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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
X ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 1996
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)
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 _x_.
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 $360,772,712 on March 3, 1997
(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 3, 1997).
(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 3, 1997, 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 definitive proxy statement for the Company's 1997 Annual
Meeting of Shareholders are incorporated by reference in Part III hereof.
CENTRAL MAINE POWER COMPANY
INFORMATION REQUIRED IN FORM 10-K
Item Number Page
Part I
Item 1. Business 1
Item 2. Properties 12
Item 3. Legal Proceedings 19
Item 4. Submission of Matters to a Vote of
Security Holders 20
Item 4.1. Executive Officers of the Registrant 21
Part II
Item 5. Market for the Registrant's Common
Equity and Related Stockholder Matters 22
Item 6. Selected Financial Data 22
Item 7. Management's Discussion and Analysis of
Financial Condition and Results of Operations 23
Item 8. Financial Statements and Supplementary Data 42
Item 9. Changes in and Disagreements with Accountants
on Accounting and Financial Disclosure 81
Part III
Item 10. Directors and Executive Officers of the
Registrant 82
Item 11. Executive Compensation 82
Item 12. Security Ownership of Certain Beneficial
Owners and Management 82
Item 13. Certain Relationships and Related Transactions 82
Part IV
Item 14. Exhibits, Financial Statement Schedules,
and Reports on Form 8-K 83
Signatures 85
FORWARD LOOKING INFORMATION
In addition to the historical information contained herein,
this report contains a number of "forward-looking statements", within the
meaning of the Securities and Exchange Act of 1934. Such statements address
future events and conditions concerning capital expenditures, earnings on
assets, resolution and impact of litigation, regulatory matters, liquidity and
capital resources, and accounting matters. Actual results in each case could
differ materially from those projected in such statements, by reason of
factors including, without limitation, electric utility restructuring,
including the ongoing state and federal activities; future economic
conditions; earnings retention and dividend payout policies; developments in
the legislative, regulatory and competitive markets in which the Company
operates; and other circumstances that could affect anticipated revenues and
costs, such as unscheduled maintenance or repair requirements of nuclear and
other facilities and compliance with laws and regulations. Nuclear investments
and obligations, which are subject to increased regulatory scrutiny, and the
amount of the expenditures and the timing of the return of the Maine Yankee
generating plant to service could have a material effect on the Company's
financial position. These and other factors are discussed in the Company's
filings with the Securities and Exchange Commission, including this report.
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
primarily 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. The Company is also diversifying into new lines of business,
largely through its subsidiaries. See "Competition - Expansion of Lines of
Business", below. Its principal executive offices are located at 83 Edison
Drive, Augusta, Maine 04336, where its general telephone number is (207)
623-3521.
The Company is the largest electric utility in Maine, serving
approximately 521,000 customers in its 11,000 square-mile service area in
southern and central Maine and having $967 million in consolidated electric
operating revenues in 1996 (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 943,000 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 62 percent of the Company's industrial sales and
approximately 25 percent of total service-area sales.
Nuclear Plant Outages. In 1996 the Company incurred substantially
higher costs associated with its investments in nuclear generating units,
particularly the 879-megawatt unit owned and operated by Maine Yankee Atomic
Power Company ("Maine Yankee") in Wiscasset, Maine, (the "Maine Yankee Plant"
or the "Plant") and expects even higher costs in 1997 to have a significant
effect on the Company's financial results for 1997. For a complete discussion
of the regulatory and operational problems causing such higher Maine Yankee
costs, see "Maine Yankee Atomic Power Company," below, and Item 7,
"Management's Discussion and Analysis of Financial Condition and Results of
Operations."
1996 Results. The Company generated net earnings of $60.2 million in
1996, compared to net earnings of $38.0 million in 1995. The earnings
applicable to common stock was $50.8 million, or $1.57 per share in 1996,
compared to earnings applicable to common stock of $27.8 million, or $0.86 per
share, in 1995.
Electric operating revenues increased by $51.0 million, or 5.6 percent,
to $967 million in 1996. Total service-area sales increased by 2.9 percent in
1996, with residential sales increasing by 1.0 percent, commercial sales
increasing by 0.5 percent, industrial sales increasing by 4.0 percent, and the
small wholesale and lighting category increasing by 58.9 percent. The primary
factors in the service-area kilowatt-hour sales increase were residential
customers' taking advantage of the Company's water heating program, increased
sales in the pulp and paper industry, and the addition of a wholesale
customer. The decreases in 1995 and 1994 were attributed to low economic
growth, the loss of a major industrial customer in September 1994, energy
management, and loss of sales due to conversions from electricity to
alternative fuels for such purposes as space and water heating.
In order to compete effectively in an increasingly competitive electric
utility industry, the Company is pursuing a strategy based on stabilizing its
price of electricity, in real terms, through the rest of the decade. To
accomplish that goal, the Company in 1996 continued its efforts to control
costs, which became a much greater challenge because of the nuclear plant
outages, reduce its costs of non-utility purchased power, and expand its lines
of business. Significant progress was made in stabilizing rates with the
adoption effective January 1, 1995, of the Alternative Rate Plan (the "ARP"),
which contains inflation-based price caps, additional pricing flexibility, and
efficiency incentives. In addition, as a result of the ARP the Company was
able to enter into five-year reduced-price contracts over the last two years
with a number of its largest customers designed to ensure that those customers
would remain on the Company's system over the five-year period. The Company
has used the pricing flexibility provision in the ARP to provide new rates to
approximately 19,000 customers, representing approximately 40 percent of
annual kilowatt-hour sales and 27 percent of service-area revenues.
The Company is actively supporting electric industry restructuring
efforts now under consideration by the Maine Legislature. This is part of a
national trend to change the electric industry over time into a more
competitive industry. A primary goal of this effort is to provide customers
with greater choices in the terms, conditions and suppliers of their electric
power needs. While many aspects of the transition are uncertain, the
transition to direct retail competition could have substantial impacts on the
value of utility assets and on the ability of electric utilities to recover
their costs through rates. Without effective action by legislators and
regulators, utilities could find their above-market costs to be "stranded," or
unrecoverable, in the new competitive setting. The Company has substantial
exposure to cost stranding relative to its size. See "Competition" and
"Restructuring and Strandable Costs," below, for more information on this
subject.
Maine Yankee, the ARP, restructuring, strandable costs, and other
significant developments are discussed in succeeding sections of this report.
In some cases more complete information is included in Management's Discussion
and Analysis of Financial Condition and Results of Operations, which appears
in Item 7 of this report, or in the Notes to Consolidated Financial Statements
for the year ended December 31, 1996, which appear in Item 8 of this report.
In those cases Item 7 and 8 should be read in conjunction with the sections
below for a full discussion of the subjects covered in that manner.
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 Items 7 and 8.
Topic Page
Regulation and Rates 3
Competition 4
Restructuring and Strandable Costs 5
Non-utility Generation 5
Maine Yankee Atomic Power Company 6
Financing and Related Considerations 7
Environmental Matters
Water Quality Control 9
Air Quality Control 9
Hazardous Waste Regulations 9
Electromagnetic Fields 10
Capital Expenditures 10
Employee Information 10
Regulation and Rates
General. The Company is subject to the regulatory authority of the
Maine Public Utilities Commission (the "MPUC" or 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 to the jurisdiction of the Federal Energy
Regulatory Commission ("FERC") under Parts I, II and III of the Federal Power
Act for some phases of its business, including licensing of its hydroelectric
stations, accounting, rates relating to wholesale sales and to interstate
transmission and sales of energy and certain other matters. 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 the Company's thermal and hydroelectric 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, local and other
federal 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 26 FERC-licensed projects,
some of which include more than one generating unit. Thirteen licenses expired
in 1993, one expires in 1997, and fourteen after 2000. The Company has 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 action on relicensing by the FERC. Of the thirteen projects with
licenses which expired in 1993, ten are operating under annual licenses, one
project is operating under a new license issued in 1993, one license was
allowed to expire, and one project was sold. 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.
Rate Regulation. Effective January 1, 1995, rate regulation for the
Company underwent a fundamental change with the implementation of the ARP,
which replaced traditional regulation. Instead of rate changes based on the
level of costs incurred and capital investments, the ARP provides for one
annual adjustment of an inflation-based cap on each of the Company's rates,
with no separate reconciliation and recovery of fuel and purchased-power
costs. Under the ARP, the MPUC is continuing to regulate the Company's
operations and prices, provide for continued recovery of deferred costs, and
specify a range for its rate of return. The MPUC confirmed in its order
approving the ARP that the ARP is intended to comply with the provisions of
Statement of Financial Accounting Standards No. 71, "Accounting for the
Effects of Certain Types of Regulation." See Note 3 of Consolidated Financial
Statements for more information on the ARP.
Competition
General. In 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, enhanced
access to electric transmission to promote competition for wholesale
purchasers and sellers. The Policy Act has combined with regulatory
development to create new areas of competition for the Company, resulting in
more options for its wholesale and retail customers. Even though the Company's
customers are at present generally unable to seek direct service from another
utility, some can curtail usage, switch fuels, install their own generation,
cancel plans to expand their operations, or even leave the Company's service
territory. In response to those threats, the Company has initiated several
programs, including the implementation of special rates to maintain or
increase employment at specific large customers' plants and incremental-energy
rates to avoid losing specific groups of customers to other energy sources. In
addition, the Company has redesigned some rates to encourage off-peak usage
and discourage switching to alternative fuels. See Item 7, "Management's
Discussion and Analysis of Financial Condition and Results of Operations," and
Notes 3 and 4 to Consolidated Financial Statements for more information.
Expansion of Lines of Business. The Company is also preparing for competition
by expanding its business opportunities through subsidiaries that capitalize
on core competencies. One such subsidiary, MaineCom Services ("MaineCom") is
developing opportunities in expanding markets by arranging fiber-optic data
service for bulk carriers, offering support for cable-TV or "super-cellular"
personal-communication vendors, and providing other telecommunications
services. The Company invested $10.7 million in MaineCom during 1996 to
develop an interchange network from Portland, Maine, to various points in New
Hampshire, Massachusetts and Connecticut. In addition, the Company has
subsidiaries or divisions that provide energy-efficiency services, utility
consulting (domestic and international) and research, engineering and
environmental services, management of rivers and recreational facilities,
locating of underground utility facilities and infrared photography, real
estate brokerage and management, modular housing, and credit and collection
services. All subsidiaries utilize skills of former Company employees and
compete for business with other companies.
In July 1996, the Company and Maine Electric Power Company, Inc.
(MEPCO), a 78 percent-owned subsidiary of the Company, entered into option
agreements with Maritimes and Northeast Pipeline, L.L.C. (M&N) in which the
Company and MEPCO agreed to provide exclusive options to M&N to acquire
property interests in certain transmission line rights of way to sections of
M&N's proposed natural gas pipeline from the United States-Canada border at
Woodland, Maine, to Dracut, Massachusetts. In November 1996, while the parties
were still engaged in negotiating the terms of the proposed long-term
arrangement, the options expired by their terms. Subsequent to the expiration
the parties have met to discuss a long-term arrangement for use of the
Company's and MEPCO's rights of way for the proposed pipeline, but the Company
cannot predict whether final agreement on such an arrangement will be reached.
Restructuring and Strandable Costs
The enactment by Congress of the Policy Act accelerated planning by
electric utilities, including the Company, for a transition to a more
competitive industry. The functional areas in which competition will take
place, the regulatory changes that will be implemented, and the resulting
structure of both the industry and the Company are still uncertain, but
regulatory, and in some states, legislative steps have already been taken
toward competition in generation and non-discriminatory transmission access. A
departure from traditional regulation could have substantial impacts on the
value of utility assets and on the ability of electric utilities to recover
their costs through rates. In the absence of full recovery, utilities would
find their above-market costs to be "stranded," or unrecoverable, in the new
competitive setting. The Company is pursuing efforts to mitigate its exposure
to stranded costs through securitization of regulatory assets. For further
discussion of this issue, see Item 7, "Management's Discussion and Analysis of
Financial Condition and Results of Operations."
Non-utility Generation
After enactment of the federal Public Utility Regulatory Policies Act of
1978 ("PURPA") and companion legislation in Maine, the Company became an
industry leader in developing supplies of energy from non-utility generators
("NUGs"), including cogeneration plants and small power producers. These
sources supplied 3.8 billion kilowatt-hours of electricity to the Company in
1996, representing 32 percent of total generation, a decrease from 37 percent
in 1995 when Maine Yankee was out of service for most of the year. The
Company's contracts with non-utility generators, however, which were entered
into pursuant to the mandates of PURPA and vigorous state implementation of
its policies, have contributed the largest part of the Company's increased
costs and the resulting rate increases in recent years prior to implementation
of the ARP in 1995, and constitute the largest part of the Company's
strandable costs.
PURPA provided substantial economic incentives to NUGs by allowing
cogenerators and small power producers to sell their entire electrical output
to an electric utility at the utility's avoided-cost rate, which has often
been substantially higher than market rates, while purchasing their own
electric energy requirements at the utility's established rate for that
customer class. Thus the Company in a number of cases has been required to pay
a higher price for energy purchased from a NUG than the NUG, which in some
cases is a large customer of the Company, has paid the Company for the NUG's
energy requirements. In addition, with the recent surplus of relatively
low-cost power in the New England market, prices paid by the Company under NUG
contracts have often been well above current wholesale market prices.
The Company's NUG contracts generally have had terms of five to 30
years, and expiration dates ranging from 1997 to 2021. They require the
Company to purchase the energy at specified prices per kilowatt-hour. As of
December 31, 1996, facilities having 573 megawatts of capacity covered by
these contracts were in service. The costs of purchases under all of these
contracts amounted to $313.4 million in 1996, $314.4 million in 1995, and
$373.5 million in 1994.
Because of the upward price pressure resulting in large part from costs
associated with its NUG contracts, the Company has taken steps to reduce those
costs. In recent years the Company has reached agreement with a number of NUGs
to buy out their contracts or to give the Company options to restructure their
contracts through lump-sum or periodic payments. The Company restructured 40
contracts representing 316 megawatts of capacity that the Company believes
should result in approximately $301 million in fuel savings over the next five
years.
Pursuant to one NUG contract buy-out, Aroostook Valley Electric Company
("AVEC"), a wholly-owned subsidiary of the Company, acquired a 33-megawatt
wood-fired generating plant in Fort Fairfield, in northern Maine. AVEC reduced
the operating costs of the plant and, after competitive bidding, was awarded a
12.5-megawatt contract to supply the Town of Houlton municipal electric
utility, which is outside the Company's retail service territory, at wholesale
for ten years starting January 1, 1996.
In accordance with prior MPUC policy and the ARP, $113 million of buyout
or restructuring costs since January 1992 has been included in Deferred
Charges and Other Assets on the Company's balance sheet and will be amortized
over their respective fuel savings periods. The Company will continue to seek
opportunities to reduce its NUG costs, but cannot predict what level of
additional savings it will be able to achieve. In October 1997 a contract
with a major NUG supplier will expire, which should result in annual savings
of approximately $25 million for the Company.
Maine Yankee Atomic Power Company
The Company owns a 38 percent stock interest in Maine Yankee, which owns
and operates the Maine Yankee Plant and is entitled under a cost-based power
contract to an approximately equal percentage of the Plant's output. The Plant
has been in commercial operation since 1972 and, through 1994, generally
produced power at a cost among the lowest in the country for nuclear plants.
The Maine Yankee Plant was shut down for eleven months in 1995 for
repairs to its steam generator tubes. The Plant returned to service in January
1996 at 90 percent of its operating capacity. On December 6, 1996, the plant
was shut down for inspection and repairs, and is expected to remain out of
service at least until August 1997. During this time, Maine Yankee must
replace 92 fuel assemblies, conduct an intensive inspection of its steam
generators, resolve cable-separation issues and other regulatory issues, as
well as any additional issues that are discovered during the outage, and
obtain the approval of the NRC to restart the plant. In addition, Maine Yankee
will make use of the outage to inspect the Plant's steam generators,
commencing approximately April 1, 1997, for deterioration beyond that which
was repaired during the extended 1995 outage. Degradation of steam generators
of the age and design of those in use in the Plant has been identified at
other plants. If major repairs to, or replacement of, the steam generators
were found to be necessary for continued operation of the Plant, Maine Yankee
would review the economics of continued operation before incurring the
substantial capital expenditures that would be required.
On January 29, 1997, the NRC announced that it had placed the Plant on
its "watch list" in "Category 2", which includes plants that display
"weaknesses that warrant increased NRC attention", but which are not severe
enough to warrant a shut-down order. Plants in category 2 remain in that
category "until the licensee demonstrates a period of improved performance."
The Plant is one of fourteen nuclear units on the watch list announced that
day by the NRC, which regulates over 100 civilian nuclear power plants in the
United States.
On February 13, 1997, Maine Yankee and Entergy Nuclear, Inc. (Entergy),
which is a subsidiary of Entergy Corporation, a Louisiana-based utility
holding company and leading nuclear plant operator, entered into a contract
under which Entergy is providing management services to Maine Yankee. At the
same time, officials from Entergy assumed management positions, including
President, at Maine Yankee.
The Company will incur significantly higher costs in 1997 for its share
of inspection, repairs and refueling costs at Maine Yankee and will also need
to purchase replacement power while the Plant is out of service. While the
amount of higher costs is uncertain, Maine Yankee has indicated that it
expects it operations and maintenance costs to increase by up to approximately
$45 million in 1997, before refueling costs. The Company's share of such costs
based on its power entitlement of approximately 38 percent would be up to
approximately $17 million. In addition, the Company estimates its share of the
refueling costs will amount to approximately $15 million, of which $10.4
million has been accrued as of December 31, 1996. The Company has been
incurring incremental replacement-power costs of approximately $1 million per
week while the plant has been out of service and expects such costs to
continue at approximately the same rate until the plant returns to service.
The impact of these higher nuclear related costs on the Company will be
a major obstacle to achieving satisfactory results in 1997, despite prudent
control of other operating costs, and is likely to trigger the low earnings
bandwidth provision of the ARP. Under the ARP, actual earnings for 1997
outside a bandwidth of 350 basis points, above or below a 10.68 percent rate
of return allowance, triggers the profit sharing mechanism. A return below
the low end of the range provides for additional revenue through rates equal
to one-half of the difference between the actual earned rate of return and the
7.18 percent (10.68 - 3.50) low end of the bandwidth. While the Company
believes that the profit sharing mechanism is likely to be triggered in 1997,
it cannot predict the amount, if any, of additional revenues that may
ultimately result.
Higher nuclear-related costs are affecting other stockholders of
Maine Yankee in varying degrees. Bangor Hydro-Electric Company, a Maine-based
7-percent stockholder, has cited its "deteriorating" financial condition and
on March 19, 1997, eliminated its common-stock dividend for the quarter. Maine
Public Service Company, a 5-percent stockholder, cited problems in satisfying
financial covenants in loan documents and reduced its common-stock dividend
substantially in early March 1997. Northeast Utilities (20-percent stock
ownership through three subsidiaries), which is also adversely affected by the
substantial additional costs associated with the three shut-down Millstone
nuclear units and the permanently shut-down Connecticut Yankee unit, as well
as an unfavorable utility deregulation plan in New Hampshire currently under
appeal, announced on March 24, 1997, that its management was planning to
recommend a suspension of its second-quarter common-stock dividend to its
board of trustees. A default by a Maine Yankee stockholder in making payments
under its power contract or capital funds agreement could have a material
adverse effect on Maine Yankee, depending on the magnitude of the default, and
would constitute a default under Maine Yankee's bond indenture and its two
major credit agreements unless cured within applicable grace periods by the
defaulting stockholder or other stockholders. The Company cannot predict,
however, what effect, if any, the financial difficulties being experienced by
some Maine Yankee stockholders will have on Maine Yankee or the Company.
For a detailed discussion of the current Maine Yankee regulatory and
operational issues, see Item 7 - "Management's Discussion and Analysis of
Financial Condition and Results of Operations" - "Maine Yankee Regulatory
Issues."
Financing and Related Considerations
1996 Financing Activity. During 1996 the Company issued $10 million of
notes under its $150-million Medium-Term Note program at variable interest
rates and an average life of five years. Notes in the amount of $34 million
matured during the year, reducing the total of outstanding Medium-Term Notes
at the end of 1996 to $68 million from $92 million at the end of 1995.
The Company's Articles of Incorporation limit the amount of unsecured
indebtedness the Company may incur without the consent of the holders of the
Company's preferred stock to 20 percent of the Company's total
capitalization. At the end of 1996, 20 percent of such capitalization
amounted to $219 million. In 1989 holders of the Company's preferred stock
consented to the issuance of unsecured Medium-Term Notes in an aggregate
principal amount of up to $150 million outstanding at any one time, so such
notes up to that amount are not included in the 20-percent limitation. The
Company is proceeding with plans to seek the consent of the holders of its
preferred stock to an additional $350 million of Medium-Term Notes, to $500
million outstanding at any one time, at its annual meeting of stockholders on
May 15, 1997, in order to increase its financing flexibility in anticipation
of industry restructuring and increased competition. The Company cannot
predict whether such consent will be obtained.
On October 23, 1996, the Company entered into a $125-million revolving
credit facility with several banks, with The First National Bank of Boston and
The Bank of New York as agents for the lenders, and terminated its 1986 and
1994 bank facilities. The new facility consists of two tranches, one a
364-day revolving-credit arrangement that matures on October 22, 1997, and the
other a three-year revolving-credit arrangement that matures on October 23,
1999. At December 31, 1996, the Company had $7.5 million in outstanding loans
under the new facility.
Securities Ratings. On September 25, 1996, Duff & Phelps Credit Rating
Co. ("D&P") placed the ratings of the Company's debt and preferred stock on
"Rating Watch--Down." D&P stated that its action was due to uncertainty
surrounding the Nuclear Regulatory Commission's investigations into the Maine
Yankee, Connecticut Yankee and Millstone Unit No. 3 nuclear facilities, in
which the Company has ownership interests." The rating agency recognized
"positive strides" taken by the Company over the past few years in dealing with
several challenges, but found that the Company's "troubled nuclear facilities
situation casts a shadow on the Company's prospects for financial
strengthening." On December 18, 1996, Moody's Investors Service ("Moody's")
placed the Company's credit ratings under review for possible downgrade, due
largely to the effect of its Maine Yankee-related costs. The current ratings
assigned the Company's securities by the three major securities-rating
agencies, Standard & Poor's Corp. ("S&P"), Moody's Investors Service and Duff
& Phelps Credit Rating Co., are shown below:
Mortgage Unsecured Commercial Preferred
Bonds Notes Paper Stock
S&P BB+ BB B B+
Moody's Baa2 Baa3 P2 Baa3
D&P BBB- BB+ D3 BB
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 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 substantial 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, state regulations restrict the sulfur content and other
characteristics of the fuel oil burned at the Company's William F. Wyman
Station in Yarmouth, Maine. The Company believes that it will continue to be
able to obtain a sufficient supply of oil with the required specifications,
subject to unforeseen events and the factors influencing the availability of
oil discussed under Item 2, Properties, "Fuel Supply", below.
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.
For a discussion of a continuing 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 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 1992 through
1996 totaled approximately $21.3 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, 1996, the Company had 1,655 full-time employees, of
whom approximately 44 percent were 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 1996 was due largely to the
implementation of an early-retirement program and other efficiency measures in
1991 and 1992, further staff reductions in the first quarter of 1994 in
connection with the Company's restructuring and cost-reduction program and
another early-retirement program in mid-1995.
In April 1995 the Company and the union agreed to a three-year labor
contract extension that provided for an annual wage increase of 2 percent on
May 1, 1995, 2 percent on May 1, 1996, and a reopening of wage negotiations
for the year commencing May 1, 1997. The wage negotiations are scheduled to
start in early April 1997.
Item 2. PROPERTIES.
