10-Q 1 third10q.txt 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 September 30, 2001 OR ( ) TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 Commission File Number 1-6564 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 September 30, 2001. PART I FINANCIAL INFORMATION Item 1. Financial Statements -------------------------------------- NEW ENGLAND POWER COMPANY Statements of Income Periods Ended September 30 (In thousands) (Unaudited)
Quarter Six Months ---------- -------------- 2001 2000 2001 2000 ------- ------- ------- ------- Operating revenue, principally from affiliates $147,151 $175,390 $ 292,167 $331,580 ------------ ------------ ------------ ------------ Operating expenses: Fuel for generation 1,699 4,296 2,755 7,882 Purchased electric energy: Contract termination and nuclear unit shutdown charges 56,584 55,812 115,039 111,520 Other 19,476 22,224 40,770 41,636 Other operation 12,764 17,856 26,599 32,506 Maintenance 5,691 5,862 9,608 10,686 Depreciation and amortization 7,637 22,480 15,363 43,247 Taxes, other than income taxes 4,637 5,894 9,377 11,697 Income taxes 13,601 15,734 24,760 26,929 ------------ ------------ ------------ ------------ Total operating expenses 122,089 150,158 244,271 286,103 ------------ ------------ ------------ ------------ Operating income 25,062 25,232 47,896 45,477 Other income and (expense): Allowance for equity funds used during construction 120 - 755 (2) Equity in income of nuclear power companies 836 1,949 1,765 2,817 Amortization of goodwill (Note F) - (4,446) - (8,783) Other income (expense), net 656 (124) 718 2,224 ------------ ------------ ------------ ------------ Operating and other income 26,674 22,611 51,134 41,733 ------------ ------------ ------------ ------------ Interest: Interest on long-term debt 3,164 4,456 6,999 8,442 Other interest 956 1,899 1,321 3,140 Allowance for borrowed funds used during construction (19) (204) (130) (532) ------------ ------------ ------------ ------------ Total interest 4,101 6,151 8,190 11,050 ------------ ------------ ------------ ------------ Net income (Note F) $ 22,573 $ 16,460 $ 42,944 $ 30,683 ======= ======= ======= ======= Statements of Retained Earnings (In thousands) Retained earnings at beginning of period $ 80,459 $ 16,077 $ 60,110 $ 1,415 Net income 22,573 16,460 42,944 30,683 Dividends declared on cumulative preferred stock (21) (24) (43) (47) Gain on redemption of preferred stock - 17 - 17 Acquisition adjustment - - - 462 ------------ ------------ ------------ ------------ Retained earnings at end of period $103,011 $ 32,530 $103,011 $ 32,530 ======= ======= ======= ======= 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 National Grid USA.
NEW ENGLAND POWER COMPANY Balance Sheets (In thousands) (Unaudited)
September 30, March 31, ASSETS 2001 2001 ------------ ------ ------ Utility plant, at original cost $ 891,523 $ 846,935 Less accumulated provisions for depreciation and amortization 327,745 320,238 --------------- --------------- 563,778 526,697 Construction work in progress 7,130 34,946 --------------- --------------- Net utility plant 570,908 561,643 --------------- --------------- Goodwill, net of amortization (Note F) 338,188 338,188 Investments: Nuclear power companies, at equity 43,182 46,474 Decommissioning trust funds 17,496 16,331 Nonutility property and other investments 14,032 14,374 --------------- --------------- Total investments 74,710 77,179 --------------- --------------- Current assets: Cash and temporary cash investments (including $112,325 and $22,075 with affiliates) 122,479 22,360 Accounts receivable: Affiliated companies 56,350 61,191 Others 69,342 89,483 Fuel, materials, and supplies, at average cost 6,535 6,289 Prepaid and other current assets 1,943 2,051 Regulatory assets-purchased power obligations and accrued Yankee nuclear plant costs 159,880 158,578 --------------- --------------- Total current assets 416,529 339,952 --------------- --------------- Regulatory assets 1,414,351 1,522,089 Deferred charges and other assets 51,129 50,170 --------------- --------------- $2,865,815 $2,889,221 ========= ========= CAPITALIZATION AND LIABILITIES ------------------------------------------------ Capitalization: Common stock, par value $20 per share, Authorized - 6,449,896 shares Outstanding - 3,619,896 shares $ 72,398 $ 72,398 Other paid-in capital 731,974 731,974 Retained earnings 103,011 60,110 Unrealized gain (loss) on securities, net (219) (145) --------------- --------------- Total common equity 907,164 864,337 Cumulative preferred stock, par value $100 per share 1,436 1,436 Long-term debt 410,282 410,279 --------------- --------------- Total capitalization 1,318,882 1,276,052 --------------- --------------- Current liabilities: Accounts payable (including $21,582 and $25,287 to affiliates) 62,798 66,017 Accrued liabilities: Taxes 67,634 39,451 Interest 1,810 1,489 Purchased power obligations and accrued Yankee nuclear plant costs 159,880 158,578 Other accrued expenses 6,815 7,621 Dividends payable 22 22 --------------- --------------- Total current liabilities 298,959 273,178 --------------- --------------- Deferred federal and state income taxes 255,950 272,304 Unamortized investment tax credits 9,054 9,312 Accrued Yankee nuclear plant costs 160,621 172,340 Purchased power obligations 585,239 636,848 Other reserves and deferred credits 237,110 249,187 --------------- --------------- $2,865,815 $2,889,221 ========= ========= The accompanying notes are an integral part of these financial statements.
NEW ENGLAND POWER COMPANY Statements of Cash Flows Six Months Ended September 30 (In thousands) (Unaudited)
2001 2000 ------- ------- Operating Activities: Net income $ 42,944 $ 30,683 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation and amortization (including amortization of above market purchased power contracts) 43,765 47,646 Amortization of goodwill (Note F) - 8,783 Deferred income taxes and investment tax credits, net (15,041) (1,815) Allowance for funds used during construction (885) (530) Changes in assets and liabilities, net of effects of merger: Decrease (increase) in accounts receivable, net (18) (18,735) Decrease (increase) in fuel, materials, and supplies (246) 602 Decrease (increase) in regulatory assets 71,519 142,232 Decrease (increase) in prepaid and other current assets 108 2,441 Increase (decrease) in accounts payable (3,219) 9,319 Increase (decrease) in purchased power contract obligations (50,345) (96,633) Increase (decrease) in other current liabilities 27,698 (6,070) Increase (decrease) in other non-current liabilities (23,758) (16,328) Other, net 2,528 (29,740) ------------ ------------- Net cash provided by operating activities $ 95,050 $ 71,855 ------------ ------------- Investing Activities: Plant expenditures, excluding allowance for funds used during construction $(19,742) $ (22,121) Proceeds from divestiture of generating assets 25,000 - Other investing activities (146) (6,594) ------------ ------------- Net cash provided by (used in) investing activities $ 5,112 $ (28,715) ------------ ------------- Financing Activities: Dividends paid on common stock $ - $(256,463) Dividends paid on preferred stock (43) (47) Changes in short-term debt - 125,000 Long-term debt - retirements - (90,575) Redemption of preferred stock, net of discount - (79) ------------ ------------- Net cash used in financing activities $ (43) $(222,164) ------------ ------------- Net increase (decrease) in cash and cash equivalents $100,119 $(179,024) Cash and cash equivalents at beginning of period 22,360 226,921 ------------ ------------- Cash and cash equivalents at end of period $122,479 $ 47,897 ======= ======== The accompanying notes are an integral part of these 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 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 hazardous waste liabilities for all sites of which it is aware are not material to its financial position. Note B - Nuclear Units ---------------------- The company has minority interests in four Yankee Nuclear Power Companies (Yankees). These ownership interests are accounted for on the equity method. Three of the Yankees have been permanently shut down, and one is operating. The Company has power contracts with each of the Yankees that require the Company to pay an amount equal to its share of total fixed and operating costs (including decommissioning costs) of the plant plus a return on equity. The Company's share of the expenses of the Yankees is accounted for in "Purchased electric energy" on the income statement. In addition, the Company has a minority non-operating ownership interest in the Seabrook 1 Nuclear generating unit. The Company's share of expenses for Seabrook 1 is accounted for in "Operation and maintenance" expense on the income statement. In view of potential terrorist activity following the events of September 11, 2001, security at nuclear plants has been enhanced in concert with Nuclear Regulatory Commission (NRC) advisory notices. The Company is unable to determine at this time whether additional security at the plants will result in material cost increases. Nuclear Units Permanently Shut Down Yankee Atomic, Connecticut Yankee, and Maine Yankee have permanently ceased operations. Yankee Atomic has discontinued further billings to the Company, subject to a final reconciliation of costs once decommissioning at the plant has been completed. The Company's remaining investment in Yankee Atomic will be repurchased no later than June 2002. In the case of Maine Yankee and Connecticut Yankee, the Company has recorded a liability and a regulatory asset reflecting the estimated future billings from the companies. Under the provisions of the Company's industry restructuring settlement agreements approved by state and federal regulators in 1998, the Company recovers all costs, including shutdown costs, that the Federal Energy Regulatory Commission (FERC) allows the Yankee companies to bill to the Company. 