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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, 1996 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
(7,363,424 shares outstanding at March 21, 1997)
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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 21, 1997 of the voting stock held by
non-affiliates of the registrant was $47.0 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, 1996.
FORM 10-K
FOR THE FISCAL YEAR ENDED DECEMBER 31, 1996
PAGE
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Cover Page 1
Index 2
PART I:
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Items 1 through 2 - Business; Properties 5
- General 5
- Certain Issues Facing the Company 7
- Construction Program 10
- Rates and Regulation 11
- Seabrook 14
- Joint Ventures 15
- Employees 17
- Power Supply Sources 17
- Company-owned Generation 18
- Power Purchase Contracts 19
- Maine Yankee 21
- Environmental Matters 31
- Executive Officers of the Company 32
Item 3 - Legal Proceedings 33
Item 4 - Submission of Matters to a Vote of Security
Holders 33
PART II:
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Item 5 - Market for Registrant's Common Equity and Related
Stockholder Matters 33
Item 6 - Selected Financial Data 35
Item 7 - Management's Discussion and Analysis of Results of
Operations and Financial Condition 37
Item 8 - Financial Statements & Supplementary Data 47
- Consolidated Statements of Income 47
- Consolidated Balance Sheets 48
- Consolidated Statements of Capitalization 50
- Consolidated Statement of Cash Flows 51
- Consolidated Statements of Retained Earnings 52
- Notes to Consolidated Financial Statements 53
1) Nature of Operations and Summary of
Significant Accounting Policies 53
2) Income Taxes 55
3) Common and Preferred Stock 57
4) Long-Term Debt and Short-Term Borrowings 58
5) Postretirement and Other Post-Employment
Benefits 59
6) Jointly Owned Facilities and Power Supply
Commitments 62
7) Unaudited Quarterly Financial Data 67
8) Recovery of Seabrook Investment and Sale of
Seabrook Interest 68
9) Contingencies 68
10) Fair Value of Financial Instruments 68
11) Regulatory Assets 68
12) Alternative Marketing Plan 69
13) Acquisition of Wholesale Customer 69
14) Derivative Financial Instruments 69
Report of Independent Accountants 71
Item 9 - Changes in and Disagreements with Audit Firms on
Financial Disclosures 72
PART III:
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Item 10 - Directors and Executive Officers of the
Registrant 72
Item 11 - Executive Compensation 72
Item 12 - Security Ownership of Certain Beneficial Owners
and Management 72
Item 13 - Certain Relationships and Related Transactions 72
PART IV:
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Item 14 - Exhibits, Financial Statement Schedules, and
Reports on Form 8-K 74
Signatures 76
Report of Independent Accountants 77
Schedule VIII - Reserves for Doubtful Accounts and
Insurance 78
EXHIBIT INDEX:
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Exhibits Incorporated Herein by Reference 79
PART I
Items 1 through 2 Business; Properties
General
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 104,000 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 1996, 31.4% of the Company's kilowatt hour ("KWH") sales were to
residential customers, 30.0% were to commercial customers, 37.8% were to
industrial customers and 0.8% 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 1996-1997 winter, as of March 20, 1997, was approximately 274.3 megawatts
("MW") on December 30, 1996. At that time the Company had approximately
420.8 MW of generating capacity and firm purchased power, comprised of 104 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, 54 MW from non-utility power producers, and 184 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
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 the consideration by the legislature of the State of Maine of a plan to
restructure the electric industry within the state to implement 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 totaling
approximately $5.0 million at December 31, 1996, 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 in 1996 under its power purchase
agreement with Maine Yankee were approximately $12.8 million. Maine Yankee's
operating license expires in 2008.
Following a year-long shutdown for repairs to the steam generators in 1995,
Maine Yankee has come under intense regulatory scrutiny in a series of events
beginning in December 1995 with an anonymous letter about an allegedly faulty
computer program. The events have evolved into a number of investigations by
Maine Yankee's primary licensing authority, the United States Nuclear
Regulatory Commission ("NRC") and by Maine Yankee itself. Concerns have
included compliance with NRC regulations, conformance of the plant to design
specifications, adequacy and condition of components and systems, and
management issues. Many of these concerns remain unresolved. During the
evolution of these events, the NRC itself has been subject to public
criticism about the adequacy of its regulatory activities and its
relationship with nuclear plant licensees, and in response the NRC has been
implementing changes in its approach to oversight of licensees that are
having the effect of amplifying the regulatory scrutiny. Civil enforcement
proceedings have been initiated by the NRC to impose monetary penalties on
Maine Yankee for alleged violations of regulations. The NRC has also
referred certain issues to the United States Department of Justice for
further investigation, which could result in further civil or criminal
proceedings. The Company cannot predict the outcome of these investigations
and proceedings.
Maine Yankee operated for part of 1996, but under a restriction imposed by
the NRC that limited its operation to 90% of full power capacity pending the
resolution of various issues (which are not yet resolved). The plant has
been off-line since early December 1996 when it was shut down to address
cable-separation and associated issues. Since then, Maine Yankee also
determined that a substantial portion of the nuclear fuel in the reactor was
defective and had to be replaced, thereby extending the shutdown into a
refueling outage. During the refueling outage, Maine Yankee is continuing to
attempt to resolve the other issues that led to the current shutdown, and
will inspect the steam generators for degradation beyond that which was the
subject of the 1995 repair. Such degradation has been identified at other
plants of similar age and design as Maine Yankee. Satisfactory condition of
the steam generators is a significant factor in the plant's continued
operation.
Management changes are taking place at Maine Yankee. Maine Yankee's chief
executive officer resigned in late 1996, and a management team from a firm
experienced in nuclear generating plant operations has been retained.
The Company cannot predict how long Maine Yankee will remain out of service.
The Company has been incurring replacement power costs of approximately $1
million per month while the plant has been out of service, and expects such
costs to continue at the same rate until the plant returns to service. The
market price for replacement power is being driven up somewhat because other
nuclear power plants in New England are also indefinitely shut down. In
addition to the replacement power costs, the Company is responsible for 7% of
whatever additional costs are necessary to return Maine Yankee to service.
In December 1996 the Maine Yankee board of directors approved about $30
million in additional operating and maintenance costs for 1997 (in additional
to incremental capital costs), and, while revised budgets have not been
approved, these costs are now likely to be greater.
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.
PROPOSED GAS PIPELINE PROJECT. On September 23, 1996, Maritimes & Northeast
Pipeline, L.L.C. ("Maritimes") filed an application with the Federal Energy
Regulatory Commission ("FERC") seeking authority under the Natural Gas Act to
construct, install, own, operate and maintain certain new natural gas
pipeline, compression and ancillary facilities in the State of Maine. The
facilities for which authorization is sought comprise a portion of a proposed
new high pressure natural gas pipeline system to transport gas in
international commerce from Sable Island, Nova Scotia, Canada through New
Brunswick, Maine, New Hampshire and into Massachusetts. As part of its
system, Maritimes has proposed constructing lateral pipelines that would make
significant quantities of natural gas available to industrial customers of
the Company. On November 4, 1996, the Company filed with the FERC a motion
to intervene in the Maritimes proceeding and requested that the FERC impose
certain conditions on any certification of the proposed pipeline system.
Specifically, the Company noted that if a customer were to use natural gas as
a substitute energy source for its current usage of electrical energy, the
Company and its remaining customers would be saddled with certain "stranded"
costs that were incurred under traditional regulatory structures providing
monopoly protection in return for the undertaking of an obligation to serve.
The Company asked that if the FERC certifies the Maritimes project, the
authorization should include the requirement that in order for any electric
customer that opts to leave its current electric supplier (in whole or in
part) to receive transmission service from the Maritimes project, it must
agree to pay any stranded costs associated with that departure.
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 to its customers. During 1996, revenue sharing payments from HMC
totaled approximately $3.5 million. HMC's principal business is selling
chlorine and caustic soda, primarily to the paper industry in the State of
Maine. The Company is unable to predict future market conditions for HMC s
products.
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
approximately $40-50 million in the period 1997 through 1999.
RATES AND REGULATION
RATE MATTERS - On March 3, 1997, the Company filed with the Maine Public
Utilities Commission a notice of its intent to file a request for a general
increase in rates. Such notice is required by Maine statute to be made at
least 60 days in advance of the filing of such a request. In the notice, the
Company notified the Commission that it expected to seek a two step rate
increase of $5 million beginning in 1998 and $4.5 million beginning in 1999.
This would represent an overall increase of about 3% per year over the two
year period. The Company also informed the Commission that this estimated
request assumes that the Company will achieve a restructuring of its purchase
power contract with the Penobscot Energy Recovery Company s generating plant
in Orrington, Maine (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 - Impact on the Company and the Company s
Response to Financial Pressures and Item 8, Financial Statements &
Supplementary Data - Notes to Consolidated Financial Statements - 6. Jointly
Owned Facilities and Power Supply Commitments - Small Power Production
Facilities ) and that the Maine Yankee nuclear power plant will return to
service by 1998. If either of these events do not occur, the Company would
expect to request a larger rate increase. Under Maine law, after the filing
of the formal request for a change in rates by a utility, the Commission has
nine months to investigate the request. If the Commission took the full
period allowed for such an investigation, new rates would be implemented in
February, 1998. 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 - Restructuring the Industry", incorporated
herein by reference, for a further 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.
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. 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
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
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 1996, the
Company paid approximately $8.25 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
At December 31, 1996, the Company had 429 full time employees
approximately 42% 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. On February 26, 1997, the employees of
the Company s customer service center, approximately 50 employees, voted to
join the International Brotherhood of Electrical Workers (AFL-CIO). To date
no contract has been negotiated between the Company and the union with
respect to these new members. However, the Company believes that such
contract negotiations are likely to be completed during 1997. The Company
believes that its relations with its employees are satisfactory.
POWER SUPPLY SOURCES
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 1996, 1995 and 1994 by type
of fuel is shown below.
Source 1996 1995 1994
------ ---- ---- ----
Hydroelectric (Company*)....... 17% 14% 15%
Nuclear Generation (Maine Yankee) 19% 1% 25%
Oil (Company)................... 2% 3% 2%
Biomass/Refuse (purchased)...... 6% 6% 8%
NEPOOL/other purchases.......... 56% 76% 50%
---- ---- ----
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
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 3,500 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
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
- ---------- ---------------------- --------------------------
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 No Fixed Term Approximately 20 MW
Paper Co.
(Cogeneration)
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)
Contracted Quantity of
Seller Term of Contract Capacity or Energy
- ---------- ---------------------- --------------------------
Great Bay Power January 1,1996 through 10 MW and associated energy
Corporation March 31, 1998 from a designated nuclear
(through PECO unit (November-March only)
Energy Company)
Great Bay Power No Fixed Term 15 MW and associated energy
Corporation under a service agreement
(through PECO for market based purchases
Energy Company)
Central Maine No Fixed Term 29 MW and associated energy
Power Company under a service agreement
for market based purchases
- ---------------------
* Through PHC, the Company has a 50% ownership interest in Bangor-Pacific,
which owns and operates the West Enfield Project.
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.
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
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.
PLANT REGULATORY AND OPERATIONAL ISSUES - Prior to 1995, the Maine Yankee
unit, like other pressurized-water reactors, had been experiencing
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 steam generator tubes. In the past, the
detection of defects had resulted in the plugging of those tubes to prevent
their subsequent use. During the refueling-and-maintenance shutdown that
commenced in early February of 1995, Maine Yankee detected through new
inspection methods substantially increased degradation of the Plant's steam
generator tubes to the extent that approximately 60 percent of the Plant's
17,000 steam generator tubes appeared to have defects to some degree, which
eliminated mitigating the problem by plugging the tubes with indicated
defects.
Following a detailed analysis of the safety, technical and financial
considerations associated with repair of 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 had 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 NRC, and was essentially
complete in early December. The project caused Maine Yankee to incur costs
of approximately $27 million during 1995.
On December 4, 1995, when the sleeving project was substantially
complete, Maine Yankee obtained a copy of a letter from the Union of
Concerned Scientists, an organization with a history of opposing nuclear
power, to a State of Maine nuclear safety official based on documentation
from an anonymous employee or former employee of Yankee Atomic Electric
Company ("Yankee"), an affiliate of the Company that has regularly performed
nuclear engineering and related services for the Company and other nuclear
plant operators. The letter contained allegations that Yankee had 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 the 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
containment's peak postulated accident pressure, both under certain assumed
accident conditions. The analyses were used in support of license amendments
that authorized Plant power uprates from 2440 megawatts thermal, a level
equal to approximately 90 percent of the maximum electrical capability of the
Plant, to its current 100-percent rated level of 2700 megawatts thermal.
In response to technical issues raised by the allegations, the NRC
initiated a special technical review of the safety analyses 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. Subsequently, the NRC informed
Maine Yankee that the allegations would be the subject of investigations by
the NRC's Office of Investigations ("OI") and the Office of the Inspector
General ("OIG").
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 "Order"). The Order
limited the power output of the Maine Yankee Plant to approximately 90
percent of its rated maximum until the NRC had reviewed and approved a Plant-
specific ECCS analysis and ordered that internal containment pressure be
limited until the NRC had reviewed the design-basis analysis of containment
pressure. The Order further contained a request for information prior to
restart, which Maine Yankee satisfied.
On January 10, 1996, Maine Yankee filed with the NRC information
specified in the Order that it believed supported operation of the Plant at
up to 90 percent of the Plant's capability and the Plant began normal
operation at the 90-percent level on January 24, 1996. On April 25, 1996,
Maine Yankee submitted the ECCS analysis requested in the Order.
In December 1995 the OIG and OI initiated separate investigations of the
anonymous allegations of wrongdoing by Maine Yankee and Yankee. On May 9,
1996, the OIG, which was responsible for investigating only the actions of
the NRC Staff and not those of Maine Yankee or Yankee, issued its report on
its investigation. The report found deficiencies in the NRC Staff s review,
documentation, and communications practices in connection with the license
amendments, as well as "significant indications of possible licensee
violations of NRC requirements and regulations." Any such violations by
Maine Yankee or Yankee are within the purview of the OI investigation. Maine
Yankee was advised on September 19, 1996, that the NRC had asked the U.S.
Department of Justice to review the OI investigation report. Maine Yankee
cannot predict the outcome of that review. An internal assessment by Maine
Yankee and Yankee noted several areas that could have been improved,
including regulatory communications, definition of responsibilities between
Maine Yankee and Yankee, and documentation and tracking of regulatory
compliance. A separate internal investigation of issues raised by the
anonymous allegations commissioned by the boards of directors of Maine Yankee
and Yankee and conducted by an independent law firm found no wrongdoing by
Maine Yankee, Yankee or any of their employees.
On June 7, 1996, the NRC formally notified Maine Yankee that it would
conduct an "Independent Safety Assessment" ("ISA") of the Plant as a "follow-
on" to the OIG report and to provide an independent evaluation of the safety
performance of Maine Yankee by a team of NRC personnel and contractors who
were "independent of any recent or significant involvement with the
licensing, regulation or inspection of Maine Yankee, with State of Maine
involvement." The NRC conducted the ISA in the summer of 1996 and released
its report on October 7, 1996.