Existing Facilities
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, 1996, the Company had
approximately 2,293 circuit-miles of overhead transmission lines, 19,254
pole-miles of overhead distribution lines and 1,330 miles of underground and
submarine cable. The maximum one-hour firm system net peak load experienced by
the Company during the winter of 1996 was approximately 1,301 megawatts on
January 3, 1996. At the time of the peak, the Company's net capability was
1,893 megawatts.
The Company operates 30 hydroelectric generating stations, of which 29
are owned by the Company, with an estimated net capability of 369 megawatts,
and it purchases an additional 74 megawatts of non-utility hydroelectric
generation in Maine. The Company also operates one oil-fired steam-electric
generating station, William F. Wyman Station in Yarmouth, Maine. The Company's
share of William F. Wyman Station has an estimated net capability of 593
megawatts. The oil-fired station is located on tidewater, permitting
waterborne delivery of fuel. The Company also has internal combustion
generating facilities with an estimated aggregate net capability of 38
megawatts.
The Company has ownership interests in five nuclear generating plants in
New England. The largest is a 38-percent interest in the Maine Yankee plant in
Wiscasset, Maine. In addition, the Company owns a 9.5 percent interest in
Yankee Atomic Electric Company ("Yankee Atomic"), discussed below, which has
permanently shut down its plant located in Rowe, Massachusetts, a 6 percent
interest in Connecticut Yankee Atomic Power Company ("Connecticut Yankee"),
discussed below, which has permanently shut down its plant in Haddam,
Connecticut, and a 4 percent interest in Vermont Yankee Nuclear Power
Corporation ("Vermont Yankee"), which owns an operating plant 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, which has been off-line for regulatory reasons
since March 31, 1996.
In December 1996, the Board of Directors of Connecticut Yankee Atomic
Power Company voted to permanently shut down the Connecticut Yankee plant for
economic reasons, and to decommission the plant. An economic analysis
conducted by Connecticut Yankee estimated that the early closing of the plant
would save over $100 million (net present value) over its remaining license
life to the year 2007, compared with the costs of continued operation. The
Company's 6-percent equity interest totaled approximately $6.4 million at
December 31, 1996. The plant did not operate after July 22, 1996. The
Company estimates its share of the cost of Connecticut Yankee's continued
compliance with regulatory requirements, recovery of its plant investments,
decommissioning and closing the plant to be approximately $45.8 million and
has recorded a regulatory asset and a liability on the consolidated balance
sheet. The Company is currently recovering through rates an amount adequate
to recover these expenses.
In 1993 the FERC approved a settlement agreement regarding the
decommissioning plan, recovery of plant investment, and all issues with
respect to the prudence of the decision to discontinue operation of the Yankee
Atomic plant. The Company estimates its remaining share of the cost of Yankee
Atomic's continued compliance with regulatory requirements, recovery of its
plant investments, decommissioning and closing the plant, to be approximately
$16.5 million. This estimate, which is subject to ongoing review and revision,
has been recorded by the Company as a regulatory asset and a liability on the
Company's balance sheet. As part of the MPUC's decision in the Company's 1993
base-rate case, the Company's current share of costs related to the
deactivation of Yankee Atomic is being recovered through rates.
The Company's share of the capacity of the three operating nuclear
generating plants, as of December 31, 1996, amounted to the following:
Maine Yankee 329 MW
Vermont Yankee 19 MW
Millstone 3 29 MW
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 an interconnection agreement. MEPCO transmits
power between NB Power and various New England utilities under separate
agreements.
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 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 $28.8 million, its
share of the construction cost for the transmission facilities incurred
through December 31, 1996.
Maine Yankee Decommissioning. Effective in 1988 Maine Yankee began
collecting $9.1 million annually for decommissioning the Maine Yankee plant,
based on a FERC-approved funding level of $167 million. In 1994, Maine Yankee,
pursuant to FERC authorization, increased its annual collection to $14.9
million and reduced its return on common equity to 10.65 percent, for a total
increase in rates of approximately $3.4 million. The increase in
decommissioning collection was 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. The market value of Maine Yankee's accumulated decommissioning
funds was $163.5 million (including actual interest earned) as of December 31,
1996.
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. Maine did not satisfy its milestone
obligation under the Waste Act requiring submission of a site license
application by the end of 1991, and therefore became subject to surcharges on
its waste and did not have access to regulated disposal facilities after the
end of 1992. Maine Yankee then began storing all low-level waste generated at
an on-site storage facility. On July 1, 1995, however, the State of South
Carolina restored access to its facility and Maine Yankee began to ship
low-level waste to the South Carolina facility for disposal.
The states of Maine, Texas and Vermont have been pursuing the
implementation of a compact for the disposal of low-level waste at a site in
Texas. The ratification bill for the compact is before Congress for
consideration at its 1997 session. 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 the Company 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. The
Maine Low-Level Radioactive Waste Authority suspended its search for a
suitable disposal site in Maine and, as of June 30, 1994, ceased operations.
In the event the required ratification by Congress is not obtained,
subject to continued NRC approval, Maine Yankee has said it will ship
low-level waste offsite for disposal in South Carolina or other available
sites as long as such sites are available, reserving its capacity to store
approximately ten to twelve years' production of low-level waste at its
facility at the Plant site. 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
current licensed operating life of the Plant.
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 as well as dispose of low-level waste at the South
Carolina site or other available sites 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 $79.3 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 unit, the
Company's retrospective premium could be as high as $6 million in any year,
for a cumulative total of $47.6 million, exclusive of the effect of inflation
indexing and a 5-percent surcharge in the event that total public liability
claims from a nuclear incident should exceed the funds available to pay such
claims.
In addition to the insurance required by the 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 insurance
company through a combination of current premiums and retrospective premium
adjustments. Based on current premiums and the Company's indirect and direct
ownership in nuclear generating facilities, this adjustment could range up to
approximately $7.7 million annually.
For a discussion of issues relating to Maine Yankee's spent nuclear fuel
disposal, see "Fuel Supply" - "Nuclear", below.
Construction Program
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 1996 capital investment outlays, including
deferred demand-side management expenditures, to minimum levels. During the
five-year period ended December 31, 1996, the Company's construction and
acquisition expenditures amounted to $264.8 million (including investment in
jointly-owned projects and excluding MEPCO). The program is currently
estimated at approximately $56 million for 1997 and $246 million for 1998
through 2001.
The following table sets forth the Company's estimated capital
expenditures as discussed above:
1998-
1997 2001 Total
Type of Facilities (Dollars in Millions)
Generating Projects $ 8 $ 33 $ 41
Transmission 3 14 17
Distribution 27 124 151
General facilities and Other 18 75 93
Total $56 246 $302
Demand-side Management
The Company's demand-side-management initiatives 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.
Actual demand-side management 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 the New England Power Pool (NEPOOL), which is
open to all investor-owned, municipal and cooperative electric utilities in
New England under a 1971 agreement 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.
On April 24, 1996, the Federal Energy Regulatory Commission (FERC)
issued Order No. 888, which requires all public utilities that own, control or
operate facilities used for transmitting electric energy in interstate
commerce to file open access non-discriminatory transmission tariffs that
offer both load-based, network and contract-based, point-to-point service,
including ancillary service to eligible customers containing minimum terms and
conditions of non-discriminatory service. This service must be comparable to
the service they provide themselves at the wholesale level; in fact, these
utilities must take wholesale transmission service they provide themselves
under the filed tariffs. The order also permits public utilities and
transmitting utilities the opportunity to recover legitimate, prudent and
verifiable wholesale stranded costs associated with providing open access and
certain other transmission services. It further requires public utilities to
functionally separate transmission from generation marketing functions and
communications. The intent of this order is to promote the transition of the
electric utility industry to open competition. Order No. 888 also clarifies
federal and state jurisdiction over transmission in interstate commerce and
local distribution and provides for deference of certain issues to state
recommendations.
On July 9, 1996, the Company and MEPCO submitted compliance filings to
meet the new pro forma tariff non-price minimum terms and conditions of
non-discriminatory transmission. Since July 9, 1996, the Company and MEPCO
have been transmitting energy pursuant to their filed tariffs, subject to
refund. FERC subsequently issued Order No. 888-A which generally reaffirms
Order No. 888 and clarifies certain terms.
Also on April 24, 1996, FERC issued Order No. 889 which requires public
utilities to functionally separate their wholesale power marketing and
transmission operation functions and to obtain information about their
transmission system for their own wholesale power transactions in the same way
their competitors do through the Open Access Same-time Information System
(OASIS). The rule also prescribed standards of conduct and protocols for
obtaining the information. The standards of conduct are designed to prevent
employees of a public utility engaged in marketing functions from obtaining
preferential information. The Company participated in efforts to develop a
regional OASIS, which was operational January 3, 1997. FERC subsequently
approved a New England Power Pool-wide Open Access Tariff, subject to refund
and issuance of further orders. The Company also participated in revising the
New England Power Pool Agreement to comply with the new regulatory
requirements. The revised agreement is pending FERC approval.
Fuel Supply
The Company's total kilowatt-hour production by energy source for each
of the last two years and as estimated for 1997 (consistent with the actual
mix for January 1997 with Maine Yankee off-line) is shown below. The 1997
estimate could change when, and if, Maine Yankee resumes operation.
Actual Estimated
Source 1996 1995 1997
Nuclear 19% 7% 2%
Hydro 17 15 17
Oil 16 21 29
Non-utility 32 37 38
Other purchases 16 20 14
100% 100% 100%
The 1997 estimated kilowatt-hour output from oil and purchased power may
vary depending upon the relative costs of Company-generated power and power
purchased through independent producers and other sources.
Oil. The Company's William F. Wyman Station in Yarmouth, Maine, and its
internal combustion electric generating units are oil-fired. The Company's
last contract for the supply of fuel oil requirements at market prices was
allowed to expire in 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 1992 was $14.02, $13.12, $12.93,
$16.16 and $18.18, 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 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 was given
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 $63.8
million of interest cost for the period April 7, 1983, through December 31,
1996.
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 $1.8 million through December 1997. Deposits are expected to
total approximately $73.2 million, with the total liability, including
interest due at the time of disposal, estimated to be approximately $126.5
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 in March 1994 the NRC granted its authorization.
Installation of the new racks began in 1996 and is expected to be completed
during 1997. 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.
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
provided for the possible development of a Monitored Retrievable Storage
("MRS") facility and abandoned 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.
In 1994 several nuclear utilities sought a declaration from the United
States Court of Appeals for the District of Columbia that existing federal
legislation required the DOE to take responsibility for spent nuclear fuel in
1998. On July 23, 1996, the court held that the DOE is obligated "to start
disposing of [spent nuclear fuel] no later than January 31, 1998," and in
October 1996 the DOE said it would not appeal the decision. The Company
cannot predict when or how the DOE will meet its responsibility.
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.
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
Environmental Protection Agency (EPA) as containing soil contaminated by
polychlorinated biphenyls (PCBs) from equipment originally owned by the
Company.
In July 1994, the EPA approved changes to the remedy it had previously
selected, the principal change being to adjust the soil cleanup standard to 10
parts per million from the standard of one part per million established in the
EPA's 1989 Record of Decision, on the part of the site where PCBs were found
in their highest concentration. The EPA stated that the purpose of adjusting
the standard of cleanup was to accommodate the selected technology's current
inability to reduce PCBs and other chemical components on the site to the
original standard.
In June 1995, after discussions between the Company and the EPA, design
work on the selected remedy was suspended. On July 7, 1995, the Company
formally requested that the EPA abandon that remedy for an already-designated
alternative remedy that the Company believes could result in substantially
lower costs. On October 10, 1995, the EPA approved the new remedy after
determining that the old remedy was no longer feasible or cost-effective at
the site. The new remedy involves transporting the contaminated soil to a
secure off-site landfill.
The Company believes that its share of the remaining costs of the
cleanup under the new method could total approximately $2.7 million to $4.2
million. This estimate is net of an agreed partial insurance recovery and the
1993 court-ordered contribution of 41 percent from Westinghouse Electric
Corp., but does not reflect any possible contributions from other insurance
carriers the Company has sued, or from any other parties. The Company has
recorded an estimated liability of $2.7 million and an equal regulatory asset,
reflecting an accounting order to defer such costs and the anticipated
ratemaking recovery of such costs when ultimately paid. In addition, the
Company has deferred as a regulatory asset $5.1 million of costs incurred
through December 31, 1996.
The Company cannot predict with certainty the level and timing of the
cleanup costs, the extent they will be covered by insurance, or 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.
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.
Name, Age, and Year
First Became Officer Office
David M. Jagger, 55, 1996 Chairman of the Board of Directors
Charles H. Abbott, 61, 1996 Vice Chairman of the Board of Directors
David T. Flanagan, 49, 1984 President and Chief Executive Officer,
and Director
Arthur W. Adelberg, 45, 1985 Vice President, Law and Power Supply
Richard A. Crabtree, 50, 1978 Vice President, Retail Operations
David E. Marsh, 49, 1986 Vice President, Corporate Services,
Treasurer and Chief Financial Officer
Curtis A. Mildner, 43, 1994 Vice President, Marketing
Gerald C. Poulin, 55, 1984 Vice President, Generation and
Technical Support
Anne M. Pare, 43, 1996 Secretary and Clerk
Each of the executive officers has for the past five years been
an officer or employee of the Company except Messrs. Jagger and Abbott, who
have been non-employee directors since 1988, and Mr. Mildner. Mr. 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.
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 December 31, 1996, there were 40,413 holders of record of the Company's
common stock.
Price Range of and Dividends on Common Stock
Market Price Dividends
High Low Declared
1996
First Quarter $16 1/4 $13 1/4 $0.225
Second Quarter 14 1/2 12 1/4 0.225
Third Quarter 13 7/8 11 5/8 0.225
Fourth Quarter 12 3/8 11 0.225
1995
First Quarter $14 1/8 $10 3/4 $0.225
Second Quarter 12 5/8 10 1/4 0.225
Third Quarter 13 1/2 11 0.225
Fourth Quarter 15 1/8 13 0.225
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, 1996, the Company's retained earnings were $72.5 million, of which $42.9
million 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, 1992 through 1996. This
information should be read in conjunction with "Management's Discussion and
Analysis of Financial Condition and Results of Operations" and the
consolidated financial statements and related notes thereto included in Items
7 and 8 hereof. The selected consolidated financial data for the years ended
December 31, 1992 through 1996 are derived from the audited consolidated
financial statements of the Company.
Selected Consolidated Financial Data
(Dollars in Thousands, Except Per Share Amounts)
1996 1995 1994 1993 1992
Electric operating revenue $ 967,046 $ 916,016 $ 904,883 $ 893,577 $ 877,695
Net income (loss) 60,229 37,980 (23,265) 61,302 63,583
Long-term obligations 587,987 622,251 638,841 581,844 499,029
Redeemable preferred stock 53,528 67,528 80,000 80,000 40,750
Total assets 2,010,914 1,992,919 2,046,007 2,004,862 1,690,005
Earnings (loss) per common share
$1.57 $0.86 $(1.04) $ 1.65 $1.85
Dividends declared per common share
$0.90 $0.90 $0.90 $1.395 $1.56
Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS.
Overview
In 1996, the Company experienced higher than normal costs associated with its
investments in nuclear generating units, particularly the Maine Yankee nuclear
plant, and incurred replacement-power costs due to unplanned nuclear-plant
outages.
While the return to service of the Maine Yankee nuclear plant in mid-January
1996 ended an 11-month consecutive outage, the plant's operating capacity was
limited to 90% of its maximum production capacity during periods of operation
in 1996 and unscheduled outages reduced the availability of the plant to less
than 10 months of operation. The additional costs incurred by the Company
under its power contract with Maine Yankee were approximately $3.6 million.
Replacement-power costs associated with the reduced level of output and
limited availability of the plant amounted to approximately $13.5 million for
a total of $17.1 million or an earnings reduction of $0.31 per share, after
tax, during 1996.
The Company's 1996 financial results benefited by approximately $15.3 million,
after tax, or $0.47 per share, as a result of non-recurring items related to a
favorable resolution of federal income-tax issues with the Internal Revenue
Service, a reduction in purchased power costs associated with an extended
outage at a non-utility generator (NUG) under contracts to the Company, an
energy-swap agreement with another utility that reduced purchased-power costs,
and the affirmation of the rate recovery of a regulatory asset.
Earnings per share in 1996 were $1.57, after recognizing the higher
nuclear-related costs and benefits of non-recurring events, compared to $0.86
per share in 1995. The 1995 earnings per share included the recognition of
$0.70 per share in Maine Yankee-related repair and replacement-power costs.
The Maine Yankee nuclear plant was shut down on December 6, 1996, for
inspection and repairs. Maine Yankee has notified the Company that, due to the
need to replace 92 fuel assemblies, it will refuel the plant during the
current outage. While the plant is out of service, Maine Yankee must, in
addition to replacing the fuel assemblies, conduct an intensive inspection of
its steam generators, resolve cable-separation and other regulatory issues,
and obtain NRC approval to restart the plant. The Company believes the plant
will be out of service at least until August 1997, but cannot predict when or
whether all of the regulatory and operational issues will be satisfactorily
resolved, or what effect the repairs and improvements to the plant will have
on its operating economics.
The Company will incur significantly higher costs in 1997 for its share of
inspection, repairs and refueling costs at Maine Yankee, and will also need to
purchase replacement power while the plant is out of service. While the amount
of higher costs is uncertain, Maine Yankee has indicated that it expects its
operations-and-maintenance costs to increase by up to approximately $45
million in 1997, before refueling costs. The Company's share of such costs,
based on its power entitlement of approximately 38%, would be up to
approximately $17 million. In addition, the Company estimates its share of the
refueling costs will amount to approximately $15 million; $10.4 million has
been accrued as of December 31, 1996. The Company has been incurring
incremental replacement-power costs of approximately $1 million per week while
the plant has been out of service and expects such costs to continue at
approximately the same rate until the plant returns to service.
The impact of these higher nuclear-related costs on the Company's 1997
financial results will be significant and is likely to trigger a low earnings
bandwidth provision of the Alternative Rate Plan (ARP). Under the ARP, actual
earnings for 1997 outside a bandwidth of 350 basis points, above or below the
10.68% rate of return allowance, triggers the profit sharing mechanism. A
return below the low end of the range provides for additional revenue through
rates equal to one-half of the difference between the actual earned rate of
return and the 7.18% (10.68 - 3.50) low end of the bandwidth. While the
Company believes the profit-sharing mechanism is likely to be triggered in
1997, it cannot predict the amount, if any, of additional revenues that may
ultimately result.
The ARP was structured to permit reasonable assurance of continued recovery of
the cost of services, including past deferrals, provide a higher degree of
price stability and predictability, and reduce regulatory costs while
providing financial incentives for improved efficiencies and protection
against significant unforeseen events.
The Company declared dividends totaling $0.90 per share in 1996, unchanged
from 1995 and 1994 levels. Dividend and capital structure policy will continue
to be reviewed by management and the Board of Directors and will take into
consideration such issues as sustainable long-term earnings, capital needs,
business opportunities and business risk, the structure of the Company and the
industry, and the overall need to assure that financial risk and business risk
are aligned. In the near term, the Company anticipates significant downward
pressure on its earnings capacity as a result of the higher cost and outages
of the Maine Yankee and Millstone Unit No. 3 nuclear facilities. The capacity
of the Company to attain earnings levels that support the current dividend are
closely related to the performance and cost associated with the Company's
Maine Yankee investment and power entitlement.
Sustained nuclear-unit outages combined with higher nuclear operating costs in
1997 will be a major obstacle to achieving satisfactory results in 1997
despite prudent control of other operating costs. On a prospective basis, a
contract with a major NUG representing 62.5 MW of capacity expires on October
31, 1997. Net annual savings due to the contract expiration would be
approximately $25 million, with 1997 savings amounting to approximately $4
million.
The Company continues to face the challenges of competition and industry
restructuring, and must achieve and maintain financial performance and
resources commensurate with both the provision of service demanded by
customers and the obligation to achieve competitive returns on investor
capital.
The Company is aggressively addressing the challenges of restructuring, the
pressure from competitive energy sources, customers' desire for choices and
enhanced service, and nuclear-plant outages in 1997. The following long-term
financial objectives are key to sustainable future earnings and growth and
will be a major focus of our 1997 activities:
1. Continue increasing the efficiency of operations: cost management under
price-cap regulation must replace the cost-plus culture encouraged by
traditional regulation.
2. Focus on volume of sales as a revenue builder.
3. Align financial policies to changing business needs and risks; competition
tends to increase business risk, which impacts the desired level of
fixed-charge obligations.
4. Expand areas of investment for growth; open competition in electric energy
could significantly reduce traditional sales-growth opportunities.
5. Recover the substantial investments made and costs being incurred for
existing service obligations; open competition could strand these costs,
absent a transition mechanism for recovery.
Earnings and Dividends
For 1996, the Company generated net income of $60.2 million, compared to $38.0
million in 1995, and a net loss of $23.3 million in 1994. Earnings applicable
to common stock were $50.8 million in 1996 or $1.57 per share, compared to
$27.8 million or $0.86 per share in 1995. In 1994, the loss applicable to
common stock was $33.8 million or $1.04 per share. The Company benefited from
higher sales, cost management initiatives, surplus power sales and certain
non-recurring events during the year as discussed below. In addition, net
income in 1996 reflects replacement power costs for unscheduled nuclear unit
outages of approximately $18.5 million. Increased nuclear operations,
maintenance and study costs to comply with NRC safety actions amounted to
approximately $4.3 million in 1996. See "Maine Yankee Regulatory Issues" and
"Other Nuclear Issues" for more information.
Certain favorable one-time events took place in 1996. Due to a flood in the
fall of 1996, a non-utility generator was temporarily forced out of service
for an extended period. This enabled the Company to purchase replacement
power at a lower cost for a savings of approximately $5.4 million. An
energy-swap agreement signed in 1994 with Northeast Utilities allowed the
Company to save approximately $6 million in purchased power costs. A
settlement with the Internal Revenue Service on audits for the years 1988-1991
provided a decrease to income tax expense of approximately $4.8 million. The
1996 Maine Public Utilities Commission's (MPUC) Alternative Rate Plan (ARP)
decision provided the Company recovery in rates for its workers' compensation
regulatory asset of $6.4 million, which resulted in the reversal of a 1995
charge due to uncertainty about recovery in rates.
Net income in 1995 reflects $29 million of replacement purchased-power energy
expense and $10 million for the Company's share of sleeving repair costs
during the extended shutdown at Maine Yankee. These two items reduced earnings
applicable to common stock by $22.9 million after income taxes, or $0.70 per
share. The loss in 1994 reflects the write-off of approximately $100 million
($60 million after taxes) of deferred balances in accordance with the MPUC
order in the ARP proceeding discussed fully below under the caption
"Alternative Rate Plan" and Note 3 to Consolidated Financial Statements,
"Regulatory Matters - Alternative Rate Plan." This write-off had the effect of
reducing earnings per share by $1.85. Absent the write-off, earnings for 1994
would have been $0.81 per share.
Dividends declared per common share have remained at $0.90 on an annual basis
for the three years ended December 31, 1996.
Revenues and Sales
Electric operating revenues increased by $51.0 million or 5.6% to $967.0
million in 1996, and by $11.1 million or 1.2% to $916.0 million in 1995. The
components of the change in electric operating revenues are as follows:
(Dollars in millions) 1996 1995
Revenues from Company service-area kilowatt-hour sales $15.0 $ 4.5
Revenues from non-territorial sales 33.4 (9.2)
Other Company operating revenues 3.0 8.7
Maine Electric Power Company, Inc. fuel cost recovery and
other revenues (0.4) 7.1
Total Change in Electric Operating Revenues $51.0 $11.1
Refer to "Alternative Rate Plan" below, for a discussion of new rates and
their impact on revenues.
