The Connecticut Light and Power Company 10Q 2005 Q2 Quarterly report

____________________________________________________________________________________

UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549

FORM 10-Q

[X]	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

	For the Quarterly Period EndedJune 30, 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

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 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 July 31, 2005
Northeast Utilities Common stock, $5.00 par value	129,899,897 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 comprised of HWP, NGC, NGS, Reeds Ferry, Select Energy, SECI, SESI, and Woods Network. For further information, see Note 11, "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 CL&P, PSNH, WMECO, and Yankee Gas. For further information, see Note 11, "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

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	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
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

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) - June 30, 2005 and December 31, 2004	2

Condensed Consolidated Statements of (Loss)/Income (Unaudited) – Three Months and Six Months Ended June 30, 2005 and 2004	4

Condensed Consolidated Statements of Cash Flows (Unaudited) - Six Months Ended June 30, 2005 and 2004	5

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

Report of Independent Registered Public Accounting Firm	31

The Connecticut Light and Power Company and Subsidiaries

Condensed Consolidated Balance Sheets (Unaudited) - June 30, 2005 and December 31, 2004	34

Condensed Consolidated Statements of Income (Unaudited) - Three Months and Six Months Ended June 30, 2005 and 2004	36

Condensed Consolidated Statements of Cash Flows (Unaudited) - Six Months Ended June 30, 2005 and 2004	37

Public Service Company of New Hampshire and Subsidiaries

Condensed Consolidated Balance Sheets (Unaudited) - June 30, 2005 and December 31, 2004	40

Condensed Consolidated Statements of Income (Unaudited) - Three Months and Six Months Ended June 30, 2005 and 2004	42

Condensed Consolidated Statements of Cash Flows (Unaudited) - Six Months Ended June 30, 2005 and 2004	43

Western Massachusetts Electric Company and Subsidiary

Condensed Consolidated Balance Sheets (Unaudited) - June 30, 2005 and December 31, 2004	46

Condensed Consolidated Statements of Income (Unaudited) - Three Months and Six Months Ended June 30, 2005 and 2004	48

Condensed Consolidated Statements of Cash Flows (Unaudited) - Six Months Ended June 30, 2005 and 2004	49

	Page

ITEM 2— Management's Discussion and Analysis of Financial Condition and Results of Operations for the Following Companies:

Northeast Utilities and Subsidiaries		50

The Connecticut Light and Power Company and Subsidiaries		74

Public Service Company of New Hampshire and Subsidiaries		77

Western Massachusetts Electric Company and Subsidiary		80

ITEM 3—Quantitative and Qualitative Disclosures About Market Risk		83

ITEM 4 —Controls and Procedures		85

PART II — OTHER INFORMATION

ITEM 1 — Legal Proceedings		86

ITEM 2 — Unregistered Sales of Equity Securities and Use of Proceeds		87

ITEM 4 — Submission of Matters to a Vote of Security Holders		87

ITEM 6 — Exhibits and Reports on Form 8-K		89

SIGNATURES		91

NORTHEAST UTILITIES AND SUBSIDIARIES

NORTHEAST UTILITIES AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
	June 30,	December 31,
	2005	2004
	(Thousands of Dollars)
ASSETS

Current Assets:
Cash and cash equivalents	$ 55,483	$ 46,989
Special deposits	94,480	82,584
Investments in securitizable assets	247,882	139,391
Receivables, less provision for uncollectible
accounts of $28,717 in 2005 and $25,325 in 2004	700,689	771,257
Unbilled revenues	114,121	144,438
Taxes receivable	35,534	61,420
Fuel, materials and supplies, at average cost	177,039	185,180
Derivative assets - current	275,201	81,567
Prepayments and other	101,018	154,395
	1,801,447	1,667,221

Property, Plant and Equipment:
Electric utility	6,106,413	5,918,539
Gas utility	800,517	786,545
Competitive energy	909,534	918,183
Other	252,373	241,190
	8,068,837	7,864,457
Less: Accumulated depreciation	2,459,733	2,382,927
	5,609,104	5,481,530
Construction work in progress	466,112	382,631
	6,075,216	5,864,161

Deferred Debits and Other Assets:
Regulatory assets	2,561,655	2,745,874
Goodwill	290,791	319,986
Prepaid pension	331,908	352,750
Prior spent nuclear fuel trust, at fair value	49,950	49,296
Derivative assets - long-term	427,156	198,769
Other	412,433	457,777
	4,073,893	4,124,452












Total Assets	$ 11,950,556	$ 11,655,834




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

NORTHEAST UTILITIES AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
	June 30,	December 31,
	2005	2004
	(Thousands of Dollars)
LIABILITIES AND CAPITALIZATION

Current Liabilities:
Notes payable to banks	$ 177,156	$ 180,000
Long-term debt - current portion	45,086	90,759
Accounts payable	809,423	825,247
Accrued interest	52,292	49,449
Derivative liabilities - current	298,719	130,275
Counterparty deposits	102,172	57,650
Other	227,403	230,022
	1,712,251	1,563,402

Rate Reduction Bonds	1,449,761	1,546,490

Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	1,368,991	1,434,403
Accumulated deferred investment tax credits	97,285	99,124
Deferred contractual obligations	369,338	413,056
Regulatory liabilities	1,092,633	1,069,842
Derivative liabilities - long-term	388,524	58,737
Other	258,714	267,895
	3,575,485	3,343,057

Capitalization:
Long-Term Debt	2,994,490	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; 151,657,618 shares issued
and 129,695,191 shares outstanding in 2005 and
151,230,981 shares issued and 129,034,442 shares
outstanding in 2004	758,288	756,155
Capital surplus, paid in	1,121,635	1,116,106
Deferred contribution plan - employee stock
ownership plan	(53,776)	(60,547)
Retained earnings	635,221	845,343
Accumulated other comprehensive income/(loss)	1,111	(1,220)
Treasury stock, 19,638,426 shares in 2005
and 19,580,065 shares in 2004	(360,110)	(359,126)
Common Shareholders' Equity	2,102,369	2,296,711
Total Capitalization	5,213,059	5,202,885

Commitments and Contingencies (Note 6)

Total Liabilities and Capitalization	$ 11,950,556	$ 11,655,834




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

NORTHEAST UTILITIES AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF (LOSS)/INCOME
(Unaudited)
	Three Months Ended			Six Months Ended
	June 30,			June 30,
	2005		2004	2005	2004
	(Thousands of Dollars, except share information)


Operating Revenues	$ 1,557,920	$ 1,524,666		$ 3,822,732	$ 3,362,953

Operating Expenses:
Operation -
Fuel, purchased and net interchange power	937,220	912,418		2,562,914	2,089,729
Other	301,091	290,175		579,906	532,122
Wholesale contract market changes, net	69,574	-		258,466	-
Restructuring and impairment charges	2,295	-		47,859	-
Maintenance	55,110	48,235		96,813	90,024
Depreciation	58,351	55,561		116,349	110,134
Amortization	24,026	28,087		47,119	57,378
Amortization of rate reduction bonds	41,116	38,294		86,906	81,293
Taxes other than income taxes	55,679	55,695		132,835	133,284
Total operating expenses	1,544,462	1,428,465		3,929,167	3,093,964
Operating Income/(Loss)	13,458	96,201		(106,435)	268,989

Interest Expense:
Interest on long-term debt	44,270	35,546		84,042	70,491
Interest on rate reduction bonds	22,235	25,043		45,273	50,738
Other interest	6,649	2,549		9,668	4,689
Interest expense, net	73,154	63,138		138,983	125,918
Other Income, Net	9,064	2,862		11,105	4,549
(Loss)/Income Before Income Tax (Benefit)/Expense	(50,632)	35,925		(234,313)	147,620
Income Tax (Benefit)/Expense	(24,317)	10,544		(91,669)	53,407
(Loss)/Income Before Preferred Dividends of Subsidiary	(26,315)	25,381		(142,644)	94,213
Preferred Dividends of Subsidiary	1,389	1,389		2,779	2,779
Net (Loss)/Income	$ (27,704)	$ 23,992		$ (145,423)	$ 91,434

Basic and Fully Diluted (Loss)/Earnings Per Common Share	$ (0.21)	$ 0.19		$ (1.12)	$ 0.71

Basic Common Shares Outstanding (average)	129,520,644	128,033,513		129,399,574	127,956,640

Fully Diluted Common Shares Outstanding (average)	129,520,644	128,182,645		129,399,574	128,121,751




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

NORTHEAST UTILITIES AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
	Six Months Ended
	June 30,
	2005	2004
	(Thousands of Dollars)

Operating Activities:
Net (loss)/income	$ (145,423)	$ 91,434
Adjustments to reconcile to net cash flows
provided by operating activities:
Wholesale contract market changes, net	203,572	-
Restructuring and impairment charges	47,812	-
Bad debt expense	6,200	4,207
Depreciation	116,349	110,134
Deferred income taxes and investment tax credits, net	(92,457)	34,478
Amortization	47,119	57,378
Amortization of rate reduction bonds	86,906	81,293
Amortization of recoverable energy costs	31,544	24,193
Pension expense	16,465	5,318
Regulatory (refunds)/overrecoveries	(59,929)	8,753
Derivative assets	72,644	(35,437)
Derivative liabilities	(59,486)	29,580
Deferred contractual obligations	(43,407)	(32,830)
Other sources of cash	32,335	18,853
Other uses of cash	(26,384)	(36,551)
Changes in current assets and liabilities:
Receivables and unbilled revenues, net	94,685	75,311
Fuel, materials and supplies	8,141	51
Investments in securitizable assets	(108,491)	(23,923)
Taxes receivable	25,886	-
Other current assets	17,424	9,007
Accounts payable	(11,856)	34,267
Other current liabilities	17,279	38,416
Net cash flows provided by operating activities	276,928	493,932

Investing Activities:
Investments in property and plant:
Electric, gas and other utility plant	(327,081)	(291,417)
Competitive energy assets	(4,989)	(11,329)
Cash flows used for investments in property and plant	(332,070)	(302,746)
Net proceeds from sale of land	23,792	-
Restricted cash - LMP costs	-	(30,257)
Other investment activities	5,543	11,450
Net cash flows used in investing activities	(302,735)	(321,553)

Financing Activities:
Issuance of common shares	7,565	2,786
Issuance of long-term debt	200,000	82,438
Retirement of rate reduction bonds	(96,729)	(90,616)
Decrease in short-term debt	(2,844)	(99,193)
Reacquisitions and retirements of long-term debt	(48,459)	(23,621)
Cash dividends on common shares	(41,629)	(38,379)
Other financing activities	16,397	(486)
Net cash flows provided by/(used in) financing activities	34,301	(167,071)
Net increase in cash and cash equivalents	8,494	5,308
Cash and cash equivalents - beginning of period	46,989	43,372
Cash and cash equivalents - end of period	$ 55,483	$ 48,680



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

NORTHEAST UTILITIES AND SUBSIDIARIES

THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES

WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (All Companies)

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 NU 2004 Form 10-K, and the current reports on Form 8-K disclosed in Part II, Item 6,"Other Information - Exhibits and Reports on Form 8-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 June 30, 2005, and the results of operations for the three months and six months ended June 30, 2005 and 2004 and cash flows for the six months ended June 30, 2005 and 2004. The res ults of operations for the three and six months ended June 30, 2005 and 2004 and statements of cash flows for the six months ended June 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 other operation and maintenance expense and maintenance expense on the accompanying condensed consolidated statements of (loss)/income which totaled $19.4 million and $34.9 million for the three and six months ended June 30, 2004, respectively.

In the company's condensed consolidated statement of cash flows for the six months ended June 30, 2004, the company changed the classification of the change in restricted cash - 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 $30.3 million increase to net cash flows used in investing activities and a corresponding increase to operating cash flows from the amounts previously reported.

The NU, CL&P, PSNH and WMECO condensed consolidated statements of cash flows for the six months ended June 30, 2004 have also been reclassified to exclude from cash flows from operations the change in accounts payable related to capital projects consistent with the December 31, 2004 presentation. These amounts totaled sources/(uses) of cash of $8.8 million, $15.8 million, $(3.9) million, and $(0.4) million for the six months ended June 30, 2004 for NU, CL&P, PSNH, and WMECO, respectively.

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." SFAS No. 123R will require NU to recognize compensation expense for the unvested portion of previously granted awards that remain 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 further information regarding equity-based compensation, see Note 1F, "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. Management identified certain potential 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 issues, 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." &n bsp;FIN 47 requires an entity to recognize a liability for the fair value of an asset retirement obligation that is conditional on a future event if the liability’s fair value can be reasonably estimated. FIN 47 is required to be implemented on December 31, 2005, with a liability for conditional asset retirements and the cumulative effect of implementation to be recognized in the financial statements. Management is currently evaluating NU’s conditional asset retirement obligations and cannot yet reasonably estimate the impact of FIN 47 on NU’s financial statements.

Guarantees

NU provides credit assurance 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 June 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 $967.1 million. A majority of these guarantees do not have established expiration dates. Additionally, NU had $78.3 million of LOCs issued, of which $76.3 million were issued for the benefit of NU Enterprises at June 30, 2005.

At June 30, 2005, NU had outstanding guarantees on behalf of the Utility Group and Rocky River Realty (RRR) of $13 million and $11.1 million, respectively. These amounts are included in the total outstanding NU guarantee exposure amount of $967.1 million. The remaining guarantee amount of $943 million is for NU Enterprises, of which $663.8 million relates to Select Energy and $279.2 million relates to the energy services businesses. The $279.2 million in guarantees related to the energy services businesses is comprised of $97.8 million related to guarantees of Select Energy Services, Inc.'s (SESI) obligations under certain financing arrangements and $181.4 million related to 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 $13 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 June 30, 2005 is $458.5 million. The amount of guarantees outstanding for compliance with the SEC limit for the Utility Group at June 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, Northeast Utilities Service Company 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 June 30, 2005 is $0.2 million.

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."

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 June 30, 2005
(Millions of Dollars)	NU Consolidated	CL&P	PSNH		WMECO	Yankee Gas and Other
Recoverable nuclear costs	$ 48.1	$ -		$ 28.0	$ 20.1		$ -
Securitized assets	1,440.6	926.0		398.7	115.9		-
Income taxes, net	301.6	197.4		35.2	53.4		15.6
Unrecovered contractual obligations	319.5	195.5		60.7	68.9		(5.6)
Recoverable energy costs	230.1	45.2		183.2	1.7		-
Other regulatory assets/(overrecoveries)	221.8	68.4		142.0	(41.3)		52.7
Totals	$2,561.7	$1,432.5		$847.8	$218.7		$ 62.7

	At December 31, 2004
(Millions of Dollars)	NU Consolidated	CL&P	PSNH		WMECO	Yankee Gas and Other
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)	230.5	67.8		152.0	(49.0)		59.7
Totals	$2,745.9	$1,526.4		$900.1	$231.6		$87.8

Included in WMECO's other regulatory assets/(overrecoveries) are $43.1 million and $50.7 million at June 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 $12.8 million and $11.6 million of regulatory costs at June 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 rates.

As discussed in Note 6D, "Commitments and Contingencies - Deferred Contractual Obligations," a substantial portion of the unrecovered contractual obligations regulatory asset has 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 $1.1 billion of regulatory liabilities at both June 30, 2005 and 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:

	At June 30, 2005
(Millions of Dollars)	NU Consolidated	CL&P	PSNH		WMECO		Yankee Gas
Cost of removal	$ 310.4	$141.2		$ 86.5	$24.1	$ 58.6
CL&P CTA, GSC and SBC overcollections	120.8	120.8		-	-	-
PSNH cumulative deferral – SCRC	227.4	-		227.4	-	-
Regulatory liabilities offsetting Utility Group derivative assets	279.0	279.0		-	-	-
Other regulatory liabilities	155.0	78.0		29.1	(1.2)	49.1
Totals	$1,092.6	$619.0		$343.0	$22.9	$107.7

	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	141.0	79.1		27.5	0.7	33.7
Totals	$1,069.8	$614.8		$323.7	$24.8	$106.5

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 Six Months Ended
(Millions of Dollars)	June 30, 2005	June 30, 2004	June 30, 2005		June 30, 2004
Borrowed funds	$2.5	$0.9		$4.4		$2.2
Equity funds	2.3	0.6		4.2		1.9
Totals	$4.8	$1.5		$8.6		$4.1
Average AFUDC rates	5.2%	4.0%		4.9%		3.7%

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.

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 is 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:

	For the Three Months Ended		For the Six Months Ended
(Millions of Dollars, except per share amounts)	June 30, 2005	June 30, 2004	June 30, 2005	June 30, 2004
Net (loss)/income, as reported	$(27.7)	$24.0	$(145.4)	$91.4
Add: Equity-based employee compensation expense included in reported net (loss)/income, net of related tax effects	1.0	0.6	1.4	1.0
Net (loss)/income before equity-based compensation	(26.7)	24.6	(144.0)	92.4
Deduct: Total equity-based employee compensation expense determined under the fair value-based method for all awards, net of related tax effects	(1.2)	(0.9)	(1.8)	(1.5)
Pro forma net (loss)/income	$(27.9)	$23.7	$(145.8)	$90.9
EPS:
Basic and fully diluted – as reported	$(0.21)	$0.19	$ (1.12)	$0.71
Basic and fully diluted – pro forma	$(0.21)	$0.19	$ (1.12)	$0.72

Net (loss)/income, as reported, includes $1 million and $0.6 million for the three months ended June 30, 2005 and 2004, respectively, and $1.4 million and $1 million for the six months ended June 30, 2005 and 2004, respectively, of expense for restricted stock and restricted stock units. NU accounts for restricted stock in accordance with APB No. 25 and amortizes the intrinsic value of the award 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 six-month period ended June 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, "New Accounting Standards," to the condensed consolidated financial statements.

Sale of Customer Receivables

At June 30, 2005 and December 31, 2004, CL&P had sold an undivided interest in its accounts receivable of $60 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 June 30, 2005 and December 31, 2004, the reserve requirements calculated in accordance with the Receivables Purchase and Sale Agreement were $14.3 million and $18.8 million, respectively. These reserve amounts are deducted from the amount of receivables eligible for sale at the time. 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 within its service territory.

At June 30, 2005 and December 31, 2004, amounts sold to CRC by CL&P but not sold to the financial institution totaling $247.9 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, and in 2004 extended the termination date of the facility to July 3, 2007. 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."

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 totaled $0.5 million at June 30, 2005.

NU has an investment in the common stock of 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 in nature. An after-tax investment write-down of $2.4 million ($3.8 million on a pre-tax basis) was recorded to reduce the carrying value of the investment.

NU owns 49 percent of the common stock of the Connecticut Yankee Atomic Power Company (CYAPC) with a carrying value of $22 million at June 30, 2005. CYAPC is 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 June 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 6D, "Commitments and Contingencies - Deferred Contractual Obligations," to the condensed consolidated financial statements.

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

Special Deposits

Special deposits represents amounts Select Energy has on deposit with unaffiliated counterparties and brokerage firms in the amount of $82.2 million and amounts included in escrow for SESI that have not been spent on construction projects of $12.3 million at June 30, 2005. Similar amounts totaled $46.3 million and $20 million, respectively, at December 31, 2004. Special deposits at December 31, 2004 also included $16.3 million in escrow for Yankee Gas, which represented payment for Yankee Gas' first mortgage bonds due on June 1, 2005.

Counterparty Deposits

Balances collected from counterparties resulting from Select Energy’s credit management activities totaled $102.2 million at June 30, 2005 and $57.7 million at December 31, 2004. These amounts are recorded as current liabilities and 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.

