Eversource Energy 8K Results of Operations and Financial Condition | ES 22 Nov 05

Exhibit 99.2

EXPLANATORY NOTE

On November 7, 2005, Northeast Utilities (NU) reported discontinued operations in its report on Form 10-Q for the quarter ended September 30, 2005 as a result of meeting certain accounting criteria requiring this presentation. NU presented in its third quarter 2005 report on Form 10-Q the operating results of the following companies as discontinued operations:

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

Select Energy Contracting, Inc. - New Hampshire (including Reeds Ferry Supply Co., Inc.), a division of Select Energy Contracting, Inc.;

Woods Network Services, Inc.; and

Woods Electrical Co., Inc.

As a result of these discontinued operations and the requirement to present discontinued operations in prior period financial statements, NU is filing Exhibit 99.2 to this report on Form 8-K to conform certain financial information presented in its first quarter 2005 report on Form 10-Q to the presentation of the discontinued operations in its third quarter 2005 report on Form 10-Q. Accordingly, Exhibit 99.2 contains the complete text of Part I, Items 1 and 2, as amended. Unaffected items in the first quarter 2005 report on Form 10-Q have not been repeated in this exhibit.

Part 1.

Financial Information

Item 1.

Financial Statements

NORTHEAST UTILITIES AND SUBSIDIARIES

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

Current Assets:
Cash and cash equivalents	$ 74,021	$ 46,989
Special deposits	48,751	82,584
Investments in securitizable assets	189,679	139,391
Receivables, less provision for uncollectible
accounts of $28,754 in 2005 and $25,325 in 2004	833,321	771,257
Unbilled revenues	145,540	144,438
Taxes receivable	21,871	61,420
Fuel, materials and supplies, at average cost	143,239	185,180
Derivative assets – current	390,723	81,567
Prepayments and other	130,984	154,395
	1,978,129	1,667,221

Property, Plant and Equipment:
Electric utility	5,983,995	5,918,539
Gas utility	795,000	786,545
Competitive energy	909,202	918,183
Other	242,864	241,190
	7,931,061	7,864,457
Less: Accumulated depreciation	2,413,986	2,382,927
	5,517,075	5,481,530
Construction work in progress	437,196	382,631
	5,954,271	5,864,161

Deferred Debits and Other Assets:
Regulatory assets	2,668,010	2,745,874
Goodwill	290,791	319,986
Purchased intangible assets, net	2,817	19,361
Prepaid pension	342,550	352,750
Prior spent nuclear fuel trust, at fair value	49,555	49,296
Derivative assets - long-term	377,498	198,769
Other	415,365	438,416
	4,146,586	4,124,452

Total Assets	$ 12,078,986	$ 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)
	March 31,		December 31,
	2005		2004
	(Thousands of Dollars)
LIABILITIES AND CAPITALIZATION

Current Liabilities:
Notes payable to banks	$ 267,000	$ 180,000
Long-term debt - current portion	84,157	90,759
Accounts payable	873,600	825,247
Accrued taxes	3,655	-
Accrued interest	58,580	49,449
Derivative liabilities – current	371,767	130,275
Counterparty deposits	95,648	57,650
Other	197,892	230,022
	1,952,299	1,563,402

Rate Reduction Bonds	1,496,152	1,546,490

Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	1,348,216	1,434,403
Accumulated deferred investment tax credits	98,203	99,124
Deferred contractual obligations	393,178	413,056
Regulatory liabilities	1,130,671	1,069,842
Derivative liabilities - long-term	325,500	58,737
Other	264,046	267,895
	3,559,814	3,343,057

Capitalization:
Long-Term Debt	2,783,144	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; 151,463,375 shares issued
and 129,367,389 shares outstanding in 2005 and
151,230,981 shares issued and 129,034,442 shares
outstanding in 2004	757,317	756,155
Capital surplus, paid in	1,118,944	1,116,106
Deferred contribution plan - employee stock ownership plan	(56,916)	(60,547)
Retained earnings	706,619	845,343
Accumulated other comprehensive income/(loss)	5,494	(1,220)
Treasury stock, 19,636,364 shares in 2005
and 19,580,065 shares in 2004	(360,081)	(359,126)
Common Shareholders' Equity	2,171,377	2,296,711
Total Capitalization	5,070,721	5,202,885

Commitments and Contingencies (Note 5)

Total Liabilities and Capitalization	$ 12,078,986	$ 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
	March 31,
	2005	2004
	(Thousands of Dollars,
	except share information)


Operating Revenues	$ 2,233,265	$ 1,799,291

Operating Expenses:
Operation -
Fuel, purchased and net interchange power	1,625,694	1,177,312
Other	243,482	204,030
Wholesale contract market changes, net	188,892	-
Restructuring and impairment charges	21,534	-
Maintenance	41,669	41,780
Depreciation	57,834	54,387
Amortization	23,093	29,291
Amortization of rate reduction bonds	45,790	42,999
Taxes other than income taxes	76,856	77,301
Total operating expenses	2,324,844	1,627,100
Operating (Loss)/Income	(91,579)	172,191

Interest Expense:
Interest on long-term debt	38,449	32,738
Interest on rate reduction bonds	23,038	25,695
Other interest	3,117	2,169
Interest expense, net	64,604	60,602
Other Income, Net	679	353
(Loss)/Income from Continuing Operations Before Income Tax (Benefit)/Expense	(155,504)	111,942
Income Tax (Benefit)/Expense	(56,405)	42,884
(Loss)/Income from Continuing Operations Before Preferred Dividends of Subsidiary	(99,099)	69,058
Preferred Dividends of Subsidiary	1,390	1,390
(Loss)/Income from Continuing Operations	(100,489)	67,668
Discontinued Operations:
Loss from Discontinued Operations Before Income Taxes	(28,177)	(247)
Income Tax Benefit	(10,947)	(21)
Loss from Discontinued Operations	(17,230)	(226)
Net (Loss)/Income	$ (117,719)	$ 67,442

Basic and Fully Diluted (Loss)/Earnings Per Common Share:
(Loss)/Income from Continuing Operations	$ (0.78)	$ 0.53
Loss from Discontinued Operations	(0.13)	-
Net (Loss)/Income	$ (0.91)	$ 0.53

Basic Common Shares Outstanding (average)	129,278,505	127,879,766

Fully Diluted Common Shares Outstanding (average)	129,278,505	128,061,086


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

NORTHEAST UTILITIES AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
	Three Months Ended
	March 31,
		2004
	2005	(Restated)*
	(Thousands of Dollars)
Operating Activities:
Net (loss)/income	$ (117,719)	$ 67,442
Adjustments to reconcile to net cash flows
provided by operating activities:
Non-cash after-tax restructuring and impairment charges	141,150	-
Bad debt expense	9,029	5,795
Depreciation	57,998	54,573
Deferred income taxes and investment tax credits, net	(16,306)	20,028
Amortization	23,093	29,291
Amortization of rate reduction bonds	45,790	42,999
Amortization of recoverable energy costs	1,094	10,189
Pension expense	8,030	2,659
Regulatory overrecoveries	(26,256)	13,669
Derivative assets	(43,820)	(1,152)
Derivative liabilities	27,344	(20,372)
Other sources of cash	12,988	9,885
Other uses of cash	(28,963)	(44,075)
Changes in current assets and liabilities:
Restricted cash - LMP costs	-	(30,051)
Receivables and unbilled revenues, net	(72,195)	(19,520)
Fuel, materials and supplies	41,941	31,589
Investments in securitizable assets	(50,288)	(20,356)
Other current assets	92,112	18,583
Accounts payable	64,701	118,834
Accrued taxes	3,655	14,594
Other current liabilities	15,076	22,693
Net cash flows provided by operating activities	188,454	327,297

Investing Activities:
Investments in property and plant:
Electric, gas and other utility plant	(161,060)	(142,840)
Competitive energy assets	(5,760)	(5,776)
Cash flows used for investments in property and plant	(166,820)	(148,616)
Other investment activities	(6,036)	6,087
Net cash flows used in investing activities	(172,856)	(142,529)

Financing Activities:
Issuance of common shares	3,984	2,522
Issuance of long-term debt	-	82,438
Retirement of rate reduction bonds	(50,338)	(47,460)
Increase/(decrease) in short-term debt	87,000	(95,000)
Reacquisitions and retirements of long-term debt	(9,121)	(6,405)
Cash dividends on common shares	(21,005)	(19,177)
Other financing activities	914	(1,153)
Net cash flows provided by/(used in) financing activities	11,434	(84,235)
Net increase in cash and cash equivalents	27,032	100,533
Cash and cash equivalents - beginning of period	46,989	43,372
Cash and cash equivalents - end of period	$ 74,021	$ 143,905



* See Note 11.

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

NORTHEAST UTILITIES AND SUBSIDIARIES

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 report on Form 10-Q and the Annual Report 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," included in NU’s original report on Form 10-Q. The condensed consolidated financial statements contain, in the opinion of management, all adjustments necessary to present fairly NU's and the above companies' financial position at March 31, 2005, and the results of operations and cash flows for the three-month periods ended March 31, 2005 and 2004. All adjustments are of a normal, recurring nature except those described i n Notes 1B and 2. The results of operations and statements of cash flows for the three-month periods ended March 31, 2005 and 2004, are not 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.

NU's condensed consolidated statements of (loss)/income for the three months ended March 31, 2005 and 2004 have been reclassified to present the operations for the following companies as discontinued operations as a result of meeting certain criteria in the third quarter of 2005 requiring this presentation:

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

Select Energy Contracting, Inc. - New Hampshire (including Reeds Ferry Supply Co., Inc.) (SECI-NH), a division of Select Energy Contracting, Inc (SECI);

Woods Network Services, Inc. (Woods Network); and

Woods Electrical Co., Inc. (Woods Electrical).

For further information regarding these companies, see Note 12, "Subsequent Events," to the condensed consolidated financial statements. NU's condensed consolidated balance sheets were not impacted by this revision.

Restructuring and impairment charges which were originally presented in NU's condensed consolidated statements of (loss)/income in the first quarter report on Form 10-Q totaling $234.4 million have been reclassified to conform to the presentation of wholesale contract market changes, net separate from restructuring and impairment charges. These amounts after the reclassification totaled $188.9 million related to wholesale contract market changes, net and $45.5 million related to restructuring and impairment charges, $24 million of which is included in discontinued operations. For further information regarding this reclassification, see Note 2, "Wholesale Contract Market Changes and Restructuring and Impairment Charges," to the condensed consolidated financial statements.

New Accounting Standards

Asset Retirement Obligations:In June 2001, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (SFAS) No. 143, "Accounting for Asset Retirement Obligations." This statement requires that legal obligations associated with the retirement of property, plant and equipment 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. SFAS No. 143 was effective on January 1, 2003 for NU. Management has completed its review process for potential asset retirement obligations (ARO) and has not identified any material AROs that have been incurred. However, management has identified certain removal obligations that arise in the ordinary course of business or have a low probability of occurring. These types of obligations primarily relate to transmission and distribution lines and poles, telecommuni cation towers, transmission cables, and certain Federal Energy Regulatory Commission (FERC) or state regulatory agency re-licensing issues. These obligations are AROs that have not been incurred or are not material in nature.

On March 30, 2005, the FASB issued FASB Interpretation No. (FIN) 47, "Accounting for Conditional Asset Retirement Obligations." FIN 47 requires an entity to recognize a liability for the fair value of an ARO that is conditional on a future event if the liability’s fair value can be reasonably estimated. FIN 47 is effective for NU no later than December 31, 2005. Management is currently evaluating the impact of FIN 47 on NU.

Share-Based Payments:On December 16, 2004, the FASB issued SFAS No. 123 (Revised 2004), "Share-Based Payments," (SFAS No. 123R), which amended SFAS No. 123, "Accounting for Stock-Based Compensation." SFAS No. 123R requires all companies to recognize compensation expense in an amount equal to the fair value of share-based payments granted to employees. NU will recognize compensation expense for the unvested portion of previously granted awards that remain outstanding at the effective date of SFAS No. 123R, and any new awards after that date.

On April 14, 2005, the Securities and Exchange Commission (SEC) announced the adoption of a rule that deferred the required effective date of SFAS No 123R until January 1, 2006 for calendar year companies, including NU. 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.

Guarantees

NU provides credit assurance 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. 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 March 31, 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 $984 million. A majority of these guarantees do not have established expiration dates. Additionally, NU had $106.4 million of LOCs issued, of which $91.4 million were issued for the benefit of NU Enterprises at March 31, 2005.

At March 31, 2005, NU had outstanding guarantees on behalf of the Utility Group and Rocky River Realty (RRR) of $12.4 million and $11.3 million, respectively. These amounts are included in the total outstanding NU guarantee exposure amount of $984 million. The remaining guarantee amount of $960.3 million is related to NU Enterprises, of which $265.6 million relates to the energy services business. The guarantees related to the energy services businesses totaled $92.6 million and were comprised of guarantees of SESI’s debt obligations and $173 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 SEC to provide up to $750 million of guarantees for NU Enterprises through June 30, 2007. The $12.4 million in 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 March 31, 2005 is $516.1 million. The amount of guarantees outstanding for compliance with the SEC limit for the Utility Group at March 31, 2005 is $0.2 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 parent. The amount of guarantees outstanding for compliance with the SEC limit under this category at March 31, 2005 is $0.2 million.