The detailed ISA report identified both deficiencies and strengths in
Maine Yankee's performance, and concluded that overall performance at Maine
Yankee was "adequate" for operation of the Plant. The ISA team stressed that
the deficiencies noted in the report stemmed from two closely related root
causes, specifically, (1) that economic pressure to be a low-cost energy
provider had limited available resources to address corrective actions and
some improvements, and (2) that a questioning culture was lacking at Maine
Yankee, which had resulted in a failure to identify or promptly correct
significant problems in areas perceived by Maine Yankee to be of low safety
significance. In a letter to Maine Yankee accompanying the ISA report
Chairman of the NRC Shirley Ann Jackson noted that although overall
performance at Maine Yankee was considered adequate for operation, a number
of significant weaknesses and deficiencies identified in the report would
result in NRC violations. The letter also directed Maine Yankee to provide
to the NRC its plans for addressing the root causes of the deficiencies noted
in the ISA and identified the NRC offices that would be responsible for
overseeing corrective actions and taking appropriate enforcement actions
against Maine Yankee.
On December 10, 1996, Maine Yankee filed its formal response to the ISA
report with the NRC. In the response Maine Yankee indicated that it would
spend substantial sums on improvements in several areas in 1997 to address
the root causes and associated deficiencies noted in the report, and that the
improvements would include physical and operating changes at the Plant, along
with a ten-percent increase in staffing, primarily in the engineering and
maintenance areas, and other changes. In a release accompanying the
response, Maine Yankee stated that a "fundamental shift in corporate culture"
would accompany the changes and that Maine Yankee would not seek to return
the Plant to the 100-percent power level from its authorized 90-percent level
until it had also reviewed the margins on all the key safety systems at the
Plant, which had been another matter of concern to the NRC.
The December 1995 allegations caused the Plant's extended tube-sleeving
outage to be further extended into January 1996, and the Plant returned to
the 90-percent operating level on January 24, 1996. The Plant operated
substantially at that level until July 20, 1996, when it was taken off-line
after a comprehensive review by Maine Yankee of the Plant s systems and
equipment revealed a need to add pressure-relief capacity to a section of the
Plant s primary component cooling system. On August 18, 1996, while the
Plant was in the restart process, Maine Yankee conducted a review of its
electrical circuitry testing procedures pursuant to a generic NRC letter to
nuclear-plant licensees that was intended to ensure that the electrical logic
features of safety systems be routinely tested. During the expanded review,
Maine Yankee found a deficiency in an electrical circuit of a safety system
and therefore elected to conduct an intensified review of other safety-
related circuits to resolve immediately any questions as to the adequacy of
related testing procedures. The Plant returned to the 90-percent operating
level on September 3, 1996.
On December 6, 1996, Maine Yankee took the Plant off-line again to
resolve cable-separation and other operational and design issues. On January
3, 1997, Maine Yankee announced that it would use the opportunity presented
by that outage to inspect the Plant s 217 fuel assemblies, since daily
monitoring had indicated evidence of minor leakage in a small number of the
Plant s 38,000 fuel rods. As a result of the inspection, Maine Yankee
determined that all of the assemblies manufactured by one supplier and
currently in the reactor core (approximately one-third of the total) would
have to be replaced before the Plant could be restarted. Maine Yankee will
therefore keep the Plant off-line for refueling, which had previously been
scheduled for late 1997. In addition, Maine Yankee will make use of the
outage to conduct a thorough inspection of the Plant s steam generators,
commencing approximately April 1, 1997, for deterioration beyond that which
was repaired during the extended 1995 outage. Degradation of steam
generators of the age and design of those in use in the Plant has been
identified at other plants. If major repairs to, or replacement of, the steam
generators were found to be necessary for continued operation of the Plant,
Maine Yankee would review the economics of continued operation before
incurring the substantial capital expenditures that would be required. The
Company cannot predict the results of the inspection.
On January 29, 1997, the NRC announced that it had placed the Plant on
its "watch list," in "Category 2," which includes plants that display
"weaknesses that warrant increased NRC attention," but which are not severe
enough to warrant a shut-down order. Plants in Category 2 remain in that
category "until the licensee demonstrates a period of improved performance."
The Plant is one of fourteen nuclear units on the watch list announced that
day by the NRC, which regulates over 100 civilian nuclear power plants in the
United States.
On February 13, 1997, Maine Yankee and Entergy Nuclear, Inc.
("Entergy"), which is a subsidiary of Entergy Corporation, a Louisiana-based
utility holding company and leading nuclear plant operator, entered into a
contract under which Entergy is providing management services to Maine
Yankee. At the same time, officials from Entergy assumed management
positions, including President, at Maine Yankee.
While the Plant is out of service Maine Yankee, in addition to
successfully completing the refueling and the inspection of the steam
generators, must resolve the cable-separation issues and other known
regulatory issues, as well as any additional issues that are discovered
during the outage. The Company must obtain the approval of the NRC Staff to
restart the Plant, following a mandated NRC process that includes an NRC-
approved restart plan and opportunities for public participation. Maine
Yankee submitted its Restart Readiness Plan ("RRP") to the NRC on March 7,
1997. The NRC has scheduled the initial public meeting for review of the RRP
for April 3, 1997. In December 1996 the Maine Yankee board of directors
approved about $30 million in additional operating and maintenance costs for
1997 (in additional to incremental capital costs). While revised budgets
have not been approved, Maine Yankee now estimates that its operations and
maintenance costs will increase by a total of approximately $47 million in
1997, net of refueling costs. The Company believes the Plant will be out of
service at least until August 1997, but cannot predict when or whether all of
the regulatory and operational issues will be satisfactorily resolved or what
effect the ultimate total of the repairs and improvements to the Plant will
have on the economics of operating the Plant.
NUCLEAR FUEL STORAGE: Federal legislation enacted in 1987 directed the DOE to
proceed with the studies necessary to develop and operate a permanent high-
level waste (spent fuel) disposal site at Yucca Mountain, Nevada. The
legislation also provided for the possible development of a Monitored
Retrievable Storage ("MRS") facility and abandoned plans to identify and
select a second permanent disposal site. An MRS facility would provide
temporary storage for high-level waste prior to eventual permanent disposal.
In late 1989, the DOE announced that the permanent disposal site was not
expected to open before 2010, although originally scheduled to open in 1998.
The Nuclear Waste Policy Act of 1996 (S. 1936), approved by the United
States Senate on July 31, 1996, would provide for an interim federal high-
level waste storage facility to commence operation by November 30, 1999, if
Yucca Mountain is found to be a stable repository site, and authorizes the
DOE to develop an integrated spent-fuel management program. A generally
similar bill is pending in the House of Representatives. The Company cannot
predict whether or in what form the legislation will be adopted.
In June 1994, several nuclear utilities other than Maine Yankee filed
suit against the DOE. The utilities sought 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. On July 23, 1996, the court held that the DOE is obligated to start
disposing of [spent nuclear fuel] no later than January 31, 1998. In October
1996 the DOE announced that it would not appeal the decision. The Company
cannot predict when or how the DOE will satisfy its responsibility.
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 1997 the available capacity of the pool will not
accommodate a full-core removal. After consideration of available
technologies, the Company elected to provide additional capacity by replacing
the fuel racks in the spent fuel pool at the Plant and, in January 1993,
filed with the NRC seeking authorization to implement the plan. On March 15,
1994, the NRC granted the authorization, and the installation of the new
racks is scheduled to be completed during 1997. The Company believes that
the replacement of the fuel racks will provide adequate storage capacity
through the Maine Yankee's licensed operating life, but cannot predict with
certainty the effect on the future cost of spent fuel disposal.
NUCLEAR INSURANCE: In accordance with the Price-Anderson Act, the limit of
liability for a nuclear-related accident is approximately $8.9 billion. 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 percent ($3.775 million) of the maximum
retrospective assessment.
Numerous liability claims were filed as a result of the 1979 accident at
Three Mile Island Unit No. 2 in Pennsylvania. On June 7, 1996, all of the
lawsuits claiming personal injuries as a result of that accident were
dismissed prior to trial by the United States District Court in which the
suits were to be heard. The suits are subject to appeal. If the first layer
of coverage carried by the owners of the unit should be exhausted to pay such
claims, Maine Yankee and other licensees in the United States would be
assessed as part of the secondary layer. The Company cannot predict the
outcome of any appeals or whether or when secondary-layer assessments will be
required, but, in any event, Maine Yankee s assessment would be limited to $5
million.
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. 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 premium 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 5 times its premium with respect to industry
losses in any policy year, which could range up to approximately $15.1
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 been shipping its low-level waste
to the South Carolina facility for disposal.
The states of Maine, Texas and Vermont have been pursuing the
implementation of a compact for the disposal of low-level waste at a site in
Texas. The ratification bill for the compact is before Congress for
consideration at its 1997 session. The compact provides for Texas to take
Maine's low-level waste over a 30-year period for disposal at a planned
facility in west Texas. In return, Maine would be required to pay $25
million, assessed to the Company by the State of Maine, payable in two equal
installments, the first after ratification by Congress and the second upon
commencement of operation of the Texas facility. In addition, Maine Yankee
would be assessed a total of $2.5 million for the benefit of the Texas county
in which the facility would be located and would also be responsible for its
pro-rata share of the Texas governing commission's operating expenses. The
Maine Low-Level Radioactive Waste Authority suspended its search for a
suitable disposal site in Maine and, as of June 30, 1994, ceased operations.
In the event the required ratification by Congress is not obtained,
subject to continued NRC approval, Maine Yankee will ship low-level waste
offsite 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 Maine Yankee will have adequate storage capacity for such low-
level waste available on-site, if needed, through the current licensed
operating life of the Plant, to October 21, 2008.
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.
HAZARDOUS SUBSTANCE SITE: Maine Yankee has been notified by the Maine
Department of Environmental Protection ("DEP") that it is one of many
potentially responsible parties under the Maine Uncontrolled Hazardous
Substance Sites law for having arranged for the transport of hazardous
substances to sites owned by the Portland Bangor Waste Oil Company that have
been designated uncontrolled hazardous substance sites by the DEP. Under the
Maine law, each responsible party is jointly and severally liable for costs
associated with the abatement, cleanup or mitigation of the hazards at such a
site. Since the investigations by the DEP and Maine Yankee are in their
early stages and a large number of potentially responsible parties is
involved, the Company cannot now predict the amount of costs that Maine
Yankee will ultimately be required to assume.
ENVIRONMENTAL MATTERS
The Company is regulated by the United States Environmental Protection
Agency ("EPA") as to compliance with the Federal Water Pollution Control Act,
the Clean Air Act, and several federal statutes governing the treatment and
disposal of hazardous wastes. The Company is also regulated by the Maine
Department of Environmental Protection under various Maine environmental
statutes. Although the Company is actively engaged in complying with these
federal and state acts and statutes, the costs of which are significant, it
has not, to date, encountered material difficulties in connection with such
compliance.
In 1992, the Company received notice from the Maine Department of
Environmental Protection 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 (the EPA ) placed one of the sites on the National
Priorities List under the Comprehensive Environmental Response, Compensation,
and Liability Act. In November, 1996, the Company received a Request for
Information from the EPA regarding use of the site during the period between
1965 and 1980. 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.
The Company estimates that during 1997 it will spend approximately
$350,000 in operations expenses and $115,000 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 53 President & Chief Executive
Officer since January 1991
Carroll R. Lee 47 Senior Vice President and
Chief Operating Officer since
December, 1996
Frederick S. Samp 46 Vice President - Finance &
Law since 1995; Treasurer since
1995; Chief Financial Officer
since 1995
Paul A. LeBlanc 49 Vice President - Human Resources
& Information Services since
November, 1996
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, Vice President-Planning & Development from
1987 until 1990 and Vice President-Operations from 1990 until 1996. Mr. Samp
was Corporate Counsel, Corporate Secretary and Clerk from 1985 until 1988 and
General Counsel, Corporate Secretary and Clerk from 1988 until 1995. Mr.
LeBlanc was Vice President-Administration from 1978 until 1987, Vice
President-Customer Services from 1987 until 1988 and Assistant to the
President from 1988 until 1996.
ITEM 3 LEGAL PROCEEDINGS
See Note 9 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, 1996, there were 7,734 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
- ------------- ---- --- ---------
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................ 12 1/2 10 1/4 .18
Second Quarter............... 11 10 .18
Third Quarter................ 10 3/4 9 7/8 .18
Fourth Quarter............... 10 3/8 9 1/4 .18
1997
- ----
First Quarter
(through March 21, 1997).. 9 1/2 6 .00
A cash dividend of $.18 per common share was declared for each of the
four quarters of 1996. The fourth quarter dividend of $18 was paid on
January 20, 1997 to stockholders of record on December 31, 1996. As a result
of current financial pressures, including ongoing difficulties at the Maine
Yankee nuclear power plant, the Company did not declare a quarterly dividend
on its common stock at a regular meeting of the Company's Board of Directors
held on March 19, 1997.
The Company's credit agreements with its lending banks and the Finance
Authority of Maine contain a number of covenants keyed to the Company's
financial condition and performance. One such covenant prohibits the Company
from paying out in dividends on its common stock more than 70% of its
earnings applicable to common stock in any calendar year.
