FORM 10-K
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15 (d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the Fiscal year ended DECEMBER 31, 1995 Commission File No. 0-505
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BANGOR HYDRO-ELECTRIC COMPANY
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(Exact Name of Registrant as specified in its charter)
MAINE 01-0024370
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(State of Incorporation) (I.R.S. Employer ID No.)
33 STATE STREET, BANGOR, MAINE 04401
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(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code 207-945-5621
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Securities registered pursuant to Section 12(b) of the Act:
Title of each class Name of exchange on which registered
COMMON STOCK, $5 PAR VALUE NEW YORK STOCK EXCHANGE
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Securities registered pursuant to Section 12(g) of the Act:
Common Stock, $5 Par value
(7,315,099 SHARES OUTSTANDING AT MARCH 20, 1996)
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7% PREFERRED STOCK, $100 PAR VALUE
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4 1/4% PREFERRED STOCK, $100 PAR VALUE
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4% PREFERRED STOCK SERIES A, $100 PAR VALUE
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Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to
such filing requirements for the past 90 days.
Yes X No
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Indicate by check mark if disclosure of delinquent filers pursuant to
Item 405 of Regulation S-K (Section 229.405 of this chapter) is not contained
herein, and will not be contained, to the best of 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]
The aggregate market value on March 20, 1996 of the voting stock held by
non-affiliates of the registrant was $82.0 million.
The information required by Part III Items 10, 11, 12 and 13 is
incorporated by reference from the registrant's proxy statement which will be
filed with the Securities and Exchange Commission within 120 days of the
close of the registrant's fiscal year ended December 31, 1995.
PART I
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ITEMS 1 THROUGH 2 BUSINESS; PROPERTIES
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GENERAL
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The Company is a public utility engaged in the generation, purchase,
transmission, distribution and sale of electric energy, with a service area
of approximately 5,275 square miles having a population of approximately
191,000 people. The Company serves approximately 103,000 customers in
portions of the counties of Penobscot, Hancock, Washington, Waldo,
Piscataquis and Aroostook. The Company also sells energy to other utilities
for resale. The Company has two material wholly-owned subsidiaries. Penobscot
Hydro Co., Inc. ("PHC") was incorporated in 1986 to own the Company's 50%
interest in a joint venture, Bangor-Pacific Hydro Associates
("Bangor-Pacific"), which redeveloped the West Enfield hydroelectric project
(the "West Enfield Project"). Bangor Var Co., Inc. ("Bangor Var Co.") was
incorporated in 1990 to hold the Company's 50% interest in a partnership
which owns certain facilities used in the Hydro-Quebec Phase II transmission
project ("HQ-II") in which the Company is a participant. See "Joint
Ventures."
In 1995, 29.6% of the Company's kilowatt hour ("KWH") sales were to
residential customers, 29.3% were to commercial customers, 39.9% were to
industrial customers and 1.2% were to other customers. For additional
information concerning the Company's sales, see Item 6, "Selected Financial
Data", below.
The Company's KWH sales are generally higher during the winter months,
with the winter peak electric demand usually 15% higher than the summer peak.
The maximum peak electric demand that the Company's system experienced during
the 1995-1996 winter, as of March 20, 1995, was approximately 267 megawatts
("MW") on January 3, 1996. At that time the Company had approximately 379.4
MW of generating capacity and firm purchased power, comprised of 106 MW from
Company-owned generating units, 61 MW from Maine Yankee Atomic Power
Company's nuclear generating facility ("Maine Yankee"), 18 MW from Hydro
Quebec, 53 MW from non-utility power producers, and 140 MW from short term
economy purchases.
The Company holds a 7% ownership interest in Maine Yankee which entitles
the Company to purchase an approximately equal amount of the output of Maine
Yankee, an entitlement of approximately 61 MW. Maine Yankee, which commenced
commercial operation on January 1, 1973, is the only nuclear facility in
which the Company has an ownership interest. Pursuant to a power purchase
contract with Maine Yankee, the Company is obligated to pay its pro rata
share of Maine Yankee's operating expenses, including fuel costs and
decommissioning costs. In addition, under a Capital Funds Agreement entered
into by the Company and the other sponsor utilities, the Company may be
required to make its pro rata share of future capital contributions to Maine
Yankee if needed to finance capital expenditures. See "Maine Yankee."
The Company, along with the major investor-owned utilities of New England,
has been a party to the New England Power Pool Agreement ("NEPOOL") since
1971. NEPOOL provides for joint planning and operation of generating and
transmission facilities in New England, and governs generating capacity
reserve obligations and provisions regarding the use of major transmission
lines. The Company, as a member of NEPOOL, has a capability responsibility
which involves carrying an allocated share of a New England capacity
requirement which is determined for each period based on certain regional
reliability criteria.
The Company is subject to the regulatory authority of the Maine Public
Utilities Commission ("MPUC") as to retail rates, accounting, service
standards, territory served, the issuance of securities and various other
matters. The Company is also subject to the jurisdiction of the Federal
Energy Regulatory Commission ("FERC") as to certain matters, including
licensing of its hydroelectric stations and rates for wholesale purchases and
sales of energy and capacity and transmission services. Maine Yankee is
subject to extensive regulation by the Nuclear Regulatory Commission ("NRC").
See "Rates and Regulation."
The principal executive offices of the Company are located at 33 State
Street, Bangor, Maine 04401; telephone (207) 945-5621.
CERTAIN ISSUES FACING THE COMPANY
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CHANGES IN THE ELECTRIC UTILITY INDUSTRY AND IN REGULATION - See Item 7,
"Management's Discussion and Analysis of Results of Operations and Financial
Condition - Recent Developments for the Company and in the Electric Utility
Industry and Potential Effects on Future Sales, Earnings and Dividend Policy"
for a discussion of the effect of competition and other events on future
sales, earnings and dividend policy. That discussion includes a description
of a pending Maine Public Utilities Commission investigation into the
possible restructuring of the electric industry in the State of Maine to
increase retail competition. Also included in Item 7 is a complete report on
the Company's efforts to provide electric rates set at competitive levels to
retain and attract customers, including a discussion of the MPUC Order in
early 1995 approving substantial changes in the way the Company's prices are
established. Finally, see Item 7 for an analysis the implications of those
developments on the Company's future dividend policy.
MAINE YANKEE - The Company, through its equity investment totalling
approximately $5.0 million at December 31, 1995, owns 7% of the common stock
of Maine Yankee Atomic Power Company, which owns and operates an 880 megawatt
nuclear generating plant in Wiscasset, Maine, and is entitled under a cost-
based power contract to an approximately equal percentage of the plant's
output. The Company's total payments under its power purchase agreement with
Maine Yankee were approximately $14.3 million, of which approximately $1.9
million were related to the plant's 1995 sleeving project. Maine Yankee's
operating license expires in 2008. During 1995, Maine Yankee experienced an
extended outage to resleeve the approximately 17,000 steam generator tubes
contained in the plant. That project was concluded in late 1995 and the
plant returned to operation at 90% of its rated generating capacity in
January, 1996. Maine Yankee is presently taking steps to meet Nuclear
Regulatory Commission requirements to return to 100% operation. The Company
cannot predict when the plant will gain the authority to return to 100%
operating level or when it will achieve this level once authority is granted.
For a further discussion regarding these issues, see Item 7, "Management's
Discussion and Analysis of Results of Operations and Financial Condition -
Recent Developments for the Company and in the Electric Utility Industry and
Potential Effects on Future Sales, Earnings and Dividend Policy - Maine
Yankee".
The Company is required to fund its pro rata share of Maine Yankee's
decommissioning costs, costs of storage and disposal of spent fuel and
low-level radioactive wastes. Provision for these items, based on current
estimates of the eventual costs, is made as Maine Yankee's rates are
established, and are included in the Company's rates to customers. To the
extent Maine Yankee cannot obtain its own financing, the Company would be
required to pay its pro rata share of additional capital expenditures to
maintain the unit in commercial operation. The magnitude of these various
costs is dependent in part upon the future resolution of several political
and technological uncertainties, and may be substantial. Maine voters have
rejected three referendum proposals to force the premature shutdown of Maine
Yankee, the most recent being in 1987; and the State of Maine has enacted
several restrictive statutes purporting to govern aspects of Maine Yankee's
operations. The Company would expect that its share of the costs of the
operation and decommissioning of Maine Yankee will continue to be reflected
in its rates, but cannot predict whether future voter and other necessary
approvals will be obtained in a timely fashion or whether all technological
uncertainties can be adequately resolved.
SIGNIFICANT CUSTOMER - Pursuant to a special rate contract approved by the
Maine Public Utilities Commission, the rate for service provided by the
Company to HoltraChem Manufacturing Company, L.L.C. ("HMC"), a significant
customer, is based in part on a "revenue sharing" arrangement whereby the
revenues for service vary depending on the price and volume of product sold
by HMC. During 1995, revenue sharing payments from HMC totalled
approximately $4.2 million. HMC's principal business is selling chlorine and
caustic soda, primarily to the paper industry in the State of Maine. As of
this writing, there have not been significant changes in the price or volume
of product sold by HMC during 1996. However, the Company is unable to
predict whether market conditions for these products will change in the
future.
CONSTRUCTION PROGRAM
The Company's construction program consists of extensions and
improvements of its transmission and distribution facilities, construction of
new generating stations or capital improvements to existing generating
stations, capital improvements to the Company's internal computer and
information systems and other general projects within the Company's service
area. The Company projects that capital expenditures will aggregate about
$33 million in the period 1996 through 1998 excluding capitalized overheads.
RATES AND REGULATION
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RATE MATTERS - See Item 7, "Management's Discussion and Analysis of Results
of Operations and Financial Condition - Recent Developments for the Company
and in the Electric Utility Industry and Potential Effects on Future Sales,
Earnings and Dividend Policy - Changes in the Industry and in Regulation",
incorporated herein by reference, for a discussion of recent changes in the
way the Company's prices will be established in the future and for a
description of the ongoing involvement by the MPUC in rate matters. In
addition, the MPUC is currently investigating the possibility of implementing
a "rate cap" mechanism for the Company that could, if implemented, restrict
the Company's opportunity to adjust rates unless its earnings varied outside
certain parameters. This investigation is a continuation of the MPUC's
investigation of regulatory flexibility for the Company described in Item 7.
It represents an attempt to institutionalize the Company's business strategy
of trying to improve its financial condition through cost reductions and
increased sales rather than through increases in core electric rates, also
described in Item 7. The MPUC is expected to conclude the investigation this
summer.
OTHER REGULATION - The MPUC regulates numerous other matters affecting the
Company, including financing, construction of generation and transmission
facilities, credit, collection, conservation and demand side management
programs, low income rate subsidies and purchases from non-utility power
producers.
Maine Yankee is subject to extensive regulation by the NRC. Under its
continuing jurisdiction, the NRC may, after appropriate proceedings, require
modification of nuclear power generating units for which operating licenses
have already been issued, or impose new conditions on such permits or
licenses, and may require that the operation of nuclear power generating
units be temporarily or permanently reduced.
The FERC regulates rates for sales of electricity to other utilities.
In addition, all the Company's hydroelectric projects are licensed by the
FERC. Under the Federal Power Act, upon not less than two years' notice the
United States is empowered to take over and thereafter to maintain and
operate a licensed hydroelectric project at or following the time a license
expires. If the United States elects this option, it must pay the licensee
its net investment in the project, not to exceed fair market value. If the
United States does not elect this option, the FERC may issue a new license to
the existing licensee upon such terms and conditions as are authorized or
required under the then-existing laws and regulations. It may also,
alternatively, issue a new license to a new licensee that has filed a
competing license application. In choosing between competing license
applications, the FERC must issue a license to the applicant whose proposal
is best adapted to serve the public interest.
The following table sets forth certain information with regard to such
licenses.
LICENSED ISSUE DATE OF CURRENT EXPIRATION
PROJECT CAPACITY ORIGINAL LICENSE DATE
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Ellsworth 8,900 KW April 12, 1977 December 31, 2018
Howland 1,875 KW September 12, 1980 September 30, 2000
Medway 3,400 KW March 29, 1979 March 31, 1999
Milford 6,400 KW December 31, 1969 Original license
expired
December 31, 1990
currently operating
on year-to-year
license.
Orono 2,332 KW November 10, 1977 Original license
expired
September 25, 1985
currently operating
on year-to-year
license.
Stillwater 1,950 KW August 10, 1978 Original license
expired
December 31, 1993
currently operating
on year-to-year
license.
Veazie 8,400 KW February 18, 1965 Original license
expired
September 25, 1985
currently operating
on year-to-year
license.
West Enfield* 13,000 KW February 3, 1970 June 26, 2024
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* Through PHC, the Company has a 50% ownership interest in Bangor-Pacific,
which owns and operates the West Enfield Project.
The Company is actively pursuing the relicensing of the projects listed
above which are operating on year-to-year licenses. Some of those
relicensing proceedings have been delayed pending completion by the FERC of
an Environmental Impact Statement of sections of the Penobscot River being
prepared in connection with the Company's licensing of the Basin Mills
project. See Note 7 to the Company's Consolidated Financial Statements,
incorporated herein by reference. The Company has not received notice that
the United States will exercise its rights to take over any of the Company's
hydroelectric projects, nor have any competing applications been filed.
Under a Federal statute enacted by Congress in 1986, participation in
relicensing proceedings by governmental agencies and other parties was
allowed to increase significantly. That increased participation may result
in more burdensome and costly conditions imposed upon licensees of
hydroelectric projects. The Company is unable to predict what terms and
conditions, if any, might be included in new licenses or license renewals
granted pursuant to the Company's licensing applications, or what impact any
such terms and conditions might have on the Company's ability to operate and
maintain the projects economically.
SEABROOK
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GENERAL - The Company was a participant in Seabrook from 1978 to 1986, with
an ownership interest of 2.17%, or 25 MW, in each of the two 1150 MW units.
Unit 2 was effectively canceled in 1984. In late 1984, following a lengthy
MPUC investigation, the conclusion of which cast doubt on the wisdom of the
Maine utilities' continued participation in Seabrook, the Company began
efforts to sell its interest in the project. An agreement for the sale of
Seabrook to EUA Power Corp. was reached in mid-1985 and was consummated in
November 1986.
In 1985, the MPUC approved an agreement among the Company, the MPUC Staff
and the Public Advocate addressing the recovery through rates of the
Company's investment in Seabrook ("Seabrook Stipulation"). Although
implementation of the Seabrook Stipulation significantly improved the
Company's financial condition, substantial write-offs were required.
In August 1989, a comprehensive settlement agreement entered into by
current and former joint owners of Seabrook became effective. Under the
agreement, the signatories, representing virtually all of the ownership
interests in Seabrook, relinquished claims against the lead owner, Public
Service Company of New Hampshire, arising out of Seabrook. As a part of the
settlement, former joint owners, including the Company, were relieved of
certain contingent liabilities.
JOINT VENTURES
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WEST ENFIELD - In 1986, the Company formed PHC, a wholly-owned subsidiary,
which owns the Company's 50% ownership interest in Bangor-Pacific, a joint
venture with a development subsidiary of Pacific Lighting Corporation.
Bangor-Pacific undertook the redevelopment of an old 3.8 MW hydroelectric
plant which the Company owned on the Penobscot River in Enfield and Howland,
Maine, into a 13 MW facility, the West Enfield Project, and now operates the
facility. Construction costs were shared equally by the Company and the
other joint venturer until Bangor-Pacific completed its financing and took
over ownership of the project, which occurred in January 1987. Commercial
operation of the redeveloped West Enfield Project began in April 1988.
Bangor-Pacific financed the $45 million cost of the redevelopment
through the private placement of $40 million of 9.45% and 10.26% fixed rate
amortizing term notes due 1996 and 2008, respectively, and $5 million of
floating rate amortizing term notes due 1996 (collectively, the "Notes").
The Notes are secured by a mortgage on the West Enfield Project and a
security interest in a 50-year power contract between the Company and
Bangor-Pacific. The holders of the Notes are without recourse to the joint
venture partners or their parent companies except that each partner has
agreed to make payments in an amount equal to 50% of any amounts due and
unpaid on the Notes but not exceeding distributions received from
Bangor-Pacific in the preceding twelve-month period.
Under the power contract between the Company and Bangor-Pacific, if the
West Enfield Project operates as anticipated, payments by the Company to
Bangor-Pacific are estimated at $7.5 million annually (without consideration
of any distributions by the joint venture to the partners). In 1995, the
Company paid approximately $7.3 million to Bangor-Pacific under this power
contract. The Company would be required to make payments under the contract,
regardless of whether any power were delivered, of approximately $4 million
per year. However, the Company has the right to terminate the contract upon
thirty-days' written notice if the failure to deliver power continues for a
period of 112 consecutive months.
NEPOOL/HYDRO-QUEBEC - The NEPOOL member utilities and Hydro-Quebec, a utility
operating within the province of Quebec, Canada ("Hydro-Quebec"), have
constructed facilities required to interconnect the electric systems in New
England with the electric system of Hydro-Quebec. The initial stage of the
interconnection consists of a completed and operational 450 KV transmission
line from the Hydro-Quebec system to a terminal having an approximate rating
of 690 MW at the Comerford Generating Station ("Comerford") on the
Connecticut River in New Hampshire. The subsequent stage, HQ-II, completed
in 1990, increased the interconnection transfer capability to approximately
2000 MW by means of a transmission line from Comerford to a terminal facility
at the Sandy Pond Substation in Massachusetts.
In 1990, the Company formed Bangor Var Co., a wholly owned corporate
subsidiary, the sole function of which is to own a 50% interest in Chester
SVC Partnership ("Chester"), a general partnership which owns the static var
compensator ("SVC"), electrical equipment which supports the HQ-II
transmission line. A wholly-owned subsidiary of Central Maine Power Company
("CMP") owns the other 50% interest in Chester. Chester has financed the
acquisition and construction of the SVC through the issuance of $33 million
in principal amount of 10.48% senior notes due 2020, and up to $3.2 million
principal amount of additional notes due 2020 (collectively, the "SVC
Notes"). The holders of the SVC Notes are without recourse to the partners
or their parent companies and may only look to Chester and to the collateral
for payment. Bangor Var Co. accounts for its investment in Chester under the
equity method. Bangor Var Co.'s financial results are included in the
Company's consolidated financial statements.
The New England utilities which participate in HQ-II have agreed under a
FERC-approved contract to bear the cost of Chester, on a cost-of-service
basis, which includes a return on and of all capital costs.
EMPLOYEES
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At December 31, 1995, the Company had 419 full time employees
approximately 43% of whom were represented by a local union affiliated with
the International Brotherhood of Electrical Workers (AFL-CIO). The present
contract expires December 31, 1998. The Company believes that its relations
with its employees are satisfactory.
POWER SUPPLY SOURCES
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GENERAL - In order to meet its load growth and reserve obligations under
NEPOOL, the Company, in addition to utilizing its own generating capacity,
acquires capacity and energy through contracts with other utilities and
independent generation facilities and through joint ownership of generating
facilities. The Company estimates that it has, or can acquire, sufficient
generating capacity, through a combination of wholly-owned and jointly-owned
generating facilities and purchased power contracts, to meet its anticipated
load growth through the 1990's.
The Company's sources of generation for electric sales to its customers
(net of off-system sales to other utilities) for 1995, 1994 and 1993 by type
of fuel is shown below.
SOURCE 1995 1994 1993
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Hydroelectric (Company*)....... 14% 15% 14%
Nuclear Generation (Maine Yankee) 1% 25% 20%
Oil (Company)................... 3% 2% 3%
Biomass/Refuse (purchased)...... 6% 8% 15%
NEPOOL/other purchases.......... 76% 50% 48%
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Total....................... 100% 100% 100%
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* Includes purchases from the West Enfield Project, in which the Company has
a 50% ownership interest.
COMPANY-OWNED GENERATION
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The Company, as a tenant in common with other utilities, owns 8.33%, or
approximately 50 MW, of William F. Wyman Unit No. 4 ("Wyman 4"), a 600 MW
oil-fired generating unit in Yarmouth, Maine, constructed and operated by CMP
as the lead owner. The Company is entitled to 8.33% of the energy produced
by Wyman 4 and pays the same percentage of the unit's operating expenses.
The Company owns two oil-fired generating units located at its Graham
Station in Veazie, Maine ("Graham"), currently in deactivated reserve status,
having a total capacity of 47 MW, as well as eleven internal combustion
generation units located at three stations having a total capacity of 21 MW.
The Company also owns seven hydroelectric stations having a total capacity of
about 30 MW (excluding PHC's ownership interest in the West Enfield Project).
All of the Company's hydroelectric stations are licensed under the Federal
Power Act. See "Rates and Regulation."
In addition, the Company owns more than 600 miles of transmission lines
and more than 3,600 miles of distribution lines to serve its customers.
Other properties consist of office, garage and warehouse facilities at
various locations in its service area.
POWER PURCHASE CONTRACTS
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The following chart sets forth information concerning the Company's
major power purchase contracts exclusive of Maine Yankee.
CONTRACTED QUANTITY OF
SELLER TERM OF CONTRACT CAPACITY OR ENERGY
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Bangor-Pacific* August 21, 1986 through Total output of energy
(Hydroelectric). May 31, 2024, at which from facility with name
time Company can either plate rating of not more
purchase the facility than 16 MW.
at its fair market value
or extend the contract
for an additional 15
years (if the West
Enfield Project's FERC
license is also
extended).
Penobscot Energy January 21, 1984 through Total output of firm
Recovery Company February 28, 2018. energy; minimum annual
("PERC") (Refuse). delivery of 105,000,000
KWH up to a maximum of
166,440,000 KWH per
calendar year.
Great Northern September 21, 1989 Approximately 20 MW.
Paper Co. through October 31,
(Cogeneration). 1996.
New England November 1, 1994 through 30 MW and associated energy
Power Company October 31, 1999. from two designated nuclear
units
New England January 1, 1996 through 25 MW and associated energy
Power Company October 31, 1998 from a designated system
contract
United Illumi- November 1, 1994 through 30 MW and associated energy
nating Company October 31, 1997 from a designated oil unit
New Brunswick November 1, 1994 through 45 MW system purchase of
Power October 31, 1997 capacity and energy
New Brunswick April 1, 1996 through 10 MW system purchase of
Power October 31, 1998 capacity and energy (months
of April-October only)
Great Bay Power January 1,1996 through 10 MW and associated energy
Corporation March 31, 1998 from a designated nuclear
unit (November-March only)
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* Through PHC, the Company has a 50% ownership interest in Bangor-Pacific,
which owns and operates the West Enfield Project.
During 1995, the Company reached agreement with Babcock-Ultrapower West
Enfield and Babcock-Ultrapower Jonesboro to buy back two power contracts
totalling approximately 49 MW. See Item 7, "Management's Discussion and
Analysis of Results of Operations and Financial Condition - Recent
Developments for the Company and in the Electric Utility Industry and
Potential Effects on Future Sales, Earnings and Dividend Policy - Buyback of
Purchased Power Contracts.
For further details with respect to certain of these contracts, see Note
6 of the Notes to Consolidated Financial Statements.
The Company purchases energy from, and sells energy to, New Brunswick
Electric Power Commission utilizing the transmission facilities of Maine
Electric Power Company, Inc. ("MEPCO"), in which the Company owns a 14.2%
equity interest. MEPCO owns and operates a 345 KV transmission line running
from Wiscasset, Maine to the Maine/New Brunswick border. The Company
interconnects with this line in Orrington, Maine. Several New England
utilities, including the Company and MEPCO's other stockholders (two other
Maine utilities), are parties to a transmission support agreement pursuant to
which such utilities have agreed to pay MEPCO's costs, based on their
relative system peaks, if MEPCO's revenues from transmission services are not
sufficient to meet its expenses. The Company anticipates that any liability
resulting therefrom will be immaterial.
The Company also purchases energy on a short-term basis from time to time
when it is economical to do so to displace higher cost energy from other
sources.
MAINE YANKEE
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GENERAL - The Company holds a 7% equity ownership interest in Maine Yankee
which entitles the Company to purchase an approximately equal amount of the
output of Maine Yankee, an entitlement of approximately 61 MW. Maine Yankee,
which commenced commercial operation on January 1, 1973, is the only nuclear
facility in which the Company has an ownership interest. The Company is
obligated to pay its pro rata share of Maine Yankee's operating expenses,
including fuel costs and decommissioning costs. In addition, under a Capital
Funds Agreement entered into by the Company and the other sponsor utilities,
each sponsor has agreed to provide a like percentage of Maine Yankee's
capital requirements not obtained from other sources, subject to obtaining
any necessary regulatory approvals.
1995 OUTAGE - The Maine Yankee plant, like other pressurized water reactors,
experienced degradation of its steam generator tubes, principally in the form
of circumferential cracking, which, until early 1995, was believed to be
limited to a relatively small number of tubes. During the refueling and
maintenance shutdown that commenced in February 1995, Maine Yankee detected
through new inspection methods increased degradation of the plant's steam
generator tubes to the extent that approximately 60% of the plant's 17,000
steam generator tubes appeared to have defects to some degree. Because of
the large number of affected tubes, the remedy of plugging the degraded tubes
to take them out of service was no longer a viable option.
Following a detailed analysis of the safety, technical and financial
considerations associated with the degraded steam generator tubes, Maine
Yankee elected to repair the tubes by inserting and welding short reinforcing
sleeves of an improved material in substantially all of the plant's steam
generator tubes. Similar repairs have been completed at other nuclear plants
in the United States and abroad, but not on the scale of the Maine Yankee
project. With Westinghouse Electric Corporation as the general contractor,
the sleeving project started in early June of 1995, after approval of the
Westinghouse sleeving process by the Nuclear Regulatory Commission (NRC), and
was essentially completed in early December. The repairs were estimated to
cost $40 million, but Maine Yankee now estimates the project was completed
for approximately $27 million. The Company charged to operations its share of
the repair costs in 1995.
During 1995, the Company incurred substantial costs for replacement
power, and as explained above, since the FCA was eliminated at the beginning
of 1995, the replacement power costs had a material impact in reducing
earnings in 1995. After Maine Yankee went off-line, the Company incurred
non-reconcilable incremental replacement power costs of approximately $8.6
million for the year. Combined with the Company's share of the repair cost,
the Maine Yankee outage adversely impacted the Company's earnings in 1995 by
$.86 per common share, after taxes.
On December 4, 1995, when the resleeving project was substantially
complete, Maine Yankee received a copy of a letter, from an organization with
a history of opposing nuclear power development, to a State of Maine nuclear
safety official based on documentation from an anonymous former employee of
Yankee Atomic Electric Company (Yankee), an affiliate of Maine Yankee and
other nuclear plant operators. The letter contained allegations that Yankee
knowingly performed inadequate analyses to support two license amendments to
increase the rated thermal power at which the Maine Yankee plant could
operate. It was further alleged in the letter that Maine Yankee deliberately
misrepresented the analyses to the NRC in seeking license amendments. The
allegedly inadequate analyses related to the operation of the plant's
emergency core cooling system (ECCS) and the calculation of the plant's
containment peak postulated accident pressure, both under certain assumed
accident conditions. The analyses were used in support of license amendments
that authorized an increased rating of the plant from a level equal to
approximately 90% of the maximum electrical capability of the plant to its
current 100% rated level.
In response to technical issues raised by the allegations, the NRC
initiated a special technical review of the safety analysis performed by
Yankee relating to Maine Yankee's license amendment applications for the
power uprates. At the same time, Maine Yankee and Yankee initiated intensive
internal investigations of the allegations and provided responsive
information and documentation to the NRC.
