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 June 30, 2001 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 June 30, 2001. PART I FINANCIAL INFORMATION Item 1. Financial Statements - -------------------------------------- NEW ENGLAND POWER COMPANY Statements of Income Periods Ended June 30 (In thousands) (Unaudited) Three Months ------------------- 2001 2000 ------- ------- Operating revenue, principally from affiliates $145,016 $156,190 ------------ ------------ Operating expenses: Fuel for generation 1,056 3,586 Purchased electric energy: Contract termination and nuclear unit shutdown charges 58,455 59,604 Other 21,294 15,516 Other operation 13,835 14,650 Maintenance 3,917 4,824 Depreciation and amortization 7,726 20,767 Taxes, other than income taxes 4,740 5,803 Income taxes 11,159 11,195 ------------ ------------ Total operating expenses 122,182 135,945 ------------ ------------ Operating income 22,834 20,245 Other income: Allowance for equity funds used during construction 635 (2) Equity in income of nuclear power companies 929 868 Amortization of goodwill (Note F) - (4,337) Other income (expense), net 62 2,348 ------------ ------------ Operating and other income 24,460 19,122 ------------ ------------ Interest: Interest on long-term debt 3,835 3,986 Other interest 365 1,241 Allowance for borrowed funds used during construction (111) (328) ------------ ------------ Total interest 4,089 4,899 ------------ ------------ Net income (Note F) $ 20,371 $ 14,223 ======= ======= Statements of Retained Earnings (In thousands) Retained earnings at beginning of period $ 60,110 $ 1,415 Net income 20,371 14,223 Dividends declared on cumulative preferred stock (22) (23) Acquisition adjustment - 462 ------------ ------------- Retained earnings at end of period (Note F) $ 80,459 $ 16,077 ======= ======= 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) June 30, March 31, ASSETS 2001 2001 ----------- ------ ------ Utility plant, at original cost $ 884,365 $ 846,935 Less accumulated provisions for depreciation and amortization 324,123 320,238 -------------- --------------- 560,242 526,697 Construction work in progress 4,943 34,946 -------------- --------------- Net utility plant 565,185 561,643 -------------- --------------- Goodwill, net of amortization (Note F) 338,188 338,188 Investments: Nuclear power companies, at equity 45,722 46,474 Decommissioning trust funds 16,872 16,331 Nonutility property and other investments 14,472 14,374 -------------- --------------- Total investments 77,066 77,179 -------------- --------------- Current assets: Cash and temporary cash investments (including $92,850 and $22,075 with affiliates) 92,922 22,360 Accounts receivable: Affiliated companies 65,824 61,191 Others 56,693 89,483 Fuel, materials, and supplies, at average cost 6,766 6,289 Prepaid and other current assets 1,120 2,051 Regulatory assets-purchased power obligations and accrued Yankee nuclear plant costs 159,229 158,578 -------------- --------------- Total current assets 382,554 339,952 -------------- --------------- Regulatory assets 1,455,830 1,522,089 Deferred charges and other assets 50,480 50,170 -------------- --------------- $2,869,303 $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 80,459 60,110 Unrealized gain (loss) on securities, net (87) (145) -------------- --------------- Total common equity 884,744 864,337 Cumulative preferred stock, par value $100 per share 1,436 1,436 Long-term debt 410,281 410,279 -------------- --------------- Total capitalization 1,296,461 1,276,052 -------------- --------------- Current liabilities: Accounts payable (including $23,690 and $25,287 to affiliates) 61,723 66,017 Accrued liabilities: Taxes 54,814 39,451 Interest 2,793 1,489 Purchased power obligations and accrued Yankee nuclear plant costs 159,229 158,578 Other accrued expenses 8,067 7,621 Dividends payable 22 22 -------------- --------------- Total current liabilities 286,648 273,178 -------------- --------------- Deferred federal and state income taxes 264,921 272,304 Unamortized investment tax credits 9,183 9,312 Accrued Yankee nuclear plant costs 165,564 172,340 Purchased power obligations 598,470 636,848 Other reserves and deferred credits 248,056 249,187 -------------- --------------- $2,869,303 $2,889,221 ======== ======== The accompanying notes are an integral part of these financial statements. NEW ENGLAND POWER COMPANY Statements of Cash Flows Quarters Ended June 30 (In thousands) (Unaudited) 2001 2000 ------- ------- (In thousands) Operating activities: Net income $ 20,371 $ 14,223 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation and amortization 21,844 32,335 Amortization of goodwill - 4,337 Deferred income taxes and investment tax credits, net (6,602) 11,224 Allowance for funds used during construction (746) (326) Changes in assets and liabilities, net of effects of acquisition: Decrease (increase) in accounts receivable, net 3,157 (2,378) Decrease (increase) in fuel, materials, and supplies (477) (26) Decrease (increase) in regulatory assets 47,963 35,382 Decrease (increase) in prepaid and other current assets 931 (25,743) Increase (decrease) in accounts payable (4,294) 864 Increase (decrease) in purchased power contract obligations (37,746) (68,794) Increase (decrease) in other current liabilities 17,113 (4,400) Increase (decrease) in other non-current liabilities (7,888) (13,852) Other, net 464 250 ------------- ------------- Net cash provided by (used in) operating activities $ 54,090 $ (16,904) ------------- ------------- Investing activities: Plant expenditures, excluding allowance for funds used during construction $ (8,460) $ (11,951) Proceeds from divestiture of generating assets 25,000 - Other investing activities (46) (2,462) ------------- ------------- Net cash provided by (used in) investing activities $ 16,494 $ (14,413) ------------- ------------- Financing activities: Dividends paid on common stock $ - $(256,463) Dividends paid on preferred stock (22) (23) Changes in short-term debt - 158,050 Long-term debt - retirements - (90,575) ------------- ------------- Net cash provided by (used in) financing activities $ (22) $(189,011) ------------- ------------- Net increase (decrease) in cash and cash equivalents $ 70,562 $(220,328) Cash and cash equivalents at beginning of period 22,360 226,921 ------------- ------------- Cash and cash equivalents at end of period $ 92,922 $ 6,593 ======== ======== 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 - ---------------------- Yankee Nuclear Power Companies 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. 