New England Power Company 25 Research Drive Westborough, Massachusetts 01582 Directors (As of June 20, 2000) L. Joseph Callan Former Executive Director for Operations, Nuclear Regulatory Commission Peter G. Flynn President of the Company Michael E. Jesanis Vice President of the Company and Senior Vice President and Chief Financial Officer of National Grid USA Cheryl A. LaFleur Vice President and General Counsel of the Company and Senior Vice President, General Counsel, and Secretary of National Grid USA Robert G. Powderly Vice President of National Grid USA Terry L. Schwennesen Vice President of the Company Richard P. Sergel President and Chief Executive Officer of National Grid USA Philip R. Sharp Lecturer, Harvard University, John F. Kennedy School of Government Officers (As of June 20, 2000) Peter G. Flynn President of the Company Michael E. Jesanis Vice President of the Company and Senior Vice President and Chief Financial Officer of National Grid USA Cheryl A. LaFleur Vice President and General Counsel of the Company and Senior Vice President, General Counsel, and Secretary of National Grid USA Marc F. Mahoney Vice President of the Company and of certain affiliates John F. Malley Vice President of the Company James S. Robinson Vice President of the Company Masheed H. Rosenqvist Vice President of the Company and of certain affiliates Terry L. Schwennesen Vice President of the Company Gregory A. Hale Clerk of the Company and of certain affiliates, Assistant Secretary or Assistant Clerk of certain affiliates and Secretary of an affiliate John G. Cochrane Treasurer of the Company and of certain affiliates, Vice President of an affiliate, Assistant Treasurer of an affiliate and Vice President and Treasurer of National Grid USA Kirk L. Ramsauer Assistant Clerk of the Company and of certain affiliates, Secretary or Clerk of certain affiliates and Assistant Secretary of an affiliate Patricia C. Easterly Assistant Treasurer of the Company and Treasurer of an affiliate Nancy B. Kellogg Assistant Treasurer of the Company and of certain affiliates Kwong O. Nuey Controller of the Company and of certain affiliates Transfer Agent, Dividend Paying Agent, and Registrar of Preferred Stock, Fleet National Bank, Boston, Massachusetts This report is not to be considered an offer to sell or buy or solicitation of an offer to sell or buy any security. New England Power Company 25 Research Drive Westborough, Massachusetts 01582 Directors (As of June 20, 2000) L. Joseph Callan Former Executive Director for Operations, Nuclear Regulatory Commission Peter G. Flynn President of the Company Michael E. Jesanis Vice President of the Company and Senior Vice President and Chief Financial Officer of National Grid USA Cheryl A. LaFleur Vice President and General Counsel of the Company and Senior Vice President, General Counsel, and Secretary of National Grid USA Robert G. Powderly Vice President of National Grid USA Terry L. Schwennesen Vice President of the Company Richard P. Sergel President and Chief Executive Officer of National Grid USA Philip R. Sharp Lecturer, Harvard University, John F. Kennedy School of Government Officers (As of June 20, 2000) Peter G. Flynn President of the Company Michael E. Jesanis Vice President of the Company and Senior Vice President and Chief Financial Officer of National Grid USA Cheryl A. LaFleur Vice President and General Counsel of the Company and Senior Vice President, General Counsel, and Secretary of National Grid USA Marc F. Mahoney Vice President of the Company and of certain affiliates John F. Malley Vice President of the Company James S. Robinson Vice President of the Company Masheed H. Rosenqvist Vice President of the Company and of certain affiliates Terry L. Schwennesen Vice President of the Company Gregory A. Hale Clerk of the Company and of certain affiliates, Assistant Secretary or Assistant Clerk of certain affiliates and Secretary of an affiliate John G. Cochrane Treasurer of the Company and of certain affiliates, Vice President of an affiliate, Assistant Treasurer of an affiliate and Vice President and Treasurer of National Grid USA Kirk L. Ramsauer Assistant Clerk of the Company and of certain affiliates, Secretary or Clerk of certain affiliates and Assistant Secretary of an affiliate Patricia C. Easterly Assistant Treasurer of the Company and Treasurer of an affiliate Nancy B. Kellogg Assistant Treasurer of the Company and of certain affiliates Kwong O. Nuey Controller of the Company and of certain affiliates Transfer Agent, Dividend Paying Agent, and Registrar of Preferred Stock, Fleet National Bank, Boston, Massachusetts This report is not to be considered an offer to sell or buy or solicitation of an offer to sell or buy any security. New England Power Company New England Power Company, (the Company) a wholly owned subsidiary of National Grid USA (formerly New England Electric System), is a Massachusetts corporation qualified to do business in Massachusetts, New Hampshire, Rhode Island, Connecticut, Maine, and Vermont. The Company is subject, for certain purposes, to the jurisdiction of the regulatory commissions of these six states, the Securities and Exchange Commission, under the Public Utility Holding Company Act of 1935, the Federal Energy Regulatory Commission, and the Nuclear Regulatory Commission. The Company's business is primarily the transmission of electric energy in wholesale quantities to other electric utilities, principally its distribution affiliates Granite State Electric Company, Massachusetts Electric Company, Nantucket Electric Company, and The Narragansett Electric Company. The Company's transmission business will also do business under the name of National Grid Transmission USA. Report of Independent Accountants New England Power Company, Westborough, Massachusetts: In our opinion, the accompanying balance sheets and the related statements of income, of retained earnings, and of cash flows present fairly, in all material respects, the financial position of New England Power Company (the Company), a wholly owned subsidiary of National Grid USA (formerly New England Electric System), at March 31, 2000 and December 31, 1999 and 1998, and the results of its operations and its cash flows for the three months ended March 31, 2000 and each of the three years in the period ended December 31, 1999 in conformity with accounting principles generally accepted in the United States. These financial statements are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States, which 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 the opinion expressed above. PricewaterhouseCoopers LLP Boston, Massachusetts June 20, 2000 New England Power Company Financial Review Merger with National Grid On March 22, 2000, the merger of New England Electric System (NEES) and The National Grid Group plc (National Grid) was completed, with NEES (renamed National Grid USA) becoming a wholly owned subsidiary of National Grid. National Grid paid a total of $4 billion, including $3.2 billion in cash paid to shareholders pursuant to the merger agreement, $642 million for National Grid USA's merger with Eastern Utilities Associates (EUA) (discussed below), an additional capital contribution of $141 million, and merger related expenses of $37 million. New England Power Company (the Company) will maintain its existing name and will remain a wholly owned subsidiary of National Grid USA. The merger of National Grid USA and National Grid has been accounted for as an acquisition of National Grid USA by National Grid using the purchase method of accounting. The application of the purchase method, including the recognition of goodwill, is being pushed down and reflected on the financial statements of the National Grid USA subsidiaries, including the Company. Total goodwill amounted to $1.7 billion, of which the Company was allocated $334.1 million at the date of the merger. This amount was determined pursuant to an independent study conducted by a third party and is being amortized over 20 years. The annual amortization expense will amount to approximately $16.7 million. The purchase accounting method requires the Company to revalue its assets and liabilities at their fair value. This revaluation resulted in a net debit adjustment to the Company's pension and postretirement benefit plans in the amount of approximately $61 million, with a corresponding offsetting credit to a regulatory liability account (see Note E of the Notes to Financial Statements). Merger with EUA The merger between the National Grid USA and EUA parent companies was completed on April 19, 2000, with EUA merging into National Grid USA. The impacts of this transaction will be reflected in subsequent reporting periods. The price paid by National Grid USA was $642 million, or $31.459 per share. On May 1, 2000, Montaup Electric Company (Montaup), formerly a subsidiary of EUA, merged into the Company. The merger of EUA and National Grid USA is being accounted for by the purchase method, the application of which, including the recognition of goodwill, is being pushed down and reflected on the financial statements of the National Grid USA subsidiaries, including the Company. Total goodwill amounted to $388 million, of which the Company was allocated $7.7 million. This amount was determined pursuant to an independent study conducted by a third party and is being amortized over 20 years. The annual amortization expense will amount to approximately $0.4 million. Industry Restructuring Pursuant to legislation enacted in Massachusetts, Rhode Island, and New Hampshire, and settlement agreements approved by state and federal regulators (the Settlement Agreements), all customers were granted choice of power supplier in 1998. To facilitate the implementation of customer choice, the settlement agreements provided for the amendment of the Company's all-requirements contracts with its affiliated distribution companies. The Company's all-requirements contracts with some unaffiliated customers were terminated pursuant to settlement agreements or tariff provisions. However, the Company remains obligated to provide transition power supply service at fixed rates to some new customer load in Rhode Island. In addition, as a result of the Settlement Agreements, the Company and its affiliate, The Narragansett Electric Company (Narragansett Electric), sold substantially all of their nonnuclear generating business (divestiture) in September 1998. As part of the divestiture plan, New England Energy Incorporated sold its oil and gas properties in 1998, resulting in a loss of approximately $120 million, before tax, which was reimbursed by the Company. The Company also agreed to endeavor to sell its minority interest in three nuclear power plants and a 60 megawatt interest in a fossil- fueled generating station in Maine. In conjunction with the divestiture, the Company transferred to the buyer of its nonnuclear generating business (the buyer) its entitlement to power procured under several long-term contracts in exchange for monthly fixed payments by the Company averaging $9.5 million per month through January 2008 (having a net present value at March 31, 2000 of approximately $687 million) toward the above-market cost of those contracts. The Company has recorded a corresponding current liability of $75 million, and a long-term liability of $612 million. For certain contracts which have been formally assigned to the buyer, the Company has made lump sum payments equivalent to the present value of the monthly fixed payment obligations of those contracts (approximately $345 million at date of purchase, which corresponds to approximately $290 million at March 31, 2000), which were separate from the $687 million figure referred to above. Under the Settlement Agreements, the Company is permitted to recover costs associated with its former generating investments and related contractual commitments that were not recovered through the sale of those investments (stranded costs). These costs are recovered from the Company's wholesale customers with which it has settlement agreements through contract termination charges (CTC) which the affiliated wholesale customers recover through delivery charges to distribution customers. The recovery of the Company's stranded costs is divided into several categories. The Company's unrecovered costs associated with generating plants (nuclear and nonnuclear) and most regulatory assets will be fully recovered through the CTC by the end of 2000 and earn a return on equity averaging 9.7 percent. The Company's obligation related to the above-market cost of purchased power contracts and nuclear decommissioning costs are recovered through the CTC as such costs are actually incurred. As the CTC rate declines, the Company, under certain of the Settlement Agreements, earns incentives based on successful mitigation of its stranded costs. These incentives supplement the Company's return on equity. Until such time as the Company divests its operating nuclear interests, the Company will share with customers, through the CTC, 80 percent of the revenues and operating costs related to the units, with shareholders retaining the balance. For further information on the potential sale of the Vermont Yankee and Millstone 3 nuclear generating units, refer to the "Nuclear Units" section below. Accounting Implications Because electric utility rates have historically been based on a utility's costs, electric utilities are subject to certain accounting standards that are not applicable to other business enterprises in general. The Company applies the provisions of Statement of Financial Accounting Standards No. 71, Accounting for the Effects of Certain Types of Regulation (FAS 71), which requires regulated entities, in appropriate circumstances, to establish regulatory assets or liabilities, and thereby defer the income statement impact of certain charges or revenues because they are expected to be collected or refunded through future customer billings. In 1997, the Emerging Issues Task Force of the Financial Accounting Standards Board concluded that a utility that had received approval to recover stranded costs through regulated rates would be permitted to continue to apply FAS 71 to the recovery of stranded costs. As discussed above, the Company received authorization from the Federal Energy Regulatory Commission (FERC) to recover through CTCs substantially all of the costs associated with its former generating business not recovered through the divestiture. Additionally, FERC Order No. 888 enables transmission companies to recover their specific costs of providing transmission service. Therefore, substantially all of the Company's business, including the recovery of its stranded costs, remains under cost-based rate regulation. Because of the nuclear cost-sharing provisions related to the Company's CTC, the Company ceased applying FAS 71 in 1997 to 20 percent of its ongoing nuclear operations, the impact of which is immaterial. As a result of applying FAS 71, the Company has recorded a regulatory asset for the costs that are recoverable from customers through the CTC. At March 31, 2000, this amounted to approximately $1.3 billion, including $1.0 billion related to the above-market costs of purchased power contracts, $0.3 billion related to accrued Yankee nuclear plant costs, and other net CTC-related regulatory assets. Impact of Mergers on Transmission and CTC Rates Under a rate consolidation plan accepted by the FERC in September 1999, upon National Grid USA's acquisition of EUA and the merger of Montaup, EUA's transmission company, into the Company on May 1, 2000, the combined company charges a single system open access transmission tariff based upon its total transmission costs. Montaup will charge a separate CTC rate until a rate for the combined company is established. Change of Fiscal Year National Grid USA and its subsidiaries, including the Company, changed their 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 National Grid USA's parent company, National Grid. The Company's first new full fiscal year began on April 1, 2000 and will end on March 31, 2001. The Company has reported results of operations for the three month transitional period ended March 31, 2000, the three month period ended March 31, 1999, and the years ended December 31, 1999, December 31, 1998, and December 31, 1997. The Company has also reported balance sheets as of March 31, 2000, December 31, 1999, and December 31, 1998, and statements of cash flows for the three month periods ended March 31, 2000, and March 31, 1999, and the years ended December 31, 1999, December 31, 1998, and December 31, 1997. Overview of Financial Results Net income for the three months ended March 31, 2000 decreased $6 million compared with the same period in 1999 primarily due to the elimination of certain liabilities related to open access transmission tariffs of approximately $5 million in the first quarter of 1999. Net income for the year ended December 31, 1999 decreased $52 million compared with the same period in 1998 as a result of the continuing impacts of the divestiture and the restructuring of the utility business. Partially offsetting the decrease was the recovery of stranded cost mitigation incentives of approximately $25 million in 1999 compared with $10 million in 1998, as well as increased transmission revenues of approximately $13 million due to the elimination of certain liabilities related to open access transmission tariffs. Net income for the year ended December 31, 1998 decreased $22 million compared with 1997. This decrease was also primarily due to the divestiture and reduced revenues as a result of industry restructuring. Operating Revenue Operating revenue for the three months ended March 31, 2000 decreased $33 million compared with the same period in 1999, largely due to CTC revenue of approximately $21 million from Narragansett Electric in 1999 related to its access charge overcollections. This payment reduced Narragansett Electric's future CTC obligations. This additional revenue in 1999 had a corresponding impact to the amortization of CTC, discussed in "Operating Expenses" below. The decrease is also due to the elimination of certain liabilities related to open access transmission tariffs of $5 million in 1999. This decrease is partially offset by the impacts of increased standard offer rates effective January 1, 2000 and increased kilowatthour sales in the three months ended March 31, 2000 compared with the same period in 1999. Operating revenue for the year ended December 31, 1999 decreased $622 million compared with 1998 due to the divestiture and reduced CTC charges. Partially offsetting this decrease was an increase in transmission revenues associated with the elimination of certain liabilities related to open access transmission tariffs discussed above. Operating revenue for the year ended December 31, 1998 decreased $460 million compared with 1997. This decrease was also the result of the divestiture and reduced revenues due to industry restructuring, partially offset by the recovery of stranded investments and increased transmission billings. Operating Expenses Operating expenses for the three months ended March 31, 2000 decreased $27 million compared with the same period in 1999. The increase in fuel and purchased power expense of approximately $5 million reflects increased purchased power expenses for standard offer requirements and increased kilowatthours purchased. Other operating expenses in the three months ended March 31, 2000 decreased approximately $3 million compared with the same period in 1999 due to the reimbursement of start-up costs from 1999 of the Independent System Operator - New England (ISO New England) in 2000. Maintenance expenses decreased approximately $1 million as a result of reduced expenses at the partially owned Millstone 3 and Seabrook 1 nuclear generating facilities. Depreciation and amortization expenses in the three months ended March 31, 2000 decreased $23 million compared with the same period in 1999. This decrease is due to additional CTC amortization in 1999 related to the additional payment of approximately $21 million by Narragansett Electric to the Company, discussed above. Operating expenses for the year ended December 31, 1999 decreased $543 million compared with 1998. The divestiture reduced all categories of operating expenses in 1999, with the exception of depreciation and amortization expense. The decrease in fuel expense and purchased power costs reflected the divestiture and the assumption of the Company's obligations under most of its previously existing purchased power contracts by the buyer of its nonnuclear generating business. The Company remains obligated to pay predetermined amounts to the buyer related to the above-market cost of those contracts. In addition, the Company also remains obligated under purchased power contracts with the four Yankee nuclear power companies, the costs of which decreased $8 million in 1999, reflecting reduced costs from Maine Yankee and Connecticut Yankee, net of increased costs of a 1999 refueling outage at Vermont Yankee. In addition to the impact of the divestiture, which reduced nonnuclear generation operation and maintenance expenses by $71 million, the decrease in other operation and maintenance expenses reflected reduced general and administrative costs due primarily to workforce reductions and reduced charges from New England Power Service Company following the divestiture. In addition, transmission costs decreased $16 million in 1999 due to the assumption of transmission support agreements by the buyer and reduced ISO New England start-up costs. These decreases were partially offset by increased costs of $3 million associated with the partially owned Millstone 3 and Seabrook 1 nuclear generating facilities which experienced refueling outages in the second quarter of 1999. Operating expenses for the year ended December 31, 1998 decreased $426 million compared with 1997 as a result of the divestiture, reduced charges of $22 million from Maine Yankee, which was closed in mid-1997, and reduced charges of $3 million and $12 million from the partially owned Seabrook 1 and Millstone 3 nuclear generating facilities, respectively. Operating expenses also decreased due to lower charges related to postretirement benefits other than pensions (PBOPs), reflecting the completion of the accelerated amortization of the Company's deferred PBOP costs in 1997 under the terms of a 1995 rate agreement. Depreciation and amortization expenses increased $3 million and $2 million in the years ended December 31, 1999, and 1998, respectively, due to the recovery and amortization of generation- related stranded costs in those years being greater than the depreciation and amortization of generation-related plant in the prior years. The increase was also due to new transmission plant expenditures. Interest Expense and Other Income The increase in interest expense for the three months ended March 31, 2000 is primarily due to increased interest rates on variable rate long-term debt and interest on short-term debt borrowings not present in 1999. The increase in other income for the three months ended March 31, 2000 is primarily due to decreased expenses related to employee incentive plans from workforce reductions following the divestiture, partially offset by merger related expenses in 2000. The decrease in interest expense in the years ended December 31, 1999 and 1998 was principally due to reduced long-term and short-term debt as a result of the divestiture. The increase in other income in the years ended December 31, 1999 and 1998 was due primarily to increased interest income resulting from the reinvestment of the proceeds from the divestiture. In 1999, this was partially offset by reduced equity income from nuclear power companies as a result of reductions in the rates of return for two of these companies. Nuclear Units Nuclear Units Permanently Shut Down Three regional nuclear generating companies in which the Company has a minority interest own nuclear generating units that have been permanently shut down. These three units, including Montaup's portion effective with the EUA merger, are as follows: Future The Company's Estimated Investment Billings to as of 3/31/00 Date the Company Unit % $(millions) Retired $(millions) - ----------------------------------------------------------------- Yankee Atomic 30 4 Feb 1992 4 Connecticut Yankee 15 16 Dec 1996 60 Maine Yankee 20 15 Aug 1997 124 Future Montaup's Estimated Investment Billings as of 3/31/00 Date to Montaup Unit % $(millions) Retired $(millions) - ----------------------------------------------------------------- Yankee Atomic 4.5 1 Feb 1992 1 Connecticut Yankee 4.5 5 Dec 1996 19 Maine Yankee 4.0 3 Aug 1997 26 In the case of each of these units, the Company has recorded a liability and an offsetting regulatory asset reflecting the estimated future billings from the companies. In a 1993 decision, the FERC allowed Yankee Atomic to recover its undepreciated investment in the plant, including a return on that investment, as well as unfunded nuclear decommissioning costs and other costs. Maine Yankee recovers its costs, including a return, in accordance with settlement agreements approved by the FERC in May 1999. Connecticut Yankee filed a similar request with the FERC, to which several parties intervened in opposition arguing that Connecticut Yankee was entitled to recover only those costs directly related to decommissioning, but should not recover any remaining unamortized investment or return on equity. In August 1998, a FERC Administrative Law Judge (ALJ) issued an initial decision which would allow for full recovery of Connecticut Yankee's unrecovered investment, but precluded a return on that investment. Connecticut Yankee, the Company, and other parties filed with the FERC exceptions to the ALJ's decision. Should the FERC uphold the ALJ's initial decision in its current form, the Company's share (including Montaup's) of the loss of the return component would total approximately $16 million to $20 million before taxes for the entire recovery period. In April 2000, a settlement was reached among Connecticut Yankee, the Connecticut Department of Public Utility Control (CDPUC), the Office of Consumer Counsel (OCC), and the Connecticut Municipal Electric Cooperative. The settlement resolves all issues in the case, except the OCC has reserved its right to appeal recovery of any costs other than decommissioning. Billings will be reduced prospectively. There will be no refund of any amounts collected up to the effective date of the settlement. Connecticut Yankee had reserved for potential refunds and will be reversing that reserve. Prospectively, Connecticut Yankee has agreed to reduce annual collections for decommissioning through the use of its pre-1983 spent fuel trust funds and to limit its return on equity to 6 percent. In addition, Connecticut Yankee has pursued litigation against the Department of Energy to assume financial responsibility for storage of spent nuclear fuel and has agreed to pass to ratepayers any recovery after litigation expenses. The settlement is pending before the FERC. A Maine statute provides that if both Maine Yankee and its decommissioning trust fund have insufficient assets to pay for the plant decommissioning, the owners of Maine