-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, Ib41ayctexWrelG51U5L52fNSr4oreAo8W1yiKeyK/DD7lXWQTZKp7aM6RyMMYNr Hera79WqaO3ISqfB+VoxHQ== 0000071297-99-000018.txt : 19990326 0000071297-99-000018.hdr.sgml : 19990326 ACCESSION NUMBER: 0000071297-99-000018 CONFORMED SUBMISSION TYPE: 8-K PUBLIC DOCUMENT COUNT: 3 CONFORMED PERIOD OF REPORT: 19990325 ITEM INFORMATION: FILED AS OF DATE: 19990325 FILER: COMPANY DATA: COMPANY CONFORMED NAME: NEW ENGLAND ELECTRIC SYSTEM CENTRAL INDEX KEY: 0000071297 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC SERVICES [4911] IRS NUMBER: 041663060 STATE OF INCORPORATION: MA FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 8-K SEC ACT: SEC FILE NUMBER: 001-03446 FILM NUMBER: 99572927 BUSINESS ADDRESS: STREET 1: 25 RESEARCH DR CITY: WESTBOROUGH STATE: MA ZIP: 01582 BUSINESS PHONE: 5083669011 MAIL ADDRESS: STREET 1: 25 RESEARCH DR CITY: WESTBOROUGH STATE: MA ZIP: 01582 8-K 1 SECURITIES AND EXCHANGE COMMISSION Washington, DC 20549 FORM 8-K CURRENT REPORT Pursuant to Section 13 of the Securities Exchange Act of 1934 Date of Earliest Event Reported: February 23, 1999 NEW ENGLAND ELECTRIC SYSTEM (exact name of registrant as specified in charter) Massachusetts 1-3446 04-1663060 (state or other (Commission (I.R.S. Employer jurisdiction of File No.) Identification No.) incorporation) 25 Research Drive, Westborough, Massachusetts 01582 (Address of principal executive offices) (508) 389-2000 (Registrant's telephone number, including area code) Item 7. Financial Statements, Pro Forma Financial Information and Exhibits - -------------------------------------------------------------- Exhibits The 1998 New England Electric System Annual Report to Shareholders, is filed with this report. SIGNATURE Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this Current Report on Form 8-K to be signed on its behalf by the undersigned thereunto duly authorized. NEW ENGLAND ELECTRIC SYSTEM s/Michael E. Jesanis By Michael E. Jesanis Senior Vice President and Chief Financial Officer Date: March 25, 1999 The name "New England Electric System" means the trustee or trustees for the time being (as trustee or trustees but not personally) under an agreement and declaration of trust dated January 2, 1926, as amended, which is hereby referred to, and a copy of which as amended has been filed with the Secretary of The Commonwealth of Massachusetts. Any agreement, obligation or liability made, entered into or incurred by or on behalf of New England Electric System binds only its trust estate, and no shareholder, director, trustee, officer or agent thereof assumes or shall be held to any liability therefor. EX-99 2 EXHIBIT INDEX Exhibit No. Description Page - ----------- ----------- ---- 13 1998 New England Electric Filed System Annual Report to herewith Shareholders EX-99 3 EXHIBIT 13 [COVER PHOTO] 19 98 Annual Report {FOLLOWING TEXT VERTICALLY PLACED ON LEFT OF COVER PHOTO] New England Electric System [NEES LOGO] [TABLE BELOW PLACED ONE THIRD OF WAY DOWN OF INSIDE FRONT COVER, ALIGNED ON RIGHT] Financial Results 1998 1997 --------------- Earnings per average share $ 3.04 $ 3.39 Dividends declared per share $ 2.36 $ 2.36 Average number of shares outstanding (in 000s) 62,456 64,952 Market price per share at year end $48 1/8 $42 3/4 Growth in kilowatthour (kWh) deliveries to ultimate customers 1.5% 2.0% Electric Utilities Return on Equity (%) NEES 11.4% National Median 11.3% New England/New York Median 10.3% [FOLLOWING TWO PARAGRAPHS ARE HORIZONTALLY ALIGNED WITH COLORED VERTICAL BAR DIVIDING THE LEFT (FIRST PARAGRAPH) FROM THE RIGHT (SECOND PARAGRAPH)] New England Electric System (NEES) is a public utility holding company headquartered in Westborough, Massachusetts. Its regulated subsidiaries are engaged in the transmission, distribution, and sale of electricity. NEES' electricity distribution subsidiaries serve 1.4 million customers in Massachusetts, Rhode Island, and New Hampshire. Unregulated subsidiaries are engaged in the marketing of energy commodities and services and the construction and leasing of telecommunications infrastructure. On the cover: The skilled people who maintain our electricity delivery system include Linda Schonrog, John Shaw, and David Petty, shown here at a Providence substation. [LARGE FONT OF FOLLOWING TEXT PLACED ON GHOSTED VERSION OF COVER PHOTO] The agreement to merge with National Grid is one of many [SMALL PHOTO OF TWO LINE WORKERS ON LEFT MARGIN HERE] bold decisions NEES has made in this century to enhance shareholder value. The merger will provide [SMALL PHOTO OF TWO LINE WORKERS CENTERED HERE] you with a 25 percent* premium on your investment. At the same time, [SMALL PHOTO OF LINE WORKER ON LEFT MARGIN HERE] it will give NEES new resources to remain a successful company and to help make the region's competitive electricity market work. [STANDARD SIZE FONT OF FOLLOWING TEXT CENTERED AT BOTTOM OF PAGE] (*over the $43 share price on December 11, 1998, the last trading day before the merger was announced) To Our Fellow Shareholders The past year has been a time of dramatic change for NEES. We completed the sale of our generating business and became one of the nation's first electric utilities whose primary focus is on the "wires business." We helped bring about lower rates and choice of energy suppliers for all customers in Massachusetts and Rhode Island and for our customers in New Hampshire, ahead of most of the nation. We announced a merger agreement that will make NEES a wholly owned subsidiary of The National Grid Group plc of the United Kingdom, enhancing our capabilities and resources. And, in a smaller transaction, we announced a merger agreement in which NEES would acquire Eastern Utilities Associates, a neighboring utility. The merger agreements, which are independent of one another, will achieve our goal to expand the scale of our transmission and distribution business. In addition, the National Grid merger will fundamentally change our ownership structure. NEES/National Grid merger On December 14, 1998, we announced the historic merger with The National Grid Group plc. National Grid is the owner and operator of the England and Wales high-voltage transmission network, including interconnections with Scotland and France. It is listed on the London Stock Exchange with a market capitalization of about $12 billion. National Grid has joint ventures and partnerships with companies in Argentina, Zambia, and India, and holds an interest in Energis, which operates a fiber optic telecommunications network in England and Wales. Under the merger agreement, National Grid will acquire all of the outstanding shares of NEES for $53.75 per share (subject to upward adjustment, as explained on page 10). That figure values the equity of NEES at approximately $3.2 billion and represents a 25 percent premium above the $43 closing price of NEES shares on December 11, 1998 (the last day of trading on the New York Stock Exchange before the merger was announced.) National Grid would also assume NEES' $1 billion of debt. Once the merger is completed and National Grid acquires all of the outstanding NEES shares, those shares will no longer be publicly traded. At the appropriate time, we will send you information on how to turn in your shares for the $53.75 per share cash payment. [FOLLOWING TEXT AT BOTTOM OF FIRST COLUMN REFERRING TO PHOTO OF ALFRED D. HOUSTON AND RICHARD P. SERGEL AT BOTTOM OF SECOND COLUMN] Alfred D. Houston, chairman, (left) and Richard P. Sergel, president and chief executive officer The proposed merger is a cash transaction that under IRS rules is taxable. The NEES Board of Directors approved the National Grid merger because they unanimously decided it was in the best interest of our shareholders. The Board considered all the options available to NEES, including continuing as a standalone company and other merger options, and concluded that the merger offered the highest value to shareholders, even taking into account the IRS rules. You will have the freedom of reinvesting your proceeds in an investment appropriate to your circumstances. The merger also requires the approval of our shareholders, National Grid shareholders, and various government and regulatory bodies. We hope to obtain all the necessary approvals and complete the merger no later than early 2000. A proxy statement will be sent to you, with more complete information and a form for voting on the proposed merger. We encourage you to read the material carefully before casting your vote. Many benefits Among the many options reviewed, the National Grid offer to purchase NEES provided the best value for shareholders while also offering benefits to customers and employees. For you, our shareholders, the NEES/National Grid merger offers a substantial premium over the value of your NEES shares on December 11, 1998. The terms fulfill our commitment to you to enhance the value of your investment in NEES during a period of dramatic change in the electric industry. [PHOTO OF ALFRED D. HOUSTON AND RICHARD P. SERGEL APPEARS HERE UNDERNEATH SECOND OF TWO COLUMNS OF TEXT] The merger will end a long and valued relationship - and in some cases, strong emotional ties - between NEES and the people who have owned NEES shares through the years, but we feel, in both our minds and hearts, that this merger is in keeping with our long history of putting your interests at the forefront of our decision making. There have been similarly bold actions in the past on your behalf, some of which are highlighted on the following pages. For employees, this merger will have minimal impact on our day-to-day work in the short term. Jobs will be preserved within New England. Our employees will benefit from new opportunities as the base of U.S. operations for a global business. For customers, the merger will mean a seamless continuation of high-quality service from the women and men in the familiar yellow NEES companies' trucks and at the busy customer service workstations. The prices charged to customers will continue to be among the lowest in the region. Customers will benefit from National Grid's decade of experience in operating a transmission network in a competitive market. We are excited by this proposed merger and the opportunities it affords NEES and our region. NEES/EUA merger We are pursuing local consolidation as well. On February 1, 1999, we announced that we had reached an agreement to acquire Eastern Utilities Associates (EUA), a neighboring electric utility with 300,000 customers in Massachusetts and Rhode Island. This merger would bring together two low-cost companies to achieve even greater cost savings for customers. The combination will serve more electricity customers in both Massachusetts and Rhode Island than any other company. We will acquire EUA for $31 per share, or $634 million, and will assume EUA's $400 million of debt. (The $31 per share is subject to upward adjustment, as explained on page 10.) We expect the deal to close by early 2000. The NEES/EUA merger requires the approval of EUA shareholders and state and federal regulators. It does not require NEES shareholder approval, as it does not involve NEES shares. National Grid supports the NEES/EUA merger, as it advances our common goal of growing our energy delivery business to achieve more efficiencies. Achievements NEES produced good financial results for you in 1998, despite lower electric rates due to industry restructuring in the region, the effects of divesting our generation business (historically, our most profitable enterprise), and other factors. Earnings per share were $3.04, compared with $3.39 in 1997. Return on equity was 11.4 percent, compared with the 1998 industry average of 11.3 percent and 12.8 percent earned by NEES in 1997. Your dividends held steady at $2.36 per year. We completed the sale of our generating business to USGen New England, Inc. in September for $1.59 billion, and used most of the proceeds to retire or reduce debt, buy out contracts with independent power producers, repurchase NEES shares, and pay income taxes related to the sale. The remainder was put in short-term investments, so we can withdraw the money when needed for a variety of purposes, including the EUA acquisition. The generation sale halved our stranded investment and is a key contributor to our having the lowest electricity delivery charge among major utilities in the states we serve. Among other 1998 achievements, our New Hampshire subsidiary Granite State Electric became the only electric utility in that state whose customers have a choice of energy suppliers, when in July the Public Utilities Commission approved the comprehensive settlement agreement reached by our subsidiary, the Governor's office, and other interested parties. In Massachusetts, voters strongly endorsed (71 percent) the Electric Utility Industry Restructuring Act in a November referendum. We were part of a broad-based coalition of businesses, individuals, trade organizations, environmentalists, and other parties who sought to retain this carefully crafted statute. Watershed year We can best describe 1998 as a watershed year for NEES, filled with accomplishment, change, and promise for the future as part of a much larger, international company. We thank you for your confidence over the years as we look toward a new era for NEES. s/Alfred D. Houston s/Richard P. Sergel Alfred D. Houston Richard P. Sergel Chairman President and Chief Executive Officer February 23, 1999 Turning Points The decision to merge with National Grid is a striking strategic move for NEES. As we mark this fundamental turning point for 1998, we highlight a few of the past decisions in which NEES met the challenges of the times to the benefit of shareholders. Long distance hydropower NEES traces its origins to 1907, a time when electricity use was growing rapidly. Two daring entrepreneurs, Henry I. Harriman and Malcolm G. Chace, adopted a plan to build a dam and hydro station at Vernon, Vermont and send power to Massachusetts industries, 60 miles away. Their company was to be one of the nation's first independent power producers. With some difficulty, they found financial support for the ambitious project, although no one had ever transmitted power that far in the icy eastern part of the country. Harriman and Chace also overcame the resistance to rights-of-way for their transmission line and of local utilities that didn't want newcomers competing for their customers. When the power began to flow, formerly skeptical manufacturers lined up for service. Long-distance transmission in New England was launched. [SEPIA PHOTO CIRCA 1907 OF BUILDING OF DAM AND HYDRO STATION APPEARS HERE] Breaking into retail By the prosperous 1920s, demand for electricity was soaring and wealthy investors were buying up and merging small retail utilities to create huge systems. Harriman and Chace did not have financing to outbid rivals for those retail companies. The needed cash was supplied by a four-party agreement that soon was taken over by International Paper, and the renamed New England Power Association (NEPA) began to aggressively buy retail companies. NEPA began to build the retail system that is the NEES of today and that is the foundation of its core electricity delivery business. [SEPIA PHOTO CIRCA 1920 OF LINE CREW APPEARS HERE] The building boom In the post-World War II years, economic prosperity and new uses of electricity such as water heating, cooking, and television had pushed growth of residential demand to more than 7 percent per year. To respond, NEES added more than 50 percent to its physical plant between the end of the war and 1960. [SEPIA PHOTO POST WORLD WAR II OF CONSTRUCTION OF GENERATING FACILITY APPEARS HERE] Consolidation By the early 1960s, cooperative long-term planning and sales of wholesale power between companies had strengthened the region's electric system. In 1962, NEES completed the process of simplifying its organization with mergers that led to the creation of NEES' single largest retail operating company, Massachusetts Electric Company. Massachusetts Electric traces its roots to nearly 100 small companies, each serving one or a few towns. The mergers streamlined administration and operations, reduced costs, and created a more efficient company. The consolidation of 1962 dovetailed with promotional efforts to attract industrial development and grow residential use with all-electric homes. [OLD LOGO OF NEW ENGLAND ELECTRIC SYSTEM APPEARS HERE] [EXPLANATORY TEXT FOR FULL-PAGE COLOR PHOTO OF NEXT PAGE APPEARS HERE] Facing Page: This gas-insulated switchgear (GIS) substation in Providence is more compact and less prone to damage from natural causes than traditional oil-insulated substations. [FULL-PAGE COLOR PHOTO TAKEN IN