On December 18, 1995, a public meeting was held at the NRC to discuss
the findings resulting from the NRC's technical review. At the meeting the
NRC informed Maine Yankee that it had concerns regarding the adequacy of a
proprietary computer code used in ECCS safety analyses supporting Maine
Yankee's last two applications for license amendments that authorized power
uprates to levels above 90% of its current maximum capacity. At the meeting
the NRC also indicated that operation of the plant at a level up to 90% could
be acceptable if operations were based on methods previously found acceptable
by the NRC staff and not on the computer code that is currently under review
by the NRC, and further informed Maine Yankee of the terms and conditions
under which Maine Yankee could resume power operation of the plant.
Subsequently, the NRC informed Maine Yankee that the allegations made in the
anonymous letter would be the subject of investigations by the NRC's Office
of Investigations and the Office of the Inspector General.
On January 3, 1996, the NRC issued a "Confirmatory Order Suspending
Authority For And Limiting Power Operation And Containment Pressure
(Effective Immediately) And Demand For Information" (the Confirmatory Order)
confirming the conclusions of the NRC from the public meeting and follow-up
communications with Maine Yankee. The Confirmatory Order limited the power
output of the Maine Yankee plant to approximately 90% of its rated maximum
until the NRC shall have reviewed and approved plant-specific analyses
meeting the NRC's criteria for operation of the ECCS under certain postulated
accident conditions, in lieu of the analyses based on the questioned computer
code. The Confirmatory Order further required that prior to operating the
plant at any level, Maine Yankee should submit under oath specified
information relating to operating the plant at up to the 90% level and
descriptions of measures taken to assure compliance with the limitations on
operating level and containment pressure.
With respect to subsequently returning the plant to its 100% operating
level, the Confirmatory Order required Maine Yankee to submit a
plant-specific analysis meeting the NRC's requirements for ECCS operation
under specified conditions at plant power levels up to 100% of its maximum
rated capability. The Confirmatory Order also required an integrated
containment analysis demonstrating that the maximum calculated containment
pressure under certain postulated accident conditions does not exceed the
design-basis pressure of the plant's containment. In addition, the
Confirmatory Order required Maine Yankee to submit a schedule for providing
the requested analyses and related information to the NRC.
As of this writing, the Maine Yankee plant is operating at the 90%
level, and Maine Yankee is continuing its efforts to meet the NRC's
requirements to return to the 100% operating level. The Company cannot
predict when the plant will gain the authority to return to the 100%
operating level or when it will achieve this level once authority is granted.
As a result of Maine Yankee's operating limitation, the Company will incur
replacement power costs of between $70,000 and $100,000 per month as long as
that limitation is in effect. Finally, the Company cannot predict the
results of the internal and external investigations of the allegations
brought to Maine Yankee's attention on December 4, 1995. Maine Yankee has
stated, however, that it intends to pursue its internal investigation
diligently and cooperate with the governmental investigations, and that it
believes that after it develops information requested by the NRC for
operation of the plant at full capacity it will be able to operate the plant
at that level while meeting all applicable NRC safety requirements.
NUCLEAR FUEL STORAGE - Federal legislation enacted in 1987 directed the U.S.
Department of Energy ("DOE") to proceed with the studies necessary to develop
and operate a permanent high-level waste (spent fuel) disposal site at Yucca
Mountain, Nevada. The legislation also provides for the possible development
of a Monitored Retrievable Storage ("MRS") facility and abandons plans to
identify and select a second permanent disposal site. An MRS facility would
provide temporary storage for high-level waste prior to eventual permanent
disposal. In late 1989, the DOE announced that the permanent disposal site
was not expected to open before 2010, although originally scheduled to open
in 1998. Additional delays due to political an technical problems are
probable.
On June 20, 1994, fourteen nuclear utilities filed suit against the DOE.
The utilities are seeking a declaration from the United States Court of
Appeals for the District of Columbia that the Nuclear Waste Policy Act
requires the DOE to take responsibility for spent nuclear fuel in 1998.
Maine Yankee is not participating in the lawsuit, but is monitoring
developments.
Under the terms of a license amendment approved by the NRC in 1984, the
present storage capacity of the spent fuel pool at the 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 Plant and, on January
25, 1993, filed with the NRC seeking authorization to implement the plan. On
March 15, 1994, the NRC granted the authorization, and installation of the
new racks is scheduled for 1996. Maine Yankee believes that the replacement
of the fuel racks will provide adequate storage capacity through the Plant's
licensed operating life, but cannot predict with certainty whether or to what
extent the new level of storage capacity at the Plant will affect the
operation of the Plant or the future cost of disposal.
NUCLEAR INSURANCE - In accordance with the Price-Anderson Act, the limit of
liability for a nuclear-related accident is approximately $8.9 billion,
effective November 18, 1994. The primary layer of insurance for the
liability is $200 million of coverage provided by the commercial insurance
market. The secondary coverage is approximately $8.7 billion, based on 110
licensed reactors. The secondary layer is based on a retrospective premium
assessment of $79.275 million per nuclear accident per licensed reactor,
payable at a rate not exceeding $10 million per year per accident. In
addition, the retrospective premium is subject to inflation-based indexing at
five-year intervals and, if the sum of all public liability claims and legal
costs arising from any nuclear accident exceeds the maximum amount of
financial protection, each licensee can be assessed an additional 5% ($3.775
million) of the maximum retrospective assessment.
In addition to the insurance required by the Price-Anderson Act, Maine
Yankee carries all-risk nuclear property damage insurance in the amount of
$500 million plus additional excess nuclear property insurance in the amount
of $2.25 billion, effective January 1, 1995. The all-risk nuclear property
damage insurance of $500 million is obtained from the commercial insurance
market and is not subject to retrospective premium assessments. The excess
insurance of $2.25 billion is provided by a nuclear electric utility industry
insurance company through a combination of current premiums, retrospective
assessments and reinsurance. If the insurance company experiences losses in
excess of its capacity to pay them, each participating utility may be
assessed a retrospective premium of up to 7.5 times its premium with respect
to industry losses in any policy year, which could range up to approximately
$22.7 million for the Company. This excess coverage amount is the maximum
offered by the industry mutual company.
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 has begun 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 1996 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 Maine Yankee by the State of Maine, payable in two equal
installments, the first after ratification by Congress and the second upon
commencement of operation of the Texas facility. In addition, Maine Yankee
would be assessed a total of $2.5 million for the benefit of the Texas county
in which the facility would be located and would also be responsible for its
pro-rata share of the Texas governing commission's operating expenses. 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, the Company will ship low-level waste off
site for disposal in South Carolina or other available sites as long as the
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, the company could
also build a second facility on the Plant site. The Company 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 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.
CITIZEN COMPLAINT - By letter dated January 20, 1996 a citizen group called
FRIENDS OF THE COAST -OPPOSING NUCLEAR POLLUTION filed a letter with the NRC
pursuant to 10 C.F.R. 2.206 alleging certain safety concerns. Specifically,
the group alleges (1) that the plant's containment is inadequate for power
operation in excess of its original license and may be inadequate for
original power operation limits based upon the design of the plant, and (2)
that the plant's emergency core cooling system may not be adequately analyzed
for materials degradation to ensure integrity at power operation at levels
above original license limits or under accident conditions. The group is
asking that the NRC suspend Maine Yankee's operating license or, in the
alternative, limit the operating license to lower generating capacity levels
than presently allowed. Maine Yankee has informed the Company that it
believes that these issues were resolved previously and are not of any
current concern.
ENVIRONMENTAL MATTERS
----------------------
The Company is regulated by the Federal Environmental Protection Agency
("EPA") as to compliance with the Federal Water Pollution Control Act, the
Clean Air Act of 1970 (the "Clean Air Act"), and certain federal statutes
governing the treatment and disposal of hazardous wastes, as well as by the
Maine Department of Environmental Protection under Maine's hazardous waste
statutes. Although the Company is actively engaged in complying with such
acts and statutes, the costs of which are significant, it has not, to date,
encountered material difficulties in connection with such compliance.
The Clean Air Act was amended by Congress in 1990 which will result in new
regulatory requirements to install more advanced pollution control equipment
and to make other changes to reduce the emission of air pollutants. The
amendment includes new initiatives to deal with the problem of acid rain
which will impact the air emissions of fossil-fueled power plants. Under
Phase I implementation, specific plants will be required to reduce their
sulphur dioxide emissions in 1995. The Company does not own or operate any
Phase I plants. Under Phase II implementation, essentially all fossil-fueled
power plants must reduce their sulphur dioxide emission. The Company has not
completed its evaluation of the concomitant capital and operating costs
needed to comply with the amendment, including the provisions relating to
nitrogen oxide emissions and monitoring. Wyman 4 is located in a
non-attainment area for nitrogen oxide and may be subject to additional
regulations for the control of nitrogen oxide emissions.
The Company estimates that during 1995 it will spend approximately
$450,000 in operations expenses and $700,000 in capital expenditures to
comply with environmental standards for air, water and hazardous materials.
EXECUTIVE OFFICERS OF THE COMPANY
---------------------------------
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 pursuant to which any were selected as
officers.
NAME AGE OFFICE AND YEAR FIRST ELECTED
- ---- --- ------------------------------
Robert S. Briggs 52 President & Chief Executive
Officer since January 1991
Carroll R. Lee 46 Vice President-Operations
since 1990
Frederick S. Samp 45 Vice President - Finance &
Law since 1995; Treasurer since
1995; Chief Financial Officer
since 1995
Each of the executive officers has for more than the last five years
been an officer or employee of the Company. Mr. Briggs was Vice President
and General Counsel from 1979 until 1987, Vice President-Law and Public
Affairs from 1987 until 1988, Executive Vice President & Chief Operating
Officer from 1988 until 1989 and President and Chief Operating Officer from
1989 until 1991. From 1983 through 1984, Mr. Lee was Vice President-Power
Supply and Planning and he served as Vice President-Engineering and
Operations from 1985 until 1987 and Vice President-Planning & Development
from 1987 until 1990. Mr. Samp was Corporate Counsel, Corporate Secretary
and Clerk from 1985 until 1988 and General Counsel, Corporate Secretary and
Clerk from 1988 until 1995.
Item 3 LEGAL PROCEEDINGS
------------------
See Note 8 to the Company's Financial Statements for a discussion of
potential liabilities under the Comprehensive Environmental Response,
Compensation, and Liability Act.
ITEM 4 SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
- ------ ----------------------------------------------------
Not applicable.
PART II
- -------
ITEM 5 MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED
- ------ -------------------------------------------------
STOCKHOLDER MATTERS
-------------------
As of December 31, 1995, there were 8,250 holders of record of the
Company's common stock.
The Company's common stock is traded on the New York Stock Exchange
("NYSE") under the symbol "BGR".
The following table sets forth the high and low prices for the Common
Stock as reported by the NYSE. The prices shown do not include commissions.
Dividends are declared quarterly.
DIVIDENDS
DECLARED
FISCAL PERIOD HIGH LOW PER SHARE
- ------------- ---- --- ---------
1994
- ----
First Quarter................ $19 $16 3/8 $.33
Second Quarter............... 17 13 .33
Third Quarter................ 13 1/2 11 1/4 .33
Fourth Quarter............... 12 1/4 9 3/8 .33
1995
- ----
First Quarter................ $12 7/8 $9 1/4 $.33
Second Quarter............... 12 3/8 9 1/8 .18
Third Quarter................ 12 1/2 10 1/4 .18
Fourth Quarter............... 12 3/4 11 1/8 .18
1996
- ----
First Quarter
(through March 20, 1996)... $12 1/2 $10 1/2 $.18
ITEM 6
- ------
SELECTED FINANCIAL DATA
- -----------------------
<TABLE>
SIX YEAR STATISTICAL SUMMARY
Bangor Hydro-Electric Company
<CAPTION>
1995 1994 1993 1992 1991 1990
- ---------------------------------------------------------------------------------------------------------------------------
MEGAWATT HOURS (MWH) GENERATED AND PURCHASED
<S> <C> <C> <C> <C> <C> <C>
Hydro Generation (Company) 275,810 271,616 275,694 305,011 313,629 350,898
Nuclear Generation (Maine Yankee) 13,606 456,871 395,665 368,641 430,879 334,343
Oil (Company) 50,706 35,759 47,115 80,770 70,681 150,074
Biomass/Refuse 177,558 190,218 281,260 307,451 338,376 435,050
NEPOOL/Other Purchases 1,540,530 958,363 937,431 767,306 702,818 674,738
- ---------------------------------------------------------------------------------------------------------------------------
Total Generated & Purchased 2,058,210 1,912,827 1,937,165 1,829,179 1,856,383 1,945,103
Less Line Losses and Company Use 140,128 136,908 135,561 131,764 122,370 125,265
- ---------------------------------------------------------------------------------------------------------------------------
Remainder - MWH sold 1,918,082 1,775,919 1,801,604 1,697,415 1,734,013 1,819,838
===========================================================================================================================
<CAPTION>
CLASSIFICATION OF SALES - MWH
<S> <C> <C> <C> <C> <C> <C>
Residential 513,076 516,470 515,242 521,889 517,259 517,946
Commercial 511,720 507,285 500,488 490,861 483,376 481,301
Industrial 686,386 611,876 615,314 563,734 539,565 567,595
Lighting 9,547 9,416 9,590 9,876 10,615 11,104
Wholesale 10,961 11,705 10,311 10,462 10,880 16,930
- ---------------------------------------------------------------------------------------------------------------------------
Total MWH Billed to Customers 1,731,690 1,656,752 1,650,945 1,596,822 1,561,695 1,594,876
Unbilled Sales - Net Increase (Decrease) 4,658 6,366 2,001 (11,832) 4,175 1,451
- ---------------------------------------------------------------------------------------------------------------------------
Total Delivered Sales (MWH) 1,736,348 1,663,118 1,652,946 1,584,990 1,565,870 1,596,327
(Less) Non-Firm Sales 295,818 231,128 254,359 208,066 203,108 236,834
- ---------------------------------------------------------------------------------------------------------------------------
Total Firm Delivered Sales (MWH) 1,440,530 1,431,990 1,398,587 1,376,924 1,362,762 1,359,493
Off-System Sales 181,734 112,801 148,658 112,425 168,143 223,511
- ---------------------------------------------------------------------------------------------------------------------------
Total Energy Sales (MWH) 1,918,082 1,775,919 1,801,604 1,697,415 1,734,013 1,819,838
===========================================================================================================================
<CAPTION>
ELECTRIC OPERATING REVENUES AND EXPENSES (000'S)
<S> <C> <C> <C> <C> <C> <C>
OPERATING REVENUES
Residential $ 66,061 $ 64,008 $ 64,244 $ 66,429 $ 58,510 $ 53,090
Commercial 55,030 53,410 53,599 53,806 46,859 41,820
Industrial 39,929 37,040 39,508 39,340 34,047 35,059
Lighting 2,051 2,010 1,915 1,933 1,755 1,621
Wholesale 859 937 903 895 898 1,431
- ---------------------------------------------------------------------------------------------------------------------------
Total Revenue From Customers $ 163,930 $ 157,405 $ 160,169 $ 162,403 $ 142,069 $ 133,021
Unbilled Sales-Net Increase (Decrease) 210 1,450 (237) (964) 2,642 (277)
- ---------------------------------------------------------------------------------------------------------------------------
Total Revenue $ 164,140 $ 158,855 $ 159,932 $ 161,439 $ 144,711 $ 132,744
(Less) Non-Firm Revenue 11,149 8,450 8,876 8,331 8,040 11,959
- ---------------------------------------------------------------------------------------------------------------------------
Total Firm Revenue $ 152,991 $ 150,405 $ 151,056 $ 153,108 $ 136,671 $ 120,785
Off-System Revenue 14,098 12,750 15,326 13,857 15,736 17,746
- ---------------------------------------------------------------------------------------------------------------------------
Total Operating Revenues $ 178,238 $ 171,605 $ 175,258 $ 175,296 $ 160,447 $ 150,490
===========================================================================================================================
<CAPTION>
OPERATING EXPENSES
<S> <C> <C> <C> <C> <C> <C>
Fuel Used in Generation $ 82,301 $ 90,339 $ 102,670 $ 101,465 $ 93,687 $ 83,904
Purchased Power 16,383 13,793 13,716 13,478 13,387 11,607
Operating and Maintenance Expense 35,711 33,498 29,474 27,042 25,253 23,898
Depreciation and Amortization 20,544 10,333 6,447 6,789 6,615 7,004
Taxes 6,306 8,803 8,866 9,499 6,856 7,735
- ---------------------------------------------------------------------------------------------------------------------------
Total Operating Expenses $ 161,245 $ 156,766 $ 161,173 $ 158,273 $ 145,798 $ 134,148
===========================================================================================================================
<CAPTION>
SUMMARY OF OPERATIONS (000'S)
<S> <C> <C> <C> <C> <C> <C>
Operating Revenue $ 184,914 $ 174,098 $ 177,972 $ 176,789 $ 162,243 $ 151,673
Operating Expenses 161,245 156,766 161,173 158,273 145,798 134,148
Other Income (including equity AFDC) 760 1,308 (2,657)* 1,690 2,367 1,738
Interest Expense (net of borrowed AFDC) 20,092 11,183 8,805 9,952 10,614 10,894
- ---------------------------------------------------------------------------------------------------------------------------
Net Income (Loss) $ 4,337 $ 7,457 $ 5,337 * $ 10,254 $ 8,198 $ 8,369
Less Preferred Dividends 1,702 1,652 1,646 1,613 1,613 1,613
- ---------------------------------------------------------------------------------------------------------------------------
Earnings on Common Stock $ 2,635 $ 5,805 $ 3,691 * $ 8,641 $ 6,585 $ 6,756
===========================================================================================================================
<CAPTION>
SELECTED FINANCIAL DATA
<S> <C> <C> <C> <C> <C> <C>
Total Assets (000's) $ 566,076 $ 381,250 $ 373,521 $ 288,867 $ 279,483 $ 269,735
ELECTRIC PLANT (000'S)
Total Electric Plant $ 323,664 $ 303,637 $ 281,606 $ 255,601 $ 232,079 $ 209,757
Depreciation Reserve 81,934 75,667 71,184 67,645 66,111 63,330
- ---------------------------------------------------------------------------------------------------------------------------
Net Electric Plant $ 241,730 $ 227,970 $ 210,422 $ 187,956 $ 165,968 $ 146,427
===========================================================================================================================
<CAPTION>
CAPITALIZATION (000'S)
<S> <C> <C> <C> <C> <C> <C>
Short-Term Debt $ 35,000 $ 27,000 $ 36,000 $ 15,000 $ 28,500 $ 23,000
Long-Term Debt 288,075 116,367 119,126 100,685 81,515 89,565
Redeemable Preferred Stock 12,070 13,740 15,168 15,102 15,068 15,034
Preferred Stock 4,734 4,734 4,734 4,734 4,734 4,734
Common Equity 103,192 105,658 93,944 82,230 79,797 67,473
- ---------------------------------------------------------------------------------------------------------------------------
Total $ 443,071 $ 267,499 $ 268,972 $ 217,751 $ 209,614 $ 199,806
- ---------------------------------------------------------------------------------------------------------------------------
<CAPTION>
CAPITAL STRUCTURE RATIOS (%)
<S> <C> <C> <C> <C> <C> <C>
Short-Term Debt 7.9% 10.1% 13.4% 6.9% 13.6% 11.5%
Long-Term Debt 65.0% 43.5% 44.3% 46.2% 38.9% 44.8%
Preferred Stock 3.8% 6.9% 7.4% 9.1% 9.4% 9.9%
Common Stock 23.3% 39.5% 34.9% 37.8% 38.1% 33.8%
- ---------------------------------------------------------------------------------------------------------------------------
Total 100.0% 100.0% 100.0% 100.0% 100.0% 100.0%
===========================================================================================================================
<CAPTION>
MISCELLANEOUS STATISTICS
<S> <C> <C> <C> <C> <C> <C>
Shares Outstanding (Average) 7,264,360 6,947,746 5,862,411 5,393,306 4,947,232 4,450,684
Shares Outstanding (Year End) 7,301,557 7,185,143 6,225,394 5,420,955 5,370,684 4,450,684
Number of Stockholders (Year End) 8,250 7,705 7,511 7,325 7,116 6,839
Earnings per Common Share $ 0.36 $ 0.84 $ 0.63 * $ 1.60 $ 1.33 $ 1.52
Dividends Declared per Common Share $ 0.87 $ 1.32 $ 1.32 $ 1.32 $ 1.29 $ 1.25
Book Value per Common Share $ 14.13 $ 14.71 $ 15.09 $ 15.17 $ 14.86 $ 15.16
Return on Common Equity 2.51% 5.55% 3.99%* 10.60% 8.81% 10.11%
Ratio of AFDC to Common Stock Earnings 48% 45% 143%* 28% 29% 21%
Ratio of Earnings to Fixed Charges 1.28 1.37 1.04 * 1.96 1.65 1.76
Payout Ratio 200% 157% 210%* 82.5 % 97.0 % 82.2 %
Percentage of Construction Expenditures
Funded Internally 100% 82% 72% 70 % 37 % 8 %
===========================================================================================================================
<CAPTION>
RESIDENTIAL CUSTOMER DATA
<S> <C> <C> <C> <C> <C> <C>
Average Number of Customers 86,194 85,041 84,211 83,305 82,568 81,151
Kilowatt-Hours per Customer 5,953 6,073 6,118 6,265 6,265 6,382
Revenue per Customer $ 766.42 $ 752.67 $ 762.89 $ 797.42 $ 708.63 $ 654.21
Revenue per Kilowatt-Hour in cents 12.88 12.39 12.47 12.73 11.31 10.25
===========================================================================================================================
<CAPTION>
MISCELLANEOUS SYSTEM DATA
<S> <C> <C> <C> <C> <C> <C>
Net System Capability at Time of Peak (MW)
Firm 330.01 340.45 341.17 342.39 337.29 323.06
System Peak Demand (MW) (Winter Peak) 267.98 275.84 267.42 253.27 264.17 251.62
Reserve Margin at Time of Peak 23.2% 23.4% 27.6% 35.2% 27.7% 28.4%
System Load Factor 79.9% 73.5% 76.4% 77.2% 73.0% 79.5%
===========================================================================================================================
* Includes the reserve established on certain licensing activites in 1993 ($5.6 million after taxes or $.95 per common
share). (See note 6).
</TABLE>
ITEM 7
- ------
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL
CONDITION
RECENT DEVELOPMENTS FOR THE COMPANY AND IN THE ELECTRIC UTILITY INDUSTRY AND
POTENTIAL EFFECTS ON FUTURE SALES, EARNINGS AND DIVIDEND POLICY
CHANGES IN THE INDUSTRY AND IN REGULATION - Historically, the electric
utility industry has been viewed as relatively stable for common equity
investors, providing a consistent level of dividends with moderate growth and
presenting a comparatively low risk to equity investments. This stability
developed because of public policies that treated electric utilities as
natural monopolies, requiring regulation of rates and service and the
protection of defined service territories. The industry has been
substantially free of competition while its profits have been limited by
traditional rate of return regulation.
In recent years, several factors have worked together to increase competitive
pressures on electric utilities in the United States and particularly in
Maine. Prices charged by Maine's electric utilities have increased rapidly to
cover the costs of implementing various public policy mandates including the
purchase of power from high cost non-utility power producers, the
subsidization of energy conservation and demand-side management measures,
financial assistance for low income customers, environmental mitigation and
improvement measures, and various other requirements. In addition, public and
regulatory policies implemented in Maine in the 1970s and 1980s overtly
discouraged the growth of electric sales, thereby tending to increase unit
costs. As a consequence of these factors, electric rates in Maine have, on
average, increased faster than the electric rates in New England, exclusive
of Maine. In the past, Maine's rates were substantially lower, on average,
than elsewhere in New England, but with the rate of increase experienced
recently, the average rate in Maine is now just below the New England
average. The Company's average rates are slightly less than the Maine
statewide average.
On an industry-wide scale, high embedded costs for many utilities have
combined with certain fundamental changes in the regulation of the electric
utility industry and in the economics of power generation to threaten the
ability of many traditional utilities to retain existing customers and to
attract new load. The Energy Policy Act of 1992 requires that the owner of
transmission facilities must, under certain specified conditions, transmit
power for third parties to "wholesale customers" meaning other retail
distribution utilities that are purchasing power for resale in their utility
business. This access to the transmission system allows existing municipal
and other distribution utilities that have traditionally purchased power
from neighboring utilities to purchase power in the competitive generation
markets. It also provides an incentive for the existing retail customers of a
utility to seek to lower their electric rates by forming a municipal utility
or utility district solely to qualify for the transmission access. Although
the 1992 Act does not require transmission access for retail customers,
individual states may authorize such access.
At the Federal level and in many of the States, various further initiatives
have been underway to restructure the electric industry in such a way so as
to allow for completion of the transition to a competitive market for the
generation of electricity and for the implementation of "retail wheeling" to
allow customers to choose their electric energy vendors. Although the State
of Maine has not heretofore taken the lead in promoting these efforts, in
1995 the Maine Legislature adopted a Resolve to study restructuring the
electric utility industry in the State. The objective of the study is to see
what it would take to implement competition by the year 2000. The first part
of the Resolve required the formation of a "Work Group" made up of
representatives of a number of diverse interests including Maine electric
utilities. The work of that Group was completed late in 1995. While the Group
reached general agreement on the identification of issues to be resolved
before effective competition can be introduced, the diverse interests of the
participants prevented a consensus on a plan of implementation.
The second part of the Legislature's Resolve requires the Maine Public
Utilities Commission (MPUC) to conduct a study of Maine's electric utility
industry and to develop at least two plans for an orderly transition to a
competitive market for the retail purchase and sale of electricity. One plan
must result in the achievement of full retail market competition in Maine by
the year 2000, and the other plan must propose a structure of regulated and
unregulated markets that maximizes the benefits of competition. The MPUC
inquiry, which was formally initiated on December 12, 1995, must be completed
and a report must be submitted to the Legislature no later than January 1,
1997.
In accordance with the MPUC's Notice of Inquiry, interested parties,
including the Company, submitted their initial comments in late January 1996.
The Company cannot predict the outcome of this proceeding, or whether this
proceeding or other proceedings and initiatives will lead to further
restructuring activities.
In addition to the increased pressures of competition from relaxed access to
transmission services and the prospect of full retail wheeling in the
future, technological improvements and increasing competition in the
generation of electricity have in recent years lowered the cost of
generation. The cost of new generation facilities today is significantly
lower than the cost of facilities built only a few years ago that are now
embedded in the existing cost structure of electric utilities. In addition,
the cost for a large retail customer to install its own generation facilities
at the point of consumption has dropped to a level that can be competitive
with the prices charged by electric utilities.
Finally, competition for the business of individual consumers and retail
customers has increased as the price of electricity has risen and the
availability of alternative methods of providing the services desired by
customers has increased. This has lead to discussions of the concept of
utilities having "core" and "non-core" customers, with the former being
thought to have no real alternative to electricity for the particular service
they need, and the latter considered as being "at risk" of loss depending on
price.
In order to meet these competitive pressures and achieve profitability over
the long term, the Company believes that it must control its costs and
increase sales in order to minimize the rates it charges for electricity, and
achieve greater revenue through increased sales. Although under traditional,
"cost-plus", rate-of-return regulation the Company could reasonably expect to
be allowed by the MPUC to increase its retail rates in an effort to enhance
its profitability, the Company believes that this approach, taken by itself,
would risk further erosion in sales. While it is difficult to forecast the
precise relationship among rates, energy sales and total revenues over the
short term, the Company believes that significant rate increases at this time
would have a negative long-term impact on the Company's competitive position
and its long-term financial success. The Company also believes this strategy
is consistent with the implementation of greater retail competition, whether
through the restructuring activities described above or otherwise.
