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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, 1997 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 20, 1998)
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7% Preferred Stock, $100 Par Value
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4 1/4% Preferred Stock, $100 Par Value
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4% Preferred Stock Series A, $100 Par Value
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Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to
such filing requirements for the past 90 days.
Yes X No
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Indicate by check mark if disclosure of delinquent filers pursuant to
Item 405 of Regulation S-K (section 229.405 of this chapter) is not contained
herein, and will not be contained, to the best of registrant's knowledge, in
definitive proxy or information statements incorporated by reference in Part
III of this Form 10-K or any amendment to this Form 10-K. [X]
The aggregate market value on March 20, 1998 of the voting stock held by
non-affiliates of the registrant was $66.1 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, 1997.
FORM 10-K
FOR THE FISCAL YEAR ENDED DECEMBER 31, 1997
PAGE
----
Cover Page 1
Index 2
PART I:
Items 1 through 2 - Business; Properties 5
- General 5
- Certain Issues Facing the Company 7
- Construction Program 7
- Rates and Regulation 7
- Seabrook 11
- Joint Ventures 11
- Employees 13
- Power Supply Sources 13
- Company-owned Generation 13
- Power Purchase Contracts 14
- Maine Yankee 16
- Environmental Matters 22
- Executive Officers of the Company 23
Item 3: Legal Proceedings 24
Item 4: Submission of Matters to a Vote of Security Holders 24
PART II:
Item 5: Market for Registrant's Common Equity and Related
Stockholder Matters 24
Item 6: Selected Financial Data 26
Item 7: Management's Discussion and Analysis of Results of
Operations and Financial Condition 28
Item 8: Financial Statements & Supplementary Data 43
- Consolidated Statements of Income 43
- Consolidated Balance Sheets 44
- Consolidated Statements of Capitalization 46
- Consolidated Statements of Cash Flows 47
- Consolidated Statements of Common Stock Investment 48
- Notes to Consolidated Financial Statements 49
1) Nature of Operations and Summary of Significant
Accounting Policies 49
2) Income Taxes 51
3) Common and Preferred Stock 53
4) Lending Agreements and Monetization of Power
Sale Contract 54
5) Postretirement Benefits 56
6) Jointly Owned Facilities and Power Supply
Commitments 59
7) Recovery of Seabrook Investment and Sale of
Seabrook Interest 65
8) Unaudited Quarterly Financial Data 66
9) Contingencies 66
10) Fair Value of Financial Instruments 67
11) Industry Restructuring and Rate Regulation 67
12) Derivative Financial Instruments 70
13) Subsequent Events 71
14) New Accounting Pronouncements 72
Report of Independent Accountants 73
Item 9: Changes in and Disagreements with Audit Firms on
Financial Disclosures 74
PART III:
Item 10: Directors and Executive Officers of the Registrant 74
Item 11: Executive Compensation 74
Item 12: Security Ownership of Certain Beneficial Owners
and Management 74
Item 13: Certain Relationships and Related Transactions 74
PART IV:
Item 14: Exhibits, Financial Statement Schedules, and
Reports on Form 8-K 75
Signatures 76
Report of Independent Accountants 77
Schedule VIII - Reserves for Doubtful Accounts and Insurance 78
EXHIBIT INDEX:
Exhibits Filed Herewith 79
Exhibits Incorporated Herein by Reference 80
FORWARD LOOKING INFORMATION - In addition to the historical information
contained herein, this report contains a number of statements that are
"forward-looking" as defined in the Private Securities Litigation Reform Act
of 1995. These statements are subject to certain risks and uncertainties that
could cause actual results to differ materially from those anticipated in the
forward-looking statements. Readers should not place undue reliance on
forward-looking statements, which reflect management s view only as of the
date hereof. The Company undertakes no obligation to publicly revise these
forward-looking statements to reflect subsequent events or circumstances.
Factors that might cause such differences include, but are not limited to,
future economic conditions, relationship with lenders, earnings retention and
dividend payout policies, electric utility restructuring, developments in the
legislative, regulatory and competitive environments in which the Company
operates, and other circumstances that could affect revenues and costs.
PART I
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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 105,000 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 three 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. For a further
discussion of Penobscot Hydro Co. and Bangor Var Co., see "Joint Ventures."
Finally, Bangor Energy Resale, Inc. was formed in 1997 as a special purpose
vehicle to permit Bangor Hydro's use of a power sales agreement as collateral
for a bank loan. For a further discussion of this transaction, see Item 7,
"Management's Discussion and Analysis of Results of Operations and Financial
Condition - Recent Events Affecting The Electric Utility Industry And The
Company - Existing Lending Agreements and Monetization of Power Sale
Contract".
In 1997, 30.5% of the Company's kilowatt hour ("KWH") sales were to
residential customers, 29.5% were to commercial customers, 39.3% were to
industrial customers and 0.7% 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 1997-1998 winter, as of March 20, 1998, was approximately 277.06
megawatts ("MW") on December 15, 1997. At that time the Company had
approximately 338.44 MW of generating capacity and firm purchased power,
comprised of 104 MW from Company-owned generating units, 9.6 MW from Hydro
Quebec, 54.8 MW from non-utility power producers, and 170.0 MW from short
term economy purchases.
The Company owns 7% of the common stock of Maine Yankee Atomic Power
Company, which owns and, prior to its permanent closure in 1997, operated an
880 MW nuclear generating plant in Wiscasset, Maine. Maine Yankee, which had
commenced commercial operation on January 1, 1973, is the only nuclear
facility in which the Company has an ownership interest. The Company s equity
ownership in the plant had entitled the Company to about 7% of the output
pursuant to a cost-based power contract. Pursuant to a contract with Maine
Yankee, the Company is obligated to pay its pro rata share of Maine Yankee's
operating expenses, including 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" and Item 7, "Management's Discussion and
Analysis of Results of Operations and Financial Condition - Recent Events
Affecting The Electric Utility Industry And The Company - 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. On December 1, 1996, the members of NEPOOL, including
the Company, entered into the 33rd Amendment to the NEPOOL Agreement which
provided for a substantial restructuring of NEPOOL. This revised agreement,
together with NEPOOL's Open Access Transmission Tariff were filed with the
Federal Energy Regulatory Commission on December 31, 1996 and were
subsequently approved. Pursuant to this restructuring, effective July 1,
1997 an independent system operator, ISO-New England, assumed oversight of
the operations and integration of the NEPOOL transmission and generation with
respect to reliability and market operations. The intent of these changes in
NEPOOL is to increase competition in the market for electric generation.
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 Events Affecting The Electric Utility Industry And The
Company" for a discussion of the effect of competition and related events on
future sales, earnings and dividend policy. That discussion includes a
description of the legislation enacted by the State of Maine to restructure
the electric industry within the state to implement retail competition.
SIGNIFICANT CUSTOMER - Pursuant to a special rate contract approved by the
MPUC, 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 1995, 1996 and 1997, revenue sharing payments from HMC totaled
approximately $4.1 million, $3.5 million and $0.4 million, respectively.
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.
OTHER ISSUES - See Item 7, "Management's Discussion and Analysis of Results
of Operations and Financial Condition - Recent Events Affecting The Electric
Utility Industry And The Company" for a discussion of the effect of other
significant issues and events on the Company.
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 $45-55 million in the period 1998 through 2000, the majority of
which are expected to be related to extensions and improvements of
transmission and distribution facilities.
RATES AND REGULATION
--------------------
RATE MATTERS - On March 3, 1997, the Company notified the MPUC of its intent
to file for a general increase in rates. Under Maine law, a utility must
ordinarily notify the MPUC two months in advance of the filing of a request
for a general increase in rates and the MPUC then has nine months to
investigate that request. However, under certain circumstances, the MPUC may
allow a utility to implement a requested increase in rates on a temporary
basis pending the conclusion of its investigation of the utility s request
for a general increase in rates.
On April 1, 1997, the Company filed with the MPUC a Petition for
Temporary Rates to increase its rates by an amount that would increase its
annual revenues by $10 million effective June 1, 1997. In doing so, the
Company cited the continuing impact on the Company s financial condition and
cash flow of the ongoing outage at the Maine Yankee nuclear power plant. The
Company also cited potential noncompliance with financial covenants contained
in its bank credit agreement (including the fixed charge coverage ratio,
discussed below) and the need to maintain adequate borrowing capacity for
working capital purposes, including mandatory debt repayments.
On June 26, 1997, the MPUC issued an order authorizing the Company to
change rates temporarily to increase its annual revenues by approximately
$5.1 million effective July 1, 1997. In doing so, however, the MPUC also
required the Company to accelerate the amortization of the deferred
regulatory asset associated with the 1993 buyout of one of its high-priced
non-utility generator contracts. As a result, revenue produced by the rate
increase did not increase earnings, but it did increase cash flow. Effective
December 12, 1997, the MPUC authorized the Company to revert to the original
amortization schedule of that deferred regulatory asset, thereby permitting
the temporary rate increase previously authorized to impact the Company s
earnings positively from that date on.
On February 9, 1998, the MPUC issued its final order on the Company s
request to increase its rates that it filed in March of 1997. Of the
approximately $22 million increase in annual revenue ultimately requested by
the Company, the MPUC authorized an increase of approximately $13.2 million
(which includes the $5.1 million temporary rate increase discussed above)
annually. While there are many factors that explain the difference between
the MPUC allowance and the Company s requested increase, much of that
difference is attributable to the proposed accounting treatment of various
costs and the deferral of other costs for future consideration, including the
deferral of certain costs associated with Maine Yankee. While those
accounting recommendations will affect the timing of receipt of revenues by
the Company and will require the Company to finance the payment of the
associated costs, they should not significantly affect the Company s earnings
during the period that the new rates are effective.
The MPUC order is based upon a determination that the Company should be
allowed to earn an annual return of 12.75% on common equity. It also includes
a rate plan under which the Company s rates will be subject to certain
reconciliations based upon actual expenditures by the Company and an annual
adjustment beginning on May 1, 1999 to account for inflation with an offset
for assumed increase in productivity. Other than those adjustments, the
Company will not change its rates unless its return on equity exceeds or
falls short of the allowed return by more than 350 basis points. If the
Company's return on equity falls outside of that bandwidth, 50% of the excess
or shortfall will be adjusted for in the Company's rates.
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 or
nonoperating licenses have already been issued, or impose new conditions on
such permits or licenses.
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
------- --------- ---------------- -------------------
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
- ------------------
* 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 had been delayed
pending completion by the FERC of an Environmental Impact
Statement ("EIS") of sections of the Penobscot River that was
being prepared in connection with the Company's licensing of the
Basin Mills project. That EIS was completed during 1997,
however, the FERC has not yet issued its final order with respect
to those projects. 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 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 1997,
the Company paid approximately $7.1 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 12 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
kilovolt ("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, 1997, the Company had 421 full time
employees approximately 53% of whom were represented by a local
union affiliated with the International Brotherhood of Electrical
Workers (AFL-CIO). Union membership is divided into two
bargaining units, 177 employees engaged in electrical, line and
meter related functions and 48 employees engaged in customer
service and credit related functions. The present contract with
electrical, line and meter related workers expires December 31,
1998. The present contract with customer service and credit
related workers expires December 31, 1999. 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 1997,
1996 and 1995 by type of fuel is shown below.
SOURCE 1997 1996 1995
------ ---- ---- ----
Hydroelectric (Company*)....... 13% 17% 14%
Nuclear Generation (Maine Yankee) 0% 19% 1%
Oil (Company)................... 4% 2% 3%
Biomass/Refuse (purchased)...... 6% 6% 6%
NEPOOL/other purchases.......... 77% 56% 76%
---- ---- ----
Total....................... 100% 100% 100%
---- ---- ----
- ---------------
* 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."
On February 9, 1998, the Company filed its plan for
divesting its generation-related assets with the MPUC in
accordance with the electric utility industry restructuring
provisions signed into law last year. This plan could result in
the identification of proposed purchasers by mid-summer 1998.
Further regulatory approvals will then be required to actually
complete the sale. The Company is offering a total of 166 MW of
generation assets, including both Company-owned facilities and
the resale of certain purchase power contracts that extend beyond
March 1, 2000, the scheduled implementation date for retail
electric competition within the State of Maine.
In addition, the Company owns approximately 600 miles of
transmission lines and approximately 3,600 miles of distribution
lines to serve its customers. Other properties consist of
office, garage and warehouse facilities at various locations in
its service area.
POWER PURCHASE CONTRACTS
------------------------
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
New Brunswick April 1, 1996 through 10 MW system purchase of
Power October 31, 1998 capacity and energy (months
of April-October only)
New Brunswick June 8, 1997 through 60 MW system purchase of
Power December 31, 1999 capacity and 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)
- -----------------
* 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 owns 7% of the common stock of Maine
Yankee, which owns and, prior to its permanent closure in 1997,
operated an 880 MW nuclear generating plant in Wiscasset, Maine.
Maine Yankee, which had commenced commercial operation on January
1, 1973, is the only nuclear facility in which the Company has an
ownership interest. The Company s equity ownership in the plant
had entitled the Company to about 7% of the output pursuant to a
cost-based power contract. Pursuant to a contract with Maine
Yankee, the Company is obligated to pay its pro rata share of
Maine Yankee's operating expenses, including 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.
PERMANENT SHUTDOWN OF THE MAINE YANKEE PLANT - On August 6, 1997,
the Board of Directors of Maine Yankee voted to permanently cease
power operations at its nuclear generating plant at Wiscasset,
Maine (the "Plant") and to begin decommissioning the Plant. As
reported in detail in the Company's Annual Report on Form 10-K
for the year ended December 31, 1996, its Quarterly Reports on
Form 10-Q for the quarters ended March 31, 1997, June 30, 1997
and September 30, 1997 and its Reports on Form 8-K dated May 27,
1997 and February 19, 1997, and reported in more condensed form
below, the Plant experienced a number of operational and
regulatory problems and has been shut down since December 6,
1996. The decision to close the Plant permanently was based on
an economic analysis of the costs, risks and uncertainties
associated with operating the Plant compared to those associated
with closing and decommissioning it. The Plant's operating
license from the NRC was scheduled to expire on October 21, 2008.
RECENT OPERATING HISTORY - The Plant generally provided reliable
and low-cost power from the time it commenced operations in late
1972 to 1995. Beginning in early 1995, however, Maine Yankee
encountered various operational and regulatory difficulties with
the Plant. In 1995, the Plant was shut down for almost the
entire year to repair a large number of steam generator tubes
that were exhibiting defects. Shortly before the Plant was to go
back on-line in December 1995, a group with a history of opposing
nuclear power released an undated, unsigned, anonymous, letter
alleging that in 1988 Yankee Atomic (then an affiliated
consultant of Maine Yankee) and Maine Yankee had used the results
of a faulty computer code as a basis to apply to the NRC for an
increase in the Plant's power output. In response to the
allegation, on January 3, 1996, the NRC issued a Confirmatory
Order that restricted the Plant to 90 percent of its licensed
thermal operation level, which restriction was still in effect
when the Plant was permanently shut down.
As a result of the controversy associated with the
allegations, the NRC, at the request of the Governor of Maine,
conducted an intensive Independent Safety Assessment ("ISA") of
the Plant in the summer and fall of 1996. On October 7, 1996,
the NRC issued its ISA report, which found that while the Plant
had been operated safely, there were weaknesses that needed to be
addressed, which would require substantial additional spending by
Maine Yankee. On December 10, 1996, Maine Yankee responded to
the ISA report, acknowledge many of the weaknesses, and
committed to revising its operations and procedures to address
the NRC's criticisms.
Another result of the controversy associated with the
allegations was an investigation of Maine Yankee initiated by the
NRC's Office of Investigations ("OI"), which, in turn, referred
certain issues to the United States Department of Justice ("DOJ")
for possible criminal prosecution. Subsequently, on September
27, 1997, the DOJ, through the United States Attorney for Maine,
announced that its review had revealed no grounds for criminal
prosecution. The Company believes that the OI investigation,
however, could ultimately result in the imposition of civil
penalties, including fines, on Maine Yankee.
In 1996 the Plant was generally in operation at the 90-
percent level from late January to early December, except for a
two-month outage from mid-July to mid-September. The Plant was
shut down again on December 6, 1996, to address several concerns,
and has not operated since then. The precipitating event causing
the shutdown was the need to evaluate and resolve cable-
separation compliance issues, and on December 18, 1996, the NRC
issued a Confirmatory Action Letter requiring the Plant to remain
shut down until Maine Yankee's plan for resolving the cable-
separation issues was accepted by the NRC. Subsequently, Maine
Yankee uncovered additional issues, including among others, the
possibility of having to replace defective fuel assemblies,
address additional cable-separation issues, and determine the
condition of the Plant's steam generators, all of which
contributed to further operational uncertainty. On January 29,
1997, the Plant was placed on the NRC's Watch List, and on
January 30, 1997, the NRC issued a supplemental Confirmatory
Action Letter requiring the resolution of additional concerns
before the Plant could be restarted.
In December 1996 Maine Yankee requested proposals from
several utilities with large and successful nuclear programs to
provide a management team, and ultimately contracted with Entergy
Nuclear, Inc., effective February 13, 1997, for management
services that included providing a new president and regulatory
compliance officer. The Entergy-provided management team made
progress in addressing technical issues, but a number of
operational and regulatory uncertainties remained. On May 27,
1997, the Board of Directors of Maine Yankee voted to minimize
spending while preserving the options of restarting the Plant or
conveying ownership interests to a third party. After
unsuccessful negotiations with one prospective purchaser, Maine
Yankee found no other interest in purchasing the Plant and, based
on its economic analysis, closed the Plant permanently.
As required by the NRC, on August 7, 1997, Maine Yankee
certified to the NRC that Maine Yankee had permanently ceased
operations and that all fuel assemblies had been permanently
removed from the Plant's reactor vessel. On August 27, 1997,
Maine Yankee filed the required Post-Shutdown Activities Report
with the NRC, describing its planned post-shutdown activities and
a proposed schedule.
MANAGEMENT AUDIT - On September 2, 1997, the MPUC released the
report of a consultant it had retained to perform a management
audit of Maine Yankee for the period January 1, 1994, to June 30,
1997. The report contained both positive and negative
conclusions, the latter including: that Maine Yankee's decision
in December 1996 to proceed with the steps necessary to restart
the Plant was "imprudent", that Maine Yankee's May 27, 1997
decision to reduce restart expenses while exploring a possible
sale of the Plant was "inappropriate", based on the consultant's
finding that a more objective and comprehensive competitive
analysis at that time "might have indicated a benefit for
restarting" the Plant; and that those decisions resulted in Maine
Yankee incurring $95.9 million in "unreasonable" costs. On
October 24, 1997, the MPUC issued a Notice of Investigation
initiating an investigation of the shutdown decision and of the
operation of the Plant prior to shutdown, and announced that it
had directed its consultant to extend its review to include those
areas. The Company believes the report's negative conclusions
are unfounded and may be contradictory. The Company has been
charging its share of the Maine Yankee expenses against income,
and believes it would have substantial constitutional and
jurisdictional grounds to challenge any effort in an MPUC
proceeding to alter wholesale Maine Yankee rates made effective
by the FERC. On November 7, 1997, Maine Yankee initiated a legal
challenge to the MPUC investigation in the Maine Supreme Judicial
Court alleging that such an investigation falls exclusively
within the jurisdiction of the FERC and that the MPUC
investigation is therefore barred on constitutional grounds. The
Company filed a similar legal challenge on the same day. The
MPUC subsequently stayed its investigation pending the outcome of
Maine Yankee's FERC rate case, in which the MPUC is
participating, while indicating that its consultant would
continue its extended review.
