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 year ended March 31, ~~2005~~2006


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

For the transition ~~period___________to______________~~period to


Commission	Registrant, State of Incorporation,	I.R.S. Employer
File Number	Address and Telephone Number	Identification Number

1-2987	Niagara Mohawk Power Corporation	15-0265555
	(a New York corporation)
	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)

(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 ~~(as~~a ~~defined~~nonaccelerated infiler. ~~Exchange~~See ~~Act~~definition of “accelerated filer” and “large accelerated filer” in Rule 12b-2). ~~YES~~of ~~o NO~~the þExchange Act.

~~State~~Large ~~the~~accelerated ~~aggregate~~filer ~~market~~o Accelerated ~~value~~filer ~~of the common equity held by non~~o Non-~~affiliates~~accelerated offiler ~~the registrant: N/A~~ 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

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 27, 2005~~	Shares Outstanding at June 20, 2006
Niagara Mohawk Power Corporation	Common Stock, $1.00 par value		~~187,364,863~~	187,364,863
	(all held by Niagara Mohawk
		(all held by Niagara Mohawk Holdings, Inc.)
	Holdings, Inc.)

NIAGARA MOHAWK POWER CORPORATION

TABLE OF CONTENTS

			PAGE	~~PAGE~~
	PART I	~~PART I~~
Item 1.	Business	~~Business~~		4	4
Item 2.		Properties			6
Item 1A.	Risk Factors			6
Item 3.		Legal Proceedings			7
Item 1B.	Unresolved Staff Comments			8
Item 4.		Submission of Matters to a Vote of Security Holders			7
Item 2.	Properties			8
		PART II
Item 3.	Legal Proceedings			9
Item 5.		Market for the Registrant’s Common Equity, Related Stockholders Matters and Issuer Purchases of Equity Securities			8
Item 4.	Submission of Matters to a Vote of Security Holders			9
Item 6.		Selected Consolidated Financial Data			8
	PART II
Item 7.		Management’s Discussion and Analysis of Financial Condition and Results of Operations			9
Item 5.	Market for the Registrant’s Common Equity, Related Stockholders Matters and Issuer Purchases of Equity Securities			9
Item 7A.		Quantitative and Qualitative Disclosures About Market Risk			21
Item 6.	Selected Consolidated Financial Data			9
Item 8.		Financial Statements and Supplementary Data			25
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations			10
Item 9.		Changes in and Disagreements with Accountants on Accounting and Financial Disclosure			61
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk			20
Item 9A.		Controls and Procedures			61
Item 8.	Financial Statements and Supplementary Data			24
Item 9B.		Other Information			62
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure			59
		PART III
Item 9A.	Controls and Procedures			59
Item 10.		Directors and Executive Officers of the Registrant			62
Item 9B.	Other Information			59
Item 11.		Executive Compensation			64
	PART III
Item 12.		Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters			70
Item 10.	Directors and Executive Officers of the Registrant			60
Item 13.		Certain Relationships and Related Transactions			70
Item 11.	Executive Compensation			62
Item 14.		Principal Accountant Fees and Services			70
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters			67
		PART IV
Item 13.	Certain Relationships and Related Transactions			68
Item 15.		Exhibits and Financial Statement Schedules			71
Item 14.	Principal Accountant Fees and Services			68
Signatures					74
	PART IV
EX-10(i)
Item 15.	Exhibits and Financial Statement Schedules			69
EX-10(j)
Signatures				71
EX-10(l)
EX-10(m)
Ex-10(n)
EX-10(o)
EX-10(p)
EX-10(r)
EX-10(u)
EX-10(v)
EX-21
EX-31.1
EX-31.2
EX-32

~~FORWARD-LOOKING~~Cautionary ~~INFORMATION~~Statement

This ~~report~~Annual ~~and~~Report ~~other~~on ~~presentations~~Form ~~made~~10-K byof Niagara Mohawk Power Corporation (the Company) ~~contain~~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. Throughout this report, forward -looking statements can be identified by the words or phrases “will likely result”, “are expected to”, “will continue”, “is anticipated”, “estimated”, “projected”, “believe”, “hopes”, or similar expressions. ~~Although~~Because ~~the Company~~these ~~believes~~forward-looking ~~that, in making any such~~ statements, ~~its expectations~~ are ~~based~~subject onto ~~reasonable~~ assumptions, ~~any~~ ~~such~~risks ~~statements~~and ~~may~~uncertainties, beactual ~~influenced~~future results bymay ~~factors~~differ ~~that~~materially ~~could~~from ~~cause~~those ~~actual~~expressed ~~outcomes~~in ~~and~~or ~~results~~implied ~~to differ~~by ~~materially~~such ~~from those projected~~statements. ~~Important~~Factors ~~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) ~~the~~changes ~~impact~~in of general economic ~~changes~~conditions in New York; (c) federal and state regulatory developments and changes in law, including those governing municipalization and exit fees; (d) ~~federal regulatory developments concerning regional transmission organizations; (e)~~ changes in accounting rules and interpretations, which may have an adverse impact on the Company’s statements of financial position, reported earnings and cash flows; (fe) 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; (hi) acts of terrorism; (ij) unseasonable weather, climatic changes or unexpected changes in historical weather patterns; and (jk) 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 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 1,600,000 electric customers in the areas of eastern, central, northern and western New York and sells, distributes, and transports natural gas to approximately ~~565~~569,000 gas customers in areas of central, northern and eastern New York.

~~On January 31, 2002,~~ Niagara Mohawk Holdings, Inc. (Holdings), the parent company of ~~Niagara~~the ~~Mohawk Power Corporation~~Company, ~~became~~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 ~~(NGT~~).

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 ~~New York Public Service Commission (~~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. ~~See Item 7 -~~ ~~Management’s Discussion and Analysis of Financial Condition and Results of Operations.~~

Merger Rate Plan: The Company’s ~~electricity~~ delivery rates are governed by a 10ten-year rate plan that ~~became~~began ~~effective~~ on ~~January~~ February 311, 2002~~, the closing of the merger~~. Under the plan, after reflecting ~~its~~the Company’s share of savings related to the acquisition, ~~the~~it ~~Company~~ may earn a threshold return on equity for ~~its~~the electricity distribution business of 10.6%, orup 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%, ~~and~~up ~~half~~to 14%, 25% of any earnings in excess of that ~~amount~~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 onannually athereafter ~~two~~for ~~year~~the ~~rolling~~prior ~~basis~~two calendar ~~thereafter~~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. ~~This~~Under the plan, gas delivery rates were frozen until the end ~~exclusion~~of ~~effectively~~the ~~offers~~2004 calendar year, after which the Company has the ~~potential~~right to ~~achieve~~request aan ~~return~~increase inat ~~excess~~any time, ofif ~~the regulatory~~needed. ~~allowed~~The Company may earn a threshold return ofon 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.

~~Under~~The ~~the Merger Rate Plan, the~~ Company resets its ~~competitive~~Competitive ~~transition~~Transition ~~charge~~Charges (CTC) in electricity rates every two years under its Merger Rate Plan (the Plan). The CTC reset is intended to account for changes in forecasted ~~the forecast of~~ electricity and natural gas commodity prices, and the effects those changes have on the Company’s above -market payments under legacy power contracts that ~~would~~ otherwise would be stranded. ~~The next CTC reset filing is~~In ~~scheduled for August 1~~addition, ~~2005~~the ~~and~~Merger asRate ~~part~~Plan ofallows ~~that filing,~~ the Company ~~is also authorized~~ to recover amounts exceeding $100 million in ~~the~~ its deferral accounts (as projected through the end of ~~the~~each two-year CTC reset period). In accordance with the Merger Rate Plan, 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 Company will include a proposal to recover the excess balance of the deferral accounts of $127 million and a projection through the end of the two year period in its August 1, 2005 filing. The Company’s deferral recovery is subject to regulatory review and approval of the PSC.

~~The~~from ~~Company~~the ~~collects~~levels of pension and post-retirement benefit expenses from the ~~transmission~~levels ~~business~~specified ~~revenues~~in ~~under~~the ~~several~~Plan, ~~Federal~~and various ~~Energy~~other ~~Regulatory~~items, including storms, environmental remediation costs, and various rate discounts. ~~Commission~~On ~~(FERC)~~July ~~rate~~29, ~~schedules~~2005, the Company filed its bi-annual CTC reset and ~~the~~deferral ~~state~~account ~~energy~~recovery ~~delivery~~filing to reset rates ~~discussed~~charged ~~above~~to customers beginning January 1, 2006. ~~Total~~In the July 29, 2005 filing, the ~~transmission~~Company ~~business~~included ~~revenues~~a ~~are~~proposal ~~determined~~to byrecover the ~~state-~~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 10the Company’s proposal for the new CTC effective January 1, 2006. The PSC also approved recovery of deferral account amounts of $100 million in calendar year 2006 and $200 million in calendar year 2007. For 2006, the actual deferral-related surcharge began in April 2006 and the full $100 million will be collected over the last nine months of the 2006 calendar year. ~~rate~~An ~~plan~~audit of the deferral amount by the Department of Public Service Staff (DPS Staff) is ongoing. A formal hearing process has been established before a hearing officer at the PSC to litigate the levels in the deferral account. Under the hearing schedule, the Staff will be filing testimony setting forth its initial adjustments in early August. The Company will continue to defer costs and revenues, as applicable, through the end of the Merger Rate Plan on December 31, 2011. The Company’s future filings for recovery of deferred amounts are subject to regulatory review and approval.

~~Under~~Electric ~~the~~Supply: ~~plan,~~Although ~~gas~~the ~~delivery~~Company ~~rates~~has ~~were~~exited ~~frozen~~the ~~until~~generation business, the ~~end~~Company ofmust ~~the~~still arrange ~~2004~~for ~~calendar~~electric ~~year,~~supply through a transition period and ~~the~~as provider of last resort. As such the Company ~~now~~will ~~has~~provide ~~the~~electricity ~~right~~to its customers who are unable or unwilling to ~~request~~obtain an alternative ~~increase~~supplier atwhich ~~any~~accounts ~~time,~~for ifapproximately ~~needed~~92% of the Company’s customers and 59% of its deliveries. The Company ~~may~~purchases ~~earn~~energy afrom various suppliers under long-term Purchase Power ~~threshold~~Agreements ~~return~~(PPAs) and purchases any additional power needs on ~~equity~~the ofopen upmarket tothrough ~~10%~~the orNew ~~12%~~York Independent ifSystem ~~certain~~Operator ~~customer~~(NYISO). ~~migration~~The ~~and~~Company ~~education~~also ~~goals~~enters into financial swaps in order to hedge ~~are~~the ~~met,~~price of electricity. For a discussion of the results of the power contracts and isseveral financial ~~required~~agreements to ~~share~~hedge ~~earnings~~the ~~above~~price ~~this~~of ~~threshold~~electricity, ~~with~~see ~~customers~~Part II, Item 8. Financial Statements and Supplementary Data — Note D – Commitments and Contingencies and Note L – Derivatives and Hedging Activities.

Electric ~~Supply~~Delivery: ~~Although~~As ~~the~~of ~~Company~~March 31, ~~has exited the generation business~~2006, the Company ~~must~~had ~~still arrange~~approximately ~~for~~52,000 ~~electric~~pole ~~supply~~miles ~~through~~of transmission ~~a transition period~~ and asdistribution ~~provider~~lines offor ~~last~~electricity ~~resort,~~delivery. inEvaluation ~~that~~of ~~the~~these facilities ~~Company~~relative ~~will provide electricity~~ to ~~its~~the ~~customers~~requirements ~~who~~of ~~are~~the ~~unable~~New orYork ~~unwilling~~State toReliability ~~obtain~~Council, anNortheast Power ~~alternative~~Coordinating ~~supplier~~Council, ~~(which~~North ~~accounts~~American ~~for~~Electric ~~approximately~~Reliability ~~93%~~Council, ofNYISO ~~the Company’s customers~~ and ~~64%~~PSC, oftheir orders, ~~its~~operating ~~deliveries).~~and ~~The~~planning ~~Company~~guides ~~purchases~~and ~~energy~~criteria, ~~from~~security ~~various~~considerations, ~~suppliers~~and ~~under~~anticipated ~~long-term Purchase~~Company ~~Power~~internal ~~Agreements (PPAs)~~ and ~~purchases~~external ~~any~~electrical ~~additional~~demands ~~power~~is ~~needs~~an onongoing ~~the~~process ~~open~~intended ~~market~~to ~~through~~maintain the ~~New~~reliability ~~York~~of ~~Independent~~electric ~~System Operator (NYISO)~~service. The Company ~~also~~continually ~~enters~~reviews ~~into~~the ~~financial~~adequacy ~~swaps~~of inits ~~order~~electric todelivery ~~hedge~~facilities ~~the~~and ~~price~~establishes ofcapital ~~electricity.~~requirements ~~For~~to asupport ~~discussion~~(within of the ~~results~~above ofprocesses) ~~the~~its ~~power contracts and several~~asset ~~financial agreements to hedge the price of electricity~~renewal, ~~see~~existing ~~Part~~load ~~II, Item 8. Financial Statements~~ and ~~Supplementary~~new ~~Data~~load —growth ~~Note D – Commitments and Contingencies and Note L – Derivatives and Hedging Activities~~needs.

~~Electric~~Gas ~~Delivery~~Supply: AsThe majority of ~~March 31, 2005,~~ the Company’s ~~had~~gas ~~approximately~~sales ~~52,000~~are ~~pole~~for ~~miles~~residential ~~of transmission~~ and ~~distribution~~commercial ~~lines for electric delivery~~space heating. ~~Evaluation~~The ofCompany ~~these~~purchases ~~facilities~~its ~~relative to~~natural ~~the~~gas ~~requirements~~under offirm ~~the~~supply ~~New~~agreements. ~~York~~The ~~State~~natural ~~Reliability Council, Northeast Power Coordinating~~gas ~~Council,~~purchased ~~North~~may ~~American~~be ~~Electric~~either ~~Reliability~~transported ~~Council,~~or ~~NYISO~~stored ~~and~~for ~~PSC,~~later ~~their~~transport ~~orders,~~on ~~operating~~a ~~and planning~~firm ~~guides~~basis ~~and criteria, security considerations, and anticipated Company internal and~~through ~~external~~interstate ~~electrical~~storage ~~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~~pipelines ~~requirements~~ to ~~support (within~~ the ~~above~~Company’s ~~processes) its asset renewal, existing load and new load growth needs~~system.

Gas ~~Supply~~Delivery: The ~~majority~~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 ~~gas~~distribution ~~sales~~areas are ~~for~~physically interconnected ~~residential~~with ~~and~~one ~~commercial~~another ~~space heating~~by its own facilities. The ~~Company~~gas ~~purchases~~distribution ~~its~~system is served by 3 interstate natural gas ~~under~~pipelines ~~firm~~regulated ~~supply~~by ~~agreements~~the FERC and one intrastate pipeline regulated by the PSC. The ~~natural~~Company ~~gas purchased~~has ~~may~~nineteen bedirect ~~either~~connections ~~transported~~with orDominion ~~stored~~Transmission, ~~for~~Inc., ~~later~~two ~~transport~~with Iroquois onGas aTransmission, ~~firm~~one ~~basis~~with ~~through interstate~~Tennessee ~~storage~~Gas ~~facilities~~Pipeline and ~~pipelines~~one towith ~~the~~Empire ~~Company’s~~State ~~system~~Pipeline (intrastate).

~~Gas Delivery: The Company sells, distributes and transports natural gas to a geographic territory~~5 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. Presently there are 12 separate distribution zones connected to 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).

ComplianceTable 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 Contents

5Compliance 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.

~~Table~~The Company has implemented an environmental audit program to identify any potential areas of concern ~~Contents~~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.

~~site~~Employee ~~remediation.~~Relations: The Company’s ~~believes~~work itforce isat ~~handling~~March 31, ~~identified~~2006 ~~wastes~~numbered ~~and~~approximately ~~by-products~~4,300 employees, inof ~~a manner~~whom ~~consistent~~approximately ~~with~~82% ~~applicable~~were ~~requirements~~union members. The ~~environmental~~Company ~~management~~also ~~systems~~receives ~~for the~~substantial ~~Company’s~~support ~~distribution,~~for ~~transmission~~its ~~and~~activities ~~investment~~from ~~recovery~~employees ~~facilities~~of ~~are~~National ~~certified~~Grid toUSA ~~the International~~Service ~~Organization~~Company, ~~for Standardization (ISO) 14001 standard~~Inc., ~~Management~~an ~~believes it is~~affiliate ~~probable~~ that ~~costs~~provides ~~associated~~administrative ~~with~~services ~~environmental~~support ~~compliance will continue~~ to beall ~~recovered~~National ~~through the~~Grid ~~ratemaking process~~companies. The Company~~’s compliance has no material effect on its capital~~ ~~expenditures,~~reimburses ~~earnings or competitive position. For a discussion of~~ the Service Company’s ~~reserves~~ for ~~environmental~~ ~~liabilities~~the ~~and~~costs ~~its~~associated ~~ability~~with tothose ~~recover these types of expenditures in rates, see Part II, Item 8~~services. ~~Financial Statements and Supplementary Data –~~ ~~Note B - Rate and Regulatory Issues.~~

The Company ~~has~~believes ~~implemented~~relations ~~an environmental audit program to identify any potential areas of concern and aid in compliance~~ with ~~legal~~employees ~~requirements.~~are 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 contributedgood. ~~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~~Seasonality: ~~The~~There ~~Company’s~~is ~~work~~seasonal ~~force~~variation atin ~~March 31,~~electric ~~2005~~customer ~~numbered approximately 4~~load,~~600,~~ ~~of whom~~usually ~~approximately~~peaking ~~83 percent~~in ~~were~~the ~~union members. The Company, however, also receives substantial~~winter ~~support~~and ~~for~~summer ~~its activities from employees of National Grid USA Service Company, Inc~~months. ~~(Service Company),~~The anseasonality ~~affiliated~~is ~~company~~correlated ~~that~~with ~~provides~~the ~~administrative~~colder ~~services~~or ~~support~~warmer totemperature ~~all National Grid~~because ~~USA~~more ~~companies.~~electricity ~~The~~is ~~Company~~used ~~reimburses Service Company~~ for ~~the~~heating ~~costs~~or ~~associated~~cooling ~~with~~during those ~~services~~ months.

InThere ~~October 2004,~~is wea ~~entered~~seasonal ~~into~~variation ain ~~new~~gas ~~42-month~~customer ~~contract~~sales, with ~~our~~loads ~~labor~~usually ~~union.~~peaking ~~The~~in ~~new~~the ~~contract~~winter ~~will~~months. ~~allow~~The usseasonality tois ~~increase~~correlated ~~productivity~~with ~~through~~colder ~~more~~temperatures ~~efficient~~when ~~working~~more ~~practices~~gas ~~and~~is toused ~~improve safety~~for ~~and services~~heating. ~~We believe our relations with employees are good.~~

~~Seasonality:~~Also ~~There~~see ~~is seasonal variation in electric customer load~~Part II, ~~usually~~Item 8. ~~peaking~~Financial inStatements ~~the winter~~ and ~~summer~~Supplementary ~~months.~~Data ~~The~~— ~~seasonality~~Note isO- ~~correlated~~Quarterly ~~to the colder or warmer temperature in that more~~Financial ~~electricity~~Data ~~is used for heating or cooling during those months~~(unaudited).

~~There~~ITEM ~~is a seasonal variation in gas customer sales, with loads usually peaking in the winter months~~1A. ~~The~~RISK ~~seasonality is correlated to the colder temperatures in that more gas is used for~~FACTORS ~~heating during those months.~~

~~Also~~This ~~see~~Annual ~~Part~~Report ~~II,~~on Form 10-K contains certain statements that are neither reported financial ~~Item 8.~~results ~~Financial~~nor ~~Statements~~other ~~and~~historical ~~Supplementary~~information. ~~Data~~These statements are forward-looking ~~Note~~statements Pwithin the meaning of Section 21E of the Securities Exchange Act of 1934, as amended. Because these forward-looking ~~Quarterly~~statements ~~Financial~~are subject to assumptions, risks and uncertainties, actual future ~~Data~~results ~~(unaudited)~~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

~~ITEM 2. PROPERTIES~~6

ElectricTable Transmission and Distribution: As of March 31, 2005, the Company’s electric transmission and distribution systems were composed of: Contents

	•		748 substations with a rated transformer capacity of approximately 22,800,000 kilo-volt-amperes
	•		approximately 9,400 pole miles of overhead and underground transmission lines

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.

6Regulatory and environmental risks

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

	•		approximately 36,000 conductor primary structure miles of overhead distribution lines
	•		about 6,300 cable primary structure miles of underground distribution cables

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.

ABreaches ~~portion~~ of ~~the~~or ~~Company’s~~changes ~~transmission~~in ~~and~~environmental ~~distribution~~or ~~lines~~health ~~are~~and ~~located~~safety onlaws ~~property~~or ~~owned~~regulations bycould ~~the Company.~~expose ~~With~~us ~~respect~~ to claims ~~the~~for ~~Company’s~~financial ~~transmission~~compensation and ~~distribution~~adverse ~~lines~~regulatory ~~that are located on property not owned by the Company~~consequences, ~~the~~as ~~Company’s~~well ~~practice~~as isdamaging ~~to obtain right of way agreements~~our reputation.

~~The~~Aspects ~~electric~~of ~~system~~our activities are potentially dangerous, such as the operation and maintenance of electricity lines and the ~~Company~~transmission isand ~~directly~~distribution ~~interconnected~~of ~~with~~natural ~~other~~gas. ~~electric~~Energy ~~utility~~delivery ~~systems~~companies also typically use and generate in ~~New~~their ~~York~~operations hazardous and potentially hazardous products and by-products. In addition, ~~Massachusetts~~there may be other aspects of our operations that are not currently regarded or proved to have adverse effects but could become so, ~~Vermont~~for example, ~~Pennsylvania~~the effects of electric and magnetic fields. We are subject to laws and regulations relating to pollution, the protection ~~Canadian~~of ~~provinces~~the environment and how we use and dispose of ~~Ontario~~hazardous substances and waste materials. We are also subject to laws and ~~Quebec,~~regulations governing health and ~~indirectly~~safety ~~interconnected~~matters including ~~with~~air ~~most~~quality, water quality, waste management, natural resources and the health and safety of the ~~electric~~public ~~utility~~and ~~systems~~our ~~through~~employees. Any breach of these obligations, or even incidents relating to the ~~Eastern~~environment ~~Interconnection~~or ofhealth and safety that do not amount to a breach, could adversely affect the ~~United~~results of ~~States~~operations and ~~Canada~~our reputation.

~~Gas~~Changes ~~Distribution:~~to ~~The Company distributes gas that it purchases from suppliers and transports gas owned by others. As of March 31, 2005,~~ the ~~Company’s~~regulatory ~~natural~~treatment ~~gas delivery system was comprised~~ of ~~approximately~~ ~~8,500~~commodity ~~miles~~costs ofmay ~~pipelines.~~have ~~Only~~an aadverse ~~small~~effect ~~part of these natural gas pipelines and mains are located~~ on ~~property owned by~~ the ~~Company.~~results ~~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~~operations.

~~Native~~Changes ~~American~~in ~~Matters:~~commodity ~~The~~prices ~~Company’s~~could ~~facilities are~~ potentially ~~affected~~affect byour ~~land~~energy ~~claim litigation~~delivery ~~involving the Cayuga, Oneida, Mohawk, Seneca and Onondaga Nations~~businesses. AOur ~~court~~rate ~~has awarded~~plan ~~damages~~permits us to ~~the~~pass ~~Cayuga~~through ~~Nation~~virtually ~~that~~all ~~are~~of ~~payable by~~ the ~~State~~increased ofcosts ~~New~~related ~~York.~~to ~~The~~commodity ~~land~~prices ~~claim litigation~~to ~~has~~consumers. ~~not been resolved~~However, ~~although~~if ~~the~~this ~~St.~~ability ~~Regis~~were ~~Mohawk~~restricted, ~~Tribe~~it ~~recently entered into a settlement with New York State that~~ could ~~lead~~have toan ~~resolution~~adverse ofeffect ~~the~~on ~~Mohawk’s land claims against parties including~~our ~~the~~operating ~~Company~~results. ~~The Company continues to monitor the land claim litigation and, where necessary,~~ ~~defends its interests.~~

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

~~ITEM~~Network 3.failure ~~LEGAL~~or ~~PROCEEDINGS~~the inability to carry out critical non-network operations may have significant adverse impacts on both our financial position and our reputation.

~~During~~We ~~the~~may ~~last~~suffer ~~quarter~~a ofmajor ~~the~~network ~~fiscal~~failure ~~year~~or ~~ended~~may ~~March 31,~~not ~~2005,~~be ~~the~~able ~~Company~~to ~~settled~~carry ~~New~~out ~~York~~critical ~~State~~non-network voperations. ~~Niagara~~Operational ~~Mohawk~~performance ~~Power~~could ~~Corp.~~be etadversely ~~al.~~affected ~~The~~by ~~New~~a ~~York~~failure ~~State~~to ~~Attorney~~maintain ~~General~~the health ~~had~~of ~~filed~~the asystem ~~civil~~or ~~action against~~network, ~~the~~inadequate ~~Company,~~forecasting ~~NRG~~of ~~Energy,~~demand ~~Inc~~or inadequate record keeping. This could cause us to fail to meet agreed standards, and ~~certain~~even ofincidents ~~NRG’s~~that ~~affiliates~~do not amount to a breach could result in ~~U.S.~~adverse ~~District~~regulatory ~~Court~~action ~~for~~and financial consequences, as well as harming our ~~the~~reputation. ~~Western~~In ~~District~~addition ofto ~~New~~these ~~York~~risks, ~~for~~we ~~alleged~~are ~~violations~~subject ofto ~~the~~other ~~Federal~~risks ~~Clean~~that ~~Air~~are ~~Act,~~largely ~~related~~outside ~~state~~of ~~environmental~~our ~~statutes~~control ~~and~~such as the ~~common~~impact ~~law~~of atweather ~~the~~or ~~Huntley~~unlawful ~~and~~acts ~~Dunkirk~~of ~~power~~third ~~plants~~parties. InWeather ~~January~~conditions ~~2005,~~can ~~the~~affect ~~Company~~financial performance, ~~the State~~ and ~~the~~severe ~~NRG~~weather ~~companies~~that ~~asked~~causes ~~the~~outages ~~Court~~or todamages ~~approve~~infrastructure will aadversely ~~settlement~~affect ~~that would~~operational ~~fully~~and ~~resolve~~potentially, ~~all~~business ~~claims~~performance. ~~asserted~~Terrorist inattack, ~~the~~sabotage or ~~litigation.~~other Anintentional ~~order~~acts ~~was~~may ~~issued~~also byphysically ~~the~~damage ~~Court~~our ~~on June 3,~~infrastructure ~~2005,~~or ~~approving~~otherwise ~~the~~significantly affect ~~settlement~~our activities and, ~~stating~~as ~~that~~ a ~~full~~consequence, ~~decision~~affect ~~will~~the ~~follow~~results of operations.

~~ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS~~7

NoTable matters were submitted to a vote of security holders during the last quarter of the fiscal year ended March 31, 2005. On May 5, 2005, by unanimous written consent of the sole common stockholder, Contents

7Our reputation may be harmed if customers suffer a disruption to their energy supply even if this disruption is outside of our control.

~~Table~~We ofare ~~Contents~~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.

	•		The following persons were elected as directors: William F. Edwards, Michael E. Jesanis, Clement E. Nadeau, Kwong O. Nuey, Jr. and Anthony C. Pini.
	•		The firm of PricewaterhouseCoopers LLP, an independent registered public accounting firm, was appointed the Company’s auditor for the fiscal year ending March 31, 2006.

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

~~PART~~Earnings IImaintenance 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 51B. ~~MARKET~~UNRESOLVED ~~FOR~~STAFF ~~THE REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDERS MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES~~COMMENTS

~~The common stock of the Company is held solely by Holdings, and therefore indirectly by National Grid and NGT.~~ There isare no ~~public~~unresolved ~~trading~~SEC ~~market~~staff ~~for~~comments ~~the~~required ~~Company’s~~to ~~common~~be ~~stock.~~reported ~~The~~under ~~Company~~this ~~did not purchase any of its equity securities during the fourth quarter of fiscal 2005. For information about the Company’s payment of dividends and restrictions on those payments, see~~ Item ~~6. Selected Consolidated Financial Data and Item~~ 81B. ~~Financial Statements and Supplementary Data.~~

ITEM 62. ~~SELECTED CONSOLIDATED FINANCIAL DATA~~PROPERTIES

AtElectric ~~the~~Transmission ~~time~~and ofDistribution: ~~the~~As ~~merger~~of ~~with National Grid, the Company changed its fiscal year from a calendar year ending December 31 to a fiscal year ending~~ March 31., ~~The Company made this change in order to align its fiscal year with that of its new parent company~~2006, ~~National~~the ~~Grid. The~~ Company’s ~~first~~electric ~~new~~transmission ~~full fiscal year began on April 1, 2002~~ and ~~ended~~distribution onsystems ~~March 31,~~were ~~2003.~~composed of:

~~The~~• ~~following~~717 ~~tables~~substations ~~set~~with ~~forth~~a ~~selected~~rated ~~financial~~transformer ~~information~~capacity ~~for~~of ~~the~~approximately ~~Company for the years ended March 31~~23, ~~2005~~090,000 ~~2004~~kilo-volt-amperes; ~~and~~• ~~2003~~approximately 9,400 ~~the~~pole ~~sixty~~miles ~~day~~of ~~period~~overhead ~~ended~~and ~~March 31,~~underground ~~2002,~~transmission ~~the~~lines; ~~thirty~~• ~~day~~approximately ~~period ended January 30~~36,000 ~~2002,~~conductor ~~the~~primary ~~three~~structure ~~months~~miles ~~ended~~of ~~March 31,~~overhead ~~2001,~~distribution ~~the~~lines; ~~years ended December 31, 2001~~ and ~~2000.~~• ~~These~~about ~~tables~~6,500 ~~have~~cable ~~been~~primary ~~derived~~structure ~~from~~miles ~~the financial statements~~ of ~~the~~underground ~~Company~~distribution ~~and should be read in connection therewith~~cables.

OnA ~~January 31,~~portion ~~2002,~~of the Company’s ~~was~~transmission ~~acquired~~and bydistribution ~~National~~lines ~~Grid~~are inlocated aon ~~purchase~~property ~~business~~owned ~~combination recorded~~by ~~under~~ the ~~“push-down” method of accounting, resulting in a new basis of accounting for the~~ ~~“successor” period beginning January 31, 2002~~Company. ~~Information~~With ~~relating~~respect to ~~all “predecessor” periods prior to~~ the ~~acquisition is presented using the~~ Company’s ~~historical~~transmission ~~basis~~and ofdistribution ~~accounting.~~lines ~~The following~~that ~~selected~~are ~~financial~~located ~~data~~on property ~~for the Company may~~ not beowned ~~indicative~~by ofthe Company, the Company’s ~~future financial~~practice ~~condition,~~is ~~results~~to ofobtain ~~operations~~right orof ~~cash~~way ~~flows~~agreements.

							60 Day		30 Day			Three
							Period		Period			months
	Year Ended		Year Ended		Year Ended		Ended		Ended			Ended
	March 31,		March 31,		March 31,		March 31,		January 30,			March 31,		Year Ended December 31,
(in 000’s except	2005		2004		2003		2002		2002			2001		2001		2000
Per share data)	(Successor)		(Successor)		(Successor)		(Successor)		(Predecessor)			(Predecessor)		(Predecessor)		(Predecessor)
Operating revenues	$	3,925,171	$	4,063,617	$	4,019,450	$	689,705	$	362,622		$	1,179,706	$	4,114,713	$	3,865,949
Net income (loss)		263,249		139,690		125,871		30,646		(20,941	)		34,010		19,358		(27,646	)
Income (loss) from		*		*		*		*		*			*		*		*
continuing operations per average common share

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, the Company’s natural gas delivery system was comprised of approximately 8,600 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.

