UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934 [FEE REQUIRED]
For the fiscal year ended December 31, 1993
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934 [NO FEE REQUIRED]
For the transition period from to
Commission file number 1-5139
CENTRAL MAINE POWER COMPANY
(Exact name of registrant as specified in its charter)
Maine 01-0042740
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
83 Edison Drive, Augusta, Maine 04336
(Address of principal executive (Zip Code)
offices)
Registrant's telephone number, including area code:(207) 623-3521
Securities registered pursuant to Section 12(b) of the Act:
Name of each exchange
Title of each class on which registered
Preferred Stock, 7 7/8% Series New York Stock Exchange
Common Stock, $5 Par Value New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act:
6% Preferred Stock, $100 Par Value (Voting, Noncallable)
(Title of class)
Dividend Series Preferred Stock, $100 Par Value (Callable)
(Title of class)
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Indicate by check mark whether the registrant (1) has filed
all reports required to be filed by Section 13 or 15(d) of the
Securities Exchange Act of 1934 during the preceding 12 months
(or for such shorter period that the registrant was required to
file such reports), and (2) has been subject to such filing
requirements for the past 90 days.
Yes x No
Indicate by check mark if disclosure of delinquent filers
pursuant to Item 405 of Regulation S-K is not contained herein,
and will not be contained, to the best of the registrant's
knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K __.
State the aggregate market value of the voting stock held by
non-affiliates of the registrant. The aggregate market value of
the voting stock held by non-affiliates of the Company was
$425,195,134 on March 21, 1994 (based, in the case of the common
stock of the Company, on the last reported sale price thereof on
the New York Stock Exchange on March 21, 1994).
(APPLICABLE ONLY TO CORPORATE REGISTRANTS)
Indicate the number of shares outstanding of each of the
registrant's classes of common stock, as of the latest
practicable date. The number of shares of the Company's Common
Stock, $5 par value (being the only class of common stock of the
Company), outstanding on March 21, 1994, was 32,442,752 shares.
DOCUMENTS INCORPORATED BY REFERENCE
List hereunder the following documents if incorporated by
reference and the Part of the Form 10-K (e.g., Part I, Part II,
etc.) into which the document is incorporated: (1) Any annual
report to security holders; (2) Any proxy or information
statement; and (3) Any prospectus filed pursuant to Rule 424(b)
or (c) under the Securities Act of 1933.
Portions of the Company's Annual Report to Shareholders for
the year ended December 31, 1993 are incorporated by reference in
Part I and Part II hereof.
Portions of the definitive proxy statement for the Company's
1994 Annual Meeting of Shareholders are incorporated by reference
in Part III hereof.
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CENTRAL MAINE POWER COMPANY
INFORMATION REQUIRED IN FORM 10-K
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Item Number Page
Part I
Item 1. Business . . . . . . . . . . . . . . . . . 1
Item 2. Properties . . . . . . . . . . . . . . . . 16
Item 3. Legal Proceedings . . . . . . . . . . . . . 24
Item 4. Submission of Matters to a Vote of
Security Holders . . . . . . . . . . . . . 26
Item 4.1.Executive Officers of the Registrant . . . . 26
Part II
Item 5. Market for the Registrant's Common
Equity and Related Stockholder
Matters . . . . . . . . . . . . . . . . . . 28
Item 6. Selected Financial Data . . . . . . . . . . 28
Item 7. Management's Discussion and Analysis
of Financial Condition and Results
of Operations . . . . . . . . . . . . . . . 30
Item 8. Financial Statements and Supplementary
Data . . . . . . . . . . . . . . . . . . . 30
Item 9. Changes in and Disagreements with
Accountants on Accounting and
Financial Disclosure . . . . . . . . . . . 30
Part III
Item 10. Directors and Executive Officers of
the Registrant . . . . . . . . . . . . . . 31
Item 11. Executive Compensation . . . . . . . . . . 31
Item 12. Security Ownership of Certain Beneficial
Owners and Management . . . . . . . . . . . 31
Item 13. Certain Relationships and Related
Transactions . . . . . . . . . . . . . . . 31
Part IV
Item 14. Exhibits, Financial Statement Schedules,
and Reports on Form 8-K . . . . . . . . . . 31
Signatures . . . . . . . . . . . . . . . . . . . . . 34
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PART I
Item 1. BUSINESS.
Introduction
General. Central Maine Power Company (the "Company") is an
investor-owned Maine public utility incorporated in 1905. The
Company is engaged in the business of generating, purchasing,
transmitting, distributing and selling electric energy for the
benefit of retail customers in southern and central Maine and
wholesale customers, principally other utilities. Its principal
executive offices are located at 83 Edison Drive, Augusta, Maine
04336, where its general telephone number is (207) 623-3521.
The Company has more customers and greater revenues than any
other electric utility in Maine, serving approximately 500,000
customers in its 11,000 square-mile service area in southern and
central Maine and having $894 million in consolidated electric
operating revenues in 1993 (reflecting consolidation of financial
statements with a majority-owned subsidiary, Maine Electric Power
Company, Inc. ("MEPCO")). The Company's service area contains
the bulk of Maine's industrial and commercial centers, including
Portland (the state's largest city), South Portland, Westbrook,
Lewiston, Auburn, Rumford, Bath, Biddeford, Saco, Sanford,
Kittery, Augusta (the state's capital), Waterville, Fairfield,
Skowhegan and Rockland, and approximately 936,000 people,
representing about 77 percent of the total population of the
state. The Company's industrial and commercial customers include
major producers of pulp and paper products, producers of
chemicals, plastics, electronic components, processed food, and
footwear, and shipbuilders. Large pulp-and-paper industry
customers account for approximately 66 percent of the Company's
industrial sales and approximately 27 percent of total service-
area sales.
Cost Reduction and Restructuring. Overall demand for energy
from the Company's system increased at a rate of 0.4 percent in
1993, after an increase of 0.8 percent in 1992. The low rate of
increase can be attributed to continued weakness in the Maine
economy, significant competition from alternative fuel sources,
the effects of the Company's demand-side management programs and
other factors.
The Company's earnings per share declined from $1.85 in 1992
to $1.65 in 1993. The rate of return on common equity for 1993
was 9.77 percent compared with 11.25 percent earned in 1992. The
reduced earnings level for 1993 is attributable to higher costs,
weak sales and cost disallowances associated with two proceedings
before the Maine Public Utilities Commission ("Maine PUC", "MPUC"
or "PUC") during 1993. For a discussion of those proceedings,
see "Base Rates" and "MPUC NUG Contracts Investigation" under
"Regulation and Rates", below.
The combination of weak sales due to economic and
competitive pressures and the disappointing and inadequate base-
rate-case decision in December 1993 offers the Company no
reasonable opportunity to achieve a level of 1994 earnings near
the 1993 level or the current allowed rate of return of 10.05
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percent on common equity. Moreover, the unfavorable outlook for
the Company's near-term earnings capacity takes into account the
significant reductions in previously planned 1994 operations,
maintenance, and capital expenditures being implemented by the
Company as part of its broad cost-reduction program.
As a result of such factors, the Company's credit ratings
came under significant pressure during 1993 and early 1994 when
its senior secured debt was downgraded by all three agencies that
rate the Company's securities, one of which lowered the rating to
below investment grade. The Company's junior securities came
under even more pressure late in the year, being assigned, in
most cases, non-investment-grade ratings. The decline in the
Company's credit ratings will impair its access to the capital
markets, make the terms and conditions of borrowing more
stringent, and increase its cost of capital, and has already
substantially reduced, if not eliminated, the Company's access to
the commercial-paper markets. The credit-rating agencies cited
the stagnant economy, inadequate rate relief and pricing
flexibility, increased competition, and uncertainty of recovery
of non-utility purchased-power costs as reasons for the credit
downgrades. For a more detailed discussion of the downgrades,
see "Financing and Related Considerations" - "Rating Agency
Actions", below.
After review of the Company's overall financial position and
outlook, including the impacts associated with the MPUC's rate-
case order and the expected near-term revenue impacts of weak
sales, the Company's Board of Directors voted on December 15,
1993, to reduce the quarterly common-stock dividend from 39 cents
to 22.5 cents per share. The dividend reduction is part of a
broad-based cost-reduction and restructuring program designed to
stabilize the Company's rates and enhance its financial
condition. The program is composed of three major initiatives:
(1) reduce the Company's operating costs while maintaining
appropriate levels of service; (2) reduce the Company's largest
external expense, non-utility power costs; and (3) work with
regulators on innovative, competitive new pricing and service
options.
The first step in implementing the cost-reduction strategy
was to restructure the Company's organization along functional
lines and eliminate 225 full-time-equivalent jobs, or
approximately 10 percent of the Company's work-force, which was
accomplished in March 1994. In addition, the Company's operating
budget for 1994 was cut $22 million, or 12 percent, from
previously planned levels, and the 1994 capital budget for plant,
equipment, and conservation programs by $14 million, or 19
percent, from previously planned levels.
The second component of the plan, reducing the cost of non-
utility power, stresses continued efforts to renegotiate, buy out
or terminate high-cost purchased power contracts. It also
includes support for Maine legislative action on bills that could
have the effect of reducing such costs.
The final segment includes continuing efforts to achieve
changes in regulation that would redefine the basis for overall
price changes and provide flexibility in setting specific prices
and in the acquisition and use of resources. As detailed below
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under "Regulation and Rates" - "Rate Stability Plan", the Company
has indicated interest in pursuing a modified price-cap approach
to the regulation of its electric rates and, consistent with the
terms of the PUC's December 1993 order in the base-rate case, has
been engaged in discussions with rate-case intervenors as to the
structure of such a plan. The Company expects to file a rate-
stability plan with the PUC sometime in the first half of 1994.
The Company is committed to its cost-reduction and
restructuring program. It believes that its ability to restore
earnings to competitive levels and improve its overall financial
health is closely tied to the success of the program.
The following topics are discussed under the general heading
of Business. Where applicable, the discussions make reference to
the various other Items of this Report. In addition, for further
discussion of information required to be furnished in response to
this Item, see pages 1 through 49 of Exhibit 13-1 hereto (the
Company's Annual Report to Shareholders for the year ended
December 31, 1993), which pages are hereby incorporated herein by
reference.
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Topic Page
Non-utility Generation . . . . . . 3
Maine Yankee Atomic Power Company
Competition . . . . . . . . . . . . 4
Regulation and Rates . . . . . . . 5
Financing and Related
Considerations . . . . . . . . . 11
Environmental Matters . . . . . . . 13
Water Quality Control . . . . . . 14
Air Quality Control . . . . . . . 14
Hazardous Waste Regulations . . . 14
Electromagnetic Fields . . . . . 15
Capital Expenditures . . . . . . 15
Employee Information . . . . . . . 15
</TABLE>
Non-utility Generation
The Company has been an industry leader in developing
supplies of energy from non-utility generators, including
cogeneration plants and small power producers. These sources
supplied 4.0 billion kilowatt-hours of electricity to the Company
in 1993, representing 40.2 percent of total generation, an
increase from 38.2 percent in 1992. The Company expects to
obtain approximately 44 percent of its energy from this source in
1994. The Company's contracts with non-utility generators,
however, which were entered into pursuant to 1978 federal
legislation and vigorous state implementation thereof, have
contributed the largest part of the Company's increased costs in
recent years. This has caused the Company to pursue re-
negotiations or buyouts of such contracts wherever practicable.
For further discussion of independent power production, see Item
2, Properties, "Non-utility Generation". For a discussion of a
regulatory proceeding involving the Company's management of its
contracts with non-utility generators, see "Regulation and Rates"
- "MPUC NUG Contracts Investigation", below.
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Maine Yankee Atomic Power Company
The Company owns a 38 percent stock interest in Maine Yankee
Atomic Power Company ("Maine Yankee"), which owns and operates a
nuclear generating plant in Wiscasset, Maine (the "Maine Yankee
Plant"). The Maine Yankee Plant has been in commercial operation
since 1972 and has consistently produced power at a cost among
the lowest in the country for nuclear plants. In 1993 the Maine
Yankee Plant produced 5.7 billion kilowatt-hours of electric
power, the highest total ever for a year that included a
scheduled refueling and maintenance shutdown, at an average cost
of 3.4 cents per kilowatt-hour. The average capacity factor for
the Maine Yankee plant in 1993 was 76 percent. For further
discussion of Maine Yankee, see "Regulation and Rates", below,
and Item 2, Properties, "Existing Facilities".
Competition
In October 1992 the United States Congress enacted the
Energy Policy Act of 1992 (the "Policy Act"). The Policy Act was
designed to encourage competition among electric utility
companies, improve energy resource planning by utility companies,
and encourage the development of alternative fuels and sources of
energy. The Policy Act provides for, among other things, (1)
enhanced access to electric transmission to promote competition
for wholesale purchasers and sellers, (2) statutory reforms to
encourage utility participation in the formation of exempt
wholesale generators, (3) tax credits for electricity generation
from renewable energy sources, (4) tax incentives for the use of
alternative fuels, and (5) required fleet vehicle conversion to
alternative fuels. The Policy Act has been a significant factor
in creating new areas of competition for the Company.
The Company is facing competition in several areas of its
traditional business and anticipates that the new competition
will continue to place pressure on both sales and the price the
Company can charge for its product. Alternative fuels and pre-
Policy Act regulation that had restricted competition from
outside of the Company's service territory have expanded
customers' energy options. As a result, the Company has been
involved in a number of negotiations with certain of its
customers and will continue to pursue retention of its customer
base. This increasingly competitive environment has resulted in
the Company's entering into contracts with two of its wholesale
customers, as well as with certain of its industrial and
commercial customers, to provide their energy needs at prices and
margins lower than the current averages. For a discussion of the
potential loss of the largest wholesale customer of the Company
to an out-of-state supplier, see "Regulation and Rates" -
"Potential Loss of Wholesale Customer", below.
In addition to negotiating a number of special agreements
with large customers, the Company is also pursuing with the MPUC
alternative pricing mechanisms that would allow the Company the
flexibility to modify the price of its product in certain
instances, when the competitive alternatives could result in the
loss of a significant end use of electricity. In its preliminary
discussions, the MPUC has indicated there may be instances in
which the ability of the Company to adjust its price in response
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to competitive pressures is advisable. In February 1994, the
MPUC approved a specific competitive-pricing plan under which the
Company will operate with respect to residential water-heating
customers. The Company believes it may be granted the authority
to develop additional market-responsive rates in certain
circumstances in the future. For a discussion of relevant PUC
orders, see "Regulation and Rates" - "Rate Design", below.
Regulation and Rates
The Company is subject to the regulatory authority of the
PUC as to retail rates, accounting, service standards, territory
served, the issuance of securities maturing more than one year
after the date of issuance, certification of generation and
transmission projects and various other matters. The Company is
also subject as to some phases of its business, including
licensing of its hydroelectric stations, accounting, rates
relating to wholesale sales (which constitute less than one
percent of operating revenues) and to interstate transmission and
sales of energy and certain other matters, to the jurisdiction of
the Federal Energy Regulatory Commission ("FERC") under Parts I,
II and III of the Federal Power Act. Other activities of the
Company from time to time are subject to the jurisdiction of
various other state and federal regulatory agencies.
The Maine Yankee Plant and the other nuclear facilities in
which the Company has an interest are subject to extensive
regulation by the federal Nuclear Regulatory Commission ("NRC").
The NRC is empowered to authorize the siting, construction and
operation of nuclear reactors after consideration of public
health, safety, environmental and antitrust matters. Under its
continuing jurisdiction, the NRC may, after appropriate
proceedings, require modification of units for which construction
permits or operating licenses have already been issued, or impose
new conditions on such permits or licenses, and may require that
the operation of a unit cease or that the level of operation of a
unit be temporarily or permanently reduced.
The United States Environmental Protection Agency ("EPA")
administers programs which affect all of the Company's thermal
generating facilities as well as the nuclear facilities in which
it has an interest. The EPA has broad authority in administering
these programs, including the ability to require installation of
pollution-control and mitigation devices. The Company is also
subject to regulation by various state and local authorities with
regard to environmental matters and land use. For further
discussion of environmental considerations as they affect the
Company, see "Environmental Matters", below.
Under the Federal Power Act, the Company's hydroelectric
projects (including storage reservoirs) on navigable waters of
the United States are required to be licensed by the FERC. The
Company is a licensee, either by itself or in some cases with
other parties, for 27 FERC-licensed projects, some of which
include more than one generating unit. Thirteen licenses were
scheduled to expire in 1993, one in 1997, and thirteen after
2000. The Company filed all applications for relicensing the
projects whose licenses were scheduled to expire in 1993 and has
been authorized to continue to operate those projects pending
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action on relicensing by the FERC. New licenses may contain
conditions that reduce operating flexibility and require
substantial additional investment by the Company.
The United States has the right upon or after expiration of
a license to take over and thereafter maintain and operate a
project upon payment to the licensee of the lesser of its "net
investment" or the fair value of the property taken, and any
severance damages, less certain amounts earned by the licensee in
excess of specified rates of return. If the United States does
not exercise its statutory right, the FERC is authorized to issue
a new license to the original licensee, or to a new licensee upon
payment to the original licensee of the amount the United States
would have been obligated to pay had it taken over the project.
The United States has not asserted such a right with respect to
any of the Company's licensed projects.
Base Rates. On March 1, 1993, the Company filed a request
with the MPUC for a $95-million increase in base rates. The
major components of the request were (1) compensating for
lower-than-forecasted sales, (2) increased operation and
maintenance expenses, (3) increased operating costs of the four
operating nuclear plants in which the Company owns interests, (4)
property additions and transmission, distribution and other
improvements, (5) energy-management program costs and, (6) the
expiration of the flow-through of certain tax benefits.
Ultimately, the Company reduced the amount of its base-rate
request from $95 million to $83 million. The decrease was the
result of lower estimates of 1994 operation and maintenance
expenses, further reductions in the Company's cost of capital, a
decrease in the level of anticipated expenditures for energy
management programs and the change in the federal income-tax rate
from 34 percent to 35 percent.
On December 14, 1993, the MPUC issued its order in the
proceeding. The MPUC's analysis indicated a need for additional
revenues of $51.5 million, yet found the Company to be entitled
to a net revenue increase of only $26.2 million. The Commission
found a total cost of capital of 8.52 percent and a cost of
equity of 10.05 percent, after deducting a one-half percent (.5%)
return-on-equity penalty established by the MPUC in a 1993
investigation of the Company's management of certain independent
power-producer contracts. See "MPUC NUG Contracts Investigation"
below, for further discussion of this investigation. To arrive
at its revenue-requirement conclusion, the MPUC deducted $25.3
million "to adjust for management inefficiency" after finding the
Company's performance in the areas of management efficiency and
cost-cutting to have been "inadequate", based largely on the
recommendations contained in a management audit of the Company
conducted by a consultant retained by the MPUC.
The Company strongly disagrees with the MPUC's
management-inefficiency finding and with the resulting deduction
of nearly one-half the revenue increase to which the Commission
itself found the Company to be otherwise entitled using
traditional ratemaking principles. The Company filed an appeal
of the base-rate order with the Maine Supreme Judicial Court.
The Company cannot, however, predict the result of that appeal.
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Rate-Stability Plan. In connection with the base-rate
proceeding, on July 21, 1993, the Company filed an alternative
rate proposal designed to promote stability in the Company's
rates. The proposal consisted of a combination of pricing and
regulatory changes that would, among other things, limit future
rate increases to annual changes based on the rate of inflation
and mandated costs, and revise existing regulatory rules and
policies to allow the Company to adjust prices more rapidly in
response to customer needs and competitive factors.
In its December 14, 1993, base-rate order, the MPUC ordered
that a follow-up proceeding be held to implement by mid-1994 a
rate-stability plan along the lines discussed in the order. The
MPUC encouraged the Company and the parties wishing to
participate in the proceeding to work together to develop a plan
containing price-cap, profit-sharing, and pricing-flexibility
components. The MPUC also directed that the initial plan have a
duration of five years, subject to a brief annual proceeding to
implement any applicable rate changes, and a detailed review at
the end of the fourth year to evaluate the performance of the
plan and initiate necessary changes. Participants in the
rate-stability plan proceeding have prepared price-cap proposals
in response to the MPUC's order and regular discussions are being
held. The Company cannot predict the outcome of this process or
the MPUC's ultimate decision on a rate-stability plan.
Fuel Clause Adjustment. The Company's electric sales are
subject to a fuel adjustment clause that enables the Company to
recover from its customers both fuel costs and the increasing
amounts of the fuel component of purchased-power costs, including
non-utility generation. The Company also collects carrying costs
on unbilled fuel and pays interest on fuel-related over-
collections.
In accordance with a January 1993 ratemaking stipulation,
the MPUC approved, as part of the $40 million July 1993 revenue
increase, $17 million to reduce deferred fuel-clause balances.
Earlier, in July 1992, the MPUC issued an order authorizing an
increase, effective September 1, 1992, in the Company's fuel cost
adjustment of $13.2 million of the $38.7 million requested by the
Company, along with the Electric Revenue Adjustment Mechanism
("ERAM") and demand-side-management incentives discussed below
under "Incentive Regulation". The orders extended the smoothing
approach that had begun in 1988, resulting in unrecovered fuel
and purchased-power costs being deferred for future recovery.
Rate Design. Effective in December 1991, the Company
implemented a rate-design order from the PUC that was intended to
realign customer class revenues and specific rate components more
closely with marginal costs. These rate design changes, which
raised or lowered some customers' rates by as much as eight
percent, were intended to reallocate revenues from customer
classes, but not to produce any change in aggregate revenues for
the Company. In February 1992, the Company filed a request with
the PUC to re-examine several rate-design changes in response to
concerns regarding the impact of such changes on some classes of
residential customers. After considering a number of proposals
by the Company and other parties, the PUC reduced the highest
winter time-of-use rates by a small percentage from the prior
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winter's rates, effective in December 1992. The increases in on-
peak rates in December 1991 resulting in part from the rate-
design changes have caused a significant number of the Company's
residential electric heating customers and water heating
customers to convert to other fuel sources.
On February 18, 1994, the PUC issued its order in an
investigation of the Company's resource planning, rate structure,
and avoided cost that was initiated in December 1992. The
primary purpose of the investigation was to examine the Company's
"long-term costs and their relationships to usage and prices, and
to specify any implications for CMP's resource planning
activities and general rate structure policies." In its order
the PUC found, among other things, (1) "no reason to encourage
electric utilities to pursue broad promotion of load growth . . .
absent a clear and convincing demonstration that ratepayers as a
group would benefit from such efforts"; (2) "that CMP's proposed
strategy of encouraging marginal usage through broad adoption of
declining block rates is not cost-justified . . ." but the PUC
said it would "continue to encourage proposals for targeted,
short-term rates that are carefully designed to retain movable
load"; and (3) the PUC reaffirmed its "existing policy of
encouraging narrowly-focused economic incentive rates for
particular kinds of customers, when it can be shown that other
ratepayers will not be harmed". The PUC also indicated that it
would initiate a rulemaking proceeding to determine how "special
rates for customers with competitive alternatives should best
reflect the utility's obligation to serve, particularly with
respect to backup and maintenance rates . . .." The Company
cannot predict what changes it will ultimately be permitted to
implement in the areas of resource planning, rate structure, and
avoided cost.
MPUC NUG Contracts Investigation. On October 28, 1993, in
connection with an investigation of the Company's management of
independent power-producer contracts, the MPUC issued an order
finding that the Company had been unreasonable and imprudent in
its management of two independent power-producer contracts and
indicated that it would reduce the Company's allowed rate of
return on equity by 0.5 percent in the then-pending base-rate
case (approximately $4 million, before income taxes, over a
12-month period) and also directed the Company to charge against
deferred fuel-cost balances approximately $4.1 million of
payments from power providers that had previously been credited
against purchased-power capacity costs, unless the Company could
demonstrate that the crediting was proper. The Company recorded
a reserve totalling $4.1 million during the third quarter of
1993, reflecting the impact of the order. Finally, the MPUC
announced that it would review in the future the Company's
administration and management of certain power-purchase contracts
for purchases of ten megawatts or more.
On December 20, 1993, the Chief Justice of the Maine Supreme
Judicial Court (the "Court"), acting on the Company's request,
issued an order staying the effectiveness of the 0.5-percent
return-on-equity penalty pending final resolution of the
Company's appeal of the October 28, 1993, MPUC order to the
Court. In addition, the Court ordered that if the Company should
not prevail on its appeal, it would be required to refund any
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revenues collected as a result of the stay order, with interest.
Finally, the Court ordered an expedited hearing on the appeal,
scheduling oral argument before the Court for March 1994.
On February 3, 1994, the MPUC filed a motion to dismiss with
the Court, stating that by order dated February 3, 1994, the
Commission had reopened and reconsidered its October 28, 1993
decision. As a result of its reconsideration, the MPUC decided
to vacate the return-on-equity penalty conditioned on either the
Company's acquiescence in the MPUC's jurisdiction or a finding by
the Court that the MPUC had retained jurisdiction, and to
consider alternative remedies. The MPUC argued that because of
its February 3 order the Company's appeal of the return-on-equity
penalty should be dismissed as moot. The Chief Justice declined
to dismiss the appeal and added the jurisdictional question to
the issues to be determined by the Court.
The MPUC, in its February 3, 1994 order, indicated that an
alternative under consideration by the MPUC "appears to present
an opportunity to insulate ratepayers sufficiently from CMP's
imprudence...," yet also noted, "We do not decide at this time
that such a remedy . . . will be adopted." The order indicated
an intent to seek additional information on the issue of annual
differences between the contract rates and avoided costs.
The case was argued on March 17 and a decision is expected
by early summer 1994. The Company cannot predict the outcome of
the appeal on either the issue of jurisdiction or the merits of
the return-on-equity penalty, or the outcome if remanded to the
PUC, including any subsequent appeal of any alternative remedy.
Incentive Regulation. In May 1991 the MPUC ordered a
three-year trial of the ERAM, which was a fundamental change in
the way the Company's revenues were treated and set new
incentives for effective utility-sponsored energy management. In
July 1992 the MPUC issued an order authorizing the Company to
begin collecting $7.8 million, which was only a portion of the
$26.2 million of ERAM revenues accrued in its first year, and an
energy-management incentive of $1.5 million, beginning in
September 1992. Approximately $18.4 million of ERAM revenues
accrued in the 12 months beginning in March 1991 were therefore
carried over to the 1993 ERAM filing.
In January 1993, the MPUC approved a stipulation that
resolved several outstanding issues, including those in the
Company's ERAM proceeding. The stipulation permitted recovery of
accrued ERAM balances in accordance with the terms of a Financial
Accounting Standards Board Emerging Issues Task Force consensus.
The stipulation also authorized recovery of the costs associated
with buy-outs by the Company of certain purchased-power contracts
and requested the MPUC to grant an increase in the Company's
fuel-cost adjustment. The stipulation also approved an
accounting order permitting the Company to accelerate the
flow-back of $5.9 million of certain deferred taxes associated
with prior losses on reacquired debt. For 1992, the stipulation
placed a limit of 11.25 percent on the Company's allowed rate of
return on equity. Earnings in excess of the limit, up to
approximately $10 million (the revenue requirement of the tax
benefits), were applied on a monthly basis to reduce 1993 ERAM
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accruals. In addition, approximately $317,000 of income, net of
income taxes, in excess of the $10 million, was used to fund a
portion of 1993 operation-and-maintenance expenses.
The January 1993 stipulation also reduced the amount of ERAM
accruals from January 1993 through November 1993 by $591,000 per
month. The ERAM program continued until December 1, 1993, which
was the effective date of the new base rates resulting from the
Company's 1993 base-rate proceeding. As contemplated by the
terms of the stipulation, the MPUC subsequently approved a
revenue increase of $40 million, effective July 1, 1993, which
included, among other things, $21.2 million toward recovery of
deferred ERAM revenues.
As of December 31, 1993, the Company had collected
approximately $19.2 million of the ERAM revenues; the unbilled
ERAM balance at that time was approximately $50.5 million.
Potential Loss of Wholesale Customer. On July 28, 1993, the
Town of Madison Electric Works (Madison), a wholesale customer of
the Company, announced that it had selected a competitive bid
from Northeast Utilities (NU) and was entering negotiations for
NU to become its wholesale electric supplier for a period of up
to ten years. The Company's bid was rejected by Madison for
being submitted after the ten-day bidding period. NU, a
Connecticut-based holding company with substantial excess
generating capacity, had submitted a bid to provide up to 45
megawatts of capacity at a rate that would initially be well
below the Company's existing rates. Substantially all of the 45
megawatts would supply a large paper-making facility in Madison's
service territory that has been served directly by the Company
under a special service agreement with Madison during the last 12
years. The Company understands that Madison intends to start
taking power from NU in late 1994 for that portion required to
serve the paper-making facility and in late 1996 for its
remaining requirements. Losing Madison as a wholesale customer
would reduce the Company's non-fuel revenues by approximately $11
million annually when fully in effect, based on current rates and
1993 sales, minus any amounts paid to the Company for
transmission of the NU power from the New Hampshire border.
The Company intervened in opposition to Madison's petition
to the MPUC for approval of its contract with NU, but cannot
predict what action the MPUC will take on the petition.
The Company has also filed with the FERC for approval of a
contract to provide transmission service for Madison over the
Company's system. The filing seeks recovery of the full cost of
providing transmission service as well as compensation for any
"stranded investment" of the Company in facilities that would no
longer be needed to serve the Madison area.
FERC Power Contracts Settlement Agreement. In August 1991,
the FERC issued an order requiring the Company to revise its
rates to a level reflecting the filed cost of service associated
with each of 14 contracts for non-territorial sales, rather than
the negotiated market-based levels. In 1991 the Company
established a $4.5 million reserve to reflect refunds associated
with some of the contracts. In 1992 the Company reversed
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approximately $1.9 million of that reserve as a result of a
settlement agreement that required the Company to refund
approximately $2.6 million related to that issue.
After rejection by the FERC of the Company's continuing
claims of disparate treatment based on its having been ordered to
make refunds while several similarly situated utilities were not,
on September 29, 1993, the FERC rescinded the Company's
obligation to make refunds. In making its decision, the FERC
invoked its "equitable discretion" and agreed that, based on its
having granted a general amnesty from refunds to other utilities,
circumstances had changed so dramatically since its approval of
the Company's 1992 refund settlement that it would be "unfair to
continue to single out Central Maine for refunds." The FERC
order allowed the utilities that had shared the $2.6 million in
refunds to repay the Company, with interest, over a 24-month
period. The utility that received the major share of the amount
refunded by the Company requested reconsideration of the FERC
rescission order. The Company recorded approximately $3.0
million of income during the third quarter of 1993, reflecting
the refund including interest. On March 22, 1994, the parties
submitted to the FERC a settlement agreement which, if approved,
would require the Company to deliver a combination of cash and
power sales having an aggregate value of up to $1.2 million.
Financing and Related Considerations
During 1993, the Company met its capital requirements
(including the refunding of several outstanding securities
issues) from a variety of sources, including the issuance of
additional General and Refunding Mortgage Bonds, utilization of
its unsecured Medium-Term Note Program and its Dividend
Reinvestment and Common Stock Purchase Plan, short-term unsecured
debt borrowings, including commercial paper, and internally
generated funds.
Financings. During 1993, the Company continued its program
of refinancing its outstanding debt to take advantage of lower
interest rates. The Company issued $75 million of Series Q 7.05%
Due 2008 General and Refunding Mortgage Bonds in March, $50
million of Series R Bonds, 7 7/8% Due 2023 in May, $60 million of
Series S Bonds, 6.03% Due 1998 in August, and $75 million of
Series T Bonds, 6.25% Due 1998 in November.
None of those series has a sinking fund, and the Series S
and Series T Bonds are not callable at the option of the Company.
The Series Q and Series R Bonds are not callable at the option of
the Company prior to March 1, 1998, and June 1, 2003,
respectively, except under limited circumstances.
The Company redeemed its $100-million Series I Bonds, 9 1/4%
Due 2016 in the second quarter of 1993, $50 million of its Series
M Bonds, 9.18% Due 1995 in the third quarter of 1993, and $27.5
million of its Series N Bonds, 8.50% Due 2001 in the fourth
quarter of 1993. Premiums paid on redemptions totalled $9.6
million.