The Company's service-area sales for the years 1996, 1995, and 1994 are shown
in the following table:
(Kilowatt-hours in millions)
1996 1995 1994
% % %
KWH change KWH change KWH change
Residential 2,829 1.0% 2,802 (2.0)% 2,860 (0.9)%
Commercial 2,489 0.5 2,477 1.6 2,439 2.2
Industrial 3,689 4.0 3,547 (4.7) 3,720 (1.9)
Wholesale and
lighting 217 58.9 136 (8.7) 149 (3.5)
Total Service-
Area Sales 9,224 2.9% 8,962 (2.2)% 9,168 (0.5)%
The primary factors in the service-area kilowatt-hour sales increase were
residential customers' taking advantage of the Company's water-heating
programs, increased sales in the pulp and paper industry, and the addition of
a wholesale customer. The decreases in 1995 and 1994 were attributed to low
economic growth, the loss of a major industrial customer in September 1994,
energy management, and loss of sales due to conversions from electricity to
alternative fuels for such purposes as space and water heating.
The average number of residential customers increased by 5,157 in 1996, 5,076
in 1995, and 4,679 in 1994, while average usage per residential customer
declined slightly in 1996, 3.1% in 1995 and 1.9% in 1994.
The 1996 increase in commercial sales reflect increases in the retail and
wholesale trade and service sectors. Combined, these sectors comprise
approximately 68% of commercial sales. Sales to all others in the commercial
sector were lower than 1995. Sales to Maine Yankee increased by 4 million
kilowatt hours in 1996, and by 14.7 million kilowatt hours in 1995 due to the
Plant's operating capacity limit of 90% and extended outages in both periods.
Industrial sales levels are significantly affected by sales to the
pulp-and-paper industry, which accounts for approximately 62% of industrial
sales and approximately 25% of total service-area sales. Sales to the
pulp-and-paper sector increased by 3.7% in 1996 and decreased by 8.6% in 1995,
and by 3.6% in 1994. The increase in 1996 reflects special arrangements the
Company has made with several paper companies to back down some of their
self-generation and buy electricity from the Company at a discounted rate.
The 1995 and 1994 decreases reflect lower sales levels primarily due to the
late-1994 loss of a major customer that had previously purchased approximately
280 million kilowatt-hours annually. Refer to "Alternative Rate Plan" and
"Competition and Economic Development," below, and Note 4 to Consolidated
Financial Statements, "Commitment's and Contingencies - Competition," for
additional information regarding the loss of this customer and the Company's
actions to preserve its remaining large-industrial-customer base and other
customer groups. Sales to all other industrial customers as a group increased
4.5% in 1996, 2.7% in 1995, and 1.5% in 1994.
Revenues from non-territorial sales were significantly higher in 1996 due to
sales to an out-of-state utility impacted by nuclear plant outages. In March
1995, a contract with a power broker expired, resulting in a decrease of $9.2
million in 1995 in non-territorial sales.
Alternative Rate Plan
In December 1994, the MPUC approved a stipulation, signed by most of the
parties to the Company's ARP proceeding, which took effect January 1, 1995.
This follow-up proceeding to the Company's 1993 base-rate case was ordered by
the MPUC in an effort to develop a five-year plan containing price-cap,
profit-sharing, and pricing-flexibility components. The price-cap mechanism
provides for adjusting the Company's retail rates annually on July 1,
commencing in 1995, at a percentage combining (1) a price index, (2) a
productivity offset, (3) a sharing mechanism, and (4) flow-through items and
mandated costs. The price cap applies to all of the Company's retail rates,
and includes fuel-and-purchased-power costs that previously had been treated
separately. The components of the July 1, 1995, price-cap increase of 2.43%
are the inflation index of 2.92%, reduced by a productivity offset of 0.5%,
and increased by 0.01% for flow-through items and mandated costs. The
components of the July 1, 1996, price-cap increase of 1.26% consisted of an
inflation index of 2.55% and earnings sharing and mandated cost items of
0.64%, reduced by a productivity offset of 1.0%, and sharing of contract
restructuring and buyout savings of 0.93%. As originally stated in the MPUC's
order approving the ARP, operation under the ARP continues to meet the
criteria of Statement of Financial Accounting Standards No. 71, "Accounting
for the Effects of Certain Types of Regulation" (SFAS No. 71). As a result,
the Company will continue to apply the provisions of SFAS No. 71 to its
accounting transactions and to its financial statements.
In 1994, the Company agreed in the ARP negotiations to record charges of
approximately $100 million ($60 million, net of tax) against 1994 earnings.
The Company believes the ARP provides the benefits of needed pricing
flexibility to set prices between defined floor and ceiling levels in three
service categories: (1) existing customer classes, (2) new customer classes
for optional targeted services, and (3) special-rate contracts. The Company
believes that the added flexibility will position it more favorably to meet
the competition from other energy sources that has eroded segments of its
customer base. Some price adjustments can be implemented upon 30-days' notice
by the Company, while certain others are subject to expedited review by the
MPUC. The Company has utilized this feature in providing new rates to
approximately 19,000 customers representing approximately 40% of annual
kilowatt-hour sales and 27% of service-area revenues. These reductions in
rates were offered to customers after consideration of associated NUG cost
reductions, savings from further NUG consolidations and other general cost
reductions.
The ARP also contains provisions to protect the Company and ratepayers against
unforeseen adverse results from its operation. These include review by the
MPUC if the Company's actual return on equity falls outside a designated
range, a mid-period review of the ARP by the MPUC in 1997 (including possible
modification or termination), and a "final" review by the MPUC in 1999 to
determine whether or with what changes the ARP should continue after 1999.
The Company will submit its 1997 compliance filing and mid-period review
filing in March 1997. The MPUC decision on the mid-period review is expected
by September 30, 1997.
While the ARP provides the Company with an expanded opportunity to be rewarded
for efficiency, it also presents the risk of reduced rates of return if costs
rise unexpectedly, like those that have resulted from the recent outages at
Maine Yankee, or if revenues from sales decline or are not adequate to fund
costs. The Company believes the ARP continues to be a competitive advantage
and does not plan to propose any significant change during the mid-period
review.
For a detailed discussion of the ARP, refer to Note 3 to Consolidated
Financial Statements,"Regulatory Matters - Alternative Rate Plan," and
"Meeting the Requirements of SFAS 71."
Maine Yankee Regulatory Issues
The Company owns 38% of the common stock of Maine Yankee and is responsible
for an approximately equal percentage of its costs. The 879-megawatt Maine
Yankee nuclear generating plant in Wiscasset, Maine (the Plant), like others
with pressurized water reactors, had been experiencing degradation of its
steam generator tubes. Until early 1995, this was believed to be limited to a
relatively small number of tubes. During a refueling shutdown in February
1995, new inspection methods used by Maine Yankee revealed that approximately
60% of the Plant's 17,000 steam generator tubes appeared to have defects.
Following a detailed analysis of safety, technical and financial
considerations, Maine Yankee repaired the tubes by inserting and welding short
reinforcing sleeves of an improved material in substantially all of the
Plant's steam generator tubes. Repairs were completed in December 1995. The
Company's approximately $10-million share of the repair costs adversely
affected the Company's 1995 earnings by $0.18 per share, net of taxes, in
spite of significant cost-reduction measures implemented by both the Company
and Maine Yankee. In addition, the Company incurred incremental
replacement-power costs during the outage totaling approximately $29 million,
or $0.52 per share, net of taxes, for 1995.
Also in December 1995, the Nuclear Regulatory Commission's (NRC) Office of the
Inspector General (OIG) and its Office of Investigations (OI) initiated
separate investigations of certain anonymous "whistleblower" allegations of
wrongdoing by Maine Yankee and Yankee Atomic Electric Company (Yankee Atomic)
in 1988 and 1989 in connection with operating license amendments. On May 9,
1996, the OIG, which was responsible for investigating only the actions of the
NRC staff and not those of Maine Yankee or Yankee Atomic, issued its report.
The report found deficiencies in the NRC staff's review, documentation, and
communications practices in connection with the license amendments, as well as
"significant indications of possible licensee violations of NRC requirements
and regulations." Any such violations by Maine Yankee are within the purview
of the OI investigation, which, with related issues, is being reviewed by the
United States Department of Justice. A separate internal investigation
commissioned by the boards of directors of Maine Yankee and Yankee Atomic and
conducted by an independent law firm noted several areas that could have been
improved, including regulatory communications, definition of responsibilities
between Maine Yankee and Yankee Atomic, and documentation and tracking of
regulatory compliance, but found no wrongdoing by Maine Yankee or Yankee
Atomic or any of their employees. Issues raised by the anonymous allegations
caused the NRC to limit the Plant to an operating level of approximately 90%
of its full thermal capacity, pending resolution of those issues. The Company
cannot predict the results of the investigations by the OI and Department of
Justice.
The December 1995 allegations caused the Plant's extended tube-sleeving outage
to be further extended into January 1996, and the Plant returned to the 90%
operating level on January 24. On June 7, 1996, the NRC formally notified
Maine Yankee that it would conduct an "Independent Safety Assessment" (ISA) of
the Plant as a "follow-on" to the OIG report and to provide an independent
evaluation of the safety performance of Maine Yankee by a team of NRC
personnel and contractors who were "independent of any recent or significant
involvement with the licensing, regulation or inspection of Maine Yankee."
The NRC conducted the ISA in the summer of 1996 and released its report on
October 7, 1996.
The detailed ISA report identified both deficiencies and strengths in Maine
Yankee's performance, and concluded that overall performance at Maine Yankee
was "adequate" for operation of the Plant. The ISA team stressed that the
deficiencies noted in the report stemmed from two closely related root causes,
specifically, (1) that economic pressure to be a low-cost energy provider had
limited available resources to address corrective actions and some
improvements, and (2) that lack of a "questioning culture" had resulted in a
failure to identify or promptly correct significant problems in areas
perceived by Maine Yankee to be of low safety significance. In a letter to
Maine Yankee accompanying the ISA report, NRC Chairman Shirley Ann Jackson
noted that although overall performance at Maine Yankee was considered
adequate for operation, a number of significant weaknesses and deficiencies
identified in the report would result in NRC violations. The letter also
directed Maine Yankee to provide to the NRC its plans for addressing the root
causes of the deficiencies noted in the ISA and identified the NRC offices
that would be responsible for overseeing corrective actions and taking any
appropriate enforcement actions against Maine Yankee.
On December 10, 1996, Maine Yankee filed its formal response to the ISA report
with the NRC. In the response, Maine Yankee indicated that it would spend
substantial sums on improvements in several areas in 1997 to address the root
causes and associated deficiencies noted in the report, and that the
improvements would include physical and operating changes at the Plant, along
with a 10% increase in staffing, primarily in the engineering and maintenance
areas, and other changes. In a release accompanying the response, Maine
Yankee stated that a "fundamental shift in corporate culture" would accompany
the changes and that Maine Yankee would not seek to return the Plant to the
100% power level from its authorized 90% level until it had reviewed the
margins on all the key safety systems at the Plant, which had been another
matter of concern to the NRC.
The Plant operated substantially at the 90% capacity level until July 20,
1996, when it was taken off-line after a comprehensive review by Maine Yankee
of the Plant's systems and equipment revealed a need to add pressure-relief
capacity to the Plant's primary component cooling system. On August 18, 1996,
while the Plant was in the restart process, Maine Yankee conducted a review of
its electrical circuitry testing procedures pursuant to a generic NRC letter
to nuclear-plant licensees that was intended to ensure that every feature of
every safety system be routinely tested. During the expanded review, Maine
Yankee found a deficiency in an electrical circuit of a safety system and
therefore elected to conduct an intensified review of other safety-related
circuits to resolve immediately any questions as to the adequacy of related
testing procedures. The Plant returned to the 90% operating level on
September 3, 1996.
On December 6, 1996, Maine Yankee took the Plant off-line to resolve
cable-separation and other operational and design issues. On January 3, 1997,
Maine Yankee announced that it would use the opportunity presented by that
outage to inspect the Plant's 217 fuel assemblies, since daily monitoring had
indicated evidence of a small number of defective fuel rods. As a result of
the inspection, Maine Yankee determined that all of the assemblies
manufactured by one supplier and currently in the reactor core (approximately
one-third of the total) would have to be replaced before the Plant could be
restarted. Maine Yankee will therefore keep the Plant off-line for refueling,
which had previously been scheduled for late 1997. In addition, Maine Yankee
will make use of the outage to inspect the Plant's steam generators,
commencing approximately April 1, 1997, for deterioration beyond that which
was repaired during the extended 1995 outage. Degradation of steam generators
of the age and design of those in use in the Plant has been identified at
other plants. If major repairs to, or replacement of, the steam generators
were found to be necessary for continued operation of the Plant, Maine Yankee
would review the economics of continued operation before incurring the
substantial capital expenditures that would be required.
In January, the NRC announced that it had placed the Plant on its "watch list"
in "Category 2", which includes plants that display "weaknesses that warrant
increased NRC attention", but which are not severe enough to warrant a
shut-down order. Plants in category 2 remain in that category "until the
licensee demonstrates a period of improved performance." The Plant is one of
fourteen nuclear units on the watch list announced that day by the NRC, which
regulates slightly over 100 civilian nuclear power plants in the United States.
After year end, Maine Yankee and Entergy Nuclear, Inc. (Entergy), which is a
subsidiary of Entergy Corporation, a Louisiana-based utility holding company
and leading nuclear plant operator, entered into a contract under which
Entergy is providing management services to Maine Yankee. At the same time,
officials from Entergy assumed management positions, including President, at
Maine Yankee.
While the Plant remains out of service, Maine Yankee must, in addition to
replacing the fuel assemblies and conducting an intensive inspection of its
steam generators, resolve the cable-separation issues and other known
regulatory issues, as well as any additional issues that are discovered during
the outage. The Company must obtain the approval of the NRC to restart the
Plant, following a mandated NRC process that includes an NRC-approved restart
plan and opportunities for public participation. The Company believes the
Plant will be out of service at least until August 1997, but cannot predict
when or whether all of the regulatory and operational issues will be
satisfactorily resolved or what effect the total of the repairs and
improvements to the Plant will have on the economics of operating the Plant.
The Company will incur significantly higher costs in 1997 for its share of
inspection, repairs and refueling costs at Maine Yankee and will also need to
purchase replacement power while the Plant is out of service. While the amount
of higher costs is uncertain, Maine Yankee has indicated that it expects it
operations and maintenance costs to increase by up to approximately $45
million in 1997, before refueling costs. The Company's share of such costs
based on its power entitlement of approximately 38% would be up to
approximately $17 million. In addition, the Company estimates its share of the
refueling costs will amount to approximately $15 million, of which $10.4
million has been accrued as of December 31, 1996. The Company has been
incurring incremental replacement-power costs of approximately $1 million per
week while the plant has been out of service and expects such costs to
continue at approximately the same rate until the plant returns to service.
The impact of these higher nuclear related costs on the Company's 1997
financial results will be significant and is likely to trigger the low
earnings bandwidth provision of the ARP. Under the ARP, actual earnings for
1997 outside a bandwidth of 350 basis points, above or below a 10.68% rate of
return allowance, triggers the profit sharing mechanism. A return below the
low end of the range provides for additional revenue through rates equal to
one-half of the difference between the actual earned rate of return and the
7.18% (10.68 - 3.50) low end of the bandwidth. While the Company believes that
the profit sharing mechanism is likely to be triggered in 1997, it cannot
predict the amount, if any, of additional revenues that may ultimately result.
Other Nuclear Issues
On December 4, 1996, the Board of Directors of Connecticut Yankee Atomic
Power Company voted to permanently shut down the Connecticut Yankee plant, for
economic reasons, and to decommission the unit. The Company has a 6% equity
interest in Connecticut Yankee, totaling approximately $6.4 million at
December 31, 1996. The plant did not operate after July 22, 1996, causing the
Company to incur replacement power costs of approximately $1.5 million in
1996. The Company estimates its share of the cost of Connecticut Yankee's
continued compliance with regulatory requirements, recovery of its plant
investments, decommissioning and closing the plant to be approximately $45.8
million and has recorded a regulatory asset and a liability on its
consolidated balance sheet. The Company is currently recovering through rates
an amount adequate to recover these expenses.
The Company has a 2.5% ownership interest in Millstone Unit No. 3 which is
operated by Northeast Utilities. This facility has been off-line since March
31, 1996 due to NRC concerns regarding license requirements and the Company
cannot predict when it will return to service. Millstone Unit No. 3, along with
two other units at the same site owned by Northeast Utilities, is on the NRC's
"watch list" in "Category 3," which requires formal NRC action before a unit
can be restarted. The Company estimates that it will incur approximately
$300,000 to $500,000 in replacement power costs each month Millstone Unit No. 3
remains out of service. The Company incurred replacement power costs of $3.5
million in 1996.
Environmental Actions
The Company has been named by the Environmental Protection Agency (EPA) as a
"potentially responsible party" (PRP) and has been incurring costs to
determine the best method of cleaning up an Augusta, Maine, site formerly
owned by a salvage company and identified by the EPA as containing soil
contaminated by PCBs from equipment originally owned by the Company. The
Company also has been named as a PRP at eleven former gas plant sites, six
former waste oil sites, and two former pole treatment and storage locations.
Refer to Note 4 to Consolidated Financial Statements, "Commitments and
Contingencies - Legal and Environmental Matters," for a more detailed
discussion of this matter.
Industry Restructuring and Strandable Costs
The Federal Energy Policy Act of 1992 accelerated planning by electric
utilities, including the Company, for a transition to a more competitive
industry. The functional areas in which competition will take place, the
regulatory changes that will be implemented, and the resulting structure of
both the industry and the Company are all uncertain, but regulatory steps have
already been taken toward competition in generation and non-discriminatory
transmission access. A departure from traditional regulation and industry
restructuring, however, could have substantial impacts on the value of utility
assets and on electric utilities' abilities to recover their costs through
rates. In the absence of full recovery, utilities would find their
above-market costs to be "stranded," or unrecoverable, in the new competitive
setting.
In January, 1996, the Company filed its recommendations for an orderly
transition to competition and adequate reimbursement of its potentially
strandable costs with the MPUC. In December 1996, the MPUC issued its Report
and Recommended Plan for Electric Utility Restructuring in Maine. The major
elements of the MPUC plan, which are similar in most, but not all, respects to
the Company's proposal include:
(1) By January 2000, investor owned utilities would transfer all generating
assets to entities distinct from transmission and distribution (T&D) assets
and obligations.
(2) By January 2006, the Company would be required to divest all generation
assets (except Maine Yankee).
(3) By January 2000, investor-owned utilities would be required to transfer
the rights to market power from all qualifying facilities contracts.
(4) Contracts between investor-owned utilities and qualifying facilities would
remain with the T&D company.
(5) Beginning January 1, 2000, all customers would have the option to purchase
power directly from power suppliers or from intermediaries such as load
aggregators, power marketers or energy service companies.
(6) Standard-offer service would be provided to customers who do not choose a
competitive power provider and who cannot obtain power in the market on
reasonable terms.
(7) The MPUC would not regulate companies that produce or sell power once
customers can purchase power in a competitive market.
(8) T&D companies would continue to be regulated. T&D companies would have
exclusive service territories and an obligation to connect customers to the
power grid.
(9) A "reasonable opportunity" to recover strandable costs would be achieved
through the regulated rates of the T&D utilities. Amounts recovered could
include costs of fulfilling obligations under contracts with NUGs, as well as
investments (and returns thereon) and other obligations undertaken by the
Company in fulfilling its legal duty to serve, with requirements for the
Company to mitigate such costs where practicable.
(10) The MPUC recommended that the Legislature fund low-income assistance
programs; otherwise, these programs would continue to be funded through T&D
company rates.
(11) All companies selling power to retail customers in Maine would be
required to include a minimum amount of renewable energy in their generation
mix, and customers would continue to fund cost-effective energy efficiency
programs through T&D rates.
The Company has substantial exposure to cost stranding relative to its size.
In its January 1996 filing, the Company estimated its net-present-value
strandable costs could be approximately $2 billion as of January 1, 1996.
These costs represent the excess costs of purchased-power obligations and the
Company's own generating costs over the market value of the power, and the
costs of deferred charges and other regulatory assets. Of the $2 billion,
approximately $1.3 billion is related to above-market costs of purchased-power
obligations, approximately $200 million is related to estimated net
above-market cost of the Company's own generation, and the remaining $500
million is related to deferred regulatory assets.
The MPUC also provided estimates of strandable costs for the Company, which
they found to be within a wide range of a negative $445 million to a positive
$965 million. These estimates were prepared using assumptions that differ
from those used by the Company, particularly a starting date for measurement
of January 1, 2000 versus a measurement starting date of January 1, 1996
utilized by the Company. The MPUC concluded that there is a high degree of
uncertainty that surrounds stranded costs numbers, resulting from having to
rely on projections and assumptions about future conditions. Given the
inherent uncertainty and volatility of these projections, the Company believes
that an annual estimation of stranded costs could serve to prevent significant
over-or-under-collection beginning in the year 2000.
Estimated strandable costs are highly dependent on estimates of the future
market for power. Higher market rates lower stranded cost exposure, while
lower market rates increase it. In addition to market-related impacts, any
estimate of the ultimate level of strandable costs depends on state and
federal regulations; the extent, timing and form that competition for electric
service will take; the ongoing level of the Company's costs of operations;
regional and national economic conditions; growth of the Company's sales;
timing of any changes that may occur from state and federal initiatives on
restructuring; and the extent to which regulatory policies ultimately address
recovery of strandable costs.
The estimated market rate for power is based on anticipated regional market
conditions and future costs of producing power. The present value of future
purchased-power obligations and the Company's generating costs reflects the
underlying costs of those sources of generation in place today, with
reductions for contract expirations and continuing depreciation. Deferred
regulatory asset totals include the current uncollected balances and existing
amortization schedules for purchased-power contract restructuring and buyouts
negotiated by the Company to lessen the impact of these obligations, energy
management costs, financing costs, and other regulatory promises. The Company
expects its strandable-cost exposure to decline over time as the market price
of power increases, non-utility generator (NUG) contracts expire, and
regulatory assets are recovered.
Major cost stranding would have a material adverse effect on the Company's
financial position. The Company believes it is entitled to recover
substantially all of its potential strandable costs, but cannot predict when
or if open electric energy competition will occur in its service territory, or
how much it might ultimately be allowed to recover through state or federal
regulation, the future market price of electricity, or the timing or
implementation of any formal recommendations in any regulatory or legislative
proceedings dealing with such issues.
The Company believes there are many uncertainties associated with any major
restructuring of the electric utility industry in Maine. Among them are: the
positions that will ultimately be taken by the Maine Legislature and the MPUC;
the role and policies of the FERC in any restructuring involving the Company,
the extent and effect of Congressional involvement; whether political
consensus is attained; and the extent to which the Company will be permitted
to recover its strandable costs.
The Company is pursuing efforts to mitigate its exposure to stranded costs.
One method of mitigation that is being actively pursued is securitization of
stranded costs including regulatory assets, above market NUG costs and above
market company owned generation costs. Pursuant to a future legislative
mandate and subject to determination by the MPUC, a portion of existing
revenues related to stranded costs would be assigned by the Company for
repayment of these costs. The property right created by this assignment could
be used as security by a trust to sell bonds, the proceeds of which could be
used by the Company to refinance existing obligations. Similarly a portion of
existing revenues could also be dedicated directly to payment of above market
non-utility power contract obligations, reducing the risks for the suppliers
as well as for the Company. Mitigation from this mechanism would result from
lower cost financing of stranded costs, enhanced credit worthiness of the
utility, which should further reduce the Company's costs, and from increased
availability of low cost funds to finance additional purchased power contract
restructuring efforts. Any mitigation achieved would be passed on to
residential and small commercial customers through lower rates. The Company
cannot predict when or if legislative support for the use of securitization
may occur.
