SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-Q (X) QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the quarterly period ended March 31, 1999 OR ( ) TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 Commission File Number 1-6564 (LOGO) NEW ENGLAND POWER COMPANY (Exact name of registrant as specified in charter) MASSACHUSETTS 04-1663070 (State or other (I.R.S. Employer jurisdiction of Identification No.) incorporation or organization) 25 Research Drive, Westborough, Massachusetts 01582 (Address of principal executive offices) Registrant's telephone number, including area code (508-389-2000) Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes (X) No ( ) Common stock, par value $20 per share, authorized and outstanding: 3,619,896 shares at March 31, 1999. PART I FINANCIAL INFORMATION Item 1. Financial Statements - ---------------------------- NEW ENGLAND POWER COMPANY Statements of Income Periods Ended March 31 (Unaudited) Three Months Twelve Months ------------ ------------- 1999 1998 1999 1998 ---- ---- ---- ---- (In Thousands) Operating revenue, principally from affiliates $167,177 $401,147$ 984,370 $1,641,002 -------- -------- -------------------- Operating expenses: Fuel for generation 3,058 83,551 143,335 353,270 Purchased electric energy 57,984 122,485 335,335 505,787 Other operation 19,210 50,202 124,073 235,859 Maintenance 5,766 25,556 40,449 95,606 Depreciation and amortization 40,367 29,884 110,407 105,889 Taxes, other than income taxes 5,634 18,383 35,743 67,489 Income taxes 13,100 22,346 64,348 88,161 -------- -------- -------------------- Total operating expenses 145,119 352,407 853,690 1,452,061 -------- -------- -------------------- Operating income 22,058 48,740 130,680 188,941 Other income: Allowance for equity funds used during construction 588 - 1,221 - Equity in income of nuclear power companies 515 1,115 4,684 4,808 Other income (expense), net 434 (2,552) 3,104 (3,866) -------- -------- -------------------- Operating and other income 23,595 47,303 139,689 189,883 -------- -------- -------------------- Interest: Interest on long-term debt 3,143 9,723 24,195 41,168 Other interest 240 1,914 9,014 7,319 Allowance for borrowed funds used during construction - credit (133) (284) (810) (1,152) -------- -------- -------------------- Total interest 3,250 11,353 32,399 47,335 -------- -------- -------------------- Net income $ 20,345 $ 35,950 $ 107,290$ 142,548 ======== ======== ==================== Statements of Retained Earnings (In Thousands) Retained earnings at beginning of period $204,603 $407,630 $ 443,061 $ 409,011 Net income 20,345 35,950 107,290 142,548 Dividends declared on cumulative preferred stock (24) (519) (735) (2,075) Dividends declared on common stock - - (130,610) (106,423) Premium on redemption of preferred stock - - (264) - Repurchase of common stock (7,085) - (200,903) - -------- -------- --------- --------- Retained earnings at end of period $217,839 $443,061 $ 217,839 $ 443,061 ======== ======== ========= ========= The accompanying notes are an integral part of these financial statements. Per share data is not relevant because the Company's common stock is wholly owned by New England Electric System. NEW ENGLAND POWER COMPANY Balance Sheets (Unaudited) March 31, December 31, ASSETS 1999 1998 ------ ---- ---- (In Thousands) Utility plant, at original cost $1,259,435 $1,262,461 Less accumulated provisions for depreciation and amortization 838,380 837,637 ---------- ---------- 421,055 424,824 Construction work in progress 46,189 33,289 ---------- ---------- Net utility plant 467,244 458,113 ---------- ---------- Investments: Nuclear power companies, at equity 47,323 48,538 Nonutility property and other investments 39,640 39,583 ---------- ---------- Total investments 86,963 88,121 ---------- ---------- Current assets: Cash and temporary cash investments (including $82,583,000 and $109,911,000 with affiliates) 165,981 179,413 Accounts receivable: Affiliated companies 77,874 107,878 Others 24,687 32,573 Fuel, materials, and supplies, at average cost 8,572 9,220 Prepaid and other current assets 15,415 21,569 ---------- ---------- Total current assets 292,529 350,653 ---------- ---------- Regulatory assets 1,429,761 1,512,562 Deferred charges and other assets 5,593 5,339 ---------- ---------- $2,282,090 $2,414,788 ========== ========== CAPITALIZATION AND LIABILITIES ------------------------------ Capitalization: Common stock, par value $20 per share, Authorized - 6,449,896 shares Outstanding - 3,619,896 and 3,749,896 shares $ 72,398 $ 74,998 Premiums on capital stocks 48,624 50,371 Other paid-in capital 184,229 190,852 Retained earnings 217,839 204,603 Unrealized gain on securities, net 73 72 ---------- ---------- Total common equity 523,163 520,896 Cumulative preferred stock, par value $100 per share 1,567 1,567 Long-term debt 371,767 371,765 ---------- ---------- Total capitalization 896,497 894,228 ---------- ---------- Current liabilities: Accounts payable (including $47,741,000 and $119,657,000 to affiliates) 80,410 162,360 Accrued liabilities: Taxes 5,619 15,009 Interest 3,272 2,440 Other accrued expenses 17,497 20,086 Dividends payable 24 24 ---------- ---------- Total current liabilities 106,822 199,919 ---------- ---------- Deferred federal and state income taxes 170,815 165,115 Unamortized investment tax credits 25,864 