-----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, OlMdxk2KwjLXB6CXss1E4G14Inw3l5VSOWs3rINxOxHjTA4vpXwZbjblPGfftR3v IyeLl0dXFYTjUmbjrtc20Q== 0000950130-97-001177.txt : 19970328 0000950130-97-001177.hdr.sgml : 19970328 ACCESSION NUMBER: 0000950130-97-001177 CONFORMED SUBMISSION TYPE: PRE 14A PUBLIC DOCUMENT COUNT: 1 CONFORMED PERIOD OF REPORT: 19970515 FILED AS OF DATE: 19970321 DATE AS OF CHANGE: 19970327 SROS: NYSE FILER: COMPANY DATA: COMPANY CONFORMED NAME: CENTRAL MAINE POWER CO CENTRAL INDEX KEY: 0000018675 STANDARD INDUSTRIAL CLASSIFICATION: 4911 IRS NUMBER: 010042740 STATE OF INCORPORATION: ME FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: PRE 14A SEC ACT: 1934 Act SEC FILE NUMBER: 001-05139 FILM NUMBER: 97562164 BUSINESS ADDRESS: STREET 1: 83 EDISON DR CITY: AUGUSTA STATE: ME ZIP: 04336 BUSINESS PHONE: 2076233521 PRE 14A 1 PRELIMINARY PROXY STATEMENT SCHEDULE 14A INFORMATION Proxy Statement Pursuant to Section 14(a) of the Securities Exchange Act of 1934 (Amendment No. ) Filed by the Registrant [X] Filed by a Party other than the Registrant [_] Check the appropriate box: [X] Preliminary Proxy Statement [_] Confidential, for Use of the Commission Only (as permitted by Rule 14a-6(e)(2)) [_] Definitive Proxy Statement [_] Definitive Additional Materials [_] Soliciting Material Pursuant to Section 240.14a-11(c) or Section 240.14a-12 Central Maine Power Company - - -------------------------------------------------------------------------------- (Name of Registrant as Specified In Its Charter) - - -------------------------------------------------------------------------------- (Name of Person(s) Filing Proxy Statement, if other than the Registrant) Payment of Filing Fee (Check the appropriate box): [X] No fee required. [_] 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 (set forth the amount on which the filing fee is calculated and state how it was determined): ------------------------------------------------------------------------- (4) Proposed maximum aggregate value of transaction: ------------------------------------------------------------------------- (5) Total fee paid: ------------------------------------------------------------------------- [_] Fee paid previously with preliminary materials. [_] 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 registration 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: ------------------------------------------------------------------------- Notes: PRELIMINARY COPY [LOGO] CENTRAL MAINE POWER COMPANY --------------------------- GENERAL OFFICE: 83 EDISON DRIVE, AUGUSTA, MAINE 04336 April , 1997 TO THE HOLDERS OF COMMON STOCK, 6% PREFERRED STOCK AND DIVIDEND SERIES PREFERRED STOCK OF CENTRAL MAINE POWER COMPANY: The Annual Meeting of the Shareholders, formal notice of which, together with a Proxy Statement, appears on the following pages, will be held on May 15, 1997. The place for the meeting will be the Augusta Civic Center, in Augusta, Maine. At the meeting, holders of Common Stock and 6% Preferred Stock will be asked: 1. To elect Class I directors of the Company for a three-year term. 2. To approve the appointment by the Company's Board of Directors of Coopers & Lybrand L.L.P., Boston, Massachusetts, as auditors for the Company for 1997. 3. To approve an amendment to the Company's Long-Term Incentive Plan to include a stock options program. In addition, holders of 6% Preferred Stock and Dividend Series Preferred Stock will be asked to consent to an increase in the existing unsecured Medium- Term Note program from $150 million to $500 million. It is important for you and the Company that each shareholder participate in this Annual Meeting. WHETHER OR NOT YOU PLAN TO ATTEND, PLEASE SIGN, DATE AND RETURN THE ENCLOSED PROXY IN THE ENCLOSED SELF-ADDRESSED ENVELOPE. No postage is necessary. Of course, if you attend the meeting, you will be able to vote your shares in person. A copy of portions of the Company's Annual Report for 1996, including certified financial statements and Management's Discussion and Analysis of Financial Condition and Results of Operations, is attached to this Proxy Statement. Cordially yours, David T. Flanagan /s/ David T. Flanagan President and Chief Executive Officer URGENT. PLEASE SIGN, DATE AND RETURN ENCLOSED PROXY IMMEDIATELY. [LOGO] CENTRAL MAINE POWER COMPANY --------------------------- NOTICE OF ANNUAL MEETING OF SHAREHOLDERS TO BE HELD ON MAY 15, 1997 AT 10:00 A.M. You are hereby notified of and invited to attend the Annual Meeting of the Shareholders of Central Maine Power Company (the "Company"), to be held at the Augusta Civic Center, Augusta, Maine, on May 15, 1997, at 10:00 A.M., Eastern Daylight Time, to hear reports on Company affairs and to consider and act upon the following matters: 1. To elect four directors to Class I of the Company's Board of Directors for a three-year term (to be voted on by holders of Common Stock and 6% Preferred Stock only); 2. To approve the appointment by the Company's Board of Directors of Coopers & Lybrand L.L.P., Boston, Massachusetts, as the Company's auditors for 1997 (to be voted on by holders of Common Stock and 6% Preferred Stock only); 3. To approve an amendment to the Company's Long-Term Incentive Plan to include a stock options program (to be voted on by holders of Common Stock and 6% Preferred Stock only); 4. To consent to an increase in the existing unsecured Medium-Term Note program from $150 million to $500 million (to be voted on by holders of 6% Preferred Stock and Dividend Series Preferred Stock only); and 5. To consider and act upon any other matters that may properly come before the meeting. The close of business on March 17, 1997 has been fixed as the record date for determination of shareholders entitled to notice of, and to vote at, the Annual Meeting or any adjournment thereof. By Order of the Board of Directors /s/ Anne M. Pare Anne M. Pare Secretary and Clerk Augusta, Maine April , 1997 April , 1997 [LOGO] CENTRAL MAINE POWER COMPANY 83 EDISON DRIVE AUGUSTA, MAINE 04336 ---------------- PROXY STATEMENT This Proxy Statement is furnished in connection with the solicitation of proxies by the Board of Directors of Central Maine Power Company for the Annual Meeting of the Shareholders of Central Maine Power Company (the "Company"), to be held on May 15, 1997, at 10:00 A.M. at the Augusta Civic Center, Augusta, Maine. It is being mailed to the shareholders on or about April , 1997. Portions of the Annual Report of the Company for the year ended December 31, 1996, including certified financial statements and Management's Discussion and Analysis of Financial Condition and Results of Operations, is attached. VOTING RIGHTS Only holders of record of shares of Common Stock and 6% Preferred Stock at the close of business on March 17, 1997 are entitled to vote on Proposals 1, 2 and 3 at the meeting. Only holders of record of shares of 6% Preferred Stock and Dividend Series Preferred Stock at the close of business on March 17, 1997 are entitled to vote on Proposal 4. The total number of shares entitled to vote at the meeting will be 32,442,752 shares of Common Stock, 5,713 shares of 6% Preferred Stock and 1,255,275 shares of Dividend Series Preferred Stock. Holders of Common Stock are entitled to one-tenth vote per share and holders of 6% Preferred Stock and Dividend Series Preferred Stock are entitled to one vote per share regarding all matters that are expected to be acted upon at the meeting on which such holders are entitled to vote. Accordingly, the holders of Common Stock are entitled to 3,244,275 votes, the holders of 6% Preferred Stock are entitled to 5,713 votes and the holders of Dividend Series Preferred Stock are entitled to 1,255,275 votes on each proposal on which they are entitled to vote at the meeting. A majority of the total votes entitled to be cast at the meeting by the holders of Common Stock and 6% Preferred Stock on Proposals 1, 2 and 3 will constitute a quorum with respect to action to be taken on Proposals 1, 2 and 3. A majority of the total number of shares of 6% Preferred Stock and Dividend Series Preferred Stock issued and outstanding will constitute a quorum with respect to action to be taken on Proposal 4. Abstentions, votes withheld from nominees for director, and broker non-votes will be counted for the purpose of determining whether a quorum is present. With respect to the election of directors, nominees who receive the greatest number of votes cast by the holders of the Company's Common Stock and 6% Preferred Stock, voting as a single class, will be elected, even though any such nominee may not receive a majority of the votes cast. Votes withheld from nominees for director will be counted in determining the total number of votes cast on the matter and will have the same effect as a vote against the matter. An affirmative vote of a majority of the votes cast at the meeting by the holders of the Company's Common Stock and 6% Preferred Stock, voting as a single class, is required for approval of Proposal 2. An affirmative vote of a majority of all outstanding shares of Common Stock and 6% Preferred Stock, voting as a single class, is required for approval of Proposal 3. An affirmative vote of a majority of the shares of 6% Preferred Stock and Dividend Series Preferred Stock present or represented at the meeting, voting as a single class, is required for approval of Proposal 4. Abstentions with respect to Proposal 2 or 4 will be counted in determining the total number of votes cast on the matter to which the votes pertain, but will have no effect on that matter. Broker non- votes will not be included in determining the total number of votes cast on Proposal 2 or 4 and will have no effect on either of those matters. Abstentions and broker non-votes with respect to Proposal 3 will count as a vote against that matter. Under the By-Laws of the Company, the election of directors at the Annual Meeting shall at the option of any shareholder be by cumulative voting. Accordingly, each shareholder having the right to vote for directors shall be entitled to as many votes as pertain to the shares of stock owned by that shareholder multiplied by the number of directors to be elected, and may cast all such votes for a single director or may distribute them among the number to be voted for, or any two or three of them, as that shareholder may see fit. If any shareholder entitled to vote for directors at the meeting either gives written notice to the President of the Company before the time fixed for the meeting of his or her intention to vote cumulatively or states his or her intention to vote cumulatively at the meeting before the voting for directors commences, all shareholders entitled to vote for directors at such meeting shall be entitled to cumulate their votes. Any shareholder who wishes to vote cumulatively but who will not be present at the meeting should give written notice to the President of the Company of such intention before the meeting and should clearly indicate in writing on the accompanying proxy the director or directors for whom he or she wishes to vote and the number of votes he or she wishes to distribute to each such director. If no written indication is made on the proxy, the votes will be evenly distributed among all the nominees. If any shareholder has indicated his or her intention to vote cumulatively (either by written notice or by a statement made at the meeting), each shareholder present at the meeting who has not given his or her proxy or has revoked his or her proxy in the manner described in the following paragraph may vote cumulatively at the meeting by means of a written ballot distributed at the meeting. Shareholders may vote at the meeting either in person or by duly authorized proxy. The giving of a proxy by a shareholder will not affect the shareholder's right to vote his or her shares if he or she attends the meeting and wishes to vote in person. A proxy may be revoked or withdrawn by the person giving it, at any time prior to the voting thereof, at the registration desk for the meeting or by advising the Secretary of the Company. In addition, the proper execution of a new proxy will operate to revoke a prior proxy. All shares represented by effective proxies on the enclosed form, received by the Company, will be voted at the meeting or any adjourned session thereof, all in accordance with the terms of such proxies. PROPOSAL 1 ELECTION OF DIRECTORS It is intended that the persons named in the accompanying proxy will vote to elect the first four persons listed below to serve as Class I directors for a three-year term expiring at the Annual Meeting of the Shareholders in the year 2000. However, if voting is cumulative, such persons may cumulate the total number of votes to which the shareholder executing the proxy is entitled in favor of one or more of the nominees in the manner that such persons shall in their discretion determine, unless other instructions are given in the proxy by the shareholder executing it. Nominees named in the accompanying proxy who receive the greatest number of votes cast by the holders of the Company's Common Stock and 6% Preferred Stock, voting as a single class, will be elected, even though any such nominee may not receive a majority of the votes cast. The remaining seven persons listed below as Class II and Class III directors will continue in office for terms which 2 expire at the 1998 and 1999 Annual Meeting of the Shareholders, respectively, or, in each case, until their respective successors are duly elected and qualified. Should any person named below as a Class I director be unable or unwilling to serve as a director, persons acting under the proxy intend to vote for such other person as management may recommend, or the Board of Directors may exercise its exclusive power to fix the number of directors at fewer than eleven. On November 20, 1995, the Board elected David M. Jagger, who has been a member of the Board since 1988, to succeed Carlton D. Reed, Jr. as Chairman of the Board effective January 1, 1996. Mr. Reed retired from the Board effective December 31, 1995. The Board also elected Charles H. Abbott, a member of the Board since 1988, to the position of Vice Chairman of the Board, which had previously been vacant, effective January 1, 1996. At its January 17, 1996 meeting, the Board elected Lyndel J. Wishcamper as a Class I director effective February 1, 1996 to fill the vacancy created by Mr. Reed's retirement. At its meeting on March 20, 1996, the Board elected William J. Ryan as a director in Class I effective April 17, 1996. On March 26, 1996, the Board fixed the number of directors at twelve effective April 17, 1996 and elected Duane D. Fitzgerald as a member of the Board in Class II, also effective April 17, to fill the vacancy created by the planned April 16, 1996 retirement of Robert H. Reny, a Class II director since January 1, 1988. At its meeting on February 20, 1997, the Board fixed the number of directors at eleven effective March 21, 1997. On March 20, 1997, Charles E. Monty, a Class II director since 1977, retired from service on the Board. Set forth below is information about each nominee and continuing director. Each person listed has been serving as a director of the Company. In addition, David T. Flanagan is President and Chief Executive Officer of the Company, David M. Jagger serves as Chairman of the Board of Directors, and Charles H. Abbott serves as Vice Chairman of the Board.
PRINCIPAL OCCUPATIONS AND BUSINESS EXPERIENCE DURING PAST FIVE YEARS AND CURRENT FIRST NAME AND DIRECTORSHIPS OF BECAME A AGE PUBLIC COMPANIES DIRECTOR -------- ----------------------- -------- CLASS I: Charles H. Abbott (61).................. Chairman, Skelton, Tain- 1988 tor & Abbott, P.A. (At- torneys); Vice Chairman of the Board of the Com- pany William J. Ryan (53).................... Chairman, President and 1996 Chief Executive Officer, Peoples Heritage Finan- cial Group, Inc. and Peoples Heritage Bank; Director, Blue Cross and Blue Shield of Maine, John J. Nissen Baking Co., and Student Loan Association of New En- gland Lyndel J. Wishcamper (54)............... President, Wishcamper 1996 Properties, Inc. (Real estate); Chairman of the Board, Atlantic Bank and Trust, N.A., and Atlantic Bancorp Kathryn M. Weare (48)................... Owner and Manager, The 1992 Cliff House (Resort and conference center)
3
PRINCIPAL OCCUPATIONS AND BUSINESS EXPERIENCE DURING PAST FIVE YEARS AND CURRENT FIRST NAME AND DIRECTORSHIPS OF BECAME A AGE PUBLIC COMPANIES DIRECTOR -------- ----------------------- -------- CLASS II: E. James Dufour (62).................... Senior Vice President, 1971 Kyes Agency, Inc. (General insurance and real estate); Director, Somerset Woods Trustees (Land trust) Duane D. Fitzgerald (57)................ Chairman of the Board, 1996 Bath Iron Works Corporation (Shipbuilding) (from March 1, 1996); Corporate Vice President, General Dynamics Corporation (September 1995 to March 1, 1996); President and Chief Executive Officer (September 1991 to March 1, 1996) and previously (December 1988 to September 1991), President and Chief Operating Officer, Bath Iron Works Corporation; Director, UAL Corporation, John J. Nissen Baking Co., Blue Cross Blue Shield of Maine David M. Jagger (55).................... President and Treasurer, 1988 Jagger Brothers, Inc. (Textiles); Chairman of the Board of the Company CLASS III: Charleen M. Chase (48).................. Executive Director, 1985 Community Concepts, Inc. (Community action agency) David T. Flanagan (49).................. President and Chief 1994 Executive Officer of the Company, effective January 1, 1994; Executive Vice President (July 1991 through December 1993); Chairman of the Board of Directors, Maine Yankee Atomic Power Company (a) Robert H. Gardiner (52)................. President, Maine Public 1992 Broadcasting Corporation (Public television) Peter J. Moynihan (53).................. Senior Vice President and 1995 Chief Investment Officer, UNUM Corporation (Insurance)
- - -------- (a) The Company owns 38 percent of the outstanding voting stock of Maine Yankee Atomic Power Company. 4 BOARD COMMITTEES, MEETINGS AND COMPENSATION CERTAIN COMMITTEES OF THE BOARD The Board's Audit Committee, which has as its members Kathryn M. Weare (Chair), Duane D. Fitzgerald and Lyndel J. Wishcamper, held six meetings in 1996. The Audit Committee recommends to the Board the independent accountants to be selected by the Company and reviews the plan and scope of the audit as well as the results and costs of the audit. The Committee also reviews with the independent accountants and management the Company's internal accounting procedures and controls, and the adequacy of the accounting services provided by the Company's personnel. The Governance Committee, now composed of David M. Jagger (Chair), Charles H. Abbott, Robert H. Gardiner and William J. Ryan, has among its concerns the selection, performance and evaluation of directors. The Committee will consider for nomination to the Board individuals whose names have been submitted by shareholders in writing. Supporting information should accompany any submission. In addition, the Board has established a committee composed of shareholders and non-employee directors to provide an additional means of receiving names of persons for consideration by the Governance Committee for nomination to the Board. The Governance Committee also oversees the Company's long-range corporate planning and succession planning, and evaluates the performance of the President and Chief Executive Officer. The Governance Committee held two meetings in 1996. The Compensation and Benefits Committee, whose members are Charles H. Abbott (Chair), E. James Dufour, Duane D. Fitzgerald and Peter J. Moynihan, held twelve meetings in 1996. This committee reviews and makes recommendations to the Board concerning compensation and benefit programs for executive officers and compensation for directors of the Company. The Compensation and Benefits Committee also administers the Company's 1987 Executive Incentive Plan and its Long-Term Incentive Plan. MEETINGS OF THE BOARD The Board held 13 meetings (including regularly scheduled and special meetings) in 1996. Each director listed above attended more than 75 percent of the aggregate of the total number of Board meetings and the total number of meetings of all committees on which that director served that were held during periods he or she served as a director. COMPENSATION OF DIRECTORS In accordance with the established guidelines for the Board of Directors of the Company, the Chairman of the Board receives an annual retainer of $25,200, the Vice Chairman of the Board receives an annual retainer of $10,300, and each director (other than the Chairman or Vice Chairman) who is the Chair of a committee of the Board and not an executive officer of the Company receives an annual retainer of $8,400. Each other director who is not an executive officer of the Company (an "outside director") receives an annual retainer of $6,800. All retainers are payable quarterly. In addition to ordinary travel expenses, all outside directors receive $600 for each meeting of the Board attended, and all outside directors serving on a committee of the Board receive $300 for each committee meeting attended on a day on which they have also attended a meeting of the full Board or another committee and $600 for any other committee meeting attended. A fee of $150 is paid to outside directors for participating in a meeting of the Board or one of its committees by telephone if, in the opinion of the person presiding at the meeting, substantial action is taken or matters of importance are resolved. In March 1988, the Company established a voluntary deferred compensation plan for outside directors. Under the plan, a director who receives a retainer as described above may elect to have all or a specified portion, in increments of 25 percent, of his or her retainer (but not meeting fees) for the calendar year 5 following the election and subsequent calendar years credited quarterly to a deferred compensation account, maintained at the election of the director either as a cash account or an account in units based on the value of the Common Stock of the Company ("Compensation Units"). The number of Compensation Units credited to a director's account is equal to the number of shares of the Company's Common Stock that could have been purchased as of the middle of a calendar quarter with the amount of the retainer deferred for that quarter. The Company matches Compensation Units in a director's account with one-half the number of Compensation Units in the account. The number of Compensation Units in the accounts of directors participating in the deferred retainer plan as of February 28, 1997 is shown in the table that appears under the caption "SECURITY OWNERSHIP." Whenever dividends are paid on the Company's Common Stock, each account maintained in Compensation Units is credited with additional Compensation Units equal to the number of shares that could have been purchased if a cash dividend had been paid on the Compensation Units in the account. Deferred retainers, whether held in a cash account or an account in Compensation Units, are paid solely in cash following retirement from the Board. The value of the Compensation Units in a director's account at the time a payment is made will be equal to the market value of the same number of shares of the Company's Common Stock on the payment date. In September 1991, the Board of Directors adopted a retirement plan for outside directors. Under the plan each outside director who has completed five or more years of service is eligible to receive, at the later of the attainment of age 62 or when he or she ceases to serve on the Board, an annual benefit equal to the amount of the director's basic annual retainer for the year the director ceases to serve on the Board, payable monthly for a period equal to the number of months the individual has served as an outside director. No death benefit is provided under the plan. For 1996, the basic annual retainer for each outside director, including the Chairman of the Board and each committee Chair, was $6,800. This amount is included in the annual retainers discussed above for the Chairman, Vice Chairman and the committee Chairs. SECURITY OWNERSHIP The following table lists the number of shares of the Common Stock of the Company beneficially owned as of March 17, 1997 by each director of the Company and each of the executive officers of the Company named in the Summary Compensation Table contained in this Proxy Statement. The total number of such shares beneficially owned as of March 17, 1997 by all directors and executive officers of the Company as a group is also listed. Shares listed as beneficially owned include shares as to which the directors and executive officers have or share the power to vote or the power to dispose. For outside directors, listings include, where appropriate, shares of Common Stock credited under the Company's Dividend Reinvestment and Common Stock Purchase Plan ("DRP"). For executive officers, shares listed include, where appropriate, DRP shares, restricted shares awarded under the Company's 1987 Executive Incentive Plan and its Long-Term Incentive Plan, and shares credited under the Employee Savings and Investment Plan for Non-Union Employees (401(k) Plan) as of December 31, 1996. The table also lists the number of Compensation Units as of February 28, 1997 in the accounts of the directors who have participated in the deferred retainer plan described above. Only outside directors are eligible to participate in the deferred retainer plan. The value of the Compensation Units at the time they are paid out will be equal to the market value of the same number of shares of the Company's Common Stock on the payment date, but the deferred amounts will be paid only in cash. Compensation Units will not be distributed in the form of Common Stock. 6
COMPENSATION UNITS SHARES BENEFICIALLY REPRESENTING DIRECTORS AND NAMED OWNED DEFERRED RETAINER EXECUTIVE OFFICERS (AS OF MARCH 17, 1997) (AS OF FEBRUARY 28 , 1997) ------------------- ---------------------- -------------------------- Charles H. Abbott......... 3,215 8,910 Charleen M. Chase......... 1,232 2,854 E. James Dufour........... 4,505 9,279 Duane D. Fitzgerald....... 500 911 David T. Flanagan......... 15,102 -- Robert H. Gardiner........ 1,000 4,335 David M. Jagger........... 1,000 9,970 Peter J. Moynihan......... 1,196 1,749 William J. Ryan........... 500 -- Kathryn M. Weare.......... 1,111 3,902 Lyndel J. Wishcamper...... 1,318 1,034 Arthur W. Adelberg........ 6,268 -- David E. Marsh............ 7,514 -- Richard A. Crabtree....... 10,153 -- Gerald C. Poulin.......... 8,035 -- All directors and executive officers as a group (including persons listed above)............ 65,097 42,944
The number of shares of Common Stock of the Company beneficially owned as of March 17, 1997 by each of the directors and named executive officers, and the aggregate number of such shares beneficially owned as of that date by all of the directors and executive officers of the Company as a group, constituted less than one percent of the total shares of that class then outstanding. As of March 17, 1997, Mr. Abbott's spouse held sole voting and investment power over 800 shares of the total number of shares listed for Mr. Abbott, and all shares listed for Ms. Chase were held jointly. Of the shares listed for Mr. Crabtree and Mr. Poulin, 2,506 and 201 shares, respectively, were held jointly as of that date. The total number of shares held jointly for all directors and executive officers as a group as of March 17, 1997 was 3,939 shares. No director or officer owned as of March 17, 1997 any shares of 6% Preferred Stock or Dividend Series Preferred Stock. As of March 17, 1997, there was no person who was known to be the beneficial owner of more than five percent of the Common Stock and the 6% Preferred Stock of the Company in the aggregate. Christine M. Nyhan, trustee, 1825 Spindrift Lane, La Jolla, California 92037, owned of record 1,675 shares of the Company's 6% Preferred Stock. The outstanding shares of Common Stock and 6% Preferred Stock will vote together as a single class at the meeting on Proposals 1, 2 and 3. Shares held by Christine M. Nyhan, trustee, represent approximately .05 percent of the combined voting power of Common Stock and 6% Preferred Stock and approximately 29.31 percent of the voting power of the 6% Preferred Stock. With respect to Proposal 4, the outstanding shares of 6% Preferred Stock and Dividend Series Preferred Stock will vote together as a single class. Shares held by Christine M. Nyhan, trustee, represent approximately .13% of the combined voting power of such securities. As of February 27, 1997, shares of Dividend Series Preferred Stock held of record by the following entities represented more than five percent of that class and of the combined voting power of the 6% Preferred Stock and the Dividend Series Preferred Stock.