Other Income/(Loss)

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

	For the Three Months Ended		For the Six Months Ended
(Millions of Dollars)	June 30, 2005	June 30, 2004	June 30, 2005	June 30, 2004
Other Income:
Investment income	$ 7.3	$ 4.3	$ 12.6	$ 8.0
CL&P procurement fee	2.8	2.7	5.8	5.8
AFUDC – equity funds	2.3	0.6	4.2	1.9
Gain on sale of RMS	-	0.6	-	0.6
Other	4.3	1.7	6.4	3.6
Total Other Income	$16.7	$ 9.9	$ 29.0	$ 19.9
Other Loss:
Environmental accrual	$ -	$ -	$ (3.6)	$ -
Investment write-downs	(0.8)	(3.8)	(0.8)	(6.3)
Charitable donations	(0.8)	(0.5)	(1.5)	(1.7)
Costs not recoverable from regulated customers	(1.6)	(1.4)	(2.3)	(2.7)
Loss on disposition of property	(0.8)	(0.7)	(0.9)	(4.4)
Other	(3.6)	(0.6)	(8.8)	(0.3)
Total Other Loss	$ (7.6)	$(7.0)	$(17.9)	$(15.4)
Totals	$ 9.1	$ 2.9	$ 11.1	$ 4.5

Investment income includes equity in earnings of regional nuclear generating and transmission companies of $1 million and $0.8 million of income for the three months ended June 30, 2005 and 2004, respectively, and $1.9 million and $0.9 million for the six months ended June 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 based on applicable accounting rules.

WHOLESALE CONTRACT MARKET CHANGES (NU, NU Enterprises)

NU Enterprises recorded $69.6 million and $258.5 million of pre-tax wholesale contract market changes for merchant energy for the three months and six months ended June 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 for the three months and six months ended June 30, 2005. A summary of those pre-tax charges (credits) is as follows (millions of dollars):

	First Quarter 2005	Second Quarter 2005	Year-to-Date
Mark-to-market on long-term wholesale electricity contracts	$ 294.3	$ 64.2	$ 358.5
Mark-to-market on retail marketing supply contracts and other wholesale contracts	(105.4)	5.4	(100.0)
Totals	$ 188.9	$ 69.6	$ 258.5

Second Quarter: The $64.2 million for the second quarter ended June 30, 2005, relates to the change since March 31, 2005 in the negative mark-to-market on certain long-term below-market wholesale electricity contracts. The decision in March 2005 to exit the wholesale marketing business changed management’s conclusion regarding the likelihood that these wholesale marketing contracts would result in physical delivery to customers. This in turn resulted in a change in the first quarter of 2005 from accrual accounting to fair value accounting for the wholesale marketing contracts. The company is seeking to divest these contracts.

The $5.4 million relates to a decrease in the mark-to-market on certain retail marketing supply contracts and other wholesale contracts related to electricity for delivery to customers primarily in 2005 and 2006.

Included in the mark-to-market on long-term wholesale electricity contracts is a $15.7 million and $70.2 million pre-tax mark-to-market charge for the three and six months ended June 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 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 contract market changes in the second quarter of 2005 as this contract expired on June 30, 2005. WMECO’s benefits under this contr act 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.

First Quarter: The $294.3 million first quarter 2005 loss in the above table was reflected as follows in the first quarter Form 10-Q:

$257.7 million pre-tax mark-to-market loss on long-term wholesale electricity contracts for the three months ended March 31, 2005 was previously included in restructuring and impairment charges;

$36.6 million pre-tax mark-to-market contract asset write-offs were previously included in restructuring and impairment charges. These mark-to-market contract asset write-offs directly related to the long-term wholesale electricity contracts.

The $105.4 million first quarter 2005 gain in the above table was reflected as follows in the first quarter Form 10-Q:

$94 million pre-tax mark-to-market gains on retail marketing supply contracts which NU Enterprises was seeking to divest. During the second quarter of 2005, management elected to retain some of these contracts. Changes in the mark-to-market for those contracts which are being retained are and will continue to be reflected in fuel, purchased and net interchange power. Originally, retail electric supply was sourced along with the wholesale supply by the wholesale marketing business. As a result of the decision to exit the wholesale marketing business, these purchase contracts with a positive market value of $94 million at March 31, 2005 were required to be marked-to-market.

$25.8 million of pre-tax mark-to-market gains on other wholesale contracts for the three months ended March 31, 2005 was previously included in restructuring and impairment charges;

$14.4 million pre-tax loss primarily associated with a contract termination payment was previously included in restructuring and impairment charges.

For information regarding wholesale current and long-term derivative assets and liabilities that are being divested, see Note 4, "Derivative Instruments," to the condensed consolidated financial statements.

RESTRUCTURING AND IMPAIRMENT CHARGES AND ASSETS HELD FOR SALE (NU, NU Enterprises)

Restructuring and Impairment Charges: NU Enterprises recorded $2.3 million and $47.8 million of pre-tax restructuring and impairment charges for the three and six months ended June 30, 2005 related to the decision to exit the wholesale marketing business and to divest its energy services businesses. These amounts are included as restructuring and impairment charges on the condensed consolidated statements of (loss)/income. A summary of those pre-tax charges is as follows (millions of dollars):

	First Quarter 2005	Second Quarter 2005	Year-to-Date
Merchant Energy:
Impairment Charges	$ 7.2	$ -	$ 7.2
Restructuring Charges	-	1.0	1.0
Subtotal	7.2	1.0	8.2
Energy Services:
Impairment Charges	38.3	0.8	39.1
Restructuring Charges	-	0.5	0.5
Subtotal	38.3	1.3	39.6
Totals	$45.5	$2.3	$47.8

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

NU Enterprises has 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, pre-tax restructuring costs totaling $1 million were recorded by merchant energy related to professional fees, employee-related and other costs. 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 and other pre-tax restructuring costs totaling $0.5 million related to professional fees, employee-related and other costs in conjunction with the divestiture of the energy services businesses. Additional restructuring charges will be recognized as incurred and may include net losses on the disposition of wholesale marketing contracts (including the value of full requirements electricity contract quantities to be delivered in excess of their notional amounts recognized in wholesale market contract changes), professional fees and employee-related and other costs.

Assets Held for Sale: On March 9, 2005, NU Enterprises announced that it would explore ways to divest its energy services businesses in a manner that would maximize their value. Certain assets and liabilities of Select Energy Contracting, Inc. - New Hampshire (SECI-NH), a division of Select Energy Contracting, Inc. (SECI) that provides mechanical and electrical contracting services in new construction and service contracts, and Woods Network Services, Inc. (Woods Network), a subsidiary of NU Enterprises that is a network products and services company, are currently being accounted for as held for sale, at the lower of carrying amount or fair value less cost to sell. SECI-NH and Woods Network are reported as part of the services and other segment of NU Enterprises. Management expects to complete these sales by the end of 2005.

For SECI-NH, the major classes of assets and liabilities held for sale were accounts receivable of $5 million and accounts payable of $3 million. For Woods Network, the major classes of assets and liabilities held for sale were accounts receivable of $3 million and accounts payable of $1 million.

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 cannot be designated as being used for 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. For contracts that meet the definition of a derivative but do not meet the hedging requirements, and for the ineffective portion of contracts that meet the cash flow hedge requirements, the changes in fair value of those contracts are 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 recognized currently i n earnings. Derivative contracts that are entered into as a normal purchase or sale and will result in physical delivery, and are documented as such, are recognized in revenue and expense when such deliveries occur.

For the six months ended June 30, 2005, a negative $0.3 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 negative $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 first half 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 $5.4 million, net of tax. Accumulated other comprehensive income at June 30, 2005, was a positive $1.9 million, net of tax (increase to equity), relating to hedged transactions, and it is estimated that a positive $0.6 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.

There was a negative pre-tax impact of $0.3 million recognized in earnings in the second quarter 2005 for the ineffective portion of cash flow hedges. A negative pre-tax $0.7 million was recognized in earnings in the second quarter 2005 for the ineffective portion of fair value hedges. The changes in the fair value of both the fair value hedges and the natural gas inventory being hedged 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 June 30, 2005. At June 30, 2005, derivative assets and liabilities have been segregated between wholesale, retail 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 June 30, 2005
(Millions of Dollars)		Assets		Liabilities
		Current	Long-Term	Current	Long-Term	Net Total
NU Enterprises:
Wholesale		$203.6	$182.5	$(286.1)	$ (350.0)	$ (250.0)
Retail		17.1	5.8	(1.3)	(0.4)	21.2
Hedging		7.3	3.1	(6.3)	-	4.1
Utility Group - Gas:
Non-trading		-	-	(0.1)	-	(0.1)
Hedging		0.3	-	(1.8)	-	(1.5)
Utility Group - Electric:
Non-trading		43.1	235.8	(3.1)	(38.1)	237.7
NU Parent:
Hedging		3.8	-	-	-	3.8
Total		$275.2	$427.2	$(298.7)	$(388.5)	$ 15.2

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 June 30, 2005, Select Energy had $419.4 million of derivative assets from retail, wholesale, 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 $14.6 million and $29.3 million related to wholesale activities at June 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 $13.3 million and $27.1 million related to wholesale activities at June 30, 2005 and December 31, 2004, respectively.

NU Enterprises - Wholesale: Certain derivative contracts are part of Select Energy's wholesale activities that the company is in the process of exiting. These contracts also include other wholesale and retail short-term and long-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 the natural gas contracts was primarily determined by prices provided by external sources and actively quoted markets. 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. In addition, to gather market intelligence and utilize this information in risk management activities for the wholes ale marketing activities, Select Energy conducted limited energy trading activities in electricity, natural gas, and oil, and therefore, experienced net open positions. Select Energy manages open trading positions with strict policies that limit its exposure to 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 June 30, 2005 was a liability of $250 million.

NU Enterprises - Retail: 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 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 line is required to enter into contracts that cannot immediately receive accrual accounting and therefore, changes in fair value are required to be marked-to-market via the income statement.

Derivatives used in retail 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 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 June 30, 2005 was an asset of $21.2 million.

Select Energy's retail portfolio includes New York Mercantile Exchange (NYMEX) futures, financial swaps, and options, 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 - 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 o ther 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 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 June 30, 2005 the NYMEX futures contracts had notional values of $44.9 million and were recorded at fair value as derivative assets totaling $6.4 million and derivative liabilities of a negative $0.4 million.

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, options, financial collars, 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 $4 million and derivative liabilities of $6 million at June 30, 2005.

Select Energy hedges certain amounts of natural gas inventory with gas futures, options 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 $0.7 million at June 30, 2005. The change in fair value of the hedged natural gas inventory was recorded as a reduction to fuel, materials and supplies of $37,000 at June 30, 2005.

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.

	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

Utility Group - Gas - Hedging: Yankee Gas maintains a master swap agreement with a financial counterparty to purchase gas at fixed prices. Under this master swap agreement, the purchase price of a specified quantity of gas for an unaffiliated customer is effectively fixed over the term of the gas service agreements with that customer for a period not extending beyond 2005. At June 30, 2005 the commodity swap agreement had a notional value of $0.3 million and was recorded at fair value as a derivative asset of $0.3 million. The firm commitment contract that is hedged is also recorded as a liability on the accompanying condensed consolidated balance sheets, and changes in fair values of the hedge and firm commitment have offsetting impacts in earnings.

In May 2005, Yankee Gas entered into an interest rate lock to hedge the interest cash outflows associated with its proposed $50 million July 2005 debt issuance. Under the cash flow hedge, Yankee Gas intended to lock the treasury rate that would be realized on its planned debt issuance. The interest rate lock is based on a United States government 30-year treasury rate and matches the index used for the debt issuance. As a cash flow hedge at June 30, 2005, the change in fair value of the lock is recorded as a $1.8 million derivative liability on the condensed consolidated balance sheets with an offsetting amount included in other comprehensive income.

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 June 30, 2005 include a derivative asset with a fair value of $278.9 million and a derivative liability with a fair value of $41.2 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.

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 June 30, 2005, the cumulative change in the fair value of the hedged debt of $3.8 million is included as a decrease to long-term debt on the condensed consolidated balance sheets. The hedge is recorded as a derivative asset of $3.8 million. The resulting changes in interest payments made are recorded as adjustments to interest expense.

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 11, "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 Northeast Generation Services Company (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 balances of these reporting units are included in the table herein.

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

(Millions of Dollars)	At June 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

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 June 30, 2005, NU's remaining intangible assets totaled $2.6 million. This amount will be amortized $0.6 million for the remainder of 2005, $1 million in 2006, and $1 million in 2007.

The exclusivity agreement intangible asset, which was included in the merchant energy business, 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.

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

The goodwill recorded related to the acquisition of Yankee Gas is not being recovered from the customers of Yankee Gas.

NU recorded amortization expense of $0.2 million and $0.9 million for the three months ended June 30, 2005 and 2004, respectively, and amortization expense of $1.1 million and $1.8 million for the six months ended June 30, 2005 and 2004, respectively, related to intangible assets subject to amortization.

COMMITMENTS AND CONTINGENCIES

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

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 independent power producer (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.

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 $227.4 million at June 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 $386.7 million to $159.3 million.

The 2004 SCRC reconciliation filing was filed with the NHPUC on May 2, 2005. The NHPUC has scheduled a hearing in late October 2005. Management does not expect the NHPUC's review of the 2004 SCRC filing to have a material impact on PSNH's net income or financial position.

The SCRC and TS/DS rate mechanisms currently reconcile accrued expenses with billed revenues on a monthly basis. PSNH has 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 will allow for the reconciliation of revenues on an accrual basis with the current accrued expenses recovered through the SCRC and TS/DS rate mechanisms, consistent with accrual accounting. At June 30, 2005, PSNH’s unbilled revenue balance related to SCRC and TS/DS was $11.7 million and $16.7 million, respectively. If approved, this change will allow for the inclusion of accrued unbilled revenue balances in the recovery of SCRC and TS/DS costs. Management believes that the unbilled revenue balance related to SCRC and TS/DS is probable of being recovered from PSNH's customers.

Environmental Legislation: The New Hampshire legislature will be considering a bill in its 2006 legislative session that would place strict limitations on the level of mercury that PSNH’s existing generation plants can emit. This bill was first proposed in the 2005 session, but was subsequently set aside and retained for the 2006 session. 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’s alternatives range from the installation of additional pollution control equipment, reducing operating capacity of its plants and possible retirement of one or more of its generating units. 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 and 2004 transition cost reconciliation filings, the standard offer service and default service reconciliations, and the transmission cost adjustment filings 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.

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.

Long-Term Contractual Arrangements (CL&P, PSNH, 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 projects as of June 30, 2005. For further information regarding these projects, see the "Business Development and Capital Expenditures" section included in the Management's Discussion and Analysis section of this combined report on Form 10-Q.

(Millions of Dollars)	2005	2006	2007	2008	2009	Thereafter	Total
Transmission business project commitments	$81.4	$ 69.5	$ 7.0	$7.0	$4.3	$ -	$169.2

PSNH: PSNH has a contract for capacity on the Portland Natural Gas Transmission System (PNGTS) pipeline which extends through 2018. Estimate future annual costs under this contract are as follows:

(Millions of Dollars)	2005	2006	2007	2008	2009	Thereafter	Total
PNGTS pipeline commitments	$1.1	$2.0	$2.0	$2.0	$2.0	$17.9	$27.0

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 $824 million at June 30, 2005, as follows (millions of dollars):

Year
2005	$400.3
2006	327.3
2007	53.1
2008	21.8
2009	7.2
Thereafter	14.3
Total	$824.0

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 $4.2 billion at June 30, 2005, the majority of which settle in 2005 and 2006.

In March 2005, HWP notified Massachusetts environmental regulators that it planned to install a selective catalytic reduction system at the 147 megawatt Mt. Tom coal-fired station in Holyoke, Massachusetts. The $14 million project commenced in July 2005 and is expected to be complete by mid-2006. The following amounts represent commitments for various services and materials associated with this project:

(Millions of Dollars)	2005	2006	Total
HWP project commitments	$9.5	$4.5	$14.0

In July 2005, HWP entered into a $50.4 million contract to purchase coal to fuel the Mt. Tom coal-fired station in Holyoke, Massachusetts. Estimated future obligations under this contract will commence in 2006 are as follows:

(Millions of Dollars)	2006	2007	2008	2009	Total
HWP coal commitments	$2.3	$22.9	$22.9	$2.3	$50.4

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 Januar y 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 did not take a position on prudence but 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 esc alator 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. A post-trial briefing schedule has been set, and a FERC administrative law judge decision in this proceeding is scheduled 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 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. On October 29, 2004, the FERC issued an order granting further consideration regarding the DPUC's and OCC's petition for reconsideration. No date has been established for this reconsideration.

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 fr om 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 can predict neither the outcome of this matter nor its ultimate impact on NU.

Consolidated Edison, Inc. Merger Litigation

Certain gain and loss contingencies continue to exist with regard to the 1999 merger agreement between NU and Consolidated Edison, Inc. and the related litigation. At this stage of the litigation, management can predict neither the outcome of this matter nor its ultimate effect on NU.

MARKETABLE SECURITIES

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

	At June 30, 2005	At December 31, 2004
(Millions of Dollars)
Globix investment	$ 6.7	$ (a)
SERP securities	55.0	55.1
WMECO prior spent nuclear fuel trust	49.9	49.3
Totals	$111.6	$104.4

(a)

At December 31, 2004, NU's investment in 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 June 30, 2005
(Millions of Dollars)	Amortized Cost	Pre-Tax Gross Unrealized Gains	Pre-Tax Gross Unrealized Losses	Estimated Fair Value
United States equity securities	$ 29.4	$3.2	$(3.8)	$ 28.8
Non-United States equity securities	5.4	1.0	-	6.4
Fixed income securities	76.8	0.3	(0.7)	76.4
Totals	$111.6	$4.5	$(4.5)	$111.6

	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 June 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 8, "Comprehensive Income," to the condensed consolidated financial statements.

For the three months and six months ended June 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 June 30,			Six Months Ended June 30,
	Realized Gains	Realized Losses	Net Realized Gains/(Losses)	Realized Gains	Realized Losses	Net Realized Gains/(Losses)
2005	$0.5	$(0.2)	$0.3	$0.6	$(0.4)	$0.2
2004	$0.3	$(0.1)	$0.2	$0.5	$(0.1)	$0.4

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 totaled $17.6 million and $4.3 million for the three months ended June 30, 2005 and 2004, respectively, and $30.5 million and $6.1 million for the six months ended June 30, 2005 and 2004, respectively.

At June 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	$ 52.3	$ 55.7
One to five years	32.5	29.0
Six to ten years	6.9	6.9
Greater than ten years	19.9	20.0
Total	$111.6	$111.6

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

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

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

	Three Months Ended June 30, 2005
	NU*	CL&P*	PSNH	WMECO		NU Enterprises		Yankee Gas	Other
Net (loss)/income	$(27.7)	$11.0	$9.0	$2.4	$(47.1)		$(0.4)			$(2.6)
Comprehensive (loss)/income items:
Qualified cash flow hedging instruments	(1.9)	-	-	-	(0.9)		(1.0)			-
Unrealized losses on securities	(2.4)	-	-	-	(1.9)		-			(0.5)
Net change in comprehensive income items	(4.3)	-	-	-	(2.8)		(1.0)			(0.5)
Total comprehensive (loss)/income	$(32.0)	$11.0	$9.0	$2.4	$(49.9)		$(1.4)			$(3.1)

	Three Months Ended June 30, 2004
	NU*	CL&P*	PSNH	WMECO		NU Enterprises		Yankee Gas	Other
Net (loss)/income	$24.0	$17.3	$6.0	$3.6	$4.0		$0.2			$(7.1)
Comprehensive (loss)/income items:
Qualified cash flow hedging instruments	2.8	-	-	-	2.8		-			-
Unrealized losses on securities	(0.6)	-	-	-	(0.6)		-			-
Net change in comprehensive income items	2.2	-	-	-	2.2		-			-
Total comprehensive (loss)/income	$26.2	$17.3	$6.0	$3.6	$6.2		$0.2			$(7.1)

	Six Months Ended June 30, 2005
	NU*	CL&P*	PSNH	WMECO		NU Enterprises		Yankee Gas	Other
Net (loss)/income	$(145.4)	$36.2	$17.8	$ 7.1	$(214.5)		$14.5			$(6.5)
Comprehensive (loss)/income items:
Qualified cash flow hedging instruments	5.4	-	-	-	6.4		(1.0)			-
Unrealized losses on securities	(3.1)	-	-	(0.3)	(1.9)		-			(0.9)
Net change in comprehensive income items	2.3	-	-	(0.3)	4.5		(1.0)			(0.9)
Total comprehensive (loss)/income	$(143.1)	$36.2	$17.8	$6.8	$(210.0)		$13.5			$(7.4)

	Six Months Ended June 30, 2004
	NU*	CL&P*	PSNH	WMECO		NU Enterprises		Yankee Gas	Other
Net (loss)/income	$ 91.4	$43.5	$17.8	$7.1	$22.8		$12.1			$(11.9)
Comprehensive (loss)/income items:
Qualified cash flow hedging instruments	19.3	-	-	-	19.2		-			0.1
Unrealized losses on securities	(0.2)	-	-	-	0.2		-			(0.4)
Net change in comprehensive income items	19.1	-	-	-	19.4		-			(0.3)
Total comprehensive (loss)/income	$110.5	$43.5	$17.8	$7.1	$42.2		$12.1			$(12.2)

*After preferred dividends of subsidiary.