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. For information concerning disputes with Stone & Webster, Inc. regarding a now terminated contract to decommission the Maine Yankee unit, see Note D-2 in the Notes to Financial Statements in the Company's 2001 Annual Report. On September 27, 2001, the Maine Yankee Board of Directors approved an initial redemption of 75,200 shares (pro rata among the owners) of its common stock at $132.84 per share, in lieu of dividends, with a redemption date of September 30, 2001. On October 1, 2001, the Company received approximately $2.4 million for the redemption of 18,048 shares. Operating Nuclear Units The Company has minority interests in two operating nuclear generating units that the Company is engaged in efforts to divest: Vermont Yankee and Seabrook 1. In addition, the Company sold its 16.2 percent interest in Millstone 3 to Dominion Resources, Inc. (Dominion) on March 31, 2001. Until such time as the Company divests its operating nuclear interests, 80 percent of the revenues and reasonable operating costs related to the units will be allocated to customers through contract termination charges (CTC), with shareholders being allocated the balance. Vermont Yankee On August 15, 2001, Vermont Yankee announced that it had reached an agreement to sell the Vermont Yankee nuclear power plant to Entergy Corporation (Entergy) for $180 million. The Company has a 22.5 percent ownership interest in Vermont Yankee. The Company's portion of the sale price would be $40.5 million ($32.6 million for the plant and related assets and $7.9 million for nuclear fuel). The plant's decommissioning trust fund will be transferred to Entergy and Entergy will assume decommissioning liability for the plant. As part of the transaction, Vermont Yankee owners, including the Company, will purchase power from the plant through 2012. Net proceeds from the sale will be credited to the Company's customers through the CTC. The sale of the plant is contingent upon the receipt of regulatory approvals by the Securities and Exchange Commission, under the Public Utility Holding Company Act of 1935, the FERC, the NRC, the Vermont Public Service Board (VPSB), and other state regulatory commissions with jurisdiction over other equity owners of Vermont Yankee. Vermont Yankee expects to close the sale no later than June 2002. The announced sale to Entergy followed termination of an earlier agreement for the sale of the plant to AmerGen Energy Company following rejection of the earlier agreements by the VPSB. For further background on the previous sale agreement, see the "Vermont Yankee" section of Note D-2 in the Notes to Financial Statements in the Company's 2001 Annual Report. Seabrook 1 In December 2000 and April 2001, respectively, Northeast Utilities (NU) and the Company filed Seabrook divestiture plans before the New Hampshire Public Utilities Commission (NHPUC). Under the terms of the Public Service Company of New Hampshire Restructuring Settlement and enabling legislation, the NHPUC, in conjunction with the Connecticut Department of Public Utility Control (CDPUC), will administer an auction of the plant. On September 28, 2001, the NHPUC and CDPUC jointly announced that JP Morgan had been retained as the exclusive financial advisor to manage the sale. The Company expects that the purchaser of the plant will be selected in the spring of 2002. On July 6, 2001, legislation was enacted to modify New Hampshire's current decommissioning law. This new legislation, initiated and supported by Seabrook's joint owners, including the Company, is designed to protect customers from future decommissioning risks. The legislation also enhances the potential sale price of Seabrook by reducing the standard for non- radiological decommissioning at the site, and by allowing the buyer of the plant to retain any decommissioning funds in excess of those contributed by customers of the present owners. The Company and the other Seabrook joint owners participated in the New Hampshire Nuclear Decommissioning Finance Committee (NHNDFC) proceeding implementing the new decommissioning legislation. The NHNDFC is responsible for establishing the level of annual contributions that the joint owners make to the Seabrook decommissioning fund. Under the new legislation, the NHNDFC