Open-Access Transmission Service Ruling
On April 24, 1996, the Federal Energy Regulatory Commission (FERC) issued
Order No. 888, which requires all public utilities that own, control or
operate facilities used for transmitting electric energy in interstate
commerce to file open access non-discriminatory transmission tariffs that
offer both load-based, network and contract-based, point-to-point service,
including ancillary service to eligible customers containing minimum terms and
conditions of non-discriminatory service. This service must be comparable to
the service they provide themselves at the wholesale level; in fact, these
utilities must take wholesale transmission service they provide themselves
under the filed tariffs. The order also permits public utilities and
transmitting utilities the opportunity to recover legitimate, prudent and
verifiable wholesale stranded costs associated with providing open access and
certain other transmission services. It further requires public utilities to
functionally separate transmission from generation marketing functions and
communications. The intent of this order is to promote the transition of the
electric utility industry to open competition. Order No. 888 also clarifies
federal and state jurisdiction over transmission in interstate commerce and
local distribution and provides for deference of certain issues to state
recommendations.
On July 9, 1996, the Company and MEPCO submitted compliance filings to meet
the new pro forma tariff non-price minimum terms and conditions of
non-discriminatory transmission. Since July 9, 1996, the Company and MEPCO
have been transmitting energy pursuant to their filed tariffs, subject to
refund. FERC subsequently issued Order No. 888-A which generally reaffirms
Order No. 888 and clarifies certain terms.
Also on April 24, 1996, FERC issued Order No. 889 which requires public
utilities to functionally separate their wholesale power marketing and
transmission operation functions and to obtain information about their
transmission system for their own wholesale power transactions in the same way
their competitors do through the Open Access Same-time Information System
(OASIS). The rule also prescribed standards of conduct and protocols for
obtaining the information. The standards of conduct are designed to prevent
employees of a public utility engaged in marketing functions from obtaining
preferential information. The Company participated in efforts to develop a
regional OASIS, which was operational January 3, 1997. FERC subsequently
approved a New England Power Pool-wide Open Access Tariff, subject to refund
and issuance of further orders. The Company also participated in revising the
New England Power Pool Agreement, which is pending FERC approval.
Competition and Economic Development
The Company faces competition in several aspects of its traditional business
and anticipates that competition will continue to put pressure on both sales
and the price the Company can charge for its product. Alternative fuels and
recent modifications to regulations that had restricted competition from
suppliers outside of the Company's service territory have expanded customers'
energy options. As a result, the Company continues to pursue retention of its
customer base. This increasingly competitive environment has resulted in the
Company's entering into contracts with its wholesale customers, as well as
with certain industrial, commercial, and residential customers, to provide
their energy needs at prices and margins lower than the current averages.
Pursuant to the pricing-flexibility provisions of the ARP, the Company
redesigned some rates to encourage off-peak usage and discourage switching to
alternative fuels. These include water-heat and space-heat retention rates,
Super-Saver rates, which discount off-peak usage, Diesel Deferral rates,
Economic Development rates, and the Maine Made Incentive program, which target
small businesses. In 1994, the Company lowered tariffs for its large
general-service customers and executed separate five-year definitive
agreements with 18 individual customers providing additional reductions.
Approximately 40% of annual service area kilowatt-hour sales and 27% of annual
revenues are covered under special tariffs allowed under the pricing
flexibility provisions of the ARP. These reductions in rates were offered to
customers after consideration of associated NUG cost reductions, savings from
further NUG consolidations and other general cost reductions. Refer to Note 4
to Consolidated Financial Statements,"Commitments and Contingencies -
Competition," for additional information.
Non-Utility Generators
In accordance with prior MPUC policy and the ARP, $113 million of buy-out or
contract-restructuring costs incurred since January 1992 were included in
Deferred Charges and Other Assets on the Company's balance sheet and will be
amortized over their respective fuel savings periods. The Company restructured
40 contracts representing 316 megawatts of capacity that should result in
approximately $301 million in fuel savings over the next five years.
The Company also restructured a purchased power contract with a 20 megawatt
waste-to-energy facility, which is estimated to save the Company approximately
$20 million over the next five years. Refer to Note 6 to Consolidated
Financial Statements, "Capacity Arrangements - Non-Utility Generators," for
more information.
On October 31, 1997, a contract with a major NUG from which the Company is
obligated to purchase electricity at substantially above-market prices will
expire. As a result, the Company expects annual operating income to increase
by approximately $25 million. Two months of this benefit, or approximately $4
million, will be reflected in 1997 results.
Expansion Of Lines Of Business
The Company is also preparing for competition by expanding its business
opportunities through subsidiaries that capitalize on core competencies. One
such subsidiary, MaineCom Services, which was approved by the MPUC on July 13,
1995, is developing opportunities in expanding markets by arranging
fiber-optic data service for bulk carriers, offering support for cable-TV or
"super-cellular" personal-communication vendors, and providing other
telecommunications consulting services. The Company invested $10.7 million in
MaineCom during 1996 to develop an interchange network from Portland, Maine,
to various points in New Hampshire, Massachusetts and Connecticut. In
addition, the Company has subsidiaries or divisions that provide
energy-efficiency services, utility consulting (domestic and international)
and research, engineering and environmental services, management of rivers and
recreational facilities, locating of underground utility facilities and
infrared photography, real estate brokerage and management, modular housing,
and credit and collections services. All subsidiaries utilize skills of
former Company employees and compete for business with other companies.
In July 1996, the Company and Maine Electric Power Company, Inc. (MEPCO), a
78%-owned subsidiary of the Company, entered into option agreements with
Maritimes and Northeast Pipeline, L.L.C. (M&N) in which the Company and MEPCO
agreed to provide exclusive options to M&N to acquire property interests in
certain transmission line rights of way to sections of M&N's proposed natural
gas pipeline from the United States-Canada border at Woodland, Maine, to
Dracut, Massachusetts. In November 1996, while the parties were still engaged
in negotiating the terms of the proposed long-term arrangement, the options
expired by their terms. Subsequent to the expiration the parties have met to
discuss a long-term arrangement for use of the Company's and MEPCO's rights of
way for the proposed pipeline, but the Company cannot predict whether final
agreement on such an arrangement will be reached.
Expenses and Taxes
The Company's fuel expense, comprising the cost of fuel used for company
generation and the energy portion of purchased power (the largest expense
category), was 49% of total operating expense in 1996, 51% in 1995, and 54% in
1994. Purchased-power energy expense includes costs associated with purchases
from NUGs, which amounted to 74% of this expense category in 1996. Fuel
expense fluctuates with changes in the price of oil, the level of energy
generated and purchased, and changes in the Company's own generation mix.
Through December 31, 1994, changes in fuel expense were provided rate
treatment through a fuel clause. Under the ARP, effective January 1, 1995,
fuel-expense recovery is subject to the annual index-based price change. Fuel
cost decreases are generally retained by the Company. Fuel expense for MEPCO
was fully recoverable through billing to MEPCO participants. See Note 3 to
Consolidated Financial Statements, "Regulatory Matters - Open Access
Transmission Service Ruling," for a discussion on FERC Order No. 888 and its
effect on MEPCO's operations.
The extended outages and reduced operating level at Maine Yankee (see"Maine
Yankee Regulatory Issues") resulted in significant increases in fuel expense,
including purchased-power energy and purchased-power capacity expense, and
affected the Company's generation mix in 1996 and 1995. The Company replaced
this power through short-term agreements.
Purchased power expense in 1996 reflected savings of approximately $5.4
million related to a paper company's extended forced outage of its
cogeneration facility due to a flood. Additional savings of approximately $6
million were achieved through a five-year capacity exchange arrangement with
Northeast Utilities designed to reduce replacement power cost when either
Maine Yankee or Northeast Utilities facilities are off-line. Although this
agreement was suspended in 1995, Northeast Utilities owed the Company energy,
which they delivered in 1996. The Company benefited by purchasing this power
at rates lower than market rates. See Note 4 to Consolidated Financial
Statements, "Commitments and Contingencies - Competition," for more
information on this matter.
The Company's oil-fired generation decreased to 16.3% of the Company's net
generation in 1996, compared to 21.6% in 1995 net generation, and 12.1% in
1994. The NUG component of the energy mix decreased from 36.8% in 1995, to
31.4% in 1996, as a result of the ongoing efforts to reform the Company's NUG
contracts and an extended forced outage at one NUG facility. The average price
of NUG energy of 8.3 cents per kilowatt-hour is significantly higher than the
Company's own cost of generation, and much higher than the price of energy on
today's open market. The Company continues to try to moderate the cost of
non-utility generation by pursuing renegotiation of contracts, by supporting
legislative bills that would promote that objective, and by other means such
as strict contract-term enforcement.
Purchased-power capacity expense is the non-fuel operation, maintenance, and
cost-of-capital expense associated with power purchases, primarily from the
Company's share of the Yankee nuclear generating facilities. In 1996,
purchased-power capacity expense increased by $15.2 million. Maine Yankee
capacity expense decreased by $12.2 million in 1996 , due mainly to the 1995
$10-million steam-generator tube repair costs. 1996 costs increased primarily
as a result of an accrual for the 1997 refueling outage that accounted for a
year over year increase of $13 million. In addition, expense increased by
$9.4 million resulting from the restructuring of a contract with a non-utility
generator. This agreement significantly decreased the cost of purchased-power
fuel resulting in a net savings in total purchased power costs.
The level of purchased-power capacity expense also fluctuates with the timing
of the maintenance and refueling outages at the other Yankee nuclear
generating facilities in which the Company has equity interests. The cost of
capacity increases during refueling periods. In December 1996, the Board of
Directors of Connecticut Yankee Atomic Power Company announced a permanent
shutdown of the Connecticut Yankee plant for economic reasons and their intent
to decommission the plant. The Company has a 6% equity interest in Connecticut
Yankee, totaling approximately $6.4 million at December 31, 1996. Purchased
power capacity expense in 1996, 1995 and 1994 includes $11.5 million, $11.5
million, and $10 million, respectively, of costs related to this facility.
During 1992, Yankee Atomic Electric Company, in which the Company is a 9.5%
equity owner, discontinued power generation and prepared a plan for
decommissioning. Purchased-power capacity expense in 1996, 1995, and 1994
contained approximately $4.8 million, $3.9 million, and $5.2 million,
respectively, of costs related to this facility. Refer to Note 6 to
Consolidated Financial Statements, "Capacity Arrangements - Power Agreements,"
and "Other Nuclear Issues" above for a more detailed discussion.
The 1996 reduction in other operation and maintenance expense is attributed to
the reversal of a reserve of $6.4 million established in 1995 for the
Company's workers compensation regulatory asset for which recovery was not
certain. In the June 1996 ARP decision, the MPUC approved recovery of this
regulatory asset. Also in 1996, the Company increased the workers
compensation obligation and charged the increase of $1.6 million to expense.
As a result, a net year-over-year reduction of $11.2 million for workers
compensation was recorded. The Company did incur an increase in distribution
expenses of $4.1 million, mainly due to line-clearance activities. The
Company has contractual obligations related to demand-side energy-management
programs which increased expense by $2.8 million in 1996. Maintenance expense
other than distribution increased $3.5 million, of which $1.4 million was for
repairs at the Millstone Unit No. 3 nuclear facility.
The 1995 other operation-and-maintenance expense increase reflects
significantly higher charges totaling approximately $27.7 million for
amortization and cost of purchased-power contract buy-outs. Also reflected is
a one-time charge of $5.6 million related to a Special Retirement Offer (SRO)
to all employees aged 50 or more who had at least five years of continuous
service. The goal of the SRO was to help the Company achieve financial savings
and make the organizational changes it needed to be an effective competitor in
the energy marketplace. Approximately 200 employees accepted the SRO.
The Company continued its reengineering effort that began in 1995 to analyze
the financial controls and customer service sectors of the business. Employee
teams have begun implementing solutions that are expected to yield
improvements in work processes and result in cost savings. The Company is
also continuing cost containment measures.
Interest expense decreased in 1996 by $1.4 million due to lower levels of
Medium-Term Notes and the repurchase of $11.5 million of Series N General and
Refunding Mortgage Bonds. Long-term debt interest expense includes $1 million
of accelerated amortization of loss on reacquired debt, as specified in the
1996 ARP. In 1995, interest expense included a full year's interest costs on
the Company's October 1994 note to the Finance Authority of Maine to finance
the buy-out of a major NUG contract, and lower interest cost from a decrease
in the amount of Medium-Term Notes outstanding. Short-term interest costs over
the period 1994 through 1996 fluctuated with the levels of rates and
outstanding balances of short-term debt.
In July 1996, the Company redeemed $14 million of its 8 7/8% Series Preferred
Stock at par, under the mandatory and optional sinking-fund provisions of that
series. This reduced dividends by approximately $700,000 in 1996. The
Company reduced the level of Flexible Money Market Preferred Stock outstanding
in 1995 by $5.5 million in anticipation of the 1999 sinking-fund requirement,
thereby reducing dividends in 1995 by $300,000.
State and federal income taxes fluctuate with the level of pre-tax earnings
and the regulatory treatment of taxes by the MPUC. A settlement with the
Internal Revenue Service on audits for the years 1988-1991 provided a decrease
to income tax expense of approximately $4.8 million in 1996. The significant
increase in income-tax expense for 1995 is due to the impact of the loss from
the write-off of deferred balances in accordance with the MPUC's ARP order in
1994. See Note 2 to Consolidated Financial Statements, "Income Taxes," for
more information.
Liquidity and Capital Resources
The MPUC approved increases in electric retail rates of 1.26% and 2.43% in
1996 and 1995, respectively, that produced additional cash pursuant to the
price cap mechanism in the ARP. Increases in rates under the ARP were based on
increases in the related price index, the sharing mechanism and provisions for
certain mandated costs. Prior rate increases were provided to fund costs of
fuel, energy-management programs, operations, maintenance, systems
improvements, and investments in generation needed to ensure the Company's
continued ability to provide reliable electric service.
Approximately $141.7 million of cash was provided from net income after adding
back non-cash items. Approximately $16.2 million of cash was used for
fluctuations in working capital. Other operating activities, including the
financing of deferred energy-management programs and the buy-out of NUG
contracts, required cash resources.
The level of cash balances and activity in capital investment programs have
required little investment-related activity during 1996 and 1995. The issuance
and redemption of Medium-Term Notes and the purchase of 8 7/8% Series
Preferred Stock used $24 million and $14 million, respectively, of cash during
1996. Dividends paid on common stock were $29.2 million, while
preferred-stock dividends were $9.8 million.
Capital-investment activities, primarily construction expenditures, utilized
$57.1 million in cash during 1996. Construction expenditures comprised
approximately $6.3 million for generating projects, $3.0 million for
transmission, $27.9 million for distribution, and $9.7 million for general
facilities and other construction expenditures. The Company invested $12.1
million in subsidiaries in 1996, of which $10.7 million was in MaineCom
Services.
The Company estimates its capital expenditures for the period 1997 through
2001 at approximately $302 million. Actual capital expenditures will depend
upon the availability of capital and other resources, load forecasts, customer
growth, and general business conditions. During the five-year period, the
Company also anticipates incurring approximately $462 million for
sinking funds, and debt and equity maturities.
The Company estimates that for the period 1997 through 2001, internally
generated funds from operating activities should provide a substantial portion
of the construction-program requirements. However, the availability at any
particular time of internally generated funds for such requirements will
depend on working-capital needs, market conditions, and other relevant factors.
Replacement power costs and increased operation, maintenance and refueling
costs for Maine Yankee will have a significant negative effect on cash and
liquidity in 1997. The Company has been incurring incremental
replacement-power costs of approximately $1 million per week while the plant
has been out of service and expects such costs to continue at approximately
the same rate until the plant returns to service. Maine Yankee has indicated
that it expects its operations and maintenance costs to increase by up to
approximately $45 million, before refueling costs. The Company's share of
such costs would be up to approximately $17 million. In addition, the Company
estimates its share of the refueling costs will amount to approximately $15
million. Internally generated funds from operating activities will not be
sufficient to meet these demands. The Company also plans to utilize its
Medium-Term Note program and revolving credit facilities, as described below,
for these cash requirements.
The Company's $150-million Medium-Term Note program was implemented to provide
flexibility to meet financing needs and provide access to a broad range of
debt maturities. As of December 31, 1996, $68 million of Medium-Term Notes
were outstanding which, under the terms of the program, permits issuance of an
additional $82 million of such notes. The Company is planning to seek the
consent of its preferred stockholders to increase the capacity of the
Medium-Term Note program from $150 million to $500 million at its annual
meeting of stockholders on May 15, 1997, in order to increase its financing
flexibility in anticipation of restructuring and increased competition. The
Company cannot predict whether such consent will be obtained.
In 1996, the Company deposited approximately $29.6 million in cash with the
Trustee under the Company's General and Refunding Mortgage Indenture in
satisfaction of the renewal and replacement fund and other obligations under
the Indenture. The total of such cash on deposit with the Trustee as of
December 31, 1996, was approximately $59.5 million. Under the Indenture such
cash may be applied at any time, at the direction of the Company, to the
redemption of bonds outstanding under the Indenture at a price equal to the
principal amount of the bonds being redeemed, without premium, plus accrued
interest to the date fixed for redemption. Such cash may also be withdrawn by
the Company by substitution of allocated property additions or available bonds.
To support its short-term capital requirements, on October 23, 1996 , the
Company entered into a $125 million revolving credit facility with several
banks, with The First National Bank of Boston and The Bank of New York acting
as agents for the lenders. The credit facility has two tranches: a $75
million, 364-day revolving credit facility that matures on October 22, 1997,
and a $50-million, 3-year revolving credit facility that matures on October
23, 1999. Both credit facilities require annual fees on the unused portion of
the credit lines. The fees are based on the Company's credit ratings and
allow for various borrowing options including LIBOR-priced, base-rate-priced
and competitive-bid-priced loans. Access to commercial paper markets has been
substantially reduced, if not precluded, as a result of downgrading of the
Company's credit ratings. The amount of outstanding short-term borrowing will
fluctuate with day-to-day operational needs, the timing of long-term
financing, and market conditions. There was $7.5 million outstanding as of
December 31, 1996, under this agreement.
Factors That May Affect Future Results
This management's discussion and analysis section contains forecast
information items that are "forward-looking statements" as defined in the
Private Securities Litigation Reform Act of 1995. All such forward-looking
information is necessarily only estimated. There can be no assurance that
actual results will not materially differ from expectations. Actual results
have varied materially and unpredictably from past expectations.
Factors that could cause actual results to differ materially include, among
other matters, electric utility restructuring, including the ongoing state and
federal activities; future economic conditions; earnings-retention and
dividend-payout policies; developments in the legislative, regulatory, and
competitive environments in which the Company operates; and other
circumstances that could affect anticipated revenues and costs, such as
unscheduled maintenance or repair requirements and compliance with laws and
regulations. Nuclear investments and obligations, which are subject to
increased regulatory scrutiny, and the amount of expenditures and the timing
of the return of the Maine Yankee generating plant to service, could have a
material effect on the Company's financial position.
Item 8. FINANCIAL STATEMENTS AND
SUPPLEMENTARY DATA.
Page
Index to Financial Statements and Financial Statement Schedule
Financial Statements:
Management report on responsibility for financial reporting 43
Report of Independent Accountants 44
Consolidated Statement of Earnings for the three years ended
December 31, 1996, 1995 and 1994 45
Consolidated Balance Sheet as of December 31, 1996 and 1995 46
Consolidated Statement of Cash Flows 48
Consolidated Statement of Capitalization and Interim Financing 50
Consolidated Statement of Changes in Common-Stock Investment 51
Notes to Consolidated Financial Statements 52
Financial Statement Schedule:
Schedule II - Valuation and Qualifying Accounts 101
Report of Management
The Management of Central Maine Power Company and its subsidiary is
responsible for the consolidated financial statements and the related
financial information appearing in this annual report. The financial
statements are prepared in conformity with generally accepted accounting
principles and include amounts based on informed estimates and judgments of
management. The financial information included elsewhere in this report is
consistent, where applicable, with the financial statements.
The Company maintains a system of internal accounting controls that is
designed to provide reasonable assurance that the Company's assets are
safeguarded, transactions are executed in accordance with management's
authorization, and the financial records are reliable for preparing the
financial statements. While no system of internal accounting controls can
prevent the occurrence of errors or irregularities with absolute assurance,
management's objective is to maintain a system of internal accounting controls
that meets its goals in a cost-effective manner.
The Company has policies and procedures in place to support and document the
internal accounting controls that are revised on a continuing basis. Internal
auditors conduct reviews, provide ongoing assessments of the effectiveness of
selective internal controls, and report their findings and recommendations for
improvement to management.
The Board of Directors has established an Audit Committee, composed entirely
of outside directors, which oversees the Company's financial reporting process
on behalf of the Board of Directors. The Audit Committee meets periodically
with management, internal auditors, and the independent public accountants to
review accounting, auditing, internal accounting controls, and financial
reporting matters. The internal auditors and the independent public
accountants have full and free access to meet with the Audit Committee, with
or without management present, to discuss auditing or financial reporting
matters.
Coopers & Lybrand L.L.P., independent public accountants, has been retained to
audit the Company's consolidated financial statements. The accompanying report
of independent public accountants is based on their audit, conducted in
accordance with generally accepted auditing standards, including a review of
selected internal accounting controls and tests of accounting procedures and
records.
David T. Flanagan David E. Marsh
President and Chief Executive Officer Vice President,
Corporate Services,
Treasurer and Chief
Financial Officer
REPORT OF INDEPENDENT ACCOUNTANTS
To the Directors and Stockholders
Central Maine Power Company
We have audited the consolidated financial statements and the financial
statement schedule of Central Maine Power Company and subsidiary listed in
Item 8 and Item 14(a) of this Form 10-K. These financial statements and
financial statements schedule are the responsibility of the Company's
management. Our responsibility is to express an opinion on these financial
statements and financial statement schedule based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free of
material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.
In our opinion, the financial statements referred to above present fairly, in
all material respects, the consolidated financial position of Central Maine
Power Company and subsidiary as of December 31, 1996 and 1995, and the
consolidated results of their operations and their cash flows for each of the
three years in the period ended December 31, 1996, in conformity with
generally accepted accounting principles. In addition, in our opinion, the
financial statement schedule referred to above, when considered in relation to
the basic financial statements taken as a whole, presents fairly, in all
material respects, the information required to be included therein.
Coopers & Lybrand L.L.P.
Portland, Maine
January 23, 1997
Consolidated Financial Statements
Consolidated Statement of Earnings
(Dollars in thousands, except per-share Year ended December 31,
amounts)
1996 1995 1994
Electric Operating Revenues (Notes 1 and 3) $967,046 $916,016 $904,883
Operating expenses
Fuel used for company generation (Notes 1
and 6) 16,827 18,702 14,783
Purchased power - energy (Notes 1 and 6) 407,926 408,072 430,874
Purchased power - capacity (Note 6) 108,720 93,489 77,775
Other operation 182,910 188,013 153,700
Maintenance 37,449 32,862 32,820
Depreciation and amortization (Note 1) 53,694 55,023 55,992
Federal and state income taxes (Note 2) 30,125 13,328 28,300
Taxes other than income taxes 27,861 27,885 25,512
Total Operating Expenses 865,512 837,374 819,756
Equity in Earnings of Associated Companies
(Note 6) 6,138 7,217 5,109
Operating Income 107,672 85,859 90,236
Other income (expense)
Allowance for equity funds used during
construction (Note 1) 851 663 807
Other, net (Note 3) 5,255 7,170 (105,133)
Income taxes (Notes 2 and 3) (1,897) (2,704) 42,443
Total Other Income (Expense) 4,209 5,129 (61,883)
Income Before Interest Charges 111,881 90,988 28,353
Interest charges
Long-term debt (Note 7) 47,966 50,307 46,213
Other interest (Note 7) 4,341 3,244 5,887
Allowance for borrowed funds used during
construction (Note 1) (655) (543) (482)
Total Interest Charges 51,652 53,008 51,618
Net income (loss) 60,229 37,980 (23,265)
Dividends on preferred stock 9,452 10,178 10,511
Earnings (Loss) Applicable to Common Stock $ 50,777 $ 27,802 $(33,776)
Weighted Average Number of Shares of
Common Stock Outstanding 32,442,752 32,442,752 32,442,408
Earnings (Loss) Per Share of Common Stock $1.57 $0.86 $(1.04)
Dividends Declared Per Share of Common
Stock $0.90 $0.90 $ 0.90
The accompanying notes are an integral part of these financial statements.