GAS-INSULATED SWITCHGEAR SUBSTATION WITH TWO CREW MEMBERS APPEARS HERE WITH FOLLOWING TEXT SUPERIMPOSED IN GOLD-TINTED TEXT BOX] NEES has embraced new technology that provide cost and environmental benefits. Coal conversion During the 1960s, NEES used mostly coal to fire its steam plants. When oil markets became flooded with supplies from the Middle East and South America, NEES decided to switch to oil at those plants. The company achieved some of the lowest fuel costs in the region. In 1970, however, new environmental regulations specifying low-sulfur oil pushed costs upward. [SEPIA PHOTO LATE 1940S OFF-LOADING COAL AT GENERATING FACILITY APPEARS HERE] When the 1973 OPEC oil embargo led to scarce supplies and skyrocketing prices, NEES joined the national effort to reduce reliance on imported oil. An innovative, long-range plan called NEESPLAN was announced in 1979. It called for energy conservation, renewables - and conversion of most of NEES' oil-fired generating units to coal. After lengthy negotiations with environmental interests and regulators, NEES converted three Brayton Point Station units and later three Salem Harbor Station units. The conversions reaped long-running financial benefits for customers and shareholders, as oil continued to be priced higher than coal. The company's diversification of its fuel mix proved to be a significant strength. It moderated the effect on NEES of sudden price increases in any one fuel or generation source. Leadership in energy conservation A second key component of NEESPLAN was energy conservation and load management (now often called demand-side management or DSM). Utilities in the 1970s found power plants more difficult and expensive to build, due to increasingly stringent environmental regulations and pressures. NEES was among the first to realize that this situation was permanent. To meet growing electricity demand, NEES, teaming with a leading environmental organization, the Conservation Law Foundation, dramatically expanded its programs in the late 1980s to reach all customers. NEES put forth another pathbreaking idea: utilities should earn a profit from successful energy efficiency programs. State approvals came in 1989-90. Through year-end 1998, DSM incentives had earned more than $60 million for NEES shareholders. DSM is now an established part of the services NEES provides for customers, and a continuing element of the company's environmental commitment. [SEPIA-TONED PHOTO OF ENERGY EFFICIENT LIGHTING APPEARS HERE] Seabrook solution In 1986, construction of Seabrook nuclear unit 1 was completed, but licensing and commercial operation remained in doubt. Delays in obtaining an operating license from the Nuclear Regulatory Commission were increasing costs day by day. Many of the joint owners were having financial difficulties, and the lead owner had filed for bankruptcy. NEES had invested approximately $543 million for its 10 percent share of Seabrook. NEES refused to wait for events to play themselves out and run the risk of large, additional financial burdens on customers and shareholders if the plant never operated. NEES worked out a rate settlement in 1988 with regulators that called for a writeoff of $179 million (after tax) of its Seabrook investment in exchange for putting the balance of its investment in Seabrook and fuel exploration costs into rates. This eliminated major uncertainties that could have jeopardized the company's financial standing. The investment community responded positively to NEES' intelligent compromise. Two years later, when Seabrook 1 went on line, NEES was able to reverse a substantial portion of the writeoff. [SEPIA-TONED PHOTO OF SEABROOK NUCLEAR REACTOR DOME APPEARS HERE] [EXPLANATORY TEXT FOR FULL-PAGE COLOR PHOTO OF NEXT PAGE APPEARS HERE] Facing Page: At our new, centralized warehouse in Franklin, Mass., Erin Penders and Jim Wilbur use bar-code tracking soft-ware and handheld computers to fulfill orders for materials such as cable and insulators. [FULL-PAGE COLOR PHOTO OF ERIN PENDERS ON FORKLIFT AND JIM WILBUR ON FLOOR OF FRANKLIN WAREHOUSE APPEARS HERE WITH FOLLOWING TEXT SUPERIMPOSED IN GOLD-TINTED TEXT BOX] Efficiency and cost control are NEES hallmarks. Industry restructuring The passage of the Public Utility Regulatory Policies Act of 1978 led to the growth of the independent power industry and to increasing competition in electric generation. Demand for independent access to retail customers led to a regulatory movement to "deregulate" the sale of power to customers. NEES recognized early that the restructuring process created substantial risk for utilities and their shareholders, who had invested in generation to meet their obligation to serve customers. NEES led the electric utility industry in successfully arguing that markets should be open to competition but that these historically allowed costs to serve customers, which could be "stranded" in a competitive generation marketplace, should be recovered in a transition charge to customers. Stranded cost recovery was incorporated into agreements and statutes in all three states that NEES serves. Potential losses to shareholders were averted at the same time that significantly lower rates were provided to customers. [SEPIA-TONED PHOTO OF PETER FLYNN PRESENTATION ABOUT CHOICE APPEARS HERE] Generation divestiture Recovery of stranded costs came at a steep price. In 1996, to gain support for its restructuring plans that included stranded cost recovery, NEES became the first U.S. utility to agree to divest its generating business to determine the level of stranded costs to be recovered. The plants commanded 45 percent more than their book value, effectively recouping NEES shareholder investments in power plants, while reducing by about half the transition charges to be paid by customers. [SEPIA-TONED PHOTO OF MANCHESTER STREET GENERATING PLANT APPEARS HERE] Growing through mergers NEES, like other utilities, has realized that to succeed as an energy delivery company in a changed industry, increased scope and scale are critical. To achieve both, NEES agreed in December 1998 to merge with an international transmission leader, The National Grid Group plc, which is based in Coventry, England. When the merger is approved, NEES will serve as National Grid's base of U.S. operations and will become a wholly owned subsidiary. The merger will give NEES shareholders a 25 percent premium on their investment compared with the December 11, 1998 share price. NEES and its customers will benefit from National Grid's financial and technical resources and its experience in running a transmission grid in a competitive market. Closer to home, NEES signed a merger agreement in February 1999 to acquire its neighbor, Eastern Utilities Associates. This will increase NEES' customer base by 20 percent when the acquisition is approved. [NATIONAL GRID LOGO APPEARS HERE] Meeting new challenges NEES, by both anticipating and adapting to the challenges of each era, has proven to be a resilient institution. Throughout our long history, we have been willing to make tough decisions to enhance shareholder value while meeting our responsibility of providing reliable, affordable electric service to customers. We appreciate your confidence in NEES, and look forward to the challenges of the next century. [EXPLANATORY TEXT FOR FULL-PAGE COLOR PHOTO OF NEXT PAGE APPEARS HERE] Facing Page: Installing electrical cable in Worcester, Mass. are underground crew members (left to right) Jim Ritchie, Kevin Peltier, and Larry McLear. [FULL-PAGE COLOR PHOTO OF THREE UNDERGROUND CREW MEMBERS INSTALLING ELECTRICAL CABLE WITH TRUCK AND UNION STATION, WORCESTER, MA IN BACKGROUND APPEARS HERE WITH FOLLOWING TEXT SUPERIMPOSED IN GOLD-TINTED TEXT BOX] Our communities depend on us for reliable, affordable, safe electricity service. Financial Review Introduction 1998 was a year of unprecedented change for the electric utility industry and for New England Electric System (NEES). Prior to 1998, the NEES companies provided their customers bundled electric service (i.e. production and delivery) within exclusive franchise service territories. By mid-1998, all NEES customers were provided the right to purchase electricity from the power supplier of their choice. NEES remains obligated to deliver that electricity over its transmission and distribution systems. In September 1998, NEES completed the divestiture of substantially all of its nonnuclear generating business. In December 1998, NEES agreed to a merger with The National Grid Group plc (National Grid), whose principal subsidiary operates the transmission system in England and Wales. On February 1, 1999, NEES entered into an agreement to acquire Eastern Utilities Associates (EUA), a utility holding company serving approximately 300,000 customers in Massachusetts and Rhode Island. Merger Agreement with National Grid On December 11, 1998, NEES, National Grid, and NGG Holdings LLC (Holdings), a directly and indirectly wholly owned subsidiary of National Grid, entered into an Agreement and Plan of Merger (Merger Agreement). Pursuant to the Merger Agreement, Holdings will merge with and into NEES (the Merger), with NEES becoming a wholly owned subsidiary of National Grid. NEES shareholders will receive $53.75 per share in cash, which will be increased at a rate of $.003288 each day beginning six months after shareholder approval of the Merger until the Merger is completed, up to a maximum price of $54.35 per share. The Merger is subject to approval by a majority vote of NEES shareholders as well as National Grid shareholder approval. In addition, the Merger is subject to a number of regulatory and other approvals and consents, including approvals by the Securities and Exchange Commission (SEC), Federal Energy Regulatory Commission (FERC), and Nuclear Regulatory Commission (NRC), support or approval from the states in which NEES operates, and approval under both the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended, and the Exon-Florio Provisions of the Omnibus Trade and Competitiveness Act of 1988. National Grid has obtained governmental clearance in the United Kingdom for the Merger. The Merger is expected to be completed by early 2000. [GRAPH APPEARS HERE, NEES YEAR-END SHARE PRICE ($)] Merger Agreement with Eastern Utilities Associates On February 1, 1999, NEES, EUA, and Research Drive LLC (Research Drive), a directly and indirectly wholly owned subsidiary of NEES, entered into an Agreement and Plan of Merger (EUA Agreement). Pursuant to the EUA Agreement, Research Drive will merge with and into EUA, with EUA becoming a wholly owned subsidiary of NEES. EUA shareholders will receive $31.00 per share in cash, which will be increased at a rate of $.003 each day beginning six months after EUA shareholder approval of the EUA acquisition until the acquisition is completed or until April 30, 2000, whichever is earlier. The acquisition of EUA is subject to approval by a two-thirds vote of EUA shareholders. In addition, the acquisition is subject to a number of regulatory and other approvals and consents, including approvals by the SEC, FERC, and NRC, support or approval from the states in which EUA operates, and approval under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended. The EUA acquisition is expected to be completed by early 2000. Industry Restructuring During 1998, pursuant to legislation enacted in Massachusetts, Rhode Island, and New Hampshire, and settlement agreements approved by state and federal regulators (the Settlement Agreements), all NEES customers were provided the right to purchase electricity from the power supplier of their choice. Customers who do not choose a power supplier are able, for a period of time, to continue to purchase their electricity from the NEES companies at a transition rate ("standard offer generation service") which, when combined with delivery charges, results in total rate reductions ranging from 8 to 24 percent compared with the rates that had been in effect prior to the introduction of customer choice. Substantially all of the obligations of the NEES companies to provide standard offer generation service are backed by contracts with USGen New England, Inc. (USGen), an indirect wholly owned subsidiary of PG&E Corporation, and other power suppliers. Pursuant to the Settlement Agreements, the NEES companies had agreed to sell their nonnuclear generating business. On September 1, 1998, NEES subsidiaries New England Power Company (NEP) and The Narragansett Electric Company (Narragansett Electric) (collectively, the Sellers) completed the sale of substantially all of their nonnuclear generating business to USGen. The assets sold include three fossil-fueled and 15 hydroelectric generating stations, totaling approximately 4,000 megawatts (MW) of capacity, as well as NEES' 100 percent interest in Narragansett Energy Resources Company (NERC), a 20 percent general partner in the Ocean State Power project, all of which had a book value of approximately $1.1 billion. The NEES companies received $1.59 billion for the sale. In addition, the NEES companies were reimbursed approximately $140 million for costs associated with early retirements and special severance programs for employees affected by industry restructuring, and the value of inventories. USGen assumed responsibility for environmental conditions at the Sellers' nonnuclear generating stations. USGen also assumed the Sellers' obligations under long-term fuel and fuel transportation contracts, and certain collective bargaining agreements. As part of the sale, NEP also signed a purchased power transfer agreement through which USGen purchased NEP's entitlement to approximately 1,100 MW of power procured under long-term contracts in exchange for monthly fixed payments by NEP averaging $9.5 million per month through January 2008 (having a net present value of $833 million) toward the above market cost of those contracts. In some cases, these transfers involved formal assignment of the contracts to USGen and a release of NEP from further obligations to the power supplier, while others did not. For those that involved formal assignment, NEP was required to make a lump sum payment equivalent to the present value of the monthly fixed payment obligations of those contracts. On or prior to the closing date, NEP made lump sum payments totaling approximately $340 million and was released from further obligations relating to two of the contracts. These lump sum payments are separate from the $833 million figure referred to above. As part of the divestiture plan, in February 1998, New England Energy Incorporated (NEEI), a wholly owned subsidiary of NEES, whose costs had been supported by the generating business, sold its oil and gas properties for approximately $50 million. NEEI's loss on the sale of approximately $120 million, before tax, has been reimbursed by NEP. NEP agreed under the Settlement Agreements to endeavor to sell its minority interest in three nuclear power plants and a 60 MW interest in a fossil-fueled generating station in Maine. The Settlement Agreements provide that the costs of NEP's generating investments and related contractual commitments that were not recovered from the divestiture of those investments ("stranded costs") are to be recovered from NEP's wholesale customers through contract termination charges (CTC). The affiliated wholesale customers, in turn, are recovering those costs through their delivery charges to distribution customers. Under the Settlement Agreements, the recovery of NEP's stranded costs is divided into several categories. Unrecovered costs associated with generating plants (nuclear and nonnuclear) and most regulatory assets will be fully recovered through the CTC by the end of 2000 and earn a return on equity averaging 9.7 percent. NEP's obligation relating to the above-market cost of purchased power contracts and nuclear decommissioning costs are recovered through the CTC over a longer period of time, as such costs are actually incurred. 