10-Q

____________________________________________________________________________________

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, 2005
	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 *

  *SEC staff has granted Northeast Utilities a waiver from this requirement on November 1, 2005 with respect to its S-3 registration statement.

Indicate by check mark whether the registrants are accelerated filers (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 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 share outstanding of each of the issuers’ classes of common stock, as of the latest practicable date:

Company - Class of Stock	Outstanding at October 31, 2005
Northeast Utilities Common stock, $5.00 par value	130,070,036 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

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
NGC	Northeast Generation Company
NGS	Northeast Generation Services Company
NU or the company	Northeast Utilities
NU Enterprises	NU’s competitive subsidiaries including the merchant energy segment, which is comprised of Select Energy, NGC, NGS and the generation operations of HWP and the energy services segment, which is comprised of E.S. Boulos Company, Woods Electrical Co. Inc., and NGS Mechanical, Inc., which are subsidiaries of NGS, SESI, SECI, Reeds Ferry Supply Co. Inc., HEC/Tobyhanna Energy Project, Inc. and HEC/CJTS Energy Center LLC and Woods Network.  For further information, see Note 12, “Segment Information,” to the condensed consolidated financial statements.
PSNH	Public Service Company of New Hampshire
Reeds Ferry	Reeds Ferry Supply Co., Inc.
SECI	Select Energy Contracting, Inc.
Select Energy	Select Energy, Inc. (including its wholly owned subsidiary SENY)
SENY	Select Energy New York, Inc.
SESI	Select Energy Services, Inc.
Utility Group	NU’s regulated utilities comprised of the electric distribution and transmission businesses of CL&P, PSNH, WMECO, the generation business of PSNH and the gas distribution business of Yankee Gas.  For further information, see Note 12 “Segment Information,” to the condensed consolidated financial statements.
WMECO	Western Massachusetts Electric Company
Woods Network	Woods Network Services, Inc.
Yankee	Yankee Energy System, Inc.
Yankee Gas	Yankee Gas Services Company
THIRD PARTIES:
Bechtel	Bechtel Power Corporation
CYAPC	Connecticut Yankee Atomic Power Company
Globix	Globix Corporation
NRG	NRG Energy, Inc.
REGULATORS:
CSC	Connecticut Siting Council
DPUC	Connecticut Department of Public Utility Control
DTE	Massachusetts Department of Telecommunications and Energy
FERC	Federal Energy Regulatory Commission
NHPUC	New Hampshire Public Utilities Commission
SEC	Securities and Exchange Commission

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OTHER:
AFUDC	Allowance For Funds Used During Construction
CTA	Competitive Transition Assessment
EPS	Earnings Per Share
FASB	Financial Accounting Standards Board
FMCC	Federally Mandated Congestion Cost
GSC	Generation Service Charge
ISO-NE	New England Independent System Operator
KWh	Kilowatt-Hour
Kv	Kilovolt
LICAP	Locational Installed Capacity
LMP	Locational Marginal Pricing
LOCs	Letters of Credit
MW	Megawatt/Megawatts
NU 2004 Form 10-K	The Northeast Utilities and Subsidiaries combined 2004 Form 10-K as filed with the SEC
NYMEX	New York Mercantile Exchange
OCC	Connecticut Office of Consumer Counsel
RMR	Reliability Must Run
ROE	Return on Equity
RTO	Regional Transmission Organization
SBC	System Benefits Charge
SCRC	Stranded Cost Recovery Charge
SFAS	Statement of Financial Accounting Standards
TS/DS	Transition Energy Service/Default Energy Service
TSO	Transitional Standard Offer

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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, 2005 and December 31, 2004	2
Condensed Consolidated Statements of (Loss)/Income (Unaudited) - Three Months and Nine Months Ended September 30, 2005 and 2004	4
Condensed Consolidated Statements of Cash Flows (Unaudited) - Nine Months Ended September 30, 2005 and 2004	5
Notes to Condensed Consolidated Financial Statements (unaudited - all companies)	6
Report of Independent Registered Public Accounting Firm	36
The Connecticut Light and Power Company and Subsidiaries
Condensed Consolidated Balance Sheets (Unaudited) - September 30, 2005 and December 31, 2004	38
Condensed Consolidated Statements of Income (Unaudited) - Three Months and Nine Months Ended September 30, 2005 and 2004	40
Condensed Consolidated Statements of Cash Flows (Unaudited) - Nine Months Ended September 30, 2005 and 2004	41
Public Service Company of New Hampshire and Subsidiaries
Condensed Consolidated Balance Sheets (Unaudited) - September 30, 2005 and December 31, 2004	44
Condensed Consolidated Statements of Income (Unaudited) - Three Months and Nine Months Ended September 30, 2005 and 2004	46
Condensed Consolidated Statements of Cash Flows (Unaudited) - Nine Months Ended September 30, 2005 and 2004	47
Western Massachusetts Electric Company and Subsidiary
Condensed Consolidated Balance Sheets (Unaudited) - September 30, 2005 and December 31, 2004	50
Condensed Consolidated Statements of Income (Unaudited) - Three Months and Nine Months Ended September 30, 2005 and 2004	52
Condensed Consolidated Statements of Cash Flows (Unaudited) - Nine Months Ended September 30, 2005 and 2004	53

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	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		87
Public Service Company of New Hampshire and Subsidiaries		91
Western Massachusetts Electric Company and Subsidiary		94
ITEM 3 - Quantitative and Qualitative Disclosures About Market Risk		97
ITEM 4 - Controls and Procedures		99
PART II — OTHER INFORMATION
ITEM 1 - Legal Proceedings		100
ITEM 2 - Unregistered Sales of Equity Securities and Use of Proceeds		100
ITEM 6 - Exhibits		100
SIGNATURES		103

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NORTHEAST UTILITIES AND SUBSIDIARIES

1

NORTHEAST UTILITIES AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
	September 30,	December 31,
	2005	2004
	(Thousands of Dollars)
ASSETS
Current Assets:
Cash and cash equivalents	$                      86,194	$                   46,989
Special deposits	164,332	82,584
Investments in securitizable assets	220,942	139,391
Receivables, less provision for uncollectible
accounts of $27,652 in 2005 and $25,325 in 2004	763,976	771,257
Unbilled revenues	110,655	144,438
Taxes receivable	31,631	61,420
Fuel, materials and supplies	204,789	185,180
Marketable securities	51,467	52,498
Derivative assets - current	877,607	81,567
Prepayments and other	100,884	154,395
Assets held for sale	136,169	-
	2,748,646	1,719,719
Property, Plant and Equipment:
Electric utility	6,202,230	5,918,539
Gas utility	815,052	786,545
Competitive energy	905,134	918,183
Other	252,789	241,190
	8,175,205	7,864,457
Less: Accumulated depreciation	2,496,041	2,382,927
	5,679,164	5,481,530
Construction work in progress	548,716	382,631
	6,227,880	5,864,161
Deferred Debits and Other Assets:
Regulatory assets	2,467,689	2,746,219
Goodwill	290,791	319,986
Prepaid pension	321,267	352,750
Marketable securities	60,983	51,924
Derivative assets - long-term	548,833	198,769
Other	263,303	402,651
	3,952,866	4,072,299
Total Assets	$                12,929,392	$            11,656,179
The accompanying notes are an integral part of these condensed consolidated financial statements.

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NORTHEAST UTILITIES AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
	September 30,	December 31,
	2005	2004
	(Thousands of Dollars)
LIABILITIES AND CAPITALIZATION
Current Liabilities:
Notes payable to banks	$                    308,000	$                   180,000
Long-term debt - current portion	40,387	90,759
Accounts payable	887,689	825,247
Accrued interest	61,694	49,449
Derivative liabilities - current	853,053	130,275
Counterparty deposits	209,477	57,650
Other	213,083	230,022
Liabilities of assets held for sale	118,374	-
	2,691,757	1,563,402
Rate Reduction Bonds	1,399,143	1,546,490
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	1,358,869	1,434,403
Accumulated deferred investment tax credits	96,364	99,124
Deferred contractual obligations	345,769	413,056
Regulatory liabilities	1,223,268	1,070,187
Derivative liabilities - long-term	403,442	58,737
Other	264,697	267,895
	3,692,409	3,343,402
Capitalization:
Long-Term Debt	2,998,359	2,789,974
Preferred Stock of Subsidiary - Non-Redeemable	116,200	116,200
Common Shareholders’ Equity:
Common shares, $5 par value - authorized
225,000,000 shares; 151,851,387 shares issued
and 130,036,277 shares outstanding in 2005 and
151,230,981 shares issued and 129,034,442 shares
outstanding in 2004	759,257	756,155
Capital surplus, paid in	1,123,988	1,116,106
Deferred contribution plan - employee stock
ownership plan	(50,269)	(60,547)
Retained earnings	540,642	845,343
Accumulated other comprehensive income/(loss)	18,075	(1,220)
Treasury stock, 19,642,592 shares in 2005
and 19,580,065 shares in 2004	(360,169)	(359,126)
Common Shareholders’ Equity	2,031,524	2,296,711
Total Capitalization	5,146,083	5,202,885
Commitments and Contingencies (Note 7)
Total Liabilities and Capitalization	$               12,929,392	$              11,656,179
The accompanying notes are an integral part of these condensed consolidated financial statements.

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NORTHEAST UTILITIES AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF (LOSS)/INCOME (Unaudited)
	Three Months Ended		Nine Months Ended
	September 30,		September 30,
	2005	2004	2005	2004
	(Thousands of Dollars, except share information)
Operating Revenues	$    1,754,862	$    1,624,487	$   5,519,556	$  4,908,837
Operating Expenses:
Operation -
Fuel, purchased and net interchange power	1,135,076	1,107,113	3,697,990	3,196,842
Other	270,469	237,925	785,979	690,195
Wholesale contract market changes, net	101,218	-	359,684	-
Restructuring and impairment charges	4,807	-	28,461	-
Maintenance	56,290	47,804	153,057	137,814
Depreciation	58,963	57,033	174,979	166,787
Amortization	79,902	42,679	127,021	100,057
Amortization of rate reduction bonds	46,123	43,286	133,029	124,579
Taxes other than income taxes	63,385	55,195	195,718	188,031
Total operating expenses	1,816,233	1,591,035	5,655,918	4,604,305
Operating (Loss)/Income	(61,371)	33,452	(136,362)	304,532
Interest Expense:
Interest on long-term debt	42,327	36,995	126,369	107,486
Interest on rate reduction bonds	21,502	24,446	66,775	75,184
Other interest	3,336	19	9,695	1,011
Interest expense, net	67,165	61,460	202,839	183,681
Other Income, Net	8,173	5,977	14,838	7,574
(Loss)/Income from Continuing Operations Before
Income Tax (Benefit)/Expense	(120,363)	(22,031)	(324,363)	128,425
Income Tax (Benefit)/Expense	(29,794)	(14,124)	(110,032)	40,305
(Loss)/Income from Continuing Operations Before
Preferred Dividends of Subsidiary	(90,569)	(7,907)	(214,331)	88,120
Preferred Dividends of Subsidiary	1,390	1,390	4,169	4,169
(Loss)/Income from Continuing Operations	(91,959)	(9,297)	(218,500)	83,951
Discontinued Operations (Note 4):
(Loss)/Income from Discontinued Operations Before Income Taxes	(3,929)	2,285	(34,242)	(551)
Income Tax (Benefit)/Expense	(1,396)	896	(12,827)	(126)
(Loss)/Income from Discontinued Operations	(2,533)	1,389	(21,415)	(425)
Net (Loss)/Income	$        (94,492)	$          (7,908)	$   (239,915)	$       83,526
Basic and Fully Diluted (Loss)/Earnings Per Common Share:
(Loss)/Income from Continuing Operations	$            (0.71)	$            (0.07)	$         (1.68)	$           0.65
(Loss)/Income from Discontinued Operations	(0.02)	0.01	(0.17)	-
Basic and Fully Diluted (Loss)/Earnings Per Common Share	$            (0.73)	$            (0.06)	$         (1.85)	$           0.65
Basic Common Shares Outstanding (average)	129,957,408	128,279,814	129,585,519	128,064,364
Fully Diluted Common Shares Outstanding (average)	129,957,408	128,279,814	129,585,519	128,231,267
The accompanying notes are an integral part of these condensed consolidated financial statements.

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NORTHEAST UTILITIES AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
	Nine Months Ended
	September 30,
	2005	2004
Operating Activities:
Net (loss)/income	$           (239,915)	$             83,526
Adjustments to reconcile to net cash flows
provided by operating activities:
Wholesale contract market changes, net	359,684	-
Restructuring and impairment charges	53,194	-
Bad debt expense	21,758	17,008
Depreciation	175,443	167,366
Deferred income taxes and investment tax credits, net	(122,012)	65,133
Amortization	127,021	100,057
Amortization of rate reduction bonds	133,029	124,579
Amortization/(deferral) of recoverable energy costs	22,158	(30,688)
Pension expense	24,699	7,977
Wholesale contract buyout payments	(145,231)	-
Mark-to-market on natural gas contracts	40,662	45,916
Regulatory refunds	(91,796)	(23,350)
Derivative assets	47,689	(20,439)
Derivative liabilities	(83,885)	57,913
Deferred contractual obligations	(67,065)	(45,982)
Other sources of cash	60,989	76,548
Other uses of cash	(12,822)	(21,108)
Changes in current assets and liabilities:
Receivables and unbilled revenues, net	(1,137)	57,974
Fuel, materials and supplies	(33,979)	(48,684)
Investments in securitizable assets	(81,551)	(46,056)
Taxes receivable	32,332	(48,487)
Other current assets	(69,082)	(64,724)
Accounts payable	50,800	(37,533)
Counterparty deposits	151,827	20,860
Other current liabilities	(54)	(9,228)
Net cash flows provided by operating activities	352,756	428,578
Investing Activities:
Investments in property and plant:
Electric, gas and other utility plant	(508,116)	(436,156)
Competitive energy assets	(13,421)	(13,915)
Cash flows used for investments in property and plant	(521,537)	(450,071)
Net proceeds from sale of property	24,649	-
Proceeds from sales of investment securities	96,471	31,651
Purchases of investment securities	(108,944)	(95,283)
Restricted cash - LMP costs	-	93,630
Other investing activities	7,222	(32,843)
Net cash flows used in investing activities	(502,139)	(452,916)
Financing Activities:
Issuance of common shares	8,161	4,470
Issuance of long-term debt	300,000	463,113
Retirement of rate reduction bonds	(147,347)	(138,016)
Increase/(decrease) in short-term debt	128,000	(103,957)
Reacquisitions and retirements of long-term debt	(52,061)	(86,628)
Cash dividends on common shares	(64,785)	(59,221)
Other financing activities	16,620	(943)
Net cash flows provided by financing activities	188,588	78,818
Net increase in cash and cash equivalents	39,205	54,480
Cash and cash equivalents - beginning of period	46,989	43,372
Cash and cash equivalents - end of period	$              86,194	$            97,852
The accompanying notes are an integral part of these condensed consolidated financial statements. 5

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)

1.

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (All Companies)

A.

Presentation

The accompanying unaudited condensed consolidated financial statements should be read in conjunction with this complete report 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 as part of the Northeast Utilities and subsidiaries combined 2004 Form 10-K as filed with the SEC (NU 2004 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, 2005, and the results of operations for the three months and nine months ended September 30, 2005 and 2004 and cash flows for the nine months ended September 30, 2005 and 2004. The results of operations for the three and nine months ended September 30, 2005 and 2004 and statements of cash flows for the nine months ended September 30, 2005 and 2004, are not necessarily indicative of the results expected for a full year.  

The condensed consolidated financial statements of NU and of 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.  These reclassifications related to 1) the presentation of certain companies as discontinued operations, and 2) other operation expense and maintenance expense on the accompanying condensed consolidated statements of (loss)/income to conform with the December 31, 2004 presentation, which totaled $5.1 million and $13 million for the three and nine months ended September 30, 2004, respectively.  For further information regarding those companies classified as discontinued operations, see Note 4, “Assets Held for Sale and Discontinued Operations,” to the condensed consolidated financial statements.

In the company’s condensed consolidated statement of cash flows for the nine months ended September 30, 2004, the company changed the classification of the change in restricted cash – locational marginal pricing (LMP) costs balances to present that change as an investing activity.  The company previously presented that change as an operating activity which resulted in a $93.6 million decrease in net cash flows used in investing activities and a corresponding decrease in operating cash flows from the amounts previously reported.  

The NU, CL&P, PSNH and WMECO condensed consolidated statements of cash flows for the nine months ended September 30, 2004 have also been reclassified to exclude from cash flows from operations the change in accounts payable related to capital projects. These amounts totaled sources/(uses) of cash of $13.6 million, $19.2 million, $(2.2) million, and $(0.2) million for the nine months ended September 30, 2004 for NU, CL&P, PSNH, and WMECO, respectively.

B.

New Accounting Standards

Share-Based Payments:  On December 16, 2004, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (SFAS) No. 123 (Revised 2004), “Share-Based Payments,” (SFAS No. 123R), which amended SFAS No. 123, “Accounting for Stock-Based Compensation.”  Under the provisions of SFAS No. 123R, NU will recognize compensation expense for the unvested portion of previously granted awards outstanding on January 1, 2006, the effective date of SFAS No. 123R, and any new awards after that date.  NU is currently determining the amount of compensation expense to be recognized, but management believes that the adoption of SFAS No. 123R will not have a material impact on NU’s consolidated financial statements.  For information

6

regarding current accounting for equity-based compensation, see Note 1F, “Summary of Significant Accounting Policies - Equity-Based Compensation,” to the condensed consolidated financial statements.

Asset Retirement Obligations: On January 1, 2003, NU implemented SFAS No. 143, “Accounting for Asset Retirement Obligations,” requiring legal obligations associated with the retirement of property, plant and equipment to be recognized as a liability at fair value when incurred and when a reasonable estimate of the fair value of the liability can be made. Upon adoption of SFAS No. 143, management identified certain conditional asset retirement obligations relating to transmission and distribution lines and poles, telecommunication towers, transmission cables, certain assets containing asbestos, and certain Federal Energy Regulatory Commission (FERC) or state regulatory agency re-licensing matters, and determined that no material asset retirement obligations had been incurred. In March 2005, the FASB issued Interpretation No. 47 (FIN 47), “Accounting for Conditional Asset Retirement Obligations - an interpretation of FASB Statement No. 143.” FIN 47 requires an entity to recognize a liability for the fair value of an asset retirement obligation even if it is conditional on a future event if the liability’s fair value can be reasonably estimated. FIN 47 is required to be implemented by December 31, 2005 by recording a liability for the fair value of conditional asset retirements with the impact of implementation recognized as a cumulative effect in the income statement. Management is currently evaluating NU’s conditional asset retirement obligations. Management has completed its initial identification of potential conditional retirement obligations (AROs) and has identified six potential categories of AROs. A fair value calculation, reflecting various probabilities and settlement scenarios, and a data consistency review across all operating companies, is currently being performed and will be completed in the fourth quarter of 2005. For those AROs recorded at the regulated companies, management believes the costs will be recovered from its customers; therefore, a regulatory asset would be recorded. Until this work is completed, management will not be able to determine whether implementation of FIN 47 will have a material effect on NU’s condensed consolidated financial statements.  

C.

Guarantees

NU provides credit assurances on behalf of subsidiaries in the form of guarantees and letters of credit (LOCs) in the normal course of business, primarily for the financial performance obligations of NU Enterprises, Inc. (NU Enterprises). NU would be required to perform under these guarantees in the event of non-performance by NU Enterprises, primarily Select Energy, Inc. (Select Energy). At September 30, 2005, the maximum level of exposure in accordance with FIN 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others,” under guarantees by NU, primarily on behalf of NU Enterprises, totaled $894 million. A majority of these guarantees do not have established expiration dates, and some guarantees have unlimited exposure to commodity price movements. Additionally, NU had $70.9 million of LOCs issued, all of which were issued for the benefit of NU Enterprises at September 30, 2005. NU has no guarantees of the performance of third parties.  

At September 30, 2005, NU had outstanding guarantees on behalf of the Utility Group and Rocky River Realty (RRR) of $12.8 million and $10.9 million, respectively.  These amounts are included in the total outstanding NU guarantee exposure amount of $894 million.  The guarantee amount of $870.3 million for NU Enterprises includes $609.3 million for Select Energy and $261 million for the energy services businesses.  The $261 million in guarantees related to the energy services businesses is comprised of $95.8 million for Select Energy Services, Inc.’s (SESI) obligations under certain financing arrangements and $165.2 million for performance obligations of the energy services businesses.

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.

NU currently has authorization from the Securities and Exchange Commission (SEC) to provide up to $750 million of guarantees for its non-utility subsidiaries through June 30, 2007.  The $12.8 million in outstanding guarantees to the Utility Group are subject to a separate $50 million SEC limitation apart from the current $750 million NU Enterprises guarantee limit.  The amount of guarantees outstanding for compliance with the SEC limit for NU Enterprises at September 30, 2005 is $511.3 million.  The amount of guarantees outstanding for compliance with the SEC limit for the Utility Group at September 30, 2005 is $0.3 million.  These amounts are calculated using different, more probabilistic and fair-value based criteria than the maximum level of exposure required to be disclosed under FIN 45.  FIN 45 includes all exposures even though they are not reasonably likely to result in exposure to NU.

On October 19, 2004, the SEC authorized NU to issue guarantees of up to an aggregate $100 million through June 30, 2007 of the debt or other obligations of two of its subsidiaries, NUSCO and RRR.  These companies provide certain specialized support and real estate services and occasionally enter into transactions that require financial backing from NU.  The amount of guarantees outstanding for compliance with the SEC limit under this category at September 30, 2005 is $0.2 million.

D.

Regulatory Accounting

The accounting policies of the Utility Group 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.”

7

The transmission and distribution businesses of CL&P, PSNH and WMECO, along with PSNH’s generation business and Yankee Gas Services Company’s (Yankee Gas) distribution business, continue to be cost-of-service rate regulated, and management believes that the application of SFAS No. 71 to those businesses continues to be appropriate.  Management also believes that it is probable that the Utility Group will recover its investments in long-lived assets, including regulatory assets.  In addition, all material net regulatory assets are earning an equity return, except for securitized regulatory assets, which are not supported by equity.

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

	At September 30, 2005
(Millions of Dollars)	NU Consolidated	CL&P	PSNH	WMECO	Yankee Gas
Recoverable nuclear costs	$    46.1	$          -	$  27.0	$   19.1	$     -
Securitized assets	1,389.1	889.1	386.8	113.2	-
Income taxes, net	315.5	214.7	34.4	50.9	15.5
Unrecovered contractual obligations	308.9	185.6	58.8	64.5	-
Recoverable energy costs	214.2	28.4	177.4	1.4	7.0
Other regulatory assets/(overrecoveries)	193.9	41.1	137.8	(34.1)	49.1
Totals	$2,467.7	$1,358.9	$822.2	$215.0	$71.6

	At December 31, 2004
(Millions of Dollars)	NU Consolidated	CL&P	PSNH	WMECO	Yankee Gas
Recoverable nuclear costs	$      52.0	$           -	$  29.7	$  22.3	$     -
Securitized assets	1,537.4	994.3	421.6	121.5	-
Income taxes, net	316.3	207.5	37.5	56.7	14.6
Unrecovered contractual obligations	354.7	213.4	64.4	77.0	(0.1)
Recoverable energy costs	255.0	43.4	194.9	3.1	13.6
Other regulatory assets/(overrecoveries)	230.8	67.8	152.0	(48.7)	59.7
Totals	$2,746.2	$1,526.4	$900.1	$231.9	$87.8

Included in WMECO’s other regulatory assets/(overrecoveries) are $40.9 million and $50.7 million at September 30, 2005 and December 31, 2004, respectively, of amounts related to WMECO’s rate cap deferral.  The rate cap deferral allows WMECO to recover stranded costs, and these amounts represent the cumulative excess of transition cost revenues over transition cost expenses.

Additionally, the Utility Group had $13.5 million and $11.6 million of regulatory costs at September 30, 2005 and December 31, 2004, respectively, that are included in deferred debits and other assets - other on the accompanying condensed consolidated balance sheets.  These amounts represent regulatory 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.

As discussed in Note 7D, “Commitments and Contingencies - Deferred Contractual Obligations,” substantial portions of the unrecovered contractual obligations regulatory assets have not yet been approved for recovery.  At this time management believes that these regulatory assets are probable of recovery.

Regulatory Liabilities:  The Utility Group had $1.2 billion of regulatory liabilities at September 30, 2005 and $1.1 billion at December 31, 2004.  These amounts include revenues subject to refund which are classified as regulatory liabilities on the accompanying condensed consolidated balance sheets.  These amounts are comprised of the following:

8 

	At September 30, 2005
(Millions of Dollars)	NU Consolidated	CL&P	PSNH	WMECO	Yankee Gas
Cost of removal	$   308.2	$140.6	$   86.1	$23.8	$57.7
CL&P CTA, GSC and SBC   overcollections	86.8	86.8	-	-	-
PSNH cumulative deferral – SCRC	271.1	-	271.1	-	-
Regulatory liabilities offsetting   Utility Group derivative assets	402.8	402.8	-	-	-
Other regulatory liabilities	154.4	94.6	29.9	0.3	29.6
Totals	$1,223.3	$724.8	$387.1	$24.1	$87.3

	At December 31, 2004
(Millions of Dollars)	NU Consolidated	CL&P	PSNH	WMECO	Yankee Gas
Cost of removal	$   328.8	$144.3	$   87.6	$24.1	$72.8
CL&P CTA, GSC and SBC   overcollections	200.0	200.0	-	-	-
PSNH cumulative deferral – SCRC	208.6	-	208.6	-	-
Regulatory liabilities offsetting   Utility Group derivative assets	191.4	191.4	-	-	-
Other regulatory liabilities	141.4	79.1	27.5	1.1	33.7
Totals	$1,070.2	$614.8	$323.7	$25.2	$106.5

E.

Allowance for Funds Used During Construction

The allowance for funds used during construction (AFUDC) is a non-cash item that is included in the cost of Utility Group 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 in other interest expense, and the cost of equity funds is recorded as other income on the condensed consolidated statements of (loss)/income, as follows:

	For the Three Months Ended		For the Nine Months Ended
(Millions of Dollars)	September 30, 2005	September 30, 2004	September 30, 2005	September 30, 2004
Borrowed funds	$2.8	$0.9	$   7.2	$3.1
Equity funds	3.7	0.3	7.9	2.2
Totals	$6.5	$1.2	$15.1	$5.3
Average AFUDC rates	6.2%	3.9%	5.3%	3.8%

The average AFUDC rate is based on a FERC-prescribed formula that develops an average rate using the cost of the company’s short-term financings as well as the company’s capitalization (preferred stock, long-term debt and common equity).  The average rate is applied to eligible construction work in progress amounts to calculate AFUDC.  For the three and nine months ended September 30, 2005, the average AFUDC rates increased by 2.3 percent and 1.5 percent, respectively.  The increase is primarily due to increases in short-term and long-term debt interest rates.

F.

Equity-Based Compensation

NU maintains an Employee Stock Purchase Plan and other long-term, equity-based incentive plans under the Northeast Utilities Incentive Plan.  NU accounts for these plans under the recognition and measurement principles of Accounting Principles Board (APB) Opinion No. 25, “Accounting for Stock Issued to Employees,” (APB No. 25) and related interpretations.  No equity-based employee compensation cost for stock options has been reflected in net income, as all options granted under those plans had an exercise price equal to the market value of the underlying common stock on the date of grant.  The following table illustrates the effect on net income and earnings per share (EPS) if NU had applied the fair value recognition provisions of SFAS No. 123 to equity-based employee compensation associated with restricted stock and restricted stock units:  

9 

	For the Three Months Ended		For the Nine Months Ended
(Millions of Dollars, except per share amounts)	September 30, 2005	September 30, 2004	September 30, 2005	September 30, 2004
Net (loss)/income, as reported	$(94.5)	$  (7.9)	$(239.9)	$83.5
Add:  Equity-based employee compensation   expense included in reported net (loss)/income,   net of related tax effects	0.5	0.7	1.9	1.7
Net (loss)/income before equity-based compensation	(94.0)	(7.2)	(238.0)	85.2
Deduct: Total equity-based employee compensation   expense determined under the fair value-based   method for all awards, net of related tax effects	(0.7)	(1.0)	(2.5)	(2.5)
Pro forma net (loss)/income	$(94.7)	$(8.2)	$(240.5)	$82.7
EPS:
Basic and fully diluted - as reported	$(0.73)	$(0.06)	$  (1.85)	$0.65
Basic and fully diluted - pro forma	$(0.73)	$(0.06)	$  (1.86)	$0.64

NU accounts for restricted stock in accordance with APB No. 25 and amortizes the intrinsic value of the stock at the award date over the related service period.

NU assumes an income tax rate of 40 percent to estimate the tax effect on total equity-based employee compensation expense determined under the fair value-based method for all awards.

During the three and nine-month periods ended September 30, 2005, no stock options were awarded.

For information regarding new accounting standards issued but not yet effective associated with equity-based compensation, see Note 1B, “Summary of Significant Accounting Policies - New Accounting Standards,” to the condensed consolidated financial statements.

G.

Sale of Customer Receivables

At September 30, 2005 and December 31, 2004, CL&P had sold an undivided interest in its accounts receivable of $100 million and $90 million, respectively, to a financial institution with limited recourse through CL&P Receivables Corporation (CRC), a wholly owned subsidiary of CL&P.  CRC can sell up to $100 million of an undivided interest in its accounts receivable and unbilled revenues. At September 30, 2005 and December 31, 2004, the reserve requirements calculated in accordance with the Receivables Purchase and Sale Agreement were $27.5 million and $18.8 million, respectively.  These reserve amounts are deducted from the amount of receivables eligible for sale.  At their present levels, these reserve amounts do not limit CL&P’s ability to access the full amount of the facility.  Concentrations of credit risk to the purchaser under this agreement with respect to the receivables are limited due to CL&P’s diverse customer base.

At September 30, 2005 and December 31, 2004, amounts sold to CRC by CL&P but not sold to the financial institution totaling $220.9 million and $139.4 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 6, 2005, CRC renewed its Receivables Purchase and Sale Agreement with CL&P and the financial institution through July 5, 2006. 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.”

H.

Other Investments

Yankee Energy System, Inc. (Yankee) maintains a long-term note receivable from BMC Energy, LLC (BMC), an operator of renewable energy projects.  In the first quarter of 2004, based on revised information that negatively impacted undiscounted cash flow projections and fair value estimates, management determined that the fair value of the note receivable from BMC had declined and that the note was impaired.  As a result, management recorded a pre-tax investment write-down of $2.5 million ($1.5 million on an after-tax basis) in the first quarter of 2004.  In the second quarter of 2005, based upon additional revised information that negatively impacted the fair value of the BMC note receivable, management recorded an additional pre-tax investment write-down of $0.8 million ($0.5 million on an after-tax basis).  Yankee’s remaining note receivable from BMC, which is included in deferred debits and other assets – other on the accompanying condensed consolidated balance sheets, totaled $0.5 million at September 30, 2005.

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On June 30, 2004, Yankee sold virtually all of the assets and liabilities of R.M. Services, Inc. (RMS), a provider of consumer collection services, for $3 million.  In conjunction with the sale in the second quarter of 2004, an estimated gain totaling $0.6 million was included as a gain from sale of RMS.  As a result of adjustments to estimates recorded in conjunction with the sale during the third quarter of 2004, this gain was increased by $0.2 million and totaled $0.8 million at September 30, 2004.  

NU has an investment in a developer of fuel cell and power quality equipment.  Based on revised information that affected the fair value of NU’s investment, management determined that at June 30, 2004, the value of NU’s investment had declined and that decline was other than temporary.  A pre-tax investment write-down of $3.8 million ($2.4 million on an after-tax basis) was recorded to reduce the carrying value of the investment.  The balance of this investment at September 30, 2005, which is included in receivables on the accompanying condensed consolidated balance sheets, was $0.6 million.

NU owns 49 percent of the common stock of the Connecticut Yankee Atomic Power Company (CYAPC) with a carrying value of $22 million at September 30, 2005.  This amount is included in deferred debits and other assets – other on the accompanying condensed consolidated balance sheets.  CYAPC is also involved in litigation over the termination of its decommissioning contract with Bechtel Power Corporation (Bechtel).  CYAPC filed with the FERC to recover the increased estimate of decommissioning and plant closure costs.  The FERC proceeding is ongoing.  Management believes that this litigation and the FERC proceeding have not impaired the value of its investment in CYAPC at September 30, 2005 but will continue to evaluate the impacts that the litigation and the FERC proceeding have on NU’s investment.  For further information regarding the Bechtel litigation, see Note 7D, “Commitments and Contingencies - Deferred Contractual Obligations,” to the condensed consolidated financial statements.

I.

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, bank overdraft amounts are reclassified from cash and cash equivalents to accounts payable.

J.

Special Deposits

Special deposits represents amounts Select Energy has on deposit with unaffiliated counterparties and brokerage firms in the amounts of $164.3 million and $46.3 million at September 30, 2005 and December 31, 2004, respectively.  Special deposits at December 31, 2004 also included $20 million in escrow for SESI that had not been spent on construction projects and $16.3 million in escrow for Yankee Gas, which represented payment for Yankee Gas’ first mortgage bonds that became due on June 1, 2005.  SESI special deposits totaling $8.7 million are included as assets held for sale on the accompanying condensed consolidated balance sheet at September 30, 2005.

K.

Counterparty Deposits

Balances collected from counterparties resulting from Select Energy’s credit management activities totaled $209.5 million at September 30, 2005 and $57.7 million at December 31, 2004.  These amounts are recorded as current liabilities and are included as counterparty deposits on the accompanying condensed consolidated balance sheets.  To the extent Select Energy requires collateral from counterparties, cash is received as a part of the total collateral required.  The right to receive such cash collateral in an unrestricted manner is determined by the terms of Select Energy’s 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.

11

L.

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, 2005	September 30, 2004	September 30, 2005	September 30, 2004
Other Income:
Investment income	$4.3	$4.7	$12.9	$10.5
CL&P procurement fee	3.1	3.0	9.0	8.8
AFUDC – equity funds	3.7	0.3	7.9	2.2
Gain on disposition of property	0.7	0.8	2.1	2.5
Gain on sale of RMS	-	0.2	-	0.8
Other	3.2	3.4	7.0	8.8
Total Other Income	$15.0	$12.4	$38.9	$33.6
Other Loss:
Environmental Reserves	$(1.4)	$(0.1)	$(5.0)	$(0.1)
Loss of disposition of property	-	-	(0.1)	(1.9)
Investment write-downs	-	-	(0.8)	(6.3)
Charitable donations	(0.4)	(0.6)	(2.1)	(2.3)
Costs not recoverable from      regulated customers	(1.3)	(2.1)	(3.2)	(4.8)
Advertising	(0.4)	(0.3)	(2.4)	(1.6)
Other	(3.3)	(3.3)	(10.5)	(9.0)
Total Other Loss	$(6.8)	$(6.4)	$(24.1)	$(26.0)
Total Other Income, Net	$ 8.2	$ 6.0	$ 14.8	$   7.6

CL&P	For the Three Months Ended		For the Nine Months Ended
(Millions of Dollars)	September 30, 2005	September 30, 2004	September 30, 2005	September 30, 2004
Other Income:
Investment income	$  2.8	$  2.8	$  7.7	$  5.9
CL&P procurement fee	3.1	3.0	9.0	8.8
AFUDC - equity funds	3.2	0.1	6.7	1.8
Return on regulatory deferrals	0.4	1.1	1.6	1.0
Other	1.6	0.8	2.6	5.7
Total Other Income	$11.1	$  7.8	$27.6	$23.2
Other Loss:
Advertising expense	$      -	$      -	$ (1.0)	$ (0.1)
Charitable donations	(0.3)	(0.3)	(1.2)	(1.4)
Loss on investments in   securitizable assets	(0.3)	(0.3)	(1.1)	(0.6)
Costs not recoverable from  regulated customers	(0.8)	(1.2)	(2.3)	(2.7)
Other	(0.9)	(0.9)	(4.0)	(3.2)
Total Other Loss	$ (2.3)	$ (2.7)	$ (9.6)	$(8.0)
Total Other Income, Net	$   8.8	$   5.1	$ 18.0	$15.2

12 

PSNH	For the Three Months Ended		For the Nine Months Ended
(Millions of Dollars)	September 30, 2005	September 30, 2004	September 30, 2005	September 30, 2004
Other Income:
Investment income	$ 0.1	$     -	$ 0.5	$     -
Gain on disposition of property	0.6	-	0.6	0.8
AFUDC - equity funds	0.2	-	0.7	-
Rental income	0.1	0.1	0.2	0.2
Conservation load management   incentive	-	-	0.6	-
Total Other Income	$ 1.0	$ 0.1	$ 2.6	$ 1.0
Other Loss:
Advertising expense	$(0.4)	$(0.2)	$(1.2)	$(1.3)
Charitable donations	(0.1)	(0.1)	(0.4)	(0.4)
Service fees	(0.2)	(0.3)	(0.8)	(0.9)
Costs not recoverable from   regulated customers	(0.3)	(0.3)	(0.7)	(0.7)
Other	(1.0)	(0.3)	(1.4)	(1.1)
Total Other Loss	$(2.0)	$(1.2)	$(4.5)	$(4.4)
Total Other Loss, Net	$(1.0)	$(1.1)	$(1.9)	$(3.4)

WMECO	For the Three Months Ended		For the Nine Months Ended
(Millions of Dollars)	September 30, 2005	September 30, 2004	September 30, 2005	September 30, 2004
Other Income:
Investment income	$0.2	$0.1	$  0.4	$0.2
Conservation load management  incentive	0.4	0.1	0.6	0.2
Other	0.5	0.3	1.2	0.9
Total Other Income	$1.1	$0.5	$  2.2	$1.3
Other Loss:
Charitable donations	$    -	$(0.1)	$(0.2)	$(0.3)
Costs not recoverable from   regulated customers	(0.2)	(0.2)	(0.4)	(0.5)
Environmental reserves	-	(0.1)	-	(0.1)
Other	(0.2)	(0.4)	(0.8)	(1.6)
Total Other Loss	$(0.4)	$(0.8)	$(1.4)	$(2.5)
Total Other Income/(Loss), Net	$  0.7	$(0.3)	$  0.8	$(1.2)

Investment income for NU includes equity in earnings of regional nuclear generating and transmission companies of $0.6 million and $0.9 million of income for the three months ended September 30, 2005 and 2004, respectively, and $2.5 million and $1.8 million for the nine months ended September 30, 2005 and 2004, respectively.  Equity in earnings relates to NU’s investment in the Yankee Companies and the Hydro-Quebec system.

None of the amounts in either other income - other or other loss - other are individually significant.  

2.