These financing and refinancing transactions reduced the
annual cost of the Company's mortgage debt to 7.1 percent at
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December 31, 1993, from 8.5 percent at December 31, 1992.
During the year, the Company also raised approximately $25.5
million of additional capital through its Dividend Reinvestment
and Common Stock Purchase Plan, resulting in the issuance of 1.2
million new shares of common stock. Effective in January 1994,
however, the Company elected to authorize an agent to purchase
outstanding shares for this plan on the open market, rather than
issue new shares. As a result, the Company's current plans call
for no additional shares of common stock to be issued for the
next several years.
In 1993, the Company issued $48 million of notes under its
$150-million medium-term note program at an average interest rate
of 4.8 percent and an average life of 2.9 years. Notes in the
amount of $26.5 million matured during the year, increasing the
total outstanding medium-term notes at year-end 1993 to $146.0
million from $124.5 million at year-end 1992.
The proceeds from the debt and equity issuances were used
for general corporate purposes, which included financing
construction and energy-management projects, retiring or
refunding outstanding securities, repaying short-term debt, and
buying out purchased-power contracts.
Rating Agency Actions. Beginning in late August 1993, three
major securities-rating agencies lowered their ratings on the
Company's outstanding debt and preferred stock on a number of
occasions.
In October 1993, Duff & Phelps Credit Rating Co. lowered the
Company's fixed income ratings as follows: General and Refunding
Mortgage Bonds from "BBB+" to "BBB-"; unsecured notes from "BBB"
to "BB+"; and preferred stock from "BBB" to "BB-."
Standard & Poor's Corp. ("S&P") announced in late October
1993, the application of more stringent financial-risk standards
to the investor-owned utility industry to reflect S&P's view of
mounting business risk. S&P stated that it believed the
industry's "credit profile" was being "threatened chiefly by
intensifying competitive pressures but also by sluggish demand
expectations, slow earnings growth prospects, high common
dividend payout, environmental cost pressures, and nuclear
operating cost and decommissioning challenges." As a result, S&P
revised rating outlooks for about one-third of the industry and
placed the Company and several other utilities on "CreditWatch
with negative implications."
On January 5, 1994, S&P removed the Company's ratings from
"CreditWatch" and lowered them again as follows: senior secured
debt to "BB+" from "BBB-"; senior unsecured debt to "BB-" from
"BB+"; preferred stock to "B+" from "BB"; and commercial paper to
"B" from "A-3." In addition, S&P assigned its preliminary "BB+"
senior-secured-debt rating to the Company's $150-million General
and Refunding Mortgage Bonds previously registered with the
Securities and Exchange Commission as a "shelf" registration.
On January 13, 1994, Moody's Investors Service ("Moody's")
lowered its rating on the Company's preferred stock to "ba2" from
"baa3" and its short-term debt rating for the Company's
commercial paper to "Prime-3" from "Prime-2." At the same time,
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Moody's confirmed its ratings on the Company's General and
Refunding Mortgage Bonds at "Baa2", unsecured medium-term notes
and pollution control revenue bonds at "Baa3", and the Company's
Securities and Exchange Commission "shelf" registration for
$150,000,000 of General and Refunding Mortgage Bonds to
"(P)Baa2."
The rating agencies explained that the downgrades primarily
reflected the MPUC's "unsupportive" base-rate decision, which in
their opinion will not allow the Company's financial parameters,
adjusted for off-balance-sheet obligations, to remain at
acceptable levels for a utility with a "below-average" business
position. In addition, the rating agencies expressed the belief
that the Company's business position also reflected a depressed
Maine economy, a large industrial-customer base, difficulty in
materially reducing its significant purchased-power obligations,
relatively high production costs, increasing rate pressures, and
a high dividend payout.
Deferred Costs. Over the past few years, the amount of the
Company's deferred charges and regulatory assets has increased
under the regulatory policies of the MPUC. The Securities and
Exchange Commission has periodically considered issues regarding
the proper accounting treatment of charges deferred by regulatory
policy. As a result, the Company has regularly requested the
MPUC to issue accounting and ratemaking orders to provide
appropriate authority to comply with changing accounting
requirements and to allow the Company to appropriately reflect
the amounts as deferred charges and regulatory assets. In recent
years, the Company received such orders with respect to issues in
the 1991 Early Retirement Incentive Program, ERAM,
purchased-power contract buy-outs, environmental-site cleanup
costs, taxes on losses on reacquired debt, and accounting for
postretirement benefits and income taxes pursuant to the newly
issued accounting standards. The Company will monitor situations
that result in deferred charges and regulatory assets and will
seek appropriate regulatory approvals.
For further discussion of financing considerations affecting
the Company, see the information incorporated by reference in
Item 7, Management's Discussion and Analysis of Financial
Condition and Results of Operations, and Item 8, Financial
Statements and Supplementary Data (Notes 4 and 7 of Notes to
Financial Statements), below.
Environmental Matters
In connection with the operation and construction of its
facilities, various federal, state and local authorities regulate
the Company regarding air and water quality, hazardous wastes,
land use, and other environmental considerations.
Such regulation sometimes requires review, certification or
issuance of permits by various regulatory authorities. In
addition, implementation of measures to achieve environmental
standards may hinder the ability of the Company to conduct
day-to-day operations, or prevent or substantially increase the
cost of construction of generating plants, and may require
substantial investment in new equipment at existing generating
plants. Although no substantial investment is presently
necessary, the Company is unable to predict whether such
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investment may be required in the future.
Water Quality Control. The federal Clean Water Act provides
that every "point source" discharger of pollutants into navigable
waters must obtain a National Pollutant Discharge Elimination
System ("NPDES") permit specifying the allowable quantity and
characteristics of its effluent. Maine law contains similar
permit requirements and authorizes the state to impose more
stringent requirements. The Company holds all permits required
for its plants by the Clean Water Act, but such permits may be
reopened at any time to reflect more stringent requirements
promulgated by the EPA or the Maine Department of Environmental
Protection ("DEP"). Compliance with NPDES and state requirements
has necessitated substantial expenditures and may require further
substantial expenditures in the future.
Air Quality Control. Under the federal Clean Air Act, as
amended, the EPA has promulgated national ambient air quality
standards for certain air pollutants, including sulfur oxides,
particulate matter and nitrogen oxides. The EPA has approved a
Maine implementation plan prepared by the DEP for the achievement
and maintenance of these standards. The Company believes that it
is in compliance with the requirements of the Maine plan. The
Clean Air Act also imposes stringent emission standards on new
and modified sources of air pollutants. Maintaining compliance
with more stringent standards, if they should be adopted, could
require substantial expenditures by the Company. Although 1990
amendments to the Clean Air Act require, among other things, an
aggregate reduction of sulfur dioxide emissions by United States
electric utilities by the year 2000, the Company believes that
the amendments will not have a material adverse effect on the
Company's operations.
In addition, a state regulation restricts the sulfur content
of the fuel oil burned in Maine to 2.0 percent. However, all oil
burned at William F. Wyman Unit No. 4 in Yarmouth, Maine, is
required by license to have a sulfur content not exceeding 0.7
percent, and the other three units at Wyman Station are required
to have a sulfur content not exceeding 1.5 percent when Wyman
Unit No. 4 is in operation. The Company believes that it will
continue to be able to obtain a sufficient supply of oil with the
required sulfur contents, subject to unforeseen events and the
factors influencing the availability of oil discussed under Item
2, Properties, "Fuel Supply", below. The operation of the
Company's present fuel adjustment clause permits it to recover
any additional cost of such fuel from its customers upon review
by the MPUC.
Hazardous Waste Regulations. Under the federal Resource
Conservation and Recovery Act of 1976, as amended ("RCRA"), the
generation, transportation, treatment, storage and disposal of
hazardous wastes are subject to EPA regulations. Maine has
adopted state regulations that parallel RCRA regulations, but in
some cases are more stringent. The notifications and
applications required by the present regulations have been made.
The procedures by which the Company handles, stores, treats, and
disposes of hazardous waste products have been revised, where
necessary, to comply with these regulations and with more
stringent requirements on hazardous waste handling imposed by
amendments to RCRA enacted in 1984.
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For a discussion of a matter in which the Company has been
named a potentially responsible party by the EPA with respect to
the disposal of certain toxic substances, see Item 3, Legal
Proceedings, under the caption "PCB Disposal", below.
Electromagnetic Fields. Public concern has arisen in recent
years as to whether electromagnetic fields associated with
electric transmission and distribution facilities and appliances
and wiring in buildings ("EMF") contribute to certain public
health problems. This concern has resulted in some areas in
opposition to existing or proposed utility facilities, requests
for new legislative and regulatory standards, and litigation. On
the basis of the scientific studies to date, the Company believes
that no persuasive evidence exists that would prove a causal
relationship or justify substantial capital outlays to mitigate
the perceived risks. Although the Company has suffered no
material effect as a result of this concern, the Company supports
further research on this subject and since 1988 has been
compiling and disseminating through a regular periodic
publication information on all related studies and published
materials as a central clearing house for such information, as
well as providing such information to its customers. The Company
intends to continue to monitor all significant developments in
this field.
Capital Expenditures. The Company estimates that its
capital expenditures for environmental purposes for the five
years from 1989 through 1993 totaled approximately $22.9 million.
The Company cannot presently predict the amount of such
expenditures in the future, as such estimates are subject to
change in accordance with changes in applicable environmental
regulations.
Employee Information
A local union affiliated with the International Brotherhood
of Electrical Workers (AFL-CIO) represents operating and
maintenance employees in each of the Company's operating
divisions, and certain office and clerical employees. At
December 31, 1993, the Company had 2,103 full-time employees, of
whom approximately 46 percent are represented by the union. At
the end of 1990 the Company had 2,322 full-time employees. The
reduction in the number of full-time employees from 1991 through
1993 was due largely to the implementation of an early retirement
program and other efficiency measures in 1991 and 1992. In the
first quarter of 1994 the Company further reduced its staffing in
connection with its restructuring and cost-reduction program
described above under "Introduction" - "Cost Reduction and
Restructuring".
In 1989 the Company and its employees represented by the
union agreed to a three-year contract, which was to expire on May
1, 1992. In November 1991, however, the Company and the union
agreed to a three-year extension of the contract providing for
annual wage increases of 3 percent, 3 percent, and 3.5 percent,
respectively, for each of the three years ending on May 1, 1995,
respectively.
Item 2. PROPERTIES.
Existing Facilities
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The electric properties of the Company form a single
integrated system which is connected at 345 kilovolts and 115
kilovolts with the lines of Public Service Company of New
Hampshire at the southerly end and at 115 kilovolts with Bangor
Hydro-Electric Company at the northerly end of the Company's
system. The Company's system is also connected with the system
of The New Brunswick Power Corporation and with Bangor
Hydro-Electric Company, in each case through the 345-kilovolt
interconnection constructed by MEPCO, a 78 percent-owned
subsidiary of the Company. At December 31, 1993, the Company had
approximately 2,273 circuit-miles of overhead transmission lines,
18,605 pole-miles of overhead distribution lines and 1,182 miles
of underground and submarine cable. The maximum one-hour firm
system net peak load experienced by the Company during the winter
of 1993-1994 was approximately 1,337 megawatts on January 27,
1994. At the time of the peak, the Company's net capability was
1,977 megawatts. The maximum such peak load experienced by the
Company during the preceding three winters was approximately
1,456 megawatts on January 8, 1991, at which time the Company's
net capability was 2,069 megawatts. The New England Power Pool
("NEPOOL"), of which the Company is a member, had sufficient
installed capacity and firm purchases to meet the NEPOOL four-
year peak load of 19,742 megawatts experienced on July 19, 1991,
and its 1993-1994 winter peak load of 19,534 megawatts on January
19, 1994. See "NEPOOL", below.
The Company operates 28 hydroelectric generating stations
with an estimated net capability of 368 megawatts and purchases
an additional 91 megawatts of hydroelectric generation in Maine.
It is currently re-evaluating some of its older hydroelectric
plants in conjunction with efforts to obtain new federal
operating licenses, with the objective of increasing their output
and extending their usefulness. The Company also operates one
oil-fired steam-electric generating station, William F. Wyman
Station in Yarmouth, Maine, after de-activating its Mason Station
in Wiscasset, Maine, in 1991. The Company's share of William F.
Wyman Station has an estimated net capability of 592 megawatts.
The oil-fired station is located on tidewater, permitting
waterborne delivery of fuel. The Company also has three internal
combustion generating facilities with an estimated aggregate net
capability of 41 megawatts.
The Company has ownership interests in five nuclear
generating plants in New England. The largest is a 38-percent
interest in Maine Yankee, which generates power at its plant in
Wiscasset, Maine. In addition, the Company owns a 9.5 percent
interest in Yankee Atomic Electric Company ("Yankee Atomic"),
which has permanently shut down its plant located in Rowe,
Massachusetts, a 6 percent interest in Connecticut Yankee Atomic
Power Company ("Connecticut Yankee"), with a plant in Haddam,
Connecticut, and a 4 percent interest in Vermont Yankee Nuclear
Power Corporation ("Vermont Yankee"), which owns a plant located
in Vernon, Vermont (collectively, with Maine Yankee, the "Yankee
Companies"). In addition, pursuant to a joint ownership
agreement, the Company has a 2.5 percent direct ownership
interest in the Millstone 3 nuclear unit ("Millstone 3") in
Waterford, Connecticut.
In February 1992, the Board of Directors of Yankee Atomic,
after concluding that it would be uneconomic to continue to
operate, decided to permanently discontinue power operation at
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the Yankee Atomic plant and to decommission that facility. The
Company had relied on Yankee Atomic for less than one percent of
the Company's system capacity. Its 9.5-percent equity investment
in Yankee Atomic is approximately $2.3 million. Currently,
purchased-power costs billed to the Company, which include the
estimated cost of the ultimate decommissioning of the unit, are
collected by the Company from its customers through the Company's
base-rate structure.
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 $32.8
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 Company's balance sheet. As part of the
MPUC's decision in the Company's recent base-rate case, the
Company's share of costs related to the deactivation of Yankee
Atomic is being recovered through rates based on the most recent
projections of costs.
The Company's share of the capacity of the four operating
nuclear generating plants amounted to the following:
<TABLE>
<S> <C> <C> <C> <S> <C> <C>
Maine Yankee . . . . 330 MW Connecticut Yankee . . 35 MW
Vermont Yankee . . . 21 MW Millstone 3 . . . . . 29 MW
</TABLE>
The Company is obligated to pay its proportionate share of
the operating expenses, including depreciation and a return on
invested capital, of each of the Yankee Companies referred to
above for periods expiring at various dates to 2012. Pursuant to
the joint ownership agreement for Millstone 3, the Company is
similarly obligated to pay its proportionate share of the
operating costs of Millstone 3. The Company is also required to
pay its share of the estimated decommissioning costs of each of
the Yankee Companies and Millstone 3. The estimated
decommissioning costs are paid as a cost of energy in the amounts
allowed in rates by the FERC.
MEPCO owns and operates a 345-kilovolt transmission
interconnection, completed in 1971, extending from the Company's
substation at Wiscasset to the Canadian border where it connects
with a line of The New Brunswick Power Corporation ("NB Power")
under a 25-year interconnection agreement. MEPCO transmits power
between NB Power and various New England utilities under separate
agreements. In 1990 MEPCO transferred to a newly formed
partnership, of which a subsidiary of the Company is a 50-percent
general partner, approximately $29 million of construction work
in progress and an equal amount of deferred credits related to
the construction of certain static var compensator facilities
used for stabilization purposes in connection with the NEPOOL
Hydro-Quebec purchase discussed in the succeeding paragraph.
NEPOOL, of which the Company is a member, contracted in
connection with 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 also entered
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into facilities-support agreements for its share of the related
transmission facilities, with its share of the support
responsibility and of associated benefits being approximately 7
percent of the totals. The Company is making facilities-support
payments on approximately $33.2 million, its share of the
construction cost for the transmission facilities incurred
through December 31, 1993.
Maine Yankee Decommissioning. Effective in 1988 Maine
Yankee began collecting $9.1 million annually for decommissioning
based on a FERC-approved funding level of $167 million. In
January 1994, Maine Yankee filed a notice of tariff change with
the FERC to increase its annual collection to $14.9 million and
to reduce its return on common equity to 10.65 percent, for a
total net 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
dismantlement and removal, of $317 million (in 1993 dollars)
based on a 1993 external engineering study. 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. Maine Yankee's accumulated decommissioning
funds were $93.8 million as of December 31, 1993.
Maine Yankee Low-Level Waste Disposal. The federal Low-
Level Radioactive Waste Policy Amendments Act (the "Waste Act"),
enacted in 1986, required operating disposal facilities to accept
low-level nuclear waste from other states until December 31,
1992. The Waste Act also set limits on the volume of waste each
disposal facility must accept from each state, established
milestones for the nonsited states to establish facilities within
their states or regions (pursuant to regional compacts) and
authorized increasing surcharges on waste disposal until 1992.
After 1992 the states in which there are operating disposal sites
are permitted to refuse to accept waste generated outside their
states or compact regions. In 1987 the Maine Legislature created
the Maine Low-Level Radioactive Waste Authority (the "Maine
Authority") to provide for such a facility if Maine is unable to
secure continued access to out-of-state facilities after 1992,
and the Maine Authority engaged in a search for a qualified
disposal site in Maine. Maine Yankee volunteered its site at the
Plant for that purpose, but progress toward establishing a
definitive site in Maine, as in other states, was difficult
because of the complex technical nature of the search process and
the political sensitivities associated with it. As a result,
Maine did not satisfy its milestone obligation under the Waste
Act requiring submission of a site license application by the end
of 1991, and is therefore subject to surcharges on its waste and
has not had access to regulated disposal facilities since the end
of 1992. Thus, Maine Yankee now stores all waste generated at an
on-site storage facility.
At the same time, the State of Maine was pursuing
discussions with the State of Texas concerning participation in a
compact with that state and Vermont. In May 1993, the Texas
Legislature approved a compact with the states of Maine and
Vermont. The Maine Legislature in June 1993 ratified the compact
and submitted it to ratification by Maine voters in a referendum
held on November 2, 1993, in which the compact was ratified by a
margin of approximately 73% to 27%. It must now be presented to
the United States Congress for final ratification.
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The compact provides for Texas to take Maine's low-level
waste over a 30-year period for disposal at a planned facility in
west Texas. In return Maine would be required to pay $25
million, assessed to Maine Yankee by the State of Maine, payable
in two equal installments, the first after ratification by
Congress and the second upon commencement of operation of the
Texas facility. In addition, Maine Yankee would be assessed a
total of $2.5 million for the benefit of the Texas county in
which the facility would be located and would also be responsible
for its pro-rata share of the Texas governing commission's
operating expenses. Pending the ratification votes, the Maine
Authority suspended its search for a suitable disposal site in
Maine.
In the event the required ratification by Congress is not
obtained, subject to continued NRC approval, Maine Yankee can
continue to utilize its capacity to store approximately ten to
twelve years' production of low-level waste in its facility at
the Maine Yankee Plant site, which it started in January 1993.
Subject to obtaining necessary regulatory approval, Maine Yankee
could also build a second facility on the Plant site. Maine
Yankee believes it is probable that it will have adequate storage
capacity for such low-level waste available on-site, if needed,
through the licensed operating life of the Maine Yankee Plant.
On January 26, 1993, the NRC published for public comment a
proposed rulemaking that, if adopted, would require a licensee
such as Maine Yankee, as a condition of its license, to document
that it had exhausted other reasonable waste management options
in order to be permitted to store low-level waste on-site beyond
January 1, 1996. Such options include taking all reasonable
steps to contract, either directly or through the state, for
disposal of the low-level waste. On February 9, 1994, the NRC,
after affirming its preference for disposal of waste over
storage, announced its decision to withdraw the proposed
rulemaking. Maine Yankee has informed the Company that it
expects the NRC to issue its formal notice of withdrawal in the
spring of 1994.
The Company cannot predict whether the final required
ratification of the Texas compact or other regulatory approvals
required for on-site storage will be obtained, but Maine Yankee
has stated that it intends to utilize its on-site storage
facility in the interim and continue to cooperate with the State
of Maine in pursuing all appropriate options.
Nuclear Insurance. The Price-Anderson Act is a federal
statute providing, among other things, a limit on the maximum
liability for damages resulting from a nuclear incident.
Coverage for the liability is provided for by existing private
insurance and retrospective assessments for costs in excess of
those covered by insurance, up to $75.5 million for each reactor
owned, with a maximum assessment of $10 million per reactor in
any year. Based on the Company's stock ownership in four nuclear
generating facilities and its 2.5 percent direct 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 $45.3 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.
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In addition to the insurance required by the Price-Anderson
Act, the nuclear generating facilities mentioned above carry
additional nuclear property-damage insurance. This additional
insurance is provided from commercial sources and from the
nuclear electric utility industry's mutual 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 $6.3 million
annually.
For a discussion of issues relating to Maine Yankee's spent
nuclear fuel disposal, see "Fuel Supply" - "Nuclear", below.
Non-utility Generation
In the Public Utility Regulatory Policies Act of 1978
("PURPA") the United States Congress provided substantial
economic incentives to non-utility power producers by allowing
cogenerators and small power producers to sell their entire
electrical output to an electric utility at the utility's
avoided-cost rate and purchase their entire electric energy
requirement at the utility's established rate for that customer
class. The Maine Legislature enacted a companion measure in
1979.
The Company has entered into a number of long-term,
noncancellable contracts for the purchase of capacity and energy
from non-utility generators. The agreements generally have terms
of five to 30 years and require the Company to purchase the
energy at specified prices per kilowatt-hour. As of December 31,
1993, facilities having 596 megawatts of capacity covered by
these contracts were in service, and another 15 megawatts is
expected to be added by the end of 1994. The costs of purchases
under all of these contracts amounted to $360.7 million in 1993,
$341.5 million in 1992 and $332.4 million in 1991. Such costs
are recoverable through the Company's fuel clause, after review
and approval by the PUC.
In connection with the Company's 1992 fuel cost adjustment
proceeding, the MPUC announced it would review the prudence of
administration and management of these contracts, as well as the
terms and conditions of recent contracts. For a discussion of an
imprudence finding by the MPUC in connection with its review, see
Item 1, "Business", "Regulation and Rates" - "MPUC NUG Contracts
Investigation", above.
In an effort to control the price pressure related to
purchases from non-utility generators, the Company negotiated
long term contract buy-outs or restructuring with three
non-utility generators in 1992, four in 1993, eleven in early
1994, and continues to renegotiate other contracts. The Company
incurred buy-out costs of approximately $11.4 million in 1993 and
$19 million in 1992. The 1994 renegotiation of prices and
contract terms did not require cash payments. Total buy-outs,
restructuring, and terminations made to date are expected to save
the Company's customers more than $170 million in fuel costs
during the next five years.
Construction Program
-20-
<PAGE>
The Company's plans for improvements and expansion of
generating, transmission and distribution facilities and power-
supply sources are under continuing review. Actual construction
expenditures depend on the availability of capital and other
resources, load forecasts, customer growth, and general business
conditions. Recent economic and regulatory considerations have
led the Company to hold its planned 1994 capital investment
outlays, including deferred demand-side management expenditures,
to a level below that of 1993. During the five-year period ended
December 31, 1993, the Company's construction and acquisition
expenditures amounted to $425.1 million (including investment in
jointly-owned projects and excluding MEPCO), including an
Allowance for Funds Used During Construction ("AFC") of $13.6
million. The program is currently estimated at approximately $60
million for 1994 and $256 million for 1995 through 1998,
including AFC estimated for the period 1994 through 1998 at $3
million, and including an estimated $35 million for conservation
and energy management programs for the 1994 through 1998 period.
The following table sets forth the Company's estimated
capital expenditures as discussed above:
<TABLE>
<S> <C> <C> <C>
1994 1995-98 1994-98
Type of Facilities (Dollars in Millions)
Generating Projects $11 $ 48 $ 59
Transmission 7 28 35
Distribution 23 100 123
General 12 52 64
Energy Management 7 28 35
Total $60 $256 $316
</TABLE>
Demand-side Management
The Company's demand-side-management efforts have included
programs aimed at residential, commercial and industrial
customers. Among the residential efforts have been programs that
offer energy audits, low-cost insulation and weatherization
packages, water heater wraps, energy-efficient light bulbs, and
water heater cycling credits. Among the commercial and
industrial efforts have been programs that offer rebates for
efficient lighting systems and motors, energy management loans,
grants to customers who make efficiency improvements, and shared
savings arrangements with customers who undertake qualifying
conservation and load management programs.
Under the Company's "Power Partners" program, customers or
energy service companies may submit energy management project
bids in response to requests for proposals issued by the Company
for specific blocks of power. Power Partners was the first
program in the United States to allow energy management proposals
to compete on an equal basis with cogeneration and small power
production facilities in a bidding process for capacity and
energy.
The Company anticipates incurring expenses of approximately
$17.5 million in 1994 in connection with conservation and
-21-
<PAGE>
load-management programs and expects the costs of all of these
programs to be recoverable through rates. Actual expenditures
depend on such factors as availability of capital and other
resources, load forecasts, customer growth, and general business
conditions. Because of budget constraints, the Company is
seeking to concentrate its efforts where the need and cost-
effectiveness are the greatest, while continuing to honor
contractual commitments.
NEPOOL
The Company is a member of NEPOOL, which is open to all
investor-owned, municipal and cooperative electric utilities in
New England under an agreement in effect since 1971 that provides
for coordinated planning and operation of approximately 99
percent of the electric power production, purchases and
transmission in New England. The NEPOOL Agreement imposes
obligations concerning generating capacity reserve and the use of
major transmission lines, and provides for central dispatch of
the region's facilities.
Fuel Supply
The Company's total kilowatt-hour production by energy source
for each of the last two years and as estimated for 1994 is shown
below:
<TABLE>
<S> <C> <S> <C> <C> <C>
Actual Estimated
Source 1992 1993 1994
Nuclear (principally from 26% 28% 27%
Maine Yankee)
Hydro 15 14 17
Oil 19 16 12
Non-utility 38 40 44
Other purchases 2 2 0
100% 100% 100%
</TABLE>
The 1994 estimated kilowatt-hour output from oil and
purchased power may vary depending upon the relative costs of
Company-generated power and power purchased through NEPOOL and
independent producers.
Oil. The Company's William F. Wyman Station in Yarmouth,
Maine, and its internal combustion electric generating units are
oil-fired. A one-year contract for the supply of the Company's
fuel oil requirements at market prices expired on June 30, 1993.
Since then the Company has been purchasing its fuel oil
requirements on the open market.
The average cost per barrel of fuel oil purchased by the
Company during the five calendar years commencing with 1989 was
$17.07, $17.33, $12.87, $14.02 and $13.12, respectively. A
substantial portion of the fuel oil burned by the Company and the
other member utilities of NEPOOL is imported. The availability
and cost of oil to the Company, both under contract and in the
open market, could be adversely affected by policies and events
in oil-producing nations and other factors affecting world
supplies and domestic governmental action.
Nuclear. As described above, the Company has interests in a
number of nuclear generating units. The cycle of production and
-22-
<PAGE>
utilization of nuclear fuel for such units consists of (1) the
mining and milling of uranium ore, (2) the conversion of the
resulting concentrate to uranium hexafluoride, (3) the enrichment
of the uranium hexafluoride, (4) the fabrication of fuel
assemblies, (5) the utilization of the nuclear fuel, and (6) the
disposal of spent fuel.
Maine Yankee has entered into a contract with the United
States Department of Energy ("DOE") for disposal of its spent
nuclear fuel, as required by the Nuclear Waste Policy Act of
1982, pursuant to which a fee of one dollar per megawatt-hour is
currently assessed against net generation of electricity and paid
to the DOE quarterly. Under this Act, the DOE has assumed the
responsibility for disposal of spent nuclear fuel produced in
private nuclear reactors. In addition, Maine Yankee is obligated
to make a payment with respect to generation prior to April 7,
1983 (the date current DOE assessments began). Maine Yankee has
elected under terms of this contract to make a single payment of
this obligation prior to the first delivery of spent fuel to DOE,
scheduled to begin no earlier than 1998. The payment will
consist of $50.4 million (all of which Maine Yankee has
previously collected from its customers, but for which a reserve
was not funded), which is the approximate one-time fee charge,
plus interest accrued at the 13-week Treasury Bill rate
compounded on a quarterly basis from April 7, 1983, through the
date of the actual payment. Current costs incurred by Maine
Yankee under this contract are recoverable under the terms of its
Power Contracts with its sponsoring utilities, including the
Company. Maine Yankee has accrued and billed $53.1 million of
interest cost for the period April 7, 1983, through December 31,
1993.
Maine Yankee has formed a trust to provide for payment of
its long-term spent fuel obligation, and is funding the trust
with deposits at least semiannually which began in 1985, with
currently projected semiannual deposits of approximately $0.6
million through December 1997. Deposits are expected to total
approximately $62.8 million, with the total liability, including
interest due at the time of disposal, estimated to be
approximately $115.9 million at January 31, 1998. Maine Yankee
estimates that trust fund deposits plus estimated earnings will
meet this total liability if funding continues without material
changes.
Under the terms of a license amendment approved by the NRC
in 1984, the present storage capacity of the spent fuel pool at
the Maine Yankee Plant will be reached in 1999 and after 1996 the
available capacity of the pool will not accommodate a full-core
removal. After consideration of available technologies, Maine
Yankee elected to provide additional capacity by replacing the
fuel racks in the spent fuel pool at the Maine Yankee Plant for
more compact storage and, on January 25, 1993, filed with the NRC
seeking authorization to implement the plan. On March 15, 1994,
the NRC granted the authorization. Maine Yankee believes that
the replacement of the fuel racks will provide adequate storage
capacity through the Maine Yankee Plant's licensed operating
life. Maine Yankee has stated that it cannot predict with
certainty whether or to what extent the storage capacity
limitation at the plant will affect the operation of the plant or
the future cost of disposal.
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<PAGE>
Federal legislation enacted in December 1987 directed the
DOE to proceed with the studies necessary to develop and operate
a permanent high-level waste (spent fuel) disposal site at Yucca
Mountain, Nevada. The legislation also provides for the possible
development of a Monitored Retrievable Storage ("MRS") facility
and abandons plans to identify and select a second permanent
disposal site. An MRS facility would provide temporary storage
for high-level waste prior to eventual permanent disposal. In
late 1989 the DOE announced that the permanent disposal site is
not expected to open before 2010, although originally scheduled
to open in 1998. Additional delays due to political and
technical problems are probable.
The Company has been advised by the companies operating
nuclear generating stations in which the Company has an interest
that each of those companies has contracted for certain segments
of the nuclear fuel production and utilization cycle through
various dates. Contracts for other segments of the fuel cycle
will be required in the future, but their availability, prices
and terms cannot now be predicted. Those companies have also
advised the Company that they are assessing options generally
similar to those described above with respect to Maine Yankee in
connection with disposal of spent nuclear fuel.
Item 3. LEGAL PROCEEDINGS.
Material proceedings before the Maine PUC involving the
Company are discussed above in Item 1, Business.
PCB Disposal
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
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 polychlorinated biphenyls
(PCBs) from equipment originally owned by the Company.
In 1990, the Company and the EPA signed a negotiated consent
agreement, which was entered as an order by the United States
District Court for the District of Maine in 1991. The agreement
provides for studies, development of work plans, additional EPA
review, and eventual cleanup of the site by the Company over a
period of years, using the method and level of cleanup selected
by the EPA.
The Company has been investigating other courses of action
that might result in lower costs and, in March 1992, acquired
title to the site to pursue the possibility of developing it in a
manner that would not require the same method and level of
cleanup currently provided in the agreement. The Company also
initiated a lawsuit against the original owners of the site and
Westinghouse Electric Corp. (Westinghouse), which arranged for
the equipment disposal, seeking contributions toward past and
future cleanup costs. On November 8, 1993, the United States
District Court for the District of Maine rendered its decision in
the suit, holding that Westinghouse was responsible for 41
percent of the necessary past and future cleanup costs and the
former owners 12.5 percent, other than a small amount (less than
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<PAGE>
5 percent) of such costs not attributable to PCBs, for which
Westinghouse was held not responsible and the former owners were
held responsible for 33 percent. The Court further concluded
that the Company had incurred approximately $3.3 million to that
point in costs subject to sharing among the parties.
