UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K


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

For the ~~fiscal~~Fiscal ~~year~~Year ~~ended~~Ended March 31, ~~2006~~2007


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

For the transition period to

Commission	Registrant, State of Incorporation,	I.R.S. Employer
Commission File Number	Registrant, State of Incorporation, Address and Telephone Number	I.R.S. Employer Identification Number
File Number	Address and Telephone Number	Identification Number
1-2987	Niagara Mohawk Power Corporation	15-0265555
	(a New York corporation)
	(a New York corporation) 300 Erie Boulevard West Syracuse, New York 13202 315.474.1511
	300 Erie Boulevard West
	Syracuse, New York 13202
	315.474.1511

Securities registered pursuant to Section 12(b) of the Act:
(Each class is registered on the New York Stock Exchange)


Registrant		Title and Class

Niagara Mohawk Power Corporation		Preferred Stock ($100 par value-cumulative):
		3.90% Series 3.60% Series

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
YES o NO þ

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
YES o NO þ

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.
YES þ NO o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. þ

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a nonaccelerated filer. See definition of “accelerated filer” and “large accelerated filer” in Rule 12b-2 of the Exchange Act.

Large accelerated filer o Accelerated filer o Non-accelerated filer þ

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). YES o NO þ ~~State the aggregate market value of the common equity held by non-affiliates of the registrant: N/A~~

State the aggregate market value of the common equity held by non-affiliates of the registrant: N/A

Indicate the number of shares outstanding of each of the registrant’s classes of common stock, as of the latest practicable date.

Registrant	Title		Shares Outstanding at June 22, 2007	~~Shares Outstanding at June 20, 2006~~
Niagara Mohawk Power Corporation	Common Stock, $1.00 par value (all held by Niagara Mohawk Holdings, Inc.)		187,364,863	~~187,364,863~~
		(all held by Niagara Mohawk Holdings, Inc.)

NIAGARA MOHAWK POWER CORPORATION

TABLE OF CONTENTS

			~~PAGE~~	PAGE
	~~PART I~~	PART I
Item 1.	~~Business~~	Business		4	4
Item 1A.	~~Risk Factors~~	Risk Factors		6	7
Item 1B.	~~Unresolved Staff Comments~~	Unresolved Staff Comments		8	8
Item 2.	~~Properties~~	Properties		8	9
Item 3.	~~Legal Proceedings~~	Legal Proceedings		9	9
Item 4.	~~Submission of Matters to a Vote of Security Holders~~	Submission of Matters to a Vote of Security Holders		9	9
	~~PART II~~	PART II
Item 5.	~~Market for the Registrant’s Common Equity, Related Stockholders Matters and Issuer Purchases of Equity Securities~~	Market for the Registrant’s Common Equity, Related Stockholders Matters and Issuer Purchases of Equity Securities		9	10
Item 6.	~~Selected Consolidated Financial Data~~	Selected Consolidated Financial Data		9	10
Item 7.	~~Management’s Discussion and Analysis of Financial Condition and Results of Operations~~	Management’s Discussion and Analysis of Financial Condition and Results of Operations		10	11
Item 7A.	~~Quantitative and Qualitative Disclosures About Market Risk~~	Quantitative and Qualitative Disclosures About Market Risk		20	23
Item 8.	~~Financial Statements and Supplementary Data~~	Financial Statements and Supplementary Data		24	27
Item 9.	~~Changes in and Disagreements with Accountants on Accounting and Financial Disclosure~~	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		59	63
Item 9A.	~~Controls and Procedures~~	Controls and Procedures		59	63
Item 9B.	~~Other Information~~	Other Information		59	63
	~~PART III~~	PART III
Item 10.	~~Directors and Executive Officers of the Registrant~~	Directors and Executive Officers and Corporate Governance		60	64
Item 11.	~~Executive Compensation~~	Executive Compensation		62	66
Item 12.	~~Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters~~	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		67	91
Item 13.	~~Certain Relationships and Related Transactions~~	Certain Relationships and Related Transactions		68	92
Item 14.	~~Principal Accountant Fees and Services~~	Principal Accountant Fees and Services		68	92
	~~PART IV~~	PART IV
Item 15.	~~Exhibits and Financial Statement Schedules~~	Exhibits and Financial Statement Schedules		69	93
Signatures				71	94
Ex-10(dd) Separation and Release Agreement, dated December 31, 2006
Ex-10(ee) Consulting Agreement, dated January 17, 2007
EX-10(ff) Separation and Release Agreement - Michael J. Kelleher
EX-21 Subsidiaries of the Registrant
EX-31.1 Section 302 Certification of PEO
EX-31.2 Section 302 Certification of PFO
EX-32 Section 906 Certification of PEO & PFO

Cautionary Statement

This Annual Report on Form 10-K of Niagara Mohawk Power Corporation (the Company) contains ~~certain~~ certain statements that are neither reported financial results nor other historical information. ~~These~~ These statements are 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. Because these forward-looking statements are subject to assumptions, risks and uncertainties, actual future results may differ materially from those expressed in or implied by such statements. 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 and gas industry restructuring; (b) changes in general economic conditions in New York; (c) federal and state regulatory developments and changes in law, including those governing municipalization and exit fees; (d) changes in accounting rules and interpretations, which may have an adverse impact on the Company’s statements of financial position, reported earnings and cash flows; (e) timing and adequacy of rate relief; (f) failure to achieve reductions in costs or to achieve operational efficiencies; (g) failure to retain key management; (h) adverse changes in electric load; (i) acts of terrorism; (j) unseasonable weather, climatic changes or unexpected changes in historical weather patterns; and (k) failure to recover costs currently deferred under the provisions of Statement of Financial Accounting Standards (SFAS) No. 71, “Accounting for the Effects of Certain Types of Regulations”,” as amended, and the Merger Rate Plan (MRP) in effect with the New York State Public Service Commission (PSC).

Readers are cautioned not to place undue reliance on these forward-looking statements, which speak only as of the date of this report. Except as required by law, Niagara Mohawk Power Corporation does not undertake any obligation to revise any statements in this report to reflect events or circumstances after the date of this report.

NIAGARA MOHAWK POWER CORPORATION

PART I

ITEM 1. BUSINESS

Niagara Mohawk Power Corporation (the Company) was organized in 1937 under the laws of New York State and is engaged principally in the regulated energy delivery business in New York State. The Company provides electric service to approximately 1,~~600~~500,000 electric customers in the areas of eastern, central, northern and western New York and sells, distributes, and transports natural gas to approximately ~~569~~571,000 gas customers in areas of central, northern and eastern New York.

Niagara Mohawk Holdings, Inc. (Holdings), the parent company of the Company, is a wholly owned subsidiary of National Grid USA (National Grid). National Grid is a wholly owned subsidiary of National Grid plc (formerly known as National Grid Transco plc).

Regulation and Rates: In conjunction with the closing of the merger with National Grid, a new rate plan (the Merger Rate Plan) that had been approved by the PSC went into effect, superseding the prior rate plan. Since then, several critical initiatives have been undertaken by various regulatory bodies and the Company that have had, and are likely to continue to have, a significant impact on the Company and the utility industry.

Merger Rate Plan (MRP): The Company’s delivery rates are governed by a ten-year rate plan that began on February 1, 2002. Under the plan, after reflecting the Company’s share of savings related to the acquisition, it may earn a threshold return on equity for the electricity distribution business of 10.6%, up to 11.75% without any sharing with customers (12.0% if certain customer outreach, education, competition-related and low income incentive targets are met). Half of any amounts in excess of 12%, up to 14%, 25% of any earnings in excess of that up to 16%, and 10% beyond that are retained by the Company. This effectively offers the Company the potential to achieve a return on equity in excess of the regulatory allowed return of 10.6%. The return on equity is calculated cumulatively from inception to December 31, 2005 and annually thereafter for the prior two calendar years. The earnings calculation used to determine the regulated returns excludes half of the synergy savings, net of the cost to achieve them, that were assumed in the rate plan based on the Company’s merger with National Grid. Under the plan, gas delivery rates were frozen until the end of the 2004 calendar year, after which the Company ~~has~~had the right to request an increase at any time, if needed. The Company may earn a threshold return on equity ranging from 10.6% to 12.6% depending on the achievement of certain customer migration levels and customer awareness and understanding of gas competitive opportunities. Above this threshold, the revenue equivalent of gas earnings must be shared equally between shareholders and customers. The Company collects the transmission business revenues under several Federal Energy Regulatory Commission (FERC) rate schedules and the state energy delivery rates discussed above. Total transmission business revenues are determined by the state-approved 10-year rate plan.

The Company resets its Competitive Transition Charges (CTC) in electricity rates every two years under its ~~Merger Rate Plan (the Plan)~~MRP. The CTC reset is intended to account for changes in forecasted electricity and natural gas commodity prices, and the effects those changes have on the Company’s above-market payments under legacy power contracts that otherwise would be stranded. In addition, the ~~Merger Rate Plan~~ MRP allows the Company to recover amounts exceeding $100 million in its deferral accounts (as projected through the end of each two-year CTC reset period). In accordance with the ~~Merger Rate Plan~~MRP, deferral accounts were established to track changes in specified cost and revenue items that have occurred since the Plan was established. These changes include costs or revenues related to changes in tax, accounting, and regulatory requirements, changes from the levels of pension and post-retirement benefit expenses from the levels specified in the Plan, and various other items, including storms, environmental remediation costs, and various rate discounts. The deferrals are subject to regulatory review and approval. On July 29, 2005, the Company made its biannual deferral account recovery filing for balances in the deferral account as of June 30, 2005 plus projected deferrals. On December 27, 2005, the PSC approved recovery of deferral account amounts of $100 million in calendar year 2006 and $200 million in

~~from~~calendar ~~the~~year ~~levels of pension and post-retirement benefit expenses from the levels specified in the Plan~~2007, and ~~various~~ ~~other~~established ~~items,~~a ~~including~~timeline ~~storms,~~for ~~environmental remediation costs, and various rate discounts. On July 29, 2005,~~ the ~~Company~~Department ~~filed~~of ~~its~~Public ~~bi-annual~~Service ~~CTC~~Staff ~~reset and deferral account recovery filing~~(Staff) to ~~reset~~perform ~~rates~~its ~~charged~~audit ~~to customers beginning January 1, 2006. In the July 29, 2005 filing, the Company included a proposal to recover the excess balance~~ of the deferral ~~accounts as of June 30, 2005 of $196 million and a projection through the end of the two year period of $373 million~~account. ~~On December 27,~~For ~~2005~~2006, the ~~PSC approved the Company’s proposal for the new CTC effective January 1, 2006. The PSC also approved recovery of~~ deferral ~~account~~surcharge ~~amounts~~was ofincluded ~~$100 million~~ in ~~calendar year~~ ~~2006~~rates ~~and~~beginning ~~$200 million~~ in ~~calendar year 2007. For 2006, the actual deferral-related surcharge began in~~ April ~~2006~~ and the ~~full~~ $100 million ~~will~~was be collected over the last nine months of the 2006 calendar year. AnThe ~~audit~~Staff offiled ~~the~~testimony ~~deferral~~on ~~amount~~August 2, by2006, ~~the~~proposing ~~Department~~in excess of ~~Public~~$200 million ~~Service Staff (DPS~~of ~~Staff)~~initial isadjustments ~~ongoing.~~to Athe ~~formal~~deferral ~~hearing~~balance ~~process~~and ~~has~~projected ~~been~~deferrals. ~~established~~After ~~before~~replies afrom ~~hearing~~the ~~officer~~Staff and at the ~~PSC~~ toCompany, ~~litigate~~an ~~the~~evidentiary ~~levels~~hearing inwas ~~the~~held ~~deferral~~on ~~account~~October 5, 2006. ~~Under~~Upon the ~~hearing~~conclusion ~~schedule,~~of the ~~Staff will be~~ ~~filing~~evidentiary ~~testimony~~hearings, ~~setting~~the ~~forth~~Company ~~its~~and ~~initial~~the ~~adjustments~~Staff inagreed ~~early~~to ~~August.~~enter ~~The~~into ~~Company~~non-binding ~~will continue~~mediation todiscussions ~~defer~~before ~~costs~~an ~~and~~administrative ~~revenues,~~law asjudge ~~applicable,~~from ~~through~~ the ~~end~~PSC ofin ~~the~~an ~~Merger~~attempt ~~Rate~~to ~~Plan~~resolve onsome ~~December 31, 2011.~~or ~~The~~all ~~Company’s future filings for recovery~~ of the ~~deferred~~ amounts ~~are~~remaining ~~subject~~in ~~to regulatory review and approval~~dispute.

~~Electric~~Through ~~Supply: Although~~ the ~~Company~~mediation ~~has~~process, ~~exited~~ the ~~generation business~~Company, the ~~Company~~Staff, ~~must~~and ~~still arrange~~Multiple ~~for~~Intervenors ~~electric~~(Parties), ~~supply through~~ reached a ~~transition~~resolution ~~period and as provider~~ of ~~last resort. As such~~ the ~~Company~~disputed ~~will~~issues ~~provide~~presented ~~electricity~~in tothe ~~its~~deferral ~~customers~~account ~~who~~case ~~are~~as ~~unable~~well oras ~~unwilling~~other ~~to obtain an~~cases ~~alternative~~pending ~~supplier~~before ~~which~~the ~~accounts~~Commission ~~for~~regarding ~~approximately~~pension ~~92%~~costs, of the ~~Company’s~~costs ~~customers~~of ~~and~~enhanced ~~59%~~inspections of ~~its~~the ~~deliveries.~~transmission ~~The~~and ~~Company~~distribution ~~purchases~~system, ~~energy from various suppliers under long-term Purchase Power Agreements (PPAs)~~ and ~~purchases any additional power needs on~~ the ~~open~~sale ~~market~~of ~~through~~ the ~~New~~Nine ~~York Independent~~Mile ~~System~~Point ~~Operator~~nuclear ~~(NYISO)~~generating facilities. ~~The~~A ~~Company~~Stipulation ~~also~~of ~~enters into financial swaps in order to hedge~~ the ~~price~~Parties of(Stipulation) ~~electricity.~~setting ~~For~~forth ~~a discussion of~~ the ~~results~~resolution of ~~the~~these issues ~~power~~was ~~contracts~~executed and ~~several financial~~filed ~~agreements~~with ~~to hedge~~ the ~~price~~Commission ofon ~~electricity, see Part~~March II23, ~~Item 8~~ 2007. ~~Financial~~A ~~Statements and~~hearing ~~Supplementary~~on ~~Data~~the —Stipulation ~~Note~~of Dthe –Parties ~~Commitments~~was ~~and~~held ~~Contingencies~~before ~~and~~the PSC’s ~~Note~~administrative Llaw –judge ~~Derivatives~~on ~~and Hedging~~May ~~Activities~~17, 2007.

~~Electric~~Under ~~Delivery:~~the ~~As of March 31~~Stipulation, ~~2006,~~ the Company ~~had~~has ~~approximately~~agreed ~~52,000~~to ~~pole~~a ~~miles~~net reduction of ~~transmission~~ ~~and~~the ~~distribution~~deferral ~~lines~~account ~~for~~balance of ~~electricity~~approximately ~~delivery~~$127 million. ~~Evaluation~~This ofincludes ~~these~~reclassifications ~~facilities relative~~from to the ~~requirements~~deferral ofaccount ~~the~~to ~~New~~other balance ~~York~~sheet ~~State~~accounts ~~Reliability~~of ~~Council,~~approximately ~~Northeast~~$64 million. ~~Power Coordinating~~It ~~Council,~~also ~~North~~includes ~~American~~a ~~Electric~~reduction ~~Reliability~~to ~~Council,~~the ~~NYISO and PSC, their orders,~~deferral ~~operating~~account ~~and~~balance ~~planning~~as ~~guides~~of ~~and criteria~~February 28, ~~security~~2007 ~~considerations,~~ and ~~anticipated~~decrease ~~Company internal~~to ~~and~~earnings ~~external~~before ~~electrical~~income ~~demands~~taxes ~~is an ongoing process intended to maintain the reliability~~ of approximately ~~electric service~~$63 million. ~~The~~These ~~Company~~adjustments ~~continually~~include ~~reviews~~impacts ~~the adequacy of its electric delivery~~to ~~facilities~~related ~~and~~gas ~~establishes~~deferral ~~capital~~balances. ~~requirements~~The tosignificant ~~support~~issues ~~(within~~resolved under the ~~above~~Stipulation ~~processes) its asset~~include: ~~renewal, existing load and new load growth needs.~~

~~Gas~~- ~~Supply:~~The Company will cease seeking to recover most disputed station service lost revenues. This resulted in a reduction to the deferral account and pre-tax earnings as of February 28, 2007 of $68 million. The ~~majority~~impact of the ~~Company’s~~settlement ~~gas~~on ~~sales~~future revenues depends on the usage by generators and prospective adjustments to delivery rates that are ~~for~~dependent ~~residential~~in part on commodity prices. We currently estimate a reduction in revenues of about $9 million to $12 million per year through December 31, 2011 which is the end of the MRP. - The Parties agreed to the method of determining incremental major storm costs related primarily to the treatment of third party contractor costs and ~~commercial~~costs ~~space heating~~incurred by affiliates during storm restoration efforts. The ~~Company~~definition ~~purchases~~of ~~its~~a ~~natural~~major ~~gas~~storm was also clarified under ~~firm~~the ~~supply~~Stipulation. ~~agreements~~Storm related adjustments resulted in a reduction of $10 million to the deferral account and pre-tax earnings. - The ~~natural~~Parties ~~gas purchased~~agreed ~~may~~to bethe ~~either~~method ~~transported~~of ordetermining ~~stored~~deferrable ~~for~~incremental ~~later~~costs ~~transport~~associated onwith the Company’s ongoing stray voltage inspection and testing program resulting in a ~~firm~~reduction ~~basis~~to ~~through interstate~~the ~~storage~~deferral ~~facilities~~account and ~~pipelines~~pre-tax earnings of $4 million. - The Parties agreed to the method for capitalizing fringe benefit overhead costs associated with the Company’s ~~system~~fixed asset construction activities. This resulted in a decrease to utility plant of $17 million, an increase to the deferral account of $11 million, and a reduction in pre-tax earnings of $6 million. - The Company is allowed to recover 50% of pension settlement losses that it incurred in fiscal years 2007 and 2004. This resulted in an increase to the deferral account and pre-tax earnings of $23 million related to fiscal 2007 and 2004 pension settlement losses. - Although it has no impact on past or future rates, the Company will exclude goodwill from any future earnings sharing filings and other filings made with the PSC.

~~Gas~~Certain ~~Delivery:~~deferral ~~The~~account ~~Company~~balances ~~sells,~~as ~~distributes~~of ~~and~~June 30, ~~transports~~2005 ~~natural~~remain ~~gas~~subject to aaudit ~~geographic~~by ~~territory~~the Staff. The ~~that~~Stipulation ~~generally~~also ~~extends~~clarifies ~~from~~going ~~Syracuse~~forward toprocedures ~~Albany~~for recording, reporting and auditing of certain other deferrals authorized for recovery. The ~~northern~~next ~~reaches~~biannual ofdeferral ~~the~~account ~~system~~filing ~~extend~~will tobe ~~Watertown~~made ~~and~~by ~~Glens~~August 1, ~~Falls.~~2007 ~~Not~~for ~~all~~deferral balances as of ~~the~~June 30, ~~Company’s~~2007 ~~distribution~~and ~~areas~~projected ~~are~~deferrals ~~physically~~through ~~interconnected~~December 31, ~~with~~2009. ~~one~~The ~~another~~Staff bywill ~~its~~audit ~~own~~future ~~facilities.~~biannual ~~The~~deferral ~~gas~~account ~~distribution~~filings ~~system~~made ispursuant ~~served~~to the byMRP, ~~3 interstate~~however ~~natural~~the ~~gas~~Parties ~~pipelines~~have ~~regulated~~agreed bythat the ~~FERC~~amount ~~and~~of ~~one~~deferral ~~intrastate~~recoveries ~~pipeline~~in ~~regulated~~calendar ~~by the~~year ~~PSC.~~2008 ~~The~~and ~~Company~~2009 ~~has~~will ~~nineteen~~not ~~direct~~exceed ~~connections~~the ~~with~~$200 million ~~Dominion~~level ~~Transmission,~~currently ~~Inc.,~~being ~~two~~collected ~~with~~in rates. Any ~~Iroquois~~deferrals ~~Gas~~in ~~Transmission,~~excess ~~one~~of ~~with~~this ~~Tennessee~~recovery ~~Gas~~level ~~Pipeline~~would ~~and~~be ~~one~~subject ~~with~~to ~~Empire~~recovery ~~State~~after ~~Pipeline (intrastate)~~2009.

Electric Supply: Although the Company has exited the generation business, the Company must still arrange for electric supply through a transition period and as provider of last resort. As such the Company will provide electricity to its customers who are unable or unwilling to obtain an alternative supplier which accounts for approximately 89% of the Company’s customers and 57% of its deliveries. The Company purchases energy from various suppliers under long-term Purchase Power Agreements (PPAs) and purchases any additional power needs on the open market through the New York Independent System Operator (NYISO). The Company also enters into financial swaps in order to hedge the price of electricity. For a discussion of the results of the power contracts and several financial agreements to hedge the price of electricity, see Part II, Item 8. Financial Statements and Supplementary Data — Note D – Commitments and Contingencies and Note L – Derivatives and Hedging Activities.

Electric Delivery: As of March 31, 2007, the Company had approximately 53,000 pole miles of transmission and distribution lines for electricity delivery. Evaluation of these facilities relative to the requirements of the New York State Reliability Council, Northeast Power Coordinating Council, North American Electric Reliability Council, NYISO and PSC, their orders, operating and planning guides and criteria, security considerations, and anticipated Company internal and external electrical demands is an ongoing process intended to maintain the reliability of electric service. The Company continually reviews the adequacy of its electric delivery facilities and establishes capital requirements to support (within the above processes) its asset renewal, existing load and new load growth needs.

Gas Supply: The majority of the Company’s gas sales are for residential and commercial space heating. The Company purchases its natural gas under firm supply agreements. The natural gas purchased may be either transported or stored for later transport on a firm basis through interstate storage facilities and pipelines to the Company’s system.

Gas Delivery: The Company sells, distributes and transports natural gas to a geographic territory that generally extends from Syracuse to Albany. The northern reaches of the system extend to Watertown and Glens Falls. Not all of the Company’s distribution areas are physically interconnected with one another by its own facilities. The gas distribution system is served by 3 interstate natural gas pipelines regulated by the FERC and one intrastate pipeline regulated by the PSC. The Company has nineteen direct connections with Dominion Transmission, Inc., two with Iroquois Gas Transmission, one with Tennessee Gas Pipeline and one with Empire State Pipeline (intrastate).

Compliance with Environmental Requirements: The Company’s operations and facilities are subject to numerous federal, state and local laws and regulations relating to the environment including, among other things, requirements concerning air and water quality; wetlands and flood plains; storage, transportation and disposal of hazardous wastes and substances; storage tanks; and site remediation. The Company believes it is handling identified wastes and by-products in a manner consistent with applicable requirements. The environmental management systems for the Company’s distribution, transmission and investment recovery facilities are certified to the International Organization for Standardization (ISO) 14001 standard. Management believes it is probable that costs associated with environmental compliance will continue to be recovered through the ratemaking process. The Company’s compliance has no material effect on its capital expenditures, earnings or competitive position. For a discussion of the Company’s reserves for environmental liabilities and its ability to recover these types of expenditures in rates, see Part II, Item 8. Financial Statements and Supplementary Data – Note B — Rate and Regulatory Issues.

The Company has implemented an environmental audit program to identify any potential areas of concern and aid in compliance with legal requirements. The Company is also currently conducting a program to investigate and remediate, as necessary to meet current environmental standards, certain properties associated with former gas manufacturing and other properties which the Company has learned may be contaminated with industrial waste, as well as investigating identified industrial waste sites as to which it may be determined that the Company has contributed. The Company has also been advised that various federal, state or local ~~agencies believe certain properties require~~ ~~investigation and has prioritized the sites based on available information in order to enhance the management of investigation and remediation, if necessary.~~

~~Employee Relations: The Company’s work force at March 31, 2006 numbered approximately 4,300~~6 employees, of whom approximately 82% were union members. The Company also receives substantial support for its activities from employees of National Grid USA Service Company, Inc., an affiliate that provides administrative services support to all National Grid companies. The Company reimburses the Service Company for the costs associated with those services.

agencies believe certain properties require investigation and has prioritized the sites based on available information in order to enhance the management of investigation and remediation, if necessary.

Employee Relations: The Company’s workforce at March 31, 2007 numbered approximately 3,950 employees, of whom approximately 81% were union members. The Company also receives substantial support for its activities from employees of National Grid USA Service Company, Inc., an affiliate that provides administrative services support to all National Grid companies. The Company reimburses the Service Company for the costs associated with those services.

The Company believes relations with employees are good.

Seasonality: There is seasonal variation in electric customer load, usually peaking in the winter and summer months. The seasonality is correlated with the colder or warmer temperature because more electricity is used for heating or cooling during those months.

There is a seasonal variation in gas customer sales, with loads usually peaking in the winter months. The seasonality is correlated with colder temperatures when more gas is used for heating.

Also see Part II, Item 8. Financial Statements and Supplementary Data — Note O- ~~Quarterly~~— ~~Financial~~Quarterly Financial Data (unaudited).

ITEM 1A. RISK FACTORS

This Annual Report on Form 10-K contains certain statements that are neither reported financial results nor other historical information. These statements are forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended. Because these forward-looking statements are subject to assumptions, risks and uncertainties, actual future results may differ materially from those expressed in or implied by such statements. We have identified the following risk factors that could have a material adverse effect on our business, financial condition, results of operations or future prospects, or your investment in our securities. Not all of these factors are within our control. In addition, other factors besides those listed below may have an adverse effect on the Company. Any forward-looking statements should be considered in light of these risk factors and the cautionary statement set out at the beginning of this report.

may have an adverse effect on the Company. Any forward-looking statements should be considered in light of these risk factors and the cautionary statement set out at the beginning of this report.

Regulatory and environmental risks

Changes in law or regulation could have an adverse effect on our results of operations.

Our business is heavily regulated, and changes in law or regulation could adversely affect us. Regulatory decisions concerning, for example, whether licenses or approvals to operate are renewed and the level of permitted revenues could have an adverse impact on our results of operations, cash flows and financial condition. Our rate plan provides for deferral and recovery of the effects of any externally imposed accounting changes, and changes in federal and state rates, laws, regulations and precedents governing taxes that increase or decrease our costs or revenues from electric operations by more than $2 million per year, or by an amount that exceeds 1% of annual gas earnings. However, these deferred amounts are subject to regulatory review and audit. This is discussed in more detail in Part II, Item 8. Financial Statements and Supplementary Data — Note B – Rate and Regulatory Issues of the Financial Statements.

Breaches of or changes in environmental or health and safety laws or regulations could expose us to claims for financial compensation and adverse regulatory consequences, as well as damaging our reputation.

Aspects of our activities are potentially dangerous, such as the operation and maintenance of electricity lines and the transmission and distribution of natural gas. Energy delivery companies also typically use and generate in their operations hazardous and potentially hazardous products and by-products. In addition, there may be other aspects of our operations that are not currently regarded or proved to have adverse effects but ~~could become so, for example, the effects of~~ electric and magnetic fields. We are subject to laws and regulations relating to pollution, the protection of the environment and how we use and dispose of hazardous substances and waste materials. We are also subject to laws and regulations governing health and safety matters including air quality, water quality, waste management, natural resources and the health and safety of the public and our employees. Any breach of these obligations, or even incidents relating to the environment or health and safety that do not amount to a breach, could adversely affect the results of operations and our reputation.

could become so, for example, the effects of electric and magnetic fields. We are subject to laws and regulations relating to pollution, the protection of the environment and how we use and dispose of hazardous substances and waste materials. We are also subject to laws and regulations governing health and safety matters including air quality, water quality, waste management, natural resources and the health and safety of the public and our employees. Any breach of these obligations, or even incidents relating to the environment or health and safety that do not amount to a breach, could adversely affect the results of operations and our reputation.

Changes to the regulatory treatment of commodity costs may have an adverse effect on the results of operations.

Changes in commodity prices could potentially affect our energy delivery businesses. Our rate plan permits us to pass through virtually all of the increased costs related to commodity prices to consumers. However, if this ability were restricted, it could have an adverse effect on our operating results.

Operational risks

Network failure or the inability to carry out critical non-network operations may have significant adverse impacts on both our financial position and our reputation.

We may suffer a major network failure or may not be able to carry out critical non-network operations. Operational performance could be adversely affected by a failure to maintain the health of the system or network, inadequate forecasting of demand or inadequate record keeping. This could cause us to fail to meet agreed standards, and even incidents that do not amount to a breach could result in adverse regulatory action and financial consequences, as well as harming our reputation. In addition to these risks, we are subject to other risks that are largely outside of our control such as the impact of weather or unlawful acts of third parties. Weather conditions can affect financial performance, and severe weather that causes outages or damages infrastructure will adversely affect operational and potentially, business performance. Terrorist attack, ~~sabotage~~ sabotage or other intentional acts may also physically damage our infrastructure or otherwise ~~significantly~~ significantly affect our activities and, as a consequence, affect the results of operations.

Our reputation may be harmed if customers suffer a disruption to their energy supply even if this disruption is outside of our control.

We are responsible for transporting available electricity and gas and, for those customers that have not chosen another supplier; we are also responsible for acquiring and providing electricity and gas which we procure from commodity suppliers. However, where there is insufficient supply, no matter the cause, our role is to manage the system safely, which, in extreme circumstances, may require us to disconnect consumers.

Our results of operations depend on a number of factors including performance against regulatory targets and the delivery of anticipated cost and efficiency savings.

Earnings maintenance and growth will be affected by our ability to meet regulatory efficiency targets. To meet these targets, we must continue to improve managerial and operational performance. Under our rate plan, earnings will be affected by our ability to deliver integration and efficiency savings. Earnings also depend on meeting service quality standards. To meet these standards, we must improve service reliability and customer service. If we do not meet these targets and standards, both the results of operations and our reputation may be harmed.

ITEM 1B. UNRESOLVED STAFF COMMENTS

There ~~are~~is no unresolved SEC staff comments required to be reported under this Item 1B.

ITEM 2. PROPERTIES

Electric Transmission and Distribution: As of March 31, ~~2006~~2007, the Company’s electric transmission and distribution systems were composed of:

• ~~717~~706 substations with a rated transformer capacity of approximately 23,~~090~~226,000 kilo-volt-amperes; • approximately 910,~~400~~500 pole miles of overhead and underground transmission lines; • approximately 36,000 conductor primary structure miles of overhead distribution lines; and • about 6,500 cable primary structure miles of underground distribution cables.

A portion of the Company’s transmission and distribution lines are located on property owned by the Company. With respect to the Company’s transmission and distribution lines that are located on property not owned by the Company, the Company’s practice is to obtain right of way agreements.

The electric system of the Company is directly interconnected with other electric utility systems in New York, Massachusetts, Vermont, Pennsylvania and the Canadian provinces of Ontario and Quebec, and indirectly interconnected with most of the electric utility systems through the Eastern Interconnection of the United States and Canada.

Gas Distribution: The Company distributes gas that it purchases from suppliers and transports gas owned by others. As of March 31, ~~2006~~2007, the Company’s natural gas delivery system was comprised of approximately 8,~~600~~100 miles of pipelines. Only a small part of these natural gas pipelines and mains are located on property owned by the Company. With respect to natural gas pipelines and mains that are not located on property owned by the Company, the Company’s practice is to obtain right of way agreements.

Native American Matters: The Company’s facilities are potentially affected by land claim litigation involving the Oneida, Mohawk and Onondaga Nations. Other than the Cayuga Nation’s and Seneca land claims, which have been dismissed by the courts, the land claim litigation has not been resolved. The Company continues to monitor the land claim litigation and, where necessary, defend its interests.

Mortgage Liens: Substantially all of the Company’s operating properties are subject to mortgage liens securing its mortgage debt.

ITEM 3. LEGAL PROCEEDINGS ~~None.~~

None.

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

NoThe ~~matters~~following ~~were~~actions ~~submitted to a vote of security holders~~ during the ~~last~~previous ~~quarter~~quarters of ~~the~~ fiscal year ended March 31, ~~2006.~~2007 Onwere ~~May 3, 2006,~~ taken by unanimous written consent of the sole common ~~stockholder~~shareholder in lieu of a special meeting,

	o		~~The~~On ~~following~~November ~~persons were elected as directors: William F. Edwards~~13, ~~Barbara~~2006 A.the ~~Hassan,~~resignation of Michael E. Jesanis, ~~Michael~~was J.accepted ~~Kelleher,~~and ~~Cheryl~~the A.number ~~LaFleur,~~of ~~Clement~~directors E.was ~~Nadeau,~~decreased ~~and~~from ~~Anthony~~seven C.to ~~Pini~~six.
	o		~~PricewaterhouseCoopers~~On ~~LLP~~December ~~was~~13, ~~appointed~~2006 the ~~Company’s~~resignation ~~independent~~of ~~registered~~Clement ~~public~~E. ~~accounting~~Nadeau ~~firm~~was ~~for~~accepted effective December 31, 2006 and the ~~fiscal~~number ~~year~~of ~~ending~~directors ~~March~~was ~~31,~~decreased ~~2007~~from six to five.

PART II


ITEM 5.		MARKET FOR THE REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDERS MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

The common stock of the Company is held solely by Niagara Mohawk Holdings, Inc., and therefore indirectly by National Grid and National Grid plc. There is no public trading market for the Company’s common stock. The Company did not purchase any of its equity securities during the fourth quarter of fiscal ~~2006~~2007. For information about the Company’s payment of dividends and restrictions on those payments, see Item 6. Selected Consolidated Financial Data and Item 8. Financial Statements and Supplementary Data.

ITEM 6. SELECTED CONSOLIDATED FINANCIAL DATA

AtThe ~~the~~following ~~time~~table ofsets ~~the~~forth ~~merger~~selected ~~with~~financial ~~National~~information ~~Grid,~~for the Company ~~changed~~for ~~its~~the ~~fiscal~~years ~~year from a~~ended ~~calendar year ending December~~March 31, to2007, a2006, ~~fiscal~~2005, ~~year~~2004, ~~ending~~and ~~March 31~~2003. ~~The~~These ~~Company~~tables ~~made~~have ~~this change~~been inderived ~~order~~from tothe ~~align~~financial statements ~~its fiscal year with that~~ of ~~its~~the ~~parent company, National Grid. The~~ Company’s ~~first~~and ~~new~~should ~~full~~be ~~fiscal~~read ~~year~~in ~~began~~connection ~~on April 1, 2002 and ended on March 31, 2003~~therewith.

The following ~~tables set forth~~ selected financial ~~information~~data for the Company ~~for~~may ~~the years~~not ~~ended~~be ~~March 31,~~indicative ~~2006,~~of ~~2005, 2004, 2003,~~ the ~~sixty~~Company’s ~~day period ended March 31, 2002,~~future ~~the~~financial ~~thirty day period ended January 30~~condition, ~~2002,~~results ~~the three months ended March 31, 2001, and the year ended December 31, 2001. These tables have been derived from the financial statements~~ of ~~the~~operations ~~Company~~or ~~and~~cash ~~should be read in connection therewith~~flows.

On January 31, 2002, the Company was acquired by National Grid in a purchase business combination recorded under the “push-down” method of accounting, resulting in a new basis of accounting for the “successor” period beginning January 31, 2002. Information relating to all “predecessor” periods prior to the acquisition is presented using the Company’s historical basis of accounting. The following selected financial data for the Company may not be indicative of the Company’s future financial condition, results of operations or cash flows.


	Fiscal Years Ended March 31,
(In thousands of dollars)	2007		2006		2005		2004		2003

Operating revenues	$	4,131,655	$	4,344,023	$	3,925,171	$	4,063,617	$	4,019,450

Net income		189,577		317,076		263,249		139,690		125,871

Income (loss) from continuing operations per average common share		*		*		*		*		*

Total assets		12,166,755		12,294,815		12,518,362		12,618,659		12,549,865

Long-term debt		2,650,065		2,925,065		2,923,569		3,473,467		3,953,989

Mandatorily redeemable preferred stock		—		—		—		—		—

Dividends paid per common share		*		*		*		*		*

9 * As all of the Company’s shares of common stock are owned by its parent company, dividend information and per share data are not relevant.

													60 Day			30 Day			Three
													Period			Period			months
	Year Ended			Year Ended			Year Ended			Year Ended			Ended			Ended			Ended			Year Ended
	March 31,			March 31,			March 31,			March 31,			March 31,			January 30,			March 31,			December 31,
(in 000’s except	2006			2005			2004			2003			2002			2002			2001			2001
per share data)	(Successor)			(Successor)			(Successor)			(Successor)			(Successor)			(Predecessor)			(Predecessor)			(Predecessor)
Operating revenues	$	4,344,023		$	3,925,171		$	4,063,617		$	4,019,450		$	689,705		$	362,622		$	1,179,706		$	4,114,713
Net income (loss)		317,076			263,249			139,690			125,871			30,646			(20,941	)		34,010			19,358
Income (loss) from continuing operations per average common share			*			*			*			*			*			*			*			*
Total assets		12,280,968			12,518,362			12,618,659			12,549,865			12,101,588				**		12,037,039			11,436,554
Long-term debt		2,648,934			2,923,569			3,473,467			3,953,989			4,146,642				**		4,674,004			4,419,822
Mandatorily redeemable preferred stock		—			—			—			—			—				**		53,750			50,700
Dividends paid per common share			*			*			*			*			*			*			*			*

*		As all of the Company’s shares of common stock are owned by its parent company, dividend information and per share data are not relevant.
**		Balance Sheet information as of the 30 day period ended January 30, 2002 is not provided.


ITEM 7.		MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The Business: The Company’s primary business driver is the long-term rate plan with state regulators through which the Company can earn and retain certain amounts in excess of traditional regulatory allowed returns. The plan provides incentive returns and shared savings allowances which allow the Company an opportunity to benefit from efficiency gains identified within operations. Other main business drivers for the Company include the ability to streamline operations, enhance reliability and generate funds for investment in the Company’s infrastructure.

CRITICAL ACCOUNTING POLICIES

The preparation of financial statements in conformity with generally accepted accounting principles in the United States of America (GAAP) requires management to apply policies and make estimates and assumptions that affect the results of operations and the reported amounts of assets and liabilities in the financial statements. Because of the inherent uncertainty in the nature of the matters where estimates are used, actual amounts could differ from estimated amounts. The following accounting policies represent those that management believes are particularly important to the financial statements and require the use of judgment in estimating matters that are inherently uncertain.

Regulatory Assets and Liabilities: Regulatory assets represent costs that have been deferred to future periods when it is probable that the regulator (namely, the FERC, PSC, or other regulatory body with jurisdiction) will allow future recovery of those costs through rates. The Company bases its assessment of recovery by either specific recovery measures (such as current rate agreements with the PSC) or historical precedents established by the regulatory body. Regulatory liabilities represent previous collections from customers to fund future expected costs or amounts received in rates that are expected to be refunded to customers in future periods. These regulatory assets and liabilities typically include deferral of under recovered or over recovered energy costs, environmental restoration costs and post retirement benefit costs, as well as the normalization of income taxes, and the deferral of losses incurred on debt retirements. The accounting for these regulatory assets and liabilities is in accordance with the provisions of SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation.”

specific recovery measures (such as current rate agreements with the PSC) or historical precedents established by the regulatory body. Regulatory liabilities represent previous collections from customers to fund future expected costs or amounts received in rates that are expected to be refunded to customers in future periods. These regulatory assets and liabilities typically include deferral of under recovered or over recovered energy costs, environmental restoration costs and post retirement benefit costs, as well as the normalization of income taxes, and the deferral of losses incurred on debt retirements. The accounting for these regulatory assets and liabilities is in accordance with the provisions of SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation.”

The Company continually assesses if its regulatory assets continue to meet the criteria for probability of future recovery. This assessment considers factors such as changes in the regulatory environment, recent rate orders to other regulated entities under the same jurisdiction, and the status of any pending or potential deregulation legislation. If future recovery of costs becomes no longer probable, the regulatory assets and liabilities would be recognized as current-period revenues or expenses.

Amortization of regulatory assets is provided over the recovery period as allowed in the related regulatory agreement. Under the ~~Merger Rate Plan~~MRP, a regulatory asset, called stranded costs, was ~~established~~ established that included the costs of the Master Restructuring Agreement (MRA), the cost of any ~~additional~~ additional Independent Power Producer (IPP) contract buyouts and the deferred loss on the sale of ~~the~~ the Company’s generation assets. The MRA represents the cost to terminate, restate or amend IPP contracts. The Company is also permitted to defer and amortize the cost of any additional IPP contract buyouts. Beginning February 1, 2002, the ~~Merger~~MRP ~~Rate Plan~~ stranded costs regulatory asset is being amortized unevenly over ten years with larger amounts being amortized in the latter years, consistent with projected recovery through rates. Amortization of the stranded cost regulatory asset is shown separately because it is the largest component of regulatory assets. ~~Amortization~~ of other regulatory assets are included in depreciation and amortization, purchased electricity & gas, and other operation and maintenance expense captions on the income statement depending on the origin of the regulatory asset.

Amortization of other regulatory assets are included in depreciation and amortization, purchased electricity & gas, and other operation and maintenance expense captions on the income statement depending on the origin of the regulatory asset.

Revenues: The Company bills its customers on a monthly cycle basis at approved tariffs based on energy delivered and a minimum customer service charge. Revenues are determined based on these bills plus an estimate for unbilled energy (discussed below) delivered between the cycle billing date and the end of the accounting period.

Unbilled Revenues: Revenues from the sale of electricity and gas to customers are generally recorded when electricity and gas are delivered to those customers. The quantity of those sales is measured by customers’ meters. Meters are read on a systematic basis throughout the month based on established meter-reading schedules. Consequently, at the end of any month, there exists a quantity of electricity and gas that has been delivered to customers but has not been captured by the meter readings. As a result, management must estimate revenue related to electricity and gas delivered to customers between their meter read dates and the end of the period.

Pension and Other Post-retirement Benefit Plans: The Company maintains qualified and nonqualified pension plans. The Company also provides health care and life insurance benefits for its retired employees. The Company’s pensions are funded through an outside trust.

11Several assumptions affect the pension and other post-retirement benefit expense and the measurement of these benefit obligations. The more significant assumptions include the return on assets, discount rate, and in the case of retiree healthcare benefits, medical trends. All ongoing costs of qualified pension and post-retirement healthcare benefits plans are recoverable from customers through reconciling provisions of the MRP. Special termination benefits paid in connection with employee separation programs and settlement and curtailment losses of pension and post-retirement benefit plans when incurred are only recoverable upon approval by the PSC.

curtailment losses of pension and post-retirement benefit plans when incurred are only recoverable upon approval by the PSC.

