CONNECTICUT LIGHT & POWER CO - Quarter Report: 2007 September (Form 10-Q)

September 2007 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 September 30, 2007
	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

	Ö

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	Ö
The Connecticut Light and Power Company			Ö
Public Service Company of New Hampshire			Ö
Western Massachusetts Electric Company			Ö

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


	Yes	No

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

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 October 31, 2007
Northeast Utilities Common stock, $5.00 par value	155,002,850 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 meet the conditions set forth in General Instruction I(1)(a) and (b) of Form 10-K and therefore filed their 2006 Form 10-K with the reduced disclosure format specified in General Instruction I(2) to Form 10-K.


GLOSSARY OF TERMS
The following is a glossary of frequently used abbreviations or acronyms that are found in this report.

NU COMPANIES, SEGMENTS OR INVESTMENTS:

CL&P	The Connecticut Light and Power Company
CRC	CL&P Receivables Corporation
HWP	Holyoke Water Power Company
Mt. Tom	Mt. Tom generating plant
NGC	Northeast Generation Company
NGS	Northeast Generation Services Company and Subsidiaries
NU or the company	Northeast Utilities
NU Enterprises	At September 30, 2007, NU Enterprises, Inc., is comprised of Select Energy, NGS, E.S. Boulos Company (Boulos), the Connecticut division of SECI (SECI-CT) and NU Enterprises parent. For further information, see Note 10, "Segment Information," to the condensed consolidated financial statements.
Parent and affiliates	Parent and affiliates is comprised of NU parent, NU's service companies, HWP (since January 1, 2007) and other subsidiaries, including 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, WMECO, the generation segment of PSNH and Yankee Gas, which is a natural gas local distribution company. For further information, see Note 10 "Segment Information," to the 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
Woods Electrical	Woods Electrical Co., Inc. a portion of which was sold in April of 2006 and the remainder of which was wound down in the second quarter of 2007.

REGULATORS:

DPU	Massachusetts Department of Public Utilities (formerly the Massachusetts Department of Telecommunications and Energy (DTE))
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
CTA	Competitive Transition Assessment
COLA	Cost of Living Adjustment
EPS	Earnings Per Share
ES	Default Energy Service
FASB	Financial Accounting Standards Board
FMCC	Federally Mandated Congestion Cost
GSC	Generation Service Charge
GWH	Gigawatt Hours
ISO-NE	New England Independent System Operator
KWH	Kilowatt-Hour
KV	Kilovolt
LOCs	Letters of Credit
MMCF	Million Cubic Feet
MW	Megawatt/Megawatts
NU 2006 Form 10-K	The Northeast Utilities and Subsidiaries combined 2006 Form 10-K as filed with the SEC
NYMEX	New York Mercantile Exchange
OCC	Connecticut Office of Consumer Counsel
Regulatory ROE	The average cost of capital method for calculating the return on equity related to the distribution and generation segments excluding the wholesale transmission segment.
RMR	Reliability Must Run
ROE	Return on Equity
SBC	System Benefits Charge
SCRC	Stranded Cost Recovery Charge
SFAS	Statement of Financial Accounting Standards
TCAM	Transmission Cost Adjustment Mechanism
TSO	Transitional Standard Offer
UI	United Illuminating Corporation

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 - Condensed Consolidated Financial Statements for the Following Companies:

Northeast Utilities and Subsidiaries

Condensed Consolidated Balance Sheets (Unaudited) - September 30, 2007 and December 31, 2006	2

Condensed Consolidated Statements of Income (Unaudited) - Three and Nine Months Ended September 30, 2007 and 2006	4

Condensed Consolidated Statements of Cash Flows (Unaudited) - Nine Months Ended September 30, 2007 and 2006	5

Not es to Condensed Con s olidated Financial St atem e n t s (Unaud ited - all co mpanies)	6

Report of Independent Registered Public Accounting Fir m	36

The Connecticut Light and Power Company and Subsidiaries

Condensed Consolidated Balance Sheets (Unaudited) - September 30, 2007 and December 31, 2006	38

Condensed Consolidated Statements of Income (Unaudited) - Three and Nine Months Ended September 30, 2007 and 2006	40

Condensed Consolidated Statements of Cash Flows (Unaudited) - Nine Months Ended September 30, 2007 and 2006	41

Public Service Company of New Hampshire and Subsidiaries

Condensed Consolidated Balance Sheets (Unaudited) - September 30, 2007 and December 31, 2006	44

Condensed Consolidated Statements of Income (Unaudited) - Three and Nine Months Ended September 30, 2007 and 2006	46

Condensed Consolidated Statements of Cash Flows (Unaudited) - Nine Months Ended September 30, 2007 and 2006	47

Western Massachusetts Electric Company and Subsidiary

Condensed Consolidated Balance Sheets (Unaudited) - September 30, 2007 and December 31, 2006	50

Condensed Consolidated Statements of Income (Unaudited) - Three and Nine Months Ended September 30, 2007 and 2006	52

Condensed Consolidated Statements of Cash Flows (Unaudited) - Nine Months Ended September 30, 2007 and 2006	53

iii


	Page

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

Northeast Utilities and Subsidiaries		54

The Connecticut Light and Power Company and Subsidiaries		76

Public Service Company of New Hampshire and Subsidiaries		80

Western Massachusetts Electric Company and Subsidiary		84

ITEM 3 - Quantitative and Qualitative Disclosures Abou t Market Risk		87

ITEM 4 - Controls and Procedures		88

PART II - OTHER INFORMATION

ITEM 1 - Legal Proceedings		89

ITEM 1A - Risk Factors		89

ITEM 2 - Unregistered Sales of Equity Securities and Use of Proceeds		89

IT EM 6 - Exhib its		90

SIGNATURES		92

NORTHEAST UTILITIES AND SUBSIDIARIES


NORTHEAST UTILITIES AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
	September 30,	December 31,
	2007	2006
	(Thousands of Dollars)
ASSETS

Current Assets:
Cash and cash equivalents	$ 207,653	$ 481,911
Special deposits	31,919	48,524
Investments in securitizable assets	339,309	375,655
Receivables, less provision for uncollectible
accounts of $18,924 in 2007 and $22,369 in 2006	326,900	361,201
Unbilled revenues	70,515	88,170
Fuel, materials and supplies	231,163	173,882
Marketable securities - current	67,781	67,546
Derivative assets - current	93,118	88,857
Prepayments and other	47,273	45,305
	1,415,631	1,731,051

Property, Plant and Equipment:
Electric utility	7,312,198	7,129,526
Gas utility	968,235	858,961
Other	307,835	299,389
	8,588,268	8,287,876
Less: Accumulated depreciation: $2,466,190 for electric
and gas utility and $176,395 for other in 2007;
$2,440,544 for electric and gas utility and
$174,562 for other in 2006	2,642,585	2,615,106
	5,945,683	5,672,770
Construction work in progress	931,358	569,416
	6,877,041	6,242,186

Deferred Debits and Other Assets:
Regulatory assets	2,101,115	2,449,132
Goodwill	287,591	287,591
Prepaid pension	108,988	21,647
Marketable securities - long-term	56,733	50,843
Derivative assets - long-term	264,723	271,755
Other	227,162	249,031
	3,046,312	3,329,999













Total Assets	$ 11,338,984	$ 11,303,236



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


NORTHEAST UTILITIES AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
	September 30,	December 31,
	2007	2006
	(Thousands of Dollars)
LIABILITIES AND CAPITALIZATION

Current Liabilities:
Long-term debt - current portion	$ 154,286	$ 4,877
Accounts payable	506,990	569,940
Accrued taxes	21,150	364,659
Accrued interest	73,709	53,782
Derivative liabilities - current	90,921	125,843
Other	201,400	244,734
	1,048,456	1,363,835

Rate Reduction Bonds	1,015,232	1,177,158

Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	1,029,796	1,099,433
Accumulated deferred investment tax credits	29,740	32,427
Deferred contractual obligations	238,768	271,528
Regulatory liabilities	857,048	809,324
Derivative liabilities - long-term	104,619	148,557
Accrued postretirement benefits	172,423	203,320
Other	379,156	322,840
	2,811,550	2,887,429

Capitalization:
Long-Term Debt	3,473,523	2,960,435

Preferred Stock of Subsidiary - Non-Redeemable	116,200	116,200

Common Shareholders' Equity:
Common shares, $5 par value - authorized
225,000,000 shares; 175,920,879 shares issued
and 154,983,295 shares outstanding in 2007 and
175,420,239 shares issued and 154,233,141 shares
outstanding in 2006	879,604	877,101
Capital surplus, paid in	1,463,520	1,449,586
Deferred contribution plan - employee stock
ownership plan	(28,501)	(34,766)
Retained earnings	914,622	862,660
Accumulated other comprehensive income	6,305	4,498
Treasury stock, 19,705,353 shares in 2007
and 19,684,249 shares in 2006	(361,527)	(360,900)
Common Shareholders' Equity	2,874,023	2,798,179
Total Capitalization	6,463,746	5,874,814


Total Liabilities and Capitalization	$ 11,338,984	$ 11,303,236








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


NORTHEAST UTILITIES AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)


	Three Months Ended September 30,		Nine Months Ended September 30,
	2007	2006	2007	2006
	(Thousands of Dollars, except share information)

Operating Revenues	$ 1,451,080	$ 1,592,784	$ 4,547,426	$ 5,401,233

Operating Expenses:
Operation -
Fuel, purchased and net interchange power	881,234	1,046,184	2,756,522	3,699,885
Other	195,237	248,956	679,015	827,278
Restructuring and impairment charges	-	1,287	193	9,712
Maintenance	53,858	55,918	159,703	143,539
Depreciation	64,522	61,355	191,393	179,840
Amortization	17,007	(8,639)	19,795	48,755
Amortization of rate reduction bonds	52,403	49,161	151,316	141,836
Taxes other than income taxes	63,485	62,179	193,435	193,046
Total operating expenses	1,327,746	1,516,401	4,151,372	5,243,891
Operating Income	123,334	76,383	396,054	157,342

Interest Expense:
Interest on long-term debt	41,706	37,448	118,153	105,269
Interest on rate reduction bonds	15,111	18,197	47,300	57,060
Other interest	4,907	4,479	15,061	18,105
Interest expense, net	61,724	60,124	180,514	180,434
Other Income, Net	10,734	12,081	36,676	38,451
Income from Continuing Operations Before
Income Tax Expense/(Benefit)	72,344	28,340	252,216	15,359
Income Tax Expense/(Benefit)	20,778	(75,702)	75,442	(85,087)
Income from Continuing Operations Before
Preferred Dividends of Subsidiary	51,566	104,042	176,774	100,446
Preferred Dividends of Subsidiary	1,390	1,390	4,169	4,169
Income from Continuing Operations	50,176	102,652	172,605	96,277
Discontinued Operations:
Income from Discontinued Operations	-	15,945	-	54,792
(Losses)/Gains from Sale/Disposition of Discontinued Operations	(90)	(1,605)	1,927	(8,083)
Income Tax (Benefit)/Expense	(38)	5,543	761	19,401
(Loss)/Income from Discontinued Operations	(52)	8,797	1,166	27,308
Net Income	$ 50,124	$ 111,449	$ 173,771	$ 123,585

Basic and Fully Diluted Earnings Per Common Share:
Income from Continuing Operations	$ 0.32	$ 0.67	$ 1.12	$ 0.63
Income from Discontinued Operations	-	0.05	-	0.17
Basic and Fully Diluted Earnings Per Common Share	$ 0.32	$ 0.72	$ 1.12	$ 0.80

Basic Common Shares Outstanding (weighted average)	154,930,930	153,883,480	154,672,270	153,651,610

Fully Diluted Common Shares Outstanding (weighted average)	155,420,239	154,320,675	155,210,704	154,036,770













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


NORTHEAST UTILITIES AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

	Nine Months Ended
	September 30,
	2007	2006
	(Thousands of Dollars)

Operating Activities:
Net income	$ 173,771	$ 123,585
Adjustments to reconcile to net cash flows
provided by operating activities:
Bad debt expense	19,983	25,665
Depreciation	191,393	182,752
Deferred income taxes	(41,144)	130,432
Amortization	19,795	48,755
Amortization of rate reduction bonds	151,316	141,836
Amortization of recoverable energy costs	1,494	6,481
Pension expense, net of capitalized portion	13,776	20,626
Regulatory overrecoveries/(refunds)	95,766	(150,541)
Derivative assets and liabilities	(31,641)	(78,422)
Deferred contractual obligations	(32,760)	(72,255)
Other non-cash adjustments	(2,561)	940
Other sources of cash	-	9,375
Other uses of cash	(33,101)	(17,398)
Changes in current assets and liabilities:
Receivables and unbilled revenues, net	43,511	658,768
Fuel, materials and supplies	(57,281)	14,831
Investments in securitizable assets	18,137	(20,284)
Other current assets	(6,483)	23,533
Accounts payable	(91,473)	(461,183)
Counterparty deposits and margin special deposits	20,858	38,842
Taxes receivable and accrued taxes	(350,529)	(245,009)
Other current liabilities	(34,676)	(1,063)
Net cash flows provided by operating activities	68,151	380,266

Investing Activities:
Investments in property and plant	(750,231)	(600,302)
Cash payments related to the sale of competitive businesses	(1,908)	(19,429)
Proceeds from sales of investment securities	196,083	127,010
Purchases of investment securities	(199,964)	(123,319)
Rate reduction bond escrow	3,372	(54,357)
Other investing activities	7,968	3,874
Net cash flows used in investing activities	(744,680)	(666,523)

Financing Activities:
Issuance of common shares	8,988	6,310
Issuance of long-term debt	655,000	250,000
Retirement of rate reduction bonds	(161,926)	(117,947)
Increase in short-term debt	-	246,000
Reacquisitions and retirements of long-term debt	(4,877)	(11,053)
Cash dividends on common shares	(89,745)	(83,560)
Other financing activities	(5,169)	1,180
Net cash flows provided by financing activities	402,271	290,930
Net (decrease)/increase in cash and cash equivalents	(274,258)	4,673
Cash and cash equivalents - beginning of period	481,911	45,782
Cash and cash equivalents - end of period	$ 207,653	$ 50,455


The accompanying notes are an integral part of these 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

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 Form 10-Q, the first and second quarter 2007 reports on Form 10-Q and the Annual Reports of Northeast Utilities (NU 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 were filed with the SEC as part of the Northeast Utilities and subsidiaries combined 2006 Form 10-K (NU 2006 Form 10-K). The accompanying 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 at September 30, 2007, the results of operations for the three and nine months ended September 30, 2007 and 2006 and cash flows for the nine months ended September 30, 2007 and 2006. The results of operations and statements of cash flows for the nine months ended September 30, 2007 and 2006 are not necessarily indicative of the results expected for a full year.

The condensed consolidated financial statements of NU and its subsidiaries, as applicable, include the accounts of all their respective subsidiaries. Intercompany transactions have been eliminated in consolidation.

The preparation of 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 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 condensed consolidated financial statements have been made to conform with the current period presentation. For the three and nine months ended September 30, 2006, wholesale contract market changes, net were separately stated on the condensed consolidated statements of income to increase the transparency of the mark-to-market related to Select Energy Inc.'s (Select Energy) wholesale marketing portfolio. As the disclosure of this amount is currently not as meaningful as it was in prior periods, a benefit of $4.8 million and a loss of $14.9 million have been reclassified to fuel, purchased and net interchange power on the accompanying condensed consolidated statements of income for the three and nine months ended September 30, 2006, respectively. For further information regarding Select Energy's derivatives, see Note 4, "Derivative Instruments," to the condensed consolidated financial statements.

In NU's, CL&P's, PSNH's and WMECO's condensed consolidated statements of income for the three and nine months ended September 30, 2006, the classification of certain cost and income items previously included in other income, net and interest expense was changed to operating expenses. In addition, certain revenues were reclassified to operating expenses as a result of the change in classification of certain revenues and associated expenses from a gross presentation to a net presentation. These changes for NU, CL&P, PSNH and WMECO for the three and nine months ended September 30, 2006 are as follows:


	Three Months Ended September 30, 2006								Nine Months Ended September 30, 2006
(Millions of Dollars)	NU		CL&P		PSNH		WMECO		NU		CL&P		PSNH		WMECO
Decrease in operating revenues	$	(1.3)	$	-	$	(1.3)	$	-	$	(1.3)	$	-	$	(1.3)	$	-
Decrease/(increase) in operating expenses	$	0.4	$	(1.0)	$	1.0	$	-	$	(2.5)	$	(3.3)	$	0.2	$	0.3
Decrease in interest expense	$	2.7	$	2.7	$	-	$	-	$	7.4	$	7.4	$	-	$	-
(Decrease)/increase in other income	$	(1.8)	$	(1.7)	$	0.3	$	-	$	(3.5)	$	(4.1)	$	1.1	$	(0.3)

These reclassifications had no impact on the companies' results of operations, financial condition or cash flows.

NU's condensed consolidated statements of income for the three and nine months ended September 30, 2006 classifies the past operations for the following as discontinued operations:

Northeast Generation Company (NGC), including certain components of Northeast Generation Services Company (NGS),

The Mt. Tom generating plant (Mt. Tom) previously owned by Holyoke Water Power Company (HWP),

Select Energy Services, Inc. (SESI) and its wholly owned subsidiaries HEC/Tobyhanna Energy Project, Inc. and HEC/CJTS Energy Center LLC, and

A portion of the former Woods Electrical Co., Inc. (Woods Electrical).

For further information regarding these companies, see Note 3, "Assets Held for Sale and Discontinued Operations," to the condensed consolidated financial statements.

Accounting Standards Issued But Not Yet Adopted

Fair Value Measurements: On September 15, 2006, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (SFAS) No. 157, "Fair Value Measurements," which establishes a framework for identifying and measuring fair value and is required to be implemented in the first quarter of 2008. SFAS No. 157 provides a fair value hierarchy, giving the highest priority to quoted prices in active markets, and is expected to be applied to fair value measurements of derivative contracts that are subject to mark-to-market accounting and to other assets and liabilities that are reported at fair value or subject to fair value measurements. SFAS No. 157 is expected to be implemented prospectively with any adjustments to fair value reflected in earnings on January 1, 2008, similar to a change in estimate. The company is evaluating the impact SFAS No. 157 will have on its financial statements.

The Fair Value Option: On February 15, 2007, the FASB issued SFAS No. 159, "The Fair Value Option for Financial Assets and Financial Liabilities - including an amendment of FAS 115." SFAS No. 159 is effective in the first quarter of 2008. SFAS No. 159 allows entities to choose, at specified election dates, to measure at fair value eligible financial assets and liabilities that are not otherwise required to be measured at fair value. If a company elects the fair value option for an eligible item, changes in that item's fair value in subsequent reporting periods must be recognized in earnings. The company does not currently plan to elect the fair value option on existing financial instruments as of January 1, 2008.

Regulatory Accounting

The accounting policies of the regulated companies 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 and WMECO, along with PSNH's generation segment and Yankee Gas Services Company's (Yankee Gas) gas distribution segment, continue to be cost-of-service rate regulated. Management believes that the application of SFAS No. 71 to those segments continues to be appropriate. Management also believes it is probable that the regulated companies will recover their investments in long-lived assets, including regulatory assets. All material net regulatory assets are earning returns at either a market rate, or at a stipulated equity rate, except for securitized regulatory assets, which are not supported by equity. Amortization and deferrals of regulatory assets are included on a net basis in amortization expense on the accompanying condensed consolidated statements of income.

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


	At September 30, 2007
(Millions of Dollars)	NU Consolidated		CL&P		PSNH		WMECO		Yankee Gas and Other
Securitized assets	$	962.3	$	586.9	$	286.6	$	88.8	$	-
Deferred benefit costs		287.6		93.1		71.8		12.7		110.0
Income taxes, net		299.0		271.1		-		27.6		0.3
Unrecovered contractual obligations		198.9		154.1		-		44.8		-
CTA and SBC undercollections		77.4		77.4		-		-		-
Regulatory assets offsetting regulated company derivative liabilities		47.0		34.2		12.8		-		-
Other regulatory assets		228.9		62.4		77.6		29.9		59.0
Totals	$	2,101.1	$	1,279.2	$	448.8	$	203.8	$	169.3


	At December 31, 2006
(Millions of Dollars)	NU Consolidated		CL&P		PSNH		WMECO		Yankee Gas and Other
Securitized assets	$	1,131.1	$	707.2	$	325.6	$	98.3	$	-
Deferred benefit costs		407.4		155.8		90.4		25.8		135.4
Income taxes, net		308.0		266.6		5.5		41.3		(5.4)
Unrecovered contractual obligations		214.4		163.7		-		50.7		-
CTA and SBC undercollections		100.5		100.5		-		-		-
Regulatory assets offsetting regulated company derivative liabilities		75.4		36.0		39.2		-		0.2
Other regulatory assets		212.3		47.6		63.8		36.2		64.7
Totals	$	2,449.1	$	1,477.4	$	524.5	$	252.3	$	194.9

Included in NU's other regulatory assets are the regulatory assets associated with the implementation of FASB Interpretation (FIN) 47, "Accounting for Conditional Asset Retirement Obligations - an interpretation of FASB Statement No. 143," totaling $51.9 million at September 30, 2007 and $46.4 million at December 31, 2006. Of these amounts, $14 million and $13.7 million, respectively, have been approved for future recovery. At this time, management believes that the remaining regulatory assets are also probable of recovery.

The regulatory assets related to deferred benefit costs totaled $287.6 million at September 30, 2007, as compared to $407.4 million at December 31, 2006. The $119.8 million decrease primarily relates to a pension plan remeasurement adjustment recorded in the second quarter of 2007 related to cost a of living adjustment (COLA) as well as changes in estimate recorded for both the Pension and PBOP Plans in the second and third quarters of 2007, respectively. For additional information, see Note 9, "Pension Benefits and Postretirement Benefits Other Than Pensions," to the condensed consolidated financial statements.

The companies above had $13.2 million and $11.2 million of costs at September 30, 2007 and December 31, 2006, respectively, that are included in deferred debits and other assets - other on the accompanying condensed consolidated balance sheets. These amounts represent costs that have not yet been approved by the applicable regulatory agency. Management believes these assets are recoverable in future cost of service regulated rates.

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


	At September 30, 2007
(Millions of Dollars)	NU Consolidated		CL&P		PSNH		WMECO		Yankee Gas and Other
Cost of removal	$	275.0	$	124.1	$	74.8	$	24.2	$	51.9
Regulatory liabilities offsetting regulated company derivative assets		307.2		306.1		0.7		-		0.4
Generation service charge/FMCC overcollections		146.2		146.2		-		-		-
Other regulatory liabilities		128.6		51.1		35.1		15.6		26.8
Totals	$	857.0	$	627.5	$	110.6	$	39.8	$	79.1


	At December 31, 2006
(Millions of Dollars)	NU Consolidated		CL&P		PSNH		WMECO		Yankee Gas and Other
Cost of removal	$	290.8	$	134.4	$	79.2	$	23.6	$	53.6
Regulatory liabilities offsetting regulated company derivative assets		294.5		294.5		-		-		-
Generation service charge/FMCC overcollections		108.2		108.2		-		-		-
Other regulatory liabilities		115.8		45.7		36.5		3.2		30.4
Totals	$	809.3	$	582.8	$	115.7	$	26.8	$	84.0

For information regarding derivative assets, see Note 4, "Derivative Instruments," to the condensed consolidated financial statements.

Allowance for Funds Used During Construction

The 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 cost of equity funds is recorded as other income on the accompanying condensed consolidated statements of income, as follows:


	For the Three Months Ended					For the Nine Months Ended
(Millions of Dollars, except percentages)	September 30, 2007		September 30, 2006			September 30, 2007			September 30, 2006
Borrowed funds	$	4.3		$	3.3		$	12.9		$	9.4
Equity funds		4.8			4.2			11.1			10.5
Totals	$	9.1		$	7.5		$	24.0		$	19.9
Average AFUDC rates		7.6%			7.9%			7.3%			7.4%

The regulated companies' average AFUDC rate is based on a Federal Energy Regulatory Commission (FERC) prescribed formula that develops 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 eligible construction work in progress (CWIP) amounts to calculate AFUDC. Although AFUDC is recorded on 100 percent of CL&P's CWIP for its major transmission projects in southwest Connecticut, 50 percent of this AFUDC is being reserved as a regulatory liability to reflect current rate base recovery for 50 percent of the CWIP as a result of FERC transmission incentives.

Income Taxes

Effective on January 1, 2007, NU implemented FIN 48, "Accounting for Uncertainty in Income Taxes - an Interpretation of FASB Statement No. 109." FIN 48 applies to all tax positions previously filed in a tax return and tax positions expected to be taken in a future tax return that have been reflected on the balance sheets. FIN 48 addresses the methodology to be used prospectively in recognizing, measuring and classifying the amounts associated with tax positions that are deemed to be uncertain, including related interest and penalties. Previously, NU recorded estimates for uncertain tax positions in accordance with SFAS No. 5, "Accounting for Contingencies."

As a result of implementing FIN 48, NU recognized a cumulative effect of a change in accounting principle of $32.5 million as a reduction to the January 1, 2007 balance of retained earnings. The CL&P, PSNH and WMECO reductions/(benefits) to the January 1, 2007 balances of retained earnings were $15.6 million, $(1.6) million and $(0.4) million, respectively.

Interest and Penalties: Effective on January 1, 2007, NU’s accounting policy for the classification of interest and penalties related to FIN 48 is as follows:

Interest on uncertain tax positions is recorded and classified as a component of other interest expense. NU recorded accrued interest expense of $17.4 million, which is included in the cumulative effect of a change in accounting principle as of January 1, 2007. NU recorded accrued interest expense of $1.3 million and $5.1 million for the three and nine months ended September 30, 2007, respectively.

No penalties have been recorded under FIN 48. If penalties are recorded in the future, then the estimated penalties would be classified as a component of other income, net.

Unrecognized Tax Benefits: Upon adoption of FIN 48 on January 1, 2007, NU recorded a liability for unrecognized tax benefits totaling $73.5 million, of which $56.9 million would impact the effective tax rate, if recognized. As of September 30, 2007, NU's liability for unrecognized tax liabilities totaled $91 million, of which $69.2 million would impact the effective tax rate, if recognized.

Tax Positions: NU is currently undergoing tax audits, and it is reasonably possible as these audits progress that the liability for unrecognized tax benefits could change significantly in the next 12 months; however, management cannot estimate the amount of change at this time.

Tax Years: The following table summarizes NU's tax years that remain subject to examination by major tax jurisdictions at January 1, 2007 and September 30, 2007:


Description		Tax Years
Federal		2002 - 2006
Connecticut		1997 - 2006
New Hampshire		2003 - 2006
Massachusetts		2003 - 2006

Sale of Customer Receivables

CL&P Receivables Corporation (CRC), a consolidated, wholly-owned subsidiary of CL&P, can sell up to $100 million of an undivided interest in its accounts receivable and unbilled revenues to a financial institution. At September 30, 2007 and December 31, 2006, there were no such sales.

At September 30, 2007 and December 31, 2006, amounts sold to CRC by CL&P but not sold to the financial institution totaling $339.3 million and $375.7 million, respectively, are included in investments in securitizable assets on the accompanying condensed consolidated balance sheets. These amounts would be excluded from CL&P's assets in the event of CL&P's bankruptcy.

On July 3, 2007, CL&P extended the bank commitment under the Receivables Purchase and Sale Agreement with CRC and the financial institution through June 30, 2008 and extended the facility termination date to June 21, 2012. CL&P's continuing involvement with the receivables that are sold to CRC and the financial institution is limited to servicing those receivables.

The transfer of receivables to the financial institution under this arrangement qualifies for sale treatment under SFAS No. 140, "Accounting for Transfers and Servicing of Financial Assets and Extinguishment of Liabilities - A Replacement of SFAS No. 125."

Cash and Cash Equivalents

Cash and cash equivalents include cash on hand and short-term cash investments that are highly liquid in nature and have original maturities of three months or less. At the end of each reporting period, any overdraft amounts are reclassified from cash and cash equivalents to accounts payable.

Special Deposits and Counterparty Deposits

To the extent Select Energy requires collateral from counterparties, or the counterparties require collateral from Select Energy, cash is paid to or by Select Energy as a part of the total collateral required based on Select Energy’s position in the transaction. 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.

Special deposits paid to unaffiliated counterparties and brokerage firms totaled $27.9 million and $48.5 million at September 30, 2007 and December 31, 2006, respectively. In addition, at September 30, 2007, PSNH also had $4 million on deposit with an unaffiliated counterparty related to an energy contract. These amounts are recorded as current assets and are included as special deposits on the accompanying condensed consolidated balance sheets.

Balances collected from counterparties resulting from Select Energy’s credit management activities totaled $0.4 million and $0.1 million at September 30, 2007 and December 31, 2006, respectively. These amounts are recorded as current liabilities and are included as current liabilities - other on the accompanying condensed consolidated balance sheets.

NU also had amounts on deposit related to four special purpose entities used to facilitate the issuance of rate reduction bonds and certificates. These amounts totaled $99.2 million and $102.5 million at September 30, 2007 and December 31, 2006, respectively. In addition, the company had $6.1 million and $11.2 million in other cash deposits held with unaffiliated parties at September 30, 2007 and December 31, 2006, respectively, primarily related to CL&P's transmission projects. These amounts are included in deferred debits and other assets - other on the accompanying condensed consolidated balance sheets.

Other Income, Net

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


NU	For the Three Months Ended				For the Nine Months Ended
(Millions of Dollars)	September 30, 2007		September 30, 2006		September 30, 2007		September 30, 2006
Other Income:
Investment income	$	4.2	$	3.9	$	18.6	$	11.9
Gain on sale of investment in Globix		-		-		-		3.1
CL&P procurement fee		-		3.0		-		8.5
AFUDC - equity funds		4.8		4.2		11.1		10.5
Energy Independence Act incentives		0.1		1.0		5.0		3.5
Conservation and load management incentives		1.4		0.5		1.8		1.3
Other		0.2		0.3		0.8		0.6
Total Other Income	$	10.7	$	12.9	$	37.3	$	39.4
Other Loss:
Investment write-downs		-		(0.7)		(0.5)		(0.7)
Other		-		(0.1)		(0.1)		(0.2)
Total Other Loss	$	-	$	(0.8)	$	(0.6)	$	(0.9)
Total Other Income, Net	$	10.7	$	12.1	$	36.7	$	38.5


CL&P	For the Three Months Ended				For the Nine Months Ended
(Millions of Dollars)	September 30, 2007		September 30, 2006		September 30, 2007		September 30, 2006
Other Income:
Investment income	$	1.3	$	1.4	$	4.3	$	4.4
CL&P procurement fee		-		3.0		-		8.5
AFUDC - equity funds		4.7		2.6		9.0		6.1
Energy Independence Act incentives		0.1		1.0		5.0		3.5
Conservation and load management incentives		1.3		0.3		1.4		0.5
Other		0.1		0.2		0.6		0.6
Total Other Income	$	7.5	$	8.5	$	20.3	$	23.6
Other Loss	$	-	$	-	$	-	$	(0.1)
Total Other Income, Net	$	7.5	$	8.5	$	20.3	$	23.5


PSNH	For the Three Months Ended				For the Nine Months Ended
(Millions of Dollars)	September 30, 2007		September 30, 2006		September 30, 2007		September 30, 2006
Other Income:
Investment income	$	0.2	$	0.1	$	0.6	$	0.6
AFUDC - equity funds		-		1.1		0.9		3.4
Other		-		-		0.1		-
Total Other Income	$	0.2	$	1.2	$	1.6	$	4.0


WMECO	For the Three Months Ended				For the Nine Months Ended
(Millions of Dollars)	September 30, 2007		September 30, 2006		September 30, 2007		September 30, 2006
Other Income:
Investment income	$	0.2	$	0.3	$	0.8	$	0.4
Conservation and load management incentives		0.1		0.2		0.4		0.8
AFUDC - equity funds		-		0.1		-		0.1
Total Other Income	$	0.3	$	0.6	$	1.2	$	1.3

Investment income for NU includes equity in earnings/(losses) of regional nuclear generating and transmission companies of $0.4 million and $0.8 million for the three months ended September 30, 2007 and 2006, respectively, and $1.5 million and $(0.4) million for the nine months ended September 30, 2007 and 2006, respectively. Equity in earnings relates to the company's investment in the Connecticut Yankee Atomic Power Company (CYAPC), Maine Yankee Atomic Power Company, Yankee Atomic Electric Company and the Hydro-Quebec transmission system.