ITEM 6 - SELECTED FINANCIAL DATA
Bangor Hydro-Electric Company
SIX YEAR STATISTICAL SUMMARY
(Unaudited)
1996 1995 1994 1993 1992 1991
- ----------------------------------------------------------------------------------------------------------------------------
MEGAWATT HOURS (MWH) GENERATED AND PURCHASED
Hydro Generation (Company) 321,532 275,810 271,616 275,694 305,011 313,629
Nuclear Generation (Maine Yankee) 348,719 13,606 456,871 395,665 368,641 430,879
Oil (Company) 26,912 50,706 35,759 47,115 80,770 70,681
Biomass/Refuse 163,279 177,558 190,218 281,260 307,451 338,376
NEPOOL/Other Purchases 1,359,116 1,540,530 958,363 937,431 767,306 702,818
- ----------------------------------------------------------------------------------------------------------------------------
Total Generated & Purchased 2,219,558 2,058,210 1,912,827 1,937,165 1,829,179 1,856,383
Less Line Losses and Company Use 141,426 140,128 136,908 135,561 131,764 122,370
- ----------------------------------------------------------------------------------------------------------------------------
Remainder - MWH sold 2,078,132 1,918,082 1,775,919 1,801,604 1,697,415 1,734,013
============================================================================================================================
CLASSIFICATION OF SALES - MWH
Residential 536,490 513,076 516,470 515,242 521,889 517,259
Commercial 512,433 511,720 507,285 500,488 490,861 483,376
Industrial 647,985 686,386 611,876 615,314 563,734 539,565
Lighting 8,945 9,547 9,416 9,590 9,876 10,615
Wholesale 4,486 10,961 11,705 10,311 10,462 10,880
- ----------------------------------------------------------------------------------------------------------------------------
Total MWH Billed to Customers 1,710,339 1,731,690 1,656,752 1,650,945 1,596,822 1,561,695
Unbilled Sales - Net Increase (Decrease) 2,998 4,658 6,366 2,001 (11,832) 4,175
- ----------------------------------------------------------------------------------------------------------------------------
Total Delivered Sales (MWH) 1,713,337 1,736,348 1,663,118 1,652,946 1,584,990 1,565,870
(Less) Interruptible Sales 237,553 295,818 231,128 254,359 208,066 203,108
- ----------------------------------------------------------------------------------------------------------------------------
Total Firm Delivered Sales (MWH) 1,475,784 1,440,530 1,431,990 1,398,587 1,376,924 1,362,762
Off-System Sales 364,795 181,734 112,801 148,658 112,425 168,143
- ----------------------------------------------------------------------------------------------------------------------------
Total Energy Sales (MWH) 2,078,132 1,918,082 1,775,919 1,801,604 1,697,415 1,734,013
============================================================================================================================
ELECTRIC OPERATING REVENUES AND EXPENSES (000'S)
OPERATING REVENUES
Residential $ 66,805 $ 66,061 $ 64,008 $ 64,244 $ 66,429 $ 58,510
Commercial 54,168 55,030 53,410 53,599 53,806 46,859
Industrial 38,947 39,929 37,040 39,508 39,340 34,047
Lighting 2,032 2,051 2,010 1,915 1,933 1,755
Wholesale 314 859 937 903 895 898
- ----------------------------------------------------------------------------------------------------------------------------
Total Revenue From Customers $ 162,266 $ 163,930 $ 157,405 $ 160,169 $ 162,403 $ 142,069
Unbilled Sales-Net Increase (Decrease) 408 210 1,450 (237) (964) 2,642
- ----------------------------------------------------------------------------------------------------------------------------
Total Revenue $ 162,674 $ 164,140 $ 158,855 $ 159,932 $ 161,439 $ 144,711
(Less) Interruptible Revenue 9,537 11,149 8,450 8,876 8,331 8,040
- ----------------------------------------------------------------------------------------------------------------------------
Total Firm Revenue $ 153,137 $ 152,991 $ 150,405 $ 151,056 $ 153,108 $ 136,671
Off-System Revenue 18,384 14,098 12,750 15,326 13,857 15,736
- ----------------------------------------------------------------------------------------------------------------------------
Total Operating Revenues $ 181,058 $ 178,238 $ 171,605 $ 175,258 $ 175,296 $ 160,447
============================================================================================================================
OPERATING EXPENSES
Fuel Used in Generation $ 78,477 $ 98,684 $ 104,132 $ 116,386 $ 114,943 $ 107,074
Operating and Maintenance Expense 32,441 35,711 33,498 29,474 27,042 25,253
Depreciation and Amortization 29,965 20,544 10,333 6,447 6,789 6,615
Taxes 10,249 6,306 8,803 8,866 9,499 6,856
- ----------------------------------------------------------------------------------------------------------------------------
Total Operating Expenses $ 151,132 $ 161,245 $ 156,766 $ 161,173 $ 158,273 $ 145,798
============================================================================================================================
SUMMARY OF OPERATIONS (000'S)
Operating Revenue $ 187,374 $ 184,914 $ 174,098 $ 177,972 $ 176,789 $ 162,243
Operating Expenses 151,132 161,245 156,766 161,173 158,273 145,798
Other Income (including equity AFDC) 1,466 760 1,308 (2,657)* 1,690 2,367
Interest Expense (net of borrowed AFDC) 26,425 20,092 11,183 8,805 9,952 10,614
- ----------------------------------------------------------------------------------------------------------------------------
Net Income $ 11,283 $ 4,337 $ 7,457 $ 5,337 * $ 10,254 $ 8,198
Less Preferred Dividends 1,537 1,702 1,652 1,646 1,613 1,613
- ----------------------------------------------------------------------------------------------------------------------------
Earnings on Common Stock $ 9,746 $ 2,635 $ 5,805 $ 3,691 * $ 8,641 $ 6,585
============================================================================================================================
SELECTED FINANCIAL DATA
Total Assets (000's) $ 556,629 $ 566,076 $ 381,250 $ 373,521 $ 288,867 $ 279,483
ELECTRIC PLANT (000'S)
Total Electric Plant $ 341,526 $ 323,664 $ 303,637 $ 281,606 $ 255,601 $ 232,079
Depreciation Reserve 87,736 81,934 75,667 71,184 67,645 66,111
- ----------------------------------------------------------------------------------------------------------------------------
Net Electric Plant $ 253,790 $ 241,730 $ 227,970 $ 210,422 $ 187,956 $ 165,968
============================================================================================================================
CAPITALIZATION (000'S)
Short-Term Debt $ 32,500 $ 35,000 $ 27,000 $ 36,000 $ 15,000 $ 28,500
Long-Term Debt 274,221 288,075 116,367 119,126 100,685 81,515
Redeemable Preferred Stock 10,670 12,070 13,740 15,168 15,102 15,068
Preferred Stock 4,734 4,734 4,734 4,734 4,734 4,734
Common Equity 108,321 103,192 105,658 93,944 82,230 79,797
- ----------------------------------------------------------------------------------------------------------------------------
Total $ 430,446 $ 443,071 $ 267,499 $ 268,972 $ 217,751 $ 209,614
============================================================================================================================
CAPITAL STRUCTURE RATIOS (%)
Short-Term Debt 7.5% 7.9% 10.1% 13.4% 6.9% 13.6%
Long-Term Debt 63.7% 65.0% 43.5% 44.3% 46.2% 38.9%
Preferred Stock 3.6% 3.8% 6.9% 7.4% 9.1% 9.4%
Common Stock 25.2% 23.3% 39.5% 34.9% 37.8% 38.1%
- ----------------------------------------------------------------------------------------------------------------------------
Total 100.0% 100.0% 100.0% 100.0% 100.0% 100.0%
============================================================================================================================
MISCELLANEOUS STATISTICS
Shares Outstanding (Average) 7,336,174 7,264,360 6,947,746 5,862,411 5,393,306 4,947,232
Shares Outstanding (Year End) 7,363,424 7,301,557 7,185,143 6,225,394 5,420,955 5,370,684
Number of Stockholders (Year End) 7,734 8,250 7,705 7,511 7,325 7,116
Earnings per Common Share $ 1.33 $ 0.36 $ 0.84 $ 0.63 * $ 1.60 $ 1.33
Dividends Declared per Common Share $ 0.72 $ 0.87 $ 1.32 $ 1.32 $ 1.32 $ 1.29
Book Value per Common Share $ 14.71 $ 14.13 $ 14.71 $ 15.09 $ 15.17 $ 14.86
Return on Common Equity 9.09% 2.51% 5.55% 3.99%* 10.60% 8.81%
Ratio of AFDC to Common Stock Earnings 12% 48% 45% 143%* 28% 29%
Ratio of Earnings to Fixed Charges 1.50 1.14 1.49 1.04 * 1.96 1.65
Payout Ratio 54% 242% 157% 210%* 82.5 97.0 %
Percentage of Construction Expenditures
Funded Internally 100% 100% 86% 72% 70% 37%%
============================================================================================================================
RESIDENTIAL CUSTOMER DATA
Average Number of Customers 88,100 86,194 85,041 84,211 83,305 82,568
Kilowatt-Hours per Customer 6,090 5,953 6,073 6,118 6,265 6,265
Revenue per Customer $ 758.29 $ 766.42 $ 752.67 $ 762.89 $ 797.42 $ 708.63
Revenue per Kilowatt-Hour in cents 12.45 12.88 12.39 12.47 12.73 11.31
============================================================================================================================
MISCELLANEOUS SYSTEM DATA
Net System Capability at Time of Peak
(MW) Firm 373.04 330.01 340.45 341.17 342.39 337.29
System Peak Demand (MW) (Winter Peak) 274.32 267.98 275.84 267.42 253.27 264.17
Reserve Margin at Time of Peak 36.0% 23.2% 23.4% 27.6% 35.2% 27.7%
System Load Factor 77.0% 79.9% 73.5% 76.4% 77.2% 73.0%
============================================================================================================================
* Includes the reserve established on certain licensing activites in 1993 ($5.6 million after taxes or $.95 per common
share). (See note 6).
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL
CONDITION
RECENT DEVELOPMENT FOR THE COMPANY AND IN THE ELECTRIC UTILITY INDUSTRY AND
POTENTIAL EFFECTS ON FUTURE SALES, EARNINGS AND DIVIDEND POLICY
"Restructuring" the Industry - The electric utility industry in the United
States is undergoing fundamental change. Electric utilities have for many
years been vertically-integrated entities combining the responsibility for
the provision of power supply and the delivery and sale of it as a legal
monopoly in a franchise territory. In return for monopoly status, electric
utilities have been subject to comprehensive regulation at the state and
federal level. From the perspective of common equity investors, the industry
has been viewed as relatively stable and of relatively low risk. Stockholders
have had a general expectation of returns consistent with the level of profit
allowed by regulation, a relatively high level of dividend payout, and
moderate growth in both dividends and market value. Now, the industry is
going through a process aimed at introducing competition wherever possible.
Generally, this involves splitting apart the generation and sale of power
from the rest of the business, and having generators compete with one another
for the sale of power directly to retail customers. The interconnected
regional grid would be operated independently, continuing as a
federally-regulated monopoly. Local transmission and distribution facilities
would continue as state-regulated monopolies. Competitors for the sale of
power and the retail customers to whom the power would be sold would each
have open and nondiscriminatory access to the necessary monopoly transmission
and distribution facilities.
This change in the industry is in various stages of development around the
United States. The impact on common equity investors is uncertain, but it is
likely that the historical perception of the nature of the investment will
change as the risks and rewards of the restructured industry are better
understood. In the interim, market values of the shares of investor-owned
electric utilities around the country are likely to reflect the perceptions
of investors as to how the various electric utilities are positioned for
success in a changed business environment. For example, many utilities are
burdened with high costs that have been incurred under the present system of
regulation with the expectation that regulation would ensure the recovery of
these costs. With the implementation of competition, such costs could become
"stranded", or uncollectible because customers would not voluntarily choose
to pay them, absent some form of enforceable cost recovery mechanism.
Uncertainty as to the outcome of this issue could be expected to have an
adverse impact on the market value of common equity shares of such high-cost
electric utilities.
The Company has a relatively high "stranded cost" potential. These costs are
largely the result of public policies of the 1980s that required utilities to
enter into long-term contracts for the purchase of power from "non-utility
generators" at contract prices that have turned out to be substantially
higher than the current cost of power from other sources. For the Company,
the most burdensome of these contracts involved three biomass-fueled plants
in the 15-25 megawatt (MW) size range which are now terminated pursuant to
buy-out arrangements described elsewhere, and a 21 MW waste-to-energy plant
owned and operated by the Penobscot Energy Recovery Company (PERC)(see Impact
on the Company and the Company's Response to Financial Pressures). The
Company's stranded cost potential also includes the remaining unrecovered
cost of its abandoned investment in the Seabrook nuclear power project and
other so-called "regulatory assets" (see Notes 8 and 11 to the Company's
Consolidated Financial Statements). In the aggregate, the Company's stranded
cost potential amounts to substantially more than the Company's common equity
capital (see Liquidity, Capital Requirements, and Capital Resources).
At the regional level, activities are currently in progress to alter the
long-standing interrelations among utilities to accommodate competition among
generators and access to an independently-operated transmission grid. The
Company is an active participant in these proceedings. The Company has for
several years been primarily a purchaser of the power necessary to serve its
customers (rather than an owner and operator of generating plants), and has
long recognized the importance of a competitive power supply market and open
access to the transmission grid.
In Maine, the Legislature is considering the manner in which the
restructuring of the electric utilities subject to its jurisdiction should
take place. In 1995, the Legislature instructed the Maine Public Utilities
Commission (MPUC) to submit a suggested plan for the implementation of retail
competition by the year 2000. That plan was presented at the end of 1996, and
implementation legislation is currently being debated. The MPUC's plan would
require that Maine's "largest utilities" (which means just the Company and
the larger adjoining utility, Central Maine Power Company) transfer their
generation assets to an entity distinct from the transmission and
distribution function by January 2000 (which is the time retail competition
would begin), and then totally divest such assets by January 2006. (The
Company's interest in the Maine Yankee Atomic Power Company nuclear
generating plant (Maine Yankee) would be exempt from this requirement due to
the probable complexity involved in divesting an asset of this nature and the
fact that Maine Yankee's operating license expires in 2008.) Existing power
purchase obligations with non-utility generators would remain with the
transmission and distribution monopoly entities, but the rights to power
under these contracts (and the rights to power from Maine Yankee) would be
sold to entities engaged in the competitive generation business. The result
would be that the remaining transmission and distribution entities would no
longer retain any power supplies, although they would continue to be
responsible for the existing contractual obligations.
The MPUC's plan recommends that the remaining transmission and distribution
companies have "a reasonable opportunity to recover legitimate, verifiable
and unmitigatable costs stranded as a result of retail access." It would
require that utilities take aggressive measures to mitigate such costs. The
intent would be to recover these costs through a non-bypassable charge for
the use of the transmission and distribution facilities. Costs for other
social programs, such as incentives for conservation, environmental
initiatives, and low income protection, would also be recovered in this
manner.
The single aspect of the MPUC's suggested plan that is of most concern to the
Company is that it would prohibit the transmission and distribution company
from marketing and retailing electricity. The Company believes that its
customers would have a greater opportunity to benefit from retail competition
if the Company were permitted to remain in the marketing and retailing aspect
of the business. Moreover, marketing and retailing have been central to the
Company's strategy in recent years. Under regulation, the Company's rates
rose rapidly in the late 1980s and early 1990s, due primarily to the
obligations to the non-utility generators and other public policy mandates.
Due to competitive pressures and public resistance to more rate increases, in
1994 the Company embarked on a strategy of avoiding rate increases by
aggressively reducing costs and increasing sales. Cost reductions have come
about by downsizing and otherwise managing budgets, and in particular by
negotiating buy-outs of high-cost non-utility generator contracts (see Impact
on the Company and the Company's Response to Financial Pressures).
Increasing sales is an effective strategy because, although rates designed by
regulation to recover embedded costs are relatively high, the marginal cost
of servicing additional sales is relatively low. Prices aimed at incenting
such additional sales can return a profit above marginal cost and still
compete favorably with customers' alternative choices. The same pricing
strategy can be applied to prevent the loss of sales when traditional rates
based on embedded cost recovery are uncompetitive with customers'
alternatives. The Company believes that, given the inherent benefits of
electricity and the likelihood that it can compete profitably at prices based
on marginal cost, a strategy based on increasing sales in a competitive
environment is more likely to result in long-term financial success than a
strategy limited to cost recovery in a regulated environment. To enable this
strategy, in 1994 the Company sought regulatory approval to engage in
flexible pricing in the form of an Alternative Marketing Plan (AMP), which
was approved by the MPUC in early 1995. AMP also included a voluntary
commitment by the Company to avoid traditional rate increases to the extent
possible.