WHOLESALE CONTRACT MARKET CHANGES (NU, NU Enterprises)

NU Enterprises recorded $101.2 million and $359.7 million of pre-tax wholesale contract market changes for the three months and nine months ended September 30, 2005, respectively, related to the changes in the fair value of wholesale contracts that the company is in the process of divesting.  These amounts are reported as wholesale contract market changes, net on the condensed consolidated statements of (loss)/income.  A quarterly summary of those pre-tax charges (benefits) is as follows (millions of dollars):  

13

	First Quarter 2005	Second Quarter 2005	Third Quarter 2005	Year-to-Date
Mark-to-market on long-term   wholesale electricity contracts	$ 294.3	$ 64.2	$  80.6	$439.1
Mark-to-market supply contracts previously held for retail marketing and other wholesale contracts	(105.4)	5.4	20.6	(79.4)
Totals	$ 188.9	$ 69.6	$101.2	$359.7

The $80.6 million in the third quarter of 2005 includes the mark-to-market of certain long-dated wholesale electricity contracts in New England and New York with municipal and other customers.  The charge reflects negative mark-to-market movements on these contracts between June 30, 2005 and September 30, 2005 as a result of rising energy prices, partially offset by positive effects of buying out certain obligations in the third quarter at prices less than the June 30, 2005 marks.  Also included in the $80.6 million charge is a pre-tax charge of $11.7 million related to a portfolio of contracts that Select Energy assigned to a third-party wholesale power marketer, obligating that marketer to assume responsibility for those contracts that Select Energy had in New England, beginning on January 1, 2006, in exchange for a $15 million payment Select Energy will make in December of 2005.  An additional $5.1 million charge from this assignment was recorded as a reduction to revenues.

The $20.6 million third quarter charge includes approximately $37 million relating to certain wholesale contracts in the PJM power pool where NU Enterprises increased its estimates of customer load above its original expectations and an additional $3.1 million charge from the assignment noted above.  Offsetting these charges is a net pre-tax benefit of $19.5 million associated with the marking-to-market of the supply contracts that previously were held to serve certain retail electric load and other mark-to-market impacts.

Included in the mark-to-market on long-term wholesale electricity contracts are $44 million and $114.2 million pre-tax mark-to-market charges for the three and nine months ended September 30, 2005, respectively, related to an intercompany contract between Select Energy and CL&P.  This contract was included in the portfolio of contracts Select Energy assigned to a third party wholesale power marketer, and Select Energy will only serve CL&P through December 31, 2005.  This contract is part of CL&P’s stranded costs, and benefits received by CL&P under this contract are provided to CL&P’s ratepayers.  A $2.8 million pre-tax mark-to-market charge for the three months ended March 31, 2005, was recorded as wholesale contract market changes by Select Energy for an intercompany contract between Select Energy and WMECO for default service from April to June of 2005.  There were no wholesale contract market changes in the second or third quarter of 2005 for this contract, as it expired on June 30, 2005.  WMECO’s benefits under this contract will be provided to ratepayers in the form of lower than market default service rates.  These charges were not eliminated in consolidation because on a consolidated basis NU retains the over-market obligation to the ratepayers of CL&P and WMECO.

For further information regarding these and other wholesale derivative assets and liabilities that are being divested, see Note 5, “Derivative Instruments,” to the condensed consolidated financial statements.

3.

RESTRUCTURING AND IMPAIRMENT CHARGES (NU, NU Enterprises)

NU Enterprises recorded $5.3 million and $53.1 million of pre-tax restructuring and impairment charges for the three and nine months ended September 30, 2005 related to the decision to exit the wholesale marketing business and to divest its energy services businesses. The amounts related to continuing operations are included as restructuring and impairment charges on the condensed consolidated statements of (loss)/income with the remainder included in discontinued operations.  A summary of those pre-tax charges is as follows (millions of dollars):  

14

	Six Months Ended June 30, 2005	Three Months Ended September 30, 2005	Year-to-Date
Merchant Energy:
Impairment charges	$ 7.2	$   -	$  7.2
Restructuring charges	1.0	4.2	5.2
Subtotal	8.2	4.2	12.4
Energy Services:
Impairment charges	39.1	-	39.1
Restructuring charges	0.5	1.1	1.6
Subtotal	39.6	1.1	40.7
Subtotal – restructuring and   impairment charges	47.8	5.3	53.1
Restructuring and impairment  charges included in   discontinued operations	24.2	0.5	24.7
Total restructuring and impairment charges in continuing operations	$23.6	$4.8	$28.4

On March 9, 2005, NU announced that it had completed its comprehensive review of the NU Enterprises businesses.  In the first quarter of 2005, as a result of that comprehensive review, an exclusivity agreement intangible asset totaling $7.2 million related to the merchant energy business was determined to be impaired and was written off.  

NU Enterprises hired an outside firm to assist in valuing its energy services businesses and their divestiture.  Based in part on that firm’s work, the company concluded that $29.1 million of goodwill associated with those businesses and $9.2 million of intangible assets were impaired as of March 31, 2005.  An impairment charge of $38.3 million was recorded for the three months ended March 31, 2005.  In the second quarter of 2005, the energy services businesses and NU Enterprises parent recorded an additional impairment charge of $0.8 million due to the impairment of certain fixed assets.  

In the second quarter of 2005, pre-tax restructuring costs totaling $1 million and $0.5 million were recorded by merchant energy and energy services business, respectively, related to professional fees, employee-related and other costs. Similar amounts were recorded in the third quarter of 2005 totaling $4.2 million and $1.1 million for merchant energy and energy services businesses, respectively. Additional restructuring charges will be recognized as incurred and may include professional fees and employee-related and other costs.

4.

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

Assets Held for Sale:  On March 9, 2005, NU concluded that NU Enterprises’ energy services businesses are not central to NU’s long-term strategy and do not meet the company’s expectations of profitability, and as a result, the company concluded that it would explore ways to divest those businesses in a manner that maximizes their value.  During the third quarter of 2005, management determined that it expects to divest four of these businesses within the next year.  Accordingly, at September 30, 2005, certain assets and liabilities of the following four energy services businesses are being accounted for as held for sale, at the lower of carrying amount or fair value less cost to sell:  SESI, a performance contracting subsidiary that specializes in upgrading the energy efficiency of large governmental and institutional facilities, Select Energy Contracting, Inc. - New Hampshire (SECI-NH), a division of Select Ener gy Contracting, Inc. (SECI) that provides mechanical contracting services, Woods Network Services, Inc. (Woods Network), a subsidiary of NU Enterprises that is a network products and services company, and Woods Electrical Co., Inc. (Woods Electrical), a subsidiary of Northeast Generation Services Company (NGS) which provides third-party electrical services.   Prior to September 30, 2005, SESI, SECI-NH, Woods Network, and Woods Electrical are reported as part of the services and other segment of NU Enterprises.  

15

The major classes of assets and liabilities that are held for sale at September 30, 2005 are as follows:

(Millions of Dollars)
Special deposits	$   8.7
Accounts and notes receivable	18.9
Other current assets	6.4
Other assets	1.1
Long-term contract receivables	101.1
Total assets	136.2
Accounts and notes payable	9.7
Other current liabilities	15.8
Long-term debt	92.8
Other liabilities	0.1
Total liabilities	118.4
Net assets	$  17.8

Discontinued Operations:  NU’s condensed consolidated statements of (loss)/income for the three and nine months ended September 30, 2005 and 2004 present the operations for SESI, SECI-NH, Woods Network, and Woods Electrical as discontinued operations as a result of meeting certain criteria requiring this presentation.  Under this presentation, revenues and expenses of these businesses are classified net of tax in (loss)/income from discontinued operations, on the condensed consolidated statements of (loss)/income and all prior periods have been 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, 2005	September 30, 2004	September 30, 2005	September 30, 2004
Operating revenue	$29.2	$46.1	$ 95.5	$127.9
Restructuring and impairment charges	$  0.5	$     -	$ 24.7	$        -
(Loss)/income before income tax   (benefit)/expense	$ (3.9)	$ 2.3	$(34.2)	$   (0.5)
Income tax (benefit)/expense	$ (1.4)	$ 0.9	$(12.8)	$   (0.1)
Net (loss)/income	$ (2.5)	$ 1.4	$(21.4)	$   (0.4)

Included in discontinued operations for the three months ended September 30, 2005 and 2004 are $1.4 million and $2.6 million, respectively, of intercompany revenue that are not eliminated in consolidation due to the separate presentation of discontinued operations.  For the nine months ended September 30, 2005 and 2004 these amounts were $9.8 million and $5.8 million, respectively. At September 30, 2005, NU does not expect that after the disposal it will have significant ongoing involvement or continuing cash flows with the entities presented in discontinued operations.

5.

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

Contracts that are derivatives and do not meet the definition of a cash flow hedge and are not elected as normal purchases or normal sales 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, the changes in the fair value of the effective portion of those contracts are generally recognized in accumulated other comprehensive income until the underlying transactions occur.  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 item they are hedging are both recorded at fair value with changes in fair value of both items recognized currently in earnings.  Derivative contracts that are elected and meet the requirements of a normal purchase or sale are recognized in revenues and expenses, as applicable, when the quantity of the contract is delivered.  

For the nine months ended September 30, 2005, a negative $0.9 million, net of tax, was reclassified as expense from other comprehensive income in connection with the consummation of the underlying hedged transactions and recognized in earnings, and a positive $2.4 million, net of tax, was reclassified as expense from other comprehensive income related to the mark-to-market changes for wholesale contracts that NU Enterprises is in the process of divesting.  Also during the nine months of 2005, new cash flow hedge transactions were entered into that hedge cash flows through 2010.  As a result of the consummation of the transactions, these new transactions and market value changes since January 1, 2005, accumulated other comprehensive income increased by $22.4 million, net of tax.  Accumulated other comprehensive income at September 30, 2005 was a positive $18.9 million, net of tax (increase to equity), relating to hedged transactions, and it is estimated that a positive $11.6 million included in this net of tax balance will be reclassified as an increase to earnings within the next twelve months.  Cash flows from hedge contracts are reported in the same category as cash flows from the underlying hedged transaction.  

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There was a positive pre-tax impact of $0.8 million recognized in earnings in the third quarter 2005 for the ineffective portion of cash flow hedges.  A negative pre-tax $8.4 million was recognized in earnings in the third quarter 2005 for the ineffective portion of fair value hedges; at the same time a positive $9.2 million was recorded in earnings for the change in fair value of the hedged natural gas inventory.  The changes in the fair value of both the fair value hedges and the natural gas inventory being hedged totaling a positive $0.8 million above are recorded in fuel, purchased, and net interchange power on the accompanying condensed consolidated statements of (loss)/income.  

The table below summarizes current and long-term derivative assets and liabilities at September 30, 2005.  At September 30, 2005, derivative assets and liabilities have been segregated between wholesale, retail, generation and hedging amounts.  Management is in the process of divesting the contracts included in the wholesale category as a result of the March 9, 2005 decision to exit this portion of the business.  

	At September 30, 2005
(Millions of Dollars)	Assets		Liabilities
	Current	Long-Term	Current	Long-Term	Net  Total
NU Enterprises:
Wholesale	$694.7	$229.4	$(798.2)	$ (365.8)	$ (239.9)
Retail	41.7	4.1	(18.8)	(1.3)	25.7
Generation	-	-	(6.1)	(1.2)	(7.3)
Hedging	40.4	11.7	(29.9)	0.1	22.3
Utility Group – Gas:
Non-trading	0.7	-	-	-	0.7
Utility Group - Electric:
Non-trading	100.1	303.6	-	(32.2)	371.5
NU Parent:
Hedging	-	-	-	(3.0)	(3.0)
Total	$877.6	$548.8	$(853.0)	$(403.4)	$ 170.0

The table below summarizes current and long-term derivative assets and liabilities at December 31, 2004.  Prior to the decision to exit the wholesale marketing business, these current and long-term derivative assets and liabilities were classified as trading, non-trading and hedging derivative assets and liabilities.  For NU Enterprises, current and long-term derivative assets totaled $55.6 million and $31.7 million, respectively, while current and long-term derivative liabilities totaled $125.8 million and $15.9 million, respectively, at December 31, 2004.  

	At December 31, 2004
(Millions of Dollars)	Assets		Liabilities
	Current	Long-Term	Current	Long-Term	Net  Total
NU Enterprises:
Trading	$49.6	$  31.7	$ (46.2)	$  (5.5)	$  29.6
Non-trading	1.5	-	(70.5)	(9.6)	(78.6)
Hedging	4.5	-	(9.1)	(0.8)	(5.4)
Utility Group - Gas:
Non-trading	0.2	-	(0.1)	-	0.1
Hedging	1.5	-	-	-	1.5
Utility Group – Electric:
Non-trading	24.2	167.1	(4.4)	(42.8)	144.1
NU Parent:
Hedging	0.1	-	-	-	0.1
Total	$81.6	$198.8	$(130.3)	$(58.7)	$  91.4

The business activities of NU Enterprises that result in the recognition of derivative assets include concentrations of credit risk to energy marketing and trading counterparties.  At September 30, 2005, Select Energy had $1.0 billion of derivative assets from retail, wholesale, generation, and hedging activities.  These assets are exposed to counterparty credit risk.  However, a significant portion of these assets is contracted with investment grade rated counterparties or collateralized with cash.  

The amounts above do not include option premiums paid, which are recorded as prepayments and amounted to $6.3 million and $29.3 million related to wholesale activities at September 30, 2005 and December 31, 2004, respectively.  These amounts also do not include option premiums received, which are recorded as other current liabilities and amounted to $6.6 million and $27.1 million related to wholesale activities at September 30, 2005 and December 31, 2004, respectively.  

NU Enterprises - Wholesale:  Certain electricity and natural gas derivative contracts are part of Select Energy’s wholesale marketing business that the company is in the process of exiting.  These contracts also include other wholesale and retail short-term and long-

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term electricity supply and sales contracts, which include contracts to sell electricity to utilities under full requirements contracts and contracts to sell electricity to municipalities with terms up to eight remaining years.  The fair value of electricity contracts was determined by prices from external sources for years through 2008 and by models based on natural gas prices and a heat-rate conversion factor to electricity for subsequent periods.  The fair value of the natural gas contracts was primarily determined by prices provided by external sources and actively quoted markets.  In addition, to gather market intelligence and utilize this information in risk management activities for the wholesale marketing activities, Select Energy conducted limited energy trading activities in electricity, natural gas, and oil.  Select Energy manages open trading positions with strict policies that limit its exposure t o market risk and require daily reporting to management of potential financial exposures.   

Derivatives used in wholesale activities are recorded at fair value and included in the condensed consolidated balance sheets as derivative assets or liabilities.  Changes in fair value are recognized in the condensed consolidated statements of (loss)/income in the period of change.  The net fair value position of the wholesale portfolio at September 30, 2005 was a liability of $239.9 million.    

NU Enterprises - Retail:  Select Energy manages its portfolio of retail marketing contracts to maximize value while operating within NU’s corporate risk tolerances.  Select Energy generally acquires retail customers in smaller increments than it acquired wholesale customers, which while requiring careful sourcing, allows energy purchases to be acquired in smaller increments with lower risk. However, fluctuations in prices, fuel costs, competitive conditions, regulations, weather, transmission costs, lack of market liquidity, plant outages and other factors can all impact the retail business adversely from time to time.

From time to time, the retail marketing business enters into contracts that do not immediately meet the criteria for the normal election and accrual accounting.  Therefore, changes in fair value are required to be marked-to-market in earnings.  Derivatives used in retail activities that do not follow accrual accounting under the normal election are recorded at fair value and included in the condensed consolidated balance sheets as derivative assets or liabilities.  Changes in fair value are recognized in fuel, purchased and net interchange power in the condensed consolidated statements of (loss)/income in the period of change.  The net fair value position of the retail portfolio at September 30, 2005 was an asset of $25.7 million.

Select Energy’s retail portfolio also includes New York Mercantile Exchange (NYMEX) futures, financial swaps, and physical power transactions, the fair value of which is based on closing exchange prices; over-the-counter forwards, and financial swaps, the fair value of which is based on the mid-point of bid and ask market prices; and bilateral contracts for the purchase or sale of electricity or natural gas, the fair value of which is determined using available information from external sources, financial transmission rights and transmission congestion contracts, the fair value of which is based on historical settlement prices as well as external sources.

NU Enterprises – Generation:  Select Energy manages its portfolio of derivative contracts relating to generation activities in order to maximize value while operating within NU’s corporate risk tolerances.  These derivative contracts include generation-asset-specific sales and forward sales of electricity at hub trading points.  The fair value of the generation contracts was determined by prices from external sources and actively quoted markets for the life of the contracts, which extend to the end of 2006.  Certain derivatives related to generation activities that do not follow accrual accounting under the normal election are recorded at fair value and included in the condensed consolidated balance sheets as derivative assets or liabilities.  Changes in fair value are recognized in revenues in the condensed consolidated statements of (loss)/income in the period of change.  The net fair value position of the generation derivative contract portfolio at September 30, 2005 was a liability of $7.3 million.  

NU Enterprises - Hedging:  Select Energy utilizes derivative financial and commodity instruments, including futures and forward contracts, to reduce market risk associated with fluctuations in the price of electricity and natural gas purchased to meet firm sales and purchase commitments to certain retail customers.  Select Energy also utilizes derivatives, including price swap agreements, call and put option contracts, and futures and forward contracts to manage the market risk associated with a portion of its anticipated supply and delivery requirements.  These derivatives have been designated as cash flow hedging instruments and are used to reduce the market risk associated with fluctuations in the price of electricity or natural gas.  A derivative that hedges exposure to the variable cash flows of a forecasted transaction (a cash flow hedge) is initially recorded at fair value with changes in fair value recorded 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.   

Select Energy maintains natural gas service agreements with certain retail customers to supply gas at fixed prices for terms extending through 2010.  Select Energy has hedged its gas supply risk under these agreements through NYMEX futures contracts.  Under these contracts, which also extend through 2010, the purchase price of a specified quantity of gas is effectively fixed over the term of the gas service agreements.  At September 30, 2005 the NYMEX futures contracts had notional values of $69.7 million and were recorded at fair value as derivative assets totaling $25.6 million and derivative liabilities of $4.4 million.   

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Select Energy also maintains various physical and financial instruments to hedge its electric and gas purchases and sales through 2006. These instruments include forwards, futures, financial transmission rights and swaps.  These hedging contracts, which are valued at the mid-point of bid and ask market prices, were recorded as derivative assets of $26.5 million and derivative liabilities of $25.1 million at September 30, 2005.   

Select Energy hedges certain amounts of natural gas inventory with gas futures and swaps, some of which are accounted for as fair value hedges.  Changes in the fair value of hedging instruments and natural gas inventory are recorded in earnings. The change in fair value of the futures, options and swaps were included in derivative liabilities and amounted to $8.4 million at September 30, 2005. The change in fair value of the hedged natural gas inventory was recorded as a increase to fuel, materials and supplies of $9.2 at September 30, 2005.   

Utility Group - Gas- Non-Trading: Yankee Gas’ non-trading derivatives consist of peaking supply arrangements to serve winter load obligations and firm sales contracts with options to curtail delivery.  These contracts are subject to fair value accounting because these contracts are derivatives that cannot be designated as normal purchase or sales, as defined, because of the optionality in the contract terms.  Non-trading derivatives at September 30, 2005 included assets of $0.7 million.  At December 31, 2004, non-trading derivatives included assets of $0.2 million and liabilities of $0.1 million.  

Utility Group - Electric - Non-Trading:  CL&P has two independent power producer (IPP) contracts 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, 2005 include a derivative asset with a fair value of $403.7 million and a derivative liability with a fair value of $32.2 million.  An offsetting regulatory liability and an offsetting regulatory asset were recorded, as these contracts are part of the stranded costs, and management believes that these costs will continue to be recovered or refunded in rates.   At December 31, 2004, the fair values of these IPP non-trading derivatives included a derivative asset with a fair value of $191.3 million and a derivative liability with a fair value of $47.2 million.

NU Parent - Hedging:  In March of 2003, 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.  As a fair value hedge, the changes in fair value of the swap and the hedged debt instrument are recorded on the condensed consolidated balance sheets but are offsetting in the condensed consolidated statements of (loss)/income.  At September 30, 2005, the cumulative change in the fair value of the hedged debt of $3 million is included as a decrease to long-term debt on the condensed consolidated balance sheets.  The hedge is recorded as a derivative liability of $3 million at September 30, 2005, and as a derivative asset of $0.1 million at December 31, 2004.  The resulting changes in interest payments made are recorded as adjustments to interest expense.

6.

GOODWILL AND OTHER INTANGIBLE ASSETS (Yankee Gas, NU Enterprises)

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 1st as 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.

NU’s reporting units that maintain goodwill are generally consistent with the operating segments underlying the reportable segments identified in Note 12, “Segment Information,” to the condensed consolidated financial statements. Consistent with the way management reviews the operating results of its reporting units, NU’s reporting unit under the NU Enterprises reportable segment that maintains goodwill is the merchant energy reporting unit. The merchant energy reporting unit is comprised of the operations of Select Energy, Northeast Generation Company (NGC), the generation operations of Holyoke Water Power Company (HWP), and NGS. As a result, NU's reporting units that maintain goodwill are as follows: the Yankee Gas reporting unit, which is classified under the Utility Group - gas reportable segment, and the merchant energy reporting unit, which is classified under the NU Enterprises - merchant energy reportable segment. The goodwill recorded related to the acquisition of Yankee Gas is not being recovered from the customers of Yankee Gas. The goodwill balances of these reporting units are included in the table herein.

A summary of NU’s goodwill balances at September 30, 2005 and December 31, 2004, by reportable segment and reporting units is as follows:

(Millions of Dollars)	At September 30, 2005	At December 31, 2004
Utility Group - Gas:
Yankee Gas	$287.6	$287.6
NU Enterprises:
Merchant Energy	3.2	3.2
Energy Services	-	29.1
Totals	$290.8	$319.9

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On March 9, 2005, NU announced that it had completed its comprehensive review of the NU Enterprises businesses.  During this review, certain goodwill balances and intangible assets were deemed to be impaired, and adjustments were recorded in the first quarter of 2005 to write these assets off.  The goodwill balance in the NU Enterprises energy services reporting unit was determined to be impaired in its entirety, and a $29.1 million write-off was recorded.  Energy services intangible assets not subject to amortization were also impaired, and an $8.5 million pre-tax write-off was recorded, while an additional $0.7 million pre-tax of other intangible assets were impaired.  At September 30, 2005, NU’s remaining intangible assets totaled $2.3 million.  This amount will be amortized $0.3 million for the remainder of 2005, $1 million in 2006, and $1 million in 2007.  Additionally, NU Enterprises had an exclusivity agreement intangible asset, which was included in the merchant energy business and was also written off.  The $7.9 million balance at December 31, 2004 was amortized by $0.7 million in the first quarter of 2005 and the remaining $7.2 million was written off at March 31, 2005.  

There were no impairments or adjustments to the goodwill balances during the third quarter of 2005 or the first nine months of 2004.  

NU recorded amortization expense of $0.3 million and $0.9 million for the three months ended September 30, 2005 and 2004, respectively, and amortization expense of $1.4 million and $2.7 million for the nine months ended September 30, 2005 and 2004, respectively, related to intangible assets subject to amortization which are included in deferred debits and other assets – other on the condensed consolidated balance sheets.

7.

COMMITMENTS AND CONTINGENCIES

A.

Regulatory Issues and Rate Matters (CL&P, PSNH, 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 the rate reduction bonds, amortization of regulatory assets, and IPP 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 April 1, 2005, CL&P filed its 2004 CTA and SBC reconciliation with the Connecticut Department of Public Utility Control (DPUC), which compared CTA and SBC revenues to revenue requirements.  For the year ended December 31, 2004, total CTA revenues exceeded the CTA revenue requirements by $14.1 million.  This amount was recorded as a regulatory liability on the accompanying condensed consolidated balance sheets.  For the same period, SBC revenues exceeded the SBC revenue requirement by $3.6 million which was recorded as a regulatory liability.  Management expects a decision in this docket from the DPUC by the end of 2005.   

In the 2001 CTA and SBC reconciliation filing, and subsequently in a September 10, 2002 petition to reopen related proceedings, CL&P requested that a deferred intercompany tax liability associated with the intercompany sale of generation assets be excluded from the calculation of CTA revenue requirements. This liability is currently included as a reduction in the calculation of CTA revenue requirements. On September 10, 2003, the DPUC issued a final decision denying CL&P’s request, and on October 24, 2003, CL&P appealed the DPUC’s final decision to the Connecticut Superior Court. The appeal has been fully briefed and argued. If CL&P’s request is granted and upheld through these court proceedings, there would be additional amounts due to CL&P from its customers. The amount due is contingent upon the findings of the court; however, management believes that CL&P’s pre-tax earnings would increase by a minimum of $17 million in 2005 if CL&P’s position is adopted by the court.

Unbilled Revenue Adjustment:  On September 9, 2005, the DPUC issued a draft decision regarding Yankee Gas Purchased Gas Adjustment (PGA) clause charges for the time 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 hearing on September 20, 2005 and requested that Yankee Gas file supplemental information regarding the two adjustments.  Yankee Gas filed the supplemental information on October 3, 2005 and is waiting for the DPUC to establish the remaining schedule.  If upheld, this disallowance would result in a $9 million pre-tax write-off.  Management believes the unbilled sales and revenue adjustments and resultant charges to customers through the PGA clause were appropriate.  Based on the facts of the case and the supplemental information provided to the DPUC, management believes the appropriateness of the PGA charges to customers for the time period under review will be allowed.

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New Hampshire:

SCRC Reconciliation Filing:  The Stranded Cost Recovery Charge (SCRC) allows PSNH to recover its stranded costs.  On an annual basis, PSNH files with the New Hampshire Public Utilities Commission (NHPUC) a SCRC reconciliation filing for the preceding calendar year.  This filing includes the reconciliation of stranded cost revenues and costs and transition energy service/default energy service (TS/DS) revenues and costs.  The NHPUC reviews the filing, including a prudence review of the operation of PSNH’s generation assets.  The cumulative deferral of SCRC revenues in excess of costs was $271.1 million at September 30, 2005.  This cumulative deferral will decrease the amount of non-securitized stranded costs that will have to be recovered from PSNH’s customers in the future from $374.1 million to $103 million.

The 2004 SCRC reconciliation filing was filed with the NHPUC on May 2, 2005.  The SCRC and TS/DS rate mechanisms currently reconcile accrued expenses with billed revenues on a monthly basis.  PSNH included a request, and supporting testimony, to include unbilled revenues as part of the reconciliation process in its annual 2004 SCRC and TS/DS reconciliation filing.  This request allows for the reconciliation of revenues on an accrual basis, including unbilled revenues, with the current accrued expenses recovered through the SCRC and TS/DS rate mechanisms, consistent with accrual accounting.  At September 30, 2005, PSNH’s unbilled revenue balance related to SCRC and TS/DS was $11.7 million and $16.7 million, respectively.  On October 19, 2005, PSNH, the NHPUC staff and the Office of Consumer Advocate reached a settlement agreement in this case, which requires no disallowances and provides for recovery of unbilled revenues. The NHPUC held a hearing on the merits of the settlement agreement on October 26, 2005, and a decision is expected later this year.  

Litigation with IPPs:  Two wood-fired IPPs that sell their output to PSNH under long-term rate orders issued by the NHPUC brought suit against PSNH in state superior court.  The IPPs and PSNH dispute the end-dates of the above-market long-term rates set forth in the respective rate orders.  Subsequent to the IPP’s court filing, PSNH petitioned the NHPUC to decide this matter, and requested that the court stay its proceeding pending the NHPUC’s decision.  By court order dated October 20, 2005, the court granted PSNH’s motion to stay indicating that the NHPUC had primary jurisdiction over this matter.  The NHPUC will determine how long each of the rate orders in question remain in effect.  PSNH recovers the over market costs of IPP contracts through the SCRC.  

Environmental Legislation:  The New Hampshire legislature will be considering legislation in its 2006 legislative session that would place strict limitations on the level of mercury that PSNH’s existing generation plants can emit.  Management has been reviewing the proposed legislation and assessing how PSNH might meet any required reduction in mercury emissions should such strict limitations be established.  PSNH conducted testing of one control technology at its Merrimack Station during the summer of 2005.  While state law and PSNH’s restructuring agreement provide for the recovery of its generation costs, including the cost to comply with state environmental regulations, at this time management is unable to determine the impact of any potential new legislation on PSNH’s net income or financial position.

Massachusetts:

Transition Cost Reconciliation and Other Filings:  On March 31, 2005, WMECO filed its 2004 transition cost reconciliation with the Massachusetts Department of Telecommunications and Energy (DTE).  The DTE has combined the 2003 transition cost reconciliation filing, standard offer service and default service reconciliation, the transmission cost adjustment filing, and the 2004 transition cost reconciliation filing into a single proceeding.  The timing of a decision in the combined proceeding is uncertain, but management does not expect the outcome to have a material adverse impact on WMECO’s net income or financial position.

B.

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 of its subsidiaries filed voluntary bankruptcy petitions. On December 5, 2003, NRG emerged from bankruptcy. NU’s NRG-related exposures as a result of these transactions relate to 1) the recovery of congestion charges incurred by NRG prior to the implementation of standard market design on March 1, 2003, 2) the recovery of CL&P’s station service billings from NRG, and 3) the recovery of Yankee Gas’ and CL&P’s expenditures that were incurred related to an NRG subsidiary’s generating plant construction project that has ceased. While it is unable to determine the ultimate outcome of these issues, management does not expect that their resolution will have a material adverse effect on NU’s consolidated financial condition or results of operations.

21 

C.

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

CL&P:  These amounts represent commitments for various services and materials primarily associated with the Bethel, Connecticut to Norwalk, Connecticut and the Middletown, Connecticut to Norwalk, Connecticut transmission projects as of September 30, 2005.  

(Millions of Dollars)	2005	2006	2007	2008	2009	Thereafter	Total
Transmission business   project commitments	$45.2	$143.8	$6.4	$6.4	$6.4	$5.4	$213.6

Merchant Energy:   Select Energy maintains off-balance sheet long-term agreements to purchase energy as part of its portfolio of resources to meet its actual or expected sales commitments.  These sale commitments are accounted for on the accrual basis.  The aggregate amount of these purchase contracts was $968.2 million at September 30, 2005, as follows (millions of dollars):

Year
2005	$343.3
2006	476.0
2007	92.1
2008	35.3
2009	7.2
Thereafter	14.3
Total	$968.2

Select Energy’s purchase contract amounts can exceed the amount expected to be reported in fuel, purchased and net interchange power.

Select Energy maintains certain wholesale energy commitments whose mark-to-market values have been recorded on the condensed consolidated balance sheet as derivative assets and liabilities.  The aggregate amount of these purchase contracts was $3.2 billion at September 30, 2005, the majority of which settle in 2005 and 2006.

D.

Deferred Contractual Obligations (NU, CL&P, PSNH, WMECO)

FERC Proceedings: In 2003, CYAPC increased the estimated decommissioning and plant closure costs for the period 2000 through 2023 by approximately $395 million over the April 2000 estimate of $436 million approved by the FERC in a 2000 rate case settlement. The revised estimate reflects the increases in the projected costs of spent fuel storage, increased security and liability and property insurance costs, and the fact that CYAPC is now self performing all work to complete the decommissioning of the plant due to the termination of the decommissioning contract with Bechtel in July 2003. NU’s share of CYAPC’s increase in decommissioning and plant closure costs is approximately $194 million. On July 1, 2004, CYAPC filed with the FERC for recovery of these increased costs. In the filing, CYAPC sought to increase its annual decommissioning collections from $16.7 million to $93 million for a six-year period beginning on January 1, 2005. On August 30, 2004, the FERC issued an order accepting the rates, with collection beginning on February 1, 2005, subject to refund.

Both the DPUC and Bechtel filed testimony in the FERC proceeding claiming that CYAPC was imprudent in its management of the decommissioning project. The DPUC has claimed that CYAPC did not terminate the contract with Bechtel soon enough, and Bechtel has claimed that CYAPC terminated the contract too soon. In its testimony, the DPUC recommended a disallowance of $225 million to $234 million out of CYAPC’s requested rate increase of approximately $395 million. NU’s share of the DPUC’s recommended disallowance is between $110 million to $115 million. The FERC staff also filed testimony that recommended a $36 million decrease in the requested rate increase claiming that CYAPC should have used a different gross domestic product (GDP) escalator. NU’s share of this recommended decrease is $17.6 million. Management expects that if the FERC staff’s position on the decommissioning GDP cost escalator is found by the FERC to be more appropriate than that used by CYAPC to develop its proposed rates, then CYAPC would review whether to reduce its estimated decommissioning obligation and reduce the customers’ obligation, including CL&P, PSNH and WMECO. Hearings in this proceeding began on June 1, 2005 and have concluded, and post-hearing briefs have been filed. While FERC staff did not take a position on prudence in the hearing, they have claimed in their brief that increases in decommissioning cost estimates were due to imprudent actions and were not the fault of ratepayers. A FERC administrative law judge decision in this proceeding is expected to be rendered in December 2005.

The company cannot at this time predict the timing or outcome of the FERC proceeding required for the collection of the increased CYAPC decommissioning costs.  The company believes that the costs have been prudently incurred and will ultimately be recovered from the customers of CL&P, PSNH and WMECO.  However, there is a risk that some portion of these increased costs may not be recovered, or will have to be refunded if recovered, as a result of the FERC proceedings.  

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On June 10, 2004, the DPUC and the Connecticut Office of Consumer Counsel (OCC) filed a petition seeking a declaratory order that CYAPC be allowed to recover all decommissioning costs from its wholesale purchasers, including CL&P, PSNH and WMECO, but that such purchasers may not be allowed to recover in their retail rates any costs that the FERC might determine to have been imprudently incurred.  On August 30, 2004, the FERC denied this petition.  On September 29, 2004, the DPUC and OCC asked the FERC to reconsider the petition and on October 20, 2005, the FERC denied the reconsideration, holding that the sponsor companies are only obligated to pay CYAPC for prudently incurred decommissioning costs and the FERC has no jurisdiction over the sponsors’ rates to their retail customers.  

Bechtel Litigation:  CYAPC is currently in litigation with Bechtel in Connecticut Superior Court (the Court) over the termination of its decommissioning contract.  On June 13, 2003, CYAPC gave notice of the termination of its contract with Bechtel for the decommissioning of its nuclear power plant.  CYAPC terminated the contract due to Bechtel’s incomplete and untimely performance and refusal to perform the remaining decommissioning work.  Bechtel has departed the site and the decommissioning responsibility has been transitioned to CYAPC, which has recommenced the decommissioning process.

On June 23, 2003, Bechtel filed a complaint against CYAPC asserting a number of claims and seeking a variety of remedies, including monetary and punitive damages and rescission of the contract.  Bechtel has since amended its complaint to add claims for wrongful termination.  On August 22, 2003, CYAPC filed its answer and counterclaims, including counts for breach of contract, negligent misrepresentation and breach of duty of good faith and fair dealing.  The parties are proceeding with depositions in the case.  Bechtel filed an offer of judgment for CYAPC to pay Bechtel the amount of $20 million, which was rejected by CYAPC.  CYAPC filed an offer of judgment for Bechtel to pay the amount of $65 million to CYAPC, which was rejected by Bechtel.  If either party prevails in litigation with an award equal to or higher than its offer, then the Court will add 12 percent annual interest to the award to the prevailing party, computed from the date of the party’s claim (from June 23, 2003 for Bechtel or August 22, 2003 for CYAPC).  A trial has been scheduled for spring of 2006.  

In the prejudgment remedy proceeding before the Court, Bechtel sought garnishment of the CYAPC decommissioning trust and related payments.  In October 2004, Bechtel and CYAPC entered into an agreement under which Bechtel waived its right to seek garnishment of the decommissioning trust and related payments in return for the potential attachment of CYAPC’s real property in Connecticut and the escrowing of $41.7 million the sponsors are scheduled to pay to CYAPC through June 30, 2007 in respect to CYAPC’s common equity.  This stipulation is subject to approval of the Court and would not be implemented until the Court found that such assets were subject to attachment.  CYAPC has contested the attachability of such assets.  The DPUC is an intervenor in this proceeding.  NU cannot predict the timing and the outcome of the litigation with Bechtel.

Spent Nuclear Fuel Litigation:  CYAPC, Yankee Atomic Electric Company (YAEC) and Maine Yankee Atomic Power Company (MYAPC) (collectively, the Yankee Companies) also commenced litigation in 1998 charging that the federal government breached contracts it entered into with each company in 1983 under the Nuclear Waste Policy Act of 1982 (the Act).  Under the Act, the DOE was to begin removing spent nuclear fuel from the nuclear plants of the Yankee Companies no later than January 31, 1998 in return for payments by each company into the nuclear waste fund.  No fuel has been collected by the DOE, and spent nuclear fuel is stored on the sites of the Yankee Companies’ plants.  The Yankee Companies collected the funds for payments into the nuclear waste fund from wholesale utility customers under FERC-approved contract rates.  The wholesale utility customers in turn collect these payments from their retail electric customers.  The Yankee Companies’ individual damage claims attributed to the government’s breach totaling $548 million are specific to each plant and include incremental storage, security, construction and other costs through 2010.  The CYAPC damage claim is $197 million, the YAEC damage claim is $191 million and the MYAPC damage claim is $160 million.

The DOE trial ended on August 31, 2004 and a verdict has not been reached.  The current Yankee Companies’ rates do not include an amount for recovery of damages in this matter.  Management cannot predict either the outcome of this matter or its ultimate impact on NU.

Yankee Atomic Electric Company: During the course of carrying out decommissioning work at the unit’s site, YAEC has identified increases in the scope of soil remediation and certain other remediation required to meet environmental standards, beyond the levels assumed in its 2003 decommissioning estimate.  YAEC is continuing to evaluate the impact of the additional requirements on its decommissioning plan.  While that evaluation is not complete, YAEC has determined that the schedule for the completion of physical work will need to extend until mid-2006 and the costs of completing decommissioning will be approximately $63 million greater than the estimate that formed the basis of its 2003 FERC settlement.  Most of the cost increase relates to decommissioning expenditures that will be made during 2006.  In order to fund these additional costs, YAEC is preparing an application to the FERC for increased decommissioning charges to go into effect in early 2006, subject to FERC acceptance and approval.  The timing and amount of the FERC application and the increase in decommissioning charges are under development, but YAEC expects that it will seek rate recovery of a significant component of the increased expenditures during 2006.  NU has a 38.5 percent ownership interest in YAEC, and NU’s share of this increase would total approximately $24 million.  The company cannot at this time predict the timing or outcome of a FERC proceeding required for the collection of the increased YAEC decommissioning costs.  The company believes that

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the costs have been prudently incurred and will ultimately be recovered from the customers of CL&P, PSNH and WMECO. However, there is a risk that some portion of these increased costs may not be recovered, or will have to be refunded if recovered, as a result of the FERC proceedings.  

E.

Consolidated Edison, Inc. Merger Litigation

Certain gain and loss contingencies continue to exist with regard to the October 13, 1999 Agreement and Plan of Merger between NU and Consolidated Edison, Inc. (CEI) and the related litigation.  On October 12, 2005, a panel of three judges at the United States Court of Appeals for the Second Circuit determined that NU shareholders do not have the right to assert a claim against CEI for damages related to breach of the agreement.  The ruling left intact the remaining claims between NU and CEI for breach of contract, which include NU’s claim for recovery of costs and expenses of approximately $32 million and CEI’s claim for damages of “at least $314 million.”  NU filed for a rehearing and requested review by the full Court of Appeals on October 26, 2005.  At this stage, NU cannot predict the outcome of this matter or its ultimate effect on NU.  