is charged with assuring that the buyer of Seabrook will have adequate funding to decommission the plant in the event of a premature shutdown. On November 5, 2001, the NHNDFC issued an order substantially approving a settlement establishing proposed terms for funding assurance. The terms of the settlement include a cash "top-off" payment to the decommissioning fund of approximately $57 million at the time of the sale. In addition, the buyer of the plant would be required to accelerate its annual decommissioning fund contributions through 2006 and provide a funding assurance package of approximately $125 million that would decline over time as additional annual contributions are made to the fund. Millstone 3 In November 1999, the Company entered into an agreement with NU and certain of NU's subsidiaries to settle claims made by the Company relative to the operation of Millstone 3. Among other things, the settlement provided for NU to include the Company's share of Millstone 3 in an auction of NU's share of the unit. Upon the closing of the sale, NU would pay the Company a fixed amount regardless of the actual sale price. In August 2000, Dominion agreed to purchase the Millstone units, including the Company's 16.2 percent interest in Millstone 3, for $1.3 billion. On March 31, 2001, the sale was completed. In accordance with the prior settlement agreement, the Company was paid approximately $27.9 million, including $25 million for the plant. In addition, the Company paid approximately $5.8 million to increase the decommissioning trust fund to the level prescribed in its settlement agreement with NU. In November 2000, the Rhode Island Attorney General and the Rhode Island Division of Public Utilities and Carriers filed a protest at the FERC. The protest contended the payment the Company received in March 2001 from the sale of Millstone 3, as established by its agreement with NU, was insufficient. In January 2001, the FERC found that Rhode Island's objection was beyond the scope of the proceeding and approved the sale. The Company cannot predict whether the Rhode Island regulators will reassert their claims in connection with the recovery of stranded costs, or the financial consequences if they do reassert their claims. Note C - 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 September 2001, the charges assessed Norwood amount to approximately $36 million, all of which remain unpaid. The Company filed a collection action in Massachusetts Superior Court (Superior Court). The Superior Court deferred action until various other appeals were decided. (For a full discussion of the events leading up to the Superior Court's decision, see Note D-6, "Town of Norwood Dispute" in the Notes to Financial Statements in the Company's 2001 Annual Report.) On March 14, 2001, the Superior Court ordered Norwood to pay the Company $27 million including interest. Norwood was ordered to pay the judgment in monthly installments of $600,000. Norwood appealed the order on April 11, 2001. Pending the appeal, Norwood entered into a consent order to establish a segregated account for the benefit of the Company in the amount of $14 million and to make regular additions to the account. Note D - Standard Offer Service and ICAP Deficiency Charge ---------------------------------------------------------- Prior to divesting substantially all of its nonnuclear generation business in 1998, the Company was the wholesale supplier of the electric energy requirements to its retail distribution affiliates as well as unaffiliated customers. The Company's all- requirements contracts with its affiliated distribution companies, as well as with some unaffiliated customers, were generally terminated pursuant to settlement agreements and tariff provisions in 1998. However, the Company remained obligated to provide transition power supply service to new customer load in Rhode Island at the standard offer price, but did not have a regulatory agreement that necessarily allowed full recovery of the costs of such standard offer power. Consequently, the Company was at risk for the difference between the actual cost of serving this load and the revenue received from this obligation. For the six months ended September 30, 2001, the Company's gain from this obligation was approximately $1 million. Effective December 1, 2001, a third party will assume the responsibility for providing transitional standard offer power service in Rhode Island and the Company's obligation will terminate. As reported in the Company's 2001 Annual Report, there has been litigation regarding a FERC order to increase the Installed Capacity (ICAP) deficiency charge to $8.75 per kilowatt-month (kW- month) instead of the rate proposed by the New England Independent System