~~Table~~Native ofAmerican ~~Contents~~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.

60 Day

30 Day

Three

Period

months

Year Ended

Ended

March 31,

January 30,

March 31,

Year Ended December 31,

(in 000’s except

2005

2004

2003

2002

2001

2000

Per share data)

(Successor)

(Predecessor)

Total assets

12,518,362

12,618,659

12,549,865

12,101,588

12,037,039

11,436,554

12,270,324

Long-term debt

2,923,569

3,473,467

3,953,989

4,146,642

4,674,004

4,419,822

4,678,963

Mandatorily redeemable

—

53,750

50,700

53,750

preferred stock

Dividends paid per

common share

*		All of the Company’s shares of common stock are owned by its parent company. Therefore, management considers 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~~Mortgage 7.Liens: ~~MANAGEMENT~~Substantially all of the Company’Ss ~~DISCUSSION~~operating ~~AND~~properties ~~ANALYSIS~~are OFsubject ~~FINANCIAL~~to ~~CONDITION~~mortgage liens ~~AND~~securing ~~RESULTS~~its OFmortgage ~~OPERATIONS~~debt.

~~Merger~~ITEM ~~with National Grid: On January 31, 2002, the acquisition of Holdings by National Grid was completed for a value of approximately $~~3.~~0 billion~~ inLEGAL ~~cash and American Depositary Shares. The~~PROCEEDINGS acquisition 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 HoldingsNone. ~~The merger transaction resulted in approximately $1.2 billion of goodwill.~~ ~~The purchase accounting method required the Company to revalue its assets and liabilities at their~~ fair value. This revaluation resulted in an increase to the Company’s pension and postretirement benefit liability in the amount of approximately $440 million, with a corresponding offsetting increase to a regulatory asset account. See Item 8. Financial Statements and Supplementary Data, - Note H - Employee Benefits for a discussion of the Company’s pension and postretirement benefit plans.

~~VEROs:~~ITEM In4. ~~fiscal~~SUBMISSION ~~2004,~~OF ~~National~~MATTERS ~~Grid~~TO made a voluntary early retirement offer (VERO) to eligible non-union employees in areas including transmission and corporate administrative functions such as finance, human resources, legal and information technology. A ~~total~~VOTE ofOF 53SECURITY ~~employees of the Company~~HOLDERS accepted the VERO. The majority of them retired by November 1, 2004, with the remainder retiring by November 1, 2007. The Company expensed approximately $19 million of VERO costs in fiscal year 2004. This amount included approximately $9 million allocated to the Company from Service Company, an affiliate.

InNo ~~January 2002,~~matters ~~the~~were ~~Company~~submitted ~~made~~to a ~~VERO~~vote toof ~~302~~security ~~eligible~~holders ~~non-union~~during ~~employees in targeted areas where significant workforce reductions were necessary in~~ the ~~combined~~last ~~organization,~~quarter ~~primarily corporate administrative functions such as finance, human resources, legal and information technology. The number~~ of ~~eligible employees that accepted~~ the ~~VERO~~fiscal ~~was 267 and most retired by~~year ~~June 30,~~ended ~~2002, with the last employees retiring by~~ March 31, ~~2004~~2006. Under the Merger Rate Plan, the Company is allowed to record a regulatory asset for separation and early retirement costs. The amortization of such regulatory asset is occurring over ten years, with approximately 69 percent of the amortization of the regulatory asset occurring within the first three years. On ~~January~~May 313, ~~2002~~ 2006, ~~the~~by ~~Company~~unanimous ~~recorded~~written aconsent ~~regulatory asset~~ of ~~$53 million related to~~ the ~~VERO.~~sole ~~This~~common ~~regulatory asset had a balance of approximately $16 million and $22 million at March 31~~stockholder, ~~2005 and 2004,~~ ~~respectively.~~

Retail Bypass: A number of generators have complained or withheld payments associated with the Company’s delivery of station service to their generation facilities, arguing that they should be

	o		The following persons were elected as directors: William F. Edwards, Barbara A. Hassan, Michael E. Jesanis, Michael J. Kelleher, Cheryl A. LaFleur, Clement E. Nadeau, and Anthony C. Pini.

	o		PricewaterhouseCoopers LLP was appointed the Company’s independent registered public accounting firm for the fiscal year ending March 31, 2007.

9PART II

~~Table~~ITEM of5. ~~Contents~~MARKET FOR THE REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDERS MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

~~permitted to bypass its retail charges.~~ The ~~FERC~~common ~~has~~stock ~~issued~~of ~~three~~the ~~orders~~Company ~~that~~is ~~directly~~held ~~conflict with~~solely by Niagara Mohawk’s ~~state-approved~~Holdings, ~~tariffs~~Inc., and ~~the~~therefore indirectly ~~orders~~by ofNational ~~the~~Grid ~~PSC~~and onNational ~~station~~Grid ~~service rates~~plc. ~~These~~ ~~orders,~~There ifis ~~upheld,~~no ~~will~~public ~~permit~~trading ~~these~~market ~~generators~~for ~~to bypass Niagara Mohawk~~the Company’s ~~state-jurisdictional~~ ~~station~~common ~~service charges for electricity~~stock. ToThe ~~the~~Company ~~extent~~did ~~that~~not ~~the~~purchase ~~Company experiences~~ any ~~lost~~of ~~revenue~~its ~~attributable~~equity tosecurities ~~retail~~during ~~bypass, it is permitted to recover these lost~~the ~~revenues~~fourth ~~under~~quarter ~~its~~of ~~rate~~fiscal ~~plans~~2006. For ~~further~~information ~~details~~about ofthe ~~these~~Company’s ~~orders~~payment of dividends and restrictions ~~the~~on ~~related~~those ~~proceedings~~payments, see Item 86. ~~Financial~~Selected ~~Statements~~Consolidated ~~and~~Financial ~~Supplementary~~Data ~~Date, Note D – Commitments~~ and ~~Contingencies, under the captions “Retail Bypass” and “Niagara Mohawk Power Corp~~Item 8. ~~v. Huntley Power L.L.C., Dunkirk~~ ~~Power~~Financial ~~L.L.C.~~Statements and ~~Oswego~~Supplementary ~~Harbor, L~~Data.~~L.C.”~~

~~PSC~~ITEM ~~Issues: 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~~6. ~~In addition,~~SELECTED ~~the~~CONSOLIDATED ~~agreement~~FINANCIAL ~~covers the funding of the entire settlement loss to benefit plan trust~~DATA funds. The Company has filed a petition with the PSC seeking recovery of a $21 million pension settlement loss incurred in fiscal year 2004. For further discussion of the settlement losses, see Item 8. Financial Statements and Supplementary Data — Note H — Employee Benefits.

AsAt ~~part of~~ the ~~Company’s~~time ~~ongoing reconciliation~~ of ~~commodity~~the ~~costs~~merger ~~and~~with ~~revenues~~National Grid, the Company ~~identified~~ ~~several~~changed ~~adjustments~~its ~~for~~fiscal ~~the~~year ~~period~~ from ~~October 1,~~a calendar ~~2001~~year ~~through~~ending ~~April~~December ~~30,~~31 ~~2003,~~to ~~and included~~a ~~them~~fiscal inyear ~~filings~~ending ~~with the PSC~~March 31. ~~Specifically,~~The ~~the~~ Company ~~requested~~made ~~recovery of $36 million~~this ofchange ~~commodity~~in ~~costs~~order ~~associated~~to ~~with~~align ~~the under-reconciliation of New York Power Authority (NYPA) hydropower revenues in~~ its ~~commodity~~fiscal ~~adjustment~~year ~~clause, and proposed to refund $24 million associated~~ with ~~other revenues~~ that ~~were~~of ~~not~~its ~~included~~parent incompany, ~~the~~National ~~commodity adjustment reconciliation~~Grid. ~~Following~~The ~~the filing, the PSC Staff completed a comprehensive audit of the~~ Company’s ~~commodity costs~~first ~~and~~new ~~revenues~~full ~~from~~fiscal ~~October 1,~~year ~~2001~~began ~~through~~on ~~December~~April 311, ~~2003,~~2002 and ~~the~~ended ~~Staff and the Company agreed that a refund of $2.8 million should be provided to customers through that period. The PSC approved the refund~~ on ~~December~~March 2031, ~~2004~~ 2003.

~~Elevated equipment voltage:~~ The ~~PSC~~following ~~issued~~tables anset ~~order~~forth onselected ~~January 5,~~financial ~~2005,~~information ~~requiring~~for ~~all electric utilities in~~ the ~~state~~Company ~~to test annually all of their publicly accessible transmission and distribution facilities~~ for ~~elevated equipment voltage and perform visual inspections of all~~the ~~facilities~~years onended ~~a five year schedule. As anticipated in the July~~March ~~2004~~31, ~~order~~2006, ~~proposing the guidelines~~2005, the order contains strict compliance requirements and potential financial penalties for failure to achieve testing and inspection targets. Failure to meet the annual target for performing tests will result in a 0.75% reduction in return on equity2004, ~~as will failure to meet the annual target for inspections. The costs to comply with this order are expected to be significant. Under its existing rate plan~~2003, the ~~Company~~sixty isday ~~eligible~~period toended ~~recover through rates that portion of its costs that the PSC considers incremental. The Company~~March 31, ~~together with other utilities~~2002, ~~has filed~~ ~~for~~the ~~rehearing~~thirty onday ~~certain~~period ~~aspects~~ended ~~of this order~~January 30, ~~including a request for more time to test remote areas of the service territory~~2002, ~~a challenge to~~ the ~~PSC~~three ~~authority~~months toended ~~impose~~March 31, ~~penalties for non-compliance~~2001, and ~~clarification that the PSC did not intend to impose a different standard for~~ ~~cost recovery for these programs than is otherwise specified in~~ the ~~Company’s~~year ~~pre-existing~~ended ~~rate plan~~December 31, ~~among other clarifications~~2001. InThese ~~February~~tables ~~the~~have ~~Company~~been ~~filed~~derived ~~plans~~from ~~for~~the ~~testing and inspections~~financial asstatements ~~required~~of by the ~~PSC~~Company and ashould ~~petition~~be toread ~~request~~in anconnection ~~extended schedule to complete testing~~therewith.

~~CRITICAL~~On ~~ACCOUNTING~~January 31, ~~POLICIES~~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.

~~The preparation of financial statements in conformity with generally accepted accounting principles~~9 ~~in the United States of America requires management to apply policies and make estimates and assumptions that affect results of operations and the reported amounts of assets and~~

10 Table of Contents


													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			*			*			*			*			*			*			*			*

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.


*		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.

~~Regulatory~~ITEM Assets and Liabilities: Regulatory assets represent costs that have been deferred to future periods when it is probable that the regulator (being the FERC, PSC, or other regulatory body having jurisdiction) will allow future recovery of those costs through rates7. ~~The~~MANAGEMENT’S ~~Company bases~~DISCUSSION ~~its~~AND ~~assessment~~ANALYSIS ofOF ~~recovery~~FINANCIAL byCONDITION ~~either~~AND ~~specific~~RESULTS ~~recovery~~OF 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”. OPERATIONS

The ~~Company~~Business: ~~continually~~The ~~assesses~~Company’s ~~whether~~primary ~~the~~business ~~regulatory~~driver ~~assets~~is ~~continue~~the tolong-term ~~meet~~rate ~~the~~plan ~~criteria~~with ~~for~~state ~~probability~~regulators ofthrough ~~future~~which ~~recovery.~~the ~~This~~Company ~~assessment~~can ~~considers~~earn ~~factors~~and ~~such~~retain ascertain ~~changes~~amounts in ~~the~~excess ~~regulatory~~of traditional ~~environment,~~regulatory ~~recent~~allowed ~~rate~~returns. ~~orders~~The toplan ~~other~~provides ~~regulated~~incentive ~~entities~~returns ~~under~~and ~~the~~shared ~~same~~savings ~~jurisdiction,~~allowances ~~and~~which allow the ~~status~~ ofCompany ~~any~~an ~~pending~~opportunity orto ~~potential~~benefit ~~deregulation~~from ~~legislation.~~efficiency Ifgains ~~future~~identified ~~recovery~~within ofoperations. Other ~~costs~~main ~~becomes~~business ~~no longer~~drivers ~~probable,~~for the ~~assets~~Company include the ability to streamline operations, enhance reliability and ~~liabilities~~generate ~~would~~funds befor ~~recognized~~investment asin ~~current-period~~the ~~revenue~~Company’s ~~or expense~~infrastructure.

~~Amortization~~CRITICAL ofACCOUNTING ~~regulatory assets is provided over the recovery period as allowed in the related~~POLICIES regulatory agreement. Amortization of the stranded cost regulatory asset is shown separately (as 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).

~~Unbilled~~The ~~Revenues:~~preparation ~~Revenues~~of ~~from~~financial ~~the~~statements ~~sale~~in ofconformity ~~electricity~~with ~~and~~generally ~~gas~~accepted toaccounting ~~customers are generally~~principles ~~recorded~~in ~~when~~the ~~electricity~~United ~~and~~States ~~gas~~of ~~are~~America ~~delivered~~requires management to ~~those~~apply ~~customers.~~policies ~~The~~and ~~quantity~~make ofestimates ~~those sales is~~and ~~measured~~assumptions bythat ~~customers’~~affect ~~meters.~~the ~~Meters~~results ~~are~~of ~~read~~operations onand athe ~~systematic~~reported ~~basis~~amounts ~~throughout~~of ~~the~~assets ~~month~~and liabilities ~~based~~in ~~on established~~the ~~meter-reading~~financial ~~schedules~~statements. ~~Consequently,~~Because atof the ~~end~~inherent ofuncertainty ~~any~~in ~~month,~~the ~~there~~nature ~~exists~~of ~~a quantity~~the ofmatters ~~electricity~~where ~~and~~estimates ~~gas~~are ~~that~~used, ~~has~~actual ~~been~~amounts ~~delivered~~could todiffer ~~customers~~from ~~but~~estimated ~~has~~amounts. ~~not~~The ~~been captured by the meter~~following ~~readings.~~accounting Aspolicies arepresent ~~result,~~those that management ~~must~~believes ~~estimate~~are ~~revenue~~particularly ~~related~~important to ~~electricity~~the financial statements and ~~gas~~require ~~delivered~~the ~~to customers~~use ~~between~~of ~~their~~judgment ~~meter~~in ~~read~~estimating ~~dates~~matters ~~and~~that ~~the~~are ~~end of the period~~inherently uncertain.

~~Pension~~Regulatory Assets and ~~Other~~Liabilities: ~~Post-retirement~~Regulatory ~~Benefit~~assets ~~Plans:~~represent ~~The~~costs ~~Company~~that ~~maintains~~have ~~qualified~~been ~~and~~deferred ~~nonqualified~~to ~~pension~~future ~~plans.~~periods ~~The~~when ~~Company~~it ~~also~~is ~~provides~~probable ~~health~~that ~~care~~the ~~and~~regulator ~~life~~(namely, ~~insurance~~the ~~benefits~~FERC, ~~for~~PSC, ~~its~~or ~~retired~~other regulatory ~~employees~~body with jurisdiction) will allow future recovery of those costs through rates. The Company’s ~~pensions~~bases its ~~are~~assessment ~~funded~~of ~~through~~recovery anby ~~outside trust.~~either

~~In addition to the market returns, various other assumptions also affect the pension and other~~10 post-retirement benefit expense and measurement of their respective obligations. The more significant assumptions include the assumed return on assets, discount rate, and in the case of retiree healthcare benefits, medical trend assumptions. All ongoing costs of qualified pension and post-retirement healthcare benefits plans are recoverable from customers through reconciling provisions of the Merger Rate Plan. Special termination benefits paid in connection with employee separation

11 Table of Contents

~~Table~~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 ~~Contents~~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.”

~~programs~~The ~~and~~Company ~~settlement~~continually ~~and~~assesses ~~curtailment~~if ~~losses~~its regulatory assets continue to meet the criteria for probability of ~~pension~~future ~~and~~recovery. ~~post-retirement~~This ~~benefit~~assessment ~~plans~~considers ~~when~~factors such as changes in the regulatory ~~incurred~~environment, ~~are~~recent ~~only~~rate ~~recoverable~~orders ~~upon~~to ~~approval~~other byregulated entities under the ~~PSC~~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 ~~Assumed~~of ~~return~~regulatory on assets. ~~The estimated rate of return for various passive asset classes~~ is ~~based~~provided ~~both~~over onthe ~~analysis~~recovery ofperiod ~~historical~~as ~~rates~~allowed ofin ~~return~~the ~~and~~related regulatory ~~forward~~agreement. ~~looking~~Under ~~analysis~~the ofMerger ~~risk~~Rate ~~premiums~~Plan, ~~and~~a ~~yields.~~regulatory ~~Current market conditions~~asset, ~~such~~called asstranded ~~inflation and interest rates~~costs, ~~are~~was established ~~evaluated~~that inincluded ~~connection with~~ the ~~setting~~costs of ~~our~~the ~~long-term~~Master ~~assumption.~~Restructuring AAgreement ~~small~~(MRA), ~~premium~~the iscost ~~added for active management~~ of ~~both~~any additional ~~equity~~Independent ~~and~~Power ~~fixed~~Producer ~~income.~~(IPP) contract ~~The~~buyouts ~~rates of return for each asset class are then weighted in accordance with our target asset allocation,~~ and the ~~resulting~~deferred ~~long-term~~loss ~~return~~ on ~~asset rate is then applied to~~ the ~~market-related~~sale ~~value~~ of ~~assets. For fiscal 2005,~~ the Company’s ~~used~~generation ~~an 8~~assets.~~50%~~ ~~assumed~~The ~~return~~MRA onrepresents ~~assets~~the ~~for~~cost ~~its~~to ~~pension~~terminate, ~~plan~~restate ~~and~~or anamend 8IPP contracts.~~26%~~ ~~assumed~~The ~~return~~Company onis ~~assets~~also ~~for~~permitted ~~its~~to ~~other~~defer ~~post-retirement~~and ~~benefits~~amortize ~~plans,~~the ~~respectively.~~cost •of ~~Discount~~any ~~rate.~~additional InIPP contract ~~determining~~buyouts. ~~the~~Beginning ~~discount~~February 1, ~~rate~~2002, the ~~Company~~Merger ~~considers~~Rate ~~Moody’s~~Plan Aastranded ~~rates~~costs ~~for~~regulatory ~~corporate~~asset is ~~bonds~~being ~~and~~amortized ~~public~~unevenly ~~utility~~over ~~bonds.~~ten Inyears ~~addition,~~with ~~the~~larger ~~Company~~amounts ~~considers~~being ~~other~~amortized ~~measures~~in ofthe ~~interest~~latter ~~rates~~years, consistent ~~for~~with ~~high~~projected ~~quality~~recovery ~~fixed~~through ~~income~~rates. ~~investments~~Amortization ~~which~~of ~~match~~ the ~~duration~~stranded ofcost ~~the~~regulatory asset ~~liabilities.~~is Ashown ~~rate~~separately isbecause ~~chosen~~it ~~within~~is the ~~range~~largest ~~set~~component byof ~~these~~regulatory ~~measures~~assets. •Amortization of ~~Medical~~other ~~trend~~regulatory ~~assumptions.~~assets ~~The~~are ~~health~~included ~~care~~in ~~cost~~depreciation ~~trend~~and ~~rate~~amortization, ispurchased ~~the~~electricity ~~assumed~~& gas, ~~rate~~and ofother ~~increase~~operation inand ~~per-capita~~maintenance ~~health~~expense ~~care~~captions ~~charges.~~on ~~For 2005,~~ the ~~health~~income ~~trend~~statement ~~was~~depending ~~set~~on ~~at 10% with~~ the origin ~~ultimate trend~~ of 5%the ~~reached~~regulatory ~~in 2009~~asset.

~~Goodwill~~Revenues: The ~~company~~Company ~~applies~~bills ~~the~~its ~~provisions~~customers ofon ~~SFAS~~a ~~No. 142,~~monthly ~~“Goodwill~~cycle ~~and~~basis ~~Other~~at ~~Intangible Assets”~~approved ~~(FAS~~tariffs ~~142).~~based ~~In accordance with FAS 142, goodwill must be reviewed for impairment at least~~on ~~annually~~energy delivered and ~~when~~a ~~events~~minimum orcustomer ~~circumstances~~service ~~indicate~~charge. ~~that~~Revenues ~~the~~are ~~asset~~determined ~~may~~based beon ~~impaired. The Company~~these ~~utilized~~bills aplus ~~discounted~~an ~~cash~~estimate ~~flow~~for ~~approach~~unbilled ~~incorporating~~energy ~~its~~(discussed ~~most~~below) ~~recent~~delivered ~~business~~between ~~plan~~the ~~forecasts~~cycle inbilling ~~the~~date ~~performance~~and of the ~~annual~~end ~~goodwill impairment test. The result~~ of the ~~annual~~accounting ~~analysis determined that no adjustment to the goodwill carrying value was required~~period.

~~Tax~~Unbilled ~~Provision~~Revenues: ~~The~~Revenues ~~Company’s~~from ~~tax~~the ~~provisions,~~sale ~~including~~of ~~both~~electricity ~~current~~ and ~~deferred~~gas ~~components,~~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 ~~estimates,~~meter-reading ~~assumptions,~~schedules. ~~calculations~~Consequently, ~~and~~at ~~interpretation~~the end of ~~tax~~any ~~statutes~~month, ~~for~~there ~~the~~exists ~~current~~a quantity of electricity and ~~future~~gas ~~years~~that inhas ~~accordance~~been ~~with~~delivered ~~SFAS~~to ~~No. 109,~~customers ~~“Accounting~~but ~~for~~has ~~Income~~not ~~Taxes”.~~been ~~Determination~~captured ofby the meter ~~current~~readings. ~~year~~As ~~federal~~a result, management must estimate revenue related to electricity and ~~state~~gas ~~income~~delivered ~~tax~~to customers ~~will~~between ~~not~~their bemeter ~~settled~~read ~~until~~dates ~~final~~and ~~IRS~~the ~~approval~~end of the period.

~~Management~~Pension ~~regularly~~and ~~makes~~Other ~~assessments~~Post-retirement ofBenefit ~~tax~~Plans: ~~return~~The ~~outcomes~~Company ~~relative~~maintains toqualified ~~financial~~and ~~statement tax~~nonqualified ~~provisions~~pension plans. The Company also provides health care and ~~adjusts~~life ~~the~~insurance ~~tax~~benefits ~~provisions~~for inits ~~the~~retired employees. ~~period~~The ~~when~~Company’s ~~facts~~pensions ~~become~~are ~~final~~funded through an outside trust.

Several 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 Merger Rate Plan. Special termination benefits paid in connection with employee separation programs and settlement and

~~Accounting for Derivative Instruments: The Company accounts for derivative financial instruments~~11 under SFAS No. 133, “Accounting for Derivatives and Hedging Activities” (FAS 133), and SFAS No. 149, “Amendment of SFAS No. 133 on Derivative Instruments and Hedging Activities,” as amended. Under the provisions of FAS 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

12 Table of Contents

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

~~result~~The ofmajor ~~regulatory~~assumptions ~~rulings. A cash flow hedge is a hedge of a forecasted transaction or the~~are: 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.

~~RESULTS~~• OFReturn ~~OPERATIONS~~ 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, the Company used an 8% assumed return on assets for its pension plan and a weighted average of 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 5.87% 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, 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 ~~following~~Company ~~discussion~~applies the provisions of SFAS No. 142, “Goodwill and ~~analysis~~Other ~~highlights~~Intangible Assets.” ~~items~~In ~~that~~accordance ~~significantly~~with ~~affected~~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’s ~~operations~~utilized ~~during~~a discounted cash flow approach incorporating its most recent business plan forecasts in the ~~years~~performance ~~ended~~of ~~March 31,~~the ~~2005~~annual ~~and~~goodwill ~~2004~~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.

~~EARNINGS~~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.

~~Net~~Management ~~income~~regularly ~~for~~makes ~~the~~assessments ~~year~~of ~~ended~~tax ~~March 31,~~return ~~2005~~outcomes ~~increased~~relative ~~by approximately $124 million from the prior year. This increase is primarily due~~ to ~~decreased~~financial ~~retiree~~statement ~~benefit expense of $54 million relating~~tax toprovisions ~~one-time items, a decrease in bad debt expense of $19 million,~~ and ~~reduced~~adjusts ~~interest~~the ~~costs~~tax ~~of approximately~~provisions ~~$47 million.~~in ~~See~~ the ~~following~~period ~~discussions~~when offacts ~~revenues~~become ~~and operating expenses for more detailed explanations~~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. 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

~~Net income for the year ended March 31, 2004 increased by approximately $14 million from the prior~~12 year. This increase is primarily due to the reduced interest costs from the redemption or refinancing of long-term debt using lower cost associated company debt or funds from the intercompany money pool. Partially offsetting these cost reductions were lower sales of both electricity and gas due to more normal weather conditions in the current year than in the prior year. See the following discussions of revenues and operating expenses for more detailed explanations.

REVENUES Table of Contents

~~Electric~~contract ~~revenues~~is ~~decreased~~designated ~~$167 million~~as ~~during~~a cash flow hedge, the ~~year~~change ~~ended~~in ~~March 31,~~its ~~2005~~market ~~from~~value is generally deferred as a component of other comprehensive income until the ~~prior~~transaction ~~year~~it is hedging is completed. ~~Electric~~ ~~revenues~~Conversely, ~~decreased~~the ~~$27 million~~change in the ~~twelve~~market ~~months~~value ~~ended~~of ~~March 31,~~a derivative ~~2004~~not designated as a cash flow hedge is deferred as a regulatory asset or liability because the Company has received approval from the ~~prior~~PSC to establish a regulatory asset or liability ~~year~~for derivative instruments that did not qualify for hedge accounting and were the result of regulatory rulings. ~~The~~A ~~table~~cash ~~below~~flow ~~details~~hedge ~~components~~is a hedge of ~~this~~a ~~fluctuation~~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.

Change in Electric Revenue for the fiscal year ended
($ in millions)	March 31, 2005			March 31, 2004
Retail sales	$	(98	)	$	(153	)
Delivery only sales and miscellaneous revenue		20			99
Sales for resale		(89	)		27
Total	$	(167	)	$	(27	)

RESULTS OF OPERATIONS

~~Retail~~The ~~sales~~following ~~include~~discussion ~~distribution delivery charges~~ and ~~recovery~~analysis ofhighlights ~~purchased~~items ~~power~~that ~~costs~~significantly ~~from customers~~affected ~~who purchase their electric supply from~~ the Company~~. Delivery only sales are charges for~~’s ~~only~~operations ~~the~~during 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. Since the ~~start~~fiscal of electricity deregulation in the State of New York, retail electric customers have been migrating to competitive suppliers for their commodity requirements which is a contributing factor for the decrease in retail sales revenues in the years ended March 31, ~~2005~~2006 and ~~2004~~2005. ~~These decreases were partially offset by increases in~~

13EARNINGS

~~Table~~Net income for the fiscal year ended March 31, 2006 increased by approximately $54 million over the prior fiscal year. This increase is primarily due to higher electric and gas margin of ~~Contents~~$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 of $32 million stemming from the recognition of a regulatory asset reflecting our ability to recover a previously fully reserved account receivable. These were offset by increased income 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 following discussions of revenues and operating expenses for more detailed explanations.

Net income for the ~~price~~year ofended ~~electricity~~March 31, ~~that~~2005 ~~was~~increased ~~passed~~by onapproximately $124 million over the prior fiscal year. This increase is primarily due to ~~customers~~decreased retiree benefit expense of $54 million relating to one-time items, a decrease in bad debt expense of $19 million, and ~~higher~~reduced ~~stranded~~interest costs ~~cost~~of approximately $47 million. See the following discussions of revenues ~~matching~~and operating ~~increased~~expenses ~~stranded~~for ~~cost~~more ~~amortization~~detailed explanations.

~~Sales for resale represent sales of electricity to the New York Independent System Operator (NYISO)~~REVENUES at the market price of electricity. All electricity purchased under certain purchased power contracts is sold to the NYISO. The decrease in sales to the NYISO for the year ended March 31, 2005 was due to the expiration of some of these contracts. The increase in sales to the NYISO for the year ended March 31, 2004 was attributable to higher electricity prices as compared to the prior year.

Electric ~~kilowatt-hour~~revenues ~~sales~~increased ~~were~~$190 million ~~approximately~~during ~~36.6~~the year ended March ~~billion~~31, ~~and~~2006 38from the prior fiscal year.5 Electric revenues decreased $167 ~~billion~~million ~~for~~in the ~~year~~twelve months ended March 31, 2005 ~~and~~relative to ~~2004~~the prior fiscal year. ~~The~~See the table below ~~details~~for ~~components~~the ofcontributing ~~this fluctuation~~factors.

Change in kWh Deliveries for the fiscal year ended
Change in Electric Revenue for the fiscal year ended
(kWh in millions)	March 31, 2005			March 31, 2004
(in millions of dollars)	March 31, 2006			March 31, 2005
Retail sales	$	~~(1.4~~52	)	$	(~~2.3~~98	)
Delivery only sales		1.6			2.0
Delivery only sales and miscellaneous revenue		185			20
Total deliveries to ultimate customers		0.2			(0.3	)
Sales for resale		(47	)		(89	)
Sales for resale		(2.1	)		0.2
Total	$	190		$	(167	)
Total deliveries		(1.9	)		(0.1	)

~~Gas~~Retail ~~revenues~~sales ~~increased~~include ~~$28 million~~distribution indelivery ~~the~~charges ~~fiscal~~and ~~year~~recovery ~~ended~~of ~~March 31,~~purchased ~~2005~~power ~~from~~costs ~~the prior year.~~from ~~This~~customers ~~increase~~who ispurchase ~~primarily~~their aelectric ~~result~~supply offrom ~~higher~~the ~~prices~~Company. ofDelivery ~~gas~~only ~~purchases,~~sales ~~which~~ are ~~being~~charges ~~passed~~for ~~through~~only tothe ~~customers.~~delivery ~~This~~of ~~increase~~energy ~~was~~for ~~affected~~customers bywho ~~the~~purchase ~~elimination~~their ofpower afrom ~~$6 million~~competitive ~~adjustment~~electricity ~~related~~suppliers. toThe ~~state~~Company ~~net~~recovers ~~income~~all ~~tax~~costs ~~recorded~~incurred into ~~the~~procure ~~prior~~power ~~year~~for ~~period~~customers ~~ended~~that ~~March 31,~~do ~~2004 and reversed~~not inreceive ~~the~~power ~~year~~from ~~ended~~competitive ~~March 31, 2005~~suppliers.

~~Gas revenues increased $71 million for the fiscal year ended March 31, 2004 compared to the prior~~13 year ended March 31, 2003 primarily due to higher prices of gas purchases, which are being passed through to customers. This increase is partially offset by an adjustment related to state net income tax.

TheTable table below details components of the gas revenue fluctuation: Contents

Change in Gas Revenue for the fiscal year ended
($’s in Millions)	March 31, 2005			March 31, 2004
Cost of Purchased Gas	$	31		$	85
Delivery Revenue		(4	)		3
Other		1			(17	)
Total	$	28		$	71

The increase in retail sales, for the fiscal year ended March 31, 2006 is primarily due to the higher cost of electricity purchased which is being passed through to customers. The increase in delivery only sales is primarily due to the migration of 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 autumn weather than experienced in the previous fiscal year also contributed to the increase in revenue for the fiscal year ended March 31, 2006.