Accordingly, although the Company has not ruled out seeking modest rate
relief from the MPUC in the future, it does not believe that the present
challenge of relatively low earnings can be solved solely by rate increases.
Despite the challenges of meeting increasing competition, the Company
believes that it can succeed in the long run because it has the experience
and breadth of knowledge to meet the needs of its customers in the part of
Maine it serves and because the marginal cost of providing electric service
is relatively low. The Company expects that, if public and regulatory
policies were adjusted to permit the active pursuit of greater sales, the
price that could be charged in a competitive environment, while lower than
many of the Company's current rates, would recover more than the marginal
cost of providing the service. The Company believes that, at such lower
prices, there is substantial potential for increased business. Moreover, the
Company believes that a strategy of greater electrification would produce
desirable environmental quality improvement, and the realization of this
beneficial impact will tend to enhance the favorable outlook for increased
sales. To the extent the Company is successful in expanding its market share
with competitive rates, the increased revenue in excess of marginal cost
will enhance earnings and offset the need for other rate increases.
Under traditional regulatory policies, the Company has had only limited
authority to adjust its prices to meet the competition. Competitive price
initiatives have been evaluated and approved by the MPUC on a case-by-case
basis. For example, for several years the Company has been allowed to sell
interruptible energy to two major customers at significantly
reduced rates, thereby retaining load that otherwise would have been lost and
providing an incentive to add new load.
More recently, the Company has been negotiating on an individual basis with
customers that have demonstrated that, without rate relief, they will curtail
their purchases from the Company. In early 1994, the MPUC authorized the
Company to enter into a five-year contract (terminable by the customer with
two years' notice) for the supply of power to one of the Company's largest
firm industrial customers at reduced rates. At present, about 40% of the
Company's commercial and industrial load is being served by such negotiated
rates.
Despite those successes in retaining customers, the Company realized some
time ago that more flexibility was necessary in order effectively to meet the
demands of competition in a timely manner. Procedural obstacles and the lack
of clear standards for evaluating proposed rate reductions had hindered the
Company's ability to react quickly and flexibly to competitive threats. In
1994, the Company sought additional regulatory flexibility, and in early
1995, the MPUC approved a new Alternative Marketing Plan (or AMP) permitting
greater opportunities for the Company to meet the challenges of competition
over the long term. Specifically, the MPUC established the following
guidelines for the reduction of rates with limited regulatory oversight:
1. For existing customer classes, the Company may offer reduced rates with a
price floor at the Company's long-term marginal cost plus 10% as long as the
rate structure of the class is maintained within specified limits. Rates that
meet the criteria take effect automatically after a 30-day notice period. If
a proposed reduction does not meet the criteria, the MPUC may suspend its
effectiveness but will make a decision within four months of the initial
filing date.
2. The Company may develop rates for new targeted customer classes with a
price floor that depends upon whether the new load is "temporary" (not
expected to continue for an extended period and sensitive to rate changes
that occur after the initial discount) or "permanent" (expected to continue
indefinitely regardless of later rate adjustments). For temporary load, the
floor is short-term marginal cost plus 1.5 cents/KWH or, under certain
circumstances, short-term marginal cost plus 10%. For permanent load, the
floor is long-term marginal cost plus 10%. Rates that meet the criteria take
effect automatically after a 30-day notice period.
3. The Company may negotiate special rate contracts with individual
customers, the criteria for which depend upon the length of the contract and
whether the load is temporary or permanent.
a. For short-term contracts (up to three years) to supply temporary
load, the floor is short-term marginal cost plus 1.5 cents/KWH. For
short-term contracts to supply permanent load, the floor is
long-term marginal cost plus 10%. Short-term contracts that meet all
criteria take effect automatically after a 30-day notice period.
b. For contracts with terms of three to five years, the floor is
long-term marginal cost plus 10%. For contracts with terms of five
to ten years, the floor is long-term marginal cost plus 25%.
Contracts that meet all criteria take effect automatically after a
30-day notice period.
c. Contracts with terms over ten years may not be approved
automatically, but the MPUC will review any such proposal within
four months of filing.
4. Any rate reduction that results in permanent load will also be subjected
to certain cost tests, the results of which must be presented by the Company
at the time of filing. If the proposal fails any of the tests, the Commission
may suspend its effectiveness and the MPUC will review it within four months
of filing.
5. The Company was authorized to eliminate seasonal rate differentials
(requiring higher charges during winter months than during the remainder of
the year) for certain classes of customers, and did so effective March 1,
1995.
6. The total amount of price reductions (the "revenue delta") offered by the
Company under the AMP is capped at 10% of the Company's revenues. If the
revenue delta approaches the cap, the Company must request authority from the
MPUC to offer further discounts.
As part of the AMP, effective January 1, 1995 the MPUC ordered the
elimination of the Fuel Cost Adjustment (FCA), a rate mechanism under which
the Company has historically been permitted to adjust retroactively for
changes in the cost of fuel for generation and in certain purchased power
costs. The Company had itself proposed this change because, under traditional
regulation, the operation of the FCA has imposed the burden of the revenue
loss as a result of price reductions on existing sales on utility
shareholders while the benefits have been enjoyed by other utility customers.
The Company believed, therefore, that a business strategy dependent on
pricing flexibility would be effective only if the FCA were eliminated.
However, the FCA had allowed the Company to respond quickly to changes in
fuel and purchased power costs (both increases and decreases) and reduced the
volatility of earnings. The Company recognized that its elimination might
result in increased or decreased earnings solely from changes in costs over
which the Company has limited control. As discussed in the following pages,
the unanticipated outage during most of 1995 of the Maine Yankee nuclear
power plant, of which the Company is a minority owner, had a significant
negative impact on 1995 earnings in part because of the elimination of the
FCA.
The Company purchases, rather than generates itself, a significant portion of
the energy required to service its retail business. These purchased energy
prices can vary with changes in the price or availability of the underlying
fuel sources, and the risk of such price volatility is no longer covered by a
rate mechanism like the FCA. To manage this exposure, in 1995, effective
January 1, 1996, the Company entered into hedging transactions with three
financial institutions. The Company determined that much of its exposure to
purchased energy price volatility is closely matched to changes in residual
oil prices. Accordingly, the Company entered into agreements known as
"swaps", essentially in which the Company agreed to pay a fixed price for a
specific quantity of a specific commodity (residual oil in this case), for a
given time period. This transfers the risk (or the benefit) of commodity
price fluctuations to the other party to the agreement for the given period
of time. These are strictly financial transactions, and no delivery of the
underlying commodity is taken. Settlements typically occur on a monthly basis
and the cash receipts/payments arising from the "swap" transactions will
offset corresponding increases/decreases in the Company's purchased energy
costs. As a result, the Company can manage a substantial portion of the risk
of energy price fluctuations, which allows the Company to more accurately
predict its future purchased energy costs and cash flow requirements. To
ensure the Company maintains a hedging, and not a speculative, position, the
Company has established official policies, procedures and controls for its
fuel hedging program.
As of January 1, 1995, the Company's collections under the FCA had exceeded
its costs by approximately $3.03 million. With the elimination of the FCA,
the MPUC recognized that there would no longer be a mechanism for the return
of that sum to customers. The MPUC allowed the Company to retain that
overcollection and ordered that the amount be amortized over a period of
three years. That retention and amortization positively affected 1995
earnings and will continue to have a short-term positive impact on the
Company's earnings in 1996 and 1997.
Also as requested by the Company, the MPUC established the recovery and
accounting procedures to be followed in the event of a buyout of one or more
of the Company's contracts for the purchase of power from high-cost
non-utility independent power producers. Under those procedures, the Company
was authorized to defer the 1995 buyback costs of the two high-cost power
purchase contracts discussed below and record them as regulatory assets, to
be amortized and collected over a ten-year period, beginning July 1, 1995.
The cost of these contracts was being recovered through the FCA, and now with
the elimination of the FCA, the revenue formerly allocated by the FCA to the
recovery of the cost of these contracts became available for general
corporate purposes, including the necessity to purchase replacement power and
to service the financing of the buyback cost.
Finally, the MPUC acknowledged with approval the Company's commitment to
attempt to cap existing electric rates at current levels for an extended
period and expressed a desire to formalize the details of such a commitment
by agreement of the affected parties. To date, the Company has not succeeded
in reaching agreement with other interested parties, and the Commission has
scheduled a formal hearing process to address the issue in 1996.
BUYBACK OF PURCHASED POWER CONTRACTS-The Company has been attempting to
alleviate the adverse impact of the high-cost contracts for the purchase of
power from independent, non-utility generators with whom the Company had been
obliged to contract in the 1980s. One method for doing so has been to pay a
fixed sum in return for terminating a contract. The first such transaction
was accomplished in 1993, and in 1995 the Company succeeded in accomplishing
two more. The 1995 transactions involved a "buyback" of the contracts for the
purchase of power from two biomass-fueled generating plants in West Enfield
and Jonesboro, Maine, which are identical plants under common ownership. The
buyback cost was approximately $170 million, including transaction costs.
The cost of the buyback was financed entirely by new debt instruments,
thereby significantly increasing the Company's indebtedness. The major
components of the new debt are as follows:
1. The Company has entered into a Loan Agreement with the Finance Authority
of Maine (FAME), a body corporate and politic and public instrumentality of
the State of Maine. Pursuant to authorizing legislation in Maine, FAME issued
$126 million of notes through a private placement, the repayment of which is
the responsibility of the Company under the terms of the Loan Agreement. Of
that amount, approximately $105 million was made available to the Company to
finance a portion of the buyback and approximately $21 million was set aside
in a capital reserve fund. The notes bear interest at an annual rate of
7.03%, mature on July 1, 2005 and are subject to a schedule of annual
principal payments beginning on July 1, 1998. The amount held in the capital
reserve fund will be used to pay the final installments of principal and
interest due in 2005. The assets in the capital reserve fund are invested in
a guaranteed annuity contract, earning interest at a rate of 6.51%, and the
interest earnings are utilized to offset the semiannual interest payments on
the FAME notes.
In order to secure the FAME notes, the Company executed a new General and
Refunding Mortgage Indenture and Deed of Trust establishing a lien on the
Company's property junior to the lien under the Company's First Mortgage
Bonds Indenture. After the issuance of $115 million in Firs Mortgage Bonds to
a group of bank lenders discussed below, the Company may not issue any
additional First Mortgage Bonds in the future except to the trustee under the
new General and Refunding Mortgage. The Company issued bonds to FAME under
the new mortgage in the amount of $126 million.
2. The Company entered into a Credit Agreement with a group of seven banks
consisting of a revolving credit facility in the initial amount of $55
million and a term loan in the amount of $60 million. The revolving credit
facility replaced the Company's short-term credit facilities that existed
prior to the closing, and also provided for the issuance of a letter of
credit required to support $4.2 million of the Company's Pollution Control
Revenue Bonds. The revolving credit facility has a term of five years. The
term loan, used to finance a portion of the buyback cost, also has a
five-year term and requires annual principal payments of $12 million
beginning June 30, 1996. The Credit Agreement has various options for
interest charges under variable rate formulas, but the Company was required
to enter into a transaction to cap or fix the rate of interest on the term
loan within 120 days of the execution of the Agreement. In August 1995, the
Company entered into agreements with three banks to cap the interest rate at
7.25%, with the cost to cap the interest rate amounting to $624,000. These
costs are being amortized over the life of the term loan. The Credit
Agreement is secured by $115 million of non-interest bearing First Mortgage
Bonds.
In addition to the buyback costs incurred to date, the Company is committed
under certain conditions to reimburse the towns of Enfield and Jonesboro for
lost property tax revenues in an amount not expected to exceed $1.4 million
over a two-year period.
The debt instruments executed in connection with this financing contain a
number of covenants and restrictions that the Company believes to be usual
and customary for such a transaction, including limitations on the aggregate
amount of indebtedness that the Company may incur and restrictions on the
payment of dividends.
The Company believes that the accomplishment of this transaction will provide
substantial benefits for its customers, and should enhance the Company's
prospects for improved earnings sooner than if the buyback did not occur.
REDUCTION OF DIVIDEND ON COMMON STOCK In June of 1995, the quarterly dividend
on common stock was reduced by $.15 from the prior quarterly level of $.33
per share that the Company had been paying since early 1992, to $.18 per
share. This resulted in a reduction in the indicated annual rate from $1.32
to $.72.
The Company had announced in March 1995 that a reduction in the common
dividend was likely to occur during the year. The reduction had been
occasioned by the continuing pressure on earnings and the necessity to avoid
further rate increases as the Company, along with the rest of the electric
utility industry, adjusts to a more competitive business environment.
As a result of the financial impact of the Maine Yankee outage and the cost
of an early retirement and severance program implemented in 1995, both
discussed below, the Company's common dividends were not covered by earnings
in 1995, even after taking into consideration the dividend reduction.
MAINE YANKEE-The Company, through its equity investment totalling
approximately $5.0 million at December 31, 1995, owns 7% of the common stock
of Maine Yankee Atomic Power Company (Maine Yankee), which owns and operates
an 880 megawatt nuclear generating plant in Wiscasset, Maine, and is entitled
under a cost-based power contract to an approximately equal percentage of the
plant's output. The Maine Yankee plant, like other pressurized water
reactors, experienced degradation of its steam generator tubes, principally
in the form of circumferential cracking, which, until early 1995, was
believed to be limited to a relatively small number of tubes. During the
refueling and maintenance shutdown that commenced in February 1995, Maine
Yankee detected through new inspection methods increased degradation of the
plant's steam generator tubes to the extent that approximately 60% of the
plant's 17,000 steam generator tubes appeared to have defects to some degree.
Because of the large number of affected tubes, the remedy of plugging the
degraded tubes to take them out of service was no longer a viable option.
Following a detailed analysis of the safety, technical and financial
considerations associated with the degraded steam generator tubes, Maine
Yankee elected to repair the tubes by inserting and welding short reinforcing
sleeves of an improved material in substantially all of the plant's steam
generator tubes. Similar repairs have been completed at other nuclear plants
in the United States and abroad, but not on the scale of the Maine Yankee
project. With Westinghouse Electric Corporation as the general contractor,
the sleeving project started in early June of 1995, after approval of the
Westinghouse sleeving process by the Nuclear Regulatory Commission (NRC), and
was essentially completed in early December. The repairs were estimated to
cost $40 million, but Maine Yankee now estimates the project was completed
for approximately $27 million. The Company charged to operations its share of
the repair costs in 1995.
During 1995, the Company incurred substantial costs for replacement power,
and as explained above, since the FCA was eliminated at the beginning of
1995, the replacement power costs had a material impact in reducing earnings
in 1995. After Maine Yankee went off-line, the Company incurred
non-reconcilable incremental replacement power costs of approximately $8.6
million for the year. Combined with the Company's share of the repair cost,
the Maine Yankee outage adversely impacted the Company's earnings in 1995 by
$.86 per common share, after taxes.
On December 4, 1995, when the resleeving project was substantially complete,
Maine Yankee received a copy of a letter, from an organization with a history
of opposing nuclear power development, to a State of Maine nuclear safety
official based on documentation from an anonymous former employee of Yankee
Atomic Electric Company (Yankee), an affiliate of Maine Yankee and other
nuclear plant operators. The letter contained allegations that Yankee
knowingly performed inadequate analyses to support two license amendments to
increase the rated thermal power at which the Maine Yankee plant could
operate. It was further alleged in the letter that Maine Yankee deliberately
misrepresented the analyses to the NRC in seeking license amendments. The
allegedly inadequate analyses related to the operation of the plant's
emergency core cooling system (ECCS) and the calculation of the plant's
containment peak postulated accident pressure, both under certain assumed
accident conditions. The analyses were used in support of license amendments
that authorized an increased rating of the plant from a level equal to
approximately 90% of the maximum electrical capability of the plant to its
current 100% rated level.
In response to technical issues raised by the allegations, the NRC initiated
a special technical review of the safety analysis performed by Yankee
relating to Maine Yankee's license amendment applications for the power
uprates. At the same time, Maine Yankee and Yankee initiated intensive
internal investigations of the allegations and provided responsive
information and documentation to the NRC.
On December 18, 1995, a public meeting was held at the NRC to discuss the
findings resulting from the NRC's technical review. At the meeting the NRC
informed Maine Yankee that it had concerns regarding the adequacy of a
proprietary computer code used in ECCS safety analyses supporting Maine
Yankee's last two applications for license amendments that authorized power
uprates to levels above 90% of its current maximum capacity. At the meeting
the NRC also indicated that operation of the plant at a level up to 90% could
be acceptable if operations were based on methods previously found acceptable
by the NRC staff and not on the computer code that is currently under review
by the NRC, and further informed Maine Yankee of the terms and conditions
under which Maine Yankee could resume power operation of the plant.
Subsequently, the NRC informed Maine Yankee that the allegations made in the
anonymous letter would be the subject of investigations by the NRC's Office
of Investigations and the Office of the Inspector General.
On January 3, 1996, the NRC issued a "Confirmatory Order Suspending Authority
For And Limiting Power Operation And Containment Pressure (Effective
Immediately) And Demand For Information" (the Confirmatory Order) confirming
the conclusions of the NRC from the public meeting and follow-up
communications with Maine Yankee. The Confirmatory Order limited the power
output of the Maine Yankee plant to approximately 90% of its rated maximum
until the NRC shall have reviewed and approved plant-specific analyses
meeting the NRC's criteria for operation of the ECCS under certain postulated
accident conditions, in lieu of the analyses based on the questioned computer
code. The Confirmatory Order further required that prior to operating the
plant at any level, Maine Yankee should submit under oath specified
information relating to operating the plant at up to the 90% level and
descriptions of measures taken to assure compliance with the limitations on
operating level and containment pressure.
With respect to subsequently returning the plant to its 100% operating level,
the Confirmatory Order required Maine Yankee to submit a plant-specific
analysis meeting the NRC's requirements for ECCS operation under specified
conditions at plant power levels up to 100% of its maximum rated capability.
The Confirmatory Order also required an integrated containment analysis
demonstrating that the maximum calculated containment pressure under certain
postulated accident conditions does not exceed the design-basis pressure of
the plant's containment. In addition, the Confirmatory Order required Maine
Yankee to submit a schedule for providing the requested analyses and related
information to the NRC.
As of this writing, the Maine Yankee plant is operating at the 90% level, and
Maine Yankee is continuing its efforts to meet the NRC's requirements to
return to the 100% operating level. The Company cannot predict when the plant
will gain the authority to return to the 100% operating level or when it will
achieve this level once authority is granted. As a result of Maine Yankee's
operating limitation, the Company will incur replacement power costs of
between $70,000 and $100,000 per month as long as that limitation is in
effect. Finally, the Company cannot predict the results of the internal and
external investigations of the allegations brought to Maine Yankee's
attention on December 4, 1995. Maine Yankee has stated, however, that it
intends to pursue its internal investigation diligently and cooperate with
the governmental investigations, and that it believes that after it develops
information requested by the NRC for operation of the plant at full capacity
it will be able to operate the plant at that level while meeting all
applicable NRC safety requirements.
ACQUISITION OF WHOLESALE CUSTOMER-On October 26, 1995, the Company acquired
the assets and service territory of its largest full requirements wholesale
customer for a purchase price of approximately $2.4 million. The customer
served approximately 1,800 customers.
COST REDUCTIONS - In the third quarter of 1995 the Company implemented an
early retirement and severance program, resulting in approximately another
10% reduction in the Company's work force, and amounting to a onetime,
non-cash charge to operations of $2.3 million or $.32 per common share (net
of income taxes). Although this program will result in future cost savings,
accounting guidelines required that the Company record the expense of the
downsizing program in the period in which it was implemented.
OTHER - The Company occasionally makes forward-looking statements such as
forecasts and projections of expected future performance or statements of the
Company's plans and objectives. These forward-looking statements may be
contained in filings with the Securities and Exchange Commission, press
releases and oral statements. Actual results could potentially differ
materially from these statements. Therefore, no assurances can be given that
such forward-looking statements and estimates will be achieved.
LIQUIDITY, CAPITAL REQUIREMENTS, AND CAPITAL RESOURCES
The Consolidated Statements of Cash Flows reflect events for the years ended
December 1995, 1994 and 1993 as they affect the Company's liquidity. Net cash
used in operations was $164.5 million in 1995. In 1995 the Company expended
approximately $197.7 million related to the purchased power contracts buyback
($168.7 million) and related financing costs ($29.0 million). These financing
costs included debt issuance cots ($2.8 million), funding of the capital
reserve fund ($21.2 million), collateral deposited with a third party
trustee, pledged on the Company's letter of credit associated with its
Pollution Control Revenue Bonds ($4.4 million), and the interest rate cap
arrangements entered into as required by the financings ($.6 million). Upon
establishing of a new letter of credit, the $4.4 million in collateral was
released to the Company in the third quarter of 1995. The receipt of these
funds is reflected in the Consolidated Statements of Cash Flows in Other, net
and was utilized to pay down outstanding short-term debt.
Exclusive of the costs to buy back the purchased power contracts, which were
entirely debt financed (see below), cash flows provided by operations were
$33.2 million in 1995 as compared to $29.3 million in 1994. With the
elimination of these purchased power contracts, the Company incurred no
purchased energy costs related to the contracts in the period from July 1995
through December 1995, while in the comparable 1994 period, the Company
incurred approximately $13.5 million in costs under these contracts. Another
component of the increase in cash flows from operations is the reduction in
payroll costs in 1995 as compared to 1994. Due principally to the reduction
in the work force through the early retirement plans in 1995 and 1994, labor
costs were approximately $1.4 million lower in 1995 as compared to 1994.
Also enhancing cash flows from operations in 1995 as compared to 1994 were
Company contributions to the defined benefit pension plans. In 1994 the
Company contributed approximately $1.2 million to the non-bargaining unit
plan, while in 1995, with the merging of the bargaining unit and
non-bargaining unit plans, no contributions were required. This was due to
the overfunded status of the bargaining unit plan prior to the merger. These
enhancements to cash flows from operations were offset to some extent by the
additional costs incurred in 1995 to replace the Company's share of Maine
Yankee output, amounting to approximately $8.6 million, as well as $1.9
million in costs associated with the resleeving project.
Over the last three years, capital expenditures have been $19.5 million in
1995, $21.5 million in 1994 and $33.6 million in 1993 (including overhead
costs allocated to the capital program). In 1995, approximately $2.0 million
of the capital expenditures was related to the Company's power production
facilities, $7.8 million was for its distribution system, $4.8 million was
for its transmission system, and $3.0 related to implementing new customer
and geographic information systems, with the remainder related to other
general property and equipment, and costs associated with the licensing of
new and the relicensing of existing hydroelectric projects. As previously
discussed, the Company acquired the assets of its largest full-requirements
wholesale customer in October 1995 at a cost of approximately $2.4 million.
The 1993 expenditures included about $11.4 million for two major
rehabilitation projects for the Company's hydroelectric system. The Company
expects its capital expenditures to total about $33 million (excluding
capitalized overheads) over the next three years, although it may be
necessary to adjust the budget for capital expenditures on a year-to-year
basis.
As previously discussed, the Company reduced its quarterly dividend by $.15
from the prior quarterly level of $.33 per share, effective for the quarter
ending June 30, 1995. This reduction has improved cash flows through a $2.2
million reduction in common dividend payments in 1995 as compared to 1994.
Capital needs in 1995 were met through internally generated funds, and due to
the 1995 buyback of purchased power contracts significantly reducing the
Company's cash needs for purchased power payments, the Company expects to
similarly meet all of its capital needs for the foreseeable future.
Accordingly, the Company does not currently have plans to issue any new debt
or equity securities. As previously discussed, the purchased power contract
buyback in 1995 was financed through the issuance of $126 million of FAME
Revenue Notes and $60 million of Medium Term Notes, thereby significantly
increasing the Company's indebtedness. Additional short-term borrowings were
also made in 1995 under the Company's revolving credit agreement to finance
this transaction. In 1995 the Company raised approximately $1.2 million
through the issuance of 116,414 shares of common stock under the Dividend
Reinvestment Plan. Also during 1995, the Company made approximately $2.1
million of required and optional sinking fund payments on its 12.25% First
Mortgage Bonds.
In 1994 the Company raised approximately $14.1 million with the issuance and
sale of 867,500 shares of common stock and approximately $1.3 million
through the issue of 92,249 shares under the Dividend Reinvestment Plan. Also
during 1994 the Company made $2.6 million in required and optional sinking
fund payments on its 12.25% First Mortgage Bonds. External capital in 1993
was provided by the issuance of 745,000 shares of common stock with proceeds
of $14.8 million, the issuance of 59,439 common shares raising approximately
$1.2 million under the Dividend Reinvestment Plan, and the issuance of $15
million 7.3% First Mortgage Bonds. The bonds contain no provisions for
sinking fund payments.
The Company has $110.7 million of First Mortgage Bond and other long-term
debt sinking fund requirements and maturities in the period 1996-2000. The
Company also has $1.5 million of required annual sinking fund payments on its
mandatory redeemable preferred stock.
In addition to requiring funds for capital improvements, the Company has from
time to time required funds to finance "regulatory assets" (such as the cost
of buying out of the high-cost contracts). Accounting rules applicable to
regulated utilities allow the establishment of regulatory assets for costs
accumulated for certain items other than the usual and customary capital
assets, and allow the deferral of the income statement impact of those costs
if they are expected to be recovered in future rates. As of December 31,
1995, the Company has net regulatory assets of approximately $250.7 million.
The effects of competition could ultimately cause the operations of the
Company, or a portion thereof, to cease meeting the criteria for application
of the accounting rules for regulatory assets. If this were to occur,
accounting standards of enterprises in general would apply and unamortized
balances of regulatory assets would be charged to operations in the year in
which those criteria were no longer applicable.
RESULTS OF OPERATIONS
Earnings per common share were $.36, $.84 and $.63, and the earned return on
average common equity was 2.5%, 5.5% and 4.0% for the years ended 1995, 1994
and 1993, respectively. In the three years presented, reported earnings
reflected significant onetime charges. Negatively impacting earnings in 1995
were the previously discussed shutdown of Maine Yankee and the cost of the
early retirement and severance program in 1995. The Company charged
approximately $2.8 million before taxes ($.24 per common share after taxes)
in 1994 to operations to reflect the cost of an early retirement program. The
1994 and 1995 work force reduction programs are now providing savings in the
form of reduced labor costs. In 1993 the Company established a reserve for
the full amount of licensing costs spent through 1993 on the Basin Mills and
Veazie hydroelectric projects. This reserve, which amounted to $8.7 million
before taxes, resulted in a $.95 reduction in earnings per common share after
taxes for the year ended December 31, 1993.
The Company's total revenues and consequently its earnings are influenced to
a large extent by the regulation of retail rates by the MPUC. Under Maine
law, the Company had historically collected revenue from its customers
separately through "base rates" and through a "fuel cost adjustment" (the
FCA see the discussion above of the Company's Alternative Marketing Plan
approved by the MPUC). Base rates were established from time to time in order
to permit the Company an opportunity to recover its costs of providing
electric service that are not included in the FCA, and to recover the
investment, and earn a reasonable return thereon, in plant and equipment to
provide that service. The FCA had also included the cost of the contracts
with the non-utility independent power producers. The FCA was a positive or
negative adjustment that was reconciled after the fact to reflect changes in
the cost of fuel for generation and certain costs of purchased power. With
the AMP order issued by the MPUC on February 14, 1995, the FCA was eliminated
effective January 1, 1995.
