Exhibit 13-1

           Management's Discussion and Analysis of Financial Condition
                            and Results of Operations


Overview

     In 1995, the Company faced the financial challenge of an 11-month outage at
the Maine Yankee Atomic Power Company (Maine Yankee) nuclear plant, and used new
pricing  flexibility under the Alternative Rate Plan (ARP) to retain and promote
electric  sales.  The Company  continued to control  costs,  reduce  non-utility
purchased power expense, and expand its lines of business.

     The  Company's  share of repair costs to the Maine  Yankee  steam-generator
tubes was  approximately  $10  million;  another $29 million  was  incurred  for
replacement  power during the plant's  outage.  Under the ARP, these  additional
costs  cannot  be  deferred  for  later  cost  recovery  consideration.  The ARP
effectively  eliminated  traditional   regulatio's   reconcilable  fuel  clause
adjustment mechanism.

     Earnings   per  share  in  1995  were  $0.86  after   recognition   of  the
approximately   $0.70   per   share   in   Maine   Yankee-related   repair   and
replacement-power costs.

     In mid-January  1996,  Maine Yankee returned to operation and was producing
power at 90-percent of its maximum production  capacity.  The Company will incur
approximately  $300,000 to $500,000  of  replacement-power  costs for each month
that the plant operates at the 90-percent level.  Replacement-power  expenses in
1996 at that level of  production  would not involve the level of  extraordinary
costs incurred in 1995.

     The ARP form of price  regulation  took effect January 1, 1995. The Company
used the  ARP's  pricing  flexibility  and  entered  into  five-year  definitive
agreements with 18 of its large  general-service  customers.  Additionally,  the
Company has instituted  programs in specific  residential and commercial markets
where it believes  customers have competitive  options that need to be addressed
by lowering  applicable  tariffs to more  competitive  levels.  Approximately 35
percent of annual  kilowatt-hour sales and 22 percent of annual revenues are now
covered by special tariffs allowed under the ARP.

     During 1995 the ceiling  prices that the Company  could charge rose by 2.43
percent under the ARP annual  adjustment  mechanism.  Increases made pursuant to
the  price-cap   adjustment   should  generate   additional  annual  revenue  of
approximately $15 million.

     A sharing  mechanism  in the ARP  designed  to  protect  the  Company  from
fluctuations of return on equity outside a specified  bandwidth was triggered by
the low 1995  earnings.  A component of the 1996 ARP increase in price caps will
reflect the  operation of this  mechanism,  although the Company has  discretion
under the ARP to set rates lower than the caps.

     Because the ARP bases annual price changes on an external inflation measure
adjusted for  productivity  gains,  managing cost  increases  below the level of
inflation and  achieving  revenues from sales volume are important for improving
the Company's profitability.

     The Company  continues  to address  the  anticipated  transition  to a more
competitive industry.  While many factors are uncertain,  a transition to direct
retail  competition,  could  have  substantial  impacts  on the value of utility
assets and on their  ability to recover  costs  through  rates.  Without  proper
action by regulators,  utilities could find above-market costs to be "stranded,"
or unrecoverable, in the new competitive setting.

     In December 1995,  the Maine Public  Utilities  Commission  (MPUC) issued a
Notice of Inquiry for investigating the future structure of the electric-utility
industry in Maine.  The MPUC  proceeding  is being  conducted as the result of a
1995 Maine  Legislative  Resolve that established a process for reviewing issues
of  competition  and structure for electric  utilities.  The MPUC is expected to
conclude its  investigation  under the Notice of Inquiry by late 1996 and report
its findings and recommendations to the Legislature in early 1997.

     In late January  1996,  the Company  filed a proposal in response to a MPUC
Notice of Inquiry  outlining its  recommendations  for an orderly  transition to
competition and for adequate  reimbursement of its potentially strandable costs.
The major elements of the Company's proposed plan are:

     (1) The Company's  generating  assets,  contracts and obligations  would be
separated from its transmission-and-distribution assets and obligations;

     (2)  Retail  customers  would  begin to have the  opportunity  to  purchase
unbundled  energy directly from suppliers,  marketers or load aggregators in the
year 2000, with possible phase-in to total open access over a period of years;

     (3) Economic and  resource-planning  regulation of generation  would cease,
with the Federal  Energy  Regulatory  Commission  (FERC)  continuing to regulate
transmission,  and  distribution  remaining a  franchised  monopoly.  The entity
providing  distribution services would be subject to performance-based  earnings
regulation  similar to the ARP; the duty to serve would be replaced by a duty to
connect customers to the retail generation market;

     (4) An opportunity for full recovery of strandable  costs would be achieved
through  a  transition  charge  to  all  retail  customers;   generation-related
strandable  costs would be recovered  through a transition  contract between the
generation company and the transmission-and-distribution company.

     The Company has  substantial  exposure  to cost  stranding  relative to its
size. As of December 31,  1995, the Company estimates its strandable costs could
be  approximately  $2 billion.  These costs represent the excess of the 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.

     The estimated  market rate for power is based on currently  existing market
conditions and  anticipated  inflation  escalation.  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  expiration and ongoing  depreciation.  Deferred  regulatory  asset
totals  reflect the  current  uncollected  balances  and  existing  amortization
schedules.  The Company's  strandable-cost  exposure is expected to decline over
time as the  market  price  of  power  increases,  non-utility  generator  (NUG)
contracts expire, and regulatory assets are recovered.

     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.

     Major cost stranding would have a material  adverse effect on the Company's
results  of  operations.   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,  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 declared  dividends of $0.90 per share in 1995,  unchanged from
the 1994 level.  In December 1993, the quarterly  dividend  payment per share of
common  stock was reduced from $0.39 to $0.225.  This  reduction  reflected  the
then-current  earnings levels and the near-term financial outlook.  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 achieved and
anticipated 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.  Near-term,  the Company
anticipates a need to increase its equity  capitalization  as a result of higher
business risk and a desire to restore its credit standing that has been weakened
in recent years.

     The Company continues to face the challenges of change and must achieve and
maintain  financial  performance  and  resources   commensurate  with  both  the
provision  of service as demanded by  customers  and the  obligation  to achieve
competitive returns on investor capital.

     The  ensuing  issues  associated  with the  restructuring  of the  electric
industry,  the  pressure  from  existing  competitive  energy  sources,  and the
appetite of customers for choices and enhanced  service are challenges  that the
Company is aggressively addressing.

Financial Objectives:

     1. Continue increasing the efficiency of operations;  cost management under
price-cap  regulation  must  replace  the  cost-plus  culture  that  traditional
regulation can entail.

     2. Focus on volume of sales as a revenue  builder;  revenue  from prices is
capped.

     3. Align  financial  policies to match  changing  business needs and risks;
competition  tends to increase  business risk, which in turn 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.


<PAGE>

                       Management's Discussion & Analysis


Earnings and Dividends

     For 1995, the Company generated net income of $38.0 million,  compared to a
net loss of $23.3 million in 1994,  and net income of $61.3 million in 1993. The
earnings  applicable  to common  stock were  $27.8  million in 1995 or $0.86 per
share,  while the loss applicable to common stock was $33.8 million or $1.04 per
share in 1994.  Earnings  applicable to common stock were $52.5 million or $1.65
per share in 1993.  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.  The two
items reduced earnings  applicable to common stock by $22.9 million after income
taxes, or $0.70 per share. See "Maine Yankee Steam-Generator  Tubes," below, for
a detailed discussion of these matters.  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.

     Total dividends  declared in 1995 and 1994 were $0.90 per common share, and
$1.395 per share for 1993. In December 1993, the quarterly  dividend payment per
share of common stock was reduced from $0.39 to $0.225.

Revenues and Sales

     Electric  operating  revenues  increased by $11.1 million or 1.2 percent to
$916.0 million in 1995, and by $11.3 million or 1.3 percent to $904.9 million in
1994.  The  components  of the  change in  electric  operating  revenues  are as
follows:

(Dollars in millions) ....................................      1995     1994
Revenues from kilowatt-hour sales ........................   $  (4.7) $  20.7
Other operating revenues .................................       8.7     (8.1)
Maine Electric Power Company, Inc. - Fuel cost recovery ..       7.1     (1.3)
Total Change in Electric Operating Revenues ..............   $  11.1  $  11.3

     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 1995,  1994,  and 1993 are
shown in the following table:



<PAGE>

<TABLE>
(Kilowatt-hours in millions)
                                                      1995                  1994                 1993
                                                KWH      % change      KWH      % change      KWH    % change
<S>                                            <C>         <C>        <C>         <C>        <C>         <C>   
Residential ........................           2,802       (2.0)%     2,860       (0.9)%     2,884       (3.5)%
Commercial .........................           2,477        1.6       2,439        2.2       2,387        0.9
Industrial .........................           3,547       (4.7)      3,720       (1.9)      3,791        3.2
Wholesale and
   lighting ........................             136       (8.7)        149       (3.5)        155        0.3
Total Service-
  Area Sales .......................           8,962       (2.2)%     9,168       (0.5)%     9,217        0.4%
</TABLE>

     The primary factors in the service-area  kilowatt-hour  sales decrease were
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 5,076 in 1995,
4,679 in 1994, and 4,771 in 1993,  while average usage per residential  customer
declined by 3.1 percent in 1995, 1.9 percent in 1994 and 4.5 percent in 1993.

     The 1995 and 1994  increases in commercial  sales reflect  increases in the
retail and service sectors.  Combined,  these sectors comprise  approximately 60
percent of  commercial  sales.  Also,  sales to Maine  Yankee  increased by 14.7
million kilowatt hours in 1995 due to its extended outage.

     Industrial  sales  levels are  significantly  affected  by changes in power
supplied to the pulp-and-paper industry customers, who account for approximately
63  percent  of  industrial   sales  and   approximately  25  percent  of  total
service-area sales. Sales to the pulp-and-paper  sector decreased by 8.6 percent
in 1995 and by 3.6 percent in 1994,  and  increased by 3.2 percent in 1993.  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
2.7 percent in 1995, 1.5 percent in 1994, and 3.3 percent in 1993.

Alternative Rate Plan

     In December 1994,  the MPUC approved a  stipulation,  signed by most of the
parties to the Company's ARP  proceeding,  to take 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 the Company's retail rate increase to be capped annually on July 1,
commencing  July 1, 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,  rate increase of 2.43 percent
are the inflation index of 2.92 percent, reduced by a productivity offset of 0.5
percent, and increased by 0.01 percent for flowthrough items and mandated costs.
As  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.

     For a detailed  discussion of each of the individual  provisions of the ARP
refer to Note 3 to  Consolidated  Financial  Statements,  "Regulatory  Matters -
Alternative Rate Plan."

     In 1994,  the Company agreed in the ARP  negotiations  to record charges of
approximately  $100 million  ($60  million,  net of tax) against 1994  earnings.
These  charges,  along with the other  provisions  of the ARP,  will  lessen the
impact of future price increases for MPUC-mandated costs.

     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  could be implemented  upon 30-days' notice by the
Company, while certain others would be subject to expedited review by the MPUC.

     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.

     During 1995, primarily as a result of the extended Maine Yankee outage, the
Company's rate of return on equity was 5.7 percent, a level below the low end of
the  earnings-sharing  mechanism.  Return on equity is one factor in the ARP for
determining the maximum annual adjustment in the Company's rates,  scheduled for
July 1996.

     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 are not controlled,  or if revenues from sales decline or are not adequate
to fund costs and provide fair rates of return on invested capital.