The ~~change~~migration inof ~~the~~retail ~~cost~~electric ofcustomers ~~purchased~~to ~~gas~~competitive ~~has~~suppliers nowas ~~impact~~a oncontributing factor for the ~~Company’s~~decrease ~~net~~in ~~income~~retail ~~because~~sales revenues in the fiscal year ended March 31, 2005 partially offset by ~~actual~~increases ~~commodity~~in ~~costs~~the ~~are~~price ~~passed~~of ~~through~~electricity tothat ~~customers~~was passed on ato ~~dollar-for-dollar basis~~customers.

~~Gas~~Sales ~~sales~~for ~~volumes~~resale ~~for~~represent ~~the~~sales ~~fiscal~~of ~~year~~electricity ~~ended~~to ~~March 31,~~the ~~2005,~~NYISO ~~excluding~~at ~~transportation~~the market price of electricity. ~~customer-owned~~All ~~gas,~~electricity ~~decreased~~purchased ~~approximately~~under ~~3.6 million~~certain ~~Dekatherms~~purchased ~~(Dth),~~power orcontracts ais ~~5.7 percent~~sold ~~decrease from~~to the ~~prior year~~NYISO. ~~Gas~~The decreases in sales ~~for~~to the ~~fiscal~~NYISO ~~year~~for the years ended March 31, ~~2004~~2006 and March 31, ~~excluding~~2005 ~~transportation~~were due to the expiration of some of these contracts.

14Electric 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	)

~~customer-owned~~Gas ~~gas,~~revenues ~~decreased~~increased ~~approximately 3.6~~$229 million ~~Dth,~~in ~~or a 5.3 percent decrease from~~ the fiscal year ended March 31, ~~2003.~~2006 ~~The~~from ~~decreased~~the ~~gas~~prior ~~usage for~~ fiscal ~~year ended March 31, 2005 as~~ ~~compared to fiscal~~ year. ~~ended~~This ~~March 31,~~increase ~~2004~~ is ~~partially~~primarily ~~due to impacts of weather and partially due to decreased use per customer as~~ a result of ~~customer response to~~ higher ~~natural gas~~ prices. ~~The~~of ~~decreased~~ gas ~~usage~~purchases ~~for~~which ~~fiscal~~are ~~year~~being ~~ended March 31, 2004 as compared to fiscal year~~passed ~~ended~~through ~~March 31, 2003 is partially due~~ to ~~impacts of weather and partially due to migration of~~ customers ~~to alternate providers~~.

~~OPERATING~~Gas ~~EXPENSES~~revenues increased $28 million for the fiscal year ended March 31, 2005 from the prior fiscal year primarily due to higher prices of gas purchases which are being passed through to customers. This increase was affected by the elimination of a $6 million adjustment related to state net income tax recorded in the fiscal year ended March 31, 2004 and reversed in the fiscal year ended March 31, 2005.

~~Purchased electricity decreased approximately $227 million for the year ended March 31, 2005 from the prior year.~~ The ~~volume~~table ofbelow ~~kWh~~details ~~purchased~~components ~~decreased 5.5 billion kWh (17% ) compared to the prior year, reflecting migration~~ of ~~customers to competitive electricity suppliers and~~ the ~~expiration~~ ofgas ~~certain~~revenue ~~sales for resale purchased power contracts This volume decrease was offset~~fluctuation: ~~by a 2% increase in the price of electricity over the prior year.~~

Purchased electricity decreased approximately $3 million for the year ended March 31, 2004 from the prior year. Corresponding to lower electric sales, the Company purchased less kWh of electricity versus the prior year. In addition, contractual obligations to certain higher cost suppliers expired in fiscal year 2004, which resulted in a reduction to purchased power expense of $16 million, as compared to the prior year. However, increases in the market price of electricity substantially offset these decreases.


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

~~Purchased gas expense increased approximately $31 million for the year ended March 31, 2005 from~~14 the prior year. 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 in the year ended March 31, 2005 from $6.61 in the prior year. This increase in price was slightly offset by decreased purchases.

PurchasedTable gas expense increased approximately $85 million for the year ended March 31, 2004 as compared to the fiscal year ended March 31, 2003. The increase is a result of higher gas prices in the fiscal year ended March 31, 2004 partially offset by decreased sales attributable to the warmer weather conditions than in the comparable prior period. The Company’s net cost per Dth, as charged to expense, including the effects of the gas cost deferral, increased to $6.61 for the year ended March 31, 2004 from $5.57 in the prior year ended March 31, 2003. Contents

~~For~~The achange ~~discussion~~in ofthe ~~hedging~~cost of purchased gas ~~purchases,~~has ~~see~~no ~~Item 7A.~~impact ~~Quantitative~~on ~~and~~the ~~Qualitative~~Company’s net income because the ~~Disclosures~~actual ~~about~~commodity ~~Market~~costs ~~Risk~~are –passed ~~“Gas~~through ~~Supply~~to ~~Price~~customers ~~Risk~~on a dollar-for-dollar basis.”

~~Other~~Gas ~~operation~~sales ~~and~~volumes ~~maintenance~~for ~~expense~~the fiscal year ended March 31, 2006, excluding transportation of customer-owned gas, decreased ~~$84~~approximately 3.9 million Dekatherms (Dth), or a 6.4% decrease from the prior fiscal year. Gas sales for the fiscal year ended March 31, 2005, excluding transportation of customer-owned gas, decreased approximately 3.6 million Dth, or a 5.7% decrease from the ~~prior~~fiscal year ended March 31, 2004. The ~~table~~decreased ~~below~~gas ~~details~~usage ~~components~~for the fiscal year ended March 31, 2006 compared with the fiscal year ended March 31, 2005 is partially due to the impacts of weather ~~this~~and ~~fluctuation~~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, 2005 compared with the fiscal year ended March 31, 2004 is partially due to the impacts of weather and to the migration of customers to alternate providers.

	For the year			For the year
	ended			Ended
($’s in millions)	March 31, 2005			March 31, 2004		Change
Bad debt expense		45			64		(19	)
VERO expense		—			19		(19	)
Recovery of 2003 pension settlement loss		(14	)		—		(14	)
Pension settlement loss		—			21		(21	)
April 2003 ice storm		—			6		(6	)
Loss on sale of facilities		8			—		8
Other		670			683		(13	)
Total	$	709		$	793	$	(84	)

OPERATING EXPENSES

15Purchased 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.

~~Table~~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 ~~Contents~~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.

~~The~~Purchased ~~decrease~~gas isexpense ~~mainly~~increased ~~due~~approximately to$232 million ~~decreased~~for ~~retiree~~the ~~benefit~~fiscal ~~expense~~year ofended ~~$54~~March ~~million~~31, ~~relating to~~2006 ~~one-time~~from ~~items.~~the ~~The~~prior ~~pension~~fiscal ~~settlement~~year. ~~loss~~This ~~recovery~~increase ofis ~~$14 million~~primarily ~~reflects~~ the ~~PSC~~result ~~July 2004 approval~~of ~~for~~increased ~~the~~gas ~~Company~~prices toduring the ~~recover~~year aand ~~portion~~an ofincrease in the ~~$30 million~~amount ~~pension~~of ~~settlement~~gas ~~loss~~sold ~~incurred in fiscal 2003~~off-system. The Company’s ~~has~~net ~~petitioned~~cost ~~the~~per ~~PSC~~Dth, ~~for~~as charged ~~recovery~~to ofexpense, aincluding ~~$21 million~~the ~~pension settlement~~effects ~~loss~~of ~~that~~the ~~was~~gas ~~recorded~~cost deferral, increased to ~~expense~~$9.92 in the fiscal ~~prior~~ year. Inended ~~fiscal 2004~~March 31, ~~the~~2006 ~~Company recorded~~from a $~~19 million~~7.12 ~~loss~~in ~~related to~~ the ~~non-union~~prior ~~employee~~fiscal ~~early~~year. ~~retirement~~The ~~program~~increase ~~(VERO).~~due ~~These~~to ~~pension~~price ~~items~~was ~~were~~slightly ~~recorded~~offset ~~to expense~~ by ~~the~~decreased ~~Company, without a similar adjustment in the comparison period~~purchases.

~~The~~Purchased ~~reduction~~gas inexpense ~~bad~~increased ~~debt~~approximately ~~expense~~$31 million for the fiscal year ended March 31, 2005 compared with the fiscal year ended March 31, ~~was~~2004. ~~mainly~~This ~~the~~increase is primarily a result of increased agas prices during the year. The Company’s net cost per Dth, as charged to expense, ~~decrease~~including the effects of the gas cost deferral, increased to $7.12 for the year ended March 31, 2005 from $6.61 in ~~accounts~~the ~~receivable~~prior ~~and~~fiscal ~~improved~~year ~~collection~~ended ~~practices~~March 31, 2004.

~~The~~For ~~decrease~~a indiscussion ~~Other~~ of ~~$13 million~~hedging ~~for~~of ~~the~~gas ~~year~~purchases, ~~ended~~see ~~March~~Item ~~31,~~7A. ~~2005,~~Quantitative ~~reflects~~and ~~ongoing reduced~~Qualitative ~~costs~~Disclosures ~~from~~about ~~merger-related~~Market ~~efficiencies~~Risk ~~including~~– ~~staffing~~“Gas ~~reductions~~Supply ~~and~~Price ~~other decreased expenses~~Risk.”

~~Other operation and maintenance expense decreased $47 million for the year ended March 31, 2004~~15 from the prior year. The decrease is primarily due to a $28 million decrease in bad debt expense and a recorded charge of $19 million to write-off certain projects in its construction work-in-process (CWIP) accounts recorded in the year ended March 31, 2003 with no comparable charge recorded in the year ended March 31, 2004. This charge was the result of a post-merger review of pre-merger CWIP projects.

DepreciationTable andof amortization remained constant for the year ended March 31, 2005 from the prior year. For the year ended March 31, 2004, depreciation and amortization increased approximately $2 million from the prior year, primarily due to increased plant acquisitions. Contents

~~Amortization~~Other ofoperation ~~stranded~~and ~~costs~~maintenance expense increased $579 million ~~and $45 million~~ for the ~~years~~year ended March 31, ~~2005~~ ~~and~~2006 ~~March 31, 2004, respectively,~~ from the prior ~~years~~fiscal in accordance with the Merger Rate Plan. Under the Merger Rate Plan (which became effective on January 31, 2002) the stranded cost regulatory asset amortization period was established for recovery over the ten year ~~period ending December 31, 2011~~. ~~This~~The ~~asset~~table isbelow ~~being~~details ~~amortized~~components ~~unevenly on an increasing graduated schedule. See 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~~fluctuation.

Other taxes decreased approximately $9 million for the year ended March 31, 2005 from the prior year primarily due to reduced Gross Receipts Tax (GRT). This reduction in GRT is primarily due to lower rates and reduced revenues.


	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

~~Other~~The ~~taxes~~increase ~~decreased approximately $26 million~~ for the fiscal year ended March 31, ~~2004~~2006 ~~from~~is primarily due to higher non-recoverable storm related costs of $18 million and a one-time $14 million pension settlement loss recovery recorded in the prior year. ~~This~~reflecting ~~decrease~~the isPSC’s ~~primarily~~July 2004 ~~due~~approval for the Company to recover a portion of the $3130 million ~~reduction~~pension ofsettlement ~~GRT~~loss asincurred ain ~~result~~fiscal ofyear ~~lower~~2003. ~~GRT~~These ~~rates~~were partially offset by ~~increased~~a ~~property~~decrease ~~taxes~~in payroll costs of $917 million. primarily attributable to ongoing headcount reductions and reduced consultant and contractor costs of $11 million mostly due to merger related efficiencies. Also offsetting the increase was 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.

~~Income~~The ~~taxes~~Company ~~increased~~is ~~$32 million~~also ~~for~~subject ~~the~~to ~~year~~service ~~ended~~quality ~~March 31,~~standards ~~2005~~with ~~from~~respect ~~the~~to ~~prior~~reliability ~~year~~and ~~primarily~~certain ~~due~~aspects toof ~~higher~~customer ~~taxable~~service ~~income~~and ~~offset~~safety. byThe aCompany ~~decrease~~works ~~related~~toward toservice aquality ~~$20 million~~standards ~~prior~~that ~~year~~the state ~~accrual~~regulators ~~with no~~expect ~~comparable~~us ~~accrual~~to inachieve. If the ~~current~~Company ~~year~~falls ~~and~~below ana ~~$8 million~~prescribed ~~adjustment~~standard, ina ~~the~~penalty is ~~current~~incurred. ~~year~~The ~~related to~~Company ~~prior~~missed targets for reliability in fiscal years’ ~~state~~ended ~~income~~March 31, ~~tax.~~2006 ~~Income~~and 2005, ~~taxes~~incurring ~~increased~~penalties of $469 million ~~for~~and ~~the~~$4 million, ~~year ended~~respectively.

16Other operation and maintenance expense decreased $84 million for the fiscal year ended March 31, 2005 from the prior fiscal year. The decrease was primarily due to a $54 million decrease relating to one-time retiree benefit expenses (which includes the pension settlement loss recovery of $14 million mentioned above), a reduction in bad debt expense of $19 million which resulted from improved collection practices and $8 million of storm expenses recorded in the 2004 fiscal year with no similar expense recorded in fiscal year 2005. These decreases were offset by an $8 million loss on the sale of facilities in fiscal year 2005.

~~Table~~Depreciation ofand ~~Contents~~amortization expense increased $3 million for the fiscal year ended March 31, 2006 from the prior fiscal year because capital projects went into service. For the fiscal year ended March 31, 2005, depreciation and amortization expense remained constant relative to the prior fiscal year.

Amortization of stranded costs increased $15 million and $57 million for the fiscal years ended March 31, ~~2004~~ 2006 and March 31, 2005, respectively, from the prior fiscal years in accordance with the Merger Rate Plan. Under the Merger Rate Plan the stranded cost regulatory asset amortization period was established for recovery over the ten year ~~primarily~~period ~~due~~ending toDecember 31, a2011. ~~$20~~This asset is being amortized unevenly on an increasing, graduated schedule. See Item ~~million~~8. ~~accrual~~Financial toStatements and ~~return~~Supplementary ~~true-up~~Data — Note B — Rate and ~~higher~~Regulatory ~~book~~Issues — “Stranded Costs” for a further ~~taxable~~discussion ~~income~~of the ratemaking treatment related to this regulatory asset.

~~OTHER INCOME (DEDUCTIONS), INTEREST AND PREFERRED DIVIDENDS~~16

OtherTable income (deductions) increased $16 million for the year ended March 31, 2005 from the prior year mainly due to a $9 million settlement of an estimated liability and a $8 million favorable adjustment to non-utility related income taxes. Contents

Other ~~income~~taxes ~~(deductions)~~ decreased approximately $68 million for the fiscal year ended March 31, ~~2004~~2006 from the ~~prior~~ prior fiscal year ~~mainly~~primarily due to anreduced ~~increase~~gross inreceipts ~~expenses~~tax ~~related to the Stock Appreciation Rights~~ (~~SARs~~GRT). ~~program due~~This toreduction ~~increases~~ in ~~the~~GRT ~~value~~is primarily ofdue ~~National~~to ~~Grid~~lower ~~Transco’s~~rates ~~stock price. See Item 8. Financial Statements~~ and ~~Supplementary~~reduced ~~Data~~tax —base, ~~Note~~partially Koffset —by ~~Stock~~a ~~Based~~slight ~~Compensation,~~increase ~~for more~~ in ~~formation on the~~ ~~Company’s~~property ~~SARs program~~taxes.

~~Interest~~Other ~~charges~~taxes decreased approximately $479 million for the fiscal year ended March 31, 2005 from the prior fiscal year. ~~The decrease is~~ primarily due to ~~long~~reduced ~~term~~GRT. ~~debt~~This ~~maturing~~reduction in ~~addition~~GRT tois ~~early~~primarily ~~redemption~~due ofto ~~third-party debt using affiliated company debt at~~ lower ~~interest~~ rates, ~~offset by increased interest payments on short term debt due to increased average short term borrowings~~ and ~~higher~~reduced ~~interest rates~~revenues.

~~Interest~~Income ~~charges~~taxes ~~decreased~~increased $7719 million for the fiscal year ended March 31, ~~2004~~2006 from the prior fiscal year. ~~The decrease is~~ primarily due to ~~the~~higher ~~early~~pre-tax ~~redemption~~book ofincome ~~third-party~~offset ~~debt~~by ~~using~~a ~~affiliated~~$4 million ~~company~~benefit ~~debt at~~related ~~lower~~to ~~interest~~prior years’ ~~rates.~~tax Inreturn ~~addition,~~true-ups ~~the~~and ~~expiration~~settlements of ~~the~~tax ~~Master~~audits. ~~Restructuring~~Income ~~Agreement interest~~taxes ~~savings~~increased ~~deferral~~$32 million infor the fiscal year ~~2004~~ended ~~contributed~~March 31, 2005 relative to the ~~decrease.~~prior ~~Also, in~~ fiscal ~~2003 the~~year ~~Company~~primarily ~~recorded~~due ~~$8 million of interest expense related~~ to ~~a PSC staff adjustment concerning~~higher ~~pension and other post~~pre-~~retirement~~tax ~~benefits~~book ~~funding~~income ~~for~~offset ~~which~~by ~~there~~a ~~was~~$20 million nodecrease ~~corresponding~~in ~~charge~~prior ~~in fiscal~~years’ ~~year~~tax ~~2004~~return true-ups.

~~EFFECTS~~OTHER OFINCOME ~~CHANGING~~(DEDUCTIONS), ~~PRICES~~INTEREST AND PREFERRED DIVIDENDS

~~The~~Other ~~Company~~income is(deductions) ~~sensitive~~decreased to$16 million ~~inflation~~for ~~because~~the offiscal ~~the~~year ~~amount~~ended ofMarch 31, ~~capital~~2006 itfrom ~~typically~~the prior ~~needs~~fiscal year and ~~because~~ ~~its~~increased ~~prices~~by ~~are~~$16 million ~~regulated~~for ~~using~~the ayear ~~rate-base~~ended ~~methodology~~March 31, ~~that~~2005 ~~reflects~~relative to the prior ~~historical~~fiscal ~~cost~~year, primarily due to a $9 million settlement of an estimated liability and an $8 million favorable adjustment to non-utility ~~plant~~related income taxes which were recorded in the 2005 fiscal year with no similar adjustments recorded in the 2006 or 2004 fiscal years.

~~The~~Interest ~~Company’s~~charges ~~consolidated~~decreased ~~financial~~$21 million ~~statements~~for ~~are~~the ~~based~~fiscal onyear ~~historical~~ended ~~events and transactions. The effects of inflation on most utilities~~March 31, ~~including~~2006 ~~the~~from ~~Company, are most significant in~~ the prior ~~areas~~fiscal ~~of depreciation and utility plant~~year. InThe ~~addition,~~decrease ~~the~~is ~~Company~~primarily ~~would not replace these with identical assets~~ due to ~~technological~~maturing ~~advances~~long-term ~~and~~debt ~~competitive~~replaced ~~and~~with ~~regulatory changes that have~~affiliated ~~occurred.~~company Indebt ~~light~~at oflower ~~these~~interest ~~considerations,~~rates ~~the~~which ~~depreciation charges in operating expenses do not reflect the cost of providing service if new facilities~~ were ~~installed.~~partially ~~See~~offset ~~“Long~~by –increased ~~Term~~interest ~~Outlook”~~payments on ~~under~~short ~~“Liquidity~~term ~~and~~debt ~~Capital~~due ~~Resources”~~to ~~below~~higher ~~for~~interest ~~a discussion of the Company’s future capital requirements~~rates.

~~LIQUIDITY~~Interest ~~AND~~charges ~~CAPITAL~~decreased ~~RESOURCES~~$47 million for the fiscal year ended March 31, 2005 from the prior fiscal year. The decrease is primarily due to maturing long-term debt and to the early redemption of third-party debt which were replaced with affiliated company debt at lower interest rates and which were partially offset by increased interest payments on short-term debt because of increased average short-term borrowings and higher interest rates.

~~Short~~EFFECTS ~~Term:~~OF AtCHANGING ~~March 31, 2005, the Company’s principal sources of liquidity included cash and cash~~PRICES equivalents of $20 million and accounts receivable of $572 million. The Company has a negative working capital balance of $423 million primarily due to long-term debt due within one year of $550 million and short-term debt to affiliates of $401 million (see intercompany money

17The 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.

~~Table~~The Company’s financial statements are based on historical events and transactions. The effects of inflation ~~Contents~~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.

~~pool~~LIQUIDITY ~~discussion below~~AND inCAPITAL ~~Item 8). Cash is being generated from sales (via electric rates) to offset stranded cost~~RESOURCES amortization (non-cash expense). This excess cash is used for debt payments and other operating needs. As discussed below, the Company believes it has sufficient cash flow and borrowing capacity to fund such deficits as necessary in the near term.

~~Net~~Short-Term ~~cash~~Outlook: ~~provided~~At byMarch 31, ~~operating~~2006, ~~activities~~the ~~increased~~Company’s ~~approximately~~principal ~~$536 million~~sources ~~for~~of ~~the~~liquidity ~~year~~included ~~ended~~cash ~~March 31,~~and ~~2005~~cash ~~from~~equivalents ~~the~~of ~~prior~~$11 million ~~year.~~and ~~The~~accounts ~~primary~~receivable ~~reasons~~of ~~for~~$654 million. ~~the~~The ~~increase~~Company inhas ~~operating~~a negative ~~cash flow~~working ~~are:~~

• Higher net income (see earnings discussion above) of approximately $124 million. • Higher stranded cost amortization of approximately $57 million. • Higher provision for deferred income taxes of approximately $32 million mainly attributable to net operating loss carryforwards. • Lower required funding of employee pension and other benefits of $156 million. • Increased regulatory liabilities and other deferred credits of $73 million.17

TheTable Company’s net cash used in investing activities decreased $55 million for the year ended March 31, 2005 from the comparable period in the prior year. This decrease was primarily a result of lower construction additions. Contents

~~The~~capital ~~Company’s~~balance ~~net~~of ~~cash~~$461 million ~~used~~primarily indue ~~financing~~to ~~activities increased~~ $~~594~~275 million ~~for~~of ~~the~~long-term debt due within one year ~~ended~~and ~~March 31,~~short-term ~~2005~~debt ~~from~~due to affiliates of $579 million (see the ~~comparable~~intercompany money ~~period~~pool indiscussion ~~prior~~below ~~year~~in Item 8). ~~This~~Cash ~~increase~~is ~~results~~being generated from ansales ~~equity~~(via electric rates) to ~~contribution~~offset ~~from~~stranded ~~Holdings~~cost ofamortization ~~$309 million~~(non-cash inexpense). ~~the~~This ~~prior~~excess ~~year~~cash ~~with~~is noused ~~comparable~~to ~~contribution~~repay indebt ~~the~~and ~~current~~for ~~year~~other ~~and~~operating anneeds. ~~increase~~As indiscussed below, the ~~net~~Company ~~payments~~believes ofit ~~short~~has ~~term~~sufficient ~~borrowings~~cash offlow and ~~$329 million~~borrowing capacity to fund working capital deficits as necessary in the near term.

~~Long-Term~~Net ~~Outlook:~~cash ~~The~~provided ~~Company’s~~by ~~total~~operating ~~capital~~activities ~~requirements~~decreased ~~consist~~approximately of$141 million ~~amounts~~ for ~~its construction~~the ~~program,~~fiscal ~~electricity~~year ended ~~and gas purchases~~March 31, ~~working~~2006 ~~capital~~from ~~needs~~the ~~and~~prior ~~maturing~~fiscal ~~debt issues~~year. ~~Construction~~The ~~expenditure~~primary ~~levels~~reasons for the ~~energy~~decrease ~~delivery~~in ~~business~~operating cash ~~are~~flow ~~generally consistent~~are: ~~from year-to-year.~~

~~The~~• ~~Company’s~~Decreased ~~long-term~~provision ~~debt~~for deferred income taxes of $77 million primarily due ~~within~~to ~~one~~the ~~year~~expiration isof federal bonus depreciation in December of 2004. • Increased accounts receivable of $~~550~~ 89 million atprimarily ~~March 31,~~due ~~2005.~~to Inthe ~~addition, construction~~higher ~~expenditures~~cost ~~planned~~of ~~within~~electricity ~~one~~and ~~year~~gas ~~are~~passed ~~estimated~~along to becustomers. • Increased materials and supplies of $~~240~~ 29 million. ~~These~~primarily ~~capital requirements~~due ~~are~~to ~~planned~~the higher cost of stored gas and the lower volume of gas sold relative to bethe ~~financed~~prior ~~primarily~~fiscal ~~from~~year ~~internally~~because ~~generated~~of ~~funds~~milder ~~and~~winter ~~borrowings from~~temperatures. • Increased other ~~National~~regulatory ~~Grid~~assets ~~USA~~of ~~companies~~$128 ~~through~~million ~~the~~primarily ~~intercompany~~due ~~money~~to ~~pool~~higher orcommodity ~~directly~~prices and timing differences between expenditures and their recovery from customers.

~~The~~These ~~following~~were ~~table~~partially ~~summarizes~~offset ~~long-term contractual cash obligations of the Company~~by:

	Contractual obligations due in
			Less than		1 - 3		4 - 5
($’s in Millions)	Total		one year		years		years		Thereafter
Long-term debt	$	3,475	$	550	$	475	$	950	$	1,500
Short-term debt due to affiliates*		401		401		—		—		—
Interest on long-term debt**		633		182		271		180		N/A
Electric purchase power commitments		4,505		437		848		750		2,470
Gas supply commitments		450		255		165		11		19
Derivative swap commitments***		619		204		379		36		—
Construction expenditures****		240		240		N/A		N/A		N/A
Total contractual cash obligations	$	10,323	$	2,269	$	2,138	$	1,927	$	3,989

•		Increased net income (see income discussion above) of $54 million.

•		Increased pension and other benefit plans expense of $7 million.

•		Increased accounts payable and accrued expenses of $30 million.

•		Increased accrued interest and tax expense of $60 million.

•		Lower required funding of employee pension and other benefits of $14 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 ~~Classified~~Company’s asnet 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 ~~current~~result ~~liability~~of asincreased ~~all~~restricted ~~borrowings~~cash ~~are~~due ~~payable~~to onequity ~~demand~~in hedge accounts related to the rise in the underlying commodity price.

18The 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.

~~Table~~Long-Term Outlook: The Company’s total capital requirements consist of ~~Contents~~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 is embarking on a Reliability Enhancement Program, to improve performance and reliability, which will result in increased capital expenditures over the next five years.

**		Forecasted, actual amounts could differ based on changes in market conditions. Amounts beyond 5 years are not forecasted and are therefore not included.
***		Forecasted, actual amounts could differ based on changes in market conditions.
****		Budgeted amount in which substantial commitments have been made. Amounts
		beyond 1 year are budgetary in nature and not considered contractual obligations
		and are therefore not included.

The Company’s long-term debt due within one year is $275 million at March 31, 2006. In addition, construction expenditures planned within one year are estimated to be approximately $337 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.

~~Expected contributions to the Company’s pension and post-retirement benefit plans trusts (as~~18 ~~disclosed in Item 8. Financial Statements and Supplementary Data — Note H — Employee Benefits) are not included on the above table.~~

InTable August 2003, the New York State PSC approved a settlement with the Company following an audit that identified reconciliation issues between the rate allowance and actual costs of the Company’s pension and other post-retirement benefits. The settlement resolved all issues associated with those obligations for the period prior to its acquisition by National Grid and, among other things, covered the funding of the Company’s pension and post-retirement benefit plans. As part of the settlement, the Company provided $100 million of tax-deductible funding by the end of fiscal 2003 and an additional $209 million of tax-deductible funding by fiscal 2004. Under the settlement, the Company will earn a rate of return of at least 6.60 percent (nominal) on the $209 million of funding through December 31, 2011 and is eligible to earn 80 percent of the amount by which the rate of return on the pension and post-retirement benefit funds exceeds 5.34 percent (nominal) measured as of that date. Contents

InThe ~~addition~~following totable ~~the~~summarizes ~~funding~~long-term ~~provided~~contractual incash ~~respect~~obligations of the ~~settlement referred to above, other contributions to the pension and post-retirement trusts were lower in the current fiscal year than in the prior years. In the prior years, the~~ Company ~~funded certain early retirement program costs.~~:

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 and 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.


			Contractual obligations due in
			Less than		1 - 3		4 - 5
($’s in millions)	Total		one year		years		years		Thereafter

Long-term debt	$	2,925	$	275	$	800	$	700	$	1,150
Short-term debt due to affiliates*		579		579		N/A		N/A		N/A
Interest on long-term debt**		509		147		232		130		N/A
Electric purchase power commitments		4,144		456		854		606		2,228
Gas supply commitments		557		295		247		11		4
Derivative swap commitments***		537		247		290		N/A		N/A
Construction expenditures****		337		337		N/A		N/A		N/A

Total contractual cash obligations	$	9,588	$	2,336	$	2,423	$	1,447	$	3,382

Capital requirements are planned to be financed primarily from internally generated funds and borrowings from other National Grid USA companies through the money pool or directly. The Company also has the ability to issue first mortgage bonds to the extent that there have been maturities or early redemptions since June 30, 1998. Through March 31, 2005, the Company had approximately $1.9 billion in such first mortgage bond maturities and early redemptions. This is expected to increase to approximately $2.4 billion in 2007 based on scheduled maturities.


*		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.

OnExpected ~~May 27,~~contributions ~~2004,~~to ~~the~~trusts ~~Company~~of ~~completed~~ the ~~refinancing~~Company’s ofpension ~~$115.7 million~~and ofpost-retirement ~~tax~~benefit ~~exempt bonds, 7.2%,~~plans ~~due~~(as ~~2029.~~disclosed ~~The bonds were reissued~~ in ~~auction rate mode~~Item 8. ~~These~~Financial ~~bonds~~Statements ~~were~~and ~~originally~~Supplementary ~~issued~~Data ~~in 1994~~— toNote ~~finance~~H ~~pollution~~— ~~control~~Employee ~~assets~~Benefits) are ~~located~~not atincluded ~~Nine~~in ~~Mile~~the ~~Point~~above ~~nuclear power station~~table.

~~New~~See ~~Accounting Standards: On December~~Item 8,. ~~2003,~~Financial ~~President~~Statements ~~Bush~~and ~~signed~~Supplementary ~~into~~Data ~~law~~— ~~the~~Note ~~Medicare Prescription~~D ~~Drug,~~— ~~Improvement~~Commitments and ~~Modernization Act of 2003 (the Act). The Act expands Medicare~~Contingencies, ~~primarily~~for ~~by adding~~ a ~~prescription~~detailed ~~drug~~discussion ~~benefit~~of ~~for~~the ~~those~~electric ~~who~~purchase ~~are~~power ~~eligible~~commitments ~~for~~and ~~Medicare~~the ~~starting~~gas insupply, storage ~~2006.~~and ~~The~~pipeline ~~Act~~commitments, ~~provides~~Note ~~employers~~L ~~currently~~— ~~sponsoring~~Derivatives ~~prescription~~and ~~drug~~Hedging ~~programs~~Activities for ~~Medicare-eligibles~~ ~~with~~ a ~~range~~detailed discussion of IPP ~~options~~and ~~for~~fossil/hydro ~~coordinating~~swaps ~~with~~and ~~the~~Note ~~new~~E ~~government~~— Long-~~sponsored program~~Term toDebt ~~potentially~~for ~~reduce~~a ~~program~~detailed ~~cost.~~discussion ~~These~~of ~~options~~mandatory ~~include supplementing the government~~debt repayments.

19The 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, the Company had approximately $2.1 billion in such first mortgage bond maturities and early redemptions. This increased to $2.4 billion in May of 2006.