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 in the Notes to Financial Statements in the Company's 2001 Annual Report. 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 operating costs related to the units will be allocated to customers through contract termination charges (CTC), with shareholders being allocated the balance. Vermont Yankee In November 1999, the Vermont Yankee Nuclear Power Corporation entered into an agreement with AmerGen Energy Company (AmerGen), a joint venture between PECO Energy and British Energy, to sell the assets of Vermont Yankee. Several other parties, including Entergy Corporation (Entergy), indicated to the Vermont Public Service Board (VPSB) that they were prepared to make an offer for Vermont Yankee. On February 14, 2001, the VPSB rejected Vermont Yankee's sale agreement with AmerGen and formally terminated the AmerGen proceeding on March 15, 2001. The VPSB also required Entergy to post a $26 million bond payable in the event that Entergy withdraws its offer. In addition, the VPSB stated that if the Entergy bond were redeemed, the proceeds would go exclusively to Vermont customers. The Vermont Yankee Board of Directors is presently considering its options with respect to that part of the order. On March 15, 2001, Vermont Yankee terminated its agreement with AmerGen. After considering its options, Vermont Yankee decided to proceed with a formal auction of the plant. The auction was officially launched on April 16, 2001. The Company expects the winning bidder of the plant will be named shortly. Any 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 Nuclear Regulatory Commission, the VPSB, and other state regulatory commissions with jurisdiction over other equity owners of Vermont Yankee. For further background on the previous sale agreement, see the "Vermont Yankee" section of Note D 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 Utilities, will administer an auction of the plant with the assistance of an asset sale specialist. The NHPUC is currently interviewing potential asset sale specialist candidates and is expected to select an asset sale specialist by the end of August. 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, seeks 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 utility 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 July 9, 2001, a settlement was filed with the NHNDFC 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. The NHNDFC conducted hearings regarding the settlement and is expected to issue a draft decision in late August. A final decision is expected in early September. 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 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. The amounts received pursuant to the sale will, after reimbursement of the Company's transaction costs and net investment in Millstone 3, be credited to customers. In November 2000, the Rhode Island Attorney General and the Rhode Island Division of Public Utilities and Carriers filed a protest at the FERC contending that the payment the Company would receive 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 June 2001, the charges assessed Norwood amount to approximately $32 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 has also entered 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 remains obligated to provide transition power supply service to new customer load in Rhode Island at the standard offer price, but does not have a regulatory agreement that necessarily allows full recovery of the costs of such standard offer power. Consequently, the Company is at risk for the difference between the actual cost of serving this load and the revenue received from this obligation. The standard offer rate is currently 3.8 cents per kilowatthour (kWh). The standard offer rate is also subject to a rolling twelve-month fuel index adjustment factor, which increased the rate by an additional 2.563 cents per kWh beginning in June 2001. The Company meets this obligation through a combination of generation from some of its remaining generation sources, as well as by periodically procuring power at market prices. Over time, the Company cannot predict whether the resulting revenues will be sufficient to cover the costs of procuring such power. For information regarding pending appeals and remands of a FERC order to increase the Installed Capacity (ICAP) deficiency charge which could affect the Company's future power supply costs, see Note C in the Notes to Financial Statements in the Company's 2001 Annual Report. 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 June 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 the cessation of goodwill amortization and that goodwill be reviewed for impairment annually, or on an interim basis if events or changes in circumstances indicate the fair value of the Company is below its carrying value. The Company will conduct a "transitional goodwill impairment test" in conjunction with the adoption of FAS 142 no later than the end of the second quarter of fiscal 2002. The Company will also perform an annual goodwill impairment test by March 31, 2002. The Company does not expect the impairment tests to require adjustments that will have a material impact on its financial position or results of operations. 