PERCENT NUMBER OF PERCENT OF OF COMBINED NAME AND ADDRESS SHARES CLASS VOTING POWER - - ---------------- --------- ---------- ------------ Cede & Co..................................... 767,762 61.16% 60.88% P.O. Box 20 Bowling Green Station New York, NY 10274 CS First Boston Corp.......................... 84,000 6.69% 6.66% Five World Trade Center New York, NY 10048
7 EXECUTIVE COMPENSATION The following Summary Compensation Table presents information on compensation to David T. Flanagan, President and Chief Executive Officer, and to other executive officers of the Company for 1994, 1995 and 1996. SUMMARY COMPENSATION TABLE
LONG-TERM ANNUAL COMPENSATION COMPENSATION ----------------------- ------------ NAME RESTRICTED AND STOCK ALL OTHER PRINCIPAL AWARD(S) COMPENSATION POSITION YEAR SALARY ($) BONUS ($)(1) ($)(2) ($)(3) --------- ---- ---------- ------------ ------------ ------------ David T. Flanagan....... 1996 265,000.08 62,606.27 0 5,017.97 President and Chief Ex- ecutive Officer 1995 240,000.00 76,000.00 0 4,989.60 1994 231,666.64 0 0 4,944.80 Arthur W. Adelberg...... 1996 166,334.32 28,262.51 0 4,768.44 Vice President, 1995 157,816.72 40,781.67 0 4,741.36 Law and Power Supply 1994 148,800.00 0 0 4,675.32 David E. Marsh.......... 1996 166,123.59 25,768.75 0 4,833.91 Vice President, 1995 157,816.72 40,781.67 0 4,800.91 Corporate Services, Treasurer, and 1994 148,800.00 0 0 4,728.86 Chief Financial Officer Richard A. Crabtree..... 1996 163,080.44 27,738.33 0 4,870.39 Vice President, 1995 156,466.64 40,646.66 0 4,839.43 Retail Operations 1994 153,400.08 12,200.00 0 4,812.94 Gerald C. Poulin........ 1996 137,294.23 23,362.25 0 4,511.31 Vice President, 1995 127,366.72 27,736.27 0 3,821.00 Generation and 1994 121,175.00 0 0 3,635.25 Technical Support
- - -------- (1) For 1996, amounts are awards for 1996 performance under 1987 Executive Incentive Plan. (2) At December 31, 1996, the number of shares and value of the aggregate restricted stock holdings of each of the named executive officers were as follows: Mr. Flanagan, 17,732 shares and $206,134; Mr. Adelberg, 6,811 shares and $79,177; Mr. Marsh, 6,811 shares and $79,177; Mr. Crabtree, 6,615 shares and $76,899; and Mr. Poulin, 5,514 shares and $64,100. The aggregate restricted stock holdings listed for each of the named executive officers include contingent grants of performance restricted shares of the Company's Common Stock under the Company's Long-Term Incentive Plan ("LTIP") for each of the 3- year performance periods beginning January 1, 1994 and January 1, 1995, respectively. Vesting of the LTIP shares is subject to attaining a threshold level of performance with respect to a specified performance objective. Of the aggregate number of shares of restricted stock, the shares contingently granted to the named executive officers under the LTIP and their value as of December 31, 1996 were as follows: Mr. Flanagan, 17,012 shares and $197,764; Mr. Adelberg, 6,296 shares and $73,191; Mr. Marsh, 6,296 shares and $73,191; Mr. Crabtree, 5,994 shares and $69,680; and Mr. Poulin, 5,202 shares and $60,473. For the 3-year performance period beginning January 1, 1994, the specified level of performance was not attained. As a result, the performance restricted shares contingently granted for that performance period plus additional performance restricted shares resulting from the reinvestment of dividends through January 1997 were forfeited on February 20, 1997. 8 The number of LTIP shares forfeited and their value as of the forfeiture date were as follows:
NUMBER OF VALUE AS OF FORFEITURE NAME SHARES FORFEITED DATE (FEBRUARY 20, 1997) ---- ---------------- ------------------------ David T. Flanagan............... 8,424 $92,664 Arthur W. Adelberg.............. 2,967 32,637 David E. Marsh.................. 2,967 32,637 Richard A. Crabtree............. 2,967 32,637 Gerald C. Poulin................ 2,448 26,928
Dividends on the performance restricted shares under the LTIP are earned at the same rate as dividends on the unrestricted Common Stock of the Company and are reinvested in additional performance restricted shares during the performance period until any payout or forfeiture. The balance of the aggregate restricted stock holdings represents awards under the Company's 1987 Executive Incentive Plan ("EIP"). Dividends on shares of restricted stock granted under the EIP are earned at the same rate as dividends on the unrestricted Common Stock of the Company and are paid either during the 3-year restriction period applicable to these shares or at the end of the restriction period. (3) For 1996, amounts of All Other Compensation include (i) matching contributions by the Company to the Employee Savings and Investment Plan for Non-Union Employees (401(k) Plan) in the amount of $4,500 for Mr. Flanagan, $4,500 for Mr. Adelberg, $4,500 for Mr. Marsh, $4,500 for Mr. Crabtree, and $4,100 for Mr. Poulin; and (ii) the value of term life insurance premiums paid under universal life insurance policies in the amount of $517.97 for Mr. Flanagan, $268.44 for Mr. Adelberg, $333.91 for Mr. Marsh, $370.39 for Mr. Crabtree and $411.31 for Mr. Poulin. The Company has purchased universal life insurance policies for Mr. Flanagan, Mr. Adelberg, Mr. Marsh, Mr. Crabtree and Mr. Poulin, who have no immediate right to receive the cash surrender value of the policies and may never have any right to receive the cash surrender value. The respective interests of these five executive officers in the cash surrender value of the policies will vest only if certain conditions are first satisfied. If an executive officer's interest in the cash surrender value vests, the retirement benefits payable to the executive officer by the Company under its Supplemental Executive Retirement Plan (the "SERP"), a defined benefit retirement income plan, will be reduced dollar for dollar by the amount of the cash surrender value of the policy at the time it vests. The premium paid on each of these policies is designed to produce a cash surrender value which is equal to, but which may be less than, the benefits payable under the SERP. 9 PENSION PLAN TABLES AND EMPLOYMENT ARRANGEMENTS BASIC PENSION PLAN The Company makes payments to the Retirement Income Plan for Non-Union Employees (the "Basic Pension Plan") for full-time non-union employees of the Company, including the executive officers. Estimated annual retirement benefits payable by the Company under the Basic Pension Plan, assuming retirement on December 31, 1996 at age 65, for average salary levels and credited years of service specified in the following Basic Pension Plan Table are as set forth in the Table.
YEARS OF SERVICE ---------------------------------------- AVERAGE ANNUAL SALARY FOR 5 HIGHEST CONSECUTIVE YEARS PRECEDING RETIREMENT 15 20 25 30 35 --------------------------- ------- ------- ------- ------- -------- $150,000.............................. $34,871 $46,998 $59,848 $70,547 $ 73,307 175,000.............................. 41,246 52,757 66,661 80,574 86,072 200,000.............................. 41,419 58,676 75,934 93,192 99,108 225,000.............................. 41,419 58,676 75,934 93,192 105,256 250,000.............................. 41,419 58,676 75,934 93,192 105,256 275,000.............................. 41,419 58,676 75,934 93,192 105,256 300,000.............................. 41,419 58,676 75,934 93,192 105,256 325,000.............................. 41,419 58,676 75,934 93,192 105,256 350,000.............................. 41,419 58,676 75,934 93,192 105,256 375,000.............................. 41,419 58,676 75,934 93,192 105,256 400,000.............................. 41,419 58,676 75,934 93,192 105,256
For Mr. Poulin, an executive officer named in the Summary Compensation Table, compensation covered by the Basic Pension Plan consists of base salary, including base salary shown in the Salary column of that Table. Because the amount of compensation that could be taken into account in determining retirement benefits under the Basic Pension Plan was limited by federal tax law to $150,000 in 1996, the 1996 covered compensation under the Basic Pension Plan for Messrs. Flanagan, Adelberg, Marsh and Crabtree was limited to that amount of their respective base salaries. Messrs. Flanagan, Adelberg, Marsh, Crabtree and Poulin have been credited with 11, 10, 22, 24 and 25 years of service, respectively. Benefits listed in the Basic Pension Plan Table are payable as a single life annuity and reflect an offset for estimated Social Security benefits payable upon attainment of age 65. SUPPLEMENTAL EXECUTIVE RETIREMENT PLAN The Company maintains a Supplemental Executive Retirement Plan (the "SERP") that provides supplemental retirement income to selected executive officers of the Company. Estimated annual retirement benefits payable by the Company under the SERP, assuming retirement on December 31, 1996 at age 65, for average compensation levels and credited years of service specified in the following SERP Table are as set forth in the Table.
YEARS OF SERVICE --------------------------------------- AVERAGE ANNUAL COMPENSATION FOR 3 HIGHEST YEARS 15 20 25 30 35 ------------------- ------- ------- ------- ------- ------- $150,000................................ $23,629 $31,002 $37,652 $26,953 $24,193 175,000................................ 27,004 38,243 47,089 33,176 27,678 200,000................................ 36,581 45,324 54,066 36,808 30,892 225,000................................ 46,331 58,324 70,316 53,058 40,994 250,000................................ 56,081 71,324 86,566 69,308 57,244 275,000................................ 65,831 84,324 102,816 85,558 73,494 300,000................................ 75,581 97,324 119,066 101,808 89,744 325,000................................ 85,331 110,324 135,316 118,058 105,994 350,000................................ 95,081 123,324 151,566 134,308 122,244 375,000................................ 104,831 136,324 167,816 150,558 138,494 400,000................................ 114,581 149,324 184,066 166,808 154,744
10 For the executive officers named in the Summary Compensation Table, compensation covered by the SERP consists of base salary shown in the Salary column of that Table, and incentive awards received under the Company's 1987 Executive Incentive Plan, including amounts shown for 1996 in the Bonus column of that Table and amounts included in the Bonus column for 1995 as follows: Mr. Flanagan, $36,000.00; Mr. Adelberg, $15,781.67; Mr. Marsh, $15,781.67; Mr. Crabtree, $15,646.66; and Mr. Poulin, $12,736.67. Messrs. Flanagan, Adelberg, Marsh, Crabtree and Poulin have been credited with 11, 10, 22, 24 and 25 years of service, respectively. Years of credited service up to 25 years are taken into account in computing retirement benefits under the SERP. Benefits listed in the SERP Table reflect the deduction of benefits payable under the Basic Pension Plan upon attainment of age 65, as shown in the Basic Pension Plan Table. SERP benefits payable by the Company to Messrs. Flanagan, Adelberg, Marsh, Crabtree and Poulin will be further reduced, dollar for dollar, by the amount of the cash surrender value of universal life insurance policies, which have been purchased for these five executive officers, at such time as their respective interests in the cash surrender value may vest. Under an employment agreement with the Company, which is described below, Mr. Flanagan is entitled to an incremental retirement benefit, beginning at age 55, that, when added to benefits payable to him under the Basic Pension Plan and the SERP, provides an aggregate annual retirement benefit of 65 percent of base salary earned during the final 12 months of employment with the Company plus the average of incentive compensation earned under the 1987 Executive Incentive Plan for the three years preceding the termination of his employment. Benefits payable to Mr. Flanagan under the Basic Pension Plan and the SERP as well as any amounts received under the universal life insurance policy for Mr. Flanagan will be offset against the total retirement benefit payable under the agreement. At assumed total covered compensation in the amounts set forth below, the aggregate annual retirement benefit payable to Mr. Flanagan, beginning at age 55, would be as follows:
TOTAL COVERED AGGREGATE COMPENSATION ANNUAL BENEFIT ------------- -------------- $250,000................................ $162,500 275,000................................ 178,750 300,000................................ 195,000 325,000................................ 211,250 350,000................................ 227,500 375,000................................ 243,750 400,000................................ 260,000
EMPLOYMENT AND TERMINATION OF EMPLOYMENT ARRANGEMENTS Effective December 9, 1994, the Company entered into separate employment agreements with Messrs. Adelberg, Marsh, Crabtree and Poulin. The Company also entered into an employment agreement with Mr. Flanagan effective December 29, 1995. The agreements are intended to encourage these executive officers to continue their employment so that the Company will have the continuing benefit of their services during a period of transition in its business due to the challenges of operating in an increasingly competitive environment and in the event of a change of control of the Company. The agreements provide for a specified minimum base salary and for participation in benefit plans in accordance with the provisions of those plans. In addition, Mr. Flanagan's agreement provides for an incremental retirement benefit that, when added to benefits payable to him under existing pension plans, provides an aggregate annual retirement benefit, beginning at age 55, of 65 percent of his base salary for the final 12 months of employment plus the average of short-term incentive compensation earned for the three years preceding the termination of his employment. The agreements also provide for severance benefits for certain terminations of employment. If, within 36 months following a change of control of the Company, the executive officer's employment is terminated by 11 the Company without cause or by the executive officer within 12 months of an event constituting a constructive discharge, the Company will provide the following severance benefits to Mr. Adelberg, Mr. Marsh, Mr. Crabtree or Mr. Poulin, as the case may be: (1) a lump sum amount equal to 2.99 times the annual average of his base salary and certain incentive compensation over the five years before the change of control; (2) the continuation of the minimum level of coverage available under the Company's group medical, life, accident and disability plans for three years; (3) three years of credit under any pension plan in which the executive officer participates; and (4) limited outplacement services. In addition to the change of control severance benefits described in items (2), (3) and (4) for the other executive officers, Mr. Flanagan's agreement provides for a lump sum payment equal to 2.99 times his base salary earned during the 12 months before the change of control plus the three-year average of short-term incentive compensation earned for the period preceding the change of control and also continues the incremental retirement benefit. If no change of control has occurred and the executive officer's employment is terminated by the Company without cause or by the executive officer within six months of a constructive discharge, the executive officer will be entitled to receive severance benefits equal to one times his annual base salary in effect at the time of termination, in 12 monthly installments. In such a case, the last six monthly payments will be reduced by an amount equal to any salary or commissions earned elsewhere by an executive officer other than Mr. Flanagan, for whom no reductions are made. The agreements for Messrs. Adelberg, Marsh, Crabtree and Poulin continue in effect until December 31, 1997, and for Mr. Flanagan until December 31, 1998, and are automatically extended for one year on each December 31 unless either the Company or the executive officer gives prior notice of an intention not to extend his agreement. The agreements provide for one final three-year extension after a change of control. COMPENSATION COMMITTEE REPORT ON EXECUTIVE COMPENSATION OVERVIEW. Beginning in mid-1996, the Compensation and Benefits Committee of the Board of Directors of the Company (the "Committee") conducted an evaluation of the Company's executive compensation programs with the assistance of an independent compensation consultant with a national practice. The Committee's objectives in assessing the design and operation of the Company's executive compensation programs were to assure that total compensation opportunities are competitive with those available in the utility industry and general industry and contain significant pay-for-performance elements to align more closely the interests of the Company's executive officers and its shareholders by supporting and increasing shareholder value. The Committee concluded that the three existing components of total direct compensation for the Company's executive officers, namely, base salary, annual incentives and long-term incentives, were appropriate means of achieving these objectives, but that each of these items needed to be redesigned to be more highly leveraged for performance and shareholder value enhancement and to be more competitive in a changing business environment. Modifications to the base salary program became effective in 1996 while certain modifications to the Company's annual and long-term incentive compensation programs will be given effect in 1997. As discussed in Proposal 3 in this Proxy Statement, one modification to the long-term incentive compensation program requires approval of the Company's shareholders. To achieve its objectives, the Committee determined that the elements of direct compensation needed to be realigned with an expanded competitive market. This market includes electric utilities in the EEI 100 Index used in the performance graph below and companies from general industry that are selected from a published survey compiled by the Committee's independent compensation consultant based on business diversity and complexity, competitive similarities, revenue size and geography. This expanded market will better enable the Company to attract and retain executive talent that is essential in aggressively managing the Company's 12 changing business requirements in an increasingly competitive climate resulting from federal and state regulatory and legislative initiatives that have opened the generation and transmission markets to competition and that are likely to result in further competition in the Company's business. Total compensation opportunities provided by base salary and annual and long- term incentives have been redesigned to reflect median compensation levels for positions with comparable responsibilities in the targeted blended market. The median represents a fifty/fifty blend of the median pay of electric utilities and companies from general industry. The mix of these compensation elements is performance leveraged to support and enhance shareholder value by tying earnings opportunities to performance results. BASE SALARY. Base salaries of the executive officers are measured against median base salary levels for positions with comparable functional responsibilities in the identified market, adjusted to take into account individual abilities and skills in light of the business challenges requiring those attributes. After reviewing market information provided by its compensation consultant showing that base salary levels for the executive officers as a group was on average approximately 25 percent below market, the Committee adjusted base salaries of the executive officers other than Mr. Flanagan an average 13 percent to bring the salaries of these officers within range of but lower than the market for their positions. Mr. Flanagan's salary for 1996 reflects an increase of approximately 10 percent to recognize his performance and to narrow the substantial 55 percent competitive gap between his prior base salary and the median market salary for his position shown by market surveys provided by the Committee's consultant. This increase represents an interim adjustment pending a separate evaluation by the Committee of the compensation and benefits of the President and Chief Executive Officer. ANNUAL INCENTIVES. In 1996, the Company's annual incentive compensation program for its executive officers, including the President and Chief Executive Officer, reflected the Company's 1996 Corporate Goals and Objectives, which were previously adopted by the Board of Directors. In this way, the annual incentive compensation program supported the Company's financial and operating goals. For 1996, three broad company performance goals focused on improving financial performance, transitioning to competition, and earning customer loyalty. In addition, the Committee adopted individual performance goals which were key components of corporate strategy. The company performance goals and the individual goals were weighted equally, so that participants could receive up to one-half of the maximum possible award under each of these two groups of goals. The potential maximum award payout in 1996 for the President and Chief Executive Officer was 30 percent of base salary and was 20 percent of base salary for the other executive officers. The Committee determined that 70 percent of the objectives under the three broad company performance goals had been attained in 1996 and also reviewed individual performance results. The total payout for the President and Chief Executive Officer was 23 percent of his base salary, and for the other executive officers the payout ranged from 14 to 17 percent of 1996 base salaries, depending on the level of achievement of their individual goals. LONG-TERM INCENTIVE COMPENSATION. The Long-Term Incentive Plan ("LTIP"), in which Mr. Flanagan and the other named executive officers participated in 1996, is intended to focus attention more sharply on a performance objective that is designed to increase value to shareholders over the longer term. Under the LTIP, contingent grants of performance restricted shares of the Company's Common Stock have been made at the beginning of certain three-year performance periods. These shares, as well as additional shares resulting from the reinvestment of dividends, have remained completely at risk and subject to forfeiture to the extent performance results have not been achieved. At the end of the performance period, the number of shares payable is based on the ranking of the three-year average of the Company's total shareholder return (stock price plus dividends) against the three-year average of the total shareholder return of other utilities in the EEI 100 Index against which the Company's performance is measured in the performance graph. 13 No shares of performance restricted stock were granted for the performance period beginning in 1996 as a result of the Committee's pending review of the Company's executive compensation programs, including the long-term incentive component. For the three-year performance period ending December 31, 1996, the threshold level of performance with respect to the ranking of the Company's total shareholder return was not attained. As a result, the shares contingently granted for that period plus shares accrued through dividend reinvestment were forfeited. Mr. Flanagan forfeited 8,424 shares, and the other named executive officers forfeited lesser amounts. OTHER POLICIES. Effective January 1, 1997, the Company's executive officers and other members of the Company's management will be required to increase their holdings of Company stock so that within a four-year period, the President and Chief Executive Officer owns stock with a value no less than three times his base salary, with lesser multiples of base salary required for other executive officers and members of management. A provision of federal tax law denies a tax deduction to any publicly-held company for compensation paid to any named executive officer that exceeds one million dollars in a taxable year, except for certain performance-based compensation. The Committee has not adopted a policy with respect to these compensation limits because it is anticipated that compensation paid to the Company's executive officers will be less than one million dollars. Compensation and Benefits Committee Charles H. Abbott (Chair) E. James Dufour Duane D. Fitzgerald Peter J. Moynihan 14 SHAREHOLDER RETURN COMPARISON The graph below compares the cumulative total shareholder return on the Common Stock of the Company with the cumulative total return on the S&P 500 Index and the Edison Electric Institute Index of 100 investor-owned electric utilities ("EEI 100 Index") at December 31 for each of the last five fiscal years (assuming the investment of $100 in the Company's Common Stock, the S&P 500 Index and the EEI 100 Index on December 31, 1991, and the reinvestment of all dividends). [GRAPH]
DECEMBER 31 ----------------------------- 1991 1992 1993 1994 1995 1996 ---- ---- ---- ---- ---- ---- Central Maine Power Company....................... $100 $110 $ 75 $ 73 $ 83 $ 71 S&P 500 Index..................................... $100 $108 $118 $120 $165 $203 EEI 100 Index..................................... $100 $108 $120 $106 $139 $140
15 PROPOSAL 2 APPROVAL OF INDEPENDENT PUBLIC ACCOUNTANTS At the regular meeting held on February 20, 1997, the Board of Directors of the Company acted to appoint Coopers & Lybrand L.L.P., Boston, Massachusetts, as auditors for the Company for 1997. At the Annual Meeting it is the intention of the persons named in the proxy enclosed herewith to vote in favor of the approval of such action by the Board of Directors. Representatives of Coopers & Lybrand L.L.P. will attend the meeting and, if they so desire, make a statement; they will also respond to appropriate questions. The appointment of Coopers & Lybrand L.L.P. by the Board of Directors is based on the recommendation of the Audit Committee, which historically has reviewed both the audit scope and the estimated audit fees and related services for the coming year. The Audit Committee considered the appointment of auditors for the Company for 1997 at a meeting held on February 18, 1997. The affirmative vote of a majority of the votes cast by the holders of the Company's Common Stock and 6% Preferred Stock, voting as a single class, entitled to vote at the Annual Meeting, is sought for approval of the appointment. THE BOARD OF DIRECTORS RECOMMENDS A VOTE FOR PROPOSAL 2. PROPOSAL 3 APPROVAL OF AMENDMENT TO LONG-TERM INCENTIVE PLAN TO INCLUDE STOCK OPTIONS PROGRAM At the 1994 Annual Meeting, the Company's shareholders adopted the Long-Term Incentive Plan (the "Plan"), under which the executive officers of the Company and ten other key members of management may earn incentive compensation to the extent that performance has resulted in gains for shareholders. The Plan is intended to focus the attention of this management group more sharply on enhancing shareholder value by tying earnings opportunities to the attainment of performance objectives that are designed to increase shareholder value over the longer term. Under the Plan, the Compensation and Benefits Committee of the Board of Directors (the "Committee"), which is composed entirely of outside directors, has made contingent grants of performance restricted shares of the Company's Common Stock at the beginning of certain three-year performance periods. During a performance period, grants of shares have remained completely at risk and have been forfeited to the extent performance results were not achieved. Participants receive compensation from these grants only to the extent that performance results warrant a payout of the shares at the end of a performance period. This approach closely aligns the interests of the Company's management with shareholder interests by providing value to this management group only if and to the extent value for shareholders is created. The Plan allows forms of Common Stock in addition to performance restricted stock to be granted, but does not currently provide for stock option grants. Maine law requires shareholder approval of stock option grants used as incentive compensation. The Board believes that stock options will emphasize the importance of enhancing value for the Company's shareholders. The options, representing the right to purchase a fixed number of shares of the Company's Common Stock during a seven-year period at a price not less than the Stock's market value as of the date the options are granted, will provide value to recipients only if and to the extent that the price of the Company's Stock increases above the Stock price on the date the options are granted. In this way, an executive will be rewarded only for appreciation in the Stock's value over a baseline represented by the option price. On March 18, 1997, the closing price of the Company's Common Stock on the New York Stock Exchange was $11.25 per share. The stock options program will also promote the Company's policy of increasing the stock holdings of the Company's executive officers so that within a four-year period, the President and Chief Executive Officer owns stock with a value no less than three times his base salary, with lesser multiples of base salary required for other executive officers and members of management. 16 Options will vest in one-third increments over three years. During the seven- year option term, an executive may exercise options which have vested by paying the exercise price of the option in cash or unrestricted Common Stock of the Company with a value equal to the exercise price. Stock underlying the option will be purchased for the executive on the open market by an agent for participants in the Plan, with the Company paying the difference between the exercise price and the market price of the Stock. There will be no provision in the stock options program permitting discount options, reload options, or repricing of "underwater" options. If approved by the Company's shareholders, stock options will be granted annually, either alone or in combination with a form of Common Stock available under the Plan. Competitive data compiled by the Committee's independent compensation consultant from companies in the utility industry and general industry and individual salaries and performance levels will be used to determine the number of options granted. At current salary and Common Stock price levels, estimated target stock option grants made in 1997 would be as follows: NEW PLAN BENEFITS