8.

MARKETABLE SECURITIES

The following is a summary of NU’s available-for-sale securities related to NU’s investment in Globix Corporation (Globix), NU’s SERP assets and WMECO’s prior spent nuclear fuel trust assets, which are included in current and long-term marketable securities on the accompanying condensed consolidated balance sheets:  

	At September 30, 2005	At December 31, 2004
(Millions of Dollars)
Globix investment	$    5.3	$      (a)
SERP assets	56.7	55.1
WMECO prior spent nuclear fuel trust assets	50.4	49.3
Totals	$112.4	$104.4

(a)

At December 31, 2004, NU’s investment in NEON Communications, Inc. (NEON) was not a marketable equity security.  On March 8, 2005, NEON merged with Globix, and NU’s investment in Globix became a marketable equity security at that time.    

	At September 30, 2005
(Millions of Dollars)	Amortized Cost	Pre-Tax Gross Unrealized Gains	Pre-Tax Gross Unrealized Losses	Estimated Fair Value
United States equity securities	$  29.3	$4.0	$(5.1)	$  28.2
Non-United States equity securities	5.3	1.5	-	6.8
Fixed income securities	77.8	0.3	(0.7)	77.4
Totals	$112.4	$5.8	$(5.8)	$112.4

	At December 31, 2004
(Millions of Dollars)	Amortized Cost	Pre-Tax Gross Unrealized Gains	Pre-Tax Gross Unrealized Losses	Estimated Fair Value
United States equity securities	$  19.3	$3.8	$(0.2)	$  22.9
Non-United States equity securities	5.6	1.3	-	6.9
Fixed income securities	74.7	0.3	(0.4)	74.6
Totals	$ 99.6	$5.4	$(0.6)	$104.4

At September 30, 2005 and December 31, 2004, NU has evaluated the securities in an unrealized loss position and has determined that none of the related unrealized losses are deemed to be other-than-temporary in nature.

For information related to the change in net unrealized holding gains and losses included in shareholders’ equity, see Note 9, “Comprehensive Income,” to the condensed consolidated financial statements.

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For the three months and nine months ended September 30, 2005 and 2004, realized gains and losses recognized on the sale of available-for-sale securities are as follows (in millions):

	Three Months Ended September 30,			Nine Months Ended September 30,
	Realized Gains	Realized Losses	Net Realized Gains/(Losses)	Realized Gains	Realized Losses	Net Realized Gains
2005	$0.2	$(0.3)	$(0.1)	$0.8	$(0.5)	$0.3
2004	$0.2	$(0.1)	$  0.1	$0.7	$(0.1)	$0.6

For the three months ended September 30, 2005 and 2004, realized gains of $0.1 million are included in other income, net on the accompanying condensed consolidated statements of (loss)/income.  For the three months ended September 30, 2005, a realized loss of $0.2 million relating to the WMECO spent nuclear fuel trust is included in fuel, purchased and net interchange power on the accompanying condensed consolidated statements of (loss)/income.

For the nine months ended September 30, 2005 and 2004, realized gains of $0.5 million and $0.6 million, respectively, are included in other income, net on the accompanying condensed consolidated statements of (loss)/income.  For the nine months ended September 30, 2005, a realized loss of $0.2 million relating to the WMECO spent nuclear fuel trust is included in fuel, purchased and net interchange power on the accompanying condensed consolidated statements of (loss)/income.  

NU utilizes the specific identification basis method for the Globix and SERP securities and the average cost basis method for the WMECO prior spent nuclear fuel trust to compute the realized gains and losses on the sale of available-for-sale securities.

Proceeds from the sale of these securities, including proceeds from short-term investments, totaled $41.9 million and $18.4 million for the three months ended September 30, 2005 and 2004, respectively, and $96.5 million and $31.7 million for the nine months ended September 30, 2005 and 2004, respectively.

At September 30, 2005, the contractual maturities of the available-for-sale securities are as follows (in millions):

	Amortized Cost	Estimated Fair Value
Less than one year	$  46.7	$  51.4
One to five years	38.1	33.3
Six to ten years	7.9	7.9
Greater than ten years	19.7	19.8
Total	$112.4	$112.4

NU’s investment in Globix is included in the one to five years maturity category in the table above.  

9.

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

Total comprehensive income, which includes all comprehensive (loss)/income items by category, for the three months and nine months ended September 30, 2005 and 2004 is as follows (millions of dollars):

	Three Months Ended September 30, 2005
	NU*	CL&P	PSNH	WMECO	NU Enterprises	Yankee Gas	Other
Net (loss)/income	$(94.5)	$26.1	$11.9	$4.8	$(129.6)	$(4.2)	$(3.5)
Comprehensive (loss)/income items:
Qualified cash flow hedging instruments	17.0	-	-	1.0	15.7	0.2	0.1
Unrealized losses on securities	-	-	-	0.1	(0.9)	-	0.8
Net change in comprehensive income items	17.0	-	-	1.1	14.8	0.2	0.9
Total comprehensive (loss)/income	$(77.5)	$26.1	$11.9	$5.9	$(114.8)	$   (4.0)	$(2.6)

	Three Months Ended September 30, 2004
	NU*	CL&P	PSNH	WMECO	NU Enterprises	Yankee Gas	Other
Net (loss)/income	$  (7.9)	$21.7	$18.2	$1.5	$(43.0)	$(3.6)	$(2.7)
Comprehensive (loss)/income items:
Qualified cash flow hedging instruments	(3.9)	-	-	-	(3.9)	-	-
Unrealized losses on securities	(0.4)	-	-	-	(0.2)	-	(0.2)
Net change in comprehensive income items	(4.3)	-	-	-	(4.1)	-	(0.2)
Total comprehensive (loss)/income	$(12.2)	$21.7	$18.2	$1.5	$(47.1)	$(3.6)	$(2.9)

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	Nine Months Ended September 30, 2005
	NU*	CL&P	PSNH	WMECO	NU Enterprises	Yankee Gas	Other
Net (loss)/income	$(239.9)	$62.3	$29.8	$11.9	$(344.1)	$10.3	$(10.1)
Comprehensive (loss)/income items:
Qualified cash flow hedging instruments	22.4	-	-	1.0	22.1	(0.8)	0.1
Unrealized losses on securities	(3.1)	-	-	(0.2)	(2.8)	-	(0.1)
Net change in comprehensive income items	19.3	-	-	0.8	19.3	(0.8)	-
Total comprehensive (loss)/income	$(220.6)	$62.3	$29.8	$12.7	$(324.8)	$ 9.5	$(10.1)

	Nine Months Ended September 30, 2004
	NU*	CL&P	PSNH	WMECO	NU Enterprises	Yankee Gas	Other
Net income/(loss)	$83.5	$65.1	$36.0	$8.7	$(20.2)	$8.5	$(14.6)
Comprehensive income/(loss) items:
Qualified cash flow hedging instruments	15.4	-	-	-	15.3	-	0.1
Unrealized losses on securities	(0.6)	-	-	-	-	-	(0.6)
Net change in comprehensive income items	14.8	-	-	-	15.3	-	(0.5)
Total comprehensive (loss)/income	$98.3	$65.1	$36.0	$8.7	$(4.9)	$8.5	$(15.1)

*After preferred dividends of subsidiary.

Comprehensive income amounts included in the Other column primarily relate to NU parent and NUSCO.

Accumulated other comprehensive income fair value adjustments in NU’s qualified cash flow hedging instruments for the nine months ended September 30, 2005 and the twelve months ended December 31, 2004 are as follows:

	Nine Months Ended September 30, 2005	Twelve Months Ended December 31, 2004
Balance at beginning of period	$(3.5)	$24.8
Hedged transactions recognized into earnings	1.5	(57.8)
Change in fair value	15.8	25.0
Cash flow transactions entered into for the period	5.1	4.5
Net change associated with the current period   hedging transactions	22.4	(28.3)
Total fair value adjustments included in   accumulated other comprehensive income/(loss)	$18.9	$(3.5)

Accumulated other comprehensive income items unrelated to NU’s qualified cash flow hedging instruments totaled $0.8 million in losses and $2.3 million in gains at September 30, 2005 and December 31, 2004, respectively.  These amounts relate to unrealized (loss)/gains on investments in marketable debt and equity securities and minimum pension liability adjustments, net of related income taxes.

10.

EARNINGS PER SHARE (NU)

EPS is computed based upon the weighted average number of common shares outstanding during each period.  Diluted EPS is computed on the basis of the weighted average number of common shares outstanding plus the potential dilutive effect if certain securities are converted into common stock.  At September 30, 2005 and 2004, 1,224,834 options and 647,856 options, respectively, were excluded from the following table as these options were antidilutive.  The following table sets forth the components of basic and fully diluted EPS:

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	Three Months Ended September 30,		Nine Months Ended September 30,
(Millions of Dollars, Except for Share Information)	2005	2004	2005	2004
(Loss)/income from continuing operations	$(92.0)	$(9.3)	$(218.5)	$83.9
(Loss)/income from discontinued operations	(2.5)	1.4	(21.4)	(0.4)
Net (loss)/income	(94.5)	(7.9)	(239.9)	83.5
Basic EPS common shares outstanding (average)	129,957,408	128,279,814	129,585,519	128,064,364
Dilutive effects of employee stock options	-	-	-	166,903
Fully diluted EPS common shares   outstanding (average)	129,957,408	128,279,814	129,585,519	128,231,267
Basic and Fully Diluted EPS:
(Loss)/income from continuing operations	(0.71)	(0.07)	(1.68)	0.65
(Loss)/income from discontinued operations	(0.02)	0.01	(0.17)	-
Basic and fully diluted EPS	$(0.73)	$(0.06)	$(1.85)	$0.65

11.

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 the majority of 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).  The components of net periodic benefit expense for the Pension Plan and the PBOP Plan for the three months and nine months ended September 30, 2005 and 2004 are estimated as follows:

NU	For Three Months Ended September 30,				For the Nine Months Ended September 30,
	Pension Benefits		Postretirement Benefits		Pension Benefits		Postretirement Benefits
(Millions of Dollars)	2005	2004	2005	2004	2005	2004	2005	2004
Service cost	$12.1	$10.2	$ 2.2	$  1.5	$36.4	$   30.5	$ 6.0	$  4.5
Interest cost	31.3	29.7	6.3	6.3	94.0	89.2	18.9	19.0
Expected return on plan assets	(42.9)	(43.8)	(3.3)	(3.2)	(128.8)	(131.3)	(8.9)	(9.4)
Amortization of unrecognized net   transition (asset)/obligation	-	(0.3)	2.9	3.0	(0.2)	(1.1)	8.9	8.9
Amortization of prior service cost	1.8	1.8	(0.1)	(0.1)	5.3	5.4	(0.3)	(0.3)
Amortization of actuarial loss	8.3	3.7	-	-	24.8	11.5	-	-
Other amortization, net	-	-	4.6	2.9	-	-	13.2	8.6
Total - net periodic expense	$10.6	$ 1.3	$12.6	$10.4	$31.5	$    4.2	$37.8	$31.3

A portion of these pension amounts is capitalized related to current employees that are working on capital projects.  Amounts capitalized were $2.3 million and approximately $7 million for the three months and nine months ended September 30, 2005, respectively, and $0.7 million and $2 million for the three months and nine months ended September 30, 2004, respectively.  

CL&P	For Three Months Ended September 30,				For the Nine Months Ended September 30,
	Pension Benefits		Postretirement Benefits		Pension Benefits		Postretirement Benefits
(Millions of Dollars)	2005	2004	2005	2004	2005	2004	2005	2004
Service cost	$ 4.3	$3.7	$0.7	$0.5	$12.8	$ 11.0	$ 2.1	$ 1.6
Interest cost	11.7	11.2	2.6	2.6	35.0	33.6	7.7	7.9
Expected return on plan assets	(20.0)	(20.3)	(1.3)	(1.1)	(59.9)	(60.9)	(3.5)	(3.5)
Amortization of unrecognized net   transition (asset)/obligation	-	(0.2)	1.6	1.6	-	(0.6)	4.7	4.7
Amortization of prior service cost	0.7	0.7	-	-	2.2	2.2	-	-
Amortization of actuarial loss	3.1	1.3	-	-	9.4	3.9	-	-
Other amortization, net	-	-	1.8	1.2	-	-	5.3	3.6
Total - net periodic   (income)/expense	$(0.2)	$(3.6)	$5.4	$4.8	$(0.5)	$(10.8)	$16.3	$14.3

For CL&P, a portion of these pension amounts is capitalized related to current employees that are working on capital projects. Amounts capitalized were $0.2 million and $0.5 million for the three months and nine months ended September 30, 2005, respectively, and $1.6 million and $4.9 million for the three months and nine months ended September 30, 2004, respectively.  The capitalized amounts offset capital project costs, as pension income was recorded for the three and nine months ended September 30, 2005 and 2004 as noted in the above table.  

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PSNH	For Three Months Ended September 30,				For the Nine Months Ended September 30,
	Pension Benefits		Postretirement Benefits		Pension Benefits		Postretirement Benefits
(Millions of Dollars)	2005	2004	2005	2004	2005	2004	2005	2004
Service cost	$2.2	$1.8	$0.4	$0.3	$ 6.6	$5.6	$1.2	$0.9
Interest cost	4.8	4.5	1.1	1.1	14.4	13.5	3.3	3.2
Expected return on plan assets	(4.1)	(4.3)	(0.5)	(0.5)	(12.4)	(12.9)	(1.5)	(1.6)
Amortization of unrecognized net   transition (asset)/obligation	0.1	0.1	0.6	0.6	0.3	0.2	1.9	1.9
Amortization of prior service cost	0.3	0.4	-	-	1.1	1.1	-	-
Amortization of actuarial loss	1.2	0.6	-	-	3.6	1.8	-	-
Other amortization, net	-	-	0.8	0.4	-	-	2.2	1.2
Total - net periodic expense	$4.5	$3.1	$2.4	$1.9	$13.6	$9.3	$7.1	$5.6

For PSNH, a portion of these pension amounts is capitalized related to current employees that are working on capital projects. Amounts capitalized were $1.2 million and $3.7 million for the three months and nine months ended September 30, 2005, respectively, and $0.9 million and $2.6 million for the three months and nine months ended September 30, 2004, respectively.  

WMECO	For Three Months Ended September 30,				For the Nine Months Ended September 30,
	Pension Benefits		Postretirement Benefits		Pension Benefits		Postretirement Benefits
(Millions of Dollars)	2005	2004	2005	2004	2005	2004	2005	2004
Service cost	$ 0.8	$  0.7	$0.2	$0.1	$2.5	$2.2	$0.5	$0.4
Interest cost	2.3	2.2	0.5	0.6	7.0	6.6	1.6	1.7
Expected return on plan assets	(4.3)	(4.4)	(0.3)	(0.3)	(13.0)	(13.2)	(0.9)	(0.9)
Amortization of unrecognized net   transition (asset)/obligation	-	(0.1)	0.3	0.3	-	(0.2)	1.0	1.0
Amortization of prior service cost	0.2	0.2	-	-	0.5	0.5	-	-
Amortization of actuarial loss	0.6	0.2	-	-	1.8	0.6	-	-
Other amortization, net	-	-	0.4	0.2	-	-	1.0	0.6
Total - net periodic   (income)/expense	$(0.4)	$(1.2)	$1.1	$0.9	$(1.2)	$(3.5)	$3.2	$2.8

For WMECO, a portion of these pension amounts is capitalized related to current employees that are working on capital projects. Amounts capitalized were $0.1 million and $0.3 million for the three months and nine months ended September 30, 2005, respectively, and $0.4 million and $1.2 million for the three months and nine months ended September 30, 2004, respectively.  The capitalized amounts offset capital project costs, as pension income was recorded for the three and nine months ended September 30, 2005 and 2004 as noted in the above table.  

NU does not currently expect to make any contributions to the Pension Plan in 2005.  However, the company would likely make a contribution to the Pension Plan in 2005 if it was determined that there was a reasonable possibility that the accumulated benefit obligation would exceed plan assets.  NU contributed and anticipates contributing approximately $12.6 million quarterly totaling approximately $50 million in 2005 to fund its PBOP Plan.  

12.

SEGMENT INFORMATION (All Companies)

NU is organized between the Utility Group 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 they operate.  Effective January 1, 2005, the portion of NGS’ business that supports NGC’s and HWP’s generation assets has been reclassified from the services and other segment to the merchant energy segment within the NU Enterprises segment.  Segment information for all periods presented has been restated to conform to the current presentation.  

The Utility Group segment, including both the regulated electric distribution and transmission businesses, as well as the gas distribution business comprised of Yankee Gas, represents approximately 69 percent and 70 percent of NU’s total revenues for the nine months ended September 30, 2005 and 2004, respectively, and includes the operations of the regulated electric utilities, CL&P, PSNH and WMECO, whose 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 businesses.  Utility Group 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.

The NU Enterprises merchant energy business segment includes Select Energy, NGC, NGS, and the generation operations of HWP, while the NU Enterprises services and other business segment includes E. S. Boulos Company, Woods Electrical Co., Inc., and NGS Mechanical, Inc., which are subsidiaries of NGS, SESI, SECI, Reeds Ferry Supply Co. Inc., HEC/Tobyhanna Energy Project, Inc. and HEC/CJTS Energy Center LLC, Woods Network, and intercompany eliminations.  The results of NU Enterprises parent are also

28

included within services and other.  In the first quarter of 2005, the decision was made to exit the wholesale marketing business and the energy services businesses.  For further information regarding NU Enterprises’ merchant energy business and services businesses, which are being divested, see Note 2, “Wholesale Contract Market Changes,” Note 3, “Restructuring and Impairment Charges,” and Note 4, “Assets Held for Sale and Discontinued Operations,” to the condensed consolidated financial statements.  

NU announced its decision to also exit its retail marketing and merchant generation businesses.  See Note 13 "Subsequent Events," to the condensed consolidated financial statements.

There were no CL&P transitional standard offer (TSO) purchases from Select Energy for the nine months ended September 30, 2005. Total Select Energy revenues from CL&P for other transactions with CL&P, represented $14.3 million and $41.0 million for the three and nine months ended September 30, 2005.  Effective January 1, 2004, Select Energy began serving a portion of CL&P’s TSO load for 2004.  Total Select Energy revenues from CL&P for CL&P’s TSO load and for other transactions with CL&P, represented $160.4 million and $474.9 million for the three and nine months ended September 30, 2004, respectively, of total NU Enterprises’ revenues. Total CL&P purchases from Select Energy are eliminated in consolidation.

WMECO’s purchases from Select Energy for standard offer and default service and for other transactions with Select Energy represented $35.9 million for the nine months ended September 30, 2005, and $28.5 million and $81.5 million for the three and nine months ended September 30, 2004, respectively.  Total WMECO purchases from Select Energy are eliminated in consolidation.  

Select Energy revenues related to contracts with NSTAR companies represented $6 million and $294.6 million for the three and nine months ended September 30, 2005, respectively, and $93.2 million and $251.6 million for the three and nine months ended September 30, 2004, respectively.  Revenues related to New Jersey basic generation service represented $84.8 million and $228 million for the three and nine months ended September 30, 2005, respectively, and $108.9 million and $238.5 million for the three and nine months ended September 30, 2004, respectively.  Revenues from Constellation Energy Commodities Group, Inc. represented $124.9 million and $282.2 million for the three and nine months ended September 30, 2005, respectively, and $99.8 million and $287.3 million for the three and nine months ended September 30, 2004, respectively.   No other individual customer represented in excess of 10 percent of NU Enterprises’ revenues for the three and nine months ended September 30, 2005 or 2004.  

Due to the decision to exit the wholesale business, all wholesale revenues, including intercompany revenues, have been included in fuel, purchased and net interchange power beginning in the second quarter of 2005.

Other in the NU consolidated tables includes the results for Mode 1 Communications, Inc., an investor in Globix, the results of the non-energy-related subsidiaries of Yankee (Yankee Energy Services Company, Yankee Energy Financial Services Company, and NorConn Properties, Inc.), the non-energy operations of HWP, and the results of NU’s parent and service companies.  Interest expense included in other primarily relates to the debt of NU parent.  

NU’s segment information for the three and nine months ended September 30, 2005 and 2004 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, 2005
	Utility Group
	Distribution (1)
(Millions of Dollars)	Electric	Gas	Transmission	NU Enterprises	Other	Eliminations	Total
Operating revenues	$1,321.5	$59.9	$42.8	$338.2	$84.9	$(92.4)	$1,754.9
Depreciation and amortization	(168.8)	(5.7)	(6.0)	(3.4)	(4.5)	3.5	(184.9)
Wholesale contract market   Changes, net	-	-	-	(101.2)	-	-	(101.2)
Restructuring and   impairment charges	-	-	-	(4.8)	-	-	(4.8)
Other operating expenses	(1,070.9)	(58.2)	(18.6)	(385.7)	(79.2)	87.2	(1,525.4)
Operating income/(loss)	81.8	(4.0)	18.2	(156.9)	1.2	(1.7)	(61.4)
Interest expense, net of AFUDC	(41.7)	(4.3)	(3.9)	(11.9)	(9.0)	3.6	(67.2)
Interest income	1.2	0.1	0.1	1.0	3.5	(4.3)	1.6
Other income/(loss), net	7.3	0.2	(0.1)	(1.7)	16.0	(15.1)	6.6
Income tax (expense)/benefit	(16.6)	3.8	(2.1)	42.4	2.4	(0.1)	29.8
Preferred dividends	(1.4)	-	-	-	-	-	(1.4)
Income/(loss) from   continuing operations	30.6	(4.2)	12.2	(127.1)	14.1	(17.6)	(92.0)
Loss from discontinued   operations	-	-	-	(2.5)	-	-	(2.5)
Net income/(loss)	$    30.6	$(4.2)	$12.2	$(129.6)	$14.1	$(17.6)	$   (94.5)

29

	For the Nine Months Ended September 30, 2005
	Utility Group
	Distribution (1)
(Millions of Dollars)	Electric	Gas	Transmission	NU Enterprises	Other	Eliminations	Total
Operating revenues	$3,602.1	$  343.0	$124.7	$1,513.1	$   253.7	$  (317.1)	$  5,519.5
Depreciation and amortization	(386.5)	(16.5)	(17.7)	(11.2)	(13.3)	10.1	(435.1)
Wholesale contract market   Changes, net	-	-	-	(359.7)	-	-	(359.7)
Restructuring and   impairment charges	-	-	-	(28.4)	-	-	(28.4)
Other operating expenses	(2,991.0)	(299.9)	(51.8)	(1,552.5)	(239.8)	302.3	(4,832.7)
Operating income/(loss)	224.6	26.6	55.2	(438.7)	0.6	(4.7)	(136.4)
Interest expense, net of AFUDC	(129.3)	(12.7)	(11.3)	(35.6)	(25.3)	11.4	(202.8)
Interest income	3.0	0.3	0.4	3.3	11.6	(13.4)	5.2
Other income/(loss), net	15.2	(0.6)	(1.7)	(5.8)	89.7	(87.1)	9.7
Income tax (expense)/benefit	(36.9)	(3.3)	(11.0)	154.1	7.1	-	110.0
Preferred dividends	(4.2)	-	-	-	-	-	(4.2)
Income/(loss) from   continuing operations	72.4	10.3	31.6	(322.7)	83.7	(93.8)	(218.5)
Loss from discontinued   operations	-	-	-	(21.4)	-	-	(21.4)
Net income/(loss)	$     72.4	$     10.3	$ 31.6	$ (344.1)	$     83.7	$     (93.8)	$   (239.9)
Total assets (2)	$8,645.3	$1,117.8	$       -	$3,097.3	$4,225.2	$(4,156.2)	$12,929.4
Cash flows for total   investments in plant	$   287.1	$     46.6	$166.2	$    13.4	$       8.2	$            -	$     521.5

	For the Three Months Ended September 30, 2004
	Utility Group
	Distribution (1)
(Millions of Dollars)	Electric	Gas	Transmission	NU Enterprises	Other	Eliminations	Total
Operating revenues	$1,037.7	$48.2	$40.8	$695.4	$74.1	$(271.7)	$1,624.5
Depreciation and amortization	(124.9)	(6.6)	(6.1)	(4.7)	(4.2)	3.5	(143.0)
Other operating expenses	(827.8)	(45.7)	(18.3)	(754.0)	(72.1)	269.9	(1,448.0)
Operating income/(loss)	85.0	(4.1)	16.4	(63.3)	(2.2)	1.7	33.5
Interest expense, net of AFUDC	(39.2)	(4.3)	(3.0)	(11.3)	(6.4)	2.7	(61.5)
Interest income	2.2	-	0.1	0.6	3.5	(3.5)	2.9
Other income/(loss), net	1.7	(0.2)	(0.3)	(0.6)	18.1	(15.6)	3.1
Income tax (expense)/benefit	(17.9)	5.0	(2.2)	30.2	2.3	(3.3)	14.1
Preferred dividends	(1.4)	-	-	-	-	-	(1.4)
Income/(loss) from   Continuing operations	30.4	(3.6)	11.0	(44.4)	15.3	(18.0)	(9.3)
Income from   discontinued operations	-	-	-	1.4	-	-	1.4
Net income/(loss)	$     30.4	$(3.6)	$11.0	$(43.0)	$15.3	$(18.0)	$    (7.9)

	For the Nine Months Ended September 30, 2004
	Utility Group
	Distribution (1)
(Millions of Dollars)	Electric	Gas	Transmission	NU Enterprises	Other	Eliminations	Total
Operating revenues	$3,061.4	$291.4	$105.4	$2,033.2	$209.9	$(792.5)	$4,908.8
Depreciation and amortization	(340.2)	(19.4)	(16.1)	(13.9)	(11.6)	9.8	(391.4)
Other operating expenses	(2,474.5)	(250.9)	(48.7)	(2,018.6)	(207.2)	787.0	(4,212.9)
Operating income/(loss)	246.7	21.1	40.6	0.7	(8.9)	4.3	304.5
Interest expense, net of AFUDC	(118.4)	(12.7)	(8.7)	(33.2)	(18.9)	8.2	(183.7)
Interest income	4.2	0.1	0.1	1.5	9.4	(9.1)	6.2
Other income/(loss), net	6.8	(0.8)	(0.5)	(1.9)	65.3	(67.5)	1.4
Income tax (expense)/benefit	(48.8)	0.8	(8.0)	13.1	11.3	(8.7)	(40.3)
Preferred dividends	(4.2)	-	-	-	-	-	(4.2)
Income/(loss) from   continuing operations	86.3	8.5	23.5	(19.8)	58.2	(72.8)	83.9
Loss from discontinued   operations	-	-	-	(0.4)	-	-	(0.4)
Net income/(loss)	$      86.3	$   8.5	$  23.6	$  (20.2)	$ 58.2	$ (72.9)	$     83.5
Cash flows for total   investments in plant	$    270.9	$ 33.9	$114.4	$   13.9	$17.0	$       -	$  450.1

(1)

Includes PSNH’s generation activities.  

30

(2)

Information for segmenting total assets between electric distribution and transmission is not available at September 30, 2005. On a NU consolidated basis, these distribution and transmission assets are disclosed in the electric distribution column above.  

Utility Group segment information related to the regulated electric distribution and transmission businesses for CL&P, PSNH and WMECO for the three and nine months ended September 30, 2005 and 2004 is as follows:

	CL&P – For the Three Months Ended September 30, 2005
(Millions of Dollars)	Distribution	Transmission	Totals
Operating revenues	$923.4	$29.0	$952.4
Depreciation and amortization	(83.6)	(4.4)	(88.0)
Other operating expenses	(791.9)	(11.5)	(803.4)
Operating income	47.9	13.1	61.0
Interest expense, net of AFUDC	(26.6)	(3.0)	(29.6)
Interest income	0.9	0.1	1.0
Other income/(loss), net	8.0	(0.1)	7.9
Income tax expense	(12.3)	(0.5)	(12.8)
Preferred dividends	(1.4)	-	(1.4)
Net income	$ 16.5	$ 9.6	$ 26.1

	CL&P - For the Nine Months Ended September 30, 2005
(Millions of Dollars)	Distribution	Transmission	Totals
Operating revenues	$2,505.3	$  83.6	$2,588.9
Depreciation and amortization	(204.0)	(13.1)	(217.1)
Other operating expenses	(2,170.3)	(32.1)	(2,202.4)
Operating income	131.0	38.4	169.4
Interest expense, net of AFUDC	(83.7)	(8.7)	(92.4)
Interest income	2.4	0.3	2.7
Other income/(loss), net	17.0	(1.7)	15.3
Income tax expense	(22.7)	(5.8)	(28.5)
Preferred dividends	(4.2)	-	(4.2)
Net income	$     39.8	$  22.5	$    62.3
Cash flows for total investments in plant	$   171.1	$137.9	$  309.0

	CL&P – For the Three Months Ended September 30, 2004
(Millions of Dollars)	Distribution	Transmission	Totals
Operating revenues	$699.4	$26.1	$725.5
Depreciation and amortization	(56.8)	(4.0)	(60.8)
Other operating expenses	(587.9)	(11.9)	(599.8)
Operating income	54.7	10.2	64.9
Interest expense, net of AFUDC	(24.7)	(2.2)	(26.9)
Interest income	2.0	0.1	2.1
Other income/(loss), net	3.2	(0.2)	3.0
Income tax expense	(19.2)	(0.8)	(20.0)
Preferred dividends	(1.4)	-	(1.4)
Net income	$  14.6	$ 7.1	$ 21.7

	CL&P - For the Nine Months Ended September 30, 2004
(Millions of Dollars)	Distribution	Transmission	Totals
Operating revenues	$2,083.4	$  69.9	$2,153.3
Depreciation and amortization	(170.6)	(11.4)	(182.0)
Other operating expenses	(1,760.9)	(32.0)	(1,792.9)
Operating income	151.9	26.5	178.4
Interest expense, net of AFUDC	(75.4)	(6.3)	(81.7)
Interest income	3.7	0.1	3.8
Other income/(loss), net	11.6	(0.3)	11.3
Income tax expense	(38.0)	(4.5)	(42.5)
Preferred dividends	(4.2)	-	(4.2)
Net income	$    49.6	$  15.5	$    65.1
Cash flows for total investments in plant	$  192.5	$105.7	$  298.2

31 

	PSNH – For the Three Months Ended September 30, 2005
(Millions of Dollars)	Distribution (1)	Transmission	Totals
Operating revenues	$298.0	$9.3	$307.3
Depreciation and amortization	(78.8)	(1.1)	(79.9)
Other operating expenses	(195.9)	(5.0)	(200.9)
Operating income	23.3	3.2	26.5
Interest expense, net of AFUDC	(10.8)	(0.6)	(11.4)
Interest income	0.2	-	0.2
Other (loss)/income, net	(1.2)	0.1	(1.1)
Income tax expense	(1.1)	(1.2)	(2.3)
Net income	$ 10.4	$1.5	$ 11.9

	PSNH - For the Nine Months Ended September 30, 2005
(Millions of Dollars)	Distribution (1)	Transmission	Totals
Operating revenues	$808.6	$27.2	$835.8
Depreciation and amortization	(166.2)	(3.2)	(169.4)
Other operating expenses	(576.7)	(13.1)	(589.8)
Operating income	65.7	10.9	76.6
Interest expense, net of AFUDC	(32.9)	(1.7)	(34.6)
Interest income	0.4	0.1	0.5
Other loss, net	(2.4)	-	(2.4)
Income tax expense	(6.8)	(3.5)	(10.3)
Net income	$  24.0	$  5.8	$  29.8
Cash flows for total investments in plant	$101.9	$22.6	$124.5

	PSNH – For the Three Months Ended September 30, 2004
(Millions of Dollars)	Distribution (1)	Transmission	Totals
Operating revenues	$247.7	$11.2	$258.9
Depreciation and amortization	(58.1)	(1.7)	(59.8)
Other operating expenses	(164.3)	(4.4)	(168.7)
Operating income	25.3	5.1	30.4
Interest expense, net of AFUDC	(11.1)	(0.5)	(11.6)
Interest income	0.1	-	0.1
Other loss, net	(1.2)	(0.1)	(1.3)
Income tax benefit/(expense)	1.4	(0.8)	0.6
Net income	$ 14.5	$ 3.7	$ 18.2

	PSNH - For the Nine Months Ended September 30, 2004
(Millions of Dollars)	Distribution (1)	Transmission	Totals
Operating revenues	$705.3	$ 24.2	$729.5
Depreciation and amortization	(139.5)	(3.4)	(142.9)
Other operating expenses	(493.1)	(11.4)	(504.5)
Operating income	72.7	9.4	82.1
Interest expense, net of AFUDC	(32.6)	(1.3)	(33.9)
Interest income	0.2	-	0.2
Other loss, net	(3.5)	(0.2)	(3.7)
Income tax expense	(6.7)	(2.0)	(8.7)
Net income	$ 30.1	$  5.9	$ 36.0
Cash flows for total investments in plant	$ 68.7	$17.9	$ 86.6

(1)

Includes PSNH’s generation activities.  

32 

	WMECO  - For the Three Months Ended September 30, 2005
(Millions of Dollars)	Distribution	Transmission	Totals
Operating revenues	$100.0	$4.6	$104.6
Depreciation and amortization	(6.5)	(0.5)	(7.0)
Other operating expenses	(83.1)	(2.2)	(85.3)
Operating income	10.4	1.9	12.3
Interest expense, net of AFUDC	(4.3)	(0.3)	(4.6)
Interest income	0.2	(0.1)	0.1
Other income, net	0.6	-	0.6
Income tax expense	(3.2)	(0.4)	(3.6)
Net income	$  3.7	$1.1	$  4.8

	WMECO  - For the Nine Months Ended September 30, 2005
(Millions of Dollars)	Distribution	Transmission	Totals
Operating revenues	$288.4	$13.9	$302.3
Depreciation and amortization	(16.3)	(1.5)	(17.8)
Other operating expenses	(244.2)	(6.5)	(250.7)
Operating income	27.9	5.9	33.8
Interest expense, net of AFUDC	(12.8)	(0.8)	(13.6)
Interest income	0.2	-	0.2
Other income, net	0.6	-	0.6
Income tax expense	(7.3)	(1.8)	(9.1)
Net income	$  8.6	$ 3.3	$ 11.9
Cash flows for total investments in plant	$22.8	$ 8.0	$ 30.8

	WMECO  - For the Three Months Ended September 30, 2004
(Millions of Dollars)	Distribution	Transmission	Totals
Operating revenues	$90.7	$ 3.5	$94.2
Depreciation and amortization	(10.0)	(0.5)	(10.5)
Other operating expenses	(75.6)	(1.9)	(77.5)
Operating income	5.1	1.1	6.2
Interest expense, net of AFUDC	(3.4)	(0.3)	(3.7)
Interest income	-	-	-
Other loss, net	(0.3)	-	(0.3)
Income tax expense	(0.1)	(0.6)	(0.7)
Net income	$ 1.3	$ 0.2	$ 1.5

	WMECO  - For the Nine Months Ended September 30, 2004
(Millions of Dollars)	Distribution	Transmission	Totals
Operating revenues	$273.0	$11.2	$284.2
Depreciation and amortization	(30.2)	(1.3)	(31.5)
Other operating expenses	(220.7)	(5.2)	(225.9)
Operating income	22.1	4.7	26.8
Interest expense, net of AFUDC	(10.4)	(0.9)	(11.3)
Interest income	0.2	-	0.2
Other loss, net	(1.3)	(0.1)	(1.4)
Income tax expense	(4.0)	(1.6)	(5.6)
Net income	$   6.6	$ 2.1	$  8.7
Cash flows for total investments in plant	$ 21.6	$ 3.5	$25.1

33 

NU Enterprises' segment information for the three and nine months ended September 30, 2005 and 2004 is as follows.  Eliminations are included in the services and other column:  

	NU Enterprises - For the Three Months Ended September 30, 2005
(Millions of Dollars)	Merchant Energy	Services and  Other	Totals
Operating revenues	$ 311.8	$26.4	$ 338.2
Depreciation and amortization	(3.2)	(0.2)	(3.4)
Wholesale contract market changes, net	(101.2)	-	(101.2)
Restructuring and impairment charges	(4.2)	(0.6)	(4.8)
Other operating expenses	(359.6)	(26.1)	(385.7)
Operating loss	(156.4)	(0.5)	(156.9)
Interest expense	(11.7)	(0.2)	(11.9)
Interest income	0.9	0.1	1.0
Other (loss)/income, net	(1.9)	0.2	(1.7)
Income tax benefit	42.0	0.4	42.4
Loss from continuing operations	(127.1)	-	(127.1)
Loss from discontinued operations	-	(2.5)	(2.5)
Net loss	$(127.1)	$(2.5)	$(129.6)

	NU Enterprises - For the Nine Months Ended September 30, 2005
(Millions of Dollars)	Merchant Energy	Services and Other	Totals
Operating revenues	$1,435.8	$  77.3	$1,513.1
Depreciation and amortization	(10.6)	(0.6)	(11.2)
Wholesale contract market changes, net	(359.7)	-	(359.7)
Restructuring and impairment charges	(19.8)	(8.7)	(28.4)
Other operating expenses	(1,466.3)	(86.1)	(1,552.5)
Operating loss	(420.6)	(18.1)	(438.7)
Interest expense	(35.3)	(0.3)	(35.6)
Interest income	2.6	0.7	3.3
Other loss, net	(5.2)	(0.6)	(5.8)
Income tax benefit	148.9	5.2	154.1
Loss from continuing operations	(309.6)	(13.1)	(322.7)
Loss from discontinued operations	-	(21.4)	(21.4)
Net loss	$ (309.6)	$(34.5)	$ (344.1)
Total assets	$2,906.9	$190.4	$3,097.3
Cash flows for total investments in plant	$     13.4	$       -	$     13.4

	NU Enterprises - For the Three Months Ended September 30, 2004
(Millions of Dollars)	Merchant Energy	Services and Other	Totals
Operating revenues	$665.8	$29.6	$695.4
Depreciation and amortization	(4.5)	(0.2)	(4.7)
Other operating expenses	(722.9)	(31.1)	(754.0)
Operating loss	(61.6)	(1.7)	(63.3)
Interest expense	(11.3)	-	(11.3)
Interest income	0.5	0.1	0.6
Other loss, net	(0.6)	-	(0.6)
Income tax benefit	29.6	0.6	30.2
Loss from continuing operations	(43.4)	(1.0)	(44.4)
Income from discontinued operations	-	1.4	1.4
Net (loss)/income	$(43.4)	$ 0.4	$(43.0)

34 

	NU Enterprises - For the Nine Months Ended September 30, 2004
(Millions of Dollars)	Merchant Energy	Services and Other	Totals
Operating revenues	$1,955.3	$77.9	$2,033.2
Depreciation and amortization	(13.2)	(0.7)	(13.9)
Other operating expenses	(1,938.9)	(79.7)	(2,018.6)
Operating income/(loss)	3.2	(2.5)	0.7
Interest expense	(33.1)	(0.1)	(33.2)
Interest income	1.4	0.1	1.5
Other loss, net	(1.9)	-	(1.9)
Income tax benefit	12.1	1.0	13.1
Loss from continuing operations	(18.3)	(1.5)	(19.8)
Loss from discontinued operations	-	(0.4)	(0.4)
Net loss	$  (18.3)	$ (1.9)	$  (20.2)
Cash flows for total investments in plant	$    13.9	$       -	$    13.9

13.