The major assumptions are:

• ~~Return~~Expected return on assets. The assumed rate of return for various passive asset classes is based on both analysis of historical rates of return and forward looking analysis of risk premiums and yields. Current market conditions, such as inflation and interest rates, are evaluated in connection with the setting of long-term assumptions. A small premium is added for active management of both equity and fixed income. The rates of return for each asset class are then weighted in accordance with the target asset allocation, and the resulting long-term return on asset rate is then applied to the market~~-related~~ value of assets. For fiscal ~~2006~~2007, the Company used an 8% assumed return on assets for its pension plan and a weighted average of 7.8% assumed return on assets for its other post-retirement benefits plans. • Discount rate. The Company bases its discount rate on two measures of rates specific to the yield curve applicable to the liabilities of the plans. The actuary calculates the present value of the projected cash flows of the plans utilizing derived zero coupon interest rates specific to the timing of each respective cash flow and calculates the single weighted average interest rate that equates the total present value with the stream of future cash flows. This results in a weighted average interest rate of 5.8792% based on the Citigroup Pension Discount Curve, which is based on AA-rated corporate bonds, and an interest rate of 6~~.16~~% based on a yield curve of top quartile yielding Aa corporate bonds. A discount rate of 6%, ~~the average between the two rates,~~ was deemed appropriate for the plans. • Medical trends. The health care cost trend rate is the assumed rate of increase in per-capita health care charges. In fiscal year 2006, the health care cost trend assumption was updated to include rates for the pre 65 and post 65 age groups. For ~~2006~~2007, the initial health trend was assumed to be 10% for the pre 65 age group and 11% for the post 65 age group. The ultimate trend of 5%, for both age groups, was assumed to be reached in 2011 for the pre 65 age group and 2012 for the post 65 age group.

Goodwill: The Company applies the provisions of SFAS No. 142, “Goodwill and Other Intangible Assets.” In accordance with SFAS No. 142, goodwill must be reviewed for impairment at least annually and when events or circumstances indicate that the asset may be impaired. The Company utilized a discounted cash flow approach incorporating its most recent business plan forecasts in the performance of the annual goodwill impairment test. The result of the annual analysis determined that no adjustment to the goodwill carrying value was required. As a result of a settled IRS audit of pre-merger years, the Company recorded a $9 million adjustment to goodwill related to a pre-merger tax contingency.

Tax Provision: The Company’s income tax provisions, including both current and deferred components, are based on estimates, assumptions, calculations, and interpretation of tax statutes for the current and future years in accordance with SFAS No. 109, “Accounting for Income Taxes.” Determination of current year federal and state income tax will not be settled until final approval of returns by taxing authorities.

Management regularly makes assessments of tax return outcomes relative to financial statement tax provisions and adjusts the tax provisions in the period when facts become final.

~~contract~~Refer isto ~~designated as a cash flow hedge,~~ the ~~change~~adoption ~~in its market value is generally deferred as a component~~ of ~~other comprehensive income until~~ the ~~transaction~~new itaccounting isstandard ~~hedging~~SFAS ~~is completed~~No. ~~Conversely~~ 158, ~~the~~“Employers’ ~~change~~Accounting ~~in the market value of a~~for ~~derivative~~Defined ~~not~~Benefit ~~designated~~Pension as a cash flow hedge is deferred as a regulatory asset or liability because the Company has received approval from the PSC to establish a regulatory asset or liability for derivative instruments that did not qualify for hedge accounting and ~~were~~Other ~~the~~Postretirement ~~result~~Plans” ofunder ~~regulatory rulings. A cash flow hedge is a hedge of a forecasted transaction or~~ the ~~variability~~New ~~of cash~~Accounting ~~flows~~Standards tosection ~~be received or paid related to a recognized asset or liability~~below. ~~To qualify as a cash~~ ~~flow hedge, the fair value changes in the derivative must be expected to offset 80% to 120% of the changes in fair value or cash flows of the hedged item.~~

Goodwill: The Company applies the provisions of SFAS No. 142, “Goodwill and Other Intangible Assets.” In accordance with SFAS No. 142, goodwill must be reviewed for impairment at least annually and when events or circumstances indicate that the asset may be impaired. The Company utilized a discounted cash flow approach incorporating its most recent business plan forecasts in the performance of the annual goodwill impairment test. The result of the annual analysis determined that no adjustment to the goodwill carrying value was required.

Federal and State Income Taxes: Regulated federal and state income taxes are recorded under the provisions of Financial Accounting Standards Board (FASB) SFAS No. 109 “Accounting for Income Taxes.” Income taxes have been computed utilizing the asset and liability approach that requires the recognition of deferred tax assets and liabilities for the tax consequences of temporary differences by applying enacted statutory tax rates applicable to future years to differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities. Deferred investment tax credits are amortized over the useful life of the underlying property.

The Company’s income tax provisions, including both current and deferred components, are based on estimates, assumptions, calculations, and interpretation of tax statutes for the current and future years. Determination of current year federal and state income tax will not be settled until final approval of returns by taxing authorities.

Management regularly makes assessments of tax return outcomes relative to financial statement tax provisions and adjusts the tax provisions in the period when facts become final.

Accounting for Derivative Instruments: The Company accounts for derivative financial instruments under SFAS No. 133, “Accounting for Derivatives and Hedging Activities,” and SFAS No. 149, “Amendment of SFAS No. 133 on Derivative Instruments and Hedging Activities,” as amended. All derivatives except those qualifying for the normal purchase normal sale exception are recognized on the balance sheet at their fair value. Fair value is determined using current quoted market prices. If a contract is designated as a cash flow hedge, the change in its market value is generally deferred as a component of other comprehensive income until the transaction it is hedging is completed. Conversely, the change in the market value of a derivative not designated as a cash flow hedge is deferred as a regulatory asset or liability because the Company has received approval from the PSC to establish a regulatory asset or liability for derivative instruments that did not qualify for hedge accounting and were the result of regulatory rulings. A cash flow hedge is a hedge of a forecasted transaction or the variability of cash flows to be received or paid related to a recognized asset or liability. To qualify as a cash flow hedge, the fair value changes in the derivative must be expected to offset 80 percent to 120 percent of the changes in fair value or cash flows of the hedged item.

RESULTS OF OPERATIONS

The following discussion and analysis highlights items that significantly affected the Company’s operations during the fiscal years ended March 31, ~~2006~~2007 and ~~2005~~2006.

EARNINGS

Net income for the fiscal year ended March 31, ~~2006~~2007 ~~increased~~decreased by ~~approximately~~ $54127 million ~~over~~compared to the same period in the prior fiscal year. ~~This~~The ~~increase~~decrease is ~~primarily~~ due to ~~higher~~the ~~electric~~deferral ~~and~~account ~~gas~~audit ~~margin~~write ofoff of $4863 million ~~which~~, ishigher ~~mostly~~operation ~~attributable~~and tomaintenance ~~favorable~~expense, ~~electric~~lower ~~volume in delivery-only~~ sales, ~~reduced interest costs~~ of ~~approximately~~electricity ~~$21 million~~due ~~and a positive adjustment~~ to ~~electric revenues of $32 million~~milder ~~stemming~~weather ~~from~~conditions in the ~~recognition~~current offiscal ayear ~~regulatory~~as ~~asset~~compared ~~reflecting~~to ~~our~~the ~~ability~~prior toyear, ~~recover~~and a ~~previously~~positive ~~fully~~adjustments ~~reserved~~to ~~account~~electric ~~receivable.~~revenues ~~These were offset by increased income tax expense~~ of $19 32 million, ~~increased~~recorded ~~depreciation~~in ~~expense~~the ofprior ~~$3 million,~~year ~~increased~~with ~~operating~~no ~~and maintenance expense~~comparable ofadjustments ~~$9 million~~in ~~and~~the ~~increased~~current ~~other deductions of $16 million~~year. ~~See~~These ~~the~~decreases ~~following~~were ~~discussions of~~partially ~~revenues and operating expenses for more detailed explanations.~~

Net income for the year ended March 31, 2005 increased by approximately $124 million over the prior fiscal year. This increase is primarily due to decreased retiree benefit expense of $54 million relating to one-time items, a decrease in bad debt expense of $19 million, and reduced interest costs of approximately $47 million. See the following discussions of revenues and operating expenses for more detailed explanations.

REVENUES

Electric revenues increased $190 million during the year ended March 31, 2006 from the prior fiscal year. Electric revenues decreased $167 million in the twelve months ended March 31, 2005 relative to the prior fiscal year. See the table below for the contributing factors.

Change in Electric Revenue for the fiscal year ended
(in millions of dollars)	March 31, 2006			March 31, 2005
Retail sales	$	52		$	(98	)
Delivery only sales and miscellaneous revenue		185			20
Sales for resale		(47	)		(89	)
Total	$	190		$	(167	)

Retail sales include distribution delivery charges and recovery of purchased power costs from customers who purchase their electric supply from the Company. Delivery only sales are charges for only the delivery of energy for customers who purchase their power from competitive electricity suppliers. The Company recovers all costs incurred to procure power for customers that do not receive power from competitive suppliers.

~~The~~offset ~~increase~~by inlower ~~retail~~income ~~sales,~~tax ~~for~~expense ~~the~~and ~~fiscal~~reduced ~~year~~interest ~~ended March 31, 2006 is primarily due to the higher cost of electricity purchased which is being passed through to customers~~expense. ~~The~~See ~~increase in delivery only sales is primarily due to~~ the ~~migration~~following ofdiscussions ~~retail electric customers to competitive suppliers for their commodity requirements which has been occurring since the start~~ of ~~electricity~~ deregulation in the state of New York. The migration of customers is also a contributing factor to the decrease in retail kilowatt-hour (kWh) sales (see table below) in the fiscal years ended March 31, 2006 and 2005. Another contributing factor to the increase in revenue was a $32 million positive adjustment to electric revenues ~~stemming from the recognition of a regulatory asset reflecting our ability to recover a previously fully reserved account receivable. Warmer summer~~ and ~~colder~~operating ~~autumn~~expenses ~~weather than experienced in the previous fiscal year also contributed to the increase in revenue~~ for ~~the~~more ~~fiscal~~detailed ~~year ended March 31, 2006~~explanations.

~~The~~Net ~~migration~~income offor ~~retail~~the ~~electric~~fiscal ~~customers~~year toended ~~competitive~~March 31, ~~suppliers~~2006 ~~was~~increased aby ~~contributing~~approximately ~~factor~~$54 million ~~for~~compared to the ~~decrease~~same period in ~~retail~~the prior fiscal year. This increase is primarily due to higher electric and gas margin of $48 million which is mostly attributable to favorable electric volume in delivery-only sales, reduced interest costs of approximately $21 million and a positive adjustment to electric revenues inof $32 million stemming from the ~~fiscal~~recognition ~~year~~of ~~ended~~a ~~March 31,~~regulatory ~~2005~~asset ~~partially~~reflecting our ability to recover a previously fully reserved account receivable. They were offset by ~~increases~~increased inincome tax expense of $19 million, increased depreciation expense of $3 million, increased operating and maintenance expense of $9 million and increased other deductions of $16 million. See the ~~price~~following discussions of ~~electricity~~revenues ~~that~~and ~~was~~operating ~~passed~~expenses onfor tomore ~~customers~~detailed explanations.

~~Sales for resale represent sales of electricity to the NYISO at the market price of electricity.~~REVENUES All electricity purchased under certain purchased power contracts is sold to the NYISO. The decreases in sales to the NYISO for the years ended March 31, 2006 and March 31, 2005 were due to the expiration of some of these contracts.

Electric ~~kilowatt-hour sales were approximately 35.8 billion and 36.6 billion for the fiscal years~~ ~~ended March 31, 2006 and 2005, respectively. The table below details components of the 0.8 and 1.9 billion decrease in kWh sales for the 2006 and 2005 fiscal years, respectively:~~

Change in kWh Deliveries for the fiscal year ended
(kWh in billions)	March 31, 2006			March 31, 2005
Retail sales		(1.6	)		(1.4	)
Delivery only sales		2.3			1.6
Total deliveries to ultimate customers		0.7			0.2
Sales for resale		(1.5	)		(2.1	)
Total deliveries		(0.8	)		(1.9	)

The Company’s electricity business encompasses the transmission and distribution of electricity including stranded cost recoveries. Rates are set based on historical or forecasted costs, and the Company earns a return on its assets, including a return on the “stranded costs” associated with the divestiture of the Company’s generating assets under deregulation. Since the start of electricity deregulation in the state of New York, retail electric customers have been migrating to competitive suppliers for their commodity requirements. Commodity costs are passed through directly to customers.

~~Gas~~Electric ~~revenues~~revenue ~~increased $229 million in the fiscal year ended March 31, 2006 from the prior fiscal~~includes: ~~year. This increase is primarily a result of higher prices of gas purchases which are being passed through to customers.~~

~~Gas~~• ~~revenues~~Retail ~~increased~~sales ~~$28 million~~— ~~for~~delivery ~~the~~charges ~~fiscal~~and ~~year~~recovery ~~ended~~of ~~March 31,~~purchased ~~2005~~power costs from customers who purchase their electric supply from the ~~prior~~Company. ~~fiscal year~~• ~~primarily~~Delivery ~~due~~only tosales ~~higher~~– ~~prices~~charges for only the delivery of ~~gas~~energy ~~purchases~~for ~~which~~customers ~~are~~who ~~being~~purchase ~~passed~~their ~~through~~power tofrom ~~customers~~competitive electricity suppliers. ~~This~~ ~~increase~~• ~~was~~Sales ~~affected~~for byresale ~~the~~– ~~elimination~~sales of aexcess ~~$6 million~~electricity ~~adjustment~~to ~~related~~the toNYISO ~~state~~at ~~net income~~the ~~tax~~market ~~recorded~~price inof ~~the~~electricity. ~~fiscal~~Any ~~year~~gains ~~ended~~or ~~March 31,~~losses ~~2004~~on ~~and~~sales ~~reversed~~for inresale ~~the~~are ~~fiscal~~passed ~~year~~through ~~ended March 31,~~directly ~~2005~~to customers.

~~The table below details components of the gas revenue fluctuation:~~Gas

Change in Gas Revenue for the fiscal year ended
(in millions of dollars)	March 31, 2006			March 31, 2005
Cost of purchased gas	$	232		$	31
Delivery revenue		(2	)		(4	)
Other		(1	)		1
Total	$	229		$	28

The Company is also a gas distribution company that services customers in cities and towns in central and eastern New York. The Company’s gas rate plan allows it to recover all commodity costs (i.e., the purchasing, interstate transportation and storage of gas for sale to customers) from customers (similar to the recovery of purchased electricity).

Gas revenue includes:

	•		Retail sales – distribution (transportation) of gas and the commodity to customers who purchase their gas supply from the Company.

	•		Transportation revenue – charges for the transportation of gas to customers who purchase their gas commodity from other suppliers.

	•		Off-System wholesale sales – sales of gas commodity off its distribution system for resale.

Electric revenues decreased $50 million during the fiscal year ended March 31, 2007 compared to the same period in the prior fiscal year. The decrease in electric revenue was primarily due to an $80 million adjustment related to settlement of the deferral audit, a decrease due to the migration of customers to competitive suppliers, a 2.3% decrease in kWh deliveries due to milder weather than experienced in the prior fiscal year, a reduction in the cost of electricity that was passed on to customers, and a positive adjustment was made to electric revenues of $32 million in fiscal year 2006 with no comparable adjustment in the current fiscal year. The deferral audit settlement adjustment was primarily due to the write off of deferred disputed station service revenues. The $32 million positive adjustment recorded in the prior year due to a one-time recognition of a regulatory asset related to the recovery of a previously fully reserved accounts receivable. These decreases were partially offset by an increase of $150 million of rate plan deferral revenues and increased energy

management assessment revenues. The deferral revenues do not impact net income since the Company recognizes an equal offsetting amount of amortization expense. For further information regarding the deferral audit stipulation, see Part II, Item 8. Financial Statements and Supplementary Data - Note B - Rate and Regulatory Issues.

Electric revenues increased $190 million during the year ended March 31, 2006 from the prior fiscal year. Retail sales revenues increased $52 million primarily as a result of higher costs of electricity purchased which were passed through to customers. Another contributing factor to the increase in revenue was a $32 million positive adjustment to electric revenues stemming from the recognition of a regulatory asset reflecting our ability to recover a previously fully reserved account receivable. Delivery only sales and miscellaneous revenues increased $185 million primarily due to the migration of retail electric customers to competitive suppliers for their commodity requirements. The migration of customers is also a contributing factor to the decrease in retail kilowatt-hour (kWh) sales in the fiscal years ended March 31, 2006. Warmer summer and colder autumn weather than experienced in the previous fiscal year also contributed to the increase in revenue for the fiscal year ended March 31, 2006. Offsetting these increases was a $47 million decrease of sales for resale. All electricity purchased under certain purchased power contracts is sold to the NYISO. The decreases in sales to the NYISO for the year ended March 31, 2006 was due to the expiration of some of these contracts.

Gas revenues decreased $162 million in the fiscal year ended March 31, 2007 compared to the same period in the prior fiscal year. This decrease is primarily due to both decreased prices of gas purchases which were passed through to customers and decreased volumes of gas sold to customers.

Gas revenues increased $229 million in the fiscal year ended March 31, 2006 from the prior fiscal year. This increase is primarily a result of higher prices of gas purchases which were passed through to customers.

The table below details components of the gas revenue fluctuation:


Change in Gas Revenue
	Fiscal Years Ended March 31,
(In millions of dollars)	2007			2006

Cost of purchased gas	$	(159	)	$	232
Delivery revenue		(3	)		(2	)
Other		—			(1	)

Total	$	(162	)	$	229

The change in the cost of purchased gas has no impact on the Company’s net income because the actual commodity costs are passed through to customers on a dollar-for-dollar basis.

Gas sales volumes for the fiscal year ended March 31, ~~2006~~2007, excluding transportation of customer-owned gas, decreased approximately 31.98 million Dekatherms (Dth), or a 63.41% decrease from the prior fiscal year. Gas sales for the fiscal year ended March 31, ~~2005~~2006, excluding transportation of customer-owned gas, decreased approximately 3.69 million Dth, or a 56.74% decrease from the fiscal year ended March 31, ~~2004~~2005. The decreased gas usage for the fiscal year ended March 31, ~~2006~~2007 compared with the fiscal year ended March 31, ~~2005~~2006 is ~~partially~~primarily due to ~~the~~a ~~impacts~~decrease ofin weather-normalized ~~and to decreased~~ use per customer ~~as a result of higher natural gas prices, offset in part by the return of customers from alternate providers~~. The decreased gas usage for the fiscal year ended March 31, 2006 ~~2005~~ compared with the fiscal year ended March 31, ~~2004~~2005 is partially due to the impacts of weather , and todecreased use per customer, somewhat offset by the ~~migration~~return of customers to from alternate providers.

OPERATING EXPENSES

Purchased electricity increased approximately $100 million for the fiscal year ended March 31, 2006 from the prior fiscal year. The volume of kWh purchased decreased 3.2 billion kWh, or 12% compared with the prior fiscal year, reflecting migration of customers to competitive electricity suppliers and the expiration of certain sales for resale purchased power contracts. This volume decrease was offset by a 22% increase in the price of electricity relative to the prior fiscal year.

Purchased electricity decreased approximately $227 million for the fiscal year ended March 31, 2005 from the prior fiscal year. The Company purchased less kWh of electricity versus the prior fiscal year because of the migration of customers to competitive electricity suppliers and the expiration of certain sales for resale purchased power contracts. This volume decrease was offset by a 2% increase in the price of electricity relative to the prior fiscal year.

Purchased gas expense increased approximately $232 million for the fiscal year ended March 31, 2006 from the prior fiscal year. This increase is primarily the result of increased gas prices during the year and an increase in the amount of gas sold off-system. The Company’s net cost per Dth, as charged to expense, including the effects of the gas cost deferral, increased to $9.92 in the fiscal year ended March 31, 2006 from $7.12 in the prior fiscal year. The increase due to price was slightly offset by decreased purchases.

Purchased gas expense increased approximately $31 million for the fiscal year ended March 31, 2005 compared with the fiscal year ended March 31, 2004. This increase is primarily a result of increased gas prices during the year. The Company’s net cost per Dth, as charged to expense, including the effects of the gas cost deferral, increased to $7.12 for the year ended March 31, 2005 from $6.61 in the prior fiscal year ended March 31, 2004.

For a discussion of hedging of gas purchases, see Item 7A. Quantitative and Qualitative Disclosures about Market Risk – “Gas Supply Price Risk.”

~~Other~~OPERATING ~~operation and maintenance expense increased $9 million for the year ended March 31, 2006 from~~EXPENSES ~~the prior fiscal year. The table below details components of this fluctuation.~~

	For the year		For the year
	ended		Ended
(in millions of dollars)	March 31, 2006		March 31, 2005			Change
Storm costs	$	18	$	—		$	18
Bad debt expense		42		45			(3	)
Payroll costs		260		277			(17	)
Recovery of pension settlement loss		—		(14	)		14
Consultants & contractors		90		101			(11	)
Materials and supplies		30		27			3
Transportation costs		28		25			3
Rents		28		25			3
Service quality penalties		9		4			5
Loss on sale of facilities		—		8			(8	)
Other		213		211			2
Total	$	718	$	709		$	9

Purchased electricity decreased $75 million for the fiscal year ended March 31, 2007 from the prior fiscal year primarily as a result of a decrease in volume purchased. The volume of kWh purchased decreased 1.3 billion kWh or 5.6% compared to the same period in the prior fiscal year, reflecting migration of customers to competitive electricity suppliers and milder weather. This volume decrease was offset by a 1% increase in the price of electricity relative to the prior fiscal year.

~~The~~Purchased ~~increase~~electricity increased $100 million for the fiscal year ended March 31, 2006 isfrom ~~primarily due to higher~~the ~~non-recoverable~~prior ~~storm~~fiscal ~~related~~year. ~~costs~~The volume of ~~$18 million~~kWh ~~and~~purchased adecreased ~~one-time $14~~3.2 ~~million~~billion ~~pension~~kWh, ~~settlement loss~~or ~~recovery~~12% ~~recorded~~compared inwith the prior fiscal year, reflecting ~~the~~migration ~~PSC’s~~of ~~July 2004~~customers ~~approval~~to ~~for~~competitive ~~the~~electricity ~~Company~~suppliers toand the ~~recover~~expiration ~~a portion~~ of ~~the~~certain ~~$30 million~~sales ~~pension~~for ~~settlement~~resale ~~loss~~purchased ~~incurred~~power incontracts. ~~fiscal~~This ~~year~~volume ~~2003.~~decrease ~~These were~~was ~~partially~~ offset by a ~~decrease~~22% increase in ~~payroll~~the ~~costs~~price of ~~$17 million~~electricity ~~primarily~~relative ~~attributable~~ to ~~ongoing~~ ~~headcount reductions and reduced consultant and contractor costs of $11 million mostly due to merger related efficiencies. Also offsetting~~ the ~~increase~~prior ~~was~~fiscal ~~a reduction in bad debt expense of $3 million reflecting the Company’s strong focus on managing bad debts despite increased commodity costs and increased accounts receivable~~year.

~~The~~Purchased ~~Company~~gas isdecreased ~~also~~$159 million ~~subject~~for tothe ~~service~~fiscal ~~quality~~year ~~standards~~ended ~~with~~March 31, ~~respect~~2007 compared to ~~reliability~~the ~~and certain~~same ~~aspects~~period ofin ~~customer~~the ~~service~~prior ~~and~~fiscal ~~safety~~year. ~~The~~This ~~Company~~decrease ~~works~~is ~~toward~~primarily ~~service~~the ~~quality~~result ~~standards~~of ~~that~~decreased ~~the~~gas prices ~~state~~during ~~regulators~~the ~~expect~~year usand toa ~~achieve.~~decrease Ifin the amount of gas sold off-system. The Company’s ~~falls~~net ~~below~~cost aper Dth, ~~prescribed~~as ~~standard~~charged to expense, aincluding ~~penalty is~~the ~~incurred.~~effects ~~The~~of ~~Company~~the ~~missed~~gas ~~targets~~cost ~~for~~deferral, ~~reliability~~decreased to $8.29 in the fiscal ~~years~~year ended March 31, ~~2006~~2007 ~~and~~from $9.92 in the prior fiscal year. The decrease in ~~2005,~~purchased ~~incurring~~gas ~~penalties~~expense was also affected by decreased purchases of ~~$9 million~~gas ~~and~~on ~~$4 million,~~behalf ~~respectively~~of system customers.

~~Other~~Purchased ~~operation~~gas ~~and maintenance~~ expense ~~decreased~~increased $84232 million for the fiscal year ended March 31, ~~2005~~ 2006 from the prior fiscal year. ~~The~~This ~~decrease~~increase ~~was~~is primarily ~~due~~the toresult aof ~~$54 million~~increased ~~decrease~~gas ~~relating to~~prices ~~one-time~~during ~~retiree~~the ~~benefit~~year and ~~expenses~~an ~~(which~~increase ~~includes~~in the ~~pension~~amount ~~settlement~~of ~~loss~~gas ~~recovery~~sold ofoff-system. ~~$14 million~~The ~~mentioned~~Company’s ~~above),~~net acost ~~reduction~~per inDth, ~~bad~~as ~~debt~~charged to expense, ofincluding ~~$19 million~~the ~~which~~effects ~~resulted~~of ~~from improved~~the ~~collection~~gas ~~practices~~cost ~~and~~deferral, ~~$8 million~~increased ofto ~~storm~~$9.92 ~~expenses recorded~~ in the ~~2004~~ fiscal year ~~with~~ended noMarch 31, ~~similar~~2006 ~~expense~~from ~~recorded~~$7.12 in the prior fiscal year ~~2005~~. ~~These~~The ~~decreases~~increase ~~were~~due ~~offset~~to byprice anwas ~~$8 million~~slightly ~~loss~~offset onby ~~the~~decreased ~~sale of facilities in fiscal year 2005~~purchases.

~~Depreciation~~For ~~and~~a ~~amortization~~discussion ~~expense~~of ~~increased~~hedging ~~$3 million~~of ~~for~~gas ~~the fiscal year ended March 31~~purchases, ~~2006 from~~see ~~the prior fiscal year because capital projects went into service~~Item 7A. ~~For~~Quantitative ~~the~~and ~~fiscal year ended~~Qualitative ~~March 31,~~Disclosures ~~2005,~~about ~~depreciation~~Market ~~and~~Risk ~~amortization~~– ~~expense~~“Gas ~~remained~~Supply ~~constant~~Price ~~relative to the prior fiscal year~~Risk.”

~~Amortization~~Other ofoperation ~~stranded~~and ~~costs~~maintenance expense increased $1575 million and $579 million for the ~~fiscal~~ years ended March 31, ~~2006~~2007 and ~~March 31,~~2006 ~~2005,~~compared ~~respectively,~~to ~~from~~ the ~~prior~~same ~~fiscal~~periods ~~years~~ in ~~accordance with~~ the ~~Merger~~ ~~Rate~~prior ~~Plan.~~fiscal ~~Under the Merger Rate Plan the stranded cost regulatory asset amortization period was established for recovery over the ten year period ending December 31, 2011~~years. ~~This~~The ~~asset is~~table ~~being amortized unevenly on an increasing, graduated schedule. See Item 8. Financial Statements~~below ~~and~~details ~~Supplementary~~components ~~Data — Note B — Rate and Regulatory Issues — “Stranded Costs” for a further discussion~~ of ~~the ratemaking treatment related to~~ this ~~regulatory asset~~fluctuation.


	For the Years Ended March 31,
(In millions of dollars)	2007			2006

Storm costs	$	13		$	18
Bad debt expense		11			(3	)
Payroll and benefit costs		(1	)		(17	)
Pension settlement loss		2			14
Consultants and contractors		25			(11	)
Materials and supplies		—			3
Rents		2			3
Service quality penalties		2			5
Energy management assessments		10			2
Uninsured claims and damages		6			—
Other		5			(5	)

Total	$	75		$	9

The Company is allowed to recover from customers the costs of major storms in which the costs and/or number of customers affected exceed certain specified thresholds. Non-recoverable storm costs are composed of: (1) the first $8 million of costs, cumulatively, associated with major storms, and (2) the costs of each storm thereafter that does not qualify as a major storm as defined in the Company’s rate plan. Non-recoverable

~~Other~~storm ~~taxes~~costs ~~decreased~~increased ~~approximately~~in ~~$8 million~~both ~~for~~fiscal years 2007 and 2006 compared to the same period in the prior fiscal years due to a higher incidence of severe storms that occurred in the current fiscal year ~~ended~~as compared ~~March~~to the prior year. In October 312006, ~~2006~~the ~~from~~Company suffered the most significant storm ~~prior~~damage ~~fiscal~~it ~~year~~has ~~primarily~~experienced ~~due~~in toWestern ~~reduced~~New ~~gross~~York ~~receipts~~since ~~tax~~the ~~(GRT).~~Company ~~This~~began ~~reduction~~serving inthe ~~GRT~~area ismore than ~~primarily~~100 years ~~due~~ago. toMost ~~lower~~of ~~rates~~the ~~and~~costs ~~reduced~~associated ~~tax~~with ~~base,~~this ~~partially~~storm ~~offset~~are byrecoverable. aThe ~~slight~~regulatory ~~increase in~~asset ~~property~~associated ~~taxes~~with this storm was $81 million at March 31, 2007.

~~Other~~Bad ~~taxes~~debt ~~decreased~~expense ~~approximately~~increased by $911 million ~~for~~in the fiscal year ended March 31, ~~2005~~2007 ~~from~~as ~~the~~a result of ~~prior~~increased ~~fiscal~~accounts ~~year~~receivable ~~primarily~~write-offs. ~~due~~Bad todebt ~~reduced~~expense ~~GRT.~~decreased ~~This~~by ~~reduction~~$3 million in ~~GRT~~the isfiscal year ~~primarily~~ended ~~due~~March 31, to2006 ~~lower rates~~as ~~and~~a ~~reduced~~result ~~revenues~~of improved collection practices.

~~Income~~Payroll ~~taxes~~and ~~increased~~benefit ~~$19 million~~costs, ~~for~~excluding ~~the~~storm ~~fiscal~~related costs decreased in the year ended March 31, ~~2006 from the prior fiscal~~2007 ~~year primarily~~ due to ~~higher~~staff ~~pre-tax~~reductions ~~book~~but ~~income~~were substantially offset by athe ~~$4 million~~write ~~benefit~~off ~~related~~of todeferred ~~prior years’~~benefit ~~tax~~costs ~~return~~in connection ~~true-ups~~with ~~and~~the ~~settlements~~Company’s settlement of ~~tax~~the ~~audits.~~deferral ~~Income~~audit ~~taxes~~proceeding ~~increased~~(See ~~$32~~Part ~~million~~II, ~~for~~Item 8. ~~the~~Financial ~~fiscal~~Statements ~~year~~and ~~ended~~Supplementary ~~March 31,~~Data ~~2005~~– ~~relative~~Note toB ~~the~~– ~~prior~~Rate ~~fiscal~~and ~~year~~Regulatory ~~primarily~~Issues). ~~due~~Payroll toand ~~higher~~benefit ~~pre-tax~~costs, ~~book~~excluding ~~income~~storm ~~offset~~related bycosts adecreased by $2017 million ~~decrease~~ in ~~prior~~the ~~years’~~fiscal ~~tax~~year ~~return~~ended ~~true-ups~~March 31, 2006, primarily due to staff reductions and a greater reliance on contractors.

In fiscal year 2007, the Company incurred a pension settlement loss of $25 million. The Company reached settlement with Staff to recover 50% of the pension settlement loss of $25 million recorded in fiscal year 2007 and approval to recover 50% of the $21 million pension settlement loss recorded in fiscal year 2004. This resulted in a $2 million net pension settlement loss recorded for the fiscal year ended March 31, 2007. In fiscal year 2005, the Company recorded a one-time $14 million pension settlement loss recovery with no comparable entry in fiscal year 2006. For further information, see Part II, Item 8. Financial Statements and Supplementary Data — Note H — Employee Benefits in the Footnotes to the Financial Statements and Note B – Rate and Regulatory Issues.

Consultants and contractor costs increased $25 million and decreased $11 million for the fiscal years ended March 31, 2007 and 2006, respectively. The increase in consultants and contractor costs in fiscal year 2007 is partially due to increased tree trimming costs associated with the Company’s reliability improvement program. Also, the Company has been utilizing more external vendors in response to future merger integration initiatives. The decrease in fiscal year 2006 was mostly due to merger related efficiencies that resulted from the Company’s merger with National Grid.

Service quality penalties have increased in part due to the doubling of the penalty associated with failing to achieve a particular electric reliability measure related to system interruptions. Service quality penalties are described in Part II, Item 8. Financial Statements and Supplementary Data — Note B — Rate and Regulatory Issues. The Company missed targets for reliability in fiscal years ended March 31, 2007 and 2006, resulting in increased penalties of $2 million and $5 million, respectively.

Energy management assessments represent amounts assessed by the New York State Energy Research Development Agency for state-wide renewable energy initiatives and electric system benefit programs. Any increases or decreases in these assessments results in an offsetting adjustment to revenues.

Uninsured claims and damages increased $6 million for the fiscal year ended March 31, 2007 compared to the same period in the prior year. The increase in uninsured claims and damages is primarily due to an increase in liabilities for new and existing cases.

Depreciation and amortization expense increased $6 million and $3 million for the fiscal year ended March 31, 2007 and 2006, compared to the same period in the prior fiscal year. Increases were due to additional capital projects that were placed in service in each of the fiscal years.

Amortization of stranded costs and rate plan deferrals increased $150 million and $15 million for the fiscal years ended March 31, 2007 and March 31, 2006, respectively, from the same period in the prior fiscal years

in accordance with the amortization of deferral accounts established under the MRP. Beginning April 1, 2006, the Company implemented a $100 million rate increase for the nine-month period ended December 31, 2006 to recover these deferred costs described in “Revenues” above. On January 1, 2007, the Company implemented an additional $200 million increase through December 31, 2007 to recover these deferred costs. These two increases resulted in a $150 million increase in revenue for the twelve-month period ended March 31, 2007. The Company records an equal amount of amortization expense to offset the increase in electric revenues. Also under the MRP, the stranded investment regulatory asset is amortized unevenly at levels that increase over the ten-year term of the plan ending December 31, 2011. The change in the amortization of stranded costs and deferral accounts is included in the Company’s rates and does not impact net income. See Part II, Item 8. Financial Statements and Supplementary Data — Note B — Rate and Regulatory Issues - “Stranded Costs” for a further discussion of the ratemaking treatment related to this regulatory asset.

Other taxes increased $1 million for the fiscal year ended March 31, 2007 compared to the same period in the prior fiscal year. The increase was a result of a $10 million increase in gross receipts tax due to a large decrease in the Power for Jobs tax credit partially offset by a $5 million decrease in property taxes due to reductions in the assessed value of relevant properties, as well as decreases in franchise tax and payroll taxes.

Other taxes decreased $8 million for the fiscal year ended March 31, 2006 from the prior fiscal year primarily due to reduced gross receipts tax (GRT). This reduction in GRT is primarily due to lower rates and reduced tax base, partially offset by a slight increase in property taxes.

Income taxes decreased $69 million for the fiscal year ended March 31, 2007 compared to the same period in the prior fiscal year primarily due to lower book pre-tax income partially offset by an $8 million charge related to prior years’ tax return true-ups and settlement of tax audits.

Income taxes increased $19 million for the fiscal year ended March 31, 2006 from the prior fiscal year primarily due to higher pre-tax book income offset by a $4 million benefit related to prior years’ tax return true-ups and settlements of tax audits.

OTHER INCOME (DEDUCTIONS), INTEREST AND PREFERRED DIVIDENDS

Other income (deductions) ~~decreased~~increased by $163 million for the fiscal year ended March 31, ~~2006~~2007 ~~from the~~compared ~~prior~~to ~~fiscal year and increased by $16 million for~~ the ~~year~~same ~~ended~~period ~~March 31,~~in ~~2005 relative to~~ the prior fiscal year,. ~~primarily~~This was due to a ~~$9 million~~write ~~settlement~~off of an ~~estimated liability and~~ an ~~$8 million~~interconnection arrangement ~~favorable~~project ~~adjustment to non-utility related income taxes which were recorded~~ in ~~the 2005~~ fiscal year 2006 with no similar ~~adjustments~~write ~~recorded~~off in ~~the 2006 or 2004~~ fiscal ~~years~~year 2007.

~~Interest~~Other ~~charges~~income (deductions) decreased $2116 million for the fiscal year ended March 31, 2006 from the ~~prior~~ prior fiscal year. ~~The decrease is~~ primarily due to ~~maturing~~a ~~long-term~~$9 million ~~debt~~settlement ~~replaced~~of ~~with~~an ~~affiliated~~estimated liability and an $8 ~~company~~million ~~debt~~favorable atadjustment ~~lower~~to ~~interest~~non-utility ~~rates~~related income taxes which were ~~partially~~recorded ~~offset~~in bythe ~~increased~~2005 fiscal ~~interest~~year ~~payments~~with ~~on short~~no ~~term~~similar ~~debt~~adjustments ~~due~~recorded toin ~~higher~~fiscal ~~interest~~year ~~rates~~2006.

Interest charges decreased $4711 million and $21 million for the fiscal ~~year~~years ended March 31, ~~2005~~2007 and 2006 from the prior fiscal ~~year~~years. The decrease is primarily due to ~~maturing~~scheduled repayments of long-term debt ~~and~~being ~~to the early redemption of third-party debt which were~~ replaced with affiliated company debt atwith lower interest rates. ~~and which~~This ~~were~~ was partially offset by increased interest ~~payments~~charges ondue to increased short- term debt ~~because~~at ofhigher ~~increased~~interest ~~average~~rates ~~short-term~~as ~~borrowings~~well ~~and~~as higher interest rates on the tax-exempt variable rate debt.

EFFECTS OF CHANGING PRICES

The Company’s financial results and financial position are impacted by inflation because of the amount of capital it typically needs and because its prices are regulated using a rate-base methodology that reflects the historical cost of utility plant.

The Company’s financial statements are based on historical events and transactions. The effects of inflation on most utilities, including the Company, are most significant in the areas of depreciation and utility plant. In addition, the Company would not replace these assets with identical assets because of technological advances and competitive and regulatory changes that have occurred. In light of these considerations, the depreciation charges in operating expenses do not reflect the cost of providing service if new facilities were installed. See “Long – Term Outlook” under “Liquidity and Capital Resources” below for a discussion of the Company’s future capital requirements.

LIQUIDITY AND CAPITAL RESOURCES

Short-Term Outlook: At March 31, ~~2006~~2007, the Company’s principal sources of liquidity included cash and cash equivalents of $1116 million and accounts receivable of $~~654~~671 million. The Company has a negative working capital balance of $195 million primarily due to $200 million of long-term debt due within one year and short-term debt due to affiliates of $395 million (see the intercompany money pool discussion below in Item 8). Cash is being generated from sales (via electric rates) to offset stranded cost amortization (non-cash expense). This excess cash is used to repay debt and for other operating needs. As discussed below, the Company believes it has sufficient cash flow and borrowing capacity to fund working capital deficits as necessary in the near term.

17At March 31, 2006, the Company’s principal sources of liquidity included cash and cash equivalents of $11 million and accounts receivable of $654 million. The Company has a negative working capital balance of $461 million primarily due to $275 million of long-term debt due within one year and short-term debt due to affiliates of $579 million (see the intercompany money pool discussion below in Item 8). Cash is being generated from sales (via electric rates) to offset stranded cost amortization (non-cash expense). This excess cash is used to repay debt and for other operating needs. As discussed below, the Company believes it has sufficient cash flow and borrowing capacity to fund working capital deficits as necessary in the near term.

~~Table~~Net ofcash ~~Contents~~provided by operating activities increased $30 million for the fiscal year ended March 31, 2007 compared to the same period in the prior fiscal year. The primary reasons for the increase in operating cash flow are:

~~capital~~• ~~balance~~Increase in accounts payable and accrued expenses of $~~461~~ 68 million ~~primarily~~ due to ~~$275 million~~higher purchased power expense accruals of ~~long-term~~$17 ~~debt~~ million primarily due ~~within~~to ~~one~~a ~~year~~higher ~~and~~cost ~~short-term~~per ~~debt~~kWh, ~~due~~unpaid toinvoice ~~affiliates~~accrual increases of $~~579~~ 16 million ~~(see~~mainly ~~the~~due ~~intercompany money~~to ~~pool~~storm ~~discussion~~costs, ~~below~~and inother ~~Item 8).~~increases ~~Cash~~partly isrelated ~~being~~to ~~generated~~service ~~from~~company ~~sales~~charges ~~(via~~due ~~electric~~to ~~rates)~~a ~~to offset~~change ~~stranded~~in ~~cost~~estimates ~~amortization~~and ~~(non-cash~~other ~~expense)~~increases including customer deposits. ~~This~~• ~~excess~~Decrease ~~cash~~in isaccounts ~~used~~receivable of $65 million primarily due to ~~repay~~the ~~debt~~higher cost of electricity and ~~for~~ ~~other~~gas ~~operating~~passed ~~needs.~~along Asto ~~discussed~~customers ~~below,~~in ~~the~~fiscal ~~Company~~years ~~believes~~2007 itand ~~has~~2006 ~~sufficient~~versus ~~cash~~fiscal ~~flow~~ year 2005. • Decrease in materials and ~~borrowing~~supplies ~~capacity~~of $36 million due to ~~fund~~lower ~~working~~levels ~~capital~~of ~~deficits~~gas asstorage. ~~necessary~~• Decrease in net income of $127 million offset by the ~~near~~recovery ~~term~~of rate plan deferrals of $150 million.

These were partially offset by:

•

Increase in pension and other postretirement benefits of $111 million.

Net cash provided by operating activities decreased approximately $141 million for the fiscal year ended March 31, 2006 from the prior fiscal year. The primary reasons for the decrease in operating cash flow are:

• Decreased provision for deferred income taxes of $77 million primarily due to the expiration of federal bonus depreciation in December of 2004. • Increased accounts receivable of $89 million primarily due to the higher cost of electricity and gas passed along to customers. • Increased materials and supplies of $29 million primarily due to the higher cost of stored gas and the lower volume of gas sold relative to the prior fiscal year because of milder winter temperatures. • Increased other ~~regulatory~~net assets of $~~128~~190 million primarily due to $128 million of higher commodity prices and timing differences between expenditures and their recovery from customers recorded in regulatory assets.

These were partially offset by:

• Increased net income (see income discussion above) of $54 million. • Increased pension and other benefit plans expense of $7 million. • ~~Increased~~Lower ~~accounts~~required ~~payable~~funding of employee pension and ~~accrued~~other ~~expenses~~benefits of $3014 million. • Increased ~~accrued~~accounts ~~interest~~payable and ~~tax~~accrued ~~expense~~expenses of $6030 million. • ~~Lower~~Increased ~~required~~accrued ~~funding~~interest ~~of employee pension~~ and ~~other~~tax ~~benefits~~expense of $1460 million. • Increased amortization of stranded costs of $15 million in accordance with the Merger Rate Plan. • Increased depreciation and amortization expense of $3 million.

The Company’s net cash used in investing activities decreased $71 million for the fiscal year ended March 31, 2007 from the comparable period in the prior fiscal year. This decrease was primarily a result of decreased restricted cash due to equity in hedge accounts related to the change in the underlying commodity price.

The Company’s net cash used in investing activities increased $119 million for the fiscal year ended March 31, 2006 from the comparable period in the prior fiscal year. This increase was primarily a result of increased restricted cash due to equity in hedge accounts related to the rise in the underlying commodity price.