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 completion of the sale of NEP's nonnuclear generating business. As the CTC rate declines, NEP, under certain of the Settlement Agreements, earns incentives based on successful mitigation of its stranded costs. These incentives supplement NEP's return on equity. Finally, the Settlement Agreements provide that until such time as NEP divests its operating nuclear interests, NEP will share with customers, through the CTC, 80 percent of the revenues and operating costs related to the units, with shareholders retaining the balance. Accounting Implications 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 Financial Accounting Standards Board (FASB) 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. [GRAPH APPEARS HERE, COST PER KWH DELIVERED TO ULTIMATE CUSTOMERS] NEP has received authorization from the FERC to recover through the 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 NEP's business, including the recovery of its stranded costs, remains under cost-based rate regulation. Under existing ratemaking practices, NEES' distribution companies will have the ability to recover through rates their specific costs of providing ongoing distribution services. NEES believes these factors and the EITF conclusion allow its principal utility subsidiaries to continue to apply FAS 71. Because of the nuclear cost-sharing provisions related to NEP's CTC, NEP ceased applying FAS 71 in 1997 to 20 percent of its ongoing nuclear operations, the impact of which is immaterial. Currently, there is much regulatory and other movement toward establishing performance-based rates. It is possible that the adoption of performance-based rates, future regulatory rules, or other circumstances could cause the application of FAS 71 to be discontinued. This discontinuation would result in a noncash write-off of previously established regulatory assets, including those being recovered through NEP's CTC. In addition, reserves for depreciation may also have to be increased to comply with unregulated accounting practices. As a result of applying FAS 71, NEES 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 costs of purchased power contracts, reduced by the gain from the sale of NEP's nonnuclear generating business. At December 31, 1998, the regulatory asset related to the CTC was approximately $1.5 billion, of which $1.2 billion related to the above-market costs of purchased power contracts. [GRAPH APPEARS HERE, TOTAL NUMBER OF NEES EMPLOYEES] As described above, the CTC regulatory asset includes the unrecovered plant costs associated with NEP's interest in operating nuclear plants. This balance sheet treatment is due to NEP's conclusion that its interests in the Millstone 3 and Seabrook 1 nuclear generating units have little, if any, market value. Three proposed sales of nuclear units by other utilities have required the seller to set aside amounts for decommissioning in excess of the proceeds from the sale of the units. Two of these proposed sales were agreed upon prior to the end of the third quarter of 1998. As a result, at the end of the third quarter of 1998, NEP recorded an impairment writedown in its reserve for depreciation of approximately $390 million, which represents the net book value at December 31, 1995, less applicable depreciation subsequent to that date, of Millstone 3 and Seabrook 1. Because the Settlement Agreements permit NEP to recover its pre-1996 investment as well as decommissioning expenses through the CTC, NEP established a regulatory asset in an amount equal to the impairment writedown. Should NEP's efforts to sell its nuclear interests result in a gain over the amounts remaining in the plant account, such gain will be credited to customers through the CTC. Impact of Restructuring on Distribution Business The Settlement Agreement applying to Massachusetts (The Massachusetts Settlement) also establishes distribution rates for NEES' Massachusetts subsidiaries Massachusetts Electric Company (Massachusetts Electric) and Nantucket Electric Company (Nantucket Electric). On March 1, 1998, Massachusetts Electric's distribution rates were set at a level approximately $45 million above the level embedded in its previously bundled rates, with such rates then frozen through the year 2000. This increase reflects changes to the distribution cost of service, including an $11 million increase in annual depreciation expense, a $3 million annual contribution to a storm fund, and increased annual amortization of unfunded deferred income taxes of approximately $1 million over six years. Through the year 2000, Massachusetts Electric's return on equity is subject to a floor of 6 percent and a ceiling of 11 percent. Earnings over the ceiling will be shared equally between customers and shareholders up to a maximum of 12.5 percent. This sharing results in an effective cap on Massachusetts Electric's return on equity of 11.75 percent, excluding certain limited incentive opportunities. To the extent that earnings fall below the floor, Massachusetts Electric will be authorized to surcharge customers for the shortfall. Under the Rhode Island statute, Narragansett Electric increased distribution rates by approximately $7 million and $11 million in 1998 and 1997, respectively. The statute does not limit Narragansett Electric's ability to seek approval from state regulators to increase rates in the future. Overview of Financial Results Earnings were $3.04 per diluted share in 1998 compared with $3.39 and $3.22 per diluted share in 1997 and 1996, respectively. The return on common equity was 11.4 percent in 1998, 12.8 percent in 1997, and 12.6 percent in 1996. The market price of NEES common shares was 48 1/8 per share at the end of 1998 compared with 42 3/4 per share and 34 7/8 per share at the end of 1997 and 1996, respectively. The decrease in 1998 earnings reflects significant revenue reductions due to the restructuring of the utility business in Massachusetts, Rhode Island, and New Hampshire, the effect of the divestiture of NEES' nonnuclear generating business, increased investments in unregulated ventures, and costs incurred in connection with the development of the Merger Agreement between NEES and National Grid. The decrease in earnings was partially offset by increased kWh deliveries to ultimate customers, a reduction in costs associated with nuclear operations, and a reduction in core business operation and maintenance expense as a result of workforce reductions. 1998 earnings were also positively affected by a share repurchase program. The increase in 1997 earnings reflected increased revenues due to increased kWh deliveries as well as rate increases and reversals of prior period refund accruals. Also contributing to the higher earnings was a decrease in the nonfuel component of purchased power expense. Partially offsetting the higher earnings were increased operation and maintenance expenses, increased expenses associated with NEES' unregulated ventures, and costs incurred to repurchase a portion of the preferred stock of NEES subsidiaries. Outlook NEES believes its 1999 earnings will be reduced by a full year's effect of industry restructuring. NEES earnings will be negatively affected by the return on the reinvestment of the sale proceeds, which is expected, at least in the near term, to be considerably less than the return historically earned in the generating business. Further, the Settlement Agreements related to recovery of stranded costs limit the return on equity earned on the unrecovered investment in NEES' generating business to 9.7 percent, before mitigation incentives, which is significantly lower than that earned by the generating business in recent years. Finally, through the year 2000, the return on equity for NEES' principal distribution subsidiary is capped at 11.75 percent, plus certain incentives. This report contains statements that may be considered forward looking under the securities laws. Actual results may differ materially for the reasons discussed in this Financial Review. For a more detailed discussion of the Merger Agreement between NEES and National Grid, refer to the proxy statement being delivered to all shareholders. Operating Revenue Operating revenue decreased $82 million in 1998 and reflects a reduction in generation-related revenues, decreased oil and gas-related revenues, and the reversal in 1997 of certain refund reserves related to rate adjustment mechanisms. These decreases were partially offset by distribution rate increases, increased kWh deliveries, and increased revenues resulting from the inclusion of NEES subsidiary AllEnergy Marketing Company, L.L.C.'s (AllEnergy) operating revenues in 1998. The reduction in generation-related revenues reflects the effects of industry restructuring and the implementation of customer choice of power supplier in Rhode Island, Massachusetts, and New Hampshire on January 1, 1998, March 1, 1998, and July 1, 1998, respectively. The reductions include the effect of a true-up mechanism for stranded cost recovery billings including nuclear decommissioning costs. The decrease in oil and gas-related revenues reflects the sale of NEEI's oil and gas properties at the beginning of 1998. Oil and gas-related revenues totaled $41 million in 1997. Rate adjustment mechanisms referred to above relate to Massachusetts Electric and Nantucket Electric reversing previously reserved amounts into revenue in the fourth quarter of 1997. These previously reserved amounts related to their purchased power cost adjustment (PPCA) mechanisms, which were eliminated in accordance with the provisions of the Massachusetts Settlement. Distribution rate increases include a $45 million rate increase at Massachusetts Electric, effective March 1, 1998, in accordance with the provisions of the Massachusetts Settlement, and a $7 million increase at Narragansett Electric, effective January 1, 1998, pursuant to Rhode Island's Utility Restructuring Act of 1996. [GRAPH APPEARS HERE, RETURN ON COMMON EQUITY (%)] In 1998, kWh deliveries to ultimate customers increased 1.5 percent, reflecting a strong economy. For the year as a whole, weather had a negative impact on 1998 deliveries when compared with 1997. AllEnergy's 1998 revenues of $171 million are included in NEES' consolidated operating revenues as a result of AllEnergy becoming a wholly owned and fully consolidated subsidiary of NEES in the fourth quarter of 1997. NEES had previously accounted for its 50 percent ownership interest under the equity method of accounting, as a component of other income. AllEnergy's 1997 revenues were $70 million. AllEnergy is an energy marketing company which offers energy commodities (natural gas, propane, and oil) and related value-added services to customers in the emerging competitive energy markets in the Northeast. Operating revenue for NEES increased $152 million in 1997 compared with 1996, and reflected higher kWh deliveries, a Narragansett Electric base rate increase, transmission rate increases in mid-1996, increased revenues related to rate adjustment mechanisms, and increased fuel revenues. Kwh deliveries to ultimate customers increased 2.0 percent in 1997, and reflected the effects of an improving regional economy. Rate adjustment mechanisms included the 1997 reversal of PPCA reserves into revenue, as discussed above. NEES' distribution companies (Massachusetts Electric, Nantucket Electric, Narragansett Electric, and Granite State Electric Company (Granite State Electric)) received approval from their respective regulatory agencies to recover demand-side management (DSM) program expenditures in rates on a current basis through 1998. These expenditures were $59 million, $63 million, and $59 million in 1998, 1997, and 1996, respectively. Narragansett Electric and Granite State Electric have received approvals from their respective state regulatory agencies to recover their 1999 DSM program expenditures. The Massachusetts Settlement and statute provide for recovery of DSM-related costs. The Massachusetts Department of Telecommunications and Energy approved Massachusetts Electric's and Nantucket Electric's DSM program expenditure recovery plans through 2002. Since 1990, the distribution companies have been allowed to earn incentives based on the results of their DSM programs and have recorded before-tax incentives of $7.2 million, $7.6 million, and $6.0 million in 1998, 1997, and 1996, respectively. Operating Expenses Operating expenses decreased $24 million in 1998, and reflect decreased fuel and nonfuel-related purchased power expenses, decreased depreciation and amortization expenses, and decreased taxes, other than income taxes partially offset by increased operation and maintenance expenses. In 1998, total fuel and purchased power costs decreased due to the effect of the sale of NEES' nonnuclear generating business to USGen on September 1, 1998. The decrease reflects reduced charges from the Maine Yankee nuclear power plant, which was closed in mid-1997 and the transfer of NEP's purchased power contracts, in conjunction with the sale of the nonnuclear generating business to USGen. These decreases were partially offset by fixed monthly contractual payments toward the above-market cost of the transferred purchased power contracts, as well as the cost of power for standard offer generation service. The decrease in depreciation and amortization expense in 1998 reflects the sale of NEEI's oil and gas properties at the beginning of 1998 and the sale of the nonnuclear generating business on September 1, 1998. These decreases were partially offset by an $11 million increase in annual depreciation expense provided for in the Massachusetts Settlement, depreciation related to new distribution-related and transmission-related utility plant expenditures, the accelerated amortization of NEP's investment in the Millstone 3 nuclear generating unit prior to its impairment writedown, and amortization of regulatory assets. See the "Accounting Implications" section above for a discussion of the latter two issues. In 1998, the increase in operation and maintenance expenses is primarily due to the inclusion of AllEnergy's operating expenses of $190 million in NEES' consolidated operating expenses, due to AllEnergy becoming a wholly owned and fully consolidated subsidiary of NEES in the fourth quarter of 1997, as discussed above. AllEnergy's operating expenses were $87 million in 1997. AllEnergy's operating expenses are primarily cost of goods sold in connection with energy commodity sales. This increase was partially offset by the effect of the sale of the nonnuclear generating business, lower charges from the partially owned Seabrook 1 and Millstone 3 nuclear generating facilities, and lower charges related to postretirement benefits other than pensions (PBOPs), reflecting the completion of the accelerated amortization of NEP's deferred PBOP costs in 1997 under the terms of a 1995 rate agreement. The decrease in taxes, other than income taxes in 1998 is primarily due to reduced property taxes resulting from the sale of the nonnuclear generating business. Operating expenses increased $133 million in 1997 compared with 1996. This increase reflected increased fuel costs, including the fuel component of purchased power expense, and increased operation and maintenance expenses, partially offset by decreased depreciation and amortization expense. The increase in the fuel component of purchased power expense was partially offset by a reduction in the nonfuel component. Fuel costs, including the fuel component of purchased power expense, increased in 1997 primarily due to increased wholesale sales to other utilities and increased replacement power costs due to the reduced generation from partially owned nuclear units. In 1997, the increase in operation and maintenance expenses reflected increased costs of partially owned nuclear plants, transmission wheeling costs, start-up costs associated with the new regional transmission control organization, increased distribution system-related costs, and the NEES companies' share of costs associated with the restoration to service of previously idled generating facilities throughout New England, in response to a tightening regional power supply. The increase also reflected increased general and administrative costs, including accelerated PBOP amortization, as discussed above. The decrease in depreciation and amortization expense in 1997 reflected the completion of the amortization of NEP's pre-1988 investment in the Seabrook 1 nuclear unit and NEP's investment in the canceled Seabrook 2 nuclear unit. The decrease in the nonfuel component of purchased power expense, which amounted to $6 million in 1997, reflected reduced charges from the Connecticut Yankee nuclear power plant which was permanently shut down in late 1996 and the expiration of certain purchased power contracts, partially offset by increased charges from the Maine Yankee nuclear power plant which was permanently shut down in mid-1997. Other Income The change in other income in 1998 primarily represents increased interest income as a result of the investment of the proceeds from the sale of the nonnuclear generating business on September 1, 1998, as well as the inclusion of AllEnergy's losses in other income during most of 1997. AllEnergy became a wholly owned and fully consolidated subsidiary of NEES in the fourth quarter of 1997, as discussed above. The decrease in other income in 1997 compared with 1996 reflected expenses associated with NEES' unregulated ventures. Nuclear Units Nuclear Units Permanently Shut Down Three regional nuclear generating companies in which NEP 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 6 Feb 1992 24 Connecticut Yankee 15 16 Dec 1996 75 Maine Yankee 20 16 Aug 1997 143
