-----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, Q4ZVOBFu5rJ2iwVxhmIXOOsl4lYjT7B091gVbSy5YqE6nVG8CUIahAvKR4J86rxQ 6lX3RQRDz6yaq69ffJ0yCg== 0000060251-96-000002.txt : 19960401 0000060251-96-000002.hdr.sgml : 19960401 ACCESSION NUMBER: 0000060251-96-000002 CONFORMED SUBMISSION TYPE: DEF 14A PUBLIC DOCUMENT COUNT: 1 CONFORMED PERIOD OF REPORT: 19960509 FILED AS OF DATE: 19960329 SROS: NYSE SROS: PSE 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: 1231 FILING VALUES: FORM TYPE: DEF 14A SEC ACT: 1934 Act SEC FILE NUMBER: 001-03571 FILM NUMBER: 96541133 BUSINESS ADDRESS: STREET 1: 175 E OLD COUNTRY RD CITY: HICKSVILLE STATE: NY ZIP: 11801 BUSINESS PHONE: 5169334590 DEF 14A 1 DEFINITIVE PROXY MATERIALS SCHEDULE 14A INFORMATION Proxy Statement Pursuant to Section 14(a) of the Securities Exchange Act of 1934 (Amendment No. ) Filed by registrant |X| Filed by a party other than the registrant |_| Check the appropriate box: |_| Preliminary proxy statement |X| Definitive proxy statement |_| Definitive additional materials |_| Soliciting material pursuant to Rule 14a-11(c) or Rule 14a-12 LONG ISLAND LIGHTING COMPANY ---------------------------- (Name of Registrant As Specified In Charter) LONG ISLAND LIGHTING COMPANY ---------------------------- (Name of Person(s) Filing the Information Statement) Payment of Filing Fee (Check the appropriate box): |X| $125 per Exchange Act Rule 0-11(c)(1)(ii), or 14A-6(i)(1), or 14a-6(j)(2). |_| $500 per each party to the controversy pursuant to Exchange Act Rule 14a-6(i)(3). |_| Fee computed on table below per Exchange Act Rules 14a-6(i)(4) and 0-11. (1) Title of each class of securities to which transaction applies: (2) Aggregate number of securities to which transaction applies: (3) Per unit price or other underlying value of transaction computed pursuant to Exchange Act Rule 0-11.(1) (4) Proposed maximum aggregate value of transaction: |_| Check box if any part of the fee is offset as provided by Exchange Act Rule 0-11(a)(2) and identify the filing for which the offsetting fee was paid previously. Identify the previous filing by registrations statement number, or the form or schedule and the date of its filing. (1) Amount Previously Paid: (2) Form, schedule or registration statement no.: (3) Filing Party: (4) Date Filed: - -------- (1) Set forth the amount on which the filing fee is calculated and state how it was determined. [LILCO LOGO] LONG ISLAND LIGHTING COMPANY EXECUTIVE OFFICES: 175 EAST OLD COUNTRY ROAD HICKSVILLE, NEW YORK 11801 April 1, 1996 Dear Shareowner: You are cordially invited to the Annual Meeting of Long Island Lighting Company Shareowners, scheduled to be held at 3:00 P.M., on Thursday, May 9, 1996 in Tilles Center for the Performing Arts at the Long Island University, C.W. Post Campus, Northern Boulevard, Greenvale, New York 11548. Your Board of Directors and management hope that many shareowners will find it convenient to attend the Annual Meeting and look forward to personally greeting those able to be present. At this year's Annual Meeting, holders of Common Stock are being asked to elect eleven Directors, to ratify the appointment of Ernst & Young LLP as independent auditors for 1996, to approve a Directors' Stock Unit Retainer Plan and to approve an Officers' Long-Term Incentive Plan. Your Board of Directors unanimously believe these proposals to be in the best interests of the Company and its shareowners and, for the reasons set forth in the accompanying Proxy Statement, strongly urges you to vote FOR all items. If you plan to attend the Annual Meeting, please bring the enclosed admission card or proof of ownership. If your shares are held through a bank or brokerage firm, please request a letter or some other evidence of ownership from your bank or firm as well as proper authorization if you wish to vote your shares in person. Regardless of the size of your holdings, it is important that your shares are represented and voted, whether or not you can join us at this Annual Meeting. Therefore, please promptly sign, date and return the enclosed proxy card. Your cooperation in complying with this request is greatly appreciated. Please note that, as part of the Company's ongoing effort to control costs, detailed financial information previously included in the Company's Annual Report to Shareowners has been appended to this Proxy Statement. Thank you. On behalf of the Board of Directors, Sincerely, /s/ WILLIAM J. CATACOSINOS [LILCO LOGO] LONG ISLAND LIGHTING COMPANY EXECUTIVE OFFICES: 175 EAST OLD COUNTRY ROAD HICKSVILLE, NEW YORK 11801 April 1, 1996 NOTICE OF ANNUAL MEETING OF SHAREOWNERS The Annual Meeting of Shareowners of Long Island Lighting Company will be held in Tilles Center for the Performing Arts at the Long Island University, C.W. Post Campus, Northern Boulevard, Greenvale, New York 11548, at 3:00 P.M., on Thursday, May 9, 1996. The purposes of the Annual Meeting are: (i) to elect eleven Directors; (ii) to ratify the appointment of Ernst & Young LLP as independent auditors for the year 1996; (iii) to approve a Directors' Stock Unit Retainer Plan; (iv) to approve an Officers' Long-Term Incentive Plan and (v) to take action on such other business as may properly come before the Annual Meeting. Only Common Stock shareowners of record at the close of business on March 20, 1996 are entitled to notice of and are eligible to vote at the Annual Meeting and at all postponements or adjournments thereof. Please mark, sign and date the enclosed proxy card and return it promptly in the postpaid return envelope provided, whether or not you expect to attend the Annual Meeting. Returning the proxy card will not affect your right to vote in person at the Annual Meeting should you decide to attend. By Order of the Board of Directors, /S/ KATHLEEN A. MARION KATHLEEN A. MARION Corporate Secretary PROXY STATEMENT Table of Contents INTRODUCTION............................................... 1 VOTING..................................................... 1 ITEM ONE -- ELECTION OF DIRECTORS.......................... 3 BOARD OF DIRECTORS......................................... 8 REPORT OF THE COMPENSATION AND MANAGEMENT APPRAISAL COMMITTEE ON EXECUTIVE COMPENSATION ................................. 10 STOCK PERFORMANCE GRAPH.................................... 13 COMPENSATION PAID TO EXECUTIVE OFFICERS.................... 14 SECURITY OWNERSHIP OF MANAGEMENT........................... 17 TRANSACTIONS WITH MANAGEMENT AND OTHERS.................... 18 ITEM TWO -- APPOINTMENT OF INDEPENDENT AUDITORS.............20 ITEM THREE -- APPROVAL OF DIRECTORS' STOCK UNIT RETAINER PLAN...............................................21 ITEM FOUR -- APPROVAL OF OFFICERS' LONG-TERM INCENTIVE PLAN. . . . . . . . . . . . . . . . . . 23 ADDITIONAL INFORMATION..................................... 24 Directors' Stock Unit Retainer Plan . . . . . . . . Appendix A Officers' Long-Term Incentive Plan. . . . . . . . . Appendix B 1995 Financial Statements . . . . . . . . . . . . . Appendix C PROXY STATEMENT OF LONG ISLAND LIGHTING COMPANY ANNUAL MEETING TO BE HELD MAY 9, 1996 INTRODUCTION This Proxy Statement is furnished in connection with the solicitation of proxies by the Board of Directors of Long Island Lighting Company (the "Company") for the Annual Meeting of Shareowners to be held on May 9, 1996 (the "Annual Meeting") and at all postponements or adjournments thereof. The Company anticipates that mailing of the proxy material to its shareowners entitled to notice of and to vote at the Annual Meeting will commence on or about April 1, 1996. VOTING The presence, in person or by proxy in writing, of the holders of a majority of the outstanding shares of the Common Stock of the Company entitled to vote at the Annual Meeting shall constitute the quorum required before action can be taken at the Annual Meeting. In the absence of a quorum, the Annual Meeting may be adjourned. Only holders of record of Common Stock at the close of business on March 20, 1996 (the "Record Date") are eligible to vote at the Annual Meeting and at all postponements or adjournments thereof. The Company has furnished to each holder of Common Stock a proxy card upon which the names of three of the Company's Directors, George Bugliarello, John H. Talmage and Basil A. Paterson constituting the Proxy Committee, appear as proxies to vote as each shareowner directs on the card. If a shareowner wishes to give a proxy to someone other than the Proxy Committee, the shareowner may cross out the names of the members of the Proxy Committee appearing on the proxy card, insert the name or names of another person or persons (not more than three) and make, if necessary, other appropriate changes providing unambiguous instructions to the person or persons named. The Company reserves the right to limit the number of persons named as proxy by a shareowner who may attend the Annual Meeting. Proxies shall be voted in accordance with the instructions given by the shareowner. To be voted, properly signed and dated proxy cards should be: (i) received by mail prior to the Annual Meeting by The Corporation Trust Company, P.O. Box 631, Wilmington, Delaware 19899, the independent Inspector of Election for the Annual Meeting, or (ii) delivered in person at the Annual Meeting to representatives of the Inspector of Election. Shareowners who hold shares through a brokerage firm should return their proxy cards directly to that firm well in advance of the Annual Meeting for their shares to be voted. Each proxy card shows the number of shares of Common Stock registered in the shareowner's name as of the close of business on the Record Date. Each share of Common Stock is entitled to one vote at the Annual Meeting, except with respect to the election of Directors described on page three. If the shareowner is also a participant in the Company's Automatic Dividend Reinvestment Plan (the "ADRP"), the proxy card shows separately the number of shares of Common Stock held by the shareowner in the ADRP. The voting instructions given on the proxy card provide that any shares owned by the shareowner in the ADRP shall be voted in the same manner as the shares owned by the shareowner and registered in the shareowner's own name. If the shareowner is a participant in the ADRP and there are no shares registered in the shareowner's own name, the proxy card shows the number of shares credited to the shareowner's account in the ADRP. If the shareowner signs the proxy card without providing restrictions or instructions as to how the person or persons named are directed to vote with respect to any Item, or with respect to other matters which may properly come before the Annual Meeting on which the shareowner is entitled to vote, then the shares will be voted in accordance with the recommendations of the Board of Directors. The proxy confers discretionary authority to vote on certain matters related to the election of Directors, on matters incident to the conduct of the meeting, including adjournments thereof, and on any other matters that may come before the meeting. The New York Stock Exchange has informed the Company that all of the matters to be considered at this meeting are considered "discretionary" items upon which brokerage firms holding shares in street or nominee name may vote in their discretion on behalf of their clients if such clients have not furnished voting instructions ten days prior to the Annual Meeting. To ensure the presence of the required number of shares for voting, the Board of Directors urges all shareowners to mark, sign, date and return their proxy cards promptly. A shareowner who has mailed a proxy may also attend the Annual Meeting and vote in person. Shareowners attending the Annual Meeting whose shares are held through a bank or brokerage firm should bring with them evidence of their holdings, such as an account statement, and, in order to be eligible to vote, a validly executed and properly notarized power of attorney from such bank or brokerage firm. A shareowner may revoke a previously given proxy before it is exercised at any time prior to the closing of the polls at the Annual Meeting. The shareowner may revoke a proxy before it is exercised by writing to the Inspector of Election, c/o Corporate Secretary, 175 East Old Country Road, Hicksville, New York 11801, by submitting a later dated proxy (in either case, provided that the revocation is received prior to the Annual Meeting) or by voting in person at the Annual Meeting. ITEM ONE -- ELECTION OF DIRECTORS All Directors are elected annually by the cumulative voting method. Proxies given to members of the Proxy Committee pursuant to this solicitation will be voted cumulatively for the election of one or more persons named below to elect the maximum number of the Company's nominees or as otherwise directed. The holders of Common Stock are entitled to cast as many votes as shall equal the number of their shares held on the Record Date multiplied by the number of Directors to be elected by them, which, for the purposes of this election, would be eleven votes for each share. The votes may be cast for a single Director, for any number of them, or for all of the Directors in any manner that the shareowner may choose. Directors shall be elected by a plurality of the votes cast by the holders of shares entitled to vote in the election. Abstentions and votes not cast by brokers and nominees are not included for purposes of determining the number of votes cast, but are counted for purposes of determining whether a quorum is present at the meeting. Currently, all nominees are Directors. If elected, the eleven persons named below will hold office for one year or until their successors are duly elected or chosen and qualified. Should any of the persons hereinafter named advise the Corporate Secretary of the Company prior to the Annual Meeting that they will be unable to serve after being elected, the shares represented by proxy will be voted for the election of any substitute nominee or nominees as the present Board of Directors may recommend to the Proxy Committee. If no substitute is recommended, the size of the Board may be reduced. The Company does not anticipate that any of the nominees named herein for election by the holders of Common Stock will be unable to serve the full term of office to which they may be elected. The Company recommends a vote FOR the eleven persons named below to serve as members of the Board of Directors. The Company's nominees for election as Directors are: - -------------------------------------------------------------------------------- WILLIAM J. CATACOSINOS - Age 65 Chairman of the Board, Director since 1978 Chief Executive Officer LILCO shares owned 9,300 and President Board/Board committee attendance 100% Chairman-Executive Committee Chairman of the Board of Directors and Chief Executive Officer ("CEO") of the Company since January 1984; President of the Company from March 1984 to January 1987 and from March 1994 to present. 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 U. S. Life Corporation; Long Island Association; Business Alliance for a New, New York; First National Bank of L.I.; 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. Dr. Catacosinos is also a former member of the boards of Utilities Mutual Insurance Co.; Ketema, Inc.; Austin International Communications; the German American Chamber of Commerce; and Center for the Study of the Presidency. - -------------------------------------------------------------------------------- - -------------------------------------------------------------------------------- JOHN H. TALMAGE - Age 66 Partner, H. R. Talmage & Son Farm Director since 1982 Riverhead, New York LILCO shares owned 647* Board/Board committee Chairman-Nominating Committee attendance 100% Member-Executive Committee and the Compensation and Management Appraisal Committee Graduate of the College of Agriculture and Life Sciences, Cornell University. 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; 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 - Age 69 Partner, Law Firm of Director since 1983 Meyer, Suozzi, English and Klein, P.C. LILCO shares owned 1052* Board/Board committee Chairman-Audit Committee attendance 84% Member-Executive Committee 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. 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; member of the board of editors of the New York Law Journal; and member, New York State Commission on Judicial Nomination. - -------------------------------------------------------------------------------- *See Notes to Security Ownership Table - -------------------------------------------------------------------------------- GEORGE BUGLIARELLO - Age 69 Chancellor, Polytechnic University Director since 1990 LILCO shares owned 615* Chairman-Compensation and Management Board/Board committee Appraisal Committee attendance 81% Member-Executive Committee Received doctor of science degree in engineering from Massachusetts Institute of Technology and several honorary degrees from other institutions. President of Polytechnic University from 1973 to July 1994, 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. 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. Chairman, Board of Infrastructure and Constructed Environment, National Research Council. Previously held a NATO Senior Faculty Fellowship at the Technical University of Berlin and the chairmanship on the Committee on Science, Engineering and Public Policy of the American Association for the Advancement of Science. Former member of the Scientific Committee of the Summer School on Environmental Dynamics in Venice. - -------------------------------------------------------------------------------- GEORGE J. SIDERIS - Age 69 Retired Senior Vice President Director since 1991 Long Island Lighting Company LILCO shares owned 3,998* Board/Board Committee Member-Nominating Committee and attendance 100% Planning and Environment Committee Received bachelors degree in economics from New York University. Joined the Company 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. - -------------------------------------------------------------------------------- - -------- * See Notes to Security Ownership Table. - -------------------------------------------------------------------------------- A. JAMES BARNES - Age 53 Dean, Indiana University School Director since 1992 of Public and Environmental Affairs LILCO shares owned 615* Board/Board committee Chairman-Planning and Environment attendance 93% Committee Member-Compensation and Management Appraisal Committee Received undergraduate degree from Michigan State University and juris doctorate from Harvard Law School. 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. - -------------------------------------------------------------------------------- RICHARD L. SCHMALENSEE - Age 52 Director, Massachusetts Institute Director since 1992 of Technology Center for Energy LILCO shares owned 215* and Environmental Policy Research Board/Board committee attendance 93% Member-Compensation and Management Appraisal Committee and Planning and Environment Committee Received doctoral degree in economics and bachelor of science degree in economics, politics and science from the Massachusetts Institute of Technology ("MIT"). Visiting Professor at Harvard Business School from 1985 to 1986. Served as area head for Economics, Finance and Accounting at MIT's Sloan School of Management and as chairman of the School's Doctoral Program Committee prior to 1989. Served as member of the President's Council of Economic Advisors from 1989 to 1991. Currently director of the MIT Center for Energy and Environmental Policy Research. 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. - -------------------------------------------------------------------------------- - -------- * See Notes to Security Ownership Table. - -------------------------------------------------------------------------------- RENSO L. CAPORALI - Age 62 Senior Vice President of Government Director since 1992 and Commercial Marketing LILCO shares owned 1,160* Raytheon Company Board/Board committee attendance 73% Member-Audit Committee 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. 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 two Princeton University Advisory Councils. Former Chairman of the Aerospace Industries Association's Board of Governors and Executive Committee. Presently corporate Senior Vice President of Government and Commercial Marketing for the Raytheon Company. Member of the National Academy of Engineering. - -------------------------------------------------------------------------------- PETER O. CRISP - Age 63 President Director since 1992 Venrock, Inc. LILCO shares owned 1,115* Board/Board committee Member-Nominating Committee attendance 73% and Audit Committee Received bachelors degree from Yale University and masters degree in business administration from Harvard Business School. General Partner, Venrock Associates, a venture capital limited partnership, since 1969. Chairman, Venrock, Inc., the corporation which manages Venrock Associates, since 1980. Director of American Superconductor Corporation, Apple Computer, Inc., Evans & Sutherland Computer Corporation, Thermo Power Corporation, Thermedics Inc., Thermo Electron Corporation, ThermoTrex Corporation and U.S. Trust Corporation as well as a number of other private companies. Member of the boards of the Memorial Sloan Kettering Cancer Center and North Shore University Hospital. - -------------------------------------------------------------------------------- - -------- * See Notes to Security Ownership Table. - -------------------------------------------------------------------------------- KATHERINE D. ORTEGA - Age 61 Former Treasurer Director since 1993 of the United States LILCO shares owned 854* Board/Board Committee Member-Nominating Committee attendance 100% and Audit Committee Received bachelor of arts degree in business and economics from Eastern New Mexico University and three honorary doctor of law degrees and an honorary doctor of social science degree. 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 Diamond Shamrock, Inc., The Kroger Company, Ralston Purina Company, Paul Revere Corporation, Rayonier Inc. and Catalyst. Member of the Comptroller General's Consultant Panel. - -------------------------------------------------------------------------------- VICKI L. FULLER - Age 38 Senior Vice President Director since 1994 Alliance Capital Management LILCO shares owned 415* Corporation Board/Board Committee attendance 85% Member-Nominating Committee and Planning & Environment Committee Received bachelors degree at Roosevelt University and masters degree in business administration at the University of Chicago and is a Certified Public Accountant. 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. Member of the Board of Trustees of North Carolina Agricultural & Technology University. 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. - -------------------------------------------------------------------------------- - -------- * See Notes to Security Ownership Table. BOARD OF DIRECTORS The business and affairs of the Company are managed under the direction of its Board of Directors. The Board has responsibility for establishing broad corporate policies and for the overall performance of the Company rather than the day-to-day management of its operations. The Company's By-laws provide that the Board consist of not less than seven nor more than fifteen directors. The Company is saddened to report that Phyllis S. Vineyard, who initially joined the Company as a Director in 1974, recently passed away. Mrs. Vineyard was a valued member of the Board of Directors. The Company mourns the loss of a dear friend and colleague. Consequently, the number of directors, as may be fixed from time to time by the Board, is currently set at eleven. The Board of Directors, which generally meets every other month and conducts special meetings as required, met a total of 10 times during 1995. In addition, the various standing committees of the Board, which are described in greater detail below, met a total of 18 times in 1995. At the Board meetings, the directors generally discuss significant developments affecting the Company and take action on various matters including the declaration of dividends, the review and approval of the Company's corporate goals, business plans, earnings plan, expense and capital budgets and other financial and securities related matters. The Board also approves the annual report to shareowners, the annual report on Form 10-K and the proxy statement. In addition to attendance at Board and committee meetings, members of the Board are kept informed of the Company's business by various reports and documents sent to them each month, as well as by reports presented at meetings of the Board and its committees by officers and employees of the Company and other individuals, if required. Directors also perform their responsibilities throughout the year by numerous personal meetings and other communications, including frequent telephone conversations with the Chairman and other Directors regarding all matters of importance to the Company. Compensation Paid to Directors The annual retainer fee paid to each Director in 1995 was $25,000, except for Dr. Catacosinos who, as an Officer of the Company, does not receive compensation for serving as a Director. The fee paid to each Director who is not also an Officer of the Company for attending each meeting of the Board of Directors or of one of its committees was $500. The Company has entered into consulting agreements with Winfield E. Fromm, Lionel M. Goldberg and Eben W. Pyne, former Directors of the Company, naming them Consulting Directors. These agreements provide that each 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 plus an additional $500 for each Board or committee meeting attended. Consulting Directors do 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 compensation account. Each participating Director's account accrues interest, compounded quarterly, at the prime rate plus 1/2%. The Deferred Compensation Plan is unfunded and any accounts under the plan will be general obligations of the Company. Distributions from a deferred compensation account commence upon termination of membership on the Board of Directors, death or disability, or at a date previously designated 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. The Company has a Retirement Plan for Directors, providing benefits to Directors who are not or who have not been Officers of the Company. 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 plan), including by virtue of an acquisition of the Company's assets or stock, the value of vested benefits could be payable immediately. In addition to Dr. Bugliarello, who would be entitled to be paid a reduced benefit, each of the Company's Consulting Directors as well as Messrs. Paterson and Talmage would be entitled to be paid full benefits were they to cease to serve as Consulting Directors or Directors 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 the Company. The Company entered into an agreement in 1987 with Mr. Sideris, while he was an Officer of the Company, which provides retirement benefits supplementing the benefits to which he is entitled under the Company's Retirement Income Plan and Supplemental Death and Retirement Benefits Plan, both discussed below. The Company has established a trust, which is currently making payment of the retirement benefits. Notwithstanding the creation of the trust, the Company continues to be primarily liable. Pursuant to the New York Business Corporation Law and the Company's Bylaws, the Company 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. The Company has established a trust, the Long Island Lighting Company Officers' and Directors' Protective Trust, to fund the Company's obligations under these agreements. Committees of the Board of Directors The Board has established standing committees to assist it in performing its duties. The principal responsibilities of each committee are described below. Each committee reports to the Board all action taken either by written report or at a subsequent Board meeting. The Director biography portion of this Proxy Statement identifies the members of the various committees. The Executive Committee, which was composed of five members including Mrs. Vineyard, has the authority during the intervals between regular Board meetings to exercise all the powers of the Board, except for certain powers reserved exclusively to the Board, which includes the power to submit matters to shareowners for approval. The Executive Committee met six times during 1995. The Audit Committee, which met three times during 1995, is composed of four outside Directors and is responsible for the substantive review of the scope and results of the independent auditors' audit of the Company's financial statements, the internal audit activity of the Company and other pertinent auditing and internal control matters. The Audit Committee also recommends to the Board of Directors the appointment of outside auditors. The Nuclear Oversight Committee, which met two times during 1995, was composed of four members and was responsible for reviewing and assessing all of the nuclear activities of the Company. However, as a result of the Company's minimal involvement in nuclear activities, the Nuclear Oversight Committee was dissolved effective January 1, 1996. The Compensation and Management Appraisal Committee, which met three times during 1995, is composed of four outside Directors and is authorized to review and recommend to the Board of Directors compensation levels of the Company's Directors and Officers. In addition, this Committee reviews the procedures involved in establishing management compensation. The Nominating Committee consists of five members and determines criteria for qualification and selection of Directors and provides the Board of Directors with recommendations relating to the Director selection process. It evaluates possible candidates for the Board of Directors and assists in attracting qualified candidates. The Nominating Committee met two times during 1995. Shareowners wishing to recommend candidates for nomination to the Board of Directors should submit to the Corporate Secretary of the Company the name, a statement of qualifications and the written consent of the candidate. Recommendations may be submitted at any time and will be brought to the attention of the Nominating Committee. The Planning and Environment Committee, which met two times during 1995, consisted of five members including Mrs. Vineyard, and reviews the Company's general and environmental objectives, strategies and plans, considers and recommends various options and opportunities available to the Company for its long-term growth and development and monitors its progress toward the accomplishment of its goals. REPORT OF THE COMPENSATION AND MANAGEMENT APPRAISAL COMMITTEE ON EXECUTIVE COMPENSATION The disclosure contained in this section of the Proxy Statement shall not be deemed incorporated by reference into any prior filing by the Company pursuant to the Securities Act of 1933 or the Securities Exchange Act of 1934 that incorporate future filings or portions thereof (including this Proxy Statement 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 the Company's Officers and administers the Annual Performance Incentive Plan (the "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 1995, the Committee used the Hay Group ("Hay"), an outside consultant, to review the compensation levels of the Company's officers, including the named executive officers and also retained William M. Mercer, Inc. ("Mercer"), to provide advice with respect to incentive compensation arrangements. The Company's Human Resources office also supplied compensation comparisons to industry data. Executive Compensation Philosophy Historically, it has been the Company's practice of acknowledging the performance of its executives with a base-salary-only compensation program. However, general industry, and the utility sector in particular, have aggressively expanded the use of performance-based pay programs. As a result, comparisons made in December 1994, showed that the Company's base-salary-only executive compensation was approximately 30 percent below the average total cash compensation for general industry, 34 percent below such average for metropolitan New York companies and, 22 percent below such average for both national and regional utilities. In light of the foregoing, the Committee set as an objective its intention to review the use of incentives and other variable performance-based pay programs to link executive pay with enhancements to company performance and customer service and to ensure the attraction and retention of key executives. The Committee also considered the New York State Public Service Commission's (PSC's) position that executive compensation programs should be based on incentives designed to improve both executive and company performance in serving ratepayers. The Committee also took into account the findings of the PSC's Executive Compensation Study of New York State Utilities, issued in September 1994, which noted that LILCO was the only utility in New York State not providing an annual incentive plan. Based on this review, the Committee determined to introduce the Incentive Plan, with awards payable in 1996, based on performance goals for the calendar year 1995. Upon adoption of the Incentive Plan by the full Board of Directors in April 1995, officer base salaries were not increased and held at their April 1995 levels. As previously stated, this change to introduce an incentive plan reflects a recognition that incentive compensation programs that supplement base salary have become the norm in general industry and the utility sector. Accordingly, LILCO's performance-based compensation program provides incentives for the achievement of goals designed to benefit the Company's ratepayers and shareholders. Notwithstanding the adoption of the Incentive Plan, during 1995 LILCO continued to remain one of the few utilities in its peer groups without a long-term executive incentive compensation plan. Because of the absence of such a plan, the Compensation Committee concluded, after a review of this issue with its outside consultants, that the total compensation for the Company's executives in 1995 will be significantly below that of the industry. Therefore, the Compensation Committee recommended and the Company's Board adopted a long-term incentive plan for its executives to take effect beginning January 1996. The provisions of the long-term plan are discussed in greater detail elsewhere in this Proxy Statement. Determination of Base Salary Levels The Committee annually approves adjustments to base salary ranges using external comparisons. The comparisons include the average compensation paid to the comparable executives of four databases provided by Hay for general industry, metropolitan New York companies, national utilities and nine Northeast utility companies (the "Hay Group Utilities"). Two of the Hay Group Utilities are also included in the Standard & Poor's Electric Utility Index shown in the performance graph on page 13. In addition to compensation levels among the Hay databases, the Committee also reviews the results of the Edison Electric Institute's Annual Compensation Survey of 118 utilities (the "EEI Utilities") as well as the compensation paid to the officers of other New York utilities. 