-----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, FA1OOl4Z/NQWFCwsVwEs317Nngb7r2EdKAOhGxc0LAcAFTM4WBo6r+FjTa8/wFxk y9iYvBkhvOV5mP6c9XSx6Q== 0000922423-98-000544.txt : 19980529 0000922423-98-000544.hdr.sgml : 19980529 ACCESSION NUMBER: 0000922423-98-000544 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 6 CONFORMED PERIOD OF REPORT: 19980331 FILED AS OF DATE: 19980528 SROS: NYSE FILER: COMPANY DATA: COMPANY CONFORMED NAME: LONG ISLAND LIGHTING CO CENTRAL INDEX KEY: 0000060251 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC & OTHER SERVICES COMBINED [4931] IRS NUMBER: 111019782 STATE OF INCORPORATION: NY FISCAL YEAR END: 0930 FILING VALUES: FORM TYPE: 10-K SEC ACT: SEC FILE NUMBER: 001-03571 FILM NUMBER: 98633090 BUSINESS ADDRESS: STREET 1: 175 E OLD COUNTRY RD CITY: HICKSVILLE STATE: NY ZIP: 11801 BUSINESS PHONE: 5165455184 MAIL ADDRESS: STREET 1: 175 E. OLD COUNTRY RD CITY: HICKSVILLE STATE: NY ZIP: 11801 10-K 1 ANNUAL REPORT S E C U R I T I E S A N D E X C H A N G E C O M M I S S I O N WASHINGTON, D.C. 20549 FORM 10-K [X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934 [NO FEE REQUIRED] FOR THE FISCAL YEAR ENDED MARCH 31, 1998 OR [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934 [NO FEE REQUIRED] COMMISSION FILE NUMBER 1-3571 LONG ISLAND LIGHTING COMPANY INCORPORATED PURSUANT TO THE LAWS OF NEW YORK STATE INTERNAL REVENUE SERVICE - EMPLOYER IDENTIFICATION NUMBER 11-1019782 175 EAST OLD COUNTRY ROAD, HICKSVILLE, NEW YORK 11801 516-755-6650 SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT: Title of each class so registered: Common Stock ($5 par)
Preferred Stock ($100 par, cumulative): Series B, 5.00% Series E, 4.35% Series I, 5 3/4%, Convertible Series D, 4.25% Series CC, 7.66% Preferred Stock ($25 par, cumulative): Series AA, 7.95% Series GG, $1.67 Series QQ, 7.05% Series NN, $1.95 General and Refunding Bonds: 7.85% Series Due 1999 8.50% Series Due 2006 9 3/4% Series Due 2021 8 5/8% Series Due 2004 7.90% Series Due 2008 9 5/8% Series Due 2024 Debentures: 7.30% Series Due 1999 7.05% Series Due 2003 8.90% Series Due 2019 7.30% Series Due 2000 7.00% Series Due 2004 9.00% Series Due 2022 6.25% Series Due 2001 7.125% Series Due 2005 8.20% Series Due 2023 7.50% Series Due 2007
NAME OF EACH EXCHANGE ON WHICH EACH CLASS IS REGISTERED: The New York Stock Exchange and the Pacific Stock Exchange are the only exchanges on which the Common Stock is registered. The New York Stock Exchange is the only exchange on which certain of the other securities listed above are registered. SECURITIES REGISTERED PURSUANT TO SECTION 12(G) OF THE ACT: None Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days. Yes [X] No [ ] Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [X] The aggregate market value of the Common Stock held by non-affiliates of the Company at March 31,1998 was $3,832,943,909. The aggregate market value of Preferred Stock held by non-affiliates of the Company at March 31, 1998, established by Lehman Brothers based on the average bid and asked price, was $735,033,360. COMMON STOCK ($5 PAR) - SHARES OUTSTANDING AT MARCH 31, 1998: 121,680,759
TABLE OF CONTENTS ABBREVIATIONS.....................................................................................................iii PART I ITEM 1. BUSINESS...............................................................................................1 The Company............................................................................................1 Territory..............................................................................................1 Business Segments......................................................................................1 Employees..............................................................................................1 Regulation and Accounting Controls.....................................................................2 Long Island Power Authority Transaction................................................................2 KeySpan Energy Corporation Transaction.................................................................4 Competitive Environment................................................................................6 Electric Operations....................................................................................6 General.......................................................................................6 System Requirements, Energy Available and Reliability.........................................7 Energy Sources................................................................................7 Oil...................................................................................7 Natural Gas...........................................................................8 Purchased Power.......................................................................8 Nuclear...............................................................................9 Interconnections......................................................................9 Conservation Services.........................................................................9 The 1989 Settlement...........................................................................9 Electric Rates................................................................................9 Gas Operations........................................................................................10 General......................................................................................10 Gas System Requirements......................................................................10 Peak Day Capability..................................................................11 Transportation ......................................................................11 Storage..............................................................................11 Cogen/IPP Deliveries.................................................................11 Peak Shaving.........................................................................11 Firm Gas Supply......................................................................12 Gas Rates....................................................................................12 Recovery of Transition Costs.................................................................12 Natural Gas Vehicles.........................................................................12 Environmental Matters.................................................................................12 General......................................................................................12 Air..........................................................................................13 Water........................................................................................15 Land.........................................................................................16 Nuclear Waste................................................................................19 The Company's Securities..............................................................................20 General......................................................................................20 The G&R Mortgage.............................................................................20 Unsecured Debt...............................................................................21 Equity Securities............................................................................21 Common Stock.........................................................................21 Preferred Stock......................................................................22 Preference Stock.....................................................................22 Executive Officers of the Company.....................................................................23 Capital Requirements, Liquidity and Capital Provided..................................................28 ITEM 2. PROPERTIES............................................................................................28 ITEM 3. LEGAL PROCEEDINGS.....................................................................................28 Shoreham..............................................................................................28 Environmental.........................................................................................29 Human Resources.......................................................................................30 Other Matters.........................................................................................30 ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS...................................................30
i
PART II ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTER...................................31 ITEM 6. SELECTED FINANCIAL DATA....................................................................................32 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS......................33 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA................................................................55 Balance Sheet..............................................................................................55 Statement of Income........................................................................................57 Statement of Cash Flows....................................................................................58 Statement of Retained Earnings.............................................................................59 Statement of Capitalization................................................................................59 Notes to Financial Statements..............................................................................61 Report of Independent Auditors.............................................................................96 ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURES..................................................................................97 PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE COMPANY............................................................98 ITEM 11. EXECUTIVE COMPENSATION....................................................................................101 ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT............................................113 ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS............................................................116 PART IV ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K..................................................................................................117 List of Financial Statements.....................................................................117 List of Financial Statement Schedules............................................................117 List of Exhibits.................................................................................118 Reports on Form 8-K...........................................................................129 SCHEDULE II .....................................................................................130 SIGNATURES.............................................................................................................131
ABBREVIATIONS The following abbreviations are sometimes used in this Annual Report. ACO.................. Administrative Consent Order AFC.................. Allowance For Funds Used During Construction ALJ.................. Administrative Law Judge BFC.................. Base Financial Component BVPA................. Bondable Value of Property Additions DEC.................. New York State Department of Environmental Conservation DOE.................. United States Department of Energy DOL.................. New York State Department of Law DSM.................. Demand Side Management Dth.................. Dekatherms (Approx. One Thousand Cubic Feet of Gas) EFRBs................ Electric Facilities Revenue Bonds EMF.................. Electromagnetic Fields EPA.................. United States Environmental Protection Agency ERISA................ Employee Retirement Income Security Act of 1974 FCA.................. Fuel Cost Adjustment FERC................. Federal Energy Regulatory Commission FMC.................. Fuel Moderation Component FRA.................. Financial Resource Asset G&R Bonds............ General and Refunding Bonds G&R Mortgage......... General and Refunding Indenture dated as of June 1, 1975 GAAP................. Generally Accepted Accounting Principles GWh.................. Gigawatt Hour (One Million kWh) IC................... Internal Combustion IDRBs................ Industrial Development Revenue Bonds IERP................. Integrated Electric Resource Plan IPP.................. Independent Power Producers ISO.................. Independent System Operator kWh.................. Kilowatt hour LIPA................. Long Island Power Authority LRAC................. Long-Range Avoided Costs LRPP................. LILCO Ratemaking and Performance Plan MDA.................. Municipal Distribution Agency MGP.................. Manufactured Gas Plant MW................... Megawatts (One Million Watts) MWh.................. Megawatt Hour NEPA................. National Energy Policy Act of 1992 NGV.................. Natural Gas Vehicle NMP2................. Nine Mile Point Nuclear Power Station, Unit 2 NMPC................. Niagara Mohawk Power Corporation NOPR................. Notice of Proposed Rulemaking NRC.................. Nuclear Regulatory Commission NUG.................. Non-Utility Generator NUSCO................ Northeast Utilities Service Company NYPA................. New York Power Authority NYPP................. New York Power Pool NYSERDA.............. New York State Energy Research and Development Authority PACB................. Public Authorities Control Board PCB.................. Polychlorinated Biphenyls PCRBs................ Pollution Control Revenue Bonds PILOTs............... Payments-in-lieu-of-taxes PRP.................. Potentially Responsible Party PSC.................. Public Service Commission of the State of New York PURPA................ Public Utility Regulatory Policies Act of 1978 QF................... Qualified Facilities RI/FS................ Remedial Investigation and Feasibility Study RMA.................. Rate Moderation Agreement RMC.................. Rate Moderation Component Shoreham............. Shoreham Nuclear Power Station SFAS................. Statement of Financial Accounting Standards PART I ITEM 1. BUSINESS THE COMPANY Long Island Lighting Company (Company or LILCO) was incorporated in 1910 under the Transportation Corporations Law of the State of New York and supplies electric and gas service in Nassau and Suffolk Counties and to the Rockaway Peninsula in Queens County, all on Long Island, New York. The mailing address of the Company is 175 East Old Country Road, Hicksville, New York 11801 and the general telephone number is (516) 755-6650. On April 11, 1997, the Company changed its year end from December 31 to March 31. Accordingly, unless otherwise indicated, references to 1998 and 1997 represent the twelve month periods ended March 31, 1998 and March 31, 1997, respectively, while references to all other periods refer to the respective calendar years ended December 31. TERRITORY The Company's service territory covers an area of approximately 1,230 square miles. The population of the service area, according to the Company's 1998 Long Island Population Survey, is 2.75 million persons, including approximately 98,500 persons who reside in Queens County within the City of New York. The 1998 population survey reflects a 1.6% increase since the 1990 census. Approximately 80% of all workers residing in Nassau and Suffolk Counties are employed within the two counties. During the year ended December 31, 1997 total non-agricultural employment in Nassau and Suffolk Counties increased by approximately 18,600 positions, an employment increase of 1.7%. The Company serves approximately 1.04 million electric customers of which approximately 931,000 are residential. The Company receives approximately 49% of its electric revenues from residential customers, 48% from commercial/industrial customers and the balance from sales to other utilities and public authorities. The Company also serves approximately 467,000 gas customers, 417,000 of which are residential, accounting for about 61% of its gas revenues, 17,000 of which are commercial/industrial, accounting for 23% of its gas revenues, 3,600 of which are firm transportation customers, accounting for 3% of its gas revenues, with the balance of the gas revenues derived from off-system sales. BUSINESS SEGMENTS For information concerning the Company's electric and gas financial and operating results, see Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations" and Note 13 of Notes to Financial Statements. EMPLOYEES As of March 31, 1998, the Company had 5,187 full-time employees, of which 2,149 belong to Local 1049 and 1,220 belong to Local 1381 of the International Brotherhood of Electrical Workers. Effective February 14, 1996, the Company and these unions agreed upon contracts which will expire on February 13, 2001. The contracts provide, among other things, for wage increases totaling 15.5% over the term of the agreements. 1 REGULATION AND ACCOUNTING CONTROLS The Company is subject to regulation by the Public Service Commission of the State of New York (PSC) with respect to rates, issuances and sales of securities, adequacy and continuance of service, safety and siting of certain facilities, accounting, conservation of energy, management effectiveness and other matters. To ensure that its accounting controls and procedures are consistently maintained, the Company actively monitors these controls and procedures. The Audit Committee of the Company's Board of Directors, as part of its responsibilities, periodically reviews this monitoring program. The Company is also subject, in certain of its activities, to the jurisdiction of the United States Department of Energy (DOE) and the Federal Energy Regulatory Commission (FERC). In addition to accounting jurisdiction, the FERC has jurisdiction over rates that the Company may charge for the sale of electric energy for resale in interstate commerce, including rates the Company charges for electricity sold to municipal electric systems within the Company's territory, and for the transmission, through the Company's system, of electric energy to other utilities or certain industrial customers. It is in the exercise of this jurisdiction over transmission that the FERC has issued two orders relating to the development of competitive wholesale electric markets. For a discussion of these FERC Orders, see Note 12 of Notes to Financial Statements. The FERC also has some jurisdiction over a portion of the Company's gas supplies and substantial jurisdiction over transportation to the Company of its gas supplies. Operation of Nine Mile Point Nuclear Power Station, Unit 2 (NMP2), a nuclear facility in which the Company has an 18% interest, is subject to regulation by the Nuclear Regulatory Commission (NRC). LONG ISLAND POWER AUTHORITY TRANSACTION On June 26, 1997, the Company and Long Island Power Authority (LIPA) entered into definitive agreements pursuant to which, after the transfer of the Company's gas business unit assets, non-nuclear electric generating facility assets and certain other assets and liabilities to one or more newly-formed subsidiaries of a new holding company (HoldCo), formed in connection with the LIPA Transaction and KeySpan Transaction discussed below, the Company's common stock will be sold to LIPA for $2.4975 billion in cash. In connection with this transaction, the principal assets to be acquired by LIPA through its stock acquisition of LILCO include: (i) the net book value of LILCO's electric transmission and distribution system, which amounted to approximately $1.3 billion at March 31, 1998; (ii) LILCO's net investment in NMP2, which amounted to approximately $0.7 billion at March 31, 1998; (iii) certain of LILCO's regulatory assets associated with its electric business; and (iv) allocated accounts receivable and other assets. The regulatory assets to be acquired by LIPA amounted to approximately $6.6 billion at March 31, 1998, and primarily consist of the Base Financial Component (BFC), Rate Moderation Component (RMC), Shoreham post-settlement costs, Shoreham nuclear fuel, and the electric portion of the regulatory tax asset. For a further discussion of these regulatory assets, see Note 1 of Notes to Financial Statements. LIPA is contractually responsible for reimbursing HoldCo for postretirement benefits other than pension costs related to employees of LILCO's electric business. Accordingly, upon consummation of the transaction, HoldCo will reclassify the associated regulatory asset for postretirement benefits other than pensions to a contractual receivable. The principal liabilities to be assumed by LIPA through its stock acquisition of LILCO include: 2 (i) LILCO's regulatory liabilities associated with its electric business; (ii) allocated accounts payable, customer deposits, other deferred credits and claims and damages; and (iii) certain series of long-term debt, a portion of which will be refinanced. The regulatory liabilities to be assumed by LIPA amounted to approximately $365 million at March 31, 1998, and primarily consist of the regulatory liability component, 1989 Settlement credits and the electric portion of the regulatory tax liability. For a further discussion of these regulatory liabilities, see Note 1 of Notes to Financial Statements. The long-term debt to be assumed by LIPA will consist of: (i) all amounts then outstanding under the General and Refunding (G&R) Indentures; (ii) all amounts then outstanding under the Debenture Indentures, except as noted below; and (iii) substantially all of the tax-exempt authority financing notes. HoldCo is required to assume the financial obligation associated with the 7.30% Debentures due July 15, 1999, with an aggregate principal amount currently outstanding of $397 million and 8.20% Debentures due March 15, 2023, with an aggregate principal amount currently outstanding of $270 million. HoldCo will seek to exchange its Debentures, with identical terms, for these two series of Debentures and will issue a promissory note to LIPA in an amount equal to the unexchanged amount of such Debentures. HoldCo will also issue a promissory note to LIPA for a portion of the tax-exempt debt borrowed to support LILCO's current gas operations, with terms identical to those currently outstanding. The Company currently estimates the amount of this promissory note to be approximately $250 million. In July 1997, in accordance with the provisions of the LIPA Transaction, the Company and The Brooklyn Union Gas Company (Brooklyn Union) formed a limited partnership and each Company invested $30 million in order to purchase an interest rate swap option instrument to protect LIPA against market risk associated with the municipal bonds expected to be issued by LIPA to finance the transaction. Upon the closing of the LIPA Transaction, each limited partner will receive from LIPA $30 million plus interest thereon, based on each partners' average weighted cost of capital. In the event that the LIPA Transaction is not consummated, the maximum potential loss to the Company is the amount originally invested. In such event, the Company plans to defer any loss and petition the PSC to allow recovery from its customers. As part of the LIPA Transaction, the definitive agreements contemplate that one or more subsidiaries of HoldCo will enter into agreements with LIPA, pursuant to which such subsidiaries will provide management and operations services to LIPA with respect to the electric transmission and distribution system, deliver power generated by its power plants to LIPA, and manage LIPA's fuel and electric purchases and any off-system electric sales. In addition, three years after the LIPA Transaction is consummated, LIPA will have the right for a one-year period to acquire all of HoldCo's generating assets at the fair market value at the time of the exercise of the right, which value will be determined by independent appraisers. In July 1997, the New York State Public Authorities Control Board (PACB), created pursuant to the New York State Public Authorities Law and consisting of five members appointed by the governor, unanimously approved the definitive agreements related to the LIPA Transaction subject to the following conditions: (i) within one year of the effective date of the transaction, LIPA must establish a plan for open access to the electric distribution system; (ii) if LIPA exercises its option to acquire the generation assets of HoldCo's generation subsidiary, LIPA may not purchase the generating facilities, as contemplated in the generation purchase right agreement, at a price greater than book value; (iii) HoldCo must agree to invest, over a ten-year period, at least $1.3 billion in energy-related and economic development projects, and natural gas infrastructure projects on Long Island; (iv) LIPA will guarantee that, over a ten-year period, average electric rates will be reduced 3 by no less than 14% when measured against the Company's rates today and no less than a 2% cost savings to LIPA customers must result from the savings attributable to the merger of LILCO and KeySpan; and (v) LIPA will not increase average electric customer rates by more than 2.5% over a twelve-month period without approval from the PSC. LIPA has adopted the conditions set forth by the PACB. The holders of common and certain series of preferred stock of the Company eligible to vote approved the LIPA Transaction in August 1997. In December 1997, the United States Nuclear Regulatory Commission (NRC) issued an order approving the indirect transfer of control of the Company's 18% ownership interest in NMP2 to LIPA. In December 1997, the Company filed with the FERC a settlement agreement reached with LIPA in connection with a previous filing of the Company's proposed rates for the sale of capacity and energy to LIPA, as contemplated in the LIPA transaction agreements. The Company also had previously filed an application with the FERC seeking approval of the transfer of the Company's electric transmission and distribution system to LIPA in connection with LIPA's purchase of the common stock of the Company. In February 1998, the FERC issued orders on both of the Company filings. Specifically, the FERC approved the Company's application to transfer assets to LIPA in connection with LIPA's acquisition of the Company's common stock. In addition, the FERC accepted the Company's proposed rates for sale of capacity and energy to LIPA. Those rates may go into effect on the date the service to LIPA begins, subject to refund, and final rates will be set after the FERC has completed its investigation of such rates, the timing of which cannot be determined at this time. In January 1998, the Company filed an application with the PSC in connection with the proposed transfer of its gas business unit assets, non-nuclear generating facility assets and certain other assets and related liabilities to one or more subsidiaries of HoldCo to be formed as contemplated in the LIPA Transaction agreements. On April 29, 1998, the PSC approved the transfer of the above-mentioned assets. In July 1997, the Company, Brooklyn Union and LIPA filed requests for private letter rulings with the Internal Revenue Service (IRS) regarding certain federal income tax issues which require favorable rulings in order for the LIPA Transaction to be consummated. On March 4, 1998, the IRS issued a private letter ruling confirming that the sale of the Company's common stock to LIPA would not result in a corporate tax liability to the Company. In addition, the IRS ruled that, after the stock sale, the income of LIPA's electric utility business will not be subject to federal income tax. In a separate ruling on February 27, 1998, the IRS also ruled that the bonds to be issued by LIPA to finance the acquisition would be tax-exempt. In January 1998, the Company filed an application with the SEC seeking an exception for most of the provisions of the Public Utilities Holding Company Act of 1935. In May 1998, the SEC issued an order approving the Company's application. The Company currently anticipates that the LIPA transaction will be consummated on or about May 28, 1998. KEYSPAN ENERGY CORPORATION TRANSACTION On December 29, 1996, The Brooklyn Union Gas Company (Brooklyn Union) and the Company entered into an Agreement and Plan of Exchange and Merger (Share Exchange Agreement), 4 pursuant to which the companies will be merged in a transaction (KeySpan Transaction) that will result in the formation of HoldCo. The Share Exchange Agreement was amended and restated to reflect certain technical changes as of February 7, 1997 and June 26, 1997. Effective September 29, 1997, Brooklyn Union reorganized into a holding company structure, with KeySpan Energy Corporation (KeySpan) becoming its parent holding company. Accordingly, the parties entered into an Amendment, Assignment and Assumption Agreement, dated as of September 29, 1997, which among other things, amended the Share Exchange Agreement and related stock option agreements to reflect the assignment by Brooklyn Union to KeySpan and the assumption by KeySpan of all Brooklyn Union's rights and obligations under such agreements. The KeySpan Transaction, which has been approved by both companies' boards of directors and shareholders, would unite the resources of the Company with the resources of KeySpan. KeySpan, with approximately 3,300 employees, distributes natural gas at retail, primarily in a territory of approximately 187 square miles which includes the boroughs of Brooklyn and Staten Island and two-thirds of the borough of Queens, all in New York City. KeySpan has energy-related investments in gas exploration, production and marketing in the United States and Northern Ireland, as well as energy services in the United States, including cogeneration projects, pipeline transportation and gas storage. Under the terms of the KeySpan Transaction, the Company's common shareowners will receive 0.803 shares (the Ratio) of HoldCo's common stock for each share of the Company's common stock that they hold at the time of closing. KeySpan common shareowners will receive one share of common stock of HoldCo for each common share of KeySpan they hold at the time of closing. Shareowners of the Company will own approximately 66% of the common stock of HoldCo while KeySpan shareowners will own approximately 34%. In the event that the LIPA Transaction is consummated, the Ratio will be 0.880 with Company shareowners owning approximately 68% of the HoldCo common stock. Consummation of the Share Exchange Agreement is not conditioned upon the consummation of the LIPA Transaction and consummation of the LIPA Transaction is not conditioned upon consummation of the Share Exchange Agreement. Based on current facts and circumstances, it is probable that the purchase method of accounting will apply to the KeySpan Transaction, with the Company being the acquiring company for accounting purposes. In March 1997, the Company filed an application with the FERC seeking approval of the transfer of the Company's common equity and certain FERC-jurisdictional assets to HoldCo. In July 1997, the FERC granted such approval. The Share Exchange Agreement contains certain covenants of the parties pending the consummation of the transaction. Generally, the parties must carry on their businesses in the ordinary course consistent with past practice, may not increase dividends on common stock beyond specified levels and may not issue capital stock beyond certain limits. The Share Exchange Agreement also contains restrictions on, among other things, charter and by-law amendments, capital expenditures, acquisitions, dispositions, incurrence of indebtedness, certain increases in employee compensation and benefits, and affiliate transactions. The Company and KeySpan expect to continue their respective current dividend policies until completion of the KeySpan Transaction. It is anticipated that HoldCo will set an initial annual dividend rate of $1.78 per share for its common stock. 5 Upon completion of the merger, Dr. William J. Catacosinos will become chairman and chief executive officer of HoldCo; Mr. Robert B. Catell, currently chairman and chief executive officer of KeySpan, will become president and chief operating officer of HoldCo. One year after the closing, Mr. Catell will succeed Dr. Catacosinos as chief executive officer, with Dr. Catacosinos continuing as chairman. The board of directors of HoldCo will be comprised of 15 members, six from the Company, six from KeySpan and three additional persons previously unaffiliated with either company. Effects of LIPA and KeySpan Transactions on Future Operations The future operations and financial position of the Company will be significantly affected by each of the proposed transactions with LIPA and KeySpan described above. The discussion contained in this report and any analysis of financial condition and results of operations does not reflect, unless otherwise indicated, the potential effects of the transactions with LIPA and KeySpan. COMPETITIVE ENVIRONMENT A discussion of the competitive issues the Company faces appears in Note 12 of Notes to Financial Statements. ELECTRIC OPERATIONS General The Company's system energy requirements are supplied from sources located both on and off Long Island. The following table indicates the 1997 summer capacity of the Company's steam generation facilities, Internal Combustion (IC) Units and other generation facilities as reported to the New York Power Pool (NYPP):
- -------------------------------------------------- ---------------------- ----------- ----------- --------- Location of Units Description Fuel Units MW - -------------------------------------------------- ---------------------- ----------- ----------- --------- Company Owned: Northport, L.I. Steam Turbine Dual* 2 778 Oil 2 754 Port Jefferson, L.I. Steam Turbine Dual* 2 382 Glenwood, L.I. Steam Turbine Gas 2 218 Island Park, L.I. Steam Turbine Dual* 2 386 Far Rockaway, L.I. Steam Turbine Dual* 1 109 Throughout L.I. IC Units Dual* 12 279 Oil 30 1,072 Jointly Owned: NMP2 (18% Share) Oswego, New York Steam Turbine Nuclear 1 205 Owned by the New York Power Authority: Holtsville, L.I. Combined Cycle Dual* 1 142 - -------------------------------------------------- ---------------------- ----------- ----------- --------- Total 55 4,325 - -------------------------------------------------- ---------------------- ----------- ----------- ---------
*Dual - Oil or natural gas. Additional generating facilities owned by others, such as independent power producers (IPPs) and cogenerators located on Long Island and investor-owned and public electric systems located off Long Island provide the balance of the Company's energy supplies. The maximum demand on the Company's system was 4,140 Megawatts (MW) on July 15, 1997, representing 84% of the total available capacity of 4,953 MW on that day, which included 766 MW of firm capacity purchased from other sources. By agreement with the NYPP, the Company is required to maintain, on a monthly basis, an installed and contracted firm power reserve 6 generating capacity equal to at least 18% of its actual peak load. The Company continues to meet this NYPP requirement. System Requirements, Energy Available and Reliability For the year ended March 31, 1998, system kilowatt hours (kWh) energy requirements on the Company's system were 1.0% higher than the corresponding 1997 period. The Company forecasts increases of 2.3% and 3.2%, for the years ending March 1999 and 2000, respectively compared to that experienced for the year ended March 31, 1998. For the years ending March 31, 2001-2010, the Company forecasts an average annual growth rate in system energy requirements of 1.1%. Due to the effects of price elasticity, the projected peak demand for electric power is expected to increase if the LIPA transaction is consummated. Based on projections of peak demand for electric power in the absence of the LIPA Transaction, the Company believes it will need to acquire additional generating or demand-side resources starting in 1998 in order to maintain electric supply reliability. In accordance with the Company's Integrated Electric Resource Plan (IERP), issued in 1996, the Company intends to institute a combination of a peak load reduction demand-side management program and a capacity purchase to meet this need. Current projections are that new electric generating capacity will not need to be installed on Long Island to meet peak demand until after 2002. It is anticipated that such new capacity would be acquired through a competitive bidding process. Fuel Mix The megawatt hours (MWh) and percentages of total energy available by type of fuel for electric operations for the years ended March 31, 1998 and 1997, and the years ended December 31, 1996 and 1995 were as follows:
(In thousands of MWh) Year Ended Year Ended March 31, December 31, --------- ------------ 1998 1997 1996 1995 - --------------------------------------------------------------------------------------------------------------- MWh % MWh % MWh % MWh % - --------------------------------------------------------------------------------------------------------------- Oil 3,434 20% 3,278 19% 4,219 24% 3,099 17% Gas 6,212 35% 5,469 31% 4,542 25% 6,344 36% Nuclear 1,545 9% 1,553 9% 1,558 9% 1,301 7% Purchased power 6,412 36% 7,261 41% 7,388 42% 7,143 40% - --------------------------------------------------------------------------------------------------------------- Total 17,603 100% 17,561 100% 17,707 100% 17,887 100% ===============================================================================================================
Energy Sources The total energy provided by oil and natural gas is generated by the Company's units located on Long Island, while the nuclear generation is provided through NMP2, the Company's 18% owned nuclear power plant which is located near Oswego, New York. Oil The availability and cost of oil used by the Company is affected by factors such as the international oil market, environmental regulations, conservation measures and the availability of alternative fuels. In order to reduce the impact of the above factors on the Company's operations, the Company, over the past several years, has refitted the majority of its steam generation units enabling them to burn oil or natural gas, whichever is more economical and consistent with seasonal environmental requirements. The Company's fuel oil is supplied principally by three suppliers. 7 Oil consumption in barrels was as follows: - ----------------------------------------------------------------------------- Years Ended Consumption (in barrels) - ----------------------------------------------------------------------------- - ----------------------------------------------------------------------------- March 31, 1998 5.6 million - ----------------------------------------------------------------------------- - ----------------------------------------------------------------------------- March 31, 1997 5.5 million - ----------------------------------------------------------------------------- - ----------------------------------------------------------------------------- December 31, 1996 7.1 million - ----------------------------------------------------------------------------- - ----------------------------------------------------------------------------- December 31, 1995 5.2 million - ----------------------------------------------------------------------------- Natural Gas Nine of the Company's eleven steam generating units have the capability of burning natural gas. Seven of these units are capable of burning either oil or natural gas. This enables the Company to burn the most cost-efficient fuel, consistent with seasonal environmental requirements, thereby reducing the Company's generation costs. In April 1996 and May 1997, the Company completed two planned conversions of oil-fired steam generating units at its Port Jefferson Power Station to dual-firing units. Gas consumption for electric generation was as follows: - ---------------------------------------------------------------------------- Years Ended Consumption (in million Dth) - ---------------------------------------------------------------------------- - ---------------------------------------------------------------------------- March 31, 1998 69.4 - ---------------------------------------------------------------------------- - ---------------------------------------------------------------------------- March 31, 1997 63.6 - ---------------------------------------------------------------------------- - ---------------------------------------------------------------------------- December 31, 1996 50.2 - ---------------------------------------------------------------------------- - ---------------------------------------------------------------------------- December 31, 1995 69.8 - ---------------------------------------------------------------------------- The percentage of energy generated by burning natural gas at the Company's steam and internal combustion units was as follows: - ----------------------------------- -------------------------------- Years Ended Percent Generated - ----------------------------------- -------------------------------- - ----------------------------------- -------------------------------- March 31, 1998 64% - ----------------------------------- -------------------------------- - ----------------------------------- -------------------------------- March 31, 1997 63% - ----------------------------------- -------------------------------- - ----------------------------------- -------------------------------- December 31, 1996 52% - ----------------------------------- -------------------------------- - ----------------------------------- -------------------------------- December 31, 1995 67% - ----------------------------------- -------------------------------- Purchased Power The Company strives to provide its customers with the most economical energy available to keep electric rates as low as possible. Often, this energy is generated more economically at power plants within other electric systems and transmitted to the Company through its interconnections. In addition, the Company is required to purchase energy from sources located within its service territory including the New York Power Authority (NYPA) Holtsville facility, IPPs and cogenerators. IPPs and cogenerators located within the Company's service territory provided approximately 206 MW of capacity to the Company during the year ended March 31, 1998. The percentage of the total energy made available to the Company by IPPs, cogenerators and the NYPA Holtsville facility was follows: - ----------------------------------- --------------------------------------- Years Ended Percent of Energy Available - ----------------------------------- --------------------------------------- - ----------------------------------- --------------------------------------- March 31, 1998 17.2% - ----------------------------------- --------------------------------------- - ----------------------------------- --------------------------------------- March 31, 1997 16.1% - ----------------------------------- --------------------------------------- - ----------------------------------- --------------------------------------- December 31, 1996 16.1% - ----------------------------------- --------------------------------------- - ----------------------------------- --------------------------------------- December 31, 1995 16.3% - ----------------------------------- --------------------------------------- 8 The Company does not expect any new major IPPs or cogenerators to be built on Long Island in the near future. Among the reasons supporting this conclusion is the Company's belief that the market for IPPs and cogenerators to provide power to the Company's remaining commercial and industrial customers is small. Furthermore, under federal law, the Company is required to buy energy from qualified producers at the Company's long-range avoided costs. Current long-range avoided cost estimates for the Company have significantly reduced the economic advantage to entrepreneurs seeking to compete with the Company and with existing IPPs. For additional information with respect to competitive issues facing the Company, see Note 12 of Notes to Financial Statements. Nuclear The Company holds an 18% interest in NMP2, an 1,137 MW nuclear generating unit near Oswego, New York, which is operated by Niagara Mohawk Power Corporation (NMPC). The cotenants of NMP2, in addition to the Company, are NMPC (41%), New York State Electric & Gas Corporation (18%), Rochester Gas and Electric Corporation (14%) and Central Hudson Gas & Electric Corporation (9%). For the year ended March 31, 1998, NMP2 operated at 86.63% of its capacity. For a further discussion of NMP2, see Note 5 of Notes to Financial Statements. Interconnections Five interconnections allow for the transfer of electricity between the Company and members of the NYPP and the New England Power Pool. Energy from these sources is transmitted pursuant to transmission agreements with NMPC, NYPA, Northeast Utilities Service Company (NUSCO), a co-owner of one of these interconnections, and Consolidated Edison Company of New York, Inc. (Con Edison) and displaces energy that would otherwise be generated on the Company's system at a higher cost. The capacity of these interconnections is utilized for Company requirements including the transmission of the Company's share of power from NMP2, the requirements of Con Edison, a co-owner with the Company of three of these interconnections, and the requirements on Long Island of NYPA, the owner of one of these interconnections. Conservation Services A discussion of conservation services appears in Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations." The 1989 Settlement In February 1989, the Company and the State of New York entered into the 1989 Settlement resolving certain issues relating to the Company and providing, among other matters, for the financial recovery of the Company and for the transfer of the Shoreham Nuclear Power Station (Shoreham) to LIPA for its subsequent decommissioning. A discussion of the 1989 Settlement and Shoreham decommissioning appears in Note 10 of Notes to Financial Statements. Electric Rates A discussion of electric rates appears in Note 4 of Notes to Financial Statements. 9 GAS OPERATIONS General The Company's gas supplies are transported by interstate pipelines from Canadian and domestic sources. On-system peak shaving and IPP/Cogen peaking supplies are available to meet system requirements during winter periods. During the past several years, the Company actively participated in proceedings before the FERC in an effort to mitigate any adverse impact that filings by interstate pipeline companies might have on the Company's gas customers as well as to decrease upstream transportation costs and improve operational tariffs. The Company also actively participated in the proceedings before the PSC which established the framework for a new competitive natural gas marketplace within the State of New York. In response to changes in federal and state regulations that have "unbundled" traditional pipeline services in order to promote competition in the gas supply and gas services market, the Company implemented its NaturalChoice(sm) firm transportation program in April 1996. Under NaturalChoice(sm), customers may purchase natural gas from qualified suppliers other than the Company. The Company continues to provide NaturalChoice(sm) customers with all gas services provided to traditional customers except for the procurement and sale of gas. These services include the local transportation of gas, meter reading and billing, equipment maintenance and emergency response. The Company's profit margins have not been impacted by this new program as the Company collects from these customers all costs associated with providing its service, including operating the gas system. As of March 31, 1998, there were approximately 3,600 NaturalChoice(sm) customers with annual requirements of approximately 4,213,000 Dth or 7 percent of the Company's annual gas system requirements. Gas System Requirements The Company has 467,000 firm gas customers at March 31, 1998, including 295,000 gas space heating customers, an increase of more than 15,000 gas space heating customers over the past three years. The Company's penetration in the gas space heating market within its service territory is approximately 29%. Total firm sales for the year ended March 31, 1998, when normalized for weather, decreased approximately 3.6% over the comparable period in 1997 primarily due to customers switching to the NaturalChoice(sm) Program. The maximum daily sendout experienced on the Company's gas system was 585,227 Dth on January 19, 1994, representing 83% of the Company's per day capability at that time. The forecasted maximum daily sendout for the 1998-1999 winter season (November 1 - March 31) is approximately 652,000 Dth, or 88% of the Company's peak-day capability. 10 Peak Day Capability The Company has firm gas peak day capability in excess of its projected requirements for firm gas customers for the 1998-1999 winter season (November 1-March 31). Firm capability is summarized in the following table: - ---------------------------------------------------- -------------------- Dth per day % of Total - ---------------------------------------------------- -------------------- Transportation 263,000 35 Storage 294,000 40 Cogen/IPP Deliveries 85,000 11 Peak Shaving 103,000 14 ==================================================== ==================== Total 745,000 100% ==================================================== ==================== Transportation The Company has available under firm contract 263,000 Dth per day of year-round and seasonal pipeline transportation capacity which is provided by four interstate pipeline companies including the Iroquois Gas Transmission System. The Company, through its majority interest in a subsidiary, LILCO Energy Systems, Inc., is a general partner in the Iroquois pipeline with an equity share of 1%. Storage In order to meet higher winter demand, the Company also has long-term firm market area storage services in Pennsylvania and New York which provide a total maximum supply of 294,000 Dth per day, with a total capacity of 22,534,000 Dth for the winter period. In order to provide the Company with greater security of supply and enhanced operational flexibility in meeting peak-day requirements, the Company also contracts for production area storage capacity in Louisiana and Mississippi. However, the Company has no incremental firm pipeline transportation capacity for these supplies. Cogen/IPP Deliveries The Company has contract rights with the Brooklyn Navy Yard Cogen facility to receive approximately 576,000 Dth of peaking supplies during the winter period at a rate of approximately 30,000 Dth per day. Also, the Company has contract rights with the Nassau District Energy Corporation to receive 250,000 Dth of peaking supplies during the winter period at a rate of 12,500 Dth per day. The Company has contract rights with the NYPA IPP facility to receive 900,000 Dth of storage service during any continuous 100-day period during each winter season at a daily rate not to exceed 31,000 Dth per day. In addition, the Company has contract rights with Nissequogue Cogen facility to receive up to 330,000 Dth of storage service for 30 days during each winter season at a daily rate not to exceed 11,000 Dth per day. The Company has the obligation to return these quantities in kind during the following summer period. In addition, the Company has the right to request 812,000 Dth in the winter season from the TBG Cogen facility with the obligation to return the quantities in kind during the following summer period. The daily quantity of 12,500 Dth is only available on warmer winter days. Peak Shaving The Company has its own peak shaving supplies to meet its firm requirements on excessively cold winter days. They include a liquefied natural gas plant with a storage capacity of approximately 600,000 Dth and vaporization facilities which provide approximately 103,000 Dth per day to the 11 peak-day capability of the Company's system. Firm Gas Supply The Company has approximately 161,000 Dth per day of firm gas supplies that are transported under its firm pipeline transportation capacity. About 83,000 Dth per day is obtained from Canadian sources and 78,000 Dth per day is obtained from domestic sources. Included in the long-term firm Canadian gas is about 3,000 Dth per day of gas contracted with Boundary Gas, Inc. (Boundary). The Company owns 2.7% of the common stock of Boundary, a corporation formed with 14 other gas utility companies to act as a purchasing agent for the importation of natural gas from Canada. The Company's 161,000 Dth per day of long-term supply contracts have commodity rates that are market-based. The Company has no fixed price supply contracts. Certain of these contracts have minimum annual take or pay arrangements and/or associated demand charges. The Company also purchases various quantities of market-priced gas in both the seasonal and monthly spot markets that is transported under firm and interruptible transportation agreements. Gas Rates A discussion of gas rates appears in Note 4 of Notes to Financial Statements. Recovery of Transition Costs Transition costs are the costs associated with unbundling the pipeline companies' merchant services in compliance with FERC Order No. 636. They include pipeline companies' unrecovered gas costs and the costs that pipelines incur as a result of modifying or terminating their gas supply contracts. In order to recover transition costs, pipeline companies must demonstrate to the FERC that such costs were attributable to Order No. 636 and that they were prudently incurred. While the Company has challenged, on both eligibility and prudence grounds, its supplier pipelines' efforts to recover their claimed transition costs, the Company estimates that it will be responsible for total transition costs of approximately $10 million. As of March 31, 1998, the Company has collected $8.7 million of these transition costs from its gas customers. Natural Gas Vehicles The Company continues to maintain a focus on promoting Natural Gas Vehicles (NGVs) and infrastructure development. Additional resources have been dedicated to the NGV program in 1997 and 1998 and an arrangement with a company named Fuelmaker has provided customers with a low risk, low cost approach to refueling their NGVs. In addition, consistent with a Clean Cities designation, the Company has aggressively assisted customers in obtaining Congestion Mitigation Air Quality (CMAQ) grants and other Department of Energy funds to help offset their incremental NGV and refueling equipment costs. As a result of these efforts, NGVs consumed approximately 130,000 Dth and resulted in $260,000 in revenue net of fuel for the year ended March 31, 1998. ENVIRONMENTAL MATTERS General The Company's ordinary business operations necessarily involve materials and activities which subject the Company to federal, state and local laws, rules and regulations dealing with the environment, including air, water and land quality. These environmental requirements may entail significant expenditures for capital improvements or modifications and may expose the Company 12 to potential liabilities which, in certain instances, may be imposed without regard to fault or for historical activities which were lawful at the time they occurred. Laws which may impose such potential liabilities include (but are not limited to) the federal Comprehensive Environmental Response, Compensation and Liability Act (CERCLA, commonly known as Superfund), the federal Resource Conservation and Recovery Act, the federal Toxic Substances Control Act (TSCA), the federal Clean Water Act (CWA), and the federal Clean Air Act (CAA). Capital expenditures for environmental improvements and related studies amounted to approximately $9.2 million for the year ended March 31, 1998 and, based on existing information, are expected to be $4.0 million for the year ended March 31, 1999. The expenditures in fiscal year 1998 and expected spending in fiscal year 1999 include a total of $10.6 million for the completion of a gas-firing capability project at Northport Unit 1 and Port Jefferson Unit 4. It is not possible to ascertain with certainty if or when the various required governmental approvals for which applications have been made will be issued, or whether, except as noted below, additional facilities or modifications of existing or planned facilities will be required or, generally, what effect existing or future controls may have upon Company operations. Except as set forth below and in Item 3 - "Legal Proceedings," no material proceedings have been commenced or, to the knowledge of the Company, are contemplated by any federal, state or local agency against the Company, nor is the Company a defendant in any material litigation with respect to any matter relating to the protection of the environment. Recoverability of Environmental Costs The Company believes that none of the environmental matters, discussed below, will have a material adverse impact on the Company's financial position, cash flows or results of operations. In addition, the Company believes that all significant costs incurred with respect to environmental investigation and remediation activities, not recoverable from insurance carriers, will be recoverable from its customers. Air Federal, state and local regulations affecting new and existing electric generating plants govern emissions of sulfur dioxide (SO2), nitrogen oxides (NOX), particulate matter, and, potentially in the future, fine particulate matter (aerosols of SO2), hazardous air pollutants and carbon dioxide (CO2). Sulfur Dioxide Requirements The laws governing the sulfur content of the fuel oil being burned by the Company in compliance with the United States Environmental Protection Agency (EPA) approved Air Quality State Implementation Plan (SIP) are administered by the New York State Department of Environmental Conservation (DEC). The Company does not expect to incur any costs to satisfy the 1990 amendments to the federal CAA with respect to the reduction of SO2 emissions, as the Company already uses natural gas and oil with acceptably low levels of sulfur as boiler fuels. These fuels also result in reduced vulnerability to any future fine particulate standards implemented in the form of stringent sulfur dioxide emission limits. The Company's use of low sulfur fuels has resulted, and will continue to result, in approximately 70,000 excess SO2 allowances per year through the year 1999. The Company presently applies the proceeds resulting from any sales of excess SO2 allowances as a reduction to the RMC balance. The Company entered into a voluntary Memorandum of Understanding with the DEC which 13 provides that the Company will not sell SO2 allowances for use in 15 states in an effort to mitigate the transport of acid rain precursors into New York State from upwind states. Nitrogen Oxides Requirements Due to the Company's program of cost-effective emission reductions, including the optimization of natural gas firing ability at almost all the steam electric generating stations, the Company had the lowest NOX emissions rate of all the utilities in New York State for the years ended December 31, 1997, 1996 and 1995. Since the Company's generating facilities are located within a CAA Amendment-designated ozone non-attainment area, they are subject to NOx reduction requirements which are being implemented in three phases. Phase I was completed in 1995; Phase II and Phase III will be completed in 1999 and 2003, respectively. The Company is currently in compliance with Phase I NOx reduction requirements. It is estimated that additional expenditures of approximately $1 million will be required to meet Phase II NOx reduction requirements. Subject to requirements that are expected to be promulgated in forthcoming regulations, the Company estimates that it may be required to spend an additional $10 million to $34 million, excluding the Northport Unit 1 conversion, by the year 2003 to meet Phase III NOx reduction requirements. The completion of the project to add gas-firing capability at Northport Unit 1 (completed in May 1998 at a total cost of approximately $8.4 million) will also facilitate the Company's compliance with the anticipated Phase III Nox reduction requirements. Continuous Emission Monitoring Additional software and equipment upgrades for Continuous Emissions Monitors of approximately $2 million may be required through 1999 at all generating facilities in order to meet EPA requirements under development for the NOx allowance tracking/trading program. Hazardous Air Pollutants Utility boilers are presently exempt from regulation as sources of hazardous air pollutants until the EPA completes a study of the risks, if any, to public health reasonably anticipated to occur as a result of emissions by electric generating units. The EPA is expected to make a determination concerning the need for control of hazardous air pollutants from utility facilities in 1998. Until such determination is made by the EPA, the Company cannot fully ascertain what, if any, costs will be incurred for the control of hazardous air pollutants. However, after the expenditure of approximately $1.5 million in fiscal 1998 and the planned spending of $0.5 million through March 31, 1999, for electrostatic precipitator upgrades and, with the maximization of clean burning natural gas as the primary fuel, hazardous air pollutant regulations, if enacted, should not impose any additional control requirements for the Company's facilities. Carbon Dioxide Requirements CO2 emissions from the Company's plants have been reduced by approximately 23% since 1990, largely through greater reliance on the use of natural gas and through conservation programs. This makes the Company less vulnerable to future CO2 reduction requirements. Opacity Issues The DEC has proposed commencing enforcement actions against all New York utilities for alleged opacity exceedences from steam electric generating facilities. Opacity is a measure of the relative level of light that is obscured from passing through a power plant stack emission plume. An exceedence occurs when the level of light passing through the plume is reduced by more than 20% 14 for six minutes or more. The Company has entered into an Administrative Consent Order (ACO) with the DEC which resolves all historical opacity exceedences, establishes an opacity reduction program to be undertaken by the Company, and sets a stipulated penalty schedule for future exceedences. The number of exceedences experienced by the Company is relatively low, placing the Company among the best performers in New York State. Electromagnetic Fields Electromagnetic fields (EMF) occur naturally and also are produced wherever there is electricity. These fields exist around power lines and other utility equipment. The Company is in compliance with all applicable regulatory standards and requirements concerning EMF. The Company also monitors scientific developments in the study of EMF, has contributed to funding for research efforts, and is actively involved in customer and employee outreach programs to inform the community of EMF developments as they occur. Although an extensive body of scientific literature has not shown an unsafe exposure level or a causal relationship between EMF exposure and adverse health effects, concern over the potential for adverse health effects will likely continue without final resolution for some time. To date, four residential property owners have initiated separate lawsuits against the Company alleging that the existence of EMF has diminished the value of their homes. These actions are in the preliminary stages of discovery and are similar to actions brought against another New York State utility, which were dismissed by the New York State Court of Appeals. The Company is not involved in any active litigation that alleges a causal relationship between exposure to EMF and adverse health effects. Water Under the federal CWA and the New York State Environmental Conservation Law, the Company is required to obtain a State Pollutant Discharge Elimination System permit to make any discharge into the waters of the United States or New York State. The DEC has the jurisdiction to issue these permits and their renewals and has issued permits for the Company's generating units. The permits allow the continued use of the circulating water systems which have been determined to be in compliance with state water quality standards. The permits also allow for the continued use of the chemical treatment systems and for the continued discharge of water in accordance with applicable permit limits. In fiscal year 1998, the Company spent approximately $300,000 to upgrade its waste water treatment facilities and for other measures designed to protect surface and ground water quality and expects to spend an additional $100,000 in the years 1998-2000. Long Island Sound Transmission Cables During 1996, the Connecticut Department of Environmental Protection (DEP) issued a modification to an Administrative Consent Order (ACO) previously issued in connection with an investigation of an electric transmission cable system located under the Long Island Sound (Sound Cable) that is jointly owned by the Company and the Connecticut Light and Power Company (Owners). The modified ACO requires the Owners to submit to the DEP and DEC a series of reports and studies describing cable system condition, operation and repair practices, alternatives for cable improvements or replacement and environmental impacts associated with leaks of fluid into the Long Island Sound which have occurred from time to time. The Company continues to compile required information and coordinate the activities necessary to perform these studies and, at the present time, is unable to determine the costs it will incur to complete the requirements of the modified ACO or to comply with any additional requirements. 