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

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

(Millions of Dollars, Net of Tax)	Six Months Ended June 30, 2005		Twelve Months Ended December 31, 2004
Balance at beginning of period	$(3.5)	$24.8
Hedged transactions recognized into earnings	2.7	(57.8)
Change in fair value	4.3	25.0
Cash flow transactions entered into for the period	(1.6)	4.5
Net change associated with the current period hedging transactions	5.4	(28.3)
Total fair value adjustments included in accumulated other comprehensive income/(loss)	$ 1.9	$(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 June 30, 2005 and December 31, 2004, respectively. These amounts relate to unrealized gains on investments in marketable debt and equity securities and minimum pension liability adjustments, net of related income taxes.

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 June 30, 2005 and 2004, 223,900 options and 626,302 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:

	Three Months Ended June 30,		Six Months Ended June 30,
(Millions of Dollars, Except for Share Information)	2005	2004		2005	2004
Net (loss)/income	$(27.7)	$24.0		$(145.4)	$91.4
Basic EPS common shares outstanding (average)	129,520,644	128,033,513		129,399,574	127,956,640
Dilutive effects of employee stock options	-	149,132		-	165,111
Fully diluted EPS common shares outstanding (average)	129,520,644	128,182,645		129,399,574	128,121,751
Basic and fully diluted EPS	$(0.21)	$0.19		$(1.12)	$0.71

10.

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 six months ended June 30, 2005 and 2004 are estimated as follows:

	For the Three Months Ended June 30,					For the Six Months Ended June 30,
	Pension Benefits		Postretirement Benefits			Pension Benefits			Postretirement Benefits
(Millions of Dollars)	2005	2004		2005	2004		2005	2004		2005	2004
Service cost	$11.9	$10.4		$ 1.9	$ 1.5		$24.2	$20.3		$ 3.8	$ 3.0
Interest cost	31.5	29.9		6.3	6.4		62.7	59.4		12.6	12.7
Expected return on plan assets	(42.9)	(43.8)		(2.8)	(3.1)		(85.9)	(87.5)		(5.6)	(6.2)
Amortization of unrecognized net transition (asset)/obligation	(0.1)	(0.3)		3.0	2.9		(0.2)	(0.7)		6.0	5.9
Amortization of prior service cost	1.8	1.8		(0.1)	(0.1)		3.6	3.6		(0.2)	(0.2)
Amortization of actuarial loss	8.6	4.2	-	-	-		16.7	7.8	-	-	-
Other amortization, net	-	-		4.3	3.0		-	-		8.6	5.7
Total - net periodic expense	$10.8	$ 2.2		$12.6	$10.6		$21.1	$ 2.9		$25.2	$20.9

A portion of these amounts is capitalized related to current employees working on capital projects. Amounts capitalized were $2.3 million and $4.7 million for the three months and six months ended June 30, 2005, respectively, and $0.7 million and $1.4 million for the three months and six months ended June 30, 2004, respectively.

NU does not currently expect to make any contributions to the Pension Plan in 2005. NU contributed and anticipates contributing approximately $12.6 million quarterly totaling approximately $50 million in 2005 to fund its PBOP Plan.

11.

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 70 percent of NU's total revenues for both the six months ended June 30, 2005 and 2004 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., ERI/HEC EFA Med LLC, and HEC/CJTS Energy Center LLC, Woods Network, and intercompany eliminations. The results of NU Enterprises parent are also included within services and other. For further information regarding NU Enterprises' merchant energy business and services businesses, see Note 2, "Wholesale Contract Market Changes" and Note 3, "Restructuring and Impairment Charges and Assets Held for Sale," to the condensed consolidated financial statements. In the first quarter of 2005, the decision was made to exit the wholesale marketing business and the energy services businesses. NU Enterprises is retaining its retail marketing and merchant generation businesses.

There were no CL&P transitional standard offer (TSO) purchases from Select Energy for the six months ended June 30, 2005. Total Select Energy revenues from CL&P for other transactions with CL&P, represented $12.5 million and $26.7 million for the three and six months ended June 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 $136 million or 22 percent and $314.5 million or 22 percent for the three and six months ended June 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 $17.4 million and $37.9 million for the three and six months ended June 30, 2005, respectively, and $21 million and $53 million for the three and six months ended June 30, 2004, respectively. Total WMECO purchases from Select Energy are eliminated in consolidation.

Select Energy revenues related to contracts with NSTAR companies represented $82.2 million and $288.6 million for the three and six months ended June 30, 2005, respectively, and $69.7 million and $158.4 million the three and six months ended June 30, 2004, respectively. Revenues related to New Jersey Basic Generation Service represented $73.5 million and $143.2 million for the three and six months ended June 30, 2005. No other individual customer represented in excess of 10 percent of NU Enterprises' revenues for the three and six months ended June 30, 2005 or 2004.

Due to merchant energy's 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 six months ended June 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 June 30, 2005
	Utility Group
	Distribution (1)			NU
(Millions of Dollars)	Electric	Gas	Transmission	Enterprises	Other	Eliminations	Total
Operating revenues	$1,105.2	$ 88.4	$45.2	$330.4	$ 82.6	$ (93.8)	$1,558.0
Depreciation and amortization	(107.1)	(5.6)	(6.1)	(3.7)	(4.4)	3.4	(123.5)
Wholesale contract market changes, net	-	-	-	(69.6)	-	-	(69.6)
Restructuring and impairment charges	-	-	-	(2.3)	-	-	(2.3)
Other operating expenses	(940.0)	(79.5)	(18.1)	(322.9)	(77.3)	88.7	(1,349.1)
Operating income/(loss)	58.1	3.3	21.0	(68.1)	0.9	(1.7)	13.5
Interest expense, net of AFUDC	(46.2)	(4.2)	(4.5)	(14.3)	(8.3)	4.3	(73.2)
Interest income	1.1	0.2	0.2	4.0	4.1	(4.8)	4.8
Other income/(loss), net	4.1	(0.5)	(0.6)	1.0	27.1	(26.8)	4.3
Income tax (expense)/benefit	(3.9)	0.8	(5.4)	30.3	2.3	0.2	24.3
Preferred dividends	(1.4)	-	-	-	-	-	(1.4)
Net income/(loss)	$ 11.8	$ (0.4)	$10.7	$ (47.1)	$ 26.1	$ (28.8)	$ (27.7)

	For the Six Months Ended June 30, 2005
	Utility Group
	Distribution (1)			NU
(Millions of Dollars)	Electric	Gas	Transmission	Enterprises	Other	Eliminations	Total
Operating revenues	$2,280.6	$283.2	$81.9	$1,234.6	$ 168.8	$(226.4)	$ 3,822.7
Depreciation and amortization	(217.5)	(10.9)	(11.7)	(8.1)	(8.7)	6.6	(250.3)
Wholesale contract market changes, net	-	-	-	(258.5)	-	-	(258.5)
Restructuring and impairment charges	-	-	-	(47.8)	-	-	(47.8)
Other operating expenses	(1,920.2)	(241.7)	(33.1)	(1,233.5)	(160.7)	216.7	(3,372.5)
Operating income/(loss)	142.9	30.6	37.1	(313.3)	(0.6)	(3.1)	(106.4)
Interest expense, net of AFUDC	(87.6)	(8.5)	(7.4)	(27.6)	(16.3)	8.4	(139.0)
Interest income	1.9	0.3	0.3	13.3	1.3	(9.2)	7.9
Other income/(loss), net	7.6	(0.7)	(1.6)	(10.1)	80.5	(72.5)	3.2
Income tax (expense)/benefit	(20.3)	(7.2)	(9.0)	123.2	4.7	0.3	91.7
Preferred dividends	(2.8)	-	-	-	-	-	(2.8)
Net income/(loss)	$ 41.7	$ 14.5	$19.4	$ (214.5)	$ 69.6	$ (76.1)	$ (145.4)
Total assets (2)	$8,590.8	$1,076.7	$ -	$2,337.1	$4,293.7	$(4,347.7)	$11,950.6
Cash flows for total investments in plant	$ 207.2	$ 27.3	$85.0	$ 5.0	$ 7.6	$ -	$ 332.1

	For the Three Months Ended June 30, 2004
	Utility Group
	Distribution (1)				NU
(Millions of Dollars)	Electric	Gas		Transmission	Enterprises	Other		Eliminations		Total
Operating revenues	$964.1	$72.0		$33.5	$621.1		$69.3		$(235.3)	$1,524.7
Depreciation and amortization	(105.1)	(6.5)		(5.1)	(4.8)		(3.8)		3.3	(122.0)
Other operating expenses	(790.2)	(55.0)	(17	(17.2)	(598.3)		(79.2)		233.4	(1,306.5)
Operating income/(loss)	68.8	10.5		11.2	18.0		(13.7)		1.4	96.2
Interest expense, net of AFUDC	(39.3)	(4.5)		(3.3)	(12.2)		(6.7)		2.9	(63.1)
Interest income	1.0	0.1		0.0	2.3		3.1		(2.9)	3.6
Other income/(loss), net	2.9	(0.2)		0.0	(0.7)		20.3		(23.0)	(0.7)
Income tax (expense)/benefit	(10.4)	(5.7)		(2.6)	(3.4)		13.6		(2.1)	(10.6)
Preferred dividends	(1.4)	-		-	-		-		-	(1.4)
Net income/(loss)	$ 21.6	$ 0.2		$ 5.3	$ 4.0		$16.6		$ (23.7)	$ 24.0

	For the Six Months Ended June 30, 2004
	Utility Group
	Distribution (1)			NU
(Millions of Dollars)	Electric	Gas	Transmission	Enterprises	Other	Eliminations	Total
Operating revenues	$2,023.7	$243.3	$64.5	$1,417.5	$135.8	$(521.8)	$3,363.0
Depreciation and amortization	(215.3)	(12.9)	(10.0)	(9.6)	(7.4)	6.4	(248.8)
Other operating expenses	(1,646.7)	(205.2)	(30.4)	(1,346.0)	(135.1)	518.2	(2,845.2)
Operating income/(loss)	161.7	25.2	24.1	61.9	(6.7)	2.8	269.0
Interest expense, net of AFUDC	(79.2)	(8.4)	(5.6)	(25.9)	(12.5)	5.7	(125.9)
Interest income	2.1	0.1	0.1	4.2	5.9	(5.8)	6.6
Other income/(loss), net	5.0	(0.6)	(0.3)	(1.3)	47.3	(52.2)	(2.1)
Income tax (expense)/benefit	(30.9)	(4.2)	(5.8)	(16.1)	9.0	(5.4)	(53.4)
Preferred dividends	(2.8)	-	-	-	-	-	(2.8)
Net income/(loss)	$ 55.9	$ 12.1	$12.5	$ 22.8	$ 43.0	$(54.9)	$ 91.4
Cash flows for total investments in plant	$ 182.8	$ 19.9	$ 76.4	$ 11.3	$ 12.3	$ -	$ 302.7

(1)

Includes PSNH's generation activities.

(2)

Information for segmenting total assets between electric distribution and transmission is not available at June 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 six months ended June 30, 2005 and 2004 is as follows:

	CL&P - For the Three Months Ended June 30, 2005
(Millions of Dollars)	Distribution	Transmission	Totals
Operating revenues	$767.0	$30.6	$797.6
Depreciation and amortization	(65.0)	(4.5)	(69.5)
Other operating expenses	(670.4)	(11.8)	(682.2)
Operating income	31.6	14.3	45.9
Interest expense, net of AFUDC	(30.6)	(3.8)	(34.4)
Interest income	0.8	0.2	1.0
Other income/(loss), net	4.6	(0.7)	3.9
Income tax expense	(0.7)	(3.2)	(3.9)
Preferred dividends	(1.4)	-	(1.4)
Net income	$ 4.3	$ 6.8	$ 11.1

	CL&P - For the Six Months Ended June 30, 2005
(Millions of Dollars)	Distribution	Transmission	Totals
Operating revenues	$1,581.9	$54.6	$1,636.5
Depreciation and amortization	(120.4)	(8.6)	(129.0)
Other operating expenses	(1,378.5)	(20.6)	(1,399.1)
Operating income	83.0	25.4	108.4
Interest expense, net of AFUDC	(57.1)	(5.8)	(62.9)
Interest income	1.5	0.3	1.8
Other income/(loss), net	9.1	(1.7)	7.4
Income tax expense	(10.4)	(5.3)	(15.7)
Preferred dividends	(2.8)	-	(2.8)
Net income	$ 23.3	$12.9	$ 36.2

Cash flows for total investments in plant

$ 117.3

$64.4

$ 181.7

	CL&P - For the Three Months Ended June 30, 2004
(Millions of Dollars)	Distribution	Transmission	Totals
Operating revenues	$656.3	$22.8	$679.1
Depreciation and amortization	(59.9)	(3.7)	(63.6)
Other operating expenses	(554.9)	(11.4)	(566.3)
Operating income	41.5	7.7	49.2
Interest expense, net of AFUDC	(25.2)	(2.6)	(27.8)
Interest income	0.9	-	0.9
Other income, net	4.1	0.1	4.2
Income tax expense	(6.0)	(1.8)	(7.8)
Preferred dividends	(1.4)	-	(1.4)
Net income	$ 13.9	$ 3.4	$ 17.3

	CL&P - For the Six Months Ended June 30, 2004
(Millions of Dollars)	Distribution	Transmission	Totals
Operating revenues	$1,384.0	$43.8	$1,427.8
Depreciation and amortization	(113.7)	(7.5)	(121.2)
Other operating expenses	(1,173.1)	(20.1)	(1,193.2)
Operating income	97.2	16.2	113.4
Interest expense, net of AFUDC	(50.7)	(4.2)	(54.9)
Interest income	1.7	0.1	1.8
Other income/(loss), net	8.4	(0.1)	8.3
Income tax expense	(18.7)	(3.6)	(22.3)
Preferred dividends	(2.8)	-	(2.8)
Net income	$ 35.1	$ 8.4	$ 43.5
Cash flows for total investments in plant	$ 112.0	$60.6	$ 172.6

	PSNH - For the Three Months Ended June 30, 2005
(Millions of Dollars)	Distribution (1)	Transmission	Totals
Operating revenues	$250.3	$ 9.3	$259.6
Depreciation and amortization	(37.6)	(1.1)	(38.7)
Other operating expenses	(192.4)	(4.0)	(196.4)
Operating income	20.3	4.2	24.5
Interest expense, net of AFUDC	(11.2)	(0.6)	(11.8)
Interest income	0.2	0.1	0.3
Other (loss)/income, net	(0.5)	0.1	(0.4)
Income tax expense	(2.2)	(1.4)	(3.6)
Net income	$ 6.6	$ 2.4	$ 9.0

	PSNH - For the Six Months Ended June 30, 2005
(Millions of Dollars)	Distribution (1)	Transmission	Totals
Operating revenues	$510.6	$17.9	$528.5
Depreciation and amortization	(87.4)	(2.1)	(89.5)
Other operating expenses	(380.8)	(8.1)	(388.9)
Operating income	42.4	7.7	50.1
Interest expense, net of AFUDC	(22.1)	(1.1)	(23.2)
Interest income	0.2	0.1	0.3
Other income/(loss), net	(1.2)	-	(1.2)
Income tax expense	(5.8)	(2.4)	(8.2)
Net income	$ 13.5	$ 4.3	$ 17.8
Cash flows for total investments in plant	$ 74.4	$ 15.2	$ 89.6

	PSNH - For the Three Months Ended June 30, 2004
(Millions of Dollars)	Distribution (1)	Transmission	Totals
Operating revenues	$219.9	$ 6.5	$226.4
Depreciation and amortization	(35.6)	(0.9)	(36.5)
Other operating expenses	(165.8)	(3.9)	(169.7)
Operating income	18.5	1.7	20.2
Interest expense, net of AFUDC	(10.6)	(0.4)	(11.0)
Interest income	0.1	-	0.1
Other loss, net	(0.6)	-	(0.6)
Income tax expense	(2.2)	(0.5)	(2.7)
Net income	$ 5.2	$ 0.8	$ 6.0

	PSNH - For the Six Months Ended June 30, 2004
(Millions of Dollars)	Distribution (1)	Transmission	Totals
Operating revenues	$457.6	$13.0	$470.6
Depreciation and amortization	(81.4)	(1.8)	(83.2)
Other operating expenses	(328.8)	(6.9)	(335.7)
Operating income	47.4	4.3	51.7
Interest expense, net of AFUDC	(21.5)	(0.8)	(22.3)
Interest income	0.1	-	0.1
Other loss, net	(2.3)	(0.1)	(2.4)
Income tax expense	(8.1)	(1.2)	(9.3)
Net income	15.6	2.2	17.8
Cash flows for total investments in plant	$ 48.2	$12.3	$ 60.5

(1)

Includes PSNH's generation activities.