Maine Yankee Steam-Generator Tubes

     The Company,  through its equity investment  totaling  approximately  $26.8
million at December 31, 1995, owns a 38-percent  stock interest in Maine Yankee,
which owns and operates an 880-megawatt  nuclear  generating plant in Wiscasset,
Maine,  and is entitled under a cost-based  power  contract to an  approximately
equal  percentage  of the Plant's  output.  The Maine Yankee  Plant,  like other
pressurized-water  reactors,  experienced  degradation  of  its  steam-generator
tubes, principally in the form of circumferential  cracking,  which, until early
1995, was believed to be limited to a relatively  small number of tubes.  During
the  refueling-and-maintenance  shutdown that  commenced in early February 1995,
Maine Yankee detected through new inspection  methods  increased  degradation of
the  Plant's  steam-generator  tubes.  Approximately  60 percent of the  Plant's
17,000 steam-generator tubes appeared to have defects to some degree. Because of
the large number of affected tubes, the remedy of plugging the degraded tubes to
take them out of service was no longer a viable option.

     Following  a  detailed  analysis  of  safety,   technical,   and  financial
considerations,  Maine  Yankee  elected  to repair  the tubes by  inserting  and
welding short  reinforcing  sleeves of an improved material in substantially all
of the Plant's  steam-generator  tubes; this was completed in December 1995. The
project  caused Maine  Yankee to incur  additional  costs during 1995,  with the
Company being  responsible for its pro-rata share. The Company has also incurred
substantial incremental costs for replacement power.

     With  the   termination   of  the   reconcilable   fuel-and-purchased-power
adjustment  under the ARP, the Company's  costs of replacement  power during the
Maine  Yankee  outage  have been  treated  like other  Company  expenses,  i.e.,
recoverable only to the extent permitted by the ARP's price-index mechanism, and
were not deferred to be collected through a specific  fuel-rate  adjustment,  as
under  pre-1995  ratemaking.  Under the ARP, no additional  price increase other
than the 2.43-percent  increase effective July 1, 1995, could occur in 1995 as a
result of the Maine Yankee outage.

     The Company's $10-million share of repair costs was less than the estimated
$15 million  recorded in the second quarter of 1995 and resulted in a $5-million
reduction to  purchased  power-capacity  expense in the fourth  quarter of 1995.
Both the  Company  and  Maine  Yankee  implemented  cost-reduction  measures  to
mitigate these  additional  costs. The Company's  incremental  replacement-power
costs totaled approximately $29 million for the twelve months ended December 31,
1995.

     On January 11, 1996,  Maine Yankee began start-up  operations and was up to
90-percent  generation  levels by January 24, 1996.  Replacement power costs for
January 1996, were approximately $2.7 million.  However,  the Plant's operations
are under  review by the  Nuclear  Regulatory  Commission  (NRC).  Until the NRC
completes its investigation,  the Plant will operate at approximately 90 percent
of its  generating  capacity.  As a result,  the Company will  continue to incur
additional  replacement-power  costs  for the 10  percent  of its share of Maine
Yankee  energy  it will not  receive  until  the Plant  returns  to  100-percent
generation  levels.  These additional costs, as was the case with those incurred
during 1995, are not reconcilable under a fuel-adjustment clause and, therefore,
the Company estimates it will incur approximately $300,000 to $500,000 per month
in additional costs until the Plant returns to full power.

Industry Restructuring and Strandable Costs

     The  enactment  by  Congress of the Energy  Policy Act of 1992  accelerated
planning by electric utilities,  including the Company, for 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 a transition to direct
competition to serve retail  customers is widely  anticipated.  A departure from
traditional regulation,  however, could have substantial impacts on the value of
utility  assets and on the ability of electric  utilities 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.

     On March 29,  1995,  as part of a broader  Notice  of  Proposed  Rulemaking
(NOPR) related to open-access  transmission  and stranded costs, and designed to
facilitate  the  development  of  a  competitive   market,  the  Federal  Energy
Regulatory  Commission (FERC) expressed support for the principle that utilities
are entitled to full  recovery of their  "legitimate  and  verifiable"  stranded
costs at both the state and federal  levels.  Earlier,  the MPUC had initiated a
rulemaking  proceeding on stranded  costs at the retail level with a preliminary
proposal  that  supported   recovery  of  stranded  costs,  but  that  contained
significant  mitigation  requirements  which the  Company  believed  would  have
resulted  in  non-recovery  of  significant   costs.  The  MPUC  terminated  its
proceeding  after  FERC  issued  its NOPR to  avoid  "parallel  and  duplicative
proceedings."

     In  1995  the  Maine   Legislature   commenced  a  process  of   developing
recommendations  for the MPUC on the future  structure of the  electric  utility
industry in Maine. A diverse committee appointed by the Maine Legislature failed
to reach consensus by its late 1995 deadline.

     In  late  January  1996,  the  Company  filed  a  proposal   outlining  its
recommendations   for  an  orderly   transition  to  competition   and  adequate
reimbursement  of its  potentially  strandable  costs  with the MPUC.  The major
elements of the Company's proposed plan are the following:

     (1) The Company's  generating  assets,  contracts and obligations  would be
separated  from its  transmission  and  distribution  assets and  obligations by
distributing shares of a newly formed  transmission-and-distribution  company to
the Company's stockholders;

     (2) Assuming certain  necessary  changes in the management and operation of
the  regional  transmission  grid,  retail  customers  would  begin  to have the
opportunity to purchase unbundled energy directly from suppliers,  marketers, or
load  aggregators in the year 2000, with possible  phase-in to total open access
to such energy over a period of years;

     (3) Economic and  resource-planning  regulation of generation  would cease,
with FERC  continuing to regulate  transmission,  and  distribution  remaining a
franchised monopoly. The entity providing distribution services would be subject
to  performance-based  regulation  of its  earnings,  similar  to the  Company's
present  ARP,  and the duty to  serve  would be  replaced  by a duty to  connect
customers to the retail generation market;

     (4)  Full  recovery  of  strandable  costs  would  be  achieved  through  a
transition charge to all retail customers,  with  generation-related  strandable
costs recovered through a transition contract between the generation company and
the transmission-and-distribution company. Amounts recovered would 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 incentives for the Company to mitigate such costs
where practicable.

     Substantial  opposition has emerged in both the FERC and state  proceedings
to allowing full recovery of stranded  costs,  largely from customer  groups and
NUGs.  The  Company  expects  to  expend  significant  effort  on  restructuring
initiatives at both the state and federal level in 1996,  although the timing of
any formal recommendations in any proceedings is yet to be determined.

     The Company has  substantial  exposure  to cost  stranding  relative to its
size. As of December 31, 1995, the Company  estimates its strandable costs could
be  approximately  $2 billion.  These costs represent the excess of the 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.

     The estimated market rate for power is based on existing market  conditions
and   anticipated   inflation   escalation.   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  expiration and ongoing  depreciation.  Deferred  regulatory  asset
totals  reflect the  current  uncollected  balances  and  existing  amortization
schedules.  The Company's  strandable-cost  exposure is expected to decline over
time as the  market  price  of  power  increases,  non-utility  generator  (NUG)
contracts expire, and regulatory assets are recovered.

     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.

     Major cost stranding would have a material  adverse effect on the Company's
results  of  operations.   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 MPUC on the Company's  proposal
and other options and proposals submitted in response to the Notice; 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 the
Company will be permitted to recover its strandable costs.

Competition and Economic Development

     The  Company  faces  competition  in  several  aspects  of its  traditional
business and  anticipates  that  competition  will continue to place 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  Bonus Block rates,  which give a 50 percent
discount on kilowatt-hours used above 750;  water-heat and space-heat  retention
rates;  and  Super-Saver  rates,  which discount  off-peak  usage.  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.  The  participating  customers agreed to take electrical
service from the Company for five years and agreed not to switch fuels,  install
new  self-generation  equipment,  or seek another  supplier of  electricity  for
existing electrical load during that period.  Approximately 35 percent of annual
kilowatt-hour  sales and 22 percent of annual revenues are covered under special
tariffs  allowed under the pricing  flexibility  provisions of the ARP. Refer to
Note 4 to Consolidated  Financial  Statements,  "Commitments and Contingencies -
Competition," for detail.

     The Company is actively promoting economic development for Maine by helping
to bring a  $600-million  expansion  by one of its major  customers to the state
through  economic-development rates, and sponsoring "Maine & Company," a private
and public partnership that will market Maine as a place to do business.

Non-Utility Generators

     In  accordance  with prior MPUC policy and the ARP, $125 million of buy-out
or  restructuring  costs  incurred  since January 1992 were included in Deferred
Charges and Other Assets on the  Company's  balance  sheet and will be amortized
over  their  respective  fuel  savings  periods.  The  Company  restructured  37
contracts   representing  297  megawatts  of  capacity  that  should  result  in
approximately $260 million in fuel savings over the next five years.

Expansion Of Lines Of Business

     Another way the Company is addressing competition is to expand its business
opportunities  through  subsidiaries  that  capitalize  on  existing  strengths.
MaineCom Services, which was approved by the MPUC on July 13, 1995, will seek to
develop 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.   Telesmart,   approved   September   9,   1995,   is   a
credit-and-collections  subsidiary.  CMPE3 is an  environmental  and engineering
division of CMP International  Consultants.  All subsidiaries  utilize skills of
former Company employees and compete for business with other companies.

Environmental Actions

     The Company has been named by the Environmental  Protection Agency (EPA) as
a "potentially  responsible party" 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.  Refer  to Note 4 to  Consolidated
Financial  Statements,  "Commitments and Contingencies - Legal and Environmental
Matters," for a more detailed discussion of this matter.

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 51 percent of total operating expense in 1995, and 54 percent in
1994 and 1993. Purchased-power energy expense includes all costs associated with
purchases from NUGs,  which  amounted to 77 percent of this expense  category in
1995.  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 change.  Fuel
cost  decreases  are generally  retained by the Company.  Fuel expense for Maine
Electric Power  Company,  Inc.  (MEPCO),  a  78-percent-owned  subsidiary of the
Company,  is  fully  recoverable  through  billing  to  MEPCO  participants  and
fluctuates with participants' energy requirements.

     The  extended  outage at Maine  Yankee (see "Maine  Yankee  Steam-Generator
Tubes") had a  significant  effect on fuel  expense,  including  purchased-power
energy and purchased-power capacity expense, and the Company's generation mix in
1995.  Maine Yankee supplied 22 percent of the Company's  generation mix in 1994
at a cost of less than three cents per kilowatt-hour.  The Company replaced this
power through short-term agreements with New Brunswick Power and Hydro-Quebec.

     The Company's oil-fired  generation increased to 21.6 percent, up from 12.1
percent of 1994 net  generation,  and 15.5 percent in 1993. The NUG component of
the energy mix decreased slightly from 37.2 percent to 36.8 percent, as a result
of the ongoing efforts to reform the Company's NUG contracts.  The average price
of NUG energy of 8.4 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 four Yankee nuclear generating facilities.  The approximately
$10-million cost of the Maine Yankee  steam-generator  tube repairs was recorded
in purchased-power capacity expense in 1995.

     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. During 1992, Yankee Atomic Electric
Company, in which the Company is a 9.5-percent equity owner,  discontinued power
generation  and prepared a plan for  decommissioning.  Purchased-power  capacity
expense in 1995,  1994,  and 1993  contained  approximately  $4.0 million,  $5.2
million,  and $5.7 million,  respectively,  of costs  related to this  facility.
Refer to Note 6 to Consolidated  Financial Statements, "Capacity Arrangements -
Power Agreements," for a more detailed discussion of this matter.

