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FORM 10-K
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15 (d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the Fiscal year ended DECEMBER 31, 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
---------------------------------
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
--------------------
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
--------------------
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
------- -------- ---------------- ------------------
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
--------------
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
---------
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.
Item 6
Selected Financial Data
SIX YEAR STATISTICAL SUMMARY
Bangor Hydro-Electric Company
1998 1997 1996 1995 1994 1993
- ---------------------------------------------------------------------------------------------------------------------------------
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).
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-yea