Yankee are jointly and severally liable for the shortfall. Under the provisions of the Settlement Agreements, the Company recovers all costs, including shutdown costs, that the FERC allows these Yankee companies to bill to the Company. Maine Yankee had hired Stone & Webster, Inc., an engineering, construction, and consulting company, as the principal contractor to decommission the unit. Stone & Webster recently announced plans to file for Chapter 11 bankruptcy protection due to financial difficulties. Stone & Webster also announced that it has negotiated the sale of substantially all of its assets. In May 2000, Maine Yankee terminated its long-term contract with Stone & Webster and negotiated an arrangement with Stone & Webster to continue work until June 2000. On June 2, 2000, Stone & Webster filed for Chapter 11 bankruptcy protection. Maine Yankee is considering its options for decommissioning the unit beyond June 30, 2000. At this time, the Company is unable to determine the potential impact, if any, of this development. Operating Nuclear Units The Company has minority interests in three operating nuclear generating units which the Company is engaged in efforts to divest: Vermont Yankee, Millstone 3, and Seabrook 1. Uncertainties regarding the future of nuclear generating stations, particularly older units, such as Vermont Yankee, have increased in recent years and could adversely affect their service lives, availability, and costs. These uncertainties stem from a combination of factors, including the acceleration of competitive pressures in the power generation industry and increased Nuclear Regulatory Commission (NRC) scrutiny. The Company performs periodic economic viability reviews of operating nuclear units in which it holds ownership interests. Until such time as the Company divests its operating nuclear interests, the Company will share with customers, through the CTC, 80 percent of the revenues and operating costs related to the units, with shareholders retaining the balance. Vermont Yankee The following tables summarize the interests of the Company, and of Montaup (effective with the EUA merger), in the Vermont Yankee Nuclear Power Corporation as of March 31, 2000: The Company's Interest (millions of dollars) ---------------------------------------------- Equity Net Estimated Decommissioning Ownership Equity Plant Decommissioning Fund License Interest (%) Investment Assets Cost (in 1999$) Balance Expiration ------------ ---------- ------ --------------- ------- ---------- 20 $11 $33 $86 $43 2012 Montaup's Interest (millions of dollars) ---------------------------------------------- Equity Net Estimated Decommissioning Ownership Equity Plant Decommissioning Fund License Interest (%) Investment Assets Cost (in 1999$) Balance Expiration ------------ ---------- ------ --------------- ------- ---------- 2.5 $1 $4 $11 $5 2012 In November 1999, the Vermont Yankee Nuclear Power Corporation entered into an agreement with AmerGen Energy Company (AmerGen), a joint venture between PECO Energy and British Energy, to sell the assets of Vermont Yankee. Under the terms of the agreement, after a Vermont Yankee contribution toward the plant's decommissioning trust fund, AmerGen will take over the fund and assume responsibility for the actual cost of decommissioning the plant. The agreement also requires the existing power purchasers (including the Company) to continue to purchase the output of the plant or to buy out of the purchased power obligation. In November 1999, the Company signed an agreement to buy out of its obligation, requiring future payments which will be recovered through the Company's CTC. The Company has recorded an accrued liability and an offsetting regulatory asset of $80 million for its share of future liabilities related to Vermont Yankee, including the purchased power contract termination payment obligation, but excluding interest and a return allowance. The proposed sale is contingent upon regulatory approvals by the NRC, the Securities and Exchange Commission (SEC), under the Public Utility Holding Company Act of 1935 (1935 Act), and the Vermont Public Service Board (VPSB), among others. The Vermont Public Service Department has identified several issues that must be resolved to its satisfaction for it to support the VPSB's approval of the sale. Millstone 3 In August 1997, the Company sued Northeast Utilities (NU) in Massachusetts Superior Court for damages, alleging that NU engaged in tortious conduct that caused the shutdown of Millstone 3, which is operated by a subsidiary of NU. The Company's claim for damages included the costs of replacement power during the outage, costs necessary to return Millstone 3 to safe operation, and other additional costs. Most of the Company's incremental replacement power costs have been recovered from customers, either through fuel adjustment clauses or through provisions in the Settlement Agreements. In August 1997, the Company also sent a demand for arbitration to Connecticut Light & Power Company and Western Massachusetts Electric Company, both subsidiaries of NU, seeking damages for breach of obligations under an agreement with the Company and others regarding the operation and ownership of Millstone 3. In July 1998, Millstone 3 returned to full operation after being shut down for more than two years. In November 1999, the Company executed an agreement which settled the litigation and arbitration. Under the settlement agreement, the NU companies paid the Company $23.7 million and paid Montaup $7.8 million. The settlement also includes an agreement by NU to include the Company's and Montaup's share of Millstone 3 in an auction of NU's share of the unit. Upon the closing of the sale, NU will pay the Company and Montaup a combined total of $25 million, regardless of the actual sale price, and reimburse the Company and Montaup for any capital expenditures in excess of pre- budgeted levels incurred after October 1999. The Company and Montaup will also be reimbursed for fuel procurement expenditures which increase net nuclear fuel account balances above current balances. The settlement also requires NU to indemnify the Company and Montaup and assume any residual liabilities resulting from the sale, including any requirements that the sellers continue to purchase output from the unit. In addition, the settlement requires NU to pay the Company and Montaup an additional combined total of $1 million per month for every month beyond April 1, 2001 that the closing does not occur. The auction process is being conducted by the CDPUC and is ongoing. Amounts received pursuant to a sale will, after reimbursement of the Company's transaction costs and net investment in Millstone 3, be credited to customers. Seabrook 1 As part of its restructuring settlement with the State of New Hampshire, Public Service Company of New Hampshire (PSNH), through its affiliate, North Atlantic Energy Corporation (NAEC), has committed to seek New Hampshire Public Utilities Commission (NHPUC) approval of a definitive plan to sell, via public auction, its share of Seabrook 1, with such sale to occur no later than December 31, 2003. NAEC is the majority owner of the plant with a 35.98 percent interest and is also the plant operator. As part of its settlement, PSNH has also agreed to make all reasonable efforts to bundle its interests with those of other owners (including the Company) seeking to sell their interests. This would allow for an auction of a majority interest. The NHPUC granted conditional approval of the settlement on April 19, 2000. The New Hampshire legislature approved the necessary legislation on May 31, 2000. Final resolution by the NHPUC approving the settlement in compliance with the legislation is expected this summer. Year 2000 Disclosure In 1999, National Grid USA and its subsidiaries completed their remediation of the potential information systems (computer) problem resulting from the fact that many software applications and operational programs written in the past might not have recognized calendar dates associated with the year 2000 (Y2K). As a result of their remediation efforts, National Grid USA and its subsidiaries have experienced no significant disruptions in any of their enterprise or operational computer systems. National Grid USA's and its subsidiaries' costs of making the necessary Y2K modifications were approximately $28 million. In addition, National Grid USA and its subsidiaries spent approximately $9 million (of which approximately $7 million has been capitalized) related to the replacement of the human resources and payroll system, in part due to the Y2K issue. Risk Management The Company's major financial market risk exposure is changing interest rates. Changing interest rates will affect interest paid on variable rate debt. At March 31, 2000, the Company's variable rate long-term debt had a carrying value and fair value of approximately $372 million and maturity dates greater than five years. The weighted average variable interest rate for the three months ended March 31, 2000, was 3.75 percent. As discussed in the "Industry Restructuring" section, the Company remains obligated to provide transition power supply service at fixed rates to some new customer load in Rhode Island. The Company meets this obligation by periodically procuring the necessary power supply at market prices. The Company cannot predict whether the resulting revenues will be sufficient to cover the costs to procure such power over the term of the obligation. In the short term, it appears that due to current high market prices, it is probable the Company will incur losses this summer. At this point, management cannot reasonably estimate the level of such losses. Utility Plant Expenditures and Financing Cash expenditures for the Company for utility plant totaled $12 million for the three months ended March 31, 2000 and were primarily transmission-related. The funds necessary for utility plant expenditures during the period were primarily provided by internal funds. Cash expenditures for fiscal year 2001 for the Company and Montaup are estimated to be approximately $45 million, principally related to transmission functions. Internally generated funds are expected to fully cover capital expenditures in fiscal year 2001. On February 8, 1999, the Company repurchased 130,000 shares of its common stock from NEES for $18 million. Approximately $7 million of the repurchase price was charged to retained earnings. Dividends payable at March 31, 2000, in the amount of $256 million were paid on June 27, 2000. The Company has regulatory approval to issue up to $375 million of short-term debt. In 1999, the Company issued $39 million of short-term tax-exempt debt. This debt remains outstanding as of March 31, 2000. The Company plans to seek the necessary regulatory approvals in 2000 which would allow the $39 million of variable rate debt to remain outstanding through 2015. This would result in classifying the debt as long-term rather than short-term. At March 31, 2000, the Company had lines of credit and standby bond purchase facilities with banks totaling $460 million which are available to provide liquidity support for $410 million of the Company's short-term and long-term bonds in tax-exempt commercial paper mode (including the $39 million discussed above), and for other corporate purposes. There were no borrowings under these lines of credit at March 31, 2000. New England Power Company Statements of Income 3 Months ended Year ended March 31, December 31, (In thousands) 2000 1999 1999 1998 1997 (unaudited) - ------------------------------------------------------------------------------------------- Operating revenue, principally from affiliates $134,564$167,177 $ 596,341$1,218,340 $1,677,903 Operating expenses: Fuel for generation 3,548 3,058 12,803 223,828 372,734 Purchased electric energy: Contract termination and nuclear unit shutdown charges 47,405 46,873 187,777 97,469 43,876 Other 14,682 11,111 56,731 302,367 483,771 Other operation 15,760 19,210 70,936 155,065 241,506 Maintenance 4,320 5,766 28,536 60,239 89,820 Depreciation and amortization 17,328 40,367 103,080 99,924 98,024 Taxes, other than income taxes 5,561 5,634 20,282 48,492 67,311 Income taxes 9,641 13,100 37,633 73,594 90,009 ---------------- --------- ---------- ---------- Total operating expenses 118,245 145,119 517,778 1,060,9781,487,051 ---------------- --------- ---------- ---------- Operating income 16,319 22,058 78,563 157,362 190,852 Other income: Allowance for equity funds used during construction (393) 588 1,958 633 - Equity in income of nuclear power companies 862 515 2,939 5,284 5,189 Other income (expense), net 1,850 434 2,087 118 (3,404) ---------------- --------- ---------- ---------- Operating and other income 18,638 23,595 85,547 163,397 192,637 ---------------- --------- ---------- ---------- Interest: Interest on long-term debt 3,749 3,143 14,052 30,775 42,277 Other interest 853 240 1,003 10,688 7,055 Allowance for borrowed funds used during construction (426) (133) (522) (961) (1,238) ---------------- --------- ---------- ---------- Total interest 4,176 3,250 14,533 40,502 48,094 ---------------- --------- ---------- ---------- Net income $ 14,462$ 20,345 $ 71,014 $ 122,895 $ 144,543 ================ ========= ========== ========== Statements of Retained Earnings 3 Months ended Year ended March 31, December 31, (In thousands) 2000 1999 1999 1998 1997 (unaudited) - ------------------------------------------------------------------------------------------- Retained earnings at beginning of period $ 27,287$204,603 $ 204,603$ 407,630 $ 400,610 Net income 14,462 20,345 71,014 122,895 144,543 Dividends declared