Based on developments in July of 2006, CYAPC management concluded that $10 million of CYAPC's regulatory assets were no longer probable of recovery and should be written off. Because the contingency surrounding these regulatory assets existed at June 30, 2006, the write-off was recorded in the second quarter of 2006. NU recorded a total after-tax write-off of $3 million ($2.1 million, $0.3 million and $0.6 million after-tax for CL&P, PSNH and WMECO, respectively) for its ownership share of this charge, which is included in investment income in the tables above.

Other Taxes

Certain excise taxes levied by state or local governments are collected by NU from its customers. These excise taxes are accounted for on a gross basis with collections in revenues and payments in expenses. For the three and nine months ended September 30, 2007 and 2006, gross receipts taxes, franchise taxes and other excise taxes of $27 million and $84.9 million, respectively, for 2007 and $29.1 million and $86.9 million, respectively, for 2006, are included in operating revenues and taxes other than income taxes on the accompanying condensed consolidated statements of income. Certain sales taxes are also collected by the regulated companies from their customers as agent for state and local governments and are recorded on a net basis with no impact on the accompanying condensed consolidated statements of income.

RESTRUCTURING AND IMPAIRMENT CHARGES (NU, NU Enterprises)

NU Enterprises recorded $0.2 million of pre-tax restructuring and impairment charges for the nine months ended September 30, 2007, relating to the decision to exit the competitive businesses. The charges for the three and nine months ended September 30, 2006 were $10.4 million and $26 million, respectively. The amounts related to continuing operations are included as restructuring and impairment charges on the condensed consolidated statements of income with the remainder included in discontinued operations. These charges are included as part of the NU Enterprises reportable segment in Note 10, "Segment Information." A summary of these pre-tax restructuring and impairment charges is as follows:


	For the Three Months Ended				For the Nine Months Ended
(Millions of Dollars)	September 30, 2007		September 30, 2006		September 30, 2007		September 30, 2006
Wholesale Marketing:
Restructuring charges	$	-	$	0.1	$	-	$	0.3
Retail Marketing:
Restructuring charges		-		0.6		-		6.4
Competitive Generation:
Impairment charges		-		-		-		0.3
Restructuring charges		-		6.8		-		9.5
Subtotal	$	-	$	6.8	$	-	$	9.8
Energy Services and Other:
Impairment charges	$	-	$	-	$	-	$	0.1
Restructuring charges		-		2.9		0.2		9.4
Subtotal	$	-	$	2.9	$	0.2	$	9.5
Total restructuring and impairment charges	$	-	$	10.4	$	0.2	$	26.0
Restructuring and impairment charges included in discontinued operations	$	-	$	9.1	$	-	$	16.3
Total restructuring and impairment charges included in continuing operations	$	-	$	1.3	$	0.2	$	9.7

Restructuring charges totaling $0.2 million for nine months ended September 30, 2007, were recorded for energy services and other related to consulting fees, legal fees, employee-related and other costs incurred.

For the three and nine months ended September 30, 2006, $0.1 million and $0.3 million, respectively, of restructuring charges were recorded for wholesale marketing for consulting, legal fees, employee-related and other costs.

On June 1, 2006, NU Enterprises completed the sale of Select Energy New York, Inc. (SENY). In connection with this transaction, NU Enterprises recorded restructuring charges of $0.3 million for retail marketing, which is included in restructuring and impairment charges on the accompanying condensed consolidated statements of income for the nine months ended September 30, 2006. In addition to the $0.3 million charge, restructuring charges of $0.6 million and $6.1 million were recorded for the three and nine months ended September 30, 2006, respectively, for consulting fees, legal fees, employee-related and other costs.

For the nine months ended September 30, 2006, $0.3 million of impairments were recorded for competitive generation related to certain long-lived assets of NGS that were no longer recoverable and were written off. In addition, restructuring charges of $6.8 million and $9.5 million, respectively, were recorded for the three and nine months ended September 30, 2006, respectively, for consulting fees, legal fees, sale-related environmental fees, employee-related and other costs.

In the first quarter of 2006, $0.1 million of impairment charges were recorded in connection with the sale of a portion of Woods Electrical.

On May 5, 2006, NU Enterprises completed the sale of SESI. In connection with this transaction, NU Enterprises recorded a pre-tax restructuring charge of $6.5 million. In the third quarter of 2006, an additional restructuring charge of $1.6 million was recorded related to additional charges incurred for the sale of SESI. These charges are included in loss from sale of discontinued operations on the accompanying condensed consolidated financial statements of income. In addition to these charges, restructuring charges of $0.3 million and $2 million were recorded for the three and nine months ended September 30, 2006, respectively, for consulting fees, legal fees, employee-related costs and other costs and a $1 million charge was recorded in the third quarter of 2006 related to NU’s guarantee of SESI’s performance under government contracts. Offsetting the charges for the first nine months of 2006 is a restructuring benefit of $1.7 million from the gain on the sale of Massachusetts service location of Select Energy Contracting, Inc. - Connecticut (SECI-CT).

The following table summarizes the liabilities related to restructuring costs which are recorded in accounts payable and other current liabilities on the accompanying condensed consolidated balance sheets at September 30, 2007 and December 31, 2006:


(Millions of Dollars)	Employee- Related Costs		Professional and Other Fees		Total
Restructuring liability as of January 1, 2005	$	-	$	-	$	-
Costs incurred		2.3		7.4		9.7
Cash payments and other deductions/reversals		(0.5)		(3.2)		(3.7)
Restructuring liability as of December 31, 2005		1.8		4.2		6.0
Costs incurred		3.3		24.0		27.3
Cash payments and other deductions/reversals		(3.7)		(25.9)		(29.6)
Restructuring liability as of December 31, 2006		1.4		2.3		3.7
Costs incurred		-		0.2		0.2
Cash payments and other deductions/reversals		(1.0)		(1.2)		(2.2)
Restructuring liability as of March 31, 2007		0.4		1.3		1.7
Costs incurred		-		-		-
Cash payments and other deductions/reversals		(0.2)		-		(0.2)
Restructuring liability as of June 30, 2007		0.2		1.3		1.5
Costs incurred		-		-		-
Cash payments and other deductions/reversals		(0.2)		(1.0)		(1.2)
Restructuring liability as of September 30, 2007	$	-	$	0.3	$	0.3

ASSETS HELD FOR SALE AND DISCONTINUED OPERATIONS (NU, NU Enterprises)

Assets Held for Sale: In the first quarter of 2006, management determined that the retail marketing and competitive generation businesses met the held for sale criteria under applicable accounting guidance, and should be recorded at the lower of their carrying amount or fair value less cost to sell. The retail marketing business was reduced to its fair value less cost to sell through an approximately $53 million pre-tax charge included in other operating expenses for the nine months ended September 30, 2006.

At September 30, 2007, management continues to believe that the remaining wholesale marketing business, NGS, Boulos, and SECI-CT do not meet the held for sale criteria under applicable accounting guidance and therefore continue to be held and used and included in continuing operations.

Discontinued Operations: NU's condensed consolidated statements of income present NGC, Mt. Tom, SESI, and a portion of Woods Electrical as discontinued operations for all periods presented. These businesses were sold in 2006. Under discontinued operations presentation, revenues and expenses of the businesses classified as discontinued operations are classified net of tax in income from discontinued operations on the condensed consolidated statements of income and all prior periods are reclassified. Summarized financial information for the discontinued operations is as follows:


	For the Three Months Ended				For the Nine Months Ended
(Millions of Dollars)	September 30, 2007		September 30, 2006		September 30, 2007		September 30, 2006
Operating revenue	$	-	$	46.4	$	-	$	157.6
Income before income tax expense		-		15.9		-		54.8
(Losses)/gains on sale/disposition of discontinued operations		(0.1)		(1.6)		1.9		(8.1)
Income tax (benefit)/expense		(0.1)		5.5		0.7		19.4
Net income		-		8.8		1.2		27.3

The gain on sale/disposition of discontinued operations of $1.9 million for the nine months ended September 30, 2007 primarily relates to the favorable resolution of contingencies from the completion of a cogeneration plant by SESI, partially offset by charges related to the sale of the competitive generation business, including a $1.9 million charge resulting from a purchase price adjustment from the sale of the competitive generation business recorded in the first quarter of 2007.

No intercompany revenues were included in discontinued operations for the three and nine months ended September 30, 2007. Included in discontinued operations are $46.3 million and $144.6 million for the three and nine months ended September 30, 2006 of intercompany revenues that are not eliminated in consolidation due to the separate presentation of discontinued operations. Of the 2006 amounts, $46.3 million and $144.4 million, respectively, represent revenues on intercompany contracts between the generation operations of NGC and Mt. Tom and Select Energy. NGC's and Mt. Tom's revenues and earnings related to these contracts are included in discontinued operations while Select Energy's related and offsetting expenses and losses are included in continuing operations.

Select Energy's obligation to NGC and Mt. Tom ended at the time of the sale of the competitive generation business. See Note 6F, "Commitments and Contingencies - Guarantees and Indemnifications," for information related to a HWP coal purchase contract with a supplier and a related back-to-back agreement with the purchaser of the competitive generation business. At September 30, 2007, NU does not have or expect to have significant ongoing involvement or continuing cash flows with the entities presented in discontinued operations.

The retail marketing business is not presented as discontinued operations because separate financial information is not available for this business.

In the second quarter of 2007, the remaining contracts of Woods Electrical were completed. The results of these contracts were not material to any of the periods presented, and discontinued operations presentation was not required.

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

Contracts that are derivatives and do not meet the requirements to be treated as a cash flow hedge or normal purchase or normal sale are recorded at fair value with changes in fair value included in earnings. For those contracts that meet the definition of a derivative and meet the cash flow hedge requirements, including those related to initial and ongoing documentation, the changes in the fair value of the effective portion of those contracts are recognized in accumulated other comprehensive income. Cash flow hedges impact net income when the forecasted transaction being hedged occurs, when hedge ineffectiveness is measured and recorded, when the forecasted transaction being hedged is no longer probable of occurring, or when there is accumulated other comprehensive loss and the hedge and the forecasted transaction being hedged are in a loss position on a combined basis. The ineffective portion of contracts that meet the cash flow hedge requirements is recognized currently in earnings. Derivative contracts designated as fair value hedges and the items they are hedging are both recorded at fair value with changes in fair value of both items recognized currently in earnings. Derivative contracts that meet the requirements of a normal purchase or sale, and are so designated, are recognized in revenues or expenses, as applicable, when the quantity of the contract is delivered. The change in fair value of a normal purchase or sale contract is not included in earnings.

The tables below summarize current and long-term derivative assets and liabilities at September 30, 2007 and December 31, 2006. The fair value of these contracts may not represent amounts that will be realized. On the accompanying condensed consolidated balance sheets at September 30, 2007 and December 31, 2006, these amounts are recorded as current or long-term derivative assets or liabilities and are summarized as follows:


	At September 30, 2007
	Assets				Liabilities
	Current		Long-Term		Current		Long-Term		Net Totals
(Millions of Dollars)
NU Enterprises - Wholesale	$	45.1	$	5.5	$	(72.4)	$	(72.9)	$	(94.7)
Regulated Companies - Gas:
Non-trading		0.4		-		-		-		0.4
Regulated Companies - Electric:
Non-trading		47.6		259.2		(18.5)		(28.5)		259.8
NU Parent:
Hedging		-		-		-		(3.2)		(3.2)
Totals	$	93.1	$	264.7	$	(90. 9)	$	(104.6)	$	162.3


	At December 31, 2006
	Assets				Liabilities
	Current		Long-Term		Current		Long-Term		Net Totals
(Millions of Dollars)
NU Enterprises:
Wholesale	$	43.6	$	22.3	$	(82.3)	$	(110.1)	$	(126.5)
Retail		0.2		-		(0.1)		-		0.1
Regulated Companies - Gas:
Non-trading		0.1		-		(0.2)		-		(0.1)
Regulated Companies - Electric:
Non-trading		45.0		249.5		(43.2)		(32.0)		219.3
NU Parent:
Hedging		-		-		-		(6.5)		(6.5)
Totals	$	88.9	$	271.8	$	(125.8)	$	(148.6)	$	86.3

For the regulated companies, offsetting regulatory assets or liabilities are recorded for the changes in fair value of their contracts, as these contracts are part of stranded costs or current regulated operating costs, and management believes that these costs will continue to be recovered or refunded in cost-of-service, regulated rates.

NU Enterprises - Wholesale: Certain electric derivative contracts are part of the remaining wholesale marketing business. These contracts include wholesale short-term and long-term electricity supply and sales contracts, which include a contract to sell electricity to a utility under full requirements contracts (four other similar contracts expired on May 31, 2007), a contract to sell electricity to the New York Municipal Power Authority (NYMPA) (an agency that is comprised of municipalities) with a term of approximately six remaining years, and a contract to purchase the output of a generating plant which expired in May of 2007. The fair value of the underlying electricity contracts was determined by prices from external sources for years through 2011 and generally by models based on natural gas prices and a heat-rate conversion factor to electricity for subsequent periods. At September 30, 2007 and December 31, 2006, the net fair value of these wholesale contracts was a liability of $94.7 million and $126.5 million, respectively.

For the three months ended September 30, 2007 and 2006, NU recorded a pre-tax charge of $2.5 million and a pre-tax benefit of $4.6 million, respectively, in fuel, purchased and net interchange power related to the wholesale contracts. Similar amounts were recorded as charges of $4.6 million and $14.1 million for the nine months ended September 30, 2007 and 2006, respectively. These amounts are associated with the mark-to-market on, and changes in, the fair value of certain long-dated wholesale electricity contracts in New England, New York and PJM and a contract to purchase generation products in New York. A benefit of $0.2 million and a charge of $0.8 million was also recorded in fuel, purchased and net interchange power for the three and nine months ended September 30, 2006 related to the mark-to-market of certain asset specific sales and forward sales of electricity at hub points for generation contracts.

Regulated Companies - Gas - Non-Trading: Yankee Gas' non-trading derivatives consist of peaking supply arrangements to serve winter load obligations and firm retail sales contracts with options to curtail delivery. These contracts are subject to fair value accounting as these contracts are derivatives that cannot be designated as normal purchases and sales because of the optionality in the contract terms. These non-trading derivatives at September 30, 2007 included current assets of $0.4 million. At December 31, 2006, these non-trading derivatives included current assets of $50 thousand and current liabilities of $0.2 million. An offsetting regulatory liability and an offsetting regulatory asset were recorded for these amounts as management believes that these costs will be refunded/recovered in rates.

Regulated Companies - Electric - Non-Trading: CL&P has contracts with two independent power producers (IPP) to purchase power that contain pricing provisions that are not clearly and closely related to the price of power and therefore do not qualify for the normal purchases and sales exception. The fair values of these IPP non-trading derivatives at September 30, 2007 include a derivative asset

with a fair value of $306.1 million and a derivative liability with a fair value of $30.6 million. An offsetting regulatory liability and an offsetting regulatory asset were recorded, as these contracts are part of stranded costs, and management believes that these costs will continue to be recovered or refunded in cost-of-service, regulated rates. At December 31, 2006, the fair values of these IPP non-trading derivatives included a derivative asset with a fair value of $289.6 million and a derivative liability with a fair value of $35.6 million.

CL&P has entered into Financial Transmission Rights contracts and bilateral basis swaps to limit the congestion costs associated with its standard offer contracts. An offsetting regulatory asset or liability has been recorded as management believes that these costs will be recovered or refunded in rates. At September 30, 2007, the fair value of these contracts is recorded as a derivative liability of $3.6 million on the accompanying condensed consolidated balance sheets. At December 31, 2006, the fair value of those contracts was recorded as a derivative asset of $4.9 million and a derivative liability of $0.4 million on the accompanying condensed consolidated balance sheets.

Pursuant to Public Act 05-01, "An Act Concerning Energy Independence," in August of 2007 the Department of Public Utility Control (DPUC) approved two CL&P contracts associated with the capacity of two generating projects to be built or modified. The DPUC also approved two capacity-related contracts entered into by United Illuminating Corporation (UI), one with a generating project to be built and one with a new demand response project. The total capacity of these four projects is expected to be 787 megawatts (MW). The contracts, referred to as contracts for differences (CFDs), obligate the utilities to pay the difference between a set capacity price and the value 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 has an agreement with UI under which it will share the costs and benefits of these four CFDs, with 80 percent to CL&P and 20 percent to UI. The ultimate cost to CL&P under the contracts will depend on the capacity prices that the projects receive in the ISO-NE capacity markets. Due to the significance of the non-observable inputs associated with modeling the fair values of these derivative contracts, their fair values are not reflected in the accompanying condensed consolidated financial statements in accordance with Emerging Issues Task Force (EITF) No. 02-3, "Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities."

PSNH has electricity procurement contracts that are non-trading derivatives at September 30, 2007. The fair value of these contracts is calculated based on market prices and is recorded as a derivative asset of $0.6 million and a derivative liability of $12.8 million at September 30, 2007. At December 31, 2006, the fair value was recorded as a derivative liability of $28.4 million. An offsetting regulatory liability/asset was recorded as management believes that these costs will be refunded/recovered in rates as the energy is delivered.

In 2007, PSNH entered into a contract to assign transmission rights of a Hydro-Quebec direct current line in exchange for two energy call options. These energy call options are derivatives that do not qualify for the normal purchases and sales exception and are accounted for at fair value calculated based on market prices. At September 30, 2007, the options are recorded as a derivative asset of $0.1 million. An offsetting regulatory liability was recorded, as the benefit of this arrangement will be refunded to customers in rates.

At December 31, 2006, PSNH had a contract to purchase oil that was a non-trading derivative, the fair value of which was recorded as a derivative liability of $10.8 million. An offsetting regulatory asset was recorded as management believes that this cost will be recovered in rates through a deferral mechanism that tracks generation revenues and costs. As of September 30, 2007, this contract has expired.

NU Parent - Hedging: In March of 2003, to manage the interest rate characteristics of the company's long-term debt, NU parent entered into a fixed to floating interest rate swap on its $263 million, 7.25 percent fixed rate note that matures on April 1, 2012. Under fair value hedge accounting, the changes in fair value of the swap and the hedged long-term debt instrument are recorded in interest expense. The cumulative changes in the fair value of the swap and the long-term debt are recorded as derivative liabilities and decreases to long-term debt of $3.2 million at September 30, 2007 and $6.5 million at December 31, 2006.

GOODWILL (Yankee Gas)

SFAS No. 142, "Goodwill and Other Intangible Assets," requires that goodwill and intangible assets deemed to have indefinite useful lives be reviewed for impairment at least annually by applying a fair value-based test. NU uses October 1^stas the annual goodwill impairment testing date. Goodwill impairment is deemed to exist if the net book value of a reporting unit exceeds its estimated fair value and if the implied fair value of goodwill based on the estimated fair value of the reporting unit is less than the carrying amount.

The only NU reporting unit that currently maintains goodwill is the Yankee Gas reporting unit, which is classified under the regulated companies - gas reportable segment. The goodwill recorded related to the acquisition of Yankee Gas is not being recovered from the customers of Yankee Gas. The goodwill balance was $287.6 million at both September 30, 2007 and December 31, 2006. The company is currently in the process of completing the annual impairment test of the Yankee Gas goodwill as of October 1, 2007.

For information regarding NU's reportable segments, see Note 10, "Segment Information," to the condensed consolidated financial statements.

COMMITMENTS AND CONTINGENCIES

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

Connecticut:

CTA and SBC Reconciliation: The Competitive Transition Assessment (CTA) allows CL&P to recover stranded costs, such as securitization costs associated with its rate reduction bonds, amortization of regulatory assets, and independent power producer over-market costs, while the System Benefits Charge (SBC) allows CL&P to recover certain regulatory and energy public policy costs, such as public education outreach costs, hardship protection costs, transition period property taxes, and displaced worker protection costs.

On March 30, 2007, CL&P filed its 2006 CTA and SBC reconciliation, which compared CTA and SBC revenues to revenue requirements, with the DPUC. For the year ended December 31, 2006, total CTA cost of service exceeded CTA revenues by $5.6 million. This amount was recorded as a regulatory asset on the accompanying condensed consolidated balance sheets. In addition, CTA refunds for the period January 2006 through August 2006 totaled $99.8 million and resulted in an additional increase to CL&P’s CTA regulatory asset. For the year ended December 31, 2006, the SBC cost of service exceeded SBC revenues by $24.3 million.

The DPUC issued a final decision in this docket on October 10, 2007. That decision approved the CTA reconciliation with minor modifications. The SBC reconciliation was approved with an adjustment to the timing of the recovery of a regulatory asset associated with a reserve for hardship customers accounts receivable greater than 90 days old totaling $17.2 million. In its decision, the DPUC determined that CL&P should amortize and recover the $17.2 million regulatory asset over five years, or approximately $3.4 million per year. The DPUC's decision also ordered CL&P to set the SBC rate to collect revenues at an annual level of $21 million, effective on January 1, 2008.

Procurement Fee Rate Proceedings: By law, CL&P was allowed to collect a fixed procurement fee of 0.50 mills per kilowatt-hour (KWH) from customers who purchased transitional standard offer (TSO) service from 2004 through the end of 2006. On December 8, 2005, a draft decision was issued by the DPUC, which accepted the methodology proposed by CL&P to calculate the variable portion (incentive portion) of the procurement fee and authorized payment of $5.8 million for its 2004 incentive fee. A final decision, which had been scheduled for December of 2005, was delayed by the DPUC, and the DPUC re-opened the docket to review additional testimony.

On April 17, 2007, CL&P filed an application with the DPUC for approval of incentive payments for the years 2005 and 2006. The incentive portion of the procurement fee earned for 2005 was $6 million and for 2006 was $5.5 million. The DPUC rejected this application and directed CL&P to refile after a DPUC decision on the 2004 case. On October 19, 2007, the DPUC released a recommendation prepared by its consultant relative to statistical adjustments to the incentive calculations. The DPUC has set a new schedule allowing for rebuttal of the consultant’s report. The new schedule calls for a final decision in this docket in February of 2008.

Management continues to believe that recovery of the $5.8 million asset related to CL&P's 2004 incentive payment, which was reflected in 2005 earnings, is probable. No amounts have been recorded for the 2005 or 2006 incentive portions of CL&P's procurement fee. The procurement fee expired at the end of 2006.

Purchased Gas Adjustment: On September 9, 2005, the DPUC issued a draft decision regarding Yankee Gas Purchased Gas Adjustment (PGA) clause charges for the period of September 1, 2003 through August 31, 2004. The draft decision disallowed approximately $9 million in previously recovered PGA revenues associated with two separate Yankee Gas unbilled sales and revenue adjustments. At the request of Yankee Gas, the DPUC reopened the PGA hearings on September 20, 2005 and requested that Yankee Gas file supplemental information regarding the two adjustments. Yankee Gas complied with this request. The DPUC issued a new decision on April 20, 2006 requiring an audit of Yankee Gas' previously recovered PGA costs and deferred any conclusion on the $9 million of previously recovered revenues until the completion of the audit. In a subsequent draft decision regarding Yankee Gas PGA charges for the period September 1, 2004 through August 31, 2005, an additional $2 million related to previously recovered revenues was also identified, bringing the total maximum amount at issue with regard to PGA clause charges under audit to approximately $11 million.

The DPUC hired a consulting firm which has concluded an audit of Yankee Gas' previously recovered PGA costs and has submitted its final report. A DPUC hearing was held on October 9, 2007. Management believes the unbilled sales and revenue adjustments and resulting charges to customers through the PGA clause for both periods were appropriate. Based on the facts of the case, the

supplemental information provided to the DPUC and the consultant’s final report, management believes the appropriateness of the PGA charges to customers for the time period under review will be approved, and has not reserved for any loss.

Massachusetts:

Transition Cost Reconciliations: WMECO filed its 2005 transition cost reconciliation with the Massachusetts Department of Public Utilities (DPU) on March 31, 2006 and filed its 2006 transition cost reconciliation with the DPU on March 31, 2007. The DPU opened a proceeding for these filings and evidentiary hearings were held on August 29, 2007. The briefing process was completed during October of 2007. The timing of the decision in this docket is uncertain. Management does not expect the outcome of the DPU's review of these filings to have a material adverse impact on WMECO's net income, financial position or cash flows.

NRG Energy, Inc. Exposures (CL&P, Yankee Gas)

Certain subsidiaries of NU, including CL&P and Yankee Gas, entered into transactions with NRG Energy, Inc. (NRG) and certain of its subsidiaries. On May 14, 2003, NRG and certain subsidiaries of NRG filed voluntary bankruptcy petitions, and on December 5, 2003, NRG emerged from bankruptcy. NU's NRG-related exposures as a result of these transactions relate to 1) the refunding of approximately $28 million of congestion charges previously withheld from NRG prior to the implementation of standard market design (SMD) on March 1, 2003, 2) the recovery of approximately $29.1 million of CL&P's station service billings from NRG, which is currently the subject of an arbitration, and 3) the recovery of, among other claimed damages, approximately $17.5 million of capital costs and expenses incurred by Yankee Gas related to an NRG subsidiary's generating plant construction project that has ceased.

On July 20, 2007, the United States District Court for the District of Connecticut issued a ruling granting CL&P's motion for summary judgment against NRG in the pre-SMD congestion litigation. In this decision, the court concluded that NRG was contractually obligated to pay for congestion charges imposed during the term of the October 29, 1999 standard offer service wholesale sales agreement between CL&P and NRG and found in favor of CL&P and against NRG on each of NRG's four counterclaims. NRG did not appeal the judgment and the matter is closed.

While it is unable to determine the ultimate outcome of the two remaining issues, management does not expect their resolution will have a material adverse effect on NU's consolidated net income, financial position or cash flows.

Long-Term Contractual Arrangements (CL&P, PSNH, Select Energy)

CL&P: These amounts represent commitments for various services and materials associated with the Middletown to Norwalk, Glenbrook Cables and the Norwalk to Northport-Long Island, New York transmission projects and other projects as of September 30, 2007:

(Millions of Dollars)

2007

2008

2009

2010

2011

Thereafter

Total

Transmission segment
project commitments

199.3

399.6

28.9

627.8

In May of 2007, CL&P and UI entered into a 15-year agreement beginning in 2010 to purchase energy, capacity and renewable energy credits from a biomass energy plant yet to be built. The agreement has been approved by the DPUC. CL&P's payments under this agreement will depend on the quantities purchased and the price of energy, and are currently estimated to be approximately $15 million annually from 2010 to 2024 before the reduction for UI's share under a sharing agreement signed and filed with the DPUC. Under this agreement, CL&P and UI will share the costs and benefits of the contract, with 80 percent to CL&P and 20 percent to UI.

PSNH: PSNH has entered into various arrangements for the purchase of wood, coal and transportation services for fuel supply for its electric generating assets. These purchase commitments at September 30, 2007 are as follows:


(Millions of Dollars)	2007		2008		2009		2010		2011		Thereafter		Total
Wood, coal and transportation contracts	$	29.0	$	101.8	$	57.0	$	44.2	$	31.3	$	3.1	$	266.4

Select Energy: Select Energy maintains long-term agreements to purchase energy as part of its portfolio of resources to meet its actual or expected sales commitments. Most purchase commitments are recorded at their mark-to-market value as derivative assets and liabilities on the condensed consolidated balance sheets with the exception of one non-derivative contract which is accounted for on the accrual basis. These purchase commitments at September 30, 2007 are as follows:


(Millions of Dollars)	2007		2008		2009		2010		2011		Thereafter		Total
Select Energy purchase commitments	$	100.3	$	193.3	$	29.7	$	32.1	$	31.2	$	84.8	$	471.4

Select Energy's purchase commitment amounts exceed the amount expected to be reported in fuel, purchased and net interchange power because many wholesale sales transactions are also classified in fuel, purchased and net interchange power, and certain purchases are included in revenues.

The amounts and timing of the costs associated with Select Energy's purchase agreements may be impacted by the exit from the NU Enterprises' businesses.

Environmental Matters (HWP)

The company remains in the process of evaluating additional potential remediation requirements at a river site in Massachusetts containing tar deposits. HWP is at least partially responsible for this site, and substantial remediation activities at this site have already been conducted. HWP first established a reserve for this site in 1994. Since that time, HWP has expensed approximately $13 million, of which $12.4 million has been spent and $0.6 million remains in the reserve. HWP's reserve is based on its most recent site assessment and estimate of required remediation costs. The ultimate remediation requirements will depend, among other things, on the level and extent of the remaining tar required to be removed, and the extent of HWP’s responsibility. These matters are the subject of ongoing discussions with the Massachusetts Department of Environmental Protection and may change from time-to-time. HWP's share of the remediation costs related to this site is not recoverable from ratepayers. At this time, management cannot predict the outcome of this matter or its ultimate effect on NU. Any additional increase to the environmental remediation reserve for this site would be recorded in earnings in future periods when it is reasonably estimable and probable, and potential increases may be material. There were no changes to the environmental reserve for this site in the third quarter of 2007.

Consolidated Edison, Inc. Merger Litigation (NU)

Certain gain and loss contingencies exist with regard to the merger agreement between NU and Consolidated Edison, Inc. (Con Edison) and the related litigation.

In 2001, Con Edison advised NU that it was unwilling to close its merger with NU on the terms set forth in the parties' 1999 merger agreement (Merger Agreement). In March of 2001, NU filed suit against Con Edison seeking damages in excess of $1 billion.

In a 2005 opinion, a panel of three judges at the Second Circuit held that the shareholders of NU had no right to sue Con Edison for its alleged breach of the parties' Merger Agreement. This ruling left intact the remaining claims between NU and Con Edison for breach of contract, which include NU's claim for recovery of costs and expenses of approximately $32 million and Con Edison's claim for damages of "at least $314 million." NU's request for a rehearing was denied in 2006. NU opted not to seek review of this ruling by the United States Supreme Court. In April of 2006, NU filed its motion for partial summary judgment on Con Edison's damage claim. NU's motion asserts that NU is entitled to a judgment in its favor with respect to this claim based on the undisputed material facts and applicable law. The matter is fully briefed and awaiting a decision. At this time, NU cannot predict the outcome of this matter or its ultimate effect on NU.

Guarantees and Indemnifications (All Companies)

NU provides credit assurances on behalf of subsidiaries in the form of guarantees and letters of credit (LOCs) in the normal course of business. In addition, NU has provided guarantees and various indemnifications on behalf of external parties as a result of the sales of SESI, the retail marketing business and the competitive generation business. The following table summarizes NU's maximum exposure at September 30, 2007, in accordance with FIN 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others," expiration dates, and fair value of amounts recorded.


