New England Power (NEWEN) 10-Q 2006 Q1 Quarterly report

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended June 30, 2005

OR

o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from                    to                    

Commission	Registrant, State of Incorporation	I.R.S. Employer
File Number	Address and Telephone Number	Identification No.
2-26651	New England Power Company	04-1663070
	(a Massachusetts corporation)
	25 Research Drive
	Westborough, Massachusetts 01582
	508.389.2000

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

YESþ NOo

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act)

YESo NOþ

The number of shares outstanding of each of the issuer’s classes of common stock, as of August 10, 2005, were as follows:

Registrant	Title	Shares Outstanding
New England Power Company	Common Stock, $20.00 par value (all held by National Grid USA)	3,619,896

NEW ENGLAND POWER COMPANY

FORM 10-Q — For the Quarter Ended June 30, 2005

	PAGE
PART I — FINANCIAL INFORMATION
Item 1. Financial Statements
Unaudited Condensed Statements of Income		3
Unaudited Condensed Statements of Retained Earnings		4
Unaudited Condensed Statements of Comprehensive Income		4
Unaudited Condensed Balance Sheets		5
Unaudited Condensed Statements of Cash Flows		7
Notes to Unaudited Condensed Financial Statements		8
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		22
Item 3. Quantitative and Qualitative Disclosures About Market Risk		25
Item 4. Controls and Procedures		26
PART II — OTHER INFORMATION
Item 1. Legal Proceedings		27
Item 4. Submission of Matters to a Vote of Security Holders		27
Item 5. Other Information		27
Item 6. Exhibits		27
Signature		28
Exhibit Index		29

PART I — FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

NEW ENGLAND POWER COMPANY

Condensed Statements of Income

Periods Ended June 30

(In thousands of dollars)

(UNAUDITED)

	Three Months
	2005		2004
			(Restated)
			(See Note F)
Operating revenue, principally from affiliates	$	110,779	$	114,978
Operating expenses:
Purchased electric energy:
Contract termination and nuclear unit shutdown charges		18,500		36,738
Other		26,024		3,837
Other operation		12,729		14,840
Maintenance		2,925		1,922
Amortization of stranded costs		17,674		17,667
Depreciation and amortization		5,105		4,790
Taxes, other than income taxes		4,340		4,293
Income taxes		6,884		11,741
Total operating expenses		94,181		95,828
Operating income		16,598		19,150
Other income:
Equity income		303		393
Other income, net		1,504		410
Operating and other income		18,405		19,953
Interest:
Interest on long-term debt		2,868		1,474
Other interest		447		214
Total interest		3,315		1,688
Net income	$	15,090	$	18,265

Per share data is not relevant because the Company’s common stock is wholly owned by
National Grid USA.

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

3

NEW ENGLAND POWER COMPANY

Condensed Statements of Retained Earnings

Periods Ended June 30

(In thousands of dollars)

(UNAUDITED)

	Three Months
	2005			2004
				(Restated)
				(See Note F)
Retained earnings at beginning of period	$	297,508		$	220,772
Net income		15,090			18,265
Dividends declared on cumulative preferred stock		(17	)		(19	)
Retained earnings at end of period	$	312,581		$	239,018

NEW ENGLAND POWER COMPANY

Condensed Statements of Comprehensive Income

Periods Ended June 30

(In thousands of dollars)

(UNAUDITED)

	Three Months
	2005		2004
			(Restated)
			(See Note F)
Net income	$	15,090	$	18,265
Unrealized gain (loss) on securities, net of tax		42		(36	)
Comprehensive income	$	15,132	$	18,229

Per share data is not relevant because the Company’s common stock is wholly owned by
National Grid USA.

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

4

NEW ENGLAND POWER COMPANY

Condensed Balance Sheets

(In thousands of dollars)

(UNAUDITED)

	June 30,		March 31,
	2005		2005
Assets
Utility plant, at original cost	$	991,935	$	966,086
Less accumulated depreciation and amortization		256,622		253,281
		735,313		712,805
Construction work in progress		34,471		37,456
Net utility plant		769,784		750,261
Goodwill		338,188		338,188
Investments:
Equity investments in nuclear power companies (Note C)		15,754		17,659
Non-utility property and other investments		12,396		12,341
Total investments		28,150		30,000
Current assets:
Cash and cash equivalents (including $518,625 and $307,325 with affiliates)		518,764		311,396
Accounts receivable:
Affiliated companies		37,300		46,645
Others (less reserves of $153 and $153)		116,806		102,639
Fuel, materials, and supplies, at average cost		3,333		3,560
Prepaid and other current assets		1,501		1,345
Regulatory assets — purchased power obligations (Note B)		13,559		104,486
Regulatory assets — derivative instruments (Note B)		52,240		—
Total current assets		743,503		570,071
Regulatory assets (Note B)		1,012,497		912,105
Additional minimum pension regulatory asset		56,359		56,359
Prepaid pension asset		13,513		13,763
Deferred charges and other assets		4,678		5,161
Total assets	$	2,966,672	$	2,675,908

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

5

NEW ENGLAND POWER COMPANY
Condensed Balance Sheets
(In thousands of dollars)
(UNAUDITED)

	June 30,		March 31,
	2005		2005
Capitalization and liabilities
Capitalization:
Common stock, par value $20 per share,
Authorized — 6,449,896 shares
Outstanding — 3,619,896 shares	$	72,398	$	72,398
Other paid-in capital		731,974		731,974
Retained earnings		312,581		297,508
Accumulated other comprehensive income		127		85
Total common equity		1,117,080		1,101,965
Cumulative preferred stock, par value $100 per share		1,112		1,112
Long-term debt		410,305		410,304
Total capitalization		1,528,497		1,513,381
Current liabilities:
Accounts payable (including $31,109 and $38,313 to affiliates)		61,776		67,845
Accrued liabilities:
Taxes		94,083		10,485
Deferred federal and state income taxes		1,804		1,427
Interest		1,401		802
Purchased power obligations (Note B)		13,559		104,486
Derivative instruments (Note B)		52,240		—
Other accrued expenses		9,769		10,270
Dividends payable		17		17
Total current liabilities		234,649		195,332
Deferred federal and state income taxes		135,910		215,612
Unamortized investment tax credits		7,338		7,447
Accrued Yankee nuclear plant costs		207,254		221,540
Purchased power obligations (Note B)		35,996		189,126
Derivative instruments (Note B)		299,075		—
Other reserves and deferred credits		517,953		333,470
Commitments and contingencies (Note C)
Total capitalization and liabilities	$	2,966,672	$	2,675,908