Operator (ISO New England) of $0.17 per kW-month. For background information on this issue, see Note C in the Notes to Financial Statements in the Company's 2001 Annual Report. Since the events previously reported, there has been further regulatory activity related to the ICAP issue. In June 2001, ISO New England made a Compliance Filing with the FERC proposing a compromise ICAP regime, including an ICAP deficiency charge of $4.87 per kW-month. Numerous parties filed over the next month supporting and protesting the ICAP Compliance Filing. (The Company supported the ICAP Compliance Filing.) In July and August, various parties appealed to the First Circuit Court of Appeals aspects of earlier FERC ICAP orders favorable to the Company and other ICAP purchasers. On August 28, 2001, the FERC issued an order accepting ISO New England's June Compliance Filing, with some modifications, and on September 28, 2001, issued two more orders favorable to ISO New England's compromise ICAP regime. Motions for rehearing and clarification of these orders (including a complaint in a separate docket) were filed in September and October. On October 19, 2001, one party filed a request that the FERC apply the new $4.87 per kW- month ICAP deficiency charge retroactively to the period January through June 2000, which could cause a significant retroactive increase in ICAP deficiency payments by the Company and other ICAP purchasers. The Company is unable at this time to determine whether these proceedings will have a material impact on earnings. Note E - Regulatory Asset Recovery ---------------------------------- 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 (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation" (FAS 71), which requires regulated entities, in appropriate circumstances, to establish regulatory assets or liabilities, and thereby defer the income statement impact of certain charges or revenues because they are expected to be collected or refunded through future customer billings. In 1997, the Emerging Issues Task Force of the Financial Accounting Standards Board (FASB) 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. The Company has 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 September 30, 2001, this amounted to approximately $1.6 billion, including $1.1 billion related to the above-market costs of purchased power contracts, $0.2 billion related to accrued Yankee nuclear plant costs, and $0.3 billion related to other net CTC regulatory assets. Note F - New Accounting Standards --------------------------------- The Company adopted SFAS No. 142, "Accounting for Goodwill and Other Intangible Assets" (FAS 142), effective April 1, 2001. FAS 142 requires that goodwill no longer be amortized and that it must be reviewed for impairment within six months of adoption ("transitional goodwill impairment test"), and annually thereafter. The transitional goodwill impairment test compares the goodwill carrying value to its fair value. If the carrying value exceeds its fair value, goodwill is reduced to fair value by a goodwill impairment adjustment that must be completed by the end of the year of initial adoption. In accordance with FAS 142, the Company utilized a discounted cash flow approach incorporating its most recent business plan forecasts in the performance of the transitional test for goodwill impairment. The result of this analysis determined that no adjustment to the goodwill carrying value was required. FAS 142 also requires that recognizable intangible assets be amortized over their useful lives and tested for impairment. Intangible assets with indefinite useful lives should be reviewed for impairment. The Company has concluded a review of its intangible assets at March 31, 2001, and no adjustment was deemed necessary effective with the adoption of FAS 142. The following table presents pro forma information for the quarter ended and six months ended September 30, 2000, to reflect the reversal of goodwill amortization in accordance with FAS 142:
September 30, 2000 (In thousands) Quarter Six Months Ended Ended Net income, as reported $16,460 $30,683 Reversal of goodwill amortization 4,446 8,783 ------- ------- Restated net income $20,906 $39,466 ======= =======