Thus, the Company has been foregoing the possibility of short-term returns
that might have been achieved if the Company had pursued, and had been
awarded, more rate increases. Instead, the Company's strategy has been aimed
at succeeding for the long term in a competitive environment. But, by
prohibiting transmission and distribution companies from engaging in
retailing and marketing, the MPUC's plan poses an impediment to the Company's
ability to continue with its strategy. The Company is vigorously pursuing
this matter in the legislative debate and cannot now predict what action, if
any, the Legislature will take on this issue or on the entire matter of
industry restructuring.
Elimination of "Fuel Cost Adjustment" - Concurrent with the approval of AMP,
the fuel cost adjustment ended. The fuel cost adjustment was a method whereby
the cost of fuel used to generate electricity and certain purchased power
costs were recovered essentially dollar-for-dollar by a periodically
reconciled charge to customers. The mechanism was developed in the late 1960s
as a way to avoid frequent rate proceedings and protect the financial
integrity of utilities when the cost of fuel used to generate electricity was
subject to wide and unpredictable fluctuations that were beyond the control
of the utilities to manage. This rationale for such cost recovery mechanisms
has now substantially lessened, with the advent of more predictable fuel
costs and the availability of other methods of managing risk. For the
Company, the fuel cost adjustment covered the cost of fuel for generation,
the variable cost of most purchased power, and the entire cost of the
contracts with the non-utility generators. Thus, the rates to recover these
costs became part of the Company's overall rates as of the beginning of 1995,
and thereafter would be subject to change only in connection with an overall
rate adjustment proceeding. The adverse financial impact of Maine Yankee's
unavailability (see Maine Yankee below) would have been substantially reduced
if the fuel cost adjustment mechanism had not been eliminated.
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
the fuel cost adjustment. 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", in which
the Company agrees 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 have occurred on a monthly basis and the cash receipts arising
from the "swap" transactions, amounting to approximately $3.6 million in
1996, offset the corresponding increases in the Company's purchased energy
costs in 1996. As a result, the Company is managing 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. See also Note 14 to the
Consolidated Financial Statements. The Company is also exploring ways to
manage other risks that were formerly mitigated by the fuel cost adjustment,
such as the cost of replacement power when Maine Yankee is unavailable, but
no acceptable method has yet been devised.
Maine Yankee - The Company owns 7% of the common stock of Maine Yankee, which
owns and operates an 880 MW nuclear generating plant in Wiscasset, Maine. The
Company's equity investment in Maine Yankee is approximately $5 million.
Under a cost-based power contract, the Company is entitled to about 7% of the
output of the plant.
Following a yearlong shutdown for repairs to the steam generators in 1995,
Maine Yankee has come under intense regulatory scrutiny in a series of events
beginning in December 1995 with an anonymous letter about an allegedly faulty
computer program. The events have evolved into a number of investigations by
Maine Yankee's primary licensing authority, the United States Nuclear
Regulatory Commission (NRC) and by Maine Yankee itself. Concerns have
included compliance with NRC regulations, conformance of the plant to design
specifications, adequacy and condition of components and systems, and
management issues. Many of these concerns remain unresolved. During the
evolution of these events, the NRC itself has been subject to public
criticism about the adequacy of its regulatory activities and its
relationship with nuclear plant licensees, and in response the NRC has been
implementing changes in its approach to oversight of licensees that are
having the effect of amplifying the regulatory scrutiny. Civil enforcement
proceedings have been initiated by the NRC to impose monetary penalties on
Maine Yankee for alleged violations of regulations. The NRC has also referred
certain issues to the United States Department of Justice for further
investigation, which could result in further civil or criminal proceedings.
The Company cannot predict the outcome of these investigations and
proceedings.
Maine Yankee operated for part of 1996, but under a restriction imposed by
the NRC that limited its operation to 90% of full power capacity pending the
resolution of various issues (which are not yet resolved). The plant has been
off-line since early December 1996 when it was shut down to address
cable-separation and associated issues. Since then, Maine Yankee also
determined that a substantial portion of the nuclear fuel in the reactor was
defective and had to be replaced, thereby extending the shutdown into a
refueling outage. During the refueling outage, Maine Yankee is continuing to
attempt to resolve the other issues that led to the current shutdown, and
will inspect the steam generators for degradation beyond that which was the
subject of the 1995 repair. Such degradation has been identified at other
plants of similar age and design as Maine Yankee. Satisfactory condition of
the steam generators is a significant factor in the plant's continued
operation.
Management changes are taking place at Maine Yankee. Maine Yankee's chief
executive officer resigned in late 1996, and a management team from a firm
experienced in nuclear generating plant operations has been retained.
The Company cannot predict how long Maine Yankee will remain out of service.
The Company has been incurring replacement power costs of approximately $1
million per month while the plant has been out of service, and expects such
costs to continue at the same rate until the plant returns to service. The
market price for replacement power is being driven up somewhat because other
nuclear power plants in New England are also indefinitely shut down. In
addition to the replacement power costs, the Company is responsible for 7% of
whatever additional costs are necessary to return Maine Yankee to service. In
December 1996 the Maine Yankee board of directors approved about $30 million
in additional operating and maintenance costs for 1997 (in addition to
incremental capital costs), and, while revised budgets have not been
approved, these costs are now likely to be greater.
Impact on the Company and the Company's Response to Financial Pressures - The
increasingly competitive environment in the electric utility industry and,
more recently, the deteriorating performance of Maine Yankee has placed the
Company under significant financial pressure. In recent years, the Company
has undertaken a number of initiatives to reduce the level of its costs.
Through aggressive programs encouraging early retirement and severance, the
Company has reduced its full-time work force since 1992 by approximately 22%.
Operation and maintenance budgets have been held to a minimum consistent with
reasonable levels of service and reliability, and the levels of the Company's
ongoing capital expenditures have been significantly reduced.
In 1993, the Company bought out a contract for the purchase of power from the
Beaver Wood Joint Venture (Beaver Wood), the owner of a 15 MW biomass-fueled
non-utility generator located in Chester, Maine. In return for the
cancellation of the contract, the Company paid Beaver Wood $24 million in
cash and issued a new series of First Mortgage Bonds to the holders of Beaver
Wood's debt in the amount of $14.3 million. In 1995, the Company bought out
two additional power purchase contracts from identical 22.5 MW biomass-fueled
non-utility generators located in West Enfield and Jonesboro, Maine. The
buyout cost was approximately $170 million, including transaction costs. The
cost of those buyouts was financed entirely by new debt instruments, thereby
significantly increasing the Company's indebtedness. These buyouts have
resulted in significant savings in purchased power costs, and the Company
believes such savings will continue over the long term. The increased debt
component of the Company's financial structure has added to the Company's
overall risk.
As the Company's earnings have declined, the Board of Directors has continued
to review the Company's dividend policies. In June of 1995, the Board reduced
the quarterly dividend on common stock by $.15 from $.33 per share to $.18
per share, resulting in a reduction in the indicated annual rate from $1.32
to $.72. At the time, the Company announced that the reduction had been
occasioned by continued pressure on earnings and the necessity to avoid
further rate increases and that based on then current financial projections,
the Company believed it could sustain that level of dividend over the long
term. As a result of the financial impact of the Maine Yankee outage and the
cost of the early retirement and involuntary severance plan implemented in
1995, the Company's common dividends were not covered by earnings in 1995,
even after taking into consideration the dividend reduction.
Although Maine Yankee operated better in 1996 than it did in 1995, it still
operated at a much lower level than had been projected, and the Company's
1996 earnings were significantly affected by that performance. The Plant has
now been off-line since early December 1996, and the Company cannot predict
how long it will remain out of service. The last several years of strained
financial operations combined with continuing uncertainty has placed the
Company in the position of having to conserve its cash resources. In
addition, it is increasingly likely in the near future that the Company will
be in violation of one or more of the financial covenants included in the
agreements with its various lenders, including a prohibition against the
payment of dividends that exceed 70% of earnings in any calendar year.
Accordingly, at its March 19, 1997 meeting, the Board of Directors determined
that the payment of common stock dividends should be suspended, and
accordingly did not declare the regular quarterly common stock dividend.
In recognition of the financial constraints that have been caused in large
part by the unanticipated problems at Maine Yankee, the Company is focusing
on two major initiatives. The last remaining high-priced non-utility
generator contract that offers a potential for substantial savings is the
Company's contract to purchase energy from PERC. PERC owns a waste-to-energy
facility in Orrington, Maine that provides solid waste disposal services to
many communities in central, eastern and northern Maine. The contract
requires the Company to purchase the electricity output of the plant until
2018 at a price that is presently substantially above the cost of alternative
sources of power, and, in the Company's opinion, is likely to remain so. The
Company has been working with PERC and the affected municipalities at a
restructuring of the power contract that would result in substantial savings
for the Company and would continue to allow PERC to meet the solid waste
disposal needs of Maine communities. As of this writing, the interested
parties appear to have arrived at a satisfactory agreement to restructure the
contract that would include: 1) an initial payment by the Company to PERC of
$8 million; 2) an additional annual payment by the Company to PERC of up to
$500,000 for four years contingent upon specified levels of profitability for
the PERC plant; 3) an annual rebate to the Company based upon a formula tied
to the profitability of the PERC plant; 4) a refinancing by PERC to extend
the term of the existing tax-exempt debt; and 5) a guarantee of that debt by
the Finance Authority of Maine (FAME). While there are a number of obstacles
to the completion of the restructuring, the Company estimates that if it is
successfully completed, the net present value of the savings from current
contract costs will be $30-35 million over the remaining life of the
contract.
The other major initiative designed to improve the Company's financial
outlook is the recent decision to apply to the MPUC for an increase in rates.
On March 3, 1997, the Company filed its notice of intent to file a general
rate increase request, and the Company anticipates that this will result in
some level of rate increase to take effect in early 1998. While the decision
to increase rates runs counter to the strategies articulated by the Company
in recent years, the Company will attempt to hold those increases to a
minimum while providing a level of financial relief that will restore the
Company's position to acceptable levels.
Proposed Gas Pipeline Project - On September 23, 1996, Maritimes & Northeast
Pipeline, L.L.C. (Maritimes) filed an application with the Federal Energy
Regulatory Commission (FERC) seeking authority under the Natural Gas Act to
construct, install, own, operate and maintain certain new natural gas
pipeline, compression and ancillary facilities in the State of Maine. The
facilities for which authorization is sought comprise a portion of a proposed
new high pressure natural gas pipeline system to transport gas in
international commerce from Sable Island, Nova Scotia, Canada through New
Brunswick, Maine, New Hampshire and into Massachusetts. As part of its
system, Maritimes has proposed constructing lateral pipelines that would make
significant quantities of natural gas available to industrial customers of
the Company. On November 4, 1996, the Company filed with the FERC a motion to
intervene in the Maritimes proceeding and requested that the FERC impose
certain conditions on any certification of the proposed pipeline system.
Specifically, the Company noted that if a customer were to use natural gas as
a substitute energy source for its current usage of electrical energy, the
Company and its remaining customers would be saddled with certain "stranded"
costs that were incurred under traditional regulatory structures providing
monopoly protection in return for the undertaking of an obligation to serve.
The Company asked that if the FERC certifies the Maritimes project, the
authorization should include the requirement that in order for any electric
customer that opts to leave its current electric supplier (in whole or in
part) to receive transmission service from the Maritimes project, it must
agree to pay any stranded costs associated with that departure.
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 or other
agencies, press releases and oral statements. Actual results could potential-
ly 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 1996, 1995 and 1994 as they affect the Company's liquidity. Net cash
provided by operations was $44.8 million in 1996 as compared to a negative
$164.5 million in 1995, the principal difference between the years being the
$197.7 million spent in 1995 for the buyout of purchased power contracts
($168.7 million) and related financing costs ($29.0 million). Exclusive of
the costs of those buyouts, which were entirely debt financed, cash flows
provided by operations were $33.2 million in 1995. Other factors that
contributed to improved cash flows in 1996 were savings in purchased power
costs because of the contract buyouts ($11.2 million), the improved operation
of Maine Yankee in 1996 as compared to 1995, the necessity in 1995 to record
expenses associated with the resleeving of steam generator tubes at Maine
Yankee and $2.4 million in refueling costs incurred in 1995 (a net $8.6
million of improved cash flow associated with Maine Yankee). Offsetting
these cash flow improvements in 1996 were $1.7 million to terminate a
demand-side management contract and $2.0 million in additional income taxes
resulting from an Internal Revenue Service examination of prior tax years and
an increase in the payment of 1996 estimated federal and state income taxes.
Also reducing 1996 cash flow from operations was a $2.9 million deterioration
in accounts receivable and unbilled revenue, as compared to a $.7 million
improvement in 1995.
Over the last three years, capital expenditures have been $18.8 million in
1996, $19.5 million in 1995 and $21.5 million in 1994. In 1996, approximately
$6.7 million of the capital expenditures was related to implementing new
customer, geographic and financial information systems, $.8 million was
related to the Company's power production facilities, $7.6 million was for
its distribution system, and $3.3 million was for its transmission system,
with the remainder related to other general property and equipment and costs
associated with the licensing of hydroelectric projects. In October 1995 the
Company acquired the assets of its largest full-requirements wholesale
customer at a cost of approximately $2.4 million. The Company expects its
capital expenditures to total between $40 million and $50 million over the
next three years, although it may be necessary to adjust the budget for
capital expenditures on a year-to-year basis.
In 1996 the Company repaid $12 million of principal on its outstanding Medium
Term Notes as required by a loan agreement entered into at the time of the
1995 purchased power contract buyouts, and made $1.6 million in sinking fund
payments on its 12.25% first mortgage bonds. In 1996, the Company also made
two sinking fund payments totalling $3 million on its 8.76% mandatory
redeemable preferred stock. As discussed in more detail in the Notes to the
Consolidated Financial Statements, the Company also made approximately
$188,000 in payments to the institutional holder of the 8.76% series
preferred stock related to a "make whole provision" under the preferred stock
purchase agreement. In 1995, the Company made $2.1 million in sinking fund
payment on its 12.25% first mortgage bonds.
In June 1995, the Company reduced its quarterly dividend from $.33 per share
to $.18 per share, thereby improving cash flow by $2.2 million in each of
1996 as compared to 1995 and 1995 compared to 1994. Under the Company's
Dividend Reinvestment and Common Stock Purchase Plan the Company realized a
common stock investment of approximately $668,000 through the issuance of
61,867 new common shares in 1996 as compared to approximately $1.2 million in
1995 through the issue of 116,414 shares.