     Operation-and-maintenance expense increased by $34.4 million in 1995 and by
$4.9 million in 1994. The 1995 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 needs  to be an  effective  competitor  in the  energy  marketplace.
Approximately 200 employees accepted the SRO.

     The Company implemented several new business processes and restructured its
customer-operations  functions,  closing and consolidating locations.  These new
processes are aimed at streamlining the Company's business practices in division
operations,  billing,  purchasing,  inventory,  accounts payable,  payroll,  and
system design and construction.  Two reengineering  teams were formed in 1995, a
Financial  Controls team and a Customer Service team. These teams sought radical
change to  realize  dramatic  improvements.  Currently,  60  projects  have been
approved,  and many are  underway  as a result  of these  teams'  efforts,  with
implementation periods ranging from three weeks to two years.

     Interest  expense  included a full year's interest costs in 1995 due to the
issuance of the Finance  Authority  of Maine Note in October 1994 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. The Company's overall level of interest
expense  during 1994 reflects the issuance of  additional  General and Refunding
Mortgage Bonds and additional notes under the Company's Medium-Term Note program
to replace short-term  borrowings  outstanding during 1993.  Short-term interest
costs over the period 1993  through 1995  fluctuated  with the costs and average
outstanding balances of short-term debt.

     The Company  reduced the level of Flexible  Money  Market  Preferred  Stock
outstanding  by $5.5  million  purchased  in  anticipation  of the  sinking-fund
requirement,  thereby  reducing  dividends in 1995 by $300,000.  The increase in
aggregate  dividends on preferred  stock for the two-year  period ended December
31, 1994, is due to the  conversion  of the dividend on the  Company's  Flexible
Money  Market  Preferred  Stock in November  1993 to a fixed  rate.  The average
variable rate in 1993 was 3.35 percent, while the fixed rate is 7.999 percent.

     State and federal income taxes fluctuate with the level of pre-tax earnings
and the regulatory  treatment of taxes by the MPUC. The significant  decrease in
income-tax  expense for 1994 is due to the impact of the loss from the write-off
of deferred  balances  in  accordance  with the MPUC's ARP order.  See Note 2 to
Consolidated Financial Statements, "Income Taxes," for more information.

Liquidity and Capital Resources

     The MPUC approved increases in base and fuel-related electric rates in 1993
and 1994, and a 2.43-percent  increase in total rates under the ARP in 1995 that
produced  additional  cash.  Increases  in rates  under  the ARP  were  based on
increases in the related price index and provisions for certain  mandated costs.
Prior rate  increases  were  provided  to fund costs of fuel,  energy-management
programs,  operations,   maintenance,   systems  improvements,   investments  in
generation needed to ensure the Company's  continued ability to provide reliable
electric  service,  and collection of unbilled revenues recorded pursuant to the
Electric Revenue Adjustment Mechanism (ERAM).

     Approximately  $114.5  million of cash was provided  from net income before
non-cash  items.  An  additional  $21.0  million  of  cash  was  generated  from
fluctuations in working capital,  primarily from refunds of income taxes related
to the 1994 net loss.  Other  operating  activities,  including the financing of
deferred energy-management  programs and the buy-out of NUG contracts,  required
cash resources.

     Increased  average cash balances and reduced  capital  investment  programs
resulted in very little  investment-related  activity  during 1995. The issuance
and  redemption of  Medium-Term  Notes and the purchase of Flexible Money Market
Preferred Stock used $35 million and $5.5 million,  respectively, of cash during
1995.  Effective in January 1994, the Company announced that it was electing the
option  under its  Dividend  Reinvestment  and  Common  Stock  Purchase  Plan to
purchase  shares  pursuant  to this plan on the  market,  rather  than issue new
shares. Dividends paid on common stock were $29.2 million, while preferred-stock
dividends were $10.3 million.

     Capital-investment   activities,   primarily   construction   expenditures,
utilized $47.1 million in cash during 1995. Construction  expenditures comprised
approximately   $4.5  million  for   generating   projects,   $3.5  million  for
transmission,  $30.8  million  for  distribution,  and $6.1  million for general
facilities and other construction expenditures.

     The Company estimates its capital  expenditures for the period 1996 through
2000 at approximately $334 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 approximately $471 million for sinking funds,
debt and equity maturities.

     The Company  estimates  that for the period 1996 through  2000,  internally
generated funds from depreciation,  deferred taxes, and retained earnings should
provide a substantial portion of the construction-program  requirements. Current
expectations  place  little  reliance  on external  funding  sources to meet the
capital  expenditure  requirements  for the next  several  years.  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.

     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, 1995, $92 million of Medium-Term  Notes
were  outstanding;  that,  pursuant  to the terms of the  program,  permits  the
issuance of an additional $58 million of such notes.

     To support its short-term capital requirements,  the Company entered into a
revolving-credit facility with several banks and Chemical Bank, as agent for the
lenders,  to provide up to $80 million of  revolving-credit  loans.  The Company
also has an unsecured $50-million  revolving-credit agreement with several banks
that  can  be  used  to  support  commercial-paper  borrowing  or as  short-term
financing.  However,  access to commercial paper markets has been  substantially
reduced,  if not eliminated,  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.

Factors That May Affect Future Results

     This   discussion   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 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.


<PAGE>

Consolidated Financial Statements

Consolidated Statement of Earnings

(Dollars in thousands, except per-share             Year ended December 31
    amounts)
                                                 1995        1994        1993
Electric Operating Revenues (Notes 1 and 3)   $916,016     $904,883    $893,577
Operating expenses
Fuel used for company generation (Notes 1
  and 6)                                        18,702       14,783      16,906
Purchased power - energy (Notes 1 and 6)       408,072      430,874     408,944
Purchased power - capacity (Note 6)             93,489       77,775      84,520
Other operation                                188,013      153,700     148,318
Maintenance                                     32,862       32,820      33,311
Depreciation and amortization (Note 1)          55,023       55,992      53,138
Federal and state income taxes (Note 2)         13,328       28,300      25,716
Taxes other than income taxes                   27,885       25,512      23,023
Total Operating Expenses                       837,374      819,756     793,876
Equity in Earnings of Associated Companies
  (Note 6)                                       7,217        5,109       5,829
Operating Income                                85,859       90,236     105,530
Other income (expense)
Allowance for equity funds used during
   construction (Note 1)                           663          807       1,523
Other, net (Note 3)                              7,170     (105,133)       (673)
Income taxes (Notes 2 and 3)                    (2,704)      42,443       3,127
Total Other Income (Expense)                     5,129      (61,883)      3,977
Income Before Interest Charges                  90,988       28,353     109,507
Interest charges
Long-term debt (Note 7)                         50,307       46,213      42,266
Other interest (Note 7)                          3,244        5,887       6,784
Allowance for borrowed funds used during
   construction (Note 1)                          (543)        (482)       (845)
Total Interest Charges                          53,008       51,618      48,205
Net income (loss)                               37,980      (23,265)     61,302
Dividends on preferred stock                    10,178       10,511       8,842
Earnings (Loss) Applicable to Common Stock    $ 27,802     $(33,776)   $ 52,460
Weighted Average Number of Shares of
   Common Stock Outstanding                 32,442,752   32,442,408  31,789,114
Earnings (Loss) Per Share of Common Stock        $0.86       $(1.04)      $1.65
Dividends Declared Per Share of Common
  Stock                                          $0.90       $ 0.90      $1.395
The accompanying notes are an integral part of these financial statements.


<PAGE>

Consolidated Balance Sheet
(Dollars in thousands)                                        December 31
Assets                                                      1995        1994
Electric property, at original cost (Notes 6 and 7)      $1,611,941  $1,579,632
Less: accumulated depreciation (Notes 1 and 6)              560,078     521,645
Electric property in service                              1,051,863   1,057,987
Construction work in progress (Note 4)                       15,928      13,647
Nuclear fuel, less accumulated amortization of $8,909 in
   1995 and $8,110 in 1994                                    1,391       2,181
Net electric property                                     1,069,182   1,073,815
Investments in associated companies, at equity (Notes 1
 and 6)                                                      54,669      49,602
Net Electric Property and Investments in Associated
  Companies                                               1,123,851   1,123,417
Current assets
Cash and cash equivalents                                    57,677      58,112
Accounts receivable, less allowances for uncollectible
   accounts of $3,313 in 1995 and $3,301 in 1994:
         Service - billed                                    87,140      81,289
         Service - unbilled (Notes 1 and 3)                  41,798      38,153
         Other accounts receivable                           15,131      12,088
Prepaid income taxes (Note 2)                                     -      28,068
Fuel oil inventory, at average cost                           3,772       4,113
Materials and supplies, at average cost                      12,772      13,026
Funds on deposit with trustee (Note 7)                       29,919      27,820
Prepayments and other current assets                          9,192       9,337
Total Current Assets                                        257,401     272,006
Deferred charges and other assets
Recoverable costs of Seabrook 1 and abandoned projects,
  net (Note 1)                                               95,127     101,976
Yankee Atomic purchased-power contract (Note 6)              21,396      38,777
Regulatory assets - deferred taxes (Note 2)                 235,081     233,234
Deferred charges and other assets (Notes 1 and 3)           260,063     276,597
Total Deferred Charges and Other Assets                     611,667     650,584
Total Assets                                             $1,992,919  $2,046,007
Stockholders' Investment and Liabilities
Capitalization (see separate statement) (Note 7)
Common-stock investment                                   $ 490,005   $ 491,323
Preferred stock                                              65,571      65,571
Redeemable preferred stock                                   67,528      80,000
Long-term obligations                                       622,251     638,841
Total Capitalization                                      1,245,355   1,275,735
Current liabilities and interim financing
Interim financing (see separate statement) (Note 7)          34,000      63,000
Sinking-fund requirements (Note 7)                           10,455       2,580
Accounts payable                                            108,170      97,800
Dividends payable                                             9,823       9,932
Accrued interest                                             12,648      14,102
Accrued income taxes (Note 2)                                 3,668           -
Miscellaneous current liabilities                            13,870      10,535
Total Current Liabilities and Interim Financing             192,634     197,949
Commitments and Contingencies (Notes 4 and 6)
Reserves and deferred credits
Accumulated deferred income taxes (Note 2)                  351,868     348,287
Unamortized investment tax credits (Note 2)                  32,452      34,167
Yankee Atomic purchased-power contract (Note 6)              21,396      38,777
Regulatory liabilities - deferred taxes (Note 2)             50,366      53,937
Other reserves and deferred credits (Note 5)                 98,848      97,155
Total Reserves and Deferred Credits                         554,930     572,323
Total Stockholders' Investment and Liabilities           $1,992,919  $2,046,007
The accompanying notes are an integral part of these financial statements.