On February 17, 1994, the MPUC issued an order allowing the Company,
effective March 1, 1994, to increase its base rates by $11.1 million. This
represented a 15.9% increase in base rates and an increase in average overall
rates of 7.9%. More than half of the rate increase was designed to allow
recovery of the costs associated with the 1993 buyout of the Beaver Wood
purchased power contract, and it was offset to a large extent by a reduction
in the FCA attributable directly to the buyout. The MPUC order provided an
authorized return on common equity of 10.6%. However, the Company failed to
earn that authorized return in 1994 primarily because the MPUC order was
based upon an overly optimistic projection of energy sales, the Company made
certain pricing concessions to its customers as discussed above, and because
of the onetime charge for the early retirement program discussed above. The
Company did not earn its authorized return in 1995, as well, due to the
reasons noted for 1994, the expense associated with the 1995 early retirement
and severance program, and the impact of the Maine Yankee shutdown.
Electric operating revenue increased by $10.8 million in 1995 compared to
1994, or 6.2% reflecting, in part, the rate increase that took effect in
March 1994 and a 4.4% increase in kilowatt-hour (KWH) sales. The majority of
the KWH sales increase is related to special contracts which the Company
entered into with three large industrial customers. KWH sales to these
customers increased 21% in 1995, resulting in associated revenues increasing
$2.7 million or 1.4%. One of the special contracts has a revenue sharing
arrangement which resulted in additional revenue from that customer of $3.5
million in 1995. Revenue from off-system sales increased by $1.4 million as
well. Absent the special contracts, KWH sales from other customer classes
were flat in l995 as compared to 1994.
The $3.9 million, or 2.2% decrease in electric operating revenues in 1994 as
compared to 1993 was due to the previously discussed pricing concessions made
to two large industrial customers in 1994, a $2.6 million decrease in
off-system sales and the 12.9% fuel rate decrease effective November 1, 1993.
These decreases were offset to some extent by the 15.9% base rate increase
effective March 1, 1994. KWH sales for 1994, excluding special contract
customers, were flat as compared to 1993.
In conjunction with the FCA, the MPUC authorized the Company to use a
deferred fuel accounting methodology under which fuel revenue essentially
matched fuel expense, which was in effect for each of 1993 and 1994. With the
elimination of the FCA effective January 1, 1995, deferred fuel accounting
has been eliminated. This change has required the Company to record, as
expense, actual fuel costs incurred. The deferred fuel revenue balance at
December 31, 1995 appears on the Consolidated Balance Sheets as a liability
of $2.0 million, which is being amortized over a three-year period beginning
January 1, 1995 as a reduction in fuel expense and is a benefit to earnings.
The significant decrease in fuel expense in 1995 is related to the buyback
of the high cost non-utility generator purchased power contracts on June 30,
1995, which eliminated the purchased energy costs in the last two quarters of
1995 for this non-utility generator (1994 comparable expense was $13.5
million). Also in 1995, certain purchased power capacity costs are no longer
reclassified to fuel for generation, due to the elimination of the FCA. In
1994, $2.2 million of such costs were reflected in fuel for generation. These
decreases were offset to some extent by the elimination of the FCA in the
first quarter of 1995, as well as $8.6 million in incremental costs in 1995
for Maine Yankee replacement power.
The increase in purchased power capacity costs in 1995 was due to the Company
recording its share of the costs of the Maine Yankee resleeving project,
amounting to approximately $1.9 million. Also in 1995, as previously
discussed, certain purchased power capacity costs are no longer reclassified
to fuel for generation. These increases were offset to some extent because,
with Maine Yankee off-line in 1995, there was no need to amortize Maine
Yankee's refueling cost. The Company amortizes these costs over the period of
operation following the refueling activity, which in this case began in
January 1996.
Other operation & maintenance (O&M) expense increased by $2.2 million in 1995
as compared to 1994 due principally to the previously discussed impact of the
early retirement and severance program in 1995, as well as a $1.7 million
increase in bad debt expense in 1995. These increases were offset by the $2.8
million charged to operations in 1994 related to the early retirement
program, as well as a $1.4 million decrease in O&M payroll expense in 1995 as
compared to 1994. The reduction in payroll expense was principally a function
of fewer employees accomplished through the work force reduction programs in
1994 and 1995, as well as greater levels of capital labor in 1995.
The $4.0 million increase in other O&M expense in 1994 as compared to 1993
was principally due to the previously mentioned early retirement program in
1994. Other major increases in 1994 expenses included a $1.4 million increase
in medical costs (including the full amount of expense for postretirement
benefits in accordance with Financial Accounting Standards Board Statement
No. 106 "Employers' Accounting for Postretirement Benefits Other Than
Pensions" which was implemented on January 1, 1993 and included in rates
beginning March 1, 1994) and $745,000 in amortization of certain deferred
costs for which recovery was allowed in the most recent base rate order.
The Company's expenses over the period 1993-1995 have been significantly
affected by amortizations authorized by the MPUC and charged annually against
earnings. The MPUC has specifically authorized the inclusion of these
expenses in the Company's base rates. Absent such regulatory authority, the
expenses that gave rise to the amortizations would have been charged to
operations when incurred. Instead, the recognition of such expenses has been
deferred, and appear on the Consolidated Balance Sheets as assets on the
strength of the regulatory authority to amortize them and collect from
customers (thus the term "regulatory assets"). Although there are a number of
such authorized amortizations, the major ones are the allowable recovery of
the Company's investment in the Seabrook nuclear power units (which it sold
in 1986) and the costs associated with the 1993 and 1995 purchased power
contract terminations. The Company's recoverable investment in Seabrook Unit
1 is being amortized at a rate of $1.7 million per year beginning in 1986 for
a period of 30 years. Effective March 1, 1994, as authorized in the base rate
order from the MPUC, the Company began amortizing the deferred costs
associated with the Beaver Wood contract termination at a rate of $3.9
million annually over a nine-year period. Under the AMP, the approximately
$170 million of costs associated with the 1995 purchased power contract
buyback have been deferred and recorded as a regulatory asset, to be
amortized and collected over a ten year period, beginning July 1, 1995, at an
annual expense of $16.9 million.
AFDC decreased in 1995 as compared to 1994, and for 1994 relative to 1993
primarily because the Company ceased accruing carrying costs associated with
the Beaver Wood purchased power contract termination when recovery was
authorized by the MPUC on March 1, 1994, as well as lower levels of
construction activity in each of 1995 and 1994. Also impacting the decrease
in AFDC in 1994 as compared to 1993 was the cessation at the end of 1993 of
accruing AFDC on costs related to the Basin Mills project.
The increase in long-term debt interest expense in 1995 as compared to 1994
was a result of incurring $186 million in debt in association with financing
the cost of the purchased power contract buyback on June 30, 1995. Other
interest expense increased in 1995 and 1994 as a result of higher levels of
borrowings under the revolving credit facility, as well as an increase in
short-term interest rates in each of 1995 and 1994 compared to the prior
years. Increased borrowing activity in 1995 was partly a function of
additional funds necessary for the cost of the purchased power contract
buyback.
CONTINGENCIES
In 1992, the Company received notice from the Maine Department of
Environmental Protection (MDEP) that it was investigating the cleanup of
several sites in Maine that were used in the past for the disposal of waste
oil and other hazardous substances, and that the Company, as a generator of
waste oil that was disposed at those sites, may be liable for certain cleanup
costs. The Company learned in October 1995 that the United States
Environmental Protection Agency placed one of the sites on the National
Priorities List under the Comprehensive Environmental Response, Compensation,
and Liability Act and will pursue potentially responsible parties. With
respect to this site, the Company is one of a number of waste generators
under investigation, and it is too early in the process to speculate on the
extent of the Company's potential liability. As to the only other site which
has been listed by the MDEP as an Uncontrolled Hazardous Substance Site, the
Company was informed that it is considered a de minimis generator.
NEW ACCOUNTING STANDARDS
In March 1995 the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards No. 121 (FAS 121), "Accounting for the
Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of",
effective for financial statements for fiscal years beginning after December
15, 1995. FAS 121 establishes accounting standards for the impairment of
long-lived assets, certain identifiable intangibles, and goodwill related to
those assets to be held and used and for long-lived assets and certain
intangibles to be disposed of. It establishes guidance for recognizing and
measuring impairment losses and requires that the carrying amount of impaired
assets be reduced to fair value. In addition, FAS 121 requires that all
regulatory assets, which must have a high probability of recovery to be
initially established, continue to meet that high probability standard or be
written-off. However, if written-off, a regulatory asset can be restored if
it regains a high probability of recovery. Management is currently evaluating
the financial impact of this accounting standard, but as long as the cost of
the Company's long-lived assets and intangibles continues being recovered
through its electric rates, as is currently the case, the effect of FAS 121
on the Company's results of operations and financial position is not expected
to be significant. Management cannot predict the outcome of the possibility
of further competition and deregulation of the electric utility industry, or
the impact thereof on the application of this accounting standard.
ITEM 8
- ------
FINANCIAL STATEMENTS & SUPPLEMENTARY DATA
- -----------------------------------------
BANGOR HYDRO-ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF INCOME
For the Years Ended December 31,
1995 1994 1993
ELECTRIC OPERATING REVENUE (Note 1): $184,913,771 $ 174,097,860 $ 177,971,770
-----------------------------------------
OPERATING EXPENSES:
Fuel for generation (Note 1) $ 82,301,027 $ 90,339,056 $ 102,670,217
Purchased power capacity (Notes 1
and 6) 16,382,964 13,793,383 13,716,436
Other operation and maintenance
(Notes 1, 5 and 9) 35,711,185 33,497,912 29,474,327
Depreciation and amortization
(Note 1) 6,522,019 5,395,045 4,747,491
Amortization of Seabrook Nuclear
Project (Note 7) 1,699,050 1,699,050 1,699,050
Amortization of contract buyouts
(Note 6) 12,322,570 3,238,630 -
Taxes -
Local property and other 4,884,565 5,189,324 4,102,097
Income (Note 2) 1,421,674 3,613,598 4,762,945
-----------------------------------------
$161,245,054 $ 156,765,998 $ 161,172,563
-----------------------------------------
OPERATING INCOME $ 23,668,717 $ 17,331,862 $ 16,799,207
OTHER INCOME AND (DEDUCTIONS):
Provision for Basin Mills (Note 6) - - (8,695,539)
Income tax benefits related to
provision for Basin Mills (Note 6) - - 3,137,895
Allowance for equity funds used
during construction (Note 1) 561,898 1,256,307 2,464,934
Other, net of applicable income taxes
(Notes 1 and 2) 197,924 51,850 435,316
-----------------------------------------
INCOME BEFORE INTEREST EXPENSE $ 24,428,539 $ 18,640,019 $ 14,141,813
-----------------------------------------
INTEREST EXPENSE:
Long-term debt (Note 4) $ 17,596,586 $ 10,767,934 $ 10,438,828
Other (Note 4) 3,201,030 1,754,391 1,164,795
Allowance for borrowed funds used
during construction (Note 1) (705,552) (1,339,379) (2,798,241)
-----------------------------------------
$ 20,092,064 $ 11,182,946 $ 8,805,382
-----------------------------------------
NET INCOME $ 4,336,475 $ 7,457,073 $ 5,336,431
DIVIDENDS ON PREFERRED STOCK (Note 3) 1,701,960 1,652,432 1,645,663
-----------------------------------------
EARNINGS APPLICABLE TO COMMON STOCK $ 2,634,515 $ 5,804,641 $ 3,690,768
=========================================
EARNINGS PER COMMON SHARE, based on the
weighted average number of shares
outstanding of 7,264,360 in 1995,
6,947,746 in 1994 and 5,862,411
in 1993 $ 0.36 0.84 0.63
=========================================
DIVIDENDS DECLARED PER COMMON SHARE $ 0.87 1.32 1.32
=========================================
The accompanying notes are an integral part of these consolidated
financial statements.
BANGOR HYDRO-ELECTRIC COMPANY
CONSOLIDATED BALANCE SHEETS
December 31,
1995 1994
ASSETS
INVESTMENT IN UTILITY PLANT:
Electric plant in service, at original
cost (Notes 4 and 6) $300,374,078 $ 274,829,540
Less - Accumulated depreciation and
amortization (Notes 1 and 6) 81,933,769 75,666,792
---------------------------
$218,440,309 $ 199,162,748
Construction work in progress (Note 1) 18,151,265 23,928,702
---------------------------
$236,591,574 $ 223,091,450
Investments in corporate joint ventures (Notes 1
and 6) -
Maine Yankee Atomic Power Company $ 5,013,781 $ 4,753,548
Maine Electric Power Company, Inc. 124,900 124,900
---------------------------
$241,730,255 $ 227,969,898
---------------------------
OTHER INVESTMENTS, principally at cost (Note 6) $ 4,184,626 $ 3,481,703
---------------------------
FUNDS HELD BY TRUSTEE at cost (Notes 4 and 10) $ 21,191,940 -
---------------------------
CURRENT ASSETS:
Cash and cash equivalents (Note 1 and 10) $ 1,424,266 $ 1,956,159
Accounts receivable, net of reserve ($1,450,000
in 1995 and $730,000 in 1994) 18,226,453 19,129,910
Unbilled revenue receivable (Note 1) 8,821,440 8,611,479
Inventories, at average cost:
Materials and supplies 3,028,911 2,992,496
Fuel oil 105,871 435,001
Prepaid expenses 1,737,507 1,680,753
Deferred Maine Yankee refueling costs (Note 12) 2,418,658 235,544
Current deferred income taxes (Note 2) - 1,094,355
---------------------------
Total current assets $ 35,763,106 $ 36,135,697
---------------------------
DEFERRED CHARGES:
Investment in Seabrook Nuclear Project, net of
accumulated amortization of $25,076,046 in 1995
and $23,376,996 in 1994 (Notes 7 and 12) $ 33,766,029 $ 35,465,079
Costs to terminate purchased power contracts, net
of accumulated amortization of $15,561,200 in
1995 and $3,238,630 in 1994. (Notes 6 and 12) 192,140,252 36,738,549
Deferred regulatory assets (Notes 2, 5 and 12) 30,328,451 33,536,787
Prepaid pension costs (Note 5) - 2,082,047
Demand-side management costs (Note 12) 1,945,944 2,684,107
Other (Note 12) 5,025,887 3,156,178
---------------------------
Total deferred charges $263,206,563 $ 113,662,747
---------------------------
Total Assets $566,076,490 $ 381,250,045
===========================
The accompanying notes are an integral part of these consolidated
financial statements.
BANGOR HYDRO-ELECTRIC COMPANY
CONSOLIDATED BALANCE SHEET
December 31,
1995 1994
STOCKHOLDERS' INVESTMENT AND LIABILITIES
CAPITALIZATION (see accompanying statement):
Common stock investment (Note 3) $103,191,680 $105,657,684
Preferred stock (Note 3) 4,734,000 4,734,000
Preferred stock subject to mandatory redemption,
exclusive of sinking fund requirements
(Notes 3 and 10) 12,070,003 13,740,491
Long-term debt, net of current portion
(Notes 4, 10 and 15) 288,074,966 116,367,155
---------------------------
Total capitalization $408,070,649 $240,499,330
---------------------------
CURRENT LIABILITIES:
Notes payable - banks (Note 4) $ 35,000,000 $ 27,000,000
---------------------------
Other current liabilities -
Current portion of long-term debt and sinking
fund requirements on preferred stock
(Notes 3, 4 and 10) $ 16,938,615 $ 2,961,253
Accounts payable 10,526,642 14,668,512
Dividends payable 1,709,209 2,766,026
Accrued interest 4,907,820 3,650,195
Deferred fuel revenue (Notes 1 and 12) 2,016,798 3,025,194
Customers' deposits 348,676 287,699
Current income taxes payable - 965,614
---------------------------
Total other current liabilities $ 36,447,760 $ 28,324,493
---------------------------
Total current liabilities $ 71,447,760 $ 55,324,493
---------------------------
COMMITMENTS AND CONTINGENCIES (Notes 6, 8 and 15)
DEFERRED CREDITS AND RESERVES (Note 2):
Deferred income taxes - Seabrook $ 17,546,355 $ 18,434,070
Other accumulated deferred income taxes 50,775,034 50,083,738
Deferred regulatory liability (Note 12) 8,567,904 9,221,892
Unamortized investment tax credits 2,354,052 2,415,245
Accrued pension (Note 5) 626,249 -
Other (Note 5) 6,688,487 5,271,277
---------------------------
Total deferred credits and reserves $ 86,558,081 $ 85,426,222
---------------------------
Total Stockholders' Investment and Liabilities $566,076,490 $381,250,045
===========================
The accompanying notes are an integral part of these consolidated
financial statements.
BANGOR HYDRO-ELECTRIC COMPANY
STATEMENTS OF CAPITALIZATION
December 31,
1995 1994
Common Stock Investment (Notes 1 and 3):
Common stock, par value $5 per share-
Authorized -- 10,000,000 shares
Outstanding -- 7,301,557 shares in 1995 and
7,185,143 shares in 1994 $ 36,507,785 $ 35,925,715
Amounts paid in excess of par value 56,610,548 55,974,218
Retained earnings 10,073,347 13,757,751
- --------------------------------------------------------------------------------
Total Common Stock $103,191,680 $ 105,657,684
- --------------------------------------------------------------------------------
Preferred Stock, Non-participating, cumulative, par
value $100 per share,
authorized 600,000 shares (Notes 3 and 10):
Not redeemable or redeemable solely at the
option of the issuer-
7%, Noncallable, 25,000 shares authorized
and outstanding $ 2,500,000 $ 2,500,000
4-1/4%, Callable at $100, 4,840 shares
authorized and outstanding 484,000 484,000
4%, Series A, Callable at $110, 17,500
shares authorized and outstanding 1,750,000 1,750,000
- --------------------------------------------------------------------------------
$ 4,734,000 $ 4,734,000
- --------------------------------------------------------------------------------
Subject to mandatory redemption requirements-
8.76%, Callable at $105.01% if called on or
prior to December 27,1996,
150,000 shares authorized and
outstanding $ 15,362,881 $ 15,240,491
Less-Sinking fund requirements 3,292,878 1,500,000
- --------------------------------------------------------------------------------
$ 12,070,003 $ 13,740,491
- --------------------------------------------------------------------------------
LONG-TERM DEBT (Notes 4, 10 and 15):
First Mortgage Bonds-
6.75% Series due 1998 $ 2,500,000 $ 2,500,000
10.25% Series due 2019 15,000,000 15,000,000
10.25% Series due 2020 30,000,000 30,000,000
8.98% Series due 2022 20,000,000 20,000,000
7.38% Series due 2002 20,000,000 20,000,000
7.30% Series due 2003 15,000,000 15,000,000
12.25% Series due 2001 9,020,703 11,128,408
- --------------------------------------------------------------------------------
$111,520,703 $ 113,628,408
Less-Sinking fund requirements 1,645,737 1,461,253
- --------------------------------------------------------------------------------
$109,874,966 $ 112,167,155
- --------------------------------------------------------------------------------
Variable rate demand pollution control revenue
bonds Series 1983 due 2009 $ 4,200,000 $ 4,200,000
- --------------------------------------------------------------------------------
Other Long-Term Debt-
Finance Authority of Maine - Taxable Electric
Rate Stabilization
Revenue Notes, 7.03% Series 1995A, due 2005 $126,000,000 $ -
- --------------------------------------------------------------------------------
Medium Term Notes, Variable interest rate-
LIBOR plus 2%, due 2000 $ 60,000,000 $ -
Less: Current portion of long-term debt 12,000,000 -
- --------------------------------------------------------------------------------
$ 48,000,000 $ -
- --------------------------------------------------------------------------------
Total long-term debt $288,074,966 $ 116,367,155
- --------------------------------------------------------------------------------
Total Capitalization $408,070,649 $ 240,499,330
================================================================================
The accompanying notes are an integral part of these consolidated
financial statements.
<TABLE>
Bangor Hydro-Electric Company
CONSOLIDATED STATEMENTS OF CASH FLOWS
<CAPTION>
For the Years Ending December 31,
1995 1994 1993
<S> <C> <C> <C>
Cash Flows From Operations:
Net Income $ 4,336,475 $ 7,457,073 $ 5,336,431
Adjustments to reconcile net income to net cash
(used in)provided by operations:
Costs to terminate purchased power contracts
(Notes 6 and 11) (197,717,853) --- (23,711,733)
Depreciation and amortization (including debt
issuance costs) (Note 1) 6,887,653 5,611,320 4,967,988
Amortization of Seabrook Nuclear Project (Note 7) 1,699,050 1,699,050 1,699,050
Amortization of costs to terminate purchased
power contracts (Note 6) 12,322,570 3,238,630 ---
Base rate case amortizations included in
operation and maintenance 1,074,867 992,871 247,986
Payment received related to terminated purchased
power contract (Note 6) 1,000,000 1,000,000 ---
Cost of early retirement and involuntary
severance plans 3,835,303 2,738,376 ---
Allowance for equity funds used during
construction (Note 1) (561,898) (1,256,307) (2,464,934)
Deferred income tax provision (Note 2) 1,791,082 2,250,851 2,258,762
Deferred investment tax credits, net (Note 2) (61,193) 143,695 (178,176)
Provision for Basin Mills Project (Note 6) --- --- 8,695,539
Changes in assets and liabilities:
Deferred fuel revenue and purchased power (Note 1) (3,191,510) 7,153,733 9,039,409
Accounts receivable, net and unbilled revenue 693,496 (1,816,459) 3,023,611
Accounts payable (4,141,870) (1,292,388) (1,081,505)
Accrued interest 1,257,625 (55,332) 1,109,433
Current and deferred income taxes 625,059 (517,084) 2,566,443
Accrued postretirement benefit costs 612,446 591,123 ---
Other current assets and liabilities, net 296,938 36,945 139,055
Other, net (Note 4) 4,719,636 1,285,426 (1,981,721)
- --------------------------------------------------------------------------------------------------------
Net Cash (Used In) Provided By Operations $ (164,522,124) $ 29,261,523 $ 9,665,638
- --------------------------------------------------------------------------------------------------------
Cash Flows From Investing:
Construction expenditures $ (19,459,606) $(21,482,132) $(33,611,031)
Allowance for borrowed funds used during construction
(Note 1) (705,552) (1,339,379) (2,798,241)
- --------------------------------------------------------------------------------------------------------
Net Cash Used In Investing $ (20,165,158)$ $(22,821,511) $(36,409,272)
- --------------------------------------------------------------------------------------------------------
Cash Flows From Financing:
Dividends on preferred stock $ (1,579,570) $ (1,579,570) $ (1,579,570)
Dividends on common stock (7,375,736) (9,116,617) (7,678,229)
Payments on long-term debt (2,107,705) (2,594,896) (15,148,118)
Issuances:
Common stock (Note 3)
Public offering (867,500 shares in 1994 and 745,000
shares in 1993) --- 14,083,863 14,803,150
Dividend reinvestment plan (116,414 shares in 1995,
92,249 shares in 1994 and 59,439 shares in 1993) 1,218,400 1,336,211 1,245,519
Long-term debt (Note 4) 186,000,000 --- 15,000,000
Short-term debt, net (Note 4) 8,000,000 (9,000,000) 21,000,000
- --------------------------------------------------------------------------------------------------------
Net Cash Provided By (Used In) Financing $ 184,155,389 $ (6,871,009) $ 27,642,752
- --------------------------------------------------------------------------------------------------------
Net Change in Cash and Cash Equivalents $ (531,893) $ (430,997) $ 899,118
Cash and Cash Equivalents - Beginning of Year 1,956,159 2,387,156 1,488,038
- --------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents - End of Year $ 1,424,266 $ 1,956,159 $ 2,387,156
- --------------------------------------------------------------------------------------------------------
Supplemental Cash Flow Information:
Cash Paid During The Year For-
Interest (Net of Amount Capitalized) $ 17,906,908 $ 9,677,372 $ 4,549,462
Income Taxes 345,834 2,226,290 ---
========================================================================================================
The accompanying notes are an integral part of these consolidated financial statements.
</TABLE>
BANGOR HYDRO-ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
For the Years Ended December 31,
1995 1994 1993
BALANCE AT BEGINNING OF YEAR $13,757,751 $17,386,444 $21,639,369
ADD - Net income 4,336,475 7,457,073 5,336,431
------------------------------------
$18,094,226 $24,843,517 $26,975,800
------------------------------------
DEDUCT:
Cash dividends declared on -
Preferred stock $ 1,579,570 $ 1,579,570 $ 1,579,570
Common stock - $.87 per share in 1995,
and $1.32 per share in 1994 and 1993 6,318,919 9,433,334 7,943,693
Other (Note 3) 122,390 72,862 66,093
------------------------------------
$ 8,020,879 $11,085,766 $ 9,589,356
------------------------------------
BALANCE AT END OF YEAR $10,073,347 $13,757,751 $17,386,444
====================================
The accompanying notes are an integral part of these consolidated
financial statements.
BANGOR HYDR0-ELECTRIC COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
NATURE OF OPERATIONS - The Company is a public utility engaged in the
generation, purchase, transmission, distribution and sale of electric energy,
with a service area of approximately 5,275 square miles having a population
of approximately 191,000 people. The Company serves approximately 103,000
customers in portions of the Maine counties of Penobscot, Hancock,
Washington, Waldo, Piscataquis, and Aroostook. The Company is subject to the
regulatory authority of the Maine Public Utilities Commission (MPUC) as to
retail rates, accounting, service standards, territory served, the issuance
of securities and other matters. The Company is also subject to the
jurisdiction of the Federal Energy Regulatory Commission (FERC) as to certain
matters, including licensing of its hydroelectric stations, rates for
wholesale purchases and sales of energy and capacity and transmission
services. The Company is a member of the New England Power Pool, and is
interconnected with other New England utilities to the south and with New
Brunswick Power Corporation to the north.
BASIS OF CONSOLIDATION-The Consolidated Financial Statements of Bangor
Hydro-Electric Company (the Company) include its wholly owned subsidiaries,
Penobscot Hydro Co., Inc. (PHC), and Bangor Var Co., Inc. (BVC). The
operations of PHC consist solely of a 50% interest in Bangor-Pacific Hydro
Associates (Bangor-Pacific), the owner and operator of the redeveloped West
Enfield hydroelectric station. PHC accounts for its investment in Bangor-
Pacific under the equity method. BVC was incorporated in 1990 to own the
Company's 50% interest in the Chester SVC Partnership (Chester), a
partnership which owns certain facilities used in the Hydro-Quebec Phase II
transmission project in which the Company is a participant. BVC accounts for
its investment in Chester under the equity method. All significant
intercompany balances and transactions have been eliminated. The accounts of
the Company are maintained in accordance with the Uniform System of Accounts
prescribed by the regulatory bodies having jurisdiction.
EQUITY METHOD OF ACCOUNTING-The Company accounts for its investments in the
common stock of Maine Yankee Atomic Power Company (Maine Yankee) and Maine
Electric Power Company, Inc. (MEPCO) under the equity method of accounting,
and records its proportionate share of the net earnings of these companies as
a reduction of purchased power capacity costs. See Note 6 for additional
information with respect to these ivestments.
ELECTRIC OPERATING REVENUE-Electric Operating Revenue consists primarily of
amounts charged for electricity delivered to customers during the period. The
Company records unbilled revenue, based on estimates of electric service
rendered and not billed at the end of an accounting period, in order to match
revenue with related costs.
DEFERRED FUEL AND PURCHASED POWER CAPACITY ACCOUNTING-Prior to January 1,
1995, the Company utilized deferred fuel accounting. Under this accounting
method, retail fuel costs were expensed when recovered through rates and
recognized as revenue. Retail fuel costs not yet expensed were classified on
the Consolidated Balance Sheets (Balance Sheets) as deferred fuel costs. The
fuel cost adjustment rate included a factor calculated to reimburse the
Company or its customers, as appropriate, for the carrying cost of funds used
to finance under- or over- collected fuel costs, respectively.