The Company’s net cash used in financing activities increased $87 million for the fiscal year ended March 31, 2007 from the comparable period in the prior fiscal year. This increase in the use of cash resulted primarily from the pay down of short-term debt to affiliates in the current year of $184 million and a decrease in borrowings of $178 million. This was offset by a decrease in the pay down of long term debt of $275 million.

The Company’s net cash used in financing activities decreased $258 million for the fiscal year ended March 31, 2006 from the comparable period in the prior fiscal year. This decrease resulted primarily from increased short-term debt to affiliates of $241 million.

Long-Term Outlook: The Company’s total capital requirements consist of amounts for its construction program, electricity and gas purchases, working capital needs and maturing debt issues. Generally, construction expenditure levels for the energy delivery business are consistent from year-to-year, however, the Company ishas ~~embarking~~embarked on a Reliability Enhancement Program, to improve performance and reliability, which will result in increased capital expenditures over the next ~~five~~four years.

The Company’s long-term debt due within one year is $~~275~~200 million at March 31, ~~2006~~2007. In addition, construction expenditures planned within one year are estimated to be approximately $~~337~~378 million. These capital requirements are planned to be financed primarily from internally generated funds and borrowings from other National Grid companies through the intercompany money pool.

1820

The following table summarizes long-term contractual cash obligations of the Company:

			Contractual obligations due in
			Less than		1 - 3		4 - 5
($’s in millions)	Total		one year		years		years		Thereafter
(In millions of dollars)	Total		one year		years		years		Thereafter
Long-term debt	$	2,~~925~~649	$	~~275~~200	$	~~800~~950	$	~~700~~350	$	1,~~150~~149
Short-term debt due to affiliates*		579		579		N/A		N/A		N/A
Short-term debt due to affiliates (a)		395		395		n/a		n/a		n/a
Interest on long-term debt**		509		147		232		130		N/A
Interest on long-term debt (b)		517		132		194		191		n/a
Electric purchase power commitments		43,~~144~~762		~~456~~449		~~854~~792		~~606~~513		2,~~228~~008
Gas supply commitments		~~557~~435		~~295~~291		~~247~~93		1150		41
Derivative swap commitments***		537		247		290		N/A		N/A
Derivative swap commitments (c)		268		222		46		n/a		n/a
Construction expenditures****		337		337		N/A		N/A		N/A
Construction expenditures (d)		378		378		n/a		n/a		n/a
Total contractual cash obligations	$	9,588	$	2,336	$	2,423	$	1,447	$	3,382
Expected contributions – pension and PBOP (e)		277		277		n/a		n/a		n/a
Total contractual cash obligations	$	8,681	$	2,344	$	2,075	$	1,104	$	3,158

*		Classified as a current liability because all borrowings are payable on demand.
**		Forecasted and actual amounts could differ due to changes in market conditions. Amounts beyond 5 years are not forecasted and, therefore, are not included.
***		Forecasted and actual amounts could differ due to changes in market conditions.
****		Represents budgeted amounts for which substantial commitments have been made. Amounts beyond 1 year are not considered contractual obligations and are therefore not included.


^(a)		Classified as a current liability because all borrowings are payable on demand.

^(b)		Forecasted and actual amounts could differ due to changes in market conditions. Amounts beyond 5 years are not forecasted and, therefore, are not included.

^(c)		Forecasted and actual amounts could differ due to changes in market conditions.

^(d)		Represents budgeted amounts for which substantial commitments have been made. Amounts beyond 1 year are not considered contractual obligations and are therefore not included.

^(e)		Represents expected company contributions.

Expected contributions to trusts of the Company’s pension and post-retirement benefit plans (as disclosed in Item 8. Financial Statements and Supplementary Data — Note H — Employee Benefits) are not included in the above table.

See Item 8. Financial Statements and Supplementary Data — Note D — Commitments and Contingencies, for a detailed discussion of the electric purchase power commitments and the gas supply, storage and pipeline commitments, Note L — Derivatives and Hedging Activities for a detailed discussion of IPP and fossil/hydro swaps and Note E — Long-Term Debt for a detailed discussion of mandatory debt repayments.

The Company also has the ability to issue first mortgage bonds to the extent that there have been maturities or early redemptions of them since June 30, 1998. Through March 31, ~~2006~~2007, the Company had approximately $2.14 billion in such first mortgage bond maturities and early redemptions. ~~This~~ ~~increased to $2.4 billion in May of 2006.~~

~~New Accounting Standards: In December 2004, the Financial Accounting Standards Board (FASB) issued~~Acquisitions Statement of SFAS No. 123R, “Share-Based Payment.” SFAS No. 123R addresses the accounting for transactions in which a company receives employee services in exchange for (a) equity instruments of the company or (b) liabilities that are based on the fair value of the company’s equity instruments or that may be settled by the issuance of such equity instruments. SFAS No. 123R also eliminates the ability to account for share-based compensation transactions using Accounting Principles Board (APB) Opinion No. 25, “Accounting for Stock Issued to Employees,” and requires that such transactions be accounted for using a fair-value-based method. SFAS No. 123R was originally effective for public companies for interim and annual periods beginning after June 15, 2005; however, in April 2005 the SEC delayed the effective date of SFAS No. 123R to annual, rather than interim, periods that begin after June 15, 2005. The SEC’s new rule resulted in a six-month deferral for the Company. The adoption of SFAS No. 123R on April 1, 2006 does not have a material impact on its results of operations or its financial position.

19In 2006, National Grid plc, the ultimate parent of the Company, announced the proposed acquisition of KeySpan Corporation (KeySpan) for $7.3 billion together with the assumption of approximately $4.5 billion of debt. This would significantly expand its operations in the northeastern US as KeySpan is the fifth largest distributor of natural gas in the US and the largest in the northeast US, serving 2.6 million customers in New York, Massachusetts and New Hampshire. KeySpan also operates an electricity transmission and distribution network serving 1.1 million customers in New York under a long-term contract with the Long Island Power Authority. KeySpan’s other interests include 6.6 GW of generation capacity, together with a small portfolio of non-regulated, energy-related services, and strategic investments in certain gas pipeline, storage and liquefied natural gas assets. The planned combination of its current US operations with those of KeySpan would result in National Grid plc becoming the third largest energy utility in the US.

National Grid plc has made significant progress towards completion and has achieved several important milestones. National Grid plc has obtained clearances from the Federal Trade Commission in respect of the

InHart-Scott-Rodino ~~March 2005~~Antitrust Improvements Act, from the ~~FASB~~Committee ~~issued~~on ~~Interpretation~~Foreign Investment ~~No. 47~~in ~~(FIN~~the ~~47)~~US and by the Federal Energy Regulatory Commission, ~~“Accounting~~and ~~for~~received ~~Conditional~~approval ~~Asset~~from ~~Retirement~~both ~~Obligations.”~~National ~~FIN~~Grid 47plc ~~will~~and ~~result~~KeySpan ~~in:~~shareholders. ~~(a)~~In March ~~more~~2007, ~~consistent~~National ~~recognition~~Grid plc and KeySpan announced an agreement with the staff of ~~liabilities~~the Long Island Power Authority in principle regarding ~~relating~~amended contracts, which is subject to ~~asset~~approval ~~retirement~~by ~~obligations,~~the ~~(b)~~board of the Authority and by the Comptroller and Attorney General of New York. In April ~~more~~2007, ~~information~~the ~~about~~staff ~~expected~~of ~~future~~the ~~cash~~New ~~outflows~~Hampshire Public Utilities ~~associated~~Commission announced that they would recommend approval. National Grid plc has also made filings with ~~those~~the ~~obligations~~New York Public Service Commission and has ~~(c) more~~held ~~information~~extensive ~~about~~discussions ~~investments~~with inregulatory ~~long-lived~~staff ~~assets because~~and ~~additional~~other ~~asset~~interested ~~retirement~~parties ~~costs~~that ~~will~~have yielded besignificant ~~recognized~~progress astoward ~~part~~resolution of ~~the~~issues ~~carrying~~important ~~amounts~~to the completion of the ~~assets~~acquisition. National Grid plc anticipates achieving a final result that will benefit investors and consumers alike by this autumn.

ANew ~~conditional retirement obligation, which is referred to in SFAS No. 143, “~~Accounting ~~for Asset~~Standards: Retirement Obligations,” is defined in FIN 47 as a legal obligation to perform an asset retirement activity in which the timing and (or) method of settlement are conditional upon a future event that may or may not be within the entity’s control. The obligation to perform the asset retirement activity is unconditional even though 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 has sufficient information to make a reasonable estimate of the fair value of an asset retirement obligation. FIN 47 is effective for the Company as of its March 31, 2006 fiscal year end. The Company has a $10 million asset retirement obligation reserve as of March 31, 2006 which does not have a material impact on the Company’s results of operations or 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,” defined the requirements for the accounting for and the reporting of a change in accounting principle. SFAS No. 154 requires retrospective application to prior periods’ financial statements of changes in accounting principle, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. When it is impracticable to determine the period-specific effects of an accounting change on one or more individual prior periods presented, SFAS No. 154 requires that the new accounting principle be applied to the balances of assets and liabilities as of the beginning of the earliest period for which retrospective application is practicable and that a corresponding adjustment be made to the opening balance of retained earnings for that period rather than being reported in an income statement. SFAS No. 154 became ~~becomes~~ effective for fiscal years ending after December 15, 2005. The Company adopted itSFAS No. 154 as of its March 31, 2006 fiscal year with no impact.

OnIn ~~March~~December 312004, ~~2006,~~ the FASB issued anSFAS ~~Exposure~~No. 123R, ~~Draft~~“Share-Based ofPayment.” ~~proposed~~SFAS ~~rules~~No. 123R onaddresses the ~~employers’~~ accounting for ~~defined~~ ~~benefit~~transactions ~~pensions~~in ~~and~~which ~~other~~a ~~postretirement~~company ~~benefit~~receives ~~plans~~employee ~~that~~services ~~would~~in ~~require~~exchange ~~employers~~for to(a) ~~fully~~equity ~~recognize~~instruments of the ~~plan’s~~company ~~funded~~or ~~status~~(b) liabilities that are based on the ~~balance~~fair ~~sheet.~~value Ifof ~~adopted~~the company’s asequity ~~proposed,~~instruments ~~the~~or ~~new rules~~that ~~would~~may be ~~applied~~settled ~~retroactively~~by tothe ~~prior~~issuance ~~financial~~of ~~statements~~such ~~presented~~equity ~~and~~instruments. SFAS beNo. 123R ~~effective~~also eliminates the ability to account for share-based compensation transactions ~~fiscal~~using ~~years~~Accounting ~~ending~~Principles ~~after~~Board ~~December~~(APB) ~~15,~~Opinion ~~2006~~No. 25, ~~The~~“Accounting ~~new~~for ~~rules,~~Stock ifIssued ~~adopted~~to ~~as proposed~~Employees, ~~may~~” ~~significantly~~and ~~increase~~requires ~~the~~that ~~Company’s~~such ~~recorded~~transactions ~~pension~~be ~~and~~accounted ~~other~~for ~~postretirement~~using ~~liabilities~~a fair-value-based method. ~~Under~~SFAS No. ~~the~~123R ~~current~~was ~~rate~~originally ~~agreements~~effective ~~with~~for ~~the~~public ~~PSC,~~companies ~~the~~for ~~Company~~interim ~~would~~and ~~recover~~annual ~~the~~periods ~~additional~~beginning ~~pension costs~~after ~~from~~June 15, ~~customers~~2005; ~~and~~however, ~~therefore~~in April 2005 the ~~costs~~Securities ~~would~~and beExchange ~~recognized~~Commission as(SEC) delayed athe effective ~~regulatory~~date ~~asset~~of ~~upon~~SFAS ~~adoption~~No. 123R ~~The comment~~to ~~period~~annual, onrather ~~this~~than ~~Exposure~~interim, ~~Draft~~periods ~~ended~~that onbegin ~~May~~after June 3115, ~~2006~~ 2005. The ~~Company~~adoption isof ~~currently~~SFAS ~~evaluating the~~No. 123R ~~Exposure~~on ~~Draft~~April 1, ~~and~~2006 atdid ~~this~~not ~~time~~have ~~cannot~~a ~~determine~~material ~~the full~~ impact ~~that~~on the ~~potential~~ ~~requirements~~Company’s results of ~~the~~operations ~~Exposure~~or ~~Draft may have on~~ its financial ~~statements~~position.

In July 2006, the FASB issued Interpretation No. 48 (FIN 48), “Accounting for Uncertainty in Income Taxes – an interpretation of FASB Statement No. 109.” FIN 48 clarifies the accounting and reporting for uncertainties in income tax law. FIN 48 prescribes a comprehensive model for the financial statement recognition, measurement, presentation and disclosure of uncertain tax positions taken or expected to be taken in income tax returns. The cumulative effect of applying the provision of this interpretation are required to be reported separately as an adjustment to the opening balance of retained earnings in the year of adoption. FIN 48 is effective for fiscal years beginning after December 15, 2006 and will be effective for the Company in the first quarter of its 2008 fiscal year. The Company is currently evaluating the impact the adoption of FIN 48 will have on its financial statements and is not yet in a position to determine such effects.

In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements,” which provides enhanced guidance for using fair value measurements in financial reporting. While the standard does not expand the use of fair value in any new circumstance, it has applicability to several current accounting standards that require or permit entities to measure assets and liabilities at fair value. This standard defines fair value, establishes a framework for measuring fair value in GAAP and expands disclosures about fair value

measurements. The Company is currently evaluating SFAS No. 157 and at this time cannot determine the full impact that the potential requirements may have on its financial statements.

In September 2006, the FASB issued SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans.” This standard amends SFAS Nos. 87, 88, 106 and 132(R). SFAS No. 158 requires an employer with a defined benefit pension plan or other postretirement plan to recognize an asset or liability on its balance sheet for the overfunded or underfunded status of the plan as defined by SFAS No. 158. The Company adopted SFAS No. 158 on March 31, 2007. The pension asset or liability is the difference between the fair value of the pension plan’s assets and the projected benefit obligation as of the year end. For post-retirement benefit plans other than pensions (PBOPs), the asset or liability is the difference between the fair value of the plan’s assets and the accumulated postretirement benefit obligation as of year end. At March 31, 2007, the Company recorded a combined liability of $443 million in connection with the adoption of SFAS No. 158. The Company has specific recovery of pension and PBOP expense and has recognized an offsetting regulatory asset in lieu of recording a charge to Accumulated other comprehensive income (AOCI) for the adjustment relating to its qualified pension plan and its PBOPs. For the non-qualified pension plan, the adoption of SFAS No. 158 resulted in a net change to AOCI of $1.3 million.

In September 2006, the SEC issued Staff Accounting Bulletin (SAB) No. 108, “Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements.” SAB No. 108 requires companies to quantify the impact of correcting misstatements using both an income statement (rollover) approach and a balance sheet (iron curtain) approach. If the misstatement of prior year expense is material to the current year, after all of the relevant quantitative and qualitative factors are considered, the prior year financial statements should be corrected. Correcting prior year financial statements for immaterial errors would not require previously filed reports to be amended.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The Company is exposed to certain market risks because of transactions conducted in the normal course of business. The financial instruments held or issued by the Company are used for investing, financing, hedging or cost control and not for trading.

Quantitative and qualitative disclosures are discussed by market risk exposure category:

20 § Commodity Price Risk § Gas Supply Price Risk § Electricity Price Risk § Interest Rate Risk § Equity Price Risk § Foreign Currency Exchange Risk

§ Interest Rate Risk § Commodity Price Risk § Equity Price Risk § Foreign Currency Exchange Risk

An Energy Procurement Risk Management Committee (EPRMC) was established to monitor and control efforts to manage commodity risks. This committee issues and oversees the Financial Risk Management Policy (the Policy) which outlines the parameters within which corporate managers are to engage in, manage and report on various areas of commodity risk exposure. At the core of the Policy is a condition that the Company will engage in activities at risk only to the extent that those activities fall within commodities and financial markets to which it has an actual market exposure in terms and in volumes consistent with its core business. That core business is to deliver energy, in the form of electricity and natural gas, to customers within the Company’s service territory. The policies of the Company may be revised as its primary markets continue to change, principally as increased competition is introduced and the role of the Company in these markets evolves.

Commodity Price Risk: The Company is exposed to commodity market price fluctuations related to: (1) the cost of electricity and natural gas for resale to its customers, and (2) the impact that natural gas, electricity and oil prices have on the swap contracts and one large non-Master Restructuring Agreement (MRA) IPP contract. For both gas and electricity, the Company reconciles and recovers commodity costs currently in rates to its customers who purchase the commodity. Where possible, the Company takes positions to mitigate expected price volatility but only to the extent that the quantities involved are based on expectations of delivery. The Company attempts to mitigate exposure through a program that hedges risks as appropriate. The Company does not speculate on movements in the underlying commodity prices. Commodity purchases are based on analyses performed in relation to expected customer deliveries for electricity and natural gas. The volume of commodities covered by hedging contracts does not exceed amounts needed for customer consumption in the normal course of business or to offset price movements in the contracts being hedged.

Large customers that continue to purchase electricity from the Company receive power from the NYISO at prevailing market prices and, in effect, assume the associated commodity price risk. For the remaining customers the Company meets a significant portion of its commodity supply responsibility through various physical and financial contracts. Some of these contracts are indexed to fuel prices, primarily natural gas. Although the current rate agreement allows for a pass-through of the commodity cost of power, the Company considers it prudent to perform certain hedging activities as a means of controlling cost volatility caused by the operation of these indexing mechanisms.

As part of the MRA, the Company entered into restated indexed swap contracts with eight IPPs. See Item 8. Financial Statements and Supplementary Data — Note L — Derivatives and Hedging Activities, for a more detailed discussion of these swap contracts.

The fair value of the liability under the swap contracts is based on the difference between projected future market prices and projected contract prices applied to the notional quantities and discounted to the present value. This liability was approximately $~~537~~268 million and $~~619~~537 million at at March 31, ~~2006~~2007 and ~~2005~~2006, respectively, and is recorded on the Company’s balance sheets under ~~both~~ both current and noncurrent liabilities. The decrease is primarily due to the revaluation of the contracts at March 31, ~~2006~~2007 and to normal contract settlements. The discount rate is a market-based rate representing the yield curve through the life of the contracts. Based on the PSC’s approval of the restated contracts as part of the MRA, including the indexed swap contracts, and the opportunity to recover the estimated indexed swap liability from customers, the Company recorded a corresponding regulatory asset. The amounts of the recorded liability and regulatory asset are sensitive to changes in anticipated future market prices and changes in the indices upon which the indexed swap contract payments are based.

21If the indexed contract price increased or decreased by 1 percent, there would be a respective $5 million increase or decrease in the present value of the projected over-market exposure associated with these contracts. If the market prices increased or fell by 1 percent, there would be a respective $3 million decrease or increase in the projected over-market exposure associated with these contracts. If the discount rate was 0.5 percent higher or lower, the respective net present value of the projected over-market exposure associated with these contracts would decrease or increase by approximately $0.1 million.

are sensitive to changes in anticipated future market prices and changes in the indices upon which the indexed swap contract payments are based.

If the indexed contract price increased or decreased by 1%, there would be a respective $11 million increase or decrease in the present value of the projected over-market exposure associated with these contracts. If the market prices increased or fell by 1%, there would be a respective $5 million decrease or increase in the projected over-market exposure associated with these contracts. If the discount rate was 0.5% higher or lower, the respective net present value of the projected over-market exposure associated with these contracts would decrease or increase by approximately $3.3 million.

The area of exposure to cash flow is in the indexing of the contract prices for the IPP indexed swaps and a non-MRA IPP where payments are based on gas prices. The contract payments under the IPP swaps and non-MRA IPP swaps are indexed to the costs of fuel, primarily natural gas. As fuel costs rise, the payments the Company makes under those contracts increase. The current rate plan allows the pass-through of the commodity cost of power to customers; however, the Company still considers it prudent to use certain financial instruments to limit the impact of commodity fluctuations on these payments.

The Company has taken steps to mitigate the potential impact that fuel prices would have on the payments for the IPP swaps and a physical power contract with a non-MRA IPP. To limit this exposure, the Company purchased NYMEX gas futures contracts and entered into fixed-for-floating swaps on gas-basis costs. To ~~hedge the non-MRA IPP contract, the Company purchased NYMEX gas~~ futures. See Item 8 — Financial Statements and Supplementary Data — Note L — Derivatives and Hedging Activities for a more detailed discussion of these contracts. As of March 31, 2006, gas futures have been purchased to hedge approximately 50% of the estimated amount needed to offset gas price changes in the period ended March 31, 2007. At March 31, 2005, the open NYMEX futures the Company had in place to hedge the payments under these contracts had a fair value pre-tax gain of $27 million.

~~Activity for the fair value of the NYMEX futures and gas basis swaps for the fiscal year ended~~24 ~~March 31, 2006 is as follows:~~

	Hedges of IPP Swaps						Hedges Non-MRA IPP
	NYMEX Futures						NYMEX Futures
(in thousands of Dths and dollars)	Dth			Fair Value			Dth			Fair Value
March 31, 2005 asset balance		20,046.9		$	25,013.5			1,593.1		$	2,006.1
New contracts		38,939.0			(722.0	)		3,241.0			(60.0	)
Settled during period		(38,398.9	)		(49,397.5	)		(3,121.1	)		(4,036.1	)
March 31, 2006 asset (liability) balance		20,587.0		$	(25,106.0	)		1,713.0		$	(2,090.0	)

Gas Supply Price Risk: The cost of natural gas sold to customers fluctuates during the year with prices historically most volatile in the winter months. The Company’s gas rate agreement includes a provision for the collection or pass-back of increases or decreases in purchased gas costs. The PSC has also mandated that the Company attempt to reduce the price volatility in the gas commodity portion of customers’ bills. In response to this mandate, the Company’s Board of Directors has authorized the use of futures, options, and swaps to hedge against gas price fluctuations. The hedging program is consistent with the Policy and is monitored by the EPRMC.

~~financial~~ ~~instruments~~hedge ~~used~~the bynon-MRA IPP contract, the Company. ~~Each~~purchased NYMEX gas futures. ~~contract~~See ~~represents~~Item 8 - ~~10,000~~Financial ~~Dth~~Statements and Supplementary Data — Note L — Derivatives and Hedging Activities for a more detailed discussion of ~~gas~~these contracts. AtAs of March 31, ~~2006~~2007, ~~and~~gas ~~2005~~futures ~~the~~have ~~mark-~~been purchased to~~-market~~ ~~net~~hedge ~~open~~approximately ~~position~~50% of ~~cash~~the ~~flow hedges~~estimated ~~for~~amount ~~gas~~needed ~~supply~~to ~~was~~offset agas ~~loss~~price ~~of $5 million~~changes ~~and~~in athe ~~gain~~period ended ~~of $7~~March ~~million~~31, ~~respectively~~2008. ~~There~~At ~~were~~March 31, ~~671~~2006 and ~~593~~2007, the open NYMEX futures ~~contracts~~the atCompany had in place ~~March 31,~~to ~~2006~~hedge ~~and~~the ~~March~~payments under these contracts had a fair value pre-tax loss of $27 ~~31,~~million ~~2005~~and $4.6 million, respectively.

~~The~~Activity ~~following~~for ~~table details~~ the fair value ~~activity~~of ~~for~~the ~~gas~~NYMEX ~~cash~~futures ~~flow~~and ~~hedges~~gas basis swaps for the fiscal year ~~ended~~ ended March 31, ~~2006~~2007 is as follows:

Hedges of Gas Supply
	Hedges of IPP Swaps						Hedges Non-MRA IPP
	NYMEX Futures						NYMEX Futures
(in thousands of dths and dollars)	Dth			Fair Value
(In thousands of Dths and dollars)	Dth			Fair Value			Dth			Fair Value
March 31, 2005 asset balance		5,930.0		$	7,233.4
March 31, 2006 asset (liability) balance		20,587.0		$	(25,106.0	)		1,713.0		$	(2,090.0	)
New Contracts		13,980.0			—
New contracts		38,015.1			124,314.6			3,134.9			6,473.6
Settled during the period		(13,200.0	)		(30,127.0	)
Settled during period		(38,827.9	)		(94,777.4	)		(3,212.1	)		(4,187.8	)
Mark-to-market adjustments		—			17,534.8
March 31, 2007 asset balance		19,774.2		$	4,431.2			1,635.8		$	195.8
March 31, 2006 asset (liability) balance		6,710.0		$	(5,358.8	)

Gas Supply Price Risk: The cost of natural gas sold to customers fluctuates during the year with prices historically most volatile in the winter months. The Company’s gas rate agreement includes a provision for the collection or pass-back of increases or decreases in purchased gas costs. The PSC has also mandated that the Company attempt to reduce the price volatility in the gas commodity portion of customers’ bills. In response to this mandate, the Company’s Board of Directors has authorized the use of futures, options, and swaps to hedge against gas price fluctuations. The hedging program is consistent with the Policy and is monitored by the EPRMC.

The Company attempts to hedge approximately 50% of its forecasted average demand for the October to April period through a program using in-ground storage and financial instruments. NYMEX gas futures are the financial instruments used by the Company. Each NYMEX futures contract represents 10,000 Dth of gas. At March 31, 2007 and 2006 the mark-to-market net open position of cash flow hedges for gas supply was a gain of $2.5 million and a loss of $5 million, respectively. There were 702 and 671 open futures contracts at March 31, 2007 and March 31, 2006, respectively.

The following table details the fair value activity for gas cash flow hedges for the fiscal year ended March 31, 2007:


*Hedges of Gas Supply*
	NYMEX Futures
(In thousands of dths and dollars)	Dth			Fair Value

March 31, 2006 asset (liability) balance		6,710.0		$	(5,358.8	)
New Contracts		13,570.0			—
Settled during the period		(13,260.0	)		(36,735.0	)
Mark-to-market adjustments		—			44,627.5

March 31, 2007 asset balance		7,020.0		$	2,533.7

The above activity coupled with the in-ground storage hedged approximately 50% of the Company’s average gas demand for the October to April period. The rest of the gas needs are met through market-based purchases that are subject to price fluctuations and which are mitigated by regulatory rate recovery for the cost of gas purchased.

The extent to which market price movement would affect the value of the hedges would be matched by an offsetting change in the anticipated gas purchased costs for the quantity of gas hedged. Therefore, for the quantities hedged, variations in market costs would not result in any significant impact on earnings.

Electricity Price Risk: The Company meets a substantial portion of its electricity requirements through a series of long-term physical and financial contracts. The remaining electricity requirements are purchased at market prices through the NYISO. If certain proscribed risk values are exceeded during a time when the Company forecasts a short power situation, the Company may use electricity swaps to lock in a price for electricity. In April 2003, the Company began utilizing NYMEX electricity swap contracts to hedge electricity purchases. The Company continues to evaluate the use of hedging instruments to manage the cost of electricity purchased. At March 31, ~~2006~~2007, the mark-to-market net open position of electricity swap contracts was a gain of $0.38 million.

Interest Rate Risk: The Company is exposed to changes in interest rates through several series of adjustable rate promissory notes and short-term borrowings. See Item 8. Financial Statements and Supplementary Data — Note E — Long-Term Debt and Note F – Short-Term Debt. Total adjustable rate promissory notes are currently valued at $575 million. There was $567 million of short term borrowing at March 31, 2006 from the intercompany money pool maintained by National Grid. At March 31, 2005 these borrowings totaled $401 million.


	*Hedges of Electric Supply*
	NYMEX SWAPS
(In thousands of KWH and dollars)	KWH			Fair Value

March 31, 2006 balance asset		100,800.0		$	317.5
New contracts		815,200.0			4,222.3
Settled during period		(612,800.0	)		(3,755.9	)
March 31, 2007 asset		303,200.0		$	783.9

Interest Rate Risk: The Company is exposed to changes in interest rates through several series of adjustable rate promissory notes and short-term borrowings. See Item 8. Financial Statements and Supplementary Data — Note E — Long-Term Debt and Note F – Short-Term Debt. Total adjustable rate promissory notes are currently valued at $575 million. There was $395 million of short term borrowings at March 31, 2007 from the intercompany money pool maintained by National Grid.

There is no interest rate cap on the promissory notes. The interest rates on short-term money pool borrowings are tied to the published, 30 day commercial paper rate with the amount borrowed from the National Grid money pool adjusted daily.

The Company also maintains long-term debt at fixed interest rates. A controlling factor on the exposure to interest rate variations is the mix of fixed to variable rate instruments maintained by the Company. For March 31, ~~2006~~2007 and ~~2005~~2006, adjustable rate instruments comprise 39.7% and 33.3% of external long-term debt, and 21.7% and 19.7% of total long-term debt, respectively. In the aggregate at March 31, 2007 and 2006, variable rate instruments do not constitute a significant portion of total capitalization and debt, thereby limiting the Company’s exposure to interest rate fluctuations.

23If interest rates averaged 1% more in the next fiscal year versus the fiscal year ended March 31, 2007, the Company’s interest expense would increase and income before taxes would decrease by approximately $10 million. This figure was derived by applying a hypothetical 1% variance to the variable rate debt of $575 million plus the short-term variable borrowings of $395 million at March 31, 2007. Changes in the actual cost of capital from levels assumed in rates would create either exposure or opportunity for the Company until these changes could be reflected in future prices.

In the aggregate at March 31, 2006 and 2005, variable rate instruments do not constitute a significant portion of total capitalization and debt, thereby limiting the Company’s exposure to interest rate fluctuations.

If interest rates averaged 1% more in the next fiscal year versus the fiscal year ended March 31, 2006, the Company’s interest expense would increase and income before taxes would decrease by approximately $11 million. This figure was derived by applying a hypothetical 1% variance to the variable rate debt of $575 million plus the short-term variable borrowings of $567 million at March 31, 2006. Changes in the actual cost of capital from levels assumed in rates would create either exposure or opportunity for the Company until these changes could be reflected in future prices.

Equity Price Risk: The Company currently has no equity price risk.

Foreign Currency Exchange Risk: The Company currently has no foreign currency exchange risk.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

A. FINANCIAL STATEMENTS

• Report of Independent Registered Public Accounting Firm • Consolidated Statements of Operations, Consolidated Statements of Comprehensive Income and Consolidated Statements of Retained Earnings for each of the three years in the period ended March 31, ~~2006~~2007. • Consolidated Balance Sheets at March 31, ~~2006~~2007 and ~~2005~~2006. • Consolidated Statements of Cash Flows for each of the three years in the period ended March 31, ~~2006~~2007. • Notes to Consolidated Financial Statements.

2427

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Stockholders and Board of Directors of
Niagara Mohawk Power Corporation:

In our opinion, the consolidated financial statements listed in the ~~accompanying~~ index appearing under Item 15 present fairly, in all material respects, the financial position of Niagara Mohawk Power Corporation and its subsidiaries at March 31, 2007 ~~2006~~ and ~~2005~~2006, and the results of their operations and their cash flows for each of the three years in the period ended March 31, ~~2006~~2007 in conformity with ~~accounting~~ accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing under Item 15~~(a)(2)~~ ~~present~~presents fairly, in all material respects, the information set forth therein when read in conjunction with the related ~~consolidated~~ consolidated financial statements. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of ~~material~~ material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

As described in Note H to the financial statements, the Company adopted a new principle of accounting for pension and postretirement benefit plans in accordance with Financial Accounting Standards Board Statement No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans. In accordance with the provisions of FASB No. 158, the 2007 financial statements include the adjustment to initially apply this new accounting principle as of March 31, 2007.


/s/ PricewaterhouseCoopers LLP

PricewaterhouseCoopers LLP

~~New York~~Boston, ~~New York~~Massachusetts June 2928, ~~2006~~2007

2528

NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES Consolidated Statements of Operations (In thousands of dollars)

Consolidated Statements of Operations (In thousands of dollars)


	For the Years Ended March 31,
	2007			2006			2005

Operating revenues:
Electric	$	3,256,621		$	3,306,942		$	3,117,156
Gas		875,034			1,037,081			808,015

Total operating revenues		4,131,655			4,344,023			3,925,171

Operating expenses:
Purchased electricity		1,389,893			1,464,626			1,364,813
Purchased gas		582,802			741,419			509,543
Other operation and maintenance		792,795			717,745			708,606
Depreciation and amortization		209,552			203,994			200,793
Amortization of stranded costs and rate plan deferrals		416,920			266,816			251,499
Other taxes		210,731			209,553			217,993
Income taxes		120,943			190,194			171,230

Total operating expenses		3,723,636			3,794,347			3,424,477

Operating income		408,019			549,676			500,694
Other income (deductions), net		(5,041	)		(7,758	)		8,347

Operating and other income		402,978			541,918			509,041

Interest:
Interest on long-term debt		101,265			138,415			169,585
Interest on debt to associated companies		85,956			75,358			66,283
Other interest		26,180			11,069			9,924

Total interest expense		213,401			224,842			245,792

Net income		189,577			317,076			263,249

Dividends on preferred stock		1,626			1,626			2,928

Income available to common shareholder	$	187,951		$	315,450		$	260,321

	For the			For the		For the
	year ended			year ended		year ended
	March 31,			March 31,		March 31,
	2006			2005		2004
Operating revenues:
Electric	$	3,306,942		$	3,117,156	$	3,284,017
Gas		1,037,081			808,015		779,600
Total operating revenues		4,344,023			3,925,171		4,063,617
Operating expenses:
Purchased electricity		1,464,626			1,364,813		1,591,652
Purchased gas		741,419			509,543		478,647
Other operation and maintenance		717,745			708,606		793,110
Depreciation and amortization		203,994			200,793		200,650
Amortization of stranded costs		266,816			251,499		194,114
Other taxes		209,553			217,993		227,006
Income taxes		190,194			171,230		138,843
Total operating expenses		3,794,347			3,424,477		3,624,022
Operating income		549,676			500,694		439,595
Other income (deductions), net		(7,758	)		8,347		(7,198	)
Operating and other income		541,918			509,041		432,397
Interest:
Interest on long-term debt		138,415			169,585		220,781
Interest on debt to associated companies		75,358			66,283		55,282
Other interest		11,069			9,924		16,644
Total interest expense		224,842			245,792		292,707
Net income		317,076			263,249		139,690
Dividends on preferred stock		1,626			2,928		4,430
Income available to common shareholder	$	315,450		$	260,321	$	135,260

Consolidated Statements of Comprehensive Income
(In thousands of dollars)

	For the			For the			For the
	For the Years Ended March 31,
	year ended			year ended			year ended
	2007			2006			2005
	March 31,			March 31,			March 31,
Net income	$	189,577		$	317,076		$	263,249
	2006			2005			2004
Net income	$	317,076		$	263,249		$	139,690
Other comprehensive income (loss), net of taxes:
Unrealized gains (losses) on securities		~~(337~~585	)		~~732~~(337	)		~~1,731~~732
Hedging activity		4(17,~~009~~526	)		144,~~557~~009			214,~~425~~557
Change in additional minimum pension liability		~~358~~1,199			—358			~~(1,557~~—	)
Reclassification adjustment for gains included in net income		(21,807	)		(4,943	)		—
Adjustment to initially apply SFAS No. 158		(1,269	)		—			—
Total other comprehensive income (loss)		(17,777	)		10,346			2,599
Reclassification adjustment for gains (losses) included in net income		21,769			(21,807	)		(4,943	)
Comprehensive income	$	299,299		$	273,595		$	142,289
Total other comprehensive income (loss)		4,758			(17,777	)		10,346
Comprehensive income	$	194,335		$	299,299		$	273,595

Per share data is not relevant because the Company’s common stock is wholly-owned by Niagara Mohawk Holdings, Inc.

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

2629

NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES Consolidated Statements of Retained Earnings (In thousands of dollars)

Consolidated Statements of Retained Earnings (In thousands of dollars)


	For the Years Ended March 31,
	2007			2006			2005

Retained earnings at beginning of period	$	788,737		$	473,287		$	220,966
Net income		189,577			317,076			263,249
Dividends on preferred stock		(1,626	)		(1,626	)		(2,928	)
Dividend to Niagara Mohawk Holdings, Inc.		—			—			(8,000	)

Retained earnings at end of period	$	976,688		$	788,737		$	473,287

	For the			For the			For the
	year ended			year ended			year ended
	March 31,			March 31,			March 31,
	2006			2005			2004
Retained earnings at beginning of period	$	473,287		$	220,966		$	85,706
Net income		317,076			263,249			139,690
Dividends on preferred stock		(1,626	)		(2,928	)		(4,430	)
Dividend to Niagara Mohawk Holdings, Inc.		—			(8,000	)		—
Retained earnings at end of period	$	788,737		$	473,287		$	220,966

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

2730

NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES Consolidated Balance Sheets (In thousands of dollars)

Consolidated Balance Sheets (In thousands of dollars)


	March 31,		March 31,
	2007		2006

ASSETS
Utility plant, at original cost:
Electric plant	$	5,854,677	$	5,658,705
Gas plant		1,617,848		1,580,204
Common plant		288,837		309,053

Total utility plant		7,761,362		7,547,962
Less: Accumulated depreciation and amortization		2,318,967		2,247,350

Net utility plant		5,442,395		5,300,612

Goodwill		1,242,461		1,214,576
Pension intangible		—		36,885
Other property and investments		47,506		47,379

Current assets:
Cash and cash equivalents		15,746		10,847
Restricted cash		37,648		66,393
Accounts receivable (less reserves of $126,619 and $123,310, respectively, and including receivables from associated companies of $10,232 and $10,238, respectively)		670,548		653,652
Materials and supplies, at average cost:
Gas storage		4,277		23,576
Other		27,926		21,356
Derivative instruments		7,945		—
Prepaid taxes		75,573		13,847
Current deferred income taxes		107,774		168,354
Regulatory asset – swap contracts		221,540		246,551
Other		14,595		13,979

Total current assets		1,183,572		1,218,555

Regulatory and other non-current assets:
Regulatory assets:
Merger rate plan stranded costs		2,220,179		2,486,590
Swap contracts regulatory asset		46,500		290,902
Regulatory tax asset		100,765		106,624
Deferred environmental restoration costs		397,407		399,630
Pension and postretirement benefit plans		1,028,129		527,829
Additional minimum pension liability		—		75,252
Loss on reacquired debt		51,975		59,521
Other		379,257		499,716

Total regulatory assets		4,224,212		4,446,064
Other non-current assets		26,609		30,744

Total regulatory and other non-current assets		4,250,821		4,476,808

Total assets	$	12,166,755	$	12,294,815

	March 31,		March 31,
	2006		2005
ASSETS
Utility plant, at original cost:
Electric plant	$	5,658,705	$	5,399,412
Gas plant		1,580,204		1,532,441
Common plant		309,053		333,922
Total utility plant		7,547,962		7,265,775
Less: Accumulated depreciation and amortization		2,247,350		2,108,379
Net utility plant		5,300,612		5,157,396
Goodwill (Note A)		1,214,576		1,224,025
Pension intangible		36,885		40,339
Other property and investments		47,379		55,048
Current assets:
Cash and cash equivalents		10,847		19,922
Restricted cash (Note A)		66,393		7,367
Accounts receivable (less reserves of $123,310 and $126,084, respectively, and including receivables from associated companies of $10,238 and $6,654, respectively)		653,652		571,552
Materials and supplies, at average cost:
Gas storage		23,576		3,498
Other		21,356		17,739
Derivative instruments (Note A and L)		317		35,326
Prepaid taxes		—		44,273
Current deferred income taxes (Note G)		168,354		307,431
Regulatory asset — swap contracts		246,551		203,558
Other		13,662		9,772
Total current assets		1,204,708		1,220,438
Regulatory and other non-current assets:
Regulatory assets (Note B):
Merger rate plan stranded costs		2,486,590		2,765,392
Swap contracts regulatory asset		290,902		415,394
Regulatory tax asset		106,624		79,933
Deferred environmental restoration costs		399,630		431,000
Pension and postretirement benefit plans		527,829		501,358
Additional minimum pension liability		75,252		194,302
Loss on reacquired debt		59,521		67,162
Other		499,716		330,094
Total regulatory assets		4,446,064		4,784,635
Other non-current assets		30,744		36,481
Total regulatory and other non-current assets		4,476,808		4,821,116
Total assets	$	12,280,968	$	12,518,362

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

2831

NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES Consolidated Balance Sheets (In thousands of dollars)

Consolidated Balance Sheets (In thousands of dollars)


	March 31,			March 31,
	2007			2006

CAPITALIZATION AND LIABILITIES
Capitalization:
Common stockholder’s equity:
Common stock ($1 par value)	$	187,365		$	187,365
Authorized - 250,000,000 shares
Issued and outstanding - 187,364,863 shares
Additional paid-in capital		2,913,384			2,929,501
Accumulated other comprehensive income (loss)		(58	)		(4,816	)
Retained earnings		976,688			788,737

Total common stockholder’s equity		4,077,379			3,900,787
Preferred equity:
Cumulative preferred stock ($100 par value, optionally redeemable)		41,170			41,170
Authorized - 3,400,000 shares
Issued and outstanding - 411,715 shares
Long-term debt		1,249,194			1,448,934
Long-term debt to affiliates		1,200,000			1,200,000

Total capitalization		6,567,743			6,590,891

Current liabilities:
Accounts payable (including payables to associated companies of $37,767 and $28,315, respectively)		330,976			275,223
Customers’ deposits		37,819			32,345
Accrued interest		56,625			65,952
Accrued taxes		30,343			75,551
Short-term debt to affiliates		395,300			578,900
Current portion of liability for swap contracts		221,540			246,551
Current portion of long-term debt		200,000			275,000
Hedging instruments		—			32,555
Other		105,886			97,284

Total current liabilities		1,378,489			1,679,361

Non-current liabilities:
Accumulated deferred income taxes		1,694,047			1,687,360
Liability for swap contracts		46,500			290,902
Employee pension and other benefits		996,006			621,635
Liability for environmental remediation costs		397,407			399,630
Nuclear fuel disposal costs		158,196			150,642
Cost of removal regulatory liability		350,073			337,995
Other		578,294			536,399

Total other non-current liabilities		4,220,523			4,024,563

Commitments and contingencies		—			—

Total capitalization and liabilities	$	12,166,755		$	12,294,815

	March 31,			March 31,
	2006			2005
CAPITALIZATION AND LIABILITIES
Capitalization:
Common stockholder’s equity:
Common stock ($1 par value)	$	187,365		$	187,365
Authorized - 250,000,000 shares
Issued and outstanding - 187,364,863 shares
Additional paid-in capital		2,929,501			2,929,501
Accumulated other comprehensive income (loss) (Note C)		(4,816	)		12,961
Retained earnings		788,737			473,287
Total common stockholder’s equity		3,900,787			3,603,114
Preferred equity (Note I):
Cumulative preferred stock ($100 par value, optionally redeemable)		41,170			41,170
Authorized - 3,400,000 shares
Issued and outstanding - 411,715 shares
Long-term debt (Note E)		1,448,934			1,723,569
Long-term debt to affiliates (Note E)		1,200,000			1,200,000
Total capitalization		6,590,891			6,567,853
Current liabilities:
Accounts payable (including payables to associated companies of $28,315 and $36,440, respectively)		275,223			271,275
Customers’ deposits		32,345			26,900
Accrued interest		65,952			82,945
Short-term debt to affiliates (Note F)		578,900			400,500
Current portion of liability for swap contracts (Note A and L)		246,551			203,558
Current portion of long-term debt (Note E)		275,000			550,420
Derivative instruments (Note A and L)		32,555			—
Accrued taxes		61,704			—
Other		97,284			107,871
Total current liabilities		1,665,514			1,643,469
Non-current liabilities:
Accumulated deferred income taxes (Note G)		1,687,360			1,711,630
Liability for swap contracts (Note A and L)		290,902			415,394
Employee pension and other benefits (Note H)		628,850			671,053
Liability for environmental remediation costs		399,630			431,000
Nuclear fuel disposal costs		150,642			145,562
Cost of removal regulatory liability (Note N)		337,995			318,455
Other		529,184			613,946
Total other non-current liabilities		4,024,563			4,307,040
Commitments and contingencies (Note D)		—			—
Total capitalization and liabilities	$	12,280,968		$	12,518,362

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

2932

NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
Consolidated Statements of Cash Flows
(In thousands of dollars)

	Year			Year			Year
	For the Years Ended March 31,
	ended			ended			ended
	2007			2006			2005
	March 31, 2006			March 31, 2005			March 31, 2004
Operating activities:
Net income	$	~~317~~189,~~076~~577		$	~~263~~317,~~249~~076		$	~~139~~263,~~690~~249
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		~~203~~209,~~994~~552			~~200~~203,~~793~~994			200,~~650~~793
Amortization of stranded costs		266,816			251,499			194,114
Amortization of stranded costs and rate plan deferrals		416,920			266,816			251,499
Provision for deferred income taxes		~~103~~147,~~474~~843			~~180~~103,~~722~~474			~~148~~180,~~435~~722
Pension and other benefit plans expense		107,208			100,143			100,484
Cash paid to pension and postretirement benefit plan trusts		(95,500	)		(109,330	)		(266,139	)
Changes in operating assets and liabilities:
Net accounts receivable		(8216,~~100~~896	)		7(82,~~102~~100	)		~~(35~~7,~~374~~102	)
Materials and supplies		~~(23~~12,~~695~~729	)		5(23,~~703~~695	)		(5,~~744~~703	)
Accounts payable and accrued expenses		(166,~~194~~986	)		(311,~~513~~194	)		(7431,~~946~~513	)
Accrued interest and tax		44,711			(15,276	)		(10,706	)
Accrued interest and taxes		(98,537	)		44,711			(15,276	)
Other regulatory assets		(169,622	)		(41,667	)		(46,137	)
Pension and other post-retirement benefits		(99,623	)		11,708			(9,187	)
Other, net		72,431			73,565			5,044
Prepaid taxes		(61,726	)		44,273			(17,496	)
Net cash provided by operating activities		743,599			884,990			349,371
Other, net		6,691			(141,464	)		49,394
Net cash provided by operating activities		773,516			743,599			884,990
Investing activities:
Construction additions		(~~269~~339,~~941~~080	)		(~~266~~269,~~012~~941	)		(~~317~~266,~~302~~012	)
Change in restricted cash		~~(59~~28,~~026~~745	)		4(59,~~796~~026	)		134,~~187~~796
Other investments		~~8,023~~(363	)		28,~~651~~023			62,~~563~~651
Other, net		~~(58~~2,~~084~~307	)		(158,~~640~~084	)		(171,~~294~~640	)
Net cash used in investing activities		(~~379~~308,~~028~~391	)		(~~260~~379,~~205~~028	)		(~~314~~260,~~846~~205	)
Financing activities:
Dividends paid on preferred stock		(1,626	)		(21,~~928~~626	)		(42,~~430~~928	)
Dividends paid on common stock to Holdings		—			~~(8,000~~—	)		—(8,000	)
Reductions in long-term debt		(~~550~~275,~~420~~000	)		(~~532~~550,~~620~~420	)		(1532,~~319,490~~620	)
Proceeds from long-term debt		—			—			45,600
Redemption of preferred stock		—			—			(25,155	)
Proceeds from long-term debt to affiliates		—			—			700,000
Net change in short-term debt to affiliates		(183,600	)		178,400			(63,000	)
Redemption of preferred stock		—			(25,155	)		(33,903	)
Net cash used in financing activities		(460,226	)		(373,646	)		(631,703	)
Net change in short-term debt to affiliates		178,400			(63,000	)		265,500
Net increase (decrease) in cash and cash equivalents		4,899			(9,075	)		(6,918	)
Equity contribution from parent		—			—			309,000
Cash and cash equivalents, beginning of period		10,847			19,922			26,840
Net cash used in financing activities		(373,646	)		(631,703	)		(37,723	)
Cash and cash equivalents, end of period	$	15,746		$	10,847		$	19,922
Net decrease in cash and cash equivalents		(9,075	)		(6,918	)		(3,198	)
Cash and cash equivalents at beginning of period		19,922			26,840			30,038
Cash and cash equivalents at end of period	$	10,847		$	19,922		$	26,840
Supplemental disclosures of cash flow information:
Interest paid	$	~~244~~224,~~499~~481		$	~~258~~244,~~735~~499		$	~~336~~258,~~147~~735
Income taxes received	$	(16,210	)	$	(54,940	)	$	(13,904	)
Income taxes paid (received)	$	120,181		$	(16,210	)	$	(54,940	)

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

3033

NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE A —– SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation: Niagara Mohawk Power Corporation and subsidiary companies (the Company) is subject to regulation by the New York State Public Service Commission (PSC) and the Federal Energy Regulatory Commission (FERC) with respect to its rates for service under a methodology that establishes prices based on the Company’s ~~cost~~costs. The Company’s accounting policies conform to generally ~~Generally~~accepted ~~Accepted~~accounting ~~Accounting Principles~~principles in the United States of America (GAAP), including the accounting principles for rate-regulated entities with respect to the Company’s transmission, distribution and gas operations (regulated business), and are in accordance with the accounting requirements and ratemaking practices of the regulatory authorities.