<PAGE>

<TABLE>
Consolidated Statement of Cash Flows
 (Dollars in thousands)                                                                Year ended December 31
                                                                                   1995           1994        1993
Operating Activities
<S>                                                                              <C>          <C>          <C>      
Net income (loss) ............................................................   $  37,980    $ (23,265)   $  61,302
Items not requiring (providing) cash:
ARP-related charges (Note 3) .................................................        --        100,390         --
Depreciation and amortization ................................................      80,872       75,417       63,647
Deferred income taxes and investment tax credits,
   net .......................................................................      (3,710)      11,022        5,584
Allowance for equity funds used during construction ..........................        (663)        (807)      (1,523)
Changes in certain assets and liabilities:
Accounts receivable ..........................................................     (12,539)       5,175       (4,881)
Inventories ..................................................................         595        4,230        2,838
Other current assets .........................................................      (1,954)      (1,391)     (24,436)
Retail fuel costs ............................................................        --         32,922       (4,349)
Accounts payable .............................................................      12,025        4,062        1,338
Accrued taxes and interest ...................................................      30,282      (25,311)       3,077
Miscellaneous current liabilities ............................................       3,335       (2,602)      (3,296)
Deferred energy-management costs .............................................      (4,075)      (5,789)     (10,192)
Maine Yankee outage accrual ..................................................      (4,710)       8,197        4,962
Purchased-power contract buyouts .............................................     (13,405)     (91,274)        (515)
Revenue adjustment-tax flowback ..............................................        --           --         (9,990)
Other, net ...................................................................      11,495       (5,604)     (16,932)
Net Cash Provided by Operating Activities ....................................     135,528       85,372       66,634
Investing Activities
Construction expenditures ....................................................     (44,867)     (42,246)     (53,576)
Investments in associated companies ..........................................        (600)      (2,004)        --
Changes in accounts payable - investing activities ...........................      (1,655)        (679)      (2,905)
Net Cash Used by Investing Activities ........................................     (47,122)     (44,929)     (56,481)
Financing Activities
Issuances:
Mortgage bonds ...............................................................        --         25,000      260,000
Common stock .................................................................        --            927       25,513
Medium-term notes ............................................................      30,000       32,000       48,000
Finance Authority of Maine ...................................................        --         66,429         --
Redemptions:
Mortgage bonds ...............................................................        --           --       (177,500)
Premiums on redemptions ......................................................        --           --         (9,634)
Preferred stock ..............................................................      (5,472)        --         (7,125)
Medium-term notes ............................................................     (65,000)     (43,000)     (26,500)
Short-term obligations, net ..................................................      (8,000)     (25,500)     (63,000)
Other long-term obligations, net .............................................        (860)        (860)        (868)
Dividends:
Common stock .................................................................     (29,222)     (29,222)     (49,345)
Preferred stock ..............................................................     (10,287)     (10,061)      (8,664)
Net Cash Provided (Used) by Financing Activities .............................     (88,841)      15,713       (9,123)
Net Increase (Decrease) in Cash and Cash
   Equivalents ...............................................................        (435)      56,156        1,030
Cash and cash equivalents, beginning of year .................................      58,112        1,956          926
Cash and Cash Equivalents, end of year .......................................   $  57,677    $  58,112    $   1,956
Supplemental Cash-Flow Information:
Cash paid during the year for:
Interest (net of amounts capitalized) ........................................   $  51,127    $  44,874    $  42,870
Income taxes (net of amounts refunded of
   $29,045, $2,802, and $605 in respective years
   indicated) ................................................................     (11,994)       1,568       15,852
</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.


<PAGE>

Consolidated Statement of Capitalization and Interim Financing
                                                      December 31
(Dollars in thousands)                           1995                1994
                                         Amount       %       Amount      %
Capitalization (Note 7)
Common-stock investment:
Common stock, par value $5 per
   share:
    Authorized - 80,000,000 shares
    Outstanding - 32,442,752 shares in
       1995 and 1994                     $  162,214           $  162,214
Other paid-in capital                       276,287              275,627
Retained earnings                            51,504               53,482
Total Common-Stock Investment               490,005   38.3%      491,323   36.7%
Preferred Stock - not subject to
  mandatory redemption                       65,571    5.1        65,571    4.9
Preferred Stock - subject to mandatory
  redemption                                 74,528               80,000
Less: current sinking fund
  requirements                                7,000                    -
Redeemable Preferred Stock - subject
   to mandatory redemption                   67,528    5.3        80,000    6.0
Long-term obligations:
Mortgage bonds                              432,500              432,500
Less: unamortized debt discount               1,807                1,990
Total Mortgage Bonds                        430,693              430,510
Medium-term notes                            92,000              127,000
Less: unamortized debt discount                   8                   17
Total Medium-Term Notes                      91,992              126,983
Other long-term obligations:
Lease obligations                            38,112               39,159
Pollution-control facility and other
  notes                                      98,909               99,769
Total Other Long-Term Obligations           137,021              138,928
Less: Current Sinking Fund
  Requirements and Current Maturities        37,455               57,580
Total Long-Term Obligations                 622,251   48.6       638,841   47.7
Total Capitalization                      1,245,355   97.3     1,275,735   95.3
Interim financing, amounts to be
 refinanced (Note 7):
Short-term obligations                            -                8,000
Current maturities of long-term
   obligations                               34,000               55,000
Total Interim Financing                      34,000    2.7        63,000    4.7
Total Capitalization and Interim
  Financing                              $1,279,355  100.0%   $1,338,735  100.0%
The accompanying notes are an integral part of these financial statements.


<PAGE>

Consolidated Statement of Changes in Common-Stock Investment

<TABLE>
For the three years ended December 31, 1995
(Dollars in thousands)                                                                         Other
                                                                              Amount at       paid-in       Retained
                                                               Shares         par value       capital       earnings         Total
Balance - December 31,
<C>                                                          <C>           <C>            <C>           <C>            <C>        
1992                                                         31,148,321    $   155,742    $   254,576   $   110,050    $   520,368
Net income ...............................................                                                   61,302         61,302
Dividends declared:
  Common stock ...........................................                                                  (44,459)       (44,459)
  Preferred stock ........................................                                                   (8,704)        (8,704)
Cost for reacquired
   preferred stock .......................................                                       1,043       (1,043)           --
Issues of common stock ...................................     1,231,616          6,158         19,355                       25,513
Capital stock expense ....................................                                        (631)                        (631)
Balance - December 31,
1993                                                          32,379,937        161,900        274,343       117,146        553,389
Net income (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 redemption Note 7)                                                                         (324)                        (324)
Capital stock expense ....................................                                         403                          403
Balance - December 31,
1995                                                          32,442,752    $   162,214    $   276,287   $    51,504    $   490,005
</TABLE>
The accompanying notes are an integral part of these financial statements.


<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-percent-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.  From March 1991 through November 1993,
the  Company  recorded  unbilled  revenues  pursuant  to  the  Electric  Revenue
Adjustment Mechanism (ERAM) under an MPUC order. 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 rates were 3.0 percent in 1995 and 1994,
and 2.9 percent in 1993.

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 8.4 percent in 1995,  8.9 percent in 1994, and 9.8 percent in
1993.

New Accounting Policy

     A new accounting standard,  Statement of Financial Accounting Standards No.
121, "Accounting  for the  Impairment of Long-Lived  Assets and for  Long-Lived
Assets to be Disposed  Of," is effective  January  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).  The new standard
also imposes  stricter  criteria for retention of  regulatory-created  assets by
requiring that such assets be probable of future  recovery at each balance sheet
date.  The Company does not expect that  adoption of this  standard  will have a
material  effect on its financial  position or results of  operations.  However,
this  assumption  may differ 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,
1995, and 1994:

(Dollars in thousands)                                  1995           1994
NUG contract buy-outs and restructuring (Note 6)      $126,485       $138,188
Energy-management costs                                 36,224         37,527
Financing costs                                         24,775         29,105
Environmental site clean-up costs (Note 4)               7,375         13,104
Postretirement benefits (Note 5)                        21,849         16,455
Non-operating property, net                              7,486          7,398
Electric Lifeline Program                                3,603          4,839
Other, including MEPCO                                  32,266         29,981
Total                                                 $260,063       $276,597

     Certain  costs are being  amortized  and  recovered  in rates over  periods
ranging  from two to 30 years.  Amortization  expense for the next five years is
shown below:

(Dollars in thousands)          Amount
1996                            $24,383
1997                             23,783
1998                             23,159
1999                             21,086
2000                             20,006

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 current  ratemaking  practices,  the deferred
taxes related to these  recoverable  costs are being  amortized  over periods of
four to 10 years.  As of  December  31,  1995,  all  deferred  taxes  related to
Seabrook I have been amortized.  The recoverable  investments as of December 31,
1995, and 1994 are as follows:

                                       December 31                Recovery
(Dollars in thousands)             1995           1994         periods ending
Recoverable costs of:
Seabrook 1                        $141,084       $141,084           2015
Other projects                      57,491         57,491       1995 to 2001
                                   198,575        198,575
Less: accumulated amortization     102,248         94,439
Less: related income taxes           1,200          2,160
Total Net Recoverable Investment  $ 95,127       $101,976

Note 2:  Income Taxes

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

                                                     Year ended December 31
(Dollars in thousands)                        1995          1994        1993
Federal:
Current                                       $15,965     $(18,579)     $13,456
Deferred                                        2,278        2,175       37,455
Investment tax credits, net                    (1,715)      (2,512)      (1,832)
Regulatory deferred                            (2,619)       8,379      (30,224)
Total Federal Taxes                            13,909      (10,537)      18,855
State:
Current                                         3,777       (6,586)       3,549
Deferred                                          343        3,003       10,250
Regulatory deferred                            (1,997)         (23)     (10,065)
Total State Taxes                               2,123       (3,606)       3,734
Total Federal and State Income Taxes          $16,032     $(14,143)     $22,589
Federal and state income taxes charged to:
Operating expenses                            $13,328     $ 28,300      $25,716
Other income                                    2,704      (42,443)      (3,127)
                                              $16,032     $(14,143)     $22,589

     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>
                                                      Year ended December 31
                                              1995                 1994                 1993
                                     Amount         %     Amount         %     Amount         %
(Dollars in thousands)
Income tax expense at
<S>                                 <C>           <C>    <C>           <C>    <C>           <C>  
 statutory federal rate .........   $ 18,161      35.0%  $(11,831)     35.0%  $ 28,055      35.0%
Permanent differences:
Investment tax-credit
 amortization ...................     (1,613)     (3.1)    (1,613)      4.8     (1,613)     (2.0)
Dividend-received
  deduction .....................     (2,219)     (4.3)    (1,469)      4.3     (1,731)     (2.2)
Other, net ......................       (217)     (0.4)       (68)      0.2       (634)     (0.8)
                                      14,112      27.2    (14,981)     44.3     24,077      30.0
Effect of timing
  differences for which
  deferred taxes are not
  recorded (flow
  through):
Tax-basis repairs ...............       (891)     (1.7)      (924)      2.7     (1,175)     (1.5)
Depreciation
  differences flowed
  through in prior years ........      2,291       4.4      2,315      (6.8)     1,728       2.2
Accelerated flowback
   of deferred taxes on
    loss on abandoned
    generating projects .........      1,873       3.6      2,051      (6.1)    (2,678)     (3.3)
Deduction of removal
  costs .........................       (189)     (0.4)      (163)      0.5       (392)     (0.5)
Carrying costs, net .............        253       0.5        429      (1.3)      (523)     (0.7)
Adjustment to tax
   accrual for change in
   rate treatment ...............       --      --            420      (1.2)       481       0.6
Excess property taxes
  paid ..........................       --      --           (116)      0.4       (912)     (1.1)
Reduction for non-
   regulated deferred
   taxes previously
   flowed through ...............       --                           --         (1,530)     (1.9)
Provision for deferred
  taxes relating to
  normalization of
  certain short-term
  timing differences* ...........     (2,545)     (4.9)      --      --           --      --
Other, net ......................       (995)     (1.9)       432      (1.3)      (221)     (0.3)
Federal Income Tax
  Expense and Effective
  Rate ..........................   $ 13,909      26.8%  $(10,537)     31.2%  $ 18,855      23.5%
</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.
As of  December  31,  1995,  the  Company  had  approximately  $1.0  million  of
investment,  energy,  and  research-and-development  credits available to reduce
future federal and state income taxes otherwise payable.

