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, 1999 Commission File No. 0-505
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BANGOR HYDRO-ELECTRIC COMPANY
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(Exact Name of Registrant as specified in its charter)
MAINE 01-0024370
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State of Incorporation) (I.R.S. Employer ID No.)
33 STATE STREET, BANGOR, MAINE 04401
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(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code 207-945-5621
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Securities registered pursuant to Section 12(b) of the Act:
Title of each class Name of exchange on which registered
COMMON STOCK, $5 PAR VALUE NEW YORK STOCK EXCHANGE
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Securities registered pursuant to Section 12(g) of the Act:
Common Stock, $5 Par value
(7,363,424 shares outstanding at March 20, 2000)
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7% Preferred Stock, $100 Par Value
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4 1/4% Preferred Stock, $100 Par Value
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4% Preferred Stock Series A, $100 Par Value
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Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to
such filing requirements for the past 90 days.
Yes X No
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Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K (Section 229.405 of this chapter) is not contained
herein, and will not be contained, to the best of registrant's knowledge, in
definitive proxy or information statements incorporated by reference in Part
III of this Form 10-K or any amendment to this Form 10-K. [X]
The aggregate market value on March 20, 2000 of the voting stock held by
non-affiliates of the registrant was $116.1 million.
The information required by Part III Items 10, 11, 12 and 13 is
incorporated by reference from the registrant's proxy statement which will be
filed with the Securities and Exchange Commission within 120 days of the
close of the registrant's fiscal year ended December 31, 1999.
FORM 10-K
FOR THE FISCAL YEAR ENDED DECEMBER 31, 1999
PAGE
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Cover Page 1
Index 3
PART I:
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Items 1 through 2: Business; Properties 6
-General 6
-Certain Issues Facing the Company 8
-Construction Program 9
-Rates and Regulation 9
-Seabrook 10
-Joint Ventures 10
-Employees 12
-Power Supply Sources 12
-Company-owned Generation 12
-Power Purchase Contracts 12
-Maine Yankee 13
-Environmental Matters 18
Item 3: Legal Proceedings 18
Item 4: Submission of Matters to a Vote of Security Holders 19
PART II:
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Item 5: Market for Registrant's Common Equity and Related
Stockholder Matters 19
Item 6: Selected Financial Data 21
Item 7: Management's Discussion and Analysis of Results
of Operations and Financial Condition 23
Item 8: Financial Statements & Supplementary Data 33
-Consolidated Statements of Income 33
-Consolidated Balance Sheets 34
-Consolidated Statements of Capitalizations 36
-Consolidated Statements of Cash Flows 37
-Consolidated Statements of Common Stock Investment 38
-Notes to Consolidated Financial Statements 39
1) Nature of Operations and Summary of
Significant Accounting Policies 39
2) Income Taxes 41
3) Common and Preferred Stock and
Earnings Per Share 43
4) Lending Agreements and Monetization
of Power Sale Contract 44
5) Postretirement Benefits 45
6) Jointly Owned Facilities and Power
Supply Commitments 48
7) Recovery of Seabrook Investment and
Sale of Seabrook Interest 56
8) Unaudited Quarterly Financial Data 56
9) Fair Value of Financial Instruments 56
10) Industry Restructuring and Rate Regulation 57
11) Storm Damage 60
12) Construction of Facilities for Casco Bay Energy 60
13) Derivative Financial Instruments 60
14) Contingencies 61
Report of Independent Accountants 63
Item 7A: Quantitative and Qualitative Disclosures
about Market Risk 64
Item 9: Changes in and Disagreements with Audit Firms
on Financial Disclosures 64
PART III:
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Item 10: Directors and Executive Officers of
the Registrant 64
Item 11: Executive Compensation 66
Item 12: Security Ownership of Certain Beneficial
Owners and Management 68
Item 13: Certain Relationships and Related Transactions 69
PART IV:
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Item 14: Exhibits, Financial Statement Schedules,
and Reports on Form 8-K 70
Signatures 72
Report of Independent Accountants 73
Schedule VIII - Reserve for Doubtful Accounts 74
EXHIBIT INDEX:
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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, 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 primarily engaged in the transmission
and distribution 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 107,000 customers in portions of the counties of
Penobscot, Hancock, Washington, Waldo, Piscataquis and Aroostook. The Company
also purchases energy at wholesale and sells energy to retail customers and
to other utilities for resale.
The Company owns approximately 600 miles of transmission lines and
approximately 3,600 miles of distribution lines to serve its customers. The
Company owns a variety of customer and business information systems used to
manage its business operations. Other properties consist of office, garage
and warehouse facilities at various locations in its service area.
The Company has three material wholly-owned subsidiaries, Bangor Var
Co., Inc. ("Bangor Var Co."), Penobscot Natural Gas Company, Inc. ("Penobscot
Gas"), and Bangor Energy Resale, Inc. Bangor Var Co. was incorporated in
1990 to hold the Company's 50% interest in a partnership which owns certain
facilities used in the Hydro-Quebec Phase II transmission project ("HQ-II")
in which the Company is a participant. For a further discussion of Penobscot
Hydro Co. and Bangor Var Co., see "Joint Ventures." 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. On March 7, 2000,
the Company and Penobscot Gas entered into a Stock Purchase Agreement to sell
the Company's interest in Penobscot Gas to SEMPRA Energy. 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 Note 4 to the Consolidated Financial Statements
included in Item 8, below.
In 1999, 30.4% of the Company's kilowatt hour ("KWH") sales were to
residential customers, 31.1% were to commercial customers, 38.0% were to
industrial customers and 0.5% 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.
During 1999, however, the Company experienced its maximum peak electric
demand during the summer months, with the peak of approximately 293.08
megawatts ("MW") occurring on July 28, 1999. At that time the Company had
approximately 267.72 MW of generating capacity and firm purchased power,
comprised of 27.4 MW from Company-owned generating units, 44.3 MW from
non-utility power producers, and 196.0 MW from short term contract purchases.
The Company served the remainder of its peak demand though spot market
purchases.
The Company owns 7% of the common stock of Maine Yankee Atomic Power
Company ("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. 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 distribution 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 rates for wholesale purchases and sales of energy and capacity and
transmission services. Maine Yankee is subject to extensive regulation by
the Nuclear Regulatory Commission ("NRC"). See "Rates and Regulation."
The principal executive offices of the Company are located at 33 State
Street, Bangor, Maine 04401; telephone (207) 945-5621.
CERTAIN ISSUES FACING THE COMPANY
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CHANGES IN THE ELECTRIC UTILITY INDUSTRY AND IN REGULATION - Pursuant to "An
Act to Restructure the State's Electric Industry", enacted in 1997 by the
Maine Legislature, effective March 1, 2000, the Company is no longer
permitted to engage directly in the generation and sale of electric energy
unless designated by the Maine Public Utilities Commission to provide so-
called "standard offer" service. For the period March 1, 2000 through
February 28, 2001, the MPUC has ordered the Company to assume the
responsibility for providing standard offer service. 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 - Standard Offer Service" and Note 10 to the Consolidated Financial
Statements included in Item 8, below. The Company will remain regulated as a
provider of electricity transmission and distribution services. As part of
the restructuring process, the Company completed the sale on May 27, 1999 of
substantially all Company-owned generation assets 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 - 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.
CONSTRUCTION PROGRAM
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The Company's construction program consists of extensions and
improvements of its transmission and distribution facilities, capital
improvements to the Company's internal computer and information systems and
other general projects within the Company's service area. The Company
projects that capital expenditures will aggregate approximately $40-50
million in the period 2000 through 2002.
RATES AND REGULATION
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RATE MATTERS - The Company has been involved in rate proceedings with the
MPUC since mid-1998 to determine its revenue requirement as a T&D utility
starting March 1, 2000 and the recoverability of the Company's stranded
costs. In February 2000, the Company received a final rate order from the
MPUC setting its T&D and stranded cost rates effective March 1, 2000. The
Company's total annual revenue requirement as set in the rate proceedings,
including $40 million associated with stranded cost recovery, amounted to $
103.2 million. The stranded cost recovery includes the decommissioning and
other plant closure expenses for Maine Yankee. There were no write-offs of
previously deferred costs based on the final rate order.
In Maine, stranded costs are treated in the same manner as most other
costs and may be included in calculations for prospective rate changes.
Absent any rate proceedings, however, in 2003 and every three years
thereafter until the stranded costs are recovered, the MPUC shall review and
reevaluate the stranded cost recovery. Customers reducing or eliminating
their consumption of electricity by switching to self-generation, conversion
to alternative fuels or utilizing demand-side management measures cannot be
assessed exit or entry fees.
OTHER REGULATION - The MPUC regulates numerous other matters affecting the
Company, including financing, construction of transmission facilities, credit
and 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 transmission services and rates for sales of
electricity to other utilities.
SEABROOK
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GENERAL - The Company was a participant in Seabrook from 1978 to 1986,
with an ownership interest of 2.17%, or 25 MW, in each of the two 1150 MW
units. Unit 2 was effectively canceled in 1984. In late 1984, following
a lengthy MPUC investigation, the conclusion of which cast doubt on the
wisdom of the Maine utilities' continued participation in Seabrook, the
Company began efforts to sell its interest in the project. An agreement
for the sale of Seabrook to EUA Power Corp. was reached in mid-1985 and
was consummated in November 1986.
In 1985, the MPUC approved an agreement among the Company, the MPUC
Staff and the Public Advocate addressing the recovery through rates of
the Company's investment in Seabrook ("Seabrook Stipulation"). Although
implementation of the Seabrook Stipulation significantly improved the
Company's financial condition, substantial write-offs were required.
In August 1989, a comprehensive settlement agreement entered into by
current and former joint owners of Seabrook became effective. Under the
agreement, the signatories, representing virtually all of the ownership
interests in Seabrook, relinquished claims against the lead owner, Public
Service Company of New Hampshire, arising out of Seabrook. As a part of the
settlement, former joint owners, including the Company, were relieved of
certain contingent liabilities.
JOINT VENTURES
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BANGOR GAS - In 1998 the Company formed Penobscot Gas, whose sole function
was to be a 50% general partner in Bangor Gas Company, LLC (Bangor Gas),
which is constructing a natural gas distribution system in the greater
Bangor, Maine area. Sempra Energy, a joint venture of Pacific Enterprises and
Enova Corporation, owns the other 50% interest in Bangor Gas. Gas service to
Maine has become feasible for the first time because of the development of
the Maritimes & Northeast Pipeline Project, extending from the Sable Offshore
Energy Project near Sable Island, Nova Scotia, through the state of Maine and
interconnecting with the Tennessee Gas Pipeline in Dracut, Massachusetts. The
pipeline passes near the Bangor area. As the restructuring of the electric
industry in Maine has developed, the Company has become increasingly
cognizant of the need to focus on its core electric transmission and dis-
tribution business. Consequently the Company has determined that it no longer
desires to participate in the Bangor Gas joint venture. On March 7, 2000, the
Company and Penobscot Gas entered into a Stock Purchase Agreement to sell the
Company's interest in Penobscot Gas to SEMPRA Energy. Penobscot Gas'
investment in Bangor Gas as of December 31, 1999 is approximately $328,000
and is recorded as an Other Investment on the Consolidated Balance Sheets.
NEPOOL/HYDRO-QUEBEC - The Company is a 1.6% participant in the NEPOOL/Hydro-
Quebec Phase 1 project (Phase 1), a 690 MW DC intertie between the New
England utilities and Hydro-Quebec constructed by a subsidiary of another New
England utility at a cost of about $140 million. The participants receive
their respective share of savings from energy transactions with Hydro-Quebec,
and are obliged to pay for their respective shares of the costs of ownership
and operation whether or not any savings are realized.
The Company is also a 1.5% participant in the NEPOOL/Hydro-Quebec Phase
2 project (Phase 2), which involves an increase to the capacity of the Phase
1 intertie to 2,000 MW. As in the Phase 1 project, the Company receives a
share of the anticipated energy cost savings derived from purchases from
Hydro-Quebec and capacity benefits provided by the intertie and is required
to pay its share of the costs of ownership and operation whether or not any
savings are obtained. In connection with the generation asset sale in May
1999, the Company sold its rights as a participant in the regional utilities
agreement with Hydro-Quebec. See Note 6 to the Consolidated Financial
Statements included in Item 8, below. The Company, though, is still required
to pay its share of the costs of ownership and operation of the Hydro-Quebec
intertie. Also in connection with the asset sale, PP&L Global (PP&L) has
agreed to pay the Company $400,000 per year to partially offset the Company's
on-going Hydro-Quebec support payments. Since the Company still has an
obligation for the costs of the Hydro-Quebec intertie, but it has sold the
rights to the benefits as a participant, a $7.5 million liability (included
in Other Long-term Liabilities) and corresponding regulatory asset (included
in Other Regulatory Assets) have been recorded as of December 31, 1999 on the
Consolidated Balance Sheet representing the present value of the Company's
estimated future payments (net of the $400,000 to be received from PP&L) for
costs of ownership and operation of the Hydro-Quebec intertie.
BANGOR VAR CO. - In 1990, the Company formed BVC, whose sole function is to
be a 50% general partner in Chester, a partnership which owns a static var
compensator (SVC), which is electrical equipment that supports the Phase 2
transmission line. A wholly-owned subsidiary of Central Maine Power Company
owns the other 50% interest in Chester. Chester has financed the acquisition
and construction of the SVC through the issuance of $33 million in principal
amount of 10.48% senior notes due 2020, and up to $3.25 million in principal
amount of additional notes due 2020 (collectively, the SVC Notes). The
holders of the SVC Notes are without recourse against the partners or their
parent companies and may only look to Chester and to the collateral for
payment. The New England utilities which participate in Phase 2 have agreed
under a FERC approved contract to bear the cost of Chester, on a cost of
service basis, which includes a return on and of all capital costs.
MEPCO - The Company owns 14.2% of the common stock of MEPCO. MEPCO owns and
operates electric transmission facilities from Wiscasset, Maine, to the
Maine-New Brunswick border. Information relating to the operations and
financial position of Maine Yankee and MEPCO appears above. In connection
with the Company's generation asset sale, the Company sold certain of its
rights to MEPCO transmission capacity. See Note 10 to the Consolidated
Financial Statements included in Item 8, below.
EMPLOYEES
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At December 31, 1999, the Company had 429 full time employees
approximately 50% of whom were represented by a local union affiliated with
the International Brotherhood of Electrical Workers (AFL-CIO). The present
collective bargaining agreement with union employees expires December 31,
2004. The Company believes that its relations with its employees are
satisfactory.
POWER SUPPLY SOURCES
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COMPANY-OWNED GENERATION - As part of the electric industry
restructuring process in the State of Maine, on May 27, 1999, the Company
completed the sale of most of its electric generating assets and certain
transmission rights to PP&L Global, 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 - Sale
of Company's Generating Assets".
The Company continues to own eleven internal combustion generation units
located at three stations having a total capacity of 21 MW. These units are
used to provide voltage support for the Company's local transmission and
distribution system, as needed, and to provide generating capacity to serve
the Company's power sales contract with UNITIL Power Corp., a New Hampshire
based electric utility, with a contract term ending in the year 2003.