Under the MPUC fuel cost adjustment (FCA) regulations effective through
December 31, 1994, the Company was allowed to recover its fuel costs on a
current basis. The fuel charge was based on the Company's projected cost of
fuel for a twelve-month period. Under- or over- collections resulting from
differences between estimated and actual fuel costs for a twelve-month period
were included in the computation of the estimated fuel costs of the
succeeding fuel adjustment period.
As of January 1, 1995, the Company's collections under the FCA had exceeded
its costs by approximately $3.03 million. With the elimination of the FCA,
the MPUC recognized that there would no longer be a mechanism for the return
of that sum to customers. The MPUC allowed the Company to retain that over-
collection and ordered that the amount be amortized over a period of three
years, effective January 1, 1995.
DEPRECIATION OF ELECTRIC PLANT AND MAINTENANCE POLICY-Depreciation of
electric plant is provided using the straight-line method at rates designed
to allocate the original cost of the properties over their estimated service
lives. The composite depreciation rate, expressed as a percentage of average
depreciable plant in service, and considering the amortization of the over-
accrued depreciation which is discussed below, was approximately 2.3% in
1995, 2.2% in 1994, and 2.1% in 1993.
A study conducted in 1989 by an independent firm determined that, as a group,
the actual lives of the Company's property, plant and equipment were longer
than the lives represented by the depreciation rates that the Company had
been using to compute its depreciation expense for accounting purposes. In
addition, the study also determined that the reserve for depreciation was
over-accumulated. The agreement on base rates with the MPUC which became
effective on October 1, 1990, contained a provision to amortize the remaining
balance of the over-accumulated reserve for depreciation account ($11.4
million at October 1, 1990) over a six-year period and adopted the longer
depreciable lives as determined by the aforementioned study. In 1995 the
Company, in accordance with the results of an updated depreciation study,
adopted shorter depreciable lives, resulting in an increase in the composite
depreciation rate from 3.0% to 3.2%.
The Company follows the practice of charging to maintenance the cost of
repairs, replacements and renewals of minor items considered to be less than
a unit of property. Costs of additions, replacements and renewals of items
considered to be units of property are charged to the utility plant accounts,
and any items retired are emoved from such accounts. The original costs of
units of property retired and removal costs, less salvage, are charged to the
reserve for depreciation.
Depreciation, local property taxes and other taxes not based on income, which
were charged to operating expenses, are stated separately in the Consolidated
Statements of Income. Rents, advertising and research and development
expenses are not significant. No royalty expenses were incurred.
Maintenance expense was $5.9 million in 1995, $6.2 million in 1994 and $6.5
million in 1993.
EQUITY RESERVE FOR LICENSED HYDRO PROJECTS-The FERC requires that a reserve
be maintained equal to one-half of the earnings in excess of a prescribed
rate of return on the Company's investment in licensed hydro property,
beginning with the twenty-first year of the project operation under license.
The required reserve for licensed hydro projects is classified in retained
earnings and had a balance of $900,542 at December 31, 1995 and $584,942 at
December 31, 1994.
ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION (AFDC)-In accordance with
regulatory requirements of the MPUC, the Company capitalizes as AFDC
financing costs related to portions of its construction work in progress, at
a rate equal to its weighted cost of capital, into utility plant with
offsetting credits to other income and interest. This cost is not an item of
current cash income, but is recovered over the service life of plant in the
form of increased revenue collected as a result of higher depreciation
expense and return. In addition, carrying costs on certain regulatory assets
were also capitalized in 1994 and 1993, and included in AFDC in the
Consolidated Statements of Income. The average AFDC (and carrying cost) rates
computed by the Company were 9.0% in 1995, 9.2% for 1994 and 10.0% in 1993.
CASH AND CASH EQUIVALENTS-The Company considers all highly liquid debt
instruments purchased with an original maturity of three months or less to be
cash equivalents.
USE OF ESTIMATES-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 liabilities at the date of the
consolidated financial statements and the reported amounts of revenues and
expenses during the reporting period. Actual results could differ from those
estimates.
RECLASSIFICATIONS-Certain prior year amounts have been reclassified to
conform with the presentation used in the 1995 Consolidated Financial
Statements.
2. INCOME TAXES
The Company adopted Statement of Financial Accounting Standards No. 109
"Accounting for Income Taxes" (FAS 109) effective January 1, 1993. FAS 109
required a change in the accounting for income taxes from the deferred method
to an asset and liability approach, which requires the recognition of
deferred tax liabilities and assets for the future tax effects of temporary
differences between the tax basis and carrying amounts of assets and
liabilities. In accordance with FAS 109, the Company recorded net additional
deferred income tax liabilities of approximately $21.2 million as of December
31, 1995 and $23.7 million as of December 31, 1994. These additional deferred
income tax liabilities have resulted from the accrual of deferred taxes on
temporary differences on which deferred taxes had not been previously accrued
($29.8 million and $32.9 million as of December 31, 1995 and 1994,
respectively), offset by the effect of the 1987 change to lower income tax
rates (reduced by the 1% increase in the federal income tax rate in 1993)
that will be refunded to customers over time ($7.2 million and $7.8 million
as of December 31, 1995 and 1994, respectively) and the establishment of
deferred tax assets on unamortized investment tax cedits ($1.4 million as of
December 31, 1995 and 1994, respectively). These latter amounts have been
recorded as deferred regulatory liabilities at December 31, 1995 and 1994.
The accrual of the additional amount of deferred tax liabilities have been
offset by regulatory assets which represent the customers' future payment of
these income taxes when the taxes are, in fact, expensed. As a result of this
accounting, the Consolidated Statements of Income for the years ended
December 31, 1995 and 1994 are not affected by the implementation of FAS 109.
The rate-making practices followed by the MPUC permit the Company to recover
federal and state income taxes payable currently, and to recover some, but
not all, deferred taxes that would otherwise be recorded in accordance with
FAS 109 in the absence of regulatory accounting.
The individual components of other accumulated deferred income taxes are as
follows at December 31, 1995 and 1994:
1995 1994
----------- -----------
Deferred income tax liabilities:
Costs to terminate purchased power contracts $77,126,042 13,643,442
Excess book over tax basis of electric
plant in service $47,658,824 $45,841,542
Deferred FERC licensing costs 1,361,034 3,158,378
Investment in jointly-owned companies 842,624 787,908
Deferred demand-side management costs 651,672 16,677
Deferred fuel revenue and purchased power 126,293 -
Prepaid pension costs - 593,290
Other 658,459 841,344
------------ -----------
$128,424,948 $64,882,581
------------ -----------
Less: Deferred Income Tax Assets:
Net operating loss carryforwards $64,769,384 1,915,213
Deferred income taxes provided on
alternative minimum tax $ 3,898,824 $ 4,463,203
Investment in Basin Mills 2,732,550 2,719,025
Unamortized investment tax credits 1,352,104 1,387,251
Postretirement benefit costs other
than pensions 1,107,808 507,033
Deferred state income tax benefit 908,722 1,301,528
Accrued pension costs 812,120 -
Reserve for bad debts 807,447 649,675
Deferred fuel revenue and purchased
power - 1,365,750
Other 1,260,955 490,165
------------- -------------
$ 77,649,914 $ 14,798,843
------------- -------------
Total other accumulated deferred income
taxes $50,775,034 $ 50,083,738
============= =============
The individual components of federal and state income taxes reflected in the
Consolidated Statements of Income for 1995, 1994 and 1993 are stated in the
table below:
Year Ended December 31,
--------------------------------------
1995 1994 1993
------------------------------------
Current:
Federal - $1,287,485 -
State - - -
- --------------------------------------------------------------------
- $1,287,485 -
- --------------------------------------------------------------------
Deferred Short-Term:
Federal - $ (797,919) $ 114,674
State - (296,436) 68,216
- --------------------------------------------------------------------
$ - $(1,094,355) $ 182,890
Deferred Long-Term:
Federal-Other $2,131,643 $ 3,003,171 $ 2,512,026
State-Other 70,424 753,782 (21,507)
Federal-Seabrook (339,415) (339,620) (341,917)
State-Seabrook (71,570) (72,127) (72,730)
- --------------------------------------------------------------------
$1,791,082 $ 3,345,206 $ 2,075,872
- --------------------------------------------------------------------
Investment Tax Credits, Net $ (61,193) $ 143,695 $ (178,176)
- --------------------------------------------------------------------
Total Provision $1,729,889 $ 3,682,031 $2,080,586
Allocated to Other Income (308,215) (68,433) 2,682,359
- --------------------------------------------------------------------
Charged to Operating Expense $1,421,674 $ 3,613,598 $4,762,945
====================================================================
The table below reconciles an income tax provision, calculated by multiplying
income before federal income taxes (as reported on the Consolidated Statements
of Income) by the statutory federal income tax rate to the federal income tax
expense reported on the Statements of Income. The difference is represented by
the temporary differences for which deferred taxes were not originally provided.
1995 1994 1993
----------- ----------- ----------
Amount % Amount % Amount %
------------------------------------
(Dollars in Thousands)
-----------------------------------
Federal income tax provision
at statutory rate $2,063 34% $3,786 34% $2,522 34%
Less (Plus) temporary reductions in
tax expense resulting from statutory
exclusions from taxable income:
Dividend received deduction
related to earnings of
associated companies 31 1 131 1 133 2
Equity component of AFDC 191 3 427 4 496 6
Amortization of equity component
of AFDC on recoverable Seabrook
investment (155) (1) (155) (1) (155) (2)
Other (104) (2) 8 - (24) -
------ --- ------ ---- ----- ----
Federal income tax provision before
effect of temporary differences $2,100 34% $3,375 30% $2,072 28%
Less (Plus) timing differences that
are flowed through for ratemaking
and accounting purposes:
Amortization of debt component of
AFDC and capitalized overheads
on recoverable Seabrook
investment (146) (3) (146) (1) (146) (2)
Book depreciation greater than tax
depreciation on assets acquired
before 1971 (292) (5) (292) (3) (292) (4)
State income tax liability
deducted for federal income
tax purposes - - 131 1 116 2
Reversal of excess deferred
income taxes 101 2 35 - 34 -
Amortization of investment tax
credits 676 11 178 2 178 3
Other 30 0 172 1 75 1
------- ---- ------ --- ------ ---
Federal income tax provision $1,731 29% $3,297 30% $2,107 28%
======= ==== ====== ==== ====== ===
Under the federal income tax laws, the Company received investment tax
credits on qualified property additions through 1986. Investment tax credits
utilized were deferred and are being amortized over the life of the related
property. In 1995 the Company recorded the utilization of approximately
$615,000 of investment tax credits, as well as amortization of deferred
investment tax credits of approximately $676,000. This was related to the
filing of amended federal income tax returns. Investment tax credits
available of about $3.5 million ($2.6 million which is attributable to PHC
and $900,000 to BVC) have not been utilized or recorded and, subject to
review by the Internal Revenue Service (IRS), may be used prior to their
expiration, which occurs between 2001 and 2005.
At December 31, 1995, the Company had, for income tax purposes, alternative
minimum tax credits of approximately $3.9 million for the reduction of future
tax liabilities. At December 31, 1995, the Company had, for income tax
reporting purposes, approximately $4.7 million of net operating loss
carryforwards that expire in 2008, as well as, in 1995, the Company generated
a net operating loss carryforward for income tax reporting purposes of
approximately $153 million that expire in 2010. These net operating losses
were principally due to the Company deducting for income tax reporting
purposes the costs of the purchased power contract terminations in 1993 and
1995, which were deferred for financial reporting purposes (see Note 6).
In 1994 the Company utilized $15.6 million of tax net operating loss
carryforwards and $322,000 of investment tax credits to reduce the
alternative minimum tax liability for 1994.
3. COMMON AND PREFERRED STOCK
COMMON STOCK-In June of 1994 the shareholders approved a proposal to increase
the number of shares the Company isauthorized to issue from 7,500,000 to
10,000,000. Prior to 1992, stockholders had been able to invest their
dividends and optional cash payments in common stock of the Company acquired
by an independent agent in the open market through the Company's Dividend
Reinvestment and Common Stock Purchase Plan (the Plan). In 1992 the Company
amended the Plan to enable it to issue original shares in return for the
reinvested dividends and optional cash payments. The common stock has general
voting rights of one vote per twelve shares owned.
PREFERRED STOCK-In June of 1994 the shareholders approved a proposal to
increase the number of shares the Company is authorized to issue from 400,000
to 600,000 shares of which there are 197,340 shares outstanding. The
remaining 402,660 authorized but unissued shares (plus additional shares
equal in number to such presently outstanding shares as may be retired) may
be issued with such preferences, restrictions or qualifications as the Board
of Directors may determine. Any new shares so issued will be required to be
issued with per share voting rights no greater than that of the common stock.
The callable preferred stock may be called in whole or in part upon any
dividend date by appropriate resolution of the Board of Directors. Except for
the holders of the 8.76% issue, which does not carry general voting rights,
the currently outstanding preferred stock has general voting rights of one
vote per share. With regard to payment of dividends or assets available in
the event of liquidation, preferred stock ranks prior to common stock.
REDEEMABLE PREFERRED SHARES-On December 27, 1989, the Company issued to an
institutional investor $15 million of nonvoting preferred stock carrying an
annual dividend rate of 8.76%. These shares have a maturity of fifteen years
with a mandatory sinking fund of $1.5 million per year starting in 1995. The
agreement to issue this series of preferred stock contains a provision
whereby, if the Company pays a dividend that is considered a return of
capital for federal income tax purposes, the Company is required to make a
payment to the stockholder in order to restore the stockholder's after-tax
yield to the level it would have been had the dividend not been considered a
return of capital. Since 100% of the dividends paid in 1990, 1993 and 1995,
pending any review by the IRS, were to be considered a return of capital, the
Company became obligated to pay this stockholder approximately $1.5 million,
on a prorata basis (10% per year) in conjunction with each sinking fund
payment starting in 1995. This obligation is being recognized over the
remaining life of the issue through a direct charge to retained earnings,
which amounted to approximately $122,000 in 1995.
In connection with financing the costs of the purchased power contract
buyback accomplished in June 1995 (see Note 6), the Company entered into a
Loan Agreement with the Finance Authority of Maine (FAME), a body corporate
and politic and public instrumentality of the State of Maine. Pursuant to
authorizing legislation in Maine, FAME issued $126 million of notes through a
private placement, the repayment of which is the responsibility of the
Company under the terms of the Loan Agreement. Of that amount, approximately
$105 million was made avalable to the Company to finance a portion of the
buyback and approximately $21 million was set aside in a capital reserve
fund. The notes bear interest at an annual rate of 7.03%, mature on July 1,
2005 and are subject to a schedule of annual principal payments beginning on
July 1, 1998. The amount held in the capital reserve fund will be used to pay
the final installments of principal and interest due in 2005. The assets in
the capital reserve fund are held by a third party trustee and invested in a
guaranteed annuity contract, earning interest at an annul rate of 6.51%, and
the interest earnings are utilized to offset the semiannual interest payments
on the Fame notes.
In order to secure the FAME notes, the Company executed a new General and
Refunding Mortgage Indenture and Deed of Trust establishing a lien on the
Company's property junior to the lien under the Company's First Mortgage
Bonds Indenture. After the issuance of $115 million in First Mortgage Bonds
to a group of bank lenders discussed below, the Company may not issue any
additional First Mortgage Bonds in the future except to the trustee under the
new General and Refunding Mortgage. The Company issued bonds to FAME under
the new mortgage in the amount of $126 million.
On June 30, 1995, the Company entered into a Credit Agreement (Agreement)
with a group of seven banks consisting of a revolving credit facility in the
initial amount of $55 million and a term loan in the amount of $60 million.
The revolving credit facility replaces the Company's short-term credit
facilities that existed prior to the closing, and also provided for the
issuance of a letter of credit required to support $4.2 million of the
Company's Pollution Control Revenue Bonds. To secure the existing letter of
credit related to the Pollution Control Revenue Bonds, until the new letter
of credit could be issued, the Company deposited approximately $4.4 million
of the proceeds from this financing with a third party trustee. These funds
were released to the Company upon the issuance of the new letter of credit in
August 1995. The receipt of these funds is reflected in Other, net in the
Consolidated Statements of Cash Flows. The Agreement is secured by $115
million of non-interest bearing First Mortgage Bonds.
The revolving credit facility has a term of five years and was automatically
and permanently reduced by $1 million on December 31, 1995. Borrowings under
the revolving credit facility will also be reduced by $2 million on June 30,
1996 and by $3 million on December 31, 1996. The term loan, used to finance a
portion of the buyback cost, also has a term of five years and requires
annual principal payments of $12 million beginning June 30, 1996. The Company
may borrow at rates, as defined with the Agreement, based on LIBO (London
Interbank Offered) rate, or the higher of the prime rate, the three month
certificate of deposit rate or the federal funds rate. A risk premium based
on the Company's senior debt rating is added to the base portion of the rate,
which results in the combined total interest rate for borrowings underthe
Agreement. A required commitment fee, based on the Company's available
revolving credit commitment, is also priced according to the Company's senior
debt rating.
The Company was required to enter into a transaction to cap or fix the rate
of interest on the term loan within 120 days of the execution of the
Agreement. In August 1995, the Company entered into agreements with three
banks to cap the LIBO rate at 7.25%, with the cost to cap the interest rate
amounting to $624,000. These costs are being amortized over the life of the
term loan.
The Agreement allows the Company to incur, outside of the revolving credit
facility, additional unsecured debt of $5 million, plus 50% of the aggregate
amount of mandated or optional reductions to the $55 million revolving credit
facility. In connection with this provision, the Company maintains a $5
million uncommitted line of credit.
The debt instruments executed in connection with the purchased power buyback
financing contains a number of covenants and restrictions that the Company
believes to be usual and customary for such a transaction, including
limitations on the aggregate amount of indebtedness the Company may incur and
restrictions on the payment of dividends.
Under the provisions of the first mortgage bond indenture, substantially all
of the Company's plant and property has been mortgaged to secure the
Company's first mortgage bonds. Sinking fund requirements and current
maturities of the first mortgage bonds for the five years subsequent to
December 31, 1995 aggregate $110,739,713 as follows:
Sinking Fund Current
Requirement Maturities Total
- -----------------------------------------------------------------------------
1996 $1,645,737 $ 12,000,000 $ 13,645,737
1997 1,853,515 12,000,000 13,853,515
1998 1,778,554 26,800,000 28,578,554
1999 1,675,205 25,100,000 26,775,205
2000 1,886,702 26,000,000 27,886,702
- -----------------------------------------------------------------------------
$8,839,713 $101,900,000 $110,739,713
=============================================================================
Certain information related to total short-term borrowings under the Credit
Agreement and the lines of credit is as follows:
1995 1994 1993
- -----------------------------------------------------------------------------
Total credit available at end of period $59,500,000 $55,000,000 $55,000,000
Unused credit at end of period $24,500,000 $28,000,000 $19,000,000
Borrowings outstanding at end of period $35,000,000 $27,000,000 $36,000,000
Effective interest rate (exclusive of
fees) on borrowings outstanding at
end of period 8.4% 6.0% 3.5%
Average daily outstanding borrowings
for the period $33,573,973 $26,035,616 $22,754,205
Weighted daily average annual interest
rate 7.5% 4.6% 3.7%
Highest level of borrowings outstanding
at any month-end during the period $47,000,000 $38,000,000 $36,000,000
=============================================================================
The average daily borrowings outstanding for the period represent the sum of
daily borrowings outstanding, divided by the number of days in the period.
The weighted daily average annual interest rate is determined by dividing the
annual interest expense by the average daily borrowings outstanding for the
period.
5. POSTRETIREMENT AND OTHER POSTEMPLOYMENT BENEFITS
POSTRETIREMENT BENEFITS-The Company has noncontributory pension plans
covering substantially all of its employees. On July 17, 1987, the Company
created separate union and nonunion plans from an original plan. Effective
January 1, 1995, the Company merged the union and nonunion plans into one
plan. Benefits under the plans are generally based on the employee's years of
service and compensation during the years preceding retirement. The Company's
general policy is to contribute to the funds the amounts deductible for
federal income tax purposes.
The following tables detail the components of pension income for 1995, 1994
and 1993, the funded status of the plans, the amounts recognized in the
Company's Consolidated Financial Statements and the major assumptions used to
determine these amounts. There were no employer contributions to the plan in
1995. Employer contributions to the plans amounted to $1,174,019 in 1994. In
1995 and 1994 the Company implemented early retirement programs which resulted
in additional pension expense of $2,548,648 and $1,608,267, respectively. The
plan's assets are composed of fixed income securities, equity securities and
cash equivalents.
Total pension income included the following components:
1995 1994 1993
- ---------------------------------------------------------------------------
Service cost-benefits earned
during the period $ 813,811 $1,060,134 $1,085,419
Interest cost on projected
benefit obligation 2,458,466 2,310,455 2,244,706
Actual return on plan assets (8,505,484) 377,447 (4,633,435)
Total of amortized obligations
and the net gain (loss) deferred 4,889,703 (3,865,833) 1,291,310
- ----------------------------------------------------------------------------
Total pension (income) $ (343,504) $ (117,797) $ (12,000)
============================================================================
1995 1994 1993
- ---------------------------------------------------------------------
Significant assumptions used were
Discount rate 7.25% 8.25% 7.0%
Rate of increase in future
compensation levels 5.0% 5.0% 5.0%
Expected long-term rate of
return on plan assets 9.0% 9.0% 9.0%
The following table sets forth the plans' funded status at December 31, 1995
and 1994:
1995 1994
- -----------------------------------------------------------------------
Actuarial present value of accumulated benefit obligation
Vested $ 31,528,835 $ 21,668,455
Non-vested 2,877,035 2,091,333
- -----------------------------------------------------------------------
Total $ 34,405,870 $ 23,759,788
=======================================================================
Projected benefit obligation $(39,121,538) $(31,179,979)
Plan assets at fair value 41,312,595 36,397,435
- -----------------------------------------------------------------------
Excess of plan assets over
projected benefit obligation $ 2,191,057 $ 5,217,456
Items not yet recognized in earnings
Net (asset) at transition (5,051,800) (5,984,125)
Prior service cost 5,096,783 5,653,162
Unrecognized net gain from past
experience and changes in assumptions (2,862,289) (2,804,446)
- -----------------------------------------------------------------------
Net pension (liability) asset recognized $ (626,249) $ 2,082,047
=======================================================================
In addition to pension benefits, the Company provides certain health care and
life insurance benefits to its retired employees. Substantially all of the
Company's employees may become eligible for retiree benefits if they reach
normal retirement age while working for the Company.
The Company adopted Statement of Financial Accounting Standards No. 106,
"Employers' Accounting for Postretirement Benefits Other Than Pensions" (FAS
106) as of January 1, 1993. This standard required the accrual of
postretirement benefits, including medical and life insurance coverage,
during the years an employee provides services to the Company. Prior to 1993,
the cost of health care benefits were expensed as benefits were paid.
The MPUC in 1993 issued a final accounting rule in connection with FAS 106
which adopted this pronouncement for ratemaking purposes and provided the
Company with the accounting and regulatory framework required to defer the
excess of the net periodic postretirement benefit cost recognized under FAS
106 over the pay-as-you-go amount in 1993 through February 28, 1994, and to
include such excess as a regulatory asset pending inclusion in the new base
rates, effective March 1, 1994. This regulatory asset, which amounted to
$705,283 at February 28, 1994, is being recovered, beginning March 1, 1994,
over a ten-year period. The Company, also in accordance with the final
accounting ruling, is amortizing the unrecognized transition obligation of
$10,023,200 over a 20-year period. In 1995 and 1994 the Company implemented
early retirement programs which resulted in $909,418 and $750,000,
respectively, of expense related to additional medical and life insurance
benefits provided to the early retirees.
In 1994 the Company established an irrevocable external Voluntary Employee
Benefit Association Trust Fund ("VEBA") to fund the payment of postretirement
medical and life insurance benefits. Company contributions to the VEBA, which
commenced in July 1994, amounted to $1,215,554 in 1995 and $755,000 in 1994.
The plan's assets are composed of United States Treasury money market funds.
The actuarially determined net periodic postretirement benefit cost for 1995,
1994 and 1993 and the major assumptions used to determine these amounts are
shown in the following tables:
1995 1994 1993
- -----------------------------------------------------------------------------
Service cost of benefits earned $ 378,400 $ 379,400 $ 359,600
Interest cost on accumulated
postretirement benefit obligation 948,000 724,000 683,200
Actual return on plan assets (23,300) (7,800) -
Amortization of unrecognized
transition obligation 501,200 501,200
Other deferrals, net 23,699 (1,800) -
Early retirement plan benefits 909,418 750,000 -
- -----------------------------------------------------------------------------
Net periodic postretirement
benefit cost $2,737,417 $2,345,000 $1,544,000
=============================================================================
1995 1994 1993
- ------------------------------------------------------------------------
Significant assumptions used were-
Discount rate 7.25% 8.25% 7.0%
Health care cost trend rate,
employees less than age 65-
Near-term 8.5% 9.0% 12.4%
Long-term 4.5% 4.5% 6.0%
Health care cost trend rate,
employees greater than age 65-
Near-term 6.8% 7.0% 9.7%
Long-term 4.5% 4.5% 5.8%
Rate of return on plan assets 5.0% 2.0% N/A
- ---------------------------------------------------------------------
The following table sets forth the benefit plan's funded status at December
31, 1995 and 1994:
1995 1994
- -----------------------------------------------------------------------------
Accumulated postretirement benefit obligation:
Retirees $ 7,749,800 $ 7,746,800
Fully eligible active plan participants 1,374,400 446,400
Other active participants 3,248,300 3,020,900
- -----------------------------------------------------------------------------
12,372,500 $11,214,100
Fair value of plan assets (606,800) (409,500)
Unrecognized net transition obligation (8,519,600) (9,020,800)
Unrecognized gain 625,986 566,423
- -----------------------------------------------------------------------------
Accrued postretirement benefit cost
(included in Other Reserves) $ 3,872,086 $ 2,350,223
=============================================================================
If the health care cost trend rate was increased one percent, the accumulated
postretirement benefit obligation as of January 1, 1995 would have increased
by 12.3%. The effect of such change on the aggregate of service and interest
cost for 1995 would be an increase of 15.6%.
The estimates of the Company's accrued pension and postretirement benefit
costs involve the utilization of significant assumptions. Any change in these
assumptions could impact the liabilities in the near term.
POSTEMPLOYMENT BENEFITS-Effective January 1, 1994 the Company adopted
Statement of Financial Accounting Standards No. 112 "Employers' Accounting
for Postemployment Benefits" (FAS 112). The effect of FAS 112 on the
Company's consolidated results of operations, cash flows and financial
position was not material.
6. JOINTLY OWNED FACILITIES AND POWER SUPPLY COMMITMENTS
MAINE YANKEE-The Company, through its equity investment totalling
approximately $5.0 million at December 31, 1995, owns 7% of the common stock
of Maine Yankee, which owns and operates an 880 megawatt nuclear generating
plant in Wiscasset, Maine, and is entitled under a cost-based power contract
to an approximately equal percentage of the plant's output. The Maine Yankee
plant, like other pressurized water reactors, experienced degradation of its
steam generator tubes, principally in the form of circumferential cracking,
which, until early 1995, was believed to be limited to a relatively small
number of tubes. During the refueling and maintenance shutdown that commenced
in February 1995, Maine Yankee detected through new inspection methods
increased degradation of the plant's steam generator tubes to the extent that
approximately 60% of the plant's 17,000 steam generator tubes appeared to
have defects to some degree. Because of the large number of affected tubes,
the remedy of plugging the degraded tubes to take them out of service was no
longer a viable option.