SUBSEQUENT EVENTS (NU, NU Enterprises)

A.

Exit From Retail Marketing Business and Competitive Generation Business

On November 7, 2005, NU announced it would exit the remainder of its merchant energy business segment, which includes the retail marketing business and the competitive generation business.  This decision creates certain loss contingencies that could be material and could include:

·

The change from accrual accounting to fair value accounting for energy contracts that are derivatives and the resulting recognition of mark-to-market losses or gains on changes in fair value of the contracts.

·

The impairment of long-lived assets, including generation assets, if expected sales prices are less than their carrying values.  The carrying value of Select Energy’s long-lived assets is approximately $10 million and the carrying value of the generation assets of NGC and HWP is approximately $825 million.  

·

The recognition of losses associated with settling energy contracts at values different than our mark-to-market at the time of settlement.  

·

The recognition of closure costs such as severance, benefit plan curtailments, and lease termination payments.  

·

The impairment of the $3.2 million of goodwill at the merchant energy segment if expected cash flows that support the fair values of the reporting units is reduced significantly by a decision to sell all or portions of the reporting units at prices less than carrying values.  

·

The impairment of intangible assets with a book value of approximately $2 million if expected cash flows that support them are reduced to below their carrying values.

NU may record charges in the fourth quarter of 2005 associated with these matters.  The level of those charges will depend on a number of factors, including how the disposition of those businesses is accomplished.  

B.

Wholesale Contract Updates

On October 28, 2005, Select Energy signed a contract with a third party wholesale power marketer to assign certain sales and purchase obligations in New England that extend to 2009.  This transaction terminated approximately 1 million megawatt-hours of net sales obligations.  Select Energy will pay $55.9 million in December 2005 and recognize a pre-tax loss in the fourth quarter of 2005 of $11.8 million when the termination value for these obligations is compared to the September 30, 2005 mark-to-market.

NU expects, at present price levels, to record a pre-tax charge of $37 million in the fourth quarter to purchase supply for an increase in the load forecasts related to a full requirements contract.  

35 

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Trustees and Shareholders of

Northeast Utilities

Berlin, Connecticut

We have reviewed the accompanying condensed consolidated balance sheet of Northeast Utilities and subsidiaries (the “Company”) as of September 30, 2005, and the related condensed consolidated statements of (loss)/income for the three-month and nine-month periods ended September 30, 2005 and 2004, and of cash flows for the nine-month periods ended September 30, 2005 and 2004. 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 Notes 2 and 3, the Company recorded significant charges in the three-month and nine-month periods ended September 30, 2005 in connection with its decision to exit certain business lines. Also, as discussed in Note 4, prior periods’ financial statements have been restated to reflect the exit of certain components of the Company’s energy services businesses as discontinued operations.

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 the Company as of December 31, 2004, 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 March 16, 2005 (which report expressed explanatory paragraphs related to the restatement of the consolidated balance sheet as of December 31, 2003 and the related consolidated statement of cash flows for the year then ended and the adoption of Financial Accounting Standards Board Interpretation No. 46, Consolidation of Variable Interest Entities), 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, 2004 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 4, 2005

36 

THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES

37

THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
	September 30,	December 31,
	2005	2004
	(Thousands of Dollars)
ASSETS
Current Assets:
Cash	$                     1,546	$                       5,608
Investments in securitizable assets	220,942	139,391
Receivables, less provision for uncollectible
accounts of $2,436 in 2005 and $2,010 in 2004	69,261	69,892
Accounts receivable from affiliated companies	16,522	66,386
Unbilled revenues	6,648	8,189
Taxes receivable	-	766
Materials and supplies, at average cost	32,425	33,213
Derivative assets - current	100,021	24,243
Prepayments and other	28,223	16,187
	475,588	363,875
Property, Plant and Equipment:
Electric utility	3,857,726	3,671,767
Less: Accumulated depreciation	1,151,358	1,089,872
	2,706,368	2,581,895
Construction work in progress	345,569	242,982
	3,051,937	2,824,877
Deferred Debits and Other Assets:
Regulatory assets	1,358,950	1,526,359
Prepaid pension	318,959	318,559
Derivative assets - long-term	303,550	167,122
Other	135,842	115,466
	2,117,301	2,127,506
Total Assets	$              5,644,826	$                5,316,258
The accompanying notes are an integral part of these condensed consolidated financial statements.

38 

THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
	September 30,	December 31,
	2005	2004
	(Thousands of Dollars)
LIABILITIES AND CAPITALIZATION
Current Liabilities:
Notes payable to banks	$                   30,000	$                     15,000
Notes payable to affiliated companies	9,825	90,025
Accounts payable	241,304	166,520
Accounts payable to affiliated companies	31,977	89,242
Accrued taxes	43,290	-
Accrued interest	15,084	14,203
Derivative liabilities - current	-	4,408
Other	71,868	65,951
	443,348	445,349
Rate Reduction Bonds	890,009	995,233
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	781,278	761,036
Accumulated deferred investment tax credits	86,613	88,540
Deferred contractual obligations	236,288	281,633
Regulatory liabilities	724,812	614,770
Derivative liabilities - long-term	32,200	42,809
Other	93,192	95,505
	1,954,383	1,884,293
Capitalization:
Long-Term Debt	1,256,803	1,052,891
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 2005 and 2004	60,352	60,352
Capital surplus, paid in	555,040	415,140
Retained earnings	369,070	347,176
Accumulated other comprehensive loss	(379)	(376)
Common Stockholder’s Equity	984,083	822,292
Total Capitalization	2,357,086	1,991,383
Commitments and Contingencies (Note 7)
Total Liabilities and Capitalization	$              5,644,826	$                5,316,258
The accompanying notes are an integral part of these condensed consolidated financial statements.

39

THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
		Three Months Ended		Nine Months Ended
		September 30,		September 30,
		2005	2004	2005	2004
	(Thousands of Dollars)
Operating Revenues		$            952,444	$              725,532	$        2,588,913	$    2,153,302
Operating Expenses:
Operation -
Fuel, purchased and net interchange power		590,091	434,690	1,613,087	1,295,954
Other		144,326	109,035	399,608	325,472
Maintenance		28,341	22,600	70,820	57,447
Depreciation		33,509	30,181	98,966	88,231
Amortization of regulatory assets, net		23,046	1,140	28,254	9,723
Amortization of rate reduction bonds		31,477	29,472	89,855	84,020
Taxes other than income taxes		40,608	33,476	118,910	114,070
Total operating expenses		891,398	660,594	2,419,500	1,974,917
Operating Income		61,046	64,938	169,413	178,385
Interest Expense:
Interest on long-term debt		15,548	10,390	43,505	30,635
Interest on rate reduction bonds		13,707	15,727	42,677	48,445
Other interest		327	743	6,271	2,648
Interest expense, net		29,582	26,860	92,453	81,728
Other Income, Net		8,787	5,052	17,979	15,150
Income Before Income Tax Expense		40,251	43,130	94,939	111,807
Income Tax Expense		12,788	20,056	28,500	42,475
Net Income		27,463	23,074	66,439	69,332
Preferred Dividends of Subsidiary		1,390	1,390	4,169	4,169
Income Available for Common Stockholder		$              26,073	$              21,684	$              62,270	$         65,163

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

40 

THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
	Nine Months Ended
	September 30,
	2005	2004
	(Thousands of Dollars)
Operating Activities:
Net income	$                   66,439	$                 69,332
Adjustments to reconcile to net cash flows
provided by operating activities:
Bad debt expense	9,871	5,655
Depreciation	98,966	88,231
Deferred income taxes and investment tax credits, net	7,574	69,398
Amortization of regulatory assets, net	28,254	9,723
Amortization of rate reduction bonds	89,855	84,020
Amortization/deferral of recoverable energy costs	15,008	(31,572)
Pension expense/(income)	548	(5,072)
Regulatory refunds	(75,020)	(31,839)
Deferred contractual obligations	(45,436)	(29,997)
Other sources of cash	10,059	16,749
Other uses of cash	(18,430)	(14,300)
Changes in current assets and liabilities:
Receivables and unbilled revenues, net	42,165	34,822
Materials and supplies	788	(1,405)
Investments in securitizable assets	(81,551)	(46,056)
Other current assets	(11,976)	(11,564)
Accounts payable	(28,676)	(25,562)
Accrued taxes	44,056	(51,740)
Other current liabilities	6,747	(1,595)
Net cash flows provided by operating activities	159,241	127,228
Investing Activities:
Investments in plant	(308,955)	(298,173)
Restricted cash - LMP costs	-	93,630
Net proceeds from sale of property	21,993	-
Proceeds from sales of investment securities	1,289	1,090
Purchases of investment securities	(1,331)	(1,590)
Other investing activities	458	(459)
Net cash flows used in investing activities	(286,546)	(205,502)
Financing Activities:
Issuance of long-term debt	200,000	280,000
Reacquisitions and retirements of long-term debt	-	(59,000)
Retirement of rate reduction bonds	(105,224)	(98,390)
Capital contribution from Northeast Utilities	140,009	58,000
Increase in short-term debt	15,000	-
NU Money Pool lending	(80,200)	(44,900)
Cash dividends on preferred stock	(4,169)	(4,169)
Cash dividends on common stock	(40,376)	(35,306)
Other financing activities	(1,797)	(643)
Net cash flows provided by financing activities	123,243	95,592
Net (decrease)/increase in cash	(4,062)	17,318
Cash - beginning of period	5,608	5,814
Cash - end of period	$                    1,546	$                   23,132
The accompanying notes are an integral part of these condensed consolidated financial statements.

41 

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42 

PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES

43 

PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
	September 30,	December 31,
	2005	2004
	(Thousands of Dollars)
ASSETS
Current Assets:
Cash	$                  4,806	$                     4,855
Receivables, less provision for uncollectible
accounts of $2,637 in 2005 and $1,764 in 2004	91,776	75,019
Accounts receivable from affiliated companies	16,997	34,341
Unbilled revenues	37,409	39,397
Notes receivable from affiliated companies	12,100	-
Taxes receivable	-	4,498
Fuel, materials and supplies, at average cost	47,269	52,479
Prepayments and other	4,620	13,092
	214,977	223,681
Property, Plant and Equipment:
Electric utility	1,709,535	1,627,174
Other	5,675	5,675
	1,715,210	1,632,849
Less: Accumulated depreciation	687,522	664,336
	1,027,688	968,513
Construction work in progress	90,177	63,190
	1,117,865	1,031,703
Deferred Debits and Other Assets:
Regulatory assets	822,200	900,115
Other	89,058	57,200
	911,258	957,315
Total Assets	$            2,244,100	$              2,212,699
The accompanying notes are an integral part of these condensed consolidated financial statements.

44 

PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
	September 30,	December 31,
	2005	2004
	(Thousands of Dollars)
LIABILITIES AND CAPITALIZATION
Current Liabilities:
Notes payable to banks	$                 20,000	$                   10,000
Notes payable to affiliated companies	-	20,400
Accounts payable	61,308	51,786
Accounts payable to affiliated companies	15,924	38,591
Accrued taxes	41,033	-
Accrued interest	14,240	11,799
Unremitted rate reduction bond collections	10,265	7,880
Other	11,757	12,629
	174,527	153,085
Rate Reduction Bonds	395,035	428,769
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	259,996	311,998
Accumulated deferred investment tax credits	1,329	1,625
Deferred contractual obligations	44,976	54,459
Regulatory liabilities	387,115	323,707
Accrued pension	70,740	57,199
Other	23,578	24,968
	787,734	773,956
Capitalization:
Long-Term Debt	457,198	457,190
Common Stockholder’s Equity:
Common stock, $1 par value - authorized
100,000,000 shares; 301 shares outstanding
in 2005 and 2004	-	-
Capital surplus, paid in	175,055	156,532
Retained earnings	254,666	243,277
Accumulated other comprehensive loss	(115)	(110)
Common Stockholder’s Equity	429,606	399,699
Total Capitalization	886,804	856,889
Commitments and Contingencies (Note 7)
Total Liabilities and Capitalization	$            2,244,100	$              2,212,699
The accompanying notes are an integral part of these condensed consolidated financial statements.

45 

PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
	Three Months Ended		Nine Months Ended
	September 30,		September 30,
	2005	2004	2005		2004
	(Thousands of Dollars)
Operating Revenues	$            307,305	$            258,876	$              835,782	$           729,472
Operating Expenses:
Operation -
Fuel, purchased and net interchange power	134,569	106,897	383,056	308,899
Other	43,124	40,770	129,998	119,324
Maintenance	13,758	12,426	48,868	49,581
Depreciation	11,755	11,882	34,596	34,646
Amortization of regulatory assets, net	56,199	36,615	99,907	75,565
Amortization of rate reduction bonds	11,907	11,251	34,820	32,719
Taxes other than income taxes	9,434	8,649	27,911	26,634
Total operating expenses	280,746	228,490	759,156	647,368
Operating Income	26,559	30,386	76,626	82,104
Interest Expense:
Interest on long-term debt	4,886	4,609	14,760	12,550
Interest on rate reduction bonds	5,928	6,656	18,346	20,423
Other interest	597	358	1,506	963
Interest expense, net	11,411	11,623	34,612	33,936
Other Loss, Net	(968)	(1,141)	(1,904)	(3,400)
Income Before Income Tax Expense/(Benefit)	14,180	17,622	40,110	44,768
Income Tax Expense/(Benefit)	2,259	(617)	10,338	8,744
Net Income	$              11,921	$              18,239	$              29,772	$             36,024
The accompanying notes are an integral part of these condensed consolidated financial statements.

46

PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
	Nine Months Ended
	September 30,
	2005	2004
	(Thousands of Dollars)
Operating activities:
Net income	$                 29,772	$                 36,024
Adjustments to reconcile to net cash flows
provided by operating activities:
Bad debt expense	3,147	1,485
Depreciation	34,596	34,646
Deferred income taxes and investment tax credits, net	(49,238)	(20,871)
Amortization of regulatory assets, net	99,907	75,565
Amortization of rate reduction bonds	34,820	32,719
Pension expense	9,837	6,747
Regulatory overrecoverries/(refunds)	5,444	(4,131)
Deferred contractual obligations	(9,417)	7,807
Other sources of cash	3,713	11,126
Other uses of cash	(15,681)	(23,803)
Changes in current assets and liabilities:
Receivables and unbilled revenues, net	(572)	(33,481)
Fuel, materials and supplies	(8,800)	320
Other current assets	8,575	5,392
Accounts payable	(11,574)	(16,650)
Accrued taxes	45,531	6,374
Other current liabilities	3,957	2,702
Net cash flows provided by operating activities	184,017	121,971
Investing Activities:
Investments in plant	(124,489)	(86,566)
Net proceeds from sale of property	857	-
Proceeds from sales of investment securities	2,208	1,868
Purchases of investment securities	(2,282)	(2,725)
Other investing activities	(4,515)	308
Net cash flows used in investing activities	(128,221)	(87,115)
Financing Activities:
Issuance of long-term debt	-	50,000
Retirement of rate reduction bonds	(33,734)	(31,746)
Increase/(decrease) in short-term debt	10,000	(10,000)
NU Money Pool lending	(32,500)	(26,000)
Capital contribution from Northeast Utilities	18,644	-
Cash dividends on common stock	(18,383)	(18,186)
Other financing activities	128	(226)
Net cash flows used in financing activities	(55,845)	(36,158)
Net decrease in cash	(49)	(1,302)
Cash - beginning of period	4,855	2,737
Cash - end of period	$                   4,806	$                   1,435
The accompanying notes are an integral part of these condensed consolidated financial statements.

47 

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48

WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY

49 

WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
	September 30,		December 31,
	2005		2004
	(Thousands of Dollars)
ASSETS
Current Assets:
Cash		$                     1,408		$                     1,678
Receivables, less provision for uncollectible
accounts of $3,831 in 2005 and $2,563 in 2004		38,728		37,909
Accounts receivable from affiliated companies		10,214		11,275
Unbilled revenues		12,056		15,057
Taxes receivable		-		4,824
Materials and supplies, at average cost		1,275		1,488
Marketable securities		15,722		18,481
Prepayments and other		766		1,027
		80,169		91,739
Property, Plant and Equipment:
Electric utility		657,472		640,884
Less: Accumulated depreciation		190,546		183,361
		466,926		457,523
Construction work in progress		21,991		11,361
		488,917		468,884
Deferred Debits and Other Assets:
Regulatory assets		215,033		231,907
Prepaid pension		80,931		79,706
Marketable securities		35,218		31,342
Other		24,048		20,008
		355,230		362,963
Total Assets		$                 924,316		$                 923,586
The accompanying notes are an integral part of these condensed consolidated financial statements.

50 

WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
	September 30,	December 31,
	2005	2004
	(Thousands of Dollars)
LIABILITIES AND CAPITALIZATION
Current Liabilities:
Notes payable to banks	$                         7,000	$                   25,000
Notes payable to affiliated companies	1,400	15,900
Accounts payable	21,545	12,860
Accounts payable to affiliated companies	5,579	20,965
Accrued taxes	6,474	544
Accrued interest	1,674	3,515
Other	9,502	10,491
	53,174	89,275
Rate Reduction Bonds	114,098	122,489
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	219,190	220,705
Accumulated deferred investment tax credits	2,738	2,990
Deferred contractual obligations	64,505	76,965
Regulatory liabilities	24,110	25,160
Other	9,138	13,846
	319,681	339,666
Capitalization:
Long-Term Debt	259,085	207,684
Common Stockholder’s Equity:
Common stock, $25 par value - authorized
1,072,471 shares; 434,653 shares outstanding
in 2005 and 2004	10,866	10,866
Capital surplus, paid in	82,979	76,103
Retained earnings	83,754	77,565
Accumulated other comprehensive income/(loss)	679	(62)
Common Stockholder’s Equity	178,278	164,472
Total Capitalization	437,363	372,156
Commitments and Contingencies (Note 7)
Total Liabilities and Capitalization	$                       924,316	$                 923,586
The accompanying notes are an integral part of these condensed consolidated financial statements.

51 

WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
	Three Months Ended			Nine Months Ended
		September 30,			September 30,
		2005	2004		2005	2004
		(Thousands of Dollars)
Operating Revenues		$            104,611	$              94,238		$             302,263	$             284,216
Operating Expenses:
Operation -
Fuel, purchased and net interchange power		62,698	54,970		179,756	161,121
Other		16,346	15,470		50,376	44,442
Maintenance		3,742	4,074		11,777	11,210
Depreciation		4,079	3,800		12,147	11,219
Amortization of regulatory (liabilities)/assets, net		182	4,144		(2,753)	12,429
Amortization of rate reduction bonds		2,739	2,563		8,354	7,840
Taxes other than income taxes		2,475	3,061		8,767	9,183
Total operating expenses		92,261	88,082		268,424	257,444
Operating Income		12,350	6,156		33,839	26,772
Interest Expense:
Interest on long-term debt		2,468	1,530		6,794	4,475
Interest on rate reduction bonds		1,867	2,062		5,752	6,316
Other interest		265	136		1,012	567
Interest expense, net		4,600	3,728		13,558	11,358
Other Income/(Loss), Net		720	(258)		829	(1,176)
Income Before Income Tax Expense		8,470	2,170		21,110	14,238
Income Tax Expense		3,613	633		9,158	5,575
Net Income		$                4,857	$                1,537		$               11,952	$                 8,663

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

52

WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
	Nine Months Ended
	September 30,
	2005	2004
	(Thousands of Dollars)
Operating Activities:
Net income	$                   11,952	$                    8,663
Adjustments to reconcile to net cash flows
provided by operating activities:
Bad debt expense	2,933	3,266
Depreciation	12,147	11,219
Deferred income taxes and investment tax credits, net	(110)	1,248
Amortization of regulatory (liabilities)/assets, net	(2,753)	12,429
Amortization of rate reduction bonds	8,354	7,840
Amortization of recoverable energy costs	1,612	448
Pension income	(521)	(1,997)
Regulatory overrecoveries	5,722	3,836
Deferred contractual obligations	(12,394)	8,178
Other sources of cash	2,669	388
Other uses of cash	(8,167)	(13,855)
Changes in current assets and liabilities:
Receivables and unbilled revenues, net	310	(4,540)
Materials and supplies	213	(97)
Other current assets	261	(1,985)
Accounts payable	(12,183)	2,324
Accrued taxes	10,754	(198)
Other current liabilities	(2,089)	66
Net cash flows provided by operating activities	18,710	37,233
Investing Activities:
Investments in plant	(30,792)	(25,135)
Net proceeds from sale of property	1,599	-
Proceeds from sales of investment securities	59,413	303
Purchases of investment securities	(60,606)	(49,552)
Other investing activities	1,458	654
Net cash flows used in investing activities	(28,928)	(73,730)
Financing Activities:
Issuance of long-term debt	50,000	50,000
Retirement of rate reduction bonds	(8,391)	(7,882)
Decrease in short-term debt	(18,000)	(10,000)
NU Money Pool (lending)/borrowing	(14,500)	2,800
Capital contribution from Northeast Utilities	6,920	6,500
Cash dividends on common stock	(5,763)	(4,864)
Other financing activities	(318)	(57)
Net cash flows provided by financing activities	9,948	36,497
Net decrease in cash	(270)	-
Cash - beginning of period	1,678	1
Cash - end of period	$                     1,408	$                           1
The accompanying notes are an integral part of these condensed consolidated financial statements.

53 

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 2005 reports on Form 10-Q and the NU 2004 Form 10-K.  All per share amounts are reported on a fully diluted basis.

FINANCIAL CONDITION AND BUSINESS ANALYSIS

Executive Summary

Strategy, Results and Outlook:

·

In March of 2005, Northeast Utilities (NU or the company) decided to exit its competitive wholesale marketing and energy services businesses.  On November 7, 2005, NU announced its decision to exit the remainder of its competitive businesses, including its competitive generation and retail marketing businesses.  Depending upon the net proceeds available from any sale, these proceeds could provide additional resources for the company’s regulated capital spending programs.  The company has determined that the electric transmission investment required to maintain a reliable system in New England is now substantially greater than what the company previously forecasted.  The New England Independent System Operator (ISO-NE) has recently determined that more than half of the new investment that needs to be made in the New England high-voltage system is in the NU service territory.  Management believes that the decision to exit its competitive businesses and focus entirely on its regulated businesses is appropriate because it simplifies the company’s business model, increases earnings predictability, lowers its operating risk, enhances its financial flexibility and can support earnings and dividend growth.  To implement this decision, the company has initiated a process to sell its 1,440 megawatts (MW) of competitive generation assets in Massachusetts and Connecticut, and its retail marketing business.  Management expects to complete the divestiture of all its competitive businesses in 2006.

·

At September 30, 2005, the retail marketing business had contracts to sell approximately 4.6 million megawatt-hours to commercial and retail customers from 2006 through 2008 in the northeast United States.  Approximately 2 million of those megawatt-hours will be sold in New England, and that supply was expected to be sourced through Northeast Generation Company (NGC) and Holyoke Water Power Company (HWP) units.  The internal price reflected in retail marketing results is well below the current market price in New England.  If, as part of the sales process, NGC and HWP no longer supply those retail contracts, and the retail marketing business had to obtain alternative power supplies at today’s prices, then it would sustain a material loss.  The company may also be required to record retail contracts currently on accrual accounting on a mark-to-market basis.  If mark-to-market accounting is requir ed, a material charge would be recorded in the fourth quarter based on current price levels.

·

NU Enterprises has signed agreements to terminate virtually all of its New England wholesale marketing obligations, effective January 1, 2006.  In connection with those agreements, NU Enterprises paid approximately $131 million to six municipal electric systems in the third quarter of 2005 and will pay another approximately $100 million to counterparties in the fourth quarter of 2005.  NU Enterprises also has reached agreements to sell two of its six services businesses to third parties for a total of approximately $6 million.  Both sales are expected to close in November 2005.  

·

In addition to the initiatives noted above, NU made significant progress in the third quarter of 2005 in deploying capital into the company’s regulated transmission and distribution infrastructure.  The Utility Group’s investment in transmission infrastructure has been focused primarily on CL&P’s four major transmission projects in southwest Connecticut.  Each of these projects has received approval from the Connecticut Siting Council (CSC) and is currently on or ahead of schedule.  The higher level of transmission rate base as a result of these ongoing projects has resulted in an increase in CL&P’s transmission business earnings. CL&P also now has a mechanism that allows for forward-looking transmission charges to be included in its retail transmission rate to promptly recover its transmission expenditures.

·

NU’s third quarter results were negatively impacted by the portions of the wholesale marketing business and the energy services businesses that have not been divested and increasing market prices on the wholesale electricity contracts the company is seeking to divest.  NU lost $94.5 million, or $0.73 per share, in the third quarter of 2005, compared to a net loss of $7.9 million, or $0.06 per share, in the third quarter of 2004.  NU lost $239.9 million, or $1.85 per share, in the first nine months of 2005, compared

54

with earnings of $83.5 million, or $0.65 per share, in the first nine months of 2004.  The 2005 NU losses were due to charges at NU Enterprises, which is exiting the wholesale marketing and energy services businesses.  The results for the third quarter of 2004 include the negative after-tax impact of $47 million related to the mark-to-market accounting for certain natural gas contracts established to mitigate the risk of electricity purchased in anticipation of winning certain levels of wholesale electric load in New England.

·

NU Enterprises lost $129.6 million in the third quarter of 2005 and $344.1 million in the first nine months of 2005, compared with losses of $43 million in the third quarter of 2004 and $20.2 million in the first nine months of 2004.  In the third quarter of 2005, NU Enterprises recorded an after-tax mark-to-market charge of $75 million associated with certain wholesale electric contracts it is seeking to divest (separate from generation and retail mark-to-market changes) and $3.3 million of after-tax restructuring and impairment charges.  During the first nine months of 2005, NU Enterprises recorded an after-tax mark-to-market charge of $239.3 million associated with certain wholesale electric contracts it is seeking to divest (separate from generation and retail mark-to-market changes) and $34.6 million of after-tax restructuring and impairment charges.  Portions of the restructuring and impairment charges are included in discontinued operations.  These losses were also caused by extreme weather-related increases in gas and oil prices in the third quarter negatively affecting wholesale supply obligations which had not been divested as of the end of the quarter.  The results for the third quarter and first nine months of 2004 include the negative after-tax impact of $47 million related to the mark-to-market accounting for certain natural gas contracts established to mitigate the risk of electricity purchased in anticipation of winning certain levels of wholesale electric load in New England.  

·

NU’s future results and liquidity could be materially negatively affected by wholesale energy contracts that require Select Energy to supply full requirements standard offer load and municipal load at prices significantly lower than current market prices. During the third quarter of 2005, sharp increases in energy prices due to weather-related events caused Select Energy to increase its load forecast and purchase additional supply at current high prices.  These amounts have been recorded in the third quarter. During October and early November, additional increases to these load forecasts were necessary, resulting in an additional mark-to-market pre-tax loss of approximately $37 million that will be reflected in the fourth quarter.  In addition, the load under these contracts could further increase in amounts which, at present price levels, could materially increase the potential loss.  

·

NU’s future results and liquidity could also be materially and adversely affected if the cost of settling or assigning its remaining competitive contracts exceeds the mark-to-market amounts estimated for accounting purposes.  During the third quarter of 2005, Select Energy entered into a transaction under which it agreed to pay approximately $20 million in excess of its mark-to-market price to settle a wholesale sales obligation in New England.  Also, subsequent to September 30, 2005, Select Energy entered into another transaction that assigned virtually all of the remaining New England wholesale obligations from January 1, 2006 forward. The cost of this assignment, which will be included in fourth quarter results, was approximately $11 million in excess of the mark-to-market at September 30, 2005.

·

The Utility Group earned $38.6 million in the third quarter of 2005 compared with $37.8 million in 2004 and earned $114.3 million in the first nine months of 2005 compared with $118.3 million in the first nine months of 2004.  Lower year-to-date earnings are primarily due to higher pension, depreciation, and interest expense, and the absence in 2005 of certain positive adjustments that had been reflected in 2004 earnings, offset by retail rate increases at all four regulated companies and a 2.3 percent year-to-date increase in regulated retail electric sales.  Year-to-date 2005 results were also lower as a result of an after-tax charge of $4.4 million related to a final regulatory decision concerning refunds to streetlighting customers at The Connecticut Light and Power Company (CL&P).

·

NU projects Utility Group earnings of between $1.22 per share and $1.30 per share in 2005 and parent and other costs of between $0.08 per share and $0.13 per share in 2005.  The regulated earnings range reflects between $0.96 per share and $1.00 per share at the regulated distribution and generation businesses and between $0.26 per share and $0.30 per share at the regulated transmission business.  The Utility Group currently estimates that the regulated distribution and generation businesses will earn towards the low end of their range and that the transmission business will earn towards the high end of their range.  

·

NU projects Utility Group earnings of between $1.21 per share and $1.31 per share in 2006 and parent and other costs of between $0.09 per share and $0.12 per share in 2006.  The regulated earnings range reflects between $0.89 per share and $0.96 per share at the regulated distribution and generation businesses and between $0.32 per share and $0.35 per share at the regulated transmission business.  The company is not providing 2005 or 2006 earnings guidance for its NU Enterprises businesses, as the earnings of NU Enterprises have been and will continue to be impacted by many factors, including changes in market prices that currently impact earnings because of the application of mark-to-market accounting to certain energy contracts until those contracts are divested or expire, potential further asset impairments or losses on disposals, due to the decision to exit all of the competitive energy businesses, and other closure costs.

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Legislative, Legal and Regulatory Items:

·

On June 8, 2005, the New Hampshire Public Utilities Commission (NHPUC) issued an order lowering the return on equity (ROE) on Public Service Company of New Hampshire’s (PSNH) generating facilities to 9.63 percent from 11 percent, effective July 1, 2005.  On July 7, 2005, PSNH asked the NHPUC to reconsider its decision.  PSNH is awaiting a response from the NHPUC as to this motion.  

·

On June 30, 2005, the Connecticut Department of Public Utility Control (DPUC) issued a final decision in CL&P’s streetlighting docket.  As a result of this decision, CL&P recorded a $4.4 million after-tax charge for streetlight billing in the second quarter of 2005.  CL&P filed an appeal of this decision on August 11, 2005 in the Connecticut Superior Court.  The court has not yet set a schedule for the appeal.

·

On July 6, 2005, Connecticut Governor Rell signed legislation creating a mechanism to allow the DPUC to true-up, at least annually, the retail transmission charge in distribution company rates based on changes in Federal Energy Regulatory Commission (FERC)-approved charges.  This mechanism will allow CL&P to include forward-looking transmission charges in its retail transmission rate and promptly recover its transmission expenditures.

·

On July 22, 2005, Governor Rell signed a bill which provides local electric distribution companies, including CL&P, with financial incentives to promote distributed generation and also provides distribution companies with the possibility of owning generation on a limited basis.  The DPUC has opened a number of new dockets to implement this legislation.   

·

In August 2005, the FERC announced that it would delay the implementation of Locational Installed Capacity (LICAP) until at least October 1, 2006.  On September 20, 2005, the FERC commissioners held a hearing on LICAP and alternatives to LICAP. The FERC has now referred to a settlement judge the development of LICAP alternatives which must be concluded by January 31, 2006.  The FERC has also delayed the implementation of two energy zones in Connecticut pending consideration of further petitions by ISO-NE.  Management cannot at this time predict the outcome of these FERC proceedings.

·

On August 8, 2005, President Bush signed comprehensive federal energy legislation.   Among other provisions potentially affecting NU are the repeal of the Public Utility Holding Company Act of 1935 (PUHCA), FERC backstop siting authority for transmission, transmission pricing and rate reform, renewable production tax credits, and accelerated depreciation for certain new electric and gas facilities.  

·

On September 9, 2005, the DPUC issued a draft decision regarding Yankee Gas Purchased Gas Adjustment (PGA) clause charges for the time 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 Service Company (Yankee Gas) unbilled sales and revenue adjustments.  At the request of Yankee Gas, the DPUC reopened the PGA hearing on September 20, 2005 and requested that Yankee Gas file supplemental information regarding the two adjustments.  Yankee Gas filed the supplemental information on October 3, 2005 and is waiting for the DPUC to establish the remaining schedule.  If upheld, this disallowance would result in a $9 million pre-tax write-off.  Management believes the unbilled sales and revenue adjustments and resultant charges to customers through the PGA clause were appropriate.  Based on the facts of the case and the supplemental information provided to the DPUC, management believes the appropriateness of the PGA charges to customers for the time period under review will be allowed.

·

PSNH’s 2004 stranded cost recovery charge (SCRC) reconciliation filing was filed with the NHPUC on May 2, 2005.  On October 19, 2005, PSNH, the NHPUC staff and the Office of Consumer Advocate reached a settlement agreement in this case. This settlement agreement, which was filed with the NHPUC on October 20, 2005, requires no disallowances and provides for recovery of unbilled revenues.  The NHPUC held a hearing on the merits of the settlement agreement on October 26, 2005, and a decision is expected later this year.  

·

On September 30, 2005, PSNH filed a petition with the NHPUC requesting a change in transition energy service/default energy service (TS/DS) rates for the period February 1, 2006 through January 31, 2007.  In its filing, PSNH did not request a specific TS/DS rate; rather, given the current price volatility in the energy markets, PSNH requested that the NHPUC review and approve its underlying operational data within the September 30, 2005 filing.  In December 2005, PSNH expects to petition for a specific TS/DS rate based on updated market information.  Management expects the NHPUC to issue an order prior to February 1, 2006.

·

On October 12, 2005, a panel of three judges at the United States Court of Appeals for the Second Circuit determined that NU shareholders do not have the right to assert a claim against Consolidated Edison, Inc. (CEI) for damages related to breach of their agreement.  The ruling left intact the remaining claims between NU and CEI for breach of contract, which include NU’s claim for recovery of costs and expenses of approximately $32 million and CEI’s claim for damages of “at least $314 million.”  NU filed

56

for a rehearing and requested review by the full Court of Appeals on October 26, 2005.  At this stage, NU cannot predict the outcome of this matter or its ultimate effect on NU.  

Liquidity:

·

The divestiture of NU’s competitive energy businesses, if successfully completed in 2006, will impact NU’s balance sheet and liquidity.  At September 30, 2005, NU’s total long-term and short-term debt, including debt of assets held for sale totaling $92.8 million related to Select Energy Services, Inc. (SESI), totaled approximately $3.4 billion.  Of that sum, approximately $339 million was owed by NGC and $326 million by Select Energy, Inc. (Select Energy) through NU parent.   That amount rose in the third quarter of 2005 as a result of $131 million of long-term wholesale electric contract buyouts by Select Energy.  Management believes that a successful divestiture of NU’s competitive businesses will lower the enterprise’s aggregate debt levels, significantly reduce the level of outstanding parent guarantees, and help retain the parent company’s investment grade senior unsecured debt ratings.  At this time, management cannot estimate the net proceeds available after the exit from the remaining NU Enterprises businesses.  If net proceeds are available, they will be used to fund NU’s regulated capital programs and repay debt.  

·

To date, NU Enterprises has funded the wholesale buyout arrangements through cash on hand and cash provided by NU parent derived from proceeds of borrowings under the NU parent $500 million revolving credit arrangement.  As a result of the need to fund additional contract buyouts expected in the fourth quarter of 2005 and in 2006, NU filed an application with the Securities and Exchange Commission (SEC) to increase its authorized borrowing limit from $450 million to $700 million.  That application was approved by the SEC on October 28, 2005.  NU is also seeking approval from the banks involved in its revolving credit arrangement to increase borrowing limits to $700 million from $500 million and to extend the agreement from its November 2009 expiration date by approximately one year.  

·

On November 2, 2005, NU arranged a separate $600 million 364-day term liquidity facility which supplements other sources of liquidity.  At the time NU increases its revolving credit agreement from $500 million to $700 million, the $600 million liquidity facility will be reduced to $400 million.  

·

NU has received SEC PUHCA approval to issue up to $750 million of long-term debt and equity and a registration statement for the sale of such shares was declared effective by the SEC on November 3, 2005.  NU is planning to sell approximately $300 million of common equity as early as the fourth quarter of 2005.  Proceeds from the sale will be used to help finance Utility Group capital expenditures and reduce debt associated with terminating certain of NU Enterprises’ long-term wholesale contracts.  

·

On August 11, 2005, Western Massachusetts Electric Company (WMECO) closed on the sale of $50 million 10-year senior notes with an interest rate of 5.24 percent.  On October 5, 2005, PSNH closed on the sale of $50 million 30-year first mortgage bonds with an interest rate of 5.60 percent.  Proceeds from both issuances were used to repay short-term borrowings incurred to finance capital expenditures.

·

Cash flows from operations decreased by $75.8 million to $352.8 million for the first nine months of 2005 from $428.6 million for the first nine months of 2004.  This decrease in cash flows from operations is primarily the result of higher regulatory refunds as CL&P refunds amounts to its ratepayers for past overcollections and $145.2 million of buyouts of long-term wholesale power contracts by NU Enterprises.

Overview

Consolidated:  NU lost $94.5 million, or $0.73 per share, in the third quarter of 2005, compared to a net loss of $7.9 million, or $0.06 per share, in the third quarter of 2004.  NU lost $239.9 million, or $1.85 per share, in the first nine months of 2005, compared with earnings of $83.5 million, or $0.65 per share, in the first nine months of 2004.  A summary of NU’s earnings/ (losses) by major business line for the third quarter and first nine months of 2005 and 2004 is as follows:

	For the Three Months Ended September 30,		For the Nine Months Ended September 30,
(Millions of Dollars)	2005	2004	2005	2004
Utility Group	$  38.6	$37.8	$ 114.3	$118.3
NU Enterprises (1)	(129.6)	(43.0)	(344.1)	(20.2)
Parent and Other	(3.5)	(2.7)	(10.1)	(14.6)
Net (Loss)/Income	$(94.5)	$ (7.9)	$(239.9)	$ 83.5

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(1)

The NU Enterprises losses include losses totaling $2.5 million and $21.4 million for the three months and nine months ended September 30, 2005, respectively, and earnings of $1.4 million and losses of $0.4 million for the three and nine months ended September 30, 2004, respectively, which are classified as discontinued operations.

