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, 1998 Commission File No. 0-505
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 17, 1999)
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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 17, 1999 of the voting stock held by
non-affiliates of the registrant was $99.2 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, 1998.
FORM 10-K
FOR THE FISCAL YEAR ENDED DECEMBER 31, 1998
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 8
- Rates and Regulation 8
- Seabrook 10
- Joint Ventures 11
- Employees 13
- Power Supply Sources 14
- Company-owned Generation 14
- Power Purchase Contracts 15
- Maine Yankee 17
- Environmental Matters 20
- Executive Officers of the Company 21
Item 3: Legal Proceedings 22
Item 4: Submission of Matters to a Vote of Security Holders 22
PART II:
Item 5: Market for Registrant's Common Equity and
Related Stockholder Matters 23
Item 6: Selected Financial Data 25
Item 7: Management's Discussion and Analysis of Results of
Operations and Financial Condition 27
Item 8: Financial Statements & Supplementary Data 37
- Consolidated Statements of Income 37
- Consolidated Balance Sheets 38
- Consolidated Statements of Capitalization 40
- Consolidated Statements of Cash Flows 41
- Consolidated Statements of Common Stock Investment 42
- Notes to Consolidated Financial Statements 43
1) Nature of Operations and Summary of Significant Accounting
Policies 43
2) Income Taxes 45
3) Common and Preferred Stock and Earnings Per Share 47
4) Lending Agreements and Monetization of Power
Sale Contract 48
5) Postretirement Benefits 50
6) Jointly Owned Facilities and Power Supply Commitments 53
7) Recovery of Seabrook Investment and Sale of
Seabrook Interest 60
8) Unaudited Quarterly Financial Data 61
9) Fair Value of Financial Instruments 61
10) Industry Restructuring and Rate Regulation 61
11) Sale of Property at Graham Station 65
12) Storm Damage 65
13) Derivative Financial Instruments 65
14) Contingencies 67
15) New Accounting Pronouncements 67
Report of Independent Accountants 69
Item 9: Changes in and Disagreements with Audit Firms on Financial
Disclosures 70
PART III:
Item 10: Directors and Executive Officers of the Registrant 70
Item 11: Executive Compensation 70
Item 12: Security Ownership of Certain Beneficial Owners
and Management 70
Item 13: Certain Relationships and Related Transactions 70
PART IV:
Item 14: Exhibits, Financial Statement Schedules, and
Reports on Form 8-K 71
Signatures 72
Report of Independent Accountants 73
Schedule VIII - Reserves for Doubtful Accounts and Insurance 74
EXHIBIT INDEX:
Exhibits Filed Herewith 75
Exhibits Incorporated Herein by Reference 76
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, the Year 2000 issue, and other circumstances that could affect
revenues and costs.
PART I
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ITEMS 1 THROUGH 2 BUSINESS; PROPERTIES
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GENERAL
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The Company is a public utility engaged in the generation, purchase,
transmission, distribution and sale of electric energy, with a service area
of approximately 5,275 square miles having a population of approximately
192,000 people. The Company serves approximately 106,000 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 four material wholly-owned subsidiaries,
Penobscot Hydro Co., Inc. ("PHC"), Bangor Var Co., Inc. ("Bangor Var Co."),
Penobscot Natural Gas Company, Inc. ("Penobscot Gas"), and Bangor Energy
Resale, 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. 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." Penobscot Gas is a corporation organized
under Maine law in 1998. It was formed to be a general partner whose sole
function is to own Bangor Hydro's interest in Bangor Gas Company, LLC
("Bangor Gas"). Bangor Gas is a limited liability company organized under
Maine law in 1997. It was formed to be a local natural gas distribution
company in the greater Bangor, Maine area. For a further discussion of
Penobscot Gas and Bangor Gas, 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 - Bangor Gas Joint
Venture". 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 - Monetization of Power Sale Contract".
In 1998, 30.4% of the Company's kilowatt hour ("KWH") sales were to
residential customers, 30.5% were to commercial customers, 38.5% 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".
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 1998-1999 winter, as of March 17, 1999, was approximately 278.97
megawatts ("MW") on December 14, 1998. At that time the Company had
approximately 338.70 MW of generating capacity and firm purchased power,
comprised of 101 MW from Company-owned generating units, 9.6 MW from Hydro-
Quebec, 53.4 MW from non-utility power producers, and 175.0 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 Note 6 to the Consolidated Financial
Statements included in Item 8, below.
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
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CHANGES IN THE ELECTRIC UTILITY INDUSTRY AND IN REGULATION - Pursuant to "An
Act to Restructure the State's Electric Industry", enacted in 1997 by the
Maine Legislature, effective March 1, 2000, the Company will no longer be
permitted to engage directly in the generation and sale of electric energy.
The Company will remain regulated as a provider of electricity transmission
and distribution services. As part of the restructuring process, the Company
reached agreement on September 25, 1998 to sell substantially all Company-
owned generation units to PP&L Global, Inc., a subsidiary of PP&L Resources,
Inc. 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 - Agreement on Sale of Company's Generating
Assets" and Note 10 to the Consolidated Financial Statements included in Item
8, below.
RATES AND REGULATION - See "Rates and Regulation", below, together with Note
10 to the Consolidated Financial Statements included in Item 8, below, for a
discussion of recent and pending regulatory proceedings affecting the
Company's rates and revenues.
YEAR 2000 ISSUE - 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
the Year 2000 Issue on the Company.
PERC POWER CONTRACT RESTRUCTURING - See Note 6 to the Consolidated Financial
Statement included in Item 8, below, for a discussion of the effect on the
Company of the restructuring of its power contract with Penobscot Energy
Recovery Company ("PERC").
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.
RESUMPTION OF COMMON STOCK DIVIDENDS - In response to financial pressures
experienced by the Company during the last several years, the Board of
Directors reduced the level of common stock dividends in 1995 and then
suspended the declaration of such dividends in 1997. Given the significant
progress that has been made in resolving several of the uncertainties which
have been facing the Company, as discussed herein, management expects that
the Board of Directors could consider the resumption of common stock
dividends sometime in 1999. The projected effects on the Company's financial
condition of the pending generation asset sale and restructuring regulatory
proceedings before the MPUC, as well as capital needs associated with
investment opportunities the Company may elect to pursue, are all factors
that the Board of Directors will consider in determining whether, and when,
to reinstate common stock dividends. The Board will also take into account
provisions in the Company's debt instruments restricting dividends and
repurchases of equity securities, as well as the levels of the Company's
indebtedness from time to time. Additionally, any future dividend policy will
necessarily reflect the fundamental changes taking place in the electric
utility industry, and the Company's need to retain financial flexibility to
take advantage of opportunities as they occur and to respond to unanticipated
developments.
CONSTRUCTION PROGRAM
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The Company's construction program consists of extensions and
improvements of its transmission and distribution facilities, 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 $45-65
million in the period 1999 through 2001.
RATES AND REGULATION
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RATE MATTERS - On February 9, 1998, the MPUC issued a final order on the
Company s request to increase its rates originally filed in March, 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 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
an "Alternative 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.
On February 16, 1999, the Company submitted its 1999 filing to the MPUC
under the Alternative Rate Plan. If approved, the Company will implement a
rate increase of approximately 2% effective May 1, 1999. The Company is not
seeking an increase due to inflation. Rather, the entire amount of the
increase is due to adjustments for specific cost items. The largest of these
is for deferred costs relating to a severe ice storm in January, 1998 at a
rate of $1.46 million annually over a four year period. The remainder of the
request consists of adjustments contemplated in the MPUC's decision in the
Company's last rate case, discussed above, but for which amounts were not
known at the time.
On July 24, 1998, the Company filed with the MPUC proposed rates to be
effective March 1, 2000 for retail transmission and distribution service,
including the recovery of the Company's stranded costs. This filing was made
pursuant to the 1997 Maine restructuring legislation. The 1997 Maine
restructuring legislation requires the MPUC to provide transmission and
distribution utilities, including the Company, a "reasonable opportunity" to
recover its stranded costs that is comparable to the opportunity that it had
prior to the implementation of industry restructuring. The Company cannot
predict the outcome of the MPUC decision, which is expected in the third
quarter of 1999, subject to later updating prior to March 1, 2000.
The Company is also engaged in numerous other MPUC proceedings relating
to various aspects of industry restructuring.
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. As part of the restructuring
process, the Company reached agreement on September 25, 1998 to sell
substantially all Company-owned generation units, including such FERC-
regulated hydroelectric units, to PP&L Global, Inc., a subsidiary of PP&L
Resources, Inc. 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 - Agreement on Sale of Company's
Generating Assets" and Note 10 to the Consolidated Financial Statements
included in Item 8, below.
The following table sets forth certain information with regard to such
licenses.
Licensed Issue Date of Current Expiration
Project Capacity Original License Date
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Ellsworth 8,900 KW April 12, 1977 December 31, 2018
Howland 1,875 KW September 12, 1980 September 30, 2000
Medway 3,400 KW March 29, 1979 March 31, 1999*
Milford 6,400 KW December 31, 1969 March 31, 2038
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 March 31, 2038
Veazie 8,400 KW February 18, 1965 March 31, 2038
West Enfield** 13,000 KW February 3, 1970 June 26, 2024
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* An "annual license" will be automatically issued at the expiration of
the current license, pending the processing of the application for a
permanent license.
** Through PHC, the Company has a 50% ownership interest in
Bangor-Pacific, which owns and operates the West Enfield Project.
SEABROOK
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GENERAL - The Company was a participant in Seabrook from 1978 to
1986, with an ownership interest of 2.17%, or 25 MW, in each of
the two 1150 MW units. Unit 2 was effectively canceled in 1984.
In late 1984, following a lengthy MPUC investigation, the
conclusion of which cast doubt on the wisdom of the Maine
utilities' continued participation in Seabrook, the Company began
efforts to sell its interest in the project. An agreement for
the sale of Seabrook to EUA Power Corp. was reached in mid-1985
and was consummated in November 1986.
In 1985, the MPUC approved an agreement among the Company,
the MPUC Staff and the Public Advocate addressing the recovery
through rates of the Company's investment in Seabrook ("Seabrook
Stipulation"). Although implementation of the Seabrook
Stipulation significantly improved the Company's financial
condition, substantial write-offs were required.
In August 1989, a comprehensive settlement agreement entered
into by current and former joint owners of Seabrook became
effective. Under the agreement, the signatories, representing
virtually all of the ownership interests in Seabrook,
relinquished claims against the lead owner, Public Service
Company of New Hampshire, arising out of Seabrook. As a part of
the settlement, former joint owners, including the Company, were
relieved of certain contingent liabilities.
JOINT VENTURES
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WEST ENFIELD - In 1986, the Company formed PHC, a wholly-owned
subsidiary, which owns the Company's 50% ownership interest in
Bangor-Pacific, a joint venture with a development subsidiary of
Pacific Lighting Corporation. Bangor-Pacific undertook the
redevelopment of an old 3.8 MW hydroelectric plant which the
Company owned on the Penobscot River in Enfield and Howland,
Maine, into a 13 MW facility, the West Enfield Project, and now
operates the facility. Construction costs were shared equally by
the Company and the other joint venturer until Bangor-Pacific
completed its financing and took over ownership of the project,
which occurred in January 1987. Commercial operation of the
redeveloped West Enfield Project began in April 1988.
Bangor-Pacific financed the 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 1998,
the Company paid approximately $7.3 million to Bangor-Pacific
under this power contract. The Company would be required to make
payments under the contract, regardless of whether any power were
delivered, of approximately $4 million per year. However, the
Company has the right to terminate the contract upon thirty-days'
written notice if the failure to deliver power continues for a
period of 12 consecutive months.
PHC accounts for its investment in Bangor-Pacific under the
equity method. PHC's financial results are included in the
Company's consolidated financial statements.
BANGOR GAS - In 1998, the Company formed Penobscot Natural Gas
Company ("Penobscot Gas") to be a 50% general partner in Bangor
Gas Company, LLC, (Bangor Gas), which is constructing a natural
gas distribution system in the Bangor, Maine area. Sempra Energy
Utility Ventures, a subsidiary of Sempra Energy, owns the other
50% interest in Bangor Gas. In the second quarter of 1998,
Bangor Gas received unconditional authority from the MPUC to
provide natural gas service to the greater Bangor area. In
October, 1998 the Company received authorization from the MPUC to
invest approximately $1.2 million in Bangor Gas.
Los Angeles based Sempra Energy is a joint-venture of Pacific
Enterprises and Enova Corporation. 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 late 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 but has the opportunity to make material capital contributions
to the joint-venture in the near term.
Penobscot Gas accounts for its investment in Bangor Gas
under the equity method. Penobscot Gas's financial results are
included in the Company's consolidated financial statements.
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. As part of the electric industry
restructuring process in the State of Maine, the Company reached
agreement on September 25, 1998 to sell substantially all
Company-owned generation units to PP&L Global, Inc. As part of
this transaction, the Company will be assigning substantially all
of its rights under the NEPOOL/Hydro-Quebec agreements to PP&L
Global and PP&L Global will assume a substantial portion of the
Company's related liabilities. 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 - Agreement on Sale of Company's Generating
Assets".
EMPLOYEES
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At December 31, 1998, the Company had 434 full time
employees approximately 50% 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, 179 employees engaged in electrical, line and
meter related functions and 40 employees engaged in customer
service and credit related functions. The present contract with
electrical, line and meter related workers expires December 31,
1999. The present contract with customer service and credit
related workers also 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 date
of implementation of retail access in Maine, scheduled to occur
on March 1, 2000.
The Company's sources of generation for electric sales to
its customers (net of off-system sales to other utilities) for
1998, 1997 and 1996 by type of fuel is shown below.
Source 1998 1997 1996
------ ---- ---- ----
Hydroelectric (Company*)....... 15% 13% 17%
Nuclear Generation (Maine Yankee) 0% 0% 19%
Oil (Company)................... 5% 4% 2%
Biomass/Refuse (purchased)...... 6% 6% 6%
NEPOOL/other purchases.......... 74% 77% 56%
---- ---- ----
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."
As part of the electric industry restructuring process in
the State of Maine, the Company reached agreement on September
25, 1998 to sell substantially all Company-owned generation
units, including all of its hydroelectric projects and Wyman 4,
to PP&L Global, Inc. On February 3, 1999, the MPUC issued an
order approving the Company's sale of substantially all of its
generation assets to PP&L Global, Inc. and in a vote taken March
10, 1999, the FERC approved the 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 - Agreement on Sale of Company's
Generating Assets".
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 Brunswick June 8, 1997 through 60 MW system purchase of
Power December 31, 1999 capacity and energy
Great Bay Power November 1, 1998 through 10 MW and associated energy
Corporation February 29, 2000 from a designated nuclear
unit
United May 1, 1998 through 35 MW and associated energy
Illuminating February 29, 2000 from a designated oil-fired
unit
- ---------------------
* 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 Reports on Form 10-K
for the years ended December 31, 1996 and December 31, 1997, 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, 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. The plant is
currently in the process of being decommissioned, and the Company
is obligated to pay its pro rata share of Maine Yankee's plant
closure and decommissioning costs.
MAINE YANKEE RATE CASE SETTLEMENT - On January 19, 1999, various
parties submitted an offer of settlement with the FERC that, if
accepted by FERC, will finally settle a number of outstanding
rate recovery issues with respect to the Company's ownership of
Maine Yankee. On March 10, 1999, the presiding Administrative
Law Judge certified the uncontested settlement and recommended
that the FERC accept it. For a more complete discussion of the
recent events associated with Maine Yankee, see Note 6 to the
Consolidated Financial Statements included in Item 8, below.
LOW-LEVEL WASTE DISPOSAL. The federal Low-Level Radioactive
Waste Policy Amendments Act (the "Waste Act"), enacted in 1986,
required states either alone or in multistate compacts to provide
for the disposal of low-level radioactive waste generated within
their borders. Subsequently, the states of Maine, Texas and
Vermont entered into 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
then-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; or, as a possible
alternative, the states could agree to a financing arrangement
for the payment, in which case Maine Yankee=s share, along with
interest, could be paid out over an extended period of time. In
addition, Maine Yankee would be assessed a total of $2.5 million
for the benefit of the Texas county in which the facility would
be located and would also be responsible for its pro-rata share
of the Texas governing commission's operating expenses.
The bill providing for ratification of the compact was
before several sessions of the Congress before finally being
approved on September 2, 1998, and signed by the President on
September 21, 1998. However, on October 22, 1998, the Texas
Natural Resources Conservation Commission voted to deny a permit
for the proposed west Texas site for the facility.
Since the Maine Yankee 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 uncertainty
associated with the schedule for opening a Texas facility.
Although other potential sites in Texas have been proposed by
various parties, the Company cannot predict whether or when a
facility in Texas will be licensed and built. Maine Yankee
intends to utilize its on-site storage facility as well as
dispose of low-level waste at an active South Carolina site or
other available sites in the interim and continue to cooperate
with the State of Maine in pursuing all appropriate options. The
Company is unable to predict whether or when the state of Maine
may assess any payments required under the compact.
NUCLEAR INSURANCE. The Price-Anderson Act is a federal statue
providing, among other things, a limit on the maximum liability
for damages resulting from a nuclear incident. Coverage for the
liability is provided for by existing private insurance and
retrospective assessments for costs in excess of those covered by
insurance, up to $88.1 million for each reactor owned, with a
maximum assessment of $10 million per reactor in any year.
However, after appropriate exemptive action by the NRC, Maine
Yankee, and therefore its sponsors, are not responsible for
retrospective assessments resulting from any event or incident
occurring after January 7, 1999.
SPENT FUEL. Like other nuclear plant operators, Maine Yankee
entered into a contract with the United States Department of
Energy ("DOE") for disposal of its spent nuclear fuel, as
required by the Nuclear Waste Policy Act of 1982, pursuant to
which a fee of one dollar per megawatt-hour was assessed against
net generation of electricity and paid to the DOE quarterly.