~~Niagara~~Basis ~~Mohawk Holdings, Inc. (Holdings), the parent company~~ of ~~the Company, is a wholly owned~~Consolidation ~~subsidiary of National Grid USA (National Grid). National Grid is a wholly owned subsidiary of National Grid plc (formerly known as National Grid Transco plc).~~

The Company’s ~~consolidated~~is ~~financial~~a ~~statements~~wholly-owned ~~include~~subsidiary ~~its~~of ~~accounts~~Niagara asMohawk ~~well~~Holdings, asInc. ~~those~~(Holdings), ofwhich ~~its~~is wholly-owned by National Grid USA (National Grid). National Grid is a wholly owned ~~subsidiaries~~subsidiary of National Grid plc (formerly known as National Grid Transco plc). ~~Inter-company~~National ~~balances~~Grid acquired and ~~transactions~~merged with ~~have~~Holdings ~~been~~in ~~eliminated~~January 2002.

~~Goodwill:~~ The ~~acquisition~~accompanying ofConsolidated ~~the~~Financial ~~Company~~Statements ~~was~~reflect ~~accounted for by~~ the ~~purchase~~results ~~method, the application~~ of ~~which~~operations, ~~including the recognition of goodwill~~comprehensive income, ~~was~~retained ~~recognized on the books of the Company~~earnings, ~~the most~~financial ~~significant~~position ~~subsidiary~~and ofcash ~~Holdings.~~flows ~~The merger transaction resulted in approximately $1.2 billion~~ of ~~goodwill. In accordance with Statement of Financial Accounting Standards (SFAS) No. 142, “Goodwill and Other Intangible Assets”,~~ the Company ~~reviews its goodwill annually for impairment~~ and ~~when events or circumstances indicate that the asset may be impaired. The Company utilized a discounted cash flow approach incorporating~~ its ~~most recent business plan forecasts in the performance of the annual goodwill impairment test~~subsidiaries. ~~The result of the annual analysis~~ ~~determined that no adjustment to the goodwill carrying value was required. As a result of a settled IRS audit of pre~~Inter-~~merger~~company ~~years,~~balances ~~the~~and ~~Company~~transactions ~~recorded~~have abeen ~~$9 million adjustment to goodwill related to a pre-merger tax contingency~~eliminated.

Goodwill: The acquisition of the Company was accounted for by the purchase method, the application of which, including the recognition of goodwill, was recognized on the books of the Company, the most significant subsidiary of Holdings. The merger transaction resulted in approximately $1.2 billion of goodwill. In accordance with Statement of Financial Accounting Standards (SFAS) No. 142, “Goodwill and Other Intangible Assets”, the Company reviews its goodwill annually for impairment and when events or circumstances indicate that the asset may be impaired. The Company utilized a discounted cash flow approach incorporating its most recent business plan forecasts in the performance of the annual goodwill impairment test. The result of the annual analysis determined that no adjustment to the goodwill carrying value was required. The Company recorded a $28 million adjustment to goodwill related to an immaterial correction of an error in a pre-merger tax contingency in fiscal year 2007.

Use of Estimates: The preparation of financial statements in conformity with GAAP 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 consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Utility Plant: The cost of additions to utility plant and replacements of retirement units of property are capitalized. Costs include direct material, labor, overhead and AFUDC (see below). Replacement of minor items of utility plant and the cost of current repairs and maintenance are charged to expense. Whenever utility plant is retired, its original cost, together with the cost of removal, less salvage, is charged to accumulated depreciation.

Allowance for Funds Used During Construction (AFUDC): The Company capitalizes AFUDC as part of construction costs. AFUDC is capitalized in ~~amounts~~“Utility ~~equivalent~~plant” towith ~~the~~offsetting ~~cost~~cash ofcredits ~~funds~~to ~~devoted~~“Other interest” and non-cash credits to ~~plant~~“Other ~~under~~income ~~construction for~~(deductions)” ~~its~~on ~~regulated~~the ~~business~~Consolidated Statement of Operations. ~~AFUDC~~This ~~represents~~method is in accordance with an ~~allowance~~established ~~for~~rate-making practice under which a utility is permitted a return on, and the ~~cost~~recovery of, ~~funds~~prudently ~~used~~incurred tocapital ~~finance~~costs through their ultimate

3134

~~construction.~~inclusion ~~AFUDC is capitalized~~ in “Utility plant” with offsetting non-cash credits to “Other interest” and “Other income (deductions)” on the Consolidated Statement of Operations. This method is in accordance with an established rate~~-making~~ ~~practice under which a utility is permitted a return on, and the recovery of, prudently incurred capital costs through their ultimate inclusion in rate~~ base and in the provision for depreciation. AFUDC rates are determined in accordance with FERC and PSC regulations. The AFUDC rates in effect at March 31, ~~2006~~2007 and ~~2005~~ 2006 were 35.4923% and 1 3.5949%, respectively. AFUDC is segregated into its two components, borrowed funds and other funds, and is reflected in the “Other interest” and “Other income (deductions)” sections, respectively, in the Company’s Consolidated Statements of Operations. The amounts of AFUDC credits were recorded as follows:

	Year Ended		Year Ended		Year Ended
	Fiscal Years Ended March 31,
	March 31,		March 31,		March 31,
(In thousands of dollars)	2007		2006		2005
(In thousands of dollars)	2006		2005		2004
Other income (deductions)	$	—	$	—	$	1
Other income (deductions)	$	—	$	1	$	(9	)
Other interest		2,176		2,040		606
Other interest		2,040		606		565

Depreciation: For accounting and regulatory purposes, the Company’s depreciation is computed on the straight-line basis using the average service lives. The Company performs depreciation studies to determine service lives of classes of property and adjusts the depreciation rates when necessary.

The weighted average service life, in years, for each asset category is presented in the table below:

	Year Ended		Year Ended		Year Ended
	Fiscal Years Ended March 31,
	March 31,		March 31,		March 31,
	2007		2006		2005
	2006		2005		2004
Asset Category:
Electric		3437		3534		3435
Gas		4243		4342		4443
Common		20		2120		1721

Revenues: The Company bills its customers on a monthly cycle basis at approved tariffs based on energy delivered and a minimum customer service charge. Revenues are determined based on these bills plus an estimate for unbilled energy delivered between the cycle billing date and the end of the accounting period. The unbilled revenues included in accounts receivable at March 31, ~~2006~~2007 and ~~2005~~2006 ~~was~~were approximately $~~133~~152 million and $~~110~~133 million, respectively.

The Company recognizes changes in accrued unbilled electric revenues in its results of operations. Pursuant to the Company’s 2000 multi-year gas settlement ~~(which ended December 2004, with the Company having the right to request a change in rates at any time, if needed)~~ changes in accrued unbilled gas revenues are deferred. At March 31, ~~2006~~2007 and ~~2005~~2006, approximately $618 million and $7 6 million, respectively, of unbilled gas revenues remain unrecognized in results of operations. The Company cannot predict when unbilled gas revenues will be allowed to be recognized in results of operations.

32In August 2001, the PSC approved certain rate plan changes. The changes allowed for certain commodity-related costs to be passed through to customers beginning September 2001. At the same time, a transmission revenue adjustment mechanism was implemented which reconciles actual and rate forecast transmission revenues for pass-back to, or recovery from, customers. The commodity adjustment clause and the transmission revenue adjustment mechanism have remained in effect under the Merger Rate Plan (MRP) which became effective upon the closing of the merger on January 31, 2002.

The PSC approved a multi-year gas rate settlement agreement (as amended through the Company’s MRP and ended in December 2004 with the Company having the right to request a change in rates at any time, if needed) in July 2000 that includes a provision for the continuation of a full gas cost collection mechanism, effective August 2000. This gas cost collection mechanism was originally reinstated in an

~~Company~~interim ~~cannot~~agreement ~~predict~~that ~~when~~became ~~unbilled~~effective November 1999. Such gas ~~revenues~~cost ~~will~~collection mechanism behas ~~allowed~~continued tounder bethe ~~recognized~~MRP. inThe ~~results~~Company’s ofgas cost collection mechanism provides for ~~operations~~the collection or pass-back of increases or decreases in purchased gas costs.

InFederal ~~August 2001,~~and ~~the~~State ~~PSC~~Income ~~approved~~Taxes: ~~certain~~Regulated ~~rate~~federal ~~plan~~and ~~changes.~~state ~~The~~income ~~changes~~taxes ~~allowed~~are ~~for~~recorded ~~certain~~under the ~~commodity-related~~provisions ~~costs~~of toFinancial beAccounting ~~passed~~Standards ~~through~~Board ~~to customers beginning September~~(FASB) ~~2001~~SFAS No. 109 At“Accounting ~~the~~for ~~same~~Income ~~time,~~Taxes.” aIncome ~~transmission~~taxes ~~revenue~~have ~~adjustment~~been ~~mechanism~~computed ~~was~~utilizing ~~implemented~~the ~~which~~asset ~~reconciles~~and ~~actual~~liability ~~and~~approach ~~rate~~that requires ~~forecast~~the ~~transmission~~recognition ~~revenues~~of ~~for~~deferred ~~pass-back~~tax ~~to,~~assets orand ~~recovery~~liabilities ~~from,~~for ~~customers.~~the ~~The~~tax ~~commodity~~consequences of temporary ~~adjustment~~differences ~~clause~~by ~~and~~applying ~~the~~enacted ~~transmission~~statutory ~~revenue~~tax ~~adjustment~~rates ~~mechanism~~applicable ~~remain~~to infuture ~~effect~~years ~~under~~to ~~the~~differences ~~Merger~~between ~~Rate~~the ~~Plan~~financial ~~which~~statement ~~became~~carrying ~~effective~~amounts ~~upon~~and the ~~closing~~tax basis of existing assets and liabilities. Deferred investment tax credits are amortized over the ~~merger~~useful onlife ~~January 31,~~of ~~2002~~the underlying property.

~~The~~Service ~~PSC~~Company ~~approved~~Charges: aNational ~~multi-year~~Grid ~~gas~~USA ~~rate~~Service ~~settlement~~Company, ~~agreement~~Inc., ~~(amended~~an ~~through~~affiliated ~~the~~service ~~Company’s Merger~~company, ~~Rate~~has ~~Plan~~furnished ~~and~~services ~~ended~~to ~~in December 2004 with~~ the Company ~~having the right to request a change in rates~~ at ~~any time, if needed) in July 2000 that includes a provision for~~ the ~~continuation~~cost of asuch ~~full~~services ~~gas cost~~since ~~collection~~the ~~mechanism,~~merger ~~effective~~with ~~August 2000~~National Grid. ~~This~~These ~~gas~~costs ~~cost~~including ~~collection~~operating ~~mechanism~~costs ~~was originally~~and ~~reinstated~~capital inexpenditures anapproximated ~~interim agreement that became effective November~~$149 ~~1999.~~million ~~Such gas cost~~and ~~collection~~$160 million ~~mechanism continues under the Merger Rate Plan. The Company’s gas cost collection mechanism provides~~ for the ~~collection~~years orended ~~pass-back~~March 31, of2007 ~~increases~~and or2006, ~~decreases in purchased gas costs~~respectively.

Federal and State Income Taxes: Regulated federal and state income taxes are recorded under the provisions of Financial Accounting Standards Board (FASB) SFAS No. 109 “Accounting for Income Taxes”. Income taxes have been computed utilizing the asset and liability approach that requires the recognition of deferred tax assets and liabilities for the tax consequences of temporary differences by applying enacted statutory tax rates applicable to future years to differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities. Deferred investment tax credits are amortized over the useful life of the underlying property.

Service Company Charges: National Grid USA Service Company, Inc., an affiliated service company, has furnished services to the Company at the cost of such services since the merger with National Grid. These costs approximated $160 million and $138 million for the years ended March 31, 2006 and 2005, respectively.

Cash and Cash Equivalents: The Company considers all highly liquid investments, purchased with an original maturity of three months or less, to be cash and cash equivalents.

Restricted Cash: Restricted cash consists of margin accounts for hedging activity, health care claims deposits, New York State Department of Conservation securitization for certain site cleanup, and worker’s compensation premium deposits. The $5929 million ~~increase~~decrease in restricted cash for the fiscal year ended March 31, ~~2006~~2007 was primarily due to increased equity in hedge accounts related to the ~~rise~~change in underlying commodity prices.

Derivatives: The Company accounts for derivative financial instruments under SFAS No. 133, “Accounting for Derivatives and Hedging Activities”,” and SFAS No. 149, “Amendment of SFAS No. 133 on Derivative Instruments and Hedging Activities,” as amended. Under the provisions of SFAS No. 133, all derivatives except those qualifying for the normal purchase/normal sale exception are recognized on the balance sheet at their fair value. Fair value is determined using current quoted market prices. If a contract is designated as a cash flow hedge, the change in its market value is generally deferred as a component of other comprehensive income until the transaction it is hedging is completed. Conversely, the change in the market value of a derivative not designated as a cash flow hedge is deferred as a regulatory asset or liability as the Company has received approval from the PSC to establish a regulatory asset or liability for derivative instruments that did not qualify for hedge accounting and were the result of regulatory rulings. A cash flow hedge is a hedge of a forecasted transaction or the variability of cash flows to be received or paid related to a recognized asset or liability. To qualify as a cash flow hedge, the fair value changes in the derivative must be expected to offset 80% to 120% of the changes in fair value or cash flows of the hedged item.

33Comprehensive Income (Loss): Comprehensive income (loss) is the change in the equity of a company, not including those changes that result from shareholder transactions. While the primary component of comprehensive income (loss) is reported net income or loss, the other components of comprehensive income (loss) relate to changes in additional minimum pension liability, the adoption of SFAS No. 158, deferred gains and losses associated with hedging activity, and unrealized gains and losses associated with certain investments held as available for sale. See Note C - Changes in Equity Accounts.

deferred as a component of other comprehensive income until the transaction it is hedging is completed. Conversely, the change in the market value of a derivative not designated as a cash flow hedge is deferred as a regulatory asset or liability as the Company has received approval from the PSC to establish a regulatory asset or liability for derivative instruments that did not qualify for hedge accounting and were the result of regulatory rulings. A cash flow hedge is a hedge of a forecasted transaction or the variability of cash flows to be received or paid related to a recognized asset or liability. To qualify as a cash flow hedge, the fair value changes in the derivative must be expected to offset 80% to 120% of the changes in fair value or cash flows of the hedged item.

Comprehensive Income (Loss): Comprehensive income (loss) is the change in the equity of a company, not including those changes that result from shareholder transactions. While the primary component of comprehensive income (loss) is reported net income or loss, the other components of comprehensive income (loss) relate to changes in additional minimum pension liability, deferred gains and losses associated with hedging activity, and unrealized gains and losses associated with certain investments held as available for sale. See Note C — Accumulated Other Comprehensive Income (Loss).

Additional Minimum Pension Liability: Additional minimum pension liability is recognized under SFAS No. 87, “Employers’ Accounting for Pensions”. Under current rate agreements with the PSC, the Company recovers pension costs from customers and therefore has recognized its additional minimum pension liability (AML) for its qualified plan as a regulatory asset. The additional minimum pension liability for its non-qualified plan is recognized as a component of accumulated other comprehensive income.

Power Purchase Agreements: The Company accounts for its power purchase agreements, which are not deemed to be derivatives or leases, as executory contracts. The Company assesses several factors in determining how to account for its power purchase contracts. These factors include:

• the term of the contract compared to the economic useful life of the facility generating the electricity;

• the involvement, if any, that the Company has in operating the facility;

• the amount of any fixed payments the Company must make, even if the facility does not generate electricity; and

• the level of control the Company has over the amount of electricity generated by the facility, and who bears the risk in the event the facility is unable to generate.

New Accounting Standards: In December 2004, the FASB issued SFAS No. 123R, “Share-Based Payment.” SFAS No. 123R addresses the accounting for transactions in which a company receives employee services in exchange for (a) equity instruments of the company or (b) liabilities that are based on the fair value of the company’s equity instruments or that may be settled by the issuance of such equity instruments. SFAS No. 123R also eliminates the ability to account for share-based compensation transactions using APB Opinion No. 25, “Accounting for Stock Issued to Employees,” and requires that such transactions be accounted for using a fair-value-based method. SFAS No. 123R was originally effective for public companies for interim and annual periods beginning after June 15, 2005; however, in

April 2005 the SEC delayed the effective date of SFAS No. 123R to annual, rather than interim, periods that begin after June 15, 2005. The SEC’s new rule resulted in a six-month deferral for the Company. The adoption of SFAS No. 123R at April 1, 2006 does not have a material impact on its results of operations or its financial position.

In March 2005, the FASB issued Interpretation No. 47 (FIN 47), “Accounting for Conditional Asset Retirement Obligations.” 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.

A conditional retirement obligation, which is referred to in SFAS No. 143, “Accounting for Asset Retirement Obligations,” is defined in FIN 47 as a legal obligation to perform an asset retirement activity in which the timing and (or) method of settlement are conditional upon a future event that may or may not be within the entity’s control. The obligation to perform the asset retirement activity is unconditional even though 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 has sufficient information to make a reasonable estimate of the fair value of an asset retirement obligation. FIN 47 is effective for the Company as of its March 31, 2006 fiscal year end. The Company has a $10 million Asset Retirement Obligation reserve as of March 31, 2006 which does not have a material impact on the Company’s results of operations or 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,” defined the requirements for the accounting for and the reporting of a change in accounting principle. SFAS No. 154 requires retrospective application to prior periods’ financial statements of changes in accounting principle, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. When it is impracticable to determine the period-specific effects of an accounting change on one or more individual prior periods presented, SFAS No. 154 requires that the new accounting principle be applied to the balances of assets and liabilities as of the beginning of the earliest period for which retrospective application is practicable and that a corresponding adjustment be made to the opening balance of retained earnings for that period rather than being reported in an income statement. SFAS No. 154 becomes effective for fiscal years ending after December 15, 2005 and the Company adopted it as of its March 31, 2006 fiscal year.

On March 31, 2006, the FASB issued an Exposure Draft of proposed rules on employers’ accounting for defined benefit pensions and other postretirement benefit plans that would require employers to fully recognize the plan’s funded status on the balance sheet. If adopted as proposed, the new rules would be applied retroactively to prior financial statements presented and be effective for fiscal years ending after December 15, 2006. The new rules, if adopted as proposed, may significantly increase the Company’s recorded pension and other postretirement liabilities. Under the current rate agreements with the PSC, the Company would recover the additional pension costs from customers and therefore the costs would be recognized as a regulatory asset upon adoption. The comment period on this Exposure Draft ended on May 31, 2006. The Company is currently evaluating the Exposure Draft, and at this time cannot

determine the full impact that the potential requirements of the Exposure Draft may have on its financial statements.

Reclassifications: Certain amounts from prior fiscal years have been reclassified on the accompanying consolidated financial statements to conform to the fiscal 2006 presentation.

NOTE B — RATE AND REGULATORY ISSUES

The Company’s financial statements conform to GAAP, including the accounting principles for rate-regulated entities that apply to its regulated operations. SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation,” permits a public utility that is regulated on a cost-of-service basis to defer certain costs it would otherwise charge to expense, if authorized to do so by the regulator. These deferred costs are known as regulatory assets. The Company’s regulatory assets were approximately $4.7 billion as of March 31, 2006 and $5.0 billion as of March 31, 2005. These regulatory assets are probable of recovery under the Company’s rate plans. The Company believes the prices it will charge for electric service in the future, including the CTCs, will be sufficient to recover and earn a return on the Merger Rate Plan’s stranded regulatory assets over their planned amortization periods, assuming no unforeseen reduction in demand or bypass of the CTC exit fees. The Company’s ongoing electricity business continues to be rate-regulated on a cost-of-service basis under the Merger Rate Plan and, accordingly, the Company continues to apply SFAS No. 71 to it. In addition, the Company’s Independent Power Producer contracts, and the Purchased Power Agreements, which were entered into when the Company exited the power generation business, continue to be the obligations of the regulated business.

In the event the Company determines, as a result of lower than expected revenues and (or) higher than expected costs, that its net regulatory assets are not probable of recovery, it can no longer apply the principles of SFAS No. 71 and would be required to record an after-tax, non-cash charge against income for any remaining unamortized regulatory assets and liabilities. If the Company could no longer apply SFAS No. 71, the resulting charge would be material to the Company’s reported financial condition and results of operations.

The Company is earning a return on most of its regulatory assets under its Merger Rate Plan.

On July 29, 2005, the Company filed its biannual CTC reset and deferral account recovery filing to reset rates charged to customers beginning January 1, 2006. The Company resets its CTC every two years under its Merger Rate Plan. The CTC reset is intended to account for changes in forecasted electricity and natural gas commodity prices, and the effects those changes have on the Company’s above market payments under legacy power contracts that otherwise would be stranded. In addition, the Merger Rate Plan allows the Company to recover amounts exceeding $100 million in its deferral accounts (as projected through the end of each two-year CTC reset period through the end of the Merger Rate Plan). In the July 29, 2005 filing, the Company included a proposal to recover the excess balance of the deferral accounts as of June 30, 2005 of $196 million and a projection through the end of the two year period of $373 million. On December 27, 2005 the PSC approved the Company’s proposal for the new CTC effective January 1, 2006. The PSC also approved recovery of deferral account amounts of $100 million in 2006 and $200 million in 2007. For 2006, the deferral-related surcharge was included in rates beginning in April and the $100 million will be collected over the last nine months of the 2006 calendar

~~year.~~• Anthe ~~audit~~term of the ~~deferral~~contract ~~amount~~compared byto the ~~DPS~~economic ~~Staff~~useful islife ~~ongoing.~~of Athe ~~formal~~facility ~~hearing~~generating ~~process~~the ~~has been~~electricity; ~~established~~• ~~before~~the ainvolvement, ~~hearing~~if ~~officer~~any, atthat the ~~PSC~~Company tohas ~~litigate~~in operating the ~~levels~~facility; in• the ~~deferral account.~~amount ~~Under~~of ~~the~~any ~~hearing~~fixed ~~schedule,~~payments the ~~Staff~~Company ~~will~~must bemake, ~~filing~~even ~~testimony~~if ~~setting~~the ~~forth~~facility ~~its~~does ~~initial adjustments~~not ingenerate ~~early~~electricity; ~~August.~~and ~~The~~• ~~Company~~the ~~will~~level ~~continue~~of tocontrol ~~defer~~the ~~costs~~Company ~~and~~has ~~revenues,~~over ~~as applicable, through~~ the ~~end~~amount of ~~the~~electricity ~~Merger~~generated ~~Rate~~by ~~Plan~~the ~~on December 31~~facility, ~~2011.~~and ~~The~~who ~~Company’s~~bears ~~future~~the ~~filings~~risk ~~for recovery~~in ofthe ~~deferred~~event ~~amounts~~the ~~are~~facility ~~subject~~is unable to ~~regulatory review and approval~~generate.

~~Stranded~~New ~~Costs~~Accounting Standards: ~~Under~~In May 2005, the ~~Merger~~FASB ~~Rate~~issued ~~Plan~~SFAS No. 154, “Accounting Changes and Error Corrections, a ~~regulatory~~replacement ~~asset~~of ~~was~~APB ~~established~~Opinion ~~that~~No. 20 ~~included~~and ~~the costs~~FASB ofStatement ~~the~~No. 3.” ~~Master~~Previously, ~~Restructuring~~APB ~~Agreement~~No. 20, “Accounting ~~(MRA)~~Changes,” ~~the~~and ~~cost~~SFAS ofNo. 3, ~~any~~“Reporting ~~additional~~Accounting ~~IPP~~Changes ~~contract~~in ~~buyouts~~Interim Financial ~~and~~Statements,” defined the ~~deferred~~requirements ~~loss~~for onthe accounting for and the ~~sale~~reporting of ~~the~~a ~~Company’s~~change ~~generation~~in accounting ~~assets~~principle. ~~The~~SFAS ~~MRA~~No. 154 ~~represents~~requires ~~the~~retrospective ~~cost~~ application to ~~terminate~~prior periods’ financial statements of changes in accounting principle, ~~restate~~unless it is impracticable to determine either the period-specific effects or ~~amend~~the ~~IPP~~cumulative ~~contracts~~effect of the change. ~~The~~When ~~Company~~it is ~~also~~impracticable ~~permitted~~ to determine ~~defer~~the ~~and~~period-specific ~~amortize~~effects of an accounting change on one or more individual prior periods presented, SFAS No. 154 requires that the ~~cost~~new accounting principle be applied to the balances of ~~any~~assets ~~additional~~and ~~IPP~~liabilities ~~contract~~as ~~buyouts.~~of ~~Beginning~~the ~~February 1,~~beginning ~~2002,~~of the ~~Merger~~earliest ~~Rate~~period ~~Plan~~for which ~~stranded~~retrospective ~~costs~~application ~~regulatory~~is ~~asset~~practicable isand ~~being~~that ~~amortized~~a ~~unevenly~~corresponding ~~over~~adjustment ~~ten~~be ~~years~~made ~~with~~to ~~larger~~the ~~amounts~~opening balance of retained earnings for that period rather than being ~~amortized~~reported in ~~the~~an ~~latter~~income statement. SFAS No. 154 became effective for fiscal years ending after December 15, ~~consistent~~2005. ~~with~~The ~~projected~~Company adopted ~~recovery~~SFAS ~~through~~No. 154 ~~rates~~as of its March 31, 2006 fiscal year with no impact.

~~Regulatory~~In ~~Tax~~December 2004, ~~Asset:~~the ~~The~~FASB ~~regulatory~~issued ~~tax~~SFAS ~~asset~~No. 123R, ~~represents~~“Share-Based Payment.” SFAS No. 123R addresses the ~~expected~~accounting ~~future~~for ~~recovery~~transactions ~~from~~in which a company receives employee services in exchange for (a) ~~ratepayers~~equity instruments of the ~~tax~~company ~~consequences~~or of(b) liabilities ~~temporary~~that ~~differences~~are ~~between~~based on the ~~recorded~~fair ~~book~~value ~~basis~~of ~~and~~ the ~~tax~~company’s ~~basis~~equity instruments or that may be settled by the issuance of ~~assets~~such ~~and~~equity ~~liabilities~~instruments. SFAS ~~This~~No. 123R ~~amount~~also iseliminates ~~primarily~~the ~~timing~~ability ~~differences~~to ~~related~~account for share-based compensation transactions using Accounting Principles Board (APB) Opinion No. 25, “Accounting for Stock Issued to Employees,” ~~depreciation~~and requires that such transactions be accounted for using a fair-value-based method. ~~These~~SFAS ~~amounts~~No. 123R ~~are~~was ~~recovered~~originally effective for public companies for interim and ~~amortized~~annual asperiods beginning after June 15, 2005; however, in April 2005 the ~~related~~Securities ~~temporary~~and ~~differences~~Exchange Commission (SEC) delayed the ~~reverse~~effective date of SFAS No. 123R to annual, rather than interim, periods that begin after June 15, 2005. The adoption of SFAS No. 123R on April 1, 2006 did not have a material impact on the Company’s results of operations or its financial position.

~~Deferred~~In ~~Environmental~~July 2006, ~~Restoration~~the ~~Costs:~~FASB ~~This~~issued ~~regulatory~~Interpretation ~~asset~~No. 48 ~~represents~~(FIN ~~deferred~~48), ~~costs~~“Accounting for Uncertainty in Income ~~associated~~Taxes ~~with~~– an interpretation of FASB Statement No. 109.” FIN 48 clarifies the ~~Company’s~~accounting ~~share~~and reporting offor uncertainties in income tax law. FIN 48 prescribes a comprehensive model for the financial ~~estimated~~statement ~~costs~~recognition, tomeasurement, ~~investigate~~presentation and ~~perform~~disclosure ~~certain~~of uncertain tax ~~remediation~~positions ~~activities~~taken ator ~~sites~~expected ~~with~~to ~~which~~be ittaken ~~may~~in beincome ~~associated~~tax returns. The ~~Company’s~~cumulative ~~rate~~effect ~~plans~~of ~~provide~~applying ~~for~~the ~~specific~~provision ~~rate~~of ~~allowances~~this interpretation are required to be reported separately as an adjustment to the opening balance of retained earnings in the year of adoption. FIN 48 is effective for ~~these~~fiscal ~~costs~~years beginning after December 15, ~~with~~2006 ~~variances~~and ~~deferred~~will ~~for~~be ~~future~~effective ~~recovery~~for orthe ~~pass-back~~Company toin ~~customers.~~the first quarter of its 2008 fiscal year. The Company ~~believes~~is ~~future~~currently ~~costs,~~evaluating ~~beyond~~the impact the ~~expiration~~adoption of ~~current~~FIN ~~rate plans,~~48 will ~~continue~~have toon beits ~~recovered~~financial statements ~~through~~and ~~rates~~is not yet in a position to determine such effects.

~~Pension~~In ~~and~~September 2006, ~~Post-retirement~~the ~~Benefit~~FASB ~~Plans:~~issued ~~Excess~~SFAS ~~costs~~No. 157, of“Fair ~~the~~Value ~~Company’s~~Measurements,” ~~pension~~which ~~and~~provides ~~post-retirement~~enhanced ~~benefits~~guidance ~~plans~~for ~~over~~using ~~amounts~~fair ~~received~~value measurements in ~~rates~~financial ~~are~~reporting. ~~deferred~~While tothe astandard does ~~regulatory~~not ~~asset~~expand the use of fair value in any new circumstance, it has applicability to several becurrent ~~recovered~~accounting instandards athat ~~future~~require ~~period~~or permit entities to measure assets and liabilities at fair value. This standard

Additional Minimum Pension Liability: The offset to any additional minimum pension liability associated with the Company’s qualified pension plan is applied to a regulatory asset on a pre-tax basis instead of being applied on an after-tax basis to other comprehensive income.

Loss on Reacquired Debt: The loss on reacquired debt regulatory asset represents the costs to redeem certain long-term debt securities which were retired prior to maturity. These amounts are amortized ratably as interest expense over the lives of the related issues in accordance with PSC directives.

Other: Included in the other regulatory asset is the accumulation of numerous miscellaneous regulatory deferrals, income earned on gas rate sharing mechanisms, the incentive earned on the sale of the fossil and hydro generation assets and certain New York Independent System Operator (NYISO) costs that were deferred for future recovery.

See Notes D, H and L for a discussion of regulatory asset accounts — Deferred environmental restoration costs, Pensions and post-retirement benefits plans and Derivatives, respectively.

~~NOTE~~defines Cfair —value, ~~ACCUMULATED~~establishes ~~OTHER~~a ~~COMPREHENSIVE~~framework ~~INCOME~~for ~~(LOSS)~~measuring fair value in GAAP and expands disclosures about fair value measurements. The Company is currently evaluating SFAS No. 157 and at this time cannot determine the full impact that the potential requirements may have on its financial statements.

	Unrealized
	Gains (Losses)									Total
	On			Additional						Accumulated
	Available-for-			Minimum						Other
	Sale			Pension			Cash Flow			Comprehensive
(in thousands of dollars)	Securities			Liability			Hedges			Income (Loss)
March 31, 2004 balance	$	1,147		$	(1,557	)	$	3,025		$	2,615
Unrealized gains (losses) on securities, net of tax		732									732
Hedging activity, net of tax								14,557			14,557
Reclassification adjustment for gain included in net income, net of tax		(173	)					(4,770	)		(4,943	)
March 31, 2005 balance	$	1,706		$	(1,557	)	$	12,812		$	12,961
Unrealized gains (losses) on securities, net of tax		(337	)								(337	)
Hedging activity, net of tax								4,009			4,009
Change in additional minimum pension liability, net of tax					358						358
Reclassification adjustment for gain included in net income, net of tax		(233	)					(21,574	)		(21,807	)
March 31, 2006 balance	$	1,136		$	(1,199	)	$	(4,753	)	$	(4,816	)

~~The~~In ~~deferred~~September 2006, ~~tax~~the ~~benefit~~SEC issued Staff Accounting Bulletin (~~expense~~SAB) onNo. 108, ~~other~~“Considering ~~comprehensive~~the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements.” SAB No. 108 requires companies to quantify the impact of correcting misstatements using both an income ~~for~~statement (rollover) approach and a balance sheet (iron curtain) approach. If the misstatement ~~following~~of ~~periods~~prior year expense is material to the current year, after all of the relevant ~~was:~~quantitative and qualitative factors are considered, the prior year financial statements should be corrected. Correcting prior year financial statements for immaterial errors would not require previously filed reports to be amended.

	For the			For the			For the
	year ended			year ended			year ended
	March 31,			March 31,			March 31,
(in thousands of dollars)	2006			2005			2004
Investment activities	$	225		$	(488	)	$	(1,127	)
Hedging activities		(2,673	)		(9,705	)		42
Change in additional minimum pension liability		(239	)		—			1,038
Reclassification adjustment for gain included in net income		14,538			3,295			(1,685	)

Reclassifications: Certain amounts from prior fiscal years have been reclassified on the accompanying consolidated financial statements to conform to the fiscal 2007 presentation.

NOTE DB —– ~~COMMITMENTS~~RATE AND ~~CONTINGENCIES~~REGULATORY ISSUES

~~Long~~The Company’s financial statements conform to GAAP, including the accounting principles for rate-~~Term~~regulated ~~Contracts~~entities with respect to its regulated operations. The Company applies the provisions of SFAS No. 71, “Accounting for the ~~Purchase~~Effects of ~~Electric~~Certain ~~Power:~~Types ~~The~~of Regulation.” In accordance with SFAS No. 71, the Company ~~has~~records ~~several~~regulatory ~~types~~assets of(expenses ~~long-term~~deferred for future ~~contracts~~recovery from customers) and regulatory liabilities (revenues collected for ~~the~~future ~~purchase~~payment of expenses ~~electric~~or ~~power~~for return to customers) on the balance sheet. The Company’s ~~commitments~~regulatory ~~under~~assets ~~these long-term~~were ~~contracts,~~approximately $4.4 billion and $4.7 billion as of March 31, 2007 and 2006, respectively. These regulatory assets are ~~summarized~~probable inof recovery under the ~~table~~Company’s ~~below~~Merger Rate Plan (MRP) and Gas Multi-Year Rate and Restructuring Agreement. The Company ~~did~~is ~~not~~earning ~~enter~~a ~~into~~return on most of its ~~any~~regulatory ~~new~~assets ~~agreements~~under its MRP. The Company believes that the prices it will charge for electric service in ~~fiscal~~the ~~2006~~future, orincluding ~~2005.~~the ~~For~~Competitive aTransition ~~detailed~~Charges ~~discussion~~(CTCs), ofwill be sufficient to recover and earn a return on the ~~financial~~MRP’s ~~swap~~stranded regulatory assets over their planned amortization ~~agreements~~periods, ~~that~~assuming no unforeseen reduction in load or bypass of the CTC charges. The Company’s ongoing ~~has~~electric ~~entered~~business ~~into~~continues to ~~hedge~~be ~~the~~rate-regulated ~~costs~~on a cost-of-service ~~purchased~~basis ~~electricity~~under ~~(which~~the ~~are~~MRP ~~not~~and, ~~included~~accordingly, inthe Company continues to apply SFAS No. 71 to it. In addition, the ~~table~~Company’s Independent ~~below~~Power Producer (IPP) contracts, ~~see~~and ~~Note~~the LPurchase —Power ~~Derivatives~~Agreements ~~and~~entered ~~Hedging~~into ~~Activities~~when the Company exited the power generation business, continue to be the obligations of the regulated business.

(in thousands of dollars)
Fiscal Year
Ended	Estimated
March 31,	Payments
2007	$	455,823
2008		439,435
2009		414,523
2010		344,111
2011		262,021
Thereafter		2,228,199

IfDeferral Audit: Under its MRP, the Company ~~needs~~is ~~any~~authorized ~~additional~~to ~~energy~~recover actual amounts deferred under the plan for each two-year period, as well as deferrals projected to ~~meet~~accrue over the subsequent two-year period that are in excess of a $100 million threshold. The deferrals are subject to regulatory review and approval. On July 29, 2005, the Company made its ~~load~~biannual deferral account recovery filing for balances in the deferral account as of June 30, it2005 ~~can~~plus ~~purchase~~projected deferrals. On December 27, 2005, the ~~electricity~~PSC approved recovery of deferral account amounts of $100 million in ~~from~~calendar ~~other~~year ~~IPPs~~2006 and $200 million in calendar year 2007, ~~utilities~~and established a timeline for the Department of Public Service Staff (Staff) to perform its audit of the deferral account. For 2006, the ~~energy~~deferral ~~merchants~~surcharge orwas ~~through~~included in rates beginning in April and the ~~NYISO~~$100 million atwas ~~market~~collected over ~~prices~~the last nine months of the 2006 calendar year. ~~Substantially~~The Staff filed testimony on August 2, 2006, ~~all~~proposing in excess of ~~these~~$200 million ~~contracts~~of ~~require~~initial ~~power~~adjustments to bethe ~~delivered~~deferral ~~before~~balance and projected deferrals. After replies from the Staff and the Company, isan ~~obligated~~evidentiary hearing was held on October 5, 2006. Upon the conclusion of the evidentiary hearings, the Company and the Staff agreed to ~~make~~enter into non-binding mediation discussions before an administrative law judge from the PSC in ~~payment~~an attempt to resolve some or all of the amounts remaining in dispute.