At the same time, the Company has been actively pursuing
recovery of its costs through its insurance carriers and has
reached agreement with one for recovering a portion of those
costs. It has also filed lawsuits seeking such recovery from
other carriers.
In August 1991, the Company requested permission from the
MPUC to defer its cleanup-related costs, with accrued carrying
costs, on the basis that such costs are allowable costs of
service and should be recoverable in rates. In August 1992, the
MPUC issued an order authorizing the Company to defer direct
costs associated with the site incurred after August 9, 1991,
with accrued carrying costs. Such costs incurred prior to the
request were charged to a $3-million reserve established in 1985.
Initial tests on the site have been completed and more
complex technological studies are still in progress. Based on
results to date and on the most likely cleanup method, the
Company believes that its remaining costs of the cleanup will
total between $7 million and $11 million, depending on the level
of cleanup ultimately required and other variable factors. Such
estimate is net of the agreed insurance recovery and considers
any contributions from Westinghouse and the former owners, but
excludes contributions from the insurance carriers the Company
has sued, or any other third parties. As a result, in the fourth
quarter of 1993, the Company decreased the liability recorded on
its books from $14 million, the estimated liability prior to the
November 1993 court ruling, to $7 million and recorded an equal
reduction in a regulatory asset established to reflect the
anticipated ratemaking recovery of such costs when ultimately
paid. Approximately $1 million of costs incurred to date has
been charged against the liability.
The Company cannot predict the level and timing of the
cleanup costs, the extent to which they will be covered by
insurance, or the ratemaking treatment of such costs, but
believes it should recover substantially all of such costs
through insurance and rates. The Company also believes that the
ultimate resolution of the legal and environmental proceedings in
which it is currently involved will not have a material adverse
effect on its financial condition.
Power Purchase Contract Suit. As previously reported, the
Company and Caithness King of Maine Limited Partnership
("Caithness") engaged in a lawsuit in the United States District
Court for the District of Maine over the Company's termination of
a contract for the purchase of approximately 80 megawatts of
electric power from a cogeneration project proposed for
construction by Caithness at the Topsham, Maine. In the suit
Caithness denied the validity of the termination and sought
damages estimated by Caithness to be in excess of $100 million
for breach of contract or, in the alternative, reformation of the
contract, and other legal relief.
Also as previously reported, on January 14, 1994, the
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<PAGE>
Company and Caithness entered into a Termination and Settlement
Agreement under which the Company paid Caithness a total of $5
million, and the parties agreed to the termination of the power-
purchase contract and to dismiss the suit and counterclaims. The
contract would have required payments by the Company over the
life of the contract that were projected to be significantly
higher than the Company's estimated avoided costs and was
therefore inconsistent with the Company's program of pursuing
terminations or other restructurings of high-cost power-purchase
contracts.
Item 4. SUBMISSION OF MATTERS TO A VOTE
OF SECURITY HOLDERS.
Not applicable.
Item 4.1. EXECUTIVE OFFICERS OF THE REGISTRANT.
The following are the present executive officers of the
Company with all positions and offices held. There are no family
relationships between any of them, nor are there any arrangements
or understandings pursuant to which any were selected as
officers.
<TABLE>
<S> <C> <S><C> <C> <S>
Name, Age, and Year
First Became Officer Office
Carlton D. Reed, Jr., 63, 1991 Chairman of the Board of
Directors
Matthew Hunter, 59, 1978 Chairman of the Company, and
Director
David T. Flanagan, 46, 1984 President and Chief
Executive Officer, and
Director
Arthur W. Adelberg, 42, 1985 Vice President, Law and
Power Supply
Richard A. Crabtree, 47, 1978 Vice President, Retail
Operations
David E. Marsh, 46, 1986 Vice President, Corporate
Services, and Chief
Financial Officer
Curtis A. Mildner, 40, 1994 Vice President, Marketing
Gerald C. Poulin, 52, 1984 Vice President, Production
and Support
Douglas Stevenson, 45, 1984 Treasurer
Robert S. Howe, 54, 1975 Comptroller
-26- <PAGE>
William M. Finn, 57, 1984 Secretary and Clerk
</TABLE>
Each of the executive officers, except Mr. Mildner, has
for the past five years been an officer or employee of the
Company.
Curtis A. Mildner joined the Company as Vice President,
Marketing, on February 7, 1994. Prior to his employment by the
Company, he had been employed since 1987 by Hussey Seating
Company of Berwick, Maine, as Vice President, Marketing, and in
related capacities.
Mr. Hunter has announced that he plans to retire
effective May 1, 1994.
-27- <PAGE>
PART II
Item 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY
AND RELATED STOCKHOLDER MATTERS.
The Company's common stock is traded on the New York
Stock Exchange. As of March 21, 1994, there were 35,146 holders
of record of the Company's common stock.
<TABLE>
<S> <C> <C> <C> <C> <C>
Price Range of and Dividends on Common Stock
Market Price Dividends
High Low Declared
1993
First Quarter $24 1/2 $21 3/4 $ .39
Second Quarter 24 3/8 21 .39
Third Quarter 24 21 7/8 .39
Fourth Quarter 22 1/4 14 3/8 .225
1992
First Quarter $22 7/8 $19 7/8 $ .39
Second Quarter 22 7/8 20 .39
Third Quarter 23 3/4 22 1/8 .39
Fourth Quarter 23 7/8 22 1/8 .39
</TABLE>
Under the most restrictive terms of the indenture securing
the Company's General and Refunding Mortgage Bonds and of 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, 1993,
$87.5 million of retained earnings was not so restricted. Future
dividend decisions will be subject to future earnings levels and
the financial condition of the Company and will reflect the
evaluation by the Company's Board of Directors of then existing
circumstances.
Item 6. SELECTED FINANCIAL DATA.
The following table sets forth selected consolidated
financial data of the Company for the five years ended December
31, 1989 through 1993. This information should be read in
conjunction with "Management's Discussion and Analysis of
Financial Condition and Results of Operations" and the financial
statements and related notes thereto included elsewhere herein.
The selected consolidated financial data for the years ended
December 31, 1989 through 1993 are derived from the audited
financial statements of the Company.
-28- <PAGE>
<TABLE>
<S> <C> <C> <C> <C> <C>
Selected Consolidated Financial Data
(Dollars in Thousands, Except Per Share Amounts)
1993 1992 1991 1990 1989
Electric operating
revenues $ 893,577 $ 877,695$ 866,539 $ 780,821 $ 727,196
Net income 61,302 63,583 59,134 48,795 48,574
Long-term
obligations 581,844 499,029 518,625 495,716 430,544
Redeemable preferred
stock 80,000 40,750 43,500 44,875 11,250
Total assets 2,004,862 1,690,005 1,574,501 1,456,072 1,324,218
Earnings per common
share $ 1.65 $1.85 $1.82 $1.68 $1.92
Dividends declared
per common share $1.395 $1.56 $1.56 $1.56 $1.53
</TABLE>
-29- <PAGE>
Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS.
The information required to be furnished in response to this
Item is submitted as pages 1 to 15 of Exhibit 13-1 hereto (the
Company's Annual Report to Shareholders for the year ended
December 31, 1993), which pages are hereby incorporated herein by
reference.
Item 8. FINANCIAL STATEMENTS AND
SUPPLEMENTARY DATA.
The information required to be furnished in response to this
Item is submitted as pages 15 through 48 of Exhibit 13-1 hereto
(the Company's Annual Report to Shareholders for the year ended
December 31, 1993), which pages are hereby incorporated herein by
reference. For ease of reference, the following is a listing of
financial information incorporated by reference to Exhibit 13-1
hereto, which shows the page number or numbers of said Exhibit on
which such information is presented.
<TABLE>
<S> <C> <S> <C>
Financial Information Page(s) of Exhibit 13-1
Report of independent public accountants 47
Management report on responsibility
for financial reporting 48
Consolidated statement of earnings for
the three years ended December 31,
1993, 1992 and 1991 15-17
Consolidated balance sheet as of
December 31, 1993 and 1992 18-20
Consolidated statement of cash flows for
the three years ended December 31, 1993,
1992 and 1991 17-18
Consolidated statement of capitalization
and interim financing as of
December 31, 1993 and 1992 20-21
Consolidated statement of changes
in common stock investment for the
three years ended December 31, 1993,
1992 and 1991 21-23
Notes to consolidated financial statements 23-46
Supplementary quarterly financial
data (unaudited) 45-46
</TABLE>
Item 9. CHANGES IN AND DISAGREEMENTS WITH
ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE.
The information required to be furnished in response to this
Item is submitted on page 49 of Exhibit 13-1 hereto (the
Company's Annual Report to Shareholders for the year ended
December 31, 1993), which page is hereby incorporated by
-30- <PAGE>
reference.
PART III
Item 10. DIRECTORS AND EXECUTIVE OFFICERS
OF THE REGISTRANT.
See the information under the heading "Election of Directors"
in the registrant's definitive proxy material for its annual
meeting of shareholders to be held on May 25, 1994, and Item 4.1,
Executive Officers of the Registrant, above, both of which are
hereby incorporated herein by reference.
Item 11. EXECUTIVE COMPENSATION.
See the information under the heading "Board Committees,
Meetings and Compensation" and the heading "Executive
Compensation" in the registrant's definitive proxy material for
its annual meeting of shareholders to be held on May 25, 1994,
which is hereby incorporated herein by reference.
Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL
OWNERS AND MANAGEMENT.
See the information under the heading "Security Ownership" in
the registrant's definitive proxy material for its annual meeting
of shareholders to be held on May 25, 1994, which is hereby
incorporated herein by reference.
Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
See the information under the heading, "Board Committees,
Meetings and Compensation" in the registrant's definitive proxy
material for its annual meeting of shareholders to be held on May
28, 1994, which is hereby incorporated herein by reference.
PART IV
Item 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES,
AND REPORTS ON FORM 8-K.
(a) Listing of Exhibits. The exhibits which are filed with
this Form 10-K or are incorporated herein by reference are set
forth in the Exhibit Index, which immediately precedes the
exhibits to this report.
(b) Reports on Form 8-K. The Company filed the following
reports on Form 8-K during the last quarter of 1993 and
thereafter to date:
Date of Report Items Reported
October 27, 1993 Item 5
Lowering of debt and preferred stock ratings. On October 27,
1993, Duff & Phelps Credit Rating Co. announced that it was
lowering the ratings of the Company's debt and preferred stock.
Date of Report Items Reported
-31-
<PAGE>
October 28, 1993 Item 5
(a) Debt and preferred stock ratings. On October 29, 1993,
Moody's Investors Service ("Moody's") lowered the ratings on the
Company's long-term debt and preferred stock, citing concerns
about the Company's "ability to safeguard its competitive
position and to gain the regulatory support needed to avoid
further pressure on cash flow and debt-protection measurements".
(b) Base-rate case. The Company reported on positions taken by
certain parties in the Company's base-rate case before the PUC.
(c) PUC order on independent power producer contracts. On
October 28, 1993, the PUC issued its written order incorporating
the conclusions of its October 5, 1993, deliberations.
Date of Report Items Reported
November 30, 1993 Item 5
Public Utilities Commission order in base-rate case and
securities downgrading. On November 30, 1993, the MPUC issued
its basic revenue requirements order finding the Company entitled
to an annual revenue increase of $26.2 million in the Company's
$83 million base-rate case. On December 1, 1993, Standard &
Poor's Corp. ("S&P") further lowered its ratings of the Company's
securities.
Date of Report Items Reported
December 15, 1993 Item 5
Common stock dividend reduction. On December 15, 1993, the
Company's Board of Directors reduced the quarterly dividend on
the Company's common stock from 39 cents to 22.5 cents per share.
Date of Report Items Reported
December 16, 1993 Item 5
(a) On December 16, 1993, the Company announced that David T.
Flanagan had been elected President, Chief Executive Officer and
a director, effective January 1, 1994, succeeding Matthew Hunter,
who planned to retire May 1, 1994.
(b) The Company reported that effective December 27, 1993, the
Company's 450,000 shares of outstanding Flexible Money Market
Preferred Stock, Series A, would no longer be subject to the
restriction that it be conveyed only in Units of 1,000 shares.
(c) On December 20, 1993, the Chief Justice of the Maine Supreme
Judicial Court issued an order temporarily staying the .5%
return-on-equity penalty that had been imposed on the Company by
the MPUC on October 28, 1993, in its independent power producer
contracts investigation.
-32-
<PAGE>
Date of Report Items Reported
January 5, 1994 Item 5
On January 5, 1994, S&P further lowered its ratings on the
Company's securities, including the senior secured debt rating to
"BB+" from BBB-".
Date of Report Items Reported
January 13, 1994 Items 4 and 5
Item 4. On January 19, 1994, the Company's Board of Directors
voted to engage Coopers & Lybrand as the Company's principal
accountants in 1994. The Item also contained information on a
disagreement in 1991 with the Company's predecessor accountants.
(This item amended by Form 8-K/A, Amendment No. 1, also dated
January 13, 1994.
Item 5. (a) On January 13, 1994, Moody's lowered its ratings on
the Company's preferred stock and commercial paper, while
confirming its rating on the Company's General and Refunding
Mortgage Bonds at "Baa2".
(b) On January 14, 1994, the Company and Caithness King of Maine
Limited Partnership entered into a Termination and Settlement
Agreement terminating power-contract litigation.
Date of Report (Form 8-K/A) Items Reported
January 13, 1994 Item 4
The Company amended its January 13, 1994, Form 8-K to provide
further information on its change of principal accountants and a
1991 disagreement with the Company's predecessor accountants.
Date of Report Items Reported
February 3, 1994 Item 5
On February 4, 1993, the Chief Justice of the Maine Supreme
Judicial Court denied the MPUC's motion to dismiss the Company's
approval of the MPUC's October 28, 1993, return-on-equity
penalty. The MPUC had contended that it had reconsidered its
order imposing the penalty and was considering alternative
remedies.
-33- <PAGE>
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the
Securities Exchange Act of 1934, the registrant has duly caused
this report to be signed on its behalf by the undersigned,
thereunto duly authorized, in the City of Augusta, and State of
Maine on the 30th day of March, 1994.
CENTRAL MAINE POWER COMPANY
By
David E. Marsh
Vice President, Corporate Services
and Chief Financial Officer
-34- <PAGE>
Pursuant to the requirements of the Securities Exchange
Act of 1934, this report has been signed below by the following
persons in the capacities and on the dates indicated.
<TABLE>
<C> <S> <C> <C>
Signature Title Date
________________________ President and March 30, 1994
David T. Flanagan Chief Executive
(Principal Executive Officer; Director
Officer)
_________________________ Vice President, March 30, 1994
David E. Marsh Corporate Services,
(Principal Financial and Chief Financial
Officer) Officer
_________________________ Comptroller March 30, 1994
Robert S. Howe
(Principal Accounting
Officer)
_________________________ Chairman of the March 30, 1994
Carlton D. Reed, Jr. Board of Directors
_________________________ Chairman of the March 30, 1994
Matthew Hunter Company; Director
_________________________ Director March 30, 1994
Charles H. Abbott
_________________________ Director March 30, 1994
Charleen M. Chase
_________________________ Director March 30, 1994
E. James Dufour
_________________________ Director March 30, 1994
Robert H. Gardiner
_________________________ Director March 30, 1994
David M. Jagger
_________________________ Director March 30, 1994
Charles E. Monty
_________________________ Director March 30, 1994
Robert H. Reny
_________________________ Director March 30, 1994
Anne Szostak
_________________________ Director March 30, 1994
Kathryn M. Weare
</TABLE>
-35- <PAGE>
The following report and consent and financial schedules of
Central Maine Power Company are filed herewith and included in
response to Item 14(d).
<TABLE>
<S> <C> <S>
Page
Report of independent public
accountants F-2
Consent of independent public
accountants F-3
Schedule V - Consolidated Property,
Plant and Equipment F-4 to F-6
Schedule VI - Consolidated Reserves
for Depreciation of Property and
Amortization of Nuclear Fuel F-7 to F-9
Schedule VIII - Valuation and Qualifying
Accounts F-10 to F-12
Schedule IX - Consolidated Short-Term
Borrowings F-13
</TABLE>
Any and all other schedules are omitted because the required
information is inapplicable or the information is presented in
the financial statements or related notes.
-36- <PAGE>
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors of
Central Maine Power Company:
We have audited, in accordance with generally accepted auditing
standards, the consolidated financial statements included in
Central Maine Power Company's annual report to shareholders
incorporated by reference in this Form 10-K, and have issued our
report thereon dated February 4, 1994. Our audits were made for
the purpose of forming an opinion on those statements taken as a
whole. The schedules listed on the accompanying index of
schedules included in reports to Item 14(a) in Form 10-K are
presented for purposes of complying with the Securities and
Exchange Commission's rules and are not part of the basic
financial statements. These schedules have been subjected to the
auditing procedures applied in the audit of the basic financial
statements and, in our opinion, fairly state, in all material
respects, the financial data required to be set forth therein in
relation to the basic financial statements taken as a whole.
ARTHUR ANDERSEN & CO.
Boston, Massachusetts
February 4, 1994
-37- <PAGE>
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the
incorporation of our reports included and incorporated by
references in this Form 10-K, into the Company's previously filed
Registration Statements File No. 33-44944, File No. 33-44754,
File No. 33-51611, File No. 33-39826 and File No. 33-36679.
ARTHUR ANDERSEN & CO.
Boston, Massachusetts,
March 28, 1994
-38- <PAGE>
<TABLE>
<S> <C> <C> <C> <C> <C>
Central Maine Power Company
CONSOLIDATED PROPERTY, PLANT AND EQUIPMENT (H)
For the Year Ended December 31, 1993
(Dollars in Thousands)
Balance at Other Changes Balance at
Beginning Additions Retirements Miscellaneous End Classification
Classification of Period at Cost or Sale Adjustments of Period
Electric Property (A) (B)&(I)
Intangible Property $ 4,767 $ 2,799 $ 0 $ 0 $ 7,566
Generating Plant-Steam 202,367 703 (290) 594 203,374
Generating Plant-Hydro 197,486 5,995 (95) (12)(C) 203,374
Generating Plant-Internal
Combustion 4,080 1 0 0 4,081
Generating Plant-Nuclear 97,750 381 0 0 98,131
Transmission 270,948 6,353 (1,195) (2,590)(D) 273,516
Distribution 600,297 29,194 (9,503) 196 620,184
Other Property and
Equipment 139,250 22,367 (5,698) (1,270)(E) 154,649
Electric Plant Acquisition
Adjustment 0 0 0 0
Total Electric Property
in Service 1,516,945 67,793 (16,781) (3,082) 1,564,875
Unfinished Construction 34,550 (14,558) 0 (303) 19,689
Total Electric Property 1,551,495 53,235 (16,781) (3,385) 1,584,564
Nuclear Fuel (F) 8,443 621 0 0 9,064
Miscellaneous Properties (G) 3,898 112 (144) 1,086 4,952
Total Property, Plant and
Equipment $1,563,836 $53,968 $(16,925) $(2,299) $1,598,580
Notes: (A) Includes Operating Property and Property Held for Future Use land retirements/sales
of $9.
(B) Transfers (to)/from various classifications contained on this page.
(C) Includes the writedown of Hydro land and water rights.
(D) Includes annual reductions of ($1,610) for Transmission Facilities under Capital
Leases.
(E) Includes annual reductions for 1) General Facilities under Capital Leases of
($995) and 2) a long term asset associated with the General Office Settlement of
($79).
(F) Includes Nuclear Fuel in Processing, in Stock, in Reactor, and Spent Fuel.
(G) Included in Deferred Charges and Other Assets on Balance Sheet.
Report for depreciation policies.
(H) Refer to Note 1 of Notes to Consolidated Financial Statements in the 1993 Annual
Report for depreciation policies.
(I) As a result of the Company's adoption of FAS 109, property classifications were
adjusted as follows: (Steam) $570; (Hydro) $5; (Transmission) $136;
(Distribution) $38; and (General) $52.
F-4
-39- <PAGE>
Central Maine Power Company
CONSOLIDATED PROPERTY, PLANT AND EQUIPMENT (H)
For the Year Ended December 31, 1992
(Dollars in Th
Balance at Other Changes Balance at
Beginning Additions Retirements Miscellaneous End
Classification of Period at Cost or Sale Adjustments of Period
Electric Property (A) (B)
Intangible Property $ 4,388 $ 379 $ 0 $ 0 $ 4,767
Generating Plant-Steam 200,409 3,324 (1,380) 14 202,367
Generating Plant-Hydro 191,855 5,909 (314) 36 (C) 197,486
Generating Plant-Internal
Combustion 4,080 0 0 0 4,080
Generating Plant-Nuclear 97,555 195 0 0 97,750
Transmission 263,137 10,974 (1,807) (1,356)(D) 270,948
Distribution 575,994 32,986 (8,478) (205) 600,297
Other Property and
Equipment 133,649 10,616 (4,587) (428)(E) 139,250
Electric Plant Acquisition
Adjustment 226 0 (226) 0
Total Electric Property
in Service 1,471,293 64,383 (16,792) (1,939) 1,516,945
Unfinished Construction 26,383 8,180 0 (13) 34,550
Total Electric Property 1,497,676 72,563 (16,792) (1,952) 1,551,495
Nuclear Fuel (F) 7,975 468 0 0 8,443
Miscellaneous Properties (G) 3,806 7 (10) 95 3,898
Total Property, Plant and
Equipment $1,509,457 $73,038 $(16,802) $(1,857) $1,563,836
Notes: (A) Includes Operating Property and Property Held for Future Use land retirements/sales
of $43.
(B) Transfers (to)/from various classifications contained on this page.
(C) Includes the writedown of Hydro land and water rights.
(D) Includes annual reductions of ($1,579) for Transmission Facilities under Capital
Leases.
(E) Includes annual reductions for 1) General Facilities under Capital Leases of
($925) and 2) a long term asset associated with the General Office Settlement of
($79) and to record the investment of purchased vehicles formerly leased $659.
(F) Includes Nuclear Fuel in Processing, in Stock, in Reactor, and Spent Fuel.
(G) Included in Deferred Charges and Other Assets on Balance Sheet.
(H) Refer to Note 1 of Notes to Consolidated Financial Statements in the 1992 Annual
Report for depreciation policies.
F-5
-40- <PAGE>
Central Maine Power Company
CONSOLIDATED PROPERTY, PLANT AND EQUIPMENT (A)
For the Year Ended December 31, 1991
(Dollars in Thousands)
Balance at Other Changes Balance at
Beginning Additions Retirements Miscellaneous End
Classification of Period at Cost or Sale Adjustments of Period
Electric Property (B) (C)
Intangible Property $ 2,327 $ 2,054 $ 0 $ 7 $ 4,388
Generating Plant-Steam 193,708 7,446 (466) (279) 200,409
Generating Plant-Hydro 191,627 1,673 (681) (764)(D) 191,855
Generating Plant-Internal
Combustion 4,079 0 0 1 4,080
Generating Plant-Nuclear 97,445 110 0 0 97,555
Transmission 257,529 7,413 (939) (866)(E) 263,137
Distribution 546,746 37,043 (7,836) 41 575,994
Other Property and
Equipment 123,570 16,686(F) (4,801) (1,806)(G) 133,649
Electric Plant Acquisition
Adjustment 226 0 0 0 2
Total Electric Property
in Service 1,417,257 72,425 (14,723) (3,666) 1,471,293
Unfinished Construction 19,410 6,903 0 70 26,383
Total Electric Property 1,436,667 79,328 (14,723) (3,596) 1,497,676
Nuclear Fuel (H) 7,877 99 0 0 7,976
Miscellaneous Properties (I) 2,682 186 (387) 1,324 3,805
Total Property, Plant
and Equipment $1,447,226 $79,613 $(15,110) $(2,272) $1,509,457
Notes: (A) Refer to Note 1 of Notes to Consolidated Financial Statements in the 1992 Annual
Report for depreciation policies.
(B) Includes Operating Property and Property Held for Future Use land retirements/sales
of $19.
(C) Transfers (to)/from various classifications contained on this page.
(D) Includes the transfer of Columbia and Lincoln Hydro stations to Deferred Charges and
Other Assets of ($739) and the writedown of Hydro land and water rights.
(E) Includes annual reductions of ($566) for Transmission Facilities under Capital
Leases.
(F) Includes an addition of Property under Capital Leases for mainframe computer
equipment of $4,167.
(G) Includes annual reductions for 1) General Facilities under Capital Leases of
($861) and 2) a long term asset associated with the General Office Settlement of
($79).
(H) Includes Nuclear Fuel in Processing, in Stock, in Reactor, and Spent Fuel.
(I) Included in Deferred Charge
</TABLE>
F-6
-41- <PAGE>
<TABLE>
<S> <C> <C> <S> <C> <C> <S> <C> <C>
Central Maine Power Company
CONSOLIDATED RESERVES FOR DEPRECIATION OF PROPERTY AND AMORTIZATION
For the Year Ended December 31, 1993
(Dollars in Thousands)
Additions to Reserves Deductions from Reserves
Balance Retirements, Ch
at Charged to Renewals and Balance
Beginning Profit and Charged to Other Accounts Replace- Other at Close
of Period Loss Description Amount ments Description Amount of Period
(A)
Electric $474,036 $42,008 $16,772 $
Salvage of Cost of
Retired Materials Removing
and Equipment $2,488 Retired Plant $2,483
Auto Adjust Reserve-
Depreciation/ Assets
Amortization Transferred to
Charged to Nonoperat-
Clearing Accounts 2,996 ing 84
Adjust Reserve-
Millstone Unit
No. III
Decommissioning
Trust Fund (A/C
128) 1,091
474,036 42,008 6,575 16,772 2,567 503,280
Nuclear
Fuel 6,544 698 7,242
Miscel- Adjust Reserve-
laneous Assets
Propert- Transferred from
ies Operating
(B) 410 45 Property 84 3 536
$480,990 $42,751 $6,659 $16,775 $2,567 $511,058
Notes: (A) Retirements are made at original cost.
(B) Included in Deferred Charges and Other Assets on Balance Sheet.
</TABLE>
F-7
-42- <PAGE>
<TABLE>
<S> <C> <C> <S> <C> <C> <S> <C> <C>
Central Maine Power Company
CONSOLIDATED RESERVES FOR DEPRECIATION OF PROPERTY AND AMORTIZATION OF NUCLEAR FUEL
For the Year Ended December 31, 1992
(Dollars in Thousands)
Additions to Reserves Deductions from Reserves
Balance Retirements, Charg
at Charged to Charged to Other Accounts Renewals and Other Balance
Beginning Profit and Replace- at Close
of Period Loss Description Amount ments Description Amount of Period
(A)
Electric $447,276 $40,321 $16,749 $
Salvage of Cost of
Retired Materials Removing
and Equipment $2,151 Retired Plant $2,820
Auto Adjust Reserve-
Depreciation/ Assets
Amortization Transferred to
Charged to Nonoperat-
Clearing Accounts 3,183 ing 2
Adjust Reserve-
Loss on Disposal
of Property 12
Assets
Transferred to
Donations 5
Investment of
purchased
vehicles
formerly leased 659
447,276 40,321 6,010 16,749 2,822 474,036
Nuclear
Fuel 5,798 746 6,544
Miscel- Adjust Reserve-
laneous Assets
Proper- Transferred from
ties Operating
(B) 371 37 Property 2 410
$453,445 $41,104 $6,012 $16,749 $2,822 $480,990
Notes: (A) Retirements are made at original cost.
(B) Included in Deferred Charges and Other Assets on Balance Sheet.
</TABLE>
F-8
-43- <PAGE>
<TABLE>
<S> <C> <C> <C> <C> <C> <C>
Central Maine Power Company
CONSOLIDATED RESERVES FOR DEPRECIATION OF PROPERTY AND AMORTIZATION OF NUCLEAR FUEL
For the Year Ended December 31, 1991
(Dollars in Thousands)
Additions to Reserves Deductions from Reserves
Balance Retirements,
at Charged to Charged to Other Accounts Renewals and Other Balance
Beginning Profit and Replace- at Close
of Period Loss Description Amount ments Description Amount of Period
(A)
Electric $421,840 $39,000 $14,704 $
Salvage of Cost of
Retired Materials Removing
and Equipment $2,314 Retired Plant $4,015
Auto Adjust Reserve-
Depreciation/ Assets
Amortization Transferred to
Charged to Nonoperating
Clearing Accounts 3,123 (A/C 122) 369
Adjust Reserve- Deferred
Debits (A/C
186) 107(B)
Assets Donations
Transferred to (A/C
Deferred Debits 426.1)
(A/C 186) 195(B) 1
421,840 39,000 5,632 14,704 4,492 447,276
Nuclear
Fuel 5,480 318 5,798
Miscel- Adjust Reserve-
laneous Assets
Proper- Transferred from Sale of
ties Operating Nonoperating
(C) 174 15 Property 369 Property 187 371
$427,494 $39,333 $6,001 $14,704 $4,679 $453,445
Notes: (A) Retirements are made at original cost.
(B) To be recovered effective January 1, 1991 in accordance with the Maine Public Utilities Commission rate order in
Docket No. 89-68.
(C) Included in Deferred Charges and Other Assets on Balance Sheet.
</TABLE>
F-9
-44- <PAGE>
<TABLE>
<S> <C> <C> <C> <C> <C>
Central Maine Power Company
VALUATION AND QUALIFYING ACCOUNTS
For the Year Ended December 31, 1993
(Dollars in Thousands)
Additions
Charged to
Balance at Charged to other Balance at
beginning costs and accounts- Deductions- end of
Description of period expenses describe describe period
Reserves deducted from assets to which they apply:
Reserve for uncollectible accounts $ 2,250 $5,548 $ $ 5,094(A) $ 2,704
Reserves not applied against assets:
Reserve for casualty and insurance $ 1,077 $1,123 $ 272(B) $ 1,397(C) $ 1,075
Reserve for workers' compensation 6,400 6,400
Reserve for hazardous material clean-up 2,981 5,019(D) 1,172(E) 6,828
Reserve for Millstone III sales tax 423 423(F)
Reserve for obsolete inventory 250 250(G)
Reserve for revenue adjustment of tax
flowback 9,990 9,990(H)
Total $21,121 $1,123 $5,291 $13,232 $14,303
Notes: (A) Amounts charged off as uncollectible after deducting customers' deposits and recoveries of accounts previously
charged off.
(B) Amounts charged to capital accounts.
(C) Principally payments for various injuries and damages and expenses in connection therewith.
(D) Amounts charged to regulatory asset account.
(E) Amounts paid, charged against the reserve.
(F) Amounts reversed, charged to nuclear operating expenses.
(G) Amounts charged off as Distribution Expense.
(H) Refer to Note 3 of Notes to Consolidated Financial Statements in the 1993 Annual Report.
</TABLE>
F-10
-45- <PAGE>
<TABLE>
<S> <C> <C> <C> <C> <C>
Central Maine Power Company
VALUATION AND QUALIFYING ACCOUNTS
For the Year Ended December 31, 1992
(Dollars in Thousands)
Additions
Charged to Balance
Balance at Charged to other at end
beginning costs and accounts- Deductions- of
Description of period expenses describe describe period
Reserves deducted from assets to which they apply:
Reserve for uncollectible accounts $ 2,336 $ 5,576 $ $5,662(A) $ 2,250
Reserves not applied against assets:
Reserve for casualty and insurance $ 1,075 $ 1,524 $393(B) $1,915(C) $ 1,077
Reserve for workers' compensation 6,400 6,400
Reserve for hazardous material clean-up 4,500 1,519(D) 2,981
Reserve for Millstone III sales tax 487 46 110(E) 423
Reserve for rate refund 4,500 4,500(F)
Reserve for obsolete inventory 250 250
Reserve for revenue adjustment of tax
flowback 9,990 9,990
Total $16,962 $11,810 $393 $8,044 $21,121
Notes: (A) Amounts charged off as uncollectible after deducting customers' deposits and recoveries of accounts previously
charged off.