30,870 Accrued Yankee nuclear plant costs 232,770 242,138 Purchased power obligations 795,765 832,668 Other reserves and deferred credits 53,557 49,850 ---------- ---------- $2,282,090 $2,414,788 ========== ========== The accompanying notes are an integral part of these financial statements. NEW ENGLAND POWER COMPANY Statements of Cash Flows Quarters Ended March 31 (Unaudited) 1999 1998 ---- ---- (In Thousands) Operating activities: Net income $ 20,345 $ 35,950 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation and amortization 42,170 30,629 Deferred income taxes and investment tax credits, net 5,726 42,358 Allowance for funds used during construction (720) (284) Reimbursement to New England Energy Incorporated of loss on sale of oil and gas properties - (120,900) Decrease (increase) in accounts receivable, net 37,890 12,099 Decrease (increase) in fuel, materials, and supplies 648 (11,637) Decrease (increase) in prepaid and other current assets 6,154 (3,816) Increase (decrease) in accounts payable (81,950) 24,009 Increase (decrease) in other current liabilities (11,147) 18,045 Other, net (709) 4,873 -------- -------- Net cash provided by (used in) operating activities$ 18,407 $ 31,326 -------- -------- Investing activities: Plant expenditures, excluding allowance for funds used during construction $(13,739) $(16,451) Other investing activities (20) (411) -------- -------- Net cash provided by (used in) investing activities$(13,759) $(16,862) -------- -------- Financing activities: Dividends paid on common stock $ - $(35,474) Dividends paid on preferred stock (24) (519) Changes in short-term debt - 71,025 Long-term debt - retirements - (50,000) Repurchase of common shares (18,056) - -------- -------- Net cash provided by (used in) financing activities$(18,080) $(14,968) -------- -------- Net increase (decrease) in cash and cash equivalents $(13,432) $ (504) Cash and cash equivalents at beginning of period 179,413 1,643 -------- -------- Cash and cash equivalents at end of period $165,981 $ 1,139 ======== ======== The accompanying notes are an integral part of these financial statements. NEW ENGLAND POWER COMPANY Notes to Unaudited Financial Statements Note A - 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. New England Power Company (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 six 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 they 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 New England Electric System (NEES) companies have recovered amounts from certain insurers, and, where appropriate, intend 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 hazardous waste liabilities for all sites of which it is aware are not material to its financial position. Note B - Nuclear Units - ---------------------- Yankee Nuclear Power Companies (Yankees) 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 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: Quarter Ended March 31, --------------- 1999 1998 ---- ---- (In thousands) Operating revenue $89,244 $122,615 ======= ======== Net income $ 5,138 $ 7,351 ======= ======== Company's equity in net income $ 515 $ 1,115 ======= ======== March 31, December 31, 1999 1998 ---- ---- (In thousands) Net plant $ 166,062 $ 171,582 Other assets 2,798,948 2,810,613 Liabilities and debt (2,707,749) (2,723,454) ----------- ----------- Net assets $ 257,261 $ 258,741 =========== =========== Company's equity in net assets $ 47,323 $ 48,538 =========== =========== At March 31, 1999, $13,380,000 of undistributed earnings of the nuclear power companies were included in the Company's retained earnings. 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 are as follows: Future Estimated NEP's Billings Investment Date to NEP Unit % $ (millions) Retired $(millions) - ----------------------------------------------------------------- Yankee Atomic 30 5 Feb 1992 21 Connecticut Yankee 15 16 Dec 1996 72 Maine Yankee 20 16 Aug 1997 139 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 Federal Energy Regulatory Commission (FERC) allowed Yankee Atomic to recover its undepreciated investment in the plant as well as unfunded nuclear decommissioning costs and other costs. Connecticut Yankee and Maine Yankee have both filed similar requests with the FERC. Several parties have intervened in opposition to both filings. 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 have 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 of the loss of the return component would total approximately $12 million to $15 million before taxes. In January 1999, parties in the Maine Yankee proceeding filed a comprehensive settlement agreement with the FERC, under which Maine Yankee would recover all unamortized investment in the plant, including a return on its equity investment of 6.5 percent, as well as decommissioning costs and other costs. This settlement agreement requires FERC approval. The Company's industry restructuring settlements allow it to recover all costs that the FERC allows these Yankee companies to bill to the Company. The Company and several other shareholders (Sponsors) of Maine Yankee are parties to 27 contracts (Secondary Purchase Agreements) under which they sold portions of their entitlements to Maine Yankee power output through 2002 to various entities, primarily municipal and cooperative systems in New England (Secondary Purchasers). Virtually all of the Secondary Purchasers had ceased making payments under the Secondary Purchase Agreements, claiming that such agreements excuse further payments upon plant shutdown. In February 1999, a settlement agreement which fully resolves the dispute between the Sponsors and Secondary Purchasers was filed with the FERC, under which the Secondary Purchasers would be required to make certain payments to Maine Yankee, and, in turn, to the Company, related to both past and future obligations under the Secondary Purchase Agreements. This settlement agreement requires FERC approval. Shutdown costs are recoverable from customers under the Settlement Agreements. 