MAINE YANKEE DEBT RESTRUCTURING AND FERC RATE PROCEEDING - Maine
Yankee entered into agreements in August 1997 with the holders of
its outstanding First Mortgage Bonds and its lender banks (the
"Standstill Agreements") under which the bondholders and banks
agreed that they would not assert that the August 1997 voluntary
permanent shutdown of the Plant constituted a covenant violation
under Maine Yankee's First Mortgage Indenture or its two bank
credit agreements. The parties also agreed in the Standstill
Agreements to maintain Maine Yankee's bank borrowing at a level
below that of the prior aggregate bank commitments, which level
Maine Yankee considered adequate for its foreseeable needs. The
Standstill Agreements, as extended in October 1997, were to
terminate on January 15, 1998, by which date Maine Yankee was to
have reached agreement on restructured debt arrangements
reflecting its decommissioning status. On November 6, 1997,
Maine Yankee filed a rate proceeding with the FERC reflecting the
Plant's decommissioning status and requesting an effective date
of January 15, 1998, for the amendments to Maine Yankee's Power
Contracts and Additional Power Contracts, which revise Maine
Yankee's wholesale rates and clarify and confirm the obligations
of Maine Yankee's sponsors to continue to pay their shares of
Maine Yankee's costs during the decommissioning period.
On January 14, 1998, the FERC issued an "Order Accepting for
Filing and Suspending Power Sales Contract Amendment, and
Establishing Hearing Procedures" (the "FERC Order") in which the
FERC accepted for filing the rates associated with the amended
Power Contracts and made them effective January 15, 1998, subject
to refund. The FERC also granted intervention requests,
including among others, those of the MPUC, Maine Yankee's largest
bondholder, and two of its lender banks, denied the request of an
intervenor group to summarily dismiss part of the filing, and
ordered that a public hearing be held concerning the prudence of
Maine Yankee's decision to shut down the Plant and on the
justness and reasonableness of Maine Yankee's proposed rate
amendments. The Company expects the prudence issue to be pursued
vigorously by several intervenors, including among others the
MPUC, which stayed its own prudence investigation pending the
outcome of the FERC proceeding after the jurisdictional challenge
by Maine Yankee and the Company discussed above. The Company
cannot predict the outcome of the FERC proceeding.
On January 15, 1998, Maine Yankee, its bondholders and
lender banks revised the Standstill Agreements and extended their
term to April 15, 1998, subject to satisfying certain milestone
obligations during the term of the extension. One such
obligation was that Maine Yankee must have accepted, by February
12, 1998, an underwritten commitment to refinance its bonds and
bank debt, subject only to closing conditions reasonably capable
of being satisfied by April 15, 1998, and reasonably satisfactory
to the bondholders and banks. Maine Yankee accepted such a
commitment prior to the deadline, received regulatory approval of
the refinancing on March 9, 1998, and is negotiating final loan
documentation and preparing for a closing before April 15.
OTHER MAINE YANKEE SHAREHOLDERS - Higher nuclear-related costs
are also affecting other stockholders of Maine Yankee in varying
degrees. Central Maine Power Company, the largest individual
stockholder in Maine Yankee with a 38% ownership interest,
reported in February, 1998 that it expected to require an
additional retail rate increase under its MPUC-approved
Alternative Rate Plan due to its poor financial performance
resulting from increased Maine Yankee-related obligations. Under
that Alternative Rate Plan, Central Maine is permitted to recover
through a retail rate increase only one half of the difference
between the low end of return on equity bandwidth of 7.05% and
its reported 1997 earnings of 1.04%. Maine Public Service
Company, a 5% stockholder, cited problems in satisfying financial
covenants in loan documents, reduced its common stock dividend
substantially in early March 1997 and obtained rate relief.
Northeast Utilities (20% stockholder through three subsidiaries),
which is also adversely affected by the substantial additional
costs associated with the three shut-down Millstone nuclear units
and the permanently shut-down Connecticut Yankee unit, as well as
significant regulatory issues in Connecticut and New Hampshire,
has implemented an indefinite suspension of its quarterly common
stock dividends. Largely as a result of nuclear-related costs,
Northeast Utilities reported a loss of $135 million for 1997 and
continues to experience difficulty in satisfying loan covenants.
A default by a Maine Yankee stockholder in making payments under
its Power Contract or Capital Funds Agreement could have a
material adverse effect on Maine Yankee, depending on the
magnitude of the default, and would constitute a default under
Maine Yankee's bond indenture and its two major credit agreements
unless cured within applicable grace periods by the defaulting
stockholder or other stockholders. The Company cannot predict,
however, what effect, if any, the financial difficulties being
experienced by some Maine Yankee stockholders will have on Maine
Yankee or the Company.
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 a 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. The DOE has indicated that the permanent
disposal site is not expected to open before 2010, although
originally scheduled to open in 1998.
On April 15, 1997, the United States Senate approved
the"Nuclear Waste Policy Act of 1997", (S. 104), which would
reform the federal policy for managing spent nuclear fuel and
instruct the DOE to develop an integrated management system,
including a central storage facility, for such fuel. The bill
would require the DOE to accept such nuclear fuel from commercial
nuclear power plants and would establish a licensing process that
would result in the storage of such fuel at a central federal
facility beginning no later than June 30, 2003, if all the
necessary approvals are obtained. The DOE would also be required
to continue site characterization work at Yucca Mountain as a
permanent disposal site. On October 30, 1997, the House of
Representatives approved a bill (H.R. 1270) with generally
similar objectives. Action to resolve the differences in the two
bills was deferred to 1998.
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 of 1982
required the DOE to take responsibility for spent nuclear fuel in
1998. On July 23, 1996, the court held that the DOE is obligated
"to start disposing of [spent nuclear fuel] no later than January
31, 1998." The DOE did not appeal the decision, but announced in
December 1996 that it anticipated it would be unable to start
accepting spent nuclear fuel for disposal by January 31, 1998. A
large number of nuclear utilities and state regulators filed a
new lawsuit against the DOE in January 1997 seeking to force the
DOE to honor its obligation to store spent nuclear fuel and
seeking other appropriate relief. On November 14, 1997, the U.S.
Court of Appeals for the District of Columbia Circuit confirmed
the DOE's obligation. On February 19, 1998, Maine Yankee filed a
petition in the same court seeking to compel the DOE to take
Maine Yankee's spent fuel from the Plant site "as soon as
physically possible," alleging that removing the spent fuel on
the DOE's indicated schedule would delay the decommissioning of
the Maine Yankee Plant indefinitely. The Company cannot predict
the ultimate results of the lawsuits.
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.
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. Maine Yankee, in recognition of the
reduced risk posed by the shutdown and defueled nuclear reactor,
reduced the amount of excess nuclear property damage insurance
purchased from the nuclear electric utility insurance company,
effective September 15, 1997, from $2.25 billion to $560 million.
This reduced the total amount of nuclear property damage coverage
to $1.06 billion, the minimum amount of nuclear property damage
insurance then required by regulation. 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 $560 million is
provided by a nuclear electric utility industry insurance company
through a combination of current premiums, retrospective premium
assessments and reinsurance. 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.
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 compact provides for Texas to take
Maine's low-level waste over a 30-year period for disposal at a
planned facility in west Texas. In return, Maine would be
required to pay $25 million, assessed to Maine Yankee by the
State of Maine, payable in two equal installments, the first
after ratification by Congress and the second upon commencement
of operation of the Texas facility. In addition, the company
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 ceased operations in 1994.
The compact is before the Congress for ratification and was
approved by the House Of Representatives in October 1997. The
Senate has deferred action on the bill until 1998. Since the
Plant has permanently stopped operating, the compact is less
beneficial to Maine Yankee than it would have been if the Plant
had remained in operation, due to the new schedule for Maine
Yankee's shipments and the anticipated schedule for opening the
Texas facility. Maine Yankee cannot predict whether the final
required ratification of the Texas compact or other regulatory
approvals 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 costs that are unrelated to
the decommissioning and dismantlement of the Plant site could
generally be considered to be operation and maintenance costs to
be recovered through Maine Yankee's billing process.
Site characterization work at the Plant site, an initial
part of the decommissioning process, and related activities could
give rise to additional environmental issues.
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 ("MDEP") 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 MDEP that it
was investigating the cleanup of several sites in Maine that were
used in the past for the disposal of waste oil and other
hazardous substances, and that the Company, as a generator of
waste oil that was disposed at those sites, may be liable for
certain cleanup costs. The Company learned in October 1995 that
the EPA placed one of the sites on the National Priorities List
("NPL") under the Comprehensive Environmental Response,
Compensation, and Liability Act.
With respect to the NPL site, the Company was one of 15 PRPs
to receive a Special Notice from the EPA in May 1997, requiring
reimbursement of past costs, amounting to $5,639,780, as well as
future costs at the site. The Special Notice also urged the PRPs
to enter into an Administrative Order on Consent to conduct or
finance response actions at the site. In response to the Special
Notice, a group of PRPs, including Bangor Hydro, is close to
signing an agreement with the EPA to fund ongoing monitoring at
the site. The Company's share of this effort is expected to be
approximately $20,000. According to the EPA's volumetric
ranking, the Company's ranks 13th with a total contribution to
the site of 1.10781 percent.
As to the other site, which has been listed by the MDEP as
an Uncontrolled Hazardous Substance Site, the Company is
considered a de minimis generator.
The Company estimates that during 1998 it will spend
approximately $370,000 in operations expenses and $75,000 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 54 President & Chief
Executive
Officer since
January 1991
Carroll R. Lee 48 Senior Vice
President and
Chief Operating Officer
since
December, 1996
Frederick S. Samp 47 Vice President-Finance &
Law since 1995; Treasurer
since
1995; Chief Financial
Officer
since 1995
Paul A. LeBlanc 50 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, 1997, there were 6,868 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
DECLARED
FISCAL PERIOD HIGH LOW PER SHARE
- ------------- ---- --- ---------
1996
- ----
First Quarter................ $12 1/2 $10 1/4 $.18
Second Quarter............... 11 10 .18
Third Quarter................ 10 3/ 9 7/8 .18
Fourth Quarter............... 10 3/8 9 1/4 .18
1997
- ----
First Quarter................ $9 1/2 $6 $.00
Second Quarter............... 6 1/4 4 7/8 .00
Third Quarter................ 6 3/8 5 1/4 .00
Fourth Quarter............... 6 11/16 5 1/16 .00
1998
- ----
First Quarter
(through March 20, 1998).. $8 1/2 $6 1/4 $.00
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 its March 19, 1997 meeting,
the Board of Directors determined that the payment of common stock dividends
should be suspended, and to date, no additional common stock dividend has
been declared.
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 50% of its
earnings applicable to common stock in any calendar year.
ITEM 6
- ------
SELECTED FINANCIAL DATA
- -----------------------
SIX YEAR STATISTICAL SUMMARY
Bangor Hydro-Electric Company
1997 1996 1995 1994 1993 1992
- --------------------------------------------------------------------------------------------------------------------------
MEGAWATT HOURS (MWH) GENERATED AND PURCHASED
Hydro Generation (Company) 262,377 321,532 275,810 271,616 275,694 305,011
Nuclear Generation (Maine Yankee) - 348,719 13,606 456,871 395,665 368,641
Oil (Company) 69,580 26,912 50,706 35,759 47,115 80,770
Biomass/Refuse 159,990 163,279 177,558 190,218 281,260 307,451
NEPOOL/Other Purchases 1,583,093 1,359,116 1,540,530 958,363 937,431 767,306
- --------------------------------------------------------------------------------------------------------------------------
Total Generated & Purchased 2,075,040 2,219,558 2,058,210 1,912,827 1,937,165 1,829,179
Less Line Losses and Company Use 141,426 140,128 136,908 135,561 131,764
- --------------------------------------------------------------------------------------------------------------------------
Remainder - MWH sold 2,075,040 2,078,132 1,918,082 1,775,919 1,801,604 1,697,415
==========================================================================================================================
CLASSIFICATION OF SALES - MWH
Residential 533,161 536,490 513,076 516,470 515,242 521,889
Commercial 523,043 512,433 511,720 507,285 500,488 490,861
Industrial 680,226 647,985 686,386 611,876 615,314 563,734
Lighting 8,780 8,945 9,547 9,416 9,590 9,876
Wholesale 3,841 4,486 10,961 11,705 10,311 10,462
- --------------------------------------------------------------------------------------------------------------------------
Total MWH Billed to Customers 1,749,051 1,710,339 1,731,690 1,656,752 1,650,945 1,596,822
Unbilled Sales - Net Increase (Decrease) 33,011 2,998 4,658 6,366 2,001 (11,832)
- --------------------------------------------------------------------------------------------------------------------------
Total Delivered Sales (MWH) 1,782,062 1,713,337 1,736,348 1,663,118 1,652,946 1,584,990
(Less) Interruptible Sales 265,438 237,553 295,818 231,128 254,359 208,066
- --------------------------------------------------------------------------------------------------------------------------
Total Firm Delivered Sales (MWH) 1,516,624 1,475,784 1,440,530 1,431,990 1,398,587 1,376,924
Off-System Sales 145,680 364,795 181,734 112,801 148,658 112,425
- --------------------------------------------------------------------------------------------------------------------------
Total Energy Sales (MWH) 1,927,742 2,078,132 1,918,082 1,775,919 1,801,604 1,697,415
==========================================================================================================================
ELECTRIC OPERATING REVENUES AND EXPENSES (000'S)
OPERATING REVENUES
Residential 67,532 $ 66,805 $ 66,061 $ 64,008 $ 64,244 $ 66,429
Commercial 55,965 54,168 55,030 53,410 53,599 53,806
Industrial 41,356 38,947 39,929 37,040 39,508 39,340
Lighting 2,065 2,032 2,051 2,010 1,915 1,933
Wholesale 310 314 859 937 903 895
- --------------------------------------------------------------------------------------------------------------------------
Total Revenue From Customers 167,228 $ 162,266 $ 163,930 $ 157,405 $ 160,169 $ 162,403
Unbilled Sales-Net Increase (Decrease) 2,375 408 210 1,450 (237) (964)
- --------------------------------------------------------------------------------------------------------------------------
Total Revenue 169,603 $ 162,674 $ 164,140 $ 158,855 $ 159,932 $ 161,439
(Less) Interruptible Revenue 11,215 9,537 11,149 8,450 8,876 8,331
- --------------------------------------------------------------------------------------------------------------------------
Total Firm Revenue 158,388 $ 153,137 $ 152,991 $ 150,405 $ 151,056 $ 153,108
Off-System Revenue 13,615 18,384 14,098 12,750 15,326 13,857
- --------------------------------------------------------------------------------------------------------------------------
Total Operating Revenues 183,218 $ 181,058 $ 178,238 $ 171,605 $ 175,258 $ 175,296
==========================================================================================================================
OPERATING EXPENSES
Fuel Used in Generation 92,792 $ 78,477 $ 98,684 $ 104,132 $ 116,386 $ 114,943
Operating and Maintenance Expense 32,471 32,441 35,711 33,498 29,474 27,042
Depreciation and Amortization 35,104 29,965 20,544 10,333 6,447 6,789
Taxes 3,168 10,249 6,306 8,803 8,866 9,499
- --------------------------------------------------------------------------------------------------------------------------
Total Operating Expenses 163,535 $ 151,132 $ 161,245 $ 156,766 $ 161,173 $ 158,273
==========================================================================================================================
SUMMARY OF OPERATIONS (000'S)
Operating Revenue 187,324 $ 187,374 $ 184,914 $ 174,098 $ 177,972 $ 176,789
Operating Expenses 163,535 151,132 161,245 156,766 161,173 158,273
Other Income (including equity AFDC) 1,292 1,466 760 1,308 (2,657)* 1,690
Interest Expense (net of borrowed AFDC) 25,467 26,425 20,092 11,183 8,805 9,952
- --------------------------------------------------------------------------------------------------------------------------
Net Income (386) $ 11,283 $ 4,337 $ 7,457 $ 5,337 * $ 10,254
Less Preferred Dividends 1,376 1,537 1,702 1,652 1,646 1,613
- --------------------------------------------------------------------------------------------------------------------------
Earnings on Common Stock (1,762) $ 9,746 $ 2,635 $ 5,805 $ 3,691 * $ 8,641
==========================================================================================================================
SELECTED FINANCIAL DATA
Total Assets (000's) 600,583 $ 556,629 $ 566,076 $ 381,250 $ 373,521 $ 288,867
ELECTRIC PLANT (000'S)
Total Electric Plant 358,878 $ 341,526 $ 323,664 $ 303,637 $ 281,606 $ 255,601
Depreciation Reserve 96,595 87,736 81,934 75,667 71,184 67,645
- --------------------------------------------------------------------------------------------------------------------------
Net Electric Plant 262,283 $ 253,790 $ 241,730 $ 227,970 $ 210,422 $ 187,956
==========================================================================================================================
CAPITALIZATION (000'S)
Short-Term Debt 34,000 $ 32,500 $ 35,000 $ 27,000 $ 36,000 $ 15,000
Long-Term Debt 243,643 274,221 288,075 116,367 119,126 100,685
Redeemable Preferred Stock 9,137 10,670 12,070 13,740 15,168 15,102
Preferred Stock 4,734 4,734 4,734 4,734 4,734 4,734
Common Equity 106,558 108,321 103,192 105,658 93,944 82,230
- --------------------------------------------------------------------------------------------------------------------------
Total 398,072 $ 430,446 $ 443,071 $ 267,499 $ 268,972 $ 217,751
==========================================================================================================================
CAPITAL STRUCTURE RATIOS (%)
Short-Term Debt 8.5% 7.5% 7.9% 10.1% 13.4% 6.9%
Long-Term Debt 61.2% 63.7% 65.0% 43.5% 44.3% 46.2%
Preferred Stock 3.5% 3.6% 3.8% 6.9% 7.4% 9.1%
Common Stock 26.8% 25.2% 23.3% 39.5% 34.9% 37.8%
- --------------------------------------------------------------------------------------------------------------------------
Total 100.0% 100.0% 100.0% 100.0% 100.0% 100.0%
==========================================================================================================================
MISCELLANEOUS STATISTICS
Shares Outstanding (Average) 7,363,424 7,336,174 7,264,360 6,947,746 5,862,411 5,393,306
Shares Outstanding (Year End) 7,363,424 7,363,424 7,301,557 7,185,143 6,225,394 5,420,955
Number of Stockholders (Year End) 6,868 7,734 8,250 7,705 7,511 7,325
Earnings per Common Share -0.24 $ 1.33 $ 0.36 $ 0.84 $ 0.63 * $ 1.60
Dividends Declared per Common Share - $ 0.72 $ 0.87 $ 1.32 $ 1.32 $ 1.32
Book Value per Common Share 14.47 $ 14.71 $ 14.13 $ 14.71 $ 15.09 $ 15.17
Return on Common Equity -1.64% 9.09% 2.51% 5.55% 3.99%* 10.60%
Ratio of AFDC to Common Stock Earnings -48% 12% 48% 45% 143%* 28%
Ratio of Earnings to Fixed Charges 0.86 1.50 1.14 1.49 1.04 * 1.96
Payout Ratio - 54% 242% 157% 210%* 82.5
Percentage of Construction Expenditures
Funded Internally 100% 100% 100% 86% 72% 70%
==========================================================================================================================
RESIDENTIAL CUSTOMER DATA
Average Number of Customers 90,433 89,769 86,194 85,041 84,211 83,305
Kilowatt-Hours per Customer 5,896 5,976 5,953 6,073 6,118 6,265
Revenue per Customer 746.76 $ 744.19 $ 766.42 $ 752.67 $ 762.89 $ 797.42
Revenue per Kilowatt-Hour in cents 12.67 12.45 12.88 12.39 12.47 12.73
==========================================================================================================================
MISCELLANEOUS SYSTEM DATA
Net System Capability at Time of Peak
(MW) Firm 344.44 373.04 330.01 340.45 341.17 342.39
System Peak Demand (MW) (Winter Peak) 277.06 274.32 267.98 275.84 267.42 253.27
Reserve Margin at Time of Peak 24.0% 36.0% 23.2% 23.4% 27.6% 35.2%
System Load Factor 79.0% 77.0% 79.9% 73.5% 76.4% 77.2%
==========================================================================================================================
* Includes the reserve established on certain licensing activites in 1993 ($5.6 million after taxes or $.95 per common
share). (See note 6).
