,783	33,154	54,898	62,434
Depreciation	47,048	39,855	93,481	78,724
Amortization of regulatory assets, net	3,633	56,404	16,640	75,988
Amortization of rate reduction bonds	36,192	33,649	76,749	71,680
Taxes other than income taxes	37,899	38,764	96,088	85,834
Total operating expenses	666,882	732,240	1,505,980	1,527,925
Operating Income	118,055	89,635	233,460	179,449

Interest Expense:
Interest on long-term debt	34,286	25,392	65,972	48,999
Interest on rate reduction bonds	5,088	7,595	10,887	15,811
Other interest (Note 1I)	(1,627)	3,404	(1,418)	6,561
Interest expense, net	37,747	36,391	75,441	71,371
Other Income, Net	8,170	9,575	10,878	21,698
Income Before Income Tax Expense	88,478	62,819	168,897	129,776
Income Tax Expense	30,076	16,564	57,360	37,453
Net Income	$ 58,402	$ 46,255	$ 111,537	$ 92,323













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


THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
	Six Months Ended June 30,
(Thousands of Dollars)	2009	2008

Operating Activities:
Net income	$ 111,537	$ 92,323
Adjustments to reconcile to net cash flows
provided by operating activities:
Bad debt expense	4,927	3,042
Depreciation	93,481	78,724
Deferred income taxes	43,664	49,945
Allowance for equity funds used during construction	(1,615)	(12,364)
Pension income and PBOP expense, net of capitalized portion, and contributions	(5,118)	(10,201)
Regulatory overrecoveries/(refunds and underrecoveries)	11,152	(133,161)
Amortization of regulatory assets, net	16,640	75,988
Amortization of rate reduction bonds	76,749	71,680
Deferred contractual obligations	(9,925)	(11,250)
Net settlement of cash flow hedge instruments	-	(3,890)
Other	(377)	(2,714)
Changes in current assets and liabilities:
Receivables and unbilled revenues, net	90,947	(18,814)
Investments in securitizable assets	-	(25,787)
Materials and supplies	(4,232)	(10,569)
Other current assets	7,148	7,794
Accounts payable	(106,597)	(21,439)
Taxes receivable/accrued	15,133	47,209
Counterparty deposits and margin special deposits	(1,001)	24,825
Other current liabilities	(5,497)	6,586
Net cash flows provided by operating activities	337,016	207,927

Investing Activities:
Investments in property and plant	(226,892)	(442,014)
Increase in NU Money Pool lending	(162,488)	-
Rate reduction bond escrow and other deposits	(1,785)	5,643
Other investing activities	1,503	592
Net cash flows used in investing activities	(389,662)	(435,779)

Financing Activities:
Cash dividends on common stock	(56,925)	(53,231)
Cash dividends on preferred stock	(2,779)	(2,779)
Decrease in short-term debt	(74,000)	-
(Decrease)/increase in NU Money Pool borrowings	(102,725)	13,500
Capital contributions from NU parent	77,000	57,058
Issuance of long-term debt	312,000	300,000
Retirements of rate reduction bonds	(89,875)	(83,940)
Other financing activities	(2,861)	(3,277)
Net cash flows provided by financing activities	59,835	227,331
Net increase/(decrease) in cash	7,189	(521)
Cash - beginning of period	-	538
Cash - end of period	$ 7,189	$ 17

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

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PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE


PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
	June 30,	December 31,
(Thousands of Dollars)	2009	2008

ASSETS

Current Assets:
Cash	$ 2,100	$ 195
Receivables, less provision for uncollectible
accounts of $4,890 in 2009 and $4,165 in 2008	94,219	108,857
Notes receivable from affiliated companies	9,000	53,800
Accounts receivable from affiliated companies	520	264
Unbilled revenues	46,745	41,449
Taxes receivable	14,928	8,809
Fuel, materials and supplies	114,259	113,121
Accumulated deferred income taxes - current	24,899	27,345
Prepayments and other	14,513	16,223
	321,183	370,063

Property, Plant and Equipment:
Electric utility	2,321,856	2,238,515
Less: Accumulated depreciation	787,362	771,282
	1,534,494	1,467,233
Construction work in progress	141,746	113,752
	1,676,240	1,580,985

Deferred Debits and Other Assets:
Regulatory assets	512,390	549,934
Other	103,439	127,851
	615,829	677,785








Total Assets	$ 2,613,252	$ 2,628,833

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


PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
	June 30,	December 31,
(Thousands of Dollars)	2009	2008

LIABILITIES AND CAPITALIZATION

Current Liabilities:
Notes payable to banks	$ 45,227	$ 45,227
Accounts payable	106,330	160,692
Accounts payable to affiliated companies	19,179	31,140
Accrued interest	10,132	11,778
Derivative liabilities - current	67,713	77,369
Other	17,275	23,422
	265,856	349,628

Rate Reduction Bonds	211,971	235,139

Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	262,217	253,670
Accumulated deferred investment tax credits	283	355
Deferred contractual obligations	21,972	23,820
Regulatory liabilities	104,785	111,403
Derivative liabilities - long-term	14,310	14,846
Accrued pension	243,744	236,332
Accrued postretirement benefits	39,541	41,849
Other	47,420	41,297
	734,272	723,572
Capitalization:
Long-Term Debt	686,805	686,779

Common Stockholder's Equity:
Common stock, $1 par value - authorized
100,000,000 shares; 301 shares outstanding
in 2009 and 2008	-	-
Capital surplus, paid in	418,204	351,245
Retained earnings	296,905	283,219
Accumulated other comprehensive loss	(761)	(749)
Common Stockholder's Equity	714,348	633,715
Total Capitalization	1,401,153	1,320,494






Total Liabilities and Capitalization	$ 2,613,252	$ 2,628,833


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


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



	Three Months Ended June 30,		Six Months Ended June 30,
(Thousands of Dollars)	2009	2008	2009	2008


Operating Revenues	$ 262,931	$ 274,039	$ 570,584	$ 565,804

Operating Expenses:
Operation -
Fuel, purchased and net interchange power	128,494	142,534	274,719	284,435
Other	58,476	55,861	121,204	109,107
Maintenance	20,852	29,283	36,374	49,173
Depreciation	15,390	13,720	30,561	27,222
Amortization of regulatory liabilities, net	(12,760)	(18,319)	(4,813)	(11,911)
Amortization of rate reduction bonds	11,528	10,870	23,214	22,747
Taxes other than income taxes	9,769	10,045	22,013	20,121
Total operating expenses	231,749	243,994	503,272	500,894
Operating Income	31,182	30,045	67,312	64,910

Interest Expense:
Interest on long-term debt	8,266	7,721	16,370	14,999
Interest on rate reduction bonds	3,406	4,081	7,064	8,232
Other interest (Note 1I)	(1,129)	332	(337)	890
Interest expense, net	10,543	12,134	23,097	24,121
Other Income, Net	2,805	1,262	4,230	2,588
Income Before Income Tax Expense	23,444	19,173	48,445	43,377
Income Tax Expense	6,874	5,482	14,380	12,997
Net Income	$ 16,570	$ 13,691	$ 34,065	$ 30,380












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


PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
	Six Months Ended June 30,
(Thousands of Dollars)	2009	2008

Operating activities:
Net income	$ 34,065	$ 30,380
Adjustments to reconcile to net cash flows
provided by operating activities:
Bad debt expense	3,210	2,523
Depreciation	30,561	27,222
Deferred income taxes	6,305	4,144
Pension and PBOP expense, net of capitalized portion, and contributions	8,206	5,504
Regulatory overrecoveries/(underrecoveries)	3,889	(545)
Amortization of regulatory liabilities, net	(4,813)	(11,911)
Amortization of rate reduction bonds	23,214	22,747
Deferred contractual obligations	(2,160)	(2,690)
Proceeds from insurance settlement for operating portion of major storm cost recovery	10,066	-
Other	4,992	(9,403)
Changes in current assets and liabilities:
Receivables and unbilled revenues, net	5,876	(327)
Fuel, materials and supplies	4,427	(9,676)
Other current assets	1,284	870
Accounts payable	(72,536)	15,293
Taxes receivable/accrued	(6,119)	(24,739)
Other current liabilities	(4,835)	2,749
Net cash flows provided by operating activities	45,632	52,141

Investing Activities:
Investments in property and plant	(112,356)	(119,208)
Decrease/(increase) in NU Money Pool lending	44,800	(16,200)
Proceeds from sales of marketable securities	4,133	2,265
Purchases of marketable securities	(4,161)	(2,319)
Other investing activities	833	3,007
Net cash flows used in investing activities	(66,751)	(132,455)

Financing Activities:
Cash dividends on common stock	(20,422)	(18,188)
Decrease in short-term debt	-	(10,000)
Issuance of long-term debt	-	110,000
Decrease in NU Money Pool borrowings	-	(11,300)
Capital contributions from NU parent	67,000	35,500
Retirements of rate reduction bonds	(23,168)	(24,380)
Other financing activities	(386)	(1,544)
Net cash flows provided by financing activities	23,024	80,088
Net increase/(decrease) in cash	1,905	(226)
Cash - beginning of period	195	450
Cash - end of period	$ 2,100	$ 224

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

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WESTERN MASSACHUSETTS ELECTRIC COMPANY


WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
	June 30,	December 31,
(Thousands of Dollars)	2009	2008

ASSETS

Current Assets:
Cash	$ 1,161	$ -
Receivables, less provision for uncollectible
accounts of $7,734 in 2009 and $6,571 in 2008	50,009	56,802
Accounts receivable from affiliated companies	396	575
Unbilled revenues	13,955	16,694
Taxes receivable	9,911	5,499
Materials and supplies	3,786	3,825
Marketable securities - current	29,569	46,428
Prepayments and other	3,381	2,380
	112,168	132,203

Property, Plant and Equipment:
Electric utility	805,897	781,486
Less: Accumulated depreciation	219,231	214,694
	586,666	566,792
Construction work in progress	69,711	57,413
	656,377	624,205

Deferred Debits and Other Assets:
Regulatory assets	249,414	268,417
Marketable securities - long-term	26,718	9,322
Other	14,757	14,342
	290,889	292,081









Total Assets	$ 1,059,434	$ 1,048,489



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


WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
	June 30,	December 31,
(Thousands of Dollars)	2009	2008

LIABILITIES AND CAPITALIZATION

Current Liabilities:
Notes payable to banks	$ 75,077	$ 29,850
Notes payable to affiliated companies	31,700	31,600
Accounts payable	34,194	50,161
Accounts payable to affiliated companies	6,454	15,047
Accrued interest	5,326	5,824
Other	8,595	10,715
	161,346	143,197

Rate Reduction Bonds	65,894	73,176

Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	198,948	187,283
Accumulated deferred investment tax credits	1,626	1,753
Deferred contractual obligations	33,997	36,509
Regulatory liabilities	22,928	29,826
Accrued postretirement benefits	17,343	18,078
Other	13,107	16,649
	287,949	290,098
Capitalization:
Long-Term Debt	305,410	303,868

Common Stockholder's Equity:
Common stock, $25 par value - authorized
1,072,471 shares; 434,653 shares outstanding
in 2009 and 2008	10,866	10,866
Capital surplus, paid in	144,530	144,545
Retained earnings	83,408	82,549
Accumulated other comprehensive income	31	190
Common Stockholder's Equity	238,835	238,150
Total Capitalization	544,245	542,018





Total Liabilities and Capitalization	$ 1,059,434	$ 1,048,489

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


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

	Three Months Ended June 30,		Six Months Ended June 30,
(Thousands of Dollars)	2009	2008	2009	2008


Operating Revenues	$ 95,120	$ 104,215	$ 213,201	$ 219,974

Operating Expenses:
Operation -
Fuel, purchased and net interchange power	46,298	51,355	109,533	113,494
Other	22,817	22,467	45,481	41,575
Maintenance	5,135	5,472	8,241	10,049
Depreciation	5,621	5,251	11,149	10,444
Amortization of regulatory (liabilities)/assets, net	(4,009)	3,654	(3,339)	6,409
Amortization of rate reduction bonds	3,586	3,365	7,240	6,807
Taxes other than income taxes	2,517	3,008	6,414	6,374
Total operating expenses	81,965	94,572	184,719	195,152
Operating Income	13,155	9,643	28,482	24,822

Interest Expense:
Interest on long-term debt	3,554	3,263	6,997	6,686
Interest on rate reduction bonds	1,112	1,312	2,280	2,660
Other interest (Note 1I)	(233)	274	394	625
Interest expense, net	4,433	4,849	9,671	9,971
Other Income, Net	1,089	477	935	724
Income Before Income Tax Expense	9,811	5,271	19,746	15,575
Income Tax Expense	4,004	2,022	7,793	6,006
Net Income	$ 5,807	$ 3,249	$ 11,953	$ 9,569








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


WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
	Six Months Ended June 30,
(Thousands of Dollars)	2009	2008

Operating Activities:
Net income	$ 11,953	$ 9,569
Adjustments to reconcile to net cash flows
provided by operating activities:
Bad debt expense	3,862	4,022
Depreciation	11,149	10,444
Deferred income taxes	12,249	3,546
Pension income and PBOP expense, net of capitalized portion, and contributions	(1,297)	(2,697)
Regulatory overrecoveries	4,139	1,755
Amortization of regulatory (liabilities)/assets, net	(3,339)	6,409
Amortization of rate reduction bonds	7,240	6,807
Deferred contractual obligations	(2,700)	(3,033)
Other	(824)	(1,618)
Changes in current assets and liabilities:
Receivables and unbilled revenues, net	6,057	(3,432)
Materials and supplies	39	(984)
Other current assets	(587)	184
Accounts payable	(24,426)	53
Taxes receivable/accrued	(4,412)	(2,338)
Counterparty deposits	-	9,019
Other current liabilities	(2,618)	173
Net cash flows provided by operating activities	16,485	37,879

Investing Activities:
Investments in property and plant	(41,478)	(27,945)
Proceeds from sales of marketable securities	78,334	90,755
Purchases of marketable securities	(79,635)	(91,180)
Other investing activities	548	386
Net cash flows used in investing activities	(42,231)	(27,984)

Financing Activities:
Cash dividends on common stock	(11,101)	(6,737)
Increase in short-term debt	45,227	-
Retirements of rate reduction bonds	(7,282)	(6,855)
Increase/(decrease) in NU Money Pool borrowings	100	(11,600)
Capital contributions from NU parent	-	16,281
Other financing activities	(37)	-
Net cash flows provided by/(used in) financing activities	26,907	(8,911)
Net increase in cash	1,161	984
Cash - beginning of period	-	1,110
Cash - end of period	$ 1,161	$ 2,094

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

NORTHEAST UTILITIES AND SUBSIDIARIES

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

The following discussion and analysis should be read in conjunction with our unaudited condensed consolidated financial statements and related combined notes included in this Quarterly Report on Form 10-Q, Northeast Utilities and subsidiaries combined first quarter 2009 Quarterly Report on Form 10-Q (the First Quarter 2009 Form 10-Q) and the Northeast Utilities and subsidiaries combined 2008 Annual Report on Form 10-K as filed with the Securities and Exchange Commission (SEC) (2008 Form 10-K). References in this Form 10-Q to "NU," "we," "us" and "our" refer to Northeast Utilities and its consolidated subsidiaries. All per share amounts are reported on a fully diluted basis.

The only common equity securities that are publicly traded are common shares of NU. The earnings and earnings per share (EPS) of each segment discussed below do not represent a direct legal interest in the assets and liabilities allocated to such segment but rather represent a direct interest in our assets and liabilities as a whole. EPS by segment is a financial measure not recognized under accounting principles generally accepted in the United States of America (GAAP) that is calculated by dividing the net income or loss attributable to controlling interests of each segment by the weighted average fully diluted NU common shares outstanding for the period. We use this non-GAAP financial measure to provide segmented earnings results and guidance and believe that this measurement is useful to investors to evaluate the actual and projected financial performance and contribution of our business segments. 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.

The discussion below also includes non-GAAP financial measures referencing our 2008 earnings and EPS excluding a significant charge resulting from the settlement of litigation. We use these non-GAAP financial measures to more fully explain and compare the 2009 and 2008 results without including the impact of this settlement. Due to the nature and significance of the litigation settlement charge, management believes that this non-GAAP presentation is more representative of our performance and provides additional and useful information to investors in analyzing historical and future performance. These non-GAAP financial measures should not be considered as alternatives to reported net income attributable to controlling interests or EPS determined in accordance with GAAP as indicators 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" in this Management's Discussion and Analysis.

Forward Looking Statements: This Management's Discussion and Analysis includes statements concerning our expectations, beliefs, plans, objectives, goals, strategies, assumptions of future events, future financial performance or growth and other statements that are not historical facts. These statements are "forward-looking statements" within the meaning of the Private Securities Litigation Reform Act of 1995. You can generally identify our "forward-looking statements" through the use of words or phrases such as "estimate," "expect," "anticipate," "intend," "plan," "project," "believe," "forecast," "should," "could," and other similar expressions. Forward-looking statements are based on the current expectations, estimates, assumptions or projections of management and are not guarantees of future performance. These expectations, estimates, assumptions or projections may vary materially from actual results. Accordingly, any such statements are qualified in their entirety by reference to, and are accompanied by, the following important factors that could cause our actual results to differ materially from those contained in our forward-looking statements, including, but not limited to, actions or inaction by local, state and federal regulatory 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 electricity positions, actions of rating agencies, and other presently unknown or unforeseen factors. Other risk factors are detailed from time to time in our reports filed with the SEC 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 of which speaks only as of the date on which such statement is made, and we undertake no obligation to update the information contained in any forward-looking statement or statements to reflect events or circumstances after the date on which such statement is made or to reflect the occurrence of unanticipated events. New factors emerge from time to time and it is not possible for management to predict all of such factors, nor can it assess the impact

of each such factor on the business or 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 and in our 2008 Form 10-K. This Quarterly Report on Form 10-Q and our 2008 Form 10-K also describe material contingencies and critical accounting policies and estimates in the respective "Management's Discussion and Analysis" and "Combined Notes to Consolidated Financial Statements." We encourage you to review these items.