~~Gas~~Through ~~Supply~~the mediation process, ~~Storage~~the Company, the Staff, and ~~Pipeline~~Multiple ~~Commitments:~~Intervenors In(Parties), ~~connection~~reached a ~~with~~resolution ~~its~~of ~~regulated~~the ~~gas~~disputed ~~business,~~issues presented in the deferral account case as well as other cases ~~Company~~pending ~~has~~before ~~long-term~~the ~~commitments~~Commission ~~with~~regarding apension ~~variety~~costs, the costs of ~~suppliers~~enhanced inspections of the transmission and ~~pipelines~~distribution tosystem, ~~purchase~~and ~~gas~~the sale of the Nine Mile Point nuclear generating ~~commodity,~~facilities. ~~provide~~A ~~gas~~Stipulation ~~storage~~of ~~capability~~the Parties (Stipulation) setting forth the resolution of these issues was executed and ~~transport~~filed ~~gas~~with ~~commodity~~the Commission on ~~interstate~~March 23, ~~gas~~2007. ~~pipelines~~A hearing on the Stipulation was held before the PSC’s administrative law judge on May 17, 2007.

~~The~~Under ~~table~~the ~~below~~Stipulation, ~~sets~~the ~~forth~~Company has agreed to a net reduction of the ~~Company’s~~deferral ~~estimated~~account ~~commitments~~balance atof approximately ~~March~~$127 ~~31,~~million. ~~2006~~This ~~for~~includes ~~each~~reclassifications from the deferral account to other balance sheet accounts of approximately $64 million. It also includes a reduction to the deferral ~~next~~account ~~five~~balance ~~years~~as of February 28, 2007 and ~~thereafter~~decrease to earnings before income taxes of approximately $63 million. These adjustments include impacts to related gas deferral balances. The significant issues resolved under the Stipulation include:

(in thousands of dollars)
Fiscal Year
Ended			Gas Storage/
March 31,	Gas Supply		Pipeline
2007	$	245,259	$	50,000
2008		195,036		46,600
2009		—		5,310
2010		—		5,310
2011		—		5,310
Thereafter		—		4,324

	-		The Company will cease seeking to recover most disputed station service lost revenues. This resulted in a reduction to the deferral account and pre-tax earnings as of February 28, 2007 of $68 million. The impact of the settlement on future revenues depends on the usage by generators and prospective adjustments to delivery rates that are dependent in part on commodity prices. We currently estimate a reduction in revenues of about $9 million to $12 million per year through December 31, 2011 which is the end of the MRP.

	-		The Parties agreed to the method of determining incremental major storm costs related primarily to the treatment of third party contractor costs and costs incurred by affiliates during storm restoration efforts. The definition of a major storm was also clarified under the Stipulation. Storm related adjustments resulted in a reduction of $10 million to the deferral account and pre-tax earnings.

	-		The Parties agreed to the method of determining deferrable incremental costs associated with the Company’s ongoing stray voltage inspection and testing program resulting in a reduction to the deferral account and pre-tax earnings of $4 million.

	-		The Parties agreed to the method for capitalizing fringe benefit overhead costs associated with the Company’s fixed asset construction activities. This resulted in a decrease to utility plant of $17

With respect to firm gas supply commitments, the amounts are based upon volumes specified in the contracts giving consideration to the minimum take provisions. Commodity prices are based on New York Mercantile Exchange quotes and reservation charges, when applicable. Storage and pipeline capacity commitments’ amounts are based upon volumes specified in the contracts and represent demand charges priced in currently filed tariffs. At March 31, 2006, the Company’s firm gas supply commitments have varying expiration dates, the latest of which is March 2008. The gas storage and transportation commitments have varying expiration dates with the latest being October 2012.

Environmental Contingencies: The normal ongoing operations and historic activities of the Company are subject to various federal, state and local environmental laws and regulations. Like many other industrial companies, the Company’s transmission and distribution business uses or generates some hazardous and potentially hazardous wastes and by-products. Under federal and state Superfund laws, potential liability for the historic contamination of property may be imposed on responsible parties jointly and severally, without fault, even if the activities were lawful when they occurred.

The Environmental Protection Agency (EPA), Department of Environmental Conservation (DEC), as well as private entities have alleged that the Company is a potentially responsible party under state or federal law for the remediation of an aggregate of approximately 100 sites, including 51 of which are Company owned. The Company’s most significant liabilities relate to manufactured gas plant (MGP) facilities formerly owned or operated by the Company’s previous owners. The Company is currently investigating and remediating, as necessary, those MGP sites and certain other properties under agreements with the EPA and DEC.

			million, an increase to the deferral account of $11 million, and a reduction in pre-tax earnings of $6 million.

	-		The Company is allowed to recover 50% of pension settlement losses that it incurred in fiscal years 2007 and 2004. This resulted in an increase to the deferral account and pre-tax earnings of $23 million related to fiscal 2007 and 2004 pension settlement losses.

	-		Although it has no impact on past or future rates, the Company will exclude goodwill from any future earnings sharing filings and other filings made with the PSC.

~~The~~Certain ~~Company~~deferral ~~believes~~account ~~that~~balances ~~obligations~~as ~~imposed~~of onJune 30, ~~the~~2005 ~~Company~~remain ~~because~~subject ofto ~~environmental~~audit ~~laws~~by ~~will~~the ~~not~~Staff. The ~~have~~Stipulation aalso ~~material~~clarifies ~~impact~~going onforward ~~its~~procedures ~~results~~for recording, reporting and auditing of certain ~~operations~~other ordeferrals ~~its~~authorized ~~financial~~for ~~condition~~recovery. The ~~Company’s~~next biannual deferral account filing will be ~~Merger~~made ~~Rate~~by ~~Plan~~August 1, ~~provides~~2007 for ~~the~~deferral ~~continued~~balances ~~application~~as of ~~deferral~~June 30, ~~accounting~~2007 ~~for~~and ~~variations~~projected indeferrals through ~~spending~~December 31, ~~from~~2009. ~~amounts~~The ~~provided~~Staff inwill ~~rates~~audit ~~related~~future tobiannual ~~these~~deferral ~~environmental~~account ~~obligations.~~filings Asmade apursuant ~~result,~~to the ~~Company~~MRP, ~~has~~however ~~recorded~~the aParties ~~regulatory~~have ~~asset~~agreed ~~representing~~that the ~~investigation,~~amount ~~remediation~~of deferral recoveries in calendar year 2008 and 2009 will not exceed the $200 million level currently being collected in rates. Any ~~monitoring~~deferrals ~~obligations~~in itexcess ~~expects~~of this recovery level would be subject to ~~recover~~recovery ~~from~~after ~~ratepayers~~2009.

~~The~~Significant ~~Company~~components isof ~~pursuing~~regulatory ~~claims~~assets ~~against other potentially responsible parties to recover investigation and remediation costs it believes~~ are ~~the~~as ~~obligations of those parties. The Company~~follows: cannot predict the success of such claims, however. As of March 31, 2006 and 2005, the Company has accrued liabilities related to its environmental obligations of $400 million and $431 million, respectively, which is reflected in the Company’s Consolidated Balance Sheets. The decrease in the accrued liabilities was primarily due to the payments made for costs which were previously accrued. The potential high end of the range at March 31, 2006 is presently estimated at approximately $526 million.

~~Nuclear~~Merger ~~Contingencies:~~Rate AsPlan ofStranded ~~March 31,~~Costs: ~~2006~~Under ~~and~~the ~~2005~~MRP, ~~the Company has~~ a ~~liability~~regulatory ofasset ~~$151 million and~~was ~~$146 million,~~established ~~respectively,~~that ~~in other non-current liabilities for~~ included the ~~disposal~~costs of ~~nuclear fuel irradiated prior to 1983. In January 1983,~~ the ~~Nuclear~~Master ~~Waste~~Restructuring ~~Policy~~Agreement ~~Act of 1982~~ (~~the Nuclear Waste Act~~MRA), ~~established~~the a cost of ~~$.001~~any ~~per~~additional ~~kWh~~IPP ofcontract buyouts ~~net~~and ~~generation~~the ~~for~~deferred ~~current~~loss ~~disposal~~on ofthe ~~nuclear~~sale ~~fuel and provides for a determination~~ of the Company’s ~~liability~~generation ~~to the U~~assets.S. ~~Department~~The ofMRA ~~Energy (DOE) for~~represents the ~~disposal~~cost ofto ~~nuclear~~terminate, ~~fuel~~restate ~~irradiated~~or ~~prior~~amend toIPP ~~1983~~contracts. The ~~Nuclear~~Company ~~Waste~~is ~~Act~~ also ~~provides~~permitted ~~three payment options for liquidating such liability and the Company has elected~~ to ~~delay~~defer ~~payment, with~~and ~~interest,~~amortize ~~until~~ the ~~year~~cost inof ~~which~~any ~~Constellation~~additional ~~Energy~~IPP ~~Group~~contract ~~Inc~~buyouts., ~~which~~Beginning ~~purchased~~February 1, 2002, the ~~Company’s~~MRP ~~nuclear~~stranded ~~assets,~~costs ~~initially~~regulatory ~~plans~~asset tois ~~ship~~being ~~irradiated~~amortized ~~fuel~~unevenly toover anten ~~approved~~years ~~DOE~~with ~~disposal~~larger ~~facility.~~amounts ~~Progress~~being amortized in ~~developing~~ the ~~DOE~~latter ~~facility~~years, ~~has~~consistent ~~been~~with ~~slow~~projected ~~and~~recovery itthrough ~~is anticipated that the DOE facility will not be ready to accept deliveries until at least 2010~~rates.

~~Legal~~Regulatory ~~Matters~~Tax Asset: The regulatory tax asset represents the expected future recovery from ratepayers of the tax consequences of temporary differences between the recorded book basis and the tax basis of assets and liabilities. This amount is primarily timing differences related to depreciation. These amounts are recovered and amortized as the related temporary differences reverse.

~~Station~~Deferred ~~Service~~Environmental ~~Cases~~Restoration ~~(Niagara~~Costs: ~~Mohawk~~This ~~Power~~regulatory ~~Corp.~~asset v.represents ~~Huntley~~deferred ~~Power L.L.C. et al., FERC Docket No.~~costs ~~EL03-27;~~associated ~~AES~~with ~~Somerset,~~the ~~L.L.C.~~Company’s v.share ~~Niagara~~of ~~Mohawk~~the ~~Power~~estimated ~~Corp.,~~costs ~~FERC~~to ~~Docket~~investigate ~~No. EL03-204;~~and ~~Nine~~perform ~~Mile~~certain ~~Point~~remediation ~~Nuclear~~activities ~~Station,~~at ~~L.L.C.~~hazardous v.waste ~~Niagara~~sites ~~Mohawk~~with ~~Power~~which ~~Corp.,~~it ~~FERC~~may ~~Docket~~be Noassociated. ~~EL03-234; Keyspan-Ravenswood,~~ ~~Inc.~~The v.Company’s rate ~~NYISO,~~plans ~~FERC~~provide ~~Docket~~for ~~No. EL01-50-004.)~~specific Arate ~~number~~allowances offor ~~generators~~these ~~have complained~~costs, ~~or withheld payments associated~~ with ~~the~~variances ~~Company’s~~deferred ~~delivery~~for ~~of station service to their~~future ~~generation~~recovery ~~facilities,~~or ~~arguing~~pass-back ~~that they should be permitted~~ to ~~bypass its retail charges~~customers. The ~~FERC~~ ~~issued~~Company ~~two~~believes ~~orders~~future oncosts, ~~complaints~~beyond ~~filed by~~ the ~~Company’s~~expiration ~~station~~of current ~~service~~rate ~~customers in December 2003~~plans, ~~allowing~~will ~~two~~continue ~~generators~~ to ~~net~~be ~~their~~recovered ~~station~~through ~~service electricity over a 30-day period and to avoid state-authorized charges for deliveries made over distribution facilities~~rates. ~~A third order in~~ ~~January 2005~~

Pension and Post-retirement Benefit Plans: Excess costs of the Company’s pension and post-retirement benefits plans over amounts received in rates are deferred to a regulatory asset to be recovered in a future period. This regulatory asset includes the deferral of the fair value adjustments to the pension and PBOPs as of January 30, 2002 acquisition of the Company by National Grid. This deferral totaled $440 million at acquisition and is being amortized on a straight-line basis over the 10 years of the MRP. This amortization is included in the pension and PBOP deferral calculation as part of the costs that are compared to the recovery of such costs in rates.

Loss on Reacquired Debt: The loss on reacquired debt regulatory asset represents the costs to redeem certain long-term debt securities which were retired prior to maturity. These amounts are amortized ratably as interest expense over the lives of the related issues in accordance with PSC directives.

Service Quality Penalties: In connection with its MRP, the Company is subject to maintaining certain service quality standards. Service quality measures focus on eleven categories including safety targets

~~involves~~related ~~affiliates~~to ofgas ~~NRG Energy~~operations, ~~Inc.~~electric ~~These~~reliability ~~orders~~measures ~~directly~~related ~~conflict~~to ~~with~~outages, ~~the Company’s~~residential ~~state-approved tariffs~~ and ~~the~~business ~~orders~~customer ofsatisfaction, ~~the~~meter ~~PSC~~reads, oncustomer ~~station~~call ~~service~~response ~~rates. The orders~~times, ifand ~~finally~~administration ~~upheld, will permit these~~of ~~generators to bypass~~ the ~~Company’s state~~Low-~~jurisdictional~~Income ~~station~~Customer ~~service~~Assistance ~~charges for electricity, including those set forth in the filing that was approved by the PSC on November 25, 2003~~Program. InIf ~~the aggregate,~~a ~~the~~prescribed ~~Company~~standard is ~~owed~~not ~~approximately $58 million as of March 31~~satisfied, ~~2006.~~the ~~The~~ Company ~~appealed~~may ~~these~~incur ~~orders~~a ~~to the U.S. Court of Appeals for the District of Columbia Circuit~~penalty, ~~and~~with the ~~matters~~ ~~were~~penalty ~~consolidated~~amount ~~for~~applied ~~appeal.~~as ~~Oral argument was heard on April 10, 2006, and on June 23, 2006, the Court issued~~ a ~~decision~~credit ~~upholding~~or ~~the~~refund ~~FERC’s orders. The Company is reviewing the decision and considering whether~~ to ~~seek rehearing or further review~~customers.

~~The~~Service ~~Court’s~~quality ~~order~~performance ~~upholding~~is ~~the~~measured ~~FERC~~on ~~orders~~a ~~has~~calendar ~~increased~~year basis, thus the ~~risk~~entire ~~that~~calendar ~~generators~~year ~~will~~is taken beinto ~~able~~account towhen ~~bypass~~determining ~~local~~whether ~~distribution~~a penalty has been incurred that would be credited or ~~company~~refunded ~~charges~~to ~~(including~~customers. ~~stranded~~Target ~~cost~~service ~~recovery~~levels ~~charges)~~for ~~when~~the ~~receiving~~customer service ~~through~~measures and the electric ~~NYISO~~reliability measures are based on performance under all operating conditions. ~~Although~~However, ~~the~~exclusions do ~~Staff~~apply ~~and~~for ~~other~~major ~~parties~~storms ~~may~~or ~~challenge~~abnormal ~~the~~operating ~~Company’s~~conditions ~~position~~such as periods of catastrophe, natural disaster, strike or other unusual events not in the ~~event~~Company’s ~~the FERC~~control. ~~orders~~Based ~~are~~upon ~~finally~~its ~~upheld~~calendar year measurements, the Company ~~believes~~has ~~that~~recorded ~~the~~service ~~provision~~quality inpenalty ~~the~~expenses ~~rate~~of ~~plan~~$11 million ~~that~~and $9 ~~permits~~million for the ~~Company~~fiscal toyears ~~recover~~ended ~~lost~~March 31, ~~revenues~~2007 ~~resulting~~and ~~from~~2006, arespectively. ~~change~~The inMRP ~~law~~includes provisions orthat ~~regulation~~allow ~~would permit~~penalties it to ~~recover~~be ~~the~~doubled ~~lost~~under ~~revenues~~certain ~~that~~circumstances ~~result~~when ~~from~~penalties ~~the~~have ~~FERC~~been incurred ~~orders~~in prior years. These ~~amounts~~circumstances are ~~subject to~~met ~~regulatory~~for ~~review~~the ~~and~~penalties ~~challenge~~associated aswith ~~part~~the frequency of outages on the ~~ongoing~~system. ~~audit~~In ofthese circumstances, the ~~Company’s~~$4.4 million ~~deferral~~penalty ~~account~~for exceeding ~~balance~~the standard for outage frequency is doubled to $8.8 million in ~~accordance~~the ~~with~~current year and prospectively unless the ~~Merger~~Company ~~Rate~~demonstrates ~~Plan~~to the Commission that it has taken appropriate action to improve service quality under the affected standard.

~~NOTE~~Other: EIncluded —in ~~LONG-TERM~~the ~~DEBT~~other regulatory asset is the accumulation of numerous miscellaneous regulatory deferrals, income earned on gas rate sharing mechanisms, the incentive earned on the sale of the fossil and hydro generation assets and certain New York Independent System Operator (NYISO) costs that were deferred for future recovery.

~~Long-term~~See ~~debt~~Notes ~~consisted~~D, H and L for a discussion of ~~the~~regulatory ~~following~~asset ataccounts ~~March 31~~— Deferred environmental restoration costs, ~~2006~~Pensions and ~~2005:~~post-retirement benefits plans and Derivatives, respectively.

(in thousands of dollars)
			March 31,			March 31,
Series		Due	2006			2005
First Mortgage Bonds:
6 5/8%		July 2005	$	—		$	110,000
9 3/4%		November 2005		—			137,981
7 3/4%	(1)	May 2006		275,000			275,000
5.15%	(2)	November 2025		75,000			75,000
Total First Mortgage Bonds				350,000			597,981
Senior Notes(3):
7.63%		October 2005		—			302,439
8.88%		May 2007		200,000			200,000
7.75%		October 2008		600,000			600,000
Total Senior Notes			$	800,000		$	1,102,439
Pollution Control Revenue Bonds-Variable Rate(4):
2004A		October 2013	$	45,600		$	45,600
1985A		July 2015		100,000			100,000
1988A		December 2023		69,800			69,800
1985B&C		December 2025		75,000			75,000
1986A		December 2026		50,000			50,000
1987A		March 2027		25,760			25,760
1987B		July 2027		93,200			93,200
1991A		July 2029		115,705			115,705
Total Pollution Control Revenue Bonds				575,065			575,065
Notes Payable to Holdings(3)
5.80%		November 2012		500,000			500,000
3.83%		June 2010		350,000			350,000
3.72%		July 2009		350,000			350,000
Total Notes Payable to Holdings				1,200,000			1,200,000
Unamortized discount				(1,131	)		(1,496	)
Total Long-Term Debt				2,923,934			3,473,989
Less long-term debt due within one year				275,000			550,420
Long-Term Debt due after one year			$	2,648,934		$	2,923,569

(1)		Not callable prior to maturity.
(2)		Fixed rate pollution control revenue bonds first callable November 1, 2008 at 102%.
(3)		Currently callable with make-whole provisions.
(4)		Currently callable at par.
(5)		Effective interest rate at March 31, 2006 and March 31, 2005 was 3.24% and 2.33%, respectively.

~~Substantially~~NOTE ~~all~~C of– ~~the~~CHANGES ~~Company’s~~IN ~~operating~~EQUITY ~~properties are subject to mortgage liens securing~~ACCOUNTS its mortgage debt. Several series of First Mortgage Bonds were issued to secure a like amount of tax-exempt revenue bonds issued by the New York State Energy Research and Development Authority (NYSERDA). Approximately $575 million of such securities bear interest at short-term adjustable interest rates (with an option to convert to other rates, including a fixed interest rate) which averaged 3.20% for the year ended March 31, 2006, 1.69% for the year ended March 31, 2005 and 1.24% for the year ended March 31, 2004. The bonds are currently in the auction rate mode and are backed by bond insurance. Pursuant to agreements between NYSERDA and the Company, proceeds from such issues were used for the purpose of financing the construction of certain pollution control facilities at the Company’s generation facilities (which the Company subsequently sold) or to refund outstanding tax-exempt bonds and notes.

The ~~aggregate~~following ~~maturities~~table details the components of ~~long-term~~accumulated ~~debt~~other comprehensive income (loss) for the fiscal ~~five~~ years ~~subsequent~~ended to March 31, ~~2006, excluding~~2007 ~~capital~~and ~~leases, are approximately~~2006:

(in millions of dollars)
	Unrealized									Total
Fiscal Year	Amount
	Gains (Losses)									Accumulated
2007	$	275
	On									Other
2008		200
	Available-for			Pension			Cash Flow			Comprehensive
2009		600
(In thousands of dollars)	Sale Securities			Liability			Hedges			Income (Loss)
2010		350
March 31, 2005 balance, net of tax	$	1,706		$	(1,557	)	$	12,812		$	12,961
2011		350
Unrealized gains (losses) on securities		(337	)								(337	)
Thereafter		1,150
Hedging activity								4,009			4,009
Total	$	2,925
Change in additional minimum pension liability					358						358
Reclassification adjustment for (loss) included in net income		(233	)					(21,574	)		(21,807	)
March 31, 2006 balance, net of tax	$	1,136		$	(1,199	)	$	(4,753	)	$	(4,816	)
Unrealized gains (losses) on securities		585									585
Hedging activity								(17,526	)		(17,526	)
Change in additional minimum pension liability					1,199						1,199
Adjustment to initially apply SFAS No. 158					(1,269	)					(1,269	)
Reclassification adjustment for gain (loss) included in net income		(265	)					22,034			21,769
March 31, 2007 balance, net of tax	$	1,456		$	(1,269	)	$	(245	)	$	(58	)

The ~~current~~deferred ~~portion~~tax ofbenefit ~~capital~~(expense) on ~~lease obligations is reflected in the~~ other ~~current~~comprehensive ~~liabilities line~~income ~~item~~for on the ~~Consolidated~~following ~~Balance~~periods ~~Sheet and~~ was ~~approximately $1 million at March 31, 2006 and~~: 2005. The non-current portion of capital lease obligations is reflected in the “Other” line item on the Consolidated Balance Sheet and was approximately $4 million and $5 million at March 31, 2006 and 2005, respectively.

At March 31, 2006 and 2005, the Company’s long-term debt, excluding intercompany debt, had a fair value of approximately $1.8 billion and $2.4 billion, respectively. The fair market value of the Company’s long-term debt was estimated based on the debts’ coupons and remaining lives along with the current interest rate conditions.


	Fiscal Years Ended March 31,
(In thousands of dollars)	2007			2006			2005

Investment activities	$	(390	)	$	225		$	(488	)
Hedging activities		11,684			(2,673	)		(9,705	)
Change in additional minimum pension liability		(799	)		(239	)		—
Adjustment to initially apply SFAS No. 158		846			—			—
Reclassification adjustment for gain (loss) included in net income		(14,513	)		14,538			3,295

~~NOTE~~In Faddition —to ~~SHORT-TERM~~the ~~DEBT~~change in AOCI, the Company recorded a $16 million decrease to additional paid in capital under its intercompany tax sharing arrangement.

The Company has regulatory approval from the FERC to issue up to $1 billion of short-term debt. The Company had short-term debt outstanding of $579 million and $401 million at March 31, 2006 and 2005, respectively, from affiliated companies. The Company participates with National Grid, and certain other National Grid affiliates, in a system money pool. The money pool is administered by the Service Company as the agent for the participants. Short-term borrowing needs are met first by available funds of the money pool participants. Borrowings from the money pool bear interest at the higher of (i) the monthly average of the rate for high-grade, 30-day commercial paper sold through dealers by major corporations as published in The Wall Street Journal, or (ii) the monthly average of the

~~rate~~NOTE ~~then~~D ~~available~~– toCOMMITMENTS ~~money~~AND ~~pool depositors from an eligible investment in readily~~CONTINGENCIES marketable money market funds or the existing short-term investment accounts maintained by money pool depositors or the Service Company during the period in question. In the event neither rate is one that is permissible for a transaction because of constraints imposed by the state regulatory commission having jurisdiction over a utility participating in the transaction, the rate is that which is permissible for the transaction as determined under the requirements of the state regulatory commission. Companies that invest in the money 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 money pool at any time without prior notice. The average interest rate for the money pool was 4.03%, 1.80 % and 1.11 % for fiscal years 2006, 2005 and 2004, respectively.

Long-Term Contracts for the Purchase of Electric Power: The Company ~~had~~has noseveral ~~short~~types of long-term contracts ~~debt~~for ~~outstanding~~the topurchase ~~third~~of electric power. The Company’s commitments under these long-~~parties~~term contracts, atas of March 31, ~~2006~~2007, orare ~~2005~~summarized in the table below. For a detailed discussion of the financial swap agreements that the Company has entered into to hedge the costs of purchased electricity (which are not included in the table below), see Note L — Derivatives and Hedging Activities.

NOTE G — FEDERAL AND STATE INCOME TAXES


(In thousands of dollars)
Fiscal Years Ended	Estimated
March 31,	Payments

2008	$	448,611
2009		441,063
2010		351,501
2011		275,942
2012		237,000
Thereafter		2,008,102

~~Following~~If isthe aCompany ~~summary~~needs ofany ~~the~~additional ~~components~~energy ofto ~~federal~~meet ~~and~~its ~~state~~load, ~~income~~it ~~tax~~can ~~and~~purchase athe ~~reconciliation~~electricity ~~between~~from ~~the~~other ~~amount~~IPPs, ofutilities, ~~federal~~energy ~~income~~merchants ~~tax~~or ~~expense~~through ~~reported~~the inNYISO ~~the~~at ~~Consolidated~~market ~~Statements~~prices. ofSubstantially ~~Operations~~all ~~and~~of ~~the~~these ~~computed~~contracts ~~amount~~require atpower to be delivered before the ~~statutory~~Company ~~tax~~is ~~rate:~~obligated to make payment.

	Year Ended March 31,
(in thousands of dollars)	2006			2005			2004
Components of federal and state income taxes:
Current tax expense (benefit):
Federal	$	61,211		$	(30,229	)	$	(12,003	)
State		22,509			9,459			(474	)
		83,720			(20,770	)		(12,477	)
Deferred tax expense:
Federal		89,908			177,180			128,426
State		13,566			3,542			20,022
		103,474			180,722			148,448
Total	$	187,194		$	159,952		$	135,971
Total income taxes in the consolidated statements of operations:
Income taxes charged to operations	$	190,194		$	171,230		$	138,843
Income taxes credited to “Other income (deductions)”		(3,000	)		(11,278	)		(2,872	)
Total	$	187,194		$	159,952		$	135,971

Gas Supply, Storage and Pipeline Commitments: In connection with its regulated gas business, the Company has long-term commitments with a variety of suppliers and pipelines to purchase gas commodity, provide gas storage capability and transport gas commodity on interstate gas pipelines.

The table below sets forth the Company’s estimated commitments at March 31, 2007 for each of the next five years and thereafter.


(In thousands of dollars)
Fiscal Years Ended			Gas Storage/
March 31,	Gas Supply		Pipeline

2008	$	241,305	$	49,952
2009		—		46,637
2010		—		46,372
2011		—		46,372
2012		—		4,015
Thereafter		—		952

With respect to firm gas supply commitments, the amounts are based upon volumes specified in the contracts giving consideration to the minimum take provisions. Commodity prices are based on New York Mercantile Exchange quotes and reservation charges, when applicable. Storage and pipeline capacity commitment amounts are based upon volumes specified in the contracts and represent demand charges priced in currently filed tariffs. At March 31, 2007, the Company’s firm gas supply commitments have varying expiration dates, the latest of which is March 2008. The gas storage and transportation commitments have varying expiration dates with the latest being October 2012.

Environmental Contingencies: The normal ongoing operations and historic activities of the Company are subject to various federal, state and local environmental laws and regulations. Like many other industrial companies, the Company’s transmission and distribution businesses use or generate some

~~Shown~~hazardous ~~below~~and ispotentially ~~the~~hazardous ~~reconciliation~~wastes ~~between~~and ~~federal~~by-products. ~~income~~Under ~~taxes~~federal and state Superfund laws, potential liability for the ~~tax~~historic ~~computed~~contamination atof ~~prevailing U.S.~~property ~~statutory~~may ~~rate~~be imposed on ~~income~~responsible parties ~~before~~jointly ~~income~~and ~~taxes:~~severally, without fault, even if the activities were lawful when they occurred.

	Year Ended March 31,
(in thousands of dollars)	2006			2005			2004
Computed tax	$	176,495		$	148,371		$	96,481
Increase (reduction) including those attributable to flow-through of certain tax adjustments:
Depreciation		10,225			16,982			21,397
Cost of removal		(7,298	)		(5,664	)		(6,857	)
Allowance for funds used during construction — (a)		—			(1	)		3
State income taxes		23,449			8,451			12,736
Accrual to return adjustment		(9,410	)		3,427			19,842
Debt premium and mortgage recording tax		3,298			487			(1,556	)
E.S.O.P. dividends		—			(1,307	)		—
Dividends exclusion — federal income tax returns		(148	)		(174	)		(149	)
Provided at other than statutory rate		—			(1	)		(2	)
Medicare Act		(7,489	)		(3,579	)		—
Subsidiaries		—			136			250
Deferred investment tax credit reversal		(2,866	)		(2,866	)		(2,872	)
Other		938			(4,310	)		(3,302	)
Total		10,699			11,581			39,490
Federal and state income taxes	$	187,194		$	159,952		$	135,971

The U.S. Environmental Protection Agency (EPA), New York Department of Environmental Conservation (DEC), as well as private entities have alleged that the Company is a potentially responsible party under state or federal law for the remediation of an aggregate of approximately 85 sites, including 47 which are Company-owned. The Company’s most significant liabilities relate to former manufactured gas plant (MGP) facilities formerly owned or operated by the Company’s previous owners. The Company is currently investigating and remediating, as necessary, those MGP sites and certain other properties under agreements with the EPA and DEC.

(The Company believes that obligations imposed on the Company because of the environmental laws will not have a) ~~Includes~~material ~~Carrying~~result ~~Charges~~on ~~(Interest~~operations ~~Expense)~~or ~~imposed~~its byfinancial condition. The Company’s MRP provides for the ~~PSC~~continued application of deferral accounting for variations in spending from amounts provided in rates related to these environmental obligations. As a result, the Company has recorded a regulatory asset representing the investigation, remediation and monitoring obligations it expects to recover from ratepayers.

The Company is pursuing claims against other potentially responsible parties to recover investigation and remediation costs it believes are the obligations of those parties. The Company cannot predict the success of such claims, however. As of March 31, 2007 and 2006, the Company had accrued liabilities related to its environmental obligations of $397 million and $400 million, respectively. The decrease in the accrued liabilities was primarily the result of the closure of some sites as well as normal spending on the sites. The high end of the range of potential liabilities at March 31, 2007 is estimated at $517 million.

Nuclear Contingencies: As of March 31, 2007 and 2006, the Company has a liability of $158 million and $151 million, respectively, in other non-current liabilities for the disposal of nuclear fuel irradiated prior to 1983. In January 1983, the Nuclear Waste Policy Act of 1982 (the Nuclear Waste Act) established a cost of $.001 per kWh of net generation for current disposal of nuclear fuel and provides for a determination of the Company’s liability to the U.S. Department of Energy (DOE) for the disposal of nuclear fuel irradiated prior to 1983. The Nuclear Waste Act also provides three payment options for liquidating such liability and the Company has elected to delay payment, with interest, until the year in which Constellation Energy Group Inc., which purchased the Company’s nuclear assets, initially plans to ship irradiated fuel to an approved DOE disposal facility. Progress in developing the DOE facility has been slow and it is anticipated that the DOE facility will not be ready to accept deliveries until at least 2010.

Legal Matters:

Station Service Cases: A number of generators complained or withheld payments associated with the Company’s delivery of station service to their generation facilities, arguing that they were permitted to bypass its retail charges. The FERC issued two orders on complaints filed by the Company’s station service customers in December 2003, allowing two generators to net their station service electricity over a 30-day period and to avoid state-authorized charges for deliveries made over distribution facilities. Subsequent to December 2003, FERC issued a third order that involved affiliates of NRG Energy, Inc. These orders directly conflict with the Company’s state-approved tariffs and the orders of the PSC on station service rates. The effect of these orders is to permit these generators to bypass the Company’s state-jurisdictional station service charges for electricity, including those set forth in the filing that was approved by the PSC on November 25, 2003. Under those state-approved tariffs, the Company was owed in aggregate approximately $62 million as of December 31, 2006. The Company appealed the FERC orders to the U.S. Court of Appeals for the District of Columbia Circuit, and the matters were

~~The~~consolidated ~~deferred~~for ~~tax~~appeal. ~~liabilities~~On ~~(assets)~~June ~~were~~23, 2006, ~~comprised~~the Court issued a decision upholding the FERC’s orders, and on October 23, 2006, the Court denied the Company’s request for rehearing. On January 22, 2007, the Company filed a joint petition for certiorari to the United States Supreme Court requesting the Court to review and reverse the decision of the ~~following:~~Court of Appeals. On April 30, 2007, the Supreme Court denied certiorari and thus the FERC orders have become final.

as at March 31 (in thousands of dollars)	2006			2005
Alternative minimum tax	$	117,618		$	111,609
Unbilled revenues		26,205			23,458
Non-utilized NOL carryforward		—			105,212
Liability for environmental costs		191,307			198,621
Voluntary early retirement program		42,089			47,558
Bad debts		52,498			29,474
Pension and other post-retirement benefits		248,446			185,324
Other		268,092			209,550
Total deferred tax assets		946,255			910,806
Depreciation related		(979,936	)		(921,928	)
Investment tax credit related		(37,811	)		(40,677	)
Deferred environmental restoration costs		(186,842	)		(200,175	)
Merger rate plan stranded costs		(795,184	)		(848,182	)
Merger fair value pension and OPEB adjustment		(109,478	)		(128,188	)
Bond redemption and debt discount		(30,009	)		(25,056	)
Pension and other post-retirement benefits		(50,832	)		(88,830	)
Other		(275,169	)		(61,969	)
Total deferred tax liabilities		(2,465,261	)		(2,315,005	)
Net accumulated deferred income tax liability		(1,519,006	)		(1,404,199	)
Current portion (net deferred tax asset)		168,354			307,431
Net accumulated deferred income tax liability (non-current)	$	(1,687,360	)	$	(1,711,630	)

Under those orders, FERC allows generators to bypass local distribution company charges (including stranded cost recovery charges) when receiving service through the New York Independent System Operator if the amount of power produced by a generator over a 30-day period exceeds the amount of power taken over the power grid. As discussed under the deferral audit section of Note B, the Company is not recovering the lost revenues associated with the FERC orders through its deferral account and recorded a charge to expense of $68 million in the fourth quarter related to this matter.

~~The Company has been audited and reported on by the Internal Revenue Service (IRS) through~~Acquisitions ~~January 31, 2002.~~

~~The~~In ~~Company and other related subsidiaries of National Grid USA have participated with National Grid Holdings~~2006, ~~Inc. (NGHI), a wholly owned subsidiary of~~ National Grid plc, inthe ~~filing~~ultimate ~~consolidated US~~parent ~~federal~~of ~~income tax returns since joining~~ the ~~NGHI~~Company, ~~consolidated~~announced ~~filing group upon~~ the ~~Company’s~~proposed acquisition ~~January 31,~~of ~~2002~~KeySpan ~~acquisition~~Corporation by(KeySpan) ~~National~~for ~~Grid~~$7.3 billion ~~The~~together ~~Company’s~~with ~~tax~~the ~~provisions~~assumption ~~and~~of ~~tax accounts are~~approximately ~~calculated~~$4.5 billion onof adebt. ~~separate~~This ~~company~~would ~~basis.~~significantly ~~Federal~~expand ~~income~~its ~~tax~~operations ~~returns~~in ~~have~~the ~~been~~northeastern ~~examined~~US ~~and all~~as ~~appeals~~KeySpan ~~and~~is ~~issues have been agreed upon by~~ the ~~Internal~~fifth ~~Revenue~~largest ~~Service~~distributor ~~(IRS) and~~of ~~the~~natural ~~Company through~~gas ~~January 31,~~in ~~2002,~~ the ~~acquisition~~US ~~date~~ and ~~final~~the ~~tax~~largest ~~return~~in ~~year end date of~~ the ~~Company’s~~northeast ~~former~~US, ~~consolidated~~serving ~~filing~~2.6 million ~~group~~customers ~~prior~~in toNew ~~its~~York, ~~acquisition~~Massachusetts byand ~~National~~New ~~Grid~~Hampshire. InKeySpan ~~addition, federal~~also ~~income~~operates ~~tax~~an ~~returns~~electricity ~~have~~transmission ~~been examined~~ and ~~all~~distribution ~~appeals~~network ~~and~~serving ~~issues~~1.1 million ~~have~~customers ~~been~~in ~~agreed~~New York ~~upon~~under bya ~~the~~long-term ~~IRS and~~contract with the ~~NGHI~~Long ~~consolidated~~Island ~~filing~~Power ~~group through March 22, 2000~~Authority. ~~The~~KeySpan’s ~~IRS~~other ~~is currently reviewing the~~interests ~~March 31,~~include ~~2001~~6.6 ~~and~~GW ~~March 31, 2002 tax returns~~ of ~~the~~generation ~~NGHI~~capacity, ~~consolidated~~together ~~filing~~with ~~group which the Company joined upon its acquisition. The IRS has issued~~ a ~~preliminary~~small ~~notice~~portfolio of ~~deficiency~~non-regulated, ~~disallowing~~energy-related ~~certain~~services, ~~tax~~and ~~deductions~~strategic ~~taken~~investments in ~~these~~certain ~~consolidated~~gas USpipeline, ~~federal~~storage ~~income~~and ~~tax returns. These~~liquefied ~~adjustments~~natural ~~are~~gas ~~being appealed~~assets. The ~~Company~~planned ~~has~~combination ~~joint~~of ~~and~~its ~~several~~current ~~liability~~US ~~for~~operations ~~any~~with ~~potential assessments~~those ~~against~~of ~~the~~KeySpan would ~~consolidated~~result ~~group, for periods since it joined the group~~ in ~~February 2002. Management~~National ~~believes~~Grid ~~that~~plc ~~the~~becoming ~~positions taken by~~ the ~~Company~~third ~~and~~largest ~~its~~energy ~~related~~utility ~~subsidiaries~~in ~~and parent company are appropriate and~~ the ~~resolution of the tax matters will not have a material effect on the Company’s financial position, results of operations or cash flows~~US.

InNational ~~December 1998,~~Grid plc has made significant progress towards completion and has achieved several important milestones. National Grid plc has obtained clearances from the ~~Company~~Federal ~~received~~Trade aCommission in ~~ruling~~respect of the Hart-Scott-Rodino Antitrust Improvements Act, from the ~~IRS~~Committee ~~which~~on ~~provided~~Foreign Investment ~~that~~in the ~~amount~~US ofand ~~cash~~by the Federal Energy Regulatory Commission, and received approval from both National Grid plc and KeySpan shareholders. In March 2007, National Grid plc and KeySpan announced an agreement with the ~~value~~staff of ~~common~~the ~~stock~~Long ~~that~~Island ~~was~~Power ~~paid~~Authority in principle regarding amended contracts, which is subject to approval by the ~~Company~~Authority toand by the ~~subject~~Comptroller ~~terminated~~and Attorney ~~IPP~~General ~~Parties~~of New York. In April 2007, the staff of the New Hampshire Public Utilities ~~was~~Commission ~~deductible~~announced inthat ~~1998~~they ~~which~~would ~~resulted~~recommend inapproval. National Grid plc has also made filings with the ~~Company~~New ~~not~~York ~~paying~~Public ~~any~~Service ~~regular~~Commission ~~federal~~and has held extensive discussions with regulatory staff and other interested parties that have yielded significant progress toward resolution of issues important to the completion of the acquisition. National Grid plc anticipates achieving a final result that will benefit investors and consumers alike by this autumn.

~~income~~NOTE ~~taxes~~E ~~for~~– ~~1998,~~LONG-TERM ~~and further generated a substantial net operating loss for federal income~~DEBT tax purposes. The Company carried back a portion of the unused net operating loss (NOL) to the years 1996 and 1997, and also for the years 1988 through 1990, which resulted in federal income tax refunds of $135 million that were received in January 1999. As a result of the merger with National Grid, the Company is now part of the consolidated tax return filing group of National Grid Holdings, Inc. The consolidated tax filing group was able to utilize the remaining NOL carryforward, which was $301 million as of March 31, 2006, in the 2005 fiscal year. National Grid’s ability to utilize the NOL carryforward generated as a result of the MRA and the utilization of alternative minimum tax credits is affected by the rules of Section 382 of the Internal Revenue Code.

~~There~~Long-term ~~were~~debt noconsisted ~~valuation~~of ~~allowances~~the ~~for~~following ~~deferred tax assets~~ at March 31, ~~2006~~2007 orand ~~2005.~~2006:

NOTE H — EMPLOYEE BENEFITS


Series	Rate %	Maturity	2007			2006

(In thousands of dollars)
First Mortgage Bonds:
7 ³/4%	7.750	May 15, 2006	$	—		$	275,000
Senior Notes: ⁽¹⁾ 8 7/8%	8.875	May 15, 2007		200,000			200,000
7 ³/4%	7.750	October 1, 2008		600,000			600,000
Tax exempt:
5.15% ⁽²⁾	5.150	November 1, 2025		75,000			75,000
2013	Variable	October 1, 2013		45,600			45,600
2015	Variable	July 1, 2015		100,000			100,000
2023	Variable	December 1, 2023		69,800			69,800
2025	Variable	December 1, 2025		75,000			75,000
2026	Variable	December 1, 2026		50,000			50,000
2027	Variable	March 1, 2027		25,760			25,760
2027	Variable	July 1, 2027		93,200			93,200
2029	Variable	July 1, 2029		115,705			115,705
Notes Payable: ⁽¹⁾
NM Holdings Note	3.720	July 31, 2009		350,000			350,000
NM Holdings Note	3.830	June 30, 2010		350,000			350,000
NM Holdings Note	5.800	November 1, 2012		500,000			500,000
Unamortized discounts				(871	)		(1,131	)

Total long-term debt				2,649,194			2,923,934

Long-term debt due within one year				200,000			275,000

Total long-term debt, excluding current portion			$	2,449,194		$	2,648,934


(1)		Currently callable with make-whole provision

(2)		Fixed rate pollution control revenue bonds first callable November 1, 2008 at 102%

Substantially all of the Company’s operating properties are subject to mortgage liens securing its mortgage debt. Several series of First Mortgage Bonds were issued to secure a like amount of tax-exempt revenue bonds issued by the New York State Energy Research and Development Authority (NYSERDA). Approximately $575 million of such securities bear interest at short-term adjustable interest rates (with an option to convert to other rates, including a fixed interest rate) which averaged 3.41% for the year ended March 31, 2007, 3.20% for the year ended March 31, 2006 and 1.69% for the year ended March 31, 2005. The bonds are currently in the auction rate mode and are backed by bond insurance. Pursuant to agreements between NYSERDA and the Company, proceeds from such issues were used for the purpose of financing the construction of certain pollution control facilities at the Company’s generation facilities (which the Company subsequently sold) or to refund outstanding tax-exempt bonds and notes.