Consolidated Balance Sheet
(Dollars in thousands) December 31
Assets 1996 1995
Electric property, at original cost (Notes 6 and 7) $1,644,434 $1,611,941
Less: accumulated depreciation (Notes 1 and 6) 598,415 560,078
Electric property in service 1,046,019 1,051,863
Construction work in progress (Note 4) 20,007 15,928
Nuclear fuel, less accumulated amortization of $9,035 in
1996 and $8,909 in 1995 1,157 1,391
Net electric property 1,067,183 1,069,182
Investments in associated companies, at equity (Notes 1 and
6) 67,809 54,669
Net Electric Property and Investments in Associated
Companies 1,134,992 1,123,851
Current assets
Cash and cash equivalents 8,307 57,677
Accounts receivable, less allowances for uncollectible
accounts of $4,177 in 1996 and $3,313 in 1995:
Service - billed 84,396 87,140
Service - unbilled (Notes 1 and 3) 45,721 41,798
Other accounts receivable 17,517 15,131
Prepaid income taxes (Note 2) 264 -
Fuel oil inventory, at average cost 9,256 3,772
Materials and supplies, at average cost 12,172 12,772
Funds on deposit with trustee (Note 7) 59,512 29,919
Prepayments and other current assets 9,500 9,192
Total Current Assets 246,645 257,401
Deferred charges and other assets
Recoverable costs of Seabrook 1 and abandoned projects, net (Note 1) 89,551 95,127
Yankee Atomic purchased-power contract (Note 6) 16,463 21,396
Connecticut Yankee purchased-power contract (Note 6) 45,769 -
Regulatory assets - deferred taxes (Note 2) 239,291 235,081
Deferred charges and other assets (Notes 1 and 3) 238,203 260,063
Total Deferred Charges and Other Assets 629,277 611,667
Total Assets $2,010,914 $1,992,919
The accompanying notes are an integral part of these financial statements.
Stockholders' Investment and Liabilities
Capitalization (see separate statement) (Note 7)
Common-stock investment $ 511,578 $ 490,005
Preferred stock 65,571 65,571
Redeemable preferred stock 53,528 67,528
Long-term obligations 587,987 622,251
Total Capitalization 1,218,664 1,245,355
Current liabilities and interim financing
Interim financing (see separate statement) (Note 7) 32,500 34,000
Sinking-fund requirements (Note 7) 9,375 10,455
Accounts payable 93,197 108,170
Dividends payable 9,512 9,823
Accrued interest 11,610 12,648
Accrued income taxes (Note 2) - 3,668
Miscellaneous current liabilities 21,342 13,870
Total Current Liabilities and Interim Financing 177,536 192,634
Commitments and Contingencies (Notes 4 and 6)
Reserves and deferred credits
Accumulated deferred income taxes (Note 2) 357,994 351,868
Unamortized investment tax credits (Note 2) 31,988 32,452
Yankee Atomic purchased-power contract (Note 6) 16,463 21,396
Connecticut Yankee purchased-power contract (Note 6) 45,769 -
Regulatory liabilities - deferred taxes (Note 2) 52,616 50,366
Other reserves and deferred credits (Note 5) 109,884 98,848
Total Reserves and Deferred Credits 614,714 554,930
Total Stockholders' Investment and Liabilities $2,010,914 $1,992,919
The accompanying notes are an integral part of these financial statements.
Consolidated Statement of Cash Flows
(Dollars in thousands) Year ended December 31
1996 1995 1994
Operating Activities
Net income (loss) $ 60,229 $ 37,980 $(23,265)
Items not requiring (providing) cash:
ARP-related charges (Note 3) - - 100,390
Depreciation 44,104 43,676 42,627
Amortization 34,881 37,196 32,790
Deferred income taxes and investment tax credits, net 3,318 (3,710) 11,022
Allowance for equity funds used during construction (851) (663) (807)
Changes in certain assets and liabilities:
Accounts receivable (3,565) (12,539) 5,175
Inventories (4,884) 595 4,230
Other current assets (308) (1,954) (1,391)
Retail fuel costs - - 32,922
Accounts payable (16,862) 12,025 4,062
Accrued taxes and interest (4,970) 30,282 (25,311)
Miscellaneous current liabilities 7,472 3,335 (2,602)
Deferred energy-management costs (5,222) (4,075) (5,789)
Maine Yankee outage accrual 8,280 (4,710) 8,197
Purchased-power contract buyouts (75) (13,405) (91,274)
Other, net 3,961 11,495 (5,604)
Net Cash Provided by Operating Activities 125,508 135,528 85,372
Investing Activities
Construction expenditures (46,922) (44,867) (42,246)
Investments in associated companies (12,059) (600) (2,004)
Changes in accounts payable - investing activities
1,889 (1,655) (679)
Net Cash Used by Investing Activities (57,092) (47,122) (44,929)
Financing Activities
Issuances:
Mortgage bonds - - 25,000
Common stock - - 927
Medium-term notes 10,000 30,000 32,000
Other Long-Term Obligations 870 - -
Finance Authority of Maine - - 66,429
Redemptions:
Mortgage bonds (11,500) - -
Preferred stock (14,000) (5,472) -
Medium-term notes (34,000) (65,000) (43,000)
Finance Authority of Maine (6,300) - -
Short-term obligations, net 7,500 (8,000) (25,500)
Other long-term obligations (1,780) (860) (860)
Funds on Deposit with Trustee (29,593) - -
Dividends:
Common stock (29,220) (29,222) (29,222)
Preferred stock (9,763) (10,287) (10,061)
Net Cash Provided (Used) by Financing Activities
(117,786) (88,841) 15,713
Net Increase (Decrease) in Cash and Cash
Equivalents (49,370) (435) 56,156
Cash and cash equivalents, beginning of year 57,677 58,112 1,956
Cash and Cash Equivalents, end of year $ 8,307 $ 57,677 $ 58,112
Supplemental Cash-Flow Information:
Cash paid during the year for:
Interest (net of amounts capitalized) $47,835 $51,127 $44,874
Income taxes (net of amounts refunded of
$0, $29,045 and $2,802 in respective years
indicated) $32,632 $(11,994) $1,568
For purposes of the statement of cash flows, the Company considers all highly
liquid instruments purchased having a maturity of three months or less to be
cash equivalents.
The accompanying notes are an integral part of these financial statements.
Consolidated Statement of Capitalization and Interim Financing
December 31
(Dollars in thousands) 1996 1995
Amount % Amount %
Capitalization (Note 7)
Common-stock investment:
Common stock, par value $5 per share:
Authorized - 80,000,000 shares
Outstanding - 32,442,752 shares in
1996 and 1995 $ 162,214 $ 162,214
Other paid-in capital 276,818 276,287
Retained earnings 72,546 51,504
Total Common-Stock Investment 511,578 40.9% 490,005 38.3%
Preferred Stock - not subject to mandatory redemption
65,571 5.2 65,571 5.1
Preferred Stock - subject to mandatory redemption
60,528 74,528
Less: current sinking fund requirements 7,000 7,000
Redeemable Preferred Stock - subject to mandatory
redemption 53,528 4.3 67,528 5.3
Long-term obligations:
Mortgage bonds 421,000 432,500
Less: unamortized debt discount 1,620 1,807
Total Mortgage Bonds 419,380 430,693
Medium-term notes 68,000 92,000
Less: unamortized debt discount - 8
Total Medium-Term Notes 68,000 91,992
Other long-term obligations:
Lease obligations 36,283 38,112
Pollution-control facility and other notes 91,699 98,909
Total Other Long-Term Obligations 127,982 137,021
Less: Current Sinking Fund Requirements and Current
Maturities 27,375 37,455
Total Long-Term Obligations 587,987 47.0 622,251 48.6
Total Capitalization 1,218,664 97.4 1,245,355 97.3
Interim financing (Note 7):
Short-term obligations 7,500 -
Current maturities of long-term obligations 25,000 34,000
Total Interim Financing 32,500 2.6 34,000 2.7
Total Capitalization and Interim Financing $1,251,164 100.0% $1,279,355 100.0%
The accompanying notes are an integral part of these financial statements.
Consolidated Statement of Changes in Common-Stock Investment
For the three years ended December 31, 1996
(Dollars in thousands) Amount at Other
par value paid-in Retained
Shares capital earnings Total
Balance - December 31, 1993 32,379,937 $161,900 $274,343 $117,146 $553,389
Net loss (23,265) (23,265)
Dividends declared:
Common stock (29,213) (29,213)
Preferred stock (10,511) (10,511)
Cost for reacquired preferred stock 675 (675)
Issues of common stock 62,815 314 613 927
Capital stock expense (4)
(4)
Balance - December 31, 1994 32,442,752 162,214 275,627 53,482 491,323
Net income 37,980 37,980
Dividends declared:
Common stock (29,199) (29,199)
Preferred stock (10,178) (10,178)
Cost for reacquired preferred stock 581 (581)
Shareholders Rights Plan redemption (324) (324)
Capital stock expense 403 403
Balance - December 31, 1995 32,442,752 162,214 276,287 51,504 490,005
Net income 60,229 60,229
Dividends declared:
Common stock (29,199) (29,199)
Preferred stock (9,452) (9,452)
Cost for reacquired preferred stock 536 (536)
Capital stock expense (5) (5)
Balance - December 31, 1996 32,442,752 $162,214 $276,818 $72,546 $511,578
The accompanying notes are an integral part of these financial statements.
Notes to Consolidated Financial Statements
Note 1: Summary of Significant Accounting Policies
General Description
Central Maine Power Company (the Company) is an investor-owned public utility
primarily engaged in the sale of electric energy at the wholesale and retail
levels to residential, commercial, industrial, and other classes of customers
in the State of Maine.
Financial Statements
The consolidated financial statements include the accounts of the Company and
its 78%-owned subsidiary, Maine Electric Power Company, Inc. (MEPCO). The
Company accounts for its investments in associated companies not subject to
consolidation using the equity method. The preparation of financial statements
in conformity with generally accepted accounting principles requires
management to make estimates and assumptions that affect the reported amounts
of assets and liabilities and disclosure of contingent assets and liabilities
at the date of the financial statements, and the reported amounts of revenues
and expenses during the reporting period. Actual results could differ from
those estimates.
Regulation
The rates, operations, accounting, and certain other practices of the Company
and MEPCO are subject to the regulatory authority of the Maine Public
Utilities Commission (MPUC) and the Federal Energy Regulatory Commission
(FERC).
Electric Operating Revenues
Electric operating revenues include amounts billed to customers and estimates
of unbilled sales and fuel costs. Through December 31, 1994, the Company's
approved tariffs provided for the recovery of the cost of fuel used in Company
generating facilities and purchased-power energy costs. The Company also
collected interest on unbilled fuel and paid interest on fuel-related
over-collections. Effective January 1, 1995, with the implementation of the
Alternative Rate Plan (ARP), these costs are no longer subject to
reconciliation through the annual fuel-cost adjustment. See Note 3,
"Regulatory Matters - Alternative Rate Plan," for further information.
Depreciation
Depreciation of electric property is calculated using the straight-line
method. The weighted average composite rate was 3.0% in each of 1996, 1995 and
1994.
Allowance for Funds Used During Construction (AFC)
An allowance for funds (including equity funds), a non-operating item, is
capitalized as an element of the cost of construction. The debt component of
AFC is classified as a reduction of interest expense, while the equity
component, a non-cash item, is classified as other income. The average AFC
rates applied to construction were 8.7% in 1996, 8.4% in 1995, and 8.9% in
1994.
Asset Valuation
The Company adopted Statement of Financial Accounting Standards No. 121,
"Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets
to be Disposed Of," effective January 1, 1996. The standard requires
impairment losses on long-lived assets to be recognized when an asset's book
value exceeds its expected future cash flows (undiscounted and without
interest). The new standard also imposes stricter criteria for retention of
regulatory-created assets by requiring that such assets be probable of future
recovery at each balance sheet date. The Company's adoption of this standard
in 1996 had no impact on accompanying financial statements. However, this may
change in the future as changes are made in the current regulatory framework
or as competitive factors influence wholesale and retail pricing in the
electric utility industry.
Deferred Charges and Other Assets
The Company defers and amortizes certain costs in a manner consistent with
authorized or probable ratemaking treatment. The Company capitalizes carrying
costs as a part of certain deferred charges, principally energy-management
costs, and classifies such carrying costs as other income. The following table
depicts the components of deferred charges and other assets at December 31,
1996, and 1995:
(Dollars in thousands) 1996 1995
NUG contract buy-outs and restructuring (Note 6) $113,796 $126,485
Energy-management costs 35,986 36,224
Postretirement benefits (Note 5) 22,962 21,849
Financing costs 20,684 24,775
Environmental site clean-up costs (Note 4) 7,876 7,375
Non-operating property, net 7,176 7,486
Electric Lifeline Program 2,368 3,603
Other, including MEPCO 27,355 32,266
Total $238,203 $260,063
Certain costs are being amortized and recovered in rates over periods ranging
from three to 30 years. Amortization expense for the next five years is shown
below:
(Dollars in thousands) Amount
1997 $26,790
1998 26,053
1999 23,910
2000 22,807
2001 19,304
Recoverable Costs of Seabrook I and Abandoned Projects
The recoverable after-tax investments in Seabrook I and abandoned projects are
reported as assets, pursuant to May 1985 and February 1991 MPUC rate orders.
The Company is allowed a current return on these assets based on its
authorized rate of return. In accordance with these rate orders, the deferred
taxes related to these recoverable costs are amortized over periods of four to
10 years. As of December 31, 1996, substantially all deferred taxes related to
Seabrook I have been amortized. The recoverable investments as of December 31,
1996, and 1995 are as follows:
December 31 Recovery
(Dollars in thousands) 1996 1995 periods ending
Recoverable costs of:
Seabrook I $141,084 $141,084 2015
Other Projects 57,491 57,491 2001
198,575 198,575
Less: accumulated amortization 108,209 102,248
Less: related income taxes 815 1,200
Total Net Recoverable Investment $ 89,551 $ 95,127
Note 2: Income Taxes
The components of federal and state income-tax provisions (benefits) reflected
in the Consolidated Statement of Earnings are as follow:
Year ended December 31
(Dollars in thousands) 1996 1995 1994
Federal:
Current $ 21,682 $ 15,965 $(18,579)
Deferred 5,751 2,278 2,175
Investment tax credits, net (464) (1,715) (2,512)
Regulatory deferred (623) (2,619) 8,379
Total Federal Taxes 26,346 13,909 (10,537)
State:
Current $ 7,022 $ 3,777 $ (6,586)
Deferred (10) 343 3,003
Regulatory deferred (1,336) (1,997) (23)
Total State Taxes 5,676 2,123 (3,606)
Total Federal and State Income Taxes $ 32,022 $ 16,032 $(14,143)
Federal and state income taxes charged to:
Operating expenses $ 30,125 $ 13,328 $ 28,300
Other income 1,897 2,704 (42,443)
$ 32,022 $ 16,032 $(14,143)
Federal income tax, excluding federal regulatory deferred taxes, differs from
the amount of tax computed by multiplying income before federal tax by the
statutory federal rate. The following table reconciles the statutory federal
rate to a rate determined by dividing the total federal income-tax expense by
income before that expense:
Year ended December 31
1996 1995 1994
Amount % Amount % Amount %
(Dollars in thousands)
Income tax expense at statutory federal
rate $30,301 35.0% $18,161 35.0% $(11,831) 35.0%
Permanent differences:
Investment tax-credit amortization
(1,482) (1.7) (1,613) (3.1) (1,613) 4.8
Dividend-received deduction (1,895) (2.2) (2,219) (4.3) (1,469) 4.3
Other, net (293) (0.3) (217) (0.4) (68) 0.2
26,631 30.8 14,112 27.2 (14,981) 44.3
Effect of timing differences for items
which receive flow through treatment:
Tax-basis repairs (1,229) (1.4) (891) (1.7) (924) 2.7
Depreciation differences flowed through
in prior years 2,327 2.7 2,291 4.4 2,315 (6.8)
Accelerated flowback of deferred taxes
on loss on abandoned generating projects
1,708 1.9 1,873 3.6 2,051 (6.1)
Deduction of removal costs (202) (0.2) (189) (0.4) (163) 0.5
Carrying costs, net 186 0.2 253 0.5 429 (1.3)
Adjustment to tax accrual for change in
rate treatment 300 0.3 - - 420 (1.2)
Excess property taxes paid - - - - (116) 0.4
IRS audit resolution regarding
depreciation methods (3,230) (3.7) - - - -
Provision for deferred taxes relating
to normalization of certain short-term
timing differences*
- - (2,545) (4.9) - -
Other, net (145) (0.2) (995) (1.9) 432 (1.3)
Federal Income Tax Expense and
Effective Rate $26,346 30.4% $13,909 26.8% $(10,537) 31.2%
*During 1995, the Company adjusted the deferred tax balances for certain
normalized items (Note 3).
The Company and MEPCO record deferred income-tax expense in accordance with
regulatory authority; they also defer investment and energy tax credits and
amortize them over the estimated lives of the assets that generated the
credits.
The Company recognizes deferred tax liabilities and assets for the expected
future tax consequences of events that have been included in the financial
statements or tax returns as required under Statement of Financial Accounting
Standards No. 109, "Accounting for Income Taxes" (SFAS No. 109). Under this
method, effective January 1, 1993, deferred tax liabilities and assets are
determined based on the difference between the financial statement and tax
basis of assets and liabilities using the enacted tax rates in effect in the
year in which the differences are expected to reverse.
At-adoption adjustments to accumulated deferred taxes were required, as well
as the recognition of a liability to ratepayers for deferred taxes established
in excess of the amount calculated using income-tax rates applicable to future
periods. Additionally, deferred taxes were recorded for the cumulative timing
differences for which no deferred taxes had been recorded previously.
Concurrently, the Company, in accordance with Statement of Financial
Accounting Standards No. 71, "Accounting for the Effects of Certain Types of
Regulation" (SFAS No. 71), recorded a regulatory asset representing its
expectations that, consistent with current and expected ratemaking, it will
collect these additional taxes recorded through rates when they are paid in
the future.
A valuation allowance has not been recorded at December 31, 1996, and 1995, as
the Company expects that all deferred income tax assets will be realized in
the future.
Accumulated deferred income taxes consisted of the following in 1996 and 1995:
(Dollars in thousands) 1996 1995
Deferred tax assets resulting from:
Investment tax credits, net $ 22,050 $ 22,370
Regulatory liabilities 17,919 13,882
Alternative minimum tax 10,241 23,850
All other 26,588 22,545
76,798 82,647
Deferred tax liabilities resulting from:
Property 288,370 273,565
Abandoned plant 61,729 65,573
Regulatory assets 85,508 96,577
435,607 435,715
Accumulated deferred income taxes, end of year, net $358,809 $353,068
Accumulated deferred income taxes, recorded as:
Accumulated deferred income taxes $357,994 $351,868
Recoverable costs of Seabrook 1 and abandoned projects,
net 815 1,200
$358,809 $353,068
Note 3: Regulatory Matters
Alternative Rate Plan
In December 1994, the MPUC approved a stipulation signed by most of the
parties to the Company's ARP proceeding. This follow-up proceeding to the
Company's 1993 base-rate case was ordered by the MPUC in an effort to develop
a five-year plan containing price-cap, profit-sharing, and pricing-flexibility
components. Although the ARP is a major reform, the MPUC is continuing to
regulate the Company's operations and prices, provide for continued recovery
of deferred costs, and specify a range for its authorized rate of return. The
ARP was adopted effective January 1, 1995.
The Company believes the ARP provides the benefits of needed pricing
flexibility to set prices between defined floor and ceiling levels in three
service categories: (1) existing customer classes, (2) new customer classes
for optional targeted services, and (3) special-rate contracts. The Company
believes that the added flexibility will position it more favorably to meet
the competition from other energy sources. See Note 4 to Consolidated
Financial Statements, "Commitments and Contingencies - Competition," for a
discussion of actions taken by the Company under the ARP's pricing flexibility
provisions.
The ARP also contains provisions to protect the Company and ratepayers against
unforeseen adverse results from its operation. These include review by the
MPUC if the Company's actual return on equity falls outside a designated
range, a mid-period review of the ARP by the MPUC in 1997 (including possible
modification or termination), and a "final" review by the MPUC in 1999 to
determine whether or with what changes the ARP should continue in effect after
1999. The Company will submit its 1997 compliance filing and the mid-period
review filing in March 1997. The mid-period review decision is expected from
the MPUC by September 30, 1997.
The Company believes, as stated in the MPUC's order approving the ARP, that
operation under the ARP continues to meet the criteria of SFAS No. 71. In its
order, the MPUC reaffirmed the applicability of previous accounting orders
allowing the Company to reflect amounts as deferred charges and regulatory
assets. As a result, the Company will continue to apply the provisions of SFAS
No. 71 to its accounting transactions and its future financial statements.
The ARP contains a mechanism that provides price caps on the Company's retail
rates to increase annually on July 1, commencing July 1, 1995, by a percentage
combining (1) a price index, (2) a productivity offset, (3) a sharing
mechanism, and (4) flow-through items and mandated costs. The price cap
applies to all of the Company's retail rates, including the Company's
fuel-and-purchased power cost, which previously had been treated separately.
Under the ARP, fuel expense is no longer subject to reconciliation or specific
rate recovery, but is subject to the annual indexed price-cap changes.
A specified standard inflation index is the basis for each annual price-cap
change. The inflation index is reduced by the sum of two productivity factors,
a general productivity offset of 1.0%, (0.5% for 1995), and a second
formula-based offset that started in 1996 intended to reflect the limited
effect of inflation on the Company's purchased-power costs during the proposed
five-year initial term of the ARP.
The sharing mechanism will adjust the subsequent year's July price-cap change
in the event the Company's earnings are outside a range of 350 basis points
above or below the Company's allowed return on equity, starting at the 10.55%
allowed return (1995) and indexed annually for changes in capital costs.
Outside that range, profits and losses would be shared equally by the Company
and ratepayers in computing the price-cap adjustment. This feature commenced
with the price-cap change of July 1, 1996, and reflected 1995 results.
The ARP also provides for partial flow-through to ratepayers of cost savings
from non-utility generator contract buy-outs and restructuring, recovery of
energy-management costs, penalties for failure to attain customer-service and
energy-efficiency targets, and specific recovery of half the costs of the
transition to Statement of Financial Accounting Standards No. 106, "Accounting
for Postretirement Benefits Other Than Pensions" (SFAS No. 106), the remaining
50% to be recovered through the annual price-cap change. The ARP also
generally defines mandated costs that would be recoverable by the Company
notwithstanding the index-based price cap. To receive such treatment, a
mandated cost's revenue requirement must exceed $3 million and have a
disproportionate effect on the Company or the electric-power industry.
Effective July 1, 1995, the MPUC approved a 2.43% increase pursuant to the
annual price-change provision in the ARP. The primary component of the
increase was the inflation-index change of 2.92%, reduced by a productivity
offset of 0.5%, and increased by .01% for flowthrough items and mandated
costs. On June 28, 1996, the MPUC approved a 1.26% increase in rates under
the ARP effective July 1, 1996. The components of the increase included the
inflation-index of 2.55% and earnings sharing and mandated cost items of
0.64%, reduced by the productivity offset of 1.0% and sharing of contract
restructuring and buyout savings of 0.93%.