~~Table~~New Accounting Standards: In December 2004, the Financial Accounting Standards Board (FASB) issued Statement of ~~Contents~~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.

~~program on a secondary payor basis or accepting a direct subsidy from the government to support a~~19 ~~portion of the cost of the employer’s program.~~

Paragraph 40Table of the Financial Accounting Standards Board’s (FASB) Statement of Financial Accounting Standard (SFAS) No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions” requires that presently enacted changes in laws affecting employer-sponsored retiree health care programs which take effect in future periods be considered in current-period measurements for benefits expected to be provided in those future periods. Therefore, under FAS 106 guidance, measures of plan liabilities and annual expense on or after the date of enactment should reflect the effects of the Act. Pursuant to guidance from the FASB under FSP FAS 106-2, the retiree health obligations will reflect the estimated subsidy payments expected from the federal government for the participant groups anticipated to qualify for the subsidy. Participant groups who are not expected to qualify, or have not yet been determined whether they will qualify, for the federal subsidy will not affect the retiree health obligations. If any portion of this group is subsequently determined to qualify for the subsidy, the retiree health care obligations will be adjusted at the time of that determination. The Company has chosen to apply the guidance prospectively, impacting retiree health costs. The Company adopted the provisions of FAS 106-2 on July 1, 2004. Any decrease in expense that results from the Act will be deferred and will be credited to customers. See Note H – Employee Benefits. Contents

In ~~December~~March ~~2004~~2005, the FASB issued ~~SFAS~~Interpretation No. ~~123R~~47 (FIN 47), “~~Share-Based~~Accounting ~~Payment.”~~for ~~This~~Conditional ~~Standard addresses the~~Asset ~~accounting~~Retirement ~~for~~Obligations.” ~~transactions~~FIN in47 ~~which~~will aresult ~~company receives employee services~~ in: ~~exchange for~~ (a) ~~equity instruments of the company or (b)~~ ~~liabilities~~more ~~that~~consistent ~~are~~recognition ~~based on the fair value~~ of ~~the~~liabilities ~~company’s~~relating ~~equity instruments or that may be settled by the issuance of such equity instruments. This Standard also eliminates the ability~~ to ~~account~~asset ~~for~~retirement ~~share-based~~obligations, ~~compensation transactions using Accounting Principles Board Opinion No.~~(b) ~~25,~~more ~~“Accounting~~information ~~for~~about ~~Stock~~expected ~~Issued~~future tocash ~~Employees,” and~~outflows ~~requires~~associated ~~that~~with ~~such~~those ~~transactions~~obligations beand ~~accounted~~(c) more ~~for~~information ~~using~~about ainvestments ~~fair~~in long-~~value-based~~lived ~~method. The Standard is~~assets ~~effective~~because ~~for~~additional ~~periods~~asset ~~beginning~~retirement ~~after~~costs ~~June 15,~~will ~~2005.~~be ~~The~~recognized ~~Company~~as ~~does~~part ~~not anticipate that adoption~~ of ~~SFAS~~the ~~123R~~carrying ~~will~~amounts ~~have a material impact on its results~~ of ~~operations or its financial position~~the assets.

InA ~~March 2005~~conditional retirement obligation, ~~FASB~~which ~~issued~~is ~~Interpretation~~referred to in SFAS No. 47143, “Accounting for ~~Conditional~~ Asset ~~Retirement~~ Retirement Obligations,” ~~(FIN~~is ~~47).~~defined in FIN 47 ~~will~~as ~~result~~a legal obligation to perform an asset retirement activity in which the timing and (aor) ~~more~~method ~~consistent~~of ~~recognition~~settlement ofare ~~liabilities~~conditional upon a future event that ~~relating~~may or may not be within the entity’s control. The obligation to perform the asset retirement activity ~~obligations,~~is ~~(b) more~~unconditional ~~information~~even though uncertainty exists about ~~expected~~the ~~future~~timing ~~cash~~and ~~outflows~~(or) method of ~~associated~~settlement. ~~with~~Uncertainty ~~those~~about ~~obligations~~the timing and (cor) ~~more~~method of settlement of a conditional asset retirement obligation should be factored into the measurement of the liability when sufficient information ~~about~~exists. ~~investments~~FIN in47 ~~long-lived~~also ~~assets~~clarifies when an entity has sufficient information to make a ~~because~~reasonable ~~additional~~estimate of the fair value of an asset retirement ~~costs~~obligation. ~~will~~FIN be47 ~~recognized~~is aseffective ~~part~~for the Company as of ~~the~~its ~~carrying~~March 31, ~~amounts~~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 ~~assets~~Company’s results of operations or financial position.

~~FIN~~In 47May 2005, ~~clarifies~~the ~~that~~FASB ~~the~~issued ~~term~~SFAS ~~conditional~~No. 154, ~~asset~~“Accounting ~~retirement~~Changes ~~obligation~~and asError ~~used~~Corrections, ina replacement of APB Opinion No. 20 and FASB Statement No. 3.” Previously, APB No. 20, “Accounting Changes,” and SFAS No. ~~143~~3, “Reporting Accounting ~~for~~Changes ~~Asset~~in ~~Retirement~~Interim ~~Obligations”~~Financial Statements,” ~~refers~~defined tothe requirements for the accounting for and the reporting of a ~~legal~~change ~~obligation~~in toaccounting ~~perform~~principle. anSFAS No. ~~asset~~154 ~~retirement~~requires ~~activity~~retrospective inapplication ~~which~~to ~~the~~prior ~~timing~~periods’ ~~and~~financial ~~(or) method~~statements of ~~settlement~~changes ~~are~~in accounting ~~conditional~~principle, onunless ~~a future~~it ~~event~~is ~~that~~impracticable ~~may~~to ordetermine ~~may~~either ~~not~~the beperiod-specific ~~within~~effects or the ~~control~~cumulative effect of the ~~entity~~change. ~~The~~When ~~obligation~~it is impracticable to ~~perform~~ determine the ~~asset~~period-specific effects ~~retirement~~of ~~activity~~an isaccounting ~~unconditional~~change ~~even~~on ~~though~~one ~~the~~or ~~uncertainty~~more ~~exists~~individual ~~about~~prior ~~the~~periods ~~timing and~~presented, ~~(or)~~SFAS No. ~~method~~154 requires ofthat ~~settlement.~~the ~~Uncertainty~~new ~~about~~accounting principle be applied to the ~~timing~~balances of assets and ~~(or) method~~liabilities as of ~~settlement~~the beginning of ~~a conditional~~the ~~asset~~earliest ~~retirement~~period ~~obligation~~for ~~should~~which retrospective application is practicable and that a corresponding adjustment be ~~factored~~made ~~into~~to the ~~measurement~~opening balance of ~~the~~retained ~~liability~~earnings for that period ~~when~~rather ~~sufficient~~than ~~information~~being ~~exists.~~reported ~~FIN~~in 47an ~~also~~income ~~clarifies~~statement. ~~when~~SFAS anNo. 154 ~~entity~~becomes ~~would~~effective ~~have~~for ~~sufficient~~fiscal years ~~information~~ending toafter ~~reasonably~~December 15, ~~estimate~~2005. ~~the~~The ~~fair~~Company ~~value~~adopted it as of anits ~~asset~~March 31, ~~retirement~~2006 ~~obligation~~fiscal year.

20On 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.

~~Table~~ITEM of7A. ~~Contents~~QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

~~This~~The ~~statement~~Company ~~will~~is beexposed ~~effective~~to ~~for~~certain ~~the~~market ~~fiscal~~risks ~~year~~because ~~ended~~of ~~March 31,~~transactions ~~2006~~conducted ~~for~~in the ~~Company. The~~normal ~~adoption~~course of ~~FIN~~business. 47The isfinancial ~~not~~instruments ~~expected~~held toor ~~have~~issued aby ~~material impact on~~ the Company’s ~~results~~are ofused ~~operations~~for investing, financing, hedging or ~~its~~cost ~~financial~~control ~~position~~and not for trading.

~~ITEM~~Quantitative ~~7A.~~and ~~QUANTITATIVE~~qualitative ~~AND~~disclosures ~~QUALITATIVE~~are ~~DISCLOSURES~~discussed ~~ABOUT~~by ~~MARKET~~market ~~RISK~~risk exposure category:

~~The Company is exposed to certain market risks because of transactions conducted in the normal~~20 ~~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.~~

QuantitativeTable andof qualitative disclosures are discussed by market risk exposure category: Contents

	§		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 ~~these~~commodity risks. This committee issues and oversees the Financial Risk ~~Management~~ 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.

~~Interest~~Commodity ~~Rate~~Price Risk: The Company is exposed to ~~changes~~commodity inmarket ~~interest~~price ~~rates~~fluctuations ~~through~~related ~~several~~to: (1) the ~~series~~cost of ~~adjustable~~ ~~rate~~electricity ~~promissory~~and ~~notes~~natural ~~and~~gas ~~short-term~~for ~~borrowings.~~resale ~~See~~to ~~Item~~its customers, and (2) 8.the ~~Financial~~impact ~~Statements~~that natural gas, electricity and ~~Supplementary~~ ~~Data~~oil —prices ~~Note~~have Eon —the ~~Long-Term~~swap ~~Debt~~contracts and ~~Note~~one Flarge ~~– Short~~non-~~Term~~Master Restructuring ~~Debt~~Agreement (MRA) IPP contract. ~~During~~For both gas and electricity, the ~~fiscal~~Company ~~year~~reconciles ~~ended~~and ~~March 31,~~recovers ~~2005~~commodity costs currently in rates to its customers who purchase the commodity. Where possible, the Company ~~converted~~takes ~~$115.7 million~~positions ofto ~~fixed-rate~~mitigate ~~long~~expected ~~term~~price ~~debt~~volatility but only to the extent ~~adjustable~~that ~~rate~~the ~~promissory~~quantities ~~notes.~~involved ~~Total~~are ~~adjustable~~based ~~rate~~on ~~promissory~~expectations ~~notes~~of ~~are~~delivery. ~~currently~~The ~~valued~~Company atattempts to ~~$575 million.~~mitigate Inexposure ~~December 2004~~through ~~the~~a program that hedges risks as appropriate. The Company ~~redeemed~~does not speculate on movements in the ~~remaining~~underlying ~~$25~~commodity prices.~~2 million~~ ofCommodity ~~Cumulative~~purchases are based on ~~Fixed/Adjustable~~analyses ~~Preferred~~performed ~~Stock,~~in ~~Series D.~~relation ~~There~~to ~~was~~expected ~~$400~~customer deliveries for electricity and natural gas.~~5 million~~ The volume of ~~short~~commodities ~~term~~covered ~~borrowing~~by ~~at March 31,~~hedging ~~2005~~contracts ~~from~~does not exceed amounts needed for customer consumption in the ~~inter-company~~normal ~~money~~course ~~pool~~of ~~maintained~~business byor ~~National~~to ~~Grid.~~offset Atprice ~~March 31,~~movements ~~2004 these~~in ~~borrowings~~the ~~totaled~~contracts ~~$463~~being hedged.~~5 million.~~

~~There~~Large iscustomers nothat ~~interest~~continue ~~rate~~to ~~cap~~purchase onelectricity from the ~~promissory~~Company ~~notes~~receive power from the NYISO at prevailing market prices and, in effect, assume the associated commodity price risk. ~~The~~For ~~interest~~the remaining ~~rates~~customers onthe ~~short~~Company ~~term~~meets ~~money-pool~~a significant portion of its commodity supply responsibility ~~borrowings~~through various physical and financial contracts. Some of these contracts are ~~tied~~indexed to ~~the published~~fuel prices, ~~30 day,~~primarily ~~commercial~~natural ~~paper~~gas. Although the current rate ~~with~~agreement ~~the~~allows ~~amount~~for ~~borrowed~~a ~~from~~pass-through of the commodity cost of power, the ~~National~~Company ~~Grid~~considers ~~money~~it ~~pool~~prudent ~~adjusted~~to ~~daily~~perform certain hedging activities as a means of controlling cost volatility caused by the operation of these indexing mechanisms.

~~The~~As ~~Company~~part ~~also~~of ~~maintains long-term debt at fixed interest rates. A controlling factor on~~ the ~~exposure~~ toMRA, ~~interest rate variations is~~ the ~~mix~~Company ofentered ~~fixed~~into torestated ~~variable~~indexed ~~rate~~swap ~~instruments~~contracts ~~maintained~~with ~~by the~~eight ~~Company~~IPPs. See ~~For March~~Item ~~31,~~8. ~~2005~~Financial ~~and~~Statements ~~2004, adjustable rate instruments comprise 19.7 percent~~ and ~~13.2 percent~~ ofSupplementary ~~total~~Data ~~long~~— ~~term~~Note ~~debt,~~L ~~respectively.~~— ~~The~~Derivatives ~~proportion~~and ~~of adjustable instruments to~~Hedging ~~total~~Activities, ~~capitalization~~for ~~increased~~a ~~because~~more ofdetailed ~~the~~discussion ~~conversion~~ of ~~$115.7 million~~these ofswap ~~fixed-rate debt to variable-rate debt~~contracts. ~~In the aggregate at March 31, 2005 and 2004 variable rate instruments do not~~

21The 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 million and $619 million at March 31, 2006 and 2005, respectively, and is recorded on the Company’s balance sheets under both current and noncurrent liabilities. The decrease is primarily due to the revaluation of the contracts at March 31, 2006 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

~~Table of Contents~~21

constituteTable a significant portion of total capitalization and debt, thus limiting the Company’s exposure to interest rate fluctuations. Contents

Ifare sensitive ~~interest~~to ~~rates~~changes ~~averaged 1 percent more~~ in ~~the~~anticipated ~~next~~future ~~fiscal~~market ~~year~~prices ~~versus 2005, the Company’s interest expense would increase~~ and ~~income~~changes ~~before~~in ~~taxes would decrease by approximately $9.75 million. This figure was derived by applying a hypothetical 1 percent variance to~~ the ~~variable rate~~indices ~~debt~~upon ofwhich ~~$575.0 million plus~~ the ~~short-term variable borrowings of $400.5 million at March 31, 2005.~~ ~~Changes~~indexed inswap ~~the~~contract ~~actual~~payments ~~cost~~are ~~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~~based.

~~Commodity~~If ~~Price~~the ~~Risk:~~indexed ~~The~~contract ~~Company~~price isincreased ~~exposed~~or todecreased ~~commodity~~by ~~market price fluctuations related to: (~~1~~) the~~%, ~~cost~~there ofwould ~~electricity~~be ~~and~~a ~~natural~~respective ~~gas for resale to its customers, and (2)~~$11 ~~the impact that~~million ~~natural~~increase ~~gas,~~or ~~electricity~~decrease ~~and~~in ~~oil~~the ~~prices~~present ~~have~~value onof the ~~swap~~projected ~~contracts~~over-market ~~and~~exposure ~~one~~associated ~~large non-Master~~with ~~Restructuring~~these ~~Agreement (MRA) IPP contract~~contracts. ~~For~~If ~~both gas and electricity,~~ the ~~Company~~market ~~reconciles and~~prices ~~recovers~~increased ~~commodity~~or ~~costs~~fell ~~currently~~by in1%, ~~rates~~there towould ~~its~~be ~~customers~~a ~~who~~respective ~~purchase the commodity. Where~~$5 ~~possible,~~million ~~the~~decrease ~~Company~~or ~~takes~~increase ~~positions~~ in ~~order to mitigate expected price volatility but only to~~ the ~~extent~~projected ~~that~~over-market ~~quantities~~exposure ~~are~~associated ~~based~~with onthese ~~expectations of delivery~~contracts. ~~The Company attempts to mitigate~~ ~~exposure~~If ~~through~~the adiscount ~~program~~rate ~~that~~was ~~hedges risks as appropriate~~0.5% ~~The~~higher ~~Company~~or ~~does~~lower, ~~not speculate on movements in~~ the ~~underlying~~respective ~~commodity~~net ~~prices.~~present ~~Commodity~~value ~~purchases~~of ~~are~~the ~~based on analyses performed~~projected inover-market ~~relation~~exposure toassociated ~~expected~~with ~~customer~~these ~~deliveries for electricity and natural gas. The volume of commodities covered by hedging~~ contracts ~~does~~would ~~not~~decrease ~~exceed amounts needed for customer consumption in the normal course of business~~ or toincrease ~~offset~~by ~~price movements in the contracts being hedged~~approximately $3.3 million.

~~Large~~The ~~customers~~area ~~that~~of ~~continue~~exposure to ~~purchase~~cash ~~electricity~~flow ~~from~~is in the ~~Company~~indexing ~~receive~~of ~~power from~~ the ~~NYISO at~~contract ~~prevailing market~~ prices ~~and,~~for ~~in effect, assume~~ the ~~associated~~IPP ~~commodity~~indexed swaps ~~price~~and ~~risk.~~a ~~For~~non-MRA ~~the remaining~~IPP ~~customers~~where ~~the~~payments ~~Company~~are ~~meets~~based aon ~~significant~~gas ~~portion~~prices. ofThe ~~its~~contract ~~commodity~~payments ~~supply~~under ~~responsibility~~the ~~through~~IPP ~~various~~swaps ~~physical~~ and ~~financial~~non-MRA ~~contracts.~~IPP ~~Some~~swaps ~~of these contracts~~ are indexed to the costs of fuel ~~prices~~, primarily natural gas. ~~Although~~As fuel costs rise, the payments the Company makes under those contracts increase. The current rate ~~agreement~~ plan allows ~~for~~the a pass-through of the commodity cost of power to customers; however, the Company still considers it prudent to ~~perform~~use certain ~~hedging~~financial ~~activities~~instruments ~~as a~~to ~~means~~limit ~~of controlling cost volatility caused by~~ the ~~operation~~impact of ~~these~~commodity fluctuations ~~indexing~~on ~~mechanisms~~these payments.

AsThe ~~part~~Company ofhas 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 ~~restated~~fixed-for-floating swaps ~~indexed~~on ~~swap~~gas-basis ~~contracts~~costs. ~~with~~To ~~eight~~hedge ~~IPPs.~~the non-MRA IPP contract, the Company purchased NYMEX gas futures. See Item 8. — Financial Statements and Supplementary Data — Note L — Derivatives and ~~Hedging~~ Hedging Activities, for a more detailed discussion of these ~~swap~~ 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.

~~The~~Activity for the fair value of the ~~liability~~NYMEX ~~under~~futures ~~the swap contracts is based upon the difference between projected future market prices~~ and ~~projected~~gas ~~contract~~basis ~~prices~~swaps ~~applied~~for to the ~~notional~~fiscal ~~quantities~~year ~~and~~ended ~~discounted to the present value. This liability was approximately $619 million and $715 million at~~ March 31, ~~2005~~2006 ~~and 2004, respectively, and~~ is ~~recorded on the Company’s balance sheets~~ as afollows: “Liability for swap contracts.” The decrease is primarily due to revaluation of the contracts at March 31, 2005, in addition to normal contract settlements, partially offset by a lowering of the discount rate. The discount rate is a market-based rate representing the yield curve through the life of the contracts. Based upon the PSC’s approval of the restated contracts, including the indexed swap contracts, as part of the MRA and being provided a reasonable opportunity to recover the estimated indexed swap liability from customers, the Company has 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.


	*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	)

~~Table~~Gas Supply Price Risk: The cost of ~~Contents~~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.

IfThe ~~the~~Company ~~indexed~~attempts ~~contract price were~~ to ~~increase~~hedge orapproximately ~~decrease~~50% ~~by 1 percent, the Company would see a $12.1 million increase or decrease in the present value~~ of ~~the~~its ~~projected~~forecasted ~~over-market~~average ~~exposure associated~~demand ~~with~~for ~~these contracts. If~~ the ~~market~~October ~~prices were~~ to ~~increase or fall by 1 percent, the~~ ~~Company~~April ~~would~~period ~~see~~through a ~~$5.9 million~~program ~~decrease~~using ~~or increase~~ in ~~the projected over~~-~~market~~ground ~~exposure associated~~storage ~~with~~and ~~these~~financial ~~contracts~~instruments. IfNYMEX ~~the discount rate were one half percent higher or lower, the~~gas ~~net~~futures ~~present~~are ~~value of~~ the ~~projected over market exposure associated with these contracts would decrease~~ ~~or increase by approximately $5.1 million.~~

~~The area of exposure to cash flow is in the indexing of the contract prices for the IPP indexed~~22 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 pays 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.

TheTable 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. Contents

Asfinancial instruments used by the Company. Each NYMEX futures contract represents 10,000 Dth of gas. At March 31, 2006 and 2005, ~~gas~~the ~~futures~~mark-to-market ~~have~~net ~~been~~open ~~purchased~~position toof ~~hedge~~cash ~~approximately~~flow hedges ~~50 percent~~for ofgas ~~the~~supply was a loss of ~~amount~~$5 million ~~needed~~and toa ~~offset~~gain ~~gas~~of ~~price~~$7 million, ~~changes~~respectively. inThere ~~the~~were ~~period~~671 ~~ended~~and 593 open futures contracts at March 31, 2006 and March 31, 2005, respectively.

AtThe ~~March 31,~~following ~~2004,~~table details the ~~open~~fair ~~NYMEX~~value ~~futures~~activity ~~the~~for ~~Company~~gas ~~had~~cash inflow ~~place~~hedges tofor ~~hedge~~ the ~~payments~~fiscal ~~under~~year ~~these~~ended ~~contracts had a fair value gain of $20.2~~March ~~million.~~31, 2006:

Activity for the fair value of the NYMEX futures and gas basis swaps for the 12 months ended March 31, 2005, is as follows:


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

March 31, 2005 asset balance		5,930.0		$	7,233.4
New Contracts		13,980.0			—
Settled during the period		(13,200.0	)		(30,127.0	)
Mark-to-market adjustments		—			17,534.8

March 31, 2006 asset (liability) balance		6,710.0		$	(5,358.8	)

	Hedges of IPP Swaps						Hedges Non-MRA IPP
(in thousands of dths and dollars)	NYMEX Futures						NYMEX Futures
	Dth			Fair Value			Dth			Fair Value
March 31, 2004 asset		20,210.0		$	18,803.4			1,640.0		$	1,500.2
New contracts		40,783.7			—			3,216.3			—
Settled during period		(40,946.8	)		(19,449.6	)		(3,263.2	)		(1,602.6	)
Mark-to-market adjustments		—			25,659.7			—			2,108.5
March 31, 2005 asset		20,046.9		$	25,013.5			1,593.1		$	2,006.1

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.

~~Gas Supply Price Risk:~~ The ~~cost~~extent ofto ~~natural~~which ~~gas~~market ~~sold~~price tomovement ~~customers~~would ~~fluctuates~~affect ~~during~~ the ~~year with~~value ~~prices~~of ~~historically most volatile in~~ the ~~winter~~hedges ~~months.~~would ~~The~~be ~~Company’s~~matched ~~gas rate agreement~~by ~~includes~~an aoffsetting ~~provision~~change ~~for~~in the ~~collection~~anticipated orgas ~~pass back of increases or decreases in~~ purchased ~~gas~~ costs. ~~The~~for ~~PSC has also mandated that~~ the ~~Company~~quantity ~~attempt~~of ~~to reduce the price volatility in the~~ gas ~~commodity portion of customers’ bills~~hedged. ~~In response to this mandate~~ Therefore, ~~the~~for ~~Company’s Board of Directors has authorized~~ the ~~use~~quantities ~~of futures~~hedged, ~~options,~~variations ~~and~~in ~~swaps~~market tocosts ~~hedge~~would ~~against~~not ~~gas~~result ~~price fluctuations.~~in ~~The hedging program is consistent with the Financial Risk Management Policy and is~~any ~~monitored~~significant byimpact ~~the~~on ~~EPRMC~~earnings.

23Electricity 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, the mark-to-market net open position of electricity swap contracts was a gain of $0.3 million.

~~Table~~Interest Rate Risk: The Company is exposed to changes in interest rates through several series of adjustable ~~Contents~~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.

~~The~~There ~~Company~~is ~~attempts~~no tointerest ~~hedge~~rate ~~approximately~~cap ~~50 percent~~on ~~of its forecasted average demand for~~ the ~~October~~ topromissory ~~April~~notes. ~~period~~The ~~through~~interest arates ~~program~~on ~~using in~~short-~~ground~~term ~~storage~~money ~~and financial instruments. The~~pool ~~Company~~borrowings ~~uses~~are ~~NYMEX~~tied ~~gas~~to ~~futures.~~the ~~Each NYMEX futures contract represents 10~~published,~~000~~ ~~Dth~~30 day ofcommercial ~~gas.~~paper Atrate ~~March 31,~~with ~~2004~~ the ~~mark~~amount toborrowed ~~market net open position of cash flow hedges for gas supply was a gain of $4.1~~from ~~million.~~the ~~There~~National ~~were~~Grid ~~453~~money ~~open~~pool ~~futures~~adjusted ~~contracts at March 31, 2004~~daily.

The ~~following~~Company ~~table~~also ~~details~~maintains ~~the~~long-term ~~fair~~debt ~~value~~at ~~activity~~fixed ~~for~~interest ~~gas~~rates. ~~cash~~A ~~flow~~controlling ~~hedges~~factor ~~for~~on the exposure ~~12 months~~to interest rate variations is the mix of fixed to variable rate instruments maintained by ~~ended~~the Company. For March 31, 2006 and 2005:, adjustable rate instruments comprise 33.3% and 19.7% of total long-term debt, respectively.

Hedges of Gas Supply
	NYMEX Futures
(in thousands of dths and dollars)	Dth			Fair Value
March 31, 2004 asset		4,640.0		$	4,089.3
New Contracts		10,260.0			—
Settled during the period		(8,970.0	)		(9,947.2	)
Mark-to-market adjustments					13,091.3
March 31, 2005 asset		5,930.0		$	7,233.4

TheTable above activity coupled with the in-ground storage hedged approximately 50 percent 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, which are mitigated by regulatory rate recovery for the cost of gas purchased. Contents

~~The~~In ~~extent to which market price movement would affect~~ the ~~value~~aggregate ofat ~~the~~March 31, ~~hedges~~2006 ~~would~~and be2005, ~~matched~~variable byrate aninstruments ~~offsetting~~do ~~change~~not inconstitute ~~the~~a ~~anticipated~~significant ~~gas~~portion ~~purchased~~of ~~costs~~total ~~for~~capitalization ~~the~~and ~~quantity~~debt, ~~of gas hedged.~~thereby ~~Therefore,~~limiting ~~for~~ the ~~quantities~~Company’s ~~hedged,~~exposure ~~variations~~to ininterest ~~market~~rate ~~costs would not result in any significant impact on earnings~~fluctuations.

~~Electricity~~If ~~Price~~interest ~~Risk:~~rates ~~The~~averaged ~~Company~~1% ~~meets~~more ain ~~substantial~~the ~~portion~~next offiscal ~~its~~year ~~electricity~~versus ~~requirements through~~the afiscal ~~series~~year ofended ~~long-term physical and financial contracts. The remaining electricity~~March 31, ~~requirements~~2006, ~~are~~the ~~purchased~~Company’s atinterest ~~market~~expense ~~prices~~would ~~through~~increase ~~the~~and ~~NYISO.~~income Ifbefore ~~certain~~taxes ~~proscribed~~would ~~risk~~decrease ~~values~~by ~~are~~approximately ~~exceeded~~$11 million. ~~during~~This afigure ~~time~~was ~~when~~derived ~~the~~by ~~Company~~applying ~~forecasts~~ a ~~short~~hypothetical ~~power~~1% ~~situation,~~variance ~~the~~to ~~Company may use~~the ~~electricity~~variable ~~swaps~~rate todebt ~~lock~~of in$575 million aplus ~~price~~the ~~for~~short-term ~~electricity.~~variable Inborrowings ~~April~~of $567 ~~2003,~~million ~~the~~at ~~Company began utilizing~~March ~~NYMEX~~31, ~~electricity swap contracts to hedge electricity purchases~~2006. ~~The~~Changes ~~Company~~in ~~continues to evaluate~~ the ~~use~~actual cost of ~~hedging~~capital ~~instruments~~from tolevels ~~manage~~assumed ~~the~~in ~~cost~~rates ofwould ~~electricity~~create ~~purchased.~~either exposure Ator ~~March 31,~~opportunity ~~2005,~~for the ~~mark~~ toCompany ~~market~~until ~~net~~these ~~open~~changes ~~position~~could ofbe ~~electricity~~reflected ~~swap~~in ~~contracts~~future ~~was a gain of $1~~prices.~~1 million.~~

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

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

24ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

~~Table~~A. ofFINANCIAL ~~Contents~~STATEMENTS

~~ITEM~~• 8Report 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. ~~FINANCIAL~~• ~~STATEMENTS~~Consolidated ~~AND~~Balance ~~SUPPLEMENTARY~~Sheets ~~DATA~~at March 31, 2006 and 2005. • Consolidated Statements of Cash Flows for each of the three years in the period ended March 31, 2006. • Notes to Consolidated Financial Statements.

~~A. FINANCIAL STATEMENTS~~24

•Table 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, 2005. • Consolidated Balance Sheets at March 31, 2005 and 2004. • Consolidated Statements of Cash Flows for each of the three years in the period ended March 31, 2005. • Notes to Consolidated Financial Statements.Contents

25REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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

~~REPORT~~In OFour ~~INDEPENDENT~~opinion, ~~REGISTERED~~the ~~PUBLIC~~consolidated ~~ACCOUNTING~~financial ~~FIRM~~statements listed in the accompanying index present fairly, in all material respects, the financial position of Niagara Mohawk Power Corporation and its subsidiaries at March 31, 2006 and 2005, and the results of their operations and their cash flows for each of the three years in the period ended March 31, 2006 in conformity with 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 fairly, in all material respects, the information set forth therein when read in conjunction with the related 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 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.

To/s/ ~~the~~PricewaterhouseCoopers ~~Stockholders~~LLP ~~and Board of Directors of~~ ~~Niagara~~PricewaterhouseCoopers ~~Mohawk Power Corporation:~~LLP

InNew ~~our opinion~~York, ~~the~~New ~~consolidated financial statements listed in the accompanying index presents~~York ~~fairly, in all material respects, the financial position of Niagara Mohawk Power Corporation and its subsidiaries at March~~June 3129, ~~2005 and 2004, and the results of their operations and their cash~~2006 ~~flows for each of the three years in the period ended March 31, 2005 in conformity with accounting~~ principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the accompanying index present fairly, in all material respects, the information set forth therein when read in conjunction with the related 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 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.