Under this Act, the DOE was given the responsibility for disposal
of spent nuclear fuel produced in private nuclear reactors. In
addition, Maine Yankee is obligated to make a payment with
respect to generation prior to April 7, 1983 (the date current
DOE assessments began). Maine Yankee elected under terms of its
DOE contract to make a single payment of this obligation prior to
the first delivery of spent fuel to DOE, which was scheduled to
begin by January 31, 1998. The payment would consist of $50.4
million (all of which Maine Yankee previously collected from its
customers, but for which a reserve was not funded), which is the
approximate one-time fee charge, plus interest accrued at the 13-
week treasury-bill rate compounded on a quarterly basis from
April 7, 1983, through the date of the actual payment. Current
costs incurred by Maine Yankee under this contract are
recoverable under the terms of its Power Contracts with its
sponsoring utilities, including the Company. Maine Yankee has
accrued and billed $82.8 million of interest cost for the period
April 7, 1983, through December 31, 1998.
Maine Yankee has formed a trust to provide for payment of
its long-term spent fuel obligation, and is funding the trust
with deposits at least semiannually which began in 1985, with
currently projected annual deposits of approximately $1.3 million
through December 2003. Deposits are expected to total
approximately $78.2 million, with the total liability, including
interest due at the time of disposal, estimated to be
approximately $168.7 million at December 31, 2003. Maine Yankee
estimates that trust fund deposits plus estimated earnings will
meet this total liability if funding continues without material
changes.
Maine Yankee's spent fuel is currently stored in the spent
fuel pool at the Plant site. Federal legislation enacted in
December 1987 directed the DOE to proceed with the studies
necessary to develop and operate a permanent high-level waste
(spent fuel) disposal site at Yucca Mountain, Nevada. The
legislation also provided for the possible development of a
Monitored Retrievable Storage ("MRS") facility and abandoned
plans to identify and select a second permanent disposal site.
An MRS facility would provide temporary storage for high-level
waste prior to eventual permanent disposal. The DOE has
indicated that the permanent disposal site is not expected to
open before 2010, although originally scheduled to open in 1998.
In 1997, the two branches of the United States Congress
approved separate bills to comprehensively reform the federal
spent nuclear fuel program. In the spring of 1998, House and
Senate members resolved differences between the bills, which
would have required the DOE to establish an interim storage
facility and begin accepting spent fuel from nuclear power plants
by 2003. On June 2, 1998, the Senate fell short of the 60 votes
needed to end debate on the bill and the bill was not brought to
a vote in the House.
In 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 Circuit that the Nuclear Waste Policy Act of 1982
required the DOE to take responsibility for spent nuclear fuel in
1998. In July 1996, the court held that the DOE was obligated
Ato 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.
In November 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.
On May 5, 1998, the Court dismissed Maine Yankee' lawsuit, as
well as that of the other nuclear utilities and state regulators,
saying that petitioners' failure to pursue remedies under the
standard contract rendered their appeal not appropriate at that
time for review. On June 2, 1998, Maine Yankee filed a claim for
money damages in the U.S. Court of Federal Claims for the costs
associated with the DOE's failure to begin to take fuel in 1998.
On November 3, 1998, the Court granted summary judgment in favor
of Maine Yankee, ruling that the DOE had violated its contractual
obligations and leaving the amount of damages incurred by Maine
Yankee for later determination by the Court. Maine Yankee
expects the hearing on its claim to take place in late 1999.
Maine Yankee intends to pursue its claim for damages vigorously,
but as an alternative to DOE disposal is considering construction
of an independent spent-fuel storage installation ("ISFSI") on
the Plant site.
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 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, 1998, the
liability recorded by the Company for its estimated environmental
remediation costs amounted to $331,000. The Company s actual
future remediation costs may be higher as additional factors
become known.
The Company estimates that during 1999 it will spend
approximately $352,000 in operations expenses and $143,000 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 55 President & Chief Executive
Officer since January 1991
Carroll R. Lee 49 Senior Vice President and
Chief Operating Officer since
December, 1996
Frederick S. Samp 48 Vice President - Finance &
Law since 1995; Treasurer since
1995; Chief Financial Officer
since 1995
Paul A. LeBlanc 51 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 14 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, 1998, there were 6,328 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
- ------------- ---- --- ---------
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................ $8 5/8 $6 1/8 $.00
Second Quarter............... 9 1/8 7 11/16 .00
Third Quarter................ 10 15/16 7 15/16 .00
Fourth Quarter............... 12 13/16 9 .00
1999
- ----
First Quarter
(through March 17, 1998).. $14 5/16 $12 11/16 $.00
The cash dividend on common stock was suspended prior to
April 20, 1997.
Approximately 70% of the outstanding shares of common stock
are registered in the "street names" of depositories and brokers
for the benefit of their clients who are unknown to the Company.
Therefore, the actual number of stockholders at any given time,
including these "beneficial owners", is likely to be
substantially greater than the number of holders shown on the
Company's records.
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 currently prohibits the Company from paying
dividends on or make certain other defined payments with respect
to its common stock, including repurchases of equity securities,
of more than 60% of its earnings applicable to common stock
during any calendar year.
See Item 1, above, for a discussion of Certain Items Facing
the Company, including their potential impact on the Company's
dividend policy.
<TABLE>
Item 6
Selected Financial Data
SIX YEAR STATISTICAL SUMMARY
Bangor Hydro-Electric Company
<CAPTION>
1998 1997 1996 1995 1994 1993
- ---------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
MEGAWATT HOURS (MWH) GENERATED AND PURCHASED
Hydro Generation (Company) 275,379 262,377 321,532 275,810 271,616 275,694
Nuclear Generation (Maine Yankee) - - 348,719 13,606 456,871 395,665
Oil (Company) 96,476 69,580 26,912 50,706 35,759 47,115
Biomass/Refuse 156,051 159,990 163,279 177,558 190,218 281,260
NEPOOL/Other Purchases 1,522,125 1,583,093 1,359,116 1,540,530 958,363 937,431
- ---------------------------------------------------------------------------------------------------------------------------------
Total Generated & Purchased 2,050,031 2,075,040 2,219,558 2,058,210 1,912,827 1,937,165
Less Line Losses and Company Use 139,028 147,298 141,426 140,128 136,908 135,561
- ---------------------------------------------------------------------------------------------------------------------------------
Remainder - MWH sold 1,911,003 1,927,742 2,078,132 1,918,082 1,775,919 1,801,604
=================================================================================================================================
CLASSIFICATION OF SALES - MWH
Residential 522,836 533,161 536,490 513,076 516,470 515,242
Commercial 532,344 523,043 512,433 511,720 507,285 500,488
Industrial 654,330 680,226 647,985 686,386 611,876 615,314
Lighting 8,901 8,780 8,945 9,547 9,416 9,590
Wholesale 2,704 3,841 4,486 10,961 11,705 10,311
- ---------------------------------------------------------------------------------------------------------------------------------
Total MWH Billed to Customers 1,721,115 1,749,051 1,710,339 1,731,690 1,656,752 1,650,945
Unbilled Sales - Net Increase (Decrease) 1,040 33,011 2,998 4,658 6,366 2,001
- ---------------------------------------------------------------------------------------------------------------------------------
Total Delivered Sales (MWH) 1,722,155 1,782,062 1,713,337 1,736,348 1,663,118 1,652,946
(Less) Interruptible Sales 248,091 265,438 237,553 295,818 231,128 254,359
- ---------------------------------------------------------------------------------------------------------------------------------
Total Firm Delivered Sales (MWH) 1,474,064 1,516,624 1,475,784 1,440,530 1,431,990 1,398,587
Off-System Sales 188,848 145,680 364,795 181,734 112,801 148,658
- ---------------------------------------------------------------------------------------------------------------------------------
Total Energy Sales (MWH) 1,911,003 1,927,742 2,078,132 1,918,082 1,775,919 1,801,604
=================================================================================================================================
ELECTRIC OPERATING REVENUES AND EXPENSES (000'S)
OPERATING REVENUES
Residential $ 71,396 $ 67,532 $ 66,805 $ 66,061 $ 64,008 $ 64,244
Commercial 60,802 55,965 54,168 55,030 53,410 53,599
Industrial 42,034 41,356 38,947 39,929 37,040 39,508
Lighting 2,207 2,065 2,032 2,051 2,010 1,915
Wholesale 235 310 314 859 937 903
- ---------------------------------------------------------------------------------------------------------------------------------
Total Revenue From Customers $ 176,674 $ 167,228 $ 162,266 $ 163,930 $ 157,405 $ 160,169
Unbilled Sales-Net Increase (Decrease) 481 2,375 408 210 1,450 (237)
- ---------------------------------------------------------------------------------------------------------------------------------
Total Revenue $ 177,155 $ 169,603 $ 162,674 $ 164,140 $ 158,855 $ 159,932
(Less) Interruptible Revenue 11,064 11,215 9,537 11,149 8,450 8,876
- ---------------------------------------------------------------------------------------------------------------------------------
Total Firm Revenue $ 166,091 $ 158,388 $ 153,137 $ 152,991 $ 150,405 $ 151,056
Off-System Revenue 14,630 13,615 18,384 14,098 12,750 15,326
- ---------------------------------------------------------------------------------------------------------------------------------
Total Operating Revenues $ 191,785 $ 183,218 $ 181,058 $ 178,238 $ 171,605 $ 175,258
=================================================================================================================================
OPERATING EXPENSES
Fuel for Generation and Purchased Power $ 82,027 $ 92,792 $ 78,477 $ 98,684 $ 104,132 $ 116,386
Operating and Maintenance Expense 34,448 32,471 32,441 35,711 33,498 29,474
Depreciation and Amortization 31,891 35,104 29,965 20,544 10,333 6,447
Taxes 11,642 3,168 10,249 6,306 8,803 8,866
- ---------------------------------------------------------------------------------------------------------------------------------
Total Operating Expenses $ 160,008 $ 163,535 $ 151,132 $ 161,245 $ 156,766 $ 161,173
=================================================================================================================================
SUMMARY OF OPERATIONS (000'S)
Operating Revenue $ 195,144 $ 187,324 $ 187,374 $ 184,914 $ 174,098 $ 177,972
Operating Expenses 160,008 163,535 151,132 161,245 156,766 161,173
Other Income (including equity AFDC) 1,292 1,292 1,466 760 1,308 (2,657)*
Interest Expense (net of borrowed AFDC) 24,963 25,467 26,425 20,092 11,183 8,805
- ---------------------------------------------------------------------------------------------------------------------------------
Net Income (Loss) $ 11,465 $ (386) $ 11,283 $ 4,337 $ 7,457 $ 5,337 *
Less Preferred Dividends 1,244 1,376 1,537 1,702 1,652 1,646
- ---------------------------------------------------------------------------------------------------------------------------------
Earnings (Loss) on Common Stock $ 10,221 $ (1,762) $ 9,746 $ 2,635 $ 5,805 $ 3,691 *
=================================================================================================================================
SELECTED FINANCIAL DATA
Total Assets (000's) $ 605,688 $ 600,583 $ 556,629 $ 566,076 $ 381,250 $ 373,521
ELECTRIC PLANT (000'S)
Total Electric Plant $ 372,782 $ 358,878 $ 341,526 $ 323,664 $ 303,637 $ 281,606
Depreciation Reserve 101,633 96,595 87,736 81,934 75,667 71,184
- ---------------------------------------------------------------------------------------------------------------------------------
Net Electric Plant $ 271,149 $ 262,283 $ 253,790 $ 241,730 $ 227,970 $ 210,422
=================================================================================================================================
CAPITALIZATION (000'S)
Short-Term Debt $ 12,000 $ 34,000 $ 32,500 $ 35,000 $ 27,000 $ 36,000
Long-Term Debt 263,028 221,643 274,221 288,075 116,367 119,126
Redeemable Preferred Stock 7,604 9,137 10,670 12,070 13,740 15,168
Preferred Stock 4,734 4,734 4,734 4,734 4,734 4,734
Common Equity 118,864 106,558 108,321 103,192 105,658 93,944
- ---------------------------------------------------------------------------------------------------------------------------------
Total $ 406,230 $ 376,072 $ 430,446 $ 443,071 $ 267,499 $ 268,972
=================================================================================================================================
CAPITAL STRUCTURE RATIOS (%)
Short-Term Debt 3.0% 9.1% 7.5% 7.9% 10.1% 13.4%
Long-Term Debt 64.7% 58.9% 63.7% 65.0% 43.5% 44.3%
Preferred Stock 3.0% 3.7% 3.6% 3.8% 6.9% 7.4%
Common Stock 29.3% 28.3% 25.2% 23.3% 39.5% 34.9%
- ---------------------------------------------------------------------------------------------------------------------------------
Total 100.0% 100.0% 100.0% 100.0% 100.0% 100.0%
=================================================================================================================================
MISCELLANEOUS STATISTICS
Shares Outstanding (Average) 7,363,424 7,363,424 7,336,174 7,264,360 6,947,746 5,862,411
Shares Outstanding (Year End) 7,363,424 7,363,424 7,363,424 7,301,557 7,185,143 6,225,394
Number of Stockholders (Year End) 6,868 6,868 7,734 8,250 7,705 7,511
Basic Earnings (Loss) per Common Share $ 1.39 $ (.24) $ 1.33 $ 0.36 $ 0.84 $ 0.63 *
Diluted Earnings (Loss) per Common Share $ 1.33 $ (.24) $ 1.33 $ 0.36 $ 0.84 $ 0.63 *
Dividends Declared per Common Share $ - $ - $ 0.72 $ 0.87 $ 1.32 $ 1.32
Book Value per Common Share $ 16.14 $ 14.47 $ 14.71 $ 14.13 $ 14.71 $ 15.09
Return on Common Equity 9.11% (1.64)% 9.09% 2.51% 5.55% 3.99%*
Ratio of AFDC to Common Stock Earnings 11% (48)% 12% 48% 45% 143%*
Ratio of Earnings to Fixed Charges 1.59 0.86 1.50 1.14 1.49 1.04*
Payout Ratio - - 54% 242% 157% 210%*
Percentage of Construction Expenditures
Funded Internally 100% 100% 100% 100% 86% 72%
=================================================================================================================================
RESIDENTIAL CUSTOMER DATA
Average Number of Customers 90,888 90,433 89,769 86,194 85,041 84,211
Kilowatt-Hours per Customer 5,753 5,896 5,976 5,953 6,073 6,118
Revenue per Customer $ 785.54 $ 746.76 $ 744.19 $ 766.42 $ 752.67 $ 762.89
Revenue per Kilowatt-Hour in cents 13.65 12.67 12.45 12.88 12.39 12.47
=================================================================================================================================
MISCELLANEOUS SYSTEM DATA
Net System Capability at Time of Peak
(MW) Firm 381.54 344.44 373.04 330.01 340.45 341.17
System Peak Demand (MW) 281.63 277.06 274.32 267.98 275.84 267.42
Reserve Margin at Time of Peak 35.5% 24.3% 36.0% 23.2% 23.4% 27.6%
System Load Factor 75.4% 79.5% 77.0% 79.9% 73.5% 76.4%
=================================================================================================================================
* Includes the reserve established on certain licensing activites in 1993 ($5.6 million after taxes or $.95 per common
share). (See note 6).
</TABLE>
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS
AND FINANCIAL CONDITION
Item 7
RECENT EVENTS AFFECTING THE ELECTRIC UTILITY INDUSTRY AND THE COMPANY
RESTRUCTURING THE INDUSTRY-In 1997, the Maine Legislature enacted "An Act to
Restructure the State's Electric Industry", some of the principal provisions
of which 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) The Company must divest of most of its generation related assets and
business functions. As discussed below, the Company has reached agreement for
the sale of many of those assets and is preparing for an anticipated closing
of that transaction.
(3) Billing and metering services will be subject to competition beginning
March 1, 2002, but the legislation permits the Maine Public Utilities
Commission (MPUC) to establish an earlier date, no sooner than March 1, 2000.
(4) The Company will continue to provide transmission and distribution
services and continue to be subject to regulation by the MPUC.
(5) 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 ("stranded costs").
Under the restructuring law, the Company, as a transmission and distribution
utility, will be prohibited from engaging in the generation and sale of
electric energy. The law permits the Company to establish an independent
affiliate to engage in retail electricity marketing activities, but only on a
limited basis and subject to stringent rules governing the relationship among
the regulated utility, its independent marketing affiliate and other
competitors. In light of those restrictions, the Company does not believe it
will be involved in the generation and sale of energy after March 1, 2000 and
that its basic business will continue to be as a regulated transmission and
distribution utility. The Company may also pursue appropriate opportunities
in other regulated or unregulated business activities that are compatible
with the Company's basic business and are not burdened with the restrictions
that will apply to electricity marketing activities.
Much of the Company's focus and resources over the near term will be devoted
to facilitating the implementation of the restructuring law. Many of the
Company s basic business processes will have to be adapted to meet the
requirements of the changed business environment. In addition, the MPUC will
soon be deciding a number of issues relating to restructuring that will have
an impact on the Company's future earnings, including the procedures for
future rate regulation and the levels of stranded costs for which recovery
will be allowed. For a more complete discussion of the industry restructuring
legislation and the current MPUC proceedings to determine the Company's
stranded cost recovery, see Note 10 to the Consolidated Financial Statements.
AGREEMENT ON SALE OF COMPANY'S GENERATING ASSETS-On September 25, 1998, the
Company and PP&L Global, Inc., a Pennsylvania corporation and a subsidiary of
PP&L Resources, Inc., reached an agreement for PP&L Global to acquire most of
the Company's electric generating assets with a combined base load capacity
of 89.2 megawatts and certain transmission rights for a sale price of $89
million. The proposed sale is a result of the Company's effort to comply with
Maine s electric utility restructuring legislation, which took effect in
September 1997. The Company began seeking proposals from prospective bidders
to purchase its generation and generation-related assets in early 1998 and as
part of the auction process, received final bids from various bidders in
August 1998.