The Company agreed in the ARP negotiations to record charges in 1994
reflecting the write-off of approximately $100 million ($60 million, net of
tax, or $1.85 per share) which consisted of undercollected balance of fuel and
purchased power costs, unrecovered energy-management costs, unrecovered
unbilled ERAM revenues and unrecovered deferred charges related to the
possible extension of the operating life of one of the Company's generating
stations. The $100-million charge was included in "Other income (expense) -
Other, net" on the Consolidated Statement of Earnings. The $40-million tax
impact was included in "Other income (expense) - Income taxes." These
charges, with the other provisions of the ARP, lessen the impact of future
price increases for MPUC-mandated and fuel-related costs.
Restructuring
The Maine Legislature in 1995 took action by Legislative Resolve (Resolve) to
develop recommendations for the MPUC on the future structure of the electric
utility industry in Maine. The Resolve stated that the findings of the MPUC
would have no legal effect, but that the MPUC's study would"...provide
information to the Legislature in order to allow the Legislature to make
informed decisions when it evaluates those plans"
In accordance with the Resolve, on December 31, 1996, the MPUC, pursuant to
the mandate of the Maine Legislature, filed its Report and Recommended Plan
for Utility Industry Restructuring (Restructuring Report).
The Company believes there are many uncertainties associated with any major
restructuring of the electric utility industry in Maine. Among them are: the
actions that will be ultimately taken by the legislature and the MPUC; the
role of the FERC in any restructuring involving the Company and the ultimate
positions it will take on relevant issues within its jurisdiction; to what
extent the United States Congress will become involved in resolving or
redefining the issues through legislative action and, if so, with what
results; whether the necessary political consensus can be reached on the
significant and complex issues involved in changing the long-standing
structure of the electric-utility industry; and, particularly with respect to
the Company, to what extent utilities will be permitted to recover strandable
costs.
The Company has substantial exposure to cost stranding relative to its size.
The Company estimated its net-present-value strandable costs could be
approximately $2 billion as of January 1, 1996. These costs represent the
excess costs of purchased-power obligations and the Company's own generating
costs over the market value of the power, and the costs of deferred charges
and other regulatory assets. Of the $2 billion, approximately $1.3 billion is
related to above-market costs of purchased-power obligations, approximately
$200 million is related to estimated net above-market cost of the Company's
own generation, and the remaining $500 million is related to deferred
regulatory assets.
Meeting the Requirements of SFAS No. 71
The Company continues to meet the requirements of SFAS No. 71, as described
above. The standard provides specialized accounting for regulated
enterprises, which requires recognition of assets and liabilities that
enterprises in general could not record. Examples of regulatory assets
include deferred income taxes associated with previously flowed through items,
NUG buyout costs, losses on abandoned plants, deferral of postemployment
benefit costs, and losses on debt refinancing. If an entity no longer meets
the requirements of SFAS No. 71, then regulatory assets and liabilities must
be written off.
The ARP provides incentive-based rates intended to recover the cost of service
plus a rate of return on the Company's investment together with a sharing of
the costs or earnings between ratepayers and the shareholders should the
earnings be less than or exceed a target rate of return. The Company has
received recognition from the MPUC that the rates implemented as a result of
the ARP continue to provide specific recovery of costs deferred in prior
periods.
The MPUC's Restructuring Report submitted to the Legislature in December 1996
recognizes that a reasonable opportunity to recover strandable costs is
essential to a successful transition to competition, with incentives for the
Company to mitigate such costs where practicable. The Company is actively
pursuing securitization of regulatory assets, which would provide further
assurance of their recoverability.
Open-Access Transmission Service Ruling
On April 24, 1996, FERC issued Order No. 888, which requires all public
utilities that own, control or operate facilities used for transmitting
electric energy in interstate commerce to file open access non-discriminatory
transmission tariffs that offer both load-based, network and contract-based,
point-to-point service, including ancillary service to eligible customers
containing minimum terms and conditions of non-discriminatory service. This
service must be comparable to the service they provide themselves at the
wholesale level; in fact, these utilities must take wholesale transmission
service they provide themselves under the filed tariffs. The order also
permits public utilities and transmitting utilities the opportunity to recover
legitimate, prudent and verifiable wholesale stranded costs associated with
providing open access and certain transmission services. It further requires
public utilities to functionally separate transmission from generation
marketing functions and communications. The intent of this order is to
promote the transition of the electric utility industry to open competition.
Order No. 888 also clarifies federal and state jurisdiction over transmission
in interstate commerce and local distribution and provides for deference of
certain issues to state recommendations.
On July 9, 1996, the Company and MEPCO submitted its compliance filings to
meet the new pro forma tariff non-price minimum terms and conditions of
non-discriminatory transmission. Since July 9, 1996, the Company and MEPCO
have been transmitting energy pursuant to their filed tariffs, subject to
refund. FERC subsequently issued Order No. 888-A, which reaffirms Order No.
888 and clarifies certain terms.
Also on April 24, 1996, FERC issued Order No. 889 which requires public
utilities to functionally separate their wholesale power marketing and
transmission operation functions and to obtain information about their
transmission system for their own wholesale power transactions in the same way
their competitors do through the Open Access Same-time Information System
(OASIS). The rule also prescribed standards of conduct and protocols for
obtaining the information. The standards of conduct are designed to prevent
employees of a public utility engaged in marketing functions from obtaining
preferential information. The Company participated in efforts to develop a
regional OASIS, which was operational January 3, 1997. FERC subsequently
approved a New England Power Pool-wide Open Access Tariff, subject to refund
and issuance of further orders. The Company also participated in revising the
New England Power Pool Agreement, which is pending FERC approval.
Note 4: Commitments and Contingencies
Construction Program
The Company's plans for improving and expanding generating, transmission,
distribution facilities, and power-supply sources are under continuing review.
Actual construction expenditures will depend upon the availability of capital
and other resources, load forecasts, customer growth, and general business
conditions. The Company's current forecast of capital expenditures for the
five-year period 1997 through 2001, are as follows:
(Dollars in millions) 1997 1998-2001 Total
Type of Facilities:
Generating projects $ 8 $ 33 $ 41
Transmission 3 14 17
Distribution 27 124 151
General facilities and other 18 75 93
Total Estimated Capital Expenditures $56 $246 $302
Competition
In September 1994, the Town of Madison's Department of Electric Works
(Madison), a wholesale customer of the Company, began receiving power from
Northeast Utilities (NU) as a result of a competitive bidding process
available under the federal Energy Policy Act of 1992. Substantially all of
the 45 megawatts involved supply the large paper-making facility of Madison
Paper Industries (MPI) in Madison's service territory that had been served
directly by the Company under a special service agreement with Madison during
the preceding 12 years.
The MPUC approved the stipulation filed by the Company, Madison, and NU,
whereby the related MPUC and FERC regulatory proceedings were deemed to be
settled among the parties, and the Company withdrew its request for
compensation for stranded costs. In return, NU agreed to pay the Company $8.4
million over a seven-year period, MPI agreed to pay the Company $1.4 million
over a three-year period, a transmission rate was agreed upon for the
Company's transmission service to Madison commencing September 1, 1994, and the
parties agreed that Madison would be supplied by NU through 2003, with Madison
having an option for an additional five years. In addition, NU and the Company
agreed to a five-year capacity exchange arrangement designed to achieve
significant replacement-power cost savings for the Company when the Company's
largest source of generation, the Maine Yankee Plant, is off-line, and
provides Maine Yankee power to NU when certain NU facilities are shut down.
The agreement provides more economic benefit to the Company than if it had
under-bid NU for Madison's business, but less than if Madison stayed on the
Company's system at the former rates. The Company records income under this
contract as the amounts are received.
Madison was the largest of the Company's three wholesale customers. The
Company later reached agreement with its other two wholesale customers to
continue to supply them at negotiated prices and margins that are lower than
the previous averages. Subsequent to year end, these customers initiated a
request for proposals to supply their energy needs after 1998.
During 1994, the Company engaged in discussions with its large general-service
customers. Those customers have alternative energy options that the Company
believed needed to be addressed by lowering its applicable tariffs. In
response to those discussions, in November 1994, the Company filed revised
tariff schedules lowering prices 15% for its two high-voltage
transmission-level rate classes.
The Company then entered into five-year definitive agreements with 18 of these
customers that lock-in non-cumulative rate reductions of 15% for the three
years 1995 through 1997, 16% for 1998, and 18% for 1999, below the December 1,
1994, levels. These contracts also protect these customers from price
increases that might otherwise be allowed under the ARP. The participating
customers agreed to take electrical service from the Company for five years
and not to switch fuels, install new self-generation equipment, or seek
another supplier of electricity for existing electrical load during that
period. New electrical load in excess of a stated minimum level could be
served by other sources, but the Company could compete for that load.
The Company believes that without offering the competitive pricing provided in
the agreements, a number of these customers would be likely to install
additional self-generation or take other steps to decrease their electricity
purchases from the Company. The revenue loss from such a usage shift could
have been substantial.
The Company estimates that based on the rate reductions effective January 1,
1995, its gross revenues were approximately $27 million lower in 1995, and
approximately $45 million lower in 1996, than would have been the case if
these customers continued to pay full retail rates without reducing their
purchases from the Company.
However, these rate reductions were negotiated giving consideration to
important related cost savings. Electricity price changes affect the cost of
some NUG power contracts. The reduction in rates to large customers reduced
purchased-power costs by approximately $20 million as a result of linkage
between retail tariffs and some contract prices.
Legal and Environmental Matters
The Company is a party in legal and administrative proceedings that arise in
the normal course of business. In connection with one such proceeding, the
Company has been named a potentially responsible party (PRP) and has been
incurring costs to determine the best method of cleaning up an Augusta, Maine,
site formerly owned by a salvage company and identified by the Environmental
Protection Agency (EPA) as containing soil contaminated by polychlorinated
biphenyls (PCBs) from equipment originally owned by the Company.
In 1995, the EPA approved a remedy to adjust the soil cleanup standard to 10
parts per million. The cleanup method using solvent extraction was found to
be technically infeasable. On July 30, 1996, the EPA approved the off-site
disposal of the contaminated soil to a EPA licensed secure landfill.
The Company believes that its share of the remaining costs of the cleanup
under the approved remedy could total approximately $2.7 million to $4.2
million. This estimate is net of an agreed partial insurance recovery and the
1993 court-ordered contribution of 41% from Westinghouse Electric Corp., but
does not reflect any possible contributions from other insurance carriers the
Company has sued, or from any other parties. The Company has recorded an
estimated liability of $2.7 million and an equal regulatory asset, reflecting
an accounting order to defer such costs and the anticipated ratemaking
recovery of such costs when ultimately paid. In addition, the Company has
deferred, as a regulatory asset, $5.1 million of costs incurred through
December 31, 1996.
The Company cannot predict with certainty the level and timing of the cleanup
costs, the extent they will be covered by insurance, or their ratemaking
treatment, but believes it should recover substantially all of such costs
through insurance and rates.
Other Environmental Sites
The Company has been named as a PRP at eleven former manufactured gas plant
sites, six former waste oil sites, and two former pole treatment and storage
locations. The Company believes that its share of the investigation and
cleanup and other costs associated with these sites could total approximately
$0.9 million which was charged to income in 1996. The Company believes that
the ultimate resolution of current legal and environmental proceedings will
not have a material adverse effect on its financial condition.
Nuclear Insurance
The Price-Anderson Act (Act) is a federal statute providing, among other
things, a limit on the maximum liability for damages resulting from a nuclear
incident. The liability is provided for by existing private insurance and by
retrospective assessments for costs in excess of that covered by insurance, up
to $79.3 million for each reactor owned, with a maximum assessment of $10
million per reactor in any year. Based on the Company's indirect ownership in
four nuclear-generation facilities (See Note 6, "Capacity Arrangements - Power
Agreements") and its 2.5% ownership interest in the Millstone Unit No. 3
nuclear plant, the Company's retrospective premium could be as high as $6
million in any year, for a cumulative total of $47.6 million, exclusive of the
effect of inflation indexing and a 5% surcharge in the event that total public
liability claims from a nuclear incident should exceed the funds available to
pay such claims.
In addition to the insurance required by the Act, the nuclear generating
facilities referenced above carry additional nuclear property-damage
insurance. This additional insurance is provided from commercial sources and
from the nuclear electric-utility industry's insurance company through a
combination of current premiums and retrospective premium adjustments. Based
on current premiums and the Company's indirect and direct ownership in nuclear
generating facilities, this adjustment could range up to approximately $7.7
million annually.
Note 5: Pension and Other Post-Employment Benefits
Pension Benefits
The Company has two separate non-contributory, defined-benefit plans that
cover substantially all of its union and non-union employees. The Company's
funding policy is to contribute amounts to the separate plans that are
sufficient to meet the funding requirements set forth in the Employee
Retirement Income Security Act (ERISA), plus such additional amounts as the
Company may determine to be appropriate. Plan benefits under the non-union
retirement plan are based on average final earnings, as defined within the
plan, and length of employee service; benefits under the union plan are based
on average career earnings and length of employee service.
During 1995, the Company offered a Special Retirement Offer (SRO) to
qualifying employees. Approximately 200 employees accepted the offer. The
$7-million cost of the SRO was included in pension expense. As part of the
SRO, the plans were amended to add five years to age and five years to
credited service for all plan participants for purposes of eligibility and
early retirement discounts. Early Retirement Incentive Program (ERIP) expenses
for 1994 relate to a 1991 ERIP reflected in accordance with an MPUC accounting
order.
A summary of the components of net periodic pension cost for the non-union and
union defined-benefit plans in 1996, 1995 and 1994 follows:
1996 1995 1994
(Dollars in Non- Non- Non-
thousands) union Union union Union union Union
Service cost -
benefits earned
during the period $2,334 $1,780 $2,014 $1,414 $2,367 $1,684
Interest cost on
projected benefit
obligation 5,225 3,852 5,653 3,889 5,469 3,816
Return on plan
assets (8,168) (5,036) (16,135) (9,786) 2,336 1,397
Net amortization
and deferral 2,911 1,536 10,030 6,028 (8,174) (5,311)
Early Retirement
Incentive Programs
- - 3,859 3,141 992 1,457
Net Periodic
Pension Cost $2,302 $2,132 $5,421 $4,686 $2,990 $3,043
Assumptions used in accounting for the non-union and union defined-benefit
plans in 1996, 1995, and 1994 are as follows:
1996 1995 1994
Weighted average discount rate 7.50% 7.25% 8.25%
Rate of increase in future compensation levels 4.5% 4.5% 5.0%
Expected long-term return on assets 8.5% 8.5% 8.5%
The following table sets forth the actuarial present value of pension-benefit
obligations, the funded status of the plans, and the liabilities recognized on
the Company's balance sheet at December 31, 1996, and 1995:
1996 1995
(Dollars in thousands) Non- Non-
union Union union Union
Actuarial present value of benefit obligations:
Vested benefit obligation $62,461 $47,617 $64,916 $47,948
Accumulated benefit obligation 64,394 48,783 $64,916 $47,948
Projected benefit obligation 75,570 55,688 $77,939 $53,735
Plan assets at estimated market value (primarily
stocks, bonds, and guaranteed annuity contracts) 77,996 48,091 73,973 45,061
Funded status - projected benefit obligation in
excess of or (less than) plan assets (2,426) 7,597 3,966 8,674
Unrecognized prior service cost (1,785) (1,481) (1,940) (1,610)
Unrecognized net gain 19,819 3,745 11,309 2,530
Unrecognized (net obligation) net asset (163) 1,675 (192) 1,945
Net Pension Liability Recognized in the
Balance Sheet $15,445 $11,536 $13,143 $11,539
Savings Plan
The Company offers an employee savings plan to all employees which allows
participants to invest from 2% to 15% of their salaries among several
alternatives. An employer contribution equal to 60% of the first 5% of the
employees' contributions is initially invested in Company common stock. The
Company's contributions to the savings-plan trust were $1.7 million in 1996,
$1.6 million in 1995, and $1.8 million in 1994.
Other Post-Employment Benefits
In addition to pension and savings-plan benefits, the Company provides certain
health-care and life-insurance benefits for substantially all of its retired
employees.
The MPUC approved a rulemaking on SFAS No. 106, effective July 20, 1993, that
adopted the accrual method of accounting for the expected cost of such
benefits during the employees' years of service, and authorized the
establishment of a regulatory asset for the deferral of such costs until they
are "phased-in" for ratemaking purposes. The effect of the change can be
reflected in annual expenses over the active service life of employees or a
period of 20 years, rather than in the year of adoption.
The MPUC prescribes the maximum amortization period of the average remaining
service life of active employees or 20 years, whichever is longer, for the
transition obligation. The Company is utilizing a 20 year amortization
period. Segregation in an external fund is required for amounts collected in
rates. The Company is proposing initial funding of $3 million annually. Until
amounts are funded, no return on assets will be reflected in postretirement
benefit cost.
As a result of the MPUC order, the Company records the cost of these benefits
by charging expense in the period recovered through rates ($9.8 million in
1996, $6.7 million in 1995, and $5.5 million in 1994), with the excess over
that amount of $1.1 million in 1996, $6.2 million in 1995 and $7.1 million in
1994, deferred for future recovery. The total amount defined as a regulatory
asset as of December 31, 1996 was $23 million. Concurrent with the initial
ARP price change, the Company began to phase in the cost of SFAS No. 106 over
a three-year period, $3 million for the first year beginning July 1, 1995 and
an additional $2.1 million for the year beginning July 1, 1996. The amounts
deferred until that point are being amortized over the same period as the
transition obligation. A summary of the components of net periodic
postretirement benefit cost for the plan in 1996, 1995 and 1994 follows:
(Dollars in thousands) 1996 1995 1994
Service cost $ 1,347 $ 846 $ 1,472
Interest on accumulated postretirement benefit
obligation 5,720 7,389 6,712
Special retirement offer - 200 -
Amortization of transition obligation 4,080 4,606 4,606
Amortization of prior service cost 35 42 -
Amortization of gain (329) (188) (171)
Postretirement benefits expense 10,853 12,895 12,619
Deferred postretirement benefits expense 1,056 6,204 7,108
Postretirement Benefit Expense Recognized in the
Statement of Earnings $ 9,797 $ 6,691 $ 5,511
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, 1996 and 1995:
(Dollars in thousands) 1996 1995
Accumulated postretirement benefit obligation:
Retirees $ 51,815 $ 87,632
Fully eligible active plan participants 2,707 4,791
Other active plan participants 19,381 15,069
Total accumulated postretirement benefit obligation 73,903 107,492
Plan assets, at fair value 849 879
Accumulated postretirement benefits obligation in
excess of plan assets 73,054 106,613
Unrecognized net gain (loss) 15,987 (2,511)
Unrecognized prior service cost (5) (1,131)
Unrecognized transition obligation (59,267) (78,303)
Accrued Postretirement Benefit Cost Recognized
in the Balance Sheet $ 29,769 $ 24,668
The assumed health-care cost-trend rates range from 5.7% to 6.8% for 1996,
reducing to 5.0% overall over a period of 25 years. Rates range from 6.4% to
9.3% for 1995, reducing to 5.0% overall, over a period of 10 years. Rates
range from 6.8% to 10.4% for 1994, reducing to 5.0% overall, over a period of
10 years. The effect of a one-percentage-point increase in the assumed
health-care cost-trend rate for each future year would increase the aggregate
of the service and interest-cost components of the net periodic postretirement
benefit cost by $0.7 million and the accumulated postretirement benefit
obligation by $8.9 million. Additional assumptions used in accounting for the
postretirement benefit plan in 1996, 1995 and 1994 are as follows:
1996 1995 1994
Weighted-average discount rate 7.50% 7.25% 8.25%
Rate of increase in future compensation levels 4.50% 4.50% 5.0%
The Company is exploring alternatives for mitigating the cost of
postretirement benefits and for funding its obligations. These alternatives
include mechanisms to fund the obligation prior to actual payment of benefits,
plan-design changes to limit future expense increases, and additional
cost-control and cost-sharing programs.
Effective September 1, 1996, the Company implemented a phase-out of the
long-term care portion of its retiree medical plans. With the exception of
one group of approximately 200 retirees, all benefits of this type will be
eliminated by September 1, 2002. These changes decreased Plan liabilities by
approximately $16 million, based on 1996 actuarial valuation results.
Note 6: Capacity Arrangements
Power Agreements
The Company, through certain equity interests, owns a portion of the
generating capacity and energy production of four nuclear generating
facilities (the Yankee companies), two of which have been permanently shut
down, and is obligated to pay its proportionate share of costs, which include
fuel, depreciation, operation-and-maintenance expenses, a return on invested
capital, and the estimated cost of decommissioning the nuclear plants.
Pertinent data related to these power agreements as of December 31, 1996, are
as follows:
(Dollars in thousands) Maine Yankee Vermont Connecticut Yankee
Yankee Yankee* Atomic*
Ownership share 38% 4% 6% 9.5%
Contract expiration date 2008 2012 1998 2000
Capacity (MW) 879 531 -- --
Company's share of: Capacity (MW)
329 19 -- --
Estimated 1996 costs $ 79,282 $ 6,525 $ 12,355 $ 4,896
Long-term obligations and redeemable
preferred stock $ 94,559 $ 6,950 $ 10,447 $ --
Estimated decommissioning obligation $118,586 $ 13,150 $ 45,769 $16,463
Accumulated decommissioning fund $ 61,254 $ 5,474 $ 12,269 $11,408
* See following for discussion on Connecticut Yankee and Yankee Atomic
Under the terms of its agreements, the Company pays its ownership share (or
entitlement share) of estimated decommissioning expense to each of the Yankee
companies and records such payments as a cost of purchased power. Effective
August 16, 1988, Maine Yankee Atomic Power Company (Maine Yankee) began
collecting $9.1 million annually for decommissioning. In 1994, Maine Yankee,
pursuant to FERC authorization, increased its annual collection to $14.9
million and reduced its return on common equity to 10.65%, for a total
increase in rates of approximately $3.4 million. The increase in
decommissioning collection is based on the estimated cost of decommissioning
the Maine Yankee Plant, assuming dismantling and removal, of $317 million (in
1993 dollars) based on a 1993 external engineering study. Accumulated
decommissioning funds were $163.5 million as of December 31, 1996. The
estimated cost of decommissioning nuclear plants is subject to change due to
the evolving technology of decommissioning and the possibility of new legal
requirements.
The Maine Yankee Plant, like other pressurized water reactors, experienced
degradation of its steam generator tubes, principally in the form of
circumferential cracking, which, until early 1995, was believed to be limited
to a relatively small number of tubes. During a refueling and maintenance
shutdown in February 1995, Maine Yankee detected through new inspection
methods that approximately 60% of the Plant's 17,000 steam generator tubes
appeared to have defects.
Following a detailed analysis of safety, technical and financial
considerations, Maine Yankee repaired the tubes by inserting and welding short
reinforcing sleeves of an improved material in substantially all of the
Plant's steam generator tubes, which was completed in December 1995. The
Company's approximately $10-million share of the repair costs adversely
affected the Company's 1995 earnings by $0.18 per share, net of taxes, in
spite of significant cost-reduction measures implemented by both the Company
and Maine Yankee. In addition, the Company's incremental replacement-power
costs during the outage totaled approximately $29 million, or $0.52 per share,
net of taxes, for 1995.