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, the executive's individual accomplishments during the year and the length of time in his or her position. However, upon the introduction of the Incentive Plan, officer base salaries were not increased and held at their April 1995 levels reflecting the philosophy to pay a greater percentage of the Company's executive compensation through performance incentives. Annual adjustments granted prior to the freeze on base salaries in April of 1995 to the Executive Officers named in the compensation table on Page 14, other than Dr. Catacosinos, including increases associated with promotions and taking on additional responsibilities, ranged from 0.0 percent to 8.9 percent, or an average of 5.2 percent. Notwithstanding these adjustments, the 1995 base salaries earned by the named executive officers in the Summary Compensation Table fell to 7.6 percent below comparable base salaries among the Hay Group Utilities. The Annual Performance Incentive Plan In April 1995 the Board of Directors, upon the recommendation of the Committee, established the Incentive Plan for the officer group, payable in 1996, based on performance achieved for the calendar year 1995. As discussed above, the Incentive Plan was implemented to ensure that the Company's compensation program remains competitive to attract and retain key executive talent and reward outstanding contributions. All officers, including the Chief Executive Officer, have been selected as participants in the plan, and awards are to be paid in cash following the close of the year. The Incentive Plan is designed to reward current performance by providing cash compensation comparable to certain competitive market benchmark levels for similar positions, which were provided by Mercer. The Incentive Plan is based on the achievement of two quantifiable objectives, reducing expenditures and maintaining or improving ten critical service goals. If threshold levels are not achieved for either objective, no incentive will be paid. The target incentive payment -- the amounts that will be paid if predetermined performance levels are attained for all program targets -- range from 10 to 25 percent of the midpoint for the base salary range of each position, which is dependent upon the executive's level in the organization. Seventy-five percent of each individual's payment is based on the level of achievement of the two corporate objectives. The balance of each award, which can be zero, 25 or 50 percent of the target incentive payment, is then subjectively determined based on each individual's contribution toward helping the Company achieve its objectives. In May 1996, the Committee will review the targets or thresholds achieved and consider each individual officer's contribution, in order to determine any incentive awards to be paid under the Incentive Plan. CEO Compensation At the end of 1994, Dr. Catacosinos' performance was reviewed by the Board. Based on compensation market and performance factors described below, the Board approved an annual compensation increase of 9.5 percent. However, for various reasons, Dr. Catacosinos requested in February 1995 that his salary be returned to its 1994 level. Although the Board felt that the increase was justified and well-deserved, Dr. Catacosinos' request was accepted. The 1995 salary reported for Dr. Catacosinos in the Summary Compensation Table on Page 14 includes the effect of two months at the higher salary rate. In recommending this 1994 annual compensation increase for Dr. Catacosinos, the Committee recognized his taking on the additional responsibilities as President and the effectiveness of the strategies and initiatives being used to address competitive factors impacting the electric and gas industries. Throughout the year, the Company pursued an aggressive program to contain operating and maintenance expenses as well as capital expenses. As a result, budget targets were underrun by 6.0 percent. In addition, positive net cash flow of $150 million was achieved and the Company's ability to meet financing obligations was improved. The debt to equity ratio improved from 65.0 percent to 62.5 percent, 5.1 million shares of common stock were issued at book value and the weighted average cost of debt continued to decrease to 8.7 percent. Workforce reductions continued through attrition, amounting to 268 for 1994 and totaling 598 since 1990, or a 9% personnel reduction, by the end of 1994. Market comparisons showed that of the nine other EEI Utilities with annual revenues between $2 and $3 billion, Dr. Catacosinos 1994 base salary was $578,820 while the 1994 average total compensation, which includes bonuses and other incentive awards paid to the CEO's of these companies, was $694,351. In 1994, LILCO was the only company in this revenue group with neither an annual nor long-term executive incentive plan. Dr. Catacosinos' total compensation for 1994 remained 16 to 33 percent below the total cash compensation (base salary and annual incentive) and 34 to 52 percent below the total direct compensation (base salary and annual and long-term incentives) of CEO's in all Hay databases. Certain Tax Matters Generally, Section 162(m) of the Internal Revenue Code limits tax deductions for executive compensation to $1 million. Section 162(m) was not applicable in 1995 to the compensation of the executives named in the Summary Compensation Table. 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 Long Island Lighting Company, the Standard & Poor's 500 Composite Stock Index ("S&P 500") and the S&P Electric Utilities Index ("S&P ELEC") over the past five-year period. The graph assumes a $100 initial investment on December 31, 1990, and a reinvestment of dividends in Long Island Lighting Company and each of the companies reported in the indices. Comparison of 5 Year Cumulative Total Return LILCO vs. S&P 500 and S&P Electric Utilities
LILCO S&P 500 S&P ELEC 1990 $100 $100 $100 1991 $123 $130 $130 1992 $138 $140 $137 1993 $139 $154 $155 1994 $ 97 $156 $134 1995 $116 $215 $177
COMPENSATION PAID TO EXECUTIVE OFFICERS Summary Compensation Table: The following table illustrates the compensation paid by the Company during the past three years to each of its most highly compensated Executive Officers:
Annual Compensation Long Term Compensation ------------------- ---------------------- Name and Other Restricted Payouts- Principal Annual Stock Options/ LTIP All Other Position Year Salary Bonus Compensation Award(s) SARs (#) Payouts Compensation Or Number in Group ($)(1) ($)(2) ($) ($) ($) ($)(3) - ---------------------------------------------------------------------------------------------------------------------------- William J. 1995 587,976(4) 0 n/a* 0 0 0 15,184 Catacosinos -CEO 1994 579,654(4) 0 n/a 0 0 0 12,303 and President 1993 534,370(4) 0 n/a 0 0 0 13,854 - ---------------------------------------------------------------------------------------------------------------------------- James T. Flynn - 1995 255,500 0 n/a 0 0 0 3,725 COO and 1994 235,178 0 n/a 0 0 0 2,116 Executive Vice 1993 212,788 0 n/a 0 0 0 4,350 President - ---------------------------------------------------------------------------------------------------------------------------- Leonard P. 1995 176,250(5) 0 n/a 0 0 0 883 Novello -General 1994 n/a 0 n/a 0 0 0 n/a Counsel 1993 n/a 0 n/a 0 0 0 n/a - ---------------------------------------------------------------------------------------------------------------------------- Edward J. 1995 172,000 0 n/a 0 0 0 650 Youngling - 1994 169,512 0 n/a 0 0 0 591 Senior Vice 1993 142,413 0 n/a 0 0 0 1,305 President - Electric Business Unit - ---------------------------------------------------------------------------------------------------------------------------- Anthony 1995 169,083 0 n/a 0 0 0 487 Nozzolillo - 1994 157,678 0 n/a 0 0 0 423 Senior Vice 1993 129,413 0 n/a 0 0 0 770 President- Finance ============================================================================================================================
* n/a - Not Applicable. Notes to Summary Compensation Table: (1) The Company has in place a 401(k) Capital Accumulation Plan, which qualifies for favorable tax treatment under the Internal Revenue Code of 1986. This plan is designed to provide for salary reduction contributions by participants under Section 401(k) of the Internal Revenue Code 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 the Company 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. (2) The amounts payable under the Incentive Plan have not yet been finally determined by the Compensation and Management Appraisal Committee and no amounts have been paid to the Executive Officers. (3) The Company 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. Plan compensation is defined as the highest salary including any incentive earned pursuant to the Incentive Plan. The cost of life insurance, paid by the Company for coverage under this Plan, is included in All Other Compensation for each of the individuals listed. During a portion of 1993 insurance coverage was provided by a group term life insurance policy. During the remaining portion of 1993 and for each subsequent year, insurance coverage for these death benefits was provided by split-dollar life insurance policies on the life of each plan participant. The cost of the term insurance for a portion of 1993 represents the average premium cost charged to the Company for all participants in the Supplemental Death and Retirement Benefits Plan. The amount shown for each participant represents, for the balance of 1993 and for each subsequent year, the amount allocated to such participant for income tax purposes. (4) A portion of Dr. Catacosinos' salary in each of these years has been deferred at his request and is reflected in the amounts shown. (5) 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. Supplemental Death and Retirement Benefits Plan: Officers and certain other senior management employees eligible to participate in the Company's Supplemental Death and RetirementBenefits 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 salary including any incentive earned pursuant to the 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. If a vested participant retires prior to age 65, reduced benefits are payable. The projected value of the annual retirement benefits payable under the Supplemental Death and Retirement Benefits Plan utilizing the 15-year certain retirement income payment election for each of the individuals listed in the Summary Compensation Table at normal retirement age, 65, based upon compensation in effect for 1995, are as follows: Dr. Catacosinos, $158,452; Mr. Flynn, $64,750; Mr. Novello, $32,250; Mr. Youngling, $25,800; and Mr. Nozzolillo, $25,500. The terms of Dr. Catacosinos' employment agreement, discussed below, provide for his continued employment beyond normal retirement age. In addition, Dr. Catacosinos has made an assignment of his rights to death benefits and therefore will not receive the monthly retirement benefits under this Plan. The Company recognizes the cost of these benefits, which are borne by the Company's shareowners, as an expense on its income statements for each year. The Company has also established a trust to provide for payments of its obligations to the participants in the Supplemental Death and Retirement Benefits Plan. Notwithstanding the creation of the trust, the Company continues to be primarily liable for the death or retirement benefits payable to the participants and is currently making such payments to such retired participants. Retirement Income Plan: Generally, all Company employees (except certain leased and part-time employees) are eligible for inclusion in the Retirement Income Plan upon completion of one year of employment with the Company. 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 the Company'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 1995.
Annual Credited Normal Retirement Service as Retirement Benefit(1) of 12/31/95 Date ---------- ----------- ---- William J. Catacosinos $126,967 11 years 11 April 1, 1995(2) months James T. Flynn $ 57,268 9 years 3 January 1, 1999 months Leonard P. Novello $ 63,156 0 years 9 January 1, 2006 months Edward J. Youngling $124,178 27 years 9 August 1, 2009 months Anthony Nozzolillo $119,130 23 years 6 September 1, 2013 months
(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. The Company 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 the Company's Retirement Income 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, the Company's Retirement Income Restoration Plan would provide payment of plan formula pension benefits which exceed those payable under the Code's maximum limitations. For 1995 the maximum benefit limit set by Section 415 and applicable to the amounts shown above was $120,000. For 1995 the maximum compensation limit set by Section 401(a)(17) and applicable to the amounts shown above was $245,000. For 1996 the maximum benefit limit set by Section 415 is $120,000 and the maximum compensation limit set by Section 401(a)(17) and to be utilized for benefits accrued in 1996 is $250,000. (2) Dr. Catacosinos' employment agreement, discussed below, provides for his continued employment beyond his normal retirement date. Agreements with Executives: The Company 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 the Company. 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 the Company'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; and (iii) continuation of life, medical and dental insurance for a period of three years. The costs associated with these arrangements will be borne by the Company's shareowners. Notwithstanding the creation of a trust to support payment of its obligations, the Company 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 the Company does not. 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 the Company until January 31, 1997. 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 the Company for cause or for such other reason as the Board of Directors may, in good faith, determine to be in the best interests of the Company and by Dr. Catacosinos if he determines it to be in the best interests of the Company or for any reason after a change in control. The Contract also provides for vested Contract Retirement Benefits commencing at the 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. The Contract Retirement Benefits in any year will be reduced by monthly benefits payable under the Company's other retirement plans. 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 the Company including service as a Director, employee or consultant. The benefit is also subject to certain annual cost of living adjustments. Assuming his retirement upon expiration of the Contract on January 31, 1997, the amount of the estimated retirement benefit payable under the Contract to Dr. Catacosinos as of January 1, 1998 (assuming continuation of his current salary) would be approximately $828,000. The Company has established trusts to provide for payments of its obligations under the Contract, the costs of which are borne by the Company's shareowners. Notwithstanding the creation of the trusts, the Company continues to be primarily liable for all amounts payable to Dr. Catacosinos and the trusts will make such payments to the extent that the Company 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 the Company or its affiliates other than those described herein. SECURITY OWNERSHIP OF MANAGEMENT The table below shows the number of shares* of the Company's Common Stock beneficially owned, as of February 29, 1996, by each Director, each Officer listed in the Summary Compensation Table, 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 0.05% 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.
Name Number of Shares* ---- ----------------- A. James Barnes.................................... 615 George Bugliarello................................. 615 Renso L. Caporali.................................. 1,160 William J. Catacosinos............................. 9,300 Peter O. Crisp..................................... 1,115 James T. Flynn..................................... 1,819 Vicki L. Fuller.................................... 415 Leonard P. Novello................................. 0 Anthony Nozzolillo................................. 120 Katherine D. Ortega................................ 854 Basil A. Paterson.................................. 1,052 Richard L. Schmalensee............................. 215 George J. Sideris.................................. 3,998 John H. Talmage.................................... 647 Edward J. Youngling................................ 1,235 All Directors and Officers as a group, including those named above, a total of 28 persons........... 27,715
* The number of shares includes whole shares held under the Company's ADRP and for Mr. Talmage includes 287 shares held or beneficially owned by a spouse, parent or child for which beneficial ownership is disclaimed. In addition, the number of shares shown for each Director, other than Dr. Catacosinos, includes 115 stock units, which do not confer any voting rights, credited pursuant to the Director's Stock Unit Retainer Plan discussed in greater detail elsewhere in this Proxy Statement. The following table sets forth certain information with respect to the shares of Preferred Stock and Common Stock owned by each person known by the Company to be the beneficial owner of more than 5% of such Preferred Stock and Common Stock as of December 31, 1995.
Title of Percentage Class Names and Address Owned of Class ----- ----------------- ----- -------- Common Stock The Capital Group, Inc. 10,510,000 8.8% 333 South Hope Street Los Angeles, CA 90071 Common Stock Franklyn Resources, Inc. 6,492,125 5.4% 777 Mariners Island Blvd. P.O. Box 7777 San Mateo, CA 94404
The Company has not been advised, nor is it aware, of any additional shares to which anyone has the right to acquire beneficial ownership. The Company 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 the Company's equity securities. Based on information provided to the Company by such persons, all Company Officers and Directors made all required filings during the fiscal year ended December 31, 1995. The Company does not know of any person beneficially owning more than 10% of a class of equity securities. 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 the Company, 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, the Company 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 the Company's Directors and Officers under certain circumstances when the Company has not previously provided indemnification. The Company has D&O liability insurance which it has purchased from Associated Electric & Gas Insurance Services Ltd. ("AEGIS"), Energy Insurance Mutual ("EIM"), Columbia Casualty, Steadfast Insurance Company, A.C.E. Insurance Company and XL Insurance Company, all with the effective date of August 26, 1994. The Company also has liability insurance effective July 1, 1994 purchased from AEGIS and EIM, which provides fiduciary liability coverage for the Company, its Directors, Officers and employees for any alleged breach of fiduciary duty under ERISA. The total annual premium for all these coverages was $1,555,457 in 1995. The Company's 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 By-laws authorize the Board of Directors to grant indemnity rights to employees and other agents of the Company. 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 Bylaws authorized the Board of Directors to enter into indemnification agreements with any of the Company's Directors or Officers extending rights to indemnification and advancement of expenses to such person to the fullest extent permitted by applicable law. The Company 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, the Company has also established a trust to fund the Company's obligations under the agreements. The Company's Restated Certificate of Incorporation (the "Certificate of Incorporation") 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 Certificate of Incorporation 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 Certificate of Incorporation provides protection to Directors only and does not affect the liability of Officers of the Company for breaches of the fiduciary duties of care and loyalty. ITEM TWO -- APPOINTMENT OF INDEPENDENT AUDITORS Ernst & Young LLP, 395 North Service Road, Melville, New York, audited the Company's 1995 financial statements. Audit related services performed by Ernst & Young LLP for 1995 consisted principally of the audit of the financial statements of the Company, the review of the unaudited quarterly financial statements and assistance and consultation in connection with filings with the SEC and the Federal Energy Regulatory Commission and in connection with the issuance of all securities. A representative of Ernst & Young LLP will be present at the Annual Meeting, shall have the opportunity to make a statement if he or she desires to do so and will be available to answer questions by shareowners concerning the financial statements of the Company. The appointment of auditors is approved annually by the Board of Directors and is subsequently submitted to the shareowners for ratification. The decision of the Board of Directors is based upon the recommendation of the Audit Committee of the Board of Directors. The Director biography portion of this Proxy Statement identifies the members of the Audit Committee. In making its recommendation, the Audit Committee reviews the audit scope for the coming year. The Board of Directors has, subject to ratification by holders of the outstanding shares of the Company's Common Stock, appointed Ernst & Young LLP as independent auditors for the year 1996. Ratification requires a favorable vote by a majority of the votes cast at a meeting of the holders of shares entitled to vote on the proposal. Abstentions and votes not cast by brokers and nominees are not included. Accordingly, the following resolution, identified on the proxy card as Item Two, will be proposed for ratification by such shareowners at the Annual Meeting: RESOLVED, that the appointment of Ernst & Young LLP by the Board of Directors of Long Island Lighting Company as independent auditors to audit the Company's 1996 financial statements and to perform other appropriate accounting services, is hereby ratified. The Board of Directors of the Company recommends a vote FOR Item Two to ratify the appointment by the Board of Directors of Ernst & Young LLP as independent auditors of the Company for 1996. ITEM THREE -- APPROVAL OF DIRECTORS' STOCK UNIT RETAINER PLAN Effective January 1, 1996, the Company's Board of Directors adopted a Directors' Stock Unit Retainer Plan (the "Plan"). The purpose of the Plan is to provide a method for Directors and Consulting Directors who are not currently employees of the Company (the "Participants") to acquire a proprietary interest in the Company and to better solidify the common interests of Directors and shareowners in enhancing the value of the Company's common stock. The Plan, as modified by the Board in February 1996, provides that in lieu of receiving all of their annual retainer in cash, at least fifty percent of the Participants' retainer is to be applied toward the purchase of stock units(1). In the future, Participants may elect to contribute up to 100 percent of their retainers and fees towards the purchase of stock units. The principal features of the Plan are summarized below. The summary is qualified in its entirety by reference to the complete text of the Plan, which is attached hereto as Appendix A. The Plan changes the manner in which Participants receive their retainer, but generally does not alter the amount of their compensation. Prior to the effective date of the Plan, all retainers were paid to Participants in cash on a quarterly basis. Under the Plan, fifty percent of each Participant's quarterly retainer will be credited to a stock unit account. In the future, Participants may be permitted to increase the percentage of their retainer to be credited to their account by entering into an individual agreement of deferral with the Company. However, this election must be irrevocably made at least six months prior to the time that such increased amount of retainer is credited to the stock unit account. Under the Plan, the value of the units which will be credited to each Participant'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 the Company's 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. - -------- (1)Prior to modifications that took effect on April 1, 1996, the Plan provided that thirty percent of the Participants' retainer be applied toward the purchase of stock units. The amounts accumulated pursuant to the Plan will be held for the benefit of each Participant, until such time as (i) the Participant ceases to serve as a Director or Consulting Director; (ii) the Participant's death; or (iii) a change in control of the Company shall have occurred. For purposes of the Plan, a change in control is defined to include: (i) the acquisition, directly or indirectly, by any person, as such term is used in Section 13(d) and 14(d) of the Securities Exchange Act of 1934 (the "Exchange Act"), of forty percent or more of the combined voting power of the Company's then outstanding securities; (ii) a merger or consolidation of the Company where the Company is not the surviving corporation or where a change in the Company's outstanding common stock occurs; (iii) a sale of all or substantially all of the Company's assets or all or substantially all of the assets acquired for or used in the electric utility business, including, in either case, by virtue of a condemnation proceeding; (iv) the liquidation or dissolution of the Company; or (v) the turnover of more than a majority of the Company's Board of Directors during a two year period without two-thirds approval of certain Directors. If the Participant so elects, the aggregate value of the stock units accumulated pursuant to the Plan may be received in certificated shares of the Company's common stock at the time of distribution. The Participant may elect to receive a distribution of Plan benefits in a lump sum or in ten annual installments. Any such shares shall be purchased by the Company on the open market or shall be taken from shares of common stock previously acquired by the Company and held in its treasury. Prior to distribution, a Participant shall have no voting or other rights of a shareholder with respect to such stock units. However, each Participant's account will be credited with an amount equal to the amount of any dividends paid on shares of the Company's common stock proportionate to the number of stock units accumulated pursuant to the Plan prior to such dividend payment date. Amounts so credited shall be applied toward the purchase of an additional number of stock units. The Board may discontinue the Plan at any time. The Plan may also be amended from time to time, provided that no amendment will be made without shareowner approval if such approval is necessary to continue to comply with Rule 16b-3 of the Exchange Act. Consent of each Participant is required to reduce or alter a stock unit account in a manner unfavorable to such Participant. The Company believes that the Plan will assist it in solidifying common interests of directors and shareowners in enhancing the value of the Company's common stock. The Plan is not intended to further compensate Participants, but rather to better align the form of their compensation with the overall financial performance of the Company consistent with the general Company movement towards performance-based compensation. In order to, among other things, qualify for an exemption from certain provisions of the Exchange Act that generally govern the acquisition and disposition of the stock units and their underlying shares, the Plan must be approved by the affirmative vote of a majority of the shares of common stock present or represented and entitled to vote at the Annual Meeting. Proxies solicited by the Board will be voted for approval of the Plan, unless shareowners specify a contrary choice in their proxies. Votes not cast by brokers and nominees are not included in the vote total, while abstentions have the same effect as a vote against the Directors' Stock Unit Retainer Plan. The Board of Directors of the Company recommends a vote FOR approval of the Directors' Stock Unit Retainer Plan. ITEM FOUR -- APPROVAL OF THE OFFICERS' LONG-TERM INCENTIVE PLAN On December 14, 1995, the Company's Board of Directors adopted an Officers' Long-Term Incentive Plan, (the "Incentive Plan"). The purpose of the Incentive Plan is to advance the interests of the Company and its shareowners by motivating the Officers of the Company to assist the Company in meeting and exceeding its business goals, focusing particularly on the long-term effects of their actions, and to provide incentives toward continued service to the Company. The principal features of the Incentive Plan are summarized below. The summary is qualified in its entirety by reference to the complete text of the Incentive Plan, which is attached as Appendix B. Awards may be made under the Incentive Plan to all employees who are Officers of the Company (the "Participants"). Approximately 20 persons are eligible to participate currently in the Incentive Plan. The Incentive Plan will be administered by the Compensation and Management Appraisal Committee of the Board of Directors (the "Committee"). The Committee is, among other things, authorized to determine the size of awards and the terms and conditions of awards consistent with the Incentive Plan. Awards made under the Incentive Plan will be paid only upon the attainment of such financial performance goal or goals as are set by the Committee. In general, the goals are to be attained over a period of three calendar years, with a new cycle beginning every two years (the "Performance Period"). However, the initial incentive Performance Period will be two years (1996-1997). The awards payable to Participants upon the attainment of specified minimum, target and maximum results over the Performance Period are a specified percentage per year as determined by the Board per plan year of the midpoint of the individual Participant's salary range. Awards will be paid in two installments and will be made solely in Company common stock. Fifty percent of the award will be distributed in the next calendar year after the end of the Performance Period. The remaining fifty percent will be subjected to a mandatory one-year deferral period. With the exception of termination due to death, disability, retirement or change in control as defined in the Incentive Plan, a Participant must be employed by the Company on the date each installment of the award is paid to be eligible to receive the award. Pro-rata awards, as approved by the Committee, may be made in the event of death, disability, retirement or change in control prior to the completion of a Performance Period. Subject to certain conditions, a Participant may defer all or part of an award. All amounts accumulated and unpaid under the Incentive Plan must be paid by the Company in a lump sum within fifteen days of a change in control, as defined in the Incentive Plan. The Board or the Committee may terminate or suspend the Incentive Plan, in whole or in part, from time to time and may amend the Incentive Plan from time to time to correct any defect or supply any omissions or reconcile any inconsistency in the Incentive Plan or in the awards made thereunder that does not constitute the modification of a material term of the Incentive Plan. However, no amendment will be made without shareowner approval if such approval is necessary to continue to comply with Rule 16b-3 of the Exchange Act and no amendment may be made that would adversely affect in a material way an award previously granted under the Incentive Plan, without the written consent of the Participant. In order to, among other things, qualify for an exemption from certain provisions of the Exchange Act that generally govern the acquisition and disposition of stock awarded under the Incentive Plan, the Incentive Plan must be approved by the affirmative vote of a majority of the shares of common stock present or represented and entitled to vote at the Annual Meeting. Proxies solicited by the Board will be voted for approval of the Incentive Plan, unless shareowners specify a contrary choice in their proxies. Votes not cast by brokers and nominees are not included in the vote total, while abstentions have the same effect as a vote against the Incentive Plan. The Board of Directors of the Company recommends a vote FOR approval of the Officer's Long-Term Incentive Plan. ADDITIONAL INFORMATION Other Business It is not anticipated that any business not otherwise discussed in this Proxy Statement will be presented at the Annual Meeting, and the Board was not aware, a reasonable time prior to this solicitation of proxies, of any other matters which may properly be presented for vote at the meeting. Should any other matter be presented at the Annual Meeting (including a proposal submitted by a shareowner that has been omitted from this Proxy Statement in accordance with the SEC's proxy regulations), the Proxy Committee will have discretionary authority to vote all proxies as they deem appropriate. 