ITEM 7
- ------
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND
FINANCIAL CONDITION
RECENT EVENTS AFFECTING THE ELECTRIC UTILITY INDUSTRY AND THE COMPANY
RESTRUCTURING THE INDUSTRY - Over the last several years, there have
been a number of legislative and regulatory initiatives throughout the
United States designed to restructure the traditional vertically
integrated electric utility industry. These initiatives typically
encourage or require the disaggregation of existing electric utility
functions into transmission and distribution activities on the one hand
and electrical generation and marketing activities on the other. They
are intended to introduce competition into markets for the production
and supply of electric energy while maintaining transmission and
distribution systems owned and maintained by more traditionally
regulated utilities. This industry restructuring poses a number of
logistical and policy questions including 1) the most efficient way to
spin-off electric generation and related assets from existing electric
utilities, 2) the extent to which existing utilities can or should be
permitted to participate in the competitive markets, 3) the extent to
which the remaining transmission and distribution utilities should be
allowed to recover through rates charged to their customers costs that
have been incurred in order to meet their historical public service
obligations but become "stranded" by the introduction of competition
into traditionally regulated markets, 4) the mechanisms through which
those stranded costs can best be recovered and 5) the uninterrupted
supply of electric energy for those consumers who do not or cannot
arrange independently for the purchase of electric energy.
In 1995, the Maine Legislature initiated a process for the development
of electric utility restructuring that culminated in "An Act to
Restructure the State's Electric Industry", which the Governor signed
into law on May 29, 1997. The principal provisions of the new law are
as follows:
1) Beginning on March 1, 2000, all consumers of electricity shall have
the right to purchase generation services directly from competitive
electricity suppliers who will not be subject to rate regulation.
2) By March 1, 2000, the Company must divest of all generation related
assets and business functions except for:
a) contracts with "qualifying facilities" (generally, those non -
utility generators from whom the Company was required to purchase what
turned out to be high - cost power generated by renewable resources
pursuant to the Public Utilities Regulatory Policies Act of 1978
(PURPA)) and conservation providers;
b) nuclear assets, namely, the Company's investment in the Maine Yankee
Atomic Power Company nuclear generating plant (Maine Yankee);
c) assets that the Maine Public Utilities Commission (MPUC) determines
necessary for the operation of the transmission and distribution
services.
The MPUC may grant an extension of the divestiture deadline if the
extension will improve the selling price. For assets not divested, the
utilities are required to sell the rights to the energy and capacity
from these assets. The Company must submit to the MPUC its divestiture
plan no later than January 1, 1999. The Company's plan has already been
submitted.
3) Billing and metering services will be subject to competition
beginning March 1, 2002, but the legislation permits the MPUC to
establish an earlier date, no sooner than March 1, 2000.
4) The Company, through an unregulated affiliate, may market and sell
electricity both within and outside its current service territory, but
limited to 33% of the load within the Company's service territory. In
addition, such an unregulated affiliate could not, itself, own any
generation assets.
5) The Company will continue to provide transmission and distribution
services which will continue to be subject to regulation by the MPUC.
6) If after March 1, 2000, 10% or more of the stock of a regulated
transmission and distribution utility is purchased by an entity, the
purchasing entity and any related entity may not sell or offer for sale
generation service to any retail customer of electric energy in the
state of Maine. In addition, if the transmission and distribution
utility has a marketing affiliate (see item 4 above), the MPUC might
require divestiture of that affiliate.
7) Maine electric utilities will be permitted a reasonable opportunity
to recover legitimate, verifiable and unmitigable costs that are
otherwise unrecoverable as a result of retail competition in the
electric utility industry (the so-called "stranded costs"). The MPUC
shall determine these stranded costs by considering:
a) the utility's regulatory assets related to generation;
b) the difference between net plant investment in generation assets
compared to the market value for those assets; and
c) the difference between future contract payments and the market value
of the purchased power contracts.
The Company must pursue all reasonable means to reduce its potential
stranded costs and to receive the highest possible value for generation
assets and contracts, including the exploration of all reasonable and
lawful opportunities to reduce the cost to ratepayers of contracts with
qualifying facilities. By July 1, 1999, the MPUC must estimate the
stranded costs for the Company and the manner for the collection of
those costs by the transmission and distribution company. Customers
reducing or eliminating their consumption of electricity by switching
to self-generation, conversion to alternative fuels or using demand-
side management measures cannot be assessed exit or entry fees. The
MPUC must include in the rates charged by the transmission and
distribution utility decommissioning expenses for Maine Yankee. In 2003
and every three years thereafter until the stranded costs are
recovered, the MPUC must review and reevaluate the stranded cost
recovery.
8) All competitive providers of retail electricity must be licensed and
registered with the MPUC and meet certain financial standards, comply
with customer notification requirements, adhere to customer
solicitation requirements and are subject to unfair trade practice
laws. Competitive electricity providers must have at least 30% of the
electricity that they sell at retail in Maine derived from renewable
resources (such as most types of hydroelectric plants and plants that
would be qualifying facilities under PURPA).
9) A standard-offer service will be available for all customers. If the
Company were to have an unregulated affiliate competitive electricity
provider, it would be prohibited from providing more than 20% of the
load within the Company's service territory under the standard - offer
service.
10) An unregulated affiliate of the Company marketing and selling
retail electric power must adhere to specific codes of conduct,
including, among others:
a) employees of the unregulated affiliate providing retail electric
power must be physically separated from the regulated distribution
affiliate and cannot be shared;
b) the regulated transmission and distribution affiliate must provide
equal access to customer information;
c) the regulated transmission and distribution company cannot
participate in joint advertising or marketing programs with the
unregulated affiliate providing retail electric power;
d) the transmission and distribution company and its unregulated
affiliated provider of retail electric power must keep separate books
of accounts and records; and
e) the transmission and distribution company cannot condition or tie
the provision of any regulated service to the provision of any service
provided by the unregulated affiliated provider of electricity.
11) Employees, other than officers, displaced as a result of retail
competition will be entitled to certain severance benefits and
retraining programs. These costs will be recovered through charges
collected by the regulated transmission and distribution company.
12) Other provisions of the new law include provisions for:
a) consumer education;
b) continuation of low-income programs and demand-side management
activities;
c) consumer protection provisions;
d) new enforcement authority for the MPUC to protect consumers.
In view of the Maine restructuring legislation, the Company has been
reviewing and revising its business plans. The Company believes its
basic business will continue to be as a regulated transmission and
distribution utility. The Company will also pursue opportunities in
other regulated or unregulated business activities that are compatible
with the Company's basic business. The Company presently believes that
it will be less likely to engage in activities that would require
isolation from its basic business, such as the approach the
restructuring law has taken governing the relationship between a
regulated transmission and distribution utility and any affiliated
entity intending to engage in marketing and selling electricity. The
Company has made no final determination whether it will establish such
an affiliate in order to continue the marketing and selling of
electricity after March 1, 2000.
MAINE YANKEE - The Company owns 7% of the common stock of Maine Yankee,
which owns and, prior to its permanent closure in 1997, operated an 880
megawatt (MW) nuclear generating plant in Wiscasset, Maine. The
Company's equity ownership in the plant entitled the Company to about
7% of the output pursuant to a cost-based power contract. Since the
plant began operation in 1972, it has provided a source of power for
the Company and its customers at a cost consistently below the cost of
power otherwise available in bulk power markets.
Following a year long shutdown for repairs to the steam generators in
1995, Maine Yankee came 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 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 included compliance with NRC regulations, conformance
of the plant to design specifications, adequacy and condition of
components and systems, and management issues. During the evolution of
these events, the NRC itself became subject to public criticism about
the adequacy of its regulatory activities and its relationship with
nuclear plant licensees, and in response, the NRC implemented changes
in its approach to oversight of licensees that had the effect of
amplifying the regulatory scrutiny.
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. In early December 1996 the
plant was shut down to address cable-separation and associated issues.
Subsequently, 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 outage into a refueling outage. During
this extended outage, the plant owners analyzed in-depth the viability
of continued operation of the plant. While the plant was shut down, the
Company incurred incremental replacement power costs of approximately
$1 million per month in addition to its 7% share of the costs expended
in the owners' efforts to return the plant to service. On May 27, 1997,
the Board of Directors of Maine Yankee voted to reduce maintenance and
repair spending at the plant and announced that Maine Yankee was
considering permanent closure based on economic concerns and
uncertainty about operation of the plant. On August 6, 1997, the Board
voted to cease power operations at the plant permanently and to begin
the process of decommissioning the plant. The decision to shut down the
plant was based on an economic analysis of the costs, risks and
uncertainties associated with operating the plant compared to those
associated with closing and decommissioning the plant. The decision to
close the plant should mitigate the costs the Company would otherwise
incur through a phasing down of Maine Yankee's operations and
maintenance costs. The need to purchase replacement power will
continue.
Maine Yankee's most recent estimate of the total costs of
decommissioning and plant closure, excluding funds already collected,
is $930 million (undiscounted). The Company's share of this estimated
cost is $65.1 million and was recorded as a regulatory asset and
decommissioning liability at September 30, 1997.
In a related matter, in early September, 1997, the MPUC released the
report of a consultant it had retained to perform a management audit of
Maine Yankee for the period January 1, 1994 to June 30, 1997. The
report contained both positive and negative conclusions, the latter
explaining that: Maine Yankee's decision in December, 1996, to proceed
with the steps necessary to restart its nuclear generating plant at
Wiscasset, Maine, was "imprudent"; that Maine Yankee's May 27, 1997,
decision to reduce restart expenses while exploring a possible sale of
the plant was "inappropriate," based on the consultant's finding that a
more objective and comprehensive competitive analysis at the time
"might have indicated a benefit for restarting" the plant; and that
those decisions resulted in Maine Yankee incurring $95.9 million in
"unreasonable" costs. If any of these costs are determined to have been
imprudently incurred, by FERC or the MPUC, the Company may be required
to write down a portion of its investment in Maine Yankee. On October
24, 1997, the MPUC issued a Notice of Investigation initiating an
investigation of the prudence of the Maine Yankee shutdown decision and
of the operation of Maine Yankee prior to the shutdown, and announced
that it had directed its consultant to extend its review to include
those areas.
On December 2, 1997, the MPUC issued an Order staying the
investigation. The MPUC noted that Maine Yankee had begun a rate
proceeding before the Federal Energy Regulatory Commission (FERC) on
November 6, 1997, which could address the prudence issues raised in the
MPUC's investigation. The MPUC therefore stayed its investigation in
order "to avoid unnecessary duplicative efforts by all parties
involved". The MPUC reserved the right to reopen the investigation
particularly if FERC declines to address the prudence issues of concern
to the Commission "if we feel it necessary to further investigate these
matters after the FERC proceeding ends." The Company cannot therefore
predict whether the MPUC will reopen its investigation once the FERC
proceeding is concluded.
THE COMPANY'S RESPONSE TO PRESSURES CAUSED BY THE CLOSURE OF MAINE
YANKEE - The operational problems that have plagued Maine Yankee since
1995 and its final closure in 1997 have placed a significant strain on
the Company's financial resources and have had a substantially negative
impact on the Company's earnings in 1995, 1996 and 1997. The Maine
Yankee experience aggravated the financial pressure the Company was
already under as a result of its attempt to avoid rate increases,
expand its revenues through marketing efforts, and otherwise deal with
emerging competitive pressures. In response, the Company has reduced
its expenditures for ongoing operation and maintenance and for capital
improvements where it reasonably can. In addition, the Company focused
on three major areas - rate relief, restructuring another high-cost
power contract, and relations with its lenders - each of which is
discussed below.
RATE CASE - On March 3, 1997, the Company notified the MPUC of its
intent to file for a general increase in rates.
Under Maine law, a utility must ordinarily notify the MPUC two months
in advance of the filing of a request for a general increase in rates
and the MPUC then has nine months to investigate that request. However,
under certain circumstances, the MPUC may allow a utility to implement
a requested increase in rates on a temporary basis pending the
conclusion of its investigation of the utility's request for a general
increase in rates.
On April 1, 1997, the Company filed with the MPUC a Petition for
Temporary Rates to increase its rates by an amount that would increase
its annual revenues by $10 million effective June 1, 1997. In doing so,
the Company cited the continuing impact on the Company's financial
condition and cash flow of the ongoing outage at the Maine Yankee
nuclear power plant. The Company also cited potential noncompliance
with financial covenants contained in its bank credit agreement
(including the fixed charge coverage ratio, discussed below) and the
need to maintain adequate borrowing capacity for working capital
purposes, including mandatory debt repayments.
On June 26, 1997, the MPUC issued an order authorizing the Company to
change rates temporarily to increase its annual revenues by
approximately $5.1 million effective July 1, 1997. In doing so,
however, the MPUC also required the Company to accelerate the
amortization of the deferred regulatory asset associated with the 1993
buyout of one of its high-priced non-utility generator contracts. As a
result, revenue produced by the rate increase did not increase
earnings, but it did increase cash flow. Effective December 12, 1997,
the MPUC authorized the Company to revert to the original amortization
schedule of that deferred regulatory asset, thereby permitting the
temporary rate increase previously authorized to impact the Company's
earnings positively from that date on.
On February 9, 1998, the MPUC issued its final order on the Company's
request to increase its rates that it filed in March of 1997. Of the
approximately $22 million increase in annual revenue ultimately
requested by the Company, the MPUC authorized an increase of
approximately $13.2 million (which includes the 5.1 million temporary
rate increase discussed above) annually. While there are many factors
that explain the difference between the MPUC allowance and the
Company's requested increase, much of that difference is attributable
to the proposed accounting treatment of various costs and the deferral
of other costs for future consideration, including the deferral of
certain costs associated with Maine Yankee. While those accounting
recommendations will affect the timing of receipt of revenues by the
Company and will require the Company to finance the payment of the
associated costs, they should not significantly affect the Company's
earnings during the period that the new rates are effective.
The MPUC order is based upon a determination that the Company should be
allowed to earn an annual return of 12.75% on common equity. It also
includes a "rate plan" under which the Company's rates will be subject
to certain reconciliations based upon actual expenditures by the
Company and an annual adjustment beginning on May 1, 1999 to account
for inflation with an offset for assumed increases in productivity.
Other than those adjustments, the Company will not change its rates
unless its return on equity exceeds or falls short of the allowed
return by more than 350 basis points. If the Company's return on equity
falls outside of that bandwidth, 50% of the excess or shortfall will be
adjusted for in the Company's rates.
RESTRUCTURING OF POWER PURCHASE CONTRACT - The Company has been working
to restructure a power purchase contract with the Penobscot Energy
Recovery Company (PERC), its last remaining high-priced non-utility
generator contract that offers a potential for substantial savings.
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
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. The Company has reached an agreement with PERC and a
committee representing the municipalities that includes the following
major components:
1) The Company would make an up-front payment to PERC of $6 million and
installment payments over the next four years following consummation of
the transaction totalling an additional $4 million. These funds would
be retained by PERC to meet operation and debt service reserve
requirements of the PERC plant.
2) As of December 31, 1997, the PERC plant was financed in part by
tax-exempt municipal revenue bonds in the principal amount of $47.9
million payable pursuant to a sinking fund schedule and finally
maturing in 2004. The credit on those bonds is enhanced by letters of
credit issued by a group of banks. Those bonds would be restructured to
extend the maturity date to 20 years from the date of closing. The
bonds would continue to be tax-exempt and their credit would be
enhanced by the moral obligation of the state of Maine under the
auspices of the Finance Authority of Maine (FAME) pursuant to the State
of Maine's Electric Rate Stabilization Program. The extended maturity
of low-cost bonds would, therefore, provide savings to be shared by the
parties.
3) The Company would continue to purchase power at the rates
established under the existing PERC contract. Payments would be made to
a trust from which disbursements would be made according to the
following priorities:
a) debt service and expense, including all principal and interest;
b) trustee and bond related fees and expenses;
c) all operating and maintenance expenses of the PERC plant;
d) operating and management fees paid to the PERC partners pursuant to
a partnership operating agreement;
e) payment to the PERC owners of any savings in interest expense
resulting from the prepayment of bonds; and
f) except for cash reserve requirements, all remaining cash would be
distributed 1/3 to the Company, 1/3 to the PERC owners and 1/3 to the
participating municipalities.
4) The Company would issue warrants for the purchase of two million
shares of its common stock, one million each to the PERC owners and the
participating municipalities. The warrants would be exercisable within
ten years of their issuance and would entitle the holder to purchase
common stock for $7 per share (subject to adjustment under certain
circumstances). No warrants may be exercised within the first nine
months after their issuance, and they would become exercisable in
500,000 share blocks following the expiration of nine months, 21
months, 33 months and 45 months from the closing date. Upon exercise,
the Company would have the option, instead of providing common stock,
to pay cash equal to the difference between the then market price of
the stock and the exercise price of $7 per share times the number of
shares as to which exercise is made. The MPUC has established a cap on
ratepayers' exposure to the cost of the warrants. Ratepayer costs are
limited to the difference between the higher of $15 per share or the
book value per share at the time the warrants are exercised and the $7
exercise price. The Company would not recover any costs above the cap
from ratepayers.
5) The municipalities would extend their waste disposal contracts
through 2017 and waive their existing rights to an early termination or
the buyout of PERC.