15 The Owners have also entered into an ACO with the DEC as a result of leaks of dielectric fluid from the Sound Cable. The ACO formalizes the DEC's authority to participate in and separately approve the reports and studies being prepared pursuant to the ACO issued by the DEP. In addition, the ACO settles any DEC claim for natural resource damages in connection with historical releases of dielectric fluid from the Sound Cable. In October 1995, the U.S. Attorney for the District of Connecticut had commenced an investigation regarding occasional releases of fluid from the Sound Cable, as well as associated operating and maintenance practices. The Owners have provided the U.S. Attorney with all requested documentation. The Company believes that all activities associated with the response to occasional releases from the Sound Cable were consistent with legal and regulatory requirements. In December 1996, a barge, owned and operated by a third party, dropped anchor which then dragged over and damaged the Sound Cable, resulting in the release of dielectric fluid into Long Island Sound. Temporary clamps and leak abaters were installed on the cables to stop the leaks. Permanent repairs were completed in June 1997. The cost to repair the Sound Cable was approximately $17.8 million, for which there was $15 million of insurance coverage. The Owners filed a claim and answer in response to the maritime limitation proceeding instituted by the barge owner in the United States District Court, Eastern District of New York. The claim seeks recovery of the amounts paid by insurance carriers and recovery of the costs incurred for which there was no insurance coverage. Any costs to repair the Sound Cable which are not reimbursed by a third party or covered by insurance will be shared equally by the Owners. Land Superfund imposes joint and several liability, regardless of fault, upon generators of hazardous substances for costs associated with environmental cleanup activities. Superfund also imposes liability for remediation of pollution caused by historical acts which were lawful at the time they occurred. In the course of the Company's ordinary business operations, the Company is involved in the handling of materials that are deemed to be hazardous substances under Superfund. These materials include asbestos, metals, certain flammable and organic compounds and dielectric fluids containing polychlorinated biphenyls (PCBs). Other hazardous substances may be handled in the Company's operations or may be present at Company locations as a result of historical practices by the Company or its predecessors in interest. The Company has received notice concerning possible claims under Superfund or analogous state laws relating to a number of sites at which it is alleged that hazardous substances generated by the Company and other potentially responsible parties (PRPs) were deposited. A discussion of these sites is set forth below. Estimates of the Company's allocated share of costs for investigative, removal and remedial activities at these sites range from preliminary to refined and are updated as new information becomes available. In December 1996, the Company filed a complaint in the United States District Court for the Southern District of New York against 14 of the Company's insurers which issued general comprehensive liability (GCL) policies to the Company. In January 1998, the Company commenced a similar action against the same and certain additional insurer defendants in New York State Supreme Court, First Department; the federal court action was subsequently dismissed in March 1998. The Company is seeking recovery under the GCL policies for the costs incurred to date and future costs associated with the clean-up of the Company's former manufactured gas plant (MGP) sites and Superfund sites for which the Company has been named a PRP. The Company is seeking a declaratory judgment that the defendant insurers are bound by the 16 terms of the GCL policies, subject to the stated coverage limits, to reimburse the Company for the clean up costs. The outcome of this proceeding cannot yet be determined. Superfund Sites Metal Bank The EPA has notified the Company that it is one of many PRPs that may be liable for the remediation of a licensed disposal site located in Philadelphia, Pennsylvania, and operated by Metal Bank of America. The Company and nine other PRPs, all of which are public utilities, completed performance of a Remedial Investigation and Feasibility Study (RI/FS), which was conducted under an ACO with the EPA. In December 1997, the EPA issued its Record of Decision (ROD), setting forth the final remedial action selected for the site. In the ROD, the EPA estimated that the present cost of the selected remedy for the site is $17.3 million. At this time, the Company cannot predict with reasonable certainty the actual cost of the selected remedy, who will implement the remedy, or the cost, if any, to the Company. Under a PRP participation agreement, the Company previously was responsible for 8.2% of the costs associated with the RI/FS. The Company's allocable share of liability for the remediation activities has not yet been determined. The Company has recorded a liability of approximately $1 million representing its estimated share of the additional cost to remediate this site based upon its 8.2% responsibility under the RI/FS. Syosset The Company and nine other PRPs have been named in a lawsuit where the Town of Oyster Bay (Town) is seeking indemnification for remediation and investigation costs that have been or will be incurred for a federal Superfund site in Syosset, New York. For a further discussion on this matter, see Item 3, Legal Proceedings - Environmental. PCB Treatment, Inc. The Company has also been named a PRP for disposal sites in Kansas City, Kansas, and Kansas City, Missouri. The two sites were used by a company named PCB Treatment, Inc. from 1982 until 1987 for the storage, processing, and treatment of electric equipment, dielectric oils and materials containing PCBs. According to the EPA, the buildings and certain soil areas outside the buildings are contaminated with PCBs. Certain of the PRPs, including the Company and several other utilities, formed a PRP group, signed an ACO, and have developed a workplan for investigating environmental conditions at the sites. Documentation connecting the Company to the sites indicates that the Company was responsible for less than 1% of the materials that were shipped to the Missouri site. The EPA has not yet completed compiling the documents for the Kansas site. Osage The EPA has notified the Company that it is a PRP at the Osage Metals Site, a former scrap metal recycling facility located in Kansas City, Kansas. Under Section 107(a) of CERCLA, parties who arranged for disposal of hazardous substances are liable for costs incurred by the EPA in responding to a release or threat of release of the hazardous substances. Osage had purchased capacitor scrap metal from PCB Treatment, Inc. Through the arrangements that the Company made with PCB Treatment, Inc. to dispose of capacitors, the Company is alleged to have arranged for disposal within the meaning of the federal Superfund law. A similar letter was sent to 861 parties who sent capacitors to PCB Treatment, Inc. The EPA is seeking to recover approximately $1.1 million dollars it expended to conduct a removal action at the site. The Company is currently 17 unable to determine its share of the $1.1 million expenditure. Port Refinery The Company has been notified that it is a PRP at the Port Refinery Superfund site located in Westchester County, New York. Port Refinery was engaged in the business of purchasing, selling, refining and processing mercury and the Company may have shipped a small amount of waste products containing mercury to this site. Tests conducted by the EPA indicated that the site and certain adjacent properties were contaminated with mercury. As a result, the EPA has performed a response action at the site and seeks to recover its costs, currently totaling approximately $4.4 million, plus interest, from the PRPs. The Company does not believe its portion of these costs, if any, will be material. Port Washington In 1989, the EPA notified the Company that it was a PRP for a landfill in Port Washington, New York. The Company does not believe that it sent any materials to the site that contributed to the contamination which requires remediation and has therefore declined the EPA's requests to participate in funding the investigation and remediation activities at the property. The Company has not received further communications regarding this site. Liberty The EPA has notified the Company that it is a PRP in a Superfund site located in Farmingdale, New York. Industrial operations took place at this site for at least fifty years. The PRP group has claimed that the Company should absorb remediation expenses in the amount of approximately $100,000 associated with removing PCB-contaminated soils from a portion of the site which formerly contained electric transformers. The Company is currently unable to determine its share of costs of remediation at this site. Huntington/East Northport The DEC has notified the Company, pursuant to the State Superfund program, that its records indicate the Company may be responsible for the disposal of waste at this municipal landfill property. The Company conducted a search of its corporate records and did not locate any documents concerning waste disposal practices associated with this landfill. The Company is currently unable to determine its share, if any, of the costs to investigate and remediate this site. Blydenburgh The New York State Office of the Attorney General has notified the Company that it may be responsible for the disposal of wastes and/or for the generation of hazardous substances which may have been disposed of at the Blydenburgh Superfund site, a municipal sanitary landfill located in the Town of Islip, Suffolk County. The State has incurred approximately $15 million in costs for the investigation and remediation of environmental conditions at the landfill. In connection with this notification, the Company conducted a review of its corporate records and did not locate any documents concerning waste disposal practices associated with this landfill. The Company is currently unable to determine its share, if any, of the costs to investigate and remediate this site. Other Sites Manufactured Gas Plant Sites The DEC has required the Company and other New York State utilities to investigate and, where necessary, remediate their former MGP sites. Currently, the Company is the owner of six pieces of property on which the Company or certain of its predecessor companies produced manufactured gas. Operations at these facilities in the late 1800's and early 1900's may have resulted in the 18 disposal of certain waste products located at these sites. The Company has entered into discussions with the DEC which are expected to lead to the issuance of one or more ACOs regarding the management of environmental activities at these six properties. Although the exact amount of the Company's cleanup costs cannot yet be determined, based on the findings of preliminary investigations conducted at each of these six sites, current estimates indicate that it may cost approximately $54 to $92 million to investigate and remediate all of these sites. Considering the range of possible remediation estimates, the Company felt it appropriate to record a $54 million liability reflecting the present value of the future stream of payments amounting to $70 million to investigate and remediate these sites. The Company used a risk-free rate of 6.0% to discount this obligation. The Company believes that the PSC will provide for future recovery of these costs and has recorded a $54 million regulatory asset. The Company's rate settlement which the PSC approved February 4, 1998 as discussed in Note 3 of Notes to Financial Statements, allows for the recovery of MGP expenditures from gas customers. The Company is also evaluating its responsibilities with respect to several other former MGP sites that existed in its territory which it does not presently own. Research is underway to determine the existence and nature of operations and relationship, if any, to the Company or its predecessor companies. North Hills Leak The Company has undertaken remediation of certain soil locations in North Hills, New York that were impacted by a release of insulating fluid from an electrical cable in August 1994. The Company estimates that any additional cleanup costs will not exceed $0.5 million. The Company has initiated cost recovery actions against the third parties it believes are responsible for causing the cable leak, the outcome of which are uncertain. Storage Facilities As a result of petroleum leaks from underground storage facilities and other historical occurrences, the Company is required to investigate and, in certain cases, remediate affected soil and groundwater conditions at several facilities within its service territory. The aggregate costs of such remediation work could be between $3 million and $5 million. To the extent that these costs are not recoverable through insurance carriers, the Company believes such costs will be recoverable from its customers. Nuclear Waste Low Level Radioactive Waste The federal Low Level Radioactive Waste Policy Amendment Act of 1985, requires states to arrange for the disposal of all low level radioactive waste generated within the state or, in the alternative, to contract for their disposal at an operating facility outside the state. As a result, New York State has stated its intentions of developing an in-state disposal facility due to the large volume of low level radioactive waste generated within the state and has committed to develop a plan for the management of such waste during the interim period until a disposal facility is available. New York State is still developing a disposal methodology and acceptance criteria for a disposal facility. The latest New York State low level radioactive waste site development schedule now assumes two possible siting scenarios, a volunteer approach and a non-volunteer approach, either of which would not begin operation until at least 2001. Low level radioactive waste generated at NMP2 is currently being disposed of at the Barnwell, South Carolina waste disposal facility which reopened in July 1995 to out-of-state low level waste generators. 19 In the event that off-site storage becomes unavailable prior to 2001, NMPC has implemented a low level radioactive waste management program that will properly handle interim on-site storage of low level radioactive waste for NMP2 for at least ten years. The Company's share of the costs associated with temporary storage and ultimate disposal are currently recovered in rates. Spent Nuclear Fuel NMPC, on behalf of the NMP2 cotenants, has entered into a contract with the DOE for the permanent storage of NMP2 spent nuclear fuel. The Company reimburses NMPC for its 18% share of the cost under the contract at a rate of $1.00 per megawatt hour of net generation less a factor to account for transmission line losses. The Company is collecting its portion of this fee from its electric customers. It is anticipated that the DOE facility may not be available for permanent storage until at least 2010. Currently, all spent nuclear fuel from NMP2 is stored at the NMPC site, and existing facilities are sufficient to handle all spent nuclear fuel generated at NMP2 through the year 2012. For information concerning environmental litigation, see Item 3 "Legal Proceedings" under the heading Environmental. THE COMPANY'S SECURITIES General The Company's securities are rated by Moody's Investors Service, Inc., Standard and Poor's, Fitch IBCA, Inc. and Duff & Phelps Credit Rating Co. For information relating to the ratings of the Company's securities, see Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations." The G&R Mortgage The Company's General and Refunding Indenture dated June 1, 1975 (G&R Mortgage) is a lien upon substantially all of the Company's properties. Outstanding at March 31, 1998 and 1997 were approximately $1.3 billion of G&R Bonds. Under the G&R Mortgage, the Company may issue G&R Bonds on the basis of either matured or redeemed G&R Bonds or on the basis of the Bondable Value of Property Additions (BVPA). Generally, when issuing G&R Bonds, the Company must satisfy a mortgage interest coverage requirement, known as the G&R Mortgage Interest Coverage. The G&R Mortgage Interest Coverage requires that the net earnings as defined in the G&R Indenture, available for interest for any 12 consecutive calendar months within the 15 consecutive calendar months preceding the issuance of any G&R Bonds must be equal to at least two times the stated annual interest payable on outstanding G&R Bonds, including any new G&R Bonds. Under the G&R Mortgage Interest Coverage, the Company would currently be able to issue approximately $5.2 billion of additional G&R Bonds based upon net earnings for the year ended March 31, 1998 and an assumed interest rate of 7.75% for such additional G&R Bonds. A change of 1/8 of 1% in the assumed interest rate of such G&R Bonds would result in a change of approximately $82 million in the amount of such G&R Bonds that the Company could issue. The maximum amount of additional G&R Bonds which the Company is currently able to issue on the basis of either matured or retired G&R Bonds and on the basis of the BVPA is approximately $1.5 billion. Under the provisions of the G&R Mortgage, the Company must also satisfy by June 30 of each year a Sinking Fund requirement, which for the year ended December 31, 1997 is $25 million. The Company believes that, based upon currently scheduled redemptions and maturities, it will 20 have sufficient retired G&R Bonds for the foreseeable future to satisfy the requirements of the G&R Sinking Fund. The G&R Mortgage also contains a Maintenance Fund covenant which requires that the aggregate amount of property additions added subsequent to December 31, 1974 must be, as of the end of each calendar year subsequent to 1974, at least equal to the cumulative provision for depreciation (as defined in the G&R Mortgage) from December 31, 1974. The G&R Mortgage requires cash (or retired G&R Bonds) to be deposited to satisfy the Maintenance Fund requirement only when such cumulative provision for depreciation exceeds such aggregate amount of property additions. As of December 31, 1997, the amount of such cumulative property additions calculated pursuant to the G&R Mortgage was approximately $10.4 billion, including approximately $5.5 billion of property additions attributable to Shoreham. Also, as of December 31, 1997, the amount of the cumulative provision for depreciation, similarly calculated, was approximately $2.0 billion. The Company anticipates that the aggregate amount of property additions will continue to exceed the cumulative provision for depreciation. For a discussion of the effect the LIPA Transaction will have on Company debt outstanding, see Long Island Power Authority Transaction, above. Unsecured Debt The Company's G&R Mortgage and its Restated Certificate of Incorporation do not contain any limitations upon the issuance of unsecured debt. The Company's unsecured debt consists of debentures and certain tax-exempt securities. The Company's Debenture Indenture, dated as of November 1, 1986, as supplemented, and its Debenture Indenture, dated as of November 1, 1992, as supplemented, each provide for the issuance of an unlimited amount of Debentures to be issued in amounts that may be authorized from time to time in one or more series. The debentures are unsecured and rank pari passu with all other unsecured indebtedness of the Company subordinate to the obligations secured by the Company's G&R Mortgage. At March 31, 1998 and 1997, there were approximately $2.3 billion of debentures outstanding. For a discussion of the effect that the LIPA Transaction will have on the Company's G&R Bonds and Debentures, see "Long Island Power Authority Transaction," above. As of March 31, 1998, the Company had outstanding approximately $941 million principal amount of promissory notes, comprised of: (i) $2 million of tax-exempt Industrial Development Revenue Bonds (IDRBs); (ii) approximately $214 million of tax-exempt Pollution Control Revenue Bonds (PCRBs); and (iii) $725 million of tax-exempt Electric Facilities Revenue Bonds (EFRBs). Of these amounts, certain series are subject to periodic tenders. For a discussion of the effect that the LIPA Transaction will have on the Company's tax exempt authority financing notes, see "Long Island Power Authority Transaction," above. For additional information respecting tender provisions and other information on the Company's outstanding debt, see Note 7 of Notes to Financial Statements. Equity Securities Common Stock The Company's common stock is listed on the New York and Pacific Stock Exchanges, and is traded under the symbol "LIL." The Board of Directors' current policy is to pay cash dividends on the common stock on a quarterly basis. However, before declaring any dividends, the Company's Board of Directors considers, among other factors, the Company's financial condition, its ability to 21 comply with provisions of the Company's Restated Certificate of Incorporation and the availability of retained earnings, future earnings and cash. For additional information with respect to the Company's common stock, see Note 6 of Notes to Financial Statements. Preferred Stock The Company's Restated Certificate of Incorporation provides that the Company may not issue additional preferred stock unless, for any 12 consecutive calendar months within the 15 calendar months immediately preceding the calendar month within which such additional shares shall be issued, the net earnings of the Company available for the payment of interest charges on the Company's interest-bearing indebtedness, determined after provision for depreciation and all taxes, and in accordance with sound accounting practice, shall have been at least one and one-half times the aggregate of the annual interest charges on the interest-bearing indebtedness of the Company and annual dividend requirements on all shares of preferred stock to be outstanding immediately after the proposed issue of such shares of the preferred stock (Earnings Ratio). At March 31, 1998, the Company satisfied the Earnings Ratio and could issue up to approximately $1,076 million of preferred stock at an assumed dividend rate of 8.25%. When the proceeds from the sale of the preferred stock to be issued are used to redeem outstanding preferred stock, the requirement to satisfy the Earnings Ratio is not applicable if the dividend requirement and the requirements for redemption in a voluntary liquidation of the preferred stock to be issued do not exceed the respective amounts for the preferred stock which is to be retired. Additional preferred stock may also be issued beyond amounts permitted under the Earnings Ratio with the approval of at least two-thirds of the votes entitled to be cast by the holders of the total number of shares of outstanding preferred stock. For additional information with respect to the Company's preferred stock, see Note 6 of Notes to Financial Statements. Preference Stock Issuance of preference stock, which is subordinate to the Company's preferred stock but senior to its common stock, with respect to declaration and payment of dividends and the right to receive amounts payable on any dissolution, does not require satisfaction of a net earnings test or any other coverage requirement, unless established by the Board of Directors for one or more series of preference stock, prior to the issuance of such series. No preference stock has been issued by the Company, nor does the Company currently plan to issue any. 22 EXECUTIVE OFFICERS OF THE COMPANY Current information regarding the Company's Executive Officers, all of whom serve at the will of the Board of Directors, follows: William J. Catacosinos: Dr. Catacosinos has served as Chairman of the Board of Directors and Chief Executive Officer of the Company since January 1984, and as a Director since December 1978. He currently chairs the Executive Committee of the Company's Board of Directors. Dr. Catacosinos also served as President of the Company from March 1984 to January 1987 and from March 1994 to December 1996. Dr. Catacosinos, 68, a resident of Mill Neck, Long Island, earned a bachelor of science degree, a masters degree in business administration and a doctoral degree in economics from New York University. Dr. Catacosinos is a member of the Boards of Atlantic Bank of New York, the Long Island Association and the Empire State Business Alliance, and is a member of the Advisory Committee of the Huntington Township Chamber Foundation. He is the former Chairman and Chief Executive Officer of Applied Digital Data Systems, Inc., Hauppauge, New York; served as Chairman of the Board and Treasurer of Corometric Systems, Inc. of Wallingford, Connecticut; and served as Assistant Director at Brookhaven National Laboratory, Upton, New York. Theodore A. Babcock: Vice President since January 1997, Treasurer since February 1994 and Assistant Corporate Secretary since January 1996, Mr. Babcock joined the Company in July 1992 as Assistant Treasurer. He previously spent five years with the AMBASE Corporation as an Assistant Vice President and was promoted in 1988 to Vice President and Treasurer. Prior to AMBASE, Mr. Babcock spent 11 years with the Associated Dry Goods Corporation where he was promoted to Assistant Treasurer and Director of Corporate Treasury Operations in 1984. Mr. Babcock, 43, received a bachelor of science degree in accounting from Manhattan College and a masters degree in finance from Iona College. Mr. Babcock is a member of the board of the Huntington Township Chamber Foundation. Michael E. Bray: Senior Vice President of the Electric Business Unit since joining the Company in March 1997. Prior to joining the Company Mr. Bray was President and CEO of DB Riley Consolidated in Worcester, Massachusetts. From 1987-1994 Mr. Bray was with ABB Power Generation, Inc. in Windsor, Connecticut holding the positions of Senior Vice President Sales & Marketing for ABB Power Generation and President of ABB's Resource Recovery Systems organization. Prior to that, he spent 17 years with General Electric Company beginning as a field engineer in the power equipment service organization and ultimately managing General Electric's cogeneration development, construction and operating organization. Mr. Bray, 50, holds a bachelor of science degree in mechanical engineering from the University of Missouri at Rolla and a masters degree in Business Administration from Washington University. Mr. Bray is a member of the American Academy of Mechanical Engineers, past Board of Director/member of American Boiler Manufacturer's Association and the Greater Hartford Chamber of Commerce. He is also a charter member of the Academy of Mechanical Engineers at the University of Missouri at Rolla. Charles A. Daverio: Vice President of The Energy Exchange Group since December 1996, Mr. Daverio, 48, holds a bachelor of engineering degree in mechanical engineering from Manhattan College, a master of science degree in industrial engineering from New York University and a master of business administration from New York Institute of Technology. He joined the Company in 1976 as an Associate Engineer. He held various supervisory and managerial positions in the Nuclear Engineering Department from 1979 through 1989. In 1990, he was assigned Manager of Gas Supply and Planning and was given the additional responsibility for Gas Operations in 1993. Mr. Daverio is the Company's representative on the Iroquois Gas 23 Transmission System's Management Committee and is on the Board of the Iroquois Pipeline Operating Company. Mr. Daverio is a member of the board of the Huntington Arts Council. Jane A. Fernandez: Vice President of Human Resources since May 1997, Ms. Fernandez joined the Company in 1973 and has held various positions in the Employee Relations/Human Resources organization since that time. She was Director of Human Resource Planning from 1988 to 1990, Director of Human Resource Services from 1990 to 1994, Director of Corporate Training and Human Resources in 1994, and Assistant Vice President of Human Resources from 1994 to 1997. Ms. Fernandez, 48, is a graduate of C. W. Post College and holds an MBA in Management from Hofstra University. James T. Flynn: President and member of the Company's Board of Directors since December 1996 and Chief Operating Officer since March 1994, Mr. Flynn joined the Company in October 1986 as Vice President of Fossil Production. He also held the positions of Group Vice President, Engineering and Operations and Executive Vice President. Before joining the Company, Mr. Flynn, 64, was General Manager-Eastern Service Department for General Electric. His career began as a member of General Electric's Technical Marketing Program in 1957. He holds a bachelor of science degree in mechanical engineering from Bucknell University and is a Licensed Professional Engineer in the State of Pennsylvania. Joseph E. Fontana: Vice President since January 1997 and Controller since October 1994, Mr. Fontana joined the Company in December 1992 as Director of Accounting Services. He held the position of Assistant Controller from February 1994 through September 1994. In his capacity as Controller, Mr. Fontana serves as the Company's Chief Accounting Officer. Mr. Fontana is a member of the American Institute of Certified Public Accountants and the New York State Society of CPAs. Before joining the Company, Mr. Fontana was a Senior Manager at the international accounting firm of Ernst & Young, LLP. Mr. Fontana, 40, holds a bachelor of science degree in accounting from Westchester State College and is a Certified Public Accountant. George B. Jongeling: Vice President of Special Projects since April 1998. Prior to joining the Company, Mr. Jongeling was President and Chief Operating Officer of Smith Cogeneration Company, an Independent Power Development Company with active independent power development in Asia and operating plants in the U.S. Previous assignments included Vice President of Operations and Member of the Board of Directors of DB Riley, President of PACE Construction Company, Vice President of Service and Spare Parts for ABB Gas Turbine Business and Vice President of Business Development for ABB waste to energy business. He started his career in 1966 as a field engineer for the General Electric Company and spent 24 years working in the power generation business in domestic and foreign management positions. His last General Electric assignment was as Manager of the Eastern Region of the U.S. for the Systems Marketing Group supporting the cogeneration, construction, development and O&M businesses for General Electric. Mr. Jongeling, 54, received a Bachelor of Science degree in Mechanical Engineering from the South Dakota School of Mines and Technology and is a licensed professional engineer in Illinois and Missouri. Robert X. Kelleher: Senior Vice President of Human Resources since May 1997, Mr. Kelleher joined the Company in 1959 and has held various managerial positions in the Finance, Accounting, Purchasing, Stores, and Employee Relations organizations. He was Industrial Relations Manager from 1975 to 1979, Manager of the Employee Relations Department from 1979 to 1985, Assistant Vice President of the Employee Relations Department from 1985 to 1986, and Vice President of Human Resources from 1986 to 1997. Mr. Kelleher, 61, is a graduate of St. 24 Francis College and the Human Resources Management and Executive Management Programs of Pennsylvania State University. Mr. Kelleher is a member of the American Compensation Association, Personnel Directors Council, Industrial Relations Research Institute and The Edison Electric Institute's Labor Relations Committee. John D. Leonard, Jr.: Vice President of Special Projects since April 1997, Mr. Leonard joined the Company in 1984 as Vice President of Nuclear Operations. He continues to be responsible for nuclear issues. Mr. Leonard served as Vice President of Engineering and Construction from March 1994 through March 1997, and previously served as Vice President of Corporate Services from July 1989 through March 1994. From 1980 to 1984, Mr. Leonard was the Vice President and Assistant Chief Engineer for Design and Analysis at the New York Power Authority. Prior to this position, he served as a Resident Manager of the Fitzpatrick Nuclear Power Plant for approximately five years. Before accepting a position at the New York Power Authority, Mr. Leonard served as Corporate Supervisor of Operational Quality Assurance of the Virginia Electric Power Company from 1974 to 1976. In 1974, Mr. Leonard retired with the rank of Commander from the United States Navy, having commanded two nuclear-powered submarines in a career that spanned 20 years. He holds a bachelor of science degree from Duke University and a master of science degree from the Naval Post Graduate School. He is 65 and a Licensed Professional Engineer in the State of New York. Adam M. Madsen: Senior Vice President of Corporate and Strategic Planning since 1984, Mr. Madsen, 61, holds a bachelors degree in electrical engineering from Manhattan College and a master of science degree in nuclear engineering from Long Island University. He has been with the Company since 1961, serving in various engineering positions including Manager of Engineering from 1978 to 1984. Prior to that time, he held the position of Manager of the Planning Department. Since 1978, Mr. Madsen has been the Company's representative to the Planning Committee of the New York Power Pool. He is a member of the Northeast Power Coordinating Council's Executive Committee and the Council's Reliability Coordinating Committee. He also serves on the Board of Directors of the Empire State Electric Energy Research Company. Mr. Madsen is a Licensed Professional Engineer in the State of New York. Kathleen A. Marion: Vice President of Corporate Services since April 1994 and Corporate Secretary since April 1992, Ms. Marion has served as Assistant to the Chairman since April 1987. She was Assistant Corporate Secretary from April 1990 to April 1992. Ms. Marion, 43, has a bachelor of science degree in business and finance from the State University of New York at Old Westbury. Brian R. McCaffrey: Vice President of Communications since February 1997, Mr. McCaffrey joined the Company in 1973. Mr. McCaffrey, 52, holds a bachelor of science degree in aerospace engineering from the University of Notre Dame. He also received a master of science degree in aerospace engineering from Pennsylvania State University and a master of science degree in nuclear engineering from Polytechnic University. He is a Licensed Professional Engineer in the State of New York. Prior to his present assignment, Mr. McCaffrey was Vice President of Administration since 1987. Previously, Mr. McCaffrey served in many positions in the nuclear organizations of the Company and positions in engineering capacities associated with gas turbine and fossil power station projects. Mr. McCaffrey is a member of the Executive Board of the Suffolk County Council Boy Scouts of America. Joseph W. McDonnell: Senior Vice President of Marketing and External Affairs since December 1996, Dr. McDonnell joined the Company in 1984. Dr. McDonnell was Assistant to the Chairman 25 from 1984 through 1987 when he was named Vice President of Communications. In July 1992 he was named Vice President of External Affairs. Prior to joining the Company, he was the Director of Strategic Planning and Business Administration for Applied Digital Data Systems, Inc. and Associate Director of the University Hospital at the State University of New York at Stony Brook. Dr. McDonnell, 46, holds bachelor of arts and master of arts degrees in philosophy from the State University of New York at Stony Brook and a doctoral degree in communications from the University of Southern California. Leonard P. Novello: Senior Vice President since December 1996, and General Counsel since he joined the Company in April 1995. Before joining the Company, Mr. Novello was General Counsel at the international accounting firm of KPMG Peat Marwick, where he advised senior management on a variety of litigation and corporate issues and was responsible for all legal matters arising out of the firm's operations and its audit, tax and management consulting engagements. Prior to joining Peat Marwick in 1975 as an Associate General Counsel, Mr. Novello was associated with the New York law firm of Cravath, Swaine and Moore. Mr. Novello is active in professional associations and is a member of the Executive Committee of the Litigation Commercial and Federal Section of the New York State Bar Association and the Association of the Bar of the City of New York. He is also a member of the Executive Committee of the CPR Institute for Dispute Resolution. Mr. Novello, 57, has a bachelors degree from the College of the Holy Cross and a juris doctorate from Fordham University. Anthony Nozzolillo: Senior Vice President of Finance and Chief Financial Officer of the Company since February 1994, Mr. Nozzolillo served as the Company's Treasurer from July 1992 to February 1994. He has been with the Company since 1972 serving in various positions including Manager of Financial Planning and Manager of Systems Planning. Mr. Nozzolillo, 49, holds a bachelor of science degree in electrical engineering from the Polytechnic Institute of Brooklyn and a master of business administration degree from Long Island University, C.W. Post Campus. Mr. Nozzolillo is chairman of the Community Advisory Board of Lawrence Public Schools' "School to Career Initiative." Richard Reichler: Deputy General Counsel and Vice President of Tax Planning and Services since January 1997. Mr. Reichler held the positions of Deputy General Counsel and Vice President of Financial Planning and Taxation from January 1995 through December 1996 and Assistant Vice President for Tax and Benefits Planning from October 1992 through December 1994. Prior to joining the Company, he was a partner in the international accounting firm of Ernst & Young LLP for 23 years. Mr. Reichler, 63, holds a bachelor of arts degree from Columbia College and a bachelor of law degree from Columbia University School of Law. Since 1989, he has taught various courses at Baruch College, including state and local taxation, corporate taxation and real estate taxation. He has authored several publications on tax and employee benefit topics and has served as a member of the Executive Committee of the Tax Section of the New York State Bar Association and as an Advisor to the Urban Development Corporation High Technology Advisory Council. William G. Schiffmacher: Senior Vice President of Customer Relations and Information Systems and Technology since December 1996, Mr. Schiffmacher held the positions of Vice President of Customer Relations from April 1994 through November 1996 and Vice President of Electric Operations from July 1990 through March 1994. He joined the Company in 1965 after receiving a bachelor of electrical engineering degree from Manhattan College. Mr. Schiffmacher, 54, also holds a master of science degree in management engineering from Long Island University. He has held a variety of positions in the Company, including Manager of Electric System Operations, 26 Manager of Electrical Engineering and Vice President of Engineering and Construction. Werner J. Schweiger: Vice President of Electric Operations since December 1996, Mr. Schweiger joined the Company in 1981 and has held a number of positions in Electric Operations, as well as in Engineering. Most recently, he was Manager of Electric Systems Engineering from October 1995 through November 1996. Mr. Schweiger, 38, received his bachelors degree in electrical engineering from Manhattan College and also holds a masters degree in Energy Management from the New York Institute of Technology. Richard M. Siegel: Vice President of Information Systems and Technology since December 1996, Mr. Siegel held the position of Director of Information Systems and Technology from June 1995 to December 1996. Mr. Siegel, 51, joined the Company in 1969 as an Associate Engineer and has held progressive management positions in Electric Operations and Engineering, including Manager of Electric System Engineering and Manager of Electric System Operations. Mr. Siegel holds a bachelor of electrical engineering degree from the City College of New York and a master of science degree in Industrial Management from the State University of New York at Stony Brook. Mr. Siegel is a Licensed Professional Engineer in the State of New York. Robert B. Steger: Senior Vice President of Gas Business Unit since December 1996, Mr. Steger held the positions of Vice President of Electric Operations from April 1994 through November 1996 and Vice President of Fossil Production from February 1990 through March 1994. He joined the Company in 1963 and held progressive operating and engineering positions including Manager of Electric Production-Fossil from 1985 through 1989. Mr. Steger, 61, holds a bachelor of mechanical engineering degree from Pratt Institute and is a Licensed Professional Engineer in the State of New York. William E. Steiger, Jr.: Vice President of Facilities and Real Estate since February 1997, Mr. Steiger, 54, held the positions of Vice President of Fossil Production from April 1994 through February 1997 and Vice President of Engineering and Construction from July 1990 through March 1994. During his career with the Company, which began in 1968, he has served, among other positions, as Lead Nuclear Engineer for Shoreham, Chief Operations Engineer for Shoreham, Plant Manager for Shoreham as well as Assistant Vice President of Nuclear Operations. Mr. Steiger, received a bachelor of science degree in marine engineering from the United States Merchant Marine Academy and a master of science degree in nuclear engineering from Long Island University. Edward J. Youngling: Senior Vice President of Engineering & Construction since February 1997, Mr. Youngling joined the Company in 1968 and has held various positions in the offices of Fossil Production, Engineering and Nuclear Operations including service as Department Manager of Nuclear Engineering. In 1988, Mr. Youngling was named Vice President of Conservation and Load Management. In 1990, he became Vice President of Customer Relations, and from March 1993 through March 1994, he was Vice President of Customer Relations and Conservation. In April 1994 he was named Senior Vice President of the Electric Business Unit. Mr. Youngling, 53, holds a bachelor of science degree in mechanical engineering from Lehigh University. Mr. Youngling serves on the board of the Empire State Electric Energy Research Company and is a member of the Executive Committee of the New York Power Pool. Mr. Youngling also serves on the Eastern Advisory Board of the Protection Mutual Insurance Company. 27 CAPITAL REQUIREMENTS, LIQUIDITY AND CAPITAL PROVIDED Information as to "Capital Requirements," "Liquidity" and "Capital Provided" appears in Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations." ITEM 2. PROPERTIES The location and general character of the principal properties of the Company are described in Item 1, "Business" under the headings "Electric Operations" and "Gas Operations." ITEM 3. LEGAL PROCEEDINGS SHOREHAM Pursuant to the LIPA Act, LIPA is required to make payments-in-lieu-of-taxes (PILOTs) to the municipalities that impose real property taxes on Shoreham. Pursuant to the 1989 Settlement, the Company agreed to fund LIPA's obligation to make Shoreham PILOTs. The timing and duration of PILOTs under the LIPA Act were the subject of litigation entitled LIPA, et al. v. Shoreham-Wading River Central School District, et al., brought in Nassau County Supreme Court by LIPA against, among others, Suffolk County, the Town of Brookhaven and the Shoreham-Wading River Central School District. The Company was permitted to intervene in the lawsuit. In June 1996, the New York State Court of Appeals rendered its opinion on the cross-appeals filed by the parties regarding the timing, duration and refundability of PILOTs under the LIPA Act. The Court affirmed portions of a prior ruling by the Appellate Division, Second Department by holding that (a) LIPA's PILOT obligation is perpetual, (b) PILOTs, like taxes, are subject to refund if the assessment upon which the PILOTs were based is determined to be excessive, and (c) PILOTs phase down by ten percent of the prior year's amount, rather than ten percent of the first PILOT year amount, until PILOTs reach a level that equals the taxes that would have been levied on the plant in a non-operative state. Additionally, the Court modified the Appellate Division's ruling by finding that PILOTs commence, not at the time the Company transferred Shoreham to LIPA in February 1992, but rather on December 1, 1992, the beginning of the next tax year. Unless otherwise agreed by the parties, the proper assessment of Shoreham for purposes of determining the proper amount of PILOTs is to be determined in a proceeding challenging the Shoreham assessment for the 1992-93 tax year. If that determination results in PILOTs that are less than the amount of PILOTs that have already been paid, LIPA, and therefore the Company, should be entitled to refunds of excessive PILOTs already made. The costs of Shoreham included real property taxes imposed by, among others, the Town of Brookhaven, and were capitalized by the Company during construction. The Company sought judicial review in New York Supreme Court, Suffolk County (Long Island Lighting Company v. The Assessor of the Town of Brookhaven, et al.) of the assessments upon which those taxes were based for the years 1976 through 1992 (excluding 1979 which had been settled). The Supreme Court consolidated the review of the tax years at issue into two phases: 1976 through 1983 (Phase I); and 1984 through 1992 (Phase II). In January 1996, the Company received approximately $81 million, including interest, from Suffolk County pursuant to ruling by the Supreme Court, upheld on appeal, that found that Shoreham had been overvalued for real property tax purposes in Phase I. 28 In November 1996, the Supreme Court ruled that Shoreham had also been over-assessed for real property tax purposes for Phase II. A judgment was entered on March 26, 1997 in the amount of $868,478,912 which includes interest to November 4, 1996. Suffolk County, the Town of Brookhaven and the Shoreham Wading-River Central School District have appealed the judgment to the Appellate Division, Second Department. All briefs have been filed and oral argument occurred on May 6, 1998. The Court reserved decision. If the assessment for the 1991-92 tax year is used to determine the proper amount of PILOTs this ruling should also result in a refund of approximately $260 million plus interest for PILOTs for the years 1992-1996. The refund of any real property taxes, PILOTs, and interest thereon, net of litigation costs, will be used to reduce electric rates in the future. However, the court's ruling is subject to appeal and, as a result, the Company is unable to determine the amount and timing of any additional real property tax and PILOT refunds. ENVIRONMENTAL In February 1994, a lawsuit was filed in the United States District Court for the Eastern District of New York by the Town of Oyster Bay (Town), against the Company and nine other PRPs. The Town is seeking indemnification for remediation and investigation costs that have been or will be incurred for a federal Superfund site in Syosset, New York, which served as a Town-owned and operated landfill between 1933 and 1975. In a Record of Decision issued in September 1990, the EPA set forth a remedial design plan, the cost of which was estimated at $27 million and is reflected in the Town's lawsuit. In an Administrative Consent Decree entered into between the EPA and the Town in December 1990, the Town agreed to undertake remediation at the site. The Company is participating in a joint PRP defense effort with several other defendants. Liability, if imposed, would be joint and several. An agreement in principal has been reached between the Company, certain other defendants, the State of New York and the Town; any settlement is subject to court approval and if approved would not have a material adverse effect on its financial position, cash flows or results of operations. In March 1996, the Village of Asharoken filed a lawsuit against the Company in the New York Supreme Court, Suffolk County (Incorporated Village of Asharoken, New York, et al. v. Long Island Lighting Company). The Village is seeking monetary damages and injunctive relief based upon theories of negligence, gross negligence and nuisance in connection with the Company's design and construction of the Northport Power Plant which the Village alleges upset the littoral drift, thereby causing beach erosion. In November 1996, the Court decided the Company's motion to dismiss the lawsuit, dismissing two of the three causes of action. The Court limited monetary damages on the surviving continuous nuisance claim to three years prior to the commencement of the action. The Company's liability, if any, resulting from this proceeding cannot yet be determined. However, the Company does not believe that this proceeding will have a material adverse effect on its financial position, cash flows or results of operations. In June 1996, a lawsuit was commenced against the Company in the New York Supreme Court, Suffolk County (Town of Riverhead, et al. v. Long Island Lighting Company), in which the plaintiffs seek monetary damages and injunctive relief based upon theories of nuisance, breach of contract, and breach of the Public Trust in connection with the Company's construction of the Shoreham Nuclear Power Station and the Company's diversion and maintenance of the Wading River Creek. The plaintiffs allege that the diversion of the Wading River Creek and the construction of the Shoreham Nuclear Power Station have caused negative environmental impacts on surrounding areas. The plaintiffs also allege that the Company has contractual obligations to 29 perform annual maintenance dredging of the Wading River Creek and beach replenishment of certain beach front property. In September 1996, the Company filed a motion to dismiss the complaint on numerous grounds. In January 1997, the plaintiffs cross-moved for an order seeking partial summary judgment. The Court issued an Order dated August 26, 1997 which denied both motions except that it dismissed Plaintiffs' cause of action alleging violation of the Public Trust Doctrine and prohibited the Town of Riverhead from suing in its sovereign capacity. The parties have filed notices of intent to appeal this order and discovery has commenced. The Company's liability, if any, resulting from this proceeding cannot yet be determined. However, the Company does not believe that this proceeding will have a material adverse effect on its financial position, cash flows or results of operations. HUMAN RESOURCES Pending before federal and state courts, the federal Equal Employment Opportunity Commission and the New York State Division of Human Rights are charges by several individuals alleging, in separate actions, that the Company discriminated against them, or that they were the subject of harassment, on various grounds. The Company has estimated that any costs to the Company resulting from these matters will not have a material adverse effect on its financial position, cash flows or results of operations. In May 1995, eight participants of the Company's Retirement Income Plan (RIP) filed a lawsuit against the Company, the RIP and Robert X. Kelleher, the Plan Administrator, in the United States District Court for the Eastern District of New York (Becher, et al. v. Long Island Lighting Company, et al.). In January 1996, the Court ordered that this action be maintained as a class action. This proceeding arose in connection with the plaintiffs' withdrawal, approximately 25 years ago, of contributions made to the RIP, thereby resulting in a reduction of their pension benefits. The plaintiffs are now seeking, among other things, to have these reduced benefits restored to their pension accounts. The Company's liability, if any, resulting from this proceeding cannot yet be determined. In November 1997, the Company filed a motion for partial summary judgment with the District Court. On April 28, 1998, the Court denied the Company's motion and permitted the Company to file a further motion for partial summary judgement on additional grounds. The Company maintains that the plaintiff's claims are without merit and intends to defend against said claims. OTHER MATTERS A discussion of legal proceedings related to competitive issues facing the Company appears in Note 12 of Notes to Financial Statements. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS None 30 PART II Item 5. Market for the Registrant's Common Equity and Related Stockholder Matters At March 31, 1998, the Company had 78,314 registered holders of record of common stock. The common stock of the Company is traded on the New York Stock Exchange and the Pacific Stock Exchange. Certain of the Company's preferred stock series are traded on the New York Stock Exchange. The high and low market prices of the Company's common stock and dividends per common share for 1996, 1997 and the first quarter of calendar 1998 are set forth on the table below.