The electric utility restructuring law requires all of Maine's investor-owned
electric utilities to divest all of their non-nuclear generation assets and
generation-related business before March 1, 2000. The law was enacted to
foster competition in an open market in which retail consumers will choose
among competitive energy providers of the electricity that flows through the
wires. The management of the "wires" or transmission and distribution
business will remain the regulated function of the existing utilities.
Pursuant to the agreement, the Company has agreed to sell to PP&L Global (i)
its Ellsworth, Howland, Milford, Medway, Orono, Stillwater and Veazie
hydroelectric facilities, which are all situated along the Penobscot River
Basin and Union River in Maine, (ii) the 50% ownership interest owned by
Penobscot Hydro Co., Inc., a wholly owned subsidiary of the Company, in
Bangor-Pacific Hydro Associates, which owns a 13 megawatt hydroelectric
generating facility located in Enfield and Howland, Maine, (iii) the
Company s 8.33% joint ownership interest in the William F. Wyman Unit No. 4
oil-fired steam plant located in Yarmouth, Maine, (iv) the Company's designs,
applications and other rights with respect to the potential development of
the Basin Mills hydroelectric project, to be located in Bradley and Orono,
Maine, (v) the Company s designs, applications and other rights with respect
to the potential development of a high-voltage transmission line from Orring-
ton, Maine, to New Brunswick, Canada, and (vi) certain of the Company's
rights to transmission capacity, including its rights as a participant in the
regional utilities agreements with Hydro-Quebec.
The sale is subject to certain closing conditions as set forth in the
agreement, including receipt of approvals by federal and state regulatory
agencies. The MPUC has already given approvals for the sale, and other
outstanding governmental proceedings should be resolved within the next few
months. In addition, third-party consents to the sale of certain of the
assets will be required, and the Company cannot predict whether or on what
terms such consents can be obtained. The Company anticipates that most of the
net after-tax proceeds from the sale will be used to retire outstanding debt.
The Company expects that a portion of the sale value will be applied to
reduce the Company s stranded costs for regulatory purposes, which should
lower the amounts that would otherwise be collected in the future from
customers.
SALE OF PROPERTY AT GRAHAM STATION-In September 1998, the Company sold
certain property and equipment at its Graham Station site in Veazie, Maine,
to Casco Bay Energy for $6.2 million. The property is to be utilized by Casco
Bay Energy, which plans to construct a $221 million gas-fired power plant
that will produce 520 megawatts of electricity. The plant will be powered by
the proposed Maritimes & Northeast gas transmission line and regional
transmission system. The Company realized a net gain from the sale of $4.5
million, which has been deferred (reflected as a component of Other Deferred
Credits on the Consolidated Balance Sheet at December 31, 1998) in
anticipation that it will likely be utilized as a future reduction to the
Company s recoverable stranded costs. In connection with the sale, the $6.2
million in proceeds were deposited with a third party trustee, as a
requirement under the Company's bond indenture. The $6.2 million was released
to the Company in January 1999 and has been utilized to repay a portion of
the Company s medium term notes. Also in connection with the sale, the
Company deposited $400,000 with a third party trustee to be utilized for
future environmental remediation at the site. Management does not expect the
future remediation costs at the site to exceed this amount.
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
nuclear generating plant in Wiscasset, Maine. The plant is currently in the
process of being decommissioned, and the Company is obligated to pay its
prorata share of Maine Yankee's plant closure and decommissioning costs.
On January 19, 1999, various interested parties submitted an offer of
settlement with the Federal Energy Regulatory Commission (FERC) that, if
accepted by FERC, will finally settle a number of outstanding rate recovery
issues with respect to the Company s ownership of Maine Yankee. For a more
complete discussion of the recent events associated with Maine Yankee, see
Note 6 to the Consolidated Financial Statements.
AMENDED AND RESTATED REVOLVING CREDIT AND TERM LOAN AGREEMENT-As reported in
the 1997 Form 10-K, during 1997 the Company negotiated amendments to the
credit agreement with its lending banks in order to resolve potential
violations of certain financial covenants. As a result of those amendments,
the Company reported that during 1998 or beyond, future cash needs might
exceed the borrowing capacity under the credit facility, and accordingly, the
Company might be required to find new sources of financing.
On June 29, 1998, the Company entered into an Amended and Restated Revolving
Credit and Term Loan Agreement with a new group of lenders that provided a
two-year term loan of $45 million and a revolving credit commitment of $30
million. Under current projections of cash needs, the new facilities should
provide adequate borrowing capacity. The Company was in compliance with all
financial covenants associated with the new credit agreement as of December
31, 1998.
The credit agreement 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 $4.6 million of the proceeds from this
financing with a third party trustee. The new letter of credit was issued in
October 1998, and the $4.6 million deposited with the third party trustee was
released to the Company. These funds were utilized to repay amounts
outstanding under the Company s revolving credit facility.
MONETIZATION OF POWER SALE CONTRACT-As reported in the 1997 Form 10-K, the
Company had been negotiating a transaction for the monetization of a power
sale contract with UNITIL Power Corp. (UNITIL), a New Hampshire based
electric utility. The Company provided power to UNITIL at significantly
above-market rates, with the contract term ending in the year 2003. Based
upon projections of wholesale electricity markets, it was expected that the
rates charged under the UNITIL contract would remain at above-market levels
for the remainder of the contract term. Therefore, the assignment of the
Company s rights under the contract had a positive present cash value. On
March 31, 1998, the Company completed a transaction with a financial
institution that provided a loan of approximately $23.3 million in net
proceeds secured by the value of the UNITIL contract.
Also as reported in the 1997 Form 10-K, beginning in early 1997, the Company
failed to comply with certain financial covenants under its bank lending
agreements and received temporary waivers from the lending banks. By using a
portion of the proceeds of the UNITIL monetization to pay down a portion of
the bank obligations, the Company was able to negotiate permanent waivers of
the earlier financial covenant violations.
At the time the Company filed its 1997 Form 10-K, the monetization of the
UNITIL contract had not been completed and the financial covenant violations
had, therefore, not been waived permanently. As discussed in the 1997 Form
10-K, all debt under the bank credit facilities, including certain medium
term notes, was classified as a current liability on the Company s
Consolidated Balance Sheets as of December 31, 1997. As a result of the
permanent waivers that became effective upon completion of the UNITIL
monetization, $22 million of medium term notes, previously classified as a
current liability, were reclassified as a long-term liability as of March 31,
1998.
RESTRUCTURING OF POWER PURCHASE CONTRACT-As previously reported in the 1997
Form 10-K, the Company had 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 offered a potential
for substantial savings. In June 1998 the Company successfully completed this
major restructuring of its obligations under various agreements with PERC.
It is anticipated that the restructuring will result in a substantial savings
for the Company and will allow PERC to continue to meet the solid waste
disposal needs of Maine communities.
This major restructuring involved several separate components which are more
fully explained in Note 6 to the Consolidated Financial Statements.
Depending upon a number of assumptions, including the ultimate cost of the
warrants and markets for solid waste disposal, it is projected that the
restructuring will result in cost savings to Bangor Hydro over the next
twenty years with a net present value of $25-40 million. The anticipated
savings resulting from this transaction were used to reduce the level of
electric rates approved by the MPUC in the Company's recent general rate case
by approximately $2.4 million on an annual basis.
The Company has deferred, as a regulatory asset, the $6.25 million in
payments to PERC, approximately $1.5 million in costs associated with the
contract restructuring, and $2 million for the estimated fair value of the
warrants. As discussed above, the Company is currently recovering PERC
restructuring costs in rates. The $2 million in warrants have also increased
additional paid-in capital on the Consolidated Balance Sheets.
STORM DAMAGE-As discussed in the 1997 Form 10-K, the Company suffered
widespread damage throughout its service territory to its transmission and
distribution equipment during a major ice storm in January 1998. The
Company s incremental costs associated with the service restoration effort
were approximately $4.5 million and have been deferred and included in Other
Deferred Charges on the Company s Consolidated Balance Sheets as of December
31, 1998. The MPUC issued an order authorizing the Company to defer
incremental, non-capitalized storm damage expenses for future recovery
through the rates charged to customers. The Company is seeking to begin
recovery of those deferred costs on May 1, 1999 as part of its annual rate
adjustment pursuant to its Alternative Rate Plan (see Note 10).
BANGOR GAS JOINT VENTURE-The Company and Energy Pacific, LLC, now Sempra
Energy, have formed a joint-venture company, Bangor Gas Company, LLC, (Bangor
Gas), that, in the second quarter of 1998, received unconditional authority
from the MPUC to provide natural gas service to the greater Bangor area. In
October 1998 the Company received authorization from the MPUC to invest
approximately $1.2 million in Bangor Gas.
Los Angeles based Sempra Energy is a joint-venture of Pacific Enterprises and
Enova Corporation. 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 late
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 but has
the opportunity to make material capital contributions to the joint-venture
in the near term.
COMMON STOCK DIVIDENDS-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.
IMPACT OF THE YEAR 2000 ISSUE-The "Year 2000" problem exists because some
computer programs and embedded microchips may not properly recognize a year
that begins with "20" instead of "19", and therefore may fail or create
erroneous results. The Company is actively engaged in identifying, assessing,
and responding to the implications of this problem for its operations.
The Company has identified all of its information technology systems and is
assessing and testing its Year 2000 compliance. The Company has established a
structured approach which inventories and prioritizes its electrical systems,
client server and network applications, desktop and personal computer
systems, and facilities. The Company s goal is that most, if not all,
computer programs and embedded chips that support its mission critical
operations will be compliant by mid-year 1999.
The Company's business is dependent upon external parties, such as suppliers
and business partners, for the reliable delivery of its products and
services. The Company has inquired in writing to its suppliers and service
providers with regard to their Year 2000 compliancy, and has established
appropriate follow-up procedures. The Company has also identified the third
parties with which it has a material relationship in order to establish their
Year 2000 status in a timely fashion, and is continuing to do so.
In addition to normal suppliers and business partners, the Company has a risk
that power will not be available on the New England Power Pool (NEPOOL) grid
for purchase and distribution to the Company s customers if electrical system
failures occur due to the Year 2000 issue. This is a significant risk, since
the Company purchases a substantial portion of its energy, which is received
through the NEPOOL grid. The Company is working to mitigate this risk by
participation on the Independent System Operator (ISO) subcommittees and in
the NEPOOL/ISO New England Year 2000 Joint Oversight Committee which has been
given responsibility for operational reliability of the NEPOOL Control Area.
This group is in the early stages of assessing NEPOOL/ISO s Year 2000 problem
and has a goal of ensuring the NEPOOL Control Area is Year 2000 compliant by
July 1, 1999. In addition, the Company is participating in and complying with
North American Electric Reliability Council (NERC) Year 2000 reporting and
guidelines. NERC has been given authority from the President's Council on
Year 2000 via the Department of Energy and has the responsibility for
guidance and oversight for the nation's electrical systems.
The Company began an initial information technology awareness plan in 1992
with the year 2000 in mind. There was an immediate development of a long-term
(five-year) technology plan to address the year 2000 as well as other issues
such as obsolete applications, hardware, and infrastructure. Implementation
of this five-year plan began in 1994 with two mission critical projects for
replacing the Customer Information System and implementing a new Geographical
Information System. In addition, the Company began replacement of its
Financial Information Systems in 1995. These major projects and the
advancement of technology in general drove infrastructure upgrades.
In addition to the major applications mentioned above, the Company has
continually updated its transmission and distribution systems, substations,
and metering devices and has become increasingly more reliant on various
technologies.
Due to the nature of the technological architecture and the fact that the
Company has kept pace with technologies, many of the enterprise information
systems are stated to be compliant by the vendors and the Company does not
believe it will need to expend funds to implement totally new enterprise
systems. The Company does, however, have other hardware and software that is
not compliant and will need to be replaced or upgraded. In addition, the
Company will also be conducting comprehensive testing to help ensure a
compliant environment exists and conducting vendor inquiries. The Company has
also begun comprehensive contingency planning for its own operations and
continues to monitor the integrated contingency planning efforts of NERC and
the Northeast Power Coordinating Council.
The estimated cost to conduct testing, develop or modify contingency plans,
and replace non-compliant technologies is approximately $2 million, with
most of these costs to be incurred during 1999. Approximately $850,000 of
these estimated costs are expected to be capitalized, instead of being
charged to expense, since the costs relate principally to investments in new
equipment and technologies and not the modification of existing systems. To
date, approximately $408,000 has been expended in connection with the Year
2000 issue, of which $320,000 has been capitalized and $88,000 charged to
expense. Time and cost estimates are based on currently available information
and could be affected by the ability to correct all relevant computer codes
and equipment, and the Year 2000 readiness of the Company's business
partners, among other factors.
There is no certainty as to whether the Company will be able to solve its
potential Year 2000 issues. Consequently, the Company is in the process of
identifying and verifying realistic failure scenarios which will require
contingency plans. While its analysis has not been completed, the Company
anticipates establishing a prioritized list of potential failures with a
formal contingency plan for each one deemed critical to its ongoing
operations during 1999.
Based on information reviewed to date, the Company believes its plans of
action are adequate for Year 2000 compliance of its critical systems and to
reduce the risk of external impacts to its operations. Nevertheless,
achieving Year 2000 compliance is subject to the risks and uncertainties
described above and adverse effects, should they occur, could be material
despite the Company's efforts to prevent or mitigate them.
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, the Year 2000 issue
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 1998, 1997 and 1996 as they affect the Company s liquidity. Net cash
provided by operations was $30.9 million in 1998, $36.4 million in 1997 and
$44.8 million in 1996.
Negatively impacting cash flows from operations in the 1998 period were the
approximately $7.7 million in costs incurred to restructure the PERC
purchased power contract, approximately $4.5 million in incremental costs
incurred in connection with the January 1998 ice storm, as well as $2.3
million in costs incurred related to selling the Company s generation assets.
Cash flows were also reduced by the effect of a large customer, who prepaid
its electric usage for a one-year period in the third quarter of 1997.
Finally, reducing cash flows from operations in the 1998 period was
approximately $1.5 million in costs incurred associated with the new
revolving credit facility, term loan and the $24.8 million in medium term
notes. Offsetting these cash flow reductions was the beneficial impact of the
3.8% temporary rate increase on July 1, 1997, the 5.83% rate increase
effective February 1998, and the reduction in Maine Yankee related costs
incurred in 1998 as a result of the shutdown of the plant in 1997.
Also impacting cash flows from operations was the previously discussed Graham
Station property sale proceeds. While the Company did realize a $4.5 million
gain on sale of the property, the full $6.2 million in proceeds were required
to be deposited with a third party trustee. Also in connection with the sale,
the Company deposited $400,000 with a third party trustee to be utilized for
future environmental remediation at the site.
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 million 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.
Over the last three years, capital expenditures have been $18.2 million in
1998, $17.5 million in 1997 and $18.8 million in 1996. In 1998, approximately
$2.6 million of the capital expenditures was related to implementing new
geographic and financial information systems, $.9 million was related to the
Company s power production facilities, $7.3 million was for its distribution
system, and $6.2 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 and $65 million over the next three years
(excluding capital expenditures related to the previously discussed gas fired
power plant being developed by Casco Bay Energy, which will be reimbursed),
although it may be necessary to adjust the budget for capital expenditures on
a year-to-year basis.
No common dividends were paid in 1998. Dividends paid on common stock were
lower in 1997 as compared to 1996 due to the suspension of the common
dividend, beginning with the first quarter of 1997. The reduction in
preferred dividends paid in 1998 and 1997 resulted from sinking fund payments
made on the Company's 8.76% mandatory redeemable preferred stock.
The Company made $1.8 million in sinking fund payments on its 12.25% first
mortgage bonds in 1998. In the first quarter of 1998 the Company made the
final $2.5 million payment on its 6.75% first mortgage bonds and made a $4
million principal repayment on its medium term notes. In June 1998 the
Company made a $12.3 million principal payment on its Finance Authority of
Maine Revenue Notes. Also, as previously discussed, in connection with the
new credit agreement, the Company fully repaid its $30 million in outstanding
medium term notes in June 1998. In 1998 the Company made $2.9 million in
principal payments associated with the medium term notes issued in connection
with the UNITIL contract monetization. In 1998 the Company 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.
As previously discussed, in connection with the monetization of the UNITIL
contract, the Company issued $24.8 million in medium term notes on March 31,
1998. The Company s net proceeds from this issuance were $23.3 million, due
to the requirement to deposit $1.5 million in a capital reserve fund for the
final payment of principal and interest in 2002. Of the $23.3 million of
proceeds received, the Company utilized $19 million to repay borrowings
outstanding under its revolving credit facility. The remaining funds were
utilized for the PERC purchased power contract restructuring transaction
discussed above. Also, as previously discussed, the Amended and Restated
Revolving Credit and Term Loan Agreement provided a two-year term loan of $45
million.
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. The Company also
made approximately $94,000 in make whole provision payments under the 8.76%
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 1998, 1997 and 1996 were met through
internally generated funds, the Company's revolving credit line, and, for
1998, the new medium term notes. As a result of the Amended and Restated
Revolving Credit and Term Loan Agreement, the new facilities should provide
adequate borrowing capacity for the Company's operation, maintenance and
construction funding requirements.
The Company has $181.1 million of first mortgage bond and other long-term
debt sinking fund requirements and maturities in the period 1999-2003. The
Company also has $1.5 million of mandatory annual sinking fund payments and
$94,000 of annual payments under the make whole provision on its redeemable
preferred stock.
RESULTS OF OPERATIONS
Earnings (loss) per common share were $1.39, $(.24), and $1.33 for the years
ended 1998, 1997 and 1996, respectively. Earned return on average common
equity was 9.1% in each of 1998 and 1996. The improvement in 1998 earnings is
attributable largely to the February 1998 rate increase authorized by the
MPUC designed to increase annual revenues by approximately $13.2 million.
Negatively impacting earnings in 1997 was 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.