There are a number of events upon which the proposed transaction is
contingent, including approval by the affected municipalities, the
rendering of an opinion by bond counsel that the PERC bonds will remain
tax-exempt and the financing of necessary cash payments by the Company.
The Company and the other parties to the transaction are tentatively
planning a closing in the spring of 1998.
Depending in part on the ultimate cost of the warrants, it is projected
that the restructured PERC contract will result in net cost savings
with a present value of $30 40 million over the remaining life of the
contract. That projection is based upon a number of assumptions about
future events and the markets for electricity.
EXISTING LENDING AGREEMENTS AND MONETIZATION OF POWER SALE CONTRACT -
The Company has been negotiating with interested parties the
monetization of a power sale contract with UNITIL Power Corp. (UNITIL),
a New Hampshire based electric utility. The Company currently provides
power to UNITIL at significantly above-market rates, with the contract
term ending in the year 2003. Based upon current projections of
wholesale electricity markets, it is expected that the rates charged
under the UNITIL contract will remain at above-market levels for the
remainder of the contract term. Therefore, the assignment of the
Company's rights under the contract has a positive present cash value.
The Company is currently proceeding to complete a transaction with a
financial institution pursuant to a letter of intent that would provide
a loan of approximately $25 million in net proceeds secured by the
value of the UNITIL contract. As discussed below, the proceeds of such
a transaction could be used to finance a portion of the contract
restructuring with PERC and to resolve outstanding financial covenant
issues under the Company's credit agreement with its lending banks.
The credit agreement with the Company's lending banks contains a number
of covenants keyed to the Company's financial condition and
performance. One such covenant requires the Company to maintain a
consolidated fixed charge ratio of 1.5 to 1.0 (defined as the ratio of
the sum of the Company's net income, income tax expense and interest
expense to the Company's interest expense, subject to a few minor
adjustments) and is measured quarterly for the prior four quarters.
After the first quarter of 1997, the Company was not in compliance with
the fixed charge ratio covenant. The Company obtained temporary waivers
of the noncompliance through June 6, 1997.
On June 6, 1997 the Company and the lending banks amended the credit
agreement. Under the amendment, compliance with the fixed charge ratio
covenant was permanently waived for the four quarters ending March 31,
1997 and June 30, 1997. The Company was also out of compliance with the
fixed charge ratio covenant for the four quarters ending September 30,
1997 and December 31, 1997 and has received temporary waivers of those
violations until March 31, 1998. On November 20, 1997, the Company and
the lending banks amended the agreement as part of a plan to reduce the
level of the banks' credit commitment and reestablish the financial
covenants to levels that the Company anticipates it can reasonably
achieve. Under the amendment (as subsequently modified), if the Company
monetizes the UNITIL contract as discussed above before March 31, 1998
in an amount that generates the net proceeds contemplated, it will be
permitted to proceed with the restructuring of its power purchase
contract with PERC and to use $6 million of the proceeds of the
monetization to complete the PERC transaction, with the remainder of
the proceeds to be used to reduce permanently the borrowing capacity of
the existing revolving credit facility. On or before December 31, 1998,
the Company must further reduce permanently the borrowing capacity
under the revolving credit facility by that additional $6 million. The
amendment also establishes new financial covenant levels that appear
reasonably achievable under the Company's current financial forecasts,
although there are a number of important variables that could affect
the Company's ability to meet those covenants in the future.
As of this writing, the monetization of the power sale contract with
UNITIL has not occurred, and only temporary waivers have been received
for the covenant violations for the four quarters ending September 30,
1997 and December 31, 1997. Consequently, the Company has classified
its $34 million of medium term notes as current liabilities as of
December 31, 1997. If the UNITIL transaction occurs, permanent waivers
will, pursuant to the credit agreement, become effective, and the
medium term notes will be reclassified as long-term liabilities.
The Company also anticipates that during 1998 or beyond, future cash
needs may exceed the borrowing capacity under the revolving credit
facility after the reductions described above, and accordingly, the
Company may be required to find new sources of financing. The Company
is in the process of exploring the alternatives available for such
additional sources of financing. The Company expects to be able to
obtain funds necessary to meet its obligations as they arise.
COMMON STOCK DIVIDENDS - 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 its March 19, 1997 meeting, the Board of Directors
determined that the payment of common stock dividends should be
suspended, and to date, no additional common stock dividend has been
declared.
STORM DAMAGE - Beginning on January 5, 1998, much of the state of Maine
experienced weather conditions that included snow, sleet and freezing
rain, culminating in a sleet storm on January 7, 8 and 9. Heavy icing
conditions caused trees to fall into power lines and also caused power
lines to fall from the added weight of the ice. Damage to transmission
and distribution equipment was widespread throughout the Company's
service territory. One of the Company's major transmission lines
serving the eastern part of its service territory was entirely
destroyed for a stretch of approximately eight miles. By January 9, an
estimated 60,000, or roughly 60%, of the Company's customers were
without power at the same time due to damage from the storm. The
Governor of Maine declared a state of emergency, and President Clinton
declared the state of Maine a federal disaster area.
The effort to restore power and repair transmission and distribution
equipment was extensive. Lineworkers and tree crews from throughout the
eastern United States and Canada participated in the effort, and by
January 18, power had been restored to all but a few of the Company's
customers. The cost of the restoration is still being determined but it
is expected to total as much as $5 million or more. The MPUC has issued
an order authorizing the Company to defer incremental storm damage
expenses for future recovery through the rates charged to customers.
The MPUC is expected to investigate the prudence of the costs incurred
and to establish a time frame for the recovery of the prudently
incurred costs. The Company believes its storm damage costs were
prudently incurred and that it should, therefore, be allowed to recover
them in rates.
PROPOSED GAS PROJECT -The Company and Energy Pacific, LLC (Energy
Pacific) have formed a joint-venture company, Bangor Gas Company, LLC,
that is currently seeking approval from the MPUC to build, own and
operate a natural gas distribution system to serve the greater Bangor
area.
Los Angeles-based Energy Pacific is a joint-venture of Pacific
Enterprises and Enova Corporation, which are in the process of a
corporate merger. Pacific Enterprises is the parent company of Southern
California Gas Company, the nation's largest natural gas distribution
company. Enova is the parent of San Diego Gas and Electric Company.
Together, the two companies provide natural gas to approximately six
million customers in California. Pacific Enterprises and the Company
worked together in a partnership to develop the West Enfield Hydro
Project in 1986.
Gas service to Maine will be made economically feasible for the first
time by the Maritimes and Northeast Pipeline Project, slated for
completion in mid-1999. The new pipeline will extend from the Sable
Offshore Energy Project near Sable Island, Nova Scotia, through the
state of Maine and interconnect with the Tennessee Gas Pipeline in
Dracut, Massachusetts. The route, as proposed, comes near the Bangor
area, providing an opportunity for retail gas distribution in the
greater Bangor marketplace.
Company officials estimate the cost to build and implement the new
Bangor Gas system to be approximately $40 million. The Company is not
obligated to make material capital contributions to the joint-venture
in the near term.
DIVESTITURE OF GENERATION ASSETS - On February 9, 1998, the Company
filed its plan for divesting its generation-related assets with the
MPUC in accordance with the electric utility industry restructuring
provisions signed into law last year. This plan could result in the
identification of proposed purchasers by mid-summer 1998. Further
regulatory approvals will then be required to actually complete the
sale. The Company is offering a total of 166 MW of generation assets.
OTHER - Management's discussion and analysis of results of operations
and financial condition contains items that are "forward-looking" as
defined in the Private Securities Litigation Reform Act of 1995. These
statements are subject to certain risks and uncertainties that could
cause actual results to differ materially from those anticipated in the
forward-looking statements. Readers should not place undue reliance on
forward-looking statements, which reflect management's view only as of
the date hereof. The Company undertakes no obligation to publicly
revise these forward-looking statements to reflect subsequent events or
circumstances. Factors that might cause such differences include, but
are not limited to, future economic conditions, relationship with
lenders, earnings retention and dividend payout policies, electric
utility restructuring, developments in the legislative, regulatory and
competitive environments in which the Company operates, and other
circumstances that could affect revenues and costs.
LIQUIDITY, CAPITAL REQUIREMENTS, AND CAPITAL RESOURCES
The Consolidated Statements of Cash Flows reflect events for the years
ended December 1997, 1996 and 1995 as they affect the Company's
liquidity. Net cash provided by operations was $36.4 million in 1997,
$44.8 million in 1996 and a negative $164.5 million in 1995. The
principal reason for the decrease in cash flows from operations in 1997
was the impact of Maine Yankee. The Company incurred approximately
$10.7 million in additional Maine Yankee operating and replacement
power costs in 1997 as compared to 1996. Also, the Company incurred
$2.7 in Maine Yankee refueling outage costs in 1997. The Company's cash
flows were improved with the 3.8% temporary rate increase effective
July 1, 1997. Positively impacting cash flows in the 1997 period was
the payment of $545,000 in income taxes, as compared to $2.3 million in
income tax payments in 1996. The Company made approximately $2 million
less in interest payments in 1997 as compared to 1996. Also enhancing
cash flows from operations in 1997 was an improvement in accounts
receivable collections for one of the Company's largest customers. In
the third quarter of the 1997, the Company received $2.6 million from a
large customer, who prepaid its electric usage for a one-year period.
Finally, in the 1996 period, the Company expended $1.7 million to
terminate a demand-side management contract.
The principal reason for the increase in cash provided by operations in
1996 as compared to 195 was the $197.7 million spent in 1995 for the
buyout of purchased power contracts ($168.7 million) and related
financing costs ($29 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 as compared to 1995 were savings in purchased power
costs because of the contract buyouts ($11.2 million), the improved
operation of Maine Yankee in 1996, 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 in
1996).
Over the last three years, capital expenditures have been $17.5 million
in 1997, $18.8 million in 1996 and $19.5 million in 1995. In 1997,
approximately $3.6 million of the capital expenditures was related to
implementing new customer, geographic and financial information
systems, $2.8 million was related to the Company's power production
facilities, $7.1 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. The Company expects its capital
expenditures to total between $45 million and $55 million over the next
three years, although it may be necessary to adjust the budget for
capital expenditures on a year-to-year basis.
Dividends paid on common stock were lower in 1997 due to the suspension
of the common dividend, beginning with the first quarter of 1997. The
reduction in preferred dividends paid resulted principally from $3
million in sinking fund payments made on the Company's 8.76% mandatory
redeemable preferred stock in 1996.
In 1997 the Company repaid $14 million of principal on its outstanding
medium term notes and made $1.9 million in sinking fund payments on its
12.25% first mortgage bonds. In 1997, the Company also made a sinking
fund payment of $1.5 million on its 8.76% mandatory redeemable
preferred stock. As discussed in more detail in Note 3 to the
Consolidated Financial Statements, the Company also made approximately
$94,000 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 1996, the Company made a $12 million
payment on its medium term notes, $1.6 million in sinking fund payments
on its 12.25% first mortgage bonds, $3 million in sinking fund payments
on its 8.76% mandatory redeemable preferred stock, and approximately
$188,000 in make whole provision payments.
Capital and operating needs in 1997 and 1996 were met through
internally generated funds and the Company's revolving credit line. The
Company anticipates that during 1998 or beyond, future cash needs may
exceed the borrowing capacity under the revolving credit facility after
the reductions described above (see "Existing Lending Agreements and
Monetization of Power Sale Contract"), and accordingly, the Company may
be required to find new sources of financing. The Company is in the
process of exploring the alternatives available for such additional
sources of financing and expects to be able to obtain amounts necessary
to meet its obligations as they arise.
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 $132.6 million of first mortgage bond and
other long-term debt sinking fund requirements and maturities in the
period 1998 2002. 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
The Company incurred a loss per common share of $.24 in 1997, as
compared to earnings per common share of $1.33 and $.36 in 1996 and
1995, respectively. Earned return on average common equity was 9.1% in
1996 and 2.5% in 1995. Negatively impacting earnings in 1997 and 1995
were the previously discussed shutdowns of Maine Yankee. Positively
impacting earnings in 1997 and 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. In 1996 Maine Yankee also operated relatively well.
Effective January 1, 1997 the Company renegotiated the revenue sharing
portion of a special rate contract with its largest industrial
customer. The rate for this 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 the industrial customer to its
customers. Under the revised revenue sharing formula, the revenues from
the revenue sharing were reduced by approximately $3.2 million in 1997.
The Company also entered into a special rate contract with a large pulp
and paper manufacturer, effective April 1, 1997. Annual revenues for
this customer are estimated to be reduced by approximately $1.5 million
due to the reduced rate. It was necessary to reduce rates to this pulp
and paper manufacturer in order to retain the customer, since the
customer was exploring self-generation for its energy needs.
Electric operating revenue for the 1997 period decreased by $49,000 as
compared to 1996. There was a $4.9 million decrease in off-system sales
(sales related to power pool and interconnection agreements and resales
of purchased power) in 1997, and revenue sharing (discussed above)
decreased by $3.2 million in 1997. Electric operating revenue
associated with kilowatt-hour (KWH) sales, excluding off-system sales,
increased by $6.9 million or 4.26% in 1997 as compared to 1996, due to
the impact of the 3.8% temporary rate increase effective July 1, 1997,
and an overall 4.0% increase in total KWH sales in 1997, excluding off-
system sales. These increases were offset by the effect of adjusting
prices downward to some customers in order to retain sales that would
otherwise be lost to competitive pressures. Of the 4.0% total increase
in KWH sales in 1997, approximately 68% was related to increased usage
by the Company's largest special contract customers.
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. This increase was somewhat offset by the impact of a
1.33% decrease in KWH 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.
Prior to the elimination of the so-called "fuel cost adjustment" method
of recovering fuel and purchased power costs 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 with the elimination of the fuel cost adjustment, deferred
fuel accounting was eliminated. This change required the Company to
record, as expense, actual fuel costs incurred. The deferred fuel
revenue balance at December 31, 1994 of $3 million, was amortized over
a three-year period beginning January 1, 1995 as a reduction in fuel
for generation and purchased power expense and was a benefit to
earnings.
The $14.3 million increase in fuel for generation and purchased power
expense in 1997, as compared to 1996, was principally due to the Maine
Yankee shutdown, as previously discussed. The increased expense in 1997
was also attributable to the 4.0% increase in KWH sales in 1997
(excluding off-system sales), a reduction in the Company's
hydroelectric power generation in 1997, as well as an overall increase
in the price of purchased power in 1997 as compared to 1996. Also, the
Company realized greater benefits/cash settlements under its fuel hedge
program (for a more complete discussion of the Company's fuel hedge
program, see Note 11 to the Consolidated Financial Statements) in 1996
as compared to 1997, due principally to the spot price of residual oil
decreasing significantly in 1997 (as compared to 1996), and the
Company's hedge in 1997 was at a higher fixed cost than in 1996.
Finally, in 1997 the Company charged to expense $1.9 million of
previously deferred Maine Yankee refueling costs, as a result of the
Company's most recent rate order (see Rate Case discussion above).
Offsetting these increases was the $4.9 million reduction in off-system
sales in 1997. Also, in connection with the most recent rate order, the
Company was ordered to defer the excess of Maine Yankee related costs
included in the rate order over the actual costs incurred effective
December 12, 1997. The Company deferred approximately $719,000 in such
costs, which prior to the rate order would have otherwise been charged
to expense, for the period from December 12 through December 31, 1997.
The significant decrease in fuel for generation and purchased power
expense in 1996 as compared to 1995 was 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.
Other operation and 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.
The increases in depreciation and amortization expense in 1997 was
principally caused by the termination, on December 31, 1996, of the
amortization of the remaining balance of the over-accumulated reserve
for depreciation. This amortization, which reduced annual depreciation
expense, amounted to $1.8 million in each of the six years from 1989
through 1996. The depreciation expense increase in 1997, as well as in
1996, were also affected by the growth in the Company's electric plant
in service, including the effect of the implementation of large
information system projects, which have shorter useful lives than
traditional utility equipment.
The Company's expenses over the period 1995 1997 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 project 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
1985, 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 purchased power contract termination at a rate of $3.9
million annually over a nine-year period. With the July 1, 1997
temporary rate increase, the MPUC required the Company to accelerate
the amortization of this deferred regulatory asset. This acceleration
resulted in additional amortization of $2.25 million in 1997. Effective
December 12, 1997, the MPUC ordered the amortization of this regulatory
asset be returned to its level prior to the temporary rate order. The
approximately $170 million of costs associated with the 1995 purchased
power contract buyback 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 million in 1997 and 1996.
Property and other taxes decreased during 1997, due primarily to funds
received related to a property tax abatement with one of the
municipalities in the Company's service territory and receipts under
the state of Maine's personal property tax reimbursement program,
offset by the effect of increases in property levels and property tax
rates. The 1996 increase as compared to 1995 was due principally to
greater property levels and higher property tax rates.
The decrease in income taxes was primarily a function of the operating
loss in 1997 as compared to earnings in 1996. Income tax expense in
1997 was increased by $184,000 in investment tax credits (ITC) recorded
in 1996 for financial reporting purposes, which were subsequently
unable to be utilized when the 1996 federal income tax return was filed
in 1997. Income tax expense in 1996 was reduced by the utilization of
$947,000 of federal and state ITC. Federal and state income tax expense
increased in 1996 over 1995 due principally to increased earnings,
offset by the utilization of federal and state ITC.
The 1997 decrease in allowance for funds used during construction
(AFDC) was principally a function of lower levels of construction work
in progress. 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.
The decrease in other income in 1997 was due primarily to the write -
off of start-up costs associated with non-core business ventures by the
Company. The 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 decreased $1 million in 1997 as
compared to 1996 due to $14 million in principal repayments on the
medium term notes in 1997, as well as $1.9 million in sinking fund
payments on the Company's 12.25% first mortgage bonds. 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 medium term notes in June 1996
and sinking fund payments on the Company's 12.25% first mortgage bonds.
The decrease in other interest expense in 1997 was principally a
function of a $2.4 million reduction in weighted average short-term
borrowings outstanding in 1997 as compared to 1996, offset by an
approximately 1/2% increase in the weighted average short-term debt
interest rate (including fees) in 1997. Other interest expense in 1996
increased primarily due to the amortization of issuance costs incurred
in connection with financing the 1995 purchased power contracts buyout.
CONTINGENCIES
ENVIRONMENTAL MATTERS - On October 10, 1996, the American Institute of
Certified Public Accountants issued Statement of Position 96 1,
"Environmental Remediation Liabilities" (SOP). The principal objective
of the SOP is to improve the manner in which existing authoritative
accounting literature is applied by entities to specific situations of
recognizing, measuring and disclosing environmental remediation
liabilities. The SOP became effective January 1, 1997. This SOP has not
had a material impact on the Company's financial position or results of
operations.
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. 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.
The Company has recorded a liability, based upon currently available
information, for what it believes are the estimated environmental
remediation costs that the Company expects to incur for these waste
disposal sites. Additional future environmental cleanup costs are not
reasonably estimable due to a number of factors, including the unknown
magnitude of possible contamination, the appropriate remediation
methods, the possible effects of future legislation or regulation and
the possible effects of technological changes. At December 31, 1997,
the liability recorded by the Company for its estimated environmental
remediation costs amounted to $331,000. The Company's actual future
environmental remediation costs may be higher as additional factors
become known.