1997 Shareowner Proposals Proposals of shareowners intended to be presented at the 1997 Annual Meeting must be received by the Company at its offices at 175 East Old Country Road, Hicksville, New York 11801, Attention: Corporate Secretary, not later than December 2, 1996. Proposals must comply with the SEC's proxy regulations relating to shareowner proposals in order to be considered for inclusion in the Company's proxy materials. Outstanding Voting Stock On February 29, 1996, there were 119,954,038 shares of Common Stock, 1,418,043 shares of Preferred Stock, $100 par value, and 22,658,000 shares of Preferred Stock, $25 par value, issued and outstanding. Holders of shares of Preferred Stock are not entitled to vote on any of the matters to be considered at this Annual Meeting. Holders of shares of Common Stock may vote on all matters. The stock books will not be closed. Solicitation of Proxies Proxies may be solicited in person, by mail, by telephone, by telegraph or telefax. The cost of solicitation of Company proxies, which includes the preparation, printing and mailing of the Notice of Annual Meeting of Shareowners, the proxy statement and the proxy card, is to be borne by the Company. Arrangements will be made with brokers and other custodians, nominees and fiduciaries to forward the Company's solicitation materials to the beneficial owners of stock held of record and the Company will reimburse them for reasonable out-of-pocket expenses incurred. In addition, the Company has retained D. F. King & Co., Inc., 77 Water Street, New York, New York 10005, to assist in the solicitation of proxies for a fee estimated at $10,000 plus reasonable out-of-pocket expenses. In addition to D. F. King & Co., Inc., regular employees of the Company may solicit proxies for which no additional compensation will be paid. Other Information Financial statements for the Company are attached as Appendix C to this Proxy Statement and are included in the Company's Annual Report on Form 10-K filed with the Securities and Exchange Commission, 450 Fifth Street, N.W., Washington, D.C. 20549, and the New York and Pacific Stock Exchanges. The Company is subject to the informational requirements of the Securities Exchange Act of 1934, as amended, and in accordance therewith files reports and other information with the SEC. Information as of particular dates concerning Directors and Officers of the Company, their remuneration and any material interest of such persons in transactions with the Company is disclosed in proxy statements distributed to shareowners of the Company and filed with the SEC. Such reports, proxy statements and other information can be inspected and copied at the public reference facilities of the SEC at Judiciary Plaza, 450 Fifth Street, N.W., Washington, D.C. 20549, and at the SEC's regional offices at 500 West Madison Street, Chicago, Illinois 60661 and at Seven World Trade Center, Suite 1300, New York, New York 10048. Copies of such materials can be obtained from the Public Reference Section of the SEC at Judiciary Plaza, 450 Fifth Street, N.W., Washington, D.C. 20549, at prescribed rates. In addition, certain securities of the Company are listed on the New York Stock Exchange and the Pacific Stock Exchange where reports, proxy statements and other information concerning the Company may be inspected. A copy of the Company's Annual Report on Form 10-K filed with the SEC is available without charge to shareowners upon written request to Investor Relations, Long Island Lighting Company, 175 East Old Country Road, Hicksville, New York 11801. Exhibits to the Company's Annual Report on Form 10-K filed with the SEC will be furnished upon payment of 25 cents per page. LONG ISLAND LIGHTING COMPANY /s/ Kathleen A. Marion KATHLEEN A. MARION CORPORATE SECRETARY APPENDIX A DIRECTORS' STOCK UNIT RETAINER PLAN OF LONG ISLAND LIGHTING COMPANY Effective January 1, 1996, the Board of Directors of the Long Island Lighting Company adopted the Directors' Stock Unit Retainer Plan upon the recommendation of the Compensation and Management Appraisal Committee. The terms of the Plan are set forth below. 1. Purpose The purpose of the Plan is to provide a method for Directors and Consulting Directors, who are not currently employees of the Company, to acquire a proprietary interest in the Company and to better solidify the common interest of directors and shareowners in enhancing the value of the Company's common stock. 2. Participation Directors or Consulting Directors of the Company, other than individuals who are employees of the Company, shall participate in the Plan on the Effective Date. All future Directors or Consulting Directors of the Company shall commence participation in the Plan immediately upon becoming a Director or Consulting Director. Employee Directors are not eligible to participate in this Plan. 3. Definitions The following terms as used herein shall have the following meanings: (a) "Board" or "Board of Directors" shall mean the Board of Directors of the Long Island Lighting Company. (b) "Change of Control" shall mean (i) the acquisition directly or indirectly by any person as such term is used in Section 13(d) and 14(d) of the Securities Exchange Act of 1934 (the "Exchange Act), or forty percent or more of the combined voting power of the Company's then outstanding securities; (ii) a merger or consolidation of the Company where the Company is not the surviving corporation or where a change in the Company's outstanding common stock occurs; (iii) a sale of all or substantially all of the Company's assets, or all or substantially all of the assets acquired for or used in the electric utility business including, in either case, by virtue of a condemnation proceeding; (iv) the liquidation or dissolution of the Company; or (v) the turnover of more than a majority of the Company's Board of Directors during a two year period without two-thirds approval of certain directors. (c) "Company" or "LILCO" shall mean Long Island Lighting Company, the sponsor of this Plan, and its successor and assigns. (d) "Effective Date" shall mean January 1, 1996. (e) "Participant" or "Member" shall mean a member of the Plan who satisfies the participation requirements set forth in Section 2. (f) "Plan" shall mean the Directors' Stock Unit Retainer Plan of Long Island Lighting Company, as set forth herein, and as may be amended from time to time. (g) "Retainer" shall mean the remuneration as determined by the Board to be paid to a Participant in consideration of such Participant's service to the Company as a Director or Consulting Director, but shall not include any amounts received either as reimbursement for expenses or as payment for attending scheduled or special meetings of the Board or any of its Committees, or paid for consulting or other services pursuant to an individual contract for non-director services. 4. Stock Unit Account (a) Fifty percent (50%) (and prior to April 1, 1996 thirty percent) of the Retainer of each Member, otherwise payable in cash, shall be credited on a quarterly basis to an account in the name of such Member, as of the date the cash portion of the Retainer is or would otherwise be paid. Cash so credited shall be credited to the purchase of stock units. Each stock unit shall be in the form of an unfunded bookkeeping entry and shall represent one share of the common stock of the Company. No shares of common stock or certificates thereof shall be held under the Plan. Any shares of stock issued and distributed pursuant to Section 5 shall be purchased by the Company on the open market, or shall be taken from shares of common stock previously acquired by LILCO and held in its treasury. (b) The number of stock units credited pursuant to Section 4(a) shall be determined by reference to the closing price per share of LILCO common stock reported on New York Stock Exchange Composite Transactions on the first trading day of the calendar month in which such credit shall have occurred, such stock units to be computed to four decimal places. (c) The stock unit account of each Member will be credited as of the pertinent date with a Dividend Equivalent in the amount of any cash dividends declared and paid from time to time in respect of LILCO's issued and outstanding common stock for each unit or fraction of a unit in the Member's stock unit account as of such date. (d) Dividend Equivalents as described in paragraph (c) above shall be credited to the Member's stock unit account as of the dividend payment date in the form of as many additional stock units (and any fractions of a unit computed to four decimal points) as could be purchased with such Dividend Equivalents based on the closing price per share of LILCO's common stock reported on New York Stock Exchange Composite Transactions on such dividend payment date or if no trading occurs on such stock on the dividend payment date, on the trading day immediately preceding such date. (e) In the event that the number of outstanding shares of LILCO common stock shall be changed by reason of stock split-ups, combinations, recapitalizations, mergers, consolidations, spin-offs or the like, the Board shall make such adjustments as it deems appropriate in the number of units credited to the stock unit accounts of Members hereunder. 5. Form and Timing of Payment Except as provided pursuant to Section 7(e), no payments shall be made to Participants prior to termination of service as a Director or Consulting Director of the Company, death, or Change of Control. The amount to be paid upon distribution shall be the fair market value determined by reference to the closing price per share reported on New York Stock Exchange Composite Transactions on the date of payment of the stock units accumulated in each Participant's stock unit account. Payment shall be made in a lump sum in cash or shares of common stock of the Company as elected by the Participant as soon as administratively practicable after the event that determines the Participant's right to receive payment. A Participant may elect payment in 10 annual installments, in which case his or her stock unit account will be valued as of the end of the calendar month after such election, and shall thereafter be credited with interest at the rate of 6% per annum until all amounts due hereunder are paid. 6. Amendment and Termination The Board may discontinue the Plan at any time. Other than as expressly permitted under the Plan, no stock unit account may be reduced or altered in a manner unfavorable to the Member without the consent of the Member. The Board may from time to time make such amendments to the Plan as it may deem proper and in the best interest of the Company without further approval of the Company's shareowners, except to the extent shareowner approval is required in order to qualify for exemption under Rule 16b-3 and, provided further, that if and to the extent required for the Plan to comply with Rule 16b-3, no amendments to the Plan shall be made more than once in any six month period that would change the amount, price or timing of the purchases of common stock hereunder other than to comport with changes in the Internal Revenue Code of 1986, as amended, the Employee Retirement Security Act, or the rules thereunder. 7. Miscellaneous (a) No interest under this Plan may be assigned or transferred. In the case of a Participant's death, payment due under this Plan shall be made to the designated beneficiary of the Participant or, absent such designation, by will or the laws of descent and distribution. (b) If, for any reason, the Company is required to withhold taxes under applicable federal, state or local laws, rules or regulations, the Company shall be entitled to deduct and withhold such amounts from any cash payments made by the Company to the person with respect to whom such withholding arises. (c) The Company shall not be required to reserve or otherwise set aside funds or shares for the payment or satisfaction of its obligations hereunder. (d) Copies of the Plan and all amendments thereto shall be made available at all reasonable times at the office of the Secretary of the Company to all Participants. (e) No Member may decrease the amount deferred hereunder to an amount less than 50% of such Member's Retainer. However, a Member may allocate to his stock unit account up to 100% of Retainer pursuant to an individual written agreement of deferral. A Member increasing or decreasing the amount deferred hereunder must irrevocably elect to do so at least six months prior to the effective date of such election, it being intended that the stock unit purchases under this Plan shall qualify in all respects as "formula awards" under Rule 16b-3 of the Exchange Act as such rule may hereafter be amended from time to time. Amounts deferred pursuant to this paragraph shall remain in the Plan for at least one year, after which the Member may request a withdrawal of such amounts. Withdrawal requests will be processed as soon as administratively practicable after receipt by the Company and may be made no more frequently than once per calendar year. (f) Deferrals of amounts made pursuant to this Plan shall not affect the determination of benefits under the Long Island Lighting Company Retirement Plan for Directors. APPENDIX B OFFICERS' LONG-TERM INCENTIVE PLAN OF LONG ISLAND LIGHTING COMPANY Article 1. Establishment and Purpose 1.1 Establishment of the Plan. Long Island Lighting Company, a New York Corporation (hereinafter referred to as the "Company"), hereby establishes an incentive compensation plan to be known as the Long Island Lighting Company Officers' Long-Term Incentive Plan (hereinafter referred to as the "Plan") as set forth in this document. The Plan shall be effective as of January 1, 1996 (the "Effective Date"). 1.2 Purpose of the Plan. The purpose of the Plan is to promote the success and enhance the value of the Company by linking the personal interests of Officers of the Company to those of Company shareowners and customers, and to provide Participants, as defined below, with an incentive for outstanding long-term performance. The Plan is further intended to assist the Company in its ability to motivate, attract and retain the services of Participants upon whom the successful conduct of its operations is largely dependent. Article 2. Definitions Whenever used in the Plan the following terms shall have the meanings set forth below and, when such meaning is intended, the initial letter of the word is capitalized: 2.1 "Award" means a payment made in accordance with the provisions of the Plan. 2.2 "Board of Directors" means the Board of Directors of the Company. 2.3 "Change in Control" means (1) the acquisition directly or indirectly by any person as such term is used in Section 13(d) and 14(d) of the Exchange Act, or forty percent or more of the combined voting power of the Company's then outstanding securities; (ii) a merger or consolidation of the Company where the Company is not the surviving corporation or where a change in the Company's outstanding common stock occurs; (iii) a sale of all or substantially all of the Company's assets, or all or substantially all of the assets acquired for or used in the electric utility business including, in either case, by virtue of a condemnation proceeding; (iv) the liquidation or dissolution of the Company; or (v) the turnover of more than a majority of the Company's Board of Directors during a two-year period without two-thirds approval of certain directors. 2.4 "Committee" means the Compensation and Management Appraisal Committee of the Board as specified in Article 3 herein. 2.5 "Disability" means with respect to any Participant in the Plan the meaning ascribed to such term in the Company's tax-qualified defined benefit pension plan. 2.6 "Exchange Act" means the Securities Exchange Act of 1934, as amended. 2.7 "Participant" means an employee participating in the Plan. 2.8 "Performance Goals" means the performance objectives of the Company established for the purpose of determining the level of Award, if any, earned during the Performance Period. 2.9 "Performance Period" means the period of three consecutive Plan Years or such other period as determined by the Committee over which the attainment of Performance Goals will be measured. The initial Performance Period will be two years Plan Years 1996-1997. 2.10 "Plan Year" means the calendar year. 2.11 "Retirement" means, with respect to any Participant, the meaning ascribed to such term in the tax-qualified defined benefit pension plan maintained by the Company for the benefit of such Participant. 2.12 "Stock" means shares of the Company's common stock par value $5 per share. Such shares may be authorized but unissued shares of common stock or shares previously issued and purchased by the Company on the open market. The maximum number of shares available for Awards under the Plan shall be one million (1,000,000). 2.13 "Subsidiary" means any corporation 25% or more of the stock of which is owned by the Company. Article 3. Administration 3.1 Committee. The Plan shall be administered by the Committee which shall consist solely of two or more Directors meeting the definition of a "disinterested person" under Rule 16b-3 of the Exchange Act. The Committee shall have exclusive and final authority in all determinations and decisions affecting the Plan and its Participants. Notwithstanding the generality of the foregoing, the Committee shall have the sole authority to interpret the Plan, to establish and revise rules and regulations relating to the Plan, and to make any other determinations that it believes necessary or appropriate for the administration of the Plan including, but not limited to, selecting Participants in the Plan, setting the Performance Goals for a Performance Period and changing the criteria to be used for determining Performance Goals under the Plan, subject to approval of the Board. Except as to those responsibilities which are exercisable by the Committee in its sole discretion, the Committee may delegate such responsibilities or duties as it deems desirable. 3.2 Costs. The Company shall pay all costs of administration of the Plan. Article 4. Eligibility 4.1 Eligibility. All employees classified as Officers of the Company as of the Effective Date shall be eligible to participate in the Plan for the initial Performance Period. Employees of the Company who are classified as Officers after the Effective Date of the Plan shall participate in the Plan if selected to do so and upon such terms as set by the Committee. 4.2 Actual Participation. No employee shall at any time have the right to participate in the Plan for any Performance Period, or by virtue of being a Participant, automatically have a right to any Award. Neither shall an employee being a Participant in one Performance Period automatically be entitled to be a Participant in any subsequent Performance Period. Article 5. Performance Goals 5.1 Setting the Goals. The Committee shall establish for each Performance Period Performance Goals designed to accomplish such financial and strategic objectives as it may from time to time determine appropriate. The Committee shall have the authority to adjust the Corporate Performance Goals for any Performance Period as it deems equitable in recognition of extraordinary or non-recurring events experienced by the Company during the Performance Period or in the event of changes in applicable accounting rules or principles or changes in the Company's method of accounting during the Performance Period. 5.2 Amount of Award. After the applicable Performance Period has ended, a Participant shall be entitled to receive payment of the Award to be determined as a function of the extent to which the Performance Goals have been achieved. Specified minimum, target and maximum results as set by the Board of Directors will result in an Award of a specified percentage per Plan Year of the midpoint of the individual Participant's salary range determined at the earlier of the beginning of the Performance Period and the time the Performance Goals are set by the Committee. Article 6. Payment of Awards 6.1 Awards. The Award for each Performance Period shall be divided into two equal portions to be known as the 50% vested portion and the 50% contingent portion, respectively, of the Award. The 50% contingent portion is subject to a mandatory deferral of one year from the date of the payment of the Award. 6.2 Vested Portion. Each Participant's vested Award shall be converted into an amount of Stock as of the end of the applicable Performance Period. The payment of the 50% vested portion of the Award shall be made in Stock to the Participant as soon as practicable after the close of the Performance Period, unless the Participant has irrevocably elected to defer payment of such vested portion of the Award in accordance with the provisions of Article 10. 6.3 Contingent Portion. Each Participant's contingent Award shall be converted into an amount of Stock as of the end of the applicable Performance Period and shall be credited to a Participant's contingent account on the Company's records of this Plan, subject however to the forfeiture provisions in Section 6.4 below. After the mandatory deferral period referred to in Section 6.1, has passed, a Participant's contingent account will become vested and immediately payable, unless the Participant has irrevocably elected to defer payment of such Award in accordance with the provisions of Article 10. 6.4 Forfeiture of Contingent Awards. If a Participant terminates his employment with the Company for any reason other than Retirement, death, Disability, or Change in Control such Participant shall forfeit the entire amount in his contingent account and the entire amount of any unpaid Award, if any, for any Performance Period. For purposes of the Plan, termination of employment followed by immediate re-employment with the Company or one of its Subsidiaries shall not be deemed a termination of employment. 6.5 Payment of Deferred Vested Awards. Each deferred vested award shall be credited to a Participant's deferred vested account in shares of Stock which shall not be subject to forfeiture, and shall be paid to the Participant or his or her beneficiary or estate in the event of his or her death, at the end of the deferral period in a lump sum or in installments as provided in the written election form provided by the Committee pursuant to Article 10. Notwithstanding any contrary provision in the Participant's written election form, the balance in the Participant's deferred vested account shall be paid in a lump sum as soon as practicable after the end of the Plan Year during which the Participant terminates employment with the Company for any reason. 6.6 Payment in the Event of Retirement, Death, Disability and Change in Control. In the event the Participant's employment with the Company terminates because of Retirement, death, Disability or Change in Control, such Participant or his or her beneficiary or estate in the event of death, shall be entitled to receive payment as soon as practicable after the close of the Performance Period during which such termination of employment occurs, of (i) the entire balance of such Participant's contingent account at the close of the Plan Year during which the termination of employment occurs and (ii) a pro-rata proportion of his or her Award, if any, for the current Performance Period determined by reference to the portion of the current Performance Period during which the Participant was employed as determined by the Committee, which determination need not be uniform among Participants and may reflect distinctions based on the reason for the termination of employment. Article 7. Beneficiary Designation Each Participant under the Plan may from time to time name any beneficiary or beneficiaries (who may be named contingently or successively) to whom any benefit under the Plan is to be paid in the case of his or her death before he or she receives any or all of such benefit. Each such designation shall revoke all prior designations by the same Participant, shall be in a form prescribed by the Committee, and will be effective only when filed by the Participant in writing with the Committee during the Participant's lifetime. In the absence of any such designation, benefits remaining unpaid at the Participant's death shall be paid to the Participant's estate. Article 8. Rights of Employees Nothing in the Plan shall interfere with or limit in any way the right of the Company to terminate any Participant's employment at any time for any reason or no reason in the Company's sole discretion, nor confer upon any Participant any right to continue in the employ of the Company. Article 9. Change in Control Upon the occurrence of a Change in Control, as defined herein, all unpaid amounts under this Plan shall be paid to the Participants in cash or Stock as determined by the Committee within 15 days of a Change in Control. Article 10. Deferrals The Committee may permit a Participant to defer such Participant's receipt of the delivery of stock that would otherwise be due to such Participant. If any such deferral election is permitted, the Committee shall in its sole discretion establish rules and procedures for such deferrals. Article 11. Amendment or Termination 11.1 Amendment or Termination. The Board may at any time and from time to time alter, amend, suspend or terminate the Plan in whole or in part, provided, however, that no amendment which requires shareowner approval in order for the Plan to continue to comply with Rule 16b-3 under the Exchange Act including any successor to such Rule shall be effective unless such amendment shall be approved by the requisite vote of the shareowners of the Company entitled to vote thereon. 11.2 Awards Previously Made. No termination, amendment or modification of the Plan shall adversely affect in any material way any Award previously made under the Plan, or any contingent or deferred account of any Participant, unless such termination, modification or amendment is required by applicable law. Article 12. Successors All obligations of the Company under the Plan, with respect to Awards made hereunder, shall be binding on any successor to the Company, whether the existence of such successor is the result of a direct or indirect purchase, merger, or consolidation or otherwise, of all or substantially all of the business and/or assets of the Company. Article 13. Legal Construction 13.1 Gender and Number. Except where otherwise indicated by the context, any masculine term used herein also shall include the feminine, the plural shall include the singular, and the singular shall include the plural. 13.2 Severability. In the event any provision of the Plan shall be held illegal or invalid for any reason, the illegality or invalidity shall not affect the remaining parts of the Plan, and the Plan shall be construed or enforced as if the illegal or invalid provision had not been included. 13.3 Requirement of Law. The issuance of shares under the Plan shall be subject to all applicable laws, rules and regulations, and to such approvals by any governmental agencies or national securities exchanges as may be required. Notwithstanding any other provision set forth in the Plan, if required by the then-current Section 16 of the Exchange Act, any equity security offered pursuant to the Plan to any Participant may not be sold or transferred within the minimum time limits specified or required in such rule. The term "equity security" shall have the meaning ascribed to it in the then-current Rule 16a-1 under the Exchange Act. 13.4 Securities Law Compliance. With respect to Participants, transactions under the Plan are intended to comply with all applicable conditions of the Federal securities laws. To the extent any provision of the Plan or action by the Committee fails to comply, it shall be deemed null and void, to the extent permitted by law, and deemed advisable by the Committee. 13.5 Governing Law. To the extent not preempted by Federal law, the Plan and all agreements hereunder shall be construed in accordance with, and governed by the laws of the State of New York. Article 14. Miscellaneous 14.1 Assignment. No interest under this Plan may be assigned, transferred or alienated in any way other than by will or by the laws of descent and distribution. Further, a Participant's rights under the Plan shall be exercisable during the Participant's lifetime only by the Participant or the Participant's legal representative. 14.2 Withholding. The Company shall withhold the amount of any Federal, state or local income taxes attributable to any amounts payable under the Plan. With respect to withholding with respect to stock, Participants may elect, subject to approval of the Committee to satisfy the withholding requirement, in whole or in part, by having the Company withhold Stock, having a value on the date the tax is to be determined equal to the minimum statutory total tax which could be imposed on the transaction. All elections shall be irrevocable, in writing, and signed by the Participant. 14.3 Other Plans. No amounts paid hereunder shall affect the level of benefits provided to a Participant or to his or her estate or beneficiary under, or otherwise be includible in, any other employee benefit plan of the Company. 14.4 Concurrent Participation. Nothing contained herein shall preclude any Participant from participating concurrently in any other Company-sponsored incentive plan. 14.5 Executive Plan. This Plan is intended to constitute a deferred compensation arrangement for a select group of management or highly-compensated employees. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS This discussion and analysis addresses matters of significance with regard to the Company and its financial condition, liquidity, capital requirements and results of operations for the last three years. Overview As the utility industry continues the transition to a more competitive marketplace, the pressure from customers and regulators to reduce rates on Long Island has intensified. This pressure to reduce rates has resulted in an attempt by the Long Island Power Authority (LIPA), an agency of the State of New York, to develop a plan to replace the Company as the primary electric and gas utility on Long Island. The Company's response to these challenges has been to continue a strategic plan designed to avoid future rate increases through an aggressive cost containment program, while maintaining a reliable electric and gas system. The Company believes that these efforts will allow it to improve its financial health and better position itself for the transition to a more competitive environment. Significant achievements during 1995 included: o Cash generated from operations exceeded the Company's operating, construction and refunding requirements; o The extinguishment of the First Mortgage debt with cash on hand, resulting in an improvement in the Company's debt ratio; o Earnings per common share of $2.10, despite a lower allowed return on common equity and the modification of certain performance-based incentives related to the electric business; o The continuation of the Company's quarterly common stock dividend rate at 44 1/2 cents per share; o Continuation of the electric rate freeze for the second consecutive year; o A reduction in the Rate Moderation Component balance from $463 million at December 31, 1994 to $383 million at December 31, 1995; o The establishment of a record peak electric energy demand of 4,077 megawatts on August 4, 1995, surpassing the old record of 3,967 megawatts on July 9, 1993; o Receipt of a 3.2% gas rate increase effective December 1, 1995, which is the final of three gas rate increases under a three-year settlement between the Company and the Public Service Commission of the State of New York; o The addition of over 6,500 new gas space heating customers, resulting from the continuation of the Company's gas expansion program; o A reduction in the level of construction expenditures and operations and maintenance expenses; o A reduction in staff levels through attrition while reducing overtime payments; o Receipt of final regulatory approval of the decommissioning of the Shoreham Nuclear Power Station. As part of its strategic effort to improve its competitive position, the Company, for the rate years ended November 30, 1995 and 1996, froze electric rates by focusing on cost reduction. The Company's cost reduction programs, which seek to maximize operating efficiencies as a means to reduce operating costs, resulted in reducing non-fuel operations and maintenance expenses by approximately $29 million from the 1994 amount. During 1995, the Company continued its policy of not replacing employees who decided to either retire or terminate employment with the Company. The benefits derived from internal process review programs and the Company's commitment to reallocate existing resources have allowed the Company to operate with increased efficiencies despite the loss, through attrition, of 857 employees or about 13% of it's workforce since 1990. In 1995, the Company's workforce was reduced by 259 employees or about 5%. In addition to reducing its operations and maintenance expense, the Company also reduced its capital expenditures by approximately $130 million in 1995, due primarily to the completion, in 1994, of the decommissioning of the Shoreham Nuclear Power Station (Shoreham). However, the Company's commitment to increase penetration in the gas home heating market on Long Island remains strong. In 1995, the Company invested approximately $50 million into its gas infrastructure to increase safety, reliability and availability of gas in order to attract new gas space heating customers. As a result of the above, the Company, for the second consecutive year, generated sufficient cash flow to meet all of its operating and construction requirements. This enhanced cash flow also allowed the Company to redeem all amounts outstanding under the First Mortgage with cash on hand. Long Island Power Authority Proposed Plan During 1995, the Governor of the State of New York requested that the Long Island Power Authority (LIPA) develop a plan that, in addition to replacing the Company as the primary electric and gas utility on Long Island, would among other things, produce an electric rate reduction of at least 10%, provide a framework for long-term competition in power production and protect property taxpayers on Long Island. In response to this request, the Board of Trustees of LIPA established a committee (Evaluation Committee) to analyze various plans involving the Company's business operations and assets. In December 1995, after soliciting information and indications of interest from various parties in connection with a LIPA-facilitated financial restructuring/acquisition of the Company, the members of the Evaluation Committee and their advisors announced a proposed plan to restructure the Company and reduce electric rates on Long Island by 12% (Proposed Plan). The Proposed Plan, which has not been adopted by the LIPA Board or formally presented to the Company's Board of Directors for consideration, generally provides that: (i) the Company sell, subject to LIPA's approval, its gas business and electric generation assets; (ii) LIPA purchase the Company's transmission, distribution and Shoreham-related assets; (iii) LIPA enter into long-term power purchase agreements with the purchasers of the generation assets; (iv) LIPA enter into agreements with contractors to manage the transmission and distribution system; and (v) LIPA exercise its power of eminent domain over all or a portion of the Company's assets or securities in order to achieve its objectives if a negotiated agreement cannot be reached with the Company. The Company has indicated to LIPA that certain elements of the Proposed Plan raise significant concerns. Specifically, the Proposed Plan contains no information regarding the values or prices contemplated to be paid for the Company's assets, no financing commitments for any portion of the proposed transaction were disclosed and no indications that endorsements by certain State officials required to approve any transaction undertaken by LIPA have been obtained. In addition, based on the limited information currently available, the Company is unable to determine how the anticipated rate reduction would be achieved and how the reliability of the electric system, including storm restoration capabilities, would be maintained given the multiple entities that would be responsible for providing such service. Notwithstanding these concerns, the Company remains willing to cooperate with LIPA in developing a plan that is beneficial to the Company's investors, customers and employees. The Company is continuously assessing various other strategies in an effort to provide the greatest possible value to its constituents in light of the changing economic, regulatory and political challenges affecting the Company. Such strategies may include a review and modification of its operations to best meet the challenges of a competitive environment, a possible reorganization of the Company, potential joint ventures and/or possible business combinations with other entities. The implementation of certain plans involving the Company's business operations and assets would be subject to, among other things, shareholder and regulatory approvals and could impact the Company's future financial results and operations. Accordingly, the Company is unable to determine what plan, if any, will be pursued by it and/or LIPA or whether any related transaction will be consummated. 