on cumulative preferred stock (24) (24) (94) (1,230) (2,075) Dividends declared on common stock, $6.66, $-0-, $66.69, $20.25, and $21.00 per share, respectively (24,098) -(241,415) (130,610)(135,448) Premium on redemption of preferred stock - - 264 (264) - Repurchase of common stock - (7,085) (7,085) (193,818) - Purchase accounting adjustment (16,212) - - - - ---------------- --------- ---------- ---------- Retained earnings at end of period$ 1,415$217,839 $ 27,287 $ 204,603 $ 407,630 ================ ========= ========== ========== The accompanying notes are an integral part of these financial statements. New England Power Company Balance Sheets At March 31, At December 31, (In thousands) 2000 1999 1998 - -------------------------------------------------------------------------------------- Assets Utility plant, at original cost $1,318,026 $1,312,384 $1,262,461 Less accumulated provisions for depreciation and amortization 854,309 849,694 837,637 ---------- ---------- ---------- 463,717 462,690 424,824 Construction work in progress 35,730 30,063 33,289 ---------- ---------- ---------- Net utility plant 499,447 492,753 458,113 ---------- ---------- ---------- Total goodwill, net of amortization 333,771 - - Investments: Nuclear power companies, at equity (Note D-1) 45,966 46,233 48,538 Decommissioning trust funds (Note D-2) 36,279 36,279 31,281 Nonutility property and other investments 7,490 7,248 8,302 ---------- ---------- ---------- Total investments 89,735 89,760 88,121 ---------- ---------- ---------- Current assets: Cash and temporary cash investments (including $37,820, $59,039, and $109,911 with affiliates) 226,921 204,344 179,413 Accounts receivable: Affiliated companies 72,780 73,444 107,878 Others 48,139 44,301 32,573 Fuel, materials, and supplies, at average cost 10,345 9,471 9,220 Prepaid and other current assets 25,377 39,315 21,569 Regulatory asset purchased power obligations 74,988 73,369 128,931 ---------- ---------- ---------- Total current assets 458,550 444,244 479,584 ---------- ---------- ---------- Regulatory assets (Note C) 1,210,800 1,272,463 1,383,631 Deferred charges and other assets 37,271 3,445 5,339 ---------- ---------- ---------- $2,629,574 $2,302,665 $2,414,788 ========== ========== ========== Capitalization and Liabilities Capitalization: Common stock, par value $20 per share, Authorized - 6,449,896 shares Outstanding - 3,619,896, 3,619,896, and 3,749,896 shares $ 72,398 $ 72,398 $ 74,998 Premium on capital stock - 48,623 50,371 Other paid-in capital (Note J) 582,983 183,937 190,852 Retained earnings 1,415 27,287 204,603 Unrealized gain on securities, net - 91 72 ---------- ---------- ---------- Total common equity 656,796 332,336 520,896 Cumulative preferred stock, par value $100 per share (Note H) 1,567 1,567 1,567 Long-term debt 371,773 371,771 371,765 ---------- ---------- ---------- Total capitalization 1,030,136 705,674 894,228 ---------- ---------- ---------- Current liabilities: Short-term debt 38,500 38,500 - Accounts payable (including $26,993, $25,620, and $119,657 to affiliates) 51,584 63,212 162,360 Accrued liabilities: Taxes 2,394 3,889 15,009 Interest 1,900 3,378 2,440 Purchased power contract obligations 74,988 73,369 128,931 Other accrued expenses (Note G) 10,879 15,693 20,086 Dividends payable 256,487 232,365 24 ---------- ---------- ---------- Total current liabilities 436,732 430,406 328,850 ---------- ---------- ---------- Deferred federal and state income taxes 176,351 179,686 165,115 Unamortized investment tax credits 16,733 19,060 30,870 Accrued Yankee nuclear plant costs (Note D-2) 268,855 277,932 242,138 Purchased power obligations 611,802 630,368 703,737 Other reserves and deferred credits 88,965 59,539 49,850 Commitments and contingencies (Note D) ---------- ---------- ---------- $2,629,574 $2,302,665 $2,414,788 ========== ========== ========== The accompanying notes are an integral part of these financial statements. New England Power Company Statements of Cash Flows 3 Months ended Year ended March 31, December 31, (In thousands) 2000 1999 1999 1998 1997 (unaudited) - -------------------------------------------------------------------------------------------- Operating activities: Net income $ 14,462$ 20,345$ 71,014 $ 122,895 $ 144,543 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation and amortization 19,165 42,170 108,789 104,331 101,186 Deferred income taxes and investment tax credits, net (2,908) 5,726 14,111 (226,722)(12,728) Allowance for funds used during construction (33) (720) (2,480) (1,594) (1,238) Reimbursement to New England Energy Incorporated of loss on sale of oil and gas properties - - - (120,900) - Buyout of purchased power contracts - - (3,472) (326,590) - Decrease (increase) in accounts receivable (3,174) 37,890 22,706 130,914 (25,128) Decrease (increase) in fuel, materials, and supplies (874) 648 (251) (10,270) 11,217 Decrease (increase) in regulatory asset purchased power obligations (1,619) 19,956 55,562 (128,931) - Decrease (increase) in prepaid and other current assets 13,938 6,154 (17,746) (8,778) 7,213 Increase (decrease) in accounts payable (11,628)(81,950)(99,148) (31,761)(18,105) Increase (decrease) in current purchased power contract payable 1,619 (19,956)(55,562) 128,931 - Increase (decrease) in other current liabilities (7,787)(11,147)(14,575) 5,037 (1,905) Other, net 13,577 (709) (3,995) (49,611) 19,919 ------------------------ ----------- --------- Net cash provided by (used in) operating activities $ 34,738$ 18,407$ 74,953 $ (413,049) $ 224,974 ------------------------ ----------- --------- Investing activities: Proceeds from sale of generating assets $ -$ -$ - $ 1,688,863 $ - Plant expenditures, excluding allowance for funds used during construction (11,890) $(13,739) (56,887)(64,446) (69,863) Other investing activities (271) (20) (4,411) (5,474) (4,040) ------------------------ ----------- --------- Net cash provided by (used in) investing activities $(12,161) $(13,759) $(61,298) $ 1,618,943 $ (73,903) ------------------------ ----------- --------- Financing activities: Capital contribution from parent $ -$ -$ - $ 34,881 $ - Dividends paid on common stock - - (9,050) (166,084) (127,386) Dividends paid on preferred stock - (24) (118) (1,206) (2,075) Changes in short-term debt - - 38,500 (111,250) 17,650 Long-term debt - retirements - - - (328,000)(38,500) Repurchase of common shares - (18,056)(18,056) (417,960) - Preferred stock - retirements - - - (38,505) - Premium on reacquisition of long-term debt - - - - (2,163) ------------------------ ----------- --------- Net cash provided by (used in) financing activities $ -$(18,080) $ 11,276 $(1,028,124) $(152,474) ------------------------ ----------- --------- Net increase (decrease) in cash and cash equivalents $ 22,577$(13,432) $ 24,931 $ 177,770 $ (1,403) Cash and cash equivalents at beginning of period 204,344 179,413 179,413 1,643 3,046 ------------------------ ----------- --------- Cash and cash equivalents at end of period $226,921$165,981$204,344 $ 179,413 $ 1,643 ======================== =========== ========= Supplementary Information: Interest paid less amounts capitalized $ 5,322$ 2,042 $ 11,849 $ 43,419 $ 46,033 ------------------------ ----------- --------- Federal and state income taxes paid$ (15) $ 11,321 $ 55,134 $ 282,076 $ 109,109 ------------------------ ----------- --------- Dividends received from investments at equity $ 1,129$ 1,730$ 5,243 $ 6,571 $ 3,267 ------------------------ ----------- --------- The accompanying notes are an integral part of these financial statements. New England Power Company Notes to Financial Statements Note A - Significant Accounting Policies 1. Nature of Operations: New England Power Company (the Company), a wholly owned subsidiary of National Grid USA (formerly New England Electric System (NEES)), is a Massachusetts corporation qualified to do business in Massachusetts, New Hampshire, Rhode Island, Connecticut, Maine, and Vermont. The Company is subject, for certain purposes, to the jurisdiction of the regulatory commissions of these six states, the Securities and Exchange Commission (SEC), under the Public Utility Holding Company Act of 1935 (1935 Act), the Federal Energy Regulatory Commission (FERC), and the Nuclear Regulatory Commission (NRC). The Company's business is primarily the transmission of electric energy in wholesale quantities to other electric utilities, principally its distribution affiliates, Granite State Electric Company, Massachusetts Electric Company, Nantucket Electric Company, and The Narragansett Electric Company (Narragansett Electric). In addition, the Company also owns minority interests in two joint owned nuclear generating units as well as minority equity interests in four nuclear generating companies (Yankees), three of which own generating facilities that are permanently shut down. The output from these generating facilities is sold to third parties. 2. Change of Fiscal Year: National Grid USA and its subsidiaries, including the Company, changed their 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 National Grid USA's parent company, The National Grid Group plc (National Grid). The Company's first new full fiscal year began on April 1, 2000 and will end on March 31, 2001. The Company has reported results of operations for the three month transitional period ended March 31, 2000, the three month period ended March 31, 1999, and the years ended December 31, 1999, December 31, 1998, and December 31, 1997. The Company has also reported balance sheets as of March 31, 2000, December 31, 1999, and December 31, 1998, and statements of cash flows for the three month periods ended March 31, 2000, and March 31, 1999, and the years ended December 31, 1999, December 31, 1998, and December 31, 1997. 3. System of Accounts: The accounts of the Company are maintained in accordance with the Uniform System of Accounts prescribed by regulatory bodies having jurisdiction. In preparing the financial statements, management is required to make estimates that affect the reported amounts of assets and liabilities and disclosures of asset recovery and contingent liabilities as of the date of the balance sheets, and revenues and expenses for the period. These estimates may differ from actual amounts if future circumstances cause a change in the assumptions used to calculate these estimates. In addition, certain presentation adjustments have been made to conform prior years with the current presentation. 4. Allowance for Funds Used During Construction (AFDC): The Company capitalizes AFDC as part of construction costs. AFDC represents the composite interest and equity costs of capital funds used to finance that portion of construction costs not yet eligible for inclusion in rate base. AFDC is capitalized in "Utility plant" with offsetting noncash credits to "Other income" and "Interest." This method is in accordance with an established rate-making practice under which a utility is permitted a return on, and the recovery of, prudently incurred capital costs through their ultimate inclusion in rate base and in the provision for depreciation. The composite AFDC rates were 3.7 percent for the three month period ended March 31, 2000, 8.1 percent for the three month period ended March 31, 1999, and 7.6 percent, 6.1 percent, and 5.9 percent for the years ended December 31, 1999, 1998, and 1997, respectively. 5. Depreciation and Amortization: The depreciation and amortization expense included in the statements of income is composed of the following: Three Months Ended Year Ended March 31, December 31, (In thousands) 2000 1999 1999 1998 1997 (unaudited) - -------------------------------------------------------------------------------------- Depreciation - transmission related $ 3,269$ 3,440$ 13,222$12,553 $11,828 Depreciation - all other (15) 354 1,286 46,256 68,432 Nuclear decommissioning costs (Note D-2) 923 699 3,637 2,719 2,638 Amortization: Seabrook 2 property losses - - - - 113 Millstone 3 additional amortization, pursuant to 1995 rate settlement - - - 22,040 15,013 Regulatory assets covered by contract termination charges (Note C) 12,785 35,874 84,935 16,356 - Goodwill 366 - - - - ----------------------------- ------- Total depreciation and amortization expense $17,328$40,367$103,080$99,924 $98,024 ============================= ======= Depreciation is provided annually on a straight-line basis. The provision for depreciation as a percentage of weighted average depreciable transmission property was 2.3 percent for the three month periods ended March 31, 2000, and March 31, 1999, and the years ended December 31, 1999, 1998, and 1997. Amortization of Seabrook and Millstone investments above normal depreciation accruals and amortization of regulatory assets covered by contract termination charges (CTC) was in accordance with rate settlement agreements. The Company will amortize goodwill associated with the mergers of National Grid and National Grid USA, and National Grid USA and Eastern Utilities Associates (EUA) over a 20 year period on a straight line basis. 