- ----------------------------------------------------- ------------------------------------------------------------------ Fiscal Year Ended March 31, 1998 ------------------------------------------------------------------ 3 Months Ended 3/31/97 6/30/97 9/30/97 12/31/97 3/31/98 - ------------------------------------- --------------- ----------------- --------------- --------------- ---------------- Market price of common stock High 24 1/2 24 1/8 26 30 1/2 31 5/8 Low 21 3/4 22 22 3/4 24 1/8 27 15/16 Dividends per common share .445 .445 .445 .445 .445 - -------------------------------------- -------------- ----------------- -------------- ----------------- -------------- - ----------------------------------------------------- ---------------------------------------------------------------- Calendar Year Ended December 31, 1996 ---------------------------------------------------------------- 3 Months Ended 3/31/96 6/30/96 9/30/96 12/31/96 - ------------------------------------- --------------- --------------- ---------------- --------------- --------------- Market price of common stock High 18 1/8 17 7/8 17 3/4 22 3/8 Low 15 7/8 16 1/8 16 5/8 17 1/8 Dividends per common share .445 .445 .445 .445 - -------------------------------------- -------------- --------------- ---------------- --------------- ---------------
31
ITEM 6. SELECTED FINANCIAL DATA (In thousands of dollars except per share amounts) - ------------------------------------------------------------------------------------------------------------------------------------ March 31 March 31 December 31 December 31 For the year ended 1998 1997 1996 1995 - ------------------------------------------------------------------------------------------------------------------------------------ REVENUES Electric $ 2,478,435 $ 2,464,957 2,466,435 $ 2,484,014 Gas 645,659 672,705 684,260 591,114 - ------------------------------------------------------------------------------------------------------------------------------------ Total Revenues 3,124,094 3,137,662 3,150,695 3,075,128 - ------------------------------------------------------------------------------------------------------------------------------------ OPERATING EXPENSES Operations - fuel and purchased power 957,807 954,848 963,251 834,979 Operations - other 400,045 372,880 381,076 383,238 Maintenance 111,120 116,988 118,135 128,155 Depreciation and amortization 158,537 154,921 153,925 145,357 Base financial component amortization 100,971 100,971 100,971 100,971 Rate moderation component amortization (35,079) (2,999) (24,232) 21,933 Regulatory liability component amortization (79,359) (79,359) (79,359) (79,359) 1989 Settlement credits amortization (9,213) (9,213) (9,214) (9,214) Other regulatory amortization 47,272 112,294 127,288 161,605 Operating taxes 466,326 469,561 472,076 447,507 Federal income tax - current 86,388 52,737 42,197 14,596 Federal income tax - deferred and other 150,983 157,873 168,000 193,742 - ------------------------------------------------------------------------------------------------------------------------------------ Total Operating Expenses 2,355,798 2,401,502 2,414,114 2,343,510 - ------------------------------------------------------------------------------------------------------------------------------------ Operating Income 768,296 736,160 736,581 731,618 - ------------------------------------------------------------------------------------------------------------------------------------ OTHER INCOME AND (DEDUCTIONS) Rate moderation component carrying charges 23,632 25,279 25,259 25,274 Other income and deductions, net (18,156) 13,921 19,197 34,400 Class Settlement (15,623) (19,895) (20,772) (21,669) Allowance for other funds used during construction 3,846 2,886 2,888 2,898 Federal income tax - current 594 -- -- -- Federal income tax - deferred and other 4,124 (723) 940 2,800 - ------------------------------------------------------------------------------------------------------------------------------------ Total Other Income and (Deductions) (1,583) 21,468 27,512 43,703 - ------------------------------------------------------------------------------------------------------------------------------------ Income Before Interest Charges 766,713 757,628 764,093 775,321 - ------------------------------------------------------------------------------------------------------------------------------------ INTEREST CHARGES Interest on long-term debt 351,261 372,108 384,198 412,512 Other interest 57,805 66,818 67,130 63,461 Allowance for borrowed funds used during construction (4,593) (3,707) (3,699) (3,938) - ------------------------------------------------------------------------------------------------------------------------------------ Total Interest Charges 404,473 435,219 447,629 472,035 - ------------------------------------------------------------------------------------------------------------------------------------ NET INCOME 362,240 322,409 316,464 303,286 Preferred stock dividend requirements 51,813 52,113 52,216 52,620 - ------------------------------------------------------------------------------------------------------------------------------------ EARNINGS FOR COMMON STOCK $ 310,427 $ 270,296 264,248 $ 250,666 ==================================================================================================================================== AVERAGE COMMON SHARES OUTSTANDING (000) 121,415 $ 120,620 120,360 119,195 - ------------------------------------------------------------------------------------------------------------------------------------ BASIC AND DILUTED EARNINGS PER COMMON SHARE $ 2.56 2.24 2.20 $ 2.10 ==================================================================================================================================== Common stock dividends declared per share $ 1.78 1.78 1.78 $ 1.78 Common stock dividends paid per share $ 1.78 1.78 1.78 $ 1.78 Book value per common share at $ 21.88 21.07 20.89 $ 20.50 Common shares outstanding at (000) 121,681 120,987 120,781 119,655 Common shareowners of record at 78,314 77,691 86,607 93,088 ==================================================================================================================================== TOTAL ASSETS $ 11,900,725 $ 11,849,574 12,209,679 $ 12,527,597 LONG-TERM DEBT $ 4,381,949 $ 4,457,047 4,456,772 $ 4,706,600 PREFERRED STOCK - REDEMPTION REQUIRED $ 562,600 $ 638,500 638,500 $ 639,550 PREFERRED STOCK - NO REDEMPTION REQUIRED $ -- $ 63,598 63,664 $ 63,934 COMMON SHAREOWNERS' EQUITY $ 2,662,447 $ 2,549,049 2,523,369 $ 2,452,953 ITEM 6. SELECTED FINANCIAL DATA (In thousands of dollars except per share amounts) - ------------------------------------------------------------------------------------------------- December 31 December 31 For the year ended 1994 1993 - ------------------------------------------------------------------------------------------------- REVENUES Electric $ 2,481,637 $ 2,352,109 Gas 585,670 528,886 - ------------------------------------------------------------------------------------------------ Total Revenues 3,067,307 2,880,995 - ------------------------------------------------------------------------------------------------ OPERATING EXPENSES Operations - fuel and purchased power 847,986 827,591 Operations - other 406,014 387,808 Maintenance 134,640 133,852 Depreciation and amortization 130,664 122,471 Base financial component amortization 100,971 100,971 Rate moderation component amortization 197,656 88,667 Regulatory liability component amortization (79,359) (79,359) 1989 Settlement credits amortization (9,214) (9,214) Other regulatory amortization 4,328 (18,044) Operating taxes 406,895 385,847 Federal income tax - current 10,784 6,324 Federal income tax - deferred and other 170,997 178,530 - ------------------------------------------------------------------------------------------------ Total Operating Expenses 2,322,362 2,125,444 - ------------------------------------------------------------------------------------------------ Operating Income 744,945 755,551 - ------------------------------------------------------------------------------------------------ OTHER INCOME AND (DEDUCTIONS) Rate moderation component carrying charges 32,321 40,004 Other income and deductions, net 35,343 38,997 Class Settlement (22,730) (23,178) Allowance for other funds used during construction 2,716 2,473 Federal income tax - current -- -- Federal income tax - deferred and other 5,069 12,578 - ------------------------------------------------------------------------------------------------ Total Other Income and (Deductions) 52,719 70,874 - ------------------------------------------------------------------------------------------------ Income Before Interest Charges 797,664 826,425 - ------------------------------------------------------------------------------------------------ INTEREST CHARGES Interest on long-term debt 437,751 466,538 Other interest 62,345 67,534 Allowance for borrowed funds used during construction (4,284) (4,210) - ------------------------------------------------------------------------------------------------ Total Interest Charges 495,812 529,862 - ------------------------------------------------------------------------------------------------ NET INCOME 301,852 296,563 Preferred stock dividend requirements 53,020 56,108 - ------------------------------------------------------------------------------------------------ EARNINGS FOR COMMON STOCK $ 248,832 $ 240,455 ================================================================================================ AVERAGE COMMON SHARES OUTSTANDING (000) 115,880 112,057 - ------------------------------------------------------------------------------------------------ BASIC AND DILUTED EARNINGS PER COMMON SHARE $ 2.15 $ 2.15 ================================================================================================ Common stock dividends declared per share $ 1.78 $ 1.76 Common stock dividends paid per share $ 1.78 $ 1.75 Book value per common share at $ 20.21 $ 19.88 Common shares outstanding at (000) 118,417 112,332 Common shareowners of record at 96,491 94,877 ================================================================================================= TOTAL ASSETS $ 12,479,289 $ 12,453,771 LONG-TERM DEBT $ 5,145,397 $ 4,870,340 PREFERRED STOCK - REDEMPTION REQUIRED $ 644,350 $ 649,150 PREFERRED STOCK - NO REDEMPTION REQUIRED $ 63,957 $ 64,038 COMMON SHAREOWNERS' EQUITY $ 2,393,628 $ 2,232,950
32 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS On April 11, 1997, the Company changed its year end from December 31 to March 31. Accordingly, unless otherwise indicated, references to 1998 and 1997 represent the twelve month periods ended March 31, 1998 and March 31, 1997, respectively, while references to all other periods refer to the respective calendar years ended December 31. Effects of LIPA and KeySpan Transactions on Future Operations The future operations and financial position of the Company will be significantly affected by each of the proposed transactions with LIPA and KeySpan described below. The discussion contained in this management's discussion and analysis of financial condition and results of operations does not reflect, unless otherwise indicated, the potential effects of the transactions with LIPA and KeySpan. RESULTS OF OPERATIONS EARNINGS Earnings for the years ended March 31, 1998 and March 31, 1997 were as follows: (In millions of dollars and shares except earnings per share) - --------------------------------------------------------------- ------------- 1998 1997 - --------------------------------------------------------------- ------------- Net income $362.2 $322.4 Preferred stock dividend requirements 51.8 52.1 =============================================================== ============= Earnings for common stock $310.4 $270.3 =============================================================== ============= Average common shares outstanding 121.4 120.6 =============================================================== ============= Basic and diluted earnings per common share $ 2.56 $ 2.24 =============================================================== ============= For the year ended March 31, 1998 the Company had higher earnings in the electric business partially offset by lower earnings in the gas business compared to the year ended March 31, 1997. In the electric business, the increase in earnings for the year ended March 31, 1998, was primarily due to a change in the method of amortizing the Rate Moderation Component (RMC) to eliminate the effects of seasonality on monthly operating income, as more fully discussed in the section titled "Rate Moderation Component." This positive contributor to earnings more than offset the effects of lower short-term interest income and the accruals for certain obligations for key employees , as more fully discussed in Note 8 of Notes to Financial Statements. The decrease in earnings in the gas business for the year ended March 31, 1998 resulted from lower short-term interest income and the accruals, noted above, partially offset by lower operations and maintenance expenses. Earnings for the years ended December 31, 1996 and December 31, 1995 were as follows: (In millions of dollars and shares except earnings per share) - --------------------------------------------- -------------- --------------- 1996 1995 - --------------------------------------------- -------------- --------------- Net income $316.5 $303.3 Preferred stock dividend requirements 52.2 52.6 ============================================= ============== =============== Earnings for common stock $264.3 $250.7 ============================================= ============== =============== Average common shares outstanding 120.4 119.2 ============================================= ============== =============== Basic and diluted earnings per common share $ 2.20 $ 2.10 ============================================= ============== =============== 33 The Company's 1996 earnings were higher for both its electric and gas businesses as compared to 1995. While the Company's allowed rate of return in 1996 was the same as 1995, the higher earnings for the electric business were the result of the Company's increased investment in electric plant in 1996, as compared to 1995. Also contributing to the increase in electric business earnings were the Company's continued efforts to reduce operations and maintenance expenses and the efficient use of cash generated by operations to retire maturing debt. The increase in earnings in the gas business was the result of additional revenues due to the continued growth in the number of gas space heating customers. Also contributing to the increase in gas business earnings was a 3.2% rate increase which became effective December 1, 1995, and an increase in off-system gas sales. REVENUES Electric Revenues The table below provides a summary of the Company's electric revenues, sales and customers.
- ------------------------------------------------------------------------------------------------------------------- Years Ended March 31, Years Ended December 31, - ------------------------------------------------------------------------------------------------------------------- REVENUES (000) 1998 1997 1996 1995 - ------------------------------------------------------------------------------------------------------------------- Residential $1,206,640 $1,199,976 $1,205,133 $1,204,987 Commercial and industrial 1,194,725 1,178,471 1,174,499 1,194,014 Other system revenues 47,832 50,499 50,513 52,472 - ------------------------------------------------------------------------------------------------------------------- Total system revenues 2,449,197 2,428,946 2,430,145 2,451,473 Other revenues 29,238 36,011 36,290 32,541 ================================================================================================------------------- Total Revenues $2,478,435 $2,464,957 $2,466,435 $2,484,014 ================================================================================================------------------- SALES - MILLIONS OF KWH Residential 7,170 7,121 7,203 7,156 Commercial and industrial 8,375 8,209 8,242 8,336 Other system sales 415 437 441 460 ================================================================================================------------------- Total system sales 15,960 15,767 15,886 15,952 ================================================================================================------------------- CUSTOMERS - MONTHLY AVERAGE Residential 928,580 922,330 920,930 915,162 Commercial and industrial 105,795 104,703 104,488 103,669 - -------------------------------------------------------------------------------------------------------------------
Years Ended March 31, 1998 and 1997 The Company's electric revenues fluctuate mainly as a result of system growth, variations in weather and fuel costs, as electric base rates have remained unchanged since December 1993. However, these variations have no impact on earnings due to the current electric rate structure which includes a revenue reconciliation mechanism to eliminate the impact on earnings caused by sales volumes that are above or below adjudicated levels. The slight increase in revenues for the year ended March 31, 1998, when compared to the year ended March 31, 1997, was primarily due to higher system sales volumes resulting in part from the addition of approximately 8,000 new electric customers and higher fuel expense recoveries, partially offset by lower sales to other utilities. Years Ended December 31, 1996 and 1995 The Company experienced a growth in electric system sales in 1996 on a weather-normalized basis compared to 1995. This growth is primarily attributable to the addition of new electric customers. 34 For a further discussion on electric rates, see Note 4 of Notes to Financial Statements. Gas Revenues The table below provides a summary of the Company's gas revenues, sales and customers.
- --------------------------------------------------------------------------------------------------------------------------- Years Ended March 31, Years Ended December 31, - --------------------------------------------------------------------------------------------------------------------------- REVENUES (000) 1998 1997 1996 1995 - --------------------------------------------------------------------------------------------------------------------------- Residential $390,990 $396,143 $414,749 $365,775 Commercial and industrial 145,861 163,824 181,356 165,257 - --------------------------------------------------------------------------------------------------------------------------- Total firm revenues 536,851 559,967 596,105 531,032 Interruptible revenues 37,565 42,584 37,927 32,837 - --------------------------------------------------------------------------------------------------------------------------- Total system revenues 574,416 602,551 634,032 563,869 Other revenues 71,243 70,154 50,228 27,245 =========================================================================================================================== Total Revenues $645,659 $672,705 $684,260 $591,114 =========================================================================================================================== SALES - THOUSANDS OF DTH Residential 37,417 39,286 40,850 38,265 Commercial and industrial 17,168 19,341 21,054 20,439 - --------------------------------------------------------------------------------------------------------------------------- Total firm sales 54,585 58,627 61,904 58,704 Interruptible sales 9,130 8,399 7,869 9,176 Off-system sales 10,372 10,036 7,457 7,743 - --------------------------------------------------------------------------------------------------------------------------- Total Sales 74,087 77,062 77,230 75,623 ========================================================================================================------------------- CUSTOMERS - MONTHLY AVERAGE Residential 415,369 411,734 410,922 407,566 Commercial and industrial 44,917 45,684 45,887 45,340 - --------------------------------------------------------------------------------------------------------------------------- Total firm customers 460,286 457,418 456,809 452,906 Interruptible customers 688 659 651 623 Firm transportation customers 3,589 833 349 - - ---------------------------------------------------------------------------------------------------------------------------
Years Ended March 31, 1998 and 1997 Despite an increase of approximately 5,600 gas space heating customers, gas revenues decreased primarily as a result of lower sales volumes due to warmer weather experienced during the year ended March 31, 1998 when compared to the year ended March 31, 1997. In 1998 and 1997, other gas revenues totaled $71 million and $70 million, respectively. Included in other gas revenues is off-system gas sales which totaled $34 million and $43 million, for 1998 and 1997, respectively. Profits generated from off-system gas sales are allocated 85% to firm gas customers and 15% to the shareowners, in accordance with PSC mandates. Off-system gas sales decreased as the demand for natural gas declined as a direct result of the warmer weather experienced in this region during this period. Years Ended December 31, 1996 and 1995 The increase in 1996 gas revenues when compared to 1995 is attributable to a 3.2% gas rate increase which became effective on December 1, 1995, higher sales volumes, an increase in gas fuel expense recoveries driven by higher sales volumes, and revenues generated through non-traditional services, including off-system gas sales. The recovery of gas fuel expenses in 1996 when compared to 1995 increased approximately $31 million as a result of higher average gas prices and increased per customer usage due to colder weather than experienced in the prior year. In 1996 and 1995, other gas 35 revenues totaled $50 million and $27 million, respectively. Included in other gas revenues is off-system gas sales which totaled $37 million and $24 million for 1996 and 1995, respectively. OPERATING EXPENSES Fuel and Purchased Power Electric System Fuel and purchased power expenses for the years ended March 31, 1998 and 1997, and for the years ended December 31, 1996 and 1995 were as follows:
(In millions of dollars) - -------------------------------------------------- ------------------------------- ----------------------------------- Years Ended Years Ended March 31, December 31, --------- ------------ 1998 1997 1996 1995 - -------------------------------------------------- --------------- --------------- --------------- ------------------- Fuel for Electric Operations Oil $123 $128 $158 $ 98 Gas 197 170 138 149 Nuclear 15 15 15 14 Purchased power 324 333 329 310 ================================================== =============== =============== =============== =================== Total $659 $646 $640 $571 ================================================== =============== =============== =============== ===================
Variations in fuel and purchased power costs have no impact on operating results as the Company's current electric rate structure includes a mechanism that provides for the recovery of fuel costs which are greater than the costs collected in base rates. If the actual fuel costs are less than the amounts included in base rates, the difference is credited to the RMC balance. Electric fuel and purchased power mix for the years ended March 31, 1998 and 1997, and years ended December 31, 1996 and 1995 were as follows:
(In thousands of MWh) - --------------------------------------------------------------------------------------------------------------- Years Ended Years Ended March 31, December 31, --------- ------------ 1998 1997 1996 1995 - --------------------------------------------------------------------------------------------------------------- MWh % MWh % MWh % MWh % - --------------------------------------------------------------------------------------------------------------- Oil 3,434 20% 3,278 19% 4,219 24% 3,099 17% Gas 6,212 35% 5,469 31% 4,542 25% 6,344 36% Nuclear 1,545 9% 1,553 9% 1,558 9% 1,301 7% Purchased power 6,412 36% 7,261 41% 7,388 42% 7,143 40% - --------------------------------------------------------------------------------------------------------------- Total 17,603 100% 17,561 100% 17,707 100% 17,887 100% ===============================================================================================================
In May 1997, the Company completed the second of two planned conversions of oil-fired steam generating units at its Port Jefferson Power Station to dual firing units, bringing the total number of steam units capable of burning natural gas to nine. As a result, seven of the Company's nine steam generating units are currently dual-fired, providing the Company with the ability to burn the most cost-efficient fuel available, consistent with seasonal environmental requirements. Years Ended March 31, 1998 and 1997 Electric fuel costs increased as a result of higher system sales volumes. During 1998, the price per kWh of power purchased increased over 1997. As a result, the Company changed the mix of generation and purchased power in 1998 when compared to 1997 by generating more electricity using gas and oil rather than purchasing the equivalent energy from off-system. 36 Years Ended December 31, 1996 and 1995 As a result of a sharp increase in the cost of natural gas in 1996, generation with oil became more economical than generation with gas. The total barrels of oil consumed for electric operations were 7.1 million and 5.2 million for the years 1996 and 1995, respectively. Gas System Variations in gas fuel costs have no impact on operating results as the Company's current gas rate structure includes a fuel adjustment clause whereby variations between actual fuel costs and fuel costs included in base rates are deferred and subsequently returned to or collected from customers. Effective February 5, 1998, in accordance with the Stipulation, discussed in Note 3 of Notes to Financial Statements, total gas fuel costs are recovered through the gas fuel adjustment clause. Years Ended March 31, 1998 and 1997 Gas system fuel expense totaled $299 million and $309 million for the years ended March 31, 1998 and 1997, respectively. The decrease is due to lower firm sales volumes and lower off-system gas sales resulting from warmer weather experienced in this region during this period. Years Ended December 31, 1996 and 1995 For the years ended December 31, 1996 and 1995, gas system fuel expense totaled $323 million and $264 million, respectively. The increase of $59 million was due to higher firm sales volumes, an increase in the Company's average price of gas and higher off-system gas sales. Operations and Maintenance Expenses Years Ended March 31, 1998 and 1997 Operations and Maintenance (O&M) expenses, excluding fuel and purchased power, were $511 million and $490 million, for the years ended March 31, 1998 and 1997, respectively. This increase in O&M was primarily due to the recognition of higher performance-based employee incentives and certain other charges for empoloyee benefits related to the KeySpan/LILCO merger. Years Ended December 31, 1996 and 1995 O&M expenses, excluding fuel and purchased power, were $499 million and $511 million, for the years ended December 31, 1996 and 1995, respectively. This decrease in O&M was primarily due to the Company's cost containment program which resulted in lower plant maintenance expenses, lower distribution expenses and lower administrative and general expenses. Rate Moderation Component The Rate Moderation Component (RMC) represents the difference between the Company's revenue requirements under conventional ratemaking and the revenues provided by its electric rate structure. In addition, the RMC is also adjusted for the operation of the Company's Fuel Moderation Component (FMC) mechanism and the difference between the Company's share of actual operating costs at Nine Mile Point Nuclear Power Station, Unit 2 (NMP2) and amounts provided for in electric rates. 37 In April 1998, the PSC authorized a revision to the Company's method for recording its monthly RMC amortization. Prior to this revision, the amortization of the annual level of RMC was recorded monthly on a straight-line, levelized basis over the Company's rate year which runs from December 1 to November 30. However, revenue requirements fluctuate from month to month based upon consumption, which is greatly impacted by the effects of weather. Under this revised method, effective December 1, 1997, the monthly amortization of the annual RMC level varies based upon each month's forecasted revenue requirements, which more closely aligns such amortization with the Company's cost of service. As a result of this change, for the fiscal year ended March 31, 1998, the Company recorded approximately $65.1 million more of non-cash RMC credits to income (representing accretion of the RMC balance), or $42.5 million net of tax, representing $.35 per share than it would have under the previous method. However, the total RMC amortization for the rate year ended November 30, 1998, will be equal to the amount that would have been provided for under the previous method. The Company continues to believe that the full amortization and recovery of the RMC balance, which at March 31, 1998, was approximately $434 million, will take place within the time frame established by the Rate Moderation Agreement (RMA), in accordance with the rate plans submitted to the Public Service Commission of the State of New York (PSC) for the single rate year 1997 and the three year rate period 1997 through 1999. In December 1997, the Company received PSC approval to continue the RMC mechanism and the LILCO Ratemaking and Performance Plan (LRPP) ratemaking mechanisms and incentives for the electric rate year ending November 30, 1997. In the event that the LIPA Transaction is not consummated, the Company expects that the PSC will issue an order providing for, among other things, the continuing recovery, through rates, of the RMC balance, one of the Shoreham-related regulatory assets. If such an electric rate order is not obtained or does not provide for the continuing recovery of the RMC balance, the Company may be required to write-off the amount not expected to be provided for in rates. For a further discussion of the LIPA Transaction, see Note 2 of Notes to Financial Statements. Years Ended March 31, 1998 and 1997 For the years ended March 31, 1998 and March 31, 1997, the Company recorded non-cash credits to income of approximately $52 million and $30 million, respectively, representing the amount by which revenue requirements exceeded revenues provided for under the current electric rate structure. Partially offsetting these accretions were the effects of the FMC mechanism and the differences between actual and adjudicated operating costs for NMP2, as discussed above. The adjustments to the accretion of the RMC totaled $17 million and $27 million, respectively, of which $12 million and $23 million, respectively, were derived from the operation of the FMC mechanism. Years Ended December 31, 1996 and 1995 For the year ended December 31, 1996, the Company recorded a non-cash credit to income of approximately $50 million, representing the amount by which revenue requirements exceeded revenues provided for under the current electric rate structure. Partially offsetting this accretion were the effects of the FMC mechanism and the differences between actual and adjudicated operating costs for NMP2. The adjustments to the accretion of the RMC totaled $26 million, of which $24 million was derived from the operation of the FMC mechanism. 38 For the year ended December 31, 1995, the Company recorded a non-cash charge to income of approximately $22 million, after giving effect to the credits generated principally by the operation of the FMC mechanism. FMC credits for 1995 totaled approximately $87 million. For a further discussion of the RMC, see Note 4 of Notes to Financial Statements. Other Regulatory Amortization The significant components of other regulatory amortization are the following:
(In millions of dollars) - ----------------------------------------- ------------------------------------------------------------------------- (Income)Expense - ----------------------------------------- ------------------------------------------------------------------------- Years Ended Years Ended March 31 December 31 - ----------------------------------------- ------------- --------------- ------------ --------------- -------------- 1998 1997 1996 1995 - ----------------------------------------- ------------- --------------- ------------ --------------- -------------- Net Margin $ 2 $ (5) $ 3 $ 64 LRPP Amortization - 42 59 53 Excess Earnings - Electric (3) 21 10 3 Excess Earnings - Gas 10 10 10 1 Shoreham Post Settlement Costs 31 30 29 27 Other 7 14 16 14 ========================================= ============= =============== ============ =============== ============== $47 $112 $127 $162 ========================================= ============= =============== ============ =============== ==============
Net Margin- An electric business unit revenue reconciliation mechanism, established under the LRPP, which eliminates the impact on earnings of experiencing sales that are above or below adjudicated levels by providing a fixed annual net margin level (defined as sales revenue, net of fuel and gross receipts taxes). Variations in electric revenue resulting from differences between actual and adjudicated net margin sales levels are deferred on a monthly basis during the rate year through a charge or credit to other regulatory amortization. These deferrals are then refunded to or recovered from ratepayers as explained below under "LRPP Amortization." LRPP Amortization- As established under the LRPP, deferred balances resulting from the net margin, electric property tax expense reconciliation, earned performance incentives, and associated carrying charges are accumulated during each rate year. The first $15 million of the total deferral is recovered from or credited to electric ratepayers by increasing or decreasing the RMC balance. Amounts deferred in excess of $15 million, upon approval by the PSC, are refunded to or recovered from ratepayers through the Fuel Cost Adjustment (FCA) mechanism over a subsequent 12-month period, with the offset being recorded in other regulatory amortization. For the rate years ended November 30, 1997 and 1996, the total amount deferred under the LRPP was $4.0 and $15.0 million, respectively. Such amounts were credited against the RMC balance. Years Ended March 31, 1998 and 1997 For the year ended March 31, 1998, there was no LRPP amortization, as the Company has not yet received approval from the PSC to begin refunding $26 million of the remaining deferred LRPP balance in excess of $15 million for the rate year ended November 30, 1995. For the year ended March 31, 1997, the Company recognized $42.4 million of non-cash charges to income representing the amortization of the deferred LRPP balance related to the rate year ended November 30, 1994. 39 Years Ended December 31, 1996 and 1995 For the year ended December 31, 1996, the Company recognized $58.7 million of non-cash charges to income representing the amortization of the deferred LRPP balance related to the rate year ended November 30, 1994. For the year ended December 31, 1995, the Company recognized $52.9 million of non-cash charges to income representing the amortization of the deferred LRPP balance related to the rate year ended November 30, 1993. For a further discussion of the LRPP, see Note 4 of Notes to Financial Statements. Excess Earnings - Also recorded in other regulatory amortization, if applicable, are non-cash charges representing: (a) 100% of electric earnings generated by the Company in excess of amounts provided for in electric rates, which is returned to the electric customer through a reduction to the RMC balance; and (b) 50% of the gas earnings generated by the Company in excess of amounts provided for in gas rates, which will be returned to the firm gas customer. Effective February 5, 1998, the Company, in accordance with the Stipulation discussed in Note 3 of Notes to Financial Statements, established a gas balancing account in order to defer excess gas earnings for future disposition. For the rate year ended November 30, 1997, the electric business earned $4.8 million in excess of its allowed return on common equity and the firm gas customers' portion of the gas business earnings was $6.3 million. Shoreham Post Settlement Costs - Represents the amortization of Shoreham decommissioning costs, fuel disposal costs, payments-in-lieu-of-taxes, carrying charges and other costs over a forty-year period on a straight line remaining life basis. Years Ended March 31, 1998 and 1997 Other regulatory amortization was a non-cash charge to income of $47 million and $112 million for the years ended March 31, 1998 and 1997, respectively. For the year ended March 31, 1997, the Company recognized approximately $42 million of charges representing the amortization of the deferred LRPP balance associated with the rate year ended November 30, 1994. For the year ended March 31, 1998, there was no LRPP amortization, as the Company has not yet received approval from the PSC to begin refunding $26 million of the remaining deferred LRPP balance in excess of $15 million for the rate year ended November 30, 1995. Also contributing to the decrease in other regulatory amortization was the timing of the recognition of electric excess earnings for the rate years ended November 30, 1997 and 1996. Years Ended December 31, 1996 and 1995 Other regulatory amortization was a non-cash charge to income of $127 and $162 for the years ended December 31, 1996 and 1995, respectively. This decrease is primarily attributable to the operation of the net margin, discussed above. For the year ended December 31, 1995, the amount deferred related to the net margin amounted to $64 million compared to $3 million for the year ended December 31, 1996. 40 Operating Taxes Operating taxes were $466 million and $470 million for the years ended March 31, 1998 and 1997, respectively. The decrease in 1998 is primarily attributable to the expiration of the Corporate Tax Surcharge and lower gross receipts taxes related to lower gas revenues. For the years ended December 31, 1996 and 1995, operating taxes were $472 million and $448 million, respectively. The increase in 1996 compared to 1995 is primarily related to higher property taxes and higher gross receipts taxes, due to increased revenues. Federal Income Tax Federal income tax was $233 million and $211 million for the years ended March 31, 1998 and 1997, respectively. For the years ended December 31, 1996 and December 31, 1995, federal income tax was $209 million and $206 million, respectively. The increase in federal income tax for both periods was primarily attributable to higher pre-tax earnings partially offset by the utilization of investment tax credits. Other Income and Deductions, Net Years Ended March 31, 1998 and 1997 Other income and deductions was a $22 million charge to income for the year ended March 31, 1998, compared to a $14 million credit to income for the same period in 1997. The difference, which amounts to approximately $36 million, relates primarily to a charge of approximately $31 million with respect to certain benefits earned by its officers recorded in 1998. For a further discussion of this matter, see Note 8 of Notes to Financial Statements. Years Ended December 31, 1996 and 1995 Other income and deductions totaled $19 million for the year ended December 31, 1996, compared to $34 million for the same period in 1995. The decrease in 1996 when compared to 1995 is primarily attributable to the recognition of non-recurring expenditures associated with one of the Company's wholly-owned subsidiaries, a decrease in non-cash carrying charge income associated with regulatory assets not currently in rate base and the recognition in 1995 of certain litigation proceeds related to the construction of the Shoreham Nuclear Power Station. INTEREST EXPENSE Years Ended March 31, 1998 and 1997 Interest expense for the year ended March 31, 1998 totaled $409 million compared to $439 million for the year ended March 31, 1997. This decrease is primarily attributable to lower outstanding debt levels as the Company retired $250 million of G&R Bonds in February 1997. Years Ended December 31, 1996 and 1995 Interest expense for the year ended December 31, 1996 totaled $451 million compared to $476 million for the year ended December 31, 1995. This decrease is primarily attributable to lower outstanding debt levels, partially offset by higher letter of credit and commitment fees associated with the change in the Company's credit rating in 1996. 41 LIQUIDITY AND CAPITAL RESOURCES LIQUIDITY For the year ended March 31, 1998, cash generated from operations exceeded the Company's operating, construction and dividend requirements. This positive cash flow is the result of, among other things: (i) the Company's continuing efforts to control both O&M expenses and construction expenditures; (ii) lower interest payments resulting from lower debt levels; and (iii) lower fuel expenditures. At March 31, 1998, the Company's cash and cash equivalents amounted to approximately $181 million, compared to $65 million at March 31, 1997. In addition, the Company has available for its use a revolving line of credit through October 1, 1998, provided by its 1989 Revolving Credit Agreement (1989 RCA). This line of credit is secured by a first lien upon the Company's accounts receivable and fuel oil inventories. In July 1997, the Company utilized $40 million in interim financing under the RCA, which was repaid in August 1997. The Company will, in order to satisfy short-term cash requirements, continue to avail itself of interim financing through the RCA, as necessary. For a further discussion of the 1989 RCA, see Note 7 of Notes to Financial Statements. The Company does not intend to access the financial markets during 1998 to meet any of its ongoing operating, construction or refunding requirements. However, the Company will avail itself of any tax-exempt financing made available to it by the New York State Energy Research and Development Authority (NYSERDA). The Company used cash on hand to satisfy the retirement of $100 million of G&R Bonds which matured on April 15, 1998. In December 1997, the Company received $24.5 million in net proceeds from the sale of Electric Facilities Revenue Bonds (EFRBs) issued by NYSERDA. The proceeds from this offering were used to reimburse the Company's treasury for amounts previously expended on electric non-nuclear generation projects. With respect to the repayment of $454 million of maturing debt and $22 million of maturing preferred stock in 1999 and the repayment of $37 million of maturing debt and $363 million of maturing preferred stock in 2000, should the LIPA Transaction not close, the Company intends to use cash generated from operations to the maximum extent practicable. Pursuant to the terms of the LIPA Transaction, each issued and outstanding share of the Company's preferred stock that is subject to optional redemption will be called for redemption at or before closing of the LIPA Transaction. The LIPA Transaction provides for repayment to the Company, at closing, for the principal amount of the preferred stock to be redeemed. Accordingly, on April 17, 1998, the Company exercised its option and called for redemption on May 19, 1998, all the outstanding shares of its Preferred Stock Series B, D, E, F, H, I, L, and NN. The redemption of these Preferred Stock Series amounted to $122 million which included approximately $5 million of redemption premiums. The Company used cash generated from operations and the utilization of interim financing through its 1989 RCA to finance the redemption. In the event the LIPA Transaction is not consummated, the Company may elect to access the capital markets for permanent financing to replace the Preferred Stock redeemed. In 1990 and 1992, the Company received Revenue Agents' Reports disallowing certain deductions and credits claimed by the Company on its federal income tax returns for the years 1981 through 1989. A settlement resolving all audit issues was reached between the Company and the Internal Revenue 42 Service in May 1998. The settlement provided for the payment of taxes and interest of approximately $9 million and $35 million, respectively, which the Company made in May 1998. In May 1998, the Company funded certain of its obligations for postretirement benefits other than pensions in order to take a current tax deduction. The Company secured a bridge loan of $250 million to fund Voluntary Employee's Beneficiary Association trusts. The Company intends to repay this bridge loan upon the closing of the LIPA Transaction. CAPITALIZATION The Company's capitalization, including current maturities of long-term debt and current redemption requirements of preferred stock, at March 31, 1998 and 1997 and December 31, 1996 and 1995, was $7.8 billion, $7.7 billion, $7.9 billion and $8.3 billion, respectively. At March 31, 1998 and 1997 and at, December 31, 1996 and 1995, the Company's capitalization ratios were as follows:
- --------------------------------------- --------------------------------- ---------------------------------- March 31 December 31 - --------------------------------------- --------------------------------- ---------------------------------- 1998 1997 1996 1995 - --------------------------------------- ---------------- ----------------- ---------------- ---------------- Long term debt 57.3% 57.8% 59.3% 61.8% Preferred stock 9.0 9.1 8.9 8.6 Common shareowners' equity 33.7 33.1 31.8 29.6 ======================================= ================ ================= ================ ================ 100.0% 100.0% 100.0% 100.0% ======================================= ================ ================= ================ ================
In support of the Company's continuing goal to reduce its debt ratio, the Company, in February 1997, retired at maturity $250 million of G&R Bonds with cash on hand and by utilizing interim financing of $30 million, which was repaid in March 1997. The Company used cash on hand to satisfy the $100 million of G&R Bonds which matured in April 1998. INVESTMENT RATING The Company's securities are rated by Standard and Poor's (S&P), Moody's Investors Service, Inc. (Moody's), Fitch IBCA, Inc. (Fitch) and Duff & Phelps Credit Rating Co. (D&P). At March 31, 1998, the ratings for each of the Company's principal securities were as follows:
- ------------------------------------------------------------------------------------------------------------------ S&P Moody's Fitch D&P - ------------------------------------------------------------------------------------------------------------------ G&R Bonds BBB* Baa3* BBB-* BBB* Debentures BB+ Ba1 BB+ BB+ Preferred Stock BB+ ba1 BB- BB - ------------------------------------------------------------------------------------------------------------------ Minimum Investment Grade BBB-* Baa3* BBB-* BBB-* ================================================================================================================== *Bold face indicates securities that meet or exceed minimum investment grade.