Electric operating revenue for 1998 increased by $7.8 million as compared to
1997 principally due to the 3.8% temporary rate increase effective on July 1,
1997 and the additional 5.83% rate increase effective February 1998. Also
benefitting 1998 revenues was a $1 million increase in off-system sales
(sales related to power pool and interconnection agreements and resales of
purchased power). Offsetting these positive factors somewhat was a 3.4%
reduction in total kilowatt-hour (KWH) sales (excluding off-system sales) in
1998 as compared to 1997, due primarily to decreased usage by the Company s
largest special contract customers and the fact that 1998 was the warmest
year on record, which along with the January 1998 ice storm, resulted in
reduced electricity sales. Also decreasing electric operating revenues in
1998 as compared to 1997 was the recording in 1997 of $335,000 in revenues
from the sale of air emission allowances to a coal fired generating facility,
and $350,000 in revenue recognized under a shared savings distribution
agreement with another utility.
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 as compared to 1996.
Electric operating revenue for 1997 decreased by $49,000 as compared to 1996.
There was a $4.9 million decrease in off-system sales in 1997, and revenue
sharing (discussed above) decreased by $3.2 million in 1997. Electric
operating revenue associated with 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.
Fuel for generation and purchased power expense decreased by $10.8 million in
1998 as compared to 1997. The principal reason for the reduction was lower
expenses associated with the permanent shutdown of the Maine Yankee nuclear
power plant in 1998, as compared to maintaining the plant in an operating
mode in the first five months of 1997. Also, in connection with the Company's
recent rate order (see the 1997 Form 10-K for discussion of the rate order),
the Company was ordered to defer, for future recovery, the excess of actual
Maine Yankee related costs incurred during 1998 over the Maine Yankee costs
included in the rate order. In the 1998 period, Maine Yankee related
expenses, including the cost of replacement power, were approximately $7.3
million lower than in 1997. The Company also recorded a $2 million benefit in
1998 related to savings realized from the previously discussed PERC contract
restructuring. Also, in December 1997 the Company charged to expense $1.9
million of previously deferred Maine Yankee refueling costs, as a result of
the Company's February 1998 rate order, which disallowed recovery of these
deferred costs.
The Company realized positive cash settlements under its fuel hedge program
(for a more complete discussion of the Company s fuel hedge program, see Note
13 to the Consolidated Financial Statements) in 1997 as compared to negative
cash settlements in 1998. This change is due principally to the spot price of
residual oil decreasing significantly (over 25%) in 1998 as compared to 1997,
increased hedge volume (covering replacement power for the Maine Yankee
closure) in 1998, and the Company's hedge in 1998 was at a higher fixed cost
than in 1997. Also offsetting the previously discussed decreases to some
extent was the $1.0 million increase in off-system sales in the 1998 period,
as well as the impact of the 3.4% reduction in KWH sales in 1998 as compared
to 1997.
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. 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 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, as discussed above, the Company charged to expense $1.9 million of
previously deferred Maine Yankee refueling costs. Offsetting these increases
was the $4.9 million reduction in off-system sales in 1997. Also, in 1997 the
Company deferred approximately $719,000 in Maine Yankee related costs in
connection with the February 1998 rate order discussed above.
Other operation and maintenance (O&M) expense increased by $2.0 million in
1998 as compared to 1997. O&M payroll expense increased by $1.5 million due
principally to significantly less payroll charged to the Company's capital
program in 1998. The lower capital labor was primarily a result of service
restoration efforts associated with the January 1998 ice storm. The Company
was ordered by the MPUC to defer incremental non-capital costs related to the
ice storm, but the non-incremental labor costs were charged principally to
other O&M in the first quarter of 1998. The increase from 1997 to 1998 was
also impacted by a 3% wage rate increase for union employees in 1998 and
various nonunion wage rate increases. Also affecting the greater other O&M
expense in 1998 was a $680,000 increase in postretirement medical and pension
and active employee medical costs in 1998 as compared to 1997.
Depreciation and amortization expense decreased $438,000 in 1998 as compared
to 1997. Effective February 1998, in connection with the Company's most
recent rate order, the Company lengthened the depreciable lives of its large
information system capital projects from seven to ten years, and began
amortizing its $3.6 million overaccumulated depreciation reserve ($1.6
million of amortization in 1998), thus reducing depreciation expense. These
decreases were offset to some extent by the impact of 1998 property
additions.
The increases in depreciation and amortization expense in 1997 as compared to
1996 was principally caused by the termination, on December 31, 1996, of the
amortization of the remaining balance of the overaccumulated reserve for
depreciation. This amortization, which reduced annual depreciation expense,
amounted to $1.8 million in 1996. The depreciation expense increase in 1997,
as well as in 1996, was 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 1996-1998 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. Effective December 12, 1997, the MPUC ordered the
amortization of this regulatory asset be returned to its level prior to the
temporary rate order. Effective with the latest rate order in February 1998,
the amortization was reduced, so that the unamortized balance of the
regulatory asset would be the same as under the original amortization
schedule as of March 1, 2000. Consequently, as a result of the rate orders,
amortization associated with this regulatory asset was $2.9 million in 1998
as compared to $6.1 million in 1997.
The approximately $170 million of costs associated with the 1995 purchased
power contract buy-back were deferred and recorded as a regulatory asset, to
be amortized and collected over a ten-year period, beginning July 1, 1995.
Amortization expense related to this contract buyout amounted to $17 million
in 1998 and 1997. Also impacting amortization of contract buyouts and
restructuring was the start of the amortization of the previously discussed
PERC contract restructuring on July 1, 1998, resulting in $500,000 of
amortization in 1998.
Property and other taxes increased in 1998 due to increases in property
taxes, as a result of increases in property levels and property tax rates,
and due to the previously mentioned increase in O&M labor costs in 1998,
associated payroll taxes increased in 1998.
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 increase in income taxes was principally a function of greater earnings
in 1998 as compared to 1997.
The decrease in income taxes in 1997 as compared to 1996 was primarily a
function of the operating loss in 1997 and 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.
The increase in allowance for funds used during construction (AFDC) in 1998
as compared to 1997 was due primarily to recording carrying costs on deferred
ice storm and incremental Maine Yankee related costs. AFDC related to
construction work in progress was lower in 1998 due to reduced construction
activity. The 1997 decrease in AFDC was principally a function of lower
levels of construction work in progress.
The decreases in other income in 1998 and 1997 was due primarily to the
write-off of start-up costs associated with non-core business ventures by the
Company.
The increase in long-term debt interest expense in 1998 was due primarily to
the previously discussed issuance of the $24.8 million of medium term notes
on March 31, 1998 and the $45 million term loan issued in June 1998, offset
by the previously discussed principal repayments in 1997 and 1998 on various
long-term debt issues.
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.
Other interest expense decreased due principally to a $10.9 million reduction
in the weighted average short-term borrowings in 1998 as compared to 1997, as
well as a slight decrease in the weighted average interest rate (including
fees) on the borrowings. These decreases were offset to some extent by a
$337,000 increase in the amortization of debt issuance costs in 1998.
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.
CONTINGENCIES AND RISK MANAGEMENT
ENVIRONMENTAL MATTERS-In 1992, the Company received notice from the Maine
Department of Environmental Protection that it was investigating the cleanup
of several sites in Maine that were used in the past for the disposal of
waste oil and other hazardous substances, and that the Company, as a
generator of waste oil that was disposed at those sites, may be liable for
certain cleanup costs. The Company learned in October 1995 that the United
States Environmental Protection Agency placed one of 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, 1998, 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.
RISK MANAGEMENT-The Company's major financial market risk exposures are
changing interest rates and changes in purchased energy prices. Changing
interest rates will affect interest paid on variable rate debt and the fair
value of fixed rate debt. The Company manages interest rate risk through a
combination of both fixed and variable rate debt instruments and derivative
financial instruments, including an interest rate swap and interest rate caps
(see Notes 4 and 13). The Company manages purchased energy price risk through
the use of swaps (see Note 13). The Company does not hold or issue
derivatives for trading purposes.
NEW ACCOUNTING PRONOUNCEMENTS
In June 1998, the Financial Accounting Standards Board issued Statement No.
133, "Accounting for Derivative Instruments and Hedging Activities" (FASB
133), and is effective for fiscal years beginning after June 15, 1999. FASB
133 establishes accounting and reporting standards for derivative instruments
and for hedging activities. It requires that an entity recognize all
derivatives as either assets or liabilities in the statement of financial
position and measure those instruments at fair value. Changes in the
derivatives fair value should be recognized currently in earnings unless the
derivative is designated as a hedge. When designated as a hedge, the change
in fair value should be recognized currently in changes in equity. FASB 133
also requires a company to formally document, designate and assess the
effectiveness of transactions that receive hedge accounting treatment. The
affects of the adoption of FASB 133 on the Company s financial statements are
currently not known. The Company believes that its fuel and interest rate
swap agreements will qualify for hedge accounting treatment under FASB 133.
In April 1998, the American Institute of Certified Public Accountants issued
Statement of Position 98-5, "Reporting on the Costs of Start-up Activities"
(SOP 98-5). The Company is required to adopt SOP 98-5 for fiscal year 1999.
SOP 98-5 defines start-up activities as onetime activities an entity
undertakes when it opens a new facility, introduces a new product line or
service, conducts business in a new territory or with a new class of customer
or beneficiary, initiates a new process in an existing facility or commences
some new operation. SOP 98-5 covers accounting for organization costs and
requires that any such costs should be expensed as incurred in the same
manner as other start-up costs. The statement requires entities to expense
previously capitalized costs in the year of adopting SOP 98-5. The Company
does not believe the application of this statement will have a material
impact on the financial statements.
BANGOR HYDRO-ELECTRIC COMPANY
Item 8 CONSOLIDATED STATEMENTS OF INCOME
Financial Statements
& Supplementary Data
For the Years Ended December 31,
1,998 1997 1996
ELECTRIC OPERATING REVENUE (Note 1): $ 195,144,007 $ 187,324,379 $ 187,373,630
-------------- ---------------------------
OPERATING EXPENSES:
Fuel for generation and purchased
power (Notes 1 and 3) $ 82,026,860 92,791,842 $ 78,476,864
Other operation and maintenance
(Notes 1 and 5) 34,448,324 32,471,149 32,440,649
Depreciation and amortization
(Note 1) 9,749,229 10,187,102 7,429,719
Amortization of Seabrook Nuclear
Project (Note 7) 1,699,050 1,699,050 1,699,050
Amortization of contract buyouts
and restructuring (Note 6) 20,442,441 23,218,500 20,836,561
Taxes -
Local property and other 5,549,049 5,124,146 5,367,045
Income (Note 2) 6,093,286 (1,956,303) 4,882,453
-------------- ---------------------------
$ 160,008,239 163,535,486 $ 151,132,341
-------------- ---------------------------
OPERATING INCOME $ 35,135,768 23,788,893 $ 36,241,289
OTHER INCOME AND (DEDUCTIONS):
Allowance for equity funds used
during construction (Note 1) 430,028 285,972 368,056
Other, net of applicable income taxes
(Notes 1 and 2) 862,723 1,005,849 1,097,931
-------------- ---------------------------
INCOME BEFORE INTEREST EXPENSE $ 36,428,519 25,080,714 $ 37,707,276
-------------- ---------------------------
INTEREST EXPENSE:
Long-term debt (Notes 4 and 13) $ 22,906,021 22,638,201 $ 23,651,316
Other (Note 4) 2,750,863 3,392,169 3,529,002
Allowance for borrowed funds used
during construction (Note 1) (693,682) (562,966) (755,708)
-------------- ---------------------------
$ 24,963,202 25,467,404 $ 26,424,610
-------------- ---------------------------
NET INCOME (LOSS) $ 11,465,317 (386,690)$ 11,282,666
DIVIDENDS ON PREFERRED STOCK (Note 3) 1,244,488 1,375,888 1,537,202
-------------- ---------------------------
EARNINGS (LOSS) APPLICABLE TO
COMMON STOCK $ 10,220,829 (1,762,578)$ 9,745,464
============== ===========================
EARNINGS (LOSS) PER COMMON SHARE, based
on the weighted average number of
shares outstanding of 7,363,424 in
1998 and 1997 and 7,336,174 in 1996
(Note 3):
Basic $ 1.39 $ (0.24)$ 1.33
Diluted 1.33 (0.24) 1.33
============== ===========================
DIVIDENDS DECLARED PER COMMON SHARE $ - $ - $ 0.72
============== ===========================
The accompanying notes are an integral part of these consolidated
financial statements.
BANGOR HYDRO-ELECTRIC COMPANY
CONSOLIDATED BALANCE SHEETS
December 31,
ASSETS 1998 1997
INVESTMENT IN UTILITY PLANT:
Electric plant in service, at original
cost (Notes 6 and 10) $ 352,975,549 $ 341,008,967
Less - Accumulated depreciation and
amortization (Notes 1 and 6) 101,633,446 96,594,713
---------------------------
$ 251,342,103 $ 244,414,254
Construction work in progress (Note 1) 13,929,940 12,011,246
---------------------------
$ 265,272,043 $ 256,425,500
Investments in corporate joint ventures (Notes 1
and 6) -
Maine Yankee Atomic Power Company $ 5,438,520 $ 5,531,912
Maine Electric Power Company, Inc. 438,753 326,005
---------------------------
$ 271,149,316 $ 262,283,417
---------------------------
OTHER INVESTMENTS, at cost (Note 6) $ 5,881,986 $ 5,274,213
---------------------------
FUNDS HELD BY TRUSTEE at cost (Notes 4,9 and 11) $ 29,867,605 $ 21,195,772
---------------------------
CURRENT ASSETS:
Cash and cash equivalents (Notes 1 and 9) $ 2,945,946 $ 936,796
Accounts receivable, net of reserve ($1,075,000
in 1998 and $1,450,000 in 1997) 17,558,084 16,614,977
Unbilled revenue receivable (Note 1) 12,086,003 11,605,163
Inventories, at average cost:
Materials and supplies 2,909,219 2,759,091
Fuel oil 16,233 34,771
Prepaid expenses 1,129,259 1,206,596
Deferred Maine Yankee refueling costs (Note 1 & 10) - 285,894
---------------------------
Total current assets $ 36,644,744 $ 33,443,288
---------------------------
DEFERRED CHARGES:
Investment in Seabrook Nuclear Project, net of
accumulated amortization of $30,173,196 in 1998
and $28,474,146 in 1997 (Notes 7 and 10) $ 28,668,879 $ 30,367,929
Costs to terminate/restructure purchased power
contracts, net of accumulated amortization of
$80,058,702 in 1998 and $59,616,261 in 1997
(Notes 6 and 10) 136,979,490 147,632,924
Maine Yankee decommissioning costs (Notes 6 and 10) 50,054,620 60,923,840
Deferred regulatory assets (Notes 2, 5 and 10) 32,995,632 32,551,381
Demand-side management costs (Note 10) 778,742 1,705,311
Other (Notes 10 and 12) 12,666,813 5,204,718
---------------------------
Total deferred charges $ 262,144,176 $ 278,386,103
---------------------------
Total Assets $ 605,687,827 $ 600,582,793
===========================
The accompanying notes are an integral part of these consolidated
financial statements.
BANGOR HYDRO-ELECTRIC COMPANY
CONSOLIDATED BALANCE SHEETS
December 31,
1998 1997
STOCKHOLDERS' INVESTMENT AND LIABILITIES
CAPITALIZATION (see accompanying statement):
Common stock investment (Note 3) $ 118,864,092 $106,558,488
Preferred stock (Note 3) 4,734,000 4,734,000
Preferred stock subject to mandatory redemption,
exclusive of sinking fund requirements
(Notes 3 and 9) 7,604,150 9,137,160
Long-term debt, net of current portion
(Notes 4, 9 and 13) 263,027,692 221,642,897
----------------------------
Total capitalization $ 394,229,934 $342,072,545
----------------------------
CURRENT LIABILITIES:
Notes payable - banks (Note 4) $ 12,000,000 $ 34,000,000
----------------------------
Other current liabilities -
Current portion of long-term debt and sinking
fund requirements on preferred stock
(Notes 3, 4 and 9) $ 27,109,119 $ 52,172,468
Accounts payable 13,895,673 13,170,952
Dividends payable 294,593 327,443
Accrued interest 3,474,369 3,666,641
Deferred revenue (Note 1) - 1,570,995
Customers' deposits 328,923 296,706
Current income taxes payable 85,685 7,768
----------------------------
Total other current liabilities $ 45,188,362 $ 71,212,973
----------------------------
Total current liabilities $ 57,188,362 $105,212,973
----------------------------
COMMITMENTS AND CONTINGENCIES (Notes 6, 12 and 14)
DEFERRED CREDITS AND RESERVES (Note 2):
Deferred income taxes - Seabrook $ 14,880,241 $ 15,765,811
Other accumulated deferred income taxes 63,774,505 55,858,652
Maine Yankee decommissioning liability (Note 6) 50,054,620 60,925,586
Deferred regulatory liability (Note 10) 9,618,159 9,972,246
Unamortized investment tax credits 1,720,708 1,962,014
Accrued pension and postretirement benfit
costs (Note 5) 7,770,149 7,034,204
Other (Note 11) 6,451,149 1,778,762
----------------------------
Total deferred credits and reserves $ 154,269,531 $153,297,275
----------------------------
Total Stockholders' Investment and Liabilities $ 605,687,827 $600,582,793
============================
The accompanying notes are an integral part of these consolidated
financial statements.