The aggregate maturities of long-term debt for the five years subsequent to March 31, 2007, excluding capital leases, are approximately:


(In thousands of dollars)
Fiscal Years Ended
March 31,	Amount

2008	$	200,000
2009		600,000
2010		350,000
2011		350,000
2012		—
Thereafter		1,150,065

Total	$	2,650,065

The current portion of capital lease obligations is reflected in the other current liabilities line item on the Consolidated Balance Sheet and was approximately $0.6 million at March 31, 2007 and 2006. The non-current portion of capital lease obligations is reflected in the “Other” line item on the Consolidated Balance Sheet and was approximately $3.4 million and $4 million at March 31, 2007 and 2006, respectively.

At March 31, 2007 and 2006, the Company’s long-term debt, excluding intercompany debt, had a fair value of approximately $1.5 billion and $1.8 billion, respectively. The fair market value of the Company’s long-term debt was estimated based on the debts’ coupons and remaining lives along with the current interest rate conditions.

NOTE F – SHORT-TERM DEBT

The Company has regulatory approval from the FERC to issue up to $1 billion of short-term debt. The Company had short-term debt outstanding of $395 million and $579 million at March 31, 2007 and 2006, respectively, from affiliated companies. The Company participates with National Grid, and certain other National Grid affiliates, in a system money pool. The money pool is administered by the National Grid USA Service Company as the agent for the participants. Short-term borrowing needs are met first by available funds of the money pool participants. Borrowings from the money pool bear interest at the higher of (i) the monthly average of the rate for high-grade, 30-day commercial paper sold through dealers by major corporations as published in The Wall Street Journal, or (ii) the monthly average of the rate then available to money pool depositors from an eligible investment in readily marketable money market funds or the existing short-term investment accounts maintained by money pool depositors or the National Grid USA Service Company during the period in question. In the event neither rate is one that is permissible for a transaction because of constraints imposed by the state regulatory commission having jurisdiction over a utility participating in the transaction, the rate is that which is permissible for the transaction as determined under the requirements of the state regulatory commission. Companies that invest in the money 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 money pool at any time without prior notice. The average interest rate for the money pool was 5.23%, 4.03% and 1.80% for fiscal years 2007, 2006 and 2005, respectively.

The Company had no short-term debt outstanding to third-parties at March 31, 2007 or 2006.

NOTE G – INCOME TAXES

The Company has joint and several liability for any potential assessments against the consolidated group.

Following is a summary of the components of federal and state income tax and reconciliation between the amount of federal income tax expense reported in the Consolidated Statements of Operations and the computed amount at the statutory tax rate:


	Year Ended March 31,
(In thousands of dollars)	2007			2006			2005

Components of federal and state income taxes:
Current tax expense (benefit):
Federal	$	(38,207	)	$	61,211		$	(30,229	)
State		4,704			22,509			9,459

		(33,503	)		83,720			(20,770	)


Deferred tax expense:
Federal		131,607			89,908			177,180
State		16,236			13,566			3,542

		147,843			103,474			180,722

Total	$	114,340		$	187,194		$	159,952


Total income taxes in the consolidated statements of operations:

Income taxes charged to operations	$	120,943		$	190,194		$	171,230
Income taxes credited to “Other income (deductions)”		(6,603	)		(3,000	)		(11,278	)

Total	$	114,340		$	187,194		$	159,952

Reconciliation between federal income taxes and the tax computed at prevailing U.S. statutory rate on income before income taxes:


	Year Ended March 31,
(In thousands of dollars)	2007			2006			2005

Computed tax	$	106,371		$	176,495		$	148,371

Increase (reduction) including those attributable to flow-through of certain tax adjustments:
Depreciation		13,599			10,225			16,982
Cost of removal		(6,861	)		(7,298	)		(5,664	)
Allowance for funds used during construction		—			—			(1	)
State income taxes		13,611			23,449			8,451
Accrual to return adjustment		(2,988	)		(9,410	)		3,427
Debt premium and mortgage recording tax		(33	)		3,298			487
E.S.O.P. dividends		—			—			(1,307	)
Dividends exclusion – federal income tax returns		(148	)		(148	)		(174	)
Provided at other than statutory rate		—			—			(1	)
Medicare Act		(9,613	)		(7,489	)		(3,579	)
Deferred investment tax credit reversal		(2,866	)		(2,866	)		(2,866	)
Audit interest expense		3,782			—			—
Other		(514	)		938			(4,174	)

Total		7,969			10,699			11,581

Federal and state income taxes	$	114,340		$	187,194		$	159,952

The following table identifies the major components of total deferred income taxes:


	As at March 31,
(In thousands of dollars)	2007			2006

Alternative minimum tax	$	—		$	117,618
Unbilled revenues		29,371			26,205
Liability for environmental costs		185,897			191,307
Voluntary early retirement program		—			42,089
Bad debts		53,904			52,498
Pension and other post-retirement benefits		493,348			248,446
Other		334,137			268,092

Total deferred tax assets		1,096,657			946,255


Depreciation related		(1,025,634	)		(979,936	)
Investment tax credit related		(34,945	)		(37,811	)
Deferred environmental restoration costs		(185,897	)		(186,842	)
Merger rate plan stranded costs		(758,235	)		(795,184	)
Merger fair value pension and OPEB adjustment		(90,768	)		(109,478	)
Bond redemption and debt discount		(25,215	)		(30,009	)
Pension and other post-retirement benefits		(237,094	)		(50,832	)
Other		(325,142	)		(275,169	)

Total deferred tax liabilities		(2,682,930	)		(2,465,261	)

Net accumulated deferred income tax liability	$	(1,586,273	)	$	(1,519,006	)
Current portion (net deferred tax asset)		107,774			168,354

Net accumulated deferred income tax liability (non-current)	$	(1,694,047	)	$	(1,687,360	)

The Company has been audited and reported on by the Internal Revenue Service (IRS) through March 31, 2002. There were no valuation allowances for deferred tax assets at March 31, 2007 or 2006.

NOTE H – EMPLOYEE BENEFITS

Summary

The Company has a non-contributory defined benefit pension plan covering substantially all employees. The pension plan is a cash balance pension plan design and under that design, pay-based credits are applied based on service time, and interest credits are applied based on an average annual 30-year Treasury bond yield. In addition, a large number of employees hired by the Company prior to July 1998 are cash balance design participants who receive a larger benefit if so yielded under pre-cash balance conversion final average pay formula provisions. Employees hired by the Company following the August 1998 cash balance design conversion participate under cash balance design provisions only.

A supplemental nonqualified, non-contributory executive retirement program provides additional defined pension benefits for certain executives.

The Company provides post-retirement benefits other than pensions (PBOPs). PBOPs include health care and life insurance coverage to eligible retired employees. Eligibility is based on certain age and length of service requirements and in some cases retirees must contribute to the cost of their coverage.

~~Governed~~The ~~by the~~ PSC’s “Statement of Policy ~~Concerning the Accounting and Ratemaking Treatment for Pensions and Postretirement Benefits Other than Pensions” (SOP), the SOP~~ dictates the accounting policy for the plans and requires amortization of unrecognized prior service costs and unrecognized gains and losses over a 10-year period calculated on a vintage year basis.

~~Funding Policy~~49

Funding policy is determined largely by the Company’s settlement agreements with the PSC and what is recovered in rates. However, the contribution for any year will not be less than the minimum contribution required by federal law or greater than the maximum tax-deductible amount.

Funding Policy

Funding policy is determined largely by the Company’s settlement agreements with the PSC and what is recovered in rates. However, the contribution for any year will not be less than the minimum amounts that are required under the Pension Protection Act of 2006.

Plan Assets

The target asset allocations for the benefit plans are:

	Pension Benefits						Non-Union PBOPs						Union PBOPs
							Non-Union
	2006			2005			2006			2005			2006			2005
	Pension Benefits						PBOPs						Union PBOPs
U.S. equities		42	%		47	%		30	%		50	%		49	%		45	%
	2007			2006			2007			2006			2007			2006
Global equities (including U.S.)		6	%		7	%		—			—			—			—
U.S. equities		43	%		42	%		30	%		30	%		49	%		49	%
Non-U.S. equities		12	%		11	%		20	%		5	%		21	%		15	%
Global equities (including U.S.)		6	%		6	%		—			—			—			—
Fixed income		35	%		35	%		50	%		45	%		30	%		40	%
Non-U.S. equities		12	%		12	%		20	%		20	%		21	%		21	%
Private equity and property		5	%		—			—			—			—			—
Fixed income		36	%		35	%		50	%		50	%		30	%		30	%
Private equity		3	%		5	%		—			—			—			—
		100	%		100	%		100	%		100	%		100	%		100	%

The percentage of the fair value of total plan assets at March 31:

	Pension Benefits						Non-Union PBOPs						Union PBOPs
							Non-Union
	2006			2005			2006			2005			2006			2005
	Pension Benefits						PBOPs						Union PBOPs
U.S. equities		46	%		46	%		29	%		54	%		50	%		52	%
	2007			2006			2007			2006			2007			2006
Global equities (including U.S.)		8	%		8	%		—			—			—			—
U.S. equities		45	%		46	%		32	%		29	%		49	%		50	%
Non-U.S. equities		13	%		12	%		20	%		5	%		22	%		16	%
Global equities (including U.S.)		6	%		8	%		—			—			—			—
Fixed income		33	%		34	%		51	%		41	%		28	%		32	%
Non-U.S. equities		12	%		13	%		21	%		20	%		22	%		22	%
Private equity and property		—			—			—			—			—			—
Fixed income		35	%		33	%		47	%		51	%		29	%		28	%
Private equity		2	%		—			—			—			—			—
		100	%		100	%		100	%		100	%		100	%		100	%

The Company manages benefit plan investments to minimize the long-term cost of operating the Plans, with a reasonable level of risk. Risk tolerance is determined as a result of a periodic asset/liability study which analyzes plan liabilities and plan funded status and results in the determination of the allocation of assets across equity and fixed income securities. Equity investments are broadly diversified across U.S. and non-U.S. stocks, as well as across growth, value, and small and large capitalization stocks. Likewise, the fixed income portfolio is broadly diversified across the various fixed income market segments. Small investments are also held in private equity, with the objective of enhancing long-term returns while improving portfolio diversification. For the PBOP plan, since the earnings on a portion of the assets are taxable, those investments are managed to maximize after tax returns consistent with the broad asset class parameters established by the asset allocation study. Investment risk and return is reviewed by the investment committee on a quarterly basis.

The estimated rate of return for various passive asset classes is based both on analysis of historical rates of return and forward looking analysis of risk premiums and yields. Current market conditions, such as inflation and interest rates, are evaluated in connection with the setting of the long-term assumption. A small premium is added for active management and rebalancing of both equity and fixed income. The rates of return for each asset class are then weighted in accordance with the target asset allocation, and the resulting long-term return on asset rate is then applied to the market-related value of assets.

4750

Assumptions ~~used~~Used for Benefits Accounting

The following weighted average assumptions were used to determine the pension and PBOP benefit obligations and net periodic costs for the fiscal years ~~ending~~ended March 31.:

	Pension Benefits						~~PBOP~~
	2006			2005			2006			2005
	Benefit obligation						Net periodic benefit cost
Benefit obligations
	2007			2006			2007			2006			2005
Discount rate		6.00	%		56.7500	%		6.00	%		5.75	%		5.75	%
Rate of compensation increase		3.90	%		3.90	%		~~n/a~~3.90	%		~~n/a~~3.90	%		3.25	%
Expected long-term rate of return		8.00	%		8.25	%		7.81	%		8.21	%
Expected long-term rate of return on assets		8.00	%		8.00	%		8.00	%		8.25	%		8.50	%
Health care cost trend rate
Initial		n/a			n/a			n/a			10.00	%
Pre 65*		n/a			n/a			10.00	%		n/a
Post 65*		n/a			n/a			11.00	%		n/a
Ultimate		n/a			n/a			5.00	%		5.00	%
Year ultimate rate is reached		n/a			n/a			n/a			2010
Pre 65*		n/a			n/a			2011			n/a
Post 65*		n/a			n/a			2012			n/a

* In fiscal year 2006, the health care cost trend assumption was updated to include rates for the pre 65 and post 65 age groups.


	PBOP
	Benefit obligation						Net periodic benefit cost
	2007			2006			2007			2006			2005

Discount rate		6.00	%		6.00	%		6.00	%		5.75	%		5.75	%
Expected long-term rate of return on assets		7.81	%		7.81	%		7.81	%		8.16	%		8.26	%
Health care cost trend rate
Initial		n/a			n/a			n/a			10.00	%		10.00	%
Pre 65*		9.50	%		10.00	%		10.00	%		n/a			n/a
Post 65*		10.50	%		11.00	%		11.00	%		n/a			n/a
Ultimate		5.00	%		5.00	%		5.00	%		5.00	%		5.00	%
Year ultimate rate is reached		n/a			n/a			n/a			2010			2009
Pre 65*		2012			2011			2011			n/a			n/a
Post 65*		2013			2012			2012			n/a			n/a

	Pension Benefits									PBOP
	2006			2005			2004			2006			2005			2004
Net periodic benefit cost
Discount rate		5.75	%		5.75	%		6.25	%		5.75	%		5.75	%		6.25	%
Rate of compensation increase		3.90	%		3.25	%		3.25	%		n/a			n/a			n/a
Expected long-term rate of return		8.25	%		8.50	%		8.50	%		8.16	%		8.26	%		8.00	%
Health care cost trend rate
Initial		n/a			n/a			n/a			10.00	%		10.00	%		10.00	%
Ultimate		n/a			n/a			n/a			5.00	%		5.00	%		5.00	%
Year ultimate rate reached		n/a			n/a			n/a			2010			2009			2008


*		As of March 31, 2006, the health care cost trend assumption was updated to include rates for the pre 65 and post 65 age groups.

The expected contributions toby the Company’s to the pension and PBOP plans during fiscal year ~~2007 are~~2008 are approximately $75277 million and $~~81 million~~0, respectively.

~~For~~Adoption ~~the calculation~~ of ~~fiscal~~SFAS year 2007 pension and PBOP expense, the expected long-term rates of return on plan assets will be changed to 8% for the qualified pension plan, 7% for the nonunion PBOP plan, and 8% for the union PBOP planNo. 158

48The Company adopted SFAS No. 158 on March 31, 2007. This standard amends SFAS Nos. 87, 88, 106 and 132(R). SFAS No. 158 requires an employer with a defined benefit pension plan or post-retirement benefit plan other than pensions (PBOPs) to recognize an asset or liability on its balance sheet for the overfunded or underfunded status of the plan as defined by SFAS No. 158. The pension asset or liability is the difference between the fair value of the pension plan’s assets and the projected benefit obligation as of the year end. For PBOPs, the asset or liability is the difference between the fair value of the plan’s assets and the accumulated post-retirement benefit obligation as of year end. The Company has specific recovery of qualified pension and PBOP expense and has recognized a regulatory asset in lieu of taking a charge to AOCI.

The following table illustrates the effect on individual financial statement line items of applying this standard, relating to the Company’s pension and PBOP plans. The Company participates in these plans with its affiliate, National Grid USA Service Company.


	Before application of						After application
(In thousands of dollars)	SFAS No. 158			Adjustment			of SFAS No. 158

Intangible asset		33,431			(33,431	)		—
Regulatory asset		38,737			399,176			437,913
Deferred tax asset		225,871			83,610			309,481
Current liability		—			(480	)		(480	)
Non-current liability		(582,942	)		(460,536	)		(1,043,478	)
AOCI, net of tax		1,269			11,661			12,930
AOCI, pre tax		2,111			17,940			20,051

The Company recorded increases in its pension and PBOP liabilities of $102 million and $342 million, respectively, with the offsetting charge to regulatory assets and AOCI.

Pension Benefits

The Company’s net periodic benefit cost for the fiscal years ended March 31, ~~2006~~2007, ~~2005~~2006 and ~~2004 included~~2005 included the following components:

(in thousands of dollars)	2006			2005			2004
(In thousands of dollars)	2007			2006*			2005*
Service cost	$	3225,~~483~~781		$	2928,~~324~~662		$	2826,~~093~~219
Interest cost		7569,~~370~~096			71,~~014~~520			7467,~~863~~891
Expected return on plan assets		(6765,~~431~~139	)		(6763,~~787~~967	)		(7164,~~391~~789	)
Amortization of unrecognized prior service cost		3,~~454~~237			13,~~851~~277			1,~~160~~801
Amortization of unrecognized loss		3428,~~268~~592			2632,~~269~~510			1825,~~026~~109
Net periodic benefit costs before settlement / curtailments		78,144			60,671			50,751
Net periodic benefit costs before settlement		61,567			72,002			56,231
Special termination benefits		—			—			14,300
Settlement loss		25,451			—			185
Settlement and curtailment loss		—			185			21,798
Net periodic benefit cost	$	87,018		$	72,002		$	56,416
Net periodic benefit costs	$	78,144		$	60,856		$	86,849

* The ~~following~~Company ~~table~~participates ~~provides~~in athe ~~reconciliation~~plans ofwith ~~the~~its ~~plans’~~affiliate, ~~fair~~National ~~value~~Grid ofUSA ~~assets~~Service ~~for~~Company. ~~the~~For fiscal years ended March 31, 2006 and 2005, pension costs have been adjusted to exclude the expense of this affiliate.

(in thousands of dollars)	2006			2005
Fair value of plan assets at beginning of period	$	830,469		$	845,900
Actual return on plan assets		107,337			52,246
Company contributions		76,181			81,730
Benefits paid		(110,411	)		(148,350	)
Settlements		—			(1,057	)
Fair value of plan assets at end of period	$	903,576		$	830,469

The following table provides the changes in the Company’s pension plans’ benefit obligations, reconciliation of the benefit obligation, funded status and the amounts recognized in the balance sheet at March 31:

(in thousands of dollars)	2006			2005
Accumulated benefit obligation	$	1,218,180		$	1,265,181
Benefit obligation at beginning of period	$	1,379,059		$	1,298,548
Service cost		32,483			29,324
Interest cost		75,370			71,014
Actuarial (gain) loss		(35,141	)		98,380
Plan amendments		—			31,201
Benefits paid		(110,411	)		(148,350	)
Settlements		—			(1,058	)
Benefit obligation at end of period	$	1,341,360		$	1,379,059

(in thousands of dollars)	2006			2005
Funded status	$	(437,784	)	$	(548,590	)
Unrecognized actuarial loss		200,422			309,737
Unrecognized prior service cost		36,885			40,339
Net amount recognized on the balance sheet	$	(200,477	)	$	(198,514	)

The benefit obligation, assets and funded status of the pension plans cannot be presented separately for the Company as the Company participates in the plan with National Grid USA Service Company, an affiliate. The following table provides the pension plans’ accumulated benefit obligation, funded status and the amounts recognized in the National Grid USA consolidated balance sheet at March 31:

(in thousands of dollars)	2006			2005
(In thousands of dollars)	2007			2006
Amounts recognized on the balance sheet consist of:
Accumulated benefit obligation	$	(1,128,177	)	$	(1,218,180	)
Employee pension liability	$	(314,604	)	$	(434,712	)
Reconciliation of benefit obligation:
Intangible asset		36,885			40,339
Benefit obligation at beginning of period	$	(1,341,360	)	$	(1,379,059	)
Regulatory assets		75,252			194,302
Service cost		(29,971	)		(32,483	)
Accumulated other comprehensive income, before taxes		1,990			1,557
Interest cost		(73,703	)		(75,370	)
Net amount recognized	$	(200,477	)	$	(198,514	)
Actuarial gain (loss)		(21,838	)		35,141
Benefits paid		59,534			110,411
Settlements		165,928			—
Benefit obligation at end of period		(1,241,410	)		(1,341,360	)
Fair value of plan assets at beginning of period		903,576			830,469
Actual return on plan assets		81,630			107,337
Company contributions		204,060			76,181
Benefits paid		(59,534	)		(110,411	)
Settlements		(165,928	)		—
Fair value of plan assets at end of period		963,804			903,576
Funded status		(277,606	)		(437,784	)
Unrecognized actuarial loss		n/a			200,422
Unrecognized prior service cost		n/a			36,885
Net amount accrued liability	$	(277,606	)	$	(200,477	)
(In thousands of dollars)	2007			2006
Amounts recognized in the National Grid USA consolidated balance sheet consist of:
Intangible asset	$	—		$	36,885
Regulatory assets		173,739			75,252
Current pension liability		(480	)		—
Employee pension liability		(277,126	)		(314,604	)
Accumulated other comprehensive income, before taxes		13,773			1,990
Net amount recognized	$	(90,094	)	$	(200,477	)
(In thousands of dollars)	2007
Amounts recognized in the Company’s balance sheet consist of:
Regulatory assets	$	173,739
Current pension liability		(480	)
Prepaid pension		(240,046	)
Accumulated other comprehensive income, before taxes		2,110
Net amount recognized in the balance sheet	$	(64,677	)

~~The following pension benefit payments, which reflect expected future services, as appropriate,~~53 ~~are expected to be paid from the Company’s pension plans:~~

(in millions of dollars)	Pension Benefits
2007		$	108
2008		$	110
2009		$	111
2010		$	115
2011		$	120
2012-2016		$	639

Additional Minimum Pension Liability

The Company has recorded an additional minimum pension liability of approximately $114 million and $236 million at March 31, 2006 and 2005, respectively, for its pension plans because the pension plans’ accumulated benefit obligation was in excess of the accrued pension liability on the balance sheet. While the offset to this entry would normally be an after-tax charge to other comprehensive income, due to the nature of its rate plan, the Company has instead recorded a pre-tax regulatory asset.

Defined contribution plan

The Company also has a defined contribution pension plan (employee savings fund plan) that covers substantially all employees. Employer matching contributions of approximately $7 million were expensed for the each of the fiscal years ended March 31, 2006, 2005 and 2004.

Postretirement Benefit Plans Other than Pensions: The Company’s total cost of PBOPs for the fiscal years ended March 31, 2006, 2005 and 2004 included the following components:


(In thousands of dollars)	2007

Amounts recognized in regulatory assets and AOCI consist of:
Net actuarial loss	$	144,522
Prior service cost		31,327

Net amount recognized	$	175,849

(in thousands of dollars)	2006			2005			2004
Service cost	$	18,887		$	13,160		$	8,629
Interest cost		70,519			62,887			57,952
Expected return on plan assets		(45,819	)		(45,798	)		(34,578	)
Amortization of unrecognized prior service cost		14,568			5,915			—
Amortization of unrecognized net loss		30,516			24,310			22,996
Special termination benefits		—			—			641
Net periodic benefit costs	$	88,671		$	60,474		$	55,640

The estimated net actuarial loss and prior service cost for the defined benefit pension plans that will be amortized from regulatory assets and AOCI into net periodic benefit cost during fiscal year 2008 is estimated to be $29 million and $3 million, respectively.

The following ~~table~~payments, ~~provides~~which areflect ~~reconciliation~~expected offuture ~~the~~services, ~~PBOP~~as ~~plans’~~appropriate, are ~~fair~~expected ~~value~~to ofbe ~~assets~~paid ~~for~~from the ~~fiscal~~ ~~years~~pension ~~ended March 31, 2006 and 2005.~~plans:

(in thousands of dollars)	2006			2005
(In thousands of dollars)	Pension Benefits
Fair value of plan assets at beginning of period	$	589,917		$	589,478
2008	$	105,480
Actual return on plan assets during year		69,721			31,836
2009	$	105,658
Company contributions		19,700			27,600
2010	$	108,887
Benefits paid from plan assets		(62,708	)		(58,997	)
2011	$	111,336
Fair value of plan assets at end of period	$	616,630		$	589,917
2012	$	115,700
2013-2017	$	543,431

~~The~~Additional ~~following~~Minimum ~~tables~~Liability ~~provide the reconciliation of the benefit obligation and the funded status~~(AML) ~~of the PBOP plans at March 31:~~

(in thousands of dollars)	2006			2005
Benefit obligation at beginning of period	$	1,268,233		$	1,059,003
Service cost		18,887			13,160
Interest cost		70,519			62,887
Actuarial loss		33,745			39,897
Plan amendments		—			152,967
Benefits paid		(65,651	)		(59,681	)
Benefit obligation at end of period	$	1,325,733		$	1,268,233

Under SFAS No. 158, the Company recognized AML, as prescribed under SFAS No. 87, “Employers’ Accounting for Pensions,” prior to recording the entries to recognize the funded status of the pension plans. The Company recognized an AML of $74 million which was subsequently eliminated under SFAS No. 158. The Company recorded an AML of approximately $114 million at March 31, 2006. While the offset to this entry would normally be an after-tax charge to other comprehensive income, due to the nature of its rate plan, the Company recorded a pre-tax regulatory asset.

(in thousands of dollars)	2006			2005
Funded status	$	(709,103	)	$	(678,317	)
Unrecognized prior service cost		132,484			147,052
Unrecognized actuarial loss		247,986			268,659
Net amount recognized	$	(328,633	)	$	(262,606	)

Defined Contribution Plan

51The Company also has a defined contribution pension plan (employee savings fund plan) that covers substantially all employees. Employer matching contributions of approximately $7 million were expensed for each of the fiscal years ended March 31, 2007, 2006 and 2005.

Settlement Loss

The Company’s pension plan has unrecognized losses as a result of changes in the value of the projected benefit obligation and the plan assets due to experience different from that assumed and from changes in actuarial assumptions. Under SFAS No. 88 “Employers’ Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits,” the Company recognized a settlement loss of approximately $25 million during the fiscal year ended March 31, 2007 due to plan payouts that exceeded the threshold as prescribed in SFAS No. 88. The Company and the PSC staff reached agreement that permits the Company to recover approximately 50% of the incurred pension settlement loss.

Postretirement Benefit Plans Other than Pensions: The Company’s total cost of PBOPs for the fiscal years ended March 31, 2007, 2006 and 2005 included the following components:


(In thousands of dollars)	2007			2006*			2005*

Service cost	$	15,851		$	16,979		$	11,433
Interest cost		73,934			68,921			61,205
Expected return on plan assets		(45,100	)		(45,343	)		(45,306	)
Amortization of unrecognized prior service cost		14,587			14,587			5,934
Amortization of unrecognized net loss		28,711			29,655			23,562

Net periodic benefit cost	$	87,983		$	84,799		$	56,828

*The Company participates in the plans with its affiliate, National Grid USA Service Company. For fiscal years ended March 31, 2006 and 2005, PBOP costs have been adjusted to exclude the expense of this affiliate.

AsThe abenefit ~~result~~obligation, ofassets ~~the~~and ~~Medicare~~funded ~~Act~~status of ~~2003,~~ the ~~Company~~PBOP ~~receives~~plan acannot ~~federal~~be ~~subsidy~~presented separately for ~~sponsoring~~the ~~a retiree~~Company ~~healthcare~~as ~~plan~~the ~~that~~Company ~~provides~~participates ain ~~benefit~~the ~~that~~plan iswith ~~actuarially~~its ~~equivalent~~affiliate, toNational ~~Medicare~~Grid ~~Part~~USA D.Service Company. The following ~~PBOP~~table ~~benefit~~provides ~~payments~~the ~~and~~PBOP ~~subsidies,~~plans’ ~~which~~funded ~~reflect~~status ~~expected~~and ~~future~~the ~~service,~~amounts asrecognized in the ~~appropriate,~~National ~~are~~Grid ~~expected~~USA toconsolidated bebalance ~~paid~~sheet ~~and~~at ~~received~~March 31:

(in millions of dollars)	Payments			Subsidies
(In thousands of dollars)	2007			2006
2007	$	68		$	4
Benefit obligation at beginning of period	$	(1,325,733	)	$	(1,268,233	)
2008	$	71		$	4
Service cost		(17,772	)		(18,887	)
2009	$	74		$	5
Interest cost		(76,057	)		(70,519	)
2010	$	77		$	5
Actuarial loss		(24,213	)		(33,745	)
2011	$	80		$	5
Medicare Part D subsidy received		(3,414	)		—
2012-2016	$	392		$	28
Benefits paid		76,240			65,651
Benefit obligation at end of period		(1,370,949	)		(1,325,733	)
Fair value of plan assets at beginning of period		616,630			589,917
Actual return on plan assets during year		58,196			69,721
Company contributions		—			19,700
Benefits paid		(70,229	)		(62,708	)
Fair value of plan assets at end of period		604,597			616,630
Funded status		(766,352	)		(709,103	)
Unrecognized prior service cost		n/a			132,484
Unrecognized actuarial loss		n/a			247,986
Net amount recognized	$	(766,352	)	$	(328,633	)
(In thousands of dollars)	2007				2006
Amounts recognized in the National Grid USA consolidated balance sheet consist of:
Regulatory asset	$	264,174		$	—
PBOP liability		(766,352	)		(328,633	)
Accumulated other comprehensive income, before tax		6,278			—
Net amount recognized	$	(495,900	)	$	(328,633	)
(In thousands of dollars)	2007
Amounts recognized on the Company’s balance sheet consist of:
Regulatory asset	$	264,174
PBOP liability		(750,196	)
Net amount recognized	$	(486,022	)
(In thousands of dollars)	2007
Amounts recognized in regulatory assets and AOCI consist of:
Net actuarial loss	$	229,867
Prior service cost		117,916
Net amount recognized	$	347,783

The estimated net actuarial loss and prior service cost for the PBOP plans that will be amortized from regulatory assets and AOCI into net periodic benefit cost during fiscal year 2008 is estimated to be $34 million and $15 million, respectively. A portion of this amount will be recorded as expense of National Grid USA Service Company.

As a result of the Medicare Act of 2003, the Company receives a federal subsidy for sponsoring a retiree healthcare plan that provides a benefit that is actuarially equivalent to Medicare Part D.

The following PBOP benefit payments expected to be paid out by the Company and subsidies expected to be received from the U.S. Federal Government, which reflect expected future services, as appropriate, are:


(In thousands of dollars)	Payments		Subsidies

2008	$	69,000	$	4,130
2009	$	76,647	$	4,530
2010	$	80,456	$	4,920
2011	$	84,250	$	5,200
2012	$	86,956	$	5,420
2013-2017	$	466,392	$	28,680

A one-percentage point change in assumed health care cost trend rates would have the following effects:

(in thousands of dollars)	2006			2005
(In thousands of dollars)	2007
Increase 1%
Total of service cost plus interest cost	$	1718,~~330~~681		$	~~13,985~~
Post-retirement benefit obligation	$	~~215~~219,~~617~~230		$	~~196,034~~
Decrease 1%
Total of service cost plus interest cost	$	(1415,~~329~~247	)	$	~~(11,629~~	)
Post-retirement benefit obligation	$	(~~185~~188,~~317~~902	)	$	~~(169,719~~	)

~~Settlement Losses~~56

Under SFAS No. 88 “Employers’ Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits,” the Company must recognize a portion of unrecognized gains or losses immediately when payouts from the plans exceed a certain amount. The Company recognized a loss of approximately $22 million in fiscal 2004 relating to the re-measurement of the benefit plans from the voluntary early retirement offer.

In July 2004, the Company obtained PSC approval that would provide rate recovery for approximately $14 million of the $30 million pension settlement loss incurred in fiscal 2003. In addition, the agreement covers the funding of the entire settlement loss to benefit plan trust funds. The Company has filed a petition with the PSC seeking recovery of a $22 million pension settlement loss incurred in fiscal year 2004.

Regulatory treatment of pensions and PBOP plans

In addition to the regulatory assets established in connection with purchase accounting and the additional minimum pension liability discussed above, the regulatory asset account “Pension and post-retirement benefit plans” includes certain other components. First, the Company is required under the Merger Rate Plan to defer the difference between pension and post-retirement benefit expense and the allowance in rates for these costs. Also, the regulatory asset account includes the unamortized portion of the merger related early retirement program costs, a post-retirement benefit phase-in deferral established in the mid-1990’s, and the offset to the additional minimum pension liability discussed above. The merger related early retirement program costs are being amortized unevenly over the 10 years of the Merger Rate Plan with larger amounts being amortized in the earlier years. This amortization in fiscal 2006 and 2005 was approximately $4

~~million~~NOTE ~~and~~I ~~$7 million,~~– ~~respectively.~~PREFERRED ~~The phase-in deferral is being amortized at a rate of~~STOCK ~~approximately $3 million per year.~~

NOTE I — PREFERRED STOCK

The Company has certain issues of non-participating preferred stock which provide for redemption at the option of the Company, as shown in the table below. From time to time, the Company repurchases shares of its preferred stock when it is approached on behalf of its shareholders.

									Redemption price
									Redemption
	Shares				(inIn thousands of dollars)				price per share
	March 31,		March 31,		March 31,		March 31,		(Before adding
Series	~~2006~~2007		~~2005~~2006		~~2006~~2007		~~2005~~2006		accumulated dividends)
Preferred $100 par value:
3.40%		57,536		57,536	$	5,754	$	5,754	$	103.50
3.60%		137,139		137,139		13,714		13,714		104.85
3.90%		94,967		94,967		9,496		9,496		106.00
4.10%		52,830		52,830		5,283		5,283		102.00
4.85%		35,128		35,128		3,513		3,513		102.00
5.25%		34,115		34,115		3,410		3,410		102.00
Total preferred stock		411,715		411,715	$	41,170	$	41,170

53NOTE J – SEGMENTS

NOTE J — SEGMENTS

Segmental information is presented in accordance with management responsibilities and the economic characteristics of the Company’s business activities. The Company is primarily engaged in the business of the purchase, transmission and distribution of electricity and the purchase, distribution, sale and transportation of natural gas in New York State. The Company’s reportable segments are electricity-transmission, electricity-distribution, and gas-distribution. Certain information regarding the Company’s segments is set forth in the following tables. Corporate assets consist primarily of other property and investments, cash, restricted cash, current deferred income taxes and unamortized debt expense. General corporate expenses, property common to the various segments, and depreciation of such common property have been allocated to the segments based on labor or plant, using a percentage derived from total labor or plant amounts charged directly to certain operating expense accounts or certain plant accounts.

			Electricity-Distribution
					Electricity -		Total
	Electricity -		Electricity –		Stranded Cost		Electricity-		Gas –
(in millions of dollars)	Transmission		Distribution		Recoveries		Distribution		Distribution		Corporate		Total
Year ended March 31, 2006
Operating revenue	$	261	$	2,550	$	496	$	3,046	$	1,037	$	—	$	4,344
Operating income before income taxes		105		346		184		530		105		—		740
Depreciation and amortization		35		131		—		131		38		—		204
Amortization of stranded costs		—		—		267		267		—		—		267
Year ended March 31, 2005
Operating revenue	$	255	$	2,376	$	486	$	2,862	$	808	$	—	$	3,925
Operating income before income taxes		105		286		176		462		105		—		672
Depreciation and amortization		35		129		—		129		37		—		201
Amortization of stranded costs		—		—		251		251		—		—		251
Year ended March 31, 2004
Operating revenue	$	255	$	2,457	$	572	$	3,029	$	780	$	—	$	4,064
Operating income before income taxes		93		234		183		417		68		—		578
Depreciation and amortization		35		130		—		130		36		—		201
Amortization of stranded costs		—		—		194		194		—		—		194

			Electricity-Distribution
						Electricity -		Total
	Electricity -		Electricity –			Stranded Cost		Electricity -			Gas –
	Transmission		Distribution			Recoveries		Distribution			Distribution		Corporate		Total
Goodwill
Goodwill, at March 31, 2005	$	303	$	706		$	—	$	706		$	215	$	—	$	1,224
Change in goodwill		—		(9	)		—		(9	)		—		—		(9	)
Goodwill, at March 31, 2006	$	303	$	697		$	—	$	697		$	215	$	—	$	1,215
Total Assets
At March 31, 2006	$	1,595	$	5,302		$	3,051	$	8,353		$	1,931	$	402	$	12,281
At March 31, 2005	$	1,557	$	5,193		$	3,402	$	8,595		$	1,819	$	547	$	12,518

NOTE K — STOCK BASED COMPENSATION


	Electric-Distribution
			Stranded
			Cost				Gas –		Electric –		Total
(In thousands of dollars)	Distribution		Recoveries		Total		Distribution		Transmission		Segments

Year ended March 31, 2007
Operating revenue	$	2,765,220	$	235,512	$	3,000,732	$	875,034	$	255,889	$	4,131,655
Operating income before income taxes		213,161		136,188		349,349		93,334		86,279		528,962
Depreciation and amortization		133,874		166		134,040		39,932		35,580		209,552
Amortization of stranded costs and rate plan deferrals		136,647		274,218		410,865		—		6,055		416,920

Year ended March 31, 2006
Operating revenue	$	2,549,445	$	496,105	$	3,045,550	$	1,037,403	$	261,070	$	4,344,023
Operating income before income taxes		345,828		184,116		529,944		104,700		105,226		739,870
Depreciation and amortization		131,001		217		131,218		38,238		34,538		203,994
Amortization of stranded costs and rate plan deferrals		—		266,816		266,816		—		—		266,816

Year ended March 31, 2005
Operating revenue	$	2,375,942	$	485,744	$	2,861,686	$	808,324	$	255,161	$	3,925,171
Operating income before income taxes		285,959		175,609		461,568		105,254		105,102		671,924
Depreciation and amortization		128,571		147		128,718		37,476		34,599		200,793
Amortization of stranded costs and rate plan deferrals		—		251,499		251,499		—		—		251,499

Prior to the Company’s merger with National Grid, stock appreciation rights (SARs) tied to the price of Holdings’ share price were granted to officers, key employees and directors. The table below sets forth the activity under the SARs program for the periods March 31, 2004 through March 31, 2006. Since SARs are payable in cash, the accounting under APB No. 25 and SFAS No. 123R is the same.


	Electricity-Distribution
			Stranded
			Cost				Gas -		Electricity –
(In thousands of dollars)	Distribution		Recoveries		Total		Distribution		Transmission		Corporate		Total

Goodwill
At March 31, 2007	$	713,397	$	—	$	713,397	$	219,468	$	309,596	$	—	$	1,242,461
Change in goodwill		16,118		—		16,118		4,880		6,887		—		27,885

At March 31, 2006	$	697,279	$	—	$	697,279	$	214,588	$	302,709	$	—	$	1,214,576


Total Assets
At March 31, 2007	$	6,167,150	$	2,371,781	$	8,538,931	$	1,960,316	$	1,637,755	$	29,753	$	12,166,755
At March 31, 2006	$	5,315,847	$	3,051,430	$	8,367,277	$	1,930,459	$	1,594,863	$	402,216	$	12,294,815

	SARs
	Shares
Outstanding at March 31, 2004		341,268
Exercised		(93,146	)
Outstanding at March 31, 2005		248,122
Exercised		(87,680	)
Outstanding at March 31, 2006		160,442

TheTable Company’s SARs program provided for the acceleration of vesting upon the occurrence of certain events relating to a change in control, merger, sale of assets or liquidation of the Company. On January 31, 2002, the acquisition of Holdings’ by National Grid was completed and outstanding Holdings’ SARs were converted to National Grid Group plc American Depositary Share (ADS) SARs. The SARs are payable in cash based on the increase in the ADS price from a specified level. As such, for these awards, compensation expense is recognized based on the value of the ADS price of National Grid Group plc over the vesting period of the award. Contents

~~Included~~NOTE inK ~~the~~– ~~Company’s~~STOCK ~~results~~BASED ~~of operations for years ended March 31, 2006 and 2005, is~~COMPENSATION ~~approximately $1 million of expense for each year related to the SARs program.~~

~~NOTE~~Prior Lto the Company’s merger with National Grid, stock appreciation rights (SARs) tied to the —price ~~DERIVATIVES~~of ~~AND~~Holdings’ ~~HEDGING~~share ~~ACTIVITIES~~price were granted to officers, key employees and directors. The table below sets forth the activity under the SARs program for the periods March 31, 2005 through March 31, 2007. Since SARs are payable in cash, the accounting under APB No. 25 and SFAS No. 123R is the same.


	SARs Shares

Outstanding at March 31, 2005		248,122
Exercised		(87,680	)
Outstanding at March 31, 2006		160,442
Exercised		(23,518	)

Outstanding at March 31, 2007		136,924

The Company’s SARs program provided for the acceleration of vesting upon the occurrence of certain events relating to a change in control, merger, sale of assets, or liquidation of the Company. On January 31, 2002, the acquisition of Holdings’ by National Grid was completed and outstanding Holdings’ SARs were converted to National Grid Group plc American Depositary Share (ADS) SARs. The SARs are payable in cash based on the increase in the ADS price from a specified level. As such, for these awards, compensation expense is recognized based on the value of the ADS price of National Grid Group plc over the vesting period of the award.

Included in the Company’s results of operations for years ended March 31, 2007 and 2006, is approximately $1 million of expense for each year related to the SARs program.

NOTE L – DERIVATIVES AND HEDGING ACTIVITIES

In the normal course of business, the Company is party to derivative financial instruments (derivatives) that are principally used to manage commodity prices associated with its natural gas and electric operations. These financial exposures are monitored and managed as an integral part of the Company’s overall Financial Risk Management Policy. At the core of the policy is a condition that the Company will engage in activities at risk only to the extent that those activities fall within commodities and financial markets to which it has a physical market exposure in terms and volumes consistent with its core business. The Company does not issue or intend to hold derivative instruments for speculative trading purposes. Derivatives are accounted for in accordance with SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” which requires derivatives to be reported at fair value as assets or liabilities on the balance sheet. The change in fair value of instruments that qualify for hedge accounting are deferred in Accumulated Other Comprehensive Income and will be reclassified through purchased electricity or purchased gas expense within the next twelve months. Other instruments are deferred in regulatory assets or liabilities according to current rate agreements and are reclassified through purchased electricity or gas expense in the hedge months. The Company’s rate agreements allow for the pass-through of the commodity costs of electricity and natural gas, including the costs of the hedging programs.

The Company has eight indexed swap contracts, expiring in fiscal year 2009 (June 2008), ~~that~~which resulted from the MRA. These derivatives are not designated as hedging instruments and are covered by regulatory rulings that allow the gains and losses to be recorded as regulatory assets or regulatory liabilities. As of March 31, 2007 and 2006, the Company had recorded liabilities at net present value of $268 million and $537 million, respectively, for these swap contracts and had recorded a corresponding swap contracts regulatory asset. The asset and liability are amortized over the remaining term of the

5559

covered by regulatory rulings that allow the gains and losses to be recorded as regulatory assets or regulatory liabilities. As of March 31, 2006 and 2005, the Company had recorded liabilities at net present value of $537 million and $619 million, respectively, for these swap contracts and had recorded a corresponding swap contracts regulatory asset. The asset and liability are amortized over the remaining term of the swaps as nominal energy quantities are settled and they are adjusted as periodic reassessments are made of energy price forecasts.

At March 31, ~~2006~~2007, the Company projects that it will make the following payments in connection with its swap contracts for the fiscal years ~~2007~~2008 ~~through~~and 2009, subject to changes in market prices and indexing provisions:

	Projected
Fiscal Years Ended	Projected
	Payment
March 31,	Payment
Year Ended	(in thousands
(In thousands of dollars)
March 31,	of dollars)
2008	$	221,540
2007	$	246,551
2009		46,500
2008		246,173
2009		44,729
Thereafter		—
Total	$	~~537~~268,~~453~~040

The Company uses New York Mercantile Exchange (NYMEX) gas futures to hedge the gas commodity component of its indexed swap contracts. These instruments, as used, do not qualify for hedge accounting status under SFAS No. 133. Cash flow hedges that qualify under SFAS No. 133 are as follows: NYMEX gas futures for the purchases of natural gas and NYMEX electric swap contracts hedging the purchases of electricity.

The following table represents the open positions ~~at March 31, 2006~~ and the results on operations of these instruments for the year ended March 31, 2006 and 2007.