In the case of each of these units, NEP has recorded a liability and an offsetting regulatory asset reflecting the estimated future billings from the companies. In a 1993 decision, the FERC allowed Yankee Atomic to recover its undepreciated investment in the plant 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, NEP, 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, NEP'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. NEP's industry restructuring settlements allow it to recover all costs that the FERC allows these Yankee companies to bill to NEP. NEP 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 NEP, 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 NEP 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 NRC scrutiny. NEP performs periodic economic viability reviews of operating nuclear units in which it holds ownership interests. Millstone 3 In July 1998, Millstone 3 returned to full operation after being shut down since April 1996. Millstone 3 remains on the NRC "Watch List," signifying that it continues to warrant increased NRC attention. Millstone 3 is operated by a subsidiary of Northeast Utilities (NU). NEP is not an owner of the Millstone 2 nuclear generating unit, which is temporarily shut down under NRC orders, or the Millstone 1 nuclear generating unit, which has been permanently shut down. A criminal investigation related to Millstone 3 is ongoing. In August 1997, NEP sued NU in Massachusetts Superior Court for damages resulting from the tortious conduct of NU that caused the shutdown of Millstone 3. NEP'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 NEP's incremental replacement power costs have been recovered from customers, either through fuel adjustment clauses or through provisions in the Settlement Agreements. NEP also seeks punitive damages. NEP 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 NEP 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. NEP subsequently amended its complaint by, among other things, adding NU's Trustees as defendants. In December 1998, NU moved for summary judgement. NEP'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. Hazardous Waste The electric utility industry typically utilizes and/or generates in its operations a range of potentially hazardous products and by-products. The most prevalent types of hazardous waste sites with which NEES and its subsidiaries have been associated are manufactured gas locations. (Until the early 1970s, NEES was a combined electric and gas holding company system.) NEES is aware of approximately 40 such manufactured gas locations, including 10 for which the NEES companies have been identified by either federal or state regulatory agencies as potentially responsible parties, mostly located in Massachusetts. NEES has reported the existence of all manufactured gas locations of which it is aware to state environmental regulatory agencies. NEES is engaged in various phases of investigation and remediation work at approximately 20 of the manufactured gas locations. NEES and its subsidiaries are 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. In 1993, the Massachusetts Department of Public Utilities approved a settlement agreement that provides for rate recovery of remediation costs of former manufactured gas sites and certain other hazardous waste sites located in Massachusetts. A more detailed discussion of this settlement agreement and of potential hazardous waste liabilities is contained in Note E of the Notes to the Financial Statements. Predicting the potential costs to investigate and remediate hazardous waste sites continues to be difficult. At December 31, 1998, NEES had total reserves for environmental response costs of $53 million. NEES believes that hazardous waste liabilities for all sites of which it is aware, and which are not covered by a rate agreement, are not material to its financial position. Year 2000 Readiness Disclosure Over the next 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. This 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 on the next page, 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. 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. 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 cannot predict the outcome of other companies' remediation efforts. The NEES companies believe total costs associated with making the necessary modifications to all centralized and noncentralized systems will be approximately $28 million. In addition, the NEES companies are spending $4 million related to the replacement of the human resources and payroll system, in part due to the Y2K issue. To date, total Y2K-related costs of $25 million have been incurred, of which $3 million has been capitalized. 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. 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 the New England Power Pool (NEPOOL) and the Independent System Operator of the NEPOOL area (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 the North American Electric Reliability Council. 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 the worst case scenario with a reasonable chance of occurring is temporary disruptions of electric service. This scenario could result from a failure to adequately remediate Y2K problems at NEES company facilities or could be caused by the inability of entities, such as ISO New England, to maintain the short-term reliability of various generators and/or transmission lines on a regional or interregional basis. The NEES companies believe that the contingency plans being developed both internally and on a regional level, as described above, should substantially mitigate the risks of this potential scenario. 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 and results of operations. 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 and power suppliers, 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. New Accounting Standards In 1997, the FASB released Statement of Financial Accounting Standards No. 131, Disclosure about Segments of an Enterprise and Related Information (FAS 131), which went into effect in 1998. FAS 131 requires the reporting in financial statements of certain new additional information about operating segments of a business. FAS 131 does not currently impact NEES' reporting requirements. In February 1998, the FASB issued Statement of Financial Accounting Standards No. 132, Employers' Disclosures about Pensions and Other Postretirement Benefits (FAS 132), which revises disclosure requirements for pension and other postretirement benefits. NEES has adopted FAS 132 in its financial statements for the year ended December 31, 1998. The adoption of FAS 131 and FAS 132 has no impact on NEES' operating results, financial position, or cash flows. In June 1998, the FASB 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. NEES, through its wholly owned indirect subsidiary, AllEnergy, uses derivative instruments to manage exposure from fluctuations in commodity prices. At this time, AllEnergy uses derivative instruments to manage risks associated with natural gas, propane, and oil prices. FAS 133 requires recognition of all derivatives as either assets or liabilities on the balance sheet and requires measurement of those instruments at fair value. If certain conditions are met, derivatives may be treated as hedges under FAS 133 for income statement purposes. Gains or losses on a derivative that qualifies as a hedge are deferred until recognized in the income statement in the same period as the hedged item is recognized in the income statement. To the extent these conditions are not met, that portion of the gain or loss is reported in earnings immediately. As of December 31, 1998, all of AllEnergy's existing futures contracts qualified as hedges under Statement of Financial Accounting Standards No. 80, Accounting for Futures Contracts (FAS 80), with limited exceptions, and are expected to qualify as hedges under FAS 133. The derivative instruments that do not qualify as hedges under FAS 80 and are recognized in income immediately are immaterial to NEES. FAS 133 is effective for fiscal years beginning after June 15, 1999. Risk Management NEES' major financial market risk exposure is changing interest rates. Changing interest rates will affect interest paid on variable rate debt and the fair value of fixed rate debt. NEES manages interest rate risk through a combination of both fixed rate and variable rate debt instruments. The table below presents the average rate on NEES long-term debt at December 31, 1998, the amounts maturing during each of the next five years, and the fair value of NEES debt at December 31, 1998.
Variable Fixed Long-Term Long-Term --------- --------- Weighted Average Rates 3.28% 7.64% Maturities (millions of dollars) 1999 $ - $ 36 2000 - 49 2001 - 18 2002 - 52 2003 - 65 Cumulative thereafter 372 503 ---- ---- Total $372 $723 ---- ---- Fair Value $372 $805 ---- ----
See the "Industry Restructuring" section above for a discussion of NEP's purchased power transfer agreement with USGen. NEP retained one purchased power contract, with Vermont Yankee, which carries fixed payment requirements of approximately $35 million in 1999, $30 million in 2000, $35 million in 2001 and 2002, $30 million in 2003, and approximately $300 million thereafter. Liquidity and Capital Resources Plant expenditures for 1998 totaled $182 million. The funds necessary for utility plant expenditures were primarily provided by internally generated funds and the proceeds from the sale of the nonnuclear generating business. Cash expenditures for utility plant and investments by NEES' unregulated subsidiaries for 1999 are estimated to be approximately $280 million. Internally generated funds are expected to meet approximately 75 percent of capital expenditure requirements for 1999. The average interest rate on the long-term debt issued in 1998 is 6.41 percent. The retirement of NEP, Narragansett Electric, NERC, and NEEI debt in the table below was in connection with the divestiture of NEP's nonnuclear generating business. NEES also paid off all $252 million of its short-term debt outstanding at December 31, 1997. The long-term debt financing activities of the NEES subsidiaries for 1998 and the projected long-term debt financings for 1999 are summarized as follows:
1998 1999 ---- ---- (millions of dollars) Issues Retirements Retirements - ---------------------------------------------------------------- NEP $ - $328 $ - Massachusetts Electric 50 40 15 Narragansett Electric - 12 8 Granite State Electric 5 - - Nantucket Electric - 1 1 Hydro-Transmission companies - 12 12 NERC - 29 - NEEI - 122 - - ---------------------------------------------------------------- $55 $544 $36 - ----------------------------------------------------------------
NEES purchased approximately 5.7 million common shares in 1998 under a repurchase program authorized by the NEES Board of Directors in 1997 and 1998. It is unlikely that NEES will repurchase additional shares in 1999. During 1998, Narragansett Electric repurchased preferred stock with a par value of $5.6 million, Massachusetts Electric repurchased or redeemed preferred stock with a par value of $5 million, and NEP repurchased or redeemed preferred stock with a par value of $9 million. At December 31, 1998, NEES and its consolidated subsidiaries had lines of credit and standby bond purchase facilities with banks totaling approximately $900 million. These lines and facilities were used at December 31, 1998 for liquidity support for $372 million of NEP bonds in tax-exempt commercial paper mode. Fees are paid on the lines and facilities in lieu of compensating balances. On February 12, 1999, NEES and AllEnergy acquired Griffith Consumers Company (Griffith Consumers), a full-service distributor of residential and commercial heating oil in Washington D.C., and in parts of Maryland, Delaware, Virginia, and West Virginia. In addition to heating oil sales, Griffith Consumers provides related repair, maintenance, and installation services. Griffith Consumers' annual revenue is approximately $100 million. Statements New England Electric System and Subsidiaries Selected Financial Data Year ended December 31 (dollar amounts expressed in millions, except per share data)
1998 1997 1996 1995 1994 ------- ------- ------- ------- ------- Operating revenue: Electric utility revenue $2,244 $2,450 $2,318 $2,242 $2,203 Unregulated subsidiary revenue 177 12 - - - Oil and gas sales - 41 33 30 40 ------- ------- ------- ------- ------- Total operating revenue $2,421 $2,503 $2,351 $2,272 $2,243 Net income $ 190 $ 220 $ 209 $ 205 $ 199 Average common shares (000s) Basic 62,359 64,899 64,960 64,970 64,970 Diluted 62,456 64,952 64,986 64,986 64,988 Per share data: Net income - Basic $ 3.05 $ 3.39 $ 3.22 $ 3.15 $ 3.07 Net income - Diluted $ 3.04 $ 3.39 $ 3.22 $ 3.15 $ 3.07 Dividends declared $ 2.36 $ 2.36 $ 2.36 $2.345 $2.285 Book Value at year end $26.53 $27.03 $25.98 $25.13 $24.33 Return on average common equity 11.4% 12.8% 12.6% 12.8% 12.7% Total assets $5,071 $5,312 $5,223 $5,191 $5,085 Capitalization: Common share equity $1,570 $1,744 $1,685 $1,632 $1,581 Minority interests 39 43 46 49 55 Cumulative preferred stock 19 39 126 147 147 Long-term debt 1,056 1,488 1,615 1,675 1,520 ------- ------- ------- ------- ------- Total capitalization $2,684 $3,314 $3,472 $3,503 $3,303 Deliveries to ultimate customers (millions of kWh) 22,422 22,097 21,674 21,311 21,155 Number of employees 3,540 4,665 4,787 4,832 4,990 Number of ultimate customers (in thousands) 1,363 1,349 1,333 1,314 1,300 ------- ------- ------ ------- -------
New England Electric System and Subsidiaries Statements of Consolidated Income Year ended December 31 (thousands of dollars, except per share data)
1998 1997 1996 ---------- ---------- ---------- Operating revenue $2,420,533 $2,502,591 $2,350,698 ---------- ---------- ---------- Operating expenses: Fuel for generation 229,722 372,461 334,994 Purchased electric energy 633,347 528,229 509,400 Other operation 675,806 556,658 501,090 Maintenance 109,040 143,372 127,785 Depreciation and amortization 206,662 236,492 246,379 Taxes, other than income taxes 134,763 146,494 143,733 Income taxes 122,354 152,024 139,199 ---------- ---------- ---------- Total operating expenses 2,111,694 2,135,730 2,002,580 ---------- ---------- ---------- Operating income 308,839 366,861 348,118 Other income: Allowance for equity funds used during construction 633 - - Equity in income of generating companies 9,437 10,240 10,334 Other income (expense), net (3,262) (15,755) (8,166) ---------- ---------- ---------- Operating and other income 315,647 361,346 350,286 ---------- ---------- ---------- Interest: Interest on long-term debt 89,805 107,311 110,479 Other interest 27,822 16,939 19,527 Allowance for borrowed funds used during construction (1,754) (1,908) (2,246) ---------- ---------- ---------- Total interest 115,873 122,342 127,760 ---------- ---------- ---------- Income after interest 199,774 239,004 222,526 Preferred dividends and net gain/loss on reacquisition of preferred stock of subsidiaries 3,454 12,319 6,463 Minority interests 6,278 6,647 7,127 ---------- ---------- ---------- Net income $ 190,042 $ 220,038 $ 208,936 ---------- ---------- ---------- Average common shares - Basic 62,359,122 64,899,322 64,960,496 Average common shares - Diluted 62,456,103 64,952,185 64,986,136 Per share data: Net income - Basic $ 3.05 $ 3.39 $ 3.22 Net income - Diluted $ 3.04 $ 3.39 $ 3.22 Dividends declared $ 2.36 $ 2.36 $ 2.36 ---------- ---------- ----------
Statements of Consolidated Retained Earnings Year ended December 31 (thousands of dollars)
1998 1997 1996 ---------- ---------- ---------- Retained earnings at beginning of year $ 954,518 $ 887,292 $ 831,529 Net income 190,042 220,038 208,936 Dividends declared on common shares (145,648) (152,812) (153,173) ---------- ---------- ---------- Retained earnings at end of year $ 998,912 $ 954,518 $ 887,292 ---------- ---------- ----------
The accompanying notes are an integral part of these consolidated financial statements. New England Electric System and Subsidiaries Consolidated Balance Sheets At December 31 (thousands of dollars)