Regulatory Accounting

The accounting policies of NU's 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 NU's Utility Group companies will recover their 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 March 31, 2005
(Millions of Dollars)	NU Consolidated	CL&P	PSNH		WMECO
Recoverable nuclear costs	$ 50.0	$ -		$ 28.8	$ 21.2
Securitized assets	1,503.4	974.6		410.1	118.7
Income taxes, net	299.2	193.8		36.0	54.7
Unrecovered contractual obligations	341.6	205.6		62.7	73.3
Recoverable energy costs	266.0	75.1		189.1	1.8
Other regulatory assets/(overrecoveries)	207.8	60.6		146.9	(45.2)
Totals	$2,668.0	$1,509.7		$873.6	$224.5

	At December 31, 2004
(Millions of Dollars)	NU Consolidated	CL&P	PSNH		WMECO
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
Unrecovered contractual obligations	354.7	213.4		64.4	77.0
Recoverable energy costs	255.0	43.4		194.9	3.1
Other regulatory assets/(overrecoveries)	230.5	67.8		152.0	(49.0)
Totals	$2,745.9	$1,526.4		$900.1	$231.6

Included in WMECO's other regulatory assets are $46.9 million and $50.7 million at March 31, 2005 and December 31, 2004, respectively, of amounts related the 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.

Included in the NU consolidated amounts above at March 31, 2005 and December 31, 2004, are $60.2 million and $87.8 million, respectively, of regulatory assets associated with Yankee Gas' environmental clean-up costs, hardship receivables, and income taxes.

Additionally, the Utility Group had $12.1 million and $11.6 million of regulatory costs at March 31, 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 5D, "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 maintained $1.1 billion of regulatory liabilities at both March 31, 2005 and December 31, 2004, respectively. 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 March 31, 2005
(Millions of Dollars)	NU Consolidated	CL&P	PSNH		WMECO
Cost of removal	$ 314.1	$142.4		$ 87.5	$24.4
CL&P CTA, GSC and SBC overcollections	149.0	149.0		-	-
PSNH Cumulative deferral – SCRC	224.2	-		224.2	-
Regulatory liabilities offsetting Utility Group derivative assets	281.3	281.3		-	-
Other regulatory liabilities	162.1	83.6		29.2	0.8
Totals	$1,130.7	$656.3		$340.9	$25.2

	At December 31, 2004
(Millions of Dollars)	NU Consolidated	CL&P	PSNH		WMECO
Cost of removal	$ 328.8	$144.3		$ 87.6	$24.1
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
Totals	$1,069.8	$614.8		$323.7	$24.8

Included in the NU consolidated amounts above at March 31, 2005 and December 31, 2004, are $108.3 million and $106.5 million, respectively, of regulatory liabilities associated with Yankee Gas' cost of removal, pension, purchased gas adjustment clause and other regulatory liabilities.

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
(Millions of Dollars)	March 31, 2005	March 31, 2004
Borrowed funds	$1.9	$1.3
Equity funds	1.9	1.3
Totals	$3.8	$2.6
Average AFUDC rates	4.5%	3.4%

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 Opinion (APB) No. 25, "Accounting for Stock Issued to Employees," 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
(Millions of Dollars, except per share amounts)	March 31, 2005	March 31, 2004
Net (loss)/income, as reported	$(117.7)	$67.4
Add: Equity-based employee compensation expense included in reported net (loss)/income, net of related tax effects	0.6	0.6
Net (loss)/income before equity-based compensation	(117.1)	68.0
Deduct: Total equity-based employee compensation expense determined under the fair value-based method for all awards, net of related tax effects	(0.8)	(1.1)
Pro forma net (loss)/income	$(117.9)	$66.9
EPS:
Basic and fully diluted – as reported	$ (0.91)	$0.53
Basic and fully diluted – pro forma	$ (0.91)	$0.53

Net (loss)/income as reported includes $0.6 million of expense for restricted stock and restricted stock units for the three months ended March 31, 2005 and 2004, respectively. 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 three-month period ended March 31, 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 March 31, 2005 and December 31, 2004, CL&P had sold an undivided interest in its accounts receivable of $100 million and $90 million, respectively, to a financial institution with limited recourse through CL&P Receivables Corporation (CRC), a wholly owned subsidiary of CL&P. CRC can sell up to $100 million of an undivided interest in its accounts receivable and unbilled revenues. At March 31, 2005 and December 31, 2004, the reserve requirements calculated in accordance with the Receivables Purchase and Sale Agreement were $23.1 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 March 31, 2005 and December 31, 2004, amounts sold to CRC by CL&P but not sold to the financial institution totaling $189.7 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 7, 2004, CRC renewed its Receivables Purchase and Sale Agreement with CL&P and the financial institution through July 6, 2005, and the termination date of the facility was extended to July 3, 2007. CL&P’s continuing involvement with the receivables that are sold to CRC and the financial institution is limited to the servicing of 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 late-March 2004, based on revised information that impacts 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 an after-tax investment write-down of $1.5 million ($2.5 million on a pre-tax basis) in the first quarter of 2004.

NU has an investment in the common stock of NEON, a provider of optical networking services. On March 8, 2005, NEON merged with Globix Corporation (Globix), an unaffiliated publicly-owned entity, and NU received 1.2748 shares of Globix common stock for each of the 2.1 million shares of NEON stock it owned. In connection with the closing of the merger, a $0.1 million after-tax loss was recognized in the first quarter of 2005. A pre-tax positive $0.4 million change in fair value subsequent to March 8, 2005 is included in accumulated other comprehensive income. For further information, see Note 7, "Comprehensive Income," to the condensed consolidated financial statements.

NU owns 49 percent of the common stock of the Connecticut Yankee Atomic Power Company (CYAPC) with a carrying value of $21.7 million at March 31, 2005. CYAPC is involved in litigation over the termination of the 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 March 31, 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 5D, "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 $17.1 million and amounts included in escrow for SESI that have not been spent on construction projects of $15.3 million at March 31, 2005. Similar amounts totaled $46.3 million and $20 million, respectively, at December 31, 2004. Special deposits at both March 31, 2005 and December 31, 2004 also included $16.3 million in escrow for Yankee Gas. The $16.3 million represents Yankee Gas’ June 1, 2005 first mortgage bond payment.

Counterparty Deposits

Balances collected from counterparties resulting from Select Energy’s credit management activities totaled $95.6 million at March 31, 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

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

	For the Three Months Ended
(Millions of Dollars)	March 31, 2005	March 31, 2004
Other Income:
Investment income	$ 4.9	$ 3.4
CL&P procurement fee	3.0	3.1
AFUDC – equity funds	1.9	1.3
Other	1.2	2.2
Total Other Income	$ 11.0	$10.0
Other Loss:
Environmental accrual	$ (3.6)	$ -
Charitable donations	(0.6)	(1.0)
Costs not recoverable from regulated customers	(0.7)	(1.3)
Loss on disposition of property	(0.1)	(3.7)
Other	(5.3)	(3.6)
Total Other Loss	$(10.3)	$ (9.6)
Totals	$ 0.7	$ 0.4

Investment income includes equity in earnings of regional nuclear generating and transmission companies of $0.9 million and $0.1 million of income for the three months ended March 31, 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.

Unbilled Revenues

In the first quarter of 2005, management adopted a new method to estimate unbilled revenues for CL&P, PSNH, WMECO, and Yankee Gas. The new method allocates billed sales to the current calendar month based on the daily load for each billing cycle. The billed sales are subtracted from total calendar month sales to estimate unbilled sales. The impact of adopting the new method was not material. The new method replaces the requirements method and the cycle method that were used periodically to test the requirements method.

WHOLESALE CONTRACT MARKET CHANGES AND RESTRUCTURING AND IMPAIRMENT CHARGES (NU, NU Enterprises)

Wholesale Contract Market Changes: NU Enterprises recorded $188.9 million of pre-tax wholesale contract market changes for the three months ended March 31, 2005 related to the changes in the fair value of wholesale contracts that the company is in the process of divesting. These amounts are reported as wholesale contract market changes, net on the condensed consolidated statements of (loss)/income. A summary of those pre-tax charges/(benefits) is as follows (millions of dollars):

	First Quarter 2005
Mark-to-market on long-term wholesale electricity contracts	$ 294.3
Mark-to-market on retail marketing supply contracts and other wholesale contracts	(105.4)
Totals	$ 188.9

The $294.3 million for the first quarter ended March 31, 2005, relates to the change in the negative mark-to-market on certain long-term below-market wholesale electricity contracts during the first quarter and to certain contract asset write-offs. 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 $105.4 million first quarter 2005 benefit in the above table includes a $94 million pre-tax mark-to-market gain on retail marketing supply contracts which NU Enterprises was seeking to divest. 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. This amount also includes $25.8 million of pre-tax mark-to-market gains on other wholesale contracts for other wholesale contracts related to electricity that would have been delivered to customers primarily in 2005 and 2006. As a result of exiting the wholesale marketing business, these contracts were also required to be marked-to-market. Prior to the decision to exit the wholesale marketing business, it was management's int ention to deliver the electricity to the customer. As such, accrual accounting was used through December 31, 2004. Under accrual accounting, earnings would have been recorded as the electricity would have been delivered in 2005 and 2006.

The $105.4 million first quarter 2005 benefit in the above table was offset by a $14.4 million pre-tax loss associated with a contract termination payment.

Included in the mark-to-market on long-term wholesale electricity contracts is a $54.5 million pre-tax mark-to-market charge for the three months ended March 31, 2005 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. 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 consolidate d basis NU retains the over-market obligation to the ratepayers of CL&P and WMECO.

For information regarding wholesale current and long-term derivative assets and liabilities that are being divested, see Note 3, "Derivative Instruments," to the condensed consolidated financial statements.

Restructuring and Impairment Charges: NU Enterprises recorded $45.5 million pre-tax restructuring and impairment charges for the three months ended March 31, 2005 related to the decision to exit the wholesale marketing business and to divest its energy services businesses. The amounts related to continuing operations are included as restructuring and impairment charges on the condensed consolidated statements of (loss)/income with the remainder included in discontinued operations. A summary of those pre-tax charges is as follows (millions of dollars):

	First Quarter 2005
Merchant Energy:
Impairment Charges	$ 7.2
Energy Services:
Impairment Charges	38.3
Subtotal	45.5
Restructuring and Impairment Charges Included in Discontinued Operations	24.0
Totals	$21.5

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 hired an outside firm, FMI Corp., 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.

Additional restructuring charges will be recognized as incurred and may include professional fees and employee-related and other costs.

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

Derivatives that are utilized for trading purposes are recorded at fair value with changes in fair value included in earnings. Other contracts that are derivatives but do not meet the definition of a cash flow hedge and cannot be designated as being used for normal purchases or normal sales are also 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 on the condensed consolidated balance sheets. 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 three months ended March 31, 2005, a positive $2.4 million, net of tax, was reclassified as revenue from other comprehensive income in connection with the consummation of the underlying hedged transactions and recognized in earnings. Also during the first quarter 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 $7.3 million, net of tax. Accumulated other comprehensive income at March 31, 2005, was a positive $3.8 million, net of tax (increase to equity), relating to hedged transactions, and it is estimated that a positive $3.7 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 cate gory as cash flows from the underlying hedged transaction.

There was a positive pre-tax impact of $0.6 million recognized in earnings in 2005 for the ineffective portion of cash flow hedges. A negative pre-tax $0.1 million was recognized in earnings in 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 tables below summarize current and long-term derivative assets and liabilities at March 31, 2005 and December 31, 2004. 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 March 31, 2005, Select Energy had $485.5 million of derivative assets from trading, non-trading, 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 below do not include option premiums paid, which are recorded as prepayments and amounted to $6.3 million and $5.4 million related to energy trading activities and $0.6 million and $5.2 million related to marketing activities at March 31, 2005 and December 31, 2004, respectively. These amounts also do not in clude option premiums paid of $13.6 million and $18.7 million related to non-trading gas options at March 31, 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 $5.5 million and $7 million related to energy trading activities and $0.1 million and $1.1 million related to marketing activities at March 31, 2005 and December 31, 2004, respectively. Also not included at March 31, 2005 and December 31, 2004 are option premiums received of $13.8 million and $19 million, respectively, related to non-trading gas options.