The 2005 NU losses were due to charges in the competitive businesses conducted by NU Enterprises which NU is seeking to exit.  In the third quarter of 2005, NU Enterprises recorded an after-tax mark-to-market charge of $75 million ($101.2 million pre-tax) associated with certain wholesale electric contracts it is seeking to divest (separate from generation and retail mark-to-market changes) and $3.3 million of after-tax ($5.3 million pre-tax) restructuring and impairment charges.  These losses were also caused by extreme weather-related increases in gas and oil prices in the third quarter negatively affecting wholesale supply obligations which had not been divested as of the end of the quarter. During the first nine months of 2005, NU Enterprises recorded an after-tax mark-to-market charge of $239.3 million ($359.7 million pre-tax) associated with certain wholesale electric contracts it is seeking to divest (separate from generation and retail mark-to-market changes) and $34.6 million of after-tax ($53.1 million pre-tax) restructuring and impairment charges.  Portions of the restructuring and impairment charges are included in discontinued operations.  The 2005 losses were also due to lower margins on wholesale electricity contracts and unseasonably hot weather in the summer of 2005, which resulted in NU Enterprises having to purchase additional energy and capacity at higher prices to serve wholesale load.  The results for the third quarter and first nine months of 2004 include the negative after-tax impact of $47 million related to the mark-to-market accounting for certain natural gas contracts established to mitigate the risk of electricity purchased in anticipation of winning certain levels of wholesale electric load in New England.

Excluding those charges described above, NU Enterprises lost $51.3 million in the third quarter of 2005 and lost $70.2 million in the first nine months of 2005, compared with losses of $43 million in the third quarter of 2004 and $20.2 million in the first nine months of 2004.  

Utility Group:  The Utility Group is comprised of CL&P, PSNH, WMECO, and Yankee Gas, including their transmission, distribution and generation businesses.  After payment of preferred dividends, earnings at the Utility Group increased by $0.8 million to $38.6 million in the third quarter of 2005 compared with $37.8 million in 2004.  Utility Group earnings totaled $114.3 million in the first nine months of 2005 compared with $118.3 million in the first nine months of 2004 as higher pension, depreciation, and interest expense, and the absence of certain positive adjustments that had been reflected in 2004 earnings were offset by 2005 retail rate increases at all four regulated companies and a 2.3 percent increase in regulated retail electric sales.  Those 2004 positive adjustments included a $6 million after-tax ($10.2 million pre-tax) benefit in the third quarter of 2004 resulting from the reconsideration of CL&P’s rate case and a lower effective tax rate at PSNH.

Year-to-date 2005 results were also lower as a result of an after-tax charge of $4.4 million related to a final regulatory decision concerning refunds to streetlighting customers at CL&P’s distribution business along with higher transmission costs which were not automatically passed on to CL&P’s retail customers in the first half of 2005.  

NU’s retail electric sales have been positively impacted by the weather.  For the first nine months of 2005, retail electric sales are 2.3 percent greater than 2004 but 1.0 percent lower than 2004 on a weather normalized basis.  The favorable weather caused NU’s distribution revenues to be approximately $14 million higher than they would have been if weather had been normal, but the general decline in customer usage eroded the positive year-to-date impacts of the weather for 2005.  In addition, from an expense perspective, the hotter than normal weather increased the number of normal and storm-related repairs which in turn increased the companies’ operation and maintenance expenses.  A summary of Utility Group earnings by company for the three and nine months ended September 30, 2005 and 2004 is as follows:

	For the Three Months Ended September 30,		For the Nine Months Ended September 30,
(Millions of Dollars)	2005	2004	2005	2004
CL&P Distribution	$16.5	$14.6	$ 39.8	$  49.6
CL&P Transmission	9.6	7.1	22.5	15.5
Total CL&P *	26.1	21.7	62.3	65.1
PSNH Distribution and Generation	10.4	14.5	24.0	30.1
PSNH Transmission	1.5	3.7	5.8	5.9
Total PSNH	11.9	18.2	29.8	36.0
WMECO Distribution	3.7	1.3	8.6	6.6
WMECO Transmission	1.1	0.2	3.3	2.1
Total WMECO	4.8	1.5	11.9	8.7
Yankee Gas	(4.2)	(3.6)	10.3	8.5
Total Utility Group Net Income	$38.6	$37.8	$114.3	$118.3

*After preferred dividends.

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CL&P’s third quarter 2005 distribution results were higher due primarily to higher sales and a $25 million distribution rate increase effective January 1, 2005, offset by higher depreciation, interest, and pension expense.  Third quarter 2004 distribution results included a positive after-tax impact of approximately $6 million ($10.2 million pre-tax) resulting from the reconsideration of CL&P's rate case.  Year-to-date 2005 distribution results were lower as a result of an after-tax charge of $4.4 million related to a final regulatory decision concerning refunds to streetlighting customers at CL&P along with higher transmission costs which were not automatically passed on to CL&P's retail customers in the first half of 2005.  CL&P transmission earnings were higher due to a higher transmission rate base and higher earnings related to the allowance for funds used during construction.

PSNH third quarter 2005 distribution and generation earnings decreased as compared to the same period of 2004 due to a higher effective tax rate in 2005 as compared with 2004.  The lower 2004 effective tax rate is due to adjustments to tax reserves totaling a positive $5.4 million recorded in the third quarter of 2004 as a result of the actual 2003 tax return amounts being compared to the 2003 year end tax provision estimates.  PSNH transmission earnings for the third quarter and first nine months of 2005 were lower than the same periods in 2004 due to a higher effective tax rate in 2005.  

WMECO third quarter and first nine months of 2005 distribution results increased as a result of higher retail sales and a $6 million annualized distribution rate increase that took effect on January 1, 2005.  Those factors were partially offset by higher interest expense and lower pension income.   WMECO transmission earnings for the three months and nine months ended September 30, 2005 were higher than the same periods in 2004 due to a lower effective tax rate and higher revenues in 2005 as compared to 2004.

Yankee Gas’ third quarter 2005 results were comparable to 2004, but the first nine months of 2005 earnings were higher due to a $14 million annualized rate increase that took effect on January 1, 2005.

NU Enterprises: NU Enterprises is the parent of NGC, Northeast Generation Services Company (NGS) and its subsidiaries, Select Energy, SESI and its subsidiaries, Select Energy Contracting, Inc. (SECI), and Reeds Ferry Supply Co., Inc. (Reeds Ferry), Woods Network Services, Inc. (Woods Network), all of which are collectively referred to as “NU Enterprises.” The generation operations of HWP are also included in the results of NU Enterprises. The companies included in the NU Enterprises segment are grouped into two business segments: the merchant energy segment and the energy services segment all of which it is exiting. The merchant energy business segment is Select Energy’s wholesale marketing business comprised of 1,295 MW of primarily pumped storage and hydroelectric generation assets owned by NGC and 145 MW of coal-fired generation assets owned by HWP; Select Energy’s retail business; and NGS.The energy services businesses consist of E.S. Boulos Company and Woods Electrical, which are subsidiaries of NGS, SESI, SECI, Reeds Ferry, and Woods Network.

NU Enterprises lost $129.6 million in the third quarter of 2005 and $344.1 million in the first nine months of 2005, compared with losses of $43 million in the third quarter of 2004 and $20.2 million in the first nine months of 2004.  A summary of NU Enterprises’ (losses)/earnings by business for the three and nine months ended September 30, 2005 and 2004 is as follows:

	For the Three Months Ended September 30,		For the Nine Months Ended September 30,
(Millions of Dollars)	2005	2004	2005	2004
Merchant Energy	$(127.1)	$(43.4)	$(309.6)	$(18.3)
Energy Services, Parent and Other (1)	(2.5)	0.4	(34.5)	(1.9)
Net Loss	$(129.6)	$(43.0)	$(344.1)	$(20.2)

(1)

The energy services, parent and other (losses)/earnings include losses totaling $2.5 million and $21.4 million for the three and nine months ended September 30, 2005, respectively, and earnings of $1.4 million and losses of $0.4 million for the three and nine months ended September 30, 2004, respectively, which are classified as discontinued operations.

A significant number of factors impacted NU Enterprises’ merchant energy results in the third quarter of 2005.  Extreme weather-related increases in gas and oil prices in the third quarter negatively affected wholesale supply obligations which had not been divested as of the end of the quarter.  In the third quarter of 2005, NU Enterprises also recorded a number of charges related to the merchant energy business.  The more significant of these items include:

·

A net after-tax charge of $59.8 million ($80.6 million pre-tax) related to certain long-dated wholesale electricity contracts in New England and New York with municipal and other customers.  The charge reflects negative mark-to-market movement on certain contracts between June 30, 2005 and September 30, 2005 as a result of rising energy prices, partially offset by the positive effect of buying out certain contracts at prices less than the June 30, 2005 marks.  Included in the net after-tax charge of $59.8 million is $8.7 million ($11.7 million pre-tax) related to certain contracts that NU Enterprises assigned to a third-party wholesale power marketer, obligating that marketer to assume responsibility for certain wholesale power contracts NU Enterprises had in New England, beginning on January 1, 2006.  NU Enterprises will pay that power marketer $15 million in December 2005.  An additional $3.8 million after-tax charge ($5.1 million pre-tax) from this assignment was recorded as a reduction to revenues.  

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·

A net after-tax charge of $15.3 million ($20.6 million pre-tax), which includes approximately $27.5 million (approximately $37 million pre-tax) relating to certain wholesale contracts in the PJM power pool where NU Enterprises increased its estimates of customer load above its original expectations and an additional $2.3 million after-tax charge ($3.1 million pre-tax) from the assignment noted above.  Offsetting these charges is an after-tax net benefit of approximately $14.5 million (approximately $19.5 million pre-tax) associated with the marking-to-market of the supply contracts to serve certain retail electric load and other mark-to-market impacts.

·

An after-tax charge of $19.6 million ($26.5 million pre-tax) associated with the ongoing negative impact of marking-to-market the supply contracts that were expected to serve certain retail electric load.  NU Enterprises recorded an after-tax gain of $59.9 million ($94 million pre-tax) in the first quarter of 2005 and will reverse that gain over the next three years.

·

In addition to the charges noted above, NU Enterprises lost approximately $31 million ($50 million pre-tax) serving load in the third quarter of 2005.  As a result of hot humid summer weather in the mid Atlantic and New England, NU Enterprises was obligated to serve more load than it had anticipated in the third quarter under various full-requirements wholesale contracts.  To serve that load, NU Enterprises needed to purchase energy and capacity at costs higher than what NU Enterprises received from its customers.

In the third quarter of 2004, NU Enterprises recorded an after-tax charge of $47 million associated with marking-to-market certain wholesale natural gas contracts intended to hedge certain wholesale electricity purchase obligations.  

Losses in the first nine months of 2005 were primarily the result of $273.9 million of after-tax ($412.8 million pre-tax) wholesale contract market changes and restructuring and impairment charges at NU Enterprises associated with the decision to exit the wholesale marketing business and divest the energy services businesses. Losses in the first nine months of 2005 also include a negative after-tax mark-to-market change of $25.7 million ($40.7 million pre-tax) on certain wholesale natural gas contracts signed in 2004 to economically hedge Select Energy’s wholesale electricity contracts for 2005 and 2006 that were used in Select Energy’s energy sourcing activities. These positions were balanced by entering into offsetting positions in the first quarter of 2005 and had no impact on the second or third quarter nor will they have an impact on future earnings. Excluding these charges, NU Enterprises lost $44.5 million for the first nine months of 2005.

Retail marketing lost $18.5 million in the third quarter of 2005 and $22 million in the first nine months of 2005.  This loss was primarily the result of a requirement to account for the sourcing of its customers’ electric requirements at March 31, 2005 market prices for supply contracts signed in the past at lower prices.  This was necessitated by the fact that the source of those contracts, wholesale marketing, is being divested, which in turn required these contracts to move from accrual accounting to mark-to-market accounting.  As a result, an after-tax gain on those retail contracts of $59.9 million was recorded in the first quarter of 2005 that represented future margins on existing retail transactions.  The majority of these contracts are being divested, while the retail sales contracts were being retained at that time and remained on accrual accounting through September 30, 2005.  Future quarterly retail energy marketing business results will be negatively affected by this accounting treatment.  The $59.9 million gain will be reversed during the fourth quarter assuming all contracts are derivatives and are marked-to-market as a result of the decision to exit the retail business.  Excluding that impact, which was $19.6 million after-tax in the third quarter and $25.9 million year-to-date, the retail energy marketing business earned $­­­1.1 million in the third quarter and $3.9 million year-to-date.  Management also expects results in NU Enterprises’ retail marketing to be negatively affected by additional electricity sales that had not been fully sourced until the third quarter of 2005.  Sourcing that additional load at current market prices is expected to cost NU Enterprises’ retail group approximately $15 million after-tax (approximately $24 million pre-tax) in 2006 and significantly less in 2007 and 2008.  The decision to exit the retail business may require the company to apply mark-to-market accounting on many of the remaining retail derivative contracts.  At today’s prices, this would result in a significant charge to earnings.  

The termination of several municipal wholesale contracts in New England resulted in NU Enterprises having additional generation from HWP’s Mt. Tom coal-fired plant and NGC’s conventional hydroelectric plants available for sale in the wholesale market.  In 2005, NU Enterprises signed agreements to sell a total of approximately 1.4 million megawatt-hours from Mt. Tom to counterparties during the years 2006 through 2008.  Approximately 1 million megawatt-hours are generated annually at Mt. Tom per year.  Those sales are at prices significantly in excess of Mt. Tom’s locked-in coal cost and are expected to be profitable during that period.  Some of the output from Mt. Tom and the conventional hydroelectric units will also be used to supply certain retail marketing load during this time period.

The services businesses and NU Enterprises parent lost $2.5 million in the third quarter of 2005 and $34.5 million in the first nine months of 2005, primarily as a result of a first-quarter after-tax charge of $25.3 million associated with the impairment of goodwill and intangible assets associated with those businesses and because of write-offs associated with certain construction contracts.  A

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portion of these charges totaling $0.3 million after-tax ($0.5 million pre-tax) and $16.3 million after-tax ($24.7 million pre-tax) for the three and nine months ended September 30, 2005, respectively, is included in the (loss)/income from discontinued operations on the condensed consolidated statements of (loss)/income as the charges relate to services companies that are presented as discontinued operations.

For information regarding the current status of the exit from the wholesale marketing business and divestiture of the energy services businesses see, “NU Enterprises Divestitures,” included in this management’s discussion and analysis.

Parent and Other:  Parent company and other after-tax expenses totaled $3.5 million in the third quarter of 2005, compared with $2.7 million in the same quarter of 2004.  After-tax parent company and other expenses totaled $10.1 million in the first nine months of 2005, compared with $14.6 million in 2004.  The results in 2004 reflected an after-tax write-down of $3.9 million associated with certain investments.

Future Outlook

Utility Group:  The Utility Group continues to estimate that it will earn between $1.22 per share and $1.30 per share in 2005.  That range reflects earnings of between $0.96 per share and $1.00 per share in the regulated distribution and generation businesses and between $0.26 per share and $0.30 per share at the transmission business.  The Utility Group currently estimates that the regulated distribution and generation businesses will earn towards the low end of their range and that the transmission business will earn towards the high end of their range.  

The Utility Group has also established an earnings range of between $1.21 per share and $1.31 per share in 2006.  This range reflects earnings of between $0.89 per share and $0.96 per share in the regulated distribution and generation businesses and between $0.32 per share and $0.35 per share at the transmission business.

NU Enterprises:  The earnings of NU Enterprises have been and will continue to be impacted by many factors, including potential further asset impairments or gains or losses on disposals that could result from the decision to exit all NU Enterprises businesses, the timing of that exit, changes in market prices which currently impact earnings because of the application of mark-to-market accounting to certain energy contracts until those contracts are divested or expire and other closure costs.  Accordingly, NU is not providing NU Enterprises 2005 or 2006 earnings guidance.

Parent and Other:  Parent and other costs, primarily related to interest expense, continue to be estimated to total between $0.08 per share and $0.13 per share in 2005.  Parent and other costs are estimated to total between $0.09 per share and $0.12 per share in 2006.

Liquidity

Consolidated:  NU continues to maintain an adequate level of liquidity.  At September 30, 2005, NU had $86.2 million of cash and cash equivalents on hand compared with $47 million at December 31, 2004.

Cash flows from operations decreased by $75.8 million from $428.6 million for the first nine months of 2004 to $352.8 million for the first nine months of 2005.  This decrease was due to $131 million of third quarter buyouts of long-term wholesale power contracts by NU Enterprises and a $14.2 million first quarter contract termination payment.  This decrease was also due to higher regulatory refunds, primarily due to lower Competitive Transition Assessment (CTA) and Generation Service Charge (GSC) collections as CL&P refunds amounts to its ratepayers for past overcollections or uses those amounts to recover current costs.  In addition, deferred income taxes decreased as a result of mark-to-market changes and restructuring and impairment charges that are not currently deductible  and the expiration of bonus depreciation provisions.  Offsetting the decrease in cash flows from operations is an increase in counterparty deposits relating to the NU Enterprises as a result of increases in market prices of energy.

NU’s cash flows from operations were negative in the fourth quarter of 2004 due to significant regulatory refunds to customers of CL&P. Because CL&P’s regulatory refunds are expected to be minimal in the fourth quarter of 2005, management expects overall Utility Group cash flows from operations to be similar for the full year of 2005 to what they were in 2004 and for Utility Group cash flows to be much higher in the fourth quarter of 2005 than they were in the same period of 2004.  However, management expects cash flows from operations at NU Enterprises to be significantly lower than they were in 2004 due to ongoing efforts to buyout certain long-term wholesale power contracts.  In addition to the $145.2 million spent in 2005, NU Enterprises expects to spend at least another $97 million in the fourth quarter of 2005 related to these buyouts.  

To date, NU Enterprises has funded wholesale buyouts through cash on hand and funds from NU derived from borrowings under the NU parent $500 million revolving credit arrangement.  At September 30, 2005, NU had $243 million drawn on that credit line and another $71 million of LOCs outstanding.  As of October 31, 2005, these amounts were $202 million in advances and $179.9 million in LOCs.  As a result of the need to fund additional contract buyouts expected in the fourth quarter of 2005 and in 2006, NU filed an

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application with the SEC to increase its authorized short-term borrowing limit from $450 million to $700 million.  That application was approved by the SEC on October 28, 2005.  NU is also seeking approval from the banks involved in its revolving credit arrangement to increase borrowing limits to $700 million from $500 million and to extend the agreement from its November 2009 expiration date by approximately one year.  On November 2, 2005, NU arranged a separate $600 million 364-day term liquidity facility, which supplements other sources of liquidity.  At the time NU increases its $500 million revolver to $700 million, the $600 million line will be reduced to $400 million.  Management expects that a separate $400 million revolving credit line for the Utility Group will not increase but that its maturity date will also be extended from its November 2009 expiration date by approximately one year.  The Utility Group had $65 million borrowed on that credit line at September 30, 2005.  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, 2005, CL&P had sold $100 million to that financial institution.

On June 23, 2005, NU filed an application with the SEC seeking authority to issue up to $750 million of new securities, including common equity, preferred stock and long-term debt, which was approved on October 20, 2005.  On October 4, 2005, NU filed an S-3 registration statement with the SEC to issue up to $750 million of equity and/or debt securities.  That registration statement became effective on November 3, 2005.  NU is planning to sell approximately $300 million of common equity as early as the fourth quarter of 2005, which would strengthen NU’s balance sheet.  The proceeds from that issuance will be used to fund the Utility Group’s capital investment initiatives and reduce the debt levels associated with buying out the long-term wholesale power contracts.  In the first nine months of 2005, NU contributed $165.5 million of equity to the Utility Group companies, including $140 million into CL&P. Through October 2005, NU’s regulated companies issued $350 million of long-term debt, including $200 million at CL&P in April, $50 million at Yankee Gas in July, $50 million at WMECO in August, and $50 million at PSNH in October.  At September 30, 2005, total short and long-term debt, excluding rate reduction bonds, represented 61 percent of consolidated capitalization.

Exiting the wholesale marketing business is having a negative impact on cash flows, the ultimate magnitude and timing of which will depend upon the method of exiting.  During 2005, $145.2 million has been paid to terminate contracts, of which $131 million was paid to six municipalities and $14.2 million to another counterparty, and under agreements signed to date, $97 million will be paid in the fourth quarter. Tax benefits associated with those payments, in the form of cash refunds, will be realized in 2006.  

The exit from other NU Enterprises businesses is expected to benefit NU’s liquidity and reduce debt.  NU is seeking to sell 1,440 MW of pumped storage, conventional hydroelectric, coal-fired, and peaking generation owned by NGC and HWP.  At September 30, 2005, NGC had approximately $339 million of debt, approximately $19 million of which was repaid on October 17, 2005.  HWP had no debt owed to external lenders.  Management cannot estimate the sales price for its generation assets.  

In addition to the recently announced sale of generation, negotiations are continuing with a number of parties interested in acquiring NU Enterprises’ services businesses, which have an aggregate book value of $50 million and debt owed to third-party lenders of approximately $90 million.  NU Enterprises also has reached agreements to sell two of its six services businesses to third parties for a total of approximately $6 million.  Both sales are expected to close in November 2005.

NU’s senior unsecured debt is rated Baa2 and BBB- with stable outlook by Moody’s Investors Service (Moody’s) and Standard & Poor’s (S&P), respectively. At October 31, 2005, Select Energy at its current credit ratings levels could have been requested to provide $50.8 million of collateral under certain contracts which counterparties have not required to date. If NU were to be downgraded to a sub-investment grade level, a number of Select Energy’s contracts would require the posting of additional collateral in the form of cash or LOCs in increasing amounts dependent upon the severity of the decline. Were NU’s senior unsecured ratings to be reduced to sub-investment grade by either Moody’s or S&P, Select Energy could, under its present contracts, be asked to provide at September 30, 2005 approximately $533 million of collateral or LOCs to various unaffiliated counterparties and approximately $125 million to several independent system operators and unaffiliated local distribution companies (LDCs). If such a downgrade were to occur, management believes NU would currently be able to provide this collateral. Moody’s and S&P’s secured ratings for NGC are currently below investment grade. The company’s decision to divest its competitive generation could result in a downgrade of NGC debt, but management does not believe that such a downgrade, in and of itself, would have a negative impact on the ratings of NU or any other subsidiary.

On September 30, 2005, NU paid a dividend of $0.175 per share.  On October 11, 2005, the NU Board of Trustees approved a dividend of $0.175 per share, payable December 30, 2005, to shareholders of record at December 1, 2005.

NU's capital expenditures totaled $521.5 million in the first nine months of 2005, compared with $450.1 million in the first nine months of 2004.  The higher level of spending reflects increased investment at the Utility Group.  NU projects capital expenditures to total $740 million in 2005.

Utility Group:  On August 11, 2005, WMECO closed on the sale of $50 million 10-year senior notes with an interest rate of 5.24 percent.  On October 5, 2005, PSNH closed on the sale of $50 million 30-year first mortgage bonds with an interest rate of 5.60 percent.  Proceeds from both issuances were used to repay short-term borrowings incurred to finance capital expenditures.

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NU Enterprises:  Currently, NU Enterprises’ liquidity is impacted by both the amount of collateral from other counterparties it receives and the amount of collateral it is required to deposit with counterparties.  During the first nine months of 2005, liquidity benefited by $45.2 million from counterparty collateral deposits received exceeding counterparty collateral deposits made.  However, NU Enterprises also made $145.2 million of payments to terminate or buyout six municipal and certain other long-term wholesale power contracts and has contracted to pay approximately an additional $97 million in the fourth quarter to terminate eight more municipal contracts and other contracts in New England.  Other charges recorded in the first nine months of 2005 were primarily non-cash in nature.  The cash and liquidity impacts of exiting the wholesale marketing and energy services businesses are discussed above.

Most of the working capital and LOCs required by NU Enterprises are currently used to support the wholesale marketing business.  As NU Enterprises’ wholesale contracts expire or are divested, its liquidity requirements are expected to decline.  However, the sale or renegotiation of additional longer-term below market wholesale power contracts will likely require NU Enterprises to continue to make significant payments to the counterparties in such transactions.

On October 17, 2005, NGC made the final sinking fund payment on the $120 million Series A first-mortgage bonds issued in 2001. NGC has $320 million of Series B first-mortgage bonds outstanding.

NU Enterprises Divestitures

Generation and Retail Marketing Businesses: On November 7, 2005, NU announced the divestiture of the competitive generation and retail marketing businesses of NU Enterprises.  NU had earlier announced the divestiture of its wholesale marketing and energy services businesses in March 2005.  Lazard Fréres & Co. LLC (Lazard) has been retained to advise the company in the divestiture of the wholesale marketing, competitive generation, and retail marketing businesses while FMI Corp. has been assisting NU Enterprises in the sale of the energy services businesses.   

Management has not yet concluded how the divestiture of Select Energy’s retail business, NGC’s generation assets and the generation assets of HWP will be structured.  This will depend in part on market conditions.  NU believes that in any event there will be significant accounting consequences that management is evaluating and with respect to which management will reach a conclusion in the fourth quarter.  This conclusion may result in certain loss contingencies that could be material and could include:

·

The change from accrual accounting to fair value accounting for energy contracts that are derivatives and the resulting recognition of mark-to-market losses or gains on changes in fair value of the contracts. At October 31, 2005, the estimated fair value of retail marketing and merchant generation contracts which are expected to be delivered from January 1, 2006 that have not been marked-to-market is approximately a negative $75 million, which excludes the value provided to retail marketing from merchant generation.  The ultimate value of the contracts depends upon the method and timing of divesting those contracts, as well as market prices at the time of divestiture.  In addition, the amount that may be marked-to-market depends upon whether or not the contract is a derivative.  

·

The impairment of long-lived assets, including generation assets, if expected sales prices are less than their carrying values.  The carrying value of Select Energy’s long-lived assets is approximately $10 million and the carrying value of the generation assets of NGC and HWP is approximately $825 million.  

·

The recognition of losses associated with settling energy contracts at values different than our mark-to-market at the time of settlement.

·

The recognition of closure costs such as severance, benefit plan curtailments, and lease termination payments.  

·

The impairment of the $3.2 million of goodwill at the merchant energy segment if expected cash flows that support the fair values of the reporting units is reduced significantly by a decision to sell all or portions of the reporting units at prices less than carrying values.

·

The impairment of intangible assets with a book value of approximately $2 million if expected cash flows that support them are reduced to below their carrying values.  

NU may record charges in the fourth quarter of 2005 associated with these matters.  The level of those charges will depend on a number of factors, including how the disposition of those businesses is accomplished.

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Wholesale Marketing Business:  NU Enterprises took several steps in the third quarter to reduce its exposure to mark-to-market charges in future quarters.  Through October 2005, Select Energy signed eight agreements to terminate wholesale electricity supply contracts with New England municipal electric systems that extend as long as eight years, terminating its wholesale sales obligations in that region.  Because most of those contracts were well below the current market price for wholesale electricity, Select Energy agreed to pay counterparties a total of $157 million, of which $131 million was paid in the third quarter.  Select Energy made a contract termination payment totaling $14.2 million in the first quarter of 2005, agreed in October 2005 to pay a third party $15 million in December 2005 to assume other Select Energy wholesale power contracts in New England beginning on January 1, 2006, agreed to pay another $55.9 million in December 2005 to terminate approximately 1 million megawatt-hours of net sales obligations, and agreed to make payments of $26 million to two other municipalities in the fourth quarter.  Select Energy is continuing to negotiate with counterparties to sell additional wholesale power obligations through 2008.  To date, Select Energy has reached agreements to terminate or assign an estimated net 7.4 million megawatt-hours of wholesale electric sales obligations.  Select Energy still has an estimated net 2.4 million megawatt-hours of wholesale obligations through 2013, though sales volumes will likely be affected by weather, economic factors, and each contract’s relative price compared with alternative sources of electricity.

Energy Services Businesses:  NU Enterprises continues to work to complete the divestiture of its energy services businesses.  NU’s condensed consolidated statements of (loss)/income for the three and nine months ended September 30, 2005 and 2004 present the operations for the following companies as discontinued operations as a result of meeting certain criteria requiring this presentation:

·

SESI and its wholly owned subsidiaries HEC/Tobyhanna Energy Project, Inc. and HEC/CJTS Energy Center LLC:  NU Enterprises has received purchase offers from several bidders and expects to complete the sale of SESI by the end of the first quarter of 2006.

·

Select Energy Contracting, Inc. - New Hampshire (including Reeds Ferry Supply Co., Inc. (Reeds Ferry)) (SECI-NH), a division of Select Energy Contracting, Inc. (SECI):  NU Enterprises has agreed on the terms of the sale of SECI-NH with the prospective buyer and expects to complete the sale of SECI-NH by the end of 2005.

·

Woods Network Services, Inc. (Woods Network):  NU Enterprises has signed a letter of intent to sell Woods Network and due diligence related to the sale is completed.  NU Enterprises expects to complete the sale of Woods Network by the end of 2005.

·

Woods Electrical Co., Inc. (Woods Electrical):  NU Enterprises is in the process of marketing Woods Electrical to potential buyers.  NU Enterprises expects to complete the sale of Woods Electrical by the third quarter of 2006.

For further information regarding these companies, see Note 4, "Assets Held For Sale and Discontinued Operations," to the condensed consolidated financial statements.  NU Enterprises’ two other energy services businesses, Select Energy Contracting, Inc., - Connecticut and E.S. Boulos Company, which are also being divested, are currently classified as assets held and used.

Business Development and Capital Expenditures

Utility Group:

NU currently forecasts transmission expenditures of up to $2.3 billion from 2006 through 2010.  Those expenditures include $1.2 billion on the four southwest Connecticut projects noted above, $0.7 billion of additional transmission projects management expects are highly likely to be built, and $0.4 billion on projects that remain in the conceptual phase.  Management forecasts approximately $450 million of transmission capital expenditures in 2006, approximately $500 million of transmission capital expenditures in 2007 and 2008.  An additional $2 billion of distribution and generation projects is currently forecasted from 2006 to 2010, totaling $4.3 billion in total regulated capital projects.  

Connecticut – CL&P: Transmission capital expenditures in Connecticut are focused primarily on four major transmission projects in southwest Connecticut.  These projects include the Bethel, Connecticut to Norwalk, Connecticut and Middletown, Connecticut to Norwalk projects, as well as a related 115 kilovolt (kV) underground project, and the replacement of the existing 138 kV cable between Connecticut and Long Island.  Each of these projects has received approval from the CSC.  Capital expenditures for the southwest Connecticut transmission projects totaled $63 million for the three months ended September 30, 2005 and $103 million for the nine months ended September 30, 2005.  In 2005, CL&P’s transmission capital expenditures in southwest Connecticut are projected to total approximately $154 million.

On April 7, 2005, the CSC unanimously approved a proposal by CL&P and United Illuminating to build a 69-mile 345 kV transmission line from Middletown to Norwalk, Connecticut.  Approximately 24 miles of the 345 kV line will be built underground with the balance being built overhead.  The project still requires CSC review of detailed construction plans, as well as United States Army Corps of Engineers approval to bury the line beneath certain navigable rivers and Department of Environmental Protection

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(DEP) approvals.  The CSC decision included provisions for low-magnetic field designs in certain areas and made variations to the proposed route.  As a result of increases due to configuration and design specification changes, current competitive bid and construction experience, and commodity price changes, CL&P’s portion of the project is now estimated to cost approximately $1.05 billion.  CL&P expects to secure final technic al approval from ISO-NE in the first quarter of 2006 and to award the major construction-related contracts during the second quarter of 2006.  CL&P expects the project to be completed by the end of 2009. Legal review of three filed appeals is ongoing.  At this time, CL&P does not expect any of these three appeals to delay construction. At September 30, 2005, CL&P has capitalized $32 million associated with this project.  

CL&P has signed all but two contracts for construction of a 21-mile 115 kV/345 kV line project between Bethel and Norwalk. Underground line construction activities began in April 2005, with overhead line work commencing in September 2005.  A considerable amount of work on the two substations had been completed earlier.  The first substation (Plumtree) was successfully energized on September 23, 2005.  The first section of 115 kV underground cable is expected to be energized in the fourth quarter of 2005.  This project is now approximately 50 percent complete and CL&P expects to complete the project by the end of 2006 at a cost of approximately $350 million.  As of September 30, 2005, CL&P has capitalized $153 million associated with this project.  

CL&P’s construction of two 115 kV underground transmission lines between Norwalk and Stamford, Connecticut was approved by the CSC on July 20, 2005.  The project is expected to cost approximately $120 million and will help meet growing electric demands in the area.  ISO-NE approval was received on August 3, 2005.  Management expects to begin construction during 2007 and expects the lines to be in service during 2008.  At September 30, 2005, CL&P has capitalized $5 million associated with this project.

On October 1, 2004, CL&P and the Long Island Power Authority (LIPA) jointly filed plans with the Connecticut Department of Environmental Protection to replace an undersea 13-mile electric transmission line between Norwalk, Connecticut and Northport - Long Island, New York, consistent with a comprehensive settlement agreement reached on June 24, 2004.  This project is estimated to cost in the range of $114 million to $135 million with CL&P and LIPA each owning approximately 50 percent of the line.  The cost range reflects that vendor contracts have not yet been signed.  On June 20, 2005, the New York State Controller’s Officer and the New York State Attorney General approved an agreement between CL&P and LIPA to replace the cable and the project had earlier received CSC approval.  State and federal permits are expected to be issued by the end of calendar year 2005.  Assuming permits are received no later than the first quarter 2006, construction activities are expected to begin in the fall of 2006 and management expects the line will be in service by 2007.  At September 30, 2005, CL&P has capitalized $6 million associated with this project.

During the first nine months of 2005, NU placed in service $81 million of electric transmission projects, including $17 million related to the Bethel to Norwalk project.

Connecticut - Yankee Gas:   Yankee Gas has begun construction of a liquefied natural gas storage and production facility in Waterbury, Connecticut, which will be capable of storing the equivalent of 1.2 billion cubic feet of natural gas. Construction of the facility began in March 2005 and is expected to be completed in 2007 in time for the 2007-2008 heating season. This project is now approximately 35 percent complete.  The facility is expected to cost $108 million and through September 30, 2005, Yankee Gas has capitalized $36.4 million related to this project.

New Hampshire:   Construction activities associated with PSNH’s $75 million conversion of a 50-megawatt (MW) coal-fired unit at Schiller Station in Portsmouth, New Hampshire to burn wood began in late 2004 and are expected to be completed in the second half of 2006. This project was approximately 65 percent complete at September 30, 2005.  At September 30, 2005, PSNH has capitalized $52 million related to this project.

NU Enterprises:   In March 2005, HWP notified Massachusetts environmental regulators that it planned to install a selective catalytic reduction system at the 145 MW Mt. Tom coal-fired station in Holyoke, Massachusetts.  The system will significantly reduce nitrogen oxide emissions from the unit and extend its operating life by meeting expected emission requirements through 2010.  The $14 million project commenced in July 2005 and is expected to be complete by mid-2006.  At September 30, 2005, HWP has capitalized $5.8 million related to this project.

Transmission Access and FERC Regulatory Charges

In January 2005, the New England transmission owners approved activation of the New England Regional Transmission Organization (RTO) which occurred on February 1, 2005.  CL&P, WMECO and PSNH are now members of the New England RTO and provide regional open access transmission service over their combined transmission system under the ISO-NE Transmission, Markets and Services Tariff, FERC Electric Tariff No. 3 and local open access transmission service under the ISO-NE Transmission, Markets and Services Tariff, FERC Electric No. 3, Schedule 21 - NU.

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In June 2004, the transmission business reached a settlement agreement with the parties to its rate case, allowing NU to implement a formula-based LNS tariff with an allowed ROE of 11.0 percent. This settlement was approved by the FERC in September 2004. As a result of the RTO start-up on February 1, 2005, the ROE in the LNS tariff was increased to 12.8 percent. The ROE being utilized in the calculation of the current RNS rates is the sum of the 12.8 percent “base” ROE, plus a 50 basis point incentive adder for joining the RTO, or a total of 13.3 percent. An initial decision by a FERC ALJ has set the base ROE at 10.72 percent as compared with the 12.8 percent requested by the New England RTO. One of the adjustments made by the ALJ was to modify the underlying proxy group used to determine the ROE, resulting in a reduction in the base ROE of approximately 50 basis points. The ALJ also deferred to the FERC final resolution on the 100 basis point incentive adder for new transmission investments. The ALJ reaffirmed the 50 basis point incentive for joining the RTO. The New England transmission owners have challenged the ALJ’s findings and recommendations through written exceptions filed on June 27, 2005. A final order from the FERC is expected by December 2005. Management cannot at this time predict what ROE will ultimately be established by the FERC in the ongoing proceedings. However, for purposes of current earnings estimates, the transmission business is assuming an ROE of 11.5 percent.

Legislative Matters

On August 8, 2005, President Bush signed into law comprehensive energy legislation.  Among other provisions potentially affecting NU are the repeal of PUHCA, FERC backstop siting authority for transmission, transmission pricing and rate reform, renewable production tax credits, and accelerated depreciation for certain new electric and gas facilities.  The renewable production tax credits provision is expected to save PSNH approximately $3 million annually in federal income taxes for the first 10 years after the Schiller Station conversion becomes operational.  The accelerated depreciation provision is expected to increase Utility Group cash flows by more than $5 million annually.  

The Regional Greenhouse Gas Initiative (RGGI) is a cooperative effort by nine northeastern states (including Massachusetts, New Hampshire and Connecticut in which NU currently owns generation) to develop a regional program for stabilizing and reducing carbon dioxide (CO2) emissions from fossil-fired electric generators.  RGGI has proposed the development of a multi-state cap-and-trade program with a market-based emissions trading system.  The current staff proposal would stabilize CO2 emissions at current levels between 2009 and 2015, and require a ten percent reduction from 2016 to 2020.  A memorandum of understanding between the participating states may be finalized by the end of 2005, although discussions as to the content of such an agreement are still ongoing. If the states agree in principle on a regional structure, then each state would need to develop the necessary legislative and regulatory mechanisms to propose the program. Upon enactment by the states, RGGI may impact HWP’s Mt. Tom plant, which is a 145 MW coal-fired generator, and PSNH’s Merrimack, Newington and Schiller stations.  At this time, the impact of this proposal on NU cannot be determined.

On January 1, 2006 a CO2 cap on emissions from fossil-fired electric generators is scheduled to take effect in Massachusetts, with a separate CO2 emissions rate limit effective in 2008.  Affected parties are currently awaiting the Massachusetts Department of Environmental Protection’s proposal concerning a trading or other form of offset program.  HWP’s Mt. Tom plant would be impacted by this regulation.  Given the uncertainty of the future compliance mechanism under these regulations, the impact of this regulation on NU cannot be determined.

Connecticut:

Transmission Tracking Mechanism:  On July 6, 2005, Governor Rell signed legislation creating a mechanism to allow the DPUC to true-up, at least annually, the retail transmission charge in distribution company rates based on changes in FERC-approved charges. This mechanism will allow CL&P to include forward-looking transmission charges in its retail transmission rate and promptly recover its transmission expenditures.  On August 1, 2005, CL&P filed an application with the DPUC to implement the tracking mechanism, effective July 1, 2005.  A final decision in this docket from the DPUC is scheduled for December 2005.