During March 1998, following the announcement that the Company received favorable tax rulings from the IRS with respect to the LIPA Transaction, Moody's raised the ratings of the Company's G&R Bonds to Baa3 from Ba1; its debentures to Ba1 from Ba3 and its preferred stock to ba1 from ba3. During October 1997, S&P announced that it raised the Company's G&R Bonds ratings one notch to BBB from BBB-. The upgrade resulted from S&P incorporating into its ratings of corporate issues a more vigorous analysis of ultimate recovery potential to supplement the analysis of default risk. The 43 incorporation of ultimate recovery risk is particularly important for ratings of electric, gas, and water utility senior secured debt. If, in S&P's analytical conclusion, full recovery of principal can be anticipated in a post-default scenario, an issue's rating may be enhanced above the corporate credit rating or default rating. CAPITAL REQUIREMENTS AND CAPITAL PROVIDED Capital requirements and capital provided for the year ended March 31, 1998, the three months ended March 31, 1997 and the year ended December 31, 1996, were as follows:
(In Millions of Dollars) - ------------------------------------------------ -------------------------- ------------------------ --------------------------- Year Ended Three Months Ended Year Ended March 31, 1998 March 31, 1997 December 31, 1996 - ------------------------------------------------ -------------------------- ------------------------ --------------------------- - ------------------------------------------------ -------------------------- ------------------------ --------------------------- CAPITAL REQUIREMENTS Construction * $257 $ 50 $240 - ------------------------------------------------ -------------------------- ------------------------ --------------------------- Redemptions and Dividends Long-term debt 1 250 415 Preferred stock 1 - 5 Preferred stock dividends 52 13 52 Common stock dividends 216 54 214 - ------------------------------------------------ -------------------------- ------------------------ --------------------------- Total Redemption and Dividends 270 317 686 - ------------------------------------------------ -------------------------- ------------------------ --------------------------- Shoreham post-settlement costs 40 12 52 Investment in interest rate hedge 30 - - ================================================ ========================== ======================== =========================== Total Capital Requirements $597 $379 $978 ================================================ ========================== ======================== =========================== CAPITAL PROVIDED Cash from operations $674 $160 $892 (Increase) Decrease in cash balances (116) 215 71 Long term debt issued 25 - - Common stock issued 18 5 19 Other investing and financing activities ( 4) (1) ( 4) ================================================ ========================== ======================== =========================== Total Capital Provided $597 $379 $978 ================================================ ========================== ======================== ===========================
* Excludes non-cash allowance for other funds used during construction. For further information, see the Statement of Cash Flows. For the year ended March 31, 1999, total capital requirements (excluding common stock dividends) are estimated to be $589 million, of which maturing debt is $101 million, construction requirements are $266 million, preferred stock dividends are $45 million, redemptions of preferred stock are $144 million and Shoreham post-settlement costs are $33 million (including $31 million for payments-in-lieu-of-taxes). The Company believes that cash generated from operations coupled with cash balances will be sufficient to meet all capital requirements during this period. OTHER MATTERS LONG ISLAND POWER AUTHORITY TRANSACTION For a discussion of the Long Island Power Authority Transaction, see Note 2 of Notes to Financial Statements. KEYSPAN ENERGY CORPORATION TRANSACTION For a discussion of the KeySpan Energy Corporation Transaction, see Note 3 of Notes to Financial Statements. 44 RATE MATTERS For a discussion of Rate Matters, see Note 4 of Notes to Financial Statements. COMPETITIVE ENVIRONMENT For a discussion of competitive issues facing the Company, see Note 12 of Notes to Financial Statements. ENVIRONMENTAL MATTERS General The Company's ordinary business operations necessarily involve materials and activities which subject the Company to federal, state and local laws, rules and regulations dealing with the environment, including air, water and land quality. These environmental requirements may entail significant expenditures for capital improvements or modifications and may expose the Company to potential liabilities which, in certain instances, may be imposed without regard to fault or for historical activities which were lawful at the time they occurred. Laws which may impose such potential liabilities include (but are not limited to) the federal Comprehensive Environmental Response, Compensation and Liability Act (CERCLA, commonly known as Superfund), the federal Resource Conservation and Recovery Act, the federal Toxic Substances Control Act (TSCA), the federal Clean Water Act (CWA), and the federal Clean Air Act (CAA). Capital expenditures for environmental improvements and related studies amounted to approximately $9.2 million for the year ended March 31, 1998 and, based on existing information, are expected to be $4.0 million for the year ended March 31, 1999. The expenditures in fiscal year 1998 and expected spending in fiscal year 1999 include a total of $10.6 million for the completion of a gas-firing capability project at Northport Unit 1 and Port Jefferson Unit 4. It is not possible to ascertain with certainty if or when the various required governmental approvals for which applications have been made will be issued, or whether, except as noted below, additional facilities or modifications of existing or planned facilities will be required or, generally, what effect existing or future controls may have upon Company operations. Except as set forth below and in Item 3 - "Legal Proceedings," no material proceedings have been commenced or, to the knowledge of the Company, are contemplated by any federal, state or local agency against the Company, nor is the Company a defendant in any material litigation with respect to any matter relating to the protection of the environment. Recoverability of Environmental Costs The Company believes that none of the environmental matters, discussed below, will have a material adverse impact on the Company's financial position, cash flows or results of operations. In addition, the Company believes that all significant costs incurred with respect to environmental investigation and remediation activities, not recoverable from insurance carriers, will be recoverable from its customers. Air Federal, state and local regulations affecting new and existing electric generating plants govern emissions of sulfur dioxide (SO2), nitrogen oxides (NOX), particulate matter, and, potentially in the future, fine particulate matter (aerosols of SO2), hazardous air pollutants and carbon dioxide (CO2). 45 Sulfur Dioxide Requirements The laws governing the sulfur content of the fuel oil being burned by the Company in compliance with the United States Environmental Protection Agency (EPA) approved Air Quality State Implementation Plan (SIP) are administered by the New York State Department of Environmental Conservation (DEC). The Company does not expect to incur any costs to satisfy the 1990 amendments to the federal CAA with respect to the reduction of SO2 emissions, as the Company already uses natural gas and oil with acceptably low levels of sulfur as boiler fuels. These fuels also result in reduced vulnerability to any future fine particulate standards implemented in the form of stringent sulfur dioxide emission limits. The Company's use of low sulfur fuels has resulted, and will continue to result, in approximately 70,000 excess SO2 allowances per year through the year 1999. The Company presently applies the proceeds resulting from any sales of excess SO2 allowances as a reduction to the RMC balance. The Company entered into a voluntary Memorandum of Understanding with the DEC which provides that the Company will not sell SO2 allowances for use in 15 states in an effort to mitigate the transport of acid rain precursors into New York State from upwind states. Nitrogen Oxides Requirements Due to the Company's program of cost-effective emission reductions, including the optimization of natural gas firing ability at almost all the steam electric generating stations, the Company had the lowest NOX emissions rate of all the utilities in New York State for the years ended December 31, 1997, 1996 and 1995. Since the Company's generating facilities are located within a CAA Amendment-designated ozone non-attainment area, they are subject to NOx reduction requirements which are being implemented in three phases. Phase I was completed in 1995; Phase II and Phase III will be completed in 1999 and 2003, respectively. The Company is currently in compliance with Phase I NOx reduction requirements. It is estimated that additional expenditures of approximately $1 million will be required to meet Phase II NOx reduction requirements. Subject to requirements that are expected to be promulgated in forthcoming regulations, the Company estimates that it may be required to spend an additional $10 million to $34 million, excluding the Northport Unit 1 conversion, by the year 2003 to meet Phase III NOx reduction requirements. The completion of the project to add gas-firing capability at Northport Unit 1 (completed in May 1998 at a total cost of approximately $8.4 million) will also facilitate the Company's compliance with the anticipated Phase III Nox reduction requirements. Continuous Emission Monitoring Additional software and equipment upgrades for Continuous Emissions Monitors of approximately $2 million may be required through 1999 at all generating facilities in order to meet EPA requirements under development for the NOx allowance tracking/trading program. Hazardous Air Pollutants Utility boilers are presently exempt from regulation as sources of hazardous air pollutants until the EPA completes a study of the risks, if any, to public health reasonably anticipated to occur as a result of emissions by electric generating units. The EPA is expected to make a determination concerning the need for control of hazardous air pollutants from utility facilities in 1998. Until such determination 46 is made by the EPA, the Company cannot fully ascertain what, if any, costs will be incurred for the control of hazardous air pollutants. However, after the expenditure of approximately $1.5 million in fiscal 1998 and the planned spending of $0.5 million through March 31, 1999, for electrostatic precipitator upgrades and, with the maximization of clean burning natural gas as the primary fuel, hazardous air pollutant regulations, if enacted, should not impose any additional control requirements for the Company's facilities. Carbon Dioxide Requirements CO2 emissions from the Company's plants have been reduced by approximately 23% since 1990, largely through greater reliance on the use of natural gas and through conservation programs. This makes the Company less vulnerable to future CO2 reduction requirements. Opacity Issues The DEC has proposed commencing enforcement actions against all New York utilities for alleged opacity exceedences from steam electric generating facilities. Opacity is a measure of the relative level of light that is obscured from passing through a power plant stack emission plume. An exceedence occurs when the level of light passing through the plume is reduced by more than 20% for six minutes or more. The Company has entered into an Administrative Consent Order (ACO) with the DEC which resolves all historical opacity exceedences, establishes an opacity reduction program to be undertaken by the Company, and sets a stipulated penalty schedule for future exceedences. The number of exceedences experienced by the Company is relatively low, placing the Company among the best performers in New York State. Electromagnetic Fields Electromagnetic fields (EMF) occur naturally and also are produced wherever there is electricity. These fields exist around power lines and other utility equipment. The Company is in compliance with all applicable regulatory standards and requirements concerning EMF. The Company also monitors scientific developments in the study of EMF, has contributed to funding for research efforts, and is actively involved in customer and employee outreach programs to inform the community of EMF developments as they occur. Although an extensive body of scientific literature has not shown an unsafe exposure level or a causal relationship between EMF exposure and adverse health effects, concern over the potential for adverse health effects will likely continue without final resolution for some time. To date, four residential property owners have initiated separate lawsuits against the Company alleging that the existence of EMF has diminished the value of their homes. These actions are in the preliminary stages of discovery and are similar to actions brought against another New York State utility, which were dismissed by the New York State Court of Appeals. The Company is not involved in any active litigation that alleges a causal relationship between exposure to EMF and adverse health effects. Water Under the federal CWA and the New York State Environmental Conservation Law, the Company is required to obtain a State Pollutant Discharge Elimination System permit to make any discharge into the waters of the United States or New York State. The DEC has the jurisdiction to issue these permits and their renewals and has issued permits for the Company's generating units. The permits allow the continued use of the circulating water systems which have been determined to be in compliance with 47 state water quality standards. The permits also allow for the continued use of the chemical treatment systems and for the continued discharge of water in accordance with applicable permit limits. In fiscal year 1998, the Company spent approximately $300,000 to upgrade its waste water treatment facilities and for other measures designed to protect surface and ground water quality and expects to spend an additional $100,000 in the years 1998-2000. Long Island Sound Transmission Cables During 1996, the Connecticut Department of Environmental Protection (DEP) issued a modification to an Administrative Consent Order (ACO) previously issued in connection with an investigation of an electric transmission cable system located under the Long Island Sound (Sound Cable) that is jointly owned by the Company and the Connecticut Light and Power Company (Owners). The modified ACO requires the Owners to submit to the DEP and DEC a series of reports and studies describing cable system condition, operation and repair practices, alternatives for cable improvements or replacement and environmental impacts associated with leaks of fluid into the Long Island Sound which have occurred from time to time. The Company continues to compile required information and coordinate the activities necessary to perform these studies and, at the present time, is unable to determine the costs it will incur to complete the requirements of the modified ACO or to comply with any additional requirements. The Owners have also entered into an ACO with the DEC as a result of leaks of dielectric fluid from the Sound Cable. The ACO formalizes the DEC's authority to participate in and separately approve the reports and studies being prepared pursuant to the ACO issued by the DEP. In addition, the ACO settles any DEC claim for natural resource damages in connection with historical releases of dielectric fluid from the Sound Cable. In October 1995, the U.S. Attorney for the District of Connecticut had commenced an investigation regarding occasional releases of fluid from the Sound Cable, as well as associated operating and maintenance practices. The Owners have provided the U.S. Attorney with all requested documentation. The Company believes that all activities associated with the response to occasional releases from the Sound Cable were consistent with legal and regulatory requirements. In December 1996, a barge, owned and operated by a third party, dropped anchor which then dragged over and damaged the Sound Cable, resulting in the release of dielectric fluid into Long Island Sound. Temporary clamps and leak abaters were installed on the cables to stop the leaks. Permanent repairs were completed in June 1997. The cost to repair the Sound Cable was approximately $17.8 million, for which there was $15 million of insurance coverage. The Owners filed a claim and answer in response to the maritime limitation proceeding instituted by the barge owner in the United States District Court, Eastern District of New York. The claim seeks recovery of the amounts paid by insurance carriers and recovery of the costs incurred for which there was no insurance coverage. Any costs to repair the Sound Cable which are not reimbursed by a third party or covered by insurance will be shared equally by the Owners. Land Superfund imposes joint and several liability, regardless of fault, upon generators of hazardous substances for costs associated with environmental cleanup activities. Superfund also imposes liability for remediation of pollution caused by historical acts which were lawful at the time they occurred. 48 In the course of the Company's ordinary business operations, the Company is involved in the handling of materials that are deemed to be hazardous substances under Superfund. These materials include asbestos, metals, certain flammable and organic compounds and dielectric fluids containing polychlorinated biphenyls (PCBs). Other hazardous substances may be handled in the Company's operations or may be present at Company locations as a result of historical practices by the Company or its predecessors in interest. The Company has received notice concerning possible claims under Superfund or analogous state laws relating to a number of sites at which it is alleged that hazardous substances generated by the Company and other potentially responsible parties (PRPs) were deposited. A discussion of these sites is set forth below. Estimates of the Company's allocated share of costs for investigative, removal and remedial activities at these sites range from preliminary to refined and are updated as new information becomes available. In December 1996, the Company filed a complaint in the United States District Court for the Southern District of New York against 14 of the Company's insurers which issued general comprehensive liability (GCL) policies to the Company. In January 1998, the Company commenced a similar action against the same and certain additional insurer defendants in New York State Supreme Court, First Department; the federal court action was subsequently dismissed in March 1998. The Company is seeking recovery under the GCL policies for the costs incurred to date and future costs associated with the clean-up of the Company's former manufactured gas plant (MGP) sites and Superfund sites for which the Company has been named a PRP. The Company is seeking a declaratory judgment that the defendant insurers are bound by the terms of the GCL policies, subject to the stated coverage limits, to reimburse the Company for the clean up costs. The outcome of this proceeding cannot yet be determined. Superfund Sites Metal Bank The EPA has notified the Company that it is one of many PRPs that may be liable for the remediation of a licensed disposal site located in Philadelphia, Pennsylvania, and operated by Metal Bank of America. The Company and nine other PRPs, all of which are public utilities, completed performance of a Remedial Investigation and Feasibility Study (RI/FS), which was conducted under an ACO with the EPA. In December 1997, the EPA issued its Record of Decision (ROD), setting forth the final remedial action selected for the site. In the ROD, the EPA estimated that the present cost of the selected remedy for the site is $17.3 million. At this time, the Company cannot predict with reasonable certainty the actual cost of the selected remedy, who will implement the remedy, or the cost, if any, to the Company. Under a PRP participation agreement, the Company previously was responsible for 8.2% of the costs associated with the RI/FS. The Company's allocable share of liability for the remediation activities has not yet been determined. The Company has recorded a liability of approximately $1 million representing its estimated share of the additional cost to remediate this site based upon its 8.2% responsibility under the RI/FS. Syosset The Company and nine other PRPs have been named in a lawsuit where the Town of Oyster Bay (Town) is seeking indemnification for remediation and investigation costs that have been or will be 49 incurred for a federal Superfund site in Syosset, New York. For a further discussion on this matter, see Item 3, Legal Proceedings - Environmental. PCB Treatment, Inc. The Company has also been named a PRP for disposal sites in Kansas City, Kansas, and Kansas City, Missouri. The two sites were used by a company named PCB Treatment, Inc. from 1982 until 1987 for the storage, processing, and treatment of electric equipment, dielectric oils and materials containing PCBs. According to the EPA, the buildings and certain soil areas outside the buildings are contaminated with PCBs. Certain of the PRPs, including the Company and several other utilities, formed a PRP group, signed an ACO, and have developed a workplan for investigating environmental conditions at the sites. Documentation connecting the Company to the sites indicates that the Company was responsible for less than 1% of the materials that were shipped to the Missouri site. The EPA has not yet completed compiling the documents for the Kansas site. Osage The EPA has notified the Company that it is a PRP at the Osage Metals Site, a former scrap metal recycling facility located in Kansas City, Kansas. Under Section 107(a) of CERCLA, parties who arranged for disposal of hazardous substances are liable for costs incurred by the EPA in responding to a release or threat of release of the hazardous substances. Osage had purchased capacitor scrap metal from PCB Treatment, Inc. Through the arrangements that the Company made with PCB Treatment, Inc. to dispose of capacitors, the Company is alleged to have arranged for disposal within the meaning of the federal Superfund law. A similar letter was sent to 861 parties who sent capacitors to PCB Treatment, Inc. The EPA is seeking to recover approximately $1.1 million dollars it expended to conduct a removal action at the site. The Company is currently unable to determine its share of the $1.1 million expenditure. Port Refinery The Company has been notified that it is a PRP at the Port Refinery Superfund site located in Westchester County, New York. Port Refinery was engaged in the business of purchasing, selling, refining and processing mercury and the Company may have shipped a small amount of waste products containing mercury to this site. Tests conducted by the EPA indicated that the site and certain adjacent properties were contaminated with mercury. As a result, the EPA has performed a response action at the site and seeks to recover its costs, currently totaling approximately $4.4 million, plus interest, from the PRPs. The Company does not believe its portion of these costs, if any, will be material. Port Washington In 1989, the EPA notified the Company that it was a PRP for a landfill in Port Washington, New York. The Company does not believe that it sent any materials to the site that contributed to the contamination which requires remediation and has therefore declined the EPA's requests to participate in funding the investigation and remediation activities at the property. The Company has not received further communications regarding this site. 50 Liberty The EPA has notified the Company that it is a PRP in a Superfund site located in Farmingdale, New York. Industrial operations took place at this site for at least fifty years. The PRP group has claimed that the Company should absorb remediation expenses in the amount of approximately $100,000 associated with removing PCB-contaminated soils from a portion of the site which formerly contained electric transformers. The Company is currently unable to determine its share of costs of remediation at this site. Huntington/East Northport The DEC has notified the Company, pursuant to the State Superfund program, that its records indicate the Company may be responsible for the disposal of waste at this municipal landfill property. The Company conducted a search of its corporate records and did not locate any documents concerning waste disposal practices associated with this landfill. The Company is currently unable to determine its share, if any, of the costs to investigate and remediate this site. Blydenburgh The New York State Office of the Attorney General has notified the Company that it may be responsible for the disposal of wastes and/or for the generation of hazardous substances which may have been disposed of at the Blydenburgh Superfund site, a municipal sanitary landfill located in the Town of Islip, Suffolk County. The State has incurred approximately $15 million in costs for the investigation and remediation of environmental conditions at the landfill. In connection with this notification, the Company conducted a review of its corporate records and did not locate any documents concerning waste disposal practices associated with this landfill. The Company is currently unable to determine its share, if any, of the costs to investigate and remediate this site. Other Sites Manufactured Gas Plant Sites The DEC has required the Company and other New York State utilities to investigate and, where necessary, remediate their former MGP sites. Currently, the Company is the owner of six pieces of property on which the Company or certain of its predecessor companies produced manufactured gas. Operations at these facilities in the late 1800's and early 1900's may have resulted in the disposal of certain waste products located at these sites. The Company has entered into discussions with the DEC which is expected to lead to the issuance of one or more ACOs regarding the management of environmental activities at these six properties. Although the exact amount of the Company's cleanup costs cannot yet be determined, based on the findings of preliminary investigations conducted at each of these six sites, current estimates indicate that it may cost approximately $54 to $92 million to investigate and remediate all of these sites. Considering the range of possible remediation estimates, the Company felt it appropriate to record a $54 million liability reflecting the present value of the future stream of payments amounting to $70 million to investigate and remediate these sites. The Company used a risk-free rate of 6.0% to discount this obligation. The Company believes that the PSC will provide for future recovery of these costs and has recorded a $54 million regulatory asset. The Company's rate settlement which the PSC approved February 4, 1998 as discussed in Note 3 of Notes to Financial Statements, allows for the recovery of MGP expenditures from gas customers. 51 The Company is also evaluating its responsibilities with respect to several other former MGP sites that existed in its territory which it does not presently own. Research is underway to determine the existence and nature of operations and relationship, if any, to the Company or its predecessor companies. North Hills Leak The Company has undertaken remediation of certain soil locations in North Hills, New York that were impacted by a release of insulating fluid from an electrical cable in August 1994. The Company estimates that any additional cleanup costs will not exceed $0.5 million. The Company has initiated cost recovery actions against the third parties it believes are responsible for causing the cable leak, the outcome of which are uncertain. Storage Facilities As a result of petroleum leaks from underground storage facilities and other historical occurrences, the Company is required to investigate and, in certain cases, remediate affected soil and groundwater conditions at several facilities within its service territory. The aggregate costs of such remediation work could be between $3 million and $5 million. To the extent that these costs are not recoverable through insurance carriers, the Company believes such costs will be recoverable from its customers. Nuclear Waste Low Level Radioactive Waste The federal Low Level Radioactive Waste Policy Amendment Act of 1985, requires states to arrange for the disposal of all low level radioactive waste generated within the state or, in the alternative, to contract for their disposal at an operating facility outside the state. As a result, New York State has stated its intentions of developing an in-state disposal facility due to the large volume of low level radioactive waste generated within the state and has committed to develop a plan for the management of such waste during the interim period until a disposal facility is available. New York State is still developing a disposal methodology and acceptance criteria for a disposal facility. The latest New York State low level radioactive waste site development schedule now assumes two possible siting scenarios, a volunteer approach and a non-volunteer approach, either of which would not begin operation until at least 2001. Low level radioactive waste generated at NMP2 is currently being disposed of at the Barnwell, South Carolina waste disposal facility which reopened in July 1995 to out-of-state low level waste generators. In the event that off-site storage becomes unavailable prior to 2001, NMPC has implemented a low level radioactive waste management program that will properly handle interim on-site storage of low level radioactive waste for NMP2 for at least ten years. The Company's share of the costs associated with temporary storage and ultimate disposal are currently recovered in rates. Spent Nuclear Fuel NMPC, on behalf of the NMP2 cotenants, has entered into a contract with the DOE for the permanent storage of NMP2 spent nuclear fuel. The Company reimburses NMPC for its 18% share of the cost under the contract at a rate of $1.00 per megawatt hour of net generation less a factor to account for transmission line losses. The Company is collecting its portion of this fee from its electric customers. It is anticipated that the DOE facility may not be available for permanent 52 storage until at least 2010. Currently, all spent nuclear fuel from NMP2 is stored at the NMPC site, and existing facilities are sufficient to handle all spent nuclear fuel generated at NMP2 through the year 2012. For information concerning environmental litigation, see Item 3 "Legal Proceedings" under the heading Environmental. IMPACT OF YEAR 2000 Some of the Company's older computer programs were written using two digits rather than four to define the applicable year. As a result, those computer programs have time-sensitive software that recognizes a date using "00" as the year 1900 rather than the year 2000. This could cause a system failure or miscalculations causing disruptions of operations, including, among other things, a temporary inability to process transactions, or engage in normal business activities. The Company embarked on a program in 1996 to complete Year 2000 compliance by December 31, 1998. A corporate-wide program has been established to review all software, hardware and associated compliance plans. The readiness of suppliers and vendor systems is also under review. Contingency and business continuation plans are being prepared and will be reviewed periodically. The Company expects to spend approximately $10 million to address the Year 2000 issue over a three-year period (1997-1999) consisting of $7 million to test and modify application systems and $3 million to test and modify non-information technology systems. All costs will be expensed as incurred. As of March 31, 1998, $4.53 million has been expended in investigating and modifying software. This effort is scheduled to be completed in 1998 and testing will continue into early 1999. The Company believes that, with modifications to existing software and conversions to new software, the Year 2000 Issue will not pose significant operational problems for its computer systems. However, if such modifications and conversions are not made, or are not completed on time, the Year 2000 Issue could have a material adverse impact on the operations of the Company. The costs of the project and the date on which the Company believes it will complete the Year 2000 modifications are based on management's best estimates, which were derived utilizing numerous assumptions of future events, including the continued availability of certain resources and other factors. However, actual results could differ materially from those anticipated. Specific factors that might cause such material differences include, but are not limited to, the availability and cost of personnel trained in this area, the ability to locate and correct all relevant computer codes and similar uncertainties. RECENT ACCOUNTING PRONOUNCEMENTS Comprehensive Income In June 1997, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (SFAS) No. 130. SFAS No. 130 establishes standards for reporting comprehensive income. Comprehensive income is the change in the equity of a company, not including those changes that result from shareholder transactions. All components of comprehensive income are required to be reported in a new financial statement that is displayed with equal 53 prominence as existing financial statements. The Company will be required to adopt SFAS No. 130 for the year ending March 31, 1999. The Company does not expect that the adoption of SFAS NO. 130 will have a significant impact on its reporting and disclosure requirements. Segment Disclosures Also in June 1997, FASB issued SFAS No. 131. SFAS No. 131 establishes standards for additional disclosure about operating segments for interim and annual financial statements. More specifically, it requires financial information to be disclosed for segments whose operating results are reviewed by the chief decision maker for decisions on resource allocation. It also requires related disclosures about products and services, geographic areas and major customers. The Company will be required to adopt SFAS No. 131 for the year ending March 31, 1999. The Company does not expect that the adoption of SFAS No. 131 will have a significant impact on its reporting and disclosure requirements. CONSERVATION SERVICES The Company's 1997 Demand Side Management (DSM) Plan focused on the pursuit of energy efficiency and peak load reduction in a way that had minimal impact on electric rate increases. To assure the success of this strategy, the Company implemented a balanced and cost-effective mix of DSM programs that continued to represent a limited reliance on broad-based rebates and a concentrated emphasis on programs that provided education and information, targeted business development, provided financing for energy efficiency, induced market transformation and improved the efficiency of LILCO facilities. The Company was successful in meeting the PSC Energy Penalty Threshold by obtaining energy savings of approximately 24.4 GWh at a cost less than that provided for in electric rates. In 1998, the Company plans to continue to follow the aforementioned strategy while introducing several new initiatives. These include a program targeted at increasing the energy efficiency of residences of low income customers, the introduction of a peak load curtailment program constructed to help the Company meet its peak supply side requirements and an increased emphasis on programs that induce market transformation. Overall, the 1998 Plan targets an annualized energy savings of 18.6 GWh at a budget of $10.7 million. CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS This report contains statements which, to the extent they are not recitations of historical fact, constitute "forward-looking statements" within the meaning of the Securities Litigation Reform Act of 1995 (Reform Act). In this respect, the words "estimate," "project," "anticipate," "expect," "intend," "believe" and similar expressions are intended to identify forward-looking statements. All such forward-looking statements are intended to be subject to the safe harbor protection provided by the Reform Act. A number of important factors affecting the Company's business and financial results could cause actual results to differ materially from those stated in the forward-looking statements. Those factors include the proposed transactions with The KeySpan Energy Corporation and LIPA as discussed under the heading "KeySpan Energy Corporation Transaction" and "Long Island Power Authority Transaction" state and federal regulatory rate proceedings, competition, and certain environmental matters each as discussed herein, in the Joint Proxy Statement/Prospectus filed June 30, 1997, or in other reports filed by the Company with the Securities and Exchange Commission. 54 FINANCIAL STATEMENTS
Balance Sheet (In thousands of dollars) - --------------------------------------------------------------------------------------------------------------------------- Assets at March 31, 1998 March 31, 1997 December 31, 1996 - --------------------------------------------------------------------------------------------------------------------------- UTILITY PLANT Electric $ 4,031,510 $ 3,900,264 $ 3,882,297 Gas 1,233,281 1,171,183 1,154,543 Common 290,221 263,267 260,268 Construction work in progress 118,808 108,850 112,184 Nuclear fuel in process and in reactor 18,119 15,503 15,454 - -------------------------------------------------------------------------------------------------------------------------- 5,691,939 5,459,067 5,424,746 Less - Accumulated depreciation and amortization 1,877,858 1,759,110 1,729,576 - -------------------------------------------------------------------------------------------------------------------------- Total Net Utility Plant 3,814,081 3,699,957 3,695,170 - -------------------------------------------------------------------------------------------------------------------------- REGULATORY ASSETS Base financial component (less accumulated amortization of $883,496, $782,525 and $757,282) 3,155,334 3,256,305 3,281,548 Rate moderation component 434,004 409,512 402,213 Shoreham post-settlement costs 1,005,316 996,270 991,795 Shoreham nuclear fuel 66,455 68,581 69,113 Unamortized cost of issuing securities 159,941 187,309 194,151 Postretirement benefits other than pensions 340,109 357,668 360,842 Regulatory tax asset 1,737,932 1,767,164 1,772,778 Other 192,763 200,137 199,879 - -------------------------------------------------------------------------------------------------------------------------- Total Regulatory Assets 7,091,854 7,242,946 7,272,319 - -------------------------------------------------------------------------------------------------------------------------- NONUTILITY PROPERTY AND OTHER INVESTMENTS 50,816 18,870 18,597 - -------------------------------------------------------------------------------------------------------------------------- CURRENT ASSETS Cash and cash equivalents 180,919 64,539 279,993 Special deposits 95,790 37,631 38,266 Customer accounts receivable (less allowance for doubtful accounts of $23,483, $23,675 and $25,000) 297,889 305,436 255,801 Other accounts receivable 43,744 42,946 65,764 Accrued unbilled revenues 124,464 141,389 169,712 Materials and supplies at average cost 54,883 55,454 55,789 Fuel oil at average cost 32,142 49,703 53,941 Gas in storage at average cost 14,634 10,893 73,562 Deferred tax asset - net operating loss -- 93,349 145,205 Prepayments and other current assets 13,807 8,805 8,569 - -------------------------------------------------------------------------------------------------------------------------- Total Current Assets 858,272 810,145 1,146,602 - -------------------------------------------------------------------------------------------------------------------------- DEFERRED CHARGES 85,702 77,656 76,991 - -------------------------------------------------------------------------------------------------------------------------- TOTAL ASSETS $11,900,725 $11,849,574 $12,209,679 ========================================================================================================================== See Notes to Financial Statements. 55 (In thousands of dollars) - --------------------------------------------------------------------------------------------------------------------------- Capitalization and Liabilities at March 31, 1998 March 31, 1997 December 31, 1996 - --------------------------------------------------------------------------------------------------------------------------- CAPITALIZATION Long-term debt $ 4,395,555 $ 4,471,675 $ 4,471,675 Unamortized discount on debt (13,606) (14,628) (14,903) - -------------------------------------------------------------------------------------------------------------------------- 4,381,949 4,457,047 4,456,772 - -------------------------------------------------------------------------------------------------------------------------- Preferred stock - redemption required 562,600 638,500 638,500 Preferred stock - no redemption required -- 63,598 63,664 - -------------------------------------------------------------------------------------------------------------------------- Total Preferred Stock 562,600 702,098 702,164 - -------------------------------------------------------------------------------------------------------------------------- Common stock 608,635 605,022 603,921 Premium on capital stock 1,146,425 1,131,576 1,127,971 Capital stock expense (47,501) (48,915) (49,330) Retained earnings 956,092 861,751 840,867 Treasury stock, at cost (1,204) (385) (60) - -------------------------------------------------------------------------------------------------------------------------- Total Common Shareowners' Equity 2,662,447 2,549,049 2,523,369 - -------------------------------------------------------------------------------------------------------------------------- Total Capitalization 7,606,996 7,708,194 7,682,305 - -------------------------------------------------------------------------------------------------------------------------- REGULATORY LIABILITIES Regulatory liability component 99,199 178,558 198,398 1989 Settlement credits 59,397 125,138 127,442 Regulatory tax liability 78,913 100,377 102,887 Other 151,922 158,660 139,510 - -------------------------------------------------------------------------------------------------------------------------- Total Regulatory Liabilities 389,431 562,733 568,237 - -------------------------------------------------------------------------------------------------------------------------- CURRENT LIABILITIES Current maturities of long-term debt 101,000 1,000 251,000 Current redemption requirements of preferred stock 139,374 1,050 1,050 Accounts payable and accrued expenses 228,583 230,189 289,141 LRPP payable 30,118 40,499 40,499 Accrued taxes (including federal income tax of $28,308, $49,262 and $25,884) 34,753 51,157 63,640 Accrued interest 146,607 143,983 160,615 Dividends payable 58,748 58,474 58,378 Class Settlement 60,000 58,333 55,833 Customer deposits 28,627 29,173 29,471 - -------------------------------------------------------------------------------------------------------------------------- Total Current Liabilities 827,810 613,858 949,627 - -------------------------------------------------------------------------------------------------------------------------- DEFERRED CREDITS Deferred federal income tax - net 2,539,364 2,420,443 2,442,606 Class Settlement 46,940 89,487 98,497 Other 22,529 20,889 39,447 - -------------------------------------------------------------------------------------------------------------------------- Total Deferred Credits 2,608,833 2,530,819 2,580,550 - -------------------------------------------------------------------------------------------------------------------------- OPERATING RESERVES Pensions and other postretirement benefits 401,401 387,048 381,996 Claims and damages 66,254 46,922 46,964 - -------------------------------------------------------------------------------------------------------------------------- Total Operating Reserves 467,655 433,970 428,960 - -------------------------------------------------------------------------------------------------------------------------- COMMITMENTS AND CONTINGENCIES -- -- -- - -------------------------------------------------------------------------------------------------------------------------- TOTAL CAPITALIZATION AND LIABILITIES $ 11,900,725 $ 11,849,574 $ 12,209,679 =========================================================================================================================
See Notes to Financial Statements. 56
STATEMENT OF INCOME (In thousands of dollars except per share amounts) - ------------------------------------------------------------------------------------------------------------------------------- Three Months Year Ended Ended Year Ended Year Ended March 31, 1998 March 31, 1997 December 31, 1996 December 31, 1995 - ------------------------------------------------------------------------------------------------------------------------------- REVENUES Electric $ 2,478,435 $ 557,791 $ 2,466,435 $ 2,484,014 Gas 645,659 293,391 684,260 591,114 - ------------------------------------------------------------------------------------------------------------------------------- Total Revenues 3,124,094 851,182 3,150,695 3,075,128 - ------------------------------------------------------------------------------------------------------------------------------- OPERATING EXPENSES Operations - fuel and purchased power 957,807 301,867 963,251 834,979 Operations - other 400,045 95,673 381,076 383,238 Maintenance 111,120 29,340 118,135 128,155 Depreciation and amortization 158,537 38,561 153,925 145,357 Base financial component amortization 100,971 25,243 100,971 100,971 Rate moderation component amortization (35,079) 5,907 (24,232) 21,933 Regulatory liability component amortization (79,359) (19,840) (79,359) (79,359) 1989 Settlement credits amortization (9,213) (2,303) (9,214) (9,214) Other regulatory amortization 47,272 12,218 127,288 161,605 Operating taxes 466,326 117,513 472,076 447,507 Federal income tax - current 86,388 23,378 42,197 14,596 Federal income tax - deferred and other 150,983 33,624 168,000 193,742 - ------------------------------------------------------------------------------------------------------------------------------- Total Operating Expenses 2,355,798 661,181 2,414,114 2,343,510 - ------------------------------------------------------------------------------------------------------------------------------- Operating Income 768,296 190,001 736,581 731,618 - ------------------------------------------------------------------------------------------------------------------------------- OTHER INCOME AND (DEDUCTIONS) Rate moderation component carrying charges 23,632 5,919 25,259 25,274 Other income and deductions, net (18,156) 645 19,197 34,400 Class Settlement (15,623) (4,496) (20,772) (21,669) Allowance for other funds used during construction 3,846 717 2,888 2,898 Federal income tax - current 594 - - - Federal income tax - deferred and other 4,124 789 940 2,800 - ------------------------------------------------------------------------------------------------------------------------------- Total Other Income and (Deductions) (1,583) 3,574 27,512 43,703 - ------------------------------------------------------------------------------------------------------------------------------- Income Before Interest Charges 766,713 193,575 764,093 775,321 - ------------------------------------------------------------------------------------------------------------------------------- INTEREST CHARGES Interest on long-term debt 351,261 90,168 384,198 412,512 Other interest 57,805 16,659 67,130 63,461 Allowance for borrowed funds used during construction (4,593) (949) (3,699) (3,938) - ------------------------------------------------------------------------------------------------------------------------------- Total Interest Charges 404,473 105,878 447,629 472,035 - ------------------------------------------------------------------------------------------------------------------------------- NET INCOME 362,240 87,697 316,464 303,286 Preferred stock dividend requirements 51,813 12,969 52,216 52,620 - ------------------------------------------------------------------------------------------------------------------------------- EARNINGS FOR COMMON STOCK $ 310,427 $ 74,728 $ 264,248 $ 250,666 =============================================================================================================================== AVERAGE COMMON SHARES OUTSTANDING (000) 121,415 120,995 120,360 119,195 - ------------------------------------------------------------------------------------------------------------------------------- BASIC AND DILUTED EARNINGS PER COMMON SHARE $ 2.56 $ 0.62 $ 2.20 $ 2.10 ================================================================================================================================== DIVIDENDS DECLARED PER COMMON SHARE $ 1.78 $ 0.45 $ 1.78 $ 1.78 - ----------------------------------------------------------------------------------------------------------------------------------
See Notes to Financial Statements. 57
STATEMENT OF CASH FLOWS (In thousands of dollars) - ------------------------------------------------------------------------------------------------------------------------ Year Three Year Year Ended Months Ended Ended Ended March 31 March 31 December 31 December 31 1998 1997 1996 1995 - ------------------------------------------------------------------------------------------------------------------------ OPERATING ACTIVITIES Net Income $362,240 $87,697 $316,464 $303,286 Adjustments to reconcile net income to net cash provided by operating activities Provision for doubtful accounts 23,239 4,821 23,119 17,751 Depreciation and amortization 158,537 38,561 153,925 145,357 Base financial component amortization 100,971 25,243 100,971 100,971 Rate moderation component amortization (35,079) 5,907 (24,232) 21,933 Regulatory liability component amortization (79,359) (19,840) (79,359) (79,359) 1989 Settlement credits amortization (9,213) (2,303) (9,214) (9,214) Other regulatory amortization 47,272 12,218 127,288 161,605 Rate moderation component carrying charges (23,632) (5,919) (25,259) (25,274) Class Settlement 15,623 4,496 20,772 21,669 Amortization of cost of issuing and redeeming securities 30,823 8,087 34,611 39,589 Federal income tax - deferred and other 146,859 32,835 167,060 190,942 Pensions and Other Post Retirement Benefits 48,512 13,496 14,952 4,900 Other 87,618 2,381 51,671 56,675 Changes in operating assets and liabilities Accounts receivable (14,905) (31,638) 69,215 (67,213) Materials and supplies, fuel oil and gas in storage 14,391 67,242 (34,531) 21,986 Accounts payable and accrued expenses 1,668 (58,952) 28,258 19,100 Class Settlement (56,503) (11,006) (42,084) (33,464) Special deposits (58,159) 635 25,146 (35,798) Other (86,819) (14,394) (26,460) (83,442) - ------------------------------------------------------------------------------------------------------------------------ Net Cash Provided by Operating Activities 674,084 159,567 892,313 772,000 - ------------------------------------------------------------------------------------------------------------------------ INVESTING ACTIVITIES Construction and nuclear fuel expenditures (257,402) (50,375) (239,896) (243,586) Shoreham post-settlement costs (39,828) (12,104) (51,722) (70,589) Investment in interest rate hedge (30,000) --- --- --- Other (1,987) 160 (4,806) 8,019 - ------------------------------------------------------------------------------------------------------------------------ Net Cash Used in Investing Activities (329,217) (62,319) (296,424) (306,156) - ------------------------------------------------------------------------------------------------------------------------ FINANCING ACTIVITIES Proceeds from issuance of securities 43,218 4,640 18,837 68,726 Redemption of securities (2,050) (250,000) (419,800) (104,800) Common stock dividends paid (215,790) (53,749) (213,753) (211,630) Preferred stock dividends paid (51,833) (12,969) (52,264) (52,667) Other (2,032) (624) (369) 529 - ------------------------------------------------------------------------------------------------------------------------ Net Cash Used in Financing Activities (228,487) (312,702) (667,349) (299,842) - ------------------------------------------------------------------------------------------------------------------------ NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS $116,380 ($215,454) ($71,460) $166,002 - ------------------------------------------------------------------------------------------------------------------------ Cash and cash equivalents at beginning of period $64,539 $279,993 $351,453 $185,451 Net increase (decrease) in cash and cash equivalents 116,380 (215,454) (71,460) 166,002 - ------------------------------------------------------------------------------------------------------------------------ CASH AND CASH EQUIVALENTS AT END OF PERIOD $180,919 $64,539 $279,993 $351,453 - ------------------------------------------------------------------------------------------------------------------------ Interest paid, before reduction for the allowance for borrowed funds used during construction $364,864 $112,981 $404,663 $427,988 Federal income tax paid $108,980 --- $45,050 $14,200 - ------------------------------------------------------------------------------------------------------------------------
See Notes to Financial Statements. 58 STATEMENT OF RETAINED EARNINGS
(In thousands of dollars) - -------------------------------------------------------------------------------------------------------------------------------- March 31, 1998 March 31, 1997 December 31, 1996 December 31, 1995 - -------------------------------------------------------------------------------------------------------------------------------- Balance at beginning of period $ 861,751 $ 840,867 $ 790,919 $ 752,480 Net income for the period 362,240 87,697 316,464 303,286 - ------------------------------------------------------------------------------------------------------------------------------ 1,223,991 928,564 1,107,383 1,055,766 Deductions Cash dividends declared on common stock 216,086 53,844 214,255 212,181 Cash dividends declared on preferred stock 51,812 12,969 52,240 52,647 Other 1 - 21 19 - ------------------------------------------------------------------------------------------------------------------------------ BALANCE AT END OF PERIOD $ 956,092 $ 861,751 $ 840,867 $ 790,919 ==============================================================================================================================
See Notes to Financial Statements.
STATEMENT OF CAPITALIZATION Shares Issued (In thousands of dollars) - ----------------------------------------------------------------------------------------------------------------------------------- March 31, 1998 March 31, 1997 December 31, 1996 March 31, 1998 March 31, 1997 - ----------------------------------------------------------------------------------------------------------------------------------- COMMON SHAREOWNERS' EQUITY Common stock, $5.00 par value 121,727,040 121,004,315 120,784,277 $ 608,635 $ 605,022 Premium on capital stock 1,146,425 1,131,576 Capital stock expense (47,501) (48,915) Retained earnings 956,092 861,751 Treasury stock, at cost 46,281 16,985 3,485 (1,204) (385) - ----------------------------------------------------------------------------------------------------------------------------- TOTAL COMMON SHAREOWNERS' EQUITY 2,662,447 2,549,049 - ----------------------------------------------------------------------------------------------------------------------------- PREFERRED STOCK - REDEMPTION REQUIRED Par value $100 per share 7.40% Series L 150,500 161,000 161,000 15,050 16,100 7.66% Series CC 570,000 570,000 570,000 57,000 57,000 Less - Series called for redemption 15,050 1,050 - ----------------------------------------------------------------------------------------------------------------------------- 57,000 72,050 - ----------------------------------------------------------------------------------------------------------------------------- Par value $25 per share 7.95% Series AA 14,520,000 14,520,000 14,520,000 363,000 363,000 $1.67 Series GG 880,000 880,000 880,000 22,000 22,000 $1.95 Series NN 1,554,000 1,554,000 1,554,000 38,850 38,850 7.05% Series QQ 3,464,000 3,464,000 3,464,000 86,600 86,600 6.875% Series UU 2,240,000 2,240,000 2,240,000 56,000 56,000 Less - Series called for redemption 38,850 - Less - Mandatory redemption of preferred stock 22,000 - - ----------------------------------------------------------------------------------------------------------------------------- 505,600 566,450 - ----------------------------------------------------------------------------------------------------------------------------- Total Preferred Stock - Redemption Required 562,600 638,500 - ----------------------------------------------------------------------------------------------------------------------------- PREFERRED STOCK - NO REDEMPTION REQUIRED Par value $100 per share 5.00% Series B 100,000 100,000 100,000 10,000 10,000 4.25% Series D 70,000 70,000 70,000 7,000 7,000 4.35% Series E 200,000 200,000 200,000 20,000 20,000 4.35% Series F 50,000 50,000 50,000 5,000 5,000 5 1/8% Series H 200,000 200,000 200,000 20,000 20,000 5 3/4% Series I - Convertible 14,743 15,978 16,637 1,474 1,598 Less - Series called for redemption 63,474 - - ----------------------------------------------------------------------------------------------------------------------------- Total Preferred Stock - No Redemption Required - 63,598 - ----------------------------------------------------------------------------------------------------------------------------- TOTAL PREFERRED STOCK $ 562,600 $ 702,098 - -----------------------------------------------------------------------------------------------------------------------------
STATEMENT OF CAPITALIZATION (In thousands of dollars) - ----------------------------------------------------------------------------- December 31, 1996 - ----------------------------------------------------------------------------- COMMON SHAREOWNERS' EQUITY Common stock, $5.00 par value $ 603,921 Premium on capital stock 1,127,971 Capital stock expense (49,330) Retained earnings 840,867 Treasury stock, at cost (60) - ----------------------------------------------------------------------------- TOTAL COMMON SHAREOWNERS' EQUITY 2,523,369 - ----------------------------------------------------------------------------- PREFERRED STOCK - REDEMPTION REQUIRED Par value $100 per share 7.40% Series L 16,100 7.66% Series CC 57,000 Less - Series called for redemption 1,050 - ----------------------------------------------------------------------------- 72,050 - ----------------------------------------------------------------------------- Par value $25 per share 7.95% Series AA 363,000 $1.67 Series GG 22,000 $1.95 Series NN 38,850 7.05% Series QQ 86,600 6.875% Series UU 56,000 Less - Series called for redemption - Less - Mandatory redemption of preferred stock - - ----------------------------------------------------------------------------- 566,450 - ----------------------------------------------------------------------------- Total Preferred Stock - Redemption Required 638,500 - ----------------------------------------------------------------------------- PREFERRED STOCK - NO REDEMPTION REQUIRED Par value $100 per share 5.00% Series B 10,000 4.25% Series D 7,000 4.35% Series E 20,000 4.35% Series F 5,000 5 1/8% Series H 20,000 5 3/4% Series I - Convertible 1,664 Less - Series called for redemption - - ----------------------------------------------------------------------------- Total Preferred Stock - No Redemption Required 63,664 - ----------------------------------------------------------------------------- TOTAL PREFERRED STOCK $ 702,164 - ----------------------------------------------------------------------------- 59
(In thousands of dollars) - ----------------------------------------------------------------------------------------------------------------------------------- Maturity Interest Rate Series March 31, 1998 March 31, 1997 - ---------------------------------------------------------------------------------------------------------------------------------- GENERAL AND REFUNDING BONDS February 15, 1997 8 3/4% $ - $ - April 15, 1998 7 5/8% 100,000 100,000 May 15, 1999 7.85% 56,000 56,000 April 15, 2004 8 5/8% 185,000 185,000 May 15, 2006 8.50% 75,000 75,000 July 15, 2008 7.90% 80,000 80,000 May 1, 2021 9 3/4% 415,000 415,000 July 1, 2024 9 5/8% 375,000 375,000 - ---------------------------------------------------------------------------------------------------------------------------------- Total General and Refunding Bonds 1,286,000 1,286,000 - ---------------------------------------------------------------------------------------------------------------------------------- DEBENTURES July 15, 1999 7.30% 397,000 397,000 January 15, 2000 7.30% 36,000 36,000 July 15, 2001 6.25% 145,000 145,000 March 15, 2003 7.05% 150,000 150,000 March 1, 2004 7.00% 59,000 59,000 June 1, 2005 7.125% 200,000 200,000 March 1, 2007 7.50% 142,000 142,000 July 15, 2019 8.90% 420,000 420,000 November 1, 2022 9.00% 451,000 451,000 March 15, 2023 8.20% 270,000 270,000 - ---------------------------------------------------------------------------------------------------------------------------------- Total Debentures 2,270,000 2,270,000 - ---------------------------------------------------------------------------------------------------------------------------------- AUTHORITY FINANCING NOTES Industrial Development Revenue Bonds December 1, 2006 7.50% 1976 A,B 2,000 2,000 Pollution Control Revenue Bonds December 1, 2006 7.50% 1976 A 27,375 28,375 December 1, 2009 7.80% 1979 B 19,100 19,100 October 1, 2012 8 1/4% 1982 17,200 17,200 March 1, 2016 3.58% 1985 A,B 150,000 150,000 Electric Facilities Revenue Bonds September 1, 2019 7.15% 1989 A,B 100,000 100,000 June 1, 2020 7.15% 1990 A 100,000 100,000 December 1, 2020 7.15% 1991 A 100,000 100,000 February 1, 2022 7.15% 1992 A,B 100,000 100,000 August 1, 2022 6.90% 1992 C,D 100,000 100,000 November 1, 2023 3.70% 1993 A 50,000 50,000 November 1, 2023 3.70% 1993 B 50,000 50,000 October 1, 2024 3.70% 1994 A 50,000 50,000 August 1, 2025 3.70% 1995 A 50,000 50,000 December 1, 2027 3.55% 1997 A 24,880 - - ---------------------------------------------------------------------------------------------------------------------------------- Total Authority Financing Notes 940,555 916,675 - ---------------------------------------------------------------------------------------------------------------------------------- Unamortized Discount on Debt (13,606) (14,628) - ---------------------------------------------------------------------------------------------------------------------------------- Total 4,482,949 4,458,047 Less Current Maturities 101,000 1,000 - ---------------------------------------------------------------------------------------------------------------------------------- TOTAL LONG-TERM DEBT 4,381,949 4,457,047 - ---------------------------------------------------------------------------------------------------------------------------------- TOTAL CAPITALIZATION $ 7,606,996 $ 7,708,194 ==================================================================================================================================
(In thousands of dollars) December 31, 1996 - ----------------------------------------------------------- GENERAL AND REFUNDING BONDS $ 250,000 100,000 56,000 185,000 75,000 80,000 415,000 375,000 - ----------------------------------------------------------- Total General and Refunding Bonds 1,536,000 - ----------------------------------------------------------- DEBENTURES 397,000 36,000 145,000 150,000 59,000 200,000 142,000 420,000 451,000 270,000 - ----------------------------------------------------------- Total Debentures 2,270,000 - ----------------------------------------------------------- AUTHORITY FINANCING NOTES Industrial Development Revenue Bonds 2,000 Pollution Control Revenue Bonds 28,375 19,100 17,200 150,000 Electric Facilities Revenue Bonds 100,000 100,000 100,000 100,000 100,000 50,000 50,000 50,000 50,000 - - ----------------------------------------------------------- Total Authority Financing Notes 916,675 - ----------------------------------------------------------- Unamortized Discount on Debt (14,903) - ----------------------------------------------------------- Total 4,707,772 Less Current Maturities 251,000 - ----------------------------------------------------------- TOTAL LONG-TERM DEBT 4,456,772 - ----------------------------------------------------------- TOTAL CAPITALIZATION $ 7,682,305 =========================================================== See Notes to Financial Statements. 60 NOTES TO FINANCIAL STATEMENTS Note 1. Summary of Significant Accounting Policies Basis of Presentation On April 11, 1997, the Company changed its year end from December 31 to March 31. Accordingly, unless otherwise indicated, references to 1998 and 1997 represent the twelve month period ended March 31, 1998 and March 31, 1997, while references to all other periods refer to the respective calendar years ended December 31. As further discussed in Note 2, on June 26, 1997, the Company and the Long Island Power Authority (LIPA) entered into definitive agreements pursuant to which, after the transfer of the Company's gas business unit assets, non-nuclear electric generating facility assets and certain other assets and liabilities to one or more newly-formed subsidiaries of a new holding company, the Company's common stock will be sold to LIPA for approximately $2.4975 billion in cash. No adjustments have been made to the Company's financial statements to reflect this proposed transaction. Nature of Operations The Company was incorporated in 1910 under the Transportation Corporations Law of the State of New York and supplies electric and gas service in Nassau and Suffolk Counties and to the Rockaway Peninsula in Queens County, all on Long Island, New York. The Company's service territory covers an area of approximately 1,230 square miles. The population of the service area, according to the Company's 1998 Long Island Population Survey estimate, is about 2.75 million persons, including approximately 98,500 persons who reside in Queens County within the City of New York. The Company serves approximately 1.04 million electric customers of which approximately 931,000 are residential. The Company receives approximately 49% of its electric revenues from residential customers, 48% from commercial/industrial customers and the balance from sales to other utilities and public authorities. The Company also serves approximately 467,000 gas customers, 417,000 of which are residential, accounting for about 61% of its gas revenues, 17,000 of which are commercial/industrial, accounting for 23% of its gas revenues, 3,600 of which are firm transportation customers, accounting for 3% of its gas revenues, with the balance of the gas revenues made up by off-system sales. The Company's geographic location and the limited electrical interconnections to Long Island serve to limit the accessibility of the transmission grid to potential competitors from off the system. In addition, the Company does not expect any new major independent power producers (IPPs) or cogenerators to be built on Long Island in the foreseeable future. One of the reasons supporting this conclusion is based on the Company's belief that the composition and distribution of the Company's remaining commercial and industrial customers would make it difficult for large electric projects to operate economically. Furthermore, under federal law, the Company is required to buy energy from qualified producers at the Company's avoided cost. Current long-range avoided cost estimates for the Company have significantly reduced the economic advantage to entrepreneurs seeking to compete with the Company and with existing IPPs. For a further discussion of the competitive issues facing the Company, see Note 12. Regulation The Company's accounting records are maintained in accordance with the Uniform Systems of Accounts prescribed by the Public Service Commission of the State of New York (PSC) and the Federal Energy Regulatory Commission (FERC). Its financial statements reflect the ratemaking policies and actions of 61 these commissions in conformity with generally accepted accounting principles for rate-regulated enterprises. Accounting for the Effects of Rate Regulation General The Company is subject to the provisions of Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation". This statement recognizes the economic ability of regulators, through the ratemaking process, to create future economic benefits and obligations affecting rate-regulated companies. Accordingly, the Company records these future economic benefits and obligations as regulatory assets and regulatory liabilities, respectively. Regulatory assets represent probable future revenues associated with previously incurred costs that are expected to be recovered from customers. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are expected to be refunded to customers through the ratemaking process. Regulatory assets net of regulatory liabilities amounted to approximately $6.7 billion at March 31, 1998, March 31, 1997 and December 31, 1996. In order for a rate-regulated entity to continue to apply the provisions of SFAS No. 71, it must continue to meet the following three criteria: (i) the enterprise's rates for regulated services provided to its customers must be established by an independent third-party regulator; (ii) the regulated rates must be designed to recover the specific enterprise's costs of providing the regulated services; and (iii) in view of the demand for the regulated services and the level of competition, it is reasonable to assume that rates set at levels that will recover the enterprise's costs can be charged to and collected from customers. Based upon the Company's evaluation of the three criteria discussed above in relation to its operations, the effect of competition on its ability to recover its costs, including its allowed return on common equity and the regulatory environment in which the Company operates, the Company believes that SFAS No. 71 continues to apply to the Company's electric and gas operations. The Company formed its conclusion based upon several factors including: (i) the Company's continuing ability to earn its allowed return on common equity for both its electric and gas operations; and (ii) the PSC's continued commitment to the Company's full recovery of the Shoreham Nuclear Power Station (Shoreham) related assets and all other prudently incurred costs. Notwithstanding the above, rate regulation is undergoing significant change as regulators and customers seek lower prices for electric and gas service. In the event that regulation significantly changes the opportunity for the Company to recover its costs in the future, all or a portion of the Company's operations may no longer meet the criteria discussed above. In that event, a significant write-down of all or a portion of the Company's existing regulatory assets and liabilities could result. If the Company had been unable to continue to apply the provisions of SFAS 71 at March 31, 1998, the Company would apply the provisions of SFAS 101 "Regulated Enterprises - Accounting for the Discontinuation of Application of FASB Statement No. 71". If SFAS 101 were implemented, the charge to earnings could be as high as $4.5 billion, net of tax. For additional information respecting the Company's Shoreham-related assets, see below and Notes 4 and 10. SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of" requires that costs which were capitalized in accordance with regulatory practices, because it was probable that future recovery would be allowed by the regulator, must be charged against current period earnings if it appears that the criterion for capitalization no longer applies. The carrying amount of such assets would be reduced by amounts for which recovery is unlikely. SFAS No. 121 also provides for 62 the restoration of previously disallowed costs that are subsequently allowed by a regulator. No impairment losses have been recognized by the Company with respect to regulatory or other long-lived assets. Discussed below are the Company's significant regulatory assets and regulatory liabilities. Base Financial Component and Rate Moderation Component Pursuant to the 1989 Settlement, the Company recorded a regulatory asset known as the Financial Resource Asset (FRA). The FRA is designed to provide the Company with sufficient cash flows to assure its financial recovery. The FRA has two components, the Base Financial Component (BFC) and the Rate Moderation Component (RMC). The BFC represents the present value of the future net-after-tax cash flows which the Rate Moderation Agreement (RMA), one of the constituent documents of the 1989 Settlement, provided the Company for its financial recovery. The BFC was granted rate base treatment under the terms of the RMA and is included in the Company's revenue requirements through an amortization included in rates over a forty-year period on a straight-line basis which began July 1, 1989. The RMC reflects the difference between the Company's revenue requirements under conventional ratemaking and the revenues resulting from the implementation of the rate moderation plan provided for in the RMA. The RMC is currently adjusted, on a monthly basis, for the Company's share of certain NMP2 operations and maintenance expenses, fuel credits resulting from the Company's electric fuel cost adjustment clause and gross receipts tax adjustments related to the FRA. In April 1998, the PSC authorized a revision to the Company's method for recording its monthly RMC amortization. Prior to this revision, the amortization of the annual level of RMC was recorded monthly on a straight-line, levelized basis over the Company's rate year which runs from December 1 to November 30. However, revenue requirements fluctuate from month to month based upon consumption, which is greatly impacted by the effects of weather. Under this revised method, effective December 1, 1997, the monthly amortization of the annual RMC level varies based upon each month's forecasted revenue requirements, which more closely aligns such amortization with the Company's cost of service. As a result of this change, for the fiscal year ended March 31, 1998, the Company recorded approximately $65.1 million more of non-cash RMC credits to income (representing accretion of the RMC balance), or $42.5 million net of tax, representing $.35 per share than it would have under the previous method. However, the total RMC amortization for the rate year ending November 30, 1998, will be equal to the amount that would have been provided for under the previous method. As discussed in Note 2, the RMC will be acquired by LIPA as part of the LIPA Transaction. For a further discussion of the 1989 Settlement and FRA, see Notes 4 and 10. Shoreham Post-Settlement Costs Shoreham post-settlement costs consist of Shoreham decommissioning costs, fuel disposal costs, payments-in-lieu-of-taxes, carrying charges and other costs. These costs are being capitalized and amortized and recovered through rates over a forty-year period on a straight-line remaining life basis which began July 1, 1989. For a further discussion of Shoreham post-settlement costs, see Note 10. Shoreham Nuclear Fuel Shoreham nuclear fuel principally reflects the unamortized portion of Shoreham nuclear fuel which was reclassified from Nuclear Fuel in Process and in Reactor at the time of the 1989 Settlement. This amount is being amortized and recovered through rates over a forty-year period on a straight-line remaining life basis which began July 1, 1989. 