~~/s/ PricewaterhouseCoopers LLP PricewaterhouseCoopers LLP~~25

Boston,Table Massachusetts May 18,of 2005 Contents

26NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES

~~Table~~Consolidated Statements of ~~Contents~~Operations (In thousands of dollars)

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


	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

	For the		For the			For the
	year ended		year ended			year ended
	March 31,		March 31,			March 31,
	2005		2004			2003
Operating revenues:
Electric	$	3,117,156	$	3,284,017		$	3,310,837
Gas		808,015		779,600			708,613
Total operating revenues		3,925,171		4,063,617			4,019,450
Operating expenses:
Purchased electricity		1,364,813		1,591,652			1,594,221
Purchased gas		509,543		478,647			393,796
Other operation and maintenance		708,606		793,110			840,367
Depreciation and amortization		200,793		200,650			198,253
Amortization of stranded costs		251,499		194,114			149,415
Other taxes		217,993		227,006			253,207
Income taxes		171,230		138,843			93,277
Total operating expenses		3,424,477		3,624,022			3,522,536
Operating income		500,694		439,595			496,914
Other income (deductions)		8,347		(7,198	)		(1,340	)
Operating and other income		509,041		432,397			495,574
Interest:
Interest on long-term debt		169,585		220,781			318,149
Interest on debt to associated companies		66,283		55,282			16,852
Other interest		9,924		16,644			34,702
Total interest expense		245,792		292,707			369,703
Net income		263,249		139,690			125,871
Dividends on preferred stock		2,928		4,430			5,568
Income available to common shareholder(s)	$	260,321	$	135,260		$	120,303

Consolidated Statements of Comprehensive Income
(In thousands of dollars)

Consolidated Statements of Comprehensive Income (In thousands of dollars)


	For the			For the			For the
	year ended			year ended			year ended
	March 31,			March 31,			March 31,
	2006			2005			2004

Net income	$	317,076		$	263,249		$	139,690
Other comprehensive income (loss), net of taxes:
Unrealized gains (losses) on securities		(337	)		732			1,731
Hedging activity		4,009			14,557			2,425
Change in additional minimum pension liability		358			—			(1,557	)
Reclassification adjustment for gains included in net income		(21,807	)		(4,943	)		—

Total other comprehensive income (loss)		(17,777	)		10,346			2,599

Comprehensive income	$	299,299		$	273,595		$	142,289

	For the		For the			For the
	year ended		year ended			year ended
	March 31,		March 31,			March 31,
	2005		2004			2003
Net income	$	263,249	$	139,690		$	125,871
Other comprehensive income (loss):
Unrealized gains (losses) on securities, net of tax		559		1,731			(710	)
Hedging activity, net of tax		9,787		2,425			600
Additional minimum pension liability		—		(1,557	)		—
Total other comprehensive income (loss)		10,346		2,599			(110	)
Comprehensive income	$	273,595	$	142,289		$	125,761

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

~~Per~~The ~~share~~accompanying ~~data~~notes isare ~~not~~an ~~relevant~~integral ~~because~~part ~~the~~of ~~Company’s~~these ~~common~~financial ~~stock is wholly-owned by Niagara Mohawk Holdings, Inc~~statements.

~~The accompanying notes are an integral part of these financial statements.~~26

27 Table of Contents

~~Table~~NIAGARA ofMOHAWK ~~Contents~~POWER CORPORATION AND SUBSIDIARY COMPANIES

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

	For the			For the			For the
	year ended			year ended			year ended
	March 31,			March 31,			March 31,
	2005			2004			2003
	2006			2005			2004
Retained earnings at beginning of period	$	~~220~~473,~~966~~287		$	85220,~~706~~966		$	2985,~~317~~706
Net income		~~263~~317,~~249~~076			~~139~~263,~~690~~249			~~125~~139,~~871~~690
Dividends on preferred stock		(21,~~928~~626	)		(42,~~430~~928	)		(54,~~568~~430	)
Dividend to Niagara Mohawk Holdings, Inc.		~~(8,000~~—	)		—(8,000	)		~~(63,914~~—	)
Retained earnings at end of period	$	~~473~~788,~~287~~737		$	~~220~~473,~~966~~287		$	85220,~~706~~966

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

2827

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

	March 31,		March 31,
	2005		2004
ASSETS
Utility plant, at original cost:
Electric plant	$	5,347,832	$	5,200,640
Gas plant		1,517,804		1,477,977
Common plant		330,437		333,789
Construction work-in-progress		69,702		152,821
Total utility plant		7,265,775		7,165,227
Less: Accumulated depreciation and amortization		2,108,379		2,078,328
Net utility plant		5,157,396		5,086,899
Goodwill		1,224,025		1,225,742
Pension intangible		40,339		10,990
Other property and investments		55,048		57,273
Current assets:
Cash and cash equivalents		19,922		26,840
Restricted cash (Note A)		7,367		12,163
Accounts receivable (less reserves of $126,085 and $124,200, respectively, and includes receivables from associated companies of $6,654 and $516, respectively)		571,552		578,654
Materials and supplies, at average cost:
Gas storage		3,498		11,226
Other		17,739		15,714
Derivative instruments (Note A and L)		35,326		24,393
Prepaid taxes		44,273		61,769
Current deferred income taxes (Note G)		307,431		273,135
Regulatory asset – swap contracts		203,558		182,000
Other		9,772		13,389
Total current assets		1,220,438		1,199,283
Regulatory and other non-current assets:
Regulatory assets (Note B):
Merger rate plan stranded costs		2,765,392		3,019,597
Swap contracts regulatory asset		415,394		533,367
Regulatory tax asset		79,933		151,080
Deferred environmental restoration costs		431,000		309,000
Pension and postretirement benefit plans		501,358		466,789
Additional minimum pension liability		194,302		157,068
Loss on reacquired debt		67,162		74,993
Other		330,094		288,427
Total regulatory assets		4,784,635		5,000,321
Other non-current assets		36,481		38,151
Total regulatory and other non-current assets		4,821,116		5,038,472
Total assets	$	12,518,362	$	12,618,659

Consolidated Balance Sheets
(In thousands of dollars)

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


	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

29The accompanying notes are an integral part of these financial statements.

~~Table of Contents~~28

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

	March 31,		March 31,
	2005		2004
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		12,961		2,615
Retained earnings		473,287		220,966
Total common stockholder’s equity		3,603,114		3,340,447
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
Cumulative preferred stock ($25 par value, optionally redeemable)		—		25,155
Authorized - 19,600,000 shares
Issued and outstanding – 0 and 503,100 shares, respectively
Long-term debt (Note E)		1,723,569		2,273,467
Long-term debt to affiliates (Note E)		1,200,000		1,200,000
Total capitalization		6,567,853		6,880,239
Current liabilities:
Accounts payable (including payables to associated companies of $36,440 and $42,485, respectively)		271,275		285,965
Customers’ deposits		26,900		26,133
Accrued interest		82,945		98,221
Short-term debt to affiliates (Note F)		400,500		463,500
Current portion of liability for swap contracts (Note A and L)		203,558		182,000
Current portion of long-term debt (Note E)		550,420		532,620
Other		107,871		125,461
Total current liabilities		1,643,469		1,713,900
Non-current liabilities:
Accumulated deferred income taxes (Note G)		1,711,630		1,551,223
Liability for swap contracts (Note A and L)		415,394		533,367
Employee pension and other benefits (Note H)		434,855		449,803
Liability for environmental remediation costs		431,000		309,000
Nuclear fuel disposal costs		145,562		143,265
Additional minimum pension liability		236,198		169,615
Cost of removal regulatory liability (Note O)		318,455		313,545
Other		613,946		554,702
Total other non-current liabilities		4,307,040		4,024,520
Commitments and contingencies (Note D)		—		—
Total capitalization and liabilities	$	12,518,362	$	12,618,659

NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES

~~The~~Consolidated ~~accompanying~~Balance ~~notes~~Sheets ~~are~~ (In anthousands ~~integral part~~ of ~~these financial statements.~~dollars)


	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

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

~~NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES~~29 ~~Consolidated Statements of Cash Flows (In thousands of dollars)~~

	Year			Year			Year
	ended			ended			ended
	March 31,			March 31,			March 31,
	2005			2004			2003
Operating activities:
Net income	$	263,249		$	139,690		$	125,871
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation and amortization		200,793			200,650			198,253
Amortization of stranded costs		251,499			194,114			149,415
Provision for deferred income taxes		180,722			148,435			123,950
Pension and other benefit plans expense		100,143			100,484			59,955
Cash paid to pension and postretirement benefit plan trusts		(109,330	)		(266,139	)		(178,969	)
Changes in operating assets and liabilities:
Net accounts receivable		7,102			(35,374	)		(15,493	)
Materials and supplies		5,703			(5,744	)		(377	)
Accounts payable and accrued expenses		(31,513	)		(74,946	)		143,015
Accrued interest		(15,276	)		(10,706	)		(2,588	)
Other, net		31,898			(41,093	)		9,281
Net cash provided by operating activities		884,990			349,371			612,313
Investing activities:
Construction additions		(266,012	)		(317,302	)		(244,814	)
Proceeds from the sale of generation assets		—			—			249,799
Change in restricted cash		4,796			13,187			(17,268	)
Other investments		2,651			6,563			1,256
Other, net		(1,640	)		(17,294	)		(17,678	)
Net cash used in investing activities		(260,205	)		(314,846	)		(28,705	)
Financing activities:
Dividends paid on preferred stock		(2,928	)		(4,430	)		(5,568	)
Dividends paid on common stock to Holdings (including a return of capital of $86.1 million for fiscal year 2003)		(8,000	)		—			(150,000	)
Reductions in long-term debt		(532,620	)		(1,319,490	)		(668,675	)
Proceeds from long-term debt		—			45,600			—
Proceeds from long-term debt to affiliates		—			700,000			500,000
Redemption of preferred stock		(25,155	)		(33,903	)		(2,131	)
Net change in short-term debt to affiliates		(63,000	)		265,500			(221,000	)
Equity contribution from parent		—			309,000			—
Other, net		—			—			(16,078	)
Net cash used in financing activities		(631,703	)		(37,723	)		(563,452	)
Net increase (decrease) in cash and cash equivalents		(6,918	)		(3,198	)		20,156
Cash and cash equivalents at beginning of period		26,840			30,038			9,882
Cash and cash equivalents at end of period	$	19,922		$	26,840		$	30,038
Supplemental disclosures of cash flow information:
Interest paid	$	258,735		$	336,147		$	336,102
Income taxes paid (received)	$	(54,940	)	$	(13,904	)	$	13,279

~~The~~NIAGARA ~~accompanying~~MOHAWK ~~notes~~POWER ~~are~~CORPORATION anAND ~~integral~~SUBSIDIARY ~~part~~COMPANIES Consolidated Statements of ~~these~~Cash ~~financial~~Flows (In ~~statements.~~thousands of dollars)


	Year			Year			Year
	ended			ended			ended
	March 31, 2006			March 31, 2005			March 31, 2004

Operating activities:
Net income	$	317,076		$	263,249		$	139,690
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation and amortization		203,994			200,793			200,650
Amortization of stranded costs		266,816			251,499			194,114
Provision for deferred income taxes		103,474			180,722			148,435
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		(82,100	)		7,102			(35,374	)
Materials and supplies		(23,695	)		5,703			(5,744	)
Accounts payable and accrued expenses		(1,194	)		(31,513	)		(74,946	)
Accrued interest and tax		44,711			(15,276	)		(10,706	)
Other regulatory assets		(169,622	)		(41,667	)		(46,137	)
Other, net		72,431			73,565			5,044

Net cash provided by operating activities		743,599			884,990			349,371

Investing activities:
Construction additions		(269,941	)		(266,012	)		(317,302	)
Change in restricted cash		(59,026	)		4,796			13,187
Other investments		8,023			2,651			6,563
Other, net		(58,084	)		(1,640	)		(17,294	)

Net cash used in investing activities		(379,028	)		(260,205	)		(314,846	)

Financing activities:
Dividends paid on preferred stock		(1,626	)		(2,928	)		(4,430	)
Dividends paid on common stock to Holdings		—			(8,000	)		—
Reductions in long-term debt		(550,420	)		(532,620	)		(1,319,490	)
Proceeds from long-term debt		—			—			45,600
Proceeds from long-term debt to affiliates		—			—			700,000
Redemption of preferred stock		—			(25,155	)		(33,903	)
Net change in short-term debt to affiliates		178,400			(63,000	)		265,500
Equity contribution from parent		—			—			309,000

Net cash used in financing activities		(373,646	)		(631,703	)		(37,723	)


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	$	244,499		$	258,735		$	336,147
Income taxes received	$	(16,210	)	$	(54,940	)	$	(13,904	)

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

~~NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES~~30

NOTESTable TOof CONSOLIDATED FINANCIAL STATEMENTS Contents

~~NOTE~~NIAGARA AMOHAWK –POWER ~~SUMMARY~~CORPORATION OFAND ~~SIGNIFICANT~~SUBSIDIARY ~~ACCOUNTING POLICIES~~COMPANIES

~~Basis~~NOTES ofTO ~~Presentation:~~CONSOLIDATED ~~Niagara~~FINANCIAL ~~Mohawk Power Corporation (the Company) is subject to regulation by~~STATEMENTS ~~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. The Company’s accounting policies conform to Generally Accepted Accounting 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.

~~The~~NOTE ~~Company~~A is— aSUMMARY ~~wholly-owned~~OF ~~subsidiary~~SIGNIFICANT ofACCOUNTING ~~Niagara Mohawk Holdings, Inc. (Holdings), which in turn~~POLICIES ~~is wholly-owned by National Grid USA (National Grid).~~

Basis of Presentation: Niagara Mohawk Power Corporation (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. The Company’s ~~consolidated~~accounting ~~financial~~policies ~~statements~~conform ~~include~~to ~~its~~Generally ~~accounts~~Accepted asAccounting Principles ~~well~~in asthe ~~those~~United States of ~~its~~America ~~wholly owned~~(GAAP), ~~subsidiaries.~~including ~~Inter~~the accounting principles for rate-~~company~~regulated ~~balances~~entities with respect to the Company’s transmission, distribution and ~~transactions~~gas ~~have~~operations (regulated ~~been~~business), ~~eliminated~~and are in accordance with the accounting requirements and ratemaking practices of the regulatory authorities.

~~Goodwill:~~Niagara ~~The~~Mohawk ~~acquisition of the Company was accounted for by the purchase method~~Holdings, ~~the~~Inc. ~~application of which~~(Holdings), ~~including~~ the ~~recognition~~parent ofcompany ~~goodwill, was recognized on the books~~ of the Company, ~~the most~~is ~~significant~~a ~~subsidiary~~wholly ~~of Holdings. The merger transaction resulted in approximately $1.2~~owned ~~billion~~subsidiary of ~~goodwill.~~National InGrid ~~accordance~~USA ~~with Statement of Financial Accounting Standards~~ (~~SFAS~~National Grid) No. ~~142,~~ ~~“Goodwill~~National ~~and~~Grid ~~Other~~is ~~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~~wholly ~~cash~~owned ~~flow~~subsidiary ~~approach incorporating its most recent business plan forecasts in the performance~~ of ~~the annual goodwill impairment test. The result of the annual analysis~~ ~~determined~~National ~~that~~Grid noplc ~~adjustment~~(formerly toknown ~~the~~as ~~goodwill~~National ~~carrying~~Grid ~~value~~Transco ~~was required~~plc).

~~Use of Estimates:~~ The ~~preparation~~Company’s ofconsolidated financial statements ininclude ~~conformity~~its ~~with~~accounts ~~GAAP~~as ~~requires management~~well toas ~~make~~those ~~estimates and assumptions that affect the reported amounts~~ of ~~assets~~its ~~and~~wholly ~~liabilities~~owned ~~and~~subsidiaries. ~~disclosure~~Inter-company ofbalances ~~contingent liabilities at the date of the consolidated financial statements~~ and ~~the~~transactions ~~reported~~have ~~amounts~~been ~~of revenues and expenses during the reporting period~~eliminated. ~~Actual~~ ~~results could differ from those estimates.~~

~~Utility Plant~~Goodwill: The ~~cost~~acquisition of ~~additions~~the toCompany ~~utility~~was ~~plant~~accounted ~~and~~for ~~replacements~~by ofthe ~~retirement~~purchase ~~units~~method, ofthe application ~~property~~of ~~are~~which, ~~capitalized.~~including ~~Costs~~the ~~include~~recognition ~~direct~~of ~~material~~goodwill, ~~labor~~was recognized on the books of the Company, ~~overhead~~the most ~~and~~significant ~~AFUDC~~subsidiary ~~(see~~of ~~below)~~Holdings. The merger transaction resulted in approximately $1.2 ~~Replacement~~billion of ~~minor~~goodwill. ~~items~~In accordance with Statement of ~~utility~~Financial ~~plant~~Accounting Standards (SFAS) No. 142, “Goodwill and Other Intangible Assets”, the ~~cost~~Company ofreviews ~~current~~its ~~repairs~~goodwill annually for impairment and ~~maintenance~~when ~~are charged~~events toor ~~expense~~circumstances indicate that the asset may be impaired. ~~Whenever~~The ~~utility~~Company utilized ~~plant~~a isdiscounted ~~retired,~~cash flow approach incorporating its ~~original~~most ~~cost,~~recent ~~together~~business ~~with~~plan forecasts in the ~~cost~~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 ~~removal,~~a settled ~~less~~IRS ~~salvage~~audit of pre-merger years, isthe ~~charged~~Company recorded a $9 million adjustment to ~~accumulated~~goodwill related ~~depreciation~~to a pre-merger tax contingency.

~~Allowance~~Use ~~for~~of ~~Funds Used During Construction (AFUDC)~~Estimates: The ~~Company~~preparation ~~capitalizes~~of ~~AFUDC~~financial asstatements ~~part~~in ~~of construction~~conformity ~~costs~~with inGAAP ~~amounts~~requires management ~~equivalent~~ to ~~the~~make ~~cost~~estimates ofand ~~funds~~assumptions ~~devoted~~that toaffect ~~plant~~the ~~under~~reported ~~construction for~~amounts ~~its~~of ~~regulated~~assets ~~business.~~and liabilities ~~AFUDC~~and ~~represents~~disclosure anof ~~allowance~~contingent ~~for~~liabilities at the ~~cost~~date of ~~funds~~the ~~used~~consolidated ~~to finance~~financial ~~construction.~~statements ~~AFUDC~~and isthe ~~capitalized~~reported inamounts ~~“Utility~~of ~~plant”~~revenues ~~with offsetting non-cash credits to “Other interest”~~ and ~~“Other~~expenses ~~income~~during ~~(deductions)”~~the onreporting ~~the~~period. ~~Consolidated~~Actual results ~~Statement~~could ofdiffer ~~Operations.~~from ~~This~~those ~~method~~estimates. ~~is in~~

32Utility 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.

~~Table~~Allowance for Funds Used During Construction (AFUDC): The Company capitalizes AFUDC as part of construction ~~Contents~~costs in amounts equivalent to the cost of funds devoted to plant under construction for its regulated business. AFUDC represents an allowance for the cost of funds used to finance

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~~, 2005 and 2004 were 1.59 percent and 1.22~~ percent, 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
	March 31,		March 31,			March 31,
	2005		2004			2003
($ in 000’s)
Other income (deductions)	$	1	$	(9	)	$	187
Other interest		606		565			384

~~Depreciation:~~construction. ~~For~~AFUDC ~~accounting~~is capitalized in “Utility plant” with offsetting non-cash credits to “Other interest” and ~~regulatory~~“Other ~~purposes,~~income (deductions)” on the ~~Company’s~~Consolidated ~~depreciation~~Statement of Operations. This method is ~~computed~~in accordance with an established rate-making practice under which a utility is permitted a return on, and the ~~straight-line~~recovery ~~basis~~of, ~~using~~prudently incurred capital costs through their ultimate inclusion in rate base and in the ~~average~~provision ~~service~~for ~~lives~~depreciation. AFUDC rates are determined in accordance with FERC and PSC regulations. The ~~Company~~AFUDC ~~performs~~rates ~~depreciation~~in effect at March 31, 2006 and 2005 were 3.49% and ~~studies~~1.59%, torespectively. ~~determine~~AFUDC ~~service~~is ~~lives~~segregated ofinto ~~classes~~its oftwo ~~property~~components, borrowed funds and ~~adjusts~~other funds, and is reflected in the ~~depreciation~~“Other ~~rates~~interest” ~~when~~and “Other income (deductions)” sections, respectively, in ~~necessary~~the Company’s Consolidated Statements of Operations. The amounts of AFUDC credits were recorded as follows:

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


	Year Ended		Year Ended		Year Ended
	March 31,		March 31,		March 31,
(In thousands of dollars)	2006		2005		2004

Other income (deductions)	$	—	$	1	$	(9	)
Other interest		2,040		606		565

	Year Ended		Year Ended		Year Ended
	March 31,		March 31,		March 31,
	2005		2004		2003
Asset Category:
Electric		35		34		34
Gas		43		44		42
Common		21		17		17

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.

~~Revenues:~~ The ~~Company~~weighted ~~bills~~average ~~its customers on a monthly cycle basis at approved tariffs based on energy delivered and a minimum customer~~ service ~~charge.~~life, ~~Revenues~~in ~~are~~years, ~~determined based on these bills plus an estimate~~ for ~~unbilled~~each ~~energy~~asset ~~delivered~~category ~~between~~is ~~the~~presented ~~cycle~~in ~~billing date and~~ the ~~end of~~table ~~the accounting period. The unbilled revenues included in accounts receivable at both March 31,~~below: ~~2005 and 2004 was approximately $110 million and $123 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 (ended December 2004 with the Company having the right to request an increase at any time, if needed), changes in accrued unbilled gas revenues are deferred. At March 31, 2005 and 2004, approximately $7 million and $9 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.


	Year Ended		Year Ended		Year Ended
	March 31,		March 31,		March 31,
	2006		2005		2004

Asset Category:
Electric		34		35		34
Gas		42		43		44
Common		20		21		17

33Revenues: 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 and 2005 was approximately $133 million and $110 million, respectively.

~~Table~~The Company recognizes changes in accrued unbilled electric revenues in its results of ~~Contents~~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 and 2005, approximately $6 million and $7 million, respectively, of unbilled gas revenues remain unrecognized in results of operations. The

~~In August 2001, the PSC approved certain rate plan changes. The changes allowed for certain~~32 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 continue to remain in effect under the Merger Rate Plan which became effective upon the closing of the merger on January 31, 2002.

TheTable PSC approved a multi-year gas rate settlement agreement (amended through the Company’s merger rate plan and ended in December 2004 with the Company having the right to request an increase 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 interim agreement that became effective November 1999. Such gas cost collection mechanism continues under the Merger Rate Plan. The Company’s gas cost collection mechanism provides for the collection or pass back of increases or decreases in purchased gas costs. Contents

~~Federal~~Company ~~and~~cannot ~~State~~predict ~~Income~~when ~~Taxes:~~unbilled ~~Regulated~~gas ~~federal~~revenues ~~and~~will ~~state~~be ~~income~~allowed 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~~be ~~years~~recognized toin ~~differences between~~results ~~the financial statement carrying amounts and the tax basis~~ of ~~existing assets and~~ ~~liabilities~~operations. ~~Deferred investment tax credits are amortized over the useful life of the underlying~~ ~~property.~~

~~Service~~In ~~Company~~August 2001, ~~Charges:~~the ~~National~~PSC ~~Grid~~approved ~~USA~~certain ~~Service~~rate ~~Company,~~plan ~~Inc~~changes., anThe ~~affiliated~~changes ~~service~~allowed ~~company~~for certain ~~operating~~commodity-related ~~pursuant~~costs to ~~the~~be ~~provisions~~passed ofthrough ~~Section~~to customers beginning September 132001. ofAt the ~~Public~~same time, ~~Utility~~a ~~Holding~~transmission ~~Company~~revenue ~~Act~~adjustment ofmechanism was implemented which reconciles actual and rate ~~1935,~~forecast ~~has~~transmission ~~furnished~~revenues ~~services~~for pass-back to, ~~the~~or ~~Company~~recovery atfrom, customers. The commodity adjustment clause and the ~~cost~~transmission ofrevenue ~~such~~adjustment ~~services~~mechanism ~~since~~remain ~~the~~in ~~merger~~effect ~~with~~under the ~~National~~Merger ~~Grid.~~Rate ~~These~~Plan ~~costs~~which ~~approximated~~became ~~$138 million~~effective ~~and~~upon ~~$113 million~~the ~~for~~closing of the ~~years~~merger ~~ended~~on ~~March~~January 31, ~~2005~~ ~~and 2004, respectively~~2002.

~~Cash~~The ~~and~~PSC ~~Cash~~approved ~~Equivalents:~~a ~~The~~multi-year gas rate settlement agreement (amended through the Company’s ~~considers~~Merger Rate ~~all~~Plan ~~highly~~and ~~liquid~~ended ~~investments,~~in ~~purchased~~December 2004 with anthe Company having the right to request a change in rates ~~original~~at ~~maturity~~any time, if needed) in July 2000 that includes a provision for the continuation of ~~three~~a ~~months~~full orgas cost ~~less~~collection mechanism, toeffective beAugust 2000. ~~cash~~This ~~and~~gas ~~cash~~cost ~~equivalents~~collection mechanism was originally reinstated in an interim agreement that became effective November 1999. Such gas cost collection mechanism continues under the Merger Rate Plan. The Company’s gas cost collection mechanism provides for the collection or pass-back of increases or decreases in purchased gas costs.

~~Restricted~~Federal ~~Cash~~and State Income Taxes: ~~Restricted~~Regulated ~~cash~~federal ~~consists~~and state income taxes are recorded under the provisions of ~~margin~~Financial ~~accounts~~Accounting ~~for~~Standards ~~hedging~~Board ~~activity,~~(FASB) SFAS ~~health~~No. 109 ~~care~~“Accounting for Income ~~claims~~Taxes”. ~~deposits,~~Income ~~New~~taxes ~~York~~have ~~State~~been ~~Department~~computed utilizing the asset and liability approach that requires the recognition of ~~Conservation~~deferred ~~securitization~~tax assets and liabilities for ~~certain~~the ~~site~~tax ~~cleanup,~~consequences of temporary differences by applying enacted statutory tax rates applicable to future years to differences between the financial statement carrying amounts and ~~worker’s~~the ~~compensation~~tax ~~premium~~basis ~~deposit~~of existing assets and liabilities. Deferred investment tax credits are amortized over the useful life of the underlying property.

~~Derivatives:~~Service ~~The~~ Company ~~accounts~~Charges: ~~for~~National ~~derivative~~Grid ~~financial~~USA ~~instruments~~Service ~~under SFAS No. 133~~Company, ~~“Accounting~~ ~~for Derivatives and Hedging Activities” (FAS 133), and SFAS No~~Inc. ~~149~~, ~~“Amendment~~an ofaffiliated ~~SFAS No. 133~~service ~~on Derivative Instruments and Hedging Activities~~company,~~” as amended. Under the provisions of FAS~~ ~~133,~~has ~~all~~furnished ~~derivatives~~services ~~except~~to ~~those qualifying for~~ the ~~normal~~Company ~~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~~cost ~~in its market value is generally deferred as a component~~ of ~~other~~such ~~comprehensive~~services ~~income~~since ~~until~~ the ~~transaction~~merger itwith ~~is hedging~~National ~~is completed~~Grid. ~~Conversely,~~These ~~the~~costs ~~change~~approximated in$160 million ~~the~~and ~~market~~$138 million ~~value~~for ~~of a derivative not designated as a cash flow hedge is deferred as a regulatory asset or liability as~~ the ~~Company~~years ~~has~~ended ~~received~~March 31, ~~approval~~2006 ~~from~~and ~~the~~2005, ~~PSC to establish a regulatory asset or liability for derivative instruments that did not~~respectively. ~~qualify for hedge~~

34Cash 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.

~~Table~~Restricted Cash: Restricted cash consists of ~~Contents~~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 $59 million increase in restricted cash for the fiscal year ended March 31, 2006 was primarily due to increased equity in hedge accounts related to the rise in underlying commodity prices.

~~accounting~~Derivatives: ~~and~~The ~~were~~Company ~~the~~accounts ~~result~~for ofderivative ~~regulatory~~financial ~~rulings~~instruments under SFAS No. 133, “Accounting Afor ~~cash~~Derivatives ~~flow~~and ~~hedge~~Hedging isActivities”, aand ~~hedge~~SFAS No. 149, “Amendment of aSFAS ~~forecasted~~No. 133 ~~transaction~~on orDerivative ~~the~~Instruments ~~variability~~and ofHedging ~~cash~~Activities,” ~~flows~~as toamended. beUnder ~~received~~the orprovisions ~~paid~~of ~~related~~SFAS toNo. 133, aall ~~recognized~~derivatives ~~asset or~~except ~~liability.~~those Toqualifying ~~qualify~~for asthe anormal ~~cash~~purchase/normal ~~flow~~sale ~~hedge,~~exception are recognized on the balance sheet at their fair value. ~~changes~~Fair invalue ~~the~~is ~~derivative~~determined ~~must~~using becurrent quoted ~~expected~~market toprices. ~~offset~~If ~~80%~~a tocontract ~~120%~~is ofdesignated ~~the~~as ~~changes~~a incash ~~fair~~flow ~~value~~hedge, orthe ~~cash~~change ~~flows~~in ofits ~~the~~market ~~hedged~~value ~~item.~~is generally

~~Comprehensive Income (Loss): Comprehensive income (loss) is the change in the equity of a company,~~33 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 additional minimum pension liability recognition, 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).

AdditionalTable 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 does not recognize its additional minimum pension liability (AML) for its qualified plan as a component of accumulated other comprehensive income but as a regulatory asset. The additional minimum pension liability for its non-qualified plan is recognized in accumulated other comprehensive income. Contents

~~Power~~deferred ~~Purchase~~as ~~Agreements:~~a ~~The~~component ~~Company~~of ~~accounts~~other ~~for~~comprehensive ~~its~~income ~~power~~until ~~purchase~~the ~~agreements~~transaction asit ~~executory~~is hedging is ~~contracts~~completed. ~~The~~Conversely, ~~Company~~the ~~assesses~~change ~~several~~in ~~factors~~the inmarket ~~determining~~value ~~how~~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 ~~account~~establish a regulatory asset or liability for ~~its~~derivative ~~power~~instruments that did not ~~purchase~~qualify ~~contracts~~for hedge accounting and were the result of regulatory rulings. ~~These~~A ~~factors~~cash ~~include:~~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 ~~term~~change ofin the ~~contract~~equity ~~compared~~of toa ~~the~~company, not ~~economic~~including ~~useful~~those ~~life~~changes ofthat result from shareholder transactions. While the ~~facility~~primary ~~generating~~component of comprehensive income (loss) is reported net income or loss, the ~~electricity;~~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 ~~the~~Minimum ~~involvement,~~Pension ifLiability: ~~any~~Additional minimum pension liability is recognized under SFAS No. 87, ~~that~~“Employers’ Accounting for Pensions”. Under current rate agreements with the PSC, the Company recovers pension costs from customers and therefore has inrecognized ~~operating~~its ~~the~~additional ~~facility;~~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 ~~the~~Purchase ~~amount~~Agreements: ofThe ~~any~~Company ~~fixed~~accounts ~~payments~~for ~~the~~its ~~Company~~power ~~must~~purchase ~~make~~agreements, ~~even~~which ifare ~~the~~not deemed ~~facility~~to ~~does~~be ~~not~~derivatives ~~generate~~or ~~electricity;~~leases, ~~and~~as executory contracts. The Company assesses several factors in determining how to account for its power purchase contracts. These factors include:

• the ~~level~~term of ~~control~~ the ~~Company~~contract ~~has~~compared ~~over~~to the ~~amount~~economic ofuseful ~~electricity~~life ~~generated~~of by the facility, ~~and~~generating ~~who bears~~ the ~~risk in the event the facility is unable to generate.~~electricity;

~~New~~• ~~Accounting~~the ~~Standards: On December 8~~involvement, ~~2003,~~if ~~President Bush signed into law the Medicare Prescription Drug~~any, ~~Improvement~~that ~~and Modernization Act of 2003 (~~the ~~Act).~~Company ~~The~~has ~~Act expands Medicare, primarily by adding a prescription drug benefit for those who are eligible for Medicare starting~~ in ~~2006.~~ ~~The~~operating ~~Act provides employers currently sponsoring prescription drug programs for Medicare-eligibles with a range of options for coordinating with~~ the new government-sponsored program to potentially reduce program cost. These options include supplementing the government program on a secondary payor basis or accepting a direct subsidy from the government to support a portion of the cost of the employer’s program. facility;

~~Paragraph 40~~• of the ~~FASB’s~~amount ~~SFAS~~of ~~No. 106,~~any ~~“Employers’~~fixed ~~Accounting~~payments ~~for~~the ~~Postretirement~~Company ~~Benefits~~must ~~Other Than~~make, ~~Pensions”~~even ~~requires~~if ~~that~~the ~~presently~~facility ~~enacted~~does ~~changes~~not ingenerate ~~laws~~electricity; ~~affecting employer-sponsored retiree health care programs which take effect in future periods be considered in current-period measurements~~ and

35 • 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.