	At March 31, 2005
(Millions of Dollars)		Assets		Liabilities
		Current	Long-Term	Current	Long-Term	Net Total
NU Enterprises:
Trading		$ 62.2	$ 51.0	$ (60.6)	$ (5.1)	$ 47.5
Non-trading		274.2	85.3	(301.0)	(276.5)	(218.0)
Hedging		12.4	0.4	(6.9)	-	5.9
Utility Group - Gas:
Non-trading		-	-	(0.1)	-	(0.1)
Hedging		1.4	-	-	-	1.4
Utility Group - Electric:
Non-trading		40.5	240.8	(3.2)	(37.7)	240.4
NU Parent:
Hedging		-	-	-	(6.2)	(6.2)
Total		$390.7	$377.5	$(371.8)	$(325.5)	$ 70.9

	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

NU Enterprises - Trading: Historically, to gather market intelligence and utilize this information in risk management activities for the wholesale marketing activities, Select Energy conducted limited energy trading activities in electricity, natural gas, and oil, and therefore, experienced net open positions. Limited trading activities will continue for price discovery and deal execution to support the retail marketing business. 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 trading 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 operating revenues in the condensed consolidated statements of (loss)/income in the period of change. The net fair value positions of the trading portfolio at March 31, 2005 and December 31, 2004 were assets of $47.5 million and $29.6, respectively. A portion of this increase in the fair value position of the trading portfolio was the result of change in valuation technique used to model a certain contract.

Select Energy's trading 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, financial swaps, and options, 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. Select Energy's trading portfolio also includes transmission congestion contracts (TCC). The fair value of the TCCs included in the trading portfolio is based on published market data.

NU Enterprises - Non-Trading: Certain non-trading derivative contracts are part of Select Energy's wholesale and retail marketing activities. These contracts include the electricity contracts and the wholesale natural gas contracts that were used in Select Energy's energy sourcing activities. 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 over terms up to eight years. The fair value of the natural gas contracts was 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 conversion factor to electricity.

The fair value of non-trading contracts, both assets and liabilities combined, decreased by $139.4 million from a negative $78.6 million to a negative $218 million, as follows (in millions):

Net fair value at December 31, 2004	$ (78.6)
Change in fair value of wholesale natural gas contracts used in energy sourcing	(40.7)
Mark-to-market restructuring charge	(137.9)
Contracts realized or otherwise settled during the period	38.3
Other changes in fair value	0.9
Net fair value at March 31, 2005	$(218.0)

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

cash flows of a forecasted transaction (a cash flow hedge) is initially recorded at fair value with changes in fair value recorded in accumulated other comprehensive income. Cash flow hedges impact net income when the forecasted transaction being hedged occurs, when hedge ineffectiveness is measured and recorded, when the forecasted transaction being hedged is no longer probable of occurring, or when there is accumulated other comprehensive loss and the hedge and the forecasted transaction being hedged are in a loss position on a combined basis.

Select Energy maintains natural gas service agreements with certain 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 March 31, 2005 the NYMEX futures contracts had notional values of $33 million and were recorded at fair value as derivative assets of $10.6 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 and swaps. These hedging contracts, which are valued at the mid-point of bid and ask market prices, were recorded as derivative assets of $2.4 million and derivative liabilities of $6.9 million at March 31, 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 fair value of the futures, options and swaps were included in derivative assets and amounted to a negative $0.2 million at March 31, 2005. The fair value of the hedged natural gas inventory was recorded as a reduction to fuel, materials and supplies of $0.1 million at March 31, 2005. For the three months ended March 31, 2005, Select Energy recorded a positive pre-tax of $0.6 million in earnings related to contracts settled for its hedging instruments and natural gas inventory. In 2004, certain of these fair value hedges were redesignated as cash flow hedges, and future changes in fair value during the hedge designation will be included in accumulated other comprehensive income (equity), unless ineffective.

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

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 March 31, 2005 the commodity swap agreement had a notional value of $1.3 million and was recorded at fair value as a derivative asset of $1.4 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.

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 March 31, 2005 include a derivative asset with a fair value of $281.3 million and a derivative liability with a fair value of $40.9 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 matched-terms 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 equal and offsetting in the condensed consolidated statements of (loss)/income. The cumulative change in the fair value of the hedged debt of $6.2 million is included as a decrease to long-term debt on the condensed consolidated balance sheets. The hedge is recorded as a derivative liability of $6.2 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 remaining reporting units that maintain goodwill are generally consistent with the operating segments underlying the reportable segments identified in Note 10, "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 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 th e 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 March 31, 2005 and December 31, 2004, by reportable segment and reporting unit is as follows:

(Millions of Dollars)	At March 31, 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 write-off was recorded. An additional $0.7 million of other intangible assets were impaired, and the total write off of $38.3 million is included in restructuring and impairment charges.

The exclusivity agreement intangible asset, which was included in the merchant energy business, was written off. The $7.9 million balance of December 31, 2004 was amortized by $0.7 million in the first quarter of 2005. The remaining $7.2 million was written off and is included in restructuring and impairment charges.

For information regarding the completion of the comprehensive review and these asset impairments, see Note 2, "Wholesale Contract Market Changes and Restructuring and Impairment Charges," to the condensed consolidated financial statements.

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

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

At March 31, 2005 and December 31, 2004, NU's intangible assets and related accumulated amortization, all of which related to NU Enterprises, consisted of the following:

	At March 31, 2005
(Millions of Dollars)	Gross Balance	Accumulated Amortization	Net Balance
Intangible assets subject to amortization:
Exclusivity agreement	$ -	$ -	$ -
Customer list	6.7	3.9	2.8
Totals	$ 6.7	$3.9	$2.8
Intangible assets not subject to amortization:
Customer relationships	$ -
Tradenames	-
Totals	$ -

	At December 31, 2004
(Millions of Dollars)	Gross Balance	Accumulated Amortization	Net Balance
Intangible assets subject to amortization:
Exclusivity agreement	$17.7	$ 9.8	$ 7.9
Customer list	6.6	3.7	2.9
Totals	$24.3	$13.5	$10.8
Intangible assets not subject to amortization:
Customer relationships	$ 5.2
Tradenames	3.3
Totals	$ 8.5

NU recorded amortization expense of $0.9 million for both the three months ended March 31, 2005 and 2004, respectively, related to intangible assets subject to amortization. Based on the remaining amount of intangible assets subject to amortization, the estimated annual amortization expense for 2005 and for each of the succeeding 5 years from 2006 through 2010 is approximately $1 million in 2005 through 2007 and no amortization expense in 2008, 2009 or 2010. These amounts may vary as acquisitions and dispositions occur in the future.

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 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 compares 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. 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. A decision from the court is not expected to be issued until the second quarter of 2005 at the earliest. 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 f indings of the court, however, management believes that CL&P's pre-tax earnings would increase by a minimum of $17 million.

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 billed with stranded costs, and transition energy service/default energy service (TS/DS) revenues billed with TS/DS costs. The NHPUC reviews the filing, including a prudence review of PSNH's generation operations. The cumulative deferral of SCRC revenues in excess of costs was $224.2 million at March 31, 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 $399.1 million to $174.9 million.

The 2004 SCRC reconciliation filing was filed with the NHPUC on May 2, 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.

accrued expenses recovered through the SCRC and TS/DS rate mechanisms, consistent with accrual accounting. At March 31, 2005, the PSNH 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 is considering a bill that would place strict limitations on the level of mercury that PSNH’s existing generation plants can emit. Management is reviewing possible legislation and 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, non-generation mercury mitigation programs, and possible retirement of one or more of its generating units. 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. On May 4, 2005, the New Ham pshire legislature voted to retain the bill for further consideration in the 2006 session.

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). This filing reconciled the recovery of generation-related stranded costs for calendar year 2004. The DTE has combined the 2003 transition cost reconciliation filing, standard offer service and default service reconciliation, the transmission cost adjustment filing, and the 2004 transition cost reconciliation filing into a single proceeding. A hearing schedule for the combined proceeding is expected to be set in May 2005. While the timing of a decision in the combined proceeding is uncertain, 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, Select Energy)

CL&P: These amounts represent commitments for various services and materials associated with the Bethel, Connecticut to Norwalk, Connecticut and the Middletown, Connecticut to Norwalk, Connecticut projects as of March 31, 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
Transmission business project commitments	$93.0	$ 72.0	$ 7.0	$7.0	$7.0

Select 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 $703.2 million at March 31, 2005, as follows (millions of dollars):

Year
2005	$483.7
2006	158.0
2007	29.1
2008	13.5
2009	6.4
Thereafter	12.5
Total	$703.2

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

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

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

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.

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. Management expects that if the FERC staff's position on the decommissioning GDP cost escalator is found by the FERC to be more appropriate than that use d 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 are expected to begin in June 2005. A FERC administrative law judge decision in this proceeding could be rendered in the fall of 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.

As mentioned above, 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.

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, 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 March 31,	At December 31,
	2005	2004
(Millions of Dollars)
Globix investment	$ 10.0	$ (a)
SERP securities	55.1	55.1
WMECO prior spent nuclear fuel trust	49.6	49.3
Totals	$114.7	$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 is a marketable equity security at March 31, 2005.

	At March 31, 2005
	Amortized Cost	Pre-Tax Gross Unrealized Gains	Pre-Tax Gross Unrealized Losses	Estimated Fair Value
United States equity securities	$ 30.0	$3.1	$(0.3)	$ 32.8
Non-United States equity securities	5.6	1.4	-	7.0
Fixed income securities	75.3	0.3	(0.7)	74.9
Totals	$110.9	$4.8	$(1.0)	$114.7

	At December 31, 2004
	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 March 31, 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 7, "Comprehensive Income," to the condensed consolidated financial statements.

For the quarters ended March 31, 2005 and 2004, realized gains and losses recognized on the sale of available-for-sale securities are as follows (in millions):

Realized

Gains

Realized

Losses

Net Realized

Gains/(Losses)

2005

$0.2

$(0.3)

$(0.1)

2004

0.2

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 $12.9 million and $1.8 million for the quarters ended March 31, 2005 and 2004, respectively.

At March 31, 2005, the contractual maturities of the available-for-sale securities are as follows (in millions):

	Amortized Cost	Estimated Fair Value
Less than one year	$ 53.5	$ 58.0
One to five years	27.4	27.5
Six to ten years	6.3	6.3
Greater than ten years	23.7	22.9
Total	$110.9	$114.7

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 ended March 31, 2005 and 2004 is as follows:

	Three Months Ended March 31, 2005
	NU*	CL&P*	PSNH	WMECO	NU Enterprises		Other
Net/(loss) income	$(117.7)	$25.2	$8.8	$4.7		$(167.4)	$11.0
Comprehensive (loss)/income items:
Qualified cash flow hedging instruments	7.3	-	-	-		7.3	-
Unrealized losses on securities	(0.6)	-	-	(0.2)		-	(0.4)
Net change in comprehensive income items	6.7	-	-	(0.2)		7.3	(0.4)
Total comprehensive (loss)/income	$(111.0)	$25.2	$8.8	$4.5		$(160.1)	$10.6

	Three Months Ended March 31, 2004
	NU*	CL&P*	PSNH	WMECO	NU Enterprises	Other
Net income	$67.4	$26.2	$11.8	$3.5	$18.8		$7.1
Comprehensive income items:
Qualified cash flow hedging instruments	16.5	-	-	-	16.5		-
Unrealized gains on securities	0.4	-	-	-	-		0.4
Net change in comprehensive income items	16.9	-	-	-	16.5		0.4
Total comprehensive income	$84.3	$26.2	$11.8	$3.5	$35.3		$7.5

*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 three months ended March 31, 2005 and the twelve months ended December 31, 2004 are as follows:

(Millions of Dollars, Net of Tax)	Three Months March 31, 2005	Twelve Months December 31, 2004
Balance at beginning of period	$(3.5)	$ 24.8
Hedged transactions recognized into earnings	2.4	(57.8)
Change in fair value	6.4	25.0
Cash flow transactions entered into for the period	(1.5)	4.5
Net change associated with the current period hedging transactions	7.3	(28.3)
Total fair value adjustments included in accumulated other comprehensive income/(loss)	$ 3.8	$ (3.5)

Accumulated other comprehensive income items unrelated to NU's qualified cash flow hedging instruments totaled $1.7 million and $2.3 million in gains at March 31, 2005 and December 31, 2004, respectively. These amounts relate to unrealized gains on investments in marketable debt and equity securities and minimum person 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 March 31, 2005 and 2004, 1,507,145 options and 655,326 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 March 31,
(Millions of Dollars, Except for Share Information)	2005	2004
(Loss)/income from continuing operations	$(100.5)	$67.7
Loss from discontinued operations	(17.2)	(0.3)
Net (loss)/income	$(117.7)	$67.4
Basic EPS common shares outstanding (average)	129,278,505	127,879,766
Dilutive effects of employee stock options	-	181,320
Fully diluted EPS common shares outstanding (average)	129,278,505	128,061,086
Basic and fully diluted EPS:
(Loss)/income from continuing operations	(0.78)	0.53
Loss from discontinued operations	(0.13)	-
Basic and fully diluted EPS	$(0.91)	$0.53

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 ended March 31, 2005 and 2004 are estimated as follows:

	For the Three Months Ended March 31,
	Pension Benefits		Postretirement Benefits
(Millions of Dollars)	2005	2004	2005	2004
Service cost	$12.3	$ 9.9	$ 1.9	$ 1.5
Interest cost	31.2	29.5	6.3	6.3
Expected return on plan assets	(43.0)	(43.7)	(2.8)	(3.1)
Amortization of unrecognized net transition (asset)/obligation	(0.1)	(0.4)	3.0	3.0
Amortization of prior service cost	1.8	1.8	(0.1)	(0.1)
Amortization of actuarial loss	8.1	3.6	-	-
Other amortization, net	-	-	4.3	2.7
Total - net periodic expense	$10.3	$ 0.7	$12.6	$10.3

A portion of this net periodic expense is capitalized related to current employees working on capital projects. Amounts capitalized were $2.3 million and $0.6 million for the three months ended March 31, 2005 and 2004, respectively.