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
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Bangor-Pacific August 21, 1986 through Total output of energy
(Hydroelectric) May 31, 2024, at which from facility with name
time Company can either plate rating of not more
purchase the facility than 16 MW
at its fair market value
or extend the contract
for an additional 15
years (if the West
Enfield Project's FERC
license is also
extended)
Penobscot Energy January 21, 1984 through Total output of firm
Recovery Company February 28, 2018 energy; minimum annual
("PERC")(Refuse) delivery of 105,000,000
KWH up to a maximum of
166,440,000 KWH per
calendar year
As part of the electric industry restructuring process in the State of
Maine, in late 1999, the Company entered into a contract to sell the output
of these contracts to Morgan Stanley Capital Group, a subsidiary of Morgan
Stanley Dean Witter & Company, for a two year period. Also a part of the
transaction are all of the energy and capacity from several smaller
agreements with Pumpkin Hill, Milo, Green Lake and Sebec Hydro. See Note 6
to the Consolidated Financial Statements included in Item 8, below.
For the period March 1, 2000 through February 28, 2001, the MPUC has
ordered the Company to assume the responsibility for providing standard offer
service. 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 - Standard Offer Service" and Note 10 to the
Consolidated Financial Statements included in Item 8, below. The Company
intends to meet its obligations through short term contracts and spot market
purchases, a strategy that has been approved by the MPUC.
MAINE YANKEE
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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. The Plant had experienced a number of operational
and regulatory problems and did not operate after 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 in 2008.
MAINE YANKEE RATE CASE SETTLEMENT - On November 6, 1997, Maine Yankee
submitted to FERC for filing certain amendments to the Power Contracts (the
"Amendatory Agreements") and revised rates to reflect the decision to shut
down the Plant and to request approval of an increase in the decommissioning
component of its formula rates. Maine Yankee's submittal also requested
certain other rate changes, including recovery of unamortized investment
(including fuel) and certain changes to its billing formula, consistent with
the non-operating status of the Plant. By Order dated January 14, 1998, the
FERC accepted Maine Yankee's new rates for filing, subject to refund after a
minimum suspension period, and set for hearing Maine Yankee's Amendatory
Agreements, rates, and issues concerning the prudence of the Plant shutdown
decision that had been raised by intervenors.
During 1998 and early 1999 the active intervenors, including among
others the MPUC Staff, the Maine Office of the Public Advocate ("OPA"), the
Company and other owners, municipal and cooperative purchasers of Maine
Yankee power (the "Secondary Purchasers"), and a Maine environmental group
(the "Settling Parties"), engaged in extensive discovery and negotiations,
which resulted in the filing of a settlement agreement with the FERC on
January 19, 1999. A separately negotiated settlement filed with the FERC on
February 5, 1999, resolved the issues raised by the Secondary Purchasers by
limiting the amounts they will pay for decommissioning the Plant and by
settling other points of contention affecting individual Secondary
Purchasers. Both settlements were found to be in the public interest and
approved by the FERC on June 1, 1999. The settlements constitute full
settlement of all issues raised in the FERC proceeding, including
decommissioning-cost issues pertaining to the prudence of management,
operation, and decision to permanently cease operation of the plant.
The primary settlement provided for Maine Yankee to collect $33.1
million in the aggregate annually, effective August 1, 1999, including both
decommissioning costs and costs related to Maine Yankee's planned on-site
independent spent fuel storage installation ("ISFSI"). The 1997 FERC filing
had called for an aggregate annual collection rate of $36.4 million for
decommissioning and ISFSI, based on a 1997 estimate. Pursuant to the
approved settlement the amount collected annually has been reduced to
approximately $15.6 million, effective October 1, 1999, as a result of 1999
Maine legislation allowing Maine Yankee to (1) use for construction of the
ISFSI funds held in trust under Maine law for spent-fuel disposal, and (2)
access approximately $6.8 million held by the State of Maine for eventual
payment to the State of Texas pursuant to a compact for low-level nuclear
waste disposal, the future of which is in question after rejection of the
selected disposal site in west Texas by a Texas regulatory agency.
The settlement also provides for recovery of the unamortized investment
(including Fuel) in the Plant, together with a return on equity of 6.50
percent, effective January 15, 1998, on equity balances up to maximum allowed
equity amounts, which resulted in a refund of $9.3 million (including tax
impacts) distributed to the sponsors on a pro rata basis on July 15, 1999.
The Settling Parties also agreed not to contest the effectiveness of the
Amendatory Agreements submitted to FERC as part of the original filing,
subject to certain limitations including the right to challenge any
accelerated recovery of unamortized investment under the terms of the
Amendatory Agreements after a required informational filing with the FERC by
Maine Yankee. In addition, the settlement contains incentives for Maine
Yankee to achieve further savings in its decommissioning and ISFSI-related
costs and resolves issues concerning restoration and future use of the Plant
site and environmental matters of concern to certain of the intervenors in
the proceeding.
As a separate part of the settlement, the Company, the other two Maine
utilities which own interests in Maine Yankee, the MPUC Staff, and OPA
entered into a further agreement resolving retail rate issues and other
issues specific to the Maine parties, including those that had been raised
concerning the prudence of the operation and shutdown of the Plant (the
"Maine Agreement"). Under the Maine Agreement, the Company is recovering its
Maine Yankee costs in accordance with its most recent rate order from the
MPUC.
Finally, the Maine Agreement requires the Company and the other two
Maine utilities, for the period from March 1, 2000, through December 1, 2004,
to hold their Maine retail ratepayers harmless from the amounts by which the
replacement power costs for Maine Yankee Board of Directors that served as a
basis for the Plant shutdown decision, up to a maximum cumulative amount of
$41 million. The Company's share of that amount would be $5.7 million for
the period. Based on the results of the two-year entitlement auction already
completed, the Company will not incur any liability for this provision in
year 2000 and does not believe that it will incur any liability in 2001.
The Company believes that the approved settlement, including the Maine
Agreement, constitutes a reasonable resolution of the issues raised in the
Maine Yankee FERC proceeding, which has eliminated significant uncertainties
concerning and the Company's future financial performance.
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 in September, 1998.
However, in October, 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.
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 - 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.
The United States Congress has been unable to agree on legislation to reform
the federal spent nuclear fuel program.
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 "to
start disposing of [spent nuclear fuel] no later than January 31, 1998". The
DOE did not appeal the decision, but announced in December 1996 that it
anticipated it would be unable to start accepting spent nuclear fuel for
disposal by January 31, 1998. A large number of nuclear utilities and state
regulators filed a new lawsuit against the DOE in January 1997 seeking to
force the DOE to honor its obligation to store spent nuclear fuel and seeking
other appropriate relief.
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's 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 are
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.
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 this site. 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, 1999, 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 2000 it will spend approximately
$373,465 in operations expenses and $55,500 in capital expenditures to comply
with environmental standards for air, water and hazardous materials.
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, 1999, there were 5,768 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
- ------------- ---- --- ---------
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................ $14 5/16 $12 9/16 $.00
Second Quarter............... 16 3/8 11 7/8 .15
Third Quarter................ 16 15/16 15 3/4 .15
Fourth Quarter............... 17 5/16 15 .15
2000
- ----
First Quarter
(through March 20, 2000).. $16 1/4 $14 1/8 $.20
Approximately 82% 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.
Item 6 Selected Financial Data
BANGOR HYDRO-ELECTRIC COMPANY
SIX-YEAR STATISTICAL SUMMARY
(Unaudited)
1999 1998 1997 1996 1995 1994
- ----------------------------------------- --------- --------- --------- --------- --------- ---------
Megawatt Hours (MWH) Generated And Purchased
Hydro Generation (Company) 205,265 275,379 262,377 321,532 275,810 271,616
Nuclear Generation (Maine Yankee) - - - 348,719 13,606 456,871
Oil (Company) 69,026 96,476 69,580 26,912 50,706 35,759
Biomass/Refuse 137,384 156,051 159,990 163,279 177,558 190,218
NEPOOL/Other Purchases 1,629,643 1,522,125 1,583,093 1,359,116 1,540,530 958,363
--------- --------- --------- --------- --------- ---------
Total Generated & Purchased 2,041,318 2,050,031 2,075,040 2,219,558 2,058,210 1,912,827
Less Line Losses and Company Use 143,198 139,028 147,298 141,426 140,128 136,908
--------- --------- --------- --------- --------- ---------
Remainder-MWH sold 1,898,120 1,911,003 1,927,742 2,078,132 1,918,082 1,775,919
========= ========= ========= ========= ========= =========
Classification of Sales-MWH
Residential 533,566 522,836 533,161 536,490 513,076 516,470
Commercial 545,087 524,292 515,904 508,331 507,243 504,992
Industrial 667,059 662,382 687,365 652,087 690,863 614,169
Lighting 8,911 8,901 8,780 8,945 9,547 9,416
Wholesale 2,716 2,704 3,841 4,486 10,961 11,705
--------- --------- --------- --------- --------- ---------
Total MWH Billed to Customers 1,757,339 1,721,115 1,749,051 1,710,339 1,731,690 1,656,752
Unbilled Sales-Net Increase (Decrease) 11,772 1,040 33,011 2,998 4,658 6,366
--------- --------- --------- --------- --------- ---------
Total Delivered Sales (MWH) 1,769,111 1,722,155 1,782,062 1,713,337 1,736,348 1,663,118
(Less) Interruptible Sales 230,378 248,091 265,438 237,553 295,818 231,128
--------- --------- --------- --------- --------- ---------
Total Firm Delivered Sales (MWH) 1,538,733 1,474,064 1,516,624 1,475,784 1,440,530 1,431,990
Off-System Sales 129,009 188,848 145,680 364,795 181,734 112,801
--------- --------- --------- --------- --------- ---------
Total Energy Sales (MWH) 1,898,120 1,911,003 1,927,742 2,078,132 1,918,082 1,775,919
========= ========= ========= ========= ========= =========
Electric Operating Revenues and Expenses (000's)
Operating Revenues
Residential $73,304 $71,396 $67,532 $66,805 $66,061 $64,008
Commercial 63,093 60,191 55,391 54,010 54,702 53,250
Industrial 43,560 42,645 41,930 39,105 40,257 37,200
Lighting 2,268 2,207 2,065 2,032 2,051 2,010
Wholesale 220 235 310 314 859 937
--------- --------- --------- --------- --------- ---------
Total Revenue from Customers $182,445 $176,674 $167,228 $162,266 $163,930 $157,405
Unbilled Sales-Net Increase (Decrease) 2,042 481 2,375 408 210 1,450
--------- --------- --------- --------- --------- ---------
Total Revenue $184,487 $177,155 $169,603 $162,674 $164,140 $158,855
(Less) Interruptible Revenue 10,049 11,064 11,215 9,537 11,149 8,450
--------- --------- --------- --------- --------- ---------
Total Firm Revenue $174,438 $166,091 $158,388 $153,137 $152,991 $150,405
Off-System Revenue 12,947 14,630 13,615 18,384 14,098 12,750
--------- --------- --------- --------- --------- ---------
Total Operating Revenues $197,434 $191,785 $183,218 $181,058 $178,238 $171,605
========= ========= ========= ========= ========= =========
Operating Expenses
Fuel for Generation and Purchased Power $80,748 $82,027 $92,792 $78,477 $98,684 $104,132
Operating and Maintenance Expense 36,492 34,448 32,471 32,441 35,711 33,498
Depreciation and Amortization 30,565 31,891 35,104 29,965 20,544 10,333
Taxes 14,032 11,642 3,168 10,249 6,306 8,803
--------- --------- --------- --------- --------- ---------
Total Operating Expenses $161,837 $160,008 $163,535 $151,132 $161,245 $156,766
========= ========= ========= ========= ========= =========
Summary of Operations (000's)
Operating Revenue $197,994 $195,144 $187,324 $187,374 $184,914 $174,098
Operating Expenses 161,837 160,008 163,535 151,132 161,245 156,766
Other Income (including equity AFDC) 2,806 1,292 1,292 1,466 760 1,308
Interest Expense (net of borrowed AFDC) 20,683 24,963 25,467 26,425 20,092 11,183
--------- --------- --------- --------- --------- ---------
Net Income (Loss) $18,280 $11,465 ($386) $11,283 $4,337 $7,457
Less Preferred Dividends 945 1,244 1,376 1,537 1,702 1,652
--------- --------- --------- --------- --------- ---------
Earnings (Loss) on Common Stock $17,335 $10,221 ($1,762) $9,746 $2,635 $5,805
========= ========= ========= ========= ========= =========
Selected Financial Data
Total Assets (000's) $543,950 $605,688 $600,583 $556,629 $566,076 $381,250
Electric Plant (000's)
Total Electric Plant $318,435 $372,782 $358,878 $341,526 $323,664 $303,637
Depreciation Reserve 84,825 101,633 96,595 87,736 81,934 75,667
--------- --------- --------- --------- --------- ---------
Net Electric Plant $233,610 $271,149 $262,283 $253,790 $241,730 $227,970
========= ========= ========= ========= ========= =========
Capitalization (000's)
Short-Term Debt - $12,000 $34,000 $32,500 $35,000 $27,000
Long-Term Debt 183,300 263,028 221,643 274,221 288,075 116,367
Redeemable Preferred Stock - 7,604 9,137 10,670 12,070 13,740
Preferred Stock 4,734 4,734 4,734 4,734 4,734 4,734
Common Equity 132,722 118,864 106,558 108,321 103,192 105,658
--------- --------- --------- --------- --------- ---------
Total $320,756 $406,230 $376,072 $430,446 $443,071 $267,499
========= ========= ========= ========= ========= =========
Capital Structure Ratios (%)
Short-Term Debt -% 3.0% 9.1% 7.5% 7.9% 10.1%
Long-Term Debt 57.1% 64.7% 58.9% 63.7% 65.0% 43.5%
Preferred Stock 1.5% 3.0% 3.7% 3.6% 3.8% 6.9%
Common Stock 41.4% 29.3% 28.3% 25.2% 23.3% 39.5%
--------- --------- --------- --------- --------- ---------
Total 100.0% 100.0% 100.0% 100.0% 100.0% 100.0%
========= ========= ========= ========= ========= =========
Miscellaneous Statistics
Shares Outstanding (Average) 7,363,424 7,363,424 7,363,424 7,336,174 7,264,360 6,947,746
Shares Outstanding (Year End) 7,363,424 7,363,424 7,363,424 7,363,424 7,301,557 7,185,143
Number of Common Stockholders (Year End) 5,678 6,328 6,868 7,734 8,250 7,705
Basic Earnings (Loss) Per Common Share $2.35 $1.39 ($0.24) $1.33 $0.36 $0.84
Diluted Earnings (Loss) Per Common Share $2.08 $1.33 ($0.24) $1.33 $0.36 $0.84
Dividends Declared Per Common Share $0.45 - - $0.72 $0.87 $1.32
Book Value Per Common Share $18.02 $16.14 $14.47 $14.71 $14.13 $14.71
Return on Common Equity 13.81% 9.11% (1.64)% 9.09% 2.51% 5.55%
Ratio of AFDC to Common Stock Earnings (4)% 11% (48)% 12% 48% 45%
Ratio of Earnings to Fixed Charges 2.25% 1.59% 0.86% 1.50% 1.14% 1.49%
Payout Ratio 26% -% -% 54% 242% 157%
Percentage of Construction Expenditures
Funded Internally 100% 100% 100% 100% 86% 72%
========= ========= ========= ========= ========= =========
Residential Customer Data
Average Number of Customers 91,726 90,888 90,433 89,769 86,194 85,041
Kilowatt-Hours per Customer 5,817 5,753 5,896 5,976 5,953 6,073
Revenue per Customer $799.16 $785.54 $746.76 $744.19 $766.42 $752.67
Revenue per Kilowatt-Hour in Cents 13.74 13.65 12.67 12.45 12.88 12.39
========= ========= ========= ========= ========= =========
Miscellaneous System Data
Net System Capability at Time of Peak
(MW) Firm* 273.72 381.54 344.44 373.04 330.01 340.45
System Peak Demand (MW) 293.08 281.63 277.06 274.32 267.98 275.84
Reserve Margin at Time of Peak** (6.6)% 35.5% 24.3% 36.0% 23.2% 23.4%
System Load Factor 74.5% 75.4% 79.5% 77.0% 79.9% 73.5%
========= ========= ========= ========= ========= =========
* The net system capability was reduced in 1999 as a result of the
generation asset sale.