NUMBER OF NAME AND POSITION UNITS ----------------- --------- David T. Flanagan................................................ 50,000 President and Chief Executive Officer Arthur W. Adelberg............................................... 13,570 Vice President, Law and Power Supply David E. Marsh................................................... 13,570 Vice President, Corporate Services, Treasurer, and Chief Financial Officer Richard A. Crabtree.............................................. 12,640 Vice President, Retail Services Gerald C. Poulin................................................. 10,355 Vice President, Generation and Technical Support Executive Group.................................................. 109,635 Other Management Group........................................... 77,000
Under federal tax law, a recipient of options pays income tax on the appreciated value of the stock over the exercise price at the time of exercise. The Company is entitled to a deduction in the same amount at the time of exercise. The stock options program will expire in ten years. Any extensions of this term will require approval of the Company's shareholders. The Plan currently provides that in any calendar year, grants will not exceed one percent of the number of outstanding shares of unrestricted Common Stock of the Company on the last day of the preceding calendar year. It is intended that this provision include shares of the Company's Common Stock available upon exercise of stock options and that no additional shares be made available for that purpose. An affirmative vote of a majority of all outstanding shares of Common Stock and 6% Preferred Stock, voting as a single class, is required for approval of Proposal 3. THE BOARD OF DIRECTORS RECOMMENDS A VOTE FOR PROPOSAL 3. 17 PROPOSAL 4 CONSENT TO INCREASE IN UNSECURED MEDIUM-TERM NOTE PROGRAM At the 1989 Annual Meeting of the Company's Shareholders, the holders of Preferred Stock of all classes outstanding consented to a program for the issuance of up to $150 million in unsecured medium-term notes (the "Medium-Term Notes" or the "Notes"). The Company now seeks the consent of the holders of the Company's Preferred Stock to an increase of $350 million in the amount of the Medium-Term Note program, for a maximum of $500 million in aggregate principal amount of Medium-Term Notes that could be outstanding at any one time. The Medium-Term Note program has given the Company the ability to take advantage of market conditions by increasing the Company's access to financial markets on a timely basis. This flexibility has allowed the Company to finance customer programs and other business requirements on favorable terms. An expanded Medium-Term Note program in an incremental amount of $350 million will continue to provide needed financial flexibility to address the Company's changing business requirements in an increasingly competitive business climate. The electric utility industry is becoming more competitive as a result of federal and state regulatory and legislative developments that have opened the generation and transmission markets to competition. The Maine Legislature and the United States Congress currently are considering proposals for the restructuring of the electric utility industry. Although the Company cannot predict the specific actions that the Maine Legislature and the Congress will take, additional competition in the Company's business is anticipated as a result of action on restructuring proposals under consideration. In this transitioning business environment, the Company is taking aggressive steps to meet the competitive challenges of operating its business to enhance shareholder value and to meet customer requirements. By increasing the maximum amount of unsecured Medium-Term Notes that can be issued, the Company will gain the flexibility to position itself to participate in a restructured, more competitive generation and transmission marketplace. The Medium-Term Note program affords this flexibility by allowing the issuance of various types of unsecured debt securities in any amount at full face value or at a discount. In addition, under the program, Notes can be issued with maturities ranging from nine months to thirty years, can bear interest at either fixed or floating rates, and can have a fixed term or be redeemable at the Company's option. The specific terms of the Notes, including interest rates, redemption provisions, maturity dates, prices and similar matters, are and would be determined by the Board of Directors or specific executive officers designated by the Board. These features give the Company the opportunity to take advantage of favorable capital market conditions to finance business structures and transactions that may be required by deregulation initiatives currently under consideration by federal and State policymakers or that may otherwise position the Company to gain a benefit in more competitive energy markets. The more restrictive features of the Company's General and Refunding Mortgage Indenture, under which bonds that are secured by substantially all the Company's operating property are issued, could inhibit the Company's strategic flexibility in changing its business to operate in a deregulated and increasingly competitive market. As part of the transition to competition, it may be in the Company's best interests to refund the $421 million in principal amount of outstanding mortgage bonds by using the expanded capacity under the Medium-Term Note program and subsequently relying on that program as the primary vehicle for meeting its financing needs in a way that allows the Company to take advantage of favorable market conditions. Currently, the Company's Articles of Incorporation limit the amount of unsecured debt that the Company can issue to 20 percent of the total of the Company's outstanding mortgage bonds and preferred and common equity capital unless the holders of the Company's Preferred Stock consent to the unsecured debt issuance. As a result of the consent of the Preferred Stock holders at the 1989 Annual Meeting, the 18 existing $150 million Medium-Term Note program is not included in calculating the 20 percent limitation. If the holders of the Company's Preferred Stock consent to an incremental $350 million of Medium-Term Notes that may be issued by the Company, the total $500 million amount of Notes would not be subject to this limitation. Based upon the Company's December 31, 1996 financial statements, which are attached to this Proxy Statement along with Management's Discussion and Analysis of Financial Condition and Results of Operations, unsecured debt issued by the Company cannot exceed $123 million without such consent. Consent to the additional amount of Medium-Term Notes would allow the Company to have up to $500 million of its unsecured Medium-Term Notes outstanding at any one time in addition to the amount of unsecured indebtedness permitted by the 20 percent limitation. The Medium-Term Notes have been issued in three series, with $68 million in aggregate principal amount outstanding as of February 28, 1997. Actual issuance of the incremental $350 million amount of Medium-Term Notes currently is subject to approval of the Maine Public Utilities Commission for Notes maturing more than one year from the date of issuance and the Federal Energy Regulatory Commission for Notes with maturities of one year or less. Representatives of Coopers & Lybrand L.L.P., the Company's accountants, will be present at the Annual Meeting, will have the opportunity to make a statement if they desire to do so, and will respond to appropriate questions. Consent to the issuance of a maximum additional amount of Medium-Term Notes of $350 million requires the affirmative vote of the holders of a majority of the 6% Preferred Stock and Dividend Series Preferred Stock present or represented at a meeting at which the holders of a majority of that Stock are represented or present, voting together as a single class. THE BOARD OF DIRECTORS RECOMMENDS A VOTE FOR PROPOSAL 4. DEADLINE FOR SHAREHOLDER PROPOSALS Proposals of shareholders intended to be presented at the 1998 Annual Meeting of the Shareholders must be received on or before December , 1997, for inclusion in the proxy materials relating to that meeting. Any such proposals should be sent to Anne M. Pare, Secretary and Clerk, Central Maine Power Company, 83 Edison Drive, Augusta, Maine 04336. 19 OTHER MATTERS The accompanying proxy is solicited by and on behalf of the Board of Directors of Central Maine Power Company for use at the Annual Meeting of the Shareholders to be held on May 15, 1997 or any adjournments thereof. The cost of solicitation will be paid by the Company. No solicitation is to be made by specially engaged employees or other paid solicitors except that Corporate Investor Communications, Inc. will solicit shareholders of record and broker nominees on behalf of the Company, for which it will receive a fee of approximately $8,000, plus reasonable expenses. Banks, brokerage firms and other custodians, nominees and fiduciaries will be reimbursed by the Company for reasonable expenses incurred in sending proxy materials to beneficial owners of the Company's Common Stock, 6% Preferred Stock and Dividend Series Preferred Stock. In addition, directors, officers or employees of the Company may solicit proxies by telephone or in person, the costs of which will be nominal. The Board of Directors of the Company does not know of any matter, other than the matters set forth in this Proxy Statement, to be acted upon at this Annual Meeting. However, if any other matter shall be properly brought before the meeting, the proxies will be voted in respect thereof in accordance with the judgment of the person or persons voting the proxies. By Order of the Board of Directors /s/ David T. Flanagan David T. Flanagan President and Chief Executive Officer Augusta, Maine April , 1997 Again, we call your attention to the enclosed Proxy. We would appreciate it very much if you would VOTE, DATE, SIGN and RETURN IT PROMPTLY, regardless of whether you plan to attend the meeting. 20 APPENDIX SELECTED FINANCIAL DATA. The following table sets forth selected consolidated financial data of the Company for the five years ended December 31, 1992 through 1996. This information should be read in conjunction with "Management's Discussion and Analysis of Financial Condition and Results of Operations" and the consolidated financial statements and related notes thereto included elsewhere herein. The selected consolidated financial data for the years ended December 31, 1992 through 1996 are derived from the audited consolidated financial statements of the Company. SELECTED CONSOLIDATED FINANCIAL DATA
(DOLLARS IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) ----------------------------------------------------------- 1996 1995 1994 1993 1992 ---------- ---------- ---------- ---------- ---------- Electric operating reve- nue.................... $ 967,046 $ 916,016 $ 904,883 $ 893,577 $ 877,695 Net income (loss)....... 60,229 37,980 (23,265) 61,302 63,583 Long-term obligations... 587,987 622,251 638,841 581,844 499,029 Redeemable preferred stock.................. 53,528 67,528 80,000 80,000 40,750 Total assets............ 2,010,914 1,992,919 2,046,007 2,004,862 1,690,005 Earnings (loss) per com- mon share.............. $ 1.57 $ 0.86 $ (1.04) $ 1.65 $ 1.85 Dividends declared per common share........... $ 0.90 $ 0.90 $ 0.90 $ 1.395 $ 1.56
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS. OVERVIEW In 1996, the Company experienced higher than normal costs associated with its investments in nuclear generating units, particularly the Maine Yankee nuclear plant, and incurred replacement-power costs due to unplanned nuclear-plant outages. While the return to service of the Maine Yankee nuclear plant in mid-January 1996 ended an 11-month consecutive outage, the plant's operating capacity was limited to 90% of its maximum production capacity during periods of operation in 1996 and unscheduled outages reduced the availability of the plant to less than 10 months of operation. The additional costs incurred by the Company under its power contract with Maine Yankee were approximately $3.6 million. Replacement-power costs associated with the reduced level of output and limited availability of the plant amounted to approximately $13.5 million for a total of $17.1 million or an earnings reduction of $0.31 per share, after tax, during 1996. The Company's 1996 financial results benefited by approximately $15.3 million, after tax, or $0.47 per share, as a result of non-recurring items related to a favorable resolution of federal income-tax issues with the Internal Revenue Service, a reduction in purchased power costs associated with an extended outage at a non-utility generator (NUG) under contracts to the Company, an energy-swap agreement with another utility that reduced purchased- power costs, and the affirmation of the rate recovery of a regulatory asset. Earnings per share in 1996 were $1.57, after recognizing the higher nuclear- related costs and benefits of non-recurring events, compared to $0.86 per share in 1995. The 1995 earnings per share included the recognition of $0.70 per share in Maine Yankee-related repair and replacement-power costs. The Maine Yankee nuclear plant was shut down on December 6, 1996, for inspection and repairs. Maine Yankee has notified the Company that, due to the need to replace 92 fuel assemblies, it will refuel the plant during the current outage. While the plant is out of service, Maine Yankee must, in addition to replacing the fuel assemblies, conduct an intensive inspection of its steam generators, resolve cable-separation and other A-1 regulatory issues, and obtain NRC approval to restart the plant. The Company believes the plant will be out of service at least until August 1997, but cannot predict when or whether all of the regulatory and operational issues will be satisfactorily resolved, or what effect the repairs and improvements to the plant will have on its operating economics. The Company will incur significantly higher costs in 1997 for its share of inspection, repairs and refueling costs at Maine Yankee, and will also need to purchase replacement power while the plant is out of service. While the amount of higher costs is uncertain, Maine Yankee has indicated that it expects its operations-and-maintenance costs to increase by up to approximately $45 million in 1997, before refueling costs. The Company's share of such costs, based on its power entitlement of approximately 38%, would be up to approximately $17 million. In addition, the Company estimates its share of the refueling costs will amount to approximately $15 million; $10.4 million has been accrued as of December 31, 1996. The Company has been incurring incremental replacement-power costs of approximately $1 million per week while the plant has been out of service and expects such costs to continue at approximately the same rate until the plant returns to service. The impact of these higher nuclear-related costs on the Company's 1997 financial results will be significant and is likely to trigger a low earnings bandwidth provision of the Alternative Rate Plan (ARP). Under the ARP, actual earnings for 1997 outside a bandwidth of 350 basis points, above or below the 10.68% rate of return allowance, triggers the profit sharing mechanism. A return below the low end of the range provides for additional revenue through rates equal to one-half of the difference between the actual earned rate of return and the 7.18% (10.68--3.50) low end of the bandwidth. While the Company believes the profit-sharing mechanism is likely to be triggered in 1997, it cannot predict the amount, if any, of additional revenues that may ultimately result. The ARP was structured to permit reasonable assurance of continued recovery of the cost of services, including past deferrals, provide a higher degree of price stability and predictability, and reduce regulatory costs while providing financial incentives for improved efficiencies and protection against significant unforeseen events. The Company declared dividends totaling $0.90 per share in 1996, unchanged from 1995 and 1994 levels. Dividend and capital structure policy will continue to be reviewed by management and the Board of Directors and will take into consideration such issues as sustainable long-term earnings, capital needs, business opportunities and business risk, the structure of the Company and the industry, and the overall need to assure that financial risk and business risk are aligned. In the near term, the Company anticipates significant downward pressure on its earnings capacity as a result of the higher cost and outages of the Maine Yankee and Millstone Unit No. 3 nuclear facilities. The capacity of the Company to attain earnings levels that support the current dividend are closely related to the performance and cost associated with the Company's Maine Yankee investment and power entitlement. Sustained nuclear-unit outages combined with higher nuclear operating costs in 1997 will be a major obstacle to achieving satisfactory results in 1997 despite prudent control of other operating costs. On a prospective basis, a contract with a major NUG representing 62.5 MW of capacity expires on October 31, 1997. Net annual savings due to the contract expiration would be approximately $25 million, with 1997 savings amounting to approximately $4 million. The Company continues to face the challenges of competition and industry restructuring, and must achieve and maintain financial performance and resources commensurate with both the provision of service demanded by customers and the obligation to achieve competitive returns on investor capital. The Company is aggressively addressing the challenges of restructuring, the pressure from competitive energy sources, customers' desire for choices and enhanced service, and nuclear-plant outages in 1997. The A-2 following long-term financial objectives are key to sustainable future earnings and growth and will be a major focus of our 1997 activities: 1. Continue increasing the efficiency of operations: cost management under price-cap regulation must replace the cost-plus culture encouraged by traditional regulation. 2. Focus on volume of sales as a revenue builder. 3. Align financial policies to changing business needs and risks; competition tends to increase business risk, which impacts the desired level of fixed-charge obligations. 4. Expand areas of investment for growth; open competition in electric energy could significantly reduce traditional sales-growth opportunities. 5. Recover the substantial investments made and costs being incurred for existing service obligations; open competition could strand these costs, absent a transition mechanism for recovery. EARNINGS AND DIVIDENDS For 1996, the Company generated net income of $60.2 million, compared to $38.0 million in 1995, and a net loss of $23.3 million in 1994. Earnings applicable to common stock were $50.8 million in 1996 or $1.57 per share, compared to $27.8 million or $0.86 per share in 1995. In 1994, the loss applicable to common stock was $33.8 million or $1.04 per share. The Company benefited from higher sales, cost management initiatives, surplus power sales and certain non-recurring events during the year as discussed below. In addition, net income in 1996 reflects replacement power costs for unscheduled nuclear unit outages of approximately $18.5 million. Increased nuclear operations, maintenance and study costs to comply with NRC safety actions amounted to approximately $4.3 million in 1996. See "Maine Yankee Regulatory Issues" and "Other Nuclear Issues" for more information. Certain favorable one-time events took place in 1996. Due to a flood in the fall of 1996, a non-utility generator was temporarily forced out of service for an extended period. This enabled the Company to purchase replacement power at a lower cost for a savings of approximately $5.4 million. An energy-swap agreement signed in 1994 with Northeast Utilities allowed the Company to save approximately $6 million in purchased power costs. A settlement with the Internal Revenue Service on audits for the years 1988-1991 provided a decrease to income tax expense of approximately $4.8 million. The 1996 Maine Public Utilities Commission's (MPUC) Alternative Rate Plan (ARP) decision provided the Company recovery in rates for its workers' compensation regulatory asset of $6.4 million, which resulted in the reversal of a 1995 charge due to uncertainty about recovery in rates. Net income in 1995 reflects $29 million of replacement purchased-power energy expense and $10 million for the Company's share of sleeving repair costs during the extended shutdown at Maine Yankee. These two items reduced earnings applicable to common stock by $22.9 million after income taxes, or $0.70 per share. The loss in 1994 reflects the write-off of approximately $100 million ($60 million after taxes) of deferred balances in accordance with the MPUC order in the ARP proceeding discussed fully below under the caption "Alternative Rate Plan" and Note 3 to Consolidated Financial Statements, "Regulatory Matters--Alternative Rate Plan." This write-off had the effect of reducing earnings per share by $1.85. Absent the write-off, earnings for 1994 would have been $0.81 per share. Dividends declared per common share have remained at $0.90 on an annual basis for the three years ended December 31, 1996. A-3 REVENUES AND SALES Electric operating revenues increased by $51.0 million or 5.6% to $967.0 million in 1996, and by $11.1 million or 1.2% to $916.0 million in 1995. The components of the change in electric operating revenues are as follows:
1996 1995 ---------- ---------- (DOLLARS IN MILLIONS) Revenues from Company service-area kilowatt-hour sales.............................................. $ 15.0 $ 4.5 Revenues from non-territorial sales................. 33.4 (9.2) Other Company operating revenues.................... 3.0 8.7 Maine Electric Power Company, Inc. fuel cost recov- ery and other revenues............................. (0.4) 7.1 ---------- ---------- Total Change in Electric Operating Revenues......... $ 51.0 $ 11.1 ========== ==========
Refer to "Alternative Rate Plan" below, for a discussion of new rates and their impact on revenues. The Company's service-area sales for the years 1996, 1995, and 1994 are shown in the following table:
1996 1995 1994 ------------ ------------ ------------ % % % KWH CHANGE KWH CHANGE KWH CHANGE ----- ------ ----- ------ ----- ------ (KILOWATT-HOURS IN MILLIONS) Residential......................... 2,829 1.0% 2,802 (2.0)% 2,860 (0.9)% Commercial.......................... 2,489 0.5 2,477 1.6 2,439 2.2 Industrial.......................... 3,689 4.0 3,547 (4.7) 3,720 (1.9) Wholesale and lighting.............. 217 58.9 136 (8.7) 149 (3.5) ----- ---- ----- ---- ----- ---- Total Service-Area Sales............ 9,224 2.9% 8,962 (2.2)% 9,168 (0.5)% ===== ==== ===== ==== ===== ====
The primary factors in the service-area kilowatt-hour sales increase were residential customers' taking advantage of the Company's water-heating programs, increased sales in the pulp and paper industry, and the addition of a wholesale customer. The decreases in 1995 and 1994 were attributed to low economic growth, the loss of a major industrial customer in September 1994, energy management, and loss of sales due to conversions from electricity to alternative fuels for such purposes as space and water heating. The average number of residential customers increased by 5,157 in 1996, 5,076 in 1995, and 4,679 in 1994, while average usage per residential customer declined slightly in 1996, 3.1% in 1995 and 1.9% in 1994. The 1996 increase in commercial sales reflect increases in the retail and wholesale trade and service sectors. Combined, these sectors comprise approximately 68% of commercial sales. Sales to all others in the commercial sector were lower than 1995. Sales to Maine Yankee increased by 4 million kilowatt hours in 1996, and by 14.7 million kilowatt hours in 1995 due to the Plant's operating capacity limit of 90% and extended outages in both periods. Industrial sales levels are significantly affected by sales to the pulp-and- paper industry, which accounts for approximately 62% of industrial sales and approximately 25% of total service-area sales. Sales to the pulp-and-paper sector increased by 3.7% in 1996 and decreased by 8.6% in 1995, and by 3.6% in 1994. The increase in 1996 reflects special arrangements the Company has made with several paper companies to back down some of their self-generation and buy electricity from the Company at a discounted rate. The 1995 and 1994 decreases reflect lower sales levels primarily due to the late-1994 loss of a major customer that had previously purchased approximately 280 million kilowatt-hours annually. Refer to "Alternative Rate Plan" and "Competition and Economic Development," below, and Note 4 to Consolidated Financial Statements, "Commitment's and Contingencies--Competition," for additional information regarding the loss of this customer and the Company's actions to preserve its remaining large-industrial-customer base and other customer groups. Sales to all other industrial customers as a group increased 4.5% in 1996, 2.7% in 1995, and 1.5% in 1994. A-4 Revenues from non-territorial sales were significantly higher in 1996 due to sales to an out-of-state utility impacted by nuclear plant outages. In March 1995, a contract with a power broker expired, resulting in a decrease of $9.2 million in 1995 in non-territorial sales. ALTERNATIVE RATE PLAN In December 1994, the MPUC approved a stipulation, signed by most of the parties to the Company's ARP proceeding, which took effect January 1, 1995. This follow-up proceeding to the Company's 1993 base-rate case was ordered by the MPUC in an effort to develop a five-year plan containing price-cap, profit- sharing, and pricing-flexibility components. The price-cap mechanism provides for adjusting the Company's retail rates annually on July 1, commencing in 1995, at a percentage combining (1) a price index, (2) a productivity offset, (3) a sharing mechanism, and (4) flow-through items and mandated costs. The price cap applies to all of the Company's retail rates, and includes fuel-and- purchased-power costs that previously had been treated separately. The components of the July 1, 1995, price-cap increase of 2.43% are the inflation index of 2.92%, reduced by a productivity offset of 0.5%, and increased by 0.01% for flow-through items and mandated costs. The components of the July 1, 1996, price-cap increase of 1.26% consisted of an inflation index of 2.55% and earnings sharing and mandated cost items of 0.64%, reduced by a productivity offset of 1.0%, and sharing of contract restructuring and buyout savings of 0.93%. As originally stated in the MPUC's order approving the ARP, operation under the ARP continues to meet the criteria of Statement of Financial Accounting Standards No. 71, "Accounting for the Effects of Certain Types of Regulation" (SFAS No. 71). As a result, the Company will continue to apply the provisions of SFAS No. 71 to its accounting transactions and to its financial statements. In 1994, the Company agreed in the ARP negotiations to record charges of approximately $100 million ($60 million, net of tax) against 1994 earnings. The Company believes the ARP provides the benefits of needed pricing flexibility to set prices between defined floor and ceiling levels in three service categories: (1) existing customer classes, (2) new customer classes for optional targeted services, and (3) special-rate contracts. The Company believes that the added flexibility will position it more favorably to meet the competition from other energy sources that has eroded segments of its customer base. Some price adjustments can be implemented upon 30-days' notice by the Company, while certain others are subject to expedited review by the MPUC. The Company has utilized this feature in providing new rates to approximately 19,000 customers representing approximately 40% of annual kilowatt-hour sales and 27% of service-area revenues. These reductions in rates were offered to customers after consideration of associated NUG cost reductions, savings from further NUG consolidations and other general cost reductions. The ARP also contains provisions to protect the Company and ratepayers against unforeseen adverse results from its operation. These include review by the MPUC if the Company's actual return on equity falls outside a designated range, a mid-period review of the ARP by the MPUC in 1997 (including possible modification or termination), and a "final" review by the MPUC in 1999 to determine whether or with what changes the ARP should continue after 1999. The Company will submit its 1997 compliance filing and mid-period review filing in March 1997. The MPUC decision on the mid-period review is expected by September 30, 1997. While the ARP provides the Company with an expanded opportunity to be rewarded for efficiency, it also presents the risk of reduced rates of return if costs rise unexpectedly, like those that have resulted from the recent outages at Maine Yankee, or if revenues from sales decline or are not adequate to fund costs. The Company believes the ARP continues to be a competitive advantage and does not plan to propose any significant change during the mid- period review. For a detailed discussion of the ARP, refer to Note 3 to Consolidated Financial Statements, "Regulatory Matters--Alternative Rate Plan," and "Meeting the Requirements of SFAS 71." A-5 MAINE YANKEE REGULATORY ISSUES The Company owns 38% of the common stock of Maine Yankee and is responsible for an approximately equal percentage of its costs. The 879-megawatt Maine Yankee nuclear generating plant in Wiscasset, Maine (the Plant), like others with pressurized water reactors, had been experiencing degradation of its steam generator tubes. Until early 1995, this was believed to be limited to a relatively small number of tubes. During a refueling shutdown in February 1995, new inspection methods used by Maine Yankee revealed that approximately 60% of the Plant's 17,000 steam generator tubes appeared to have defects. Following a detailed analysis of safety, technical and financial considerations, Maine Yankee repaired the tubes by inserting and welding short reinforcing sleeves of