6. Cash: The Company classifies short-term investments with a maturity at purchase date of 90 days or less as cash. Note B - Mergers with National Grid and EUA Merger with National Grid On March 22, 2000, the merger of NEES and National Grid was completed, with NEES (renamed National Grid USA) becoming a wholly owned subsidiary of National Grid. National Grid paid a total of $4 billion, including $3.2 billion in cash paid to shareholders pursuant to the merger agreement, $642 million for National Grid USA's merger with EUA (discussed below), an additional capital contribution of $141 million, and merger related expenses of $37 million. The Company will maintain its existing name and will remain a wholly owned subsidiary of National Grid USA. The merger of National Grid USA and National Grid has been accounted for as an acquisition of National Grid USA by National Grid using the purchase method of accounting. The application of the purchase method, including the recognition of goodwill, is being pushed down and reflected on the financial statements of the National Grid USA subsidiaries, including the Company. Total goodwill amounted to $1.7 billion, of which the Company was allocated $334.1 million at the date of the merger. This amount was determined pursuant to an independent study conducted by a third party and is being amortized over 20 years. The annual amortization expense will amount to approximately $16.7 million. The purchase accounting method requires the Company to revalue its assets and liabilities at their fair value. This revaluation resulted in a net debit adjustment to the Company's pension and postretirement benefit plans in the amount of approximately $61 million, with a corresponding offsetting credit to a regulatory liability account (see Note E). Merger with EUA The merger between the National Grid USA and EUA parent companies was completed on April 19, 2000, with EUA merging into National Grid USA. The impacts of this transaction will be reflected in subsequent reporting periods. The price paid by National Grid USA was $642 million, or $31.459 per share. On May 1, 2000, Montaup Electric Company (Montaup), formerly a subsidiary of EUA, merged into the Company. The merger of EUA and National Grid USA is being accounted for by the purchase method, the application of which, including the recognition of goodwill, is being pushed down and reflected on the financial statements of the National Grid USA subsidiaries, including the Company. Total goodwill amounted to $388 million, of which the Company was allocated $7.7 million. This amount was determined pursuant to an independent study conducted by a third party and is being amortized over 20 years. The annual amortization expense will amount to approximately $0.4 million. Note C - Industry Restructuring Pursuant to legislation enacted in Massachusetts, Rhode Island, and New Hampshire, and settlement agreements approved by state and federal regulators (the Settlement Agreements), all customers were granted choice of power supplier in 1998. To facilitate the implementation of customer choice, the Settlement Agreements provided for the amendment of the Company's all- requirements contracts with its affiliated distribution companies. The Company's all-requirements contracts with some unaffiliated customers were terminated pursuant to settlement agreements or tariff provisions. However, the Company remains obligated to provide transition power supply service at fixed rates to some new customer load in Rhode Island. In addition, as a result of the Settlement Agreements, the Company and its affiliate, Narragansett Electric, sold substantially all of their nonnuclear generating business (divestiture) in September 1998. As part of the divestiture plan, New England Energy Incorporated sold its oil and gas properties in 1998, resulting in a loss of approximately $120 million, before tax, which was reimbursed by the Company. The Company also agreed to endeavor to sell its minority interest in three nuclear power plants and a 60 megawatt interest in a fossil- fueled generating station in Maine. In conjunction with the divestiture, the Company transferred to the buyer of its nonnuclear generating business (the buyer) its entitlement to power procured under several long-term contracts in exchange for monthly fixed payments by the Company averaging $9.5 million per month through January 2008 (having a net present value at March 31, 2000 of approximately $687 million) toward the above-market cost of those contracts. The Company has recorded a corresponding current liability of $75 million, and a long-term liability of $612 million. For certain contracts which have been formally assigned to the buyer, the Company has made lump sum payments equivalent to the present value of the monthly fixed payment obligations of those contracts (approximately $345 million at date of purchase, which corresponds to approximately $290 million at March 31, 2000), which were separate from the $687 million figure referred to above. Under the Settlement Agreements, the Company is permitted to recover costs associated with its former generating investments and related contractual commitments that were not recovered through the sale of those investments (stranded costs). These costs are recovered from the Company's wholesale customers with which it has settlement agreements through CTCs which the affiliated wholesale customers recover through delivery charges to distribution customers. The recovery of the Company's stranded costs is divided into several categories. The Company's unrecovered costs associated with generating plants (nuclear and nonnuclear) and most regulatory assets will be fully recovered through the CTC by the end of 2000 and earn a return on equity averaging 9.7 percent. The Company's obligation related to the above-market cost of purchased power contracts and nuclear decommissioning costs are recovered through the CTC as such costs are actually incurred. As the CTC rate declines, the Company, under certain of the Settlement Agreements, earns incentives based on successful mitigation of its stranded costs. These incentives supplement the Company's return on equity. Until such time as the Company divests its operating nuclear interests, the Company will share with customers, through the CTC, 80 percent of the revenues and operating costs related to the units, with shareholders retaining the balance. For further information on the potential sale of the Vermont Yankee and Millstone 3 nuclear generating units, refer to the "Nuclear Units" section below. Accounting Implications Because electric utility rates have historically been based on a utility's costs, electric utilities are subject to certain accounting standards that are not applicable to other business enterprises in general. The Company applies the provisions of Statement of Financial Accounting Standards No. 71, Accounting for the Effects of Certain Types of Regulation (FAS 71), which requires regulated entities, in appropriate circumstances, to establish regulatory assets or liabilities, and thereby defer the income statement impact of certain charges or revenues because they are expected to be collected or refunded through future customer billings. In 1997, the Emerging Issues Task Force of the Financial Accounting Standards Board concluded that a utility that had received approval to recover stranded costs through regulated rates would be permitted to continue to apply FAS 71 to the recovery of stranded costs. As discussed above, the Company received authorization from the FERC to recover through CTCs substantially all of the costs associated with its former generating business not recovered through the divestiture. Additionally, FERC Order No. 888 enables transmission companies to recover their specific costs of providing transmission service. Therefore, substantially all of the Company's business, including the recovery of its stranded costs, remains under cost-based rate regulation. Because of the nuclear cost-sharing provisions related to the Company's CTC, the Company ceased applying FAS 71 in 1997 to 20 percent of its ongoing nuclear operations, the impact of which is immaterial. As a result of applying FAS 71, the Company has recorded a regulatory asset for the costs that are recoverable from customers through the CTC. At March 31, 2000, this amounted to approximately $1.3 billion, including $1.0 billion related to the above-market costs of purchased power contracts, $0.3 billion related to accrued Yankee nuclear plant costs, and other net CTC-related regulatory assets. Note D - Commitments and Contingencies 1. Yankee Nuclear Power Companies The Company has minority interests in four Yankee Nuclear Power Companies. These ownership interests are accounted for on the equity method. The Company's share of the expenses of the Yankees is accounted for in "Purchased electric energy" on the income statement. A summary of combined results of operations, assets, and liabilities of the four Yankees is as follows: Three Months Ended Year Ended March 31, December 31, (In thousands) 2000 1999 1999 1998 1997 (unaudited) - ------------------------------------------------------------------------------------------ Operating revenue $ 81,225 $ 89,244$ 377,039$ 439,046 $ 660,742 =========== ====================== =========== =========== Net income $ 5,310 $ 5,138$ 13,890 $ 23,218 $ 29,959 =========== ====================== =========== =========== Company's equity in net income $ 862 $ 515$ 2,939 $ 5,284 $ 5,189 =========== ====================== =========== =========== Net plant 167,317 166,062 172,100 171,582 204,689 Other assets 2,520,887 2,798,948 2,631,750 2,810,613 3,100,589 Liabilities and debt (2,437,609) (2,707,749)(2,554,261) (2,723,454) (3,036,845) ----------- ---------------------- ----------- ----------- Net assets $ 250,595 $ 257,261$ 249,589 $ 258,741 $ 268,433 =========== ====================== =========== =========== Company's equity in net assets $ 45,966 $ 47,323$ 46,233 $ 48,538 $ 49,825 =========== ====================== =========== =========== Company's purchased electric energy: Vermont Yankee $ 7,761 $ 7,874$ 37,551 $ 35,108 $ 31,240 All other Yankees $ 9,324 $ 9,370$ 37,765 $ 48,543 $ 75,900 =========== ====================== =========== =========== 2. Nuclear Units Nuclear Units Permanently Shut Down Three regional nuclear generating companies in which the Company has a minority interest own nuclear generating units that have been permanently shut down. These three units, including Montaup's portion effective with the EUA merger, are as follows: Future The Company's Estimated Investment Billings to as of 3/31/00 Date the Company Unit % $(millions) Retired $(millions) - ----------------------------------------------------------------- Yankee Atomic 30 4 Feb 1992 4 Connecticut Yankee 15 16 Dec 1996 60 Maine Yankee 20 15 Aug 1997 124 Future Montaup's Estimated Investment Billings as of 3/31/00 Date to Montaup Unit % $(millions) Retired $(millions) - ----------------------------------------------------------------- Yankee Atomic 4.5 1 Feb 1992 1 Connecticut Yankee 4.5 5 Dec 1996 19 Maine Yankee 4.0 3 Aug 1997 26 In the case of each of these units, the Company has recorded a liability and an offsetting regulatory asset reflecting the estimated future billings from the companies. In a 1993 decision, the FERC allowed Yankee Atomic to recover its undepreciated investment in the plant, including a return on that investment, as well as unfunded nuclear decommissioning costs and other costs. Maine Yankee recovers its costs, including a return, in accordance with settlement agreements approved by the FERC in May 1999. Connecticut Yankee filed a similar request with the FERC, to which several parties intervened in opposition arguing that Connecticut Yankee was entitled to recover only those costs directly related to decommissioning, but should not recover any remaining unamortized investment or return on equity. In August 1998, a FERC Administrative Law Judge (ALJ) issued an initial decision which would allow for full recovery of Connecticut Yankee's unrecovered investment, but precluded a return on that investment. Connecticut Yankee, the Company, and other parties filed with the FERC exceptions to the ALJ's decision. Should the FERC uphold the ALJ's initial decision in its current form, the Company's share (including Montaup's) of the loss of the return component would total approximately $16 million to $20 million before taxes for the entire recovery period. In April 2000, a settlement was reached among Connecticut Yankee, the Connecticut Department of Public Utility Control (CDPUC), the Office of Consumer Counsel (OCC), and the Connecticut Municipal Electric Cooperative. The settlement resolves all issues in the case, except the OCC has reserved its right to appeal recovery of any costs other than decommissioning. Billings will be reduced prospectively. There will be no refunds of any amounts collected up to the effective date of the settlement. Connecticut Yankee had reserved for potential refunds and will be reversing that reserve. Prospectively, Connecticut Yankee has agreed to reduce annual collections for decommissioning through the use of its pre-1983 spent fuel trust funds and to limit its return on equity to 6 percent. In addition, Connecticut Yankee has pursued litigation against the Department of Energy (DOE) to assume financial responsibility for storage of spent nuclear fuel and has agreed to pass to ratepayers any recovery after litigation expenses. The settlement is pending before the FERC. A Maine statute provides that if both Maine Yankee and its decommissioning trust fund have insufficient assets to pay for the plant decommissioning, the owners of Maine Yankee are jointly and severally liable for the shortfall. Under the provisions of the Settlement Agreements, the Company recovers all costs, including shutdown costs, that the FERC allows these Yankee companies to bill to the Company. Maine Yankee had hired Stone & Webster, Inc., an engineering, construction, and consulting company, as the principal contractor to decommission the unit. Stone & Webster recently announced plans to file for Chapter 11 bankruptcy protection due to financial difficulties. Stone & Webster also announced that it has negotiated the sale of substantially all of