Capital and operating needs in 1996 and 1995 were met through internally
generated funds and the Company's revolving credit line. Absent the
extraordinary need for additional cash to finance restructuring of a
non-utility generator contract or to meet the incremental costs associated
with continuing difficulties at Maine Yankee, the Company expects to continue
to meet all of its capital needs for the foreseeable future within existing
credit arrangements. Accordingly, the Company does not currently have plans
to issue any new debt or equity securities. However, if Maine Yankee remains
out of service for an extended period of time, it is possible that the
Company would have to seek additional outside sources of funds for operations
and capital expenditures.
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 the transaction. The Company has $112.4
million of first mortgage bond and other long-term debt sinking fund
requirements and maturities in the period 1997-2001. The Company also has
$1.5 million of mandatory annual sinking fund payments and $94,000 of annual
payments under the "make whole provision" on its redeemable preferred stock.
RESULTS OF OPERATIONS
Earnings per common share were $1.33, $.36 and $.84, and the earned return on
average common equity was 9.1%, 2.5% and 5.5% for the years ended 1996,1995
and 1994, respectively. Positively impacting earnings in 1996 was the 1995
buyout of two high cost power purchase contracts from non-utility generating
plants. That transaction has resulted in incremental savings of approximately
$2.4 million or $.32 per common share after income taxes in 1996 as compared
to 1995. Negatively impacting earnings in 1996 and 1995 were the previously
discussed shutdowns of Maine Yankee. The Company charged approximately $2.3
million ($.32 per common share) and $1.7 million ($.24 per common share)
after taxes in 1995 and 1994, respectively, to operations to reflect the cost
of early retirement and severance programs.
The Company's total revenues and consequently its earnings are influenced to
a large extent by the regulation of retail rates by the MPUC. 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 then-applicable
fuel cost adjustment attributable directly to the buyout. The MPUC order
provided an authorized return on common equity of 10.6%. However, the Company
has failed to earn that authorized return in 1996, 1995 and 1994 primarily
because the MPUC order was based upon an overly optimistic projection of
energy sales; because the Company has found it necessary to make certain
pricing concessions to some of its customers as discussed elsewhere; because
of the onetime charge for the early retirement programs in 1995 and 1994; and
because of the impact of the Maine Yankee shutdowns in 1996 and 1995.
Electric operating revenue increased by $2.5 million, or 1.3%, in 1996 as
compared to 1995 due principally to a $4.3 million increase in off-system
sales (sales related to power pool and interconnection agreements and resales
of purchased power). This increase was somewhat offset by the impact of a
1.33% decrease in retail kilowatt-hour (KWH) electricity sales in 1996 and
the effect of selective price reductions to meet competitive pressures. The
KWH sales decrease was caused primarily by drastically reduced sales to one
of the Company's largest special contract customers from which the Company
receives a relatively low profit margin. Without the impact of the reduced
sales to this customer, total KWH sales were 1.7% higher in 1996 than in
1995.
Electric operating revenue increased by $10.8 million in 1995 compared to
1994, or 6.2%, reflecting both a base rate increase that took effect in March
1994 and a 4.4% increase in KWH sales. The majority of the KWH sales increase
was attributable to special contracts with three large industrial customers.
Absent the increased sales under those special contracts, KWH sales would
have been at roughly the same level in 1995 as in 1994. Revenue from
off-system sales increased by $1.4 million as well.
Prior to the elimination of the fuel cost adjustment effective January 1,
1995, the MPUC had authorized the Company to use a deferred fuel accounting
methodology under which fuel revenue essentially matched fuel expense.
Effective January 1, 1995, deferred fuel accounting was eliminated. This
change requires the Company to record, as expense, actual fuel costs
incurred. The deferred fuel revenue balance at December 31, 1994 of $3.0
million, is being amortized over a three-year period beginning January 1,
1995 as a reduction in fuel for generation and purchased power expense and is
a benefit to earnings.
The significant decrease in fuel for generation and purchased power expense
in 1996 is related principally to the buyout of the high cost purchased power
contracts in June 1995 ($18 million reduction in expense in 1996) and the
improved performance of Maine Yankee in 1996. The incremental replacement
power costs for Maine Yankee were $4.3 million in 1996, compared to $10.5
million in replacement power and steam tube resleeving project expenses in
1995. Offsetting these decreases was a $4.3 million increase in off-system
sales in 1996. The decrease in expense in 1995 compared to 1994 was also
significantly affected by the purchased power contracts buyout ($13.5 million
reduction in expense in 1995), offset by costs incurred during the Maine
Yankee outage in 1995.
Other operation & maintenance (O&M) expense decreased by $3.3 million in 1996
from 1995 levels, principally because of the charges for the 1995 early
retirement and severance program ($3.9 million charge to other O&M in 1995).
Bad debt expense was $.8 million lower in 1996 due to the $.7 million
increase in the reserve for uncollectible accounts in 1995 and a reduction in
bad debt write-offs in 1996. O&M payroll expense decreased in 1996 by $.9
million principally as a result of the early retirement and severance
program. These decreases were offset to some extent by a $.7 million increase
in active employee medical expenses and postretirement pension, medical and
life insurance benefit costs in 1996. Additionally, in 1996 the Company
recorded $.3 million in expense related to the first year of amortization of
deferred demand-side management contract termination costs. Finally, in 1996
the Company incurred $.4 million in additional demand-side management
expenses with one of its principal third party vendors.
Other O&M expense increased by $2.2 million in 1995 over 1994 levels
primarily because the charges for an early retirement and severance program
in 1995 exceeded those for a 1994 early retirement program and because of a
$1.7 million increase in bad debt expense. Offsetting those increases was a
$1.4 million decrease in O&M payroll expense due principally a reduction in
the number of employees and greater levels of capital labor in 1995.
The increases in depreciation and amortization expense in 1996 and in 1995
were caused mainly by the growth in the Company's electric plant in service.
A study conducted in 1989 by an independent firm determined that the reserve
for depreciation was over-accumulated. An agreement on base rates with the
MPUC, effective October 1, 1990, contained a provision to amortize the
remaining balance of the over-accumulated reserve for depreciation account
($11.4 million on October 1, 1990) over a six-year period. This amortization,
which has reduced the Company's depreciation expense by approximately $1.8
million per year over the six-year period, ended on December 31, 1996.
The Company's expenses over the period 1994-1996 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 electric 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 abandoned investment in the Seabrook nuclear power units 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 buy-
back were deferred and recorded as a regulatory asset, to be amortized and
collected over a ten-year period, beginning July 1, 1995. Amortization
expense related to this contract buyout amounted to $17.0 million in 1996 as
compared to $8.4 million in 1995.
Federal and state income tax expense increased in 1996 due principally to
increased earnings, offset by the utilization of $947,000 in federal and
state investment tax credits (ITC). The decrease in 1995 as compared to 1994
was due to a decrease in earnings, as well as greater amortization of
deferred ITC amounting to $498,000 in 1995.
Allowance for funds used during construction (AFDC) decreased in 1996 as
compared to 1995 due to the discontinuance of recording AFDC on the Company's
hydro relicensing costs in March of 1995. AFDC in 1995 as compared to 1994
decreased principally 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 1995.
In 1996 increase in other income was due principally to $1.4 million of
interest income earned on the $21 million capital reserve fund set aside in
connection with the June 30, 1995 purchased power contracts buyback financing
with FAME.
Long-term debt interest expense increased by $6.1 million in the 1996 period
as compared to 1995 due to the borrowings to finance the purchased power
contract buyouts. The increase was offset to some extent by the impact of
$12 million in debt repayments on the Company's Medium Term Notes in June
1996 and sinking fund payments on the Company's 12.25% first mortgage bonds.
The increase in long-term debt interest expense in 1995 as compared to 1994
was also due to the additional borrowings.
Other interest expense in 1996 increased due primarily to the amortization of
issuance costs incurred in connection with financing the 1995 purchased power
contracts buyout. Other interest expense increased in 1995 as a result of
higher levels of borrowings under the revolving credit facility, as well as
an increase in short-term interest rates in 1995 as compared to 1994.
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 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 those 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 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
Department of Environmental Protection as an Uncontrolled Hazardous Substance
Site, the Company was informed that it is considered a de minimis generator.
ITEM 8 - FINANCIAL STATEMENTS & SUPPLEMENTARY DATA
BANGOR HYDRO-ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF INCOME
For the Years Ended December 31,
1996 1995 1994
ELECTRIC OPERATING REVENUE (Note 1): $187,373,630 $ 184,913,771 $ 174,097,860
-----------------------------------------
OPERATING EXPENSES:
Fuel for generation and purchased
power (Notes 1 and 14) $ 78,476,864 $ 98,683,991 $ 104,132,439
Other operation and maintenance
(Notes 1 and 5) 32,440,649 35,711,185 33,497,912
Depreciation and amortization
(Note 1) 7,429,719 6,522,019 5,395,045
Amortization of Seabrook Nuclear
Project (Note 8) 1,699,050 1,699,050 1,699,050
Amortization of contract buyouts
(Note 6) 20,836,561 12,322,570 3,238,630
Taxes -
Local property and other 5,367,045 4,884,565 5,189,324
Income (Note 2) 4,882,453 1,421,674 3,613,598
-----------------------------------------
$151,132,341 $ 161,245,054 $ 156,765,998
-----------------------------------------
OPERATING INCOME $ 36,241,289 $ 23,668,717 $ 17,331,862
OTHER INCOME AND (DEDUCTIONS):
Allowance for equity funds used
during construction (Note 1) 368,056 561,898 1,256,307
Other, net of applicable income taxes
(Notes 1 and 2) 1,097,931 197,924 51,850
-----------------------------------------
INCOME BEFORE INTEREST EXPENSE $ 37,707,276 $ 24,428,539 $ 18,640,019
-----------------------------------------
INTEREST EXPENSE:
Long-term debt (Note 4) $ 23,651,316 $ 17,596,586 $ 10,767,934
Other (Note 4) 3,529,002 3,201,030 1,754,391
Allowance for borrowed funds used
during construction (Note 1) (755,708) (705,552) (1,339,379)
-----------------------------------------
$ 26,424,610 $ 20,092,064 $ 11,182,946
-----------------------------------------
NET INCOME $ 11,282,666 $ 4,336,475 $ 7,457,073
DIVIDENDS ON PREFERRED STOCK (Note 3) 1,537,202 1,701,960 1,652,432
-----------------------------------------
EARNINGS APPLICABLE TO COMMON STOCK $ 9,745,464 $ 2,634,515 $ 5,804,641
=========================================
EARNINGS PER COMMON SHARE, based on the
weighted average number of shares
outstanding of 7,336,174 in 1996,
7,264,360 in 1995 and 6,947,746
in 1994 $ 1.33 0.36 0.84
=========================================
DIVIDENDS DECLARED PER COMMON SHARE $ 0.72 0.87 1.32
=========================================
The accompanying notes are an integral part of these consolidated
financial statements.
BANGOR HYDRO-ELECTRIC COMPANY
CONSOLIDATED BALANCE SHEETS
December 31,
1996 1995
ASSETS
INVESTMENT IN UTILITY PLANT:
Electric plant in service, at original
cost (Notes 4 and 6) $317,832,993 $ 300,374,078
Less - Accumulated depreciation and
amortization (Notes 1 and 6) 87,736,285 81,933,769
---------------------------
$230,096,708 $ 218,440,309
Construction work in progress (Note 1) 18,554,154 18,151,265
---------------------------
$248,650,862 $ 236,591,574
Investments in corporate joint ventures (Notes 1
and 6) -
Maine Yankee Atomic Power Company $ 5,013,781 $ 5,013,781
Maine Electric Power Company, Inc. 124,900 124,900
---------------------------
$253,789,543 $ 241,730,255
---------------------------
OTHER INVESTMENTS, principally at cost (Note 6) $ 4,812,895 $ 4,184,626
---------------------------
FUNDS HELD BY TRUSTEE at cost (Notes 4 and 10) $ 21,199,004 21,191,940
---------------------------
CURRENT ASSETS:
Cash and cash equivalents (Notes 1 and 10) $ 1,274,386 $ 1,424,266
Accounts receivable, net of reserve ($1,450,000
in 1996 and 1995) 20,691,010 18,226,453
Unbilled revenue receivable (Note 1) 9,229,777 8,821,440
Inventories, at average cost:
Materials and supplies 2,993,910 3,028,911
Fuel oil 302,851 105,871
Prepaid expenses 1,671,964 1,737,507
Deferred Maine Yankee refueling costs (Note 1 & 11) 895,798 2,418,658
---------------------------
Total current assets $ 37,059,696 $ 35,763,106
---------------------------
DEFERRED CHARGES:
Investment in Seabrook Nuclear Project, net of
accumulated amortization of $26,775,096 in 1996
and $25,076,046 in 1995 (Notes 8 and 11) $ 32,066,979 $ 33,766,029
Costs to terminate purchased power contracts, net
of accumulated amortization of $36,397,761 in
1996 and $15,561,200 in 1995 (Notes 6 and 11) 171,703,691 192,140,252
Deferred regulatory assets (Notes 2, 5 and 11) 29,498,630 30,328,451
Demand-side management costs (Note 11) 2,631,880 1,945,944
Other (Note 11) 3,867,087 5,025,887
---------------------------
Total deferred charges $239,768,267 $ 263,206,563
---------------------------
Total Assets $556,629,405 $ 566,076,490
===========================
The accompanying notes are an integral part of these consolidated
financial statements.
BANGOR HYDRO-ELECTRIC COMPANY
CONSOLIDATED BALANCE SHEETS
December 31,
1996 1995
STOCKHOLDERS' INVESTMENT AND LIABILITIES
CAPITALIZATION (see accompanying statement):
Common stock investment (Note 3) $108,321,066 $103,191,680
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) 10,670,171 12,070,003
Long-term debt, net of current portion
(Notes 4, 10 and 14) 274,221,451 288,074,966
---------------------------
Total capitalization $397,946,688 $408,070,649
---------------------------
CURRENT LIABILITIES:
Notes payable - banks (Note 4) $ 32,500,000 $ 35,000,000
---------------------------
Other current liabilities -
Current portion of long-term debt and sinking
fund requirements on preferred stock
(Notes 3, 4 and 10) $ 15,447,429 $ 16,938,615
Accounts payable 13,432,594 10,526,642
Dividends payable 1,687,495 1,709,209
Accrued interest 3,719,387 4,907,820
Deferred fuel revenue (Notes 1 and 11) 1,008,402 2,016,798
Customers' deposits 359,974 348,676
---------------------------
Total other current liabilities $ 35,655,281 $ 36,447,760
---------------------------
Total current liabilities $ 68,155,281 $ 71,447,760
---------------------------
COMMITMENTS AND CONTINGENCIES (Notes 6, 9 and 14)
DEFERRED CREDITS AND RESERVES (Note 2):
Deferred income taxes - Seabrook $ 16,651,386 $ 17,546,355
Other accumulated deferred income taxes 54,805,629 50,775,034
Deferred regulatory liability (Note 11) 8,445,642 8,567,904
Unamortized investment tax credits 2,178,588 2,354,052
Accrued pension (Note 5) 640,328 626,249
Other (Note 5) 7,805,863 6,688,487
---------------------------
Total deferred credits and reserves $ 90,527,436 $ 86,558,081
---------------------------
Total Stockholders' Investment and Liabilities $556,629,405 $566,076,490
===========================
The accompanying notes are an integral part of these consolidated
financial statements.