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

SESI	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	Not Specified	(1)	Through project completion	0.2

	Indemnifications to lenders for payment of shortfalls in the event of early termination of government contracts	$2.3		2017-2018	0.1

	Surety bonds covering certain projects	$79.8		Through project completion (2)	-

Hess (Retail Marketing Business)	General indemnifications in connection with the sale including compliance with laws, validity of contract information, completeness and accuracy of information provided, absence of default on contracts, and various claims	Not Specified	(1)	None	-

ECP (Competitive Generation Business)	General indemnifications in connection with the sale of NGC and the generating assets of Mt. Tom including compliance with laws, validity of contract information, completeness and accuracy of information provided, absence of default on contracts, and various claims	Not Specified	(1)	None	-
On behalf of subsidiaries:

Regulated Companies	Surety bonds, primarily for self-insurance	$15.3		None	N/A
	Letters of credit	$28.0		2007-2008	N/A

Rocky River Realty Company	Lease payments for real estate	$11.2		2024	N/A

NUSCO	Lease payments for fleet of vehicles	$9.6		None	N/A

SECI-CT and Boulos	Surety bonds covering ongoing projects	$69.0		Through project completion	N/A

NGS	Performance guarantee and insurance bonds	$23.9	(3)	2020 (3)	N/A

Select Energy	Performance guarantees and surety bonds for retail marketing contracts	$5.4	(4)	None (5)	N/A

	Performance guarantees for wholesale contracts	$66.6	(4)	2013	N/A

	Letters of credit	$7.0		2007	N/A

HWP	Performance and payment guarantee related to coal purchase contract	Not Specified	(6)	2009	N/A

(1)

There is no specified maximum exposure included in the related sale agreements. For retail marketing business guarantees, all claims are subject to a $0.3 million threshold.

(2)

The company expects appropriate acknowledgment of project completion for the majority of these surety bonds by the end of the first quarter of 2008. In October of 2007, $2.6 million of these bonds were removed from the maximum exposure amount.

(3)

Included in the maximum exposure is $22.7 million related to a performance guarantee of NGS's obligations for which there is no specified maximum exposure in the agreement. The maximum exposure is calculated as of September 30, 2007 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 which are billed annually on their anniversary date.

(4)

Maximum exposure is as of September 30, 2007; however, exposures vary with underlying commodity prices and for certain contracts are essentially unlimited. The performance guarantees for the wholesale contracts are expected to expire in 2013.

(5)

NU does not currently anticipate that these remaining guarantees on behalf of Select Energy will result in significant guarantees of the performance of Hess.

(6)

There is no specified maximum exposure included in this guarantee agreement. NU has guaranteed the performance of HWP under a back-to-back agreement with Energy Capital Partners (ECP) relating to an HWP coal supply contract. The maximum exposure to loss under very unlikely circumstances is estimated at approximately $46.6 million at September 30, 2007. NU would have recourse to ECP for approximately $35 million, of which $2 million is secured by an LOC.

Several 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.

In July of 2006, under its former SESI guarantee, NU was required to purchase contract payments relating to the only guaranteed SESI project that was financed and behind schedule. Through September 30, 2007, NU has recorded a $0.5 million loss to reduce the carrying value of the contract payments purchased to the amount expected to be received from refinancing through SESI's completion of the project. The carrying value of these assets is $8.8 million at September 30, 2007 and is included in other deferred debits on the accompanying condensed consolidated balance sheets. NU may record additional losses associated with this transaction, the amount of which will depend on changes in interest rates used to determine SESI's refinancing proceeds, the amount of project cash available to offset NU's costs, and other factors.

Transmission Rate Matters and FERC Regulatory Issues (CL&P, PSNH, WMECO)

Pursuant to an October 31, 2006 FERC return on equity (ROE) decision, the New England transmission owners submitted a compliance filing that calculated the refund amounts for transmission customers for the February 1, 2005 to October 31, 2006 time period. Subsequently, on July 26, 2007, the FERC disagreed with the ROEs the transmission owners used in their refund calculations for the 15-month period between June 3, 2005 and September 3, 2006, rejected a portion of the compliance filing, and required another compliance filing within 30 days. On August 27, 2007, NU and the other New England transmission owners filed a revised compliance filing which outlined the regional refund process to comply with the FERC's July 26, 2007 order. In addition, the transmission owners filed a request for rehearing on the issue of the last clean rate doctrine for the period from June 3, 2005 to September 3, 2006. NU is awaiting a final FERC determination on this issue.

NU's transmission companies currently estimate additional related pre-tax refunds to be $3.4 million (approximately $2 million after-tax). NU's distribution companies would receive a net after-tax benefit of approximately $0.3 million as a result of these refunds. The additional estimated refunds and benefits totaling $1.7 million after-tax were recorded in the third quarter of 2007.

COMPREHENSIVE INCOME (NU, CL&P, PSNH, WMECO, NU Enterprises, Yankee Gas)

Total comprehensive income, which includes all comprehensive income/(loss) items by category, for the three and nine months ended September 30, 2007 and 2006 is as follows:


	Three Months Ended September 30, 2007
(Millions of Dollars)	NU*		CL&P		PSNH		WMECO		NU Enterprises		Yankee Gas		Other
Net income/(loss)	$	50.2	$	33.6	$	13.0	$	5.3	$	0.7	$	(3.4)	$	1.0
Comprehensive (loss)/income items:
Qualified cash flow hedging items		(5.2)		(4.6)		-		(0.6)		-		-		-
Unrealized losses on securities		(0.7)		-		-		(0.1)		-		-		(0.6)
Pension, SERP, and other postretirement benefits		1.7		-		-		-		5.6		-		(3.9)
Net change in comprehensive (loss)/income items		(4.2)		(4.6)		-		(0.7)		5.6		-		(4.5)
Total comprehensive income/(loss)	$	46.0	$	29.0	$	13.0	$	4.6	$	6.3	$	(3.4)	$	(3.5)


	Three Months Ended September 30, 2006
(Millions of Dollars)	NU*		CL&P		PSNH		WMECO		NU Enterprises		Yankee Gas		Other
Net income/(loss)	$	111.5	$	99.6	$	7.9	$	3.7	$	3.2	$	(5.3)	$	2.4
Comprehensive loss items:
Unrealized losses on securities		(0.9)		-		(0.1)		(0.1)		-		-		(0.7)
Net change in comprehensive loss items		(0.9)		-		(0.1)		(0.1)		-		-		(0.7)
Total comprehensive income/(loss)	$	110.6	$	99.6	$	7.8	$	3.6	$	3.2	$	(5.3)	$	1.7


	Nine Months Ended September 30, 2007
(Millions of Dollars)	NU*		CL&P		PSNH		WMECO		NU Enterprises		Yankee Gas		Other
Net income	$	173.8	$	91.6	$	38.2	$	16.8	$	8.1	$	10.5	$	8.6
Comprehensive (loss)/income items:
Qualified cash flow hedging instruments		(6.8)		(6.2)		-		(0.7)		-		-		0.1
Unrealized gains/(losses) on securities		0.6		-		-		(0.1)		-		-		0.7
Pension, SERP, and other postretirement benefits		8.0		-		-		-		9.4		-		(1.4)
Net change in comprehensive income/(loss) items		1.8		(6.2)		-		(0.8)		9.4		-		(0.6)
Total comprehensive income	$	175.6	$	85.4	$	38.2	$	16.0	$	17.5	$	10.5	$	8.0


	Nine Months Ended September 30, 2006
(Millions of Dollars)	NU*		CL&P		PSNH		WMECO		NU Enterprises		Yankee Gas		Other
Net income/(loss)	$	123.6	$	148.2	$	27.9	$	11.5	$	(73.7)	$	6.4	$	3.3
Comprehensive income/(loss) items:
Qualified cash flow hedging instruments		13.2		(4.6)		-		0.1		17.8		-		(0.1)
Unrealized losses on securities		(1.0)		-		(0.1)		(0.2)		-		-		(0.7)
Other		2.3		-		-		-		-		-		2.3
Net change in comprehensive income/(loss) items		14.5		(4.6)		(0.1)		(0.1)		17.8		-		1.5
Total comprehensive income/(loss)	$	138.1	$	143.6	$	27.8	$	11.4	$	(55.9)	$	6.4	$	4.8

*After preferred dividends of subsidiary.

Comprehensive income amounts included in the Other column primarily relate to NU parent and Northeast Utilities Service Company (NUSCO).

Accumulated other comprehensive income fair value adjustments in NU's qualified cash flow hedging instruments for the nine months ended September 30, 2007 and the twelve months ended December 31, 2006 are as follows:


(Millions of Dollars, Net of Tax)	Nine Months Ended September 30, 2007		Twelve Months Ended December 31, 2006
Balance at beginning of period	$	5.9	$	18.2
Hedged transactions recognized into earnings		0.1		2.3
Amount reclassified into earnings due to discontinuation of cash flow hedges		-		(14.1)
Change in fair value of hedged transactions delivered		-		(4.5)
Cash flow transactions entered into for the period		(6.9)		4.0
Net change associated with the current period hedging transactions		(6.8)		(12.3)
Total fair value adjustments included in accumulated other comprehensive income	$	(0.9)	$	5.9

In the first quarter of 2006, $14.1 million was reclassified from accumulated other comprehensive income into earnings (included in other operation expenses) due to discontinuing cash flow hedge accounting and the conclusion that the retail marketing contracts hedged beyond June 1, 2006 were no longer probable of physical delivery due to the retail business being sold.

In March of 2006, CL&P entered into a forward lock agreement to hedge the interest rate associated with $125 million of its $250 million, 30-year fixed rate long-term debt issuance. Under the agreement, CL&P locked in a LIBOR swap rate of 5.322 percent based on the notional amount of $125 million in long-term debt that was issued in June of 2006. On June 1, 2006, the hedge was settled, and a net of tax charge of $4.6 million, ($7.8 million pre-tax), was recorded in accumulated other comprehensive income to be amortized into earnings over the term of the long-term debt.

In February of 2007, CL&P entered into two forward lock agreements to hedge the interest rates associated with $75 million of its $150 million, 10-year fixed rate long-term debt issuance and with $75 million of its $150 million, 30-year fixed rate long-term debt issuance. Under the agreements, CL&P locked in a LIBOR swap rate of 5.229 percent for the 10-year hedge and 5.369 percent for the 30-year hedge, both based on the notional amounts of $75 million in long-term debt that was issued in March of 2007. On March 27, 2007, the hedge was settled and a net-of-tax charge of $1.6 million ($2.6 million pre-tax), was recorded in accumulated other comprehensive income to be amortized into earnings over the terms of the long-term debt.

In July of 2007, CL&P entered into two forward lock agreements to hedge the interest rates associated with $50 million of its $100 million, 10-year fixed rate long-term debt issuance and with $50 million of its $100 million, 30-year fixed rate long-term debt issuance. Under the agreements, CL&P locked in a LIBOR swap rate of 5.718 percent for the 10-year hedge and 5.865 percent for the 30-year hedge, both based on the notional amounts of $50 million in long-term debt that was issued in July of 2007. On July 16, 2007, the hedge was settled and a net-of-tax charge of $4.7 million ($7.7 million pre-tax), was recorded in accumulated other comprehensive income to be amortized into earnings over the terms of the long-term debt. In addition, a net of tax charge of $67,000 ($110,000 pre-tax) was recorded related to ineffectiveness incurred upon termination of the hedge.

Also, in July of 2007, WMECO entered into a forward lock agreement to hedge the interest rate associated with its $40 million, 30-year fixed rate long-term debt issuance. Under the agreement, WMECO locked in a LIBOR swap rate of 5.882 percent based on the notional amount of $40 million in long-term debt that was issued in July of 2007. On August 15, 2007, the hedge was settled and a net-of-tax charge of $0.6 million ($1 million pre-tax), was recorded in accumulated other comprehensive income to be amortized into earnings over the term of the long-term debt.

It is estimated that a charge of $192,000 will be reclassified as a decrease to earnings over the next twelve months, as a result of amortization of the interest rate locks.

Accumulated other comprehensive income items unrelated to NU's cash flow hedging instruments totaled a positive $7.2 million and a negative $1.4 million at September 30, 2007 and December 31, 2006, respectively. These amounts relate to net unrealized gains on investments in marketable debt and equity securities and amounts recorded for pension, supplemental executive retirement plan (SERP) and other postretirement benefits, net of related income taxes related to the implementation of SFAS No. 158, "Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans."

At September 30, 2007, it is estimated that a pre-tax $0.6 million included in the accumulated other comprehensive income balance will be reclassified as a decrease to earnings in the next year related to pension, SERP and other postretirement benefits adjustments.

EARNINGS PER SHARE (NU)

Earnings per share (EPS) is computed based upon the 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 weighted-average number of common shares outstanding plus the potential dilutive effect if certain securities are converted into common stock. The following table excludes 152,050 options for the nine months ended September 30, 2006, as these options were antidilutive. There were no antidilutive options for the three months ended September 30, 2006 or the three and nine months ended September 30, 2007. The following table sets forth the components of basic and fully diluted EPS:


	For the Three Months Ended September 30,				For the Nine Months Ended September 30,
(Millions of Dollars, Except for Share Information)	2007		2006		2007		2006
Income from continuing operations	$	50.2	$	102.7	$	172.6	$	96.3
Income from discontinued operations		-		8.8		1.2		27.3
Net income	$	50.2	$	111.5	$	173.8	$	123.6
Basic EPS common shares outstanding (average)		154,930,930		153,883,480		154,672,270		153,651,610
Dilutive effect		489,309		437,195		538,434		385,160
Fully diluted EPS common shares outstanding (average)		155,420,239		154,320,675		155,210,704		154,036,770
Basic and Fully Diluted EPS:
Income from continuing operations	$	0.32	$	0.67	$	1.12	$	0.63
Income from discontinued operations		-		0.05		-		0.17
Basic and fully diluted EPS	$	0.32	$	0.72	$	1.12	$	0.80

Restricted share units (RSUs) are included in basic common shares outstanding when shares are both vested and issued. The dilutive effect of RSUs granted but not 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 difference between the market value of RSUs outstanding but not issued 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 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 previous table.

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

NU's subsidiaries participate in a uniform noncontributory defined benefit retirement plan (Pension Plan) covering substantially all regular NU employees and also provide certain health care benefits, primarily medical and dental, and life insurance benefits through a benefit plan to retired employees (PBOP Plan). In addition, NU maintains a SERP which provides benefits to eligible participants, who are officers of NU, that would have been provided to them under NU’s Pension Plan if certain Internal Revenue Code and other limitations were not imposed.

NU estimated the December 31, 2006 prepaid or accrued PBOP Plan asset or obligation based on an actuarial valuation as of the beginning of the year (January 1, 2006), adjusted for known changes during the year such as actual earnings, interest rate levels, expenses incurred and benefits paid during the year. The estimated December 31, 2006 balance was also used to estimate the related 2007 PBOP Plan income or expense and the prepaid or accrued PBOP Plan asset or obligation recorded through the second quarter of 2007. The December 31, 2006 year end estimates were adjusted and recorded in the third quarter of 2007 based on an actuarial valuation using actual data as of January 1, 2007. The actuarial valuation resulted in a decrease to the accrued PBOP Plan liability of $14.5 million with a decrease to the regulatory asset for deferred benefits of $13 million and an increase to accumulated other comprehensive income of approximately $0.9 million, net of tax.

The pre-tax, pre-capitalization earnings impact of this change in estimate is to decrease annual 2007 PBOP Plan expense by approximately $1.4 million.

The components of net periodic benefit expense/(income) for the Pension Plan, PBOP Plan and SERP for the three and nine months ended September 30, 2007 and 2006 are as follows:


NU	For the Three Months Ended September 30,
	Pension Benefits				Postretirement Benefits				SERP Benefits
(Millions of Dollars)	2007		2006		2007		2006		2007		2006
Service cost	$	11.4	$	12.4	$	1.6	$	2.1	$	0.2	$	0.3
Interest cost		33.7		33.1		6.2		6.8		0.5		0.5
Expected return on plan assets		(48.4)		(43.8)		(4.6)		(3.5)		-		-
Amortization of unrecognized net transition obligation		-		-		3.2		3.1		-		-
Amortization of prior service cost		2.5		1.8		(0.1)		(0.1)		-		-
Amortization of actuarial loss		4.1		10.9		2.9		4.4		0.2		0.2
Net periodic expense - before curtailments and termination benefits		3.3		14.4		9.2		12.8		0.9		1.0
Curtailments		-		(4.2)		-		(1.5)		-		-
Termination benefits		(0.3)		(0.7)		-		(0.2)		-		-
Total curtailments and termination benefits		(0.3)		(4.9)		-		(1.7)		-		-
Total - net periodic expense	$	3.0	$	9.5	$	9.2	$	11.1	$	0.9	$	1.0


NU	For the Nine Months Ended September 30,
	Pension Benefits				Postretirement Benefits				SERP Benefits
(Millions of Dollars)	2007		2006		2007		2006		2007		2006
Service cost	$	35.7	$	37.0	$	5.8	$	6.2	$	0.6	$	0.8
Interest cost		102.8		96.6		19.5		20.5		1.5		1.5
Expected return on plan assets		(146.8)		(130.2)		(13.7)		(10.5)		-		-
Amortization of unrecognized net transition obligation/(asset)		0.1		(0.1)		9.0		8.6		-		-
Amortization of prior service cost		6.4		4.8		(0.2)		(0.2)		0.1		0.1
Amortization of actuarial loss		15.9		30.3		8.7		13.4		0.5		0.7
Net periodic expense - before curtailments and termination benefits		14.1		38.4		29.1		38.0		2.7		3.1
Curtailments		-		(4.9)		-		(2.1)		-		-
Termination benefits		(0.3)		-		-		0.3		-		-
Total curtailments and termination benefits		(0.3)		(4.9)		-		(1.8)		-		-
Total - net periodic expense	$	13.8	$	33.5	$	29.1	$	36.2	$	2.7	$	3.1

A portion of these pension amounts is capitalized related to current employees that are working on capital projects. Amounts capitalized were approximately $0.4 million and a de minimis amount for the three and nine months ended September 30, 2007, respectively, and $7.7 million and $12.9 million for the three and nine months ended September 30, 2006, respectively. The amounts for the three and nine months ended September 30, 2007 offset capital costs, as pension income was recorded for those periods for certain of NU's subsidiaries.


CL&P	For the Three Months Ended September 30,
	Pension Benefits				Postretirement Benefits				SERP Benefits
(Millions of Dollars)	2007		2006		2007		2006		2007		2006
Service cost	$	3.9	$	4.2	$	0.5	$	0.7	$	-	$	-
Interest cost		12.1		12.1		2.4		2.8		-		0.1
Expected return on plan assets		(22.5)		(20.4)		(1.8)		(1.4)		-		-
Amortization of unrecognized net transition obligation		-		-		1.2		1.7		-		-
Amortization of prior service cost		1.0		0.8		-		-		-		-
Amortization of actuarial loss		1.2		4.1		1.5		1.7		0.1		-
Net periodic (income)/expense - before curtailments and termination benefits		(4.3)		0.8		3.8		5.5		0.1		0.1
Curtailments		-		(1.0)		-		(0.8)		-		-
Termination benefits		-		(0.4)		-		-		-		-
Total curtailments and termination benefits		-		(1.4)		-		(0.8)		-		-
Total - net periodic (income)/expense	$	(4.3)	$	(0.6)	$	3.8	$	4.7	$	0.1	$	0.1


CL&P	For the Nine Months Ended September 30,
	Pension Benefits				Postretirement Benefits				SERP Benefits
(Millions of Dollars)	2007		2006		2007		2006		2007		2006
Service cost	$	12.2	$	12.8	$	1.9	$	2.1	$	-	$	-
Interest cost		36.8		35.9		7.6		8.3		0.1		0.2
Expected return on plan assets		(68.2)		(61.0)		(5.4)		(4.1)		-		-
Amortization of unrecognized net transition obligation		-		-		4.3		4.6		-		-
Amortization of prior service cost		2.8		2.0		-		-		-		-
Amortization of actuarial loss		5.1		11.9		3.8		5.3		0.1		0.1
Net periodic (income)/expense - before curtailments and termination benefits		(11.3)		1.6		12.2		16.2		0.2		0.3
Curtailments		-		(1.3)		-		(1.4)		-		-
Termination benefits		-		(0.8)		-		(0.1)		-		-
Total curtailments and termination benefits		-		(2.1)		-		(1.5)		-		-
Total - net periodic (income)/expense	$	(11.3)	$	(0.5)	$	12.2	$	14.7	$	0.2	$	0.3

Not included in the pension (income)/expense amounts above are intercompany allocations totaling $2.6 million and $8.6 million for the three and nine months ended September 30, 2007, respectively, and $2.7 million and $8.8 million for the three and nine months ended September 30, 2006, respectively. Intercompany allocations of postretirement benefits totaled $1.9 million and $5.5 million for the three and nine months ended September 30, 2007, respectively, and $1.7 million and $5.6 million for the three and nine months ended September 30, 2006, respectively. Intercompany allocations of SERP benefits totaled $0.5 million and $1.4 million for the three and nine months ended September 30, 2007, respectively, and $0.5 million and $1.5 million for the three and nine months ended September 30, 2006, respectively

For CL&P, a portion of the pension amounts, including intercompany allocations, is capitalized related to current employees that are working on capital projects. Amounts capitalized were $1.3 million and $3.2 million for the three and nine months ended September 30, 2007, respectively, and $3 million and $4.4 million for the three and nine months ended September 30, 2006, respectively. The amounts for the three and nine months ended September 30, 2007 offset capital costs, as pension income was recorded for those periods.


PSNH	For the Three Months Ended September 30,
	Pension Benefits				Postretirement Benefits				SERP Benefits
(Millions of Dollars)	2007		2006		2007		2006		2007		2006
Service cost	$	2.3	$	2.4	$	0.4	$	0.5	$	-	$	-
Interest cost		5.3		5.2		1.2		1.2		0.1		-
Expected return on plan assets		(4.4)		(4.2)		(0.8)		(0.6)		-		-
Amortization of unrecognized net transition obligation		0.1		0.1		0.6		0.6		-		-
Amortization of prior service cost		0.5		0.4		-		-		-		-
Amortization of actuarial loss		0.9		1.7		0.6		0.8		-		0.1
Net periodic expense - before curtailments and termination benefits		4.7		5.6		2.0		2.5		0.1		0.1
Curtailments		-		(0.7)		-		(0.1)		-		-
Termination benefits		-		(0.1)		-		-		-		-
Total curtailments and termination benefits		-		(0.8)		-		(0.1)		-		-
Total - net periodic expense	$	4.7	$	4.8	$	2.0	$	2.4	$	0.1	$	0.1


PSNH	For the Nine Months Ended September 30,
	Pension Benefits				Postretirement Benefits				SERP Benefits
(Millions of Dollars)	2007		2006		2007		2006		2007		2006
Service cost	$	7.3	$	7.2	$	1.3	$	1.3	$	-	$	-
Interest cost		16.3		15.2		3.6		3.7		0.1		0.1
Expected return on plan assets		(13.4)		(12.3)		(2.5)		(1.9)		-		-
Amortization of unrecognized net transition obligation		0.2		0.2		1.8		1.9		-		-
Amortization of prior service cost		1.3		1.0		-		-		-		-
Amortization of actuarial loss		3.1		4.6		1.7		2.5		0.2		0.1
Net periodic expense - before curtailments and termination benefits		14.8		15.9		5.9		7.5		0.3		0.2
Curtailments		-		(0.6)		-		0.1		-		-
Termination benefits		-		-		-		-		-		-
Total curtailments and termination benefits		-		(0.6)		-		0.1		-		-
Total - net periodic expense	$	14.8	$	15.3	$	5.9	$	7.6	$	0.3	$	0.2

Not included in the pension expense amounts above are intercompany allocations totaling $0.4 million and $1.4 million for the three and nine months ended September 30, 2007, respectively, and $0.4 million and $1.3 million for the three and nine months ended September 30, 2006, respectively. Intercompany allocations of postretirement benefits totaled $0.3 million and $1 million for both the three and nine months ended September 30, 2007 and 2006, respectively. Intercompany allocations of SERP benefits totaled $0.1 million and $0.3 million for both the three and nine months ended September 30, 2007 and 2006, respectively.

For PSNH, a portion of these pension amounts, including intercompany allocations, is capitalized related to current employees that are working on capital projects. Amounts capitalized were $1.1 million and $3.6 million for the three and nine months ended September 30, 2007, respectively, and $3.9 million and $7.3 million for the three and nine months ended September 30, 2006, respectively.


WMECO	For the Three Months Ended September 30,								For the Nine Months Ended September 30,
	Pension Benefits				Postretirement Benefits				Pension Benefits				Postretirement Benefits
	2007		2006		2007		2006		2007		2006		2007		2006
(Millions of Dollars)
Service cost	$	0.8	$	0.8	$	0.1	$	0.1	$	2.5	$	2.6	$	0.4	$	0.5
Interest cost		2.4		2.4		0.5		0.6		7.4		7.2		1.7		1.8
Expected return on plan assets		(4.9)		(4.4)		(0.4)		(0.4)		(15.1)		(13.4)		(1.3)		(1.1)
Amortization of unrecognized net transition obligation		-		-		0.2		0.4		-		-		0.8		1.0
Amortization of prior service cost		0.2		0.2		-		-		0.6		0.5		-		-
Amortization of actuarial loss		0.2		0.8		0.3		0.4		0.9		2.4		0.7		1.1
Net periodic (income)/expense - before curtailments and termination benefits		(1.3)		(0.2)		0.7		1.1		(3.7)		(0.7)		2.3		3.3
Curtailments		-		(0.2)		-		(0.1)		-		(0.2)		-		(0.3)
Termination benefits		-		(0.1)		-		-		-		(0.2)		-		-
Total curtailments and termination benefits		-		(0.3)		-		(0.1)		-		(0.4)		-		(0.3)
Total net periodic (income)/expense	$	(1.3)	$	(0.5)	$	0.7	$	1.0	$	(3.7)	$	(1.1)	$	2.3	$	3.0

A de minimis amount of SERP expense was recorded for WMECO for the three and nine months ended September 30, 2007 and 2006. Intercompany allocations of SERP benefits totaled $0.1 and $0.2 million for both the three and nine months ended September 30, 2007 and 2006, respectively.

Not included in the pension income amounts above are intercompany expense allocations totaling $0.4 million and $1.4 million for the three and nine months ended September 30, 2007, respectively, and $0.6 million and $1.6 million for the three and nine months ended September 30, 2006, respectively. Intercompany allocations of postretirement benefits totaled $0.3 million and $0.9 million for both the three and nine months ended September 30, 2007 and 2006, respectively.

For WMECO, a portion of these pension amounts, including intercompany allocations, is capitalized related to current employees that are working on capital projects. Amounts capitalized were $0.4 million and $1.2 million for the three and nine months ended September 30, 2007, respectively, and $0.2 million and $0.1 million for the three and nine months ended September 30, 2006. The capitalized amounts for 2007 and 2006 offset capital project costs, as pension income was recorded for those periods.

Curtailment and Termination Benefits: In December of 2005, a new program was approved allowing then current employees to elect to receive retirement benefits under a new 401(k) benefit rather than under the Pension Plan. The approval of the new plan resulted in the recording of an estimated pre-capitalization, pre-tax curtailment expense of $6.2 million in 2005, as a certain number of employees were expected to elect the new 401(k) benefit, resulting in a reduction in aggregate estimated future years of service under the Pension Plan. Because the predicted level of elections of the new benefit did not occur, NU recorded an adjustment to this curtailment in the third quarter of 2006. This adjustment resulted in a pre-capitalization, pre-tax reduction in the curtailment expense of $3.6 million for NU.

In addition, as a result of its corporate reorganization, NU recorded a combined pre-capitalization, pre-tax curtailment expense and related termination benefits for the Pension Plan totaling $5.5 million in 2005. Based on a revised estimate of expected head count reductions, NU recorded an adjustment to the curtailment and related termination benefits in the first nine months of 2006. This adjustment resulted in a combined pre-capitalization, pre-tax reduction in the curtailment expense ($0.6 million) and termination benefits ($0.7 million) totaling $1.3 million for NU. In addition, NU recorded an additional pre-capitalization, pre-tax reduction in termination benefit expense of $0.3 million in the third quarter of 2007.

Severance Benefits: As a result of its corporate reorganization, in 2005 NU recorded severance and termination benefits totaling $14.4 million relating to expected terminations of regulated company and NUSCO employees. These severance benefits were recorded in other operating expenses because these amounts were for benefits under an existing benefit arrangement. In 2006, NU updated its prior estimates of regulated company and NUSCO severance benefits and a total reduction in severance and related expenses of $2.4 million was recorded. This reduction was also included in other operating expenses on the accompanying condensed consolidated statements of income and was primarily due to a reduction in the expected number of terminated regulated company and NUSCO employees.

In the first nine months of 2006, NU recorded $4.1 million for severance and other employee benefits, as these benefits became probable and estimable as a result of the sale of the retail marketing business to Hess. Of this amount, $0.6 million was for enhanced minimum benefits and was included in restructuring charges, with the remaining $3.5 million included in other operating expenses on the accompanying condensed consolidated statements of income for the nine months ended September 30, 2006 because these amounts were for severance benefits under an existing benefit arrangement.

NU contributed $9.1 million in the third quarter of 2007 and $28.7 million for the nine months ended September 30, 2007 to fund its PBOP Plan. NU funded an additional $2.5 million to its PBOP Plan with funds received from the federal Medicare subsidy for a portion of its 2006 subsidy.

10.

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 segment operates. Cash flows for total investments in plant included in the segment information below are cash capital expenditures that do not include cost of removal, AFUDC, and the capitalized portion of pension expense or income. Segment information for all periods presented has been reclassified to conform to the current period presentation, except as indicated.

The regulated companies segment, including the electric distribution, generation and transmission segments, as well as the gas distribution segment (Yankee Gas), represents approximately 96 percent of NU's total revenues for both the three and nine months ended September 30, 2007. Similar amounts for 2006 were 95 percent and 85 percent, respectively. CL&P's, PSNH's and WMECO's complete condensed consolidated financial statements are included in this combined report on Form 10-Q. PSNH's distribution segment includes generation activities. Also included in this combined report on Form 10-Q is detailed information regarding CL&P's, PSNH's, and WMECO's transmission segments.

At September 30, 2007, the NU Enterprises business segment includes: 1) Select Energy (wholesale contracts), 2) NGS, 3) Boulos, 4) SECI-CT, 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 the Rocky River Realty Company and the Quinnehtuk Company (real estate subsidiaries), Mode 1 Communications, Inc. and 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.).

Effective on January 1, 2007, financial information for the remaining operations of HWP that were not exited as part of the sale of the competitive generation business was included as part of the Other reportable segment as these operations were no longer considered part of NU Enterprises subsequent to the sale. Accordingly, HWP’s remaining operations have been presented as part of the Other reportable segment for the three and nine months ended September 30, 2007.

As a result of the sale of NU Enterprises' retail marketing and competitive generation businesses, the financial information used by management was reduced to the remaining wholesale contracts, the operations of the remaining energy services businesses and NU Enterprises parent. As a result of exiting these businesses in 2006, the operations of NU Enterprises have been aggregated and presented as one reportable segment for the three and nine months ended September 30, 2007 and 2006.

Customer Concentrations: Select Energy provided basic generation service in the New Jersey market in 2007. In 2006, Select Energy also provided service in the Maryland market. Select Energy revenues related to these contracts represented $37.8 million and $96.1 million for the three months ended September 30, 2007 and 2006, respectively, and $145.9 million and $346.6 million for the nine months ended September 30, 2007 and 2006, respectively, of total NU Enterprises' billings. No other individual customer represented in excess of 10 percent of NU Enterprises' billings for the three and nine months ended September 30, 2007 and 2006. As these contracts expire, sales under a long-term contract with NYMPA may exceed 10 percent of NU Enterprises' billings in future periods.

Select Energy reported the settlement of all derivative contracts of the wholesale marketing business, including full requirements sales contracts and intercompany revenues, in fuel, purchased and net interchange power. This presentation is a result of applying mark-to-market accounting to those contracts due to the decision to exit the wholesale marketing business.