** While the reserve margin at time of peak in 1999 was negative,
the system requirements were met through spot market purchases.
Item 7
MANAGEMENT'S DISCUSSION AND ANALYSIS
OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION
------------------------------------------------
Recent Events Affecting the Electric Utlility Industry and the Company
- ----------------------------------------------------------------------
Industry Restructuring - As discussed in the 1998 Form 10-K, in 1997,
the Maine Legislation 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 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, in 1999 the
Company completed transactions to sell most of its generation
related assets to PP&L Global (PP&L).
(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. There is currently activity within
the legislature to extend the date one year to March 1, 2003 and
limit the scope of the competitive billing and metering services
to only the largest industrial customers. If such a change is
enacted, the implementation of competitive billing and metering
would not have a significant impact on the Company or its
operations.
(4) The Company will continue to provide transmission and
distribution (T&D) services which will be subject to continued
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, is 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 and except as it is required to
provide standard offer service discussed below, 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 Compa-
ny'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 have been devoted to
facilitating the implementation of the restructur-ing law. Many of
the Company's basic business processes are being adapted to meet the
requirements of the changed business environment. In addition, the
MPUC has decided upon 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.
Current Rate Proceedings - The Company has been involved in rate
proceedings with the MPUC since mid-1998 to determine its
revenue requirement as a T&D utility starting March 1, 2000 and the
recoverability of the Company's stranded costs. In February 2000,
the Company received a final rate order from the MPUC setting its
T&D and stranded cost rates effective March 1, 2000. The Company's
total annual revenue requirement as set in the rate proceedings,
including $40 million associated with stranded cost recovery,
amounted to $ 103.2 million. The stranded cost recovery includes the
decommissioning and other plant closure expenses for Maine Yankee.
There were no write-offs of previously deferred costs based on the
final rate order.
In Maine, stranded costs are treated in the same manner as most
other costs and may be included in calculations for prospective rate
changes. Absent any rate proceedings, however, in 2003 and every
three years thereafter until the stranded costs are recovered, the
MPUC shall review and reevaluate the stranded cost recovery.
Customers reducing or eliminating their consumption of electricity
by switching to self-generation, conversion to alternative fuels or
utilizing demand-side management measures cannot be assessed exit or
entry fees.
Sale of Company's Generating Assets - On May 27, 1999, the Company
completed most of the transaction for the sale of its electric
generating assets and certain transmission rights to PP&L. The
purchase price for the assets transferred was $79 million.
The sale involved all but one of the Company's hydroelectric plants
on the Penobscot, Piscataquis, and Union rivers and Bangor Hydro's
8.33% ownership interest in the Wyman Unit #4 oil-fired plant in
Yarmouth, Maine-a total base load capacity of 83 megawatts. The
sale also involved a transfer by the Company of rights to transmit
power over the Maine Electric Power Company (MEPCO) transmission
facilities connecting the New England Power Pool (NEPOOL) to New
Brunswick Canada; the Company's rights as a participant in the
regional utilities' agreement with Hydro-Quebec pursuant to an
agency agreement; and the Company's rights to develop a second high
voltage transmission line that will connect NEPOOL to New Brunswick,
Canada.
As discussed in the 1998 Form 10-K, the Company and other Maine
utilities were required to sell their generation assets as a result
of the comprehensive electric utility industry restructuring law
adopted in Maine in 1997. The Company conducted an auction in 1998,
which led to the signing of a purchase and sale agreement with PP&L
in late September 1998. The purchase and sale agreement also
included the Company's 50% interest in the 13 megawatt West Enfield
hydro station on the Penobscot River. In late July 1999, the Company
received $10 million in proceeds from the transfer of the economic
interest in that project, and in late August 1999, the MPUC approved
the sale to PP&L of Penobscot Hydro Company, Inc. (Penobscot Hydro),
the Company's wholly-owned subsidiary which held the 50% interest in
the West Enfield hydro station. The Company has utilized a
significant portion of the net proceeds of the sale to reduce
outstanding debt and preferred stock.
The Company realized a net gain on the sale to PP&L of approximately
$24.8 million, and $24.3 million of this amount has been recorded as
a deferred liability at December 31, 1999 on the Consolidated
Balance Sheets. Included in the determination of the deferred gain
on sale is the accrual of carrying costs on the deferred gain
balance, the selling and closing costs associated with the asset
sale, the costs incurred related to the early retirement of debt and
preferred stock through the utilization of asset sale proceeds,
income tax expense impacts associated with the asset sale gain, and
the net expense associated with the sale of its generating assets
and the simultaneous purchased power buyback agreement with PP&L
(see below for a discussion of the net expense). As specified in the
previously discussed rate order from the MPUC, the deferred gain
will be utilized over a 70 month period to reduce electric rates
effective March 1, 2000. As discussed in Note 6, the other $.5
million of the gain on the sale of Penobscot Hydro, that is
allocable to shareholders pursuant to orders of the MPUC, has been
recorded as other income in 1999.
As discussed in the 1998 Form 10-K, 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 Company
realized a net gain from the sale of $5.1 million, which has been
recorded as a deferred liability at December 31, 1999. Included in
the determination of this deferred gain is the accrual of carrying
costs on the deferred gain balance, the selling and closing costs
associated with the asset sale, and the net savings associated with
the sale of these assets (through reduced depreciation and property
tax expense, and the return on these assets included in the
Company's rates through March 1, 2000). Consistent with the deferred
gain on sale of generating assets discussed above, this $5.1 million
gain will also be utilized to reduce electric rates starting March
1, 2000.
As discussed above, as a result of the sale of the Company's
generation assets, the Company was required by the MPUC to defer all
savings, for the period from the asset sale through February 29,
2000, associated with the sale of its generating assets and the
simultaneous purchased power buyback agreement with PP&L. This
included savings associated with the Casco Bay Energy sale in
September 1998. Any net savings or expense for this period are to be
flowed-back to/recovered from customers effective with new rates on
March 1, 2000. As of December 31, 1999 the net expense recorded as a
reduction of the deferred asset sale gain amounted to approximately
$225,000. The reason for the net expense is due principally to
unusually high purchased power costs during hot weather in early
June and in July 1999 to replace generation lost from the asset sale
to PP&L. Since these high costs would not have occurred if the
Company had not sold these assets, the Company has recorded the net
expense as a reduction of the deferred asset sale gain.
Alternative Rate Plan Filing - In May 1999, the MPUC approved a
portion of the Company's February 1999 request for rate adjustment
under the so-called Alternative Rate Plan or ARP. Pursuant to the
MPUC Order, the Company implemented an increase in its standard
tariff of about 1.36% effective June 1, 1999. An ARP is a method of
utility regulation intended to replace the costly, controversial
periodic rate increase proceedings of the past. Under such a plan,
utilities are permitted to adjust rates annually based on a formula
tied to inflation minus a "productivity factor". Adjustments for
certain specified categories of costs that are unrelated to
inflation are also permitted. The MPUC implemented this plan for the
Company in 1998.
The 1999 increase was comprised entirely of the recovery of some of
the specified categories of costs that are unrelated to inflation.
This was made up mostly of the recovery of a portion (about $1.4
million, or about 25%) of the costs incurred in connection with the
1998 ice storm. The inflation component actually contributed to a
reduction of the 1999 adjustment because the productivity factor
offset of 1.2% exceeded the inflation rate of .9%. The ARP will not
be in effect with the implementation of new rates on March 1, 2000,
and the Company is uncertain if any alternative rate plan will be
adopted in the future.
Deferral of Restructuring Related Costs - Also as part of the
restructuring law, employees, other than officers, displaced as a
result of retail competition are entitled to certain severance
benefits and retraining programs, and these costs are recoverable
through charges collected by the regulated distribution company. In
connection with this part of the law, the Company incurred
approximately $840,000 in benefit costs associated with the
employees terminated as a result of the generation asset sale. This
amount has been deferred as a component of Other Regulatory Assets
on the Consolidated Balance Sheets as of December 31, 1999. In 1999,
the Company has also been incurring significant costs in connection
with implementing various aspects of the electric industry
restructuring. Consequently, the Company filed an accounting order
request with the MPUC in 1999 to seek the deferral of certain
incremental costs associated with this effort. In September 1999 the
Company received an accounting order from the MPUC related to the
Company's request which approved the deferral of certain incremental
restructuring related costs. In connection with the accounting
order, the Company has deferred, as a component of Other Regulatory
Assets on the Consolidated Balance Sheets as of December 31, 1999,
approximately $829,000 of restructuring costs. As a result of the
current rate order received from the MPUC, the Company will start
recovery of the deferred restructuring costs discussed above,
amounting to $1.7 million, on March 1, 2000 over a three-year
period. Based on the accounting order, the Company will also defer,
for future recovery, certain additional incremental restructuring
costs incurred from January 1, 2000 through the advent of retail
competition on March 1, 2000.
Standard Offer Service - The restructuring law also provided for a
standard-offer service being available for all customers who do not
choose to purchase energy from a competitive supplier starting March
1, 2000. The MPUC solicited bids from competitive energy suppliers
to provide energy under the standard offer service, but all bids
were rejected as too high. Consequently, as permitted by the Maine
legislature, the MPUC has ordered the Company to assume the
responsibility of being the standard offer service provider starting
March 1, 2000 for a one-year period. The MPUC has established the
schedule of rates that the Company may charge for the standard offer
service. The Company must purchase the energy for these customers
from third parties, and the MPUC has allowed the Company to defer
the difference between the revenues realized from the standard offer
sales and the costs incurred to provide this service. This deferred
amount will be recovered from/returned to customers in a future rate
proceeding.
Bangor Gas Joint Venture-In 1998 the Company formed Penobscot Gas,
whose sole function was to be a 50% general partner in Bangor Gas
Company, LLC (Bangor Gas), which is constructing a natural gas
distribution system in the greater Bangor, Maine area. Sempra
Energy, a joint venture of Pacific Enterprises and Enova
Corporation, owns the other 50% interest in Bangor Gas. Gas service
to Maine has become feasible for the first time because of the
development of the Maritimes & Northeast Pipeline Project, extending
from the Sable Offshore Energy Project near Sable Island, Nova
Scotia, through the state of Maine and interconnecting with the
Tennessee Gas Pipeline in Dracut, Mass-achusetts. The pipeline
passes near the Bangor area. As the restructuring of the electric
industry in Maine has developed, the Company has become increasingly
cognizant of the need to focus on its core electric transmission and
distribution business. Consequently the Company has determined that
it no longer intends to participate in the Bangor Gas joint venture
and intends to sell its joint venture interest. Penobscot Gas'
investment in Bangor Gas as of December 31, 1999 is approximately
$328,000 and is recorded as an Other Investment on the Consolidated
Balance Sheets. Management is currently unable to predict the
financial statement impact of this decision.
Common Stock Dividends-At a regularly scheduled board of directors
meeting held on June 16, 1999, the board of directors of the
Company declared a cash dividend on its common stock of $.15 per
share, payable July 20, 1999 to shareholders of record on
June 30, 1999. This was the first common stock dividend since the
Company's board of directors voted not to declare a common dividend
payments in March 1997 due to financial difficulties triggered by
problems at the Maine Yankee nuclear generating plant. The Company
has a 7% ownership interest in Maine Yankee, which was permanently
shut down later in 1997 and is now in the process of being
decommissioned. As a result of regulatory orders from the MPUC that
provide certainty about Maine Yankee cost recovery, the Company's
financial position became more secure. The Company also declared
cash dividends on its common stock of $.15 per share at the end
of each of the third and fourth quarters of 1999. Prior to the March
1997 vote, the Company had been paying quarterly dividends on its
common stock of $.18 per share.
The Year 2000 Issue-The Company has successfully transitioned into
the Year 2000 (Y2K) without experiencing any material technological
problems. All of the Company's electrical equipment and computer
systems continue to function normally as the Company continues to
monitor these systems for any abnormalities. The Company experienced
minor problems which were quickly identified and corrected. These
anomalies did not harm the Company's systems or data and did not
have any significant impact on operations or customers.
The successful rollover to the year 2000 was due, in large part, to
the Company establishing a structured approach in connection with
its Y2K compliance activities. The Company inventoried and
prioritized its mission critical systems which included:
- The entire electrical transmission and distribution system,
- Telecommunications systems (phone and radio),
- Computer networks including division offices,
- Customer Information System (outage processing),
- Geographical Information System, and
- Key facilities devices (generators and uninterrupted power supply
systems).
The Company attained its goal of inventorying and prioritizing and
completed testing of the systems and devices that support its
mission critical operations as of June 30, 1999.
The Company also identified and contacted the third parties with
which it has a material relationship in order to establish
their Y2K status. The Company will continue to monitor these
relationships to ensure that key third parties are able to continue
their expected level of services.
The Company will continue to assess its systems and have contingency
plans in place as part of normal operations to deal with any
potential problems. With the assessment, testing, and transition
into the year 2000 complete, the Company believes that the
probability of encountering problems of a material nature with its
systems or the systems of a third party has been substantially
reduced.
Through December 31, 1999, the cost to conduct testing, develop and
modify contingency plans, and replace non-compliant technologies was
approximately $1.8 million, which included both internal and
external costs. Approximately $1 million of such expenditures were
charged to expense, and the remaining $700,000 of costs were
capitalized, since the costs related principally to investments in
new equipment and technologies and not the modification of existing
systems. During 1999, approximately $1.3 million was expended in
connection with the Y2K, of which $400,000 was capitalized and
$900,000 charged to expense. The Company charged approximately
$100,000 to expense in January 2000 in connection with Y2K
activities.
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, relationships with lenders, earnings
retention and dividend payout policies, electric utility
restructuring, developments in the legislative, regulatory and
competitive environments in which the Company operates and other
circumstances that could affect revenues and costs.
Liquidity, Capital Requirements, and Capital Resources
- ------------------------------------------------------
The Consolidated Statements of Cash Flows reflect events for the
years ended December 1999, 1998 and 1997 as they affect the
Company's liquidity. Net cash provided by operations was $47.4
million in 1999, $30.9 million in 1998, and $36.4 million in 1997.