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

6

NEW ENGLAND POWER COMPANY

Condensed Statements of Cash Flows

Periods Ended June 30

(In thousands of dollars)

(UNAUDITED)

	Three Months
	2005			2004
				(Restated)
				(See Note F)
Operating activities:
Net income	$	15,090		$	18,265
Adjustments to reconcile net income to net cash provided by operating activities:
Amortization of stranded costs		17,674			17,667
Depreciation and amortization		5,105			4,790
Deferred income tax (tax benefit) and investment tax credits, net		(79,870	)		92
Allowance for funds used during construction		(468	)		(171	)
Changes in assets and liabilities:
Increase in accounts receivable, net		(4,822	)		(9,681	)
Decrease in regulatory assets		25,129			38,925
Decrease (increase) in prepaid and other current assets		71			(236	)
(Decrease) increase in accounts payable		(6,069	)		75
Increase (decrease) in purchased power contract obligations		2,610			(29,476	)
Increase in other current liabilities		84,073			9,136
Decrease in other non-current liabilities		(26,148	)		(17,052	)
Increase in other non-current liabilities — USGen settlement payment		195,805			—
Other, net		5,002			842
Net cash provided by operating activities	$	233,182		$	33,176
Investing activities:
Plant expenditures	$	(25,797	)	$	(9,529	)
Net cash used in investing activities	$	(25,797	)	$	(9,529	)
Financing activities:
Dividends paid on preferred stock	$	(17	)	$	(19	)
Net cash used in financing activities	$	(17	)	$	(19	)
Net increase in cash and cash equivalents	$	207,368		$	23,628
Cash and cash equivalents at beginning of period		311,396			229,716
Cash and cash equivalents at end of period	$	518,764		$	253,344
Supplemental disclosures of cash flow information:
Interest paid	$	2,069		$	1,235
Federal and state income taxes paid	$	3,354		$	4,574
Dividends received from investments at equity	$	42		$	838

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

7

NEW ENGLAND POWER COMPANY

Notes to Unaudited Condensed Financial Statements

NOTE A — SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation:New England Power Company (the Company or NEP), in the opinion of management, has included all adjustments (which include normal recurring adjustments, except as described in the notes) necessary for a fair statement of the financial position and results of operations for the interim periods presented. The March 31, 2005 condensed balance sheet data included in this quarterly report on Form 10-Q was derived from audited financial statements included in the Company’s Annual Report on Form 10-K for the year ended March 31, 2005. As such, the March 31, 2005 balance sheet included in this Form 10-Q is considered unaudited as it does not include all the footnote disclosures contained in the Company’s Form 10-K. These financial statements and the notes thereto should be read in conjunction with the audited financial statements included in the Company’s Annual Report on Form 10-K for the year ended March 31, 2005.

The Company is a wholly owned subsidiary of National Grid USA and, indirectly, National Grid plc (formerly known as National Grid Transco plc).

New Accounting Standards:In March 2005, the FASB issued Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations” (FIN 47). FIN 47 will result in (a) more consistent recognition of liabilities relating to asset retirement obligations, (b) more information about expected future cash outflows associated with those obligations and (c) more information about investments in long-lived assets because additional asset retirement costs will be recognized as part of the carrying amounts of the assets.

FIN 47 clarifies that the term conditional asset retirement obligation as used in FASB Statement No. 143, “Accounting for Asset Retirement Obligations”, refers to a legal obligation to perform an asset retirement activity in which the timing and (or) method of settlement are conditional on a future event that may or may not be within the control of the entity. The obligation to perform the asset retirement activity is unconditional even though the uncertainty exists about the timing and (or) method of settlement. Uncertainty about the timing and (or) method of settlement of a conditional asset retirement obligation should be factored into the measurement of the liability when sufficient information exists. FIN 47 also clarifies when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation.

This statement will be effective for the fiscal year ended March 31, 2006 for the Company. The adoption of FIN 47 is not expected to have a material impact on the Company’s results of operations or its financial position.

In May 2005, the FASB issued SFAS No. 154, “Accounting Changes and Error Corrections, a replacement of APB Opinion No. 20 and FASB Statement No. 3.” Previously, APB No. 20, “Accounting Changes” and SFAS No. 3, “Reporting Accounting Changes in Interim Financial Statements” required the inclusion of the cumulative effect of changes in accounting principle in net income of the period of the change. SFAS No. 154 requires companies to recognize a change in accounting principle, including a change required by a new accounting pronouncement when the pronouncement does not include specific transition provisions, retrospectively to prior periods’ financial statements. The Company does not anticipate that the adoption of SFAS No. 154 will have a material impact on its results of operations or its financial position.

8

NEW ENGLAND POWER COMPANY
Notes to Unaudited Condensed Financial Statements

NOTE B — RATE AND REGULATORY

The Company’s financial statements conform to generally accepted accounting principles in the United States of America (GAAP), including the accounting principles for rate regulated entities with respect to its regulated operations. Because electricity rates have historically been based on a utility’s costs, electric utilities are subject to certain accounting standards that are not applicable to other business enterprises in general. The Company applies the provisions of SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation” (FAS 71), which requires regulated entities, in appropriate circumstances, to establish regulatory assets or liabilities, and thereby defer the income statement impact of certain charges or revenues because they are expected to be collected or refunded through future customer billings.

The Company has received authorization from the Federal Energy Regulatory Commission (FERC) to recover through contract termination charges (CTCs) substantially all of the costs associated with its former generating business not recovered through the divestiture of the generation assets. Additionally, FERC enables transmission companies to recover their specific costs of providing transmission service. Therefore, substantially all of the Company’s business, including the recovery of its stranded costs, remains under cost-based rate regulation.