Financial Condition and Business Analysis

Executive Summary

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

Results, Strategy and Outlook:

We earned $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, compared with $57.8 million, or $0.37 per share, in the second quarter of 2008 and $116.2 million, or $0.75 per share, in the first half of 2008. The 2009 second quarter earnings benefited from a net favorable impact of $11.1 million, or $0.06 per share, from the earlier than projected resolution of various routine tax issues. First half 2008 results include an after-tax charge of $29.8 million, or $0.19 per share, associated with the settlement of litigation.

Our regulated companies, which consist of The Connecticut Light and Power Company (CL&P), Public Service Company of New Hampshire (PSNH), Western Massachusetts Electric Company (WMECO), and Yankee Gas Services Company (Yankee Gas), earned $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, compared with $60.8 million, or $0.39 per share, in the second quarter of 2008 and $147.1 million, or $0.94 per share, in the first half of 2008. The 2009 second quarter results benefited from the regulated companies' $10.1 million portion of the after-tax impact from the resolution of routine tax issues and implementation of rigorous cost management initiatives.

Earnings at the distribution segments of our regulated companies (which includes the generation business of PSNH and gas distribution segment of Yankee Gas) totaled $38.2 million in the second quarter of 2009 and $97.4 million in the first half of 2009, compared with $25.6 million in the second quarter of 2008 and $79.4 million in the first half of 2008. Earnings at the transmission segments of our regulated companies totaled $41.8 million in the second quarter of 2009 and $77.2 million in the first half of 2009, compared with $35.2 million in the second quarter of 2008 and $67.7 million in the first half of 2008.

Our competitive businesses held by NU Enterprises, Inc. (NU Enterprises) earned $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, compared with $2.2 million, or $0.01 per share, in the second quarter of 2008 and $4.1 million, or $0.03 per share, in the first half of 2008. While first half 2009 results included positive after-tax mark-to-market results of $4.6 million, first half 2008 results included a net after-tax reduction of earnings of $2.4 million associated with the implementation of Statement of Financial Accounting Standards (SFAS) No. 157, "Fair Value Measurements" (SFAS No. 157), and negative after-tax mark-to-market results of $0.9 million.

NU parent and other companies recorded 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, compared with $5.2 million, or $0.03 per share, in the second quarter of 2008 and $35 million, or $0.22 per share, in the first half of 2008. First half 2008 results included the after-tax charge of $29.8 million from the settlement of litigation.

We project consolidated 2009 earnings of between $1.80 per share and $1.90 per share, which has been narrowed from the previously reported guidance that we would earn at the low end of a range of between $1.80 per share and $2.00 per share. We reduced our distribution and generation segment earnings guidance range by $0.10 per share to between $0.90 per share and $1.00 per share, due primarily to a combination of lower than projected retail electric sales for the full year, as a result of mild summer weather and economic weakness, higher uncollectible expense and a higher than initially expected level of average shares outstanding. We now project transmission segment earnings of approximately $0.90 per share, which reflects a higher than previously projected level of capital investment in 2009. We also project that our competitive business will earn approximately $0.05 per share, which reflects strong performance in the first half of 2009. We continue to project net expenses at NU parent and other companies of $0.05 per share.

On August 6, 2009, we filed an application with the U.S. Department of Energy (DOE) through CL&P, PSNH and WMECO for federal stimulus funding of 50 percent to match our investment in a $253 million project involving, among other things, the installation of smart grid technology and expanded access to advanced meters for over 200,000 of our customers. This project is

also subject to approval by respective state regulatory commissions. This application was made through the DOE's Smart Grid Investment Grant program to cover eligible expenditures, the majority of which is expected to be incurred at CL&P.

Legal, Regulatory and Other Items:

On May 22, 2009, the Federal Energy Regulatory Commission (FERC) granted the petition for a declaratory order requested by NU and NSTAR approving a new participant-funded transmission tie line connecting New England with the Hydro-Québec system in order for H.Q. Energy Services (U.S.) Inc. (HQUS) to sell and deliver into New England at least 1,200 megawatts (MW) of firm electric power from Canadian low-carbon energy resources. The terms of service and rate paid by HQUS for the right to transport this power will be filed at the FERC for approval, and purchase power agreements between HQUS and New England utilities are required to be filed with respective state commissions for approval. We believe that all approvals will be in place to permit the commencement of construction in 2011, at an estimated cost of $525 million to NU, and transmission of power over the new line will commence in 2014.

On June 30, 2009, PSNH filed an application with the New Hampshire Public Utilities Commission (NHPUC) requesting a permanent increase in distribution rates of approximately $51 million on an annualized basis, effective August 1, 2009, and another $17 million effective July 1, 2010. On July 31, 2009, the NHPUC approved a temporary increase in distribution rates of $25.6 million on an annualized basis, effective August 1, 2009. PSNH expects a decision on the permanent distribution rate request in mid-2010. Any differences between temporary and permanent rates will be reconciled back to August 1, 2009.

On June 18, 2009, WMECO and the Massachusetts Attorney General (AG) filed a stipulation agreement with the Massachusetts Department of Public Utilities (DPU) in which the AG supported WMECO's proposal to install 6 MW of solar energy generation in its service territory at an estimated cost of approximately $40 million. Under the agreement, these projects would be commissioned beginning in 2010 and the related return on equity (ROE) would be fixed at 9 percent. WMECO expects a decision from the DPU by August 12, 2009.

On June 1, 2009, CL&P commenced a three-month, time-based rate "smart grid" pilot program involving nearly 3,000 customers. CL&P will file a report on the pilot's results with the Connecticut Department of Public Utility Control (DPUC) by December 1, 2009.

In June 2009, the New England Independent System Operator (ISO-NE) reaffirmed the need date of our first transmission project under the New England East-West Solutions (NEEWS) series of projects. In order to adequately meet reliability needs, we are currently expecting to complete this approximately $714 million Greater Springfield Reliability Project (GSRP) in late 2013 assuming all approvals are obtained. The timing of the other two major projects in the NEEWS series are subject to change based on ISO-NE's annual process to review the need dates for all projects (refer to "Business Development and Capital Expenditures - Regulated Companies-Transmission Segment" for further discussion).

On July 7, 2009, the New Hampshire Site Evaluation Committee concluded 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. On August 5, 2009, the New Hampshire Supreme Court dismissed an appeal of a prior NHPUC ruling on the project, holding the appellants were not harmed and thus lacked standing to bring their challenge. Construction is ahead of schedule and on budget, and we currently expect to complete the project by mid-2012.

Liquidity:

CL&P completed the remarketing of $62 million of tax-exempt pollution control revenue bonds (PCRBs) on April 2, 2009. The bonds carry a coupon of 5.25 percent and are subject to a mandatory tender for purchase on April 1, 2010, after which CL&P can remarket the bonds.

Our cash capital expenditures totaled $420.9 million in the first half of 2009, compared with $625.1 million in the first half of 2008. The decrease in our cash capital expenditures was primarily the result of lower transmission segment capital expenditures, particularly at CL&P, due to the completion in 2008 of three major transmission projects in southwest Connecticut. We project capital expenditures of approximately $970 million in 2009, which is $50 million higher than our previously announced projection of $920 million due primarily to the timing of capital spending on transmission projects.

After rate reduction bond (RRB) payments included in financing activities, we had consolidated cash flows provided by operations in the first half of 2009 of $388 million, which represented an increase of $221.4 million from the first half of 2008. The improved cash flows were due primarily to the increase in operating results from higher distribution rates and transmission revenues at CL&P in 2009, a favorable shift in timing of collections of accounts receivable and unbilled revenues, a lower level of

operating costs that will be recovered from customers in future periods ("regulatory underrecoveries") and the absence in 2009 of the litigation settlement payment of $49.5 million made in March 2008. We project consolidated operating cash flows of approximately $580 million in 2009, after RRB payments, which is higher than previous projections due to $80 million of lower income tax payments from an accelerated deduction of depreciation.

Primarily as a result of NU parent's March 2009 common share offering and CL&P's February 2009 first mortgage bond issuance, which resulted in total gross proceeds of approximately $630 million, our cash and cash equivalents totaled $481.1 million as of June 30, 2009, compared with $89.8 million as of December 31, 2008. As of June 30, 2009, we also had $263 million of aggregate borrowing availability on our revolving credit lines.

Overview

Consolidated: We earned $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, compared with $57.8 million, or $0.37 per share, in the second quarter of 2008 and $116.2 million, or $0.75 per share, in the first half of 2008. The 2009 earnings benefited from a net favorable impact of $11.1 million, or $0.06 per share, from the earlier than projected resolution of various routine tax issues in the second quarter. The 2008 results include a first-quarter, after-tax charge of $29.8 million, or $0.19 per share, resulting from the settlement of litigation. A summary of our earnings by segment, which also reconciles the non-GAAP financial measures of consolidated non-GAAP earnings and EPS, as well as EPS by segment, 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 2009 and 2008 is as follows:


	For the Three Months Ended June 30,								For the Six Months Ended June 30,
(Millions of Dollars, except	2009				2008				2009				2008
per share amounts)	Amount		Per Share		Amount		Per Share		Amount		Per Share		Amount		Per Share
Net income attributable to controlling interests (GAAP)	$	82.9	$	0.47	$	57.8	$	0.37	$	180.5	$	1.07	$	116.2	$	0.75

Regulated companies	$	80.0	$	0.46	$	60.8	$	0.39	$	174.6	$	1.03	$	147.1	$	0.94
Competitive businesses		5.5		0.03		2.2		0.01		11.3		0.07		4.1		0.03
NU parent and other companies		(2.6)		(0.02)		(5.2)		(0.03)		(5.4)		(0.03)		(5.2)		(0.03)
Non-GAAP earnings		82.9		0.47		57.8		0.37		180.5		1.07		146.0		0.94
Litigation charge (after-tax)		-		-		-		-		-		-		(29.8)		(0.19)
Net income attributable to controlling interests (GAAP)	$	82.9	$	0.47	$	57.8	$	0.37	$	180.5	$	1.07	$	116.2	$	0.75

Regulated Companies: Our regulated companies segment their respective earnings between their electric transmission segments and their electric and gas distribution segments, with PSNH generation included in its electric distribution segment. A summary of regulated company earnings by segment for the second quarter and first half of 2009 and 2008 is as follows:


	For the Three Months Ended June 30,				For the Six Months Ended June 30,
(Millions of Dollars)	2009		2008		2009		2008
CL&P Transmission	$	35.1	$	30.0	$	65.2	$	55.8
PSNH Transmission		4.7		3.6		8.6		8.8
WMECO Transmission		2.0		1.6		3.4		3.1
Total Transmission		41.8		35.2		77.2		67.7
CL&P Distribution		21.9		14.8		43.6		33.7
PSNH Distribution		11.9		10.1		25.4		21.6
WMECO Distribution		3.8		1.7		8.6		6.5
Yankee Gas		0.6		(1.0)		19.8		17.6
Total Distribution		38.2		25.6		97.4		79.4
Net Income - Regulated Companies	$	80.0	$	60.8	$	174.6	$	147.1

The higher second quarter and first half 2009 transmission segment earnings reflect a higher level of investment in this segment as we continued to build out our transmission infrastructure to meet our customers' and the region's reliability needs. The results primarily reflect the effect of CL&P's investment of approximately $1.6 billion since the beginning of 2005 in the southwest Connecticut transmission projects that were completed in late 2008. The first half 2008 transmission segment results included earnings of approximately $2.9 million related to the February 1, 2005 through December 31, 2007 time period as a result of a first quarter 2008 order issued by the FERC.

CL&P's second quarter 2009 distribution segment earnings were $7.1 million higher than the same period in 2008 due primarily to the favorable resolution of various routine tax issues and realized gains on the sale of securities in the NU supplemental benefit trust. In

total, these two items contributed to $6.3 million of earnings to CL&P in the second quarter of 2009. Retail electric sales decreased 5.3 percent from 2008, but revenues were slightly higher as a result of the distribution rate increase that took effect on February 1, 2009. CL&P's operations and maintenance expense was lower for the quarter due to lower storm costs and specific cost-containment initiatives that more than offset other operating cost increases including pension expense. Depreciation, amortization, and interest expense were higher than 2008.

For the first six months of 2009, CL&P's distribution segment earnings were $9.9 million higher than the same period in 2008 due primarily to the same factors that affected earnings in the second quarter. The resolution of tax issues and realized gains on the sale of securities in the NU supplemental benefit trust contributed $9.6 million of earnings to CL&P in 2009. Distribution revenues were higher due to the distribution rate increases effective February 1, 2008 and February 1, 2009, and operations and maintenance expense was lower despite an increase in pension expense. These improvements were essentially offset by other operating cost increases including depreciation, amortization, and interest expense. For the 12 months ended June 30, 2009, CL&P's distribution segment Regulatory ROE was 7.7 percent, and for full year 2009, we expect it to be approximately 7 percent.

PSNH's second quarter 2009 distribution segment earnings were $1.8 million higher than the same period in 2008 primarily due to the resolution of tax issues, higher generation-related earnings, and lower operations and maintenance expense partially offset by lower revenues attributable to a 7 percent decrease in retail electric sales, and higher pension expense, depreciation, and property taxes. PSNH's second quarter 2008 earnings included a positive pre-tax adjustment to its generation cost recovery mechanism of $1.9 million.

PSNH's distribution segment earnings for the six months ended June 30, 2009 were $3.8 million higher than the same period in 2008 primarily due to higher generation-related earnings, the resolution of tax issues, lower operations and maintenance expense, and lower carrying costs on credits owed to customers partially offset by higher depreciation and amortization expense, pension expense, and the absence of the $1.9 million positive pre-tax adjustment to its generation cost recovery mechanism that occurred in 2008. For the 12 months ended June 30, 2009, PSNH's distribution segment Regulatory ROE was 8 percent, and for full year 2009, we expect it will remain at approximately 8 percent, as the additional revenues from the temporary rate relief effective August 1, 2009 will be offset by higher costs including amortization of significant December 2008 storm costs and capital costs associated with PSNH's growing rate base.

WMECO's second quarter and first half 2009 distribution segment earnings were $2.1 million higher than the same periods in 2008 primarily due to a $1.6 million pre-tax charge related to a DPU ruling that was recorded in the second quarter of 2008, and the resolution of tax issues in the second quarter of 2009. For the second quarter and first six months of 2009, retail electric sales and distribution revenues were lower and depreciation expense was higher, but these were offset by decreases in other costs including operations and maintenance expense and uncollectibles expense. For the 12 months ended June 30, 2009, WMECO's distribution segment Regulatory ROE was 7.7 percent, and for full year 2009, we expect it to be approximately 7.5 percent.

Yankee Gas's second quarter 2009 earnings were $1.6 million higher than the same period in 2008 due primarily to a DPUC order requiring Yankee Gas to refund $5.8 million to customers, which amount was recorded in the second quarter of 2008. Excluding the impact of the pre-tax $5.8 million refund from the 2008 results, second quarter 2009 earnings were down by approximately $1.9 million due primarily to lower revenues attributable to higher uncollectibles expense and employee benefit costs partially offset by the resolution of tax issues.

Yankee Gas's earnings for the first six months of 2009 were $2.2 million higher than the same period in 2008 primarily due to the absence of the $5.8 million refund recorded in 2008, an 8.8 percent increase in firm natural gas sales, and the resolution of tax issues partially offset by higher uncollectibles expense, employee benefit costs and interest expense. For the 12 months ended June 30, 2009, Yankee Gas's Regulatory ROE was 8.1 percent, and for full year 2009, 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 gigawatt-hour (GWh) sales and Yankee Gas firm natural gas sales for the second quarter and first half of 2009 as compared to the same periods in 2008 on an actual and weather normalized basis (using a 30-year average) is as follows:


	For the Three Months Ended June 30, 2009 Compared to 2008
	Electric								Firm Natural Gas
	CL&P		PSNH		WMECO		Total		Yankee Gas
	Percentage Decrease	Weather Normalized Percentage Increase/ (Decrease)	Percentage Decrease	Weather Normalized Percentage Decrease	Percentage Decrease	Weather Normalized Percentage Decrease	Percentage Decrease	Weather Normalized Percentage Increase/ (Decrease)	Percentage (Decrease)/ Increase	Weather Normalized Percentage (Decrease)/ Increase
Residential	(4.8)%	1.2 %	(5.1)%	(1.0)%	(7.0)%	(2.4)%	(5.1)%	0.4 %	(19.2)%	(21.2)%
Commercial	(3.3)%	(0.4)%	(6.0)%	(3.4)%	(10.6)%	(8.2)%	(4.7)%	(1.9)%	(1.3)%	(3.5)%
Industrial	(12.8)%	(10.9)%	(13.2)%	(10.8)%	(15.1)%	(13.8)%	(13.3)%	(11.3)%	15.2 %	14.7 %
Other	(13.2)%	(13.2)%	(0.5)%	(0.5)%	(21.4)%	(21.4)%	(12.9)%	(12.9)%	-	-
Total	(5.3)%	(1.3)%	(7.0)%	(4.0)%	(10.4)%	(7.4)%	(6.3) %	(2.6)%	0.3 %	(1.3)%


	For the Six Months Ended June 30, 2009 Compared to 2008
	Electric								Firm Natural Gas
	CL&P		PSNH		WMECO		Total		Yankee Gas
	Percentage Increase/ (Decrease)	Weather Normalized Percentage Increase/ (Decrease)	Percentage Decrease	Weather Normalized Percentage Increase/ (Decrease)	Percentage (Decrease)/ Increase	Weather Normalized Percentage (Decrease)/ Increase	Percentage Increase/ (Decrease)	Weather Normalized Percentage Increase/ (Decrease)	Percentage Increase	Weather Normalized Percentage (Decrease)/ Increase
Residential	0.6 %	1.5 %	(0.6)%	0.1 %	(2.0)%	(1.4)%	0.1 %	0.9 %	3.2 %	(2.5)%
Commercial	(2.8)%	(1.7)%	(3.7)%	(2.8)%	(6.9)%	(5.8)%	(3.5)%	(2.4)%	10.4 %	5.2 %
Industrial	(18.4)%	(17.4)%	(10.7)%	(9.4)%	(15.5)%	(14.8)%	(15.7)%	(14.7)%	13.4 %	12.0 %
Other	(2.9)%	(2.9)%	(3.5)%	(3.5)%	14.9 %	14.9 %	(1.7)%	(1.7)%	-	-
Total	(3.3)%	(2.3)%	(3.8)%	(2.9)%	(6.6)%	(5.8)%	(3.8)%	(2.8)%	8.8 %	4.5 %

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 2009 and 2008 is as follows:


	For the Three Months Ended June 30,
	Electric			Firm Natural Gas
	2009	2008	Percentage Decrease	2009	2008	Percentage (Decrease)/Increase
Residential	2,967	3,126	(5.1)%	1,695	2,098	(19.2)%
Commercial	3,469	3,641	(4.7)%	2,099	2,127	(1.3)%
Industrial	1,119	1,291	(13.3)%	3,447	2,992	15.2 %
Other	66	76	(12.9)%	-	-	-
Total*	7,622	8,133	(6.3)%	7,242	7,217	0.3 %


	For the Six Months Ended June 30,
	Electric			Firm Natural Gas
	2009	2008	Percentage Increase/(Decrease)	2009	2008	Percentage Increase
Residential	7,116	7,111	0.1 %	8,156	7,906	3.2 %
Commercial	7,102	7,356	(3.5)%	8,366	7,577	10.4 %
Industrial	2,128	2,525	(15.7)%	7,753	6,835	13.4 %
Other	164	167	(1.7)%	-	-	-
Total*	16,510	17,160	(3.8)%	24,276	22,319	8.8 %

*Amounts may not total due to rounding of GWh or million cubic feet.