In June 1998, the FASB issued SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities". In June 2000, the FASB issued SFAS No. 138, "Accounting for Certain Derivative Instruments and Certain Hedging Activities". These accounting pronouncements require that an entity recognize derivative instruments as either assets or liabilities in the statement of financial position and the measure of those instruments at fair value. The Company adopted the pronouncements effective at the beginning of fiscal 2002. The standards have not materially affected the Company's financial position or results of operations. In July 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations" (FAS 143). FAS 143 provides the accounting requirements for retirement obligations associated with tangible long lived assets. FAS 143 is effective for fiscal years beginning after June 15, 2002, and early adoption is permitted. The Company is currently unable to determine the impact of this statement on its financial position or results of operations. Note G ------ 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 Annual Report for the period ended March 31, 2001. Certain prior period amounts on the financial statements have been reclassified to conform with the current presentation. 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 Annual Report on Form 10-K for the period ended March 31, 2001. The Company is a wholly owned subsidiary of National Grid USA. FERC Proceedings ---------------- On June 13, 2001, the Federal Energy Regulatory Commission (FERC) issued a comprehensive order addressing several rehearing requests and compliance filings that had resulted from an earlier FERC order relating to New England Power Pool's (NEPOOL) proposed congestion management and multi-settlement systems. In the June 13 Order, the FERC found that "energy uplift" costs (which had been about $9 million per month for NEPOOL in 2000) should be allocated on the basis of reliance on the energy markets administered by the Independent System Operator-New England (ISO New England). This would have the effect of relieving parties that procure power under bilateral contracts (such as the Company) from paying energy uplift charges. However, the NEPOOL Participants Committee and ISO New England submitted a filing on July 13, 2001 that the Company believes does not comport with the FERC's order. The Company has filed a protest to the NEPOOL and ISO New England filing. With respect to transmission facilities, the June 13 Order reaffirmed the FERC's earlier order in which it held that transmission owners (TOs) should not have a "decisional" role in transmission planning; and that ISO New England is the sole entity that should have decisional responsibility for planning. The FERC also ordered that transmission projects that are in the regional plan approved by ISO New England should be subject to competitive request for proposals for construction. Any qualified party (including individual TOs like the Company) would be eligible to compete to build transmission projects in any utility's service area. The FERC directed ISO New England to develop an allocation methodology for the cost of transmission upgrades, or adopt the default cost allocation methodology employed by the Pennsylvania- New Jersey-Maryland Interconnection (PJM). The FERC also ruled that a greater percentage of generator-related upgrade costs should be rolled into the transmission tariff and paid by transmission load customers, rather than being paid directly by the generator. National Grid USA presented to the FERC in January 2001 a joint proposal, with ISO New England and other utilities in New England, for a regional transmission organization (RTO) in New England. The RTO would consist of an ISO with responsibility for administering a competitive wholesale market in electricity and an Independent Transmission Company offering transmission services and undertaking transmission network development and the provision of connections for new generation. The proposal was designed to respond to the FERC's objective set out in "Order 2000" of separating transmission operations from market participation, and would give the Independent Transmission Company, of which National Grid USA would be a member, the opportunity to propose financial incentives to deliver greater value for customers and shareholders. On July 11 and 12, 2001, the FERC issued a series of orders relating to RTO proceedings around the country, including New England. The FERC denied the joint proposal made by National Grid USA, ISO New England, and the other participating New England TOs in January, finding that the proposed scope of the RTO was too small. The FERC ordered National Grid USA and the other New England parties to join a 45-day FERC-led mediation process commencing in July, and involving participants of the proposed New York, PJM, and PJM-West RTOs. The purpose of the mediation is to develop a proposal for a "Northeast" RTO to cover a larger region than offered by the proposals that had been submitted. Although it rejected the proposed New England RTO, the FERC nevertheless supported the concept that a transmission company that is independent of market participants may have an active role in transmission planning, and may qualify to earn