CENTRAL MAINE POWER CO, PRE 14A, 1997-03-21

CENTRAL MAINE POWER CO
PRE 14A, 1997-03-21
ELECTRIC SERVICES

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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:

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(2) Aggregate number of securities to which transaction applies:

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(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):

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(4) Proposed maximum aggregate value of transaction:

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(5) Total fee paid:

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[_] 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:

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(2) Form, Schedule or Registration Statement No.:

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(3) Filing Party:

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(4) Date Filed:

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Notes:
<PAGE>

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.
<PAGE>

[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
<PAGE>

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
<PAGE>

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
<PAGE>

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.

3
<PAGE>

<TABLE>
<CAPTION>
PRINCIPAL OCCUPATIONS
AND BUSINESS EXPERIENCE
DURING PAST FIVE
YEARS AND CURRENT FIRST
NAME AND DIRECTORSHIPS OF BECAME A
AGE PUBLIC COMPANIES DIRECTOR
-------- ----------------------- --------
<C> <S> <C>
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)
</TABLE>

- - --------
(a) The Company owns 38 percent of the outstanding voting stock of Maine
Yankee Atomic Power Company.

4
<PAGE>

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
<PAGE>

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
<PAGE>

<TABLE>
<CAPTION>
COMPENSATION UNITS
SHARES BENEFICIALLY REPRESENTING
DIRECTORS AND NAMED OWNED DEFERRED RETAINER
EXECUTIVE OFFICERS (AS OF MARCH 17, 1997) (AS OF FEBRUARY 28 , 1997)
------------------- ---------------------- --------------------------
<S> <C> <C>
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
</TABLE>

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.

<TABLE>
<CAPTION>
PERCENT
NUMBER OF PERCENT OF OF COMBINED
NAME AND ADDRESS SHARES CLASS VOTING POWER
- - ---------------- --------- ---------- ------------
<S> <C> <C> <C>
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
</TABLE>

7
<PAGE>

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

<TABLE>
<CAPTION>
LONG-TERM
ANNUAL COMPENSATION COMPENSATION
----------------------- ------------
NAME RESTRICTED
AND STOCK ALL OTHER
PRINCIPAL AWARD(S) COMPENSATION
POSITION YEAR SALARY ($) BONUS ($)(1) ($)(2) ($)(3)
--------- ---- ---------- ------------ ------------ ------------
<S> <C> <C> <C> <C> <C>
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
</TABLE>
- - --------
(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
<PAGE>

The number of LTIP shares forfeited and their value as of the forfeiture date
were as follows:

<TABLE>
<CAPTION>
NUMBER OF VALUE AS OF FORFEITURE
NAME SHARES FORFEITED DATE (FEBRUARY 20, 1997)
---- ---------------- ------------------------
<S> <C> <C>
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
</TABLE>

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
<PAGE>

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.
<TABLE>
<CAPTION>
YEARS OF SERVICE
----------------------------------------
AVERAGE ANNUAL SALARY FOR
5 HIGHEST CONSECUTIVE YEARS
PRECEDING RETIREMENT 15 20 25 30 35
--------------------------- ------- ------- ------- ------- --------
<S> <C> <C> <C> <C> <C>
$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
</TABLE>

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.

<TABLE>
<CAPTION>
YEARS OF SERVICE
---------------------------------------
AVERAGE ANNUAL
COMPENSATION
FOR 3 HIGHEST YEARS 15 20 25 30 35
------------------- ------- ------- ------- ------- -------
<S> <C> <C> <C> <C> <C>
$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
</TABLE>

10
<PAGE>

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:

<TABLE>
<CAPTION>
TOTAL COVERED AGGREGATE
COMPENSATION ANNUAL BENEFIT
------------- --------------
<S> <C>
$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
</TABLE>

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
<PAGE>

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
<PAGE>

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
<PAGE>

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
<PAGE>

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]

<TABLE>
<CAPTION>
DECEMBER 31
-----------------------------
1991 1992 1993 1994 1995 1996
---- ---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C> <C>
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
</TABLE>

15
<PAGE>

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
<PAGE>

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

<TABLE>
<CAPTION>
NUMBER OF
NAME AND POSITION UNITS
----------------- ---------
<S> <C>
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
</TABLE>

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
<PAGE>

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
<PAGE>

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
<PAGE>

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
<PAGE>

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

<TABLE>
<CAPTION>
(DOLLARS IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
-----------------------------------------------------------
1996 1995 1994 1993 1992
---------- ---------- ---------- ---------- ----------
<S> <C> <C> <C> <C> <C> <C>
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
</TABLE>

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
<PAGE>

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
<PAGE>

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
<PAGE>

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:

<TABLE>
<CAPTION>
1996 1995
---------- ----------
(DOLLARS IN MILLIONS)
<S> <C> <C>
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
========== ==========
</TABLE>

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:

<TABLE>
<CAPTION>
1996 1995 1994
------------ ------------ ------------
% % %
KWH CHANGE KWH CHANGE KWH CHANGE
----- ------ ----- ------ ----- ------
(KILOWATT-HOURS IN MILLIONS)
<S> <C> <C> <C> <C> <C> <C>
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)%
===== ==== ===== ==== ===== ====
</TABLE>

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
<PAGE>

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
<PAGE>

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
<PAGE>

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

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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.

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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.

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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.

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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.

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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

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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

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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,

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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.