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

NU's segment information for the three and nine months ended September 30, 2007 and 2006 is as follows (some amounts between the financial statements and between segment schedules may not agree due to rounding):


	For the Three Months Ended September 30, 2007
	Regulated Companies
	Distribution (1)
(Millions of Dollars)	Electric		Gas		Transmission		NU Enterprises		Other		Eliminations		Total
Operating revenues	$	1,243.3	$	71.7	$	72.9	$	68.4	$	93.2	$	(98.4)	$	1,451.1
Depreciation and amortization		(116.6)		(6.8)		(9.6)		(0.1)		(2.0)		1.2		(133.9)
Other operating expenses		(1,043.4)		(64.3)		(29.0)		(66.1)		(87.6)		96.5		(1,193.9)
Operating income/(loss)		83.3		0.6		34.3		2.2		3.6		(0.7)		123.3
Interest expense, net of AFUDC		(43.2)		(5.1)		(8.9)		(1.8)		(8.3)		5.6		(61.7)
Interest income		1.0		-		0.4		0.6		7.1		(5.6)		3.5
Other income/(loss), net		2.9		-		3.8		(0.1)		27.2		(26.5)		7.3
Income tax (expense)/benefit		(11.1)		1.1		(9.2)		(0.2)		(0.9)		(0.5)		(20.8)
Preferred dividends		(1.0)		-		(0.4)		-		-		-		(1.4)
Income/(loss) from continuing operations		31.9		(3.4)		20.0		0.7		28.7		(27.7)		50.2
Income from discontinued operations		-		-		-		-		-		-		-
Net income/(loss)	$	31.9	$	(3.4)	$	20.0	$	0.7	$	28.7	$	(27.7)	$	50.2


	For the Nine Months Ended September 30, 2007
	Regulated Companies
	Distribution (1)
(Millions of Dollars)	Electric		Gas		Transmission		NU Enterprises		Other		Eliminations		Total
Operating revenues	$	3,784.7	$	351.5	$	214.7	$	221.6	$	287.1	$	(312.2)	$	4,547.4
Depreciation and amortization		(312.7)		(18.4)		(27.8)		(0.4)		(6.1)		3.0		(362.4)
Restructuring and impairment charges		-		-		-		(0.2)		-		-		(0.2)
Other operating expenses		(3,230.6)		(303.9)		(84.4)		(206.9)		(269.3)		306.4		(3,788.7)
Operating income/(loss)		241.4		29.2		102.5		14.1		11.7		(2.8)		396.1
Interest expense, net of AFUDC		(127.1)		(13.6)		(26.0)		(7.0)		(25.4)		18.6		(180.5)
Interest income		3.1		0.1		1.4		1.8		27.3		(18.4)		15.3
Other income/(loss), net		10.9		1.0		7.7		-		113.1		(111.4)		21.3
Income tax expense		(35.7)		(6.2)		(27.4)		(2.0)		(2.6)		(1.5)		(75.4)
Preferred dividends		(3.0)		-		(1.2)		-		-		-		(4.2)
Income/(loss) from continuing operations		89.6		10.5		57.0		6.9		124.1		(115.5)		172.6
Income from discontinued operations		-		-		-		1.2		-		-		1.2
Net income/(loss)	$	89.6	$	10.5	$	57.0	$	8.1	$	124.1	$	(115.5)	$	173.8
Total assets (2)	$	9,618.7	$	1,266.2	$	-	$	165.9	$	4.394.5	$	(4,106.3)	$	11,339.0
Cash flows for total investments in plant	$	259.5	$	43.3	$	436.5	$	6.8	$	4.1	$	-	$	750.2

(1)

Includes PSNH's generation activities.

(2)

Information for segmenting total assets between electric distribution and transmission is not available at September 30, 2007. For NU and subsidiaries, distribution and transmission assets are disclosed in the electric distribution column above.


	For the Three Months Ended September 30, 2006
	Regulated Companies
	Distribution (1)
(Millions of Dollars)	Electric		Gas		Transmission		NU Enterprises		Other		Eliminations		Total
Operating revenues	$	1,396.0	$	62.6	$	58.0	$	80.4	$	91.8	$	(96.0)	$	1,592.8
Depreciation and amortization		(87.1)		(5.7)		(7.6)		(0.2)		(4.8)		3.5		(101.9)
Restructuring and impairment charges		-		-		-		(1.3)		-		-		(1.3)
Other operating expenses		(1,241.8)		(61.7)		(24.1)		(93.7)		(84.1)		92.2		(1,413.2)
Operating income/(loss)		67.1		(4.8)		26.3		(14.8)		2.9		(0.3)		76.4
Interest expense, net of AFUDC		(38.7)		(4.2)		(6.5)		(5.3)		(9.7)		4.3		(60.1)
Interest income		1.7		-		0.1		0.4		5.6		(6.1)		1.7
Other income/(loss), net		6.5		0.4		2.0		-		18.0		(16.5)		10.4
Income tax benefit /(expense)		57.5		3.3		(3.4)		14.1		4.8		(0.6)		75.7
Preferred dividends		(1.1)		-		(0.3)		-		-		-		(1.4)
Income/(loss) from continuing operations		93.0		(5.3)		18.2		(5.6)		21.6		(19.2)		102.7
Income from discontinued operations		-		-		-		8.8		-		-		8.8
Net income/(loss)	$	93.0	$	(5.3)	$	18.2	$	3.2	$	21.6	$	(19.2)	$	111.5


	For the Nine Months Ended September 30, 2006
	Regulated Companies
	Distribution (1)
(Millions of Dollars)	Electric		Gas		Transmission		NU Enterprises		Other		Eliminations		Total
Operating revenues	$	4,081.2	$	335.1	$	155.2	$	854.0	$	263.5	$	(287.8)	$	5,401.2
Depreciation and amortization		(327.4)		(17.0)		(22.0)		(0.5)		(14.0)		10.5		(370.4)
Restructuring and impairment charges		-		-		-		(9.7)		-		-		(9.7)
Other operating expenses		(3,533.8)		(297.5)		(67.3)		(996.0)		(245.8)		276.6		(4,863.8)
Operating income/(loss)		220.0		20.6		65.9		(152.2)		3.7		(0.7)		157.3
Interest expense, net of AFUDC		(119.7)		(12.7)		(16.0)		(22.7)		(28.4)		19.1		(180.4)
Interest income		7.3		-		0.2		4.0		20.1		(21.8)		9.8
Other income/(loss), net		16.6		0.8		4.9		(0.1)		105.9		(99.4)		28.7
Income tax benefit/(expense)		23.1		(2.3)		(10.5)		70.0		6.5		(1.7)		85.1
Preferred dividends		(3.3)		-		(0.9)		-		-		-		(4.2)
Income/(loss) from continuing operations		144.0		6.4		43.6		(101.0)		107.8		(104.5)		96.3
Income from discontinued operations		-		-		-		27.3		-		-		27.3
Net income/(loss)	$	144.0	$	6.4	$	43.6	$	(73.7)	$	107.8	$	(104.5)	$	123.6
Cash flows for total investments in plant	$	217.9	$	62.3	$	285.2	$	17.2	$	17.7	$	-	$	600.3

(1)

Includes PSNH's generation activities.

The regulated companies information related to the distribution and transmission segments for CL&P, PSNH and WMECO for the three and nine months ended September 30, 2007 and 2006 is as follows:


	CL&P - For the Three Months Ended September 30, 2007
(Millions of Dollars)	Distribution		Transmission		Total
Operating revenues	$	862.5	$	55.9	$	918.4
Depreciation and amortization		(73.0)		(7.4)		(80.4)
Other operating expenses		(745.0)		(21.6)		(766.6)
Operating income		44.5		26.9		71.4
Interest expense, net of AFUDC		(28.0)		(7.6)		(35.6)
Interest income		0.8		0.3		1.1
Other income, net		2.6		3.9		6.5
Income tax expense		(2.2)		(6.2)		(8.4)
Preferred dividends		(1.0)		(0.4)		(1.4)
Net income	$	16.7	$	16.9	$	33.6


	CL&P - For the Nine Months Ended September 30, 2007
(Millions of Dollars)	Distribution		Transmission		Total
Operating revenues	$	2,668.0	$	164.5	$	2,832.5
Depreciation and amortization		(211.6)		(21.5)		(233.1)
Other operating expenses		(2,324.2)		(60.9)		(2,385.1)
Operating income		132.2		82.1		214.3
Interest expense, net of AFUDC		(82.0)		(21.6)		(103.6)
Interest income		2.2		1.2		3.4
Other income, net		9.7		7.3		17.0
Income tax expense		(14.8)		(20.5)		(35.3)
Preferred dividends		(3.0)		(1.2)		(4.2)
Net income	$	44.3	$	47.3	$	91.6
Cash flows for total investments in plant	$	166.5	$	383.6	$	550.1


	CL&P - For the Three Months Ended September 30, 2006
(Millions of Dollars)	Distribution		Transmission		Total
Operating revenues	$	1,040.5	$	42.8	$	1,083.3
Depreciation and amortization		(63.9)		(5.7)		(69.6)
Other operating expenses		(942.0)		(17.0)		(959.0)
Operating income		34.6		20.1		54.7
Interest expense, net of AFUDC		(24.0)		(5.2)		(29.2)
Interest income		1.2		0.1		1.3
Other income, net		5.2		2.0		7.2
Income tax benefit/(expense)		68.5		(1.5)		67.0
Preferred dividends		(1.1)		(0.3)		(1.4)
Net income	$	84.4	$	15.2	$	99.6


	CL&P - For the Nine Months Ended September 30, 2006
(Millions of Dollars)	Distribution		Transmission		Total
Operating revenues	$	2,918.1	$	109.7	$	3,027.8
Depreciation and amortization		(183.9)		(16.3)		(200.2)
Other operating expenses		(2,618.1)		(46.1)		(2,664.2)
Operating income		116.1		47.3		163.4
Interest expense, net of AFUDC		(74.9)		(12.2)		(87.1)
Interest income		5.6		0.2		5.8
Other income, net		13.3		4.5		17.8
Income tax benefit/(expense)		57.4		(4.9)		52.5
Preferred dividends		(3.3)		(0.9)		(4.2)
Net income	$	114.2	$	34.0	$	148.2
Cash flows for total investments in plant	$	129.6	$	258.8	$	388.4


	PSNH - For the Three Months Ended September 30, 2007
(Millions of Dollars)	Distribution (1)		Transmission		Total
Operating revenues	$	272.8	$	11.5	$	284.3
Depreciation and amortization		(32.6)		(1.5)		(34.1)
Other operating expenses		(212.6)		(4.9)		(217.5)
Operating income		27.6		5.1		32.7
Interest expense, net of AFUDC		(10.9)		(0.8)		(11.7)
Interest income		0.1		-		0.1
Other income, net		-		-		-
Income tax expense		(5.8)		(2.3)		(8.1)
Net income	$	11.0	$	2.0	$	13.0


	PSNH - For the Nine Months Ended September 30, 2007
(Millions of Dollars)	Distribution (1)		Transmission		Total
Operating revenues	$	778.2	$	33.5	$	811.7
Depreciation and amortization		(70.3)		(4.4)		(74.7)
Other operating expenses		(633.4)		(15.3)		(648.7)
Operating income		74.5		13.8		88.3
Interest expense, net of AFUDC		(31.9)		(2.9)		(34.8)
Interest income		0.4		0.1		0.5
Other income, net		0.7		0.4		1.1
Income tax expense		(12.0)		(4.9)		(16.9)
Net income	$	31.7	$	6.5	$	38.2
Cash flows for total investments in plant	$	71.9	$	41.2	$	113.1


	PSNH - For the Three Months Ended September 30, 2006
(Millions of Dollars)	Distribution (1)		Transmission		Total
Operating revenues	$	255.3	$	10.5	$	265.8
Depreciation and amortization		(18.2)		(1.3)		(19.5)
Other operating expenses		(213.5)		(4.7)		(218.2)
Operating income		23.6		4.5		28.1
Interest expense, net of AFUDC		(10.5)		(0.9)		(11.4)
Interest income		0.2		-		0.2
Other income, net		1.0		-		1.0
Income tax expense		(8.5)		(1.5)		(10.0)
Net income	$	5.8	$	2.1	$	7.9


	PSNH - For the Nine Months Ended September 30, 2006
(Millions of Dollars)	Distribution (1)		Transmission		Total
Operating revenues	$	844.6	$	31.1	$	875.7
Depreciation and amortization		(130.5)		(3.9)		(134.4)
Other operating expenses		(637.7)		(14.3)		(652.0)
Operating income		76.4		12.9		89.3
Interest expense, net of AFUDC		(31.9)		(2.5)		(34.4)
Interest income		0.8		-		0.8
Other income, net		2.8		0.4		3.2
Income tax expense		(26.9)		(4.1)		(31.0)
Net income	$	21.2	$	6.7	$	27.9
Cash flows for total investments in plant	$	65.0	$	16.9	$	81.9

(1)

Includes PSNH's generation activities.


	WMECO - For the Three Months Ended September 30, 2007
(Millions of Dollars)	Distribution		Transmission		Total
Operating revenues	$	108.1	$	5.4	$	113.5
Depreciation and amortization		(11.0)		(0.6)		(11.6)
Other operating expenses		(85.8)		(2.5)		(88.3)
Operating income		11.3		2.3		13.6
Interest expense, net of AFUDC		(4.3)		(0.5)		(4.8)
Interest income		0.2		-		0.2
Other income, net		-		-		-
Income tax expense		(3.0)		(0.7)		(3.7)
Net income	$	4.2	$	1.1	$	5.3


	WMECO - For the Nine Months Ended September 30, 2007
(Millions of Dollars)	Distribution		Transmission		Total
Operating revenues	$	338.7	$	16.7	$	355.4
Depreciation and amortization		(30.8)		(1.9)		(32.7)
Other operating expenses		(273.2)		(8.2)		(281.4)
Operating income		34.7		6.6		41.3
Interest expense, net of AFUDC		(13.2)		(1.5)		(14.7)
Interest income		0.5		0.1		0.6
Other income, net		0.6		0.1		0.7
Income tax expense		(9.0)		(2.1)		(11.1)
Net income	$	13.6	$	3.2	$	16.8
Cash flows for total investments in plant	$	21.1	$	11.7	$	32.8


	WMECO - For the Three Months Ended September 30, 2006
(Millions of Dollars)	Distribution		Transmission		Total
Operating revenues	$	100.3	$	4.7	$	105.0
Depreciation and amortization		(5.0)		(0.6)		(5.6)
Other operating expenses		(86.4)		(2.4)		(88.8)
Operating income		8.9		1.7		10.6
Interest expense, net of AFUDC		(4.2)		(0.4)		(4.6)
Interest income		0.3		-		0.3
Other income, net		0.3		-		0.3
Income tax expense		(2.5)		(0.4)		(2.9)
Net income	$	2.8	$	0.9	$	3.7


	WMECO - For the Nine Months Ended September 30, 2006
(Millions of Dollars)	Distribution		Transmission		Total
Operating revenues	$	318.7	$	14.3	$	333.0
Depreciation and amortization		(12.9)		(1.7)		(14.6)
Other operating expenses		(278.3)		(6.9)		(285.2)
Operating income		27.5		5.7		33.2
Interest expense, net of AFUDC		(12.8)		(1.3)		(14.1)
Interest income		0.6		-		0.6
Other income, net		0.7		-		0.7
Income tax expense		(7.4)		(1.5)		(8.9)
Net income	$	8.6	$	2.9	$	11.5
Cash flows for total investments in plant	$	23.2	$	9.1	$	32.3

11.

SUBSEQUENT EVENT (PSNH)

On an annual basis, PSNH files with the New Hampshire Public Utilities Commission (NHPUC) a stranded cost recovery charge/energy service (SCRC/ES) reconciliation filing for the preceding calendar year. The NHPUC reviews the filing, including a prudence review of the operations within PSNH's generation segment. On May 1, 2007, PSNH filed its 2006 SCRC/ES reconciliation with the NHPUC.

On November 5, 2007, PSNH, the New Hampshire Office of Consumer Advocate, and staff of the NHPUC entered into a settlement agreement resolving all outstanding issues in this proceeding with de minimis adjustments to PSNH's SCRC/ES reconciliation. The settlement agreement also favorably resolved the NHPUC staff's audit of PSNH's Northern Wood Power Project costs, with no disallowances. The settlement agreement was the subject of a NHPUC hearing on November 6, 2007, and a decision is expected by the end of 2007. If the settlement agreement is approved by the NHPUC, this matter will not have a material adverse impact on PSNH's net income, financial position or cash flows.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Trustees and Shareholders of Northeast Utilities:

We have reviewed the accompanying condensed consolidated balance sheet of Northeast Utilities and subsidiaries (the "Company") as of September 30, 2007, and the related condensed consolidated statements of income for the three-month and nine-month periods ended September 30, 2007 and 2006, and of cash flows for the nine-month periods ended September 30, 2007 and 2006. 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.

As discussed in Note 1.E., the Company adopted Financial Accounting Standards Board Interpretation No. 48, Accounting for Uncertainty in Income Taxes – an Interpretation of FASB Statement No. 109, as of January 1, 2007.

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, 2006, and the related consolidated statements of income, comprehensive income, shareholders' equity, and cash flows for the year then ended (not presented herein); and in our report dated February 26, 2007 (which report included an explanatory paragraph related to recording charges, gains and losses in connection with the Company's ongoing divestiture activities, realizing a reduction to income tax expense related to a ruling that certain income taxes could not be used to reduce customer's rates, and the adoption of Statement of Financial Accounting Standard No. 158, Employers' Accounting for Defined Benefit Pension and Other Postretirement Plans), we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying condensed consolidated balance sheet as of December 31, 2006 is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.


/s/	Deloitte & Touche LLP
	Deloitte & Touche LLP

Hartford, Connecticut

November 8, 2007

THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES


THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
	September 30,	December 31,
	2007	2006
	(Thousands of Dollars)
ASSETS

Current Assets:
Cash	$ 10,669	$ 3,310
Investments in securitizable assets	339,309	375,656
Receivables, less provision for uncollectible
accounts of $2,188 in 2007 and $1,679 in 2006	91,770	73,052
Accounts receivable from affiliated companies	738	1,965
Unbilled revenues	7,158	8,044
Materials and supplies	54,456	39,447
Derivative assets - current	47,085	45,031
Prepayments and other	30,575	15,945
	581,760	562,450

Property, Plant and Equipment:
Electric utility	4,661,852	4,557,231
Less: Accumulated depreciation	1,274,399	1,260,526
	3,387,453	3,296,705
Construction work in progress	745,541	337,665
	4,132,994	3,634,370

Deferred Debits and Other Assets:
Regulatory assets	1,279,243	1,477,375
Prepaid pension	303,854	243,139
Derivative assets - long-term	259,112	249,423
Other	143,343	154,537
	1,985,552	2,124,474










Total Assets	$ 6,700,306	$ 6,321,294



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


THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
	September 30,	December 31,
	2007	2006
	(Thousands of Dollars)
LIABILITIES AND CAPITALIZATION

Current Liabilities:
Notes payable to affiliated companies	$ 130,525	$ 258,925
Accounts payable	323,448	326,163
Accounts payable to affiliated companies	36,818	47,906
Accrued taxes	35,221	186,647
Accrued interest	39,285	29,587
Derivative liabilities - current	6,371	4,101
Other	79,168	80,543
	650,836	933,872

Rate Reduction Bonds	629,488	743,899

Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	667,604	719,470
Accumulated deferred investment tax credits	22,064	24,019
Deferred contractual obligations	163,280	185,195
Regulatory liabilities	627,544	582,841
Derivative liabilities - long-term	27,852	31,923
Accrued postretirement benefits	72,534	85,768
Other	170,107	127,638
	1,750,985	1,756,854
Capitalization:
Long-Term Debt	2,025,924	1,519,440

Preferred Stock - Non-Redeemable	116,200	116,200

Common Stockholder's Equity:
Common stock, $10 par value - authorized
24,500,000 shares; 6,035,205 shares outstanding
in 2007 and 2006	60,352	60,352
Capital surplus, paid in	938,198	672,693
Retained earnings	529,908	513,344
Accumulated other comprehensive (loss)/income	(1,585)	4,640
Common Stockholder's Equity	1,526,873	1,251,029
Total Capitalization	3,668,997	2,886,669

Commitments and Contingencies (Note 6)
.
Total Liabilities and Capitalization	$ 6,700,306	$ 6,321,294


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


THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
		Three Months Ended		Nine Months Ended
		September 30,		September 30,
		2007	2006	2007	2006
	(Thousands of Dollars)


Operating Revenues		$ 918,418	$ 1,083,299	$ 2,832,483	$ 3,027,779

Operating Expenses:
Operation -
Fuel, purchased and net interchange power		604,953	726,271	1,809,996	1,992,936
Other		87,946	158,601	365,184	472,979
Maintenance		29,391	31,246	80,281	74,803
Depreciation		38,354	37,802	114,818	110,235
Amortization of regulatory assets/(liabilities), net		6,156	(1,811)	15,493	(6,132)
Amortization of rate reduction bonds		35,904	33,614	102,833	96,137
Taxes other than income taxes		44,291	42,847	129,540	123,385
Total operating expenses		846,995	1,028,570	2,618,145	2,864,343
Operating Income		71,423	54,729	214,338	163,436

Interest Expense:
Interest on long-term debt		21,457	17,977	60,637	46,924
Interest on rate reduction bonds		9,230	11,459	29,097	36,025
Other interest		4,897	(254)	13,849	4,170
Interest expense, net		35,584	29,182	103,583	87,119
Other Income, Net		7,545	8,504	20,275	23,500
Income Before Income Tax Expense/(Benefit)		43,384	34,051	131,030	99,817
Income Tax Expense/(Benefit)		8,408	(66,982)	35,274	(52,518)
Net Income		$ 34,976	$ 101,033	$ 95,756	$ 152,335













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


THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
	Nine Months Ended
	September 30,
	2007	2006
	(Thousands of Dollars)
Operating Activities:
Net income	$ 95,756	$ 152,335
Adjustments to reconcile to net cash flows
provided by operating activities:
Bad debt expense	13,720	12,651
Depreciation	114,818	110,235
Deferred income taxes	(27,738)	10,391
Amortization of regulatory assets/(liabilities), net	15,493	(6,132)
Amortization of rate reduction bonds	102,833	96,137
Amortization/(deferral) of recoverable energy costs	3,096	(3,937)
Pension income, net of capitalized portion	(6,570)	(2,480)
Regulatory overrecoveries/(refunds)	66,976	(117,670)
Deferred contractual obligations	(21,915)	(48,657)
Other non-cash adjustments	(13,382)	(13,729)
Other sources of cash	-	14,171
Other uses of cash	(24,703)	(4,462)
Changes in current assets and liabilities:
Receivables and unbilled revenues, net	(13,984)	8,603
Materials and supplies	(15,009)	(5,842)
Investments in securitizable assets	18,138	(20,284)
Other current assets	(15,798)	(13,179)
Accounts payable	(34,858)	26,853
Taxes receivable and accrued taxes	(162,843)	(57,612)
Other current liabilities	7,755	11,464
Net cash flows provided by operating activities	101,785	148,856

Investing Activities:
Investments in plant	(550,128)	(388,365)
Proceeds from sales of investment securities	1,515	1,524
Purchases of investment securities	(1,565)	(1,566)
Rate reduction bond escrow	2,257	(52,020)
Other investing activities	2,164	(1,620)
Net cash flows used in investing activities	(545,757)	(442,047)

Financing Activities:
Issuance of long-term debt	500,000	250,000
Retirement of rate reduction bonds	(114,411)	(73,217)
Decrease in NU Money Pool borrowing	(128,400)	(15,700)
Capital contributions from Northeast Utilities Parent	265,000	60,000
Increase in short-term debt	-	130,000
Cash dividends on preferred stock	(4,169)	(4,169)
Cash dividends on common stock	(59,386)	(47,798)
Other financing activities	(7,303)	(1,492)
Net cash flows provided by financing activities	451,331	297,624
Net increase in cash	7,359	4,433
Cash - beginning of period	3,310	2,301
Cash - end of period	$ 10,669	$ 6,734

The accompanying notes are an integral part of these 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)
	September 30,	December 31,
	2007	2006
	(Thousands of Dollars)
ASSETS

Current Assets:
Cash	$ 3,308	$ 31
Special deposits	4,000	-
Receivables, less provision for uncollectible
accounts of $2,438 in 2007 and $2,626 in 2006	94,443	86,784
Accounts receivable from affiliated companies	82	590
Unbilled revenues	39,078	44,433
Notes receivable from affiliated companies	7,300	-
Taxes receivable	500	6,671
Fuel, materials and supplies	81,595	84,856
Derivative assets - current	574	-
Prepayments and other	6,794	12,652
	237,674	236,017

Property, Plant and Equipment:
Electric utility	1,960,131	1,893,124
Other	6,288	5,816
	1,966,419	1,898,940
Less: Accumulated depreciation	729,823	723,764
	1,236,596	1,175,176
Construction work in progress	92,745	67,202
	1,329,341	1,242,378

Deferred Debits and Other Assets:
Regulatory assets	448,768	524,536
Other	73,226	68,345
	521,994	592,881








Total Assets	$ 2,089,009	$ 2,071,276

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


PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
	September 30,	December 31,
	2007	2006
	(Thousands of Dollars)
LIABILITIES AND CAPITALIZATION

Current Liabilities:
Notes payable to affiliated companies	$ -	$ 36,500
Accounts payable	79,946	69,948
Accounts payable to affiliated companies	14,321	22,327
Accrued interest	12,728	8,641
Derivative liabilities - current	12,182	39,180
Other	17,290	2,362
	136,467	178,958

Rate Reduction Bonds	295,856	333,831

Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	182,099	200,136
Accumulated deferred investment tax credits	656	877
Deferred contractual obligations	30,699	35,623
Regulatory liabilities	110,586	115,731
Derivative liabilities - long-term	624	-
Accrued pension	152,810	150,634
Accrued postretirement benefits	30,646	36,521
Other	43,247	44,304
	551,367	583,826
Capitalization:
Long-Term Debt	576,991	507,099

Common Stockholder's Equity:
Common stock, $1 par value - authorized
100,000,000 shares; 301 shares outstanding
in 2007 and 2006	-	-
Capital surplus, paid in	275,107	231,171
Retained earnings	253,002	236,215
Accumulated other comprehensive income	219	176
Common Stockholder's Equity	528,328	467,562
Total Capitalization	1,105,319	974,661


Commitments and Contingencies (Note 6)

Total Liabilities and Capitalization	$ 2,089,009	$ 2,071,276


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


PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)


	Three Months Ended		Nine Months Ended
	September 30,		September 30,
	2007	2006	2007	2006
	(Thousands of Dollars)


Operating Revenues	$ 284,326	$ 265,779	$ 811,655	$ 875,733

Operating Expenses:
Operation -
Fuel, purchased and net interchange power	140,881	147,595	409,493	437,797
Other	49,584	43,050	152,123	131,892
Maintenance	16,621	17,807	56,733	53,544
Depreciation	13,702	12,593	40,345	37,096
Amortization of regulatory assets/(liabilities), net	7,027	(5,690)	(4,682)	60,530
Amortization of rate reduction bonds	13,374	12,622	38,977	36,788
Taxes other than income taxes	10,471	9,737	30,355	28,755
Total operating expenses	251,660	237,714	723,344	786,402
Operating Income	32,666	28,065	88,311	89,331

Interest Expense:
Interest on long-term debt	6,211	6,206	18,616	17,889
Interest on rate reduction bonds	4,441	5,083	13,752	15,912
Other interest	1,066	132	2,446	577
Interest expense, net	11,718	11,421	34,814	34,378
Other Income	205	1,243	1,598	4,007
Income Before Income Tax Expense	21,153	17,887	55,095	58,960
Income Tax Expense	8,137	9,997	16,867	31,034
Net Income	$ 13,016	$ 7,890	$ 38,228	$ 27,926












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


PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

	Nine Months Ended
	September 30,
	2007	2006
	(Thousands of Dollars)
Operating activities:
Net income	$ 38,228	$ 27,926
Adjustments to reconcile to net cash flows
provided by operating activities:
Bad debt expense	2,269	3,119
Depreciation	40,345	37,096
Deferred income taxes	(11,287)	(20,392)
Amortization of regulatory (liabilities)/assets, net	(4,682)	60,530
Amortization of rate reduction bonds	38,977	36,788
Pension expense, net of capitalized portion	11,294	8,114
Regulatory underrecoveries	(4,248)	(4,243)
Deferred contractual obligations	(4,924)	(10,219)
Other non-cash adjustments	(3,470)	(8,548)
Other sources of cash	-	434
Other uses of cash	(8,392)	(6,385)
Changes in current assets and liabilities:
Receivables and unbilled revenues, net	(4,065)	38,970
Accrued taxes/(taxes receivable)	10,336	(19,612)
Fuel, materials and supplies	3,261	(5,665)
Other current assets	2,634	8,390
Accounts payable	(4,988)	10,617
Other current liabilities	8,140	3,910
Net cash flows provided by operating activities	109,428	160,830

Investing Activities:
Investments in plant	(113,132)	(81,874)
Proceeds from sales of investment securities	2,596	2,613
Purchases of investment securities	(2,682)	(2,683)
Increase in NU Money Pool Lending	(7,300)	-
Other investing activities	(667)	(1,267)
Net cash flows used in investing activities	(121,185)	(83,211)

Financing Activities:
Issuance of long-term debt	70,000	-
Retirement of rate reduction bonds	(37,975)	(35,783)
Decrease in NU Money Pool borrowing	(36,500)	(8,400)
Capital contributions from Northeast Utilities Parent	43,763	5,500
Cash dividends on common stock	(23,040)	(35,494)
Other financing activities	(1,214)	(242)
Net cash flows provided by/(used in) financing activities	15,034	(74,419)
Net increase in cash	3,277	3,200
Cash - beginning of period	31	27
Cash - end of period	$ 3,308	$ 3,227


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

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WESTERN MASSACHUSETTS ELECTRIC COMPANY


WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY

CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)

	September 30, 2007	December 31, 2006
	(Thousands of Dollars)
ASSETS

Current Assets:
Cash	$ 1,564	$ 1,336
Receivables, less provision for uncollectible
accounts of $6,519 in 2007 and $5,073 in 2006	51,789	43,182
Accounts receivable from affiliated companies	5,336	5,628
Unbilled revenues	14,357	15,940
Taxes receivable	13,281	-
Materials and supplies	2,127	1,875
Marketable securities - current	27,210	28,054
Prepayments and other	1,931	1,080
	117,595	97,095

Property, Plant and Equipment:
Electric utility	726,931	703,723
Less: Accumulated depreciation	206,078	201,099
	520,853	502,624
Construction work in progress	28,438	23,470
	549,291	526,094

Deferred Debits and Other Assets:
Regulatory assets	203,761	252,346
Prepaid pension	83,784	69,933
Marketable securities - long-term	29,004	25,964
Other	14,696	17,261
	331,245	365,504







Total Assets	$ 998,131	$ 988,693



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


WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY

CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)

	September 30,		December 31,
	2007		2006
	(Thousands of Dollars)
LIABILITIES AND CAPITALIZATION

Current Liabilities:
Notes payable to affiliated companies		$ 35,600	$ 30,800
Accounts payable		23,277	28,008
Accounts payable to affiliated companies		6,098	4,184
Accrued taxes		610	27,615
Accrued interest		1,961	4,546
Other		10,010	9,273
		77,556	104,426

Rate Reduction Bonds		89,888	99,428

Deferred Credits and Other Liabilities:
Accumulated deferred income taxes		184,335	197,881
Accumulated deferred investment tax credits		2,091	2,319
Deferred contractual obligations		44,789	50,711
Regulatory liabilities		39,849	26,756
Accrued postretirement benefits		12,069	14,293
Other		12,842	12,136
		295,975	304,096
Capitalization:
Long-Term Debt		303,986	261,777

Common Stockholder's Equity:
Common stock, $25 par value - authorized
1,072,471 shares; 434,653 shares outstanding
in 2007 and 2006		10,866	10,866
Capital surplus, paid in		119,410	114,544
Retained earnings		100,363	92,663
Accumulated other comprehensive income		87	893
Common Stockholder's Equity		230,726	218,966
Total Capitalization		534,712	480,743

Commitments and Contingencies (Note 6)

Total Liabilities and Capitalization		$ 998,131	$ 988,693

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


WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY

CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
	Three Months Ended			Nine Months Ended
	September 30,			September 30,
	2007		2006	2007	2006
	(Thousands of Dollars)



Operating Revenues	$ 113,500	$ 104,959		$ 355,421	$ 333,035

Operating Expenses:
Operation -
Fuel, purchased and net interchange power	56,555	66,171		184,462	216,463
Other	23,863	15,250		73,327	47,955
Maintenance	4,927	4,400		14,244	11,753
Depreciation	5,341	4,315		15,827	12,842
Amortization of regulatory assets/(liabilities), net	3,202	(1,614)		7,417	(7,071)
Amortization of rate reduction bonds	3,124	2,924		9,506	8,911
Taxes other than income taxes	2,926	2,902		9,327	9,026
Total operating expenses	99,938	94,348		314,110	299,879
Operating Income	13,562	10,611		41,311	33,156

Interest Expense:
Interest on long-term debt	2,960	2,644		8,265	8,066
Interest on rate reduction bonds	1,440	1,654		4,451	5,123
Other interest	410	304		1,938	946
Interest expense, net	4,810	4,602		14,654	14,135
Other Income	312	564		1,248	1,322
Income Before Income Tax Expense	9,064	6,573		27,905	20,343
Income Tax Expense	3,724	2,901		11,058	8,865
Net Income	$ 5,340	$ 3,672		$ 16,847	$ 11,478








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


WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

	Nine Months Ended
	September 30,
	2007	2006
	(Thousands of Dollars)

Operating Activities:
Net income	$ 16,847	$ 11,478
Adjustments to reconcile to net cash flows
provided by operating activities:
Bad debt expense	5,258	4,309
Depreciation	15,827	12,842
Deferred income taxes	(12,671)	13,976
Amortization of regulatory assets/(liabilities), net	7,417	(7,071)
Amortization of rate reduction bonds	9,506	8,911
Pension income, net of capitalized portion	(2,342)	(882)
Regulatory overrecoveries/(underrecoveries)	32,229	(15,704)
Deferred contractual obligations	(5,922)	(13,378)
Other non-cash adjustments	(2,034)	56
Other sources of cash	556	2,559
Other uses of cash	(1,215)	-
Changes in current assets and liabilities:
Receivables and unbilled revenues, net	(11,637)	4,670
Materials and supplies	(252)	(183)
Other current assets	215	161
Accounts payable	(4,373)	(10,017)
Taxes receivable and accrued taxes	(38,106)	(5,452)
Other current liabilities	(3,781)	(2,865)
Net cash flows provided by operating activities	5,522	3,410

Investing Activities:
Investments in plant	(32,792)	(32,323)
Proceeds from sales of investment securities	152,518	76,428
Purchases of investment securities	(154,951)	(78,282)
Other investing activities	136	(69)
Net cash flows used in investing activities	(35,089)	(34,246)

Financing Activities:
Issuance of long-term debt	40,000	-
Retirement of rate reduction bonds	(9,540)	(8,947)
Increase in short-term debt	-	30,000
Increase/(decrease) in NU Money Pool borrowing	4,800	(11,300)
Capital contributions from Northeast Utilities Parent	4,800	28,000
Cash dividends on common stock	(9,584)	(5,959)
Other financing activities	(681)	(183)
Net cash flows provided by financing activities	29,795	31,611
Net increase in cash	228	775
Cash - beginning of period	1,336	1
Cash - end of period	$ 1,564	$ 776


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

NORTHEAST UTILITIES AND SUBSIDIARIES

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

This discussion should be read in conjunction with the condensed consolidated financial statements and footnotes in this Form 10-Q, the First and Second Quarter 2007 reports on Form 10-Q and the Northeast Utilities and subsidiaries combined 2006 Form 10-K as filed with the Securities and Exchange Commission (SEC) (NU 2006 Form 10-K). All per share amounts are reported on a fully diluted basis.