an improved material in substantially all of the Plant's steam generator tubes. Repairs were completed in December 1995. The Company's approximately $10-million share of the repair costs adversely affected the Company's 1995 earnings by $0.18 per share, net of taxes, in spite of significant cost-reduction measures implemented by both the Company and Maine Yankee. In addition, the Company incurred incremental replacement-power costs during the outage totaling approximately $29 million, or $0.52 per share, net of taxes, for 1995. Also in December 1995, the Nuclear Regulatory Commission's (NRC) Office of the Inspector General (OIG) and its Office of Investigations (OI) initiated separate investigations of certain anonymous "whistleblower" allegations of wrongdoing by Maine Yankee and Yankee Atomic Electric Company (Yankee Atomic) in 1988 and 1989 in connection with operating license amendments. On May 9, 1996, the OIG, which was responsible for investigating only the actions of the NRC staff and not those of Maine Yankee or Yankee Atomic, issued its report. The report found deficiencies in the NRC staff's review, documentation, and communications practices in connection with the license amendments, as well as "significant indications of possible licensee violations of NRC requirements and regulations." Any such violations by Maine Yankee are within the purview of the OI investigation, which, with related issues, is being reviewed by the United States Department of Justice. A separate internal investigation commissioned by the boards of directors of Maine Yankee and Yankee Atomic and conducted by an independent law firm noted several areas that could have been improved, including regulatory communications, definition of responsibilities between Maine Yankee and Yankee Atomic, and documentation and tracking of regulatory compliance, but found no wrongdoing by Maine Yankee or Yankee Atomic or any of their employees. Issues raised by the anonymous allegations caused the NRC to limit the Plant to an operating level of approximately 90% of its full thermal capacity, pending resolution of those issues. The Company cannot predict the results of the investigations by the OI and Department of Justice. The December 1995 allegations caused the Plant's extended tube-sleeving outage to be further extended into January 1996, and the Plant returned to the 90% operating level on January 24. On June 7, 1996, the NRC formally notified Maine Yankee that it would conduct an "Independent Safety Assessment" (ISA) of the Plant as a "follow-on" to the OIG report and to provide an independent evaluation of the safety performance of Maine Yankee by a team of NRC personnel and contractors who were "independent of any recent or significant involvement with the licensing, regulation or inspection of Maine Yankee." The NRC conducted the ISA in the summer of 1996 and released its report on October 7, 1996. The detailed ISA report identified both deficiencies and strengths in Maine Yankee's performance, and concluded that overall performance at Maine Yankee was "adequate" for operation of the Plant. The ISA team stressed that the deficiencies noted in the report stemmed from two closely related root causes, specifically, (1) that economic pressure to be a low-cost energy provider had limited available resources to address corrective actions and some improvements, and (2) that lack of a "questioning culture" had resulted in a failure to identify or promptly correct significant problems in areas perceived by Maine Yankee to be of low safety significance. In a letter to Maine Yankee accompanying the ISA report, NRC Chairman Shirley Ann Jackson noted that although overall performance at Maine Yankee was considered adequate for operation, a number of significant weaknesses and deficiencies identified in the report would result in NRC violations. The letter also directed Maine Yankee to provide to the NRC its plans for addressing the root A-6 causes of the deficiencies noted in the ISA and identified the NRC offices that would be responsible for overseeing corrective actions and taking any appropriate enforcement actions against Maine Yankee. On December 10, 1996, Maine Yankee filed its formal response to the ISA report with the NRC. In the response, Maine Yankee indicated that it would spend substantial sums on improvements in several areas in 1997 to address the root causes and associated deficiencies noted in the report, and that the improvements would include physical and operating changes at the Plant, along with a 10% increase in staffing, primarily in the engineering and maintenance areas, and other changes. In a release accompanying the response, Maine Yankee stated that a "fundamental shift in corporate culture" would accompany the changes and that Maine Yankee would not seek to return the Plant to the 100% power level from its authorized 90% level until it had reviewed the margins on all the key safety systems at the Plant, which had been another matter of concern to the NRC. The Plant operated substantially at the 90% capacity level until July 20, 1996, when it was taken off-line after a comprehensive review by Maine Yankee of the Plant's systems and equipment revealed a need to add pressure-relief capacity to the Plant's primary component cooling system. On August 18, 1996, while the Plant was in the restart process, Maine Yankee conducted a review of its electrical circuitry testing procedures pursuant to a generic NRC letter to nuclear-plant licensees that was intended to ensure that every feature of every safety system be routinely tested. During the expanded review, Maine Yankee found a deficiency in an electrical circuit of a safety system and therefore elected to conduct an intensified review of other safety-related circuits to resolve immediately any questions as to the adequacy of related testing procedures. The Plant returned to the 90% operating level on September 3, 1996. On December 6, 1996, Maine Yankee took the Plant off-line to resolve cable- separation and other operational and design issues. On January 3, 1997, Maine Yankee announced that it would use the opportunity presented by that outage to inspect the Plant's 217 fuel assemblies, since daily monitoring had indicated evidence of a small number of defective fuel rods. As a result of the inspection, Maine Yankee determined that all of the assemblies manufactured by one supplier and currently in the reactor core (approximately one-third of the total) would have to be replaced before the Plant could be restarted. Maine Yankee will therefore keep the Plant off-line for refueling, which had previously been scheduled for late 1997. In addition, Maine Yankee will make use of the outage to inspect the Plant's steam generators, commencing approximately April 1, 1997, for deterioration beyond that which was repaired during the extended 1995 outage. Degradation of steam generators of the age and design of those in use in the Plant has been identified at other plants. If major repairs to, or replacement of, the steam generators were found to be necessary for continued operation of the Plant, Maine Yankee would review the economics of continued operation before incurring the substantial capital expenditures that would be required. In January, the NRC announced that it had placed the Plant on its "watch list" in "Category 2", which includes plants that display "weaknesses that warrant increased NRC attention", but which are not severe enough to warrant a shut-down order. Plants in category 2 remain in that category "until the licensee demonstrates a period of improved performance." The Plant is one of fourteen nuclear units on the watch list announced that day by the NRC, which regulates slightly over 100 civilian nuclear power plants in the United States. After year end, Maine Yankee and Entergy Nuclear, Inc. (Entergy), which is a subsidiary of Entergy Corporation, a Louisiana-based utility holding company and leading nuclear plant operator, entered into a contract under which Entergy is providing management services to Maine Yankee. At the same time, officials from Entergy assumed management positions, including President, at Maine Yankee. While the Plant remains out of service, Maine Yankee must, in addition to replacing the fuel assemblies and conducting an intensive inspection of its steam generators, resolve the cable-separation issues and other known regulatory issues, as well as any additional issues that are discovered during the outage. The Company must obtain the approval of the NRC to restart the Plant, following a mandated NRC process that includes A-7 an NRC-approved restart plan and opportunities for public participation. The Company believes the Plant will be out of service at least until August 1997, but cannot predict when or whether all of the regulatory and operational issues will be satisfactorily resolved or what effect the total of the repairs and improvements to the Plant will have on the economics of operating the Plant. The Company will incur significantly higher costs in 1997 for its share of inspection, repairs and refueling costs at Maine Yankee and will also need to purchase replacement power while the Plant is out of service. While the amount of higher costs is uncertain, Maine Yankee has indicated that it expects it operations and maintenance costs to increase by up to approximately $45 million in 1997, before refueling costs. The Company's share of such costs based on its power entitlement of approximately 38% would be up to approximately $17 million. In addition, the Company estimates its share of the refueling costs will amount to approximately $15 million, of which $10.4 million has been accrued as of December 31, 1996. The Company has been incurring incremental replacement-power costs of approximately $1 million per week while the plant has been out of service and expects such costs to continue at approximately the same rate until the plant returns to service. The impact of these higher nuclear related costs on the Company's 1997 financial results will be significant and is likely to trigger the low earnings bandwidth provision of the ARP. Under the ARP, actual earnings for 1997 outside a bandwidth of 350 basis points, above or below a 10.68% rate of return allowance, triggers the profit sharing mechanism. A return below the low end of the range provides for additional revenue through rates equal to one-half of the difference between the actual earned rate of return and the 7.18% (10.68-- 3.50) low end of the bandwidth. While the Company believes that the profit sharing mechanism is likely to be triggered in 1997, it cannot predict the amount, if any, of additional revenues that may ultimately result. OTHER NUCLEAR ISSUES On December 4, 1996, the Board of Directors of Connecticut Yankee Atomic Power Company voted to permanently shut down the Connecticut Yankee plant, for economic reasons, and to decommission the unit. The Company has a 6% equity interest in Connecticut Yankee, totaling approximately $6.4 million at December 31, 1996. The plant did not operate after July 22, 1996, causing the Company to incur replacement power costs of approximately $1.5 million in 1996. The Company estimates its share of the cost of Connecticut Yankee's continued compliance with regulatory requirements, recovery of its plant investments, decommissioning and closing the plant to be approximately $45.8 million and has recorded a regulatory asset and a liability on its consolidated balance sheet. The Company is currently recovering through rates an amount adequate to recover these expenses. The Company has a 2.5% ownership interest in Millstone Unit No. 3 which is operated by Northeast Utilities. This facility has been off-line since March 31, 1996 due to NRC concerns regarding license requirements and the Company cannot predict when it will return to service. Millstone Unit No. 3, along with two other units at the same site owned by Northeast Utilities, is on the NRC's "watch list" in "Category 3," which requires formal NRC action before a unit can be restarted. The Company estimates that it will incur approximately $300,000 to $500,000 in replacement power costs each month Millstone Unit No. 3 remains out of service. The Company incurred replacement power costs of $3.5 million in 1996. ENVIRONMENTAL ACTIONS The Company has been named by the Environmental Protection Agency (EPA) as a "potentially responsible party" (PRP) and has been incurring costs to determine the best method of cleaning up an Augusta, Maine, site formerly owned by a salvage company and identified by the EPA as containing soil contaminated by PCBs from equipment originally owned by the Company. The Company also has been named as a PRP at eleven former gas plant sites, six former waste oil sites, and two former pole treatment and storage locations. Refer to Note 4 to Consolidated Financial Statements, "Commitments and Contingencies--Legal and Environmental Matters," for a more detailed discussion of this matter. A-8 INDUSTRY RESTRUCTURING AND STRANDABLE COSTS The Federal Energy Policy Act of 1992 accelerated planning by electric utilities, including the Company, for a transition to a more competitive industry. The functional areas in which competition will take place, the regulatory changes that will be implemented, and the resulting structure of both the industry and the Company are all uncertain, but regulatory steps have already been taken toward competition in generation and non-discriminatory transmission access. A departure from traditional regulation and industry restructuring, however, could have substantial impacts on the value of utility assets and on electric utilities' abilities to recover their costs through rates. In the absence of full recovery, utilities would find their above- market costs to be "stranded," or unrecoverable, in the new competitive setting. In January, 1996, the Company filed its recommendations for an orderly transition to competition and adequate reimbursement of its potentially strandable costs with the MPUC. In December 1996, the MPUC issued its Report and Recommended Plan for Electric Utility Restructuring in Maine. The major elements of the MPUC plan, which are similar in most, but not all, respects to the Company's proposal include: (1) By January 2000, investor owned utilities would transfer all generating assets to entities distinct from transmission and distribution (T&D) assets and obligations. (2) By January 2006, the Company would be required to divest all generation assets (except Maine Yankee). (3) By January 2000, investor-owned utilities would be required to transfer the rights to market power from all qualifying facilities contracts. (4) Contracts between investor-owned utilities and qualifying facilities would remain with the T&D company. (5) Beginning January 1, 2000, all customers would have the option to purchase power directly from power suppliers or from intermediaries such as load aggregators, power marketers or energy service companies. (6) Standard-offer service would be provided to customers who do not choose a competitive power provider and who cannot obtain power in the market on reasonable terms. (7) The MPUC would not regulate companies that produce or sell power once customers can purchase power in a competitive market. (8) T&D companies would continue to be regulated. T&D companies would have exclusive service territories and an obligation to connect customers to the power grid. (9) A "reasonable opportunity" to recover strandable costs would be achieved through the regulated rates of the T&D utilities. Amounts recovered could include costs of fulfilling obligations under contracts with NUGs, as well as investments (and returns thereon) and other obligations undertaken by the Company in fulfilling its legal duty to serve, with requirements for the Company to mitigate such costs where practicable. (10) The MPUC recommended that the Legislature fund low-income assistance programs; otherwise, these programs would continue to be funded through T&D company rates. (11) All companies selling power to retail customers in Maine would be required to include a minimum amount of renewable energy in their generation mix, and customers would continue to fund cost-effective energy efficiency programs through T&D rates. The Company has substantial exposure to cost stranding relative to its size. In its January 1996 filing, the Company estimated its net-present-value strandable costs could be approximately $2 billion as of January 1, 1996. These costs represent the excess costs of purchased-power obligations and the Company's own generating costs over the market value of the power, and the costs of deferred charges and other regulatory assets. Of the $2 billion, approximately $1.3 billion is related to above-market costs of purchased-power obligations, approximately $200 million is related to estimated net above- market cost of the Company's own generation, and the remaining $500 million is related to deferred regulatory assets. A-9 The MPUC also provided estimates of strandable costs for the Company, which they found to be within a wide range of a negative $445 million to a positive $965 million. These estimates were prepared using assumptions that differ from those used by the Company, particularly a starting date for measurement of January 1, 2000 versus a measurement starting date of January 1, 1996 utilized by the Company. The MPUC concluded that there is a high degree of uncertainty that surrounds stranded costs numbers, resulting from having to rely on projections and assumptions about future conditions. Given the inherent uncertainty and volatility of these projections, the Company believes that an annual estimation of stranded costs could serve to prevent significant over-or- under-collection beginning in the year 2000. Estimated strandable costs are highly dependent on estimates of the future market for power. Higher market rates lower stranded cost exposure, while lower market rates increase it. In addition to market-related impacts, any estimate of the ultimate level of strandable costs depends on state and federal regulations; the extent, timing and form that competition for electric service will take; the ongoing level of the Company's costs of operations; regional and national economic conditions; growth of the Company's sales; timing of any changes that may occur from state and federal initiatives on restructuring; and the extent to which regulatory policies ultimately address recovery of strandable costs. The estimated market rate for power is based on anticipated regional market conditions and future costs of producing power. The present value of future purchased-power obligations and the Company's generating costs reflects the underlying costs of those sources of generation in place today, with reductions for contract expirations and continuing depreciation. Deferred regulatory asset totals include the current uncollected balances and existing amortization schedules for purchased-power contract restructuring and buyouts negotiated by the Company to lessen the impact of these obligations, energy management costs, financing costs, and other regulatory promises. The Company expects its strandable-cost exposure to decline over time as the market price of power increases, non-utility generator (NUG) contracts expire, and regulatory assets are recovered. Major cost stranding would have a material adverse effect on the Company's financial position. The Company believes it is entitled to recover substantially all of its potential strandable costs, but cannot predict when or if open electric energy competition will occur in its service territory, or how much it might ultimately be allowed to recover through state or federal regulation, the future market price of electricity, or the timing or implementation of any formal recommendations in any regulatory or legislative proceedings dealing with such issues. The Company believes there are many uncertainties associated with any major restructuring of the electric utility industry in Maine. Among them are: the positions that will ultimately be taken by the Maine Legislature and the MPUC; the role and policies of the FERC in any restructuring involving the Company, the extent and effect of Congressional involvement; whether political consensus is attained; and the extent to which the Company will be permitted to recover its strandable costs. The Company is pursuing efforts to mitigate its exposure to stranded costs. One method of mitigation that is being actively pursued is securitization of stranded costs including regulatory assets, above market NUG costs and above market company owned generation costs. Pursuant to a future legislative mandate and subject to determination by the MPUC, a portion of existing revenues related to stranded costs would be assigned by the Company for repayment of these costs. The property right created by this assignment could be used as security by a trust to sell bonds, the proceeds of which could be used by the Company to refinance existing obligations. Similarly a portion of existing revenues could also be dedicated directly to payment of above market non- utility power contract obligations, reducing the risks for the suppliers as well as for the Company. Mitigation from this mechanism would result from lower cost financing of stranded costs, enhanced credit worthiness of the utility, which should further reduce the Company's costs, and from increased availability of low cost funds to finance additional purchased power contract restructuring efforts. Any mitigation achieved would be passed on to residential and small commercial customers through lower rates. The Company cannot predict when or if legislative support for the use of securitization may occur. A-10 OPEN-ACCESS TRANSMISSION SERVICE RULING On April 24, 1996, the Federal Energy Regulatory Commission (FERC) issued Order No. 888, which requires all public utilities that own, control or operate facilities used for transmitting electric energy in interstate commerce to file open access non-discriminatory transmission tariffs that offer both load-based, network and contract-based, point-to-point service, including ancillary service to eligible customers containing minimum terms and conditions of non- discriminatory service. This service must be comparable to the service they provide themselves at the wholesale level; in fact, these utilities must take wholesale transmission service they provide themselves under the filed tariffs. The order also permits public utilities and transmitting utilities the opportunity to recover legitimate, prudent and verifiable wholesale stranded costs associated with providing open access and certain other transmission services. It further requires public utilities to functionally separate transmission from generation marketing functions and communications. The intent of this order is to promote the transition of the electric utility industry to open competition. Order No. 888 also clarifies federal and state jurisdiction over transmission in interstate commerce and local distribution and provides for deference of certain issues to state recommendations. On July 9, 1996, the Company and MEPCO submitted compliance filings to meet the new pro forma tariff non-price minimum terms and conditions of non- discriminatory transmission. Since July 9, 1996, the Company and MEPCO have been transmitting energy pursuant to their filed tariffs, subject to refund. FERC subsequently issued Order No. 888-A which generally reaffirms Order No. 888 and clarifies certain terms. Also on April 24, 1996, FERC issued Order No. 889 which requires public utilities to functionally separate their wholesale power marketing and transmission operation functions and to obtain information about their transmission system for their own wholesale power transactions in the same way their competitors do through the Open Access Same-time Information System (OASIS). The rule also prescribed standards of conduct and protocols for obtaining the information. The standards of conduct are designed to prevent employees of a public utility engaged in marketing functions from obtaining preferential information. The Company participated in efforts to develop a regional OASIS, which was operational January 3, 1997. FERC subsequently approved a New England Power Pool-wide Open Access Tariff, subject to refund and issuance of further orders. The Company also participated in revising the New England Power Pool Agreement, which is pending FERC approval. COMPETITION AND ECONOMIC DEVELOPMENT The Company faces competition in several aspects of its traditional business and anticipates that competition will continue to put pressure on both sales and the price the Company can charge for its product. Alternative fuels and recent modifications to regulations that had restricted competition from suppliers outside of the Company's service territory have expanded customers' energy options. As a result, the Company continues to pursue retention of its customer base. This increasingly competitive environment has resulted in the Company's entering into contracts with its wholesale customers, as well as with certain industrial, commercial, and residential customers, to provide their energy needs at prices and margins lower than the current averages. Pursuant to the pricing-flexibility provisions of the ARP, the Company redesigned some rates to encourage off-peak usage and discourage switching to alternative fuels. These include water-heat and space-heat retention rates, Super-Saver rates, which discount off-peak usage, Diesel Deferral rates, Economic Development rates, and the Maine Made Incentive program, which target small businesses. In 1994, the Company lowered tariffs for its large general- service customers and executed separate five-year definitive agreements with 18 individual customers providing additional reductions. Approximately 40% of annual service area kilowatt-hour sales and 27% of annual revenues are covered under special tariffs allowed under the pricing flexibility provisions of the ARP. These reductions in rates were offered to customers after consideration of associated NUG cost reductions, savings from further NUG consolidations and other general cost reductions. Refer to Note 4 to Consolidated Financial Statements, "Commitments and Contingencies--Competition," for additional information. A-11 NON-UTILITY GENERATORS In accordance with prior MPUC policy and the ARP, $113 million of buy-out or contract-restructuring costs incurred since January 1992 were included in Deferred Charges and Other Assets on the Company's balance sheet and will be amortized over their respective fuel savings periods. The Company restructured 40 contracts representing 316 megawatts of capacity that should result in approximately $301 million in fuel savings over the next five years. The Company also restructured a purchased power contract with a 20 megawatt waste-to-energy facility, which is estimated to save the Company approximately $20 million over the next five years. Refer to Note 6 to Consolidated Financial Statements, "Capacity Arrangements--Non-Utility Generators," for more information. On October 31, 1997, a contract with a major NUG from which the Company is obligated to purchase electricity at substantially above-market prices will expire. As a result, the Company expects annual operating income to increase by approximately $25 million. Two months of this benefit, or approximately $4 million, will be reflected in 1997 results. EXPANSION OF LINES OF BUSINESS The Company is also preparing for competition by expanding its business opportunities through subsidiaries that capitalize on core competencies. One such subsidiary, MaineCom Services, which was approved by the MPUC on July 13, 1995, is developing opportunities in expanding markets by arranging fiber-optic data service for bulk carriers, offering support for cable-TV or "super- cellular" personal-communication vendors, and providing other telecommunications consulting services. The Company invested $10.7 million in MaineCom during 1996 to develop an interchange network from Portland, Maine, to various points in New Hampshire, Massachusetts and Connecticut. In addition, the Company has subsidiaries or divisions that provide energy-efficiency services, utility consulting (domestic and international) and research, engineering and environmental services, management of rivers and recreational facilities, locating of underground utility facilities and infrared photography, real estate brokerage and management, modular housing, and credit and collections services. All subsidiaries utilize skills of former Company employees and compete for business with other companies. In July 1996, the Company and Maine Electric Power Company, Inc. (MEPCO), a 78%-owned subsidiary of the Company, entered into option agreements with Maritimes and Northeast Pipeline, L.L.C. (M&N) in which the Company and MEPCO agreed to provide exclusive options to M&N to acquire property interests in certain transmission line rights of way to sections of M&N's proposed natural gas pipeline from the United States--Canada border at Woodland, Maine, to Dracut, Massachusetts. In November 1996, while the parties were still engaged in negotiating the terms of the proposed long-term arrangement, the options expired by their terms. Subsequent to the expiration the parties have met to discuss a long-term arrangement for use of the Company's and MEPCO's rights of way for the proposed pipeline, but the Company cannot predict whether final agreement on such an arrangement will be reached. EXPENSES AND TAXES The Company's fuel expense, comprising the cost of fuel used for company generation and the energy portion of purchased power (the largest expense category), was 49% of total operating expense in 1996, 51% in 1995, and 54% in 1994. Purchased-power energy expense includes costs associated with purchases from NUGs, which amounted to 74% of this expense category in 1996. Fuel expense fluctuates with changes in the price of oil, the level of energy generated and purchased, and changes in the Company's own generation mix. Through December 31, 1994, changes in fuel expense were provided rate treatment through a fuel clause. Under the ARP, effective January 1, 1995, fuel-expense recovery is subject to the annual index-based price A-12 change. Fuel cost decreases are generally retained by the Company. Fuel expense for MEPCO was fully recoverable through billing to MEPCO participants. See Note 3 to Consolidated Financial Statements, "Regulatory Matters--Open Access Transmission Service Ruling," for a discussion on FERC Order No. 888 and its effect on MEPCO's operations. The extended outages and reduced operating level at Maine Yankee (see "Maine Yankee Regulatory Issues") resulted in significant increases in fuel expense, including purchased-power energy and purchased-power capacity expense, and affected the Company's generation mix in 1996 and 1995. The Company replaced this power through short-term agreements. Purchased power expense in 1996 reflected savings of approximately $5.4 million related to a paper company's extended forced outage of its cogeneration facility due to a flood. Additional savings of approximately $6 million were achieved through a five-year capacity exchange arrangement with Northeast Utilities designed to reduce replacement power cost when either Maine Yankee or Northeast Utilities facilities are off-line. Although this agreement was suspended in 1995, Northeast Utilities owed the Company energy, which they delivered in 1996. The Company benefited by purchasing this power at rates lower than market rates. See Note 4 to Consolidated Financial Statements, "Commitments and Contingencies--Competition," for more information on this matter. The Company's oil-fired generation decreased to 16.3% of the Company's net generation in 1996, compared to 21.6% in 1995 net generation, and 12.1% in 1994. The NUG component of the energy mix decreased from 36.8% in 1995, to 31.4% in 1996, as a result of the ongoing efforts to reform the Company's NUG contracts and an extended forced outage at one NUG facility. The average price of NUG energy of 8.3 cents per kilowatt-hour is significantly higher than the Company's own cost of generation, and much higher than the price of energy on today's open market. The Company continues to try to moderate the cost of non- utility generation by pursuing renegotiation of contracts, by supporting legislative bills that would promote that objective, and by other means such as strict contract-term enforcement. Purchased-power capacity expense is the non-fuel operation, maintenance, and cost-of-capital expense associated with power purchases, primarily from the Company's share of the Yankee nuclear generating facilities. In 1996, purchased-power capacity expense increased by $15.2 million. Maine Yankee capacity expense decreased by $12.2 million in 1996 , due mainly to the 1995 $10-million steam-generator tube repair costs. 