Positively impacting cash flows from operating activities in the
1999 period as compared to 1998 were the beneficial impacts of the
5.83% and 1.36% rate increases effective February 13, 1998 and June
1, 1999, respectively, $1.8 million received from the federal
government in connection with service restoration costs associated
with the major ice storm in January 1998 (see Note 11), a $1.75
million payment received in the first quarter of 1999 related to a
terminated purchased power contract (see Note 6), a $2.9 million
reduction in deferred Maine Yankee incremental costs in the 1999
period as compared to 1998, and a reduction in the Company's
interest payments of $2.9 million in the 1999 period due principally
to the long-term debt principal payments and reduction in borrowings
on the Company's revolving credit facility in 1999. In addition, in
the 1998 period, cash flows were reduced by $7.7 million in payments
associated with restructuring the Penobscot Energy Recovery Company
(PERC) purchased power contract as compared to $1.1 million in such
payments in 1999 (see Note 6), were reduced by a $1.3 million due to
the effect of a large customer who prepaid its electric usage for a
one-year period in the third quarter of 1997, and were reduced by
$4.2 million because of incremental costs incurred in 1998 in
connection with the previously discussed ice storm.
Offsetting the previously discussed cash flow enhancements in 1999
as compared to 1998 were an $8.2 million increase in state and
federal income tax payments as a result of the gain on sale of
generating assets for income tax purposes. In 1999 the Company
recorded $5.3 million in cost deferrals associated with its
generation asset sale as compared to $2.3 million of such costs in
1998 (see Note 10). The generation asset sale cost deferrals include
the selling and closing costs associated with the sale, the costs
incurred for the early retirement of long-term debt and preferred
stock through the utilization of asset sale proceeds, income tax
expense impacts associated with the asset sale gain, and the net
expense associated with the sale of the generating assets and the
simultaneous purchased power buyback agreement with PP&L. Also in
1999, the Company paid $3.3 million to holders of the PERC warrants
in lieu of issuing shares of common stock (see Note 6).
Negatively impacting cash flows from operations in the 1998 period
as compared to 1997 were the approximately $7.7 million in
costs incurred to restructure the PERC purchased power contract, the
$4.2 million in incremental costs incurred in connection with the
January 1998 ice storm, as well as the $2.3 million in deferred
costs incurred to sell the Company's generation assets. Cash flows
were also reduced by the effect of the large customer, which 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
were 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.
Over the last three years, capital expenditures have been $20.3
million in 1999, $18.2 million in 1998 and $17.5 million in 1997. In
1999, approximately $8 million of the capital expenditures were
related to the Company's electric distribution system, $5.6 million
was associated with the electric transmission system and certain
fiber optic equipment, $3.2 million was expended in connection with
Y2K compliance and restructuring related activities, and the
remainder related to other general property and equipment, software,
and internal combustion facilities. In 1998, approximately $2.6
million of the capital expenditures were related to implementing new
geographic and financial information systems, $.9 million were
related to the Company's power production facilities, $7.3 million
were for its distribution system, and $6.2 million were 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 expen-
ditures to total between $40 and $50 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.
As previously discussed, the Company received approximately $79.6
million in proceeds related to its generation asset sale in late May
1999 and an additional $10 million in late July 1999 in connection
with the sale of Penobscot Hydro.
Also impacting cash flows from operations were the previously
discussed Graham Station property sale proceeds. The full $6.2
million in sales proceeds were required to be deposited with a third
party trustee in September 1998. In January 1999 the trustee
released the $6.2 million to the Company, and the funds were
utilized to repay outstanding medium term notes.
The reduction in preferred dividends in 1999 as compared to 1998
resulted from the $1.5 million sinking fund payment made on the
Company's 8.76% mandatory redeemable preferred stock in December
1998 and the final redemption of the remaining outstanding preferred
stock in October 1999. The reduction in preferred dividends paid in
1998 as compared to 1997 resulted from a $1.5 million sinking fund
payments made on the 8.76% preferred stock in December 1997.
As previously discussed, the Company reinstated its common stock
dividend in the second quarter of 1999, resulting in the increase in
dividends on common stock in the 1999 period. No common dividends
were paid in 1998, while in 1997 no common dividends were paid after
the first quarter.
In 1999 the Company made $85.8 million in repayments on long-term
debt. The increase in repayments in 1999 was due principally to the
utilization of generation asset sale proceeds. The Company made $3.7
million in principal repayments on the Company's 12.25% first
mortgage bonds (which were fully repaid in August 1999); a $13.1
million principal payment at the end of June 1999 on the Finance
Authority of Maine Revenue Notes; $4.7 million in payments on the
$24.8 million medium term notes; principal repayments of $6.2
million and $38.8 million in January and June 1999, respectively, on
the $45 million medium term notes which were issued on June 29,
1998; the full redemption of $15 million in outstanding 10.25%
series first mortgage bonds in early July 1999; and the redemption
of $4.2 million in outstanding variable rate Pollution Control
Revenue Bonds in early September 1999.
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 Power Corp. (UNITIL) contract
monetization (see Note 4).
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. Also, in
June 1998 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 1999, through the use of generation asset sale proceeds, the
Company redeemed the remaining outstanding 90,000 shares of its
8.76% mandatory redeemable preferred stock amounting to $9 million.
As discussed in more detail in Note 3 to the Consolidated Financial
Statements, the Company also made approximately $563,000 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. Of this amount approximately $320,000 was
recorded as a reduction of the deferred asset sale gain, while
approximately $243,000 was recorded as a reduction in the 8.76%
preferred stock balance. In each of 1998 and 1997 the Company made
sinking fund payment of $1.5 million on this preferred stock and
$94,000 in make whole provision payments.
Capital and operating needs in 1999, 1998 and 1997 were met through
internally generated funds, the Company's revolving credit line,
generation asset sale proceeds in 1999, and, for 1998, the new
medium term notes. As a result of the Amended and Restated
Revolving Credit and Term Loan Agreement in 1998, these facilities
should provide adequate borrowing capacity for the Company's
operation, maintenance and construction funding requirements.
The Company has approximately $133 million of first mortgage bonds
and other long-term debt maturities in the period 2000-2004.
Results of Operations
- ---------------------
Earnings - Basic earnings (loss) per common share were $2.35, $1.39,
and $(.24), for the years ended 1999, 1998 and 1997, respectively.
Earned return on average common equity was 13.8% in 1999 and 9.1% in
1998.
Results for 1999 compared favorably to those in 1998 in part because
of several one-time benefits to earnings (of approximately $.52 per
common share net of income taxes). The largest of these was a $1.5
million income tax benefit recorded in the fourth quarter of 1999
(approximately $.20 per common share) from the flow through of
unamortized deferred investment tax credits and excess deferred
income taxes associated with the 1999 sale of the Company's
generation assets. Other one-time items for 1999 include a gain on
the sale of a subsidiary as part of the mandatory divestiture of
generation assets (approximately $.04 per common share after taxes)
recorded in the third quarter of 1999. In the second quarter the
Company recorded a one-time benefit of $896,000 ($.07 per common
share after taxes) because of the settlement of a dispute related to
the NEPOOL transmission rates, and in the first quarter the Company
recorded a one-time benefit of $802,000 ($.07 per common share after
taxes) due to the settlement, by the NEPOOL, of a contract dispute
with Hydro-Quebec. Finally, in 1999 the Company participated in a
major construction project for a third party unrelated to its core
utility business. This activity, now completed, allowed the Company
to charge some of its fixed costs directly to that third party and
resulted in a benefit to 1999 earnings of $.14 per share after
taxes.
Aside from the above mentioned benefits, improvement in 1999
earnings is also attributable to improved energy sales and to the
fact that the February 1998 rate increase authorized by the MPUC was
in effect for the entire year.
The improvement in 1998 earnings as compared to 1997 was
attributable largely to the February 1998 rate increase, as well as
increased costs incurred in 1997 related to the shutdowns of the
Maine Yankee nuclear power plant (see Note 6).
Revenues - Electric operating revenue for 1999 increased by $2.9
million as compared to 1998 due principally to the impact of the
previously discussed rate increases on February 13, 1998 and on June
1, 1999, and an overall 2.7% increase in kilowatt-hour (KWH) sales
(excluding off-system sales, which are sales related to power pool
and interconnection agreements and resales of purchased power) in
the 1999 period. The increase in KWH sales in 1999 was affected by
service interruptions during the ice storm in January 1998,
slightly colder weather in the winter and spring of 1999, and warmer
weather during the summer months of 1999 as compared to 1998. The
increased revenues were offset by a $1.7 million reduction in
off-system sales in the 1999 period and a $1.8 million reduction in
revenue sharing from the Company's largest industrial customer.
Electric operating revenue for 1998 increased by $7.8 million as
compared to 1997 principally due to a 3.8% temporary rate increase
effective on July 1, 1997 and the additional 5.83% rate increase
effective February 1998. Also benefiting 1998 revenues was a $1
million increase in off-system sales. Offsetting these positive
factors somewhat was a 3.4% reduction in total 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.
Expenses - Fuel for generation and purchased power expense decreased
$1.3 million in 1999 as compared to 1998. The decreased expense
was a result of several factors. The previously discussed
settlements of the disputes with Hydro-Quebec and NEPOOL resulted in
$747,000 and $896,000 reductions in expense, respectively in 1999.
The Company recorded a benefit of $2.9 million in 1999 as compared
to $2 million for 1998 related to savings realized from the
restructuring of the PERC purchased power contract in June 1998. The
$1.7 million reduction in off-system sales in 1999 also impacted the
decrease in fuel and purchased power expense.
Excluding the impact of the unusually high replacement power costs
incurred in June 1999, which are discussed below, there was a
reduction in oil-related and other purchased power costs in the 1999
period as compared to 1998. A significant portion of the Company's
power contracts are directly tied to the price of residual oil,
which was 34% higher in 1999 as compared to 1998. However, the
Company had hedged these purchases through its fuel risk management
program with a fixed price about 13% lower in 1999 compared to 1998
(see Note 13 for a discussion of the Company's fuel risk management
program). As a result, the Company received approximately $1.8
million in hedge settlements in 1999 as compared to paying out $5.1
million in hedge settlements in 1998. Any hedge settlement
receipts/payments offset corresponding increases/decreases in
purchased power costs. Also, prior to the generation asset sale at
the end of May 1999, purchased power expenses were reduced by an
increase in power generation by the Company's hydroelectric
facilities.
Purchased power expenses increased by about $3.2 million in the 1999
period due to the May 27th sale of the Company's hydroelectric
facilities and subsequent buyback contract with PP&L for the power
from the plants. Incremental replacement power costs for other
entitlements in Wyman #4, Hydro-Quebec and MEPCO transmission were
$3.6 million greater than the comparable 1998 expense. June 1999
replacement power costs were extremely high due to very unusual
circumstances in NEPOOL, with record-breaking loads while many
generators were still out of service on spring maintenance. Further,
the NEPOOL new market rules resulted in on-peak power prices that
were two to three times as great as would normally occur during
June.
Fuel for generation and purchased power expense decreased by $10.8
million in 1998 as compared to 1997. The prin-cipal 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 February 1998 rate
order (see the 1998 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 Com-
pany 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 in 1997 as compared to negative cash settlements in 1998.
This change was 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 fact that 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 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.
Other operation and maintenance (O&M) expense increased by $2
million in 1999 as compared to 1998. Increasing other O&M expense in
1999 was a $1.7 million increase in postretirement and active
medical costs (due principally to higher medical claims costs) and
pension expense; the Company incurred approximately $826,000 of
additional incremental non-labor expenditures in 1999 as compared to
1998 related to electric utility industry restructuring activities
(net of the previously discussed deferral in 1999), costs associated
with Y2K compliance, and an upgrade to the Company's customer
information system; the Company recorded $671,000 of amortization
expense associated with deferred ice storm costs for the period from
June 1 through December 31, 1999; the Company incurred $497,000 in
additional employee incentive bonus expense in 1999 as a result of
attaining a greater level of targeted goals in 1999, and the Company
incurred approximately $410,000 in increased outside legal services
expense in 1999 as compared to 1998, with much of the increase
attributable to Federal Energy Regulatory Commission and NEPOOL
issues.
Offsetting the increases in other O&M expense to some extent was a
$1.7 million increase in overhead expenses allocated to capital
projects in 1999 as compared to 1998. This increase was principally
a result of major construction activ-ities being performed by the
Company in connection with the Maine Independence Station, a new 520
megawatt gas fired generation facility in Veazie, Maine, coming
online and connecting to the regional transmission power grid. The
Company was reimbursed by the owner of the facility for the
construction costs incurred, including overheads. Also,in 1999
there was a $730,000 reduction in hydroelectric and Wyman #4 non-
labor O&M expenses as a result of the generation asset sale in late
May 1999.
Other O&M expense increased by $2 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 $1.7 million in 1999
as compared to 1998 due principally to the sale of the Company's
generation assets in May 1999. This reduction was offset somewhat by
the impact of 1999 property additions.
Depreciation and amortization expense decreased $438,000 in 1998 as
compared to 1997. Effective February 1998, in connection with
the Company's 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 Company's expenses over the period 1997-1999 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 amor-tizations 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 to collect these amounts 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 to be returned to the level before 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 $2.8 million in 1999, $2.9 million in 1998 and
$6.1 million in 1997.
The approximately $170 million of costs associated with the 1995
purchased power contract buy-back were deferred and recorded as a
regulatory asset, to be amortized and collected over a ten-year
period, beginning July 1, 1995. Amor-tization expense related to
this contract buyout amounted to $17 million in each of 1999, 1998
and 1997.
Also impacting amortization of contract buyouts and restructuring
was the start of the amortization of the deferred PERC contract
restructuring costs (see Note 6) on July 1, 1998, resulting in $1
million of amortization expense in 1999 and $500,000 in 1998.
The decrease in property and other taxes in 1999 was due principally
to reductions in property taxes as a result of the sale of the
Company's generation assets. This reduction in property taxes was
offset to some extent by increased electric plant additions in 1999.
Property and other taxes were greater in 1998 due to increases in
property taxes, as a result of increases in property levels and
property tax rates, and due to the previously mentioned increase in
O&M labor costs in 1998, associated payroll taxes increased in 1998.
The increases in income taxes in each of 1998 and 1999 were due
principally to greater earnings in each year. See Note 2 to the
Consolidated Financial Statements for a reconciliation of the
Company's effective income tax rate for each year.
Other Income and (Deductions) and Interest Expense - Allowance for
funds used during construction (AFDC) decreased $1.7 million in 1999
relative to 1998 due principally to $1.8 million in carrying costs
being recorded on the previously discussed deferred asset sale gain.
The increase in AFDC in 1998 as compared to 1997 was due primarily
to recording carrying costs on deferred ice storm and incremental
Maine Yankee related costs. AFDC related to construction work in
progress was lower in 1998 due to reduced construction activity.
The $2.3 million increase in other income in 1999 was principally a
result of the previously discussed $1.5 million income tax benefit
associated with the flow-through of unamortized investment tax
credits and excess deferred income taxes related to
generation assets sold to PP&L in May 1999; the Company recognized
$.5 million in other income as a result of the previously discussed
gain on sale of Penobscot Hydro; and the Company earned
approximately $756,000 in interest income realized from invested
generation asset sale proceeds.
The decrease in other income in 1998 as compared to 1997 was due
primarily to the write-off of costs associated with non-core
business ventures by the Company.
Long-term debt interest expense decreased $3.9 million in 1999 as
compared to 1998 as a result of the previously discussed principal
repayments in 1998 and 1999 on various long-term debt issues.
The $268,000 increase in long-term debt interest expense in 1998 was
due primarily to the previously discussed issuance of the $24.8
million of medium term notes on March 31, 1998 and the $45 million
term loan issued in June 1998, offset by the previously discussed
principal repayments in 1997 and 1998 on various long-term debt
issues.