	WMECO - For the Three Months Ended June 30, 2005
(Millions of Dollars)	Distribution	Transmission	Totals
Operating revenues	$ 88.1	$ 5.2	$ 93.3
Depreciation and amortization	(4.6)	(0.5)	(5.1)
Other operating expenses	(77.3)	(2.3)	(79.6)
Operating income	6.2	2.4	8.6
Interest expense, net of AFUDC	(4.4)	-	(4.4)
Interest income	0.1	-	0.1
Other loss, net	(0.1)	-	(0.1)
Income tax expense	(0.9)	(0.9)	(1.8)
Net income	$ 0.9	$ 1.5	$ 2.4

	WMECO - For the Six Months Ended June 30, 2005
(Millions of Dollars)	Distribution	Transmission	Totals
Operating revenues	$188.3	$9.4	$197.7
Depreciation and amortization	(9.8)	(1.0)	(10.8)
Other operating expenses	(161.0)	(4.4)	(165.4)
Operating income	17.5	4.0	21.5
Interest expense, net of AFUDC	(8.5)	(0.5)	(9.0)
Interest income	0.2	-	0.2
Other loss, net	(0.1)	-	(0.1)
Income tax expense	(4.2)	(1.3)	(5.5)
Net income	$ 4.9	$2.2	$ 7.1
Cash flows for total investments in plant	$ 15.5	$5.4	$ 20.9

	WMECO - For the Three Months Ended June 30, 2004
(Millions of Dollars)	Distribution	Transmission	Totals
Operating revenues	$88.0	$4.1	$92.1
Depreciation and amortization	(9.6)	(0.5)	(10.1)
Other operating expenses	(69.6)	(1.8)	(71.4)
Operating income	8.8	1.8	10.6
Interest expense, net of AFUDC	(3.5)	(0.3)	(3.8)
Interest income	0.1	-	0.1
Other loss, net	(0.7)	-	(0.7)
Income tax expense	(2.2)	(0.4)	(2.6)
Net income	$ 2.5	$1.1	$ 3.6

	WMECO - For the Six Months Ended June 30, 2004
(Millions of Dollars)	Distribution	Transmission	Totals
Operating revenues	$182.3	$7.7	$190.0
Depreciation and amortization	(20.1)	(0.9)	(21.0)
Other operating expenses	(145.1)	(3.3)	(148.4)
Operating income	17.1	3.5	20.6
Interest expense, net of AFUDC	(7.0)	(0.7)	(7.7)
Interest income	0.2	-	0.2
Other loss, net	(1.1)	-	(1.1)
Income tax expense	(4.0)	(0.9)	(4.9)
Net income	$ 5.2	$1.9	$ 7.1
Cash flows for total investments in plant	$ 15.5	$1.5	$ 17.0

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

	NU Enterprises - For the Three Months Ended June 30, 2005
(Millions of Dollars)	Merchant Energy	Services and Other	Totals
Operating revenues	$276.7	$53.7	$330.4
Depreciation and amortization	(3.8)	0.1	(3.7)
Wholesale contract market changes, net	(69.6)	-	(69.6)
Restructuring and impairment charges	(1.0)	(1.3)	(2.3)
Other operating expenses	(264.8)	(58.1)	(322.9)
Operating loss	(62.5)	(5.6)	(68.1)
Interest expense	(10.2)	(4.1)	(14.3)
Interest income	-	4.0	4.0
Other income, net	0.8	0.2	1.0
Income tax benefit	28.3	2.0	30.3
Net loss	$ (43.6)	$ (3.5)	$ (47.1)

	NU Enterprises - For the Six Months Ended June 30, 2005
(Millions of Dollars)	Merchant Energy	Services and Other	Totals
Operating revenues	$1,120.4	$114.2	$1,234.6
Depreciation and amortization	(8.4)	0.3	(8.1)
Wholesale contract market changes, net	(258.5)	-	(258.5)
Restructuring and impairment charges	(8.2)	(39.6)	(47.8)
Other operating expenses	(1,109.1)	(124.4)	(1,233.5)
Operating loss	(263.8)	(49.5)	(313.3)
Interest expense	(21.6)	(6.0)	(27.6)
Interest income	-	13.3	13.3
Other income/(loss), net	0.5	(10.6)	(10.1)
Income tax benefit	102.5	20.7	123.2
Net loss	$ (182.4)	$(32.1)	$ (214.5)
Total assets	$2,095.9	$241.2	$2,337.1
Cash flows for total investments in plant	$ 5.0	$ -	$ 5.0

	NU Enterprises - For the Three Months Ended June 30, 2004
(Millions of Dollars)	Merchant Energy	Services and Other	Totals
Operating revenues	$553.5	$67.6	$621.1
Depreciation and amortization	(4.4)	(0.4)	(4.8)
Other operating expenses	(527.9)	(70.4)	(598.3)
Operating income/(loss)	21.2	(3.2)	18.0
Interest expense	(10.5)	(1.7)	(12.2)
Interest income	0.4	1.9	2.3
Other loss, net	(0.6)	(0.1)	(0.7)
Income tax (expense)/benefit	(4.6)	1.2	(3.4)
Net income/(loss)	$ 5.9	$(1.9)	$ 4.0

	NU Enterprises - For the Six Months Ended June 30, 2004
(Millions of Dollars)	Merchant Energy	Services and Other	Totals
Operating revenues	$1,289.6	$127.9	$1,417.5
Depreciation and amortization	(8.7)	(0.9)	(9.6)
Other operating expenses	(1,216.1)	(129.9)	(1,346.0)
Operating income/(loss)	64.8	(2.9)	61.9
Interest expense	(21.8)	(4.1)	(25.9)
Interest income	0.8	3.4	4.2
Other loss, net	(1.3)	-	(1.3)
Income tax (expense)/benefit	(17.5)	1.4	(16.1)
Net income/(loss)	$ 25.0	$ (2.2)	$ 22.8
Cash flows for total investments in plant	$ 11.3	$ -	$ 11.3

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Trustees and Shareholders of Northeast Utilities

We have reviewed the accompanying condensed consolidated balance sheet of Northeast Utilities and subsidiaries ("the Company") as of June 30, 2005, and the related condensed consolidated statements of (loss)/income for the three-month and six-month periods ended June 30, 2005 and 2004, and of cash flows for the six-month periods ended June 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 Note 2, the Company’s competitive business subsidiary, Northeast Utilities Enterprises, Inc., recorded significant charges in the three-month and six-month periods ended June 30, 2005 in connection with its decision to exit certain business lines.

We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet and consolidated statement of capitalization of Northeast Utilities and subsidiaries as of December 31, 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, 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

August 8, 2005

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THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES

THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
	June 30,	December 31,
	2005	2004
	(Thousands of Dollars)
ASSETS

Current Assets:
Cash	$ 2,240	$ 5,608
Investments in securitizable assets	247,882	139,391
Notes receivable from affiliated companies	8,375	-
Receivables, less provision for uncollectible
accounts of $2,429 in 2005 and $2,010 in 2004	65,330	69,892
Accounts receivable from affiliated companies	67,456	66,386
Unbilled revenues	7,591	8,189
Taxes receivable	-	766
Materials and supplies, at average cost	32,699	33,213
Derivative assets - current	43,139	24,243
Prepayments and other	10,001	15,004
	484,713	362,692

Property, Plant and Equipment:
Electric utility	3,780,551	3,671,767
Less: Accumulated depreciation	1,130,528	1,089,872
	2,650,023	2,581,895
Construction work in progress	294,124	242,982
	2,944,147	2,824,877

Deferred Debits and Other Assets:
Regulatory assets	1,432,473	1,526,359
Prepaid pension	318,759	318,559
Derivative assets - long-term	235,816	167,122
Other	111,684	116,649
	2,098,732	2,128,689











Total Assets	$ 5,527,592	$ 5,316,258



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

THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
	June 30,	December 31,
	2005	2004
	(Thousands of Dollars)
LIABILITIES AND CAPITALIZATION

Current Liabilities:
Notes payable to banks	$ -	$ 15,000
Notes payable to affiliated companies	-	90,025
Accounts payable	247,683	166,520
Accounts payable to affiliated companies	47,590	89,242
Accrued taxes	17,367	-
Accrued interest	16,732	14,203
Derivative liabilities - current	3,086	4,408
Other	68,573	65,951
	401,031	445,349

Rate Reduction Bonds	926,870	995,233

Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	786,162	761,036
Accumulated deferred investment tax credits	87,255	88,540
Deferred contractual obligations	252,218	281,633
Regulatory liabilities	619,003	614,770
Derivative liabilities - long-term	38,156	42,809
Other	92,206	95,505
	1,875,000	1,884,293

Capitalization:
Long-Term Debt	1,255,015	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	537,073	415,140
Retained earnings	356,456	347,176
Accumulated other comprehensive loss	(405)	(376)
Common Stockholder's Equity	953,476	822,292
Total Capitalization	2,324,691	1,991,383



Commitments and Contingencies (Note 6)

Total Liabilities and Capitalization	$ 5,527,592	$ 5,316,258



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

THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
		Three Months Ended		Six Months Ended
		June 30,		June 30,
		2005	2004	2005	2004
	(Thousands of Dollars)


Operating Revenues		$ 797,568	$ 679,080	$ 1,636,469	$ 1,427,770

Operating Expenses:
Operation -
Fuel, purchased and net interchange power		486,311	391,607	1,022,996	861,264
Other		139,746	124,300	255,282	216,437
Maintenance		23,804	18,416	42,479	34,847
Depreciation		33,005	29,425	65,457	58,050
Amortization of regulatory assets, net		9,462	9,143	5,208	8,583
Amortization of rate reduction bonds		26,998	25,086	58,378	54,548
Taxes other than income taxes		32,312	31,937	78,302	80,594
Total operating expenses		751,638	629,914	1,528,102	1,314,323
Operating Income		45,930	49,166	108,367	113,447

Interest Expense:
Interest on long-term debt		15,182	10,346	27,957	20,245
Interest on rate reduction bonds		14,202	16,128	28,970	32,718
Other interest		5,042	1,324	5,944	1,905
Interest expense, net		34,426	27,798	62,871	54,868
Other Income, Net		4,864	5,031	9,192	10,098
Income Before Income Tax Expense		16,368	26,399	54,688	68,677
Income Tax Expense		3,925	7,754	15,712	22,419
Net Income		12,443	18,645	38,976	46,258
Preferred Dividends of Subsidiary		1,390	1,390	2,779	2,779
Income Available for Common Stockholder		$ 11,053	$ 17,255	$ 36,197	$ 43,479













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

THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

	Six Months Ended
	June 30,
	2005	2004
	(Thousands of Dollars)

Operating Activities:
Net income	$ 38,976		$ 46,258
Adjustments to reconcile to net cash flows
provided by operating activities:
Bad debt expense	7,331		319
Depreciation	65,457		58,050
Deferred income taxes and investment tax credits, net	14,715		15,709
Amortization of regulatory assets, net	5,208		8,583
Amortization of rate reduction bonds	58,378		54,548
Deferral of recoverable energy costs	(1,845)		(6,486)
Pension expense/(income)	365		(3,381)
Regulatory (refunds)/overrecoveries	(50,325)		17,223
Deferred contractual obligations	(29,506)		(21,049)
Other sources of cash	6,829		14,079
Other uses of cash	(29,015)		(15,162)
Changes in current assets and liabilities:
Receivables and unbilled revenues, net	(11,616)		3,939
Materials and supplies	514		(727)
Investments in securitizable assets	(108,491)		(23,923)
Other current assets	5,762		(17,335)
Accounts payable	42,507		44,105
Accrued taxes	17,367		(39,607)
Other current liabilities	5,090		20,053
Net cash flows provided by operating activities	37,701		155,196

Investing Activities:
Investments in plant	(181,672)		(172,510)
Restricted cash - LMP costs	-		(30,257)
Net proceeds from sale of land	21,993		-
Other investment activities	1,243		(804)
Net cash flows used in investing activities	(158,436)		(203,571)

Financing Activities:
Issuance of long-term debt	200,000		-
Retirement of rate reduction bonds	(68,363)		(63,877)
Capital contribution from Northeast Utilities	122,000		23,000
Increase in short-term debt	(15,000)		5,000
NU Money Pool (lending)/borrowing	(90,025)		105,100
Cash dividends on preferred stock	(2,779)		(2,779)
Cash dividends on common stock	(26,918)		(23,537)
Other financing activities	(1,548)		(345)
Net cash flows provided by financing activities	117,367		42,562
Net decrease in cash	(3,368)		(5,813)
Cash - beginning of period	5,608		5,814
Cash - end of period	$ 2,240		$ 1


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

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PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
	June 30,	December 31,
	2005	2004
	(Thousands of Dollars)
ASSETS

Current Assets:
Cash	$ 215	$ 4,855
Receivables, less provision for uncollectible
accounts of $2,549 in 2005 and $1,764 in 2004	75,795	75,019
Accounts receivable from affiliated companies	44,469	34,341
Unbilled revenues	39,670	39,397
Taxes receivable	-	4,498
Fuel, materials and supplies, at average cost	57,024	52,479
Prepayments and other	8,613	11,065
	225,786	221,654

Property, Plant and Equipment:
Electric utility	1,696,428	1,627,174
Other	5,675	5,675
	1,702,103	1,632,849
Less: Accumulated depreciation	680,771	664,336
	1,021,332	968,513
Construction work in progress	71,926	63,190
	1,093,258	1,031,703

Deferred Debits and Other Assets:
Regulatory assets	847,806	900,115
Other	77,853	59,227
	925,659	959,342


Total Assets	$ 2,244,703	$ 2,212,699

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

PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
	June 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	33,000	20,400
Accounts payable	67,200	51,786
Accounts payable to affiliated companies	28,730	38,591
Accrued taxes	12,225	-
Accrued interest	11,680	11,799
Unremitted rate reduction bond collections	9,428	7,880
Other	11,707	12,629
	193,970	153,085

Rate Reduction Bonds	406,068	428,769

Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	286,876	311,998
Accumulated deferred investment tax credits	1,428	1,625
Deferred contractual obligations	48,240	54,459
Regulatory liabilities	343,038	323,707
Accrued pension	66,182	57,199
Other	21,545	24,968
	767,309	773,956
Capitalization:
Long-Term Debt	457,195	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	171,450	156,532
Retained earnings	248,872	243,277
Accumulated other comprehensive loss	(161)	(110)
Common Stockholder's Equity	420,161	399,699
Total Capitalization	877,356	856,889



Commitments and Contingencies (Note 6)


Total Liabilities and Capitalization	$ 2,244,703	$ 2,212,699

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

PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)


	Three Months Ended		Six Months Ended
	June 30,		June 30,
	2005	2004	2005	2004
	(Thousands of Dollars)


Operating Revenues	$ 259,586	$ 226,448	$ 528,477	$ 470,596

Operating Expenses:
Operation -
Fuel, purchased and net interchange power	122,256	99,960	248,487	202,002
Other	44,335	39,862	86,874	78,554
Maintenance	21,075	20,947	35,110	37,155
Depreciation	11,523	11,433	22,841	22,764
Amortization of regulatory assets, net	15,771	14,435	43,708	38,950
Amortization of rate reduction bonds	11,350	10,612	22,913	21,468
Taxes other than income taxes	8,758	8,965	18,477	17,985
Total operating expenses	235,068	206,214	478,410	418,878
Operating Income	24,518	20,234	50,067	51,718

Interest Expense:
Interest on long-term debt	5,102	3,934	9,874	7,941
Interest on rate reduction bonds	6,115	6,810	12,418	13,767
Other interest	546	293	909	605
Interest expense, net	11,763	11,037	23,201	22,313
Other Loss, Net	(158)	(486)	(936)	(2,259)
Income Before Income Tax Expense	12,597	8,711	25,930	27,146
Income Tax Expense	3,534	2,686	8,079	9,361
Net Income	$ 9,063	$ 6,025	$ 17,851	$ 17,785










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

PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

	Six Months Ended
	June 30,
	2005	2004
	(Thousands of Dollars)

Operating activities:
Net income	$ 17,851	$ 17,785
Adjustments to reconcile to net cash flows
provided by operating activities:
Bad debt expense	1,040	589
Depreciation	22,841	22,764
Deferred income taxes and investment tax credits, net	(23,021)	(12,250)
Amortization of regulatory assets, net	43,708	38,950
Amortization of rate reduction bonds	22,913	21,468
Pension expense	6,558	4,498
Regulatory overrecoveries	2,571	3,587
Deferred contractual obligations	(6,153)	(5,569)
Other sources of cash	3,760	10,491
Other uses of cash	(19,319)	(8,516)
Changes in current assets and liabilities:
Receivables and unbilled revenues, net	(12,217)	(6,664)
Fuel, materials and supplies	(4,545)	(5,204)
Other current assets	6,950	(13,526)
Accounts payable	9,562	9,866
Accrued taxes	12,225	14,177
Other current liabilities	437	(1,231)
Net cash flows provided by operating activities	85,161	91,215

Investing Activities:
Investments in plant	(89,651)	(60,453)
Other investment activities	(2,780)	415
Net cash flows used in investing activities	(92,431)	(60,038)


Financing Activities:
Retirement of rate reduction bonds	(22,701)	(21,408)
Increase/(decrease) in short-term debt	10,000	(10,000)
NU Money Pool borrowing	12,600	13,200
Capital contribution from Northeast Utilities	15,000	-
Cash dividends on common stock	(12,256)	(12,124)
Other financing activities	(13)	(118)
Net cash flows used in financing activities	2,630	(30,450)
Net (decrease)/increase in cash	(4,640)	727
Cash - beginning of period	4,855	2,737
Cash - end of period	$ 215	$ 3,464



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

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WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY

WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY

CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)

	June 30,		December 31,
	2005		2004
	(Thousands of Dollars)
ASSETS

Current Assets:
Cash		$ 1		$ 1,678
Receivables, less provision for uncollectible
accounts of $3,358 in 2005 and $2,563 in 2004		38,872		37,909
Accounts receivable from affiliated companies		12,566		11,275
Unbilled revenues		14,494		15,057
Taxes receivable		-		4,824
Materials and supplies, at average cost		1,349		1,488
Prepayments and other		909		1,027
		68,191		73,258

Property, Plant and Equipment:
Electric utility		651,504		640,884
Less: Accumulated depreciation		187,856		183,361
		463,648		457,523
Construction work in progress		18,872		11,361
		482,520		468,884

Deferred Debits and Other Assets:
Regulatory assets		218,744		231,561
Prepaid pension		80,556		79,706
Prior spent nuclear fuel trust, at fair value		49,950		49,296
Other		18,665		20,535
		367,915		381,098










Total Assets		$ 918,626		$ 923,240




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

WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY

CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)

	June 30,		December 31,
	2005		2004
		(Thousands of Dollars)
LIABILITIES AND CAPITALIZATION

Current Liabilities:
Notes payable to banks		$ 10,000		$ 25,000
Notes payable to affiliated companies		33,300		15,900
Accounts payable		25,496		12,860
Accounts payable to affiliated companies		12,976		20,965
Accrued taxes		2,651		544
Accrued interest		3,520		3,515
Other		9,752		10,491
		97,695		89,275

Rate Reduction Bonds		116,823		122,489

Deferred Credits and Other Liabilities:
Accumulated deferred income taxes		219,919		220,705
Accumulated deferred investment tax credits		2,823		2,990
Deferred contractual obligations		68,881		76,965
Regulatory liabilities		22,880		24,814
Other		8,994		13,846
		323,497		339,320
Capitalization:
Long-Term Debt		208,723		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		80,572		76,103
Retained earnings		80,818		77,565
Accumulated other comprehensive loss		(368)		(62)
Common Stockholder's Equity		171,888		164,472
Total Capitalization		380,611		372,156

Commitments and Contingencies (Note 6)

Total Liabilities and Capitalization		$ 918,626		$ 923,240



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

WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY

CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
	Three Months Ended		Six Months Ended
	June 30,		June 30,
	2005	2004	2005	2004
	(Thousands of Dollars)



Operating Revenues	$ 93,317	$ 92,056	$ 197,652	$ 189,978

Operating Expenses:
Operation -
Fuel, purchased and net interchange power	54,360	49,540	117,058	106,151
Other	18,138	15,112	34,030	28,972
Maintenance	4,197	3,787	8,035	7,136
Depreciation	4,041	3,732	8,068	7,419
Amortization of regulatory (liabilities)/assets, net	(1,682)	3,730	(2,935)	8,285
Amortization of rate reduction bonds	2,768	2,596	5,615	5,277
Taxes other than income taxes	2,876	2,990	6,292	6,122
Total operating expenses	84,698	81,487	176,163	169,362
Operating Income	8,619	10,569	21,489	20,616

Interest Expense:
Interest on long-term debt	2,149	1,482	4,326	2,945
Interest on rate reduction bonds	1,917	2,105	3,885	4,254
Other interest	410	194	747	431
Interest expense, net	4,476	3,781	8,958	7,630
Other Income/(Loss), Net	74	(637)	109	(918)
Income Before Income Tax Expense	4,217	6,151	12,640	12,068
Income Tax Expense	1,849	2,571	5,545	4,942
Net Income	$ 2,368	$ 3,580	$ 7,095	$ 7,126














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

WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

	Six Months Ended
	June 30,
	2005	2004
	(Thousands of Dollars)

Operating Activities:
Net income	$ 7,095	$ 7,126
Adjustments to reconcile to net cash flows
provided by operating activities:
Bad debt expense	781	660
Depreciation	8,068	7,419
Deferred income taxes and investment tax credits, net	123	(2,221)
Amortization of regulatory (liabilities)/assets, net	(2,935)	8,285
Amortization of rate reduction bonds	5,615	5,277
Amortization of recoverable energy costs	1,351	298
Pension income	(348)	(1,331)
Regulatory overrecoveries	5,307	7,977
Deferred contractual obligations	(8,018)	(5,763)
Other sources of cash	1,465	1,790
Other uses of cash	(8,319)	(2,807)
Changes in current assets and liabilities:
Receivables and unbilled revenues, net	(2,472)	(9,918)
Materials and supplies	139	(77)
Other current assets	4,942	(10,404)
Accounts payable	5,263	12,509
Accrued taxes	2,107	5,269
Other current liabilities	(1,063)	11,409
Net cash flows provided by operating activities	19,101	35,498

Investing Activities:
Investments in plant	(20,919)	(17,039)
Net proceeds from sale of land	1,599	-
Other investment activities	1,109	734
Net cash flows used in investing activities	(18,211)	(16,305)

Financing Activities:
Retirement of rate reduction bonds	(5,666)	(5,332)
Increase in short-term debt	(15,000)	(10,000)
NU Money Pool borrowing/(lending)	17,400	(7,100)
Capital contribution from Northeast Utilities	4,500	6,500
Cash dividends on common stock	(3,842)	(3,242)
Other financing activities	41	(19)
Net cash flows used in financing activities	(2,567)	(19,193)
Net decrease in cash	(1,677)	-
Cash - beginning of period	1,678	1
Cash - end of period	$ 1	$ 1



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

NORTHEAST UTILITIES AND SUBSIDIARIES

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

This discussion should be read in conjunction with the condensed consolidated financial statements and footnotes in this Form 10-Q, the First Quarter 2005 Form 10-Q, the NU 2004 Form 10-K, and the current reports on Form 8-K disclosed in Part II, Item 6, "Other Information - Exhibits and Reports on Form 8-K," included in this report on Form 10-Q. All per share amounts are reported on a fully diluted basis.