IMPACT OF THE YEAR 2000 ISSUE - The "Year 2000" issue is the result of
computer programs being written using two digits rather than four to
define the applicable year. Any of the Company's computer programs that
have date - sensitive software may recognize a date using "00" as the
year 1900 rather than the year 2000. This could result in system
failure or miscalculations causing disruptions of operations,
including, among other things, an inability to process transactions,
send invoices or engage in similar normal business activities.
The Company has been in the process of replacing its aged customer
billing and information system and its financial systems for the past
several years. This effort will provide the added benefit of ensuring
that these computer systems will properly utilize dates beyond December
31, 1999. The Company will continue to assess the "Year 2000" issues as
it relates to information systems and personal computer based
applications and believes the risks associated with this issue can be
mitigated without significant additional costs. The Company presently
believes that, with replacement and modification of existing computer
systems, the "Year 2000" problem will not pose significant operational
problems for the Company. However, if such replacements and
modifications are not completed in time, the "Year 2000" problem may
have a material impact on the operations of the Company.
The "Year 2000" issue also creates risks for the Company from
unforeseen problems with the computer systems of third parties with
whom the Company deals. Such failures of third parties' computer
systems could have a material impact on the Company's ability to
conduct its business. The Company is currently formulating a plan to
assess the potential impact of third party vendor failures to address
the problem and, if necessary, address this issue. The Company
anticipates completing the assessment of the "Year 2000" issue as it
relates to its significant suppliers and major customers by the end of
1998. The Company cannot predict whether the systems of other companies
will be converted in time or that a failure to convert by another
company would not have a material adverse effect on the Company.
NEW ACCOUNTING PRONOUNCEMENTS
In June 1997 the Financial Accounting Standards Board (FASB) issued
Statement No. 128, "Earnings per Share", which establishes standards
for computing and presenting earnings per share (EPS) and applies to
entities with publicly held common stock or potential common stock.
This Statement simplifies the standards for computing earnings per
share previously found in APB Opinion No. 15, "Earnings per Share", and
makes them comparable to international EPS standards. It also requires
dual presentation of basic and diluted EPS on the face of the statement
of income for all entities with complex capital structures and requires
a reconciliation of the numerator and denominator of the basic EPS
computation to the numerator and denominator of the diluted EPS
computation. This Statement is effective for financial statements
issued for periods ending after December 15, 1997. The application of
this Statement currently does not impact the Company's EPS
calculations. If the Company's PERC restructuring transaction is
completed, as previously discussed, the issuance of warrants will cause
this Statement to have an effect on the Company's EPS calculations.
In June 1997 the FASB issued Statement No. 130, "Reporting
Comprehensive Income", which establishes standards for reporting and
display of comprehensive income and its components (revenues, expenses,
gains and losses) in a full set of general-purpose financial
statements. This Statement requires that all items that are required to
be recognized under accounting standards as components of comprehensive
income be reported in a financial statement that is displayed with the
same prominence as other financial statements. This Statement is
effective for fiscal years beginning after December 15, 1997.
Management does not believe the implementation of this Statement will
have a significant effect on the Company's financial statements.
In June 1997 the FASB issued Statement No. 131, "Disclosures about
Segments of an Enterprise and Related Information", which establishes
standards for the way public enterprises report information about
operating segments in annual financial statements and requires that
those enterprises report selected information about operating segments
in interim financial reports issued to shareholders. It also
establishes standards for related disclosures about products and
services, geographic areas, and major customers. This Statement
requires that a public business enterprise report financial and
descriptive information about its reportable operating segments, which
are components of an enterprise about which separate financial
information is available that is evaluated regularly by the chief
operating decision maker in deciding how to allocate resources and in
assessing performance. This Statement is effective for financial
statements for periods beginning after December 15, 1997. Management
does not believe the implementation of this Statement will have a
significant effect on the Company's financial statement disclosures.
ITEM 8
FINANCIAL STATEMENTS
& SUPPLEMENTARY DATA
- --------------------
BANGOR HYDRO-ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF INCOME
1997 1996 1995
ELECTRIC OPERATING REVENUE (Note 1): $187,324,379 $187,373,630 $184,913,771
------------- ----------- ------------
OPERATING EXPENSES:
Fuel for generation and purchased
power (Notes 1 and 12) $ 92,791,842 78,476,864 $ 98,683,991
Other operation and maintenance
(Notes 1 and 5) 32,471,149 32,440,649 35,711,185
Depreciation and amortization
(Note 1) 10,187,102 7,429,719 6,522,019
Amortization of Seabrook Nuclear
Project (Note 7) 1,699,050 1,699,050 1,699,050
Amortization of contract buyouts
(Note 6) 23,218,500 20,836,561 12,322,570
Taxes -
Local property and other 5,124,146 5,367,045 4,884,565
Income (Note 2) (1,956,303) 4,882,453 1,421,674
------------- ------------ ------------
$163,535,486 151,132,341 $161,245,054
------------- ----------- -------------
OPERATING INCOME $ 23,788,893 36,241,289 $ 23,668,717
OTHER INCOME AND (DEDUCTIONS):
Allowance for equity funds used
during construction (Note 1) 285,972 368,056 561,898
Other, net of applicable income taxes
(Notes 1 and 2) 1,005,849 1,097,931 197,924
------------- ------------ ------------
INCOME BEFORE INTEREST EXPENSE $ 25,080,714 37,707,276 $ 24,428,539
------------- ----------- -------------
INTEREST EXPENSE:
Long-term debt (Note 4) $ 22,638,201 23,651,316 $ 17,596,586
Other (Note 4) 3,392,169 3,529,002 3,201,030
Allowance for borrowed funds used
during construction (Note 1) (562,966) (755,708) (705,552)
------------- ------------ ------------
$ 25,467,404 26,424,610 $ 20,092,064
------------- ------------ ------------
NET INCOME (LOSS) $ (386,690) 11,282,666 $ 4,336,475
DIVIDENDS ON PREFERRED STOCK (Note 3) 1,375,888 1,537,202 1,701,960
------------- ------------ ------------
EARNINGS (LOSS) APPLICABLE TO
COMMON STOCK $ (1,762,578) 9,745,464 $ 2,634,515
============= =========== =============
BASIC AND DILUTED EARNINGS (LOSS) PER
COMMON SHARE, based on the
weighted average number of shares
outstanding of 7,363,424 in 1997,
7,336,174 in 1996 and 7,264,860
in 1995 (Note 14) $ (0.24) 1.33 0.36
============= ============= ===========
DIVIDENDS DECLARED PER COMMON SHARE $ - 0.72 0.87
============= ============= ===========
The accompanying notes are an integral part of these consolidated
financial statements.
BANGOR HYDRO-ELECTRIC COMPANY
CONSOLIDATED BALANCE SHEETS
December 31,
ASSETS 1997 1996
INVESTMENT IN UTILITY PLANT:
Electric plant in service, at original
cost (Notes 4 and 6) $341,008,967 $317,832,993
Less - Accumulated depreciation and
amortization (Notes 1 and 6) 96,594,713 87,736,285
--------------------------
$244,414,254 $230,096,708
Construction work in progress (Note 1) 12,011,246 18,554,154
--------------------------
$256,425,500 $248,650,862
Investments in corporate joint ventures (Notes 1
and 6) -
Maine Yankee Atomic Power Company $ 5,531,912 $ 5,013,781
Maine Electric Power Company, Inc. 326,005 124,900
--------------------------
$262,283,417 $253,789,543
--------------------------
OTHER INVESTMENTS, principally at cost (Note 6) $ 5,274,213 $ 4,812,895
--------------------------
FUNDS HELD BY TRUSTEE at cost (Notes 4 and 10) $ 21,195,772 $ 21,199,004
--------------------------
CURRENT ASSETS:
Cash and cash equivalents (Notes 1 and 10) $ 936,796 $ 1,274,386
Accounts receivable, net of reserve ($1,450,000
in 1997 and 1996) 16,614,977 20,691,010
Unbilled revenue receivable (Note 1) 11,605,163 9,229,777
Inventories, at average cost:
Materials and supplies 2,759,091 2,993,910
Fuel oil 34,771 302,851
Prepaid expenses 1,206,596 1,671,964
Deferred Maine Yankee refueling costs (Note 1 & 11) 285,894 895,798
--------------------------
Total current assets $ 33,443,288 $ 37,059,696
--------------------------
DEFERRED CHARGES:
Investment in Seabrook Nuclear Project, net of
accumulated amortization of $28,474,146 in 1997
and $26,775,096 in 1996 (Notes 7 and 11) $ 30,367,929 $ 32,066,979
Costs to terminate purchased power contracts, net
of accumulated amortization of $59,616,261 in
1997 and $36,397,761 in 1996 (Notes 6 and 11) 147,632,924 171,703,691
Maine Yankee decommissioning costs (Notes 6 and 11) 60,923,840 -
Deferred regulatory assets (Notes 2, 5 and 11) 32,551,381 29,498,630
Demand-side management costs (Note 11) 1,705,311 2,631,880
Other (Note 11) 5,204,718 3,867,087
--------------------------
Total deferred charges $278,386,103 $239,768,267
--------------------------
Total Assets $600,582,793 $556,629,405
==========================
The accompanying notes are an integral part of these consolidated
financial statements.
BANGOR HYDRO-ELECTRIC COMPANY
CONSOLIDATED BALANCE SHEETS
December 31,
1997 1996
STOCKHOLDERS' INVESTMENT AND LIABILITIES
CAPITALIZATION (see accompanying statement):
Common stock investment (Note 3) $106,558,488 $108,321,066
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) 9,137,160 10,670,171
Long-term debt, net of current portion
(Notes 4, 10 and 12) 221,642,897 274,221,451
---------------------------
Total capitalization $342,072,545 $397,946,688
---------------------------
CURRENT LIABILITIES:
Notes payable - banks (Note 4) $ 34,000,000 $ 32,500,000
---------------------------
Other current liabilities -
Current portion of long-term debt and sinking
fund requirements on preferred stock
(Notes 3, 4 and 10) $ 52,172,468 $ 15,447,429
Accounts payable 13,170,952 13,432,594
Dividends payable 327,443 1,687,495
Accrued interest 3,666,641 3,719,387
Deferred revenue (Notes 1 and 11) 1,570,995 1,008,402
Customers' deposits 296,706 359,974
Current income taxes payable 7,768 -
---------------------------
Total other current liabilities $ 71,212,973 $ 35,655,281
---------------------------
Total current liabilities $105,212,973 $ 68,155,281
---------------------------
COMMITMENTS AND CONTINGENCIES (Notes 6, 9 and 12)
DEFERRED CREDITS AND RESERVES (Note 2):
Deferred income taxes - Seabrook $ 15,765,811 $ 16,651,386
Other accumulated deferred income taxes 55,858,652 54,805,629
Maine Yankee decommissioning liability (Note 6) 60,925,586 -
Deferred regulatory liability (Note 11) 9,972,246 8,445,642
Unamortized investment tax credits 1,962,014 2,178,588
Accrued pension (Note 5) 658,880 640,328
Other (Note 5) 8,154,086 7,805,863
---------------------------
Total deferred credits and reserves $153,297,275 $ 90,527,436
---------------------------
Total Stockholders' Investment and Liabilities $600,582,793 $556,629,405
===========================
The accompanying notes are an integral part of these consolidated
financial statements.
BANGOR HYDRO-ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF CAPITALIZATION
December 31,
1997 1996
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 1997 and
1996 $ 36,817,120 $ 36,817,120
Amounts paid in excess of par value 56,969,428 56,969,428
Retained earnings 12,771,940 14,534,518
- -------------------------------------------------------------------------------
Total common stock investment $106,558,488 $ 108,321,066
- -------------------------------------------------------------------------------
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 103.75% if called on or
prior to December 27, 1998, 150,000
shares authorized and 105,000 shares
outstanding in 1997 and 120,000 out-
standing in 1996 $ 10,731,074 $ 12,264,085
Less-Sinking fund requirements 1,593,914 1,593,914
- -------------------------------------------------------------------------------
$ 9,137,160 $ 10,670,171
- -------------------------------------------------------------------------------
LONG-TERM DEBT (Notes 4, 10 and 12):
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 5,521,451 7,374,966
- -------------------------------------------------------------------------------
$108,021,451 $ 109,874,966
Less-Current maturity and sinking fund
requirements 4,278,554 1,853,515
- -------------------------------------------------------------------------------
$103,742,897 $ 108,021,451
- -------------------------------------------------------------------------------
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 34,000,000 48,000,000
- -------------------------------------------------------------------------------
$160,000,000 174,000,000
Less: Current portion of long-term debt $ 46,300,000 $ 12,000,000
- -------------------------------------------------------------------------------
$113,700,000 $ 162,000,000
- -------------------------------------------------------------------------------
Total long-term debt $221,642,897 $ 274,221,451
- -------------------------------------------------------------------------------
Total Capitalization $342,072,545 $ 397,946,688
===============================================================================
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,
1997 1996 1995
-------------- -------------- --------------
Cash Flows From Operations:
Net Income (Loss) $ (386,690)$ 11,282,666 $ 4,336,475
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 10,187,102 7,429,719 6,522,019
Amortization of Seabrook Nuclear Project (Note 7) 1,699,050 1,699,050 1,699,050
Amortization of costs to terminate purchased
power contracts (Note 6) 23,218,500 20,836,561 12,322,570
Other amortizations 1,665,566 2,000,150 1,440,501
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
plan - - 3,835,303
Allowance for equity funds used during
construction (Note 1) (285,972) (368,056) (561,898)
Deferred income tax provision (Note 2) (1,766,249) 4,495,490 1,791,082
Deferred investment tax credits, net (Note 2) (216,574) (175,464) (61,193)
Changes in assets and liabilities:
Deferred fuel revenue and Maine Yankee refueling
costs (Note 1) (398,498) 514,464 (3,191,510)
Accounts receivable, net and unbilled revenue 1,700,647 (2,872,894) 693,496
Accounts payable (261,642) 2,905,952 (4,141,870)
Accrued interest (52,746) (1,188,433) 1,257,625
Current and deferred income taxes 344,790 (722,833) 625,059
Accrued postretirement benefit costs (Note 5) 547,237 1,411,000 612,446
Other current assets and liabilities, net 906,745 (85,138) 296,938
Other, net (Note 4) (1,528,112) (1,618,007) 4,719,636
- -------------------------------------------------------------------------------------------------------
Net Cash Provided By (Used In) Operations $ 36,373,154 $ 44,841,549 $ (164,522,124)
- -------------------------------------------------------------------------------------------------------
Cash Flows From Investing:
Construction expenditures $ (17,525,312)$ (18,816,194)$ (19,459,606)
Allowance for borrowed funds used during construction
(Note 1) (562,966) (755,708) (705,552)
- -------------------------------------------------------------------------------------------------------
Net Cash (Used In) Provided By Investing $ ($18,088,278)$ ($19,571,902)$ ($20,165,158)
- -------------------------------------------------------------------------------------------------------
Cash Flows From Financing:
Dividends on preferred stock $ (1,349,620)$ (1,481,020)$ (1,579,570)
Dividends on common stock (1,325,416) (5,273,157) (7,375,736)
Payments on long-term debt (15,853,515) (13,645,737) (2,107,705)
Payments on mandatory redeemable preferred stock (1,593,915) (3,187,828) -
Issuances:
Common stock dividend reinvestment plan (Note 3) - 668,215 1,218,400
Long-term debt (Note 4) - - 186,000,000
Short-term debt, net (Note 4) 1,500,000 (2,500,000) 8,000,000
- -------------------------------------------------------------------------------------------------------
Net Cash (Used In) Provided by Financing $ (18,622,466)$ (25,419,527)$ 184,155,389
- -------------------------------------------------------------------------------------------------------
Net Change in Cash and Cash Equivalents $ (337,590)$ (149,880)$ (531,893)
Cash and Cash Equivalents - Beginning of Year 1,274,386 1,424,266 1,956,159
- -------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents - End of Year $ 936,796 $ 1,274,386 $ 1,424,266
=======================================================================================================
The accompanying notes are an integral part of these consolidated financial statements.
Bangor Hydro-Electric Company
CONSOLIDATED STATEMENTS OF COMMON STOCK INVESTMENT
Amounts
Paid in
Common Excess of Retained Total Common
Stock Par Value Earnings Stock Investment
BALANCE DECEMBER 31, 1994 $ 35,925,715 $ 55,974,218 $ 13,757,751 $ 105,657,684
Issuance of 116,414 shares of
common stock 582,070 636,330 - 1,218,400
Net income - - 4,336,475 4,336,475
Cash dividends declared on-
Preferred stock - - (1,579,570) (1,579,570)
Common stock - $.87 per share - - (6,318,919) (6,318,919)
Other (Note 3) - - (122,390) (122,390)
- ------------------------------ ------------ ------------ ------------ ---------------
BALANCE DECEMBER 31, 1995 $ 36,507,785 $ 56,610,548 $ 10,073,347 $ 103,191,680
Issuance of 61,867 shares of
common stock 309,335 358,880 668,215
Net income - - 11,282,666 11,282,666
Cash dividends declared on-
Preferred stock - - (1,448,170) (1,448,170)
Common stock - $.72 per share - - (5,284,293) (5,284,293)
Other (Note 3) - - (89,032) (89,032)
- ------------------------------- ------------ ------------ ------------ ---------------
BALANCE DECEMBER 31, 1996 $ 36,817,120 $ 56,969,428 $ 14,534,518 $ 108,321,066
Net loss - - (386,690) (386,690)
Cash dividends declared on-
Preferred stock - - (1,314,984) (1,314,984)
Other (Note 3) - - (60,904) (60,904)
- ------------------------------ ------------ ------------ ------------ ---------------
BALANCE DECEMBER 31, 1997 $ 36,817,120 $ 56,969,428 $ 12,771,940 $ 106,558,488
============ ============ ============ ===============
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 105,000
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 hydro-electric 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 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.
Prior to the receipt of the most recent rate order from the MPUC (See Note
11), the Company was 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. With the previously mentioned rate
order, the Company was not be allowed recovery, in its new rates effective
February 13, 1998, of the deferred Maine Yankee Refueling Costs. Consequently
the Company charged to operations $1.9 million of such unrecoverable costs at
December 31, 1997.
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 (excluding intangible assets),
expressed as a percentage of average depreciable plant in service, and
considering the amortization of the over-accrued depreciation (discussed
below), was approximately 3.0% in 1997, 2.4% in 1996, and 2.3% in 1995.
A study conducted in 1989 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. This
amortization ended in 1996.
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 $5.7 million in 1997, $6.5 million in 1996 and $5.9
million in 1995.
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 approximately $1.9 million and $1.5 million at
December 31, 1997 and 1996, respectively.
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. The average AFDC rates computed by the Company were 8.7%
in 1997, 8.6% for 1996 and 9.0% in 1995.
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.