1998 1997 ---------- ---------- Assets Utility plant, at original cost $4,130,102 $5,860,101 Less accumulated provisions for depreciation and amortization 1,694,653 1,995,017 ---------- ---------- 2,435,449 3,865,084 Construction work in progress 52,977 48,708 ---------- ---------- Net utility plant 2,488,426 3,913,792 ---------- ---------- Oil and gas properties, at full cost (Note A) - 1,299,817 Less accumulated provision for amortization - 1,128,659 ---------- ---------- Net oil and gas properties - 171,158 ---------- ---------- Investments: Nuclear power companies, at equity (Note E) 48,538 49,825 Other subsidiaries, at equity 2,374 37,418 Other investments 169,196 117,645 ---------- ---------- Total investments 220,108 204,888 ---------- ---------- Current assets: Cash 187,673 14,264 Marketable securities 57,915 - Accounts receivable, less reserves of $18,196 and $17,834 294,943 257,185 Unbilled revenues 87,467 71,260 Fuel, materials, and supplies, at average cost 38,339 66,509 Prepaid and other current assets 57,081 64,265 ---------- ---------- Total current assets 723,418 473,483 ---------- ---------- Regulatory assets (Note C) 1,599,657 532,213 Deferred charges and other assets 38,926 16,113 ---------- ---------- $5,070,535 $5,311,647 ---------- ---------- Capitalization and liabilities Capitalization (see accompanying statements): Common share equity $1,570,003 $1,744,442 Minority interests in consolidated subsidiaries 38,742 43,062 Cumulative preferred stock of subsidiaries 19,480 39,113 Long-term debt 1,055,740 1,487,481 ---------- ---------- Total capitalization 2,683,965 3,314,098 ---------- ---------- Current liabilities: Long-term debt due within one year 36,307 89,910 Short-term debt - 251,950 Accounts payable 204,992 136,218 Accrued taxes 24,196 14,831 Accrued interest 16,680 24,969 Dividends payable 34,412 36,162 Other current liabilities (Note H) 142,975 120,002 ---------- ---------- Total current liabilities 459,562 674,042 ---------- ---------- Deferred federal and state income taxes 472,140 720,375 Unamortized investment tax credits 65,292 90,018 Accrued Yankee nuclear plant costs (Note E) 242,138 299,564 Purchased power obligations 832,668 - Other reserves and deferred credits 314,770 213,550 Commitments and contingencies (Note E) ---------- ---------- $5,070,535 $5,311,647 ---------- ----------
The accompanying notes are an integral part of these consolidated financial statements. New England Electric System and Subsidiaries Consolidated Statements of Cash Flows Year ended December 31 (thousands of dollars)
1998 1997 1996 ----------- --------- --------- Operating activities Net income $ 190,042 $ 220,038 $ 208,936 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation and amortization 211,069 239,654 250,508 Deferred income taxes and investment tax credits, net (273,448) (31,178) (30,328) Allowance for funds used during construction (2,387) (1,908) (2,246) Buyout of purchased power contracts (326,590) - - Minority interests 6,278 6,647 7,127 Decrease (increase) in accounts receivable, net and unbilled revenues (44,682) 4,217 30,770 Decrease (increase) in fuel, materials, and supplies (19,141) 10,664 126 Decrease (increase) in prepaid and other current assets 2,708 24,729 (7,209) Increase (decrease) in accounts payable 63,232 (15,710) (9,568) Increase (decrease) in other current liabilities 22,241 (2,718) 33,999 Other, net 13,481 66,678 40,455 ----------- --------- --------- Net cash provided by (used in) operating activities $ (157,197) $ 521,113 $ 522,570 ----------- --------- --------- Investing activities Proceeds from sale of generating assets $ 1,728,588 $ - $ - Plant expenditures, excluding allowance for funds used during construction (181,941) (203,095) (234,409) Oil and gas exploration and development - (13,156) (20,371) Proceeds from sale of New England Energy Incorporated oil and gas property 50,000 - - Purchase of available-for-sale securities, net (57,915) - - Other investing activities (46,718) (22,669) (10,309) ----------- --------- --------- Net cash provided by (used in) investing activities $ 1,492,014 $(238,920) $(265,089) ----------- --------- --------- Financing activities Dividends paid to minority interests $ (6,704) $ (6,809) $ (8,878) Dividends paid on NEES common shares (147,350) (152,763) (153,759) Short-term debt (251,950) 105,900 (59,862) Long-term debt - issues 55,000 25,000 97,850 Long-term debt - retirements (543,630) (142,205) (106,811) Preferred stock - redemptions (19,614) (87,221) (20,900) Premium on reacquisition of long-term debt (22,116) (2,163) - Return of capital to minority interests and related premium (3,786) (3,348) (1,633) Repurchase of common shares (221,258) (12,797) (2,075) ----------- --------- --------- Net cash provided by (used in) financing activities $(1,161,408) $(276,406) $(256,068) ----------- --------- --------- Net increase in cash and cash equivalents $ 173,409 $ 5,787 $ 1,413 Cash and cash equivalents at beginning of year 14,264 8,477 7,064 ----------- --------- --------- Cash and cash equivalents at end of year $ 187,673 $ 14,264 $ 8,477 ----------- --------- --------- Supplementary information Interest paid less amounts capitalized $ 114,316 $ 115,545 $ 119,710 ----------- --------- --------- Federal and state income taxes paid $ 399,754 $ 174,000 $ 168,255 ----------- --------- --------- Dividends received from investments at equity $ 12,387 $ 10,802 $ 12,987 ----------- --------- ---------
The accompanying notes are an integral part of these consolidated financial statements. New England Electric System and Subsidiaries Consolidated Statements of Capitalization At December 31 (thousands of dollars)
Common share equity 1998 1997 ---------- ---------- Common shares, par value $1 per share Authorized - 150,000,000 shares Issued - 64,969,652 shares $ 64,970 $ 64,970 Paid-in capital 736,744 736,605 Retained earnings 998,912 954,518 Treasury stock - 5,798,637 and 431,875 shares, respectively (237,767) (16,415) Accumulated other comprehensive income, net 7,144 4,764 ---------- ---------- Total common share equity $1,570,003 $1,744,442 ---------- ----------
Shares outstanding ------------------ Cumulative preferred stock of subsidiaries 1998 1997 1998 1997 ------- ------- ------- ------- $100 par value 4.44% to 4.76% 52,745 106,400 $ 5,275 $10,640 6.00% to 6.99% 69,672 108,690 6,967 10,869 $50 par value 4.50% to 6.95% 144,766 256,000 7,238 12,800 $25 par value 6.84% - 192,160 - 4,804 ------- ------- ------- ------- Total cumulative preferred stock of subsidiaries (annual dividend requirement of $1,091 for 1998 and $2,284 for 1997) 267,183 663,250 $19,480 $39,113 ------- ------- ------- -------
Long-term debt (Note I) Maturity Rate 1998 1997 ----------------- ----------------------- ---------- Mortgage bonds 1998 through 2000 6.040%-8.280%$ 59,000 $199,000 2002 through 2005 6.240%-8.520% 156,500 191,500 2006 through 2015 5.720%-7.250% 80,000 93,500 2021 through 2028 6.910%-9.125% 252,200 393,700 2018 through 2022 Variable - 371,850 Pollution control revenue bonds New England Power Company 2018 through 2022 Variable 371,850 - Notes Granite State Electric Company 2001 through 2028 7.300%-9.440% 20,000 15,000 Nantucket Electric Company 1998 through 2017 4.600%-8.500% 29,265 30,735 New England Energy Incorporated 1998 through 2002 Variable - 122,000 Hydro-Transmission companies 2001 through 2015 8.820%-9.410% 124,970 136,490 Narragansett Energy Resources Company 2010 7.250% - 28,640 AllEnergy Marketing Company, L.L.C. 2001 through 2003 0.000%-8.000% 1,135 - Unamortized discounts and premiums, net (2,873) (5,024) -------------------- Total long-term debt 1,092,047 1,577,391 -------------------- Long-term debt due in one year (36,307) (89,910) -------------------- $1,055,740$1,487,481 --------------------
The accompanying notes are an integral part of these consolidated financial statements. New England Electric System and Subsidiaries Statements of Consolidated Comprehensive Income At December 31 (thousands of dollars)
1998 1997 1996 -------- -------- -------- Net income $190,042 $220,038 $208,936 Other comprehensive income, net of tax: Unrealized gains, net of tax expense of $2,762, $3,053 and $0, respectively 5,466 4,731 - Less: Reclassification adjustments for realized gains/(losses) included in net income net of tax expense/(benefit) of $109, $(21), and $0, respectively 169 (33) - Minimum pension liability adjustment, net of tax expense of $1,570, $0, and $0, respectively (2,917) - - -------- -------- -------- Total comprehensive income $192,422 $224,802 $208,936 -------- -------- --------
The accompanying notes are an integral part of these consolidated financial statements. Notes New England Electric System and Subsidiaries Notes to Consolidated Financial Statements Note A - Significant Accounting Policies 1. Nature of operations New England Electric System (NEES) is a public utility holding company headquartered in Westborough, Massachusetts. NEES' regulated subsidiaries are engaged in the transmission, distribution, and sale of electricity. NEES' electricity distribution subsidiaries serve 1.4 million customers in Massachusetts, Rhode Island, and New Hampshir. Unregulated subsidiaries are engaged in the marketing of energy commodities and services and the construction and leasing of telecommunications infrastructure. The NEES system provides electric service to distribution customers through separate distribution subsidiaries: Massachusetts Electric Company (Massachusetts Electric) and Nantucket Electric Company (Nantucket Electric), which operate in Massachusetts; The Narragansett Electric Company (Narragansett Electric), which operates in Rhode Island; and Granite State Electric Company (Granite State Electric), which operates in New Hampshire. 2. Basis of consolidation and financial statement presentation The consolidated financial statements include the accounts of NEES and all subsidiaries except New England Electric Transmission Corporation, which is recorded under the equity method. Presentation of this subsidiary on the equity basis is not material to the consolidated financial statements. New England Power Company (NEP) has a minority interest in four regional nuclear generating companies (Yankees). NEP accounts for these ownership interests under the equity method. During 1997, NEES increased its ownership from 50 percent to 100 percent of AllEnergy Marketing Company, L.L.C. (AllEnergy), an energy marketing enterprise. NEES owns 50.4 percent of the outstanding common stock of both New England Hydro-Transmission Electric Company, Inc. and New England Hydro-Transmission Corporation (Hydro-Transmission companies). The consolidated financial statements include 100 percent of the assets, liabilities, and earnings of the Hydro-Transmission companies. Minority interests, which represent the minority stockholders' proportionate share of the equity and income of the Hydro-Transmission companies, have been separately disclosed on the NEES consolidated balance sheets and income statements. NEP is also a 12 percent and 10 percent joint owner, respectively, of the Millstone 3 and Seabrook 1 nuclear generating units, each 1,150 megawatts (MW). NEP's share of the related expenses for these units is included in "Operating expenses." The accounts of NEES and its utility subsidiaries are maintained in accordance with the Uniform System of Accounts prescribed by regulatory bodies having jurisdiction. All significant intercompany transactions between consolidated subsidiaries have been eliminated. In preparing the financial statements, management is required to make estimates that affect the reported amounts of assets and liabilities and disclosures of asset recovery and contingent liabilities as of the date of the balance sheets, and revenues and expenses for the period. These estimates may differ from actual amounts if future circumstances cause a change in the assumptions used to calculate these estimates. 3. Electric sales revenue All of NEES' distribution subsidiaries accrue revenues for electricity delivered but not yet billed (unbilled revenues), with the exception of Granite State Electric. Accrued revenues were also recorded in accordance with rate adjustment mechanisms, which included Massachusetts Electric's and Nantucket Electric's purchased power cost adjustment (PPCA) mechanisms. Upon approval of the Massachusetts Settlement in November 1997, the PPCA mechanisms were eliminated as of July 31, 1996. Pending final approval of the settlement, Massachusetts Electric and Nantucket Electric had accrued refund reserves of $9 million for the last five months of 1996 and an additional $9 million in the first nine months of 1997. Upon final approval of the settlement, these refund reserves were reversed in the fourth quarter of 1997. 4. Allowance for funds used during construction (AFDC) The utility subsidiaries capitalize AFDC as part of construction costs. AFDC represents the composite interest and equity costs of capital funds used to finance that portion of construction costs not yet eligible for inclusion in rate base. AFDC is capitalized in "Utility plant" with offsetting noncash credits to "Other income" and "Interest." This method is in accordance with an established rate-making practice under which a utility is permitted a return on, and the recovery of, prudently incurred capital costs through their ultimate inclusion in rate base and in the provision for depreciation. 5. Depreciation and amortization The depreciation and amortization expense included in the statements of consolidated income is composed of the following:
Year ended December 31 (thousands of dollars) 1998 1997 1996 -------- -------- -------- Depreciation - transmission and distribution related $112,254 $ 99,114 $ 93,897 Depreciation - all other 53,293 72,896 77,296 Nuclear decommissioning costs (see Note E-4) 2,719 2,638 2,629 Amortization: Oil and gas properties (see Note A-6) - 46,718 49,163 Investment in Seabrook 1 pursuant to rate settlement - - 15,210 Seabrook 2 property losses - 113 6,280 Millstone 3 accelerated amortization, pursuant to 1995 rate settlement 22,040 15,013 1,904 Regulatory assets covered by CTC (see Note C) 16,356 - - -------- -------- -------- Total depreciation and amortization expense $206,662 $236,492 $246,379 -------- -------- --------
Depreciation is provided annually on a straight-line basis. The provision for depreciation as a percentage of weighted average depreciable transmission and distribution property was 3.4 percent in 1998, 3.2 percent in 1997, and 3.1 percent in 1996. In 1996, New England Energy Incorporated (NEEI), a wholly owned subsidiary of NEES, reduced amortization expense of its oil and gas properties by $13 million to correct amounts recorded in the years 1990 through 1996. Amortization of Seabrook and Millstone 3 investments above normal depreciation accruals was in accordance with rate settlement agreements. 6. Oil and gas investments NEEI participated in a rate-regulated domestic oil and gas exploration, development, and production program through a partnership with a nonaffiliated oil company. Losses from this program, calculated under the full cost method of accounting, have been charged to NEP, and ultimately to distribution customers, in accordance with Securities and Exchange Commission (SEC) and Federal Energy Regulatory Commission (FERC) approvals. Such losses were $11 million and $22 million in 1997 and 1996, respectively. In February 1998, NEEI sold its oil and gas properties for $50 million. NEEI's loss on the sale of approximately $120 million, before tax, has been reimbursed by NEP, and is being recovered through contract termination charges (CTC). See Note C for a discussion of regulatory asset recovery. 7. Cash NEES and its subsidiaries classify short-term investments with an original maturity of 90 days or less as cash. 8. Marketable securities At December 31, 1998, marketable securities consist primarily of corporate debt, mortgage-backed government securities, and collateralized mortgage obligations. Marketable securities have been categorized as available-for-sale and, as a result, are carried at fair value, based generally on quoted market prices. At December 31, 1998, NEES had marketable securities with a fair value of approximately $58 million. Fair value closely approximated cost. Marketable securities are available for current operations and are classified as current assets, and have contractual maturities of less than two years. During 1998, the proceeds received from the sales of securities held as available-for-sale totaled approximately $64 million, which resulted in immaterial realized gains and losses. 9. Average common shares The following table summarizes the reconciling amounts between basic and diluted earnings per share (EPS) computations, in compliance with Statement of Financial Accounting Standards No. 128, Earnings per Share, which became effective during 1997, and requires restatement for all prior-period EPS data presented.