Energy Legislation: Public Act 05-01, an “Act Concerning Energy Independence,” was signed by Governor Rell on July 22, 2005. The new legislation provides incentives to encourage the construction of distributed generation, new large-scale generation, and conservation and load management initiatives to reduce federally mandated congestion cost (FMCC) charges. FMCC charges represent the costs of power market rules approved by the FERC that are resulting in significantly higher costs for Connecticut. The most significant cost item in 2005 is reliability must run (RMR) contracts, and proposed for October 2006, a new administrative rule called LICAP. The legislation requires regulators to a) implement near-term measures as soon as possible, and b) commence a new request for proposals to build customer side distributed resources and contracts for new or repowered larger generating facilities in the state. Developers could receive contracts of up to 15 years from the distribution companies. The legislation provides utilities with the opportunity to earn one-time awards for generation that is installed in their service territories. Those awards can be as high as $200 per kilowatt for distributed generation and $25 per kilowatt for more traditional generation. It also allows distribution companies, such as CL&P, to bid as much as 250 MW of capacity into the request for proposals. If such utility bid was accepted, then the unit after five years would have to be a) sold, b) have its capacity sold, or c) both, provided that the DPUC could waive these requirements.

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The legislation also requires the DPUC to investigate the financial impact on distribution companies of entering into long-term contracts and to allow distribution companies to recover through rates any increased costs. The DPUC has opened a number of new dockets to implement this legislation.

New Hampshire:

Environmental Legislation:  The New Hampshire legislature will be considering legislation in its 2006 legislative session that would place strict limitations on the level of mercury that PSNH’s existing generation plants can emit.  Management has been reviewing the proposed legislation and assessing how PSNH might meet any required reduction in mercury emissions should such strict limitations be established.   PSNH conducted testing of one control technology at its Merrimack Station during the summer of 2005.  While state law and PSNH’s restructuring agreement provide for the recovery of its generation costs, including the cost to comply with state environmental regulations, at this time management is unable to determine the impact of any potential new legislation on PSNH’s net income or financial position.

Utility Group Regulatory Issues and Rate Matters

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 through a combination of the RNS tariff and NU’s LNS tariff.  NU’s LNS rate is reset on January 1 ^st and June 1 ^st of each year.  Additionally, NU’s LNS tariff provides for a true-up to actual costs, which ensures that NU’s transmission business recovers its total transmission revenue requirements, including the allowed ROE.  For the nine months ended September 30, 2005, this true up has resulted in the recognition of a $4.5 million regulatory liability, including approximately $3.8 million due to NU’s electric distribution companies, including CL&P, PSNH and WMECO.

NU intends to file at the FERC a request to include an allowance for 50 percent of construction work in progress for its four major southwest Connecticut transmission projects in its formula rate for transmission service (Schedule 21 – NU).  These revisions would allow NU to collect 50 percent of the construction financing expenses while these projects are under construction.  NU has provided to ISO-NE its notice of intent to file the revisions to its tariff in November 2005 with new rates to be effective early in the first quarter of 2006.

Transmission - Retail Rates:  A significant portion of the NU transmission business revenue comes from ISO-NE charges to the distribution businesses of CL&P, PSNH and WMECO.  The distribution businesses recover these costs through the retail rates that are charged to their retail customers.  For CL&P, any difference between the revenues received from retail customers and the retail transmission expenses charged to the distribution business has historically impacted the distribution business’s earnings.  However, in July 2005, CL&P began tracking its retail transmission revenues and expenses and will adjust its retail transmission rates on a regular basis and thereby recover all of its retail transmission expenses on a timely basis.  This ratemaking change resulted from the enactment of the new legislation passed by the Connecticut legislature.  WMECO implemented its retail transmission tracker and rate adjustment mechanism in January 2002 as part of its 2002 rate change filing.  PSNH does not currently have a retail transmission rate tracking mechanism.   

LICAP:   In March 2004, ISO-NE filed a proposal at the FERC to implement LICAP.  LICAP is an administratively determined electric generation capacity pricing mechanism intended to provide a revenue stream sufficient to maintain existing generation assets and encourage the construction of new generation assets at levels sufficient to serve peak load, plus a fixed reserve margin and a statistically-determined contingency.  In June 2004, the FERC ordered the creation of five LICAP zones, including two in Connecticut, and accepted ISO-NE’s demand curve methodology which will be used to determine pricing.  The FERC ordered LICAP to be implemented by January 1, 2006, and set certain issues pertaining to the demand curve for hearings.  The hearings on the demand curve and associated issues ended on March 31, 2005 and an initial decision from the FERC ALJ was issued on June 15, 2005.  The ALJ largely adopted the demand curve as filed by ISO-NE.

In August 2005, the FERC announced that it would delay the implementation of LICAP until at least October 1, 2006.  On September 20, 2005, the FERC commissioners held a hearing on LICAP and alternatives to LICAP.   The FERC has now referred to a settlement judge the development of LICAP alternatives, which must be concluded by January 31, 2006.  The FERC has also delayed the implementation of two energy zones in Connecticut pending consideration of further petitions by ISO-NE.  Management cannot at this time predict the outcome of these FERC proceedings.

If LICAP is implemented, LICAP costs totaling several hundred million dollars annually will be incurred, in part, because Connecticut is a constrained area with insufficient generation assets.  These costs would be expected to be recovered from CL&P’s customers through the FMCC mechanism.  PSNH and WMECO also will incur LICAP charges, but to a lesser degree and will also expect to recover these costs from their customers.

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Connecticut - CL&P:     

Streetlighting Decision: On June 30, 2005, the DPUC issued a final decision which requires CL&P to recalculate all previously issued refunds (except the towns of Stamford and Middletown) utilizing applicable approved pre-tax cost of capital rates.  The final decision also provides for a five year period for those towns that wish to phase in the purchase of their streetlights in which to complete the asset purchase.  As a result of this decision, CL&P recorded an additional $7.4 million of pre-tax reserve for streetlight billing in the second quarter of 2005.  CL&P filed an appeal of this decision on August 11, 2005 in the Connecticut Superior Court.  The court has not yet set a schedule for the appeal.

Procurement Fee Rate Proceedings:  CL&P is currently allowed to collect a fixed procurement fee of 0.50 mills per kilowatt-hour (kWh) from customers who purchase transitional standard offer (TSO) service through 2006.  One mill is equal to one-tenth of a cent. That fee can increase to 0.75 mills if CL&P outperforms certain regional benchmarks.  The fixed portion of the procurement fee amounted to approximately $12 million (approximately $7 million after-tax) for 2004.  On September 15, 2004, CL&P submitted to the DPUC its proposed methodology to calculate the variable portion (incentive portion) of the procurement fee.  On November 18, 2004 the DPUC suspended this proceeding.  On May 13, 2005, CL&P filed a motion to reopen this docket which was granted by the DPUC on June 30, 2005.  As part of that filing, CL&P also requested approval of $5.8 million for its 2004 incentive payment and again requested that the DPUC approve the proposed methodology.  A final decision in this docket from the DPUC is scheduled for December 2005.  The variable portion of the procurement fee has not yet been reflected in earnings.

Retail Transmission Rate Filing:  On February 1, 2005, CL&P filed an application with the DPUC to obtain approval to defer for future recovery in its retail transmission rate the increased transmission costs that CL&P is incurring.  As a result of the legislation described above, CL&P withdrew its application and filed for a transmission adjustment clause on August 1, 2005 with the rate tracking mechanism effective in July 2005.  A final decision in this docket from the DPUC is scheduled for December 2005.

CTA and SBC Reconciliation:  The CTA allows CL&P to recover stranded costs, such as securitization costs associated with the rate reduction bonds, amortization of regulatory assets, and independent power producers (IPP) 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 April 1, 2005, CL&P filed its 2004 CTA and SBC reconciliation with the DPUC, which compared CTA and SBC revenues to revenue requirements.  For the year ended December 31, 2004, total CTA revenues exceeded the CTA revenue requirements by $14.1 million.  This amount was recorded as a regulatory liability on the accompanying condensed consolidated balance sheets.  For the same period, SBC revenues exceeded the SBC revenue requirement by $3.6 million which was recorded as a regulatory liability. Management expects a decision in this docket from the DPUC by the end of 2005.   

In the 2001 CTA and SBC reconciliation filing, and subsequently in a September 10, 2002 petition to reopen related proceedings, CL&P requested that a deferred intercompany tax liability associated with the intercompany sale of generation assets be excluded from the calculation of CTA revenue requirements. This liability is currently included as a reduction in the calculation of CTA revenue requirements. On September 10, 2003, the DPUC issued a final decision denying CL&P’s request, and on October 24, 2003, CL&P appealed the DPUC’s final decision to the Connecticut Superior Court. The appeal has been fully briefed and argued. If CL&P’s request is granted and upheld through these court proceedings, there would be additional amounts due to CL&P from its customers. The amount due is contingent upon the findings of the court; however, management believes that CL&P’s pre-tax earnings would increase by a minimum of $17 million in 2005 if CL&P’s position is adopted by the court.

CL&P TSO Rates: Most of CL&P’s customers buy their energy at CL&P’s TSO rate, rather than buying energy directly from competitive suppliers.  On December 22, 2004, the DPUC approved an increase of 16.2 percent in TSO rates effective January 1, 2005, although the impact was partially offset by a continuation of the CTA refund.  The DPUC also ordered that projected 2004 and 2005 CTA overrecoveries and half of projected 2004 distribution overrecoveries be used to moderate increases for customers that otherwise would occur when the current CTA refund expired on May 1, 2005.  Overall, the final decision approved an increase to the January 2004 TSO rates of approximately 10.4 percent, including the effects of existing and new refunds and overrecoveries.  The DPUC denied requests by the Connecticut Attorney General and Office of Consumer Counsel (OCC) to defer the recovery of higher supplier costs into future years. On February 3, 2005, the OCC filed an appeal with the Connecticut Superior Court challenging this decision.   On October 20, 2005, this appeal was dismissed by the court.

Also, pursuant to state law, on December 19, 2003, the DPUC set CL&P’s TSO rates for January 1, 2004 through December 31, 2004 and confirmed that state law exempted FMCC charges, Energy Adjustment Clause (EAC) charges and certain other charges from the statutorily imposed rate cap.  The OCC filed appeals of this decision with the Connecticut Superior Court.  The OCC claimed that the decision improperly implements an EAC charge under Connecticut law, fails to properly define and identify the fees that CL&P will be allowed to collect from customers and improperly calculates base rates for purposes of determining the rate cap.   

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On May 16, 2005, the DPUC approved a 4.8 percent increase to customer rates related to $79.8 million of additional RMR contract costs, which have been approved by the FERC.  This additional amount will be recovered over the period June through December 2005 through an increase to the FMCC rates effective June 1, 2005.  On August 24, 2005, the DPUC issued a final decision supporting the interim rate increase approved in May 2005.

CL&P secured half of its 2006 TSO requirements during bidding in 2003 and 2004.  Bids to supply CL&P with its remaining 2006 TSO requirements are due on November 15, 2005.  CL&P is not seeking bids for 2007 TSO at this time.

Connecticut - Yankee Gas:

Unbilled Revenue Adjustment: On September 9, 2005, the DPUC issued a draft decision regarding Yankee Gas PGA clause charges for the time 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 hearing on September 20, 2005 and requested that Yankee Gas file supplemental information regarding the two adjustments.  Yankee Gas filed the supplemental information on October 3, 2005 and is waiting for the DPUC to establish the remaining schedule.  If upheld, this disallowance would result in a $9 million pre-tax write-off.  Management believes the unbilled sales and revenue adjustments and resultant charges to customers through the PGA clause were appropriate. Based on the facts of the case and the supplemental information provided to the DPUC, management believes the appropriateness of the PGA charges to customers for the time period under review will be allowed.

New Hampshire:

TS/DS Rates:  In accordance with the “Agreement to Settle PSNH Restructuring” and state law, PSNH files for updated TS/DS rates periodically to ensure timely recovery of its costs.  The TS/DS rate recovers PSNH’s generation and purchased power costs, including a return on PSNH’s generation assets.  PSNH defers for future recovery or refund any difference between its TS/DS revenues and the actual costs incurred.  

On January 28, 2005 the NHPUC issued an order approving a TS/DS rate of $0.0649 per kWh for the period February 1, 2005 through January 31, 2006 which included an 11 percent ROE on PSNH’s generation assets.  This generation ROE was the subject of a second set of proceedings.  On June 8, 2005, the NHPUC issued an order requiring PSNH to use a generation ROE of 9.63 percent, effective July 1, 2005.  This decrease in allowed ROE will lower PSNH’s net income by approximately $1.4 million annually based on the current level of generation asset investment.  On July 7, 2005, PSNH filed a motion for reconsideration in the ROE portion of above docket.  PSNH is awaiting a response from the NHPUC as to this motion.   

On July 1, 2005, after a review of its TS/DS costs, PSNH filed a petition with the NHPUC requesting an increase in the TS/DS rate from the current $0.0649 per kWh to $0.0734 per kWh based on actual costs and underrecoveries incurred to date and updated cost projections.  The updated cost projections include an increase in costs as a direct result of higher fuel and purchased power costs that PSNH expects to incur.  The generation ROE used in the updated cost projections was based upon the 9.63 percent ROE ordered on June 8, 2005.  An order changing the TS/DS rate to $0.0724 per kWh, effective August 1, 2005 was issued by the NHPUC on August 1, 2005.

On September 30, 2005, PSNH filed a petition with the NHPUC requesting a change in TS/DS rates for the period February 1, 2006 through January 31, 2007.  In its filing, PSNH did not request a specific TS/DS rate; rather, given the current price volatility in the energy markets, PSNH requested that the NHPUC review and approve its underlying operational data within the September 30, 2005 filing.  In December 2005, PSNH expects to petition for a specific TS/DS rate based on updated market information.  Management expects the NHPUC to issue an order prior to February 1, 2006.

SCRC Reconciliation Filing:  The Stranded Cost Recovery Charge (SCRC) allows PSNH to recover its stranded costs.  On an annual basis, PSNH files with the NHPUC a SCRC reconciliation filing for the preceding calendar year.  This filing includes the reconciliation of stranded cost revenues and costs and TS/DS revenues and costs.  The NHPUC reviews the filing, including a prudence review of the operation of PSNH’s generation assets.  The cumulative deferral of SCRC revenues in excess of costs was $271.1 million at September 30, 2005.  This cumulative deferral will decrease the amount of non-securitized stranded costs that will have to be recovered from PSNH’s customers in the future from $374.1 million to $103 million.

The 2004 SCRC reconciliation filing was filed with the NHPUC on May 2, 2005.  The SCRC and TS/DS rate mechanisms currently reconcile accrued expenses with billed revenues on a monthly basis.  PSNH included a request, and supporting testimony, to include unbilled revenues as part of the reconciliation process in its annual 2004 SCRC and TS/DS reconciliation filing.  This request allows for the reconciliation of revenues on an accrual basis, including unbilled revenues, with the current accrued expenses recovered through the SCRC and TS/DS rate mechanisms, consistent with accrual accounting.  At September 30, 2005, PSNH’s unbilled

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revenue balance related to SCRC and TS/DS was $11.7 million and $16.7 million, respectively.  On October 19, 2005, PSNH, the NHPUC staff and the Office of Consumer Advocate reached a settlement agreement in this case which requires no disallowances and provides for recovery of unbilled revenues. The NHPUC held a hearing on the merits of the settlement agreement on October 26, 2005, and a decision is expected later this year.  

Litigation with IPPs:  Two wood-fired IPPs that sell their output to PSNH under long-term rate orders issued by the NHPUC brought suit against PSNH in state superior court.  The IPPs and PSNH dispute the end-dates of the above-market long-term rates set forth in the respective rate orders.  Subsequent to the IPP’s court filing, PSNH petitioned the NHPUC to decide this matter, and requested that the court stay its proceeding pending the NHPUC’s decision.  By court order dated October 20, 2005, the court granted PSNH’s motion to stay indicating that the NHPUC had primary jurisdiction over this matter.  The NHPUC will determine how long each of the rate orders in question remain in effect.  PSNH recovers the over market costs of IPP contracts through the SCRC.

Massachusetts:

Transition Cost Reconciliation and Other Filings: On March 31, 2005, WMECO filed its 2004 transition cost reconciliation with the Massachusetts Department of Telecommunications and Energy (DTE).  The DTE has combined the 2003 transition cost reconciliation filing, standard offer service and default service reconciliation, the transmission cost adjustment filing, and the 2004 transition cost reconciliation filing into a single proceeding.  The timing of a decision in the combined proceeding is uncertain, but management does not expect the outcome to have a material adverse impact on WMECO’s net income or financial position.

Nuclear Decommissioning and Plant Closure Costs

FERC Proceedings:  In 2003, the Connecticut Yankee Atomic Power Company (CYAPC) increased the estimated decommissioning and plant closure costs for the period 2000 through 2023 by approximately $395 million over the April 2000 estimate of $436 million approved by the FERC in a 2000 rate case settlement.  The revised estimate reflects the increases in the projected costs of spent fuel storage, increased security and liability and property insurance costs, and the fact that CYAPC is now self performing all work to complete the decommissioning of the plant due to the termination of the decommissioning contract with Bechtel Power Corporation (Bechtel) in July 2003.  NU’s share of CYAPC’s increase in decommissioning and plant closure costs is approximately $194 million. On July 1, 2004, CYAPC filed with the FERC for recovery of these increased costs.  In the filing, CYAPC sought to increase its annual decommissioning collections from $16.7 million to $93 million for a six-year period beginning on January 1, 2005.  On August 30, 2004, the FERC issued an order accepting the rates, with collection beginning on February 1, 2005, subject to refund.

Both the DPUC and Bechtel filed testimony in the FERC proceeding claiming that CYAPC was imprudent in its management of the decommissioning project. The DPUC has claimed that CYAPC did not terminate the contract with Bechtel soon enough, and Bechtel has claimed that CYAPC terminated the contract too soon. In its testimony, the DPUC recommended a disallowance of $225 million to $234 million out of CYAPC’s requested rate increase of approximately $395 million. NU’s share of the DPUC’s recommended disallowance is between $110 million to $115 million. The FERC staff also filed testimony that recommended a $36 million decrease in the requested rate increase claiming that CYAPC should have used a different gross domestic product (GDP) escalator. NU’s share of this recommended decrease is $17.6 million. Management expects that if the FERC staff’s position on the decommissioning GDP cost escalator is found by the FERC to be more appropriate than that used by CYAPC to develop its proposed rates, then CYAPC would review whether to reduce its estimated decommissioning obligation and reduce the customers’ obligation, including CL&P, PSNH and WMECO. Hearings in this proceeding began on June 1, 2005 and have concluded, and post-hearing briefs have been filed. While FERC staff did not take a position on prudence in the hearing, they have claimed in their brief that increases in decommissioning cost estimates were due to imprudent actions and were not the fault of ratepayers. A FERC administrative law judge decision in this proceeding is expected to be rendered in December 2005.

The company cannot at this time predict the timing or outcome of the FERC proceeding required for the collection of the increased CYAPC decommissioning costs.  The company believes that the costs have been prudently incurred and will ultimately be recovered from the customers of CL&P, PSNH and WMECO.  However, there is a risk that some portion of these increased costs may not be recovered, or will have to be refunded if recovered, as a result of the FERC proceedings.  

On June 10, 2004, the DPUC and the OCC filed a petition seeking a declaratory order that CYAPC be allowed to recover all decommissioning costs from its wholesale purchasers, including CL&P, PSNH and WMECO, but that such purchasers may not be allowed to recover in their retail rates any costs that the FERC might determine to have been imprudently incurred.  On August 30, 2004, the FERC denied this petition.  On September 29, 2004, the DPUC and OCC asked the FERC to reconsider the petition and on October 20, 2005, the FERC denied the reconsideration, holding that the sponsor companies are only obligated to pay CYAPC for prudently incurred decommissioning costs and the FERC has no jurisdiction over the sponsors’ rates to their retail customers. 

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Bechtel Litigation:  CYAPC is currently in litigation with Bechtel in Connecticut Superior Court (the Court) over the termination of its decommissioning contract.  On June 13, 2003, CYAPC gave notice of the termination of its contract with Bechtel for the decommissioning of its nuclear power plant.  CYAPC terminated the contract due to Bechtel’s incomplete and untimely performance and refusal to perform the remaining decommissioning work.  Bechtel has departed the site and the decommissioning responsibility has been transitioned to CYAPC, which has recommenced the decommissioning process.

On June 23, 2003, Bechtel filed a complaint against CYAPC asserting a number of claims and seeking a variety of remedies, including monetary and punitive damages and rescission of the contract.  Bechtel has since amended its complaint to add claims for wrongful termination.  On August 22, 2003, CYAPC filed its answer and counterclaims, including counts for breach of contract, negligent misrepresentation and breach of duty of good faith and fair dealing.  The parties are proceeding with depositions in the case.  Bechtel filed an offer of judgment for CYAPC to pay Bechtel the amount of $20 million, which was rejected by CYAPC.  CYAPC filed an offer of judgment for Bechtel to pay the amount of $65 million to CYAPC, which was rejected by Bechtel.  If either party prevails in litigation with an award equal to or higher than its offer, then the Court will add 12 percent annual interest to the award to the prevailing party, computed from the date of the party’s claim (from June 23, 2003 for Bechtel or August 22, 2003 for CYAPC).  A trial has been scheduled for spring of 2006.  

In the prejudgment remedy proceeding before the Court, Bechtel sought garnishment of the CYAPC decommissioning trust and related payments.  In October 2004, Bechtel and CYAPC entered into an agreement under which Bechtel waived its right to seek garnishment of the decommissioning trust and related payments in return for the potential attachment of CYAPC’s real property in Connecticut and the escrowing of $41.7 million the sponsors are scheduled to pay to CYAPC through June 30, 2007 in respect to CYAPC’s common equity.  This stipulation is subject to approval of the Court and would not be implemented until the Court found that such assets were subject to attachment.  CYAPC has contested the attachability of such assets.  The DPUC is an intervenor in this proceeding.  NU cannot predict the timing and the outcome of the litigation with Bechtel.

Spent Nuclear Fuel Litigation:  CYAPC, Yankee Atomic Electric Company (YAEC) and Maine Yankee Atomic Power Company (MYAPC) (collectively, the Yankee Companies) also commenced litigation in 1998 charging that the federal government breached contracts it entered into with each company in 1983 under the Nuclear Waste Policy Act of 1982 (the Act).  Under the Act, the DOE was to begin removing spent nuclear fuel from the nuclear plants of the Yankee Companies no later than January 31, 1998 in return for payments by each company into the nuclear waste fund.  No fuel has been collected by the DOE, and spent nuclear fuel is stored on the sites of the Yankee Companies’ plants.  The Yankee Companies collected the funds for payments into the nuclear waste fund from wholesale utility customers under FERC-approved contract rates.  The wholesale utility customers in turn collect these payments from their retail electric customers.  The Yankee Companies’ individual damage claims attributed to the government’s breach totaling $548 million are specific to each plant and include incremental storage, security, construction and other costs through 2010.  The CYAPC damage claim is $197 million, the YAEC damage claim is $191 million and the MYAPC damage claim is $160 million.

The DOE trial ended on August 31, 2004 and a verdict has not been reached.  The current Yankee Companies’ rates do not include an amount for recovery of damages in this matter.  Management cannot predict either the outcome of this matter or its ultimate impact on NU.

Yankee Atomic Electric Company:  During the course of carrying out decommissioning work at the unit’s site, YAEC has identified increases in the scope of soil remediation and certain other remediation required to meet environmental standards, beyond the levels assumed in its 2003 decommissioning estimate.  YAEC is continuing to evaluate the impact of the additional requirements on its decommissioning plan.  While that evaluation is not complete, YAEC has determined that the schedule for the completion of physical work will need to extend until mid-2006 and the costs of completing decommissioning will be approximately $63 million greater than the estimate that formed the basis of its 2003 FERC settlement.  Most of the cost increase relates to decommissioning expenditures that will be made during 2006.  In order to fund these additional costs, YAEC is preparing an application to the FERC for increased decommissioning charges to go into effect in early 2006, subject to FERC acceptance and approval.  The timing and amount of the FERC application and the increase in decommissioning charges are under development, but YAEC expects that it will seek rate recovery of a significant component of the increased expenditures during 2006.  NU has a 38.5 percent ownership interest in YAEC, and NU’s share of this increase would total approximately $24 million.  The company cannot at this time predict the timing or outcome of a FERC proceeding required for the collection of the increased YAEC decommissioning costs.  The company believes that the costs have been prudently incurred and will ultimately be recovered from the customers of CL&P, PSNH and WMECO. However, there is a risk that some portion of these increased costs may not be recovered, or will have to be refunded if recovered, as a result of the FERC proceedings.  

NU Enterprises

NU Enterprises currently has two business segments:  the merchant energy business segment and the energy services and other business segment.  NU has decided to exit all aspects of both segments.

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Merchant Energy Segment:  The merchant energy business segment includes Select Energy’s retail marketing business, 1,440 MW of generation assets, including 1,295 MW of primarily pumped storage and hydroelectric generation assets at NGC, 145 MW of coal-fired generation assets at HWP and NGS.

The merchant energy segment also continues to include the wholesale marketing business, which NU Enterprise is exiting.  Prior to the March 2005 decision to exit this business, the wholesale business was comprised primarily of full requirements sales to LDCs and bilateral sales to other load-serving counterparties.  These sales were sourced by the generation assets and an inventory of energy contracts.   

Energy Services and Other Segment:  In March of 2005, NU Enterprises announced that it would explore ways to divest the energy services businesses in a manner that maximizes their value.  These businesses include the operations of the contracting businesses of NGS’ contracting businesses, SESI, SECI, Reeds Ferry, and Woods Network.  

Outlook:  NU will not provide 2005 earnings guidance for NU Enterprises because earnings at NU Enterprises for the remainder of 2005 will likely be impacted by many factors, such as:

·

The application of mark-to-market accounting to wholesale marketing contracts until those contracts are settled or until the commodities are delivered.  The value of these contracts have and will fluctuate with changes in electricity and capacity values and with gas prices that are used to value the long-term portions of the contracts.  These changes in value have been reflected in earnings and have been significant.  These changes could continue to be significant until the contracts are divested.

·

Proceeds that NU Enterprises may receive in 2006 should the sale of its generating assets occur during that year.

·

The method of exiting the retail business has not yet been determined.

·

The recognition of additional gains or losses on wholesale marketing contracts that have not been recorded yet.  Serving full requirements contracts could result in quantities of electricity to be delivered in amounts different from the notional amounts that were multiplied by current market prices to determine the mark-to-market charge.  Differences have impacted and are reasonably likely to continue to impact NU Enterprises’ earnings.  In addition, gains or losses may be recorded on the disposition of these wholesale contracts.  

·

Additional asset impairments or losses on disposals associated with merchant energy, energy services and generation assets.  As these businesses are marketed there could be additional impairments or losses on disposals to the extent sales are consummated. NU guarantees the performance of certain services companies, and the fair value of those guarantees may be recognized if they become guarantees to third parties.

·

The recognition of additional restructuring costs.  Costs associated with certain restructuring activities and employee costs are expected to be recognized in future periods as incurred.

Intercompany Transactions:  There were no CL&P TSO purchases from Select Energy in the third quarter of 2005, compared to $134.8 million of CL&P standard offer purchases from Select Energy in the third quarter of 2004.  Other energy purchases between CL&P and Select Energy totaled $14.3 million in the third quarter of 2005 compared to $25.6 million in the third quarter of 2004. WMECO purchases from Select Energy totaled $28.5 million in the third quarter of 2004.  In February 2005, WMECO entered into a contract with Select Energy under which Select Energy provided default service from April through June of 2005.  These amounts are eliminated in consolidation.

There were no CL&P TSO purchases from Select Energy in the first nine months of 2005, compared to $391.5 million of CL&P standard offer purchases from Select Energy in the first nine months of 2004.  Other energy purchases between CL&P and Select Energy totaled $41 million in the first nine months of 2005 compared to $83.4 million in the first nine months of 2004.  WMECO purchases from Select Energy in the first nine months of 2005 totaled $35.9 million, compared to $81.5 million in the first nine months of 2004.  These amounts are eliminated in consolidation.

There are $44 million and $114.2 million pre-tax mark-to-market charges for the three and nine months ended September 30, 2005, respectively, related to an intercompany contract between Select Energy and CL&P.  The contract extends through 2013 at below current market prices for CL&P.  This contract was included in the portfolio of contracts Select Energy assigned to a third party wholesale marketer, and Select Energy will only serve CL&P through December 31, 2005.  This contract is part of CL&P’s stranded costs, and benefits received by CL&P under this contract are provided to CL&P’s ratepayers.  A $2.8 million pre-tax mark-to-market charge for the three months ended March 31, 2005, was recorded as wholesale contract market changes by Select Energy for the intercompany contract between Select Energy and WMECO for default service from April to June of 2005.  There were no wholesale

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contract market changes in the second quarter of 2005 as this contract expired on June 30, 2005.  WMECO’s benefits under this contract will be provided to ratepayers in the form of lower than market default service rates.  These charges were not eliminated in consolidation because on a consolidated basis NU retains the over-market obligation to the ratepayers of CL&P and WMECO.

Risk Management:  The decision to exit the wholesale marketing business is expected to reduce the risk profile of NU Enterprises. Until exiting the wholesale marketing business, NU Enterprises will continue to be exposed to certain market risks for existing contracts until they expire or are divested.  The merchant energy business segment is comprised of generation assets and the retail marketing business, which will enter into contracts of varying lengths of time to buy and sell energy commodities, including electricity, natural gas, and oil to customers.  Market risk represents the loss that may affect the merchant energy business segment’s financial results, primarily Select Energy, due to adverse changes in commodity market prices.

Risk management within Select Energy has been organized to address the market, credit and operational exposures arising from the merchant energy business segment.  The framework for managing these risks is set forth in NU’s risk management policies and procedures, which are in the process of being revised.  These new policies and procedures will be reviewed with the NU Board of Trustees when completed, and periodically thereafter as appropriate.

Retail Marketing Activities:   Select Energy manages its portfolio of retail marketing contracts to maximize value while operating within NU’s corporate risk tolerance.  Select Energy generally acquires retail customers in small increments, which while requiring careful sourcing, allows energy purchases to be acquired in small increments.  However, fluctuations in prices, fuel costs, competitive conditions, regulations, weather, transmission costs, lack of market liquidity, plant outages and other factors can all impact the retail business adversely from time to time.

The number of commercial and industrial customers seeking to leave their transmission and distribution companies for the purpose of securing competitive electric and gas supplies rose during the first half of 2005, and during that period NU Enterprises bid on approximately 40 percent more retail business than in 2004 and had a 24 percent success rate in 2005 as compared to 16 percent last year.  However, in some regions the increase in energy prices due partly to hurricanes Katrina and Rita has caused the wholesale market price to be significantly greater than the regulated supply alternative, which has reduced retail marketing opportunities.  In these regions, as the regulated supply alternative rates are adjusted to reflect wholesale markets, retail opportunities should recover.

NU Enterprises expects retail revenues to be approximately $1.1 billion in 2005, compared with about $850 million in 2004.  Through the first nine months of 2005, 8 million megawatt-hours were delivered as compared to 7 million megawatt-hours in 2004.  For natural gas, NU Enterprises delivered 34 billion cubic feet in the first nine months of 2005 as compared to 28 billion cubic feet in the first nine months of 2004.  NU Enterprises expects delivered megawatt-hours to reach 11.5 million in 2005, compared with 10 million in 2004 and for delivered natural gas to exceed 50 billion cubic feet in 2005, compared with 40 billion cubic feet in 2004.

On average, electric unit margins on new business now range from approximately $1.50 to $2.00 a megawatt-hour.  For natural gas, unit margins are now expected to be between approximately $0.15 and $0.25 per thousand cubic feet.  If the projected volumes are multiplied by unit margins, NU Enterprises’ 2005 gross margin is now expected to be approximately $30 million:  $20 million electric and $10 million gas.  This is down from the original 2005 goal of approximately $40 million due to the reduced sale opportunities from current market conditions.  Based on what has been delivered to date and what is under contract, NU Enterprises has secured approximately 90 percent of the gross margin now projected for 2005.  

From time to time, the retail marketing business line enters into contracts that do not immediately meet the criteria for the normal election and accrual accounting.  Therefore changes in fair value are required to be marked-to-market and included in earnings. At September 30, 2005, Select Energy had retail derivative assets and liabilities as follows:   

(Millions of Dollars)
Current retail derivative assets	$41.7
Long-term retail derivative assets	4.1
Current retail derivative liabilities	(18.8)
Long-term retail derivative liabilities	(1.3)
Portfolio position	$25.7

The methods used to determine the fair value of retail energy sourcing contracts are identified and segregated in the table of fair value of contracts at September 30, 2005.  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, including bilateral contracts for the purchase or sale of electricity or natural gas, and are marked to the mid-point of bid and ask market prices.  

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As of and for the quarter and nine months ended September 30, 2005, the sources of the fair value of retail energy sourcing contracts and the changes in fair value of these contracts are included in the following tables:  

(Millions of Dollars)	Fair Value of Retail Sourcing Contracts at September 30, 2005
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	$ (4.5)	$ (0.6)	$   -	$ (5.1)
Prices provided by external sources	27.4	3.4	-	30.8
Totals	$ 22.9	$   2.8	$   -	$25.7

(Millions of Dollars)	Three Months Ended September 30, 2005	Nine Months Ended September 30, 2005
	Total Portfolio Fair Value	Total Portfolio Fair Value
Fair value of retail sourcing contracts outstanding   at beginning of period	$21.2	$     -
Contracts realized or otherwise settled during the period	(11.4)	(16.7)
Changes in fair value of contracts	15.9	12.4
Changes in fair value – other	-	30.0
Fair value of retail sourcing contracts outstanding  at end of period	$25.7	$25.7

Subsequent to March 31, 2005, management elected to retain certain contracts to help support its retail marketing business, which were required to be marked-to-market with market changes now recorded to fuel, purchased and net interchange power on the condensed consolidated statements of (loss)/income.

For further information regarding Select Energy’s derivative contracts, see Note 5, “Derivative Instruments,” to the condensed consolidated financial statements.

Merchant Generation Activities:  The merchant generation assets, either owned by NU Enterprises or contracted with third parties, are subject to certain operational risks, including but not limited to the length of scheduled and non-scheduled outages, bidding and scheduling with various ISOs, environmental issues and fuel costs.  Generation is also subject to various federal, state and local regulations.  These risks may result in changes in the anticipated gross margins which Select Energy realizes from its generation portfolio/activities.  

During the first nine months of 2005, NU Enterprises’ merchant generation assets continued to run well while energy prices have strengthened and reserve margins have started to tighten.  NU Enterprises believes that generating unit availability will become increasingly important as the capacity market tightens in New England due to load growth and the absence of new plant construction. Through the first nine months of 2005, the 1,080 MW Northfield Mountain facility had an availability factor of 95 percent, while the 145 MW Mt. Tom plant at HWP had an availability factor of 86 percent.  The approximately 200 MW of other hydroelectric units had an aggregate availability factor of 84 percent.

Conventional hydroelectric generation in the first nine months of 2005 is nearly 4 percent under budget due to significantly below average rainfall.  Generation was 455,104 megawatt-hours through September 2005, compared with a budgeted amount of 472,032 megawatt-hours.  Approximately 1 million megawatt-hours are generated annually at Mt. Tom, a coal-fired unit located in Holyoke, Massachusetts.  Through September 2005, more than 765,950 megawatt-hours were generated at Mt. Tom.

For the Northfield Mountain facility, on-peak, off-peak spreads continued to be favorable, averaging 1.74 over the third quarter.  As a result, NU Enterprises has realized $13 million of energy-related gross margin through September 2005 and is on target to earn the $14 million in energy-related gross margin projected for 2005.

In March 2004, ISO-NE filed a proposal at the FERC to implement LICAP requirements.  LICAP is an administratively determined electric generation capacity pricing mechanism intended to provide a revenue stream sufficient to maintain existing generation assets and encourage the construction of new generation assets at levels sufficient to serve peak load, plus a fixed reserve margin and a statistically-determined contingency.  In June 2004, the FERC ordered the creation of five LICAP zones, including two in Connecticut, and accepted ISO-NE’s demand curve methodology.  The demand curve will be used to determine pricing.  The FERC ordered LICAP to be implemented by January 1, 2006 and set certain issues pertaining to the demand curve for hearings.  The hearings on the demand curve and associated issues ended on March 31, 2005, and an initial decision from the FERC ALJ was issued on June 15, 2005.  The ALJ largely adopted the demand curve as filed by ISO-NE.  

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On August 10, 2005, FERC scheduled oral arguments on LICAP for September 20, 2005 and delayed the implementation of the LICAP mechanism, if it proceeds, to no earlier than October 1, 2006.  At the September 20, 2005 oral arguments, state regulators and certain market participants suggested alternatives to the ISO-NE-proposed LICAP mechanism.  A FERC settlement judge has been assigned to the case, with a deadline for settlement of January 31, 2006.

If LICAP is implemented as recommended by the FERC ALJ, NU Enterprises’ pumped storage, conventional hydroelectric and coal-fired generation assets will be eligible for significant LICAP revenues.

Management believes that if the FERC approves LICAP to take effect on January 1, 2007 consistent with the ALJ recommendation, NU Enterprises will receive approximately $80 million of capacity and forward reserve revenue in 2007.  If there is no LICAP market in 2007, it is estimated, based on current capacity values, that the capacity and forward reserve revenue will be approximately $40 million.  

Management also believes that even without the introduction of LICAP, capacity prices will increase to above $3 a kilowatt-month by 2009 with significant additional revenue from forward reserves.  Based on projections related to the New England load growth and capacity situation, management believes that the capacity and forward reserve revenue without LICAP could reach $90 million by 2009 which is significantly above the $50 million projected earlier in 2005.  With LICAP, management believes that capacity-related revenue would still be approximately $120 million.  Because capacity revenues are highly dependent on the amount of available generating capacity compared with peak customer load, management is not certain that such revenues will actually be realized.

Certain sales contracts used by merchant generation to sell forward amounts to be generated do not meet the criteria for the normal election and accrual accounting.  Management has not designated hedge accounting for these contracts, and the contracts are marked-to-market with changes in fair value included in earnings.  At September 30, 2005, Select Energy had generation derivative assets and liabilities as follows:   

(Millions of Dollars)
Current generation derivative liabilities	$(6.1)
Long-term generation derivative liabilities	(1.2)
Portfolio position	$(7.3)

The methods used to determine the fair value of generation contracts are identified and segregated in the table of fair value of contracts at September 30, 2005.  A description of each method is noted within the retail marketing section above.

As of and for the quarter and nine months ended September 30, 2005, the sources of the fair value of generation contracts and the changes in fair value of these contracts are included in the following tables:  

(Millions of Dollars)	Fair Value of Generation Contracts at September 30, 2005
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	$(3.4)	$(1.2)	$   -	$(4.6)
Prices provided by external sources	(2.7)	-	-	(2.7)
Totals	$(6.1)	$(1.2)	$   -	$(7.3)

(Millions of Dollars)	Three Months Ended September 30, 2005	Nine Months Ended September 30, 2005
	Total Portfolio Fair Value	Total Portfolio Fair Value
Fair value of generation contracts outstanding   at beginning of period	$     -	$     -
Contracts realized or otherwise settled during the period	-	-
Changes in fair value of contracts	(7.3)	(7.3)
Fair value of merchant generation contracts   outstanding at end of period	$(7.3)	$(7.3)

The change in fair value of merchant generation contracts is included in revenue on the accompanying condensed consolidated statements of (loss)/income.  