(B) Amounts charged to capital accounts.
(C) Principally payments for various injuries and damages and expenses in connection therewith.
(D) Amounts paid, charged against the reserve net of estimated insurance recoveries.
(E) Amounts paid to Northeast Utilities related to Millstone Unit 3 Sales and Use Tax settlement
agreement dated June 12, 1992.
(F) Amount of refund paid per Federal Energy Regulatory Commission stipulation of $2,076 and
reversal of prior year reserve accrual of $2,424.
</TABLE>
F-11
-46- <PAGE>
<TABLE>
<S> <C> <C> <C> <C> <C>
Central Maine Power Company
VALUATION AND QUALIFYING ACCOUNTS
For the Year Ended December 31, 1991
(Dollars in Thousands)
Additions
Charged Charged to Balance
Balance at to costs other at end
beginning and accounts- Deductions- of
Description of period expenses describe describe period
Reserves deducted from assets to which they apply:
Reserve for uncollectible accounts $ 1,259 $5,690 $ $4,613(C) $ 2,336
Reserves not applied against assets:
Reserve for casualty and insurance $ 1,075 $1,520 $ 392(D) $1,912(E) $ 1,075
Reserve for workers' compensation 4,750 1,650(G) 6,400
Reserve for hazardous material clean-up 3,000 (912)(B) 4,500(A) 2,088(B) 4,500
Reserve for Millstone III sales tax 359 128 487
Reserve for wheeling 1,600 111 1,711(F)
Reserve for rate refund 4,500 4,500
Total $10,784 $5,347 $6,542 $5,711 $16,962
Notes: (A) Amounts deferred, net of anticipated insurance recovery, in anticipation of future rate treatment.
(B) Amounts previously charged to Account 186, Deferred Charges and Other Assets were charged against the reserve
and the remaining balance ($912) was credited to expense.
(C) Amounts charged off as uncollectible after deducting customers' deposits and recoveries of accounts previously
charged off.
(D) Amounts charged to capital accounts.
(E) Principally payments for various injuries and damages and expenses in connection therewith.
(F) Payment of contract settlement.
(G) Charged to Account 186, Deferred Charges and Other Assets.
</TABLE>
F-12
-47- <PAGE>
<TABLE>
<S> <C> <C> <C> <C> <C>
CENTRAL MAINE POWER COMPANY
CONSOLIDATED SHORT-TERM BORROWINGS
For the Years Ended December 31,
(Dollars in Thousands)
Weighted Maximum amount Average amount Weighted average
Balance at end average outstanding outstanding interest rate
Category of aggregate short- of interest during the during the during the
term borrowings (A) period rate (B) period (C) period period
1993
Commercial paper $15,500 3.74% $105,940 $39,623(D) 3.54%(E)
Notes payable to banks 10,000 3.70 29,000 18,492(D) 3.86 (E)
1992
Commercial paper 61,000 3.76 65,400 46,932(D) 3.99 (E)
Notes payable to banks 27,500 4.11 43,500 28,589(D) 4.63 (E)
Medium-term notes - - 7,500 3,340(D) 6.98 (E)
1991
Commercial paper 38,500 5.77 38,500 24,614(D) 6.30 (E)
Notes payable to banks 45,000 5.61 45,000 12,734(D) 6.03 (E)
Medium-term notes (G) 7,500 7.79 27,500 18,035 8.01 (F)
Notes: (A) Refer to Note 7 of Notes to Consolidated Financial Statements for general terms of short-
term borrowing.
(B) At end of period.
(C) Maximum amount outstanding at any month end for each category.
(D) Average daily balance of net proceeds during the period.
(E) Based on the daily amount of net proceeds outstanding during the period.
(F) Embedded cost rate.
(G) Medium-term notes interest rates and average balances are calculated on a 360-day year.
</TABLE>
F-13
-48- <PAGE>
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
ANNUAL REPORT PURSUANT TO
SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR
ENDED DECEMBER 31, 1993
CENTRAL MAINE POWER COMPANY
File No. 1-5139
(Exact name of Registrant as specified in charter)
EXHIBITS
F-13
-49-
<PAGE>
<TABLE>
<C> <S> <C> <S> <C> <S> <C>
EXHIBIT INDEX
The following designated exhibits, as indicated below, are either filed herewith or have
heretofore been filed with the Securities and Exchange Commission under the Securities Act of 1933, the
Securities Exchange Act of 1934 or the Public Utility Holding Company Act of 1935 and are incorporated
herein by reference to such filings. Reference is made to Item 8 of this Form 10-K for a listing of
certain financial information and statements incorporated by reference herein.
Prior
Exhibit Description of Exhibit
No. Document SEC Docket No.
EXHIBIT 2: PLAN OF ACQUISITION,
REORGANIZATION, ARRANGEMENT,
LIQUIDATION OR SUCCESSION
Not Applicable.
EXHIBIT 3: ARTICLES OF INCORPORATION AND
BY-LAWS
Incorporated herein by
reference:
3-1 Articles of Incorporation, as Annual Report on 3.1
amended. Form
10-K for year ended
December 31, 1992
3-2 Bylaws, as amended. Annual Report on 3.2
Form
10-K for the year
ended December 31,
1990
EXHIBIT 4: INSTRUMENTS DEFINING THE RIGHTS
OF SECURITY HOLDERS
F-13
-50-
<PAGE>
Prior
Exhibit Description of Exhibit
No. Document SEC Docket No.
Incorporated herein by
reference:
4-1 General and Refunding Mortgage 2-58251 2.18
between the Company and The
First National Bank of Boston,
as Trustee, dated as of
April 15, 1976, relating to the
Series A Bonds.
4-2 First Supplemental Indenture 2-60786 2.19
dated as of March 15, 1977 to
the General and Refunding
Mortgage.
4-3 Supplemental Indenture to the Annual Report on A
General and Refunding Mortgage Form
Indenture dated as of October 1, 10-K for the year
1978 relating to the Series B ended December 31,
Bonds. 1978
4-4 Supplemental Indenture to the Quarterly Report on A
General and Refunding Mortgage for the quarter
Indenture dated as of October 1, ended Septem-
1979, relating to the Series C ber 30, 1979
Bonds.
4.10 Supplemental Indenture to the 33-9232 4.16
General and Refunding Mortgage
Indenture dated as of December
1, 1986, relating to the Series
I Bonds.
F-13
-51-
<PAGE>
Prior
Exhibit Description of Exhibit
No. Document SEC Docket No.
4.14 Indenture, dated as of Augst 1, 33-29626 4.1
1989, between the Company and
The Ban of New York, Trustee,
relating to the Medium-Term
Notes.
4.15 First Supplemental Indenture, Current Report on 4.15
dated as of August 7, 1989, Form
relating to the Medium-Term 8-K dated
Notes, Series A, and August 16, 1989
supplementing the Indenture
relating to the Medium-Term
Notes.
4.15.1 Second Supplemental Indenture, Current Report on 4.1
dated as of January 10, 1992, Form
relating to the Medium-Term 8-K dated
Notes, Series B, and January 28, 1992
supplementing the Indenture
relating to the Medium-Term
Notes.
4.17 Supplemental Indenture to the Current Report on 4.1
General and Refunding Mortgage Form
Indenture, dated as of 8-K dated September
September 15, 1991, relating to 17, 1991
the Series N Bonds.
4.18 Supplemental Indenture to the Current Report on 1.2
General and Refunding Mortgage Form
Indenture, dated as of 8-K dated
December 1, 1991, relating to December 10, 1991
the Series O Bonds.
F-13
-52-
<PAGE>
Prior
Exhibit Description of Exhibit
No. Document SEC Docket No.
4.19 Supplemental Indenture to the Annual Report on 4.19
General and Refunding Mortgage Form
Indenture, dated as of 10-K for year ended
December 15, 1992, relating to December 31, 1992
the Series P Bonds.
4.20 Supplemental Indenture to the Current Report on 4.1
General and Refunding Mortgage Form
Indenture, dated as of February 8-K dated March 1,
15, 1993, relating to the Series 1993
Q Bonds.
4.21 Supplemental Indenture to the Current Report on 4.1
General and Refunding Mortgage Form
Indenture, dated as of May 20, 8-K dated May 20,
1993, relating to the Series R 1993
Bonds.
4.22 Supplemental Indenture to the Current Report on 4.1
General and Refunding Mortgage Form
Indenture, dated as of August 8-K dated November
15, 1993, relating to the Series 30, 1993
S Bonds.
4.23 Supplemental Indenture to the Current Report on 4.2
General and Refunding Mortgage Form
Indenture, dated as of November 8-K dated November
1, 1993, relating to the Series 30, 1993
T Bonds.
EXHIBIT 9: VOTING TRUST AGREEMENT
Not applicable.
EXHIBIT 10: MATERIAL CONTRACTS
F-13
-53-
<PAGE>
Prior
Exhibit Description of Exhibit
No. Document SEC Docket No.
Incorporated herein by
reference:
10-1 Agreement dated April 1, 1968 2-30554 4.27
between the Company and
Northeast Utilities Service
Company relating to services in
connection with the New England
Power Pool and NEPEX.
10-2 Form of New England Power Pool 2-55385 4.8
Agreement dated as of
September 1, 1971 as amended to
November 1, 1975.
10-3 Agreement setting forth 2-50198 5.10
Supplemental NEPOOL
Understandings dated as of
April 2, 1973.
10-4 Sponsor Agreement dated as of 2-32333 4.27
August 1, 1968 among the Company
and the other sponsors of
Vermont Yankee Nuclear Power
Corporation.
10-5 Power Contract dated as of 2-32333 4.28
February 1, 1968 between the
Company and Vermont Yankee
Nuclear Power Corporation.
10-6 Amendment to Exhibit 10.5 dated 2-46612 13-21
as of June 1, 1972.
F-13
-54-
<PAGE>
Prior
Exhibit Description of Exhibit
No. Document SEC Docket No.
10-7 Capital Funds Agreement dated as 2-32333 4.29
of February 1, 1968 between the
Company and Vermont Yankee
Nuclear Power Corporation.
10-8 Amendment to Exhibit 10.7 dated 70-4611 B-3
as of March 12, 1968.
10-9 Stockholder Agreement dated as 2-32333 4.30
of May 20, 1968 among the
Company and the other
stockholders of Maine Yankee
Atomic Power Company.
10-10 Power Contract dated as of May 2-32333 4.31
20, 1968 between the Company and
Maine Yankee Atomic Power
Company.
10-10.1 Amendment No. 1 to Exhibit 10-10 Annual Report on 10-1.1
dated as of March 1, 1984. Form
10-K for the year
ended December 31,
1985 of Maine
Yankee Atomic Power
company (File No.
1-6554)
F-13
-55-
<PAGE>
Prior
Exhibit Description of Exhibit
No. Document SEC Docket No.
10-10.2 Amendment No. 2 to Exhibit 10-10 Annual Report on 10-1.2
dated as of January 1, 1984. Form
10-K for the year
ended December 31,
1985 of Maine
Yankee Atomic Power
Company (File No.
1-6554)
10-10.3 Amendment No. 3 to Exhibit 10-10 Annual Report on 10-1.3
dated as of October 1, 1984. Form
10-K for the year
ended December 31,
1985 of Maine
Yankee Atomic Power
Company (File No.
1-6554)
10-10.4 Additional Power Contract Annual Report on 10-1.4
between the Company and Maine Form
Yankee Atomic Power Company 10-K for the year
dated February 1, 1984. ended December 31,
1985 of Maine
Yankee Atomic Power
Company (File No.
1-6554)
10-11 Capital Funds Agreement dated as 2-32333 4.32
of May 20, 1968 between the
Company and Maine Yankee Atomic
Power Company.
F-13
-56-
<PAGE>
Prior
Exhibit Description of Exhibit
No. Document SEC Docket No.
10-11.1 Amendment No. 1 to Exhibit 10-11 Annual Report on 10-2.1
dated as of August 1, 1985. Form
10-K for the year
ended December 31,
1985 of Maine
Yankee Atomic Power
Company (File No.
1-6554)
10-25 Agreement dated as f May 1, 1973 2-48966 13-57
for Joint Ownership,
Construction and Operation of
New Hampshire Nuclear Units
among Public Service Company of
New Hampshire and certain other
utilities, including the
Company.
10-42 Twentieth Amendment to Exhibit Annual Report on 10-42
10-25 dated as of September 19, Form
1986. 10-K for the year
ended December 31,
1986
10-46 Participation Agreement, dated 2-35073 4.23.1
June 20, 1969 among Maine
Electric Power Company, Inc.,
the Company and certain other
utilities.
F-13
-57-
<PAGE>
Prior
Exhibit Description of Exhibit
No. Document SEC Docket No.
10-47 Power Purchase and Transmission 2-35073 4.23.2
Agreement dated August 1, 1969,
among Maine Electric Power
Company, Inc., the Company and
certain other utilities,
relating to purchase and
transmission of power from The
New Brunswick Electric Power
Commission.
10-48 Agreement amending Exhibit 10-47 2-37987 4.41
dated June 24, 1970.
10-49 Agreement supplementing Exhibit 2-51545 5.7.4
10-47 dated December 1, 1971.
10-50 Assignment Agreement dated March 2-51545 5.7.5
20, 1972, between Maine Electric
Power Company, Inc., and the New
Brunswick Electric Power
Commission.
10-51 Capital Funds Agreement dated as 2-24123 4.19.1
of September 1, 1964 among
Connecticut Yankee Atomic Power
Company, the Company and certain
other utilities.
10-52 Power Contract dated as of 2-24123 4.19.2
July 1, 1964 among Connecticut
Yankee Atomic Power Company, the
Company and certain other
utilities.
F-13
-58-
<PAGE>
Prior
Exhibit Description of Exhibit
No. Document SEC Docket No.
10-53 Stockholder Agreement dated as 2-24123 4.19.3
of July 1, 1964 among the
stockholders of Connecticut
Yankee Atomic Power Company,
including the Company.
10-54 Connecticut Yankee Transmission 2-24123 4.19.4
Agreement dated as of October 1,
1964 among the stockholders of
Connecticut Yankee Atomic Power
Company, including the Company.
10-55 Agreements with Yankee Atomic
Electric Company each dated
June 30, 1959, as follows:
10-55.1 Stock Agreement. 2-15553 4.17.1
10-55.2 Power Contract. 2-15553 4.17.2
10.55.3 Research Agreement. 2-15553 4.17.3
10-56 Transmission Agreement with 2-15553 4.18
Cambridge Electric Light Company
and other sponsoring
stockholders of Yankee Atomic
Electric Company.
10-57 Agreement for Joint Ownership, 2-52900 5.16
Construction and Operation of
Wyman Unit No. 4 dated
November 1, 1974 among the
Company and certain utilities.
F-13
-59-
<PAGE>
Prior
Exhibit Description of Exhibit
No. Document SEC Docket No.
10-58 Amendment to Exhibit 10-57 dated 2-55458 5.48
as of June 30, 1975.
10-59 Amendment to Exhibit 10-57 dated 2-58251 5.19
as of August 16, 1976.
10-60 Amendment to Exhibit 10-57 dated 2-68184 5.31
as of December 31, 1978.
10-61 Transmission Agreement dated 2-54449 13-57
November 1, 1974 among the
Company and certain other
utilities, relating to Wyman
Unit No. 4.
10-62 Sharing Agreement--1979 2-50142 2.43
Connecticut Nuclear Unit dated
September 1, 1973 among the
Company and certain other
utilities, relating to Millstone
Unit No. 3.
10-63 Amendment to Exhibit 10-62 dated 2-51999 5.16
as of August 1, 1974, relating
to Millstone Unit
No. 3.
10-64 Agreement dated as of 2-58251 5.24
February 25, 1977 among the
Company, the Connecticut Light
and Power Company, the Hartford
Electric Light Company and
Western Massachusetts Electric
Company, relating to Millstone
Unit No. 3.
F-13
-60-
<PAGE>
Prior
Exhibit Description of Exhibit
No. Document SEC Docket No.
10-70 Project Agreement dated Annual Report on 10-69
December 5, 1984 among the Form
Company, the Cities of Lewiston 10-K for the year
and Auburn, Maine and certain ended December 31,
other parties, relating to 1984
development of hydro-electric
plant.
10-73 Trust Indenture dated as of 2-60786 5.27
June 1, 1977 between the Town of
Yarmouth and Casco Bank & Trust
Company, as trustee, relating to
the Town of Yarmouth's 6 3/4%
Pollution Control Revenue Bonds
(Central Maine Power Company,
1977 Series A).
10-74 Installment Sale Agreement dated 2-60786 5.28
as of June 1, 1977 between the
Town of Yarmouth and the
Company.
10-75 Agreements Relating to
$11,000,000 Floating/Fixed Rate
Pollution Control Revenue
Refunding Bonds:
10-75.1 Bond Purchase Agreement dated as Quarterly Report on 28.3
of May 1, 1984. Form 10-Q for the
quarter ended
June 30, 1984
F-13
-61-
<PAGE>
Prior
Exhibit Description of Exhibit
No. Document SEC Docket No.
10-75.2 Loan Agreement dated as of Quarterly Report on 28.4
May 1, 1984. Form 10-Q for the
quarter ended
June 30, 1984
10-76 Agreements Relating to
$8,500,000 Floating/Fixed Rate
Pollution Control Revenue Bonds:
10-76.1 Bond Purchase Agreement dated Annual Report on 10-77.1
December 28, 1984. Form
10-K for year ended
December 31, 1984
10-76.2 Loan Agreement dated as of Annual Report on 10-77.2
December 1, 1984. Form
10-K for year ended
December 31, 1984
10-77.1 Indenture of Trust dated as of Annual Report on 10-1.4
March 14, 1988 between Maine Form
Yankee Atomic Power Company and 10-K for year ended
Maine National Bank relating to December 31, 1987,
decommissioning trust funds. of Maine Yankee
Atomic Power
Company (1-6554)
10-77.1(a) Amended and Restated Indenture Annual Report on 10-6.1
of Trust dated as of January 1, Form
1993 between Maine Yankee Atomic 10-K for year ended
Power Company and The Bank of December 31, 1992,
New York relating to of Maine Yankee
decommissioning trust funds. Atomic Power
Company (1-6554)
F-13
-62-
<PAGE>
Prior
Exhibit Description of Exhibit
No. Document SEC Docket No.
10-77.2 Indenture of Trust dated as of Annual Report on 10-7
October 16, 1985 between the Form
Company and Norstar Bank of 10-K for year ended
Maine relating to the spent fuel December 31, 1985,
disposal funds. of Maine Yankee
Atomic Power
Company (1-6554)
10-78 Form of Agreement of Purchase Annual Report on 0.79
and Sale dated February 19, 1986 Form
between the Company and Eastern 10-K for the year
Utilities Associates, relating ended December 31,
to the sale of the Company's 1985
Seabrook Project interest.
10-79 Addendum to Agreement of Quarterly Report on 2.1
Purchase and Sale dated June 23, Form 10-Q for the
1986, among the Company, Eastern quarter ending
Utilities Associates and EUA June 30, 1986
Power Corporation, amending
Exhibit 10-78.
10-80 Agreement, dated as of Quarterly Report on 2.1
October 29, 1986, between the Form 10-Q for the
Company and EUA Power quarter ended
Corporation, relating to the September 30, 1986
sale of the Company's interest
in the Seabrook Project.
F-13
-63-
<PAGE>
Prior
Exhibit Description of Exhibit
No. Document SEC Docket No.
10-81 Credit Agreement, dated as of Quarterly Report on 2.2
October 15, 1986, among the Form 10-Q for the
Company, various banks and quarter ended
Continental Illinois National September 30, 1986
Bank and Trust Company of
Chicago, as agent, establishing
the terms of a $40 million
unsecured credit facility.
10-86 Labor Agreement dated as of Annual Report on 10.86
May 1, 1989 between the Company Form
(Northern, Western and Southern 10-K for the year
Division) and Local 1837 of the ended December 31,
International Brotherhood of 1989
Electrical Workers.
10-86.1 Agreement dated as of Annual Report on 10.86.1
November 25, 1991 extending Form
Labor Contract. 10-K for year ended
December 31, 1991
10-89 1987 Executive Incentive Plan, Annual Report on 10.89
as amended January 20, 1993.* Form
10-K for year ended
December 31, 1992
10-90 Deferred Compensation Plan for Annual Report on 10.90
Non-Employee Directors, as Form
amended and restated effective 10-K for year ended
February 1, 1992.* December 31, 1992
10-91 Retirement Plan for Outside Annual Report on 10.91
Directors, as amended and Form
restated effective April 24, 10-K for year ended
1991.* December 31, 1992
F-13
-64-
<PAGE>
Prior
Exhibit Description of Exhibit
No. Document SEC Docket No.
10-92 Employment Agreement between the Filed herewith
Company and Matthew Hunter dated
as of October 20, 1993.*
10-93 Central Maine Power Company Filed herewith
Long-Term Incentive Plan.*
10-94 Central Maine Power Company Filed herewith
Supplemental Executive
Retirement Plan, as amended and
restated effective January 1,
1993.*
*Management contract or compensatory plan or arrangement required to be filed
in response to Item 14(c) of
Form 10-K.
EXHIBIT 11: STATEMENT RE COMPUTATION OF PER
SHARE EARNINGS
Not Applicable.
EXHIBIT 12: STATEMENTS RE COMPUTATION OF
RATIOS
Not Applicable.
EXHIBIT 13: ANNUAL REPORT TO SECURITY
HOLDERS, FORM 10-Q OR QUARTERLY
REPORT TO SECURITY HOLDERS
F-13
-65-
<PAGE>
Prior
Exhibit Description of Exhibit
No. Document SEC Docket No.
13-1 Management's Discussion and Filed herewith
Analysis of Financial Condition
and REsults of Operations and
Financial Statements from Annual
Report of Central Maine Power
Company to Shareholders for the
year ended December 31, 1993
(pages 1-49).
EXHIBIT 16: LETTER RE CHANGE IN CERTIFYING Current Report on 16.1
ACCOUNTANT Form 8-K/A dated
January 13, 1994
EXHIBIT 18: LETTER RE CHANGE IN ACCOUNTING
PRINCIPLES
Not Applicable.
EXHIBIT 21: SUBSIDIARIES OF THE REGISTRANT
List of subsidiaries of Annual Report on 22.1
registrant. Form
10-K for year ended
December 31, 1992
EXHIBIT 22: PUBLISHED REPORT CONCERNING
MATTERS SUBMITTED TO VOTE OF
SECURITY HOLDERS
Not Applicable.
EXHIBIT 23: CONSENTS OF EXPERTS AND COUNSEL
F-13
-66-
<PAGE>
Prior
Exhibit Description of Exhibit
No. Document SEC Docket No.
23-1 Consent of Arthur Andersen & Co. Filed herewith at
to the incorporation by page F-3
reference of their reports
included or incorporated by
reference herein in the
Company's Registration
Statements (File Number 33-
36679, 33-39826, 33-44754, 33-
44944 and 33-51611).
EXHIBIT 24: POWER OF ATTORNEY
Not Applicable.
EXHIBIT 27: FINANCIAL DATA SCHEDULE
Not Applicable.
EXHIBIT 28: INFORMATION FROM REPORTS
FURNISHED TO STATE INSURANCE
REGULATORY AUTHORITIES
Not Applicable.
EXHIBIT 99: ADDITIONAL EXHIBITS
To be filed under cover of a
Form 10-K/A amendment of this
Form 10-K within 180 days after
December 31, 1993, pursuant to
Rule 15d-21 under the Securities
Exchange Act of 1934:
F-13
-67-
<PAGE>
Prior
Exhibit Description of Exhibit
No. Document SEC Docket No.
99-1 and -2 Information, financial
statements and exhibits required
by Form 11-K with respect to
certain employee savings plans
maintained by the Company.
</TABLE>
F-13
-68- <PAGE>
Exhibit 10-92
EMPLOYMENT AGREEMENT
THIS AGREEMENT made as of this 20th day of October, 1993 by
and between MATTHEW HUNTER ("Hunter") of Chelsea, in the County
of Kennebec and State of Maine, and CENTRAL MAINE POWER COMPANY,
a corporation organized and existing under the laws of the State
of Maine and having its principal place of business at Augusta,
in the County of Kennebec and State of Maine ("CMP");
W I T N E S S E T H:
WHEREAS, Hunter is presently serving as President and Chief
Executive Officer of CMP and the parties desire to continue that
relationship, and to reach a written agreement as to the terms
and conditions of that employment;
WHEREAS, Hunter and CMP have an existing Employment
Agreement dated August 28, 1991, which the parties desire to
terminate; and
WHEREAS, Hunter has foregone any salary increase during the
past three years, notwithstanding his serving CMP in an exemplary
fashion.
NOW THEREFORE, in consideration of these premises and the
covenants herein contained, the parties agree as follows:
1. Hunter and CMP agree that the Employment Agreement
dated August 28, 1991 is hereby terminated and neither party
shall have any further obligations, rights or responsibilities
with respect to the provisions thereof.
2. Subject to the terms and conditions hereof, CMP hereby
employs Hunter as its President and Chief Executive Officer to
serve for a period of time at the pleasure of the CMP Board of
<PAGE>
Directors, but in no event to continue after February 1, 1995.
Hunter shall also be elected to such other offices and
directorships of subsidiary and affiliated entities as the Board
shall deem appropriate. Hunter accepts such employment, and
shall serve as President and Chief Executive Officer subject to
the Company's By-Laws, any position description as adopted or
amended by the Board of Directors now or in the future, and to
the direction of the Board of Directors and its Governance
Committee. The parties recognize that Section 4.3 of the CMP
By-Laws provides that the officers may be elected annually by the
Board.
3. Hunter agrees during the period he is employed
hereunder to devote his full time and attention to the business
of CMP. Hunter shall retain the right to expend reasonable
amounts of time for professional, charitable and civic
activities, in accordance with his past practices, provided such
activities do not interfere with the services required to be
performed hereunder, and provided further that Hunter will not
accept any future commitments requiring the expenditure of
significant amounts of time, without the consent of the CMP
Governance Committee.
4. During the period Hunter is employed hereunder, CMP
shall pay to Hunter, as compensation for the services hereunder,
a base salary at the annual rate of Two Hundred Eighty-Five
Thousand Dollars ($285,000).
5. During the period Hunter is employed hereunder, Hunter
shall participate in all of CMP's regular fringe benefit programs
and employee benefit plans, in accordance with the terms of such
<PAGE>
programs and plans as they presently exist or may hereafter be
amended which are applicable to CMP's senior officers. Hunter
shall be entitled to maintain all his existing rights and
benefits in said regular fringe benefit programs and employee
benefit plans as they may exist as of the effective date hereof,
and as they may be subsequently amended or terminated.
6. Upon Hunter's retirement, on February 1, 1995 or prior
thereto with the mutual consent for Hunter and CMP, Hunter shall
be entitled to receive an annual benefit (the "Benefit"), payable
in equal monthly payments, of: (i) sixty-five (65%) percent of
Hunter's total compensation earned during the immediately
preceding twelve months including any incentive compensation and
deferred compensation, if any, but specifically excluding from
such compensation any payments actually received by or accrued
for Hunter pursuant to any long term incentive plan adopted by
the Board of Directors of CMP; with the Benefit undiminished by
(x) any amount receivable by Hunter or his spouse pursuant to
Social Security, (y) any so-called early retirement reduction
such as that provided in CMP's Retirement Income Plan for Non-
Union Employees (the "Plan"), or (z) any so-called joint and
survivor formula reduction such as that provided in the Plan;
from the Benefit shall be subtracted: (ii)(a) any benefits to
which Hunter would be entitled pursuant to the fifty percent
(50%) joint and survivor annuity benefit with Hunter's wife as
contingent annuitant, all pursuant to the Plan, which election
Hunter agrees to make, provided nevertheless, if Hunter is then
unmarried there shall be subtracted the life annuity benefit to
which Hunter would be entitled pursuant to the Plan, whether or
<PAGE>
not such election has been made; (b) any benefits payable under
any supplemental employee benefit plan instituted by CMP after
the date hereof; and (c) any benefits under any disability income
protection plan maintained by CMP.
In the event that prior to February 1, 1995, CMP terminates
Hunter's employment for any reason other than cause as described
in Section 12(c) hereof, Hunter shall be entitled to receive the
Benefit, above described.
7. In the event Hunter dies prior to February 1, 1995, and
prior to his receipt of any benefits hereunder, Hunter's spouse
shall be entitled to receive for her lifetime, one-half of the
amount to which Hunter would have been entitled pursuant to
Section 6 hereof.
In the event Hunter dies after the date of this Agreement,
having received benefits hereunder, Hunter's spouse shall be
entitled to receive for her lifetime, one-half of the amount
which Hunter was then receiving.
8. Any benefit payable to Hunter or his spouse pursuant to
this Employment Agreement shall be determined by the actuary then
providing services to CMP in connection with the administration
of the Plan. The actuary's good faith determination of the
amounts payable hereunder shall be final and binding upon the
parties.
9. Upon the termination of Hunter's employment for any
reason whatsoever, any benefit which Hunter received pursuant to
this Agreement shall be in total satisfaction of any and all
rights which Hunter may have against CMP, the Board or any
Committee thereof.
<PAGE>
10. During the period Hunter is employed hereunder, CMP
shall provide Hunter with an automobile and the payment of, or
reimbursement for, travel and other out-of-pocket expenses
reasonably incurred by Hunter in the performance of his duties
hereunder.
11. Hunter agrees that during the employment period and for
a term of two years after any termination of Hunter's employment
with CMP for any reason, voluntarily or involuntarily, he shall
not, without the prior written consent of CMP's Governance
Committee, directly or indirectly, acquire any interest in as
stockholder, director, consultant, agent, employee, partner,
owner of real estate, or otherwise act, with or without
compensation, for any corporation, entity or business which is at
the time or thereafter involved with any business related to the
production, generation, co-generation, or distribution of
electrical energy within the geographical area in which CMP does
business now or in the future, or engage in activities which in
CMP's reasonable judgment, may be deemed competitive with the
activities of CMP; with the exception that Hunter may acquire and
own minority stock holdings in companies whose shares are listed
for trading on the American or New York Stock Exchanges, or
traded "over the counter," and regularly reported by NASDAQ.
The parties agree that the subject matter, duration of, and
geographic area covered by this covenant are reasonable in light
of the facts as they exist on the date hereof. However, if at
any time a court or other body having jurisdiction over this
Agreement shall determine that any of the subject matter,
duration or geographic area hereof is unreasonable in any
<PAGE>
respect, it shall be reduced, and not terminated, as such court
or body determined may be reasonable.
12. Except as otherwise specifically provided herein, this
Agreement and Hunter's services hereunder
(a) shall terminate forthwith upon his death, in which
event the benefits payable to Hunter's spouse would be
determined in accordance with the provisions of Section 6
or 7 hereof, whichever is applicable; and
(b) may be terminated by CMP if Hunter becomes totally
disabled in which event he shall be entitled to receive a
benefit as determined in accordance with Section 6 hereof;
and
(c) may be terminated by CMP for cause, which for the
purposes of this Agreement shall include any of the
following: failure to follow the express directions of the
Board of Directors or the Governance Committee, dishonest or
illegal conduct, a material violation of any of the
provisions of this Agreement, or the conviction of a crime,
other than a minor traffic violation; in which event no
payments shall be due Hunter or his spouse under this
Agreement.
13. Any notice or other communication provided for herein
or contemplated hereby shall be sufficiently given or made if in
writing and delivered or mailed, certified mail - return receipt
requested as follows:
To CMP:
Central Maine Power Company
General Office
Edison Drive
Augusta, Maine 04336
Attention: Chairman of the Governance Committee
To Hunter:
Mr. Matthew Hunter
R.F.D. #2, Box 430
Augusta, Maine 04330
14. This Agreement shall be binding upon and inure to the
benefit of the parties hereto, and their respective heirs, legal
<PAGE>
representatives, successors and assigns.