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. Operating Nuclear Units The Company has minority interests in three other nuclear generating units: Vermont Yankee, Millstone 3, and Seabrook 1. Uncertainties regarding the future of nuclear generating stations, particularly older units, such as Vermont Yankee, are increasing rapidly 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. Nuclear Divestiture The Company is engaged in efforts to divest its interests in the three operating nuclear units mentioned above. On February 25, 1999, the Board of Directors of Vermont Yankee Nuclear Power Corporation granted an exclusive right to AmerGen Energy Company (AmerGen), a joint venture by PECO Energy and British Energy to conduct a due diligence review over the next 120 days and negotiate a possible agreement to purchase the assets of Vermont Yankee. Provided the due diligence review leads to successful completion of negotiations for a sale, consummation of such a sale would be contingent on regulatory approvals by the NRC, the Securities and Exchange Commission, under the Public Utility Holding Company Act of 1935, and the Vermont Public Service Board, among others. The regulatory process could take eight to twelve months or longer. In past negotiations for the sale of nuclear plants, due diligence review has not guaranteed that a sale will occur. The Company has a 20 percent ownership interest in Vermont Yankee and an investment of approximately $11 million at March 31, 1999. Millstone 3 In July 1998, Millstone 3 returned to full operation after being shut down since April 1996. In April 1999, the NRC eliminated its "Watch List" designation process and has implemented a process that categorizes plants as requiring one of three levels of attention: "agency focus", calling for the attention of the Executive Director for Operations and/or the Commission; "regional focus", calling for special attention from the appropriate Regional Administrator; and "routine focus", calling for normal everyday oversight. Millstone 3 has been categorized as the subject of regional focus. Millstone 3 is operated by a subsidiary of Northeast Utilities (NU). A criminal investigation related to Millstone 3 is ongoing. In August 1997, the Company sued NU in Massachusetts Superior Court for damages resulting from the tortious conduct of NU that caused the shutdown of Millstone 3. The Company's damages include 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 settlement agreements approved by state and federal regulators in 1998 (Settlement Agreements). The Company also seeks punitive damages. The Company also sent a demand for arbitration to Connecticut Light & Power Company and Western Massachusetts Electric Company, both subsidiaries of NU, seeking damages resulting from their breach of obligations under an agreement with the Company and others regarding the operation and ownership of Millstone 3. The arbitration is scheduled for October 1999. In July 1998, the court denied NU's motion to dismiss and its motion to stay pending arbitration. The Company subsequently amended its complaint by, among other things, adding NU's Trustees as defendants. In December 1998, NU moved for summary judgement. The Company's suit has been consolidated with suits filed by other joint owners. The court is in the process of scheduling a trial date. Some or all of the damages awarded from the lawsuit would be refunded to customers. 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 through 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 recently enacted 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 12 percent share of Seabrook 1 has no franchise service territory. The New Hampshire Nuclear Decommissioning Finance Committee is reviewing Seabrook Station's decommissioning estimate and associated annual funding levels. Among the items being considered is the imposition of joint and several liability among the Seabrook joint owners for decommissioning funding. The Company cannot predict what additional liability, if any, may be imposed on it. The Nuclear Waste Policy Act of 1982 establishes that the federal government (through the Department of Energy (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 contract termination charges (CTC). Similar costs are billed to the Company by Vermont Yankee and also recovered from customers through the same mechanism. In November 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 (the Appeals Court) held that the DOE was obligated to begin disposing of utilities' spent nuclear fuel by January 31, 1998. The DOE failed to meet this deadline, and is not expected to have a temporary