BANGOR HYDRO-ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF CAPITALIZATION
December 31,
1998 1997
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 1998 and
1997 $ 36,817,120 $ 36,817,120
Amounts paid in excess of par value 59,054,203 56,969,428
Retained earnings 22,992,769 12,771,940
- ------------------------------------------------------------------------------
Total common stock investment $ 118,864,092 $ 106,558,488
- ------------------------------------------------------------------------------
Preferred Stock, Non-participating, cumulative, par
value $100 per share,
authorized 600,000 shares (Notes 3 and 9):
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 103.15% if called on or
prior to December 27, 1999, 150,000
shares authorized and 90,000 shares
outstanding in 1998 and 105,000 out-
standing in 1997 $ 9,198,064 $ 10,731,074
Less-Sinking fund requirements 1,593,914 1,593,914
- ------------------------------------------------------------------------------
$ 7,604,150 $ 9,137,160
- ------------------------------------------------------------------------------
LONG-TERM DEBT (Notes 4, 9 and 13):
First Mortgage Bonds-
6.75% Series due 1998 $ - $ 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 3,742,897 5,521,451
- ------------------------------------------------------------------------------
$ 103,742,897 $ 108,021,451
Less-Sinking fund requirements and current
maturity in 1997 1,675,205 4,278,554
- ------------------------------------------------------------------------------
$ 102,067,692 $ 103,742,897
- ------------------------------------------------------------------------------
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 $ 113,700,000 $ 126,000,000
Medium Term Notes, Variable interest rate -
LIBO rate plus 2%, due 2000 - 34,000,000
Medium Term Notes, Variable interest rate -
LIBO rate plus 2%, due 2000 45,000,000 -
Medium Term Notes, Variable interest rate -
LIBO rate plus 1.125%, due 2002 21,900,000 -
- ------------------------------------------------------------------------------
$ 180,600,000 160,000,000
Less: Current portion of long-term debt 23,840,000 46,300,000
- ------------------------------------------------------------------------------
$ 156,760,000 $ 113,700,000
- ------------------------------------------------------------------------------
Total long-term debt $ 263,027,692 $ 221,642,897
- ------------------------------------------------------------------------------
Total Capitalization $ 394,229,934 $ 342,072,545
==============================================================================
The accompanying notes are an integral part of these consolidated
financial statements.
<TABLE>
Bangor Hydro-Electric Company
CONSOLIDATED STATEMENT OF CASH FLOWS
<CAPTION>
For the Years Ending December 31,
1998 1997 1996
-------------- -------------- --------------
<S> <C> <C> <C>
Cash Flows From Operations:
Net Income (Loss) $ 11,465,317 $ (386,690)$ 11,282,666
Adjustments to reconcile net income (loss)to net cash
provided by (used in) operations:
Depreciation and amortization 9,749,229 10,187,102 7,429,719
Amortization of Seabrook Nuclear Project (Note 7) 1,699,050 1,699,050 1,699,050
Amortization of costs to terminate/restructure
power contracts (Note 6) 20,442,441 23,218,500 20,836,561
Other amortizations 2,035,505 1,784,625 2,126,963
Allowance for equity funds used during
construction (Note 1) (430,028) (285,972) (368,056)
Deferred income tax provision (Note 2) 6,118,180 (1,766,249) 4,495,490
Deferred investment tax credits, net (Note 2) (241,306) (216,574) (175,464)
Changes in assets and liabilities:
Cost to restructure purchased power contract (Note 6) (7,704,185) - -
Cost to terminate demand-side management contract - - (1,702,678)
Payment received related to terminate purchased
power contract (Note 6) - 1,000,000 1,000,000
Deferred incremental Maine Yankee costs
(Notes 1 and 10) (793,608) (718,877) -
Deferred incremental ice storm costs (Note 12) (4,200,423) - -
Deposit of Graham Station property sale proceeds
with trustee (Note 11) (6,200,000) - -
Deferred costs associated with generation asset
sale (Note 10) (2,317,688) - -
Deferred fuel revenue and Maine Yankee refueling
costs (Note 1) (1,285,101) 1,172,497 514,464
Accounts receivable, net and unbilled revenue (1,423,947) 1,700,647 (2,872,894)
Accounts payable 724,721 (261,642) 2,905,952
Accrued interest (192,272) (52,746) (1,188,433)
Current and deferred income taxes 121,153 344,790 (722,833)
Accrued postretirement benefit costs (Note 5) 600,699 547,237 1,411,000
Other current assets and liabilities, net (22,036) 906,745 (85,138)
Other, net (Note 4) 2,786,259 (2,499,289) (1,744,820)
- -------------------------------------------------------------------------------------------------------
Net Cash Provided By (Used In) Operations $ 30,931,960 $ 36,373,154 $ 44,841,549
- -------------------------------------------------------------------------------------------------------
Cash Flows From Investing:
Construction expenditures $ (18,240,226)$ (17,525,312)$ (18,816,194)
Allowance for borrowed funds used during construction
(Note 1) (693,682) (562,966) (755,708)
- -------------------------------------------------------------------------------------------------------
Net Cash (Used In) Provided By Investing $ ($18,933,908)$ ($18,088,278)$ ($19,571,902)
- -------------------------------------------------------------------------------------------------------
Cash Flows From Financing:
Dividends on preferred stock $ (1,216,434)$ (1,349,620)$ (1,481,020)
Dividends on common stock - (1,325,416) (5,273,157)
Payments on long-term debt (53,478,554) (15,853,515) (13,645,737)
Payments on mandatory redeemable preferred stock (1,593,914) (1,593,915) (3,187,828)
Issuances:
Common stock dividend reinvestment plan (Note 3) - - 668,215
Long-term debt, net of capital reserve fund
requirements (Note 4) 68,300,000 - -
Short-term debt, net (Note 4) (22,000,000) 1,500,000 (2,500,000)
- -------------------------------------------------------------------------------------------------------
Net Cash (Used In) Provided by Financing $ (9,988,902)$ (18,622,466)$ (25,419,527)
- -------------------------------------------------------------------------------------------------------
Net Change in Cash and Cash Equivalents $ 2,009,150 $ (337,590)$ (149,880)
Cash and Cash Equivalents - Beginning of Year 936,796 1,274,386 1,424,266
- -------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents - End of Year $ 2,945,946 $ 936,796 $ 1,274,386
=======================================================================================================
The accompanying notes are an integral part of these consolidated financial statements.
</TABLE>
<TABLE>
Bangor Hydro-Electric Company
CONSOLIDATED STATEMENTS OF COMMON STOCK INVESTMENT
<CAPTION>
Amounts
Paid in
Common Excess of Retained Total Common
Stock Par Value Earnings Stock Investment
<S> <C> <C> <C> <C>
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 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
Net income - - 11,465,317 11,465,317
Cash dividends declared on-
Preferred stock - - (1,183,584) (1,183,584)
Issuance of warrants (Note 6) - 2,084,775 - 2,084,775
Other (Note 3) - - (60,904) (60,904)
------------ ------------ ------------ ---------------
BALANCE DECEMBER 31, 1998 $ 36,817,120 $ 59,054,203 $ 22,992,769 $ 118,864,092
============ ============ ============ ===============
The accompanying notes are an integral part of these consolidated financial statements.
</TABLE>
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 192,000 people. The Company serves approximately 106,000
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),
Bangor Var Co., Inc. (BVC), Bangor Energy Resale, Inc. (BERI), and Penobscot
Natural Gas Co., Inc. (Penobscot Gas). 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. BERI 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
(see Note 4 for a discussion of this financing arrangement). The operations
of Penobscot Gas consist solely of a 50% interest in Bangor Gas Company, LLC,
which is developing a natural gas local distribution company in the greater
Bangor, Maine area. 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 MAINE YANKEE REFUELING COSTS-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 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 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 overaccumulated depreciation (discussed
below), was approximately 2.5% in 1998, 3.0% in 1997, and 2.4% in 1996.
A study conducted as of December 31, 1996 determined that the Company's
reserve for depreciation was overaccumulated by approximately $3.6 million.
In connection with the MPUC's rate order in February 1998, the Company was
allowed to amortize this balance over a two-year period, starting in February
1998. The Company recorded approximately $1.6 million in amortization in 1998
which reduced depreciation expense.
A similar study conducted in 1989 determined 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 $7.0 million in 1998, $5.7 million in 1997 and $6.5
million in 1996.
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 $3 million and $1.9 million at
December 31, 1998 and 1997, 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. In addition, carrying costs on certain regulatory assets
were also capitalized in 1998 and included in AFDC in the Consolidated
Statements of Income. The average AFDC (carrying costs) rates computed by the
Company were 9.1% in 1998, 8.7% for 1997 and 8.6% in 1997.
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 $23.8 million, $24.6 million and
$26.7 million in 1998, 1997 and 1996, respectively. Cash paid for income
taxes was approximately $655,000, $545,000 and $2.3 million in 1998, 1997 and
1996, respectively. Noncash operating activity: In 1998, the Company issued
common stock warrants in connection with the Penobscot Energy Recovery
Company (PERC) purchased power contract restructuring (see Note 6), which
were recorded at a fair value of $2 million as a regulatory asset and
additional paid-in capital.
RISK MANAGEMENT AND DERIVATIVE FINANCIAL INSTRUMENTS-The Company's major
financial market risk exposures are changing interest rates and changes in
purchased energy prices. Changing interest rates will affect interest paid on
variable rate debt and the fair value of fixed rate debt. The Company manages
interest rate risk through a combination of both fixed and variable rate debt
instruments and derivative financial instruments, including an interest rate
swap and interest rate caps (see Notes 4 and 13). The Company manages
purchased energy price risk through the use of swaps (see Note 13). The
Company does not hold or issue derivatives for trading purposes. The
Company's accounting for derivatives 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 1998 Consolidated Financial
Statements.
2. INCOME TAXES
In accordance with Statement of Financial Accounting Standards No. 109
"Accounting for Income Taxes" (FAS 109), the Company recorded net additional
deferred income tax liabilities of approximately $23 million as of December
31, 1998 and $22.1 million as of December 31, 1997. 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
($32.6 million and $32.1 million as of December 31, 1998 and 1997,
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 ($8.6 million and $8.8 million
as of December 31, 1998 and 1997, respectively), and the establishment of
deferred tax assets on unamortized investment tax credits ($1.0 million as of
December 31, 1998 and $1.2 million as of December 31, 1997). These latter
amounts have been recorded as deferred regulatory liabilities at December 31,
1998 and 1997. 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, 1998 and
1997:
1998 1997
- -------------------------------------------------------------------------------
Deferred Income Tax Liabilities:
Excess book over tax basis of electric plant
in service $ 53,209,720 $ 51,559,302
Costs to terminate purchased power contracts 50,851,911 58,026,033
Deferred incremental ice storm costs 2,119,432 -
Investment in jointly owned companies 2,036,802 1,405,388
Deferred incremental Maine Yankee costs 697,692 293,302
Deferred demand-side management costs 318,927 685,447
Other 287,215 407,745
- -------------------------------------------------------------------------------
$109,521,699 $112,377,217
- -------------------------------------------------------------------------------
Deferred Income Tax Assets:
Net operating loss carryforward $ 27,159,196 $ 39,757,653
Deferred taxes provided on alternative
minimum tax 7,314,289 6,447,244
Deferred state income tax benefit 2,881,091 1,987,659
Reserve for Basin Mills investment 2,835,939 2,825,592
Postretirement benefit costs other than pensions 2,362,537 2,122,130
Unamortized investment tax credit 1,017,397 1,160,073
Reserve for bad debts 719,981 873,007
Accrued pension costs 324,064 458,869
Other 1,132,700 886,338
- -------------------------------------------------------------------------------
$ 45,747,194 $ 56,518,565
- -------------------------------------------------------------------------------
Total other accumulated deferred income taxes $ 63,774,505 $ 55,858,652
===============================================================================
The individual components of federal and state income taxes reflected in the
Consolidated Statements of Income for 1998, 1997 and 1996 are stated in the
table below.
Year Ended December 31,
- -----------------------------------------------------------------------
1998 1997 1996
---------- ----------- ---------
Current:
Federal $ 725,466 $ 524,373 $ 1,804,206
State 195,876 141,581 526,576
- -----------------------------------------------------------------------
$ 921,342 $ 665,954 $ 2,330,782
- -----------------------------------------------------------------------
Deferred:
Federal-Other $ 5,089,469 $ (661,330) $ 4,034,809
State-Other 1,442,801 (690,829) 861,136
Federal-Seabrook (341,917) (341,917) (331,076)
State-Seabrook (72,173) (72,173) (69,379)
- -----------------------------------------------------------------------
$ 6,118,180 $(1,766,249) $ 4,495,490
- -----------------------------------------------------------------------
Investment Tax Credits, Net $ (385,805) $ (140,379) $(1,122,798)
- -----------------------------------------------------------------------
Total Provision $ 6,653,717 $(1,240,674) $ 5,703,474
Allocated to Other Income (560,431) (715,629) (821,021)
- -----------------------------------------------------------------------
Charged to Operating Expense $6,093,286 $(1,956,303) $ 4,882,453
=======================================================================
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.
1998 1997 1996
- -----------------------------------------------------------------------
Amount % Amount % Amount %
-------------------------------------------
(Dollars in Thousands)
-------------------------------------------
Federal income tax
provision at statutory
rate $6,342 35.0% $(569) 35.0% $5,860 34.5%
Less (Plus) permanent
reductions in tax expense
resulting from
statutory exclusions from
taxable income:
Dividend received
deduction related to
earnings of associated
companies 40 .2 29 (1.8) 116 .7
Equity component of AFDC 151 .8 100 (6.2) 127 .8
Amortization of equity
component of AFDC
on recoverable
Seabrook investment (160) (.9) (160) 9.8 (157) (.9)
Other (28) (.1) (80) 5.1 (68) (.5)
- -------------------------------------------------------------------------
Federal income tax provision
before effect of timing
differences $6,339 35.0 $(458) 28.1% $5,842 34.4%
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) (.8) (151) 9.3 (149) (.9)
Book depreciation greater
than tax depreciation (88) (.5) (79) 4.8 (90) (.5)
Equity earnings in excess
of dividends 201 1.1 217 (13.3) (6) -
State income tax liability
deducted for federal income
tax purposes 498 2.8 (186) 11.4 314 1.9
Reversal of excess deferred
income taxes 124 .7 173 (10.6) 101 .6
Amortization of investment
tax credits 241 1.3 217 (13.3) 175 1.0
Investment tax credits
flowed through - - (184) 11.3 540 3.2
Other 282 1.5 46 (2.9) 164 .9
- ----------------------------------------------------------------------------
Federal income tax provision $5,232 28.9% $(511) 31.4 $4,793 28.2%
============================================================================
Under the federal income tax laws, the Company received investment tax
credits (ITC) on qualified property additions through 1986. ITC utilized were
deferred and are being amortized over the life of the related property. In
1998 the Company recorded $144,499 of state of Maine ITC and $213,322 of
amortization of deferred ITC. 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, 1998, the Company had federal and state alternative minimum
tax credits of approximately $7.3 million for the reduction of future tax
liabilities. In 1998, 1997 and 1996 the Company utilized approximately $31.9
million, $21.5 million and $32.6 million, respectively, of tax net operating
loss carryforwards to reduce its regular income tax liability. At December
31, 1998, the Company had, for income tax reporting purposes, approximately
$66.6 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 AND EARNINGS PER SHARE
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 462,660 (plus additional
shares equal in number to such presently outstanding shares as may be
retired) may be issued with such preferences, restrictions or qualifications
as the Board of Directors may determine. Any new shares so issued will be
required to be issued with per share voting rights no greater than that of
the common stock. The callable preferred stock may be called in whole or in
part upon any dividend date by appropriate resolution of the Board of
Directors. Except for the holders of the 8.76% issue, which does not carry
general voting rights, the currently outstanding preferred stock has general
voting rights of one vote per share. With regard to payment of dividends or
assets available in the event of liquidation, preferred stock ranks prior to
common stock.
REDEEMABLE PREFERRED SHARES-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 each
of 1998 and 1997. In each of 1998 and 1997 the Company made $1.5 million
sinking fund payments, as well as approximately $94,000 under the make whole
provision.
EARNINGS PER SHARE-The following table reconciles basic and diluted earnings
per common share assuming all common stock warrants (see Note 6 for
discussion of warrants issued in connection with the PERC purchased power
contract restructuring) were converted to common shares in accordance with
Statement of Financial Accounting Standards No. 128, "Earnings per Share":
1998 1997 1996
- ---------------------------------------------------------------------------
Earnings (loss) applicable
to common stock $10,220,829 $(1,762,578) $9,745,464
- ---------------------------------------------------------------------------
Average common shares outstanding 7,363,424 7,363,424 7,336,174
Plus: incremental shares from
assumed conversion of warrants 329,778 - -
- ---------------------------------------------------------------------------
Average common shares outstanding plus
assumed warrants converted 7,693,202 7,363,424 7,336,174
- ---------------------------------------------------------------------------
Basic earnings (loss) per
common share $ 1.39 $ (0.24) $ 1.33
===========================================================================
Diluted earnings (loss) per
common share $ 1.33 $ (0.24) $ 1.33
===========================================================================
4. LENDING AGREEMENTS AND MONETIZATION OF POWER SALE CONTRACT
As previously reported, during 1997 the Company negotiated amendments to the
credit agreement with its lending banks in order to resolve potential
violations of certain financial covenants. As a result of those amendments,
the Company reported that during 1998 or beyond, future cash needs might
exceed the borrowing capacity under the credit facility, and accordingly, the
Company might be required to find new sources of financing.
On June 29, 1998, the Company entered into an Amended and Restated Revolving
Credit and Term Loan Agreement with a new group of lenders that provided a
two-year term loan of $45 million and a revolving credit commitment of $30
million. Amounts outstanding under the existing credit agreement, including
$11 million of notes payable and $30 million of medium term notes, were fully
repaid upon the execution of the amended credit agreement. The amended credit
agreement is secured by $82.5 million of non-interest bearing First Mortgage
Bonds.
The revolving credit portion of the new credit agreement has a term of three
years. The Company may borrow, at its option, at rates, as defined in the
agreement, based on the London Interbank Offered (LIBO) rate, or the base
rate, which is the higher of the agent bank's defined base rate or one-half
of one percent (1/2%) above the federal funds interest rate. The applicable
risk premium based on the Company's corporate credit rating is added to the
core interest rate, which results in the total combined interest rate for
borrowing under the agreement. A required commitment fee, based on the
Company's available revolving credit commitment, is also priced according to
the Company's corporate credit rating.