Other interest expense decreased $1.4 million due principally to a
$20 million reduction in weighted average short-term borrowings
outstanding in 1999 as compared to 1998. The Company fully repaid
the outstanding balance under its revolving credit line in April
1999, and no new borrowings have subsequently occurred.
Other interest expense decreased in 1998 due principally to a $10.9
million reduction in the weighted average short-term borrowings in
1998 as compared to 1997, as well as a slight decrease in the
weighted average interest rate (including fees) on the borrowings.
These decreases were offset to some extent by a $337,000 increase in
the amortization of debt issuance costs in 1998.
Contingencies and Risk Management
- ---------------------------------
Environmental Matters-In 1992, the Company received notice from the
Maine Department of Environmental Protection that it was
investigating the cleanup of several sites in Maine that were used
in the past for the disposal of waste oil and other hazardous
substances, and that the Company, as a generator of waste oil that
was disposed at those sites, may be liable for certain cleanup
costs. The Company learned in October 1995 that the United States
Environmental Protection Agency placed one of those sites on the
National Priorities List under the Comprehensive Environmental
Response, Compensation, and Liability Act and will pursue
potentially responsible parties. With respect to this site, the
Company is one of a number of waste generators under investigation.
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 this waste
disposal site. 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, 1999, the liability recorded by the Company for its
estimated environmental remediation costs amounted to $331,000. The
Company's actual future environmental remediation costs may be
higher as additional factors become known.
Risk Management - The Company's major financial market risk exposures
are changing interest rates and changes in purchased energy prices.
Changing interest rates will affect interest paid on variable rate
debt and the fair value of fixed rate debt. The Company manages
interest rate risk through a combination of both fixed and variable
rate debt instruments and derivative financial instruments,
including an interest rate swap (see Notes 4 and 13). The Company
managed purchased energy price risk through the use of swaps (see
Note 13). The Company does not hold or issue derivatives for trading
purposes.
New Accounting Pronouncement
- ----------------------------
In May 1999, the Financial Accounting Standards Board voted to delay
for one year the effective date of Statement of Financial Accounting
Standards No. 133, "Accounting for Derivative Instruments and
Hedging Activities" (SFAS 133). The new effective date for
implementing this pronouncement is for fiscal years beginning after
June 15, 2000. The effects of the adoption on the Company's
financial statements are currently not known. The Company's fuel
hedge risk management program expires in February 2000, but the
Company believes its interest rate swap agreement will qualify for
hedge accounting treatment under SFAS 133.
Item 8 Financial Statements & Supplementary Data
BANGOR HYDRO-ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF INCOME
For the Years Ended December 31, 1999 1998 1997
- --------------------------------------------------------------------------- ------------ ------------ ------------
Electric Operating Revenue (Note 1): $197,994,796 $195,144,007 $187,324,379
------------ ------------ ------------
Operating Expenses:
Fuel for generation and purchased power (Notes 1 and 3) $80,748,385 $82,026,860 $ 92,791,842
Other operation and maintenance (Notes 1 and 5) 36,491,666 34,448,324 32,471,149
Depreciation and amortization (Note 1) 8,063,939 9,749,229 10,187,102
Amortization of Seabrook Nuclear Project (Note 7) 1,699,050 1,699,050 1,699,050
Amortization of contract buyouts and restructuring (Note 6) 20,801,816 20,442,441 23,218,500
Taxes-
Local property and other 5,059,140 5,549,049 5,124,146
Income (Note 2) 8,973,166 6,093,286 (1,956,303)
------------ ------------ ------------
$161,837,162 $160,008,239 $163,535,486
------------ ------------ ------------
Operating Income $36,157,634 $35,135,768 $23,788,893
Other Income And (Deductions):
Allowance for equity funds used during construction (Note 1) (326,026) 430,028 285,972
Other, net of applicable income taxes (Notes 1 and 2) 3,132,097 862,723 1,005,849
------------ ------------ ------------
Income Before Interest Expense $38,963,705 $36,428,519 $25,080,714
------------ ------------ ------------
Interest Expense:
Long-term debt (Notes 4 and 13) $19,004,624 $22,906,021 $22,638,201
Other (Note 4) 1,393,547 2,750,863 3,392,169
Allowance for borrowed funds used during construction (Note 1) 284,933 (693,682) (562,966)
------------ ------------ ------------
$20,683,104 $24,963,202 $25,467,404
------------ ------------ ------------
Net Income (Loss) $18,280,601 $11,465,317 ($386,690)
Dividends On Preferred Stock (Note 3) 945,396 1,244,488 1,375,888
------------ ------------ ------------
Earnings (Loss) Applicable To Common Stock $17,335,205 $10,220,829 ($1,762,578)
------------ ------------ ------------
Earnings (Loss) Per Common Share, based on the weighted average
number of shares outstanding of 7,363,424 in 1999, 1998 and 1997 (Note 3):
Basic $2.35 $1.39 ($0.24)
Diluted 2.08 1.33 (0.24)
------------ ------------ ------------
Dividends Declared Per Common Share $0.45 - -
------------ ------------ ------------
The accompanying notes are an integral part of these consolidated financial statements.
BANGOR HYDRO-ELECTRIC COMPANY
CONSOLIDATED BALANCE SHEETS
December 31, 1999 1998
- ------------------------------------------------------------------------------- ------------ ------------
Assets
Investment In Utility Plant:
Electric plant in service, at original cost (Notes 6, 10 and 12) $306,970,789 $352,975,549
Less-Accumulated depreciation and amortization (Notes 1, 6 and 10) 84,825,432 101,633,446
------------ ------------
$222,145,357 $251,342,103
Construction work in progress (Note 1) 5,668,246 13,929,940
------------ ------------
$227,813,603 $265,272,043
Investments in corporate joint ventures (Notes 1 and 6)
Maine Yankee Atomic Power Company 5,266,697 5,438,520
Maine Electric Power Company, Inc. 529,630 438,753
------------ ------------
$233,609,930 $271,149,316
------------ ------------
Other Investments, at cost (Notes 6 and 9) $3,629,431 $5,881,986
------------ ------------
Funds held by trustee, at cost (Notes 4, 9 and 10) $22,698,843 $29,867,605
Current Assets: ------------ ------------
Cash and cash equivalents (Notes 1 and 9) $15,691,166 $2,945,946
Accounts receivable, net of reserve ($1,075,000 in 1999 and 1998) 18,269,672 17,558,084
Unbilled revenue receivable (Note 1) 14,127,645 12,086,003
Inventories, at average cost:
Materials and supplies 2,792,904 2,909,219
Fuel oil 45,310 16,233
Prepaid expenses 927,998 1,129,259
------------ ------------
Total current assets $51,854,695 $36,644,744
Regulatory Assets and Deferred Charges: ------------ ------------
Investment in Seabrook Nuclear Project, net of accumulated amortization of
$31,872,246 in 1999 and $30,173,196 in 1998 (Notes 7 and 10) $26,969,829 $28,668,879
Costs to terminate/restructure purchased power contracts, net of accumulated
amortization of $100,860,518 in 1999 and $80,058,702 in 1998 (Notes 6 and 10) 118,565,234 136,979,490
Maine Yankee decommissioning costs (Notes 6 and 10) 46,041,644 50,054,620
Other regulatory assets (Notes 2, 5, 6, 10, 11 and 12) 36,925,665 42,773,542
Other deferred charges 3,655,009 3,750,861
------------ ------------
Total deferred charges $232,157,381 $262,227,392
------------ ------------
Total Assets $543,950,280 $605,771,043
============ ============
The accompanying notes are an integral part of these consolidated financial statements.
BANGOR HYDRO-ELECTRIC COMPANY
CONSOLIDATED BALANCE SHEETS
December 31, 1999 1998
- -------------------------------------------------------------------------------------------------
Stockholders' Investment and Liabilities
Capitalization (see accompanying statement):
Common stock investment (Note 3) $132,721,895 $118,864,092
Preferred stock (Note 3) 4,734,000 4,734,000
Preferred stock subject to mandatory redemption,
exclusive of sinking fund requirements (Notes 3 and 9) - 7,604,150
Long-term debt, net of current portion (Notes 4, 9 and 13) 183,300,000 263,027,692
---------------------------
Total capitalization 320,755,895 $394,229,934
--------------------------
Current Liabilities:
Notes payable-banks (Note 4) - $12,000,000
---------------------------
Other current liabilities-
Current portion of long-term debt and sinking fund requirements
on preferred stock in 1998 (Notes 3, 4 and 9) $19,460,000 $27,109,119
Accounts payable 14,175,408 13,895,673
Dividends payable 1,170,942 294,593
Accrued interest 2,552,758 3,474,369
Customers' deposits 398,897 328,923
Current income taxes payable 4,125,696 85,685
---------------------------
Total other current liabilities $41,883,701 $45,188,362
---------------------------
Total current liabilities $41,883,701 $57,188,362
---------------------------
Commitments and Contingencies (Notes 6, 12 and 14)
Regulatory and Other Long-term Liabilities (Note 2):
Deferred income taxes-Seabrook $13,994,668 $14,880,241
Other accumulated deferred income taxes 55,826,890 63,774,505
Maine Yankee decommissioning liability (Note 6) 46,041,644 50,054,620
Deferred gain on asset sale (Note 10) 29,357,358 4,510,108
Other regulatory liabilities (Note 10) 9,872,188 9,701,375
Unamortized investment tax credits 1,591,727 1,720,708
Accrued pension and postretirement benefit costs (Note 5) 11,301,057 7,770,149
Other (Note 6 and 12) 13,325,152 1,941,041
---------------------------
Total deferred credits and reserves $181,310,684 $154,352,747
---------------------------
Total Stockholders' Investment and Liabilities $543,950,280 $605,771,043
============== ============
The accompanying notes are an integral part of these consolidated financial statements.
BANGOR HYDRO-ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF CAPITALIZATION
December 31, 1999 1998
- ----------------------------------------------------------------- --------------- ---------------
Common Stock Investment (Notes 1 and 3):
Common stock, par value $5 per share-
Authorized-10,000,000 shares
Outstanding-7,363,424 shares in 1999 and 1998 $36,817,120 $36,817,120
Amounts paid in excess of par value 58,890,342 59,054,203
Retained earnings 37,014,433 22,992,769
--------------- ---------------
Total Common Stock Investment $132,721,895 $118,864,092
--------------- ---------------
Preferred Stock, non-participating, cumulative, par value $100 per share,
authorized 600,000 shares (Note 3):
Not redeemable or redeemable solely at the option of the issuer-
7%, Noncallable, 25,000 shares authorized and outstanding $2,500,000 $2,500,000
4 1/4%, Callable at $100, 4,840 shares authorized and outstanding 484,000 484,000
4%, Series A, Callable at $110, 17,500 shares authorized and outstanding 1,750,000 1,750,000
--------------- ---------------
$4,734,000 $4,734,000
--------------- ---------------
Subject to mandatory redemption requirements-
8.76%, 150,000 shares authorized and 90,000 outstanding in 1998 - $9,198,064
Less-Sinking fund requirements - 1,593,914
--------------- ---------------
- $7,604,150
Long-Term Debt (Notes 4, 9 and 13): --------------- ---------------
First Mortgage Bonds-
10.25% Series due 2019 - $15,000,000
10.25% Series due 2020 30,000,000 30,000,000
8.98% Series due 2022 20,000,000 20,000,000
7.38% Series due 2002 20,000,000 20,000,000
7.30% Series due 2003 15,000,000 15,000,000
12.25% Series due 2001 - 3,742,897
--------------- ---------------
$85,000,000 $103,742,897
Less-Sinking fund requirements - 1,675,205
--------------- ---------------
$85,000,000 $102,067,692
--------------- ---------------
Variable rate demand pollution control revenue bonds
Series 1983 due 2009 - $4,200,000
--------------- ---------------
Other Long-Term Debt-
Finance Authority of Maine-Taxable Electric Rate Stabilization
Revenue Notes, 7.03% Series 1995A, due 2005 $100,600,000 $113,700,000
Medium Term Notes, Variable interest rate-Libo rate plus 2%, due 2000 - 45,000,000
Medium Term Notes, Variable interest rate-Libo rate plus 1.125%, due 2002 17,160,000 21,900,000
--------------- ---------------
$117,760,000 $180,600,000
Less: Current portion of other long-term debt 19,460,000 23,840,000
--------------- ---------------
$98,300,000 $156,760,000
--------------- ---------------
Total Long-Term Debt $183,300,000 $263,027,692
--------------- ---------------
Total Capitalization $320,755,895 $394,229,934
============== ==============
The accompanying notes are an integral part of these consolidated financial statements.
BANGOR HYDRO-ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 1999 1998 1997
- ----------------------------------------------------------------------------- ------------- ------------- -------------
Cash Flows From Operating Activities:
Net income (loss) $18,280,601 $11,465,317 ($386,690)
Adjustments to reconcile net income (loss) to net cash
from operating activities:
Depreciation and amortization 8,063,939 9,749,229 10,187,102
Amortization of Seabrook Nuclear Project (Note 7) 1,699,050 1,699,050 1,699,050
Amortization of costs to terminate/restructure power contracts (Note 6) 20,801,816 20,442,441 23,218,500
Other amortizations 2,590,725 2,035,505 1,784,625
Allowance for equity funds used during construction (Note 1) 326,026 (430,028) (285,972)
Deferred income tax provision and investment tax credits, net (Note 2) (131,897) 5,876,874 (1,982,823)
Flow-through of unamortized investment tax credits
and excess deferred income taxes (Note 2) (1,485,131) - -
Gain on sale of subsidiary (Note 10) (523,390) - -
Changes in assets and liabilities:
Costs to restructure purchased power contract (Note 6) (1,099,000) (7,704,185) -
Exercise of PERC warrants-cash paid in lieu of issuing shares (Note 6) (3,321,710) - -
Payment received related to terminated purchased power contract (Note 6) 1,750,000 - 1,000,000
Deferred incremental Maine Yankee costs 2,886,401 (793,608) (718,877)
Deferred incremental ice storm costs (Note 11) 1,817,851 (4,200,423) -
Deferred costs associated with generation asset sale (Note 10) (5,266,689) (2,317,688) -
Deferred revenue and Maine Yankee refueling costs - (1,285,101) 1,172,497
Accounts receivable, net and unbilled revenue (2,759,315) (1,423,947) 1,700,647
Accounts payable (11,081) 724,721 (261,642)
Accrued interest (921,611) (192,272) (52,746)
Current and deferred income taxes 3,755,913 121,153 344,790
Accrued postretirement benefit costs (Note 5) 1,608,414 600,699 547,237
Other current assets and liabilities, net (356,034) (22,036) 906,745
Other, net (345,523) (3,413,741) (2,499,289)
------------ ------------ ------------
Net Increase in Cash From Operating Activities $47,359,355 $30,931,960 $36,373,154
------------ ------------ ------------
Cash Flows From Investing Activities:
Construction expenditures ($20,323,360) ($18,240,226) ($17,525,312)
Receipt of asset sale proceeds (Note 10) 89,587,841 6,200,000 -
Release (deposit) of Graham Station property sale proceeds
held by trustee (Note 10) 6,200,000 6,200,000) -
Allowance for borrowed funds used during construction (Note 1) 284,933 (693,682) (562,966)
------------- ------------- -------------
Net Increase (Decrease) in Cash From Investing Activities $75,749,414 ($18,933,908) ($18,088,278)
------------- ------------- -------------
Cash Flows From Financing Activities:
Dividends on preferred stock ($1,127,882) ($1,216,434) ($1,349,620)
Dividends on common stock (2,209,028) - (1,325,416)
Payments on long-term debt (85,782,897) (53,478,554) (15,853,515)
Payments on mandatory redeemable preferred stock (9,243,742) (1,593,914) (1,593,915)
Issuance of long-term debt, net of capital reserve fund requirements (Note 4) - 68,300,000 -
Short-term debt, net (Note 4) (12,000,000) (22,000,000) 1,500,000
------------- ------------- -------------
Net Decrease in Cash From Financing Activities ($110,363,549) ($9,988,902) ($18,622,466)
------------- ------------- -------------
Net Increase (Decrease) in Cash and Cash Equivalents $12,745,220 $2,009,150 ($337,590)
Cash and Cash Equivalents-Beginning of Year 2,945,946 936,796 1,274,386
------------- ------------- -------------
Cash and Cash Equivalents-End of Year $15,691,166 $2,945,946 $936,796
============== ============== ==============
The accompanying notes are an integral part of these consolidated financial statements.