Also in December 1995, the Nuclear Regulatory Commission's (NRC) Office of the
Inspector General (OIG) and its Office of Investigations (OI) initiated
separate investigations of certain anonymous "whistleblower" allegations of
wrongdoing by Maine Yankee and Yankee Atomic Electric Company (Yankee Atomic)
in 1988 and 1989 in connection with operating license amendments. On May 9,
1996, the OIG, which was responsible for investigating only the actions of the
NRC staff and not those of Maine Yankee or Yankee Atomic, issued its report on
its investigation. The report found deficiencies in the NRC staff's review,
documentation, and communications practices in connection with the license
amendments, as well as "significant indications of possible licensee
violations of NRC requirements and regulations." Any such violations by Maine
Yankee are within the purview of the OI investigation, which, with related
issues, is being reviewed by the United States Department of Justice. A
separate internal investigation commissioned by the boards of directors of
Maine Yankee and Yankee Atomic and conducted by an independent law firm noted
several areas that could have been improved, including regulatory
communications, definition of responsibilities between Maine Yankee and Yankee
Atomic, and documentation and tracking of regulatory compliance, but found no
wrongdoing by Maine Yankee or Yankee Atomic or any of their employees. Issues
raised as a result of the anonymous allegations caused the NRC to limit the
Plant to an operating level of approximately 90% of its full thermal capacity,
pending resolution of those issues. The Company cannot predict the results of
the investigations by the OI and Department of Justice.
On January 11, 1996, Maine Yankee began start-up operations and was up to a
90% generation level on January 24, 1996. The Plant operated substantially at
that level until July 20, 1996, when it was taken off-line after a
comprehensive review by Maine Yankee of the Plant's systems and equipment
revealed a need to add pressure-relief capacity to the Plant's primary
component cooling system. On August 18, 1996, while the Plant was in the
restart process, Maine Yankee conducted a review of its electrical circuitry
testing procedures pursuant to a generic NRC letter to nuclear-plant licensees
that was intended to ensure that every feature of every safety system be
routinely tested. During the expanded review, Maine Yankee found a deficiency
in an electrical circuit of a safety system and therefore elected to conduct
an intensified review of other safety-related circuits to resolve immediately
any questions as to the adequacy of related testing procedures. The Plant
returned to the 90% operating level on September 3, 1996.
On December 6, 1996, Maine Yankee took the Plant off-line to resolve
cable-separation and associated issues. On January 3, 1997, Maine Yankee
announced that it would use the opportunity presented by that outage to
inspect the Plant's 217 fuel assemblies, since daily monitoring had indicated
evidence of a small number of defective fuel rods. As a result of the
inspection, Maine Yankee determined that all of the assemblies manufactured by
one supplier and currently in the reactor core (approximately one-third of the
total) have to be replaced. Maine Yankee will therefore keep the Plant
off-line for refueling, which had previously been scheduled for late 1997. In
addition, Maine Yankee will make use of the outage to inspect the Plant's
steam generators for deterioration beyond that which was repaired during the
extended 1995 outage. Degradation of steam generators of the age and design
of those in use in the Plant has been identified at other plants.
In January 1997, the NRC announced that it had placed the Plant on its "watch
list" in "Category 2", which includes plants that display "weaknesses that
warrant increased NRC attention", but which are not severe enough to warrant a
shut-down order. Plants in category 2 remain in that category "until the
licensee demonstrates a period of improved performance." The Plant is one of
fourteen nuclear units on the watch list announced that day by the NRC, which
regulates slightly over 100 civilian nuclear power plants in the United States.
After year end, Maine Yankee and Entergy Nuclear, Inc. (Entergy), which is a
subsidiary of Entergy Corporation, a Louisiana-based utility holding company
and leading nuclear plant operator, entered into a contract under which
Entergy is providing management services to Maine Yankee at the same time,
officials from Entergy assumed management positions, including President, at
Maine Yankee.
The Maine Yankee nuclear plant was shut down on December 6, 1996, for
inspection and repairs. While the plant is out service, Maine Yankee must, in
addition to replacing the fuel assemblies, conduct an intensive inspection of
its steam generators, resolve cable-separation issues and other regulatory
issues, and obtain the approval of the NRC to restart the plant. The Company
believes the plant will be out of service at least until August 1997, but
cannot predict when or whether all of the regulatory and operational issues
will be satisfactorily resolved or what effect the repairs and improvements to
the plant will have on the economics of operating the plant.
The Company will incur significantly higher costs in 1997 for its share of
inspection, repairs and refueling costs at Maine Yankee and will also need to
purchase replacement power while the plant is out of service. While the amount
of higher costs is uncertain, Maine Yankee has indicated that it expects it
operations and maintenance costs to increase by up to approximately $45
million in 1997, before refueling costs. The Company's share of such costs
based on its power entitlement of approximately 38% would be up to
approximately $17 million. In addition, the Company estimates its share of the
refueling costs will amount to approximately $15 million, of which $10.4
million has been accrued as of December 31, 1996. The Company has been
incurring incremental replacement-power costs of approximately $1 million per
week while the plant has been out of service and expects such costs to
continue at approximately the same rate until the plant returns to service.
The impact of these higher nuclear related costs on the Company's 1997
financial results will be significant and is likely to trigger the low
earnings bandwidth provision of the ARP. Under the ARP actual earnings for
1997 outside a bandwidth of 350 basis points, above or below a 10.68% rate of
return allowance, triggers the profit sharing mechanism. A return below the
low end of the range provides for additional revenue through rates equal to
one-half of the difference between the actual earned rate of return and the
7.18% (10.68 - 3.50) low end of the bandwidth. While the Company believes that
the profit sharing mechanism is likely to be triggered in 1997, it cannot
predict the amount, if any, of additional revenues that may ultimately result.
Condensed financial information on Maine Yankee Atomic Power Company is as
follows:
(Dollars in thousands) 1996 1995 1994
Earnings:
Operating revenues $185,661 $205,977 $173,857
Operating income 17,150 18,527 16,223
Net income 8,106 8,571 8,573
Earnings applicable to common stock 6,637 7,057 7,014
Company's Equity Share of Net Earnings $ 2,522 $ 2,682 $ 2,665
Investment:
Net electric property and nuclear fuel $222,360 $242,399 $254,820
Current assets 44,979 34,799 38,950
Deferred charges and other assets 334,722 303,760 256,140
Total Assets 602,061 580,958 549,910
Less:
Redeemable preferred stock 18,000 18,600 19,200
Long-term obligations 223,572 224,185 226,491
Current liabilities 34,265 30,904 29,210
Reserves and deferred credits 255,472 236,653 208,100
Net Assets $ 70,752 $ 70,616 $ 66,909
Company's Equity in Net Assets $ 26,886 $ 26,834 $ 25,425
In December 1996, the Board of Directors of Connecticut Yankee Atomic Power
Company announced a permanent shutdown of the Connecticut Yankee plant in
Haddam, Connecticut, and decided to decommission the plant for economic
reasons. An economic analysis conducted by Connecticut Yankee estimates that
the early closing of the Plant would save over $100 million (net present
value) over its remaining license life to the year 2007, compared with the
costs of continued operation. The Company has a 6% equity interest in
Connecticut Yankee, totaling approximately $6.4 million at December 31, 1996.
The plant did not operate after July 22, 1996. The Company estimates its
share of the cost of Connecticut Yankee's continued compliance with
regulatory requirements, recovery of its plant investments, decommissioning
and closing the plant to be approximately $45.8 million and has recorded a
regulatory asset and a liability on the consolidated balance sheet. The
Company is currently recovering through rates an amount adequate to recover
these expenses.
On February 26, 1992, the Board of Directors of Yankee Atomic Electric Company
(Yankee Atomic) decided to permanently discontinue power operation at the
Yankee Atomic Plant in Rowe, Massachusetts, and to decommission that
facility. The Company relied on Yankee Atomic for less than 1% of the
Company's system capacity. Its 9.5% equity investment in Yankee Atomic is
approximately $2.2 million.
On March 18, 1993, the FERC approved a settlement agreement regarding the
Yankee Atomic decommissioning plan, recovery of plant investment, and all
issues with respect to prudence of the decision to discontinue operation. The
Company has estimated its remaining share of the cost of Yankee Atomic's
continued compliance with regulatory requirements, recovery of its plant
investments, decommissioning and closing the plant, to be approximately $16.5
million. This estimate, which is subject to ongoing review and revision, has
been recorded by the Company as a regulatory asset and a liability on the
accompanying consolidated balance sheet. As part of the MPUC's decision in the
Company's 1993 base-rate case, the Company's current share of costs related to
the deactivation of Yankee Atomic is being recovered through rates.
The Company has approximately a 60% ownership interest in the jointly owned,
Company-operated, 620-megawatt oil-fired W. F. Wyman Unit No. 4. The Company
also has a 2.5% ownership interest in the Millstone Unit No. 3 nuclear plant
operated by Northeast Utilities, and is entitled to approximately 29-megawatt
share of that unit's capacity. The Company's share of the operating costs of
these units is included in the appropriate expense categories in the
Consolidated Statement of Earnings. The Company's plant in service, nuclear
fuel, decommissioning fund, and related accumulated depreciation and
amortization attributable to these units as of December 31, 1996, and 1995
were as follows:
Wyman 4 Millstone 3
(Dollars in thousands) 1996 1995 1996 1995
Plant in service, nuclear fuel and
decommissioning fund $116,372 $116,447 $112,040 $112,033
Accumulated depreciation and amortization 63,023 59,832 39,181 36,411
Millstone Unit No. 3 has been out of service since April, 1996, due to NRC
concerns regarding operating license requirements and the Company cannot predict
when it will return to service. The Company estimates that it will incur
approximately $300,000 to $500,000 in replacement power costs each month
Millstone Unit No. 3 remains out of service. The Company incurred replacement
power costs of $3.5 million in 1996.
Power-Pool Agreements
The New England Power Pool, of which the Company is a member, has contracted
in its Hydro-Quebec Projects to purchase power from Hydro-Quebec. The
contracts entitle the Company to 85.9 megawatts of capacity credit in the
winter and 127.25 megawatts of capacity credit during the summer. The Company
has entered into facilities-support agreements for its share of the related
transmission facilities. The Company's share of the support responsibility and
of associated benefits is approximately 7%.
The Company is making facilities-support payments on approximately $28.8
million, its remaining share of the construction cost for these transmission
facilities incurred through December 31, 1996. These obligations are reflected
on the Company's consolidated balance sheet as lease obligations with a
corresponding charge to electric property.
Non-Utility Generators
The Company has entered into a number of long-term, non-cancelable contracts
for the purchase of capacity and energy from non-utility generators (NUG). The
agreements generally have terms of five to 30 years, with expiration dates
ranging from 1997 to 2021. They require the Company to purchase the energy at
specified prices per kilowatt-hour, which are often above market prices. As of
December 31, 1996, facilities having 573 megawatts of capacity covered by
these contracts were in-service. The costs of purchases under all of these
contracts amounted to $313.4 million in 1996, $314.4 million in 1995, and
$373.5 million in 1994.
During 1996, the Company reached agreement with three NUGs to buy out
contracts or to give the Company options to restructure their contracts
through lump-sum or periodic payments. In accordance with prior MPUC policy
and the ARP, at December 31, 1996, $113 million of buy-out or restructuring
costs incurred since January 1992 were included in Deferred Charges and Other
Assets on the Company's balance sheet and are amortized over their respective
fuel savings periods.
The Company's estimated contractual obligations with NUGs as of December 31,
1996, are as follows:
(Dollars in Amount
millions)
1997 $ 331
1998 291
1999 295
2000 294
2001 268
2002 - 2015 2,369
$3,848
In early 1996, the Company entered into a restructuring agreement with Maine
Energy Recovery Company (MERC), a 20 megawatt waste to energy facility located
in Biddeford, Maine. The agreement provides for a significant reduction in
energy rates for energy sold to the Company and extended the previous power
contract five years. In addition, the Company will make capacity payments to
CL Power Sales One.
Note 7: Capitalization and Interim Financing
Retained Earnings
Under terms of the most restrictive test in the Company's General and
Refunding Mortgage Indenture and the Company's Articles of Incorporation, no
dividend may be paid on the common stock of the Company if such dividend would
reduce retained earnings below $29.6 million. At December 31, 1996, the
Company's retained earnings were $72.5 million, of which $42.9 million were not
so restricted.
Mortgage Bonds
Substantially all of the Company's electric-utility property and franchises
are subject to the lien of the General and Refunding Mortgage.
The Company's outstanding Mortgage Bonds may be redeemed at established prices
plus accrued interest to the date of redemption, subject to certain refunding
limitations. Bonds may also be redeemed under certain conditions at their
principal amount plus accrued interest by means of cash deposited with the
trustee under certain provisions of the mortgage indenture. In 1996, the
Company deposited approximately $29.6 million in cash with the Trustee under
the Company's General and Refunding Mortgage Indenture in satisfaction of the
renewal and replacement fund and other obligations under the Indenture. The
total of such cash on deposit with the Trustee as of December 31, 1996, was
approximately $59.5 million. Under the Indenture such cash may be applied at
any time, at the direction of the Company, to the redemption of bonds
outstanding under the Indenture at a price equal to the principal amount of
the bonds being redeemed, without premium, plus accrued interest to the date
fixed for redemption. Such cash may also be withdrawn by the Company by
substitution of allocated property additions or available bonds.
Mortgage Bonds outstanding as of December 31, 1996, and 1995 were as follows:
(Dollars in thousands)
Interest
Series Redeemed/maturity rate 1996 1995
Central Maine Power Company
General and Refunding Mortgage Bonds:
U 1998-April 15 7.54% $ 25,000 $ 25,000
S 1998-August 15 6.03 60,000 60,000
T 1998-November 1 6.25 75,000 75,000
O 1999-January 1 7 3/8 50,000 50,000
P 2000-January 15 7.66 75,000 75,000
N 2001-September 15 8.50 11,000 22,500
Q 2008-March 1 7.05 75,000 75,000
R 2023-June 1 7 7/8 50,000 50,000
Total Mortgage Bonds $421,000 $432,500
Limitations on Unsecured Indebtedness
The Company's Articles of Incorporation limit certain unsecured indebtedness
that may be outstanding to 20% of capitalization, as defined; 20% of defined
capitalization amounted to $219 million as of December 31, 1996. Unsecured
indebtedness, as defined, amounted to $96 million as of December 31, 1996.
In May 1989, holders of the Company's preferred stock consented to the
issuance of unsecured Medium-Term Notes in an aggregate principal amount of
$150 million outstanding at any one time; the notes are therefore not subject
to such limitations.
Medium-Term Notes
Under the terms of the Company's Medium-Term Note program, the Company may
offer Medium-Term Notes up to an aggregate principal amount of $150 million.
Maturities can range from nine months to 30 years; interest rates pertaining
to such notes are established at the time of issuance. Interest on fixed-rate
notes is payable on March 1 and September 1, while interest on floating-rate
notes is payable on the dates indicated thereupon.
Medium-Term Notes outstanding as of December 31, 1996, and 1995 were as
follows:
(Dollars in thousands)
Maturity Interest rate 1996 1995
Series A:
2000 9.65% $ 5,000 $ 5,000
Series B:
1996-1998 4.92-7.98 23,000 57,000
Series C:
1997-2001 7.40-7.50 40,000 30,000
Total Medium-Term Notes $68,000 $92,000
Pollution-Control Facility and Other Notes
Pollution-control facility and other notes outstanding as of December 31,
1996, and 1995 were as follows:
(Dollars in thousands)
Series Interest rate Maturity 1996 1995
Central Maine Power
Company:
Yarmouth Installment Notes 6 3/4% June 1, 2002 $10,250 $10,250
Yarmouth Installment Notes 6 3/4 December 1, 2003 1,000 1,000
Industrial Development
Authority of the State of 7 3/8 May 1, 2014 11,000 11,000
New Hampshire Notes 7 3/8 May 1, 2014 8,500 8,500
Finance Authority of Maine 8.16 January 1, 2005 60,129 66,429
Maine Electric Power
Company, Inc.:
Promissory Notes Variable* July 1, 1996 - 1,730
Variable* November 1, 2000 820
Total Pollution-Control
Facility and Other Notes $91,699 $98,909
*The average rate was 6.3% in 1996 and 6.7% in 1995.
The bonds issued by the Industrial Development Authority of the State of New
Hampshire are supported by loan agreements between the Company and the
Authority. The bonds are subject to redemption at the option of the Company at
their principal amount plus accrued interest and premium, beginning in 2001.
In September 1994, the Finance Authority of Maine (FAME) approved the
Company's application for funds to finance the contract buy-out of a NUG
contract for a 32-megawatt wood fired generating plant in Fort Fairfield,
Maine. On October 26, 1994, FAME issued $79.3 million of Taxable Electric Rate
Stabilization Revenue Notes Series 1994A (FAME notes). FAME and the Company
entered into a loan agreement under which the Company issued FAME a note for
approximately $66.4 million, evidencing a loan in that amount. The proceeds of
the loan, along with $13 million of the Company's own funds, were used to buy
out the Fort Fairfield contract. Concurrently, the Company purchased all of
the common stock of Aroostook Valley Electric Company (AVEC) for $2 million.
On October 26, 1994, AVEC paid the former owners of the Fort Fairfield
facility $2 million and took title to the facility. In connection with the
FAME financing, AVEC granted FAME a mortgage on the facility. The remaining
$12.9 million of FAME-notes proceeds was placed in a capital-reserve account.
The amount in the capital-reserve account is equal to the highest amount of
principal and interest on the FAME notes to accrue and come due in any year
the FAME notes are outstanding. The amounts invested in the capital reserve
account are initially invested in government securities designed to generate
interest income at a rate equal to the interest on the FAME notes. Under the
terms of the loan agreement, the Company is also responsible for or receives
the benefit from the interest rate differential and investment gains and
losses on the capital reserve account.
Capital Lease Obligations
The Company leases a portion of its buildings and equipment under lease
arrangements, and accounts for certain transmission agreements as capital
leases using periods expiring between 2006 and 2021. The net book value of
property under capital leases was $33.1 million and $35.1 million at December
31, 1996, and 1995, respectively. Assets acquired under capital leases are
recorded as electric property at the lower of fair-market value or the present
value of future lease payments, in accordance with practices allowed by the
MPUC, and are amortized over their contract terms. The related obligation is
classified as other long-term debt. Under the terms of the lease agreements,
executory costs are excluded from the minimum lease payments.
Estimated future minimum lease payments for the five years ending December 31,
2001, together with the present value of the minimum lease payments, are as
follows:
(Dollars in thousands) Amount
1997 $ 5,619
1998 5,447
1999 5,276
2000 5,105
2001 4,934
Thereafter 56,298
Total minimum lease payments 82,679
Less: amounts representing interest 46,396
Present Value of Net Minimum Lease Payments $36,283
Sinking-Fund Requirements
Consolidated sinking-fund requirements for long-term obligations, including
capital lease payments and maturing debt issues, for the five years ending
December 31, 2001, are as follows:
(Dollars in thousands)
Sinking fund Maturing debt
Total
1997 $ 2,375 $ 25,000 $ 27,375
1998 9,212 178,000 187,212
1999 9,855 60,000 69,855
2000 10,520 80,000 90,520
2001 10,950 21,000 31,950
Operating Lease Obligations
The Company has a number of operating-lease agreements primarily involving
computer and other office equipment, land, and telecommunication equipment.
These leases are noncancelable and expire on various dates through 2007.
Following is a schedule by year of future minimum rental payments required
under the operating leases that have initial or remaining noncancelable lease
terms in excess of one year as of December 31, 1996:
(Dollars in thousands) Amount
1997 $4,277
1998 4,042
1999 3,278
2000 3,123
2001 3,099
Thereafter 1,936
$19,755
Rent expense under all operating leases was approximately $5 million, $5.7
million, and $7 million for the years ended December 31, 1996, 1995 and 1994,
respectively.
Disclosure of Fair Value of Financial Instruments
The methods and assumptions used to estimate the fair value of each class of
financial instruments for which it is practicable are discussed below. The
carrying amounts of cash and temporary investments approximate fair value
because of the short maturity of these investments. The fair value of
redeemable preferred stock and pollution-control facility and other notes is
based on quoted market prices as of December 31, 1996 and 1995. The fair
value of long-term obligations is based on quoted market prices for the same
or similar issues, or on the current rates offered to the Company based on the
weighted average life of each class of instruments.
The estimated fair values of the Company's financial instruments as of
December 31, 1996, and 1995 are as follows:
1996 1995
Carrying Fair value Carrying Fair value
(Dollars in thousands) amount amount
Cash and temporary investments $ 8,307 $ 8,307 $ 57,677 $ 57,677
Redeemable preferred stock 60,528 57,228 74,528 75,117
Mortgage bonds 421,000 415,578 432,500 435,311
Medium-term notes 68,000 67,667 92,000 92,156
Pollution-control facility and other notes 91,699 91,791 98,909 99,694
Preferred Stock
Preferred-stock balances outstanding as of December 31, 1996, 1995, and 1994
were as follows:
Current shares
(Dollars in thousands, except per-share amounts) outstanding 1996 1995 1994
Preferred Stock - Not Subject to
Mandatory Redemption:
$25 par value - authorized 2,000,000
shares; outstanding: None $ - $ - $ -
$100 par value noncallable -authorized
5,713 shares; outstanding 6% voting 5,713 571 571 571
$100 par value callable - authorized
2,300,000* shares; outstanding:
3.50% series (redeemable at $101) 220,000 22,000 22,000 22,000
4.60% series (redeemable at $101) 30,000 3,000 3,000 3,000
4.75% series (redeemable at $101) 50,000 5,000 5,000 5,000
5.25% series (redeemable at $102) 50,000 5,000 5,000 5,000
7 7/8% series (optional redemption after
9/1/97, at $100) 300,000 30,000 30,000 30,000
Preferred Stock - Not Subject to Mandatory Redemption $65,571 $65,571 $65,571
Redeemable Preferred Stock - Subject to
Mandatory Redemption:
$100 par value callable - authorized
2,300,000*shares; outstanding: None $ - $ - $ -
Flexible Money Market Preferred Stock,
Series A - 7.999% (395,275 shares in 1996 and 1995; 450,000
shares in 1994) 395,275 39,528 39,528 45,000
8 7/8% series (redeemable at $102.958) 210,000 21,000 35,000 35,000
Redeemable Preferred Stock - Subject to
Mandatory Redemption $60,528 $74,528 $80,000
*Total authorized $100 par value callable is 2,300,000 shares. Shares
outstanding are classified as Not Subject to Mandatory Redemption and Subject
to Mandatory Redemption.
Sinking-fund provisions for the 8 7/8% Series Preferred Stock require the
Company to redeem all shares at par plus an amount equal to dividends accrued
to the redemption date on the basis of 70,000 shares annually commencing on
July, 1996. The Company also has the non-cumulative right to redeem up to an
equal amount of the respective number of shares annually, beginning in 1996,
at par plus an amount equal to dividends accrued to the redemption date. The
sinking-fund requirement for the five-year period ending December 31, 2000 is
$7.0 million annually beginning in 1996. The Company redeemed $14 million of
these shares at par in 1996 pursuant to the mandatory and optional
sinking-fund provisions.
Sinking-fund provisions for the Flexible Money Market Preferred Stock, Series
A, 7.999%, require the Company to redeem all shares at par plus an amount
equal to dividends accrued to the redemption date on the basis of 90,000
shares annually beginning in October 1999. The Company also has the
non-cumulative right to redeem up to an equal number of shares annually
beginning in 1999, at par plus an amount equal to dividends accrued to the
redemption date. The sinking-fund requirement for the five-year period ending
December 31, 2000, is $9 million annually beginning in 1999. In 1995, the
Company purchased 54,725 shares on the open market that may be used to reduce
the sinking-fund requirement in 1999.
Interim Financing and Credit Agreements
The Company uses funds obtained from short-term borrowing to provide initial
financing for construction and other corporate purposes.