Consistent with New England electric consumption statistics, our second quarter and first half 2009 actual and weather normalized retail electric sales were lower than the same period in 2008. The negative trend in our sales is most prevalent in the industrial class. The decline in 2009 industrial sales reflects the fact that many industrial customers have been negatively impacted by the economic conditions of our region and nation. We believe the reduction in industrial sales is primarily driven by a reduced number of shifts and days of operations. In this regard, a portion of these reduced industrial sales may be regained when the economy begins to recover. Further, commercial and industrial sales in the first half of 2009 were negatively impacted by additional installation of distributed generation, utilization of conservation and load management programs, and other measures employed by customers to reduce their usage of electricity.

Our residential sales in the second quarter of 2009 for all three electric distribution companies were lower than the second quarter of 2008 primarily due to the cool and rainy weather in June 2009 and a decrease in air conditioning load. For our service territories, June 2009 was the coldest June since 1985, and for the second quarter of 2009, the amount of cooling degree days was over 30 percent lower than last year for CL&P and WMECO and more than 50 percent lower than last year for PSNH. On a weather normalized basis,

the residential sales results for the first half of 2009 vary by operating company. CL&P has maintained a positive sales growth rate, whereas PSNH's residential sales growth was essentially flat and WMECO's sales have declined.

Excluding the impacts of the CL&P distribution rate increases effective February 1, 2008 and February 1, 2009, total electric distribution rate revenues for the first six months of 2009 were $2.4 million lower than the same period in 2008. This change in revenues reflects the fact that our recovery of distribution revenues varies between customer classes. As compared to other customer classes, a greater portion of residential revenues is recovered through volumetric charges. In contrast to residential rates, a much smaller portion of commercial and industrial revenues is recovered through volumetric charges. In fact, distribution rates for certain large businesses are structured so that we recover 100 percent of the distribution revenues through non-volumetric charges. In this regard, rate design has significantly mitigated the impact of the declining commercial and industrial sales on distribution revenues and earnings.

Firm natural gas sales were slightly higher in the second quarter of 2009 than the same period in 2008, but lower on a weather normalized basis. For the first six months of 2009, actual and weather normalized sales were higher than 2008. The 2009 results for the commercial and industrial sectors have benefitted substantially from the addition of new large gas-fired distributed generation in Yankee Gas's service region during the last twelve months. The rate of growth in gas sales is expected to moderate for the balance of 2009 as the weak economic conditions are expected to continue until later in 2009 or early 2010, and the large distributed generation load additions are reflected in future quarterly year-over-year comparisons. Yankee Gas recovers almost half of its total distribution revenues through non-usage charges, and thus, similar to our electric distribution companies, changes in sales have less of an impact on revenues.

Our uncollectibles expense is influenced by the economic conditions of our region; however, a portion of the uncollectibles expense for each of the electric distribution companies is allocated to the respective company's energy supply rate and recovered as a tracked expense. Additionally, for CL&P and Yankee Gas, write-offs attributable to hardship customers are tracked and fully recovered. For the second quarter of 2009, our total uncollectibles expense was approximately $7.7 million higher than the same period in 2008, but $7.1 million was attributable to hardship customers and did not impact earnings. For the first six months of 2009, our total uncollectibles expense was approximately $10.8 million higher than the same period in 2008, but only $3 million was not tracked and impacted earnings. Through June 30, 2009, our uncollectibles expense is consistent with our expectations, but we continue to monitor our receivables and collections closely. The weak economic conditions in our region continue to negatively affect our customers and create a greater risk of bad debts and related write-offs through the remainder of the year and into the foreseeable future.

Competitive Businesses: NU Enterprises, which continues to manage to completion Select Energy Inc.'s (Select Energy) remaining wholesale marketing contracts and to manage its energy services activities, earned $5.5 million in the second quarter of 2009 and $11.3 million in the first half of 2009, compared with $2.2 million in the second quarter of 2008 and $4.1 million in the first half of 2008. First half 2008 results included a net after-tax reduction of earnings of $2.4 million associated with the implementation of SFAS No. 157. Competitive business earnings for the second quarter and first half of 2009 included positive mark-to-market after-tax results of $1.3 million and $4.6 million, respectively, associated with Select Energy's wholesale marketing contracts, compared to negative mark-to-market after-tax results of $1.4 million and $0.9 million for the second quarter and first half of 2008, respectively.

NU Parent and Other Companies: NU parent and other companies recorded net expenses of $2.6 million in the second quarter of 2009 and $5.4 million in the first half of 2009, compared with net expenses of $5.2 million in the second quarter of 2008 and $35 million in the first half of 2008. The net expenses in the first half of 2008 included a $29.8 million after-tax charge resulting from the payment by NU parent of $49.5 million made in March 2008 as part of a litigation settlement. The decrease in net expenses for the second quarter of 2009 was the result of a decrease in net interest costs for NU parent due to interest earned on significantly higher cash balances after the sale of common shares in March 2009 resulting in net proceeds of $370.8 million.

Current Economic Conditions

Weak economic conditions in the Northeast continue to have a negative effect on our customers, which results in lower sales and greater risk of nonpayment. The weak economic conditions may also limit our ability to obtain distribution rate relief or could impact the timing of our major transmission projects. We have included our best estimate of the impacts of these factors in the assumptions that were used to develop our earnings guidance; however, we are unable to predict the actual impact of these factors on our future results of operations.

We expect to make significant investments in our capital projects from 2009 through 2013. We believe that even under present circumstances, our current credit ratings and business profile will allow us to have adequate access to the capital markets as needed. At this point in time, while the impacts of the uncertainty in the capital and credit markets and the ongoing economic downturn cannot be predicted, we believe that we currently have sufficient operating flexibility and access to funding sources to maintain adequate liquidity. This belief is supported by our successful debt and equity issuances of approximately $700 million in the first half of 2009.

Future Outlook

EPS Guidance: We project consolidated 2009 earnings of between $1.80 per share and $1.90 per share, which are consistent with our previously announced projection that we would earn at the lower end of a range of between $1.80 per share and $2.00 per share. This revised projection includes the impact of the issuance of 18,975,000 common shares on March 20, 2009, which was originally forecast for mid-2009 with a lower number of shares. The narrowing of the range was also a result of higher uncollectible expense and our expectation that retail electric sales in the distribution segment will decline by more than the originally projected 1 percent to 2 percent for the full year, as a result of mild summer weather and economic weakness. Factors that could have a further negative impact on our 2009 earnings are lower sales, higher storm costs and higher uncollectible expense than currently projected.

A summary of our projected 2009 EPS by segment, which also reconciles consolidated fully diluted EPS to the non-GAAP financial measures of EPS by segment, is as follows:


	2009 EPS Range
(Approximate amounts)		Low		High
Fully Diluted EPS (GAAP)	$	1.80	$	1.90

Regulated companies:
Distribution segment	$	0.90	$	1.00
Transmission segment		0.90		0.90
Total regulated companies		1.80		1.90
Competitive businesses		0.05		0.05
NU parent and other companies		(0.05)		(0.05)
Fully Diluted EPS (GAAP)	$	1.80	$	1.90

Long-Term Growth Rate: We project that we will achieve an average compounded annual EPS growth rate through 2013 of between 8 percent and 11 percent over 2007 EPS of $1.59. We currently estimate we will likely be at the lower end of this range. This EPS growth rate assumes achieved Regulatory ROEs of approximately 12 percent for transmission, between 9.5 percent and 10 percent for generation and between 9 percent and 9.5 percent for distribution investments. 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 Regulatory ROEs and FERC's current transmission policies remain consistent and enable us to achieve projected transmission ROEs. We expect to update the EPS growth rate estimate later this year when we update our capital investment plan.

Liquidity

Consolidated: We had $481.1 million of cash and cash equivalents on hand as of June 30, 2009, compared with $89.8 million as of December 31, 2008. During the first half of 2009 our cash position increased primarily as a result of the issuance of 18,975,000 common shares on March 20, 2009, which yielded proceeds of $370.8 million, net of underwriting commissions of $12.5 million, and the issuance of $250 million of first mortgage bonds by CL&P on February 13, 2009.

On April 1, 2009, using funds borrowed through the NU Money Pool, Yankee Gas retired $50 million of first mortgage bonds carrying a coupon of 6.2 percent that had been issued in January 1999. Yankee Gas does not plan to issue any long-term debt in 2009.

On April 2, 2009, CL&P completed the remarketing of $62 million of tax-exempt PCRBs it had elected to acquire in October 2008. The bonds carry a coupon of 5.25 percent until the mandatory tender for purchase on April 1, 2010, after which CL&P can remarket the bonds.

On February 20, 2009, PSNH filed an application with the NHPUC to issue $150 million of first mortgage bonds. PSNH anticipates approval in the third quarter and expects to issue the bonds in the fourth quarter. No other long-term debt or equity financings are planned by NU or its subsidiaries in 2009. We have only annual sinking fund requirements of $4.3 million continuing in 2010 through 2012, the mandatory tender of $62 million in 2010, and no debt maturities until April 1, 2012.

The proceeds from the above completed or planned 2009 financings were or will be used primarily to repay short-term borrowings and fund our capital programs. The combined borrowings and letters of credit (LOCs) outstanding on our revolving credit facilities totaled approximately $581 million as of June 30, 2009, compared with approximately $706 million as of December 31, 2008.

We had consolidated operating cash flows in the first half of 2009 of $388 million, compared with $166.6 million in the first half of 2008, both after RRB payments included in financing activities. The increase in the first half 2009 operating cash flows were partially

due to the absence in 2009 of the litigation settlement payment of $49.5 million made in March 2008. The improved cash flows were also due primarily to the increase in operating results from higher distribution rates and increased transmission revenues at CL&P after significant projects were placed in service in late 2008; a favorable shift in timing of collections of accounts receivable and unbilled revenues; and a decrease in regulatory underrecoveries related primarily to CL&P's Federally Mandated Congestion Charge (FMCC), Generation Service Charge (GSC), and Transmission Adjustment Charge (TAC) included in customer rates. We project consolidated operating cash flows of approximately $580 million in 2009, after RRB payments of $244 million, which is higher than previously announced. The $580 million includes $80 million of lower income tax payments as a result of an extension of tax rules allowing the accelerated deduction of depreciation.

A summary of the current credit ratings and outlooks by Moody's Investors Service (Moody's), Standard & Poor's (S&P) and Fitch Ratings (Fitch) for NU parent and WMECO's senior unsecured debt and CL&P and PSNH's first mortgage bonds is as follows:

Moody's

S&P

Fitch

Current

Outlook

Current

Outlook

Current

Outlook

NU Parent

Baa2

Stable

BBB-

Stable

BBB

Stable

CL&P

Stable

BBB+

Stable

A-

Stable

PSNH

Stable

BBB+

Stable

BBB+

Stable

WMECO

Baa2

Stable

BBB

Stable

BBB+

Stable

In August 2009, Moody's completed an industry-wide review of the number of levels between utility first mortgage bonds and utility unsecured debt. Moody's stated that its review of utility credit defaults showed a much higher rate of recovery for first mortgage bonds than for unsecured debt. The review resulted in one-level upgrades of CL&P and PSNH first mortgage bonds by Moody's.

If NU parent's senior unsecured debt ratings were to be reduced to a sub-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 were to occur, Select Energy, under its remaining contracts, would have been required to provide additional cash or LOCs in an aggregate amount of $27.2 million to various unaffiliated counterparties and additional cash or LOCs in the aggregate amount of $2.8 million to an independent system operator, in each case as of June 30, 2009. NU parent would have been able to and remains able to provide that collateral.

If unsecured debt ratings for CL&P or PSNH were to be reduced by either Moody's or S&P, certain supply contracts could require CL&P and PSNH to post additional collateral in the form of cash or LOCs with various unaffiliated counterparties from whom they purchase power. As of June 30, 2009, CL&P only had one supply contract requiring collateral posting for which $1 million of collateral has been posted for the out-of-the-money position. Also as of June 30, 2009, no additional collateral would have been required under CL&P's supply contracts if its unsecured debt ratings had been reduced. If these ratings were to be reduced by one level, PSNH would have been required to post additional collateral of $3.8 million as of June 30, 2009. If these ratings were to be reduced by two levels or below investment grade, the amount of additional collateral required to be posted by PSNH would have been $23 million as of June 30, 2009. PSNH would have been able to and remains able to provide these collateral amounts.

On July 1, 2009, WMECO filed an application with the DPU to issue and sell up to $150 million of senior secured or unsecured long-term debt. Subject to approval by the DPU, and if market conditions continue to favor secured debt, WMECO expects that most of the new long-term debt that it will issue in future years will be first mortgage bonds. If WMECO decides to issue first mortgage bonds, WMECO will be obligated to secure its currently outstanding unsecured senior notes in an aggregate principal amount of $195 million, equally and ratably with such first mortgage bonds. WMECO does not expect to issue new long-term debt, either secured or unsecured, in 2009.

NU paid common dividends of $78.9 million in the first half of 2009, compared with $62.6 million in the first half of 2008. The increase is the result of a 6.3 percent increase in NU parent's common dividend rate that took effect in the third quarter of 2008, an additional 11.8 percent increase that took effect in the first quarter of 2009, and for the second quarter of 2009 a higher number of shares outstanding. On July 14, 2009, our Board of Trustees declared a common dividend of $0.2375 per share, payable on September 30, 2009 to shareholders of record as of September 1, 2009.

In general, the regulated companies pay approximately 60 percent of their cash earnings to NU parent in the form of common dividends. In the first half of 2009, CL&P, PSNH, WMECO, and Yankee Gas paid $56.9 million, $20.4 million, $11.1 million, and $19.1 million, respectively, in common dividends to NU parent. In the first half of 2009, NU parent contributed $77 million and $67 million of equity to CL&P and PSNH. NU made no equity contributions to WMECO and Yankee Gas for the six months ended June 30, 2009.

NU targets paying out approximately 50 percent of consolidated earnings in the form of common dividends. NU's ability to pay common dividends is subject to approval by its Board of Trustees and to NU's future earnings and cash flow requirements and may be

limited by certain state statutes, the leverage restrictions in its revolving credit agreement and the ability of its subsidiaries to pay common dividends. The Federal Power Act limits the payment of dividends by CL&P, PSNH and WMECO to their respective retained earnings balances unless a higher amount is approved by FERC, and PSNH is required to reserve an additional amount under its FERC hydroelectric license conditions. In addition, relevant state statutes may impose additional limitations on the payment of dividends by the regulated companies. CL&P, PSNH, WMECO and Yankee Gas also are parties to a revolving credit agreement that imposes leverage restrictions.

Cash capital expenditures included on the accompanying unaudited condensed consolidated statements of cash flows and described in the Liquidity section of this Management's Discussion and Analysis do not include amounts incurred on capital projects but not yet paid, cost of removal, the allowance for funds used during construction (AFUDC) related to equity funds, and the capitalized portions of pension and postretirement benefits other than pension (PBOP) expense or income. A summary of our cash capital expenditures by company for the first half of 2009 and 2008 is as follows:


	For the Six Months Ended June 30,
(Millions of Dollars)		2009		2008
CL&P	$	226.9	$	442.0
PSNH		112.4		119.2
WMECO		41.5		27.9
Yankee Gas		25.4		23.4
Other		14.7		12.6
Totals	$	420.9	$	625.1

The decrease in our total cash capital expenditures was primarily the result of lower transmission segment capital expenditures, particularly at CL&P (refer to "Business Development and Capital Expenditures" for further discussion).

As a result of Lehman Brothers Commercial Bank (LBCB) declining to fund its current commitment of approximately $56 million under our credit facilities referred to below, we are limited to an aggregate of $844 million of borrowing capacity under our credit facilities, which we believe provides sufficient operating flexibility to maintain adequate liquidity. We have no other exposure to Lehman Brothers Holdings Inc., the parent of LBCB, or any of its affiliates.

NU parent has a credit facility in a nominal aggregate amount of $500 million including the commitment of LBCB, which expires on November 6, 2010. As of June 30, 2009, NU parent had $87 million of LOCs issued for the benefit of certain subsidiaries (primarily PSNH) and $234.4 million of borrowings outstanding under this facility. The weighted-average interest rate on these short-term borrowings as of June 30, 2009 was 0.85 percent, which is based on a variable rate plus an applicable margin based on NU parent's credit ratings. NU parent had approximately $161 million of borrowing availability on this facility as of June 30, 2009, excluding LBCB's commitment.