Under settlement agreements approved by the appropriate commissions, the Company is permitted to recover costs associated with its former generating investments (nuclear and nonnuclear) and related contractual commitments that were not recovered through the sale of those investments (stranded costs). Stranded costs are recovered from the Company’s wholesale customers with whom it has settlement agreements through a CTC. The wholesale customers in turn recover stranded cost charges through delivery charges to distribution customers. The Company earns a return on equity (ROE) of approximately 9.7 percent on stranded cost recovery. Most stranded costs will be fully recovered through CTCs by the end of 2010. The Company’s stranded cost obligation related to the above-market cost of purchased power contracts and nuclear decommissioning costs are recovered through the CTC as these costs are actually incurred. The Company, under certain settlement agreements, earns incentives based on successful mitigation of its stranded costs and these incentives supplement the Company’s ROE.

9

NEW ENGLAND POWER COMPANY
Notes to Unaudited Condensed Financial Statements

As a result of applying FAS 71, the Company has recorded net regulatory assets for the costs that are recoverable from customers through CTCs or through transmission rates. The following table details regulatory assets and liabilities summarized in the Company’s financial statements:

	June 30,			March 31,
(In thousands)	2005			2005
Regulatory assets — current
Purchased power payment obligations	$	13,559		$	104,486
Derivative instrument		52,240			—
Total current regulatory assets	$	65,799		$	104,486
Regulatory assets — non-current
Purchased power payment obligations	$	35,996		$	189,126
Purchased power contracts bought-out		176,084			193,829
Derivative instrument		299,075			—
Accrued Yankee nuclear decommissioning costs		207,254			221,540
Additional minimum pension liability		56,359			56,359
Other regulatory assets		294,088			307,610
Total regulatory assets non-current	$	1,068,856		$	968,464
Total regulatory assets	$	1,134,655		$	1,072,950
Regulatory liabilities included in other reserves and deferred credits:
CTC related liabilities	$	(144,940	)	$	(152,412	)
Proceeds from USGen		(195,805	)		—
Pensions and other post-retirement employee benefits		(42,965	)		(43,933	)
Total regulatory liabilities	$	(383,710	)	$	(196,345	)
Net regulatory assets	$	750,945		$	876,605

Purchased power payment obligations:When it divested its generating business in 1998, the Company transferred its entitlement to power procured under several long-term contracts (the Contracts). The buyers of the Company’s generating business (the Buyers) agreed to fulfill the Company’s performance and payment obligations under the Contracts. At the same time the Company agreed to pay the Buyers a fixed amount monthly for the above-market cost of the Contracts.

Purchased power contracts bought-out:In conjunction with divestiture, the Company has made lump sum payments to effectively terminate a number of purchase power contracts. These payments are recorded as regulatory assets and are amortized as they are recovered from
customers.

Derivative instrument:As discussed in the Company’s Form 10-K for the fiscal year ended March 31, 2005, the Company resumed the performance and payment obligations under power supply contracts that had been transferred to USGen (as described in“Purchased power payment obligations”above) and removed the related liability from the balance sheet and offsetting regulatory asset for the above market portion of the contracts with USGen. The Company continues to record a derivative liability of approximately $351 million for the above-

10

NEW ENGLAND POWER COMPANY
Notes to Unaudited Condensed Financial Statements

market portion of the Contracts with an equal offset to a corresponding regulatory asset which is reflected in the table above. The performance and payment obligations will not affect the results of operations, as the Company will recover the above-market cost of the Contracts from customers through the CTC. In accordance with the settlement as described in the Company’s Form 10-K for the fiscal year ended March 31,2005, the Company received proceeds of approximately $196 million in June 2005 from USGen (which is reflected as a regulatory liability in the above table). That amount relates in part to the Contracts and the Company has filed a plan with regulators to credit the $196 million to customers through the CTC.

Accrued Yankee nuclear decommissioning costs:The regulatory asset represents the estimated future decommissioning billings from the Yankees. Under settlement agreements, the Company is permitted to recover prudently incurred decommissioning costs through CTC’s. For a
discussion of decommissioning nuclear units, see Note C — Commitments and Contingencies.

Additional minimum pension liability:The offset to any additional minimum pension liability associated with the Company’s qualified pension plan is applied to this regulatory asset on a pre-tax basis instead of after-tax to other comprehensive income as determined by regulatory rulings.

Other regulatory assets:Included in the other regulatory assets is the accumulation of numerous miscellaneous regulatory deferrals. This largely consists of unrecovered costs associated with divested fixed assets that are being recovered through the CTC.

CTC related liabilities:CTC related liabilities consist of obligations to customers that resulted from the sale of certain stranded assets. These amounts are being refunded to customers as determined per rate filings.

Pensions and other post-retirement employee benefits:As a result of the fiscal 2000 merger of the Company with National Grid and the fiscal 2001 acquisition of Montaup Electric Co, the Company revalued its pension and other post-retirement benefit plans in accordance with
FAS 87 and FAS 106 and recognized previously unrecognized net gains in these benefit plans. The recognition of these gains was offset on the balance sheet by the establishment of a regulatory liability which is being passed back to customers over a 15 year period.

NOTE C — COMMITMENTS AND CONTINGENCIES

Decommissioning Nuclear Units:The Company has minority interests in Yankee Atomic Electric Company, Connecticut Yankee Atomic Power Company, and Maine Yankee Atomic Power Company (together, the Yankees), which own nuclear generating units that have been permanently retired and are conducting decommissioning operations. These ownership interests are accounted for by the equity method. These three units are as follows:

	The Company's					Future Estimated
	Investment as of					Billings to the
	June 30, 2005					Company
Unit	%		(in millions)		Date Retired	(in millions)
Yankee Atomic		34.5	$	0.3	Feb 1992	$	32
Connecticut Yankee		19.5		8.8	Dec 1996		112
Maine Yankee		24.0		6.6	Aug 1997		63

11

NEW ENGLAND POWER COMPANY
Notes to Unaudited Condensed Financial Statements

With respect to each of the units, the Company has recorded a liability and a regulatory asset reflecting the estimated future decommissioning billings from the Yankees. In a 1993 decision, the FERC allowed Yankee Atomic to recover its undepreciated investment in the plant, including a return on that investment, as well as unfunded nuclear decommissioning costs and other costs. Maine Yankee and Connecticut Yankee recover their prudently incurred costs, including a return, in accordance with settlement agreements approved by the FERC in May 1999 and July 2000, respectively. The Yankees collect the approved costs from their purchasers, including NEP. The Company’s share of the decommissioning costs is accounted for in “Purchased electric energy” on the income statement. Under settlement agreements, the Company is permitted to recover prudently incurred decommissioning costs through CTCs.