BANGOR HYDRO-ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF CAPITALIZATION
December 31,
1996 1995
Common Stock Investment (Notes 1 and 3):
Common stock, par value $5 per share-
Authorized -- 10,000,000 shares
Outstanding -- 7,363,424 shares in 1996 and
7,301,557 shares in 1995 $ 36,817,120 $ 36,507,785
Amounts paid in excess of par value 56,969,428 56,610,548
Retained earnings 14,534,518 10,073,347
- --------------------------------------------------------------------------------
Total Common Stock $108,321,066 $ 103,191,680
- --------------------------------------------------------------------------------
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 $104.38% if called on or
prior to December 27, 1997, 150,000
shares authorized and 120,000 shares
outstanding in 1996 and 150,000 out-
standing in 1995 $ 12,264,085 $ 15,362,881
Less-Sinking fund requirements 1,593,914 3,292,878
- --------------------------------------------------------------------------------
$ 10,670,171 $ 12,070,003
- --------------------------------------------------------------------------------
LONG-TERM DEBT (Notes 4, 10 and 14):
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 7,374,966 9,020,703
- --------------------------------------------------------------------------------
$109,874,966 $ 111,520,703
Less-Sinking fund requirements 1,853,515 1,645,737
- --------------------------------------------------------------------------------
$108,021,451 $ 109,874,966
- --------------------------------------------------------------------------------
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 $ 126,000,000
- --------------------------------------------------------------------------------
Medium Term Notes, Variable interest rate-
LIBO rate plus 2%, due 2000 $ 48,000,000 $ 60,000,000
Less: Current portion of long-term debt 12,000,000 12,000,000
- --------------------------------------------------------------------------------
$ 36,000,000 $ 48,000,000
- --------------------------------------------------------------------------------
Total long-term debt $274,221,451 $ 288,074,966
- --------------------------------------------------------------------------------
Total Capitalization $397,946,688 $ 408,070,649
================================================================================
The accompanying notes are an integral part of these consolidated
financial statements.
Bangor Hydro-Electric Company
CONSOLIDATED STATEMENT OF CASH FLOWS
For the Years Ending December 31,
1995 1995 1994
Cash Flows From Operations:
Net Income $ 11,282,666 $ 4,336,475 $ 7,457,073
Adjustments to reconcile net income to net cash
provided by (used in) operations:
Costs to terminate purchased power contracts
(Note 6) - (197,717,853) -
Depreciation and amortization 7,429,719 6,522,019 5,395,045
Amortization of Seabrook Nuclear Project (Note 8) 1,699,050 1,699,050 1,699,050
Amortization of costs to terminate purchased
power contracts (Note 6) 20,836,561 12,322,570 3,238,630
Other amortizations 2,000,150 1,440,501 1,209,146
Cost to terminate demand-side management contract (1,702,678) - -
Payment received related to terminated purchased
power contract (Note 6) 1,000,000 1,000,000 1,000,000
Cost of early retirement and involunary severance
plans - 3,835,303 2,738,376
Allowance for equity funds used during
construction (Note 1) (368,056) (561,898) (1,256,307)
Deferred income tax provision (Note 2) 4,495,490 1,791,082 2,250,851
Deferred investment tax credits, net (Note 2) (175,464) (61,193) 143,695
Changes in assets and liabilities:
Deferred fuel revenue and Maine Yankee refueling
costs (Note 1) 514,464 (3,191,510) 7,153,733
Accounts receivable, net and unbilled revenue (2,872,894) 693,496 (1,816,459)
Accounts payable 2,905,952 (4,141,870) (1,292,388)
Accrued interest (1,188,433) 1,257,625 (55,332)
Current and deferred income taxes (722,833) 625,059 (517,084)
Accrued postretirement benefit costs (Note 5) 1,411,000 612,446 591,123
Other current assets and liabilities, net (85,138) 296,938 36,945
Other, net (Note 4) (1,618,007) 4,719,636 1,285,426
- -------------------------------------------------------------------------------------------------------
Net Cash Provided By (Used in) Operations $ 44,841,549 $ (164,522,124)$ 29,261,523
- -------------------------------------------------------------------------------------------------------
Cash Flows From Investing:
Construction expenditures $ (18,816,194)$ (19,459,606)$ (21,482,132)
Allowance for borrowed funds used during construction
(Note 1) (755,708) (705,552) (1,339,379)
- -------------------------------------------------------------------------------------------------------
Net Cash (Used In) Provided By Investing $ ($19,571,902)$ ($20,165,158)$ ($22,821,511)
- -------------------------------------------------------------------------------------------------------
Cash Flows From Financing:
Dividends on preferred stock $ (1,481,020)$ (1,579,570)$ (1,579,570)
Dividends on common stock (5,273,157) (7,375,736) (9,116,617)
Payments on long-term debt (13,645,737) (2,107,705) (2,594,896)
Payments on mandatory redeemable preferred stock (3,187,828) - -
Issuances:
Common stock (Note 3)
Public offering (867,500 shares in 1994) - - 14,083,863
Dividend reinvestment plan (61,867 shares in 1996,
116,414 shares in 1995, and 92,249 shares in 1994) 668,215 1,218,400 1,336,211
Long-term debt (Note 4) - 186,000,000 -
Short-term debt, net (Note 4) (2,500,000) 8,000,000 (9,000,000)
- -------------------------------------------------------------------------------------------------------
Net Cash (Used In) Provided by Financing $ (25,419,527)$ 184,155,389 $ (6,871,009)
- -------------------------------------------------------------------------------------------------------
Net Change in Cash and Cash Equivalents $ (149,880)$ (531,893)$ (430,997)
Cash and Cash Equivalents - Beginning of Year 1,424,266 1,956,159 2,387,156
- -------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents - End of Year $ 1,274,386 $ 1,424,266 $ 1,956,159
- -------------------------------------------------------------------------------------------------------
Supplemental Cash Flow Information:
Cash Paid During The Year For-
Interest (Net of Amount Capitalized) $ 26,650,769 $ 17,906,908 $ 9,677,372
Income Taxes 2,348,363 345,834 2,226,290
=======================================================================================================
The accompanying notes are an integral part of these consolidated financial statements.
BANGOR HYDRO-ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
For the Years Ended December 31,
1996 1995 1994
BALANCE AT BEGINNING OF YEAR $10,073,347 $13,757,751 $17,386,444
ADD - Net income 11,282,666 4,336,475 7,457,073
------------------------------------
$21,356,013 $18,094,226 $24,843,517
------------------------------------
DEDUCT:
Cash dividends declared on -
Preferred stock $ 1,448,170 $ 1,579,570 $ 1,579,570
Common stock - $.72 per share in 1996,
$.87 per share in 1995 and $1.32 per
share in 1994 5,284,293 6,318,919 9,433,334
Other (Note 3) 89,032 122,390 72,862
------------------------------------
$ 6,821,495 $ 8,020,879 $11,085,766
------------------------------------
BALANCE AT END OF YEAR $14,534,518 $10,073,347 $13,757,751
====================================
The accompanying notes are an integral part of these consolidated
financial statements.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Nature of Operations - Bangor Hydro-Electric Company (the Company) is a
public utility engaged in the generation, purchase, transmission,
distribution and sale of electric energy and other energy related services,
with a service area of approximately 5,275 square miles having a population
of approximately 191,000 people. The Company serves approximately 104,000
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 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. See Note 6 for additional information with respect to these
investments. 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 fuel for generation and purchased power expense. See Note 6
for additional information with respect to these investments.
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.
Accounting for Deferred Fuel and Maine Yankee Refueling Costs - 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 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.
The Company is allowed to defer Maine Yankee refueling costs and amortize
these costs over the period of Maine Yankee's refueling cycle. The
unamortized refueling costs are presented on the Consolidated Balance Sheets
as Deferred Maine Yankee refueling costs.
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 (discussed below), was approximately 2.4% in 1996,
2.3% in 1995, and 2.2% in 1994.
A study conducted in 1989 by an independent firm determined that the Company's
reserve for depreciation was over-accumulated by $11.4 million. 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 over a six-year period. 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 removed from such accounts. The original costs of
units of property retired and removal costs, less salvage, are charged to the
depreciation reserve.
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 $6.5 million in 1996, $5.9 million in 1995 and $6.2
million in 1994.
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, 1996 and 1995.
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 included in AFDC in the Consolidated
Statements of Income. The average AFDC (and carrying cost) rates computed by
the Company were 8.6% in 1996, 9.0% for 1995 and 9.2% in 1994.
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 1996 Consolidated Financial
Statements.
2. INCOME TAXES
In accordance with Statement of Financial Accounting Standards No. 109
"Accounting for Income Taxes" (FAS 109), the Company recorded net additional
deferred income tax liabilities of approximately $20.5 million as of December
31, 1996 and $21.2 million as of December 31, 1995. 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
($29.0 million and $29.8 million as of December 31, 1996 and 1995,
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 as of December 31,
1996 and 1995), and the establishment of deferred tax assets on unamortized
investment tax credits ($1.3 million as of December 31, 1996 and $1.4 million
as of December 31, 1995). These latter amounts have been recorded as deferred
regulatory liabilities at December 31, 1996 and 1995. 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, 1996, 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, 1996 and 1995:
1996 1995
- -------------------------------------------------------------------------------
Deferred Income Tax Liabilities:
Costs to terminate purchased power contracts $ 67,731,973 $ 77,126,042
Excess book over tax basis of electric plant
in service 51,356,093 47,658,824
Deferred FERC licensing costs 1,351,945 1,361,034
Investment in jointly owned companies 832,646 842,624
Deferred demand-side management costs 1,018,733 651,672
Other 510,215 784,752
- -------------------------------------------------------------------------------
$ 122,801,605 $ 128,424,948
- -------------------------------------------------------------------------------
Less: Deferred Income Tax Assets:
Net tax operating loss carryforwards $ 51,252,151 $ 64,769,384
Deferred income taxes provided on alternative
minimum tax 5,808,234 3,898,824
Investment in Basin Mills 2,801,261 2,732,550
Unamortized investment tax credits 1,251,322 1,352,104
Postretirement benefit costs other than pensions 1,861,054 1,107,808
Deferred state income tax benefit 2,213,840 908,722
Accrued pension costs 1,008,523 812,120
Reserve for bad debts 807,447 807,447
Other 992,144 1,260,955
- -------------------------------------------------------------------------------
$ 67,995,976 $ 77,649,914
- -------------------------------------------------------------------------------
Total other accumulated deferred income taxes $ 54,805,629 $ 50,775,034
===============================================================================
The individual components of federal and state income taxes reflected in the
Consolidated Statements of Income for 1996, 1995 and 1994 are stated in the
table at the top of the following page.
- ---------------------------------------------------------------------------
Year Ended December 31,
- ---------------------------------------------------------------------------
1996 1995 1994
---------------------------------------------
Current:
Federal $ 1,804,206 $ --- $ 1,287,485
State 526,576 --- ---
- ---------------------------------------------------------------------------
$ 2,330,782 $ --- $ 1,287,485
- ---------------------------------------------------------------------------
Deferred-Short-Term:
Federal $ --- $ --- $ (797,919)
State --- --- (296,436)
- ---------------------------------------------------------------------------
$ --- $ --- $ (1,094,355)
- ---------------------------------------------------------------------------
Deferred-Long-Term:
Federal-Other $ 4,034,809 $ 2,131,643 $ 3,003,171
State-Other 861,136 70,424 753,782
Federal-Seabrook (331,076) (339,415) (339,620)
State-Seabrook (69,379) (71,570) (72,127)
- ---------------------------------------------------------------------------
$ 4,495,490 $ 1,791,082 $ 3,345,206
- ---------------------------------------------------------------------------
Investment Tax Credits, Net $ (1,122,798)$ (61,193)$ 143,695
- ---------------------------------------------------------------------------
Total Provision $ 5,703,474 $ 1,729,889 $ 3,682,031
Allocated to Other Income (821,021) (308,215) (68,433)
- ---------------------------------------------------------------------------
Charged to Operating Expense $ 4,882,453 $ 1,421,674 $ 3,613,598
===========================================================================
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 Consolidated Statements of Income. The
difference is represented by the temporary differences for which deferred
taxes were not originally provided.
1996 1995 1994
- --------------------------------------------------------------------------------
Amount % Amount % Amount %
------------- ----------------------------
(Dollars in Thousands)
------------------------------------------
Federal income tax provision at
statutory rate $5,860 34.5 % $ 2,063 34.0 % $3,798 34.1 %
Less (Plus) temporary reductions in
tax expense resulting from statutory
exclusions from taxable income:
Dividends received deduction
related to earnings of associated
companies 116 .7 31 .5 132 1.2
Equity component of AFDC 127 .8 191 3.1 428 3.8
Amortization of equity component
of AFDC on recoverable Seabrook
investment (157) (.9) (155) (2.5) (155) (1.4)
Other (68) (.5) (104) (1.7) 7 .1
- --------------------------------------------------------------------------------
Federal income tax provision before
effect of temporary differences $5,842 34.4 % $ 2,100 34.6 % $3,386 30.4 %
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 (149) (.9) (146) (2.4) (147) (1.3)
Book depreciation greater than tax
depreciation on assets acquired
before 1971 (90) (.5) (292) (4.8) (293) (2.6)
State income tax liability deducted
for federal income tax purposes 314 1.9 -- -- 131 1.2
Reversal of excess deferred income
taxes 101 .6 101 1.7 35 .3
Amortization of investment tax
credits 175 1.0 676 11.1 178 1.6
Investment tax credits flowed
through 540 3.2 62 1.0 -- --
Other 158 .9 (32) (.5) 185 1.6
- --------------------------------------------------------------------------------
Federal income tax provision $4,793 28.2 % $ 1,731 28.5 % $3,297 29.6%
================================================================================
Under the federal income tax laws, the Company received investment tax
credits (ITC) on qualified property additions through 1986. ITC utilized were
deferred and are being amortized over the life of the related property. In
1996 the Company recorded the utilization of approximately $540,000 of ITC,
which were utilized to reduce income taxes payable upon an Internal Revenue
Service (IRS) examination of the Company's 1993 and 1994 federal income tax
returns and to reduce federal alternative minimum income taxes, which were
flowed-through for financial reporting purposes as a reduction of income tax
expense. The Company in 1996 also recorded $407,000 of State of Maine ITC and
$175,000 of amortization of deferred ITC. Comparatively, in 1995, the Company
recorded the utilization of $615,000 of deferred ITC and $676,000 of
amortization of deferred ITC.
ITC available of about $2.6 million ($1.6 million which is attributable to
PHC and $950,000 to BVC) have not been utilized or recorded and, subject to
review by the IRS, may be used prior to their expiration, which occurs
between 2001 and 2005.