(In thousands of dollars)				Balances as of March 31, 2006
	Balances as of March 31, 2006
												Year Ended
									Accumulated
						Accumulated			~~Accumulated~~Deferred			~~March~~Gain ~~31, 2006~~Reclass
						Accumulated			Deferred			Gain/(Loss)
Derivative Instrument				Regulatory		OCI,**			Income Tax			to Commodity
				Regulatory		OCI** ,			Income Tax			Reclass to
(In thousands of dollars)	Asset*			Deferral		net of tax			on OCI**			Costs
Derivative Instrument	Asset*			Deferral		net of tax			on OCI**			Commodity Costs
Qualified for Hedge Accounting
NYMEX futures — gas supply	$	(5,358.8	)	$	—	$	4,943.0		$	(3,296.0	)	$	35,956.6
NYMEX electric swaps — electric supply	$	317.5		$	—	$	(190.5	)	$	127.0		$	3,260.2
Non-Qualified for Hedge Accounting
NYMEX futures — IPP swaps/non-MRA IPP	$	(27,195.9	)	$	31,718.1	$	—		$	—		$	59,464.9


	Balances as of March 31, 2007
							Accumulated
					Accumulated		Deferred			Loss Reclass
Derivative Instrument			Regulatory		OCI,**		Income Tax			to Commodity
(In thousands of dollars)	Asset*		Deferral		net of tax		on OCI**			Costs

*Qualified for Hedge Accounting*
NYMEX futures — gas supply	$	2,533.7	$	—	$	214.9	$	(143.3	)	$	(36,722.9	)

NYMEX electric swaps — electric supply	$	783.9	$	—	$	30.1	$	(20.1	)	$	(4,644.7	)

*Non-Qualified for Hedge Accounting*
NYMEX futures — IPP swaps/non-MRA IPP	$	4,627.0	$	2,272.1	$	—	$	—		$	(101,132.4	)


*		Differences between asset and regulatory or other comprehensive income deferral represent contracts settled for the following month.

**		Other Comprehensive Income (OCI)

~~At March 31, 2005, the Company in part recorded a deferred gain on the futures contracts~~60 ~~hedging the IPP swaps and non-MRA IPP of $30 million, which partially offset the consolidated balance sheet item “Derivative instruments” for $27 million, with the resulting $3 million having~~

~~settled~~The ~~through~~gains ~~cash~~and ~~for~~losses on the ~~hedge~~derivatives ~~month~~that are deferred and reported in accumulated other comprehensive income will be reclassified as purchased energy expense in the periods in which expense is impacted by the variability of ~~April 2005~~the cash flows of the hedged item. For the twelve months ended March 31, ~~2005~~ 2007, ~~settlement~~the realized net loss of ~~NYMEX~~$37 million ~~futures~~from ~~contracts~~hedging ~~resulted~~instruments, as shown in the atable ~~decrease~~above, was recorded to ~~purchased~~gas ~~power~~purchases ~~expense~~and was offset by a corresponding increase in the cost of a comparable amount of gas. For the twelve months ended March 31, 2006, a realized net gain of $1936 million was recorded to gas purchases and was offset by a corresponding decrease in the cost of a comparable amount of gas.

The ~~gains~~actual ~~and~~amounts ~~losses~~to onbe ~~the~~recorded ~~derivatives that are deferred and reported~~ in ~~accumulated other comprehensive income will be reclassified as~~ purchased energy expense inare ~~the~~dependent ~~periods~~on infuture ~~which~~changes ~~expense~~in isthe ~~impacted~~contract byvalues. ~~the~~The ~~variability~~majority of ~~the~~these ~~cash~~deferred ~~flows~~amounts ofwill ~~the~~be ~~hedged~~reclassified ~~item.~~to ~~For~~expense within the next twelve months. ~~ended~~A ~~March 31,~~nominal ~~2006,~~amount ~~the realized net gain~~ of ~~$36 million~~the ~~from~~ hedging instruments, ~~as shown~~extend ininto ~~the table above, was recorded to gas purchases and was offset by a corresponding increase~~April 2008. inThere ~~the~~were ~~cost~~no ofgains aor ~~comparable~~losses ~~amount~~recorded ofduring ~~gas. For~~ the ~~twelve~~fiscal ~~months~~year ended March 31, ~~2005,~~2007 afrom ~~realized~~the ~~net~~discontinuance ~~gain~~ of ~~$8 million was recorded to~~ gas ~~purchases~~futures ~~and~~or ~~was~~electric ~~offset~~swap bycash aflow ~~corresponding decrease in the cost of a comparable amount of gas~~hedges.

The ~~actual~~deferred ~~amounts~~gain ~~to be recorded in purchased energy expense are dependent~~ on ~~future~~NYMEX ~~changes in~~electric ~~the~~swap ~~contract~~contracts ~~values. The majority of these deferred amounts will be reclassified~~ to ~~expense within~~hedge ~~the~~electricity ~~next~~purchases ~~twelve~~was ~~months~~$0. ~~A nominal amount of the hedging instruments extend into April~~8 ~~2007.~~million ~~There~~and ~~were~~$0.3 million nofor ~~gains or losses recorded during~~ the fiscal ~~year~~years ended March 31, ~~2006~~2007 ~~from~~and ~~the discontinuance~~2006, ~~of gas futures or electric swap cash flow hedges~~respectively.

AtNOTE ~~March 31,~~M ~~2006,~~– ~~the~~RESTRICTION ~~deferred~~ON ~~gain~~COMMON ~~on NYMEX electric swap contracts to hedge electricity~~DIVIDENDS ~~purchases was $0.3 million. There were no open electric swaps at March 31, 2005.~~

NOTE M — RESTRICTION ON COMMON DIVIDENDS

The indenture securing the Company’s mortgage debt provides that retained earnings shall be reserved and held unavailable for the payment of dividends on common stock to the extent that expenditures for maintenance and repairs plus provisions for depreciation do not exceed 2.25% of depreciable property as defined therein. These provisions have never resulted in a restriction of the Company’s retained earnings.

The Company is limited by the ~~Merger~~MRP ~~Rate Plan~~ and under FERC and SEC orders with respect to the amount of dividends it can make to Holdings. As long as the Company remains rated Investment Grade, it is allowed to make dividends in an amount up to the pre-merger retained earnings balance plus any earnings subsequent to the merger, together with other adjustments that are authorized under the MRP ~~Merger Rate Plan~~ and other regulatory orders.

NOTE N — – COST OF REMOVAL AND ASSET RETIREMENT OBLIGATION

In 2001, FASB issued SFAS No. 143. SFAS No. 143 provides accounting requirements for retirement obligations associated with tangible long-lived assets. The Company was required to adopt SFAS No. 143 and FIN 47 as of April 1, 2003. Retirement obligations associated with long-lived assets included within the scope of SFAS No. 143 are those for which there is a legal obligation under existing or enacted law, statute, written or oral contract, or by legal construction under the doctrine of promissory estoppel. In March 2005, the FASB issued FIN 47 that clarifies that the term “conditional asset retirement obligation” used in SFAS No. 143 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 Company. This statement is effective for the Company for its fiscal year ended March 31, 2006. The Company has an $11 million asset retirement obligation reserve as of March 31, 2007.

Under the Company’s current and prior rate plans it has collected through rates an implied cost of removal for its plant assets. This cost of removal collected from customers differs from the SFAS No. 143 and FIN 47 definition of an asset retirement obligation in that these collections are for costs to ~~remove an asset when it is no longer deemed usable (i.e. it is broken or obsolete) and not necessarily from a legal obligation. For a vast majority of its electric and gas transmission and~~

5761

remove an asset when it is no longer deemed usable (i.e. it is broken or obsolete) and not necessarily from a legal obligation. For a vast majority of its electric and gas transmission and distribution assets, the Company would use these funds to remove the asset so a new one could be installed in its place.

The cost of removal collections from customers has historically been embedded within accumulated depreciation (as these costs have been charged over time through depreciation expense). With the adoption of SFAS No. 143, the Company has reclassified these cost of removal collections to a regulatory liability account to more properly reflect the future usage of these collections. The Company estimates it has collected over time approximately $~~338~~350 million and $~~318~~338 million for cost of removal through March 31, ~~2006~~2007 and ~~2005~~2006, respectively.

InNOTE ~~March 2005,~~O ~~the~~– ~~FASB~~QUARTERLY ~~issued~~FINANCIAL ~~FIN~~DATA ~~47 that clarifies that the term ‘conditional asset retirement obligation’ used in SFAS No. 143 refers to a legal obligation to perform an asset retirement activity in which the timing and~~ (orUNAUDITED) ~~method of settlement are conditional on a future event that~~ may or may not be within the control of the Company. This statement is effective for the Company for its fiscal year ended March 31, 2006. The Company has a $10 million asset retirement obligation reserve as of March 31, 2006 which does not have a material impact on the Company’s results of operations or financial position.

~~NOTE~~Operating Orevenues, operating income, and net income by quarter from April 1, 2005 through March —31, ~~QUARTERLY~~2007 ~~FINANCIAL~~are ~~DATA~~shown ~~(UNAUDITED)~~in the following table. The Company believes it has included all adjustments necessary for a fair presentation of the results of operations for the quarters. Due to the seasonal nature of the regulated utility business, the annual amounts are not generated evenly by quarter during the year. The Company’s quarterly results of operations reflect the seasonal nature of its business, with peak electric loads in summer and winter periods. Gas sales peak in the winter. The Company’s consolidated financial statements for the fiscal year ended March 31, 2006 included out-of-period adjustments. The out-of-period adjustments had a positive impact of $7 million on reported net income for the fiscal year ended March 31, 2006 and an offsetting negative impact on several prior fiscal years. These adjustments were recorded in fiscal year 2006 because they did not meet the materiality threshold for prior period restatement.

Operating revenues, operating income, and net income by quarter from April 1, 2004 through March 31, 2006 are shown in the following table. The Company believes it has included all adjustments necessary for a fair presentation of the results of operations for the quarters. Due to the seasonal nature of the regulated utility business, the annual amounts are not generated evenly by quarter during the year. The Company’s quarterly results of operations reflect the seasonal nature of its business, with peak electric loads in summer and winter periods. Gas sales peak in the winter. The Company’s consolidated financial statements for the fiscal year ended March 31, 2006 included out-of-period adjustments. The out-of-period adjustments had a positive impact of $7 million on reported net income for the fiscal year ended March 31, 2006 and an offsetting negative impact on several prior fiscal years. The adjustments were recorded in fiscal year 2006 because they did not meet the materiality threshold for prior period restatement.


(In thousands of dollars)		Operating		Operating		Net
Quarters Ended		Revenues		Income		Income

March 31,	2007	$	1,233,137	$	95,963	$	41,107
	2006		1,292,625		179,746		120,172
December 31,	2006		1,003,469		92,220		37,277
	2005		1,111,485		119,502		63,304
September 30,	2006		979,866		135,574		82,224
	2005		981,081		131,043		76,251
June 30,	2006		915,183		84,262		28,969
	2005		958,832		119,385		57,349

		(In thousands of dollars)
		Operating		Operating		Net
Quarter Ended		Revenues		Income		Income
March 31,	2006	$	1,294,825	$	179,746	$	120,172
	2005		1,215,027		164,521		116,679
December 31,	2005		1,109,285		119,502		63,304
	2004		907,037		116,611		55,517
September 30,	2005		981,081		131,043		76,251
	2004		912,868		114,948		50,218
June 30,	2005		958,832		119,385		57,349
	2004		890,239		104,614		40,835

In the third fiscal quarter of 2007, the Company recorded a pension settlement loss of $25 million (See Note H-Employee Benefits) and in the fourth quarter, deferral account audit write off of $63 million (See Note B-Rate and Regulatory Issues).

58NOTE P – SUBSEQUENT EVENT

On April 26, 2007, the Board of Directors declared a cash dividend of $0.4 million payable to stockholders on June 30, 2007.


ITEM 9.		CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

There is no disagreement or reportable event required to be reported under this Item 9.

ITEM 9A. 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 are effective in ~~providing~~ providing reasonable assurance that the information required to be disclosed in reports that the ~~Company~~ Company files or submits under the Securities Exchange Act of 1934, as amended, is recorded, processed, summarized and reported as and when required and accumulated and communicated to the Company’s management, including the Chief Financial Officer and President, as appropriate, to allow timely decisions regarding disclosure.

During the most recent fiscal quarter, there were no changes in the Company’s internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, the internal control over financial reporting.

ITEM 9B. OTHER INFORMATION

None.

5963

PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OFAND ~~THE~~CORPORATE ~~REGISTRANT~~GOVERNANCE

The following table lists the Company’s executive officers and directors:

Name	Age		Position
William F. Edwards		4950	President and Director
John G. Cochrane		48	Chief Financial Officer
Colin Buck		57	Senior Vice President and Chief Financial Officer
Joseph T. Ash, Jr.		5758	Vice President, ~~Energy Supply, Pricing and~~ Regulatory Proceedings - NY
Paul J. Bailey		4849	Controller
Barbara A. Hassan		5657	Senior Vice President and Director
Michael E. Jesanis		49	President and Chief Executive Officer of National Grid USA and Director
Susan Crossett		46	Vice President and Director
Michael J. Kelleher		48	Senior Vice President, Business Services, and Director
Anthony C. Pini		54	Senior Vice President, and Director
Clement E. Nadeau		54	Senior Vice President, Operations, and Director
Cheryl A. LaFleur		52	President, and acting Chief Executive Officer of National Grid USA, and Director
Anthony C. Pini		53	Senior Vice President, Customer Service, and Director
Lawrence J. Reilly		51	Executive Vice President and General Counsel of National Grid USA
Cheryl A. LaFleur		51	Executive Vice President, Chief Operating Officer of National Grid USA, and Director
Masheed H. Saidi		52	Vice President
Lawrence J. Reilly		50	Executive Vice President and General Counsel of National Grid USA
Steven W. Tasker		49	Senior Vice President and Treasurer
Masheed H. Saidi		51	Vice President, and Senior Vice President, Transmission, National Grid USA Service Company, Inc.
Steven W. Tasker		48	Senior Vice President and Treasurer

Directors are elected at the annual meeting of stockholders and hold office until the next annual meeting or a special meeting in lieu thereof, and until their successors are elected and qualified. There are no family relationships between any of the directors and executive officers listed in the table. There are no arrangements or understandings between any executive officer and any other person pursuant to which he or she was selected as an officer.

Mr. Edwards was elected President of the Company and appointed a director effective January 31, 2002. ~~Prior to that, he served as Senior Vice President and Chief Financial Officer of the Company from 1997 to 2002.~~ He ~~served as Senior Vice President and Chief Financial Officer of Niagara Mohawk Holdings, Inc. from 1999 to 2002. He~~ also serves as an Executive Vice President of National Grid USA Service Company and is a director of the National Grid USA Service Company and of National Grid USA.

Mr. ~~Cochrane~~ Ash was ~~elected~~appointed ~~Chief~~Vice ~~Financial~~President, ~~Officer~~Regulatory ~~effective~~Proceedings ~~August 1~~in April 2006, ~~2002.~~Prior Heto ~~has~~that he served as ~~National~~ ~~Grid~~Vice ~~USA’s~~President, ~~Chief~~Energy ~~Financial~~Supply, Pricing ~~Officer~~and ~~since~~Regulatory ~~January 2001~~Proceedings ~~and~~from isJuly 2003 ~~its~~to ~~Treasurer,~~April an2006. ~~Executive Senior~~He was Vice President, ~~and~~Gas aDelivery, ~~director~~from December 1998 to July 2003.

Mr. ~~Ash~~Bailey was ~~has~~elected ~~served~~Controller asof ~~Vice~~the ~~President,~~Company ~~Energy~~effective ~~Supply,~~January 2006. ~~Pricing~~He ~~and~~also ~~Regulatory~~serves ~~Proceedings~~as ~~since~~Controller ~~July~~of National ~~2003~~Grid USA Service Company, Inc. HeMr. Bailey was Vice President, ~~Gas~~of ~~Delivery~~Finance and Administration of Harvard Bioscience, Inc. from ~~December~~October 2003 until September 2005, when he joined National Grid. From 1998 to ~~April~~ 2002, Mr. Bailey worked for Thermo Electron Corporation as the Controller of its analytical instruments business, formerly known as Thermo Instrument Systems, Inc.

60Mr. Buck was elected Senior Vice President and Chief Financial Officer of the Company effective January 2007 and also effective as of January 2007 became the Senior Vice President and Chief Financial Officer of National Grid, USA He also, effective January 2007 was elected Senior Vice President of the Company’s four New England electric distribution affiliates and Vice President and Chief Financial Officer of the Company’s transmission affiliate, New England Power Corporation.

MrMs. ~~Bailey~~Crossett ~~was~~has ~~elected~~served ~~Controller effective January 2006. He also serves~~ as ~~Controller of National Grid USA Service Company, Inc. Mr. Bailey was~~ Vice President of ~~Finance~~the ~~and Administration~~Company ofsince ~~Harvard Bioscience, Inc. from October~~July ~~2003 until September 2005, when he joined National Grid. From 1998 to~~ 2002~~, Mr~~. ~~Bailey~~ ~~worked~~She ~~for~~was ~~Thermo~~elected ~~Electron Corporation as the~~director ~~Controller~~ of ~~its~~the ~~analytical instruments business~~Company, ~~formerly~~effective ~~known as Thermo Instrument Systems~~May 15, ~~Inc~~ 2007.

Ms. Hassan was elected Senior Vice President and a director in April 2006. Since May 2000, she has served as Senior Vice President of the Company’s New England electricity distribution affiliates.

MrMs. ~~Jesanis~~LaFleur was elected director of the Company in ~~January~~April ~~2002~~2006. HeShe also became Executive Vice President and Chief Operating Officer of National Grid USA in ~~November~~April ~~2003~~2006, having been ~~its~~a ~~Chief~~Senior ~~Operating Officer and responsible for the~~Vice ~~day-to-day~~President ~~operations~~ since ~~January~~March ~~2001~~2000. ~~Mr. Jesanis~~She isserves ~~also~~as a director of National Grid USA and the Company’s four anNew ~~executive~~England ~~director~~electric distribution affiliates and was President of ~~National~~the ~~Grid~~four ~~plc~~distribution affiliates from January 2001 until April 2006. Ms. LaFleur was appointed President and acting Chief Executive Officer effective April 23, 2007.

Mr. ~~Kelleher~~Pini has served as a director and was elected Senior Vice President of the Company ~~effective~~since ~~May 1,~~January ~~2004~~2002. ~~and~~Previously, he was ~~elected a director in May 2006. He served as Vice~~ President of ~~National~~NEES ~~Grid~~Communications, ~~USA~~Inc. from ~~January 2002~~1997 to ~~March 2004~~ ~~and as its Treasurer from April~~ 2002 toand ~~April 2003.~~Vice ~~Prior~~President toof ~~that, he served as Vice~~Retail ~~President~~Customer ~~Financial~~Service ~~Planning~~ of ~~Niagara~~National ~~Mohawk~~Grid ~~Power~~USA ~~Corporation~~subsidiaries from ~~1999~~1993 to ~~2001~~1997.

MsMr. ~~LaFleur~~Reilly ~~was~~has ~~elected~~been ~~director~~Secretary ~~of the Company in April 2006. She also became Executive Vice President~~ and ~~Chief~~General ~~Operating~~Counsel ~~Officer~~ of National Grid USA insince ~~April~~January ~~2006,~~2001 ~~having~~and ~~been~~is a Director, ~~Senior~~Executive Vice President ~~since~~and ~~March 2000.~~General ~~She~~Counsel ~~serves as a director~~ of National Grid USA ~~and the Company’s four New England electric distribution affiliates and was President of the four distribution affiliates from January 2001 until April 2006~~.

MrMs. ~~Nadeau~~Saidi is Vice President of the Company and was elected director and Senior Vice President ~~and~~of aNational ~~director~~Grid USA in April 2007. She also serves as Senior Vice President of ~~the~~National Grid USA Service Company ~~effective~~with ~~January 31,~~responsibility for National Grid’s US ~~2002~~transmission operations. ~~Prior~~From 1998 to ~~that~~2004, heMs. Saidi was a Vice President of the Company’s transmission affiliate, New England Power Company, and from 2004 to 2005 she served as ~~Vice~~Senior Vice President~~-Electric~~ ~~Delivery~~and ~~beginning~~Chief inOperating ~~1998~~Officer of GridAmerica.

Mr. ~~Pini~~Tasker has ~~was~~served ~~elected~~as Senior Vice President, Distribution Finance, and Treasurer of the Company since ~~effective~~ January ~~31,~~ 2002. ~~Previously, he~~He was ~~President of NEES Communications, Inc. from 1997 to 2002 and~~ Vice President ~~of Retail~~ ~~Customer~~and ~~Service~~Controller ~~of National Grid USA subsidiaries~~ from ~~1993~~December 1998 to ~~1997~~January 2002.

Mr. Reilly has been Secretary and General Counsel of National Grid USA since January 2001 and is a Director and Executive Vice President of National Grid USA.

Ms. Saidi has served as Vice President since November 2005, when she was also elected Senior Vice President of National Grid USA Service Company with responsibility for National Grid’s US transmission operations. From 1998 to 2004, Ms. Saidi was a Vice President of the Company’s transmission affiliate, New England Power Company, and from 2004 to 2005 she served as Senior Vice President and Chief Operating Officer of GridAmerica.

Mr. Tasker has served as Senior Vice President, Distribution Finance, and Treasurer since February 2002. He was Vice President and Controller from December 1998 to February 2002.

Section 16(a) Beneficial Ownership Reporting Compliance

Section 16(a) of the Securities Exchange Act of 1934 requires the Company’s executive officers and directors, and persons who own more than 10 % of a registered class of the Company’s ~~equity~~ equity securities, to file reports with the Securities and Exchange Commission disclosing their ~~ownership~~ ownership of stock in the Company and changes in such ownership. To the Company’s knowledge, based solely on written representations from reporting persons, no such reports were required to be filed ~~during~~ during the fiscal year ended March 31, ~~2004~~2007.

Senior Financial Officer Code of Ethics

The Company has adopted a code of ethics that applies to its principal executive officer, principal financial officer and principal accounting officer. This code is available on the National Grid plc website, at www.nationalgrid.com, where any amendments or waivers will also be posted. There were no amendments to, or waivers under, the Company’s Code of Ethics in the fiscal year ended March 31, ~~2006~~2007.

The inclusion of National Grid plc’s website address in this annual report does not, and is not intended to, incorporate the contents of its website into this report and such information does not constitute part of this annual report.

Corporate Governance

Because the Company only has preferred stock listed on the New York Stock Exchange (‘NYSE”), the NYSE’s corporate governance rules, which relate to matters such as the independence of directors and the establishment of independent board committees, do not apply to us. The rules of the SEC that apply to audit committees, however, can apply even when only preferred stock is listed, unless there is an applicable exemption. Under the SEC’s rules on audit committees, because our parent company National Grid, plc has common shares listed on the NYSE we are exempt from the requirement to maintain an independent audit committee. As a result, we do not have an audit committee, a compensation committee or a nominating committee. In addition, we do not have any procedure by which security holders can nominate directors because the holders of our preferred stock do not have the right to vote in the election of directors.

ITEM 11. EXECUTIVE COMPENSATION

~~Summary~~COMPENSATION ~~Compensation~~DISCUSSION ~~Table~~AND ANALYSIS

~~The~~Objectives ~~following~~of ~~table~~Executive ~~sets~~Compensation ~~forth the compensation paid or accrued for services rendered to Niagara~~Programs Mohawk in the fiscal years ended March 31, 2006, 2005 and 2004 by the president and the four most highly paid persons who were serving as executive officers on March 31, 2006 (the Named Executive Officers).

					Annual Compensation (a)
							Other Annual
Name and Principal							Compensation		All Other Compensation
Position	Year		Salary($)		Bonus($)(b)		($)(c)		($)(d)(e)
William F. Edwards		2006		435,000		665,637		6,850		540
President		2005		420,000		266,410		3,675		540
		2004		399,994		210,000		7,000		270
John G. Cochrane (f)		2006		193,737		108,533		8,409		4,336
Chief Financial Officer		2005		166,900		110,001		7,300		3,876
		2004		146,181		99,044		5,276		2,952
Michael E. Jesanis (f)		2006		358,646		294,162		7,177		3,886
President & CEO, National		2005		259,534		203,511		3,686		2728
Grid USA		2004		225,015		146,390		6,773		2,682
Michael J. Kelleher Senior Vice President		2006		205,000		108,191		6,997		1,590
Business Services		2005		203,333		108,352		130,640		9,540
Clement E. Nadeau		2006		230,917		121,855		6,325		1,008
Senior Vice President		2005		218,750		151,091		6,150		828
Operations		2004		210,000		120,250		11,096		5,889

The executive compensation programs applicable to the named executives are derived from a number of different sources, given the global reach of the National Grid companies. For 2006/07, one of the named officers (Mr. Jesanis) was an Executive Director of National Grid plc. The compensation policies and programs that apply to an Executive Director are reviewed and approved by the Remuneration Committee of the Board of Directors for National Grid plc (the “Remuneration Committee”). The compensation policies and programs that apply to the direct reports of an Executive Director (which for 2006/07 include Mr. Edwards, Mr. Cochrane, Mr. Buck and Ms. LaFleur) as well as those of the remaining named executives (Mr. Kelleher, Mr. Ash and Mr. Tasker), primarily stem from the Remuneration Committee reviewed and approved programs and policies, although their annual salary levels and the specifics of their annual bonus criteria are established through a process that ends with a review at the Executive Director level.

While the Remuneration Committee generally reviews and approves the compensation programs for executives, including the named executives, typical of other multi-national companies, components of compensation packages, and entire benefits packages, are based upon local (ameaning by country) practices, ~~Includes~~in ~~deferred~~order to ensure competitive compensation/benefit packages are offered as necessary to attract and retain executives in ~~category~~the local market, and ~~year~~to ~~earned~~take into account tax incentives and/or other applicable rules and regulations that may be unique to the particular country. Consequently, as will become evident in this disclosure, named executives who have roots in the U.S. based operations (Mr. Jesanis, Mr. Edwards, Mr. Cochrane, Ms. LaFleur, Mr. Kelleher, Mr. Ash and Mr. Tasker) participate in certain compensation (and all benefit) programs that are U.S. based, and Mr. Buck, who recently moved from the U.K. to join the U.S. operations, participates in certain particular U.K. unique compensation and benefit programs.

62Also noteworthy is the fact that the National Grid plc companies are transitioning from operating predominantly on a local (by country) basis to an international lines of business operating model. This is significant in the area of executive compensation and benefits because this will result in a greater integration of U.K. and U.S. executive teams, increased centralization of compensation

~~(b) The bonus figure represents cash bonuses~~ and benefits ~~the fair market value of unrestricted securities of National Grid plc awarded under an incentive compensation plan and cash bonuses awarded under the all~~decision-~~employees goals program. For Mr. Edwards~~making, itas ~~also~~well ~~includes~~as amore ~~special~~commonality cash bonus associated with the completion of certain corporate objectives. (c) Includes amounts reimbursed for the payment of taxes on certain non-cash benefits and contributions to the incentive thrift plan that are not bonus contributions. (d) Includes Company contributions to life insurance. Also includes the value of financial services provided to Messrs. Jesanis, Cochrane and Kelleher. (e) No options or stock appreciation rights were awarded in ~~fiscal~~compensation ~~2004, 2005 or 2006. (f) Messrs. Cochrane~~ and ~~Jesanis~~benefit ~~perform service for affiliate companies~~programs. ~~Compensation that is allocable to Niagara Mohawk is set forth in the table.~~

~~Long~~The National Grid plc Board of Directors Remuneration Committee members are John Allan, Ken Harvey, Stephen Pettit and George Rose. Each is a Non-~~Term~~executive Director of National Grid plc, is regarded as ~~Incentive~~independent, ~~Plans~~and —has ~~Awards~~served throughout inthe ~~Last~~reporting ~~Fiscal~~year. ~~Year~~The Group Human Resources Director and Group Head of Compensation and Benefits provide the Remuneration Committee with advice on compensation policies and practices and are usually invited to attend meetings, along with the Chairman and the Chief Executive of National Grid plc. No Director or other attendee is present during any discussion regarding his or her own compensation. The Remuneration Committee is responsible for developing and/or monitoring National Grid policy regarding total compensation of the executive group.

~~The~~In addition ~~following~~to ~~table~~conferring ~~sets~~with ~~forth~~the ~~awards~~Group ~~made~~Human Resources ~~under~~Director ~~the~~and ~~National~~Group ~~Grid~~Head ~~Performance~~of ~~Share~~Compensation ~~Plan~~and toBenefits during fiscal year 2006/07, the Remuneration Committee retained and conferred with Mercer Human Resources Consulting Limited ~~Named~~and ~~Executive~~Deloitte ~~Officers~~& ~~during~~Touche ~~fiscal~~LLP, ~~2006~~independent human resources and compensation advisors, respectively, on executive compensation and benefit matters. The process used in setting total compensation for the named executives is explained in more detail below.

				Estimated Future Payouts
	Number of			Threshold		Maximum
Name	Shares (#)		Performance Period	(#)		(#)
William F. Edwards		4,481	July 1, 2005 through June 30, 2008		1,344		4,481
John G. Cochrane		4,574	July 1, 2005 through June 30, 2008		1,372		4,574
Michael E. Jesanis		21,634	July 1, 2005 through June 30, 2008		6,490		21,634
Michael J. Kelleher		2,122	July 1, 2005 through June 30, 2008		637		2,122
Clement E. Nadeau		2,880	July 1, 2005 through June 30, 2008		864		2,880

Executive compensation programs are designed with the aim of attracting, motivating and retaining high caliber executives to deliver value for National Grid plc shareholders and high levels of customer service, safety and reliability in an efficient and responsible manner. Executive compensation policies and practices take into consideration the elements of compensation and benefits that are typically offered in the local (country) markets in which the National Grid companies operate. Executive compensation policy is framed around the following key principles:

~~Under~~• ~~the~~total ~~National~~rewards ~~Grid~~should ~~Performance~~be Share Plan, executives receive notional allocations of American Depositary Shares of National Grid. Shares vest after three years, subject to the satisfaction of the relevant performance criteria which are set at ~~the~~levels ~~date~~that ~~of grant and measured over a three-year period. Shares must then be held for a further year, after which they~~ are ~~released.~~ ~~For~~competitive ~~the~~in ~~grants set forth above,~~ the relevant ~~criteria~~market; ~~are~~• ~~total~~a ~~shareholder~~significant ~~return~~proportion ~~(TSR) performance and earnings per share (EPS) growth . Vesting~~ of ~~fifty~~executive’s ~~percent~~total ofreward ~~the~~should ~~award~~be ~~is subject to TSR~~ performance ~~relative to the TSR performance of companies in the FTSE 100~~based. ~~Vesting~~Performance ofbased ~~the other~~incentives ~~fifty~~should ~~percent~~be ofearned ~~the~~through ~~award is subject to National Grid EPS growth versus~~ the UKachievement ~~inflation rate as measured by the UK Retail Price Index (RPI). The proportion~~ of ~~the~~demanding ~~original~~targets ~~award~~for ~~of shares~~short-term ~~that~~business ~~will~~and ~~transfer~~personal toperformance, ~~participants~~and ~~will~~long-term ~~depend on~~ National Grid’s ~~performance~~plc ~~against~~shareholder ~~each of~~value ~~these~~creation, ~~measurements.~~consistent ~~For~~with the ~~TSR~~Framework ~~criterion,~~for ~~National~~Responsible ~~Grid~~Business ~~must~~which ~~achieve~~can ~~median~~be ~~TSR~~found ~~ranking relative~~at towww.nationalgrid.com/responsibility/managementandgovernance; ~~TSR~~• ~~performance~~rewards ~~of the FTSE 100 companies in order~~ for ~~participants~~higher tolevels ~~realize~~of ~~the threshold~~performance ~~payout~~should ofbe ~~30%~~substantial ofbut ~~the~~not ~~original~~excessive; ~~award.~~• Itincentive ~~must~~plans, ~~achieve~~performance ~~more~~measures ~~than~~and ~~7.5 percentage~~targets ~~point above~~should ~~median~~be ~~relative~~structured to ~~the~~operate ~~FTSE~~soundly ~~100~~throughout ~~companies for participants to achieve~~ the ~~maximum~~business ~~payout~~cycle, ~~of 100%~~and ofshould ~~the~~be ~~original~~aligned ~~award.~~as ~~For~~closely ~~the~~as ~~EPS~~possible ~~criterion,~~with National Grid’s ~~EPS~~plc ~~must~~shareholders’ ~~exceed~~interests; ~~RPI~~and by• ~~a minimum~~base ofsalary ~~3 percentage~~should ~~points~~be tocompetitive ~~realize~~based ~~the~~upon ~~threshold of 30% of~~ the ~~original~~relevant ~~award.~~market Toand ~~achieve the~~scope ~~maximum~~of ~~payout, National Grid’s EPS must exceed RPI growth by 6 percentage points~~responsibilities.

~~Option/SAR~~Compensation ~~Exercises in Fiscal Year 2005 and Fiscal Year-End Option/SAR Values~~Program

~~The following table sets forth, for the Named Executive Officers, the number of shares for which~~67 ~~stock options were exercised in fiscal year 2006, the realized value or spread (the difference~~

~~between~~The ~~the~~named ~~exercise~~executives ~~price~~perform ~~and~~services ~~market~~for ~~value~~both on the ~~date~~Company ofand ~~exercise~~affiliated National Grid companies (including parent companies). ~~and~~This ~~the~~compensation ~~number~~discussion and ~~unrealized~~analysis does not reflect ~~spread~~allocations ofbased ~~the~~upon ~~unexercised~~time ~~options~~spent ~~held~~performing byservices ~~each~~for atthe ~~fiscal~~various ~~year-end~~National Grid companies.

					Number of Securities
					Underlying Unexercised
					Options on March 31, 2006				Value of Unexercised Options
			Value		(#)				on March 31, 2006 ($)(a)(b)
	Options		Realized						Exercisable		Unexercisable
Name	Exercised (#)		($)		Exercisable		Unexercisable		(b)		(c)
William F. Edwards		0		0		56,206			$	88,997
John G. Cochrane		0		0		92,395		32,620	$	73,780		0
Michael E. Jesanis		0		0		143,960		51,169	$	112,790		0
Michael J. Kelleher		0		0		33,724			$	53,399
Clement E. Nadeau		0		0		29,508			$	46,723

The executive compensation program reflects the compensation philosophy and principles as set forth above. To achieve those objectives, direct compensation includes three basic components: base salary, annual incentive compensation (including the Executive Director’s Deferred Share Plan, applicable to Mr. Jesanis, the U.K. Annual Bonus Plan, applicable to Mr. Buck, and the Incentive Compensation Plan, applicable to Mr. Edwards, Mr. Cochrane, Ms. LaFleur, Mr. Kelleher, Mr. Ash and Mr. Tasker), and long-term incentive compensation (the Performance Share Plan, applicable to all named executives).

~~(a)~~The ~~Calculated~~mix ~~based~~between onsalary and incentive pay is weighted more heavily toward incentive pay at the top ~~closing~~executive ~~price~~levels to ensure that those with the greatest potential impact on National ~~March~~Grid 31performance have the largest stake in its success. In addition, ~~2006~~the proportion of total compensation that is linked to National Grid plc ~~ordinary~~share performance ~~shares~~is ~~traded~~greatest onat the ~~London~~top executive ~~Stock~~levels. ~~Exchange~~The ~~(£5.725).~~annual ~~(b)~~bonus Aprograms ~~conversion~~include ~~rate~~a ofsignificant ~~$1.74/£1.00~~National ~~was~~Grid ~~used~~share element in order to ~~translate~~increase the ~~option~~proportion ~~value,~~of ~~which~~rewards islinked ~~the~~to ~~exchange~~both ~~rate~~short-term ~~for~~performance and longer-term total shareholder returns. This practice also ensures that the executives’ total compensation shares a significant level of personal risk with National Grid ~~companies’~~plc ~~balance~~shareholders. ~~sheet~~The atcompensation mix ~~March~~in ~~31,~~place for 2006./07 ~~(c)~~was ~~The~~first ~~performance~~established ~~condition~~following ~~associated~~a review in 2005, where the Remuneration Committee, in consultation with ~~grants~~its ofoutside ~~stock~~compensation ~~options~~expert ~~made~~at onthe ~~June~~time (Ernst 18& Young LLP), ~~2001~~undertook toa ~~Messrs.~~complete ~~Cochrane~~review of the mix between fixed and ~~Jesanis~~variable compensation, ~~was~~and ~~tested~~the inoperation ~~March~~of ~~2006~~annual and ~~was~~long ~~not~~term ~~met~~incentive pay. AsThat review resulted in a number ~~result~~of adjustments from prior practice, ~~these~~including ~~options~~an ~~have~~increase ~~lapsed~~in the amount of incentive pay that would be tied to National Grid shares (ordinary shares or ADSs, as applicable) through both the annual and ~~are~~long noterm ~~longer~~incentive ~~exercisable~~plans.

~~The~~For ~~following~~fiscal year ~~table~~2006/07, ~~sets forth~~Mr. Jesanis, ~~for~~as ~~the~~an ~~Named~~ Executive ~~Officers~~Director, ~~exercises~~could achieve a maximum annual bonus equal to 100% of ~~SARs~~annual salary, one-half delivered in ~~fiscal year~~deferred ~~2006~~National Grid plc American Depositary Shares (ADSs), ~~the~~plus ~~realized~~a ~~value~~maximum oraward ~~spread~~grant (~~the~~in ~~difference~~ADSs) ~~between~~equal to 125% of annual salary under the ~~exercise~~long ~~price~~term incentive plan. Mr. Edwards, Mr. Cochrane and ~~market~~Ms. LaFleur, ~~value~~as direct reports to an Executive onDirector, ~~the~~could ~~date~~achieve a maximum annual bonus equal to 67.5% of ~~exercise~~annual salary, one-third delivered in ADSs, plus a maximum award grant (in ADSs) ~~and~~equal to 60% of annual salary under the ~~number~~long ~~and~~term incentive ~~unrealized~~plan. ~~spread~~Mr. Buck could achieve a maximum annual bonus equal to 50% of annual salary, 40% delivered in deferred in National Grid plc ordinary shares, plus a maximum award grant in National Grid plc ordinary shares equal to 60% of annual salary under the ~~unexercised~~long ~~options~~term incentive plan. Mr. Kelleher and ~~SARs~~Mr. Tasker could achieve a maximum annual bonus equal to 67.5% of annual ~~held~~salary by(49.5% ~~each~~for atMr. ~~fiscal~~Ash), ~~year~~one-~~end~~third delivered in ADSs, plus a maximum award grant (in ADSs) equal to 60% (40% for Mr. Ash) of annual salary under the long term incentive plan.

					Number of Securities
					Underlying Unexercised
	SARs		Value		SARs At Fiscal				Value of Unexercised SARs
	Exercised		Realized		Year-End (#)				At Fiscal Year-End ($)(a)
Name	(#)		($)		Exercisable		Unexercisable		Exercisable		Unexercisable
William F. Edwards		0		0		0		0		0		0
John G. Cochrane		0		0		0		0		0		0
Michael Jesanis		0		0		0		0		0		0
Michael J. Kelleher		0		0		0		0		0		0
Clement E. Nadeau		12,312	$	308,703		0		0		0		0

(a) SAR grants were made under Niagara Mohawk’s Long Term Incentive Plan which was terminated when its parent, Niagara Mohawk Holdings, Inc. merged with a subsidiary of National Grid USA. At that time, outstanding grants of SARs were converted to SARs over National Grid Group American Depositary Shares using a specified exchange ratio.

~~Pension~~Following ~~Plans~~a thorough review of the remuneration policy in light of the proposed KeySpan acquisition, which will result in a larger and more complex role for executives, the Remuneration Committee is in the process of modifying variable compensation (a portion of which is subject to National Grid plc shareholder approval). The changes would include increases in maximum potential bonus awards, including an increase in the maximum long term incentive compensation award (Performance Share Plan) to a maximum of up to 150% of base salary for Ms. LaFleur, 150% for Mr. Edwards, 80% for Mr. Buck, and 60% for Mr. Ash and Mr. Tasker. In conjunction with this change, the upper target of the Performance Share Plan will be subject to more challenging targets than historical stretch targets. It is believed that the increase in range of potential bonuses will motivate executives toward greater excellence. In addition, a new multi-national annual bonus plan has been introduced for fiscal year 2007/08 (Annual Bonus Plan 2007/08) that will apply to Mr. Edwards and Ms. LaFleur in lieu of the Incentive Compensation Plan. The Annual Bonus Plan 2007/08 will provide a maximum bonus of up to 110% of annual salary, 60% of which will be based upon financial targets and 40% of which will be based upon individual objectives. Further, two-thirds of awards will be paid in cash and one-third in ADSs that will vest after three years. The Annual Bonus Plan 2007/08 will also apply to Mr. Buck, whose maximum bonus will be 70% of annual salary under the plan. These changes were the results of a benchmarking process performed for The Remuneration Committee, taking into account advice from Deloitte & Touche, including benchmarking against comparative size companies of equivalent complexity in the energy services sector as well as the general industry performed by Towers Perrin.