15. This Agreement shall be governed by and construed in
accordance with the laws of the State of Maine, and may be
amended only in writing. This Agreement contains the entire
agreement and understandings of the parties with respect to the
subject matter hereof, and supersedes any and all prior
agreements and understandings whether oral or written between
Hunter and CMP.
IN WITNESS WHEREOF, Matthew Hunter and Central Maine Power
Company have executed this agreement as of the date first written
above.
WITNESS:
Laurie E. Halligan Matthew Hunter
Matthew Hunter
"Hunter"
CENTRAL MAINE POWER COMPANY
William M. Finn By: Carlton D. Reed, Jr.
Its Chairman of the Board
"CMP" <PAGE>
Exhibit 10-93
CENTRAL MAINE POWER COMPANY
LONG-TERM INCENTIVE PLAN
<PAGE>
CENTRAL MAINE POWER COMPANY
LONG-TERM INCENTIVE PLAN
Table of Contents
Section Page
1. Purpose . . . . . . . . . . . . . . . . . . . . . . . . 1
2. Definitions . . . . . . . . . . . . . . . . . . . . . 2
3. Grant of Awards . . . . . . . . . . . . . . . . . . . . 4
a. Authority . . . . . . . . . . . . . . . . . . . . . 4
b. Eligibility . . . . . . . . . . . . . . . . . . . . 5
c. Amount of Award . . . . . . . . . . . . . . . . . . 5
d. Limitations on Awards . . . . . . . . . . . . . . . 6
4. Restriction Period . . . . . . . . . . . . . . . . . . 7
a. Transfer Restrictions . . . . . . . . . . . . . . . 7
b. Termination of Employment . . . . . . . . . . . . . 7
c. Stock Certificates . . . . . . . . . . . . . . . . 8
5. Award Payouts . . . . . . . . . . . . . . . . . . . . . 9
6. Beneficiary . . . . . . . . . . . . . . . . . . . . . 10
a. Designation . . . . . . . . . . . . . . . . . . . 10
b. No Beneficiary . . . . . . . . . . . . . . . . . 10
7. Administration of the Plan . . . . . . . . . . . . . 11
a. Section 16 Compliance . . . . . . . . . . . . . . 11
b. Decisions and Interpretations . . . . . . . . . . 11
c. Procedure . . . . . . . . . . . . . . . . . . . . 12
d. Advisors . . . . . . . . . . . . . . . . . . . . 12
e.Indemnification . . . . . . . . . . . . . . . . . . 12
8. Amendment or Discontinuance . . . . . . . . . . . . . 13
9. Purchase of Stock . . . . . . . . . . . . . . . . . . 14
a. Agent and Purchases by Agent . . . . . . . . . . 14
b. Custody and Sales by Agent . . . . . . . . . . . 14
- i -
<PAGE>
10. Miscellaneous . . . . . . . . . . . . . . . . . . . . 15
a. No Claim or Right . . . . . . . . . . . . . . . . 15
b. Leave . . . . . . . . . . . . . . . . . . . . . . 16
c. Incapacity . . . . . . . . . . . . . . . . . . . 16
d. No Assignment . . . . . . . . . . . . . . . . . . 17
e. Plan Documents . . . . . . . . . . . . . . . . . 17
f. Applicability of Laws . . . . . . . . . . . . . . 17
g. Notices . . . . . . . . . . . . . . . . . . . . . 17
h. Successors Bound . . . . . . . . . . . . . . . . 17
i. Captions . . . . . . . . . . . . . . . . . . . . 18
11. Effective Date and Shareholder Approval . . . . . . . 18
- ii -
<PAGE>
CENTRAL MAINE POWER COMPANY
LONG-TERM INCENTIVE PLAN
1. Purpose
The purpose of the Central Maine Power Company Long-Term
Incentive Plan is to motivate Key Employees of Central Maine
Power Company to attain and surpass long-range performance
objectives intended to provide the shareholders of the Company
sound returns on their investment. Under the Plan, the
motivation of Key Employees to improve performance is enhanced by
providing them with incentive awards that are payable only to the
extent that performance results in shareholder benefits. The
Plan further aligns the interests of Key Employees with those of
the Company's shareholders by providing for such incentive awards
to be paid in the form of the Common Stock of the Company subject
to performance and other restrictions set forth in the Plan. The
Plan is also designed to attract and retain persons of ability as
Key Employees of the Company by providing them with compensation
opportunities that are competitive with those offered by other
utilities.
The long-range performance objectives under the Plan are
intended to complement certain performance objectives under the
Company's 1987 Executive Incentive Plan that are designed to
benefit the Company's customers. Together, the Plan and the 1987
Executive Incentive Plan place a greater portion of total pay
offered to Key Employees at risk by providing for that portion of
compensation to be paid only to the extent that performance has
resulted in benefits for the Company's shareholders and
customers.
2. Definitions
When used herein, the following terms shall have the
following meanings:
"Award" means a contingent grant to any Key Employee, in
accordance with the provisions of the Plan, of Performance
Restricted Stock or other Common Stock of the Company, as may be
determined by the Compensation and Benefits Committee.
"Award Payout" means any shares of Performance Restricted
Stock including the shares of Performance Restricted Stock
resulting from the reinvestment of dividends, after the lapse of
the Restriction Period applicable thereto, and any additional
shares of the Common Stock of the Company, actually distributed
to any Key Employee based on the level of performance achieved
for the relevant Performance Period as measured by reference to
the Performance Measure and any other performance standards
established by the Compensation and Benefits Committee.
"Beneficiary" means the beneficiary or beneficiaries
designated pursuant to Section 6 to receive an Award Payout or
Award Payouts, if any, under the Plan upon the death of a Key
Employee.
"Company" means Central Maine Power Company and its
successors and assigns.
"Compensation and Benefits Committee" means the Central
Maine Power Company Compensation and Benefits Committee appointed
by the Board of Directors of the Company and responsible for the
administration of the Plan.
"Key Employee" means an employee, including without
limitation any officer, of the Company whose contributions and
-1-
<PAGE>
responsibilities have a significant impact on the future of the
Company, in the judgment of the Compensation and Benefits
Committee.
"Market Value" means, as of any specified date, the reported
closing price based upon composite transactions on the New York
Stock Exchange for one share of the common stock of any specified
electric utility, including without limitation the Company, on
such exchange, or, if no sales of that utility's common stock
have taken place on such exchange on that date, the reported
closing price on the most recent earlier trading day on which
sales of such common stock were reported.
"Performance Measure" means the Company's Total Shareholder
Return or a change, on a basis determined by the Compensation and
Benefits Committee, in the Company's Total Shareholder Return as
ranked against the Total Shareholder Return of other electric
utilities designated by the Compensation and Benefits Committee
or a change in such other utilities' Total Shareholder Return,
and, alternatively, also means improvement in the ranking of the
Company's Total Shareholder Return or in the ranking of the level
of change therein, in each case based on levels of performance
established by the Compensation and Benefits Committee.
"Performance Period" means a period of three (3) or more
years, as determined by the Compensation and Benefits Committee,
beginning on the first day of the first year of such period or at
such other time as may be determined by the Compensation and
Benefits Committee, over which performance is measured by
reference to the Performance Measure and any other performance
standards established by the Compensation and Benefits Committee.
"Performance Restricted Stock" means the Common Stock of the
Company granted under the Plan for no consideration but subject
to the requirements and restrictions of Sections 3 and 4 hereof
and such other restrictions as the Compensation and Benefits
Committee deems appropriate or desirable, and includes additional
shares of Performance Restricted Stock resulting from the
reinvestment of dividends.
"The Plan" or "this Plan" means the Central Maine Power
Company Long-Term Incentive Plan, as the same may be amended,
administered or interpreted from time to time.
"Restriction Period" means the period described in Section
4.a of this Plan.
"Total Disability" means the complete and permanent
inability of a Key Employee to perform all of his or her duties
under the terms of his or her employment with the Company, as
determined by the Compensation and Benefits Committee upon the
basis of such evidence, which may include independent medical
reports and data, as the Compensation and Benefits Committee
deems appropriate or necessary.
"Total Shareholder Return" means the appreciation or
depreciation in the Market Value of the common stock of an
electric utility, including without limitation the Company, plus
dividends thereon, as measured at any point in, or as averaged
over, a Performance Period.
3. Grant of Awards
a. Authority. Subject to the provisions of the Plan, the
Compensation and Benefits Committee shall have the full power and
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authority to (i) determine and designate from time to time the
Key Employees or groups of Key Employees to whom Awards may be
granted; (ii) determine the amount, terms and conditions of each
Award, including, in addition to the Performance Measure and any
part thereof, any performance standards pertaining to the Company
or otherwise and any other criteria that must be satisfied as a
condition to any Award Payout; (iii) determine the form or forms
of Awards that may be granted; and (iv) determine the timing of
any Award and Award Payout, including Performance Periods and
whether and to what extent an Award or Award Payout shall be
deferred and the conditions of any such deferral.
b. Eligibility. The Compensation and Benefits Committee
shall determine and designate from time to time the Key Employees
or groups of Key Employees eligible to participate in the Plan,
based upon the Key Employee's contribution towards the
achievement of the Company's long-range corporate objectives, the
recommendations of the President and Chief Executive Officer of
the Company with respect to Key Employees other than the
President and Chief Executive Officer, and such other factors as
the Compensation and Benefits Committee, in its discretion, deems
relevant.
c. Amount of Award. Subject to the provisions of the Plan,
Key Employees participating in the Plan shall be granted an Award
of a specified number of shares of Performance Restricted Stock
for each Performance Period under the Plan. The number of shares
of Performance Restricted Stock granted to any Key Employee shall
be determined by the Compensation and Benefits Committee, taking
into account the purposes of the Plan and such factors as the
Compensation and Benefits Committee, in its discretion, deems
relevant. Such factors may include the value of the Key
Employee's position with the Company, market levels of similar
compensation, and the Market Value of the Company's Common Stock,
and the Compensation and Benefits Committee may develop a formula
based on these or other factors deemed relevant by the
Compensation and Benefits Committee. Any such formula shall not
be revised more than once in any six (6) month period. Subject
to the restrictions set forth in or established by the
Compensation and Benefits Committee pursuant to this Plan, each
Key Employee who receives an Award shall, upon the issuance of a
certificate for the shares of Performance Restricted Stock
awarded as provided in Section 4.c hereof, have all of the rights
of a shareholder with respect to such shares, including the right
to vote the shares and receive dividends and other distributions
for his or her account. Dividends on shares of Performance
Restricted Stock shall be payable at the same rate as paid on the
unrestricted shares of the Common Stock of the Company and shall
be reinvested in additional shares of Performance Restricted
Stock during the Performance Period until any Award Payout. Such
additional shares shall be added to the shares of Performance
Restricted Stock constituting the Award and shall be subject in
all respects to the provisions of Sections 4.a, 4.b and 5 of this
Plan and to other applicable provisions hereof.
d. Limitations on Awards. Subject to the provisions of
this Section 3.d, in any calendar year, grants of Awards,
together with additional shares of Performance Restricted Stock
resulting from the reinvestment of dividends, shall not exceed
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one percent (1%) of the number of outstanding shares of the
unrestricted Common Stock of the Company on the last day of the
preceding calendar year. In the event of any recapitalization,
reclassification, split-up or consolidation of shares of the
Common Stock of the Company, merger or consolidation of the
Company into, or consolidation of the Company with, or sale by
the Company of all or substantially all of its assets to, another
company, or other restructuring or event which could distort the
implementation of the Plan or the value of the Awards or affect
the realization of the objectives of the Plan, the Compensation
and Benefits Committee may make such adjustments in any Awards,
or in the terms, conditions or restrictions pertaining to the
Performance Restricted Stock or the Awards, as the Compensation
and Benefits Committee deems equitable.
4. Restriction Period
a. Transfer Restrictions. Each Award of Performance
Restricted Stock and additional shares of Performance Restricted
Stock resulting from the reinvestment of dividends on the shares
constituting the Award as provided in Section 3.c of this Plan
shall be subject to a Restriction Period, which shall mean a
period commencing on the date the Award is granted and ending as
of the date of any Award Payout relating to such Award. No
shares of Performance Restricted Stock received or held for the
account of a Key Employee as provided in this Plan shall be sold,
assigned, exchanged, pledged or otherwise transferred or disposed
of during the Restriction Period. The Compensation and Benefits
Committee may provide for the lapse of restrictions in
installments in circumstances it deems appropriate.
b. Termination of Employment. If a Key Employee's
employment with the Company terminates due to the Key Employee's
death, Total Disability, retirement, voluntary resignation or for
any other reason, all Awards granted for Performance Periods that
have not yet closed as of the date of any such event and all
additional shares of Performance Restricted Stock resulting from
the reinvestment of dividends on shares constituting such Awards
shall be forfeited by the Key Employee and all such shares shall
be acquired by the Company unless the Compensation and Benefits
Committee, in its sole discretion, otherwise determines. In
making any determination under this Section 4.b, the Compensation
and Benefits Committee may, in its discretion, permit an Award
Payout relating to all or a portion of any relevant Performance
Period and impose any terms and conditions, consistent with the
provisions of this Plan, as it deems appropriate.
c. Stock Certificates. After compliance with any
applicable requirements of federal and state securities laws and
regulations and the rules of any stock exchange on which the
Common Stock of the Company is then listed, a certificate for the
number of shares of Performance Restricted Stock granted to a Key
Employee shall be issued and shall be registered in the name of
the Key Employee and bear an appropriate legend reciting the
restrictions applicable to such shares or shall be registered in
nominee name. All certificates issued under the Plan shall be
subject to appropriate stop-transfer orders, including such stop-
transfer orders and other restrictions as the Compensation and
Benefits Committee may deem advisable under any applicable
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federal or state securities laws and rules, regulations or other
requirements of the Securities and Exchange Commission and any
stock exchange on which the Common Stock of the Company is then
listed. All certificates representing Awards and all additional
shares of Performance Restricted Stock resulting from the
reinvestment of dividends shall be received and held by the
Company or a bank or other institution, as determined by the
Compensation and Benefits Committee, during the Restriction
Period for the account of each individual Key Employee who was
granted an Award.
5. Award Payouts
Following the close of each Performance Period, the
Compensation and Benefits Committee shall evaluate performance
results by reference to the Performance Measure and any other
performance standards established for that Performance Period.
Based on its evaluation and the consideration of any other
factors it may deem appropriate, the Compensation and Benefits
Committee shall determine whether and to what extent any Award
Payouts shall be made. Each Award Payout to be made shall be
reduced, prior to being made, by the number of shares of the
Common Stock of the Company whose Market Value is sufficient to
satisfy all applicable federal and state tax withholding
requirements. Notwithstanding the attainment of a level of
performance under the Performance Measure or any other
performance standard established by the Compensation and Benefits
Committee otherwise sufficient for any Award Payout, no Award
Payout shall be made for a Performance Period during which the
dividend on the Common Stock of the Company may have been
reduced. In such event, the Compensation and Benefits Committee
shall consider whether and to what extent to defer an Award
Payout and shall determine the conditions of any such deferral,
taking into account circumstances it deems appropriate. If the
Compensation and Benefits Committee determines that no Award
Payout shall be made at any time with respect to a Performance
Period, the Award for that Performance Period and any additional
shares of Performance Restricted Stock resulting from the
reinvestment of dividends shall be forfeited by the Key Employee
and acquired by the Company.
6. Beneficiary
a. Designation. Each Key Employee shall file with the
Compensation and Benefits Committee a written designation of one
or more persons as the Beneficiary who shall be entitled to
receive an Award Payout or Award Payouts, if any, under the Plan
upon such Key Employee's death. A Key Employee may from time to
time revoke or change his or her Beneficiary designation, without
the consent of any prior Beneficiary (unless such consent is
otherwise required by law) by filing a new designation with the
Compensation and Benefits Committee. The last such designation
received by the Compensation and Benefits Committee shall be
controlling; provided, however, that no designation, or change or
revocation thereof, shall be effective unless received by the
Compensation and Benefits Committee prior to the Key Employee's
death, and in no event shall it be effective as of a date prior
to such receipt.
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b. No Beneficiary. If no Beneficiary designation is in
effect at the time of a Key Employee's death, or if such
designation conflicts with law, or if no designated Beneficiary
survives the Key Employee, the Key Employee's estate shall be
entitled to receive an Award Payout or Award Payouts, if any,
under the Plan upon the Key Employee's death. If the
Compensation and Benefits Committee is in doubt as to the right
of any person to receive any Award Payout, the Company may retain
such Award Payout, without liability for any interest thereon,
until the Compensation and Benefits Committee determines the
rights thereto, or the Company may turn over such Award Payout to
any court of appropriate jurisdiction and such turnover shall be
a complete discharge of any liability of the Company in
connection with such Award Payout.
7. Administration of the Plan
a. Section 16 Compliance. The Plan shall be administered
by the Compensation and Benefits Committee in conformance with
the requirements of Rule 16b-3 under the Securities Exchange Act
of 1934 as said Rule may be interpreted or amended from time to
time, the intent of this Plan being that all transactions
hereunder shall comply with all applicable conditions of said
Rule 16b-3 or its successor.
b. Decisions and Interpretations. All decisions,
determinations or actions of the Compensation and Benefits
Committee made or taken pursuant to grants of authority under
this Plan shall be made or taken in the sole discretion of the
Compensation and Benefits Committee and shall be final,
conclusive and binding on all persons for all purposes. In
addition, the Compensation and Benefits Committee shall have full
power, discretion and authority to establish rules and
guidelines, consistent with this Plan, for the administration of
the Plan and to interpret, construe and administer the Plan and
such rules and guidelines and any part thereof, and its
interpretations and constructions thereof shall be final,
conclusive and binding on all persons for all purposes. The
decisions and determinations of the Compensation and Benefits
Committee under the Plan need not be uniform with respect to Key
Employees, whether or not such Key Employees are similarly
situated.
c. Procedure. The Compensation and Benefits Committee
shall keep minutes of its actions under the Plan. The act of a
majority of the members of the Compensation and Benefits
Committee present at a meeting duly called and held shall be the
act of the Compensation and Benefits Committee, provided that at
least a majority of the members of the entire Compensation and
Benefits Committee is in attendance at such meeting. Any
decision or determination reduced to writing and signed by all
members of the Compensation and Benefits Committee shall be fully
as effective as if made by unanimous vote at a meeting duly
called and held.
d. Advisors. The Compensation and Benefits Committee may
employ such legal counsel, whether independent legal counsel or
counsel regularly employed by the Company, and consultants and
agents as the Compensation and Benefits Committee may deem
appropriate for the administration of the Plan and shall be fully
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protected in relying upon any opinion received from any such
counsel or consultant and any computations received from any such
consultant or agent. All expenses incurred by the Compensation
and Benefits Committee in interpreting and administering the
Plan, including without limitation meeting fees and expenses and
professional fees, shall be paid by the Company.
e. Indemnification. No member or former member of the
Compensation and Benefits Committee shall be liable for any
action or determination made in good faith with respect to the
Plan or any Award or Award Payout under the Plan. Each member or
former member of the Compensation and Benefits Committee shall be
indemnified and held harmless by the Company against all cost and
expense (including counsel fees) and liability (including any sum
paid in settlement of a claim with the approval of the Board of
Directors of the Company) arising out of any action taken or
omitted in connection with the Plan unless arising out of such
member's or former member's own willful misconduct. Such
indemnification shall be in addition to any rights of
indemnification the members or former members of the Compensation
and Benefits Committee may have as directors or under the bylaws
of the Company.
8. Amendment or Discontinuance
The Board of Directors of the Company may, at any time,
amend or terminate the Plan. The Plan may also be amended by the
Compensation and Benefits Committee, provided that all such
amendments shall also be reported to and acted upon by the Board
of Directors. No amendment shall, without approval by the
holders of a majority of the shares of the Common Stock and 6%
Preferred Stock of the Company present, or represented, and
entitled to vote at a meeting duly called and held, (i)
materially modify the requirements as to eligibility for
participation in the Plan, (ii) materially increase the benefits
provided under the Plan, or (iii) materially increase the maximum
number of shares of Performance Restricted Stock which are
available under the Plan. No amendment or termination shall
retroactively impair any rights of any person with respect to an
Award or Award Payout, and all amendments shall comply with the
requirements of Rule 16b-3 of the Securities Exchange Act of 1934
as said Rule may be interpreted or amended from time to time.
9. Purchase of Stock
a. Agent and Purchases by Agent. Notwithstanding any other
provision of this Plan, the Compensation and Benefits Committee
shall appoint an agent for Key Employees, and not for the
Company, for the purchase of Common Stock of the Company to be
granted under the Plan and for the purchase of additional shares
of Common Stock representing reinvested dividends. Such agent
shall not be an affiliate of the Company. The agent (and not the
Company or any affiliate thereof) shall exercise all direct and
indirect control and influence over the times when, and the
prices at which, the agent may purchase or cause to be purchased
Common Stock for the benefit or account of Key Employees under
the Plan, the amount of any such Common Stock to be purchased,
the manner in which any such Common Stock is to be purchased, and
the selection of a broker or dealer through which such purchases
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<PAGE>
may be executed; provided, however, that the Compensation and
Benefits Committee may provide the agent with any formula adopted
by the Compensation and Benefits Committee pursuant to Section
3.c of the Plan for determining the number of shares of Common
Stock to be purchased by the agent under the Plan and may provide
the agent with instructions which are not inconsistent with the
provisions of this Section 9.
b. Custody and Sales by Agent. The agent (or its delegate)
shall hold all shares of Common Stock purchased in connection
with Awards granted for the initial Performance Period under the
Plan and all additional shares of Common Stock resulting from the
reinvestment of dividends thereon, in each case on behalf of the
particular Key Employee who was granted an Award. In the event
that the shareholders of the Company approve the Plan pursuant to
Section 11 hereof, then such Common Stock shall be held on behalf
of the Key Employees as directed by the Compensation and Benefits
Committee, in accordance with the terms of the Plan. In the
event that such shareholder approval is not obtained, the agent
shall sell all shares of Common Stock purchased, including shares
representing reinvested dividends. The agent (and not the
Company or any affiliate thereof) shall exercise all direct and
indirect control and influence over the times when, and the
prices at which, the agent may sell or cause to be sold such
Common Stock, the manner in which any such Common Stock is to be
sold, and the selection of a broker or dealer through which such
sales may be executed. All proceeds of such sales shall be paid
to the Company.
10. Miscellaneous
a. No Claim or Right. Nothing in this Plan and no Award or
Award Payout hereunder shall confer upon any Key Employee any
right to continue in the employ of the Company, or shall
interfere in any way with the right (subject to any separate
contractual arrangement with such Key Employee) of the Company to
terminate his or her employment at any time. No Award or Award
Payout under the Plan shall be deemed salary or compensation for
the purpose of computing benefits under any employee benefit
plan, including any retirement or supplemental or excess
retirement benefit plan, or other arrangement of the Company for
the benefit of its employees unless the Compensation and Benefits
Committee shall determine otherwise. No Key Employee shall have
any claim or right to any Award or Award Payout until an Award
Payout relating to a particular Award is actually made under the
Plan, and any such right shall be no greater than the right of an
unsecured general creditor of the Company. Nothing contained in
this Plan, and no action taken pursuant to its provisions, shall
create or be construed to create a trust of any kind between the
Company and any Key Employee.
b. Leave. Absence on leave approved by the President and
Chief Executive Officer of the Company shall not be considered
interruption or termination of employment for any purposes of the
Plan; provided, however, that the Compensation and Benefits
Committee shall determine, in its discretion, whether an Award
may be granted or an Award Payout may be made to a Key Employee
if he or she is absent on leave during the Performance Period.
c. Incapacity. If the Compensation and Benefits Committee
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shall find that any person entitled to receive any Award Payout
under the Plan is unable to care for his or her affairs because
of illness or accident, or is a minor, then any Award Payout due
him or her may, if the Compensation and Benefits Committee so
directs the Company, be paid to his or her spouse, an institution
maintaining or having custody of such person, or any other person
deemed by the Compensation and Benefits Committee to be a proper
recipient on behalf of such person otherwise entitled to such
Award Payout, unless a prior claim therefor has been made by a
duly appointed legal representative. Any such Award Payout shall
be a complete discharge of any liability of the Company in
connection with such Award Payout.
d. No Assignment. The interest of any Key Employee or
other person in any Award or Award Payout under the Plan may not
be assigned, transferred, pledged or encumbered, except as
provided in Section 6 with respect to the designation of a
Beneficiary or as may otherwise be required by law, and any such
assignment, transfer, pledge or encumbrance shall be void.
e. Plan Documents. Copies of the Plan and all amendments,
administrative rules and guidelines, and interpretations shall be
made available to all Key Employees at all reasonable times at
the Company's headquarters.
f. Applicability of Laws. The Plan and Awards and Award
Payouts hereunder shall be subject to all applicable federal and
state laws, rules and regulations and to such approvals by any
governmental or regulatory agency as may be required.
g. Notices. All requests, notices and other communications
from a Key Employee, Beneficiary or other person to the
Compensation and Benefits Committee, required or permitted under
the Plan, shall be in such form as may be prescribed from time to
time by the Compensation and Benefits Committee and shall be
mailed by first class mail or delivered to the Company's
headquarters or such other location as may be specified by the
Compensation and Benefits Committee.
h. Successors Bound. The terms of the Plan shall be
binding upon the Company and its successors and assigns.
i. Captions. Captions preceding the Sections and
subsections hereof are inserted solely as a matter of convenience
and in no way define or limit the scope or intent of any
provision hereof.
11. Effective Date and Shareholder Approval
The effective date of this Plan shall be January 1, 1993;
provided, however, that grants of Awards shall be conditioned
upon approval of the Plan by the holders of a majority of the
shares of the Company's Common Stock and 6% Preferred Stock
present, or represented, and entitled to vote at the 1994 Annual
Meeting of the Shareholders of the Company. Notwithstanding
anything in the Plan to the contrary, Key Employees may be
selected for participation in the Plan, Award criteria may be
determined and Awards conditioned on such shareholder approval
may be granted, all as provided herein, prior to submission of
the Plan for approval by the shareholders. In the event that
such shareholder approval is not obtained, all Awards and any
additional shares of Performance Restricted Stock resulting from
the reinvestment of dividends shall be forfeited and the Plan
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shall be cancelled.
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Exhibit 10-94
CENTRAL MAINE POWER COMPANY
SUPPLEMENTAL EXECUTIVE RETIREMENT PLAN
As Amended and Restated Effective January 1, 1993
<PAGE>
PREAMBLE
The primary objective of the Central Maine Power Company
Supplemental Executive Retirement Plan is to provide a
competitive level of retirement income in order to attract and
retain selected executives. The plan is designed to provide a
benefit which, when added to other retirement income of an
executive, will meet this objective. Participation in the plan
shall be limited to senior officers of the Company who are
selected by the Board of Directors. This plan is effective as of
January 1, 1993.
ARTICLE I
Definitions
1.1 "Basic Plan" shall mean the Retirement Income Plan for
Non-Union Employees of Central Maine Power Company, as amended
from time to time.
1.2 "Basic Plan Benefit" shall mean the amount of benefit
payable annually from the Basic Plan to the Participant in the
form of a Single Life Annuity.
1.3 "Benefit Service" shall mean benefit service as defined
in the Basic Plan.
1.4 "Board" or "Board of Directors" shall mean the Board of
Directors of Central Maine Power Company.
1.5 "Code" shall mean the Internal Revenue Code of 1986, as
amended.
1.6 "Committee" shall mean the Compensation and Benefits
Committee of the Board of Directors.
1.7 "Company" shall mean Central Maine Power Company.
1.8 "Credited Service" shall mean credited service as
defined in the Basic Plan.
1.9 "Earnings" shall mean a Participant's earnings as
defined in the Basic Plan, but determined without regard to those
provisions in the Basic Plan incorporating the limits of Section
401(a)(17) of the Code, and including amounts deferred by the
Participant under any elective deferred compensation plan
maintained by the Company and any amounts received by the
Participant from the Executive Incentive Plan.
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1.10 "Effective Date" shall mean January 1, 1993.
1.11 "ERISA" shall mean the Employee Retirement Income
Security Act of 1974, as amended.
1.12 "Final Average Earnings" shall mean the average of a
Participant's highest thirty-six (36) consecutive months of
Earnings while employed by the Company.
1.13 "Participant" shall mean an employee of the Company who
is a member of the select group of management employees
identified in Schedule A, attached hereto and made a part hereof,
and who is vested under the Basic Plan.
1.14 "Plan" shall mean the Central Maine Power Company
Supplemental Executive Retirement Plan as set forth herein and
hereafter amended.
1.15 "Retirement" shall mean the termination of a
Participant's employment with the Company and the commencement of
benefit payments under the Plan.
1.16 "Retirement Date" shall mean one of the dates specified
in Article II.
1.17 "Single Life Annuity" shall mean a series of equal
monthly payments, beginning on the Participant's Retirement Date
and ending with the monthly payment immediately preceding the
Participant's death.
1.18 "Surviving Spouse" shall mean the surviving spouse of
the Participant but only if the Participant and the surviving
spouse had been married throughout the one-year period ending on
the date of the Participant's death. A former spouse will be
treated as the Surviving Spouse with specific reference to this
Plan only to the extent provided under a qualified domestic
relations order as described in Section 206(d)(3) of ERISA and
applicable regulations thereunder.
ARTICLE II
Eligibility for Benefits
A Participant is eligible to retire from the Company and
receive a benefit under the Plan beginning on one of the
following dates:
2.1 "Normal Retirement Date," which is the first day of the
month coinciding with or next following the date on which the
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Participant reaches age 65.
2.2 "Early Retirement Date," which is the first day of any
month, prior to the Participant's Normal Retirement Date,
coinciding with or following the date on which the Participant
has both reached age 55 and completed five (5) years of Credited
Service.
2.3 "Deferred Retirement Date," which is the first day of
the month, after the Participant's Normal Retirement Date,
coinciding with or next following the date on which the
Participant terminates employment with the Company.
The benefit to which the Participant will be entitled upon
his or her Retirement Date shall be determined in accordance with
Article III.
ARTICLE III
Supplemental Plan Benefits
3.1 Retirement Benefit. On Retirement a Participant shall
be entitled to an annual benefit under this Plan equal to the
amount determined under subsection (a) less the amounts
determined under subsections (b), (c), and (d):
(a) 2.6% of the Participant's Final Average Earnings,
multiplied by--
(i) the Participant's completed years of Benefit
Service (excluding any partial years), not in
excess of 25; and
(ii) except as provided in Section 3.2, if a
Participant retires before age 62, the applicable
early retirement reduction factor specified in the
Basic Plan.
(b) 100% of the Participant's Basic Plan Benefit,
determined in accordance with all applicable provisions of
the Basic Plan.
(c) 100% of the amount payable annually as a Single
Life Annuity that is the actuarial equivalent of the
Participant's retirement benefit under any other
nonqualified retirement plan of (or employment agreement
with) the Company, determined in accordance with all
applicable provisions of the nonqualified retirement plan or
employment agreement, as the case may be.
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(d) 100% of the amount payable annually as a Single
Life Annuity that is the actuarial equivalent of any amount
released to the Participant under any split-dollar life
insurance agreement with the Company.
For purposes of this Section, actuarial equivalence shall be
determined in accordance with the actuarial assumptions specified
in the Basic Plan.
3.2 Disability Retirement Benefit. If a Participant
retires before age 62 with a disability benefit payable from the
Basic Plan, the amount determined under subsection (a) of Section
3.1 shall not be reduced by the application of any early
retirement reduction factor.
3.3 Pre-Retirement Death Benefit. If a Participant dies
prior to the date his or her Retirement benefits commence under
this Plan, a death benefit shall be payable to his or her
Surviving Spouse in an amount equal to fifty percent (50%) of the
amount the Participant would have received under the Plan had he
or she been eligible to and elected early retirement the day
before the date of his or her death with a benefit payable in the
form of a qualified joint and survivor annuity, as described in
the Basic Plan.
3.4 Post-Retirement Death Benefit. If the Participant dies
after his or her Retirement benefits commence under this Plan a
death benefit shall be payable only to the extent that such
benefit is provided under the form of benefit payment in effect
under Section 3.5.