The regulated companies maintain a joint credit facility in a nominal aggregate amount of $400 million including the commitment of LBCB, which also expires on November 6, 2010. There were $259.6 million of borrowings outstanding under this facility as of June 30, 2009 ($114 million for CL&P, $45.2 million for PSNH, $75.1 million for WMECO, and $25.3 million for Yankee Gas). The weighted-average interest rate on these short-term borrowings as of June 30, 2009 was 0.82 percent, which is based on a variable rate plus an applicable margin based on the borrower's credit ratings. The regulated companies had approximately $102 million of aggregate borrowing availability on this facility as of June 30, 2009, excluding LBCB's commitment and subject to each individual company's borrowing limits.

Our credit facilities and bond indentures require that NU parent and certain of its subsidiaries, including CL&P, PSNH and WMECO, comply with certain financial and non-financial covenants as are customarily included in such agreements, including a consolidated debt to capitalization ratio. All such companies currently are, and expect to, remain in compliance with these covenants. Refer to Note 2, "Short-Term Debt," and Note 11, "Long-Term Debt," to our consolidated financial statements included in the 2008 Form 10-K for further discussion of material terms and conditions of these agreements.

Impact of Financial Market Conditions: While the impact of continued market volatility and the extent and impacts of the current economic downturn cannot be predicted, we believe that we currently have sufficient operating flexibility and access to funding sources to maintain adequate liquidity. The credit outlooks for NU parent and our regulated companies are all stable. Our companies have low risk of calls for collateral due to our business model, as described further below. Cash contributions to our pension plan are not required until the third quarter of 2010, as further described below. We have no long-term debt maturing until April 2012, projected capital expenditures for 2009 of approximately $970 million are significantly less than 2008, and projected operating cash flows for 2009 are higher than 2008.

Our regulated standard offer type contracts do not require us to post collateral. In the event of an energy supplier's default under these contracts we could be required to provide standard offer type services directly to customers until a substitute supplier could be arranged. Such an event would require us to post additional collateral with ISO-NE. Our suppliers currently are performing on these contracts, and any additional costs we would incur from a supplier default would be recoverable from customers. In other regulated contracts that do contain collateral posting requirements, the counterparties are generally exposed to us at this time, and when we have been exposed to them, these counterparties have been posting the necessary collateral. As of June 30, 2009 and December 31, 2008, PSNH had posted $71 million and $75 million, respectively, in related collateral in the form of NU LOCs with counterparties. PSNH had an additional $10 million of LOCs posted with ISO-NE at June 30, 2009 and December 31, 2008. Also, our ongoing collateral requirements for Select Energy's few remaining wholesale contracts are not material as we continue to wind down this business. We have not experienced any significant performance difficulties with suppliers on Select Energy's remaining sourcing contracts. As of June 30, 2009, Select Energy had posted $28.3 million in collateral, as compared to $26.3 million as of December 31, 2008. Refer to "NU Enterprises Contracts - Counterparty Credit Risk" in this Management's Discussion and Analysis for further discussion.

As of January 1, 2008 our pension plan funded ratio (the value of plan assets divided by the funding target in accordance with the requirement of the Pension Protection Act) was 111 percent. We have not been required to make a contribution to the plan since 1991. Due primarily to the negative financial market conditions experienced in 2008, the fair value of our pension plan assets dropped by approximately $900 million to $1.56 billion as of January 1, 2009, which resulted in a projected funding ratio of approximately 77 percent. At this funding level, we had previously reported the need to provide estimated contributions to the plan of approximately $300 million to $350 million in 2010.

The Internal Revenue Service recently issued guidance to determine a plan's benefit liabilities for funding purposes. Using this guidance, we have revised our previous contribution estimates and are currently estimating a pretax contribution to the plan of approximately $50 million in order to meet minimum funding requirements for the plan year beginning January 1, 2009. This contribution would occur in the third quarter of 2010. No cash contribution will be required to be made in 2010 for the plan year beginning January 1, 2010. We have not yet determined the amount of contributions for the 2010 plan year required to be made in 2011 or contributions for future plan years, but such amounts could be substantial.

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 $415.3 million in the first half of 2009, compared with $658.4 million in the first half of 2008. These amounts included $18 million and $8.7 million in the first half of 2009 and 2008, respectively, that related to our corporate service company and other affiliated companies that support the regulated companies.

Regulated Companies: Capital expenditures for the regulated companies are expected to total approximately $970 million in 2009, which includes planned spending of our corporate service company and other affiliated companies that support the regulated companies. This increase of approximately $50 million from previous projections is due primarily to higher expected capital expenditures in the transmission segment described below.

Transmission Segment: Transmission segment capital expenditures decreased by $298.7 million in the first half of 2009, as compared with the same period in 2008, due primarily to reduced expenditures at CL&P, which completed three major transmission projects in southwest Connecticut in the second half of 2008. Capital expenditures for the consolidated transmission segment are expected to total approximately $275 million ($147 million for CL&P), which is higher than the previously announced amount of approximately $225 million in 2009 ($97 million for CL&P), due to a change in the timing of capital investments. A summary of transmission segment capital expenditures by company in the first half of 2009 and 2008 is as follows:


	For the Six Months Ended June 30,
(Millions of Dollars)		2009		2008
CL&P	$	75.4	$	368.7
PSNH		27.3		41.0
WMECO		24.9		15.6
HWP		-		1.0*
Totals	$	127.6	$	426.3

Represents capital additions of Holyoke Water Power Company (HWP) and its former subsidiary, Holyoke Power and Electric Company (HP&E), which were transferred to WMECO in December 2008. Effective July 31, 2009, HP&E was merged into HWP, and HWP assumed all assets and liabilities of HP&E.

In October 2008, we commenced state siting filings for our current series of major transmission projects, NEEWS. That series of projects involves our construction of new overhead 345 kilovolt (KV) lines in Massachusetts and Connecticut as well as associated substation work and 115 KV rebuilds. One of the projects will connect to a new transmission line that National Grid USA plans to build in Rhode Island and Massachusetts. On September 24, 2008, ISO-NE issued its technical approval of the NEEWS projects, which was a precursor to the siting application process. We continue to estimate that CL&P's and WMECO's total capital expenditures for these projects will be $1.49 billion through 2013, although the timing of projected annual capital spending could be affected if receipt of siting approvals is delayed or if the need dates for these projects change through ISO-NE's regional system planning process. Since inception of the project through June 30, 2009, CL&P and WMECO have capitalized approximately $48.1 million and $48.2 million, respectively, in costs associated with NEEWS, of which $14.9 million and $13.9 million, respectively, were capitalized in the first half of 2009. Transmission capital spending is driven by a number of factors, including the federal reliability requirements of the North American Electrical Reliability Corporation (NERC) and peak load growth. As those NERC requirements evolve and as projections of peak load growth are updated, the timing of some of our principal projects will continue to be evaluated by us and by ISO-NE as part of its regional system planning process.

The first of the NEEWS projects, GSRP, which involves the construction of a 115 KV/345 KV line from Ludlow, Massachusetts to North Bloomfield, Connecticut, is the largest and most complicated project within NEEWS. This project is expected to cost approximately $714 million if built according to our preferred route configuration. CL&P filed its application to build the Connecticut portion of the GSRP with the Connecticut Siting Council (CSC) on October 20, 2008. WMECO filed its application to build its portion of the project with the Massachusetts Energy Facilities Siting Board (MAEFSB) on October 27, 2008. Public hearings before the MAEFSB and CSC began in May 2009 and June 2009, respectively. Evidentiary hearings before the CSC took place in July 2009 and are expected to begin before the MAEFSB in October 2009. The discovery phases of both state proceedings are currently ongoing. The Connecticut Energy Advisory Board received three proposals in response to a formal request for alternatives to the GSRP. One of the proposals is for construction of a combined cycle generating facility in lieu of the GSRP. The CSC is considering this application in parallel with the GSRP application to ascertain which project satisfies the reliability needs identified by ISO-NE. In June 2009, ISO-NE reaffirmed that the need date for GSRP does not have to be changed. Following decisions by the state siting boards, which are expected in March 2010 in Connecticut and mid-2010 in Massachusetts, we expect to commence construction in late 2010/early 2011 and to place the project in service in late 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 continue to estimate CL&P's share of this project will cost approximately $250 million. Municipal consultations concluded in November 2008, and CL&P plans to file its siting application with Connecticut regulators in late 2009 or early 2010, depending on when ISO-NE completes its evaluation of the need date for this project as part of its regional system planning process. We currently expect the project to be placed in service in late 2013.

The third 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 would be six to twelve months behind the Interstate Reliability Project, and CL&P currently expects to file the siting application in 2010. ISO-NE continues to evaluate the need date for this project as part of its regional system planning process. This project is currently expected to be placed in service after the other two projects at an estimated cost of approximately $315 million. Included as part of NEEWS are approximately $210 million of associated reliability related expenditures, some of which may be incurred in advance of the three major projects.

During the siting approval process, state regulators may require changes in configuration 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.

On May 22, 2009, the FERC granted the petition for a declaratory order requested by NU and NSTAR approving a new participant-funded transmission tie line connecting New England with the Hydro-Québec system in order for HQUS to sell and deliver into New England at least 1,200 MW of firm electric power from Canadian low-carbon energy resources. The FERC order requires the terms and conditions of the transmission services agreement to be filed with the FERC, which we expect to occur by the end of 2009. Critical components of the project include the location of the southern terminus of the new line and the negotiation of power purchase agreements (PPAs) between HQUS and New England utilities and other entities for terms that are expected to be at least 20 years. We anticipate that the PPAs can be successfully negotiated with interested New England utilities and filed with respective state commissions by the end of 2009 or in early 2010 for required approvals. Among other permits and approvals, this transmission project would require state siting approvals and technical approval from ISO-NE as appropriate. We believe that all approvals will be in place to permit the commencement of construction in 2011, at an estimated cost to NU of $525 million, and transmission of power

over the new line will commence in 2014. In June 2009, two generator associations that had protested our original petition filed requests for rehearing on the FERC order, which were responded to by NU and NSTAR. In July 2009, the FERC granted rehearing but has not indicated when an order on rehearing will be issued.

Distribution Segment: Distribution segment capital expenditures increased by $46.3 million in the first half of 2009, as compared with the same period in 2008, primarily due to increased generation business capital expenditures at PSNH related to its Clean Air Project further described below and the absence in 2009 of a $17.5 million capital cost recovery by Yankee Gas related to a legal settlement in February 2008. We currently expect capital expenditures for the consolidated distribution segment to total approximately $645 million in 2009 ($285 million for CL&P and $153 million for the PSNH generation business). Due to lower economic growth, increased conservation and load management and internal strategies to reduce capital spending, we currently expect to reduce our projected capital expenditures over the next five years by $200 million.

A summary of distribution segment capital expenditures by company in the first half of 2009 and 2008 is as follows:


		For the Six Months Ended June 30,
(Millions of Dollars)		2009		2008
CL&P	$	133.6	$	131.6
PSNH		45.7		44.0
WMECO		16.8		15.9
Totals - Electric distribution (excluding generation)		196.1		191.5
Yankee Gas		23.8		6.2
Other		0.2		0.3
Total distribution		220.1		198.0
PSNH generation		49.6		25.4
Total distribution segment	$	269.7	$	223.4

PSNH's Clean Air Project is currently expected to cost $457 million, which will be recovered through PSNH's generation rates under New Hampshire law. Construction is ahead of schedule and on budget, and PSNH currently expects to complete the project by mid-2012. Since inception of the project, PSNH capitalized approximately $70.3 million associated with this project, of which $42.8 million was capitalized in the first half of 2009. We expect total spending on this project to be approximately $145 million by the end of 2009. Refer to "Regulatory Developments and Rate Matters - New Hampshire - Merrimack Clean Air Project" for further discussion.

Smart Grid and Other Strategic Initiatives: We continue to evaluate certain development projects that would benefit our customers, such as investments in advanced metering infrastructure (AMI) systems and other projects that are detailed below:

On June 1, 2009, CL&P commenced a three-month, time-based rate smart grid pilot program that involves nearly 3,000 customers. The pilot is testing nearly 1,500 residential and 1,500 commercial and industrial customers' interest in and response to peak time-based energy rates, coupled with smart meters. CL&P will file a report on the pilot's results with the DPUC by December 1, 2009. The cost of the pilot is estimated to be $13 million and is authorized to be recovered through CL&P rates.

On June 18, 2009, WMECO and the AG filed a stipulation agreement with the DPU in which the AG agreed to support WMECO's initial proposal, under the Massachusetts Green Communities Act of 2007 (GCA), to install 6 MW of solar energy generation in its service territory at an estimated cost of approximately $40 million. Under the agreement, the projects would be commissioned in 2010 through 2012, no more than 3 MW could be commissioned in any given year, the ROE would be fixed at 9 percent and the benefits of renewable energy and tax credits will be used to reduce the impact on customer bills. Briefs were filed with the DPU on July 14, 2009. WMECO expects a decision from the DPU by August 12, 2009. WMECO would need to file an additional application with the DPU if it seeks to develop more than the initial 6 MW under the GCA, which allows for electric utility ownership of up to 50 MW of solar energy generating facilities.

On August 6, 2009, we filed an application with the DOE through CL&P, PSNH and WMECO for federal stimulus funding of 50 percent to match our investment in a $253 million project involving, among other things, the installation of smart grid technology in Connecticut, New Hampshire and Massachusetts, as well as expanded access to advanced meters for over 200,000 of our customers. This application was made through the DOE's Smart Grid Investment Grant program for matching funds available as a result of the American Recovery and Reinvestment Act of 2009 to cover eligible expenditures, the majority of which is expected to be incurred at CL&P. The specific projects included in this application and related financial investment of CL&P, PSNH and WMECO are subject to approval from respective state regulatory commissions.

The estimated capital expenditures discussed above do not include expenditures for these initiatives, except for the CL&P AMI pilot program.

Transmission Rate Matters

Transmission - Wholesale Rates: NU's transmission rates recover total transmission revenue requirements, ensuring that we recover all regional and local revenue requirements. These rates provide for annual true-ups to actual costs. The financial impacts of differences between actual and projected costs are deferred for future recovery from or refund to customers. As of June 30, 2009, NU was in a total underrecovery position of $26.5 million ($21.2 million for CL&P).

Legislative Matters

2009 Federal Legislation: On February 17, 2009, President Obama signed into law The American Recovery and Reinvestment Act of 2009. We expect to benefit from the Act's extension of tax rules allowing the accelerated deduction of depreciation, which we project will positively impact cash flow by approximately $80 million in 2009. We may also benefit from the Act's grant provisions. As discussed in "Business Development and Capital Expenditures-Smart Grid and Other Strategic Initiatives" in this Management's Discussion and Analysis, we have a pending application with the DOE for funding of 50 percent on a $253 million project involving, among other things, the installation of smart grid technology and the expansion of advanced meters in our service regions. We also expect to benefit from the Act's solar credit provisions. We are continuing to evaluate further opportunities but cannot estimate at this time any impact that the Act will have on our earnings.

It is possible that the United States Environmental Protection Agency will adopt regulations and/or Congress will enact legislation addressing climate change and carbon constraints. Any such regulations or laws will likely impact PSNH's generating plants and possibly the prices that CL&P and WMECO pay for generation service. Until any regulations are adopted or legislation is enacted, we are unable to determine the actual impacts on any of our companies. We would anticipate recovering related costs from customers.

Regulatory Developments and Rate Matters

Connecticut - CL&P:

Distribution Rates: CL&P implemented new distribution rates in 2009 to reflect the DPUC's 2008 decision allowing a $20.1 million annualized increase in distribution rates, effective February 1, 2009. CL&P continues to evaluate filing a new distribution rate case in either late 2009 or in 2010.

Renewable Energy Contracts: In May 2009, pursuant to Connecticut's "Act Concerning Energy Independence," the DPUC approved five renewable energy plant projects with total capacity of 27.3 MW. Contracts for the purchase of energy, capacity and renewable energy certificates from these projects have been signed by CL&P and approved by the DPUC on August 4, 2009. Purchases under the contracts are scheduled to begin from September 2010 through July 2011 and to extend for 15 to 20 years. As directed by the DPUC, CL&P and The United Illuminating Company (UI) have signed a sharing agreement under which they will share the costs and benefits of these contracts with 80 percent to CL&P and 20 percent to UI. CL&P's portion of the costs and benefits of these contracts will be paid by or refunded to CL&P's customers.

Standard Service and Last Resort Service Rates: CL&P's residential and small commercial customers who do not choose competitive suppliers are served under Standard Service (SS) rates, and large commercial and industrial customers who do not choose competitive suppliers are served under Last Resort Service (LRS) rates. Effective April 1, 2009, the DPUC approved a decrease to CL&P's total average LRS rates of approximately 22 percent, which was a result of the energy supply portion decreasing to 8.207 cents per kilowatt-hour (kWh) from 11.738 cents per kWh in the previous three-month period. Effective July 1, 2009, the DPUC approved total average SS rates that did not change from the previous rates, however, the energy supply portion of the rates increased from 12.316 cents per kWh to 12.516 cents per kWh. The DPUC also approved a decrease to CL&P's total average LRS rates of approximately 2.3 percent, which was primarily the result of the energy supply portion decreasing to 7.944 cents per kWh. CL&P is fully recovering from customers the costs of its SS and LRS services.

CTA and SBC Reconciliation: On March 31, 2009, CL&P filed with the DPUC its 2008 Competitive Transition Assessment (CTA) and Systems Benefit Charge (SBC) reconciliation, which compared CTA and SBC revenues to revenue requirements. For the 12 months ended December 31, 2008, total CTA revenues exceeded CTA revenue requirements by $84.9 million, which has been recorded as a decrease to Regulatory assets on the accompanying unaudited condensed consolidated balance sheet. For the 12 months ended December 31, 2008, the SBC revenues exceeded SBC cost of service by $2.5 million, which has been recorded as a decrease to Regulatory assets on the accompanying unaudited condensed consolidated balance sheet. We expect a decision in this docket from the

DPUC by the end of 2009 and do not expect the outcome to have a material adverse impact on CL&P's earnings, financial position or cash flows.