1996 costs increased primarily as a result of an accrual for the 1997 refueling outage that accounted for a year over year increase of $13 million. In addition, expense increased by $9.4 million resulting from the restructuring of a contract with a non-utility generator. This agreement significantly decreased the cost of purchased-power fuel resulting in a net savings in total purchased power costs. The level of purchased-power capacity expense also fluctuates with the timing of the maintenance and refueling outages at the other Yankee nuclear generating facilities in which the Company has equity interests. The cost of capacity increases during refueling periods. In December 1996, the Board of Directors of Connecticut Yankee Atomic Power Company announced a permanent shutdown of the Connecticut Yankee plant for economic reasons and their intent to decommission the plant. The Company has a 6% equity interest in Connecticut Yankee, totaling approximately $6.4 million at December 31, 1996. Purchased power capacity expense in 1996, 1995 and 1994 includes $11.5 million, $11.5 million, and $10 million, respectively, of costs related to this facility. During 1992, Yankee Atomic Electric Company, in which the Company is a 9.5% equity owner, discontinued power generation and prepared a plan for decommissioning. Purchased-power capacity expense in 1996, 1995, and 1994 contained approximately $4.8 million, $3.9 million, and $5.2 million, respectively, of costs related to this facility. Refer to Note 6 to Consolidated Financial Statements, "Capacity Arrangements--Power Agreements," and "Other Nuclear Issues" above for a more detailed discussion. The 1996 reduction in other operation and maintenance expense is attributed to the reversal of a reserve of $6.4 million established in 1995 for the Company's workers compensation regulatory asset for which A-13 recovery was not certain. In the June 1996 ARP decision, the MPUC approved recovery of this regulatory asset. Also in 1996, the Company increased the workers compensation obligation and charged the increase of $1.6 million to expense. As a result, a net year-over-year reduction of $11.2 million for workers compensation was recorded. The Company did incur an increase in distribution expenses of $4.1 million, mainly due to line-clearance activities. The Company has contractual obligations related to demand-side energy- management programs which increased expense by $2.8 million in 1996. Maintenance expense other than distribution increased $3.5 million, of which $1.4 million was for repairs at the Millstone Unit No. 3 nuclear facility. The 1995 other operation-and-maintenance expense increase reflects significantly higher charges totaling approximately $27.7 million for amortization and cost of purchased-power contract buy-outs. Also reflected is a one-time charge of $5.6 million related to a Special Retirement Offer (SRO) to all employees aged 50 or more who had at least five years of continuous service. The goal of the SRO was to help the Company achieve financial savings and make the organizational changes it needed to be an effective competitor in the energy marketplace. Approximately 200 employees accepted the SRO. The Company continued its reengineering effort that began in 1995 to analyze the financial controls and customer service sectors of the business. Employee teams have begun implementing solutions that are expected to yield improvements in work processes and result in cost savings. The Company is also continuing cost containment measures. Interest expense decreased in 1996 by $1.4 million due to lower levels of Medium-Term Notes and the repurchase of $11.5 million of Series N General and Refunding Mortgage Bonds. Long-term debt interest expense includes $1 million of accelerated amortization of loss on reacquired debt, as specified in the 1996 ARP. In 1995, interest expense included a full year's interest costs on the Company's October 1994 note to the Finance Authority of Maine to finance the buy-out of a major NUG contract, and lower interest cost from a decrease in the amount of Medium-Term Notes outstanding. Short-term interest costs over the period 1994 through 1996 fluctuated with the levels of rates and outstanding balances of short-term debt. In July 1996, the Company redeemed $14 million of its 8 7/8% Series Preferred Stock at par, under the mandatory and optional sinking-fund provisions of that series. This reduced dividends by approximately $700,000 in 1996. The Company reduced the level of Flexible Money Market Preferred Stock outstanding in 1995 by $5.5 million in anticipation of the 1999 sinking-fund requirement, thereby reducing dividends in 1995 by $300,000. State and federal income taxes fluctuate with the level of pre-tax earnings and the regulatory treatment of taxes by the MPUC. A settlement with the Internal Revenue Service on audits for the years 1988-1991 provided a decrease to income tax expense of approximately $4.8 million in 1996. The significant increase in income-tax expense for 1995 is due to the impact of the loss from the write-off of deferred balances in accordance with the MPUC's ARP order in 1994. See Note 2 to Consolidated Financial Statements, "Income Taxes," for more information. LIQUIDITY AND CAPITAL RESOURCES The MPUC approved increases in electric retail rates of 1.26% and 2.43% in 1996 and 1995, respectively, that produced additional cash pursuant to the price cap mechanism in the ARP. Increases in rates under the ARP were based on increases in the related price index, the sharing mechanism and provisions for certain mandated costs. Prior rate increases were provided to fund costs of fuel, energy-management programs, operations, maintenance, systems improvements, and investments in generation needed to ensure the Company's continued ability to provide reliable electric service. Approximately $141.7 million of cash was provided from net income after adding back non-cash items. Approximately $16.2 million of cash was used for fluctuations in working capital. Other operating activities, A-14 including the financing of deferred energy-management programs and the buy-out of NUG contracts, required cash resources. The level of cash balances and activity in capital investment programs have required little investment-related activity during 1996 and 1995. The issuance and redemption of Medium-Term Notes and the purchase of 8 7/8% Series Preferred Stock used $24 million and $14 million, respectively, of cash during 1996. Dividends paid on common stock were $29.2 million, while preferred-stock dividends were $9.8 million. Capital-investment activities, primarily construction expenditures, utilized $57.1 million in cash during 1996. Construction expenditures comprised approximately $6.3 million for generating projects, $3.0 million for transmission, $27.9 million for distribution, and $9.7 million for general facilities and other construction expenditures. The Company invested $12.1 million in subsidiaries in 1996, of which $10.7 million was in MaineCom Services. The Company estimates its capital expenditures for the period 1997 through 2001 at approximately $302 million. Actual capital expenditures will depend upon the availability of capital and other resources, load forecasts, customer growth, and general business conditions. During the five-year period, the Company also anticipates incurring expenses of approximately $462 million for sinking funds, and debt and equity maturities. The Company estimates that for the period 1997 through 2001, internally generated funds from operating activities should provide a substantial portion of the construction-program requirements. However, the availability at any particular time of internally generated funds for such requirements will depend on working-capital needs, market conditions, and other relevant factors. Replacement power costs and increased operation, maintenance and refueling costs for Maine Yankee will have a significant negative effect on cash and liquidity in 1997. The Company has been incurring incremental replacement-power costs of approximately $1 million per week while the plant has been out of service and expects such costs to continue at approximately the same rate until the plant returns to service. Maine Yankee has indicated that it expects its operations and maintenance costs to increase by up to approximately $45 million, before refueling costs. The Company's share of such costs would be up to approximately $17 million. In addition, the Company estimates its share of the refueling costs will amount to approximately $15 million. Internally generated funds from operating activities will not be sufficient to meet these demands. The Company also plans to utilize its Medium-Term Note program and revolving credit facilities, as described below, for these cash requirements. The Company's $150-million Medium-Term Note program was implemented to provide flexibility to meet financing needs and provide access to a broad range of debt maturities. As of December 31, 1996, $68 million of Medium-Term Notes were outstanding which, under the terms of the program, permits issuance of an additional $82 million of such notes. The Company is planning to seek the consent of its preferred stockholders to increase the capacity of the Medium- Term Note program from $150 million to $500 million at its annual meeting of stockholders on May 15, 1997, in order to increase its financing flexibility in anticipation of restructuring and increased competition. The Company cannot predict whether such consent will be obtained. In 1996, the Company deposited approximately $29.6 million in cash with the Trustee under the Company's General and Refunding Mortgage Indenture in satisfaction of the renewal and replacement fund and other obligations under the Indenture. The total of such cash on deposit with the Trustee as of December 31, 1996, was approximately $59.5 million. Under the Indenture such cash may be applied at any time, at the direction of the Company, to the redemption of bonds outstanding under the Indenture at a price equal to the principal amount of the bonds being redeemed, without premium, plus accrued interest to the date fixed for redemption. Such cash may also be withdrawn by the Company by substitution of allocated property additions or available bonds. A-15 To support its short-term capital requirements, on October 23, 1996 , the Company entered into a $125 million revolving credit facility with several banks, with The First National Bank of Boston and The Bank of New York acting as agents for the lenders. The credit facility has two tranches: a $75 million, 364-day revolving credit facility that matures on October 22, 1997, and a $50-million, 3-year revolving credit facility that matures on October 23, 1999. Both credit facilities require annual fees on the unused portion of the credit lines. The fees are based on the Company's credit ratings and allow for various borrowing options including LIBOR-priced, base-rate-priced and competitive-bid-priced loans. Access to commercial paper markets has been substantially reduced, if not precluded, as a result of downgrading of the Company's credit ratings. The amount of outstanding short-term borrowing will fluctuate with day-to-day operational needs, the timing of long-term financing, and market conditions. There was $7.5 million outstanding as of December 31, 1996, under this agreement. FACTORS THAT MAY AFFECT FUTURE RESULTS This management's discussion and analysis section contains forecast information items that are "forward-looking statements" as defined in the Private Securities Litigation Reform Act of 1995. All such forward-looking information is necessarily only estimated. There can be no assurance that actual results will not materially differ from expectations. Actual results have varied materially and unpredictably from past expectations. Factors that could cause actual results to differ materially include, among other matters, electric utility restructuring, including the ongoing state and federal activities; future economic conditions; earnings-retention and dividend-payout policies; developments in the legislative, regulatory, and competitive environments in which the Company operates; and other circumstances that could affect anticipated revenues and costs, such as unscheduled maintenance or repair requirements and compliance with laws and regulations. Nuclear investments and obligations, which are subject to increased regulatory scrutiny, and the amount of expenditures and the timing of the return of the Maine Yankee generating plant to service, could have a material effect on the Company's financial position. A-16 FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
PAGE ---- Index to Financial Statements and Financial Statement Schedule Financial Statements: Management report on responsibility for financial reporting............. A-18 Report of Independent Accountants....................................... A-19 Consolidated Statement of Earnings for the three years ended December 31, 1996, 1995 and 1994................................................ A-20 Consolidated Balance Sheet as of December 31, 1996 and 1995............. A-21 Consolidated Statement of Cash Flows.................................... A-22 Consolidated Statement of Capitalization and Interim Financing.......... A-23 Consolidated Statement of Changes in Common-Stock Investment............ A-24 Notes to Consolidated Financial Statements.............................. A-25
A-17 REPORT OF MANAGEMENT The Management of Central Maine Power Company and its subsidiary is responsible for the consolidated financial statements and the related financial information appearing in this annual report. The financial statements are prepared in conformity with generally accepted accounting principles and include amounts based on informed estimates and judgments of management. The financial information included elsewhere in this report is consistent, where applicable, with the financial statements. The Company maintains a system of internal accounting controls that is designed to provide reasonable assurance that the Company's assets are safeguarded, transactions are executed in accordance with management's authorization, and the financial records are reliable for preparing the financial statements. While no system of internal accounting controls can prevent the occurrence of errors or irregularities with absolute assurance, management's objective is to maintain a system of internal accounting controls that meets its goals in a cost-effective manner. The Company has policies and procedures in place to support and document the internal accounting controls that are revised on a continuing basis. Internal auditors conduct reviews, provide ongoing assessments of the effectiveness of selective internal controls, and report their findings and recommendations for improvement to management. The Board of Directors has established an Audit Committee, composed entirely of outside directors, which oversees the Company's financial reporting process on behalf of the Board of Directors. The Audit Committee meets periodically with management, internal auditors, and the independent public accountants to review accounting, auditing, internal accounting controls, and financial reporting matters. The internal auditors and the independent public accountants have full and free access to meet with the Audit Committee, with or without management present, to discuss auditing or financial reporting matters. Coopers & Lybrand LLP, independent public accountants, has been retained to audit the Company's consolidated financial statements. The accompanying report of independent public accountants is based on their audit, conducted in accordance with generally accepted auditing standards, including a review of selected internal accounting controls and tests of accounting procedures and records. David T. Flanagan David E. Marsh President and Chief Executive Officer Vice President, Corporate Services, Treasurer and Chief Financial Officer A-18 REPORT OF INDEPENDENT ACCOUNTANTS To the Directors and Stockholders Central Maine Power Company We have audited the accompanying consolidated balance sheet and consolidated statement of capitalization and interim financing of Central Maine Power Company and subsidiary as of December 31, 1996 and 1995, and the related consolidated statements of earnings, changes in common stock investment, and cash flows for each of the three years in the period ended December 31, 1996. 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 consolidated financial position of Central Maine Power Company and subsidiary as of December 31, 1996 and 1995, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 1996 in conformity with generally accepted accounting principles. Portland, Maine January 23, 1997 A-19 CONSOLIDATED FINANCIAL STATEMENTS CONSOLIDATED STATEMENT OF EARNINGS
YEAR ENDED DECEMBER 31, ------------------------------------- 1996 1995 1994 ----------- ----------- ----------- (DOLLARS IN THOUSANDS, EXCEPT PER- SHARE AMOUNTS) Electric Operating Revenues (Notes 1 and 3)..................................... $ 967,046 $ 916,016 $ 904,883 ----------- ----------- ----------- Operating expenses Fuel used for company generation (Notes 1 and 6)............................... 16,827 18,702 14,783 Purchased power--energy (Notes 1 and 6). 407,926 408,072 430,874 Purchased power--capacity (Note 6)...... 108,720 93,489 77,775 Other operation......................... 182,910 188,013 153,700 Maintenance............................. 37,449 32,862 32,820 Depreciation and amortization (Note 1).. 53,694 55,023 55,992 Federal and state income taxes (Note 2). 30,125 13,328 28,300 Taxes other than income taxes........... 27,861 27,885 25,512 ----------- ----------- ----------- Total Operating Expenses................ 865,512 837,374 819,756 ----------- ----------- ----------- Equity in Earnings of Associated Compa- nies (Note 6).......................... 6,138 7,217 5,109 ----------- ----------- ----------- Operating Income........................ 107,672 85,859 90,236 ----------- ----------- ----------- Other income (expense) Allowance for equity funds used during construction (Note 1).................. 851 663 807 Other, net (Note 3)..................... 5,255 7,170 (105,133) Income taxes (Notes 2 and 3)............ (1,897) (2,704) 42,443 ----------- ----------- ----------- Total Other Income (Expense)............ 4,209 5,129 (61,883) ----------- ----------- ----------- Income Before Interest Charges.......... 111,881 90,988 28,353 ----------- ----------- ----------- Interest charges Long-term debt (Note 7)................. 47,966 50,307 46,213 Other interest (Note 7)................. 4,341 3,244 5,887 Allowance for borrowed funds used during construction (Note 1).................. (655) (543) (482) ----------- ----------- ----------- Total Interest Charges.................. 51,652 53,008 51,618 ----------- ----------- ----------- Net income (loss)....................... 60,229 37,980 (23,265) Dividends on preferred stock............ 9,452 10,178 10,511 ----------- ----------- ----------- Earnings (Loss) Applicable to Common Stock.................................. $ 50,777 $ 27,802 $ (33,776) =========== =========== =========== Weighted Average Number of Shares of Common Stock Outstanding............... 32,442,752 32,442,752 32,442,408 Earnings (Loss) Per Share of Common Stock.................................. $ 1.57 $ 0.86 $ (1.04) Dividends Declared Per Share of Common Stock.................................. $ 0.90 $ 0.90 $ 0.90
The accompanying notes are an integral part of these financial statements. A-20 CONSOLIDATED BALANCE SHEET
DECEMBER 31 ----------------------- 1996 1995 ----------- ----------- (DOLLARS IN THOUSANDS) ASSETS Electric property, at original cost (Notes 6 and 7)... $ 1,644,434 $ 1,611,941 Less: accumulated depreciation (Notes 1 and 6)........ 598,415 560,078 ----------- ----------- Electric property in service.......................... 1,046,019 1,051,863 ----------- ----------- Construction work in progress (Note 4)................ 20,007 15,928 Nuclear fuel, less accumulated amortization of $9,035 in 1996 and $8,909 in 1995........................... 1,157 1,391 ----------- ----------- Net electric property................................. 1,067,183 1,069,182 Investments in associated companies, at equity (Notes 1 and 6)............................................. 67,809 54,669 ----------- ----------- Net Electric Property and Investments in Associated Companies............................................ 1,134,992 1,123,851 ----------- ----------- CURRENT ASSETS Cash and cash equivalents............................. 8,307 57,677 Accounts receivable, less allowances for uncollectible accounts of $4,177 in 1996 and $3,313 in 1995: Service--billed..................................... 84,396 87,140 Service--unbilled (Notes 1 and 3)................... 45,721 41,798 Other accounts receivable........................... 17,517 15,131 Prepaid income taxes (Note 2)......................... 264 -- Fuel oil inventory, at average cost................... 9,256 3,772 Materials and supplies, at average cost............... 12,172 12,772 Funds on deposit with trustee (Note 7)................ 59,512 29,919 Prepayments and other current assets.................. 9,500 9,192 ----------- ----------- Total Current Assets.................................. 246,645 257,401 ----------- ----------- DEFERRED CHARGES AND OTHER ASSETS Recoverable costs of Seabrook 1 and abandoned pro- jects, net (Note 1).................................. 89,551 95,127 Yankee Atomic purchased-power contract (Note 6)....... 16,463 21,396 Connecticut Yankee purchased-power contract (Note 6).. 45,769 -- Regulatory assets--deferred taxes (Note 2)............ 239,291 235,081 Deferred charges and other assets (Notes 1 and 3)..... 238,203 260,063 ----------- ----------- Total Deferred Charges and Other Assets............... 629,277 611,667 ----------- ----------- Total Assets.......................................... $ 2,010,914 $ 1,992,919 ----------- ----------- STOCKHOLDERS' INVESTMENT AND LIABILITIES CAPITALIZATION (SEE SEPARATE STATEMENT) (NOTE 7) Common-stock investment............................... $ 511,578 $ 490,005 Preferred stock....................................... 65,571 65,571 Redeemable preferred stock............................ 53,528 67,528 Long-term obligations................................. 587,987 622,251 ----------- ----------- Total Capitalization.................................. 1,218,664 1,245,355 ----------- ----------- CURRENT LIABILITIES AND INTERIM FINANCING Interim financing (see separate statement) (Note 7)... 32,500 34,000 Sinking-fund requirements (Note 7).................... 9,375 10,455 Accounts payable...................................... 93,197 108,170 Dividends payable..................................... 9,512 9,823 Accrued interest...................................... 11,610 12,648 Accrued income taxes (Note 2)......................... -- 3,668 Miscellaneous current liabilities..................... 21,342 13,870 ----------- ----------- Total Current Liabilities and Interim Financing....... 177,536 192,634 ----------- ----------- COMMITMENTS AND CONTINGENCIES (NOTES 4 AND 6) RESERVES AND DEFERRED CREDITS Accumulated deferred income taxes (Note 2)............ 357,994 351,868 Unamortized investment tax credits (Note 2)........... 31,988 32,452 Yankee Atomic purchased-power contract (Note 6)....... 16,463 21,396 Connecticut Yankee purchased-power contract (Note 6).. 45,769 -- Regulatory liabilities--deferred taxes (Note 2)....... 52,616 50,366 Other reserves and deferred credits (Note 5).......... 109,884 98,848 ----------- ----------- Total Reserves and Deferred Credits................... 614,714 554,930 ----------- ----------- Total Stockholders' Investment and Liabilities........ $ 2,010,914 $ 1,992,919 =========== ===========
The accompanying notes are an integral part of these financial statements. A-21 CONSOLIDATED STATEMENT OF CASH FLOWS
YEAR ENDED DECEMBER 31 ---------------------------- 1996 1995 1994 -------- -------- -------- (DOLLARS IN THOUSANDS) Operating Activities Net income (loss)................................ $ 60,229 $ 37,980 $(23,265) Items not requiring (providing) cash: ARP-related charges (Note 3)..................... -- -- 100,390 Depreciation..................................... 44,104 43,676 42,627 Amortization..................................... 34,881 37,196 32,790 Deferred income taxes and investment tax credits, net............................................. 3,318 (3,710) 11,022 Allowance for equity funds used during construc- tion............................................ (851) (663) (807) Changes in certain assets and liabilities: Accounts receivable.............................. (3,565) (12,539) 5,175 Inventories...................................... (4,884) 595 4,230 Other current assets............................. (308) (1,954) (1,391) Retail fuel costs................................ -- -- 32,922 Accounts payable................................. (16,862) 12,025 4,062 Accrued taxes and interest....................... (4,970) 30,282 (25,311) Miscellaneous current liabilities................ 7,472 3,335 (2,602) Deferred energy-management costs................. (5,222) (4,075) (5,789) Maine Yankee outage accrual...................... 8,280 (4,710) 8,197 Purchased-power contract buyouts................. (75) (13,405) (91,274) Other, net....................................... 3,961 11,495 (5,604) -------- -------- -------- Net Cash Provided by Operating Activities........ 125,508 135,528 85,372 -------- -------- -------- Investing Activities Construction expenditures........................ (46,922) (44,867) (42,246) Investments in associated companies.............. (12,059) (600) (2,004) Changes in accounts payable--investing activi- ties............................................ 1,889 (1,655) (679) -------- -------- -------- Net Cash Used by Investing Activities............ (57,092) (47,122) (44,929) -------- -------- -------- Financing Activities Issuances: Mortgage bonds................................... -- -- 25,000 Common stock..................................... -- -- 927 Medium-term notes................................ 10,000 30,000 32,000 Other Long-Term Obligations...................... 870 -- -- Finance Authority of Maine....................... -- -- 66,429 Redemptions: Mortgage bonds................................... (11,500) -- -- Preferred stock.................................. (14,000) (5,472) -- Medium-term notes................................ (34,000) (65,000) (43,000) Finance Authority of Maine....................... (6,300) -- -- Short-term obligations, net...................... 7,500 (8,000) (25,500) Other long-term obligations...................... (1,780) (860) (860) Funds on Deposit with Trustee.................... (29,593) -- -- Dividends: Common stock..................................... (29,220) (29,222) (29,222) Preferred stock.................................. (9,763) (10,287) (10,061) -------- -------- -------- Net Cash Provided (Used) by Financing Activities. (117,786) (88,841) 15,713 -------- -------- -------- Net Increase (Decrease) in Cash and Cash Equiva- lents........................................... (49,370) (435) 56,156 Cash and cash equivalents, beginning of year..... 57,677 58,112 1,956 -------- -------- -------- Cash and Cash Equivalents, end of year........... $ 8,307 $ 57,677 $ 58,112 ======== ======== ======== Supplemental Cash-Flow Information: Cash paid during the year for: Interest (net of amounts capitalized)............ $ 47,835 $ 51,127 $ 44,874 Income taxes (net of amounts refunded of $0, $29,045 and $2,802 in respective years indicated)...................................... $ 32,632 $(11,994) $ 1,568
For purposes of the statement of cash flows, the Company considers all highly liquid instruments purchased having a maturity of three months or less to be cash equivalents. The accompanying notes are an integral part of these financial statements. A-22 CONSOLIDATED STATEMENT OF CAPITALIZATION AND INTERIM FINANCING