This discussion includes references to non-GAAP earnings, which in each instance refers to the exclusion of the impact of a non-recurring tax-related benefit. Management uses these non-GAAP references to more fully explain and compare the 2006 results to 2007 results without the impact of this tax-related benefit.

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:

Northeast Utilities (NU or the company) earned $50.2 million, or $0.32 per share, in the third quarter of 2007, compared with non-GAAP earnings of $37.5 million, or $0.23 per share, in the third quarter of 2006, which excludes a one-time $74 million reduction in tax expense in 2006 at CL&P's distribution segment pursuant to a private letter ruling (PLR) received from the Internal Revenue Service (IRS). Including this $74 million reduction in income tax expense, NU earned $111.5 million, or $0.72 per share, in the third quarter of 2006. The results in 2007 included regulated company net income of $48.5 million, or $0.31 per share, after payment of preferred dividends, NU Enterprises, Inc. (NU Enterprises) net income of $0.7 million, and parent and affiliates net income of $1 million, or $0.01 per share.

NU earned $173.8 million, or $1.12 per share, in the first nine months of 2007, compared with non-GAAP earnings of $49.6 million, or $0.32 per share, in the first nine months of 2006, which excludes the $74 million reduction in tax expense in 2006 at CL&P's distribution segment discussed above. Including this $74 million reduction in income tax expense, NU earned $123.6 million, or $0.80 per share, in the first nine months of 2006. The results in 2007 included regulated company net income of $157.1 million, or $1.02 per share, after payment of preferred dividends, NU Enterprises net income of $8.1 million, or $0.05 per share, and parent and affiliates net income of $8.6 million, or $0.05 per share.

Earnings at the distribution segments of The Connecticut Light and Power Company (CL&P), Public Service Company of New Hampshire (PSNH) (including generation), Western Massachusetts Electric Company (WMECO) and Yankee Gas Services Company (Yankee Gas) totaled $28.5 million in the third quarter of 2007 and $100.1 million in the first nine months of 2007, compared with non-GAAP earnings of $13.7 million in the third quarter of 2006 and $76.4 million in the first nine months of 2006, which excludes the $74 million reduction in tax expense at CL&P in 2006. Including this $74 million reduction in CL&P income tax expense, those segments earned $87.7 million in the third quarter of 2006 and $150.4 million in the first nine months of 2006.

The transmission segments of CL&P, PSNH and WMECO earned $20 million in the third quarter of 2007 and $57 million in the first nine months of 2007, compared with $18.2 million in the third quarter of 2006 and $43.6 million in the first nine months of 2006.

NU raised its 2007 earnings guidance to between $1.45 per share and $1.60 per share from between $1.30 per share and $1.55 per share and projects consolidated 2008 earnings of between $1.65 per share and $1.95 per share. The company's earnings guidance does not include the impact of marking-to-market Select Energy's remaining wholesale energy contracts.

NU projects approximately $6 billion of capital expenditures from 2008 through 2012, including approximately $1.3 billion in 2008. Based on that capital investment projection, NU expects its regulated rate base to grow from approximately $5.4 billion at the end of 2007 to approximately $9.4 billion at the end of 2012.

NU projects average compounded annual earnings per share growth rate of between 10 percent and 14 percent from 2008 through 2012 with 2007 earnings per share (EPS) as the base year, with significantly higher growth projected for 2008 than in the later years. This growth rate assumes that the company meets its capital investment and rate base projections and that it receives appropriate approvals and allowed returns and timely rate treatment for those investments.

Legislative, Regulatory and Other Items:

On July 30, 2007, CL&P filed an application with the Connecticut Department of Public Utility Control (DPUC) to raise distribution rates by approximately $189 million effective on January 1, 2008 and approximately $22 million effective in January of 2009. A draft decision is currently scheduled for December 13, 2007 and a final decision is currently scheduled for December 27, 2007.

Liquidity:

During 2007, NU's liquidity position benefited from the proceeds the company received from the sale of NU Enterprises' competitive generation business in November of 2006 and the issuance of $655 million of long-term debt in the first nine months of 2007, including $45 million in long-term borrowings under the regulated companies' revolving credit line. As expected, the company's level of consolidated cash on hand declined in the first nine months of 2007 from $481.9 million at December 31, 2006 to $207.7 million at September 30, 2007, primarily as a result of the payment of $398.5 million in federal and state income taxes primarily related to the sale of the competitive generation business.

NU's cash capital expenditures totaled $750.2 million in the first nine months of 2007, compared with $600.3 million in the first nine months of 2006. The increase was primarily the result of higher transmission capital expenditures, particularly at CL&P.

NU’s regulated companies issued long-term debt totaling $310 million in the third quarter of 2007, including $200 million of first-mortgage bonds at CL&P, $70 million of first mortgage bonds at PSNH, and $40 million of senior unsecured notes at WMECO. Proceeds were used primarily to repay short-term debt incurred in financing the companies’ capital expenditure programs.

Consolidated operating cash flows were $68.2 million in the first nine months of 2007, compared with $380.3 million in the first nine months of 2006. The reduced level of cash flows was primarily due to the $398.5 million of federal and state income tax payments made in the first quarter of 2007 primarily related to the sale of NU’s competitive generation business. Excluding the tax payments of $398.5 million and $55 million made in the first quarter of 2007 and 2006, respectively, NU's cash flows from operations in the first nine months of 2007 totaled $466.7 million, compared with $435.3 million in the first nine months of 2006. The improved 2007 cash flows excluding the tax payments were primarily due to an expected reduction in regulatory refunds, a reduction in payments made to the Connecticut Yankee Atomic Power Company (CYAPC), the Yankee Atomic Electric Company (YAEC) and the Maine Yankee Atomic Power Company (MYAPC) (collectively, the Yankee Companies) for decommissioning and closure costs, lower cash payments related to Select Energy's derivative contracts and changes in working capital items related to the divestiture of the NU Enterprises' businesses in 2006. NU projects consolidated operating cash flows of approximately $400 million in 2007, excluding the tax payments discussed above and approximately $550 million in 2008, rising to between approximately $800 million and approximately $850 million in 2012.

NU paid common dividends of $89.7 million in the first nine months of 2007, compared with $83.6 million in the first nine months of 2006.

Overview

Consolidated: NU earned $50.2 million, or $0.32 per share, in the third quarter of 2007, compared with non-GAAP earnings of $37.5 million, or $0.23 per share, in the third quarter of 2006, which excludes a one-time $74 million reduction in tax expense in 2006 at CL&P's distribution segment pursuant to a PLR received from the IRS. NU earned $173.8 million, or $1.12 per share, in the first nine months of 2007, compared with non-GAAP earnings of $49.6 million, or $0.32 per share, in the first nine months of 2006, which excludes the $74 million reduction in tax expense. Including the $74 million reduction in tax expense, NU earned $111.5 million, or $0.72 per share and $123.6 million, or $0.80 per share in the three and nine months ended September 30, 2006, respectively. A summary of NU's earnings/(losses) by segment, which may or may not reflect aggregations of specific subsidiaries, for the third quarter and first nine months of 2007 and 2006 is as follows:


	For the Three Months Ended September 30,								For the Nine Months Ended September 30,
	2007				2006				2007				2006
(Millions of Dollars, except per share amounts)	Amount		Per Share		Amount		Per Share		Amount		Per Share		Amount			Per Share
Regulated companies	$	48.5	$	0.31	$	105.9	$	0.69	$	157.1	$	1.02	$	194.0	$	1.26
NU Enterprises		0.7		-		3.2		0.02		8.1		0.05		(73.7)		(0.48)
Parent and affiliates		1.0		0.01		2.4		0.01		8.6		0.05		3.3		0.02
Net Income	$	50.2	$	0.32	$	111.5	$	0.72	$	173.8	$	1.12	$	123.6	$	0.80

The only common equity securities that are publicly traded are common shares of NU. The EPS of each segment does not represent a direct legal interest in the assets and liabilities allocated to any one segment but rather represents a direct interest in NU's assets and liabilities as a whole. EPS by segment is a non-GAAP measure that is calculated by dividing the net income or loss of each segment by the average fully diluted NU common shares outstanding for the period. Management uses this measure to provide segmented earnings guidance and believes that this measurement is useful to investors to evaluate the actual financial performance and contribution of NU's business segments. This non-GAAP measure should not be considered as an alternative to NU consolidated EPS determined in accordance with GAAP as an indicator of NU's operating performance.

Regulated Companies: NU's regulated companies, which are comprised of CL&P, PSNH, WMECO and Yankee Gas, segment their earnings between their electric transmission segments and their electric and gas distribution segments, with PSNH generation included with its distribution segment. A summary of regulated company earnings by segment for the third quarter and first nine months of 2007 and 2006 is as follows (millions of dollars):


	For the Three Months Ended September 30,				For the Nine Months Ended September 30,
		2007		2006		2007		2006
CL&P Transmission*	$	16.9	$	15.2	$	47.3	$	34.0
PSNH Transmission		2.0		2.1		6.5		6.7
WMECO Transmission		1.1		0.9		3.2		2.9
Total Transmission		20.0		18.2		57.0		43.6
CL&P Distribution*		16.7		84.4		44.3		114.2
PSNH Distribution and Generation		11.0		5.8		31.7		21.2
WMECO Distribution		4.2		2.8		13.6		8.6
Yankee Gas		(3.4)		(5.3)		10.5		6.4
Total Distribution and Generation		28.5		87.7		100.1		150.4
Net Income - Regulated Companies	$	48.5	$	105.9	$	157.1	$	194.0

*After preferred dividends in all periods.

The increases in third quarter and year-to-date 2007 transmission segment earnings reflect a higher level of investment in NU’s transmission infrastructure, partially offset by a $2 million after-tax charge related to a Federal Energy Regulatory Commission (FERC) order concerning allowed transmission returns during a 15-month period which ended on September 3, 2006 and the impact of an increased effective income tax rate.

CL&P’s 2006 third quarter and year-to-date distribution segment earnings benefited from a one-time $74 million reduction in income tax expense pursuant to a PLR received from the IRS which was related to the treatment of excess deferred income taxes and unamortized tax credits related to CL&P’s former generating plants. CL&P's distribution non-GAAP earnings were $10.4 million and $40.2 million for the three and nine months ended September 30, 2006, which excludes the PLR.

In the third quarter of 2007, CL&P’s distribution earnings were $16.7 million or $6.3 million higher than the non-GAAP third quarter of 2006 earnings, which excludes the PLR. The 2007 increase is primarily due to lower storm and heat-related operating costs and a $7 million annualized rate increase, partially offset by the expiration of a fixed procurement fee of approximately $1.8 million (after-tax) that CL&P was allowed to collect from customers who purchased transitional standard offer (TSO) service through 2006, and higher interest expense.

In the first nine months of 2007, CL&P’s distribution earnings were $44.3 million or $4.1 million higher than the non-GAAP earnings in the first nine months of 2006, which excludes the PLR. The 2007 increase is primarily due to a 0.9 percent increase in retail sales, a $7 million annualized distribution rate increase that took effect on January 1, 2007, and the absence of a competitive transition assessment (CTA)-related rate base credit that was attributable to deferred tax liabilities on CL&P's former generating plants, offset by higher interest expense, and the absence of the fixed procurement fee of approximately $5.1 million (after-tax). For the 12 months ended September 30, 2007, CL&P's distribution Regulatory ROE was approximately 9 percent, or an increase of 1.2 percent from the distribution Regulatory ROE of 7.8 percent for the 12 months ended June 30, 2007. The increase in the distribution Regulatory ROE

was primarily due to lower storm expenses and a lower effective tax rate in the third quarter of 2007, but this increase in the distribution Regulatory ROE is expected to reverse in the fourth quarter of 2007. Management continues to estimate CL&P's Regulatory ROE will be between 7 percent and 7.5 percent for the 12 months ending December 31, 2007, which is below its allowed 9.85 percent Regulatory ROE.

PSNH's third quarter 2007 distribution and generation segment earnings were $5.2 million higher than the same period of 2006 due to a $37.7 million annualized energy delivery rate increase that became effective on July 1, 2007, and a lower effective tax rate partially offset by higher operating and interest expenses.

PSNH's distribution and generation earnings for the nine months ended September 30, 2007 were $10.5 million higher than the same period of 2006 due to a one percent increase in retail sales, the $37.7 million delivery rate increase noted above, a $24.5 million annualized interim rate increase that took effect on July 1, 2006, the implementation of a retail transmission cost tracking mechanism, and the recovery of approximately $4.5 million of retail transmission costs that were expensed in 2006, partially offset by increased operating expenses. For the 12 months ended September 30, 2007, PSNH's distribution and generation Regulatory ROE was 9.4 percent. Management expects that PSNH will be able to earn between a 9 percent and 10 percent Regulatory ROE in 2007 and 2008 as a result of the increased revenues generated by the rate settlement that took effect on July 1, 2007.

WMECO's third quarter and year-to-date 2007 distribution segment earnings were higher than the same periods of 2006 by $1.4 million and $5 million, respectively, due to the impact of a distribution rate settlement that took effect on January 1, 2007, which included an annualized distribution rate increase of $1 million and several cost tracking mechanisms. For the 12 months ended September 30, 2007, WMECO's distribution Regulatory ROE was 9.9 percent. Management expects that WMECO will be able to earn between a 9 percent and 10 percent Regulatory ROE during 2007 and 2008.

Yankee Gas' third quarter 2007 results improved compared to the same period of 2006 due to a $22.1 million net annualized increase in distribution rates that took effect on July 1, 2007, partially offset by lower firm natural gas sales. For the first nine months of 2007, Yankee Gas earned $10.5 million, compared with $6.4 million in the same period of 2006. The improvement in year-to-date 2007 results was due to an 8.2 percent increase in firm natural gas sales and the distribution rate increase noted above, partially offset by higher operating and interest expenses. Yankee Gas' Regulatory ROE was 6.6 percent for the 12 months ended September 30, 2007. As a result of its rate case settlement agreement, management expects Yankee Gas' Regulatory ROE to improve over the balance of 2007 and that it will be able to earn between 9 percent and 10 percent in 2008.

For the distribution segment of the regulated companies, a summary of changes in CL&P, PSNH and WMECO electric kilowatt-hour (KWH) sales and Yankee Gas firm natural gas sales for the third quarter and first nine months of 2007 as compared to 2006 on an actual and weather normalized basis is as follows:


		For the Three Months Ended September 30, 2007 Compared to September 30, 2006
	Electric									Firm Natural Gas
	CL&P			PSNH		WMECO		Total		Yankee Gas
	Percentage (Decrease)/ Increase		Weather Normalized Percentage (Decrease)/ Increase	Percentage Increase/ (Decrease)	Weather Normalized Percentage Increase/ (Decrease)	Percentage (Decrease)/ Increase	Weather Normalized Percentage (Decrease)/ Increase	Percentage (Decrease)/ Increase	Weather Normalized Percentage (Decrease)/ Increase	Percentage Decrease	Weather Normalized Percentage Increase/ (Decrease)
Residential	(2.6)%		(2.4)%	0.3 %	0.4 %	(2.2)%	(1.6)%	(2.0)%	(1.7)%	(0.7)%	1.5 %
Commercial	1.0 %		1.1 %	0.7 %	0.7 %	(0.9)%	(0.8)%	0.8 %	0.8 %	(8.7)%	(7.2)%
Industrial	0.1 %		- %	(3.2)%	(3.2)%	1.0 %	1.0 %	(0.7)%	(0.8)%	(2.8)%	(2.6)%
Other	(3.6)%		(3.6)%	5.3%	5.3 %	(1.0)%	(1.0)%	(4.7)%	(2.9)%	- %	- %
Total	(0.7)%		(0.6)%	(0.2)%	(0.1)%	(1.0)%	(0.7)%	(0.6)%	(0.5)%	(4.0)%	(3.0)%


		For the Nine Months Ended September 30, 2007 Compared to September 30, 2006
	Electric									Firm Natural Gas
	CL&P			PSNH		WMECO		Total		Yankee Gas
	Percentage Increase/ (Decrease)		Weather Normalized Percentage Increase/ (Decrease)	Percentage Increase/ (Decrease)	Weather Normalized Percentage Increase/ (Decrease)	Percentage Increase/ (Decrease)	Weather Normalized Percentage Increase/ (Decrease)	Percentage Increase/ (Decrease)	Weather Normalized Percentage Increase/ (Decrease)	Percentage Increase/ (Decrease)	Weather Normalized Percentage Increase/ (Decrease)
Residential	1.5 %		0.1 %	2.3 %	1.7 %	1.1 %	- %	1.6 %	0.4 %	15.8 %	8.1 %
Commercial	1.3 %		1.0 %	1.6 %	1.6 %	0.9 %	0.7 %	1.4 %	1.2 %	9.6 %	3.1 %
Industrial	(2.5)%		(2.7)%	(2.9)%	(2.7)%	(2.3)%	(2.3)%	(2.6)%	(2.6)%	(0.2)%	(1.8)%
Other	7.8 %		7.8 %	7.1 %	7.1 %	0.1 %	0.1 %	7.1 %	7.2 %	- %	- %
Total	0.9 %		0.2 %	1.0 %	0.8 %	0.3 %	(0.2)%	0.9 %	0.3 %	8.2 %	3.1 %

A summary of NU's electric sales in gigawatt hours (GWH) and firm natural gas sales in million cubic feet (MMCF) for the third quarter and first nine months of 2007 and 2006 is as follows:


	For the Three Months Ended September 30, 2007 and 2006
	Electric			Firm Natural Gas
	2007	2006	Percentage (Decrease)/ Increase	2007	2006	Percentage (Decrease)/ Increase
Residential	3,967	4,046	(2.0)%	947	954	(0.7)%
Commercial	4,043	4,012	0.8 %	1,182	1,294	(8.7)%
Industrial	1,469	1,479	(0.7)%	2,461	2,533	(2.8)%
Other	81	85	(4.7)%	-	-	- %
Total	9,560	9,622	(0.6)%	4,590	4,781	(4.0)%


	For the Nine Months Ended September 30, 2007 and 2006
	Electric			Firm Natural Gas
	2007	2006	Percentage Increase/ (Decrease)	2007	2006	Percentage Increase/ (Decrease)
Residential	11,339	11,156	1.6 %	9,462	8,168	15.8 %
Commercial	11,440	11,284	1.4 %	9,086	8,292	9.6 %
Industrial	4,235	4,349	(2.6)%	8,960	8,974	(0.2)%
Other	257	240	7.1 %	-	-	- %
Total	27,271	27,029	0.9 %	27,508	25,434	8.2 %

NU's electric sales per customer, as well as distribution segment earnings, adjusted for weather impacts, were negatively affected by commodity driven retail rate increases which took effect beginning in early 2006. The longer term trend in customer usage in NU's service territory has reflected a generally increasing use per customer as the penetration of air conditioning and other electronic devices has increased. During 2007, as generation costs have stabilized, there are signs that use per customer may be recovering reflecting a potential slowdown in customer initiated price response. NU cannot determine at this time if these trends will continue or what effect they will have on distribution segment earnings.

NU Enterprises: NU Enterprises continues to wind down its remaining wholesale contracts and energy services activities.

NU's condensed consolidated statements of income for all periods presented classify the operations for the following as discontinued operations:

A portion of the former Woods Electrical Co., Inc. (Woods Electrical), which was sold in April of 2006,

Select Energy Services, Inc. (SESI), which was sold in May of 2006,

Northeast Generation Company (NGC), which was sold in November of 2006 (including certain components of Northeast Generation Services Company (NGS)), and

Holyoke Water Power Company's (HWP) Mt. Tom generating plant, which was sold in November of 2006.

NU Enterprises earned $0.7 million in the third quarter of 2007 and $8.1 million in the first nine months of 2007, compared with earnings of $3.2 million in the third quarter of 2006 and losses of $73.7 million in the first nine months of 2006. These amounts include mark-to-market impacts related to Select Energy’s wholesale contracts of a negative impact of $1.5 million and a negative $2.8 million for the three and nine months ended September 30, 2007, respectively, and a positive impact of $2.9 million and a negative impact of $8.9 million for the three and nine months ended September 30, 2006, respectively. NU Enterprises earnings in the first nine months of 2007 were primarily due to higher than expected margins and the favorable resolution of certain contingencies from the SESI sale related to a contract to complete a cogeneration facility, partially offset by the $2.8 million negative mark-to-market on the remaining wholesale contracts.

The losses in the nine months of 2006 were primarily due to the retail marketing business, which was sold on June 1, 2006. The retail marketing business lost $71.3 million in the first nine months of 2006. These results reflect the operating margins of the retail marketing business being more than offset by its ongoing expenses and an approximately $33 million after-tax charge (approximately $53 million pre-tax) to record the retail marketing business at fair value less cost to sell.

Parent and Affiliates: Parent company and affiliates earned $1 million in the third quarter of 2007 and $8.6 million in the first nine months of 2007, compared with earnings of $2.4 million in the third quarter of 2006 and $3.3 million in the first nine months of 2006. The decline in third quarter 2007 earnings from 2006 was primarily attributable to a higher effective tax rate.

The improvement in the results for the first nine months of 2007 compared with 2006 is due to higher interest income earned on cash balances that NU affiliates borrowed from NU parent through the NU Money Pool (Pool) or that NU parent invested in outside money market funds. Earnings on the Pool investments are eliminated in consolidation along with the corresponding interest expense for the Pool borrowers. The company expects that NU parent earnings will continue to decline as NU parent's cash was used to pay taxes in

March of 2007 related to the sale of the competitive generation business and will continue to be used to make equity investments in the regulated companies to support capital expenditures.

Future Outlook

Regulated Companies: NU projects 2007 earnings of between $0.85 per share and $0.95 per share in its distribution and generation segment and between $0.50 per share and $0.55 per share at the transmission segment of the regulated companies. NU projects 2008 earnings of between $1.10 per share and $1.25 per share for the distribution and generation segment and between $0.70 per share and $0.80 per share for the transmission segment.

Earnings in the distribution segment may be impacted by the outcome of the current CL&P distribution rate case for which a draft decision is currently scheduled for December 13, 2007, and for which a final decision is currently scheduled for December 27, 2007, as well as by sales and operating cost levels.

Parent and Affiliates: NU projects 2007 earnings of approximately $0.05 per share for NU parent and affiliates. NU projects a loss of between $0.10 per share and $0.15 per share in 2008 for NU parent and affiliates. The lower projected results for 2008 reflect the assumption that NU parent's interest income will no longer be higher than its costs in 2008 as it fully invests its cash in the regulated companies. NU parent interest expense is expected to increase due to the anticipated issuance of new long-term debt in 2008.

NU Enterprises: NU projects 2007 earnings of approximately $0.05 per share for NU Enterprises in 2007 and approximately breakeven results in 2008. This earnings guidance does not include the impact of marking-to-market Select Energy's remaining wholesale contracts. In the first nine months of 2007, marking those obligations to market resulted in a $2.8 million after-tax charge. For additional information regarding sensitivity analyses of Select Energy's remaining wholesale contracts, see Item 3, "Quantitative and Qualitative Disclosures About Market Risk," included in this report on Form 10-Q.

Long-Term Growth Rate: NU projects that it can achieve average compounded annual EPS growth of between 10 percent and 14 percent for the period from 2008 through 2012 with 2007 EPS as the base year, with significantly higher growth projected in 2008 than in the later years. This growth rate assumes that the company meets its capital investment and rate base projections and that it receives appropriate regulatory approvals and allowed returns and timely rate treatment for those investments. The company currently expects transmission segment earnings to be approximately 50 percent of total earnings by 2012.

Liquidity

Consolidated: During 2007, NU's liquidity position benefited from the proceeds from the sale of NU Enterprises' competitive generation assets in November of 2006 and the issuance of $655 million of long-term debt by the regulated companies in 2007, including $45 million in long-term borrowings under the regulated companies' revolving credit line. At September 30, 2007, NU parent had $35 million of letters of credit (LOC) and no borrowings under its $500 million revolving credit line. CL&P had no sales of accounts receivable under its $100 million accounts receivable sales facility. The company had $207.7 million of cash and cash equivalents on hand at September 30, 2007.

The company's level of consolidated cash on hand declined in the first nine months of 2007 from $481.9 million at December 31, 2006 to $207.7 million at September 30, 2007, primarily as a result of the payment of $398.5 million in federal and state income taxes in the first quarter of 2007. Of that amount, $177.2 million was paid by CL&P, $47.9 million was paid by WMECO, $7.1 million was paid by PSNH and $166.3 million was paid by other NU companies. CL&P and WMECO accrued the majority of these tax obligations in 2000 upon the sale of the generation assets to NGC, but due to the intercompany nature of the sales, the federal and state income tax payments were deferred at that time. It was not until NU sold NGC to an unaffiliated third party in November of 2006 that CL&P and WMECO were required to pay these tax obligations.

Primarily as a result of those tax payments, NU had consolidated operating cash flows in the first nine months of 2007 of $68.2 million, compared with $380.3 million in the same period of 2006. Excluding the tax payments of $398.5 million and $55 million made in the first quarter of 2007 and 2006, respectively, NU's cash flows from operations in the first nine months of 2007 totaled $466.7 million, compared with $435.3 million in the first nine months of 2006. The improved 2007 cash flows excluding the tax payments were due to an expected reduction in regulatory refunds related to CTA amounts refunded to CL&P ratepayers during the first nine months of 2006 as compared to the first nine months of 2007. In addition to lower regulatory refunds paid, the regulated companies made lower payments to the Yankee Companies for decommissioning and closure costs in the first nine months of 2007 as compared to 2006, primarily as a result of the extension of the collection period for CYAPC's decommissioning and closure costs.

Also impacting cash flows from operations were lower cash payments related to Select Energy's derivative contracts and changes in working capital items related to the divestiture of the NU Enterprises' businesses in 2006. NU projects consolidated operating cash flows of approximately $400 million in 2007, excluding the tax payments discussed above and approximately $550 million in 2008 rising to between approximately $800 million and approximately $850 million in 2012.

Three of the regulated companies issued long-term debt in the third quarter of 2007 totaling $310 million. On August 17, 2007, WMECO closed on the sale of $40 million of 30-year senior unsecured notes due in 2037 with a coupon rate of 6.7 percent. On September 17, 2007, CL&P closed on the sale of $100 million of first mortgage bonds due in 2017 with a coupon rate of 5.75 percent and $100 million of first mortgage bonds due in 2037 with a coupon rate of 6.375 percent. On September 24, 2007, PSNH closed on the sale of $70 million of first mortgage bonds due in 2017 with a coupon rate of 6.15 percent. Previously, CL&P sold $300 million of bonds in March of 2007. No additional long-term debt issuances are anticipated by NU or its subsidiaries over the remainder of 2007. Including the $300 million in bonds issued by CL&P in the first quarter of 2007, NU issued a total of $610 million of notes and bonds in 2007 at a discount of $2.7 million and paid $5.9 million in associated debt issuance costs in the first nine months of 2007. NU’s 2008 cash flow projections contemplates refinancing of $150 million of debt due on June 1, 2008 which is included in long-term debt - current portion on the accompanying condensed consolidated balance sheet at September 30, 2007.

NU's senior unsecured debt is rated Baa2, BBB-, and BBB with a stable outlook by Moody's Investors Service (Moody's), Standard & Poor's (S&P) and Fitch Ratings (Fitch), respectively. Fitch reaffirmed its ratings and stable outlook on NU, CL&P, PSNH and WMECO on May 10, 2007. On September 6, 2007, as part of a comprehensive reassessment of utility secured debt ratings, S&P raised PSNH’s secured debt ratings by one notch to BBB+.