incentive rates for transmission. On September 17, 2001, the FERC administrative law judge presiding over the mediation issued a report outlining a business plan and schedule of milestones for the parties to discuss how the RTO should be structured and should operate. On November 7, 2001, the FERC issued general guidelines concerning RTO market design, and the FERC may act on specific RTO proposals as early as December 2001. Earnings -------- Net income for the quarter and six months ended September 30, 2001 increased approximately $6 million and $12 million, respectively, compared with the same periods in 2000. The increase is primarily due to the adoption of Statement of Financial Accounting Standards No. 142 "Accounting for Goodwill and Other Intangible Assets" (FAS 142), effective April 1, 2001, which requires the cessation of goodwill amortization. (See Note F.) Also contributing to the increase in earnings is a decrease in interest expense due to decreased interest rates on variable-rate long-term debt and refinancing of short-term debt. Operating Revenue ----------------- Operating revenue for the quarter and six months ended September 30, 2001 decreased approximately $28 million and $39 million, respectively, compared with the same periods in 2000. The decrease in revenue is primarily attributable to reduced kilowatthour (kWh) sales as a result of the sale of the Company's interest in the Millstone 3 nuclear generating facility (Millstone 3) in March 2001 and the effect of a refueling outage at the Vermont Yankee nuclear power plant during the quarter ended June 30, 2001. The decrease is also related to reduced contract termination charge (CTC) revenue due to fully reconciling true-up mechanisms that allow the Company to adjust revenues proportionately with correlating expenses. Partially offsetting these decreases are increased kWh sales related to obligations to new customer load in Rhode Island, and increased transmission revenues. The transmission charge is a formula rate that recovers the Company's actual costs plus a return on actual investment. Operating Expenses ------------------ Operating expenses for the quarter and six months ended September 30, 2001 decreased approximately $28 million and $42 million, respectively, compared with the same periods in 2000. Fuel for generation expense for the quarter and six months ended September 30, 2001 decreased approximately $3 million and $5 million, respectively, primarily due to the sale of Millstone 3. Purchased power expense increased approximately $3 million for the six months ended September 30, 2001 compared with the same period in 2000, despite a $2 million decrease in expense for the quarter then ended as compared to the prior year. The increase for the year to date period is attributed to the costs of a refueling outage at Vermont Yankee during the quarter ended June 30, 2001 and the inclusion of Montaup Electric Company's (Montaup) purchased power costs effective May 1, 2000. Also contributing is the increased cost of purchased power to supply standard offer customers in Rhode Island for the six month period, offset by a decrease in purchased power expense for the quarter due to lower fuel prices. Effective December 1, 2001, a third party will assume the responsibility for providing transitional standard offer power service in Rhode Island and the Company's obligation will terminate. All these costs are partially offset by decreased charges from the three Yankee nuclear units which have been permanently shut down. Nuclear operation and maintenance expenses for the quarter and six months ended September 30, 2001 decreased approximately $5 million and $9 million, respectively, as a result of the sale of Millstone 3. Other operating expenses for the six months ended September 30, 2001 increased approximately $2 million compared with the same period in 2000, primarily due to increased pension and postretirement healthcare expenses. Depreciation and amortization expenses for the quarter and six months ended September 30, 2001 decreased approximately $15 million and $28 million, respectively, compared with the same periods in 2000. This decrease is due to reduced nuclear depreciation and decommissioning expense as a result of the sale of Millstone 3 in March 2001, and the full recovery of the Company's CTC-related fixed costs associated with its generating plants and regulatory assets (excluding Montaup's fixed costs) at the end of 2000. Other Income and Expense-net ---------------------------- Other income and expense-net for the quarter and six months ended September 30, 2001 increased approximately $4 million and $7 million, respectively, compared with the same periods in 2000. The increase is due primarily to the cessation of