The Yankees are periodically required to file rate cases, presenting the Yankees’ estimates of future decommissioning costs for FERC approval. Yankee Atomic and Maine Yankee are currently collecting decommissioning and other costs under FERC Orders issued in their respective rate cases. Connecticut Yankee is also collecting costs, subject to refund under a rate case now pending at the FERC, as described below.

Future estimated billings from the Yankees are based on decommissioning cost estimates. These estimates include the projected costs of decontaminating the units as required by the Nuclear Regulatory Commission, dismantling the units, security, liability and property insurance and other costs. They also include costs for interim spent fuel storage facilities, which the Yankees have constructed during litigation they brought to enforce the Department of Energy’s obligation to remove the fuel as required by the Nuclear Waste Policy Act of 1982. A trial at the U.S. Court of Federal Claims to determine the level of damages has concluded and the parties are awaiting an order. Any damages received by the Yankees would be applied to reduce the decommissioning and other costs collected from their purchasers. The decommissioning costs that are actually incurred by the Yankees may exceed the estimated amounts, perhaps substantially.

Connecticut Yankee Rate Filing, Prudence Challenge and Other Proceedings:On July 1, 2004, Connecticut Yankee filed with the FERC seeking a rate increase to reflect increased costs for decommissioning, pensions and other employment benefits, increased security and insurance costs and other expenses. In aggregate, the increase amounts to approximately $396 million through 2010, NEP’s share of which is included in the future estimated billings shown in the table above. The rate case also reflects the impact of the termination of a fixed price contract with Bechtel Power Corporation to perform decommissioning operations and projects a substantial increase in costs over and delay in completion compared with those previously projected.

The Connecticut Department of Public Utility Control and the Connecticut Office of Consumer Counsel (together, the Department) have intervened at the FERC requesting that the FERC reject Connecticut Yankee’s rate filing, or in the alternative, disallow a portion of the requested rate increase on the ground that $205 million to $235 million of these costs were imprudently incurred. Bechtel and three New England states have also intervened, asserting that these costs are imprudent and should be disallowed. FERC authorized Connecticut Yankee to begin

12

NEW ENGLAND POWER COMPANY
Notes to Unaudited Condensed Financial Statements

charging the proposed new rates effective February 1, 2005, subject to refund. Hearings on the rate increase filing at FERC were held in June, initial briefs are due in September, and an initial decision is due in December.

Prior to Connecticut Yankee’s filing, the Department petitioned the FERC to determine that Connecticut Yankee’s purchasers, including NEP, were obliged to pay for all of Connecticut Yankee’s decommissioning costs, whether or not prudent, and could not pass on any imprudent costs to their retail customers. The FERC denied the petition on the ground that it has no jurisdiction over retail rates. The Department and Bechtel moved for clarification and rehearing. FERC has not yet ruled on this motion.

Connecticut Yankee and Bechtel are litigating the termination of the fixed price contract in Connecticut state court, with each party seeking substantial damages. Trial is scheduled to commence in mid-2006.

Hydro Quebec Interconnection:Three affiliates of the Company were created to construct and operate transmission facilities to transmit power from Hydro Quebec to New England. Under the financial and organizational agreements (the Support Agreements) entered into at the time these facilities were constructed, the Company agreed to guarantee a portion of the project debt. At June 30, 2005, the Company had guaranteed approximately $13 million of project debt with terms through 2015. As discussed in further detail in Note B “Rate and Regulatory”, the Company entered into the HQ Transmission Line Agreements with the purchaser of its nonnuclear generation, USGen, under which USGen assumed the Company’s rights to use the Hydro Quebec line and also agreed to reimburse the Company for its payment obligations under the Support Agreements. The HQ Transmission Line Agreements terminated on April 1, 2004 and the Company has resumed performance and payment obligations under the Support Agreements. The Company remains an obligor under the Support Agreements for the portion of the rights it transferred until 2020. Costs associated with these Support Agreements are recoverable from the Company’s customers through CTCs.

The company and its affiliates along with the ISO, Hydro Quebec TransEnergie and the other interconnection rights holders have entered into a series of agreements formalizing the ISO’s operational responsibilities over the Hydro Quebec Interconnection facilities and integrating these facilities into the newly formed New England RTO. On March 31, 2005, these agreements were filed for FERC approval. FERC accepted these agreements in an Order dated May 25, 2005 with the exception of two agreements where final versions had not yet been filed because French-English versions of the agreements were being prepared. Final French-English versions of the two agreements were filed with FERC on July 27. The agreements accepted by FERC on May 25 and those filed on July 27 will not materially affect the underlying Support Agreements.

Millstone 3 Prudence Challenge:In November 1999, NEP agreed with Northeast Utilities (NU) to settle certain claims. As part of the agreement, NU agreed to include NEP’s 16.2 percent ownership interest in Millstone Unit 3 in an auction of NU’s share of the unit. Upon the closing of the sale, NEP was to receive a fixed amount, regardless of the actual sale price. In March 2001, the Millstone units were sold, including NEP’s interest, for $1.3 billion. In accordance with the settlement, NEP was paid approximately $25 million for its interest in the unit (plus reimbursement of pre-paid amounts), from which NEP paid approximately $6.2 million to increase the decommissioning trust fund.

13

NEW ENGLAND POWER COMPANY
Notes to Unaudited Condensed Financial Statements

Regulatory authorities from Rhode Island, New Hampshire and Massachusetts expressed an intent to challenge the reasonableness of the settlement agreement on various grounds, taking the position that NEP would have received approximately $140 million of sale proceeds if there had been no agreement with NU. The matter has been resolved in New Hampshire and Massachusetts. In the event that Rhode Island proceeds with a challenge, the dispute will be resolved by the FERC. Management believes that the Company acted prudently because, among other reasons, the amount it received under the settlement agreement was the highest sale price for a nuclear unit at the time the agreement was reached.

Town of Norwood Dispute:From 1983 until 1998, NEP was the wholesale power supplier for Norwood. In April 1998, Norwood began taking power from another supplier, although its contract term with NEP ran to 2008. Pursuant to a tariff amendment approved by the FERC in May 1998, NEP has been assessing Norwood a CTC. Norwood made a payment of approximately $20 million in July 2004. NEP and Norwood are engaged in litigation in the Massachusetts courts and at the FERC, as follows.