63 Unamortized Cost of Issuing Securities Unamortized cost of issuing securities represents the unamortized premiums or discounts and expenses related to the issues of long-term debt that have been retired prior to maturity and the costs associated with the early redemption of those issues. In addition, this balance includes the unamortized capital stock expense and redemption costs related to certain series of preferred stock that have been refinanced. These costs are amortized and recovered through rates, as provided by the PSC, over the shorter of the life of the redeemed issue or the new issue. Postretirement Benefits Other Than Pensions The Company defers as a regulatory asset the difference between postretirement benefit expense recorded in accordance with SFAS No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions", and postretirement benefit expense reflected in current rates. Pursuant to a PSC order, the ongoing annual SFAS No. 106 benefit expense was phased into and fully reflected in rates by November 30, 1997, with the accumulated deferred asset to be recovered in rates over the fifteen-year period which began December 1, 1997. For a further discussion of SFAS No. 106, see Note 8. Regulatory Tax Asset and Regulatory Tax Liability The Company has recorded a regulatory tax asset for amounts that it will collect in future rates for the portion of its deferred tax liability that has not yet been recognized for ratemaking purposes. The regulatory tax asset is comprised principally of the tax effect of the difference in the cost basis of the BFC for financial and tax reporting purposes, depreciation differences not normalized and the allowance for equity funds used during construction. The regulatory tax liability is primarily attributable to deferred taxes previously recognized at rates higher than current enacted tax law, unamortized investment tax credits and tax credit carryforwards. Regulatory Liability Component Pursuant to the 1989 Settlement, certain tax benefits attributable to the Shoreham abandonment are to be shared between electric customers and shareowners. A regulatory liability of approximately $794 million was recorded in June 1989 to preserve an amount equivalent to the customer tax benefits attributable to the Shoreham abandonment. This amount is being amortized over a ten-year period on a straight-line basis which began July 1, 1989. 1989 Settlement Credits Represents the unamortized portion of an adjustment of the book write-off to the negotiated 1989 Settlement amount. A portion of this amount is being amortized over a ten-year period which began on July 1, 1989. The remaining portion is not currently being recognized for ratemaking purposes. Utility Plant Additions to and replacements of utility plant are capitalized at original cost, which includes material, labor, indirect costs associated with an addition or replacement and an allowance for the cost of funds used during construction. The cost of renewals and betterments relating to units of property is added to utility plant. The cost of property replaced, retired or otherwise disposed of is deducted from utility plant and, generally, together with dismantling costs less any salvage, is charged to accumulated depreciation. The cost of repairs and minor renewals is charged to maintenance expense. Mass properties (such as poles, wire and meters) are accounted for on an average unit cost basis by year of installation. 64 Allowance for Funds Used During Construction The Uniform Systems of Accounts as prescribed by the PSC, defines the Allowance For Funds Used During Construction (AFC) as the net cost of borrowed funds used for construction purposes and a reasonable rate of return upon the utility's equity when so used. AFC is not an item of current cash income. AFC is computed monthly using a rate permitted by the FERC on a portion of construction work in progress. The average AFC rate, without giving effect to compounding, was as follows: Periods AFC Rate ------------------------ -------- 12 Months Ended 3/31/98 9.29% 3 Months Ended 3/31/97 2.26% 12 Months Ended 12/31/96 9.02% 12 Months Ended 12/31/95 9.36% Depreciation The provisions for depreciation result from the application of straight-line rates to the original cost, by groups, of depreciable properties in service. The rates are determined by age-life studies performed annually on depreciable properties. The average depreciation rate as a percentage of respective average depreciable plant costs was as follows: Periods Electric Gas ------- -------- --- 12 Months Ended 3/31/98 3.07% 2.04% 3 Months Ended 3/31/97 .78% .51% 12 Months Ended 12/31/96 3.00% 2.00% 12 Months Ended 12/31/95 3.00% 2.00% Cash and Cash Equivalents Cash equivalents are highly liquid investments with maturities of three months or less when purchased. The carrying amount approximates fair value because of the short maturity of these investments. LRPP Payable Represents the current portion of amounts due to ratepayers that result from the revenue and expense reconciliations, performance-based incentives and associated carrying charges as established under the LILCO Ratemaking and Performance Plan (LRPP). For further discussion of the LRPP, see Note 4. Fair Values of Financial Instruments The fair values for the Company's long-term debt and redeemable preferred stock are based on quoted market prices, where available. The fair values for all other long-term debt and redeemable preferred stock are estimated using discounted cash flow analyses based upon the Company's current incremental borrowing rate for similar types of securities. Revenues Revenues are comprised of cycle billings rendered to customers and the accrual of electric and gas revenues for services rendered to customers not billed at month-end. The Company's electric rate structure provides for a revenue reconciliation mechanism which eliminates the impact on earnings of experiencing electric sales that are above or below the levels reflected in rates. The Company's gas rate structure provides for a weather normalization clause which reduces the impact on revenues of experiencing weather which is warmer or colder than normal. 65 Fuel Cost Adjustments The Company's electric and gas tariffs include fuel cost adjustment (FCA) clauses which provide for the disposition of the difference between actual fuel costs and the fuel costs allowed in the Company's base tariff rates (base fuel costs). The Company defers these differences to future periods in which they will be billed or credited to customers, except for base electric fuel costs in excess of actual electric fuel costs, which are currently credited to the RMC as incurred. Pursuant to the Stipulation, as described in Note 3, gas fuel costs are excluded from base fuel costs and recovered through the gas fuel adjustment clause. Federal Income Tax The Company provides deferred federal income tax with respect to certain items of income and expense that are reported in different periods for federal income tax purposes than for financial statement purposes. Additionally, the Company provides deferred federal income tax with respect to items with different bases for financial and tax reporting purposes, as discussed in Note 9. The Company defers the benefit of 60% of pre-1982 gas and pre-1983 electric and 100% of all other investment tax credits, with respect to regulated properties, when realized on its tax returns. Accumulated deferred investment tax credits are amortized ratably over the lives of the related properties. For ratemaking purposes, the Company provides deferred federal income tax with respect to certain differences between income before income tax for financial reporting purposes and taxable income for federal income tax purposes. Also, certain accumulated deferred federal income tax is deducted from rate base and amortized or otherwise applied as a reduction in federal income tax expense in future years. Reserves for Claims and Damages Losses arising from claims against the Company, including workers' compensation claims, property damage, extraordinary storm costs and general liability claims, are partially self-insured. Reserves for these claims and damages are based on, among other things, experience, risk of loss and the ratemaking practices of the PSC. Extraordinary storm losses incurred by the Company are partially insured by various commercial insurance carriers. These insurance carriers provide partial insurance coverage for individual storm losses to the Company's transmission and distribution system between $15 million and $25 million. Storm losses which are outside of this range are self-insured by the Company. Recent Accounting Pronouncements Earnings Per Share At December 31, 1997, the Company adopted SFAS No. 128, "Earnings Per Share." This statement replaced the calculation of primary and fully diluted earnings per share with basic and diluted earnings per share. Unlike primary earnings per share, basic earnings per share excludes any dilutive effects of options, warrants and convertible securities. Diluted earnings per share are very similar to the previously reported fully diluted earnings per share. None of the earnings per share amounts for periods presented were effected by the adoption of SFAS No. 128. Comprehensive Income In June 1997, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (SFAS) No. 130. SFAS No. 130 establishes standards for reporting comprehensive income. Comprehensive income is the change in the equity of a company, not including those changes that result from shareholder transactions. All components of comprehensive income are required to be reported in a new financial statement that is displayed with equal prominence as existing financial statements. The Company will be required to adopt SFAS No. 130 for the year ending March 31, 1999. 66 The Company does not expect that the adoption of SFAS No. 130 will have a significant impact on its reporting and disclosure requirements. Segment Disclosures In June 1997, FASB issued SFAS No. 131 "Disclosures about Segments of an Enterprise and Related Information." SFAS No. 131 establishes standards for additional disclosure about operating segments for interim and annual financial statements. More specifically, it requires financial information to be disclosed for segments whose operating results are reviewed by the chief operating decision maker for decisions on resource allocation. It also requires related disclosures about products and services, geographic areas and major customers. The Company will be required to adopt SFAS No. 131 for the fiscal year ending March 31, 1999. The Company does not expect that the adoption of SFAS No. 131 will have a significant impact on its reporting and disclosure requirements. Use of Estimates The preparation of the financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. Actual results could differ from those estimates. Reclassifications Certain prior year amounts have been reclassified in the financial statements to conform with the current year presentation. Note 2. Long Island Power Authority Transaction On June 26, 1997, the Company and Long Island Power Authority (LIPA) entered into definitive agreements pursuant to which, after the transfer of the Company's gas business unit assets, non-nuclear electric generating facility assets and certain other assets and liabilities to one or more newly-formed subsidiaries of a new holding company (HoldCo), formed in connection with the LIPA Transaction and KeySpan Transaction discussed below, the Company's common stock will be sold to LIPA for $2.4975 billion in cash. In connection with this transaction, the principal assets to be acquired by LIPA through its stock acquisition of LILCO include: (i) the net book value of LILCO's electric transmission and distribution system, which amounted to approximately $1.3 billion at March 31, 1998; (ii) LILCO's net investment in NMP2, which amounted to approximately $0.7 billion at March 31, 1998 (as more fully discussed in Note 5); (iii) certain of LILCO's regulatory assets associated with its electric business; and (iv) allocated accounts receivable and other assets. The regulatory assets to be acquired by LIPA amounted to approximately $6.6 billion at March 31, 1998, and primarily consist of the Base Financial Component (BFC), Rate Moderation Component (RMC), Shoreham post-settlement costs, Shoreham nuclear fuel, and the electric portion of the regulatory tax asset. For a further discussion of these regulatory assets, see Note 1. LIPA is contractually responsible for reimbursing HoldCo for postretirement benefits other than pension costs related to employees of LILCO's electric business. Accordingly, upon consummation of the transaction, HoldCo will reclassify the associated regulatory asset for postretirement benefits other than pensions to a contractual receivable. The principal liabilities to be assumed by LIPA through its stock acquisition of LILCO include: (i) LILCO's regulatory liabilities associated with its electric business; (ii) allocated accounts payable, customer deposits, other deferred credits and claims and damages; and (iii) certain series of long-term 67 debt. The regulatory liabilities to be assumed by LIPA amounted to approximately $365 million at March 31, 1998, and primarily consist of the regulatory liability component, 1989 Settlement credits and the electric portion of the regulatory tax liability. For a further discussion of these regulatory liabilities, see Note 1 of Notes to Financial Statements. The long-term debt to be assumed by LIPA will consist of: (i) all amounts then outstanding under the General and Refunding (G&R) Indentures; (ii) all amounts then outstanding under the Debenture Indentures, except as noted below; and (iii) substantially all of the tax-exempt authority financing notes. HoldCo is required to assume the financial obligation associated with the 7.30% Debentures due July 15, 1999, with an aggregate principal amount currently outstanding of $397 million and 8.20% Debentures due March 15, 2023, with an aggregate principal amount currently outstanding of $270 million. HoldCo will seek to exchange its Debentures, with identical terms, for these two series of Debentures and will issue a promissory note to LIPA in an amount equal to the unexchanged amount of such Debentures. HoldCo will also issue a promissory note to LIPA for a portion of the tax-exempt debt borrowed to support LILCO's current gas operations, with terms identical to those currently outstanding. The Company currently estimates the amount of this promissory note to be approximately $250 million. In July 1997, in accordance with the provisions of the LIPA Transaction, the Company and The Brooklyn Union Gas Company (Brooklyn Union) formed a limited partnership and each Company invested $30 million in order to purchase an interest rate swap option instrument to protect LIPA against market risk associated with the municipal bonds expected to be issued by LIPA to finance the transaction. Upon the closing of the LIPA Transaction, each limited partner will receive from LIPA $30 million plus interest thereon, based on each partners' average weighted cost of capital. In the event that the LIPA Transaction is not consummated, the maximum potential loss to the Company is the amount originally invested. In such event, the Company plans to defer any loss and petition the PSC to allow recovery from its customers. As part of the LIPA Transaction, the definitive agreements contemplate that one or more subsidiaries of HoldCo will enter into agreements with LIPA, pursuant to which such subsidiaries will provide management and operations services to LIPA with respect to the electric transmission and distribution system, deliver power generated by its power plants to LIPA, and manage LIPA's fuel and electric purchases and any off-system electric sales. In addition, three years after the LIPA Transaction is consummated, LIPA will have the right for a one-year period to acquire all of HoldCo's generating assets at the fair market value at the time of the exercise of the right, which value will be determined by independent appraisers. In July 1997, the New York State Public Authorities Control Board (PACB), created pursuant to the New York State Public Authorities Law and consisting of five members appointed by the governor, unanimously approved the definitive agreements related to the LIPA Transaction subject to the following conditions: (i) within one year of the effective date of the transaction, LIPA must establish a plan for open access to the electric distribution system; (ii) if LIPA exercises its option to acquire the generation assets of HoldCo's generation subsidiary, LIPA may not purchase the generating facilities, as contemplated in the generation purchase right agreement, at a price greater than book value; (iii) HoldCo must agree to invest, over a ten-year period, at least $1.3 billion in energy-related and economic development projects, and natural gas infrastructure projects on Long Island; (iv) LIPA will guarantee that, over a ten-year period, average electric rates will be reduced by no less than 14% when measured against the Company's rates today and no less than a 2% cost savings to LIPA customers must result from the savings attributable to the merger of LILCO and KeySpan; and (v) LIPA will not increase average electric customer rates by more than 68 2.5% over a twelve-month period without approval from the PSC. LIPA has adopted the conditions set forth by the PACB. The holders of common and certain series of preferred stock of the Company eligible to vote approved the LIPA Transaction in August 1997. In December 1997, the United States Nuclear Regulatory Commission (NRC) issued an order approving the indirect transfer of control of the Company's 18% ownership interest in NMP2 to LIPA. In December 1997, the Company filed with the FERC a settlement agreement reached with LIPA in connection with a previous filing of the Company's proposed rates for the sale of capacity and energy to LIPA, as contemplated in the LIPA transaction agreements. The Company also had previously filed an application with the FERC seeking approval of the transfer of the Company's electric transmission and distribution system to LIPA in connection with LIPA's purchase of the common stock of the Company. In February 1998, the FERC issued orders on both of the Company filings. Specifically, the FERC approved the Company's application to transfer assets to LIPA in connection with LIPA's acquisition of the Company's common stock. In addition, the FERC accepted the Company's proposed rates for sale of capacity and energy to LIPA. Those rates may go into effect on the date the service to LIPA begins, subject to refund, and final rates will be set after the FERC has completed its investigation of such rates, the timing of which cannot be determined at this time. In January 1998, the Company filed an application with the PSC in connection with the proposed transfer of its gas business unit assets, non-nuclear generating facility assets and certain other assets and related liabilities to one or more subsidiaries of HoldCo to be formed as contemplated in the LIPA Transaction agreements. On April 29, 1998, the PSC approved the transfer of the above-mentioned assets. In July 1997, the Company, Brooklyn Union and LIPA filed requests for private letter rulings with the Internal Revenue Service (IRS) regarding certain federal income tax issues which require favorable rulings in order for the LIPA Transaction to be consummated. On March 4, 1998, the IRS issued a private letter ruling confirming that the sale of the Company's common stock to LIPA would not result in a corporate tax liability to the Company. In addition, the IRS ruled that, after the stock sale, the income of LIPA's electric utility business will not be subject to federal income tax. In a separate ruling on February 27, 1998, the IRS also ruled that the bonds to be issued by LIPA to finance the acquisition would be tax-exempt. In January 1998, the Company filed an application with the SEC seeking an exception for most of the provisions of the Public Utilities Holding Company Act of 1935. In May 1998, the SEC issued an order approving the Company's application. The Company currently anticipates that the LIPA transaction will be consummated by June 30, 1998. Note 3. KeySpan Energy Corporation Transaction On December 29, 1996, The Brooklyn Union Gas Company (Brooklyn Union) and the Company entered into an Agreement and Plan of Exchange and Merger (Share Exchange Agreement), pursuant to which the companies will be merged in a transaction (KeySpan Transaction) that will result in the formation of HoldCo. The Share Exchange Agreement was amended and restated to reflect certain technical changes as of February 7, 1997 and June 26, 1997. Effective September 29, 1997, Brooklyn Union reorganized into a 69 holding company structure, with KeySpan Energy Corporation (KeySpan) becoming its parent holding company. Accordingly, the parties entered into an Amendment, Assignment and Assumption Agreement, dated as of September 29, 1997, which among other things, amended the Share Exchange Agreement and related stock option agreements to reflect the assignment by Brooklyn Union to KeySpan and the assumption by KeySpan of all Brooklyn Union's rights and obligations under such agreements. The KeySpan Transaction, which has been approved by both companies' boards of directors and shareholders, would unite the resources of the Company with the resources of KeySpan. KeySpan, with approximately 3,300 employees, distributes natural gas at retail, primarily in a territory of approximately 187 square miles which includes the boroughs of Brooklyn and Staten Island and two-thirds of the borough of Queens, all in New York City. KeySpan has energy-related investments in gas exploration, production and marketing in the United States and Northern Ireland, as well as energy services in the United States, including cogeneration projects, pipeline transportation and gas storage. Under the terms of the KeySpan Transaction, the Company's common shareowners will receive .803 shares (the Ratio) of HoldCo's common stock for each share of the Company's common stock that they currently hold. KeySpan common shareowners will receive one share of common stock of HoldCo for each common share of KeySpan they currently hold. Shareowners of the Company will own approximately 66% of the common stock of HoldCo while KeySpan shareowners will own approximately 34%. In the event that the LIPA Transaction is consummated, the Ratio will be 0.880 with Company shareowners owning approximately 68% of the HoldCo common stock. Based on current facts and circumstances, it is probable that the purchase method of accounting will apply to the KeySpan Transaction, with the Company being the acquiring company for accounting purposes. Consummation of the Share Exchange Agreement is not conditioned upon the consummation of the LIPA Transaction and consummation of the LIPA Transaction is not conditioned upon consummation of the Share Exchange Agreement. In March 1997, the Company filed an application with the FERC seeking approval of the transfer of the Company's common equity and certain FERC-jurisdictional assets to HoldCo. On July 17, 1997, the FERC granted such approval. The Share Exchange Agreement contains certain covenants of the parties pending the consummation of the transaction. Generally, the parties must carry on their businesses in the ordinary course consistent with past practice, may not increase dividends on common stock beyond specified levels and may not issue capital stock beyond certain limits. The Share Exchange Agreement also contains restrictions on, among other things, charter and by-law amendments, capital expenditures, acquisitions, dispositions, incurrence of indebtedness, certain increases in employee compensation and benefits, and affiliate transactions. Upon completion of the merger, Dr. William J. Catacosinos will become chairman and chief executive officer of HoldCo; Mr. Robert B. Catell, currently chairman and chief executive officer of KeySpan, will become president and chief operating officer of HoldCo. One year after the closing, Mr. Catell will succeed Dr. Catacosinos as chief executive officer, with Dr. Catacosinos continuing as chairman. The board of directors of HoldCo will be comprised of 15 members, six from the Company, six from KeySpan and three additional persons previously unaffiliated with either company. 70 In March 1997, the Company and the Brooklyn Union Gas Company (Brooklyn Union) filed a joint petition with the PSC seeking approval, under section 70 of the New York Public Service Law, of the KeySpan Agreement by which the Company and KeySpan each would become subsidiaries of HoldCo through an exchange of shares of common stock with HoldCo. In addition, the petition called for approximately $1.0 billion of savings attributable to operating synergies that are expected to be realized over the 10-year period following the combination to be allocated to customers, net of transaction costs for the combination. On December 10, 1997, Brooklyn Union, the Company, the Staff of the PSC and three other parties entered into a Settlement Agreement (Stipulation) resolving all issues among them in the proceeding. Hearings on the Stipulation were held in early January 1998 and, on February 4, 1998, the PSC approved, effective February 5, 1998, the Stipulation, modified only to reduce Brooklyn Union's earnings cap for the remaining years of its rate plan. Under the Stipulation, a three-year gas rate plan covering the period December 1, 1997 through November 30, 2000 will be implemented by the Company which provides for, among other things, an estimated reduction in customers' bills of approximately 3.9%, including fuel savings, through at least November 30, 2000. This gas rate reduction will occur in three phases as follows: (i) a reduction in base rates of approximately $12.2 million to reflect decreases in the Company's gas cost of service effective on February 5, 1998; (ii) a base rate reduction of approximately $6.2 million associated with non-fuel savings related to the KeySpan Transaction to become effective on the closing date of the transaction; and (iii) an expected reduction in the Gas Adjustment Clause (GAC) to reflect annual fuel savings associated with the transaction estimated at approximately $4.0 million, the actual level of which will be reflected in rates if and when they actually materialize. The Company will be subject to an earnings sharing provision pursuant to which it will be required to credit to core/firm customers 60% of any utility earnings up to 100 basis points above 11.10% and 50% of any utility earnings in excess of 12.10% of the allowed return on common equity. Both a customer service and a safety and reliability incentive performance program will be implemented effective December 1, 1997, with maximum pre-tax return on equity penalties of 40 and 12 basis points, respectively, if the Company fails to achieve certain performance standards in these areas. The Stipulation, which obligates the Company to reduce electric customers' bills by approximately 2.5% resulting from the savings in operating and fuel costs, related to synergy savings, also defers the time within which the PSC must act on the Company's pending electric rate plan until July 1, 1998. However, any reduction in customers' bills would not become effective until the PSC sets the Company's electric rates. For Brooklyn Union, effective on the date of the consummation of the KeySpan Transaction, Brooklyn Union's base rates to core/firm customers will be reduced by $23.9 million annually. In addition, effective in the fiscal year in which the KeySpan Transaction is consummated, Brooklyn Union will be subject to an earnings sharing provision pursuant to which it will be required to credit to core/firm customers 60% of any utility earnings up to 100 basis points above certain threshold equity return levels over the term of the rate plan (other than any earnings associated with discrete incentives) and 50% of any utility earnings in excess of 100 basis points above such threshold levels. The threshold levels, as modified by the February 5, 1998 Order, are 13.75% for fiscal year 1998, 13.50% for fiscal years 1999, 71 2000, and 2001; and 13.25% for fiscal year 2002. A safety and reliability incentive mechanism will be implemented effective on the consummation date of the KeySpan Transaction, with a maximum 12 basis point pre-tax penalty return on common equity if Brooklyn Union fails to achieve certain safety and reliability performance standards. With the exception of the simplification of the customer service performance standards, the current Brooklyn Union rate plan approved by the PSC in 1996 remains unchanged. Any gas cost savings allocable to Brooklyn Union resulting from the KeySpan Transaction will be reflected in rates to utility customers through the GAC as those savings are realized. The Stipulation adopts certain affiliate transaction restrictions, cost allocation and financial integrity conditions, and a competitive code of conduct. These restrictions and conditions eliminate or relax many restrictions currently applicable to Brooklyn Union in such areas as affiliate transactions, use of the name and reputation of Brooklyn Union by unregulated affiliates, common officers of HoldCo, the utility subsidiaries and unregulated subsidiaries, dividend payment restrictions, and the composition of the Board of Directors of Brooklyn Union. The Stipulation also enables the utilities to form one or more shared services subsidiaries to perform functions common to both utilities and their affiliates such as accounting, finance, human resources, legal and information systems and technology to realize synergy savings. Note 4. Rate Matters Electric In April 1996, the PSC issued an order directing the Company to file financial and other information sufficient to provide a legal basis for setting new rates for the three-year period 1997 through 1999. In compliance with the order, the Company submitted a multi-year rate plan (Plan) in September 1996. Major elements of the Plan include: (i) a base rate freeze for the three-year period December 1, 1996 through November 30, 1999; (ii) an allowed return on common equity of 11.0% through the term of the Plan with the Company fully retaining all earnings up to 12.66%, and sharing with the customer any earnings above 12.66%; (iii) the continuation of existing LRPP revenue and expense reconciliation mechanisms and performance incentive programs; (iv) crediting all net proceeds from the Shoreham property tax litigation to the RMC to reduce its balance; and (v) a mechanism to fully recover any outstanding RMC balance at the end of the 1999 rate year through inclusion in the FCA, over a two-year period. Pursuant to the provisions of the Stipulation discussed above, under the heading KeySpan Energy Corporation Transaction, the PSC has until July 1, 1998 to render a decision on this filing. As an interim measure, pending the consummation of the LIPA Transaction or the adjudication of its electric rate filing, the Company submitted petitions in May 1997 and December 1997 requesting PSC approval to extend, through the rate years ending November 30, 1996 and 1997, respectively, the provisions of its 1995 electric rate order (1995 Order). These petitions were approved by the PSC in December 1997 and April 1998, respectively. 1995 Electric Rate Order The basis of the 1995 Order included minimizing future electric rate increases while continuing to provide for the recovery of the Company's regulatory assets and retaining consistency with the RMA's objective of restoring the Company to financial health. The 1995 Order, which became effective December 1, 1994, froze base electric rates, reduced the Company's allowed return on common equity from 11.6% to 11.0% and modified or eliminated certain performance based incentives, as discussed below. The LRPP, originally approved by the PSC in November 1991, contained three major components: (i) revenue reconciliation; (ii) expense attrition and reconciliation; and, (iii) performance-based incentives. 72 In the 1995 Order, the PSC continued the three major components of the LRPP with modifications to the expense attrition and reconciliation mechanism and the performance-based incentives. The revenue reconciliation mechanism remains unchanged. Revenue reconciliation provides a mechanism that eliminates the impact of experiencing sales that are above or below adjudicated levels by providing a fixed annual net margin level (defined as sales revenues, net of fuel expenses and gross receipts taxes). The difference between actual and adjudicated net margin levels are deferred on a monthly basis during the rate year. The expense attrition and reconciliation component permits the Company to make adjustments for certain expenses recognizing that these cost increases are unavoidable due to inflation and changes outside the control of the Company. Pursuant to the 1995 Order, the Company is permitted to reconcile expenses for property taxes only, whereas under the original LRPP the Company was able to reconcile expenses for wage rates, property taxes, interest costs and demand side management (DSM) costs. The original LRPP had also provided for the deferral and amortization of certain cost variances for enhanced reliability, production operations and maintenance expenses and the application of an inflation index to other expenses. Under the 1995 Order, these deferrals have been eliminated and any unamortized balances were credited to the RMC during 1995. The modified performance-based incentive programs include the DSM program, the customer service performance program and the transmission and distribution reliability program. Under these revised programs, the Company was subject to a maximum penalty of 38 basis points of the allowed return on common equity and could earn up to 4 basis points under the customer service program. Pursuant to the Stipulation, the Company's customer service incentive program was further modified to eliminate the 4 basis point reward and increased the maximum penalty which can be incurred under the these programs from 38 to 62 basis points. The partial pass-through fuel incentive program remains unchanged. Under this incentive, the Company can earn or forfeit up to 20 basis points of the allowed return on common equity. For the rate year ended November 30, 1997, the Company earned 12.7 basis points, or approximately $2.9 million, net of tax effects, as a result of its performance under all incentive programs. For the rate years ended November 30, 1996 and 1995, the Company earned 20 and 19 basis points, respectively, or approximately $4.3 million and $4.0 million, respectively, net of tax effects, under the incentive programs in effect at those times. The deferred balances resulting from the net margin and expense reconciliations, and earned performance-based incentives are netted at the end of each rate year, as established under the LRPP and continued under the 1995 Order. The first $15 million of the total deferral is recovered from or credited to ratepayers by increasing or decreasing the RMC balance. Deferrals in excess of the $15 million, upon approval of the PSC, are refunded to or recovered from the customers through the FCA mechanism over a 12-month period. For the rate year ended November 30, 1997, the amount to be returned to customers resulting from the revenue and expense reconciliations, performance-based incentive programs and associated carrying charges totaled $4.1 million. Consistent with the mechanics of the LRPP, it is anticipated that the entire balance of the deferral will be used to reduce the RMC balance upon approval by the PSC of the Company's reconciliation filing which was submitted to the PSC in March 1998. For the rate year ended November 30, 1996, the Company recorded a net deferred LRPP credit of approximately $14.5 million 73 which was subsequently applied as a reduction to the RMC upon the PSC's approval of the Company's reconciliation filing in December 1996. For the rate year ended November 30, 1995, the Company recorded a net deferred credit of approximately $41 million. The first $15 million of the deferral was applied as a reduction to the RMC while the remaining portion of the deferral of $26 million will be returned to customers through the FCA when approved by the PSC. Another mechanism of the LRPP provides that earnings in excess of the allowed return on common equity, excluding the impacts of the various incentive and/or penalty programs, are used to reduce the RMC. For the rate years ended November 30, 1997, 1996 and 1995, the Company earned $4.8 million, $9.1 million, and $6.2 million, respectively, in excess of its allowed return on common equity. These excess earnings were applied as reductions to the RMC. In the event that the LIPA Transaction is not consummated, the Company is currently unable to predict the outcome of the electric rate proceeding currently before the PSC and its effect, if any, on the Company's financial position, cash flows or results of operations. Gas In May 1997, the Company submitted a petition requesting PSC approval to extend through the rate year ending November 30, 1997, the gas excess earnings sharing mechanism established in its prior three-year gas rate settlement agreement which expired on November 30, 1996. Pursuant to this request, earnings in excess of a return on common equity of 11.0% are to be allocated equally between customers and shareowners with the customers' share of excess earnings credited to the regulatory asset created as a result of costs associated with manufactured gas plant (MGP) site investigation and remediation costs. This request was approved by the PSC in December 1997. As a result of this mechanism, the customer's allocation of excess earnings amounted to $6.3 million for the rate year ended November 30, 1997, and will be applied to offset costs incurred to investigate and remediate MGP sites. The prior gas rate settlement provided that earnings in excess of a 10.6% return on common equity be shared equally between the Company's firm gas customers and its shareowners. For the rate years ended November 30, 1996 and 1995, the firm gas customers' portion of gas excess earnings totaled approximately $10 million and $1 million, respectively. In 1997, the Company was granted permission by the PSC to apply the customers' portion of the gas excess earnings and associated carrying charges for the 1996 and 1995 rate years to the recovery of deferred costs associated with post-retirement benefits other than pensions and costs incurred for investigation and remediation of MGP sites. Note 5. Nine Mile Point Nuclear Power Station, Unit 2 The Company has an undivided 18% interest in NMP2, located near Oswego, New York which is operated by Niagara Mohawk Power Corporation (NMPC). The owners of NMP2 and their respective percentage ownership are as follows: the Company (18%), NMPC (41%), New York State Electric & Gas Corporation (18%), Rochester Gas and Electric Corporation (14%) and Central Hudson Gas & Electric Corporation (9%). The Company's share of the rated capability is approximately 205 MW. The Company's net utility plant investment, excluding nuclear fuel, was approximately $689 million at March 31, 1998, $710 million at March 31, 1997 and $715 million at December 31, 1996. The accumulated provision for depreciation, excluding decommissioning costs, was approximately $196 million and $175 million at March 31, 1998 and 1997, respectively, and $169 million at December 31, 1996. Generation from NMP2 and operating expenses incurred by NMP2 are shared in the same proportions as the cotenants' respective ownership interests. The Company is required to provide its respective share of financing for any capital additions to NMP2. Nuclear fuel costs associated with NMP2 are being amortized on the basis of the quantity of heat produced for the generation of electricity. 74 NMPC has contracted with the United States Department of Energy for the disposal of spent nuclear fuel. The Company reimburses NMPC for its 18% share of the cost under the contract at a rate of $1.00 per megawatt hour of net generation less a factor to account for transmission line losses. For the year ended March 31, 1998 and for the three months ended March 31, 1997, this totaled $1.4 million and $0.4 million, respectively. For the years ended December 31, 1996 and 1995, this totaled $1.4 million and $1.2 million, respectively. As discussed in Note 2, the LIPA Transaction contemplates that LIPA will acquire the Company's 18% interest in NMP2. Nuclear Plant Decommissioning NMPC expects to commence the decommissioning of NMP2 in 2026, shortly after the cessation of plant operations, using a method which provides for the removal of all equipment and structures and the release of the property for unrestricted use. The Company's share of decommissioning costs, based upon a "Site-Specific" 1995 study (1995 study), is estimated to be $309 million in 2026 dollars ($155 million in 1998 dollars). The Company's share of the estimated decommissioning costs is currently being provided for in electric rates and is being charged to operations as depreciation expense over the service life of NMP2. The amount of decommissioning costs recorded as depreciation expense for the year ended March 31, 1998 and the three months ended March 31, 1997, totaled $2.2 million and $0.5 million, respectively, and $3.9 million and $2.3 million for the years ended December 31, 1996 and 1995, respectively. The accumulated decommissioning costs collected in rates through March 31, 1998 and 1997 and December 31, 1996 amounted to $17.7 million, $15.5 million and $14.9 million, respectively. The Company has established trust funds for the decommissioning of the contaminated portion of the NMP2 plant. It is currently estimated that the cost to decommission the contaminated portion of the plant will be approximately 76% of the total decommissioning costs. These funds comply with regulations issued by the NRC and the FERC governing the funding of nuclear plant decommissioning costs. The Company's policy is to make quarterly contributions to the funds based upon the amount of decommissioning costs reflected in rates. As of March 31, 1998, the balance in these funds, including reinvested net earnings, was approximately $17.9 million. These amounts are included on the Company's Balance Sheet in Nonutility Property and Other Investments. The trust funds investment consists of U.S. Treasury debt securities and cash equivalents. The carrying amounts of these instruments approximate fair market value. The FASB issued an exposure draft in 1996 entitled "Accounting for Certain Liabilities Related to Closure or Removal of Long-Lived Assets." Under the provisions of the exposure draft, the Company would be required to change its current accounting practices for decommissioning costs as follows: (i) the Company's share of the total estimated decommissioning costs would be accounted for as a liability, based on discounted future cash flows; (ii) the recognition of the liability for decommissioning costs would result in a corresponding increase to the cost of the nuclear plant rather than as depreciation expense; and (iii) investment earnings on the assets dedicated to the external decommissioning trust fund would be recorded as investment income rather than as an increase to accumulated depreciation. Discussions of the issues expressed in the exposure draft are ongoing. If the Company was required to record the present value of its share of NMP2 decommissioning costs on its Balance Sheet as of March 31, 1998, the Company would have to recognize a liability and corresponding increase to nuclear plant of approximately $62 million. Upon consummation of the LIPA Transaction, LIPA will acquire the Company's interest in NMP2 as well as the trusts referred to above. Nuclear Plant Insurance NMPC procures public liability and property insurance for NMP2, and the Company reimburses NMPC for its 18% share of those costs. 75 The Price-Anderson Amendments Act mandates that nuclear power plants secure financial protection in the event of a nuclear accident. This protection must consist of two levels. The primary level provides liability insurance coverage of $200 million (the maximum amount available) in the event of a nuclear accident. If claims exceed that amount, a second level of protection is provided through a retrospective assessment of all licensed operating reactors. Currently, this "secondary financial protection" subjects each of the 110 presently licensed nuclear reactors in the United States to a retrospective assessment of up to $76 million for each nuclear incident, payable at a rate not to exceed $10 million per year. The Company's interest in NMP2 could expose it to a maximum potential loss of $13.6 million, per incident, through assessments of $1.8 million per year in the event of a serious nuclear accident at NMP2 or another licensed U.S. commercial nuclear reactor. These assessments are subject to periodic inflation indexing and to a 5% surcharge if funds prove insufficient to pay claims. NMPC has also procured $500 million primary nuclear property insurance with the Nuclear Insurance Pools and approximately $2.3 billion of additional protection (including decontamination costs) in excess of the primary layer through Nuclear Electric Insurance Limited (NEIL). Each member of NEIL, including the Company, is also subject to retrospective premium adjustments in the event losses exceed accumulated reserves. For its share of NMP2, the Company could be assessed up to approximately $1.6 million per loss. This level of insurance is in excess of the NRC required $1.06 billion of coverage. The Company has obtained insurance coverage from NEIL for the extra expense incurred in purchasing replacement power during prolonged accidental outages. Under this program, should losses exceed the accumulated reserves of NEIL, each member, including the Company, would be liable for its share of deficiency. The Company's maximum liability per incident under the replacement power coverage, in the event of a deficiency, is approximately $0.7 million. Note 6. Capital Stock Common Stock Currently the Company has 150,000,000 shares of authorized common stock, of which 121,727,040 were issued and 46,281 shares were held in Treasury at March 31, 1998. The Company has 1,644,865 shares reserved for sale through its Employee Stock Purchase Plan, 2,829,968 shares committed to the Investor Common Stock Plan and 86,099 shares reserved for conversion of the Series I Convertible Preferred Stock at a rate of $17.15 per share. In addition, in connection with the Share Exchange Agreement, as discussed in Note 3, the Company has granted KeySpan the option to purchase, under certain circumstances, 23,981,964 shares of common stock at a price of $19.725 per share. In connection with such option, the Company has received shareowner approval to increase the authorized shares of common stock to 160,000,000. Preferred Stock The Company has 7,000,000 authorized shares, cumulative preferred stock, par value $100 per share and 30,000,000 authorized shares, cumulative preferred stock, par value $25 per share. Dividends on preferred stock are paid in preference to dividends on common stock or any other stock ranking junior to preferred stock. Preferred Stock Subject to Mandatory Redemption The aggregate fair value of redeemable preferred stock with mandatory redemptions at March 31, 1998 and 1997 and December 31, 1996 amounted to approximately $675, $643 and $637 million, respectively, compared to their carrying amounts of $639, $640 and $640 million, respectively. For a further discussion on the basis of the fair value of the securities discussed above, see Note 1. 76 Each year the Company is required to redeem certain series of preferred stock through the operation of sinking fund provisions as follows:
- ------------------------------------------------------------------------------------------------------------- Series Redemption Provision Number of Shares Redemption Amounts Beginning Ending - ------------------------------------------------------------------------------------------------------------- 6.875% Series UU 10/15/99 10/15/19 112,000 $2,800,000 =============================================================================================================
The aggregate par value of preferred stock required to be redeemed through sinking funds during the fiscal year ended March 31, is $2.8 million in each of the years 2000, 2001, 2002 and 2003. The Company also has the non-cumulative option to double the number of shares to be redeemed pursuant to the sinking fund provisions in any year for the preferred stock series UU. The Company is also required to redeem all shares of certain series of preferred stock which are not subject to sinking fund requirements. The mandatory redemption requirements for these series are as follows:
- ------------------------------------------------------------------------------------------------------------ Series Redemption Date Number of Shares Redemption Amounts - ------------------------------------------------------------------------------------------------------------ $1.67 Series GG 3/1/99 880,000 $ 22,000,000 7.95% Series AA 6/1/00 14,520,000 363,000,000 7.05% Series QQ 5/1/01 3,464,000 86,600,000 7.66% Series CC 8/1/02 570,000 57,000,000 ============================================================================================================
Preferred Stock Subject to Optional Redemption The Company has the option to redeem certain series of its preferred stock. For the series subject to optional redemption at March 31, 1998, the call prices were as follows:
- ----------------------------------------------------------------------------------------------------------- Series Call Price Redemption Amounts - ----------------------------------------------------------------------------------------------------------- 5.00% Series B $101.00 $10,100,000 4.25% Series D 102.00 7,140,000 4.35% Series E 102.00 20,400,000 4.35% Series F 102.00 5,100,000 5 1/8% Series H 102.00 20,400,000 5 3/4% Series I - Convertible 100.00 1,474,300 7.40% Series L 102.07 15,361,535 $1.95 Series NN 26.95 41,880,300 ===========================================================================================================
On April 17, 1998, the Company exercised its option to redeem its callable preferred stock and called for redemption on May 19, 1998 all of the outstanding shares of the preferred stock series noted above for a total of $122 million including approximately $5 million of call premiums. Preference Stock At March 31, 1998, none of the authorized 7,500,000 shares of nonparticipating preference stock, par value $1 per share, which ranks junior to preferred stock, were outstanding. Note 7. Long-Term Debt G&R Mortgage The General and Refunding (G&R) Bonds are the Company's only outstanding secured indebtedness. The G&R Mortgage is a lien on substantially all of the Company's properties. The annual G&R Mortgage sinking fund requirement for 1997, due not later than June 30, 1998, is estimated at $25 million. It is anticipated that this requirement will be satisfied with retired G&R Bonds, property additions, or any combination thereof. 77 Upon consummation of the LIPA Transaction, all of the Company's series of G&R Bonds will be assumed by LIPA. LIPA has indicated that it intends to redeem all such G&R Bonds as soon as practicable after the closing of the LIPA Transaction. 1989 Revolving Credit Agreement The Company has available through October 1, 1998, $250 million under its 1989 Revolving Credit Agreement (1989 RCA). This line of credit is secured by a first lien upon the Company's accounts receivable and fuel oil inventories. In February 1997, the Company utilized $30 million in interim financing under the 1989 RCA, which was repaid in March 1997, and $40 million in July 1997, which was repaid in August 1997. At March 31, 1998, no amounts were outstanding under the 1989 RCA. The Company has filed, with the lending institutions, the documentation necessary to terminate the 1989 RCA effective upon the closing of the LIPA and KeySpan Transactions. Authority Financing Notes Authority Financing Notes are issued by the Company to the New York State Energy Research and Development Authority (NYSERDA) to secure certain tax-exempt Industrial Development Revenue Bonds, Pollution Control Revenue Bonds (PCRBs) and Electric Facilities Revenue Bonds (EFRBs) issued by NYSERDA. Certain of these bonds are subject to periodic tender, at which time their interest rates may be subject to redetermination. Tender requirements of Authority Financing Notes at March 31, 1998 were as follows:
(In thousands of dollars) - -------------------------------------------------------------------------------------------------------------- Interest Rate Series Principal Tendered - -------------------------------------------------------------------------------------------------------------- PCRBs 8 1/4% 1982 $ 17,200 Tendered every three years, next tender October 2000 3.58% 1985 A,B 150,000 Tendered annually on March 1 EFRBs 3.70% 1993 A 50,000 Tendered weekly 3.70% 1993 B 50,000 Tendered weekly 3.70% 1994 A 50,000 Tendered weekly 3.70% 1995 A 50,000 Tendered weekly 3.55% 1997 A 24,880 Tendered weekly ==============================================================================================================
The 1997, 1995, 1994 and 1993 EFRBs and the 1985 PCRBs are supported by letters of credit pursuant to which the letter of credit banks have agreed to pay the principal, interest and premium, if applicable, in the aggregate, up to approximately $408 million in the event of default. The obligation of the Company to reimburse the letter of credit banks is unsecured. The expiration dates for these letters of credit are as follows:
- ----------------------------------------------------------------------------------------------------------------- Series Expiration Date - ----------------------------------------------------------------------------------------------------------------- PCRBs 1985 A,B 3/16/99 EFRBs 1993 A,B 11/17/99 1994 A 10/26/00 1995 A 8/24/98 1997 A 12/30/98 =================================================================================================================
Prior to expiration, the Company is required to obtain either an extension of the letters of credit or a substitute credit facility. If neither can be obtained, the authority financing notes supported by letters of credit must be redeemed. In accordance with the LIPA Agreement, LIPA will assume substantially all of the tax-exempt authority financing notes. HoldCo will issue a promissory note to LIPA for a portion of the tax-exempt debt borrowed to support LILCO's current gas operations, with terms identical to those currently outstanding. The Company currently estimates the amount of this promissory note to be approximately $250 million. 78 Fair Values of Long-Term Debt The carrying amounts and fair values of the Company's long-term debt at March 31, 1998 and 1997 and December 31, 1996 were as follows:
Fair Value (In thousands of dollars) - ----------------------------------------------------------------------------------------------------------------- March 31, 1998 March 31, 1997 December 31, 1996 - ----------------------------------------------------------------------------------------------------------------- General and Refunding Bonds $1,288,470 $1,314,273 $1,571,745 Debentures 2,407,178 2,256,573 2,271,095 Authority Financing Notes 987,646 959,092 950,758 ================================================================================================================= Total $4,683,294 $4,529,938 $4,793,598 ================================================================================================================= Carrying Amount (In thousands of dollars) - ----------------------------------------------------------------------------------------------------------------- March 31, 1998 March 31, 1997 December 31, 1996 - ----------------------------------------------------------------------------------------------------------------- General and Refunding Bonds $1,286,000 $1,286,000 $1,536,000 Debentures 2,270,000 2,270,000 2,270,000 Authority Financing Notes 940,555 916,675 916,675 ================================================================================================================= Total $4,496,555 $4,472,675 $4,722,675 =================================================================================================================
For a further discussion on the basis of the fair value of t securities listed above, see Note 1. Debt Maturity Schedule The total long-term debt maturing in each of the next five years ending March 31 is as follows: 1999, $101 million; 2000, $490 million; 2001, $1 million; 2002, $146 million; and 2003, $154 million. Note 8. Retirement Benefit Plans Pension Plans The Company maintains a defined benefit pension plan which covers substantially all employees (Primary Plan), a supplemental plan which covers officers and certain key executives (Supplemental Plan) and a retirement plan which covers the Board of Directors (Directors' Plan). The Company also maintains ss.401(k) plans for its union and non-union employees to which it does not contribute. Primary Plan The Company's funding policy is to contribute annually to the Primary Plan a minimum amount consistent with the requirements of the Employee Retirement Income Security Act of 1974, plus such additional amounts, if any, as the Company may determine to be appropriate from time to time. Pension benefits are based upon years of participation in the Primary Plan and compensation. The Primary Plan's funded status and amounts recognized on the Balance Sheet at March 31, 1998 and March 31, 1997 and December 31, 1996 were as follows:
(In thousands of dollars) - --------------------------------------------------------------------------------------------------------------------- March 31, 1998 March 31, 1997 December 31, 1996 - --------------------------------------------------------------------------------------------------------------------- Actuarial present value of benefit obligation Vested benefits $661,075 $642,392 $547,002 Nonvested benefits 59,268 57,960 55,157 ===================================================================================================================== Accumulated Benefit Obligation $720,343 $700,352 $602,159 ===================================================================================================================== Plan assets at fair value $919,100 $744,400 $746,400 Actuarial present value of projected benefit obligation 825,159 807,703 689,661 - --------------------------------------------------------------------------------------------------------------------- Projected benefit obligation less (greater) than plan assets 93,941 (63,303) 56,739 Unrecognized net obligation 62,652 69,399 71,085 Unrecognized net (gain) (163,034) ( 1,605) (123,759) ===================================================================================================================== Net (Accrued) Prepaid Pension Cost $( 6,441) $ 4,491 $ 4,065 ====================================================================================================================
79 The increase in the present value of the accrued benefit at March 31, 1997 compared to December 31, 1996, is due primarily to the change in the discount rate from 7.25% to 7.00% and the use of updated actuarial assumptions, relating to mortality. Periodic pension cost for the Primary Plan and the significant assumptions consisted of the following:
(In thousands of dollars) - -------------------------------------------------------------------------------------------------------------------------- Year Ended Three Months Ended Year Ended Year Ended March 31, 1998 March 31, 1997 December 31, 1996 December 31, 1995 - -------------------------------------------------------------------------------------------------------------------------- Service cost - benefits earned during the period $ 21,114 $ 4,645 $ 17,384 $ 15,385 Interest cost on projected benefits obligation and service cost 56,379 12,494 47,927 45,987 Actual return on plan assets (200,025) (3,694) (81,165) (102,099) Net amortization and deferral 151,438 (9,446) 33,541 57,665 - -------------------------------------------------------------------------------------------------------------------------- Net Periodic Pension Cost $ 28,906 $ 3,999 $ 17,687 $ 16,938 ========================================================================================================================== - -------------------------------------------------------------------------------------------------------------------------- March 31, 1998 March 31, 1997 December 31, 1996 December 31, 1995 - -------------------------------------------------------------------------------------------------------------------------- Discount rate for obligation 7.00% 7.00% 7.25% 7.25% Discount rate for expense 7.00% 7.25% 7.25% 7.25% Rate of future compensation increases 4.50% 5.00% 5.00% 5.00% Long-term rate of return on assets 8.50% 7.50% 7.50% 7.50% ==========================================================================================================================
The Primary Plan assets at fair value include cash, cash equivalents, group annuity contracts, bonds and equity securities. In 1993, the PSC issued an Order which addressed the accounting and ratemaking treatment of pension costs in accordance with SFAS No. 87, "Employers' Accounting for Pensions." Under the Order, the Company is required to recognize any deferred net gains or losses over a ten-year period rather than using the corridor approach method. The Company believes that this method of accounting for financial reporting purposes results in a better matching of revenues and the Company's pension cost. The Company defers differences between pension rate allowance and pension expense under the Order. In addition, the PSC requires the Company to measure and pay a carrying charge on amounts in excess of the pension rate allowance and the annual pension contributions contributed into the pension fund. In addition, effective December 1, 1997, in accordance with the Stipulation, the Company defers the difference between the sum of gas pension and gas postretirement benefit costs other than pension and the amounts provided for in rates, to the extent that such differences are in excess of or below three percent of the Company's pretax net income from its gas operations. Such excess will be transferred to a gas balancing account. For a further discussion of the Stipulation, see Note 3. Supplemental Plan The Supplemental Plan provides supplemental death and retirement benefits for officers and other key executives without contribution from such employees. The Supplemental Plan is a non-qualified plan under the Internal Revenue Code. The provision for plan benefits totaled approximately $0.7 million for the three months ended March 31, 1997 and $2.7 million and $2.3 million for the years ended December 31, 1996 and 1995, respectively. For the year ended March 31, 1998, the Company recorded a charge of approximately $31 million relating to certain benefits earned by its officers relating to the termination of their annuity benefits earned through the supplemental retirement plan and other executive retirement benefits. These charges, the cost of which are borne by the Company's shareowners, result from provisions of the officers' employment contracts, including the Chairman's employment contract, and the pending transactions with LIPA and KeySpan which affect the timing of when these costs are recorded. 80 Directors' Plan The Directors' Plan provides benefits to directors who are not officers of the Company. Directors who have served in that capacity for more than five years qualify as participants under the plan. The Directors' Plan is a non-qualified plan under the Internal Revenue Code. The provision for retirement benefits, which are unfunded, totaled approximately $132,000 for the year ended March 31, 1998, $34,000 for the three months ended March 31, 1997 and $127,000 and $114,000 for the years ended December 31, 1996 and 1995, respectively. Postretirement Benefits Other Than Pensions In addition to providing pension benefits, the Company provides certain medical and life insurance benefits to retired employees. Substantially all of the Company's employees may become eligible for these benefits if they reach retirement age after working for the Company for a minimum of five years. These and similar benefits for active employees are provided by the Company or by insurance companies whose premiums are based on the benefits paid during the year. Effective January 1, 1993, the Company adopted the provisions of SFAS No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions," which requires the Company to recognize the expected cost of providing postretirement benefits when employee services are rendered rather than when paid. As a result, the Company, in 1993, recorded an accumulated postretirement benefit obligation and a corresponding regulatory asset of approximately $376 million. The PSC requires the Company to defer as a regulatory asset the difference between postretirement benefit expense recorded for accounting purposes in accordance with SFAS No. 106 and the postretirement benefit expense reflected in rates. The ongoing annual postretirement benefit expense was phased into and fully reflected in rates beginning December 1, 1996 with the accumulated regulatory asset to be recovered in rates over a 15-year period, beginning December 1, 1997. In addition, the Company is required to recognize any deferred net gains or losses over a ten-year period. In addition, effective December 1, 1997, in accordance with the Stipulation, the Company defers the difference between the sum of gas pension and gas postretirement benefit costs other than pension and the amounts provided for in rates, to the extent that such differences are in excess of or below three percent of the Company's pretax net income from its gas operations. Such excess will be transferred to a gas balancing account. For a further discussion of the Stipulation, see Note 3. In 1994, the Company established Voluntary Employee's Beneficiary Association trusts for union and non-union employees for the funding of incremental costs collected in rates for postretirement benefits. The Company funded the trusts with approximately $21 million for the year ended March 31, 1998, $5 million for the three months ended March 31, 1997 and $18 million and $50 million for the years ended December 31, 1996 and 1995, respectively. In May 1998, the Company funded an additional $250 million into the trusts, representing obligations related to the electric business unit employees. The Company secured a bridge loan to fund these trusts. 81 Accumulated postretirement benefit obligation other than pensions at March 31, 1998, March 31, 1997 and December 31, 1996 was as follows:
(In thousands of dollars) - -------------------------------------------------------------------------------------------------------------------------- March 31, 1998 March 31, 1997 December 31, 1996 - -------------------------------------------------------------------------------------------------------------------------- Retirees $157,380 $169,655 $156,181 Fully eligible plan participants 60,711 62,491 56,950 Other active plan participants 140,850 183,526 152,627 - -------------------------------------------------------------------------------------------------------------------------- Accumulated postretirement benefit obligation $358,941 $415,672 $365,758 Plan assets 108,165 80,533 74,692 - -------------------------------------------------------------------------------------------------------------------------- Accumulated postretirement benefit obligation in excess of plan assets 250,776 335,139 291,066 Unrecognized prior service costs (175) (185) (188) Unrecognized net gain 102,346 28,563 75,309 =========================================================================================================================== Accrued Postretirement Benefit Cost $352,947 $363,517 $366,187 ===========================================================================================================================
The increase in the present value of the accrued benefit at March 31, 1997 compared to December 31, 1996 is due to the change in the discount rate from 7.25% to 7.00% and the use of updated actuarial assumptions relating to mortality. The change in the accumulated postretirement benefit obligation from March 31, 1997 to March 31, 1998 reflects a decrease in the healthcare cost trend rate based on the company's review of the medical plan cost experience and also revised assumptions with respect to future compensation increases, mortality and the percentage of employees who are assumed to be married at the time of retirement. At March 31, 1998, March 31, 1997 and December 31, 1996 the Plan assets, which are recorded at fair value, include cash and cash equivalents, fixed income investments and approximately $100,000 of listed equity securities of the Company. Periodic postretirement benefit cost other than pensions and the significant assumptions consisted of the following:
(In thousands of dollars) - -------------------------------------------------------------------------------------------------------------------------- Year Ended Three Months Ended Year Ended Year Ended March 31, 1998 March 31, 1997 December 31, 1996 December 31, 1995 - -------------------------------------------------------------------------------------------------------------------------- Service cost - benefits earned during the period $ 12,204 $ 2,821 $ 10,690 $ 9,082 Interest cost on projected benefits obligation and service cost 27,328 6,642 25,030 22,412 Actual return on plan assets (6,632) (591) (3,046) (1,034) Net amortization and deferral (10,000) (3,446) (12,175) (14,699) - -------------------------------------------------------------------------------------------------------------------------- Net Periodic Pension Cost $ 22,900 $ 5,426 $ 20,499 $ 15,761 ==========================================================================================================================
- -------------------------------------------------------------------------------------------------------------------------- March 31, 1998 March 31, 1997 December 31, 1996 December 31, 1995 - -------------------------------------------------------------------------------------------------------------------------- Discount rate for obligation 7.00% 7.00% 7.25% 7.25% Discount rate for expense 7.00% 7.25% 7.25% 7.25% Rate of future compensation increases 4.50% 5.00% 5.00% 5.00% Long-term rate of return on assets 8.50% 7.50% 7.50% 7.50% ==========================================================================================================================
The actuarial assumptions used for postretirement benefit plans are: - -------------------------------------------------------------------------------------------------------------------------- (In thousands of dollars) March 31, 1998 March 31, 1997 December 31, 1996 - -------------------------------------------------------------------------------------------------------------------------- Health care cost trend 5.00%(a) 8.00%(b) 8.00%(b) Effect of one percent increase in health care cost trend rate: On cost components $ 7 $ 1 $ 5 On accumulated benefit obligation $42 $59 $43 ==========================================================================================================================
(a) Per year indefinitely (b) Gradually declining to 6.0% in 2001 and thereafter. 82 Note 9. Federal Income Tax The significant components of the Company's deferred tax assets and liabilities calculated under the provisions of SFAS No. 109, "Accounting for Income Taxes," were as follows:
(In thousands of dollars) - -------------------------------------------------------------------------------------------------------------------------- 3/31/98 3/31/97 12/31/96 - -------------------------------------------------------------------------------------------------------------------------- Deferred Tax Assets Net operating loss carryforwards $ - $ 93,349 $ 145,205 Reserves not currently deductible 39,667 56,749 58,981 Tax depreciable basis in excess of 10,559 33,848 34,314 book Nondiscretionary excess credits 24,858 27,037 27,700 Credit carryforwards 40,318 128,469 135,902 Other 261,729 225,885 186,907 - -------------------------------------------------------------------------------------------------------------------------- Total Deferred Tax Assets $ 377,131 $ 565,337 $ 589,009 - -------------------------------------------------------------------------------------------------------------------------- Deferred Tax Liabilities 1989 Settlement $2,169,909 $2,165,462 $2,163,239 Accelerated depreciation 650,562 642,656 642,702 Call premiums 38,698 43,617 44,846 Rate case deferrals 564 2,579 2,127 Other 56,762 38,117 33,496 - -------------------------------------------------------------------------------------------------------------------------- Total Deferred Tax Liabilities 2,916,495 2,892,431 2,886,410 ========================================================================================================================== Net Deferred Tax Liability $2,539,364 $2,327,094 $2,297,401 ========================================================================================================================== SFAS No. 109 requires utilities to establish regulatory assets and liabilities for the portion of its deferred tax assets and liabilities that have not yet been recognized for ratemaking purposes. The major components of these regulatory assets and liabilities are as follows: (In thousands of dollars) - -------------------------------------------------------------------------------------------------------------------------- 3/31/98 3/31/97 12/31/96 - -------------------------------------------------------------------------------------------------------------------------- Regulatory Assets 1989 Settlement $1,652,412 $1,659,065 $1,660,871 Plant items 100,661 120,460 125,976 Other (15,141) (12,361) (14,069) ========================================================================================================================== Total Regulatory Assets $1,737,932 $1,767,164 $1,772,778 ========================================================================================================================== Regulatory Liabilities Carryforward credits $ 38,720 $ 64,548 $ 68,421 Other 40,193 35,829 34,466 ========================================= =============================== ========================= ====================== Total Regulatory Liabilities $ 78,913 $ 100,377 $ 102,887 ========================================= =============================== ========================= ======================
The federal income tax amounts included in the Statement of Income differ from the amounts which result from applying the statutory federal income tax rate to income before income tax. The table below sets forth the reasons for such differences.