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 June 30, 2000 to reflect the reversal of goodwill amortization in accordance with FAS 142: Quarter Ended June 30, 2000 (In thousands) Net income, as reported $ 14,223 Reversal of goodwill amortization 4,337 ------- Restated net income $ 18,560 ======= In June 1998, the FASB issued SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities" (FAS 133). In June 2000, the FASB issued SFAS No. 138, "Accounting for Certain Derivative Instruments and Certain Hedging Activities" (FAS 138). 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. 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. 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, 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 the 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. Earnings - -------- Net income for the quarter ended June 30, 2001 increased approximately $6 million compared with the same period 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.) Earnings were also affected by increased income due to the May 1, 2000 merger with Montaup Electric Company (Montaup), and decreased interest expense, partially offset by a reduction in other income. Operating Revenue - ----------------- Operating revenue for the quarter ended June 30, 2001 decreased approximately $11 million compared with the same period 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 during the quarter ended June 30, 2001 at the Vermont Yankee nuclear power plant (Vermont Yankee). 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 ended June 30, 2001 decreased approximately $14 million compared with the same period in 2000. Fuel for generation decreased approximately $3 million primarily due to the sale of Millstone 3. Purchased power expense increased approximately $5 million compared with the same period in 2000. The increase is largely attributed to the costs of a refueling outage at Vermont Yankee. Also contributing to the increase are costs of standard offer purchases related to obligations to supply new customer load in Rhode Island, and the inclusion of Montaup's purchased power costs effective May 1, 2000. These costs are partially offset by decreased charges from the Yankee Atomic nuclear power plant due to the completion of the purchased power contract and final billing in June 2000. Nuclear operation and maintenance expenses decreased approximately $4 million as a result of the sale of Millstone 3. Other operating expenses 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 ended June 30, 2001 decreased approximately $13 million compared with the same period 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 costs associated with its generating plants and regulatory assets (excluding Montaup's) at the end of 2000. Other Income and Expense-net - ---------------------------- Other income and expense-net for the quarter ended June 30, 2001 increased approximately $3 million compared with the same period in 2000. The increase reflects the cessation of goodwill amortization as a result of the adoption of FAS 142, increased allowance for equity funds used during construction, and decreased interest income from other investing activities. Interest Expense - ---------------- Interest expense decreased approximately $1 million for the quarter ended June 30, 2001 compared with the same period in 2000 primarily due to reduced short-term borrowings. Utility Plant Expenditures and Financing - ---------------------------------------- Cash expenditures for the Company for utility plant totaled approximately $8 million for the quarter ended June 30, 2001 and were primarily transmission-related. The funds necessary for utility plant expenditures during the period were primarily provided by internally generated funds. At June 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, with regulatory approval, operate a money pool to more effectively utilize cash resources and to reduce outside short-term borrowings. Short-term borrowing needs are met first by available funds of the money pool participants. Borrowing companies pay interest at a rate designed to approximate the cost of outside short-term borrowings. Companies 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 June 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 June 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 June 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 three months ended June 30, 2001, was approximately 3.32 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), is incorporated herein and made a part hereof. Item 4. Submission of Matters to a Vote of Security Holders - ------------------------------------------------------------ On April 18, 2001, the Annual Meeting of Shareholders was held. By unanimous vote of the 3,619,896 shares present of 3,634,257 total shares having general voting rights: The number of directors for the ensuing year was fixed at eight. The following were elected as directors: L. Joseph Callan Peter G. Flynn Michael E. Jesanis Robert G. Powderly Lawrence J. Reilly Terry L. Schwennesen Richard P. Sergel Philip R. Sharp John G. Cochrane was elected as Treasurer and Gregory A. Hale was elected as Clerk. PricewaterhouseCoopers was selected as Auditor for the year 2001. Item 6. Exhibits and Reports on Form 8-K - ----------------------------------------- None. 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 June 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: August 13, 2001 NEW ENGLAND POWER COMPANY Notes to Unaudited Financial Statements 21 NEW ENGLAND POWER COMPANY NEW ENGLAND POWER COMPANY