The maturity of the new term loan is the earlier of two years or when the
Company completes any portion of its generation asset sale (see Note 10). In
addition, the medium term notes require principal payments of $3 million each
on September 30, 1999, December 31, 1999 and March 31, 2000. Interest on the
term loans is determined similarly to the revolving credit portion of the new
credit agreement but with a different risk premium.
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 $30 million revolving credit
facility.
The new credit agreement contains financial covenants which are not
significantly different than the covenants contained in the previous credit
agreement. The Company was in compliance with all covenants associated with
the new credit agreement during 1998.
The credit agreement 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 $4.6 million of the proceeds from this
financing with a third party trustee. The new letter of credit was issued in
October 1998, and the $4.6 million deposited with the third party trustee was
released to the Company. These funds were utilized to repay amounts
outstanding under the Company's revolving credit facility.
As reported in the 1997 Form 10-K, the Company had been negotiating a
transaction for the monetization of a power sale contract with UNITIL Power
Corp. (UNITIL), a New Hampshire based electric utility. The Company provided
power directly to UNITIL at significantly above-market rates, with the
contract term ending in the year 2003. On March 31, 1998, the Company
completed a transaction with a financial institution and one of its wholly
owned subsidiaries, Bangor Energy Resale, Inc. (BERI) (see below) that
provided a loan of approximately $23.3 million in net proceeds secured by the
value of the UNITIL contract. As a requirement of the financing, the Company
established BERI, a special purpose entity which holds the medium term notes
and acts as a conduit between Bangor Hydro and UNITIL for the procurement of
power under the terms of the original power sales contract between the two
parties.
The loan is comprised of $24.8 million in medium term notes, with a term of
53 months. BERI must maintain a capital reserve fund of $1.5 million, funded
with proceeds from the loan, which will be used to pay the final installment
of principal and interest due in 2002. The assets in the capital reserve fund
are held by a third party trustee and invested in money market funds whose
investments are limited to U.S. Treasury and Agency obligations, repurchase
agreements and short-term bank and corporate obligations. Interest is
payable, at the Company's option, under the agreement at the LIBO rate plus
1.125% or the base rate, which is the higher of (a) the lending banks
reported "base rate" and (b) one-half of one percent (1/2%) above the federal
funds effective interest rate. Also in connection with the loan agreement,
BERI was required to purchase an interest rate cap or swap to provide
interest rate protection through the maturity date of the term loan. This was
accomplished in April 1998, when BERI entered into an interest rate swap
agreement with the same financial institution. The interest rate swap fixed
the LIBO interest rate on the medium term notes at 5.72%. The agreement also
contains certain financial covenants. BERI was in compliance with all
financial covenants during 1998.
Also as previously reported, beginning in early 1997, the Company failed to
comply with certain financial covenants under its bank lending agreements and
received temporary waivers from the lending banks. By using a portion of the
proceeds of the UNITIL monetization to pay down a portion of the bank
obligations, the Company was able to negotiate permanent waivers of the
earlier financial covenant violations.
At the time the Company filed its 1997 Form 10-K, the monetization of the
UNITIL contract had not been completed and the financial covenant violations
had, therefore, not been waived permanently. As discussed in the 1997 Form
10-K, all debt under the bank credit facilities, including certain medium
term notes, was classified as a current liability on the Company's
Consolidated Balance Sheets as of December 31, 1997. As a result of the
permanent waivers that became effective upon completion of the UNITIL
monetization, $22 million of medium term notes, previously classified as a
current liability, were reclassified as a long-term liability as of March 31,
1998.
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 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. 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.
In August 1995, the Company entered into agreements with three banks to cap
the LIBO rate on the $60 million term loan at 7.25%, with the cost to cap
the interest rate amounting to $624,000. In 1998 the Company prepaid the
remaining outstanding balance of the $60 million term loan, but the interest
rate cap remains in place because the benefits of the cap are also applicable
to the new $45 million term loan. The interest rate cap costs are continuing
to be amortized over the life of the $60 million term loan, which matched the
term of the interest rate cap.
Certain information related to total short-term borrowings under the Credit
Agreements and the lines of credit is as follows:
1998 1997 1996
- --------------------------------------------------------------------
Total credit available
at end of period $30,000,000 $54,000,000 $54,000,000
Letter of credit secured
under the revolving
credit facility $ 4,200,000 $ 4,200,000 $ 4,200,000
Unused credit at end
of period $13,800,000 $15,800,000 $17,300,000
Borrowings outstanding
at end of period $12,000,000 $34,000,000 $32,500,000
Effective interest rate 7.2% 8.3% 7.7%
(exclusive of fees) on
borrowings outstanding
at end of period
Average daily outstanding
borrowings for the
period $20,369,863 $31,236,301 $33,609,973
Weighted daily average
annual interest rate 7.9% 8.1% 7.6%
Highest level of borrowings
outstanding at any
month-end during the
period $37,500,000 $36,500,000 $41,500,000
=====================================================================
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 for the five
years subsequent to December 31, 1998 are:
Sinking Fund Requirements Current Maturities Total
- ---------------------------------------------------------------------------
1999 $1,675,205 $ 23,840,000 $ 25,515,205
2000 1,886,702 58,460,000 60,346,702
2001 180,990 21,340,000 21,520,990
2002 - 41,560,000 41,560,000
2003 - 32,200,000 32,200,000
- ---------------------------------------------------------------------------
$3,742,897 $177,400,000 $181,142,897
- ---------------------------------------------------------------------------
5. Postretirement Benefits
The Company has a noncontributory pension plan covering substantially all of
its employees. 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 1998, 1997
and 1996, 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
1998, 1997 or 1996. The plan's assets are composed of fixed income
securities, equity securities and cash equivalents. Total pension expense
included the following components:
1998 1997 1996
-----------------------------------------------------------------------------
Service cost-benefits earned during
the period $ 1,190,152 $ 1,046,466 $ 991,569
Interest cost on projected benefit
obligation 3,058,307 2,861,434 2,781,366
Expected return on plan assets (3,737,267) (3,513,402) (3,382,910)
Total of amortized obligations and
the net gain (loss) deferred (375,946) (375,946) (375,946)
- -------------------------------------------------------------------------------
Total pension expense $ 135,246 $ 18,552 $ 14,079
===============================================================================
1998 1997 1996
- -------------------------------------------------------------------------------
Significant assumptions used were-
Discount rate 7.0% 7.5% 7.25%
Rate of increase in future
compensation levels 4.0% 5.0% 5.0%
Expected long-term rate of return
on plan assets 9.0% 9.0% 9.0%
- -------------------------------------------------------------------------------
The following table sets forth the plan's funded status at
December 31, 1998 and 1997:
1998 1997
- -------------------------------------------------------------------------------
Change in Projected Benefit Obligation
Balance as of December 31, 1997 and 1996 $ 44,557,086 $ 39,369,783
Service cost 1,190,152 1,046,466
Interest cost 3,058,307 2,861,434
Benefits paid (3,069,692) (3,064,931)
Gains and losses 1,709,136 4,344,334
- -------------------------------------------------------------------------------
Balance as of December 31, 1998 and 1997 $ 47,444,989 $ 44,557,086
- -------------------------------------------------------------------------------
Change in Plan Assets
Balance as of December 31, 1997 and 1996 $ 48,323,318 $ 44,143,680
Benefits paid (3,069,692) (3,064,931)
Actual return 3,114,389 7,244,569
- -------------------------------------------------------------------------------
Balance as of December 31, 1998 and 1997 $ 48,368,015 $ 48,323,318
- -------------------------------------------------------------------------------
Funded Status $ 923,026 $ 3,766,232
Unrecognized net transition asset (2,254,825) (3,187,150)
Unrecognized prior service cost 3,427,646 3,984,025
Unrecognized gain (2,889,973) (5,221,987)
- -------------------------------------------------------------------------------
Accrued pension balance at December 31, 1998 and 1997$ (794,126)$ (658,880)
===============================================================================
The discount rate and rate of increase in future compensation levels used to
determine pension obligations, effective January 1, 1999, are 6.75% and 4%,
respectively, and were used to calculate the plan's funded status at December
31, 1998. At December 31, 1997, the Company changed to the 83-Group Annuity
Mortality Table to calculate the plan's funded status.
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 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
amounted to approximately $1.3 million in 1998, $1.1 million in 1997 and
$490,000 in 1996. 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 1998,
1997 and 1996 and the major assumptions used to determine these amounts are
shown in the following tables:
1998 1997 1996
- -------------------------------------------------------------------------------
Service cost of benefits earned $ 401,856 $ 342,739 $ 326,809
Interest cost on accumulated
postretirement benefit obligation 1,060,671 994,936 928,423
Actual return on plan assets (10,608) (9,395) (21,000)
Amortization of unrecognized
transition obligation 501,200 501,200 501,200
Other deferrals, net (14,392) (11,605) -
- -------------------------------------------------------------------------------
Net periodic postretirement
benefit cost $ 1,938,727 $ 1,817,875 $ 1,735,432
===============================================================================
1998 1997 1996
- -------------------------------------------------------------------------------
Significant assumptions used were-
Discount rate 7.0% 7.5% 7.25%
Health care cost trend rate, employees less
than age 65-
Near-term 8.0% 8.5% 9.0%
Long-term 5.0% 4.5% 4.5%
Health care cost trend rate, employees greater
than age 65-
Near-term 8.0% 6.8% 7.0%
Long-term 5.0% 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, 1998 and 1997:
1998 1997
- -------------------------------------------------------------------------------
Change in Accumulated Postretirement Benefit Obligation
Balance as of December 31, 1997 and 1996 $ 16,234,790 $ 13,238,720
Service cost 401,856 342,739
Interest cost 1,060,671 994,936
Claims paid (1,292,715) (1,052,060)
Gains and losses 2,669,027 2,710,455
- -------------------------------------------------------------------------------
Balance as of December 31, 1998 and 1997 $ 19,073,629 $ 16,234,790
- -------------------------------------------------------------------------------
Change in Plan Assets
Balance as of December 31, 1997 and 1996 $ 283,731 $ 240,878
Employer contributions 1,338,027 1,105,122
Retiree contributions 45,757 42,259
Claims paid (1,292,715) (1,052,060)
Actual return, less expenses (53,392) (52,468)
- -------------------------------------------------------------------------------
Balance as of December 31, 1998 and 1997 $ 321,408 $ 283,731
- -------------------------------------------------------------------------------
Funded Status $ (18,752,221)$ (15,951,059)
Unrecognized net transition obligation 7,016,000 7,517,200
Unrecognized loss 4,760,198 2,058,535
- -------------------------------------------------------------------------------
Accrued postretirement benefit cost balance at
December 31, 1998 and 1997 $ (6,976,023)$ (6,375,324)
===============================================================================
The discount rate used to determine postretirement benefit obligations,
effective January 1, 1998, and the Plan's funded status at December 31, 1998,
was 6.75%. At December 31, 1997, the Company changed to the 83-Group Annuity
Mortality Table to calculate the plan's funded status.
Assumed health care cost trend rates have a significant effect on the amounts
reported for the health care plan. A one-percentage-point change in assumed
health care cost trend rates would have the following effect:
1% Increase 1% Decrease
- ----------------------------------------------------------------------------
Effect on total of service and interest
cost components $ 367,015 $ (282,659)
Effect on postretirement benefit obiliation 3,432,472 (2,712,012)
- -----------------------------------------------------------------------------
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 $330,000 in 1998, $295,000
in 1997 and $290,000 in 1996.
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 (the 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.
The entire output of the Plant had been sold at wholesale by Maine Yankee to
ten New England electric utilities, which collectively own all of the common
equity of Maine Yankee; a portion of that output (approximately 6.2%) was in
turn resold by certain of the owner utilities to 28 municipal and cooperative
utilities in New England (the Secondary Purchasers). Maine Yankee recovered,
and since the shutdown decision has continued to recover, its costs of
providing service through a formula rate filed with the FERC and contained in
Power Contracts with its utility purchasers, which are also filed with the
FERC. On November 6, 1997, Maine Yankee submitted for filing certain
amendments to the Power Contracts (the Amendatory Agreements) and revised
rates to reflect the decision to shut down the Plant and to request approval
of an increase in the decommissioning component of its formula rates. Maine
Yankee's submittal also requested certain other rate changes, including
recovery of unamortized investment (including fuel) and certain changes to
its billing formula, consistent with the non-operating status of the Plant.
By Order dated January 14, 1998, the FERC accepted Maine Yankee's new rates
for filing, subject to refund after a minimum suspension period, and set
Maine Yankee's Amendatory Agreements, rates, and issues concerning the
prudence of the Plant shutdown decision for hearing.
By Complaint dated December 9, 1997, the Maine Office of the Public Advocate
(OPA) sought a FERC investigation of Maine Yankee's actions leading to the
decision to shut down the Plant, including actions associated with the
management and operation of Maine Yankee since 1993. The MPUC had initiated
an investigation in Maine earlier, raising generally similar issues. By
decision dated May 4, 1998, the FERC consolidated the OPA Complaint with the
comprehensive rate proceeding. In addition, the Secondary Purchasers
intervened in the FERC proceeding, raising similar prudence issues and other
issues unique to their status as indirect purchasers from Maine Yankee. In
support of its request for an increase in decommissioning collections, Maine
Yankee submitted with its initial filing a 1997 decommissioning cost study
performed by TLG Services, Inc. (TLG). During 1998, Maine Yankee engaged in
an extensive competitive bid process to hire a Decommissioning Operations
Contractor (DOC) to perform certain major decontamination and dismantlement
activities at the Plant on a fixed-price, turnkey basis. As a result of that
process, a consortium headed by Stone & Webster Engineering Corporation
(Stone & Webster) was selected to perform such activities under a fixed-price
contract. The contract provides for, among other undertakings, construction
of an independent spent fuel storage installation (ISFSI) and completion of
major decommissioning activities and site restoration by the end of 2004. The
DOC process resulted in fixing certain costs that had been estimated in the
earlier decommissioning cost estimate performed by TLG. Since the filing of
the rate request, Maine Yankee and the active intervenors, including among
others the MPUC Staff, the OPA, the Company and other owners, the Secondary
Purchasers, and a Maine environmental group (the Settling Parties), engaged
in extensive discovery. More recently, those parties participated in
settlement discussions that resulted in an Offer of Settlement filed by those
parties with the FERC on January 19, 1999, which, if approved by the FERC,
would result in full settlement of all issues raised in the consolidated FERC
proceeding, including decommissioning cost issues and issues pertaining to
the prudence of the management, operation, and decision to permanently cease
operation of, the Plant. Approval of the settlement would also resolve the
issues raised by the Secondary Purchasers by limiting the amounts they will
pay for decommissioning the Plant and by settling other points of contention
affecting individual Secondary Purchasers.
The Offer of Settlement provides for Maine Yankee to collect $33.6 million in
the aggregate annually, effective January 15, 1998: (1) $26.8 million for
estimated decommissioning costs, and (2) $6.8 million for ISFSI-related
costs. The original filing with FERC on November 6, 1997 called for an
aggregate annual collection rate of $36.4 million for decommissioning and the
ISFSI, based on the TLG estimate. The amount collected annually could be
reduced to approximately $26 million if Maine Yankee is able to (1) use in
connection with the construction of the ISFSI funds held in trust under Maine
law for spent-fuel disposal, and (2) access approximately $6.8 million being
held by the state of Maine for eventual payment to the state of Texas
pursuant to a compact for low-level nuclear waste disposal, the future of
which is now in question after rejection of the selected disposal site in
west Texas by a Texas regulatory agency. Both would require authorizing
legislation in Maine, which Maine Yankee intends to pursue. The Offer of
Settlement also provides for recovery of all unamortized investment
(including fuel) in the Plant, together with a return on equity of 6.50%,
effective January 15, 1998, on equity balances up to maximum allowed equity
amounts. The Settling Parties also agreed in the proposed settlement not to
contest the effectiveness of the Amendatory Agreements submitted to FERC as
part of the original filing, subject to certain limitations including the
right to challenge any accelerated recovery of unamortized investment under
the terms of the Amendatory Agreements after a required informational filing
with the FERC by Maine Yankee. As a separate part of the Offer of Settlement,
the Company, the other two Maine owners of Maine Yankee, the MPUC Staff, and
the OPA entered into a further agreement resolving retail rate issues and
other issues specific to the Maine parties, including those that had been
raised concerning the prudence of the operation and shutdown of the Plant
(the Maine Agreement).
Under the Maine Agreement, the Company would continue to recover its Maine
Yankee costs in accordance with its most recent Alternative Rate Plan (ARP)
order (see Note 10) from the MPUC without any adjustment reflecting the
outcome of the FERC proceeding. To the extent that the Company has collected
from its retail customers a return on equity in excess of the 6.50%
contemplated by the Offer of Settlement, no refunds would be required, but
such excess amounts would be credited to the customers to the extent required
by the ARP. The final major provision of the Maine Agreement requires the
Maine owners, for the period from March 1, 2000, through December 1, 2004, to
hold their Maine retail ratepayers harmless from the amounts by which the
replacement power costs for Maine Yankee exceed the replacement power costs
assumed in the report to the Maine Yankee Board of Directors that served as a
basis for the Plant shutdown decision, up to a maximum cumulative amount of
$41 million. The Company's share of that amount would be $5.74 million for
the period. The Maine Agreement, which was approved by the MPUC on December
22, 1998, also sets forth the methodology for calculating such replacement
power costs. The Company believes that the Offer of Settlement, including the
Maine Agreement, constitutes a reasonable resolution of the issues raised in
the Maine Yankee FERC proceeding, and that approval of the Offer of
Settlement by the FERC would eliminate significant uncertainties concerning
the Company's future financial performance. Although all of the active
parties to the proceeding have agreed to support or, with respect to certain
individual provisions, not oppose, the Offer of Settlement, the Company
cannot predict with certainty whether or in what form it will be approved by
the FERC.