(In thousands of dollars) - ------------------------------------------------------------------------------------------------------------------------- Year Ended Three Months Ended Year Ended Year Ended March 31, 1998 March 31, 1997 December 31, 1996 December 31, 1995 - ------------------------------------------------------------------------------------------------------------------------- Income before federal income tax $594,893 $143,910 $525,721 $508,824 Statutory federal income tax rate 35% 35% 35% 35% - ------------------------------------------------------------------------------------------------------------------------- Statutory federal income tax $208,213 $ 50,369 $184,002 $178,088 Additions (reductions) in federal income tax Excess of book over tax depreciation 17,912 4,356 18,339 18,588 1989 Settlement 4,212 1,053 4,212 4,213 Interest capitalized 2,962 588 2,270 2,218 Tax credits (2,464) (940) (4,383) (1,025) Tax rate change amortization 2,223 815 3,686 3,752 Allowance for funds used during (2,953) (583) (2,305) (2,392) construction Other items 2,549 555 3,436 2,096 - ------------------------------------------------------------------------------------------------------------------------- Total Federal Income Tax Expense $232,654 $56,213 $209,257 $205,538 ========================================================================================================================= Effective Federal Income Tax Rate 39.1% 39.1% 39.8% 40.4% =========================================================================================================================
83 The Company currently has tax credit carryforwards of approximately $40 million. This balance is composed of investment tax credit (ITC) carryforwards, net of the 35% reduction required by the Tax Reform Act of 1986, totaling approximately $31 million and research and development credits totaling approximately $9 million. In 1990 and 1992, the Company received Revenue Agents' Reports disallowing certain deductions and credits claimed by the Company on its federal income tax returns for the years 1981 through 1989. A settlement resolving all audit issues was reached between the Company and the Internal Revenue Service in May 1998. The settlement provided for the payment of taxes and interest of approximately $9 million and $35 million, respectively, which the Company made in May 1998. The Company had previously provided reserves adequate to cover such taxes and interest. Note 10. The 1989 Settlement In February 1989, the Company and the State of New York entered into the 1989 Settlement resolving certain issues relating to the Company and providing, among other matters, for the financial recovery of the Company and for the transfer of Shoreham to LIPA, an agency of the State of New York, for its subsequent decommissioning. In February 1992, the Company transferred ownership of Shoreham to LIPA. In May 1995, the NRC terminated LIPA's possession-only license for Shoreham which signified the NRC's approval that decommissioning was complete and that the site is suitable for unrestricted use. Upon the effectiveness of the 1989 Settlement, in June 1989, the Company recorded the FRA on its Balance Sheet and the retirement of its investment of approximately $4.2 billion, principally in Shoreham. For a further discussion of the FRA, see Note 1. Pursuant to the 1989 Settlement, the Company was required to reimburse LIPA for all of its costs associated with the decommissioning of Shoreham. The PSC has determined that all costs associated with Shoreham which are prudently incurred by the Company subsequent to the effectiveness of the 1989 Settlement are decommissioning costs. The RMA provides for the recovery of such costs through electric rates over the balance of a forty-year period ending 2029. At March 31, 1998, Shoreham post-settlement costs totaled approximately $1.2 billion, consisting of $587 million of property taxes and payments-in-lieu-of-taxes, and $568 million of decommissioning costs, fuel disposal costs and all other costs incurred at Shoreham after June 30, 1989. Note 11. The Class Settlement The Class Settlement, which became effective in June 1989, resolved a civil lawsuit against the Company brought under the federal Racketeer Influenced and Corrupt Organizations Act. The lawsuit, which the Class Settlement resolved, had alleged that the Company made inadequate disclosures before the PSC concerning the construction and completion of nuclear generating facilities. The Class Settlement provides the Company's electric customers with rate reductions aggregating $390 million that are being reflected as adjustments to their monthly electric bills over a ten-year period which began on June 1, 1990. Upon its effectiveness, the Company recorded its liability for the Class Settlement on a present value basis at $170 million. The Class Settlement obligation at March 31, 1998 reflects the present value of the remaining reductions to be refunded to customers. The remaining reductions to customers bills, amounting to approximately $130 million as of March 31, 1998, consists of approximately $10 million for the two-month period beginning April 1, 1998, and $60 million for each of the 12-month periods beginning June 1, 1998 and 1999. 84 Note 12. Commitments and Contingencies Electric The Company has entered into contracts with numerous Independent Power Producers (IPPs) and the New York Power Authority (NYPA) for electric generating capacity. Under the terms of the agreement with NYPA, which is set to expire in May 2014, the Company may purchase up to 100% of the electric energy produced at the NYPA facility located within the Company's service territory at Holtsville, NY. The Company is required to reimburse NYPA for the minimum debt service payments, and to make fixed non-energy payments and expenses associated with operating and maintaining the plant. With respect to contracts entered into with the IPPs, the Company is obligated to purchase all the energy they make available to the Company at prices that often exceed current market prices. However, the Company has no obligation to the IPPs if they fail to deliver energy. For purposes of the table below, the Company has assumed full performance by the IPPs, as no event has occurred to suggest anything less than full performance by these parties. The Company also has contracted with NYPA for firm transmission (wheeling) capacity in connection with a transmission cable which was constructed, in part, for the benefit of the Company. In accordance with the provisions of this agreement, which expires in 2020, the Company is required to reimburse NYPA for debt service payments and the cost of operating and maintaining the cables. The cost of such contracts is included in electric fuel expense and is recoverable through rates. The following table represents the Company's commitments under purchased power contracts.
Electric Operations (In millions of dollars) - ------------------------------------------------------------------------------------------------------------------------- NYPA Holtsville ------------------------------------------- Other Fixed Firm Total For the fiscal years ended Debt Service Charges Energy* Transmission IPPs* Business* - ------------------------------------------------------------------------------------------------------------------------- 1999 $ 21.7 $ 14.7 $ 6.7 $ 25.7 $ 127.6 $ 196.4 2000 21.7 13.7 6.7 26.0 132.7 200.8 2001 21.8 14.6 7.2 27.8 135.8 207.2 2002 21.9 16.3 8.7 27.8 139.5 214.2 2003 22.0 16.7 9.0 27.9 137.9 213.5 Subsequent Years 232.4 217.1 119.8 474.0 957.5 2,000.8 - ------------------------------------------------------------------------------------------------------------------------- Total $341.5 $293.1 $158.1 $609.2 $1,631.0 $3,032.9 - ------------------------------------------------------------------------------------------------------------------------- Less: Imputed Interest $166.8 $154.1 $ 85.3 $381.9 $ 805.2 $1,593.3 - ------------------------------------------------------------------------------------------------------------------------- Present Value of Payments $174.7 $139.0 $ 72.8 $227.3 $ 825.8 $1,439.6 - -------------------------------------------------------------------------------------------------------------------------
*Assumes full performance by the IPPs and NYPA. Gas In order to provide for sufficient supplies of gas for the Company's gas customers, the Company has entered into long-term firm gas transportation, storage and supply contracts which contain provisions that require the Company to make fixed payments (demand charges) even if the services are not fully utilized. The cost of such contracts is included in gas fuel expense and is recoverable through rates. The table below sets forth the Company's aggregate obligation under these commitments which extend through 2014. Gas Operations (In millions of dollars) --------------------------------------------------------------------- For the fiscal years ended 1999 $111.73 2000 110.37 2001 101.33 2002 97.81 2003 91.69 Subsequent Years 371.20 --------------------------------------------------------------------- Total $884.13 Less: Imputed Interest 258.45 ===================================================================== Present Value of Payments $625.68 ===================================================================== 85 Competitive Environment The electric industry continues to undergo fundamental changes as regulators, elected officials and customers seek lower energy prices. These changes, which may have a significant impact on future financial performance of electric utilities, are being driven by a number of factors including a regulatory environment in which traditional cost-based regulation is seen as a barrier to lower energy prices. In 1997 and 1998, both the PSC and the FERC continued their separate, but in some cases parallel, initiatives with respect to developing a framework for a competitive electric marketplace. The Electric Industry - State Regulatory Issues In 1994, the PSC began the second phase of its Competitive Opportunities Proceedings to investigate issues related to the future of the regulatory process in an industry which is moving toward competition. The PSC's overall objective was to identify regulatory and ratemaking practices that would assist New York State utilities in the transition to a more competitive environment designed to increase efficiency in providing electricity while maintaining safe, affordable and reliable service. As a result of the Competitive Opportunities Proceedings, in May 1996, the PSC issued an order (Order) which stated its belief that introducing competition to the electric industry in New York has the potential to reduce electric rates over time, increase customer choice and encourage economic growth. The Order called for a competitive wholesale power market to be in place by early 1997 to be followed by the introduction of retail access for all customers by early 1998. The PSC stated that competition should be transitioned on an individual company basis, due to differences in individual service territories, the level and type of strandable investments (i.e., costs that utilities would have otherwise recovered through rates under traditional cost of service regulation that, under market competition, would not be recoverable) and utility specific financial conditions. The Order contemplates that implementation of competition will proceed on two tracks. The Order requires that each major electric utility (except the Company and Niagara Mohawk Power Corporation) file a rate/restructuring plan which is consistent with the PSC's policy and vision for increased competition. Those plans were submitted by October 1, 1996, in compliance with the Order. However, the Company was exempted from this requirement due to the PSC's separate investigation of the Company's rates and LIPA's examination of the Company's structure. The PSC has now approved settlement agreements with each of the five New York utilities that were required to file restructuring plans in the Competitive Opportunities Proceeding. LILCO and Niagara Mohawk were exempt however, on February 18,1998 the PSC also approved a settlement agreement on the Niagara Mohawk PowerChoice restructuring proposal that had been filed in October 1995. In general, the terms of the agreements vary from three to five years with all agreements calling for some rate reductions, structural separation of the generation and power delivery function, divestiture of fossil generation, full retail access in two to four years, and the imposition of a system benefits charge to cover the costs of research and development (R&D), conservation, low-income and environmental programs. In each case, the PSC is giving the utility a reasonable opportunity to recover all prudently-incurred stranded costs. The PSC Order also anticipated that certain other filings would be made on October 1, 1996, by all New York State utilities, to both the PSC and the FERC. The filings were to address the delineation of transmission and distribution facilities jurisdiction between the FERC or the PSC, a pricing of each company's transmission services, and a joint filing by all the utilities to address the formation of an Independent System Operator (ISO) and the creation of a market exchange that will establish spot market 86 prices. Although there were extensive collaborative meetings among the parties, it was not possible for the additional filings to be completed by October 1, 1996. On December 31, 1996, the New York Power Pool members submitted a compliance filing to the FERC which provides open membership and comparable services to eligible entities in accordance with FERC Order 888, discussed below. The New York State utilities submitted the full ISO/Power Exchange filing to the FERC in January 1997, which proposes to establish a competitive wholesale marketplace in New York State for electric energy and transmission pricing at market-based rates. Subsequent to the FERC filing in January 1997, the New York State utilities made three relating filings with the FERC: (i) a supplemental filing, providing additional details regarding the creation of a New York State Reliability Council, in May 1997; (ii) a request for market-based rate authority, by six of the New York utilities, in August 1997; and (iii) a supplemental filing with the FERC on December 19, 1997 which expands upon and provides additional details with respect to the January 1997 filing. The PSC has taken the position that a fully operational wholesale competitive structure will foster the expeditious movement to full retail competition. The PSC's vision of the retail competitive structure, known as the Flexible Retail Poolco Model, consists of: (i) the creation of an ISO to coordinate the safe and reliable operation of electric generation and transmission; (ii) open access to the transmission system, which would be regulated by the FERC; (iii) the continuation of a regulated distribution company to operate and maintain the distribution system; (iv) the deregulation of energy/customer services such as meter reading and customer billing; (v) the ability of customers to choose among suppliers of electricity; and (vi) the allowance of customers to acquire electricity either by long-term contracts, purchases on the spot market, or a combination of the two. One issue discussed in the Order that could affect the Company is strandable investments. The PSC stated in its Order that it is not required to allow recovery of all prudently-incurred investments, that it has considerable discretion to set rates that balance ratepayer and shareholder interests, and that the amount of strandable investments that a utility will be permitted to recover will depend on the particular circumstances of each utility. Additionally, the Order provided that every effort should be made by utilities to mitigate these costs prior to seeking recovery. Certain aspects of the restructuring envisioned by the PSC --particularly the PSC's apparent determinations that it may deny the utilities recovery of prudent investments made on behalf of the public, order retail wheeling, require divestiture of generation assets, and deregulate certain sectors of the energy market -- could, if implemented, have a negative impact on the operations and financial conditions of New York's investor-owned electric utilities, including the Company. The Company is party to a lawsuit commenced in September 1996 by the Energy Association of New York State and the state's other investor-owned electric utilities (collectively, Petitioners) against the PSC in New York Supreme Court, Albany County (The Energy Association of New York State, et al. v. Public Service Commission of the State of New York, et al.). The Petitioners have requested that the Court declare that the Order is unlawful or, in the alternative, that the Court clarify that the PSC's statements in the Order constitute simply a policy statement with no binding legal effect. In November 1996, the Court issued a Decision and Order denying the Petitioners' request to invalidate the Order. Although the Court stated that most of the Order is a non-binding statement of policy, the Court rejected the Petitioners' substantive challenges to the Order. In December 1996, the Petitioners filed a notice of appeal with the Third Department of the Appellate Division of the New York State Supreme Court. The litigation is ongoing and the Company is unable at this time to predict the likelihood of success or the impact of the litigation on the Company's financial position, cash flows or results of operations. At the request of the 87 Energy Association and Public Utility Law Project of New York (PULP), the Court has extended the time in which the Energy Association and PULP must perfect their appeals until July 6, 1998. The Electric Industry - Federal Regulatory Issues In April 1996, in response to its Notice of Proposed Rulemaking issued in March 1995, the FERC issued Orders 888 and 889 relating to the development of competitive wholesale electric markets. Order 888 is a final rule on open transmission access and stranded cost recovery and provides that the FERC has exclusive jurisdiction over interstate wholesale wheeling and that utility transmission systems must now be open to qualifying sellers and purchasers of power on a non-discriminatory basis. Order 888 allows utilities to recover legitimate, prudent and verifiable stranded costs associated with wholesale transmission, including the circumstances where full requirements customers become wholesale transmission customers, such as where a municipality establishes its own electric system. With respect to retail wheeling, the FERC concluded that it has jurisdiction over rates, terms and conditions of service, but would leave the issue of recovery of the costs stranded by retail wheeling to the states. Order 888 required utilities to file open access tariffs under which they would provide transmission services, comparable to those which they provide to themselves and to third parties on a non-discriminatory basis. Additionally, utilities must use these same tariffs for their own wholesale sales. Order 888-A, issued in March 1997, generally reaffirmed the FERC's basic determination in Order 888. One pertinent change made in 888-A, however, was that the FERC, as opposed to the states, will be the primary forum for determining stranded costs in cases involving municipal annexation. Order 888-B, issued November 1997, reaffirmed 888-A's findings. The Company filed its open access tariff in July 1996. In September 1996, the FERC ordered Rate Hearings on 28 utility transmission tariffs, including the Company's. On the basis of a preliminary review, the FERC was not satisfied that the tariff rates were just and reasonable. Settlement discussions have been held between the Company and various intervenors concerning the Company's transmission rates. In December 1996, the parties reached a tentative settlement on the rate issues. On May 14, 1997, the FERC approved the settlement agreement that the Company filed (with five other entities) concerning the rates for the Company's open access electric tariff. The effective date for those rates was July 9, 1996. The Company and four other New York utilities are seeking review of certain non-rate aspects of the FERC's open access transmission tariff orders in the U.S. Court of Appeals for the D.C. Circuit. Order 889, which is a final rule on a transmission pricing bulletin board, addresses the rules and technical standards for operation of an electronic bulletin board that will make available, on a real-time basis, the price, availability and other pertinent information concerning each transmission utility's services. It also addresses standards of conduct to ensure that transmission utilities functionally separate their transmission and wholesale power merchant functions to prevent discriminatory self-dealing. In December 1996, the Company filed its standards of conduct in accordance with the Order. Order 889-A and 889-B, issued in March and November 1997, respectively, generally reaffirmed and clarified the original Order 889. Order 889-A implemented new discounting policies and required that all negotiations between a transmission provider and a potential customer take place on the transmission pricing bulletin board and be visible to all. 88 It is not possible to predict the ultimate outcome of these proceedings, the timing thereof, or the amount, if any, of stranded costs that the Company would recover in a competitive environment. The outcome of the state and federal regulatory proceedings could adversely affect the Company's ability to apply SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation," which, pursuant to SFAS No. 101, "Accounting for Discontinuation of Application of SFAS No. 71," could then require a significant write-down of all or a portion of the Company's net regulatory assets. The Company's Service Territory The Company's geographic location and the limited electrical interconnections to Long Island serve to limit the accessibility of its transmission grid to potential competitors from off the system. However, the changing utility regulatory environment has affected the Company by requiring the Company to co-exist with state and federally mandated competitors, non-utility generators (NUGs). The Public Utility Regulatory Policies Act of 1978 (PURPA), the goals of which are to reduce the United States' dependency on foreign oil, to encourage energy conservation and to promote diversification of the fuel supply, has negatively impacted the Company through the encouragement of the NUG industry. The PURPA provides for the development of a new class of electric generators which rely on either cogeneration technology or alternate fuels. Utilities are obligated under the PURPA to purchase the output of certain of these generators, which are known as qualified facilities (QFs). For the years ended March 31, 1998 and 1997, the Company lost sales to NUGs totaling 447 and 422 gigawatt hours (GWh) representing a loss in electric revenues net of fuel (net revenues) of approximately $36 million and $34 million, respectively or 2.0% and 1.9% of the Company's net revenues, respectively. For the year ended December 31, 1996, the Company lost sales to NUGs totaling 422 GWh representing a loss in electric net revenues of approximately $34 million, or 1.9% of the Company's net revenues. For the year ended December 31, 1995, the Company lost sales to NUGs totaling 366 GWh or approximately $28 million or 1.5% of the Company's net revenues. The increase in lost net revenues resulted principally from the completion of seven facilities that became commercially operational during 1996 and the full year operation of the IPP located at the State University of New York at Stony Brook, NY. The Company estimates that in 1999 sales losses to NUGs will be 447 GWh, or approximately 1.8% of projected net revenues. The Company believes that load losses due to NUGs have stabilized. This belief is based on the fact that the Company's customer load characteristics, which lack a significant industrial base and related large thermal load, will mitigate load loss and thereby make cogeneration economically unattractive. Additionally, as mentioned above, the Company is required to purchase all the power offered by QFs, which for the years ended March 31, 1998 and 1997, approximated 220 megawatts (MW) and 226 MW, respectively. The Company estimates that purchases from QFs required by federal and state law cost the Company $71 million and $64 million in 1998 and 1997, respectively, more than it would have cost had the Company purchased the power in the open market or generated it. For the years ended December 31, 1996 and 1995, QFs offered approximately 218 MW and 205 MW, respectively. The Company estimates that purchases from QFs required by federal and state law cost the Company $63 million and $53 million for the years ended December 31, 1996 and 1995, respectively, more than it would have cost had the Company purchased the power in the open market or generated it. 89 QFs have the choice of pricing sales to the Company at either the PSC's published estimates of the Company's long-range avoided costs (LRAC) or the Company's tariff rates, which are modified from time to time, reflecting the Company's actual avoided costs. Additionally, until repealed in 1992, New York State law set a minimum price of six cents per kilowatt-hour (kWh) for utility purchases of power from certain categories of QFs, considerably above the Company's avoided cost. The six cent minimum continues to apply to contracts entered into before June 1992. The Company believes that the repeal of the six cent minimum, coupled with recent PSC updates which resulted in lower LRAC estimates, has significantly reduced the economic benefits of constructing new QFs within its service territory. The Company has also experienced a revenue loss as a result of its policy of voluntarily providing wheeling of New York Power Authority (NYPA) power for economic development. The Company estimates that for the years ended March 31, 1998 and 1997, NYPA power displaced approximately 373 GWh and 424 GWh of annual energy sales, respectively. Net revenue loss associated with these volumes of sales is approximately $23 million, or 1.2% of the Company's 1998 net revenues, and $27 million, or 1.5% of the Company's 1997 net revenues. Currently, the potential loss of additional load is limited by conditions in the Company's transmission agreements with NYPA. The Company estimates that for the years ended December 31, 1996 and 1995, NYPA power displaced approximately 417 GWh and 429 GWh of annual energy sales, respectively. Net revenue loss associated with these volumes of sales is approximately $26 million, or 1.4% of the Company's 1996 net revenues, and $30 million, or 1.6% of the Company's 1995 net revenues. A number of customer groups are seeking to hasten consideration and implementation of full retail competition. For example, an energy consultant has petitioned the PSC, seeking alternate sources of power for Long Island school districts. The County of Nassau has also petitioned the PSC to authorize retail wheeling for all classes of electric customers in the county. In addition, several towns and villages on Long Island are investigating municipalization, in which customers form a government-sponsored electric supply company. This is one form of competition that is likely to increase as a result of the National Energy Policy Act of 1992 (NEPA). NEPA sought to increase economic efficiency in the creation and distribution of power by relaxing restrictions on the entry of new competitors to the wholesale electric power market. NEPA does so by creating exempt wholesale generators that can sell power in wholesale markets without the regulatory constraint placed on utility generators such as on the Company. NEPA also expanded the FERC's authority to grant access to utility transmission systems to all parties who seek wholesale wheeling for wholesale competition. While it should be noted that the FERC's position favoring stranded cost recovery from retail turned wholesale customers will reduce utility risk from municipalization, significant issues associated with the removal of restrictions on wholesale transmission system access have yet to be resolved. There are numerous towns and villages in the Company's service territory that are considering the formation of a municipally-owned and operated electric authority to replace the services currently provided by the Company. In 1995, Suffolk County issued a request for proposal from suppliers for up to 300 MW of power which the County would then sell to its residential and commercial customers. The County has awarded the bid to two off-Long Island suppliers and has requested the Company to deliver the power. After the Company challenged Suffolk County's eligibility for such service, the County petitioned the FERC to order the Company to provide the requested transmission service. 90 In December 1996, the FERC ordered the Company to provide transmission services to Suffolk County to the extent necessary to accommodate proposed sales to customers to which it was providing service on the date of enactment of NEPA (this Order could provide Suffolk County with the ability to import up to 200 MW of power on a daily basis). The FERC reserved decision on the remaining 100 MW of Suffolk County's request until the County identifies the ownership or control of distribution facilities that it alleges qualifies it for a wheeling order to Suffolk County customers who were not receiving service on the date of NEPA's enactment. The Company may ask the FERC to reconsider its decision once that decision becomes final, which is not expected for several months. The Company and Suffolk County submitted briefs in July 1997 addressing the pricing for the 200 MW of power. The FERC has yet to determine the pricing of that service. As previously noted, FERC Order 888 allows utilities to recover legitimate, prudent and verifiable stranded costs associated with wholesale transmission, including the circumstances where full requirements customers become wholesale transmission customers, such as where a municipality establishes its own electric system. The matters discussed above involve substantial social, economic, legal, environmental and financial issues. The Company is opposed to any proposal that merely shifts costs from one group of customers to another, that fails to enhance the provision of least-cost, efficiently-generated electricity or that fails to provide the Company's shareowners with an adequate return on and recovery of their investment. The Company is unable to predict what action, if any, the PSC or the FERC may take regarding any of these matters, or the impact on the Company's financial position, cash flows or results of operations if some or all of these matters are approved or implemented by the appropriate regulatory authority. Notwithstanding the outcome of the state or federal regulatory proceedings, or any other state action, the Company believes that, among other obligations, the State has a contractual obligation to allow the Company to recover its Shoreham-related assets. Environmental Matters The Company is subject to federal, state and local laws and regulations dealing with air and water quality and other environmental matters. Environmental matters may expose the Company to potential liabilities which, in certain instances, may be imposed without regard to fault or for historical activities which were lawful at the time they occurred. The Company continually monitors its activities in order to determine the impact of its activities on the environment and to ensure compliance with various environmental laws. Except as set forth below, no material proceedings have been commenced or, to the knowledge of the Company, are contemplated against the Company with respect to any matter relating to the protection of the environment. The New York State Department of Environmental Conservation (DEC) has required the Company and other New York State utilities to investigate and, where necessary, remediate their former manufactured gas plant (MGP) sites. Currently, the Company is the owner of six pieces of property on which the Company or certain of its predecessor companies are believed to have produced manufactured gas. Operations at these facilities in the late 1800's and early 1900's may have resulted in the disposal of certain waste products on these sites. The Company has entered into discussions with the DEC which is expected to lead to the issuance of one or more ACOs regarding the management of environmental activities at these six properties. Although the exact amount of the Company's cleanup costs cannot yet be determined, based on the findings of preliminary investigations conducted at each of these six sites, current estimates indicate that it may cost approximately $54 to $92 million to investigate and remediate all of these sites. In considering the range of possible remediation estimates, the Company felt it appropriate to record a $54 million liability 91 reflecting the present value of the future stream of payments amounting to $70 million to investigate and remediate these sites. The Company used a risk-free rate of 6.0% to discount this obligation. The Company believes that the PSC will provide for future recovery of these costs and has recorded a $54 million regulatory asset. The Company's rate settlement which the PSC approved February 4, 1998 as discussed in Note 3 of Notes to Financial Statements, allows for the recovery of MGP expenditures from gas customers. In December 1996, the Company filed a complaint in the United States District Court for the Southern District of New York against 14 of the Company's insurers which issued general comprehensive liability (GCL) policies to the Company. In January 1998, the Company commenced a similar action against the same and certain additional insurer defendants in New York State Supreme Court, First Department; the federal court action was subsequently dismissed in March 1998. The Company is seeking recovery under the GCL policies for the costs incurred to date and future costs associated with the clean-up of the Company's former manufactured gas plant (MGP) sites and Superfund sites for which the Company has been named a PRP. The Company is seeking a declaratory judgment that the defendant insurers are bound by the terms of the GCL policies, subject to the stated coverage limits, to reimburse the Company for the clean up costs. The outcome of this proceeding cannot yet be determined. The Company has been notified by the United States Environmental Protection Agency (EPA) that it is one of many PRPs that may be liable for the remediation of three licensed treatment, storage and disposal sites to which the Company may have shipped waste products and which have subsequently become environmentally contaminated. At one site, located in Philadelphia, Pennsylvania, and operated by Metal Bank of America, the Company and nine other PRPs, all of which are public utilities, completed performance of a Remedial Investigation and Feasibility Study (RI/FS), which was conducted under an ACO with the EPA. In December 1997, the EPA issued its Record of Decision (ROD), setting forth the final remedial action selected for this site. In the ROD, the EPA estimated that the present cost of the selected remedy for the site is $17.3 million. At this time, the Company cannot predict with reasonable certainty the actual cost of the selected remedy, who will implement the remedy, or the cost, if any, to the Company. Under a PRP participation agreement, the Company previously was responsible for 8.2% of the costs associated with the RI/FS. The Company's allocable share of liability for the remediation activities has not yet been determined. The Company has recorded a liability of approximately $1 million representing its estimated share of the cost to remediate this site based upon its 8.2% responsibility under the RI/FS. The Company has also been named a PRP for disposal sites in Kansas City, Kansas, and Kansas City, Missouri. The two sites were used by a company named PCB, Inc. from 1982 until 1987 for the storage, processing, and treatment of electric equipment, dielectric oils and materials containing PCBs. According to the EPA, the buildings and certain soil areas outside the buildings are contaminated with PCBs. Certain of the PRPs, including the Company and several other utilities formed a PRP group, signed an ACO, and have developed a workplan for investigating environmental conditions at the sites. Documentation connecting the Company to the sites indicates that the Company was responsible for less than 1% of the materials that were shipped to the Missouri site. The EPA has not yet completed compiling the documents for the Kansas site. In addition, the Company was notified that it is a PRP at a Superfund site located in Farmingdale, New York. Industrial operations took place at this site for at least fifty years. The PRP group has claimed that the Company should absorb remediation expenses in the amount of approximately $100,000 associated with removing PCB-contaminated soils from a portion of the site which formerly contained electric transformers. The Company is currently unable to determine its share of costs of remediation at this site. 92 During 1996, the Connecticut Department of Environmental Protection (DEP) issued a modification to an ACO previously issued in connection with an investigation of an electric transmission cable located under the Long Island Sound (Sound Cable) that is jointly owned by the Company and the Connecticut Light and Power Company (Owners). The modified ACO requires the Owners to submit to the DEP and DEC a series of reports and studies describing cable system condition, operation and repair practices, alternatives for cable improvements or replacement and environmental impacts associated with leaks of fluid into the Long Island Sound, which have occurred from time to time. The Company continues to compile required information and coordinate the activities necessary to perform these studies and, at the present time, is unable to determine the costs it will incur to complete the requirements of the modified ACO or to comply with any additional requirements. The Owners have also entered into an ACO with the DEC as a result of leaks of dielectric fluid from the Sound Cable. The ACO formalizes the DEC's authority to participate in and separately approve the reports and studies being prepared pursuant to the ACO issued by the DEP. In addition, the ACO settles any DEC claim for natural resource damages in connection with historical releases of dielectric fluid from the Sound Cable. In October 1995, the U.S. Attorney for the District of Connecticut had commenced an investigation regarding occasional releases of fluid from the Sound Cable, as well as associated operating and maintenance practices. The Owners have provided the U.S. Attorney with all requested documentation. The Company believes that all activities associated with the response to occasional releases from the Sound Cable were consistent with legal and regulatory requirements. In December 1996, a barge, owned and operated by a third party, dropped anchor which then dragged over and damaged the Sound Cable, resulting in the release of dielectric fluid into Long Island Sound. Temporary clamps and leak abaters were installed on the cables to stop the leaks. Permanent repairs were completed in June 1997. The cost to repair the Sound Cable was approximately $17.8 million, for which there was $15 million of insurance coverage. The Owners filed a claim and answer in response to the maritime limitation proceeding instituted by the barge owner in the United States District Court, Eastern District of New York. The claim seeks recovery of the amounts paid by insurance carriers and recovery of the costs incurred for which there was no insurance coverage. Any costs to repair the Sound Cable which are not reimbursed by a third party or covered by insurance will be shared equally by the Owners. The Company believes that none of the environmental matters, discussed above, will have a material adverse impact on the Company's financial position, cash flows or results of operations. In addition, the Company believes that all significant costs incurred with respect to environmental investigation and remediation activities, not recoverable from insurance carriers, will be recoverable through rates. 93 Note 13. Business Segments Identifiable assets by segment include net utility plant, regulatory assets, materials and supplies, accrued unbilled revenues, gas in storage, fuel and deferred charges. Assets utilized for overall Company operations consist primarily of cash and cash equivalents, accounts receivable, common net utility plant and unamortized cost of issuing securities.
(In millions of dollars) - -------------------------------------------------------------------------------------------------------------------------- Year Ended Three Months Ended Year Ended Year Ended March 31, 1998 March 31, 1997 December 31, 1996 December 31, 1995 - -------------------------------------------------------------------------------------------------------------------------- Operating revenues Electric $ 2,478 $ 558 $ 2,467 $ 2,484 Gas 646 293 684 591 ========================================================================================================================== Total $ 3,124 $ 851 $ 3,151 $ 3,075 ========================================================================================================================== Operating expenses (excludes federal income tax) Electric $ 1,595 $ 400 $ 1,644 $ 1,657 Gas 523 204 560 478 ========================================================================================================================== Total $ 2,118 $ 604 $ 2,204 $ 2,135 ========================================================================================================================== Operating income (before federal income tax) Electric $ 883 $ 158 $ 823 $ 827 Gas 123 89 124 113 ========================================================================================================================== Total operating income $ 1,006 $ 247 $ 947 $ 940 ========================================================================================================================== AFC $ (8) $ (2) $ (6) $ (7) Other income and deductions 10 (2) (23) (38) Interest charges 409 107 451 476 Federal income tax 233 56 209 206 ========================================================================================================================== Net Income $ 362 $ 88 $ 316 $ 303 ========================================================================================================================== Depreciation and Amortization Electric $ 131 $ 32 $ 129 $ 122 Gas 28 7 25 23 ========================================================================================================================== Total $ 159 $ 39 $ 154 $ 145 ========================================================================================================================== Construction and nuclear fuel expenditures* Electric $ 181 $ 35 $ 165 $ 162 Gas 80 16 78 84 ========================================================================================================================== Total $ 261 $ 51 $ 243 $ 246 ==========================================================================================================================
* Includes non-cash allowance for other funds used during construction and excludes Shoreham post-settlement costs.
- -------------------------------------------------------------------------------------------------------------------------- March 31, 1998 March 31, 1997 December 31, 1996 December 31, 1995 - -------------------------------------------------------------------------------------------------------------------------- Identifiable Assets Electric $ 9,553 $10,048 $9,835 $10,020 Gas 1,219 1,134 1,232 1,181 - -------------------------------------------------------------------------------------------------------------------------- Total Identifiable Assets 10,772 11,182 11,067 11,201 Assets Utilized for Overall Company Operations 1,129 668 1,143 1,326 ========================================================================================================================== Total Assets $11,901 $11,850 $12,210 $12,527 ==========================================================================================================================
94 Note 14. Disaggregated Condensed Balance Sheet (Unaudited) Set forth below is the Company's condensed balance sheet at March 31, 1998 which has been disaggregated pursuant to the terms of the LIPA Agreement to give effect to the proposed LIPA transaction as if it had occurred on March 31, 1998. The assets, capitalization and liabilities attributable to HoldCo Subsidiary represent the Company's transfer of its gas and generation business to such subsidiary. The assets, capitalization and liabilities attributable to LIPA represent those items that will be aqcquired or assumed by LIPA through its acquisition of the Company's common stock. All such amounts exclude the proceeds from the sale of common stock to LIPA. The disaggregated condensed balance sheet was prepared by management of the Company, and is subject to adjustment. For a further discussion of the LIPA Transaction, see Note 2.