FMCC Filing: On February 6, 2009, CL&P filed with the DPUC its semi-annual FMCC filing, which reconciled actual FMCC revenues and charges and GSC revenues and expenses, for the period July 1, 2008 through December 31, 2008, and also included the previously filed revenues and expenses for the January 1, 2008 through June 30, 2008 period. The filing identified an underrecovery for the full year totaling approximately $31.9 million, which has been recorded as a Regulatory asset on the accompanying unaudited condensed consolidated balance sheets. The DPUC held a hearing on this filing on April 9, 2009 with a final decision expected in the third quarter of 2009. We do not expect the outcome of the DPUC's review of this filing to have a material adverse impact on CL&P's earnings, financial position or cash flows.

2008 Management Audit: On August 18, 2008, a consulting firm hired by the DPUC began an on-site management audit of CL&P, which is required to be conducted every six years by statute and requires a diagnostic review of all functions of the Company. The audit has been completed; however, a final audit report has not yet been published by the DPUC. We do not expect a material impact to CL&P's earnings, financial position or cash flows from the results of this audit.

New Hampshire:

Distribution Rates, ES, SCRC, and TCAM Filings: On April 17, 2009, PSNH filed an application with the NHPUC to increase its distribution rates by approximately $36.4 million annually on a temporary basis, to be effective on August 1, 2009. PSNH subsequently filed with the NHPUC requests for changes in its Energy Service (ES) rate, Stranded Cost Recovery Charge (SCRC) rate and Transmission Cost Adjustment Mechanism (TCAM) rate to be effective August 1, 2009.

On June 30, 2009, PSNH filed an application with the NHPUC requesting a permanent increase in distribution rates of approximately $51 million on an annualized basis to be effective on August 1, 2009, and another $17 million effective July 1, 2010. A procedural schedule for this rate case has not yet been issued.

On July 31, 2009, the NHPUC issued an order accepting a settlement agreement entered into by PSNH and the NHPUC staff, which resolved all issues regarding PSNH's request for temporary rates. In the settlement agreement, PSNH and the NHPUC staff agreed on a temporary increase of $25.6 million in distribution rates on an annualized basis, effective August 1, 2009. Included in the $25.6 million temporary increase is $6 million to begin the recovery of PSNH's deferral of storm costs incurred in December 2008. On July 23 and 24, 2009, the NHPUC issued orders approving the ES, SCRC, and TCAM rates as filed. The combined result of these approved rate changes was a net decrease of approximately one percent in rates billed to PSNH customers who purchase energy from PSNH. PSNH expects a decision on the permanent distribution rate request in mid-2010. Any differences between temporary and permanent rates will be reconciled back to August 1, 2009.

ES and SCRC Reconciliation: On an annual basis, PSNH files with the NHPUC an ES/SCRC reconciliation filing for the preceding year. On May 1, 2009, PSNH filed its 2008 ES/SCRC reconciliation with the NHPUC, whose evaluation includes a prudence review of PSNH's generation activities. During 2008, ES revenues exceeded ES costs by $20.7 million, and SCRC costs exceeded SCRC revenues by $6.4 million, resulting in an ES regulatory liability for refunds to customers and a SCRC regulatory asset for costs that will be recovered from customers. 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: In 2006, New Hampshire enacted a statute requiring PSNH to reduce the mercury emissions from its coal-fired stations by at least 80 percent through the installation of wet scrubber technology at its Merrimack Station in Bow, New Hampshire no later than July 1, 2013. The installation is currently expected to cost $457 million. On December 11, 2008, several parties filed an appeal with the New Hampshire Supreme Court requesting that the court overturn a previous ruling by the NHPUC that it lacked present authority to find whether the project is in the public interest. On August 5, 2009, the court dismissed that appeal, holding that the appellants were not harmed and thus lacked standing to bring their challenge. Separately, the New Hampshire Site Evaluation Committee voted on July 7, 2009 that it does not need to review the project.

Massachusetts:

Basic Service Rates: Effective April 1, 2009, the basic service rates for medium and large commercial and industrial customers decreased from 10.205 cents per kWh to 7.679 cents per kWh. Effective July 1, 2009, the rates for all basic service customers decreased due to the decline in the cost of energy, as reflected in WMECO's basic service solicitations. Basic service rates for residential customers decreased from 11.805 cents per kWh to 8.554 cents per kWh, small commercial and industrial customers decreased from 12.074 cents per kWh to 9.179 cents per kWh and rates for medium and large commercial and industrial customers decreased from 7.679 cents per kWh to 7.256 cents per kWh.

Transition Cost Reconciliation: On July 18, 2008, WMECO filed its 2007 transition cost (TC) reconciliation with the DPU, which compared TC revenue and revenue requirements. The DPU issued a decision on June 2, 2009, which did not have a material adverse impact on WMECO's earnings, financial position or cash flows.

On July 2, 2009, WMECO filed the 2008 cost reconciliation for transition, transmission, basic/default service, basic/default service adder, and capital projects scheduling list. There is currently no timeline for the DPU's review of this filing. 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. There is currently no timeline for the DPU's review of this filing. 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.

Contingent Matter:

C2 Prudency Audit: Pursuant to the decision in CL&P's 2007 rate case, the DPUC has hired a consulting firm to perform a prudency audit of certain costs incurred in the implementation of a new customer service system (C2) at CL&P. The audit began on December 1, 2008 and is near completion. The DPUC intends to open a docket to review the findings of the audit after completion. We continue to believe that our C2 expenses were prudent and will be recovered in rates. We do not expect the outcome of the DPUC's review of this audit to have a material adverse impact on CL&P's earnings, financial position or cash flows.

NU Enterprises Divestitures

We have exited most of our competitive businesses. NU Enterprises continues to manage to completion its remaining wholesale marketing contracts and to manage its energy services activities.

Wholesale Marketing: During the first half of 2009, Select Energy continued to manage its long-term wholesale sales contract with the New York Municipal Power Agency (NYMPA), an agency comprised of municipalities, that expires in 2013, and related supply contracts. In addition to the NYMPA portfolio, Select Energy has a contract to operate and purchase the output of a certain generating facility in New England through mid-2012.

Energy Services: Most of NU Enterprises' energy services businesses were sold in 2005 and 2006. Certain other businesses were wound down in 2007, and we continue to wind down minimal activity at the other energy services businesses. However, we continue to own and manage one energy services business, E.S. Boulos Company (Boulos), which is an electrical contractor based in Maine.

NU Enterprises Contracts

Wholesale Derivative Contracts: As of June 30, 2009 and December 31, 2008, NU Enterprises' wholesale derivative liabilities (through its subsidiary Select Energy) were subject to mark-to-market accounting. Numerous factors could either positively or negatively affect the realization of the wholesale derivative net fair value amounts in cash. These factors include the volatility of commodity prices until the derivative contracts result in deliveries, are exited or expire, differences between expected and actual volumes, the performance of counterparties, and other factors.

Select Energy has policies and procedures requiring all of its wholesale derivative energy positions to be valued daily and segregating responsibilities between the individuals actually transacting (front office) and those confirming the trades (middle office). The middle office is responsible for determining the portfolio's fair value independent from the front office.

The methods Select Energy used to determine the fair value of its wholesale derivative contracts are identified and segregated in the table of fair value of wholesale derivative contracts as of June 30, 2009 and December 31, 2008. A description of each method is as follows: 1) prices actively quoted primarily represent NYMEX futures and swaps that are marked to closing exchange prices; and 2) prices provided by external sources primarily include over-the-counter forwards and options, including bilateral contracts for the purchase or sale of electricity, and are marked to the mid-point of bid and ask market prices. The mid-points of market prices are adjusted to include all applicable market information, such as historical experience with intra-month price volatility and exit pricing assumptions. Currently, a portion of the NYMPA contract's fair value related to intra-month volatility and an exit price premium are determined based upon a model. For the commodity pricing, broker quotes for electricity prices are available for on-peak and off-peak periods throughout the period of the NYMPA contract.

Generally, valuations of short-term derivative contracts derived from quotes or other external sources are more reliable should there be a need to liquidate the contracts, while valuations for longer-term derivative contracts are less certain. Accordingly, there is a risk that derivative contracts will not be realized at the amounts recorded.

The tables below disaggregate the estimated fair value of the wholesale derivative contracts. Valuations of individual contracts are broken into their component parts based upon prices actively quoted, prices provided by external sources and model-based amounts. Under SFAS No. 157, contracts are classified in their entirety according to the lowest level for which there is at least one input that is significant to the valuation. Therefore, all of these contracts are classified as Level 3 under SFAS No. 157. As of June 30, 2009 and December 31, 2008, the sources of the fair value of wholesale derivative contracts are included in the following tables:


	Fair Value of Wholesale Contracts as of June 30, 2009
(Millions of Dollars) Sources of Fair Value	Maturity Less than One Year		Maturity of One to Four Years		Maturity in Excess of Four Years		Total Fair Value
Prices actively quoted	$	(5.0)	$	(14.9)	$	(1.2)	$	(21.1)
Prices provided by external sources		-		(10.5)		(2.9)		(13.4)
Model-based⁽¹⁾		(1.8)		(7.2)		(1.2)		(10.2)
Totals	$	(6.8)	$	(32.6)	$	(5.3)	$	(44.7)


	Fair Value of Wholesale Contracts as of December 31, 2008
(Millions of Dollars) Sources of Fair Value	Maturity Less than One Year		Maturity of One to Four Years		Maturity in Excess of Four Years		Total Fair Value
Prices actively quoted	$	(10.1)	$	(7.3)	$	(1.2)	$	(18.6)
Prices provided by external sources		(2.7)		(21.2)		(10.0)		(33.9)
Model-based ⁽¹⁾		(1.7)		(6.7)		(3.0)		(11.4)
Totals	$	(14.5)	$	(35.2)	$	(14.2)	$	(63.9)

⁽¹⁾

The model-based amounts include the effects of implementing SFAS No. 157.

For the three and six months ended June 30, 2009, the changes in fair value of these contracts are included in the following table:


	For the Three Months Ended June 30, 2009		For the Six Months Ended June 30, 2009
(Millions of Dollars)	Total Portfolio Fair Value		Total Portfolio Fair Value
Fair value of wholesale contracts outstanding at the beginning of the period	$	(49.2)	$	(63.9)
Contracts realized or otherwise settled during the period ⁽¹⁾		2.3		11.8
Change in unrealized gains included in pre-tax earnings		2.2		7.4
Fair value of wholesale contracts outstanding at the end of the period	$	(44.7)	$	(44.7)

⁽¹⁾

Amount includes purchases, issuances and settlements of $2.1 million and $11.4 million for the three and six months ended June 30, 2009, and realized intra-month gains of $0.2 million and $0.4 million for the three and six months ended June 30, 2009.

For further information regarding Select Energy's derivative contracts, see Note 2, "Derivative Instruments," to the unaudited condensed consolidated financial statements.

Counterparty Credit: Counterparty credit risk relates to the risk of loss that Select Energy would incur because of non-performance by counterparties pursuant to the terms of their contractual obligations. Select Energy has established credit policies with regard to its counterparties to minimize overall credit risk. These policies require an evaluation of potential counterparties' financial condition (including credit ratings), collateral requirements under certain circumstances (including cash advances, LOCs, and parent guarantees), and the use of standardized agreements that allow for the netting of positive and negative exposures associated with a single counterparty. This evaluation results in Select Energy establishing credit limits prior to entering into contracts. The appropriateness of these limits is subject to continuing review. Concentrations among these counterparties may affect Select Energy's overall exposure to credit risk, either positively or negatively, in that the counterparties may be similarly affected by changes in economic, regulatory or other conditions. As of June 30, 2009, approximately 98 percent of Select Energy's counterparty credit exposure to wholesale counterparties was non-rated, and approximately 2 percent was collateralized. All of the non-rated credit exposure is comprised of one counterparty, which is a non-rated public entity that we have assessed as creditworthy. To date, this counterparty has met all of its contractual obligations.

Off-Balance Sheet Arrangements

Letters of Credit: NU 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, 2009, PSNH had posted $85 million in such NU LOCs, including $10 million with ISO-NE. In addition, Select Energy had posted a $2 million NU LOC with ISO-NE as of June 30, 2009.

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 5C, "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 or results of operations. 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 the 2008 Form 10-K. There have been no material changes with regard to these critical accounting policies and estimates.

Other Matters

Accounting Standards Issued But Not Yet Adopted and Accounting Standards Recently Adopted: For information regarding new accounting standards, see Notes 1B, "Summary of Significant Accounting Policies - Accounting Standards Issued But Not Yet Adopted," and Note 1C, "Summary of Significant Accounting Policies - Accounting Standards Recently Adopted," to the unaudited condensed consolidated financial statements.

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 most recent Annual Report on Form 10-K and the First Quarter 2009 Form 10-Q.

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

RESULTS OF OPERATIONS - NU CONSOLIDATED

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, 2009:


	Income Statement Variances (Millions of Dollars) 2009 over/(under) 2008
	Second Quarter		Percent		Six Months		Percent
Operating Revenues	$	(101)	(8)	%	$	(27)	(1)	%

Operating Expenses:
Fuel, purchased and net interchange power		(78)	(12)			(62)	(4)
Other operation		(2)	(1)			(41)	(8)
Maintenance		(14)	(20)			(22)	(18)
Depreciation		9	14			19	14
Amortization of regulatory (liabilities)/assets, net		(55)	(a)			(62)	(88)
Amortization of rate reduction bonds		3	7			6	6
Taxes other than income taxes		(5)	(8)			10	7
Total operating expenses		(142)	(12)			(152)	(6)

Operating Income		41	30			125	47

Interest expense, net		(1)	(2)			7	6
Other income, net		2	20			(7)	(31)
Income before income tax expense		44	54			111	67
Income tax expense		19	83			47	(a)
Net Income		25	42			64	54
Preferred dividends of subsidiary		-	-			-	-
Net Income attributable to controlling interests	$	25	43	%	$	64	55	%

(a) Percent greater than 100.

Net income attributable to controlling interests was $64 million higher for the first six months of 2009 versus 2008 due primarily to higher distribution and transmission earnings and the absence of a first quarter 2008 $29.8 million after-tax litigation settlement charge.

Comparison of the Second Quarter of 2009 to the Second Quarter of 2008

Operating Revenues


	For the Three Months Ended June 30,
(Millions of Dollars)	2009		2008		Variance
Electric distribution	$	1,007	$	1,098	$	(91)
Gas distribution		70		113		(43)
Total distribution		1,077		1,211		(134)
Transmission		128		84		44
Regulated companies		1,205		1,295		(90)
Competitive businesses		19		30		(11)
HWP & Other		-		-		-
NU consolidated	$	1,224	$	1,325	$	(101)

Operating revenues decreased $101 million in 2009 due primarily to lower revenues from the regulated companies ($90 million) and lower revenues from competitive businesses ($11 million). The lower regulated companies' revenues were due primarily to lower CL&P wholesale revenues as a result of decreased market revenue related to sales of independent power producers (IPP) purchased generation output to ISO-NE, and the recovery of a lower level of electric and gas distribution fuel and other expenses passed through to customers through regulatory tracking mechanisms. Competitive businesses' revenues decreased $11 million due primarily to lower Boulos revenues as a result of less work on transmission projects and a lower level of work in other areas in part due to the economic downturn.

Distribution segment revenues decreased $134 million due primarily to lower electric distribution revenues ($91 million) and lower gas distribution revenues ($43 million). Transmission segment revenues increased $44 million due primarily to a higher transmission investment base as a result of the completion of our southwest Connecticut projects in 2008.

Electric distribution revenues decreased $91 million due primarily to a decrease in the portion of electric distribution revenues that does not impact earnings ($89 million) and the component of revenues that does flow through to earnings ($2 million). The portion of electric distribution segment revenues that flows through to earnings decreased $2 million due primarily to lower retail electric sales ($9 million), partially offset by increases in CL&P retail rates. Gas distribution revenues decreased $43 million due primarily to decreased recovery of fuel costs primarily as a result of lower prices, partially offset by higher sales volumes. Retail electric sales decreased 6.3 percent and firm natural gas sales increased 0.3 percent in the second quarter of 2009 compared with the same period of 2008.

The $89 million decrease in electric distribution revenues that does not impact earnings consists of the portions of CL&P, PSNH and WMECO distribution revenues that are included in regulatory commission approved tracking mechanisms that track the recovery of certain incurred costs ($82 million) and revenues that are eliminated in consolidation ($7 million). The distribution revenue tracking components decreased $82 million due primarily to lower CL&P wholesale revenues as a result of decreased market revenue related to sales of IPP purchased generation output to ISO-NE ($70 million), lower recovery of generation service and related congestion charges ($59 million), partially offset by higher retail transmission revenues ($33 million) mainly as a result of the higher 2009 retail rates and higher CL&P delivery-related FMCC ($12 million). The tracking mechanisms allow for rates to be changed periodically with overcollections refunded to customers or undercollections recovered from customers in future periods.

Fuel, Purchased and Net Interchange Power

Fuel, purchased and net interchange power expenses decreased $78 million in 2009 due to lower costs at the four regulated companies. Fuel and purchased power expense from the regulated companies decreased primarily at Yankee Gas ($44 million) as a result of lower gas prices this year versus last year. The decreases for CL&P, PSNH and WMECO are $15 million, $14 million and $5 million respectively.

Other Operation

Other operation decreased $2 million in 2009 due primarily to lower competitive businesses' expenses ($14 million) and lower NU parent and other companies' expenses ($2 million), partially offset by higher regulated companies' distribution and transmission segment expenses ($13 million).

Competitive businesses' expenses were lower by $14 million due primarily to lower Boulos expenses as a result of a lower level of work in part due to the economic downturn.

Higher regulated companies' distribution and transmission segment expenses of $13 million are due primarily to transmission segment intercompany billings to the distribution segment that are eliminated in consolidation and further costs that are eliminated on an NU consolidated basis ($6 million), higher transmission segment expenses ($3 million), Yankee Gas expenses ($2 million) and higher costs that are tracked and recovered through distribution tracking mechanisms ($2 million).