NU does not 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.

10.

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 62 percent and 69 percent of NU's total revenues for the three months ended March 31, 2005 and 2004, respectively, and includes the operations of the regulated electric utilities, CL&P, PSNH and WMECO, whose complete condensed consolidated financial statements are included in NU’s original 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, the generation operations of HWP and NGS, while the NU Enterprises services and other business segment includes E. S. Boulos Company, Woods Electrical and NGS Mechanical, Inc., which are subsidiaries of NGS, SECI, Reeds Ferry Supply Co. Inc., HEC/Tobyhanna Energy Project, Inc., and HEC/CJTS Energy Center LLC, which are subsidiaries of SESI, Woods Network, and intercompany eliminations. The results of NU Enterprises parent are also included within services and other.

NU's condensed consolidated statements of (loss)/income for the three months ended March 31, 2005 and 2004 present the operations for SESI, SECI-NH, Woods Network, and Woods Electrical as discontinued operations. For further information regarding these companies, see Note 12, "Subsequent Events," to the condensed consolidated financial statements.

There were no CL&P transitional standard offer (TSO) purchases from Select Energy in the first quarter of 2005. Total Select Energy revenues from CL&P for other transactions with CL&P, represented $14.2 million or 2 percent for the three months ended March 31, 2005, of total NU Enterprises' revenues. 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 $178.5 million or 24 percent for the three months ended March 31, 2004, 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 $20.5 million and $32 million, or 2 percent and 4 percent, of total NU Enterprises' revenues for the three months ended March 31, 2005 and 2004, respectively. Total WMECO purchases from Select Energy are eliminated in consolidation.

Select Energy revenues related to contracts with NSTAR companies represented $206.4 million or 24 percent and $88.7 million or 12 percent of total NU Enterprises' revenues for the three months ended March 31, 2005 and 2004, respectively. No other individual customer represented in excess of 10 percent of NU Enterprises' revenues for the three months ended March 31, 2005 or 2004.

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 months ended March 31, 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 March 31, 2005
	Utility Group
	Distribution (1)			NU
(Millions of Dollars)	Electric	Gas	Transmission	Enterprises	Other	Eliminations	Total
Operating revenues	$1,175.4	$ 194.9	$ 36.7	$ 872.9	$ 86.1	$ (132.7)	$2,233.3
Depreciation and amortization	(110.4)	(5.4)	(5.6)	(4.4)	(4.2)	3.3	(126.7)
Wholesale contract market changes, net	-	-	-	(188.9)	-	-	(188.9)
Restructuring and impairment charges	-	-	-	(21.5)	-	-	(21.5)
Other operating expenses	(980.2)	(162.2)	(15.0)	(875.0)	(83.4)	128.0	(1,987.8)
Operating income/(loss)	84.8	27.3	16.1	(216.9)	(1.5)	(1.4)	(91.6)
Interest expense, net of AFUDC	(41.4)	(4.3)	(3.0)	(11.7)	(8.0)	3.8	(64.6)
Interest income	1.0	0.1	0.1	0.9	4.1	(4.3)	1.9
Other income/(loss), net	3.4	(0.3)	(0.9)	(4.4)	46.5	(45.5)	(1.2)
Income tax (expense)/benefit	(16.5)	(7.9)	(3.5)	81.9	2.4	-	56.4
Preferred dividends	(1.4)	-	-	-	-	-	(1.4)
Income/(loss) from continuing operations	29.9	14.9	8.8	(150.2)	43.5	(47.4)	(100.5)
Loss from discontinued operations	-	-	-	(17.2)	-	-	(17.2)
Net income/(loss)	$ 29.9	$ 14.9	$ 8.8	$ (167.4)	$ 43.5	$ (47.4)	$ (117.7)
Total assets (2)	$8,637.3	$1,110.7	$ -	$2,444.6	$4,418.1	$(4,531.7)	$12,079.0
Cash flows for total investments in plant	$ 103.1	$ 12.0	$ 41.6	$ 5.8	$ 4.3	$ -	$ 166.8

	For the Three Months Ended March 31, 2004
	Utility Group
	Distribution (1)			NU
(Millions of Dollars)	Electric	Gas	Transmission	Enterprises	Other	Eliminations	Total
Operating revenues	$1,059.6	$ 171.2	$ 31.1	$ 756.8	$ 66.5	$ (285.9)	$1,799.3
Depreciation and amortization	(110.2)	(6.4)	(5.0)	(4.5)	(3.6)	3.0	(126.7)
Other operating expenses	(856.5)	(139.8)	(13.2)	(708.9)	(66.2)	284.2	(1,500.4)
Operating income/(loss)	92.9	25.0	12.9	43.4	(3.3)	1.3	172.2
Interest expense, net of AFUDC	(39.9)	(3.9)	(2.3)	(11.4)	(5.8)	2.7	(60.6)
Interest income	1.1	-	-	0.4	2.8	(2.8)	1.5
Other income/(loss), net	2.2	(0.5)	(0.3)	(0.5)	27.0	(29.0)	(1.1)
Income tax (expense)/benefit	(20.6)	(8.7)	(3.1)	(12.8)	5.7	(3.4)	(42.9)
Preferred dividends	(1.4)	-	-	-	-	-	(1.4)
Income/(loss) from continuing operations	34.3	11.9	7.2	19.1	26.4	(31.2)	67.7
Loss from discontinued operations	-	-	-	(0.3)	-	-	(0.3)
Net income/(loss)	$ 34.3	$ 11.9	$ 7.2	$ 18.8	$ 26.4	$ (31.2)	$ 67.4
Cash flows for total investments in plant	$ 102.9	$ 8.4	$29.4	$ 5.8	$ 2.1	$ -	$ 148.6

(1)

Includes PSNH's generation activities.

(2)

Information for segmenting total assets between electric distribution and transmission is not available at March 31, 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 months March 31, 2005 and 2004 is as follows:

	CL&P - For the Three Months Ended March 31, 2005
(Millions of Dollars)	Distribution	Transmission	Totals
Operating revenues	$ 814.9	$24.0	$ 838.9
Depreciation and amortization	(55.5)	(4.1)	(59.6)
Other operating expenses	(708.0)	(8.9)	(716.9)
Operating income	51.4	11.0	62.4
Interest expense, net of AFUDC	(26.5)	(1.9)	(28.4)
Interest income	0.8	0.1	0.9
Other income/(loss), net	4.4	(0.9)	3.5
Income tax expense	(9.7)	(2.1)	(11.8)
Preferred dividends	(1.4)	-	(1.4)
Net income	$ 19.0	$ 6.2	$ 25.2
Cash flows for total investments in plant	$ 60.8	$30.4	$ 91.2

	CL&P - For the Three Ended March 31, 2004
(Millions of Dollars)	Distribution	Transmission	Totals
Operating revenues	$ 727.7	$21.0	$ 748.7
Depreciation and amortization	(53.9)	(3.6)	(57.5)
Other operating expenses	(618.2)	(8.7)	(626.9)
Operating income	55.6	8.7	64.3
Interest expense, net of AFUDC	(25.5)	(1.6)	(27.1)
Interest income	0.9	0.1	1.0
Other income/(loss), net	4.4	(0.3)	4.1
Income tax expense	(12.8)	(1.9)	(14.7)
Preferred dividends	(1.4)	-	(1.4)
Net income	$ 21.2	$ 5.0	$ 26.2
Cash flows for total investments in plant	$ 63.5	$21.7	$ 85.2

	PSNH - For the Three Months Ended March 31, 2005
(Millions of Dollars)	Distribution (1)	Transmission	Totals
Operating revenues	$ 260.3	$8.6	$268.9
Depreciation and amortization	(49.8)	(1.0)	(50.8)
Other operating expenses	(188.4)	(4.2)	(192.6)
Operating income	22.1	3.4	25.5
Interest expense, net of AFUDC	(10.9)	(0.6)	(11.5)
Interest income	0.2	-	0.2
Other (loss)/income, net	(1.0)	0.1	(0.9)
Income tax expense	(3.5)	(1.0)	(4.5)
Net income	$ 6.9	$1.9	$ 8.8
Cash flows for total investments in plant	$ 33.1	$7.1	$40.2

(1)

Includes PSNH's generation activities.

	PSNH - For the Three Months Ended March 31, 2004
(Millions of Dollars)	Distribution (1)	Transmission	Totals
Operating revenues	$237.7	$ 6.5	$244.2
Depreciation and amortization	(45.8)	(0.9)	(46.7)
Other operating expenses	(163.0)	(3.0)	(166.0)
Operating income	28.9	2.6	31.5
Interest expense, net of AFUDC	(10.8)	(0.5)	(11.3)
Interest income	-	-	-
Other loss, net	(1.7)	-	(1.7)
Income tax expense	(6.0)	(0.7)	(6.7)
Net income	$ 10.4	$ 1.4	$ 11.8
Cash flows for total investments in plant	$ 27.8	$ 5.8	$ 33.6

(1)

Includes PSNH's generation activities.

	WMECO - For the Three Months Ended March 31, 2005
(Millions of Dollars)	Distribution	Transmission	Totals
Operating revenues	$100.3	$4.1	$104.4
Depreciation and amortization	(5.1)	(0.5)	(5.6)
Other operating expenses	(83.8)	(2.0)	(85.8)
Operating income	11.4	1.6	13.0
Interest expense, net of AFUDC	(4.0)	(0.5)	(4.5)
Interest income	0.1	-	0.1
Other loss, net	(0.2)	-	(0.2)
Income tax expense	(3.3)	(0.4)	(3.7)
Net income	$ 4.0	$0.7	$ 4.7
Cash flows for total investments in plant	$ 7.5	$3.4	$ 10.9

	WMECO - For the Three Months Ended March 31, 2004
(Millions of Dollars)	Distribution	Transmission	Totals
Operating revenues	$ 94.3	$ 3.6	$ 97.9
Depreciation and amortization	(10.5)	(0.5)	(11.0)
Other operating expenses	(75.4)	(1.5)	(76.9)
Operating income	8.4	1.6	10.0
Interest expense, net of AFUDC	(3.5)	(0.3)	(3.8)
Interest income	(0.1)	-	(0.1)
Other loss, net	(0.2)	-	(0.2)
Income tax expense	(1.9)	(0.5)	(2.4)
Net income	$ 2.7	$ 0.8	$ 3.5
Cash flows for total investments in plant	$ 7.9	$ 0.3	$ 8.2

NU Enterprises' segment information for the three months ended March 31, 2005 and 2004 is as follows. Eliminations are included in the services and other column:

	NU Enterprises - For the Three Months Ended March 31, 2005
(Millions of Dollars)	Merchant Energy	Services and Other	Totals
Operating revenues	$ 843.8	$ 29.1	$ 872.9
Depreciation and amortization	(4.1)	(0.3)	(4.4)
Wholesale contract market changes, net	(188.9)	-	(188.9)
Restructuring and impairment charges	(7.2)	(14.3)	(21.5)
Other operating expenses	(845.4)	(29.6)	(875.0)
Operating loss	(201.8)	(15.1)	(216.9)
Interest expense	(11.7)	-	(11.7)
Interest income	0.6	0.3	0.9
Other loss, net	(4.3)	(0.1)	(4.4)
Income tax benefit	78.3	3.6	81.9
Loss from continuing operations	(138.9)	(11.3)	(150.2)
Loss from discontinued operations	-	(17.2)	(17.2)
Net loss	$ (138.9)	$(28.5)	$ (167.4)
Total assets	$2,217.4	$227.2	$2,444.6
Cash flows for total investments in plant	$ 5.8	$ -	$ 5.8

	NU Enterprises - For the Three Months Ended March 31, 2004
(Millions of Dollars)	Merchant Energy	Services and Other	Totals
Operating revenues	$ 736.3	$ 20.5	$ 756.8
Depreciation and amortization	(4.3)	(0.2)	(4.5)
Other operating expenses	(688.4)	(20.5)	(708.9)
Operating income/(loss)	43.6	(0.2)	43.4
Interest expense	(11.4)	-	(11.4)
Interest income	0.4	-	0.4
Other loss, net	(0.5)	-	(0.5)
Income tax (expense)/benefit	(13.0)	0.2	(12.8)
Income from continuing operations	19.1	-	19.1
Loss from discontinued operations	-	(0.3)	(0.3)
Net income/(loss)	$ 19.1	$ (0.3)	$ 18.8
Cash flows for total investments in plant	$ 5.8	$ -	$ 5.8

11.