its assets. In May 2000, Maine Yankee terminated its long-term contract with Stone & Webster and negotiated an arrangement with Stone & Webster to continue work until June 2000. On June 2, 2000, Stone & Webster filed for Chapter 11 bankruptcy protection. Maine Yankee is considering its options for decommissioning the unit beyond June 30, 2000. At this time, the Company is unable to determine the potential impact, if any, of this development. Operating Nuclear Units The Company has minority interests in three operating nuclear generating units which the Company is engaged in efforts to divest: Vermont Yankee, Millstone 3, and Seabrook 1. Uncertainties regarding the future of nuclear generating stations, particularly older units, such as Vermont Yankee, have increased in recent years and could adversely affect their service lives, availability, and costs. These uncertainties stem from a combination of factors, including the acceleration of competitive pressures in the power generation industry and increased NRC scrutiny. The Company performs periodic economic viability reviews of operating nuclear units in which it holds ownership interests. Until such time as the Company divests its operating nuclear interests, the Company will share with customers, through the CTC, 80 percent of the revenues and operating costs related to the units, with shareholders retaining the balance. Vermont Yankee The following tables summarize the interests of the Company, and of Montaup (effective with the EUA merger), in the Vermont Yankee Nuclear Power Corporation as of March 31, 2000: The Company's Interest (millions of dollars) ---------------------------------------------- Equity Net Estimated Decommissioning Ownership Equity Plant Decommissioning Fund License Interest (%) Investment Assets Cost (in 1999$) Balance Expiration ------------ ---------- ------ --------------- ------- ---------- 20 $11 $33 $86 $43 2012 Montaup's Interest (millions of dollars) ---------------------------------------------- Equity Net Estimated Decommissioning Ownership Equity Plant Decommissioning Fund License Interest (%) Investment Assets Cost (in 1999$) Balance Expiration ------------ ---------- ------ --------------- ------- ---------- 2.5 $1 $4 $11 $5 2012 In November 1999, the Vermont Yankee Nuclear Power Corporation entered into an agreement with AmerGen Energy Company (AmerGen), a joint venture between PECO Energy and British Energy, to sell the assets of Vermont Yankee. Under the terms of the agreement, after a Vermont Yankee contribution toward the plant's decommissioning trust fund, AmerGen will take over the fund and assume responsibility for the actual cost of decommissioning the plant. The agreement also requires the existing power purchasers (including the Company) to continue to purchase the output of the plant or to buy out of the purchased power obligation. In November 1999, the Company signed an agreement to buy out of its obligation, requiring future payments which will be recovered through the Company's CTC. The Company has recorded an accrued liability and an offsetting regulatory asset of $80 million for its share of future liabilities related to Vermont Yankee, including the purchased power contract termination payment obligation, but excluding interest and a return allowance. The proposed sale is contingent upon regulatory approvals by the NRC, the SEC, under the 1935 Act, and the Vermont Public Service Board (VPSB), among others. The Vermont Public Service Department has identified several issues that must be resolved to its satisfaction for it to support the VPSB's approval of the sale. Millstone 3 In August 1997, the Company sued Northeast Utilities (NU) in Massachusetts Superior Court for damages, alleging that NU engaged in tortious conduct that caused the shutdown of Millstone 3, which is operated by a subsidiary of NU. The Company's claim for damages included the costs of replacement power during the outage, costs necessary to return Millstone 3 to safe operation, and other additional costs. Most of the Company's incremental replacement power costs have been recovered from customers, either through fuel adjustment clauses or through provisions in the Settlement Agreements. In August 1997, the Company also sent a demand for arbitration to Connecticut Light & Power Company and Western Massachusetts Electric Company, both subsidiaries of NU, seeking damages for breach of obligations under an agreement with the Company and others regarding the operation and ownership of Millstone 3. In July 1998, Millstone 3 returned to full operation after being shut down for more than two years. In November 1999, the Company executed an agreement which settled the litigation and arbitration. Under the settlement agreement, the NU companies paid the Company $23.7 million and paid Montaup $7.8 million. The settlement also includes an agreement by NU to include the Company's and Montaup's share of Millstone 3 in an auction of NU's share of the unit. Upon the closing of the sale, NU will pay the Company and Montaup a combined total of $25 million, regardless of the actual sale price, and reimburse the Company and Montaup for any capital expenditures in excess of pre- budgeted levels incurred after October 1999. The Company and Montaup will also be reimbursed for fuel procurement expenditures which increase net nuclear fuel account balances above current balances. The settlement also requires NU to indemnify the Company and Montaup and assume any residual liabilities resulting from the sale, including any requirements that the sellers continue to purchase output from the unit. In addition, the settlement requires NU to pay the Company and Montaup an additional combined total of $1 million per month for every month beyond April 1, 2001 that the closing does not occur. The auction process is being conducted by the CDPUC and is ongoing. Amounts received pursuant to a sale will, after reimbursement of the Company's transaction costs and net investment in Millstone 3, be credited to customers. Seabrook 1 As part of its restructuring settlement with the State of New Hampshire, Public Service Company of New Hampshire (PSNH), through its affiliate, North Atlantic Energy Corporation (NAEC), has committed to seek New Hampshire Public Utilities Commission (NHPUC) approval of a definitive plan to sell, via public auction, its share of Seabrook 1, with such sale to occur no later than December 31, 2003. NAEC is the majority owner of the plant with a 35.98 percent interest and is also the plant operator. As part of its settlement, PSNH has also agreed to make all reasonable efforts to bundle its interests with those of other owners (including the Company) seeking to sell their interests. This would allow for an auction of a majority interest. The NHPUC granted conditional approval of the settlement on April 19, 2000. The New Hampshire legislature approved the necessary legislation on May 31, 2000. Final resolution by the NHPUC approving the settlement in compliance with the legislation is expected this summer. Nuclear Decommissioning The Company is liable for its share of decommissioning costs for Millstone 3, Seabrook 1, and all of the Yankees. Decommissioning costs include not only estimated costs to decontaminate the units as required by the NRC, but also costs to dismantle the uncontaminated portion of the units. The Company records decommissioning costs on its books consistent with its rate recovery. The Company is recovering its share of projected decommissioning costs for Millstone 3 and Seabrook 1 and these costs are recorded as depreciation expense. In addition, the Company is paying its portion of projected decommissioning costs for all of the Yankees through purchased power expense. Such costs reflect estimates of total decommissioning costs approved by the FERC. In New Hampshire, legislation was enacted in 1998 which makes owners of Seabrook 1, in which the Company owns a 10 percent interest, proportional guarantors for decommissioning costs in the event that an owner without a franchise service territory fails to fund its share of decommissioning costs. Currently, a single owner of an approximate 15 percent share of Seabrook 1 has no franchise service territory. The impact of this legislation to the Company is not considered material to its financial position or results of operation. The Nuclear Waste Policy Act of 1982 establishes that the federal government (through the DOE) is responsible for the disposal of spent nuclear fuel. The federal government requires the Company to pay a fee based on its share of the net generation from the Millstone 3 and Seabrook 1 nuclear generating units. Prior to 1998, the Company recovered this fee through its fuel clause. Under the Settlement Agreements, substantially all of these costs are recovered through CTCs. Similar costs are billed to the Company by Vermont Yankee and are also recovered from customers through CTCs. In 1997, ruling on a lawsuit brought against the DOE by numerous utilities and state regulatory commissions, the U.S. Court of Appeals for the District of Columbia held that the DOE was obligated to begin disposing of utilities' spent nuclear fuel by January 1998. The DOE failed to meet this deadline and is not expected to have a temporary or permanent repository for spent nuclear fuel before 2010, at the earliest. Many utilities, including Yankee Atomic, Connecticut Yankee, and Maine Yankee, are plaintiffs in on-going litigation related to the DOE's failure to accept spent nuclear fuel. Decommissioning Trust Funds Each nuclear unit in which the Company and Montaup have an ownership interest has established a decommissioning trust fund or escrow fund into which payments are being made to meet the projected costs of decommissioning. The tables below list information on the operating nuclear plants in which the Company and Montaup are joint owners. The Company's share of (millions of dollars) -------------------------------------------- Decommissioning The Company's Net Estimated Fund OwnershipPlant AssetsDecommissioning Balances* License Unit Interest (%)(at 3/31/00) Cost (in 1999 $) (at 3/31/00) Expiration - ---------------------------------------------------------------------------------------- Millstone 3 12 12** 76 23 2025 Seabrook 1 10 14** 56 13 2026 Montaup's share of (millions of dollars) -------------------------------------------- Decommissioning The Company's Net Estimated Fund OwnershipPlant AssetsDecommissioning Balances* License Unit Interest (%)(at 3/31/00) Cost (in 1999 $) (at 3/31/00) Expiration - ---------------------------------------------------------------------------------------- Millstone 3 4 4** 25 8 2025 <FN> *Certain additional amounts are anticipated to be available through tax deductions. **Represents post-December 1995 spending including nuclear fuel. For further information, refer to Note C. </FN> There is no assurance that decommissioning costs actually incurred will not substantially exceed the estimated amounts. For example, decommissioning cost estimates assume the availability of permanent repositories for both low-level and high-level nuclear waste; those repositories do not currently exist. The temporary low-level repository located in Barnwell, South Carolina will gradually become unavailable to units other than Connecticut Yankee and Millstone 3. If any of the operating units were shut down prior to the end of their operating licenses, which the Company believes is likely, the funds collected for decommissioning to that point would be insufficient. Under the Settlement Agreements, the Company will recover decommissioning costs through CTCs. Nuclear Insurance The Price-Anderson Act limits the amount of liability claims that would have to be paid in the event of a single incident at a nuclear plant to $9.5 billion (based upon 106 licensed reactors). The maximum amount of commercially available insurance coverage to pay such claims is $200 million. The remaining $9.3 billion would be provided by an assessment of up to $88.1 million per incident levied on each of the participating nuclear units in the United States, subject to a maximum assessment of $10 million per incident per nuclear unit in any year. The maximum assessment, which was most recently adjusted in 1998, is adjusted for inflation at least every five years. The Company's current interest in Vermont Yankee, Millstone 3, and Seabrook 1 would subject the Company to a $35.4 million maximum assessment per incident. The Company's payment of any such assessment would be limited to a maximum of $4.0 million per year. As a result of the permanent cessation of power operation of the Yankee Atomic, Connecticut Yankee, and Maine Yankee plants, these units have received from the NRC an exemption from participating in the secondary financial protection system under the Price-Anderson Act. However, these plants must continue to maintain $100 million of commercially available nuclear liability insurance coverage. Each of the nuclear units in which the Company has either an ownership or purchased power interest also carries nuclear property insurance to cover the costs of property damage, decontamination, and premature decommissioning resulting from a nuclear incident. These policies may require additional premium assessments if losses relating to nuclear incidents at units covered by this insurance occur in a prior six-year period. The Company's maximum potential exposure for these assessments, either directly or indirectly, is approximately $4.6 million with respect to the current policy period. 3. Plant Expenditures Utility plant expenditures for the Company and Montaup are estimated to be approximately $45 million in fiscal year 2001. 