~~Table~~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 ~~Contents~~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

~~for benefits expected to be provided in those future periods. Therefore, under FAS 106 guidance,~~34 measures of plan liabilities and annual expense on or after the date of enactment should reflect the effects of the Act. Pursuant to guidance from the FASB under FSP FAS 106-2, the retiree health obligations will reflect the estimated subsidy payments expected from the federal government for the participant groups anticipated to qualify for the subsidy. Participant groups who are not expected to qualify, or have not yet been determined whether they will qualify, for the federal subsidy will not affect the retiree health obligations. If any portion of this group is subsequently determined to qualify for the subsidy, the retiree health care obligations will be adjusted at the time of that determination. The Company has chosen to apply the guidance prospectively, impacting retiree health costs. The Company adopted the provisions of FAS 106-2 on July 1, 2004. Any decrease in expense that results from the Act will be deferred and will be credited to customers. See Note H – Employee Benefits.

InTable December 2004, the FASB issued SFAS No. 123R, “Share-Based Payment.” This Standard 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. This Standard also eliminates the ability to account for share-based compensation transactions using Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees,” and requires that such transactions be accounted for using a fair-value-based method. The Standard is effective for periods beginning after June 15, 2005. The Company does not anticipate that adoption of SFAS 123R will have a material impact on its results of operations or its financial position. Contents

~~In March~~April 2005, the ~~FASB~~SEC ~~issued~~delayed ~~Interpretation~~the effective date of SFAS No. ~~47,~~123R ~~“Accounting~~to ~~for~~annual, ~~Conditional~~rather ~~Asset~~than ~~Retirement~~interim, ~~Obligations”~~periods ~~(FIN~~that ~~47).~~begin ~~FIN~~after ~~47 will result in (a)~~June ~~more~~15, ~~consistent~~2005. ~~recognition~~The ofSEC’s ~~liabilities relating~~new torule ~~asset~~resulted ~~retirement~~in ~~obligations,~~a ~~(b) more~~six-month ~~information~~deferral ~~about~~for ~~expected future cash outflows~~the ~~associated~~Company. ~~with~~The ~~those~~adoption ~~obligations~~of ~~and~~SFAS ~~(c)~~No. ~~more~~123R ~~information~~at ~~about~~April 1, ~~investments~~2006 indoes ~~long-lived~~not ~~assets because~~have ~~additional~~a ~~asset~~material ~~retirement~~impact ~~costs~~on ~~will~~its results ~~be recognized as part~~ of ~~the~~operations ~~carrying~~or ~~amounts~~its offinancial ~~the assets~~position.

~~FIN~~In 47March 2005, ~~clarifies that~~ the ~~term~~FASB ~~conditional~~issued ~~asset~~Interpretation ~~retirement obligation as used in FASB Statement~~ No. ~~143~~47 (FIN 47), “Accounting for ~~Asset~~Conditional Asset Retirement Obligations.”, ~~refers~~FIN to47 awill ~~legal~~result ~~obligation to perform an asset retirement activity~~ in: ~~which the timing and~~ (ora) ~~method~~more ofconsistent ~~settlement~~recognition ~~are~~of ~~conditional on a~~liabilities ~~future~~relating ~~event that may or may not be within the control of the entity. The obligation~~ to ~~perform the~~ asset retirement ~~activity~~obligations, is(b) more ~~unconditional~~information ~~even~~about ~~though~~expected ~~the~~future ~~uncertainty~~cash ~~exists~~outflows associated ~~about~~with ~~the~~those ~~timing~~ obligations and (orc) ~~method~~more ofinformation ~~settlement. Uncertainty~~ about ~~the~~investments ~~timing~~in ~~and~~long-lived ~~(or) method of settlement of a~~assets ~~conditional~~because additional asset retirement ~~obligation~~costs ~~should~~will be ~~factored~~recognized ~~into~~as ~~the~~part ~~measurement~~ of the ~~liability when~~carrying ~~sufficient~~amounts ~~information exists. FIN 47 also clarifies when an entity would have sufficient information to reasonably estimate the fair value~~ of ~~an asset retirement obligation~~the assets.

~~This~~A ~~statement~~conditional ~~will~~retirement beobligation, ~~effective~~which ~~for~~is ~~the~~referred ~~fiscal~~to ~~year~~in ~~ended~~SFAS ~~March~~No. 31143, ~~2006~~“Accounting for Asset Retirement Obligations,” is defined in FIN 47 as a legal obligation to perform an asset retirement activity in which the ~~Company~~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 ~~adoption~~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 isalso ~~not~~clarifies ~~expected~~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 ~~its~~ financial position.

~~Reclassifications:~~In ~~Certain~~May 2005, ~~amounts~~the ~~from~~FASB ~~prior~~issued ~~years~~SFAS ~~have~~No. 154, ~~been~~“Accounting ~~reclassified~~Changes onand 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 ~~accompanying~~for the accounting for and the reporting of a change in accounting principle. SFAS No. ~~consolidated~~154 requires retrospective application to prior periods’ financial statements of changes in accounting principle, unless it is impracticable to ~~conform~~determine either the period-specific effects or the cumulative effect of the change. When it is impracticable to determine the ~~fiscal~~period-specific effects ~~2005~~of ~~presentation~~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.

36On 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

~~Table of Contents~~35

NOTETable Bof – RATE AND REGULATORY ISSUES Contents

~~The~~determine ~~Company’s financial statements conform to GAAP, including~~ the ~~accounting~~full ~~principles~~impact for rate-regulated entities with respect to its regulated operations. Substantively, SFAS No. 71 “Accounting for the Effects of Certain Types of Regulation” (FAS 71) permits a public utility, regulated on a cost-of-service basis, to defer certain costs, which would otherwise be charged to expense, when authorized to do so by the regulator. These deferred costs are known as regulatory assets, which in the case of the Company, are approximately $5 billion and $5.2 billion at March 31, 2005 and 2004, respectively. These regulatory assets are probable of recovery under the Company’s Merger Rate Plan and Gas Multi-Year Rate and Restructuring Agreement. The Company believes that the ~~regulated~~potential ~~cash~~requirements ~~flows to be derived from prices it will charge for electric service in the future, including the Competitive Transition Charges (CTCs), and assuming no unforeseen reduction in demand or bypass~~ of the ~~CTC~~Exposure orDraft ~~exit~~may ~~fees,~~have will be sufficient to recover the Merger Rate Plan stranded regulatory assets over the planned amortization period with a return. Under the Merger Rate Plan, the Company’s remaining electric business (electricity transmission and distribution business) continues to be rate-regulated on ~~a cost-of-service basis and, accordingly,~~its ~~the~~financial ~~Company continues to apply FAS 71 to these businesses~~statements. ~~Also, the Company’s Independent Power~~ ~~Producer (IPP) contracts and the Purchase Power Agreements (PPAs) entered into in connection with the generation divestiture continue to be the obligations of the regulated business.~~

InReclassifications: ~~the~~Certain ~~event~~amounts ~~the~~from ~~Company~~prior ~~determines,~~fiscal asyears ahave ~~result~~been ofreclassified ~~lower~~on ~~than expected revenues and/or higher than~~the ~~expected~~accompanying ~~costs,~~consolidated ~~that~~financial ~~its~~statements ~~net regulatory assets are not probable of recovery, it can no longer apply the principles of FAS 71 and would be required~~ to ~~record~~conform ~~an after-tax, non-cash charge against income for any remaining unamortized regulatory assets and liabilities. If the Company could no longer apply FAS 71, the resulting charge would be material~~ to the ~~Company’s~~fiscal ~~reported~~2006 ~~financial condition and results of operations~~presentation.

~~Under~~NOTE ~~the~~B ~~Merger~~— ~~Rate~~RATE ~~Plan,~~AND ~~the~~REGULATORY ~~Company is earning a return on most of its regulatory assets.~~ISSUES

~~Stranded~~The ~~Costs:~~Company’s ~~Under~~financial ~~the~~statements ~~Merger~~conform ~~Rate~~to ~~Plan~~GAAP, aincluding ~~regulatory~~the ~~asset~~accounting ~~was~~principles ~~established~~for rate-regulated entities that ~~included~~apply to its regulated operations. SFAS No. 71, “Accounting for the ~~costs~~Effects of ~~the~~Certain ~~Master~~Types ~~Restructuring~~of ~~Agreement (MRA)~~Regulation,” ~~the~~permits ~~cost~~a public utility that is regulated on a cost-of-service ~~any~~basis ~~additional~~to ~~IPP~~defer ~~contract~~certain ~~buyouts~~costs it would otherwise charge to expense, if authorized to ~~and~~do so by the regulator. These deferred ~~loss~~costs onare ~~the~~known ~~sale~~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 ~~generation~~rate ~~assets~~plans. The Company ~~MRA~~believes ~~represents~~the prices it will charge for electric service in the ~~cost~~future, including the CTCs, will be sufficient to ~~terminate~~recover and earn a return on the Merger Rate Plan’s stranded regulatory assets over their planned amortization periods, ~~restate~~assuming no unforeseen reduction in demand or bypass ~~amend~~of ~~IPP~~the ~~contracts~~CTC exit fees. The Company’s isongoing ~~also~~electricity ~~permitted~~business continues to ~~defer~~be rate-regulated ~~and~~on ~~amortize the~~a cost -of-service ~~any~~basis ~~additional~~under ~~IPP~~the ~~contract~~Merger ~~buyouts.~~Rate ~~Beginning~~Plan ~~January 31~~and, ~~2002~~accordingly, the ~~Merger Rate Plan~~Company ~~stranded~~continues ~~costs~~to ~~regulatory~~apply ~~asset~~SFAS isNo. 71 ~~being~~to ~~amortized~~it. ~~unevenly~~In ~~over~~addition, ~~ten~~the ~~years~~Company’s ~~with~~Independent ~~larger~~Power ~~amounts~~Producer ~~being~~contracts, ~~amortized~~and inthe Purchased Power Agreements, which were entered into when the ~~latter~~Company ~~years~~exited the power generation business, ~~consistent~~continue ~~with~~to ~~projected~~be ~~recovery~~the ~~through~~obligations ~~rates~~of the regulated business.

~~Regulatory~~In ~~Tax~~the ~~Asset:~~event ~~The~~the ~~regulatory~~Company ~~tax~~determines, ~~asset~~as ~~represents~~a ~~the~~result of lower than expected ~~future~~revenues ~~recovery~~and ~~from~~(or) higher ~~ratepayers~~than ofexpected ~~the~~costs, ~~tax~~that ~~consequences~~its net regulatory assets are not probable of ~~temporary~~recovery, ~~differences~~it ~~between~~can no longer apply the ~~recorded~~principles ~~book~~of ~~basis~~SFAS No. 71 and ~~the~~ would be required to record an after-tax, ~~basis~~non-cash ofcharge against income for any remaining unamortized regulatory assets and liabilities. ~~This~~If ~~amount~~the isCompany could ~~primarily~~no ~~timing~~longer ~~differences~~apply ~~related~~SFAS ~~to depreciation~~No. 71, ~~These~~the ~~amounts~~resulting ~~are~~charge ~~recovered~~would ~~and~~be ~~amortized~~material asto the ~~related~~Company’s ~~temporary differences~~reported ~~reverse~~financial condition and results of operations.

~~Deferred~~The ~~Environmental~~Company ~~Restoration~~is ~~Costs:~~earning ~~This~~a ~~regulatory~~return ~~asset~~on ~~represents~~most ~~deferred costs associated with the Company’s share~~ of ~~the~~its ~~estimated~~regulatory ~~costs~~assets tounder ~~investigate~~its ~~and~~Merger ~~perform~~Rate ~~certain remediation activities at sites which it may be associated~~Plan. ~~The Company’s rate plans provide for~~ ~~specific rate allowances for these costs, with variances deferred for future recovery or pass-back to~~

37On 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

~~Table of Contents~~36

customers.Table The Company believes future costs, beyond the expiration of current rate plans, will continue to be recovered through rates. Contents

~~Pension~~year. ~~and~~An ~~Post-retirement~~audit ~~Benefit~~of ~~Plans:~~the ~~Excess~~deferral ~~costs~~amount ofby the ~~Company’s~~DPS ~~pension~~Staff ~~and post-retirement~~is ~~benefits~~ongoing. ~~plans~~A ~~over~~formal ~~amounts~~hearing ~~received~~process inhas been ~~rates~~established ~~are~~before ~~deferred~~a tohearing aofficer ~~regulatory~~at ~~asset~~the PSC to be ~~recovered~~litigate inthe alevels ~~future~~in ~~period~~the deferral account. AsUnder athe ~~result~~hearing ofschedule, the ~~closing~~Staff ofwill ~~the~~be ~~merger,~~filing ~~the~~testimony ~~Company~~setting ~~revalued~~ forth its ~~assets~~initial adjustments ~~and~~in ~~liabilities,~~early ~~which~~August. ~~resulted~~The inCompany anwill ~~increase~~continue to defer costs and revenues, as applicable, through the end of the Merger Rate Plan on December 31, 2011. The Company’s ~~postretirement~~future ~~liability~~filings for recovery of ~~approximately~~deferred ~~$440 million~~amounts are subject to regulatory review and approval.

~~Additional~~Stranded ~~Minimum~~Costs: ~~Pension~~Under ~~Liability:~~the ~~The~~Merger ~~offset~~Rate toPlan, a regulatory asset was established that included the costs of the Master Restructuring Agreement (MRA), the cost of any additional ~~minimum~~IPP ~~pension~~contract ~~liability~~buyouts ~~associated~~and ~~with~~the deferred loss on the sale of the Company’s ~~qualified~~generation ~~pension~~assets. ~~plan~~The isMRA ~~applied~~represents the cost to ~~this~~terminate, ~~regulatory~~restate ~~asset~~or onamend ~~a pre-tax~~IPP ~~basis~~contracts. ~~instead~~The ofCompany ~~after-tax~~is also permitted to ~~other~~defer ~~comprehensive~~and ~~income~~amortize the ascost ~~determined~~of byany additional IPP contract buyouts. Beginning February 1, 2002, the Merger Rate Plan stranded costs regulatory asset is being amortized unevenly over ten years with larger amounts ~~rulings~~being amortized in the latter years, consistent with projected recovery through rates.

~~Loss~~Regulatory onTax ~~Reacquired Debt~~Asset: The ~~loss on reacquired debt~~ regulatory tax asset represents the ~~costs~~expected tofuture recovery from ~~redeem~~ratepayers ~~certain~~of ~~long-term~~the ~~debt~~tax ~~securities,~~consequences ~~which~~of ~~were~~temporary ~~retired~~differences ~~prior~~between tothe ~~maturity.~~recorded ~~These~~book ~~amounts~~basis ~~are~~and the ~~amortized~~tax asbasis ~~interest~~of ~~expense~~assets ~~ratably~~and ~~over~~liabilities. ~~the~~This ~~lives~~amount ofis ~~the~~primarily timing differences related ~~issues~~to depreciation. inThese ~~accordance~~amounts ~~with~~are ~~PSC~~recovered and amortized as the related temporary differences ~~directives~~reverse.

~~Other:~~Deferred ~~Included~~Environmental inRestoration ~~the~~Costs: ~~other~~This regulatory asset isrepresents deferred costs associated with the ~~accumulation~~Company’s share of ~~numerous~~the ~~miscellaneous regulatory~~estimated ~~deferrals,~~costs ~~income~~to ~~earned~~investigate onand ~~gas~~perform ~~rate~~certain remediation ~~sharing~~activities ~~mechanisms,~~at ~~the~~sites ~~incentive~~with ~~earned~~which onit ~~the sale~~may ofbe ~~the~~associated. ~~fossil~~The ~~and~~Company’s ~~hydro~~rate ~~generation~~plans ~~assets~~provide for ~~and~~specific ~~certain~~rate ~~New~~allowances ~~York~~for ~~Independent~~these ~~System Operator (NYISO)~~ costs, ~~that~~with ~~were~~variances deferred for future recovery or pass-back to customers. The Company believes future costs, beyond the expiration of current rate plans, will continue to be recovered through rates.

~~See~~Pension ~~Notes H, D~~ and LPost-retirement ~~for~~Benefit aPlans: ~~discussion~~Excess costs of ~~regulatory~~the ~~asset~~Company’s ~~accounts~~pension ~~— Pensions~~ and ~~postretirement~~ post-retirement benefits ~~Plans,~~plans ~~Deferred~~over ~~environmental~~amounts ~~restoration~~received ~~costs~~in ~~and~~rates ~~Swap~~are ~~contracts~~deferred to a regulatory asset, to ~~respectively~~be recovered in a future period.

~~NOTE~~Additional CMinimum –Pension ~~ACCUMULATED~~Liability: ~~OTHER~~The ~~COMPREHENSIVE~~offset ~~INCOME~~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.

	Unrealized			Additional					Total
	Gains and			Minimum					Accumulated
	Losses on			Pension					Other
	Available-for-			Liability			Cash Flow		Comprehensive
($ in 000’s)	Sale Securities			Adjustment			Hedges		Income
March 31, 2003	$	(584	)	$	—		$	600	$	16
Unrealized gains (losses) on securities, net of taxes		1,731								1,731
Hedging activity, net of taxes								2,425		2,425
Change in additional minimum pension liability					(1,557	)				(1,557	)
March 31, 2004	$	1,147		$	(1,557	)	$	3,025	$	2,615
Unrealized gains on securities, net of taxes		559								559
Hedging activity, net of taxes								9,787		9,787
March 31, 2005	$	1,706		$	(1,557	)	$	12,812	$	12,961

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.

38Other: 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.

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

~~Taxes on other comprehensive income for the following periods were:~~37

	For the		For the year		For the
	year ended		ended		year ended
	March 31,		March 31,		March 31,
($ in 000’s)	2005		2004		2003
Unrealized gain/(losses) on securities	$	373	$	1,154	$	758
Hedging activities		6,524		1,617		(452	)

NOTE DC –— ~~COMMITMENTS~~ACCUMULATED ~~AND~~OTHER ~~CONTINGENCIES~~COMPREHENSIVE INCOME (LOSS)

Commodity Reconciliations: As part of the Company’s ongoing reconciliation of commodity costs and revenues, the Company identified several adjustments for the period from October 1, 2001 through April 30, 2003, and included them in filings with the PSC. Specifically, the Company requested recovery of $36 million of commodity costs associated with the under-reconciliation of New York Power Authority (NYPA) hydropower revenues in its commodity adjustment clause, and proposed to refund $24 million associated with other revenues that were not included in the commodity adjustment reconciliation. Following the filing, the PSC Staff completed a comprehensive audit of the Company’s commodity costs and revenues from October 1, 2001 through December 31, 2003, and the Staff and the Company agreed that a refund of $2.8 million should be provided to customers through that period. The PSC approved the refund on December 20, 2004.


	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	)

~~Long-Term Contracts for the Purchase of Electric Power:~~ The ~~Company~~deferred ~~has~~tax ~~several~~benefit ~~types of long-term contracts for the purchase of electric power. The Company’s commitments under these long-term contracts, as of March~~(expense) ~~31,~~on ~~2005~~other ~~are~~comprehensive ~~summarized~~income infor the ~~table~~following ~~below. The Company did not enter into~~periods ~~any new agreements in fiscal 2005 or 2004. For a detailed discussion of the financial swap~~was: ~~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.~~

(In thousands of dollars)
	For the			For the			For the
Fiscal Year
	year ended			year ended			year ended
Ended	Estimated
	March 31,			March 31,			March 31,
March 31,	Payments
(in thousands of dollars)	2006			2005			2004
2006	$	437,266
Investment activities	$	225		$	(488	)	$	(1,127	)
2007		430,807
Hedging activities		(2,673	)		(9,705	)		42
2008		416,889
Change in additional minimum pension liability		(239	)		—			1,038
2009		408,397
Reclassification adjustment for gain included in net income		14,538			3,295			(1,685	)
2010		342,060
Thereafter		2,470,043

IfNOTE ~~the~~D ~~Company~~— ~~needs~~COMMITMENTS ~~any~~AND ~~additional energy to meet its load it can purchase the electricity~~CONTINGENCIES from other IPPs, other utilities, other energy merchants or through the NYISO at market prices. Substantially all of these contracts require power to be delivered before the Company is obligated to make payment.

39Long-Term Contracts for the Purchase of Electric Power: The Company has several types of long-term contracts for the purchase of electric power. The Company’s commitments under these long-term contracts, as of March 31, 2006, are summarized in the table below. The Company did not enter into any new agreements in fiscal 2006 or 2005. 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.

~~Table of Contents~~38

GasTable 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. Contents

The table below sets forth the Company’s estimated commitments at March 31, 2005, for the next five years, and thereafter.


(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

(In thousands of dollars)
Fiscal Year
Ended			Gas Storage/
March 31,	Gas Supply		Pipeline
2006	$	198,056	$	56,919
2007		60,070		53,660
2008		—		51,713
2009		—		5,310
2010				5,310
Thereafter		—		19,266

If the Company needs any additional energy to meet its load, it can purchase the electricity from other IPPs, utilities, energy merchants or through the NYISO at market prices. Substantially all of these contracts require power to be delivered before the Company is obligated to make payment.

~~With~~Gas ~~respect to firm gas supply commitments~~Supply, ~~the~~Storage ~~amounts~~and ~~are~~Pipeline ~~based~~Commitments: ~~upon~~In ~~volumes~~connection ~~specified~~with ~~in the~~its ~~contracts~~regulated ~~giving~~gas ~~consideration~~business, ~~for~~ the ~~minimum take provisions. Commodity prices are based on~~ ~~New~~Company ~~York~~has ~~Mercantile~~long-term ~~Exchange quotes and reservation charges, when applicable. Storage and pipeline capacity~~ commitments’ ~~amounts~~with ~~are~~a ~~based~~variety ~~upon~~of ~~volumes~~suppliers ~~specified in the contracts,~~ and ~~represent demand~~pipelines ~~charges~~to ~~priced~~purchase ~~at current filed tariffs. At March 31, 2005, the Company’s firm~~ gas ~~supply~~ ~~commitments have varying expiration dates~~commodity, ~~the~~provide ~~latest of which is November 2006. The~~ gas storage ~~and~~ ~~transportation~~capability ~~commitments~~and ~~have~~transport ~~varying~~gas ~~expiration~~commodity ~~dates~~on ~~with~~interstate ~~the~~gas ~~latest being October 2012~~pipelines.

~~Environmental Contingencies:~~ The ~~normal~~table ~~ongoing~~below ~~operations~~sets ~~and~~forth ~~historic~~the ~~activities~~Company’s ofestimated ~~Niagara Mohawk~~commitments ~~are~~at ~~subject to various federal~~March 31, ~~state~~2006 and local environmental laws and regulations. Like most other industrial companies, our transmission and distribution companies use or generate some hazardous and potentially hazardous wastes and by-products. Under federal and state Superfund laws, potential liability for ~~the~~each ~~historic contamination~~ of ~~property may be imposed on responsible~~the ~~parties~~next ~~jointly~~five years and ~~severally, without fault, even if the activities were lawful when they occurred~~thereafter.

The Environmental Protection Agency (EPA), Department of Environmental Conservation (DEC), as well as private entities have alleged that Niagara Mohawk is a potentially responsible party under state or federal law for the remediation of an aggregate of approximately 100 sites, including 56 which are Company owned. Our most significant liabilities relate to former manufactured gas plant (MGP) facilities formerly owned or operated by our predecessors. Niagara Mohawk is currently investigating and remediating, as necessary, those MGP sites and certain other properties under agreements with the EPA and DEC.


(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

WeWith ~~believe~~respect ~~that~~to ~~our~~firm ~~ongoing~~gas ~~operations~~supply commitments, ~~and~~the ~~our~~amounts ~~approach~~are tobased ~~addressing~~upon ~~conditions~~volumes atspecified ~~historic~~in ~~sites,~~the contracts giving consideration to the minimum take provisions. Commodity prices are inbased ~~substantial~~on New ~~compliance~~York ~~with~~Mercantile ~~all~~Exchange ~~applicable~~quotes ~~environmental~~and ~~laws~~reservation charges, when applicable. Storage and ~~that~~pipeline capacity commitments’ amounts are based upon volumes specified in the ~~obligations~~ ~~imposed~~contracts onand usrepresent demand ~~are~~charges ~~not~~priced ~~likely~~in tocurrently ~~have~~filed atariffs. ~~material~~At ~~adverse~~March 31, ~~impact~~2006, onthe ~~our~~Company’s ~~financial~~firm gas supply ~~condition~~commitments have varying expiration dates, ~~results~~the latest of ~~operations~~which oris ~~cash flows~~March 2008. The ~~Merger~~gas ~~Rate~~storage ~~Plan~~and transportation ~~provides~~commitments ~~for~~have ~~the~~varying ~~continued application~~expiration ofdates ~~deferral~~with ~~accounting~~the ~~for~~latest ~~variations~~being October 2012.

40Environmental 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.

~~Table of Contents~~39

inTable spendingof from amounts provided in rates. The Company has recorded a regulatory asset representing the investigation, remediation and monitoring obligations to be recovered from ratepayers. Contents

WeThe ~~are~~Environmental ~~pursuing~~Protection ~~claims~~Agency ~~against~~(EPA), ~~potentially~~Department ~~responsible~~of ~~parties~~Environmental toConservation ~~recover~~(DEC), ~~investigation and~~as ~~remediation~~well ~~costs,~~as ~~but~~private weentities ~~cannot~~have ~~predict~~alleged that the ~~success~~Company ofis ~~such~~a ~~claims.~~potentially Asresponsible ofparty ~~March 31, 2005 and~~under ~~2004,~~state ~~the~~or ~~Company~~federal ~~has~~law ~~accrued~~for athe ~~liability~~remediation inof ~~the~~an ~~amount~~aggregate of ~~$431 million~~approximately ~~and~~100 ~~$309 million~~sites, including 51 ~~respectively,~~of which isare ~~reflected~~Company inowned. ~~the~~The Company’s ~~Consolidated~~most ~~Balance~~significant ~~Sheets.~~liabilities ~~The~~relate ~~increase~~to inmanufactured ~~the~~gas ~~liability~~plant ~~follows~~(MGP) facilities aformerly ~~recent~~owned ~~review~~or ~~and~~operated ~~reflects experience~~ by the ~~National~~Company’s ~~Grid~~previous ~~Companies~~owners. ~~in restoring~~The ~~similar~~Company ~~sites.~~is currently ~~The~~investigating ~~potential~~and ~~high~~remediating, ~~end~~as ofnecessary, ~~the~~those ~~range~~MGP atsites ~~March 31,~~and ~~2005~~certain isother ~~presently~~properties ~~estimated~~under atagreements ~~approximately~~with ~~$558 million~~the EPA and DEC.

~~Nuclear~~The ~~Contingencies:~~Company Asbelieves ofthat ~~March 31,~~obligations ~~2005~~imposed ~~and~~on ~~2004,~~ the Company ~~has~~because ~~a liability~~ of ~~$146 million and~~environmental ~~$143 million,~~laws ~~respectively,~~will ~~in other non-current liabilities for the disposal of nuclear fuel~~not ~~irradiated~~have ~~prior~~a tomaterial ~~1983.~~impact Inon ~~January 1983,~~its ~~the~~results ~~Nuclear Waste Policy Act~~ of ~~1982~~operations ~~(the~~or ~~Nuclear~~its ~~Waste Act)~~financial ~~established a cost of $~~condition.~~001~~ ~~per~~The ~~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~~Merger ~~disposal~~Rate ofPlan ~~nuclear fuel irradiated prior to 1983. The Nuclear Waste Act also~~ provides ~~three payment options~~ for ~~liquidating such liability and~~ the ~~Company~~continued ~~has~~application ~~elected~~of todeferral ~~delay~~accounting ~~payment,~~for ~~with interest,~~variations ~~until the year~~ in ~~which Constellation Energy Group Inc, who purchased the Company’s~~ ~~nuclear~~spending ~~assets,~~from ~~initially~~amounts ~~plans~~provided toin ~~ship~~rates ~~irradiated~~related ~~fuel~~ to anthese ~~approved~~environmental ~~DOE disposal facility~~obligations. ~~Progress~~ inAs ~~developing~~a result, the ~~DOE~~Company ~~facility~~ has ~~been~~recorded ~~slow~~a ~~and~~regulatory itasset isrepresenting ~~anticipated that~~ the ~~DOE~~investigation, ~~facility~~remediation and ~~will~~monitoring ~~not~~obligations beit ~~ready~~expects to ~~accept~~recover ~~deliveries~~from ~~until at least 2010~~ratepayers.

~~Legal~~The ~~Matters:~~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, 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.

~~Retail~~Nuclear ~~Bypass~~Contingencies: AAs ~~number~~ of ~~generators~~March 31, ~~have~~2006 ~~complained~~and or2005, ~~withheld~~the ~~payments~~Company ~~associated~~has ~~with~~a ~~the Company’s~~liability ~~delivery~~ of ~~station~~$151 million and ~~service~~$146 million, torespectively, ~~their~~in ~~generation~~other ~~facilities,~~non-current ~~arguing~~liabilities ~~that~~for ~~they~~the ~~should~~disposal ~~be permitted~~of tonuclear ~~bypass~~fuel irradiated ~~its~~prior ~~retail~~to ~~charges~~1983. ~~The~~In ~~FERC~~January 1983, ~~issued~~the ~~two~~Nuclear ~~orders~~Waste onPolicy ~~complaints~~Act ~~filed~~of by1982 ~~Niagara Mohawk’s~~(the ~~station~~Nuclear ~~service~~Waste Act) ~~customers~~established ina ~~December 2003,~~cost ~~allowing~~of ~~two~~$.001 ~~generators~~per tokWh of net ~~their~~generation ~~station service~~for ~~electricity~~current ~~over~~disposal aof ~~30-day~~nuclear ~~period~~fuel and provides ~~to avoid state-authorized charges~~ for ~~deliveries~~a ~~made over~~determination ~~distribution~~of ~~facilities.~~the ACompany’s ~~third~~liability ~~order~~to ~~involving~~the ~~affiliates of NRG Energy, Inc~~U. ~~is discussed below~~S. ~~These~~Department ~~orders~~of ~~directly~~Energy ~~conflict with Niagara Mohawk’s state-approved tariffs and~~ (DOE) for the ~~orders~~ disposal of ~~the~~nuclear ~~PSC~~fuel onirradiated ~~station~~prior ~~service~~to ~~rates~~1983. The ~~December 2003~~Nuclear ~~FERC~~Waste ~~orders,~~Act ifalso ~~upheld,~~provides ~~will~~three payment ~~permit~~options ~~these generators~~for toliquidating ~~bypass~~such ~~Niagara~~liability ~~Mohawk’s~~and ~~state-jurisdictional~~the ~~station~~Company ~~service~~has ~~charges~~elected ~~for~~to ~~electricity~~delay payment, with ~~including~~interest, ~~those~~until ~~set~~the ~~forth~~year in ~~the~~which ~~filing~~Constellation ~~that~~Energy ~~was~~Group ~~approved~~Inc., bywhich purchased the ~~PSC~~Company’s nuclear ~~on November 25~~assets, ~~2003.~~initially ~~Niagara Mohawk~~plans ~~filed~~to ~~for~~ship ~~rehearing~~irradiated offuel ~~these~~to ~~orders,~~an ~~and~~approved ~~the~~DOE ~~FERC~~disposal ~~denied~~facility. Progress ~~these~~in ~~requests~~developing inthe ~~January 2005. Niagara~~DOE ~~Mohawk~~facility has ~~appealed~~been ~~the~~slow ~~December 2003~~ and ~~January 2005~~it ~~orders~~is toanticipated that the ~~U.S.~~DOE ~~Court~~facility will ofnot ~~Appeals for~~be ~~the~~ready ~~District~~to ofaccept ~~Columbia~~deliveries ~~Circuit~~until at least 2010.