If NU's senior unsecured debt ratings were to be reduced to a sub-investment grade level by either Moody's or S&P, Select Energy could, under its present contracts, be required to provide approximately $72.4 million of collateral or LOCs to various unaffiliated counterparties and approximately $21.2 million to several independent system operators and unaffiliated local distribution companies (LDCs) at September 30, 2007. If such a downgrade were to occur, NU would currently be able to provide that collateral.

The company expects to issue approximately $0.5 billion of equity during the 2008 through 2012 period with approximately half of that amount expected to be issued later in 2009 and the remainder expected to be issued later in that period.

NU paid common dividends of $89.7 million in the first nine months of 2007, compared with $83.6 million in the first nine months of 2006. The increase reflects a 7.1 percent increase in NU's common dividend that took effect in the third quarter of 2006 and another 6.7 percent increase that took effect in the third quarter of 2007.

Management expects to continue its current policy of dividend increases, subject to the approval of the NU Board of Trustees and the company's future earnings and cash requirements. In general, the regulated companies pay approximately 60 percent of their cash earnings to NU in the form of common dividends. In the first nine months of 2007, CL&P, PSNH, WMECO, and Yankee Gas paid $59.4 million, $23 million, $9.6 million, and $12.7 million, respectively, in common dividends to NU. In the first nine months of 2007, NU parent contributed $265 million of equity to CL&P, $43.8 million to PSNH, $4.8 million to WMECO and $52.7 million to Yankee Gas. At September 30, 2007, NU parent had $350.6 million invested in the Pool and will continue to infuse equity into the regulated companies as their capital needs and structure dictate. At September 30, 2007, the Pool had a balance of $178.6 million invested externally.

NU's ability to pay dividends may be affected by certain state statutes, the leverage restrictions in its revolving credit agreement and the ability of its subsidiaries to pay dividends to it. The Federal Power Act limits the payment of dividends by CL&P, PSNH and WMECO to their respective retained earnings balances, and PSNH is required to reserve an additional amount under certain FERC hydroelectric license conditions. In addition, certain state statutes may impose additional limitations on the regulated companies. CL&P, PSNH, WMECO and Yankee Gas also have a leverage restriction under their revolving credit agreement.

Cash capital expenditures included on the accompanying condensed consolidated statements of cash flows and described in the liquidity section of this management's discussion and analysis do not include cost of removal, the allowance for funds used during construction (AFUDC) related to equity funds and the capitalized portion of pension expense or income. NU's cash capital expenditures totaled $750.2 million in the first nine months of 2007, compared with $600.3 million in the first nine months of 2006. NU’s cash capital expenditures in the first nine months of 2007 included $550.1 million by CL&P, $113.1 million by PSNH, $32.8 million by WMECO, $43.3 million by Yankee Gas, and $10.9 million by other NU subsidiaries. The increase in NU's regulated companies’ cash capital expenditures was primarily the result of higher transmission capital expenditures, particularly at CL&P.

Regulated Companies: The regulated companies maintain a $400 million credit line that expires on November 6, 2010. There were $45 million of long-term borrowings by Yankee Gas outstanding under that facility at September 30, 2007.

In addition to its revolving credit facility, CL&P has an arrangement with a financial institution under which CL&P can sell up to $100 million of accounts receivable and unbilled revenues. There were no amounts outstanding under that facility at September 30, 2007. For more information regarding CL&P's sale of receivables, see Note 1F, "Summary of Significant Accounting Policies - Sale of Customer Receivables," to the condensed consolidated financial statements.

NU Enterprises: Most of the working capital and LOCs required by NU Enterprises are currently used to support the few remaining wholesale contracts. As Select Energy's remaining wholesale contracts expire or are exited, its liquidity requirements will continue to decline.

Business Development and Capital Expenditures

Consolidated: NU's consolidated capital expenditures, including cost of removal, AFUDC, and the capitalized portion of pension expense or income, totaled $842.1 million in the first nine months of 2007, compared with $664.6 million in the first nine months of 2006. These amounts include $8.2 million and $28.5 million for the first nine months of 2007 and 2006, respectively, that related to corporate service companies and other affiliates that support the regulated companies.

Regulated Companies:

NU projects a total of approximately $1.3 billion of regulated company capital expenditures in 2007 and approximately $6 billion from 2008 through 2012. A summary of these estimated capital expenditures for the regulated companies transmission and the distribution and generation segments by company for 2007 and 2008 through 2012, including corporate service companies’ capital expenditures on behalf of the regulated companies, is as follows (millions of dollars):


	Year
	2007		2008		2009		2010		2011		2012		2008-2012 Totals
CL&P:
Transmission	$	658	$	538	$	311	$	155	$	420	$	530	$	1,954
Distribution		279		334		291		289		298		298		1,510
PSNH:
Transmission		77		108		58		55		108		72		401
Distribution and generation		125		167		144		153		172		252		888
WMECO:
Transmission		19		50		137		222		135		104		648
Distribution		34		35		40		34		34		34		177
Yankee Gas distribution		65		57		61		60		62		68		308
Totals - transmission		754		696		506		432		663		706		3,003
Totals - distribution and generation		503		593		536		536		566		652		2,883
Corporate service companies		19		22		27		19		18		14		100
Totals	$	1,276	$	1,311	$	1,069	$	987	$	1,247	$	1,372	$	5,986

The significant increase in capital spending at PSNH in 2011 and 2012 reflects the installation of a wet scrubber at PSNH’s coal-fired 440-megawatt (MW) Merrimack Station to reduce mercury and sulfur emissions. As a result of 2006 state legislation, PSNH must complete installation of that scrubber by July 1, 2013. PSNH expects that the full cost of that installation will be recoverable through PSNH’s energy rate.

Actual levels of capital expenditures could vary from the estimated amounts for the companies and periods above.

Based on the estimated capital expenditures above, projected transmission and distribution and generation rate base at December 31^st of each year are as follows (millions of dollars):


	Year
	2007		2008		2009		2010		2011		2012
CL&P:
Transmission	$	1,221	$	1,722	$	2,203	$	2,239	$	2,553	$	2,864
Distribution		1,918		2,128		2,305		2,459		2,594		2,711
PSNH:
Transmission		168		296		307		368		372		459
Distribution and generation		925		1,085		1,176		1,248		1,322		1,404
WMECO:
Transmission		80		114		242		438		564		621
Distribution and generation		372		394		424		449		475		504
Yankee Gas distribution		666		714		733		754		779		812
Totals - transmission		1,469		2,132		2,752		3,045		3,489		3,944
Totals - distribution and generation		3,881		4,321		4,638		4,910		5,170		5,431
Totals	$	5,350	$	6,453	$	7,390	$	7,955	$	8,659	$	9,375

The estimated capital expenditures and projected rate base amounts reflected above do not include expenditures on new regulated generating facilities, any material investment in Automated Meter Infrastructure (AMI), or any significant transmission expenditures to better interconnect new renewable generation in Northern New England or Canada with southern New England.

Several factors may impact the regulated companies rate base amounts above, including the level and timing of capital expenditures and plant placed in service, regulatory approval of rate increases and other factors.

Transmission Segment: Transmission rate base totaled approximately $1.2 billion at September 30, 2007, compared with approximately $1.1 billion at December 31, 2006. Transmission rate base is expected to total approximately $1.5 billion at the end of 2007. For 2007, CL&P, PSNH and WMECO are currently projecting transmission segment capital expenditures of $658 million, $77 million, and $19 million, respectively, totaling $754 million. A summary of transmission segment capital expenditures by company in the first nine months of 2007 and 2006 is as follows (millions of dollars):


		For the Nine Months Ended September 30,
		2007		2006
CL&P	$	429.9	$	291.5
PSNH		47.0		16.7
WMECO		12.3		9.0
Other		0.8		0.5
Totals	$	490.0	$	317.7

The increase in transmission segment capital expenditures in the first nine months of 2007 as compared with 2006 primarily relates to CL&P, which is undertaking a significant enhancement of its transmission system in southwest Connecticut. CL&P has three major projects under construction in southwest Connecticut, including:

A 69-mile, 345 kilovolt (KV)/115 KV transmission project from Middletown to Norwalk, Connecticut. CL&P's portion of this project is estimated to cost approximately $1.05 billion. Although the project scheduled completion date is by the end of 2009, construction of the project is currently ahead of schedule, and CL&P continues to review the remaining work to determine whether it can be completed at an earlier date. At September 30, 2007, CL&P's portion of this project was approximately 48 percent complete and by early November of 2007, was estimated to be approximately 52 percent complete. CL&P has capitalized $465.2 million associated with this project.

A two-cable, nine-mile, 115 KV underground transmission project between Norwalk and Stamford, Connecticut (Glenbrook Cables), construction of which began in October of 2006. This project is required to support the growing electric demand in the area and is currently estimated to cost approximately $223 million. This project is on schedule to be completed by the end of 2008. At September 30, 2007, this project was approximately 49 percent complete and by early November of 2007, was estimated to be approximately 54 percent complete. CL&P has capitalized $95.6 million associated with this project.

The replacement of the existing 138 KV undersea cable between Connecticut and Long Island for which permitting and contracting are complete and cable manufacturing is well underway. CL&P and the Long Island Power Authority (LIPA) jointly filed plans with the Department of Environmental Protection (DEP) to replace this 11-mile undersea electric transmission line

between Norwalk and Northport - Long Island, New York and each owns approximately 50 percent of the line. CL&P's portion of the project is estimated to cost $72 million. Final DEP permits and the United States Army Corps of Engineers permit have been received. Marine construction activities commenced in October of 2007, and a second half of 2008 project in-service date is expected. The existing cables were decommissioned on September 10, 2007, and it is expected that they will be removed by the end of 2007. At September 30, 2007, the project was approximately 55 percent complete, and by early November of 2007, was estimated to be approximately 56 percent complete. CL&P has capitalized $20.1 million associated with this project, not including the cost of the replacement cable for which CL&P will take ownership of in the fourth quarter of 2007.

As part of a New England Independent System Operator (ISO-NE) regional system plan, NU, ISO-NE and National Grid have begun planning a series of 345 KV and 115 KV upgrades to the transmission system connecting Massachusetts, Rhode Island and Connecticut called the New England East-West Solution (NEEWS). NEEWS includes three 345 KV NU projects that work together to address the region's transmission needs: 1) the Greater Springfield 345 KV Reliability Project, 2) the Central Connecticut Reliability Project, and 3) the Interstate Reliability Project. A fourth project, National Grid's Rhode Island Reliability Project, is also included in NEEWS. NU and National Grid have entered into a formal agreement to plan and permit these projects and expect to work with ISO-NE on the technical review of these projects during the remainder of 2007 with the completion of the ISO-NE review by mid-2008. The filing of the first project applications with the various state siting authorities will occur shortly after receiving the technical approvals from ISO-NE. At this time, the company expects to complete construction of these projects in 2013. NU has not yet completed a detailed estimate of the total cost for NEEWS and the timing of expenditures is highly dependent upon receipt of technical and siting approvals. Assuming virtually all of the 345 KV portions of the NEEWS projects are constructed overhead and on existing rights of way, NU currently expects its share of the cost of the NEEWS 345 KV projects to cost approximately $1.05 billion. However, the NEEWS overhead projects are currently being evaluated against preliminary engineering and routing analyses recently completed, and the company expects the cost of the NEEWS projects to increase and this increase, could be substantial due to scope, material and labor costs. The company anticipates that it will have additional information on the scope, material and labor costs of these projects in the first quarter of 2008.

Also, as part of the ISO-NE regional system plan, studies have identified transmission infrastructure upgrades that are required for the reliability of the 115 KV system in the Springfield, Massachusetts area. This WMECO project is referred to as the Springfield 115 KV Cables project. After further planning and engineering studies, the company has concluded that the Springfield 115 KV Cables project is a separate and distinct project, independent of the NEEWS projects. WMECO expects to receive technical approval from ISO-NE by the end of 2007. Once technical approval is received, WMECO expects to begin to file applications for the Springfield 115 KV Cables project with the Massachusetts siting agencies. At this time, WMECO expects the Springfield 115 KV Cables project to cost approximately $350 million, which includes 10 miles of new and upgraded underground cables and a new switching station. WMECO also expects to complete the project by the end of 2011.

In October of 2006, the Bethel, Connecticut to Norwalk project was completed and energized and has operated reliably since then. As a result, in addition to improving reliability, the company believes the completion of that project is the primary reason for the decrease in congestion costs of approximately 60 percent, or more than $130 million, in Connecticut through September 30, 2007.

Distribution and Generation Segment: For 2007, CL&P, PSNH, WMECO and Yankee Gas are currently projecting distribution segment (and in the case of PSNH, including its generation segment) capital expenditures of $279 million, $125 million, $34 million, and $65 million, respectively, totaling $503 million. A summary of distribution and generation segment capital expenditures by company in the first nine months of 2007 and 2006 is as follows (millions of dollars):


		For the Nine Months Ended September 30,
		2007		2006
CL&P	$	192.1	$	152.5
PSNH		84.7		77.0
WMECO		23.0		22.9
Yankee Gas		44.0		64.0
Other		0.1		2.0
Totals	$	343.9	$	318.4

Capital expenditures at Yankee Gas above included $11 million spent on its liquefied natural gas (LNG) storage and production facility in Waterbury, Connecticut, which is capable of storing the equivalent of 1.2 bcf of natural gas. The LNG storage facility was filled with LNG by the end of October of 2007 for use by customers in the 2007/2008 heating season. The facility was placed in service in July of 2007 on budget with a final cost projected to be approximately $108 million. The capital cost of this facility has been included in Yankee Gas' rates since July 1, 2007.

Transmission Rate Matters and FERC Regulatory Issues

CL&P, PSNH and WMECO and most other New England utilities, generation owners and marketers are parties to a series of agreements that provide for coordinated planning and operation of the region's generation and transmission facilities and the market rules by which these parties participate in the wholesale markets and acquire transmission services. Under these arrangements, ISO-NE, a non-profit corporation whose board of directors and staff are independent from all market participants, has served as the Regional Transmission Organization for New England since February 1, 2005. ISO-NE ensures the reliability of the New England transmission system, administers the independent system operator tariff (ISO Tariff), subject to FERC approval, and oversees the efficient and competitive functioning of the regional wholesale power market.

Transmission - Wholesale Rates: Wholesale transmission revenues are based on rates and formulas that are approved by the FERC. Most of NU’s wholesale transmission revenues are collected under the FERC Electric Tariff No. 3, Open Access Transmission Tariff (OATT). Tariff No. 3 includes the Regional Network Service (RNS) and Local Network Service (LNS) rate schedules. The RNS rate, administered by ISO-NE, is set on June 1^st of each year and recovers the revenue requirements associated with transmission facilities that benefit the New England region. The LNS rate, administered by NU, is set on January 1^st and June 1^st of each year and recovers the revenue requirements for local transmission facilities. The LNS rate provides for an annual true-up to total actual costs, which ensures that NU recovers its total (both regional and local) revenue requirements.

FERC ROE Decision: As a result of the preliminary October 31, 2006 FERC return on equity (ROE) decision, the company recorded an estimated regulatory liability for refunds of $25.6 million as of December 31, 2006. During the first half of 2007, the company completed the customer refunds that were calculated in accordance with the compliance filing required by the FERC ROE decision, and refunded approximately $23.9 million to regional, local and localized transmission customers. The $1.7 million positive pre-tax difference ($1 million after-tax) between the estimated regulatory liability recorded and the actual amount refunded was recognized in pre-tax earnings in the second quarter of 2007.

Pursuant to the October 31, 2006 FERC ROE decision, the New England transmission owners submitted a compliance filing that calculated the refund amounts for transmission customers for the February 1, 2005 to October 31, 2006 time period. Subsequently, on July 26, 2007, the FERC disagreed with the ROEs the transmission owners used in their refund calculations for the 15-month period between June 3, 2005 and September 3, 2006, rejected a portion of the compliance filing, and required another compliance filing within 30 days. On August 27, 2007, NU and the other New England transmission owners filed a revised compliance filing which outlined the regional refund process to comply with the FERC’s July 26, 2007 order. In addition, the transmission owners filed a request for rehearing on the issue of the last clean rate doctrine for the period from June 3, 2005 to September 3, 2006. NU is awaiting a final FERC determination on this issue.

Legislative Matters

There have been no other significant legislative changes in any of NU's jurisdictions in the third quarter of 2007. See "Regulatory Developments and Rate Matters," included in this Management's Discussion and Analysis for further information on how recent legislative actions continue to impact NU's businesses.

Regulatory Developments and Rate Matters

Connecticut - CL&P:

Distribution Rates: On July 30, 2007, CL&P filed an application with the DPUC to raise distribution rates by approximately $189 million effective on January 1, 2008, and approximately $22 million effective in January of 2009. In its application, CL&P cited a weak Regulatory ROE, which has been significantly lower than its 9.85 percent authorized Regulatory ROE since the end of 2004, and requested an authorized Regulatory ROE of 11 percent. The application also cited the December 31, 2007 expiration of $30 million of refunds per year to customers for four years totaling $120 million from previous overrecoveries and the need to upgrade CL&P's aging distribution facilities. Hearings were held on the proposal in the fall of 2007 and CL&P currently anticipates a draft decision on December 13, 2007 and a final decision on December 27, 2007.

As required by Public Act 07-242, "An Act Concerning Electricity and Energy Efficiencies" (Energy Efficiency Act), CL&P's rate case includes a proposal to implement distribution revenue decoupling from the volume of electricity sales using a revenue per customer adjustment mechanism. The company expects a determination on its decoupling proposal as part of the rate case decision. It is unclear what decoupling mechanism will be adopted by the DPUC and what impact it will have on CL&P.

Time-of-Use Rates: On March 30, 2007, CL&P filed a metering compliance plan with the DPUC that would meet the DPUC's objective of offering time-of-use rates to all CL&P customers. CL&P's filing discussed the technology, implementation options and costs comparing an open advanced metering infrastructure (AMI) system deployed on a geographic basis to a fixed automated metering reading (AMR) network system deployed on a usage-based priority schedule. The plan provided for full deployment by 2010. On July 2, 2007, CL&P filed a revised AMI plan consistent with the requirements of the Connecticut Energy Efficiency Act. The revised plan provided a more incremental deployment schedule based on customer interest and allowed for future DPUC input at various milestones. In both plans, CL&P requested cost recovery through its federally mandated congestion cost (FMCC) mechanism. As there is a wide range of outcomes in the technology that could be used and the schedule and level of implementation of AMI, the cost of implementing AMI could vary greatly. A draft decision is expected in the fall of 2007.

Standard Service Procurement and Rates: On July 1, 2007, CL&P implemented a 5 percent average decrease in the overall rates for residential and small commercial and industrial customers who receive standard service as a result of lower power procurement costs, reduced FMCC charges and a decline in CL&P’s transmission charge. The average standard service generation rate decreased from $0.11241 per KWH to $0.10791 per KWH. At the same time, CL&P implemented a 0.9 percent increase in overall supplier of last resort standard service rates due to an increase in the generation service charge (GSC) from $0.11359 per KWH to $0.11571 per KWH. Large commercial and industrial customers are served through provider of last resort rates. CL&P is fully recovering the cost of its standard service and supplier of last resort service.

FMCC Filings: On February 2, 2007, CL&P filed with the DPUC its semi-annual FMCC reconciliation filing for the period January 1, 2006 through December 31, 2006. The filing did not request a change to the GSC or FMCC rates, as these rates were previously adjusted beginning January 1, 2007 using projected overrecoveries for the same period. On August 22, 2007, the filing was approved by the DPUC as filed.

On August 2, 2007, CL&P filed with the DPUC its semi-annual reconciliation to document actual FMCC charges (including Energy Independence Act charges), GSC revenue and expenses and Energy Adjustment Clause (EAC) charges for the period January 1, 2007 through June 30, 2007 and projected costs for the period July 1, 2007 through December 31, 2007. The filing included overrecoveries totaling approximately $64 million associated with these charges for the period January 1, 2007 through June 30, 2007. Additionally, CL&P had remaining overrecoveries outstanding of approximately $37 million associated with the prior FMCC reconciliation period. CL&P expects that the majority of the $37 million will be returned to customers by the end of 2007. A draft decision is scheduled for December 21, 2007, and a final decision is scheduled for January 9, 2008.

Independence and Energy Efficiency Acts: Pursuant to Public Act 05-01, "An Act Concerning Energy Independence" (Energy Independence Act), in May of 2007 CL&P and United Illuminating Corporation (UI) entered into a 15-year agreement beginning in 2010 to purchase energy, capacity and renewable energy credits from a biomass energy plant yet to be built. The agreement has been approved by the DPUC. CL&P's payments under this agreement will depend on the quantities purchased and the price of energy, and are currently estimated to be approximately $15 million annually from 2010 to 2024. CL&P and UI have signed a sharing agreement and filed it with the DPUC under which they will share the costs and benefits of these contracts, with 80 percent to CL&P and 20 percent to UI, regardless of which contracts were signed by CL&P and which contracts were signed by UI. CL&P's portion of the costs and benefits of these contracts will be paid by or returned to CL&P's customers.

Also pursuant to the Energy Independence Act, the DPUC conducted a request for proposal process and selected three generating projects to be built or modified that would be eligible to sign contracts for differences (CFDs) with CL&P and UI for a total of 782 MW of capacity. The process also selected one new demand response project for 5 MW. The CFDs obligate the utilities to pay the difference between a set capacity price and the value that the projects receive in the ISO-NE capacity markets. The contracts are for periods of up to 15 years and are subject to another sharing agreement between CL&P and UI. As of September 30, 2007, these contracts have been approved by the DPUC and signed by CL&P or UI, whichever is the primary obligor. CL&P’s portion of the costs and benefits of these contracts will be paid by or refunded to CL&P’s customers. The costs to CL&P under these agreements will depend on the capacity prices that the projects receive in the ISO-NE capacity markets. On October 5, 2007, NRG Energy, Inc. (NRG) filed an appeal of the DPUC's decision in New Britain Superior Court. For further information, see Note 4, "Derivative Instruments," to the condensed consolidated financial statements.

The Connecticut Clean Energy Fund has approved, for further consideration by the DPUC, 11 more renewable energy projects of different designs totaling approximately 160 MW, of which the DPUC is expected to approve up to 125 MW. It is currently unknown which projects will be approved by the DPUC. A final decision is anticipated in early 2008. CL&P's share of the future costs of such projects will be paid by CL&P's customers. The ultimate cost of these projects cannot be estimated at this time.

The Energy Efficiency Act provides for the electric distribution companies to enter into negotiations for cost-of-service based contracts for the energy associated with these projects, for term lengths equivalent to the associated CFDs. These energy contracts must be approved by the DPUC after a finding that they will stabilize the cost of electricity for Connecticut ratepayers. Depending on

its terms, a long-term contract to purchase energy from a project that is also under a CFD could result in CL&P consolidating these projects into its financial statements. CL&P would seek to recover from customers any costs that result from consolidation of a project. One project expressed an interest in negotiating such a contract with CL&P.

New Hampshire:

SCRC/ES Rates: On September 7, 2007, PSNH filed petitions with the New Hampshire Public Utilities Commission (NHPUC) requesting a change in its stranded cost recovery charge (SCRC) and default energy service (ES) rates for the period January 1, 2008 through December 31, 2008. Consistent with previous filings, PSNH will update its filing in November of 2007 to reflect the most current energy market data.

Massachusetts:

Rate Case Settlement: The Massachusetts Department of Public Utilities (DPU) approved a rate case settlement to increase WMECO distribution rates by $1 million beginning on January 1, 2007 and an additional $3 million beginning on January 1, 2008. On October 1, 2007, WMECO filed for the DPU's review the second phase of the rate case settlement increase of $3 million. As part of this filing, WMECO also included its annual update to customer rates for its various cost reconciliation mechanisms. The net impact of both the rate case settlement increase and the annual update of the various cost reconciliation mechanisms is an average 1.1 percent reduction on customers’ total bills. This overall rate adjustment does not include changes to the default/basic service component. A decision on WMECO’s filing is expected by December 31, 2007.

Contingent Matters:

The items summarized below contain contingencies that may have an impact on the company's net income, financial position or cash flows. See Note 6A, "Commitments and Contingencies - Regulatory Developments and Rate Matters," and Note 11, "Subsequent Event," to the condensed consolidated financial statements for further information regarding these matters.

CTA and SBC Reconciliation: On March 30, 2007, CL&P filed its 2006 CTA and System Benefits Charge (SBC) reconciliation, which compared CTA and SBC revenues to revenue requirements, with the DPUC. The DPUC issued a final decision on October 10, 2007. The outcome of this docket did not have a material adverse impact on CL&P’s net income, financial position or cash flows.

Procurement Fee Rate Proceedings: On December 8, 2005, a draft decision was issued by the DPUC, which accepted the methodology proposed by CL&P to calculate the variable portion (incentive portion) of a procurement fee CL&P was allowed to collect from customers who purchased TSO service from 2004 through 2006 and authorized payment of $5.8 million for its 2004 incentive fee. A final decision, which had been scheduled for December of 2005, was delayed by the DPUC, and the DPUC re-opened the docket to review additional testimony. On October 19, 2007, the DPUC released a recommendation prepared by its consultant relative to statistical adjustments to the incentive calculations. The DPUC has set a new schedule allowing for rebuttal of the consultant’s report. The new schedule calls for a final decision in this docket in February of 2008. Management continues to believe that recovery of the $5.8 million asset related to CL&P's 2004 incentive payment, which was reflected in 2005 earnings, is probable.

Purchased Gas Adjustment: In 2005 and 2006, the DPUC issued decisions regarding Yankee Gas Purchased Gas Adjustment (PGA) clause charges and required an audit of approximately $11 million in previously recovered PGA revenues associated with unbilled sales and revenue adjustments for the period of September 1, 2003 through August 31, 2005. The audit has concluded, and a final report has been submitted. A DPUC hearing was held on October 9, 2007. Management believes the unbilled sales and revenue adjustments and resulting charges to customers through the PGA clause for this period were appropriate and that the appropriateness of the PGA charges to customers for the time period under review will be approved.

SCRC/ES Reconciliation and Rates: On May 1, 2007, PSNH filed its 2006 SCRC/ES reconciliation with the NHPUC. On November 5, 2007, PSNH, the New Hampshire Office of Consumer Advocate, and staff of the NHPUC entered into a settlement agreement resolving all outstanding issues in this proceeding with de minimis adjustments to PSNH's SCRC/ES reconciliation. The settlement agreement was the subject of a NHPUC hearing on November 6, 2007, and a decision is expected by the end of 2007. If the settlement agreement is approved by the NHPUC, this matter will not have a material adverse impact on PSNH's net income, financial position or cash flows.

Transition Cost Reconciliations: WMECO filed its 2005 transition cost reconciliation with the DPU on March 31, 2006 and filed its 2006 transition cost reconciliation with the DPU on March 31, 2007. Management does not expect the outcome of the DPU's review of these filings to have a material adverse impact on WMECO's net income, financial position or cash flows.

NU Enterprises Divestitures

NU has exited substantially all of its competitive businesses. NU Enterprises continues to wind down its few remaining wholesale contracts and energy services activities.

Wholesale Marketing Business: During the nine months ended September 30, 2007, Select Energy continued to manage its remaining obligations in the PJM power pool and under a long-term contract with the New York Municipal Power Authority (NYMPA). The remaining PJM wholesale sales contract will expire on May 31, 2008. In addition to the PJM and NYMPA contracts, Select Energy's only other long-term wholesale obligation is a non-derivative contract to purchase the output of a certain generating facility in New England through 2012. Based on the current value of this non-derivative contract, when combined with the net wholesale derivative contract portfolio that has been marked-to-market at September 30, 2007 at a value of negative $94.7 million, management believes, under present conditions, that the estimated total net cash cost at September 30, 2007 to exit the remaining wholesale marketing business is less than $50 million.

Retail Marketing Business: On June 1, 2006, Select Energy sold its retail marketing business and paid approximately $24.4 million in 2006 and will pay approximately $15 million by the end of 2007 to the purchaser. These amounts were and are included in other current liabilities on the accompanying condensed consolidated balance sheets.

Competitive Generation Business: NU completed the sale of NU Enterprises' competitive generation assets on November 1, 2006.

Energy Services Businesses: Most of NU Enterprises' energy services businesses were sold in 2005 and 2006. In the second quarter of 2007, the energy services businesses recorded an after-tax gain of approximately $2.5 million related the favorable resolution of certain contingencies from the SESI sale related to a contract to complete a cogeneration facility. There were no such gains or charges related to this contract recorded in the third quarter of 2007.

In connection with the sale of the retail marketing business, the competitive generation business and certain of the energy services businesses, NU provided various guarantees and indemnifications to the purchasers of these businesses. See Note 6F, "Commitments and Contingencies - Guarantees and Indemnifications," to the condensed consolidated financial statements for information regarding these items.

NU Enterprises Contracts

Wholesale Derivative Contracts: At September 30, 2007 and December 31, 2006, the fair value of Select Energy's wholesale derivative assets and derivative liabilities, which are subject to mark-to-market accounting (excluding the non-derivative contract described previously), are as follows:


(Millions of Dollars)	September 30, 2007		December 31, 2006
Current wholesale derivative assets	$	45.1	$	43.6
Long-term wholesale derivative assets		5.5		22.3
Current wholesale derivative liabilities		(72.4)		(82.3)
Long-term wholesale derivative liabilities		(72.9)		(110.1)
Portfolio position	$	(94.7)	$	(126.5)

Numerous factors could either positively or negatively affect the realization of the wholesale net fair value amounts in cash. These factors include the amounts paid or received to exit some or all of these contracts, the volatility of commodity prices until the contracts are exited or expire, the outcome of future transactions, the performance of counterparties, and other factors.

Select Energy has policies and procedures requiring all of its wholesale 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 energy contracts are identified and segregated in the table of fair value of contracts at September 30, 2007 and December 31, 2006. A description of each method is as follows: 1) prices actively quoted primarily represent New York Mercantile Exchange (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 prior contract settlements with third parties. Currently, Select Energy also has a contract for which a portion of the contract's fair value is determined based on a model. The model utilizes natural gas prices and a conversion factor to electricity for the years 2012 and 2013. Broker quotes for electricity at locations for which Select Energy has entered into transactions are generally available through the year 2011.

Generally, valuations of short-term 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 contracts are less certain. Accordingly, there is a risk that contracts will not be realized at the amounts recorded.

At September 30, 2007 and December 31, 2006, the sources of the fair value of wholesale contracts are included in the following tables:


	Fair Value of Wholesale Contracts at September 30, 2007
(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	$	(7.0)	$	(3.7)	$	-	$	(10.7)
Prices provided by external sources		(20.3)		(34.3)		(3.0)		(57.6)
Model-based		-		3.6		(30.0)		(26.4)
Totals	$	(27.3)	$	(34.4)	$	(33.0)	$	(94.7)


	Fair Value of Wholesale Contracts at December 31, 2006
(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	$	(6.9)	$	(11.2)	$	(1.9)	$	(20.0)
Prices provided by external sources		(32.2)		(44.8)		(12.7)		(89.7)
Model-based		0.4		3.5		(20.7)		(16.8)
Totals	$	(38.7)	$	(52.5)	$	(35.3)	$	(126.5)

For the three and nine months ended September 30, 2007, the changes in fair value of these contracts are included in the following table:


	For the Three Months Ended September 30, 2007			For the Nine Months Ended September 30, 2007
(Millions of Dollars)	Total Portfolio Fair Value			Total Portfolio Fair Value

Fair value of wholesale contracts outstanding at the beginning of the period	$	(89.6)	$	(126.5)
Contracts realized or otherwise settled during the period		(2.6)		36.4
Changes in fair value recorded in fuel, purchased and net interchange power		(2.5)		(4.6)
Fair value of wholesale contracts outstanding at the end of the period	$	(94.7)	$	(94.7)

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 by the company. 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 to economic, regulatory or other conditions. At September 30, 2007, Select Energy's counterparty credit exposure to wholesale and trading counterparties of approximately one percent was collateralized, approximately 14 percent was rated BBB- or better and approximately 85 percent was non-rated. The composition of Select Energy's credit portfolio has shifted from being largely investment grade-rated to being mostly non-rated. This is largely due to the exit from the New England wholesale and retail portfolios and the expiration of the PJM obligations. The bulk of the non-rated credit exposure is comprised of one counterparty (96 percent of the total) that is a creditworthy, non-rated public entity. Select Energy was provided $0.4 million and $0.1 million of counterparty deposits at September 30, 2007 and December 31, 2006, respectively.