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 1995, both the Public Service Commission of the State of New York (PSC) and the Federal Energy Regulatory Commission (FERC) continued their separate initiatives with respect to developing a framework for a competitive electric marketplace. New York State Competitive Opportunities Proceedings 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. During 1995, the proceedings continued with the PSC adopting a series of principles which it will use to guide the transition of the electric utility industry in New York State from a rate-regulated cost of service model to a competitive market-driven model. The principles state, among other things, that: (i) consumers should have a reasonable opportunity to realize savings from competition; (ii) a basic level of reasonably priced service must be maintained; (iii) the integrity, safety and reliability of the system should not be jeopardized; and (iv) the current industry structure, in which most power plants are vertically integrated with natural monopoly transmission and distribution systems, should be thoroughly examined to ensure that it does not impede or obstruct the development of effective wholesale or retail competition. In addition, the principles state that utilities should have a reasonable opportunity to recover prudent and verifiable expenditures and commitments made pursuant to their legal obligations, consistent with these principles. In October 1995, the Energy Association, which is comprised of the Company and the six other investor-owned New York State utilities, filed a proposal designed to achieve the principles outlined by the PSC. The proposal, which is referred to as the "Wholesale Poolco Model", establishes a framework that will allow competition at the wholesale level. The plan would, among other things: (i) allow utilities, non-regulated generators and other market participants to create a wholesale exchange that allows market forces to determine the price of wholesale electricity; (ii) establish an Independent System Operator (ISO) to coordinate the safe and reliable operation of the bulk power transmission system; (iii) increase customer choice by providing clear market price signals so customers can make informed decisions on the use of electricity; and (iv) separate the generation portion of a utility's business from its regulated transmission and distribution business. In this model, competing generating suppliers would bid energy sales into the market. The market clearing price for energy would be determined by the bid of the highest price unit needed to serve the load in a particular location. Regulated utility companies could purchase energy from the market, which would establish a half-hour locational spot market price for electricity, or the utility could seek to enter into bilateral energy agreements with other parties. Bilateral agreements would be administered independently of the wholesale exchange, but would be scheduled through the ISO. These bilateral agreements would be permitted among utility companies, generating companies and power marketers. In the Wholesale Poolco Model, the purchase of electricity by end use customers would still be bundled with transmission, distribution and customer service, all of which would be provided by regulated utilities. The support of the New York State utilities for the Wholesale Poolco Model is predicated on a number of factors, including: (i) a reasonable opportunity to fully recover all investments and expenditures made to provide reliable service under the existing regulatory compact; (ii) PSC support for the option of each utility to continue in the generation business; (iii) special treatment of nuclear plants based on their unique characteristics; and (iv) the adoption of a clearly defined transition plan to ensure that the interests of the customer and the investor are adequately protected. In December 1995, an Administrative Law Judge (ALJ) of the PSC issued a Recommended Decision (RD) to the PSC with respect to this Competitive Opportunities Proceedings. The ALJ recommended a competitive model which seeks to transition the electric utility industry in New York State to full retail competition through two stages. The first stage of this recommendation seeks to transition the industry from its current cost of service rate regulation to a competitive wholesale model similar to the Wholesale Poolco Model. This first stage would allow participants to become familiar with the operation of a deregulated, competitive generation market prior to the eventual movement to full retail competition in the second stage, through a model known as the Flexible Retail Poolco Model. The Flexible Retail Poolco Model contains many of the same attributes associated with the Wholesale Poolco Model, including: (i) an ISO to coordinate the safe and reliable operation of generation and transmission; (ii) open access to the transmission system, which would be regulated by FERC; and (iii) the continuation of a regulated distribution company to operate and maintain the distribution system. The principal difference between the models is that customers would have a choice among suppliers of electricity in the Flexible Retail Poolco Model whereas in the Wholesale Poolco Model, the regulated entity would acquire electric energy from the spot energy sales exchange to sell to the customer. The Flexible Retail Poolco Model would also: (i) deregulate energy/customer services such as meter reading and customer billing; (ii) unbundle electricity into four components: generation, transmission, distribution, and energy/customer services; and (iii) provide customers with a choice among suppliers of electricity, and allow customers to acquire electricity either by long-term contracts or purchases on the spot market or a combination of the two. One of the most contentious issues of the Competitive Opportunities Proceedings has been the position taken by the various parties to the proceedings on the amount of recovery utilities should be permitted to collect from customers for so-called stranded investments. Stranded investments represent costs that utilities would have otherwise recovered through rates under traditional cost of service regulation that, under competition, utilities may not be able to recover since the market price for their product may be inadequate to recover these costs. The Staff of the PSC, for example, has indicated that utilities should not expect full recovery of stranded costs. The Energy Association has commented that utilities have a sound legal precedent confirmed by long-standing PSC policy to fully recover all prudently incurred costs, including stranded costs. The RD states that for recovery, stranded costs must be prudent, verifiable and unable to be reduced through mitigation measures. The RD states that recovery of stranded costs be predicated on the prudency of the costs incurred. The costs must be verifiable and the Company must show that it was unable to avoid incurring these costs. The RD states that a generic decision should address the definition, the method of measurement, the requirements for mitigation, a preferable recovery mechanism and a standard for the recovery of stranded investments. The calculation of the amount to be recovered from customers, however, should be left to individual rate cases or special proceedings that should begin during 1996. The RD further directs New York State investor-owned utilities to individually file, within six months of the PSC's order, a comprehensive long-term proposal addressing the significant components of the RD. 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 these proceedings could adversely affect the Company's ability to apply Statement of Financial Accounting Standards (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" and SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of," could then require a significant write-down of assets, the amount of which cannot presently be determined. For a further discussion of SFAS No. 71 and SFAS No. 121, see Note 1 of Notes to Financial Statements. The Electric Industry - Federal Regulatory Issues As a result of Congress' passage of the Public Utility Regulatory Policies Act of 1978 (PURPA), and the National Energy Policy Act of 1992 (NEPA), the once monopolistic electric utility industry now faces competition. PURPA's goal is to reduce the United States' dependence on foreign oil, encourage energy conservation and promote diversification of fuel supply. Accordingly, PURPA provided for the development of a new class of electric generators which rely on either cogeneration technology or alternate fuels. The utilities are obligated under PURPA to purchase the output of certain of these new generators, which are known as qualified facilities (QFs). 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 (i.e., sales to an entity for resale to the ultimate consumer). NEPA does so by creating exempt wholesale generators that can sell power in wholesale markets without the regulatory constraints placed on utility generators such as the Company. NEPA also expanded FERC's authority to grant access to utility transmission systems to all parties who seek wholesale wheeling for wholesale competition. Significant issues associated with the removal of restrictions on wholesale transmission system access have yet to be resolved and the potential impact on the Company's financial position cannot yet be determined. FERC is in the process of setting policy which will largely determine how wholesale competition will be implemented. FERC has declared that utilities must provide wholesale wheeling to others that is comparable to the service utilities provide themselves. FERC has issued policy statements concerning regional transmission groups, transmission information requirements and "good faith" requests for service and transmission pricing. In March 1995, FERC issued a Notice of Proposed Rulemaking (NOPR) which combined the issues of open transmission access and stranded cost recovery. The NOPR contained a strong endorsement of the right of the utilities to full recovery of stranded costs due to wholesale wheeling and retail-turned-wholesale wheeling arrangements. During the year, FERC has followed up on these issues through an extensive comment period, holding public hearings on pro-forma transmission tariffs, ancillary services, real-time information systems and power pooling issues. FERC recently announced its interest in exploring the role of an ISO in providing comparable transmission access. It is expected that FERC will issue a final order on open access in 1996. Utilities, including the Company, and numerous other interested parties are actively involved in these proceedings. It is not possible to predict the outcome of these proceedings or the effect, if any, on the financial condition of the Company. The Company participates in the wholesale electricity market primarily as a buyer, and in this regard should benefit if rules are adopted which result in lower wholesale prices for its retail customers. The Company's Service Territory The changing utility regulatory environment has affected the Company in a number of ways. For example, PURPA's encouragement of the non-utility generator (NUG) industry has negatively impacted the Company. In 1995, the Company lost sales to NUGs totaling 366 gigawatt-hours (Gwh) representing a loss in electric revenues net of fuel (net revenues) of approximately $28 million, or 1.5% of the Company's net revenues. In 1994, the Company lost sales to NUGs totaling 237 Gwh or approximately $24 million of net revenues. The increase in lost net revenues resulted principally from the completion, in April 1995, of a QF located at the State University of New York at Stony Brook, New York (Stony Brook Project). The annual load loss due to this QF is estimated to be 188 Gwh. The Company estimates that in 1996, sales losses to NUGs will be 414 Gwh, or approximately 1.7% of projected net revenues, an increase reflecting 12 months of operation for the Stony Brook Project. 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 in 1995 and 1994 approximated 205 megawatts (MW). 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 now only applies 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. The Company estimates that purchases from QFs required by federal and state law cost the Company $53 million more than it would have cost had the Company generated this power in both 1995 and 1994. 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 in 1995 and 1994 NYPA power displaced approximately 429 Gwh and 400 Gwh of annual energy sales, respectively. The net revenue loss associated with this amount of sales is approximately $30 million or 1.6% of the Company's 1995 net revenues and $28 million or 1.5% of the Company's 1994 net revenues. Currently, the potential loss of additional load is limited by conditions in the Company's transmission agreements with NYPA. Aside from NUGs, 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 likely to increase as a result of NEPA. The Town of Southampton and several other towns in the Company's service territory are considering the formation of a municipally owned and operated electric authority to replace the services currently provided by the Company. Suffolk County issued a request for proposal from suppliers for up to 200 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. The Company has responded that it does not believe the County is eligible under present laws and regulations to purchase wholesale power and resell it to retail customers, and has declined to offer the requested retail wheeling service. 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. 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 FERC may take regarding any of these matters, or the impact on the Company's financial condition if some or all of these matters are approved or implemented by the appropriate regulatory authority. Notwithstanding the outcome of the federal or state regulatory rate 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. Liquidity During 1995, cash generated from operations exceeded the Company's operating, construction and refunding requirements in addition to allowing for the early redemption of the Company's remaining First Mortgage Bonds. This positive cash flow is the result of: (i) the Company's continuing efforts to control both operations and maintenance (O&M) costs and construction expenditures; (ii) lower fuel costs; (iii) significantly lower costs incurred at Shoreham as a result of the completion of the plant's decommissioning in 1994; (iv) lower interest payments resulting from lower debt levels; and (v) the collection of previously deferred revenues. At December 31, 1995, the Company's cash and cash equivalents amounted to approximately $351 million, compared to $185 million at December 31, 1994. In addition, the Company has available for its use a $300 million revolving line of credit through October 1, 1996, 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. For a further discussion of the 1989 RCA, see Note 7 of Notes to Financial Statements. In January 1996, the Company received approximately $81 million, including interest, from Suffolk County pursuant to a judgment in the Company's favor that found that the Shoreham property was overvalued for property tax purposes between 1976 and 1983 (excluding 1979 which had previously been settled). The Company has petitioned the PSC to allow the Company to reduce the Rate Moderation Component (RMC) by the amount received, net of litigation costs incurred by the Company. The Company is also seeking recovery from Suffolk County for the overpayment of taxes on the Shoreham property for the years 1984 through 1992 in a separate proceeding which is currently pending before the New York Supreme Court. For a further discussion of this proceeding, see "Shoreham Related Litigation" below. The Company currently believes that it will not need to access the financial markets to retire its $415 million of maturing debt in 1996 as cash balances on hand at that time will be sufficient to support all Company requirements for 1996. 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). With respect to the repayment of $251 million and $101 million of debt maturing in 1997 and 1998, respectively, the Company intends to use cash generated from operations to the maximum extent practicable. 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. The Revenue Agents' Reports reflect proposed adjustments to the Company's federal income tax returns for this period which, if sustained, would give rise to tax deficiencies totaling approximately $227 million. The Company believes that any such deficiencies as finally determined would be significantly less than the amounts proposed in the Revenue Agents' Reports. The Revenue Agents have also proposed investment tax credit (ITC) adjustments which, if sustained, would reduce the ITC carryforwards by approximately $96 million. The Company has protested some of the proposed adjustments which are presently under review by the Regional Appeals Office of the Internal Revenue Service. If this review does not result in a settlement that is satisfactory to the Company, the Company intends to seek a judicial review. The Company believes that its reserves are adequate to cover any tax deficiency that may ultimately be determined and that cash from operations will be sufficient to satisfy any settlement reached. The Company will exhaust its net operating loss carryforwards for alternative minimum tax purposes in 1996. As a result, it is anticipated that the Company will be required to pay approximately $80 million of alternative minimum tax in 1996. In addition, during 1996, the Company anticipates utilization of net operating loss carryforwards amounting to approximately $547 million and to fully utilize its remaining NOL for regular income tax purposes in 1997. Capitalization The Company's capitalization, including current maturities of long-term debt and current redemption requirements of preferred stock, at December 31, 1995 and 1994, was $8.3 billion. At December 31, 1995 and 1994, the Company's capitalization ratios were as follows:
1995 1994 ---- ---- Long-term debt 61.8% 62.5% Preferred stock 8.6 8.6 Common shareowners' equity 29.6 28.9 ==== ==== 100.0% 100.0%
In support of the Company's continuing goal to reduce its debt ratio, the Company, in 1995, retired at maturity, with cash on hand, $25 million of First Mortgage Bonds and voluntarily redeemed prior to maturity, the remaining $75 million of First Mortgage Bonds. With the retirement/ redemption of the First Mortgage Bonds, the lien of the First Mortgage was discharged leaving the Company's General and Refunding Bonds (G&R Bonds) as its only outstanding secured indebtedness. The Company currently anticipates that it will use cash on hand to satisfy the $415 million of G&R Bonds scheduled to mature in 1996. At such time, assuming a level of earnings consistent with 1995, the Company's debt ratio will be below 60%. During 1995, the Company received proceeds from the sale of $50 million of Electric Facilities Revenue Bonds (EFRBs) issued by NYSERDA. The proceeds from this offering were used to reimburse the Company's treasury for electric projects previously completed or under construction. Investment Rating The Company's securities are rated by Standard and Poor's Corporation (S&P), Moody's Investors Service (Moody's), Fitch Investors Service, L.P. (Fitch) and Duff and Phelps, Inc. (D&P). The rating agencies have been watching the electric utility industry closely and have expressed concern regarding the ability of high cost utilities, such as the Company, to recover all of their fixed costs in a competitive, deregulated marketplace. In 1995, Fitch lowered its credit ratings of the Company's securities one level. Both Fitch and S&P have placed the Company's securities on "Credit Watch" with "evolving or developing" implications. Credit Watch indicates a rating change is likely, and the evolving or developing status indicates ratings may be raised or lowered. In December 1995, Moody's stated that it will continue to review the Company's credit ratings and also changed the direction of the ratings review to uncertain from negative. Currently, only the Company's G&R Bonds meet or exceed minimum investment grade. At December 31, 1995, 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- =============================================================================
Capital Requirements and Capital Provided Capital requirements and capital provided for 1995 and 1994 were as follows:
- ------------------------------------------------------------------------------------- (In millions of dollars) 1995 1994 - ------------------------------------------------------------------------------------- Capital Requirements Construction* Electric $ 144 $ 135 Gas 79 119 Common 21 23 - ------------------------------------------------------------------------------------ Total Construction 244 277 - ------------------------------------------------------------------------------------ Refundings and Dividends Long-term debt 100 635 Preferred stock 5 5 Common stock dividends 211 205 Preferred stock dividends 53 53 Redemption costs - 2 - ------------------------------------------------------------------------------------ Total Refundings and Dividends 369 900 - ------------------------------------------------------------------------------------ Shoreham post-settlement costs 71 167 - ------------------------------------------------------------------------------------ Total Capital Requirements $ 684 $ 1,344 ==================================================================================== Capital Provided Cash generated from operations $ 772 $ 836 Long-term debt issued 49 331 Common stock issued 20 118 Financing costs - (4) - ------------------------------------------------------------------------------------ Other investing activities 9 - - ------------------------------------------------------------------------------------ (Increase) decrease in cash (166) 63 ==================================================================================== Total Capital Provided $ 684 $ 1,344
* Excludes non-cash allowance for other funds used during construction. For further information, see the Statement of Cash Flows. Based upon the availability of electricity provided by the Company's existing generating facilities, including its portion of energy generated at Nine Mile Nuclear Power Station, Unit 2 (NMP2), and by its ability to purchase power under firm contracts from other electric systems and certain non-Company owned facilities located within the Company's service territory, the Company believes it has adequate generating resources to meet its energy demands for the next several years. For 1996, total capital requirements (excluding common stock dividends) are estimated at $792 million, of which maturing debt is $415 million, construction requirements is $270 million, preferred stock dividends are $52 million, preferred stock sinking funds are $5 million and Shoreham post-settlement costs are $50 million (including $49 million for payments- in-lieu-of-taxes). The Company believes that cash generated from operations and cash on hand will be sufficient to meet all capital requirements in 1996. Rate Matters Electric In 1993, the Company filed an Electric Rate Plan (Plan) with the PSC for the three-year period which began December 1, 1994. The goals of this Plan included minimizing future electric rate increases in addition to providing for the continued recovery of the Company's regulatory assets while retaining consistency with the Rate Moderation Agreement's (RMA) objective of restoring the Company to financial health. As a result of the rate proceeding initiated by the filing of the Company's Plan, the PSC issued an Order for the rate year beginning December 1, 1994. The Order, which among other things, froze overall 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. In addition, the PSC ordered that the rate proceeding be continued to allow the parties to develop a plan for achieving long-term rate stability at the prevailing rate levels, while, among other things, providing for the continuing recovery of the Shoreham-related assets. In its rate decision, the PSC reaffirmed its commitment to allow the Company to recover its Shoreham-related assets, noting that it is a crucial factor in the Company's ability to maintain its investment grade bond rating and to secure reasonably priced capital. The continuation of the rate proceeding will also enable the PSC to consider the Company's operations and its opportunities to achieve greater efficiency over the next several years. The Company filed a compliance filing under the terms of the Order to extend the overall rate freeze through the rate year which began December 1, 1995. The PSC has yet to issue an electric rate order in response to this filing. In February 1996, the PSC issued an order to show cause and instituted a proceeding to examine various opportunities to reduce the Company's current electric rates. Specifically, the Company has been directed to address the following: (i) should all or a part of the $81 million Suffolk County property tax refund, as more fully discussed under the captions "Liquidity" and "Shoreham Related Litigation", be used to reduce current rates; (ii) should the return of the $26 million 1995 rate year net reconciliation credit to customers, as more fully discussed in Note 3 of Notes to Financial Statements, be accelerated; (iii) determine, upon review of the forecasts reflected in the September 1995 compliance filing for the rate year commencing December 1, 1995, whether adjustments to the forecasts can be reflected in rate reductions currently; and (iv) revisit the current mechanics of the Fuel Cost Adjustment (FCA) clause, as more fully discussed in Notes 1 and 3 of Notes to Financial Statements, to determine whether all or a portion of any fuel cost savings can be reflected in current customer bills. The Company has been directed to submit a response to the order to show cause addressing these items. Interested parties will have an opportunity to submit comments on the Company's filing, after which a hearing before an ALJ will be convened and the ALJ will determine further procedures. The Company is unable to predict the outcome of this proceeding and the impact, if any, that it may have on the Company's cash flow, financial condition or results of its operations. While no assurance can be given, the Company's objective is to continue the current rate freeze through the rate year ending November 30, 1997. For a further discussion respecting electric rates see Note 3 of Notes to Financial Statements. Gas In December 1993, the PSC approved a three-year gas rate settlement between the Company and the Staff of the PSC. The gas rate settlement provides that the Company receive, for each of the rate years beginning December 1, 1993, 1994 and 1995, annual gas rate increases of 4.7%, 3.8% and 3.2%, respectively. In the determination of the revenue requirements for the gas rate settlement, an allowed return on common equity of 10.1% was used. The gas rate decision also provides 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 a further discussion respecting gas rates see Note 3 of Notes to Financial Statements. Environment The Company is subject to federal, state and local laws and regulations dealing with air and water quality and other environmental matters. The Company continually monitors its activities in order to determine the impact of such 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 (NYSDEC) 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 is believed to have produced manufactured gas. The Company expects to enter into an Administrative Consent Order (ACO) with the NYDEC in 1996 regarding the management of environmental activities at these properties. Although the exact amount of the Company's clean-up costs cannot yet be determined, based on the findings of investigations at two of these six sites, preliminary estimates indicate that it will cost approximately $35 million to clean up all of these sites over the next five to ten years. Accordingly, the Company had recorded a $35 million liability and a corresponding regulatory asset to reflect its belief that the PSC will provide for the future recovery of these costs through rates as it has for other New York State utilities. The Company has notified its former and current insurance carriers that it seeks to recover from them certain of these investigation and clean-up costs. However, the Company is unable to predict the amount of insurance recovery, if any, that it may obtain. In addition, there are several other sites within the Company's service territory that were former MGP sites. Research is underway to determine their relationship, if any, to the Company or its predecessor companies. 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 been notified by the Environmental Protection Agency (EPA) that it is one of many potentially responsible parties (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, have entered into an ACO with the EPA to conduct a Remedial Investigation and Feasibility Study (RI/FS). Under a PRP participant agreement, the Company is responsible for 8.2% of the costs associated with this RI/FS which has been completed and is currently being reviewed by the EPA. The Company's total share of costs to date is approximately $0.5 million. The level of remediation required will be determined when the EPA issues its decision. Based on information available to date, the Company currently anticipates that the total cost to remediate this site will be between $14 million and $30 million. The Company has recorded a liability of $1.1 million representing its estimated share of the additional cost to remediate this site. With respect to the other two sites, located in Kansas City, Kansas and Kansas City, Missouri, the Company is investigating allegations that it had made agreements for disposal of polychlorinated biphenyls (PCBs) or items containing PCBs at these sites. The EPA has provided the Company with documents indicating that the Company was responsible for less than 1% of the total weight of the PCB-containing equipment, oil and materials that were shipped to the Missouri site. The EPA has not yet completed compiling documents for the Kansas site. The Company is currently unable to determine its share, if any, of the cost to remediate these two sites or the impact, if any, on the Company's financial position. In addition, the Company was notified that it is a PRP at a Superfund Site in Farmingdale, New York. Portions of the site are allegedly contaminated with PCBs, solvents and metals. The Company was also notified by other PRPs that it should be responsible for expenses in the amount of approximately $0.1 million 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 the cost to remediate this site or the impact, if any, on the Company's financial position. The Connecticut Department of Environmental Protection (DEP) and the Company have signed an ACO which will require the Company to address leaks from an electric transmission cable located under the Long Island Sound (Sound Cable). The Sound Cable is jointly owned by the Company and the Connecticut Light and Power Company, a subsidiary of Northeast Utilities. Specifically, the order requires the Company to evaluate existing procedures and practices for cable maintenance, operations and fluid spill response procedures and to propose alternatives to minimize fluid spill occurrences and their impact on the environment. Alternatives to be evaluated range from improving existing monitoring and maintenance practices to removal and replacement of the Sound Cable. The Company is currently unable to determine the costs it will incur to complete the requirements of the ACO or to comply with any additional DEP requirements. In addition, the Company has been served with a subpoena from the U.S. Attorney for the District of Connecticut to supply certain written information regarding releases of fluid from the Sound Cable, as well as associated operating and maintenance practices. Since the investigation is in its preliminary stages, the Company is unable to determine the likelihood of a criminal proceeding being initiated at this time. However, the Company believes all activities associated with the response to releases from the Sound Cable were consistent with legal and regulatory requirements. The Company believes that all significant costs incurred with respect to environmental investigations and remediation activities will be recoverable through rates. Conservation Services The Company's 1995 Demand Side Management (DSM) Plan (1995 DSM Plan) focused on promoting energy efficient load growth while minimizing the impact that conservation programs have on increasing the Company's electric rates. The 1995 DSM Plan reflected the Company's goal to educate its customers on the benefits of energy efficiency while reducing the reliance on cash subsidies. The PSC approved funding for the Company's 1995 DSM Plan at $12 million, as compared to $19 million and $33 million in 1994 and 1993, respectively. In addition, the PSC established an incremental annualized energy savings goal of 70 Gwh, including a monetary penalty to the Company if 80% of the threshold was not achieved. The Company was successful in exceeding the penalty threshold identified by the PSC. In 1996, the Company plans to continue its pursuit of energy efficiency and peak load reduction while maintaining the strategy of controlling electric rates. Through careful management of DSM expenditures and the delivery of targeted DSM programs, the Company plans to offer cost-effective DSM programs that will appeal to a variety of customers. The 1996 DSM Plan will continue to focus on customer education and information and to promote efficient load growth in both the residential and commercial sectors. In addition, the Company will place an increased emphasis on programs which facilitate the attraction, expansion and retention of major commercial/industrial customers. These programs will act to position the Company as a business partner, helping to improve the economic climate on Long Island. At the same time, these programs will help to improve the Company's competitiveness as an energy provider. Shoreham Related Litigation 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 are the subject of litigation 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. On January 10, 1994, the Appellate Division, Second Department, affirmed a lower court's March 29, 1993 decision holding, in major part, that the Company is not obligated for any real property taxes that accrued after February 28, 1992, attributable to property that it conveyed to LIPA, that PILOTs commenced on March 1, 1992, that PILOTs are subject to refunds and that the LIPA act does not provide for the termination of PILOTs. Generally, these holdings are favorable to the Company. In October 1995, the Court of Appeals granted the parties motion for leave to appeal the lower court decision following an agreement between the parties to voluntarily dismiss outstanding causes of action. The proper amount of PILOTs is to be determined in pending litigation described below. The costs of Shoreham included real property taxes imposed by, among others, the Town of Brookhaven on Shoreham and capitalized by the Company during construction. The Company had sought judicial review in New York Supreme Court, Suffolk County of the assessments upon which those taxes were based for the years 1976 through 1992 (excluding 1979). The Supreme Court consolidated the review of the tax years at issue into two phases: 1976 through 1983, excluding 1979, which had been settled (Phase I); and 1984 through 1992 (Phase II). In October 1992, the Supreme Court ruled that Shoreham had been overvalued for real property tax purposes for Phase I. In May 1995, the New York Court of Appeals denied the request of the Town of Brookhaven and other respondents for leave to appeal this decision, which had been previously affirmed in an unanimous decision by the New York State Appellate Division, Second Department. Thereafter, in January 1996, the Company received approximately $81 million, including interest, from Suffolk County pursuant to this Phase I judgment. In the Phase II proceeding, the Company is seeking to recover over $500 million, plus interest, in property taxes paid on Shoreham for the years 1984-1992. In this proceeding, the taking of evidence has been completed and final briefs have been filed by the parties. The amount of the Company's recovery, if any, in the Phase II proceeding and the timing of all refunds cannot yet be determined. LIPA has been permitted to intervene in the proceeding for the 1991-92 tax year which under the Appellate Division's decision discussed above, will partially establish LIPA's PILOT obligation. Pursuant to the Appellate Division's decision, LIPA's PILOT obligations will be determined either by agreement or in a separate proceeding challenging the Shoreham assessment for the 1992-93 tax year. Results of Operations Earnings Earnings for the years 1995, 1994 and 1993 were as follows:
(In millions of dollars and shares except earnings per share) - ----------------------------------------------------------------------------------------- 1995 1994 1993 - ----------------------------------------------------------------------------------------- Net income $ 303.3 $ 301.8 $ 296.6 Preferred stock dividend requirements 52.6 53.0 56.1 - ---------------------------------------------------------------------------------------- Earnings for Common Stock $ 250.7 $ 248.8 $ 240.5 ======================================================================================== Average common shares outstanding 119.2 115.9 112.1 - ---------------------------------------------------------------------------------------- Earnings per Common Share $ 2.10 $ 2.15 $ 2.15 ========================================================================================
The Company's 1995 earnings per common share were lower than 1994 earnings per common share as a result of the PSC's current electric rate order, effective December 1, 1994, that lowered the allowed return on common equity from 11.6% to 11.0% and modified certain performance-based incentives. These two actions had the effect of reducing the Company's earnings by 15 cents per common share compared to the previous year. The effects of the electric rate order were mitigated by a significant reduction in operating costs which were achieved by a comprehensive cost containment program. Earnings per common share for the gas business were higher in 1995 when compared to 1994 due to cost containment measures and a write-off in 1994 of previously deferred storm costs. The higher level of earnings in the gas business also helped to mitigate the adverse effects of the electric rate order. Earnings per common share for 1994 equaled that of 1993. The electric business achieved a higher level of earnings which were offset by a decrease in the gas business earnings. Revenues Total revenues, including revenues from the recovery of fuel costs, were $3.1 billion for each of the years ended December 31, 1995 and 1994, and $2.9 billion for the year ended December 31, 1993. Electric Revenues Revenues from the Company's electric operations totaled $2.5 billion for the years ended December 31, 1995 and 1994, compared to $2.4 billion in 1993. The Company's electric rates have not increased since December 1, 1993, when the Company received an electric rate increase of 4.0%. Given the absence of any electric rate increases combined with operating in a mature market, electric revenues have remained relatively flat over the last two years. The December 1993 rate increase provided $69 million of additional electric revenues in 1994 when compared to 1993. For a further discussion on electric rates, see Notes 1 and 3 of Notes to Financial Statements. Total electric sales volumes were 16,572 million kilowatt hour (kWh) in 1995, 16,382 million kWh in 1994 and 16,128 million kWh in 1993. The increase in 1995 sales when compared to 1994 is attributable primarily to higher sales for resale. System sales for 1995, when compared to 1994, were negatively impacted by a 174 million kWh reduction in customer usage due to the effects of weather. Partially offsetting this reduction was a 116 million kWh increase in system load over 1994. The 116 million kWh growth occurred despite the loss of the Stony Brook Project. The increase in system sales for 1994, when compared to 1993, was primarily the result of warmer weather experienced in the comparable summer months. In each of the years 1995, 1994 and 1993, residential sales accounted for 45% of total system sales, while commercial and industrial sales accounted for 52% of the total, with sales to public authorities representing 3%. Gas Revenues Revenues from the Company's gas operations for the years 1995, 1994 and 1993 were $591 million, $586 million and $529 million, respectively. In December 1993, the PSC approved a three-year gas rate settlement between the Company and the Staff of the PSC. The gas rate settlement provided the Company with annual gas rate increases of 4.7%, 3.8% and 3.2% for the rate years beginning December 1, 1993, 1994 and 1995, respectively. These rate increases provided $21 million in additional revenues for 1995 as compared to 1994, and $25 million in additional revenues for 1994 as compared to 1993. A decrease of $24 million in the recoveries of gas fuel expenses more than offset the additional revenues provided by the annual gas rate increase in 1995. The decrease in the recovery of gas fuel expenses in 1995 was primarily due to lower average gas prices when compared to 1994. The recoveries of gas fuel expenses in 1994 when compared to 1993, increased by $33 million primarily due to increased billed sales volumes and higher average gas prices. The Company has a weather normalization clause to mitigate the impact on revenues of experiencing weather that is warmer or colder than normal. In 1993, the Company began selling gas to businesses off the Company's system. These off-system gas sales revenues totaled $24 million, $26 million and $8 million for the years 1995, 1994 and 1993, respectively. Profits realized from off-system sales are allocated 85% to firm gas customers and 15% to shareowners. For 1995, firm gas sales volumes decreased by less than 1% when compared to 1994 even though the 1995 heating season was much warmer than the 1994 heating season. The impact of the warmer weather was ameliorated by the addition of over 6,500 new gas space heating customers during 1995, resulting from the continuation of the Company's gas expansion program. In 1994, the Company added over 7,000 gas space heating customers. Operating Expenses Fuel and Purchased Power Fuel and purchased power expenses for the years 1995, 1994 and 1993 were as follows:
(In millions of dollars) - ------------------------------------------------------------------------------------------- 1995 1994 1993 - ------------------------------------------------------------------------------------------- Fuel for Electric Operations Oil $ 98 $ 145 $ 180 Gas 149 101 93 Nuclear 14 15 13 Purchased power 310 308 293 - ------------------------------------------------------------------------------------------- Total 571 569 579 - ------------------------------------------------------------------------------------------- Gas fuel 264 279 249 - ------------------------------------------------------------------------------------------- Total $ 835 $ 848 $ 828 ===========================================================================================
During 1995, the Company refitted an additional steam generating unit to enable it to burn either oil or natural gas, bringing the total number of steam units capable of burning natural gas to seven. Of these seven, five are dual-fired, having the capability of burning either natural gas or oil. As a result, the Company, over the past three years, has increased the amount of energy generated with natural gas, thereby displacing more costly energy generated with oil or purchased from others. Electric fuel expense for 1995 increased slightly from 1994 as a result of increased electric sales volumes. For 1994, fuel expense for electric generation decreased relative to 1993 as a result of an increase in the amount of energy generated with more economical natural gas. Electric fuel and purchased power mix for the years 1995, 1994 and 1993 were as follows:
(In thousands of MWH) - ------------------------------------------------------------------------------------------ 1995 1994 1993 - ------------------------------------------------------------------------------------------ MWH % MWH % MWH % - ------------------------------------------------------------------------------------------ Oil 3,099 17% 4,480 25% 5,894 34% Gas 6,344 36 4,056 23 3,329 19 Nuclear 1,301 7 1,498 9 1,291 7 Purchased power 7,143 40 7,640 43 7,023 40 - ------------------------------------------------------------------------------------------ Total 17,887 100% 17,674 100% 17,537 100% ==========================================================================================
The Company has reduced oil consumption by purchasing more economical power from other systems, by increased generation with natural gas, by using energy generated at NMP2 and by purchasing energy supplied by cogenerators and independent power producers (IPPs) as required by New York State law. The total barrels of oil consumed for electric operations were 5.2 million, 7.5 million, and 9.7 million for the years 1995, 1994 and 1993, respectively. Cogenerators and IPPs provided approximately 10% of the total energy made available by the Company in 1995 and approximately 9% in both 1994 and 1993. The increase in purchased power expenses in 1995 and 1994 is primarily attributable to purchases from the 136 MW facility in Holtsville, New York, owned by NYPA, and constructed for the benefit of the Company. Gas system fuel expenses decreased in 1995 by $15 million when compared with 1994, despite higher sales volumes, because of a decline in the average price of gas. In 1994, these expenses increased by $30 million when compared with 1993, primarily due to the costs associated with the Company's off-system gas sales which began in 1993. Operations and Maintenance Expenses Operations and maintenance (O&M) expenses, excluding fuel and purchased power, were $511 million, $541 million and $522 million, for the years 1995, 1994 and 1993, respectively. The decrease in O&M for 1995 was primarily due to the continuation of the Company's cost containment efforts which resulted in lower production costs, lower transmission and distribution costs and lower administrative and general expenses. O&M expenses increased in 1994 when compared to 1993 due to the write-off of previously deferred storm costs associated with gas operations, an increase in costs associated with the Company's gas expansion program, the recognition of certain costs which exceeded the Company's insurance recoveries, and an increase in employee benefit costs. Rate Moderation Component Amortization The rate moderation component amortization reflects the difference between the Company's revenue requirements under conventional ratemaking and the revenues provided by its electric rate structure. In 1995, 1994 and 1993, the Company recorded non-cash charges to income of approximately $22 million, $198 million and $89 million, respectively, representing the amortization of the RMC. In 1995, the operation of the Fuel Moderation Component (FMC) as discussed in Note 3 of Notes to Financial Statements, resulted in credits to the RMC of $87 million which more than offset the accretion of the RMC resulting from revenues under the current electric rate structure being less than revenue requirements under conventional ratemaking. For the years 1994 and 1993, revenues under the rate structure in effect in those years, were greater than that required by conventional ratemaking resulting in the amortization of the RMC. In addition, the RMC amortization for the years 1994 and 1993 increased as a result of the FMC, which totaled $83 million and $45 million for 1994 and 1993, respectively. For a further discussion on the RMC, see Note 3 of Notes to Financial Statements. Other Regulatory Amortization In 1995, the net total of other regulatory amortization was a non-cash charge to income of $161.6 million, compared to $4.3 million in 1994. This change is primarily attributable to the operation of the revenue reconciliation mechanism and increased amortization of the LRPP deferrals, as more fully discussed in Note 3 of Notes to Financial Statements. The revenue reconciliation mechanism, as established under the LRPP, eliminates the impact on earnings of experiencing electric 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). The difference between the actual and adjudicated net margin sales level is deferred on a monthly basis during the year. During 1995, the Company recorded a non-cash charge to income of approximately $64 million representing a net margin level in excess of that provided for in rates. In 1994, the Company recorded non-cash income of approximately $51 million as the actual net margin level was below that which was provided for in rates. The increase in the amortization of the LRPP deferrals in 1995 totaled $34 million. In 1994, other regulatory amortization was higher than 1993 as a result of the amortization of the 1992 rate year LRPP deferrals which began in August 1993, the operation of the interest deferral mechanism and an increase in amortization expense related to Shoreham post-settlement costs. These items were partially offset by higher net margin revenues. Operating Taxes Operating taxes were $448 million, $407 million and $386 million for the years 1995, 1994 and 1993, respectively. The increase in operating tax of approximately $41 million in 1995 when compared to 1994 is primarily attributable to increased property taxes. The increase of $21 million in 1994 when compared to 1993 is primarily attributable to higher gross receipts taxes resulting from increased revenues, higher property taxes, additional payroll taxes and higher dividend taxes. Federal Income Tax Federal income tax was $206 million, $177 million and $172 million for the years 1995, 1994 and 1993, respectively. The increase in federal income tax in 1995 when compared to 1994 is primarily attributable to higher earnings and the amortization of a tax rate increase which had previously been deferred. Interest Expense The reductions in interest expense in 1995 when compared to 1994 and in 1994 when compared to 1993 are primarily attributable to lower outstanding debt levels. The Company's strategy is to apply available cash balances toward the satisfaction of debt whenever practicable. Accordingly, in 1995, the Company used approximately $75 million of cash on hand to redeem, prior to maturity, the remaining outstanding First Mortgage Bonds. During 1994, the Company used approximately $200 million of cash on hand and the proceeds from the issuance of 5.1 million shares of common stock to reduce debt levels by approximately $300 million. The lower interest expense in 1994 also reflects the satisfaction of $175 million of debt which matured in November 1993 with the use of cash on hand. Selected Financial Data Additional information respecting revenues, expenses, electric and gas operating income and operations data and balance sheet information for the last five years is provided in Tables 1 through 11 of Selected Financial Data. Information with regard to the Company's business segments for the last three years is provided in Note 11 of Notes to Financial Statements.
FINANCIAL STATEMENTS Statement of Income (In thousands of dollars except per share amounts) - ---------------------------------------------------------------------------------------------------- For year ended December 31 1995 1994 1993 - ---------------------------------------------------------------------------------------------------- Revenues Electric $ 2,484,014 $ 2,481,637 $ 2,352,109 Gas 591,114 585,670 528,886 - ---------------------------------------------------------------------------------------------------- Total Revenues 3,075,128 3,067,307 2,880,995 - ---------------------------------------------------------------------------------------------------- Operating Expenses Operations - fuel and purchased power 834,979 847,986 827,591 Operations - other 383,238 406,014 387,808 Maintenance 128,155 134,640 133,852 Depreciation and amortization 145,357 130,664 122,471 Base financial component amortization 100,971 100,971 100,971 Rate moderation component amortization 21,933 197,656 88,667 Regulatory liability component amortization (79,359) (79,359) (79,359) 1989 Settlement credits amortization (9,214) (9,214) (9,214) Other regulatory amortization 161,605 4,328 (18,044) Operating taxes 447,507 406,895 385,847 Federal income tax - current 14,596 10,784 6,324 Federal income tax - deferred and other 193,742 170,997 178,530 - ---------------------------------------------------------------------------------------------------- Total Operating Expenses 2,343,510 2,322,362 2,125,444 - ---------------------------------------------------------------------------------------------------- Operating Income 731,618 744,945 755,551 - ---------------------------------------------------------------------------------------------------- Other Income and (Deductions) Rate moderation component carrying charges 25,274 32,321 40,004 Other income and deductions, net 34,400 35,343 38,997 Class Settlement (21,669) (22,730) (23,178) Allowance for other funds used during construction 2,898 2,716 2,473 Federal income tax - deferred and other 2,800 5,069 12,578 - ---------------------------------------------------------------------------------------------------- Total Other Income and (Deductions) 43,703 52,719 70,874 - ---------------------------------------------------------------------------------------------------- Income Before Interest Charges 775,321 797,664 826,425 - ---------------------------------------------------------------------------------------------------- Interest Charges Interest on long-term debt 412,512 437,751 466,538 Other interest 63,461 62,345 67,534 Allowance for borrowed funds used during construction (3,938) (4,284) (4,210) - ---------------------------------------------------------------------------------------------------- Total Interest Charges 472,035 495,812 529,862 - ---------------------------------------------------------------------------------------------------- Net Income 303,286 301,852 296,563 Preferred stock dividend requirements 52,620 53,020 56,108 - ---------------------------------------------------------------------------------------------------- Earnings for Common Stock $ 250,666 $ 248,832 $ 240,455 ==================================================================================================== Average Common Shares Outstanding (000) 119,195 115,880 112,057 - ---------------------------------------------------------------------------------------------------- Earnings per Common Share $ 2.10 $ 2.15 $ 2.15 ==================================================================================================== Dividends Declared per Common Share $ 1.78 $ 1.78 $ 1.76
See Notes to Financial Statements.
Balance Sheet (In thousands of dollars) - ----------------------------------------------------------------------------------------------------- Assets at December 31 1995 1994 - ----------------------------------------------------------------------------------------------------- Utility Plant Electric $ 3,786,540 $ 3,657,178 Gas 1,086,145 994,742 Common 244,828 232,346 Construction work in progress 100,521 129,824 Nuclear fuel in process and in reactor 16,456 23,251 - ----------------------------------------------------------------------------------------------------- 5,234,490 5,037,341 Less - Accumulated depreciation and amortization 1,639,492 1,538,995 - ----------------------------------------------------------------------------------------------------- Total Net Utility Plant 3,594,998 3,498,346 - ----------------------------------------------------------------------------------------------------- Regulatory Assets Base financial component (less accumulated amortization of $656,311 and $555,340) 3,382,519 3,483,490 Rate moderation component 383,086 463,229 Shoreham post-settlement costs 968,999 922,580 Shoreham nuclear fuel 71,244 73,371 Unamortized cost of issuing securities 222,567 254,482 Postretirement benefits other than pensions 383,642 412,727 Regulatory tax asset 1,802,383 1,831,689 Other 230,663 250,804 - ----------------------------------------------------------------------------------------------------- Total Regulatory Assets 7,445,103 7,692,372 - ----------------------------------------------------------------------------------------------------- Nonutility Property and Other Investments 16,030 24,043 - ----------------------------------------------------------------------------------------------------- Current Assets Cash and cash equivalents 351,453 185,451 Special deposits 63,412 27,614 Customer accounts receivable (less allowance for doubtful accounts of $24,676 and $23,365) 282,218 245,125 LRPP receivable 69,558 54,512 Other accounts receivable 107,387 14,030 Accrued unbilled revenues 184,440 164,379 Materials and supplies at average cost 63,595 74,777 Fuel oil at average cost 32,090 37,723 Gas in storage at average cost 53,076 68,447 Deferred tax asset 191,000 213,996 Prepayments and other current assets 8,986 5,327 - ----------------------------------------------------------------------------------------------------- Total Current Assets 1,407,215 1,091,381 - ----------------------------------------------------------------------------------------------------- Deferred Charges 21,023 172,768 - ----------------------------------------------------------------------------------------------------- Total Assets $ 12,484,369 $ 12,478,910 ===================================================================================================== See Notes to Financial Statements.
(In thousands of dollars) - ----------------------------------------------------------------------------------------------------- Capitalization and Liabilities at December 31 1995 1994 - ----------------------------------------------------------------------------------------------------- Capitalization Long-term debt $ 4,722,675 $ 5,162,675 Unamortized discount on debt (16,075) (17,278) - ----------------------------------------------------------------------------------------------------- 4,706,600 5,145,397 - ----------------------------------------------------------------------------------------------------- Preferred stock - redemption required 639,550 644,350 Preferred stock - no redemption required 63,934 63,957 - ----------------------------------------------------------------------------------------------------- Total Preferred Stock 703,484 708,307 - ----------------------------------------------------------------------------------------------------- Common stock 598,277 592,083 Premium on capital stock 1,114,508 1,101,240 Capital stock expense (50,751) (52,175) Retained earnings 790,919 752,480 - ----------------------------------------------------------------------------------------------------- Total Common Shareowners' Equity 2,452,953 2,393,628 - ----------------------------------------------------------------------------------------------------- Total Capitalization 7,863,037 8,247,332 - ----------------------------------------------------------------------------------------------------- Regulatory Liabilities Regulatory liability component 277,757 357,117 1989 Settlement credits 136,655 145,868 Regulatory tax liability 116,060 111,218 Other 132,694 147,041 - ----------------------------------------------------------------------------------------------------- Total Regulatory Liabilities 663,166 761,244 - ----------------------------------------------------------------------------------------------------- Current Liabilities Current maturities of long-term debt 415,000 25,000 Current redemption requirements of preferred stock 4,800 4,800 Accounts payable and accrued expenses 260,879 241,775 Accrued taxes (including federal income tax of $28,736 and $28,340) 60,498 58,133 Accrued interest 158,325 149,929 Dividends payable 57,899 57,367 Class Settlement 45,833 35,833 Customer deposits 29,547 28,474 - ----------------------------------------------------------------------------------------------------- Total Current Liabilities 1,032,781 601,311 - ----------------------------------------------------------------------------------------------------- Deferred Credits Deferred federal income tax 2,337,732 2,204,023 Class Settlement 129,809 151,604 Other 8,708 9,774 - ----------------------------------------------------------------------------------------------------- Total Deferred Credits 2,476,249 2,365,401 - ----------------------------------------------------------------------------------------------------- Operating Reserves Pensions and other postretirement benefits 396,490 453,016 Claims and damages 52,646 50,606 - ----------------------------------------------------------------------------------------------------- Total Operating Reserves 449,136 503,622 - ----------------------------------------------------------------------------------------------------- Commitments and Contingencies - - - ----------------------------------------------------------------------------------------------------- Total Capitalization and Liabilities $ 12,484,369 $12,478,910 =====================================================================================================
See Notes to Financial Statements.
Statement of Retained Earnings (In thousands of dollars) - ------------------------------------------------------------------------------------- 1995 1994 1993 - ------------------------------------------------------------------------------------- Balance at January 1 $ 752,480 $ 711,432 $ 667,988 Net income for the year 303,286 301,852 296,563 - ------------------------------------------------------------------------------------- 1,055,766 1,013,284 964,551 Deductions Cash dividends declared on common stock 212,181 207,794 197,236 Cash dividends declared on preferred stock 52,647 53,046 55,861 Other 19 (36) 22 - ------------------------------------------------------------------------------------- Balance at December 31 $ 790,919 $ 752,480 $ 711,432 =====================================================================================
See Notes to Financial Statements.
Statement of Capitalization Shares Outstanding (In thousands of dollars) - -------------------------------------------------------------------------------------------- At December 31 1995 1994 1995 1994 - -------------------------------------------------------------------------------------------- Common Shareowners' Equity Common stock, $5.00 par value 119,655,441 118,416,606 $ 598,277 $ 592,083 Premium on capital stock 1,114,508 1,101,240 Capital stock expense (50,751) (52,175) Retained earnings 790,919 752,480 - -------------------------------------------------------------------------------------------- Total Common Shareowners' Equity 2,452,953 2,393,628 - -------------------------------------------------------------------------------------------- Preferred Stock - Redemption Required Par value $100 per share 7.40% Series L 171,500 182,000 17,150 18,200 8.50% Series R 37,500 75,000 3,750 7,500 7.66% Series CC 570,000 570,000 57,000 57,000 Less - Sinking fund requirement 4,800 4,800 - -------------------------------------------------------------------------------------------- 73,100 77,900 - -------------------------------------------------------------------------------------------- Par value $25 per share 7.95% Series AA 14,520,000 14,520,000 363,000 363,000 $1.67 Series GG 880,000 880,000 22,000 22,000 $1.95 Series NN 1,554,000 1,554,000 38,850 38,850 7.05% Series QQ 3,464,000 3,464,000 86,600 86,600 6.875% Series UU 2,240,000 2,240,000 56,000 56,000 - -------------------------------------------------------------------------------------------- 566,450 566,450 - -------------------------------------------------------------------------------------------- Total Preferred Stock - Redemption Required 639,550 644,350 - -------------------------------------------------------------------------------------------- Preferred Stock - No Redemption Required Par value $100 per share 5.00% Series B 100,000 100,000 10,000 10,000 4.25% Series D 70,000 70,000 7,000 7,000 4.35% Series E 200,000 200,000 20,000 20,000 4.35% Series F 50,000 50,000 5,000 5,000 5 1/8% Series H 200,000 200,000 20,000 20,000 5 3/4% Series I - Convertible 19,336 19,569 1,934 1,957 - -------------------------------------------------------------------------------------------- Total Preferred Stock - No Redemption Required 63,934 63,957 - -------------------------------------------------------------------------------------------- Total Preferred Stock $ 703,484 $ 708,307 - --------------------------------------------------------------------------------------------
See Notes to Financial Statements.
(In thousands of dollars) ---------------------------------------------------------------------------------------------------- At December 31 Maturity Interest Series 1995 1994 ---------------------------------------------------------------------------------------------------- First Mortgage Bonds June 1, 1995 4.55% O $ - $ 25,000 March 1, 1996 5 1/4% P - 40,000 April 1, 1997 5 1/2% Q - 35,000 ----------------------------------------------------------------------------------------------------- Total First Mortgage Bonds - 100,000 ----------------------------------------------------------------------------------------------------- General and Refunding Bonds May 1, 1996 8 3/4% 415,000 415,000 February 15, 1997 8 3/4% 250,000 250,000 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 1,951,000 1,951,000 ----------------------------------------------------------------------------------------------------- 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% 1976A,B 2,000 2,000 Pollution Control Revenue Bonds December 1, 2006 7.50% 1976A 28,375 28,375 December 1, 2009 7.80% 1979B 19,100 19,100 October 1, 2012 8 1/4% 1982 17,200 17,200 March 1, 2016 4.70% 1985A,B 150,000 150,000 Electric Facilities Revenue Bonds September 1, 2019 7.15% 1989A,B 100,000 100,000 June 1, 2020 7.15% 1990A 100,000 100,000 December 1, 2020 7.15% 1991A 100,000 100,000 February 1, 2022 7.15% 1992A,B 100,000 100,000 August 1, 2022 6.90% 1992C,D 100,000 100,000 November 1, 2023 5.00% 1993A 50,000 50,000 November 1, 2023 5.05% 1993B 50,000 50,000 October 1, 2024 4.95% 1994A 50,000 50,000 August 1, 2025 5.00% 1995A 50,000 - ----------------------------------------------------------------------------------------------------- Total Authority Financing Notes 916,675 866,675 ----------------------------------------------------------------------------------------------------- Unamortized Discount on Debt (16,075) (17,278) ----------------------------------------------------------------------------------------------------- Total 5,121,600 5,170,397 Less Current Maturities 415,000 25,000 ----------------------------------------------------------------------------------------------------- Total Long-Term Debt 4,706,600 5,145,397 ----------------------------------------------------------------------------------------------------- Total Capitalization $ 7,863,037 $ 8,247,332 ==========================================================================================================
See Notes to Financial Statements.