Summary Financial Information for Maine Yankee and MEPCO
<TABLE>
<CAPTION>
- ------------------------------------------------------------------------------------------------------------------
Maine Yankee MEPCO
- ------------------------------------------------------------------------------------------------------------------
(Dollars in Thousands)
- ------------------------------------------------------------------------------------------------------------------
1998 1997 1996 1998 1997 1996
---------- ----------- ---------- --------- --------- ---------
<S> <C> <C> <C> <C> <C> <C>
Operations:
As reported by investee-
Operating Revenue $ 110,608 $ 238,586 $ 185,661 $ 3,514 $ 24,473 $ 55,391
- ------------------------------------------------------------------------------------------------------------------
Depreciation & decommissioning
collections $ 57,617 $ 33,625 $ 32,952 $ 364 $ 222 $ 845
Interest and Preferred Dividends 15,958 18,031 15,922 77 67 61
Other expenses, net 32,117 179,317 130,150 2,125 23,112 54,265
- ------------------------------------------------------------------------------------------------------------------
Operating expenses $ 105,692 $ 230,973 $ 179,024 $ 2,566 $ 23,401 $ 55,171
- ------------------------------------------------------------------------------------------------------------------
Earnings Applicable to Common Stock $ 4,916 $ 7,613 $ 6,637 $ 948 $ 1,072 $ 220
==================================================================================================================
Amounts Reported by the Company-
Purchased power costs $ 7,185 $ 16,764 $ 12,839 $ - $ - $ -
Equity in net income (215) (524) (449) (123) (15) (15)
- ------------------------------------------------------------------------------------------------------------------
Net purchased power expense $ 6,970 $ 16,240 $ 12,390 $ (123) $ (15) $ (15)
==================================================================================================================
Financial Position:
As reported by investee-
Plant in service $ 687 $ 687 $ 409,865 $ 23,633 $ 23,510 $ 23,146
Accumulated depreciation - - (225,735) (22,899) (22,618) (22,545)
Other assets 1,182,611 1,367,456 417,931 4,781 3,470 10,126
- ------------------------------------------------------------------------------------------------------------------
Total assets $1,183,298 $ 1,368,143 $ 602,061 $ 5,515 $ 4,362 $ 10,727
Less-
Preferred stock 16,800 17,400 18,000 - - -
Long-term debt 68,433 143,665 103,332 220 420 620
Other liabilities and deferred credits 1,018,575 1,128,128 409,392 2,079 1,578 9,110
- ------------------------------------------------------------------------------------------------------------------
Net assets $ 79,490 $ 78,950 $ 71,337 $ 3,216 $ 2,364 $ 997
==================================================================================================================
Company's reported equity-
Equity in net assets $ 5,564 $ 5,527 $ 4,994 $ 457 $ 336 $ 142
Adjust Company's estimated to actual (125) 5 20 (18) (10) (17)
- ------------------------------------------------------------------------------------------------------------------
Equity in net assets as reported $ 5,439 $ 5,532 $ 5,014 $ 439 $ 326 $ 125
==================================================================================================================
</TABLE>
Maine Yankee's most recent estimate of the total costs of decommissioning and
plant closure, excluding funds already collected, is $715.0 million
(undiscounted). The Company's share of this estimated cost is $50.1 million
and is recorded as a regulatory asset and decommissioning liability at
December 31, 1998. 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 10) 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 10) for Maine Yankee non-decommissioning plant closure costs.
Accumulated decommissioning funds at December 31, 1998 had an adjusted market
value of $212.7 million of which the Company's share was approximately $14.9
million.
MEPCO-The Company owns 14.2% of the common stock of MEPCO. MEPCO owns and
operates electric transmission facilities from Wiscasset, Maine, to the
Maine-New Brunswick border. Information relating to the operations and
financial position of Maine Yankee and MEPCO appears above. In connection
with the Company's generation asset sale (see Note 10), the Company has
reached an agreement to sell certain of its rights to MEPCO transmission
capacity.
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. See Note 10 for a discussion of an
agreement to sell the Company's generating assets. Included in the Company's
utility plant are the following amounts with respect to this unit:
1998 1997 1996
- -------------------------------------------------------------------------
Electric plant in service $ 16,887,608 $ 16,886,776 $ 16,885,690
Accumulated depreciation (9,851,639) (9,389,542) (8,927,440)
- -------------------------------------------------------------------------
$ 7,035,969 $ 7,497,234 $ 7,958,250
=========================================================================
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 connection with the Company's generation asset sale, an
agreement has been reached to sell the Company's rights as a participant in
the regional utilities agreement with Hydro-Quebec (see Note 10).
BANGOR VAR CO.-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 33.
PENOBSCOT NATURAL GAS COMPANY-In 1998 the Company formed Penobscot Gas, whose
sole function is to be a 50% general partner in Bangor Gas Company, LLC
(Bangor Gas), which is constructing a natural gas distribution system in the
greater Bangor, Maine area. Sempra Energy, a joint venture of Pacific
Enterprises and Enova Corporation, owns the other 50% interest in Bangor Gas.
In the second quarter of 1998, Bangor Gas received unconditional authority
from the MPUC to provide natural gas service to the greater Bangor area, and
in October 1998 the Company received authorization from the MPUC to invest
approximately $1.2 million in Bangor Gas.
Gas service to Maine will be made economically feasible for the first time by
the Maritimes and Northeast Pipeline Project, slated for completion in late
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 but has
the opportunity to make material capital contributions to the joint-venture
in the near term.
Summary Financial Information for Bangor-Pacific and Chester
<TABLE>
<CAPTION>
- ----------------------------------------------------------------------------------------------------------------
Bangor-Pacific Chester
- ----------------------------------------------------------------------------------------------------------------
(Dollars in Thousands)
- ----------------------------------------------------------------------------------------------------------------
1998 1997 1996 1998 1997 1996
--------- --------- --------- --------- --------- ---------
<S> <C> <C> <C> <C> <C> <C>
Operations:
As reported by investee-
Operating Revenue $ 7,309 $ 7,057 $ 8,252 $ 4,535 $ 4,642 $ 4,782
- ----------------------------------------------------------------------------------------------------------------
Depreciation $ 868 $ 870 $ 866 $ 1,075 $ 1,075 $ 1,075
Interest expense 3,082 3,294 3,501 2,737 2,859 2,988
Other expenses, net 890 911 832 723 708 719
- ----------------------------------------------------------------------------------------------------------------
Operating expenses $ 4,840 $ 5,075 $ 5,199 $ 4,535 $ 4,642 $ 4,782
- ----------------------------------------------------------------------------------------------------------------
Net Income $ 2,469 $ 1,982 $ 3,053 $ - $ - $ -
================================================================================================================
Company's reported equity in net income $ 1,235 $ 991 $ 1,527 $ - $ - $ -
================================================================================================================
Financial Position:
As reported by investee-
Plant in service $ 44,047 $ 44,047 $ 44,043 $ 31,993 $ 31,993 $ 31,993
Accumulated depreciation (9,031) (8,163) (7,293) (8,523) (7,447) (6,372)
Other assets 3,308 3,129 3,114 3,008 3,087 3,277
- ----------------------------------------------------------------------------------------------------------------
Total assets $ 38,324 $ 39,013 $ 39,864 $ 26,478 $ 27,633 $ 28,898
Less-
Long-term debt 26,300 28,500 30,600 24,654 25,837 27,021
Other liabilities 2,517 2,425 2,359 1,824 1,796 1,877
- ----------------------------------------------------------------------------------------------------------------
Net assets $ 9,507 $ 8,088 $ 6,905 $ - $ - $ -
================================================================================================================
Company's reported equity in net assets $ 4,754 $ 4,044 $ 3,453 $ - $ - $ -
================================================================================================================
</TABLE>
At December 31, 1998, Penobscot Gas has approximately a $77,000 equity
investment in Bangor Gas and recorded an equity loss in Bangor Gas of
approximately $98,000 for the year ended December 31, 1998. At December 31,
1998, Bangor Gas' total assets, principally construction work in progress,
amounted to $2.9 million.
SMALL POWER PRODUCTION FACILITIES-As of the end of 1998, 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.
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 each of the years from 1994 through 1997 the Company received
its $1 million payment. The Company was entitled to receive the final two
payments totaling $2 million in 1998 and 1999 from Beaver Wood. However, in
July 1998, Beaver Wood indicated that it would not be making the payment due
at that time and requested the Company agree to a lower payment. After
assessing the potential costs and benefits of foreclosing on the mortgage,
the Company determined that accepting a payment of $1.75 million would be a
better alternative. This $1.75 million payment was received in February 1999.
Management believes it is entitled to recover the $250,000 shortfall from its
customers.
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 was 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. Effective with the latest rate order in
February 1998, the amortization was reduced, so that the unamortized balance
of the regulatory asset would be the same as under the original amortization
schedule as of March 1, 2000.
The 1995 transactions involved a "buyback" of the contracts for the purchase
of power from two biomass-fueled generating plants in West Enfield and Jones-
boro, 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 buy-back was financed
entirely by new debt instruments, thereby significantly increasing the Com-
pany'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.
As previously reported, the Company had been working to restructure a power
purchase contract with the PERC, its last remaining high-priced non-utility
generator contract that offered 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, and, in the Company's opinion, is likely to
remain so. The Company's net purchased power under this contract was
approximately $14.7 million in 1998 and is projected to be $15 million
annually, net of revenues from the resale of power to another utility (these
amounts are not reduced by the Company's pro rata share of PERC's net
revenues discussed below). In June 1998 the Company successfully completed
this major restructuring of its obligations under various agreements with
PERC.
It is anticipated that the restructuring will result in a substantial savings
for the Company and will allow PERC to continue to meet the solid waste
disposal needs of Maine communities.
This major restructuring involved several separate components including the
following:
1) PERC refinanced $45 million in existing bonds with a remaining five-year
term over a twenty year period using tax exempt bonds issued by the Finance
Authority of Maine under its Electric Rate Stabilization Program.
2) PERC will share the net revenues generated by the facility on a pro rata
basis with the Company and the Municipal Review Committee (MRC) which
represents over 130 Maine municipalities receiving waste disposal service
from PERC. In 1998 the Company realized $2 million in savings associated with
its share of PERC net revenues. The Company expects to realize approximately
$3.6 million annually in such savings through the term of the PERC contract.
3) The Company made a onetime payment of $6 million to PERC in June 1998 and
is making additional quarterly payments, starting in October 1998, of
$250,000 for four years totaling $4 million.
4) Bangor Hydro and PERC amended their existing power purchase agreement to
include the MRC as a party.
5) The MRC's constituent municipalities extended their contracts with PERC
by 15 years to supply solid waste to the facility through 2018.
6) Bangor Hydro issued two million warrants to purchase common stock, one
million each to PERC and the MRC. Each warrant entitles the warrant holder to
acquire one share of Bangor Hydro common stock at a price of $7 per share. No
warrants may be exercised within the first nine months after their issuance,
and they 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.
Depending upon a number of assumptions, including the ultimate cost of the
warrants and markets for solid waste disposal, it is projected that the
restructuring will result in cost savings to Bangor Hydro over the next
twenty years with a net present value of $25-40 million. The anticipated
savings resulting from this transaction were used to reduce the level of
electric rates approved by the MPUC in the Company's recent general rate case
by approximately $2.4 million on an annual basis.
The refinancing by PERC was made possible by the Maine Legislature through an
amendment to the Electric Rate Stabilization Program that allowed PERC to
qualify for such financing. Under the Program, the state of Maine's "moral
obligation" supports the new nonrecourse debt.
The Company has deferred, as a regulatory asset, the $6.25 million in
payments to PERC, approximately $1.5 million in costs associated with the
contract restructuring, and $2 million for the estimated fair value of the
warrants. As discussed above, the Company is currently recovering PERC
restructuring costs in rates. The $2 million in warrants have also increased
additional paid-in capital on the Consolidated Balance Sheets.
WEST ENFIELD PROJECT-In 1986, the Company entered into a joint venture with a
development subsidiary of Pacific Lighting Corporation for the purpose of
financing and constructing the redevelopment of an old 3.8 MW hydroelectric
plant which the Company owned on the Penobscot River in Enfield and Howland,
Maine, into a 13 MW facility for the purpose of operating the facility once
it was completed. Commercial operation of the redeveloped project began in
April 1988. PHC was formed to own the Company's 50% interest in the joint
venture, Bangor-Pacific.
Bangor-Pacific financed the 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 33. In connection with the Company's generation asset sale
(see Note 10), an agreement has been reached to sell PHC's ownership interest
in Bangor-Pacific.
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 February 29, 2000. This contract is directly tied to the price of oil
and the Company has hedged this purchase through its energy risk management
program (see Note 13 for a discussion of the Company's fuel hedge program).
The Company's purchased power expense (including hedge settlements) under
this contract was approximately $13.4 million in 1998 and is projected to be
approximately $13.3 million in 1999.
The Company has also entered into a new 40 MW purchase power contract tied
directly to the price of oil. The term of this contract is January 1, 1999
through February 29, 2000. The Company has also hedged this purchase through
its energy risk management program and expects the purchased power expense to
be approximately $8.3 million in 1999.
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. As discussed
in Note 10, the Company's investment in the Basin Mills and Veazie projects
is included in the assets to be sold as part of its generation asset sale.
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. UNAUDITED QUARTERLY FINANCIAL DATA
Unaudited quarterly financial data pertaining to the results of operations
are shown below:
Quarter Ended
------------------------------------------
Mar. 31 June 30 Sept. 30 Dec. 31
------------------------------------------
(DOLLARS IN THOUSANDS EXCEPT PER SHARE AMOUNTS)
1998
- ----------------------------------------------------------------------------
Electric Operating Revenue $ 49,100 $ 46,601 $ 49,158 $ 50,285
Operating Income 8,410 8,006 9,087 9,633
Net Income 2,408 2,267 2,949 3,841
Basic Earnings Per Share
of Common Stock $ .28 $ .27 $ .36 $ .48
============================================================================
1997
- ----------------------------------
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
Basic Earnings (Loss) Per Share
of Common Stock $ .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
Basic Earnings Per Share of
Common Stock $ .51 $ .32 $ .26 $ .24
============================================================================
9. FAIR VALUE OF FINANCIAL INSTRUMENTS
The following methods and assumptions were used to estimate the fair value at
December 31, 1998 of each class of financial instrument for which it is
practical to estimate the value:
Cash and cash equivalents: the carrying amount of $2,945,946 approximates
fair value.
Funds held by trustee-money market funds and U.S. Treasury Bills: the
carrying amount of $8,675,668 approximates fair value.
The fair values of other financial instruments at December 31, 1998 based
upon similar issuances of comparable companies are as follows:
In Thousands
- ------------------------------------------------------------------------
Carrying Amount Fair Value
------------------------------
Funds held by trustee-guaranteed
investment contract $ 21,192 $ 19,825
Mandatory redeemable cumulative
preferred stock 9,198 8,922
First Mortgage Bonds 103,743 110,607
Pollution Control Revenue Bonds 4,200 4,200
FAME Revenue Notes 113,700 120,280
Medium Term Notes-LIBO rate plus 2% 45,000 45,000
Medium Term Notes-LIBO rate plus 1.125% 21,900 21,900
- -------------------------------------------------------------------------
10. INDUSTRY RESTRUCTURING AND RATE REGULATION
INDUSTRY RESTRUCTURING-In the Company's 1996 and 1997 Form 10-K's, 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 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% 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 is
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 is currently conducting several rulemaking proceedings associated
with the new restructuring law.
AGREEMENT ON SALE OF COMPANY'S GENERATING ASSETS-On September 25, 1998, the
Company and PP&L Global, Inc., a Pennsylvania corporation and a subsidiary of
PP&L Resources, Inc., reached an agreement for PP&L Global to acquire most
of the Company's electric generating assets with a combined base load
capacity of 89.2 megawatts and certain transmission rights for a sale price
of $89 million. The proposed sale is a result of the Company's effort to
comply with Maine's previously discussed electric utility restructuring
legislation. The Company began seeking proposals from prospective bidders to
purchase its generation and generation-related assets in early 1998 and as
part of the auction process, received final bids from various bidders in
August 1998.
Pursuant to the agreement, the Company has agreed to sell to PP&L Global (i)
its Ellsworth, Howland, Milford, Medway, Orono, Stillwater and Veazie
hydroelectric facilities, which are all situated along the Penobscot River
Basin and Union River in Maine, (ii) the 50% ownership interest owned by PHC
in Bangor-Pacific, (iii) the Company's 8.33% joint ownership interest in the
William F. Wyman Unit No. 4 oil-fired steam plant, (iv) the Company's
designs, applications and other rights with respect to the potential
development of the Basin Mills hydroelectric project, to be located in
Bradley and Orono, Maine, (v) the Company's designs, applications and other
rights with respect to the potential development of a high-voltage
transmission line from Orrington, Maine, to New Brunswick, Canada, and (vi)
certain of the Company's rights to transmission capacity, including its
rights as a participant in the regional utilities' agreements with Hydro-
Quebec.
The sale is subject to certain closing conditions as set forth in the
agreement, including receipt of approvals by federal and state regulatory
agencies. The MPUC has already given approvals for the sale, and other
outstanding governmental proceedings should be resolved within the next few
months. In addition, third-party consents to the sale of certain of the
assets will be required, and the Company cannot predict whether or on what
terms such consents can be obtained. The Company anticipates that most of the
net after-tax proceeds from the sale will be used to retire outstanding debt.
The Company expects that a portion of the sale value will be applied to
reduce the Company's stranded costs for regulatory purposes, which should
lower the amounts that would otherwise be collected in the future from
customers.