DECEMBER 31 ---------------------------------- 1996 1995 ---------------- ---------------- AMOUNT % AMOUNT % ---------- ----- ---------- ----- (DOLLARS IN THOUSANDS) Capitalization (Note 7) Common-stock investment: Common stock, par value $5 per share: Authorized--80,000,000 shares Outstanding--32,442,752 shares in 1996 and 1995...................................... $ 162,214 $ 162,214 Other paid-in capital...................... 276,818 276,287 Retained earnings.......................... 72,546 51,504 ---------- ---------- Total Common-Stock Investment.............. 511,578 40.9% 490,005 38.3% ---------- ----- ---------- ----- Preferred Stock--not subject to mandatory redemption................................ 65,571 5.2 65,571 5.1 ---------- ----- ---------- ----- Preferred Stock--subject to mandatory re- demption.................................. 60,528 74,528 Less: current sinking fund requirements.... 7,000 7,000 ---------- ---------- Redeemable Preferred Stock--subject to mandatory redemption...................... 53,528 4.3 67,528 5.3 ---------- ----- ---------- ----- Long-term obligations: Mortgage bonds............................. 421,000 432,500 Less: unamortized debt discount............ 1,620 1,807 ---------- ---------- Total Mortgage Bonds....................... 419,380 430,693 ---------- ---------- Medium-term notes.......................... 68,000 92,000 Less: unamortized debt discount............ -- 8 ---------- ---------- Total Medium-Term Notes.................... 68,000 91,992 ---------- ---------- Other long-term obligations: Lease obligations.......................... 36,283 38,112 Pollution-control facility and other notes. 91,699 98,909 ---------- ---------- Total Other Long-Term Obligations.......... 127,982 137,021 ---------- ---------- Less: Current Sinking Fund Requirements and Current Maturities........................ 27,375 37,455 ---------- ---------- Total Long-Term Obligations................ 587,987 47.0 622,251 48.6 ---------- ----- ---------- ----- Total Capitalization....................... 1,218,664 97.4 1,245,355 97.3 ---------- ----- ---------- ----- Interim financing (Note 7): Short-term obligations..................... 7,500 -- Current maturities of long-term obliga- tions..................................... 25,000 34,000 ---------- ---------- Total Interim Financing.................... 32,500 2.6 34,000 2.7 ---------- ----- ---------- ----- Total Capitalization and Interim Financing. $1,251,164 100.0% $1,279,355 100.0% ========== ===== ========== =====
The accompanying notes are an integral part of these financial statements. A-23 CONSOLIDATED STATEMENT OF CHANGES IN COMMON-STOCK INVESTMENT FOR THE THREE YEARS ENDED DECEMBER 31, 1996
AMOUNT OTHER AT PAR PAID-IN RETAINED SHARES VALUE CAPITAL EARNINGS TOTAL ---------- -------- -------- -------- -------- (DOLLARS IN THOUSANDS) Balance--December 31, 1993... 32,379,937 $161,900 $274,343 $117,146 $553,389 ---------- -------- -------- -------- -------- Net loss..................... (23,265) (23,265) Dividends declared: Common stock............... (29,213) (29,213) Preferred stock............ (10,511) (10,511) Cost for reacquired preferred stock....................... 675 (675) Issues of common stock....... 62,815 314 613 927 Capital stock expense........ (4) (4) ---------- -------- -------- -------- -------- Balance--December 31, 1994... 32,442,752 162,214 275,627 53,482 491,323 ---------- -------- -------- -------- -------- Net income................... 37,980 37,980 Dividends declared: Common stock............... (29,199) (29,199) Preferred stock............ (10,178) (10,178) Cost for reacquired preferred stock....................... 581 (581) Shareholders Rights Plan re- demption.................... (324) (324) Capital stock expense........ 403 403 ---------- -------- -------- -------- -------- Balance--December 31, 1995... 32,442,752 162,214 276,287 51,504 490,005 ---------- -------- -------- -------- -------- Net income................... 60,229 60,229 Dividends declared: Common stock............... (29,199) (29,199) Preferred stock............ (9,452) (9,452) Cost for reacquired preferred stock....................... 536 (536) Capital stock expense........ (5) (5) ---------- -------- -------- -------- -------- Balance--December 31, 1996... 32,442,752 $162,214 $276,818 $ 72,546 $511,578 ========== ======== ======== ======== ========
The accompanying notes are an integral part of these financial statements. A-24 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS NOTE 1: SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES General Description Central Maine Power Company (the Company) is an investor-owned public utility primarily engaged in the sale of electric energy at the wholesale and retail levels to residential, commercial, industrial, and other classes of customers in the State of Maine. Financial Statements The consolidated financial statements include the accounts of the Company and its 78%-owned subsidiary, Maine Electric Power Company, Inc. (MEPCO). The Company accounts for its investments in associated companies not subject to consolidation using the equity method. The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Regulation The rates, operations, accounting, and certain other practices of the Company and MEPCO are subject to the regulatory authority of the Maine Public Utilities Commission (MPUC) and the Federal Energy Regulatory Commission (FERC). Electric Operating Revenues Electric operating revenues include amounts billed to customers and estimates of unbilled sales and fuel costs. Through December 31, 1994, the Company's approved tariffs provided for the recovery of the cost of fuel used in Company generating facilities and purchased-power energy costs. The Company also collected interest on unbilled fuel and paid interest on fuel-related over- collections. Effective January 1, 1995, with the implementation of the Alternative Rate Plan (ARP), these costs are no longer subject to reconciliation through the annual fuel-cost adjustment. See Note 3, "Regulatory Matters--Alternative Rate Plan," for further information. Depreciation Depreciation of electric property is calculated using the straight-line method. The weighted average composite rate was 3.0% in each of 1996, 1995 and 1994. Allowance for Funds Used During Construction (AFC) An allowance for funds (including equity funds), a non-operating item, is capitalized as an element of the cost of construction. The debt component of AFC is classified as a reduction of interest expense, while the equity component, a non-cash item, is classified as other income. The average AFC rates applied to construction were 8.7% in 1996, 8.4% in 1995, and 8.9% in 1994. Asset Valuation The Company adopted Statement of Financial Accounting Standards No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of," effective January 1, 1996. The standard requires impairment losses on long-lived assets to be recognized when an asset's book value exceeds its expected future cash flows (undiscounted and without interest). The new standard also imposes stricter criteria for retention of regulatory-created assets by requiring that such assets be probable of future A-25 recovery at each balance sheet date. The Company's adoption of this standard in 1996 had no impact on accompanying financial statements. However, this may change in the future as changes are made in the current regulatory framework or as competitive factors influence wholesale and retail pricing in the electric utility industry. Deferred Charges and Other Assets The Company defers and amortizes certain costs in a manner consistent with authorized or probable ratemaking treatment. The Company capitalizes carrying costs as a part of certain deferred charges, principally energy-management costs, and classifies such carrying costs as other income. The following table depicts the components of deferred charges and other assets at December 31, 1996, and 1995:
1996 1995 ----------- ----------- (DOLLARS IN THOUSANDS) NUG contract buy-outs and restructuring (Note 6).... $ 113,796 $ 126,485 Energy-management costs............................. 35,986 36,224 Postretirement benefits (Note 5).................... 22,962 21,849 Financing costs..................................... 20,684 24,775 Environmental site clean-up costs (Note 4).......... 7,876 7,375 Non-operating property, net......................... 7,176 7,486 Electric Lifeline Program........................... 2,368 3,603 Other, including MEPCO.............................. 27,355 32,266 ----------- ----------- Total........................................... $ 238,203 $ 260,063 =========== ===========
Certain costs are being amortized and recovered in rates over periods ranging from three to 30 years. Amortization expense for the next five years is shown below:
AMOUNT ---------------------- (DOLLARS IN THOUSANDS) 1997............................................... $26,790 1998............................................... 26,053 1999............................................... 23,910 2000............................................... 22,807 2001............................................... 19,304
Recoverable Costs of Seabrook I and Abandoned Projects The recoverable after-tax investments in Seabrook I and abandoned projects are reported as assets, pursuant to May 1985 and February 1991 MPUC rate orders. The Company is allowed a current return on these assets based on its authorized rate of return. In accordance with these rate orders, the deferred taxes related to these recoverable costs are amortized over periods of four to 10 years. As of December 31, 1996, substantially all deferred taxes related to Seabrook I have been amortized. The recoverable investments as of December 31, 1996, and 1995 are as follows:
DECEMBER 31 ----------------------- RECOVERY 1996 1995 PERIODS ENDING ----------- ----------- -------------- (DOLLARS IN THOUSANDS) Recoverable costs of: Seabrook I................ $ 141,084 $ 141,084 2015 Other Projects............ 57,491 57,491 2001 ----------- ----------- 198,575 198,575 ----------- ----------- Less: accumulated amortiza- tion....................... 108,209 102,248 Less: related income taxes.. 815 1,200 ----------- ----------- Total Net Recoverable Investment............. $ 89,551 $ 95,127 =========== ===========
A-26 NOTE 2: INCOME TAXES The components of federal and state income-tax provisions (benefits) reflected in the Consolidated Statement of Earnings are as follow:
YEAR ENDED DECEMBER 31 -------------------------- 1996 1995 1994 ------- ------- -------- (DOLLARS IN THOUSANDS) Federal: Current....................................... $21,682 $15,965 $(18,579) Deferred...................................... 5,751 2,278 2,175 Investment tax credits, net................... (464) (1,715) (2,512) Regulatory deferred........................... (623) (2,619) 8,379 ------- ------- -------- Total Federal Taxes......................... 26,346 13,909 (10,537) ------- ------- -------- State: Current....................................... $ 7,022 $ 3,777 $ (6,586) Deferred...................................... (10) 343 3,003 Regulatory deferred........................... (1,336) (1,997) (23) ------- ------- -------- Total State Taxes........................... 5,676 2,123 (3,606) ------- ------- -------- Total Federal and State Income Taxes........ $32,022 $16,032 $(14,143) ======= ======= ======== Federal and state income taxes charged to: Operating expenses............................ $30,125 $13,328 $ 28,300 Other income.................................. 1,897 2,704 (42,443) ------- ------- -------- $32,022 $16,032 $(14,143) ======= ======= ========
A-27 Federal income tax, excluding federal regulatory deferred taxes, differs from the amount of tax computed by multiplying income before federal tax by the statutory federal rate. The following table reconciles the statutory federal rate to a rate determined by dividing the total federal income-tax expense by income before that expense:
YEAR ENDED DECEMBER 31 -------------------------------------------- 1996 1995 1994 ------------- ------------- -------------- AMOUNT % AMOUNT % AMOUNT % ------- ---- ------- ---- -------- ---- (DOLLARS IN THOUSANDS) Income tax expense at statutory federal rate.................... $30,301 35.0% $18,161 35.0% $(11,831) 35.0% ------- ---- ------- ---- -------- ---- Permanent differences: Investment tax-credit amortiza- tion............................ (1,482) (1.7) (1,613) (3.1) (1,613) 4.8 Dividend-received deduction...... (1,895) (2.2) (2,219) (4.3) (1,469) 4.3 Other, net....................... (293) (0.3) (217) (0.4) (68) 0.2 ------- ---- ------- ---- -------- ---- 26,631 30.8 14,112 27.2 (14,981) 44.3 ======= ==== ======= ==== ======== ==== Effect of timing differences for items which receive flow through treatment: Tax-basis repairs................ (1,229) (1.4) (891) (1.7) (924) 2.7 Depreciation differences flowed through in prior years.......... 2,327 2.7 2,291 4.4 2,315 (6.8) Accelerated flowback of deferred taxes on loss on abandoned generating projects............. 1,708 1.9 1,873 3.6 2,051 (6.1) Deduction of removal costs....... (202) (0.2) (189) (0.4) (163) 0.5 Carrying costs, net.............. 186 0.2 253 0.5 429 (1.3) Adjustment to tax accrual for change in rate treatment........ 300 0.3 -- -- 420 (1.2) Excess property taxes paid....... -- -- -- -- (116) 0.4 IRS audit resolution regarding depreciation methods............ (3,230) (3.7) -- -- -- -- Provision for deferred taxes relating to normalization of certain short-term timing differences*.................... -- -- (2,545) (4.9) -- -- Other, net....................... (145) (0.2) (995) (1.9) 432 (1.3) ------- ---- ------- ---- -------- ---- Federal Income Tax Expense and Effective Rate.................. $26,346 30.4% $13,909 26.8% $(10,537) 31.2% ======= ==== ======= ==== ======== ====
- - -------- * During 1995, the Company adjusted the deferred tax balances for certain normalized items (Note 3). The Company and MEPCO record deferred income-tax expense in accordance with regulatory authority; they also defer investment and energy tax credits and amortize them over the estimated lives of the assets that generated the credits. The Company recognizes deferred tax liabilities and assets for the expected future tax consequences of events that have been included in the financial statements or tax returns as required under Statement of Financial Accounting Standards No. 109, "Accounting for Income Taxes" (SFAS No. 109). Under this method, effective January 1, 1993, deferred tax liabilities and assets are determined based on the difference between the financial statement and tax basis of assets and liabilities using the enacted tax rates in effect in the year in which the differences are expected to reverse. At-adoption adjustments to accumulated deferred taxes were required, as well as the recognition of a liability to ratepayers for deferred taxes established in excess of the amount calculated using income-tax rates applicable to future periods. Additionally, deferred taxes were recorded for the cumulative timing differences for which no deferred taxes had been recorded previously. Concurrently, the Company, in accordance with Statement of Financial Accounting Standards No. 71, "Accounting for the Effects of Certain Types of Regulation" (SFAS No. 71), recorded a regulatory asset representing its expectations that, consistent with current and expected ratemaking, it will collect these additional taxes recorded through rates when they are paid in the future. A-28 A valuation allowance has not been recorded at December 31, 1996, and 1995, as the Company expects that all deferred income tax assets will be realized in the future. Accumulated deferred income taxes consisted of the following in 1996 and 1995:
1996 1995 ----------- ----------- (DOLLARS IN THOUSANDS) Deferred tax assets resulting from: Investment tax credits, net............................ $ 22,050 $ 22,370 Regulatory liabilities................................. 17,919 13,882 Alternative minimum tax................................ 10,241 23,850 All other.............................................. 26,588 22,545 ----------- ----------- 76,798 82,647 ----------- ----------- Deferred tax liabilities resulting from: Property............................................... 288,370 273,565 Abandoned plant........................................ 61,729 65,573 Regulatory assets...................................... 85,508 96,577 ----------- ----------- 435,607 435,715 ----------- ----------- Accumulated deferred income taxes, end of year, net.... $ 358,809 $ 353,068 =========== =========== Accumulated deferred income taxes, recorded as: Accumulated deferred income taxes...................... $ 357,994 $ 351,868 Recoverable costs of Seabrook 1 and abandoned projects, net................................................... 815 1,200 ----------- ----------- $ 358,809 $ 353,068 =========== ===========
NOTE 3: REGULATORY MATTERS ALTERNATIVE RATE PLAN In December 1994, the MPUC approved a stipulation signed by most of the parties to the Company's ARP proceeding. This follow-up proceeding to the Company's 1993 base-rate case was ordered by the MPUC in an effort to develop a five-year plan containing price-cap, profit-sharing, and pricing-flexibility components. Although the ARP is a major reform, the MPUC is continuing to regulate the Company's operations and prices, provide for continued recovery of deferred costs, and specify a range for its authorized rate of return. The ARP was adopted effective January 1, 1995. The Company believes the ARP provides the benefits of needed pricing flexibility to set prices between defined floor and ceiling levels in three service categories: (1) existing customer classes, (2) new customer classes for optional targeted services, and (3) special-rate contracts. The Company believes that the added flexibility will position it more favorably to meet the competition from other energy sources. See Note 4 to Consolidated Financial Statements, "Commitments and Contingencies--Competition," for a discussion of actions taken by the Company under the ARP's pricing flexibility provisions. The ARP also contains provisions to protect the Company and ratepayers against unforeseen adverse results from its operation. These include review by the MPUC if the Company's actual return on equity falls outside a designated range, a mid-period review of the ARP by the MPUC in 1997 (including possible modification or termination), and a "final" review by the MPUC in 1999 to determine whether or with what changes the ARP should continue in effect after 1999. The Company will submit its 1997 compliance filing and the mid-period review filing in March 1997. The mid-period review decision is expected from the MPUC by September 30, 1997. The Company believes, as stated in the MPUC's order approving the ARP, that operation under the ARP continues to meet the criteria of SFAS No. 71. In its order, the MPUC reaffirmed the applicability of A-29 previous accounting orders allowing the Company to reflect amounts as deferred charges and regulatory assets. As a result, the Company will continue to apply the provisions of SFAS No. 71 to its accounting transactions and its future financial statements. The ARP contains a mechanism that provides price caps on the Company's retail rates to increase annually on July 1, commencing July 1, 1995, by a percentage combining (1) a price index, (2) a productivity offset, (3) a sharing mechanism, and (4) flow-through items and mandated costs. The price cap applies to all of the Company's retail rates, including the Company's fuel-and- purchased power cost, which previously had been treated separately. Under the ARP, fuel expense is no longer subject to reconciliation or specific rate recovery, but is subject to the annual indexed price-cap changes. A specified standard inflation index is the basis for each annual price-cap change. The inflation index is reduced by the sum of two productivity factors, a general productivity offset of 1.0%, (0.5% for 1995), and a second formula- based offset that started in 1996 intended to reflect the limited effect of inflation on the Company's purchased-power costs during the proposed five-year initial term of the ARP. The sharing mechanism will adjust the subsequent year's July price-cap change in the event the Company's earnings are outside a range of 350 basis points above or below the Company's allowed return on equity, starting at the 10.55% allowed return (1995) and indexed annually for changes in capital costs. Outside that range, profits and losses would be shared equally by the Company and ratepayers in computing the price-cap adjustment. This feature commenced with the price-cap change of July 1, 1996, and reflected 1995 results. The ARP also provides for partial flow-through to ratepayers of cost savings from non-utility generator contract buy-outs and restructuring, recovery of energy-management costs, penalties for failure to attain customer-service and energy-efficiency targets, and specific recovery of half the costs of the transition to Statement of Financial Accounting Standards No. 106, "Accounting for Postretirement Benefits Other Than Pensions" (SFAS No. 106), the remaining 50% to be recovered through the annual price-cap change. The ARP also generally defines mandated costs that would be recoverable by the Company notwithstanding the index-based price cap. To receive such treatment, a mandated cost's revenue requirement must exceed $3 million and have a disproportionate effect on the Company or the electric-power industry. Effective July 1, 1995, the MPUC approved a 2.43% increase pursuant to the annual price-change provision in the ARP. The primary component of the increase was the inflation-index change of 2.92%, reduced by a productivity offset of 0.5%, and increased by .01% for flowthrough items and mandated costs. On June 28, 1996, the MPUC approved a 1.26% increase in rates under the ARP effective July 1, 1996. The components of the increase included the inflation-index of 2.55% and earnings sharing and mandated cost items of 0.64%, reduced by the productivity offset of 1.0% and sharing of contract restructuring and buyout savings of 0.93%. The Company agreed in the ARP negotiations to record charges in 1994 reflecting the write-off of approximately $100 million ($60 million, net of tax, or $1.85 per share) which consisted of undercollected balance of fuel and purchased power costs, unrecovered energy-management costs, unrecovered unbilled ERAM revenues and unrecovered deferred charges related to the possible extension of the operating life of one of the Company's generating stations. The $100-million charge was included in "Other income (expense)--Other, net" on the Consolidated Statement of Earnings. The $40-million tax impact was included in "Other income (expense)--Income taxes." These charges, with the other provisions of the ARP, lessen the impact of future price increases for MPUC- mandated and fuel-related costs. RESTRUCTURING The Maine Legislature in 1995 took action by Legislative Resolve (Resolve) to develop recommendations for the MPUC on the future structure of the electric utility industry in Maine. The Resolve stated that the A-30 findings of the MPUC would have no legal effect, but that the MPUC's study would ". . . provide information to the Legislature in order to allow the Legislature to make informed decisions when it evaluates those plans." In accordance with the Resolve, on December 31, 1996, the MPUC, pursuant to the mandate of the Maine Legislature, filed its Report and Recommended Plan for Utility Industry Restructuring (Restructuring Report). The Company believes there are many uncertainties associated with any major restructuring of the electric utility industry in Maine. Among them are: the actions that will be ultimately taken by the legislature and the MPUC; the role of the FERC in any restructuring involving the Company and the ultimate positions it will take on relevant issues within its jurisdiction; to what extent the United States Congress will become involved in resolving or redefining the issues through legislative action and, if so, with what results; whether the necessary political consensus can be reached on the significant and complex issues involved in changing the long-standing structure of the electric-utility industry; and, particularly with respect to the Company, to what extent utilities will be permitted to recover strandable costs. The Company has substantial exposure to cost stranding relative to its size. The Company estimated its net-present-value strandable costs could be approximately $2 billion a of January 1, 1996. These costs represent the excess costs of purchased-power obligations and the Company's own generating costs over the market value of the power, and the costs of deferred charges and other regulatory assets. Of the $2 billion, approximately $1.3 billion is related to above-market costs of purchased-power obligations, approximately $200 million is related to estimated net above-market cost of the Company's own generation, and the remaining $500 million is related to deferred regulatory assets. MEETING THE REQUIREMENTS OF SFAS NO. 71 The Company continues to meet the requirements of SFAS No. 71, as described above. The standard provides specialized accounting for regulated enterprises, which requires recognition of assets and liabilities that enterprises in general could not record. Examples of regulatory assets include deferred income taxes associated with previously flowed through items, NUG buyout costs, losses on abandoned plants, deferral of postemployment benefit costs, and losses on debt refinancing. If an entity no longer meets the requirements of SFAS No. 71, then regulatory assets and liabilities must be written off. The ARP provides incentive-based rates intended to recover the cost of service plus a rate of return on the Company's investment together with a sharing of the costs or earnings between ratepayers and the shareholders should the earnings be less than or exceed a target rate of return. The Company has received recognition from the MPUC that the rates implemented as a result of the ARP continue to provide specific recovery of costs deferred in prior periods. The MPUC's Restructuring Report submitted to the Legislature in December 1996 recognizes that a reasonable opportunity to recover strandable costs is essential to a successful transition to competition, with incentives for the Company to mitigate such costs where practicable. The Company is actively pursuing securitization of regulatory assets, which would provide further assurance of their recoverability. OPEN-ACCESS TRANSMISSION SERVICE RULING On April 24, 1996, FERC issued Order No. 888, which requires all public utilities that own, control or operate facilities used for transmitting electric energy in interstate commerce to file open access non-discriminatory transmission tariffs that offer both load-based, network and contract-based, point-to-point service, including ancillary service to eligible customers containing minimum terms and conditions of non-discriminatory service. This service must be comparable to the service they provide themselves at the wholesale level; in fact, these utilities must take wholesale transmission service they provide themselves under the filed tariffs. The order also permits public utilities and transmitting utilities the opportunity to recover A-31 legitimate, prudent and verifiable wholesale stranded costs associated with providing open access and certain transmission services. It further requires public utilities to functionally separate transmission from generation marketing functions and communications. The intent of this order is to promote the transition of the electric utility industry to open competition. Order No. 888 also clarifies federal and state jurisdiction over transmission in interstate commerce and local distribution and provides for deference of certain issues to state recommendations. On July 9, 1996, the Company and MEPCO submitted its compliance filings to meet the new pro forma tariff non-price minimum terms and conditions of non- discriminatory transmission. Since July 9, 1996, the Company and MEPCO have been transmitting energy pursuant to their filed tariffs, subject to refund. FERC subsequently issued Order No. 888-A, which reaffirms Order No. 888 and clarifies certain terms. Also on April 24, 1996, FERC issued Order No. 889 which requires public utilities to functionally separate their wholesale power marketing and transmission operation functions and to obtain information about their transmission system for their own wholesale power transactions in the same way their competitors do through the Open Access Same-time Information System (OASIS). The rule also prescribed standards of conduct and protocols for obtaining the information. The standards of conduct are designed to prevent employees of a public utility engaged in marketing functions from obtaining preferential information. The Company participated in efforts to develop a regional OASIS, which was operational January 3, 1997. FERC subsequently approved a New England Power Pool-wide Open Access Tariff, subject to refund and issuance of further orders. The Company also participated in revising the New England Power Pool Agreement, which is pending FERC approval. NOTE 4: COMMITMENTS AND CONTINGENCIES Construction Program The Company's plans for improving and expanding generating, transmission, distribution facilities, and power-supply sources are under continuing review. Actual construction expenditures will depend upon the availability of capital and other resources, load forecasts, customer growth, and general business conditions. The Company's current forecast of capital expenditures for the five-year period 1997 through 2001, are as follows:
1997 1998-2001 TOTAL ------ ---------- ------- (DOLLARS IN MILLIONS) Type of Facilities: Generating projects................................. $ 8 $ 33 $ 41 Transmission........................................ 3 14 17 Distribution........................................ 27 124 151 General facilities and other........................ 18 75 93 ------ ------- ------- Total Estimated Capital Expenditures................ $ 56 $ 246 $ 302 ====== ======= =======