RESTATEMENT AND RECLASSIFICATION OF PREVIOUSLY ISSUED FINANCIAL STATEMENTS (NU, Select Energy)

NU concluded that it incorrectly classified as unrestricted cash from counterparties amounts that should have been classified as cash and cash equivalents at December 31, 2003 and March 31, 2004. Corrections were made to reclassify unrestricted cash from counterparties to cash and cash equivalents because those funds were unrestricted and were used to fund or were available to fund the company's operations. The condensed consolidated statement of cash flows for the three months ended March 31, 2004, has been restated for these corrections.

The effects of the corrections and other reclassifications to conform with the current period presentation on the condensed consolidated statement of cash flows for the three months ended March 31, 2004 are summarized in the following table (in thousands):

Condensed Consolidated Statement of Cash Flows	Previously Reported	Currently Reported
Net income	$ 67,442	$ 67,442
Adjustments to reconcile net cash flows provided by operating activities:
Bad debt expense	-	5,795
Pension expense	724	2,659
Regulatory overrecoveries	13,670	13,669
Derivative assets	-	(1,152)
Other sources of cash	9,884	9,885
Derivative liabilities	-	(20,372)
Other uses of cash	(42,504)	(44,075)
Unrestricted cash from counterparties (1)	(24,409)	-
Receivables and unbilled revenues, net	(13,725)	(19,520)
Other current assets	(67,493)	18,583
Accounts payable (1)	71,082	118,834
Other current liabilities	87,245	22,693
Other operating activities	152,856	152,856
Net cash flows provided by operating activities	254,772	327,297
Investments in property and plant:
Electric, gas and other utility plant	(132,073)	(142,840)
Competitive energy assets	(5,697)	(5,776)
Other investment activities	6,087	6,087
Net cash flows used in investing activities	(131,683)	(142,529)
Net cash flows used in financing activities	(84,235)	(84,235)
Net increase in cash and cash equivalents	38,854	100,533
Cash and cash equivalents - beginning of period (1)	37,196	43,372
Cash and cash equivalents - end of period	$ 76,050	$143,905

(1)

These amounts relate to the restatement of the balances in unrestricted cash from counterparties and cash and cash equivalents.

Certain other reclassifications of prior period data included in the accompanying condensed consolidated financial statements, primarily related to fuel, purchased and net interchange power, and other operation and maintenance expenses totaling $15.4 million on the accompanying condensed consolidated statements of (loss)/income have been made to conform with the current period presentation. The condensed consolidated statement of cash flows has also been reclassified to exclude from cash flows from operations the change in accounts payable related to capital projects. This accounts payable reclassification was also made for CL&P, PSNH and WMECO.

12.

SUBSEQUENT EVENTS

Beginning with the quarter ended September 30, 2005, the operations of SESI, SECI-NH, Woods Network and Woods Electrical were presented as discontinued operations as a result of meeting certain criteria requiring this presentation. As a result, NU's condensed consolidated statements of (loss)/income for the three months ended March 31, 2005 and 2004 included in this report on Form 10-Q also present the operations for SESI, SECI-NH, Woods Network, and Woods Electrical as discontinued operations. Under this presentation, revenues and expenses of these businesses are included in the loss from discontinued operations on the condensed consolidated statements of (loss)/income for all prior periods. Summarized financial information for the discontinued operations is as follows.

	For the Three Months Ended
(Millions of Dollars)	March 31, 2005	March 31, 2004
Operating revenue	$ 35.1	$ 40.6
Restructuring and impairment charges	$ 24.0	$ -
Loss before income tax benefit	$(28.2)	$ (0.3)
Income tax benefit	$(11.0)	$ -
Net loss	$(17.2)	$ (0.3)

Included in discontinued operations for the three months ended March 31, 2005 and 2004 are $3.5 million and $1.6 million, respectively, of intercompany revenues that are not eliminated in consolidation due to the separate presentation of discontinued operations. NU does not expect that after the disposal it will have significant ongoing involvement or continuing cash flows with the entities presented in discontinued operations.

NU's condensed consolidated balance sheets were not impacted by this revision. At September 30, 2005, the assets and liabilities of these companies totaled $136.2 million and $118.4 million, respectively, as those amounts are not significantly different than those reported on the balance sheets included herein.

On November 7, 2005, NU announced, as disclosed in its third quarter 2005 report on Form 10-Q, it would exit the remainder of its merchant energy business segment, which includes the retail marketing business and the competitive generation business.

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 March 31, 2005, and the related condensed consolidated statements of (loss)/income and cash flows for the three-month periods ended March 31, 2005 and 2004. These interim financial statements are the responsibility of the Company’s management.

We conducted our reviews in accordance with 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 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, NU Enterprises, Inc., recorded significant restructuring and impairment charges in the quarter ended March 31, 2005 in connection with its decision to exit certain businesses.

As discussed in Notes 1A and 12, the consolidated financial statements for all periods presented have been restated to reflect certain components of the Company’s energy services businesses as discontinued operations.

We have previously audited, in accordance with 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 (November 22, 2005 as to Notes 1B, 1H, 1V, 13, 15 and 17), 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.

As discussed in Note 11, the Company has restated the condensed consolidated statement of cash flows for the three months ended March 31, 2004.

/s/	Deloitte & Touche LLP
	Deloitte & Touche LLP

Hartford, Connecticut

May 9, 2005 (November 22, 2005 as to Notes 1A, 1L, 2, 8, 10 and 12)

NORTHEAST UTILITIES AND SUBSIDIARIES

Item 2.

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 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 NU’s original 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:

In March 2005, Northeast Utilities (NU or the company) concluded its review of its competitive energy businesses. NU decided that it would exit the wholesale marketing business and divest its energy services businesses. NU decided to retain its competitive retail energy marketing business and its 1,443 megawatts (MW) of competitive generation assets.

NU reported consolidated losses of $117.7 million, or $0.91 per share in the first quarter of 2005, compared with earnings of $67.4 million, or $0.53 per share, in the same period of 2004.

NU Enterprises lost $167.4 million in the first quarter of 2005, compared with earnings of $18.8 million in the first quarter of 2004. The 2005 losses were due primarily to charges related to the decision to exit the wholesale marketing and energy services businesses. First quarter 2005 NU Enterprises results also were affected by a $25.7 million after-tax negative movement in the value of certain natural gas contracts signed in 2004 to hedge Select Energy, Inc.'s (Select Energy) wholesale electricity positions. These positions were balanced in the first quarter of 2005 and will have no impact on future earnings.

The Utility Group earned $53.6 million in the first quarter of 2005, compared with earnings of $53.4 million in the first quarter of 2004.

NU projects regulated company 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.

The decision to exit the wholesale marketing business has and is expected to continue to reduce the risk profile of NU Enterprises in 2005. Until exiting the wholesale marketing business, however, NU Enterprises will continue to be exposed to certain market risks for existing contracts until they expire or are divested.

Regulatory Items:

On April 7, 2005, the Connecticut Siting Council (CSC) approved construction of a 69-mile 345 kilovolt (kV) transmission project that The Connecticut Light and Power Company (CL&P) has proposed to build with United Illuminating (UI) between Middletown and Norwalk, Connecticut. CL&P would own 80 percent of the project, which is expected to cost between $840 million and $990 million.

On April 4, 2005, the New Hampshire Supreme Court upheld the New Hampshire Public Utilities Commission’s (NHPUC) approval of Public Service Company of New Hampshire’s (PSNH) Northern Wood Power Project, which involves converting one of PSNH’s three existing 50 megawatt coal-burning units at Schiller Station in Portsmouth, New Hampshire to burn wood chips. The court rejected claims from competing wood-fired generating plants that PSNH’s project was not in the public interest.

The NHPUC will hold hearings on the allowed return on equity (ROE) on PSNH’s generation investments. Any changes would apply prospectively, as the NHPUC deems appropriate. PSNH currently earns an 11 percent ROE on its generation investments. The NHPUC has scheduled hearings in this docket and a decision is expected in June 2005.

Liquidity:

CL&P sold $200 million of first mortgage bonds in April 2005. Proceeds were used to repay short-term borrowings.

Cash flows from operations decreased by $138.8 million to $188.5 million for the first quarter of 2005 from $327.3 million for the first quarter of 2004.

Overview

Consolidated: NU lost $117.7 million, or $0.91 per share, in the first quarter of 2005, compared with net income of $67.4 million, or $0.53 per share, in the first quarter of 2004. A summary of NU's earnings/(losses) by major business line for the first quarters of 2005 and 2004 is as follows:

	For the Three Months Ended March 31,
(Millions of Dollars)	2005	2004
Utility Group	$ 53.6	$53.4
NU Enterprises (1)	(167.4)	18.8
Parent and Other	(3.9)	(4.8)
Net (Loss)/Income	($117.7)	$67.4

(1)

The NU Enterprises losses include losses totaling $17.2 million and $0.3 million for the three months ended March 31, 2005 and 2004, respectively, which are classified as discontinued operations.

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 first quarter of 2005, NU Enterprises recorded an after-tax mark-to-market charge of $120.1 million ($188.9 million pre-tax) associated with certain wholesale electric contracts it is seeking to divest and $29.9 million of after-tax ($45.5 million pre-tax) restructuring and impairment charges.

Those charges exclude a negative after-tax mark-to-market charge of $25.7 million on certain wholesale natural gas contracts signed in 2004 to 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 out in the first quarter of 2005 and will have no impact on future earnings.

Excluding the restructuring charges and mark-to-market charge on natural gas contracts noted above, NU Enterprises earned $8.3 million in the first quarter of 2005, compared with earnings of $18.8 million in the first quarter of 2004. NU Enterprises' earnings in the first quarter of 2005 were favorably impacted by the net increase in the mark-to-market of one wholesale energy trading contract of $9.2 million after-tax, offset by after-tax losses on construction

contracts at NU Enterprises' energy services businesses totaling $3.1 million. In 2004, NU Enterprises' wholesale margins were much stronger in the first quarter of 2004 than in the other quarters of the year due to contract pricing terms.

For information regarding these charges, see Note 2, "Wholesale Contract Market Changes and Restructuring and Impairment Charges," to the condensed consolidated financial statements.

NU's condensed consolidated statements of (loss)/income for the three months ended March 31, 2005 and 2004 present the operations for the following companies as discontinued operations as a result of meeting certain criteria in the third quarter of 2005 requiring this presentation:

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

Select Energy Contracting, Inc. - New Hampshire (including Reeds Ferry Supply Co., Inc. (Reeds Ferry)) (SECI-NH), a division of Select Energy Contracting, Inc. (SECI);

Woods Network Services, Inc. (Woods Network); and

Woods Electrical Co., Inc. (Woods Electrical).

Utility Group:The Utility Group is comprised of CL&P, PSNH, Western Massachusetts Electric Company (WMECO), and Yankee Gas Services Company (Yankee Gas), including their transmission, distribution and generation businesses. After payment of preferred dividends, earnings at the Utility Group increased by $0.2 million to $53.6 million in the first quarter of 2005 compared with $53.4 million in 2004. Utility Group earnings were virtually the same in 2005 as compared with 2004 as retail rate increases were offset by lower sales and higher pension, depreciation, and interest expense. A summary of Utility Group earnings by company for the three months ended March 31, 2005 and 2004 is as follows:

	For the Three Months Ended March 31,
(Millions of Dollars)		2005	2004
CL&P Distribution		$ 19.0	$ 21.2
CL&P Transmission		6.2	5.0
Total CL&P *		25.2	26.2

PSNH Distribution and Generation		6.9	10.4
PSNH Transmission		1.9	1.4
Total PSNH		8.8	11.8

WMECO Distribution		4.0	2.7
WMECO Transmission		0.7	0.8
Total WMECO		4.7	3.5

Yankee Gas		14.9	11.9

Total Utility Group Net Income		$53.6	$53.4

*After preferred dividends.

CL&P’s first quarter 2005 results were slightly lower due to lower kilowatt-hour (kWh) sales, which decreased 0.6 percent compared with the same period of 2004, primarily in the industrial sales class, as well as higher depreciation, interest, and pension expense. Those cost increases and sales declines were offset by a $25 million annualized distribution rate increase that took effect on January 1, 2005 and higher transmission earnings.

PSNH earnings decreased due to higher operating costs, including depreciation, operation and other expenses. PSNH’s retail sales decreased 2.7 percent in the first quarter of 2005, compared with the same period of 2004, primarily due to an 11.5 percent decrease in industrial sales. The decrease in industrial retail sales is primarily the result of the loss of three large industrial customers.

WMECO earnings increased due primarily to a $6 million annualized distribution rate increase that took effect on January 1, 2005 which more than offset higher interest and pension expense. WMECO’s retail sales rose 0.4 percent in the first quarter of 2005, compared with the same period of 2004.