Critical Accounting Policies and Estimates Update

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America 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 the financial statements of NU. Management communicates to and discusses with NU's Audit Committee of the Board of Trustees all critical accounting policies and estimates. All of these critical accounting policies and estimates were reported in the NU 2006 Form 10-K and certain accounting policies and estimates were updated in the NU First and Second Quarter 2007 reports on Form 10-Q. There have been no further material changes with regard to these critical accounting policies and estimates except as follows:

PBOP Benefits: NU's subsidiaries provide certain health care benefits, primarily medical and dental, and life insurance benefits through a benefit plan to retired employees (PBOP Plan). NU estimates the year end (December 31^st) prepaid or accrued PBOP Plan asset or obligation based on an actuarial valuation as of the beginning of the year (January 1^st), adjusted for known changes during the year such as actual earnings, interest rate levels, expenses incurred and benefits paid during the year. This estimated year end balance is also used to estimate the following year's related PBOP Plan income or expense and the prepaid or accrued PBOP Plan asset or obligation. This estimate is adjusted in the following year based on an actuarial valuation using actual data as of January 1^stof that year. An actuarial valuation as of January 1, 2007 was completed in the third quarter of 2007, resulting in a third quarter decrease to the accrued PBOP Plan liability of $14.5 million with a decrease to the regulatory asset for deferred benefits of $13 million and an increase to accumulated other comprehensive income of approximately $0.9 million, net of tax.

The pre-tax, pre-capitalization earnings impact of this change in estimate is to decrease annual 2007 PBOP Plan expense by approximately $1.4 million.

For additional information regarding these changes, see Note 9, "Pension Benefits and Postretirement Benefits Other Than Pensions," to the condensed consolidated financial statements.

As a result of the completion of the actuarial valuation as of January 1, 2007, the forecasted expense for the PBOP Plan has changed since last reported in NU's 2006 Form 10-K. Based on current Plan assumptions, NU currently estimates that the expected contributions and forecasted expense along with the amounts included in NU's 2006 Form 10-K are as follows (in millions):


	PBOP Plan - Current Estimate				PBOP Plan - NU's 2006 Form 10-K
Year	Expected Contributions		Forecasted Expense		Expected Contributions		Forecasted Expense
2007		$38.4		$38.4		$39.8		$39.8
2008		$36.7		$36.7		$36.7		$36.7
2009		$33.4		$33.4		$33.9		$33.9

Goodwill Impairment Testing: NU conducts goodwill impairment testing as of October 1^st of each year. NU's remaining goodwill balance totaling $287.6 million relates to the acquisition of Yankee Gas in 2000. The testing of goodwill for impairment requires management to use estimates and judgment. Key factors that are considered in the impairment analysis include cash flow projections, interest rates, and recent comparable acquisition values. The company is in the process of completing the annual impairment test of the Yankee Gas goodwill as of October 1, 2007.

If as a result of the impairment analysis the estimated fair value of Yankee Gas is lower than its carrying value, then a second step of goodwill impairment testing would be required. The estimated fair value of Yankee Gas initially determined would be allocated to the assets and liabilities of Yankee Gas to determine the new value of goodwill. This new value would be compared to the carrying value of Yankee Gas goodwill, and any excess carrying value would be written off.

Income Taxes: Income tax expense is estimated annually for each of the jurisdictions in which NU operates. This process involves estimating actual current and deferred income tax expense or benefit as impacted by earnings and the impact of temporary differences resulting from differing treatment of items, such as timing of the deduction and expenses, for tax and book accounting purposes, as well as, any impact of permanent differences resulting from tax credits, flow-through items, non-tax deductible expenses, etc. These differences result in deferred tax assets and liabilities that are included in the condensed consolidated balance sheets. The income tax estimation process impacts all of NU's segments. In accordance with the provisions of Accounting Principles Board (APB) No. 28, "Interim Financial Reporting," NU records income tax expense quarterly using an estimated annualized effective tax rate. Adjustments to these estimates can significantly affect NU's condensed consolidated financial statements.

Part of the annual process in making adjustments to these estimates is a reconciliation of the income tax returns actually filed to the estimates or provisions made prior to filing the annual income tax returns. In this annual process, the estimates that are made by management in order to record income tax expense are compared each year to the actual tax positions and amounts included on NU's income tax returns as filed, and adjustments are recorded as needed. The income tax returns are filed in the fall of each year for the

previous tax year. As the 2006 tax returns associated with certain jurisdictions are finalized, NU will reconcile and record the related estimate to actual adjustments during the fourth quarter of 2007. As a result of not yet having completed the reconciliations of estimates to actual data, management cannot predict the fourth quarter impact of adjusting the estimates to actual tax return amounts at this time.

In the third quarter of 2006, the impact of these return to provision adjustments positively impacted earnings as follows (in millions):


CL&P	$	2.0
PSNH		0.1
WMECO		0.1
NU Enterprises		2.9
Other		(0.3)
Total	$	4.8

Other Matters

Contractual Obligations and Commercial Commitments: For updated information regarding NU's contractual obligations and commercial commitments at September 30, 2007, see Note 6C, "Commitments and Contingencies - Long-Term Contractual Arrangements," to the condensed consolidated financial statements.

HWP Environmental Matters: The company remains in the process of evaluating additional potential remediation requirements at a river site in Massachusetts containing tar deposits. HWP is at least partially responsible for this site, and substantial remediation activities at this site have already been conducted. HWP first established a reserve for this site in 1994. Since that time, HWP has expensed approximately $13 million, of which $12.4 million has been spent and $0.6 million remains in the reserve. HWP’s reserve is based on its most recent site assessment and estimate of required remediation costs. The ultimate remediation requirements will depend, among other things, on the level and extent of the remaining tar required to be removed, and the extent of HWP’s responsibility. These matters are the subject of ongoing discussions with the Massachusetts Department of Environmental Protection and may change from time-to-time. HWP's share of the remediation costs related to this site is not recoverable from ratepayers. At this time, management cannot predict the outcome of this matter or its ultimate effect on NU. Any additional increase to the environmental remediation reserve for this site would be recorded in earnings in future periods when it is reasonably estimable and probable, and potential increases may be material. There were no changes to the environmental reserve for this site in the third quarter of 2007.

Consolidated Edison, Inc. Merger Litigation: Certain gain and loss contingencies exist with regard to the merger agreement between NU and Consolidated Edison, Inc. (Con Edison) and the related litigation.

For information regarding other commitments and contingencies, see Note 6, "Commitments and Contingencies," to the condensed consolidated financial statements.

Accounting Standards Issued But Not Yet Adopted:

fair value reflected in earnings on January 1, 2008, similar to a change in estimate. The company is evaluating the impact SFAS No. 157 will have on its financial statements.

Forward Looking Statements: This discussion and analysis includes statements concerning NU's expectations, plans, objectives, future financial performance 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. In some cases the reader can identify these forward looking statements by words such as "estimate," "expect," "anticipate," "intend," "plan," "believe," "forecast," "should," "could," and similar expressions. Forward looking statements involve risks and uncertainties that may cause actual results or outcomes to differ materially from those included in the forward looking statements. Factors that may cause actual results to differ materially from those included in the forward looking statements include, but are not limited to, actions or inactions by local, state and federal regulatory bodies, competition and industry restructuring, changes in economic conditions, changes in weather patterns, changes in laws, regulations or regulatory policy, changes in levels or timing of capital expenditures, developments in legal or public policy doctrines, technological developments, changes in accounting standards and financial reporting regulations, fluctuations in the value of the remaining electricity positions, actions of rating agencies, subsequent recognition, derecognition and measurement of tax positions, and other presently unknown or unforeseen factors. Other risk factors are detailed from time to time in the company's reports to the SEC, including the risk factors set forth in our Annual Report on Form 10-K for the year ended December 31, 2006 and our quarterly reports on Form 10-Q for the quarters ended March 31, 2007 and June 30, 2007. Any forward looking statement speaks only as of the date on which such statement is made and the company undertakes no obligation to update the information contained in any forward looking statements to reflect developments or circumstances occurring after the statement is made.

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

RESULTS OF OPERATIONS - NU CONSOLIDATED

The following table provides the variances in income statement line items for the condensed consolidated statements of income/(loss) for NU included in this report on Form 10-Q for the three and nine months ended September 30, 2007:


	Income Statement Variances (Millions of Dollars) 2007 over/(under) 2006
	Third Quarter		Percent		Nine Months		Percent
Operating Revenues	$	(142)	(9)	%	$	(854)	(16)	%

Operating Expenses:
Fuel, purchased and net interchange power		(165)	(16)			(943)	(25)
Other operation		(54)	(22)			(148)	(18)
Restructuring and impairment charges		(1)	(100)			(10)	(98)
Maintenance		(2)	(4)			16	11
Depreciation		3	5			12	6
Amortization		26	(a)			(29)	(59)
Amortization of rate reduction bonds		3	7			9	7
Taxes other than income taxes		1	2			-	-
Total operating expenses		(189)	(12)			(1,093)	(21)

Operating Income		47	61			239	(a)

Interest expense, net		2	3			-	-
Other income, net		(1)	(11)			(2)	(5)
Income/(Loss) before income tax benefit		44	(a)			237	(a)
Income tax expense / (benefit)		96	(a)			161	(a)
Preferred dividends of subsidiary		-	-			-	-
Income/(loss) from continuing operations		(52)	(51)			76	79
Income/(loss) from discontinued operations		(9)	(a)			(26)	(96)
Net Income	$	(61)	(55)	%	$	50	41	%

(a) Percent greater than 100.

Comparison of the Third Quarter of 2007 to the Third Quarter of 2006

Net income is $61 million lower in 2007 primarily due to the CL&P 2006 one-time $74 million income tax reduction associated with the PLR. Non-GAAP net income increased $13 million, which excludes the 2006 one-time income tax item.

Operating Revenues

Operating revenues decreased $142 million in 2007 primarily due to lower revenues from the regulated companies ($129 million) and lower revenues from NU Enterprises ($12 million). The lower 2007 regulated revenues are being driven by the recovery of a lower level of CL&P distribution related expenses passed through to customers through their regulatory tracking mechanisms. Regulated revenues for the CL&P distribution and transmission segments which recover their fixed costs and flow through to earnings are higher in 2007 compared to 2006.

Revenues from the regulated companies decreased $129 million due to lower distribution segment revenues ($143 million), partially offset by higher transmission segment revenues ($14 million). Distribution segment revenues decreased $143 million primarily due to lower electric distribution revenues ($152 million), partially offset by higher gas distribution revenues ($9 million). Transmission segment revenues increased $14 million primarily due to a higher transmission investment base and higher operating expenses which are recovered under FERC-approved transmission tariffs.

The distribution component of the electric distribution segment which flows through to earnings increased $8 million primarily due to an increase in retail rates ($10 million), partially offset by a decrease in retail sales ($1 million).

The decrease in electric distribution revenues is partially offset by higher gas distribution revenues of $9 million primarily due to the rate increase effective July 1, 2007. Firm gas sales decreased 4 percent compared with 2006. On a weather normalized basis, firm gas sales deceased 3 percent.

NU Enterprises' revenues decreased $12 million due to the exit from components of the competitive businesses during the latter part of 2006.

Fuel, Purchased and Net Interchange Power

Fuel, purchased and net interchange power expenses decreased $165 million in 2007 primarily due to lower costs at NU Enterprises ($29 million) and lower costs at the regulated companies ($136 million). NU Enterprises' fuel expenses decreased due to the exit from significant components of the competitive businesses. Fuel, purchased and net interchange power expenses from the regulated companies decreased primarily due to lower fuel, purchased and net interchange power expenses at CL&P, PSNH and WMECO ($138 million), mainly as a result of a decrease in standard offer supply costs as a result of a reduction in load caused by customer migration, partially offset by higher 2007 supply prices.

Other Operation

Other operation expenses decreased $54 million in 2007 primarily due to lower regulated company distribution and transmission segment expenses ($55 million) and lower NU Enterprises' expenses ($1 million).

Lower regulated company distribution and transmission segment expenses of $55 million are primarily due to lower reliability must run (RMR) expenses at CL&P ($65 million), partially offset by higher retail transmission expenses at WMECO ($7 million) and higher administration and general expenses at WMECO and PSNH ($4 million).

Restructuring and Impairment Charges

See Note 2, "Restructuring and Impairment Charges," to the condensed consolidated financial statements for a description and explanation of these charges.

Maintenance

Maintenance expenses decreased $2 million in 2007 primarily due to lower regulated company distribution and transmission segment expenses.

Lower regulated company distribution and transmission segment expenses of $2 million in 2007 are primarily due to significant storm expenses in 2006.

Depreciation

Depreciation increased $3 million in 2007 primarily due to higher distribution and transmission depreciation expense as a result of higher plant balances from the ongoing construction program.

Amortization

Amortization increased $26 million in 2007 for the regulated companies' distribution segments primarily due to higher amortization for PSNH distribution ($13 million), CL&P distribution ($8 million) and WMECO distribution ($5 million).

Amortization of Rate Reduction Bonds

Amortization of rate reduction bonds increased $3 million in 2007. The higher portion of principal within the rate reduction bonds payment results in a corresponding increase in the amortization of regulatory assets.

Interest Expense, Net

Interest expense increased $2 million, primarily due to higher interest for the regulated company distribution and transmission segments ($8 million), partially offset by lower interest at NU Enterprises ($5 million). The higher regulated company distribution and transmission segment interest is primarily due to higher interest at CL&P mainly as a result of the March 2007 and September 2007 debt issuances.

Income Tax Expense/(Benefit)

Income tax expense increased $96 million due primarily to an increase in pre-tax earnings and lower favorable tax adjustments; partially offset by a decrease in flow through regulatory amortizations and the reversal of a state tax reserve. In 2006, a significant portion of the tax adjustments included a $74 million tax benefit to remove deferred tax balances associated with the IRS PLR and a $5 million favorable change in estimate to actual adjustment. Prior year flow through regulatory amortizations were higher as a result of the regulatory recovery of tax expense associated with nondeductible acquisition costs.

Income/(Loss) from Discontinued Operations

See Note 3, "Assets Held for Sale and Discontinued Operations," to the condensed consolidated financial statements for a description and explanation of the discontinued operations.

Comparison of the First Nine Months of 2007 to the First Nine Months of 2006

Net income is $50 million higher in 2007 primarily due to the $82 million increase in NU Enterprises net income as a result of the 2006 losses associated with its retail marketing business, partially offset by the CL&P 2006 one-time $74 million income tax reduction associated with the PLR. Non-GAAP net income, which excludes these two items, increased by $42 million.

Operating Revenues

Operating revenues decreased $854 million in 2007 primarily due to lower revenues from NU Enterprises ($634 million) and lower revenues from the regulated companies ($220 million). The lower 2007 regulated revenues are being driven by the recovery of a lower level of CL&P distribution related expenses passed through to customers through their regulatory tracking mechanisms. Regulated revenues for the CL&P distribution and transmission segments which recover their fixed costs and flow through to earnings are higher in 2007 compared to 2006.

NU Enterprises' revenues decreased $634 million due to the exit from significant components of the competitive businesses during 2006.

Revenues from the regulated companies decreased $220 million due to lower distribution segment revenues ($280 million), partially offset by higher transmission segment revenues ($60 million). Distribution segment revenues decreased $280 million primarily due to lower electric distribution revenues ($296 million), partially offset by higher gas distribution revenues ($16 million). Transmission segment revenues increased $60 million primarily due to a higher transmission investment base and higher operating expenses which are recovered under FERC-approved transmission tariffs.

Lower electric distribution revenues include the components of CL&P, PSNH and WMECO retail revenues which are included in regulatory commission approved tracking mechanisms that track the recovery of certain incurred costs ($323 million). The distribution revenue tracking components decrease of $323 million is primarily due to lower CL&P revenue associated with the recovery of FMCC ($190 million), the pass through of lower energy supply costs ($88 million), a decrease in PSNH’s SCRC revenues mainly as a result of a rate decrease that went into effect July 1, 2006 ($73 million) and lower wholesale revenues ($27 million), partially offset by higher retail transmission revenues ($27 million), WMECO’s higher transition cost recoveries ($11 million) and WMECO’s pension and default service revenues ($8 million). The tracking mechanisms allow for rates to be changed periodically with over collections refunded to customers or under collections collected from customers in future periods.

The distribution component of the electric distribution segment which flows through to earnings increased $27 million primarily due to an increase in retail rates ($22 million) and an increase in retail sales ($6 million). The distribution retail electric sales were positively affected by weather impacts in 2007 as compared with 2006. Retail KWH electric sales increased by 0.9 percent in 2007 compared with 2006 (a 0.3 percent increase on a weather normalized basis).

The decrease in electric distribution revenues is partially offset by higher gas distribution revenues of $16 million primarily due to higher sales volumes as a result of a colder winter in 2007. Firm gas sales increased 8.2 percent in 2007 compared with 2006. On a weather normalized basis, firm gas sales increased 3.1 percent.

Fuel, Purchased and Net Interchange Power

Fuel, purchased and net interchange power expenses decreased $943 million in 2007 primarily due to lower costs at NU Enterprises ($700 million) and lower costs at the regulated companies ($243 million). NU Enterprises' fuel expenses decreased due to the exit from significant components of the competitive businesses. Fuel, purchased and net interchange power expenses from the regulated companies decreased primarily due to lower fuel, purchased and net interchange power expenses at CL&P, PSNH and WMECO ($243 million), mainly as a result of a decrease in standard offer supply costs as a result of a reduction in load caused by customer migration, partially offset by higher 2007 supply prices.

Other Operation

Other operation expenses decreased $148 million in 2007 primarily due to lower NU Enterprises' expenses ($92 million) and lower regulated company distribution and transmission segment expenses ($56 million).

NU Enterprises' expenses decreased $92 million primarily due to the exit from significant components of the competitive business.

Lower regulated company distribution and transmission segment expenses of $56 million are primarily due to lower RMR expenses at CL&P ($115 million), partially offset by higher retail transmission expenses at WMECO and PSNH ($28 million), higher Energy Independence Act (EIA) expenses which will also be recovered through the FMCC deferral mechanism ($11 million) and higher administration and general expenses at WMECO and PSNH ($9 million).

Restructuring and Impairment Charges

See Note 2, "Restructuring and Impairment Charges," to the condensed consolidated financial statements for a description and explanation of these charges.

Maintenance

Maintenance expenses increased $16 million in 2007 primarily due to higher regulated company distribution and transmission segment expenses ($11 million).

Higher regulated company distribution and transmission segment expenses of $11 million are primarily due to higher underground line ($3 million), tree trimming ($3 million) and overhead line expenses ($3 million) at CL&P, WMECO and PSNH.

Depreciation

Depreciation increased $12 million in 2007 primarily due to higher distribution and transmission depreciation expense ($12 million) as a result of higher plant balances from the ongoing construction program.

Amortization

Amortization decreased $29 million in 2007 for the regulated companies' distribution segments primarily due to lower amortization for PSNH distribution ($65 million), partially offset by higher amortization for CL&P distribution ($22 million) and WMECO distribution ($14 million). The PSNH decrease is primarily due to lower ES overrecoveries, lower amortization levels of stranded costs, and the deferral of retail transmission costs.

Amortization of Rate Reduction Bonds

Amortization of rate reduction bonds increased $9 million in 2007. The higher portion of principal within the rate reduction bonds payment results in a corresponding increase in the amortization of regulatory assets.

Other Income, Net

Other income, net decreased $2 million, primarily due to a lower TSO procurement fee ($9 million) and the absence of the gain on sale of investment in Globix from 2006 ($3 million), partially offset by higher interest earned on cash the parent received from the November 2006 sale of NU's competitive generation ($7 million) and higher Energy Independence Act (EIA) incentives ($2 million).

Income Tax Expense/(Benefit)

Income tax expense increased $161 million due primarily to an increase in pre-tax earnings and lower favorable tax adjustments, partially offset by a decrease in flow through regulatory amortizations. In 2006, a significant portion of the tax adjustments included a $74 million tax benefit to remove deferred tax balances associated with the IRS PLR and a $5 million change in estimate to actual adjustment. Prior year flow through regulatory amortizations were higher as a result of the regulatory recovery of tax expense associated with nondeductible acquisition costs.

Income/(Loss) from Discontinued Operations

See Note 3, "Assets Held for Sale and Discontinued Operations," to the condensed consolidated financial statements for a description and explanation of the discontinued operations.

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, condensed consolidated financial statements and footnotes in this Form 10-Q, the First and Second Quarter 2007 Form 10-Q and the NU 2006 Form 10-K.

RESULTS OF OPERATIONS

The following table provides the variances in income statement line items for the condensed consolidated statements of income for CL&P included in this report on Form 10-Q for the three and nine months ended September 30, 2007:


	Income Statement Variances (Millions of Dollars) 2007 over/(under) 2006
	Third Quarter		Percent		Nine Months		Percent
Operating Revenues	$	(165)	(15)	%	$	(195)	(6)	%

Operating Expenses:
Fuel, purchased and net interchange power		(121)	(17)			(183)	(9)
Other operation		(70)	(45)			(108)	(23)
Maintenance		(2)	(6)			5	7
Depreciation		1	1			5	4
Amortization of regulatory assets/(liabilities), net		8	(a)			22	(a)
Amortization of rate reduction bonds		2	7			7	7
Taxes other than income taxes		1	3			6	5
Total operating expenses		(181)	(18)			(246)	(9)

Operating Income		16	31			51	31

Interest expense, net		6	22			17	19
Other income, net		(1)	(11)			(3)	(14)
Income before income tax expense		9	27			31	31
Income tax expense/(benefit)		75	(a)			88	(a)
Net Income	$	(66)	(65)	%	$	(57)	(37)	%

(a) Percent greater than 100.

Comparison of the Third Quarter of 2007 to the Third Quarter of 2006

Net income is $66 million lower in 2007 primarily due to the 2006 one-time $74 million income tax reduction associated with the PLR. Non-GAAP net income increased $8 million, which excludes the 2006 one-time income tax item.

Operating Revenues

Operating revenues decreased $165 million due to lower distribution business revenues ($178 million), partially offset by higher transmission business revenues ($14 million). The lower 2007 regulated revenues are being driven by the recovery of a lower level of distribution related expenses passed through to customers through their regulatory tracking mechanisms. Regulated revenues for the distribution and transmission segments which recover their fixed costs and flow through to earnings are higher in 2007 compared to 2006.

The distribution business revenue decrease of $178 million is primarily due to the components of revenues, which are included in regulatory commission approved tracking mechanisms that track the recovery of certain incurred costs ($178 million). The distribution business revenue tracking components decreased $178 million primarily due to a decrease in revenues associated with the recovery of FMCC charges ($82 million), lower TSO related revenues ($74 million), as a result of the pass through of lower energy supply costs, lower wholesale revenues ($12 million) and lower retail transmission revenue ($6 million). The tracking mechanisms allow for rates to be changed periodically with over collections refunded to customers or under collections collected from customers in future periods.

The distribution component of revenues which impacts earnings was unchanged as the revenue increase resulting from the rate increase effective January 1, 2007 was offset by lower retail sales. Retail sales decreased 0.7 percent in 2007 compared to the same period in 2006.

Transmission business revenues increased $14 million primarily due to a higher rate base and higher operating expenses which are recovered under FERC-approved transmission tariffs.

Fuel, Purchased and Net Interchange Power

Fuel, purchased and net interchange power expense decreased $121 million primarily due to a decrease in standard offer supply costs ($102 million), lower other purchased power costs ($13 million) and lower deferred fuel costs ($6 million), all of which are included in regulatory commission-approved tracking mechanisms. The $102 million decrease in supply costs was due primarily to a reduction in load caused primarily by customer migration, partially offset by higher 2007 supply prices. These supply costs are the contractual amounts the company must pay to various suppliers that have earned the right to supply Standard Service and Last Resort Service load through a competitive solicitation process.

Other Operation

Other operation expenses decreased $70 million primarily due to lower RMR costs ($65 million), which are tracked and recovered through the FMCC and lower distribution expense primarily due to storm-related expenses ($4 million).

Maintenance

Maintenance expenses decreased $2 million primarily due to lower expense related to overhead lines primarily due to storm-related expenses ($4 million), partially offset by higher expenses related to underground network inspection activities ($2 million).

Depreciation

Depreciation expense increased $1 million primarily due to higher utility plant balances.

Amortization of Regulatory Assets/(Liabilities), Net

Amortization of regulatory assets/(liabilities), net increased $8 million primarily due to higher amortization related to the recovery of transition charges ($4 million) and higher SFAS No. 109 amortization ($3 million).

Amortization of Rate Reduction Bonds

Amortization of rate reduction bonds increased $2 million. The higher portion of principal within the rate reduction bonds’ payment results in a corresponding increase in the amortization of regulatory assets.

Taxes Other Than Income Taxes

Taxes other than income taxes increased $1 million primarily due to higher property taxes ($3 million) primarily related to an increase from the prior year’s assessment which was partially offset by a lower mill rate. The property taxes increase was partially offset by lower gross earnings taxes ($2 million).

Interest Expense, Net

Interest expense, net increased $6 million primarily due to higher interest on long-term debt ($3 million) mainly as a result of $300 million of new debt issued in March of 2007, higher interest on short-term debt ($2 million), higher FMCC deferral interest ($2 million) and higher tax-related interest ($1 million), partially offset by lower rate reduction bond interest resulting from lower principal balances outstanding ($2 million).

Other Income, Net

Other income, net decreased $1 million primarily due to a lower TSO procurement fee ($3 million) and lower Energy Independence Act (EIA) incentives ($1 million), partially offset by higher AFUDC income ($2 million) and higher conservation and load management incentives ($1 million).

Income Tax Expense

Income tax expense increased $75 million in 2007 due to a decrease in favorable tax adjustments, lower state tax credits and an increase in pre-tax earnings, partially offset by a reversal of a state tax reserve. In 2006, a significant portion of the tax adjustments related to a $74 million tax benefit to remove deferred tax balances associated with the PLR received from the IRS. A change in estimate to actual adjustment was included in 2006. The change in estimate to actual adjustment pertaining to 2006 tax returns will be recorded in the fourth quarter of 2007.

Comparison of the First Nine Months of 2007 to the First Nine Months of 2006

Net income is $57 million lower in 2007 primarily due to the 2006 one-time $74 million income tax reduction associated with the PLR. Non-GAAP net income increased $17 million, which excludes the 2006 one-time income tax item.

Operating Revenues

Operating revenues decreased $195 million due to lower distribution business revenues ($250 million), partially offset by higher transmission business revenues ($56 million). The lower 2007 regulated revenues are being driven by the recovery of a lower level of distribution related expenses passed through to customers through their regulatory tracking mechanisms. Regulated revenues for the distribution and transmission segments which recover their fixed costs and flow through to earnings are higher in 2007 compared to 2006.

The distribution business revenue decrease of $250 million is primarily due to the components of revenues, which are included in regulatory commission approved tracking mechanisms that track the recovery of certain incurred costs ($258 million). The distribution business revenue tracking components decreased $258 million primarily due to a decrease in revenues associated with the recovery of FMCC charges ($190 million), lower TSO related revenues ($46 million), as a result of the pass through of higher energy supply costs, lower wholesale revenues ($14 million) and lower retail revenues ($2 million). The tracking mechanisms allow for rates to be changed periodically with over collections refunded to customers or under collections collected from customers in future periods.

The distribution component of revenues which impacts earnings increased $7 million as a result of the rate increase effective January 1, 2007 and higher retail sales. Retail sales increased 0.9 percent in 2007 compared to the same period in 2006.

Transmission business revenues increased $56 million primarily due to a higher rate base and higher operating expenses, which are recovered under FERC-approved transmission tariffs.

Fuel, Purchased and Net Interchange Power

Fuel, purchased and net interchange power expense decreased $183 million primarily due to a decrease in standard offer supply costs ($260 million) and lower other purchased power costs ($45 million), partially offset by an increase in deferred fuel costs ($121 million), all of which are included in regulatory commission-approved tracking mechanisms. The $260 million decrease in supply costs was due primarily to a reduction in load caused primarily by customer migration, partially offset by higher 2007 supply prices. These supply costs are the contractual amounts the company must pay to various suppliers that have earned the right to supply Standard Service and Last Resort Service load through a competitive solicitation process. The offsetting $121 million increase in deferred fuel costs was largely the result of more timely collection of supply costs from customers due to a change in customer supply rates from average annual rates in 2006 to average semi-annual or monthly rates in 2007, and the deferral of significant refunds received from ISO-NE in 2007. The change in 2007 to average semi-annual or monthly customer supply rates had the effect of better matching revenue to incurred supply expense, thereby reducing the need for deferred fuel cost credits (i.e., underrecoveries). Additionally, the refunds received from ISO-NE in 2007 were primarily related to previously paid reliability must run charges to ISO-NE that must be returned to customers.

Other Operation

Other operation expenses decreased $108 million primarily due to lower RMR costs ($115 million), which are tracked and recovered through the FMCC, partially offset by higher Energy Independence Act (EIA) expenses which will also be recovered through the FMCC deferral mechanism ($11 million).

Maintenance

Maintenance expenses increased $5 million primarily due to higher expenses related to underground network inspection activities ($3 million), higher expenses related to structure maintenance ($1 million) and tree trimming ($1 million), partially offset by lower expenses related to overhead lines maintenance primarily due to storm-related expenses ($2 million).

Depreciation

Depreciation expense increased $5 million primarily due to higher utility plant balances.

Amortization of Regulatory Assets/(Liabilities), Net

Amortization of regulatory assets/(liabilities), net increased $22 million primarily due to higher amortization related to the recovery of transition charges ($10 million), higher SFAS No. 109 amortization ($9 million) and a higher system benefit charge deferral ($3 million).

Amortization of Rate Reduction Bonds

Amortization of rate reduction bonds increased $7 million. The higher portion of principal within the rate reduction bonds’ payment results in a corresponding increase in the amortization of regulatory assets.

Taxes Other Than Income Taxes

Taxes other than income taxes increased $6 million primarily due to higher property taxes ($3 million) primarily related to an increase from the prior year’s assessment which was partially offset by a lower mill rate and gross earnings taxes ($2 million).

Interest Expense, Net

Interest expense, net increased $17 million primarily due to higher interest on long-term debt ($14 million) mainly as a result of $250 million of new debt issued in June of 2006 and $300 million of new debt issued in March of 2007, higher FMCC deferral interest ($4 million), higher interest on short-term debt ($3 million) and higher tax-related interest ($3 million), partially offset by lower rate reduction bond interest resulting from lower principal balances outstanding ($7 million).

Other Income, Net

Other income, net decreased $3 million, primarily due to a lower TSO procurement fee ($9 million), partially offset by higher AFUDC income ($3 million) and higher Energy Independence Act (EIA) incentives ($2 million).