3.5 Payment of Benefits. The benefits payable under the
Plan shall be paid at such time and in such form as the benefits
payable under the Basic Plan that the benefits payable hereunder
are intended to supplement, unless the Committee shall otherwise
determine. No benefit shall be paid hereunder until an
application shall be made to the Committee in writing. In
addition, the Committee may require an applicant for a benefit
hereunder to furnish such information as it may reasonably
request, and may delay the commencement of benefits, if
necessary, until such information is made available.
ARTICLE IV
Administration
4.1 The complete authority to control and manage the
operation and administration of the Plan shall be placed in the
Committee. The Committee shall have sole discretion to construe
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the Plan and to determine all questions relating to eligibility
for and entitlement to benefits. Further, the Committee shall
have the sole discretion to determine the time and form of
benefit payments under the Plan.
4.2 Subject to the provisions of this Plan, the Committee
from time to time may establish rules for the administration and
interpretation of the Plan. The determination of the Committee
as to any disputed questions shall be conclusive. All actions,
decisions and interpretations of the Committee in administering
the Plan shall be performed in a uniform and nondiscriminatory
manner.
4.3 If an application for a benefit ("claim") is denied by
the Committee, the Committee shall give written notice of such
denial to the applicant, by certified or registered mail, within
60 days after the claim was filed with the Committee; provided,
however, that such 60-day period may be extended to 120 days by
the Committee if it determines that special circumstances exist
which require an extension of the time required for processing
the claim. Such denial shall set forth:
(a) the specific reason or reasons for the denial;
(b) the specific Plan provisions on which the denial
is based;
(c) any additional material or information necessary
for the applicant to perfect the claim and an explanation of
why such material or information is necessary; and
(d) an explanation of the Plan's claim review
procedure.
Following receipt of such denial, the applicant or his or her
duly authorized representative may:
(a) request a review of the denial by filing written
application for review with the Committee within 60 days
after receipt by the applicant of such denial;
(b) review documents pertinent to the claim at such
reasonable time and location as shall be mutually agreeable
to the applicant and the Committee; and
(c) submit issues and comments in writing to the
Committee relating to its review of the claim.
The Committee shall, after consideration of the application
for review, render a decision and shall give written notice
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thereof to the applicant, by certified or registered mail, within
60 days after receipt by the Committee of the application for
review; provided, however, that such 60-day period may be
extended to 120 days by the Committee if it determines that
special circumstances exist which require an extension of the
time required for processing the application for review. Such
notice shall include specific reasons for the decision and
specific references to the pertinent Plan provisions on which the
decision is based.
4.4 Any act that the Plan authorizes or requires the
Committee to do may be done by a majority of its members. The
action of such majority, expressed from time to time by a vote at
a meeting or in writing without a meeting, shall constitute the
action of the Committee and shall have the same effect for all
purposes as if assented to by all members of the Committee at the
time in office.
4.5 The members of the Committee may authorize one or more
of their number to execute or deliver any instrument, make any
payment or perform any other act which the Plan authorizes or
requires the Committee to do.
4.6 The Committee may employ counsel and other agents, may
delegate ministerial duties to such agents or to employees of the
Company and may procure such clerical, accounting, actuarial,
consulting and other services as it may require in carrying out
the provisions of the Plan.
4.7 The Company shall indemnify and save harmless each
member of the Committee against all expenses and liabilities
arising out of his or her acts or omissions with respect to the
Plan, provided such member would be entitled to indemnification
pursuant to the By-Laws of the Company.
ARTICLE V
Miscellaneous
5.1 The Board may at any time, in its sole discretion,
terminate this Plan or amend the Plan in whole or in part. No
such termination or amendment shall have the effect of
retroactively reducing any benefit, based on a Participant's
Benefit Service, Credited Service, and Earnings as of the date of
such termination or amendment, or restricting any right of a
Participant, retired Participant, Surviving Spouse, or other
person or estate entitled to benefits hereunder.
5.2 Nothing contained herein will confer upon any
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Participant the right to be retained in the service of the
Company or any other right not expressly provided for herein, nor
will the existence of this Plan impair the right of the Company
to discharge or otherwise deal with a Participant.
5.3 This Plan is unfunded for purposes of the Code and
ERISA and is not intended to meet the requirements of Section
401(a) of the Code. This Plan constitutes a mere promise by the
Company to make benefit payments in the future, and the
Participant hereunder shall have no greater rights than a
general, unsecured creditor of the Company.
5.4 To the maximum extent permitted by law, no benefit
under this Plan shall be assignable or subject in any manner to
alienation, sale, transfer, claims of creditors, pledge,
attachment or encumbrances of any kind.
5.5 Each Participant shall receive a copy of this Plan and
the Committee will make available for inspection by the
Participant a copy of any rules and regulations adopted by the
Committee in administering the Plan.
5.6 This Plan is established under and will be construed
according to the laws of the State of Maine, except to the extent
such laws may be preempted by ERISA.
IN WITNESS WHEREOF, Central Maine Power Company has caused
this document to be executed by its duly authorized officer on
this twentieth day of October, 1993.
CENTRAL MAINE POWER COMPANY
By: Carlton D. Reed, Jr.
Chairman of the Board
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SCHEDULE A
Arthur W. Adelberg
Senior Vice President,
Law and Governmental Relations
Richard A. Crabtree
Senior Vice President,
Customer Services and Division Operations
Matthew Hunter
President and Chief Executive Officer
David T. Flanagan
Executive Vice President
Donald F. Kelly
Senior Vice President,
Production, Engineering and Power Supply
David E. Marsh
Senior Vice President, Finance
and Chief Financial Officer <PAGE>
Exhibit 13-1
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Overview: The Company's earnings per share declined by 11
percent in 1993 to $1.65 from $1.85 in 1992. The return on
common equity for 1993 was 9.77 percent versus 11.25 percent
earned in 1992. The reduced earnings level for 1993 can be
attributed to higher costs, weak sales and cost disallowances
associated with two proceedings before the Maine Public Utilities
Commission (MPUC) during 1993.
The combination of weak sales due to economic and competitive
pressures, and a disappointing and inadequate rate-case decision
in December 1993, offers the Company no reasonable opportunity to
achieve a level of 1994 earnings near the 1993 level or the
current allowed rate of 10.05 percent on common equity. The
reduction in the Company's earnings capacity for the near term
takes into account the significant reductions in previously
planned 1994 operation, maintenance, and capital expenditures
described later in this section.
Service-area kilowatt-hour sales increased by 0.4 percent during
1993. The small increase can be attributed to a weak economic
climate, significant competition from alternative fuel sources,
energy-management impacts and other factors.
On December 14, 1993, the MPUC issued its order in the Company's
base-rate proceeding filed in March 1993. The MPUC's analysis of
the Company's revenue deficiency indicated a need for additional
revenues of $51.5 million, yet found the Company entitled to a
net revenue increase of only $26.2 million. The Commission found
a total cost of capital of 8.52 percent and a cost of equity of
10.05 percent, after deducting the one-half percent (.5%)
return-on-equity penalty it established in the 1993 investigation
of the Company's management of certain Independent Power Producer
(IPP) contracts. To arrive at its revenue-requirement
conclusion, the MPUC deducted $25.3 million "to adjust for
management inefficiency" after finding the Company's performance
in the areas of management efficiency and cost-cutting to have
been "inadequate." In so doing, the Commission noted that "Much
of our cost efficiency finding occurs in the context of reviewing
the results of the Commission-ordered Management Audit".
In issuing that decision, the MPUC disallowed recovery of
approximately $2.5 million of previously deferred costs and $1.3
million of previously deferred income-tax-related expenses which,
as a result, were reflected as reductions in earnings during the
fourth quarter of 1993.
The Company strongly disagrees with the MPUC's management-
inefficiency finding and with the resulting deduction of nearly
one-half the revenue increase to which the Commission itself
found the Company to be otherwise entitled using traditional
ratemaking principles. The Company has appealed the order to the
Maine Supreme Judicial Court.
The Company's credit ratings came under significant pressure
during 1993 when its senior secured debt was downgraded by all
three agencies that rate the Company's securities, one of which
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dropped the rating to below investment grade. As noted later in
this report, the Company's other securities came under even more
pressure as the junior securities were, in most cases, assigned
non-investment-grade ratings. The decline in the Company's
credit ratings will impair its access to the capital markets,
will make the terms and conditions of borrowing more stringent
and increase the cost of capital, and has substantially reduced,
if not eliminated, the Company's access to the commercial-paper
markets. The credit-rating agencies cited the stagnant economy,
inadequate rate relief and pricing flexibility, increased
competition, and uncertainty of recovery of non-utility
purchased-power costs as reasons for the credit downgrades.
After review of the Company's overall financial position and
outlook, including the impacts associated with the MPUC's
rate-case order and the expected near-term revenue impacts of
weak sales, the Company's Board of Directors voted on December
15, 1993, to reduce the quarterly dividend paid on common stock
from 39 cents to 22.5 cents.
In response to the business challenges facing the Company, the
Company's Board of Directors, in December 1993, approved a
broad-based restructuring and rate-stability plan.
The rate-stabilizing strategy:
1. Cut in-house operating costs while maintaining service.
2. Cut non-utility power costs, the largest external cost.
3. Work with regulators on innovative, competitive new products
and pricing.
The first step in implementing the strategy was to eliminate at
least 225 full-time equivalent jobs, or 10 percent of the
Company's work-force, by March 1994. The Company's operating
budget for 1994 was cut $22 million, or 12 percent, from
previously planned levels. The 1994 capital budget for plant,
equipment, and conservation programs was cut by $14 million, or
19 percent, from previously planned levels.
The second component of the plan, reducing the cost of
non-utility power, includes continued efforts to renegotiate
existing contracts, buy-outs, or contract terminations, and
support for Maine legislative action on bills that would have the
effect of reducing the cost of non-utility power to our
customers.
The third component includes continuing Company efforts to
achieve changes in regulation that would redefine the basis for
overall price changes and provide flexibility in setting specific
prices, and in the acquisition and use of resources. As detailed
later in this report, the Company has indicated its interest in
pursuing a price-cap approach to the regulation of electric rates
and, consistent with the terms of the MPUC December 1993 order in
the base-rate case, will be filing a plan with the MPUC sometime
in the first half of 1994.
Earnings in 1993 reflect the January 1993 stipulation that
lowered the level of 1993 accruals under the Electric Revenue
Adjustment Mechanism (ERAM), and the October 1993 MPUC order in a
proceeding reviewing non-utility purchased power contract
administration. In that proceeding, the MPUC found that the
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Company had been unreasonable and imprudent in its management of
two contracts and determined it would reduce the Company's
allowed rate of return on equity by one-half percent (.5% or
approximately $4 million, before income taxes, over a 12-month
period) and directed the Company to charge against deferred
fuel-cost balances approximately $4.1 million of payments from
power providers that had previously been credited against
purchased-power capacity costs. The Company recorded a reserve
for this order totalling $4.1 million during the third quarter of
1993.
The Company not only strongly disagrees with the MPUC findings,
but has received an order from the Chief Justice of the Maine
Supreme Judicial Court temporarily restraining the MPUC from
implementing the rate-of-return penalty pending a decision on the
Company's appeal of the MPUC penalty. On February 3, 1994, the
MPUC indicated its intent to vacate the penalty portion of the
order and to seek an alternative cost-disallowance remedy. The
Company cannot predict the outcome of its appeal or the outcome
of any alternative remedy imposed by the MPUC, or any appeal from
such alternative remedy, or any Maine legislative action. (See
Note 3 to Consolidated Financial Statements, "Regulatory Matters
- Other MPUC Proceedings," for further information.)
The Company's financial objectives for 1994 and beyond include
seeking cost reductions and cost control, risk reduction
associated with purchased-power contract review proceedings,
restructuring prices, achieving pricing flexibility to enhance
our ability to compete for sales, and seeking rate recovery of
the costs of providing electric service. Our ability to restore
earnings to competitive levels and to improve overall financial
health depends significantly on meeting these challenges.
Our near-term success in reducing the upward pressure on electric
rates depends heavily on our ability to reduce our largest cost
of service, non-utility generation. While our pricing goal is to
lower our inflation-adjusted overall rates by the year 2000, we
must continue to focus on improving financial ratios and on
regaining lost ground in our credit standing. Achieving
acceptable earnings levels for the upcoming year is the most
difficult of our financial challenges.
Earnings and Dividends: Net income for 1993 was $61.3 million
compared to $63.6 million in 1992, and $59.1 million in 1991.
Earnings applicable to common stock were $52.5 million or $1.65
per share in 1993, compared to $56.8 million or $1.85 in 1992,
and $53.7 million or $1.82 in 1991.
Total dividends declared in 1993 were $1.395 per common share,
resulting in a cash distribution of 85 percent of current-year
common earnings per share. Total dividends per share for 1992
and 1991 were $1.56. In December 1993, the quarterly dividend
payment per share of common stock was reduced from $0.39 to
$0.225. This reduction reflects current earnings levels and the
near-term financial outlook discussed below. Future dividend
levels depend on earnings quality and growth, and on other
considerations such as changes in capital costs.
Revenues and Sales: Electric operating revenues increased by
$15.9 million or 2 percent to $893.6 million in 1993, and by
$11.2 million or 1 percent to $877.7 million in 1992. The
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components of the change in electric operating revenues are as
follows:
<TABLE>
<S> <C> <S> <C> <C>
(Dollars in millions) 1993 1992
Revenues from kilowatt-hour
sales:
Total service-area base revenues $15.3 $ 8.7
Fuel cost recoveries 12.3 3.1
Non-territorial base revenues (0.1) 0.1
Revenues from kilowatt-hour
sales 27.5 11.9
Other operating revenues:
Electric Revenue Adjustment
Mechanism, including revenue
adjustment-tax flowback (14.6) 3.0
Other, including Maine Electric
Power Company, Inc. 3.0 (3.7)
Total Change in Electric
Operating Revenues $15.9 $11.2
</TABLE>
Refer to "Incentive Regulation," "Base Rates," and "Fuel Rates,"
below, for a discussion of ERAM, the tax-benefit flowback, new
rates, and their impact on revenues.
The Company's service-area sales for the years 1993, 1992 and
1991 are shown in the following table:
<TABLE>
<S> <C> <C> <C> <C> <C> <C>
(Kilowatt-hours
in millions) 1993 1992 1992
KWH % KWH % KWH %
change change change
Residential 2,884 (3.5)% 2,990 0.4% 2,977 (3.6)%
Commercial 2,387 0.9 2,366 1.7 2,327 0.4
Industrial 3,791 3.2 3,672 0.6 3,651 (0.2)
Wholesale and
lighting 155 0.3 154 2.1 151 0.1
Total
Service-Area
Sales 9,217 0.4 % 9,182 0.8% 9,106 (1.2)%
</TABLE>
Service-area kilowatt-hour sales increased by 0.4 percent in
1993. The primary factors are the continued weak economy, rising
electricity prices, energy management, weather conditions, and
loss of sales due to conversions from electricity. Sales levels
for 1992 rose a modest 0.8 percent from the prior year due to
the previously discussed economic conditions, competitive
pressures, electricity-price increases and energy-management
activities.
Residential kilowatt-hour sales decreased in 1993 by 3.5 percent,
after increasing by 0.4 percent in 1992 and decreasing by 3.6
percent in 1991. The increase in the average number of
residential customers was 4,771 in 1993, 5,657 in 1992, and 5,670
in 1991. Average usage per residential customer declined by 4.5
percent in 1993.
The 1993 increase in commercial sales of 0.9 percent reflects a
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4-percent increase in the retail sector and a 3.6-percent
decrease in the service sector, which combined, comprise
approximately 60 percent of commercial sales. Commercial sales
had increased by 1.7 percent in 1992 and by 0.4 percent in 1991.
Industrial-sales levels are significantly affected by changes in
power supplied to the Company's large pulp-and-paper industry
customers, who account for approximately 66 percent of industrial
sales and approximately 27 percent of total service-area sales.
Sales to the pulp-and-paper sector increased by 3.2 percent in
1993, by 0.1 percent in 1992, and by 3.5 percent in 1991. The
1993 increase results primarily from the increased levels of
production by many of the Company's customers and purchases of
excess energy under newly approved tariffs at lower rates. Sales
to all other industrial customers as a group increased by 3.3
percent in 1993 and 1.5 percent in 1992; they decreased 6.8
percent in 1991.
Sales to major industrial customers are shown in the following
table:
<TABLE>
<S> <C> <C> <C>
(Kilowatt-hours in 1993 1992 1991
millions)
Paper and allied
products 2,519* 2,441* 2,438*
Transportation
equipment
(shipbuilding) 208 212 202
Chemicals and allied
products 182 167 157
Textile mill products 141 134 130
Electrical and
electronic machinery 136 151 169
Food products 95 85 85
Lumber and wood
products 88 85 86
Leather and leather
products 81 77 72
</TABLE>
*Totals include sales made under simultaneous-purchase-and-sale
contracts related to purchases required under the Public
Utilities Regulatory Policy Act of 1978 (PURPA).
Non-territorial Sales: On August 2, 1991, the Federal Energy
Regulatory Commission (FERC) issued an order requiring the
Company to revise its rates to a level reflecting the filed cost
of service associated with each of 14 contracts for
non-territorial sales, rather than the negotiated market-based
levels. Other revenues in 1991 reflect the establishment of a
$4.5-million reserve to reflect refunds associated with some of
the contracts. Other revenues for 1992 reflect the reversal of
approximately $1.9 million of that reserve after a settlement
agreement established that the Company would refund approximately
$2.6 million related to this issue.
The FERC rejected the Company's continuing claims of disparate
treatment based on its having been ordered to make refunds while
several similarly situated utilities were not. But on September
29, 1993, the FERC rescinded the Company's obligation to make
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refunds, invoking its "equitable discretion" to declare that it
would be "unfair to continue to single out Central Maine for
refunds." The FERC order allows the utilities that had shared
the $2.6 million in refunds to repay the Company, with interest,
over a 24-month period. The utility receiving the largest refund
has requested reconsideration of the FERC rescission order. The
Company recorded approximately $3.0 million of income during the
third quarter of 1993, reflecting the refund including interest.
The Company cannot predict the outcome of the other utility's
request for reconsideration, or what portion, if any, of the $3.0
million received in 1993, may have to be refunded by the Company.
Corporate Restructuring: Maine and the New England region
continue to experience a significant economic downturn that began
in late 1989. The recession was a significant factor in the
small level of growth in total kilowatt-hour sales in 1993 and
1992, and the decline in such sales in 1991. The 1991 decline,
the first since 1949, was primarily due to lower usage per
customer in the residential-customer class, which represents
approximately 31 percent of total service-area sales.
Lower sales in recent years have not produced revenues sufficient
to cover the cost of service. This has required the Company to
seek price increases. However, the state of the economy has made
obtaining adequate rate increases difficult.
In response to the slow growth in revenues and concerns over the
rising price of electricity, the Company undertook cost-control
activities beginning in 1991. For example, a reduction of
approximately 10 percent in the Company's work force since 1991
and the reduction in functions not critical to safety or service
quality were implemented to reduce operation-and-maintenance
outlays during 1993, 1992 and 1991. The Company's
capital-investment program has also been reduced. Slower growth
in the Company's service area has eliminated the need for certain
construction projects, while other projects are being deferred.
Please refer to the "Overview" section above for a detailed
discussion of the Company's current restructuring plans.
Incentive Regulation: On May 7, 1991, the MPUC ordered a
three-year trial of the Electric Revenue Adjustment Mechanism
(ERAM), a fundamental change in the way the Company's revenues
were treated, and set new incentives for effective
utility-sponsored energy-management. On July 16, 1992, the MPUC
issued an order authorizing the Company to begin collecting $7.8
million, which was only a portion of the $26.2 million of ERAM
revenues accrued in its first year, and an energy-management
incentive of $1.5 million, beginning in September 1992.
Approximately $18.4 million of ERAM revenues accrued in the 12
months beginning March 1, 1991, were, therefore, carried over to
the 1993 ERAM filing. In January 1993, the MPUC approved a
stipulation that resolved several outstanding issues, including
those in the Company's ERAM proceeding. The stipulation
permitted recovery of accrued ERAM balances in accordance with
the terms of an Emerging Issues Task Force consensus. The
stipulation also approved an Accounting Order permitting the
Company to accelerate the flow-back of $5.9 million of certain
deferred taxes associated with prior losses on reacquired debt.
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For 1992, the stipulation placed a limit of 11.25 percent on the
Company's allowed rate of return on equity. Earnings in excess
of the limit, up to approximately $10 million (the revenue
requirement of the tax benefits), were applied on a monthly basis
to reduce 1993 ERAM accruals.
The stipulation also reduced the amount of ERAM accruals from
January 1993 through November 1993 by $591,000 per month. The
ERAM program continued until the effective date of new base
rates, December 1, 1993.
As contemplated in the January 1993 stipulation, the MPUC
approved a revenue increase of $40 million, effective July 1,
1993, which includes, among other things, $21.2 million toward
recovery of deferred ERAM revenues.
As of December 31, 1993, the Company had collected approximately
$19.2 million of the ERAM revenues; the unbilled ERAM balance at
that time was approximately $50.5 million.
Base Rates: On March 1, 1993, the Company filed a request with
the MPUC for a $95-million increase in base rates. The major
components of the request were (1) compensating for
lower-than-forecasted sales, (2) increased
operation-and-maintenance expenses, (3) increased operating costs
of the four operating nuclear plants in which the Company owns
interests, (4) property additions and transmission, distribution
and other improvements, (5) energy-management program costs, and
(6) the expiration of the flow-through of certain tax benefits.
Ultimately, the Company reduced the amount of its base-rate
request from $95 million to $83 million. The decrease was the
result of lower estimates of 1994 operation-and-maintenance
expenses, further reductions in the Company's cost of capital, a
decrease in the level of anticipated expenditures for energy-
management programs, and the change in the federal income tax
rate from 34 percent to 35 percent.
On December 14, 1993, the MPUC issued its order in the
proceeding. The MPUC's analysis indicated a need for additional
revenues of $51.5 million, yet found the Company to be entitled
to a net revenue increase of only $26.2 million. The Commission
found a total cost of capital of 8.52 percent and a cost of
equity of 10.05 percent, after deducting a one-half percent (.5%)
return-on-equity penalty it had established in a 1993
investigation of the Company's management of certain independent
power producer contracts. See Note 3 to Consolidated Financial
Statements, "Regulatory Matters - Other MPUC Proceedings," for
further discussion of this investigation. To arrive at its
revenue-requirement conclusion, the MPUC deducted $25.3 million
"to adjust for management inefficiency" after finding the
Company's performance in the areas of management efficiency and
cost-cutting to have been "inadequate".
The Company strongly disagrees with the MPUC's
management-inefficiency finding and with the resulting deduction
of nearly one-half the revenue increase to which the Commission
itself found the Company to be otherwise entitled using
traditional ratemaking principles. The Company filed an appeal
of the base-rate order with the Maine Supreme Judicial Court.
The Company cannot, however, predict the result of that appeal.
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Fuel Rates: In accordance with the January 1993 ratemaking
stipulation, the MPUC approved, as part of the $40 million July
1993 revenue increase, $17 million to reduce deferred fuel-clause
balances. In July 1992, the MPUC issued an order authorizing an
increase, effective September 1, 1992, in the Company's Fuel Cost
Adjustment of $13.2 million of the $38.7 million requested by the
Company, along with the ERAM and demand-side-management
incentives discussed above.
The orders extended the smoothing approach that began in 1988,
resulting in unrecovered-fuel and purchased-power costs' being
deferred for future recovery. The Company has repeatedly
expressed concern about the regulators' tendency to defer the
recovery of expenses.
Rate Stability: In connection with the base-rate proceeding,
the Company filed, on July 21, 1993, an alternative rate
proposal. The proposal consisted of a combination of pricing and
regulatory changes that would, among other things, limit future
rate increases to annual changes based on the rate of inflation
and mandated costs, and revise existing regulatory rules and
policies to allow the Company to adjust prices more rapidly in
response to customer needs and competitive factors.
In its December 14, 1993 base-rate order, the MPUC ordered that a
follow-up proceeding be held to implement, by mid-1994, a
rate-stability plan along the lines discussed in the order. The
MPUC encouraged the Company and the parties wishing to
participate in the proceeding to work together to develop a plan
containing price-cap, profit-sharing-and pricing-flexibility
components. The MPUC also directed that the initial plan have a
duration of five years, subject to a brief annual proceeding to
implement any applicable rate changes, and a detailed review at
the end of the fourth year to evaluate the performance of the
plan and initiate necessary changes. Participants in the
rate-stability plan proceeding have prepared price-cap proposals
in response to the MPUC's order and discussions are under way.
The Company cannot predict the outcome of this process or the
MPUC's ultimate decision on price-cap regulation.
Deferred Costs: Over the past few years, the amount of deferred
charges and regulatory assets has increased under the regulatory
policies adopted by the MPUC. The Securities and Exchange
Commission has periodically considered issues regarding the
proper accounting treatment of charges deferred by regulatory
policy. As a result, the Company has regularly requested the
MPUC to issue accounting and ratemaking orders to provide
appropriate authority to comply with changing accounting
requirements and to allow the Company to appropriately reflect
the amounts as deferred charges and regulatory assets. In recent
years, the Company received such orders with respect to issues in
the 1991 Early Retirement Incentive Program, ERAM,
purchased-power contract buy-outs, environmental-site cleanup
costs, taxes on losses on reacquired debt, accounting for
postretirement benefits and income taxes pursuant to the newly
issued accounting standards. The Company will monitor situations
that result in deferred charges and regulatory assets and will
seek appropriate regulatory approvals.
Competition: The Company faces competition in several aspects of
its traditional business and anticipates that competition will
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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
outside of the Company's service territory have expanded
customers' energy options. As a result, the Company has been
involved in a number of negotiations with certain customers
during 1993 and will continue to pursue retention of its customer
base. This increasingly competitive environment has resulted in
the Company's entering into contracts with two of its wholesale
customers, as well as with certain industrial and commercial
customers, to provide their energy needs at prices and margins
lower than the current averages.
On July 28, 1993, the Town of Madison Electric Works (Madison), a
wholesale customer of the Company, announced that it had selected
a competitive bid from Northeast Utilities (NU) and was entering
negotiations for NU to become its wholesale electric supplier for
a period of up to 10 years. The Company's bid was rejected by
Madison for being submitted after the 10-day bidding period. NU,
a Connecticut-based holding company with substantial excess
generating capacity, submitted a bid to provide up to 45
megawatts of capacity at a rate that would initially be well
below the Company's existing rates. Substantially all of the 45
megawatts would supply a large paper-making facility in Madison's
service territory that has been served directly by the Company
under a special service agreement with Madison during the last 12
years. The Company understands that Madison intends to start
taking power from NU in late 1994 for that portion required to
serve the paper-making facility and in late 1996 for its
remaining requirements. Losing Madison as a wholesale customer
would reduce the Company's non-fuel revenues by approximately $11
million annually when fully in effect, based on current rates and
1993 sales, minus any amounts paid to the Company for
transmission of the NU power from the New Hampshire border.
The Company has intervened in opposition to Madison's petition to
the MPUC for approval of its contract with NU. The Company
cannot predict what action the MPUC will take on the petition.
The Company expects to file with the FERC to seek approval of a
contract to provide transmission service for Madison from NU, in
early 1994. The filing will request recovery of the full cost of
providing transmission service as well as a stranded-investment
fee to compensate the Company for lost-base revenues.
In addition to special agreements with its large customers, the
Company is also pursuing with the MPUC alternative pricing
mechanisms that would allow the Company the flexibility to modify
the price of its product in certain instances, when the
competitive alternatives could result in the loss of a
significant end use of electricity. In its preliminary
discussions, the MPUC has indicated there may be instances in
which the ability of the Company to adjust its price in response
to competitive pressures is advisable. In February 1994, the
MPUC approved a specific plan under which the Company may operate
with respect to residential water-heating customers. The Company
believes it may be granted the authority to develop additional
market-responsive rates in certain circumstances in the future.
Rating Agency Actions: Beginning in late August 1993, three
major securities-rating agencies lowered their ratings on the
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Company's outstanding debt and preferred stock on a number of
occasions.
In October 1993, Duff & Phelps Credit Rating Co. lowered the
fixed income ratings as follows: General and Refunding Mortgage
Bonds from "BBB+" to "BBB-"; unsecured notes from "BBB" to "BB+";
and preferred stock from "BBB" to "BB-."
Standard & Poor's Corp. (S&P) announced, in late October 1993,
application of more stringent financial-risk standards to the
investor-owned utility industry to reflect S&P's view of mounting
business risk. S&P stated that it believed the industry's
"credit profile" was being "threatened chiefly by intensifying
competitive pressures but also by sluggish demand expectations,
slow earnings growth prospects, high common dividend payout,
environmental cost pressures, and nuclear operating cost and
decommissioning challenges." As a result, S&P revised rating
outlooks for about one-third of the industry and placed the
Company and several other utilities on "CreditWatch with negative
implications."
By January 1994, S&P had removed the Company's ratings from
"CreditWatch" and lowered them as follows: senior secured debt to
"BB+" from "BBB-"; senior unsecured debt to "BB-" from "BB+";
preferred stock to "B+" from "BB"; and commercial paper to "B"
from "A-3." In addition, S&P assigned its preliminary "BB+"
senior-secured-debt rating to the Company's $150-million General
and Refunding Mortgage Bonds recently registered with the
Securities and Exchange Commission as a "shelf" registration
pursuant to Rule 415 under the Securities Act of 1933.
By January 1994, Moody's Investors Service (Moody's) had lowered
its rating on the Company's preferred stock to "ba2" from "baa3"
and its short-term debt rating for the Company's commercial paper
to "Prime-3" from "Prime-2." At the same time, Moody's confirmed
its ratings on the Company's General and Refunding Mortgage Bonds
at "Baa2", unsecured medium-term notes and pollution control
revenue bonds at "Baa3", and the Company's Securities and
Exchange Commission "shelf" registration for $150,000,000 of
General and Refunding Mortgage Bonds to "(P)Baa2."
The rating agencies explained that the downgrades primarily
reflect the MPUC's "unsupportive" base-rate decision, which in
their opinion will not allow the Company's financial parameters,
adjusted for off-balance-sheet obligations, to remain at
acceptable levels for a utility with a "below-average" business
position. Additionally, the rating agencies expressed the belief
that the Company's business position also reflects a depressed
Maine economy, a large industrial-customer base, significant
purchased-power obligations, relatively high production costs,
increasing rate pressures, and a high dividend payout.
Financing and Refinancing in 1993: During 1993, the Company
continued its program to refinance its outstanding debt to take
advantage of the currently low interest rates. The Company
issued $75 million of Series Q 7.05% Due 2008 General and
Refunding Mortgage Bonds in March, $50 million of Series R 7 7/8%
Due 2023 in May, $60 million of Series S 6.03% Due 1998 in
August, and $75 million of Series T 6.25% Due 1998 in November.
None of these series has sinking funds, and Series S 6.03% Due
-10-
<PAGE>
1998 and Series T 6.25% Due 1998 are not callable at the option
of the Company. The Series Q and Series R bonds are not callable
at the option of the Company prior to March 1, 1998, and June 1,
2003, respectively, except under limited circumstances.
The Company redeemed its $100-million Series I 9 1/4% Due 2016 in
the second quarter of 1993, $50 million of its Series M 9.18% Due
1995 in the third quarter of 1993, and $27.5 million of its
Series N 8.50% Due 2001 in the fourth quarter of 1993. Premiums
paid on redemptions totalled $9.6 million.
These financing and refinancing transactions reduced the annual
cost of the Company's mortgage debt to 7.1 percent at December
31, 1993, from 8.5 percent at December 31, 1992.
During the year, the Company also raised approximately $25.5
million of additional capital through its Dividend Reinvestment
and Common Stock Purchase Plan, resulting in the issuance of 1.2
million new shares of common stock.
In 1993, the Company issued $48 million of notes under its
$150-million Medium-Term Note program at an average interest rate
of 4.8 percent and an average life of 2.9 years. Notes in the
amount of $26.5 million matured during the year, increasing the
total outstanding notes at year-end 1993 to $146.0 million from
$124.5 million at year-end 1992.