or permanent repository for spent nuclear fuel for many years. In February 1998, Maine Yankee petitioned the Appeals Court to compel the DOE to remove Maine Yankee's spent fuel from the site. In May 1998, the Appeals Court rejected the petitions of Maine Yankee and the other utilities and state regulatory commissions, stating that the issue of damages was a contractual matter. The operators of the units in which the Company has an obligation, including Maine Yankee, Connecticut Yankee, and Yankee Atomic, continue to pursue damage claims against the DOE in the Federal Court of Claims (Claims Court). In October 1998, the Claims Court ruled that the DOE violated a commitment to remove spent fuel from Yankee Atomic. The Claims Court issued similar rulings in November 1998 related to cases brought by Connecticut Yankee and Maine Yankee. Further proceedings will be scheduled by the Claims Court to decide the amount of damages. On April 6, 1999, a federal judge with the Claims Court dismissed a lawsuit brought by Northern States Power Company seeking damage payments resulting from the DOE's failure to remove spent fuel from nuclear power plants. It is unclear at this time what effect, if any, this ruling will have on the independent separate lawsuits brought by Yankee Atomic, Maine Yankee, and Connecticut Yankee. Note C - Town of Norwood Dispute - -------------------------------- In September 1998, the United States District Court (District Court) for the District of Massachusetts dismissed the lawsuit filed in April 1997 by the Town of Norwood, Massachusetts against NEES and the Company. The Company had been a wholesale power supplier for Norwood pursuant to rates approved by the FERC. In the lawsuit, Norwood had alleged that the Company's divestiture of its power generating assets would violate the terms of a 1983 power contract. Norwood also alleged that the divestiture and recovery of stranded investment costs contravened federal antitrust laws. The District Court judge granted NEES' and the Company's motion for dismissal on the grounds that the contract did not require the Company to retain its generating units, that the FERC-approved filed rates govern these matters, and that Norwood had adequate opportunity at the FERC to litigate these matters. Norwood filed a motion to alter or amend the order of dismissal, which was denied. In December 1998, Norwood filed a second motion to amend judgement and also filed an appeal with the First Circuit Court of Appeals (First Circuit). In March 1999, the District Court denied Norwood's second motion to amend judgement. In March 1998, Norwood gave notice of its intent to terminate its contract with the Company, without accepting responsibility for its share of the Company's stranded costs, and began taking power from another supplier commencing in April 1998. In May 1998, the FERC ruled that the Company could assess a CTC to any of the Company's unaffiliated customers that choose to terminate their wholesale power contracts early. Norwood claimed that the CTC approved by the FERC did not apply to Norwood; however, in denying Norwood's motion for rehearing, the FERC ruled that the charge did apply to Norwood. Norwood has appealed this decision to the First Circuit. The Company's billings to Norwood for this charge through March 1999 have been approximately $7 million, which remain unpaid. The Company filed a collection action with the Massachusetts Superior Court in December 1998 to recover these amounts. Norwood filed a motion to dismiss or stay in January 1999, which has been denied. Norwood also appealed the FERC's orders approving the divestiture and the Massachusetts and Rhode Island industry restructuring settlement agreements (including modification of the Company's contracts with Massachusetts Electric Company and The Narragansett Electric Company) to the First Circuit, despite the FERC's finding that those settlement agreements do not apply to Norwood. The First Circuit has consolidated all three of Norwood's appeals from the FERC's orders with two other appeals filed by the Northeast Center for Social Issue Studies, which challenge the FERC's approval of the Company's sale of its hydroelectric facilities. The case is expected to be fully briefed by July 1999. Note D - New Accounting Standards - --------------------------------- In June 1998, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities (FAS 133), which establishes accounting and reporting standards for such instruments. FAS 133 is effective for fiscal years beginning after June 15, 1999. Currently, the Company has no such holdings. Note E - ------ In the opinion of the Company, these financial statements reflect all adjustments (which include normal recurring adjustments) necessary for a fair statement of the results of its operations for the periods presented and should be considered in conjunction with the notes to the financial statements in the Company's 1998 Annual Report. NEW ENGLAND POWER COMPANY Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations - ----------------------------------------------------------------- This section contains management's assessment of New England Power Company's (the Company) financial condition and the principal factors having an impact on the results of operations. This discussion should be read in conjunction with the Company's