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION - Cash paid for interest,
net of amounts capitalized was approximately $24.6 million, $26.7 million and
$17.9 million in 1997, 1996 and 1995, respectively. Cash paid for income
taxes was approximately $545,000, $2.3 million and $346,000 in 1997, 1996 and
1995, respectively.
DERIVATIVE FINANCIAL INSTRUMENTS - The Company uses derivative financial
instruments (derivatives), including swaps and interest rate caps (see Note
12), as a means of hedging exposure to price and interest rate risk. The
Company does not hold or issue derivatives for trading purposes. The
Company's accounting for derivatives that are used to manage risk is in
accordance with Statement of Financial Accounting Standards No. 80,
"Accounting for Futures Contracts".
RECLASSIFICATIONS - Certain prior year amounts have been reclassified to
conform with the presentation used in the 1997 Consolidated Financial
Statements.
2. INCOME TAXES
In accordance with Statement of Financial Accounting Standards No. 109
"Accounting for In-come Taxes" (FAS 109), the Company recorded net additional
deferred income tax liabilities of approximately $22.1 million as of December
31, 1997 and $20.5 million as of December 31, 1996. 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
($32.1 million and $29 million as of December 31, 1997 and 1996,
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 ($8.8 million and $7.2 million
as of December 31, 1997 and 1996, respectively), and the establishment of
deferred tax assets on unamortized investment tax credits ($1.2 million as of
December 31, 1997 and $1.3 million as of December 31, 1996). These latter
amounts have been recorded as deferred regulatory liabilities at December 31,
1997 and 1996. 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 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, 1997 and
1996:
1997 1996
- -------------------------------------------------------------------------------
Deferred Income Tax Liabilities:
Costs to terminate purchased power contracts $ 58,026,033 $ 67,731,973
Excess book over tax basis of electric plant
in service 51,559,302 52,708,038
Investment in jointly owned companies 1,405,388 832,646
Deferred demand-side management costs 685,447 1,018,733
Other 701,047 510,215
- -------------------------------------------------------------------------------
$ 112,377,217 $ 122,801,605
- -------------------------------------------------------------------------------
Less: Deferred Income Tax Assets:
Net tax operating loss carryforwards $ 39,757,653 $ 51,252,151
Deferred income taxes provided on alternative
minimum tax 6,447,244 5,808,234
Investment in Basin Mills 2,825,592 2,801,261
Unamortized investment tax credits 1,160,073 1,251,322
Postretirement benefit costs other than pensions 2,122,130 1,861,054
Deferred state income tax benefit 1,987,659 2,213,840
Accrued pension costs 458,869 1,008,523
Reserve for bad debts 873,007 807,447
Other 886,338 992,144
- -------------------------------------------------------------------------------
$ 56,518,565 $ 67,995,976
- -------------------------------------------------------------------------------
Total other accumulated deferred income taxes $ 55,858,652 $ 54,805,629
===============================================================================
The individual components of federal and state income taxes reflected in the
Consolidated Statements of Income for 1997, 1996 and 1995 are stated in the
table below.
Year Ended December 31,
- -----------------------------------------------------------------------
1997 1996 1995
---------- ----------- ---------
Current:
Federal $ 524,373 $ 1,804,206 $ --
State 141,581 526,576 --
- -----------------------------------------------------------------------
$ 665,954 $ 2,330,782 $ --
- -----------------------------------------------------------------------
Deferred:
Federal-Other $ (661,330) $ 4,034,809 $ 2,131,643
State-Other (690,829) 861,136 70,424
Federal-Seabrook (341,917) (331,076) (339,415)
State-Seabrook (72,173) (69,379) (71,570)
- -----------------------------------------------------------------------
$(1,766,249) $ 4,495,490 $ 1,791,082
- -----------------------------------------------------------------------
Investment Tax Credits, Net $ (140,379) $(1,122,798) $ (61,193)
- -----------------------------------------------------------------------
Total Provision $(1,240,674) $ 5,703,474 $ 1,729,889
Allocated to Other Income (715,629) (821,021) (308,215)
- -----------------------------------------------------------------------
Charged to Operating Expense $(1,956,303) $ 4,882,453 $ 1,421,674
=======================================================================
The table below reconciles an income tax provision (benefit), calculated by
multiplying income (loss) 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 (benefit) reported on the Consolidated
Statements of Income. The difference is represented by the permanent and
timing differences for which deferred taxes are not provided for ratemaking
purposes.
1997 1996 1995
- -----------------------------------------------------------------------
Amount % Amount % Amount %
-------------------------------------------
(Dollars in Thousands)
-------------------------------------------
Federal income tax
provision at statutory
rate $(569) 35.0% $5,860 34.5% $2,063 34.0%
Less (Plus) permanent
reductions in tax expense
resulting from
statutory exclusions from
taxable income:
Dividend received
deduction related to
earnings of associated
companies 29 (1.8) 116 .7 31 .5
Equity component of AFDC 100 (6.2) 127 .8 191 3.1%
Amortization of equity
component of AFDC
on recoverable
Seabrook investment (160) 9.8 (157) (.9) (155) (2.5)
Other (80) 5.1 (68) (.5) (104) (1.7)
- ------------------------------------------------------------------------
Federal income tax provision
before effect of timing
differences $(458) 28.1% $5,842 34.4% $2,100 34.6%
Less (Plus) timing differences
that are flowed through for rate-
making and accounting purposes:
Amortization of debt component
of AFDC and capitalized
overheads on recoverable
Seabrook investment (151) 9.3 (149) (.9) (146) (2.4)
Book depreciation greater
than tax depreciation on
assets acquired
before 1971 (79) 4.8 (90) (.5) (292) (4.8)
Equity earnings in excess
of dividends 217 (13.3) (6) -- 129 2.1
State income tax liability
deducted for federal income
tax purposes (186) 11.4 314 1.9 -- --
Reversal of excess deferred
income taxes 173 (10.6) 101 .6 101 1.7
Amortization of investment
tax credits 217 (13.3) 175 1.0 676 11.1
Investment tax credits
flowed through (184) 11.3 540 3.2 62 1.0
Other 46 (2.9) 164 .9 (161) (2.6)
- ------------------------------------------------------------------------
Federal income tax provision $(511) 31.4% $4,793 28.2% $1,731 28.5%
========================================================================
Under the federal income ax 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
1997 the Company recorded $108,140 of state of Maine ITC and $216,574 of
amortization of deferred ITC. Income tax expense in 1997 was increased by
$184,000 in ITC recorded in 1996 for financial reporting purposes, which were
subsequently unable to be utilized when the 1996 federal income tax return
was filed in 1997. 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.
ITC available of about $3.2 million ($2.2 million which is attributable to
PHC and $955,000 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, 1997, the Company had federal and state alternative minimum
tax credits of approximately $6.4 million for the reduction of future tax
liabilities. In 1997 and 1996 the Company utilized approximately $21.5
million and $32.6 million, respectively, of tax net operating loss
carryforwards to reduce its regular income tax liability. At December 31,
1997, the Company had, for income tax reporting purposes, approximately $99.4
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).
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 447,660 (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. Under the Company's current credit
facilities with its bank lending group, preferred stock may be issued only to
refund preferred stock or debt. 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 - 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 $61,000 in 1997.
In 1997 the Company made a $1.5 million sinking fund payment, as well as
approximately $94,000 under the make whole provision.
4. LENDING AGREEMENTS AND MONETIZATION OF POWER SALE CONTRACT
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%.
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 medium term notes 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 medium term notes,
used to finance a portion of the buyback cost, also have a term of five years
and originally required annual principal payments of $12 million beginning
June 30, 1996 (see 1997 update below). The Company may borrow at rates, as
defined in the Agreement, based on the London Interbank Offered (LIBO) 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.
CURRENT DEVELOPMENTS - The Company has been negotiating with interested
parties the monetization of a power sale contract with UNITIL Power Corp.
(UNITIL), a New Hampshire based electric utility. The Company currently
provides power to UNITIL at significantly above-market rates, with the
contract term ending in the year 2003. Based upon current projections of
wholesale electricity markets, it is expected that the rates charged under
the UNITIL contract will remain at above-market levels for the remainder of
the contract term. Therefore, the assignment of the Company's rights under
the contract has a positive present cash value. The Company is currently
proceeding to complete a transaction with a financial institution pursuant to
a letter of intent that would provide a loan of approximately $25 million in
net proceeds secured by the value of the UNITIL contract. As discussed below,
the proceeds of such a transaction could be used to finance a portion of the
contract restructuring with the Penobscot Energy Recovery Company (PERC) (see
Note 6) and to resolve outstanding financial covenant issues under the
Company's credit agreement with its lending banks.
That credit agreement contains a number of covenants keyed to the Company's
financial condition and performance. One such covenant requires the Company
to maintain a consolidated fixed charge ratio of 1.5 to 1.0 (defined as the
ratio of the sum of the Company's net income, income tax expense and interest
expense to the Company's interest expense, subject to a few minor
adjustments) and is measured quarterly for the prior four quarters. After the
first quarter of 1997, the Company was not in compliance with the fixed
charge ratio covenant. The Company obtained temporary waivers of the
noncompliance through June 6, 1997.
On June 6, 1997 the Company and the lending banks amended the credit
agreement. Under the amendment, compliance with the fixed charge ratio
covenant was permanently waived for the four quarters ending March 31, 1997
and June 30, 1997. The Company was also out of compliance with the fixed
charge ratio covenant for the four quarters ending September 30, 1997 and
December 31, 1997 and has received temporary waivers of those violations
until March 31, 1998. On November 20, 1997, the Company and the lending
banks amended the agreement as part of a plan to reduce the level of the
banks' credit commitment and reestablish the financial covenants to levels
that the Company anticipates it can reasonably achieve. Under the amendment
(as subsequently modified), if the Company monetizes the UNITIL contract as
discussed above before March 31, 1998 in an amount that generates the net
proceeds contemplated, it will be permitted to proceed with the restructuring
of its power purchase contract with PERC and to use $6 million of the
proceeds of the monetization to complete the PERC transaction, with the
remainder of the proceeds to be used to reduce permanently the borrowing
capacity of the existing revolving credit facility. On or before December 31,
1998, the Company must further reduce permanently the borrowing capacity
under the revolving credit facility by that additional $6 million. The
amendment also establishes new financial covenant levels that appear
reasonably achievable under the Company's current financial forecasts
although there are a number of important variables that could affect the
Company's ability to meet those covenants in the future.
As of this writing, the monetization of the power sale contract with UNITIL
has not occurred, and only temporary waivers have been received for the
covenant violations for the four quarters ending September 30, 1997 and
December 31, 1997. Consequently, the Company has classified its $34 million
of medium term notes as current liabilities as of December 31, 1997. If the
UNITIL transaction occurs, permanent waivers of the violations will, pursuant
to the credit agreement, become effective, and the medium term notes will be
reclassified as long-term liabilities.
Certain information related to total short-term borrowings under the Credit
Agreement and the lines of credit is as follows:
1997 1996 1995
- --------------------------------------------------------------------
Total credit available
at end of period $54,000,000 $54,000,000 $59,000,000
Letter of credit secured
under the revolving
credit facility $ 4,200,000 $ 4,200,000 $ 4,200,000
Unused credit at end
of period $15,800,000 $17,300,000 $19,800,000
Borrowings outstanding
at end of period $34,000,000 $32,500,000 $35,000,000
Effective interest rate 8.3% 7.7% 8.4%
(exclusive of fees)on
borrowings outstanding
at end of period
Average daily outstanding
borrowings for the
period $31,236,301 $33,609,973 $33,573,973
Weighted daily average
annual interest rate 8.1% 7.6% 8.4%
Highest level of borrowings
outstanding at any
month-end during the
period $36,500,000 $41,500,000 $47,000,000
=====================================================================
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 and other long-term debt (including
the impact of the previously discussed classification of the medium term
notes as current obligations at December 31, 1997) for the five years
subsequent to December 31, 1997 are:
Sinking Fund Current
Requirements Maturities Total
- ---------------------------------------------------------------------
1998 $ 1,778,554 $ 48,800,000 $ 50,578,554
1999 1,675,205 13,100,000 14,775,205
2000 1,886,702 14,000,000 15,886,702
2001 180,990 15,100,000 15,280,990
2002 -- 36,100,000 36,100,000
- ---------------------------------------------------------------------
$5,521,451 $127,100,000 $ 132,621,451
=====================================================================
5. 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 plan
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 1997 and
1996 and pension income for 1995, the funded status of the plan, 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 1997, 1996 or 1995. In 1995 the Company
implemented an early retirement program which resulted in additional pension
expense of approximately $2.5 million. The plan's assets are composed of
fixed income securities, equity securities and cash equivalents. Total
pension expense (income) included the following components:
1997 1996 1995
- ------------------------------------------------------------------------
Service cost benefits earned
during the period $1,046,466 $ 991,569 $ 813,811
Interest cost on projected
benefit obligation 2,861,434 2,781,366 2,458,466
Actual return on plan assets (7,560,449) (6,298,817) (8,505,484)
Total of amortized obligations
and the net gain
(loss) deferred 3,671,101 2,539,961 4,889,703
- ------------------------------------------------------------------------
Total pension expense (income)$ 18,552 $ 14,079 $ (343,504)
========================================================================
1997 1996 1995
- ------------------------------------------------------------------------
Significant assumptions used were
Discount rate 7.5% 7.25% 8.25%
Rate of increase in future
compensation levels 5.0% 5.0% 5.0%
Expected long-term rate of
return on plan assets 9.0% 9.0% 9.0%
- ------------------------------------------------------------------------
The following table sets forth the plan's funded status
at Decemeber 31,1997 and 1996:
1997 1996
- ------------------------------------------------------------------------
Actuarial present value of
accumulated benefit obligation
Vested $ 35,691,586 $ 30,856
Non-vested 2,754,950 2,696,764
- ------------------------------------------------------------------------
Total $ 38,446,536 $ 33,552,824
========================================================================
Projected benefit obligation $(44,557,086) $(39,369,783)
Plan assets at fair value 48,323,318 44,143,679
- ------------------------------------------------------------------------
Excess of plan assets over
projected benefit obligation $ 3,766,232 $ 4,773,896
Items not yet recognized in earnings
Net (asset) at transition (3,187,150) (4,119,475)
Prior service cost 3,984,025 4,540,404
Unrecognized net gain from past
experience and changes in
assumptions (5,221,987) (5,835,153)
- ------------------------------------------------------------------------
Net pension liability recognized $ (658,880) $ (640,328)
========================================================================
The discount rate and rate of increase in future compensation levels used to
determine pension obligations, effective January 1, 1998, are 7% and 4%,
respectively, and were used to calculate the plan's funded status at December
31, 1997. The Company also changed to the 83-Group Annuity Mortality Table to
calculate the plan's funded status at December 31, 1997.
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 the Company implemented an early
retirement program which resulted in $909,418 of expense related to
additional medical and life insurance benefits provided to the early
retirees.
In 1994 the Company established an irrevocable external Voluntary Employee
Benefit Association Trust Fund (VEBA) to fund the payment of postretirement
medical and life insurance benefits. Company contributions to the VEBA, which
commenced in July 1994, amounted to approximately $1.1 million in 1997,
$490,000 in 1996 and $1.2 million in 1995. 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 1997,
1996 and 1995 and the major assumptions used to determine these amounts are
shown in the following tables:
1997 1996 1995
- --------------------------------------------------------------------------------
Service cost of benefits earned $ 342,739 $ 326,809 $ 378,400
Interest cost on accumulated post-
retirement benefit obligation 994,936 928,423 948,000
Actual return on plan assets (9,395) (21,000) (23,300)
Amortization of unrecognized transition
obligation 501,200 501,200 501,200
Other deferrals, net (11,605) -- 23,699
Early retirement plan benefits -- -- 909,418
- --------------------------------------------------------------------------------
Net periodic postretirement benefit
cost $ 1,817,875 $ 1,735,432 $ 2,737,417
================================================================================
1997 1996 1995
- --------------------------------------------------------------------------------
Significant assumptions used were-
Discount rate 7.25% 7.25% 8.25%
Health care cost trend rate, employees
less than age 65-
Near-term 8.5% 9.0% 8.5%
Long-term 4.5% 4.5% 4.5%
Health care cost trend rate, employees
greater than age 65-
Near-term 6.8% 7.0% 6.8%
Long-term 4.5% 4.5% 4.5%
Rate of return on plan assets 5.0% 5.0% 5.0%
- --------------------------------------------------------------------------------
The following table sets forth the benefit plan's funded status at December 31,
1997 and 1996:
1997 1996
- --------------------------------------------------------------------------------
Accumulated postretirement benefit obligation:
Retirees $ 9,923,357 $ 8,606,932
Fully eligible active plan participants 1,203,946 847,920
Other active participants 5,107,487 3,783,868
- --------------------------------------------------------------------------------
$ 16,234,790 $ 13,238,720
Fair value of plan assets (283,731) (240,878)
Unrecognized net transition obligation (7,517,200) (8,018,400)
Unrecognized (loss) gain (2,058,535) 683,075
- --------------------------------------------------------------------------------
Accrued postretirement benefit cost
(included in Other Reserves) $ 6,375,324 $ 5,662,517
================================================================================
The discount rate used to determine postretirement benefit obligations,
effective January 1, 198, and the Plan's funded status at December 31, 1997,
was 7%. The Company changed to the 83-Group Annuity Mortality Table to
calculate the plan's funded status at December 31, 1997.
If the health care cost trend rate was increased one percent, the accumulated
postretirement benefit obligation as of December 31, 1997 would have
increased by 15.8%. The effect of such change on the aggregate of service and
interest cost for 1997 would be an increase of 17.0%.
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 $295,000 in 1997, $290,000
in 1996 and $216,000 in 1995.
6. JOINTLY OWNED FACILITIES AND POWER SUPPLY COMMITMENTS
MAINE YANKEE - The Company owns 7% of the common stock of Maine Yankee, which
owns and, prior to its permanent closure in 1997, operated an 880 megawatt
(MW) nuclear generating plant in Wiscasset, Maine. The Company's equity
ownership in the plant entitled the Company to about 7% of the output
pursuant to a cost-based power contract. The Company is obligated to pay its
pro rata share of Maine Yankee's operating expenses, capital costs and
decommissioning costs. The Company's equity investment in Maine Yankee is
approximately $5.5 million as of December 31, 1997.
Following a year long shutdown for repairs to the steam generators in 1995,
Maine Yankee came 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 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 included compliance
with NRC regulations, conformance of the plant to design specifications,
adequacy and condition of components and systems, and management issues.
During the evolution of these events, the NRC itself became subject to public
criticism about the adequacy of its regulatory activities and its
relationship with nuclear plant licensees, and in response, the NRC
implemented changes in its approach to oversight of licensees that had the
effect of amplifying the regulatory scrutiny.