The proceeds from the debt and equity issuances were used for
general corporate purposes, which included financing construction
and energy-management projects, retiring or refunding outstanding
securities, repaying short-term debt, and buying out
purchased-power contracts.
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 54 percent
of total operating expenses in 1993, 53 percent in 1992, and 54
percent in 1991. Purchased-power energy expense includes all
costs associated with purchases from non-utility generators.
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.
Under current ratemaking practice, changes in fuel expense are
provided rate treatment through a fuel clause, with interest
being paid to or recovered from customers on over-collected or
under-collected balances. 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.
-11-
<PAGE>
The Company's diverse energy mix held dependence on oil-fired
generation to 15.5 percent of 1993 net generation.
Diversification of the Company's energy mix has helped mitigate
the impact of oil-price changes. However, in recent years,
significant amounts of non-utility generation have been purchased
and added to the Company's energy mix. The average price of
non-utility generators' energy 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 plans to moderate
the cost of non-utility generation by continuing to negotiate
buy-outs or changes whenever possible, and by supporting
legislative action on bills that would promote that objective.
To control the price pressure related to purchases from
non-utility generators, the Company negotiated contract buy-outs
or restructuring with non-utility generators in early 1994, 1993,
and 1992. In January 1994, the Company entered into a
termination-and-settlement agreement and paid $5 million to
terminate a purchased-power contract and dismiss a lawsuit and
counterclaims related to the Company's termination of a long-term
contract to purchase approximately 80 megawatts of electric power
from a cogeneration project proposed for construction by
Caithness King of Maine Limited Partnership (Caithness). In the
suit, Caithness denied the validity of the Company's termination
of the contract and sought damages estimated to be in excess of
$100 million for breach of the contract, or in the alternative,
reformation of the contract and other legal relief. The
contract termination is expected to save approximately $57
million in fuel costs over the next five years.
In February 1993, the Company successfully negotiated a buy-out
of two long-term contracts with a non-utility generator that is
expected to save customers approximately $50 million in fuel
costs during the next five years. The Company agreed to pay $11
million to buy out each of the contracts for plants yet to be
built that were expected to begin delivering power in 1994 and
1996. The agreement gives the Company the option to decide by
mid-1996 whether to pay the $11-million termination fee or have
the second plant built to take power delivery by late 1998. The
cancelled plants each had a committed capacity of 31 megawatts.
The Company has reached agreements in principle to renegotiate 11
long-term hydro contracts. Lower prices for power will enable
CMP to save approximately $6 million over the first five years of
the contracts. The 11 hydroelectric dams have a combined
capacity of 8.7 megawatts.
The Company paid approximately $19 million in 1992 to buy-out
three long-term contracts, which is expected to save the
Company's customers approximately $11 million over the next five
years. Additionally, the 1992 contract negotiations reduced
existing capacity by approximately 13.4 megawatts.
Total buy-outs, restructuring, and terminations made to date are
expected to save the Company's customers more than $170 million
in fuel costs during the next five years.
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. Effective January 1, 1991, the
-12-
<PAGE>
MPUC approved an accounting and ratemaking methodology whereby
the Company charges to expense the cost of Maine Yankee's
refueling outages over a nineteen-month period (the estimated
time between refueling outages). Purchased-power capacity
expense includes $5.0 million, $7.6 million and $6.7 million of
such expense in 1993, 1992, 1991, respectively, related to the
Maine Yankee outages.
The level of purchased-power capacity expense also fluctuates
with the timing of the maintenance and refueling outages at the
three 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 the generation of power and prepared a plan for
decommissioning. Purchased-power capacity in 1993 and 1992
contained approximately $5.7 million and $6.9 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 decreased by $3.2 million in
1993. The reduction reflects the impact of cost-containment
practices and certain one-time items. As previously discussed,
the MPUC's December 1993 base-rate-case decision required the
Company to charge to expense approximately $2.5 million of
previously deferred costs. During the fourth quarter of 1992,
the Company was required, pursuant to another MPUC decision, to
charge to expense approximately $3.5 million of incremental costs
related to the cleanup effort after Hurricane Bob, which hit the
Company's service territory in 1991. Additionally, as the result
of a court decision on responsibility for certain costs incurred
in connection with an environmental site, the Company was able to
credit $0.8 million to expense for costs charged to expense in
prior years which became recoverable from third parties.
Cost-control measures instituted in 1991 continued through 1993.
Notwithstanding these efforts, 1993 expense included increases
reflecting continued costs for mandated energy-management
programs and amortization of purchased-power contract buy-out
costs and other general cost increases.
For 1992, operation-and-maintenance expense increased reflecting
the Hurricane Bob charge, increased costs of meeting customer
requirements, and costs associated with energy-management
programs. Operation-and-maintenance expense for 1993, 1992, and
1991 also reflect the implementation of an early-retirement
program accepted by approximately 200 employees in 1991.
The Company's overall level of interest expense during 1993
reflects the continued refinancing of General and Refunding
Mortgage Bonds at lower interest rates, and the issuance of $49
million in additional notes under the Company's Medium-Term Note
program since January 1, 1991. Short-term interest rates over
the period 1991 through 1993 fluctuated with the change in the
cost and average outstanding balances of short-term debt.
The increase in aggregate dividends on preferred stock for the
three-year period ended December 31, 1993, is due to the issuance
of two series of preferred stock in August 1992.
State and federal income taxes fluctuate with the level of
-13-
<PAGE>
pre-tax earnings and the regulatory treatment of taxes by the
MPUC. The increase in 1993 is primarily the result of
eliminating a one-time accelerated flow-back of $5.9 million of
deferred income taxes recorded in 1992 pursuant to the January
1993 stipulation, as discussed under the heading "Incentive
Regulation" above and an increase in the federal income tax rate
to 35 percent from 34 percent. Additionally, the December 1993
base-rate-case decision discontinued a previously approved policy
whereby the Company could defer the impact of Internal Revenue
Service audits for recovery in future periods.
Liquidity and Capital Resources: As noted above, the MPUC
approved increases in base electric rates in 1991, 1992, and
1993, and fuel rates in each of the three years. The new rates
produce additional cash. Increases in rates are being used 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 ERAM.
Approximately $129.0 million of cash was provided from net income
before non-cash items, primarily depreciation and deferred taxes.
Approximately $62.4 million of cash was applied to fluctuations
in working capital and other operating activities, including the
financing of deferred energy-management programs, the buy-out of
purchased-power contracts, the financing of unbilled fuel and
ERAM balances, and depositing funds with the Mortgage Bond
Trustee to allow for redemption of outstanding General and
Refunding Mortgage Bonds.
Proceeds from the Company's Dividend Reinvestment and Common
Stock Purchase Plan provided approximately $25.5 million of cash,
while the issuance of General and Refunding Mortgage Bonds
provided $260 million of cash. The issuance and redemption of
Medium-Term Notes provided $21.5 million and short-term
obligations used $63 million, respectively, of cash during 1993.
Retirements and redemptions of mortgage bonds required $177.5
million of cash resources.
Dividends paid on common stock were $49.3 million, while
preferred-stock dividends were $8.7 million. The January 1994
record-date dividend on common stock was reduced from $0.39 per
share to $0.225 per share.
Capital-investment activities, primarily construction
expenditures, utilized $56.5 million in cash during 1993.
Construction expenditures comprised approximately $6.1 million
for generating projects, $3.1 million for transmission, $29.0
million for distribution, and $10.1 million for general
construction expenditures. In addition, $5.3 million was used
for various capitalized energy-management programs.
The Company's construction program for the period 1994 through
1998 has been estimated at approximately $281 million, including
an Allowance for Funds Used During Construction of approximately
$3 million. Actual construction expenditures will depend upon
the availability of capital and other resources, load forecasts,
customer growth, and general business conditions. As a result of
the recent base-rate case, the Company has reduced its planned
1994 capital-investment outlays to one half of the 1990 amount.
-14-
<PAGE>
During the five-year period, the Company also anticipates
incurring approximately $35 million in costs associated with
energy-management programs, and $301 million for sinking funds
and debt maturities.
The Company estimates that for the period 1994 through 1998,
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 reduced
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.
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. As a result, current
financing plans do not anticipate the issuance of any additional
common stock during the next several years.
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, 1993, $146 million of Medium-Term Notes were
outstanding, which, pursuant to the terms of the program, permits
the issuance of an additional $4 million of such notes.
The ultimate nature, timing, and amount of financing of the
Company's total construction, refinancing, and energy-management
capital requirements will be determined in light of market
conditions, the level of earnings and internally generated funds,
and other relevant factors.
To support its short-term capital requirements, the Company
maintains lines of credit totalling $73 million and 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, as previously discussed,
access to commercial paper markets has been substantially
reduced, if not eliminated, as a result of downgrading of the
Company's credit ratings. Borrowings under lines of credit may
be subject to more stringent terms and conditions in the future.
The amount of outstanding short-term borrowing will fluctuate
with day-to-day operational needs, the timing of long-term
financing, and market conditions.
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
<TABLE>
<S> <C> <C> <C> <C>
Consolidated Statement of Earnings
(Dollars in Thousands, Except Per-Share Amounts)
Year Ended December 31
1993 1992 1991
Electric Operating
Revenues (Notes 1
and 3) $893,577 $877,695 $866,539
Operating expenses
-15- <PAGE>
Year Ended December 31
1993 1992 1991
Fuel used for
company generation
(Notes 1 and 6) 16,906 23,411 28,437
Purchased power -
energy (Notes 1 and
6) 408,944 388,599 385,190
Purchased power -
capacity (Note 6) 84,520 79,895 77,232
Other operation 148,318 144,126 138,838
Maintenance 33,311 40,749 37,402
Depreciation and
amortization (Note
1) 53,138 50,431 47,946
Federal and state
income taxes (Note
2) 25,716 18,258 21,685
Taxes other than
income taxes 23,023 24,706 23,739
Total Operating
Expenses 793,876 770,175 760,469
Equity in Earnings
of Associated
Companies (Note 6) 5,829 6,688 8,193
Operating Income 105,530 114,208 114,263
Other income
(expense)
Allowance for
equity funds used
during construction
(Note 1) 1,523 1,633 886
Other, net (673) 1,927 344
Income taxes
applicable to other
income (Note 2) 3,127 (177) (46)
Total Other Income 3,977 3,383 1,184
Income Before
Interest Charges 109,507 117,591 115,447
Interest charges
Long-term debt
(Note 7) 42,266 46,299 47,878
Other interest
(Note 7) 6,784 8,844 9,136
Allowance for
borrowed funds used
during construction
(Note 1) (845) (1,135) (701)
Total Interest
Charges 48,205 54,008 56,313
Net income 61,302 63,583 59,134
Dividends on
preferred stock 8,842 6,770 5,479
Earnings Applicable
to Common Stock $ 52,460 $ 56,813 $ 53,655
-16-
<PAGE>
Year Ended December 31
1993 1992 1991
Weighted Average
Number of Shares of
Common Stock
Outstanding 31,789,114 30,630,427 29,508,590
Earnings Per Share
of Common Stock $ 1.65 $1.85 $1.82
Dividends Declared
Per Share of Common
Stock $1.395 $1.56 $1.56
The accompanying notes are an integral part of these financial
statements.
</TABLE>
<TABLE>
<S> <C> <C> <C>
Consolidated Statement of Cash Flows
(Dollars in Thousands)
Year Ended December 31
1993 1992 1991
Operating Activities
Net income $ 61,302 $ 63,583 $ 59,134
Items not requiring
(providing) cash:
Depreciation and
amortization 63,647 60,330 58,119
Deferred income taxes and
investment tax credits,
net 5,584 1,511 3,079
Allowance for equity funds
used during construction (1,523) (1,633) (886)
Changes in certain assets
and liabilities:
Accounts receivable (4,881) (26,017) (38,102)
Inventories 2,838 1,168 4,467
Other current assets (24,436) (2,184) (2,955)
Retail fuel costs (4,349) (1,617) (27,946)
Accounts payable 1,338 (11,046) 23,806
Accrued taxes and interest 3,077 1,736 (196)
Miscellaneous current
liabilities (3,296) 1,506 1,194
Deferred energy-management
costs (10,192) (11,183) (9,513)
Maine Yankee outage
accrual 4,962 (3,122) 6,666
Purchased-power contract
buyouts (515) (19,365) -
Revenue adjustment-tax
flowback (9,990) 9,990 -
Other, net (16,932) (6,771) 2,831
Net Cash Provided by
Operating Activities 66,634 56,886 79,698
Investing Activities
Construction expenditures (53,576) (72,307) (75,609)
Investments in associated
companies - (885) (259)
-17-
<PAGE>
Year Ended December 31
1993 1992 1991
Changes in accounts
payable - investing
activities (2,905) (1,932) (905)
Net Cash Used by Investing
Activities (56,481) (75,124) (76,773)
Financing Activities
Issuances:
Mortgage bonds 260,000 75,000 100,000
Common stock 25,513 24,179 18,397
Medium-term notes 48,000 70,000 20,000
Preferred stock - 75,000 -
Redemptions:
Mortgage bonds (177,500) (135,000) (121,250)
Premiums on redemptions (9,634) (3,212) (2,871)
Preferred stock (7,125) (2,750) (1,375)
Medium-term notes (26,500) (37,500) (25,000)
Short-term obligations,
net (63,000) 5,000 56,950
Other long-term
obligations, net (868) (874) 5,156
Dividends:
Common stock (49,345) (47,566) (45,813)
Preferred stock (8,664) (6,115) (5,508)
Net Cash Provided (Used)
by Financing Activities (9,123) 16,162 (1,314)
Net Increase (Decrease) in
Cash and Cash Equivalents 1,030 (2,076) 1,611
Cash and cash equivalents,
beginning of year 926 3,002 1,391
Cash and Cash Equivalents,
end of year $ 1,956 $ 926 $ 3,002
Supplemental Cash-Flow
Information:
Cash paid during the year
for:
Interest (net of amounts
capitalized) $ 42,870 $ 49,874 $ 54,712
Income taxes 15,852 17,749 18,323
Supplemental Noncash
Investing and Financing
Activities:
New capital lease
obligations incurred $ - $ - $ 4,167
</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.
<TABLE>
<C> <C> <C> <C>
Consolidated Balance Sheet
(Dollars in Thousands)
December 31,
-18- <PAGE>
Assets 1993 1992
Electric property, at original cost
(Notes 6 and 7) $1,564,875 $1,516,945
Less: accumulated depreciation (Note 1) 503,280 474,036
Electric property in service 1,061,595 1,042,909
Construction work in progress (Note 4) 19,689 34,550
Nuclear fuel, less accumulated
amortization of $7,242 in 1993 and
$6,544 in 1992 1,822 1,899
Net electric property 1,083,106 1,079,358
Investments in associated companies, at
equity (Notes 1 and 6) 47,452 46,904
Net Electric Property and Investments in
Associated Companies 1,130,558 1,126,262
Current assets
Cash and temporary cash investments 1,956 926
Accounts receivable, less allowances for
uncollectible accounts of $2,704 in 1993
and $2,250 in 1992:
Service - billed 83,330 80,831
Service - unbilled (Notes 1 and 3) 67,022 67,425
Other accounts receivable 10,651 7,866
Undercollected retail fuel costs 84,708 80,359
Prepaid income taxes 1,335 2,488
Fuel oil inventory, at average cost 6,939 8,488
Materials and supplies, at average cost 14,430 15,719
Funds on deposit with trustee 27,758 4,407
Prepayments and other current assets 8,008 6,923
Total Current Assets 306,137 275,432
Deferred charges and other assets (Note
1)
Recoverable costs of Seabrook 1 and
abandoned projects, net 110,443 113,127
Yankee Atomic purchased-power contract
(Note 6) 32,775 38,217
Regulatory assets - deferred taxes (Note
2) 237,387 -
Deferred charges and other assets 187,562 136,967
Total Deferred Charges and Other Assets 568,167 288,311
Total Assets $2,004,862 $1,690,005
</TABLE>
<TABLE>
<S> <C> <C>
(Dollars in Thousands)
December 31
Stockholders' Investment and Liabilities 1993 1992
Capitalization (see separate statement) (Note
7)
Common stock investment $ 553,389 $ 520,368
Preferred stock 65,571 110,571
Redeemable preferred stock 80,000 40,750
Long-term obligations 581,844 499,029
Total Capitalization 1,280,804 1,170,718
Current liabilities and interim financing
Interim financing (see separate statement)
(Note 7) 68,500 115,000
Sinking-fund requirements (Note 7) 3,421 4,726
Accounts payable 94,417 95,984
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<PAGE>
Dividends payable 9,468 14,291
Accrued interest 12,680 10,756
Miscellaneous current liabilities 13,137 16,433
Total Other Current Liabilities 133,123 142,190
Total Current Liabilities and Interim Financing 201,623 257,190
Commitments and contingencies (Notes 4 and 6)
Reserves and deferred credits
Accumulated deferred income taxes (Note 2) 341,349 137,933
Unamortized investment tax credits (Note 2) 36,679 38,511
Yankee Atomic purchased - power contract (Note
6) 32,775 38,217
Regulatory liabilities - deferred taxes (Note
2) 49,734 -
Other reserves and deferred credits 61,898 47,436
Total Reserves and Deferred Credits 522,435 262,097
Total Stockholders' Investment and Liabilities $2,004,862 $1,690,005
The accompanying notes are an integral part of these financial statements.
</TABLE>
<TABLE>
<S> <C> <C> <C> <C> <C>
Consolidated Statement of Capitalization and Interim Financing
(Dollars in Thousands)
December 31
1993 1992
Amount % Amount %
Capitalization
(Note 7)
Common-stock
investment:
Common stock, par
value $5 per share:
Authorized -
80,000,000 shares
Outstanding -
32,379,937 shares
in 1993 and
31,148,321 shares
in 1992 $ 161,900 $ 155,742
Other paid-in
capital 274,343 254,576
Retained earnings 117,146 110,050
Total Common Stock
Investment 553,389 41.0% 520,368 40.5%
Preferred Stock -
not subject to
mandatory
redemption 65,571 4.9 110,571 8.6
Preferred stock -
subject to
mandatory
redemption 80,000 42,125
Less: current
sinking fund
requirements - 1,375
-20-
<PAGE>
December 31
1993 1992
Amount % Amount %
Redeemable
Preferred Stock -
subject to
mandatory
redemption 80,000 5.9 40,750 3.2
Long-term
obligations:
Mortgage bonds 407,500 325,000
Less: unamortized
debt discount 2,175 892
Total Mortgage
Bonds 405,325 324,108
Medium-Term Notes 146,000 124,500
Other long-term
obligations:
Lease obligations 42,740 45,204
Pollution-control
facility and other
notes 34,200 35,068
Total Other
Long-Term
Obligations 76,940 80,272
Less: Current
Sinking Fund
Requirements
and Current
Maturities 46,421 29,851
Total Long-Term
Obligations 581,844 43.1 499,029 38.8
Total
Capitalization 1,280,804 94.9 1,170,718 91.1
Interim financing,
amounts to be
refinanced (Note
7):
Short-term
obligations 25,500 88,500
Current maturities
of long-term
obligations 43,000 26,500
Total Interim
Financing 68,500 5.1 115,000 8.9
Total
Capitalization and
Interim Financing $1,349,304 100.0% $1,285,718 100.0%
The accompanying notes are an integral part of these financial statements.
</TABLE>
<TABLE>
<C> <S> <C> <C> <C> <C> <C>
Consolidated Statement of Changes in Common Stock Investment
For the Three Years Ended December 31, 1993
(Dollars in Thousands)
-21- <PAGE>
Amount Other
at Paid-In
Par Capital Retained
Shares Value Earnings Total
Balance -
December 31,
1990 28,945,143 $144,726 $223,837 $ 95,142 $463,705
Net income 59,134 59,134
Dividends
declared:
Common stock (46,200) (46,200)
Preferred
stock (5,479) (5,479)
Cost for
reacquired
preferred stock 617 (617) -
Issues of common
stock 1,053,791 5,269 13,128 18,397
Capital stock
expense (6) (6)
Balance -
December 31,
1991 29,998,934 149,995 237,576 101,980 489,551
Net income 63,583 63,583
Dividends
declared:
Common stock (47,988) (47,988)
Preferred
stock (6,908) (6,908)
Cost for
reacquired
preferred stock 617 (617) -
Issues of common
stock 1,149,387 5,747 18,432 24,179
Capital stock
expense (2,049) (2,049)
Balance -
December 31,
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
</TABLE>
-22- <PAGE>
The accompanying notes are an integral part of these financial
statements.
Note 1 - Summary of Significant Accounting Policies
Financial Statements: The consolidated financial statements
include the accounts of Central Maine Power Company (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.
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. The Company's approved tariffs provide for the
recovery of the cost of fuel used in Company generating
facilities and purchased-power energy costs. The Company also
collects interest on unbilled fuel and pays interest on
fuel-related over-collections. 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 - Incentive Regulation," for
further information.
Depreciation: Depreciation of electric property is calculated
using the straight-line method. The weighted average composite
rates were 2.9 percent in 1993, 2.9 percent in 1992, and 3.0
percent in 1991.
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 9.8 percent in 1993, 10.2 percent in 1992, and
10.5 percent in 1991.
Property Taxes: Effective January 1, 1993, the Company changed
its method of accounting for property taxes such that these taxes
are accrued monthly during the fiscal period of the taxing
entity. Previously, the Company had accrued taxes over a
statutory tax year of April to March. The effect of the change
was to increase earnings for common stock by $2.7 million or $.09
per share for the year ended December 31, 1993.
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.
Deferred costs related to energy-management programs of $43.3
million are being amortized and recovered through rates over
periods of five to 10 years, while $9.2 million are deferred for
-23-
<PAGE>
future recovery. Deferred financing costs of $30.1 million are
being recovered through rates over periods ranging from three to
30 years. Other deferred amounts totalling $30.8 million are
being recovered through rates over periods ranging from 5 to 38
years.
In accordance with MPUC accounting orders, deferred charges and
other assets include $8.0 million related to environmental-site
cleanup and $9.9 million related to postretirement benefits.
Refer to Note 4, "Commitments and Contingencies - Legal and
Environmental Matters" and Note 5, "Pension and Other
Post-Employment Benefits - Other Post-Employment Benefits," for
additional discussion of these matters.
During 1992, the Company paid approximately $19 million to buy
out certain purchased-power contracts, the cost of which was
deferred. The MPUC authorized the Company to begin amortization
and recovery in rates effective July 1993, over periods of two to
15 years.
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, 1993, all
deferred taxes related to Seabrook I have been amortized. The
recoverable investments as of December 31, 1993, and 1992 are as
follows:
<TABLE>
<S> <C> <C> <C> <C>
(Dollars in Thousands)
December 31,
Recovery
Periods
Recoverable costs of: 1993 1992 Ending
Seabrook 1 $141,084 $141,084 2015
Other projects 57,491 57,491 1995 to 2001
198,575 198,575
Less: accumulated
amortization 84,212 73,984
Less: related income taxes 3,920 11,464
Total Net Recoverable
Investment $110,443 $113,127
</TABLE>
Note 2 - Income Taxes
The components of federal and state income taxes reflected in the
Consolidated Statement of Earnings are as follows:
<TABLE>
<S> <C> <C> <C>
Year Ended December 31,
(Dollars in Thousands) 1993 1992 1991
Federal:
Current $ 13,456 $13,087 $13,471
Deferred 37,455 4,187 3,896
Investment tax credits,
net (1,832) (1,690) 447
-24- <PAGE>
Regulatory deferred (30,224) - -
Total Federal Taxes 18,855 15,584 17,814
State:
Current 3,549 3,837 5,181
Deferred 10,250 (986) (1,264)
Regulatory deferred (10,065) - -
Total State Taxes 3,734 2,851 3,917
Total Federal and State
Income Taxes $22,589 $18,435 $21,731
Federal and state
income taxes charged
to:
Operating expense $25,716 $18,258 $21,685
Other income (3,127) 177 46
$22,589 $18,435 $21,731
</TABLE>
The Company and MEPCO record deferred income-tax expense in
accordance with regulatory authority and 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,
1993, the Company had fully utilized all investment and energy
tax credits generated.
Effective January 1, 1993, the Company adopted the provisions of
the Financial Accounting Standards Board (FASB) Statement of
Financial Accounting Standards No. 109, "Accounting for Income
Taxes" (SFAS No. 109). SFAS No. 109 requires recognition of
deferred tax liabilities and assets for the expected future tax
consequences of events that have been included in the financial
statements or tax returns. Under this method, 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.
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 have 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)
was able to record 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. The adoption of
SFAS No. 109 had no impact on net income.
The Company filed a request for an accounting order with the MPUC
in 1992 to reaffirm its regulatory policy allowing recovery of
amounts for income taxes payable in the future and on August 31,
1993, the MPUC adopted and established for regulatory accounting
and reporting purposes the standards required by the FASB in SFAS
No. 109. Prior to the implementation of SFAS No. 109, the
Company accounted for income taxes using Accounting Principles
Board Opinion No. 11.
-25- <PAGE>
Accumulated deferred income taxes consisted of the following in
1993:
<TABLE>
<S> <C> <C>
(Dollars in Thousands) 1993
Accumulated deferred income taxes, net at
January 1, 1993 $297,564
Assets:
Investment tax credits, net $ 25,198
Regulatory liabilities 10,191
Alternative minimum tax 4,768
All other 12,095
52,252
Liabilities:
Property-related 254,796
Abandoned plant 76,128
Regulatory assets 66,597
397,521
Accumulated deferred income taxes, net at
December 31, 1993 $345,269
Accumulated deferred income taxes, recorded as:
Accumulated deferred income taxes $341,349
Recoverable costs of Seabrook 1 and abandoned
projects, net 3,920
$345,269
</TABLE>
A valuation allowance has not been recorded at December 31, 1993,
as the Company expects that all deferred income tax assets will
be realized in the future.
The tax effects of the significant timing differences for the
years ended December 31, 1992, and 1991 required to be disclosed
pursuant to the accounting standards for income taxes in effect
prior to the adoption of SFAS No. 109 are as follows:
<TABLE>
<S> <C> <C> <C> <C>
Year Ended December 31
(Dollars in Thousands) 1992 1991
Federal State Federal State
Depreciation $ 7,173 $ (64) $ 9,127 $ (106)
Amortization of loss on
investments in abandoned
projects (6,181) (1,364) (6,147) (1,353)
Alternative minimum tax 1,187 - 328 -
Energy management costs 2,163 627 1,802 522
Loss on reacquired debt (3,183) (892) 480 140
Hurricane Bob (1,202) (347) 1,202 347
Maine Yankee refueling
outage 1,148 331 (2,064) (595)
Early retirement programs (364) (113) (1,132) (381)
Revenue adjustment-tax
flowback (3,063) (981) - -
Purchased-power contract
buyouts 5,740 1,655 - -
Other, net 769 162 300 162
Total Deferred Taxes $4,187 $(986) $3,896 $ (1,264)
</TABLE>
-26- <PAGE>
The Omnibus Budget Revenue Reconciliation Act of 1993 increased
the corporate tax rate from 34 percent to 35 percent effective
January 1, 1993. The tax impact on total current and deferred
tax expense for the year ended December 31, 1993 was
approximately $0.7 million. The additional deferred taxes
recorded as a result of the corporate tax rate change were
approximately $13.0 million.
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>
<S> <C> <C> <C> <C> <C> <C> <C>
Year Ended December 31
(Dollars in 1993 1992 1991
Thousands)
Amount % Amount % Amount %
Income tax
expense at
statutory
federal rate $28,055 35.0 % $26,917 34.0 % $26,162 34.0 %
Permanent
differences:
Investment tax
credit
amortization (1,613) (2.0) (1,613) (2.0) (1,608) (2.1)
Dividend
received
deduction (1,731) (2.2) (1,920) (2.4) (2,432) (3.2)
Other, net (634) (0.8) (585) (0.8) (395) (0.5)
24,077 30.0 22,799 28.8 21,727 28.2
Effect of
timing
differences for
which deferred
taxes are not
recorded (flow
through):
Tax basis
repairs (1,175) (1.5) (899) (1.1) (1,583) (2.0)
Depreciation
differences
flowed through
in prior years 1,728 2.2 2,024 2.5 2,104 2.7
Accelerated
flowback of
deferred taxes
on loss on
abandoned
generating
projects (2,678) (3.3) (2,778) (3.5) (2,808) (3.6)
Deduction of
removal costs (392) (0.5) (649) (0.8) (1,058) (1.4)
Carrying costs,
net (523) (0.7) (199) (0.3) 51 0.1
-27-
<PAGE>
Year Ended December 31
(Dollars in 1993 1992 1991
Thousands)
Amount % Amount % Amount %
Adjustment to
tax accrual for
change in rate
treatment 481 0.6 - - (150) (0.2)
Reduction for
non-regulated
deferred taxes
previously
flowed through (1,530) (1.9) - - - -
Excess property
taxes paid (912) (1.1) 175 0.2 (25) -
Accelerated
flowback of
deferred taxes
on loss on
reacquired debt - - (4,618) (5.8) - -
Accelerated
5-year flowback
of certain
regulatory
deferred taxes - - - - (710) (0.9)
Other, net (221) (0.3) (271) (0.3) 266 0.3
Federal Income
Tax Expense and
Effective Rate $18,855 23.5 % $15,584 19.7 % $17,814 23.2 %
</TABLE>
Note 3 - Regulatory Matters
Incentive Regulation: On May 7, 1991, the MPUC ordered a
three-year trial of the Electric Revenue Adjustment Mechanism
(ERAM), a fundamental change in the way the Company's revenues
were treated, and set new incentives for effective
utility-sponsored energy management. On July 16, 1992, the MPUC
issued an order authorizing the Company to begin collecting $7.8
million, which was only a portion of the $26.2 million of ERAM
revenues accrued in its first year, and an energy-management
incentive of $1.5 million, beginning in September 1992.
Approximately $18.4 million of ERAM revenues accrued in the 12
months beginning March 1, 1991, were, therefore, carried over to
the 1993 ERAM filing. In January 1993, the MPUC approved a
stipulation that resolved several outstanding issues, including
those in the Company's ERAM proceeding. The stipulation
permitted recovery of accrued ERAM balances in accordance with
the terms of an Emerging Issues Task Force consensus. The
stipulation also authorized recovery of the costs associated with
buy-outs by the Company of certain purchased-power contracts and
requested the MPUC to grant an increase in the Company's
fuel-cost adjustment. The stipulation also approved an
Accounting Order permitting the Company to accelerate the
flow-back of $5.9 million of certain deferred taxes associated
with prior losses on reacquired debt. For 1992, the stipulation
placed a limit of 11.25 percent on the Company's allowed rate of
return on equity. Earnings in excess of the limit, up to
approximately $10 million (the revenue requirement of the tax
benefits), were applied on a monthly basis to reduce 1993 ERAM
-28-
<PAGE>
accruals. Additionally, approximately $317,000 of income, net of
income taxes, in excess of the $10 million, was used to fund a
portion of 1993 operation-and-maintenance expenses.
The stipulation also reduced the amount of ERAM accruals from
January 1993 through November 1993 by $591,000 per month. The
ERAM program continued until the effective date of new base
rates, December 1, 1993.
As contemplated by the terms of the January 1993 stipulation, the
MPUC approved a revenue increase of $40 million, effective
July 1, 1993, which included, among other things, $21.2 million
toward recovery of deferred ERAM revenues.
As of December 31, 1993, the Company had collected approximately
$19.2 million of the ERAM revenues; the unbilled ERAM balance at
that time was approximately $50.5 million.
Base Rates: On March 1, 1993, the Company filed a request with
the MPUC for a $95-million increase in base rates. The major
components of the request were (1) compensating for
lower-than-forecasted sales, (2) increased
operation-and-maintenance expenses, (3) increased operating costs
of the four operating nuclear plants in which the Company owns
interests, (4) property additions and transmission, distribution
and other improvements, (5) energy-management program costs and,
(6) the expiration of certain tax benefits. Ultimately, the
Company reduced the amount of its base-rate request from $95
million to $83 million. The decrease was the result of lower
estimates of 1994 operation and maintenance expenses, further
reductions in the Company's cost of capital, a decrease in the
level of anticipated expenditures for energy-management programs
and the change in the federal income-tax rate from 34 percent to
35 percent.