State Collection Action:NEP filed a collection action in Massachusetts Superior Court (Worcester County) to collect the CTC, which Norwood has refused to pay, apart from the initial payment in 2004. In March 2001, the Superior Court ruled that Norwood has breached the agreement by not paying the CTC charge, and ordered Norwood to make regular and substantial payments to an escrow account. Following unsuccessful appeals by Norwood, the Superior Court entered judgment for NEP on June 9, 2004 in the amount of approximately $43.3 million, based on amounts owed through January 31, 2001. Norwood continues to contest the judgment in the Massachusetts Appeals Court.

FERC 206 Proceeding:In December 2002, Norwood challenged the CTC rate with the FERC under Section 206 of the Federal Power Act, which permits the FERC to make prospective adjustments to filed rates. On June 9, 2004, the FERC administrative law judge issued an initial decision recommending that FERC revise the CTC formula to reduce the CTC amount that NEP previously calculated under the formula that FERC accepted and approved in 1998. NEP challenged this initial decision, arguing that no reduction is appropriate. Norwood and the FERC staff challenged the initial decision, arguing that the reduction is insufficient.

On July 22, 2005, the FERC ruled that NEP correctly calculated the CTC payable by Norwood at approximately $600,000 per month from April 1998 through October 2008. FERC also reduced the late payment interest rate previously calculated by NEP, from 18% to 8%. The Company will ask FERC to reconsider the interest question in August. On August 1, 2005, NEP sent Norwood an invoice for approximately $50 million representing Norwood’s current monthly CTC for July 2005, plus its outstanding unpaid balance and interest, as calculated under FERC’s recent order. The Company intends to continue to bill Norwood in accordance with that order through October 2008, unless and until the order is modified as a result of further FERC action or judicial review.

14

NEW ENGLAND POWER COMPANY
Notes to Unaudited Condensed Financial Statements

NOTE D — SEGMENTS

The Company’s reportable segments are electric transmission and stranded cost recoveries (see Note B — “Rate and Regulatory”). The Company is engaged principally in the business of electric power transmission. Certain information regarding the Company’s segments is set forth in the following table. Corporate assets consist primarily of other property and investments, cash and unamortized debt expense.

			Three months ended June 30,
							2004
(In millions)	2005						(Restated)
			Stranded						Stranded
	Electric		cost				Electric		cost
	transmission		recoveries		Total		transmission		recoveries		Total
Operating revenues	$	40	$	71	$	111	$	42	$	73	$	115
Operating income before income taxes		16		7		23		21		10		31
Depreciation and amortization		5		—		5		5		—		5
Amortization of stranded costs		—		18		18		—		18		18

	Total assets at:
(In millions)	June 30, 2005		March 31, 2005
Electric transmission	$	1,222	$	1,203
Stranded cost recoveries		1,199		1,133
Corporate assets		546		340
Total	$	2,967	$	2,676

NOTE E — EMPLOYEE BENEFITS

As discussed in the Company’s Annual Report on Form 10-K for the year ended March 31, 2005, National Grid USA and its subsidiaries (including the Company) provide benefits to retirees in the form of pension and postretirement benefits other than pension (PBOP). The qualified defined benefit pension plans cover substantially all employees meeting certain minimum age and service requirements. Funding for the qualified defined benefit pension plans is based on actuarially determined contributions, the maximum of which is generally the amount deductible for income tax purposes and the minimum being that required by the Employee Retirement Income Security Act of 1974, as amended. The pension plans’ assets primarily consist of investments in equity and debt securities. In addition, National Grid USA and its subsidiaries (including the Company) sponsor non-qualified plans (plans that do not meet the criteria for tax benefits) that cover officers and certain other key employees. National Grid USA and its subsidiaries (including the Company) provide certain health care and life insurance benefits to retired U.S. employees and their eligible

15

NEW ENGLAND POWER COMPANY
Notes to Unaudited Condensed Financial Statements

dependents. These benefits are subject to minimum age and service requirements. The health care benefits include medical coverage, dental coverage, and prescription drugs and are subject to certain limitations, such as deductibles and co-payments.

Benefit plans’ costs charged to the Company during the three months ended June 30, 2005 and 2004 included the following components:

(in thousands)	Pension Benefits						PBOP Benefits
For the Three Months Ended June 30,	2005			2004			2005			2004
Service cost	$	17		$	18		$	11		$	18
Interest cost		1,855			1,959			892			947
Expected return on plans’ assets		(2,299	)		(2,551	)		(923	)		(921	)
Amortization of prior service cost		33			38			(26	)		(14	)
Recognized actuarial loss		733			680			317			353
Net periodic benefit cost	$	339		$	144		$	271		$	383

NOTE F — RESTATEMENT OF PREVIOUSLY ISSUED FINANCIAL STATEMENTS

In connection with the preparation of NEP’s financial statements for its annual report on Form 10-K for fiscal year ended March 31, 2005, management concluded that the Company had understated net income for the fiscal years ended March 31, 2003 and 2004. The following provides a description of the details of the accounting adjustments included in the restatement of the Company’s financial statements and the effect of the adjustments on the Company’s Statement of Income, Statement of Retained Earnings, Statement of Comprehensive Income and Statement of Cash Flows for these periods. The restatements reflect accounting errors in recording revenues for the recovery of stranded and transmission costs and certain true-ups for expenses relating to federal and state income tax filings were not made timely in fiscal 2003 and 2004. The underlying regulatory filings and income tax filings, however, were timely and accurately filed.

Details of Accounting Adjustments Included in the Restatement of the Three Months Ended June 2004: The accounting adjustments relate primarily to the categories described below. These adjustments affected reported net income and common equity which relate to both the timing and recognition of revenues and expenses and affect the comparison of period-to-period results, as well as business segment reporting.

Operating revenues: (composed of stranded cost revenues and transmission revenues)

Stranded cost revenues: There were two adjustments recorded during the three months ended March 31, 2005 related to the three months ended June 30, 2004 which affected stranded cost revenues.