COMPETITION In September 1994, the Town of Madison's Department of Electric Works (Madison), a wholesale customer of the Company, began receiving power from Northeast Utilities (NU) as a result of a competitive bidding process available under the federal Energy Policy Act of 1992. Substantially all of the 45 megawatts involved supply the large paper-making facility of Madison Paper Industries (MPI) in Madison's service territory that had been served directly by the Company under a special service agreement with Madison during the preceding 12 years. The MPUC approved the stipulation filed by the Company, Madison, and NU, whereby the related MPUC and FERC regulatory proceedings were deemed to be settled among the parties, and the Company A-32 withdrew its request for compensation for stranded costs. In return, NU agreed to pay the Company $8.4 million over a seven-year period, MPI agreed to pay the Company $1.4 million over a three-year period, a transmission rate was agreed upon for the Company's transmission service to Madison commencing September 1, 1994, and the parties agreed that Madison would be supplied by NU through 2003, with Madison having an option for an additional five years. In addition, NU and the Company agreed to a five-year capacity exchange arrangement designed to achieve significant replacement-power cost savings for the Company when the Company's largest source of generation, the Maine Yankee Plant, is off-line, and provides Maine Yankee power to NU when certain NU facilities are shut down. The agreement provides more economic benefit to the Company than if it had under-bid NU for Madison's business, but less than if Madison stayed on the Company's system at the former rates. The Company records income under this contract as the amounts are received. Madison was the largest of the Company's three wholesale customers. The Company later reached agreement with its other two wholesale customers to continue to supply them at negotiated prices and margins that are lower than the previous averages. Subsequent to year end, these customers initiated a request for proposals to supply their energy needs after 1998. During 1994, the Company engaged in discussions with its large general- service customers. Those customers have alternative energy options that the Company believed needed to be addressed by lowering its applicable tariffs. In response to those discussions, in November 1994, the Company filed revised tariff schedules lowering prices 15% for its two high-voltage transmission- level rate classes. The Company then entered into five-year definitive agreements with 18 of these customers that lock-in non-cumulative rate reductions of 15% for the three years 1995 through 1997, 16% for 1998, and 18% for 1999, below the December 1, 1994, levels. These contracts also protect these customers from price increases that might otherwise be allowed under the ARP. The participating customers agreed to take electrical service from the Company for five years and not to switch fuels, install new self-generation equipment, or seek another supplier of electricity for existing electrical load during that period. New electrical load in excess of a stated minimum level could be served by other sources, but the Company could compete for that load. The Company believes that without offering the competitive pricing provided in the agreements, a number of these customers would be likely to install additional self-generation or take other steps to decrease their electricity purchases from the Company. The revenue loss from such a usage shift could have been substantial. The Company estimates that based on the rate reductions effective January 1, 1995, its gross revenues were approximately $27 million lower in 1995, and approximately $45 million lower in 1996, than would have been the case if these customers continued to pay full retail rates without reducing their purchases from the Company. However, these rate reductions were negotiated giving consideration to important related cost savings. Electricity price changes affect the cost of some NUG power contracts. The reduction in rates to large customers reduced purchased-power costs by approximately $20 million as a result of linkage between retail tariffs and some contract prices. LEGAL AND ENVIRONMENTAL MATTERS The Company is a party in legal and administrative proceedings that arise in the normal course of business. In connection with one such proceeding, the Company has been named a potentially responsible party (PRP) and has been incurring costs to determine the best method of cleaning up an Augusta, Maine, site formerly owned by a salvage company and identified by the Environmental Protection Agency (EPA) as containing soil contaminated by polychlorinated biphenyls (PCBs) from equipment originally owned by the Company. A-33 In 1995, the EPA approved a remedy to adjust the soil cleanup standard to 10 parts per million. The cleanup method using solvent extraction was found to be technically infeasable. On July 30, 1996, the EPA approved the off-site disposal of the contaminated soil to a EPA licensed secure landfill. The Company believes that its share of the remaining costs of the cleanup under the approved remedy could total approximately $2.7 million to $4.2 million. This estimate is net of an agreed partial insurance recovery and the 1993 court-ordered contribution of 41% from Westinghouse Electric Corp., but does not reflect any possible contributions from other insurance carriers the Company has sued, or from any other parties. The Company has recorded an estimated liability of $2.7 million and an equal regulatory asset, reflecting an accounting order to defer such costs and the anticipated ratemaking recovery of such costs when ultimately paid. In addition, the Company has deferred, as a regulatory asset, $5.1 million of costs incurred through December 31, 1996. The Company cannot predict with certainty the level and timing of the cleanup costs, the extent they will be covered by insurance, or their ratemaking treatment, but believes it should recover substantially all of such costs through insurance and rates. OTHER ENVIRONMENTAL SITES The Company has been named as a PRP at eleven former gas manufactured plant sites, six former waste oil sites, and two former pole treatment and storage locations. The Company believes that its share of the investigation and cleanup and other costs associated with these sites could total approximately $0.9 million which was charged to income in 1996. The Company believes that the ultimate resolution of current legal and environmental proceedings will not have a material adverse effect on its financial condition. NUCLEAR INSURANCE The Price-Anderson Act (Act) is a federal statute providing, among other things, a limit on the maximum liability for damages resulting from a nuclear incident. The liability is provided for by existing private insurance and by retrospective assessments for costs in excess of that covered by insurance, up to $79.3 million for each reactor owned, with a maximum assessment of $10 million per reactor in any year. Based on the Company's indirect ownership in four nuclear-generation facilities (See Note 6, "Capacity Arrangements--Power Agreements") and its 2.5% ownership interest in the Millstone Unit No. 3 nuclear plant, the Company's retrospective premium could be as high as $6 million in any year, for a cumulative total of $47.6 million, exclusive of the effect of inflation indexing and a 5% surcharge in the event that total public liability claims from a nuclear incident should exceed the funds available to pay such claims. In addition to the insurance required by the Act, the nuclear generating facilities referenced above carry additional nuclear property-damage insurance. This additional insurance is provided from commercial sources and from the nuclear electric-utility industry's insurance company through a combination of current premiums and retrospective premium adjustments. Based on current premiums and the Company's indirect and direct ownership in nuclear generating facilities, this adjustment could range up to approximately $7.7 million annually. NOTE 5: PENSION AND OTHER POST-EMPLOYMENT BENEFITS Pension Benefits The Company has two separate non-contributory, defined-benefit plans that cover substantially all of its union and non-union employees. The Company's funding policy is to contribute amounts to the separate plans that are sufficient to meet the funding requirements set forth in the Employee Retirement Income Security Act (ERISA), plus such additional amounts as the Company may determine to be appropriate. Plan benefits under the non-union retirement plan are based on average final earnings, as defined within the plan, and A-34 length of employee service; benefits under the union plan are based on average career earnings and length of employee service. During 1995, the Company offered a Special Retirement Offer (SRO) to qualifying employees. Approximately 200 employees accepted the offer. The $7- million cost of the SRO was included in pension expense. As part of the SRO, the plans were amended to add five years to age and five years to credited service for all plan participants for purposes of eligibility and early retirement discounts. Early Retirement Incentive Program (ERIP) expenses for 1994 relate to a 1991 ERIP reflected in accordance with an MPUC accounting order. A summary of the components of net periodic pension cost for the non-union and union defined-benefit plans in 1996, 1995 and 1994 follows:
1996 1995 1994 -------------- --------------- -------------- NON- NON- NON- UNION UNION UNION UNION UNION UNION ------ ------ ------- ------ ------ ------ (DOLLARS IN THOUSANDS) Service cost--benefits earned during the period............ $2,334 $1,780 $ 2,014 $1,414 $2,367 $1,684 Interest cost on projected benefit obligation........... 5,225 3,852 5,653 3,889 5,469 3,816 Return on plan assets......... (8,168) (5,036) (16,135) (9,786) 2,336 1,397 Net amortization and deferral. 2,911 1,536 10,030 6,028 (8,174) (5,311) Early Retirement Incentive Programs..................... -- -- 3,859 3,141 992 1,457 ------ ------ ------- ------ ------ ------ Net Periodic Pension Cost..... $2,302 $2,132 $ 5,421 $4,686 $2,990 $3,043 ====== ====== ======= ====== ====== ======
Assumptions used in accounting for the non-union and union defined-benefit plans in 1996, 1995, and 1994 are as follows:
1996 1995 1994 ---- ---- ---- Weighted average discount rate................................ 7.50% 7.25% 8.25% Rate of increase in future compensation levels................ 4.5% 4.5% 5.0% Expected long-term return on assets........................... 8.5% 8.5% 8.5%
The following table sets forth the actuarial present value of pension-benefit obligations, the funded status of the plans, and the liabilities recognized on the Company's balance sheet at December 31, 1996, and 1995:
1996 1995 ---------------- ---------------- NON- NON- UNION UNION UNION UNION ------- ------- ------- ------- (DOLLARS IN THOUSANDS) Actuarial present value of benefit obliga- tions: Vested benefit obligation................. $62,461 $47,617 $64,916 $47,948 ------- ------- ------- ------- Accumulated benefit obligation............ 64,394 48,783 $64,916 $47,948 ------- ------- ------- ------- Projected benefit obligation.............. 75,570 55,688 $77,939 $53,735 Plan assets at estimated market value (primarily stocks, bonds, and guaranteed annuity contracts)....................... 77,996 48,091 73,973 45,061 ------- ------- ------- ------- Funded status--projected benefit obliga- tion in excess of or (less than) plan as- sets..................................... (2,426) 7,597 3,966 8,674 Unrecognized prior service cost........... (1,785) (1,481) (1,940) (1,610) Unrecognized net gain..................... 19,819 3,745 11,309 2,530 Unrecognized (net obligation) net asset... (163) 1,675 (192) 1,945 ------- ------- ------- ------- Net Pension Liability Recognized in the Balance Sheet............................ $15,445 $11,536 $13,143 $11,539 ======= ======= ======= =======
A-35 SAVINGS PLAN The Company offers an employee savings plan to all employees which allows participants to invest from 2% to 15% of their salaries among several alternatives. An employer contribution equal to 60% of the first 5% of the employees' contributions is initially invested in Company common stock. The Company's contributions to the savings-plan trust were $1.7 million in 1996, $1.6 million in 1995, and $1.8 million in 1994. OTHER POST-EMPLOYMENT BENEFITS In addition to pension and savings-plan benefits, the Company provides certain health-care and life-insurance benefits for substantially all of its retired employees. The MPUC approved a rulemaking on SFAS No. 106, effective July 20, 1993, that adopted the accrual method of accounting for the expected cost of such benefits during the employees' years of service, and authorized the establishment of a regulatory asset for the deferral of such costs until they are "phased-in" for ratemaking purposes. The effect of the change can be reflected in annual expenses over the active service life of employees or a period of 20 years, rather than in the year of adoption. The MPUC prescribes the maximum amortization period of the average remaining service life of active employees or 20 years, whichever is longer, for the transition obligation. The Company is utilizing a 20 year amortization period. Segregation in an external fund is required for amounts collected in rates. The Company is proposing initial funding of $3 million annually. Until amounts are funded, no return on assets will be reflected in postretirement benefit cost. As a result of the MPUC order, the Company records the cost of these benefits by charging expense in the period recovered through rates ($9.8 million in 1996, $6.7 million in 1995, and $5.5 million in 1994), with the excess over that amount of $1.1 million in 1996, $6.2 million in 1995 and $7.1 million in 1994, deferred for future recovery. The total amount defined as a regulatory asset as of December 31, 1996 was $23 million. Concurrent with the initial ARP price change, the Company began to phase in the cost of SFAS No. 106 over a three-year period, $3 million for the first year beginning July 1, 1995 and an additional $2.1 million for the year beginning July 1, 1996. The amounts deferred until that point are being amortized over the same period as the transition obligation. A summary of the components of net periodic postretirement benefit cost for the plan in 1996, 1995 and 1994 follows:
1996 1995 1994 ------- ------- ------- (DOLLARS IN THOUSANDS) Service cost........................................ $ 1,347 $ 846 $ 1,472 Interest on accumulated postretirement benefit obligation......................................... 5,720 7,389 6,712 Special retirement offer............................ -- 200 -- Amortization of transition obligation............... 4,080 4,606 4,606 Amortization of prior service cost.................. 35 42 -- Amortization of gain................................ (329) (188) (171) ------- ------- ------- Postretirement benefits expense..................... 10,853 12,895 12,619 Deferred postretirement benefits expense............ 1,056 6,204 7,108 ------- ------- ------- Postretirement Benefit Expense Recognized in the Statement of Earnings.............................. $ 9,797 $ 6,691 $ 5,511 ======= ======= =======
A-36 The following table sets forth the accumulated postretirement benefit obligation, the funded status of the plan, and the liability recognized on the Company's balance at December 31, 1996 and 1995:
1996 1995 ----------- ----------- (DOLLARS IN THOUSANDS) Accumulated postretirement benefit obligation: Retirees............................................. $ 51,815 $ 87,632 Fully eligible active plan participants.............. 2,707 4,791 Other active plan participants....................... 19,381 15,069 ----------- ----------- Total accumulated postretirement benefit obligation.. 73,903 107,492 Plan assets, at fair value........................... 849 879 ----------- ----------- Accumulated postretirement benefits obligation in ex- cess of plan assets................................. 73,054 106,613 Unrecognized net gain (loss)......................... 15,987 (2,511) Unrecognized prior service cost...................... (5) (1,131) Unrecognized transition obligation................... (59,267) (78,303) ----------- ----------- Accrued Postretirement Benefit Cost Recognized in the Balance Sheet....................................... $ 29,769 $ 24,668 =========== ===========
The assumed health-care cost-trend rates range from 5.7% to 6.8% for 1996, reducing to 5.0% overall over a period of 25 years. Rates range from 6.4% to 9.3% for 1995, reducing to 5.0% overall, over a period of 10 years. Rates range from 6.8% to 10.4% for 1994, reducing to 5.0% overall, over a period of 10 years. The effect of a one-percentage-point increase in the assumed health-care cost-trend rate for each future year would increase the aggregate of the service and interest-cost components of the net periodic postretirement benefit cost by $0.7 million and the accumulated postretirement benefit obligation by $8.9 million. Additional assumptions used in accounting for the postretirement benefit plan in 1996, 1995 and 1994 are as follows:
1996 1995 1994 ---- ---- ---- Weighted-average discount rate................................ 7.50% 7.25% 8.25% Rate of increase in future compensation levels................ 4.50% 4.50% 5.0%
The Company is exploring alternatives for mitigating the cost of postretirement benefits and for funding its obligations. These alternatives include mechanisms to fund the obligation prior to actual payment of benefits, plan-design changes to limit future expense increases, and additional cost- control and cost-sharing programs. Effective September 1, 1996, the Company implemented a phase-out of the long- term care portion of its retiree medical plans. With the exception of one group of approximately 200 retirees, all benefits of this type will be eliminated by September 1, 2002. These changes decreased Plan liabilities by approximately $16 million, based on 1996 actuarial valuation results. NOTE 6: CAPACITY ARRANGEMENTS Power Agreements The Company, through certain equity interests, owns a portion of the generating capacity and energy production of four nuclear generating facilities (the Yankee companies), two of which have been permanently shut down, and is obligated to pay its proportionate share of costs, which include fuel, depreciation, operation-and-maintenance expenses, a return on invested capital, and the estimated cost of decommissioning the nuclear plants. A-37 Pertinent data related to these power agreements as of December 31, 1996, are as follows:
MAINE YANKEE VERMONT YANKEE CONNECTICUT YANKEE* YANKEE ATOMIC* ------------ -------------- ------------------- -------------- (DOLLARS IN THOUSANDS) Ownership share......... 38% 4% 6% 9.5% Contract expiration date................... 2008 2012 1998 2000 Capacity (MW)........... 879 531 -- -- Company's share of: Capacity (MW).......... 329 19 -- -- Estimated 1996 costs.... $ 79,282 $ 6,525 $12,355 $ 4,896 Long-term obligations and redeemable preferred stock........ $ 94,559 $ 6,950 $10,447 $ -- Estimated decommissioning obligation............. $118,586 $13,150 $45,769 $16,463 Accumulated decommissioning fund... $ 61,254 $ 5,474 $12,269 $11,408
- - -------- * See following for discussion on Connecticut Yankee and Yankee Atomic. Under the terms of its agreements, the Company pays its ownership share (or entitlement share) of estimated decommissioning expense to each of the Yankee companies and records such payments as a cost of purchased power. Effective August 16, 1988, Maine Yankee Atomic Power Company (Maine Yankee) began collecting $9.1 million annually for decommissioning. In 1994, Maine Yankee, pursuant to FERC authorization, increased its annual collection to $14.9 million and reduced its return on common equity to 10.65%, for a total increase in rates of approximately $3.4 million. The increase in decommissioning collection is based on the estimated cost of decommissioning the Maine Yankee Plant, assuming dismantling and removal, of $317 million (in 1993 dollars) based on a 1993 external engineering study. Accumulated decommissioning funds were $163.5 million as of December 31, 1996. The estimated cost of decommissioning nuclear plants is subject to change due to the evolving technology of decommissioning and the possibility of new legal requirements. The Maine Yankee Plant, like other pressurized water reactors, experienced degradation of its steam generator tubes, principally in the form of circumferential cracking, which, until early 1995, was believed to be limited to a relatively small number of tubes. During a refueling and maintenance shutdown in February 1995, Maine Yankee detected through new inspection methods that approximately 60% of the Plant's 17,000 steam generator tubes appeared to have defects. Following a detailed analysis of safety, technical and financial considerations, Maine Yankee repaired the tubes by inserting and welding short reinforcing sleeves of an improved material in substantially all of the Plant's steam generator tubes, which was completed in December 1995. The Company's approximately $10-million share of the repair costs adversely affected the Company's 1995 earnings by $0.18 per share, net of taxes, in spite of significant cost-reduction measures implemented by both the Company and Maine Yankee. In addition, the Company's incremental replacement-power costs during the outage totaled approximately $29 million, or $0.52 per share, net of taxes, for 1995. Also in December 1995, the Nuclear Regulatory Commission's (NRC) Office of the Inspector General (OIG) and its Office of Investigations (OI) initiated separate investigations of certain anonymous "whistleblower" allegations of wrongdoing by Maine Yankee and Yankee Atomic Electric Company (Yankee Atomic) in 1988 and 1989 in connection with operating license amendments. On May 9, 1996, the OIG, which was responsible for investigating only the actions of the NRC staff and not those of Maine Yankee or Yankee Atomic, issued its report on its investigation. The report found deficiencies in the NRC staff's review, documentation, and communications practices in connection with the license amendments, as well as "significant indications of possible licensee violations of NRC requirements and regulations." Any such violations by Maine Yankee are within the purview of the OI investigation, which, with related issues, is being reviewed by the United States Department of Justice. A separate internal investigation commissioned by the boards of directors of Maine Yankee and Yankee Atomic and conducted by an independent law firm A-38 noted several areas that could have been improved, including regulatory communications, definition of responsibilities between Maine Yankee and Yankee Atomic, and documentation and tracking of regulatory compliance, but found no wrongdoing by Maine Yankee or Yankee Atomic or any of their employees. Issues raised as a result of the anonymous allegations caused the NRC to limit the Plant to an operating level of approximately 90% of its full thermal capacity, pending resolution of those issues. The Company cannot predict the results of the investigations by the OI and Department of Justice. On January 11, 1996, Maine Yankee began start-up operations and was up to a 90% generation level on January 24, 1996. The Plant operated substantially at that level until July 20, 1996, when it was taken off-line after a comprehensive review by Maine Yankee of the Plant's systems and equipment revealed a need to add pressure-relief capacity to the Plant's primary component cooling system. On August 18, 1996, while the Plant was in the restart process, Maine Yankee conducted a review of its electrical circuitry testing procedures pursuant to a generic NRC letter to nuclear-plant licensees that was intended to ensure that every feature of every safety system be routinely tested. During the expanded review, Maine Yankee found a deficiency in an electrical circuit of a safety system and therefore elected to conduct an intensified review of other safety-related circuits to resolve immediately any questions as to the adequacy of related testing procedures. The Plant returned to the 90% operating level on September 3, 1996. On December 6, 1996, Maine Yankee took the Plant off-line to resolve cable- separation and associated issues. On January 3, 1997, Maine Yankee announced that it would use the opportunity presented by that outage to inspect the Plant's 217 fuel assemblies, since daily monitoring had indicated evidence of a small number of defective fuel rods. As a result of the inspection, Maine Yankee determined that all of the assemblies manufactured by one supplier and currently in the reactor core (approximately one-third of the total) have to be replaced. Maine Yankee will therefore keep the Plant off-line for refueling, which had previously been scheduled for late 1997. In addition, Maine Yankee will make use of the outage to inspect the Plant's steam generators for deterioration beyond that which was repaired during the extended 1995 outage. Degradation of steam generators of the age and design of those in use in the Plant has been identified at other plants. In January 1997, the NRC announced that it had placed the Plant on its "watch list" in "Category 2", which includes plants that display "weaknesses that warrant increased NRC attention", but which are not severe enough to warrant a shut-down order. Plants in category 2 remain in that category "until the licensee demonstrates a period of improved performance." The Plant is one of fourteen nuclear units on the watch list announced that day by the NRC, which regulates slightly over 100 civilian nuclear power plants in the United States. After year end, Maine Yankee and Entergy Nuclear, Inc. (Entergy), which is a subsidiary of Entergy Corporation, a Louisiana-based utility holding company and leading nuclear plant operator, entered into a contract under which Entergy is providing management services to Maine Yankee at the same time, officials from Entergy assumed management positions, including President, at Maine Yankee. The Maine Yankee nuclear plant was shut down on December 6, 1996, for inspection and repairs. While the plant is out of service, Maine Yankee must, in addition to replacing the fuel assemblies, conduct an intensive inspection of its steam generators, resolve cable-separation issues and other regulatory issues, and obtain the approval of the NRC to restart the plant. The Company believes the plant will be out of service at least until August 1997, but cannot predict when or whether all of the regulatory and operational issues will be satisfactorily resolved or what effect the repairs and improvements to the plant will have on the economics of operating the plant. The Company will incur significantly higher costs in 1997 for its share of inspection, repairs and refueling costs at Maine Yankee and will also need to purchase replacement power while the plant is out of service. While the amount of higher costs is uncertain, Maine Yankee has indicated that it expects it operations and maintenance costs to increase by up to approximately $45 million in 1997, before refueling costs. The A-39 Company's share of such costs based on its power entitlement of approximately 38% would be up to approximately $17 million. In addition, the Company estimates its share of the refueling costs will amount to approximately $15 million, of which $10.4 million has been accrued as of December 31, 1996. The Company has been incurring incremental replacement-power costs of approximately $1 million per week while the plant has been out of service and expects such costs to continue at approximately the same rate until the plant returns to service. The impact of these higher nuclear related costs on the Company's 1997 financial results will be significant and is likely to trigger the low earnings bandwidth provision of the ARP. Under the ARP actual earnings for 1997 outside a bandwidth of 350 basis points, above or below a 10.68% rate of return allowance, triggers the profit sharing mechanism. A return below the low end of the range provides for additional revenue through rates equal to one-half of the difference between the actual earned rate of return and the 7.18% (10.68-- 3.50) low end of the bandwidth. While the Company believes that the profit sharing mechanism is likely to be triggered in 1997, it cannot predict the amount, if any, of additional revenues that may ultimately result. Condensed financial information on Maine Yankee Atomic Power Company is as follows:
1996 1995 1994 -------- -------- -------- (DOLLARS IN THOUSANDS) Earnings: Operating revenues.................................. $185,661 $205,977 $173,857 Operating income.................................... 17,150 18,527 16,223 Net income.......................................... 8,106 8,571 8,573 Earnings applicable to common stock................. 6,637 7,057 7,014 -------- -------- -------- Company's Equity Share of Net Earnings.............. $ 2,522 $ 2,682 $ 2,665 -------- -------- -------- Investment: Net electric property and nuclear fuel.............. $222,360 $242,399 $254,820 Current assets...................................... 44,979 34,799 38,950 Deferred charges and other assets................... 334,722 303,760 256,140 -------- -------- -------- Total Assets........................................ 602,061 580,958 549,910 -------- -------- -------- Less: Redeemable preferred stock.......................... 18,000 18,600 19,200 Long-term obligations............................... 223,572 224,185 226,491 Current liabilities................................. 34,265 30,904 29,210 Reserves and deferred credits....................... 255,472 236,653 208,100 -------- -------- -------- Net Assets.......................................... $ 70,752 $ 70,616 $ 66,909 -------- -------- -------- Company's Equity in Net Assets...................... $ 26,886 $ 26,834 $ 25,425 ======== ======== ========