On December 14, 1993, the MPUC issued its order in the
proceeding. The MPUC's analysis indicated a need for additional
revenues of $51.5 million, yet found the Company to be entitled
to a net revenue increase of only $26.2 million. The Commission
found a total cost of capital of 8.52 percent and a cost of
equity of 10.05 percent, after deducting a one-half percent (.5%)
return-on-equity penalty established by the MPUC in a 1993
investigation of the Company's management of certain independent
power-producer contracts. See "Other MPUC Proceedings" below,
for further discussion of this investigation. To arrive at its
revenue-requirement conclusion, the MPUC deducted $25.3 million
"to adjust for management inefficiency" after finding the
Company's performance in the areas of management efficiency and
cost-cutting to have been "inadequate".
The Company strongly disagrees with the MPUC's
management-inefficiency finding and with the resulting deduction
of nearly one-half the revenue increase to which the Commission
itself found the Company to be otherwise entitled using
traditional ratemaking principles. The Company filed an appeal
of the base-rate order with the Maine Supreme Judicial Court.
The Company cannot, however, predict the result of that appeal.
Other MPUC Proceedings: On October 28, 1993, in connection with
a proceeding on independent power-producer contracts, the MPUC
issued an order finding that the Company had been unreasonable
-29-
<PAGE>
and imprudent in its management of two independent power-producer
contracts and indicated that it would reduce the Company's
allowed rate of return on equity by one-half percent (.5%) in the
then-pending base-rate case (approximately $4 million, before
income taxes, over a 12-month period) and directed the Company to
charge against deferred fuel-cost balances approximately $4.1
million of payments from power providers that had previously been
credited against purchased-power capacity costs, unless the
Company could demonstrate that the crediting was proper. The
Company recorded a reserve totalling $4.1 million during the
third quarter of 1993, reflecting the impact of the order.
Finally, the MPUC announced that it would review in the future
the Company's administration and management of certain
power-purchase contracts for purchases of 10 megawatts or more.
On December 20, 1993, the Chief Justice of the Maine Supreme
Judicial Court, acting on the Company's request, issued an order
staying the effectiveness of the 0.5-percent return-on-equity
penalty pending final resolution of the Company's appeal of the
October 28, 1993, MPUC order to the Maine Supreme Judicial Court.
In addition, the court ordered that if the Company should not
prevail on its appeal, it would be required to refund any
revenues collected as a result of the stay order, with interest.
Finally, the court ordered an expedited hearing on the appeal,
scheduling oral argument before the Maine Supreme Judicial Court
for March 1994. Based on that schedule, a decision is expected
by early summer 1994.
On February 3, 1994, the MPUC filed a Motion to Dismiss with the
Court, stating that by order dated February 3, 1994, the
Commission had reopened and reconsidered its October 28, 1993
decision. As a result of such reconsideration, the MPUC decided
to vacate the return-on-equity penalty conditioned on either the
Company's acquiescence in the MPUC's jurisdiction or a finding by
the Court that the MPUC retains jurisdiction, and to consider
alternative remedies. The MPUC argued that, because of its
February 3 order, the Company's appeal of the return-on-equity
penalty should be dismissed as moot.
The Chief Justice declined to dismiss the appeal and added the
jurisdictional question to the issues to be determined by the
Court.
The MPUC, in its February 3, 1994 order, indicated that an
alternative remedy under consideration by the MPUC "appears to
present an opportunity to insulate ratepayers sufficiently from
CMP's imprudence...," yet also noted, "We do not decide at this
time that such a remedy...will be adopted." The MPUC order
indicated an intent to seek additional information on the issue
of annual differences between the contract rates and avoided
costs. The Company cannot predict the outcome of the appeal on
either the issue of jurisdiction or the merits of the
return-on-equity penalty, nor is it able to predict the outcome
of this issue if remanded to the Commission, or any appeal from
such alternative remedy or any legislative action.
Federal Energy Regulatory Commission: On August 2, 1991, the
FERC issued an order requiring the Company to revise its rates to
a level reflecting the filed cost of service associated with each
of 14 contracts for non-territorial sales, rather than the
negotiated market-based levels. Other revenues in 1991 reflect
-30-
<PAGE>
the establishment of a $4.5-million reserve to reflect refunds
associated with some of the contracts. Other revenues for 1992
reflect the reversal of approximately $1.9 million of that
reserve as a result of a settlement agreement that required the
Company to refund approximately $2.6 million related to this
issue.
After rejection by the FERC of the Company's continuing claims of
disparate treatment based on its having been ordered to make
refunds while several similarly situated utilities were not, on
September 29, 1993, the FERC rescinded the Company's obligation
to make refunds. In making its decision, the FERC invoked its
"equitable discretion" and agreed that, based on its having
granted a general amnesty from refunds to other utilities,
circumstances had changed so dramatically since its approval of
the Company's 1992 refund settlement that it would be "unfair to
continue to single out Central Maine for refunds." The FERC
order allows the utilities that had shared the $2.6 million in
refunds to repay the Company, with interest, over a 24-month
period. The utility that received the major share of the amount
refunded by the Company has requested reconsideration of the FERC
rescission order. The Company recorded approximately $3.0
million of income during the third quarter of 1993, reflecting
the refund including interest.
The Company cannot predict the outcome of the other utility's
request for reconsideration, or what portion, if any, of the $3.0
million received in 1993, may have to be refunded by the Company.
Note 4 - Commitments and Contingencies
Construction Program: The Company's plans for improvements and
expansion of generating, transmission-and-distribution
facilities, and power-supply sources are under continuing review.
As part of the Company's cost reduction actions, the general
construction budget was reduced by $14 million, and a
transmission project of $5 million was deferred for one year.
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 forecasted capital expenditures for the five-year period
1994 through 1998, including AFC of approximately $3 million, are
as follows:
<TABLE>
<S> <C> <C> <C> <C>
(Dollars in Millions) 1994 1995 -1998 Total
Type of Facilities:
Generating projects $11 $48 $ 59
Transmission 7 28 35
Distribution 23 100 123
General 12 52 64
Energy management 7 28 35
Total Estimated
Capital Expenditures $60 $256 $316
</TABLE>
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 as a potentially responsible party and has been
incurring costs to determine the best method of cleaning up an
-31-
<PAGE>
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 1990, the Company and the EPA signed a negotiated consent
agreement, which was entered as an order by the United States
District Court for the District of Maine in 1991. The agreement
provides for studies, development of work plans, additional EPA
review, and eventual cleanup of the site by the Company over a
period of years, using the method and level of cleanup selected
by the EPA.
The Company has been investigating other courses of action that
might result in lower costs and, in March 1992, acquired title to
the site to pursue the possibility of developing it in a manner
that would not require the same method and level of cleanup
currently provided in the agreement. The Company also initiated
a lawsuit against the original owners of the site and
Westinghouse Electric Co. (Westinghouse), which arranged for the
equipment disposal, seeking contributions toward past and future
cleanup costs. On November 8, 1993, the United States District
Court for the District of Maine rendered its decision in the
suit, holding that Westinghouse was responsible for 41 percent of
the necessary past and future cleanup costs and the former owners
12.5 percent, other than a small amount (less than 5 percent) of
such costs not attributable to PCBs, for which Westinghouse was
held not responsible and the former owners were held responsible
for 33 percent. The Court further concluded that the Company had
incurred approximately $3.3 million to that point in costs
subject to sharing among the parties.
At the same time, the Company has been actively pursuing recovery
of its costs through its insurance carriers and has reached
agreement with one for recovering a portion of those costs. It
has also filed lawsuits seeking such recovery from other
carriers.
In August 1991, the Company requested permission from the MPUC to
defer its cleanup-related costs, with accrued carrying costs, on
the basis that such costs are allowable costs of service and
should be recoverable in rates. In August 1992, the MPUC issued
an order authorizing the Company to defer direct costs associated
with the site incurred after August 9, 1991, with accrued
carrying costs. Such costs incurred prior to the request were
charged to a $3-million reserve established in 1985.
Initial tests on the site have been completed and more complex
technological studies are still in progress. Based on results to
date and on the most likely cleanup method, the Company believes
that the remaining costs of the cleanup will total between $7
million and $11 million, depending on the level of cleanup
ultimately required and other variable factors. Such estimate is
net of the agreed insurance recovery and considers any
contributions from Westinghouse and the former owners, but
excludes contributions from the insurance carriers the Company
has sued, or any other third parties. As a result, in the fourth
quarter of 1993, the Company decreased the liability recorded on
its books from $14 million, the estimated liability prior to the
November 1993 court ruling, to $7 million and recorded an equal
reduction in a regulatory asset, established to reflect the
-32-
<PAGE>
anticipated ratemaking recovery of such costs when ultimately
paid. Approximately $1 million of costs incurred to date has
been charged against the liability.
The Company cannot predict the level and timing of the cleanup
costs, the extent to which they will be covered by insurance, or
the ratemaking treatment of such costs, but believes it should
recover substantially all of such costs through insurance and
rates. The Company also believes that the ultimate resolution of
the legal and environmental proceedings in which it is currently
involved will not have a material adverse effect on its financial
condition.
Power Purchase Contract Suit: In December 1992, the Company
terminated a 30-year power-purchase contract with Caithness King
of Maine Limited Partnership (Caithness) for the purchase of
approximately 80 megawatts of electric power from a cogeneration
project proposed for construction by Caithness at Topsham, Maine.
On March 17, 1993, after legal action was threatened against the
Company by Caithness, the Company instituted a
declaratory-judgment action against Caithness and certain
affiliated entities in the United States District Court for the
District of Maine seeking a judicial confirmation of its right to
terminate the contract. On April 15, 1993, Caithness filed its
response to the action, including counterclaims alleging a breach
of the contract by the Company, among other claims, and seeking
damages estimated by Caithness to be in excess of $100 million
or, in the alternative, reformation of the contract and other
legal relief.
In January 1994, a termination-and-settlement agreement was
reached between the parties, whereby Caithness would terminate
the project and release all rights, claims, interests and
entitlement thereunder, and the Company would pay Caithness $5
million in consideration. The Company expects to defer this
amount and amortize it over the life of the original contract
when ultimately allowed in rates.
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 $75.5 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 $45.3 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
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<PAGE>
premiums and the Company's indirect and direct ownership in
nuclear generating facilities, this adjustment could range up to
approximately $6.3 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. Total
pension expense related to these plans amounted to $3.7 million
in 1993, $8.1 million in 1992, and $11.1 million in 1991. 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 1991, the Company offered an Early Retirement Incentive
Plan (ERIP) to qualifying employees. Approximately 200 employees
accepted the offer. The actuarial present value of the ERIP was
$12.2 million, of which $3.1 million and $6.7 million were
included in pension expense for 1992 and 1991, respectively. The
remaining $2.4 million cost was recorded as a deferred charge and
is being amortized to expense in 1994 and 1995 in accordance with
accounting and ratemaking orders from the MPUC.
A summary of the components of net periodic pension cost for the
non-union and union defined-benefit plans in 1993, 1992, and 1991
follows:
<TABLE>
<S> <C> <C> <C> <C> <C> <C>
1993 1992 1991
(Dollars in Non- Non- Non-
Thousands) Union Union Union Union Union Union
Service cost
- benefits
earned during
the period $2,092 $1,436 $2,344 $1,271 $2,240 $1,252
Interest cost
on projected
benefit
obligation 5,355 3,691 5,709 3,705 5,026 3,207
Return on
plan assets (9,669) (6,051) (5,085) (3,198) (14,927) (9,525)
Net
amortization
and deferral 4,419 2,457 351 (104) 10,641 6,484
Early
Retirement
Incentive
Program - - 1,240 1,821 2,727 4,006
Net periodic
pension cost $2,197 $1,533 $4,559 $ 3,495 $ 5,707 $ 5,424
</TABLE>
Assumptions used in accounting for the non-union and union
defined-benefit plans in 1993, 1992, and 1991 are as follows:
-34- <PAGE>
<TABLE>
<S> <C> <C> <C>
1993 1992 1991
Weighted average discount
rates 7.5% 8.0% 8.5%
Rate of increase in future
compensation levels 5.0% 5.5% 7.0%
Expected long-term return
on assets 8.5% 8.5% 8.5%
</TABLE>
The following table sets forth the actuarial present value of
pension-benefit obligations, the funded status of the plans, and
the liabilities recognized on the Company's balance sheet at
December 31, 1993, and 1992:
<TABLE>
<S> <C> <C> <C> <C>
1993 1992
(Dollars in Thousands) Non- Union Non- Union
Union Union
Actuarial present value
of benefit obligations:
Vested benefit
obligation $54,837 $41,521 $50,771 $38,194
Accumulated benefit
obligation $58,777 $44,674 $53,783 $40,503
Projected benefit
obligation $73,674 $50,845 $68,037 $46,293
Plan assets at
estimated market value
(primarily stocks,
bonds, and guaranteed
annuity contracts) 80,787 50,007 71,713 45,248
Funded status-projected
benefit obligation in
excess of or (less
than) plan assets (7,113) 838 (3,676) 1,045
Early Retirement
Incentive Program
deferral (992) (1,457) (992) (1,457)
Unrecognized prior
service cost (1,724) (1,089) (1,619) (1,169)
Unrecognized net gain 15,516 5,529 13,776 5,771
Unrecognized (net
obligation) net asset (250) 2,980 (279) 3,304
Net Pension Liability
Recognized in the
Balance Sheet $ 5,437 $ 6,801 $ 7,210 $ 7,494
</TABLE>
Other Post-Employment Benefits: In addition to pension benefits,
the Company provides certain health-care and life-insurance
benefits for substantially all of its retired employees.
In December 1990, FASB issued Statement of Financial Accounting
Standards No. 106, "Employers' Accounting for Postretirement
Benefits Other Than Pensions" (SFAS No. 106), which the Company
adopted effective January 1, 1993. The new standards require the
accrual of the expected cost of such benefits during the
employees' years of service. The effect of the change can be
reflected in annual expenses over the active service life of
-35-
<PAGE>
employees or a period of 20 years, rather than in the year of
adoption.
The MPUC approved a rulemaking on SFAS No. 106, effective
July 20, 1993, for all jurisdictional utilities. The rule adopts
the accrual method of accounting and authorizes the establishment
of a regulatory asset for the deferral of such costs until they
are "phased-in" for ratemaking purposes. 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
will be adopted concurrent with the initial recovery in rates.
Until then, 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
($6.5 million in 1993, $5.0 million in 1992, and $3.8 million in
1991), with the excess over that amount in 1993 of $ 9.9 million
deferred for future recovery. During 1993, the Company
contributed $0.9 million to a Voluntary Employee Benefit
Association (VEBA) trust based on an actuarial computation of
claims incurred but not paid, as of December 31, 1993.
A summary of the components of net periodic postretirement
benefit cost for the plan in 1993 follows:
<TABLE>
<S> <C>
(Dollars in Thousands) 1993
Service cost $ 1,429
Interest on accumulated post-retirement
benefit obligation 8,352
Actual return on plan assets -
Amortization of transition obligation 5,306
Postretirement benefits expense 15,087
Deferred postretirement benefits expense 8,612
Postretirement benefit expense recognized in
the income statement $ 6,475
</TABLE>
The health-care cost trend rates assume trends ranging from 10.2
percent to 16.1 percent for 1993, 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 $1.1 million and the accumulated
postretirement benefit obligation by $10.0 million. Additional
assumptions used in accounting for the postretirement benefit
plan in 1993 are as follows:
1993
Weighted average discount rate 7.5%
Rate of increase in future compensation levels 5.5%
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, 1993:
-36-
<PAGE>
<TABLE>
<S> <C> <S> <C> <C>
(Dollars in Thousands) 1993
Accumulated post-retirement benefit obligation:
Retirees $ 73,809
Fully eligible active plan participants 5,559
Other active plan participants 22,880
Total accumulated postretirement benefit obligation 102,248
Plan assets, at fair value 854
Accumulated postretirement benefits obligation in excess of
plan assets 101,394
Unrecognized net loss (4,013)
Unrecognized transition obligation (87,515)
Accrued postretirement benefit cost recognized in the balance
sheet $ 9,866
</TABLE>
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, 1993, are as follows:
<TABLE>
<S> <C> <C> <C> <C> <C>
Maine Vermont Connecticut Yankee
Yankee Yankee Yankee Atomic*
Ownership share 38% 4% 6% 9.5%
Contract expiration date 2008 2012 1998 2000
Capacity (MW) 880 519 583 -
Company's share of:
Capacity (MW) 330 21 35 -
Estimated annual costs (1993
costs in thousands) $67,368 $6,469 $13,378 $5,722
Long-term obligations and
redeemable preferred stock
(thousands) $93,444 $6,413 $12,074 $1,710
*See below for discussion on Yankee Atomic.
</TABLE>
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
began collecting $9.1 million annually for decommissioning based
on a FERC-approved funding level of $167 million. In January
1994, Maine Yankee filed a Notice of Tariff Change with the FERC
to increase its annual collection to $14.9 million and to reduce
-37-
<PAGE>
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 dismantlement
and removal, of $317 million (in 1993 dollars) based on a 1993
external engineering study. 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. Accumulated decommissioning funds were $93.8
million as of December 31, 1993.
Condensed financial information of Maine Yankee Atomic Power
Company is as follows:
<TABLE>
<S> <C> <C> <C>
(Dollars in Thousands) 1993 1992 1991
Earnings:
Operating revenues $193,102 $187,259 $166,471
Operating income 16,580 17,064 20,059
Net income 8,980 9,173 8,863
Earnings applicable to common stock 7,376 8,394 8,369
Company's Equity Share of Net
Earnings $ 2,803 $ 3,190 $ 3,180
Investment:
Net electric property and nuclear
fuel $261,674 $273,195 $288,428
Current assets 36,018 44,149 38,342
Deferred charges and other assets 237,125 203,849 160,111
Total Assets 534,817 521,193 486,881
Less:
Redeemable preferred stock 19,800 20,400 6,000
Long-term obligations 218,839 210,754 221,405
Current liabilities 27,887 40,027 46,598
Reserves and deferred credits 201,222 183,095 145,929
Net Assets $ 67,069 $ 66,917 $ 66,949
Company's Equity in Net Assets $ 25,486 $ 25,428 $ 25,441
</TABLE>
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 $2.3 million. Presently,
purchased-power costs billed to the Company, which include the
estimated cost of the ultimate decommissioning of the unit, are
collected by the Company from its customers through the Company's
base-rate structure.
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 $32.8
million. This estimate, which is subject to ongoing review and
-38-
<PAGE>
revision, has been recorded by the Company as a regulatory asset
and a liability on the accompanying balance sheet. As part of
the MPUC's decision in the Company's recent base-rate case, the
Company's share of costs related to the deactivation of Yankee
Atomic are being recovered through rates based on the most recent
projections of costs. Costs incurred to date total $11.0
million.
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, and related
accumulated depreciation and amortization attributable to these
units as of December 31, 1993, and 1992 were as follows:
<TABLE>
<S> <C> <C> <C> <C>
Wyman 4 Millstone 3
(Dollars in Thousands) 1993 1992 1993 1992
Plant in service and nuclear
fuel $115,598 $115,697 $107,713 $106,229
Accumulated depreciation and
amortization 53,397 49,846 28,744 24,165
</TABLE>
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 $33.2 million, its share of the construction cost
for these transmission facilities incurred through December 31,
1993. These obligations are reflected on the Company's 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 and require the Company to
purchase the energy at specified prices per kilowatt-hour. As of
December 31, 1993, facilities having 596 megawatts of capacity
covered by these contracts were in service; another 15 megawatts
are expected to be added by the end of 1994. The costs of
purchases under all of these contracts amounted to $360.7 million
in 1993, $341.5 million in 1992, and $332.4 million in 1991.
Such costs are recoverable through the Company's fuel clause,
after review and approval by the MPUC.
-39-
<PAGE>
In connection with the Company's 1992 Fuel Cost Adjustment
proceeding, the MPUC announced it would review the prudence of
administration and management of these contracts, as well as the
terms and conditions of recent contracts. Refer to Note 3,
"Regulatory Matters - Other MPUC Proceedings," for further
discussion on this issue.
To control the price pressure related to purchases from
non-utility generators, the Company negotiated long term contract
buy-outs or restructuring with three non-utility generators in
1992, four in 1993, 11 in early 1994, and continues to
renegotiate other contracts. The Company incurred buy-out costs
of approximately $11.4 million in 1993 and $19 million in 1992.
The 1994 renegotiation of prices and contract terms did not
require cash payments. Total buy-outs, restructuring, and
terminations made to date are expected to save the Company's
customers more than $170 million in fuel costs during the next
five years.
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, 1993, the
Company's retained earnings were $117.1 million, of which $87.5
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.
Mortgage Bonds outstanding as of December 31, 1993, and 1992 were
as follows:
<TABLE>
<S> <C> <C> <C> <C>
(Dollars in Thousands)
Interest
Series Redeemed/Maturity Rate 1993 1992
Central Maine Power Company
General and Refunding Mortgage Bonds:
I 1993-April 1 and June 21 9 1/4% $ - $100,000
M 1993-August 20 and September 27 9.18 - 50,000
S 1998-August 15 6.03 60,000 -
T 1998-November 1 6.25 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 50,000
Q 2008-March 1 7.05 75,000 -
-40- <PAGE>
R 2023-June 1 7 7/8 50,000 -
Total Mortgage Bonds $407,500 $325,000
</TABLE>
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 $230 million as of
December 31, 1993. Unsecured indebtedness, as defined, amounted
to $56 million as of December 31, 1993.
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 from time to time 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, 1993, and 1992
were as follows:
<TABLE>
<C> <S> <C> <C> <C>
(Dollars in Thousands)
Maturity Interest Rate 1993 1992
Series A:
1992-1995 5.75%-9.58% $ 13,000 $ 39,500
1996-2000 9.35%-9.65 15,000 15,000
Total Series A 28,000 54,500
Series B:
1992-1995 3.625-6.50* 85,000 55,000
1996-2000 4.92%-6.50 33,000 15,000
Total Series B 118,000 70,000
Total Medium-Term Notes $146,000 $124,500
*Includes $10 million of variable rate notes in 1993, with an average
interest rate of 3.625%.
</TABLE>
Pollution-Control Facility and Other Notes: Pollution-control
facility and other notes outstanding as of December 31, 1993, and
1992 were as follows:
<TABLE>
<S> <C> <S> <C> <C> <C>
(Dollars in Thousands)
Interest
Series Rate Maturity 1993 1992
Central Maine Power Company:
Promissory Note 9% June 15, 1993 $ - $ 8
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
-41- <PAGE>
Industrial Development
Authority of the State 7 3/8% May 1, 2014 11,000 11,000
of New Hampshire Notes 7 3/8% May 1, 2014 8,500 8,500
Maine Electric Power
Company, Inc.:
Promissory Notes Variable
* July 1, 1996 3,450 4,310
Total Pollution-Control Facility and Other Notes $34,200 $35,068
</TABLE>
*The average rate was 4.4% in 1993 and 5.0% in 1992.
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.
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 1996 and 2021. The net book value of property under
capital leases was $40.0 million and $42.6 million at
December 31, 1993, and 1992, 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, 1998, together with the present value of the minimum
lease payments are as follows:
<TABLE>
<C> <S> <C>
(Dollars in Thousands) Amount
1994 $ 7,030
1995 6,865
1996 5,719
1997 5,505
1998 5,340
Thereafter 70,815
Total minimum lease payments 101,274
Less: amounts representing interest 58,534
Present Value of Net Minimum Lease Payments $ 42,740
</TABLE>
Consolidated sinking-fund requirements for long-term obligations,
including capital lease payments and maturing debt issues, for
the five years ending December 31, 1998, are as follows:
<TABLE>
<C> <C> <C> <C> <C>
Sinking Maturing
(Dollars in Thousands) Fund Debt Total
1994 $ 3,421 $ 43,000 $ 46,421
1995 3,503 55,000 58,503
-42- <PAGE>
1996 3,450 10,000 13,450
1997 1,678 15,000 16,678
1998 1,685 143,000 144,685
</TABLE>
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, 1993. 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, 1993 are as follows:
<TABLE>
<S> <C> <C>
(Dollars in Thousands) Carrying Fair
Amount Value
Cash and temporary investments $ 1,956 $ 1,956
Redeemable preferred stock 80,000 79,450
Mortgage bonds 407,500 407,772
Medium-term notes 146,000 148,132
Pollution-control facility and other notes 34,200 37,253
</TABLE>
Anticipated regulatory treatment of the excess of fair value over
carrying value of the Company's financial instruments, if in fact
settled at amounts approximating those above, would dictate that
the excess be used to reduce the Company's rates over a
prescribed amortization period. Accordingly, any settlement
would not result in a material impact on the Company's financial
position or results of operations.
Preferred Stock: Preferred-stock balances outstanding as of
December 31, 1993, 1992, and 1991 were as follows:
<TABLE>
<C> <C> <C> <C> <C>
Current
Shares
(Dollars in Thousands, except Out-
per-share amounts) standing 1993 1992 1991
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
-43-
<PAGE>
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 -
Flexible Money Market
Preferred Stock, Series A -
(redeemable at $100)** None - 45,000 -
Preferred Stock - Not Subject
to Mandatory Redemption $65,571 $110,571 $35,571
Redeemable Preferred Stock -
Subject to Mandatory
Redemption:
$100 par value callable -
authorized 2,300,000* shares;
outstanding:
8.40% series (71,250 shares in
1992 and 98,750 shares in
1991) None $ - $ 7,125 $ 9,875
Flexible Money Market
Preferred Stock, Series A -
7.999% (redeemable at $100) 450,000 45,000 - -
8 7/8% series (redeemable at
$105.917) (350,000 shares in
1992 and in 1991) 350,000 35,000 35,000 35,000
Redeemable Preferred Stock -
Subject to Mandatory Redemption $80,000 $ 42,125 $44,875
*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.
**The average rate was 3.35% through November 16, 1993 and 3.45%
in 1992.
</TABLE>
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, 1998, is $7,000,000 annually beginning in
1996.
On August 27, 1992, the Company issued through a public offering
450,000 shares of Flexible Money Market Preferred Stock, Series
A, $100 par value. The annualized dividend rate based on the
initial 55-day dividend period rate was 3.25 percent. At the
option of the Company, the term of each dividend period
subsequent to the initial period was 49 days or longer, subject
to certain adjustments. Subsequent dividend rates were set by
auction at the end of each dividend period. On November 16,
-44-
<PAGE>
1993, the Board of Directors voted to fix the dividend at 7.999
percent.
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.
Interim Financing: 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 agreement to provide initial financing for
construction and other corporate purposes. As of December 31,
1993, the Company had existing lines of credit totalling $73
million and had an additional $50-million, unsecured
revolving-credit agreement with a group of banks described below.
Annual fees on the unused portion of the lines of credit are 3/16
of 1 percent. These lines of credit are subject to periodic
review and renewal during the year by the banks. Under the terms
of these agreements, the Company had outstanding at December 31,
1993, $15.5 million of commercial paper and $10 million of
short-term bank notes.
As of December 31, 1993, MEPCO had lines of credit totalling $2.5
million with commercial banks to provide for its working-capital
needs. These lines of credit are subject to annual review and
renewal. Annual fees for the lines of credit range from 3/16 to
1/4 of 1 percent. At December 31, 1993, there was no short-term
borrowing outstanding under the MEPCO credit lines.
Credit Agreement: In November 1986, the Company entered into an
unsecured revolving-credit agreement with several banks providing
for loans of up to $40 million. In early 1992, the credit
agreement was amended to increase the aggregate principal amount
of notes that may be outstanding to $50 million. The agreement
is for a three-year period, but may be extended for successive
one-year periods with bank approval. With extensions, the
agreement is presently scheduled to expire on October 15, 1996.
In addition, long-term floating-rate loans outstanding at the
termination of the revolving credit phase may be payable two
years thereafter, under certain conditions. The Company may
borrow at rates, as defined within the credit agreement, based on
a Certificate of Deposit loan rate, a Eurodollar loan rate, or
the agent bank's reference rate. A commitment fee of 3/16 of 1
percent per annum is paid on the unused portion of the line.
Note 8 - Quarterly Financial Data (Unaudited)
Unaudited, consolidated quarterly financial data pertaining to
the results of operations, which reflect the seasonality of
electric sales and higher rates and lower contribution to
earnings per kilowatt-hour during peak-consumption periods, are
shown below.
<TABLE>
<S> <C> <C> <S><C> <S><C>
(Dollars in Thousands, Except
Per-Share Amounts) Quarter Ended
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March June 30 September December 31
31 30
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 (1) .62 .37 .36 .31
1992
Electric operating revenues $246,624 $203,822 $207,170 $220,079
Operating income 34,801 28,678 27,423 23,306
Net income 21,521 15,105 15,203 11,754
Earnings per common share (1) .67 .45 .44 .30
1991
Electric operating revenues $229,213 $202,956 $203,126 $231,244
Operating income 30,506 29,569 26,929 27,259
Net income 16,187 15,535 13,583 13,829
Earnings per common share (1) .51 .48 .41 .42
(1) Earnings per share are computed using the weighted average
number of common shares outstanding during the applicable
quarter.
</TABLE>
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<PAGE>
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
TO THE SHAREHOLDERS AND THE BOARD OF DIRECTORS OF CENTRAL MAINE
POWER COMPANY
We have audited the accompanying consolidated balance sheet and
consolidated statement of capitalization and interim financing of
Central Maine Power Company (a Maine corporation) and subsidiary
as of December 31, 1993, and 1992, and the related consolidated
statements of earnings, changes in common stock investment and
cash flows for each of the three years in the period ended
December 31, 1993. These financial statements are the
responsibility of the Company's management. Our responsibility
is to express an opinion on the financial statements based on our
audits.
We conducted our audits in accordance with generally accepted
auditing standards. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether
the financial statements are free of material misstatement. An
audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An
audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating
the overall financial statement presentation. We believe that
our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to
above present fairly, in all material respects, the financial
position of Central Maine Power Company and subsidiary as of
December 31, 1993, and 1992, and the results of their operations
and their cash flows for each of the three years in the period
ended December 31, 1993, in conformity with generally accepted
accounting principles.
As discussed in Notes 2 and 5 to the consolidated financial
statements, effective January 1, 1993, the Company changed its
methods of accounting for income taxes and other postretirement
benefits.
ARTHUR ANDERSEN & CO.
Boston, Massachusetts
February 4, 1994
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MANAGEMENT REPORT ON RESPONSIBILITY FOR FINANCIAL REPORTING
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 it 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. A staff of internal auditors conducts
comprehensive reviews, provides ongoing assessments of the
effectiveness of selective internal controls, and reports 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.
Arthur Andersen & Co., 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, President and Chief Executive Officer
David E. Marsh, Vice President, Corporate Services, and Chief
Financial Officer
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<PAGE>
CHANGES IN AND DISAGREEMENTS WITH
ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
Change in Independent Accountant
On January 19, 1994, on recommendation of the Company's Audit
Committee, which had requested proposals from major accounting
firms consistent with its policy of periodically reviewing
accounting services, the Board of Directors of the Company
engaged Coopers & Lybrand as the Company's principal accountant
to audit the Company's 1994 financial statements.
During 1991, the Company was considering a change in the
accounting treatment of deferred investment tax credits. After
discussions with the predecessor auditors, Arthur Andersen & Co.,
who disagreed with the proposed accounting, and with the Office
of the Chief Accountant of the Securities and Exchange
Commission, the Company rejected the proposed change.
Arthur Andersen & Co., has agreed in writing with the information
in this section.
The 1991 disagreement cited above was discussed with the Audit
Committee of the Company by Arthur Andersen & Co. The Company
has authorized Arthur Andersen & Co. to respond fully to any
inquiries by Coopers & Lybrand concerning the disagreement.
During the period of the disagreement neither the Company nor
anyone acting on its behalf consulted Coopers & Lybrand regarding
any matter.
-49- <PAGE>