Maine Yankee operated for part of 1996, but under a restriction imposed by
the NRC that limit-ed its operation to 90% of full power capacity pending the
resolution of various issues. In early December 1996 the plant was shut down
to address cable-separation and associated issues. Subsequently, 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 outage into a
refueling outage. During this extended outage, the plant owners analyzed
in-depth the viability of continued operation of the plant. While the plant
was shut down, the Company incurred incremental replacement power costs of
approximately $1 million per month in addition to its 7% share of the costs
expended in the owners' efforts to return the plant to service. On May 27,
1997, the Board of Directors of Maine Yankee voted to reduce maintenance and
repair spending at the plant and announced that Maine Yankee was considering
permanent closure based on economic concerns and uncertainty about operation
of the plant. On August 6, 1997, the Board voted to cease power operations at
the plant permanently and to begin the process of decommissioning the plant.
The formal vote followed an announcement by the Maine Yankee Board on August
1, 1997. The decision to shut down the plant was based on an economic
analysis of the costs, risks and uncertainties associated with operating the
plant compared to those associated with closing and decommissioning the
plant. The decision to close the plant should mitigate the costs the Company
would otherwise incur through a phasing down of Maine Yankee's operations and
maintenance costs. The need to purchase replacement power will continue.
Maine Yankee's most recent estimate of the total costs of decommissioning and
plant closure, excluding funds already collected, is $930 million
(undiscounted). The Company's share of this estimated cost is $65.1 million
and was recorded as a regulatory asset and decommissioning liability at
September 30, 1997. The regulatory asset was recorded for the full amount of
the decommissioning and plant closure costs due to the recent industry
restructuring legislation (see Note 11) allowing the Company future recovery
of nuclear decommissioning expenses related to Maine Yankee, as well as the
Company being allowed a recovery mechanism in its most recent rate order (see
Note 11) for Maine Yankee non-decommissioning plant closure costs.
Accumulated decommissioning funds at December 31, 1997 had an adjusted market
value of $199.5 million of which the Company's share was approximately $14
million.
In a related matter, in early September, 1997, the MPUC released the report
of a consultant it had retained to perform a management audit of Maine Yankee
for the period January 1, 1994 to June 30, 1997. The report contained both
positive and negative conclusions, the latter explaining that: Maine Yankee's
decision in December, 1996 to proceed with the steps necessary to restart its
nuclear generating plant at Wiscasset, Maine, was "imprudent"; that Maine
Yankee's May 27, 1997, decision to reduce restart expenses while exploring a
possible sale of the plant was "inappropriate," based on the consultant's
finding that a more objective and comprehensive competitive analysis at the
time "might have indicated a benefit for restarting" the plant; and that
those decisions resulted in Maine Yankee incurring $95.9 million in
"unreasonable" costs. If any of these costs are determined to have been
imprudently incurred, by FERC or the MPUC, the Company may be required to
write down a portion of its investment in Maine Yankee. On October 24, 1997,
the MPUC issued a Notice of Investigation initiating an investigation of the
prudence of the Maine Yankee shutdown decision and of the operation of Maine
Yankee prior to the shutdown, and announced that it had directed its
consultant to extend its review to include those areas.
On December 2, 1997, the MPUC issued an Order staying the investigation. The
MPUC noted that Maine Yankee had begun a rate proceeding before the FERC on
November 6, 1997, which could address the prudence issues raised in the
MPUC's investigation. The MPUC therefore stayed its investigation in order
"to avoid unnecessary duplicative efforts by all parties involved". The MPUC
reserved the right to reopen the investigation particularly if FERC declines
to address the prudence issues of concern to the Commission "if we feel it
necessary to further investigate these matters after the FERC proceeding
ends." The Company cannot therefore predict whether the MPUC will reopen its
investigation once the FERC proceeding is concluded.
During 1997, 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 these three years. With the Plant off-line for most of 1995, portions of
1996 and all of 1997, and operating at 90% capacity in 1996 when on-line, the
Company incurred replacement power costs of $12.9 million in 1997, $4.3
million in 1996 and $8.6 million in 1995.
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 37.
- ---------------------------------------------------------------------------------------------------------------
Maine Yankee MEPCO
- ---------------------------------------------------------------------------------------------------------------
(Dollars in Thousands)
- ---------------------------------------------------------------------------------------------------------------
1997 1996 1995 1997 1996 1995
---------- --------- --------- --------- --------- ---------
Operations:
As reported by investee-
Operating Revenue $ 238,586 $ 185,661 $ 205,977 $ 24,473 $ 55,391 $ 49,699
- ---------------------------------------------------------------------------------------------------------------
Depreciation $ 33,625 $ 32,952 $ 32,722 $ 222 $ 845 $ 1,383
Interest and Preferred Divivends 18,031 15,922 17,332 67 61 96
Other expenses, net 179,317 130,150 148,866 23,112 54,265 48,115
- ---------------------------------------------------------------------------------------------------------------
Operating expenses $ 230,973 $ 179,024 $ 198,920 $ 23,401 $ 55,171 $ 49,594
- ---------------------------------------------------------------------------------------------------------------
Earnings Applicable to Common Stock $ 7,613 $ 6,637 $ 7,057 $ 1,072 $ 220 $ 105
===============================================================================================================
Amounts Reported by the Company-
Purchased power costs $ 16,764 $ 12,839 $ 14,299 $ - $ - $ -
Equity in net income (524) (449) (498) (215) (15) (15)
- ---------------------------------------------------------------------------------------------------------------
Net purchased power expense $ 16,240 $ 12,390 $ 13,801 $ (215) $ (15) $ (15)
===============================================================================================================
Financial Position:
As reported by investee-
Plant in service $ 687 $ 409,865 $ 404,499 $ 23,510 $ 23,146 $ 23,135
Accumulated depreciation - (225,735) (208,537) (22,618) (22,545) (21,777)
Other assets 1,367,456 417,931 384,996 3,470 10,126 4,667
- ---------------------------------------------------------------------------------------------------------------
Total assets $1,368,143 $ 602,061 $ 580,958 $ 4,362 $ 10,727 $ 6,025
Less-
Preferred stock 17,400 18,000 18,600 - - -
Long-term debt 143,665 103,332 109,999 420 620 -
Other liabilities and deferred credits 1,128,128 409,392 381,158 1,578 9,110 5,147
- ---------------------------------------------------------------------------------------------------------------
Net assets $ 78,950 $ 71,337 $ 71,201 $ 2,364 $ 997 $ 878
===============================================================================================================
Company's reported equity-
Equity in net assets $ 5,527 $ 4,994 $ 4,984 $ 336 $ 142 $ 125
Adjust Company's estimated to actual 5 20 30 (10) (17) -
- ---------------------------------------------------------------------------------------------------------------
Equity in net assets as reported $ 5,532 $ 5,014 $ 5,014 $ 326 $ 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:
1997 1996 1995
- -------------------------------------------------------------------------
Electric plant in service $ 16,886,776 $ 16,885,690 $ 16,876,963
Accumulated depreciation (9,389,542) (8,927,440) (8,459,911)
- -------------------------------------------------------------------------
$ 7,497,234 $ 7,958,250 $ 8,417,052
=========================================================================
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 38.
- ----------------------------------------------------------------------------------------------------------------
Bangor-Pacific Chester
- ----------------------------------------------------------------------------------------------------------------
(Dollars in Thousands)
- ----------------------------------------------------------------------------------------------------------------
1997 1996 1995 1997 1996 1995
--------- --------- --------- --------- --------- ---------
Operations:
As reported by investee-
Operating Revenue $ 7,057 $ 8,252 $ 7,277 $ 4,642 $ 4,782 $ 5,016
- ----------------------------------------------------------------------------------------------------------------
Depreciation $ 870 $ 866 $ 862 $ 1,075 $ 1,075 $ 1,075
Interest expense 3,294 3,501 3,657 2,859 2,988 3,114
Other expenses, net 911 832 707 708 719 827
- ----------------------------------------------------------------------------------------------------------------
Operating expenses $ 5,075 $ 5,199 $ 5,226 $ 4,642 $ 4,782 $ 5,016
- ----------------------------------------------------------------------------------------------------------------
Net Income $ 1,982 $ 3,053 $ 2,051 $ - $ - $ -
================================================================================================================
Company's reported equity in net income $ 991 $ 1,527 $ 1,026 $ - $ - $ -
================================================================================================================
Financial Position:
As reported by investee-
Plant in service $ 44,047 $ 44,043 $ 44,035 $ 31,993 $ 31,993 $ 31,993
Accumulated depreciation (8,163) (7,293) (6,427) (7,447) (6,372) (5,296)
Other assets 3,129 3,114 3,399 3,087 3,277 3,351
- ----------------------------------------------------------------------------------------------------------------
Total assets $ 39,013 $ 39,864 $ 41,007 $ 27,633 $ 28,898 $ 30,048
Less-
Long-term debt 28,500 30,600 32,600 25,837 27,021 28,204
Other liabilities 2,425 2,359 2,255 1,796 1,877 1,844
- ----------------------------------------------------------------------------------------------------------------
Net assets $ 8,088 $ 6,905 $ 6,152 $ - $ - $ -
================================================================================================================
Company's reported equity in net assets $ 4,044 $ 3,453 $ 3,076 $ - $ - $ -
================================================================================================================
SMALL POWER PRODUCTION FACILITIES - As of the end of 1997, the Company had
contracts with six independent, non-utility power producers known as "small
power production facilities." The West Enfield Project, described below, is
one such facility. There are four other relatively small hydroelectric
facilities, and a 20 MW facility fueled by municipal solid waste (see PERC
discussion below). 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, the buyback costs were 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 was committed
under certain conditions to reimburse the towns of Enfield and Jonesboro for
lost property tax revenues in an amount which was not expected to exceed $1.4
million over a two-year period. In 1997 and 1996 the Company made payments of
approximately $1.5 million 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
could 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 connection with the temporary rate increase effective July 1, 1997,
the MPUC required the Company to accelerate the amortization of this
regulatory asset, and effective December 12, 1997, the MPUC authorized the
Company to revert to the original amortization schedule (see Note 11). In
each of the years from 1994 through 1997 the Company received its $1 million
payment.
The Company has been working to restructure its power purchase contract with
PERC, its last remaining high-priced non-utility generator contract that
offers a potential for substantial savings. 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 above the cost of alternative sources of
power (projected to be $15 milion annually, net of revenues from the resale
of power to another utility), and, in the Company's opinion, is likely to
remain so. The Company's net purchased power expense under this contract was
approximately $15 million in 1997. 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. The
Company has reached an agreement with PERC and a committee representing the
municipalities that includes the following major components:
1) The Company would make an up-front payment to PERC of $6 million and
installment payments over the next four years following consummation of the
transaction totalling an additional $4 million. These funds would be retained
by PERC to meet operation and debt service reserve requirements of the PERC
plant.
2) As of December 31, 1997, the PERC plant was financed in part by
tax-exempt municipal revenue bonds in the principal amount of $47.9 million
payable pursuant to a sinking fund schedule and finally maturing in 2004. The
credit on those bonds is enhanced by letters of credit issued by a group of
banks. Those bonds would be restructured to extend the maturity date to 20
years from the date of closing. The bonds would continue to be tax-exempt and
their credit would be enhanced by the moral obligation of the state of Maine
under the auspices of FAME pursuant to the State of Maine's Electric Rate
Stabilization Program. The extended maturity of low-cost bonds would,
therefore, provide savings to be shared by the parties.
3) The Company would continue to purchase power at the rates established
under the existing PERC contract. Payments would be made to a trust from
which disbursements would be made according to the following priorities:
a) debt service and expense, including all principal and interest;
b) trustee and bond related fees and expenses;
c) all operating and maintenance expenses of the PERC plant;
d) operating and management fees paid to the PERC partners pursuant to a
partnership operating agreement;
e) payment to the PERC owners of any savings in interest expense resulting
from the prepayment of bonds; and
f) except for cash reserve requirements, all remaining cash would be
distributed 1/3 to the Company, 1/3 to the PERC owners and 1/3 to the
participating municipalities.
4) The Company would issue warrants for the purchase of two million shares
of its common stock, one million each to the PERC owners and the
participating municipalities. The warrants would be exercisable within ten
years of their issuance and would entitle the holder to purchase common stock
for $7 per share (subject to adjustment under certain circumstances). No
warrants may be exercised within the first nine months after their issuance,
and they would become exercisable in 500,000 share blocks following the
expiration of nine months, 21 months, 33 months and 45 months from the
closing date. Upon exercise, the Company would have the option, instead of
providing common stock, to pay cash equal to the difference between the then
market price of the stock and the exercise price of $7 per share times the
number of shares as to which exercise is made. The MPUC has established a cap
on ratepayers' exposure to the cost of the warrants. Ratepayer costs are
limited to the difference between the higher $15 per share or the book value
per share at the time the warrants are exercised and the $7 exercise price.
The Company would not recover any costs above the cap from ratepayers.
5) The municipalities would extend their waste disposal contracts through
2017 and waive their existing rights to an early termination or the buyout of
PERC.
There are a number of events upon which the proposed transaction is
contingent, including approval by the affected municipalities, the rendering
of an opinion by bond counsel that the PERC bonds will remain tax-exempt and
the financing of necessary cash payments by the Company. The Company and the
other parties to the transaction are tentatively planning a closing in the
spring of 1998.
Depending in part on the ultimate cost of the warrants, it is projected that
the restructured PERC contract will result in net cost savings with a present
value of $30 40 million over the remaining life of the contract. That
projection is based upon a number of assumptions about future events and the
markets for electricity.
WEST ENFIELD PROJECT - In 1986, the Company entered into a joint venture with
a development subsidiary of Pacific Lighting Corporation or 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 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 twelve consecutive months. Information
relating to the operations and financial position of Bangor-Pacific appears
at the top of page 38.
OTHER POWER SUPPLY COMMITMENTS - The Company has a contract, which started in
June 1997, for the delivery of up to 60 MW of power from another utility,
ending December 31, 1999. The Company's purchased power expense under this
contract was a approximately $7.3 million in 1997 and is projected to be
approximately $12 million annually through the end of the contract.
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. Under the
industry restructuring provisions (see Notes 11 and 13), the Company is
required to divest of its generation assets by March 1, 2000, which includes
the Company's investment in the Basin Mills and Veazie projects.
Consequently, the Company is unlikely to expend significant amounts related
to these projects in the future.
7. RECOVERY OF SEABROOK INVESTMENT AND SALE OF SEABROOK INTEREST
The Company was a participant in the Seabrook nuclear project in Seabrook,
New Hampshire. On December 31, 1984, the Company had almost $87 million
invested in Seabrook, but because the uncertainties arising out of the
Seabrook Project were having an adverse impact on the Company's financial
condition, an agreement for the sale of Seabrook was reached in mid-1985 and
was finally consummated in November 1986. During 1985, a comprehensive
agreement was negotiated among the Company, the MPUC staff, and the Maine
Public Advocate addressing the recovery through rates of the Company's
investment in Seabrook (the Seabrook Stipulation). This negotiated agreement
was approved by the MPUC in late 1985. Although the implementation of the
Seabrook Stipulation significantly improved the Company's financial
condition, substantial write-offs were required as a result of the
determination that a portion of the Company's investment in Seabrook would
not be recovered. In addition to the disallowance of certain Seabrook costs,
the Seabrook Stipulation also provided for the recovery through customer
rates of 70% of the Company's year-end 1984 investment in Seabrook Unit 1
over 30 years, and 60% of the Company's investment in Unit 2 over seven
years, with base rate treatment on the unamortized balances. As of December
31, 1992, the Company's investment in Seabrook Unit 2 was fully amortized.
8. UNAUDITIED 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
----------------------------------------------
1997 DOLLARS IN THOUSANDS EXCEPT PER SHARE AMOUNTS)
- --------------------------------------------------------------------------------
Electric Operating Revenue $ 48,176 $ 42,236 $ 47,557 $ 49,356
Operating Income 6,657 4,896 5,902 6,334
Net Income (Loss) 716 (1,037) (188) 122
Earnings (Loss) Per Share
of Common Stock $ 0.05 $ (.19) $ (.07) $ (.03)
================================================================================
1996
- ----------------------------------
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 (Loss) 3,293 (1,696) 828 1,911*
Earnings (Loss) Per Share of
Common Stock $ .40 $ (.29) $ .05 $ .20 *
================================================================================
* Includes $498,000 of amortization of investment tax credit or $.07 per
common share.
9. CONTINGENCIES
ENVIRONMENTAL MATTERS - On October 10, 1996, the American Institute of
Certified Public Accountants issued Statement of Position 96-1,
"Environmental Remediation Liabilities" (SOP). The principal objective of
the SOP is to improve the manner in which existing authoritative accounting
literature is applied by entities to specific situations of recognizing,
measuring and disclosing environmental remediation liabilities. The SOP
became effective January 1, 1997. This SOP has not had a material impact on
the Company's financial position or results of operations.
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.
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.
The Company has recorded a liability, based upon currently available
information, for what it believes are the estimated environmental remediation
costs that the Company expects to incur for these waste disposal sites.
Additional future environmental cleanup costs are not reasonably estimable
due to a number of factors, including the unknown magnitude of possible
contamination, the appropriate remediation methods, the possible effects of
future legislation or regulation and the possible effects of technological
changes. At December 31, 1997, the liability recorded by the Company for its
estimated environmental remediation costs amounted to $331,000. The Company's
actual future environmental remediation costs may be higher as additional
factors become known.
10. FAIR VALUE OF FINANCIAL INSTRUMENTS
The following methods and assumptions were used to estimate the fair value at
December 31, 1997 of each class of financial instrument for which it is
practical to estimate the value:
Cash and cash equivalents: the carrying amount of $936,796 approximates fair
value.
The fair values of other financial instruments at December 31, 1997 based
upon similar issuances of comparable companies are as follows:
In Thousands
- -----------------------------------------------------------------------------
Carrying Fair
Amount Value
-------------------------
Funds held by trustee-guaranteed investment contract $ 21,196 $ 21,680
Mandatory redeemable cumulative preferred stock 10,500 10,500
First Mortgage Bonds 108,021 115,896
Pollution Control Revenue Bonds 4,200 4,200
FAME Revenue Notes 126,000 119,784
Medium Term Notes 34,000 34,000
- -----------------------------------------------------------------------------
11. INDUSTRY RESTRUCTUING AND RATE REGULATION
INDUSTRY RESTRUCTURING - In the Company's 1996 Form 10-K, the Company
described electric utility restructuring efforts in Maine, including the
MPUC's recommendation to the legislature. After months of hearings and
deliberations, the Maine legislature passed L.D. 1804, "An Act to Restructure
the State's Electric Industry", which the Governor signed into law on May 29,
1997. The principal provisions of the new law are as follows:
1) Beginning on March 1, 2000, all consumers of electricity have the right to
purchase generation services directly from competitive electricity suppliers
who will not be subject to rate regulation.
2) By March 1, 2000, the Company must divest of all generation related assets
and business functions except for:
a) contracts with qualifying facilities and conservation providers;
b) nuclear assets, namely, the Company's investment in Maine Yankee, however,
the MPUC may require divestiture on or after January 1, 2009;
c)assets that the MPUC determines necessary for the operation of the
transmission and distribution services.
The MPUC may grant an extension of the divestiture deadline if the extension
will improve the selling price. For assets not divested, the utilities are
required to sell the rights to the energy and capacity from these assets. The
Company shall submit to the MPUC its divestiture plan no later than January
1, 1999.