In December 1996, the Board of Directors of Connecticut Yankee Atomic Power Company announced a permanent shutdown of the Connecticut Yankee plant in Haddam, Connecticut, and decided to decommission the plant for economic reasons. An economic analysis conducted by Connecticut Yankee estimates that the early closing of the Plant would save over $100 million (net present value) over its remaining license life to the year 2007, compared with the costs of continued operation. The Company has a 6% equity interest in Connecticut Yankee, totaling approximately $6.4 million at December 31, 1996. The plant did not operate after July 22, 1996. The Company estimates its share of the cost of Connecticut Yankee's continued compliance with regulatory requirements, recovery of its plant investments, decommissioning and closing the plant to be approximately $45.8 million and has recorded a regulatory asset and a liability on the consolidated balance sheet. The Company is currently recovering through rates an amount adequate to recover these expenses. A-40 On February 26, 1992, the Board of Directors of Yankee Atomic Electric Company (Yankee Atomic) decided to permanently discontinue power operation at the Yankee Atomic Plant in Rowe, Massachusetts, and to decommission that facility. The Company relied on Yankee Atomic for less than 1% of the Company's system capacity. Its 9.5% equity investment in Yankee Atomic is approximately $2.2 million. On March 18, 1993, the FERC approved a settlement agreement regarding the Yankee Atomic decommissioning plan, recovery of plant investment, and all issues with respect to prudence of the decision to discontinue operation. The Company has estimated its remaining share of the cost of Yankee Atomic's continued compliance with regulatory requirements, recovery of its plant investments, decommissioning and closing the plant, to be approximately $16.5 million. This estimate, which is subject to ongoing review and revision, has been recorded by the Company as a regulatory asset and a liability on the accompanying consolidated balance sheet. As part of the MPUC's decision in the Company's 1993 base-rate case, the Company's current share of costs related to the deactivation of Yankee Atomic is being recovered through rates. The Company has approximately a 60% ownership interest in the jointly owned, Company-operated, 620-megawatt oil-fired W. F. Wyman Unit No. 4. The Company also has a 2.5% ownership interest in the Millstone Unit No. 3 nuclear plant operated by Northeast Utilities, and is entitled to approximately 29-megawatt share of that unit's capacity. The Company's share of the operating costs of these units is included in the appropriate expense categories in the Consolidated Statement of Earnings. The Company's plant in service, nuclear fuel, decommissioning fund, and related accumulated depreciation and amortization attributable to these units as of December 31, 1996, and 1995 were as follows:
WYMAN 4 MILLSTONE 3 ----------------- ----------------- 1996 1995 1996 1995 -------- -------- -------- -------- (DOLLARS IN THOUSANDS) Plant in service, nuclear fuel and decommissioning fund...................... $116,372 $116,447 $112,040 $112,033 Accumulated depreciation and amortization.. 63,023 59,832 39,181 36,411
Millstone Unit No. 3 has been out of service since April, 1996, due to NRC concerns regarding operating license requirements and the Company cannot predict when it will return to service. The Company estimates that it will incur approximately $300,000 to $500,000 in replacement power costs each month Millstone Unit No. 3 remains out of service. The Company incurred replacement power costs of $3.5 million in 1996. POWER-POOL AGREEMENTS The New England Power Pool, of which the Company is a member, has contracted in its Hydro-Quebec Projects to purchase power from Hydro-Quebec. The contracts entitle the Company to 85.9 megawatts of capacity credit in the winter and 127.25 megawatts of capacity credit during the summer. The Company has entered into facilities-support agreements for its share of the related transmission facilities. The Company's share of the support responsibility and of associated benefits is approximately 7%. The Company is making facilities-support payments on approximately $28.8 million, its remaining share of the construction cost for these transmission facilities incurred through December 31, 1996. These obligations are reflected on the Company's consolidated balance sheet as lease obligations with a corresponding charge to electric property. NON-UTILITY GENERATORS The Company has entered into a number of long-term, non-cancelable contracts for the purchase of capacity and energy from non-utility generators (NUG). The agreements generally have terms of five to 30 years, with expiration dates ranging from 1997 to 2021. They require the Company to purchase the energy at specified prices per kilowatt-hour, which are often above market prices. As of December 31, 1996, facilities A-41 having 573 megawatts of capacity covered by these contracts were in-service. The costs of purchases under all of these contracts amounted to $313.4 million in 1996, $314.4 million in 1995, and $373.5 million in 1994. During 1996, the Company reached agreement with three NUGs to buy out contracts or to give the Company options to restructure their contracts through lump-sum or periodic payments. In accordance with prior MPUC policy and the ARP, at December 31, 1996, $113 million of buy-out or restructuring costs incurred since January 1992 were included in Deferred Charges and Other Assets on the Company's balance sheet and are amortized over their respective fuel savings periods. The Company's estimated contractual obligations with NUGs as of December 31, 1996, are as follows:
AMOUNT --------------------- (DOLLARS IN MILLIONS) 1997...................................................... $ 331 1998...................................................... 291 1999...................................................... 295 2000...................................................... 294 2001...................................................... 268 2002--2015................................................ 2,369 ------ $3,848 ======
On October 31, 1997, a contract with a major non-utility generator from which the Company is obligated to purchase electricity at substantially above-market prices expires. The Company expects annual operating expenses to decrease by approximately $25 million dollars. Two months of this benefit, or approximately $4 million, will be reflected in 1997 results. In early 1996, the Company entered into a restructuring agreement with Maine Energy Recovery Company (MERC), a 20 megawatt waste to energy facility located in Biddeford, Maine. The agreement provides for a significant reduction in energy rates for energy sold to the Company and extended the previous power contract five years. In addition, the Company will make capacity payments to CL Power Sales One. NOTE 7: CAPITALIZATION AND INTERIM FINANCING Retained Earnings Under terms of the most restrictive test in the Company's General and Refunding Mortgage Indenture and the Company's Articles of Incorporation, no dividend may be paid on the common stock of the Company if such dividend would reduce retained earnings below $29.6 million. At December 31, 1996, the Company's retained earnings were $72.5 million, of which $42.9 million were not so restricted. MORTGAGE BONDS Substantially all of the Company's electric-utility property and franchises are subject to the lien of the General and Refunding Mortgage. The Company's outstanding Mortgage Bonds may be redeemed at established prices plus accrued interest to the date of redemption, subject to certain refunding limitations. Bonds may also be redeemed under certain conditions at their principal amount plus accrued interest by means of cash deposited with the trustee under certain provisions of the mortgage indenture. In 1996, the Company deposited approximately $29.6 million in cash with the Trustee under the Company's General and Refunding Mortgage Indenture in satisfaction of the renewal and replacement fund and other obligations under the Indenture. The total of such cash on deposit with the Trustee as of December 31, 1996, was approximately $59.5 million. Under the Indenture such cash may be applied at any time, at the direction of the Company, to the redemption of bonds outstanding under the Indenture at a price equal to the principal amount of the bonds being redeemed, A-42 without premium, plus accrued interest to the date fixed for redemption. Such cash may also be withdrawn by the Company by substitution of allocated property additions or available bonds. Mortgage Bonds outstanding as of December 31, 1996, and 1995 were as follows:
SERIES REDEEMED/MATURITY INTEREST RATE 1996 1995 ------ ----------------- ------------- -------- -------- (DOLLARS IN THOUSANDS) Central Maine Power Company General and Refunding Mortgage Bonds: U........................... 1998-April 15 7.54% $ 25,000 $ 25,000 S........................... 1998-August 15 6.03 60,000 60,000 T........................... 1998-November 1 6.25 75,000 75,000 O........................... 1999-January 1 7 3/8 50,000 50,000 P........................... 2000-January 15 7.66 75,000 75,000 N........................... 2001-September 15 8.50 11,000 22,500 Q........................... 2008-March 1 7.05 75,000 75,000 R........................... 2023-June 1 7 7/8 50,000 50,000 -------- -------- Total Mortgage Bonds........ $421,000 $432,500 ======== ========
LIMITATIONS ON UNSECURED INDEBTEDNESS The Company's Articles of Incorporation limit certain unsecured indebtedness that may be outstanding to 20% of capitalization, as defined; 20% of defined capitalization amounted to $219 million as of December 31, 1996. Unsecured indebtedness, as defined, amounted to $96 million as of December 31, 1996. In May 1989, holders of the Company's preferred stock consented to the issuance of unsecured Medium-Term Notes in an aggregate principal amount of $150 million outstanding at any one time; the notes are therefore not subject to such limitations. MEDIUM-TERM NOTES Under the terms of the Company's Medium-Term Note program, the Company may offer Medium-Term Notes up to an aggregate principal amount of $150 million. Maturities can range from nine months to 30 years; interest rates pertaining to such notes are established at the time of issuance. Interest on fixed-rate notes is payable on March 1 and September 1, while interest on floating-rate notes is payable on the dates indicated thereupon. Medium-Term Notes outstanding as of December 31, 1996, and 1995 were as follows:
MATURITY INTEREST RATE 1996 1995 -------- ------------- ------- ------- (DOLLARS IN THOUSANDS) Series A: 2000................................... 9.65% $ 5,000 $ 5,000 Series B: 1996-1998.............................. 4.92-7.98 23,000 57,000 Series C: 1997-2001.............................. 7.40-7.50 40,000 30,000 ------- ------- Total Medium-Term Notes.......................... $68,000 $92,000 ======= =======
A-43 POLLUTION-CONTROL FACILITY AND OTHER NOTES Pollution-control facility and other notes outstanding as of December 31, 1996, and 1995 were as follows:
SERIES INTEREST RATE MATURITY 1996 1995 ------ ------------- ---------------- ------- ------- (DOLLARS IN THOUSANDS) Central Maine Power Company: Yarmouth Installment Notes...... 6 3/4% June 1, 2002 $10,250 $10,250 Yarmouth Installment Notes...... 6 3/4 December 1, 2003 1,000 1,000 Industrial Development Authority of the State of New Hampshire Notes.......................... 7 3/8 May 1, 2014 11,000 11,000 7 3/8 May 1, 2014 8,500 8,500 Finance Authority of Maine...... 8.16 January 1, 2005 60,129 66,429 Maine Electric Power Company, Inc.: Promissory Notes................ Variable* July 1, 1996 820 1,730 ------- ------- Total Pollution-Control Facility and Other Notes................ $91,699 $98,909 ======= =======
- - -------- * The average rate was 6.3% in 1996 and 6.7% in 1995. The bonds issued by the Industrial Development Authority of the State of New Hampshire are supported by loan agreements between the Company and the Authority. The bonds are subject to redemption at the option of the Company at their principal amount plus accrued interest and premium, beginning in 2001. In September 1994, the Finance Authority of Maine (FAME) approved the Company's application for funds to finance the contract buy-out of a NUG contract for a 32-megawatt wood fired generating plant in Fort Fairfield, Maine. On October 26, 1994, FAME issued $79.3 million of Taxable Electric Rate Stabilization Revenue Notes Series 1994A (FAME notes). FAME and the Company entered into a loan agreement under which the Company issued FAME a note for approximately $66.4 million, evidencing a loan in that amount. The proceeds of the loan, along with $13 million of the Company's own funds, were used to buy out the Fort Fairfield contract. Concurrently, the Company purchased all of the common stock of Aroostook Valley Electric Company (AVEC) for $2 million. On October 26, 1994, AVEC paid the former owners of the Fort Fairfield facility $2 million and took title to the facility. In connection with the FAME financing, AVEC granted FAME a mortgage on the facility. The remaining $12.9 million of FAME-notes proceeds was placed in a capital-reserve account. The amount in the capital-reserve account is equal to the highest amount of principal and interest on the FAME notes to accrue and come due in any year the FAME notes are outstanding. The amounts invested in the capital reserve account are initially invested in government securities designed to generate interest income at a rate equal to the interest on the FAME notes. Under the terms of the loan agreement, the Company is also responsible for or receives the benefit from the interest rate differential and investment gains and losses on the capital reserve account. CAPITAL LEASE OBLIGATIONS The Company leases a portion of its buildings and equipment under lease arrangements, and accounts for certain transmission agreements as capital leases using periods expiring between 2006 and 2021. The net book value of property under capital leases was $33.1 million and $35.1 million at December 31, 1996, and 1995, respectively. Assets acquired under capital leases are recorded as electric property at the lower of fair-market value or the present value of future lease payments, in accordance with practices allowed by the MPUC, and are amortized over their contract terms. The related obligation is classified as other long-term debt. Under the terms of the lease agreements, executory costs are excluded from the minimum lease payments. A-44 Estimated future minimum lease payments for the five years ending December 31, 2001, together with the present value of the minimum lease payments, are as follows:
AMOUNT ---------------------- (DOLLARS IN THOUSANDS) 1997..................................................... $ 5,619 1998..................................................... 5,447 1999..................................................... 5,276 2000..................................................... 5,105 2001..................................................... 4,934 Thereafter............................................... 56,298 ------- Total minimum lease payments............................. 82,679 Less: amounts representing interest...................... 46,396 ------- Present Value of Net Minimum Lease Payments.............. $36,283 =======
SINKING-FUND REQUIREMENTS Consolidated sinking-fund requirements for long-term obligations, including capital lease payments and maturing debt issues, for the five years ending December 31, 2001, are as follows:
SINKING FUND MATURING DEBT TOTAL ------------ ------------- -------- (DOLLARS IN THOUSANDS) 1997........................................ $ 2,375 $ 25,000 $ 27,375 1998........................................ 9,212 178,000 187,212 1999........................................ 9,855 60,000 69,855 2000........................................ 10,520 80,000 90,520 2001........................................ 10,950 21,000 31,950
OPERATING LEASE OBLIGATIONS The Company has a number of operating-lease agreements primarily involving computer and other office equipment, land, and telecommunication equipment. These leases are noncancelable and expire on various dates through 2007. Following is a schedule by year of future minimum rental payments required under the operating leases that have initial or remaining noncancelable lease terms in excess of one year as of December 31, 1996:
AMOUNT ---------------------- (DOLLARS IN THOUSANDS) 1997..................................................... $ 4,277 1998..................................................... 4,042 1999..................................................... 3,278 2000..................................................... 3,123 2001..................................................... 3,099 Thereafter............................................... 1,936 ------- $19,755 =======
Rent expense under all operating leases was approximately $5 million, $5.7 million, and $7 million for the years ended December 31, 1996, 1995 and 1994, respectively. A-45 DISCLOSURE OF FAIR VALUE OF FINANCIAL INSTRUMENTS The methods and assumptions used to estimate the fair value of each class of financial instruments for which it is practicable are discussed below. The carrying amounts of cash and temporary investments approximate fair value because of the short maturity of these investments. The fair value of redeemable preferred stock and pollution-control facility and other notes is based on quoted market prices as of December 31, 1996 and 1995. The fair value of long-term obligations is based on quoted market prices for the same or similar issues, or on the current rates offered to the Company based on the weighted average life of each class of instruments. The estimated fair values of the Company's financial instruments as of December 31, 1996, and 1995 are as follows:
1996 1995 -------------------------- -------------------------- CARRYING AMOUNT FAIR VALUE CARRYING AMOUNT FAIR VALUE --------------- ---------- --------------- ---------- (DOLLARS IN THOUSANDS) Cash and temporary in- vestments............... $ 8,307 $ 8,307 $ 57,677 $ 57,677 Redeemable preferred stock................... 60,528 57,228 74,528 75,117 Mortgage bonds........... 421,000 415,578 432,500 435,311 Medium-term notes........ 68,000 67,667 92,000 92,156 Pollution-control facil- ity and other notes..... 91,699 91,791 98,909 99,694
PREFERRED STOCK Preferred-stock balances outstanding as of December 31, 1996, 1995, and 1994 were as follows:
CURRENT SHARES OUTSTANDING 1996 1995 1994 ----------- ------- ------- ------- (DOLLARS IN THOUSANDS, EXCEPT PER- SHARE AMOUNTS) Preferred Stock--Not Subject to Mandatory Redemption: $25 par value--authorized 2,000,000 shares; outstanding:.............................. None $ -- $ -- $ -- $100 par value noncallable--authorized 5,713 shares; outstanding 6% voting....... 5,713 571 571 571 $100 par value callable--authorized 2,300,000* shares; outstanding: 3.50% series (redeemable at $101).......... 220,000 22,000 22,000 22,000 4.60% series (redeemable at $101).......... 30,000 3,000 3,000 3,000 4.75% series (redeemable at $101).......... 50,000 5,000 5,000 5,000 5.25% series (redeemable at $102).......... 50,000 5,000 5,000 5,000 7 7/8% series (optional redemption after 9/1/97, at $100).......................... 300,000 30,000 30,000 30,000 ------- ------- ------- Preferred Stock--Not Subject to Mandatory Redemption................................ $65,571 $65,571 $65,571 ======= ======= ======= Redeemable Preferred Stock--Subject to Mandatory Redemption: $100 par value callable--authorized 2,300,000* shares; outstanding:........... None $ -- $ -- $ -- Flexible Money Market Preferred Stock, Se- ries A--7.999% (395,275 shares in 1996 and 1995; 450,000 shares in 1994)............. 395,275 39,528 39,528 45,000 8 7/8% series (redeemable at $102.958)..... 210,000 21,000 35,000 35,000 ------- ------- ------- ------- Redeemable Preferred Stock--Subject to Mandatory Redemption...................... $60,528 $74,528 $80,000 ======= ======= =======
- - -------- * Total authorized $100 par value callable is 2,300,000 shares. Shares outstanding are classified as Not Subject to Mandatory Redemption and Subject to Mandatory Redemption. A-46 Sinking-fund provisions for the 8 7/8% Series Preferred Stock require the Company to redeem all shares at par plus an amount equal to dividends accrued to the redemption date on the basis of 70,000 shares annually commencing on July, 1996. The Company also has the non-cumulative right to redeem up to an equal amount of the respective number of shares annually, beginning in 1996, at par plus an amount equal to dividends accrued to the redemption date. The sinking-fund requirement for the five-year period ending December 31, 2000 is $7.0 million annually beginning in 1996. The Company redeemed $14 million of these shares at par in 1996 pursuant to the mandatory and optional sinking-fund provisions. Sinking-fund provisions for the Flexible Money Market Preferred Stock, Series A, 7.999%, require the Company to redeem all shares at par plus an amount equal to dividends accrued to the redemption date on the basis of 90,000 shares annually beginning in October 1999. The Company also has the non-cumulative right to redeem up to an equal number of shares annually beginning in 1999, at par plus an amount equal to dividends accrued to the redemption date. The sinking-fund requirement for the five-year period ending December 31, 2000, is $9 million annually beginning in 1999. In 1995, the Company purchased 54,725 shares on the open market that may be used to reduce the sinking-fund requirement in 1999. INTERIM FINANCING AND CREDIT AGREEMENTS The Company uses funds obtained from short-term borrowing to provide initial financing for construction and other corporate purposes. To support its short-term capital requirements, on October 23, 1996 , the Company entered into a $125 million revolving credit facility with several banks, with The First National Bank of Boston and The Bank of New York acting as agents for the lenders. The credit facility has two tranches which consist of: a $75 million 364-day revolving credit facility which matures on October 22, 1997 and a $50-million 3-year revolving credit facility which matures on October 23, 1999. Both credit facilities require annual fees on the unused portion of the credit lines which are based on the Company's credit ratings and allow for various borrowing options including LIBOR-priced, base-rate-priced and competitive-bid-priced loans. The amount of outstanding short-term borrowing will fluctuate with day-to-day operational needs, the timing of long- term financing, and market conditions. There was $7.5 million outstanding as of December 31, 1996, under this credit agreement. A-47 NOTE 8: QUARTERLY FINANCIAL DATA (UNAUDITED) Quarterly revenue variability increased after January 1, 1995, when the ARP replaced MPUC rules prescribing different revenue allocations for energy sold in winter versus non-winter months. Twelve-month results are unaffected by this reporting change. Unaudited, consolidated quarterly financial data pertaining to the results of operations are shown below.
QUARTER ENDED ------------------------------------------- MARCH 31 JUNE 30 SEPTEMBER 30 DECEMBER 31 -------- -------- ------------ ----------- (DOLLARS IN THOUSANDS, EXCEPT PER- SHARE AMOUNTS) 1996 Electric operating revenues.... $274,139 $216,358 $228,987 $247,562 Operating income............... 39,601 20,495 14,667 32,909 Net income..................... 27,857 9,096 3,392 19,884 Earnings per common share*..... .78 .20 .04 .54 -------- -------- -------- -------- 1995 Electric operating revenues.... $263,312 $202,584 $217,872 $232,248 Operating income............... 39,361 4,052 22,169 20,277 Net income (loss).............. 26,376 (8,619) 10,400 9,823 Earnings (loss) per common share*........................ .73 (.34) .24 .23 -------- -------- -------- -------- 1994 Electric operating revenues.... $241,026 $212,336 $233,543 $217,978 Operating income............... 26,233 26,609 25,652 11,742 Net income (loss).............. 11,416 15,307 14,083 (64,071) Earnings (loss) per common share*........................ .27 .39 .35 (2.06) -------- -------- -------- --------
- - -------- * Earnings per share are computed using the weighted-average number of common shares outstanding during the applicable quarter. A-48 PRELIMINARY COPY PROXY DETACH HERE CENTRAL MAINE POWER COMPANY PROXY SOLICITED ON BEHALF OF THE BOARD OF DIRECTORS (Common Shareholders) The undersigned shareholder hereby appoints Arthur W. Adelberg and David E. Marsh, and either of them, proxies, with power of substitution, to vote all shares that the undersigned is entitled to vote at the Annual Meeting of the Shareholders of Central Maine Power Company to be held on May 15, 1997 at 10 A.M. EDT, at the Augusta Civic Center, Augusta, Maine, and at any adjournments, on the proposals described in the accompanying Proxy Statement as marked on the reverse side, and in their discretion on any other matters that may properly come before the meeting or any adjournment. If this proxy is properly signed, your shares will be voted as you directed by marking the boxes on the reverse side. IF NO DIRECTION IS GIVEN, YOUR SHARES WILL BE VOTED FOR THE --- ELECTION OF ALL NOMINEES FOR DIRECTOR NAMED ON THE REVERSE SIDE, FOR PROPOSAL 2, --- AND FOR PROPOSAL 3 ON THE REVERSE SIDE. --- SEE REVERSE CONTINUED AND TO BE SIGNED ON REVERSE SIDE SIDE [LOGO]/(R)/ Central Maine Power DETACH HERE [X] Please mark votes as in this example. THE BOARD OF DIRECTORS RECOMMENDS A VOTE FOR PROPOSALS 1, 2 AND 3. ---
FOR AGAINST ABSTAIN 1. Election of Directors 2. Approval of Coopers & Lybrand [_] [_] [_] Nominees: Charles H. Abbott, William J. Ryan L.L.P. as auditors for 1997. Lyndel J. Wishcamper, Kathryn M. Weare VOTE FOR WITHHOLD VOTE 3. Proposal to amend the Long-Term [_] [_] [_] ALL FOR ALL Incentive Plan to include a stock [_] [_] options program. [_]_______________________________________ To withhold vote for any nominee, write that nominee's name above. MARK HERE MARK HERE FOR ADDRESS [_] IF YOU PLAN [_] CHANGE AND TO ATTEND NOTE AT LEFT THE MEETING Please date, sign exactly as name(s) appear at left, and return promptly in enclosed envelope. If signing for a corporation or partnership, sign in that name and indicate your title. If signing as attorney, executor, guardian, trustee or custodian, please add your title. Signature: _____________________________________ Date: _________ Signature: ________________________ Date: _______________
PRELIMINARY COPY PROXY DETACH HERE CENTRAL MAINE POWER COMPANY PROXY SOLICITED ON BEHALF OF THE BOARD OF DIRECTORS (6% Preferred Shareholders) The undersigned shareholder hereby appoints Arthur W. Adelberg and David E. Marsh, and either of them, proxies, with power of substitution, to vote all shares that the undersigned is entitled to vote at the Annual Meeting of the Shareholders of Central Maine Power Company to be held on May 15, 1997 at 10 A.M. EDT, at the Augusta Civic Center, Augusta, Maine, and at any adjournments, on the proposals described in the accompanying Proxy Statement as marked on the reverse side, and in their discretion on any other matters that may properly come before the meeting or any adjournment. If this proxy is properly signed, your shares will be voted as you directed by marking the boxes on the reverse side. IF NO DIRECTION IS GIVEN, YOUR SHARES WILL BE VOTED FOR THE --- ELECTION OF ALL NOMINEES FOR DIRECTOR NAMED ON THE REVERSE SIDE, FOR PROPOSAL 2, --- --- FOR PROPOSAL 3, AND FOR PROPOSAL 4 ON THE REVERSE SIDE. - - --- --- SEE REVERSE CONTINUED AND TO BE SIGNED ON REVERSE SIDE SIDE [LOGO] Central Maine Power DETACH HERE [X] Please mark votes as in this example. THE BOARD OF DIRECTORS RECOMMENDS A VOTE FOR PROPOSALS 1,2,3 AND 4. ---
FOR AGAINST ABSTAIN 1. Election of Directors 2. Approval of Coopers & Lybrand [_] [_] [_] Nominees: Charles H. Abbott, William J. Ryan L.L.P. as auditors for 1997. Lyndel J. Wishcamper, Kathryn M. Weare VOTE FOR WITHHOLD VOTE 3. Proposal to amend the Long-Term ALL FOR ALL Incentive Plan to include a stock [_] [_] options program. [_] [_] [_] 4. Proposal to consent to an increase in the existing unsecured Medium- Term Note program from $150 million to $500 million. [_] [_] [_] [_]_______________________________________ To withhold vote for any nominee, write that nominee's name above. MARK HERE MARK HERE FOR ADDRESS [_] IF YOU PLAN [_] CHANGE AND TO ATTEND NOTE AT LEFT THE MEETING Please date, sign exactly as name(s) appear at left, and return promptly in enclosed envelope. If signing for a corporation or partnership, sign in that name and indicate your title. If signing as attorney, executor, guardian, trustee or custodian, please add your title. Signature _____________________________________ Date_________ Signature _____________________________________ Date _______________
PRELIMINARY COPY PROXY DETACH HERE CENTRAL MAINE POWER COMPANY PROXY SOLICITED ON BEHALF OF THE BOARD OF DIRECTORS (Dividend Series Preferred Shareholders) The undersigned shareholder hereby appoints Arthur W. Adelberg and David E. Marsh, and either of them, proxies, with power of substitution, to vote all shares that the undersigned is entitled to vote at the Annual Meeting of the Shareholders of Central Maine Power Company to be held on May 15, 1997 at 10 A.M. EDT, at the Augusta Civic Center, Augusta, Maine, and at any adjournments, on the proposal described in the accompanying Proxy Statement as marked on the reverse side, and in their discretion on any other matters that may properly come before the meeting or any adjournment. If this proxy is properly signed, your shares will be voted as you directed by marking the box on the reverse side. IF NO DIRECTION IS GIVEN, YOUR SHARES WILL BE VOTED FOR PROPOSAL 4 ON THE --- REVERSE SIDE. SEE REVERSE CONTINUED AND TO BE SIGNED ON REVERSE SIDE SIDE [LOGO] Central Maine Power DETACH HERE [X] Please mark votes as in this example. THE BOARD OF DIRECTORS RECOMMENDS A VOTE FOR PROPOSAL 4. ---
FOR AGAINST ABSTAIN Proposal 1: Not applicable. 4. Proposal to consent to an increase [_] [_] [_] Proposal 2: Not applicable. in the existing unsecured Medium- Proposal 3: Not applicable. Term Note program from $150 million to $500 million. MARK HERE MARK HERE FOR ADDRESS [_] IF YOU PLAN [_] CHANGE AND TO ATTEND NOTE AT LEFT THE MEETING Please date, sign exactly as name(s) appear at left, and return promptly in enclosed envelope. If signing for a corporation or partnership, sign in that name and indicate your title. If signing as attorney, executor, guardian, trustee or custodian, please add your title. Signature: _____________________________________ Date: _________ Signature: _______________________________ Date: _______________
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