Wholesale Contracts:  As a result of NU’s decision to exit the wholesale marketing and trading businesses, certain wholesale energy contracts previously accounted for under accrual accounting were required to be marked-to-market in the first quarter 2005.  Existing energy trading contracts have been and will continue to be marked-to-market with changes in fair value reflected in the income statement.  

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At September 30, 2005, Select Energy had wholesale derivative assets and derivative liabilities as follows:   

(Millions of Dollars)
Current wholesale derivative assets	$   694.7
Long-term wholesale derivative assets	229.4
Current wholesale derivative liabilities	(798.2)
Long-term wholesale derivative liabilities	(365.8)
Portfolio position	$ (239.9)

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

Select Energy has policies and procedures requiring all wholesale positions to be marked-to-market at the end of each business day and segregating responsibilities between the individuals actually transacting (front office) and those confirming the trades (middle office).  The determination of the portfolio’s fair value is the responsibility of the middle office independent from the front office.

The methods used to determine the fair value of wholesale energy contracts are identified and segregated in the table of fair value of contracts at September 30, 2005.  A description of each method is as follows: 1) prices actively quoted primarily represent NYMEX futures, swaps and options 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 or natural gas, and are marked to the mid-point of bid and ask market prices.  Currently, Select Energy has several contracts for which a portion of the contract’s fair value is determined based on a model or other valuation method.  The model primarily utilizes natural gas prices and a conversion factor to electricity.  Broker quotes for electricity at locations for which Select Energy has entered into deals are generally available through the year 2008.  For all natural gas positions, broker quotes extend through 2013.

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.  

As of and for the quarter and nine months ended September 30, 2005, the sources of the fair value of wholesale contracts and the changes in fair value of these contracts are included in the following tables:

(Millions of Dollars)	Fair Value of Wholesale Contracts at September 30, 2005
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	$   38.9	$      8.0	$        -	$    46.9
Prices provided by external sources	(142.4)	(102.0)	(5.1)	(249.5)
Models based	-	(17.7)	(19.6)	(37.3)
Totals	$(103.5)	$(111.7)	$ (24.7)	$(239.9)

(Millions of Dollars)	Three Months Ended September 30, 2005	Nine Months Ended September 30, 2005
	Total Portfolio Fair Value	Total Portfolio Fair Value
Fair value of wholesale contracts outstanding   at beginning of period	$(250.0)	$  (49.0)
Contracts realized or otherwise settled during the period	111.3	161.2
Changes in fair value of contracts	(101.2)	(338.7)
Changes in model based assumption	-	14.3
Changes in fair value – other	-	(27.7)
Fair value of wholesale contracts outstanding  at end of period	$(239.9)	$(239.9)

Changes in fair value of wholesale contracts are recorded as wholesale contract market changes, net on the accompanying condensed consolidated statements of (loss)/income, while changes in fair value of contracts formerly designated as trading are recorded as revenue and changes in fair value of gas contracts are recorded as fuel, purchased and net interchange power on the accompanying condensed consolidated statements of (loss)/income.  Select Energy’s wholesale contract market changes of $359.7 million for the nine months ended September 30, 2005 consists of the negative change in fair value of $338.7 million above, a first quarter positive

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change in fair value of certain retail contracts retained to support the retail marketing business of $30 million (see retail marketing activities), $36.8 million of contract asset write-offs and a $14.2 million loss on a first quarter contract termination payment.

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 written 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 establishing credit limits prior to Select Energy’s entering into contracts.  The appropriateness of these limits is subject to continuing review.  Concentrations among these counterparties may affect Select Energy’s overall exposure to credit risk, either positively or negatively, in that the counterparties may be similarly affected by changes to economic, regulatory or other conditions.  At September 30, 2005, approximately 74 percent of Select Energy’s counterparty credit exposure to wholesale and trading counterparties was collateralized or rated BBB- or better.  Select Energy was provided $209.5 million and $57.7 million of counterparty deposits at September 30, 2005 and December 31, 2004, respectively.  For further information, see Note 1K, “Summary of Significant Accounting Policies - Counterparty Deposits,” to the condensed consolidated financial statements.

Critical Accounting Policies and Estimates Update

Evaluation of Discontinued Operations Presentation:  During 2005, NU recorded restructuring and impairment charges associated with NU Enterprises’ decision to exit the wholesale marketing business and to divest the energy services businesses.  In order for discontinued operations treatment to be appropriate, management must conclude that there is a component of a business that is “held for sale” in accordance with the provisions of Statement of Financial Accounting Standards (SFAS) No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” and that it meets the criteria for discontinued operations.  Based on the status of the sale of the service businesses, at this point in time discontinued operations presentation is only appropriate for SESI, SECI-NH, Woods Network and Woods Electrical.  For further information regarding these companies, see Note 4, “Assets Held for Sale and Discontinued Operations,” to the condensed consolidated financial statements.  Management will continue to evaluate this classification in the fourth quarter of 2005 for the remaining NU Enterprises’ businesses that are being exited and divested.

Long-Lived Assets:  The company evaluates long-lived assets such as property, plant and equipment to determine if they are impaired when events or changes in circumstances such as the following occur:

·

A significant decrease in the market price of a long-lived asset, or adverse change in an asset’s use or physical condition or in regulatory factors or business climate,

·

An unanticipated accumulation of costs for the acquisition or construction of an asset,

·

A current-period loss combined with a history of losses or expected future losses or

·

A current expectation that an asset will more likely than not be disposed of significantly before the end of its previously estimated useful life.

For long-lived assets held and used, an impairment loss is recognized if the carrying amount of an asset is not recoverable and exceeds its fair value.  The carrying amount is not recoverable if it exceeds the sum of the undiscounted future cash flows expected to result from the use and eventual disposition of the asset.  When the company believes one of the above events or changes in circumstances has occurred, the company estimates the undiscounted future cash flows associated with the long-lived asset or asset group.  This necessarily requires the company to estimate uncertain future cash flows.

In order to estimate an asset’s future cash flows, the company considers historical cash flows, changes in the market and other factors that may affect future cash flows.  If the company is considering alternative ways to recover the carrying amount of an asset, such as retaining or selling it, the company probability-weights the alternative estimated cash flows.  The company considers various relevant factors, including forward price curves for energy, fuel costs, and operating costs.  

If the estimated undiscounted cash flows from an asset held and used are less than the carrying amount of the asset, or if the company has classified an asset as “held for sale” under SFAS No. 144, the company then estimates the asset’s fair value to determine the amount of any impairment loss.  For assets held for sale, the company reduces the estimate of fair value by expected costs to sell.  The process of estimating fair value involves judgment.  The company considers quoted market prices in active markets, but if these are unavailable the company may consider prices of similar assets, consult with brokers, or employ other valuation techniques such as a

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present value method that probability-weights a range of possible outcomes.  The use of these techniques also involves the projection of inherently uncertain future cash flows.  

Actual future market prices, costs and cash flows could vary significantly from those assumed in the estimates, and the impact of such variations could be material.

Derivative Accounting: Most of the contracts used in Select Energy’s generation, retail marketing, and wholesale marketing activities are derivatives, and many Utility Group contracts for the purchase or sale of energy or energy-related products are derivatives.  The application of derivative accounting under SFAS No. 133, as amended, is complex and requires management judgment in the following respects: election and designation of the normal purchases and sales exception, identification of derivatives and embedded derivatives, identifying hedge relationships, assessing and measuring hedge ineffectiveness, and determining the notional amount and fair value of derivatives.  All of these judgments, depending upon their timing and effect, can have a significant impact on NU’s consolidated net income.

The fair value of derivatives is based upon the notional amount of a contract and the underlying market price or fair value per unit. When quantities are not specified in the contract, the company estimates notional amounts using amounts referenced in default provisions and other relevant sections of the contract.  The notional amount is updated during the term of the contract, and updates can have a material impact on mark-to-market amounts.

The judgment applied in the election of the normal purchases and sales exception (and resulting accrual accounting) includes the conclusion that it is probable at the inception of the contract and throughout its term that it will result in physical delivery and that the quantities will be used or sold by the business over a reasonable period in the normal course of business.  If facts and circumstances change and management can no longer support this conclusion, then the normal exception and accrual accounting would be terminated and fair value accounting would be applied.  Cash flow hedge contracts that are designated as hedges for contracts for which the company has elected the normal purchases and sales exception can continue to be accounted for as cash flow hedges only if the normal exception for the hedged contract continues to be appropriate.  If the normal exception is terminated, then the hedge designation would be terminated at the same time.

Income Taxes:  Income tax expense is calculated in each reporting period in each of the jurisdictions in which NU operates.  This process involves estimating actual current tax expense or benefit as well as the income tax impact of temporary differences resulting from differing treatment of items, such as timing of the deduction and expenses, for tax and book accounting purposes.  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.  Adjustments made to income tax estimates can significantly affect NU’s condensed consolidated financial statements.

The estimates that are made by management in order to record income tax expense are compared each year to the actual tax amounts included on NU’s income tax returns as filed.  The income tax returns are filed in the fall for the previous tax year.  Management adjusted NU’s tax reserves to reflect the difference in the actual tax return amounts being compared to the year end estimated tax expense amounts.  Recording these tax reserve adjustments resulted in a positive/(negative) impact in the third quarter on NU’s earnings as follows (in millions):

	2005	2004
CL&P	$(0.3)	$ (3.2)
PSNH	1.3	5.4
WMECO	0.2	0.6
NU Enterprises	(1.0)	1.8
Other companies	(0.4)	(0.9)
Total	$(0.2)	$  3.7

Truing up income tax amounts between the consolidated financial statements and the income tax returns is an annual process.  

Goodwill Impairment Testing:  NU conducts annual goodwill impairment testing as of October 1st. Testing of current goodwill balances commenced in October of 2005.

Other Matters

Share-Based Payments:  On December 16, 2004, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (SFAS) No. 123 (Revised 2004), “Share-Based Payments,” (SFAS No. 123R), which amended SFAS No. 123, “Accounting for Stock-Based Compensation.”  Under the provisions of SFAS No. 123R, NU will recognize compensation expense for the unvested portion of previously granted awards outstanding on January 1, 2006, the effective date of SFAS No. 123R, and any new

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awards after that date.  NU is currently determining the amount of compensation expense to be recognized, but management believes that the adoption of SFAS No. 123R will not have a material impact on NU’s consolidated financial statements.  For information regarding current accounting for equity-based compensation, see Note 1F, “Summary of Significant Accounting Policies - Equity-Based Compensation,” to the condensed consolidated financial statements.

Asset Retirement Obligations:  On January 1, 2003, NU implemented SFAS No. 143, “Accounting for Asset Retirement Obligations,” requiring legal obligations associated with the retirement of property, plant and equipment to be recognized as a liability at fair value when incurred and when a reasonable estimate of the fair value of the liability can be made.  Upon adoption of SFAS No. 143, management identified certain conditional asset retirement obligations relating to transmission and distribution lines and poles, telecommunication towers, transmission cables, certain assets containing asbestos, and certain FERC or state regulatory agency re-licensing matters, and determined that no material asset retirement obligations had been incurred.  In March 2005, the FASB issued Interpretation No. 47 (FIN 47), “Accounting for Conditional Asset Retirement Obligations - an interpretation of FASB Statement No. 143.”  FIN 47 requires an entity to recognize a liability for the fair value of an asset retirement obligation even if it is conditional on a future event if the liability’s fair value can be reasonably estimated.  FIN 47 is required to be implemented by December 31, 2005 by recording a liability for the fair value of conditional asset retirements with the impact of implementation recognized as a cumulative effect in the income statement.  Management is currently evaluating NU’s conditional asset retirement obligations.  Management has completed its initial identification of potential conditional retirement obligations (AROs) and has identified six potential categories of AROs.  A fair value calculation, reflecting various probabilities and settlement scenarios, and a data consistency review across all operating companies, is currently being performed and will be completed in the fourth quarter of 2005.  For those AROs recorded at the regulated companies, management believes the costs will be recovered from its customers; therefore, a regulatory asset would be recorded.  Until this work is completed, management will not be able to determine whether implementation of FIN 47 will have a material effect on NU’s condensed consolidated financial statements.  

Consolidated Edison, Inc. Merger Litigation:  Certain gain and loss contingencies continue to exist with regard to the October 13, 1999 Agreement and Plan of Merger between NU and Consolidated Edison, Inc. (CEI) and the related litigation.  On October 12, 2005, a panel of three judges of the United States Court of Appeals for the Second Circuit determined that NU shareholders do not have the right to assert a claim against CEI for damages related to breach of the agreement.  The ruling left intact the remaining claims between NU and CEI for breach of contract, which include NU’s claim for recovery of costs and expenses of approximately $32 million and CEI’s claim for damages of  “at least $314 million.”  NU filed for a rehearing and requested review by the full Court of Appeals on October 26, 2005.  At this stage, NU cannot predict the outcome of this matter or its ultimate effect on NU.  

Commitments and Contingencies:  For further information regarding other commitments and contingencies, see Note 7, “Commitments and Contingencies,” to the condensed consolidated financial statements.

Contractual Obligations and Commercial Commitments:  For updated information regarding NU’s contractual obligations and commercial commitments at September 30, 2005, see Note 7C, “Commitments and Contingencies - Long-Term Contractual Arrangements,” to the condensed consolidated 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 inc lude, but are not limited to, actions by state and federal regulatory bodies, competition and industry restructuring, changes in economic conditions, changes in weather patterns, changes in laws, regulations or regulatory policy, expiration or initiation of significant energy supply contracts, changes in levels of capital expenditures, developments in legal or public policy doctrines, technological developments, volatility in electric and natural gas commodity markets, effectiveness of our risk management policies and procedures, changes in accounting standards and financial reporting regulations, fluctuations in the value of electricity positions, methods, timing and results of disposition of competitive businesses, terrorist attacks on domestic energy facilities and other presently unknown or unforeseen factors. Other risk factors are detailed from time to time in our reports to the SEC.  Management 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 http://www.nu.com/.

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Risk Factors

NU is subject to a variety of significant risks in addition to the matters set forth under “Other Matters” above.  The company’s susceptibility to certain risks, including those discussed below, could exacerbate other risks.  These risk factors should be considered carefully in evaluating the company’s risk profile.

Risks Related to Disposition of Competitive Businesses:  In March 2005, NU announced the decision to exit its wholesale marketing business and divest its energy services businesses, and on November 7, 2005 announced the decision to exit the remainder of its competitive businesses, retail marketing and generation.

NU Enterprises has disposed of a portion of its wholesale business and is in the process of selling certain of its services businesses. To date, NU Enterprises has paid or agreed to pay an aggregate of approximately $242 million either to counterparties or third parties to extinguish its wholesale obligations.  Because of recent energy price movements, these transactions are proving far costlier than NU anticipated in March, significantly affecting NU’s liquidity and financial condition. NU's ability to execute the remainder of its divestiture plan and meet its other corporate objectives could be negatively affected if it is unable to procure needed capital.

While the energy services businesses present a lower level of volatility and risk, the wholesale marketing business, until fully disposed of, will continue to present financial risk to NU from a variety of perspectives.  These include earnings volatility around Select Energy’s portfolio of electric supply contracts, which are accounted for on a mark-to-market basis until disposed of.  NU has recorded after tax losses associated with this portfolio during the first, second and third quarters of $120.1 million, $44.2 million and $75 million, respectively.  The combined first, second and third quarter after tax aggregate earnings charge of $239.3 million may not be adequate to absorb future negative price movements which may occur or if further charges are taken as the portfolio is divested.  Two large remaining wholesale contracts expiring in 2008 and 2013, respectively, pose an additional level of risk due to the possibility that Select Energy may have to serve much higher levels of load than were previously anticipated.  NU expects, at present price levels, to record a pre-tax charge of $37 million in the fourth quarter to purchase supply for an increase in the load forecasts related to these contracts.  In addition, several recent wholesale contract terminations cost significantly more than Select Energy’s mark-to-market at the time of termination.  Future contract settlements could also be at amounts worse than NU’s mark-to-market amounts.

Select Energy will continue to be dependent upon the financial reliability of its counterparties and its ability to manage its wholesale marketing portfolio of contracts and assets within acceptable risk parameters until these contracts are divested.

The decision to exit the retail marketing and generation businesses could have material negative financial implications for the fourth quarter of 2005 or in 2006, depending on the outcome of a number of factors, including the resolution of certain accounting issues related to impairment of assets and goodwill, recognition of closure costs, recognition of losses in settling energy contracts and recognition of changes in the fair value of derivative contracts.  For information regarding these loss contingencies, see Note 13, “Subsequent Events,” to the condensed consolidated financial statements.

NU expects to achieve such disposition by the end of 2006.  Exiting from Select Energy’s retail obligations could have an adverse impact on NU’s liquidity.  NU’s equity investment in its combined wholesale, retail and generation businesses is approximately $156.4 million at September 30, 2005.  Should it fail to realize this amount on sale of these businesses, it could incur further charges.  

Risks Related to Liquidity and Collateral Calls:  NU’s Moody’s and S&P senior unsecured debt ratings are currently Baa2 and BBB-, respectively, with stable outlooks.  Were either of these ratings to decline to sub-investment grade, Select Energy could be asked to provide, as of September 30, 2005, approximately $533 million of collateral or LOCs to unaffiliated counterparties and $125 million to several independent system operators and LDCs.  NU’s presently available credit facilities would be adequate to meet such calls. Its ability to meet any future calls would depend on its liquidity and access to bank lines and the market at such time.  

Risks Related to Future Financings:  NU expects to obtain the liquidity needed to dispose of its remaining wholesale and retail marketing businesses through bank borrowings and a portion of the proceeds from the planned sale of approximately $300 million of common shares which could occur as early as the fourth quarter of 2005 or early 2006. While NU is reasonably confident these transactions can be effected on a timely basis and reasonable terms, failure to obtain such financing could delay its ability to exit its competitive businesses and constrain its ability to finance regulated capital projects.  In addition, any downgrade of NU’s operating company ratings could negatively impact the cost or availability of capital to such companies.

Risks Related to NU Enterprises’ Wholesale and Retail Marketing and Merchant Generation Businesses:  Until Select Energy disposes of its retail supply business, it will be subject to a number of ongoing risks which are similar, though of a lesser magnitude, to those of the wholesale marketing business.  Fluctuations in prices, fuel costs, competitive conditions, regulations, weather, transmission costs, lack of market liquidity, plant outages and other factors can all impact the retail business adversely from time to

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time. Extreme price volatility in the third quarter appears to be responsible for a decline in new business in both the retail gas and electric sectors, which may affect Select Energy’s ability to dispose of this business in accordance with its present expectations.

A significant portion of Select Energy’s competitive energy marketing activities has been providing electricity to full requirements customers, which are primarily regulated LDCs and commercial and industrial retail customers. Under the terms of full requirements contracts, Select Energy is required to provide a percentage of the LDC’s electricity requirements at all times. The volumes sold under these contracts vary based on the usage of the LDC’s retail electric customers, and usage is dependent upon factors outside of Select Energy’s control, such as unanticipated migration or inflow of customers. The varying sales volumes could be different than the supply volumes that Select Energy expected to utilize, either from its owned limited generation or from electricity purchase contracts, to serve the full requirements contracts. Differences between actual sales volumes and supply volumes can require Select Energy to purchase additional electricity or sell excess electricity, both of which are subject to market conditions such as weather, plant availability, transmission congestion, and potentially volatile price fluctuations that can impact prices and, in turn, Select Energy’s margins.

The competitive generation business is also subject to these risks.  In addition, although the market price of near and long-term capacity has increased, the future value of LICAP credits have not been determined and are subject to regulatory decision-making over which NU has no control.  

Risks Associated with the Transmission Operations of NU’s Utility Subsidiaries:  NU, primarily through its subsidiary CL&P, has undertaken a substantial transmission capital investment program over the past several years and expects to invest more than $2.3 billion in regulated electric transmission infrastructure from 2006 through 2010.  Included in this amount is approximately $1.5 billion for costs associated with construction of two Connecticut 345 kV transmission lines from Middletown to Norwalk and Bethel to Norwalk; replacement of an undersea electric transmission line between Norwalk and Northport, New York; and two 115 kV underground transmission lines between Norwalk and Stamford, Connecticut.  The regulatory approval process for these transmission projects has encompassed an extensive permitting, design and technical approval process.  Various factors have resulted in increased cost estimates and delayed construction.  Recoverability of all such investments in rates may be subject to prudence review at the FERC at the time such projects are placed in service.  While NU believes that all such expenses have been prudently incurred, it cannot predict the outcome of future reviews should they occur.  

The projects are expected to help alleviate reliability issues in southwest Connecticut and to help reduce customers’ costs in all of Connecticut.  However, if due to further regulatory or other delays, the projected in-service date for one or more of these projects is delayed, there may be increased risk of failures in the existing electricity transmission system in southwestern Connecticut and supply interruptions or blackouts may occur.  

The successful implementation of NU’s transmission construction plans is also subject to the risk that new legislation, regulations or judicial or regulatory interpretations of applicable law or regulations could impact NU’s ability to meet its construction schedule and/or require NU to incur additional expenses, and may adversely affect its ability to achieve forecasted levels of revenues.

Risks Associated with the Distribution Operations of NU’s Utility Subsidiaries:  CL&P and WMECO procure energy for a substantial portion of their customers via requests for proposal on an annual, semi-annual or quarterly basis.  There is a risk that any given solicitation will not be fully subscribed or that prices will be much higher than current prices.  CL&P and WMECO receive approvals of recovery of these contract prices from the DPUC and DTE, respectively.  While both regulators have consistently approved solicitation processes, results and recovery of costs, management cannot predict the outcome of future solicitation efforts or the regulatory proceedings related thereto.  Recent increases in fuel and energy prices could lead to consumer or regulatory resistance to prompt recovery of such costs.

The energy requirements for PSNH are currently met primarily through PSNH’s generation resources or long-term fixed price contracts.  The remaining energy needs are met through spot market or bilateral energy purchases.  Unplanned forced outages can increase the level of energy purchases needed by PSNH and therefore increase the market risk associated with procuring the necessary amount of energy to meet requirements.  PSNH recovers these costs through its SCRC proceedings, subject to a prudence review.

Litigation-Related Risks:  NU and its affiliates are engaged in litigation that could result in the imposition of large cash awards against them.  This litigation includes 1) civil lawsuits between CEI and NU relating to the parties’ October 13, 1999 Agreement and Plan of Merger and 2) the termination of a decommissioning contract between CYAPC, the stock of which is 49 percent owned by subsidiaries of NU, and Bechtel, in which, among other things, the prudence of NU’s actions has been questioned.  

Further information regarding these legal proceedings, as well as other matters, is set forth in Part I, Item 3, “Legal Proceedings,” in NU’s Form 10-K and in Part II, Item 1, “Legal Proceedings” of all 2005 reports on Form 10-Q.

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NU may also be subject to future litigation based on asserted or unasserted claims and cannot predict the outcome of any of these proceedings.  Adverse outcomes in existing or future litigation could result in the imposition of substantial cash damage awards against us.  

Risks Associated With Environmental Regulation:  NU’s 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 regulation of CO2 and mercury emissions have been proposed in various New England states.  Compliance with these requirements requires NU 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 NU’s business and results of operations, financial position and cash flows.  

NU’s failure to comply with environmental laws and regulations, even if due to factors beyond its 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 NU.  Revised or additional laws could result in significant additional expense and operating restrictions on NU’s facilities or increased compliance costs that would negatively impact competitive generation margins or which may not be fully recoverable in distribution company rates for regulated generation.  The cost impact of any such legislation would be dependent upon the specific requirements adopted and cannot be determined at this time.

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RESULTS OF OPERATIONS - NU CONSOLIDATED

The following table provides the variances in income statement line items for the condensed consolidated statements of (loss)/income for NU included in this report on Form 10-Q for the three and nine months ended September 30, 2005:

	Income Statement Variances (Millions of Dollars) 2005 over/(under) 2004
	Third Quarter				Percent		Nine Months			Percent
Operating Revenues:		$	130		8	%	$	611		12	%
Operating Expenses:
Fuel, purchased and net interchange power		28			3		501			16
Other operation		33			14		96			14
Wholesale contract market changes, net		101			100		360			100
Restructuring and impairment charges		5			100		28			100
Maintenance		8			18		15			11
Depreciation		2			3		8			5
Amortization		37			87		27			27
Amortization of rate reduction bonds		3			7		8			7
Taxes other than income taxes		8			15		8			4
Total operating expenses		225			14		1,051			23
Operating (Loss)/Income		(95)			(a)		(440)			(a)
Interest expense, net		6			9		19			10
Other Income, net		2			37		7			96
(Loss)/income before income tax (benefit) expense		(99)			(a)		(452)			(a)
Income tax (benefit)/expense		(16)			(a)		(150)			(a)
Preferred dividends of subsidiary		-			-		-			-
(Loss)/income from continuing operations		(83)			(a)		(302)			(a)
(Loss)/income from discontinued operations		(4)			(a)		(21)			(a)
Net (Loss)/Income		$		(87)	(a)	%	$		(323)	(a)	%

(a) Percent greater than 100.

Comparison of the Third Quarter of 2005 to the Third Quarter of 2004

Operating Revenues

Operating revenues increased $130 million in the third quarter of 2005, compared with the same period in 2004, primarily due to higher electric distribution revenues ($284 million), and higher gas distribution revenues ($12 million), partially offset by lower revenues from NU Enterprises ($163 million).  

The electric distribution revenue increase of $284 million is primarily due to the components of CL&P, PSNH and WMECO retail rates which are included in regulatory commission approved tracking mechanisms that track the recovery of certain incurred costs ($258 million).  The tracking mechanisms allow for rates to be changed periodically with overcollections refunded to customers or undercollections collected from customers in future periods.  The distribution revenue tracking components increase of $258 million is primarily due to the pass through of higher energy supply costs ($145 million), CL&P FMCC charges ($85 million), higher wholesale revenues ($34 million), and higher CL&P conservation and load management cost recoveries ($3 million).  The distribution component of these companies and the retail transmission component of PSNH which flow through to earnings increased $25 million primarily due to an increase in retail sales volumes and an increase in retail rates.  Regulated retail sales were 6.8 percent higher in the third quarter of 2005 compared to the same period of 2004.

The higher gas distribution revenue of $12 million is primarily due to the increased recovery of gas costs ($9 million) and the January 1, 2005 rate increase.

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The NU Enterprises’ revenue decrease of $163 million is primarily due to the mark-to-mark accounting for certain wholesale contracts related to the business to be exited.  As a result of mark-to-market accounting, receipts under those contracts are netted with expenses to serve those contracts and recorded in fuel, purchased and net interchange power, resulting in reduced revenues by approximately $252 million.  Additionally, revenues are lower primarily due to the wholesale marketing business ($207 million), primarily due to lower electricity volumes, partially offset by higher revenues from the merchant retail business ($99 million) and the impact of eliminating lower intercompany revenue from the Utility Group ($197 million).  

Fuel, Purchased and Net Interchange Power

Fuel, purchased and net interchange power expense increased $28 million in the third quarter of 2005, primarily due to higher purchased power costs for the Utility Group ($388 million), partially offset by lower costs at NU Enterprises ($360 million).  The $388 million increase for the Utility Group is due to an increase for CL&P and WMECO ($352 million) resulting primarily from an increase in standard offer supply costs and higher retail sales, which includes higher third party supplier volume ($189 million), higher expenses for PSNH ($27 million) primarily due to higher energy costs and higher retail sales, and higher Yankee Gas expenses ($9 million) primarily due to increased gas prices.

NU Enterprises’ lower fuel costs of $360 million is primarily due to the mark-to-market accounting for certain wholesale contracts related to the business to be exited ($252 million).  Additionally, fuel costs are lower primarily due to the wholesale marketing business ($214 million) primarily due to lower electricity sales.  These decreases are partially offset by higher fuel costs in the merchant retail business ($99 million).

Other Operation

Other operation expenses increased $33 million in the third quarter of 2005 primarily due to higher CL&P RMR costs and other power pool related expenses ($25 million) and higher administrative and general expenses primarily due to increased pension costs ($9 million).  Also, other business related expenses increased including higher bad debt expense ($3 million) and higher conservation and load management (C&LM) spending ($3 million).  These increases were partially offset by lower expenses for NU Enterprises ($8 million), primarily due to exiting the wholesale marketing business.

Wholesale Contract Market Changes, Net

See Note 2, “Wholesale Contract Market Changes,” to the condensed consolidated financial statements for a description and explanation of these charges.

Restructuring and Impairment Charges

See Note 3, “Restructuring and Impairment Charges and Assets Held for Sale,” to the condensed consolidated financial statements for a description and explanation of these charges.

Maintenance

Maintenance expenses increased $8 million in the third quarter of 2005 primarily due to higher overhead ($4 million) line maintenance, higher transmission expenses ($4 million), and higher substation maintenance expenses ($1 million).

Depreciation

Depreciation increased $2 million in the third quarter of 2005 primarily due to higher CL&P plant balances.

Amortization

Amortization increased $37 million in the third quarter of 2005 primarily due to higher Utility Group recovery of stranded costs.

Amortization of Rate Reduction Bonds

Amortization of rate reduction bonds increased $3 million in the third quarter of 2005 due to the repayment of a higher principal amount as compared to 2004.

Taxes Other Than Income Taxes

Taxes other than income taxes increased $8 million in the third quarter of 2005 due to higher gross earnings tax related to higher CL&P revenues.

Interest Expense, Net

Interest expense, net increased $6 million in the third quarter of 2005 primarily due to the issuance of $280 million of ten-year and thirty-year first mortgage bonds in September 2004 and the issuance of $200 million of first mortgage bonds in April 2005 at CL&P, and higher debt levels and interest rates for NU parent.

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Other Income, Net

Other income, net increased $2 million in the third quarter of 2005 primarily due to higher allowance for funds used during construction (AFUDC) as a result of increased CL&P construction work in progress.  

Income Tax (Benefit)/Expense

Third quarter income tax benefit increased $16 million in the third quarter of 2005 due to higher losses before tax expense and greater favorable flow through adjustments, offset by increases to the deferred state income tax valuation allowance.  The increase in the state income tax valuation allowance was required due to the magnitude of the tax losses limiting the ability to utilize the state tax benefits within the applicable state tax carryforward period.

(Loss)/Income from Discontinued Operations

See Note 4, “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 2005 to the First Nine Months of 2004

Operating Revenues

Operating revenues increased $611 million in the first nine months of 2005, compared with the same period in 2004, primarily due to higher electric distribution revenues ($541 million), higher gas distribution revenues ($52 million), higher regulated transmission revenues ($17 million), and higher revenues from NU Enterprises ($5 million).

The electric distribution revenue increase of $541 million is primarily due to the components of CL&P, PSNH and WMECO retail rates which are included in regulatory commission approved tracking mechanisms that track the recovery of certain incurred costs

($496 million).  The tracking mechanisms allow for rates to be changed periodically with overcollections refunded to customers or undercollections collected from customers in future periods.  The distribution revenue tracking components increase of $496 million is primarily due to the pass through of higher energy supply costs ($322 million), CL&P FMCC charges ($166 million) and higher wholesale revenues ($36 million), partially offset by lower CL&P conservation and load management cost recoveries ($8 million) and lower transition cost recoveries for CL&P and WMECO ($8 million).  The distribution component of these companies and the retail transmission component of PSNH which flow through to earnings increased $45 million primarily due to an increase in retail rates and an increase in retail sales volumes.  

The higher gas distribution revenue of $52 million is primarily due to the increased recovery of gas costs ($42 million) and the January 1, 2005 rate increase.

Transmission revenues increased $17 million in the first nine months of 2005, primarily due to the recovery of 2005 expenses as allowed under Tariff Schedule 21, a higher transmission investment base and the incremental recovery of 2004 expenses as allowed under FERC Tariff Schedule 21.

The NU Enterprises’ revenue increase of $5 million is primarily due to higher revenues from the merchant retail business ($219 million) and the impact of eliminating lower intercompany revenue from the Utility Group ($527 million).  This increase is partially offset by lower revenues from the mark-to-market accounting for certain wholesale contracts related to the business to be exited ($543 million) and lower revenues from the wholesale marketing business primarily due to lower electricity volumes ($206 million).  

Fuel, Purchased and Net Interchange Power

Fuel, purchased and net interchange power expense increased $501 million in the first nine months of 2005, primarily due to higher purchased power costs for the Utility Group ($972 million), partially offset by lower costs at NU Enterprises ($471 million).  The $972 million increase for the Utility Group is due to an increase for CL&P and WMECO ($859 million) resulting primarily from an increase in standard offer supply costs and higher retail sales, which includes higher third party supplier volume ($523 million), higher expenses for PSNH ($71 million) primarily due to higher energy costs and higher retail sales, and higher Yankee Gas expenses ($42 million) primarily due to increased gas prices.

NU Enterprises’ lower fuel costs of $471 million is primarily due to the mark-to-market accounting for certain wholesale contracts related to the business to be exited ($543 million).  Additionally, fuel costs are lower primarily due to the wholesale marketing business ($148 million) primarily due to lower electricity sales.  These decreases are partially offset by higher fuel costs in the merchant retail business ($220 million).

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Other Operation

Other operation expenses increased $96 million in the first nine months of 2005 primarily due to higher CL&P RMR costs and other power pool related expenses ($65 million) and higher administrative and general expenses primarily due to increased pension costs ($26 million).  Also, other business related expenses increased including higher bad debt expense ($8 million) and higher expenses for NU Enterprises ($8 million).  These increases were partially offset by lower C&LM spending ($7 million).

NU Enterprises’ other operating expenses increased $8 million primarily due to higher transmission expenses during the first six months of 2005, partially offset by lower third quarter wholesale other operating expenses as a result of exiting the business.

Wholesale Contract Market Changes, Net

See Note 2, “Wholesale Contract Market Changes,” to the condensed consolidated financial statements for a description and explanation of these charges.

Restructuring and Impairment Charges

See Note 3, “Restructuring and Impairment Charges and Assets Held for Sale,” to the condensed consolidated financial statements for a description and explanation of these charges.

Maintenance

Maintenance expenses increased $15 million in the first nine months of 2005 primarily due to higher overhead ($7 million) and underground ($2 million) line maintenance, higher transmission expenses ($4 million), and higher substation maintenance expenses ($2 million).

Depreciation

Depreciation increased $8 million in the first nine months of 2005 primarily due to higher CL&P plant balances.

Amortization

Amortization increased $27 million in the first nine months of 2005 primarily due to higher Utility Group recovery of stranded costs.

Amortization of Rate Reduction Bonds

Amortization of rate reduction bonds increased $8 million in the first nine months of 2005 due to the repayment of a higher principal amount as compared to 2004.

Taxes Other Than Income Taxes

Taxes other than income taxes increased $8 million in the first nine months of 2005 due to higher gross earnings tax related to higher CL&P revenues.

Interest Expense, Net

Interest expense, net increased $19 million in the first nine months of 2005 primarily due to the issuance of $280 million of ten-year and thirty-year first mortgage bonds in September 2004 and the issuance of $200 million of first mortgage bonds in April 2005 at CL&P.  Additionally, the increase is primarily due to higher debt levels and interest rates at NU Parent and higher interest related to the final decision on the streetlight refund docket.

Other Income, Net

Other income, net increased $7 million in the first nine months of 2005 primarily due to higher AFUDC as a result of increased CL&P construction work in progress ($6 million), higher interest and dividend income ($2 million) and a gain on the sale of land by HWP ($1 million),

Income Tax (Benefit)/Expense

Income tax expense decreased $150 million from an expense of $40 million to a benefit of $110 million in the first nine months of 2005 due to a loss before tax expense and greater favorable flow through adjustments, offset by increases to the deferred state income tax valuation allowance.  The increase in the state income tax valuation allowance was required due to the magnitude of the tax losses limiting the ability to utilize the state tax benefits within the applicable state tax carryforward period.

(Loss)/Income from Discontinued Operations

See Note 4, “Assets Held for Sale and Discontinued Operations,” to the condensed consolidated financial statements for a description and explanation of the discontinued operations.

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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 2005 reports on Form 10-Q and the NU 2004 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 third quarter and the nine months ended September 30, 2005:

	Income Statement Variances (Millions of Dollars) 2005 over/(under) 2004
	Third Quarter			Percent		Nine Months			Percent
Operating Revenues:		$	227	31	%	$	436		20	%
Operating Expenses:
Fuel, purchased and net interchange power		156		36		317			24
Other operation		35		32		74			23
Maintenance		6		25		13			23
Depreciation		3		11		11			12
Amortization of regulatory assets, net		22		(a)		19			(a)
Amortization of rate reduction bonds		2		7		6			7
Taxes other than income taxes		7		21		5			4
Total operating expenses		231		35		445			23
Operating (Loss)/Income		(4)		(6)		(9)			(5)
Interest expense, net		3		10		11			13
Other Income, net		4		74		3			19
(Loss)/income before income tax expense		(3)		(7)		(17)			(15)
Income tax (benefit)/expense		(7)		(36)		(14)			(33)
Preferred dividends of subsidiaries		-		-		-			-
Net (Loss)/Income		$	4	20	%	$		(3)	(4)	%

(a) Percent greater than 100.

Comparison of the Third Quarter of 2005 to the Third Quarter of 2004

Operating Revenues

Operating revenues increased $227 million in the third quarter of 2005, compared with the same period in 2004, due to higher distribution revenues ($224 million) and higher transmission revenues ($3 million).  

The distribution revenue increase of $224 million is primarily due to the components of retail rates which are included in regulatory commission approved tracking mechanisms that track the recovery of certain incurred costs ($207 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 rates which impact earnings increased $17 million as a result of higher sales ($14 million) and the retail rate increase effective January 1, 2005.  Retail sales in the third quarter of 2005 were 7.4 percent higher than the same period last year.  

The distribution revenue tracking components increased $207 million primarily due to higher TSO related revenues ($100 million), an increase in revenues associated with the recovery of FMCC charges ($85 million), higher wholesale revenues ($28 million) primarily due to higher market prices for the sales of IPP contract related power, and an increase in revenues associated with recovery of

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conservation and load management and renewable energy costs ($5 million), partially offset by the absence of the 2004 positive impact of the DPUC order in the petition for reconsideration docket ($10 million).

Fuel, Purchased and Net Interchange Power

Fuel, purchased and net interchange power expense increased $156 million in the third quarter of 2005 primarily due to higher TSO supply costs as a result of the higher retail sales and a higher cost per KWh in 2005.

Other Operation

Other operation expenses increased $35 million in the third quarter of 2005 primarily due to higher RMR costs ($31 million) which are tracked and recovered through the FMCC,  higher administrative and general expenses ($5 million) primarily due to higher pension expense, and higher C&LM expenses ($3 million), partially offset by lower retail transmission expense charged to distribution ($5 million).

Maintenance

Maintenance expenses increased $6 million in the third quarter of 2005 due to higher expenses related to distribution lines maintenance ($5 million), in part due to heat related and storm activity, and higher tree trimming expenses ($1 million).

Depreciation

Depreciation expense increased $3 million in the third quarter of 2005 primarily due to higher utility plant balances resulting from plant additions.

Amortization of Regulatory Assets, Net

Amortization of regulatory assets, net increased $22 million in the third quarter of 2005 primarily due to higher amortization related to the recovery of transition charges as a result of higher wholesale revenues.