4. Hydro-Quebec Interconnection Three affiliates of the Company were created to construct and operate transmission facilities to transmit power from Hydro- Quebec to New England. Under support agreements entered into at the time these facilities were constructed, the Company agreed to guarantee a portion of the project debt. That portion (including Montaup's) at March 31, 2000, amounted to $24 million. 5. Hazardous Waste The Federal Comprehensive Environmental Response, Compensation and Liability Act, more commonly known as the "Superfund" law, imposes strict, joint and several liability, regardless of fault, for remediation of property contaminated with hazardous substances. A number of states, including Massachusetts, have enacted similar laws. The electric utility industry typically utilizes and/or generates in its operations a range of potentially hazardous products and by-products. The Company currently has in place an internal environmental audit program and an external waste disposal vendor audit and qualification program intended to enhance compliance with existing federal, state, and local requirements regarding the handling of potentially hazardous products and by-products. The Company has been named as a potentially responsible party (PRP) by either the United States Environmental Protection Agency or the Massachusetts Department of Environmental Protection for several sites at which hazardous waste is alleged to have been disposed. Private parties have also contacted or initiated legal proceedings against the Company regarding hazardous waste cleanup. The Company is currently aware of other possible hazardous waste sites, and may in the future become aware of additional sites that it may be held responsible for remediating. Predicting the potential costs to investigate and remediate hazardous waste sites continues to be difficult. There are also significant uncertainties as to the portion, if any, of the investigation and remediation costs of any particular hazardous waste site that may ultimately be borne by the Company. The Company has recovered amounts from certain insurers, and, where appropriate, intends to seek recovery from other insurers and from other PRPs, but it is uncertain whether, and to what extent, such efforts will be successful. The Company believes that the Company's hazardous waste liabilities for all sites of which the Company is aware are not material to its financial position. 6. Town of Norwood Dispute From 1983 until 1998, the Company was the wholesale power supplier for the Town of Norwood, Massachusetts (Norwood). In April 1998, Norwood began taking power from another supplier. Pursuant to a tariff amendment approved by the FERC in May 1998, the Company has been assessing Norwood a CTC. Through March 2000, the charges assessed Norwood amount to approximately $18 million, all of which remain unpaid. The Company has filed a collection action in Massachusetts Superior Court. Separately, Norwood filed suit in Federal District Court (District Court) in April 1997 alleging that the divestiture violated the terms of the 1983 power contract and contravened antitrust laws. The District Court dismissed the lawsuit. On appeal, the First Circuit Court of Appeals (First Circuit) consolidated appeals Norwood made from FERC's orders approving the divestiture, the wholesale rate settlement between the Company and its distribution affiliates, and the CTC tariff amendment. On February 2, 2000, the First Circuit dismissed Norwood's appeal from the FERC orders and dismissed its appeal from all but one of Norwood's District Court claims, which relates to alleged generation market power. On February 28, 2000 and March 3, 2000, respectively, the First Circuit denied Norwood's petition for further review of its District Court claims decision and its decision on the FERC orders. On May 30, 2000, Norwood petitioned the US Supreme Court for review of the First Circuit decisions. Norwood has also appealed a 1999 FERC decision that rejected Norwood's challenge to the calculation of the CTC based on the terms of the 1983 power contract. On June 12, 2000, Norwood moved to amend its complaint to reassert a claim for rescission with respect to the Company's divestiture. The Company has filed a motion to dismiss. Note E - Employee Benefits 1. Pension Plans: The Company participates with other subsidiaries of National Grid USA in noncontributory, defined-benefit plans covering substantially all employees of the Company. The plans provide pension benefits based on the employee's compensation during the five years prior to retirement. Absent unusual circumstances, the Company's funding policy is to contribute each year the net periodic pension cost for that year. 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. Net pension cost for the three months ended March 31, 2000 and the years ended December 31, 1999, 1998, and 1997 included the following components: Three Months Ended Year Ended March 31, December 31, - ---------------------------------------------------------------------------------------- (thousands of dollars) 2000 1999 1998 1997 - ---------------------------------------------------------------------------------------- Service cost - benefits earned during the period$ 118 $ 527$ 2,430$ 2,887 Plus (less): Interest cost on projected benefit obligation 1,760 7,044 7,435 7,003 Return on plan assets at expected long-term rate (2,200)(8,090)(8,675) (7,842) Amortization of transition obligation (33) (170) (184) (175) Amortization of prior service cost 24 115 161 171 Amortization of net (gain)/loss (100) 36 159 65 Curtailment (gain)/loss - - (5,680) - - ----------------------------------------------------------------------------------------- Benefit cost $ (431) $ (538)$(4,354) $ 2,109 - ----------------------------------------------------------------------------------------- Special termination benefits not included above $ - $ -$10,911$ - - ----------------------------------------------------------------------------------------- The funded status of the plans cannot be presented separately for the Company as the Company participates in the plans with other National Grid USA subsidiaries. The following table sets forth the funded status of the National Grid USA companies' plans: At At March 31, December 31, - --------------------------------------------------------------------------- (millions of dollars) 2000 1999 1998 - --------------------------------------------------------------------------- Benefit obligation $ 800 $ 789 $843 Unrecognized prior service costs - (5) (6) Transition liability not yet recognized (amortized) - (2) (2) Additional minimum liability - 6 7 - --------------------------------------------------------------------------- 800 788 842 - --------------------------------------------------------------------------- Plan assets at fair value 991 947 837 Transition asset not yet recognized (amortized) - (5) (6) Net (gain)/loss not yet recognized (amortized) - (206) (92) - --------------------------------------------------------------------------- 991 736 739 - --------------------------------------------------------------------------- Accrued (prepaid) pension benefits recorded on National Grid USA books $(191) $ 52 $103 - --------------------------------------------------------------------------- The following provides a reconciliation of benefit obligations and plan assets: At At March 31, December 31, - --------------------------------------------------------------------------- (millions of dollars) 2000 1999 1998 - --------------------------------------------------------------------------- Changes in benefit obligation: Benefit obligation at January 1 $789 $843 $819 Service cost 2 11 14 Interest cost 15 56 55 Actuarial (gain)/loss 10 (55) (5) Benefits paid (16) (66) (94) Special termination benefits - - 64 Curtailment - - (11) Plan amendments - - 1 - --------------------------------------------------------------------------- Benefit obligation end of period $800 $789 $843 - --------------------------------------------------------------------------- Reconciliation of change in plan assets: Fair value of plan assets at January 1 $947 $837 $834 Actual return on plan assets during year 59 117 93 Company contributions 1 59 4 Benefits paid from plan assets (16) (66) (94) - --------------------------------------------------------------------------- Fair value of plan assets end of period $991 $947 $837 - --------------------------------------------------------------------------- March 31, December 31, 2001 2000 1999 1998 1997 - ----------------------------------------------------------------------------- Assumptions used to determine pension cost: Discount rate 7.75% 7.75% 6.75% 6.75% 7.25% Average rate of increase in future compensation level 5.10% 5.10% 4.13% 4.13% 4.13% Expected long-term rate of return on assets 8.50% 8.50% 8.50% 8.50% 8.50% The plans' funded status at March 31, 2000 and December 31, 1999 and 1998 were calculated using the assumed rates from 2001, 2000, and 1999, respectively, and the 1983 Group Annuity Mortality table. Plan assets are composed primarily of equity and fixed income securities. Fair value adjustments of approximately $33 million are reflected in the Company's financial statements. 2. Postretirement Benefit Plans Other than Pensions (PBOPs): The Company provides 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. The Company's total cost of PBOPs for the three months ended March 31, 2000 and the years ended December 31, 1999, 1998, and 1997 included the following components: Three Months Ended Year Ended March 31, December 31, - ----------------------------------------------------------------------------------------- (thousands of dollars) 2000 1999 1998 1997 - ----------------------------------------------------------------------------------------- Service cost - benefits earned during the period $ 47 $ 193 $ 1,109 $ 1,363 Plus (less): Interest cost on projected benefit obligation 786 2,816 3,244 3,545 Return on plan assets at expected long-term rate (803) (2,896) (2,656) (2,343) Amortization of transition obligation 19 85 1,732 2,556 Amortization of prior service cost - - 5 8 Amortization of net (gain)/loss (285) (1,252) (1,138) (983) Curtailment (gain)/loss - - 27,149 - - ----------------------------------------------------------------------------------------- Benefit cost $(236) $(1,054)$29,445 $ 4,146 - ----------------------------------------------------------------------------------------- Special termination benefits not included above $ - $ - $ 439 $ - - ----------------------------------------------------------------------------------------- The following table sets forth the Company's benefits earned and the plans' funded status, including fair value adjustments recorded in the first quarter of 2000 of approximately $28 million: At At March 31, December 31, - ----------------------------------------------------------------------------- (millions of dollars) 2000 1999 1998 - ----------------------------------------------------------------------------- Benefit obligation $38 $ 42 $ 41 Unrecognized prior service costs - - - Transition liability not yet recognized (amortized) - (1) (1) - ----------------------------------------------------------------------------- 38 41 40 - ----------------------------------------------------------------------------- Plan assets at fair value 40 39 36 Net (gain)/loss not yet recognized (amortized) - (25) (26) - ----------------------------------------------------------------------------- 40 14 10 - ----------------------------------------------------------------------------- Accrued (prepaid) PBOPs recorded on books $(2) $ 27 $ 30 - ----------------------------------------------------------------------------- The following provides a reconciliation of benefit obligations and plan assets: At At March 31, December 31, - ----------------------------------------------------------------------------- (millions of dollars) 2000 1999 1998 - ----------------------------------------------------------------------------- Changes in benefit obligation: Benefit obligation at January 1 $42 $41 $ 51 Service cost - - 1 Interest cost 1 3 3 Actuarial (gain)/loss (4) - 2 Benefits paid (1) (2) (2) Special termination benefits - - - Curtailment - - (14) - ----------------------------------------------------------------------------- Benefit obligation end of year $38 $42 $ 41 - ----------------------------------------------------------------------------- Reconciliation of change in plan assets: Fair value of plan assets at January 1 $39 $36 $ 34 Actual return on plan assets during year 2 4 4 Company contributions - 1 - Benefits paid from plan assets (1) (2) (2) - ----------------------------------------------------------------------------- Fair value of plan assets end of year $40 $39 $ 36 - ----------------------------------------------------------------------------- March 31, December 31, 2001 2000 1999 1998 1997 - ---------------------------------------------------------------------------- Assumptions used to determine postretirement benefit cost: Discount rate 7.75% 7.75% 6.75% 6.75% 7.25% Expected long-term rate of return on assets 8.40% 8.42% 8.35% 8.27% 8.21% Health care cost rates: 1997 to 1999 5.25% 5.25% 8.00% 2000 8.25% 8.25% 5.25% 5.25% 6.25% 2001 6.75% 6.75% 5.25% 5.25% 6.25% 2002 to 2004 5.25% 5.25% 5.25% 5.25% 6.25% 2005 and beyond 5.25% 5.25% 5.25% 5.25% 5.25% The plans' funded status at March 31, 2000 and December 31, 1999 and 1998 were calculated using the assumed rates in effect for 2001, 2000, and 1999, respectively. The assumptions used in the health care cost trends have a significant effect on the amounts reported. A one percentage point change in the assumed rates would increase the accumulated postretirement benefit obligation (APBO) as of March 31, 2000 by approximately $4 million or decrease the APBO by approximately $4 million, and change the net periodic cost for fiscal year 2001 by approximately $100,000. The Company generally funds the annual tax-deductible contributions. Plan assets are invested in equity and fixed income securities and cash equivalents. 