Yankee Gas earnings rose due to a $14 million annualized rate increase that took effect on January 1, 2005 that more than offset higher operating costs. Yankee Gas’s firm natural gas retail sales decreased 2.3 percent in the first quarter of 2005, compared with the first quarter of 2004.

Included in Utility Group earnings are earnings related to the transmission business. Transmission business earnings were $8.8 million in the first quarter of 2005, compared with $7.2 million in the first quarter of 2004. The increase was driven primarily by higher transmission rates related to a larger transmission rate base.

NU Enterprises: NU Enterprises is the parent of Northeast Generation Company (NGC), Northeast Generation Services Company (NGS), Select Energy, SESI and their respective subsidiaries and 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 will be exiting. The merchant energy segment will include 1,296 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 on a going forward basis a nd NGS. The energy services

businesses consist of the E.S. Boulos Company, Woods Electrical, and NGS Mechanical, Inc., which are subsidiaries of NGS, SECI, Reeds Ferry, HEC/Tobyhanna Energy Project, Inc., and HEC/CJTS Energy Center, LLC, which are subsidiaries of SESI and Woods Network. The businesses will be divested in a manner that maximizes their values. SESI, SECI-NH, Woods Network, and Woods Electrical are classified as discontinued operations.

NU Enterprises lost $167.4 million in the first quarter of 2005, compared with earnings of $18.8 million in the first quarter of 2004. A summary of NU Enterprises’ (losses)/earnings by business for the first quarter of 2005 and 2004 is as follows:

	For the Three Months Ended March 31,
(Millions of Dollars)	2005	2004
Merchant Energy	$(138.9)	$19.1
Energy Services, Parent and Other (1)	(28.5)	(0.3)
Net (Loss)/Income	$(167.4)	$18.8

(1)

The energy services, parent and other losses include losses totaling $17.2 million and $0.3 million for the three months ended March 31, 2005 and 2004, respectively, which are classified as discontinued operations.

In the first quarter of 2005, NU Enterprises recorded an after-tax mark-to-market charge of $120.1 million ($188.9 million pre-tax) associated with certain wholesale electric contracts it is seeking to divest. 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. This charge consists of the following components:

An after-tax loss of $164.2 million ($257.7 million pre-tax) associated with the 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;

After-tax mark-to-market contract asset write-offs of $23.3 million ($36.6 million pre-tax) directly relating to the long-term wholesale electricity contracts;

After-tax mark-to-market gains of $59.9 million ($94 million pre-tax) on retail marketing supply contracts associated with marking-to-market certain wholesale electricity positions that were obtained to support Select Energy's retail marketing contracts. 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 were required to be marked-to-market;

After-tax mark-to-market gains of $16.5 million ($25.8 million pre-tax) were recorded for other wholesale contracts related to electricity that would have been delivered to customers primarily in 2005 and 2006. As a result of exiting the wholesale marketing business, these contracts were also required to be marked-to-market. Prior to the decision to exit the wholesale marketing business, it was management's intention to deliver the electricity to the customer. As such, accrual accounting was used through December 31, 2004. Under accrual accounting, earnings would have been recorded as the electricity would have been delivered in 2005 and 2006;

An after-tax loss of $9 million ($14.4 million pre-tax) associated with a contract termination payment.

Also in the first quarter of 2005, NU Enterprises recorded an after-tax loss of $29.9 million ($45.5 million pre-tax) relating to restructuring and impairment charges. In March 2005, NU Enterprises hired an outside firm, FMI Corp., to assist in valuing its energy services businesses and assist in their divestiture. Based in part on that firm's work, the company concluded that $19.2 million after-tax ($29.1 million pre-tax) of goodwill associated with those businesses and $6.1 million after-tax ($9.2 million pre-tax) of intangible assets were impaired. An after-tax impairment charge of $25.3 million ($38.3 million pre-tax) was recorded. In addition, an exclusivity agreement intangible asset totaling $4.6 million after-tax ($7.2 million pre-tax) related to the merchant energy business was determined to be impaired and was written off. NU Enterprises has initiated the process of divesting those businesses and intends to compl ete that process by the end of 2005. NU Enterprises may record additional charges as the divestiture is completed.

A portion of these impairment charges totaling $14.6 million after-tax ($24 million pre-tax) is included in loss from discontinued operations on the condensed consolidated statements of (loss)/income as the charges relate to service companies that are presented as discontinued operations.

Aside from the restructuring charges and the marking-to-market of the wholesale natural gas positions, NU Enterprises earned $8.3 million in the first quarter of 2005, compared with earnings of $18.8 million in the first quarter of 2004. First quarter 2005 earnings were favorably impacted by the net increase in the mark-to-market of one wholesale energy trading contract of $9.2 million after-tax.

Aside from the impairments, the energy services, parent and other businesses lost $3.2 million in the first quarter of 2005 compared with losses of $0.3 million in the same period of 2004. The weaker performance was due to reserves taken against certain construction contracts.

Parent and Other: Parent company and other expenses totaled $3.9 million in the first quarter of 2005, compared with $4.8 million in the same quarter of 2004. Results in 2005 were negatively affected by a $2.2 million charge associated with higher manufactured gas plant environmental liabilities at HWP's Mt. Tom coal-fired unit. First quarter 2004 results reflected a write-down of approximately $1.5 million associated with a note receivable from an operator of renewable energy projects.

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 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 sold or until the commodities are delivered, 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 March 31, 2005, NU had $74 million of cash and cash equivalents compared with $47 million at December 31, 2004.

Cash flows from operations decreased by $138.8 million from $327.3 million for the first three months of 2004 to $188.5 million for the first three 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. The decrease in operating cash flows is also due to changes in working capital items, primarily receivables and unbilled revenues, investments in securitizable assets and accounts payable. Receivables and unbilled revenues, increased in part due to CL&P rate increases in the first quarter of 2005 for transitional standard offer (TSO) and Federally Mandated Congestion Costs (FMCC) charges, higher Yankee Gas receivables as a result of the seasonality of that business and higher r eceivable levels at NU Enterprises due to an increased number of customers and level of sales and increased gas volumes and sales. 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. These decreases are offset by a decrease in amounts that Select Energy has on deposit with unaffiliated counterparties and brokerage firms.

On March 31, 2005, NU paid a dividend of $0.1625 per share. On April 12, 2005, the NU Board of Trustees approved a common dividend of $0.1625 per share, payable June 30, 2005, to shareholders of record at June 1, 2005.

NU's capital expenditures totaled $166.8 million in the first three months of 2005, compared with $148.6 million in the first three 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 January 14, 2005, Fitch Ratings removed NU from watch-negative and affirmed NU and CL&P credit ratings with a negative outlook. On February 16, 2005, Moody's Investors Service downgraded by one notch the securities of NU, CL&P and NGC. The securities of WMECO were downgraded two notches and the ratings of PSNH securities were affirmed. All NU securities were placed on a stable outlook by Moody's.

Utility Group: At March 31, 2005, the Utility Group had $152 million of borrowings on its $400 million revolving credit line. 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 March 31, 2005, CL&P had sold $100 million to that financial institution.

On April 7, 2005, CL&P closed on the sale of $100 million of 10-year first mortgage bonds carrying a coupon rate of 5.0 percent and $100 million of 30-year first mortgage bonds carrying a coupon rate of 5.625 percent. Proceeds were used to repay short-term borrowings.

PSNH and Yankee Gas are expected to issue $50 million of first mortgage bonds later in 2005 and WMECO is expected to issue $50 million of senior unsecured notes. In the second quarter of 2005, Yankee Gas received approval from the Connecticut Department of Public Utility Control (DPUC) regarding its issuance. The application for the WMECO issuance is pending before the Massachusetts Department of Telecommunications and Energy (DTE).

NU Enterprises: At March 31, 2005, NU Enterprises had $91.4 million of letters of credit (LOCs) and $115 million of cash borrowings outstanding on NU parent's $500 million revolving credit line. During the first quarter of 2005, Select Energy also posted approximately $13 million in new deposits with unaffiliated counterparties and brokerage firms related to the mark-to-market on its natural gas contracts that were used in Select Energy's energy sourcing activities.

Although the charges recorded in the first quarter of 2005 were primarily non-cash in nature, NU Enterprises' exiting the wholesale marketing business and divesting of the energy services businesses could have an impact on NU Enterprises' liquidity requirements. 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 also 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, may require NU Enterprises to make upfront payments to the counterparties in such transactions.

Nuclear Decommissioning and Plant Closure Costs

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

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.

Business Development and Capital Expenditures

Utility Group:

Connecticut – CL&P: On April 7, 2005, the CSC approved a proposal by CL&P and UI to build a 69-mile 345 kV transmission line from Middletown, Connecticut to Norwalk, Connecticut. The project is expected to cost between $840 million and $990 million with CL&P owning 80 percent of the project. Approximately 24 miles of the 345 kV line will be built underground with the balance being built overhead. Towns along the overhead section opposed the project and an appeal of the CSC’s project approval to the Connecticut Superior Court is possible. 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. At March 31, 2005, CL&P has capitalized $21 million associated with this project.

In March 2005, CL&P signed contracts for construction of a 345 kV line between Bethel, Connecticut and Norwalk, Connecticut. Line construction activities began in April 2005, although a considerable amount of substation work had been completed earlier. CL&P expects to complete the project by the end of 2006 at a cost of between $300 million and $350 million. At March 31, 2005, CL&P has capitalized $77 million associated with this project.

On May 3, 2005, hearings resumed at the CSC on CL&P’s construction of two 115 kV underground transmission lines between Norwalk, Connecticut and Stamford, Connecticut. 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 March 31, 2005, CL&P has capitalized $4 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. The project has received CSC approval, and federal and New York state approvals are expected in 2005. Assuming final approval is received in 2005, construction activities are scheduled to begin in the fall of 2006 and management expects the line will be in service by 2007. At March 31, 2005, CL&P has capitalized $7 million of costs related to this project.

Proposed legislation in the current session of the Connecticut General Assembly would provide for new demand-side and supply-side initiatives to address anticipated rising capacity costs caused by changes in the wholesale electricity market rules. The draft bill contemplates promotion of distributed generation to help meet the state's generation shortfall. The draft bill also would require utilities to enter into long-term electricity contracts with generators under a request for proposal process administered by the DPUC. The draft bill is expected to undergo revisions over the next month with a potential vote occurring prior to the end of the session in early June 2005.

Connecticut – Yankee Gas: In January 2005, Yankee Gas held formal groundbreaking for a 1.2 billion cubic foot liquefied natural gas storage facility in Waterbury, Connecticut. Construction of the facility began in March and is expected to be completed in 2007 in time for the 2007-2008 heating season. The facility is expected to cost $108 million and through March 31, 2005, Yankee Gas has capitalized $17.5 million related to this project.

New Hampshire: On April 4, 2005, the New Hampshire Supreme Court dismissed an appeal of the NHPUC's approval of PSNH’s conversion of a 50 megawatt coal-burning unit at Schiller Station to burn wood chips. The appeal was filed by the owners of other New Hampshire wood-burning generating units. Construction activities associated with the $75 million project began in late 2004 and are expected to be completed in the second half of 2006. At March 31, 2005, PSNH has capitalized $29 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 has denied PSNH permission to construct this crossing. On April 12, 2005, B&M filed a request for a declaratory ruling and injunctive relief with the Rockingham County (New Hampshire) Superior Court, asking the court to rule that PSNH had no legal entitlement to such a crossing. On April 20, 2005, PSNH filed a petition for condemnation against B&M and certain of its affiliates at the NHPUC. Failure to receive authority in a timely manner to build the conveyor over the railroad track could delay the construction and operation of the project.

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 is expected to be complete by mid-2006. At March 31, 2005, HWP has capitalized $0.4 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 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. 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, the transmission business is assuming an ROE that is more conservative than that reflected in current transmission rates.

Utility Group Regulatory Issues and Rate Matters

Transmission: 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 and June 1 of each year. Additionally, NU’s LNS tariff provides for a true-up to actual costs, which ensures that NU recovers its total transmission revenue requirements, including the allowed ROE. Through March 31, 2005, this true-up has resulted in the recognition of a $2.6 million regulatory liability for refund to electric distribution companies, including CL&P, PSNH and WMECO.

On June 14, 2004, the transmission business reached a settlement agreement with the parties to its rate case, which allows NU to implement formula-based rates as proposed with an allowed ROE of 11.0 percent. On September 16, 2004, the FERC approved the settlement agreement. Effective February 1, 2005, the ROE was increased from 11.0 percent to the aforementioned 12.8 percent. While management cannot at this time predict what the ultimate ROE will be, management does not believe the final approved ROE will result in a material impact on its financial statements. Transmission segment earning guidance previously provided assumed an ROE of between 11.0 percent and 12.0 percent.