3) Billing and metering services will be subject to competition beginning
March 1, 2002, but the legislation permits the MPUC to establish an earlier
date, no sooner than March 1, 2000.
4) The Company, through an unregulated affiliate, may market and sell
electricity both within and outside its current service territory, limited to
33% of the load within the Company's service territory and unlimited outside
the Company's service territory.
5) The Company will continue to provide transmission and distribution
services which will be subject to continued regulation by the MPUC.
6) If after March 1, 2000, 10% or more of the stock of a regulated
distribution utility is purchased by an entity, the purchasing entity and any
related entity may not sell or offer for sale generation service to any
retail customer of electric energy in the state of Maine.
7) Maine electric utilities will be permitted a reasonable opportunity to
recover legitimate, verifiable and unmitigable costs that are otherwise
unrecoverable as a result of retail competition in the electric utility
industry. The MPUC shall determine these stranded costs by considering:
a) the utility's regulatory assets related to generation;
b) the difference between net plant investment in generation assets compared
to the market value for those assets; and
c) the difference between future contract payments and the market value of
the purchased power contracts.
The Company shall pursue all reasonable means to reduce its potential
stranded costs and to receive the highest possible value for generation
assets and contracts, including the exploration of all reasonable and lawful
opportunities to reduce the cost to ratepayers of contracts with qualifying
facilities. By July 1, 1999, the MPUC will have estimated the stranded costs
for the Company and the manner for the collection of these costs by the
transmission and distribution company. Customers reducing or eliminating
their consumption of electricity by switching to self-generation, conversion
to alternative fuels or utilizing demand-side management measures cannot be
assessed exit or entry fees. The MPUC shall include in the rates charged by
the transmission and distribution utility decommissioning expenses for Maine
Yankee. In 2003 and every three years thereafter until the stranded costs are
recovered, the MPUC shall review and revaluate the stranded cost recovery.
8) All competitive providers of retail electricity must be licensed and
registered with the MPUC and meet certain financial standards, comply with
customer notification requirements, adhere to customer solicitation
requirements and are subject to unfair trade practice laws. Competitive
electricity providers must have at least 30% renewable resources (which
include hydroelectric generation) in their energy portfolios.
9) A standard-offer service will be available for all customers. An
unregulated affiliate of the Company providing retail electric power are
prohibited from providing more than 20% of the load within the Company's
service territory under the standard offer service.
10) An unregulated affiliate of the Company marketing and selling retail
electric power must adhere to specific codes of conduct, including, among
others:
a) employees of the unregulated affiliate providing retail electric power must
be physically separated from the regulated distribution affiliate and cannot
be shared;
b) the regulated distribution affiliate must provide equal access to customer
information;
c) the regulated distribution company cannot participate in joint advertising
or marketing programs with the unregulated affiliate providing retail
electric power;
d) the distribution company and its unregulated affiliated provider of retail
electric power must keep separate books of accounts and records; and
e) the distribution company cannot condition or tie the provision of any
regulated service to the provision of any service provided by the unregulated
affiliated provider of electricity.
11) Employees, other than officers, displaced as a result of retail
competition will be entitled to certain severance benefits and retraining
programs. These costs will be recovered through charges collected by the
regulated distribution company.
12) Other provisions of the new law include provisions for:
a) consumer education;
b) continuation of low-income programs and demand-side management activities;
c) consumer protection provisions;
d) new enforcement authority for the MPUC to protect consumers.
The MPUC will conduct several rulemaking proceedings associated with the new
restructuring law.
REGULATORY ASSETS AND MEETING THE REQUIREMENTS OF FAS 71 - The Company is
subject to the provisions of Statement of Financial Accounting Standards No.
71, "Accounting for the Effects of Certain Types of Regulation" (FAS 71). FAS
71 allows the establishment of regulatory assets for costs accumulated for
certain items other than the usual and customary capital assets, and allows
the deferral of the income statement impact of those costs if they are
expected to be recovered in future rates. As of December 31, 1997, the
Company has regulatory assets, net of regulatory liabilities, of
approximately $264.4 million. The Company continues to meet the requirements
of FAS 71 since the Company's rates are intended to recover the cost of
service plus a rate of return on the Company's investment, as well as
providing specific recovery of costs deferred in prior periods.
The recent legislation enacted in Maine associated with industry
restructuring specifically addressed the issue of cost recovery of regulatory
assets stranded as a result of industry restructuring. Specifically, the
legislation requires the MPUC, when retail access begins, to provide a
"reasonable opportunity" for the recovery of stranded costs through the rates
of the transmission and distribution company, comparable to the utility's
opportunity to recover stranded costs before the implementation of retail
access under the legislation. If the Company is not allowed full recovery of
its stranded costs, it would be required to write-off any disallowed costs.
As provided for in Emerging Issues Task Force Issue No. 97 4, "Deregulation
of the Pricing of Electricity," the Company will continue to record
regulatory assets in a manner consistent with FAS 71 as long as future
recovery is probable, since the Maine legislation provides the opportunity to
recover regulatory assets including stranded costs through the rates of the
transmission and distribution company. The Company anticipates, based on
current generally accepted accounting principles, that FAS 71 will continue
to apply to the regulated transmission and distribution segments of its
business.
If the Company failed to meet the requirements of FAS 71, due to legislative
or regulatory initiatives, the Company would be required to revert to
Statement of Financial Accounting Standards No. 101, "Regulated
Enterprises Accounting for the Discontinuation of Application of FASB No. 71"
(FAS 101). If, under FAS 101, legislative or regulatory changes and/or
competition result in electric rates which do not fully recover the Company's
costs, a write-down of assets could be required. The Company does not
anticipate any write-down of assets at this time.
RATE ORDER - On March 3, 1997, the Company notified the MPUC of its intent to
file for a general increase in rates. Under Maine law, a utility must
ordinarily notify the MPUC two months in advance of the filing of a request
for a general increase in rates and the MPUC then has nine months to
investigate that request. However, under certain circumstances, the MPUC may
allow a utility to implement a requested increase in rates on a temporary
basis pending the conclusion of its investigation of the utility's request
for a general increase in rates.
On April 1, 1997, the Company filed with the MPUC a Petition for Temporary
Rates to increase its rates by an amount that would increase its annual
revenues by $10 million effective June 1, 1997. In making its Petition for a
Temporary Increase in Rates, the Company cited the continuing impact on the
Company's financial condition and cash flow of the ongoing outage at the
Maine Yankee nuclear power plant. The Company also cited potential
noncompliance with financial covenants contained in its bank credit agreement
(including the fixed charge coverage ratio, discussed below) and the need to
maintain adequate borrowing capacity for working capital purposes, including
mandatory debt repayments.
On June 26, 1997, the MPUC issued an order authorizing the Company to change
rates temporarily to increase its annual revenues by approximately $5.1
million effective July 1, 1997. In doing so, however, the MPUC also required
the Company to accelerate the amortization of the deferred regulatory asset
associated with the 1993 buyout of one of its high-priced non-utility
generator contracts. As a result, the rate increase did not have any net
impact on earnings but increased cash flow. Effective December 12, 1997, the
MPUC authorized the Company to revert to the original amortization schedule
of that deferred regulatory asset, thereby permitting the temporary rate
increase previously authorized to impact the Company's earnings positively
from that date.
On February 9, 1998, the MPUC issued its final order on the Company's request
to increase its rates permanently. Of the approximately $22 million increase
in annual revenue ultimately requested by the Company, the MPUC authorized an
increase of approximately $13.2 million (which includes the $5.1 million
temporary rate increase above) annually. While there are many factors that
explain the difference between the MPUC allowance and the Company's requested
increase, much of that difference is attributable to the proposed accounting
treatment of various costs and the deferral of other costs for future
consideration, including the deferral of certain costs associated with the
Company's ownership interest in the Maine Yankee nuclear power plant. While
those accounting recommendations will affect the timing of receipt of
revenues by the Company and will require the Company to finance the payment
of the associated costs, they should not significantly affect the Company's
earnings during the period that the new rates are effective.
The MPUC order is based upon a determination that the Company should be
allowed to earn an annual return of 12.75% on common equity. It also includes
a "rate plan" under which the Company's rates will be subject to certain
reconciliations based upon actual expenditures by the Company and an annual
adjustment beginning on May 1, 1999 to account for inflation with an offset
for assumed increases in productivity. Other than those adjustments, the
Company will not change its rates unless its return on equity exceeds or
falls short of the allowed return by more than 350 basis points. If the
Company's return on equity falls outside of that bandwidth, 50% of the excess
or shortfall will be adjusted for in the Company's rates.
12. DERIVATIVE FINANCIAL INSTRUMENTS
INTEREST RATE CAPS - As discussed in Note 4, the Company, in 1995, 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 was
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 1997, 1996 and 1995 the
notional rate was not in excess of 7.25%. 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. 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%.
FUEL SWAPS - 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 FA. 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 1997 and 1996 amounting to
475,000 and 775,000 barrels of residual oil, respectively. As a result of
market movements in 1997 and 1996 the Company received cash payments of
approximately $1.2 million and $3.6 million, respectively, 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. 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.
The Company manages the credit risk related to the fuel swaps through credit
limits, collateral instruments, monitoring procedures, and diversification of
counterparts. Basis risk is the risk that changes in the Company's costs do
not move perfectly in tandem with the index/commodity specified in the swap.
While basis risk exists with the residual oil swaps, the relationship between
the Company's oil related purchased power costs and the index is highly
correlated, and the Company continues to develop its purchased power
portfolio to ensure that a high degree of correlation exists. Therefore, the
Company does not expect any significant exposure to market/basis risk from
the oil swaps. As a result of the achievement of this high degree of
correlation, the "swaps" are accounted for as hedges, and are not speculative
financial instruments.
At December 31, 1997, the Company was a party to "swaps" covering 1,180,000
barrels and 816,000 barrels of residual oil for the years 1998 and 1999
respectively. The fair market value of these 1998 and 1999 "swaps" at
December 31, 1997 is estimated to be a negative $1.3 million. This value has
not been recorded in the Consolidated Financial Statements. 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.
13. SUBSEQUENT EVENTS
STORM DAMAGE - Beginning on January 5, 1998, much of the state of Maine
experienced weather conditions that included snow, sleet and freezing rain,
culminating in a sleet storm on January 7, 8 and 9. Heavy icing conditions
caused trees to fall into power lines and also caused power lines to fall
from the added weight of the ice. Damage to transmission and distribution
equipment was widespread throughout the Company's service territory. One of
the Company's major transmission lines serving the eastern part of its
service territory was entirely destroyed for a stretch of approximately eight
miles. By January 9, an estimated 60,000, or roughly 60%, of the Company's
customers were without power at the same time due to damage from the storm.
The Governor of Maine declared a state of emergency, and President Clinton
declared the state of Maine a federal disaster area.
The effort to restore power and repair transmission and distribution
equipment was extensive. Lineworkers and tree crews from throughout the
eastern United States and Canada participated in the effort, and by January
18, power had been restored to all but a few of the Company's customers. The
cost of the restoration is still being determined but it is expected to total
as much as $5 million or more. The MPUC has issued an order authorizing the
Company to defer incremental storm damage expenses for future recovery
through the rates charged to customers. The MPUC is expected to investigate
the prudence of the costs incurred and to establish a time frame for the
recovery of the prudently incurred costs. The Company believes its storm
damage costs were prudently incurred and that it should, therefore, be
allowed to recover them in rates.
DIVESTITURE OF GENERATION ASSETS - On February 9, 1998, the Company filed
its plan for divesting its generation related assets with the MPUC in
accordance with the electric utility industry "restructuring" provisions
signed into law last year. The Company anticipates that the MPUC will proceed
expeditiously with the case, but cannot predict when the plan will be
approved. This plan could result in the identification of proposed purchasers
by mid-summer 1998. The Company is offering a total of 166 MW of generation
assets.
14. NEW ACCOUNTING PRONOUNCEMENTS
In June 1997 the Financial Accounting Standards Board (FASB) issued Statement
No. 128, "Earnings per Share", which establishes standards for computing and
presenting earnings per share (EPS) and applies to entities with publicly
held common stock or potential common stock. This Statement simplifies the
standards for computing earnings per share previously found in APB Opinion
No. 15, "Earnings per Share", and makes them comparable to international EPS
standards. It also requires dual presentation of basic and diluted EPS on the
face of the statement of income for all entities with complex capital
structures and requires a reconciliation of the numerator and denominator of
the basic EPS computation to the numerator and denominator of the diluted EPS
computation. This Statement is effective for financial statements issued for
periods ending after December 15, 1997. The application of this Statement
currently does not impact the Company's EPS calculations. If the Company's
PERC transaction (see Note 6) is completed, the issuance of warrants will
cause this Statement to have an effect on the Company's EPS calculations.
In June 1997 the FASB issued Statement No. 130, "Reporting Comprehensive
Income", which establishes standards for reporting and display of
comprehensive income and its components (revenues, expenses, gains and
losses) in a full set of general-purpose financial statements. This Statement
requires that all items that are required to be recognized under accounting
standards as components of comprehensive income be reported in a financial
statement that is displayed with the same prominence as other financial
statements. This Statement is effective for fiscal years beginning after
December 15, 1997. Management does not believe the implementation of this
Statement will have a significant effect on the Company's financial
statements.
In June 1997 the FASB issued Statement No. 131, "Disclosures about Segments
of an Enterprise and Related Information", which establishes standards for
the way public enterprises report information about operating segments in
annual financial statements and requires that those enterprises report
selected information about operating segments in interim financial reports
issued to shareholders. It also establishes standards for related disclosures
about products and services, geographic areas, and major customers. This
Statement requires that a public business enterprise report financial and
descriptive information about its reportable operating segments, which are
components of an enterprise about which separate financial information is
available that is evaluated regularly by the chief operating decision maker
in deciding how to allocate resources and in assessing performance. This
Statement is effective for financial statements for periods beginning after
December 15, 1997. Management does not believe the implementation of this
Statement will have a significant effect on the Company's financial statement
disclosures.
COOPERS & LYBRAND
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, 1997 and 1996, and the related consolidated
statements of income, common stock investment, and cash flows for each of the
three years in the period ended December 31, 1997. 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, 1997 and 1996, and the consolidated results of its operations
and its cash flows for each of the three years in the period ended December
31, 1997, in conformity with generally accepted accounting principles.
/s/ Coopers & Lybrand L.L.P.
----------------------------
COOPERS & LYBRAND L.L.P.
Boston, Massachusetts
January 23, 1998
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, 1998, 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, 1998, 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, 1998,
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, 1998, 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, 1998, 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, 1997, 1996 and 1995
Consolidated Balance Sheets - December 31, 1997 and
1996
Consolidated Statements of Common Stock Investment
for the Years ended December 31, 1997, 1996 and 1995
Consolidated Statements of Capitalization - December
31, 1997 and 1996
Consolidated Statements of Cash Flows
for the Years Ended December 31, 1997, 1996 and 1995
Notes to Consolidated Financial Statements
Report of Independent Accountants
(b) Schedules
Report of Independent Accountants
Schedule VIII - Reserves for Doubtful Accounts and Insurance
All other schedules are omitted as the required information
is inapplicable or the information is presented in the
Company's consolidated financial statements or related notes.
(c) Exhibits
See Exhibit Index, page
(d) Reports on Form 8-K
The Company has no current reports on Form 8-K for the Fourth
Quarter of 1997. Two Current Reports on Form 8-K, dated
January 23, 1998 and February 13, 1998, were filed in the
first quarter of 1998 regarding significant storm damage from
a recent ice storm, the divestitue of generation assets, and
the results of the Company's request for an increase in
retail rates.
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/ 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 18, 1998.
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
January 23, 1998
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
------- ------- ------- ------- -------
1997
Reserve for Doubtful Accounts $ 1,450,000 $ 1,401,313 $ - $ 1,401,313 (A) $ 1,450,000
----------- ----------- ---------- ----------- -----------
Reserve for Retirees' Life Insurance $ - $ - $ - $ - $ -
----------- ----------- ---------- ----------- -----------
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
----------- ----------- ---------- ----------- -----------
NOTE:
(A) Accounts written off, less recoveries.
EXHIBIT INDEX
EXHIBITS FILED HEREWITH
-----------------------
EXHIBIT NO. DESCRIPTION OF EXHIBIT
---------- ----------------------
4. INSTRUMENTS DEFINING THE RIGHTS OF SECURITY HOLDERS
---------------------------------------------------
4(a) Second Amendment dated as of
June 6, 1997 to the Credit
Agreement Dated as of June 30,
1995 among Bangor Hydro-
Electric Company and the Banks
named therein, Chase Manhattan
Bank (formerly known as
Chemical Bank) as
Administrative Agent and Fleet
Bank of Maine and First
National Bank of Boston as
Co-Agents.
4(b) Security Agreement dated as of
June 6, 1997 between Bangor
Hydro-Electric Company and
Chase Manhattan Bank as
Administrative Agent under the
Credit Agreement dated as of
June 30, 1995, as amended
from time to time.
4(c) Third Amendment dated as of
November 20, 1997 to the Credit
Agreement Dated as of June 30,
1995 among Bangor Hydro-
Electric Company and the Banks
named therein, Chase Manhattan
Bank (formerly known as
Chemical Bank) as
Administrative Agent and Fleet
Bank of Maine and First
National Bank of Boston as
Co-Agents.
4(d) Amended and Restated Security
Agreement Dated as of November
20, 1997 between Bangor
Hydro-Electric Company and
Chase Manhattan Bank as
Administrative Agent under the
Credit Agreement dated as of
June 30, 1995, as amended
from time to time.
EXHIBITS INCORPORATED HEREIN BY REFERENCE
-----------------------------------------
EXHIBIT NO. DESCRIPTION OF EXHIBIT INCORPORATED BY REFERENCE TO:
----------- --------------------- ----------------------------
3. ARTICLES OF INCORPORATION & BY-LAWS
-----------------------------------
3.1 Company's Certificate Form S-2, Reg. No. 33-39181,
of Organization, together Exhibit 3.1
with all amendments thereto
3.2 Articles of Amendment Form S-2, Reg. No. 33-63500,
increasing Company's Exhibit 4.3
authorized capital stock
3.3 Articles of Amendment Form 10-K, 1995, Exhibit 3(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 10(b)
1985 to Agreement with
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 10(f)
1985 to NEPOOL Agreement
re: Hydro-Quebec Phase II
interconnection project
10.50 Firm Energy Contract dated Form 10-K, 1985, Exhibit 10(g)
October 14, 1985 between
New England utilities and
Hydro-Quebec re: Hydro-
Quebec Phase II
interconnection project
10.51 Boston Edison AC Facilities Form 10-K, 1985, Exhibit 10(h)
Support Agreement dated June
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 10(d)
of Obligations dated
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 10(f)
Costs re Tewksbury-Seabrook
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 10(l)
August 1, 1986, and First
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 10(h)
Agreement, dated as of July
22, 1987, among the Company
and the Banks named therein
10.90 Dividend Reinvestment and Form 10-K, 1987, Exhibit 10(i)
Common Stock Purchase Plan
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