Income Tax Expense

Income tax expense increased $88 million due primarily to a decrease in favorable tax adjustments, lower state tax credits and higher pre-tax earnings. The third quarter of 2006 adjustments included a $74 million tax benefit to remove deferred tax balances associated with the PLR received from the IRS and a change in estimate to actual adjustment of $2 million.

LIQUIDITY

Net cash flows from operations decreased by $47.1 million from $148.9 million for the first nine months of 2006 to $101.8 million for the first nine months of 2007. CL&P’s operating cash flows declined in the first nine months of 2007 primarily as a result of the payment in March of 2007 of $177.2 million in federal and state income taxes and a higher level of payments to suppliers related to purchased power which were made in the first nine months of 2007 as compared to 2006. CL&P accrued the majority of this tax obligation in 2000 upon the sale of the generation assets to NGC, but due to the intercompany nature of the sales, the federal and state income tax payment was deferred at that time. It was not until these assets were sold to an unaffiliated third party in November of 2006 that CL&P was required to pay this tax obligation. These decreases were partially offset by $184.6 million decline in regulatory refunds to CL&P ratepayers and lower payments made to the Yankee Companies for decommissioning and closure costs in 2007 as compared to 2006, primarily as a result of the extension of the collection period for CYAPC’s decommissioning and closure costs.

Capital expenditures described herein are cash capital expenditures and exclude cost of removal, AFUDC related to equity funds and the capitalized portion of pension expense or income. CL&P's capital expenditures totaled $550.1 million in the first nine months of 2007, compared with $388.4 million in the first nine months of 2006. This increase is primarily due to higher transmission capital expenditures.

On March 27, 2007, CL&P closed on the sale of $150 million of first mortgage bonds due 2017 carrying a coupon rate of 5.375 percent and on the sale of $150 million of first mortgage bonds due in 2037 carrying a coupon rate of 5.75 percent. On September 17, 2007, CL&P closed on the sale of $100 million of first mortgage bonds due in 2017 with a coupon rate of 5.75 percent and $100 million of first mortgage bonds due in 2037 with a coupon rate of 6.375 percent.

Additionally, CL&P has an arrangement with a financial institution under which CL&P can sell up to $100 million of accounts receivable and unbilled revenues. At September 30, 2007, there were no amounts outstanding under that facility. Financing activities for the nine months ended September 30, 2007 included a capital contribution from NU parent in the amount of $265 million as well as the payment of $59.4 million in dividends to NU, compared to $60 million and $47.8 million, respectively, during the first nine months of 2006.

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, condensed consolidated financial statements and footnotes in this Form 10-Q, the First and Second Quarter 2007 Form 10-Q and the NU 2006 Form 10-K.

RESULTS OF OPERATIONS

The following table provides the variances in income statement line items for the condensed consolidated statements of income for PSNH included in this report on Form 10-Q for the third quarter and the nine months ended September 30, 2007:


	Income Statement Variances (Millions of Dollars) 2007 over/(under) 2006
	Third Quarter		Percent		Nine Months		Percent
Operating Revenues	$	18	7	%	$	(64)	(7)	%

Operating Expenses:
Fuel, purchased and net interchange power		(7)	(5)			(28)	(6)
Other operation		6	15			20	15
Maintenance		(1)	(7)			3	6
Depreciation		1	9			3	9
Amortization of regulatory assets/(liabilities), net		13	(a)			(65)	(a)
Amortization of rate reduction bonds		1	6			2	6
Taxes other than income taxes		1	8			2	6
Total operating expenses		14	6			(63)	(8)

Operating Income		4	16			(1)	(1)

Interest expense, net		-	-			1	1
Other income		(1)	(84)			(2)	(60)
Income before income tax expense		3	18			(4)	(7)
Income tax expense		(2)	(19)			(14)	(46)
Net Income	$	5	65	%	$	10	37	%

(a) Percent greater than 100.

Comparison of the Third Quarter of 2007 to the Third Quarter of 2006

Operating Revenues

Operating revenues increased $18 million primarily due to higher distribution business revenue ($18 million) and higher transmission business revenue ($1 million).

The distribution business revenue increase of $18 million is partially due to the components of revenues, which are included in regulatory commission approved tracking mechanisms that track the recovery of certain incurred costs ($11 million). The distribution revenue tracking components increase of $11 million is primarily due to higher retail transmission revenues ($6 million), higher REC revenue from the Northern Wood Power Plant ($4 million) and higher wholesale revenues ($2 million), partially offset by the pass through of lower energy supply costs ($1 million). The tracking mechanisms allow for rates to be changed periodically with over collections refunded to customers or under collections collected from customers in future periods.

The distribution component of PSNH’s retail rates which impacts earnings increased $7 million, primarily due to the rate increase effective July 1, 2007.

Transmission business revenues increased $1 million primarily due to a higher transmission investment base and higher operating expenses, which are recovered under FERC-approved transmission tariffs.

Fuel, Purchased and Net Interchange Power

Fuel, purchased and net interchange power costs decreased $7 million primarily due to a decrease in the purchase of higher priced independent power producers’ power as purchase obligations expired and an increase in lower priced coal generation.

Other Operation

Other operation expenses increased $6 million primarily due to higher administrative and general expenses ($3 million) mainly due to higher incentive accruals ($1 million) and higher pension and other benefit costs ($1 million), higher transmission expenses ($2 million) and higher fossil steam expenses ($1 million).

Maintenance

Maintenance expenses decreased $1 million primarily due to lower boiler maintenance costs as a result of the planned overhaul of a generating plant in 2006 ($3 million), partially offset by higher overhead line maintenance expenses ($2 million).

Depreciation

Depreciation expense increased $1 million primarily due to higher utility plant balances.

Amortization of Regulatory Assets

Amortization of regulatory assets increased $13 million primarily due to an increase in the stranded cost recovery charge rate effective July 1, 2007, which has increased the recovery of deferred stranded cost under-recoveries ($10 million) and the deferral of retail transmission costs ($4 million) under the Transmission Cost Adjustment Mechanism (TCAM). These increases were partially offset by net reductions in energy service (ES) over recovery expense in the third quarter of 2007 as compared to the third quarter of 2006 ($2 million). ES over recovery expense decreased primarily as a result of a decrease in the ES rate effective July 1, 2007.

Amortization of Rate Reduction Bonds

Amortization of rate reduction bonds increased $1 million. The higher portion of principal within the rate reduction bonds’ payment results in a corresponding increase in the amortization of regulatory assets.

Taxes Other Than Income Taxes

Taxes other than income taxes increased $1 million primarily due to higher payroll-related taxes and higher property taxes.

Other Income

Other income decreased $1 million primarily due to lower AFUDC income, as a result of decreased eligible construction work in progress (CWIP), higher short-term debt and a lower portion of CWIP being subject to the equity rate.

Income Tax Expense

Income tax expense decreased $2 million due to a decrease in the effective tax rate, partially offset by higher pre-tax earnings. The decrease in the effective tax rate (from 56 to 38 percent) was due to an increase in tax credits and lower flow-through regulatory amortizations. The increase in tax credits was the result of a full year of production tax credits at the Northern Wood Power Project. In 2006, flow-through regulatory amortizations were higher as a result of the regulatory recovery of tax expense associated with nondeductible acquisition costs.

Comparison of the First Nine Months of 2007 to the First Nine Months of 2006

Operating Revenues

Operating revenues decreased $64 million primarily due to lower distribution business revenue ($66 million), partially offset by higher transmission business revenue ($2 million).

The distribution business revenue decrease of $66 million is primarily due to the components of revenues, which are included in regulatory commission approved tracking mechanisms that track the recovery of certain incurred costs ($83 million). The distribution revenue tracking components decrease of $83 million is primarily due to a decrease in the SCRC revenue ($73 million) mainly as a result of rate decreases on July 1, 2006 and January 1, 2007, offset in part by a rate increase on July 1, 2007, lower wholesale revenues ($14 million) and the pass through of lower energy supply costs ($18 million), partially offset by higher retail transmission revenues ($10 million), higher REC revenue from the Northern Wood Power Plant ($5 million) and higher SBC revenue ($4 million). The tracking mechanisms allow for rates to be changed periodically with over collections refunded to customers or under collections collected from customers in future periods.

The distribution component of PSNH’s retail rates which impacts earnings increased $17 million, as a result of the rate increases effective July 1, 2006 and July 1, 2007, and higher sales. Retail sales increased 1.0 percent in 2007 compared to the same period of 2006.

Transmission business revenues increased $2 million primarily due to a higher transmission investment base and higher operating expenses, which are recovered under FERC-approved transmission tariffs.

Fuel, Purchased and Net Interchange Power

Fuel, purchased and net interchange power costs decreased $28 million primarily due to a decrease in the purchase of higher priced independent power producers’ power as purchase obligations expired and an increase in lower priced coal generation.

Other Operation

Other operation expenses increased $20 million primarily due to higher retail transmission expenses ($9 million), higher administrative expenses ($6 million) primarily due to higher employee incentive program costs and higher Electric Assistance Program (EAP) expenses ($3 million).

Maintenance

Maintenance expenses increased $3 million primarily due to higher distribution expenses mainly as a result of higher overhead line maintenance ($2 million) and higher tree trimming expenses ($1 million).

Depreciation

Depreciation expense increased $3 million primarily due to higher utility plant balances.

Amortization of Regulatory Assets

Amortization of regulatory assets decreased $65 million primarily due to lower ES over recoveries in the first nine months of 2007 as compared to the first nine months of 2006 ($36 million), lower stranded cost amortization levels in the first nine months of 2007, as compared to the first nine months of 2006, primarily as a result of PSNH’s full recovery of non-securitized stranded costs in June 2006 ($23 million) and the deferral of retail transmission costs through the TCAM, which was implemented in 2007 ($6 million).

Amortization of Rate Reduction Bonds

Taxes Other Than Income Taxes

Taxes other than income taxes increased $2 million primarily due to higher property taxes ($1 million) and higher payroll-related taxes ($1 million).

Interest Expense, Net

Interest expense, net increased $1 million primarily due to higher short-term debt interest ($2 million) and higher long-term debt interest ($1 million), partially offset by lower rate reduction bond interest resulting from lower principal balances outstanding ($2 million).

Other Income

Other income decreased $2 million primarily due to lower AFUDC income, as a result of decreased eligible CWIP, higher short-term debt and a lower portion of CWIP being subject to the equity rate.

Income Tax Expense

Income tax expense decreased $14 million due to lower pre-tax earnings and a decrease in the effective tax rate (from 53 to 31 percent). The decrease in the effective tax rate was due to an increase in tax credits and lower flow-through regulatory amortizations. The increase in tax credits was the result of a full year of production tax credits at the Northern Wood Power Project. In 2006, flow- through regulatory amortizations were higher as a result of the regulatory recovery of tax expense associated with nondeductible acquisition costs.

LIQUIDITY

Net cash flows from operations decreased by $51.4 million from $160.8 million for the first nine months of 2006 to $109.4 million for the first nine months of 2007. The decrease in operating cash flows is primarily due to a significant reduction in approved SCRC rates effective on January 1, 2007 as a result of the completion of PSNH's recovery of its Part 3 non-securitized stranded costs in the second quarter of 2006.

Capital expenditures described herein are cash capital expenditures and exclude cost of removal, AFUDC related to equity funds and the capitalized portion of pension expense. PSNH's capital expenditures totaled $113.1 million in the first nine months of 2007 compared to $81.9 million in the first nine months of 2006.

On September 24, 2007, PSNH closed on the sale of $70 million of first mortgage bonds due in 2017 with a coupon rate of 6.15 percent.

Financing activities for the nine months ended September 30, 2007 included a capital contribution from NU parent in the amount of $43.8 million as well as the payment of $23 million in dividends to NU, compared to $5.5 million and $35.5 million, respectively, during the first nine months of 2006.

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, condensed consolidated financial statements and footnotes in this Form 10-Q, the First and Second Quarter 2007 Form 10-Q and the NU 2006 Form 10-K.

RESULTS OF OPERATIONS

The following table provides the variances in income statement line items for the condensed consolidated statements of income for WMECO included in this report on Form 10-Q for the third quarter and the nine months ended September 30, 2007:


	Income Statement Variances (Millions of Dollars) 2007 over/(under) 2006
	Third Quarter		Percent		Nine Months		Percent
Operating Revenues	$	9	8	%	$	22	7	%

Operating Expenses:
Fuel, purchased and net interchange power		(10)	(15)			(32)	(15)
Other operation		9	56			25	53
Maintenance		1	12			3	21
Depreciation		1	24			3	23
Amortization of regulatory assets/(liabilities), net		5	(a)			14	(a)
Amortization of rate reduction bonds		-	-			1	7
Taxes other than income taxes		-	-			-	-
Total operating expenses		6	6			14	5

Operating Income		3	28			8	25

Interest expense, net		-	-			1	4
Other income		-	-			-	-
Income before income tax expense		3	38			7	37
Income tax expense		1	28			2	25
Net Income	$	2	45	%	$	5	47	%

(a) Percent greater than 100.

Comparison of the Third Quarter of 2007 to the Third Quarter of 2006

Operating Revenues

Operating revenues increased $9 million due to higher distribution business revenue ($8 million) and higher transmission business revenue ($1 million).

The distribution business revenue increase of $8 million is primarily due to the components of revenues which are included in regulatory commission approved tracking mechanisms that track the recovery of certain incurred costs ($7 million). The distribution revenue tracking components increased $7 million primarily due to higher retail transmission revenues ($7 million) and higher transition cost recoveries ($4 million), partially offset by the pass through of lower energy supply costs ($4 million). The tracking mechanisms allow for rates to be changed periodically with over collections refunded to customers or under collections collected from customers in future periods.

The distribution component of revenues, which impacts earnings, increased $1 million primarily due to the distribution rate increase effective January 1, 2007.

Transmission business revenues increased $1 million primarily due to a higher transmission investment base and higher operating expenses, which are recovered under FERC-approved transmission tariffs.

Fuel, Purchased and Net Interchange Power

Fuel, purchased and net interchange power expense decreased $10 million primarily due to lower default service supply costs ($7 million) and lower other purchased power costs ($3 million), which are included in a regulatory commission approved tracking mechanism. The default service supply costs are the contractual amounts the company must pay to various suppliers that have earned the right to supply default service load through a competitive solicitation process. The decrease in these costs is primarily the result of decreased load levels resulting from customers migrating from default service to a third party energy supplier during the third quarter of 2007 as compared to the third quarter of 2006. Lower other purchased power costs of $3 million are the result of lower capacity costs for the Yankee companies' contractual obligations.

Other Operation

Other operation expenses increased $9 million primarily due to an increase in retail transmission expenses ($7 million) and higher administrative expenses ($1 million). The increase in retail transmission expenses is mainly due to the deferral, resulting from the regulatory tracking mechanism as a result of the increase in retail transmission revenue rates and lower RMR expenses.

Maintenance

Maintenance expense increased $1 million primarily due to higher tree trimming and maintenance of station equipment and structures.

Depreciation

Depreciation expense increased $1 million primarily due to revised depreciation rates effective January 1, 2007 per the distribution rate settlement and higher utility plant balances.

Amortization of Regulatory Assets/(Liabilities), Net

Amortization of regulatory assets/(liabilities), net increased $5 million primarily due to the deferral of transition costs, as a result of a higher transition charge rate and lower power contract net costs.

Income Tax Expense

Income tax expense increased $1 million due to higher pre-tax earnings, partially offset by a decrease in the effective tax rate (from 44 to 41 percent). The higher effective tax rate in 2006 was primarily caused by a non-deductible state tax loss.

Comparison of the First Nine Months of 2007 to the First Nine Months of 2006

Operating Revenues

Operating revenues increased $22 million due to higher distribution business revenue ($20 million) and higher transmission business revenue ($2 million).

The distribution business revenue increase of $20 million is primarily due to the components of revenues which are included in regulatory commission approved tracking mechanisms that track the recovery of certain incurred costs ($17 million). The distribution revenue tracking components increased $17 million primarily due to higher retail transmission revenues ($18 million), higher transition cost recoveries ($11 million), higher pension tracker and default service true-up revenues ($8 million), and higher wholesale revenues ($1 million), partially offset by the pass through of lower energy supply costs ($24 million). The tracking mechanisms allow for rates to be changed periodically with over collections refunded to customers or under collections collected from customers in future periods.

The distribution component of revenues which impacts earnings increased $3 million primarily due to the distribution rate increase effective January 1, 2007 and higher retail sales. Retail sales increased 0.3 percent compared to the same period of 2006.

Transmission business revenues increased $2 million primarily due to a higher transmission investment base and higher operating expenses, which are recovered under FERC-approved transmission tariffs.

Fuel, Purchased and Net Interchange Power

Fuel, purchased and net interchange power expense decreased $32 million primarily due to lower default service supply costs ($24 million) and lower other purchased power costs ($8 million), which are included in a regulatory commission approved tracking mechanism. The default service supply costs are the contractual amounts the company must pay to various suppliers that have earned the right to supply default service load through a competitive solicitation process. The decrease in these costs is primarily the result of decreased load levels resulting from customers migrating from default service to a third party energy supplier during the first nine months of 2007 as compared to the first nine months of 2006. Lower other purchased power costs of $8 million are the result of lower capacity costs for the Yankee companies' contractual obligations.

Other Operation

Other operation expenses increased $25 million primarily due to an increase in retail transmission expenses ($19 million), higher administrative expenses ($3 million) and higher uncollectible account expenses ($2 million). The increase in retail transmission expenses is mainly due to the deferral, resulting from the regulatory tracking mechanism as a result of the increase in retail transmission revenue rates and lower RMR expenses.

Maintenance

Maintenance expense increased $3 million primarily due to higher tree trimming and maintenance of station equipment, structures, and overhead lines.

Depreciation

Depreciation expense increased $3 million primarily due to revised depreciation rates effective January 1, 2007 per the distribution rate settlement and higher utility plant balances.

Amortization of Regulatory Assets/(Liabilities), Net

Amortization of regulatory assets/(liabilities), net increased $14 million primarily due to the deferral of transition costs, as a result of a higher transition charge rate and lower power contract net costs.

Amortization of Rate Reduction Bonds

Interest Expense, Net

Interest expense, net increased $1 million primarily due to higher interest on short-term debt, partially offset by lower rate reduction bond interest resulting from lower principal balances outstanding.

Income Tax Expense

Income tax expense increased $2 million due to higher pre-tax earnings, partially offset by a decrease in the effective tax rate (from 44 to 40 percent). The higher effective tax rate in 2006 was primarily caused by a non-deductible state tax loss.

LIQUIDITY

Net cash flows from operations increased by $2.1 million from $3.4 million for the first nine months of 2006 compared to $5.5 million for the first nine months of 2007. WMECO’s operating cash flows increased in the first nine months of 2007 primarily as a result of an increase in recoveries from ratepayers due to retail rate adjustments that were effective in January of 2007. This increase is offset by the payment of $47.9 million in federal and state income taxes in 2007. WMECO accrued the majority of this tax obligation in 2000 upon the sale of the generation assets to NGC, but due to the intercompany nature of the sales, the federal and state income tax payment was deferred at that time. It was not until these assets were sold to an unaffiliated third party in November of 2006 that WMECO was required to pay this deferred tax obligation.

Capital expenditures described herein are cash capital expenditures and exclude cost of removal, AFUDC related to equity funds and the capitalized portion of pension expense or income. WMECO's capital expenditures totaled $32.8 million in the first nine months of 2007 compared with $32.3 million in the first nine months of 2006. These capital expenditures will significantly increase with the Springfield 115 KV Cables project, which is expected to cost approximately $350 million.

On August 17, 2007, WMECO closed on the sale of $40 million of 30-year senior unsecured notes due in 2037 with a coupon rate of 6.7 percent.

Financing activities for the nine months ended September 30, 2007 included a capital contribution from NU parent in the amount of $4.8 million as well as the payment of $9.6 million in dividends to NU, compared to $28 million and $6 million, respectively, during the first nine months of 2006.

ITEM 3.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Market Risk Information

NU Enterprises utilizes the sensitivity analysis methodology to disclose quantitative information for its commodity price risks (including where applicable capacity and ancillary components). Sensitivity analysis provides a presentation of the potential loss of future earnings, fair values or cash flows from market risk-sensitive instruments over a selected time period due to one or more hypothetical changes in commodity price components, or other similar price changes. Under sensitivity analysis, the fair value of the portfolio 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 management's 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. As the NU Enterprises' businesses are exited, the risks associated with commodity prices are being reduced.

Wholesale Portfolio: When conducting sensitivity analyses of the change in the fair value of the wholesale portfolio, which includes a non-derivative power purchase contract, 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.

A hypothetical change in the fair value of the wholesale portfolio was determined assuming a 10 percent change in forward market prices. At September 30, 2007, Select Energy has calculated the market price resulting from a 10 percent change in forward market prices of those contracts. A 10 percent increase in prices for all products would have resulted in a pre-tax decrease in fair value of $0.7 million and a 10 percent decrease in prices for all products would have resulted in a pre-tax decrease in fair value of $0.2 million. A 10 percent increase in energy prices would have resulted in a $8.8 million pre-tax decrease, and a 10 percent decrease in energy prices would have resulted in a $8 million pre-tax increase. A 10 percent increase/(decrease) in capacity prices would have resulted in a $2.3 million pre-tax increase/(decrease). A 10 percent increase/(decrease) in ancillary prices would have resulted in a $5.8 million pre-tax increase/(decrease).

The impact of a change in electricity prices on wholesale transactions at September 30, 2007 are not necessarily representative of the results that will be realized, if such a change were to occur. Also, energy, capacity and ancillaries have different market volatilities. These transactions are accounted for at fair value, and changes in market prices impact earnings.

Other Risk Management Activities

Interest Rate Risk Management: NU manages its interest rate risk exposure in accordance with its written policies and procedures by maintaining a mix of fixed and variable rate long-term debt. At September 30, 2007, approximately 89 percent (82 percent including the long-term debt subject to the fixed-to-floating interest rate swap as variable long-term debt) of NU's long-term debt, including fees and interest due for spent nuclear fuel disposal costs, is 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 NU's variable interest rates, including the rate on long-term debt subject to the fixed-to-floating interest rate swap, annual interest expense would have increased by $3.7 million. At September 30, 2007, NU parent maintained a fixed-to-floating interest rate swap to manage the interest rate risk associated with its $263 million of fixed-rate long-term debt.

Credit Risk Management: Credit risk relates to the risk of loss that NU would incur as a result of non-performance by counterparties pursuant to the terms of its contractual obligations. NU serves 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 NU realizes 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 which, in turn, require NU to manage the portfolio of market risk inherent in those transactions in a manner consistent with the parameters established by NU's 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 individuals from outside of the management of these activities that create these risk exposures and functions to ensure compliance with NU's stated risk management policies.

NU tracks and re-balances the risk in its 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.

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. 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.

At September 30, 2007 and December 31, 2006, Select Energy maintained collateral balances from counterparties of $0.4 million and $0.1 million, respectively. These amounts are included in counterparty deposits on the accompanying condensed consolidated balance sheets. Select Energy also has collateral balances deposited with counterparties of $27.9 million and $48.5 million at September 30, 2007 and December 31, 2006, respectively, which are included in current liabilities - other on the accompanying condensed consolidated balance sheets.

The regulated companies have a lower level of credit risk related to providing regulated electric and gas distribution service than NU Enterprises. However, the regulated companies are subject to credit risk from certain long-term or high-volume supply contracts with energy marketing companies. The 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.

NU has 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 NU’s Risk and Capital Committee, comprised of senior NU 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 the company's financial condition or results of operations. The findings of this process are periodically discussed with NU's Finance Committee of the Board of Trustees.

Additional quantitative and qualitative disclosures about market risk are set forth in Part II, Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations," included in this combined report on Form 10-Q.

ITEM 4.

CONTROLS AND PROCEDURES

NU evaluated the design and operation of its disclosure controls and procedures at September 30, 2007 to determine whether they are effective in ensuring that the disclosure of required information is made timely and in accordance with the Exchange Act and the rules and forms of the SEC. This evaluation was made under the supervision and with the participation of management, including NU’s principal executive officer and principal financial officer, as of the end of the period covered by this report on Form 10-Q. The principal executive officer and principal financial officer have concluded, based on their review, that NU’s disclosure controls and procedures are effective to ensure that information required to be disclosed by NU in reports that it files under the Exchange Act i) is recorded, processed, summarized, and reported within the time periods specified in SEC rules and forms and ii) is accumulated and communicated to management including the principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding required disclosure.

There have been no changes in internal controls over financial reporting for NU during the quarter ended September 30, 2007 that have materially affected, or are reasonably likely to materially affect internal controls over financial reporting.

PART II. OTHER INFORMATION

ITEM 1.

LEGAL PROCEEDINGS

The company is a party to various legal proceedings. We have identified these legal proceedings in Part I, Item 3, "Legal Proceedings" in our Annual Report on Form 10-K for the year ended December 31, 2006, as updated in our quarterly reports on Form 10-Q for the quarters ended March 31, 2007 and June 30, 2007. There have been no material changes with regard to the legal proceedings previously disclosed in our reports.

ITEM 1A.

RISK FACTORS

The company is subject to a variety of significant risks in addition to the matters set forth under "Forward Looking Statements," in Item 2, "Management's Discussion and Analysis of Financial Condition and Results of Operations - Other Matters." We have identified a number of these risk factors in our Annual Report on Form 10-K for the year ended December 31, 2006 as updated in our quarterly reports on Form 10-Q for the quarters ended March 31, 2007 and June 30, 2007. Our susceptibility to certain risks, including those discussed in detail in our reports, could exacerbate other risks. These risk factors should be considered carefully in evaluating our risk profile. Other than the twelfth risk factor set forth in our Annual Report on Form 10-K, which is updated below, there have been no material changes with regard to the risk factors previously disclosed.

Costs of Compliance with Environmental Regulations May Increase and Have an Adverse Effect on our Business and Results of Operations

Our subsidiaries' operations are subject to extensive federal, state and local environmental statutes, rules and regulations which regulate, among other things, air emissions, water discharges and the management of hazardous and solid waste. In particular, more stringent regulations of carbon dioxide and mercury emissions have been proposed in various New England states. Compliance with these requirements requires us to incur significant costs relating to environmental monitoring, installation of pollution control equipment, emission fees, maintenance and upgrading of facilities, remediation and permitting. The costs of compliance with these legal requirements may increase in the future. An increase in such costs, unless promptly recovered, could have an adverse impact on our business and results of operations, financial position and cash flows.

In addition, global climate change issues have received an increased focus on the federal and state government levels which could potentially lead to additional rules and regulations that impact how we operate our business, both in terms of the power plants we own and operate as well as general utility operations. Although we would expect that any costs of these rules and regulations would be recovered from ratepayers, the impact would be dependent upon the specific rules and regulations adopted and cannot be determined at this time.

Any failure by us to comply with environmental laws and regulations, even if due to factors beyond our control, or reinterpretations of existing requirements, could also increase costs. Existing environmental laws and regulations may be revised or new laws and regulations seeking to protect the environment may be adopted or become applicable to us. Revised or additional laws could result in significant additional expense and operating restrictions on our facilities or increased compliance costs which may not be fully recoverable in distribution company rates for generation. The cost impact of any such legislation would be dependent upon the specific requirements adopted and cannot be determined at this time. For further information, see Item 1, "Business - Other Regulatory and Environmental Matters - Environmental Regulation" in NU's 2006 Form 10-K.

ITEM 2.

UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

There were no purchases made by or on behalf of NU or any "affiliated purchaser" (as defined in Rule 10b-18(a)(3) under the Securities Exchange Act of 1934), of common stock during the quarter ended September 30, 2007.

ITEM 6.

EXHIBITS

Document designated with a (*) are filed herewith. The balance of the exhibits has heretofore been filed with the SEC as the exhibits and in the file numbers indicated and are incorporated herein by reference.

(a)

Listing of Exhibits (NU)

Exhibit No.

Description

*15

Deloitte & Touche LLP Letter Regarding Unaudited Financial Information

*31

Certification of Charles W. Shivery, Chairman, President and Chief Executive Officer of Northeast Utilities, required by Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated November 8, 2007

*31.1

Certification of David R. McHale, Senior Vice President and Chief Financial Officer of Northeast Utilities, required by Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated November 8, 2007

*32

Certification of Charles W. Shivery, Chairman, President and Chief Executive Officer of Northeast Utilities and David R. McHale, Senior Vice President and Chief Financial Officer of Northeast Utilities, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, dated November 8, 2007

Listing of Exhibits (CL&P)

Supplemental Indenture (2007 Series C Bonds and 2007 Series D Bonds) between CL&P and Deutsche Bank Trust Company Americas, as Trustee dated as of September 1, 2007 (incorporated by reference to Exhibit 4 to CL&P Form 8-K filed September 17, 2007, File No. 0-00404)

*31

Certification of Leon J. Olivier, Chief Executive Officer of The Connecticut Light and Power Company, required by Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated November 8, 2007

*31.1

Certification of David R. McHale, Senior Vice President and Chief Financial Officer of The Connecticut Light and Power Company, required by Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated November 8, 2007

*32

Certification of Leon J. Olivier, Chief Executive Officer of The Connecticut Light and Power Company and David R. McHale, Senior 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, November 8, 2007

Listing of Exhibits (PSNH)

Fifteenth Supplemental Indenture (2007 Series N Bonds) between PSNH and U.S. Bank, National Association, as Trustee, dated as of September 1, 2007 (incorporated by reference to Exhibit 4.1 to PSNH Form 8-K filed September 24, 2007, File No. 001-06392)

*31

Certification of Leon J. Olivier, Chief Executive Officer of Public Service Company of New Hampshire, required by Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated November 8, 2007

*31.1

Certification of David R. McHale, Senior Vice President and Chief Financial Officer of Public Service Company of New Hampshire, required by Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated November 8, 2007

*32

Certification of Leon J. Olivier, Chief Executive Officer of Public Service Company of New Hampshire and David R. McHale, Senior Vice President and Chief Financial Officer of Public Service Company of New Hampshire, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, dated November 8, 2007

Listing of Exhibits (WMECO)

Supplemental Indenture (2007 Series D Senior Notes) between WMECO and The Bank of New York, as Trustee dated as of August 1, 2007 (incorporated by reference to Exhibit 4.1 to WMECO Form 8-K filed August 20, 2007, File No 000-07624)

*31

Certification of Leon J. Olivier, Chief Executive Officer of Western Massachusetts Electric Company, required by Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated November 8, 2007

*31.1

Certification of David R. McHale, Senior Vice President and Chief Financial Officer of Western Massachusetts Electric Company, required by Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated November 8, 2007

*32

Certification of Leon J. Olivier, Chief Executive Officer of Western Massachusetts Electric Company and David R. McHale, Senior Vice President and Chief Financial Officer of Western Massachusetts Electric Company, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, dated November 8, 2007

SIGNATURE

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


		NORTHEAST UTILITIES
		Registrant
Date: November 8, 2007	By	/s/ David R. McHale
		David R. McHale
		Senior Vice President and Chief Financial Officer
		(for the Registrant and as Principal Financial Officer)

____________________________________________________________________________________

SIGNATURE

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


		THE CONNECTICUT LIGHT AND POWER COMPANY
		Registrant
Date: November 8, 2007	By	/s/ David R. McHale
		David R. McHale
		Senior 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: November 8, 2007	By	/s/ David R. McHale
		David R. McHale
		Senior Vice President and Chief Financial Officer
		(for the Registrant and as Principal Financial Officer)

____________________________________________________________________________________

SIGNATURE

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


		WESTERN MASSACHUSETTS ELECTRIC COMPANY
		Registrant
Date: November 8, 2007	By	/s/ David R. McHale
		David R. McHale
		Senior Vice President and Chief Financial Officer
		(for the Registrant and as Principal Financial Officer)