A significant portion of NU’s transmission businesses’ revenue is from charges to CL&P, PSNH and WMECO. These companies recover transmission charges through rates charged to their retail customers. WMECO has a rate tracking mechanism to track transmission costs charged in distribution rates to the actual amount of transmission charges incurred. Higher transmission charges to WMECO were reflected in a $6 million energy delivery rate increase WMECO implemented January 1, 2005 following regulatory approval in December 2004. The 2004 rates set in the CL&P distribution rate case contained a level of transmission revenue sufficient to recover CL&P’s 2004 transmission costs. 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 began incurring in 2005. That applicatio n is still pending. Additionally, legislation to allow CL&P a retail transmission tracking mechanism similar to WMECO’s is pending before the Connecticut legislature. The June 2005 PSNH rate increase from its settlement agreement contemplates higher transmission costs. However, PSNH currently does not have a transmission rate tracking mechanism that tracks transmission costs.

LICAP: In March 2004, the New England System Operator (ISO-NE) filed a proposal at the FERC to implement locational installed capacity (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 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 is expected on June 15, 2005.

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, 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, CL&P will incur LICAP charges, in part because Connecticut is a constrained area with insufficient generation assets. CL&P could incur LICAP costs totaling several hundred million dollars annually. These costs would 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 recover these costs from their customers.

Connecticut - CL&P:

Public Act No. 03-135 and Rate Proceedings:Under Public Act No. 03-135, CL&P is allowed to collect a fixed procurement fee of 0.50 mills per kWh from customers who purchase TSO service. 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 and has not indicated when the schedule will be resumed. The variable portion of the procurement fee has not yet been reflected in earnings. The schedule in this proceeding has not been determined, but CL&P expects to file its calculations with the DPUC in the second quarter of 2005.

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. If the DPUC does not approve this deferral, CL&P’s application provides for an alternate proposal to increase its retail transmission rate to recover an additional $7.6 million on an annual basis, that became effective in 2005. Under this proposal the increase would equal $0.00031 per kWh, and would represent approximately a 0.2 percent increase in overall rates as of February 1, 2005. The discovery process is underway, and a decision in this docket is expected by the end of the second quarter of 2005.

CTA and SBC Reconciliation: The CTA allows CL&P to recover stranded costs, such as securitization costs associated with the rate reduction bonds, amortization of regulatory assets, and independent power 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 DPUC, which compares 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. 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 expires 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, 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 February 1, 2005, CL&P filed for a 1.6 percent increase to rates ($29.2 million) to collect additional FMCC from customers effective May 1, 2005. The increase is necessary to collect costs related to additional RMR contracts with ISO-NE related to two generating plants located in southwest Connecticut. The RMR contracts have preliminary approval for billing from the FERC and are subject to a future review by the FERC prior to final approval.

On April 25, 2005, CL&P filed a supplemental request to increase rates by an additional $71.1 million for a new RMR contract with ISO-NE for an unaffiliated generator which has been recently approved by the FERC. When combined with the February 1, 2005 request of $29.2 million, CL&P is requesting approval from the DPUC to increase FMCC rates effective June 1, 2005 by $100.3 million or 6 percent annually. If the current request for a June 1, 2005 rate increase is approved, the RMR costs being recovered in the FMCC charge would total $186 million. In addition, the FMCC rates are also recovering $22 million related to southwest Connecticut summer emergency generation resources billed to CL&P by ISO-NE.

New Hampshire:

Transition Energy Service and Default Energy Service (TS/DS):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 investment. 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 its order approving a TS/DS rate of $0.0649 per kWh for the period February 1, 2005 through January 31, 2006. This TS/DS rate currently includes an 11 percent ROE on PSNH's generation assets. The generation ROE is currently the subject of a NHPUC docket and PSNH has filed testimony supporting an 11.4 percent ROE on its generation assets. The NHPUC staff is advocating an ROE of 9.08 percent. The NHPUC has scheduled hearings in the docket and a decision is expected in June 2005. A one percent change in ROE would impact PSNH's annual net income by approximately $1 million.

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 billed with stranded costs, and TS/DS revenues billed with TS/DS costs. The NHPUC reviews the filing, including a prudence review of PSNH's generation operations. The cumulative deferral of SCRC revenues in excess of costs was $224.2 million at March 31, 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 $399.1 million to $174.9 million.

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 March 31, 2004, the PSNH 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.

Wholesale Distribution Rate Case:On March 30, 2005, PSNH filed with the FERC a $1.8 million settlement agreement regarding its wholesale distribution rate case and requested that the FERC allow the revised rates to become effective on June 1, 2005. This FERC filing was necessary due to the reclassification of certain assets from PSNH's transmission business to distribution business. The settlement agreement allows PSNH to recover certain delivery costs arising from the provision of wholesale delivery service to another New Hampshire utility. Management believes that the FERC will allow PSNH to recover these costs under the terms of the settlement agreement.

Environmental Legislation:The New Hampshire legislature is considering a bill that would place strict limitations on the level of mercury that PSNH’s existing generation plants can emit. Management is reviewing possible legislation and 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, non-generation mercury mitigation programs, and possible retirement of one or more of its generating units. 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. On May 4, 2005, the New Hampshire legi slature voted to retain the bill for further consideration in the 2006 session.

Massachusetts:

Transition Cost Reconciliation and Other Filings:On March 31, 2005, WMECO filed its 2004 transition cost reconciliation with the DTE. This filing reconciled the recovery of generation-related stranded costs for calendar year 2004. The DTE has combined the 2003 transition cost reconciliation filing, standard offer service and default service reconciliation, the transmission cost adjustment filing, and the 2004 transition cost reconciliation filing into a single proceeding. A hearing schedule for the combined proceeding is expected to be set in May 2005. 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.

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, NGC’s 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 announced it will exit. Management is evaluating options to maximize the value of the generation assets, including supplying retail 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 E.S. Boulos Company, Woods Electrical, and NGS Mechanical, Inc., which are subsidiaries of NGS, SECI, Reeds Ferry, HEC/Tobyhanna Energy Project, Inc., and HEC/CJTS Energy Center LLC, which are subsidiaries of SESI and Woods Network. The subsidiaries of NGS provide third-party electrical services. Woods Network is a network design,

products and services company. SESI performs energy management services for large commercial customers, institutional facilities and the United States government and energy-related construction services. SESI, SECI-NH, Woods Network, and Woods Electrical are classified as discontinued operations.

Outlook: NU is not providing 2005 earnings guidance for NU Enterprises because earnings at NU Enterprises 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 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 will be reflected in earnings and could be significant.

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 excess of the amounts currently included in the mark-to-market charge.

Additional asset impairments or losses on disposals. As the energy 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 energy services businesses, and the fair value of those guarantees may be recognized if they become guarantees to unaffiliated third parties.

The recognition of additional restructuring costs. Costs associated with certain restructuring activities and employee costs will be recognized in future periods.

Intercompany Transactions: There were no CL&P TSO purchases from Select Energy in the first quarter of 2005, compared to $148.5 million of CL&P standard offer purchases from Select Energy in the first quarter of 2004. Other energy purchases between CL&P and Select Energy totaled $14.2 million in the first quarter of 2005 compared to $30 million in the first quarter of 2004. WMECO purchases from Select Energy in the first quarter of 2005 totaled $20.5 million, compared to $32 million in the first quarter of 2004. In February 2005, WMECO entered into a contract with Select Energy under which Select Energy will provide default service from April through June of 2005. These amounts are eliminated or will be eliminated in consolidation.

Included in Select Energy’s restructuring and impairment charges is a negative $54.5 million pre-tax mark-to-market charge 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 loss was recorded by Select Energy for the intercompany contract between Select Energy and WMECO for default service from April to June of 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.

NU Enterprises' Market and Other Risks

Overview:The decision to exit the wholesale marketing business has and is expected to continue to reduce the risk profile of NU Enterprises in 2005. Until exiting the wholesale marketing business, NU Enterprises will continue to be exposed to certain market risks for existing contracts until they expire or are divested. The merchant energy business segment 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. Contracts with lower quantities and less complex terms will result in an NU Enterprises risk profile that is reduced compared to the wholesale marketing business that the company is exiting. Market risk represents the loss that may affect the merchant energy business segment’s financial results, primarily Select Energy, due to adverse changes in co mmodity 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 reviewed by the NU Board of Trustees on an as needed basis.

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 the weather. 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 electricity or sell exc ess 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 pricing terms of full requirement contracts and of supply contracts can affect the timing of Select Energy's margins. Many full requirements contracts have higher prices in certain months, while many supply contracts have one price for the entire contract term. Accordingly, Select Energy's margins will tend to be higher in the months when the full requirements contract price is higher and lower or could be negative when the full requirements contract price is lower.

Energy Sourcing Activities: In June 2004, Select Energy began purchasing fixed-price electricity and some electricity with prices indexed to gas for 2005 and 2006 in anticipation of winning full requirements contract sales and sales to load-serving entities. Purchasing electricity in advance created the risk of electricity price decreases before the full requirement quantities are contracted and before contract prices are known.

To mitigate the risk of electricity price decreases on the fixed-price electricity that was purchased, Select Energy in June 2004 began selling wholesale natural gas contracts for 2005 and 2006. The intended result of this risk mitigation strategy was that decreases in the value of the fixed-price electricity purchase contracts would be offset in part by increases in the value of the gas contracts, and vice versa. Select Energy intended to purchase natural gas when quantities and prices of electricity are secured by full requirements contracts or sales contracts with load-serving entities. Natural gas was sold in this risk mitigation strategy due to the high liquidity of the natural gas market compared to the low liquidity of physical electricity supply in New England.

The electricity contracts were accounted for on the accrual basis through 2004, which would have resulted in earnings recognition when the electricity would have been delivered to customers in 2005 and 2006. These electricity purchase contracts were to be used to meet electricity sales contract requirements, which was a key component of the merchant energy wholesale marketing business. Until the decision to exit wholesale marketing activities was made, management believed that this electricity would be delivered to its customers. The decision in March 2005 to exit the wholesale marketing business changed management’s conclusion regarding the likelihood that many 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 natural gas contracts are recorded at current fair value. At March 31, 2005 the fair value of the natural gas contracts was a negative $80.9 million. The changes in fair values totaling a negative $77.7 million increased fuel, purchased and net interchange power in 2004. An additional change in fair value of a negative $40.7 million increased fuel, purchased and net interchange power in the first quarter of 2005. $37.5 million of the negative fair value was realized in the first quarter of 2005, much of which was deposited with a broker in 2004. Of the total fair value of negative $80.9 million, approximately negative $58.9 million relates to 2005 with approximately negative $22 million related to 2006.

In the first quarter of 2005, the electricity and natural gas positions that were part of energy sourcing activities were balanced, and changes in the fair value of these contracts are no longer expected to impact earnings. Overall, energy sourcing activities resulted in an after-tax loss of $28 million, comprised of an after-tax loss of $48 million in 2004 and an after-tax gain of $20 million in the first quarter of 2005. Cash flows from these contracts are expected to be positive for the remainder of 2005 and 2006 as the electricity positions are realized.

The electricity and natural gas contracts are included in non-trading derivative assets and liabilities in the table in Note 3, "Derivative Instruments," to the condensed consolidated financial statements.

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.

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.

In March 2004, the 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 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 is expected on June 15, 2005.

Depending on the pricing curves that are ultimately implemented, LICAP could produce significant benefits for generation assets either owned or contracted by NU Enterprises. NU Enterprises owns or contracts approximately 300 MW of generation assets in Connecticut and approximately 1,300 MW of generation assets in western Massachusetts.

Hedging and Other Non-Trading:For information on derivatives used for hedging purposes and non-trading derivatives, see Note 3, "Derivative Instruments," to the condensed consolidated financial statements.

Wholesale Contracts Defined as "Energy Trading": Historically, energy trading transactions at Select Energy have included financial transactions and physical delivery transactions for electricity, natural gas and oil in which Select Energy attempted to profit from changes in market prices. Energy trading contracts are recorded at fair value, and changes in fair value affect net income.

At March 31, 2005 and December 31, 2004, Select Energy had trading derivative assets and trading derivative liabilities as follows:

(Millions of Dollars)	2005	2004
Current trading derivative assets	$62.2	$49.6
Long-term trading derivative assets	51.0	31.7
Current trading derivative liabilities	(60.6)	(46.2)
Long-term trading derivative liabilities	(5.1)	(5.5)
Portfolio position	$47.5	$29.6

There can be no assurances that Select Energy will realize cash corresponding to the present positive net fair value of its trading positions. Numerous factors could either positively or negatively affect the realization of the net fair value amount in cash. These include the sales price to be received on the sale of these contracts, the volatility of commodity prices until the contracts are sold, the outcome of future transactions, the performance of counterparties, and other factors.

Select Energy has policies and procedures requiring all trading positions to be marked-to-market at the end of each business day and segregating responsibilities between the individuals actually trading (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 energy trading contracts are identified and segregated in the table of fair value of contracts at March 31, 2005. A description of each method is as follows: 1) prices actively quoted primarily represent New York Mercantile Exchange futures 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 one contract for which a portion of the contract's fair value is determined based on a model or other valuation method. The model utilizes natural gas prices and a conversion factor to electricity. The fair value of this contract at December 31, 2004 was $5.5 million, net of a modeling reserve that reduced the value of the c ontract to zero for years beyond 2007 that did not have liquid prices. In the first quarter of 2005 the modeling reserve was reversed, and the fair value of this contract at March 31, 2005, which now includes prices provided by external sources for 2008, is now $25.5 million. Broker quotes for electricity at locations for which Select Energy has entered into deals are available through the year 2008. For all natural gas positions, broker quotes extend through 2013.