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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
<PAGE>

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

<TABLE>
<CAPTION>
PAGE
----
<S> <C>
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
</TABLE>

A-17
<PAGE>

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
<PAGE>

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
<PAGE>

CONSOLIDATED FINANCIAL STATEMENTS
CONSOLIDATED STATEMENT OF EARNINGS

<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-------------------------------------
1996 1995 1994
----------- ----------- -----------
(DOLLARS IN THOUSANDS, EXCEPT PER-
SHARE AMOUNTS)
<S> <C> <C> <C>
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
</TABLE>

The accompanying notes are an integral part of these financial statements.

A-20
<PAGE>

CONSOLIDATED BALANCE SHEET

<TABLE>
<CAPTION>
DECEMBER 31
-----------------------
1996 1995
----------- -----------
(DOLLARS IN THOUSANDS)
<S> <C> <C>
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
=========== ===========
</TABLE>

The accompanying notes are an integral part of these financial statements.

A-21
<PAGE>

CONSOLIDATED STATEMENT OF CASH FLOWS

<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31
----------------------------
1996 1995 1994
-------- -------- --------
(DOLLARS IN THOUSANDS)
<S> <C> <C> <C>
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
</TABLE>

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
<PAGE>

CONSOLIDATED STATEMENT OF CAPITALIZATION AND INTERIM FINANCING

<TABLE>
<CAPTION>
DECEMBER 31
----------------------------------
1996 1995
---------------- ----------------
AMOUNT % AMOUNT %
---------- ----- ---------- -----
(DOLLARS IN THOUSANDS)
<S> <C> <C> <C> <C>
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%
========== ===== ========== =====
</TABLE>

The accompanying notes are an integral part of these financial statements.

A-23
<PAGE>

CONSOLIDATED STATEMENT OF CHANGES IN COMMON-STOCK INVESTMENT

FOR THE THREE YEARS ENDED DECEMBER 31, 1996

<TABLE>
<CAPTION>
AMOUNT OTHER
AT PAR PAID-IN RETAINED
SHARES VALUE CAPITAL EARNINGS TOTAL
---------- -------- -------- -------- --------
(DOLLARS IN THOUSANDS)
<S> <C> <C> <C> <C> <C>
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
========== ======== ======== ======== ========
</TABLE>

The accompanying notes are an integral part of these financial statements.

A-24
<PAGE>

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
<PAGE>

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:

<TABLE>
<CAPTION>
1996 1995
----------- -----------
(DOLLARS IN THOUSANDS)
<S> <C> <C>
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
=========== ===========
</TABLE>

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:

<TABLE>
<CAPTION>
AMOUNT
----------------------
(DOLLARS IN THOUSANDS)
<S> <C>
1997............................................... $26,790
1998............................................... 26,053
1999............................................... 23,910
2000............................................... 22,807
2001............................................... 19,304
</TABLE>

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:

<TABLE>
<CAPTION>
DECEMBER 31
----------------------- RECOVERY
1996 1995 PERIODS ENDING
----------- ----------- --------------
(DOLLARS IN THOUSANDS)
<S> <C> <C> <C>
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
=========== ===========
</TABLE>

A-26
<PAGE>

NOTE 2: INCOME TAXES

The components of federal and state income-tax provisions (benefits)
reflected in the Consolidated Statement of Earnings are as follow:

<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31
--------------------------
1996 1995 1994
------- ------- --------
(DOLLARS IN THOUSANDS)
<S> <C> <C> <C>
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)
======= ======= ========
</TABLE>

A-27
<PAGE>

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:

<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31
--------------------------------------------
1996 1995 1994
------------- ------------- --------------
AMOUNT % AMOUNT % AMOUNT %
------- ---- ------- ---- -------- ----
(DOLLARS IN THOUSANDS)
<S> <C> <C> <C> <C> <C> <C>
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%
======= ==== ======= ==== ======== ====
</TABLE>
- - --------
* 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
<PAGE>

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:

<TABLE>
<CAPTION>
1996 1995
----------- -----------
(DOLLARS IN THOUSANDS)
<S> <C> <C>
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
=========== ===========
</TABLE>

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 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
<PAGE>

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
<PAGE>

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
<PAGE>

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.

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:

<TABLE>
<CAPTION>
1997 1998-2001 TOTAL
------ ---------- -------
(DOLLARS IN MILLIONS)
<S> <C> <C> <C>
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
====== ======= =======
</TABLE>

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
<PAGE>

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
<PAGE>

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
<PAGE>

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:

<TABLE>
<CAPTION>
1996 1995 1994
-------------- --------------- --------------
NON- NON- NON-
UNION UNION UNION UNION UNION UNION
------ ------ ------- ------ ------ ------
(DOLLARS IN THOUSANDS)
<S> <C> <C> <C> <C> <C> <C>
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
====== ====== ======= ====== ====== ======
</TABLE>

Assumptions used in accounting for the non-union and union defined-benefit
plans in 1996, 1995, and 1994 are as follows:

<TABLE>
<CAPTION>
1996 1995 1994
---- ---- ----
<S> <C> <C> <C>
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%
</TABLE>

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:

<TABLE>
<CAPTION>
1996 1995
---------------- ----------------
NON- NON-
UNION UNION UNION UNION
------- ------- ------- -------
(DOLLARS IN THOUSANDS)
<S> <C> <C> <C> <C>
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
======= ======= ======= =======
</TABLE>

A-35
<PAGE>

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.