financial statements and footnotes and the 1998 Annual Report on Form 10-K. Merger Agreements - ----------------- For a full discussion of New England Electric Systems' (NEES) merger agreements with The National Grid Group plc (National Grid) and Eastern Utilities Associates (EUA), see the Merger Agreements sections of the Company's Form 10-K for 1998 and the Company's 1998 Annual Report. Update of Merger Agreements with National Grid and EUA On April 9, 1999, NEES and National Grid received clearance under the Hart-Scott-Rodino (HSR) Antitrust Improvements Act of 1976, as amended. In addition, shareholders of National Grid approved the proposed merger on April 22, 1999 with 99 percent of those voting approving the merger. On May 3, 1999, NEES received the approval of more than the required majority of outstanding shares for the merger with 75 percent of outstanding shares voting in favor of the merger. Of those shares voted, in excess of 94 percent voted in favor of the merger. NEES and National Grid have also filed for merger approval with the Securities and Exchange Commission (SEC), Federal Energy Regulatory Commission (FERC), and Nuclear Regulatory Commission (NRC). NEES and National Grid have also made filings in the states in which NEES subsidiaries operate where support or approval for the merger is required. On April 21, 1999, the New Hampshire Public Utilities Commission (NHPUC) issued an order finding that the NEES/National Grid merger filing did not satisfy the requirements for exemption from the NHPUC's formal review process. Hearings on the merger are scheduled for June 1999. On April 29, 1999, the Committee on Foreign Investment in the United States under the Exon-Florio Provisions of the Omnibus Trade and Competitiveness Act of 1988 concluded there were no issues of national security to warrant any investigation. The NEES/National Grid merger is expected to be completed by early 2000. On April 29, 1999, NEES and EUA also received clearance under HSR for the NEES acquisition of EUA. NEES and EUA have filed for merger approval with the FERC and the Commonwealth of Massachusetts. The acquisition of EUA also requires approval by the SEC and NRC, and approval by certain states in which EUA subsidiaries operate. On May 17, 1999, EUA shareholders approved the acquisition of EUA by NEES. The acquisition of EUA is expected to be completed by early 2000. Industry Restructuring - ---------------------- For a full discussion of industry restructuring activities, the Company's divestiture of its nonnuclear generating business and stranded cost recovery, see the "Industry Restructuring" section of the Company's Form 10-K for 1998 and the Company's 1998 Annual Report. Regulatory Asset Recovery - ------------------------- Historically, electric utility rates have been based on a utility's costs. As a result, electric utilities are subject to certain accounting standards that are not applicable to other business enterprises in general. Statement of Financial Accounting Standards No. 71, Accounting for the Effects of Certain Types of Regulation (FAS 71), requires regulated entities, in appropriate circumstances, to establish regulatory assets, and thereby defer the income statement impact of these charges because they are expected to be included in future customer charges. In 1997, the Emerging Issues Task Force (EITF) of the Federal Accounting Standards Board concluded that a utility that had received approval to recover stranded costs through regulated transmission and distribution rates would be permitted to continue to apply FAS 71 to the recovery of stranded costs. The Company has received authorization from the Federal Energy Regulatory Commission (FERC) to recover through contract termination charges (CTC) substantially all of the costs associated with its former generating business not recovered through the sale of that business. 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. The Company believes these factors and the EITF conclusion allow it to continue to apply FAS 71. 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. The regulatory asset reflects the loss on the sale of NEES' oil and gas business and the unrecovered plant costs in operating nuclear plants (assuming no market value), the costs associated with permanently closed nuclear power plants, and the present value of the payments associated with the above-market cost of purchased power contracts, reduced by the gain from the sale of the nonnuclear generating business. At March 31, 1999, the regulatory asset related to the CTC was approximately $1.4 billion, of which $1.1 billion related to the above-market costs of purchased power contracts. Currently, there is much regulatory and other movement toward establishing performance-based rates. It is possible that the adoption of performance-based rates for the Company or its affiliates, future regulatory rules, or other circumstances could cause the application of FAS 71 to be discontinued. Absent the circumstances described in the next paragraph, this discontinuation would result in a noncash write-off of previously established regulatory assets, including those being recovered through the Company's CTC. In April 1999, Massachusetts Electric Company, (Massachusetts Electric), a distribution affiliate, filed a rate plan which, if approved, may cause