Generally, valuations of short-term contracts derived from quotes or other external sources are more reliable should there be a need to liquidate the contracts, while valuations for longer-term contracts are less certain. Accordingly, there is a risk that contracts will not be realized at the amounts recorded. However, Select Energy has obtained corresponding purchase or sale contracts for a large portion of the trading contracts that have maturities in excess of one year. Because these trading contracts are sourced, changes in the value of these contracts due to fluctuations in commodity prices are not expected to significantly affect Select Energy's earnings.

As of and for the quarters ended March 31, 2005 and December 31, 2004, the sources of the fair value of trading contracts and the changes in fair value of these trading contracts are included in the following tables. Intercompany transactions are eliminated and not reflected in the amounts below.

(Millions of Dollars)	Fair Value of Trading Contracts at March 31, 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	$(0.1)	$ 0.3	$ -	$ 0.2
Prices provided by external sources	2.8	18.8	11.4	33.0
Model based	-	3.1	11.2	14.3
Totals	$ 2.7	$22.2	$22.6	$47.5

(Millions of Dollars)	Fair Value of Trading Contracts at December 31, 2004
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	$0.7	$ -	$ -	$ 0.7
Prices provided by external sources	2.8	13.6	12.5	28.9
Totals	$3.5	$13.6	$12.5	$29.6

The fair value of energy trading contracts increased to $47.5 million at March 31, 2005 from $29.6 million at December 31, 2004. The change in the fair value of the trading portfolio is primarily attributable to the change in valuation technique on the contract that is marked to model.

Three Months Ended March 31,

2005

2004

(Millions of Dollars)

Total Portfolio Fair Value

Fair value of trading contracts outstanding

at the beginning of the year

$29.6

$32.5

Contracts realized or otherwise

settled during the period

(2.1)

(5.7)

Changes in fair value attributable to changes

in valuation techniques and assumptions

14.3

Changes in fair value of contracts

5.7

0.6

Fair value of trading contracts outstanding

at the end of the period

$47.5

$27.4

For further information regarding Select Energy's derivative contracts, see Note 3, "Derivative Instruments," and Note 7, "Comprehensive Income," to the condensed consolidated financial statements.

Changing Market: In general, the market for energy products has become shorter term in nature with less liquidity, market pricing information is less readily available and participants are sometimes unable to meet Select Energy's credit standards without providing cash or LOC support. Select Energy is being adversely affected by these factors, and there could be a continuing adverse impact on Select Energy.

Changes are occurring in the administration of transmission systems in territories in which Select Energy does business. As the market continues to evolve, there could be additional challenges or opportunities that management cannot determine at this time.

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 ex posure to credit risk, either positively or negatively, in that the counterparties may be similarly affected by changes to economic, regulatory or other conditions. At March 31, 2005, approximately 73 percent of Select Energy's counterparty credit exposure to wholesale and trading counterparties was collateralized or rated BBB- or better. Select Energy was provided $95.6 million and $57.7 million of counterparty deposits at March 31, 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 two levels to sub-investment grade, Select Energy could, under its present contracts, be asked to provide at March 31, 2005 approximately $500 million of collateral or LOCs to various unaffiliated counterparties and approximately $154 million to several independent system operators and unaffiliated LDCs, which management believes NU would currently be able to provide, subject to the Securities and Exchange Commission (SEC) limits. NU's credit ratings outlooks are currently stable or negative, but 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

Derivative Accounting and Fair Value Determination: The application of derivative accounting under SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities," as amended, is complex and requires management judgment in the several respects, including the determination of the fair value of derivatives. Most of the contracts comprising Select Energy’s wholesale and retail marketing activities are derivatives. The fair value of contracts in the trading portfolio and contracts that have been marked-to-market as restructuring charges has been determined by prices provided by external sources and actively quoted markets through 2008. Certain contracts have also been modeled for years after 2008 utilizing natural gas prices and a conversion factor to estimate electricity prices. Judgments made by management in determining the fair value of derivatives can have a significant impact on NU’s con solidated net income.

Evaluation of Discontinued Operations Presentation: In the first quarter of 2005, NU recorded restructuring and impairment charges associated with NU Enterprises' decision to exit the wholesale marketing business and to divest the energy services businesses in a separate restructuring line item within operating expenses. Management has evaluated the classification of these charges to determine if these charges should be presented as discontinued operations and as of March 31, 2005 concluded that these charges should not be classified as discontinued operations. Management will continue to evaluate this classification in the second quarter of 2005. Under current accounting guidance, in order for discontinued operations treatment to be appropriate, management must conclude that there is a component of a business that is "held for sale" for accounting purposes. During the third quarter of 2005, management determine d that it expects to divest four of the energy services businesses within the next year. Accordingly, at September 30, 2005, SESI, SECI-NH, Woods Network, and Woods Electrical were accounted for as discontinued operations.

Unbilled Revenues: In the first quarter of 2005, management adopted a new method to estimate unbilled revenues for CL&P, PSNH, WMECO, and Yankee Gas. The new method allocates billed sales to the current calendar month based on the daily load for each billing cycle. The billed sales are subtracted from total calendar month sales to estimate unbilled sales. The impact of adopting the new method was not material. The new method replaces the requirements method and the cycle method that were used periodically to test the requirements method.

Other Matters

Commitments and Contingencies: For further information regarding other commitments and contingencies, see Note 5, "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 March 31, 2005, see Note 5C, "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: On April 29, 2005, NU announced charges associated with the March 2005 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.

While the energy services businesses present a lower level of volatility and risk, the wholesale marketing business, until 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, rather than accrual, basis until disposed of or restructured. The earnings charge referred to above may not be adequate to absorb future negative price movements which may occur or if further charges are taken if the portfolio is sold or restructured.

In connection with its first quarter 2005 loss, NU has received a waiver of certain covenants in its loan agreements for the first quarter of 2005 and future losses may require NU to request additional waivers. NU cannot predict what impact the need for such waivers might have. In addition, Select Energy’s ability to function will continue to be dependant upon the financial reliability of its counterparties and its ability to manage its wholesale marketing portfolio of contracts and assets within acceptable risk parameters.

Risks Related to Retained Retail Competitive and Generation Businesses: In March 2005, NU announced it intended to stay in the retail competitive energy and generating 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.

The competitive generation business is also subject to these risks. In addition, 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.

Unless CL&P is able to increase rates to recover these construction costs on a timely basis, certain of NU’s and CL&P’s financial ratios may decline and CL&P’s ability to pay dividends to NU to support its common dividend and interest requirements may be weakened.

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 which may not be fully recoverable in rates. 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 months ended March 31, 2005:

	Income Statement Variances (Millions of Dollars) 2005 over/(under) 2004
	Amount			Percent
Operating Revenues:		$	434	24	%

Operating Expenses:
Fuel, purchased and net interchange power		448		38
Other operation		39		19
Wholesale contract market changes, net		189		100
Restructuring and impairment charges		21		100
Maintenance		-		-
Depreciation		3		6
Amortization		(6)		(21)
Amortization of rate reduction bonds		3		6
Taxes other than income taxes		-		-
Total operating expenses		697		43

Operating (Loss)/Income		(263)		(a)

Interest expense, net		4		7
Other Income, Net		-		-
(Loss)/income from continuing operations before income tax (benefit)/expense		(267)		(a)
Income tax (benefit)/expense		(99)		(a)
Preferred dividends of subsidiaries		-		-
Net loss from discontinued operations		(17)		(a)
Net (Loss)/Income		$	(185)	(a)	%

(a) Percent greater than 100.

Comparison of the First Quarter of 2005 to the First Quarter of 2004

Operating Revenues

Operating revenues increased $434 million in the first quarter of 2005, compared with the same period in 2004, due to higher revenues from NU Enterprises ($289 million), higher electric distribution revenues ($116 million), higher gas distribution revenues ($24 million), and higher regulated transmission revenues ($6 million).

The NU Enterprises’ revenue increase of $289 million is primarily due to additional third party volume ($172 million), higher revenues for the merchant retail energy business ($69 million) and higher revenues for the wholesale marketing business ($39 million). Higher revenues for the merchant retail energy business resulted from higher gas volumes ($27 million), higher electric volumes ($23 million), higher gas prices ($10 million), and higher electricity prices ($8 million). Higher revenues for the wholesale marketing business resulted from higher electricity prices ($60 million), trading ($12 million) and higher gas volumes ($12 million), partially offset by lower electric volumes ($44 million).

The electric distribution revenue increase of $116 million is primarily due to non-earnings components of CL&P, PSNH and WMECO retail rates ($106 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 ($13 million), partially offset by a decrease in retail sales volumes ($3 million). The non-earnings components increase of $106 million is primarily due to the pass through of higher energy supply costs ($90 million) and CL&P FMCC ($36 million), partially offset by lower wholesale revenues ($9 million) due to lower sales volumes, lower CL&P conservation and load management cost recoveries ($6 million) and lower transition cost recoveries for CL&P and WMECO ($4 million). Regulated retail sales decreased 1.0 percent in 2005 compared with 2004.

The higher gas distribution revenue of $24 million is primarily due to the increased recovery of gas costs ($19 million).

Transmission revenues increased $6 million in the first quarter of 2005, primarily due to a higher transmission investment base and higher expenses.

Fuel, Purchased and Net Interchange Power

Fuel, purchased and net interchange power expense increased $448 million in the first quarter of 2005, primarily due to higher purchased power costs for the Utility Group ($293 million) and higher wholesale costs at NU Enterprises ($156 million). The $293 million increase for the Utility Group is primarily due to an increase in the standard offer supply costs for CL&P and WMECO ($233 million), which includes higher third party supplier volume ($160 million), higher expenses for PSNH ($24 million) primarily due to higher energy and capacity purchases and higher Yankee Gas expenses ($19 million) primarily due to increased gas prices.

Other Operation

Other operation expenses increased $39 million in the first quarter of 2005, primarily due to higher CL&P reliability must run costs and other power pool related expenses ($21 million) and higher expenses for NU Enterprises ($12 million). The higher expenses for NU Enterprises were primarily due to higher expenses at the energy services businesses ($7 million), higher transmission expenses ($2 million) and higher pension expense ($1 million).

Wholesale Contract Market Changes, Net

See Note 2, "Wholesale Contract Market Changes and Restructuring and Impairment Charges," to the condensed consolidated financial statements for a description and explanation of these amounts.

Restructuring and Impairment Charges

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

Depreciation

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

Amortization

Amortization decreased $6 million in the first 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 first quarter of 2005 due to the repayment of a higher principal amount as compared to 2004.

Interest Expense, Net

Interest expense, net increased $4 million in the first 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 and higher interest rates for NU Parent.

Income Tax (Benefit)/Expense

Income tax (benefit)/expense decreased $99 million primarily due to lower income before tax expense and a lower effective tax rate due to write-offs of non-deductible goodwill and intangibles and increases in the deferred tax valuation allowance on state tax benefits at NU Enterprises.

Net Loss From Discontinued Operations

Beginning with the quarter ended September 30, 2005, the operations of SESI, SECI-NH, Woods Network and Woods Electrical were presented as discontinued operations as a result of meeting certain criteria requiring this presentation. Under this presentation, revenues and expenses of these businesses are included in the loss income from discontinued operations on the consolidated statements of income. See Note 12, "Subsequent Events," to the condensed consolidated financial statements for further information.

Exhibit 15

November 22, 2005

Northeast Utilities

107 Selden Street

Berlin, CT 06037

We have made a review, in accordance with standards of the Public Company Accounting Oversight Board (United States), of the unaudited interim financial information of Northeast Utilities and subsidiaries for the periods ended March 31, 2005 and 2004, as indicated in our report dated May 9, 2005 (November 22, 2005 as to Notes 1A, 1L, 2, 8, 10 and 12), (which report included explanatory paragraphs related to the Company’s recording of significant charges due to its decision to exit certain businesses and the restatement of certain financial information to reflect the presentation of certain components of the Company’s energy services businesses as discontinued operations); because we did not perform an audit, we expressed no opinion on that information.

We are aware that our report referred to above, which is included in the Form 8-K dated November 22, 2005, is incorporated by reference in Registration Statement Nos. 33-34622, 33-40156, 333-108712, 333-116725, 333-118276 and 333-128811 on Forms S-3 and Registration Statement Nos. 33-63023, 333-52413, 333-63144 and 333-106008 on Forms S-8 of Northeast Utilities.

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

/s/	Deloitte & Touche LLP
	Deloitte & Touche LLP

Hartford, Connecticut

Eversource Energy (ES) 8-KResults of Operations and Financial Condition