(1) The Company is allowed to earn incentives, referred to as mitigation incentives, for reducing the amount of stranded costs to be charged to customers as compared to the original CTC filings made in 1998. The Company incorrectly recorded these mitigation incentives in the years prior

16

NEW ENGLAND POWER COMPANY
Notes to Unaudited Condensed Financial Statements

to the year ended March 31, 2005 because it used outdated data. This resulted in an overstatement of pre-tax revenue of $1.7 million pre-tax ($1.0 million after-tax) for the fiscal years ended March 31, 2002 and prior, and an offsetting understatement of revenue of $1.7 million pre-tax ($1.0 million after-tax), for the fiscal year ended March 31, 2004. Certain amounts related to this error correction pertained to the fiscal quarter ended June 30, 2004 and is being restated and reflected in this Form 10-Q for the quarter ended June 30, 2005.

(2) During fiscal 2004, the Company made a payment to buy out a purchased power contract. The Company is allowed to earn a return on this buyout payment however the Company did not begin recording this return until fiscal 2005. This resulted in an understatement of revenue for the year ended March 31, 2004 of $673,000 pre-tax ($409,000 after-tax). This error was detected and corrected during the fiscal quarter ended December 31, 2004. Certain amounts related to this error correction pertained to the fiscal quarter ended June 30, 2004 and is being restated and reflected in this Form 10-Q for the quarter ended June 30, 2005.

Transmission revenues: Monthly billings to the Company’s transmission customers are determined based on monthly costs incurred to serve those customers, net of certain revenues received during the month. Beginning in the fiscal year ended March 31, 2002, certain revenues related to stranded cost recovery were incorrectly netted against transmission costs as part of the monthly billings to transmission customers. This error was detected and corrected during the fiscal quarter ended December 31, 2004. This error resulted in an understatement of revenue to on a pre-tax basis by $941,000 and $463,000 for the fiscal years ended March 31, 2003 and 2004, respectively ($572,000 and $281,000 after-tax, respectively). Certain amounts related to this error correction pertained to the fiscal quarter ended June 30, 2004 and is being restated and reflected in this Form 10-Q for the quarter ended June 30, 2005.

17

NEW ENGLAND POWER COMPANY
Notes to Unaudited Condensed Financial Statements

The Company has set forth below selected restated financial statements for the three months ended June 30, 2004. Because certain of the data set forth in the following tables has been restated from amounts previously reported, the following tables reconcile the information presented with those previously reported.

Statement of Income
For the Three Months Ended June 30, 2004	Previously
(In thousands)	Reported		Adjustments			As Restated
Operating revenue, principally from affiliates	$	113,919	$	1,059	(a)	$	114,978
Operating expenses:
Purchased electric energy:
Contract termination and nuclear unit shutdown charges		36,738		—			36,738
Other		3,837		—			3,837
Other operation		14,840		—			14,840
Maintenance		1,922		—			1,922
Amortization of stranded costs		17,667		—			17,667
Depreciation and amortization		4,790		—			4,790
Taxes, other than income taxes		4,293		—			4,293
Income taxes		11,326		415	(b)		11,741
Total operating expenses		95,413		415			95,828
Operating income		18,506		644			19,150
Other income:
Equity in income		393		—			393
Other income, net		410		—			410
Operating and other income		19,309		644			19,953
Interest expense:
Interest on long-term debt		1,474		—			1,474
Other interest		214		—			214
Total interest		1,688		—			1,688
Net income	$	17,621	$	644		$	18,265

(a)	Amount consists of stranded cost and incremental transmission revenue adjustments.
(b)	Amount consists of the income tax effect on the stranded cost and incremental transmission revenue adjustments.

18

NEW ENGLAND POWER COMPANY
Notes to Unaudited Condensed Financial Statements

Statement of Comprehensive Income
For the Three Months Ended June 30, 2004	Previously
(In thousands)	Reported			Adjustments		As Restated
Net income	$	17,621		$	644	$	18,265
Unrealized gain (loss) on securities, net of tax		(36	)		—		(36	)
Comprehensive income (Note A)	$	17,585		$	644	$	18,229

Statement of Retained Earnings
For the Three Months Ended June 30, 2004	Previously
(In thousands)	Reported			Adjustments			As Restated
Retained earnings at beginning of period	$	209,319		$	11,453	(a)	$	220,772
Net income		17,621			644			18,265
Dividends declared on cumulative preferred stock		(19	)		—			(19	)
Retained earnings at end of period	$	226,921		$	12,097		$	239,018

(a) Amount includes adjustments for prior periods.

19

NEW ENGLAND POWER COMPANY
Notes to Unaudited Condensed Financial Statements

Statement of Cash Flows
For the Three Months Ended June 30, 2004	Previously						As
(In thousands)	Reported			Adjustments			Restated
Operating activities:
Net income	$	17,621		$	644		$	18,265
Adjustments to reconcile net income to net cash provided by operating activities:
Amortization of stranded costs		17,667			—			17,667
Depreciation and amortization		4,790			—			4,790
Deferred income taxes and investment tax credits, net		92			—			92
Allowance for funds used during construction		(171	)		—			(171	)
Changes in assets and liabilities:
Increase in accounts receivable, net		(9,348	)		(333	)		(9,681	)
Decrease in regulatory assets		39,425			(500	)		38,925
Decrease in prepaid and other current assets		(236	)		—			(236	)
Decrease in accounts payable		75			—			75
Decrease in purchased power contract obligations		(29,476	)		—			(29,476	)
Increase in other current liabilities		9,005			131			9,136
Decrease in other non-current liabilities		(17,110	)		58			(17,052	)
Other, net		842			—			842
Net cash provided by operating activities	$	33,176		$	—		$	33,176
Investing activities:
Plant expenditures, excluding allowance for funds used during construction	$	(9,529	)				$	(9,529	)
Net cash provided by investing activities	$	(9,529	)				$	(9,529	)
Financing activities:
Dividends paid on cumulative preferred stock	$	(19	)				$	(19	)
Net cash used in financing activities	$	(19	)				$	(19	)
Net increase in cash and cash equivalents	$	23,628					$	23,628
Cash and cash equivalents at beginning of period	$	229,716					$	229,716
Cash and cash equivalents at end of period	$	253,344					$	253,344

20

NEW ENGLAND POWER COMPANY
Notes to Unaudited Condensed Financial Statements

NOTE G — BILLING ERRORS

In fiscal 2006, the Company discovered it had cumulatively overcharged its affiliate Massachusetts Electric Company (MECO) by approximately $6.3 million including interest ($3.8 million after-tax), resulting in an overstatement of revenue. Specifically, the Company invoiced MECO for the use of diesel generators on Nantucket Island to provide back-up service to the island in the event the undersea cable that connects the island to the mainland fails. The overcharge was related to the use of incorrect allocations for administrative and general expense attributed to the Nantucket diesel units. The Company will refund these overcharges to MECO, which resulted in a decrease in operating revenue of $6.3 million and a decrease in net income of $3.8 million in the current quarter.