3. Early Retirement and Special Severance Programs: In 1998, the Company offered a voluntary early retirement program to all employees who were at least 55 years old with 10 years of service. This program was part of an organizational review with the goal of streamlining operations and reducing the work force to reflect industry restructuring. The early retirement offer was accepted by 104 employees. A special severance program was also utilized in 1998 for employees affected by the organizational restructuring, but who were not eligible for, or did not accept, the early retirement offer. The cost of these programs was in part reimbursed by the buyer at the closing of the divestiture and will be recovered in part from customers as a component of stranded cost recovery. Note F - Income Taxes The Company and other subsidiaries intend to elect to participate with National Grid General Partnership, National Grid USA's parent company that is wholly owned by National Grid, in filing a consolidated federal income tax return. The Company's income tax provision is calculated on a separate return basis. Federal income tax returns have been examined and reported on by the Internal Revenue Service through 1993. Total income taxes in the statements of income are as follows: Three Months Ended Year Ended March 31, December 31, (In thousands) 2000 1999 1999 1998 1997 (unaudited) - -------------------------------------------------------------------------------- Income taxes charged to operations $9,641$13,100$37,633$ 73,594$90,009 Income taxes charged (credited) to "Other income" (4) - 1,985 (19,582) (373) ----------------------------------- Total income taxes $9,637$13,100$39,618$ 54,012$89,636 =================================== Total income taxes, as shown above, consist of the following components: Three Months Ended Year Ended March 31, December 31, (In thousands) 2000 1999 1999 1998 1997 (unaudited) - -------------------------------------------------------------------------------- Current income taxes $12,545$ 7,374$ 25,507 $ 280,734 $102,364 Deferred income taxes (581)10,732 25,921(204,129)(10,705) Investment tax credits, net (2,327)(5,006)(11,810)(22,593) (2,023) ---------------------- --------- -------- Total income taxes $ 9,637$13,100$ 39,618 $ 54,012 $ 89,636 ====================== ========= ======== Investment tax credits (ITC) have been deferred and amortized over the estimated lives of the property giving rise to the credits. ITC amortization in 1999 reflects the accelerated amortization of the property giving rise to the credits, while the increase in amortization of ITC in 1998 compared with 1997 results from the recognition in income of unamortized ITC related to the generating assets divested during 1998. Total income taxes, as shown above, consist of federal and state components as follows: Three Months Ended Year Ended March 31, December 31, (In thousands) 2000 1999 1999 1998 1997 (unaudited) - -------------------------------------------------------------------------- Federal income taxes $8,035 $10,975 $33,746 $41,255 $73,077 State income taxes 1,602 2,125 5,872 12,757 16,559 ------ ------- ------- ------- ------- Total income taxes $9,637 $13,100 $39,618 $54,012 $89,636 ====== ======= ======= ======= ======= With regulatory approval from the FERC, the Company has adopted comprehensive interperiod tax allocation (normalization) for temporary book/tax differences. Total income taxes differ from the amounts computed by applying the federal statutory tax rates to income before taxes. The reasons for the differences are as follows: Three Months Ended Year Ended March 31, December 31, (In thousands) 2000 1999 1999 1998 1997 (unaudited) - ---------------------------------------------------------------------------- Computed tax at statutory rate $ 8,435 $11,706 $38,721 $ 61,917 $81,963 Increases (reductions) in tax resulting from: Amortization of investment tax credits (1,513) (3,254) (7,677) (15,157) (2,023) State income taxes, net of federal income tax benefit 1,042 1,381 3,817 8,292 10,763 Rate recovery of deficiency in deferred tax reserves 1,617 3,508 8,207 - - Prior year tax adjustment - - (2,028) (188) (313) All other differences 56 (241) (1,422) (852) (754) ------- ------- ------- -------- ------- Total income taxes $ 9,637 $13,100 $39,618 $ 54,012 $89,636 ======= ======= ======= ======== ======= The following table identifies the major components of total deferred income taxes: At March 31,At December 31, (In millions) 2000 1999 1998 - ----------------------------------------------------------------------------- Deferred tax asset: Plant related $ 67 $ 67 $ 76 Investment tax credits 6 8 13 All other 3 2 24 ----- ----- ----- 76 77 113 ----- ----- ----- Deferred tax liability: Plant related (159) (157) (53) All other, principally regulatory assets (93) (100) (225) ----- ----- ----- (252) (257) (278) ----- ----- ----- Net deferred tax liability $(176) $(180) $(165) ===== ===== ===== Note G - Short-term Borrowings and Other Accrued Expenses At March 31, 2000, the Company had $39 million of short-term debt outstanding. The Company has regulatory approval to issue up to $375 million of short-term debt. The Company plans to seek the necessary regulatory approvals in 2000 which would allow the $39 million of variable rate debt to remain outstanding through 2015. This would result in classifying the debt as long-term rather than short-term. National Grid USA and certain subsidiaries, including the Company, with regulatory approval, operate a money pool to more effectively utilize cash resources and to reduce outside short-term borrowings. Short-term borrowing needs are met first by available funds of the money pool participants. Borrowing companies pay interest at a rate designed to approximate the cost of outside short-term borrowings. Companies which 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. At March 31, 2000, the Company had lines of credit and standby bond purchase facilities with banks totaling $460 million which are available to provide liquidity support for $410 million of the Company's short-term and long-term bonds in tax-exempt commercial paper mode (including the $39 million discussed above), and for other corporate purposes. There were no borrowings under these lines of credit at March 31, 2000. Fees are paid on the lines and facilities in lieu of compensating balances. The components of other accrued expenses are as follows: At March 31, At December 31, (In thousands) 2000 1999 1998 - ----------------------------------------------------------------------------- Accrued wages and benefits $ 1,215 $ 1,063 $ 3,059 Rate adjustment mechanisms 9,110 14,550 16,781 Other 554 80 246 ------- ------- ------- $10,879 $15,693 $20,086 ------- ------- ------- Note H - Cumulative Preferred Stock A summary of cumulative preferred stock at March 31, 2000 and December 31, 1999 and 1998 is as follows (in thousands of dollars except for share data): Shares Dividends Outstanding Amount Declared - ------------------------------------------------------------------------------ 2000 1999 1998 2000 1999 1998 2000 1999 1998 - ------------------------------------------------------------------------------ $100 par value 6.00% Series 15,67215,672 15,672$1,567$1,567$1,567 $24 $94 $277 4.56% Series - - - - - - - - 247 4.60% Series - - - - - - - - 236 4.64% Series - - - - - - - - 98 6.08% Series - - - - - - - - 372 ------------------------------------------------------------------------------ Total 15,67215,672 15,672$1,567$1,567$1,567 $24 $94 $1,230 The 6.00% Series cumulative preferred stock is noncallable. The dividend requirement for cumulative preferred stock was $24,000 for the three months ended March 31, 2000, and the annual dividend requirement was $94,000 as of December 31, 1999. In 1998, the Company repurchased or redeemed preferred stock with an aggregate par value of $38 million. The preferred dividend requirement for 1998 was $1.2 million. There are no mandatory redemption provisions on the Company's cumulative preferred stock. Note I - Long-term Debt A summary of long-term debt is as follows: (In thousands) At March 31,At December 31, Series Rate % Maturity 2000 1999 1998 - ----------------------------------------------------------------------------- Pollution Control Revenue Bonds: MIFA 1 (a) variable March 1, 2018 $ 79,250 $ 79,250 $ 79,250 BFA 1 (b) variable November 1, 2020 135,850135,850 135,850 BFA 2 (b) variable November 1, 2020 50,600 50,600 50,600 MIFA 2 (a) variable October 1, 2022 106,150106,150 106,150 Unamortized discounts (77) (79) (85) -------- -------- -------- Total long-term debt $371,773 $371,771 $371,765 ======== ======== ======== <FN> (a) MIFA = Massachusetts Industrial Finance Authority (b) BFA = Business Finance Authority of the State of New Hampshire </FN> At March 31, 2000, interest rates on the Company's variable rate long-term bonds ranged from 3.45 percent to 3.95 percent. At March 31, 2000, the Company's long-term debt had a carrying value and fair value of approximately $372,000,000. The fair value of debt that reprices frequently at market rates approximates carrying value. Note J - Common Stock The purchase accounting method was used in National Grid's merger with National Grid USA, which resulted in a purchase accounting adjustment of approximately $16 million to the Company's retained earnings to reflect post merger net income. This also resulted in a reduction to the premium on capital stock of $49 million, a reduction in the unrealized gain on securities - net of $73,000, and an increase of $399 million in other paid-in-capital due to the push down of goodwill. The Company repurchased shares of its common stock in 1999 and 1998 as follows (dollar amounts expressed in thousands): Reductions to: --------------------------------------- Common stock Number of Cash and related Other paid- Retained Year Shares Paid premium in capital earnings - ---------------------------------------------------------------------------- 1999 130,000 $ 18,056 $ 4,348 $ 6,623 $ 7,085 1998 2,700,000 $417,960 $90,266 $133,876 $193,818 Note K - Supplementary Income Statement Information Advertising expenses, expenditures for research and development, and rents were not material and there were no royalties paid in the three months ended March 31, 2000, and March 31, 1999, and the years ended December 31, 1999, 1998, or 1997. Taxes, other than income taxes, charged to operating expenses are set forth by classes as follows: Three Months Ended Year Ended March 31, December 31, (In thousands) 2000 1999 1999 1998 1997 (unaudited) - -------------------------------------------------------------------------- Municipal property taxes $4,718 $4,618 $17,640 $42,080 $59,102 Federal and state payroll and other taxes 843 1,016 2,642 6,412 8,209 ------ ------ ------- ------- ------- $5,561 $5,634 $20,282 $48,492 $67,311 ====== ====== ======= ======= ======= New England Power Service Company, an affiliated service company operating pursuant to the provisions of Section 13 of the 1935 Act, furnished services to the Company at the cost of such services. These costs amounted to $11,514,000, $10,088,000, $43,584,000, $74,203,000, and $91,985,000, including capitalized construction costs of $4,597,000, $3,415,000, $17,229,000, $21,281,000, and $24,347,000, in the three months ended March 31, 2000, the three months ended March 31, 1999, and the years ended December 31, 1999, 1998, and 1997, respectively. New England Power Company Selected Financial Information Three Months Ended March 31, Year Ended December 31, (In millions) 2000 1999 1999 1998 1997 1996 1995 (unaudited) - -------------------------------------------------------------------------------------- Operating revenue $ 135 $ 167$ 596 $1,218 $1,678 $1,600 $1,571 Net income $ 14 $ 20$ 71 $ 123 $ 145 $ 152 $ 151 Total assets $2,630 $2,282$2,303 $2,415 $2,763 $2,648 $2,648 Capitalization: Common equity $ 657 $ 523$ 332 $ 521 $ 913 $ 906 $ 889 Cumulative preferred stock 1 1 2 1 40 40 61 Long-term debt 372 372 372 372 648 733 735 ------ ------------ ------ ------ ------ ------ Total capitalization $1,030 $ 896$ 706 $ 894 $1,601 $1,679 $1,685 Preferred dividends declared $ - $ -$ - $ 1 $ 2 $ 3 $ 3 Common dividends declared $ 24 $ -$ 241 $ 131 $ 135 $ 134 $ 135 ------ ------------ ------ ------ ------ ------ Selected Quarterly Financial Information (Unaudited) Three Months Ended First Second Third Fourth March 31, Quarter Quarter Quarter Quarter (In thousands) 2000 1999 1999 1999 1999 - ------------------------------------------------------------------------------------ Operating revenue $134,564 $167,177 $139,620 $142,066 $147,478 Operating income $ 16,319 $ 22,058 $ 13,796 $ 18,782 $ 23,927 Net income $ 14,462 $ 20,345 $ 14,254 $ 17,669 $ 18,746 First Second Third Fourth Quarter Quarter Quarter Quarter 1998 1998 1998 1998 -------------------------------------------- Operating revenue $401,147 $358,320 $321,569 $137,304 Operating income $ 48,740 $ 32,523 $ 54,647 $ 21,452 Net income $ 35,950 $ 20,425 $ 47,956 $ 18,564 Per share data is not relevant because the Company's common stock is wholly owned by National Grid USA, a wholly owned subsidiary of The National Grid Group plc.