BANGOR HYDRO-ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF COMMON STOCK INVESTMENT
Amounts Paid
Common in Excess of Retained Total Common
Stock Par Value Earnings Stock Investment
Balance December 31, 1996 $36,817,120 $56,969,428 $14,534,518 $108,321,066
Net loss - - (386,690) (386,690)
Cash dividends declared on-
Preferred stock - - (1,314,984) (1,314,984)
Other (Note 3) - - (60,904) (60,904)
------------- ------------- ------------- -------------
Balance December 31, 1997 $36,817,120 $56,969,428 $12,771,940 $106,558,488
Net income - - 11,465,317 11,465,317
Cash dividends declared on-
Preferred stock - - (1,183,584) (1,183,584)
Issuance of warrants (Note 6) - 2,084,775 - 2,084,775
Other (Note 3) - - (60,904) (60,904)
------------- ------------- ------------- -------------
Balance December 31, 1998 $36,817,120 $59,054,203 $22,992,769 $118,864,092
Net income - - 18,280,601 18,280,601
Cash dividends declared on-
Preferred stock - - (899,718) (899,718)
Common Stock - - (3,313,541) (3,313,541)
Exercise of warrants-cash paid in lieu of issuing shares
(Note 3) - (410,052) - (410,052)
Transfer of mandatory redeemable 8.76% preferred stock
issuance costs to the deferred asset sale gain (Note 10) - 246,191 - 246,191
Other (Note 3) - - (45,678) (45,678)
------------- ------------- ------------- -------------
Balance December 31, 1999 $36,817,120 $58,890,342 $37,014,433 $132,721,895
------------- ------------- ------------- -------------
The accompanying notes are an integral part of these consolidated financial statements.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 1. Nature of Operations and Summary of Significant
Accounting Policies
- --------------------------------------------------------
Nature of Operations - Bangor Hydro-Electric Company (the
Company) is a public utility engaged in the purchase,
transmission, distribution and sale of electric energy and
other energy related services, with a service area of
approximately 5,275 square miles having a population of
approximately 192,000 people. The Company serves
approximately 107,000 customers in portions of the Maine
counties of Penobscot, Hancock, Washington, Waldo,
Piscataquis, and Aroostook. The Company's regulated
operations are subject to the regulatory authority of the
Maine Public Utilities Commission (MPUC) as to retail rates,
accounting, service standards, territory served, the issuance
of securities and other matters. The Company is also subject
to the jurisdiction of the Federal Energy Regulatory
Commission (FERC) as to certain matters, including rates for
transmission services. The Company is a member of the New
England Power Pool (NEPOOL), and is interconnected with other
New England utilities to the south and with New Brunswick
Power Corporation to the north.
Basis of Consolidation - The Consolidated Financial Statements
of the Company include its wholly- owned subsidiaries,
Penobscot Hydro Co., Inc. (PHC) for the first seven months of
1999, Bangor Var Co., Inc. (BVC), Bangor Energy Resale, Inc.
(BERI), Penobscot Natural Gas Co., Inc. (Penobscot Gas), and
CareTaker, Inc. (CareTaker). The Company sold PHC in July
1999 in connection with its asset sale to PP&L Global. See
Note 10 for a detailed discussion of this sale. The
operations of PHC consisted solely of a 50% interest in
Bangor-Pacific Hydro Associates (Bangor-Pacific), the owner
and operator of the redeveloped West Enfield hydroelectric
station. PHC accounted for its investment in Bangor-Pacific
under the equity method. BVC was incorporated in 1990 to own
the Company's 50% interest in the Chester SVC Partnership
(Chester), a partnership which owns certain facilities used
in the Hydro-Quebec Phase II transmission project in which
the Company is a participant. BVC accounts for its investment
in Chester under the equity method. BERI was formed in 1997
as a special purpose vehicle to permit Bangor Hydro's use of
a power sales agreement as collateral for a bank loan (see
Note 4 for a discussion of this financing arrangement). The
operations of Penobscot Gas consist solely of a 50% interest
in Bangor Gas Company, LLC, which is developing a natural gas
local distribution company in the greater Bangor, Maine area.
CareTaker was incorporated in 1997 and provides security
alarm services on a retail basis to residential and
commercial customers. See Note 6 for additional information
with respect to these investments, excluding CareTaker. All
significant intercompany balances and transactions have been
eliminated. The accounts of the Company are maintained in
accordance with the Uniform System of Accounts prescribed by
the regulatory bodies having jurisdiction.
Equity Method of Accounting - The Company accounts for its
investments in the common stock of Maine Yankee Atomic Power
Company (Maine Yankee) and Maine Electric Power Company, Inc.
(MEPCO) under the equity method of accounting, and records
its proportionate share of the net earnings of these
companies as a reduction of fuel for generation and purchased
power expense. See Note 6 for additional information with
respect to these investments.
Electric Operating Revenue - Electric Operating Revenue
consists primarily of amounts charged for electricity
delivered to customers during the period. The Company records
unbilled revenue, based on estimates of electric service
rendered and not billed at the end of an accounting period,
in order to match revenue with related costs.
Depreciation of Electric Plant and Maintenance Policy-
Depreciation of electric plant is provided using the
straight-line method at rates designed to allocate the
original cost of properties over their estimated service
lives. The composite depreciation rate (excluding intangible
assets), expressed as a percentage of average depreciable
plant in service, and considering the amortization of
overaccumulated depreciation (discussed below), was
approximately 2.1% in 1999, 2.5% in 1998, and 3.0% in 1997.
A study conducted as of December 31, 1996 determined that the
Company's reserve for depreciation was overaccumulated by
approximately $3.6 million. In connection with the MPUC's
rate order in February 1998, the Company was allowed to
amortize this balance over a two-year period, starting in
February 1998. The Company recorded approximately $2.4
million in amortization in 1999 and $1.6 million in 1998
which reduced depreciation expense. The 1999 amortization was
increased by approximately $400,000 due to the impact of the
sale of the Company's hydroelectric plant assets in May 1999.
The Company follows the practice of charging to maintenance
the cost of repairs, replacements and renewals of minor items
considered to be less than a unit of property. Costs of
additions, replacements and renewals of items considered to
be units of property are charged to the utility plant
accounts, and any items retired are removed from such
accounts. The original costs of units of property retired and
removal costs, less salvage, are charged to the depreciation
reserve.
Depreciation, local property taxes and other taxes not based
on income, which were charged to operating expenses, are
stated separately in the Consolidated Statements of Income.
Rents, advertising and research and development expenses are
not significant. No royalty expenses were incurred.
Maintenance expense was $9.5 million in 1999, $7.0 million in
1998 and $5.7 million in 1997.
Equity Reserve for Licensed Hydro Projects - The FERC requires
that a reserve be maintained equal to one-half of the
earnings in excess of a prescribed rate of return on the
Company's investment in licensed hydro property, beginning
with the twenty-first year of the project operation under
license. As a result of the generation asset sale (see Note
10), the Company is seeking authorization from the FERC to
reclassify the reserve for licensed hydro projects,
classified as appropriated retained earnings, to
unappropriated earnings. The Company expects to receive such
authorization from the FERC in 2000. The reserve balance at
December 31, 1999 amounted to approximately $3 million.
Allowance for Funds Used During Construction (AFDC) - In
accordance with regulatory requirements of the MPUC, the
Company capitalizes as AFDC financing costs related to
portions of its construction work in progress, at a rate
equal to its weighted cost of capital, into utility plant
with offsetting credits to other income and interest. This
cost is not an item of current cash income, but is recovered
over the service life of plant in the form of increased
revenue collected as a result of higher depreciation expense
and return. In addition, carrying costs on certain regulatory
assets and liabilities, including the deferred asset sale
gain (see Note 10), were also capitalized in 1999 and
included in AFDC in the Consolidated Statements of Income.
The average AFDC (carrying costs) rates computed by the
Company were 9.5% in 1999, 9.1% for 1998 and 8.7% in 1997.
Cash and Cash Equivalents - The Company considers all highly
liquid debt instruments purchased with an original maturity
of three months or less to be cash equivalents.
Use of Estimates - The preparation of financial statements in
conformity with generally accepted accounting
principles requires management to make estimates and
assumptions that affect the reported amounts of assets and
liabilities and disclosure of contingent liabilities at the
date of the Consolidated Financial Statements and the
reported amounts of revenues and expenses during the
reporting period. Actual results could differ from those
estimates.
Supplemental Disclosure of Cash Flow Information - Cash paid
for interest, net of amounts capitalized was approximately
$20.9 million, $23.8 million and $24.6 million in 1999, 1998
and 1997, respectively. Cash paid for income taxes was
approximately $8.9 million, $655,000 and $545,000 in 1999,
1998 and 1997, respectively. Noncash operating activity: In
1998, the Company issued common stock warrants in connection
with the Penobscot Energy Recovery Company (PERC) purchased
power contract restructuring (see Note 6), which were
recorded at a fair value of $2 million as a regulatory asset
and additional paid-in capital.
Risk Management and Derivative Financial Instruments - The
Company's major financial market risk exposures are changing
interest rates and changes in purchased energy prices.
Changing interest rates will affect interest paid on
variable rate debt and the fair value of fixed rate debt. The
Company manages interest rate risk through a combination of
both fixed and variable rate debt instruments and an interest
rate swap (see Notes 4 and 14). The Company managed purchased
energy price risk through the use of swaps (see Note 14). The
Company does not hold or issue derivatives for trading
purposes. The Company's accounting for derivatives used to
manage risk is in accordance with Statement of Financial
Accounting Standards No. 80, "Accounting for Futures
Contracts".
Reclassifications-Certain prior year amounts have been
reclassified to conform with the presentation used in the
1999 Consolidated Financial Statements.
Note 2. Income Taxes
- --------------------
The individual components of federal and state income taxes
reflected in the Consolidated Statements of Income for 1999,
1998 and 1997 are stated in the table below.
Year Ended December 31, 1999 1998 1997
- ---------------------------- ------------ ------------ ------------
Current:
Federal $7,390,387 $725,466 $524,373
State 2,314,251 195,876 141,581
------------ ------------ ------------
$9,704,638 $921,342 $665,954
------------ ------------ ------------
Deferred:
Federal-Other $89,444 $5,089,469 ($661,330)
State-Other (375,468) 1,442,801 (690,829)
Federal-Seabrook (341,917) (341,917) (341,917)
State-Seabrook (72,173) (72,173) (72,173)
------------ ------------ ------------
($700,114) $6,118,180 ($1,766,249)
------------ ------------ ------------
Investment Tax Credits, Net ($317,877) ($385,805) ($140,379)
------------ ------------ ------------
Total Provision $8,686,647 $6,653,717 ($1,240,674)
Allocated to Other Income 286,519 (560,431) (715,629)
Charged to Operating Expense $8,973,166 $6,093,286 ($1,956,303)
============ ============ ============
The table below reconciles an income tax provision (benefit),
calculated by multiplying income (loss) before federal income taxes
(as reported on the Consolidated Statements of Income) by the
statutory federal income tax rate to the federal income tax expense
(benefit) reported on the Consolidated Statements of Income. The
difference is represented by the permanent and timing differences
for which deferred taxes are not provided for ratemaking purposes.
1999 1998 1997
----------------------------------------------
(Dollars in Thousands) Amount % Amount % Amount %
- ------------------------------------------------------------------ ----------------------------------------------
Federal income tax provision at statutory rate $9,439 35.0% $6,342 35.0% ($569) 35.0%
Less (Plus) permanent differences in tax expense resulting from
statutory exclusions from taxable income:
Dividend received deduction related to earnings of associated companies 253 .9 40 .2 29 (1.8)
Equity component of AFDC 185 .7 151 .8 100 (6.2)
Amortization of equity component of AFDC on recoverable
Seabrook investment (160) (.6) (160) (.9) (160) 9.8
Other (29) (.1) (28) (.1) (80) 5.1
-------------- -------------- -------------
Federal income tax provision before effect of timing differences $9,190 34.1% $6,339 35.0% ($458) 28.1%
Less (Plus) timing differences that are flowed through for rate-
making and accounting purposes:
Amortization of debt component of AFDC and capitalized overheads
on recoverable Seabrook investment (151) (.6) (151) (.8) (151) 9.3
Book depreciation greater than tax depreciation (85) (.3) (88) (.5) (79) 4.8
Equity earnings in excess of (less than) dividends (276) (1.0) 201 1.1 217 (13.3)
State income tax liability deducted for federal income tax purposes 673 2.5 498 2.8 (186) 11.4
Reversal of excess deferred income taxes 167 .6 124 .7 173 (10.6)
Amortization of investment tax credits 350 1.3 241 1.3 217 (13.3)
Investment tax credits and excess deferred taxes flowed through 1,485 5.5 - - (184) 11.3
Other 27 .1 282 1.5 46 (2.9)
------------- --------------- --------------
Federal income tax provision $7,000 26.0% $5,232 28.9% ($511) 31.4%
============= =============== ==============
Under the federal income tax laws, the Company received
investment tax credits (ITC) on qualified property additions
through 1986. ITC utilized were deferred and are being
amortized over the life of the related property. In 1999 the
Company utilized the remaining available ITC of about $3.2
million to reduce its federal income tax obligation.
In 1999 the Company utilized its remaining tax net operating
loss carryforwards of $66.6 million to reduce its regular
income tax liability. Also in 1999, the Company utilized $4.2
million of federal and state alternative minimum tax credits
to reduce its regular income tax liability. At December 31,
1999, the Company had federal alternative minimum tax credits
remaining of approximately $3.6 million for the reduction of
future tax liabilities. In 1998 and 1997 the Company utilized
approximately $31.9 million and $21.5 million, respectively,
of tax net operating loss carryforwards to reduce its regular
income tax liability. These net operating losses were
principally due to the Company deducting for income tax
reporting purposes the costs of the purchased power contract
terminations in 1995, which were deferred for financial
reporting purposes (see Note 6).