FINANCIAL CONDITION AND BUSINESS ANALYSIS

Executive Summary

The following items in this executive summary are explained in this report on Form 10-Q:

Strategy, Results and Outlook:

Northeast Utilities (NU or the company) continues to make significant progress toward the strategic direction announced in March 2005. Progress in the second quarter of 2005 included the continued deployment of significant capital into the company's regulated transmission and distribution infrastructure and the completion of several steps in the exit from the wholesale marketing and energy services businesses. NU's second quarter results reflect that progress, but were negatively impacted by the effect of increasing market prices on the wholesale electricity contracts the company is seeking to divest.

NU reported a consolidated loss of $27.7 million, or $0.21 per share in the second quarter of 2005, compared with earnings of $24 million, or $0.19 per share, in the same period of 2004. For the first half of 2005, NU lost $145.4 million, or $1.12 per share, compared with earnings of $91.4 million, or $0.71 per share, in the first half of 2004. The lower results were due primarily to charges at NU Enterprises related to the decision to exit the wholesale marketing and energy services businesses.

NU Enterprises lost $47.1 million in the second quarter of 2005, compared with earnings of $4 million in the second quarter of 2004. NU Enterprises lost $214.5 million in the first half of 2005, compared with earnings of $22.8 million in the first half of 2004. NU Enterprises continues to work toward the goal of exiting the wholesale marketing business and completing the divestiture of its energy services businesses by the end of 2005. During the second quarter of 2005, NU Enterprises solicited bids from firms that wanted to purchase all or a large portion of the wholesale portfolio of contracts. NU Enterprises has reached agreements to settle 6 of its 15 long-dated contract obligations. NU Enterprises is also in the process of receiving and analyzing bids for several of its energy services businesses.

The Utility Group earned $22.1 million in the second quarter of 2005, compared with earnings of $27.1 million in the second quarter of 2004. The Utility Group earned $75.6 million in the first half of 2005, compared with $80.5 million in the first half of 2004. Lower earnings are primarily due to a $4.4 million charge at The Connecticut Light and Power Company (CL&P) related to an adverse regulatory decision related to prior year streetlight billings.

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 company is not providing 2005 earnings guidance for its NU Enterprises businesses.

Legislative and Regulatory Items:

On August 8, 2005, President Bush is expected to sign comprehensive federal energy legislation repealing the 1935 Act and adopting provisions designed to facilitate the construction of natural gas and electric transmission facilities.

On July 6, 2005, Connecticut Governor Rell signed legislation creating a mechanism to allow regulators to periodically true-up 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 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 Connecticut Department of Public Utility Control (DPUC) will be conducting numerous proceedings to implement the bill.

In May 2005, the DPUC approved an interim 4.8 percent increase in CL&P rates by raising the Federally Mandated Congestion Cost (FMCC) charges on customer bills to approximately 1.8 cents per kilowatt-hour (kWh) from approximately 1.2 cents per kWh. On July 29, 2005, the DPUC issued a draft decision that supports the interim rate increase approved in May 2005 and a final decision is expected by the end of August 2005. The increase is due to new reliability must run (RMR) contracts filed at the FERC by generators in Connecticut.

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.

On June 15, 2005, a FERC administrative law judge (ALJ) issued an initial decision concerning the implementation of Locational Installed Capacity (LICAP) in New England. The ALJ largely adopted the demand curve as filed by the New England Independent System Operator (ISO-NE). On July 15, 2005, ISO-NE filed a motion with the FERC requesting a FERC decision no later than September 15, 2005 to allow for implementation by January 1, 2006.

On June 30, 2005, the 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.

On July 1, 2005, after a review of its transition energy service/default energy service (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. 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.

In May 2005, a FERC ALJ issued an initial decision concerning the ROE allowed New England electric transmission owners, including NU. The decision endorsed a base ROE of 10.72 percent plus another 0.50 percent for regional transmission facilities. The ALJ deferred to the FERC final resolution on an additional 100 basis point adder for all new transmission investments. A final FERC decision is expected in late 2005.

Liquidity:

Yankee Gas Services Company (Yankee Gas) sold $50 million of 30-year first mortgage bonds in July 2005. Proceeds were used to repay short-term borrowings incurred to finance capital expenditures.

Cash flows from operations decreased by $217 million to $276.9 million for the first half of 2005 from $493.9 million for the first half 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.

Overview

Consolidated: NU lost $27.7 million, or $0.21 per share, in the second quarter of 2005, compared with net income of $24 million, or $0.19 per share, in the second quarter of 2004. NU lost $145.4 million, or $1.12 per share, in the first half of 2005, compared with earnings of $91.4 million, or $0.71 per share, in the first half of 2004. A summary of NU's earnings/(losses) by major business line for the second quarter and first half of 2005 and 2004 is as follows:

	For the Three Months Ended June 30,		For the Six Months Ended June 30,
(Millions of Dollars)	2005	2004	2005	2004
Utility Group	$ 22.1	$27.1	$ 75.6	$80.5
NU Enterprises	(47.1)	4.0	(214.5)	22.8
Parent and Other	(2.7)	(7.1)	(6.5)	(11.9)
Net (Loss)/Income	$(27.7)	$24.0	$(145.4)	$91.4

The 2005 NU losses were due to the company’s decision for NU Enterprises to exit the wholesale marketing and energy services businesses. In the second quarter of 2005, NU Enterprises recorded an after-tax mark-to-market charge of $44.3 million ($69.6 million pre-tax) associated with certain wholesale electric contracts it is seeking to divest and $1.4 million of after-tax ($2.3 million pre-tax) restructuring and impairment charges.

Excluding the wholesale contract market changes and the restructuring and impairment charges described above, NU Enterprises lost $1.4 million in the second quarter of 2005 and lost $18.8 million in the first half of 2005, compared with earnings of $4 million in the second quarter of 2004 and $22.8 million in the first half of 2004.

Utility Group: The Utility Group is comprised of CL&P, PSNH, Western Massachusetts Electric Company (WMECO), and Yankee Gas, including their transmission, distribution and generation businesses. After payment of preferred dividends, earnings at the Utility Group decreased by $5 million to $22.1 million in the second quarter of 2005 compared with $27.1 million in 2004. Utility Group earnings totaled $75.6 million in the first half of 2005 compared with $80.5 million in the first half of 2004 as retail rate increases at all four regulated companies were offset by an after-tax charge of $4.4 million related to a final regulatory decision concerning refunds to streetlighting customers, higher pension, depreciation, and interest expense, and the absence of certain positive adjustments that had been reflected in 2004 earnings. Retail electric and firm gas sales in the second quarter of 2005 were approximately 1 percent and 3 perc ent higher than the second quarter of 2004, respectively. On a year-to-date basis, 2005 retail electric sales were approximately the same as last year and firm gas sales decreased by 0.8 percent. On a weather normalized basis, both 2005 electric and firm gas sales were approximately 1.5 percent lower than 2004. A summary of Utility Group earnings by company for the three and six months ended June 30, 2005 and 2004 is as follows:

	For the Three Months Ended June 30,		For the Six Months Ended June 30,
(Millions of Dollars)	2005	2004	2005	2004
CL&P Distribution	$ 4.3	$13.9	$23.3	$35.1
CL&P Transmission	6.8	3.4	12.9	8.4
Total CL&P *	11.1	17.3	36.2	43.5
PSNH Distribution and Generation	6.6	5.2	13.5	15.6
PSNH Transmission	2.4	0.8	4.3	2.2
Total PSNH	9.0	6.0	17.8	17.8
WMECO Distribution	0.9	2.5	4.9	5.2
WMECO Transmission	1.5	1.1	2.2	1.9
Total WMECO	2.4	3.6	7.1	7.1
Yankee Gas	(0.4)	0.2	14.5	12.1
Total Utility Group Net Income	$22.1	$27.1	$75.6	$80.5

*After preferred dividends.

CL&P’s second quarter and first half 2005 distribution results were lower due primarily to an after-tax charge of $4.4 million related to a final regulatory decision concerning refunds to streetlighting customers along with higher transmission costs which were not automatically passed on to CL&P's retail customers. A $25 million distribution rate increase effective January 1, 2005 was offset by higher depreciation, interest, and pension expense. 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 second quarter 2005 distribution and generation earnings increased as compared to the same period of 2004 due to higher rates and higher residential and commercial sales, partially offset by higher operating costs. As a result of a settlement agreement approved by the NHPUC in 2004, PSNH implemented energy delivery rate increases of $3.5 million annually effective October 1, 2004 and $10 million annually, effective June 1, 2005. PSNH transmission earnings for the second quarter and first half 2005 were higher due to a higher transmission rate base.

The distribution earnings for CL&P and PSNH are also lower in 2005 as a result of certain retail transmission expenses that were charged to the distribution businesses but not included in the retail transmission rates that were charged to customers. There is no impact to earnings for the Utility Group; however, because the transmission earnings for CL&P and PSNH increased by a commensurate amount. With the enactment of the new Connecticut legislation, CL&P will be able to recover future increases in its retail transmission expenses and as a result, the Utility Group earnings will increase. WMECO already has similar ratemaking treatment for its retail transmission expenses, but PSNH does not.

WMECO second quarter and first half 2005 distribution results reflect a $6 million annualized distribution rate increase that took effect on January 1, 2005 which was offset by higher interest expense and lower pension income. WMECO’s 2005 transmission earnings have been comparable to those of 2004 as a result of a stable rate base.

Yankee Gas' second quarter 2005 results were lower than in 2004 primarily due to the absence of a positive tax adjustment which occurred in the second quarter of 2004. Year-to-date earnings were $2.4 million higher in 2005 due to a $14 million annualized rate increase that took effect on January 1, 2005.

NU Enterprises: NU Enterprises is the parent of Northeast Generation Company (NGC), Northeast Generation Services Company (NGS), Select Energy, Inc. (Select Energy), Select Energy Services, Inc. (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 Holyoke Water Power Company (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. Included in the merchant energy business segment is Select Energy’s wholesale marketing business, which NU Enterprises is exiting. The merchant energy segment will include 1,296 megawatts (MW) of primarily pumped storage and hydroelectric generation assets owned by NGC, 147 MW of coal-fired generation assets owned by HWP, Select Energy’s retail business and NGS. The energy services

businesses being divested consist of the E.S. Boulos Company, Woods Electrical Co. Inc., which are subsidiaries of NGS, SESI, SECI, Reeds Ferry, and Woods Network. These businesses will be divested in a manner that maximizes their values.

NU Enterprises lost $47.1 million in the second quarter of 2005 and $214.5 million in the first half of 2005, compared with earnings of $4 million in the second quarter of 2004 and $22.8 million in the first half of 2004. A summary of NU Enterprises’ (losses)/earnings by business for the three and six months ended June 30, 2005 and 2004 is as follows:

	For the Three Months Ended June 30,		For the Six Months Ended June 30,
(Millions of Dollars)	2005	2004	2005	2004
Merchant Energy	$(43.6)	$5.9	$(182.4)	$25.0
Energy Services, Parent and Other	(3.5)	(1.9)	(32.1)	(2.2)
Net (Loss)/Income	$(47.1)	$4.0	$(214.5)	$22.8

In the second quarter of 2005, NU Enterprises recorded an after-tax mark-to-market charge of $44.3 million ($69.6 million pre-tax) associated with certain wholesale electric contracts it is seeking to divest and $1.4 million of after-tax ($2.3 million pre-tax) restructuring and impairment charges. The mark-to-market charge reflects increases in electricity prices in the forward markets over the next several years, which reduced the mark-to-market value of certain wholesale electric contracts. NU Enterprises is seeking to divest those contracts and will continue to mark them to market until they are divested or expire. If wholesale electric prices continue to fluctuate, those price movements will have an impact on NU Enterprises' earnings.

Losses in the first half of 2005 were primarily the result of $195.7 million of after-tax ($306.3 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 half 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 quarter nor will they have an impact on future earnings. Losses in the first half of 2005 also include a positive after-tax impact relating to trading contracts total ing $16.4 million ($25.8 million pre-tax) in the first half of 2005.

Excluding the mark-to-market and restructuring and impairment charges, the merchant energy segment lost $12.8 million for the first half of 2005. Retail marketing lost $3.5 million in the first half 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. These contracts are being divested, while the sales contracts are being retained and remain on accrual accounting. Fu ture quarterly retail energy marketing business results will be negatively affected by this accounting treatment. Excluding that impact, which was $6.3 million after-tax, the retail energy marketing business earned $2.8 million for the first six months of 2005. Retail marketing remains on target to earn the $6 million projected for 2005, compared with approximately $5 million in 2004, excluding the impact of this accounting treatment. This after-tax negative impact is expected to be approximately $17 million for the third quarter of 2005, $4 million for the fourth quarter of 2005, approximately $20 million for 2006, approximately $11 million for 2007, and approximately $3 million in 2008.

The remainder of the merchant energy segment, which includes merchant generation and wholesale marketing, lost $9.2 million for the first half of 2005. Losses are expected to continue through 2005 because the discontinuance of wholesale marketing activities and the marking-to-market of wholesale contracts significantly reduced future wholesale gross margins. At the same time, the merchant energy cost structure has not yet been reduced to going-forward levels due to managing the wholesale marketing contracts until they are divested. While merchant generation assets continue to run well, energy and capacity values realized in 2005 remain modest.

The services businesses lost $3 million in the second quarter of 2005 and $30.9 million in the first half of 2005, primarily as a result of an 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. Management expects to sell the energy services businesses before the end of 2005.

Additionally, NU Enterprises parent lost $0.5 million in the second quarter of 2005 and $1.2 million in the first half of 2005 which includes $0.2 million of restructuring and impairment charges recorded in the second quarter. In 2004, the services businesses and NU Enterprises parent lost $1.9 million in the second quarter and $2.2 million in the first half of 2004.

Parent and Other: Parent company and other after-tax expenses totaled $2.7 million in the second quarter of 2005, compared with $7.1 million in the same quarter of 2004, when NU recorded a $2.4 million after-tax write-off on an investment in a fuel cell development company. After-tax parent company and other expenses totaled $6.5 million in the first half of 2005, compared with $11.9 million in 2004. Results in 2005 were negatively affected by a $2.2 million first-quarter after-tax charge associated with higher manufactured gas plant environmental liabilities at HWP's Mt. Tom coal-fired unit and a second quarter $0.5 million after-tax impairment charge involving a former Yankee Energy System, Inc. note receivable from an operator of renewable energy projects. First quarter 2004 results reflected an after-tax write-down of approximately $1.5 million associated with that note receivable.

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.

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

Liquidity

Consolidated: NU continues to maintain an adequate level of liquidity. At June 30, 2005, NU had $55.5 million of cash and cash equivalents compared with $47 million at December 31, 2004.

Cash flows from operations decreased by $217 million from $493.9 million for the first six months of 2004 to $276.9 million for the first six months of 2005. The decrease in operating cash flows is 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 and changes in working capital items, primarily investments in securitizable assets and accounts payable. Investments in securitizable assets are receivables and unbilled revenues which are eligible to be but have not been sold to the financial institution under CL&P's receivables sales arrangement. Investments in securitizable assets, when combined with receivables and unbilled revenues, increased by $7.6 million in part due to CL&P rate increases in the first half of 2005 for Tr ansitional Standard Offer (TSO) and FMCC charges compared with a decrease of $55.6 million in the first half of 2004.

In 2004, net cash flows from operations totaled $517.1 million for the entire year, or only $23.2 million more than for the first six months of 2004. The primary reason for the low level of cash flows in the second half of 2004 was significant regulatory refunds to customers from CL&P. Management anticipates that Utility Group net cash flows in the second half of 2005 will significantly exceed those in the second half of 2004. However, if NU Enterprises succeeds in buying out many more of its below-market wholesale marketing contracts, NU would need to borrow on its $500 million revolving credit line, provide additional equity infusions to NU Enterprises, or a combination of the two. As of June 30, 2005, there was $147 million borrowed on that revolving credit line, of which $450 million can be borrowed presently, and an additional $78.3 million of letters of credit (LOCs). There was also $30 million borrowed by NU’s re gulated companies on their separate $400 million revolving credit line. Both credit lines mature in November 2009. 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 June 30, 2005, CL&P had sold $60 million to that financial institution.

On June 22, 2005, NU companies closed on the sale of approximately 39 acres of property in Stamford, Connecticut to an unaffiliated developer. The property formerly served as a manufactured gas plant and later as an electric generation plant. The sales price was approximately $24 million resulting in a gain of $13.6 million which was recorded as a regulatory liability, and will be used as an offset to stranded costs. The cost of the land included amounts recorded related to environmental remediation. The developer assumed financial responsibility and liability associated with the environmental cleanup. Proceeds were used primarily to reduce short-term debt.

On June 23, 2005, NU filed an application with the Securities and Exchange Commission (SEC) seeking authority to issue up to $750 million of new securities, including common equity, preferred equity and debt. NU expects to issue additional common equity no later than 2006 and possibly as early as late 2005. The proceeds will be used to fund the Utility Group’s capital investment initiatives. In the first half of 2005, NU infused $141.5 million of equity into the Utility Group companies, including $122 million into CL&P. An equity issuance would strengthen NU’s balance sheet. The issuance of $200 million of debt primarily to support CL&P's capital program, combined with losses associated with exiting the wholesale marketing business and divesting the energy services businesses has caused a decrease in the equity component of total consolidated capitalization. At June 30, 2005, total short and long-ter m debt, excluding rate reduction bonds, represented 59 percent of consolidated capitalization.

Exiting the wholesale marketing business will have an impact on cash outflows, the magnitude of which will depend upon the method of exiting. The negative mark-to-market on the wholesale contracts being divested at June 30, 2005 was $250 million. If these contracts were settled at this amount, there would be significant cash tax benefits. This, combined with the anticipated positive after-tax cash proceeds related to selling the energy services businesses, is expected to reduce the negative cash outflows to a manageable amount from a liquidity and leverage standpoint.