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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Explanatory Note:On June 20, 2005, management of New England Power Company concluded there were accounting errors for certain true-ups for revenues relating to regulatory filings for the recovery of stranded and transmission costs and certain true-ups for expenses relating to federal and state income tax filings in fiscal 2001, 2002, 2003 and 2004. Management’s investigation and review of the affected accounts resulted in the restatement of the financial statements.

This Form 10-Q contains restated statements of income, comprehensive income, retained earnings, and cash flows for the quarterly period ended June 30, 2004.

FORWARD-LOOKING INFORMATION

This report and other presentations made by New England Power Company (the Company) contain forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended. Throughout this report, forward-looking statements can be identified by the words or phrases “will likely result”, “are expected to”, “will continue”, “is anticipated”, “estimated”, “projected”, “believe”, “hopes” or similar expressions. Although the Company believes that, in making any such statements, its expectations are based on reasonable assumptions, any such statements may be influenced by factors that could cause actual outcomes and results to differ materially from those projected. Important factors that could cause actual results to differ materially from those in the forward-looking statements include, but are not limited to:

(a) the impact of further electric industry restructuring;

(b) the impact of general economic changes;

(c) federal and state regulatory developments and changes in law, which may have a substantial adverse impact on revenues or on the value of the Company’s assets;

(d) federal regulatory developments concerning regional transmission organizations;

(e) changes in accounting rules and interpretations, which may have an adverse impact on the Company’s statements of financial position and reported earnings;

(f) timing and adequacy of rate relief;

(g) adverse changes in electric load;

(h) acts of terrorism;

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(i) climatic changes or unexpected changes in weather patterns; and

(j) failure to recover costs currently deferred under the provisions Statement of Financial Accounting Standards No. 71, “Accounting for the Effects of Certain Types of Regulations”, as amended.

CRITICAL ACCOUNTING POLICIES

Certain critical accounting policies are based on assumptions and conditions that, if changed, could have a material effect on the financial condition, results of operations and liquidity of the Company. See the Company’s Annual Report on Form 10-K for the fiscal year ended March 31, 2005, Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — “Critical Accounting Policies” for a detailed discussion of these policies.

RESULTS OF OPERATIONS

EARNINGS

Net incomefor the quarter ended June 30, 2005, decreased approximately $3 million compared with the same period in 2004. The decrease for the quarter was due primarily to the refund of an overcharge to one of the Company’s affiliates (see Note G “Billing Errors”), and an increase in interest expense due to higher interest rates. Partially offsetting this decrease was an increase in interest income from an intercompany borrowing arrangement (see Liquidity and Capital Resources).

REVENUES

The Company has two primary sources of revenue: transmission and stranded cost recovery. Transmission revenues are based on a formula rate that recovers the Company’s actual costs plus a return on investment. Stranded cost recovery revenues are in the form of a Contract Termination Charge (CTC), which is billed to former wholesale customers of the Company in connection with the Company’s divestiture of its electric generation investments.

Operating revenuedecreased $4 million for the quarter ended June 30, 2005, compared to the same period in 2004. The decrease was primarily due to the correction of an overcharge to one of the Company’s affiliates which reduced operating revenue by $6 million (see Note G “Billing Errors) and lower recovery of transmission related expenses of $1 million. This decrease was offset by higher recovery of purchased electric energy expenses of $4 million.

OPERATING EXPENSES

Purchased electric energyincreased $4 million for the quarter ended June 30, 2005, compared with the same period in 2004. The increase was primarily due to higher nuclear decommissioning costs of $3 million and higher monthly power obligations of $1 million.

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Operation and maintenance expensedecreased $1 million for the quarter ended June 30, 2005 compared with the same period in 2004. The primary reason for the decrease was a reduction in operating expenses related to the HQ contracts (see Note B), offset by increased transmission maintenance costs.

Income taxesdecreased approximately $5 million for the quarter ended June 30, 2005 compared with same period in 2004. This decrease was primarily due to a decrease in book taxable income and audit true-ups.

NON OPERATING EXPENSES

Other income netincreased $1 million for the quarter ended June 30, 2005 compared with the same period in 2004. The increase was a result of higher interest income from associated companies due to a larger investment in the money pool by the Company. (See ‘Net cash flows used in investing activities’ below for further discussion on the money pool.)

Interest chargesincreased $2 million for the quarter ended June 30, 2005, compared to the same period in 2004. This increase was primarily due to higher interest rates on long term debt.

LIQUIDITY AND CAPITAL RESOURCES

At June 30, 2005 the Company’s principal sources of liquidity included cash and cash equivalents of approximately $519 million and accounts receivable of $154 million. The Company has a positive working capital balance of approximately $509 million.

Net cash flows provided by operating activitiesincreased approximately $200 million for the three months ended June 30, 2005 compared with the same period in 2004. The primary reason for the increase in operating cash flow was the receipt of $195 million related to the USGen settlement.

Net cash flows used in investing activitiesfor the three months ended June 30, 2005, increased approximately $16 million compared with the same period in 2004, due to increased plant expenditures. Cash expenditures for the Company for utility plant totaled approximately $26 million for three months ended June 30, 2005, and were primarily transmission-related. The funds necessary for utility plant expenditures during the period were primarily provided by internal funds.

At June 30, 2005, the Company had no short-term debt outstanding. The Company has regulatory approval to issue up to $375 million of short-term debt. National Grid USA and certain subsidiaries, including the Company, with regulatory approval, operate a money pool to more effectively utilize cash resources and to reduce outside short-term borrowings. Short-term borrowing needs are met first by available funds of the money pool participants. Borrowing companies pay interest at a rate designed to approximate the cost of outside short-term borrowings. Companies that invest in the pool share the interest earned on a basis proportionate to their average monthly investment in the money pool. Funds may be withdrawn from or repaid to the pool at any time without prior notice.