In accordance with Statement of Financial Accounting
Standards No. 109 "Accounting for Income Taxes" (FAS 109),
the Company recorded net additional deferred income tax
liabilities of approximately $16 million as of December 31,
1999 and $23 million as of December 31, 1998. These
additional deferred income tax liabilities have resulted from
the accrual of deferred taxes on temporary differences on
which deferred taxes had not been previously accrued ($24.8
million and $32.6 million as of December 31, 1999 and 1998,
respectively), offset by the effect of the 1987 change to
lower income tax rates (reduced by the 1% increase in the
federal income tax rate in 1993) that will be refunded to
customers over time ($7.9 million and $8.6 million as of
December 31, 1999 and 1998, respectively), and the
establishment of deferred tax assets on unamortized
investment tax credits ($900,000 as of December 31, 1999 and
$1 million as of December 31, 1998). These latter amounts
have been recorded in Other Regulatory Liabilities at
December 31, 1999 and 1998. The accrual of the additional
amount of deferred tax liabilities have been offset by
regulatory assets which represent the customers' future
payment of these income taxes when the taxes are, in fact,
expensed. As a result of this accounting, the Consolidated
Statements of Income are not affected by the implementation
of FAS 109. The rate-making practices followed by the MPUC
permit the Company to recover federal and state income taxes
payable currently, and to recover some, but not all, deferred
taxes that would otherwise be recorded in accordance with FAS
109 in the absence of regulatory accounting. The individual
components of other accumulated deferred income taxes are as
follows at December 31, 1999 and 1998:
1999 1998
- ------------------------------------------ ------------ -----------
Deferred Income Tax Liabilities:
Costs to terminate purchased power contracts $42,793,031 $50,851,911
Excess book over tax basis of electric
plant in service 35,395,877 53,209,720
Investment in jointly-owned companies 1,492,533 2,036,802
Deferred incremental ice storm costs 1,429,579 2,119,432
Deferred incremental Maine Yankee costs - 697,692
Deferred demand-side management costs 94,013 318,927
Other 906,506 287,215
----------- ------------
$82,111,539 $109,521,699
----------- ------------
Deferred Income Tax Assets:
Deferred asset sale gain $12,121,099 -
Deferred taxes provided on alternative
minimum tax 3,627,596 7,314,289
Deferred state income tax benefit 3,317,437 2,881,091
Postretirement benefit costs other
than pensions 3,090,544 2,362,537
Unamortized investment tax credit 941,134 1,017,397
Reserve for bad debts 719,981 719,981
Accrued pension costs 446,765 324,064
Deferred incremental Maine Yankee costs 453,414 -
Net operating loss carryforward - 27,159,196
Reserve for Basin Mills investment - 2,835,939
Other 1,566,679 1,132,700
----------- -----------
$26,284,649 $45,747,194
----------- -----------
Total other accumulated deferred income taxes $55,826,890 $63,774,505
=========== ===========
As a result of the Company's generation asset sale to PP&L
Global (see Note 10), the Company realized $1.5 million in
income tax benefits associated with flowing through the
unamortized deferred ITC associated with the generation
assets sold and the reversal of the excess deferred income
taxes associated with these assets. These income tax benefits
have been recorded as a component of Other Income in the
Consolidated Statements of Income in 1999.
Note 3. Common and Preferred Stock and Earnings Per Share
- ---------------------------------------------------------
Common Stock - Prior to 1992, stockholders had been able to
invest their dividends and optional cash payments in common
stock of the Company acquired by an independent agent in the
open market through the Company's Dividend Reinvestment and
Common Stock Purchase Plan (the Plan). In 1992 the Company
amended the Plan to enable it to issue original shares in
return for the reinvested dividends and optional cash
payments. The common stock has general voting rights of one
vote per twelve shares owned. In January 1997, the Company
further amended the Plan to allow for the option of
purchasing shares either on the open market or from newly
issued shares sold by the Company. The Company anticipates
that for the foreseeable future common stock will be
purchased on the open market.
Preferred Stock - Authorized but unissued shares of 552,660
(plus additional shares equal in number to such presently
outstanding shares as may be retired) may be issued with such
preferences, restrictions or qualifications as the board of
directors may determine. Any new shares so issued will be
required to be issued with per share voting rights no greater
than that of the common stock. The callable preferred stock
may be called in whole or in part upon any dividend date by
appropriate resolution of the board of directors. The
currently outstanding preferred stock has general voting
rights of one vote per share. With re-gard to payment of
dividends or assets available in the event of liquidation,
preferred stock ranks prior to common stock.
Redeemable Preferred Stock - On December 27, 1989, the Company
issued to an institutional investor $15 million of nonvoting
preferred stock carrying an annual dividend rate of 8.76%.
These shares had a maturity of fifteen years with a mandatory
sinking fund of $1.5 million per year starting in 1995.
Through the utilization of generation asset sale proceeds,
the Company redeemed the remaining outstanding 90,000 shares
in October 1999 at a cost of $9.8 million, which included a
call premium of $282,000 and $563,000 associated with the
make whole provision, which is discussed below. The agreement
to issue this series of preferred stock contained a provision
whereby, if the Company paid a dividend that was considered a
return of capital for federal income tax purposes, the
Company was required to make a payment (make whole provision)
to the stockholder in order to restore the stockholder's
after-tax yield to the level it would have been had the
dividend not been considered a return of capital. Since 100%
of the dividends paid in 1990 and 1995 and 50% in 1993 were
considered a return of capital, the Company became obligated
to pay this stockholder approximately $939,000, on a pro-rata
basis (10% per year) in conjunction with each sinking fund
payment starting in 1995. With the redemption of the
remaining outstanding shares in 1999, the Company was
obligated to pay the remaining make whole provision amount of
$563,000 at the time of the redemption. The make whole
provision obligation was being recognized over the remaining
life of the issue through a direct charge to retained
earnings, which amounted to approximately $46,000 in 1999 and
$61,000 in each of 1998 and 1997. In each of 1998 and 1997
the Company made $1.5 million sinking fund payments, as well
as approximately $94,000 under the make whole provision.
Exercise of Warrants - In 1999, 349,999 common stock warrants,
which were issued in connection with the PERC purchased power
contract restructuring, were exercised at market prices
ranging from $16 1/16 to $16 3/4 per share. For a complete
discussion of the PERC contract restructuring and the
issuance of warrants, see Note 6. The Company exercised its
option to pay cash to the holders of the warrants instead of
actually issuing shares of common stock. These payments
amounted to approximately $3.3 million. Since the common
shares were not issued, and the Company had recorded the
estimated fair value of these warrants when issued in June
1998 as an addition to additional paid-in capital, amounting
to approximately $410,000, an adjustment has been made in
connection with the cash payments option to reduce additional
paid-in capital by the $410,000 as of December 31, 1999.
Earnings Per Share - The following table reconciles basic and
diluted earnings per common share assuming all outstanding
common stock warrants were converted to common shares (see
Note 6 for discussion of warrants issued in connection with
the PERC purchased power contract restructuring):
1999 1998 1997
- --------------------------------------------- ------------- ------------ ------------
Earnings (loss) applicable to common stock $17,335,205 $10,220,829 $(1,762,578)
----------- ----------- ------------
Average common shares outstanding 7,363,424 7,363,424 7,363,424
Plus: incremental shares from assumed conversion
of outstanding warrants 984,200 329,778 -
----------- ----------- ------------
Average common shares outstanding plus assumed
warrants converted 8,347,624 7,693,202 7,363,424
----------- ---------- -----------
Basic earnings (loss) per common share $2.35 $1.39 $(0.24)
----------- ----------- ------------
Diluted earnings (loss) per common share $2.08 $1.33 $(0.24)
=========== =========== ============
Note 4. Lending Agreements and Monetization of Power Sale Contract
- ------------------------------------------------------------------
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 revolv-ing credit commitment of $30 million.
The amended credit agreement is secured by $82.5 million of
non-interest bearing First Mortgage Bonds.
The revolving credit portion of the credit agreement has a
term of three years. The Company may borrow, at its option,
at rates, as defined in the agreement, based on the London
Interbank Offered (LIBO) rate, or the base rate, which is the
higher of the agent bank's defined base rate or one-half of
one percent (1/2%) above the federal funds interest rate. The
applicable risk premium based on the Company's corporate
credit rating is added to the core interest rate, which
results in the total combined interest rate for borrowing
under the agreement. A required commitment fee, based on the
Company's available revolving credit commitment, is also
priced according to the Company's corporate credit rating.
The maturity of the term loan was the earlier of two years or
when the Company completed any portion of its generation
asset sale (see Note 10). Interest on the term loan was
determined similarly to the revolving credit portion of the
new credit agreement but with a different risk premium. In
January 1999 the Company utilized the $6.2 million in
proceeds associated with the sale of property at its Graham
Station in Veazie, Maine to Casco Bay Energy (see Note 10) to
repay a portion of the outstanding medium term notes, and the
remaining principal outstanding of $38.8 million was repaid
at the end of May 1999 utilizing proceeds from the Company's
generation asset sale to PP&L Global on May 27, 1999.
The agreement allows the Company to incur, outside of the
revolving credit facility, additional unsecured debt of $5
million, plus 50% of the aggregate amount of mandated or
optional reductions to the $30 million revolving credit
facility.
The new credit agreement contains certain financial covenants
related to the Company's debt ratio, fixed charge coverage,
net worth, and limitation on the payment of common dividends.
The Company was in compliance with all covenants associated
with the new credit agreement during 1999 and 1998.
The Company provided power directly to UNITIL Power Corp.
(UNITIL), a New Hampshire based electric utility, at
significantly above-market rates, with the contract term
ending in the year 2003. On March 31, 1998, the Company
completed a transaction with lenders and one of its wholly
owned subsidiaries, BERI (see below) that provided a loan of
approximately $23.3 million in net proceeds secured by the
value of the UNITIL contract. As a requirement of the
financing, the Company established BERI, a special purpose
entity which holds the medium term notes and acts as a
conduit between Bangor Hydro and UNITIL for the procurement
of power under the terms of the original power sales contract
between the two parties.
The loan was comprised of $24.8 million in medium term notes,
with a term of 53 months. BERI must maintain a capital
reserve fund of $1.5 million, funded with proceeds from the
loan, which will be used to pay the final installment of
principal and interest due in 2002. The assets in the capital
reserve fund are held by a third party trustee and invested
in money market funds whose investments are limited to U.S.
Treasury and Agency obligations, repurchase agreements and
short-term bank and corporate obligations. Interest is
payable, at the Company's option, under the agreement at the
LIBO rate plus 1.125% or the base rate, which is the higher
of (a) the lending bank's reported "base rate" and (b) one-
half of one percent (1/2%) above the federal funds
effective interest rate. To provide interest rate protection
through the maturity date of the term loan, in April 1998,
BERI entered into an interest rate swap agreement with one of
the lending banks. The interest rate swap fixed the LIBO
interest rate on the medium term notes at 5.72%. As a result
of the interest rate swap agreement, BERI incurred additional
interest expense in 1999 amounting to approximately $114,000.
The agreement also contains certain financial covenants, with
which BERI was in compliance during 1999 and 1998.
In connection with financing the costs of the purchased power
contract buyback accomplished in June 1995 (see Note 6), the
Company entered into a Loan Agreement with the Finance
Authority of Maine (FAME), a body corporate and politic and
public instrumentality of the state of Maine. Pursuant to
authorizing legislation in Maine, FAME issued $126 million of
notes through a private placement, the repayment of which is
the responsibility of the Company under the terms of the Loan
Agreement. Of that amount, approximately $105 million was
made available to the Company to finance a portion of the
buyback and approximately $21 million was set aside in a
capital reserve fund. The notes bear interest at an annual
rate of 7.03%, mature on July 1, 2005 and are subject to a
schedule of annual principal payments beginning on July
1, 1998. The amount held in the capital reserve fund will be
used to pay the final installment of principal and interest
due in 2005. The assets in the capital reserve fund are held
by a third party trustee and invested in a guaranteed
investment contract, earning interest at an annual rate of
6.51%. The interest earnings are utilized to offset the
semiannual interest payments on the FAME notes.
In order to secure the FAME notes, the Company executed a
General and Refunding Mortgage Indenture and Deed of Trust
establishing a lien on the Company's property junior to the
lien under the Company's First Mortgage Bonds Indenture. The
Company may not issue any additional First Mortgage Bonds in
the future. The Company issued bonds to FAME under the new
mortgage in the amount of $126 million.
Certain information related to total short-term borrowings
under the Credit Agreements and the lines of credit is as
follows:
1999 1998 1997
- ---------------------------------------------------------- ------------ ------------ ------------
Total credit available at end of period $30,000,000 $30,000,000 $54,000,000
Letter of credit secured under the revolving credit facility - $4,200,000 $4,200,000
Unused credit at end of period $30,000,000 $13,800,000 $15,800,000
Borrowings outstanding at end of period - $12,000,000 $34,000,000
Effective interest rate (exclusive of fees) on borrowings -% 7.2% 8.3%
outstanding at end of period
Average daily outstanding borrowings for the period $2,802,740 $20,369,863 $31,236,301
Weighted daily average annual interest rate 6.7% 7.9% 8.1%
Highest level of borrowings outstanding at any
month-end during the period $13,000,000 $37,500,000 $36,500,000
=========== =========== ===========
Under the provisions of the first mortgage bond indenture,
substantially all of the Company's plant and property has
been mortgaged to secure the Company's first mortgage bonds.
Current maturities of the first mortgage bonds and other
long-term debt for the five years subsequent to December 31,
1999, amounting to $132,960,000, are $19,460,000 in 2000,
$21,340,000 in 2001, $41,560,000 in 2002, $32,200,000 in
2003, and $18,400,000 in 2004.
Note 5. Postretirement Benefits
- -------------------------------
The Company has a noncontributory pension plan covering
substantially all of its employees. Benefits under the plan
are generally based on the employee's years of service and
compensation during the years preceding retirement. The
Company's general policy is to contribute to the funds the
amounts deductible for federal income tax purposes. The
Company also has an unfunded noncontributory supplemental
non-qualified pension plan that provides additional
retirement benefits to certain management employees.
The following tables detail the funded status of the plan,
the amounts recognized in the Company's Consolidated
Financial Statements, the components of pension expense for
1999, 1998 and 1997 and the major assumptions used to
determine these amounts (includes both the funded and
unfunded plans). There were no employer contributions to the
plan in 1999, 1998 or 1997. The plan's assets are composed of
fixed income securities, equity securities and cash
equivalents.
The following table sets forth the plans' funded status at
December 31, 1999 and 1998:
1999 1998
- ------------------------------------------ ------------ ------------
Change in Projected Benefit Obligation
Balance as of December 31, 1998 and 1997 $48,215,365 $45,276,387
Service cost 1,439,047 1,208,393
Interest cost 3,295,172 3,107,258
Benefits paid (2,965,723) (3,013,719)
Amendments 1,047,567 -
(Gains) and losses (5,865,968) 1,637,046
----------- -----------
Balance as of December 31, 1999 and 1998 $45,165,460 $48,215,365
----------- -----------
Change in Plan Assets
Balance as of December 31, 1998 and 1997 $49,495,200 $48,323,318
Employer contributions 40,000 40,000
Benefits paid (2,965,723) (3,013,719)
Actual return, less expenses 5,265,253 4,145,601
----------- -----------
Balance as of December 31, 1999 and 1998 $51,834,730 $49,495,200
----------- -----------
Funded status $6,669,270 $1,279,835
Unrecognized net transition asset (1,322,500) (2,254,825)
Unrecognized prior service cost 3,290,845 3,599,188
Unrecognized gain (11,178,648) (4,067,348)
----------- -----------
Accrued pension balance at December 31, 1999 and 1998 ($2,541,033) ($1,443,150)
============ ============
The accumulated benefit obligation for the unfunded
supplemental pension plan with accumulated benefit
obligations in excess of plan assets was $1,220,982 and
$666,976 as of December 31, 1999 and 1998, respectively.