(In millions of dollars) - ------------------------------------------------------------------------------------------------------------------------- ASSETS LILCO HoldCo Subsidiary LIPA - ------------------------------------------------------------------------------------------------------------------------- Total Net Utility Plant $3,814.1 $1,777.8 $2,036.3 - ------------------------------------------------------------------------------------------------------------------------- Regulatory Assets Shoreham related 4,661.1 4,661.1 Regulatory tax asset 1,737.9 21.0 1,716.9 Other 692.8 430.1 262.7 - ------------------------------------------------------------------------------------------------------------------------- Total Regulatory Assets 7,091.8 451.1 6,640.7 - ------------------------------------------------------------------------------------------------------------------------ Nonutility Property and Other Investments 50.8 32.9 17.9 Total Current Assets 858.3 494.2 364.1 Deferred Charges 85.7 38.0 47.7 - ------------------------------------------------------------------------------------------------------------------------- Total Assets $11,900.7 $2,794.0 $9,106.7 ========================================================================================================================= - ------------------------------------------------------------------------------------------------------------------------- CAPITALIZATION AND LIABILITIES - ------------------------------------------------------------------------------------------------------------------------- Long term debt, including current maturities $4,482.9 $1,130.5 $3,352.4 Preferred stock, including current maturities 702.0 363.0 339.0 Common Shareowner's Equity 2,662.5 161.7 2,500.8 - ------------------------------------------------------------------------------------------------------------------------- Total Capitalization $7,847.4 $1,655.2 $6,192.2 Regulatory Liabilities 389.4 1.6 365.2 Current Liabilities 587.4 433.0 154.4 Deferred Credits 2,608.8 211.2 2,397.6 Operating Reserves 467.7 470.4 (2.7) Commitments and Contingencies - - - - ------------------------------------------------------------------------------------------------------------------------- Total Capitalization and Liabilities $11,900.7 $2,794.0 $9,106.7 =========================================================================================================================
95 Note 15. Quarterly Financial Information (Unaudited) Summarized quarterly financial data for 1998, 1997 and 1996 is as follows:
(In thousands of dollars except earnings per common share) - ---------------------------------------------------------------------------------------------------------------------------- Fiscal Year Ended March 31, 1998 ----------------------------------------------------------------------------- 3 Months Ended 3/31/97 6/30/97 9/30/97 12/31/97 3/31/98 - ---------------------------------------------------------------------------------------------------------------------------- Operating Revenues $851,182 $664,488 $852,408 $779,622 $827,576 Operating Income 190,001 144,079 242,611 171,969 209,637 Net Income 87,697 45,161 144,384 56,756 115,939 Earnings for common stock 74,728 32,193 131,435 43,807 102,992 Basic and diluted earnings per common share .62 .26 1.09 .36 .85 - ----------------------------------------------------------------------------------------------------------------------------
- ---------------------------------------------------------------------------------------------------------------------------- Calendar Year Ended December 31, 1996 ------------------------------------------------------------------ 3 Months Ended 3/31/96 6/30/96 9/30/96 12/31/96 - ---------------------------------------------------------------------------------------------------------------------------- Operating Revenues $864,214 $694,602 $849,775 $742,104 Operating Income 190,421 141,065 235,402 169,693 Net Income 81,753 40,524 130,023 64,164 Earnings for common stock 68,682 27,453 116,972 51,141 Basic and diluted earnings per common share .57 .23 .97 .43 - ----------------------------------------------------------------------------------------------------------------------------
Report of Ernst & Young LLP, Independent Auditors To the Shareowners and Board of Directors of Long Island Lighting Company We have audited the accompanying balance sheet of Long Island Lighting Company and the related statement of capitalization as of March 31, 1998 and 1997, and December 31, 1996 and the related statements of income, retained earnings and cash flows for the year ended March 31, 1998, the transition period from January 1, 1997 to March 31, 1997 and each of the two years in the period ended December 31, 1996. Our audits also included the financial statement schedule listed in the index at Item 14(a). These financial statements and schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits. We conducted our audits in accordance with generally accepted auditing standards. Those standards 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. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Long Island Lighting Company at March 31, 1998 and 1997, and December 31, 1996, and the results of its operations and its cash flows for the year ended March 31, 1998, the transition period from January 1, 1997 to March 31, 1997 and each of the two years in the period ended December 31, 1996, in conformity with generally accepted accounting principles. Also, in our opinion, the related finacial statement schedule, whe considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein. As dicussed in Note 1 to the financial statements, during the year ended March 31, 1998 the Company changed its method of accounting for revenues provided for under the Rate Moderation Component. Melville, New York May 22, 1998 96 Item 9. Changes In And Disagreements With Accountants On Accounting And Financial Disclosures Not applicable. 97 PART III Item 10. Directors and Executive Officers of the Company Directors of the Company All Directors are elected annually. Current information regarding the Company's Directors follows: William J. Catacosinos: Chairman of the Board of Directors and Chief Executive Officer ("CEO") of LILCO since January 1984 and a Director since 1978; President of LILCO from March 1984 to January 1987 and from March 1994 to December 1996. Dr. Catacosinos, 68, is a resident of Mill Neck, Long Island. Received bachelor of science degree, masters degree in business administration and a doctoral degree in economics from New York University. Member, boards of Atlantic Bank of New York; Long Island Association; Empire State Business Alliance; and a member of the Advisory Committee of the Huntington Township Chamber Foundation. Former chairman and chief executive officer of Applied Digital Data Systems, Inc., Hauppauge, New York; chairman of the board and treasurer of Corometric Systems, Inc. of Wallingford, Connecticut; and assistant director at Brookhaven National Laboratory, Upton, New York. John H. Talmage: Director of LILCO since 1982. Graduate of the College of Agriculture and Life Sciences, Cornell University, Mr. Talmage is 68. President since 1992 and director since 1960, Friar's Head Farm, Inc.; Chairman, board of directors, H.P. Hood, Inc. of Boston, Massachusetts, 1980 to 1995; partner, HR Talmage & Son Farm 1954 to present; director, Agway, Inc., 1967 to 1995; Curtice Burns Foods, Inc., 1969 to 1984; and Suffolk County Federal Savings and Loan Association, 1975 to 1982. Basil A. Paterson: Director of LILCO since 1983. Received juris doctorate from St. John's University School of Law. Served as Secretary of State of New York from 1979 to 1982, as Deputy Mayor of New York City, as a New York State Senator and as a commissioner of the Port Authority of New York and New Jersey. Mr. Paterson, 72, is a partner in the law firm of Meyer, Suozzi, English and Klein, P.C., Mineola, New York. Served as a professor at a number of universities, as a member of the board of editors of the New York Law Journal and as a member of the State of New York Commission on Judicial Nomination. George Bugliarello: Director of LILCO since 1990. Received doctor of science degree in engineering from Massachusetts Institute of Technology and several honorary degrees from other institutions. Dr. Bugliarello, 71, served as President of Polytechnic University from 1973 to July 1994, and presently holds the position of Chancellor. Member, board of directors of the Lord Corporation, Symbol Technologies, Comtech Telecommunications Corp., the Teagle Foundation, the Jura Corp., the Greenwall Foundation and Spectrum Information Technologies, Inc., and the ANSER Corporation. Member of the Council on Foreign Relations and National Academy of Engineering. Fellow, the American Society of Civil Engineers, the American Association for the Advancement of Science and the New York Academy of Medicine; Founding Fellow, the American Institute of Medical and Biological Engineering. Previously held a NATO Senior Faculty Fellowship at the Technical University of Berlin and the chairmanship on the 98 Committee on Science, Engineering and Public Policy of the American Association for the Advancement of Science and of the Board on Infrastructure and Constructed Environment, National Research Council. Former member of the Scientific Committee of the Summer School on Environmental Dynamics in Venice. George J. Sideris: Director of LILCO since 1991. Received bachelors degree in economics from New York University. Mr. Sideris, 71, joined LILCO in 1984 as Vice President of Finance and Chief Financial Officer. Became Senior Vice President of Finance in 1987 and retired in January 1992. Member, board of directors of Utilities Mutual Insurance Company through December 1994. Self-employed as a management and financial consultant, 1981-1984. Previously served as a vice president of Qualpeco Services, Inc., and as a vice president and chairman of the Northeast Operations Group of U.S. Industries, Inc. A. James Barnes: Director of LILCO since 1992. Received undergraduate degree from Michigan State University and juris doctorate from Harvard Law School. Mr. Barnes, 56, served as General Counsel of the U.S. Department of Agriculture from 1981 to 1983, as General Counsel of the U.S. Environmental Protection Agency from 1983 to 1984 and as Deputy Administrator of the Agency from 1985 to 1988. Previously was a partner in the law firm of Beveridge, Fairbanks and Diamond, Washington, D.C. and also served with the U.S. Department of Justice. Joined the Indiana University School of Public and Environmental Affairs as its Dean in 1988. Currently serving as a member of the Board of Trustees of the National Institute for Global Environmental Change. Richard L. Schmalensee: Director of LILCO since 1992. Received doctoral degree in economics and bachelor of science degree in economics, politics and science from the Massachusetts Institute of Technology ("MIT"). Gordon Y. Billard Professor of Economics and Management at MIT's Sloan School since 1988. Served as member of the President's Council of Economic Advisors from 1989 to 1991. Currently, Deputy Dean of the MIT Sloan School of Management and Director of the MIT Center for Energy and Environmental Policy Research. Dr. Schmalensee, 54, is a consultant to a variety of government agencies and private firms through the National Economic Research Associates Inc. on a range of issues including aspects of utility regulation. Renso L. Caporali: Director of LILCO since 1992. Received doctorate and two masters degrees in Aeronautical Engineering from Princeton University and a masters of mechanical engineering degree and bachelor of civil engineering degree from Clarkson College of Technology. Dr. Caporali, 65, served as President of Grumman Corporation's Aircraft Systems Division since 1985, Vice Chairman of Corporate Technology 1988 to 1990 and Chairman and CEO from 1990 to June 1994. Consultant to and member of the board of directors of Northrop-Grumman from June 1994 to March 1995. Serves on a Princeton University Advisory Council. Former Chairman of the Aerospace Industries Association's Board of Governors and Executive Committee. Presently corporate Senior Vice President of Engineering and Business Development for the Raytheon Company. Member of the National Academy of Engineering. Katherine D. Ortega: Director of LILCO since 1993. Received bachelor of arts degree in business and economics from Eastern New Mexico University and three honorary doctor of law 99 degrees and an honorary doctor of social science degree. Ms. Ortega, 63, served as Treasurer of the United States from 1983 to 1989. Served as a commissioner of the Copyright Royalty Tribunal, a member of the President's Advisory Committee on Small and Minority Business and an alternate representative to the United Nations General Assembly. Member of the board of directors of Ultramar Diamond Shamrock Corporation, The Kroger Company, Ralston Purina Company, Rayonier Inc. and Catalyst. Member of the Comptroller General's Consultant Panel. Advisory Board Member of Washington Mutual Investors Fund. Vicki L. Fuller: Director of LILCO since 1994. Received bachelors degree at Roosevelt University and masters degree in business administration at the University of Chicago and is a Certified Public Accountant. Ms. Fuller, 41, served as an associate in Morgan Stanley and Co.'s corporate finance department from 1981 to 1983. Served as a rating officer at Standard & Poor's Corporation from 1984 to 1985. Joined Equitable Capital Management Corporation ("ECM") in 1985 as a senior investment manager, holding various positions including Managing Director from 1989 to 1993. Vice President of Alliance Capital Management Corporation ("Alliance"), which acquired ECM, from 1993 to 1994; currently holds the position of Senior Vice President of Alliance. In compliance with Section 305(b) of the Federal Power Act, Ms. Fuller has authorization to hold the position of an officer or director of a public utility and at the same time the position of an officer or director of a firm that is authorized to underwrite or participate in the marketing of the securities of a public utility. James T. Flynn: Appointed by the Board of Directors, Mr. Flynn became a Director in December 1996. Holds a bachelor of science degree in mechanical engineering from Bucknell University and is a Licensed Professional Engineer. Joined LILCO in October 1986 as Vice President of Fossil Production and was promoted to Group Vice President, Engineering and Operations in April 1992. Appointed Executive Vice President and Chief Operating Officer in March 1994. Mr. Flynn, 64, has served as President and Chief Operating Officer since December 1996. Executive Officers of the Company Information required by Item 10 as to the Company's Executive Officers is set forth in Item 1, "Business" under the heading "Executive Officers of the Company" above. Compliance with Section 16(a) of the Exchange Act LILCO is required to identify any Director, Officer, or person who owns more than ten percent of a class of equity securities who failed to timely file with the Securities and Exchange Commission (the "SEC") a required report relating to ownership and changes in ownership of LILCO's equity securities. Based on information provided to LILCO by such persons, all LILCO Officers and Directors made all required filings during the fiscal year ended March 31, 1998. LILCO does not know of any person beneficially owning more than 10% of a class of equity securities. 100 Item 11. Executive Compensation Compensation Paid to Directors The annual retainer fee paid to each Director during the prior fiscal year was $12,500 in cash and $12,500 applied to a deferred stock unit account, except for Dr. Catacosinos and Mr. Flynn who, as Officers of LILCO, do not receive compensation for serving as Directors. The fee paid to each Director who is not also an Officer of LILCO for attending each meeting of the Board of Directors or of one of its committees was $500. Under the terms of the Directors' Stock Unit Retainer Plan (the "Retainer Plan"), each non-employee director of LILCO is required to apply at least 50% of his or her annual retainer to the purchase of Common Stock units ("Stock Units"). Allocation of Stock Units under the Retainer Plan are made automatically on the date during each fiscal quarter on which the quarterly installment of the annual retainer is paid. Under the Retainer Plan, the value of the units which will be credited to each non-employee Director's account on a quarterly basis will be determined by dividing the aggregate amount of cash credited to such account by the closing price per share of LILCO Common Stock, as reported on a New York Stock Exchange listing of composite transactions, on the first trading day of the calendar month in which the Participant's retainer is paid. The amounts accumulated pursuant to the Retainer Plan will be held until such time as (i) a participant ceases to serve as a Director or Consulting Director; (ii) a participant's death; or (iii) a "Change in Control" (as defined in the Retainer Plan). If the Director so elects, the aggregate value of the Stock Units accumulated pursuant to the Retainer Plan may be received in certificated shares of LILCO Common Stock at the time of distribution. The Director may elect to receive a distribution of Retainer Plan benefits in a lump sum or in ten annual installments. Any such shares shall be purchased by LILCO on the open market or shall be taken from shares of Common Stock previously acquired by LILCO and held in its treasury. Prior to distribution, a Director shall have no voting or other rights of a shareholder with respect to such Stock Units. However, each Director's account will be credited with an amount equal to the amount of any dividends paid on shares of LILCO Common Stock proportionate to the number of Stock Units accumulated pursuant to the Retainer Plan prior to such dividend payment date. Amounts so credited shall be applied toward the purchase of an additional number of Stock Units. The transactions contemplated with KeySpan and/or LIPA will result in a Change in Control for purposes of the Retainer Plan. LILCO has entered into a consulting agreement with Eben W. Pyne, a former Director of LILCO, naming him Consulting Director. This agreement provides that the Consulting Director will advise and counsel the Board and any of its committees on various matters and will receive an annual retainer of $25,000 (half of which was credited to a deferred stock unit account pursuant to the Retainer Plan as discussed above) plus an additional $500 for each Board or committee meeting attended. A Consulting Director does not have the right to vote at meetings of the Board or at meetings of committees of the Board. Directors may elect to defer the receipt of any portion of their compensation under the Deferred Compensation Plan for Directors. Amounts deferred may be allocated to a deferred 101 compensation account. Each participating Director's account accrues interest, compounded quarterly, at the prime rates plus 1/2%. The Deferred Compensation Plan for Directors is unfunded and any accounts under the plan will be general obligations of LILCO. Distributions from a deferred compensation account commence upon termination of membership on the Board of Directors, death or disability, or at a date previously designed by the participating Director. Distributions from the deferred compensation account may be made by lump-sum payment or annually over either a five or ten-year period. Currently none of the Directors are participating in the Deferred Compensation Plan for Directors. The Deferred Compensation will be terminated immediately prior to the completion of the transactions contemplated with KeySpan and/or LIPA. LILCO has a Retirement Plan for Directors (the "Retirement Plan"), providing benefits to Directors who are not or who have not been Officers of LILCO. Directors who have served in that capacity for more than five years qualify as participants under the plan. The plan provides for a monthly benefit equal to one-twelfth of the highest annual retainer paid to each participant. A full benefit is available for participants who serve for ten years with a reduction of one-sixtieth for each month of service less than ten years. Under the plan, payment of benefits is to begin when the Director ceases to serve as a Director or Consulting Director or reaches age 65, whichever is later. The plan also provides that in the event of a "change in control" (as defined in the Retirement Plan), including by virtue of an acquisition of LILCO's assets or stock, the value of vested benefits could be payable immediately. In addition to Directors Barnes, Bugliarello, Caporali, Ortega and Schmalensee who would be entitled to be paid a reduced benefit, Directors Paterson, Talmage and Pyne would be entitled to be paid full benefits were they to cease to serve as a Consulting Director or Director at this time. Benefits are provided on a straight-life annuity basis except that if the Director is married at the time benefits begin, a joint and 50% survivor benefit may be paid on an actuarially equivalent basis. The benefits are unfunded and are general obligations of LILCO. The transactions contemplated with KeySpan and/or LIPA will result in a Change in Control for purposes of the Retirement Plan and such Retirement Plan will be terminated immediately prior to the close of these transactions. LILCO entered into an agreement in 1987 with Mr. Sideris, while he was an Officer of LILCO, which provides retirement benefits supplementing the benefits to which he is entitled under LILCO's Retirement Income Plan and Supplemental Death and Retirement Benefits Plan, both discussed below. LILCO has established a trust, which is currently making payment of the retirement benefits. Notwithstanding the creation of the trust, LILCO continues to be primarily liable. Pursuant to the New York Business Corporation Law and LILCO By-laws, LILCO has entered into agreements with its Directors and Officers providing for indemnification and advancement of expenses in defending certain actions or proceedings in advance of their final disposition subject to refund if they are found not to be entitled to indemnification. LILCO has established a trust, the Long Island Lighting Company Officers' and Directors' Protective Trust, to fund LILCO's obligations under these agreements. 102 Report of the Compensation and Management Appraisal Committee on Executive Compensation The disclosure contained in this section of the Form 10-K shall not be deemed incorporated by reference into any prior filing by LILCO pursuant to the Securities Act of 1933 or the Securities Exchange Act of 1934 that incorporate future filings or portions thereof (including this Form 10-K or any amendment or any part thereof). The Compensation and Management Appraisal Committee (the "Committee"), which establishes the procedures by which management compensation is determined, reviews and recommends to the Board of Directors the compensation levels of LILCO's officers and administers the Annual Stock Incentive Compensation Plan (the "Annual Stock Incentive Plan") and the Long-Term Incentive Plan (the "Long-Term Incentive Plan") discussed below. The Committee is made up entirely of outside Directors. Its members are George Bugliarello, A. James Barnes, Richard L. Schmalensee and John H. Talmage. During 1997, the Committee used two outside consultants, the Hay Group ("Hay") and William M. Mercer, Inc. ("Mercer"), to review the compensation levels of LILCO's officers, including the named executive officers, and to provide advice with respect to incentive compensation arrangements. LILCO's Human Resources office also supplied industry compensation comparisons. Executive Compensation Philosophy It is the Board's philosophy to use incentives and other variable performance-based pay programs to link executive pay with enhancements to LILCO performance and customer service and to ensure the attraction, retention and motivation of key executives. In order to keep pace with industry practice and accomplish these objectives, the Board adopted the Annual Stock Incentive Program in 1995 and adopted the Long-Term Incentive Program in 1996. Both incentive programs have been approved by common stock shareholders. This performance-based compensation philosophy places a significant emphasis on the achievement of strategic goals related to financial and customer service performance. However, even after the adoption of the Annual and Long-Term Incentive Plans, data provided to the Committee by Hay and Mercer indicate that LILCO's officer total compensation opportunities remains significantly below all competitive market segments, including other comparable electric utilities, as described below. Determination of Base Salary Levels In 1997, the Committee considered adjustments to base salary ranges using the external comparisons to other utility and non-utility companies as described below. Specifically, the Committee studied the average compensation levels of comparable executives of three databases provided by Hay for general industry, metropolitan New York companies and 15 electric and gas stock-issuing utilities. For CEO compensation, Hay also provided comparisons to 37 Standard & Poor's Utilities. In addition to compensation levels among the Hay databases, the Committee also reviewed the results of the Edison Electric Institute's Annual Compensation Survey of 85 utilities (the "EEI Utilities") as well as the compensation paid to the officers of ten other regional utilities. Based on these comparisons and the recommendation of Hay, the Board adopted a 103 philosophy to target base salary ranges at the median of general industry in the metropolitan New York area. Individual base salary increases within those ranges are then subjectively determined based on several factors. These factors include the competitiveness of the executive's current base salary and potential incentive compensation, the executive's individual accomplishments during the year and the executive's length of time in his or her position. However, based on data provided by Hay in December 1997, LILCO base salaries were 4.2 percent below general industry, 11.7 percent below metropolitan New York companies and 9.7 percent below the Hay utility group. The Annual Stock Incentive Compensation Plan Annual incentive compensation is earned under LILCO's Annual Stock Incentive Plan. This Plan was adopted in 1995 and approved by shareholders at the 1997 Annual Meeting. Awards earned under the Plan, less applicable tax withholding, are paid in common stock. By making the awards payable in LILCO common stock, officers' performance is more closely aligned with shareholder interest. At the end of 1997, the Board altered its policy of paying awards in the calendar year following the year in which they were earned to a policy of paying awards at the end of the year in which they were earned. Therefore, officers received payment in stock for the performance achieved in 1997 at the end of December 1997. In addition, officers received payment at that time of awards for performance earned in 1996. The Annual Stock Incentive Plan is based on the achievement of two quantifiable objectives: reducing expenditures and maintaining or improving critical service goals. If threshold levels are not achieved for either objective, no incentive is earned. As threshold levels are exceeded, the officers become eligible to receive awards from the Annual Stock Incentive Plan. For 1998, target incentive awards - the amounts earned if goal performance levels are attained for all program objectives - are 60% for the CEO, 50% for the COO, 35% for senior officers and 20% for other officers, of the greater of their base salary or the midpoint of the base salary range for each participant. For 1997, target incentive awards were 45% for the CEO, 30% for the COO, 20% for senior officers and 15% for other officers. For 1996, target incentive awards were 45% for the CEO, 25% for the COO, 15% for senior officers and 10% for other officers. The midpoint for the base salary range is dependent upon the executive's level in the organization. Seventy-five percent of each individual's earned incentive award is based on the level of achievement of the two corporate objectives. The balance of each award, which can range from zero to 50 percent of the earned incentive award, is then subjectively determined by the Committee based on each individual's contribution toward helping LILCO achieve its objectives. Based on the level of achievement for the increase in net cash flow and service goals, and individual contributions to LILCO, awards under the Annual Stock Incentive Plan paid in 1997 for plan year 1997 and 1996 ranged from 75 to 112 percent and from 75 to 124 percent, respectively, of each individual's earned incentive award. As a result of the closing of the KeySpan Transaction at the end of May 1998, both KeySpan and LILCO terminated their Annual Incentive Plans. LILCO pro-rated its target goals so that 5/12ths of the earned incentive was made based on the results achieved to date. For 1998, all participants were paid 100 percent of their pro-rated individual earned incentive. 104 The Officer Long-term Incentive Plan In December 1995, LILCO's Board of Directors adopted, and at the 1996 Annual Meeting the shareholders approved, the Long-Term Incentive Plan. The purpose of the Long-Term Incentive Plan is to motivate the Officers to meet or exceed LILCO's business goals, with a particular focus on the long-term effects of their actions, and to provide incentives for continued service to LILCO. Awards made under the Long-Term Incentive Plan are paid only upon the attainment of financial performance goals or goals set by the Committee. The first Performance Period was for two years (1996-1997) and the goals included freezing rates, improving earnings and reducing operating and maintenance expenditures. Subsequent Performance Periods were to include goals to be attained over the period of three calendar years, with a new cycle beginning every two years (the "Performance Period"). Awards are paid for the attainment of specified threshold, target and maximum results over the Performance Period and are a specified percentage per year of the greater of the participant's base salary or midpoint of that individual participant's salary range. For the 1996-1997 Performance Period, the maximum award of 125% of each participants target incentive award was earned. Originally, the Plan was designed so that the awards would be paid in two installments, each of which could be paid in shares of Common Stock. However, following the completion of the first cycle at the end of 1997 and due to the anticipated closing of the KeySpan Transaction during 1998, the Board determined to award the full amounts for the 1996-97 cycle to all officers. In addition, similar to the Annual Stock Incentive Plan and as a result of the closing of the KeySpan Transaction at the end of May 1998, both KeySpan and LILCO terminated their Long-Term Incentive Plans. LILCO pro-rated its target goals so that 17/36ths of the earned incentive award for the 1997-99 Performance Period was made. All goals for this period achieved their maximum levels and, thus, 125% of each participant's target incentive award was earned. Special Performance Incentives During 1997, the Board authorized special performance incentives to seven officers, including four of the named officers in the Compensation table, in recognition of the efforts of these individuals in connection with the KeySpan Transaction and the LIPA Transaction. The amount of the awards were paid in shares of common stock, net of appropriate employment tax withholdings, and were based on a percentage of the greater of base salary or the midpoint of the base salary range for each participant. Awards related to the LIPA Transaction ranged from 5 percent to 20 percent, and for the KeySpan Transaction ranged from 5 percent to 25 percent, based on each individual's contribution and involvement in one or both of the transactions. Transaction-Related Actions In order to reduce the risk of loosing key executives during the critical period of planning for the consummation of the KeySpan Transaction and LIPA Transactions, the Company entered into Retention Agreements with eligible officers, except the CEO and COO, for a one-year period commencing July 1997. These Agreements provided an incentive of 20 percent of the greater of 105 each participant's base salary or the midpoint of the base salary range for continued employment throughout the period of the Agreement. In addition, payments were made of benefits previously accrued by executives under plans and programs which are not to be continued by the new combined entity. Finally, because the payments of the pro-rated 1998 Annual Incentive and the 1997-1999 Long-term Incentive were made immediately prior to the closing of the two transactions, these awards were authorized to be paid in cash rather than stock for administrative simplicity prior to the share exchange and delisting of LILCO's Common Stock. CEO Compensation Coming into 1997, Dr. Catacosinos' base salary had been held at its March 1995 level in order to transition to incentive-based compensation through the introduction of the Annual Stock and Long-Term Incentive Plans. Therefore, during 1997, the Board twice, in January and in December, considered Dr. Catacosinos' base salary level. Each time the Board considered the competitive market, Dr. Catacosinos's tenure as CEO and the performance factors described below. Based on these factors, Dr. Catacosinos' base salary was increased by 14 percent in February 1997 and by 5.7 percent in December 1997. In authorizing the February increase in base salary for Dr. Catacosinos, the Board considered the Company's performance during 1996. Throughout 1996, the Company continued to pursue its aggressive program to contain operating and maintenance expenses as well as capital expenses. As a result, budget targets were underrun by 5.6 percent and earnings increased by 4 cents per share. In addition, positive net cash flow of $241 million was achieved and the Company was able to use $415 million of cash to satisfy its obligation regarding G&R bonds that matured. The debt to equity ratio continued to improve, dropping from 61.8 to 59.3 percent. In addition, at the end of 1996 the Company had successfully negotiated a merger agreement with Brooklyn Union that is expected to result in significant synergy savings to the combined entity and enhance such entity's competitive position. In authorizing the December increase in base salary for Dr. Catacosinos, the Board considered the Company's performance and achievements during 1997. Notably in 1997, the Company negotiated the LIPA Transaction that would enable electric rates to be reduced by approximately 20 percent and included the purchase by LIPA, in a stock transaction, of the electric transmission and distribution system, the Company's 18 percent interest in the Nine Mile Point 2 nuclear plant and the Company's electric regulatory assets. In addition during 1997, while planning for the consummation of the KeySpan Transaction and LIPA Transaction, the Company was also able to achieve significant financial results. Specifically, earnings per share increased by 13 cents per share. Net cash flow of $187 million was achieved. The Company was able to use cash to redeem $252 million of maturing debt, reducing the debt to equity ratio to 57.5 percent. In making its determination with respect to Dr. Catacosinos' Annual Stock Incentive Plan award for plan year 1996, the Board considered, among other things, the level of achievement of the budget and service goals in accordance with the Annual Stock Incentive Plan and the period of 106 time from the earning of the incentive to the granting of the award. Based on these achievements, the Board approved an incentive award for Dr. Catacosinos of 10,535 shares of LILCO common stock. For 1997, based on the level of goal achievement, Dr. Catacosinos was awarded 8,351 shares of common stock. Awards of shares of common stock for 1996 and 1997 were net of the appropriate income and employment taxes. For the 1998 pro-rated incentive, Dr. Catacosinos was granted an award of $218,750. With respect to Dr. Catacosinos' 1996-97 Long-term Incentive, based on the results achieved, the Board granted an award of 17,164 shares of Common Stock, net of appropriate income and employment taxes. For the 1997-99 pro-rated Performance Period, an award of $743,750 was granted based on the results achieved. Hay's market comparisons in 1997 showed that Dr. Catacosinos' total direct compensation was 21.5 percent below general industry, 25.3 percent below metropolitan New York companies and 27.4 below the Hay utility group. However, by establishing direct links between performance and both direct and long-term compensation, the Committee believes that LILCO's compensation programs properly align management's interests with the long-term interests of ratepayers and shareholders. Certain Tax Matters Generally, Section 162(m) of the Internal Revenue Code of 1986, as amended limits tax deductions for executive compensation to $1 million. However, since LILCO will have no publicly traded equity securities at the end of its 1998 tax year, Section 162(m) does not apply. George Bugliarello -- Chairman John H. Talmage A. James Barnes Richard L. Schmalensee Stock Performance Graph Set forth below is a graph comparing the cumulative return of LILCO, the Standard & Poor's 500 Composite Stock Index ("S&P 500") and the S&P Electric Utilities Index ("S&P ELEC") over the preceding five fiscal years commencing with fiscal year ended March 31, 1993. The graph assumes a $100 initial investment on March 31, 1993, and a reinvestment of dividends in LILCO and each of the companies reported in the indices. LILCO S&P 500 S&P ELEC 1993 $ 100 $ 100 $ 100 1994 84 101 90 1995 63 117 93 1996 85 155 113 1997 127 186 112 1998 177 275 155 107 PRIVILEGED AND CONFIDENTIAL ATTORNEY-CLIENT COMMUNICATION Compensation Paid to Executive Officers Summary Compensation Table: In March 1997, the Board of Directors voted to change the Company's fiscal year end from December 31 to March 31 effective with the three month period ended March 31, 1997 (the "Transition Period"). Accordingly, the following table illustrates the compensation paid by LILCO to each of its most highly compensated Executive Officers for the fiscal year ended March 31, 1998 and for the fiscal years ended December 31, 1996 and 1995. Also included is certain compensation earned during fiscal 1998.
Annual Compensation Long Term Compensation - ----------------------------------------------------------------------------------------------------------------------------------- Other Restricted Payouts- Annual Stock Options/ LTIP All Other Name and Principal Salary Bonus Compensation Award(s)($) SARs (#) Payouts Compensation Position Year ($)(1)(2) ($)(3) ($) ($)(4) ($)(5) - ----------------------------------------------------------------------------------------------------------------------------------- William J. Catacosinos - 1997/98 673,333(6) 1,202,972 n/a n/a n/a 742,500 23,241 CEO 1996 580,413(6) 153,203 n/a n/a n/a n/a 18,653 1995 587,976(6) 0 n/a n/a n/a n/a 15,184 - ----------------------------------------------------------------------------------------------------------------------------------- James T. Flynn - COO and 1997/98 310,000 408,956 n/a n/a n/a 294,362 8,300 President 1996 263,364 90,554 n/a n/a n/a n/a 5,800 1995 255,500 0 n/a n/a n/a n/a 3,725 - ----------------------------------------------------------------------------------------------------------------------------------- Leonard P. Novello - 1997/98 258,335 211,458 n/a n/a n/a 125,000 1,753 Senior Vice President 1996 236,186 33,693 n/a n/a n/a n/a 1,410 and General Counsel 1995 176,250(7) 0 n/a n/a n/a n/a 883 - ----------------------------------------------------------------------------------------------------------------------------------- Michael E. Bray - 1997/98 254,334(8) 62,500 n/a n/a n/a 0 738 Senior Vice President - 1996 0 0 n/a n/a n/a n/a n/a Electric Business Unit 1995 0 0 n/a n/a n/a n/a n/a - ----------------------------------------------------------------------------------------------------------------------------------- Adam M. Madsen - 1997/98 198,666 133,945 n/a n/a n/a 96,196 833 Senior Vice President - 1996 172,166 15,826 n/a n/a n/a n/a 1,392 Corporate and Strategic 1995 162,000 0 n/a n/a n/a n/a 1,205 Planning =================================================================================================================================
* n/a - Not Applicable. 108 Notes to Summary Compensation Table: (1) During the Transition Period, Dr. Catacosinos, Mr. Flynn, Mr. Novello, and Mr. Madsen received salary payments of $133,234, $75,000, $62,083, $43,000, respectively. As discussed below, Mr. Bray was not an employee of the Company during the Transition Period. (2) LILCO has in place a 401(k) Capital Accumulation Plan, which qualifies for favorable tax treatment under the Internal Revenue Code of 1986, as amended. This plan is designed to provide for salary reduction contributions by participants under Section 401(k) of the Internal Revenue Code of 1986, as amended that permit employees to defer a portion of their current compensation and therefore a portion of their current federal and, in most instances, state and local income taxes. Although this plan allows LILCO to make matching contributions to these deferred amounts, no such matching contributions have been made to date. The amounts shown for annual salary in the Summary Compensation Table for each individual officer include amounts deferred by those individuals into this plan. (3) Represents (i) the dollar value of LILCO Common Stock awards under the Annual Stock Incentive Plan for plan years 1996 (other than for Mr. Bray) and 1997, including applicable tax withholdings and (ii) awards in connection with the LIPA and KeySpan transactions (other than for Mr. Bray). The net amount of these awards were primarily paid in shares of LILCO Common Stock as follows: Dr. Catacosinos - 27,081 shares, Mr. Flynn - 8,976 shares, Mr. Novello - 4,533 shares, Mr. Bray - 1,406 shares, and Mr. Madsen - 3,013 shares. For the 1998 plan year, pro rata amounts will be paid in cash immediately prior to completion of the transactions contemplated with KeySpan and LIPA as follows: Dr. Catacosinos - $218,750, Mr. Flynn - $109,354, Mr. Novello - $50,130, Mr. Bray - $48,998, and Mr. Madsen - $38,646. (4) Represents the dollar value of LILCO Common Stock awards under the Long Term Incentive Plan for plan years 1996-1997, including applicable tax withholdings. The net amount of the awards were paid in shares of LILCO Common Stock as follows: Dr. Catacosinos - 16,703, Mr. Flynn - 6,621, Mr. Novello - 2,812, Mr. Madsen - 2,164. For the 1998 plan year, pro rata amounts will be paid in cash immediately prior to completion of the transactions contemplated with KeySpan and LIPA as follows: Dr. Catacosinos - $743,150, Mr. Flynn - $371,803, Mr. Novello - $170,442, Mr. Bray - $166,593, and Mr. Madsen - $131,395. (5) LILCO has a noncontributory Supplemental Death and Retirement Benefits Plan for its Officers and certain other senior management employees. Currently, death benefits for the Chairman, CEO, President and Chief Operating Officer ("COO") are five times their plan compensation and, for each other Officer, three times their plan compensation. Compensation under this plan is defined as the highest salary including any incentive earned pursuant to the Annual Stock Incentive Plan. The cost of life insurance, paid by LILCO for coverage under this plan, is included in All Other Compensation for each of the individuals listed. For each year reflected in the Compensation Table, insurance coverage for these death benefits was provided by split-dollar life insurance policies on the life of each plan participant. The amount shown for each participant represents the amount allocated to such participant for income tax purposes. (6) A portion of Dr. Catacosinos' salary in each of these years has been deferred at his request and is reflected in the amounts shown. (7) Leonard P. Novello assumed duties as General Counsel effective April 1, 1995. Prior to that date, Mr. Novello was General Counsel for the public accounting firm of KPMG Peat Marwick. (8) Michael E. Bray assumed the duties of Senior Vice President - Electric Business Unit effective March 1, 1997. Prior to that date, Mr. Bray was President and CEO of DB Riley Consolidated. 109 Supplemental Death and Retirement Benefits Plan: Officers and certain other senior management employees eligible to participate in LILCO's Supplemental Death and Retirement Benefits Plan are provided with death benefits, generally funded by life insurance, equal to five times the plan compensation for the Chairman, CEO, President and COO and three times the plan compensation for each other Officer. "Plan compensation" is defined in this plan as the highest annual rate of pay consisting of (i) the highest rate of base pay in effect at any time and (ii) a single incentive benefit payment pursuant to the annual stock incentive plan. Prior to retirement, participants elect either to receive continued death benefit coverage or to receive monthly retirement benefits, a partial lump-sum distribution, or a combination of each. For a participant who retires on or after age 65 and elects the death benefit, the death benefit coverage will be continued up to five times plan compensation for the Chairman, CEO, President and COO and up to three times plan compensation for each Officer. For a participant who retires on or after age 65 and elects the monthly retirement income benefit, the annual retirement benefits payable under the 15-year certain option will be, for the Chairman, CEO, President and COO, 25% of plan compensation and, for each other Officer, 15% of such Officer's plan compensation, with other options available to make payment on an actuarially equivalent basis through a lifetime annuity, a joint and survivor annuity or an increasing income annuity. Retirement benefits under this plan are not available to participants who retire prior to age 60. A participant will vest upon the earlier of attainment of age 60 with ten years of service or upon attainment of his or her normal retirement date (i.e., age 65). If a vested participant retires prior to age 65, reduced benefits are payable. The terms of Dr. Catacosinos' employment agreement, discussed below, provide for his continued employment beyond normal retirement age. In contemplation of the consummation of the KeySpan transaction, the Board of Directors determined, for various reasons, to discontinue future participation in the plan and to make payments of the accrued retirement benefits under it. The projected annual pension assuming payment on May 28, 1998, pursuant to the Supplemental Death and Retirement Benefits Plan considering the Change of Control provisions in the Executive Employment Agreements with each officer, are as follows: Mr. Flynn, $125,444; Mr. Novello, $16,099; Mr. Bray, $2,658; and Mr. Madsen, $38,069. Accordingly, each officer received, pursuant to Board actions, a benefit representing the present value of the projected annual amounts earned. Pursuant to the terms of the plan, Dr. Catacosinos would be entitled to an annual retirement benefit, however, because Dr. Catacosinos has made an assignment of his rights to death benefits, he did not receive any retirement income benefits under this plan. LILCO recognized the cost of all benefits provided under the Plan, which were borne by LILCO's shareholders, as an expense on its income statement. LILCO has also established a trust to provide for payments of its obligations to retired participants in the Supplemental Death and Retirement Benefits Plan. Notwithstanding the creation of the trust, LILCO continues to be primarily liable for both the death and retirement benefits payable to the participants and is currently making payments to retired participants. Retirement Income Plan: Generally, all LILCO employees (except certain leased and part-time employees) are eligible for inclusion in the Retirement Income Plan upon completion of one year 110 of employment with LILCO. A participant will vest upon completion of five years of service. This plan is currently noncontributory and provides fixed-dollar pension benefits. The Retirement Income Plan uses a career average pay formula which provides a credit for each year of participation in the retirement plan. For service before January 1, 1992, pension benefits are determined based on the greater of the accrued benefit as of December 31, 1991, or by multiplying a moving five-year average of plan compensation, not to exceed the January 1, 1992 salary, by a certain percentage determined by years of participation in the retirement plan at December 31, 1991. For service after January 1, 1992, pension benefits are equal to 2% of "plan compensation" through age 49 and 2 1/2% thereafter. "Plan compensation" is defined in this plan as the base rate of pay in effect on January 1 of each year and may differ from the amounts reported under the heading "Salary" in the Summary Compensation Table. Any difference is primarily attributable to the timing of annual salary increases for the named executive officers which impacts the amount paid to such officer and reported for a given year. The following table shows the projected annual retirement benefit payable on a straight-life annuity basis pursuant to LILCO's Retirement Income Plan to each of the individuals listed in the Summary Compensation Table at normal retirement age (which is the later of age 65 or five years of service), assuming continuation of employment to normal retirement date at the rate of plan compensation during fiscal 1998:
Annual Credited Normal Retirement Service as Retirement Benefit(1) of 3/31/97 Date - ------------------------------------------------------------------------------------------------------------------------ William J. Catacosinos $196,452 14 years, 2 months April 1, 1995(2) James T. Flynn $ 68,353 11 years, 6 months January 1, 1999 Leonard P. Novello $ 24,333 3 years, 0 months December 1, 2005 Michael E. Bray $ 10,080 1 year, 1 month June 1, 2012 Adam M. Madsen $ 82,935 30 years, 3 months August 1, 2001
(1) These Retirement Income Plan benefits may be limited at retirement by the maximum benefit limitation under Section 415 or the maximum compensation limitation under Section 401(a)(17) of the Internal Revenue Code. The benefits shown have been calculated without the limitations. LILCO has established the Retirement Income Restoration Plan of Long Island Lighting Company to restore qualified plan benefits which have been reduced pursuant to the Code or which may not be includible in the calculation of benefits pursuant to LILCO's Retirement Income Plan. "Plan compensation" is defined in the Retirement Income Restoration Plan, as the highest annual rate of pay consisting of (i) the highest rate of base pay in effect at any time and (ii) a single incentive benefit payment pursuant to the annual stock incentive plan. In the event that the retirement benefits are reduced by operation of either Section 415 or 401(a)(17) of the Internal Revenue Code, LILCO's Retirement Income Restoration Plan would provide payment of plan formula pension benefits which exceed those payable under the Code's maximum limitations. For 1997, the maximum benefit limit set by Section 415 and applicable to the amounts shown above was $125,000. For 1997, the maximum compensation limit set by Section 401(a)(17) and applicable to the amounts shown above was $160,000. For 1998, the maximum benefit limit set by Section 415 is $130,000 and the maximum compensation limit set by Section 401(a)(17) and to be utilized for benefits accrued in 1998 is $160,000. Because the Supplemental Plan retirement benefits were paid through March 31, 1998, any retirement benefit adjustments payable to the officers are to be 111 made from the Retirement Income Restoration Plan immediately prior to the completion of the transactions contemplated with KeySpan and/or LIPA. (2) Dr. Catacosinos' employment agreement, discussed below, provides for his continued employment beyond his normal retirement date. Agreements with Executives: LILCO has entered into individual employment agreements with each of its Officers to provide them with employment security and to minimize distractions resulting from personal uncertainties and risks of a change in control of LILCO. Currently, the principal benefits under these agreements, payable if the Officer's employment is terminated for any reason (including voluntary resignation) within three years of a change in control (as defined in these agreements), including by virtue of an acquisition of LILCO's assets or stock, prior to December 31, 1999, are: (i) severance pay equal to three years' salary; (ii) accelerated vesting and payment of the value of supplemental retirement benefits at the time of a change in control, which are enhanced by three years of service; (iii) continuation of life, medical and dental insurance for a period of three years; (iv) gross up of any tax payable pursuant to the Internal Revenue Code amended. The costs associated with these arrangements will be borne by LILCO's shareholders. Notwithstanding the creation of a trust to support payment of its obligations, LILCO is primarily liable for the compensation and retirement benefits payable to the Officers and the trust will make such payments only to the extent that LILCO does not. The transactions contemplated with KeySpan and/or LIPA will result in a change in control (as defined in these agreements) and entitle each Officer to the benefits payable under the terms of the employment agreements if such Officer's employment is terminated for any reason. LILCO has also entered into individual employment agreements with certain of its officers (not including Dr. Catacosinos and Mr. Flynn), effective July 1, 1997, pursuant to which such officers are employed for a one year term and are entitled to receive a retention bonus equal to 20% of the greater of job value or salary, if they are still employed by LILCO or its affiliates at the end of such term or are terminated without cause (as determined by the Chief Executive Officer) prior to the expiration of such term. These agreements have been entered into to induce such officers to continue their employment during the period prior to the consummation of the LIPA and KeySpan Transactions. Under the terms of an employment contract dated as of January 30, 1984, as amended (the "Contract"), Dr. Catacosinos has agreed to serve as CEO of LILCO until January 31, 2002. The Contract provides for a five-year consulting period following the termination of his employment (other than, except after a change in control, for cause). His consulting compensation will be 90% of his base annual salary at his retirement during the first two years, 75% of such salary during the third and fourth years and 50% of such salary during the fifth year. The Contract also provides for supplemental disability benefits. Dr. Catacosinos' employment under the Contract may be terminated by LILCO for cause or for such other reason as the Board of Directors may, in good faith, determine to be in the best interests of LILCO and by Dr. Catacosinos if he determines it to be in the best interests of LILCO or for any reason after a change in control. The transactions contemplated with KeySpan and/or LIPA will result in a change in control under the Contract. The Contract also provides for vested Contract Retirement Benefits commencing at the 112 earlier of Dr. Catacosinos' retirement or death, payable monthly to Dr. Catacosinos and his wife as a joint and survivor annuity with a minimum guaranteed period of ten years or the present value thereof as a lum sum on a change-in-control. The Contract Retirement Benefits in any year will be reduced by monthly benefits payable under LILCO's other retirement plans payable under their normal retirement forms. The benefit will be based upon a formula that considers his age at retirement, his highest annual salary, the highest bonus he has received and the length of his service to LILCO including service as a Director, employee or consultant. The benefit is also subject to certain annual cost of living adjustments. Assuming, for illustrative purposes, his retirement at May 31, 1998 the amount of the estimated retirement benefit payable under the Contract to Dr. Catacosinos as of May 31, 1998 (assuming continuation of his current salary) would be approximately $2,094,000. LILCO has established trusts to provide for payments of its obligations under the Contract, the costs of which are borne by LILCO's shareholders. Notwithstanding the creation of the trusts, LILCO continues to be primarily liable for all amounts payable to Dr. Catacosinos and the trusts will make such payments to the extent that LILCO does not. The Officers have also entered into indemnification agreements that are described below under the heading "Transactions with Management and Others." No Director or Officer or associate of any Director or Officer has any arrangement with any person with respect to any future employment by LILCO or its affiliates other than those described herein. Item 12. Security Ownership of Certain Beneficial Owners and Management Current Ownership of LILCO Common Stock. The following table shows the number of shares* of Common Stock beneficially owned, as of March 31, 1998, by each Director, certain Officers, and by all Directors and Officers as a group. The percentage of shares held by any one person, or all Directors and Officers as a group, does not exceed 1% of all outstanding shares of Common Stock. The address of each of the Directors and Officers is: c/o Long Island Lighting Company, 175 East Old Country Road, Hicksville, New York 11801. 113 Name Number of Shares* A. James Barnes.....................................................1,893 Michael E. Bray.....................................................1,406 George Bugliarello..................................................2,393 Renso L. Caporali...................................................2,625 William J. Catacosinos.............................................25,442 James T. Flynn.....................................................21,327 Vicki L. Fuller.....................................................1,693 Adam M. Madsen......................................................7,283 Leonard P. Novello..................................................8,534 Katherine D. Ortega.................................................2,264 Basil A. Paterson...................................................2,499 Richard L. Schmalensee..............................................1,493 George J. Sideris...................................................5,271 John H. Talmage.....................................................1,925 Edward J. Youngling.................................................6,269 All Directors and Officers as a group, including those named above, a total of 32 persons......................... 157,958 *The number of shares includes whole shares held under LILCO's Investor Common Stock Plan. The number also includes shares held or beneficially owned by a spouse, parent or child for which beneficial ownership is disclaimed for John H. Talmage - 287 shares, and for George Bugliarello - 500 shares. In addition, the number of shares shown for each Director, other than Dr. Catacosinos and Mr. Flynn, includes 1,393 LILCO Common Stock units, which do not confer any voting rights, credited pursuant to the Retainer Plan. 114 The following table sets forth certain information with respect to the shares of Preferred Stock and Common Stock owned by each person known by LILCO to be the beneficial owner of more than 5% of such Preferred Stock and Common Stock as of December 31, 1997.