the application of FAS 71 to be discontinued upon consummation of the NEES/National Grid merger. The Company is recovering its stranded costs as a component of Massachusetts Electric's distribution rates. As a result, the Company may not be able to continue to apply FAS 71 to its recovery of stranded costs after the merger is completed. Because the discontinuation of FAS 71 would be coincident with the completion of the NEES/National Grid merger, the regulatory assets would not be written off but instead would be reclassified to either an intangible asset account or a goodwill account. Year 2000 Readiness Disclosure - ------------------------------ Over the course of this year, most companies will face a potentially serious information systems (computer) problem because many software applications and operational programs written in the past may not properly recognize calendar dates associated with the year 2000 (Y2K). This could cause computers to either shut down or lead to incorrect calculations. During 1996, the NEES companies began the process of identifying the changes required to their computer software and hardware to mitigate Y2K issues. The NEES companies established a Y2K Project team to manage these issues, which has consisted of as many as 70 full-time equivalent staff at some points in time, primarily external consultants being overseen by an internal Y2K management team. To facilitate the Y2K Project, NEES entered into contracts with Keane, Inc. and IBM to provide personnel support to the Y2K Project. Through March 31, 1999, the NEES companies have spent approximately $17 million with these vendors, which is included in the cost figures disclosed below. The Y2K Project team reports project progress to a Y2K Executive Oversight Committee each month. The team also makes regular reports to NEES' Board of Directors and its Audit Committee. The NEES companies have separated their Y2K Project into four parts as shown below, along with the estimated completion dates for each part. Substantial Contingency Testing Completion Documentation, of Critical and Clean Category Specific Example Systems Management - -------- ---------------- ----------- ------------------- Mainframe/Midrange Accounting/Customer Completed Throughout 1999 systems service integrated systems Desktop systems Personal computers/ June 30, 1999 Throughout 1999 Department software/ Networks Operational/ Dispatching systems/ June 30, 1999 Throughout 1999 Embedded Transmission and systems Distribution systems/ Telephone systems External issues Electronic Data June 30, 1999 Throughout 1999 Interchange/Vendor communications The NEES companies are using a three-phase approach in coordinating their Y2K Project for system-related issues: (I) Assessment and Inventory, (II) Pilot Testing, and (III) Renovation, Conversion, or Replacement of Application and Operating Software Packages and Testing. Phase I, which was an initial assessment of all systems and devices for potential Y2K defects, was completed in mid-1997. These assessments included, but were not limited to, the review of program code for mainframe and midrange systems, analysis of personal computer hardware and network equipment for desktop systems, reaching consensus with key "data exchange" partners regarding the approach and execution of plans to address Y2K- related issues, and coordination with other New England Power Pool (NEPOOL) member utilities related to operational systems, such as transmission systems. Phase II, which consisted of renovation pilots for a cross-section of systems in order to facilitate the establishment of templates for Phase III work, was completed in late 1997. Phase III, which is currently ongoing, requires the renovation, conversion, or replacement of the remaining applications and operating software packages. Critical systems include major operational and informational systems such as the NEES companies' financial-related and customer information systems. These mission critical systems were first addressed at an individual component level, and then, upon satisfactory completion of that testing, reviewed at an integrated level, during which the Y2K Project team tested for Y2K problems which could be caused by various system interfaces. Additionally, contingency plans are being formulated for mission critical systems, as described below. The overall Y2K Project has also been designed such that Y2K- related work performed by external consultants is reviewed by NEES employees, and vice-versa. The Y2K Project team management periodically benchmarks its progress against the recommended progress schedule documented by the North American Electric Reliability Council (NERC), and is currently ahead of the recommended schedule. The NEES companies have also implemented a formalized communication process with third parties to give and receive information related to their progress in remediating their own Y2K issues, and to communicate the NEES companies' progress in addressing the Y2K issue. These third parties include major customers, suppliers, and significant businesses with which the NEES companies have data links (such as banks). The NEES companies have identified standard offer generation service providers, telecommunications companies, and the Independent System Operator- New England (ISO New England) as critical to business