NU's credit ratings outlooks at Moody's Investors Service (Moody's) and Standard & Poor's (S&P) are currently stable and management does not believe that at this time there is a significant risk of a ratings downgrade to sub-investment grade levels. However, if NU were to be downgraded to a sub-investment grade level, this downgrade could have a negative impact on NU's liquidity.

On June 30, 2005, NU paid a dividend of $0.1625 per share. On May 10, 2005, the NU Board of Trustees approved a common dividend of $0.175 per share, payable September 30, 2005, to shareholders of record at September 1, 2005. The dividend represents the fifth consecutive annual increase approved by the Board of Trustees.

NU's capital expenditures totaled $332.1 million in the first six months of 2005, compared with $302.7 million in the first six 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.

On May 27, 2005, S&P downgraded all rated securities for NU's companies by one notch, except for those of NGC, which were affirmed with a negative outlook. The downgrade did not result in a material increase in borrowing costs or other negative factors. All S&P ratings for NU's companies, except for those of NGC, are now stable.

Utility Group: On July 21, 2005, Yankee Gas closed on the sale of $50 million of 30-year first-mortgage bonds. The interest rate was 5.35 percent. Proceeds were used to repay short-term borrowings incurred to finance capital expenditures.

WMECO is expected to issue a separate $50 million of senior unsecured notes in August 2005. The issuance was approved on June 9, 2005 by the Massachusetts Department of Telecommunications and Energy (DTE). An application for PSNH to issue $50 million of first mortgage bonds later in 2005 is pending with the NHPUC.

NU Enterprises: During the first half of 2005, liquidity benefited from counterparty collateral deposits received exceeding counterparty collateral deposits made by $20 million.

The charges recorded in the first half 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. 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. The sale or renegotiation of the longer-term below market electricity contracts, however, will likely require NU Enterprises to make significant upfront payments to the counterparties in such transactions.

NU Enterprises Divestitures

Wholesale Marketing Business: NU Enterprises continues to work toward the goal of exiting the wholesale marketing business by the end of 2005. NU Enterprises is continuing to evaluate several alternatives to accomplish this goal, including selling the wholesale portfolio of contracts, restructuring long-term wholesale contracts, and serving out some or all of the remaining contracts until they expire. During the second quarter of 2005, NU Enterprises solicited bids from firms that wanted to purchase all or a large portion of the wholesale portfolio of contracts with 28 firms expressing interest in the wholesale portfolio of contracts and 15 firms submitting indicative bids.

In parallel, NU Enterprises is restructuring its long-dated contract obligations and has reached agreements to buy out 6 of the 15 municipal contracts that are being sold. Those 6 contracts, which account for over 20 percent of the value of these load obligations, will terminate between September 1, 2005 and March 1, 2006. Active negotiations are continuing with the other 9 municipalities, and NU Enterprises remains hopeful that it will be able to renegotiate or sell all of those contracts in 2005 under acceptable terms.

NU Enterprises is also seeking to divest the contracts to serve a number of investor-owned utilities in New England and PJM over the next three years. These contracts currently total approximately 26 million megawatt-hours of sales obligations. Approximately 75 percent of the sales and purchase obligations are for delivery over the next 12 months. These contracts are essentially volumetrically balanced based on the company's projected load obligations; however, load variability could result in an inbalance. Such an inbalance or significant changes in basis prices could have material economic consequences. If NU Enterprises cannot sell this portfolio of contracts on acceptable terms, then contracts would be divested individually or served out.

Energy Services Businesses: NU Enterprises continues to work to complete the divestiture of its energy services businesses by the end of 2005. During the second quarter of 2005, a number of parties have expressed interest in those companies and NU Enterprises was in the process of receiving and analyzing bids for several of these businesses with the expectation of selling these businesses by the end of 2005.

Business Development and Capital Expenditures

Utility Group:

Connecticut – CL&P: Transmission capital expenditures in Connecticutare focused primarily on four major transmission projects in southwest Connecticut. These projects include the Bethel, Connecticut to Norwalk, Connecticut and Middletown, Connecticut to Norwalk, Connecticut projects, as well as a related 115 kilovolt (kV) underground project, and the replacement of the existing Long Island cable. Each of these projects has received approval from the Connecticut Siting Council (CSC). Capital expenditures for the southwest Connecticut transmission projects totaled $25 million for the three months ended June 30, 2005 and $41 million for the six months ended June 30, 2005. In 2005, CL&P's transmission capital expenditures in southwest Connecticut are projected to total approximately $155 million.

On April 7, 2005, the CSC unanimously approved a proposal by CL&P and UI to build a 69-mile 345 kV transmission line from Middletown to Norwalk. 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. CL&P expects the project to be completed by the end of 2009. The project is currently expected to cost between $840 million and $990 million with CL&P owning 80 percent of the project. The CSC’s approval included variations to the proposed route for which the CL&P is reevaluating the project costs. The period to appeal the CSC’s approval ended May 27, 2005 and legal review of the three appeals filed is ongoing. However, CL&P, at this time, does not expect any of th ese three appeals to delay construction. At June 30, 2005, CL&P has capitalized $26 million associated with this project.

In March 2005, CL&P signed contracts for construction of a 21-mile 345 kV line between Bethel and Norwalk. Line construction activities began in April 2005, although a considerable amount of substation work had been completed earlier. This project is now approximately 30 percent complete and CL&P expects to complete the project by the end of 2006 at a cost of between $300 million and $350 million. The cost range reflects that not all vendor contracts have been signed. At June 30, 2005, CL&P has capitalized $95 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 meet growing electric demands in the area. Management expects the lines to be in service during 2008. At June 30, 2005, CL&P has capitalized $5 million related to 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. Federal approvals also are expected in 2005. Assuming final approval is received in 2005, construction activities are scheduled to begin i n the fall of 2006 and management expects the line will be in service by 2007. At June 30, 2005, CL&P has capitalized $8 million of costs related to this project.

Connecticut – Yankee Gas: In January 2005, Yankee Gas held formal groundbreaking for 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 and is expected to be completed in 2007 in time for the 2007-2008 heating season. This project is now approximately 20 percent complete. The facility is expected to cost $108 million and through June 30, 2005, Yankee Gas has capitalized $28.1 million related to this project.

New Hampshire: Construction activities associated with PSNH’s $75 million conversion of a 50-megawatt coal-fired unit at Schiller Station in Portsmouth, New Hampshire began in late 2004 and are expected to be completed in the second half of 2006. This project is now approximately 55 percent complete. At June 30, 2005, PSNH has capitalized $41 million related to this project.

As part of the project, a conveyor must be constructed over a single railroad track owned by Boston & Maine Corporation (B&M). B&M had initially denied PSNH permission to construct this crossing. A settlement agreement resolving the conveyor issues was reached in June 2005 and all court and regulatory filings have been withdrawn. As part of this settlement agreement, a license agreement was signed for the track crossing rights along with crossing rights for several other apparatus which were previously subject to short-term crossing rights.

NU Enterprises: In March 2005, HWP notified Massachusetts environmental regulators that it planned to install a selective catalytic reduction system at the 147 megawatt Mt. Tom coal-fired station in Holyoke, Massachusetts. The system will significantly reduce nitrogen oxide emissions from the unit and extend its operating life. The $14 million project commenced in July 2005 and is expected to be complete by mid-2006. At June 30, 2005, HWP has capitalized $2.6 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.

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 re solution 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 that is more conservative than that reflected in current transmission rates.

Legislative Matters

On August 8, 2005, President Bush is expected to sign into law comprehensive energy legislation. Among other provisions potentially affecting NU are: the repeal of the 1935 Act; FERC backstop siting authority for transmission and transmission rate reform; renewable production tax credits; and accelerated depreciation for certain new electric and gas facilities. The legislation also expressed a "sense of Congress" that the FERC should note the concerns of the New England states with regard to LICAP and carefully consider their objections.

Connecticut:

Transmission Tracking Mechanism: On July 6, 2005, Governor Rell signed legislation creating a mechanism to allow regulators to periodically true-up the retail transmission charge in distribution company rates based on changes in FERC-approved charges. This mechanism will allow CL&P to promptly recover its transmission expenditures.

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 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 RMR contracts, and proposed for 2006, a new administrative rule called LICAP. The bill 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 c ompanies. The bill 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. The bill 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.

New Hampshire:

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 six months ended June 30, 2005, this true up has resulted in the recognition of a $1.6 million regulatory asset.

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, beginning in July 2005, CL&P will track its retail transmission revenues and expenses and 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 a Connecticut legislative session. 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 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. 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. On July 15, 2005, ISO-NE filed a motion with the FERC requesting a FERC decision no later than September 15, 2005 to allow for implementation by January 1, 2006.

On March 23, 2005, the FERC issued two orders affirming its prior decisions regarding the LICAP market and the creation of two separate LICAP and energy zones in Connecticut. These orders were appealed by CL&P, the DPUC, the Connecticut Office of Consumer Counsel (OCC), and the Connecticut Attorney General to the First Circuit Court of Appeals which dismissed the appeal without prejudice on May 5, 2005. 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.

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 expects to file an appeal of this decision in August 2005.

Procurement Fee Rate Proceedings: CL&P is currently allowed to collect a fixed procurement fee of 0.50 mills per kWh from customers who purchase 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 propo sed methodology. The schedule in this proceeding has not yet been determined. 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.

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 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.

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 OCC to defer the recovery of higher supplier costs into future years. On February& nbsp;3, 2005, the OCC filed an appeal with the Connecticut Superior Court challenging this decision. This appeal is identical to the appeal filed with the same court in February 2004 challenging the DPUC's December 2003 decision. Management believes that this appeal will not impact the DPUC's December 22, 2004 order.

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 claims 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. Management believes that these appeals will not impact the TSO rates approved by the DPUC.

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 July 29, 2005, the DPUC issued a draft decision that supports the interim rate increase approved in May 2005 and a final decision is expected by the end of August 2005.

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. This NHPUC order continued the practice of requiring an interim review of TS/DS costs for a possible TS/DS rate change effective August 1, 2005. The TS/DS rate of $0.0649 per kWh included an 11 percent ROE on PSNH's generation assets. This generation ROE was the subject of a second set of proceedings in this docket in which PSNH subsequently filed testimony supporting an 11.4 percent ROE on its generation assets while the NHPUC staff advocated an ROE of 9.08 percent. 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’s motion cited several issues with the NHPUC’s order, including a mathematical error and the generation ROE not being commensurate with the risks associated with generation assets. 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.

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 $227.4 million at June 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 $386.7 million to $159.3 million.

Wholesale Distribution Rate Case: On May 19, 2005, the FERC issued an order allowing PSNH to bill wholesale distribution rates under the terms of its settlement agreement. The settlement agreement allows PSNH to recover certain delivery costs arising from the provision of wholesale delivery service to another New Hampshire utility. The effect of the settlement agreement will be to increase PSNH’s annual revenues by approximately $1.8 million.

Massachusetts:

Transition Cost Reconciliation and Other Filings: On March 31, 2005, WMECO filed its 2004 transition cost reconciliation with the DTE. The DTE has combined the 2003 and 2004 transition cost reconciliation filings, the standard offer service and default service reconciliations, and the transmission cost adjustment filings 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.

Financing Debt Issuance Application: On March 4, 2005, WMECO filed an application requesting permission to issue long-term debt securities not to exceed $50 million through December 31, 2005 and also requested approval to enter into interest rate locks. Proceeds from the issuance of long-term debt will be used to refinance short-term debt and finance planned capital expenditures. On June 9, 2005, the DTE issued a decision approving the $50 million financing and interest rate lock application and an interest rate lock was entered into in June 2005.

Nuclear Decommissioning and Plant Closure Costs

The Connecticut Yankee Atomic Power Company (CYAPC) is involved in an ongoing FERC proceeding to recover its increased estimate of decommissioning and plant closure costs and is also involved in litigation over the termination of the decommissioning contract with Bechtel Power Corporation (Bechtel). The company cannot at this time predict the timing or outcome of the FERC proceeding or the outcome of the litigation with Bechtel.

CYAPC, Yankee Atomic Electric Company and Maine Yankee Atomic Power Company commenced litigation in 1998 charging that the federal government breached contracts it entered into with each company in 1983 regarding the removal of spent nuclear fuel. Management can predict neither the outcome of this matter nor its ultimate impact on NU.

For further information regarding these issues, see Note 6D, "Deferred Contractual Obligations," to the condensed consolidated financial statements.

NU Enterprises

NU Enterprises currently has two business segments: the merchant energy business segment and the energy services and other business segment.

Merchant Energy Segment: The merchant energy business segment includes Select Energy's retail marketing business, 1,443 MW of generation assets, including 1,296 MW of primarily pumped storage and hydroelectric generation assets at NGC, 147 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 will exit. 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 most 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.

The recognition of additional gains or losses on wholesale marketing contracts that have not been recorded yet. Many full requirements contracts have quantities of electricity expected to be delivered in amounts different from the notional amounts that were multiplied by current market prices to determine the mark-to-market charge. In addition, gains or losses may be recorded on the disposition of these wholesale contracts.

Additional asset impairments or losses on disposals. As the services 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 second quarter of 2005, compared to $108.3 million of CL&P standard offer purchases from Select Energy in the second quarter of 2004. Other energy purchases between CL&P and Select Energy totaled $12.5 million in the second quarter of 2005 compared to $27.7 million in the second quarter of 2004. WMECO purchases from Select Energy in the second quarter of 2005 totaled $17.4 million, compared to $21 million in the second 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 six months of 2005, compared to $256.8 million of CL&P standard offer purchases from Select Energy in the first six months of 2004. Other energy purchases between CL&P and Select Energy totaled $26.7 million in the first six months of 2005 compared to $57.7 million in the first six months of 2004. WMECO purchases from Select Energy in the first six months of 2005 totaled $37.9 million, compared to $53 million in the first six months of 2004. These amounts are eliminated in consolidation.

Included in these charges is a $15.7 million and $70.2 million pre-tax mark-to-market charge for the three and six months ended June 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 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 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. Contracts with lower quantities and less complex terms will result in an NU Enterprises risk profile that is reduced compared to the current wholesale marketing business. The merchant energy business segment will be comprised of generation assets and the retail marketing segment, 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 in light of NU Enterprises' change in focus from wholesale marketing to retail marketing and merchant generation. 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 with low 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.

Currently, 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 continues to rise. In 2005, NU Enterprises is bidding on 50 percent more retail business than in 2004, with a 20 percent success rate in 2005 as compared to 13 percent last year.

NU Enterprises expects retail revenues to be between $1.1 billion and $1.3 billion in 2005, compared with about $850 million in 2004. Through the first six months of 2005, 5.3 million megawatt-hours were delivered as compared to 4.8 million megawatt-hours in 2004. For natural gas, NU Enterprises delivered 27.8 billion cubic feet in the first six months of 2005 as compared to 22.5 billion cubic feet in the first six months of 2004. NU Enterprises expects delivered megawatt-hours to reach 13 million in 2005, compared with 10 million in 2004 and for delivered natural gas to exceed 60 billion cubic feet in 2005, and increase from 40 billion cubic feet in 2004.

On average, electric unit margins on new business range from $1.60 to $2.20 a megawatt-hour. For natural gas, unit margins are expected to be between $0.20 and $0.25 per thousand cubic feet. If the projected volumes are multiplied by unit margins, NU Enterprises' 2005 gross margin goal is approximately $40 million, $25 million electric and $15 million gas. Based on what has been delivered to date and what is under contract, NU Enterprises has secured approximately 70 percent of the gross margin projected for 2005. With many customers signing month-to-month or three-month contracts, expecting that energy prices will decrease, NU Enterprises is within reach of 2005 targeted margins.

From time to time, the retail marketing business line enters into contracts that cannot immediately receive accrual accounting and therefore changes in fair value are required to be marked-to-market and included in earnings.

At June 30, 2005, Select Energy had retail derivative assets and liabilities as follows:

(Millions of Dollars)
Current retail derivative assets	$17.1
Long-term retail derivative assets	5.8
Current retail derivative liabilities	(1.3)
Long-term retail derivative liabilities	(0.4)
Portfolio position	$21.2

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 June 30, 2005. A description of each method is as follows: 1) prices actively quoted primarily represent New York Mercantile Exchange (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.

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 ended June 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. Intercompany transactions are eliminated and not reflected in the amounts below.

(Millions of Dollars)	Fair Value of Retail Sourcing Contracts at June 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	$ (0.6)	$ -	$ -	$ (0.6)
Prices provided by external sources	16.4	5.4	-	21.8
Totals	$15.8	$5.4	$ -	$21.2

	Three Months Ended June 30, 2005
(Millions of Dollars)	Total Portfolio Fair Value
Fair value of retail sourcing contracts outstanding at March 31, 2005	$30.7
Contracts realized or otherwise settled during the period	(5.3)
Changes in fair value of contracts	(4.2)
Fair value of retail sourcing contracts outstanding at June 30, 2005	$21.2

Subsequent to March 31, 2005, management elected to retain certain contracts to help support its retail marketing business, and market changes are 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 4, "Derivative Instruments," to the condensed consolidated financial statements.

Generation Activities: The 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. A significant determinant of the future value of generation assets is the implementation of LICAP.

During the first six months of 2005, NU Enterprises' 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 six months of 2005, the 1,080 megawatt Northfield Mountain facility had an availability factor of 94 percent, while the 147 megawatt Mt. Tom plant at HWP had an availability factor of 91 percent. The nearly 200 MW of other hydroelectric units had an aggregate availability factor of 85 percent.

Conventional hydroelectric generation in the first half of 2005 is nearly 10 percent ahead of budget due to above average rainfall and plant availability. That percentage translates into 400,000 megawatt-hours through June 2005, compared with a projected amount of 370,000 megawatt-hours. Approximately 1 million megawatt-hours are generated annually at Mt. Tom, a coal-fired unit located in Holyoke, Massachusetts. Through June 2005, more than 500,000 megawatt-hours were generated at Mt Tom.

For the Northfield Mountain facility, on-peak, off-peak spreads rose to as high as 2:1 in June 2005, an increase from 1.4:1 earlier in 2005. As a result, NU Enterprises has realized $6 million of energy-related gross margin through June 2005 and is on target to earn the $12 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 de mand curve as filed by ISO-NE. On July 15, 2005, ISO-NE filed a motion with the FERC requesting a FERC decision no later than September 15, 2005 to allow for implementation by January 1, 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. ISO-NE has indicated that it needs FERC approval of the LICAP market by September 15, 2005 to have adequate time to implement LICAP on January 1, 2006. Management believes that if the FERC approves LICAP to take effect on January 1, 2006 consistent with the ALJ recommendation, NU Enterprises will receive approximately $50 million of capacity-related revenue in 2006. If there is no LICAP market in 2006, it is estimated, based on current capacity values, that the capacity and forward reserve revenue will be somewhat less than $30 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-related 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.

Hedging: For information on derivatives used for hedging purposes, see Note 4, "Derivative Instruments," and Note 8, "Comprehensive Income," to the condensed consolidated financial statements.

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.

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

(Millions of Dollars)
Current wholesale derivative assets	$ 203.6
Long-term wholesale derivative assets	182.5
Current wholesale derivative liabilities	(286.1)
Long-term wholesale derivative liabilities	(350.0)
Portfolio position	$(250.0)

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 June 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 ye ar 2008. For all natural gas positions, broker quotes extend through 2013.

As of and for the quarter ended June 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. Intercompany transactions are eliminated and not reflected in the amounts below.