Year ended December 31 1998 1997 1996 -------- -------- -------- Income after interest and minority interest (000s) $193,496 $232,357 $215,399 Less: preferred stock dividends and net gain/loss on reacquisition of preferred stock of subsidiaries (000s) $ 3,454 $ 12,319 $ 6,463 Income available to common shareholders (000s) $190,042 $220,038 $208,936 Basic EPS $ 3.05 $ 3.39 $ 3.22 Diluted EPS $ 3.04 $ 3.39 $ 3.22 -------- -------- -------- Average common shares outstanding for Basic EPS 62,359,122 64,899,322 64,960,496 Effect of Dilutive Securities Average potential common shares related to share-based compensation plans 96,981 52,863 25,640 ---------- ---------- ---------- Average common shares outstanding for Diluted EPS 62,456,103 64,952,185 64,986,136 ---------- ---------- ----------
10. New accounting standards In 1997, the Financial Accounting Standards Board (FASB) released Statement of Financial Accounting Standards No. 131, Disclosure about Segments of an Enterprise and Related Information (FAS 131), which went into effect in 1998. FAS 131 requires the reporting in financial statements of certain new additional information about operating segments of a business. FAS 131 does not currently impact NEES' reporting requirements. In February 1998, the FASB issued Statement of Financial Accounting Standards No. 132, Employers' Disclosures about Pensions and Other Postretirement Benefits (FAS 132), which revises disclosure requirements for pension and other postretirement benefits. NEES has adopted FAS 132 in its financial statements for the year ending December 31, 1998. The adoption of FAS 131 and FAS 132 has no impact on NEES' operating results, financial position, or cash flows. 11. Derivative instruments NEES, through its wholly owned indirect subsidiary, AllEnergy, uses derivative instruments to manage exposure in fluctuations in commodity prices. At this time, AllEnergy uses derivative instruments to manage risks associated with natural gas, propane, and oil prices. Hedge criteria used and accounting for hedge transactions are in accordance with Statement of Financial Accounting Standards No. 80, Accounting for Futures Contracts (FAS 80). FAS 80 states that in order to qualify as a hedge, price movements in commodity derivatives must be highly correlated with the underlying hedged commodity and must reduce exposure to market fluctuations throughout the hedged period. Any gain or loss on a derivative that qualifies as a hedge under FAS 80 is deferred until recognized in the income statement in the same period as the hedged item is recognized in the income statement. In June 1998, the FASB 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 requires recognition of all derivatives as either assets or liabilities on the balance sheet and requires measurement of those instruments at fair value. If certain conditions are met, derivatives may be treated as hedges and accounted for in the income statement in the same manner as under FAS 80. To the extent these conditions are not met, that portion of the gain or loss is reported in earnings immediately. FAS 133 is effective for fiscal years beginning after June 15, 1999. As of December 31, 1998, all of AllEnergy's derivative instruments qualified as hedges under FAS 80, with limited exceptions, and are expected to qualify as hedges under FAS 133. The derivative instruments that do not qualify as hedges under FAS 80 and are recognized in income immediately are immaterial to NEES. Note B - Merger Agreements Merger Agreement with National Grid On December 11, 1998, NEES, The National Grid Group plc (National Grid), and NGG Holdings LLC (Holdings), a directly and indirectly wholly owned subsidiary of National Grid, entered into an Agreement and Plan of Merger (Merger Agreement). Pursuant to the Merger Agreement, Holdings will merge with and into NEES (the Merger), with NEES becoming a wholly owned subsidiary of National Grid. NEES shareholders will receive $53.75 per share in cash, which will be increased at a rate of $.003288 each day beginning six months after shareholder approval of the Merger until the Merger is completed, up to a maximum price of $54.35 per share. The Merger is subject to approval by a majority vote of NEES shareholders as well as National Grid shareholder approval. In addition, the Merger is subject to a number of regulatory and other approvals and consents, including approvals by the SEC, FERC, and Nuclear Regulatory Commission (NRC), support or approval from the states in which NEES operates, and approval under both the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended, and the Exon-Florio Provisions of the Omnibus Trade and Competitiveness Act of 1988. National Grid has obtained governmental clearance in the United Kingdom for the Merger. The Merger is expected to be completed by early 2000. Merger Agreement with Eastern Utilities Associates On February 1, 1999, NEES, Eastern Utilities Associates (EUA), and Research Drive LLC (Research Drive), a directly and indirectly wholly owned subsidiary of NEES, entered into an Agreement and Plan of Merger (EUA Agreement). Pursuant to the EUA Agreement, Research Drive will merge with and into EUA, with EUA becoming a wholly owned subsidiary of NEES. EUA shareholders will receive $31.00 per share in cash, which will be increased at a rate of $.003 each day beginning six months after EUA shareholder approval of the EUA acquisition until the acquisition is completed or until April 30, 2000, whichever is earlier. The acquisition of EUA is subject to approval by a two-thirds vote of EUA shareholders. In addition, the acquisition is subject to a number of regulatory and other approvals and consents, including approvals by the SEC, FERC, and NRC, support or approval from the states in which EUA operates, and approval under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended. The EUA acquisition is expected to be completed by early 2000. Note C - Industry Restructuring During 1998, pursuant to legislation enacted in Massachusetts, Rhode Island, and New Hampshire, and settlement agreements approved by state and federal regulators (the Settlement Agreements), all NEES customers were provided the right to purchase electricity from the power supplier of their choice. Customers who do not choose a power supplier are able, for a period of time, to continue to purchase their electricity from the NEES companies at a transition rate ("standard offer generation service") which, when combined with delivery charges, results in total rate reductions ranging from 8 to 24 percent compared with rates that had been in effect prior to the introduction of customer choice. Substantially all of the obligations of the NEES companies to provide standard offer generation service are backed by contracts with USGen New England, Inc. (USGen), an indirect wholly owned subsidiary of PG&E Corporation, and other power suppliers. The Settlement Agreements provide that the costs of NEP's generating investments and related contractual commitments that were not recovered from the divestiture of those investments ("stranded costs"), are to be recovered from NEP's wholesale customers through CTCs. The affiliated wholesale customers, in turn, are recovering those costs through their delivery charges to distribution customers. Under the Settlement Agreements, the recovery of NEP's stranded costs is divided into several categories. Unrecovered costs associated with generating plants (nuclear and nonnuclear) and most regulatory assets will be fully recovered through the CTC by the end of 2000 and earn a return on equity averaging 9.7 percent. NEP's obligation relating to the above-market cost of purchased power contracts and nuclear decommissioning costs are recovered through the CTC over a longer period of time, as such costs are actually incurred. 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 completion of the sale of NEP's nonnuclear generating business. As the CTC rate declines, NEP, under certain of the Settlement Agreements, earns incentives based on successful mitigation of its stranded costs. These incentives supplement NEP's return on equity. Finally, the Settlement Agreements provide that until such time as NEP divests its operating nuclear interests, NEP will share with customers, through the CTC, 80 percent of the revenues and operating costs related to the units, with shareholders retaining the balance. Accounting Implications 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 Financial 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. NEP has received authorization from the FERC to recover through the 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 NEP's business, including the recovery of its stranded costs, remains under cost-based rate regulation. Under existing ratemaking practices, NEES' distribution companies will have the ability to recover through rates their specific costs of providing ongoing distribution services. NEES believes these factors and the EITF conclusion allow its principal utility subsidiaries to continue to apply FAS 71. Because of the nuclear cost-sharing provisions related to NEP's CTC, NEP ceased applying FAS 71 in 1997 to 20 percent of its ongoing nuclear operations, the impact of which is immaterial. Currently, there is much regulatory and other movement toward establishing performance-based rates. It is possible that the adoption of performance-based rates, future regulatory rules, or other circumstances could cause the application of FAS 71 to be discontinued. This discontinuation would result in a noncash write-off of previously established regulatory assets, including those being recovered through NEP's CTC. In addition, reserves for depreciation may also have to be increased to comply with unregulated accounting practices. As a result of applying FAS 71, NEES 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 NEP's nonnuclear generating business. At December 31, 1998, the regulatory asset related to the CTC was approximately $1.5 billion, of which $1.2 billion related to the above-market costs of purchased power contracts. All but approximately $60 million of total net regulatory assets are recoverable under NEP's CTC. These costs relate primarily to NEES' distribution subsidiaries and consist primarily of $48 million of deferred FAS 109 costs (see Note G), and $23 million of unamortized loss on reacquired debt, partially offset by net regulatory liabilities classified in current assets and liabilities. As described above, the CTC regulatory asset includes the unrecovered plant costs associated with NEP's interest in operating nuclear plants. This balance sheet treatment is due to NEP's conclusion that its interests in the Millstone 3 and Seabrook 1 nuclear generating units have little, if any, market value. Three proposed sales of nuclear units by other utilities have required the seller to set aside amounts for decommissioning in excess of the proceeds from the sale of the units. Two of these proposed sales were agreed upon prior to the end of the third quarter of 1998. As a result, at the end of the third quarter of 1998, NEP recorded an impairment writedown in its reserve for depreciation of approximately $390 million, which represents the net book value at December 31, 1995, less applicable depreciation subsequent to that date, of Millstone 3 and Seabrook 1. Because the Settlement Agreements permit NEP to recover its pre-1996 investment as well as decommissioning expenses through the CTC, NEP established a regulatory asset in an amount equal to the impairment writedown. Should NEP's efforts to sell its nuclear interests result in a gain over the amounts remaining in the plant account, such gain will be credited to customers through the CTC. Note D - Divestiture of Generating Business On September 1, 1998, NEES subsidiaries NEP and Narragansett Electric (collectively, the Sellers) completed the sale of substantially all of their nonnuclear generating business to USGen. The assets sold include three fossil-fueled and 15 hydroelectric generating stations, totaling approximately 4,000 MW of capacity, as well as NEES' 100 percent interest in Narragansett Energy Resources Company, a 20 percent general partner in the Ocean State Power project, all of which had a book value of approximately $1.1 billion. The NEES companies received $1.59 billion for the sale. The gain on the sale is passed on to customers as a reduction in CTCs, as described in Note C above. In addition, the NEES companies were reimbursed approximately $140 million for costs associated with early retirements and special severance programs for employees affected by industry restructuring, and the value of inventories. USGen assumed responsibility for environmental conditions at the Sellers' nonnuclear generating stations. USGen also assumed the Sellers' obligations under long-term fuel and fuel transportation contracts, and certain collective bargaining agreements. As part of the sale, NEP also signed a purchased power transfer agreement through which USGen purchased NEP's entitlement to approximately 1,100 MW of power procured under long-term contracts in exchange for monthly fixed payments by NEP averaging $9.5 million per month through January 2008 (having a net present value of $833 million) toward the above-market cost of those contracts. In some cases, these transfers involved formal assignment of the contracts to USGen and a release of NEP from further obligations to the power supplier, while others did not. For those that involved formal assignment, NEP was required to make a lump sum payment equivalent to the present value of the monthly fixed payment obligations of those contracts. On or prior to the closing date, NEP made lump sum payments totaling approximately $340 million and was released from further obligations relating to two of the contracts. These lump sum payments are separate from the $833 million figure referred to above. USGen is responsible for the balance of the costs under the purchased power contracts. The present value of the future monthly fixed payments is recorded as a liability on the balance sheet. This liability, as well as the lump sum payments previously made, net of amortization, are also recorded as a regulatory asset on the balance sheet. As part of the divestiture plan, in February 1998, NEEI sold its oil and gas properties for approximately $50 million. NEEI's loss on the sale of approximately $120 million, before tax, has been reimbursed by NEP. In addition, NEP agreed under the Settlement Agreements to endeavor to sell its minority interest in three nuclear power plants and a 60 MW interest in a fossil-fueled generating station in Maine. Note E - Commitments and Contingencies 1. Plant expenditures The NEES subsidiaries' cash expenditures for utility plant and investments by NEES' unregulated subsidiaries are estimated to be $280 million in 1999. At December 31, 1998, substantial commitments had been made relative to future planned expenditures. 2. Long-term contracts for the purchase of electricity Historically, NEP purchased a portion of its electricity requirements pursuant to long-term contracts with owners of various generating units. These contracts expire in various years from 1998 to 2029. See Note D for a discussion of USGen's purchase of NEP's entitlement to approximately 1,100 MW of power procured under long-term contracts. NEP retained one purchased power contract, with Vermont Yankee, which requires minimum fixed payments, even when the supplier is unable to deliver power, to cover a proportionate share of the capital and fixed operating costs of the unit. This contract has fixed payment requirements of approximately $35 million in 1999, $30 million in 2000, $35 million in 2001 and 2002, $30 million in 2003, and approximately $300 million thereafter. NEP holds an ownership interest in Vermont Yankee. 3. 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. NEES subsidiaries currently have 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. NEES and/or its subsidiaries have been named as potentially responsible parties (PRPs) by either the United States Environmental Protection Agency or the Massachusetts Department of Environmental Protection for 20 sites at which hazardous waste is alleged to have been disposed. Private parties have also contacted or initiated legal proceedings against NEES and certain subsidiaries regarding hazardous waste cleanup. The most prevalent types of hazardous waste sites with which NEES and its subsidiaries have been associated are manufactured gas locations. (Until the early 1970s, NEES was a combined electric and gas holding company system.) NEES is aware of approximately 40 such manufactured gas locations, including 10 for which the NEES companies have been identified by either federal or state regulatory agencies as PRPs, mostly located in Massachusetts. NEES has reported the existence of all manufactured gas locations of which it is aware to state environmental regulatory agencies. NEES is engaged in various phases of investigation and remediation work at approximately 20 of the manufactured gas locations. NEES and its subsidiaries are 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. In 1993, the Massachusetts Department of Public Utilities approved a settlement agreement that provides for the rate recovery of remediation costs of former manufactured gas sites and certain other hazardous waste sites located in Massachusetts. Under that agreement, qualified costs related to these sites are paid out of a special fund established on Massachusetts Electric's books. Rate-recoverable contributions of $3 million, adjusted since 1993 for inflation, are added annually to the fund along with interest, lease payments, and any recoveries from insurance carriers and other third parties. At December 31, 1998, the fund had a balance of $47 million. 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 NEES or its subsidiaries. The 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. At December 31, 1998, NEES had total reserves for environmental response costs of $53 million, which includes reserves established in connection with the Massachusetts Electric hazardous waste fund referred to above. NEES believes that hazardous waste liabilities for all sites of which it is aware, and which are not covered by a rate agreement, are not material to its financial position. 4. Nuclear units Nuclear Units Permanently Shut Down Three regional nuclear generating companies in which NEP 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 6 Feb 1992 24 Connecticut Yankee 15 16 Dec 1996 75 Maine Yankee 20 16 Aug 1997 143
In the case of each of these units, NEP has recorded a liability and an offsetting regulatory asset reflecting the estimated future billings from the companies. In a 1993 decision, the FERC allowed Yankee Atomic to recover its undepreciated investment in the plant 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, NEP, 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, NEP'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. NEP's industry restructuring settlements allow it to recover all costs that the FERC allows these Yankee companies to bill to NEP. NEP 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 NEP, 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 NEP 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 NRC scrutiny. NEP performs periodic economic viability reviews of operating nuclear units in which it holds ownership interests. Millstone 3 In July 1998, Millstone 3 returned to full operation after being shut down since April 1996. Millstone 3 remains on the NRC "Watch List," signifying that it continues to warrant increased NRC attention. Millstone 3 is operated by a subsidiary of Northeast Utilities (NU). NEP is not an owner of the Millstone 2 nuclear generating unit, which is temporarily shut down under NRC orders, or the Millstone 1 nuclear generating unit, which has been permanently shut down. A criminal investigation related to Millstone 3 is ongoing. In August 1997, NEP sued NU in Massachusetts Superior Court for damages resulting from the tortious conduct of NU that caused the shutdown of Millstone 3. NEP'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 NEP's incremental replacement power costs have been recovered from customers, either through fuel adjustment clauses or through provisions in the Settlement Agreements. NEP also seeks punitive damages. NEP 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 NEP 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. NEP subsequently amended its complaint by, among other things, adding NU's Trustees as defendants. In December 1998, NU moved for summary judgement. NEP'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 NEP 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. NEP records decommissioning costs on its books consistent with its rate recovery. NEP is recovering its share of projected decommissioning costs for Millstone 3 and Seabrook 1 through depreciation expense. In addition, NEP 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 NEP 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. NEP 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 NEP 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, NEP recovered this fee through its fuel clause. Under the Settlement Agreements, substantially all of these costs are recovered through CTCs. Similar costs are billed to NEP 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 NEP 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. Decommissioning Trust Funds Each nuclear unit in which NEP has an ownership interest has established a decommissioning trust fund or escrow fund into which payments are being made to meet the projected costs of decommissioning. The table below lists information on each operating nuclear plant in which NEP has an ownership interest.