24

At June 30, 2005, the Company had credit and standby bond purchase facilities with banks totaling $440 million which are available to provide liquidity support for $410 million of the Company’s long-term bonds, and for other corporate purposes. There were no borrowings under these facilities at June 30, 2005. Fees are paid on the facilities in lieu of compensating balances.

OTHER REGULATORY MATTERS

New England RTO and Rate Filing:The Company is a Participating Transmission Owner (PTO) in New England’s Regional Transmission Organization (RTO) which commenced operations effective February 1, 2005. FERC issued two orders in 2004 and two in 2005 that approved the establishment of the RTO and resolved certain issues concerning the proposed return on equity (ROE) for New England PTOs. Other issues were set for hearing. A number of parties, including NEP, have filed appeals from one or more of those orders with the US Court of Appeals for the District of Columbia Circuit.

NEP’s last allowed base ROE for transmission assets was 10.25%. Effective on the RTO operations date of February 1, 2005, NEP’s transmission rates began to reflect a proposed base return on equity of 12.8%, subject to refund, plus the additional 0.5% incentive return on regional network service (RNS) rates that FERC approved in March 2004. Approximately 70% of the Company’s transmission costs are recovered through RNS rates. An additional 1.0% incentive adder is also applicable to new RNS transmission investment, subject to refund.

NEP and the other parties continue to participate in FERC proceedings to determine outstanding ROE issues, including base return on equity and the proposed 1% ROE incentive for new transmission investment. The administrative law judge issued an initial decision on May 27, 2005, which concluded that the base ROE should be 10.72% and that NEP and other PTOs are not entitled to the proposed 1% ROE incentive. The parties, including the PTOs, filed briefs on exception to the judge’s initial decision on June 27 and the briefs opposing exceptions on July 18. A final FERC order is expected by year end 2005.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Interest Rate Risk:The Company’s major financial market risk exposure is changing interest rates. Changing interest rates will affect interest paid on variable rate debt. At June 30, 2005, the Company’s tax exempt variable rate long-term debt had a carrying value of approximately $410 million. While the ultimate maturity dates of the underlying loan agreements range from 2015 through 2022, this debt is issued in tax exempt commercial paper mode. The various components that comprise this debt are issued for periods ranging from one day to 270 days, and are remarketed through remarketing agents at the conclusion of each period. The weighted average variable interest rate for the quarter ended June 30, 2005 was approximately 2.59 percent.

Commodity Risk:The Company is party to contracts for the purchase of electricity which are recognized as a derivative liability in accordance with FAS 133 (see Note B “Rate and Regulatory”). These contracts are exposed to commodity price risk arising from market price fluctuations in the cost of electricity. The Company’s rate plan allows for full recovery of the cost of electricity from its customers resulting in the recognition of regulatory assets related to commodity risk.

25

ITEM 4. CONTROLS AND PROCEDURES

The Company has carried out an evaluation under the supervision and with the participation of its management, including the Chief Financial Officer and President, of the effectiveness of the Company’s disclosure controls and procedures as of the end of the period covered by this report. There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of the controls and procedures. Accordingly, even effective disclosure controls and procedures can provide only reasonable assurance of achieving their control objectives. Based on and as of that evaluation, it was determined that these disclosure controls and procedures were not effective, due to the material weakness described in the Company’s Form 10-K for the fiscal year ended March 31, 2005, in providing reasonable assurance that information required to be disclosed in reports that the Company files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported as and when required.

As described in the Company’s Form 10-K for the fiscal year ended March 31, 2005, the Company identified errors that resulted in the understatement of revenue and the overstatement of income tax expense. To address the underlying control deficiency, the Company established a formal written policy requiring that true-ups and analysis of estimated stranded cost revenues and income tax expense be recorded on a timely basis. In addition, the Company updated its procedures to require that the related managers confirm that true-ups and analysis are being recorded on a timely basis.

The changes described above were made during the fiscal quarter ended June 30, 2005. Other than these changes, there were no changes in our internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

26

PART II—OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

Town of Norwood Dispute:As described in the Company’s 10-K for the fiscal year ended March 31, 2005, NEP and Norwood are engaged in litigation in the Massachusetts courts and at the FERC with respect to Norwood’s payment of a contract termination charge, or CTC. On July 22, 2005, the FERC ruled that NEP correctly calculated the CTC payable by Norwood at approximately $600,000 per month from April 1998 through October 2008. FERC also reduced the late payment interest rate previously calculated by NEP, from 18% to 8%. The Company will ask FERC to reconsider the interest question in August. On August 1, 2005, NEP sent Norwood an invoice for approximately $50 million representing Norwood’s current monthly CTC for July 2005, plus its outstanding unpaid balance and interest, as calculated under FERC’s recent order. The Company intends to continue to bill Norwood in accordance with that order through October 2008, unless and until the order is modified as a result of further FERC action or judicial review.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

As reported in the Company’s 10-K for the fiscal year ended March 31, 2005, the Annual Meeting of Stockholders was held on April 20, 2005. By a vote of 3,619,896 shares out of 3,631,013 total shares voted, the following actions were taken:

• The number of directors was fixed at five.

• The following persons were elected as directors: John G. Cochrane, Michael E. Jesanis, Stephen P. Lewis, Lawrence J. Reilly, and Jeffrey A. Scott.

• James S. Robinson was elected Treasurer and Gregory A. Hale was elected Clerk.

PricewaterhouseCoopers LLP, was appointed as the Company’s independent registered public accountant for the fiscal year ending March 31, 2006.

ITEM 5. OTHER INFORMATION

None

ITEM 6. EXHIBITS

The exhibit index is incorporated herein by reference.

27

SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report on Form 10-Q for the quarter ended June 30, 2005 to be signed on its behalf by the undersigned thereunto duly authorized.

	NEW ENGLAND POWER COMPANY
Date: August 12, 2005	By:	/s/ Marcy L. Reed
		Marcy L. Reed
		Authorized Officer and Controller and Principal Accounting Officer

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EXHIBIT INDEX

Exhibit
Number	Description
31.1	Certification of Principal Executive Officer
31.2	Certification of Principal Financial Officer
32	Certifications Pursuant to 18 U.S.C. 1350

29