(Millions of Dollars)	Fair Value of Wholesale Contracts at June 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	$(23.8)	$ (1.2)	$ -	$ (25.0)
Prices provided by external sources	(34.9)	(83.2)	31.6	(86.5)
Model based	0.1	(37.6)	(101.0)	(138.5)
Totals	$(58.6)	$(122.0)	$ (69.4)	$(250.0)

Three Months Ended June 30, 2005

(Millions of Dollars)

Total Portfolio Fair Value

Fair value of wholesale contracts outstanding

at March 31, 2005

$(201.2)

Contracts realized or otherwise

settled during the period

13.8

Changes in fair value of wholesale contracts

(69.6)

Changes in fair value of contracts formerly

designated as trading

7.0

Fair value of wholesale contracts outstanding

at June 30, 2005

$(250.0)

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 on the accompanying condensed consolidated statements of (loss)/income.

For further information regarding Select Energy's derivative contracts, see Note 4, "Derivative Instruments," to the condensed consolidated financial statements.

Counterparty Credit: Counterparty credit risk relates to the risk of loss that Select Energy would incur because of non-performance by counterparties pursuant to the terms of their contractual obligations. Select Energy has established 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 June 30, 2005, approximately 71 percent of Select Energy's counterparty credit exposure to wholesale and trading counterparties was collateralized or rated BBB- or better. Select Energy was provided $102.2 million and $57.7 million of counterparty deposits at June 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.

Select Energy's Credit: A number of Select Energy's contracts require the posting of additional collateral in the form of cash or LOCs in the event NU's ratings were to decline and in increasing amounts dependent upon the severity of the decline. At NU's present

investment grade ratings, Select Energy has not had to post any collateral based on credit downgrades. Were NU's unsecured ratings to decline to sub-investment grade by either Moody's or S&P, Select Energy could, under its present contracts, be asked to provide at June 30, 2005 approximately $450 million of collateral or LOCs to various unaffiliated counterparties and approximately $70 million to several independent system operators and unaffiliated LDCs. If such a downgrade were to occur, management believes NU would currently be able to provide this collateral, subject to the SEC limits. NU's, Moody's and S&P'S credit ratings outlooks are currently stable and management does not believe that at this time there is a significant risk of a ratings downgrade to sub-investment grade levels.

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 material services businesses. In order for discontinued operations treatment to be appropriate, management must conclude that there is a material component of a business that is "held for sale" for accounting purposes and that NU has no significant continuing involvement. As the wholesale marketing business is not a component of a business and based on the status of the sale of the services businesses, at this point in time, discontinued operations presentation is not appropriate. Management will continue to evaluate this classification in the third quarter of 2005 for all NU Enterprises’ businesses that are being exited and divested.

Other Matters

Commitments and Contingencies: For further information regarding other commitments and contingencies, see Note 6, "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 June 30, 2005, see Note 6C, "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 statemen ts include, 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, obtaining new contracts at anticipated volumes and margins, 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 d evelopments or circumstances occurring after the statement is made.

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

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 in detail below, could exacerbate other risks. These risk factors should be considered carefully in evaluating the company's risk profile.

Risks Related to Disposition of Wholesale Competitive and Services Businesses: In March 2005, NU announced the decision to exit its wholesale marketing business and divest the energy services businesses. NU Enterprises is exploring a number of alternatives for exiting these businesses. To date, however, it has disposed of a portion of the wholesale marketing business and none of the energy services businesses.

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 will be accounted for on a mark-to-market basis until disposed of or restructured. NU has recorded losses associated with this portfolio of $44.3 million after taxes during the second quarter. The combined first and second quarter earnings charge of $164.3 million associated with this portfolio in the aggregate may not be adequate to absorb future negative price movements which may occur or if further charges are taken if the portfolio is divested.

NU Enterprises is in the process of exiting the wholesale marketing business. Select Energy’s ability to function 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.

Risks Related to NU Enterprises' Retail Marketing and Merchant Generation Businesses: In March 2005, NU announced it intended to stay in the retail competitive energy and generation businesses. Select Energy generally acquires retail customer load in small increments, which while requiring careful sourcing, allows energy assets to be acquired with lower risk. While retail customers have a generally high retention rate, they normally contract for periods of one to two years, making long-term load servicing difficult to evaluate. In addition, 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.

A significant portion of Select Energy's merchant 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 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 electric ity 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 $1.5 billion in regulated electric transmission infrastructure from 2005 through 2009. Included in this amount is approximately $1.4 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 constru ction.

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.

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 Consolidated Edison, Inc. 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.

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 this Form 10-Q.

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. 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.

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 six months ended June 30, 2005:

	Income Statement Variances (Millions of Dollars) 2005 over/(under) 2004
	Second Quarter				Percent		Six Months			Percent
Operating Revenues:		$	33		2	%	$	460		14	%

Operating Expenses:
Fuel, purchased and net interchange power		25			3		473			23
Other operation		11			4		48			9
Wholesale contract market changes, net		69			100		258			100
Restructuring and impairment charges		2			100		48			100
Maintenance		7			14		7			8
Depreciation		3			5		6			6
Amortization		(4)			(14)		(10)			(18)
Amortization of rate reduction bonds		3			7		6			7
Taxes other than income taxes		-			-		(1)			-
Total operating expenses		116			8		835			27

Operating (Loss)/Income		(83)			(86)		(375)			(a)

Interest expense, net		10			16		13			10
Other Income, net		6			(a)		6			(a)
(Loss)/income before income tax expense		(87)			(a)		(382)			(a)
Income tax (benefit)/expense		(35)			(a)		(145)			(a)
Preferred dividends of subsidiary		-			-		-			-
Net (Loss)/Income		$		(52)	(a)	%	$		(237)	(a)	%

(a) Percent greater than 100.

Comparison of the Second Quarter of 2005 to the Second Quarter of 2004

Operating Revenues

Operating revenues increased $33 million in the second quarter of 2005, compared with the same period in 2004, due to higher electric distribution revenues ($141 million), higher gas distribution revenues ($16 million), and higher regulated transmission revenues ($12 million), partially offset by lower revenues from NU Enterprises ($134 million).

The electric distribution revenue increase of $141 million is primarily due to non-earnings components of CL&P, PSNH and WMECO retail rates ($131 million). The distribution component of these companies and the retail transmission component of CL&P and PSNH which flow through to earnings increased $10 million primarily due to an increase in retail rates ($7 million) and an increase in retail sales volumes ($3 million). The non-earnings components increase of $131 million is primarily due to the pass through of higher energy supply costs ($87 million), CL&P FMCC charges ($45 million), and higher wholesale revenues ($11 million), partially offset by lower CL&P conservation and load management cost recoveries ($5 million) and lower transition cost recoveries for CL&P and WMECO ($4 million).

The higher gas distribution revenue of $16 million is primarily due to the increased recovery of gas costs ($13 million).

Transmission revenues increased $12 million in the second quarter of 2005, primarily due to the incremental recovery of 2004 expenses as allowed under FERC Tariff Schedule 21, a higher transmission investment base and higher expenses.

The NU Enterprises’ revenue decrease of $134 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 that change, 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 $290 million. Additionally, revenues are lower primarily due to the wholesale marketing business ($38 million), and lower revenues from the services businesses ($14 million), partially offset by higher revenues from the merchant retail business ($51 million) and higher third party volumes ($155 million).

Fuel, Purchased and Net Interchange Power

Fuel, purchased and net interchange power expense increased $25 million in the second quarter of 2005, primarily due to higher purchased power costs for the Utility Group ($260 million), partially offset by lower wholesale costs at NU Enterprises ($235 million). The $260 million increase for the Utility Group is due to an increase for CL&P and WMECO ($228 million) resulting primarily from an increase in standard offer supply costs, which includes higher third party supplier volume ($112 million), higher expenses for PSNH ($19 million) primarily due to higher energy and capacity purchases and higher Yankee Gas expenses ($13 million) primarily due to increased gas prices.

Other Operation

Other operation expenses increased $11 million in the second quarter of 2005 primarily due to higher CL&P RMR costs and other power pool related expenses ($19 million), partially offset by lower expenses for NU Enterprises ($9 million). The lower expenses for NU Enterprises were primarily due to lower expenses at the energy services businesses.

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 $7 million in the second quarter of 2005 primarily due to higher overhead ($2 million) and underground ($1 million) line maintenance, higher substation maintenance expenses ($1 million), higher tree trimming expense ($1 million) and higher transmission expenses ($1 million).

Depreciation

Depreciation increased $3 million in the second quarter of 2005 primarily due to higher CL&P plant balances.

Amortization

Amortization decreased $4 million in the second quarter of 2005 primarily due to lower Utility Group recovery of stranded costs.

Amortization of Rate Reduction Bonds

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

Interest Expense, Net

Interest expense, net increased $10 million in the second quarter of 2005 primarily due to the issuance of $280 million of ten-year and thirty-year first mortgage bonds at CL&P in September 2004, higher interest related to the final decision on the streetlight refund docket, and higher interest rates for NU parent.

Other Income, Net

Other income, net increased $6 million in the second quarter of 2005 primarily due to higher interest and dividend income ($3 million) and a gain on the sale of land by HWP ($1 million).

Income Tax (Benefit)/Expense

Second quarter income tax expense decreased $35 million primarily due to lower income before tax expense and lower New Hampshire income taxes resulting from lower unitary taxable income.

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

Operating Revenues

Operating revenues increased $460 million in the first six months of 2005, compared with the same period in 2004, due to higher electric distribution revenues ($257 million), higher revenues from NU Enterprises ($148 million), higher gas distribution revenues ($40 million), and higher regulated transmission revenues ($17 million).

The electric distribution revenue increase of $257 million is primarily due to non-earnings components of CL&P, PSNH and WMECO retail rates ($236 million). The distribution component of these companies and the retail transmission component of CL&P and PSNH which flow through to earnings increased $21 million primarily due to an increase in retail rates ($19 million) and an increase in retail sales volumes ($1 million). The non-earnings components increase of $236 million is primarily due to the pass through of higher energy supply costs ($177 million), CL&P FMCC charges ($81 million) and higher wholesale revenues ($3 million), partially offset by lower CL&P conservation and load management cost recoveries ($12 million) and lower transition cost recoveries for CL&P and WMECO ($8 million).

The NU Enterprises’ revenue increase of $148 million is primarily due to additional third party volumes ($331 million) and higher revenues from the merchantretail energy business ($120 million), partially offset by lower revenues from the mark-to-market accounting for certain wholesale contracts related to the business to be exited ($290 million) and lower revenues from the services businesses ($15 million).

The higher gas distribution revenue of $40 million is primarily due to the increased recovery of gas costs ($33 million).

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

Fuel, Purchased and Net Interchange Power

Fuel, purchased and net interchange power expense increased $473 million in the first six months of 2005, primarily due to higher purchased power costs for the Utility Group ($552 million), partially offset by lower wholesale costs at NU Enterprises ($79 million). The $552 million increase for the Utility Group is due to an increase for CL&P and WMECO ($476 million) resulting primarily from an increase in standard offer supply costs, which includes higher third party supplier volume ($272 million), higher expenses for PSNH ($44 million) primarily due to higher energy and capacity purchases and higher Yankee Gas expenses ($33 million) primarily due to increased gas prices.

Other Operation

Other operation expenses increased $48 million in the first six months of 2005 primarily due to higher CL&P RMR costs and other power pool related expenses ($40 million) and higher expenses for NU Enterprises ($1 million).

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 $7 million in the first six months of 2005 primarily due to higher overhead ($4 million) and underground ($2 million) line maintenance.

Depreciation

Depreciation increased $6 million in the first six months of 2005 primarily due to higher CL&P plant balances.

Amortization

Amortization decreased $10 million in the first six months of 2005 primarily due to lower Utility Group recovery of stranded costs.

Amortization of Rate Reduction Bonds

Amortization of rate reduction bonds increased $6 million in the first six months of 2005 due to the repayment of a higher principal amount as compared to 2004.

Interest Expense, Net

Interest expense, net increased $13 million in the first six months of 2005 primarily due to the issuance of $280 million of ten-year and thirty-year first mortgage bonds at CL&P in September 2004, higher interest related to the final decision on the streetlight refund docket, and higher interest rates for NU parent.

Other Income, Net

Other income, net increased $6 million in the first six months of 2005 primarily due to higher interest and dividend income ($3 million) and a gain on the sale of land by HWP ($1 million).

Income Tax (Benefit)/Expense

Income tax expense decreased $145 million primarily due to lower income before tax expense.

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 Quarter 2005 Form 10-Q, the NU 2004 Form 10-K, and the current reports on Form 8-K disclosed in Part II, Item 6, "Other Information - Exhibits and Reports on Form 8-K," included in this report on Form 10-Q.

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 second quarter and the six months ended June 30, 2005:

	Income Statement Variances (Millions of Dollars) 2005 over/(under) 2004
	Second Quarter				Percent		Six Months			Percent
Operating Revenues:		$	118		17	%	$	209		15	%

Operating Expenses:
Fuel, purchased and net interchange power		95			24		162			19
Other operation		15			12		38			18
Restructuring and impairment charges		-			-		-			-
Maintenance		5			29		8			22
Depreciation		4			12		7			13
Amortization		-			-		(3)			(39)
Amortization of rate reduction bonds		2			8		4			7
Taxes other than income taxes		-			-		(2)			(3)
Total operating expenses		121			19		214			16

Operating (Loss)/Income		(3)			(7)		(5)			(4)

Interest expense, net		7			24		8			15
Other Income, net		-			-		(1)			(9)
(Loss)/income before income tax expense		(10)			(38)		(14)			(20)
Income tax (benefit)/expense		(4)			(49)		(7)			(30)
Preferred dividends of subsidiaries		-			-		-			-
Net (Loss)/Income		$		(6)	(33)	%	$		(7)	(16)	%

(a) Percent greater than 100.

Comparison of the Second Quarter of 2005 to the Second Quarter of 2004

Operating Revenues

Operating revenues increased $118 million in the second quarter of 2005, compared with the same period in 2004, due to higher distribution revenues ($111 million) and higher transmission revenues ($8 million).

The distribution revenue increase of $111 million is primarily due to the non-earnings components of retail rates ($106 million). The distribution and retail transmission components of CL&P's rates which flows through to earnings increased $7 million, primarily due to the retail rate increase effective January 1, 2005, partially offset by the additional reserve recorded to reflect the final decision on the streetlight docket ($3 million).

The non-earnings revenue components increase of $106 million is primarily due to higher TSO related revenues ($61 million), an increase in revenues associated with the recovery of FMCC charges ($45 million), and higher wholesale revenues ($9 million), partially offset by lower revenue as a result of lower retail rates for the recovery of system benefit,

conservation and load management, and renewable energy costs ($7 million). Retail sales in the second quarter of 2005 were 1.1 percent higher than the same period last year.

Fuel, Purchased and Net Interchange Power

Fuel, purchased and net interchange power expense increased $95 million in the second quarter of 2005 primarily due to higher standard offer service supply costs.

Other Operation

Other operation expenses increased $15 million in the second quarter of 2005 primarily due to higher RMR costs ($11 million) and other power pool related expenses recovered through the FMCC charge ($5 million), higher retail transmission expense charged to distribution ($4 million), partially offset by lower C&LM expenses ($4 million).

Maintenance

Maintenance expenses increased $5 million in the second quarter of 2005 due to higher expenses related to overhead and underground lines maintenance ($4 million) and higher tree trimming expenses ($1 million).

Depreciation

Depreciation expense increased $4 million in the second quarter of 2005 due to higher utility plant balances resulting from plant additions.

Amortization of Rate Reduction Bonds

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

Interest Expense, Net

Interest expense, net increased $7 million in the second quarter of 2005 due to higher interest on long-term debt as a result of new debt issued in the third quarter of 2004 ($5 million), 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 ($2 million).

Income Tax Expense

Income tax expense decreased $4 million in the second quarter of 2005 primarily due to lower book taxable income and a lower effective tax rate. The effective tax rate decreased from 29.4 percent to 24.0 percent primarily due to a greater favorable flow through adjustment for plant related items.

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

Operating Revenues

Operating revenues increased $209 million in the first six months of 2005, compared with the same period in 2004, due to higher distribution revenues ($198 million) and higher transmission revenues ($11 million).

The distribution revenue increase of $198 million is primarily due to the non-earnings components of retail rates ($186 million). The distribution and retail transmission components of CL&P's rates which flows through to earnings increased $15 million, primarily due to the retail rate increase effective January 1, 2005, partially offset by the additional reserve recorded to reflect the final decision on the streetlight docket ($3 million).

The non-earnings revenue components increase of $186 million is primarily due to higher TSO related revenues ($125 million) and an increase in revenues associated with the recovery of FMCC charges ($81 million), partially offset by lower revenues as a result of lower retail rates for the recovery of system benefit, conservation and load management, and renewable energy costs ($15 million) and lower wholesale revenue ($3 million). Retail sales for the first six months of 2005 were 0.2 percent higher than the same period last year.

Fuel, Purchased and Net Interchange Power

Fuel, purchased and net interchange power expense increased $162 million in the first six months of 2005 primarily due to higher standard offer service supply costs.

Other Operation

Other operation expenses increased $38 million in the first six months of 2005 primarily due to higher RMR costs ($28 million) and other power pool related expenses recovered through the FMCC charge ($9 million), and higher retail transmission expense charged to distribution ($4 million).

Maintenance

Maintenance expenses increased $8 million in the first six months of 2005 due to higher expenses related to overhead and underground lines maintenance.

Depreciation

Depreciation expense increased $7 million in the first six months of 2005 due to higher utility plant balances resulting from plant additions.

Amortization of Regulatory Liabilities

Amortization of regulatory liabilities decreased $3 million in the first six months of 2005 primarily due to lower amortization related to the recovery of transition charges.

Amortization of Rate Reduction Bonds

Amortization of rate reduction bonds increased $4 million in the first six months of 2005 due to the repayment of additional principal.

Taxes Other Than Income Taxes

Taxes other than income taxes decreased $2 million in the first six months of 2005 due to lower taxes paid in 2005 to the Town of Waterford for lost property tax revenue as a result of the sale of Millstone.

Interest Expense, Net

Interest expense, net increased $8 million in the first six months of 2005 due to higher interest on long-term debt as a result of new debt issued in the third quarter of 2004 ($8 million), 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 ($4 million).

Other Income, Net

Other income, net decreased $1 million in the first six months of 2005 primarily due to the 2004 reversal of a Seabrook reserve.

Income Tax Expense

Income tax expense decreased $7 million in the first six months of 2005 primarily due to lower book taxable income and a lower effective tax rate. The effective tax rate decreased from 32.6 percent to 28.7 percent primarily due to a greater favorable flow through adjustment for plant related items.

LIQUIDITY

Net cash flows from operations decreased by $117.5 million from net cash flows provided by operating activities of $155.2 million for the first half of 2004 to $37.7 million for the first half of 2005. The 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 and accounts payable. 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. Investments in securitizable assets, when combined with receivables and unbilled revenues, increased in part due to CL&P rate increases in the first half of 2005 for TSO and FMCC charges.

CL&P's capital expenditures totaled $181.7 million in the first six months of 2005, compared with $204.2 million in the first six months of 2004. CL&P projects capital expenditures to total $420 million in 2005.

On May 27, 2005, S&P downgraded all rated securities for CL&P by one notch. The downgrade did not result in a material increase in borrowing costs or other negative factors. All S&P ratings for CL&P are now stable.

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 Quarter 2005 Form 10-Q, the NU 2004 Form 10-K, and the current reports on Form 8-K disclosed in Part II, Item 6, "Other Information - Exhibits and Reports on Form 8-K," included in this report on Form 10-Q.