Amortization of Rate Reduction Bonds

Amortization of rate reduction bonds increased $2 million in the third quarter of 2005 due to the repayment of additional principal.

Taxes Other Than Income Taxes

Taxes other than income taxes increased $7 million in the third quarter of 2005 primarily due to higher Connecticut GET (gross earnings tax) resulting from higher revenue ($6 million) and higher property taxes ($1 million).

Interest Expense, Net

Interest expense, net increased $3 million in the third quarter of 2005 primarily due to higher interest on long-term debt ($5 million) as a result of $280 million of new debt issued in September 2004 and $200 million of new debt issued in April 2005, partially offset by lower rate reduction bond interest resulting from lower principal balances outstanding ($2 million).

Other Income, Net

Other income, net increased $4 million in the third quarter of 2005 primarily due to a higher allowance for funds used during construction ($3 million), as a result of increased eligible CWIP for transmission and lower short term debt resulting in a greater component of CWIP being subject to the higher equity rate.

Income Tax Expense

Income tax expense decreased $7 million in the third quarter of 2005 primarily due to adjustments to tax reserves as a result of actual tax return amounts compared to year-end estimates that increased tax expense in September 2004 by $2 million compared to September 2005, lower pre-tax income, greater favorable flow through adjustments for plant related items, and lower state tax due to lower rates and higher credits.  The effective tax rate decreased from 46.5 percent to 31.8 percent due to these items.

Comparison of the First Nine Months of 2005 to the First Nine Months of  2004

Operating Revenues

Operating revenues increased $436 million in the first nine months of 2005, compared with the same period in 2004, due to higher distribution revenues ($422 million) and higher transmission revenues ($14 million).  

The distribution revenue increase of $422 million is primarily due to the components of retail rates which are included in regulatory commission approved tracking mechanisms that track the recovery of certain incurred costs ($392 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 rates which impact earnings increased $30 million, primarily due to increased sales volumes and the retail rate increase effective January 1, 2005, partially offset by the additional reserve recorded to reflect the final

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decision on the streetlight docket ($3 million).  Retail sales for the first nine months of 2005 were 2.7 percent higher than the same period last year.  

The distribution revenue tracking components increased $392 million primarily due to higher TSO related revenues ($225 million), an increase in revenues associated with the recovery of FMCC charges ($166 million), and higher wholesale revenues ($24 million) primarily due to higher market prices for the sales of IPP contract related power , partially offset by the absence of the 2004 positive impact of the DPUC order in the petition for reconsideration docket ($10 million) and lower revenues as a result of lower retail rates for the recovery of system benefit, conservation and load management, and renewable energy costs ($11 million).

Transmission revenues increased $14 million primarily due to higher expenses which are recovered under the NU schedule 21 tariff, higher rate base and additional revenues resulting from the 2004 schedule 21 true-up.

Fuel, Purchased and Net Interchange Power

Fuel, purchased and net interchange power expense increased $317 million in the first nine months of 2005 primarily due to higher TSO supply costs as a result of the higher retail sales and a higher cost per KWh in 2005.

Other Operation

Other operation expenses increased $74 million in the first nine months of 2005 primarily due to higher RMR costs ($60 million) which are tracked and recovered through the FMCC, higher administrative and general expenses ($11 million) primarily due to higher pension expense, and other power pool related expenses recovered through the FMCC charge ($10 million), partially offset by lower C&LM expenses ($6 million) and lower retail transmission expense charged to distribution ($3 million).

Maintenance

Maintenance expenses increased $13 million in the first nine months of 2005 primarily due to higher expenses related to distribution lines maintenance ($11 million) in part due to heat related and storm activity, higher expenses for substation maintenance ($1 million) and higher tree trimming expenses ($1 million).

Depreciation

Depreciation expense increased $11 million in the first nine months of 2005 due to higher utility plant balances resulting from plant additions.

Amortization of Regulatory Assets, Net

Amortization of regulatory assets, net increased $19 million in the first nine months of 2005 primarily due to higher amortization related to the recovery of transition charges as a result of higher wholesale revenues.

Amortization of Rate Reduction Bonds

Amortization of rate reduction bonds increased $6 million in the first nine months of 2005 due to the repayment of additional principal.

Taxes Other Than Income Taxes

Taxes other than income taxes increased $5 million in the first nine months of 2005 primarily due to higher Connecticut GET (gross earnings tax) resulting from higher revenue ($6 million) and higher property taxes ($2 million), partially offset by lower taxes paid in 2005 to the Town of Waterford for lost property tax revenue as a result of the sale of Millstone ($3 million).

Interest Expense, Net

Interest expense, net increased $11 million in the first nine months of 2005 primarily due to higher interest on long-term debt ($13 million) as a result of $280 million of new debt issued in September 2004, $200 million of new debt issued in April 2005, and higher other interest related to the final decision on the streetlight docket ($4 million), partially offset by lower rate reduction bond interest resulting from lower principal balances outstanding ($6 million).

Other Income, Net

Other income, net increased $3 million in the first nine months of 2005 primarily due to a higher allowance for funds used during construction ($5 million), as a result of increased eligible CWIP for transmission and lower short term debt resulting in a greater component of CWIP being subject to the higher equity rate.

Income Tax Expense

Income tax expense decreased $14 million in the first nine months of 2005 primarily due to adjustments to tax reserves as a result of actual tax return amounts compared to year-end estimates that increased tax expense in September 2004 by $2 million compared to September 2005, lower pre-tax income, greater favorable flow through adjustments for plant related items, and lower state tax due to lower rates and higher credits.  The effective tax rate decreased from 38.0 percent to 30.0 percent due to these items.

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LIQUIDITY

Net cash flows from operations increased by $32 million from net cash flows provided by operating activities of $127.2 million for the first nine months of 2004 to $159.2 million for first the nine months of 2005.  The increase primarily relates to accrued taxes arising from higher current tax expense that will be paid in a later quarter.  In addition, the TSO procurement fee, the recovery of FMCC charges, and additional recoverable energy costs totaling an increase of $46.6 million for the nine months ended September 30, 2005 also contributed to the increase.  An offsetting decrease in operating cash flows is due to higher regulatory refunds, primarily due to lower CTA and GSC collections as CL&P refunds amounts to its ratepayers for past overcollections or uses those amounts to recover current costs and changes in working capital items, primarily investments in securitizable assets.  Investments in securitizable assets are receivables and unbilled revenues are eligible to be but have not been sold to the financial institution under CL&P’s receivables sales arrangement.  

Management expects that a separate $400 million revolving credit line for the Utility Group, including CL&P, will not increase but that its maturity date will be extended from its November 2009 expiration date by approximately one year.  CL&P had $30 million borrowed on that credit line at September 30, 2005.  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, 2005, CL&P had sold $100 million to that financial institution.

In April 2005, CL&P sold $200 million of first mortgage bonds the proceeds from which were used to repay short-term borrowings.

CL&P’s capital expenditures totaled $309 million in the first nine months of 2005, compared with $298.2 million in the first nine months of 2004.  CL&P projects capital expenditures to total $420 million in 2005.

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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 2005 reports on Form 10-Q and the NU 2004 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, 2005:

	Income Statement Variances (Millions of Dollars) 2005 over/(under) 2004
	Third Quarter			Percent		Nine Months			Percent
Operating Revenues:		$	49	19	%	$		106	15	%
Operating Expenses:
Fuel, purchased and net interchange power		28		26		74			24
Other operation		2		6		11			9
Maintenance		1		11		(1)			(1)
Depreciation		-		-		-			-
Amortization of regulatory assets, net		19		53		24			32
Amortization of rate reduction bonds		1		6		2			6
Taxes other than income taxes		1		9		1			5
Total operating expenses		52		23		111			17
Operating Income/(Loss)		(3)		(13)		(5)			(7)
Interest expense, net		-		-		1			2
Other Income, net		-		-		1			44
Income/(loss) before income tax expense		(3)		(20)		(5)			(10)
Income tax expense/(benefit)		3		(a)		1			18
Preferred dividends of subsidiaries		-		-		-			-
Net Income		$	(6)	(35)	%	$	(6)		(17)	%

(a) Percent greater than 100.

Comparison of the Third Quarter of 2005 to the Third Quarter of 2004

Operating Revenues

Operating revenues increased $49 million in the third quarter of 2005, as compared to the same period in 2004, primarily due to higher distribution revenue ($50 million), partially offset by lower transmission revenue ($2 million).  The distribution revenue increase of $50 million is primarily due to the components of retail rates which are included in regulatory commission approved tracking mechanisms that track the recovery of certain incurred costs ($44 million).  The tracking mechanisms allow for rates to be changed periodically with over allocations refunded to customers or under collections collected from customers in future periods.  The transition service energy component of retail revenues increased by $39 million primarily due to an increase in the rate in 2005 as compared to 2004.  The distribution and transmission components of retail rates which impact earnings increased $5 million primarily due to the retail rate increases effective October 1, 2004 and June 1, 2005 ($2 million) and higher retail sales ($3 million).  Retail sales increased 4.8 percent in 2005 compared to the same period of 2004.  

Fuel, Purchased and Net Interchange Power

Fuel, purchased and net interchange power increased $28 million primarily due to higher retail sales and the higher cost of energy as a result of higher fuel prices.

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Other Operation

Other operation expenses increased $2 million primarily due to higher administrative expenses as a result of higher pension expense ($2 million) and higher fossil steam expenses ($1 million), partially offset by lower power pool related expenses ($2 million).

Maintenance

Maintenance expense increased $1 million in 2005 primarily due to higher substation and fossil steam plant maintenance.

Amortization of Regulatory Assets, Net

Amortization of regulatory assets, net increased $19 million in 2005 primarily due to an acceleration in the recovery of PSNH’s non-securitized stranded costs.  The acceleration of non-securitized stranded cost recovery was due to the positive reconciliation of stranded cost revenues and stranded cost expense, which also includes net TS/DS costs.

Amortization of Rate Reduction Bonds

Amortization of rate reduction bonds increased $1 million as a result of the repayment of additional principal.

Taxes Other Than Income Taxes

Taxes other than income taxes increased $1 million primarily due to higher property taxes.

Income Tax Expense

Income tax expense increased $3 million in the third quarter of 2005 primarily due to adjustments to tax reserves as a result of actual tax return amounts compared to year-end estimates that reduced tax expense by $5 million in September 2004 and only $1 million in September 2005, partially offset by a lower pre-tax income and lower state unitary taxable income estimated for 2005.  The effective tax rate increased from (3.5) percent to 15.9 percent due to these items.

Comparison of the First Nine Months of 2005 to the First Nine Months of 2004

Operating Revenues

Operating revenues increased $106 million in the first nine months of 2005, as compared to the same period in 2004, primarily due to higher distribution revenue ($103 million) and higher transmission revenue ($3 million).  The distribution revenue increase of $103 million is primarily due to the components of retail rates which are included in regulatory commission approved tracking mechanisms that track the recovery of certain incurred costs ($88 million).  The tracking mechanisms allow for rates to be changed periodically with over allocations refunded to customers or under collections collected from customers in future periods.  The transition service energy component of retail revenues increased by $83 million due to an increase in the rate in 2005 as compared to 2004.  The distribution and transmission components of PSNH’s retail rates which impact earnings increased $9 million primarily due to the retail rate increases effective October 1, 2004 and June 1, 2005 ($6 million) and higher retail sales ($3 million).  Retail sales increased 2.0 percent in 2005 compared to the same period of 2004.  

Fuel, Purchased and Net Interchange Power

Fuel, purchased and net interchange power increased $74 million primarily due to higher retail sales and the higher cost of energy as a result of higher fuel prices.

Other Operation

Other operation expenses increased $11 million as a result of higher administrative expenses ($9 million), primarily due to higher pension and other benefit costs ($6 million), and higher power pool related expenses ($2 million).

Maintenance

Maintenance expense decreased $1 million in 2005 primarily due to lower overhead line maintenance ($2 million), partially offset by higher substation maintenance ($1 million).

Amortization of Regulatory Assets, Net

Amortization of regulatory assets, net increased $24 million in 2005 primarily due to an acceleration in the recovery of PSNH’s non-securitized stranded costs.  The acceleration of non-securitized stranded cost recovery was due to the positive reconciliation of stranded cost revenues and stranded cost expense, which also includes net TS/DS costs.

Amortization of Rate Reduction Bonds

Amortization of rate reduction bonds increased $2 million as a result of the repayment of additional principal.

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Taxes Other Than Income Taxes

Taxes other than income taxes increased $1 million primarily due to higher property taxes.

Interest Expense

Interest expense increased $1 million in 2005 primarily due to higher interest rates on the variable pollution control revenue bonds ($2 million) and the issuance of $50 million of ten-year first mortgage bonds in July 2004 ($1 million), partially offset by lower rate reduction bond interest resulting from lower principal balances outstanding ($2 million).

Other Income, Net

Other income, net increased $1 million in 2005 primarily due to the 2005 recording of a C&LM incentive.

Income Tax Expense

Income tax expense increased $1 million in the first nine months of 2005 primarily due to adjustments to tax reserves as a result of actual tax return amounts compared to year-end estimates that reduced tax expense by $5 million in September 2004 and only $1 million in September 2005, partially offset by a lower pre-tax income and lower state unitary taxable income estimated for 2005.  The effective tax rate increased from 19.5 percent to 25.8 percent due to these items.

LIQUIDITY

Net cash flows from operations increased by $62 million from $122 million for the first nine months of 2004 to $184 million for the first nine months of 2005.  The increase in operating cash flows is due to changes in working capital items, primarily receivables and unbilled revenues.

Management expects that a separate $400 million revolving credit line for the Utility Group, including PSNH, will not increase but that its maturity date will be extended from its November 2009 expiration date by approximately one year.  PSNH had $20 million borrowed on that credit line at September 30, 2005.

On October 5, 2005, PSNH closed on the sale of $50 million 30-year first mortgage bonds with an interest rate of 5.60 percent. Proceeds from the issuance were used to repay short-term borrowings incurred to finance capital expenditures.

PSNH’s capital expenditures totaled $124.5 million in the first nine months of 2005, compared with $86.6 million in the first nine months of 2004.  PSNH projects capital expenditures to total $150 million in 2005.

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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 2005 reports on Form 10-Q and the NU 2004 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, 2005:

	Income Statement Variances (Millions of Dollars) 2005 over/(under) 2004
	Third Quarter				Percent		Nine Months			Percent
Operating Revenues:		$	10		11	%	$	18		6	%
Operating Expenses:
Fuel, purchased and net interchange power		8			14		19			12
Other operation		1			6		6			13
Maintenance		-			-		-			-
Depreciation		-			-		1			8
Amortization of regulatory (liabilities)/assets, net		(4)			(96)		(15)			(a)
Amortization of rate reduction bonds		-			-		-			-
Taxes other than income taxes		(1)			(19)		-			-
Total operating expenses		4			5		11			4
Operating Income		6			(a)		7			26
Interest expense, net		1			23		2			19
Other Income, net		1			(a)		2			(a)
Income before income tax expense		6			(a)		7			48
Income tax expense		3			(a)		4			64
Net Income		$		3	(a)	%	$		3	38	%

(a) Percent greater than 100.  

Comparison of the Third Quarter of 2005 to the Third Quarter of 2004

Operating Revenues

Operating revenues increased $10 million in the third quarter of 2005, as compared to the same period in 2004, due primarily to higher electric distribution revenues ($9 million).

The electric distribution revenue increase of $9 million is primarily due to the components of retail rates which are included in regulatory commission approved tracking mechanisms that track the recovery of certain incurred costs ($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 revenue tracking components increase of $6 million is primarily due to the pass through of higher energy supply costs ($7 million), higher retail transmission revenues ($2 million), and higher wholesale revenues ($1 million), partially offset by lower transition cost recoveries ($3 million).  The distribution component which flow through to earnings increased $3 million primarily due to an increase in retail sales volume.

Fuel, Purchased and Net Interchange Power

Fuel, purchased and net interchange power expense increased $8 million in the third quarter of 2005 due to higher default service supply costs ($6 million) and higher current year purchased power costs ($2 million).

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Other Operation

Other operation expenses increased $1 million in the third quarter of 2005 due to higher administrative and general expense ($1 million) primarily due to higher pension costs.

Amortization of Regulatory (Liabilities)/Assets, Net

Amortization of regulatory (liabilities)/assets, net decreased $4 million in the third quarter of 2005 primarily due to the lower recovery of stranded costs as a result of the decrease in the transition component of retail rates.

Taxes other than income taxes

Taxes other than income taxes decreased $1 million primarily due to lower property taxes.

Interest Expense, Net

Interest expense, net increased $1 million in the third quarter of 2005 primarily due to higher long-term debt levels as a result of the issuance of $50 million of thirty-year senior notes in September 2004 and the issuance of $50 million ten-year senior notes in August 2005.

Other Income, Net

Other income, net increased $1 million in the third quarter of 2005 primarily due to higher interest income and the recording of a C&LM incentive.

Income Tax Expense

Income tax expense increased $3 million in the third quarter of 2005 primarily due to higher pre-tax income and greater unfavorable flow through adjustments.  The effective tax rate increased from 29.2 percent to 42.7 percent due to these items.

Comparison of the First Nine Months of 2005 to the First Nine Months of 2004

Operating Revenues

Operating revenues increased $18 million in the first nine months of 2005, as compared to the same period in 2004, due primarily to higher electric distribution revenues ($15 million) and higher transmission revenues ($3 million).

The electric distribution revenue increase of $15 million is primarily due to the components of retail rates which are included in regulatory commission approved tracking mechanisms that track the recovery of certain incurred costs ($10 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 revenue tracking components increase of $10 million is primarily due to the pass through of higher energy supply costs ($14 million), higher retail transmission revenues ($4 million and higher wholesale revenues ($3 million), partially offset by lower transition cost recoveries ($10 million).  The distribution component which flow through to earnings increased $5 million primarily due to an increase in retail rates ($4 million) and an increase in retail sales volume.  Retail sales were 1.1 percent higher than the same period last year.    

Transmission revenues increased $3 million in the first nine months of 2005, primarily due to the recovery of 2005 expenses as allowed under Tariff Schedule 21, a higher transmission investment base and the incremental recovery of 2004 expenses as allowed under Tariff Schedule 21.

Fuel, Purchased and Net Interchange Power

Fuel, purchased and net interchange power expense increased $19 million in the first nine months of 2005 due to higher default service supply costs ($13 million) and higher current year purchased power costs ($5 million).

Other Operation

Other operation expenses increased $6 million in the first nine months of 2005 due to higher administrative and general expense ($3 million) primarily due to higher pension costs and higher retail transmission expenses ($2 million).

Depreciation

Depreciation expense increased $1 million the first nine months of 2005 primarily due to higher utility plant balances.

Amortization of Regulatory (Liabilities)/Assets, Net

Amortization of regulatory (liabilities)/assets, net decreased $15 million in the first nine months of 2005 primarily due to the lower recovery of stranded costs as a result of the decrease in the transition component of retail rates.

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Interest Expense, Net

Interest expense, net increased $2 million in the first nine months of 2005 primarily due to higher long-term debt levels as a result of the issuance of $50 million of thirty-year senior notes in September 2004 and the issuance of $50 million ten-year senior notes in August 2005.

Other Income, Net

Other income, net increased $2 million in the first nine months of 2005 primarily to higher interest income and the recording of a C&LM incentive.

Income Tax Expense

Income tax expense increased $4 million in the first nine months of 2005 primarily due to higher pre-tax income and greater unfavorable flow through adjustments.  The effective tax rate increased from 39.2 percent to 43.4 percent due to these items.

LIQUIDITY

Net cash flows from operations decreased by $18.5 million from $37.2 million for the first nine months of 2004 to $18.7 million for the first nine months of 2005.  The decrease in operating cash flows is primarily due to the decrease in deferred contractual obligations, offset by increases in receivables and unbilled revenues.

Management expects that a separate $400 million revolving credit line for the Utility Group, including WMECO, will not increase but that its maturity date will be extended from its November 2009 expiration date by approximately one year.  WMECO had $7 million borrowed on that credit line at September 30, 2005.

On August 11, 2005, WMECO closed on the sale of $50 million 10-year senior notes with an interest rate of 5.24 percent.  Proceeds from the issuance were used to repay short-term borrowings incurred to finance capital expenditures.

WMECO’s capital expenditures totaled $30.8 million in the first nine months of 2005, compared with $25.1 million in the first nine months of 2004.  WMECO projects capital expenditures to total $40 million in 2005.

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ITEM 3.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Market Risk Information

Select Energy 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.

NU Enterprises - Retail Marketing Portfolio:  When conducting sensitivity analyses of the change in the fair value of Select Energy’s electricity and natural gas on the retail marketing portfolio, which would result from a hypothetical change in the future market price of electricity and natural gas, the fair values of the contracts are determined from models that take into consideration estimated future market prices of electricity and natural gas, the volatility of the market prices in each period, as well as the time value factors of the underlying commitments. In most instances, market prices and volatility are determined from quoted prices on the futures exchange.

Select Energy has determined a hypothetical change in the fair value for its retail marketing portfolio, which includes cash flow and fair value hedges and electricity and natural gas contracts, assuming a 10 percent change in forward market prices.  At September 30, 2005, a 10 percent increase in market price would have resulted in a pre-tax decrease in fair value of $12.4 million ($7.8 million after-tax) and a 10 percent decrease would have resulted in a pre-tax increase in fair value of $12.7 million ($8 million after-tax).

The impact of a change in electricity and natural gas prices on Select Energy’s retail marketing portfolio at September 30, 2005, is not necessarily representative of the results that will be realized when these contracts are physically delivered.  Most contracts in the retail marketing portfolio are accounted for at delivery, and changes in fair value are not expected to impact earnings.

NU Enterprises - Generation Portfolio:  When conducting sensitivity analyses of the change in the fair value of Select Energy’s electricity on the generation portfolio, 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. In most instances, market prices and volatility are determined from quoted prices.  Models are used for periods beyond 2008.  

Select Energy has determined a hypothetical change in the fair value for its generation portfolio, which is comprised of electricity contracts and generation availability, assuming a 10 percent change in forward market prices.  At September 30, 2005, a 10 percent increase in market price would have resulted in a pre-tax increase in fair value of $174.6 million ($110 million after-tax) and a 10 percent decrease would have resulted in a pre-tax decrease in fair value of $174.7 million ($110 million after-tax).

The impact of a change in electricity prices on Select Energy’s generation portfolio at September 30, 2005, is not necessarily representative of the results that will be realized when these contracts are physically delivered or electricity is generated.  Most contracts in the generation portfolio are accounted for at delivery, and changes in fair value are not expected to impact earnings.

NU Enterprises - Wholesale Transactions to be Divested:  Wholesale contracts include contracts that were marked-to-market in the condensed consolidated statement of (loss)/income.  These contracts included certain long-term below market wholesale electricity contracts, certain shorter-term wholesale contracts of three years or less and certain wholesale electricity positions that were obtained to support Select Energy’s retail marketing contracts.  At September 30, 2005, Select Energy has calculated the market price resulting from a 10 percent change in forward market prices of those contracts.  A 10 percent increase would have resulted as a pre-tax decrease in fair value of $47.9 million ($28.8 million after-tax) and a 10 percent decrease would have resulted in a pre-tax increase in fair value of $47.1 million ($28.3 million after-tax) for the restructuring transactions.

The impact of a change in electricity and natural gas prices on Select Energy’s wholesale transactions at September 30, 2005, are not necessarily representative of the results that will be realized when these contracts are physically delivered.  These transactions are accounted for at fair value, and changes in market prices impact earnings.

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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 debt.  At September 30, 2005, approximately 87 percent (79 percent including the debt subject to the fixed-to-floating interest rate swap in variable rate 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 variable-rate 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 debt subject to the fixed-to-floating interest rate swap, annual interest expense would have increased by $3.9 million.  At September 30, 2005, NU parent maintained a fixed-to-floating interest rate swap to manage the interest rate risk associated with its $263 million of fixed-rate 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, requires 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 operating outside of the business lines that create or actively manage these risk exposures 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, 2005 and December 31, 2004, Select Energy maintained collateral balances from counterparties of $209.5 million and $57.7 million, respectively.  These amounts are included in other current liabilities on the accompanying condensed consolidated balance sheets.  Select Energy also has collateral balances deposited with counterparties of $164.3 million and $46.3 million at September 30, 2005 and December 31, 2004, respectively.

The Utility Group has a lower level of credit risk related to providing regulated electric and gas distribution service than NU Enterprises.  However, the Utility Group companies are subject to credit risk from certain long-term or high-volume supply contracts with energy marketing companies.  The Utility Group manages the credit risk with these counterparties in accordance with established credit risk practices and maintains an oversight group that monitors contracting risks, including credit risk.

NU has formed a Risk and Capital Committee comprised of senior NU officers, which reports to the Chief Executive Officer, to review the risks of large capital projects.  NU has also enlisted external engineering firms as agents on large projects providing engineering, procurement and construction management services and is conducting competitive bids on large components of all major projects.

Additional quantitative and qualitative disclosures about market risk are set forth in "Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations," to the condensed consolidated financial statements herein.

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ITEM 4.

CONTROLS AND PROCEDURES

NU evaluated the design and operation of its disclosure controls and procedures at September 30, 2005 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 concluded, based on their review, that NU’s disclosure controls and procedures were 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 timeframes 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.

During the third quarter of 2005, management enhanced existing internal controls over financial reporting in the area of validating mark-to-market amounts.  As of  September 30, 2005 these enhancements were evaluated and found to be effective.  This represents a significant change in internal controls over financial reporting.  There were no other changes in internal controls over financial reporting that have materially affected, or are reasonably likely to affect NU’s internal control over financial reporting.

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PART II.  OTHER INFORMATION

ITEM 1.

LEGAL PROCEEDINGS  

1.

Consolidated Edison, Inc. v. NU – Merger-Related Litigation and Appeal

In an opinion dated October 12, 2005, a panel of three judges at the United States Court of Appeals for the Second Circuit (Second Circuit) held that the shareholders of NU had no right to sue Consolidated Edison, Inc. (CEI) for its alleged breach of the parties' merger agreement dated October 13, 1999. Accordingly, the Second Circuit reversed: (i) the March 21, 2003 opinion and order of the United States District Court for the Southern District of New York (“District Court”) insofar as it denied CEI’s motion for summary judgment as to NU’s claim for the shareholder premium arising out of such breach and (ii) the May 15, 2004 opinion and order of the District Court insofar as it denied NU’s motion for summary judgment on its cross-claim against former shareholder Robert Rimkoski (for declaratory judgment on Rimkoski’s claim for the premium). As a result of its determination that no shareholder has the right to sue CEI for breach of the merger agreement, the Second Circuit did not reach the second issue presented for review which was whether the right to pursue recovery of the $1 billion merger premium belongs to NU’s current shareholders or shareholders who held shares at the time of the breach. The Second Circuit remanded the case to the District Court for further proceedings consistent with its opinion.

The opinion left intact the remaining claims between NU and CEI for breach of contract, which include NU’s claim for recovery of costs and expenses of approximately $32 million and CEI’s claim for damages of “at least $314 million.”  NU filed for a rehearing and requested review by the full Court of Appeals on October 26, 2005.

For further information on this litigation and related matters, see Part I, Item 3, “Legal Proceedings” in NU’s 2004 10-K and Part II, Item 1, “Legal Proceedings” of its Forms 10-Q for the quarters ended March 31, 2005 and June 30, 2005.

ITEM 2.

UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

The table below sets forth the information with respect to 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, 2005.

Period	Total Number of Shares Purchased (1)	Average Price Paid Per Share	Total Number of  Shares Purchased as Part of Publicly Announced Plans or Programs	Maximum Number of Shares That May Yet Be Purchased Under the Plans or Programs
Month #1 (July 1, 2005 to July 31, 2005)	89	$20.96	-	N/A
Month #2 (August 1, 2005 to August 31, 2005)	-	N/A	-	N/A
Month #3 (September 1, 2005 to September 30, 2005)	-	N/A	-	N/A
Total	89	$20.96	-	N/A

(1) Purchases were made in open market transactions related to a compensation plan for certain trustees of the Company.

ITEM 6.

EXHIBITS

(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 7, 2005

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 7, 2005

100

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 7, 2005

(a)

Listing of Exhibits (CL&P)

31

Certification of Cheryl W. Grisé, Chief Executive Officer of The Connecticut Light and Power Company, required by Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated November 7, 2005

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 7, 2005

32

Certification of Cheryl W. Grisé, 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, dated November 7, 2005

(a)

Listing of Exhibits (PSNH)

4.1.4

Fourteenth Supplemental Indenture, dated as of October 1, 2005, between PSNH and Wachovia Bank, National Association successor to First Union National Bank, as successor to First Fidelity Bank, National Association, as Trustee (Exhibit 99.2 to PSNH Form 8-K filed October 6, 2005)

31

Certification of Cheryl W. Grisé, Chief Executive Officer of Public Service Company of New Hampshire, required by Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated November 7, 2005

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 7, 2005

32

Certification of Cheryl W. Grisé, 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 7, 2005

(a)

Listing of Exhibits (WMECO)

4.2.3

Third Supplemental Indenture between WMECO and The Bank of New York Trust, as Trustee, dated as of August 1, 2005 (Exhibit 4.1, WMECO Form 8-K filed August 12, 2005, File No. 0-7624)

31

Certification of Cheryl W. Grisé, Chief Executive Officer of Western Massachusetts Electric Company, required by Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated November 7, 2005

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 7, 2005

32

Certification of Cheryl W. Grisé, 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 7, 2005

101

10

Material Contracts

10.31

Northeast Utilities System’s Second Amended and Restated Tax Allocation Agreement dated as of September 21, 2005 (Exhibit D.4 to Amendment No. 1 to U5S Annual Report for the year ended December 31, 2004, filed September 30, 2005)

102

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 4, 2005	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 4, 2005	By	/s/ David R. McHale
		David R. McHale
		Senior Vice President and Chief Financial Officer
		(for the Registrant and as Principal Financial Officer)

103

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 4, 2005	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 4, 2005	By	/s/ David R. McHale
		David R. McHale
		Senior Vice President and Chief Financial Officer
		(for the Registrant and as Principal Financial Officer)

104

EX-15

Exhibit 15

November 4, 2005

Northeast Utilities

107 Selden Street

Berlin, CT 06037

We have made a review, in accordance with the standards of the Public Company Accounting Oversight Board (United States), of the unaudited interim financial information of Northeast Utilities and subsidiaries (the "Company") for the periods ended September 30, 2005 and 2004, as indicated in our report dated November 7, 2005 (which report includes explanatory paragraphs related to significant charges recorded due to Company’s decision to exit certain business lines, and the presentation of certain components as discontinued operations); because we did not perform an audit, we expressed no opinion on that information.

We are aware that our report referred to above, which is included in your Quarterly Report on Form 10-Q for the quarter ended September 30, 2005, is incorporated by reference in Registration Statement Nos. 33-34622, 33-40156, and 333-128811 on Forms S-3 and Registration Statement Nos. 33-63023, 333-52413, 333-63144 and 333-106008 on Forms S-8 of Northeast Utilities.

We also are aware that the aforementioned report, pursuant to Rule 436(c) under the Securities Act of 1933, is not considered a part of the Registration Statement prepared or certified by an accountant or a report prepared or certified by an accountant within the meaning of Sections 7 and 11 of that Act.

/s/	Deloitte & Touche LLP
	Deloitte & Touche LLP

Hartford, Connecticut

EX-31

Exhibit 31

CERTIFICATION PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Charles W. Shivery, certify that:

1.

I have reviewed this quarterly report on Form 10-Q of Northeast Utilities (the registrant);

2.

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.

The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)

Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)

Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)

Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)

Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5.

The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

(a)

all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

(b)

any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date:  November 4, 2005

/s/ Charles W. Shivery

     (Signature)

     Charles W. Shivery

     Chairman, President and Chief Executive Officer

     (Principal Executive Officer)

EX-31.1

Exhibit 31.1

CERTIFICATION PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, David R. McHale, certify that:

1.

I have reviewed this quarterly report on Form 10-Q of Northeast Utilities (the registrant);

2.

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.

The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)

Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)

Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)

Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)

Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5.

The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

(a)

all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

(b)

any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date:  November 4, 2005

/s/ David R. McHale

     (Signature)

     David R. McHale

     Senior Vice President and Chief Financial Officer

     (Principal Financial Officer)

EX-32

Exhibit 32

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Northeast Utilities (the registrant) on Form 10-Q for the period ending September 30, 2005 as filed with the Securities and Exchange Commission (the Report), we, Charles W. Shivery, Chairman, President and Chief Executive Officer of the registrant and David R. McHale, Senior Vice President and Chief Financial Officer of the registrant, certify, pursuant to 18 U.S.C. Sec. 1350, as adopted pursuant to Sec. 906 of the Sarbanes-Oxley Act of 2002, that:

1)

The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2)

The information contained in the Report fairly presents, in all material respects, the financial condition and result of operations of the registrant.

/s/ Charles W. Shivery

     (Signature)

     Charles W. Shivery

     Chairman, President and Chief Executive Officer

/s/ David R. McHale

     (Signature)

     David R. McHale

     Senior Vice President and Chief Financial Officer

November 4, 2005

A signed original of this written statement required by Section 906, or other document authenticating, acknowledging, or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to the registrant and will be retained by the registrant and furnished to the Securities and Exchange Commission or its staff upon request.

EX-31

Exhibit 31

CERTIFICATION PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Cheryl W. Grisé, certify that:

1.

I have reviewed this quarterly report on Form 10-Q of The Connecticut Light and Power Company (the registrant);

2.

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.

The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)

Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)

Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)

Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)

Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5.

The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

(a)

all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

(b)

any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date:  November 4, 2005

/s/ Cheryl W. Grisé

     (Signature)

     Cheryl W. Grisé

     Chief Executive Officer

     (Principal Executive Officer)

EX-31.1

Exhibit 31.1

CERTIFICATION PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, David R. McHale, certify that:

1.

I have reviewed this quarterly report on Form 10-Q of The Connecticut Light and Power Company (the registrant);

2.

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.

The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)

Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)

Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)

Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)

Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5.

The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

(a)

all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

(b)

any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date:  November 4, 2005

/s/ David R. McHale

     (Signature)

     David R. McHale

     Senior Vice President and Chief Financial Officer

     (Principal Financial Officer)

EX-32

Exhibit 32

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of The Connecticut Light and Power Company (the registrant) on Form 10-Q for the period ending September 30, 2005 as filed with the Securities and Exchange Commission (the Report), we, Cheryl W. Grisé, Chief Executive Officer of the registrant and David R. McHale, Senior Vice President and Chief Financial Officer of the registrant, certify, pursuant to 18 U.S.C. Sec. 1350, as adopted pursuant to Sec. 906 of the Sarbanes-Oxley Act of 2002, that:

1)

The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2)

The information contained in the Report fairly presents, in all material respects, the financial condition and result of operations of the registrant.

/s/ Cheryl W. Grisé

     (Signature)

     Cheryl W. Grisé

     Chief Executive Officer

/s/ David R. McHale

     (Signature)

     David R. McHale

     Senior Vice President and Chief Financial Officer

November 4, 2005

A signed original of this written statement required by Section 906, or other document authenticating, acknowledging, or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to the registrant and will be retained by the registrant and furnished to the Securities and Exchange Commission or its staff upon request.

EX-31

Exhibit 31

CERTIFICATION PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Cheryl W. Grisé, certify that:

1.

I have reviewed this quarterly report on Form 10-Q of Public Service Company of New Hampshire (the registrant);

2.

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.

The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)

Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)

Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)

Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)

Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5.

The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

(a)

all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

(b)

any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date:  November 4, 2005

/s/ Cheryl W. Grisé

     (Signature)

     Cheryl W. Grisé

     Chief Executive Officer

     (Principal Executive Officer)

EX-31.1

Exhibit 31.1

CERTIFICATION PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, David R. McHale, certify that:

1.

I have reviewed this quarterly report on Form 10-Q of Public Service Company of New Hampshire (the registrant);

2.

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.

The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)

Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)

Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)

Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)

Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5.

The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

(a)

all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

(b)

any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date:  November 4, 2005

/s/ David R. McHale

     (Signature)

     David R. McHale

     Senior Vice President and Chief Financial Officer

     (Principal Financial Officer)

EX-32

Exhibit 32

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Public Service Company of New Hampshire (the registrant) on Form 10-Q for the period ending September 30, 2005 as filed with the Securities and Exchange Commission (the Report), we, Cheryl W. Grisé, Chief Executive Officer of the registrant, and David R. McHale, Senior Vice President and Chief Financial Officer of the registrant, certify, pursuant to 18 U.S.C. Sec. 1350, as adopted pursuant to Sec. 906 of the Sarbanes-Oxley Act of 2002, that:

1)

The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2)

The information contained in the Report fairly presents, in all material respects, the financial condition and result of operations of the registrant.

/s/ Cheryl W. Grisé

     (Signature)

     Cheryl W. Grisé

     Chief Executive Officer

/s/ David R. McHale

     (Signature)

     David R. McHale

     Senior Vice President and Chief Financial Officer

November 4, 2005

A signed original of this written statement required by Section 906, or other document authenticating, acknowledging, or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to the registrant and will be retained by the registrant and furnished to the Securities and Exchange Commission or its staff upon request.

EX-31

Exhibit 31

CERTIFICATION PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Cheryl W. Grisé, certify that:

1.

I have reviewed this quarterly report on Form 10-Q of Western Massachusetts Electric Company (the registrant);

2.

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.

The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)

Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)

Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)

Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)

Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5.

The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

(a)

all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

(b)

any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date:  November 4, 2005

/s/ Cheryl W. Grisé

     (Signature)

     Cheryl W. Grisé

     Chief Executive Officer

     (Principal Executive Officer)

EX-31.1

Exhibit 31.1

CERTIFICATION PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, David R. McHale, certify that:

1.

I have reviewed this quarterly report on Form 10-Q of Western Massachusetts Electric Company (the registrant);

2.

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.

The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)

Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)

Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)

Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)

Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5.

The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

(a)

all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

(b)

any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date:  November 4, 2005

/s/ David R. McHale

     (Signature)

     David R. McHale

     Senior Vice President and Chief Financial Officer

     (Principal Financial Officer)

EX-32

Exhibit 32

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Western Massachusetts Electric Company (the registrant) on Form 10-Q for the period ending September 30, 2005 as filed with the Securities and Exchange Commission (the Report), we, Cheryl W. Grisé, Chief Executive Officer of the registrant, and David R. McHale, Senior Vice President and Chief Financial Officer of the registrant, certify, pursuant to 18 U.S.C. Sec. 1350, as adopted pursuant to Sec. 906 of the Sarbanes-Oxley Act of 2002, that:

1)

The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2)

The information contained in the Report fairly presents, in all material respects, the financial condition and result of operations of the registrant.

/s/ Cheryl W. Grisé

     (Signature)

     Cheryl W. Grisé

     Chief Executive Officer

/s/ David R. McHale

     (Signature)

     David R. McHale

     Senior Vice President and Chief Financial Officer

November 4, 2005

A signed original of this written statement required by Section 906, or other document authenticating, acknowledging, or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to the registrant and will be retained by the registrant and furnished to the Securities and Exchange Commission or its staff upon request.