InLegal ~~an order dated May 10, 2004, in a related proceeding concerning the NYISO, the FERC reaffirmed~~Matters: its reasoning of the December 2003 orders. In so ruling, the FERC indicated that the NYISO station service order would be limited to merchant generators self-supplying their own power, and should not be interpreted to apply to self-supplying retail industrial and commercial customers that do not compete with incumbent utilities for customer load. The Company appealed the order to the Court of Appeals for the District of Columbia Circuit on July 9, 2004.

~~These~~Station ~~recent~~Service Cases (Niagara Mohawk Power Corp. v. Huntley Power L.L.C. et al., FERC ~~orders~~Docket No. EL03-27; AES Somerset, L.L.C. v. Niagara Mohawk Power Corp., FERC Docket No. EL03-204; Nine Mile Point Nuclear Station, L.L.C. v. Niagara Mohawk Power Corp., FERC Docket No. EL03-234; Keyspan-Ravenswood, Inc. v. NYISO, FERC Docket No. EL01-50-004.) A number of generators have complained ~~increased~~or withheld payments associated with the ~~risk~~Company’s delivery of station service to their generation facilities, arguing that ~~generators~~they ~~will~~should be ~~able~~permitted to bypass ~~local distribution~~its ~~company~~retail charges. ~~(including~~The FERC ~~stranded~~issued ~~cost~~two ~~recovery~~orders ~~charges)~~on ~~when~~complaints ~~receiving~~filed by the Company’s station service customers in December ~~through~~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. A third order in January 2005

4140

~~the~~involves ~~NYISO~~affiliates of NRG Energy, Inc. ~~Although~~These ~~subject~~orders todirectly ~~review~~conflict bywith the Company’s ~~PSC~~state-approved ~~Staff~~tariffs and the ~~other~~orders ~~parties~~of the PSC on station service rates. The orders, if finally upheld, will permit these generators to bypass the Company’s ~~believes~~state-jurisdictional station service charges for electricity, including those set forth in the filing that ifwas itapproved ~~experiences~~by ~~any~~the ~~lost~~PSC ~~revenue~~on ~~attributable~~November 25, to2003. ~~retail~~In ~~bypass~~the aggregate, itthe ~~will~~Company beis ~~permitted~~owed toapproximately $58 million as of March 31, 2006. The Company ~~recover~~appealed these ~~lost~~orders ~~revenues~~to ~~under~~the ~~its~~U.S. ~~Merger~~Court ~~Rate~~of ~~Plan~~Appeals for the District of Columbia Circuit, and the matters were consolidated for appeal. Oral argument was heard on April 10, 2006, and on June 23, 2006, the Court issued a decision upholding the FERC’s orders. The Company is reviewing the decision and considering whether to seek rehearing or further review.

~~Niagara~~The ~~Mohawk~~Court’s ~~Power~~order ~~Corp.~~upholding v.the ~~Huntley~~FERC ~~Power~~orders ~~L.L.C.,~~has ~~Dunkirk~~increased ~~Power~~the Lrisk that generators will be able to bypass local distribution company charges (including stranded cost recovery charges) when receiving service through the NYISO.~~L.C.~~ Although the Staff and ~~Oswego~~other ~~Harbor~~parties may challenge the Company’s position, ~~L.L.C.~~in the event the ~~The~~FERC orders are finally upheld, the Company ~~previously~~believes ~~owned~~that ~~three~~the ~~power~~provision ~~plants~~in (the ~~Plants),~~rate ~~which~~plan itthat permits ~~sold~~the Company to ~~three~~recover ~~affiliates~~lost ~~of NRG~~revenues ~~Energy,~~resulting ~~Inc.~~from a change in ~~1999:~~law ~~Huntley~~or ~~Power~~regulation ~~L.L.C.,~~would permit ~~Dunkirk~~it ~~Power~~to ~~L.L.C.~~recover ~~and~~the ~~Oswego~~lost ~~Harbor,~~revenues ~~L.L.C. (collectively,~~that result from the ~~NRG~~FERC ~~Affiliates)~~orders. ~~The~~These ~~Company~~amounts isare insubject to ~~involved~~regulatory inreview ~~several~~and ~~proceedings~~challenge ~~with~~as part of the ~~NRG Affiliates~~ongoing toaudit ~~recover~~of ~~bills~~the ~~for~~Company’s ~~station~~deferral ~~service~~account balance ~~rendered~~in toaccordance with the ~~Plants~~Merger Rate Plan.

~~The~~NOTE ~~most~~E ~~significant~~— ~~is a proceeding at FERC involving Niagara Mohawk’s complaint against the NRG Affiliates for failure to pay station service charges the Company assessed under its state~~LONG-~~approved retail~~TERM ~~tariffs. A state collection action and other proceedings have all been stayed pending the~~DEBT outcome of the FERC proceeding. As of March 31, 2005, the NRG Affiliates owed Niagara Mohawk approximately $43.5 million for station service. On November 19, 2004 and April 22, 2005, the FERC issued orders denying Niagara Mohawk’s complaint and found that the NRG Affiliates do not have to pay state-approved retail rates for station service. Niagara Mohawk has appealed the orders to the US Court of Appeals for the District of Columbia Circuit. The Court has consolidated this appeal with the two retail bypass cases discussed above. Although subject to review by the PSC Staff and other parties, the Company believes that if the Court were to uphold the FERC’s orders, the Company will be permitted to recover under its rate plans the station service charges not paid by the NRG Affiliates.

~~New~~Long-term ~~York~~debt ~~ISO~~consisted ~~Mitigation Error: On March 4, 2005, FERC issued an order on remand from the U.S. Court~~ of ~~Appeals for~~ the ~~District~~following ofat ~~Columbia Circuit (PSEG Energy Resource & Trade LLC v. New York Independent System Operator, FERC Docket No.~~March ~~EL02-16; H.Q. Energy Services~~31, ~~Inc.~~2006 v. New York Independent System Operator, FERC Docket No. EL01-19). In this case, the New York Independent System Operator (NYISO) had “mitigated”, or retroactively reduced, bid prices of approximately $3,500 per megawatt-hour to about $300 per megawatt-hour during a period of several hours on May 8 and ~~9, 2000. FERC had approved the NYISO’s action, but the Court of Appeals reversed FERC. On~~2005: remand, FERC reinstated the original higher market prices. Although the NYISO has asked for more time to determine the unmitigated prices, management currently estimates the Company’s exposure for increased power supply costs during those two days to range between $7 and $10 million, with interest.

NOTE E – LONG-TERM DEBT

(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

Long-term debt consisted of the following:


⁽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.

($ in 000’s)
			March 31,		March 31,			March 31,		March 31,
Series	Due		2005		2004		Series	2005		2004
First Mortgage Bonds:							Promissory Notes (3):
8%		2004	$	—	$	232,425	2015	$	100,000	$	100,000
6 5/8%		2005		110,000		110,000	2023		69,800		69,800
9 3/4%		2005		137,981		137,981	2025		75,000		75,000
7 3/4%		2006		275,000		275,000	2026		50,000		50,000
6 5/8%(1)		2013		45,600		45,600	2027		25,760		25,760

42 Table of Contents

~~Table~~Substantially all of ~~Contents~~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 3.20% 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.

($ in 000’s)
			March 31,		March 31,			March 31,			March 31,
Series	Due		2005		2004		Series	2005			2004
5.15%		2025		75,000		75,000	2027		93,200			93,200
7.2%(2)		2029		115,705		115,705	Total Promissory Notes		413,760			413,760
Total First Mortgage Bonds				759,286		991,711	Notes Payable to Holdings
							5.80% Due 2012		500,000			500,000
Senior Notes:							3.83% Due 2010		350,000			350,000
							3.72% Due 2009		350,000			350,000
5 3/8%		2004		—		300,000	Total Notes Payable to Holdings		1,200,000			1,200,000
7 5/8%		2005		302,439		302,439
8 7/8%		2007		200,000		200,000	Other		—			195
7 3/4%		2008		600,000		600,000	Unamortized discount		(1,496	)		(2,018	)
Total Senior Notes			$	1,102,439	$	1,402,439	Total Long-Term Debt		3,473,989			4,006,087
							Less long-term debt due
							within one year		550,420			532,620
							Long-Term Debt due after
							one year	$	2,923,569		$	3,473,467

The aggregate maturities of long-term debt for the five years subsequent to March 31, 2006, excluding capital leases, are approximately:

(1) Refinanced to auction rate mode on December 11, 2003. Effective interest rate at March 31, 2005 and March 31, 2004 was 2.70 percent and 1.18 percent, respectively. (2) Refinanced to auction rate mode on May 27, 2004. Effective interest rate at March 31, 2005 was 2.10 percent. (3) Refinanced to auction rate mode on May 1, 2003. Effective interest rate at March 31, 2005 and March 31, 2004 was 2.35 percent and 1.19 percent, respectively.


(in millions of dollars)
Fiscal Year	Amount

2007	$	275
2008		200
2009		600
2010		350
2011		350
Thereafter		1,150

Total	$	2,925

~~Substantially~~The ~~all~~current portion of ~~the~~capital ~~Company’s~~lease ~~operating~~obligations ~~properties~~is ~~are~~reflected ~~subject~~in tothe ~~mortgage~~other ~~liens~~current ~~securing~~liabilities ~~its~~line ~~mortgage~~item ~~debt.~~on ~~Several series of First Mortgage Bonds and Promissory Notes were issued to secure a like amount of tax-exempt revenue bonds issued by~~ the ~~New~~Consolidated ~~York~~Balance ~~State~~Sheet ~~Energy Research~~ and ~~Development~~ ~~Authority~~was ~~(NYSERDA).~~approximately ~~Approximately~~ $~~414~~1 million ~~of such securities bear interest~~ at ~~short-term~~ ~~adjustable interest rates (with an option to convert to other rates~~March 31, ~~including~~2006 ~~a fixed~~and ~~interest~~2005. ~~rate~~The ~~which~~non-current ~~would~~portion ~~require~~of ~~the~~capital ~~Company~~lease toobligations ~~issue~~is ~~First~~reflected ~~Mortgage~~in ~~Bonds~~the to“Other” ~~secure~~line ~~the debt)~~item ~~which~~on ~~averaged 1.69 percent for~~ the ~~year~~Consolidated ~~ended~~Balance ~~March 31,~~Sheet ~~2005,~~and ~~1.24 percent~~was ~~for~~approximately ~~the year ended March~~$4 ~~31,~~million ~~2004,~~and ~~1.36~~$5 ~~percent~~million ~~for~~at ~~the year ended~~ March 31, ~~2003 and are supported by bank direct pay~~2006 ~~letters of credit. Pursuant to agreements between NYSERDA~~ and ~~the Company~~2005, 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 (see Note F)respectively.

OnAt ~~May~~March 131, ~~2003~~2006 and 2005, the Company’s ~~completed~~long-term ~~the~~debt, ~~restructuring~~excluding ofintercompany ~~$414 million~~debt, ofhad ~~variable~~a ~~rate tax-exempt~~fair ~~bonds.~~value ~~The~~of ~~bonds~~approximately ~~are~~$1.8 billion ~~currently in the auction rate mode~~ and ~~are backed by bond insurance~~$2.4 billion, ~~which allowed~~respectively. ~~the~~The ~~Company~~fair tomarket ~~terminate~~value ~~$424 million~~ of ~~letter of credit facilities that were in place to~~the ~~provide~~Company’s ~~liquidity~~long-term ~~support~~debt ~~for~~was ~~principal~~estimated ~~and~~based ~~interest~~on ~~while~~ the ~~bonds~~debts’ ~~were~~coupons inand aremaining ~~variable~~lives ~~rate~~along ~~mode.~~with ~~The restructuring of~~ the ~~$414 million~~current ofinterest ~~tax-exempt~~rate ~~bonds was accomplished through a non-cash transaction~~conditions.

~~The~~NOTE ~~aggregate~~F ~~maturities~~— ~~of long~~SHORT-~~term~~TERM ~~debt for the five years subsequent to March 31, 2005,~~DEBT ~~excluding capital leases are approximately:~~

43The 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

~~Table of Contents~~42

($’s in millions)
Fiscal Year	Amount
2006	$	550
2007		275
2008		200
2009		600
2010		350
Thereafter		1,500
Total	$	3,475

~~The~~rate ~~current~~then ~~portion~~available ofto ~~capital~~money ~~lease~~pool ~~obligations~~depositors isfrom ~~reflected~~an eligible investment in readily marketable money market funds or the ~~other~~existing ~~current~~short-term ~~liabilities~~investment accounts maintained by money ~~line~~pool ~~item~~depositors onor the ~~Consolidated~~Service ~~Balance~~Company ~~Sheet~~during ~~and~~the ~~was~~period ~~approximately~~in $1question.~~0 million~~ atIn ~~March 31,~~the ~~2005~~event neither rate is ~~and~~one ~~2004.~~that ~~The~~is ~~non-current~~permissible ~~portion~~for a transaction because of ~~capital~~constraints ~~lease~~imposed ~~obligations~~by isthe ~~reflected~~state regulatory commission having jurisdiction over a utility participating in the ~~“Other”~~transaction, ~~line~~the rate is that ~~item~~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 ~~Consolidated~~money ~~Balance~~pool. ~~Sheet~~Funds ~~and~~may ~~was~~be ~~approximately~~withdrawn ~~$5 million~~from or repaid to the money pool at ~~March 31~~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.

AtThe ~~March 31, 2005, the~~ Company’s ~~long-term debt, excluding intercompany debt,~~ had ano ~~fair value of approximately $2.4 billion. The fair market value of the Company’s long~~short-term debt ~~was~~outstanding ~~estimated based~~to onthird-parties ~~the~~at ~~debts’~~March 31, ~~coupons~~2006 ~~and~~or ~~remaining lives along with the current interest rate conditions~~2005.

~~Early~~NOTE ~~Extinguishment~~G of— ~~Debt~~FEDERAL AND STATE INCOME TAXES

~~During~~Following is a summary of the ~~years~~components ~~ended~~of ~~March 31,~~federal ~~2005,~~and ~~2004~~state income tax and ~~2003,~~a reconciliation between the ~~Company~~amount ~~defeased~~of orfederal ~~redeemed approximately~~income ~~$0,~~tax ~~$658 million~~expense reported in the Consolidated Statements of Operations and ~~$122 million,~~the ~~respectively,~~computed inamount ~~long-term~~at ~~debt~~the ~~prior~~statutory totax ~~its~~rate: ~~scheduled maturity.~~

Losses resulting from the early redemption of debt are recorded as a regulatory asset. They are deferred and amortized as interest expense ratably over the lives of the related issues in accordance with PSC directives as discussed in Note B – Rate and Regulatory Issues – Loss on Reacquired Debt.


	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

4443

~~NOTE~~Shown Fbelow –is ~~SHORT-TERM~~the ~~DEBT~~reconciliation between federal income taxes and the tax computed at prevailing U.S. statutory rate on income before income taxes:

The Company had short-term debt outstanding of $401 million and $464 million at March 31, 2005, 2004, respectively, from the inter-company money pool. The Company has regulatory approval from the Securities and Exchange Commission (SEC), under the Public Utility Holding Company Act of 1935, to issue up to $1 billion of short-term debt. National Grid and certain subsidiaries, including the Company, operate a money pool to more effectively utilize cash resources and to reduce outside short-term borrowings. Short-term borrowing needs are met first by available funds of the money pool participants. Borrowing companies pay interest at a rate designed to approximate the cost of outside short-term borrowings. Companies that invest in the pool share the interest earned on a basis proportionate to their average monthly investment in the money pool. Funds may be withdrawn from or repaid to the pool at any time without prior notice. The average interest rate for the money pool was 1.80 percent, 1.11 percent and 1.62 percent for fiscal years 2005, 2004 and 2003, respectively.


	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~~(a) ~~Company~~Includes ~~had~~Carrying noCharges ~~short-term~~(Interest ~~debt~~Expense) ~~outstanding~~imposed toby ~~third-parties~~the ~~at March 31, 2005, 2004 or 2003~~PSC.

~~NOTE G – FEDERAL AND STATE INCOME TAXES~~44

FollowingTable is a summary of the components of federal and state income tax and a 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: Contents

	Year Ended March 31,
(In thousands of dollars)	2005			2004			2003
Components of federal and state income taxes:
Current tax expense (benefit):
Federal	$	(30,229	)	$	(12,003	)	$	(34,908	)
State		9,459			(474	)		14,320
		(20,770	)		(12,477	)		(20,588	)
Deferred tax expense (benefit):
Federal		177,180			128,426			111,157
State		3,542			20,022			(344	)
		180,722			148,448			110,813
Total	$	159,952		$	135,971		$	90,225
Total income taxes in the consolidated statements of operations:
Income taxes charged to operations	$	171,230		$	138,843		$	93,277
Income taxes credited to “Other income (deductions)”		(11,278	)		(2,872	)		(3,052	)
Total	$	159,952		$	135,971		$	90,225

The deferred tax liabilities (assets) were comprised of the following:


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	)

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

~~Reconciliation~~The ~~between~~Company and other related subsidiaries of National Grid USA have participated with National Grid Holdings, Inc. (NGHI), a wholly owned subsidiary of National Grid plc, in filing consolidated US federal income ~~taxes~~tax returns since joining the NGHI consolidated filing group upon the Company’s January 31, 2002 acquisition by National Grid. The Company’s tax provisions and tax accounts are calculated on a separate company basis. Federal income tax returns have been examined and all appeals and issues have been agreed upon by the Internal Revenue Service (IRS) and the Company through January 31, 2002, the acquisition date and final tax ~~computed~~return atyear ~~prevailing~~end Udate of the Company’s former consolidated filing group prior to its acquisition by National Grid.S In addition, federal income tax returns have been examined and all appeals and issues have been agreed upon by the IRS and the NGHI consolidated filing group through March 22, 2000. ~~statutory~~The ~~rate~~IRS is currently reviewing the onMarch 31, ~~income~~2001 ~~before~~and March 31, 2002 tax returns of the NGHI consolidated filing group which the Company joined upon its acquisition. The IRS has issued a preliminary notice of deficiency disallowing certain tax deductions taken in these consolidated US federal income ~~taxes:~~tax returns. These adjustments are being appealed. The Company has joint and several liability for any potential assessments against the consolidated group, for periods since it joined the group in February 2002. Management believes that the positions taken by the Company and its related subsidiaries 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.

	Year Ended March 31,
(In thousands of dollars)	2005			2004			2003
Computed tax	$	148,371		$	96,481		$	75,641
Increase (reduction) including those attributable to flow-through of certain tax adjustments:
Depreciation		16,982			21,397			12,183
Cost of removal		(5,664	)		(6,857	)		(6,730	)
Allowance for funds used during construction — (a)		(1	)		3			642
State income taxes		8,451			12,736			20,174
Non-deductible executive compensation		—			—			(9,878	)
Accrual to return adjustment		3,427			19,842			6,934
Debt premium and mortgage recording tax		487			(1,556	)		3,196
Real estate taxes		—			—			(9,300	)
E.S.O.P. dividends		(1,307	)		—			—
Dividends exclusion – federal income tax returns		(174	)		(149	)		—
Provided at other than statutory rate		(1	)		(2	)		(2	)
Voluntary Early Retirement Plan		—			—			(251	)
Medicare Act		(3,579	)		—			—
Subsidiaries		136			250			—
Deferred investment tax credit reversal		(2,866	)		(2,872	)		(3,029	)
Other		(4,310	)		(3,302	)		645
Total		11,581			39,490			14,584
Federal and State Income Taxes	$	159,952		$	135,971		$	90,225

In December 1998, the Company received a ruling from the IRS which provided that the amount of cash and the value of common stock that was paid by the Company to the subject terminated IPP Parties was deductible in 1998 which resulted in the Company not paying any regular federal

~~(a) Includes Carrying Charges (Interest Expense) imposed by the PSC.~~45

46 Table of Contents

~~Table~~income taxes for 1998, and further generated a substantial net operating loss for federal income tax purposes. The Company carried back a portion of ~~Contents~~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.

~~The~~There were no valuation allowances for deferred tax ~~liabilities (~~assets~~) were~~ ~~comprised~~at ofMarch 31, ~~the~~2006 ~~following:~~or 2005.

At March 31 (In thousands of dollars)	2005			2004
Alternative minimum tax	$	111,609		$	81,639
Unbilled revenues		23,458			22,611
Non-utilized NOL carryforward		105,212			318,216
Liability for environmental costs		198,621			148,325
Voluntary early retirement program		47,558			219,237
Bad debts		29,474			29,474
Pension and other post-retirement benefits		185,324			40,830
Other		209,550			265,082
Total deferred tax assets		910,806			1,125,414
Depreciation related		(921,928	)		(921,798	)
Investment tax credit related		(40,677	)		(43,203	)
Deferred environmental restoration costs		(200,175	)		(148,325	)
Merger rate plan stranded costs		(848,182	)		(896,816	)
Merger fair value pension and OPEB adjustment		(128,188	)		(146,898	)
Bond redemption and debt discount		(25,056	)		(30,772	)
Pension and other post-retirement benefits		(88,830	)		(110,163	)
Other		(61,969	)		(105,527	)
Total deferred tax liabilities		(2,315,005	)		(2,403,502	)
Net accumulated deferred income tax liability	$	(1,404,199	)	$	(1,278,088	)
Current portion (net deferred tax asset)		307,431			273,135
Net accumulated deferred income tax liability (non-current)	$	(1,711,630	)	$	(1,551,223	)

NOTE H — EMPLOYEE BENEFITS

~~The Company has been audited and reported on by the Internal Revenue Service (IRS) through~~Summary ~~December 31, 1998.~~

InThe ~~December 1998, the~~ Company ~~received~~has a ~~ruling~~non-contributory ~~from~~defined ~~the~~benefit ~~IRS~~pension ~~which~~plan ~~provided~~covering ~~that~~substantially ~~the amount of cash~~all ~~and~~employees. ~~the~~The ~~value~~pension ofplan ~~common~~is ~~stock~~a ~~that~~cash ~~was~~balance ~~paid~~pension byplan ~~the~~design ~~Company~~and tounder ~~the~~that ~~subject~~design, ~~terminated IPP Parties~~pay-based ~~was~~credits ~~deductible~~are inapplied ~~1998~~based ~~which~~on ~~resulted~~service ~~in the Company not paying any regular federal income taxes for 1998~~time, and ~~further~~interest ~~generated~~credits aare ~~substantial~~applied ~~net~~based ~~operating~~on ~~loss~~an ~~for~~average annual ~~federal~~30-year ~~income~~Treasury ~~tax~~bond ~~purposes~~yield. ~~The~~ ~~Company~~In ~~carried~~addition, ~~back~~ a ~~portion~~large number of ~~the~~employees ~~unused~~hired ~~net~~by ~~operating loss (NOL) to~~ the ~~years 1996 and~~Company ~~1997,~~prior ~~and~~to ~~also for the years 1988 through 1990, which resulted in federal income tax refunds of $135~~July ~~million~~1998 ~~that~~are ~~were~~cash ~~received~~balance indesign ~~January 1999.~~participants Aswho receive a ~~result~~larger ofbenefit ~~the~~if ~~merger~~so ~~with National Grid, the~~yielded ~~Company~~under ispre-cash ~~now~~balance ~~part~~conversion offinal ~~the~~average ~~consolidated~~pay ~~tax~~formula ~~return filing group of National Grid General Partnership (the parent company, through an intermediary entity, of National Grid)~~provisions. ~~The~~Employees ~~Company anticipates~~hired ~~that~~by the ~~consolidated tax filing group will be able to utilize the remaining NOL~~ ~~carryforward~~Company ~~prior~~following ~~to its expiration in 2019. The amount of~~ the ~~NOL carryforward as of March~~August ~~31, 2005~~1998 ~~and~~cash ~~2004~~balance ~~was~~design ~~$301 million~~conversion ~~and~~participate ~~$909 million,~~under ~~respectively.~~cash ~~National Grid’s ability to utilize~~balance ~~the~~design ~~NOL~~provisions ~~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~~only.

~~There~~A ~~were~~supplemental nononqualified, ~~valuation~~non-contributory ~~allowances~~executive ~~for~~retirement ~~deferred~~program ~~tax~~provides ~~assets~~additional defined atpension ~~March 31,~~benefits ~~2005~~for orcertain ~~2004~~executives.

47The 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.

~~Table~~Governed by the PSC’s “Statement of ~~Contents~~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.

~~NOTE~~Funding ~~H — EMPLOYEE BENEFITS~~Policy

~~Summary~~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.

~~The Company has a non-contributory defined benefit pension plan covering substantially all~~46 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.

SupplementalTable nonqualified,of non-contributory executive retirement program provides additional defined pension benefits for certain executives. Contents

~~The~~Plan ~~Company provides postretirement benefits other than pensions (PBOPs). PBOP benefits include~~Assets 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.

~~Funding~~The ~~Policy~~target asset allocations for the benefit plans are:

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.


	Pension Benefits						Non-Union PBOPs						Union PBOPs
	2006			2005			2006			2005			2006			2005

U.S. equities		42	%		47	%		30	%		50	%		49	%		45	%
Global equities (including U.S.)		6	%		7	%		—			—			—			—
Non-U.S. equities		12	%		11	%		20	%		5	%		21	%		15	%
Fixed income		35	%		35	%		50	%		45	%		30	%		40	%
Private equity and property		5	%		—			—			—			—			—

		100	%		100	%		100	%		100	%		100	%		100	%

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

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. 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.


	Pension Benefits						Non-Union PBOPs						Union PBOPs
	2006			2005			2006			2005			2006			2005

U.S. equities		46	%		46	%		29	%		54	%		50	%		52	%
Global equities (including U.S.)		8	%		8	%		—			—			—			—
Non-U.S. equities		13	%		12	%		20	%		5	%		22	%		16	%
Fixed income		33	%		34	%		51	%		41	%		28	%		32	%
Private equity and property		—			—			—			—			—			—

		100	%		100	%		100	%		100	%		100	%		100	%

The ~~target~~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 ~~allocations~~study ~~for~~which analyzes plan liabilities and plan funded status and results in the determination ~~benefit~~of ~~plans~~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.

	Pension Benefits						PBOPs
	2005			2004			2005			2004
U.S. Equities		44	%		42	%		50	%		50	%
Global Equities (including U.S.)		7	%		7	%		—			—
Non-U.S. Equities		11	%		11	%		15	%		15	%
Fixed Income		35	%		35	%		35	%		35	%
Private Equity and Property		3	%		5	%		—			—
		100	%		100	%		100	%		100	%

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 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.

~~Expected Rate of Return on Assets~~47

48 Table of Contents

~~Table~~Assumptions ofused ~~Contents~~for Benefits Accounting

The ~~estimated~~following ~~rate~~weighted ofaverage ~~return~~assumptions ~~for~~were ~~various~~used ~~passive~~to ~~asset~~determine ~~classes~~the ispension ~~based both on analysis of historical rates of return~~ and ~~forward~~PBOP ~~looking analysis of risk premiums and yields. Current market~~benefit ~~conditions,~~obligations ~~such as inflation~~ and ~~interest~~net ~~rates,~~periodic ~~are~~costs ~~evaluated in connection with the setting of our long-term assumption. 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 our target asset allocation, and~~ the ~~resulting~~fiscal ~~long-term~~years ~~return~~ending ~~on asset rate is then applied to the market-related value of assets~~March 31.

Pension Benefits

Pension Benefits

PBOP

2006

2005

2006

2005

Benefit obligations

Discount rate

6.00

5.75

6.00

5.75

Rate of compensation increase

3.90

3.90

n/a

n/a

Expected long-term rate of return

8.00

8.25

7.81

8.21

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

2010

Pre 65*

n/a

n/a

2011

n/a

Post 65*

n/a

n/a

2012

n/a

~~The~~* ~~Company’s~~In ~~net~~fiscal ~~periodic~~year ~~benefit~~2006, the health care cost ~~for~~trend ~~the~~assumption ~~years~~was ~~ended~~updated ~~March 31,~~to ~~2005,~~include ~~2004~~rates for the pre 65 and ~~2003~~post ~~included the~~65 ~~following~~age ~~components:~~ groups.

	Year Ended March 31,
	Pension Benefits									PBOP
(In thousands)	2005			2004			2003
	2006			2005			2004			2006			2005			2004
Service cost-benefits earned during the period	$	29,324		$	28,093		$	24,970
Net periodic benefit cost
Plus (less):
Discount rate		5.75	%		5.75	%		6.25	%		5.75	%		5.75	%		6.25	%
Interest cost on projected benefit obligation		71,014			74,863			83,493
Rate of compensation increase		3.90	%		3.25	%		3.25	%		n/a			n/a			n/a
Return on plan assets at expected long-term rate		(67,787	)		(71,391	)		(75,613	)
Expected long-term rate of return		8.25	%		8.50	%		8.50	%		8.16	%		8.26	%		8.00	%
Amortization of unrecognized prior service cost		1,851			1,160			—
Health care cost trend rate
Amortization of unrecognized loss		26,269			18,026			5,559
Initial		n/a			n/a			n/a			10.00	%		10.00	%		10.00	%
Net periodic benefit costs before settlement curtailments	$	60,671		$	50,751		$	38,409
Ultimate		n/a			n/a			n/a			5.00	%		5.00	%		5.00	%
Settlement and curtailment loss		185			21,798			29,548
Year ultimate rate reached		n/a			n/a			n/a			2010			2009			2008
Special termination benefits not included above		—			14,300			—
Net periodic benefit costs	$	60,856		$	86,849		$	67,957

The ~~following~~expected ~~weighted~~contributions ~~average assumptions were used~~ to ~~determine~~ the ~~net~~Company’s ~~periodic~~ pension ~~cost. The~~and ~~expected~~PBOP ~~long-term~~plans ~~rate~~during offiscal ~~return~~year on2007 ~~plan assets will be decreased to 8.25% for the calculation~~are ofapproximately ~~fiscal~~$75 million ~~year~~and ~~2006~~$81 million, ~~pension expense~~respectively.

	Year Ended March 31,
	2005			2004			2003
Discount rate		5.75	%		6.25	%		6.25	%
Rate of compensation increase		3.25	%		3.25	%		3.25	%
Expected return on plan assets		8.50	%		8.50	%		8.50	%

For the calculation of fiscal 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 plan.

~~The following table provides a reconciliation of the plans’ fair value of assets for the fiscal~~48 ~~years 2005 and 2004.~~

(In thousands)	2005			2004
Reconciliation of change in plan assets:
Fair value of plan assets at beginning of period	$	845,900		$	737,593
Actual return on plan assets during year		52,246			207,264
Company contributions		81,730			90,194
Benefits paid from plan assets		(148,350	)		(54,689	)
Settlements		(1,057	)		(134,462	)
Fair value of plan assets at end of period	$	830,469		$	845,900

49Pension Benefits

~~Table~~The ofCompany’s ~~Contents~~net periodic benefit cost for the years ended March 31, 2006, 2005 and 2004 included the following components:

The following table provides a reconciliation of the Company’s pension plans’ percentage distribution of the fair market value of the types of assets held in the pension plan’s trust for the fiscal years ended March 31, 2005 and 2004.


(in thousands of dollars)	2006			2005			2004

Service cost	$	32,483		$	29,324		$	28,093
Interest cost		75,370			71,014			74,863
Expected return on plan assets		(67,431	)		(67,787	)		(71,391	)
Amortization of unrecognized prior service cost		3,454			1,851			1,160
Amortization of unrecognized loss		34,268			26,269			18,026

Net periodic benefit costs before settlement / curtailments		78,144			60,671			50,751

Special termination benefits		—			—			14,300
Settlement and curtailment loss		—			185			21,798

Net periodic benefit costs	$	78,144		$	60,856		$	86,849

	2005			2004
Distribution of plan assets:
Debt securities		34	%		33	%
Equity securities		66	%		67	%
		100	%		100	%

The following table provides a reconciliation of the plans’ fair value of assets for the fiscal years 2006 and 2005.