     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 valuation allowance has not been recorded at December 31, 1995, and 1994,
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 1995 and 1994:
(Dollars in thousands)                                          1995      1994
Deferred tax assets resulting from:
Investment tax credits, net                                  $ 22,370  $ 23,491
Regulatory liabilities                                         13,882    15,629
Alternative minimum tax                                        23,850    24,175
All other                                                      22,545    16,922
                                                               82,647    80,217
Deferred tax liabilities resulting from:
Property                                                      273,565   263,060
Abandoned plant                                                65,573    70,294
Regulatory assets                                              96,577    97,310
                                                              435,715   430,664
Accumulated deferred income taxes, end of year, net          $353,068  $350,447
Accumulated deferred income taxes, recorded as:
Accumulated deferred income taxes                            $351,868  $348,287
Recoverable costs of Seabrook 1 and abandoned projects, net     1,200     2,160
                                                             $353,068  $350,447

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  will  continue  to
regulate the Company's operations and prices,  provide for continued recovery of
deferred costs,  and specify a range for its authorized rate of return.  The ARP
was adopted effective January 1, 1995.

     The Company believes, 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 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, no
separate fuel-clause price adjustments will occur.

     A  specified  standard  inflation  index will be the basis for each  annual
price-cap  change.  The  inflation  index  will  be  reduced  by the  sum of two
productivity factors, a general productivity offset of 1.0 percent, (0.5 percent
for 1995),  and a second  formula-based  offset  starting  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  were  outside a range of 350 basis
points above or below the Company's  allowed  return on equity,  starting at the
current 10.55-percent allowed return 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 will
commence with the price-cap change of July 1, 1996, and reflect 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 percent 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-percent  increase pursuant
to the annual  price-change  provision in the ARP. The primary  component of the
increase  is  the  inflation-index   change  of  2.92  percent,   reduced  by  a
productivity  offset  of  0.5  percent,   and  increased  by  0.01  percent  for
flowthrough items and mandated costs.

     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), as follows:

     (1) the  undercollected  balance  of fuel and  purchased-power  costs as of
December 31, 1994, totaling approximately $59 million;

     (2) the unrecovered deferred charges for  energy-management  costs for 1993
and 1994, which totaled approximately $15 million;

     (3) the  unrecovered  balance of unbilled  ERAM revenues as of December 31,
1994, totaling approximately $24 million; and

     (4) the unrecovered  deferred charges related to the possible  extension of
the operating life of one of the Company's  generating  stations,  which totaled
approximately $2.6 million as of December 31, 1994.

     The  $100-million  charge is included in "Other  income  (expense) - Other,
net" on the  Consolidated  Statement of Earnings.  The $40-million tax impact is
included in "Other income (expense) - Income taxes."

     These charges, with the other provisions of the ARP, will lessen the impact
of future price increases for MPUC-mandated and fuel-related costs.

     During 1995, the Company adjusted the prior regulatory treatment of certain
regulatory assets and deferred taxes. The net after-tax effect of the adjustment
was immaterial to financial results.

     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.  See  Note  4  to  Consolidated  Financial  Statements,  "Commitments  and
Contingencies  -  Competition,"  for a  discussion  of  actions  under the ARP's
pricing flexibility provisions.

     The ARP also  contains  provisions  to protect the  Company and  ratepayers
against unforeseen adverse results from its operation.  These provisions include
review by the MPUC if the  Company's  actual  return on equity falls outside the
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.

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 process included  appointment of a "Work Group on
Electric Utility  Restructuring" (Work Group), which comprised diverse interests
and was  charged  with  developing  a plan  for  "the  orderly  transition  to a
competitive  market for  retail  purchases  and sales of  electric  energy"  and
examining related issues. The Work Group discussed restructuring issues, but was
unable to reach a consensus by its late 1995 reporting deadline.

     The Resolve also directed the MPUC to develop at least two plans,  starting
the process no later than January 1, 1996, and  submitting its findings,  to the
Legislature no later than January 1, 1997. One plan would be designed to achieve
"...full retail market competition for purchases and sales of electric energy by
the year 2000" and the other to achieve a more limited form of competition.  The
Resolve further stated that the 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."

     On December 12, 1995, pursuant to the Resolve,  the MPUC issued a Notice of
Inquiry  (Notice)  initiating  its  study.  In the  Notice  the  MPUC  solicited
"...detailed  proposals and plans for achieving  retail  competition in Maine by
the year 2000," and requested  that the  proposals  include  "...specific  plans
(including  implementation  timetables)  for  an  orderly  transition  to a more
competitive  market" The Notice required that interested  parties file plans and
proposals with the MPUC by January 31, 1996, and outlined a schedule calling for
a final report by the MPUC to the  Legislature  in December  1996,  with a draft
report  issued for comments on July 19, 1996,  after  completion  of  discovery,
party conferences, and opportunities for public participation.

     On January 31, 1996, the Company filed its restructuring  proposal with the
MPUC, with initial comments on issues raised by the Resolve and the MPUC Notice.
The major elements of the Company's filed proposal are:

     (1) The Company's  generating  assets,  contracts and obligations  would be
separated  from its  transmission  and  distribution  assets and  obligations by
distributing shares of the newly formed transmission-and-distribution company to
the  Company's  stockholders,  assuming  other  aspects  of  its  proposal  were
accepted.

     (2) Assuming certain  necessary  changes in the management and operation of
the regional transmission grid have been effected,  retail customers would begin
to have the  opportunity to purchase  unbundled  energy directly from suppliers,
marketers  or load  aggregators  by the end of the year  2000,  with a  possible
phase-in to total open access to such energy over a period of years.

     (3) Economic and  resource-planning  regulation of generation  would cease,
with the FERC continuing to regulate transmission,  and distribution remaining a
franchised monopoly. The entity providing distribution services would be subject
to  performance-based  regulation  of its  earnings,  similar  to the  Company's
present ARP, and the current duty to serve all customers  would be replaced by a
duty to connect customers to the retail generation market.

     (4)  Full  recovery  of  strandable  costs  would  be  achieved  through  a
transition charge to all retail customers;  generation-related  strandable costs
would be recovered through a transition  contract between the generation company
and the  transmission-and-distribution  company. Amounts recovered would include
the costs of fulfilling obligations under contracts with non-utility generators,
as well as investments (and returns thereon) and other obligations undertaken by
the Company's  legal duty to serve,  with incentives for the Company to mitigate
such costs where practicable.

     The Company has  substantial  exposure  to cost  stranding  relative to its
size. As of December 31, 1995, the Company  estimates its strandable costs could
be  approximately  $2 billion.  These costs represent the excess of the 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.

     The estimated market rate for power is based on existing market  conditions
and  anticipated  inflation.   The  present  value  of  future  purchased  power
obligations and the Company's  generating  costs reflect the underlying costs of
those  sources of  generation  in place  today,  with  reductions  for  contract
expiration and  depreciation.  Deferred  regulatory asset totals reflect current
uncollected  balances  and  existing  amortization   schedules.   The  Company's
strandable-cost exposure is expected to decline over time as the market price of
power increases,  non-utility  generator (NUG) contracts expire,  and regulatory
assets are recovered.

     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
Company's  sales  and  costs  of  operations;  regional  and  national  economic
conditions;  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.

     Major cost stranding would have a material  adverse effect on the Company's
results  of  operations.   The  Company  believes  it  is  entitled  to  recover
substantially  all of its strandable  costs,  but cannot predict when or if open
electric  energy  competition  will  occur in its  service  territory,  or under
competition 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 MPUC on the Company's  proposal
and other options and proposals submitted in response to the Notice; 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.

Non-Utility Generators

     In 1994,  the Governor of Maine signed into law a bill allowing the Finance
Authority  of Maine  (FAME)  to borrow up to $100  million  to lend to  electric
utilities for financing buy-outs or other restructuring of NUG contracts to save
money for customers.  The law anticipated the State agency's bonds, which do not
pledge the full faith and credit of the state,  would likely bear lower interest
rates than the bonds of the Company with its then down-graded credit rating.

     On June 9, 1994, the Company  announced that it had agreed to buy out a NUG
contract for a 32-megawatt wood-fired generating plant in Fort Fairfield, Maine.
The Company  agreed to pay $76 million to buy out the contract and $2 million to
acquire the generating plant.

     On August 5, 1994, the MPUC issued an order approving a stipulation entered
into by the Company with the Town of Fort Fairfield and other intervenors to the
Company's  application  for approval of the  buy-out.  In the  stipulation,  the
Company agreed to continue  operation of the plant for a minimum of three years,
provided  that  certain  plant-efficiency  criteria  can be met,  while the Town
agreed to support the Company's  efforts to obtain the necessary  regulatory and
financing approvals.

     In a series of orders,  the MPUC approved the buy-out of the power-purchase
contract;  acquisition of the facility by the Company's subsequently established
subsidiary,  Aroostook Valley Electric Company (AVEC);  recovery in rates of the
cost of the buy-out and operation of the plant; and an ultimate rate decrease of
$5.6 million reflecting purchased-power savings effective December 1, 1994.

     In September  1994,  FAME approved the Company's  application  for funds to
finance the buy-out.  On October 26, 1994,  FAME issued $79.3 million of Taxable
Electric Rate  Stabilization  Revenue Notes Series 1994A (FAME notes).  FAME and
the Company  entered into a loan agreement under which the Company issued FAME a
note for  approximately  $66.4  million,  evidencing a loan in that amount.  The
proceeds of the loan,  along with $13 million of the Company's  own funds,  were
used to buy out the Fort Fairfield contract. Concurrently, the Company purchased
all of the common stock of AVEC for $2 million.  On October 26, 1994,  AVEC paid
the former  owners of the Fort  Fairfield  facility $2 million and took title to
the  facility.  In  connection  with the FAME  financing,  AVEC  granted  FAME a
mortgage on the facility. The remaining $12.9 million of FAME-notes proceeds was
placed in a capital-reserve  account. The amount in the capital-reserve  account
is equal to the highest  amount of  principal  and interest on the FAME notes to
accrue  and come due in any year the FAME  notes are  outstanding.  The  amounts
invested in the capital  reserve  account are  initially  invested in government
securities  designed to generate interest income at a rate equal to the interest
on the FAME notes.  Under the terms of the loan  agreement,  the Company is also
responsible for or receives the benefit from the interest rate  differential and
investment gains and losses on the capital reserve account.

Note 4:  Commitments and Contingencies

Construction Program

     The   Company's    plans   for   improving   and   expanding    generating,
transmission-and-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 1996 through 2000, are as follows:

(Dollars in millions)                           1996       1997-2000      Total
Type of Facilities:
Generating projects                              $13          $ 49         $ 62
Transmission                                       4            16           20
Distribution                                      30           132          162
General facilities and other                      20            70           90
Total Estimated Capital
  Expenditures                                   $67          $267         $334

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 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 has 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.

     During  1994,   the  Company   engaged  in   discussions   with  its  large
general-service  customers.  Those customers have  competitive  options that the
Company  believed  needed to be addressed by lowering its applicable  tariffs to
more competitive levels. In response to those discussions, in November 1994, the
Company filed revised tariff  schedules  lowering  prices 15 percent 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 percent for
the three years 1995 through 1997, 16 percent for 1998, and 18 percent 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 than
would have been the case if these  customers  continued to pay full retail rates
without reducing their purchases from the Company.