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 second quarter and the six months ended June 30, 2005:

	Income Statement Variances (Millions of Dollars) 2005 over/(under) 2004
	Second Quarter				Percent		Six Months			Percent
Operating Revenues:		$	33		15	%	$	58		12	%

Operating Expenses:
Fuel, purchased and net interchange power		22			22		47			23
Other operation		5			11		8			11
Restructuring and impairment charges		-			-		-			-
Maintenance		-			-		(2)			(6)
Depreciation		-			-		-			-
Amortization		1			9		5			12
Amortization of rate reduction bonds		1			7		1			7
Taxes other than income taxes		-			-		-			-
Total operating expenses		29			14		59			14

Operating Income/(Loss)		4			21		(1)			(3)

Interest expense, net		1			7		1			4
Other Income, net		1			67		1			59
Income/(loss) before income tax expense		4			45		(1)			(4)
Income tax expense/(benefit)		1			32		(1)			(14)
Preferred dividends of subsidiaries		-			-		-			-
Net Income		$		3	50	%	$		-	-	%

Comparison of the Second Quarter of 2005 to the Second Quarter of 2004

Operating Revenues

Operating revenues increased $33 million in the second quarter of 2005, as compared to the same period in 2004, primarily due to higher distribution retail revenue ($29 million), higher transmission revenue ($3 million) and higher wholesale revenue ($1 million). The distribution retail revenue increase of $29 million is primarily due to a non-earnings component of retail rates. The transition service energy component of retail revenues increased by $23 million primarily due to an increase in the rate in 2005 as compared to 2004 ($21 million). The distribution and transmission components of PSNH's retail rates which flow through to earnings increased $4 million due to the retail rate increases effective October 1, 2004 and June 1, 2005 ($2 million) and higher sales ($2 million). Retail sales increased 3.9 percent in 2005.

Fuel, Purchased and Net Interchange Power

Fuel, purchased and net interchange power increased $22 million primarily due to the higher cost of energy as a result of higher fuel prices.

Other Operation

Other operation expenses increased $5 million as a result of higher power pool related expenses ($3 million) and higher administrative expenses primarily due to higher pension and other benefit costs ($2 million).

Amortization of Regulatory Assets, Net

Amortization of regulatory assets, net increased $1 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.

Interest Expense

Interest expense increased $1 million in 2005 primarily due to the issuance of $50 million of ten-year first mortgage bonds in July 2004.

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 second quarter of 2005 primarily due to higher book taxable income, partially offset by a lower effective tax rate. The effective tax rate decreased from 30.8 percent to 28.1 percent primarily due to a decrease in state income taxes resulting from lower unitary taxable income.

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

Operating Revenues

Operating revenues increased $58 million in the first six months of 2005, as compared to the same period in 2004, primarily due to higher distribution retail revenue ($48 million), higher transmission revenue ($5 million) and higher wholesale revenue ($5 million). The distribution retail revenue increase of $48 million is primarily due to a non-earnings component of retail rates. The transition service energy component of retail revenues increased by $44 million primarily due to an increase in the rate in 2005 as compared to 2004 ($40 million). The distribution and transmission components of PSNH's retail rates which flow through to earnings increased $4 million due to the retail rate increases effective October 1, 2004 and June 1, 2005 ($3 million) and higher sales ($1 million). Retail sales increased 0.4 percent in 2005.

Fuel, Purchased and Net Interchange Power

Fuel, purchased and net interchange power increased $47 million primarily due to the higher cost of energy as a result of higher fuel prices.

Other Operation

Other operation expenses increased $8 million as a result of higher administrative expenses primarily due to higher pension and other benefit costs ($4 million) and higher power pool related expenses ($3 million).

Maintenance

Maintenance expense decreased $2 million in 2005 primarily due to lower overhead line maintenance ($2 million).

Amortization of Regulatory Assets, Net

Amortization of regulatory assets, net increased $5 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.

Interest Expense

Interest expense increased $1 million in 2005 primarily due to the issuance of $50 million of ten-year first mortgage bonds in July 2004.

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 decreased $1 million in the first six months of 2005 primarily due to lower book taxable income and a lower effective tax rate. The effective tax rate decreased from 34.5 percent to 31.2 percent primarily due to a decrease in state income taxes resulting from lower unitary taxable income.

LIQUIDITY

Net cash flows from operations decreased by $6 million from $91.2 million for the first half of 2004 to $85.2 million for the first half of 2005. The decrease in operating cash flows is due to changes in working capital items, primarily receivables and unbilled revenues.

PSNH's capital expenditures totaled $89.7 million in the first six months of 2005, compared with $60.5 million in the first six months of 2004. PSNH projects capital expenditures to total $150 million in 2005.

On May 27, 2005, S&P downgraded all rated securities for PSNH by one notch. The downgrade did not result in a material increase in borrowing costs or other negative factors. All S&P ratings for PSNH are now stable.

An application for PSNH to issue $50 million of first mortgage bonds later in 2005 is pending with the NHPUC.

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 Quarter 2005 Form 10-Q, the NU 2004 Form 10-K, and the current reports on Form 8-K disclosed in Part II, Item 6, "Other Information - Exhibits and Reports on Form 8-K," included in this report on Form 10-Q.

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 second quarter and the six months ended June 30, 2005:

	Income Statement Variances (Millions of Dollars) 2005 over/(under) 2004
	Second Quarter				Percent		Six Months			Percent
Operating Revenues:		$	1		1	%	$	8		4	%

Operating Expenses:
Fuel, purchased and net interchange power		5			10		11			10
Other operation		3			20		5			17
Restructuring and impairment charges		-			-		-			-
Maintenance		-			-		1			13
Depreciation		-			-		1			9
Amortization		(5)			(a)		(11)			(a)
Amortization of rate reduction bonds		-			-		-			-
Taxes other than income taxes		-			-		-			-
Total operating expenses		3			4		7			4
							��
Operating (Loss)/Income		(2)			(18)		1			4

Interest expense, net		1			18		1			17
Other Income, net		1			(a)		1			(a)
(Loss)/income before income tax expense		(2)			(31)		1			5
Income tax (benefit)/expense		(1)			(28)		1			12
Preferred dividends of subsidiaries		0			0		0			0
Net (Loss)/Income		$		(1)	(34)	%	$		-	-	%

(a) Percent greater than 100.

Comparison of the Second Quarter of 2005 to the Second Quarter of 2004

Operating Revenues

Operating revenues increased $1 million in the second quarter of 2005, as compared to the same period in 2004, primarily due to higher wholesale transmission revenues.

Fuel, Purchased and Net Interchange Power

Fuel, purchased and net interchange power expense increased $5 million in the second quarter of 2005 due to higher purchased power costs ($3 million) and higher default service supply costs ($2 million).

Other Operation

Other operation expenses increased $3 million in the second quarter of 2005 due to higher administrative and general expense ($2 million) primarily due to lower pension income.

Amortization of Regulatory (Liabilities)/Assets, Net

Amortization of regulatory (liabilities)/assets, net decreased $5 million in the second 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.

Interest Expense, Net

Interest expense, net increased $1 million in the second quarter of 2005 primarily due to higher long-term debt levels as a result of new debt issued in the third quarter of 2004.

Other Income, Net

Other income, net increased $1 million in the second quarter of 2005 primarily due to the 2004 interest payment related to and IRS settlement.

Income Tax Expense

Income tax expense decreased $0.7 million in the second quarter of 2005 primarily due to lower book taxable income.

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

Operating Revenues

Operating revenues increased $8 million in the first six months of 2005, as compared to the same period in 2004, primarily due to higher default service revenues ($8 million), higher delivery revenues ($2 million), and higher retail transmission revenues ($3 million) and higher wholesale transmission revenues ($2 million), partially offset by lower transition charge revenues ($7 million). Retail sales were 1.9 percent lower than the same period last year.

Fuel, Purchased and Net Interchange Power

Fuel, purchased and net interchange power expense increased $11 million in the first six months of 2005 due to higher default service supply costs ($7 million) and higher purchased power costs ($4 million).

Other Operation

Other operation expenses increased $5 million in the first six months of 2005 due to higher administrative and general expense ($3 million) primarily due to lower pension income and higher retail transmission expenses ($1 million).

Maintenance

Maintenance expense increased $1 million in the first six months of 2005 primarily due to higher tree trimming expenses and higher overhead and underground lines maintenance expenses.

Depreciation

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

Amortization of Regulatory (Liabilities)/Assets, Net

Amortization of regulatory (liabilities)/assets, net decreased $11 million in the first six 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.

Interest Expense, Net

Interest expense, net increased $1 million in the first six months of 2005 primarily due to higher long-term debt levels as a result of new debt issued in the third quarter of 2004.

Other Income, Net

Other income, net increased $1 million in the first six months of 2005 primarily due to the 2004 interest payment related to and IRS settlement.

Income Tax Expense

Income tax expense increased $0.6 million in the first six months of 2005 primarily due to higher book taxable income and a higher effective tax rate. The effective tax rate increased from 41.0 percent to 43.9 percent primarily due to a greater unfavorable flow through adjustment for allowance for doubtful accounts.

LIQUIDITY

Net cash flows from operations decreased by $16.4 million from $35.5 million for the first half of 2004 to $19.1 million for the first half of 2005. The decrease in operating cash flows is due to lower amortization of regulatory assets and changes in working capital items, including accounts payable and accrued taxes.

WMECO's capital expenditures totaled $20.9 million in the first six months of 2005, compared with $17 million in the first six months of 2004. WMECO projects capital expenditures to total $40 million in 2005.

On May 27, 2005, S&P downgraded all rated securities for WMECO by one notch. The downgrade did not result in a material increase in borrowing costs or other negative factors. All S&P ratings for WMECO are now stable.

WMECO is expected to issue a separate $50 million of senior unsecured notes in August 2005. The issuance was approved on June 9, 2005 by the DTE.

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 and Generation Portfolios: When conducting sensitivity analyses of the change in the fair value of Select Energy's electricity, natural gas and oil on the retail marketing and generation portfolios, which would result from a hypothetical change in the future market price of electricity, natural gas and oil, the fair values of the contracts are determined from models that take into consideration estimated future market prices of electricity, natural gas and oil, 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 and generation portfolios, which includes cash flow and fair value hedges and electricity, natural gas and oil contracts, assuming a 10 percent change in forward market prices. At June 30, 2005, a 10 percent increase in market price would have resulted in a pre-tax increase in fair value of $150.5 million ($94.8 million after-tax) and a 10 percent decrease would have resulted in a pre-tax decrease in fair value of $148.2 million ($93.4 million after-tax).

The impact of a change in electricity, natural gas and oil prices on Select Energy's wholesale and retail marketing portfolio at June 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 and generation portfolios 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 June 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 $76.6 million ($48.4 million after-tax) and a 10 percent decrease would have resulted in a pre-tax increase in fair value of $75.6 million ($47.6 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 June 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.

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 June 30, 2005, approximately 87 percent (78 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 June 30, 2005, NU parent maintained a fixed-to-floating interest rate swap to manage the interest rate risk associated with i ts $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. These risk management policies are being revised in light of NU Enterprises change in focus from wholesale marketing to retail marketing and merchant generation.

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 pos itively or negatively, in that the counterparties may be similarly affected by changes to economic, regulatory or other conditions.

At June 30, 2005 and December 31, 2004, Select Energy maintained collateral balances from counterparties of $102.2million 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 $82.2 million and $46.3 million at June 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.

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.

ITEM 4.

CONTROLS AND PROCEDURES

NU evaluated the design and operation of their disclosure controls and procedures at June 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 officers 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 time periods specified in SEC rules and forms and ii) is accumulated and communicated to management, including the p rincipal executive officers and principal financial officer, as appropriate to allow timely decisions regarding required disclosure.

There have been no significant changes in NU's internal controls over financial reporting during the quarter ended June 30, 2005 that have materially affected, or are reasonably likely to materially affect NU's internal control over financial reporting.

PART II. OTHER INFORMATION

ITEM 1.

LEGAL PROCEEDINGS

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

The Second Circuit Court of Appeals heard arguments on June 8, 2005 on two issues certified to it by the United States District Court for the Southern District of New York in the Rimkoski phase of the proceeding. A ruling is pending.

For further information on this litigation and related matters, see Part I, Item 3, "Legal Proceedings" in NU's 2004 Form 10-K.

Northern Wood Power Project

In August 2003, PSNH sought the approval of the NHPUC to modify one of its older 50 megawatt coal-fired generating stations, Unit 5 at Schiller Station in Portsmouth (Northern Wood Power Project), to a technologically advanced fluidized bed boiler capable of burning wood, with the plan to burn locally sourced low-grade wood fuel. This project would qualify Schiller Unit 5 to receive revenues from the sale of renewable energy certificates necessary to fulfill renewable portfolio standard requirements in various New England states. In May 2004, the NHPUC approved the Northern Wood Power Project and a risk/reward cost-recovery mechanism jointly offered by PSNH, the New Hampshire Governor’s Office of Energy and Planning, the New Hampshire Office of Consumer Advocate, and the New Hampshire Timberland Owners’ Association. Ground-breaking for the Project took place on October 15, 2004. The NHPUC’s orders approving this Norther n Wood Power Project were appealed to the New Hampshire Supreme Court (Supreme Court) by four existing wood-fired generating plants. On April 4, 2005, the Supreme Court rejected the appeal and affirmed the NHPUC's approval order. Construction is expected to be completed in late-summer 2006.

Hawkins, Delafield & Wood (Hawkins) v. NU, NUSCO and CL&P

On December 12, 2002, Hawkins, a New York law firm sued by the Connecticut Resources Recovery Authority (CRRA) as a result of the Enron bankruptcy brought an apportionment complaint against a number of former Enron officers, directors and outside accountants. In addition to the Enron defendants, Hawkins also named as defendants in its complaint NU, NUSCO and CL&P. Hawkins asserts in its complaint that in the event it is found liable to CRRA, then the apportionment defendants, including NU, NUSCO and CL&P, are responsible for some or all of the $220 million claimed as damages.

On February 16, 2005, the United States District Court for the Southern District of Texas (the court to which the case was transferred after Hawkins removed it from the Connecticut Superior Court to Federal Court) entered an order striking the apportionment complaint with prejudice and remanding the case to the Waterbury Superior Court. Subsequently, Hawkins appealed the February 16, 2005 order to the United States District Court of Appeals for the Fifth Circuit.

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 June 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 (April 1, 2005 to April 30, 2005)	96	$19.38	- -	N/A
Month #2 (May 1, 2005 to May 31, 2005)	- -	N/A	- -	N/A
Month #3 (June 1, 2005 to June 30, 2005)	- -	N/A	- -	N/A
Total	96	$19.38	-	N/A

(1) Purchases were made in open market transactions related to a compensation plan for certain management employees.

ITEM 4.

SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

At the Annual Meeting of Shareholders of NU held on May 10, 2005 the following ten nominees were elected to serve on the Board of Trustees by the votes set forth below:

		For	Withheld	Total
1.	Richard H. Booth	108,322,742	2,076,903	110,399,645
2.	Cotton M. Cleveland	99,429,663	10,969,982	110,399,645
3.	Sanford Cloud, Jr.	108,310,108	2,089,537	110,399,645
4.	James F. Cordes	108,367,023	2,032,622	110,399,645
5.	E. Gail de Planque	108,331,579	2,068,066	110,399,645
6.	John G. Graham	108,313,606	2,086,039	110,399,645
7.	Elizabeth T. Kennan	105,748,516	4,651,129	110,399,645
8.	Robert E. Patricelli	105,813,156	4,586,489	110,399,645
9.	Charles W. Shivery	105,726,635	4,673,010	110,399,645
10.	John F. Swope	105,768,575	4,631,070	110,399,645

NU's shareholders also ratified the Board of Trustees' selection of Deloitte & Touche LLP to serve as independent auditors of NU and its subsidiaries for 2005. The vote ratifying such selection was 109,234,682 votes in favor and 690,711 votes against, and 474,252 abstentions.

NU's shareholders also voted to amend the Declaration of Trust of Northeast Utilities to allow for the optional electronic delivery of notices to shareholders, including electronic delivery of proxy materials, and to clarify the wording in the Declaration of Trust that allows electronic voting by shareholders. The vote approving such amendment was 107,637,047 votes in favor, 1,749,935 votes against, and 1,012,663 abstentions.

CL&P. In a written Consent in Lieu of an Annual Meeting of Stockholders of CL&P dated June 30, 2005, stockholders voted to fix the number of directors for the ensuing year at three and the following three directors were elected, to serve on the Board of Directors for the ensuing year: Cheryl W. Grisé, Raymond P. Necci and Leon J. Olivier. The vote on each of these proposals was 6,035,205 shares in favor, representing 100 percent of the issued and outstanding shares of common stock of CL&P.

WMECO. In a written Consent in Lieu of an Annual Meeting of Stockholders of WMECO dated June 30, 2005 ("WMECO Consent"), stockholders voted to fix the number of directors for the ensuing year at four and the following four directors were elected, to serve on the Board of Directors for the ensuing year: Cheryl W. Grisé, David R. McHale, Leon J. Olivier and Rodney O. Powell. In the WMECO Consent, stockholders also voted to elect Randy A. Shoop as Vice President and Treasurer and O. Kay Comendul as Secretary and Clerk for the ensuing year. The vote on each of these proposals was 434,653 shares in favor, representing 100 percent of the issued and outstanding shares of common stock of WMECO.

PSNH. In a written Consent in Lieu of an Annual Meeting of Stockholders of PSNH dated June 30, 2005 ("PSNH Consent"), stockholders voted to amend the By-Laws, effective June 30, 2005, to specify that the Board of Directors may consist of one or more individuals and to clarify that one-third of the Board then in office shall constitute a quorum of the transaction of business at any meeting of the Board. In the PSNH Consent, stockholders also voted to fix the number of directors for the ensuing year at four and the following four directors were elected, to serve on the Board of Directors for the ensuing year: Cheryl W. Grisé, Gary A. Long, David R. McHale and Leon J. Olivier. The vote on each of these proposals was 301 shares in favor, representing 100 percent of the issued and outstanding shares of common stock of PSNH.

ITEM 6.

EXHIBITS AND REPORTS ON FORM 8-K

(a)

Listing of Exhibits (NU)

Exhibit No.

Description

3.1

Declaration of Trust of NU, as amended through May 10, 2005 (Exhibit A.1, NU Form U-1 dated June 23, 2005, File No. 70-10315).

*10.5.8

Eighth Supplemental Indenture and Deed of Trust dated July 1, 2005 between Yankee Gas Services Company and The Bank of New York, as Successor Trustee to Fleet Bank (formerly the Connecticut National Bank.

Deloitte & Touche LLP Letter Regarding Unaudited Financial Information

Certification of Charles W. Shivery, Chairman, President and Chief Executive Officer of Northeast Utilities, required by Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated August 8, 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 August 8, 2005

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 August 8, 2005

(a)

Listing of Exhibits (CL&P)

*4.12.3

Amendment No. 4 to the Amended and Restated Receivables Purchase and Sales Agreement dated as of July 7, 2004.

*4.12.4

Amendment No. 5 to the Amended and Restated Receivables Purchase and Sales Agreement dated as of July 7, 2005.

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 August 8, 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 August 8, 2005

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 August 8, 2005

(a)

Listing of Exhibits (PSNH)

3.2

By Laws of PSNH, as in effect June 30, 2005.

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 August 8, 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 August 8, 2005

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 August 8, 2005

(a)

Listing of Exhibits (WMECO)

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 August 8, 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 August 8, 2005

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 August 8, 2005

(b)

Reports on Form 8-K:

NU, CL&P, PSNH and WMECO filed a current report on Form 8-K dated April 28, 2005 disclosing:

NU’s financial results for the first quarter 2005 and three months ended March 31, 2005

NU, CL&P, PSNH and WMECO filed a current report on Form 8-K dated July 26, 2005 disclosing:

NU's financial results for the second quarter of 2005 and the six months ended June 30, 2005

SIGNATURE

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

		NORTHEAST UTILITIES
		Registrant
Date: August 8, 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: August 8, 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.

		PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE
		Registrant
Date: August 8, 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: August 8, 2005	By	/s/ David R. McHale
		David R. McHale
		Senior Vice President and Chief Financial Officer
		(for the Registrant and as Principal Financial Officer)

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The Connecticut Light and Power Company (CNLTN) 10-Q2005 Q2 Quarterly report

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