The expected contribution to the Company’s pension plans during fiscal year 2006 is approximately $80 million.


(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~~ ~~and~~sheet ~~the assumptions used in developing the obligations~~ at March 31:

(In thousands)	2005			2004
(in thousands of dollars)	2006			2005
Accumulated benefit obligation	$	1,~~265~~218,~~181~~180		$	1,~~234~~265,~~898~~181
Change in benefit obligation:
Benefit obligation at beginning of period	$	1,379,059		$	1,298,548
Benefit obligation at beginning of period	$	1,298,548		$	1,296,660
Service cost		32,483			29,324
Service cost		29,324			28,093
Interest cost		75,370			71,014
Interest cost		71,014			74,863
Actuarial (gain) loss		(35,141	)		98,380
Actuarial loss		98,380			73,783
Plan amendments		—			31,201
Plan amendments		31,201			—
Benefits paid		(110,411	)		(148,350	)
Benefits paid		(148,350	)		(54,689	)
Settlements		—			(1,058	)
Settlements		(1,058	)		(134,462	)
Benefit obligation at end of period	$	1,341,360		$	1,379,059
Special termination benefits		—			14,300
Benefit obligation at end of period	$	1,379,059		$	1,298,548

(In thousands)	2005			2004
Funded status	$	(548,590	)	$	(452,648	)
Unrecognized actuarial loss		309,737			222,270
Unrecognized prior service cost		40,339			10,990
Net amount recognized on the balance sheet	$	(198,514	)	$	(219,388	)

(In thousands)	2005			2004
Amounts recognized on the balance sheet consist of:
Employee pension liability	$	(434,712	)	$	(389,003	)
Intangible asset		40,339			10,990


(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	)


(in thousands of dollars)	2006			2005

Amounts recognized on the balance sheet consist of:
Employee pension liability	$	(314,604	)	$	(434,712	)
Intangible asset		36,885			40,339
Regulatory assets		75,252			194,302
Accumulated other comprehensive income, before taxes		1,990			1,557

Net amount recognized	$	(200,477	)	$	(198,514	)

(In thousands)	2005			2004
Regulatory assets		194,302			157,068
Accumulated other comprehensive income		1,557			1,557
Net amount recognized on the balance sheet	$	(198,514	)	$	(219,388	)

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

The following weighted average assumptions were used to determine the pension benefit obligation at March 31, 2005 and 2004.


(in millions of dollars)	Pension Benefits

2007		$	108
2008		$	110
2009		$	111
2010		$	115
2011		$	120
2012-2016		$	639

	2005			2004
Discount rate		5.75	%		5.75	%
Average rate of increase in future compensation level		3.90	%		3.25	%

Additional Minimum Pension Liability

The ~~following~~Company has recorded an additional minimum pension ~~benefit~~liability ~~payments,~~of ~~which~~approximately ~~reflect~~$114 million ~~expected~~and $236 million ~~future~~at ~~services~~March 31, as2006 ~~appropriate~~and 2005, respectively, for its pension plans because the pension ~~are~~plans’ ~~expected~~accumulated benefit obligation was in excess of the accrued pension liability on the balance sheet. While the offset to this entry would normally be ~~paid~~an ~~from~~after-tax charge to other comprehensive income, due to the ~~Company’s~~nature ~~pension~~of its rate plan:, the Company has instead recorded a pre-tax regulatory asset.

(In thousands)	Pension Benefits
2006	$	110,000
2007	$	110,000
2008	$	109,000
2009	$	111,000
2010	$	117,000
2011-2015	$	666,000

Defined contribution plan

~~Postretirement~~The ~~Benefit~~Company ~~Plans~~also ~~Other~~has ~~than~~a ~~Pensions:~~defined ~~The~~contribution ~~Company’s~~pension ~~total~~plan ~~cost~~(employee savings fund plan) that covers substantially all employees. Employer matching contributions of ~~PBOPs~~approximately $7 million were expensed for the each of the fiscal years ended March 31, ~~2005~~2006, ~~2004~~2005 and ~~2003 included the following components:~~2004.

	Year Ended March 31,
(In thousands)	2005			2004			2003
Service cost — benefits earned during the period	$	13,160		$	8,629		$	6,745
Plus (less):
Interest cost on projected benefit obligation		62,887			57,952			55,551
Return on plan assets at expected long-term rate		(45,798	)		(34,578	)		(23,642	)
Amortization of prior service cost		5,915			—			—
Amortization of net (gain) loss		24,310			22,996			(498	)
Net periodic benefit costs before settlement and curtailments	$	60,474		$	54,999		$	38,156
Special termination benefits not included above		—			641			—
Net periodic benefit costs	$	60,474		$	55,640		$	38,156

TheTable following weighted average assumptions were used to determine the net periodic post-retirement benefits cost. The expected long-term rate of return on plan assets will be decreased to 8.17% for the calculation of fiscal year 2006 PBOP expense. Contents

(In thousands)		2005				2004				2003
Discount rate			5.75	%			6.25	%			6.25	%

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)	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

~~Table~~The following table provides a reconciliation of ~~Contents~~the PBOP plans’ fair value of assets for the fiscal years ended March 31, 2006 and 2005.

(In thousands)	2005			2004			2003
(in thousands of dollars)	2006			2005
Expected return on plan assets		8.26	%		8.00	%		8.50	%
Fair value of plan assets at beginning of period	$	589,917		$	589,478
Medical trend
Actual return on plan assets during year		69,721			31,836
Initial		10.00	%		10.00	%		10.00	%
Company contributions		19,700			27,600
Ultimate		5.00	%		5.00	%		5.00	%
Benefits paid from plan assets		(62,708	)		(58,997	)
Year ultimate rate is reached		2009			2008			2007
Fair value of plan assets at end of period	$	616,630		$	589,917

The following ~~table~~tables ~~provides~~provide athe reconciliation of the ~~Company’s~~benefit ~~portion~~obligation ofand the ~~Companies’~~funded ~~PBOP~~status ~~fair value~~ of ~~assets for~~ the ~~fiscal~~PBOP ~~years~~plans ~~ended~~at March 31~~, 2005 and 2004.~~:

(In thousands)	2005			2004
(in thousands of dollars)	2006			2005
Reconciliation of change in plan assets:
Benefit obligation at beginning of period	$	1,268,233		$	1,059,003
Fair value of plan assets at beginning of period	$	589,478		$	330,749
Service cost		18,887			13,160
Actual return on plan assets during year		31,836			92,305
Interest cost		70,519			62,887
Company contributions		27,600			175,945
Actuarial loss		33,745			39,897
Benefits paid from plan assets		(58,997	)		(9,521	)
Plan amendments		—			152,967
Fair value of plan assets at end of period	$	589,917		$	589,478
Benefits paid		(65,651	)		(59,681	)
Benefit obligation at end of period	$	1,325,733		$	1,268,233

The following table provides the percentage distribution of the fair market value of the types of assets held in the PBOP trust at March 31.


(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	)

	2005			2004
Distribution of plan assets:
Debt securities		32	%		35	%
Equity securities		67	%		63	%
Other		1	%		2	%
		100	%		100	%

TheTable Companyof expects to contribute approximately $61 million to its PBOP plans in fiscal year 2006. Contents

~~The~~As ~~following~~a ~~provides~~result of the ~~reconciliation~~Medicare Act of 2003, the ~~benefit~~Company ~~obligation,~~receives ~~funded~~a ~~status~~federal ~~and~~subsidy ~~the~~for sponsoring a ~~assumptions~~retiree ~~used~~healthcare inplan ~~developing~~that ~~the~~provides ~~obligations~~a ~~for~~benefit ~~the~~that ~~Company’s~~is actuarially equivalent to Medicare Part D. The following PBOP ~~plan~~benefit atpayments ~~March 31~~and subsidies, which reflect expected future service, as appropriate, are expected to be paid and received:

(In thousands)	2005			2004
(in millions of dollars)	Payments			Subsidies
Change in benefit obligation:
2007	$	68		$	4
Benefit obligation at beginning of period	$	1,059,003		$	932,596
2008	$	71		$	4
Service cost		13,160			8,629
2009	$	74		$	5
Interest cost		62,887			57,952
2010	$	77		$	5
Actuarial loss		39,897			111,361
2011	$	80		$	5
Plan amendments		152,967			—
2012-2016	$	392		$	28
Benefits paid		(59,681	)		(52,176	)
Special termination benefits		—			641
Benefit obligation at end of period	$	1,268,233		$	1,059,003

52A one-percentage point change in assumed health care cost trend rates would have the following effects:


(in thousands of dollars)	2006			2005

Increase 1%
Total of service cost plus interest cost	$	17,330		$	13,985
Post-retirement benefit obligation	$	215,617		$	196,034
Decrease 1%
Total of service cost plus interest cost	$	(14,329	)	$	(11,629	)
Post-retirement benefit obligation	$	(185,317	)	$	(169,719	)

(In thousands)	2005			2004
Funded status	$	(678,317	)	$	(469,525	)
Unrecognized prior service cost		147,052			—
Unrecognized actuarial loss		268,659			239,110
Net amount recognized	$	(262,606	)	$	(230,415	)

Settlement Losses

	2005			2004
Discount rate		5.75	%		5.75	%
Health care cost trend
Initial		10.00	%		10.00	%
Ultimate		5.00	%		5.00	%
Year ultimate rate reached		2010			2009

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.

~~The~~In ~~following~~July 2004, ~~PBOP~~the ~~benefit~~Company ~~payments~~obtained ~~and~~PSC ~~subsidies,~~approval ~~which~~that ~~reflect~~would ~~expected~~provide ~~future~~rate ~~service,~~recovery asfor approximately ~~appropriate~~$14 million of the $30 million pension settlement loss incurred in fiscal 2003. In addition, ~~are~~the agreement ~~expected~~covers the funding of the entire settlement loss to bebenefit ~~paid:~~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.

(In thousands)	Payments		Subsidies
2006	$	60,000	$	—
2007		63,000		4,000
2008		65,000		5,000
2009		65,000		5,000
2010		64,000		5,000
2011-2015		308,000		29,000

Regulatory treatment of pensions and PBOP plans

AIn ~~one-percentage~~addition ~~point~~to ~~change~~the regulatory assets established in ~~assumed~~connection ~~health~~with ~~care~~purchase ~~cost~~accounting ~~trend~~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 ~~would~~for ~~have~~these costs. Also, the ~~following~~regulatory asset account includes ~~effects:~~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

(In thousands)	2005			2004
Increase 1%
Total of service cost plus interest cost	$	13,985		$	7,789
Post-retirement benefit obligation		196,034			107,991
Decrease 1%
Total of service cost plus interest cost		(11,629	)		(6,880	)
Post-retirement benefit obligation		(169,719	)		(97,642	)

PSCTable Audit of Contents

Inmillion ~~August~~and $7 ~~2003~~million, the New York State PSC approved a settlement with the Company following an audit that identified reconciliation issues between the rate allowance and actual costs of the Company’s pension and other post-retirement benefitsrespectively. The settlement resolved all issues associated with those obligations for the period prior to its acquisition by National Grid and, among other things, covered the funding of the Company’s pension and postphase-~~retirement~~in ~~benefit~~deferral ~~plans.~~is Asbeing ~~part~~amortized ofat ~~the settlement,~~a ~~the~~rate ~~Company provided $100 million~~ of ~~tax-deductible funding during fiscal 2003 and an~~ ~~additional~~approximately $~~209~~3 million ofper ~~tax-deductible funding by the end of fiscal~~year.

53NOTE I — PREFERRED STOCK

~~Table~~The Company has certain issues of ~~Contents~~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.

2004. Under the settlement, the Company will earn a rate of return of at least 6.60 percent (nominal) on the $209 million of funding through December 31, 2011 and is eligible to earn 80 percent of the amount by which the rate of return on the pension and post-retirement benefit funds exceeds 5.34 per cent (nominal) measured as of that date.


									Redemption price
	Shares				(in thousands of dollars)				per share
	March 31,		March 31,		March 31,		March 31,		(Before adding
Series	2006		2005		2006		2005		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

~~Additional Minimum Pension Liability~~53

TheTable Company has recorded an additional minimum pension liability of approximately $236 million and $170 million at March 31, 2005 and 2004, respectively, for its qualified pension plans because the pension plans’ accumulated benefit obligation was in excess of the prepaid pension asset and accrued pension liability on the balance sheet. While the offset to this entry would normally be a charge after-tax to other comprehensive income, due to the nature of its rate plan, the Company has instead recorded a pre-tax regulatory asset. Contents

~~Voluntary~~NOTE ~~Early~~J ~~Retirement~~— ~~Offer~~SEGMENTS

InSegmental ~~fiscal~~information ~~2004,~~is ~~National~~presented ~~Grid~~in ~~made~~accordance awith ~~voluntary~~management ~~early~~responsibilities ~~retirement~~and ~~offer~~the ~~(VERO) to~~economic characteristics ~~eligible~~of ~~non-union employees~~the Company’s business activities. The Company ~~expensed~~is ~~approximately~~primarily ~~$19 million~~engaged in the business of ~~VERO~~the ~~costs~~purchase, intransmission and distribution of electricity and the ~~fiscal~~purchase, distribution, ~~2004~~sale and transportation of natural gas in New York State. ~~This~~The Company’s reportable ~~amount~~segments ~~included~~are ~~approximately~~electricity-transmission, ~~$9 million~~electricity-distribution, ~~allocated~~and togas-distribution. Certain information regarding the Company’s ~~from~~segments ~~National~~is ~~Grid~~set ~~USA~~forth ~~Service~~in the following tables. Corporate ~~Company~~assets consist primarily of other property and investments, ancash, ~~affiliate~~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.

Settlement Losses


			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

As the result of the decline in the stock market since the close of the merger with Niagara Mohawk and a reduction in the discount rate applied to pension obligations, the Company has an unrecognized loss in its pension plans. Under SFAS No. 88 “Employers’ Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits” (FAS 88), the Company must recognize a portion of this loss immediately when payouts from the plans exceed a certain amount. The Company recognized approximately $22 million in fiscal 2004 relating to the remeasurement of the benefit plans from the VERO. The Company had a net settlement loss of approximately $30 million in fiscal 2003 relating to normal lump-sum distributions and the spin-off of the assets and liabilities related to the sale of NM Energy.


			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

~~In July 2004, the Company obtained PSC approval that would provide rate recovery for approximately~~54 $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 $21 million pension settlement loss incurred in fiscal year 2004.

RegulatoryTable treatment of pensions and PBOP plans Contents

InNOTE ~~addition to the regulatory assets established in connection with purchase accounting and the~~K ~~additional~~— ~~minimum~~STOCK ~~pension~~BASED ~~liability discussed above, the regulatory asset account “Pension and~~COMPENSATION postretirement benefit plans” includes certain other components. First, the Company is required under the Merger Rate Plan to defer the difference between pension and postretirement benefit expense and the allowance in rates for these costs. Also, the regulatory asset account includes the unamortized portion of the merger early retirement program costs, a postretirement benefit phase-in deferral established in the mid-1990’s, and the offset to the additional minimum pension liability discussed above. The merger 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 2005 and 2004 was approximately $7 million and $8 million, respectively. The phase-in deferral is being amortized at a rate of approximately $3 million per year.

54Prior 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.


	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

~~Defined~~The ~~contribution~~Company’s ~~plan~~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.

~~The~~Included ~~Company~~in ~~also~~the ~~has~~Company’s aresults ~~defined~~of ~~contribution~~operations ~~pension~~for ~~plan~~years ~~(employee~~ended ~~savings~~March 31, ~~fund~~2006 ~~plan)~~and ~~that~~2005, ~~covers~~is ~~substantially all employees. Employer matching contributions of~~ approximately $71 million, ~~$7 million,~~of ~~and~~expense ~~$8 million were expensed~~ for ~~the~~each ~~fiscal~~year ~~years~~related ~~ended~~to ~~March 31,~~the ~~2005,~~SARs ~~2004 and 2003, respectively~~program.

~~Medicare~~NOTE ~~Act~~L — ofDERIVATIVES ~~2003~~AND HEDGING ACTIVITIES

~~The~~In ~~Medicare~~the ~~Prescription~~normal ~~Drug,~~course ~~Improvement~~of ~~and~~business, ~~Modernization~~the ~~Act~~Company ~~was~~is ~~signed~~party ~~into~~to ~~law~~derivative onfinancial ~~December~~instruments 8,(derivatives) that ~~2003.~~are Itprincipally ~~created~~used ato ~~new~~manage ~~Medicare~~commodity ~~prescription~~prices ~~drug~~associated ~~benefit~~with ~~(Medicare~~its ~~Part~~natural D)gas and electric operations. These financial exposures are monitored and amanaged ~~federal subsidy~~as toan ~~sponsors~~integral part of ~~retiree~~the ~~healthcare~~Company’s ~~plans~~overall ~~that~~Financial ~~provide~~Risk aManagement ~~benefit~~Policy. ~~that~~At isthe atcore ~~least~~of ~~actuarially~~the policy is a ~~equivalent~~condition tothat ~~Medicare~~the ~~Part~~Company D.will Onengage ~~May 19,~~in ~~2004,~~activities ~~the~~at ~~FASB~~risk ~~issued~~only ~~Staff~~to ~~Position~~the ~~No. 106-2,~~extent that those ~~“Accounting~~activities ~~and~~fall ~~Disclosure~~within ~~Requirements~~commodities ~~Related~~and financial markets to ~~the~~which ~~Medicare~~it ~~Prescription~~has ~~Drug,~~a ~~Improvement~~physical ~~and~~market exposure ~~Modernization~~in ~~Act~~terms ofand ~~2003”~~volumes ~~(the~~consistent ~~FSP)~~with its core business. The ~~FSP~~Company ~~provides~~does ~~guidance~~not onissue ~~accounting~~or ~~for~~intend ~~the~~to hold ~~effects~~derivative ~~of the~~instruments ~~Act,~~for ~~which~~speculative ~~resulted~~trading inpurposes. aDerivatives ~~reduction~~are accounted for in accordance ~~the~~with ~~APBO~~SFAS No. 133, “Accounting for ~~the~~Derivative ~~subsidy~~Instruments ~~related~~and toHedging ~~benefits~~Activities,” ~~attributed~~which requires derivatives to ~~past~~be ~~service.~~reported ~~The~~at ~~reduction~~fair invalue ~~the~~as ~~APBO~~assets ~~represents~~or aliabilities ~~deferred~~on ~~actuarial~~the ~~gain~~balance sheet. The change in ~~the~~fair ~~amount~~value of ~~$71.5 million~~ instruments that qualify for ~~the~~hedge ~~Company’s~~accounting ~~postretirement~~are ~~benefits~~deferred ~~plan~~in Accumulated asOther ofComprehensive ~~July 1,~~Income ~~2004~~and will be reclassified through purchased electricity or purchased gas expense within the next twelve months. OnOther ~~January 21,~~instruments are deferred in regulatory ~~2005~~assets ~~final~~or ~~regulations~~liabilities ~~were~~according ~~issued~~to oncurrent ~~the~~rate ~~new~~agreements ~~Medicare~~and ~~prescription~~are ~~drug~~reclassified ~~program~~through purchased electricity or gas expense in the hedge months. The ~~impact~~Company’s ~~on plan~~rate ~~obligations~~agreements asallow afor ~~result~~the pass-through of the ~~final~~commodity ~~regulations~~costs ~~was~~of ~~not~~electricity ~~significant~~and natural gas, including the costs of the hedging programs.

($’s in 000’s)
Reduction in Net Periodic
Benefit Cost For the Year
Ended March 31,	2005
Service cost	$	491
Interest cost		3,713
Recognized actuarial loss		6,022
Total expense reduction	$	10,226
Annualized expense reduction	$	13,635

The Company has eight indexed swap contracts, expiring in fiscal year 2009 (June 2008), that resulted from the MRA. These derivatives are not designated as hedging instruments and are

~~NOTE I – PREFERRED STOCK~~55

TheTable 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. Contents

									Redemption price
	Shares				($’s in 000’s)				per share
	March 31,		March 31,		March 31,		March 31,		(Before adding
Series	2005		2004		2005		2004		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

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.

55At March 31, 2006, the Company projects that it will make the following payments in connection with its swap contracts for the fiscal years 2007 through 2009, subject to changes in market prices and indexing provisions:


	Projected
	Payment
Year Ended	(in thousands
March 31,	of dollars)

2007	$	246,551
2008		246,173
2009		44,729
Thereafter		—

Total	$	537,453

									Redemption price
	Shares				($’s in 000’s)				per share
	March 31,		March 31,		March 31,		March 31,		(Before adding
Series	2005		2004		2005		2004		accumulated dividends)
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
Preferred $25 par value:
Adjustable Rate - Series D		—		503,100		—		25,155		50.00	*
Total preferred stock		411,715		914,815	$	41,170	$	66,325

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 ~~Redeemed~~following table represents the open positions at March 31, 2006 and the results on ~~December~~operations of these instruments for the year ended March 31, ~~2004~~2006.

During fiscal 2005, the Company redeemed all outstanding Cumulative Fixed/Adjustable Rate Series D Preferred Stock for $25 million.


(In thousands of dollars)				Balances as of March 31, 2006
												Year Ended
									Accumulated			March 31, 2006
						Accumulated			Deferred			Gain/(Loss)
				Regulatory		OCI ,**			Income Tax			Reclass to
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

~~NOTE~~* JDifferences –between ~~SEGMENTS~~ asset and regulatory or other comprehensive income deferral represent contracts settled for the following month. ** Other Comprehensive Income (OCI)

~~The~~At ~~Company’s reportable segments are electricity-transmission~~March 31, ~~electricity-distribution~~2005, ~~including~~ the ~~sub-segment stranded cost recoveries and gas-distribution. The~~ Company ~~is engaged principally~~ in ~~the~~part ~~business~~recorded ofa ~~the~~deferred ~~purchase,~~gain ~~transmission,~~on ~~and distribution of electricity and~~ the ~~purchase, distribution,~~futures ~~sale, and transportation of natural gas in New York State. Certain information~~contracts ~~regarding~~hedging the ~~Company’s~~IPP ~~segments~~swaps isand ~~set~~non-MRA ~~forth~~IPP inof ~~the following table. General corporate expenses~~$30 million, ~~property~~ ~~common~~which topartially ~~the~~offset ~~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~~consolidated ~~plant~~balance ~~amounts~~sheet ~~charged~~item ~~directly~~“Derivative toinstruments” ~~certain~~for ~~operating expense accounts or certain plant accounts. Corporate assets consist primarily of other property and investments~~$27 million, ~~cash,~~with ~~restricted~~the ~~cash, current~~resulting ~~deferred~~$3 million ~~income taxes, and unamortized debt expense.~~having

					Electricity -		Total
	Electricity -		Electricity –		Stranded Cost		Electricity		Gas –
	Transmission		Distribution		Recoveries		Distribution		Distribution		Corporate		Total
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
Year ended March 31, 2003
Operating revenue	$	248	$	2,545	$	517	$	3,062	$	709	$	—	$	4,019
Operating income before income taxes		85		256		181		437		68		—		590
Depreciation and amortization		35		127		—		127		36		—		198
Amortization of stranded costs		—		—		149		149		—		—		149

						Electricity -		Total
	Electricity -		Electricity –			Stranded Cost		Electricity			Gas –
	Transmission		Distribution			Recoveries		Distribution			Distribution		Corporate		Total
Goodwill
Goodwill, at March 31, 2004	$	303	$	708		$	—	$	708		$	215	$	—	$	1,226
Change in goodwill		—		(2	)		—		(2	)		—		—		(2	)
Goodwill, at March 31, 2005	$	303	$	706		$	—	$	706		$	215	$	—	$	1,224
Total Assets
At March 31, 2005	$	1,557	$	5,193		$	3,402	$	8,595		$	1,819	$	547	$	12,518
At March 31, 2004	$	1,546	$	5,137		$	3,672	$	8,809		$	1,686	$	578	$	12,619

56settled through cash for the hedge month of April 2005. For the twelve months ended March 31, 2005, settlement of NYMEX futures contracts resulted in a decrease to purchased power expense of $19 million.

~~Table~~The gains and losses on the derivatives 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 ~~Contents~~the cash flows of the hedged item. For the twelve months ended March 31, 2006, the realized net gain of $36 million from hedging instruments, as shown in the table above, was recorded to gas purchases and was offset by a corresponding increase in the cost of a comparable amount of gas. For the twelve months ended March 31, 2005, a realized net gain of $8 million was recorded to gas purchases and was offset by a corresponding decrease in the cost of a comparable amount of gas.

~~NOTE~~The Kactual –amounts ~~STOCK~~to ~~BASED~~be ~~COMPENSATION~~recorded in purchased energy expense are dependent on future changes in the contract values. The majority of these deferred amounts will be reclassified to expense within the next twelve months. A nominal amount of the hedging instruments extend into April 2007. There were no gains or losses recorded during the fiscal year ended March 31, 2006 from the discontinuance of gas futures or electric swap cash flow hedges.

~~Prior~~At ~~to the merger~~March 31, ~~stock appreciation rights (SARs)~~2006, ~~tied to~~ the ~~price~~deferred ofgain ~~the~~on ~~Holdings’~~NYMEX ~~share price~~electric ~~were~~swap ~~granted~~contracts to ~~officers,~~hedge ~~key~~electricity purchases ~~employees~~was ~~and directors~~$0.3 million. ~~The~~There ~~table~~were ~~below~~no ~~sets~~open ~~forth~~electric ~~the activity~~swaps ~~under~~at ~~the SARs program for the periods~~ March 31, ~~2003 through March 31,~~ 2005.

								Options
								Wtd. Avg.
								Exercise
	SARs*			Units		Options		Price
Outstanding at March 31, 2003		752,880			—		—		—
Exercised		(411,612	)
Outstanding at March 31, 2004		341,268			—		—		—
Exercised		(93,146	)
Outstanding at March 31, 2005		248,122

NOTE M — RESTRICTION ON COMMON DIVIDENDS

The indenture securing the Company’s ~~SARs~~mortgage ~~program~~debt ~~provided~~provides ~~for~~that ~~the~~retained ~~acceleration~~earnings ofshall ~~vesting upon the occurrence of~~be ~~certain~~reserved ~~events~~and ~~relating~~held tounavailable afor ~~change~~the inpayment ~~control, merger, sale~~ of ~~assets~~dividends oron ~~liquidation~~common ofstock ~~the Company.~~to ~~On January 31, 2002,~~ the ~~acquisition~~extent ofthat expenditures ~~Holdings’~~for bymaintenance ~~National Grid was completed~~ and ~~outstanding~~ ~~Holdings~~repairs ~~SARs~~plus ~~were~~provisions ~~converted~~for todepreciation ~~National~~do ~~Grid~~not ~~Transco~~exceed ~~plc~~2.25% ~~(NGT) American Depositary~~of ~~Share~~depreciable ~~(ADS) SARs.~~property ~~The~~as ~~SARs~~defined ~~are~~therein. ~~payable~~These inprovisions ~~cash~~have ~~based~~never onresulted ~~the increase~~ in ~~the ADS price from~~ a ~~specified~~ ~~level.~~restriction ~~As such, for these awards, compensation expense is recognized based on~~ of the ~~value of Holdings~~Company’ ~~stock price or NGT’~~s ~~ADS~~retained ~~price over the vesting period of the award~~earnings.

~~Included~~The inCompany is limited by the ~~Company’s~~Merger ~~results~~Rate Plan and under FERC and SEC orders with respect to the amount of ~~operations~~dividends ~~for~~it ~~years~~can ~~ended~~make ~~March 31,~~to ~~2005~~Holdings. ~~and~~As ~~2004~~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 ~~approximately~~plus ~~$1 million~~any ~~and~~earnings ~~$5 million,~~subsequent ~~respectively~~to the merger, ~~related~~together towith other adjustments that are authorized under the ~~SARs~~Merger ~~program~~Rate Plan and other regulatory orders.

~~Since~~NOTE ~~SARs~~N — ~~are~~COST ~~payable~~OF inREMOVAL ~~cash,~~AND ~~the~~ASSET ~~accounting~~RETIREMENT ~~under APB No. 25 and SFAS No. 123 is the same.~~OBLIGATION

In ~~December 2004~~2001, ~~the~~ FASB issued SFAS No. ~~123R,~~143. ~~“Share-Based~~SFAS ~~Payment~~No.” 143 ~~This~~provides ~~Standard addresses the~~ accounting ~~for~~requirements ~~transactions in which a company receives employee services in exchange~~ for ~~(a)~~retirement ~~equity~~obligations ~~instruments~~associated ofwith ~~the~~tangible ~~company~~long-lived orassets. ~~(b) liabilities~~The ~~that~~Company ~~are~~was ~~based~~required onto ~~the~~adopt ~~fair~~SFAS ~~value of the~~No. ~~company’s~~143 ~~equity~~as ~~instruments or that may be settled by the issuance~~ of ~~such~~April 1, ~~equity instruments~~2003. ~~This~~ ~~Standard~~Retirement ~~also~~obligations ~~eliminates~~associated ~~the~~with ~~ability to account for share~~long-~~based~~lived ~~compensation~~assets ~~transactions~~included within ~~using~~the ~~Accounting~~scope ~~Principles~~of ~~Board~~SFAS ~~Opinion~~ No. ~~25,~~143 ~~“Accounting~~are those for ~~Stock~~which ~~Issued~~there tois ~~Employees,” and requires that such transactions be accounted for using~~ a ~~fair-value-based~~legal ~~method.~~obligation ~~The~~under ~~Standard~~existing isor enacted ~~effective~~law, ~~for~~statute, ~~periods~~written ~~beginning~~or ~~after~~oral ~~June 15~~contract, ~~2005.~~or ~~The~~by ~~Company~~legal ~~does~~construction ~~not~~under ~~anticipate~~the ~~that~~doctrine ~~adoption~~ of ~~SFAS 123R will have a material impact on its results of operations or its financial position~~promissory estoppel.

~~NOTE~~Under Lthe –Company’s ~~DERIVATIVES~~current ~~AND~~and ~~HEDGING~~prior ~~ACTIVITIES~~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 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

Indistribution ~~the normal course of business~~assets, the Company iswould ~~party~~use tothese ~~derivative~~funds ~~financial instruments (derivatives) that are principally used~~ to ~~manage~~remove ~~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~~asset ~~overall~~so ~~financial risk-management policy. At the core of the policy is~~ a ~~condition~~ ~~that~~new ~~the~~one ~~Company~~could ~~will engage in activities at risk only to the extent that those~~be ~~activities~~installed ~~fall within commodities and financial markets to which it has a physical market exposure~~ in ~~terms and volumes consistent with~~ its ~~core business~~place. ~~The Company does not issue or intend to~~ hold derivative instruments for speculative trading purposes. Derivatives are accounted for in accordance with SFAS 133, 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~~cost ~~has~~of ~~eight~~removal ~~indexed~~collections ~~swap~~from ~~contracts,~~customers ~~expiring~~has inhistorically ~~June 2008~~been ~~that~~embedded ~~resulted~~within ~~from the MRA.~~accumulated ~~These~~depreciation ~~derivatives~~(as ~~are~~these ~~not~~costs ~~designated~~have asbeen ~~hedging~~charged ~~instruments~~over ~~and~~time ~~are~~through ~~covered~~depreciation byexpense). ~~regulatory~~With ~~rulings~~the ~~that~~adoption ~~allow~~of ~~the~~SFAS ~~gains and losses to be recorded as regulatory assets or regulatory liabilities~~No.

Filing Compare · NIAGARA MOHAWK POWER CORP /NY/