goodwill amortization as a result of the adoption of FAS 142. Interest Expense ---------------- Interest expense for the quarter and six months ended September 30, 2001 decreased approximately $2 million and $3 million, respectively, compared with the same periods in 2000 primarily due to decreased interest rates on the Company's variable rate long-term debt and the refinancing of short-term debt. Utility Plant Expenditures and Financing ---------------------------------------- Cash expenditures for utility plant totaled approximately $12 million and $20 million for the quarter and six months ended September 30, 2001, respectively, and were primarily transmission- related. The funds necessary for utility plant expenditures during the period were primarily provided by internally generated funds. At September 30, 2001, the Company had no short-term debt outstanding. The Company has regulatory approval to issue up to $375 million of short-term debt. National Grid USA and certain subsidiaries, including the Company, operate a money pool to more effectively utilize cash resources and to reduce outside short-term borrowings. Short-term borrowing needs are met first by available funds of the money pool participants. Borrowing companies pay interest at a rate designed to approximate the cost of outside short-term borrowings. Companies that invest in the pool share the interest earned on a basis proportionate to their average monthly investment in the money pool. Funds may be withdrawn from or repaid to the pool at any time without prior notice. At September 30, 2001, the Company had lines of credit and standby bond purchase facilities with banks totaling $456 million which are available to provide liquidity support for $410 million of the Company's long-term bonds in tax-exempt commercial paper mode, and for other corporate purposes. There were no borrowings under these lines of credit at September 30, 2001. Fees are paid on the lines and facilities in lieu of compensating balances. Item 3. Quantitative and Qualitative Disclosures about Market Risk ----------------------------------------------------------------- New England Power Company's (the Company) major financial market risk exposure is changing interest rates. Changing interest rates will affect interest paid on variable rate debt. At September 30, 2001, the Company's tax exempt variable rate long-term debt had a carrying value and fair value of approximately $410 million. While the ultimate maturity dates of the underlying loan agreements range from 2015 through 2022, this debt is issued in tax exempt commercial paper mode. The various components that comprise this debt are issued for periods ranging from one day to 270 days, and are remarketed through remarketing agents at the conclusion of each period. The weighted average variable interest rate for the six months ended September 30, 2001, was approximately 3.05 percent. For a full discussion of the Company's risk associated with standard offer service and the Installed Capacity deficiency charge, refer to Note D in the Notes to Unaudited Financial Statements. PART II. OTHER INFORMATION Item 1. Legal Proceedings -------------------------- Information concerning several Federal Energy Regulatory Commission proceedings, discussed in this report in the FERC Proceedings section of Management's Discussion and Analysis of Financial Condition and Results of Operations (Part I, Item II) and in Note D of Notes to Unaudited Financial Statements, is incorporated herein and made a part hereof. As previously reported, the Company had reached a settlement in principal on March 31, 2001, with NSTAR, formerly known as Boston Edison Company (BECO), resolving issues surrounding a $3 million refund to Montaup ordered by the FERC in January 2000. The refund related to Montaup's purchased power agreement with BECO for 11 percent of the output from the Pilgrim plant. BECO appealed the FERC order to the First Circuit Court of Appeals which, in turn, remanded it to FERC for further proceedings. All conditions to the settlement have been met. Under the terms of the settlement agreement, the Company returned to BECO 75 percent of the refund amount, plus interest through March 31, 2001. The refunded amount will be recovered by the Company from customers through the contract termination charge. Item 6. Exhibits and Reports on Form 8-K ----------------------------------------- The Company filed a report on Form 8-K dated August 15, 2001 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 September 30, 2001 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: November 13, 2001 NEW ENGLAND POWER COMPANY Notes To Unaudited Financial Statements 18 NEW ENGLAND POWER COMPANY NEW ENGLAND POWER COMPANY NEW ENGLAND POWER COMPANY