REGULATORY PROCEEDINGS-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 included a $5.1 million temporary rate increase in July 1997)
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 treatments have
affected the timing of receipt of revenues by the Company and have required
the Company to finance the payment of the associated costs, they did not
significantly affect the Company's earnings in 1998.
The MPUC order was based upon a determination that the Company should be
allowed to earn an annual return of 12.75% on common equity. It also
included a new rate plan, the Alternative Rate Plan, under which the Com-
pany's rates are 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.
In February 1999, the Company submitted its 1999 filing to the MPUC under the
Alternative Rate Plan. If approved, the Company will implement a rate
increase of approximately 2% effective May 1, 1999. The Company is not
seeking an increase due to inflation. Rather, the entire amount of the
increase is due to adjustments for specific cost items. The largest of these
is for the recovery of the 1998 ice storm costs (see Note 12) at a rate of
$1.46 million annually over a four-year period. The remainder of the request
consists of adjustments for items contemplated in the MPUC's decision in the
Company's last rate case, discussed above, but for which the amounts were not
known at the time.
As previously discussed, the 1997 Maine restructuring legislation requires
the MPUC, when retail access begins, to provide a "reasonable opportunity" to
recover stranded costs through the rates of the transmission and distribution
(T&D) utility, comparable to the utility's opportunity to recover stranded
costs before the implementation of retail access under the legislation. The
principal restructuring provisions of the legislation provide for customers
to have direct retail access to generation services and for deregulation of
competitive electricity providers, commencing March 1, 2000, with T&D
companies continuing to be regulated by the MPUC. The MPUC is conducting the
proceeding that will ultimately determine the Company's stranded costs and
corresponding revenue requirements, and has scheduled completion of the
current phase of the proceeding for the second quarter of 1999. On July 24,
1998, the Company filed direct testimony in the proceeding estimating its
future revenue requirements as a T&D utility and providing an estimate of its
stranded costs, and rebuttal testimony was filed on November 25, 1998. The
Company estimated its total stranded costs to be approximately $284 million,
which includes the net present value of above-market purchased power
obligations and has estimated its stranded cost revenue requirement to be
approximately $40.6 million, annually starting March 1, 2000. The Company
cannot predict the results of the MPUC proceeding, which is scheduled to
conclude in May 1999, subject to later updating prior to March 1, 2000. The
Company is also actively involved in numerous other MPUC rule-makings in
connection with the various aspects of the introduction of retail
competition.
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, 1998, the
Company has regulatory assets, net of regulatory liabilities, of
approximately $246.3 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.
11. SALE OF PROPERTY AT GRAHAM STATION
In September 1998, the Company sold certain property and equipment at its
Graham Station site in Veazie, Maine, to Casco Bay Energy for $6.2 million.
The property is to be utilized by Casco Bay Energy, which plans to construct
a $221 million gas-fired power plant that will produce 520 MW's of
electricity. The plant will be powered by the proposed Maritimes & Northeast
gas transmission line and regional transmission system. The Company realized
a net gain from the sale of $4.5 million, which has been deferred (reflected
as a component of Other Deferred Credits on the Consolidated Balance Sheet at
December 31, 1998) in anticipation that it will likely be utilized as a
future reduction to the Company's recoverable stranded costs. In connection
with the sale, the $6.2 million in proceeds were deposited with a third party
trustee, as a requirement under the Company's bond indenture. The $6.2
million was released by the trustee in January 1999 and has been utilized to
repay a portion of the Company's medium term notes. Also in connection with
the sale, the Company deposited $400,000 with a third party trustee to be
utilized for future environmental remediation at the site.
12. STORM DAMAGE
As discussed in the 1997 Form 10-K, the Company suffered widespread damage
throughout its service territory to its transmission and distribution
equipment during a major ice storm in January 1998. The Company's incremental
costs associated with the service restoration effort were approximately $4.5
million and has been deferred and included in Other Deferred Charges on the
Company's Consolidated Balance Sheets as of December 31, 1998. The MPUC
issued an order authorizing the Company to defer incremental, non-capitalized
storm damage expenses for future recovery through the rates charged to
customers. As discussed in Note 10, the Company is seeking to begin recovery
of those deferred costs on May 1, 1999 as part of its annual rate adjustment
pursuant to its Alternative Rate Plan.
13. 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 1998, 1997 and 1996 the
notional rate was not in excess of 7.25%. In 1998 the Company prepaid the
remaining outstanding balance of the $60 million of medium term notes, but
the interest rate cap remains in place because the benefits of the cap are
also applicable to the new $45 million term loan. 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.
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 rate mechanisms which were previously in place. 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 1998 and 1997 amounting to
1,180,000 and 865,000 barrels of residual oil, respectively. As a result of
market movements in 1998 and 1997 the Company made cash payments of
approximately $5.1 million in 1998 and received cash payments of $1.2 million
in 1997 associated with the swap transactions. Additionally, as a result of
the dramatic decrease in oil prices in 1998 (near twelve-year lows) the
Company exceeded its margin limit with at least one of the counterparties to
the swap agreements. Therefore the Company was required to post about $0.8
million of collateral in the form of cash, letter of credit, or other
marketable security. The Company chose to provide cash as collateral and is
reflected in accounts receivable on the Consolidated Balance Sheet at
December 31, 1998.
The cash paid/received from the "swaps" was recorded as an increase/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
counterparties. 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, 1998, the Company was a party to "swaps" covering 1.6 million
barrels of residual oil for the year 1999 and 265,000 barrels for the first
two months of the year 2000. With the advent of retail competition in the
electric utility industry starting March 1, 2000, and the Company no longer
selling electricity in the retail market, the utilization of fuel swaps will
no longer be required. The fair market value of these 1999 and 2000 "swaps"
at December 31, 1998 is estimated to be a negative $4.1 million. Also, the
Company expects to be required to post collateral in the first quarter of
1999. Collateral is not expected to be posted after the first quarter because
hedge volumes will be significantly reduced and the Company does not
anticipate entering into any additional hedge transactions. Since the "swaps"
are accounted for as hedges, the fair market 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.
INTEREST RATE SWAP-As discussed in Note 4, in connection with the $24.8
million in BERI medium term notes, BERI entered into an interest rate swap
arrangement with a major financial institution to provide interest rate
protection through the maturity date of the term loan. The interest rate swap
fixed the LIBO interest rate on the medium term notes at 5.72%. BERI will be
reimbursed for incremental interest expense incurred in excess of the 5.72%
and incurs additional expense for incremental interest expense below 5.72%.
During 1998, BERI incurred minor additional interest expense in connection
with the interest rate swap arrangement. Market risk is the potential loss
arising from adverse changes in interest rates. The fair value of the
interest rate swap at December 31, 1998 is a negative $286,000 and represents
the estimated payment that would be made to terminate the agreement.
14. 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, 1998, the liability recorded by the Company for its
estimated environmental remediation costs amounted to $331,000. The Com-
pany's actual future environmental remediation costs may be higher as
additional factors become known.
15. NEW ACCOUNTING PRONOUNCEMENTS
In June 1998, the Financial Accounting Standards Board issued Statement No.
133, "Accounting for Derivative Instruments and Hedging Activities" (FASB
133), and is effective for fiscal years beginning after June 15, 1999. FASB
133 establishes accounting and reporting standards for derivative instruments
and for hedging activities. It requires that an entity recognize all
derivatives as either assets or liabilities in the statement of financial
position and measure those instruments at fair value. Changes in the
derivatives fair value should be recognized currently in earnings unless the
derivative is designated as a hedge. When designated as a hedge, the change
in fair value should be recognized currently in changes in equity. FASB 133
also requires a company to formally document, designate and assess the
effectiveness of transactions that receive hedge accounting treatment. The
affects of the adoption of FASB 133 on the Company's financial statements are
currently not known. The Company believes that its fuel and interest rate
swap agreements will qualify for hedge accounting treatment under FASB 133.
In April 1998, the American Institute of Certified Public Accountants issued
Statement of Position 98-5, "Reporting on the Costs of Start-up Activities"
(SOP 98-5). The Company is required to adopt SOP 98-5 for fiscal year 1999.
SOP 98-5 defines start-up activities as one-time activities an entity
undertakes when it opens a new facility, introduces a new product line or
service, conducts business in a new territory or with a new class of customer
or beneficiary, initiates a new process in an existing facility or commences
some new operation. SOP 98-5 covers accounting for organization costs and
requires that any such costs should be expensed as incurred in the same
manner as other start-up costs. The statement requires entities to expense
previously capitalized costs in the year of adopting SOP 98-5. The Company
does not believe the application of this statement will have a material
impact on the financial statements.
On January 1, 1998, the Company adopted Statement of Financial Accounting
Standards No. 131, "Disclosures about Segments of an Enterprise and Related
Information" (FASB 131). FASB 131 establishes standards for the way public
business enterprises report information about operating segments in annual
financial statements. It also establishes standards for related disclosures
about products and services, geographic areas and major customers. The
adoption of FASB 131 in 1998 did not have any impact on financial statement
disclosures.
PRICEWATERHOUSECOOPERS LLP
REPORT OF INDEPENDENT CERTIFIED PUBLIC ACCOUNTANTS
TO THE STOCKHOLDERS AND DIRECTORS OF BANGOR HYDRO-ELECTRIC COMPANY:
In our opinion, the accompanying consolidated balance sheets and statements
of capitalization and the related consolidated statements of income, common
stock investment and cash flows present fairly, in all material respects, the
financial position of Bangor Hydro-Electric Company (the Company) and its
subsidiaries at December 31, 1998 and 1997, and the results of their
operations and their cash flows for each of the three years in the period
ended December 31, 1998, in conformity with generally accepted accounting
principles. 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 of these
statements in accordance with generally accepted auditing standards which
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, assessing the accounting
principles used and significant estimates made by management, and evaluating
the overall financial statement presentation. We believe that our audits
provide a reasonable basis for the opinion expressed above.
PricewaterhouseCoopers, LLP
January 27, 1999
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 19, 1999, 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 19, 1999, 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 19, 1999,
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 19, 1999, 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 19, 1999, 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, 1998, 1997 and 1996
Consolidated Balance Sheets - December 31, 1998 and
1997
Consolidated Statements of Common Stock Investment
for the Years ended December 31, 1998, 1997 and 1996
Consolidated Statements of Capitalization - December
31, 1998 and 1997
Consolidated Statements of Cash Flows
for the Years Ended December 31, 1998, 1997 and 1996
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 one current report on Form 8-K, dated
September 25, 1998 relating to the Company's agreement to
sell substantially all of its generation assets to PP&L
Global, Inc.
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/ Marion M. Kane
- ----------------------- -----------------------
Robert S. Briggs Marion M. Kane
President and Director
Chairman of the Board
/s/ William C. Bullock, Jr.
- ---------------------------
William C. Bullock, Jr. Norman A. Ledwin
Director Director
/s/ Jane J. Bush /s/ James E. Rier, Jr.
- -------------------------- ------------------------
Jane J. Bush James E. Rier, Jr.
Director Director
/s/ Carroll R. Lee
------------------------
David M. Carlisle Carroll R. Lee
Director Director, Senior Vice
President and Chief
Operating Officer
/s/ Joseph H. Cyr /s/ Frederick S. Samp
- ------------------------- ------------------------
Joseph H. Cyr 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 17, 1999.
PRICEWATERHOUSECOOPERS
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/ PriceWaterhouseCoopers, L.L.P.
----------------------------------------
PRICEWATERHOUSECOOPERS, L.L.P.
January 27, 1999
<TABLE>
SCHEDULE VIII
RESERVES FOR DOUBTFUL ACCOUNTS AND INSURANCE
--------------------------------------------
Additions
-----------------------------
<CAPTION>
Balance at Charged to Charged to Balance at
Beginning Costs and Other End
Of Period Expenses Accounts Deductions of Period
------- ------- ------- ------- -------
1998
<S> <C> <C> <C> <C> <C>
Reserve for Doubtful Accounts $ 1,450,000 $ 1,345,536 $ - $ 1,720,536 (A)$ 1,075,000
----------- ----------- ---------- ----------- -----------
Reserve for Retirees' Life Insurance $ - $ - $ - $ - $ -
----------- ----------- ---------- ----------- -----------
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
----------- ----------- ---------- ----------- -----------
NOTE:
(A) Accounts written off, less recoveries.
</TABLE>
EXHIBIT INDEX
EXHIBITS FILED HEREWITH
EXHIBIT NO. DESCRIPTION OF EXHIBIT
----------- ----------------------
3. ARTICLES OF INCORPORATION & BY-LAWS
-----------------------------------
3(a) Articles of Amendment
Allowing Use of Similar Name
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).
4.24 Second Amendment dated as of Form 10-K, 1997, Exhibit 4(a)
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.
4.25 Security Agreement dated as of Form 10-K, 1997, Exhibit 4(b)
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.
4.26 Third Amendment dated as of Form 10-K, 1997, Exhibit 4(c)
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.
4.27 Amended and Restated Security Form 10-K, 1997, Exhibit 4(d)
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.
4.28 TERM LOAN AGREEMENT Form 10-Q, First Quarter 1998,
dated as of March 31, 1998 Exhibit 4(a)
among BANGOR ENERGY RESALE,
INC., BANKBOSTON, N.A. and
the certain other lending
institutions and
BANKBOSTON, N.A., as Agent,
including all Exhibits thereto
4.29 GUARANTY, dated as of March 31, Form 10-Q, First Quarter 1998,
1998, by BANGOR HYDRO Exhibit 4(b)
ELECTRIC COMPANY, in favor of
(a) BANKBOSTON, N.A., as Agent,
for itself and the other
lending institutions which are
or may become parties to a Term
Loan Agreement, dated as of
March 31, 1998
4.30 Warrant to Purchase Form 10-Q, Second Quarter 1998,
Common Stock Granted to Exhibit 4(a)
the Municipal Review
Committee, Inc. on
June 26, 1998
4.31 Warrant to Purchase Form 10-Q, Second Quarter 1998,
Common Stock Dated Exhibit 4(b)
Granted to PERC
Management Company
Limited Partnership on
June 26, 1998
4.32 Warrant to Purchase Form 10-Q, Second Quarter 1998,
Common Stock Granted to Exhibit 4(c)
Energy National, Inc. on
June 26, 1998
4.33 Supplemental Indenture Form 10-Q, Second Quarter 1998,
Dated as of June 29, 1998 Exhibit 4(d)
between the Company and
Citibank, N.A.
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
10.110 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
10.127 ASSIGNMENT OF CONTRACTS Form 10-Q, 1st Quarter 1998,
AND ENTITLEMENTS, made March Exhibit 10(a)
31, 1998 by and between Bangor
Hydro-Electric Company and
Bangor Energy Resale, Inc.
10.128 Rate Agreement made October 30, Form 10-Q, 1st Quarter 1998,
1997, by and between Bangor Exhibit 10(b)
Hydro-Electric Company and
Bangor Energy Resale, Inc.
10.129 Management and Support Services Form 10-Q, 1st Quarter 1998,
Agreement made March 31, 1998 Exhibit 10(c)
by and between Bangor Hydro-
Electric Company and Bangor
Energy Resale, Inc.
10.130 Surplus Cash Agreement Form 10-Q, 2nd Quarter 1998,
dated as of June 26, 1998 Exhibit 10(a)
among the Company,
Penobscot Energy Recovery
Company Limited
Partnership and the
Municipal Review
Committee, Inc.
10.131 Guaranty Agreement dated Form 10-Q, 2nd Quarter 1998,
as of June 1, 1998 Exhibit 10(b)
between the Company and
The Chase Manhattan Bank
10.132 Amendment No. 2 to Form 10-Q, 2nd Quarter 1998,
Purchase Power Agreement Exhibit 10(c)
dated as of June 26, 1998
between the Company and
Penobscot Energy Recovery
Company Limited
Partnership
10.133 Amended and Restated Form 10-Q, 2nd Quarter 1998,
Revolving Credit And Exhibit 10(d)
Term Loan Agreement
dated as of June 19, 1998
between the Company and
BankBoston, N.A. and Fleet
National Bank
10.134 Asset Purchase Agreement Form 8-K, September 25, 1998
dated as of September 25, Exhibit 2
1998 between Bangor Hydro-
Electric Company and PP&L
Global, Inc. (schedules and
exhibits omitted).
<TABLE> <S> <C>
<ARTICLE> UT
<LEGEND>
This schedule contains summary financial information extracted from Bangor
Hydro-Electric Company-1998 Form 10K and is qualified in its entirety by
rreference to such 10K.
</LEGEND>
<CIK> 0000009548
<NAME> BANGOR HYDRO-ELECTRIC COMPANY
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1998
<PERIOD-END> DEC-31-1998
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 251,342
<OTHER-PROPERTY-AND-INVEST> 55,557
<TOTAL-CURRENT-ASSETS> 36,645
<TOTAL-DEFERRED-CHARGES> 262,144
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 605,688
<COMMON> 36,817
<CAPITAL-SURPLUS-PAID-IN> 59,054
<RETAINED-EARNINGS> 22,993
<TOTAL-COMMON-STOCKHOLDERS-EQ> 118,864
7,604
4,734
<LONG-TERM-DEBT-NET> 263,028
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 12,000
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 25,515
1,594
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<OTHER-ITEMS-CAPITAL-AND-LIAB> 172,349
<TOT-CAPITALIZATION-AND-LIAB> 605,688
<GROSS-OPERATING-REVENUE> 195,144
<INCOME-TAX-EXPENSE> 6,093
<OTHER-OPERATING-EXPENSES> 153,915
<TOTAL-OPERATING-EXPENSES> 160,008
<OPERATING-INCOME-LOSS> 35,136
<OTHER-INCOME-NET> 1,292
<INCOME-BEFORE-INTEREST-EXPEN> 36,428
<TOTAL-INTEREST-EXPENSE> 24,963
<NET-INCOME> 11,465
1,244
<EARNINGS-AVAILABLE-FOR-COMM> 10,221
<COMMON-STOCK-DIVIDENDS> 0
<TOTAL-INTEREST-ON-BONDS> 22,906
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