operations. The NEES companies have been in contact with all of these parties regarding the progress of their Y2K remediation efforts, and will continue to monitor their ongoing remediation efforts through continued communications. The NEES companies cannot predict the outcome of other companies' remediation efforts. Therefore, contingency plans are being developed, as described below. The NEES companies believe total costs associated with making the necessary modifications to all centralized and noncentralized systems will be approximately $28 million. These costs include the replacement of approximately one thousand desktop computers. In addition, the NEES companies are spending $7 million related to the replacement of the human resources and payroll system, in part due to the Y2K issue. As of March 31, 1999, total Y2K-related costs of approximately $30 million have been incurred, of which approximately $4 million has been capitalized. The NEES companies continually review their cost estimates based upon the overall Y2K Project status, and update these estimates as warranted. The NEES companies are in the process of developing Y2K contingency plans to allow for critical information and operating systems to function from January 1, 2000 forward. If required, these plans are intended to address both internal risks as well as potential external risks related to suppliers and customers. Part of the contingency planning for accounting and desktop systems will include taking extensive data back-ups prior to year-end closing. For operational systems, the NEES companies have in place an overall disaster recovery program, which already includes periodic disaster simulation training (for outages due to severe weather, for instance). As part of Y2K contingency planning, the NEES companies will review their disaster recovery plans, modifying them for Y2K-specific issues, such as a potential loss of telecommunication services. The NEES companies expect that these contingency plans will be in place by the third quarter of 1999. Interregional and regional contingency plans are being formulated that address emergency scenarios due to the interconnection of utility systems throughout the United States. At a regional level, the NEES companies are participating and cooperating with NEPOOL and ISO New England. Overall regional activities, including those of NEPOOL and ISO New England, will be coordinated by the Northeast Power Coordinating Council, whose activities will be incorporated into the interregional coordinating effort by NERC. The target for the completion of this planning process is mid-1999. The NEES companies have noted that the Y2K coordination efforts by ISO New England began in May 1998, resulting in a demanding and difficult schedule to attain regional and interregional target dates. The NEES companies believe that the contingency plans being developed both internally and on a regional level should substantially mitigate the risks of Y2K-related failures at NEES company facilities or those caused by the inability of entities, such as ISO New England, to maintain the short-term reliability of various generator and/or transmission lines on a regional or interregional basis. Such risks include temporary disruptions of electric service, which the NEES companies believe is the worst case Y2K scenario with a reasonable chance of occurring. In the event that a short-term disruption in service occurs, NEES does not expect that it would have a material impact on its financial position or results of operation. While the NEES companies believe that their overall Y2K program will satisfactorily address all critical operational and system-related issues, significant risks remain. These risks include, but are not limited to, the Y2K readiness of third parties, including other utilities, power suppliers, and ISO New England, cost and timeline estimates of remaining Y2K mitigation efforts, and the overall accuracy of assumptions made related to future events in the development of the Y2K mitigation effort. Earnings - -------- Net income for the first quarter of 1999 decreased $16 million compared with the corresponding period in 1998. The decrease in earnings reflects the continuing impact of the restructuring of the utility business and the effect of the divestiture of the Company's nonnuclear generating business on September 1, 1998. Partially offsetting this revenue decrease is an increase in transmission billings, including the elimination of $5 million of certain liabilities related to open access transmission tariffs and the recovery of the Company's stranded investment costs including mitigation incentives. The mitigation incentives recorded in the first quarter amounted to approximately $6 million. Operating Revenue - ----------------- Operating revenue decreased $234 million in the first quarter of 1999 compared with the corresponding period in 1998. Industry restructuring continues to have a negative impact on revenues. Rate reductions were implemented upon the commencement of providing customer choice of electric supplier. These initial rate reductions commenced for all customers in Rhode Island, Massachusetts, and New Hampshire on January 1, March 1, and July 1, 1998, respectively. Further rate reductions were provided to customers following the sale of the Company's nonnuclear