Following a detailed analysis of the safety, technical and financial
considerations associated with the degraded steam generator tubes, Maine
Yankee elected to repair the tubes by inserting and welding short reinforcing
sleeves of an improved material in substantially all of the Plant's steam
generator tubes. Similar repairs have been completed at other nuclear plants
in the United States and abroad, but not on the scale of the Maine Yankee
project. With Westinghouse Electric Corporation as the general contractor,
the sleeving project started in early June of 1995, after approval of the
Westinghouse sleeving process by the Nuclear Regulatory Commission (NRC), and
was essentially completed in early December. The repairs were estimated to
cost $40 million, but Maine Yankee now estimates the project will be
completed for approximately $27 million. The Company has charged to
operations its share of the repair costs in 1995.
During 1995, the Company incurred substantial costs for replacement power,
and as explained above, since the FCA was eliminated at the beginning of
1995, the replacement power costs had a material impact in reducing earnings
in 1995. After Maine Yankee went off-line, the Company incurred
nonreconcilable replacement power costs of approximately $8.6 million for the
year. Combined with the Company's share of the repair cost, the Maine Yankee
outage adversely impacted the Company's earnings in 1995 by $.86 per common
share, after taxes.
On December 4, 1995, when the resleeving project was substantially complete,
Maine Yankee received a copy of a letter, from an organization with a history
of opposin nuclear power development, to a State of Maine nuclear safety
official based on documentation from an anonymous former employee of Yankee
Atomic Electric Company (Yankee), an affiliate of Maine Yankee and other
nuclear plant operators. The letter contained allegations that Yankee
knowingly performed inadequate analyses to support two license amendments to
increase the rated thermal power at which the Maine Yankee plant could
operate. It was further alleged in the letter that Maine Yankee deliberately
misrepresented the analyses to the NRC in seeking license amendments. The
allegedly inadequate analyses related to the operation of the plant's
emergency core cooling system (ECCS) and the calculation of the plant's
containment peak postulated accident pressure, both under certain assumed
accident conditions. The analyses were used in support of license amendments
that authorized an increased rating of the plant from a level equal to
approximately 90% of the maximum electrical capability of the plant to its
current 100% rated level.
In response to technical issues raised by the allegations, the NRC initiated
a special technical review of the safety analysis performed by Yankee
relating to Maine Yankee's license amendment applications for the power up
rates. At the same time, Maine Yankee and Yankee initiated intensive internal
investigations of the allegations and provided responsive information and
documentation to the NRC.
On December 18, 1995, a public meeting was held at the NRC to discuss the
findings resulting from the NRC's technical review. At the meeting the NRC
informed Maine Yankee that it had concerns regarding the adequacy of a
proprietary computer code used in ECCS safety analyses supporting Maine
Yankee's last two applications for license amendments that authorized power
up rates to levels above 90% of its current maximum capacity. At the meeting
the NRC also indicated that operation of the plant at a level up to 90% could
be acceptable if operations were based on methods previously found acceptable
by the NRC staff and not on the computer code that is currently under review
by the NRC, and further informed Maine Yankee of the terms and conditions
under which Maine Yankee could resume power operation of the plant.
Subsequently, the NRC informed Maine Yankee that the allegations made in the
anonymous letter would be the subject of investigations by the NRC's Office
of Investigations and the Office of the Inspector General.
On January 3, 1996, the NRC issued a "Confirmatory Order Suspending Authority
For And Limiting Power Operation And Containment Pressure (Effective
Immediately) And Demand For Information" (the Confirmatory Order) confirming
the conclusions of the NRC from the public meeting and follow-up
communications with Maine Yankee. The Confirmatory Order limited the power
output of the Maine Yankee plant to approximately 90% of its rated maximum
until the NRC shall have reviewed and approved plant-specific analyses
meeting the NRC's criteria for operation of the ECCS under certain postulated
accident conditions, in lieu of the analyses based on the questioned computer
code. The Confirmatory Orer further required that prior to operating the
plant at any level, Maine Yankee should submit under oath specified
information relating to operating the plant at up to the 90% level and
descriptions of measures taken to assure compliance with the limitations on
operating level and containment pressure.
With respect to subsequently returning the plant to its 100% operating level,
the Confirmatory Order required Maine Yankee to submit a plant-specific
analysis meeting the NRC's requirements for ECCS operation under specified
conditions at plant power levels up to 100% of its maximum rated capability.
The Confirmatory Order also required an integrated containment analysis
demonstrating that the maximum calculated containment pressure under certain
postulated accident conditions does not exceed the design-basis pressure of
the plant's containment. In addition, the Confirmatory Order required Maine
Yankee to submit a schedule for providing the requested analyses and related
information to the NRC.
As of this writing, the Maine Yankee plant is operating at the 90% level. The
Company cannot predict when Maine Yankee will gain the authority to return to
the 100% operating level or when it will achieve this level once authority is
granted. As a result of Maine Yankee's operating limitation, the Company will
incur replacement power costs of between $70,000 and $100,000 per month as
long as that limitation is in effect. Finally, the Company cannot predict the
results of the internal and external investigations of the allegations
brought to Maine Yankee's attention on December 4, 1995, or whether any party
will seek an NRC hearing or any appeal with respect to the Order. Maine
Yankee has stated, however, that it intends to pursue its internal
investigation diligently and cooperate with the governmental investigations,
and that it believes that after it develops information requested by the NRC
for operation of the plant at full capacity it will be able to operate the
plant at that level while meeting all applicable NRC safety requirements.
The Company is obligated to pay its pro rata share of Maine Yankee's
operating expenses, fuel costs, capital costs and decommissioning costs.
Estimated costs of decommissioning the Maine Yankee plant assuming
dismantlement and removal is $317 million (in 1993 dollars) of which the
Company's share is approximately $22.2 million.
The estimated cost of decommissioning is subject to change due to evolving
technology and the possibility of new legal requirements. Accumulated
decommissioning funds at December 31, 1995 were $142.1 million of which the
Company's share was approximately $9.9 million.
MEPCO-The Company owns 14.2% of the common stock of MEPCO. MEPCO owns and
operates electric transmission facilities from Wiscasset, Maine, to the
Maine-New Brunswick border. Several New England utilities, including the
Company and MEPCO's other stockholders (two other Maine utilities), are
parties to a transmission support agreement pursuant to which such utilities
have agreed to pay MEPCO's costs, based on theirrelative system peaks, if
MEPCO's revenues from transmission services are not sufficient to meet its
expenses. Information relating to the operations and financial position of
Maine Yankee and MEPCO appears below:
Maine Yankee MEPCO
- -----------------------------------------------------------------------------
(Dollar in Thousands)
- -----------------------------------------------------------------------------
1995 1994 1993 1995 1994 1993
------ ------ ------ ------ ------ ------
Operations:
As reported by investee-
Operating Revenue $205,977 $173,857 $193,102 $49,699 $24,746 $12,809
- -----------------------------------------------------------------------------
Depreciation $ 32,722 $ 30,823 $ 25,458 $ 1,383 $ 1,383 $ 1,395
Interest and Prefer-
red Dividends 17,332 14,583 14,407 96 106 124
Other expenses, net 148,866 121,437 145,861 48,115 23,152 11,185
- -----------------------------------------------------------------------------
Operating expenses $198,920 $166,843 $185,726 $49,594 $24,641 $12,704
- -----------------------------------------------------------------------------
Earnings Applicable
to Common Stock $ 7,057 $ 7,014 $ 7,376 $ 105 $ 105 $ 105
=============================================================================
Amounts Reported by the Company-
Purchased power costs $14,299 $11,771 $ 11,265 $ - $ - $ -
Equity in net income (498) (480) (542) (15) (15) (15)
- -----------------------------------------------------------------------------
Net purchased power
expense $ 13,801 $11,291 $10,723 $ (15)$ (15)$ (15)
=============================================================================
Financial Position:
As reported by investee-
Plant in service $404,499 $401,092 $396,133 $23,135 $23,099 $23,123
Accumulated deprec-
iation (208,537)(192,293)(175,996)(21,777)(20,463)(19,174)
Other assets 384,996 341,111 314,680 4,561 3,927 2,414
- -----------------------------------------------------------------------------
Total assets $580,958 $549,910 $534,817 $ 5,919 $ 6,563 $ 6,363
Less-
Preferred stock 18,600 19,200 19,800 - - -
Long-term debt 109,999 118,666 115,333 870 1,730 2,590
Other liabilities and
deferred credits 381,158 344,550 332,030 4,171 3,955 2,895
- -----------------------------------------------------------------------------
Net assets $ 71,201 $ 67,494 $ 67,654 $ 878 $ 878 $ 878
=============================================================================
Company's reported equity-
Equity in net assets $ 4,984 $ 4,725 $ 4,736 $ 125 $ 125 $ 125
Adjust Company's
estimate to actual 30 29 20 - - -
- -----------------------------------------------------------------------------
Equity in net assets
as reported $ 5,014 $ 4,754 $ 4,756 $ 125 $ 125 $ 125
=============================================================================
Wyman 4-The Company owns 8.33% (50 MW) of the oil-fired 600 MW Wyman Unit No.
4 in Yarmouth, Maine. The Company's proportionate share of the direct
expenses of this unit is included in the corresponding operating expenses in
the Consolidated Statements of Income. Included in the Company's utility
plant are the following amounts with respect to this unit:
1995 1994 1993
- ------------------------------------------------------------------------
Electric plant in service 16,876,963 16,771,430 16,767,909
Accumulated depreciation (8,459,911) (7,996,737) (7,539,591)
- ------------------------------------------------------------------------
$ 8,417,052 $8,774,693 $9,228,318
========================================================================
NEPOOL/HYDRO-QUEBEC PROJECT - The Company is a 1.6% participant in the
NEPOOL/Hydro-Quebec Phase 1 project (Phase 1), a 690 MW DC intertie between
the New England utilities and Hydro-Quebec constructed by a subsidiary of
another New England utility at a cost of about $140 million. The participants
receive their respective share of savings from energy transactions with
Hydro-Quebec, and are obliged to pay for their respective shares of the costs
of ownership and operation whether or not any savings are realized.
The Company is also a 1.5% participant in the NEPOOL/Hydro-Quebec Phase 2
project (Phase 2), which involves an increase to the capacity of the Phase 1
intertie to 2,000 MW. As in the Phase 1 project, the Company receives a share
of the anticipated energy cost savings derived from purchases from Hydro-
Quebec and capacity benefits provided by the intertie and is required to pay
its share of the costs of ownership and operation whether or not any savings
are obtained.
In 1990, the Company formed Bangor Var Co., Inc. whose sole function is to be
a 50% general partner in Chester, a partnership which owns a static var
compensator (SVC), which is electrical equipment that supports the Phase 2
transmission line. A wholly-owned subsidiary of Central Maine Power Company
owns the other 50% interest in Chester. Chester has financed the acquisition
and construction of the SVC through the issuance of $33 million in principal
amount of 10.48% senior notes due 2020, and up to $3.25 million principal
amount of additional notes due 2020 (collectively, the SVC Notes). The
holders of the SVC Notes are without recourse against the partners or their
parent companies and may only look to Chester and to the collateral for
payment. The New England utilities which participate in Phase 2 have agreed
under a FERC approved contract to bear the cost of Chester, on a cost of
service basis, which includes a return on and of all capital costs.
Information relating to the operations and financial position of Chester
appears at the top of the following page.
Bangor Pacific Chester
- --------------------------------------------------------------------------
(Dollar in Thousands)
- --------------------------------------------------------------------------
1995 1994 1993 1995 1994 1993
----- ------ ------ ------ ------ -------
Operations:
As reported by investee-
Operating Revenue $7,277 $6,880 $7,370 $5,016 $5,173 $5,057
- ---------------------------------------------------------------------------
Depreciation $ 862 $ 855 $ 856 $1,075 $1,075 $ 995
Interest Expense 3,657 3,791 3,909 3,114 3,227 3,201
Other expenses, net 707 1,134 1,037 827 871 861
- ---------------------------------------------------------------------------
Operating expenses $5,226 $5,780 $5,802 $5,016 $5,173 $5,057
- ---------------------------------------------------------------------------
Net Income $2,051 $1,100 $1,568 $ - $ - $ -
===========================================================================
Company's reported
equity in net income $1,026 $ 550 $ 784 $ - $ - $ -
===========================================================================
Financial Position:
As reported by investee-
Plant in service $44,035 $43,977 $43,894 $31,993 $31,991 $31,991
Accumulated
depreciation (6,427) (5,572) (4,717) (5,296) (4,221) (3,146)
Other assets 3,399 2,978 3,696 3,351 3,555 3,632
- ---------------------------------------------------------------------------
Total assets $41,007 $41,383 $42,873 $30,048 $31,325 $32,477
Less-
Long-term debt 32,600 34,500 36,300 28,204 29,387 30,643
Other liabilities 2,255 2,241 2,231 1,844 1,938 1,834
- ----------------------------------------------------------------------------
Net assets $ 6,152 $ 4,642 $ 4,342 $ - $ - $ -
============================================================================
Company's reported
equity in net assets $ 3,076 $ 2,321 $ 2,171 $ - $ - $ -
============================================================================
SMALL POWER PRODUCTION FACILITIES-As of the end of 1995, the Company had
contracts with seven independent, non-utility power producers known as "small
power production facilities." The West Enfield Project, described below, is
one such facility. There are five other relatively small hydroelectric
facilities, and a 20 MW facility fueled by municipal solid waste. The cost of
power from the small power production facilities is more than the Company
would incur from other sources if it were not obligated under these
contracts, and, in the case of the solid waste plant, substantially more. The
prices were negotiated at a time when oil prices wre much higher than at
present, and when forecasts for the costs of the Company's long-term power
supply were higher than current forecasts. In the Company's 1987 rate
proceeding, the MPUC investigated the events surrounding the contract
negotiations but reached no conclusion about the Company's prudence in
entering into these contracts.
The Company has been attempting to alleviate the adverse impact of high-cost
contracts with small power production facilities. One method for doing so has
been to pay a fixed sum in return for terminating the contract. The first
such transaction was accomplished in 1993, and in 1995 the Company succeeded
in accomplishing two more. The 1995 transactions involved a "buyback" of the
contracts for the purchase of power from two biomass-fueled generating plants
in West Enfield and Jonesboro, Maine, which are identical plants under common
ownership. The buyback cost was approximately $170 million, including
transaction costs. Under the Company's Alternative Marketing Plan (AMP), the
buyback costs have been deferred and recorded as a regulatory asset, to be
amortized and collected over a ten-year period, beginning July 1, 1995. The
cost of the buyback was financed entirely by new debt instruments, thereby
significantly increasing the Company's indebtedness. See Note 4 for
discussion of these financings.
In addition to the buyback costs incurred to date, the Company is committed
under certain conditions to reimburse the towns of Enfield and Jonesboro for
lost property tax revenues in an amount not expected to exceed $1.4 million
over a two-year period. The Company believes that the accomplishment of this
transaction will provide substantial long-term benefits for its customers,
and should enhance the Company's prospects for improved earnings sooner than
if the buyback did not occur.
In the 1993 transaction, the Company negotiated an agreement to cancel its
long-term purchased power agreement with one of the biomass plants, the
Beaver Wood Joint Venture (Beaver Wood), in June 1993. In connection with the
cancellation the Company paid Beaver Wood $24 million in cash and issued a
new series of 12.25% First Mortgage Bonds due July 15, 2001 to the holders of
Beaver Wood's debt in the amount of $14.3 million in substitution for Beaver
Wood's previously outstanding 12.25% Secured Notes. Also, in connection with
the cancellation agreement, a reconstituted Beaver Wood partnership paid the
Company $1 million at the time of settling the transaction and has agreed to
pay the Company $1 million annually for the next six years in return for
retaining the ownership and the option of operating the plant. The payments
are secured by a mortgage on the property of the Beaver Wood facility. The
Company believes this contract buyout transaction will result in significant
savings to its customers compared to the continuation of payments under the
purchased power contract.
In May 1993 the Company received an accounting order from the MPUC related to
this purchased power contract buyout. The order stipulated that the Company
may seek recovery of the costs associated with the buyout in a future base
rate case, and could also record carrying costs on the deferred balance.
Consequently, a regulatory asset of $40.3 million had been recorded as of
December 31, 1993. Effective with the implementation of new base rates on
March 1, 1994, the Company began recovering over a nine-year period the
deferred balance, net of the additional $6 million anticipated from Beaver
Wood. In each of 1994 and 1995 the Company received its $1 million payment.
The Company also has a 30-year contract with the municipal solid waste
facility, a 20 MW waste-to-energy plant in the Company's service territory in
Orrington, completed in 1988. The Company has contracted to resell a portion
of the capacity for fifteen years from this facility to another utility. The
cost to the Company of the power delivered by this facility (net of revenues
from the foregoing resale) is projected to be $15 million annually.
WEST ENFIELD PROJECT-In 1986, the Company entered into a joint venture with a
development subsidiary of Pacific Lighting Corporation for the purpose of
financing and constructing the redevelopment of an old 3.8 MW hydroelectric
plant which the Company owned on the Penobscot River in Enfield and Howland,
Maine, into a 13 MW facility for the purpose of operating the facility once
it was completed. Commercial operation of the redeveloped project began in
April 1988. A wholly-owned corporate subsidiary, Penobscot Hydro Co., Inc.
(PHC) was formed to own the Company's 50% interest in the joint venture,
Bangor-Pacific.
Bangor-Pacific financed the $45 million estimated cost of the redevelopment
through the issuance in a privately placed transaction of $40 million of
fixed rate term notes and a commitment for up to $5 million of floating rate
notes. The notes are secured by a mortgage on the project and a security
interest in a 50-year purchased power contract, and the revenues expected
thereunder, between the Company and Bangor-Pacific. Except as described
below, the holders of the notes issued by Bangor-Pacific are without recourse
to the joint venture partners or their parent companies.
In the event Bangor-Pacific fails to pay when due amounts payable pursuant to
the loan agreement, each partner has agreed to make capital contributions to
Bangor-Pacific in an amount equal to 50% of such amounts due and payable, but
not exceeding an amount equal to distributions from Bangor-Pacific received
by such partner in the preceding twelve-month period. The Company is obliged
to provide funds necessary to support the foregoing limited financial
commitment to the project undertaken by PHC as the partner.
Under the purchased power contract, if the project operates as anticipated,
payments by the Company to Bangor-Pacific are estimated to be about $7.5
million annually (without consideration of any distributions by the joint
venture to the partners). It is possible that the Company would be required
to make payments under the contract regardless of whether any power is
delivered, in an amount of approximately $4 million per year. However, the
Company has the right to terminate the contract if the failure to deliver
power continues for a period of 12 consecutive months.
Information relating to the operations and financial position of Bangor-
Pacific appears on page 44.
BASIN MILLS AND VEAZIE PROJECTS- As a result of increased uncertainty about
the recoverability of amounts invested through 1993 in licensing activities
for proposed additional hydroelectric facilities, the Company established a
reserve against those investments in the amount of $8.7 million as of
December 31, 1993. Since 1993 the Company has charged to non-operating
expense all amounts related to these licensing activities. The projects for
which the reserve was established are a proposed 38 megawatt generating
facility located at the so-called Basin Mills site on the Penobscot River in
Orono and Bradley, Maine and an 8 megawatt addition to the Company's existing
dam and power station on the Penobscot River in Veazie and Eddington, Maine.
The projects would require a total investment of $140 million. The Company
has been pursuing the permitting of these facilities since the early 1980's.
7. RECOVERY OF SEABROOK INVESTMENT AND SALE OF SEABROOK INTEREST
The Company was a participant in the Seabrook nuclear project in Seabrook,
New Hampshire. On December 31, 1984, the Company had almost $87 million
invested in Seabrook, but because the uncertainties arising out of the
Seabrook Project were having an adverse impact on the Company's financial
condition, an agreement for the sale of Seabrook was reached in mid-1985 and
was finally consummated in November 1986. During 1985, a comprehensive
agreement was negotiated among the Company, the MPUC staff, and the Maine
Public Advocate addressing the recovery through rates of the Company's
investment in Seabrook (the Seabrook Stipulation). This negotiated agreement
was approved by the MPUC in late 1985. Although the implementation of the
Seabrook Stipulation significantly improved the Company's financial
condition, substantial write-offs were required as a result of the
determination that a portion of the Company's investment in Seabrook would
not be recovered. In addition to the disallowance of certain Seabrook costs,
the Seabrook Stipulation also provided for the recovery through customer
rates of 70% of the Company's year-end 1984 investment in Seabrook Unit 1
over 30 years, and 60% of the Company's investment in Unit 2 over seven
years, with base rate treatment on the unamortized balances. As of December
31, 1992, the Company's investment in Seabrook Unit 2 was fully amortized.
8. CONTINGENCIES
ENVIRONMENTAL MATTERS-In 1992, the Company received notice from the Maine
Department of Environmental Protection (MDEP) that it was investigating the
cleanup of several sites in Maine that were used in the past for the disposal
of waste oil and other hazardous substances, and that the Company, as a
generator of waste oil that was disposed at those sites, may be liable for
certain cleanup costs. The Company learned in October 1995 that the United
States Environmental Protection Agency placed one of the sites on the
National Priorities List under the Comprehensive Environmental Response,
Compensation, and Liability Act will pursue potentially responsible parties.
With respect to this site, the Company is one of a number of waste generators
under investigation, and it is too early in the process to speculate on the
extent of the Company's potential liability. As to the only other site wich
has been listed by the MDEP as an Uncontrolled Hazardous Substance Site, the
Company was informed that it is considered a de minimis generator.
9. UNAUDITED QUARTERLY FINANCIAL DATA
Unaudited quarterly financial data pertaining to the results of operations
are shown below:
QUARTER ENDED
------------------------------------------------
MAR 31 JUNE 30 SEPT 30 DEC 31
------------------------------------------------
(DOLLARS IN THOUSANDS EXCEPT PER SHARE AMOUNTS)
------------------------------------------------
1995
- ----
Electric Operating Revenue $48,263 $43,694 $46,025 $46,931
Operating Income 6,004 1,438 7,538 8,688*
Net Income (Loss) 3,293 (1,696) 828 1,911*
Earnings (Loss) Per Share
of Common Stock $ .40 $ (.29) $ .05 $ .20*
=======================================================================
1994
- ----
Electric Operating Revenue $46,375 $39,664 $42,575 $45,484
Operating Income 3,037 4,550 5,589 4,157
Net Income 1,095 2,008 3,073 1,282
Earnings Per Share
of Common Stock $ .11 $ .22 $ .37 $ .12
=======================================================================
1993
- ----
Electric Operating Revenue $49,679 $40,548 $43,476 $44,269
Operating Income 4,779 4,486 4,396 3,168
Net Income (Loss) 2,908 2,766 3,244 (3,582)**
Earnings (Loss) Per Share
of Common Stock $ .46 $ .42 $ .46 $(.64)**
=======================================================================
*Includes $498,000 of amortization of investment tax credits or $.07 per
common share.
**Includes the provision for Basin Mills of $5.6 million after-tax or $.95
per common share.
10. FAIR VALUE OF FINANCIAL INSTRUMENTS
The following methods and assumptions were used to estimate the fair value at
December 31, 1995 of each class of financial instrument for which it is
practical to estimate the value:
Cash and cash equivalents: the carrying amount of $1,424,266 approximates
fair value. The fair values of other financial instruments at December 31,
1995 based upon similar issuances of comparable companies are as follows:
In Thousands
- --------------------------------------------------------------------------
Carrying Fair
Amount Value
------------------------
Funds held by trustee guaranteed annuity contract $ 21,192 $ 22,739
Mandatory redeemable cumulative preferred stock 15,000 13,860
First Mortgage Bonds 111,521 109,051
Pollution Control Revenue Bonds 4,200 4,200
FAME Revenue Notes 126,000 131,477
Medium Term Notes 60,000 60,000
- --------------------------------------------------------------------------
11. SIGNIFICANT NON-CASH ACTIVITY
In connection with the termination of the purchased power agreement in 1993
with the Beaver Wood Joint Venture, the Company issued $14.3 million of First
Mortgage Bonds in substitution for Beaver Wood's previously outstanding
secured notes which is not reflected in the Consolidated Statements of Cash
Flows.
12. REGULATORY AND LONG-LIVED ASSETS
Accounting rules applicable to regulated utilities allow the establishment of
regulatory assets for costs accumulated for certain items other than the
usual and customary capital assets, and allow the deferral of the income
statement impact of those costs if they are expected to be recovered in
future rates. As of December 31, 1995, the Company has regulatory assets, net
of regulatory liabilities, of approximately $250.7 million. The effects of
competition could ultimately cause the operations of the Company, or a
portion thereof, to cease meeting the criteria for application of the
accounting rules for regulatory assets. If this were to occur, accounting
standards of enterprises in general would apply and unamortized balances of
regulatory assets would be charged to operations in the year in which those
criteria were no longer applicable.
In March 1995 the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards No. 121 (FAS 121), "Accounting for the
Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of",
effective for financial statements for fiscal years beginning after December
15, 1995. FAS 121 establishes accounting standards for the impairment of
long-lived assets, certain identifiable intangibles, and goodwill related to
those assets to be held and used and for long-lived assets and certain
intangibles to be disposed of. It establishes guidance for recognizing and
measuring impairment losses and reuires that the carrying amount of impaired
assets be reduced to fair value. Management is currently evaluating the
financial impact of this accounting standard, but as long as the cost of the
Company's long-lived assets and intangibles continue being recovered through
its electric rates, as is currently the case, the effect of FAS 121 on the
Company's results of operations and financial position is not expected to be
significant. Management cannot predict the outcome of the possibility of
further competition and deregulation of the electric utility industry, or the
application of this accounting standards.
13. ALTERNATIVE MARKETING PLAN
On February 14, 1995 the MPUC issued an order approving many aspects of the
Company's Alternative Marketing Plan (AMP) proposal. The AMP proposal
included a plan for allowing increased flexibility to offer reduced prices
and develop related marketing programs, a commitment to attempt to cap
electric rates at current levels for an extended period, the elimination of
fuel cost accounting and the fuel adjustment clause, the elimination of
seasonal rate differentials and an understanding about the method of
amortizing the cost of any future buyout of high-cost purchased power
contracts.
14. ACQUISITION OF WHOLESALE CUSTOMER
On October 26, 1995, the Company acquired the assets and service territory of
its largest full requirements wholesale customer for a purchase price of
approximately $2.4 million. The customer served approximately 1,800
customers. The acquisition was accounted for using the purchase method of
accounting. The purchase price exceeded the value assigned to the assets
acquired by approximately $582,000 and has been recorded as an electric plant
acquisition adjustment, which is being amortized on a straight-line basis
over a period of 15 years.
15. DERIVATIVE FINANCIAL INSTRUMENTS
In 1995 the Company adopted Statement of Financial Accounting Standards No.
119, "Disclosure About Derivative Financial Instruments and Fair Value of
Financial Instruments." As discussed in Note 4, the Company entered into
interest rate cap agreements (the cap or caps) with three financial
institutions related to its $60 million of Medium Term Notes to manage its
exposure to interest rate fluctuations. Under the caps, the LIBO rate is
capped at 7.25% over the five-year term of the Medium Term Notes for the full
notional amount of $60 million. At the beginning of each calendar quarter
the notional interest rate is set by the financial institutions based on the
current LIBO rate. The Company will be reimbursed for incremental interest
expense incurred in excess of the 7.25% cap. In 1995 the notional rate was
not in excess of 7.25%.