Maintenance

Maintenance expenses decreased $14 million in 2009 due primarily to lower regulated companies' distribution expenses ($14 million) and lower transmission line expenses ($1 million). Distribution expenses were $14 million lower due primarily to lower PSNH generation expenses as a result of the Merrimack Station Unit 2 maintenance outage that are tracked and recovered through NHPUC approved tracking mechanisms ($5 million), lower distribution line maintenance expenses ($4 million) as a result of lower storm-related expense, lower tree trimming ($2 million) primarily at PSNH and lower equipment maintenance expenses ($1 million).

Depreciation

Depreciation increased $9 million in 2009 due primarily to higher regulated transmission and distribution plant balances resulting from completed construction programs put into service.

Amortization of Regulatory (Liabilities)/Assets, Net

Amortization of regulatory (liabilities)/assets, net decreased $55 million in 2009 for the distribution segment due primarily to lower amortization at CL&P resulting from a lower recovery of transition costs ($58 million) resulting primarily from the lower CL&P retail CTA revenues and higher transition costs, partially offset by higher amortization of the SBC balance ($2 million).

Amortization of Rate Reduction Bonds

Amortization of RRBs increased $3 million in 2009. The higher portion of principal within the RRB payments results in a corresponding increase in the amortization of RRBs.

Taxes Other than Income Taxes

Taxes other than income taxes decreased $5 million in 2009 due primarily to the favorable resolution of various routine tax issues ($8 million), partially offset by higher Connecticut gross earnings tax recoverable in rates ($3 million), mainly as a result of higher CL&P revenues that are subject to gross earnings tax, and higher property taxes at PSNH and CL&P ($2 million).

Interest Expense, Net

Interest expense, net decreased $1 million in 2009 due primarily to lower other interest ($8 million) mostly related to the resolution of various routine tax issues and lower RRB interest resulting from lower principal balances outstanding ($3 million), partially offset by higher long-term debt interest ($10 million) resulting from the issuance of new long-term debt in 2008 and 2009.

Other Income, Net

Other income, net increased $2 million in 2009 due primarily to higher interest and investment income ($7 million) and lower investment losses ($1 million), mostly related to the supplemental benefit trust, partially offset by lower AFUDC equity income ($4 million) as a result of lower eligible construction work in progress (CWIP) balances and lower Energy Independence Act incentives ($3 million).

Income Tax Expense

Income tax expense increased $19 million due primarily to higher pre-tax earnings ($14 million) and flow through impacts ($2 million).

Comparison of the First Six Months of 2009 to the First Six Months of 2008

Operating Revenues


	For the Six Months Ended June 30,
(Millions of Dollars)	2009		2008		Variance
Electric distribution	$	2,252	$	2,296	$	(44)
Gas distribution		272		312		(40)
Total distribution		2,524		2,608		(84)
Transmission		256		173		83
Regulated companies		2,780		2,781		(1)
Competitive businesses		38		63		(25)
HWP & Other		-		1		(1)
NU consolidated	$	2,818	$	2,845	$	(27)

Operating revenues decreased $27 million in 2009 due primarily to lower revenues from the competitive businesses ($25 million) and lower revenues from regulated companies ($1 million). Competitive businesses' revenues decreased $25 million due primarily to lower Boulos revenues as a result of less work on transmission projects and a lower level of work in part due to the economic downturn.

Distribution segment revenues decreased $84 million due primarily to lower electric distribution revenues ($44 million) and lower gas distribution revenues ($40 million). Transmission segment revenues increased $83 million due primarily to a higher transmission investment base as a result of the completion of our southwest Connecticut projects in 2008.

Electric distribution revenues decreased $44 million due primarily to a decrease in the portion of electric distribution revenues that does not impact earnings ($56 million), partially offset by the component of revenues that does flow through to earnings ($12 million). The portion of electric distribution segment revenues that flows through to earnings increased $12 million due primarily to increases in CL&P retail rates, partially offset by lower sales volumes. Gas distribution revenues decreased $40 million due primarily to decreased recovery of fuel costs, partially offset by higher sales volumes. Retail electric sales decreased 3.8 percent and firm natural gas sales increased 8.8 percent in 2009 compared with 2008.

The $56 million decrease in electric distribution revenues that does not impact earnings consists of revenues that are eliminated in consolidation ($32 million) and the portions of CL&P, PSNH and WMECO distribution revenues that are included in regulatory commission approved tracking mechanisms that track the recovery of certain incurred costs ($24 million). The distribution revenue tracking components decreased $24 million due primarily to lower CL&P wholesale revenues as a result of a decrease in the market

revenue related to sales of IPP purchased generation output to ISO-NE ($97 million) and lower recovery of generation service and related congestion charges ($47 million), partially offset by higher retail transmission revenues ($76 million) mainly as a result of the higher 2009 retail rates, and higher CL&P delivery-related FMCC ($26 million), higher PSNH SCRC revenues ($9 million) and PSNH Northern Wood Power Plant renewable energy certificate revenues ($5 million). The tracking mechanisms allow for rates to be changed periodically with overcollections refunded to customers or undercollections recovered from customers in future periods.

Fuel, Purchased and Net Interchange Power

Fuel, purchased and net interchange power expenses decreased $62 million in 2009 due to lower costs at the regulated companies ($57 million) and lower competitive businesses expenses ($5 million). Fuel and purchased power expense from the regulated companies decreased primarily at Yankee Gas ($49 million) due to a decrease in gas prices this year versus last year. Competitive businesses' expenses decreased due to lower Select Energy mark-to-market expenses related to the remaining wholesale marketing contracts, including the 2008 expense associated with the implementation of SFAS No. 157.

Other Operation

Other operation decreased $41 million in 2009 due primarily to lower NU parent and other companies' expenses ($51 million) and lower competitive businesses' expenses ($27 million), partially offset by higher regulated companies' distribution and transmission segment expenses ($37 million).

NU parent and other companies' expenses were lower by $51 million in 2009 due primarily to the 2008 $49.5 million payment resulting from the settlement of litigation. Competitive businesses' expenses were lower by $27 million due primarily to lower Boulos expenses as a result of a lower level of work in part due to the economic downturn.

Higher regulated companies' distribution and transmission segment expenses of $37 million are due primarily to higher electric distribution segment expenses ($16 million), higher costs that are tracked and recovered through distribution tracking mechanisms ($7 million), higher transmission segment expenses ($7 million), higher Yankee Gas expenses ($6 million) and transmission segment intercompany billings to the distribution segment that are eliminated in consolidation and further costs that are eliminated on an NU consolidated basis ($1 million).

Maintenance

Maintenance expenses decreased $22 million in 2009 due primarily to lower regulated companies' distribution expenses ($21 million) and lower transmission line expenses ($1 million). Distribution expenses were $21 million lower due primarily to lower overhead line maintenance expenses ($18 million) primarily as a result of lower storm-related expenses, lower PSNH generation expenses as a result of the Merrimack Station Unit 2 maintenance outage that are tracked and recovered through NHPUC approved tracking mechanisms ($6 million), partially offset by higher tree trimming expenses ($4 million). PSNH and WMECO 2009 storm related expenses were primarily for additional work in the after-math of the December 2008 ice storm that were not expensed, but rather recorded to their respective major storm reserves.

Depreciation

Depreciation increased $19 million in 2009 due primarily to higher regulated transmission and distribution plant balances resulting from completed construction programs put into service.

Amortization of Regulatory (Liabilities)/Assets, Net

Amortization of regulatory (liabilities)/assets, net decreased $62 million in 2009 for the distribution segment due primarily to lower amortization at CL&P resulting from a lower recovery of transition costs ($71 million) as a result of lower retail CTA revenue and higher transition costs, partially offset by higher amortization of the SBC balance ($9 million).

Amortization of Rate Reduction Bonds

Amortization of RRBs increased $6 million in 2009. The higher portion of principal within the RRB payments results in a corresponding increase in the amortization of RRBs.

Taxes Other than Income Taxes

Taxes other than income taxes increased $10 million in 2009 due primarily to higher Connecticut gross earnings tax recoverable in rates ($11 million), mainly as a result of higher CL&P revenues that are subject to gross earnings tax, higher property taxes at PSNH and CL&P ($5 million), partially offset by the resolution of various routine tax issues ($8 million).

Interest Expense, Net

Interest expense, net increased $7 million in 2009 due primarily to higher long-term debt interest ($23 million) resulting from the issuance of new long-term debt in 2008 and 2009, partially offset by lower other interest ($10 million) mostly related to the resolution of various routine tax issues and lower RRB interest resulting from lower principal balances outstanding ($6 million).

Other Income, Net

Other income, net decreased $7 million in 2009 due primarily to lower AFUDC equity income ($12 million) as a result of lower eligible CWIP balances and lower Energy Independence Act incentives ($5 million), partially offset by lower investment losses ($4 million), higher interest and investment income ($4 million) mostly related to the supplemental benefit trust.

Income Tax Expense

Income tax expense increased $47 million due primarily to higher pre-tax earnings ($33 million), lower favorable flow through impacts ($5 million) and higher state taxes ($6 million).

THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES

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

CL&P is a wholly owned subsidiary of NU. This discussion should be read in conjunction with NU's Management's Discussion and Analysis of Financial Condition and Results of Operations, unaudited condensed consolidated financial statements and footnotes in this Form 10-Q, the First Quarter 2009 Form 10-Q and the 2008 Form 10-K.

RESULTS OF OPERATIONS

The following table provides the variances in income statement line items for the unaudited condensed consolidated statements of income for CL&P included in this Quarterly Report on Form 10-Q for the three and six months ended June 30, 2009:


	Income Statement Variances (Millions of Dollars) 2009 over/(under) 2008
	Second Quarter		Percent		Six Months		Percent
Operating Revenues	$	(37)	(4)	%	$	32	2	%

Operating Expenses:
Fuel, purchased and net interchange power		(15)	(4)			6	1
Other operation		(1)	(1)			9	4
Maintenance		(5)	(16)			(8)	(12)
Depreciation		7	18			15	19
Amortization of regulatory assets, net		(53)	(94)			(59)	(78)
Amortization of rate reduction bonds		3	8			5	7
Taxes other than income taxes		(1)	(2)			10	12
Total operating expenses		(65)	(9)			(22)	(1)

Operating Income		28	32			54	30

Interest expense, net		1	4			4	6
Other income, net		(1)	(15)			(11)	(50)
Income before income tax expense		26	41			39	30
Income tax expense		14	82			20	53
Net Income	$	12	26	%	$	19	21	%

Comparison of the Second Quarter of 2009 to the Second Quarter of 2008

Operating Revenues

Operating revenues decreased $37 million due to lower distribution segment revenues ($68 million), partially offset by higher transmission segment revenues ($31 million).

The distribution segment revenues decreased $68 million due primarily to a decrease in the portion of distribution revenues that does not impact earnings ($69 million) as a result of the inclusion of distribution revenues in regulatory tracking mechanisms and consolidation eliminations, partially offset by an increase in the portion of revenues that flows through to earnings ($1 million).

The $69 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 ($68 million) and transmission segment intracompany billings to the distribution segment that are eliminated in consolidation ($2 million). The distribution revenues included in DPUC approved tracking mechanisms decreased $68 million due primarily to lower wholesale revenues as a result of decreased market revenue generated from the sale of CL&P's purchased IPP generation output to ISO-NE due to a decrease in the market price of energy ($70 million) and a decrease in revenues associated with the recovery of GSC and supply-related FMCC ($39 million), partially offset by higher retail transmission revenues ($28 million) and delivery-related FMCC ($12 million). The lower GSC and supply-related FMCC revenue was due primarily to lower sales resulting primarily from current economic conditions, weather-related impacts and some additional customer migration to third-party suppliers in 2009 as compared to 2008. The higher delivery-related FMCC revenue was due primarily to a larger prior year overrecovery being refunded to customers in 2008 as compared to 2009, partially offset by lower reliability must run costs built into the 2009 rate as compared to

2008. The tracking mechanisms allow for rates to be changed periodically with overcollections refunded to customers or undercollections recovered from customers in future periods.

The portion of revenues that flows through to earnings increased $1 million primarily as a result of rate changes, partially offset by lower retail sales. Retail sales as compared to the same period in 2008 decreased 12.8 percent for the industrial, 4.8 percent for the residential, and 3.3 percent for the commercial classes and total retail sales decreased overall by 5.3 percent.

Transmission segment revenues increased $31 million due primarily to a higher transmission investment base as a result of the completion of our southwest Connecticut projects in 2008.

Fuel, Purchased and Net Interchange Power

Fuel, purchased and net interchange power expense decreased $15 million due primarily to a decrease in GSC supply costs ($50 million) and other purchased power costs ($14 million), partially offset by higher deferred fuel and purchased power costs ($49 million), all of which are included in DPUC approved tracking mechanisms. The $50 million decrease in GSC supply costs was due primarily to a decrease in load resulting from current economic conditions, weather-related impacts and some additional migration to third-party suppliers. These GSC supply costs are the contractual amounts CL&P must pay to various suppliers that have been awarded the right to supply SS and LRS load through a competitive solicitation process. The $49 million increase in deferred fuel costs was due primarily to the combined effect of a second quarter 2008 net underrecovery of GSC and FMCC expenses as compared with a second quarter 2009 net overrecovery of these expenses.

Other Operation

Other operation expenses decreased $1 million due primarily to lower consolidation eliminations of transmission segment intracompany billing to the distribution segment ($2 million), lower distribution segment expenses ($2 million) and lower costs that are tracked and recovered through distribution tracking mechanisms ($1 million), partially offset by higher transmission segment expenses ($4 million).

Maintenance

Maintenance expenses decreased $5 million in 2009 due primarily to lower distribution lines expenses including lower storm expenses.

Depreciation

Depreciation expense increased $7 million due primarily to higher utility plant balances resulting from completed construction programs put into service.

Amortization of Regulatory Assets, Net

Amortization of regulatory assets, net decreased $53 million due primarily to lower amortization related to the recovery of transition charges ($58 million) as a result of lower retail CTA revenue and higher transition costs, partially offset by a higher amortization of the SBC balance ($2 million).

Amortization of Rate Reduction Bonds

Amortization of RRBs increased $3 million. The higher portion of principal within the RRBs' payment results in a corresponding increase in the amortization of regulatory assets.

Taxes Other Than Income Taxes

Taxes other than income taxes decreased $1 million due primarily to the favorable resolution of various routine tax issues ($4 million), partially offset by higher gross earnings taxes recoverable in rates as a result of higher distribution and transmission revenues that are subject to gross earnings tax ($4 million).

Interest Expense, Net

Interest expense, net, increased $1 million due primarily to higher long-term debt interest ($9 million) resulting from the $300 million debt issuance in May 2008 and the $250 million debt issuance in February 2009, partially offset by lower other interest ($5 million) mostly related to the resolution of various routine tax issues and lower RRB interest resulting from lower principal balances outstanding ($3 million).

Other Income, Net

Other income, net, decreased $1 million due primarily to a lower AFUDC equity income ($4 million) as a result of lower eligible CWIP due to large transmission projects being completed and placed in-service in 2008 and lower capital expenditures in 2009, and lower Energy Independence Act incentives ($3 million), partially offset by higher interest and investment income ($3 million), lower

investment losses ($1 million) due primarily to the supplemental benefit trust and an increase in conservation and load management incentives ($1 million).

Income Tax Expense

Income tax expense increased $14 million due primarily to higher pre-tax earnings ($7 million), flow through impacts ($3 million) and higher state taxes ($3 million).

Comparison of the First Six Months of 2009 to the First Six Months of 2008

Operating Revenues

Operating revenues increased $32 million due to higher transmission segment revenues ($68 million), partially offset by lower distribution segment revenues ($36 million).

Transmission segment revenues increased $68 million due primarily to a higher transmission investment base as a result of the completion of our southwest Connecticut projects in 2008.

The distribution segment revenues decreased $36 million due primarily to a decrease in the portion of distribution revenues that does not impact earnings ($50 million) as a result of the inclusion of distribution revenues in regulatory tracking mechanisms and costs that are eliminated in consolidation, partially offset by an increase in the portion of revenues that flows through to earnings ($13 million).

The $50 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 ($30 million) and transmission segment intracompany billings to the distribution segment that are eliminated in consolidation ($20 million). The distribution revenues included in DPUC approved tracking mechanisms decreased $30 million due primarily to lower wholesale revenues as a result of decreased market revenue generated from the sale of CL&P's purchased IPP generation output to ISO-NE due to a decrease in the market price of energy ($97 million) and a decrease in revenues associated with the recovery of GSC and supply-related FMCC ($32 million), partially offset by higher retail transmission revenues ($63 million) and delivery-related FMCC ($26 million). The lower GSC and supply-related FMCC revenue was due primarily to lower sales resulting from current economic conditions, weather-related impacts and some additional migration to third-party suppliers in 2009 as compared to 2008. The higher delivery-related FMCC revenue was due primarily to a larger prior year overrecovery being refunded to customers in 2008 as compared to 2009, partially offset by lower reliability must run costs built into the 2009 rate as compared to 2008. The tracking mechanisms allow for rates to be changed periodically with overcollections refunded to customers or undercollections recovered from customers in future periods.

The portion of revenues that flows through to earnings increased $13 million primarily as a result of rate changes ($17 million), partially offset by lower retail sales ($4 million). Retail sales as compared to the same period in 2008 decreased 18.4 percent and 2.8 percent for the industrial and commercial classes, respectively, partially offset by an increase of 0.6 percent for the residential class and total retail sales decreased overall by 3.3 percent.

Fuel, Purchased and Net Interchange Power

Fuel, purchased and net interchange power expense increased $6 million due primarily to an increase in deferred fuel and purchased power costs ($70 million), partially offset by lower GSC supply costs ($42 million) and other purchased power costs ($22 million), all of which are included in DPUC approved tracking mechanisms. The $70 million increase in deferred fuel costs was due primarily to the combined effect of a first half 2008 net underrecovery of GSC and FMCC expenses as compared with a first half 2009 net overrecovery of these expenses. The $42 million decrease in GSC supply costs was due primarily to a decrease in load resulting from current economic conditions, weather-related impacts and some additional customer migration to third-party suppliers. These GSC supply costs are the contractual amounts CL&P must pay to various suppliers that have been awarded the right to supply SS and LRS load through a competitive solicitation process.