NEP's share of (millions of dollars) ------------------------------------------- Nep's Estimated Decommissioning Ownership Net Decommissioning Fund License Unit Interest (%) Plant Assets Cost (in 1998 $) Balances* Expiration - ---- -------------------------------------- ---------- ---------- Vermont Yankee 20 34 105 38 2012 Millstone 3 12 9** 67 21 2025 Seabrook 1 10 15** 50 10 2026 * Certain additional amounts are anticipated to be available through tax deductions. ** Represents post-December 1995 spending. See Note C for a discussion of an impairment writedown and establishment of an offsetting regulatory asset.
There is no assurance that decommissioning costs actually incurred by Vermont Yankee, Millstone 3, or Seabrook 1 will not substantially exceed these amounts. For example, decommissioning cost estimates assume the availability of permanent repositories for both low-level and high-level nuclear waste; those repositories do not currently exist. The temporary low-level repository located in Barnwell, South Carolina may become unavailable, which could increase the cost of decommissioning the Yankee Atomic, Connecticut Yankee, and Maine Yankee plants. If any of the operating units were shut down prior to the end of their operating licenses, which NEP believes is likely, the funds collected for decommissioning to that point would be insufficient. Under the Settlement Agreements discussed in Note C, NEP will recover decommissioning costs through CTCs. Nuclear Insurance The Price-Anderson Act limits the amount of liability claims that would have to be paid in the event of a single incident at a nuclear plant to $9.7 billion (based upon 108 licensed reactors). The maximum amount of commercially available insurance coverage to pay such claims is $200 million. The remaining $9.5 billion would be provided by an assessment of up to $88.1 million per incident levied on each of the participating nuclear units in the United States, subject to a maximum assessment of $10 million per incident per nuclear unit in any year. The maximum assessment, which was most recently adjusted in 1998, is adjusted for inflation at least every five years. NEP's current interest in Vermont Yankee, Millstone 3, and Seabrook 1 would subject NEP to a $35.4 million maximum assessment per incident. NEP's payment of any such assessment would be limited to a maximum of $4.0 million per year. As a result of the permanent cessation of power operation of the Yankee Atomic, Connecticut Yankee, and Maine Yankee plants, these units have received from the NRC an exemption from participating in the secondary financial protection system under the Price-Anderson Act. However, these plants must continue to maintain $100 million of commercially available nuclear liability insurance coverage. Each of the nuclear units in which NEP has either an ownership or purchased power interest also carries nuclear property insurance to cover the costs of property damage, decontamination, and premature decommissioning resulting from a nuclear incident. These policies may require additional premium assessments if losses relating to nuclear incidents at units covered by this insurance occur in a prior six-year period. NEP's maximum potential exposure for these assessments, either directly or indirectly, is approximately $4.6 million with respect to the current policy period. 5. 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 NEP. NEP had been a wholesale power supplier for Norwood pursuant to rates approved by the FERC. In the lawsuit, Norwood had alleged that NEP'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 NEP's motion for dismissal on the grounds that the contract did not require NEP 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 1998, Norwood gave notice of its intent to terminate its contract with NEP, without accepting responsibility for its share of NEP's stranded costs, and began taking power from another supplier commencing in April 1998. In May 1998, the FERC ruled that NEP could assess a CTC to any of NEP'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. NEP's billings to Norwood for this charge through December 1998 have been approximately $6 million, which remain unpaid. NEP 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. Norwood also appealed the FERC's orders approving the divestiture and the Massachusetts and Rhode Island industry restructuring settlement agreements (including modification of NEP's contracts with Massachusetts Electric and Narragansett Electric) 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 NEP's sale of its hydroelectric facilities. The case is to be fully briefed by May 1999. Note F - Employee Benefits Pension Plans The NEES companies' retirement plans are noncontributory defined-benefit plans covering substantially all employees. The plans provide pension benefits based on the employee's compensation during the five years prior to retirement. Absent unusual circumstances, the NEES companies' funding policy is to contribute each year the net periodic pension cost for that year. However, the contribution for any year will not be less than the minimum contribution required by federal law or greater than the maximum tax deductible amount. The plans' funded status at December 31, 1998 and 1997 were calculated using the assumed rates from 1999 and 1998, respectively, and the 1983 Group Annuity Mortality table. Plan assets are composed primarily of corporate equity, debt securities, and cash equivalents. In addition to its regular pension funds shown in the table below, NEES and its subsidiaries have a separate trust fund, commonly referred to as a Rabbi Trust, for certain supplemental pensions and deferred compensation for key executives and employees. The Rabbi Trust is currently invested in municipal bonds, equities, and NEES common shares. At December 31, 1998 and 1997, the Rabbi Trust held 184,233 and 148,875 NEES common shares, respectively, which are accounted for as treasury stock. At the end of 1998 and 1997, the difference between cost and the market value of investments, other than NEES shares, in the Rabbi Trust was approximately $10.1 million, after tax, and $4.8 million, after tax, respectively. These amounts represent unrealized gains in Rabbi Trust investments. The market value of such external investments was $64 million and $53 million at December 31, 1998 and 1997, respectively. Postretirement Benefit Plans Other than Pensions (PBOPs) The NEES subsidiaries provide health care and life insurance coverage to eligible retired employees. Eligibility is based on certain age and length of service requirements and in some cases retirees must contribute to the cost of their coverage. The plans' funded status at December 31, 1998 and 1997 were calculated using the assumed rates in effect for 1999 and 1998, respectively. The assumptions used in the health care cost trends have a significant effect on the amounts reported. A one percentage point change in the assumed rates would increase the accumulated postretirement benefit obligation (APBO) as of December 31, 1998 by approximately $43 million or decrease APBO by approximately $39 million, and change the net periodic cost for 1998 by approximately $4 million. The NEES subsidiaries fund the annual tax-deductible contributions. Plan assets are invested in equity and debt securities and cash equivalents. Net pension cost and total cost of PBOPs for 1998, 1997, and 1996 included the following components:
Postretirement Benefits Pensions Other than Pensions - ----------------------------------------------------------------------------------------- Year ended December 31 1998 1997 1996 1998 1997 1996 (thousands of dollars) - ----------------------------------------------------------------------------------------- Service cost - benefits earned during the period $ 14,903$ 15,019 $ 14,918 $ 6,397 $ 6,527 $ 6,794 Plus (less): Interest cost on projected benefit obligation 55,210 52,497 51,461 23,611 24,249 24,667 Return on plan assets at expected long-term rate (60,235)(55,606) (52,085) (18,916) (16,397)(12,958) Amortization of transition obligation (788) (766) (766) 16,897 18,397 18,397 Amortization of prior service cost 1,109 1,629 1,624 57 61 61 Amortization of net (gain)/loss 1,889 717 2,029 (7,843) (7,348) (5,359) Curtailment (gain)/loss (9,300) - - 56,124 - - - ----------------------------------------------------------------------------------------- Benefit cost $ 2,788$ 13,490 $ 17,181 $ 76,327 $ 25,489$ 31,602 - ----------------------------------------------------------------------------------------- Special termination benefits not included above$ 63,980$ - $ - $ 4,335 $ -$ - - -----------------------------------------------------------------------------------------
The following table sets forth benefits earned and the plans' funded status:
Postretirement Benefits Pension Other than Pensions - ----------------------------------------------------------------------------- At December 31 1998 1997 1998 1997 (millions of dollars) - ----------------------------------------------------------------------------- Benefit obligation $843 $819 $365 $348 Unrecognized prior service costs (6) (8) (1) (1) Transition liability not yet recognized (amortized) (2) (4) (194) (276) Additional minimum liability 7 4 - - - ----------------------------------------------------------------------------- 842 811 170 71 - ----------------------------------------------------------------------------- Plan assets at fair value 837 834 258 239 Transition asset not yet recognized (amortized) (6) (8) - - Net (gain) not yet recognized (amortized) (92) (52) (151) (153) - ----------------------------------------------------------------------------- 739 774 107 86 - ----------------------------------------------------------------------------- Accrued pension/(prepaid) payments recorded on books $103 $ 37 $ 63 $(15) - -----------------------------------------------------------------------------
The following provides a reconciliation of benefit obligations and plan assets:
Pension Postretirement Benefits Benefits Other than Pensions -------------------------------------- (millions of dollars) 1998 1997 1998 1997 ---- ---- ---- ---- Changes in benefit obligation Benefit obligation at January 1 $819 $807 $348 $369 Service cost 14 15 6 7 Interest cost 55 53 24 24 Actuarial (gain)/loss (5) 59 8 (38) Benefits paid from plan assets (94) (47) (16) (14) Special termination benefits 64 - 4 - Curtailment (11) - (9) - Plan Amendments 1 - - - Dispositions (Yankee Atomic) - (68) - - ---- ---- ---- ---- Benefit obligation at December 31 $843 $819 $365 $348 ---- ---- ---- ---- Reconciliation of change in plan assets Fair value of plan assets at January 1 $834 $812 $239 $202 Actual return on plan assets during year 93 130 33 38 Company contributions 4 8 2 13 Benefits paid from plan assets (94) (47) (16) (14) Dispositions (Yankee Atomic) - (69) - - ---- ---- ---- ---- Fair value of plan assets at December 31 $837 $834 $258 $239 ---- ---- ---- ----
Pension plans with benefit obligations in excess of the fair value of plan assets had aggregate benefit obligations of $66 million and $62 million and plan assets with a fair value of $0 and $0 at December 31, 1998 and 1997, respectively. All PBOP plans for 1998 and 1997 had aggregate benefit obligations in excess of the fair value of plan assets, the amounts of which are disclosed in the table above.
Year ended December 31 1999 1998 1997 1996 ---- ---- ---- ---- Assumptions used to determine pension cost: Discount rate 6.75% 6.75% 7.25% 7.25% Average rate of increase in future compensation levels 4.13% 4.13% 4.13% 4.13% Expected long-term rate of return on assets 8.50% 8.50% 8.50% 8.50% Assumptions used to determine postretirement benefit cost: Discount rate 6.75% 6.75% 7.25% 7.25% Expected long-term rate of return on assets 8.25% 8.25% 8.25% 8.25% Health care cost rate - 1996 to 1999 5.25% 5.25% 8.00% 8.00% Health care cost rate - 2000 to 2004 5.25% 5.25% 6.25% 6.25% Health care cost rate - 2005 and beyond 5.25% 5.25% 5.25% 5.25%
Early retirement and special severance programs In 1998, NEES subsidiary companies offered a voluntary early retirement program to all employees who were at least 55 years old with 10 years of service. This program was part of an organizational review with the goal of streamlining operations and reducing the work force to reflect the sale of the nonnuclear generating business. The early retirement offer was accepted by 758 employees. A special severance program was also utilized in 1998 for employees affected by the organizational restructuring, but who were not eligible for, or did not accept, the early retirement offer. The cost of these programs was in part reimbursed by USGen at the closing of the sale of the nonnuclear generating business and will be recovered in part from customers as a component of stranded cost recovery. Stock-based compensation At December 31, 1998, NEES has three stock-based compensation plans and measures its compensation cost for those plans using the method of accounting prescribed by Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees, and related interpretations. The compensation cost charged against income for these plans was $6.1 million, $3.3 million, and $3.7 million for 1998, 1997, and 1996, respectively. If compensation cost for stock-based compensation had been accounted for under Statement of Financial Accounting Standards No. 123, Accounting for Stock-Based Compensation, the cost figures shown above would have been decreased, before taxes, by approximately $1 million and $300,000 in 1998 and 1997, respectively, and had no impact on earnings in 1996. These changes would have increased earnings per average diluted common share by $.01 in 1998, and had no impact on earnings per share in 1997 and 1996. Note G - Income Taxes Total income taxes in the statements of consolidated income are as follows:
Year ended December 31 (thousands of dollars) 1998 1997 1996 -------- -------- -------- Income taxes charged to operations $122,354 $152,024 $139,199 Income taxes charged to "Other income" (18,936) (7,268) (3,018) -------- -------- -------- Total income taxes $103,418 $144,756 $136,181 -------- -------- --------
Total income taxes, as shown above, consist of the following components:
Year ended December 31 (thousands of dollars) 1998 1997 1996 -------- -------- -------- Current income taxes $376,866 $175,934 $166,509 Deferred income taxes (248,722) (29,260) (28,652) Investment tax credits, net (24,726) (1,918) (1,676) -------- -------- -------- Total income taxes $103,418 $144,756 $136,181 -------- -------- --------
Total income taxes, as shown above, consist of federal and state components as follows:
Year ended December 31 (thousands of dollars) 1998 1997 1996 -------- -------- -------- Federal income taxes $ 81,963 $118,317 $111,573 State income taxes 21,455 26,439 24,608 -------- -------- -------- Total income taxes $103,418 $144,756 $136,181 -------- -------- --------
Investment tax credits (ITC) of subsidiaries are deferred and amortized over the estimated lives of the property giving rise to the credits. Although ITC were generally eliminated by the 1986 tax legislation, additional carryforward amounts continue to be recognized. The increase in amortization of ITC in 1998 results from the recognition in income of unamortized ITC relating to the generating assets divested during 1998. With regulatory approval, the subsidiaries have adopted comprehensive interperiod tax allocation (normalization) for temporary book/tax differences. Total income taxes differ from the amounts computed by applying the federal statutory tax rates to income before taxes. The reasons for the differences are as follows:
Year ended December 31 (thousands of dollars) 1998 1997 1996 -------- -------- -------- Computed tax at statutory rate $103,920 $131,989 $123,053 Increases (reductions) in tax resulting from: Amortization of ITC, net (18,682) (4,469) (4,347) State income tax, net of federal income tax benefit 13,946 17,185 15,995 All other differences 4,234 51 1,480 -------- -------- -------- Total income taxes $103,418 $144,756 $136,181 -------- -------- --------
The following table identifies the major components of total deferred income taxes:
At December 31 (millions of dollars) 1998 1997 ------ ------ Deferred tax asset: Plant related $ 88 $ 99 ITC 28 39 All other 118 152 ------ ------ 234 290 ------ ------ Deferred tax liability: Plant related (384) (821) Equity AFDC (38) (51) All other (284) (138) ------ ------ (706) (1,010) ------ ------ Net deferred tax liability $ (472) $ (720) ------ ------
There were no valuation allowances for deferred tax assets deemed necessary. Federal income tax returns for NEES and its subsidiaries have been examined and reported on by the Internal Revenue Service through 1993. Note H - Short-Term Borrowings and Other Current Liabilities At December 31, 1998, NEES and its consolidated subsidiaries had lines of credit and standby bond purchase facilities with banks totaling approximately $900 million. These lines and facilities were used at December 31, 1998 for liquidity support for $372 million of NEP bonds in tax-exempt commercial paper mode (see Note I). Fees are paid on the lines and facilities in lieu of compensating balances. The components of other current liabilities are as follows:
At December 31 (thousands of dollars) 1998 1997 -------- -------- Accrued wages and benefits $ 23,875 $ 58,281 Rate adjustment mechanisms 79,952 27,152 Customer deposits 10,999 11,059 Other 28,149 23,510 -------- -------- $142,975 $120,002 -------- --------
Note I - Long-Term Debt Substantially all of the properties of Massachusetts Electric and Narragansett Electric are subject to the lien of mortgage indentures under which mortgage bonds have been issued. The aggregate payments to retire maturing long-term debt are as follows:
(thousands of dollars) 1999 2000 2001 2002 2003 ------- ------- ------- ------- ------- Maturing long-term debt $24,480 $37,485 $ 6,495 $41,500 $54,010 Mandatory prepayments 11,827 11,825 11,095 10,593 10,510 ------- ------- ------- ------- ------- Total $36,307 $49,310 $17,590 $52,093 $64,520 ------- ------- ------- ------- -------
At December 31, 1998, interest rates on NEP's variable rate bonds ranged from 3.05 percent to 3.45 percent. At December 31, 1998, the NEES subsidiaries' long-term debt had a carrying value of approximately $1,095,000,000 and a fair value of approximately $1,177,000,000. The fair value of debt that reprices frequently at market rates approximates carrying value. The fair market value of the NEES subsidiaries' long-term debt was estimated based on the quoted prices for similar issues or on the current rates offered to the NEES companies for debt of the same remaining maturity. In order to satisfy certain terms of its mortgage indenture, NEP defeased or retired all $641 million of its mortgage bonds outstanding at the time of the sale of its nonnuclear generating business. NEP retired $372 million of mortgage bonds securing the issuance of a like amount of pollution control revenue bonds (PCRBs), leaving the underlying PCRBs outstanding as unsecured obligations of NEP. Pursuant to a tender offer, NEP purchased $183 million of bonds. Provisions for the payment of the remaining mortgage bonds were made by depositing with trustees approximately $97 million of U.S. treasury obligations sufficient to pay principal, interest, and premium, as applicable, to the maturity date, or to the first date on which the bonds could be redeemed. Both the U.S. treasury obligations and defeased bonds were removed from the balance sheet effective September 30, 1998. Note J - Supplementary Quarterly Financial Information (unaudited)
1998 Quarter ended Mar 31 June 30 Sept 30 Dec 31 -------- -------- -------- -------- (thousands of dollars, except per share amounts) Operating revenue $619,563 $572,008 $630,558 $598,404 Operating income $ 87,146 $ 67,150 $ 92,264 $ 62,279 Net income $ 56,878 $ 34,409 $ 66,193 $ 32,562 Net income per average common share, basic $ .88 $ .55 $ 1.06 $ .56 Net income per average common share, diluted $ .88 $ .54 $ 1.07 $ .55 -------- -------- -------- --------
1997 Quarter ended Mar 31 June 30 Sept 30 Dec 31 -------- -------- -------- ------- (thousands of dollars, except per share amounts) Operating revenue $638,146 $577,625 $628,606 $658,214 Operating income $ 94,962 $ 66,583 $104,524 $100,792 Net income $ 61,820 $ 32,232 $ 67,746 $ 58,240 Net income per average common share, basic and diluted $ .95 $ .50 $ 1.04 $ .90 -------- -------- -------- -------
Report of Management The management of New England Electric System is responsible for the integrity of the consolidated financial statements included in this Annual Report. The financial statements were prepared in accordance with generally accepted accounting principles using management's informed best estimates and judgments where appropriate to fairly present the financial condition of the NEES companies and their results of operations. The information included elsewhere in this report is consistent with the financial statements. The NEES companies maintain an accounting system and system of internal controls which are designed to provide reasonable assurance as to the reliability of the financial records, the protection of assets, and the prevention of any material misstatement of the financial statements. The NEES companies' accounting controls have been designed to provide reasonable assurance that errors or irregularities, which could be material to the financial statements, are prevented or detected by employees within a timely period as they perform their assigned functions. The NEES companies' internal auditing staff independently assesses the effectiveness of internal controls and recommends improvements where appropriate. PricewaterhouseCoopers LLP, the NEES companies' independent accountants, are engaged to audit and express their opinion on the financial statements. Their audit includes a review of internal controls to the extent required by generally accepted auditing standards. The Audit Committee, composed solely of outside directors, meets periodically with management, the internal auditor, and the independent accountants to ensure that each is carrying out its responsibilities and to discuss auditing, internal accounting control, and financial reporting matters. Both the internal auditor and the independent accountants have free access to the Audit Committee, without management present, to discuss the results of their audit work. s/Richard P. Sergel s/Michael E. Jesanis Richard P. Sergel Michael E. Jesanis President and Senior Vice President Chief Executive Officer and Chief Financial Officer Report of Independent Accountants To the Board of Directors and Shareholders of New England Electric System: In our opinion, the accompanying consolidated balance sheets and consolidated statements of capitalization and the related consolidated statements of income and comprehensive income, of retained earnings, and of cash flows present fairly, in all material respects, the financial position of New England Electric System and its subsidiaries (the "Company") at December 31, 1998 and 1997, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1998 in conformity with generally accepted accounting principles. These financial statements are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with generally accepted auditing standards which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for the opinion expressed above. s/PricewaterhouseCoopers LLP February 23, 1999 Shareholder Information For information or assistance with your share account, write or call Shareholder Services at: Bank of New York Shareholder Relations Dept - 11E P.O. Box 11258 Church Street Station New York, NY 10286 Toll-free number: 1-800-466-7215 Fax: 212-815-4023 E-mail: shareowner-svcs@email.bankofny.com If you have questions about the merger with National Grid or the proxy process, write or call: Innisfree M&A Incorporated 501 Madison Avenue, 20th floor New York, NY 10022 Toll-free number: 1-877-750-5836 Dividend reinvestment Shareholders of New England Electric System common shares who hold their shares in registered form are eligible to participate in the Dividend Reinvestment and Common Share Purchase Plan. The Plan provides participants the opportunity to reinvest their dividends and send in optional cash payments to purchase additional common shares. These shares will be newly issued shares or shares purchased in the open market. The Company will pay all brokerage commissions and service charges associated with the Plan. For more information on the Plan, please contact Bank of New York at the toll-free number 1-800-466-7215. Direct deposit of dividends Shareholders who hold New England Electric System common shares in their own name may request to have their dividends directly deposited into their checking or savings account. This service is provided without fees. If you participate in Direct Deposit, you will receive a credit advice for your records. To sign up for this service, please call Bank of New York at the toll-free number to request an authorization form. Change of address Please contact Bank of New York at the toll-free number to notify us of your address change. Note: Upon completion of the merger of NEES and National Grid, NEES shares will no longer be publicly traded. At the appropriate time, NEES will send you information on how to turn in your shares for the cash payment. Form 10-K Copies of the Annual Report on Form 10-K to the Securities and Exchange Commission for 1998 are available upon request at no charge by contacting: Merrill IR Edge 33 Boston Post Road, Suite 270 Marlborough, MA 01752 Telephone: 508-786-1907 Fax: 508-786-1915 E-mail: iredge@merrillcorp.com Stock exchange listings New England Electric System common shares are listed on the New York Stock Exchange and the Boston Stock Exchange under the symbol NES. Transfer agent Certificates for transfer should be mailed to our transfer agent at: Bank of New York Receive and Deliver Department - 11W P.O. Box 11002 Church Street Station New York, NY 10286
New England Electric System common shares 1998 1997 ---- ---- Price Range ($) Price Range ($) -------------- -------------- High Low Dividend High Low Dividend Declared $ Declared $ - ---------------------------------------------------------------------------------------- First Quarter 45.8125 41.0000 .590 35.6250 33.375 .590 Second Quarter 45.5625 40.6250 .590 37.1250 33.250 .590 Third Quarter 43.6250 39.0000 .590 39.6875 36.250 .590 Fourth Quarter 49.1250 40.3125 .590 43.3125 37.250 .590 - ----------------------------------------------------------------------------------------
The total number of shareholders at December 31, 1998 was 44,291 NEES Officers As of January 1, 1999 Alfred D. Houston Chairman Richard P. Sergel President and Chief Executive Officer Cheryl A. LaFleur Senior Vice President, General Counsel, and Secretary Michael E. Jesanis Senior Vice President and Chief Financial Officer David C. Kennedy Vice President John G. Cochrane Treasurer (Elected Vice President and Treasurer, effective March 1, 1999) Executive Officers of Major Subsidiaries As of January 1, 1999 Peter G. Flynn President of New England Power Company William H. Heil Chairman and Chief Executive Officer of AllEnergy Marketing Company, L.L.C. Robert L. McCabe Chairman of the electricity distribution subsidiaries (Massachusetts Electric Company, Nantucket Electric Company, The Narragansett Electric Company, and Granite State Electric Company) Anthony C. Pini President of NEES Communications, Inc. Lawrence J. Reilly President and Chief Executive Officer of the electricity distribution subsidiaries [PHOTO OF NEES OFFICERS] NEES Officers (left to right) Cheryl LaFleur, Al Houston, Rick Sergel, Mike Jesanis, Dave Kennedy, John Cochrane [MAP OF SERVICE AREAS] NEES Subsidiaries As of January 1, 1999 Massachusetts Electric Company 55 Bearfoot Road, Northborough, Massachusetts 01532 The Narragansett Electric Company 280 Melrose Street, Providence, Rhode Island 02901 Granite State Electric Company 9 Lowell Road, Salem, New Hampshire 03079 Nantucket Electric Company 25 Research Drive, Westborough, Massachusetts 01582 AllEnergy Marketing Company, L.L.C. 95 Sawyer Road, Waltham, Massachusetts 02154 Granite State Energy, Inc. 4 Park Street, Concord, New Hampshire 03301 NEES Energy, Inc. 25 Research Drive, Westborough, Massachusetts 01582 New England Power Company 25 Research Drive, Westborough, Massachusetts 01582 NEES Communications, Inc. 25 Research Drive, Westborough, Massachusetts 01582 NEES Global, Inc. 25 Research Drive, Westborough, Massachusetts 01582 New England Electric Transmission Corporation 4 Park Street, Concord, New Hampshire 03301 New England Hydro-Transmission Corporation 9 Lowell Road, Salem, New Hampshire 03079 New England Hydro-Transmission Electric Company, Inc. 25 Research Drive, Westborough, Massachusetts 01582 New England Power Service Company 25 Research Drive, Westborough, Massachusetts 01582 New England Water Heater Co., Inc. 40 Washington Street, Wellesley, Massachusetts 02181 NEES Directors As of January 1, 1999 Joan T. Bok Chairman Emeritus, New England Electric System, Westborough, Massachusetts - - Corporate Responsibility Committee - - Executive Committee William M. Bulger President, University of Massachusetts, Boston, Massachusetts - - Audit Committee Alfred D. Houston Chairman, New England Electric System, Westborough, Massachusetts - - Corporate Responsibility Committee - - Executive Committee Paul L. Joskow Professor of Economics and Management, Massachusetts Institute of Technology, Cambridge, Massachusetts - - Audit Committee - - Corporate Governance Committee - - Executive Committee John M. Kucharski Chairman of the Board, EG&G, Inc., Wellesley, Massachusetts - - Compensation Committee Edward H. Ladd Chairman, Standish, Ayer & Wood, Inc., investment counselors, Boston, Massachusetts - - Corporate Governance Committee - - Executive Committee Joshua A. McClure Former President, American Custom Kitchens, Inc., Providence, Rhode Island - - Corporate Responsibility Committee George M. Sage President and Treasurer, Bonanza Bus Lines, Inc., Providence, Rhode Island - - Compensation Committee - - Corporate Governance Committee - - Executive Committee Richard P. Sergel President and Chief Executive Officer, New England Electric System, Westborough, Massachusetts - - Corporate Responsibility Committee - - Executive Committee Charles E. Soule Former President and Chief Executive Officer, Paul Revere Insurance Group, Worcester, Massachusetts - - Audit Committee Anne Wexler Chairman, The Wexler Group, management consultants, Washington, D.C. - - Compensation Committee - - Corporate Governance Committee - - Executive Committee James Q. Wilson Professor Emeritus of Management, University of California at Los Angeles - - Corporate Responsibility Committee James R. Winoker Chief Executive Officer, Belvoir Properties, Inc., Providence, Rhode Island - - Audit Committee - - Corporate Responsibility Committee [THE FOLLOWING TEXT APPEARS TO THE LOWER RIGHT OF NEES DIRECTORS' PHOTO] The name "New England Electric System" means the trustee or trustees for the time being (as trustee or trustees but not personally) under an Agreement and Declaration of Trust dated January 2, 1926, as amended, which is hereby referred to, and a copy of which, as amended, has been filed with the Secretary of the Commonwealth of Massachusetts. Any agreement, obligation, or liability made, entered into, or incurred by or on behalf of New England Electric System binds only its trust estate, and no shareholder, director, trustee, officer, or agent thereof assumes or shall be held to any liability therefor. This report is not to be considered as an offer to sell or buy or solicitation of an offer to sell or buy any security. [PHOTO OF NEES DIRECTORS STANDING ON STAIRCASE APPEARS AT BOTTOM LEFT TWO-THIRDS OF INSIDE BACK COVER] Row closest to railing (top to bottom): George M. Sage, William M. Bulger, James R. Winoker, Joan T. Bok, Joshua A. McClure, Anne Wexler, Paul L. Joskow. Interior row (top to bottom): Edward H. Ladd, Alfred D. Houston, John M. Kucharski, Charles E. Soule, James Q. Wilson, Richard P. Sergel. [NEES LOGO] New England Electric System 25 Research Drive Westborough, Massachusetts 01582 Telephone 508.389.2000 www.nees.com Design NEES Electronic Publishing Group -----END PRIVACY-ENHANCED MESSAGE-----