The Company purchases, rather than generates itself, a significant portion of
the energy required to service its retail business. These purchased energy
prices can vary with changes in the price or availability of the underlying
fuel sources, and the risk of such pice volatility is no longer covered by a
rate mechanism like the FCA. To manage this exposure, effective January 1,
1996, the Company entered into hedging transactions with three financial
institutions. The Company determined that much of its exposure to purchased
energy price volatility is closely matched to changes in residual oil prices.
Accordingly, the Company entered into agreements known as "swaps",
essentially in which the Company agreed to pay a fixed price for a specific
quantity of a specific commodity (residual oil in this case), for a given
time period. This transfers the risk (or the benefit) of commodity price
fluctuations to the other party to the agreement for the given period of
time. These are strictly financial transactions, and no delivery of the
underlying commodity is taken. Settlements typically occur on a monthly basis
and the cash receipts/payments arising from the "swap" transactions will
offset corresponding increases/decreases in the Company's purchased energy
costs. As a result, the Company can manage a substantial portion of the risk
of energy price fluctuations, which allows the Company to more accurately
predict its future purchased energy costs and cash flow requirements. To
ensure the Company maintains a hedging, and not a speculative, position, the
Company has established official policies, procedures and controls for its
fuel hedging program.
Credit risk arises from potential nonperformance of counterparties to these
agreements. The Company managed credit risk related to the cap by spreading
the risk amongst three financial institutions and reviewing their financial
stability prior to entering into the arrangements. The Company manages the
credit risk related to the fuel swaps through credit limits, collateral
instruments, monitoring procedures, as well as spreading the risk amongst
three financial institutions. Market risk of the fuel swaps is the risk that
changes in fuel prices will result in a decrease in the value or an increase
in the cost of obligations arising from derivatives. As the Company utilizes
derivatives only for risk management purposes, the Company is not exposed to
market risk because gains and losses arising on derivative instruments will
be offset by corresponding losses and gains on the underlying transaction
being hedged. There is no market risk associated with changes in interest
rates since the Company paid for the cap when entering into the agreement.
The Company will receive a payment if the notional interest rate exceeds
7.25%.
COOPERS & LYBRAND
REPORT OF INDEPENDENT ACCOUNTANTS
To the Stockholders and Directors of Bangor Hydro-Electric Company:
We have audited the accompanying consolidated balance sheets and statements
of capitalization of Bangor Hydro-Electric Company and subsidiaries (the
"Company") as of December 31, 1995 and 1994, and the related consolidated
statements of income, retained earnings, and cash flows for each of the three
years in the period ended December 31, 1995. These financial statements are
the responsibility of the Company's management. Our responsiblity is to
express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audits 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 the Company as
of December 31, 1995 and 1994, and the consolidated results of its operations
and its cash flows for each of the three years in the period ended December
31, 1995, in conformity with generally accepted accounting principles.
/s/ COOPERS & LYBRAND L.L.P.
COOPERS & LYBRAND L.L.P.
Boston, Massachusetts
February 1, 1996
ITEM 9 CHANGES IN AND DISAGREEMENTS WITH AUDIT FIRMS ON
FINANCIAL DISCLOSURE
- ----------------------------------------------------------
There have been no changes in or disagreements with audit firms on
financial disclosure.
PART III
- --------
ITEM 10 DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
- -----------------------------------------------------------
See Part I above, and see the information under "Election of Directors"
in the Company's definitive proxy statement for the annual meeting of
stockholders to be held on May 15, 1996, which information is incorporated
herein by reference.
ITEM 11 EXECUTIVE COMPENSATION
- --------------------------------
See the information under "Executive Compensation" in the Company's
definitive proxy statement for the annual meeting of stockholders to be held
on May 15, 1996, which information is incorporated herein by reference.
ITEM 12 SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
AND MANAGEMENT
- --------------------------------------------------------
(a) Security Ownership of Certain Beneficial Owners
See the Company's definitive proxy statement for the
annual meeting of stockholders to be held on May 15, 1996,
which information is incorporated herein by reference.
(b) Security Ownership of Management
See the Company's definitive proxy statement for the
annual meeting of stockholders to be held on May 15, 1996, which
information is incorporated herein by reference.
(c) Changes in Control
Not applicable.
ITEM 13 CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
- --------------------------------------------------------
See the information under "Compensation Committee Interlocks and Insider
Participation" in the Company's definitive proxy statement for the annual
meeting of stockholders to be held on May 15, 1996, which information is
incorporated herein by reference.
PART IV
- --------
ITEM 14 EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS
ON FORM 8-K
- --------------------------------------------------------------
(a) Consolidated Financial Statements of the Company (See
Item 8)
Consolidated Statements of Income for the Years Ended
December 31, 1995, 1994 and 1993
Consolidated Balance Sheets - December 31, 1995 and
1994
Consolidated Statements of Retained Earnings for the
Years ended December 31, 1995, 1994 and 1993
Consolidated Statements of Capitalization - December
31, 1995 and 1994
Consolidated Statements of Cash Flows
for the Years Ended December 31,1995, 1994 and 1993
Notes to Consolidated Financial Statements
Report of Independent Accountants
(b) Schedules
Report of Independent Accountants
Schedule VIII - Reserves for Doubtful Accounts
and Insurance
All other schedules are omitted as the required information is
inapplicable or the information is presented in the Company's
consolidated financial statements or related notes.
(c) Exhibits
See Exhibit Index, page
(d) Reports on Form 8-K
A Current Report on Form 8-K dated January 12, 1996 was filed in the
first quarter of 1996, regarding the return to operation of the Maine
Yankee nuclear generating facility.
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.
Bangor Hydro-Electric Company
/s/ Robert S. Briggs
-------------------------------
By: Robert S. Briggs
President and
Chairman of the Board
Pursuant to the requirements of the Securities and Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dates indicated.
/s/ Robert S. Briggs
- --------------------------- -----------------------------
Robert S. Briggs Helen Sloane Dudman
President and Director
Chairman of the Board
/s/ William C. Bullock, Jr. /s/ G. Clifton Eames
- --------------------------- -------------------------------
William C. Bullock, Jr. G. Clifton Eames
Director Director
/s/ Jane J. Bush /s/ Robert H. Foster
- --------------------------- -------------------------------
Jane J. Bush Robert H. Foster
Director Director
/s/ David M. Carlisle /c/ Carroll R. Lee
- --------------------------- --------------------------------
David M. Carlisle Carroll R. Lee
Director Director, Vice President-
Operations
/s/ Frederick S. Samp
- ---------------------------- --------------------------------
Alton E. Cianchette Frederick S. Samp
Director Vice President - Finance & Law
(Chief Financial Officer)
/s/ David R. Black
----------------------
David R. Black
Controller
(Chief Accounting Officer)
Each of the above signatures is affixed as of March 13, 1996.
COOPERS & LYBRAND
REPORT OF INDEPENDENT ACCOUNTANTS
To the Stockholders and Board of Directors of
Bangor Hydro-Electric Company:
Our report on the consolidated financial statements of Bangor Hydro-Electric
Company is included in Item 8 of this Form 10-K. In connection with our
audits of such financial statements, we have also audited the related
financial statement schedule listed in the index in Item 14(b) of this Form
10-K.
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.
/s/ Coopers & Lybrand L.L.P.
----------------------------------
COOPERS & LYBRAND L.L.P.
Boston, Massachusetts
February 1, 1996
<TABLE>
SCHEDULE VIII
RESERVES FOR DOUBTFUL ACCOUNTS AND INSURANCE
----------------------------------------------
<CAPTION>
Additions
-----------------------------
Balance at Charged to Charged to Balance at
Beginning Costs and Other End
Of Period Expenses Accounts Deductions of Period
------- ------- ------- ------- -------
<S> <C> <C> <C> <C> <C>
1995
Reserve for Doubtful Accounts $ 730,000 $ 2,637,301 $ - $ 1,917,301 (A) $ 1,450,000
----------- ----------- ---------- ----------- -----------
Reserve for Retirees' Life Insurance $ 848,000 $ 32,000 $ - $ 28,000 $ 852,000
----------- ----------- ---------- ----------- -----------
1994
Reserve for Doubtful Accounts $ 1,450,000 $ 913,841 $ - $ 1,633,841 (A) $ 730,000
----------- ----------- ---------- ----------- -----------
Reserve for Retirees' Life Insurance $ 700,000 $ 164,000 $ - $ 16,000 $ 848,000
----------- ----------- ---------- ----------- -----------
1993
Reserve for Doubtful Accounts $ 1,450,000 $ 1,090,813 $ - $ 1,090,813 (A) $ 1,450,000
----------- ----------- ---------- ----------- -----------
Reserve for Retirees' Life Insurance $ 612,000 $ 92,000 $ - $ 4,000 $ 700,000
----------- ----------- ---------- ----------- -----------
NOTE:
(A) Accounts written off, less recoveries.
</TABLE>
EXHIBIT INDEX
EXHIBITS FILED HEREWITH
-----------------------
EXHIBIT NO. DESCRIPTION OF EXHIBIT
----------- ----------------------
3. ARTICLES OF INCORPORATION
-------------------------
3(a) Articles of Amendment
changing Corporate Clerk.
4. INSTRUMENTS DEFINING THE RIGHTS OF SECURITY HOLDERS
---------------------------------------------------
10(a) Supplemental Indenture
Dated as of October 1, 1995
to General and Refunding
Mortgage and Deed of Trust
dated as of June 1, 1995
(Bangor Hydro-Electric
Company to Chemical Bank).
EXHIBITS INCORPORATED HEREIN BY REFERENCE
-----------------------------------------
EXHIBIT NO. DESCRIPTION OF EXHIBIT INCORPORATED BY REFERENCE TO:
- ----------- ---------------------- -----------------------------
3. ARTICLES OF INCORPORATION & BY-LAWS
-----------------------------------
3.1 Company's Certificate Form S-2, Reg. No. 33-39181,
of Organization, together Exhibit 3.1
with all amendments thereto
3.2 Articles of Amendment Form S-2, Reg. No. 33-63500,
increasing Company's Exhibit 4.3
authorized capital stock
3.3 By-Laws of the Company Form S-2, Reg. No. 33-63500,
Exhibit 4.4
4. INSTRUMENTS DEFINING THE RIGHTS OF SECURITY HOLDERS
----------------------------------------------------
4.1 Mortgage and Deed of Form S-1, Reg. No. 2-54452,
Trust dated as of Exhibit 4(b)(1)
July 1, 1936, re
First Mortgage Bonds
4.2 Supplemental Indenture Form S-1, Reg. No. 2-54452,
dated as of December 1, Exhibit 4(b)(2)
1945, amending the
Mortgage
4.3 Supplemental Indenture Form S-1, Reg. No. 2-54452
dated as of September 1, Exhibit 4(b)(4)
1969, re 8 1/4% Series
Bonds, together with form
of purchase agreement.
(Supplemental indentures
and purchase agreements
with respect to prior
issues are substantially
identical in substantive
content to the 8 1/4%
Series documents).
4.4 Supplemental Indenture Form 10-K, 1975, Exhibit B
dated as of November 1,
1975, re 10 1/2% Series
Bonds, together with form
of purchase agreement
4.5 Supplemental Indenture Form 8-K, 6/28/76, Exhibit A
dated as of June 1, 1976,
re 9 1/4% Series Bonds
4.6 Form of Purchase Form 10-K, 1976, Exhibit C
Agreement re 9 1/4%
Series Bonds
4.7 Supplemental Indenture Form S-7, Reg. No. 2-61589,
dated as of January 1, Exhibit 5(a)(7)
1978, re 8.6% Series
Bonds, together with form
of purchase agreement
4.8 Supplemental Indenture Form 10-Q, 3rd Quarter 1979,
dated as of August 1, Exhibit A
1979, re 10.25% Series
Bonds, together with form
of purchase agreement
Common Stock Purchase Plan
4.9 Supplemental Indenture Form 10-Q, 1st Quarter, 1981,
dated as of April 1, Exhibit A
1981 re 15.25% Series
Bonds, together with form
of purchase agreement
4.10 Supplemental Indenture Form 10-Q, 2nd Quarter 1981,
dated as of July 30, Exhibit (4)
1981 re 16.50% Series
Bonds, together with form
of purchase agreement
4.11 Bond Purchase Agreement, Form 10-K, 1983, Exhibit 4(a)
including form of
supplemental indenture,
with respect to First
Mortgage Bonds, 12.50%
Series due 1998
4.12 Loan Agreement, Indenture Form 10-K, 1983, Exhibit 4(b)
of Trust and Letter of
Credit Reimbursement
Agreement with respect to
Variable Rate Demand
Pollution Control Revenue
Bonds (Bangor Hydro-
Electric Company Project)
Series 1983
4.13 Bond Purchase Agreement, Form 10-K, 1984, Exhibit 4(a)
including form of
supplemental indenture,
with respect to First
Mortgage Bonds, 17.35%
Series due 1994
4.14 Bond Purchase Agreement Form 10-Q, First Quarter,
dated as of March 1, 1989 1989, Exhibit 4.1
including form of
supplemental indenture,
with respect to First
Mortgage Bonds, 10.25%
Series due 2019
4.15 Preferred Stock Purchase Form 10-K, 1990, Exhibit 4(a)
Agreement, 8.76% Series
dated as of December 19,
1989
4.16 Bond Purchase Agreement Form 10-K, 1990, Exhibit 4(b)
dated as of June 15, 1990
including form of
supplemental indenture,
with respect to First
Mortgage Bonds, 10.25%
Series due 2020
4.17 Loan Agreement by and Form 10-Q, 3rd Quarter 1995,
Finance Authority of Exhibit 4.1
Maine and Bangor Hydro-
Electric Company
4.18 Credit Agreement Dated Form 10-Q, 3rd Quarter 1995,
as of June 30, 1995 Exhibit 4.2
among Bangor Hydro-
Electric Company, the
Banks named therein,
Chemical Bank as
Administrative Agent
and Fleet Bank of Maine
and First National Bank
of Boston, as Co-Agents.
4.19 Purchase Contract dated Form 10-Q, 3rd Quarter 1995,
as of June 28, 1995 among Exhibit 4.3
the Finance Authority of
Maine and Bangor Hydro-
Electric Company and
Prudential Securities
Incorporated
4.20 General and Refunding Form 10-Q, 3rd Quarter 1995,
Mortgage Indenture and Exhibit 4.4
Deed of Trust - Bangor
Hydro-Electric Company
to Chemical Bank, As
Trustee, Dated as of
June 1, 1995
4.21 Supplemental Indenture Form 10-Q, 3rd Quarter 1995,
Dated as of June 15, 1995 Exhibit 4.5
to General and Refunding
Mortgage Indenture and Deed
of Trust dated as of June
1, 1995 (Bangor Hydro-
Electric Company to Chemical
Bank).
4.22 Supplemental Indenture as Form 10-Q, 3rd Quarter 1995,
of June 29, 1995 to
Mortgage and Deed of Trust
dated as of July 1, 1936
(Bangor Hydro-Electric
Company to Citibank, N.A.
at Trustee).
10. MATERIAL CONTRACTS
------------------
10.1 New England Power Pool Form S-7, Reg. No. 2-69904,
Agreement dated as of Exhibit 10(a)(3)
September 1, 1971, with
all amendments through
December 1980
10.2 Copy of Twelfth Amendment Form S-7, Reg. No. 2-69904,
dated as of June 16, 1980 Exhibit 10(a)(4)
to the Agreement for Joint
Ownership, Construction and
Operation of New Hampshire
Nuclear Units
10.3 Participation Agreement Form S-1, Reg. No. 2-54452,
dated June 20, 1969 Exhibit 13(a)(2)(a)-1
between Maine Electric
Power Company, Inc.
("MEPCO") and the Company
10.4 Agreement dated June Form S-1, Reg. No. 2-54452,
29, 1969 among Maine Exhibit 13(a)(2)(a)-2
participants in MEPCO
Participation Agreement
10.5 Power Contract dated Form S-1, Reg. No. 2-54452,
May 20, 1968 between Exhibit 13(a)(3)(a)
Maine Yankee Atomic
Power Company ("Maine
Yankee") and the
Company and other
utilities
10.6 Stockholder Agreement Form S-1, Reg. No. 2-54452,
dated May 20, 1968 Exhibit 13(a)(3)(b)
among stockholders of
Maine Yankee, (including
the Company).
10.7 Capital Funds Agreement Form S-1, Reg. No. 2-54452,
dated May 29,1968 Exhibit 13(a)(3)(c)
between Maine Yankee
and sponsors, including
the Company
10.8 Maine Yankee Transmission Form S-1, Reg. No. 2-54452,
Agreement dated April 1, Exhibit 13(a)(3)(d)
1971 among the Company
and other utilities
10.9 Modification of Maine Form S-1, Reg. No. 2-54452,
Yankee Transmission Exhibit 13(a)(3)(f)
Agreement of December
1, 1972
10.10 Agreement for Joint Form S-1, Reg. No. 2-54452,
Ownership, Construction Exhibit 13(a)(4)(a)
and Operation dated
November 1, 1974 of
Wyman Unit No. 4 among
Central Maine Power
Company, the Company
and other utilities
10.11 Amendment No. 1 dated Form S-1, Reg. No. 2-54452,
June 30, 1975 to Wyman 4 Exhibit 13(a)(4)(b)
Agreement of November 1,
1974
10.12 Transmission Agreement Form S-1, Reg. No. 2-54452,
dated November 1, 1974 Exhibit 13(a)(4)(c)
re Wyman Unit No. 4
among Central Maine
Power Company and other
utilities
10.13 Form of Federal Power Form S-1, Reg. No. 2-54452,
Commission license Exhibit 13(b)(4)
for hydro-electric
dam facility
10.14 Employee Stock Ownership Form S-7, Reg. No. 2-59747,
Plan, including related Exhibit 5(a)(2)
trust agreements, dated
June 1, 1977
10.15 Sample of binder relating Form S-7, Reg. No. 2-59747,
to contingent liability Exhibit 5(a)(4)
for nuclear incidents
10.16 Agreements relating to Form S-7, Reg. No. 2-61589,
Seabrook 1 and 2 Exhibit 5(a)(3)
including offering
letter dated September
7, 1977 and the Company's
response thereto dated
October 6, 1977, the
Agreement to Transfer
Ownership Share between
the Company and The
Connecticut Light and
Power Co., dated November
1, 1977 and a letter
amendment thereto dated
January 31, 1978, and the
Joint Ownership Agreement
with Public Service
Company of New Hampshire
and other utilities as
amended through January
31, 1975
10.17 Amendment No. 2 dated Form 10-K, 1976, Exhibit H(2)
August 16, 1976 to Joint
Ownership Agreement
dated November 1, 1974
with Central Maine Power
Company and others re
Wyman Unit No. 4
10.18 Copies of Tenth and Form 10-K, 1979, Exhibit D
Eleventh Amendments
dated October 11, 1979
and December 15, 1979,
respectively, to the
Agreement for Joint
Ownership Construction
and Operation of New
Hampshire Nuclear Units
10.19 Copies of Forms of Form 10-Q, 2nd Qtr. 1979,
documents related to Exhibit A
the Company's proposed
purchase of an additional
1.80142% interest in the
Seabrook Nuclear Units,
consisting of PSNH's
offer to sell ownership
shares dated March 8,
1979, the Company's
letter response thereto
dated March 19, 1979,
and the Sixth, Seventh,
Eighth and Ninth Amendment
to the Agreement for Joint
Ownership, Construction
and Operation of New
Hampshire Nuclear Units,
dated April 18, 1979,
April 18, 1979, April 25,
1979, and June 8, 1979,
respectively
10.20 Copy of Thirteenth Form 10-K, 1981, Exhibit
Amendment dated as of 10(a)
December 31, 1980 to
the Agreement for Joint
Ownership, Construction
and Operation of New
Hampshire Nuclear Units
10.21 Forms of contracts Form 10-Q, 2nd Qtr. 1982,
concerning the Company's Exhibit 10
participation with
other New England
utilities in the
proposed Quebec
interconnection
10.22 Fourteenth Amendment Form 10-K, 1983, Exhibit 10.1
dated as of June 1, 1982
to the Agreement for
Joint Ownership,
Construction and
Operation of New
Hampshire Nuclear
Units
10.23 Third Amendment dated Form 10-K, 1983, Exhibit 10.2
as of November 1, 1982
to Preliminary Quebec
Interconnection Support
Agreement
10.24 Second Amendment dated Form 10-K, 1983, Exhibit 10.3
as of November 1, 1982
to Agreement With
Respect to Use of
Quebec Interconnection
10.25 Amendment No. 2 dated Form 10-K, 1983, Exhibit 10.4
as of November 1, 1982,
to Phase 1 Terminal
Facility Support
Agreement (Quebec
Interconnection)
10.26 Amendment No. 2 dated Form 10-K, 1983, Exhibit 10.5
as of November 1, 1982
to Phase 1 Vermont
Transmission Line
Support Agreement
(Quebec Interconnection)
10.27 Fourth Amendment Form 10-Q, 1st Quarter 1983,
dated as of March 1, Exhibit 10.1
1983, to Preliminary
Quebec Interconnection
Support Agreement
10.28 Fourteenth Amendment to Form 10-Q, 2nd Quarter 1983,
Agreement for Joint Exhibit 10.2
Ownership, Construction
and Operation of New
Hampshire Nuclear Units
10.29 Fifth Amendment to Form 10-Q, 2nd Quarter 1983,
Preliminary Quebec Exhibit 10.2
Interconnection
Support Agreement
10.30 Amendment dated as of Form 10-Q, 2nd Quarter 1983,
September 1, 1981 Exhibit 10.3
to New England Power
Pool Agreement
10.31 Amendment dated as of Form 10-Q, 2nd Quarter 1983,
June 1, 1982 to New Exhibit 10.4
England Power Pool
Agreement
10.32 Amendment dated as of Form 10-Q, 2nd Quarter 1983,
June 15, 1983 to New Exhibit 10.5
England Power Pool
Agreement
10.33 Amendment dated as of Form 10-Q, 3rd Quarter 1983,
October 1, 1983 to Exhibit 10.1
New England Power Pool
Agreement
10.34 Amendment No. 1 to the Form 10-K, 1983, Exhibit 10(b)
Maine Yankee Power
Contract
10.35 Amendment No. 2 to the Form 10-K, 1983, Exhibit 10(c)
Maine Yankee Power
Contract
10.36 Additional Power Con- Form 10-K, 1983, Exhibit 10(d)
tract between Maine
Yankee and its sponsors,
including the Company
10.37 Interim Protection Agree- Form 10-Q, 1st Quarter 1984,
ment dated as of April Exhibit 10.1
27, 1984 relating to
the Seabrook project
10.38 Fifteenth Amendment Form 10-Q, 1st Quarter 1984,
to the Seabrook Joint Exhibit 10.2
Ownership Agreement
10.39 Sixteenth Amendment Form 10-Q, 2nd Quarter 1984,
to the Seabrook Joint Exhibit 10.1
Ownership Agreement
10.40 Agreement for Seabrook Form 10-Q, 2nd Quarter 1984,
Project Disbursing Agent Exhibit 10.2
10.41 Seventeenth Amendment to Form 10-K, 1984, Exhibit 10(a)
Seabrook Joint Ownership
Agreement and corresponding
First Amendment to Seabrook
Project Disbursing Agent
Agreement (neither of which
were executed by the Company)
10.42 Preliminary Support Form 10-K, 1984, Exhibit 10(b)
Agreement - Phase 2 of
Hydro-Quebec Inter-
connection
10.43 Letter of Intent between Form 10-Q, 2nd Quarter 1985,
the Company and Eastern Exhibit 10.1
Utilities Associates
re: possible sale of
Seabrook interest
10.44 First, Second and Third Form 10-K, 1985, Exhibit 10(a)
Amendments to agreement for
Seabrook Project Disbursing
Agent (none of which were
executed by the Company)
10.45 Amendment dated September 1, Form 10-K, 1985, Exhibit
1985 to Agreement with 10(b)
respect to Use of Quebec
Interconnection
10.46 Energy Contract dated Form 10-K, 1985, Exhibit 10(c)
March 1983 between NEPOOL
and Hydro-Quebec re:
Hydro-Quebec Phase I
interconnection project
10.47 Energy Banking Agreement Form 10-K, 1985, Exhibit 10(d)
dated March 1983 between
NEPOOL and Hydro-Quebec re
Hydro-Quebec Phase I
interconnection project
10.48 Interconnection Agreement Form 10-K, 1985, Exhibit 10(e)
dated March 1983 between
NEPOOL and Hydro-Quebec re:
Hydro-Quebec Phase I
interconnection project
10.49 Amendment dated September 1 Form 10-K, 1985, Exhibit
1985 to NEPOOL Agreement 10(f)
re: Hydro-Quebec Phase II
interconnection project
10.50 Firm Energy Contract dated Form 10-K, 1985, Exhibit
October 14, 1985 between 10(g)
New England utilities and
Hydro-Quebec re: Hydro-
Quebec Phase II
interconnection project
10.51 Boston Edison AC Facilities Form 10-K, 1985, Exhibit
Support Agreement dated June 10(h)
1, 1985 re: Hydro-Quebec
Phase II interconnection
project
10.52 Phase II New England Form 10-K, 1985, Exhibit
Power AC Facilities 10(i)
Support Agreement dated
June 1, 1985 re: Hydro-
Quebec Phase II
interconnection project
10.53 Phase II Massachusetts Form 10-K, 1985, Exhibit
Transmission Facilities 10(j)
Support Agreement dated
June 1, 1985 re: Hydro-
Quebec Phase II
interconnection project
10.54 Phase II New Hampshire Form 10-K, 1985, Exhibit 10(k)
Facilities Support
Agreement dated June 1,
1985 re: Hydro-Quebec
Phase II interconnection
project
10.55 First Amendment dated Form 10-K, 1985, Exhibit 10(l)
March 1, 1985 and Second
Amendment dated January 1,
1986 to Preliminary Quebec
Interconnection Support
Agreement - Phase II
10.56 Amendment No. 3 dated Form 10-K, 1985, Exhibit 10(m)
October 1, 1984 to Maine
Yankee Power Contract
10.57 Amendment No. 1 dated Form 10-K, 1985, Exhibit 10(n)
August 1, 1985 to Maine
Yankee Capital Funds
Agreement
10.58 Amendments dated August 1, Form 10-K, 1985, Exhibit
1985, August 15, 1985, and 10(o)
January 1, 1986 to
NEPOOL Agreement
10.59 Fourth Amendment to Form 10-Q, 1st Quarter 1986,
Seabrook Project Exhibit 10.1
Disbursing Agent Agreement
10.60 Third Amendment to Vermont Form 10-Q, 1st Quarter 1986,
Transmission Line Support Exhibit 10.2
Agreement
10.61 First Amendment to Hydro- Form 10-Q, 1st Quarter 1986,
Quebec Phase I Intercon- Exhibit 10.3
nection Agreement
10.62 First Amendment to Hydro- Form 10-Q, 2nd Quarter 1986,
Quebec Phase II Exhibit 10.1
Massachusetts Trans-
mission Facilities
Support Agreement
10.63 First Amendment to Hydro- Form 10-Q, 2nd Quarter 1986,
Quebec Phase II New Exhibit 10.2
Hampshire Transmission
Facilities Support
Agreement
10.64 First Amendment to Hydro- Form 10-Q, 2nd Quarter 1986,
Quebec Phase II New England Exhibit 10.3
Power AC Facilities
Support Agreement
10.65 First Amendment to Form 10-Q, 2nd Quarter 1986,
Hydro-Quebec Phase II Exhibit 10.4
Boston Edison Company AC
Facilities Support
Agreement
10.66 Eighteenth Amendment to Form 10-Q, 2nd Quarter 1986,
Seabrook Joint Ownership Exhibit 10.5
Agreement
10.67 Amendment Number 3 to Form 10-Q, 3rd Quarter 1986,
Hydro-Quebec Phase l Exhibit 10.1
Terminal Facility Support
Agreement
10.68 Amendment Number 3 to Form 10-Q, 3rd Quarter 1986,
Hydro-Quebec Phase I Exhibit 10.2
Vermont Transmission Line
Support Agreement
10.69 Power Sale Agreement for Form 10-Q, 3rd Quarter 1986,
sale of approximately Exhibit 10.3
31 MW of system power by
Bangor Hydro-Electric
Company to UNITIL
Power Corp.