At December 31, 1996, the Company had, for income tax purposes, federal and
state alternative minimum tax credits of approximately $5.8 million for the
reduction of future tax liabilities. In 1996 the Company utilized
approximately $32.6 million of tax net operating loss carryforwards to reduce
its regular income tax liability. At December 31, 1996, the Company had, for
income tax reporting purposes, approximately $126.1 million of tax net
operating loss carryforwards 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 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 - 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. In January 1997, the
Company further amended the Plan to allow for the option of purchasing shares
either on the open market or from newly issued shares sold by the Company.
The Company anticipates that for the foreseeable future common stock will be
purchased on the open market.
Preferred Stock - Authorized but unissued shares of 432,660 (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 where-
by, 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 (make
whole provision) 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 and
1995 and 50% in 1993, pending any review by the IRS (for 1995 only), were
considered a return of capital, the Company became obligated to pay this
stockholder approximately $939,000, on a pro-rata 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 $89,000 in 1996.
In 1996 the Company made two sinking fund payments totalling $3 million, as
well as approximately $188,000 under the make whole provision.
4. LONG-TERM DEBT AND SHORT-TERM BORROWINGS
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 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 held by a third party trustee and invested in a
guaranteed investment contract, earning interest at an annual 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. 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 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. 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
1995 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, 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 under
the 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.
In August 1995, the Company entered into agreements with three banks to cap
the LIBO rate on the term loan 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. The Company was in compliance with
the covenants during 1996, but it is likely that the Company will not be in
compliance with all covenants for the quarter ending March 31, 1997. The
noncompliance with the covenants would create an event of default under the
Agreement, resulting in the associated outstanding debt being callable by the
lenders. As of December 31, 1996 the Company has classified the Medium Term
Notes as long-term, the classification which the Company believes to be most
appropriate. If in the future it became likely that the lenders would call
the debt, then the outstanding borrowings could be classified as short-term.
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, 1996 aggregate $112,374,966 as follows:
Sinking Fund Current
Requirements Maturities Total
- ------------------------------------------------------------------------------
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
2001 180,990 15,100,000 15,280,990
- ------------------------------------------------------------------------------
$ 7,374,966 $ 105,000,000 $ 112,374,966
==============================================================================
Certain information related to total short-term borrowings under the Credit
Agreement and the lines of credit is as follows:
1996 1995 1994
- ------------------------------------------------------------------------------
Total credit available at end
of period $ 54,000,000 $ 59,000,000 $ 55,000,000
Letter of credit secured under
the revolving credit facility $ 4,200,000 $ 4,200,000 $ -
Unused credit at end of period $ 17,300,000 $ 19,800,000 $ 28,000,000
Borrowings outstanding at end
of period $ 32,500,000 $ 35,000,000 $ 27,000,000
Effective interest rate (exclusive
of fees) on borrowings outstand-
ing at end of period 7.7 % 8.4 % 6.0 %
Average daily outstanding borrow-
ings for the period $ 33,609,973 $ 33,573,973 $ 26,035,616
Weighted daily average annual
interest rate 7.6 % 7.5 % 4.6 %
Highest level of borrowings at
any month-end during the period $ 41,500,000 $ 47,000,000 $ 38,000,000
============================================================================
5. POSTRETIREMENT AND OTHER POSTEMPLOYMENT BENEFITS
Postretirement Benefits - The Company has a noncontributory pension plan
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 expense for 1996 and
pension income for 1995 and 1994, 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 1996 and 1995. Employer contributions to the
plans amounted to approximately $1.2 million in 1994. In 1995 and 1994 the
Company implemented early retirement programs which resulted in additional
pension expense of approximately $2.5 million and $1.6 million, respectively.
The plan's assets are composed of fixed income securities, equity securities
and cash equivalents. Total pension expense (income) included the following
components:
1996 1995 1994
- --------------------------------------------------------------------------------
Service cost-benefits earned during
the period $ 991,569 $ 813,811 $ 1,060,134
Interest cost on projected benefit
obligation 2,781,366 2,458,466 2,310,455
Actual return on plan assets (6,298,817) (8,505,484) 377,447
Total of amortized obligations and
the net gain (loss) deferred 2,539,961 4,889,703 (3,865,833)
- --------------------------------------------------------------------------------
Total pension expense (income) $ 14,079 $ (343,504)$ (117,797)
================================================================================
1996 1995 1994
- --------------------------------------------------------------------------------
Significant assumptions used were-
Discount rate 7.25% 8.25% 7.0%
Rate of increase in future compen-
sation 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 plan's funded status at December 31, 1996
and 1995:
1996 1995
- --------------------------------------------------------------------------------
Actuarial present value of accumulated benefit obligation
Vested $ 30,856,060 $ 31,528,835
Non-vested 2,696,764 2,877,035
- --------------------------------------------------------------------------------
Total $ 33,552,824 $ 34,405,870
================================================================================
Project benefit obligation $ (39,369,783)$ (39,121,538)
Plan assets at fair value 44,143,679 41,312,595
- --------------------------------------------------------------------------------
Excess of plan assets over projected
benefit obligation $ 4,773,896 $ 2,191,057
Items not yet recognized in earnings-
Net (asset) at transition (4,119,475) (5,051,800)
Prior service cost 4,540,404 5,096,783
Unrecognized net gain from past ex-
perience and changes in assumptions (5,835,153) (2,862,289)
- --------------------------------------------------------------------------------
Net pension liability recognized $ (640,328)$ (626,249)
================================================================================
The discount rate and rate of increase in future compensation levels used to
determine pension obligations, effective January 1, 1997, are 7.5% and 5%,
respectively, and were used to calculate the plan's funded status at December
31, 1996.
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 MPUC in 1993 issued a final accounting rule in connection with Statement
of Financial Accounting Standards No. 106, "Employers' Accounting for Post-
retirement Benefits Other Than Pensions" (FAS 106), which adopted this
pronouncement for ratemaking purposes and authorized the Company 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 and retiree contributions to the
VEBA, which commenced in July 1994, amounted to $528,000 in 1996, $1,226,000
in 1995 and $755,000 in 1994. The VEBA's assets are composed of United States
Treasury money market funds. The Company's general policy is to contribute to
the VEBA amounts necessary to fund claims and administrative costs.
The actuarially determined net periodic postretirement benefit cost for 1996,
1995 and 1994 and the major assumptions used to determine these amounts are
shown in the following tables:
1996 1995 1994
- --------------------------------------------------------------------------------
Service cost of benefits earned $ 326,809 $ 378,400 $ 379,400
Interest cost on accumulated post-
retirement benefit obligation 928,423 948,000 724,000
Actual return on plan assets (21,000) (23,300) (7,800)
Amortization of unrecognized transition 501,200 501,200 501,200
Other deferrals, net -- 23,699 (1,800)
Early retirement plan benefits -- 909,418 750,000
- --------------------------------------------------------------------------------
Net periodic postretirement benefit
cost $ 1,735,432 $ 2,737,417 $ 2,345,000
================================================================================
1996 1995 1994
- --------------------------------------------------------------------------------
Significant assumptions used were-
Discount rate 7.25% 8.25% 7.0%
Health care cost trend rate, employees
less than age 65-
Near-term 9.0% 8.5% 9.0%
Long-term 4.5% 4.5% 4.5%
Health care cost trend rate, employees
greater than age 65-
Near-term 7.0% 6.8% 7.0%
Long-term 4.5% 4.5% 4.5%
Rate of return on plan assets 5.0% 5.0% 2.0%
- --------------------------------------------------------------------------------
The following table sets forth the benefit plan's funded status at December 31,
1996 and 1995:
1996 1995
- --------------------------------------------------------------------------------
Accumulated postretirement benefit obligation:
Retirees $ 8,606,932 $ 7,749,800
Fully eligible active plan participants 847,920 1,374,400
Other active participants 3,783,868 3,248,300
- --------------------------------------------------------------------------------
$ 13,238,720 $ 12,372,500
Fair value of plan assets (240,878) (606,800)
Unrecognized net transition obligation (8,018,400) (8,519,600)
Unrecognized gain 683,075 625,986
- --------------------------------------------------------------------------------
Accrued postretirement benefit cost
(included in Other Reserves) $ 5,662,517 $ 3,872,086
================================================================================
The discount rate used to determine postretirement benefit obligations,
effective January 1, 1997, and the Plan's funded status at December 31, 1996,
was 7.5%.
If the health care cost trend rate was increased one percent, the accumulated
postretirement benefit obligation as of December 31, 1996 would have
increased by 13.2%. The effect of such change on the aggregate of service and
interest cost for 1996 would be an increase of 17.5%.
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.
The Company also provides a defined contribution 401(k) savings plan for
substantially all of its employees. The Company's matching of employee
voluntary contributions amounted to approximately $290,000 in 1996 and
$216,000 in each of 1995 and 1994.
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 is not material.
6. JOINTLY OWNED FACILITIES AND POWER SUPPLY COMMITMENTS
Maine Yankee - The Company owns 7% of the common stock of Maine Yankee, which
owns and operates an 880 megawatt (MW) nuclear generating plant in Wiscasset,
Maine. The Company's equity investment in Maine Yankee is approximately $5
million. Under a cost-based power contract, the Company is entitled to about
7% of the output of the plant.
Following a yearlong shutdown for repairs to the steam generators in 1995,
Maine Yankee has come under intense regulatory scrutiny in a series of events
beginning in December 1995 with an anonymous letter about an allegedly faulty
computer program. The events have evolved into a number of investigations by
Maine Yankee's primary licensing authority, the United States Nuclear
Regulatory Commission (NRC) and by Maine Yankee itself. Concerns have
included compliance with NRC regulations, conformance of the plant to design
specifications, adequacy and condition of components and systems, and
management issues. Many of these concerns remain unresolved. During the
evolution of these events, the NRC itself has been subject to public
criticism about the adequacy of its regulatory activities and its
relationship with nuclear plant licensees, and in response the NRC has been
implementing changes in its approach to oversight of licensees that are
having the effect of amplifying the regulatory scrutiny. Civil enforcement
proceedings have been initiated by the NRC to impose monetary penalties on
Maine Yankee for alleged violations of regulations. The NRC has also referred
certain issues to the United States Department of Justice for further
investigation, which could result in further civil or criminal proceedings.
The Company cannot predict the outcome of these investigations and
proceedings.
Maine Yankee operated for part of 1996, but under a restriction imposed by
the NRC that limited its operation to 90% of full power capacity pending the
resolution of various issues (which are not yet resolved). The plant has been
off-line since early December 1996 when it was shut down to address
cable-separation and associated issues. Since then, Maine Yankee also
determined that a substantial portion of the nuclear fuel in the reactor was
defective and had to be replaced, thereby extending the shutdown into a
refueling outage. During the refueling outage, Mine Yankee is continuing to
attempt to resolve the other issues that led to the current shutdown, and
will inspect the steam generators for degradation beyond that which was the
subject of the 1995 repair. Such degradation has been identified at other
plants of similar age and design as Maine Yankee. Satisfactory condition of
the steam generators is a significant factor in the plant's continued
operation.
Management changes are taking place at Maine Yankee. Maine Yankee's chief
executive officer resigned in late 1996, and a management team from a firm
experienced in nuclear generating plant operations has been retained.
During 1996 and 1995 the Company incurred substantial cost for replacement
power, and, since the FCA was eliminated at the beginning of 1995, the
replacement power costs had a material impact in reducing earnings in 1996
and 1995. With the Plant off-line for most of 1995 and portions of 1996, and
operating at 90% capacity in 1996 when on-line, the Company incurred
replacement power costs of $4.3 million in 1996 and $8.6 million in 1995.
Maine Yankee has estimated that the cost of resolving the previously
mentioned cable separation issue will be approximately $7.2 million, and the
Company has accrued for its share of this cost at December 31, 1996. The
Company, in 1995, incurred approximately $1.9 million in expense related to
its share of Maine Yankee's steam tube resleeving project costs.
The Company cannot predict how long Maine Yankee will remain out of service.
The Company has been incurring replacement power costs of approximately $1
million per month while the plant has been out of service, and expects such
costs to continue at least at the same rate until the plant returns to
service. The market price for replacement power is being driven up somewhat
because other nuclear power plants in New England are also indefinitely shut
down. In addition to the replacement power costs, the Company is responsible
for 7% of whatever additional costs are necessary to return Maine Yankee to
service. In December 1996 the Maine Yankee board of directors approved about
$30 million in additional operating and maintenance costs for 1997 (in
addition to incremental capital costs), and, while revised budgets have not
been approved, these costs are now likely to be greater.
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 $369.4 million (in 1996 dollars) of which the
Company's share is approximately $25.9 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, 1996 had an adjusted market value of $163.5 million of which the
Company's share was approximately $11.4 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. Information relating to the operations and
financial position of Maine Yankee and MEPCO appears at the top of page 30
[below in this electronic filing].
- --------------------------------------------------------------------------------------------------------------
Maine Yankee MEPCO
- --------------------------------------------------------------------------------------------------------------
(Dollars in Thousands)
- --------------------------------------------------------------------------------------------------------------
1996 1995 1994 1996 1995 1994
--------- --------- --------- --------- --------- ---------
Operations:
As reported by investee-
Operating Revenue $ 185,661 $ 205,977 $ 173,857 $ 55,391 $ 49,699 $ 24,746
- --------------------------------------------------------------------------------------------------------------
Depreciation $ 32,952 $ 32,722 $ 30,823 $ 845 $ 1,383 $ 1,383
Interest and Preferred Divivends 15,922 17,332 14,583 61 96 106
Other expenses, net 130,150 148,866 121,437 54,265 48,115 23,152
- --------------------------------------------------------------------------------------------------------------
Operating expenses $ 179,024 $ 198,920 $ 166,843 $ 55,171 $ 49,594 $ 24,641
- --------------------------------------------------------------------------------------------------------------
Earnings Applicable to Common Stock $ 6,637 $ 7,057 $ 7,014 $ 220 $ 105 $ 105
==============================================================================================================
Amounts Reported by the Company-
Purchased power costs $ 12,839 $ 14,299 $ 11,771 $ - $ - $ -
Equity in net income (449) (498) (480) (15) (15) (15)
- --------------------------------------------------------------------------------------------------------------
Net purchased power expense $ 12,390 $ 13,801 $ 11,291 $ (15) $ (15) $ (15)
==============================================================================================================
Financial Position:
As reported by investee-
Plant in service $ 409,865 $ 404,499 $ 401,092 $ 23,146 $ 23,135 $ 23,099
Accumulated depreciation (225,735) (208,537) (192,293) (22,545) (21,777) (20,463)
Other assets 417,931 384,996 341,111 10,126 4,667 3,927
- --------------------------------------------------------------------------------------------------------------
Total assets $ 602,061 $ 580,958 $ 549,910 $ 10,727 $ 6,025 $ 6,563
Less-
Preferred stock 18,000 18,600 19,200 - - -
Long-term debt 103,332 109,999 118,666 620 - 1,730
Other liabilities and deferred credits 409,392 381,158 344,550 9,110 5,147 3,955
- --------------------------------------------------------------------------------------------------------------
Net assets $ 71,337 $ 71,201 $ 67,494 $ 997 $ 878 $ 878
==============================================================================================================
Company's reported equity-
Equity in net assets $ 4,994 $ 4,984 $ 4,725 $ 142 $ 125 $ 125
Adjust Company's estimated to actual 20 30 29 (17) - -
- --------------------------------------------------------------------------------------------------------------
Equity in net assets as reported $ 5,014 $ 5,014 $ 4,754 $ 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:
1996 1995 1994
- -------------------------------------------------------------------------
Electric plant in service $ 16,885,690 $ 16,876,963 $ 16,771,430
Accumulated depreciation (8,927,440) (8,459,911) (7,996,737)
- -------------------------------------------------------------------------
$ 7,958,250 $ 8,417,052 $ 8,774,693
=========================================================================
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 BVC, 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 page 32.