Statement of Cash Flows (In thousands of dollars) - ------------------------------------------------------------------------------------------------- For year ended December 31 1995 1994 1993 - ------------------------------------------------------------------------------------------------- Operating Activities Net Income $ 303,286 $ 301,852 $ 296,563 Adjustments to reconcile net income to net cash provided by operating activities Depreciation and amortization 145,357 130,664 122,471 Base financial component amortization 100,971 100,971 100,971 Rate moderation component amortization 21,933 197,656 88,667 Regulatory liability component amortization (79,359) (79,359) (79,359) 1989 Settlement credits amortization (9,214) (9,214) (9,214) Other regulatory amortization 161,605 4,328 (18,044) Rate moderation component carrying charges (25,274) (32,321) (40,004) Amortization of cost of issuing and redeeming securities 39,589 46,237 52,063 Class Settlement 21,669 22,730 23,178 Provision for doubtful accounts 17,751 19,542 18,555 Federal income tax - deferred and other 190,942 165,928 165,952 Other 61,576 46,531 9,228 Changes in operating assets and liabilities Accounts receivable (67,213) (17,353) (65,898) Class Settlement (33,464) (30,235) (25,302) Accrued unbilled revenues (20,061) 5,663 (26,870) Accounts payable and accrued expenses 19,100 (44,598) (8,800) Other (77,194) 6,727 (22,144) - ------------------------------------------------------------------------------------------------- Net Cash Provided by Operating Activities 772,000 835,749 582,013 - ------------------------------------------------------------------------------------------------- Investing Activities Construction and nuclear fuel expenditures (243,586) (276,954) (302,220) Shoreham post-settlement costs (70,589) (167,367) (207,114) Other investing activities 8,019 (1,349) (934) - ------------------------------------------------------------------------------------------------- Net Cash Used in Investing Activities (306,156) (445,670) (510,268) - ------------------------------------------------------------------------------------------------- Financing Activities Proceeds from issuance of securities 68,726 449,434 1,305,802 Redemption of securities (104,800) (639,858) (1,165,600) Common stock dividends paid (211,630) (205,086) (195,794) Preferred stock dividends paid (52,667) (52,927) (56,727) Other financing activities 529 (4,723) (20,379) - ------------------------------------------------------------------------------------------------- Net Cash Used in Financing Activities (299,842) (453,160) (132,698) - ------------------------------------------------------------------------------------------------- Net Increase (Decrease) in Cash and Cash Equivalents $ 166,002 $ (63,081) $ (60,953) ================================================================================================= Cash and cash equivalents at January 1 $ 185,451 $ 248,532 $ 309,485 Net increase (decrease) in cash and cash equivalents 166,002 (63,081) (60,953) - ------------------------------------------------------------------------------------------------- Cash and Cash Equivalents at December 31 $ 351,453 $ 185,451 $ 248,532 ================================================================================================= Interest paid, before reduction for the allowance for borrowed funds used during constuction $ 427,988 $ 446,340 $ 469,978 Federal income tax - paid $ 14,200 $ 10,780 $ 6,000 Federal income tax - refunded $ - $ - $ 1,000 - -------------------------------------------------------------------------------------------------
See Notes to Financial Statements. Notes to Financial Statements Note 1. Summary of Significant Accounting Policies Nature of Operations Long Island Lighting Company (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 1995 estimate, is about 2.7 million persons, including approximately 98,000 persons who reside in Queens County within the City of New York. The Company serves approximately 1 million electric customers of which approximately 915,000 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 453,000 gas customers, 408,000 of which are residential, accounting for 62% of the gas revenues, with the balance of the gas revenues made up by the commercial/industrial customer class. The Company believes that its current customer base is stable. 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. 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 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. The Company records these future economic benefits and obligations as regulatory assets and liabilities. Regulatory assets represent probable future revenues to the Company 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 $6.8 billion and $6.9 billion at December 31, 1995 and 1994, respectively. 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 affirmation of its 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. As discussed more fully in Note 10, the PSC has initiated Competitive Opportunities Proceedings seeking ways to transition the electric industry to full retail competition, the outcome of which could result in significant changes in the way the Company will be regulated in the future. 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, all or a portion of the Company's existing regulatory assets and liabilities would be written-off. For additional information respecting the Company's Shoreham-related assets, see Note 10. Effective January 1, 1996, the Company adopted SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of" which amends SFAS No. 71. Under SFAS No. 121, costs which were capitalized, 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 the asset would be reduced by disallowed costs. SFAS No. 121 also provides for the restoration of previously disallowed costs that are subsequently allowed by a regulator. The adoption of SFAS No. 121 is not expected to have an effect on the Company's financial position or results of operations. Discussed below are the Company's significant regulatory assets and regulatory liabilities. Base Financial Component and Rate Moderation Component Pursuant to the 1989 Settlement, as more fully discussed in Note 2, 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 forty years 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 Nine Mile Point Nuclear Power Station, Unit 2 (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. For a further discussion of the 1989 Settlement and FRA, see Notes 2 and 3. Shoreham Post-Settlement Costs The balance consists 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 2. Shoreham Nuclear Fuel The balance 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. Unamortized Cost of Issuing Securities The balance 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 over the shorter of the life of the redeemed issue or the new issue as provided by the PSC. 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 and postretirement benefit expense reflected in current rates. Pursuant to a PSC order, the ongoing annual SFAS No. 106 benefit expense must be phased into and fully reflected in rates by November 30, 1997, ending with the accumulated deferred asset being recovered in rates over the next fifteen-year period. 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 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 The balance 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. Allowance for Funds Used During Construction The Uniform Systems of Accounts 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 FERC on a portion of construction work in progress. The average annual AFC rate, without giving effect to compounding, was 9.36%, 9.18% and 9.73% for the years 1995, 1994 and 1993, respectively. 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. Depreciation for electric properties was equivalent to approximately 3.0% of respective average depreciable plant costs for each of the years 1995, 1994 and 1993. Depreciation for gas properties was equivalent to approximately 2.0% of respective average depreciable plant costs for each of the years 1995, 1994 and 1993. 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. 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 which is based upon the Company's current incremental borrowing rate for similar types of securities. Revenues Revenues are based on cycle billings rendered to certain customers monthly and others bi-monthly. The Company also accrues electric and gas revenues for services rendered to customers but not billed at month-end. The Company's electric rate structure as discussed in Note 3, 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 structure provides for a weather normalization clause which reduces the impact on revenues of experiencing weather which is warmer or colder than normal. 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. Federal Income Tax The Company provides deferred federal income tax with respect to certain items of income and expense that are reported in different years for federal income tax purposes and financial statement purposes and 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 and taxable income. Also, certain accumulated deferred federal income tax are 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 $35 million. Storm losses which are outside of this range, as well as the uninsured layers within this range, are self-insured by the Company. 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. The 1989 Settlement On February 28, 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 the Long Island Power Authority (LIPA), an agency of the State of New York, for its subsequent decommissioning. 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. The FRA has two components, the BFC and the RMC. For a further discussion of the FRA, see Note 1. On February 29, 1992, the Company transferred ownership of Shoreham to LIPA. Pursuant to the 1989 Settlement, the Company was required to reimburse LIPA for all of its costs associated with the decommissioning of Shoreham. Effective May 1, 1995, the Nuclear Regulatory Commission (NRC) terminated LIPA's possession-only license for Shoreham. The termination signified the NRC's approval that decommissioning was complete and that the site is suitable for unrestricted use. At December 31, 1995, Shoreham post- settlement costs totaled approximately $1.052 billion, consisting of $487 million of property taxes and payments-in-lieu-of-taxes, and $565 million of decommissioning costs, fuel disposal costs and all other costs incurred at Shoreham after June 30, 1989. 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. Note 3. Rate Matters Electric In 1993, the Company filed an Electric Rate Plan (Plan) with the PSC for the three-year period which began December 1, 1994. The goals of this Plan included minimizing future electric rate increases in addition to providing for the continued recovery of the Company's regulatory assets while retaining consistency with the Rate Moderation Agreement's (RMA) objective of restoring the Company to financial health. As a result of the rate proceeding initiated by the filing of the Company's Plan, the PSC issued an Order, in 1995, for the rate year beginning December 1, 1994, which among other things, froze overall 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 under the heading "Modifications to the LILCO Ratemaking and Performance Plan". In addition, the PSC ordered that the rate proceeding be continued to allow the parties to develop a plan for achieving long-term rate stability, while, among other things, providing for the continuing recovery of the Shoreham- related assets. In its rate decision, the PSC reaffirmed its commitment to allow the Company to recover its Shoreham-related assets, noting that it is a crucial factor in the Company's ability to maintain its investment grade bond rating and to secure reasonably priced capital. The continuation of the rate proceeding will also enable the PSC to consider the Company's operations and its opportunities for greater efficiency over the next several years. In 1995, the Company, through a compliance filing, requested a continuation of the rate freeze for the rate year beginning December 1, 1995. The PSC has yet to issue an electric rate order in response to this filing. In February 1996, the PSC issued an order to show cause and instituted a proceeding to examine various opportunities to reduce the Company's current electric rates. Specifically, the Company has been directed to address the following: (i) should all or a part of the $81 million Suffolk County property tax refund that the Company received in January 1996, pursuant to a judgment in the Company's favor that found that the Shoreham property was overvalued for property tax purposes between 1976 and 1983 (excluding 1979 which had previously been settled), be used to reduce current rates; (ii) should the return of the $26 million 1995 rate year net reconciliation credit to customers, as more fully discussed below, be accelerated; (iii) determine, upon review of the forecasts reflected in the September 1995 compliance filing for the rate year commencing December 1, 1995, whether adjustments to the forecasts can be reflected in rate reductions currently; and (iv) revisit the current mechanics of the Fuel Cost Adjustment (FCA) clause, as more fully discussed in Note 1, to determine whether all or a portion of any fuel cost savings can be reflected in current customer bills. The Company has been directed to submit a response to the order to show cause addressing these items. Interested parties will have an opportunity to submit comments on the Company's filing, after which a hearing before an ALJ will be convened and the ALJ will determine further procedures. The Company is unable to predict the outcome of this proceeding and the impact, if any, that it may have on the Company's cash flow, financial condition or results of its operations. While no assurances can be given, the Company's objective is to continue the current rate freeze through the rate year ending November 30, 1997. Rate Moderation Component The RMA, one of the constituent documents of the 1989 Settlement, provides for the full recovery of the RMC. The RMC balance represents deferred revenues to be collected from customers which result from the difference between conventional revenue requirements and revenues provided for under the 1989 Settlement and subsequent rate orders. Prior to December 31, 1992, the RMC had increased as the difference between revenues resulting from the implementation of the rate moderation plan provided for in the RMA and revenue requirements under conventional ratemaking, together with a carrying charge computed at the Company's allowed return on common equity, was deferred. The RMC had provided the Company with a substantial amount of non-cash earnings from the effective date of the 1989 Settlement through December 31, 1992. For the period December 31, 1992 through December 31, 1994, the RMC balance had decreased as revenues resulting from the operation of the rate moderation plan exceeded revenue requirements under conventional ratemaking. During 1995, the Company was able to reduce the RMC balance by approximately $80 million by applying credits generated by the operation of the Company's Fuel Moderation Component Mechanism (FMC), as described below, and by crediting certain deferred customer benefits to the RMC, as prescribed by the PSC. The FMC and deferred customer benefits, which amounted to $87 million and $86 million, respectively, more than offset the accretion of the RMC resulting from revenues under the current electric rate order being less than the Company's revenue requirements under conventional ratemaking. The FMC mechanism, which is included in the Company's FCA clause, allows the Company to collect the higher of the base cost of fuel included in electric rates or the actual cost of fuel. The actual cost of fuel consumed for electric generation for 1995 was approximately $87 million below the base cost of fuel, enabling the Company to use this excess to credit and thus reduce the RMC balance. For the years ended December 31, 1994 and 1993, the Company credited the RMC balance $83 million and $45 million, respectively, as a result of the operation of the FMC mechanism. To assist in the recovery of the RMC balance, the Company, as authorized by the PSC, has credited the RMC with $86 million of deferred customer benefits, as noted above. These credits consisted principally of: (i) deferred amounts collected in rates that because of the Company's cost containment programs had not been expended for enhanced reliability and production operations and maintenance expenses during the term of the LRPP; (ii) net litigation proceeds related to the construction of Shoreham; and (iii) proceeds from the sale of sulfur dioxide emissions credits. For the years ended December 31, 1994 and 1993, the Company credited the RMC balance with deferred customer benefits totaling $5.1 million and $10.1 million, respectively. Modifications to the Lilco Ratemaking and Performance Plan In November 1991, the PSC approved the Lilco Ratemaking and Performance Plan (LRPP). The LRPP contained three major components: (i) revenue reconciliation; (ii) expense attrition and reconciliation; and (iii) performance-based incentives. In its latest electric rate order, the PSC has 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 current electric rate order, which became effective December 1, 1994, 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 current rate 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 is subject to a maximum penalty of 38 basis points of the allowed return on common equity and can earn up to 4 basis points under the customer service program. This 4 basis point incentive can only be used to offset a penalty under the transmission and distribution reliability program. Under the original LRPP, the Company was allowed to earn up to 40 basis points or forfeit up to 18 basis points under these incentive programs. The partial passthrough 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, 1995, the Company earned 19 basis points, or approximately $4.0 million, net of tax effects, as a result of its performance under all incentive programs. In each of the rate years ended November 30, 1994 and 1993, the Company earned 50 and 49 basis points, respectively, or approximately $9.2 million, net of tax effects, under the incentive programs in effect at those times. The deferred balances resulting from the net margin expense reconciliations, and earned performance-based incentives are netted at the end of each rate year and, as established under the LRPP and continuing under the current rate order, the first $15 million of the total deferral is used to increase or decrease 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, 1995, the amount to be returned to customers resulting from the revenue and expense reconciliations, performance-based incentive programs and associated carrying charges totaled $41 million. In accordance with the current electric rate order, and as established under the LRPP, the first $15 million of the deferral will be used to reduce the RMC. The remaining balance of $26 million is expected to be returned to the customers through the FCA over a 12-month period. For the rate years ended November 30, 1994 and 1993, the Company recorded deferred charges of approximately $79 million and $63 million, respectively. The first $15 million of the rate year ended November 30, 1993 was applied as an increase to the RMC while the remaining deferrals of $48 million were recovered from customers through the FCA. It is anticipated that the first $15 million of deferrals for the rate year ended November 30, 1994 will be reclassified to increase the RMC balance upon approval by the PSC of the Company's pending reconciliation filing and that the remaining $64 million will be recovered from customers through the FCA. Another provision of the LRPP, which is continuing under the current rate structure, is a mechanism whereby 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 year ended November 30, 1995, the Company earned $3.3 million, net of tax effects, in excess of its allowed return on common equity which was fully applied as a reduction to the RMC. In 1994, the Company did not earn in excess of its allowed return on common equity, while for the rate year ended November 30, 1993, the Company earned $8.9 million, net of tax effects, in excess of the allowed return on common equity which was shared equally between customers (by a reduction to the RMC) and shareowners. Under the modified mechanism currently in effect, all excess earnings are allocated to customers via a reduction to the RMC. Gas In December 1993, the PSC approved a three-year gas rate settlement between the Company and the Staff of the PSC. The gas rate settlement provides that the Company receive, for each of the rate years beginning December 1, 1993, 1994 and 1995, annual gas rate increases of 4.7%, 3.8% and 3.2%, respectively. In the determination of the revenue requirements for the gas rate settlement, an allowed return on common equity of 10.1% was used. The gas rate decision also provides 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, 1995, and 1994, the Company earned approximately $1.5 million and $9.2 million, net of tax effects, respectively, in excess of the 10.6% return on common equity. The firm gas customers' portion of these excess earnings amounting to $0.8 million and $4.6 million, net of tax effects, respectively, has been deferred. The PSC has granted the Company permission to retain the customers' portion of the 1994 rate year excess earnings through the term of the gas rate settlement agreement and apply such excess earnings to the recovery of deferred Postretirement Benefits Other Than Pensions or manufactured gas plant (MGP) site cleanup costs. For a further discussion of Postretirement Benefits Other Than Pensions and MGP costs, see Notes 8 and 10, respectively. The Company has requested that the same treatment be granted for the disposition of the customer's portion of the 1995 rate year excess earnings which amounted to $1.5 million. Note 4. The Class Settlement The Class Settlement, which became effective on June 28, 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. Upon its effectiveness, the Company recorded its liability for the Class Settlement on a present value basis at $170 million and simultaneously recorded a charge to income (net of tax effects of $57 million) of approximately $113 million. The Class Settlement provides the Company's electric customers with reductions that are being reflected as adjustments to their monthly electric bills over a ten-year period which began on June 1, 1990. The remaining reductions to customers bills, amounting to approximately $247 million as of December 31, 1995, consists of approximately $17 million for the five-month period beginning January 1, 1996, $50 million for the 12-month period beginning June 1, 1996 and $60 million for each of the 12-month periods beginning June 1, 1997, 1998 and 1999, respectively. Note 5. Nine Mile Point Nuclear Power Station, Unit 2 The Company has an 18% undivided interest in NMP2, located near Oswego, New York which is operated by Niagara Mohawk Power Corporation (NMPC). Ownership of NMP2 is shared by five cotenants: 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%). At December 31, 1995, the Company's utility plant investment in NMP2 included in rate base was $740 million, net of accumulated depreciation of $153 million. Generation from NMP2 and operating expenses incurred by NMP2 are shared in the same proportions as the cotenants' respective ownership interests. The Company's share of operating expenses is included on its Statement of Income. 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. 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 1995, 1994 and 1993, this totaled $1.2 million, $1.4 million, and $1.0 million, respectively. 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. In 1995, NMPC completed a decommissioning study for NMP2 (1995 study) which is currently under evaluation by the Company and the other cotenants. The Company's share of decommissioning costs under the 1995 study is estimated to be $418 million in 2026 dollars ($145 million in 1995 dollars). Previously, the Company's share of decommissioning costs was $234 million in 2026 dollars, which was based upon a 1989 study which was updated to reflect a change in the NRC minimum decommissioning funding requirement. The increase included in the 1995 study is primarily due to the inclusion of nuclear fuel storage charges and costs for continuing care of the nuclear site. The Company's share of the estimated decommissioning costs, based upon the 1989 study, is currently being provided for in electric rates and is being charged to operations as depreciation expense over the expected service life of NMP2. The Company believes that the incremental decommissioning costs identified in the 1995 study will also be recoverable through rates. The amount of decommissioning costs recorded as depreciation expense in 1995, 1994 and 1993 was $2.3 million, $1.6 million and $1.7 million, respectively. The accumulated decommissioning costs collected in rates through December 31, 1995, 1994 and 1993 amounted to $11.0 million, $8.7 million and $7.1 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 77% of the total decommissioning costs. These funds comply with regulations issued by the NRC and FERC governing the funding of nuclear plant decommissioning costs. The Company's policy is to make contributions to the funds based upon the amount of decommissioning costs collected in rates. As of December 31, 1995, the balance in these funds, including reinvested net earnings, was approximately $10.3 million. These amounts are included on the Company's Balance Sheet in Special deposits. 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 Financial Accounting Standards Board issued an exposure draft in 1996 entitled "Accounting for Certain Liabilities Related to Closure or Removal of Long-Lived Assets". If the provisions of the exposure draft were adopted, 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. The Company cannot presently predict the impact, if any, that this exposure draft will have on the Company's financial condition. Note 6. Capital Stock Common Stock The Company has 150,000,000 shares of authorized common stock, of which 119,655,441 were issued and outstanding at December 31, 1995. The Company has 1,707,443 shares reserved for sale through its Employee Stock Purchase Plan, 3,812,382 shares committed to the Automatic Dividend Reinvestment Plan and 112,798 shares reserved for conversion of the Series I Convertible Preferred Stock at a rate of $17.15 per share. 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 December 31, 1995 and 1994 amounted to approximately $598 million and $564 million, respectively, compared to their carrying amounts of $644 million and $649 million, respectively. For a further discussion on the fair value of the securities discussed above, See Note 1. Each year the Company is required to redeem certain series of preferred stock through the operation of sinking fund provisions as follows:
Redemption Number Redemption Series Provision Beginning of Shares Price ------ ------------------- --------- ----- L July 31, 1979 10,500 $100 R December 15, 1982 37,500 100 NN March 1, 1999 77,700 25 UU October 15, 1999 112,000 25
In addition, the Company 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 NN and UU. The aggregate par value of preferred stock required to be redeemed through sinking funds in 1996 is $4.8 million, $1.1 million in 1997 and 1998 and $5.8 million in 1999 and 2000. 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:
Redemption Number of Redemption Series Date Shares Amounts ------ ---- ------ ------- $1.67 Series GG March 1, 1999 880,000 $ 22,000,000 7.95% Series AA June 1, 2000 14,520,000 363,000,000 7.05% Series QQ May 1, 2001 3,464,000 86,600,000 7.66% Series CC August 1, 2002 570,000 57,000,000
Preferred Stock Not Subject to Mandatory Redemption The Company has the option to redeem certain series of its preferred stock. For the series subject to optional redemption at December 31, 1995, the call prices were as follows:
Series Call Price ------ ---------- 5.00% Series B $101 4.25% Series D 102 4.35% Series E 102 4.35% Series F 102 5 1/8% Series H 102 5 3/4% Series I - Convertible 100
Preference Stock At December 31, 1995, 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 During 1995, the Company retired the remaining $100 million of First Mortgage Bonds with cash on hand. As a result, the lien of the First Mortgage has been discharged making the General and Refunding Bonds (G&R Bonds) 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 1995, due not later than June 30, 1996, is estimated at $25 million. The Company expects to satisfy this requirement with retired G&R Bonds, plant additions or with cash on hand, or any combination thereof. 1989 Revolving Credit Agreement The Company has available through October 1, 1996, $300 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. At December 31, 1995, no amounts were outstanding under the 1989 RCA. The Company has agreed to pay a fee of one quarter of one percent per annum on the unused portion. The 1989 RCA may be extended for one-year periods upon the acceptance by the lending banks of a request by the Company, which must be delivered to the lending banks prior to April 1 of each year. It is the Company's intent to request an extension prior to April 1, 1996. 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 December 31, 1995 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 1997 4.70% 1985 A,B 150,000 Tendered annually on March 1 EFRBs 5.00% 1993 A 50,000 Tendered weekly 5.05% 1993 B 50,000 Tendered weekly 4.95% 1994 A 50,000 Tendered weekly 5.00% 1995 A 50,000 Tendered weekly
The 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 $381 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 March 16, 1999 EFRBs 1993 A,B November 17, 1996 1994 A October 26, 1997 1995 A August 24, 1998
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 1996, the Company amended the letter of credit for the PCRBs to extend the stated expiration date to March 16, 1999. Fair Values of Long-Term Debt The carrying amounts and fair values of the Company's long-term debt at December 31 were as follows:
(In thousands of dollars) - --------------------------------------------------------------------------------- 1995 - --------------------------------------------------------------------------------- Fair Carrying Value Amount - --------------------------------------------------------------------------------- General and Refunding Bonds $1,968,173 $1,951,000 Debentures 2,245,138 2,270,000 Authority Financing Notes 928,967 916,675 - --------------------------------------------------------------------------------- Total $5,142,278 $5,137,675 ================================================================================= 1994 - --------------------------------------------------------------------------------- First Mortgage Bonds $ 95,688 $ 100,000 General and Refunding Bonds 1,844,289 1,951,000 Debentures 1,867,510 2,270,000 Authority Financing Notes 829,651 866,675 - --------------------------------------------------------------------------------- Total $4,637,138 $5,187,675 =================================================================================
For a further discussion on the fair value of the securities listed above, see Note 1. Maturity Schedule The total long-term debt maturing in each of the next five years is as follows: 1996, $415 million; 1997, $251 million; 1998, $101 million; 1999, $454 million; and 2000, $37 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 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 (ERISA) 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 service and compensation. The Primary Plan's funded status and amounts recognized on the Balance Sheet at December 31, 1995 and 1994 were as follows:
(In thousands of dollars) - -------------------------------------------------------------------------------- 1995 1994 - -------------------------------------------------------------------------------- Actuarial present value of benefit obligation Vested benefits $ 518,487 $ 467,962 Nonvested benefits 54,305 50,385 - -------------------------------------------------------------------------------- Accumulated Benefit Obligation $ 572,792 $ 518,347 ================================================================================ Plan assets at fair value $ 685,300 $ 597,200 Actuarial present value of projected benefit obligation 662,360 592,339 - -------------------------------------------------------------------------------- Projected benefit obligation less than plan assets 22,940 4,861 Unrecognized net obligation 77,831 84,577 Unrecognized net gain (97,285) (90,335) - -------------------------------------------------------------------------------- Net Prepaid (Accrued) Pension Cost $ 3,486 $ (897) ================================================================================
Periodic pension cost for the Primary Plan included the following components:
(In thousands of dollars) - -------------------------------------------------------------------------------------- 1995 1994 1993 - -------------------------------------------------------------------------------------- Service cost - benefits earned during the period $ 15,385 $ 16,465 $ 14,481 Interest cost on projected benefit obligation and service cost 45,987 43,782 $ 41,865 Actual return on plan assets (102,099) (12,431) $ (54,010) Net amortization and deferral 57,665 (31,633) $ 10,025 - -------------------------------------------------------------------------------------- Net Periodic Pension Cost $ 16,938 $ 16,183 $ 12,361 ======================================================================================
Assumptions used in accounting for the Primary Plan were as follows:
1995 1994 1993 ---- ---- ---- Discount rate 7.25% 7.75% 7.25% Rate of future compensation increases 5.00% 5.00% 5.00% Long-term rate of return on assets 7.50% 7.50% 7.50%