10.70 Purchase Agreement with Form 10-Q, 3rd Quarter 1986,
respect to Wyman No. 4 Exhibit 10.4
between Bangor Hydro-
Electric Company and
Fitchburg Gas and Electric
Light Company
10.71 Nineteenth Amendment to Form 10-K, 1986, Exhibit 10(a)
Seabrook Joint Ownership
Agreement
10.72 Twentieth Amendment to Form 10-K, 1986, Exhibit 10(b)
Seabrook Joint Ownership
Agreement
10.73 Agreement of Purchase and Form 10-K, 1986, Exhibit 10(c)
Sale dated February 19,
1986, regarding the sale
of the Company's Seabrook
interest to EUA Power
10.74 Bill of Sale and Assumption Form 10-K, 1986, Exhibit
of Obligations dated 10(d)
November 25, 1986 regarding
the sale of the Company's
Seabrook interest to EUA
Power
10.75 Deed dated November 21, Form 10-K, 1986, Exhibit 10(e)
1986 regarding the sale
of the Company's Seabrook
interest to EUA Power
10.76 Agreement to Share Certain Form 10-K, 1986, Exhibit
Costs re Tewksbury-Seabrook 10(f)
Transmission Line dated
May 8, 1986
10.77 Joint Venture Agreement Form 10-K, 1986, Exhibit
effective as of June 9, 10(g)
1986, between the Company
and Pacific Lighting Energy
Systems (as amended by a
First Amendment thereto
dated June 16, 1986) re
Bangor-Pacific Hydro
Associates (formerly West
Enfield Associates)
10.78 Capital Support Agreement Form 10-K, 1986, Exhibit
dated as of January 29, 10(h)
1987, among the Company
and lenders to Bangor-
Pacific Hydro Associates
10.79 Power Purchase Agreement Form 10-K, 1986, Exhibit
dated June 9, 1986 and 10(i)
Amendment No. 1 thereto
dated January 14, 1987,
between the Company and
Bangor-Pacific Hydro
Associates (formerly West
Enfield Associates)
10.80 Deed and Bill of Sale re Form 10-K, 1986, Exhibit
transfer of West Enfield 10(j)
site from the Company to
Bangor-Pacific Hydro
Associates
10.81 Assignment by the Company Form 10-K, 1986, Exhibit
of Joint Venture Interest 10(k)
to Penobscot Hydro Co., Inc.
10.82 Power Sale Agreement dated Form 10-K, 1986, Exhibit
August 1, 1986, and First 10(l)
Amendment thereto, between
the Company and Unitil
Power Corp. re Wyman No. 4
10.83 Third Amendment to Pre- Form 10-K, 1987, Exhibit
liminary Quebec Intercon- 10(a)
nection Support Agreement -
Phase II
10.84 Fourth Amendment to Pre- Form 10-K, 1987, Exhibit
liminary Quebec Intercon- 10(b)
nection Support Agreement -
Phase II
10.85 Fifth Amendment to Pre- Form 10-K, 1987, Exhibit
liminary Quebec Intercon- 10(c)
nection Support Agreement -
Phase II
10.86 Sixth Amendment to Pre- Form 10-K, 1987, Exhibit
liminary Quebec Intercon- 10(d)
nection Support Agreement -
Phase II
10.87 Seventh Amendment to Pre- Form 10-K, 1987, Exhibit
liminary Quebec Intercon- 10(e)
nection Support Agreement -
Phase II
10.88 Amendment to New England Form 10-K, 1987, Exhibit
Power Pool Agreement dated 10(f)
March 1, 1988
10.89 Second Amendment to Credit Form 10-K, 1987, Exhibit
Agreement, dated as of July 10(h)
22, 1987, among the Company
and the Banks named therein
10.90 Dividend Reinvestment and Form 10-K, 1987, Exhibit
Common Stock Purchase Plan 10(i)
Effective as of December 1,
1987
10.91 Deed dated December 2, Form 10-K, 1988, Exhibit
1988 regarding the sale 10(a)
of certain Seabrook trans-
mission facilities to EUA
Power
10.92 Ninth Amendment to Form 10-K, 1988, Exhibit
Preliminary Quebec 10(b)
Interconnection Support
Agreement - Phase II
10.93 Tenth Amendment to Form 10-K, 1988, Exhibit
Preliminary Quebec 10(c)
Interconnection Support
Agreement - Phase II
10.94 Second Amendment to Form 10-K, 1988, Exhibit
Massachusetts Trans- 10(d)
mission Facilities
Support Agreement
10.95 Third Amendment to Form 10-K, 1988, Exhibit
Massachusetts Trans- 10(e)
mission Facilities
Support Agreement
10.96 Fourth Amendment to Form 10-K, 1988, Exhibit
Massachusetts Trans- 10(f)
mission Facilities
Support Agreement
10.97 Fifth Amendment to Form 10-K, 1988, Exhibit 10(g)
Massachusetts Trans-
mission Facilities
Support Agreement
10.98 Sixth Amendment to Form 10-K, 1988, Exhibit 10(h)
Massachusetts Trans-
mission Facilities
Support Agreement
10.99 Second Amendment to Form 10-K, 1988, Exhibit 10(i)
New Hampshire Trans-
mission Facilities
Support Agreement
10.100 Third Amendment to Form 10-K, 1988, Exhibit 10(j)
New Hampshire Trans-
mission Facilities
Support Agreement
10.101 Fourth Amendment to Form 10-K, 1988, Exhibit 10(k)
New Hampshire Trans-
mission Facilities
Support Agreement
10.102 Fifth Amendment to Form 10-K, 1988, Exhibit 10(l)
New Hampshire Trans-
mission Facilities
Support Agreement
10.103 Sixth Amendment to Form 10-K, 1988, Exhibit 10(m)
New Hampshire Trans-
mission Facilities
Support Agreement
10.104 Second Amendment to Form 10-K, 1988, Exhibit 10(n)
Phase II AC New England
Power Facilities Sup-
port Agreement
10.105 Third Amendment to Form 10-K, 1988, Exhibit 10(o)
Phase II AC New England
Power Facilities Sup-
port Agreement
10.106 Fourth Amendment to Form 10-K, 1988, Exhibit 10(p)
Phase II AC New England
Power Facilities Sup-
port Agreement
10.107 Fifth Amendment to Form 10-K, 1988, Exhibit 10(q)
Phase II AC New England
Power Facilities Sup-
port Agreement
10.108 Second Amendment to Form 10-K, 1988, Exhibit 10(r)
Phase II Boston Edison
AC Facilities Support
Agreement
10.109 Third Amendment to Form 10-K, 1988, Exhibit 10(s)
Phase II Boston Edison
AC Facilities Support
Agreement
110.110 Fourth Amendment to Form 10-K, 1988, Exhibit 10(t)
Phase II Boston Edison
AC Facilities Support
Agreement
10.111 Fifth Amendment to Form 10-K, 1988, Exhibit 10(u)
Phase II Boston Edison
AC Facilities Support
Agreement
10.112 Letter of Assurances, Form 10-K, 1988, Exhibit 10(v)
Consents and Agreements
With Respect to Credit
Facility Financing for
Phase II Hydro-Quebec
Financing
10.113 Agreement With Hanlin Form 10-K, 1988, Exhibit 10(w)
Group, Inc., also known
as "LCP", for the sale of
electricity
10.114 401 (k) Plan for Non- Form 10-K, 1988, Exhibit 10(x)
Union Employees
10.115 Credit Agreement dated Form 10-Q, First Quarter, 1989
as of May 2, 1989 among Exhibit 4.2
the Company, the Banks
named therein, and
Manufacturers Hanover
Trust Company, as Agent
10.116 Agreement for the Sale Form S-2, Reg. No. 33-39181,
and Purchase of Electricity Exhibit 10.79
dated as of August 13, 1984
between Ultrapower Incorpor-
ated-Jonesboro and the
Company
10.117 Agreement for the Sale Form S-2, Reg. No. 33-39181,
and Purchase of Electricity Exhibit 10.80
dated as of August 13, 1984
between Ultrapower Incorpor-
ated-West Enfield and the
Company
10.118 Amendment Agreement Form S-2, Reg. No. 33-39181,
dated November 3, 1988 Exhibit 10.81
between the Company and
Babcock-Ultrapower West
Enfield and Babcock-
Ultrapower-Jonesboro
10.119 Agreement for the Form S-2, Reg. No. 33-39181,
Purchase and Sale of Exhibit 10.82
Electricity dated as of
June 21, 1984 between
Penobscot Energy Recovery
Company and the Company
10.120 Amendment No. 1 as of Form S-2, Reg. No. 33-39181,
March 24, 1986 to the Exhibit 10.83
Agreement for the Purchase
and Sale of Electricity
dated as of June 21, 1984
between Penobscot Energy
Recovery Company and the
Company
10.121 Power Purchase Agree- Form S-2, Reg. No. 33-39181,
ment dated October 24, 1984 Exhibit 10.84
between Alternative Energy
Decisions, Inc. and the
Company
10.122 Partnership Agreement Form S-2, Reg. No. 33-39181,
dated as of July 1, 1990 Exhibit 10.85
between NORVARCO and
Bangor Var Co., Inc.
10.123 Form of Agreement with Form 10-K, 1992, Exhibit 10(a)
certain Executive Officers
providing supplemental
death and retirement
benefits
10.124 Form of Agreement with Form 10-K, 1992, Exhibit 10(b)
certain Executive Officers
providing benefits upon
a change of control
10.125 Purchase Agreement between Form 10-Q, 3rd Quarter 1995,
Babcock-Ultrapower Exhibit 10.1
Jonseboro and Bangor Hydro-
Electric Company
10.126 Purchase Agreement between Form 10-Q, 3rd Quarter 1995,
Babcock-Ultrapower West Exhibit 10.2
Enfield and Bangor Hydro-
Electric Company
<TABLE> <S> <C>
<ARTICLE> UT
<LEGEND>
This schedule contains summary financial information extracted from 10-K and is
qualified in its entirety by reference to such 10-K.
</LEGEND>
<CIK> 0000009548
<NAME> BANGOR HYDRO-ELECTRIC COMPANY
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1995
<PERIOD-END> DEC-31-1995
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 218,440
<OTHER-PROPERTY-AND-INVEST> 48,666
<TOTAL-CURRENT-ASSETS> 35,763
<TOTAL-DEFERRED-CHARGES> 263,207
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 566,076
<COMMON> 36,508
<CAPITAL-SURPLUS-PAID-IN> 56,611
<RETAINED-EARNINGS> 10,073
<TOTAL-COMMON-STOCKHOLDERS-EQ> 103,192
12,070
4,734
<LONG-TERM-DEBT-NET> 288,075
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 35,000
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 13,646
3,923
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 106,066
<TOT-CAPITALIZATION-AND-LIAB> 566,076
<GROSS-OPERATING-REVENUE> 184,914
<INCOME-TAX-EXPENSE> 1,422
<OTHER-OPERATING-EXPENSES> 159,823
<TOTAL-OPERATING-EXPENSES> 161,245
<OPERATING-INCOME-LOSS> 23,669
<OTHER-INCOME-NET> 760
<INCOME-BEFORE-INTEREST-EXPEN> 24,429
<TOTAL-INTEREST-EXPENSE> 20,092
<NET-INCOME> 4,337
1,702
<EARNINGS-AVAILABLE-FOR-COMM> 2,635
<COMMON-STOCK-DIVIDENDS> 6,319
<TOTAL-INTEREST-ON-BONDS> 17,597
<CASH-FLOW-OPERATIONS> (164,522)
<EPS-PRIMARY> .36
<EPS-DILUTED> .36
</TABLE>
STATE OF MAINE
CHANGE OF CLERK or
REGISTERED OFFICE or BOTH
Pursuant to 13-A MRSA Section 304 the undersigned
corporation advises you of the following
change(s):
FIRST: The name and registered office of the clerk appearing on the record
in Secretary of State's office
FREDERICK S. SAMP
------------------------------------------------------------------
33 STATE STREET, BANGOR ME 04401
------------------------------------------------------------------
(street, city, state and zip code)
SECOND: The name and physical location of the registered office of the
successor (new) clerk, who must be a Maine resident, are:
ANDREW LANDRY
------------------------------------------------------------------
(name)
33 STATE STREET, BANGOR ME 04401
------------------------------------------------------------------
(street address (not PO Box), city, state and zip code)
------------------------------------------------------------------
(mailing address if different from above)
THIRD: Upon a change in clerk this must be completed:
(X) Such change was authorized by the directors and the power to
make such change is not reserved to the shareholders by the
articles or the bylaws.
( ) Such change was authorized by the shareholders. (Complete the
following)
I certify that I have custody of the minutes showing the above
action by the shareholders.
/s/ Andrew Landry
-----------------------------------------------
(signature of new clerk, secretary or
assistant secretary)
Dated: OCTOBER 13, 1995 BANGOR HYDRO-ELECTRIC COMPANY
----------------- ----------------------------------------------
(Name of Corporation)
By /s/ Andrew Landry
---------------------------------------------
(signature)
ANDREW LANDRY, CLERK
---------------------------------------------
(type or print name and capacity)
By
--------------------------------------------
(signature)
--------------------------------------------
(type or print name and capacity)
- ---------------------------------------
This document MUST be signed by (1) the CLERK or (2) the PRESIDENT or a vice-
president AND the SECRETARY, an assistant secretary or other officer the
bylaws designate as second certifying officer OR (3) if no such officers, a
majority of the DIRECTORS or such directors designated by a majority of
directors then in office OR (4) if no directors, the holders, or such of them
designated by the HOLDERS, OF RECORD OF A MAJORITY OF ALL OUTSTANDING SHARES
entitled to vote thereon OR (5) the HOLDERS OF ALL OUTSTANDING SHARES.
BANGOR HYDRO-ELECTRIC COMPANY
FORM 10-K
EXHIBIT 10(A)
- -------------
EXHIBIT 10(A) TO BHE FORM 10-K FOR 1995
FORM NO. MBCA-3 Rev. 90
SUBMIT COMPLETED FORMS TO: Secretary of State, Station 101,
Augusta, Maine 04333
BANGOR HYDRO-ELECTRIC COMPANY
TO
CHEMICAL BANK,
as Trustee
-------------
Supplemental Indenture
DATED AS OF OCTOBER 1, 1995
TO
General and Refunding Mortgage Indenture and Deed of Trust
DATED AS OF JUNE 1, 1995
SUPPLEMENTAL INDENTURE, dated as of October 1, 1995 (the
"Supplemental Indenture"), made by and between BANGOR HYDRO-
ELECTRIC COMPANY, a corporation organized and existing under the
laws of the State of Maine (the "Company"), the post office
address of which is 33 State Street, Bangor, Maine 04401, and
CHEMICAL BANK, a corporation organized and existing under the
laws of the State of New York (the "Trustee"), as Trustee under
the General and Refunding Mortgage Indenture and Deed of Trust
dated as of June 1, 1995, hereinafter mentioned, the post office
address of which is 450 West 33rd Street, New York, New York
10001;
WHEREAS, the Company has heretofore executed and delivered
its General and Refunding Mortgage Indenture and Deed of Trust
dated as of June 1, 1995 (the "Indenture"), to the Trustee, for
the security of the bonds of the Company issued thereunder (the
"Bonds"); and
WHEREAS, the Company has heretofore executed and delivered
its Supplemental Indenture dated as of June 15, 1995; and
WHEREAS, the Company has heretofore executed authenticated,
delivered and issued a Series of Bonds entitled General and
Refunding Mortgage Bonds, Series A (the "Series A Bonds") in the
aggregate principal amount of $126,000,000, all of which are
Outstanding as of the date hereof; and
WHEREAS, Section 14.01 of the Indenture provides that
without the consent of any Holders, the Company and the Trustee,
at any time and from time to time, may enter into one or more
indentures supplemental thereto, in form satisfactory to the
Trustee, for among other things, the purpose of correcting or
amplifying the description of any property at any time subject to
the Lien of the Indenture; and
WHEREAS, the Company, in the exercise of the powers and
authority conferred upon and reserved to it under Section 14.01
of the Indenture, has duly resolved and determined to make,
execute and deliver to the Trustee a Supplemental Indenture in
the form hereof for the purposes herein provided; and
WHEREAS, all conditions and requirements necessary to make
this Supplemental Indenture a valid, binding and legal instrument
have been done, performed and fulfilled and the execution and
delivery hereof have been in all respects duly authorized;
NOW, THEREFORE, THIS SUPPLEMENTAL INDENTURE WITNESSETH:
THAT BANGOR HYDRO-ELECTRIC COMPANY, in consideration of the
service by the Trustee, and its successors, under the Indenture
and of One Dollar to it duly paid by the Trustee at or before the
ensealing and delivery of these presents, the receipt whereof is
hereby acknowledged, hereby covenants and agrees to and with the
Trustee and its successors in the trust under the Indenture, for
the benefit of those who shall hold the Bonds as follows:
ARTICLE I.
SUPPLEMENTAL PROPERTY DESCRIPTION
The description of property subject to the Lien of the
Indenture is set forth in Exhibit A hereto, and amplifies the
description of property subject to the Lien of the Indenture
attached as Exhibit A to the Indenture as originally executed and
delivered by the Company and filed in each county in the State of
Maine in which the Company has any right, title or interest in
property, and is deemed to replace and supersede such Exhibit A
in full.
ARTICLE II.
THE TRUSTEE.
The Trustee hereby accepts the trusts hereby declared and
provided, and agrees to perform the same upon the terms and
conditions in the Indenture set forth and upon the following
terms and conditions:
The Trustee shall not be responsible in any manner
whatsoever for or in respect of the validity or sufficiency
of this Supplemental Indenture or the due execution hereof
by the Company or for or in respect of the recitals
contained herein, all of which recitals are made by the
Company solely.
ARTICLE III.
MISCELLANEOUS PROVISIONS.
This Supplemental Indenture may be simultaneously executed
in any number of counterparts, each of which when so executed
shall be deemed to be an original; but such counterparts shall
together constitute but one and the same instrument.
IN WITNESS WHEREOF, said Bangor Hydro-Electric Company has
caused this Supplemental Indenture to be executed on its behalf
by an Authorized Executive Officer as defined in the Indenture,
and its corporate seal to be hereto affixed and said seal and
this Supplemental Indenture to be attested by an Authorized
Executive Officer as defined in the Indenture; and Chemical Bank,
in evidence of its acceptance of the trust hereby created, has
caused this Supplemental Indenture to be executed on its behalf
by its President or one of its Vice Presidents and its corporate
seal to be hereto affixed and said seal and this Supplemental
Indenture to be attested by its Secretary or one of its Trust
Officers all as of the date first above written.
BANGOR HYDRO-ELECTRIC COMPANY
By /s/ Robert S. Briggs
--------------------------
[CORPORATE SEAL] President and Chief
Executive Officer
ATTEST:
/s/ Andrew Landry
- --------------------
Clerk
CHEMICAL BANK
[CORPORATE SEAL] By /s/
-------------------------
Vice President
ATTEST:
/s/
- ------------------------
Trust Officer
STATE OF MAINE )
) ss.:
COUNTY OF PENOBSCOT )
BE IT REMEMBERED, that on this 18TH day of October 1995,
before me, the undersigned, GAYLE A. KILLAM ,
a Notary Public within and for the County and State aforesaid,
personally came Robert S. Briggs, President, and Andrew Landry,
Clerk, of Bangor Hydro-Electric Company, a corporation duly
organized, incorporated and existing under the laws of the State
of Maine, who are personally known to me to be such officers, and
who are personally known to me to be the same persons who
executed as such officers the within instrument of writing, and
such persons duly acknowledged that they signed, sealed and
delivered the said instrument as their free and voluntary act as
such President and Clerk, respectively, and as the free and
voluntary act of said Bangor Hydro-Electric Company for the uses
and purposes therein set forth.
IN WITNESS WHEREOF, I have hereunto subscribed my name and
affixed my official seal on the day and year last above written.
/s/ Gayle A. Killam
---------------------------------
Notary Public
[NOTARIAL SEAL]
STATE OF NEW YORK )
) ss.:
COUNTY OF NEW YORK )
BE IT REMEMBERED, that on this 30TH day of November, 1995,
before me, the undersigned ROBERT J. STANISLARO , a Notary
Public within and for the County and State aforesaid, personally
came W.B. DODGE , a Vice-President and WANDA EILAND ,
a Trust Officer, of Chemical Bank, a corporation organized and
existing under the laws of State of New York, who are personally
known to me to be the same persons who executed as such officers
the within instrument of writing, and such persons duly
acknowledged that they signed, sealed and delivered the said
instrument as their free and voluntary act as such Vice-President
and Trust Officer, respectively, and as the free and voluntary
act of Chemical Bank for the uses and purposes therein set forth.
IN WITNESS WHEREOF, I have hereunto subscribed my name and
affixed my official seal on the day and year last above written.
/s/ Robert J. Stanislaro
----------------------------
Notary Public
[NOTARIAL SEAL]
EXHIBIT A
DESCRIPTION OF PROPERTY
All land and interests in land subject to the lien of and referenced in
the Mortgage and Deed of Trust, dated as of July 1, 1936, between Bangor
Hydro-Electric Company and City Bank Farmers Trust Company (as predecessor to
Citibank, N.A.), as supplemented and amended by duly recorded indentures
supplemental thereto (and related real estate property descriptions) (the
"1936 Mortgage") except land and interests in land which have been
specifically released from such lien from time to time; and as originally
recorded in the following places in the State of Maine: in Aroostook County
Registry of Deeds, in Book 444, Page 130; in Hancock County Registry of
Deeds, in Book 654, Page 79, in Penobscot County Registry of Deeds, in Book
1117, Page 3, in Piscataquis County Registry of Deeds, in Book 257, Page 241,
in Washington County Registry of Deeds, in Book 418, Page 102; in Cumberland
County Registry of Deeds, in Book 3957, Page 1; in Waldo County Registry of
Deeds, in Book 786, Page 119; in the City Clerk's Office for the City of
Bangor, in Book 19, Page 304; and in the Rockingham County Registry of Deeds
in the State of New Hampshire, in book 2351, Page 203.
Such land and interests in land are further described in certain
supplemental indentures, dated respectively as of March 1, 1938, recorded in
the Penobscot County Registry of Deeds in Book 1129, Page 380, in the
Washington County Registry of Deeds in Book 426, Page 31, in the Hancock
County Registry of Deeds in Book 661, Page 104, and in the Piscataquis County
Registry of Deeds in Book 260, Page 119; January 17, 1939, recorded in the
Penobscot County Registry of Deeds in Book 1134, Page 445, in the Washington
County Registry of Deeds in Book 426, Page 198, in the Hancock County
Registry of Deeds in Book 662, Page 302, and in the Piscataquis County
Registry of Deeds in Book 260, Page 462; March 1, 1941, recorded in the
Penobscot County Registry of Deeds in Book 1167, Page 226, in the Washington
County Registry of Deeds in Book 437, Page 216, in the Hancock County
Registry of Deeds in Book 679, Page 33, and in the Piscataquis County
Registry of Deeds in Book 264, Page 441; February 11, 1942, recorded in the
Penobscot County Registry of Deeds in Book 1177, Page 412, in the Washington
County Registry of Deeds in Book 448, Page 14, in the Hancock County Registry
of Deeds in Book 681, Page 591, and in the Piscataquis County Registry of
Deeds in Book 272, Page 253; July 10, 1945, recorded in the Penobscot County
Registry of Deeds in Book 1223, Page 382, in the Washington County Registry
of Deeds in Book 463, Page 37, in the Hancock County Registry of Deeds in
Book 700, Page 580, and in the Piscataquis County Registry of Deeds in Book
278, Page 171; July 8, 1947, recorded in the Penobscot County Registry of
Deeds in Book 1268, Page 48, in the Washington County Registry of Deeds in
Book 472, Page 457, in the Hancock County Registry of Deeds in Book 717, Page
119, and in the Piscataquis County Registry of Deeds in Book 290, Page 94;
September 13, 1949, recorded in the Penobscot County Registry of Deeds in
Book 1308, Page 446, in the Washington County Registry of Deeds in Book 488,
page 57, in the Hancock County Registry of Deeds in Book 731, Page 11, and in
the Piscataquis County Registry of Deeds in Book 294, Page 208; May 20, 1952,
recorded in the Penobscot County Registry of Deeds in Book 1363, Page 193, in
the Washington County Registry of Deeds in Book 515, Page 1, in the Hancock
County Registry of Deeds in Book 749, Page 28, and in the Piscataquis County
Registry of Deeds in Book 308, Page 35; January 8, 1981, recorded in the
Waldo County Registry of Deeds in Book 788, Page 333; December 1, 1984,
recorded in the Penobscot County Registry of Deeds in Book 3608, Page 117, in
the Washington County Registry of Deeds in Book 1305, Page 209, in the Waldo
County Registry of Deeds in Book 833, Page 100, in the Hancock County
Registry of Deeds in Book 1521, Page 214, and in the Piscataquis County
Registry of Deeds in Book 571, Page 448; March 15, 1989, recorded in the
Penobscot County Registry of Deeds in Book 4408, Page 165, in the Washington
County Registry of Deeds in Book 1565, page 289, in the Waldo County Registry
of Deeds in Book 1086, Page 83, in the Hancock County Registry of Deeds in
Book 1742, Page 486, and in the Piscataquis County Registry of Deeds in Book
715, Page 327; July 3, 1990, recorded in the Penobscot County Registry of
Deeds in Book 4678, Page 205, in the Washington County Registry of Deeds in
Book 1649, page 40, in the Waldo County Registry of Deeds in Book 776, Page
203, in the Hancock County Registry of Deeds in Book 1817, Page 360, and in
the Piscataquis County Registry of Deeds in Book 776, Page 203; March 31,
1992, recorded in the Penobscot County Registry of Deeds in book 5037, Page
229, in the Washington County Registry of Deeds in Book 1762, Page 314, in
the Waldo County Registry of Deeds in Book 1278, Page 298, in the Hancock
County Registry of Deeds in Book 1924, Page 177, and in the Piscataquis
County Registry of Deeds in Book 846, Page 14; October 22, 1992, recorded in
the Penobscot County Registry of Deeds in Book 5192, Page 1, in the
Washington County Registry of Deeds in Book 1808, Page 1, in the Hancock
County Registry of Deeds in Book 2015, Page 209, and in the Piscataquis
County Registry of Deeds in Book 873, Page 8; June 23, 1995, recorded in the
Penobscot County Registry of Deeds in Book 5891, Page 41, in the Washington
County Registry of Deeds in Book 2009, Page 98, in the Waldo County Registry
of Deeds in Book 1539, Page 306, in the Hancock County Registry of Deeds in
Book 2406, Page 122, and in the Piscataquis County Registry of Deeds in Book
991, Page 268.