     However,  there are important  related 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 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.

     In July 1994,  the EPA  approved  changes  to the remedy it had  previously
selected,  the principal  change being to adjust the soil cleanup standard to 10
parts per million  from the one part per million  established  in the EPA's 1989
Record of  Decision,  on the part of the site  where  PCBs  were  found in their
highest concentration. The EPA stated that the purpose of adjusting the standard
of cleanup was to accommodate  the selected  technology's  current  inability to
reduce PCBs and other chemical components on the site to the original standard.

     In June 1995,  after  discussions  between the Company and the EPA,  design
work on the selected remedy was suspended. On July 7, 1995, the Company formally
requested that the EPA abandon that remedy for an already-designated alternative
remedy that the Company believes could result in  substantially  lower costs. On
October 10, 1995, the EPA approved the new remedy after determining that the old
remedy was no longer  feasible  or  cost-effective  at the site.  The new remedy
involves transporting the contaminated soil to a secure off-site landfill.

     The Company  believes that its share of the remaining  costs of the cleanup
under the new method could total approximately $3.5 million to $5 million.  This
estimate  is  net  of  an  agreed  partial  insurance   recovery  and  the  1993
court-ordered  contribution of 41 percent 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 $3.5 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, $3.9 million of costs incurred through December 31, 1995.

     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.  The  Company  also  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-percent  ownership  interest in the Millstone 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-percent  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  $11.6  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 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 1995, 1994, and 1993 follows:


(Dollars in                       Non-                Non-                Non-
  thousands)            union     Union      union    Union     union     Union
Service cost -
  benefits earned
  during the period    $ 2,014   $ 1,414   $ 2,367   $ 1,684  $ 2,092   $ 1,436
Interest cost on
 projected benefit
 obligation              5,653     3,889     5,469     3,816    5,355     3,691
Return on plan
  assets               (16,135)   (9,786)    2,336     1,397   (9,669)   (6,051)
Net amortization
   and deferral         10,030     6,028    (8,174)   (5,311)   4,419     2,457
Early Retirement
  Incentive Programs     3,859     3,141       992     1,457        -         -
Net Periodic
   Pension Cost        $ 5,421   $ 4,686   $ 2,990   $ 3,043  $ 2,197   $ 1,533

     Assumptions used in accounting for the non-union and union  defined-benefit
plans in 1995, 1994, and 1993 are as follows:

                                              1995        1994       1993
Weighted average discount rate                7.25%       8.25%      7.5%
Rate of increase in future compensation
   levels                                     4.5%        5.0%       5.0%
Expected long-term return on assets           8.5%        8.5%       8.5%

     The   following   table  sets  forth  the   actuarial   present   value  of
pension-benefit obligations, the funded status of the plans, and the liabilities
recognized on the Company's balance sheet at December 31, 1995, and 1994:

<TABLE>
                                                        1995                    1994
(Dollars in thousands)                                        
                                               Non-union     Union     Non-union     Union
Actuarial present value of benefit
   obligations:
<S>                                            <C>         <C>         <C>         <C>     
Vested benefit obligation ..................   $ 64,916    $ 47,948    $ 51,657    $ 39,235
Accumulated benefit obligation .............   $ 64,916    $ 47,948    $ 55,346    $ 42,247
Projected benefit obligation ...............   $ 77,939    $ 53,735    $ 68,578    $ 47,816
Plan assets at estimated market
  value (primarily stocks, bonds, and
  guaranteed annuity contracts) ............     73,973      45,061      74,905      46,067
Funded status - projected benefit obligation
  in excess of or (less than) plan assets ..      3,966       8,674      (6,327)      1,749
Unrecognized prior service cost ............     (1,940)     (1,610)     (1,294)     (1,009)
Unrecognized net gain ......................     11,309       2,530      15,564       5,690
Unrecognized (net obligation) net asset ....       (192)      1,945        (221)      2,655
Net Pension Liability Recognized in the
  Balance Sheet ............................   $ 13,143    $ 11,539    $  7,722    $  9,085
</TABLE>

Savings Plan

     The Company offers an employee  savings plan to all employees  which allows
participants  to invest  from 1 percent to 15 percent  of their  salaries  among
several alternatives.  An employer contribution equal to 60 percent of the first
5 percent of the  employees'  contributions  is  initially  invested  in Company
common stock. The Company's  contributions  to the savings-plan  trust were $1.6
million in 1995, $1.8 million in 1994, and $1.9 million in 1993.

Other Post-Employment Benefits

     In addition  to pension and  savings-plan  benefits,  the Company  provides
certain  health-care and  life-insurance  benefits for  substantially all of its
retired employees.

     The MPUC  approved a rulemaking on SFAS No. 106,  effective  July 20, 1993,
that adopts the  accrual  method of  accounting  for the  expected  cost of such
benefits   during  the   employees'   years  of  service,   and  authorizes  the
establishment  of a  regulatory  asset for the deferral of such costs until they
are  "phased-in"  for  ratemaking  purposes.  The  effect of the  change  can be
reflected  in annual  expenses  over the active  service  life of employees or a
period of 20 years, rather than in the year of adoption.

     The  MPUC  prescribes  the  maximum  amortization  period  of  the  average
remaining service life of active employees or 20 years, whichever is longer, for
the transition obligation.  Segregation in an external fund will be required for
amounts  collected in rates.  A formal  funding plan is being  developed.  Until
amounts are  funded,  no return on assets will be  reflected  in  postretirement
benefit cost.

     As a result of the MPUC order, the Company  continued to record the cost of
these  benefits  by charging  expense in the period paid ($6.7  million in 1995,
$5.5  million  in 1994,  and $6.5  million in 1993),  with the excess  over that
amount of $6.2  million in 1995,  $7.1 million in 1994 and $8.6 million in 1993,
deferred for future recovery.  Concurrent with the initial ARP price change, the
Company began to phase in the cost of SFAS No. 106 over a three-year  period, $3
million for the first year beginning  July 1, 1995.  The amounts  deferred until
that  point  are  being  amortized  over  the  same  period  as  the  transition
obligation.  A summary of the components of net periodic  postretirement benefit
cost for the plan in 1995, 1994 and 1993 follows:

(Dollars in thousands)                               1995     1994     1993
Service cost                                       $   846  $ 1,472  $ 1,429
Interest on accumulated postretirement benefit
 obligation                                          7,389    6,712    8,352
Special retirement offer                               200        -        -
Amortization of transition obligation                4,606    4,606    5,306
Amortization of prior service cost                      42        -        -
Amortization of gain                                  (188)    (171)       -
Postretirement benefits expense                     12,895   12,619   15,087
Deferred postretirement benefits expense             6,204    7,108    8,612
Postretirement Benefit Expense Recognized in the
  Statement of Earnings                            $ 6,691  $ 5,511  $ 6,475

     The  following  table sets  forth the  accumulated  postretirement  benefit
obligation,  the funded status of the plan, and the liability  recognized on the
Company's balance sheet at December 31, 1995 and 1994:

(Dollars in thousands)                                         1995       1994
Accumulated postretirement benefit obligation:
Retirees                                                    $ 87,632   $ 62,911
Fully eligible active plan participants                        4,791      6,919
Other active plan participants                                15,069     17,785
Total accumulated postretirement benefit obligation          107,492     87,615
Plan assets, at fair value                                       879        754
Accumulated postretirement benefits obligation in excess
   of plan assets                                            106,613     86,861
Unrecognized net gain (loss)                                  (2,511)    13,022
Unrecognized prior service cost                               (1,131)         -
Unrecognized transition obligation                           (78,303)   (82,909)
Accrued Postretirement Benefit Cost Recognized in the
   Balance Sheet                                            $ 24,668   $ 16,974

     The  assumed  health-care  cost-trend  rates  range from 6.4 percent to 9.3
percent for 1995,  reducing to 5.0  percent  overall  over a period of 10 years.
Rates range from 6.8 percent to 10.4  percent for 1994,  reducing to 5.0 percent
overall,  over a period of 10 years.  Rates for 1993 range from 10.2  percent to
16.1 percent, reducing to 4.5 percent overall, over a period of eight years. The
effect of a one-percentage-point  increase in the assumed health-care cost-trend
rate for each  future  year would  increase  the  aggregate  of the  service and
interest-cost components of the net periodic postretirement benefit cost by $0.8
million and the accumulated  postretirement  benefit obligation by $8.8 million.
Additional assumptions used in accounting for the postretirement benefit plan in
1995, 1994 and 1993 are as follows:

                                                1995        1994         1993
Weighted-average discount rate                  7.25%       8.25%        7.5%
Rate of increase in future compensation levels  4.50%       5.0%         5.5%

     The  Company  is  exploring   alternatives   for  mitigating  the  cost  of
postretirement  benefits  and for funding its  obligations.  These  alternatives
include  mechanisms to fund the obligation  prior to actual payment of benefits,
plan-design   changes  to  limit  future  expense   increases,   and  additional
cost-control and cost-sharing programs.

Note 6:  Capacity Arrangements

Power Agreements

     The  Company,  through  certain  equity  interests,  owns a portion  of the
generating capacity and energy production of four nuclear generating  facilities
(the Yankee  companies) and is obligated to pay its  proportionate  share of the
generating   costs,   which  include   depreciation,   operation-and-maintenance
expenses,   a  return  on  invested   capital,   and  the   estimated   cost  of
decommissioning the nuclear plants at the end of their estimated service lives.

     Pertinent  data related to these power  agreements as of December 31, 1995,
are as follows:


(Dollars in thousands)               Maine     Vermont  Connecticut     Yankee 
                                    Yankee     Yankee     Yankee        Atomic*
Ownership share                         38%         4%         6%          9.5%
Contract expiration date              2008       2012       1998        2000
Capacity (MW)                          880        531        583           -
Company's share of: Capacity
  (MW)                                 330         19         35           -
Estimated 1995 costs              $ 72,467    $ 6,480    $12,688     $ 4,022
Long-term obligations and
  redeemable preferred stock      $ 95,020    $ 6,594    $10,958     $     -
Estimated decommissioning
  obligation                      $118,586    $12,475    $23,130     $21,396
Accumulated
  decommissioning fund            $ 53,231    $ 4,833    $10,716     $10,598
* See following for discussion on Yankee Atomic.

     Under the terms of its agreements, the Company pays its ownership share (or
entitlement  share) of estimated  decommissioning  expense to each of the Yankee
companies  and records  such  payments as a cost of purchased  power.  Effective
August 16,  1988,  Maine  Yankee  Atomic  Power  Company  (Maine  Yankee)  began
collecting $9.1 million  annually for  decommissioning.  In 1994,  Maine Yankee,
pursuant to FERC authorization, increased its annual collection to $14.9 million
and reduced its return on common equity to 10.65  percent,  for a total increase
in  rates  of  approximately  $3.4  million.  The  increase  in  decommissioning
collection is based on the estimated  cost of  decommissioning  the Maine Yankee
Plant, assuming dismantling and removal, of $317 million (in 1993 dollars) based
on a 1993 external  engineering study.  Accumulated  decommissioning  funds were
$142.1 million as of December 31, 1995.  The estimated  cost of  decommissioning
nuclear  plants  is  subject  to  change  due  to  the  evolving  technology  of
decommissioning and the possibility of new legal requirements.