- ------------------------------------------------------------------------------------------------
Bangor-Pacific Chester
- ------------------------------------------------------------------------------------------------
(Dollars in Thousands)
- ------------------------------------------------------------------------------------------------
1996 1995 1994 1996 1995 1994
--------- --------- --------- --------- --------- ---------
Operations:
As reported by investee-
Operating Revenue $ 8,252 $ 7,277 $ 6,880 $ 4,782 $ 5,016 $ 5,173
- ------------------------------------------------------------------------------------------------
Depreciation $ 866 $ 862 $ 855 $ 1,075 $ 1,075 $ 1,075
Interest expense 3,501 3,657 3,791 2,988 3,114 3,227
Other expenses, net 832 707 1,134 719 827 871
- ------------------------------------------------------------------------------------------------
Operating expenses $ 5,199 $ 5,226 $ 5,780 $ 4,782 $ 5,016 $ 5,173
- ------------------------------------------------------------------------------------------------
Net Income $ 3,053 $ 2,051 $ 1,100 $ - $ - $ -
================================================================================================
Company's reported equity in
net income $ 1,527 $ 1,026 $ 550 $ - $ - $ -
================================================================================================
Financial Position:
As reported by investee-
Plant in service $ 44,043 $ 44,035 $ 43,977 $ 31,993 $ 31,993 $ 31,991
Accumulated depreciation (7,293) (6,427) (5,572) (6,372) (5,296) (4,221)
Other assets 3,114 3,399 2,978 3,277 3,351 3,555
- ------------------------------------------------------------------------------------------------
Total assets $ 39,864 $ 41,007 $ 41,383 $ 28,898 $ 30,048 $ 31,325
Less-
Long-term debt 30,600 32,600 34,500 27,021 28,204 29,387
Other liabilities 2,359 2,255 2,241 1,877 1,844 1,938
- ------------------------------------------------------------------------------------------------
Net assets $ 6,905 $ 6,152 $ 4,642 $ - $ - $ -
================================================================================================
Company's reported equity in
net assets $ 3,453 $ 3,076 $ 2,321 $ - $ - $ -
================================================================================================
Small Power Production Facilities - As of the end of 1996, 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 were much higher than at
present, and when forecasts for the costs of the Company's long-term power
supply were higher than current forecasts.
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. These contract terminations have resulted in
significant savings in purchased power costs, and the Company believes such
savings will continue over the long term. 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. In 1996 the Company made payments of approximately
$859,000 to the two towns under this commitment.
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 agreed to pay
the Company $1 million annually for a six-year period beginning in 1994 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.
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, 1995 and 1996 the Company received its $1 million
payment.
The last remaining high-priced non-utility power purchase contract that
offers a potential for substantial savings is the Company's contract to
purchase energy from the Penobscot Energy Recovery Company (PERC). PERC owns
a 20 MW waste-to-energy facility in Orrington, Maine that provides solid
waste disposal services to many communities in central, eastern and northern
Maine. The contract requires the Company to purchase the electricity output
of the plant until 2018 at a price that is presently substantially above the
cost of alternative sources of power, and in the Company's opinion, is likely
to remain so. The Company has been working with PERC and the affected
municipalities at a restructuring of the power contract that would result in
substantial savings for the Company and would continue to allow the PERC
plant to meet the solid waste disposal needs of Maine communities. As of this
writing, the interested parties appear to have arrived at a satisfactory
agreement to restructure the contract that would include: 1) an initial
payment by the Company to PERC of $8 million; 2) an additional annual payment
by the Company to PERC of up to $500,000 for four years contingent upon
specified levels of profitability for the PERC plant; 3) an annual rebate to
the Company based upon a formula tied to the profitability of the PERC plant;
4) a refinancing by PERC to extend the term of the existing tax-exempt debt;
and 5) a guarantee of that debt by FAME. While there are a number of obsta-
cles to the completion of the restructuring, the Company estimates that if it
is successfully completed, the net present value of the savings from current
contract costs will be $30-35 million over the remaining life of the
contract.
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. 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 at the top
of page 32.
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 MW generating facility
located at the so-called Basin Mills site on the Penobscot River in Orono and
Bradley, Maine and an 8 MW 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 1980s.
7. 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
----------------------------------------------
1996 (DOLLARS IN THOUSANDS EXCEPT PER SHARE AMOUNTS)
- -------------------------------------------------------------------------------
Electric Operating Revenue $ 48,161 $ 43,152 $ 47,355 $ 48,706
Operating Income 10,454 9,036 8,417 8,334
Net Income 4,095 2,758 2,295 2,135
Earnings Per Share of Common Stock$ .51 $ .32 $ .26 $ .24
=============================================================================
1995
- ---------------------------------
Electric Operating Revenue $ 48,263 $ 43,694 $ 46,025 $ 46,931
Operating Income 6,004 1,438 7,538 8,688 *
Net Income 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
===============================================================================
* Includes $498,000 of amortization of investment tax credit or $.07 per common
share.
8. 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.
9. CONTINGENCIES
Environmental Matters - In 1992, the Company received notice from the Maine
Department of Environmental Protection 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 Department of Environmental
Protection as an Uncontrolled Hazardous Substance Site, the Company was
informed that it is considered a de minimis generator.
10. FAIR VALUE OF FINANCIAL INSTRUMENTS
The following methods and assumptions were used to estimate the fair value at
December 31, 1996 of each class of financial instrument for which it is
practical to estimate the value:
Cash and cash equivalents: the carrying amount of $1,274,386 approximates
fair value. The fair values of other financial instruments at December 31,
1996 based upon similar issuances of comparable companies are as follows:
In Thousands
- ------------------------------------------------------------------------------
Carrying Fair
Amount Value
-------------------------
Funds held by trustee-guaranteed investment contract $ 21,199 $ 20,603
Mandatory redeemable cumulative preferred stock 12,000 12,587
First Mortgage Bonds 109,875 117,068
Pollution Control Revenue Bonds 4,200 4,200
FAME Revenue Notes 126,000 125,824
Medium Term Notes 48,000 48,000
- ------------------------------------------------------------------------------
11. REGULATORY 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, 1996, the Company has regulatory assets, net
of regulatory liabilities, of approximately $227.7 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.
12. ALTERNATIVE MARKETING PLAN
On February 14, 1995 the MPUC issued an order approving many aspects of the
Company's 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.
13. 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 $624,000 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.
14. DERIVATIVE 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. During 1996 and 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 price volatility is no longer covered by a
rate mechanism like the FCA. A significant portion of the Company's exposure
to purchased energy price volatility is closely matched to changes in
residual oil prices. To manage the oil-related risk of energy price
fluctuations, the Company has 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 occur on a monthly basis and the
cash receipts/payments arising from the "swap" transactions offset
corresponding increases/decreases in the Company's purchased energy costs.
The Company entered into "swap" transactions for 1996 amounting to 775,000
barrels of residual oil. As a result of market movements in 1996 the Company
received cash payments of approximately $3.6 million from the swap
transactions. The cash received from the "swaps" was recorded as a reduction
in fuel for generation and purchased power expense in the Consolidated
Statements of Income. At December 31, 1996, The Company was a party to
"swaps" covering 475,000 barrels and 180,000 barrels of residual oil for the
years 1997 and 1998 respectively. The fair market value of these transactions
is estimated to be $1.7 million. The fair market value estimate was
determined using available market data. Judgement is required in interpreting
market data, and the use of different market assumptions or estimation
methodologies may affect the estimated fair market value.
As a result of these hedging activities, the Company is managing 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 non-performance of counter parties to these
agreements. The Company controlled the 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 risk related to the fuel swaps through credit limits, collateral
instruments, and monitoring procedures. 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 for risk management purposes only, it does not expect
any significant exposure to market risk because gains and losses arising on
derivative instruments are 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 payment if the notional interest
rate exceeds 7.25%.
REPORT OF INDEPENDENT CERTIFIED PUBLIC 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, 1996 and 1995, and the related consolidated
statements of income, retained earnings, and cash flows for each of the three
years in the period ended December 31, 1996. These financial statements are
the responsibility of the Company's management. Our responsibility is to
express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free
of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements.
An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in
all material respects, the consolidated financial position of the Company as
of December 31, 1996 and 1995, and the consolidated results of its operations
and its cash flows for each of the three years in the period ended December
31, 1996, in conformity with generally accepted accounting principles.
COOPERS & LYBRAND L.L.P.
Boston, Massachusetts
February 5, 1997
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 13, 1997, 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 13, 1997, 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 13, 1997,
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 13, 1997, 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 13, 1997, 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
covered by the Report of the of Independent
Auditors(See Item 8):
Consolidated Statements of Income for the Years Ended
December 31, 1996, 1995 and 1994
Consolidated Balance Sheets - December 31, 1996 and
1995
Consolidated Statements of Retained Earnings for the
Years ended December 31, 1996, 1995 and 1994
Consolidated Statements of Capitalization - December
31, 1996 and 1995
Consolidated Statements of Cash Flows
for the Years Ended December 31, 1996, 1995 and 1994
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 79.
(d) Reports on Form 8-K
One Current Report on Form 8-K dated December 26, 1996 was
filed in the fourth quarter of 1996, regarding the Maine
Yankee Atomic Power Company s formal response to the Nuclear
Regulatory Commission s ("NRC") Independent Safety Assessment
of the Maine Yankee nuclear generating facility. Two Current
Reports on Form 8-K, dated February 19, 1997 and March 19,
1997, were filed in the first quarter of 1997, regarding the
premature replacement of a portion of the fuel assembies at
the Maine Yankee nuclear generating facility, the change in
management at the Maine Yankee Atomic Power Company and the
placement of the Maine Yankee nuclear generating facility on
the NRC s "Watch List" in "Category 2" (8-K dated February
19, 1997) and Bangor Hydro-Electric Company s suspension of
its common dividend on March 19, 1997 (8-K dated March 19,
1997).
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 /s/ G. Clifton Eames
- --------------------------- --------------------------------
Robert S. Briggs G. Clifton Eames
President and Director
Chairman of the Board
/s/ Marion M. Kane
- --------------------------- --------------------------------
William C. Bullock, Jr. Marion M. Kane
Director Director
/s/ Jane J. Bush /s/ Norman A. Ledwin
- --------------------------- --------------------------------
Jane J. Bush Norman A. Ledwin
Director Director
/s/ David M. Carlisle /s/ Carroll R. Lee
- --------------------------- --------------------------------
David M. Carlisle Carroll R. Lee
Director Director, Senior Vice
President and Chief
Operating Officer
/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 19, 1997.
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 5, 1997
SCHEDULE VIII
RESERVES FOR DOUBTFUL ACCOUNTS AND INSURANCE
--------------------------------------------
Additions
-----------------------------
Balance at Charged to Charged to Balance at
Beginning Costs and Other End
Of Period Expenses Accounts Deductions of Period
------- ------- ------- ------- -------
1996
Reserve for Doubtful
Accounts $ 1,450,000 $ 1,826,884 $ - $ 1,826,884 (A)$1,450,000
---------- ---------- -------- ---------- ---------
Reserve for Retirees'
Life Insurance $ 852,000 $ - $ - $ 852,000 $ -
---------- ---------- -------- ---------- --------
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
---------- ---------- -------- ---------- ----------
NOTE:
(A) Accounts written off, less recoveries.
EXHIBIT INDEX
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. 3-39181,
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 Articles of Amendment Form 10-K, 1995, Exhibit3(a)
changing Corporate Clerk
3.4 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).
4.23 Supplemental Indenture Form 10-K, 1995, Exhibit 4(a)
Dated as of October 1, 1995 (Identified as Exhibit 10(a))
to General and Refunding
Mortgage and Deed of Trust
dated as of June 1, 1995
(Bangor Hydro-Electric
Company to Chemical Bank).
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 10(i)
Power AC Facilities
Support Agreement dated
June 1, 1985 re: Hydro-
Quebec Phase II
interconnection project
10.53 Phase II Massachusetts Form 10-K, 1985, Exhibit 10(j)
Transmission Facilities
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 10(o)
1985, August 15, 1985, and
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 10(g)
effective as of June 9,
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 10(h)
dated as of January 29,
1987, among the Company
and lenders to Bangor-
Pacific Hydro Associates
10.79 Power Purchase Agreement Form 10-K, 1986, Exhibit 10(i)
dated June 9, 1986 and
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 10(j)
transfer of West Enfield
site from the Company to
Bangor-Pacific Hydro
Associates
10.81 Assignment by the Company Form 10-K, 1986, Exhibit 10(k)
of Joint Venture Interest
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 10(a)
liminary Quebec Intercon-
nection Support Agreement -
Phase II
10.84 Fourth Amendment to Pre- Form 10-K, 1987, Exhibit 10(b)
liminary Quebec Intercon-
nection Support Agreement -
Phase II
10.85 Fifth Amendment to Pre- Form 10-K, 1987, Exhibit 10(c)
liminary Quebec Intercon-
nection Support Agreement -
Phase II
10.86 Sixth Amendment to Pre- Form 10-K, 1987, Exhibit 10(d)
liminary Quebec Intercon-
nection Support Agreement -
Phase II
10.87 Seventh Amendment to Pre- Form 10-K, 1987, Exhibit 10(e)
liminary Quebec Intercon-
nection Support Agreement -
Phase II
10.88 Amendment to New England Form 10-K, 1987, Exhibit 10(f)
Power Pool Agreement dated
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 10(a)
1988 regarding the sale
of certain Seabrook trans-
mission facilities to EUA
Power
10.92 Ninth Amendment to Form 10-K, 1988, Exhibit 10(b)
Preliminary Quebec
Interconnection Support
Agreement - Phase II
10.93 Tenth Amendment to Form 10-K, 1988, Exhibit 10(c)
Preliminary Quebec
Interconnection Support
Agreement - Phase II
10.94 Second Amendment to Form 10-K, 1988, Exhibit 10(d)
Massachusetts Trans-
mission Facilities
Support Agreement
10.95 Third Amendment to Form 10-K, 1988, Exhibit 10(e)
Massachusetts Trans-
mission Facilities
Support Agreement
10.96 Fourth Amendment to Form 10-K, 1988, Exhibit 10(f)
Massachusetts Trans-
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