generating business on September 1, 1998. These rate reductions also include the effect of various true-up mechanisms, including stranded cost recovery billings, fuel expense, nuclear operating costs and decommissioning costs, and the non-fuel component of purchased power expense. Partially offsetting this revenue decrease is an increase in transmission billings, the elimination of certain liabilities related to open access transmission tariffs, and the ability of the Company to recover its stranded investments from the affiliated wholesale customers through CTCs. The CTC rate was originally set at 2.8 cents per kilowatthour (kWh), and subsequently reduced to approximately 1.5 cents or less per kWh upon the sale of the Company's nonnuclear generating business. Operating Expenses - ------------------ Operating expenses for the first quarter of 1999 decreased $207 million compared with the corresponding period in 1998. The September 1, 1998 sale of the Company's nonnuclear generating business had the impact of decreasing all categories of operating expenses other than depreciation and amortization. The decrease in operating expenses also reflects reduced charges from both the Maine Yankee nuclear power plant and the Vermont Yankee nuclear power plant, which experienced a refueling shutdown beginning in March 1998. In addition to the impact of the sale, the decrease in other operation and maintenance expenses reflects reduced general and administrative costs primarily due to workforce reductions and reduced transmission billings to the Company. In conjunction with industry restructuring, NEPOOL transmission costs are billed directly to the Company's distribution affiliates. Reduced charges of approximately $2 million from the partially owned Millstone 3 nuclear generating facility also contributed to the decrease in operation and maintenance expenses. Depreciation and amortization expenses increased during the first quarter primarily due to the recovery and amortization of generation-related stranded costs in 1999 being greater than depreciation and amortization of generation-related plant in 1998. Interest Expense and Other Income - --------------------------------- The decrease in interest expense is due principally to reduced interest on long-term debt as a result of the defeasement of debt in conjunction with the sale of the Company's nonnuclear generating business. The increase in other income during the first quarter is primarily due to increased interest income as a result of the reinvestment of the proceeds from the September 1, 1998 sale. Utility Plant Expenditures and Financing - ---------------------------------------- Cash expenditures for utility plant totaled $14 million for the first three months of 1999. These expenditures were primarily transmission-related. The funds necessary for utility plant expenditures during the period were primarily provided by internally generated funds. On February 8, 1999, the Company repurchased 130,000 shares of its common stock from NEES for $18 million. Approximately $7 million in connection with the repurchase was charged to retained earnings. At March 31, 1999, the Company had lines of credit and standby bond purchase facilities with banks totaling $445 million which are available to provide liquidity support for $372 million of the Company's bonds in tax-exempt commercial paper mode and for other corporate purposes. There were no borrowings under these lines of credit at March 31, 1999. PART II. OTHER INFORMATION Item 1. Legal Proceedings - -------------------------- Information concerning a lawsuit brought by the Company against Northeast Utilities on August 7, 1997 in Massachusetts Superior Court, Worcester County concerning the Millstone 3 nuclear unit, discussed in this report in Note B of Notes to Unaudited Financial Statements, is incorporated herein and made a part hereof. Information concerning a demand for arbitration sent by the Company to Connecticut Light & Power Company and Western Massachusetts Electric Company concerning the Millstone 3 nuclear unit, discussed in this report in Note B of Notes to Unaudited Financial Statements, is incorporated herein and made a part hereof. Information concerning a settlement agreement between the Company and secondary purchasers of Maine Yankee power output, discussed in this report in Note B of Notes to Unaudited Financial Statements, is incorporated herein and made a part hereof. Information concerning dismissal of a lawsuit brought against the Company by the Town of Norwood, Massachusetts and appeals of that lawsuit and related Federal Energy Regulatory Commission orders, and the Company's collection action, discussed in this report in Note C of Notes to Unaudited Financial Statements, is incorporated herein and made a part hereof. Item 6. Exhibits and Reports on Form 8-K - ----------------------------------------- The Company is filing Financial Data Schedules. The Company filed a report on Form 8-K dated February 1, 1999 containing Items 5 and 7. SIGNATURE Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report on Form 10-Q for the quarter ended March 31, 1999 to be signed on its behalf by the undersigned thereunto duly authorized. NEW ENGLAND POWER COMPANY s/John G. Cochrane John G. Cochrane, Treasurer, Authorized Officer, and Principal Financial Officer Date: May 17, 1999