To support its short-term capital requirements, on October 23, 1996 , the
Company entered into a $125 million revolving credit facility with several
banks, with The First National Bank of Boston and The Bank of New York acting
as agents for the lenders. The credit facility has two tranches which consist
of: a $75 million 364-day revolving credit facility which matures on October
22, 1997 and a $50-million 3-year revolving credit facility which matures on
October 23, 1999. Both credit facilities require annual fees on the unused
portion of the credit lines which are based on the Company's credit ratings
and allow for various borrowing options including LIBOR-priced,
base-rate-priced and competitive-bid-priced loans. The amount of outstanding
short-term borrowing will fluctuate with day-to-day operational needs, the
timing of long-term financing, and market conditions. There was $7.5 million
outstanding as of December 31, 1996, under this credit agreement.
Note 8: Quarterly Financial Data (Unaudited)
Quarterly revenue variability increased after January 1, 1995, when the ARP
replaced MPUC rules prescribing different revenue allocations for energy sold
in winter versus non-winter months. Twelve-month results are unaffected by
this reporting change.
Unaudited, consolidated quarterly financial data pertaining to the results of
operations are shown below.
(Dollars in thousands, except per-
share amounts) Quarter ended
March 31 June 30 September 30 December 31
1996
Electric operating revenues $274,139 $216,358 $228,987 $247,562
Operating income 39,601 20,495 14,667 32,909
Net income 27,857 9,096 3,392 19,884
Earnings per common share* .78 .20 .04 .54
1995
Electric operating revenues $263,312 $202,584 $217,872 $232,248
Operating income 39,361 4,052 22,169 20,277
Net income (loss) 26,376 (8,619) 10,400 9,823
Earnings (loss) per common share* .73 (.34) .24 .23
1994
Electric operating revenues $241,026 $212,336 $233,543 $217,978
Operating income 26,233 26,609 25,652 11,742
Net income (loss) 11,416 15,307 14,083 (64,071)
Earnings (loss) per common share* .27 .39 .35 (2.06)
*Earnings per share are computed using the weighted-average number of common
shares outstanding during the applicable quarter.
Item 9. CHANGES IN AND DISAGREEMENTS WITH
ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE.
Not applicable.
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 15, 1997, 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 15, 1997, 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 15, 1997, 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 15, 1997, which is hereby
incorporated herein by reference.
PART IV
Item 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES,
AND REPORTS ON FORM 8-K.
(a) List of documents filed as part of this report:
(1) Financial Statements and Supplementary Data
See the Index to Financial Statements and Schedules under Item
8 in Part II hereof, where these documents are listed, on page
42.
(2) Exhibits - see (c) below.
(b) Reports on Form 8-K. The Company filed the following reports on
Form 8-K during the last quarter of 1996 and thereafter to date:
Date of Report Items Reported
December 4, 1996 Item 5
The Company reported on Maine Yankee Atomic Power Company's response to
the NRC's Independent Safety Assessment.
The Board of Directors of Connecticut Yankee Atomic Power Company voted
to permanently discontinue power operation at the Connecticut Yankee
plant at Haddam, Connecticut ("CY Plant"), and to decommission the CY
Plant, for reasons based on the economics of continuing to operate the
unit.
Date of Report Items Reported
December 18, 1996 Item 5
On December 20, 1996, Maine Yankee Atomic Power Company announced that
its President and Chief Executive Officer, Charles D. Frizzle, had
submitted his registration to facilitate a broad restructuring effort.
On December 18, 1996, Moody's Investors Service placed the credit
ratings of the Company under review for possible downgrade.
Date of Report Items Reported
December 31, 1996 Item 5
The Company reported that on December 31, 1996, the MPUC issued its
Report and Recommended Plan on Electric Utility Industry Restructuring.
The Company reported the inspection of fuel assemblies and resolution of
the cable-separation and associated issues at the Maine Yankee Atomic
Power Company nuclear generating plant and that Maine Yankee and Entergy
Corporation, a Louisiana-based utility holding company and nuclear plant
operator, announced the signing of a memorandum of understanding for
Entergy to provide management services to Maine Yankee.
Date of Report Items Reported
January 29, 1997 Item 5
On January 29, 1997, the NRC announced that it had placed the Plant on
its "watch list," in "Category 2," which includes plants that display
"weaknesses that warrant increased NRC attention," but which are not
severe enough to warrant a shut-down order.
The Company reported on a Maine-based group which had announced its
intention to start gathering signatures aimed at a new referendum to
force a permanent shutdown of the Maine Yankee Atomic Power Company Plant.
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 27th day of March, 1997.
CENTRAL MAINE POWER COMPANY
By
David E. Marsh
Vice President, Corporate Services,
Treasurer, and Chief Financial Officer
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.
Signature Title Date
President and Chief Executive Officer; Director March 27, 1997
David T. Flanagan
(Principal Executive Officer)
Vice President, Corporate Services, Treasurer, and March 27, 1997
David E. Marsh Chief Financial Officer
(Principal Financial Officer)
Comptroller March 27, 1997
Michael W. Caron
(Principal Accounting Officer)
Chairman of the Board of Directors March 27, 1997
David M. Jagger
Vice Chairman of the Board of Directors March 27, 1997
Charles H. Abbott
Director March 27, 1997
Charleen M. Chase
Director March 27, 1997
E. James Dufour
Director March 27, 1997
Duane D. Fitzgerald
Director March 27, 1997
Robert H. Gardiner
Director March 27, 1997
Peter J. Moynihan
Director March 27, 1997
William J. Ryan
Director March 27, 1997
Kathryn M. Weare
Director March 27, 1997
Lyndel J. Wishcamper
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, 1996
CENTRAL MAINE POWER COMPANY
File No. 1-5139
(Exact name of Registrant as specified in charter)
EXHIBITS
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 amended. Annual Report on Form 10-K 3.1
for year ended December 31,
1992
3-2 Bylaws, as amended. Filed herewith
EXHIBIT 4: INSTRUMENTS DEFINING THE RIGHTS OF SECURITY HOLDERS
Incorporated herein by reference:
4-1 General and Refunding Mortgage between the Company 2-58251 2.18
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 dated as of March 15, 2-60786 2.19
1977 to the General and Refunding Mortgage.
4-3 Supplemental Indenture to the General and Annual Report on Form 10-K A
Refunding Mortgage Indenture dated as of October for the year ended December
1, 1978 relating to the Series B Bonds. 31, 1978
4-4 Supplemental Indenture to the General and Quarterly Report on for the A
Refunding Mortgage Indenture dated as of October quarter ended September 30,
1, 1979, relating to the Series C Bonds. 1979
4.10 Supplemental Indenture to the General and 33-9232 4.16
Refunding Mortgage Indenture dated as of December
1, 1986, relating to the Series I Bonds.
4.14 Indenture, dated as of August 1, 1989, between the 33-29626 4.1
Company and The Bank of New York, Trustee,
relating to the Medium-Term Notes.
4.15 First Supplemental Indenture, dated as of August Current Report on Form 8-K 4.15
7, 1989, relating to the Medium-Term Notes, Series dated August 16, 1989
A, and supplementing the Indenture relating to the
Medium-Term Notes.
4.15.1 Second Supplemental Indenture, dated as of January Current Report on Form 8-K 4.1
10, 1992, relating to the Medium-Term Notes, dated January 28, 1992
Series B, and supplementing the Indenture relating
to the Medium-Term Notes.
4.15.2 Third Supplemental Indenture, dated as of December Annual Report on Form 10-K 4.15.2
15, 1994, relating to the Medium-Term Notes, for year ended December 31,
Series C, and supplementing the Indenture relating 1994
to the Medium-Term Notes.
4.17 Supplemental Indenture to the General and Current Report on Form 8-K 4.1
Refunding Mortgage Indenture, dated as of dated September 17, 1991
September 15, 1991, relating to the Series N Bonds.
4.18 Supplemental Indenture to the General and Current Report on Form 8-K 1.2
Refunding Mortgage Indenture, dated as of December dated December 10, 1991
1, 1991, relating to the Series O Bonds.
4.19 Supplemental Indenture to the General and Annual Report on Form 10-K 4.19
Refunding Mortgage Indenture, dated as of December for year ended December 31,
15, 1992, relating to the Series P Bonds. 1992
4.20 Supplemental Indenture to the General and Current Report on Form 8-K 4.1
Refunding Mortgage Indenture, dated as of February dated March 1, 1993
15, 1993, relating to the Series Q Bonds.
4.21 Supplemental Indenture to the General and Current Report on Form 8-K 4.1
Refunding Mortgage Indenture, dated as of May 20, dated May 20, 1993
1993, relating to the Series R Bonds.
4.22 Supplemental Indenture to the General and Current Report on Form 8-K 4.1
Refunding Mortgage Indenture, dated as of August dated November 30, 1993
15, 1993, relating to the Series S Bonds.
4.23 Supplemental Indenture to the General and Current Report on Form 8-K 4.2
Refunding Mortgage Indenture, dated as of November dated November 30, 1993
1, 1993, relating to the Series T Bonds.
4.24 Supplemental Indenture to the General and Annual Report on Form 10-K 4.24
Refunding Mortgage Indenture, dated as of April for year ended December 31,
12, 1994, relating to the Series U Bonds. 1994
4.26 Supplemental Indenture to the General and Annual Report on Form 10-K 4.26
Refunding Mortgage Indenture, dated as of February for year ended December 31,
15, 1996, evidencing the succession of State 1995
Street Bank and Trust Company as Trustee
EXHIBIT 9: VOTING TRUST AGREEMENT
Not applicable.
EXHIBIT 10: MATERIAL CONTRACTS
Incorporated herein by reference:
10-1 Agreement dated April 1, 1968 between the Company 2-30554 4.27
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 Agreement dated as 2-55385 4.8
of September 1, 1971 as amended to November 1,
1975.
10-3 Agreement setting forth Supplemental NEPOOL 2-50198 5.10
Understandings dated as of April 2, 1973.
10-4 Sponsor Agreement dated as of August 1, 1968 among 2-32333 4.27
the Company and the other sponsors of Vermont
Yankee Nuclear Power Corporation.
10-5 Power Contract dated as of February 1, 1968 2-32333 4.28
between the Company and Vermont Yankee Nuclear
Power Corporation.
10-6 Amendment to Exhibit 10.5 dated as of June 1, 1972. 2-46612 13-21
10-7 Capital Funds Agreement dated as of February 1, 2-32333 4.29
1968 between the Company and Vermont Yankee
Nuclear Power Corporation.
10-8 Amendment to Exhibit 10.7 dated as of March 12, 70-4611 B-3
1968.
10-9 Stockholder Agreement dated as of May 20, 1968 2-32333 4.30
among the Company and the other stockholders of
Maine Yankee Atomic Power Company.
10-10 Power Contract dated as of May 20, 1968 between 2-32333 4.31
the Company and Maine Yankee Atomic Power Company.
10-10.1 Amendment No. 1 to Exhibit 10-10 dated as of March Annual Report on Form 10-K 10-1.1
1, 1984. for the year ended December
31, 1985 of Maine Yankee
Atomic Power company (File
No. 1-6554)
10-10.2 Amendment No. 2 to Exhibit 10-10 dated as of Annual Report on Form 10-K 10-1.2
January 1, 1984. 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 dated as of Annual Report on Form 10-K 10-1.3
October 1, 1984. for the year ended December
31, 1985 of Maine Yankee
Atomic Power Company (File
No. 1-6554)
10-10.4 Additional Power Contract between the Company and Annual Report on Form 10-K 10-1.4
Maine Yankee Atomic Power Company dated February for the year ended December
1, 1984. 31, 1985 of Maine Yankee
Atomic Power Company (File
No. 1-6554)
10-11 Capital Funds Agreement dated as of May 20, 1968 2-32333 4.32
between the Company and Maine Yankee Atomic Power
Company.
10-11.1 Amendment No. 1 to Exhibit 10-11 dated as of Annual Report on Form 10-K 10-2.1
August 1, 1985. for the year ended December
31, 1985 of Maine Yankee
Atomic Power Company (File
No. 1-6554)
10-25 Agreement dated as of May 1, 1973 for Joint 2-48966 13-57
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 10-25 dated as of Annual Report on Form 10-K 10-42
September 19, 1986. for the year ended December
31, 1986
10-46 Participation Agreement, dated June 20, 1969 among 2-35073 4.23.1
Maine Electric Power Company, Inc., the Company
and certain other utilities.
10-47 Power Purchase and Transmission Agreement dated 2-35073 4.23.2
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 dated June 24, 2-37987 4.41
1970.
10-49 Agreement supplementing Exhibit 10-47 dated 2-51545 5.7.4
December 1, 1971.
10-50 Assignment Agreement dated March 20, 1972, between 2-51545 5.7.5
Maine Electric Power Company, Inc., and the New
Brunswick Electric Power Commission.
10-51 Capital Funds Agreement dated as of September 1, 2-24123 4.19.1
1964 among Connecticut Yankee Atomic Power
Company, the Company and certain other utilities.
10-52 Power Contract dated as of July 1, 1964 among 2-24123 4.19.2
Connecticut Yankee Atomic Power Company, the
Company and certain other utilities.
10-53 Stockholder Agreement dated as of July 1, 1964 2-24123 4.19.3
among the stockholders of Connecticut Yankee
Atomic Power Company, including the Company.
10-54 Connecticut Yankee Transmission Agreement dated as 2-24123 4.19.4
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 Cambridge Electric 2-15553 4.18
Light Company and other sponsoring stockholders of
Yankee Atomic Electric Company.
10-57 Agreement for Joint Ownership, Construction and 2-52900 5.16
Operation of Wyman Unit No. 4 dated November 1,
1974 among the Company and certain utilities.
10-58 Amendment to Exhibit 10-57 dated as of June 30, 2-55458 5.48
1975.
10-59 Amendment to Exhibit 10-57 dated as of August 16, 2-58251 5.19
1976.
10-60 Amendment to Exhibit 10-57 dated as of December 2-68184 5.31
31, 1978.
10-61 Transmission Agreement dated November 1, 1974 2-54449 13-57
among the Company and certain other utilities,
relating to Wyman Unit No. 4.
10-62 Sharing Agreement--1979 Connecticut Nuclear Unit 2-50142 2.43
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 as of August 1, 2-51999 5.16
1974, relating to Millstone Unit
No. 3.
10-64 Agreement dated as of February 25, 1977 among the 2-58251 5.24
Company, the Connecticut Light and Power Company,
the Hartford Electric Light Company and Western
Massachusetts Electric Company, relating to
Millstone Unit No. 3.
10-70 Project Agreement dated December 5, 1984 among the Annual Report on Form 10-K 10-69
Company, the Cities of Lewiston and Auburn, Maine for the year ended December
and certain other parties, relating to development 31, 1984
of hydro-electric plant.
10-73 Trust Indenture dated as of June 1, 1977 between 2-60786 5.27
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 as of June 1, 2-60786 5.28
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 of May 1, 1984. Quarterly Report on Form 28.3
10-Q for the quarter ended
June 30, 1984
10-75.2 Loan Agreement dated as of May 1, 1984. Quarterly Report on Form 28.4
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 December 28, 1984. Annual Report on Form 10-K 10-77.1
for year ended December 31,
1984
10-76.2 Loan Agreement dated as of December 1, 1984. Annual Report on Form 10-K 10-77.2
for year ended December 31,
1984
10-77.1 Indenture of Trust dated as of March 14, 1988 Annual Report on Form 10-K 10-1.4
between Maine Yankee Atomic Power Company and for year ended December 31,
Maine National Bank relating to decommissioning 1987, of Maine Yankee Atomic
trust funds. Power Company (1-6554)
10-77.1(a) Amended and Restated Indenture of Trust dated as Annual Report on Form 10-K 10-6.1
of January 1, 1993 between Maine Yankee Atomic for year ended December 31,
Power Company and The Bank of New York relating to 1992, of Maine Yankee Atomic
decommissioning trust funds. Power Company (1-6554)
10-77.2 Indenture of Trust dated as of October 16, 1985 Annual Report on Form 10-K 10-7
between the Company and Norstar Bank of Maine for year ended December 31,
relating to the spent fuel disposal funds. 1985, of Maine Yankee Atomic
Power Company (1-6554)
10-78 Form of Agreement of Purchase and Sale dated Annual Report on Form 10-K 0.79
February 19, 1986 between the Company and Eastern for the year ended December
Utilities Associates, relating to the sale of the 31, 1985
Company's Seabrook Project interest.
10-79 Addendum to Agreement of Purchase and Sale dated Quarterly Report on Form 2.1
June 23, 1986, among the Company, Eastern 10-Q for the quarter ending
Utilities Associates and EUA Power Corporation, June 30, 1986
amending Exhibit 10-78.
10-80 Agreement, dated as of October 29, 1986, between Quarterly Report on Form 2.1
the Company and EUA Power Corporation, relating to 10-Q for the quarter ended
the sale of the Company's interest in the Seabrook September 30, 1986
Project.
10-81 Credit Agreement, dated as of October 15, 1986, Quarterly Report on Form 2.2
among the Company, various banks and Continental 10-Q for the quarter ended
Illinois National Bank and Trust Company of September 30, 1986
Chicago, as agent, establishing the terms of a $40
million unsecured credit facility.
10-86 Labor Agreement dated as of May 1, 1989 between Annual Report on Form 10-K 10.86
the Company (Northern, Western and Southern for the year ended December
Division) and Local 1837 of the International 31, 1989
Brotherhood of Electrical Workers.
10-86.1 Agreement dated as of November 25, 1991 extending Annual Report on Form 10-K 10.86.1
Labor Contract. for year ended December 31,
1991
10-89 1987 Executive Incentive Plan, as amended January Annual Report on Form 10-K 10.89
20, 1993.* for year ended December 31,
1992
10-90 Deferred Compensation Plan for Non-Employee Annual Report on Form 10-K 10.90
Directors, as amended and restated effective for year ended December 31,
February 1, 1992.* 1992
10-91 Retirement Plan for Outside Directors, as amended Annual Report on Form 10-K 10.91
and restated effective April 24, 1991.* for year ended December 31,
1992
10-92 Employment Agreement between the Company and Annual Report on Form 10-K 10.92
Matthew Hunter dated as of October 20, 1993.* for year ended December 31,
1993.
10-93 Central Maine Power Company Long-Term Incentive Annual Report on Form 10-K 10.93
Plan.* for year ended December 31,
1993.
10-94.1 Central Maine Power Company Supplemental Executive Annual Report on Form 10-K 10-94.1
Retirement Plan, as Amended and Restated Effective for year ended December 31,
January 1, 1993, and as further Amended Effective 1995
January 1, 1996.*
10-95 Competitive Advance and Revolving Credit Facility Annual Report on Form 10-K 10.95
between the Company and Chemical Bank dated as of for year ended December 31,
November 7, 1994. 1994
10-96.5 Employment Agreement between the Company and Annual Report on Form 10-K 10-96.5
Arthur W. Adelberg As Amended and Restated for year ended December 31,
Effective December 9, 1994.* 1995
10-96.6 Employment Agreement between the Company and Annual Report on Form 10-K 10-96.6
Richard A. Crabtree As Amended and Restated for year ended December 31,
Effective December 9, 1994.* 1995
10-96.7 Employment Agreement between the Company and Annual Report on Form 10-K 10-96.7
Gerald C. Poulin As Amended and Restated Effective for year ended December 31,
December 9, 1994.* 1995
10-96.8 Employment Agreement between the Company and David Annual Report on Form 10-K 10-96.8
E. Marsh As Amended and Restated Effective for year ended December 31,
December 9, 1994.* 1995
10-97 Employment Agreement between the Company and Annual Report on Form 10-K 10-97
David T. Flanagan dated December 29, 1995.* for year ended December 31,
1995
10-98 Credit Agreement dated as of October 23, 1996, Filed herewith
between the Company and certain banks.
*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
Not Applicable.
EXHIBIT 16: LETTER RE CHANGE IN CERTIFYING ACCOUNTANT
Not Applicable.
EXHIBIT 18: LETTER RE CHANGE IN ACCOUNTING PRINCIPLES
Not Applicable.
EXHIBIT 21: SUBSIDIARIES OF THE REGISTRANT
List of subsidiaries of registrant. Filed herewith
EXHIBIT 22: PUBLISHED REPORT CONCERNING MATTERS SUBMITTED TO
VOTE OF SECURITY HOLDERS
Not Applicable.
EXHIBIT 23: CONSENTS OF EXPERTS AND COUNSEL
23-1 Consent of Coopers & Lybrand to the incorporation Filed herewith
by reference of their reports included or
incorporated by reference herein in the Company's
Registration Statements (File Number 33-36679,
33-39826, 33-44754, 33-51611 and 33-56939).
EXHIBIT 24: POWER OF ATTORNEY
Not Applicable.
EXHIBIT 27: FINANCIAL DATA SCHEDULE Filed herewith
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, 1996, pursuant to Rule 15d-21 under the
Securities Exchange Act of 1934:
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.
Central Maine Power Company
Form 10-K - 1996
Schedule II
Page 1 of 3
Central Maine Power Company
VALUATION AND QUALIFYING ACCOUNTS
For the Year Ended December 31, 1996
(Dollars in Thousands)
Additions
Charged Charged to
Balance to costs other Balance
at Beginning and accounts- Deductions at end
Description of Period Expenses describe -describe of period
Reserves deducted from
assets to which they apply:
Uncollectible accounts $ 3,313 $7,396 $ $6,532(A) $ 4,177
Reserves not applied
against assets:
Casualty and insurance $ 1,275 $ 798 $ $ 798(C) $ 1,275
Workers' compensation 6,400 2,820 270(B) 1,496(C) 7,994
Hazardous material
clean-up 3,540 895 796(D) 3,639
Total $11,215 $4,513 $270 $3,090 $12,908
Notes: (A) Amounts charged off as uncollectible after deducting
customers' deposits and recoveries of accounts previously
charged off.
(B) Amounts transferred to capital accounts.
(C) Principally payments for various injuries and damages and
expenses in connection therewith.
(D) Amounts charged to regulatory asset account.
Central Maine Power Company
Form 10-K - 1996
Schedule II
Page 2 of 3
Central Maine Power Company
VALUATION AND QUALIFYING ACCOUNTS
For the Year Ended December 31, 1995
(Dollars in Thousands)
Additions
Charged Charged to
Balance to costs other Balance
at Beginning and accounts- Deductions at end
Description of Period Expenses describe -describe of period
Reserves deducted from
assets to which they apply:
Uncollectible accounts $ 3,301 $4,407 $ $ 4,395(A) $ 3,313
Reserves not applied
against assets:
Casualty and insurance $ 1,275 $1,274 $273(B) $ 1,547(C) $ 1,275
Workers' compensation 6,400 6,400
Hazardous material
clean-up 10,000 6,460(D) 3,540
Postemployment benefits 1,045 1,045(E)
Compensation 2,344 2,344(E) -
Interest on IRS issues 1,000 1,000(F)
Total $22,064 $1,274 $273 $12,396 $11,215
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) To adjust the estimated minimum liability balance for a
change in clean-up method.
(E) Amounts transferred to deferred credit account.
(F) Reversal of reserve.
Central Maine Power Company
Form 10-K - 1996
Schedule II
Page 3 of 3
Central Maine Power Company
VALUATION AND QUALIFYING ACCOUNTS
For the Year Ended December 31, 1994
(Dollars in Thousands)
Additions
Charged Charged to
Balance to costs other Balance
at Beginning and accounts- Deductions at end
Description of Period Expenses describe -describe of period
Reserves deducted from
assets to which they apply:
Uncollectible accounts $ 2,704 $4,924 $ $4,327(A) $ 3,301
Reserves not applied
against assets:
Casualty and insurance $ 1,075 $2,492 $ 548(B) $2,840(C) $ 1,275
Workers' compensation 6,400 6,400
Hazardous material
clean-up 6,828 5,730(D) 2,558(E) 10,000
Postemployment benefits 1,045 1,045
Compensation 181 1,283 1,108(D) 228(B) 2,344
Interest on IRS issues 1,000 1,000
Total $14,484 $5,820 $7,386 $5,626 $22,064
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.