Other Operation

Other operation expenses increased $9 million due primarily to higher transmission segment expenses ($7 million), higher distribution segment expenses ($7 million) due primarily to pension expenses, partially offset by lower transmission segment intracompany billing to the distribution segment that are eliminated in consolidation ($4 million).

Maintenance

Maintenance expenses decreased $8 million in 2009 due primarily to lower distribution lines expenses including lower storm expenses.

Depreciation

Depreciation expense increased $15 million due primarily to higher utility plant balances resulting from completed construction programs put into service.

Amortization of Regulatory Assets, Net

Amortization of regulatory assets, net decreased $59 million due primarily to lower amortization related to the recovery of transition charges ($71 million) as a result of lower retail CTA revenue and higher transition costs, partially offset by higher amortization of the SBC balance ($9 million).

Amortization of Rate Reduction Bonds

Amortization of RRBs increased $5 million. The higher portion of principal within the RRBs' payment results in a corresponding increase in the amortization of regulatory assets.

Taxes Other Than Income Taxes

Taxes other than income taxes increased $10 million due primarily to higher gross earnings taxes recoverable in rates as a result of higher distribution and transmission revenues that are subject to gross earnings tax ($12 million), higher property taxes as a result of higher plant balances and higher municipal tax rates ($2 million) and higher payroll taxes ($1 million), partially offset by the resolution of various routine tax issues ($4 million).

Interest Expense, Net

Interest expense, net, increased $4 million due primarily to higher long-term debt interest ($17 million) resulting from the $300 million debt issuance in May 2008 and the $250 million debt issuance in February 2009, partially offset by lower other interest ($8 million) mostly related to the resolution of various routine tax issues and lower RRB interest resulting from lower principal balances outstanding ($5 million).

Other Income, Net

Other income, net, decreased $11 million due primarily to a lower AFUDC equity income ($11 million) as a result of lower eligible CWIP due to large transmission projects being completed and placed in-service in 2008 and lower capital expenditures in 2009, and lower Energy Independence Act incentives ($5 million), partially offset by lower investment losses ($3 million) and higher interest and investment income ($1 million) due primarily to the supplemental benefit trust.

Income Tax Expense

Income tax expense increased $20 million due primarily to higher pre-tax earnings ($11 million), depreciation and other flow through impacts ($6 million) and higher state taxes ($3 million).

LIQUIDITY

CL&P had consolidated operating cash flows in the first half of 2009 of $247.1 million, compared with $124 million in the first half of 2008, both after RRB payments included in financing activities. The increase in first half 2009 operating cash flows was primarily due to higher operating results as a result of new distribution rates and increased transmission revenues after significant projects were placed in service in late 2008; a favorable shift in timing of collections of accounts receivable and unbilled revenues; and a decrease in the negative cash flow impact from regulatory underrecoveries of $144.3 million, primarily related to the FMCC, GSC and TAC charges included in customer rates. These factors were partially offset by increases of $85.2 million and $55 million in the negative cash flow effect of our accounts payable balances related to operating activities and the change in the amount of income tax refunds or payables, respectively. We project consolidated operating cash flows at CL&P of approximately $410 million in 2009, after approximately $183 million of RRB payments, which is higher than previous projections due to approximately $45 million of lower income tax payments from an accelerated deduction of depreciation.

As of June 30, 2009, CL&P had borrowings of $114 million under the $400 million credit facility it shares with other NU subsidiaries, under which it can borrow up to $200 million. Other financing activities for the first six months of 2009 included the $250 million bond issuance in February 2009, the remarketing of $62 million of tax-exempt PCRBs described above and capital contributions from NU parent of $77 million, offset by $102.7 million in repayment of NU Money Pool borrowings and $56.9 million in common dividends paid to NU parent.

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 $226.9 million in the first six months of 2009, compared with $442 million in the first six months of 2008. This decrease was primarily the result of lower transmission segment capital expenditures in 2009 due to the completion in 2008 of three major transmission projects in southwest Connecticut.

In August 2009, Moody's completed an industry-wide review of the number of levels between utility first mortgage bonds and utility unsecured debt. Moody's stated that its review of utility credit defaults showed a much higher rate of recovery for first mortgage bonds than for unsecured debt. The review resulted in a one-level upgrade of CL&P first mortgage bonds by Moody's.

While the impact of continued market volatility and the extent and impacts of the current economic downturn cannot be predicted, we believe that CL&P currently has sufficient operating flexibility and access to funding sources to maintain adequate liquidity. The credit outlooks for CL&P are stable. CL&P has low risk of calls for collateral due to its business model, as described under "Liquidity-Impact of Financial Market Conditions" in this "Management's Discussion and Analysis of Financial Condition and Results of Operations." Capital contributions from NU parent and other internal sources of funding are provided to CL&P as necessary. CL&P has the mandatory tender of $62 million in 2010 but does not have any long-term debt maturing until 2014; projected capital expenditures for 2009 of approximately $430 million are significantly less than 2008; and projected operating cash flows for 2009 are higher than 2008.

PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES

Management's Discussion and Analysis of

Financial Condition and Results of Operations

PSNH is a wholly owned subsidiary of NU. This discussion should be read in conjunction with NU's Management's Discussion and Analysis of Financial Condition and Results of Operations, unaudited condensed consolidated financial statements and footnotes in this Form 10-Q, the First Quarter 2009 Form 10-Q and the 2008 Form 10-K.

RESULTS OF OPERATIONS

The following table provides the variances in income statement line items for the unaudited condensed consolidated statements of income for PSNH included in this Quarterly Report on Form 10-Q for the three and six months ended June 30, 2009:


	Income Statement Variances (Millions of Dollars) 2009 over/(under) 2008
	Second Quarter		Percent		Six Months		Percent
Operating Revenues	$	(11)	(4)	%	$	5	1	%

Operating Expenses:
Fuel, purchased and net interchange power		(14)	(10)			(10)	(3)
Other operation		3	5			12	11
Maintenance		(9)	(29)			(13)	(26)
Depreciation		2	12			4	12
Amortization of regulatory liabilities, net		5	30			7	60
Amortization of rate reduction bonds		1	6			1	2
Taxes other than income taxes		-	-			2	9
Total operating expenses		(12)	(5)			3	-

Operating Income		1	4			2	4

Interest expense, net		(2)	(13)			(1)	(4)
Other income, net		1	(a)			2	63
Income before income tax expense		4	22			5	12
Income tax expense		1	25			1	11
Net Income	$	3	21	%	$	4	12	%

(a) Percent greater than 100.

Comparison of the Second Quarter of 2009 to the Second Quarter of 2008

Operating Revenues

Operating revenues decreased $11 million in 2009 due to lower distribution segment revenues ($13 million), partially offset by higher transmission segment revenues ($2 million).

The distribution segment revenues decreased $13 million due primarily to a decrease in the portion of electric distribution revenues that does not impact earnings ($11 million) as a result of the inclusion of distribution revenues in regulatory tracking mechanisms and transmission segment intracompany billings to the distribution segment that are eliminated in consolidation. The component of revenues that flows through to earnings decreased $2 million primarily as a result of lower retail sales volumes. Retail sales decreased 7 percent in 2009 compared to the same period in 2008.

The $11 million decrease in distribution revenues that does not impact earnings is due to the portion of retail revenues that are included in NHPUC approved tracking mechanisms that track the recovery of certain incurred costs ($7 million) and the portion of revenues that are eliminated in consolidation ($4 million). The distribution revenues included in NHPUC approved tracking mechanisms decreased $7 million due primarily to the pass-through of lower energy supply costs ($15 million), partially offset by an increase in the SCRC ($4 million), higher retail transmission revenues ($2 million), higher Northern Wood Power Plant renewable energy certificate revenues ($2 million) and higher wholesale revenues ($1 million). The tracking mechanisms allow for rates to be changed periodically with overcollections refunded to customers or undercollections recovered from customers in future periods.

Transmission segment revenues increased $2 million due primarily to a higher transmission investment base.

Fuel, Purchased and Net Interchange Power

Fuel, purchased and net interchange power costs decreased $14 million due primarily to a migration of ES customers to competitive supply and lower retail sales.

Other Operation

Other operation expenses increased $3 million due primarily to higher generation business costs that are tracked and recovered through distribution tracking mechanisms ($3 million) and higher distribution segment expenses ($2 million) mainly due to higher administrative and general expenses including higher pension expense, partially offset by lower transmission segment expenses ($1 million) and lower retail transmission expenses that are tracked and recovered through a tracking mechanism ($1 million).

Maintenance

Maintenance expenses decreased $9 million due primarily to higher expenses in 2008 as a result of the Merrimack Station Unit 2 maintenance outage ($5 million) and lower tree trimming expenses ($2 million).

Depreciation

Depreciation expense increased $2 million due primarily to higher utility plant balances resulting from completed construction programs put into service.

Amortization of Regulatory Liabilities, Net

Amortization of regulatory liabilities, net increased $5 million due primarily to an increase in the net deferral associated with PSNH's ES tracking mechanism.

Amortization of Rate Reduction Bonds

Amortization of RRBs increased $1 million. The higher portion of principal within the RRB payment results in a corresponding increase in the amortization of RRBs.

Interest Expense, Net

Interest expense, net decreased $2 million due primarily to lower other interest ($1 million), mainly related to the favorable resolution of various routine tax issues, and lower RRB interest resulting from lower principal balances outstanding ($1 million).

Other Income, Net

Other income, net increased $1 million due primarily to higher interest and investment income on the supplemental benefit trust and interest income related to the return on the December 2008 ice storm.

Income Tax Expense

Income tax expense increased $1 million due primarily to the resolution of various routine tax issues.

Comparison of the First Six Months of 2009 to the First Six Months of 2008

Operating Revenues

Operating revenues increased $5 million in 2009 due to higher transmission segment revenues ($3 million) and higher distribution segment revenues ($2 million).

Transmission segment revenues increased $3 million due primarily to a higher transmission investment base.

The distribution segment revenues increased $2 million due primarily to an increase in the portion of electric distribution revenues that does not impact earnings ($2 million) as a result of the inclusion of distribution revenues in regulatory tracking mechanisms and transmission segment intracompany billings to the distribution segment that are eliminated in consolidation. The component of revenues that flows through to earnings decreased $1 million primarily as a result of lower sales volumes. Retail sales decreased 3.8 percent in 2009 compared to the same period in 2008.

The $2 million increase in distribution revenues that does not impact earnings is due to the portion of retail revenues that are included in NHPUC approved tracking mechanisms that track the recovery of certain incurred costs ($11 million), partially offset by revenues that are eliminated in consolidation ($9 million). The distribution revenues included in NHPUC approved tracking mechanisms increased $11 million due primarily to an increase in the SCRC ($9 million), higher retail transmission revenues ($6 million), higher Northern Wood Power Plant renewable energy certificate revenues ($5 million), and higher wholesale revenue ($1 million), partially

offset by the pass-through of lower energy supply costs ($10 million). The tracking mechanisms allow for rates to be changed periodically with overcollections refunded to customers or undercollections recovered from customers in future periods.

Fuel, Purchased and Net Interchange Power

Fuel, purchased and net interchange power costs decreased $10 million due primarily to a migration of ES customers to competitive supply and lower retail sales, partially offset by higher forward energy market prices.

Other Operation

Other operation expenses increased $12 million due primarily to higher distribution segment expenses ($10 million) mainly due to higher administrative and general expenses including higher pension expense and higher generation business costs that are tracked and recovered through distribution tracking mechanisms ($5 million), partially offset by lower retail transmission expenses that are tracked and recovered through a tracking mechanism ($1 million).

Maintenance

Maintenance expenses decreased $13 million due primarily to lower storm costs ($11 million) and higher expenses in 2008 as a result of the Merrimack Station Unit 2 maintenance outage ($6 million), partially offset by higher tree trimming expenses ($3 million).

Depreciation

Depreciation expense increased $4 million due primarily to higher utility plant balances resulting from completed construction programs put into service.

Amortization of Regulatory Liabilities, Net

Amortization of regulatory liabilities, net increased $7 million due primarily to an increase in net deferrals associated with PSNH's SCRC, TCAM and ES tracking mechanisms.

Amortization of Rate Reduction Bonds

Amortization of RRBs increased $1 million. The higher portion of principal within the RRB payment results in a corresponding increase in the amortization of RRBs.

Taxes Other Than Income Taxes

Taxes other than income taxes increased $2 million due primarily to higher property taxes as a result of higher net plant balances and higher local municipal tax rates ($3 million), partially offset by lower sales taxes as a result of the resolution of various routine tax issues ($1 million).

Interest Expense, Net

Interest expense, net decreased $1 million due primarily to lower other interest ($1 million), mainly related to the resolution of various routine tax issues, and lower RRB interest resulting from lower principal balances outstanding ($1 million), partially offset by higher long-term debt interest ($1 million), mainly resulting from the $110 million debt issuance in May 2008.

Other Income, Net

Other income, net increased $2 million due primarily to higher interest income related to the return on the December 2008 ice storm and lower investment losses on the supplemental benefit trust, partially offset by lower AFUDC equity income due to decreased eligible CWIP and higher short-term debt resulting in a lower portion of CWIP being subject to the equity rate.

Income Tax Expense

Income tax expense increased $1 million due primarily to the resolution of various routine tax issues.

LIQUIDITY

PSNH had consolidated operating cash flows in the first half of 2009 of $22.5 million, compared with $27.8 million in the first half of 2008, both after RRB payments. The decrease in first half 2009 operating cash flows was due to an increase of $87.8 million in the negative cash flow effect of accounts payable balances as a result of, among other things, costs related to the major storm in December 2008 that were paid to vendors in the first half of 2009 and deferred. These costs began to be recovered from customers on August 1, 2009 at an annual rate of $6 million pursuant to the temporary rate case settlement. This level of recovery could be modified once PSNH's permanent rate case is decided. The impact from accounts payable balances was offset by, among other things, insurance settlement proceeds for the recovery of major storm costs and a decrease in the negative cash flow impact from various other working capital items, such as accrued income taxes and fuel, materials and supplies due primarily to a change in timing of coal purchases by the generation segment.

WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY

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

WMECO is a wholly owned subsidiary of NU. This discussion should be read in conjunction with NU's Management's Discussion and Analysis of Financial Condition and Results of Operations, unaudited condensed consolidated financial statements and footnotes in this Form 10-Q, the First Quarter 2009 Form 10-Q and the 2008 Form 10-K.

RESULTS OF OPERATIONS

The following table provides the variances in income statement line items for the unaudited condensed consolidated statements of income for WMECO included in this Quarterly Report on Form 10-Q for the three and six months ended June 30, 2009:


	Income Statement Variances (Millions of Dollars) 2009 over/(under) 2008
	Second Quarter		Percent		Six Months		Percent
Operating Revenues	$	(9)	(9)	%	$	(7)	(3)	%

Operating Expenses:
Fuel, purchased and net interchange power		(5)	(10)			(4)	(3)
Other operation		-	-			4	9
Maintenance		-	-			(2)	(18)
Depreciation		-	-			1	7
Amortization of regulatory (liabilities)/assets, net		(8)	(a)			(10)	(a)
Amortization of rate reduction bonds		-	-			-	-
Taxes other than income taxes		-	-			-	-
Total operating expenses		(13)	(13)			(11)	(5)

Operating Income		4	36			4	15

Interest expense, net		-	-			-	-
Other income, net		1	(a)			-	-
Income before income tax expense		5	86			4	27
Income tax expense		2	98			2	30
Net Income	$	3	79	%	$	2	25	%

(a) Percent greater than 100.

Comparison of the Second Quarter of 2009 to the Second Quarter of 2008

Operating Revenues

Operating revenues decreased $9 million in 2009 due to lower distribution segment revenues ($10 million), partially offset by higher transmission segment revenues ($1 million).

The distribution segment revenues decreased $10 million due primarily to a decrease in the portion of distribution revenues that does not impact earnings ($9 million) as a result of the inclusion of distribution revenues in regulatory tracking mechanisms and costs that are eliminated in consolidation and the portions of revenues that flows through to earnings ($1 million). The $9 million distribution segment revenue decrease that does not impact earnings is due to the portions of retail revenues that are included in DPU approved tracking mechanisms that track the recovery of certain incurred costs ($7 million) and revenues that are eliminated in consolidation ($2 million). The distribution revenue DPU approved tracking mechanisms that track the recovery of certain incurred costs decreased $7 million due primarily to the pass through of lower energy supply costs ($5 million), lower transition cost recoveries ($3 million), and lower wholesale revenues ($2 million), partially offset by higher retail transmission revenues ($3 million). Tracking mechanisms allow for rates to be changed periodically with overcollections refunded to customers or undercollections recovered from customers in future periods.

The distribution segment revenues that flow through to earnings decreased $1 million due primarily to lower retail sales. Retail sales as compared to the same period in 2008 decreased 15.1 percent for the industrial, 10.6 percent for the commercial, and 7 percent for the residential classes. Total retail sales decreased overall by 10.4 percent.

Transmission segment revenues increased $1 million due primarily to a higher transmission investment base.

Fuel, Purchased and Net Interchange Power

Fuel, purchased and net interchange power expense decreased $5 million due primarily to lower Default Service supply costs and lower deferral of excess Default Service revenue over Default Service expense. The Default Service supply costs are the contractual amounts we must pay to various suppliers that serve Default Service load after winning a competitive solicitation process. To the extent that these costs do not match the revenues collected from customers, the DPU allows the difference to be deferred for future collection or refund.

Amortization of Regulatory (Liabilities)/Assets, Net

Amortization of regulatory (liabilities)/assets, net decreased $8 million in 2009 due primarily to the deferral of allowed distribution segment transition costs that are in excess of transition revenues, resulting mainly from a decrease in the TC portion rate.