The Primary Plan assets at fair value include cash, cash equivalents, group annuity contracts, bonds and listed 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. This change in the annual pension cost calculation reduced pension expense by $4.6 million in the year of adoption, 1993. 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 the difference between the pension rate allowance and the annual pension contributions contributed into the pension fund. Supplemental Plan The Supplemental Plan, the cost of which is borne by the Company's shareowners, 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. Death benefits are currently provided by insurance. The provision for plan benefits, which are unfunded, totaled approximately $2.3 million in both 1995 and 1994, and $2.8 million in 1993. 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 $114,000, $148,000, and $150,000 in 1995, 1994 and 1993, respectively. Postretirement Benefits Other Than Pensions In addition to providing pension benefits, the Company provides certain medical and life insurance benefits for 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. Additionally, as a result of adopting SFAS No. 106, the Company's postretirement benefit cost for 1993 increased by $28 million above the amount that would have been recorded under the pay-as-you-go method. In 1993, the PSC issued an Order which required that the effects of implementing SFAS No. 106 be phased into rates. The Order 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 will be phased into and fully reflected in rates within a five-year period from the year of adoption, which began December 1, 1993, with the accumulated regulatory asset being 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 1994, the Company established Voluntary Employee's Beneficiary Association (VEBA) trusts for union and non-union employees for the funding of incremental costs collected in rates for postretirement benefits. For the years ended December 31, 1995 and 1994, the Company funded the trusts with approximately $50 million and $2 million, respectively. Accumulated postretirement benefit obligation other than pensions at December 31 was as follows:
(In thousands of dollars) - ------------------------------------------------------------------------------------- 1995 1994 - ------------------------------------------------------------------------------------- Retirees $ 135,497 $ 159,590 Fully eligible plan participants 52,028 57,788 Other active plan participants 142,035 133,030 - ------------------------------------------------------------------------------------- Accumulated postretirement benefit obligation $ 329,560 $ 350,408 Plan assets (53,646) (2,200) - ------------------------------------------------------------------------------------ Accumulated postretirement benefit obligation in excess of plan assets 275,914 348,208 Unrecognized net gain 100,335 73,936 - ------------------------------------------------------------------------------------- Accrued Postretirement Benefit Cost $ 376,249 $ 422,144 =====================================================================================
At December 31, 1995, the Plan assets at fair value include cash and cash equivalents of $53.5 million and listed equity securities of the Company representing $0.1 million. At December 31, 1994, the Plan assets at fair value include cash and cash equivalents of approximately $2.2 million. Periodic postretirement benefit cost other than pensions for the years were as follows:
(In thousands of dollars) - -------------------------------------------------------------------------------------- 1995 1994 1993 - -------------------------------------------------------------------------------------- Service cost - benefits earned during the period $ 9,082 $ 11,275 $ 12,980 Interest cost on projected benefit obligation and service cost 22,412 25,713 29,531 Actual return on plan assets (1,034) - - Amortization of net gain (14,699) (5,213) - - -------------------------------------------------------------------------------------- Periodic Postretirement Benefit Cost $ 15,761 $ 31,775 $ 42,511 ======================================================================================
Assumptions used to determine the postretirement benefit obligation were as follows:
1995 1994 1993 ---- ---- ---- Discount rate 7.25% 7.75% 7.25% Rate of future compensation increases 5.00% 5.00% 5.00% Long-term rate of return on assets 7.50% - -
The assumed health care cost trend rates used in measuring the accumulated postretirement benefit obligation at December 31, 1995 and 1994 were 8.5% and 9.0%, respectively, gradually declining to 6.0% in 2001 and thereafter. A one percentage point increase in the health care cost trend rate would increase the accumulated postretirement benefit obligation as of December 31, 1995 and 1994 by approximately $36 million and $44 million, respectively, and the sum of the service and interest costs in 1995 and 1994 by $4 million and $6 million, respectively. Note 9. Federal Income Tax At December 31, the significant components of the Company's deferred tax assets and liabilities calculated under the provisions of SFAS No. 109 were as follows:
(In thousands of dollars) - -------------------------------------------------------------------------------------- 1995 1994 - -------------------------------------------------------------------------------------- Deferred Tax Assets Net operating loss carryforwards $ 338,921 $ 552,917 Reserves not currently deductible 66,825 86,267 Tax depreciable basis in excess of book 41,428 48,557 Nondiscretionary excess credits 29,826 31,933 Credit carryforwards 149,545 142,329 Other 125,246 89,763 - --------------------------------------------------------------------------------------- Total Deferred Tax Assets $ 751,791 $ 951,766 - --------------------------------------------------------------------------------------- Deferred Tax Liabilities 1989 Settlement $ 2,155,418 $ 2,174,729 Accelerated depreciation 628,475 608,302 Call premiums 50,062 56,324 Rate case deferrals 28,971 55,598 Other 35,597 46,840 - --------------------------------------------------------------------------------------- Total Deferred Tax Liabilities 2,898,523 2,941,793 - --------------------------------------------------------------------------------------- Net Deferred Tax Liability $ 2,146,732 $ 1,990,027 =======================================================================================
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) - -------------------------------------------------------------------------------------- 1995 1994 - -------------------------------------------------------------------------------------- Regulatory Assets 1989 Settlement $ 1,666,744 $ 1,672,820 Plant items 149,520 169,743 Other (13,881) (10,874) - -------------------------------------------------------------------------------------- Total Regulatory Assets $ 1,802,383 $ 1,831,689 ====================================================================================== Regulatory Liabilities Carryforward credits $ 82,330 $ 75,114 Other 33,730 36,104 - -------------------------------------------------------------------------------------- Total Regulatory Liabilities $ 116,060 $ 111,218 ======================================================================================
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) - --------------------------------------------------------------------------------------------- 1995 1994 1993 - --------------------------------------------------------------------------------------------- Income before federal income tax $ 508,824 $ 478,564 $ 468,839 Statutory federal income tax rate 35% 35% 35% Statutory federal income tax $ 178,088 $ 167,497 $ 164,094 Additions (reductions) in federal income tax Excess of book depreciation over tax depreciation 18,588 14,745 12,437 1989 Settlement 4,213 4,213 4,256 Interest capitalized 2,218 2,449 3,443 Tax credits (1,025) (2,058) (5,586) Rate case adjustments 3,752 (4,779) (1,285) Allowance for funds used during construction (2,392) (2,450) (2,304) Other items 2,096 (2,905) (2,779) - --------------------------------------------------------------------------------------------- Total Federal Income Tax Expense $ 205,538 $ 176,712 $ 172,276 ============================================================================================= Effective Federal Income Tax Rate 40.4% 36.9% 36.7% =============================================================================================
The Company's net operating loss (NOL) carryforwards for federal income tax purposes are estimated to be approximately $968 million at December 31, 1995. The Company anticipates that it will fully utilize its NOL carryforwards by the end of 1997, however, should they not be utilized they will expire in the years 2004 through 2007. The Company currently has tax credit carryforwards of approximately $150 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 $142 million and research and development credits totaling approximately $8 million. The credit carryforwards will expire in the years 1998 through 2010. For financial reporting purposes, a valuation allowance was not required to offset the deferred tax assets related to these carryforwards. Realization is dependent on generating sufficient taxable income prior to expiration of the loss carryforwards. Although realization is not assured, the Company believes it is more likely than not that all of the deferred tax assets will be realized. The amount of the deferred tax assets considered realizable, however, could be reduced in the near term if estimates of future taxable income during the carryforward period are reduced. 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. The Revenue Agents' Reports reflect proposed adjustments to the Company's federal income tax returns for this period which, if sustained, would give rise to tax deficiencies totaling approximately $227 million. The Company believes that any such deficiencies as finally determined would be significantly less than the amounts proposed in the Revenue Agents' Reports. The Revenue Agents have also proposed ITC adjustments which, if sustained, would reduce the ITC carryforwards by approximately $96 million. The Company has protested some of the proposed adjustments which are presently under review by the Regional Appeals Office of the Internal Revenue Service. If this review does not result in a settlement that is satisfactory to the Company, the Company intends to seek a judicial review. The Company believes that its reserves are adequate to cover any tax deficiency that may ultimately be determined and that cash from operations will be sufficient to satisfy any settlement reached. Note 10. Commitments and Contingencies Commitments The Company has entered into substantial commitments for gas supply, purchased power and transmission facilities. The costs associated with these commitments are recovered from customers through provisions in the Company's rate tariffs. The Company expended approximately $1 million in 1995 to meet continuous emission monitoring requirements and to meet Phase I nitrogen oxide (NOx) reduction requirements under the federal Clean Air Act (CAA). Subject to requirements that are expected to be promulgated in forthcoming regulations, the Company estimates that it may be required to expend approximately $50 to 60 million (net of NOx credit sales) by 2003 to meet Phase II and Phase III Nox reduction requirements and approximately $24 million by 1999 to meet potential requirements for the control of hazardous air pollutants from power plants. The Company believes that all of the above costs will be recoverable through rates. Contingencies Long Island Power Authority Proposed Plan During 1995, the Governor of the State of New York requested that the Long Island Power Authority (LIPA) develop a plan that, in addition to replacing the Company as the primary electric and gas utility on Long Island, would among other things, produce an electric rate reduction of at least 10%, provide a framework for long-term competition in power production and protect property taxpayers on Long Island. In response to this request, the Board of Trustees of LIPA established a committee (Evaluation Committee) to analyze various plans involving the Company's business operations and assets. In December 1995, after soliciting information and indications of interest from various parties in connection with a LIPA-facilitated financial restructuring/acquisition of the Company, the members of the Evaluation Committee and their advisors announced a proposed plan to restructure the Company and reduce electric rates on Long Island by 12% (Proposed Plan). The Proposed Plan, which has not been adopted by the LIPA Board or formally presented to the Company's Board of Directors for consideration, generally provides that: (i) the Company sell, subject to LIPA's approval, its gas business and electric generation assets; (ii) LIPA purchase the Company's transmission, distribution and Shoreham-related assets; (iii) LIPA enter into long-term power purchase agreements with the purchasers of the generation assets; (iv) LIPA enter into agreements with contractors to manage the transmission and distribution system; and (v) LIPA exercise its power of eminent domain over all or a portion of the Company's assets or securities in order to achieve its objectives if a negotiated agreement cannot be reached with the Company. The Company has indicated to LIPA that certain elements of the Proposed Plan raise significant concerns. Specifically, the Proposed Plan contains no information regarding the values or prices contemplated to be paid for the Company's assets, no financing commitments for any portion of the proposed transaction were disclosed and no indications that endorsements by certain State officials required to approve any transaction undertaken by LIPA have been obtained. In addition, based on the limited information currently available, the Company is unable to determine how the anticipated rate reduction would be achieved and how the reliability of the electric system, including storm restoration capabilities, would be maintained given the multiple entities that would be responsible for providing such service. Notwithstanding these concerns, the Company remains willing to cooperate with LIPA in developing a plan that is beneficial to the Company's investors, customers and employees. The Company is continuously assessing various other strategies in an effort to provide the greatest possible value to its constituents in light of the changing economic, regulatory and political challenges affecting the Company. Such strategies may include a review and modification of its operations to best meet the challenges of a competitive environment, a possible reorganization of the Company, potential joint ventures and/or possible business combinations with other entities. The implementation of certain plans involving the Company's business operations and assets would be subject to, among other things, shareholder and regulatory approvals and could impact the Company's future financial results and operations. Accordingly, the Company is unable to determine what plan, if any, will be pursued by it and/or LIPA or whether any related transaction will be consummated. 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 1995, both the Public Service Commission of the State of New York (PSC) and the Federal Energy Regulatory Commission (FERC) continued their separate initiatives with respect to developing a framework for a competitive electric marketplace. New York State Competitive Opportunities Proceedings 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. During 1995, the proceedings continued with the PSC adopting a series of principles which it will use to guide the transition of the electric utility industry in New York State from a rate-regulated cost of service model to a competitive market-driven model. The principles state, among other things, that: (i) consumers should have a reasonable opportunity to realize savings from competition; (ii) a basic level of reasonably priced service must be maintained; (iii) the integrity, safety and reliability of the system should not be jeopardized; and (iv) the current industry structure, in which most power plants are vertically integrated with natural monopoly transmission and distribution systems, should be thoroughly examined to ensure that it does not impede or obstruct the development of effective wholesale or retail competition. In addition, the principles state that utilities should have a reasonable opportunity to recover prudent and verifiable expenditures and commitments made pursuant to their legal obligations, consistent with these principles. In October 1995, the Energy Association, which is comprised of the Company and the six other investor-owned New York State utilities, filed a proposal designed to achieve the principles outlined by the PSC. The proposal, which is referred to as the "Wholesale Poolco Model", establishes a framework that will allow competition at the wholesale level. The plan would, among other things: (i) allow utilities, non-regulated generators and other market participants to create a wholesale exchange that allows market forces to determine the price of wholesale electricity; (ii) establish an Independent System Operator (ISO) to coordinate the safe and reliable operation of the bulk power transmission system; (iii) increase customer choice by providing clear market price signals so customers can make informed decisions on the use of electricity; and (iv) separate the generation portion of a utility's business from its regulated transmission and distribution business. In this model, competing generating suppliers would bid energy sales into the market. The market clearing price for energy would be determined by the bid of the highest price unit needed to serve the load in a particular location. Regulated utility companies could purchase energy from the market, which would establish a half-hour locational spot market price for electricity, or the utility could seek to enter into bilateral energy agreements with other parties. Bilateral agreements would be administered independently of the wholesale exchange, but would be scheduled through the ISO. These bilateral agreements would be permitted among utility companies, generating companies and power marketers. In the Wholesale Poolco Model, the purchase of electricity by end use customers would still be bundled with transmission, distribution and customer service, all of which would be provided by regulated utilities. The support of the New York State utilities for the Wholesale Poolco Model is predicated on a number of factors, including: (i) a reasonable opportunity to fully recover all investments and expenditures made to provide reliable service under the existing regulatory compact; (ii) PSC support for the option of each utility to continue in the generation business; (iii) special treatment of nuclear plants based on their unique characteristics; and (iv) the adoption of a clearly defined transition plan to ensure that the interests of the customer and the investor are adequately protected. In December 1995, an Administrative Law Judge (ALJ) of the PSC issued a Recommended Decision (RD) to the PSC with respect to this Competitive Opportunities Proceedings. The ALJ recommended a competitive model which seeks to transition the electric utility industry in New York State to full retail competition through two stages. The first stage of this recommendation seeks to transition the industry from its current cost of service rate regulation to a competitive wholesale model similar to the Wholesale Poolco Model. This first stage would allow participants to become familiar with the operation of a deregulated, competitive generation market prior to the eventual movement to full retail competition in the second stage, through a model known as the Flexible Retail Poolco Model. The Flexible Retail Poolco Model contains many of the same attributes associated with the Wholesale Poolco Model, including: (i) an ISO to coordinate the safe and reliable operation of generation and transmission; (ii) open access to the transmission system, which would be regulated by FERC; and (iii) the continuation of a regulated distribution company to operate and maintain the distribution system. The principal difference between the models is that customers would have a choice among suppliers of electricity in the Flexible Retail Poolco Model whereas in the Wholesale Poolco Model, the regulated entity would acquire electric energy from the spot energy sales exchange to sell to the customer. The Flexible Retail Poolco Model would also: (i) deregulate energy/customer services such as meter reading and customer billing; (ii) unbundle electricity into four components: generation, transmission, distribution, and energy/customer services; and (iii) provide customers with a choice among suppliers of electricity, and allow customers to acquire electricity either by long-term contracts or purchases on the spot market or a combination of the two. One of the most contentious issues of the Competitive Opportunities Proceedings has been the position taken by the various parties to the proceedings on the amount of recovery utilities should be permitted to collect from customers for so-called stranded investments. Stranded investments represent costs that utilities would have otherwise recovered through rates under traditional cost of service regulation that, under competition, utilities may not be able to recover since the market price for their product may be inadequate to recover these costs. The Staff of the PSC, for example, has indicated that utilities should not expect full recovery of stranded costs. The Energy Association has commented that utilities have a sound legal precedent confirmed by long-standing PSC policy to fully recover all prudently incurred costs, including stranded costs. The RD states that for recovery, stranded costs must be prudent, verifiable and unable to be reduced through mitigation measures. The RD states that recovery of stranded costs be predicated on the prudency of the costs incurred. The costs must be verifiable and the Company must show that it was unable to avoid incurring these costs. The RD states that a generic decision should address the definition, the method of measurement, the requirements for mitigation, a preferable recovery mechanism, and a standard for the recovery of stranded investments. The calculation of the amount to be recovered from customers, however, should be left to individual rate cases or special proceedings that should begin during 1996. The RD further directs New York State investor-owned utilities to individually file, within six months of the PSC's order, a comprehensive long-term proposal addressing the significant components of the RD. 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 these proceedings could adversely affect the Company's ability to apply Statement of Financial Accounting Standards (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" and SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of," could then require a significant write-down of assets, the amount of which cannot presently be determined. For a further discussion of SFAS No. 71 and SFAS No. 121, see Note 1. The Electric Industry - Federal Regulatory Issues As a result of Congress' passage of the Public Utility Regulatory Policies Act of 1978 (PURPA), and the National Energy Policy Act of 1992 (NEPA), the once monopolistic electric utility industry now faces competition. PURPA's goal is to reduce the United States' dependence on foreign oil, encourage energy conservation and promote diversification of fuel supply. Accordingly, PURPA provided for the development of a new class of electric generators which rely on either cogeneration technology or alternate fuels. The utilities are obligated under PURPA to purchase the output of certain of these new generators, which are known as qualified facilities (QFs). 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 (i.e., sales to an entity for resale to the ultimate consumer). NEPA does so by creating exempt wholesale generators that can sell power in wholesale markets without the regulatory constraints placed on utility generators such as the Company. NEPA also expanded FERC's authority to grant access to utility transmission systems to all parties who seek wholesale wheeling for wholesale competition. Significant issues associated with the removal of restrictions on wholesale transmission system access have yet to be resolved and the potential impact on the Company's financial position cannot yet be determined. FERC is in the process of setting policy which will largely determine how wholesale competition will be implemented. FERC has declared that utilities must provide wholesale wheeling to others that is comparable to the service utilities provide themselves. FERC has issued policy statements concerning regional transmission groups, transmission information requirements and "good faith" requests for service and transmission pricing. In March 1995, FERC issued a Notice of Proposed Rulemaking (NOPR) which combined the issues of open transmission access and stranded cost recovery. The NOPR contained a strong endorsement of the right of the utilities to full recovery of stranded costs due to wholesale wheeling and retail-turned-wholesale wheeling arrangements. During the year, FERC has followed up on these issues through an extensive comment period, holding public hearings on pro-forma transmission tariffs, ancillary services, real-time information systems and power pooling issues. FERC recently announced its interest in exploring the role of an ISO in providing comparable transmission access. It is expected that FERC will issue a final order on open access in 1996. Utilities, including the Company, and numerous other interested parties are actively involved in these proceedings. It is not possible to predict the outcome of these proceedings or the effect, if any, on the financial condition of the Company. The Company participates in the wholesale electricity market primarily as a buyer, and in this regard should benefit if rules are adopted which result in lower wholesale prices for its retail customers. The Company's Service Territory The changing utility regulatory environment has affected the Company in a number of ways. For example, PURPA's encouragement of the non-utility generator (NUG) industry has negatively impacted the Company. In 1995, the Company lost sales to NUGs totaling 366 gigawatt-hours (Gwh) representing a loss in electric revenues net of fuel (net revenues) of approximately $28 million, or 1.5% of the Company's net revenues. In 1994, the Company lost sales to NUGs totaling 237 Gwh or approximately $24 million of net revenues. The increase in lost net revenues resulted principally from the completion, in April 1995, of a QF located at the State University of New York at Stony Brook, New York (Stony Brook Project). The annual load loss due to this QF is estimated to be 188 Gwh. The Company estimates that in 1996, sales losses to NUGs will be 414 Gwh an increase reflecting 12 months of operation for the Stony Brook Project or approximately 1.7% 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 in 1995 and 1994 approximated 205 megawatts (MW). 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 now only applies 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. The Company estimates that purchases from QFs required by federal and state law cost the Company $53 million more than it would have cost had the Company generated this power in both 1995 and 1994. 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 in 1995 and 1994 NYPA power displaced approximately 429 Gwh and 400 Gwh of annual energy sales, respectively. The net revenue loss associated with this amount of sales is approximately $30 million or 1.6% of the Company's 1995 net revenues and $28 million or 1.5% of the Company's 1994 net revenues. Currently, the potential loss of additional load is limited by conditions in the Company's transmission agreements with NYPA. Aside from NUGs, 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 likely to increase as a result of NEPA. The Town of Southampton and several other towns in the Company's service territory are considering the formation of a municipally owned and operated electric authority to replace the services currently provided by the Company. Suffolk County issued a request for proposal from suppliers for up to 200 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. The Company has responded that it does not believe the County is eligible under present laws and regulations to purchase wholesale power and resell it to retail customers, and has declined to offer the requested retail wheeling service. 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. 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 FERC may take regarding any of these matters, or the impact on the Company's financial condition 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 rate 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. Environment The Company is subject to federal, state and local laws and regulations dealing with air and water quality and other environmental matters. The Company continually monitors its activities in order to determine the impact of such 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 (NYSDEC) 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 is believed to have produced manufactured gas. The Company expects to enter into an Administrative Consent Order (ACO) with the NYDEC in 1996 regarding the management of environmental activities at these properties. Although the exact amount of the Company's clean-up costs, cannot yet be determined, based on the findings of investigations at two of these six sites, preliminary estimates indicate that it will cost approximately $35 million to clean up all of these sites over the next five to ten years. Accordingly, the Company had recorded a $35 million liability and a corresponding regulatory asset to reflect its belief that the PSC will provide for the future recovery of these costs through rates as it has for other New York State utilities. The Company has notified its former and current insurance carriers that it seeks to recover from them certain of these investigation and clean-up costs. However, the Company is unable to predict the amount of insurance recovery, if any, that it may obtain. In addition, there are several other sites within the Company's service territory that were former MGP sites. Research is underway to determine their relationship, if any, to the Company or its predecessor companies. 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 been notified by the Environmental Protection Agency (EPA) that it is one of many potentially responsible parties (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, have entered into an ACO with the EPA to conduct a Remedial Investigation and Feasibility Study (RI/FS). Under a PRP participant agreement, the Company is responsible for 8.2% of the costs associated with this RI/FS which has been completed and is currently being reviewed by the EPA. The Company's total share of costs to date is approximately $0.5 million. The level of remediation required will be determined when the EPA issues its decision. Based on information available to date, the Company currently anticipates that the total cost to remediate this site will be between $14 million and $30 million. The Company has recorded a liability of $1.1 million representing its estimated share of the additional cost to remediate this site. With respect to the other two sites, located in Kansas City, Kansas and Kansas City, Missouri, the Company is investigating allegations that it had made agreements for disposal of polychlorinated biphenyls (PCBs) or items containing PCBs at these sites. The EPA has provided the Company with documents indicating that the Company was responsible for less than 1% of the total weight of the PCB-containing equipment, oil and materials that were shipped to the Missouri site. The EPA has not yet completed compiling documents for the Kansas site. The Company is currently unable to determine its share, if any, of the cost to remediate these two sites or the impact, if any, on the Company's financial position. In addition, the Company was notified that it is a PRP at a Superfund Site in Farmingdale, New York. Portions of the site are allegedly contaminated with PCBs, solvents and metals. The Company was also notified by other PRPs that it should be responsible for expenses in the amount of approximately $0.1 million 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 the cost to remediate this site or the impact, if any, on the Company's financial position. The Connecticut Department of Environmental Protection (DEP) and the Company have signed an ACO which will require the Company to address leaks from an electric transmission cable located under the Long Island Sound (Sound Cable). The Sound Cable is jointly owned by the Company and the Connecticut Light and Power Company, a subsidiary of Northeast Utilities. Specifically, the order requires the Company to evaluate existing procedures and practices for cable maintenance, operations and fluid spill response procedures and to propose alternatives to minimize fluid spill occurrences and their impact on the environment. Alternatives to be evaluated range from improving existing monitoring and maintenance practices to removal and replacement of the Sound Cable. The Company is currently unable to determine the costs it will incur to complete the requirements of the ACO or to comply with any additional DEP requirements. In addition, the Company has been served with a subpoena from the U.S. Attorney for the District of Connecticut to supply certain written information regarding releases of fluid from the Sound Cable, as well as associated operating and maintenance practices. Since the investigation is in its preliminary stages, the Company is unable to determine the likelihood of a criminal proceeding being initiated at this time. However, the Company believes all activities associated with the response to releases from the Sound Cable were consistent with legal and regulatory requirements. The Company believes that all significant costs incurred with respect to environmental investigations and remediation activities will be recoverable through rates. Nuclear Plant Insurance The NRC requires the owners of nuclear facilities to maintain certain types of insurance. For property damage at each nuclear generating site, the NRC requires a minimum of $1.06 billion of coverage. With respect to third party liability and property damage, the NRC requires nuclear plant owners to carry $200 million in primary coverage. Pursuant to these requirements, the Company carries property insurance and third-party bodily injury and property liability insurance for its 18% share in NMP2. The annual premiums for this coverage are not material. The third-party liability and property damage insurance policies also include retroactive premiums under certain circumstances. The retroactive premium is related to the NRC's requirement that nuclear facility owners, in addition to carrying $200 million in primary coverage, also participate in a Secondary Financial Protection Fund (Fund). Under the Price Anderson Act, that assessment related to the Fund could be up to $79.3 million per nuclear incident in any one year at any nuclear unit, but not in excess of $10 million in payments per year for each incident. The Price Anderson Act also limits liability for third-party bodily injury and third-party property damage arising out of a nuclear occurrence at each unit to $8.9 billion. The Company is liable for its share of any retroactive premium assessment levied against the NMP2 owners. Note 11. Segments of Business 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 and unamortized cost of issuing securities.