~~Executive~~Executives ~~Supplement~~are ~~Retirement~~provided ~~Benefit~~with ~~Table~~benefits and perquisites that are intended to be comparable to those provided to executives in applicable peer groups. These other programs include the following:

Five-Year
Average	Annual Annuity Value Based On Years of Service
Compensation	15 Years		20 Years		25 Years		30 Years		35 Years		40 Years
$150,000	$	42,874	$	56,166	$	69,082	$	81,999	$	90,040	$	94,540
$200,000	$	58,874	$	77,166	$	94,957	$	112,749	$	124,040	$	130,040
$250,000	$	74,874	$	98,166	$	120,832	$	143,499	$	158,040	$	165,540
$300,000	$	90,874	$	119,166	$	146,707	$	174,249	$	192,040	$	201,040
$350,000	$	106,874	$	140,166	$	172,582	$	204,999	$	226,040	$	236,540
$400,000	$	122,874	$	161,166	$	198,457	$	235,749	$	260,040	$	272,040
$450,000	$	138,874	$	182,166	$	224,332	$	266,499	$	294,040	$	307,540
$500,000	$	154,874	$	203,166	$	250,207	$	297,249	$	328,040	$	343,040
$550,000	$	160,124	$	210,166	$	258,957	$	307,749	$	340,290	$	355,290
$600,000	$	165,374	$	217,166	$	267,707	$	318,249	$	352,540	$	367,540
$650,000	$	170,624	$	224,166	$	276,457	$	328,749	$	364,790	$	379,790
$700,000	$	175,874	$	231,166	$	285,207	$	339,249	$	377,040	$	392,040
$750,000	$	181,124	$	238,166	$	293,957	$	349,749	$	389,290	$	404,290
$800,000	$	186,374	$	245,166	$	302,707	$	360,249	$	401,540	$	401,541
$850,000	$	191,624	$	252,166	$	311,457	$	370,749	$	413,790	$	428,790
$900,000	$	196,874	$	259,166	$	320,207	$	381,249	$	426,040	$	441,040
$1,000,000	$	207,374	$	273,166	$	337,707	$	402,249	$	450,540	$	465,540
$1,100,000	$	217,874	$	287,166	$	355,207	$	423,249	$	475,040	$	490,040
$1,200,000	$	228,374	$	301,166	$	372,707	$	444,249	$	499,540	$	514,540
$1,300,000	$	238,874	$	315,166	$	390,207	$	465,249	$	524,040	$	539,040
$1,400,000	$	249,374	$	329,166	$	407,707	$	486,249	$	548,540	$	563,540
$1,500,000	$	259,874	$	343,166	$	425,207	$	507,249	$	573,040	$	588,040
$1,600,000	$	270,374	$	357,166	$	442,707	$	528,249	$	597,540	$	612,540

	•		ability to allocate a portion of any annual base pay or bonuses into a deferred compensation plan (does not apply to Mr. Buck)

	•		retirement plans

	•		401(k) plan with employer match (available to all U.S. employees)

	•		share purchase plans (only applies to Mr. Buck)

	•		executive life insurance

	•		severance and change in control termination protection

	•		other reasonable and customary perquisites

~~The~~In ~~table~~the ~~above~~design ~~shows~~of ~~the~~compensation ~~maximum~~and ~~retirement~~ benefit anprograms, ~~executive~~the ~~officer~~compensation ~~can~~amounts ~~earn~~realized in prior ~~aggregate~~years ~~under~~are ~~the~~generally ~~applicable~~not ~~tax-qualified~~taken ~~plan~~into ~~(described~~consideration ~~below)~~when ~~together~~establishing ~~with the ESRP. In developing the ESRP benefit, final~~ compensation ~~includes~~targets ~~both~~or ~~base salary and annual incentive pay~~awards. ~~The~~There ~~benefit~~is ~~calculations~~also ~~are~~no ~~made~~policy asthat ofwould ~~March 31,~~automatically ~~2006~~result ~~and~~in ~~assume~~an ~~the~~adjustment ~~officer~~to ~~has~~payments ~~selected~~if athe ~~straight~~relevant ~~life~~performance ~~annuity~~measures ~~commencing~~upon atwhich ~~age~~they ~~65.~~are ~~Annual~~based ~~compensation~~are ~~limits~~restated ofor ~~$210,000~~otherwise ~~under~~adjusted ain ~~tax-qualified~~subsequent ~~plan~~years ~~will~~in ~~reduce~~a ~~the~~manner ~~portion~~that ~~payable~~would ~~under~~reduce ~~the~~or ~~qualified~~increase ~~pension~~the ~~plan~~size ~~for~~of ~~some~~a ~~highly compensated~~previous ~~officers~~payment. ~~The benefits listed are shown without any joint and survivor benefits. If a~~ ~~participant elected a 100 percent joint and survivor benefit at age 65~~However, ~~with~~in aan ~~spouse~~instance ofsuch ~~the~~as ~~same age~~this, the ~~benefit~~Remuneration ~~shown~~Committee inwould ~~the~~have ~~table~~discretion ~~would~~to beconsider ~~reduced~~an adjustment, byif ~~approximately 16 percent~~warranted.

~~For~~Base ~~purposes of the pension program, the Named Executive Officers had approximately the following~~Salary credited years of benefit service at March 31, 2006: William F. Edwards, 27 years; John G.Cochrane, 25 years; Michael E. Jesanis, 22 years; Michael J. Kelleher, 17 years; and Clement E. Nadeau, 33 years.

~~Tax-Qualified~~Salaries ~~Pension~~are ~~Plans:~~reviewed ~~National~~annually ~~Grid~~and ~~USA~~targeted ~~Companies~~broadly ~~Final~~at ~~Average~~the ~~Pay~~median ~~Pension~~position ~~Plan~~in ~~and~~the ~~Niagara~~local (country) ~~Mohawk~~marketplace ~~Pension~~taking ~~Plan.~~into account the regulated nature of a majority of National Grid’s operating

6569

~~Depending~~activities onalong ~~their~~with ~~company~~the ~~origin~~size, ~~prior~~complexity toand ~~the~~international ~~merger~~scope of ~~Niagara~~the ~~Mohawk~~National ~~Holdings~~Grid ~~with a subsidiary~~businesses. ofBase ~~National~~salaries ~~Grid~~for ~~USA,~~executives ~~the~~are ~~Named~~established ~~Executive~~based ~~Officers~~on ~~participate~~the inscope ~~one~~ of ~~two qualified~~their ~~pension~~responsibilities, ~~plans:~~taking into ~~the~~account ~~National~~competitive ~~Grid~~market ~~USA~~compensation ~~Companies~~levels ~~Final~~for ~~Average~~similar ~~Pay~~positions. ~~Pension~~This ~~Plan~~analysis ~~(FAPP) or~~is ~~the~~completed ~~Niagara~~with ~~Mohawk~~references ~~Pension Plan (Nimo Plan). Both FAPP~~ and ~~the~~data ~~Nimo~~points ~~Plan~~supplied ~~are~~by ~~noncontributory~~Towers Perrin, ~~tax-qualified~~who ~~defined~~is ~~benefit~~retained ~~plans~~by ~~which~~Human ~~between~~Resources ~~them~~(U.K. ~~provide~~and aU.S.). ~~retirement~~Business ~~benefit~~performance toand the ~~substantially~~individual’s ~~all~~experience ~~employees~~in of the ~~National~~role ~~Grid~~are ~~USA~~taken ~~companies.~~into ~~Pension~~account ~~benefits~~in setting ~~are~~individual ~~related~~salaries, toas are ~~compensation,~~the ~~subject~~employment toand ~~the~~salary ~~maximum~~practices ~~annual~~prevailing ~~limits~~for ~~noted~~other inexecutives ~~the~~with ~~table~~similar ~~above~~levels of responsibility and expertise.

~~Under~~Setting ~~FAPP,~~annual asalaries ~~participant’s~~for ~~retirement~~the ~~benefit~~named executives is ~~computed~~based ~~using~~in ~~formulas~~part ~~based~~on an overall recommendation by the Remuneration Committee on ~~percentages~~salary ofincrease parameters. Those parameters are established in ~~highest~~consultation ~~average~~with an outside compensation ~~computed~~expert ~~over~~(Deloitte ~~five~~& Touche ~~consecutive~~for ~~years~~fiscal year 2006/07). ~~The~~With ~~compensation~~respect ~~covered~~to Mr. Jesanis, Mr. Edwards, Mr. Cochrane, Mr. Buck and Ms. LaFleur, salary reviews for fiscal year 2006/07 were undertaken by ~~FAPP~~their ~~includes~~respective managers, taking into account market reference information obtained from Towers Perrin. Due to his status as an Executive Director, recommendations regarding Mr. Jesanis’s annual salary were then reviewed and approved by the Remuneration Committee in consultation with Deloitte & Touche. Relative to Mr. Edwards, ~~bonus~~Mr. Cochrane, Mr. Buck and ~~incentive~~Ms. LaFleur, ~~share~~the ~~awards~~salary adjustment recommendations were ultimately reviewed and approved by the Executive Directors (acting as The Executive Committee). With respect to Mr. Kelleher, Mr. Ash and Mr. Tasker, for fiscal year 2006/07, reviews were initially performed by the U.S. Manager of Compensation, using market reference information obtained from Towers Perrin. Those recommendations were then presented to the Executive Director with responsibility for U.S. operations (Mr. Jesanis for fiscal year 2006/07), who exercised final decision-making authority.

~~Under~~Annual ~~the~~Bonus ~~Nimo Plan, a participant’s retirement benefit is based on one of two formulas depending~~Plans on age and years of service on July 1, 1998: the cash balance formula, or the highest five-year average compensation. Under the cash balance formula a participant’s retirement benefit grows monthly, according to pay credits (from 4 percent to 8 percent times base salary) plus interest credits. Messrs. Edwards, Kelleher and Nadeau will receive the retirement benefit resulting from the higher of the two formulas.

~~Nonqualified~~Annual ~~Pension~~bonuses ~~Plan:~~for the named executives during fiscal year 2006/07 were delivered through one of three different plans, namely the Executive ~~Supplemental~~Director’s ~~Retirement~~Deferred Share Plan (Mr. Jesanis), the U.K. Annual Bonus Plan (Mr. Buck), and the Incentive Compensation Plan (Mr. Edwards, Mr. Cochrane, Ms. LaFleur, Mr. Kelleher, Mr. Ash and Mr. Tasker). Bonus awards for fiscal year 2006/07 were based on achievement of a combination of demanding Group (meaning National Grid plc in total), individual, and, where applicable, divisional targets. The process for setting financial targets is derived from the business planning process conducted by the executive directors and the highest level financial executives at National Grid. They make recommendations to the Remuneration Committee based upon analysis of National Grid company operations, investor community expectations, and divisional contributions towards operational and financial success. Recommendations regarding annual bonus targets are then presented to the Remuneration Committee. The Remuneration Committee believes that the targets established for fiscal year 2006/07 were stretch targets but achievable in view of National Grid’s historical annual performance and its 2006/07 business plan. As noted earlier, maximum bonus opportunity levels are set to reward exceptional operational and financial performance. Over the past three years, bonus payouts for the named executives have ranged from 60% to 80% of target.

~~The~~ Executive ~~Supplemental~~Deferred ~~Retirement~~Share Plan (~~ESRP)~~Mr. isJesanis) a— For ~~noncontributory,~~fiscal ~~nonqualified~~year ~~defined benefit~~2006/07, this plan ~~that~~included ~~provides~~a ~~additional~~maximum ~~retirement~~bonus potential ~~benefits to each~~ of ~~the~~100% ~~Named Executive Officers and other members~~ of ~~management~~annual ~~who~~salary, ~~are~~with ~~eligible to receive either~~ a ~~FAPP~~targeted orpayout ~~Nimo~~of ~~Plan~~50%. ~~benefit~~Awards ~~and whose~~were ~~compensation~~based ~~exceeds~~70% ~~legal limits under the applicable plan, whose deferred compensation is~~on ~~not~~financial ~~eligible~~targets ~~for~~and ~~inclusion~~30% ~~under the FAPP or NiMo Plan, or who are otherwise selected for participation. Depending~~ on ~~the~~individual ~~participant~~targets, ~~the~~with ~~ESRP~~half ~~may provide for unreduced benefits payable as early as age 55, enhance the qualified plan formula, give credit for more years~~ of ~~service,~~each ~~take into account certain deferred compensation, and/or~~ award ~~benefits~~delivered ~~not~~in ~~otherwise~~National ~~payable due to~~Grid ~~limits~~plc onAmerican ~~benefits~~Depositary ~~that~~Shares ~~can be provided under the qualified plan. Mr. Nadeau and other ESRP participants who formerly participated in the Niagara Mohawk Supplemental Executive Retirement Plan~~ (~~Niagara Mohawk SERP~~ADSs) ~~are~~that ~~entitled~~vest toon the ~~pension~~third ~~benefit~~anniversary ~~paid under the NiMo Plan, plus the higher~~ of ~~the pension benefit paid under the ESRP or that paid under the Niagara Mohawk SERP~~award. The ~~SERP~~ ~~benefit~~Remuneration ~~paid~~Committee ~~under~~may, ~~the Niagara Mohawk was frozen~~ at the time of ~~the~~release ~~merger~~ of ~~Niagara Mohawk Holdings with a subsidiary of National Grid USA. For Mr. Nadeau~~ADSs, ~~that~~use ~~amount~~its isdiscretion ~~frozen as an annual annuity of $45,770. Mr. Edwards and Mr. Kelleher received the Niagara Mohawk SERP benefit at the merger and are eligible~~ to ~~receive a pension benefit under the ESRP, to be offset by the SERP~~ ~~benefit already received.~~

~~Employment Contracts, Termination of Employment and Change-in-Control Arrangements~~70

Employment contracts. Of the Named Executive Officers, only Mr. Jesanis has an employment contract. His agreement sets forth his salary and certain benefits, and provides for 12 months’ written notice for termination other than for cause or disability. There are no termination or change-in-control arrangements particular to Mr. Jesanis.

~~Termination~~pay ~~without~~a ~~cause.~~cash ~~For~~amount ~~termination~~equivalent ~~without~~to ~~cause,~~the ~~each~~value of the ~~Named~~dividends ~~Executive~~that ~~Officers except~~would ~~for~~have Mraccumulated on the deferred shares. ~~Jesanis~~ isThe ~~entitled~~principal tomeasures aof ~~lump~~financial ~~sum~~performance ~~equal~~were toadjusted ~~two~~earnings ~~times~~per ~~his~~share (EPS) and ~~annualized~~cash ~~base~~flow; ~~pay~~the main divisional measures were divisional operating profit and divisional ~~bonus~~cash ~~under~~flow. ~~the~~Individual ~~National~~targets, ~~Grid~~representing ~~USA~~30% ~~Companies’~~of ~~Executive~~the ~~Severance~~bonus, ~~Plan.~~were ~~The~~set ~~plan~~in relation to key ~~also~~operating ~~provides~~and strategic objectives and included overriding measures for asafety ~~lump~~and ~~sum~~customer ~~payment~~service performance. toThe ~~cover~~Remuneration Committee set targets at the ~~employer’s~~start ~~contribution~~of fiscal ~~toward~~year ~~health~~2006/07 ~~insurance~~and reviewed ~~premiums~~performance ~~for~~against ~~18 months,~~those atargets ~~pro-rated~~at ~~bonus~~fiscal ifyear ~~the~~end. ~~executive~~The ~~worked~~Remuneration atCommittee ~~least~~may ~~six~~use ~~months~~its ~~that~~discretion to ~~year~~reduce ~~and~~payments to take into account any significant safety or service standard incidents, or to ~~outplacement~~increase ~~counseling~~them ~~for~~in ~~18 months~~the event of exceptional value creation.

~~Change~~U.K. Annual inBonus ~~control~~Plan (Mr. Buck) ~~Under~~— ~~the~~For ~~National~~fiscal ~~Grid~~year ~~USA~~2006/07, ~~Companies’~~this ~~Incentive~~plan ~~Compensation~~included ~~Plan,~~a inmaximum ~~the~~bonus potential of ~~event~~50% of annual salary. Awards were based 60% on a ~~change~~financial inelement ~~control~~and 40% on individual objectives, with 60% paid in cash and 40% of each ~~Named~~award delivered in National Grid plc ordinary shares that vest on the third anniversary of the award date. (The share component is delivered through the Executive ~~Officer~~Director’s Deferred ~~would~~Share ~~receive~~Plan.) aThe ~~cash~~shares ~~payment~~are held in antrust for three years before release. During this time they are not owned by the executive, and therefore no dividends are paid. The Remuneration Committee may, at the time of release of shares, use its discretion to pay a cash amount ~~equal~~equivalent to the ~~average~~value ~~annual~~of ~~bonus~~the ~~percentage~~dividends ~~for~~that would have accumulated on the ~~incentive~~deferred ~~compensation~~shares. The principal measures of the annual bonus plan for financial performance were group level ~~for~~earnings per share (EPS) and cash flow as well as business unit operating profit and cash flow, with achievement producing the ~~three~~following ~~prior~~percentages ~~years~~of ~~multiplied~~the financial byperformance ~~that~~component: ~~officer’s~~20% ~~annualized~~at ~~base~~threshold; ~~compensation.~~50% ~~These~~at ~~payments~~target; and ~~would~~100% beat ~~made~~stretch intarget ~~lieu~~performance. Individual targets, representing 40% of the ~~bonuses~~bonus, ~~under~~were ~~these~~set ~~plans~~in relation ~~for~~to key individual projects and deliverables required during the year infor ~~which~~that role. Targets are set at the ~~change~~start inof ~~control~~each fiscal year ~~occurs~~and performance against those targets is reviewed at fiscal year end. Further, discretion is retained to reduce payments to take into account any significant safety or service standard incidents.

~~Messrs~~Incentive Compensation Plan (Mr. Edwards, ~~and~~ Mr. Cochrane, ~~each~~Ms. LaFleur, ~~have~~Mr. Kelleher, aMr. Ash ~~change~~and ofMr. Tasker) ~~control~~— ~~agreement~~For ~~with~~fiscal ~~National~~year ~~Grid~~2006/07, ~~USA providing~~the ~~for~~principal ~~severance~~measure ~~payments~~of ~~and~~organization financial ~~benefits~~performance inwas ~~the~~based ~~event~~upon U.S. ~~that~~operations’ ~~employment~~contribution isto ~~terminated~~EPS, ~~without cause~~with ora ~~the~~target ~~executive~~payout ~~terminates~~at 45% ~~with~~of ~~good~~base ~~reason~~salary ~~within~~(33% ~~36 months~~for ~~after~~Mr. aAsh), ~~change~~further ~~in control or~~adjusted ~~other~~for ~~qualifying~~individual ~~transaction.~~performance Indown ~~addition~~ to ~~any~~0% ~~other~~for ~~compensation~~unsatisfactory individual performance and ~~benefits~~up ~~payable~~to ~~under~~150% of ~~executive~~target ~~plans,~~(resulting ~~but~~in ~~subject~~a tomaximum ~~certain~~annual ~~limits~~bonus ~~tied~~equal to ~~applicable~~67.5% ~~tax~~- ~~law,~~49.5% for ~~the~~Mr. ~~executive~~Ash) ~~will~~for ~~be entitled~~exceptional toindividual aperformance, measured ~~lump~~based ~~sum~~upon ~~cash~~pre-established ~~payment~~goals ~~equal~~related to ~~three~~operating ~~times~~and ~~the~~strategic ~~sum~~objectives, ofincluding safety, ~~his~~budgets, ~~annual~~leadership ~~base~~and ~~salary~~corporate ~~plus bonus;~~values. aIf ~~lump~~the ~~sum~~threshold ~~cash~~level ~~payment~~of ~~for~~earnings ~~the~~is ~~amount~~not achieved, heno ~~would~~bonus ~~have~~is ~~accrued~~payable. ~~under~~The ~~each~~level ~~pension~~of ~~plan~~bonus ~~had~~available ~~he remained~~is ~~employed~~calibrated ~~for~~with anearnings achievement. ~~additional~~Two-thirds ~~36 months;~~of ~~and~~the ~~reimbursement~~award ofis ~~legal~~paid ~~fees~~in cash and ~~expenses,~~one-third ~~if any,~~in ~~that~~ADSs. heEither ~~incurs~~component inmay be ~~disputing~~deferred inunder ~~good~~the ~~faith~~terms ~~any~~of ~~issue~~the ~~relating~~National toGrid ~~the~~USA ~~agreement~~Companies’ Deferred Compensation Plan.

~~Post-employment~~The ~~health~~named ~~and~~executives ~~life~~(excluding ~~insurance~~Mr. Buck) Atalso ~~retirement,~~participated ~~the~~in ~~Named Executive Officers may become eligible for post-retirement health and life insurance benefits determined based on their age and years of service. The executive may be required to contribute to~~ the ~~cost~~USA ofGoals ~~benefits.~~program, ~~Under~~ a ~~retiree~~ ~~health~~bonus ~~care~~ plan ~~applicable to Messrs. Cochrane and Jesanis, post-employment health care~~ ~~benefits~~covering ~~are~~substantially ~~protected~~all ~~for~~of ~~three years following a change in control~~U. ~~Messrs~~S. ~~Cochrane,~~ ~~Edwards and~~employees ~~Jesanis have agreements~~ that ~~provide~~can ~~for three times base~~ pay ~~life~~up ~~insurance~~to ~~coverage for life~~5. ~~Mr. Edwards~~7% ~~has~~of ansalary ~~agreement~~on ~~providing~~the ~~for~~achievement of ~~health~~certain ~~care~~earnings ~~benefits for him~~ and ~~his~~performance ~~dependents for their lifetimes~~targets.

Long-Term Incentive Compensation

Since 2003, long-term incentive compensation has been delivered through the Performance Share Plan. Prior to that date, long-term incentive compensation was delivered through the Executive Share Option Plan, discussed below. (The Executive Share Option Plan is described

due to the fact that several of the named executives have either exercised rights under the plan during fiscal year 2006/07 or have outstanding rights under the plan.) The long-term incentive compensation programs have been offered to a large number of senior employees who have significant influence over National Grid plc’s ability to meet its strategic objectives. Eligible executives, including the named executives, receive awards that vest subject to the achievement of performance conditions set by the Remuneration Committee at the date of grant.

Performance Share Plan. The value of shares constituting an award (as a percentage of salary) may vary by grade and seniority subject to a maximum (125% of annual salary for Mr. Jesanis, 60% of annual salary for Mr. Edwards, Mr. Buck, Mr. Cochrane, Ms. LaFleur, Mr. Kelleher and Mr. Tasker, and 40% of annual salary for Mr. Ash.). Awards were made at maximum applicable percentages in the fiscal year 2006/07. Shares vest after three years, subject to the satisfaction of the relevant performance criteria. Vested shares must then be held for a further year (the retention period) after which they are released. During the retention period, the Remuneration Committee has discretion to pay an amount, equivalent in cash or shares, to the dividend which would have been paid on the vested shares.

Under the terms of the Performance Share Plan, the Remuneration Committee may allow shares to vest early to a departing named executive to the extent the performance condition has been met, in which event the number of shares that vest are pro-rated to reflect the proportion of the performance period that has elapsed at the executive’s date of departure.

Performance Share Plan awards made in June 2003 and June 2004 were based on National Grid plc’s Total Shareholder Return (TSR) performance over a three-year period relative to the TSR performance of the following group of comparative companies:


Ameren Corporation		Iberdrola SA
AWG plc		International Power plc
Centrica plc		Kelda Group plc
Consolidated Edison, Inc.		Pennon Group plc
Dominion Resources, Inc.		RWE AG
E.ON AG		Scottish Power plc
Electrabel SA		Scottish & Southern Energy plc
Endesa SA		Severn Trent plc
Enel SpA		The Southern Company, Inc.
Exelon Corporation		Suez SA
FirstEnergy Corporation		United Utilities plc
FPL Group, Inc.		Viridian Group plc
Gas Natural SDG SA

Following consultation with the major National Grid plc shareholders, the performance conditions for awards under the Performance Share Plan were amended beginning with the June 2005 award. The change provided that 50% of any award be based on National Grid plc’s TSR

performance when compared to the FTSE 100 (as of June 27 2005) and 50% be based on the annualized growth of the National Grid plc’s EPS.

These measures were chosen because the Remuneration Committee believes they offer an improved balance between meeting the needs of shareholders (by measuring TSR performance against other large UK companies) and providing a measure of performance (EPS growth) over which the participating executives have direct influence. The Remuneration Committee considers the new Performance Share Plan performance conditions to be at least as challenging as the previous single performance criterion.

In calculating TSR for the fiscal year 2006/07 award, it is assumed that all dividends are reinvested. No shares will be released under the TSR part of the award if the National Grid plc’s TSR over the three-year performance period, when ranked against that of the FTSE 100 comparator group, falls below the median. For TSR at the median, 30% of those shares will be released; 100% will be released if National Grid plc’s TSR performance is 7.5% above that of the median company in the FTSE 100 (upper target).

The EPS measure is calculated by reference to National Grid plc’s real EPS growth - where annualized growth in EPS (excluding exceptional items and including continuing operations only) over the three-year performance period exceeds the average annual increase in RPI (the general index of retail prices for all items in the U.K., over the same period by 3% (threshold performance), 30% of the shares under the EPS part of the award will be released; 100% of the shares will be released where EPS growth exceeds RPI growth by 6% (upper target). As part of the Remuneration Committee’s proposals for fiscal year 2007/08 awards, required performance will be increased for 100% vesting of the shares for EPS growth exceeding RPI growth by 8% (upper target), which the Remuneration Committee considers to be more challenging.

For performance (for each target) between the threshold and the upper target, the number of shares released is calculated on a straight-line basis.

No re-testing of performance is permitted for any of the PSP awards that do not vest after the three-year performance period and any such awards lapse.

The performance criterion for the 2003 award was not reached and this award has lapsed in full.

Executive Share Option Plan.

In 2000, 2001 and 2002 certain named executives were provided grants of options to purchase National Grid plc ordinary shares at fair market value option pricing, dependent upon certain financial measures (performance conditions). Options were generally subject to an exercise window of between three and ten years following grant (with exceptions for death, and good leavers). If the performance condition is not satisfied after the relevant testing period, it is retested.

Options become exercisable if the full total shareholder return (TSR), measure over the period of three years beginning with the financial year in which the option is granted, is at least median compared with a comparator group of companies. Grants in excess of 100% of salary vest on a sliding scale, becoming fully exercisable if National Grid plc’s TSR is in the top quartile of comparative companies.

Options granted in March 2000 are vested. Options granted in June 2000 remain unvested. The June 2000 grants will continue to be tested annually throughout the testing period (due to expire June 5, 2010) Because the performance condition applicable to the June 2001 option was not met in March 2006, those options have lapsed and are no longer exercisable. The June 2002 grants are vested.

The comparator group for the 2000 grants is un-audited and this information follows below. The Remuneration Committee at that time believed the group to be an appropriate mix of energy distribution sector companies, including UK and international utilities.


Allegheny Energy, Inc.	Energy East Corporation	NSTAR	Scottish Power plc
BG Group plc	FPL Group, Inc.	Powergen plc	The Southern Company, Inc.
British Energy plc	GPU, Inc.	Progress Energy, Inc.	TXU, Corp
Central & South West Corp.	Innogy Holdings plc	Public Service Enerprise	United Utilities plc
Consolidated Edison, Inc.	International Power plc	Group, Inc.	Xcel Energy, Inc.
Duke Energy Corporation	Niagara Mohawk	Scottish & Southern
	Holdings, Inc.	Energy plc

The Executive Share Option Plan was replaced by the Performance Share Plan in 2003.

Stock Appreciation Rights.

This is a Company legacy plan that existed prior to the merger of the Company into National Grid USA in 2002. Stock appreciation rights (SARs) were granted under Company’s Long Term Incentive Plan prior to the merger. At the time of merger, outstanding grants of SARs were converted to SARs over National Grid ADSs using a specified exchange ratio. Named executive holders of SARs are all vested in the SARs. In addition to any increase in value of the SARs over time, a participant is entitled to dividend equivalents accumulated from the date of grant. SARs may be exercised during the exercise period, which is established upon each grant. SARs lapse on the earlier of fifteen years from the date of grant or the end of the exercise period, if earlier.

Other Compensation Programs

The compensation programs noted below are part of a comprehensive compensation and benefits program that is designed to attract and retain high quality executive talent with expertise in the relevant business operations of the National Grid companies, including the Company. National Grid, like many companies, has come together by a series of mergers and acquisitions. Some of the named executives participate in legacy arrangements that originated with the company for which they worked for at the time of the particular merger. Certain legacy programs are maintained in their original forms due to certain tax advantages (such as tax favorable life insurance arrangements) or due to the desire to retain continuity in programs with long term implications (such as qualified pension plan benefit designs). Where reasonably possible, arrangements are brought to a common platform over time.

Executive Life Insurance

The named executive officers, as well as all other executives and eligible management employees, receive employer paid individual life insurance. Some executives participate in the group term life insurance plan that is provided to all other employees, while other executives receive coverage through split dollar life insurance programs (the “Split Dollar Programs”). Under the Split Dollar Programs the employer pays life insurance policy premiums on policies owned by the executive, and the National Grid employer retains the right, through a collateral assignment agreement with the executive, to be reimbursed for premiums paid plus amounts available through the insurance policy(ies) in excess of the life insurance promise. Executives receive a reimbursement for imputed income attributable to annual life insurance coverage provided pursuant to the Split Dollar Programs.

Mr. Edwards receives death benefits of three times base salary both during employment and after termination from National Grid, which is payable to his named beneficiary grossed up for estimated taxes. Mr. Jesanis, Mr. Cochrane and Ms. LaFleur receive life insurance coverage of three times base salary both during employment and after termination from National Grid under Split Dollar Programs. Mr. Buck receives 4 times base salary life insurance coverage during employment, which is provided all or in part through the U.K. pension plan in which he participates in, Mr. Kelleher, Mr. Ash and Mr. Tasker all receive a life insurance benefit of two times base salary during employment through the all employee insured arrangement. The total cash surrender values of policies (amounts attributable to the executive and their employer) under applicable Split Dollar Programs as of March 31, 2007 for the applicable named executives are as follows: Mr. Jesanis — $169,252; Mr. Cochrane — $190,535; and Ms, LaFleur — $288,777.

Perquisites

In addition to providing perquisites to attract and retain executives, additional perquisites are provided in some cases to account for the difficulties an executive faces when asked to undertake an extraordinary assignment at personal sacrifice, such as a temporary overseas assignment.

Named executive officers are reimbursed for financial and estate planning up to certain limits. The reimbursements for financial and estate planning are grossed up for applicable income tax impacts.

All such perquisites (including applicable income tax gross-ups) are reflected in the All Other Compensation column of the Summary Compensation Table and the accompanying footnotes.

Post-Retirement and Post-Employment Plans

The following post-employment plans are available to executives:

•

qualified pension plans and supplemental retirement plans are discussed in detail in the narrative following the Pension Benefits table. A qualified pension plan is available to all employees in order to be competitive in the marketplace, to provide a tax effective method for us to fund retirement benefits, and to help attract and retain executives. In addition to the qualified plan participation, the named executive officers (excluding Mr. Buck) also participate in executive supplemental pension plans.

			These unfunded plans are maintained to provide named executive officers and other eligible employees with a pension benefit that will make up for the lost pension benefits that result from the Internal Revenue Code limits on the qualified plans, as well as, under certain circumstances, an enhanced formula and/or enhanced early retirement reduction factors. The retirement excess plans are provided in order to attract and retain qualified executives, which plans are common among companies that operate in similar industries to those of the National Grid plc companies. Mr. Edward, Mr. Kelleher, Mr. Ash and Mr. Tasker participated under the terms of a Company supplemental retirement plan up through the date of the merger of the Company with National Grid in 2002. The benefits payable under that plan (including those already distributed to Mr. Edwards and Mr. Kelleher immediately prior to the merger) are offset against the National Grid executive supplemental retirement plan benefits. For a more detailed discussion, see the disclosures following the 2006 Pension Benefits table below.

			The named executive officers (other than Mr. Buck) are entitled to retiree medical and life insurance coverage if they terminate employment after age 55 with age and service totaling 85 points at the time or if they terminated employment at age 60 or older with at least 10 years of service. Retiree medical coverage is available to all non-union employees of the Company and its U.S. based affiliates who meet either eligibility criteria. The level of benefit coverage depends upon several factors, including date of hire, age and service as of certain dates, and company of origin prior to the Company merger with National Grid. In addition, Mr. Jesanis, Mr. Cochrane and Ms. LaFleur qualify for executive retiree health care benefits supplemental to those they may become eligible to receive under the general non-union employee plan. The executive health care plan provides health care benefits commencing upon the earlier of termination of employment or the earliest date they are eligible to receive qualified pension plan benefits (generally age 55). The employer pays the full cost of coverage and reimburses the executive for taxes if, and to the extent, the benefits are delivered on a taxable basis. Mr. Edwards is entitled to post-employment health care and life insurance coverage through an agreement explained in more detail under the section “Employment, Severance and Change in Control Agreements.

	•		The named executives (excluding Mr. Buck) may elect to defer certain portions of their salary and bonuses into a deferred compensation plan. Deferral elections are generally allowed for 10 years, until separation from service, or to a specified age. These are unsecured promises from the applicable named executive’s National Grid employer. The plan is provided to allow executives an opportunity to defer income and associated income taxes on their compensation. In addition, when recruiting senior executives, the opportunity to defer compensation is an attractive feature in the recruitment process. The Deferred Compensation Plan is discussed in some detail in a narrative following the Nonqualified Deferred Compensation table.

	•		Change of control protection and severance benefits are provided in agreements with Mr. Edwards, Mr. Jesanis, Mr. Cochrane and Ms. LaFleur. Mr. Kelleher, Mr. Ash and Mr. Tasker are provided severance benefits under the terms of the National Grid USA Companies’ Executive Severance Plan (the “Executive Severance Plan”). Change of control severance benefits are discussed in detail in a narrative following the Nonqualified Deferred Compensation table. These individual agreement benefits and the Executive Severance Plan benefits are provided to ensure the continued employment of the executive leadership team during a period of time when there may be a great deal of uncertainty pending a major corporate event, including a change of control.

	•		Mr. Buck participated in a share matching plan prior to the plan’s replacement by the Executive Director’s Deferred Share Plan in June of 2006. The share matching plan was intended to encourage executives in the U.K. to purchase and retain shares in National Grid plc by investing part of their annual bonus in National Grid plc ordinary shares (Qualifying Shares). The National Grid U.K. employer matched that commitment with a right to acquire further ordinary shares(matching shares) at a nominal price, subject to retention of the Qualifying Shares and continued employment with National Grid.

Policy with Respect to Section 162(m) Deduction Limit

Under Section 162(m) of the Internal Revenue Code of 1986, as amended, compensation in excess of $1,000,000 paid in any year to the Chief Executive Officer or any of the other named executive officers cannot be deducted. This Section 162(m) limit does not apply to the Company.

Executive Stock Ownership Policy

Executive Directors are encouraged to build up and retain a shareholding of National Grid plc securities at a level of at least 100% of annual salary. As a minimum, this is expected to be achieved by retaining 50% of the after-tax gain on any options exercised or shares received through the long-term incentive or all-employee share plans.

Fiscal 2006/07 Summary Compensation Table


										Change in
										Pension Value
										and Nonqualified
										Deferred		All Other
Name and Principal			Salary			Bonus ($)		Stock		Compensation		Compensation ($)
Position	Year		($) (a)			(a) (b)		Awards (c)		Earnings ($) (d)		(e)		Total ($)
Michael E. Jesanis		2007		660,000			528,000		50,406		1,172,433		3,429,424		5,840,263
President & Chief Executive Officer (f)(j)

Cheryl A. LaFleur		2007		525,000	(i)		337,975		42,924		575,104		39,989		1,520,991
Acting President and Chief Executive Officer (j)

John G. Cochrane		2007		408,000			458,140		40,495		459,717		25,797		1,392,149
Senior VP and Director Mergers & Acquisitions (g) (j)

William F. Edwards		2007		456,000			245,680		44,251		45,212		7,300		798,442
President NY Distribution

Michael J. Kelleher		2007		211,833			107,607		24,677		54,247		6,910		405,274
Senior VP Business Services & Economic Development

Steven W. Tasker		2007		198,901			91,181		19,615		48,878		6,579		365,154
Senior VP NY Regulatory Affairs

Joseph T. Ash		2007		198,141			70,767		13,543		40,096		7,492		330,039
VP Regulatory Proceedings NY

Colin Buck		2007		338,602			151,887		181,354		433,400		254,654		1,359,897
Senior VP and Chief Financial Officer (h)


(a)		Includes deferred compensation in category and year earned.

(b)		The bonus figure represents cash bonuses and the fair market value of unrestricted securities of National Grid plc awarded under an incentive compensation plan and cash bonuses awarded under the all-employees goals program. For Mr. Edwards, it also includes a special cash bonus in the amount of $25,000, associated with the completion of certain corporate objectives. For Mr. Cochrane, it also includes special bonuses totalling $175,600 which mainly reflects payments for special UK-based projects, including to be in the U.K. for long periods and a special one time payment for managing the successful sale of the U.K. wireless business. For Mr. Buck, 60% of his award was paid in cash and the remaining 40% is payable in deferred National Grid plc shares under the Executive Director’s Deferred Share Plan. These shares remain in trust for a 3 year period.

(c)		Represents FAS 123R expense of equity awards under the various executive plans.


(d)				Earnings on Nonqualified Deferred
		Change in Pension Value		Compensation
	Michael E. Jesanis	$	1,140,251	$	32,182
	Cheryl A. LaFleur	$	566,443	$	8,661
	John G. Cochrane	$	454,884	$	4,833
	William F. Edwards	$	45,212	$	0
	Michael J. Kelleher	$	52,237	$	2,010
	Steven W. Tasker	$	48,878	$	0
	Joseph T. Ash	$	38,558	$	1,538
	Colin Buck	$	433,400	$	0


(e)	Other Compensation includes:
	Michael E. Jesanis	Severance Benefits	$	2,598,711
		Legal Service	$	19,117
		Gross up on Legal Services	$	12,950
		Financial Planning Services	$	7,475
		Gross up on Financial Planning Services	$	5,156
		UK Compromise Agreement	$	100
		Vacation Payout	$	124,383
		Thrift Plan Company Match	$	8,333
		Life Insurance Premiums	$	2,072
		Gross up on Life Insurance Premiums	$	1,423
		Post-employment Consulting Services	$	649,704
		Mr. Jesanis’ employment was terminated effective January 1, 2007. Mr. Jesanis has a 6 month consulting service agreement with National Grid whereby he will receive monthly payments of $216,568. Payments under this agreement made in fiscal year 2006/2007 have been included above.

	Cheryl A. LaFleur	Life Insurance Premiums	$	1,315
		Gross up on life insurance premiums	$	918
		Financial Planning Services	$	15,625
		Gross up on Financial Planning Services	$	10,985
		Thrift Plan Company Match	$	11,146

	John G. Cochrane	Life Insurance Premiums	$	1,224
		Gross up on life insurance premiums	$	835
		Financial Planning Services	$	7,475
		Gross up on Financial Planning Services	$	5,117
		Thrift Plan Company Match	$	11,146

	William F. Edwards	Imputed Income on Group Term Life Insurance	$	612
		Thrift Plan Company Match	$	6,688

	Michael J. Kelleher	Imputed Income on Group Term Life Insurance	$	540
		Thrift Plan Company Match	$	6,370

	Steven W. Tasker	Imputed Income on Group Term Life Insurance	$	612
		Thrift Plan Company Match	$	5,967


Joseph T. Ash	Imputed Income on Group Term Life Insurance	$	1,548
	Thrift Plan Company Match	$	5,944

Colin Buck	Allowances associated with overseas assignment	$	47,115
	Housing expenses	$	61,314
	Company paid taxes	$	129,707
	Company paid benefits associated with	$	3,960
	overseas assignment
	Car Allowance and associated expenses	$	11,848
	Life Insurance Premiums	$	710


(f)		Mr. Jesanis served as CEO of National Grid in the US. His employment terminated effective January 1, 2007.

(g)		Mr. Cochrane resigned as CFO of National Grid in the US on December 31, 2006 to take on a global position at National Grid.

(h)		Mr. Colin Buck is on assignment from the UK and was appointed as Senior VP and Chief Financial Officer of National Grid USA as of January 1, 2007. When paid in pounds sterling, a conversion rate of $1.97/1.00£ was used, which is the balance sheet exchange rate for the fiscal year ending March 31, 2007 that the National Grid companies use in translating/reporting results.

(i)		Includes salary supplement of $75,000 for Acting President & CEO position.

(j)		Mr. Jesanis, Mr. Cochrane and Ms. LaFleur performed services for affiliate companies. The amounts shown on this table and the other compensation tables represent their total compensation for the 2006/07 fiscal year for all services to all National Grid companies.

Grants of Plan Based Awards in Fiscal 2006/07


				Estimated Future Payouts				All Other Stock
				under Equity Incentive				Awards Number of		Grant Date Fair
				Plan Awards (a)				Shares of Stock (b)		Value of Stock
				Threshold		Maximum
	Grant Date			(#)		(#)		(#)
Jesanis, Michael		06/27/2006			6,131		20,435			$	1,100,000
LaFleur, Cheryl		06/27/2006			1,505		5,015			$	270,000
		05/08/2007							1,373	$	106,202
Cochrane, John		06/27/2006			1,137		3,789			$	204,000
		05/08/2007							1,145	$	88,566
Edwards, William F		06/27/2006			1,525		5,082			$	273,600
		05/08/2007							885	$	68,455
Kelleher, Michael		06/27/2006			593		1,978			$	106,500
		05/08/2007							432	$	33,415
Tasker, Steven		06/27/2006			669		2,229			$	120,001
		05/08/2007							365	$	28,233
Ash, Joseph		06/27/2006			444		1,479			$	79,643
		05/08/2007							280	$	21,658
Buck, Colin		06/27/2006			6,086		20,286			$	236,399
		06/14/2007	(c)						4,242	$	60,743


(a)		The table reflects grants made under the Performance Share Plan, under which the named executives received notional allocations of National Grid plc American Depositary Shares (ADSs). Mr. Buck, however, received notional allocations of National Grid plc ordinary shares. See the “Long-Term Incentive Compensation” section under the Compensation Program description for details regarding this 2006/07 grant.

(b)		For all named executives, except Mr. Buck, represents the 1/3 portion of the 2006/2007 fiscal year bonus paid in unrestricted shares under the Incentive Compensation Plan.

		For Mr. Buck, represents restricted shares that are deferred to the Executive Director’s Deferred Share Plan under which shares are held in trust for a 3 year period.

(c)		Exchange rate of $1.97/£1.00 used, which is the exchange rate for the National Grid companies’ balance sheet at March 31, 2007.

Stock Awards

There were no grants of stock options to the named executive officers during 2006/07. As noted earlier, the Executive Share Option Plan was replaced by the Performance Share Plan beginning with awards made in 2003. Outstanding options from previous grants are reflected in the Outstanding Equity Awards at Fiscal Year-End table.

Outstanding Equity Awards at Fiscal 2006/07 Year End


	Stock Options/SARs											Equity Incentive Plan Awards
	No of
	Securities		No of Securities
	underlying		Underlying					No. of		Market		No of
	unexercised		Unexercised	Option		Option		Shares		Value of		Unearned		Payout Value of
	Options (#)		Options (#)	Price ($)		Expiration		Not		Shares Not		Shares Not		Unearned Shares Not		Footbote
NEO	Exercisable		Unexercisable	(a)		Date		Vested		Vested		Vested		Vested (a)		Reference
Jesanis, Michael													19,987	$	1,575,175		b
													21,634	$	1,704,976		c
													20,435	$	1,610,482		d
									6,203		488,858						k
LaFleur, Cheryl													5,700	$	449,217		b
													5,260	$	414,541		c
													5,015	$	395,232		d
		73,344		$	11.160		03/31/2010										e
Cochrane, John													5,170	$	407,448		b
													4,574	$	360,477		c
													3,789	$	298,611		d
Edwards, William F													5,329	$	419,978		b
													4,481	$	353,148		c
													5,082	$	400,512		d
Kelleher, Michael													2,538	$	200,020		b
													2,122	$	167,235		c
													1,978	$	155,886		d
Tasker, Steven													2,284	$	180,002		b
													1,992	$	156,990		c
													2,229	$	175,667		d
		20,234		$	9.486		06/18/2012										f
		4,104		$	23.040		12/31/2010										g
Ash, Joseph													1,962	$	154,625		b
													1,394	$	109,861		c
													1,479	$	116,560		d
		21,723		$	9.486		06/18/2012										f
		4,104		$	26.200		12/31/2008										h
		4,104		$	26.200		12/31/2009										i

Stock Options/SARs

Equity Incentive Plan Awards

No of

Securities

No of Securities

Underlying

No. of

Market

No of

unexercised

Unexercised

Option

Value of

Unearned

Payout Value of

Options (#)

Price ($)

Expiration

Not

Shares Not

Unearned Shares Not

Footnote

NEO

Exercisable

Unexercisable

(a)

Date

Vested

Vested (a)

Reference

Ash, Joseph

4,104

23.040

12/31/2010

Buck, Colin

4,242

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Filing Compare · NIAGARA MOHAWK POWER CORP /NY/