     The Maine Yankee Plant, like other pressurized water reactors,  experienced
degradation  of  its  steam  generator   tubes,   principally  in  the  form  of
circumferential cracking, which, until early 1995, was believed to be limited to
a  relatively  small  number  of  tubes.  During  the  refueling-and-maintenance
shutdown that commenced in early February 1995,  Maine Yankee  detected  through
new inspection  methods  increased  degradation  of the Plant's steam  generator
tubes.  Approximately  60 percent of the Plant's  17,000 steam  generator  tubes
appeared  to have  defects to some  degree.  Mitigating  the problem by plugging
additional tubes was therefore not a viable option.

     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;  this was completed in December 1995. The project caused
Maine  Yankee to incur  additional  costs during  1995,  with the Company  being
responsible  for its pro-rata share.  The Company has also incurred  substantial
incremental costs for replacement power.

     The Company's  share of the repair costs of  approximately  $10 million was
less than the $15-million  estimate  recorded during the second quarter of 1995,
resulting in a reversal of approximately $5 million of Purchased  power-capacity
expense in the fourth quarter of 1995. The earnings  impact was $0.18 per share,
net of  taxes.  Both  the  Company  and  Maine  Yankee  implemented  significant
cost-reduction measures to partially offset the additional costs. In addition to
its  share  of costs  related  to the  steam-generator  repairs,  the  Company's
incremental  replacement-power costs during the outage totaled approximately $29
million or $0.52 per share,  net of taxes,  for the twelve months ended December
31, 1995.

     With the effective termination of the reconcilable fuel-and-purchased-power
adjustment  under the ARP,  costs of  replacement  power  during a Maine  Yankee
outage are being treated like other Company expenses, i.e., subject to the ARP's
price-index  mechanism,  and are not  being  deferred  and  collected  through a
specific fuel-rate adjustment,  as under pre-1995 ratemaking.  Under the ARP, no
additional price increase other than the 2.43-percent increase effective July 1,
1995,  associated with the price index, could take effect in 1995 as a result of
the Maine Yankee outage.  Although the ARP contains provisions that could result
in rate  adjustments  based on low earnings or the  incurring  of  extraordinary
costs by the Company, neither provision affected the Company's prices in 1995.

     On January 11, 1996,  Maine Yankee began start-up  operations and was up to
90-percent   generation  levels  by  January  24,  1996.  However,  the  Plant's
operations are under review by the Nuclear  Regulatory  Commission (NRC).  Until
the NRC completes its investigation,  the Plant will operate at approximately 90
percent of its generating  capacity.  As a result,  the Company will continue to
incur  additional  replacement-power  costs for the 10  percent  of its share of
Maine Yankee energy it will not receive  until the Plant returns to  100-percent
generation levels.

     Condensed financial  information on Maine Yankee Atomic Power Company is as
follows:

(Dollars in thousands)                     1995          1994          1993
Earnings:
Operating revenues                        $205,977      $173,857      $193,102
Operating income                            18,527        16,223        16,580
Net income                                   8,571         8,573         8,980
Earnings applicable to common stock          7,057         7,014         7,376
Company's Equity Share of Net
   Earnings                              $   2,682     $   2,665     $   2,803
Investment:
Net electric property and nuclear fuel    $242,399      $254,820      $261,674
Current assets                              34,799        38,950        36,018
Deferred charges and other assets          303,760       256,140       237,125
Total Assets                               580,958       549,910       534,817
Less:
Redeemable preferred stock                  18,600        19,200        19,800
Long-term obligations                      224,185       226,491       218,839
Current liabilities                         30,904        29,210        27,887
Reserves and deferred credits              236,653       208,100       201,222
Net Assets                               $  70,616     $  66,909     $  67,069
Company's Equity in Net Assets           $  26,834     $  25,425     $  25,486


     On February 26, 1992,  the Board of  Directors  of Yankee  Atomic  Electric
Company (Yankee Atomic)  decided to permanently  discontinue  power operation at
the  Yankee  Atomic  Plant  in Rowe,  Massachusetts,  and to  decommission  that
facility.

     The  Company  relied  on  Yankee  Atomic  for less  than 1  percent  of the
Company's system capacity. Its 9.5-percent equity investment in Yankee Atomic is
approximately $2.2 million.

     On March 18, 1993, the FERC approved a settlement  agreement  regarding the
decommissioning plan, recovery of plant investment,  and all issues with respect
to prudence of the decision to discontinue operation.  The Company has estimated
its remaining  share of the cost of Yankee  Atomic's  continued  compliance with
regulatory requirements, recovery of its plant investments,  decommissioning and
closing the plant, to be approximately  $21.4 million.  This estimate,  which is
subject to ongoing  review and  revision,  has been recorded by the Company as a
regulatory asset and a liability on the accompanying consolidated balance sheet.
As part of the  MPUC's  decision  in the  Company's  1993  base-rate  case,  the
Company's current share of costs related to the deactivation of Yankee Atomic is
being recovered through rates.

     The  Company  has  approximately  a  60-percent  ownership  interest in the
jointly owned, Company-operated,  619-megawatt oil-fired W. F. Wyman Unit No. 4.
The Company also has a 2.5-percent ownership interest in the Millstone 3 nuclear
plant operated by Northeast Utilities, and receives power from its approximately
29-megawatt share of that unit's capacity.  The Company's share of the operating
costs of these units is included in the  appropriate  expense  categories in the
Consolidated  Statement of Earnings.  The  Company's  plant in service,  nuclear
fuel,   decommissioning   fund,  and  related   accumulated   depreciation   and
amortization  attributable to these units as of December 31, 1995, and 1994 were
as follows:

                                           Wyman 4             Millstone 3

(Dollars in thousands)                1995       1994        1995        1994
Plant in service, nuclear fuel and
 decommissioning fund               $116,447   $116,363    $112,033    $109,640
Accumulated depreciation and
   amortization                       59,832     56,605      36,411      32,594

Power-Pool Agreements

     The New  England  Power  Pool,  of  which  the  Company  is a  member,  has
contracted in its Hydro-Quebec Projects to purchase power from Hydro-Quebec. The
contracts entitle the Company to 85.9 megawatts of capacity credit in the winter
and 127.25  megawatts  of capacity  credit  during the  summer.  The Company has
entered  into  facilities-support  agreements  for  its  share  of  the  related
transmission  facilities.  The Company's share of the support responsibility and
of associated benefits is approximately 7 percent.

     The Company is making  facilities-support  payments on approximately  $30.6
million,  its remaining share of the  construction  cost for these  transmission
facilities  incurred through December 31, 1995. These  obligations are reflected
on  the  Company's  consolidated  balance  sheet  as  lease  obligations  with a
corresponding charge to electric property.

Non-Utility Generators

     The  Company  has  entered  into  a  number  of  long-term,  non-cancelable
contracts for the purchase of capacity and energy from  non-utility  generators.
The agreements  generally have terms of five to 30 years,  with expiration dates
ranging  from 1997 to 2021.  They  require the Company to purchase the energy at
specified prices per kilowatt-hour.  As of December 31, 1995,  facilities having
538 megawatts of capacity covered by these contracts were in-service.  The costs
of purchases  under all of these  contracts  amounted to $314.4 million in 1995,
$373.5 million in 1994, and $360.7 million in 1993.

     During  1995,  the  Company  reached  agreement  with three NUGs to buy-out
contracts or to give the Company options to restructure  their contracts through
lump-sum or periodic payments. In accordance with prior MPUC policy and the ARP,
$125 million of buy-out or restructuring  costs incurred since January 1992 were
included in Deferred Charges and Other Assets on the Company's balance sheet and
are amortized over their respective fuel savings periods.

     The Company's  estimated  contractual  obligations with NUGs as of December
31, 1995, are as follows:

(Dollars in               Amount
  millions)
1996                         $ 319
1997                           317
1998                           274
1999                           291
2000                           295
Thereafter                   3,151

Note 7:  Capitalization and Interim Financing

Retained Earnings

     Under  terms of the most  restrictive  test in the  Company's  General  and
Refunding  Mortgage  Indenture and the Company's  Articles of Incorporation,  no
dividend may be paid on the common stock of the Company if such  dividend  would
reduce  retained  earnings  below $29.6  million.  At  December  31,  1995,  the
Company's retained earnings were $51.5 million,  of which $21.9 million were not
so restricted.

Mortgage Bonds

     Substantially all of the Company's electric-utility property and franchises
are subject to the lien of the General and Refunding Mortgage.

     The Company's  outstanding  Mortgage  Bonds may be redeemed at  established
prices  plus  accrued  interest  to the date of  redemption,  subject to certain
refunding  limitations.  Bonds may also be redeemed under certain  conditions at
their principal amount plus accrued interest by means of cash deposited with the
trustee under certain provisions of the mortgage  indenture.  As of December 31,
1995, approximately $30 million was on deposit with the trustee.

Mortgage Bonds outstanding as of December 31, 1995, and 1994 were as follows:

(Dollars in thousands)
                  Series   Redeemed/maturity   Interest    1995       1994
                                               rate
Central Maine Power Company
General and Refunding Mortgage Bonds:
                    U      1998-April 15         7.54%*  $ 25,000   $ 25,000
                    S      1998-August 15        6.03      60,000     60,000
                    T      1998-November 1       6.25      75,000     75,000
                    O      1999-January 1       7 3/8      50,000     50,000
                    P      2000-January 15       7.66      75,000     75,000
                    N      2001-September 15     8.50      22,500     22,500
                    Q      2008-March 1          7.05      75,000     75,000
                    R      2023-June 1          7 7/8      50,000     50,000
Total Mortgage Bonds                                     $432,500   $432,500
*Adjustable, no adjustment during 1995 and 1994.

Limitations on Unsecured Indebtedness

     The  Company's   Articles  of   Incorporation   limit   certain   unsecured
indebtedness  that  may be  outstanding  to 20  percent  of  capitalization,  as
defined;  20 percent of defined  capitalization  amounted to $221  million as of
December 31, 1995. Unsecured indebtedness,  as defined,  amounted to $95 million
as of December 31, 1995.

     In May 1989,  holders of the  Company's  preferred  stock  consented to the
issuance of unsecured Medium-Term Notes in an aggregate principal amount of $150
million outstanding at any one time; the notes are therefore not subject to such
limitations.

Medium-Term Notes

     Under the terms of the Company's  Medium-Term Note program, the Company may
offer  Medium-Term  Notes up to an aggregate  principal  amount of $150 million.
Maturities can range from nine months to 30 years;  interest rates pertaining to
such notes are established at the time of issuance. Interest on fixed-rate notes
is payable on March 1 and September 1, while interest on floating-rate  notes is
payable on the dates indicated thereupon.

Medium-Term Notes outstanding as of December 31, 1995, and 1994 were as follows:

(Dollars in thousands)
Maturity                                     Interest rate     1995       1994
Series A:
1996-2000                                     9.35%-9.65%    $ 5,000    $ 15,000
Total Series A                                                 5,000      15,000
Series B:
1994-1995                                      4.62-6.50*          -      63,000
1996-2000                                       4.92-7.98     57,000      57,000
Total Series B                                                57,000     120,000
Series C:
1997-1999                                       7.40-7.50     30,000           -
Total Series C                                                30,000           -
Total Medium-Term Notes                                       92,000     135,000
Less: Amounts classified as short-term
  obligations                                                      -       8,000
Amounts Classified as Long-Term Obligations                  $92,000    $127,000

     * Includes $10 million of  variable-rate  notes,  with an average  interest
rate of 4.62%, and $8 million of variable-rate  notes,  with an average interest
rate of 6.35%.