Title of Percentage Class Names and Address Owned of Class Common Stock KeySpan Energy Corporation 23,981,964* 16.6% One MetroTech Center Brooklyn, NY 11201-3850 Common Stock The Capital Group Companies, Inc. 11,696,700 9.6% and Capital Research and Management Company 333 South Hope Street Los Angeles, CA 90071 Common Stock John A. Levin & Co., Inc. 6,861,988 5.7% One Rockefeller Plaza New York, NY 10020 and Baker Fentress & Company 200 West Madison Street Chicago, IL 60606
*Represents the number of shares that may be purchased pursuant to the Amended and Restated LILCO Stock Option Agreement filed on June 30, 1997 as Exhibit B to Registration Statement on Form S-4, No. 333-30353. LILCO has not been advised, nor is it aware, of any additional shares to which anyone has the right to acquire beneficial ownership. 115 Item 13. Certain Relationships and Related Transactions Transactions with Management and Others Indemnification of Directors and Officers: For many years prior to 1986, statutory provisions of the New York Business Corporation Law permitted corporations, including LILCO, under certain circumstances in connection with litigation in which its Directors and Officers were defendants, to indemnify them for, among other things, judgments, amounts paid in settlement and reasonable expenses. To reimburse it when it has indemnified its Directors and Officers, LILCO began in 1970, pursuant to statutory authorization, to purchase Director and Officer ("D&O") liability insurance in each year. D&O liability insurance also provides direct payment to LILCO's Directors and Officers under certain circumstances when LILCO has not previously provided indemnification. LILCO has D&O liability insurance which it has purchased from Associated Electric & Gas Insurance Services Ltd. ("AEGIS"), Energy Insurance Mutual ("EIM"), Steadfast Insurance Company, A.C.E. Insurance Company and XL Insurance Company, all with the effective date of August 26, 1997. LILCO also has liability insurance effective August 26, 1997 purchased from AEGIS and EIM, which provides fiduciary liability coverage for LILCO, its Directors, Officers and employees for any alleged breach of fiduciary duty under ERISA. The total annual premium for all these coverages was approximately $1.5 million in fiscal 1998. The LILCO By-laws provide for the mandatory indemnification of Directors and Officers to the extent not expressly prohibited by the New York Business Corporation Law. In addition, the Bylaws authorize the Board of Directors to grant indemnity rights to employees and other agents of LILCO. Such provisions are effective as to all claims for indemnification, whether the acts or omissions giving rise to a claim for such indemnification occurred or the expenses for which indemnity is sought were incurred, before or after the provisions of the By-laws were adopted. One of the provisions of the By-laws authorized the Board of Directors to enter into indemnification agreements with any of LILCO's Directors or Officers extending rights to indemnification and advancement of expenses to such person to the fullest extent permitted by applicable law. LILCO has entered into such agreements, which are described under the heading "Compensation Paid to Directors," with each of its Directors and Officers. Pursuant to the terms of those agreements and the provisions of the By-laws, LILCO has also established a trust to fund LILCO's obligations under the agreements. The LILCO Restated Certificate of Incorporation (the "LILCO Certificate") limits the personal liability of Directors for certain breaches of duty in such capacity pursuant to provisions of the New York Business Corporation Law. The LILCO Certificate does not bar litigation against Directors but provides that Directors are still required to defend themselves in litigation in which acts or omissions to act are alleged for which they might be held liable. Furthermore, the LILCO Certificate provides protection to Directors only and does not affect the liability of Officers of LILCO for breaches of the fiduciary duties of care and loyalty. 116 PART IV Item 14. Exhibits, Financial Statement Schedules, And Reports On Form 8-K (a)(1) List of Financial Statements Statement of Income for the year ended March 31, 1998, the three months ended March 31, 1997 and the years ended December 31, 1996 and 1995. Balance Sheet at March 31, 1998 and 1997 and December 31, 1996. Statement of Retained Earnings at March 31, 1998 and 1997 and December 31, 1996 and 1995. Statement of Capitalization at March 31, 1998 and 1997 and December 31, 1996. Statement of Cash Flows for the year ended March 31, 1998, the three months ended March 31, 1997 and the years ended December 31, 1996 and 1995. Notes to Financial Statements. (2) List of Financial Statement Schedules Valuation and Qualifying Accounts (Schedule II) (3) List of Exhibits 117 (3) LIST OF EXHIBITS Exhibits listed below which have been filed with the Securities and Exchange Commission pursuant to the Securities Act of 1933 or the Securities Exchange Act of 1934, and which were filed as noted below, are hereby incorporated by reference and made a part of this report with the same effect as if filed herewith. 2(a) Amended and Restated Agreement and Plan of Exchange and Merger dated June 26, 1997 between The Brooklyn Union Gas Company and Long Island Lighting Company dated as of June 26, 1997 (filed as Annex A to Registration Statement on Form S-4, No. 333-30353, on June 30, 1997). 2(b) Amendment, Assignment and Assumption Agreement dated as of September 29, 1997 by and among The Brooklyn Union Gas Company, Long Island Lighting Company and KeySpan Energy Corporation (filed as Exhibit 2.5 to Schedule 13D by Long Island Lighting Company on October 24, 1997). 2(c) Agreement and Plan of Merger dated as of June 26, 1997 by and among BL Holding Corp., Long Island Lighting Company, Long Island Power Authority and LIPA Acquisition Corp. (filed as Annex D to Registration Statement on Form S-4 No. 333-30353 on June 30, 1997). 2(d) Amended and Restated LILCO Stock Option Agreement between The Brooklyn Union Gas Company and Long Island Lighting Company dated as of June 26, 1997 (filed as Annex B to Registration Statement on Form S-4, No. 333-30353, on June 30, 1997). 2(e) Amended and Restated Brooklyn Union Stock Option Agreement between Long Island Lighting Company and The Brooklyn Union Gas Company dated as of June 26, 1997 (filed as Annex C to Registration Statement on Form S-4, No. 333-30353, on June 30, 1997). 3(a) Restated Certificate of Incorporation of the Company dated November 11, 1993 (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31, 1993.) 3(b) By-laws of the Company as amended on December 18, 1996 (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31, 1996.) 118 4(a) General and Refunding Indenture dated as of June 1, 1975 (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31, 1991.) Twenty-seven Supplemental Indentures to the General and Refunding Indenture dated as of June 1, 1975, as follows: Previously Filed As An Supplemental Indenture Exhibit To The Company's NUMBER DATE FORM DATE ------ ---- ---- ---- First 06/1/75 10-K 12/31/87 Second 09/1/75 10-K 12/31/87 Third 06/1/76 10-K 12/31/87 Fourth 12/1/76 10-K 12/31/87 Fifth 05/1/77 10-K 12/31/87 Sixth 04/1/78 10-K 12/31/87 Seventh 03/1/79 10-K 12/31/87 Eighth 02/1/80 10-K 12/31/87 Ninth 03/1/81 10-K 12/31/87 Tenth 07/1/81 10-K 12/31/87 Eleventh 07/1/81 10-K 12/31/87 Twelfth 12/1/81 10-K 12/31/87 Thirteenth 12/1/81 10-K 12/31/87 Fourteenth 06/1/82 10-K 12/31/87 Fifteenth 10/1/82 10-K 12/31/87 Sixteenth 04/1/83 10-K 12/31/87 Seventeenth 05/1/83 10-K 12/31/87 Eighteenth 09/1/84 10-K 12/31/87 Nineteenth 10/1/84 10-K 12/31/87 Twentieth 06/1/85 10-K 12/31/87 Twenty-first 04/1/86 10-K 12/31/87 Twenty-second 02/1/91 10-K 12/31/90 Twenty-third 05/1/91 10-K 12/31/91 Twenty-fourth 07/1/91 10-K 12/31/91 Twenty-fifth 05/1/92 10-K 12/31/92 Twenty-sixth 07/1/92 10-K 12/31/92 Twenty-seventh 06/1/94 10-K 12/31/94 4(b) Debenture Indenture dated as of November 1, 1986 from the Company to The Connecticut Bank and Trust Company, National Association, as Trustee (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31, 1986). Seven Supplemental Indentures to the Debenture Indenture dated as of November 1, 1986, filed as follows: 119 Previously Filed As An Supplemental Indenture Exhibit To The Company's NUMBER DATE FORM DATE ------ ---- ---- ---- First 11/1/86 10-K 12/31/86 Second 04/1/86 10-K 12/31/89 Third 07/1/86 10-K 12/31/89 Fourth 07/1/92 10-K 12/31/92 Fifth 11/1/92 10-K 12/31/92 Sixth 06/1/93 10-K 12/31/92 Seventh 07/1/93 10-K 12/31/92 4(c) Debenture Indenture dated as of November 1, 1992 from the Company to Chemical Bank, as Trustee (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31, 1992). Four Supplemental Indentures to the Debenture Indenture dated as of November 1, 1992, filed as follows: Previously Filed As An Supplemental Indenture Exhibit to the Company's NUMBER DATE FORM DATE ------ ---- ---- ---- First 01/1/93 10-K 12/31/92 Second 03/1/93 10-K 12/31/92 Third 03/1/93 10-K 12/31/92 Fourth 03/1/93 10-K 12/31/92 10(a)Sound Cable Project Facilities and Marketing Agreement dated as of August 26, 1987 between the Company and the Power Authority of the State of New York (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31, 1987). 10(b)Transmission Agreement by and between the Company and Consolidated Edison Company of New York, Inc. dated as of March 31, 1989 (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31, 1989). 10(c)Contract for the sale of Firm Power and Energy by and between the Company and the State of New York dated as of April 26, 1989 (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31, 1989). 120 10(d)Capacity Supply Agreement dated as of December 13, 1991 between the Company and the Power Authority of the State of New York (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31, 1991). 10(e)Nine Mile Point Nuclear Station Unit 2 Operating Agreement dated as of January 1, 1993 by and between the Company, New York State Electric & Gas Corporation, Rochester Gas and Electric Corporation and Central Hudson Gas and Electric Corporation (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31, 1993). 10(f)Settlement Agreement on Issues Related to Nine Mile Two Nuclear Plant dated as of June 6, 1990 by and between the Company, the Staff of the Department of Public Service and others (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31, 1990). 10(g)Settlement Agreement -- LILCO Issues dated as of February 28, 1989 by and between the Company and the State of New York (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31, 1988). 10(h)Amended and Restated Asset Transfer Agreement by and between the Company and the Long Island Power Authority dated as of June 16, 1988 as amended and restated on April 14, 1989 (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31, 1989). 10(i)Memorandum of Understanding concerning proposed agreements on power supply for Long Island dated as of June 16, 1988 by and between the Company and New York Power Authority as amended May 24, 1989 (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31, 1989). 10(j)Rate Moderation Agreement submitted by the staff of the New York State Public Service Commission on March 16, 1989 and supported by the Company (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31, 1989). 121 10(k)Site Cooperation and Reimbursement Agreement dated as of January 24, 1990 by and between the Company and Long Island Power Authority (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31, 1989). 10(l)Stipulation of settlement of federal Racketeer Influenced and Corrupt Organizations Act Class Action and False Claims Action dated as of February 27, 1989 among the attorneys for the Company, the ratepayer class, the United States of America and the individual defendants named therein (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31, 1988). 10(m)Revolving Credit Agreement dated as of June 27, 1989, between the Company and the banks and co-agents listed therein, with the Exhibits thereto (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31, 1989) and as amended by the First Amendment dated as of October 13, 1989 (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31, 1990) and as amended by the Second Amendment dated as of March 5, 1992 and as modified by a Waiver dated November 5, 1992 (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31, 1992). 10(n)Indenture of Trust dated as of December 1, 1989 by and between New York State Energy Research and Development Authority ("NYSERDA") and The Connecticut National Bank, as Trustee, relating to the 1989 EFRBs (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31, 1989). Participation Agreement dated as of December 1, 1989 by and between NYSERDA and the Company relating to the 1989 EFRBs (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31, 1989). 10(o)Indenture of Trust dated as of May 1, 1990 by and between NYSERDA and The Connecticut National Bank, as Trustee, relating to the 1990 EFRBs (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31, 1990). 122 Participation Agreement dated as of May 1, 1990 by and between NYSERDA and the Company relating to the 1990 EFRBs (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31, 1990). 10(p)Indenture of Trust dated as of January 1, 1991 by and between NYSERDA and The Connecticut National Bank, as Trustee, relating to the 1991 EFRBs (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31, 1990). Participation Agreement dated as of January 1, 1991 by and between NYSERDA and the Company relating to the 1991 EFRBs (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31, 1990). 10(q)Indenture of Trust dated as of February 1, 1992 by and between NYSERDA and IBJ Schroder Bank and Trust Company, as Trustee, relating to the 1992 EFRBs, Series A (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31, 1991). Participation Agreement dated as of February 1, 1992 by and between NYSERDA and the Company relating to the 1992 EFRBs, Series A (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31, 1991). 10(r)Indenture of Trust dated as of February 1, 1992 by and between NYSERDA and IBJ Schroder Bank and Trust Company, as Trustee, relating to the 1992 EFRBs, Series B (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31, 1991). Participation Agreement dated as of February 1, 1992 by and between NYSERDA and the Company relating to the 1992 EFRBs, Series B (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31, 1991). 10(s)Indenture of Trust dated as of August 1, 1992 by and between NYSERDA and IBJ Schroder Bank and Trust Company, as Trustee, relating to the 1992 EFRBs, Series C (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31, 1992). 123 Participation Agreement dated as of August 1, 1992 by and between NYSERDA and the Company relating to the 1992 EFRBs, Series C (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31, 1992). 10(t)Indenture of Trust dated as of August 1, 1992 by and between NYSERDA and IBJ Schroder Bank and Trust Company, as Trustee, relating to the 1992 EFRBs, Series D (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31, 1992). Participation Agreement dated as of August 1, 1992 by and between NYSERDA and the Company relating to the 1992 EFRBs, Series D (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31, 1992). 10(u)Indenture of Trust dated as of November 1, 1993 by and between NYSERDA and Chemical Bank, as Trustee, relating to the 1993 EFRBs, Series A (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31, 1993). Participation Agreement dated as of November 1, 1993 by and between NYSERDA and the Company relating to the 1993 EFRBs, Series A (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31, 1993). 10(v)Indenture of Trust dated as of November 1, 1993 by and between NYSERDA and Chemical Bank, as Trustee, relating to the 1993 EFRBs, Series B (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31, 1993). Participation Agreement dated as of November 1, 1993 by and between NYSERDA and the Company relating to the 1993 EFRBs, Series B (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31, 1993). 124 10(w)Indenture of Trust dated as of October 1, 1994 by and between NYSERDA and Chemical Bank, as Trustee, relating to the 1994 EFRBs, Series A (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31, 1994). Participation Agreement dated as of October 1, 1994 by and between NYSERDA and the Company relating to the 1994 EFRBs, Series A (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31,1994). 10(x)Indenture of Trust dated as of August 1, 1995 by and between NYSERDA and Chemical Bank, as Trustee, relating to the 1995 EFRBs, Series A (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31, 1995). Participation Agreement dated as of August 1, 1995 by and between NYSERDA and the Company relating to the 1995 EFRBs, Series A (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31, 1995). 10(y)Indenture of Trust dated as of December 1, 1997 by and between NYSERDA and The Chase Manhattan Bank, as Trustee, relating to the 1997 EFRBs, Series A (filed as an Exhibit to the Company's Form 10-Q for the period ended December 31, 1997). Participation Agreement dated as of December 1, 1997 by and between NYSERDA and the Company relating to the 1997 EFRBs, Series A (filed as an Exhibit to the Company's Form 10-Q for the period ended December 31, 1997). 10(z)Supplemental Death and Retirement Benefits Plan as amended and restated effective January 1, 1993 (filed as an Exhibit to the Company's Form 10-Q for the Quarterly Period Ended September 30, 1995) and related Trust Agreement, which Trust Agreement was filed as Exhibit 10(q) to the Company's Form 10-K for the Year Ended December 31, 1990. 125 10(aa) Executive Agreements and Management Contracts (1) Executive Employment Agreement dated as of January 30, 1984 by and between William J. Catacosinos and the Company, as amended by amendments dated March 20, 1987 (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31, 1986), December 22, 1989 (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31, 1989), and December 2, 1991 (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31, 1991), which amendment was restated by an amendment dated as of December 2, 1991, and amendments dated as of May 31, 1995 and August 4, 1995 (filed as Exhibits to the Company's Form 10-Q for the Quarterly Period Ended September 30, 1995); an Executive Employment Agreement dated as of August 4, 1995 (filed as an Exhibit to the Company's Form 10-Q for the Quarterly Period ended September 30, 1995; an amendment dated as of December 29, 1996 (filed as an Exhibit to the Company's Form 10-Q for the Quarterly Period Ended June 30, 1997). (2) Executive Employment Agreement dated as of November 21, 1994 by and between the Company and Theodore A. Babcock (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31, 1994), which agreement is substantially the same as Executive Employment Agreement by and between the Company and (1) Charles A. Daverio dated as of December 1, 1996, (2) Jane A. Fernandez, (3) James T. Flynn, (4) Joseph E. Fontana, (5) Robert X. Kelleher, (6) Howard A. Kosel dated as of April 1, 1997, (7) John D. Leonard, Jr., (8) Adam M. Madsen, (9) Kathleen A. Marion, (10) Brian R. McCaffrey, (11) Joseph W. McDonnell, (12) Leonard P. Novello dated as of April 1, 1995, (13) Anthony Nozzolillo, (14) Richard Reichler, (15) William G. Schiffmacher, (16) Werner J. Schweiger dated as of December 1, 1996, (17) Richard M. Siegel dated as of December 1, 1996, (18) Robert B. Steger, (19) William E. Steiger, and (20) Edward J. Youngling. (3) Executive Employment Agreement by and between the Company and Michael E. Bray dated as of March 1, 1997 (filed as an Exhibit to the Company's Form 10- Q for the transition period from 1/1/97 to 3/31/97.) 126 (4) Executive Retention Agreement dated as of July 1, 1997 by and between the Company and Theodore A. Babcock, Vice President and Treasurer (filed as an Exhibit to the Company's Form 10-Q for the period ended December 31, 1997), which agreement is substantially the same as Executive Retention Agreement by and between the Company and (1) Michael E. Bray, Senior Vice President; (2) Charles A. Daverio, Vice President; (3) Jane A. Fernandez, Vice President; (4) Joseph E. Fontana, Vice President and Controller; (5) Robert X. Kelleher, Senior Vice President; (6) Howard A. Kosel, Vice President; (7) John D. Leonard, Jr., Vice President; (8) Adam M. Madsen, Senior Vice President; (9) Kathleen A. Marion, Vice President; (10) Brian R. McCaffrey, Vice President; (11) Joseph W. McDonnell, Senior Vice President; (12) Leonard P. Novello, Senior Vice President and General Counsel; (13) Anthony Nozzolillo, Senior Vice President and Chief Financial Officer; (14) Richard Reichler, Vice President; (15) William G. Schiffmacher, Senior Vice President; (16) Werner J. Schweiger, Vice President; (17) Richard M. Siegel, Vice President; (18) Robert B. Steger, Senior Vice President; (19) William E. Steiger, Jr, Vice President, and (20) Edward J. Youngling,, Senior Vice President. (5) Indemnification Agreement by and between the Company and Theodore A. Babcock dated as of February 23, 1994 (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31, 1994), which agreement is substantially the same as Indemnification Agreement by and between the Company and (1) Michael E. Bray dated as of March 1, 1997, (2) Charles A. Daverio dated as of December 1, 1996, (3) Jane A. Fernandez dated as of September 19, 1994, (4) James T. Flynn dated as of November 25, 1987, (5) Joseph E. Fontana dated as of October 20, 1994, (6) George B. Jongeling dated as of April 1, 1998, (7) Robert X. Kelleher dated as of November 25, 1987, (8) Howard A. Kosel dated as of April 1, 1997, (9) John D. Leonard, Jr. dated as of November 25, 1987, (10) Adam M. Madsen dated as of November 25, 1987, (11) Kathleen A. Marion dated as of May 30, 1990, (12) Brian R. McCaffrey dated as of November 25, 1987, (13) Joseph W. McDonnell dated as of March 18, 1988, (14) Leonard P. Novello dated as of April 1, 1995, (15) Anthony Nozzolillo dated as of July 29, 1992, (16) Richard Reichler dated as of September 30, 1993, 127 (17) William G. Schiffmacher dated as of November 25, 1987, (18) Werner J. Schweiger dated as of December 1, 1996, (19) Richard M. Siegel dated as of December 1, 1996, (20) Robert B. Steger dated as of February 20, 1990, (21) William E. Steiger, Jr. dated as of March 1, 1989, and (22) Edward J. Youngling dated as of November 4, 1988. (6) Indemnification Agreement by and between the Company and Vicki L. Fuller dated as of January 3, 1994, (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31, 1994) which agreement is substantially the same as Indemnification Agreement by and between the Company and (1) A. James Barnes dated as of January 31, 1992, (2) George Bugliarello dated as of May 30, 1990, (3) Renso L. Caporali dated as of April 17, 1992, (4) William J. Catacosinos dated as of November 19, 1987, (5) Katherine D. Ortega dated as of April 20, 1993, (6) Basil A. Paterson dated as of November 19, 1987, (7) Richard L. Schmalensee dated as of February 8, 1992, (8) George J. Sideris dated as of November 30, 1987, and (9) John H. Talmage dated as of November 19, 1987. (7) Indemnification Agreement by and between the Company and Eben W. Pyne dated as of April 20, 1993, (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31, 1993.) (8) Long Island Lighting Company Officers' and Directors' Protective Trust dated as of April 18, 1988 as Amended and Restated as of September 1, 1994 by and between the Company and Clarence Goldberg, as Trustee (filed as an Exhibit to the Company's Form 10-Q for the Quarterly period Ended September 30, 1994). (9) Long Island Lighting Company's Retirement Plan for Directors dated as of February 2, 1990 (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31, 1989). (10) Trust Agreement for Officers dated March 20, 1987 by and between the Company and Clarence Goldberg as Trustee (filed as an Exhibit to the Company's Form 10-K for the Year Ended December 31, 1988). 128 *(11) Consulting Agreement dated as of August 9, 1997 by and between the Company and Eben W. Pyne. *18 Letter re change in accounting principles. *23 Consent of Ernst & Young LLP, Independent Auditors. *24(a) Powers of Attorney executed by the Directors and Officers of the Company. *24(b) Certificate as to Corporate Power of Attorney. *24(c) Certified copy of Resolution of Board of Directors authorizing signature pursuant to Power of Attorney. *27 Financial Data Schedule UT for the twelve-month period ended March 31, 1998. Financial Statements of subsidiary companies accounted for by the equity method have been omitted because such subsidiaries do not constitute significant subsidiaries. (b) REPORTS ON FORM 8-K None. - -------- *Filed herewith. 129 SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS (Thousands of Dollars)
- --------------------------------------- -------------- ------------------------------- --------------- --------------- Column A Column B Column C Column D Column E - --------------------------------------- -------------- ------------------------------- --------------- --------------- Additions ---------------- -------------- Balance at Charged to Charged to Balance at Description beginning of costs and other Deductions- end of period period expenses accounts- describe describe - --------------------------------------- -------------- ---------------- -------------- --------------- --------------- - ---------------------------------------------------------------------------------------------------------------------- Year ended March 31, 1998 Deducted from asset accounts: Allowance for doubtful accounts $23,675 $23,239 -- $23,431(1) $23,483 Three Months Ended March 31, 1997 Deducted from asset accounts: Allowance for doubtful accounts $25,000 $ 4,821 -- $6,146(1) $23,675 Year ended December 31, 1996 Deducted from asset accounts: Allowance for doubtful accounts $24,676 $23,119 -- $22,795(1) $25,000 Year ended December 31, 1995 Deducted from asset accounts: Allowance for doubtful accounts $23,365 $17,751 -- $16,440(1) $24,676
(1) Uncollectible accounts written off, net of recoveries. 130 SIGNATURES Pursuant to the requirements of the Securities Exchange Act of 1934, this amendment has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. Date May 28, 1998 Signature and Title -------------------------------------------- WILLIAM J. CATACOSINOS* William J. Catacosinos, Principal Executive Officer, President and Chairman of the Board of Directors JAMES T. FLYNN* James T. Flynn, President, Chief Operating Officer and Director /s/ JOSEPH E. FONTANA -------------------------------------------- Joseph E. Fontana, Controller, Principal Accounting Officer -------------------------------------------- A. JAMES BARNES* A. James Barnes, Director -------------------------------------------- GEORGE BUGLIARELLO* George Bugliarello, Director -------------------------------------------- RENSO L. CAPORALI* Renso L. Caporali, Director -------------------------------------------- VICKI L. FULLER* Vicki L. Fuller, Director -------------------------------------------- KATHERINE D. ORTEGA* Katherine D. Ortega, Director -------------------------------------------- BASIL A. PATERSON* Basil A. Paterson, Director -------------------------------------------- RICHARD L. SCHMALENSEE* Richard L. Schmalensee, Director -------------------------------------------- GEORGE J. SIDERIS* George J. Sideris, Director -------------------------------------------- JOHN H. TALMAGE* John H. Talmage, Director /s/ ANTHONY NOZZOLILLO -------------------------------------------- *Anthony Nozzolillo (Individually, as Senior Vice President and Principal Financial Officer and as attorney-in-fact for each of the persons indicated) 131 Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this amendment to be signed on its behalf by the undersigned, thereunto duly authorized. LONG ISLAND LIGHTING COMPANY Date: May 28, 1998 By: /s/ ANTHONY NOZZOLILLO ----------------------- Anthony Nozzolillo Principal Financial Officer Original powers of attorney, authorizing Kathleen A. Marion and Anthony Nozzolillo, and each of them, to sign this report and any amendments thereto, as attorney-in-fact for each of the Directors and Officers of the Company, and a certified copy of the resolution of the Board of Directors of the Company authorizing said persons and each of them to sign this report and amendments thereto as attorney-in-fact for any Officers signing on behalf of the Company, are being filed with the Securities and Exchange Commission. 132 EX-10.(AA)(11) 2 CONSULTING AGREEMENT Exhibit 10(aa)(11) CONSULTING AGREEMENT AGREEMENT made as of August 7, 1997 between LONG ISLAND LIGHTING COMPANY, a New York corporation, having its principal offices at 175 East Old Country Road, Hicksville, New York 11801 (hereinafter the "Company") and EBEN W. PYNE, residing in Old Westbury, New York (hereinafter the "Consultant"); WHEREAS, the Company has requested that the Consultant perform services for it; and WHEREAS, the Consultant is willing to perform consulting services for the Company; NOW THEREFORE, it is agreed that: 1. Effective August 7, 1997, the Consultant will be engaged as a Consulting Director for a period ending on the day of the 1998 Annual Meeting of Shareholders. The Consultant will advise and counsel the Board of Directors and any of its committees on various business and financial matters and any other areas requested by or on behalf of the Board of Directors of the Company. 2. For such services, the Consultant will receive an annual retainer equal to the annual retainer paid to a duly elected Director, an additional $500.00 for each Board or Committee meeting attended and the same pension and health benefits provided to a duly elected director. Consultant acknowledges that he will participate in the Company's Directors' Stock Unit Retainer Plan, which was effective January 1, 1996, and that at least 50% of Consultant's retainer will be applied to the purchase of stock units. 3. The Consultant shall have the right to participate as a Consulting Director in the Company's Deferred Compensation Plan for Directors and the Company's Retirement Income Plan for Directors. 4. This agreement shall be governed by the laws of the State of New York. IN WITNESS WHEREOF, this agreement has been executed this 7th day of August, 1997. CONSULTANT LONG ISLAND LIGHTING COMPANY /s/ EBEN W. PYNE By: /s/ KATHLEEN A. MARION - ------------------ ----------------------------- EBEN W. PYNE CORPORATE SECRETARY EX-18 3 LETTER RE: CHANGE IN ACCOUNTING PRINCIPLES Exhibit 18 May 22, 1998 Anthony Nozzolillo Senior Vice President and Principal Financial Officer Long Island Lighting Company 175 E Old Country Road Hicksville, NY 11801 Dear Mr. Nozzolillo: Note 1 of Notes to the Financial Statements of Long Island Lighting Company included in its Annual Report on Form 10-K for the year ended March 31, 1998 describes a change in the method of accounting for the annual amortization of the Rate Moderation Component (RMC) of a regulatory asset from a straight line method to a method which is computed based upon monthly forecasted revenue requirements. You have advised us that you believe that the change is to a preferable method in your circumstances because the monthly amortization of the RMC, which varies based upon each month's forecasted revenue requirements, more closely aligns such amortization with the Company's cost of service producing a better matching of revenue with the related expense for reporting within a rate year. There are no authoritative criteria for determining a "preferable" method of accounting for the annual amortization of the RMC, however we conclude that the change in the method of accounting for the annual amortization of the RMC is to an acceptable alternative method which, based on your business judgment to make this change for the reason cited above, is preferable in your circumstances. Very truly yours, /s/ Ernst & Young LLP - --------------------- EX-23 4 CONSENT OF INDEPENDENT AUDITORS Consent of Independent Auditors We consent to the incorporation by reference in the Post-Effective Amendment No. 3 to Registration Statement (No. 33-16238) on Form S-8 relating to Long Island Lighting Company's Employee Stock Purchase Plan, Post-Effective Amendment No. 1 to Registration Statement (No. 2-87427) on Form S-3 relating to Long Island Lighting Company's Automatic Dividend Reinvestment Plan and in the related Prospectus, Registration Statement (No. 2-88578) on Form S-3 relating to the issuance of Common Stock and in the related Prospectus and Registration Statement (No. 33-52963) on Form S-3 relating to the issuance of General and Refunding Bonds, Debentures, Preferred Stock or Common Stock and in the related Prospectus, of our report dated May 22, 1998, with respect to the financial statements and schedule of Long Island Lighting Company included in this Annual Report on Form 10-K for the year ended March 31, 1998. /s/ Ernst & Young LLP - --------------------- Melville, New York May 26, 1998 EX-24 5 EXHIBIT 24 Exhibit 24(a) Annual Report on Form 10-K for the period ending March 31, 1998 LONG ISLAND LIGHTING COMPANY POWER OF ATTORNEY WHEREAS, LONG ISLAND LIGHTING COMPANY, a New York corporation (the "Company"), intends to file with the Securities and Exchange Commission under the Securities Exchange Act of 1934, as amended, an Annual Report on Form 10-K as prescribed by said Commission pursuant to said Act and the rules and regulations promulgated thereunder. NOW, THEREFORE, in my capacity either as a director or officer, or both as the case may be, of the Company, I do hereby appoint KATHLEEN A. MARION and ANTHONY NOZZOLILLO, and each of them severally, as my attorneys-in-fact with power to execute in my name and place, and in my capacity as a director, officer, or both, as the case may be, of LONG ISLAND LIGHTING COMPANY, said Report, any amendment to said Report and any other documents required in connection therewith, and to file the same with the Securities and Exchange Commission. IN WITNESS WHEREOF, I have executed this power of attorney this 7th day of May 1998. /S/ WILLIAM J. CATACOSINOS -------------------------- WILLIAM J. CATACOSINOS PRINCIPAL EXECUTIVE OFFICER, and CHAIRMAN OF THE BOARD OF DIRECTORS Exhibit 24(a) Annual Report on Form 10-K for the period ending March 31, 1998 LONG ISLAND LIGHTING COMPANY POWER OF ATTORNEY WHEREAS, LONG ISLAND LIGHTING COMPANY, a New York corporation (the "Company"), intends to file with the Securities and Exchange Commission under the Securities Exchange Act of 1934, as amended, an Annual Report on Form 10-K as prescribed by said Commission pursuant to said Act and the rules and regulations promulgated thereunder. NOW, THEREFORE, in my capacity either as a director or officer, or both as the case may be, of the Company, I do hereby appoint KATHLEEN A. MARION and ANTHONY NOZZOLILLO, and each of them severally, as my attorneys-in-fact with power to execute in my name and place, and in my capacity as a director, officer, or both, as the case may be, of LONG ISLAND LIGHTING COMPANY, said Report, any amendment to said Report and any other documents required in connection therewith, and to file the same with the Securities and Exchange Commission. IN WITNESS WHEREOF, I have executed this power of attorney this 27 day of May 1998. /S/ A. JAMES BARNES ------------------- A. JAMES BARNES, DIRECTOR Exhibit 24(a) Annual Report on Form 10-K for the period ending March 31, 1998 LONG ISLAND LIGHTING COMPANY POWER OF ATTORNEY WHEREAS, LONG ISLAND LIGHTING COMPANY, a New York corporation (the "Company"), intends to file with the Securities and Exchange Commission under the Securities Exchange Act of 1934, as amended, an Annual Report on Form 10-K as prescribed by said Commission pursuant to said Act and the rules and regulations promulgated thereunder. NOW, THEREFORE, in my capacity either as a director or officer, or both as the case may be, of the Company, I do hereby appoint KATHLEEN A. MARION and ANTHONY NOZZOLILLO, and each of them severally, as my attorneys-in-fact with power to execute in my name and place, and in my capacity as a director, officer, or both, as the case may be, of LONG ISLAND LIGHTING COMPANY, said Report, any amendment to said Report and any other documents required in connection therewith, and to file the same with the Securities and Exchange Commission. IN WITNESS WHEREOF, I have executed this power of attorney this 27 day of May 1998. /S/ GEORGE BUGLIARELLO ---------------------- GEORGE BUGLIARELLO, DIRECTOR Exhibit 24(a) Annual Report on Form 10-K for the period ending March 31, 1998 LONG ISLAND LIGHTING COMPANY POWER OF ATTORNEY WHEREAS, LONG ISLAND LIGHTING COMPANY, a New York corporation (the "Company"), intends to file with the Securities and Exchange Commission under the Securities Exchange Act of 1934, as amended, an Annual Report on Form 10-K as prescribed by said Commission pursuant to said Act and the rules and regulations promulgated thereunder. NOW, THEREFORE, in my capacity either as a director or officer, or both as the case may be, of the Company, I do hereby appoint KATHLEEN A. MARION and ANTHONY NOZZOLILLO, and each of them severally, as my attorneys-in-fact with power to execute in my name and place, and in my capacity as a director, officer, or both, as the case may be, of LONG ISLAND LIGHTING COMPANY, said Report, any amendment to said Report and any other documents required in connection therewith, and to file the same with the Securities and Exchange Commission. IN WITNESS WHEREOF, I have executed this power of attorney this 27 day of May 1998. /S/ RENSO L. CAPORALI --------------------- RENSO L. CAPORALI, DIRECTOR Exhibit 24(a) Annual Report on Form 10-K for the period ending March 31, 1998 LONG ISLAND LIGHTING COMPANY POWER OF ATTORNEY WHEREAS, LONG ISLAND LIGHTING COMPANY, a New York corporation (the "Company"), intends to file with the Securities and Exchange Commission under the Securities Exchange Act of 1934, as amended, an Annual Report on Form 10-K as prescribed by said Commission pursuant to said Act and the rules and regulations promulgated thereunder. NOW, THEREFORE, in my capacity either as a director or officer, or both as the case may be, of the Company, I do hereby appoint KATHLEEN A. MARION and ANTHONY NOZZOLILLO, and each of them severally, as my attorneys-in-fact with power to execute in my name and place, and in my capacity as a director, officer, or both, as the case may be, of LONG ISLAND LIGHTING COMPANY, said Report, any amendment to said Report and any other documents required in connection therewith, and to file the same with the Securities and Exchange Commission. IN WITNESS WHEREOF, I have executed this power of attorney this 7th day of May 1998. /S/ JAMES T. FLYNN ------------------ JAMES T. FLYNN, PRESIDENT, CHIEF OPERATING OFFICER AND DIRECTOR Exhibit 24(a) Annual Report on Form 10-K for the period ending March 31, 1998 LONG ISLAND LIGHTING COMPANY POWER OF ATTORNEY WHEREAS, LONG ISLAND LIGHTING COMPANY, a New York corporation (the "Company"), intends to file with the Securities and Exchange Commission under the Securities Exchange Act of 1934, as amended, an Annual Report on Form 10-K as prescribed by said Commission pursuant to said Act and the rules and regulations promulgated thereunder. NOW, THEREFORE, in my capacity either as a director or officer, or both as the case may be, of the Company, I do hereby appoint KATHLEEN A. MARION and ANTHONY NOZZOLILLO, and each of them severally, as my attorneys-in-fact with power to execute in my name and place, and in my capacity as a director, officer, or both, as the case may be, of LONG ISLAND LIGHTING COMPANY, said Report, any amendment to said Report and any other documents required in connection therewith, and to file the same with the Securities and Exchange Commission. IN WITNESS WHEREOF, I have executed this power of attorney this 27 day of May 1998. /S/ VICKI L. FULLER ------------------- VICKI L. FULLER, DIRECTOR Exhibit 24(a) Annual Report on Form 10-K for the period ending March 31, 1998 LONG ISLAND LIGHTING COMPANY POWER OF ATTORNEY WHEREAS, LONG ISLAND LIGHTING COMPANY, a New York corporation (the "Company"), intends to file with the Securities and Exchange Commission under the Securities Exchange Act of 1934, as amended, an Annual Report on Form 10-K as prescribed by said Commission pursuant to said Act and the rules and regulations promulgated thereunder. NOW, THEREFORE, in my capacity either as a director or officer, or both as the case may be, of the Company, I do hereby appoint KATHLEEN A. MARION and ANTHONY NOZZOLILLO, and each of them severally, as my attorneys-in-fact with power to execute in my name and place, and in my capacity as a director, officer, or both, as the case may be, of LONG ISLAND LIGHTING COMPANY, said Report, any amendment to said Report and any other documents required in connection therewith, and to file the same with the Securities and Exchange Commission. IN WITNESS WHEREOF, I have executed this power of attorney this 27 day of May 1998. /S/ KATHERINE D. ORTEGA ----------------------- KATHERINE D. ORTEGA, DIRECTOR Exhibit 24(a) Annual Report on Form 10-K for the period ending March 31, 1998 LONG ISLAND LIGHTING COMPANY POWER OF ATTORNEY WHEREAS, LONG ISLAND LIGHTING COMPANY, a New York corporation (the "Company"), intends to file with the Securities and Exchange Commission under the Securities Exchange Act of 1934, as amended, an Annual Report on Form 10-K as prescribed by said Commission pursuant to said Act and the rules and regulations promulgated thereunder. NOW, THEREFORE, in my capacity either as a director or officer, or both as the case may be, of the Company, I do hereby appoint KATHLEEN A. MARION and ANTHONY NOZZOLILLO, and each of them severally, as my attorneys-in-fact with power to execute in my name and place, and in my capacity as a director, officer, or both, as the case may be, of LONG ISLAND LIGHTING COMPANY, said Report, any amendment to said Report and any other documents required in connection therewith, and to file the same with the Securities and Exchange Commission. IN WITNESS WHEREOF, I have executed this power of attorney this 27 day of May 1998. /S/ BASIL A. PATERSON --------------------- BASIL A. PATERSON, DIRECTOR Exhibit 24(a) Annual Report on Form 10-K for the period ending March 31, 1998 LONG ISLAND LIGHTING COMPANY POWER OF ATTORNEY WHEREAS, LONG ISLAND LIGHTING COMPANY, a New York corporation (the "Company"), intends to file with the Securities and Exchange Commission under the Securities Exchange Act of 1934, as amended, an Annual Report on Form 10-K as prescribed by said Commission pursuant to said Act and the rules and regulations promulgated thereunder. NOW, THEREFORE, in my capacity either as a director or officer, or both as the case may be, of the Company, I do hereby appoint KATHLEEN A. MARION and ANTHONY NOZZOLILLO, and each of them severally, as my attorneys-in-fact with power to execute in my name and place, and in my capacity as a director, officer, or both, as the case may be, of LONG ISLAND LIGHTING COMPANY, said Report, any amendment to said Report and any other documents required in connection therewith, and to file the same with the Securities and Exchange Commission. IN WITNESS WHEREOF, I have executed this power of attorney this 27 day of May 1998. /S/ RICHARD L. SCHMALENSEE -------------------------- RICHARD L. SCHMALENSEE, DIRECTOR Exhibit 24(a) Annual Report on Form 10-K for the period ending March 31, 1998 LONG ISLAND LIGHTING COMPANY POWER OF ATTORNEY WHEREAS, LONG ISLAND LIGHTING COMPANY, a New York corporation (the "Company"), intends to file with the Securities and Exchange Commission under the Securities Exchange Act of 1934, as amended, an Annual Report on Form 10-K as prescribed by said Commission pursuant to said Act and the rules and regulations promulgated thereunder. NOW, THEREFORE, in my capacity either as a director or officer, or both as the case may be, of the Company, I do hereby appoint KATHLEEN A. MARION and ANTHONY NOZZOLILLO, and each of them severally, as my attorneys-in-fact with power to execute in my name and place, and in my capacity as a director, officer, or both, as the case may be, of LONG ISLAND LIGHTING COMPANY, said Report, any amendment to said Report and any other documents required in connection therewith, and to file the same with the Securities and Exchange Commission. IN WITNESS WHEREOF, I have executed this power of attorney this 7th day of May 1998. /S/ GEORGE J.. SIDERIS ---------------------- GEORGE J. SIDERIS, DIRECTOR Exhibit 24(a) Annual Report on Form 10-K for the period ending March 31, 1998 LONG ISLAND LIGHTING COMPANY POWER OF ATTORNEY WHEREAS, LONG ISLAND LIGHTING COMPANY, a New York corporation (the "Company"), intends to file with the Securities and Exchange Commission under the Securities Exchange Act of 1934, as amended, an Annual Report on Form 10-K as prescribed by said Commission pursuant to said Act and the rules and regulations promulgated thereunder. NOW, THEREFORE, in my capacity either as a director or officer, or both as the case may be, of the Company, I do hereby appoint KATHLEEN A. MARION and ANTHONY NOZZOLILLO, and each of them severally, as my attorneys-in-fact with power to execute in my name and place, and in my capacity as a director, officer, or both, as the case may be, of LONG ISLAND LIGHTING COMPANY, said Report, any amendment to said Report and any other documents required in connection therewith, and to file the same with the Securities and Exchange Commission. IN WITNESS WHEREOF, I have executed this power of attorney this 11 day of May 1998. /S/ JOHN H. TALMAGE ------------------- JOHN H. TALMAGE, DIRECTOR EXHIBIT 24(b) Form 10-K for year ended March 31, 1998 LONG ISLAND LIGHTING COMPANY CERTIFICATE AS TO POWER OF ATTORNEY WHEREAS, LONG ISLAND LIGHTING COMPANY, a New York corporation, intends to file with the Securities and Exchange Commission under the Securities Exchange Act of 1934, as amended, an Annual Report for the year ended March 31, 1998, on Form 10-K as prescribed by said Commission pursuant to said Act and the rules and regulations promulgated thereunder. NOW, THEREFORE, in my capacity as Assistant Corporate Secretary of Long Island Lighting Company, I do hereby certify that Anthony Nozzolillo has been appointed by the Board of Directors of Long Island Lighting Company with power to execute, among other documents, said Report, any amendment to said Report and any other documents required in connection therewith, and to file the same with the Securities and Exchange Commission. WITNESS my hand and the seal of the Company this 27 day of May, 1998 /S/ THEODORE A. BABCOCK ----------------------- THEODORE A. BABCOCK Assistant Corporate Secretary (Corporate Seal) LONG ISLAND LIGHTING COMPANY (Resolution adopted on May 27, 1998) "RESOLVED, that the proper officers of the Corporation be, and hereby are, and each of them with the full authority without the others hereby is, authorized, empowered and directed, in the name and on behalf of the Corporation, to execute the corporation's Form 10-K for the year ended March 31, 1998, substantially in the form previously circulated to the Directors of the Corporation, with such changes as such proper officers, with the advice of counsel deem necessary or desirable, the execution by such proper officers to be conclusive evidence that they or he/she deemed such changes to be necessary or desirable, and to execute any amendment to such Form 10-K, to procure all necessary signatures thereon, and to file such Form 10-K and any amendment when so executed (together with appropriate exhibits thereto) with the Securities Exchange Commission." Exhibit 24(c) Form 10-K for year ending March 31, 1998 LONG ISLAND LIGHTING COMPANY I, KATHLEEN A. MARION, Corporate Secretary of LONG ISLAND LIGHTING COMPANY (the "Company"), a New York corporation, DO HEREBY CERTIFY that annexed hereto is a true, correct and complete copy of the resolution adopted at a meeting of the Board of Directors of the Company duly called and held on May 27, 1998, at which meeting a quorum was present and acting throughout. AND I DO FURTHER CERTIFY that the foregoing resolution has not been in any way amended, annulled, rescinded or revoked and that the same is still in full force and effect. WITNESS my hand and the seal of the Company this 27 day of May, 1998. /S/ KATHLEEN A. MARION ---------------------- KATHLEEN A. MARION Corporate Secretary (Corporate Seal) EX-27 6 LONG ISLAND LIGHTING COMPANY FDS UT (UNAUDITED)
UT This schedule contains summary financial information extracted fom the Statement of Income, Balance Sheet and Statement of Cash Flows, and is qualified in its entirety by reference to such financial statements. 1,000 12-MOS MAR-31-1998 MAR-31-1998 PER-BOOK 3,814,081 50,816 854,272 85,702 7,091,854 11,896,725 608,635 1,097,720 953,492 2,659,847 562,600 0 4,395,555 0 0 0 101,000 139,374 0 0 4,038,349 11,896,725 3,124,094 237,371 2,118,427 2,355,798 768,296 (4,183) 764,113 404,473 359,640 51,813 307,827 215,790 351,261 674,084 2.54 2.54
-----END PRIVACY-ENHANCED MESSAGE-----