(In millions of dollars) - --------------------------------------------------------------------------------- For year ended December 31 1995 1994 1993 - --------------------------------------------------------------------------------- Operating revenues Electric $ 2,484 $ 2,481 $ 2,352 Gas 591 586 529 - --------------------------------------------------------------------------------- Total $ 3,075 $ 3,067 $ 2,881 ================================================================================= Operating expenses (excludes federal income tax) Electric $ 1,657 $ 1,640 $ 1,514 Gas 478 500 427 - --------------------------------------------------------------------------------- Total $ 2,135 $ 2,140 $ 1,941 ================================================================================= Operating income (before federal income tax) Electric $ 827 $ 842 $ 838 Gas 113 85 102 - --------------------------------------------------------------------------------- Total operating income 940 927 940 AFC (7) (7) (7) Other income and deductions (38) (45) (56) Interest charges 476 500 534 Federal income tax 206 177 172 - --------------------------------------------------------------------------------- Net Income $ 303 $ 302 $ 297 ================================================================================= Depreciation and Amortization Electric $ 122 $ 112 $ 106 Gas 23 19 16 - --------------------------------------------------------------------------------- Total $ 145 $ 131 $ 122 ================================================================================= Construction and nuclear fuel expenditures* Electric $ 162 $ 155 $ 171 Gas 84 125 134 - --------------------------------------------------------------------------------- Total $ 246 $ 280 $ 305 ================================================================================= Identifiable Assets Electric $ 9,964 $ 10,264 $ 10,377 Gas 1,180 1,181 956 - --------------------------------------------------------------------------------- Total identifiable assets 11,144 11,445 11,333 Assets utilized for overall Company operations 1,340 1,034 1,121 - --------------------------------------------------------------------------------- Total Assets $ 12,484 $ 12,479 $ 12,454 =================================================================================
* Includes non-cash allowance for other funds used during construction and excludes Shoreham post-settlement costs. Note 12. Quarterly Financial Information (Unaudited)
(In thousands of dollars except earnings per common share) - ------------------------------------------------------------------------------------------ 1995 1994 - ------------------------------------------------------------------------------------------ Operating Revenues For the quarter ended March 31 $ 791,188 $ 872,143 June 30 653,824 626,310 September 30 875,794 913,440 December 31 754,322 655,414 ========================================================================================== Operating Income For the quarter ended March 31 $ 180,875 $ 183,865 June 30 143,246 139,478 September 30 239,561 276,965 December 31 167,936 144,637 ========================================================================================== Net Income For the quarter ended March 31 $ 70,299 $ 69,620 June 30 41,392 24,787 September 30 131,221 168,872 December 31 60,374 38,573 ========================================================================================== Earnings for Common Stock For the quarter ended March 31 $ 57,127 $ 56,348 June 30 28,220 11,516 September 30 118,069 155,620 December 31 47,250 25,348 ========================================================================================== Earnings per Common Share For the quarter ended March 31 $ .48 $ .50 June 30 .24 .10 September 30 .99 1.32 December 31 .39 .21 ==========================================================================================
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 December 31, 1995 and 1994 and the related statements of income, retained earnings and cash flows for each of the three years in the period ended December 31, 1995. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits 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 December 31, 1995 and 1994, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1995, in conformity with generally accepted accounting principles. /s/ Ernst & Young LLP Melville, New York February 7, 1996
(In thousands of dollars except per share amounts) - ------------------------------------------------------------------------------------------------------------ 1995 1994 1993 1992 1991 - ------------------------------------------------------------------------------------------------------------ Summary of Operations Table 1 - ------------------------------------------------------------------------------------------------------------ Revenues $ 3,075,128 $ 3,067,307 $ 2,880,995 $ 2,621,839 $ 2,547,729 Operating expenses 2,343,510 2,322,362 2,125,444 1,880,734 1,762,449 - ------------------------------------------------------------------------------------------------------------ Operating income 731,618 744,945 755,551 741,105 785,280 Other income and (deductions) 43,703 52,719 70,874 66,330 40,482 - ------------------------------------------------------------------------------------------------------------ Income before interest charges 775,321 797,664 826,425 807,435 825,762 Interest charges 472,035 495,812 529,862 505,461 520,224 - ------------------------------------------------------------------------------------------------------------ Net income 303,286 301,852 296,563 301,974 305,538 Preferred stock dividend requirements 52,620 53,020 56,108 63,954 66,394 - ------------------------------------------------------------------------------------------------------------ Earnings for Common Stock $ 250,666 $ 248,832 $ 240,455 $ 238,020 $ 239,144 ============================================================================================================ Average common shares outstanding (000) 119,195 115,880 112,057 111,439 111,348 Earnings per Common Share $ 2.10 $ 2.15 $ 2.15 $ 2.14 $ 2.15 ============================================================================================================ Common stock dividends declared per share $ 1.78 $ 1.78 $ 1.76 $ 1.72 $ 1.60 Common stock dividends paid per share $ 1.78 $ 1.78 $ 1.75 $ 1.71 $ 1.55 Book value per common share at December 31 $ 20.50 $ 20.21 $ 19.88 $ 19.58 $ 19.13 Common shares outstanding at December 31 (000) 119,655 118,417 112,332 111,600 111,365 Common shareowners of record at December 31 93,088 96,491 94,877 86,111 90,435 ============================================================================================================
- ------------------------------------------------------------------------------------------------------------ Capitalization Ratios* Table 2 - ------------------------------------------------------------------------------------------------------------ Long-term debt 61.8% 62.5% 65.0% 64.7% 63.9% Preferred stock 8.6 8.6 8.5 8.8 8.8 Common equity 29.6 28.9 26.5 26.5 27.3 - ------------------------------------------------------------------------------------------------------------ Total 100.0% 100.0% 100.0% 100.0% 100.0% ============================================================================================================
*Includes current maturities of long-term debt and current redemption requirements of preferred stock.
(In thousands of dollars) - ------------------------------------------------------------------------------------------------------------ Operations and Maintenance Expense Details Table 3 - ------------------------------------------------------------------------------------------------------------ Payroll and employee benefits $ 440,721 $ 435,830 $ 418,766 $ 420,297 $ 403,983 Less - Charged to construction and other 165,733 155,766 130,432 131,447 121,911 - ------------------------------------------------------------------------------------------------------------ Payroll and employee benefits charged to operations 274,988 280,064 288,334 288,850 282,072 - ------------------------------------------------------------------------------------------------------------ Fuel and Purchased Power Fuel - electric operations 266,039 261,154 287,349 282,138 354,859 Fuel - gas operations 264,282 267,629 253,511 206,344 172,992 Purchased power costs 309,807 307,584 292,136 280,914 197,154 Fuel cost adjustments deferred (5,149) 11,619 (5,405) (27,612) 43,697 - ------------------------------------------------------------------------------------------------------------ Total fuel and purchased power 834,979 847,986 827,591 741,784 768,702 - ------------------------------------------------------------------------------------------------------------ All other 236,405 260,590 233,326 209,095 240,687 - ------------------------------------------------------------------------------------------------------------ Total Operations and Maintenance Expense $ 1,346,372 $ 1,388,640 $ 1,349,251 $ 1,239,729 $ 1,291,461 ============================================================================================================ Full-time Employees at December 31 5,688 5,947 6,215 6,438 6,538 - ------------------------------------------------------------------------------------------------------------
(In thousands of dollars) - ------------------------------------------------------------------------------------------------------------- - ------------------------------------------------------------------------------------------------------------- 1995 1994 1993 1992 1991 - ------------------------------------------------------------------------------------------------------------- Electric Operating Income Table 4 - ------------------------------------------------------------------------------------------------------------- Revenues - ------------------------------------------------------------------------------------------------------------- Residential $ 1,204,987 $ 1,202,124 $ 1,145,891 $ 1,045,799 $ 1,047,490 Commercial and industrial 1,194,014 1,196,422 1,132,487 1,076,302 1,070,098 Other system revenues 52,472 52,477 49,790 49,395 47,838 - ------------------------------------------------------------------------------------------------------------- Total system revenues 2,451,473 2,451,023 2,328,168 2,171,496 2,165,426 Sales to other utilities 19,104 14,895 12,872 9,997 23,040 Other revenues 13,437 15,719 11,069 13,139 8,102 - ------------------------------------------------------------------------------------------------------------- Total Revenues 2,484,014 2,481,637 2,352,109 2,194,632 2,196,568 - ------------------------------------------------------------------------------------------------------------- Operating Expenses Operations - fuel and purchased power 570,697 568,738 579,032 559,583 593,656 Operations - other 293,184 310,438 306,116 294,909 296,798 Maintenance 106,031 107,573 111,765 105,341 127,446 Depreciation and amortization 121,980 111,996 106,149 104,034 104,172 Base financial component amortization 100,971 100,971 100,971 100,971 100,971 Rate moderation component amortization 21,933 197,656 88,667 (30,444) (228,572) Regulatory liability component amortization (79,359) (79,359) (79,359) (79,359) (79,359) 1989 Settlement credits amortization (9,214) (9,214) (9,214) (9,214) (9,214) Other regulatory amortization 155,532 (4,883) (17,082) (21,984) 10,375 Operating taxes 375,164 336,263 326,407 331,122 338,429 Federal income tax - current 14,596 10,784 6,324 530 515 Federal income tax - deferred and other 168,377 156,646 158,941 158,908 173,259 - ------------------------------------------------------------------------------------------------------------- Total Operating Expenses 1,839,892 1,807,609 1,678,717 1,514,397 1,428,476 - ------------------------------------------------------------------------------------------------------------- Electric Operating Income $ 644,122 $ 674,028 $ 673,392 $ 680,235 $ 768,092 =============================================================================================================
(In thousands of dollars) - ------------------------------------------------------------------------------------------------------------- Gas Operating Income Table 5 - ------------------------------------------------------------------------------------------------------------- Revenues - ------------------------------------------------------------------------------------------------------------- Residential - space heating $ 323,729 $ 326,474 $ 310,109 $ 243,950 $ 190,976 - other 42,046 42,263 39,515 33,035 29,383 Commercial and industrial - space heating 130,964 126,092 106,140 90,363 70,938 - other 34,293 35,275 33,181 29,094 25,515 - ------------------------------------------------------------------------------------------------------------- Total firm revenues 531,032 530,104 488,945 396,442 316,812 Interruptible revenues 32,837 26,804 24,028 19,658 21,686 - ------------------------------------------------------------------------------------------------------------- Total system revenues 563,869 556,908 512,973 416,100 338,498 Off-system revenues, net 16,213 20,904 5,812 - - Other revenues 11,032 7,858 10,101 11,107 12,663 - ------------------------------------------------------------------------------------------------------------- Total Revenues 591,114 585,670 528,886 427,207 351,161 - ------------------------------------------------------------------------------------------------------------- Operating Expenses Operations - fuel 264,282 279,248 248,559 182,201 175,046 Operations - other 90,054 95,576 81,692 77,300 78,469 Maintenance 22,124 27,067 22,087 20,395 20,046 Depreciation and amortization 23,377 18,668 16,322 15,103 14,783 Other regulatory amortization 6,073 9,211 (962) (88) - Operating taxes 72,343 70,632 59,440 57,866 49,951 Federal income tax - deferred and other 25,365 14,351 19,589 13,560 (4,322) - ------------------------------------------------------------------------------------------------------------- Total Operating Expenses 503,618 514,753 446,727 366,337 333,973 - ------------------------------------------------------------------------------------------------------------- Gas Operating Income $ 87,496 $ 70,917 $ 82,159 $ 60,870 $ 17,188
- ------------------------------------------------------------------------------------------------------------- - ------------------------------------------------------------------------------------------------------------- 1995 1994 1993 1992 1991 - ------------------------------------------------------------------------------------------------------------- Electric Sales and Customers Table 6 - ------------------------------------------------------------------------------------------------------------- Sales - millions of kWh Residential 7,156 7,159 7,118 6,788 7,022 Commercial and industrial 8,336 8,394 8,257 8,181 8,322 Other system sales 460 457 449 471 469 - ------------------------------------------------------------------------------------------------------------- Total system sales 15,952 16,010 15,824 15,440 15,813 Sales to other utilities 620 372 304 227 598 - ------------------------------------------------------------------------------------------------------------- Total Sales 16,572 16,382 16,128 15,667 16,411 ============================================================================================================= Customers - monthly average Residential 915,162 908,490 905,997 902,885 898,974 Commercial and industrial 103,669 102,490 102,254 101,838 101,740 Other 4,549 4,583 4,553 4,593 4,540 - ------------------------------------------------------------------------------------------------------------- Total Customers - monthly average 1,023,380 1,015,563 1,012,804 1,009,316 1,005,254 ============================================================================================================= Customers - at December 31 1,025,107 1,016,739 1,011,965 1,009,028 1,005,363 - ------------------------------------------------------------------------------------------------------------- Residential kWh per customer 7,819 7,880 7,857 7,518 7,811 Revenue per kWh 16.84c. 16.79c. 16.10c. 15.41c. 14.92c. - ------------------------------------------------------------------------------------------------------------- Commercial and Industrial kWh per customer 80,410 81,901 80,750 80,333 81,797 Revenue per kWh 14.32c. 14.25c. 13.72c. 13.16c. 12.86c. - ------------------------------------------------------------------------------------------------------------- System kWh per customer 15,588 15,765 15,624 15,297 15,730 Revenue per kWh 15.37c. 15.31c. 14.71c. 14.06c. 13.69c. =============================================================================================================
- ------------------------------------------------------------------------------------------------------------- Gas Sales and Customers Table 7 - ------------------------------------------------------------------------------------------------------------- Sales - thousands of dth Residential - space heating 35,336 35,693 37,191 35,089 29,687 - other 2,929 3,151 3,297 3,203 3,195 Commercial and industrial - space heating 16,170 15,679 14,366 13,662 11,636 - other 4,269 4,366 4,329 4,338 4,171 - ------------------------------------------------------------------------------------------------------------- Total firm sales 58,704 58,889 59,183 56,292 48,689 Interruptible sales 9,176 6,914 5,920 5,090 4,538 Off-system sales 7,743 7,232 2,894 - - - --------------------------------------------------------------------------------------------------------------- Total Sales 75,623 73,035 67,997 61,382 53,227 =============================================================================================================== Customers - monthly average Residential - space heating 245,452 239,857 233,882 227,834 220,562 - other 162,114 163,608 166,974 169,189 171,581 Commercial and industrial - space heating 35,027 33,776 32,783 31,666 30,453 - other 10,313 10,448 10,631 10,777 11,003 - ------------------------------------------------------------------------------------------------------------- Total firm customers 452,906 447,689 444,270 439,466 433,599 Interruptible customers 623 576 542 531 472 - ------------------------------------------------------------------------------------------------------------- Total Customers - monthly average 453,529 448,265 444,812 439,997 434,071 ============================================================================================================= Customers - at December 31 455,869 449,906 446,384 442,117 436,853 - ------------------------------------------------------------------------------------------------------------- Residential dth per customer 93.9 96.3 101.0 96.4 83.9 Revenue per dth $ 9.56 $ 9.49 $ 8.64 $ 7.23 $ 6.70 - ------------------------------------------------------------------------------------------------------------- Commercial and Industrial dth per customer 450.8 453.3 430.6 424.1 381.3 Revenue per dth $ 8.09 $ 8.05 $ 7.45 $ 6.64 $ 6.10 - ------------------------------------------------------------------------------------------------------------- System dth per customer 149.7 146.8 146.4 139.5 122.6 Revenue per dth $ 8.31 $ 8.46 $ 7.88 $ 6.78 $ 6.36 - -------------------------------------------------------------------------------------------------------------
- ------------------------------------------------------------------------------------------------------------ 1995 1994 1993 1992 1991 - ------------------------------------------------------------------------------------------------------------ Electric Operations Table 8 - ------------------------------------------------------------------------------------------------------------ Energy - millions of kWh Net generation 10,744 10,034 10,514 10,592 13,570 Power purchased 7,143 7,640 7,023 6,438 4,236 - ------------------------------------------------------------------------------------------------------------ Total Energy Available 17,887 17,674 17,537 17,030 17,806 ============================================================================================================ System sales 15,952 16,010 15,824 15,440 15,813 Company use and unaccounted for 1,315 1,292 1,409 1,363 1,395 - ------------------------------------------------------------------------------------------------------------ Total system energy requirements 17,267 17,302 17,233 16,803 17,208 Sales to other utilities 620 372 304 227 598 - ------------------------------------------------------------------------------------------------------------ Total Energy Available 17,887 17,674 17,537 17,030 17,806 ============================================================================================================ Peak Demand - MW Station coincident demand 3,591 3,253 2,931 2,975 3,085 Power purchased - net 486 629 1,036 636 819 - ------------------------------------------------------------------------------------------------------------ System Peak Demand 4,077 3,882 3,967 3,611 3,904 ============================================================================================================ System Capability - MW Company stations 3,957 4,063 4,063 4,091 4,078 Nine Mile Point 2 (18% share) 203 189 188 188 194 Firm purchases - net 713 616 548 432 423 - ------------------------------------------------------------------------------------------------------------ Total Capability 4,873 4,868 4,799 4,711 4,695 ============================================================================================================ Fuel Consumed for Electric Operations Oil - thousands of barrels 5,154 7,518 9,740 10,656 15,314 Gas - thousands of dth 69,826 44,308 36,269 34,475 32,924 Nuclear - thousands of MW days - thermal 169 203 175 124 154 - ------------------------------------------------------------------------------------------------------------ Fuel Mix (Percentage of total energy available) Oil 17 % 25 % 34 % 37 % 50 % Gas 36 23 19 19 18 Purchased power 40 43 40 38 25 Nuclear fuel 7 9 7 6 7 - ------------------------------------------------------------------------------------------------------------ Total 100 % 100 % 100 % 100 % 100 % ============================================================================================================
- ------------------------------------------------------------------------------------------------------------ Gas Operations Table 9 - ------------------------------------------------------------------------------------------------------------ Company Requirements-thousands of dth System sales 67,880 65,803 65,103 61,382 53,227 Off-system sales 7,743 7,232 2,894 - - Company use and unaccounted for 2,054 2,516 1,905 3,577 2,412 - ------------------------------------------------------------------------------------------------------------ Total Company Requirements 77,677 75,551 69,902 64,959 55,639 ============================================================================================================ Maximum Day Sendout - dth 564,874 585,227 485,896 448,726 435,050 - ------------------------------------------------------------------------------------------------------------ System Capability - dth per day Natural gas 592,335 579,897 561,584 561,584 507,344 LNG manufactured or LP gas 124,700 125,700 120,700 120,700 128,200 - ------------------------------------------------------------------------------------------------------------ Total Capability 717,035 705,597 682,284 682,284 635,544 ============================================================================================================ Heating Degree Days (30 year average 4,969) 4,906 4,839 4,899 5,066 4,378 - ------------------------------------------------------------------------------------------------------------
(In thousands of dollars) - ------------------------------------------------------------------------------------------------------------- 1995 1994 1993 1992 1991 - ------------------------------------------------------------------------------------------------------------- Balance Sheet Table 10 - ------------------------------------------------------------------------------------------------------------- Assets Net utility plant $ 3,594,998 $ 3,498,346 $ 3,347,557 $ 3,161,148 $ 3,002,733 Regulatory Assets Base financial component 3,382,519 3,483,490 3,584,461 3,685,432 3,786,403 Rate moderation component 383,086 463,229 609,827 651,657 602,053 Shoreham post-settlement costs 968,999 922,580 777,103 586,045 378,386 Shoreham nuclear fuel 71,244 73,371 75,497 77,629 79,760 Unamortized cost of issuing securities 222,567 254,482 174,694 195,524 168,405 Postretirement benefits other than pensions 383,642 412,727 402,921 - - Regulatory tax asset 1,802,383 1,831,689 1,848,998 - - Other 230,663 250,804 247,858 190,008 131,143 - ------------------------------------------------------------------------------------------------------------- Total Regulatory Assets 7,445,103 7,692,372 7,721,359 5,386,295 5,146,150 - ------------------------------------------------------------------------------------------------------------- Nonutility property and other investments 16,030 24,043 23,029 20,730 9,788 Current assets 1,407,215 1,091,381 1,075,561 961,532 859,242 Deferred charges 21,023 172,768 286,005 323,418 681,347 - ------------------------------------------------------------------------------------------------------------- Total Assets $ 12,484,369 $ 12,478,910 $ 12,453,511 $ 9,853,123 $ 9,699,260 ============================================================================================================= Capitalization and Liabilities Long-term debt $ 4,722,675 $ 5,162,675 $ 4,887,733 $ 4,755,733 $ 5,001,016 Unamortized discount on debt (16,075) (17,278) (17,393) (14,731) (14,850) - ------------------------------------------------------------------------------------------------------------- 4,706,600 5,145,397 4,870,340 4,741,002 4,986,166 - ------------------------------------------------------------------------------------------------------------- Preferred stock - redemption required 639,550 644,350 649,150 557,900 524,912 Preferred stock - no redemption required 63,934 63,957 64,038 154,276 154,371 - ------------------------------------------------------------------------------------------------------------- Total Preferred Stock 703,484 708,307 713,188 712,176 679,283 - ------------------------------------------------------------------------------------------------------------- Common stock 598,277 592,083 561,662 558,002 556,825 Premium on capital stock 1,114,508 1,101,240 1,010,283 998,089 993,509 Capital stock expense (50,751) (52,175) (50,427) (39,304) (40,216) Retained earnings 790,919 752,480 711,432 667,988 620,373 - ------------------------------------------------------------------------------------------------------------- Total Common Shareowners' Equity 2,452,953 2,393,628 2,232,950 2,184,775 2,130,491 - ------------------------------------------------------------------------------------------------------------- Total Capitalization 7,863,037 8,247,332 7,816,478 7,637,953 7,795,940 - ------------------------------------------------------------------------------------------------------------- Regulatory Liabilities Regulatory liability component 277,757 357,117 436,476 515,835 595,194 1989 Settlement credits 136,655 145,868 155,081 164,294 173,507 Regulatory tax liability 116,060 111,218 114,748 - - Other 132,694 147,041 142,455 102,718 74,858 - ------------------------------------------------------------------------------------------------------------- Total Regulatory Liabilities 663,166 761,244 848,760 782,847 843,559 - ------------------------------------------------------------------------------------------------------------- Current liabilities 1,032,781 601,311 1,188,972 1,177,130 492,895 Deferred credits 2,476,249 2,365,401 2,166,145 237,893 559,559 Operating reserves 449,136 503,622 433,156 17,300 7,307 - ------------------------------------------------------------------------------------------------------------- Total Capitalization and Liabilities $ 12,484,369 $ 12,478,910 $ 12,453,511 $ 9,853,123 $ 9,699,260 =============================================================================================================
(In thousands of dollars) - ------------------------------------------------------------------------------------------------------------- Construction Expenditures* Table 11 - ------------------------------------------------------------------------------------------------------------- Electric $ 145,472 $ 136,041 $ 137,583 $ 141,752 $ 129,643 Gas 79,536 120,019 124,859 104,028 89,950 Common 21,477 23,610 42,251 27,124 17,958 - ------------------------------------------------------------------------------------------------------------- Total Construction Expenditures $ 246,485 $ 279,670 $ 304,693 $ 272,904 $ 237,551 =============================================================================================================
*Includes non-cash allowance for other funds used during construction and excludes Shoreham post-settlement costs. LILCO LOGO NOTICE OF ANNUAL MEETING AND PROXY STATEMENT 1996 [LOGO] Printed on Recycled Paper PROXY FOR COMMON SHARES PROXY SOLICITED ON BEHALF OF THE BOARD OF DIRECTORS OF LONG ISLAND LIGHTING COMPANY The Shareowner hereby appoints, and if a participant in the Company's P Automatic Dividend Reinvestment Plan (ADRP) hereby authorizes and directs The Bank of New York as Agent to appoint, GEORGE BUGLIARELLO, JOHN H. R TALMAGE and BASIL A. PATERSON and each or any of them with the power of substitution as Proxies to vote, as designated herein, all shares of O Common Stock which the Shareowner is entitled to vote at the Annual Meeting of Shareowners of the Company on May 9, 1996 and any adjournments X thereof. In their discretion, the Proxies are authorized to vote upon such business as may properly come before the meeting. Y THE SHARES REPRESENTED BY THIS PROXY, WHEN SIGNED AND RETURNED, WILL BE VOTED IN THE MANNER DIRECTED HEREIN BY THE UNDERSIGNED SHAREOWNER. IF NO DIRECTION IS GIVEN, THIS PROXY WILL BE VOTED FOR THE NOMINEES AND FOR ITEM TWO, THREE AND FOUR ON THE OTHER SIDE. THIS PROXY IS CONTINUED ON THE OTHER SIDE. PLEASE SIGN ON THE OTHER SIDE AND RETURN PROMPTLY. The shares represented by this proxy when signed and returned will be voted as directed by the Shareowner. If no direction is given, such shares will be voted FOR the nominees names below and FOR Items Two, Three and Four. The Board of Directors recommends a vote FOR all nominees named below and FOR Items Two, Three and Four.
ITEM ONE - Election of the following nominees as Directors: W.J. Catacosinos, J.H. Talmage, B.A. Paterson, G. Bugliarello, G.J. Sideris, A.J. Barnes, R.L. Schmalensee, R.L. Caporali, P.O. Crisp, K.D. Ortega and V.L. Fuller. FOR ALL WITHHELD Withheld for the following only: nominees named above for all nominees (Write the name of the nominee(s) on the line below) / / / / -------------------------------------------------- ITEM TWO - Appointment of Independent Auditors FOR AGAINST ABSTAIN / / / / / / ITEM THREE - Approval of Directors' Stock Unit Retainer Plan FOR AGAINST ABSTAIN / / / / / / ITEM FOUR - Approval of Officers' Long-Term Incentive Plan FOR AGAINST ABSTAIN / / / / / /
/ / Discontinue mailing the Annual Report to this account. PLEASE SIGN AND DATE BELOW Date ____________________________________________ , 1996 Signature ____________________________________________L.S. Signature ____________________________________________L.S. Signature of Common Shareowner(s) PLEASE SIGN AS YOUR NAME APPEARS ABOVE AND RETURN IN THE ENCLOSED POSTAGE PAID ENVELOPE. IF SIGNING AS EXECUTOR, ADMINISTRATOR, TRUSTEE, GUARDIAN, ETC., YOU SHOULD SO INDICATE. IF THE SIGNER IS A CORPORATION, PLEASE SIGN IN FULL CORPORATE NAME, BY PRESIDENT OR OTHER AUTHORIZED OFFICER. IF A PARTNERSHIP, PLEASE SIGN IN PARTNERSHIP NAME BY AUTHORIZED PERSON. [LILCO LOGO] LONG ISLAND LIGHTING COMPANY EXECUTIVE OFFICES: 175 EAST OLD COUNTRY ROAD HICKSVILLE, NEW YORK 11801 Dear Shareowner, You are cordially invited to attend our annual meeting of shareowners to be held at 3:00 p.m. on Thursday, May 9, 1996 in TILLES CENTER FOR THE PERFORMING ARTS AT THE LONG ISLAND UNIVERSITY, C.W. POST CAMPUS, NORTHERN BOULEVARD, GREENVALE, NEW YORK. The middle third of this form is your admission card. Please bring the admission card with you if you plan to attend the annual meeting. The bottom third is your proxy card which we ask you to mark, sign and return in the enclosed envelope. Your participation is important to us. Please complete and return the enclosed proxy card at your earliest convenience. PLEASE NOTE: If you are a registered shareowner and duplicate copies of the Company's Annual Report are sent to your household, you may discontinue the mailing of such report to this account by checking the appropriate box on the proxy card. Sincerely, /s/ KATHLEEN A. MARION KATHLEEN A. MARION VICE PRESIDENT & CORPORATE SECRETARY ADMISSION CARD LILCO Annual Meeting of Shareowners - May 9, 1996 - 3:00 p.m. Name(s):___________________________________________________________________ Address:___________________________________________________________________ ___________________________________________________________________ Shares Owned - Common No. of Shares:________________ Dear Shareowner: Please bring this card to the Annual Meeting. It will expedite your admittance when presented upon your arrival. Very truly yours, /s/ Kathleen A. Marion KATHLEEN A. MARION VICE PRESIDENT & CORPORATE SECRETARY Tilles Center-L.I. University-C.W. Post Campus-Northern Boulevard-Greenvale, New York -----END PRIVACY-ENHANCED MESSAGE-----