Other Income, Net

Other income, net increased $1 million in 2009 due primarily to higher interest and investment income mainly due to the supplemental benefit trust.

Income Tax Expense

Income tax expense increased $2 million due primarily to higher pre-tax earnings.

Comparison of the First Six Months of 2009 to the First Six Months of 2008

Operating Revenues

Operating revenues decreased $7 million in 2009 due to lower distribution segment revenues ($9 million), partially offset by higher transmission segment revenues ($2 million).

The distribution segment revenues decreased $9 million due primarily to a decrease in the portion of distribution revenues that does not impact earnings due to the portions of retail revenues that are included in DPU approved tracking mechanisms that track the recovery of certain incurred costs ($5 million) and revenues that are eliminated in consolidation ($4 million). The distribution revenue DPU approved tracking mechanisms that track the recovery of certain incurred costs decreased $5 million due primarily to lower transition cost recoveries ($5 million), the pass through of lower energy supply costs ($5 million), and lower wholesale revenues ($3 million), partially offset by higher retail transmission revenues ($7 million). Tracking mechanisms allow for rates to be changed periodically with overcollections refunded to customers or undercollections recovered from customers in future periods.

Retail sales as compared to the same period in 2008 decreased 15.5 percent for the industrial, 6.9 percent for the commercial, and 2 percent for the residential classes. Total retail sales decreased overall by 6.6 percent. The lower revenue resulting from the lower retail sales of $1 million was partially offset by higher revenue due to the absence of a 2008 regulatory decision on streetlight refunds.

Transmission segment revenues increased $2 million due primarily to a higher transmission investment base.

Fuel, Purchased and Net Interchange Power

Fuel, purchased and net interchange power expense decreased $4 million due primarily to lower Default Service supply costs. The Default Service supply costs are the contractual amounts we must pay to various suppliers that serve Default Service load after winning a competitive solicitation process. To the extent that these costs do not match the revenues collected from customers, the DPU allows the difference to be deferred for future collection or refund.

Other Operation

Other operation expenses increased $4 million due primarily to higher retail transmission costs that are tracked and recovered through distribution tracking mechanisms ($4 million).

Maintenance

Maintenance expenses decreased $2 million due primarily to lower storm cost expenses ($2 million), partially offset by higher tree trimming expenses ($1 million). The decrease in 2009 storm-related expenses was primarily related to additional work performed in the first quarter in the aftermath of the December 2008 ice storm that was not recorded to expense, but rather to the storm reserve.

Depreciation

Depreciation expense increased $1 million due primarily to higher utility plant balances resulting from completed construction programs put into service.

Amortization of Regulatory (Liabilities)/Assets, Net

Amortization of regulatory (liabilities)/assets, net decreased $10 million in 2009 due primarily to the deferral of allowed distribution segment transition costs that are in excess of transition revenues, resulting mainly from a decrease in the TC portion rate.

Income Tax Expense

Income tax expense increased $2 million due primarily to higher pre-tax earnings.

LIQUIDITY

WMECO had consolidated operating cash flows in the first half of 2009 of $9.2 million, compared with operating cash flows of $31 million in the first half of 2008, both after RRB payments. The decrease in first half 2009 operating cash flows was primarily due to an increase of $24.5 million in the negative cash flow effect of accounts payable balances partially as a result of costs related to the major storm in December 2008 that were paid to vendors in the first half of 2009. These costs were deferred and are expected to be recovered from customers. WMECO anticipates filing a distribution rate case in mid-2010, which would include a request for more timely recovery of the December 2008 storm costs.

ITEM 3.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Market Risk Information

Commodity Price Risk Management: We have no contracts entered into for trading purposes. 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, and the sensitivity analyses below do not include these contracts. The wholesale portfolio held by Select Energy includes contracts that are market-risk sensitive, including a wholesale sales contract with NYMPA through 2013 with approximately 0.4 million remaining MWh of supply contract volumes, net of related sales volumes. Select Energy also has a non-derivative contract that expires in mid-2012 to purchase output from a generation facility, which is less exposed to market price volatility and is not included in the sensitivity analysis below. As Select Energy's contract volumes are winding down, and as the NYMPA contract is substantially hedged against price risks, we have somewhat limited exposure to commodity price risks.

For Select Energy's wholesale portfolio derivatives, we utilize the sensitivity analysis methodology to disclose quantitative information for our commodity price risks (including, where applicable, capacity and ancillary components). 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. Under the sensitivity analysis, the fair value of the derivatives is a function of the underlying commodity components, contract prices and market prices represented by each derivative contract. For swaps, forward contracts and options, fair value reflects our best estimates considering over-the-counter quotations, time value and volatility factors of the underlying commitments. Exchange-traded futures and options are recorded at fair value based on closing exchange prices. A portion of the fair value of the NYMPA contract is based on a model.

Select Energy's Wholesale Portfolio: When conducting sensitivity analyses of the change in the fair value of the wholesale portfolio, which includes several derivative contracts, which would result from a hypothetical change in the future market price of electricity, the fair values of the contracts are determined from models that take into consideration estimated future market prices of electricity, the volatility of the market prices in each period, as well as the time value factors of the underlying commitments.

Hypothetical changes in the fair value of the wholesale portfolio were determined using a 30 percent assumed change in forward market prices. As of June 30, 2009, we determined the following hypothetical changes and calculated the nominal adjusted impact on pre-tax income:


	30% Price Increase		30% Price Decrease
(Millions of Dollars) Commodity	Nominal Impact on Pre-Tax Income		Nominal Impact on Pre-Tax Income
Energy	$	(0.2)	$	(3.8)
Capacity		(2.4)		2.4
Ancillaries		(1.7)		1.7
	$	(4.3)	$	0.3

The impact of a change in electricity prices on wholesale transactions as of June 30, 2009 are not necessarily representative of the results that will be realized if such a change were to occur. Energy, capacity and ancillaries have different market volatilities. The method we use to determine the fair value of these contracts includes discounting expected future cash flows using a LIBOR swap curve. As such, the wholesale portfolio is also exposed to interest rate volatility. This exposure is not modeled in sensitivity analyses, and we do not believe that such exposure is material. The derivative contracts in the wholesale portfolio are accounted for at fair value, and changes in market prices impact earnings.

Other Risk Management Activities

Interest Rate Risk Management: We manage our interest rate risk exposure in accordance with our written policies and procedures by maintaining a mix of fixed and variable rate long-term debt. As of June 30, 2009, approximately 93 percent (87 percent including the long-term debt subject to the fixed-to-floating interest rate swap as variable rate long-term debt) of our long-term debt, including fees and interest due for spent nuclear fuel disposal costs, was at a fixed interest rate. The remaining long-term debt is at variable interest rates and is subject to interest rate risk that could result in earnings volatility. Assuming a one percentage point increase in our variable interest rate, annual interest expense would have increased by a pre-tax amount of $3.3 million. As of June 30, 2009, we maintained a fixed-to-floating interest rate swap at NU parent to manage the interest rate risk associated with $263 million of its fixed-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.

Credit risks and market risks at NU Enterprises are monitored regularly by a Risk Oversight Council. The Risk Oversight Council is comprised of members of management from other areas of NU that do not create these risk exposures and functions to ensure compliance with our stated risk management policies.

We track and re-balance the risk in our portfolio in accordance with fair value and other risk management methodologies that utilize forward price curves in the energy markets to estimate the size and probability of future potential exposure.

The NYMEX traded futures and option contracts cleared off the NYMEX exchange are ultimately guaranteed by NYMEX to Select Energy. Select Energy has established written credit policies with regard to its counterparties to minimize overall credit risk on all types of transactions. These policies require an evaluation of potential counterparties' financial condition (including credit ratings), collateral requirements under certain circumstances (including cash in advance, LOCs, and parent guarantees), and the use of standardized agreements, which allow for the netting of positive and negative exposures associated with a single counterparty in the extent of default. This evaluation results in establishing credit limits prior to Select Energy entering into energy contracts. The appropriateness of these limits is subject to continuing review. Concentrations among these counterparties may impact Select Energy's overall exposure to credit risk, either positively or negatively, in that the counterparties may be similarly affected by changes to economic, regulatory or other conditions.

As of June 30, 2009 and December 31, 2008, Select Energy had cash collateral balances deposited with its NYMEX broker of $28.3 million and $26.3 million, respectively, which are included in Current assets - prepayments and other on the accompanying unaudited condensed consolidated balance sheets. Select Energy held no collateral balances from counterparties at either period end. In addition, Select Energy had posted a $2 million NU LOC as of June 30, 2009 in favor of ISO-NE.

Our regulated companies are subject to credit risk from certain long-term or high-volume supply contracts with energy marketing companies. Our regulated companies manage the credit risk with these counterparties in accordance with established credit risk practices and maintain an oversight group that monitors contracting risks, including credit risk. As of June 30, 2009, CL&P had $1 million in cash collateral deposited with counterparties. As of December 31, 2008, our regulated companies neither held cash collateral nor deposited collateral with counterparties. NU 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, 2009, PSNH had posted $85 million in such NU LOCs.

We have implemented an Enterprise Risk Management (ERM) methodology for identifying the principal risks of the Company. ERM involves the application of a well-defined, enterprise-wide methodology that will enable our Risk and Capital Committee, comprised of our senior officers, to oversee the identification, management and reporting of the principal risks of the business. However, there can be no assurances that the ERM process will identify every risk or event that could impact our financial condition or results of operations. The findings of this process are periodically discussed with our Board of Trustees.

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, 2009 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 report on Form 10-Q. There are inherent limitations of disclosure controls and procedures, including the possibility of human error and the circumventing or overriding of the controls and procedures. Accordingly, even effective disclosure controls and procedures can only provide reasonable assurance of achieving their control objectives. The principal executive officers and principal financial officer have concluded, based on their review, that the disclosure controls and procedures of NU, CL&P, PSNH, and WMECO are effective to ensure that information required to be disclosed by us in reports filed under the Securities Exchange Act of 1934 (i) is recorded, processed, summarized, and reported within the time periods

specified in SEC rules and regulations and (ii) is accumulated and communicated to management, including the principal executive officers and principal financial officer, as appropriate to allow timely decisions regarding required disclosures.

There have been no changes in internal controls over financial reporting for NU, CL&P, PSNH, and WMECO during the quarter ended June 30, 2009 that have materially affected, or are reasonably likely to materially affect, internal controls over financial reporting.

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 Annual Report on Form 10-K for the year ended December 31, 2008, which disclosures are incorporated herein by reference. There have been no material changes with regard to the legal proceedings previously disclosed in our most recent Form 10-K, other than as follows:

Connecticut MGP Cost Recovery: On August 5, 2004, Yankee Gas and CL&P (NU Companies) demanded contribution from UGI Utilities, Inc. (UGI) of Pennsylvania for past and future remediation costs related to historic manufactured gas plant (MGP) operations on thirteen sites currently or formerly owned by the NU Companies (Yankee Gas is responsible for ten of the sites, CL&P for two of the sites, and both companies share responsibility for one site) in a number of different locations throughout the State of Connecticut. The NU Companies alleged that UGI controlled operations of the plants at various times throughout the period 1883 to 1941, when UGI was forced to divest its interests. Investigations and remediation expenditures at the sites to date total over $20 million, and projected potential remediation costs for all sites, based on litigation modeling assumptions, could total as much as $232 million. At this point, we are unable to estimate the potential costs associated with these sites.

In September 2006, the NU Companies filed a complaint against UGI in the U.S. District Court for the District of Connecticut seeking a fair and equitable contribution for the actual and anticipated remediation costs related to the former MGP operations. On May 22, 2009, the court issued its Memorandum of Decision in this matter. The court granted judgment in favor of the NU Companies with respect to one of the sites for which Yankee Gas is responsible, and granted judgment in favor of UGI with respect to the remaining sites. The parties are proceeding with the damages phase of the case with respect to the site judged in our favor. The NU Companies filed their notices of appeal with respect to the judgments in favor of UGI, which appeals were subsequently withdrawn by stipulation of the parties and will be re-filed after entry of judgment following the damages phase.

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 "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 our Annual Report on Form 10-K for the year ended December 31, 2008 and our Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2009, 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 most recent Annual Report on Form 10-K and Quarterly Report on Form 10-Q other than as set forth below.

Market performance or changes in assumptions could require us to make significant unplanned contributions to our pension plan.

We provide a defined benefit pension plan for a substantial number of employees, former employees and retirees. As a result of negative market returns on pension plan investments in 2008 due to adverse financial market conditions, at March 31, 2009, we had calculated the pension plan’s funded ratio at approximately 77 percent as of January 1, 2009, and estimated contributions to the pension plan of approximately $300 million to $350 million would be required in 2010. Pursuant to recent Internal Revenue Service guidance that provides flexibility in determining the pension plan’s benefit liabilities for funding purposes, we have now re-calculated our projected funding ratio and revised our contribution estimates to the pension plan for the plan year beginning January 1, 2009 to be approximately $50 million, which contribution must be made by the third quarter of 2010. No contribution will be required to be made in 2010 for the plan year beginning January 1, 2010. We have not yet determined the amount of contributions for the 2010 plan year required to be made in 2011 or contributions for future plan years, but such amounts could be substantial.

The measurement of our expected future pension plan obligations, costs and liabilities is highly dependent on a variety of assumptions, many of which relate to factors beyond our control. These assumptions include investment returns, interest rates, and the demographics of plan participants. For example, changes in interest rates affect the discount rate used to measure the liabilities under the pension plan, and as the discount rate decreases, the liabilities increase, potentially increasing the funding requirements. Changes in these assumptions or other factors, including changes in laws or regulations governing pension plan contributions, could result in significant increases in our pension expense and funding requirements in the future.

If we are required to make significant unplanned contributions to fund the pension plan, the contributions could negatively affect our financial condition, cash flows, results of operations, and the timing and amount of our future equity and debt financings.

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 common shares during the quarter ended June 30, 2009.

ITEM 4.

SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

At the Annual Meeting of Shareholders of NU held on May 12, 2009, the following twelve nominees were elected to serve on the Board of Trustees by the votes set forth below:


		For	Withheld	Total

1.	Richard H. Booth	124,823,695	1,448,002	126,271,697
2.	John S. Clarkeson	124,831,818	1,439,879	126,271,697
3.	Cotton M. Cleveland	123,885,641	2,386,056	126,271,697
4.	Sanford Cloud, Jr.	124,612,952	1,658,745	126,271,697
5.	James F. Cordes	124,768,132	1,503,565	126,271,697
6.	E. Gail de Planque	123,151,029	3,120,668	126,271,697
7.	John G. Graham	125,025,189	1,246,508	126,271,697
8.	Elizabeth T. Kennan	123,819,165	2,452,532	126,271,697
9.	Kenneth R. Leibler	124,961,217	1,310,480	126,271,697
10.	Robert E. Patricelli	123,884,783	2,386,914	126,271,697
11.	Charles W. Shivery	123,845,283	2,426,414	126,271,697
12.	John F. Swope	123,749,043	2,522,654	126,271,697

NU's shareholders also ratified the Board of Trustees' selection of Deloitte & Touche LLP to serve as independent auditors of NU and its subsidiaries for 2009. The vote ratifying such selection was 125,374,192 votes in favor and 502,787 votes against, and 394,718 abstentions.

CL&P. In a written Consent in Lieu of an Annual Meeting of Stockholders of CL&P dated April 22, 2009 (CL&P Consent), stockholders voted to fix the number of directors for the ensuing year at seven and the following seven directors were elected to serve on the Board of Directors for the ensuing year: Gregory B. Butler, Jean M. LaVecchia, David R. McHale, Raymond P. Necci, Leon J. Olivier, James B. Robb and Charles W. Shivery. The vote on each of these proposals was 6,035,205 shares in favor, representing 100 percent of the issued and outstanding shares of common stock of CL&P.

WMECO. In a written Consent in Lieu of an Annual Meeting of Stockholders of WMECO dated April 22, 2009 (WMECO Consent), stockholders voted to fix the number of directors for the ensuing year at seven and the following seven directors were elected to serve on the Board of Directors for the ensuing year: Gregory B. Butler, Peter J. Clarke, Jean M. LaVecchia, David R. McHale, Leon J. Olivier, James B. Robb and Charles W. Shivery. The vote on each of these proposals was 434,653 shares in favor, representing 100 percent of the issued and outstanding shares of common stock of WMECO.

PSNH. In a written Consent in Lieu of an Annual Meeting of Stockholders of PSNH dated April 22, 2009 (PSNH Consent), stockholders voted to fix the number of directors for the ensuing year at seven and the following seven directors were elected to serve on the Board of Directors for the ensuing year: Gregory B. Butler, Jean M. LaVecchia, Gary A. Long, David R. McHale, Leon J. Olivier, James B. Robb and Charles W. Shivery. The vote on each of these proposals was 301 shares in favor, representing 100 percent of the issued and outstanding shares of common stock of PSNH.

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 7, 2009

*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 7, 2009

*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 7, 2009

Listing of Exhibits (CL&P)

*12

Ratio of Earnings to Fixed Charges

*31

Certification of Leon J. Olivier, Chief Executive Officer of The Connecticut Light and Power Company, required by Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated August 7, 2009

*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 7, 2009

*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 7, 2009

Listing of Exhibits (PSNH)

*12

Ratio of Earnings to Fixed Charges

*31

Certification of Leon J. Olivier, Chief Executive Officer of Public Service Company of New Hampshire, required by Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated August 7, 2009

*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 7, 2009

*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 7, 2009

Listing of Exhibits (WMECO)

*12

Ratio of Earnings to Fixed Charges

*31

Certification of Leon J. Olivier, Chief Executive Officer of Western Massachusetts Electric Company, required by Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated August 7, 2009

*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 7, 2009

*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 7, 2009

SIGNATURE

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


		NORTHEAST UTILITIES
		(Registrant)




Date: August 7, 2009	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 7, 2009	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.


		PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE
		(Registrant)




Date: August 7, 2009	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 7, 2009	By	/s/ David R. McHale
		David R. McHale
		Executive Vice President and Chief Financial Officer
		(for the Registrant and as Principal Financial Officer)