Pollution-Control Facility and Other Notes

     Pollution-control  facility and other notes  outstanding as of December 31,
1995, and 1994 were as follows:

(Dollars in thousands)
Series                      Interest rate  Maturity            1995     1994
Central Maine Power
  Company:
Yarmouth Installment Notes       6 3/4%    June 1, 2002      $10,250   $10,250
Yarmouth Installment Notes       6 3/4     December 1, 2003    1,000     1,000
Industrial Development
  Authority of the State of      7 3/8     May 1, 2014        11,000    11,000
  New Hampshire Notes            7 3/8     May 1, 2014         8,500     8,500
Finance Authority of Maine        8.16     January 1, 2005    66,429    66,429
Maine Electric Power
   Company, Inc.:
Promissory Notes                Variable*  July 1, 1996        1,730     2,590
Total Pollution-Control
  Facility and Other Notes                                   $98,909   $99,769
*The average rate was 6.7% in 1995 and 4.9% in 1994.

     The bonds issued by the  Industrial  Development  Authority of the State of
New  Hampshire  are  supported  by loan  agreements  between the Company and the
Authority.  The bonds are subject to  redemption at the option of the Company at
their principal amount plus accrued interest and premium, beginning in 2001.

Capital Lease Obligations

     The Company  leases a portion of its buildings  and  equipment  under lease
arrangements, and accounts for certain transmission agreements as capital leases
using  periods  expiring  between 2006 and 2021.  The net book value of property
under  capital  leases was $35.1 million and $36.2 million at December 31, 1995,
and 1994,  respectively.  Assets  acquired  under capital leases are recorded as
electric  property at the lower of  fair-market  value or the  present  value of
future lease payments, in accordance with practices allowed by the MPUC, and are
amortized over their  contract  terms.  The related  obligation is classified as
other long-term debt. Under the terms of the lease  agreements,  executory costs
are excluded from the minimum lease payments.

     Estimated  future minimum lease payments for the five years ending December
31, 2000, together with the present value of the minimum lease payments,  are as
follows:

(Dollars in thousands)                         Amount
1996                                          $ 5,807
1997                                            5,635
1998                                            5,463
1999                                            5,291
2000                                            5,119
Thereafter                                     61,537
Total minimum lease payments                   88,852
Less: amounts representing interest            50,740
Present Value of Net Minimum Lease            $38,112
Payments

Sinking-Fund Requirements

     Consolidated sinking-fund requirements for long-term obligations, including
capital  lease  payments  and maturing  debt  issues,  for the five years ending
December 31, 2000, are as follows:

(Dollars in thousands)
            Sinking fund   Maturing debt
                                             Total
1996          $ 3,455        $ 34,000       $ 37,455
1997            8,477          25,000         33,477
1998            9,014         178,000        187,014
1999            9,657          60,000         69,657
2000           10,301          80,000         90,301

Operating Lease Obligations

     The Company has a number of operating-lease  agreements primarily involving
computer and other office  equipment,  land,  and  telecommunication  equipment.
These leases are noncancelable and expire on various dates through 2007.

     Following is a schedule by year of future minimum rental payments  required
under the operating  leases that have initial or remaining  noncancelable  lease
terms in excess of one year as of December 31, 1995:

(Dollars in thousands)          Amount
1996                            $4,364
1997                             4,112
1998                             3,922
1999                             3,352
2000                             3,190
Thereafter                       2,352

     Rent expense under all operating leases was approximately  $5,684,  $7,343,
and $5,934 for the years ended December 31, 1995, 1994 and 1993, respectively.

Disclosure of Fair Value of Financial Instruments

     The methods and  assumptions  used to estimate the fair value of each class
of financial  instruments for which it is practicable are discussed  below.  The
carrying  amounts  of cash and  temporary  investments  approximate  fair  value
because of the short maturity of these investments. The fair value of redeemable
preferred  stock and  pollution-control  facility  and  other  notes is based on
quoted  market  prices as of  December  31,  1995.  The fair value of  long-term
obligations is based on quoted market prices for the same or similar issues,  or
on the current rates  offered to the Company based on the weighted  average life
of each class of instruments.

     The estimated  fair values of the  Company's  financial  instruments  as of
December 31, 1995, and 1994 are as follows:

                                             1995                  1994
(Dollars in thousands)                 Carrying  Fair value Carrying  Fair value
                                        amount               amount
Cash and temporary investments         $ 57,677   $ 57,677  $ 58,112   $ 58,112
Redeemable preferred stock               74,528     75,117    80,000     79,476
Mortgage bonds                          432,500    435,311   432,500    374,286
Medium-term notes                        92,000     92,156   135,000    130,788
Pollution-control facility and other
  notes                                  98,909     99,694    99,769     90,873

Rights Plan

     On  September  28, 1994,  the Board of  Directors of the Company  adopted a
shareholder-rights  plan and  declared a dividend of one  common-share  purchase
right (a right) for each outstanding  share of the common stock, par value $5.00
per share, of the Company.  The dividend was distributed to the  shareholders of
record as of the close of business on October 17, 1994.

     On May 24,  1995,  the  shareholders  of the  Company  voted to  approve  a
shareholder   proposal  at  the  Company's   annual   meeting  of   shareholders
recommending  redemption of the rights and termination of the Shareholder Rights
Plan.

     On July  19,  1995,  the  Board of  Directors  of the  Company  terminated,
effective  immediately,   the  right  to  exercise  the  rights  issued  to  its
shareholders  pursuant to the Shareholder Rights Plan and ordered the redemption
of the rights.  The Board directed  payment of the redemption  price of $.01 per
right on August  28,  1995,  to holders  of record at the close of  business  on
August 14, 1995. This one-time payment amounted to $324,428.

Preferred Stock

     Preferred-stock  balances  outstanding  as of December 31, 1995,  1994, and
1993 were as follows:

                                                     
 (Dollars in thousands, except per-share Current shares           
   amounts)                               outstanding  1995     1994     1993
Preferred Stock - Not Subject to
Mandatory Redemption:
$25 par value - authorized 2,000,000
  shares; outstanding:                       None   $      -  $      - $      -
$100 par value noncallable -authorized
  5,713 shares; outstanding 6% voting        5,713       571       571      571
$100 par value callable - authorized
  2,300,000* shares; outstanding:
3.50% series (redeemable at $101)          220,000    22,000    22,000   22,000
4.60% series (redeemable at $101)           30,000     3,000     3,000    3,000
4.75% series (redeemable at $101)           50,000     5,000     5,000    5,000
5.25% series (redeemable at $102)           50,000     5,000     5,000    5,000
7 7/8% series (optional redemption after
  9/1/97, at $100)                         300,000    30,000    30,000   30,000
Preferred Stock - Not Subject to Mandatory
  Redemption                                         $65,571   $65,571  $65,571
Redeemable Preferred Stock - Subject to
  Mandatory Redemption:
$100 par value callable - authorized
  2,300,000*shares; outstanding:              None  $      -   $     - $      -
                                                           
Flexible Money Market Preferred Stock,
Series A - 7.999% (redeemable at $100)
  (450,000 shares in 1994 and 1993)        395,275    39,528    45,000   45,000
8 7/8% series (redeemable at $103.944)     350,000    35,000    35,000   35,000
Redeemable Preferred Stock - Subject to
  Mandatory Redemption                               $74,528   $80,000  $80,000

     *Total  authorized  $100 par value  callable is  2,300,000  shares.  Shares
outstanding are classified as Not Subject to Mandatory Redemption and Subject to
Mandatory Redemption.

     Sinking-fund  provisions for the 8 7/8% Series  Preferred Stock require the
Company to redeem all shares at par plus an amount equal to dividends accrued to
the  redemption  date on the basis of 70,000 shares  annually  beginning in July
1996.  The Company  also has the  non-cumulative  right to redeem up to an equal
amount of the respective  number of shares  annually,  beginning in 1996, at par
plus  an  amount  equal  to  dividends  accrued  to  the  redemption  date.  The
sinking-fund  requirement for the five-year  period ending December 31, 2000, is
$7.0 million annually beginning in 1996.

     Sinking-fund  provisions  for the Flexible  Money Market  Preferred  Stock,
Series A, 7.999%, require the Company to redeem all shares at par plus an amount
equal to dividends  accrued to the redemption date on the basis of 90,000 shares
annually  beginning in October  1999.  The Company  also has the  non-cumulative
right to redeem up to an equal number of shares  annually  beginning in 1999, at
par plus an amount equal to dividends  accrued to the redemption  date. In 1995,
the  Company  purchased  54,725  shares on the open  market  that may be used to
reduce the sinking-fund requirement in 1999.

Interim Financing and Credit Agreements

     The  Company  uses funds  obtained  from  short-term  borrowing,  primarily
through  issuance of commercial  paper backed by lines of credit with commercial
banks,  and its  revolving-credit  agreements to provide  initial  financing for
construction and other corporate purposes.

     At December 31, 1995,  the Company had a total of $130 million in unsecured
committed  bank  lines  with  commercial  banks  for the  purpose  of  providing
short-term  borrowing  capacity to back commercial paper issuance and to finance
general corporate needs.

     On  November  6, 1995,  the  Company  extended  its  $80-million  unsecured
Competitive  Advance  and  Revolving  Credit  Facility  with  several  banks and
Chemical  Bank,  as agent for the lenders,  to October 15, 1996.  The  Company's
other  $50-million  revolving  credit  facility  with several  banks also has an
expiration date of October 15, 1996. Both credit  facilities have annual fees on
unused  portion of the credit  lines of 3/8 of 1 percent  and allow for  various
borrowing options including LIBOR-priced,  ABR-priced and competitive-bid priced
loans.  Under the terms of these  agreements,  the Company had no  borrowings at
December 31, 1995, and 1994.

     As of December 31, 1995,  MEPCO had a line of credit  totaling $2.0 million
with a commercial bank to provide for its  working-capital  needs.  This line of
credit is subject to annual  review and  renewal.  Annual  fees for this line of
credit is 1/4 of 1  percent.  At  December  31,  1995,  and  1994,  there was no
short-term borrowing outstanding under the MEPCO credit line.

Note 8:  Quarterly Financial Data (Unaudited)

     Quarterly revenue variability increased after January 1, 1995, when the ARP
replaced MPUC rules prescribing different revenue allocations for energy sold in
winter versus  non-winter  months.  Twelve-month  results are unaffected by this
reporting  change.  Quarterly  financial  data for 1994  and  1993  reflect  the
seasonality  of  electric  sales and  higher  rates and  lower  contribution  to
earnings per kilowatt-hour during peak-consumption periods.

     Unaudited,  consolidated quarterly financial data pertaining to the results
of operations are shown below.

 (Dollars in thousands, except per-           Quarter ended
   share amounts)
                                March 31   June 30   September 30  December 31
1995
Electric operating revenues      $263,312   $202,584    $217,872      $232,248
Operating income                   39,361      4,052      22,169        20,277
Net income (loss)                  26,376     (8,619)     10,400         9,823
Earnings (loss) per common
  share*                              .73       (.34)        .24           .23
1994
Electric operating revenues      $241,026   $212,336    $233,543      $217,978
Operating income                   26,233     26,609      25,652        11,742
Net income (loss)                  11,416     15,307      14,083       (64,071)
Earnings (loss) per common
  share*                              .27        .39         .35         (2.06)
1993
Electric operating revenues      $236,021   $198,953    $227,383      $231,220
Operating income                   33,298     24,227      21,623        26,382
Net income                         21,573     13,702      13,561        12,466
Earnings per common share*            .62        .37         .36           .31

     *Earnings  per share are  computed  using  the  weighted-average  number of
common shares outstanding during the applicable quarter.




<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