(CAPTION>
Total pension expense included the following components:
1999 1998 1997
- ------------------------------------------------------- ------------- ------------ ------------
Service cost-benefits earned during the period $1,439,047 $1,208,393 $1,064,129
Interest cost on projected benefit obligation 3,295,172 3,107,258 2,913,572
Expected return on plan assets (4,317,379) (3,737,267) (3,513,402)
Total of amortized obligations and deferred net loss 252,043 (333,507) (333,060)
------------- ----------- ------------
Total pension expense $668,883 $244,877 $131,239
============= =========== ============
1999 1998 1997
- -------------------------------------------------------- ------------- ----------- ------------
Significant assumptions used were-
Discount rate 6.75% 7.0% 7.5%
Rate of increase in future compensation levels 4.0% 4.0% 5.0%
Expected long-term rate of return on plan assets 9.0% 9.0% 9.0%
The discount rate and rate of increase in future compensation
levels used to determine pension obligations, effective
January 1, 2000, are 8% and 4%, respectively, and were used
to calculate the plans' funded status at December 31, 1999.
In addition to pension benefits, the Company provides certain
health care and life insurance benefits to its retired
employees. Substantially all of the Company's employees may
become eligible for retiree benefits if they reach normal
retirement age while working for the Company.
The MPUC in 1993 issued a final accounting rule in connection
with Statement of Financial Accounting Standards No. 106,
"Employers' Accounting for Postretirement Benefits Other
Than Pensions" (SFAS 106), which adopted this pronouncement
for ratemaking purposes and authorized the Company to defer
the excess of the net periodic postretirement benefit cost
recognized under SFAS 106 over the pay-as-you-go amount in
1993 through February 28, 1994, and to include such excess as
a regulatory asset pending inclusion in the new base rates,
effective March 1, 1994. This regulatory asset, which
amounted to $705,283 at February 28, 1994, is being
recovered, beginning March 1, 1994, over a ten-year period.
The Company, also in accordance with the final accounting
ruling, is amortizing the unrecognized transition obligation
of $10,023,200 over a 20-year period.
In 1994 the Company established an irrevocable external
Voluntary Employee Benefit Association Trust Fund (VEBA) to
fund the payment of postretirement medical and life insurance
benefits. Company contributions to the VEBA amounted to
approximately $1.3 million in each of 1999 and 1998, and $1.1
million in 1997. The VEBA's assets are composed of United
States Treasury money market funds. The Company's general
policy is to contribute to the VEBA amounts necessary to fund
claims and administrative costs.
The following table sets forth the benefit plan's funded status
at December 31, 1999 and 1998.
1999 1998
- ------------------------------------------------- ----------- -----------
Change in Accumulated Postretirement Benefit Obligation
Balance as of December 31, 1998 and 1997 $19,073,629 $16,234,790
Service cost 583,385 401,856
Interest cost 1,518,092 1,060,671
Claims paid (1,301,239) (1,292,715)
Gains and losses 846,966 2,669,027
------------ ------------
Balance as of December 31, 1999 and 1998 $20,720,833 $19,073,629
Change in Plan Assets
Balance as of December 31, 1998 and 1997 $321,408 $283,731
Employer contributions 1,347,000 1,338,027
Retiree contributions 47,152 45,757
Claims paid (1,301,239) (1,292,715)
Actual return, less expenses (55,350) (53,392)
------------ ------------
Balance as of December 31, 1999 and 1998 $358,971 $321,408
------------ ------------
Funded status ($20,361,862) ($18,752,221)
Unrecognized net transition obligation 6,514,800 7,016,000
Unrecognized loss 5,087,038 4,760,198
Accrued postretirement benefit cost balance at ------------ ------------
December 31, 1999 and 1998 ($8,760,024) ($6,976,023)
============ ============
The actuarially determined net periodic postretirement
benefit cost for 1999, 1998 and 1997 and the major
assumptions used to determine these amounts are shown in the
following tables:
1999 1998 1997
- ------------------------------------------- ---------- ---------- ----------
Service cost of benefits earned $583,385 $401,856 $342,739
Interest cost on accumulated postretirement
benefit obligation 1,518,092 1,060,671 994,936
Actual return on plan assets (9,710) (10,608) (9,395)
Amortization of unrecognized transition obligation 501,200 501,200 501,200
Other deferrals, net 405,834 (14,392) (11,605)
---------- ---------- ----------
Net periodic postretirement benefit cost $2,998,801 $1,938,727 $1,817,875
========== ========== ==========
1999 1998 1997
- --------------------------------------- ------- ------ -------
Significant assumptions used were-
Discount rate 6.75% 7.0% 7.5%
Health care cost trend rate,
employees less than age 65-
Near-term 7.5% 8.0% 8.5%
Long-term 4.5% 5.0% 4.5%
Health care cost trend rate,
employees greater than age 65-
Near-term 7.5% 8.0% 6.8%
Long-term 4.5% 5.0% 4.5%
Rate of return on plan assets 5.0% 5.0% 5.0%
The discount rate used to determine postretirement benefit
obligations, effective January 1, 2000, and the Plan's funded
status at December 31, 1999, was 8%.
Assumed health care cost trend rates have a significant
effect on the amounts reported for the health care plan. A
one-percentage-point change in assumed health care cost trend
rates would have the following effect:
1% Increase 1% Decrease
- --------------------------------------------------- ----------- -----------
Effect on total of service and interest cost components $ 308,173 $ (392,320)
Effect on postretirement benefit obligation 2,374,781 (2,904,741)
In 1999 the Company incurred $469,000 and $175,587 in special
termination benefits associated with enhanced pension and
postretirement medical benefits, respectively, provided to
employees who were displaced due to the asset sale to PP&L
Global (see Note 10). The state of Maine electric utility
restructuring legislation allows utilities to recover the
costs of providing such benefits to the workers displaced due
to the sale of the Company's generation assets, and
consequently, the special termination benefits expense of
$644,587 has been deferred as a regulatory asset at December
31, 1999. This regulatory asset will begin to be recovered
starting March 1, 2000 over a three-year period as specified
in the Company's most recent rate order from the MPUC.
The estimates of the Company's accrued pension and
postretirement benefit costs involve the utilization of
significant assumptions. Any change in these assumptions
could impact the liabilities in the near term.
The Company also provides a defined contribution 401(k)
savings plan for substantially all of its employees. The
Company's matching of employee voluntary contributions
amounted to approximately $331,000 in 1999, $330,000 in 1998
and $295,000 in 1997.
Note 6. Jointly Owned Facilities and Power Supply Commitments
- -------------------------------------------------------------
Maine Yankee - The Company owns 7% of the common stock of
Maine Yankee, which owns and, prior to its permanent closure
in 1997, operated an 880 megawatt (MW) nuclear generating
plant (the Plant) in Wiscasset, Maine. Maine Yankee, which
had commenced commercial operation on January 1, 1973, is the
only nuclear facility in which the Company has an ownership
interest. The Company's equity ownership in the plant had
entitled the Company to about 7% of the output pursuant to a
cost-based power contract. Pursuant to a contract with Maine
Yankee, the Company is obligated to pay its pro rata share of
Maine Yankee's operating expenses, including decommissioning
costs. In addition, under a Capital Funds Agreement entered
into by the Company and the other sponsor utilities, the
Company may be required to make its pro rata share of future
capital contributions to Maine Yankee if needed to finance
capital expenditures.
The entire output of the Plant had been sold at wholesale by
Maine Yankee to ten New England electric utilities, which
collectively own all of the common equity of Maine Yankee; a
portion of that output (approximately 6.2%) was in turn
resold by certain of the owner utilities to 28 municipal and
cooperative utilities in New England (the Secondary
Purchasers). Maine Yankee recovered, and since the shutdown
decision has continued to recover, its costs of providing
service through a formula rate filed with the FERC and
contained in Power Contracts with its utility purchasers,
which are also filed with the FERC. Pursuant to the FERC
filing dated November 6, 1997, Maine Yankee submitted for
filing certain amendments to the Power Contracts (the
Amendatory Agreements), revised rates to reflect the decision
to shut down the Plant, a requested approval of an increase
in the decommissioning component of its formula rates, and
certain other rate changes, including recovery of unamortized
investment (including fuel) and certain changes to its
billing formula, consistent with the non-operating status of
the Plant. By Order dated June 1, 1999, the FERC approved an
Offer of Settlement submitted by the various intervenors in
the case.
The Offer of Settlement provides for Maine Yankee to collect
$33.6 million in the aggregate annually, effective January
15, 1998: (1) $26.8 million for estimated decommissioning
costs, and (2) $6.8 million for interim spent fuel storage
installation (ISFSI)-related costs. The original filing with
FERC on November 6, 1997 called for an aggregate annual
collection rate of $36.4 million for decommissioning and the
ISFSI. The amount collected annually could be reduced to
approximately $26 million if Maine Yankee is able to (1) use
funds held in trust under Maine law for spent-fuel disposal
in connection with the construction of the ISFSI, and (2)
access approximately $6.8 million being held by the state of
Maine for eventual payment to the state of Texas pursuant to
a compact for low-level nuclear waste disposal, the future of
which is now in question after rejection of the selected
disposal site in west Texas by a Texas regulatory agency.
Both required authorizing legislation in Maine, which was
obtained pursuant to P.L. 173. The Offer of Settlement also
provides for recovery of all unamortized investment
(including fuel) in the Plant, together with a return on
equity of 6.50%, effective January 15, 1998, on equity
balances up to maximum allowed equity amounts. The Settling
Parties also agreed in the proposed settlement not to contest
the effectiveness of the Amendatory Agreements submitted to
FERC as part of the original filing, subject to certain
limitations including the right to challenge any accelerated
recovery of unamortized investment under the terms of the
Amendatory Agreements after a required informational filing
with the FERC by Maine Yankee. As a separate part of the
Offer of Settlement, the Company, the other two Maine owners
of Maine Yankee, the MPUC Staff, and the Office of the Public
Advocate entered into a further agreement resolving retail
rate issues and other issues specific to the Maine parties,
including those that had been raised concerning the prudence
of the operation and shutdown of the Plant (the Maine
Agreement).
Under the Maine Agreement, the Company would continue to
recover its Maine Yankee costs in accordance with its
February 1998 rate order from the MPUC without any adjustment
reflecting the outcome of the FERC proceeding. To the extent
that the Company has collected from its retail customers a
return on equity in excess of the 6.50% contemplated by the
Offer of Settlement, no refunds would be required, but such
excess amounts would be credited to the customers to the
extent required by the Company's Alternative Rate Plan. The
final major provision of the Maine Agreement requires the
Maine owners, for the period from March 1, 2000, through
December 1, 2004, to hold their Maine retail ratepayers
harmless from the amounts by which the replacement power
costs for Maine Yankee exceed the replacement power costs
assumed in the report to the Maine Yankee board of directors
that served as a basis for the Plant shutdown decision, up to
a maximum cumulative amount of $41 million. The Company's
share of that amount would be $5.74 million for the period.
The Maine Agreement, which was approved by the MPUC on
December 22, 1998, also sets forth the methodology for
calculating such replacement power costs. The Company
believes that the Offer of Settlement, including the Maine
Agreement, constitutes a reasonable resolution of the issues
raised in the Maine Yankee FERC proceeding, and eliminates
significant uncertainties concerning the Company's future
financial performance.
Maine Yankee's most recent estimate of the total costs of
decommissioning and plant closure, for the period from 1999
to 2008, excluding funds already collected, is $715 million
(undiscounted). The Company's share of the estimated cost at
December 31, 1999 is approximately $46 million and is
recorded as a regulatory asset and decommissioning
liability. The regulatory asset was recorded for the full
amount of the decommissioning and plant closure costs due
to the recent industry restructuring legislation (see Note
10) allowing the Company future recovery of nuclear
decommissioning expenses related to Maine Yankee, as well as
the Company being allowed a recovery mechanism in its
February 1998 rate order for Maine Yankee non-decommissioning
plant closure costs. Accumulated decommissioning funds at
December 31, 1999 had an adjusted market value of $181.1
million of which the Company's share was approximately $12.7
million.
Summary Financial Information for Maine Yankee and MEPCO
- ------------------------------------------------------------------------------------------------------------------
Maine Yankee MEPCO
- ------------------------------------------------------------------------------------------------------------------
(Dollars in Thousands)
- ------------------------------------------------------------------------------------------------------------------
1999 1998 1997 1999 1998 1997
---------- ----------- ---------- --------- --------- ---------
Operations:
As reported by investee-
Operating Revenue $ 69,439 $ 110,608 $ 238,586 $ 2,738 $ 3,514 $ 24,473
- ------------------------------------------------------------------------------------------------------------------
Depreciation & decommissioning
collections $ 55,286 $ 57,617 $ 33,625 $ 326 $ 364 $ 222
Interest and Preferred Dividends 14,079 15,958 18,031 72 77 67
Other expenses, net (4,789) 32,117 179,317 (969) 2,125 23,112
- ------------------------------------------------------------------------------------------------------------------
Operating expenses $ 64,576 $ 105,692 $ 230,973 $ (571) $ 2,566 $ 23,401
- ------------------------------------------------------------------------------------------------------------------
Earnings Applicable to Common Stock $ 4,863 $ 4,916 $ 7,613 $ 3,309 $ 948 $ 1,072
==================================================================================================================
Amounts Reported by the Company-
Purchased power costs $ 4,368 $ 7,185 $ 16,764 $ - $ - $ -
Equity in net income (83) (215) (524) (199) (123) (15)
- ------------------------------------------------------------------------------------------------------------------
Net purchased power expense $ 4,285 $ 6,970 $ 16,240 $ (199) $ (123) $ (15)
==================================================================================================================
Financial Position:
As reported by investee-
Plant in service $ 685 $ 687 $ 687 $ 23,493 $ 23,633 $ 23,510
Accumulated depreciation - - - (23,015) (22,899) (22,618)
Other assets 1,091,265 1,182,611 1,367,456 7,589 4,781 3,470
- ------------------------------------------------------------------------------------------------------------------
Total assets $1,091,950 $ 1,183,298 $1,368,143 $ 8,067 $ 5,515 $ 4,362
Less-
Preferred stock 15,000 16,800 17,400 - - -
Long-term debt 54,000 68,433 143,665 - 220 420
Other liabilities and deferred credits 947,972 1,018,575 1,128,128 4,339 2,079 1,578
- ------------------------------------------------------------------------------------------------------------------
Net assets $ 74,978 $ 79,490 $ 78,950 $ 3,728 $ 3,216 $ 2,364
==================================================================================================================
Company's reported equity-
Equity in net assets $ 5,248 $ 5,564 $ 5,527 $ 529 $ 457 $ 336
Adjust Company's estimated to actual 19 (125) 5 1 (18) (10)
- ------------------------------------------------------------------------------------------------------------------
Equity in net assets as reported $ 5,267 $ 5,439 $ 5,532 $ 530 $ 439 $ 326
==================================================================================================================
MEPCO - The Company owns 14.2% of the common stock of MEPCO.
MEPCO owns and operates electric transmission facilities from
Wiscasset, Maine, to the Maine-New Brunswick border.
Information relating to the operations and financial position
of Maine Yankee and MEPCO appears above. In connection with
the Company's generation asset sale (see Note 10), the
Company sold certain of its rights to MEPCO transmission
capacity.
Wyman 4 - The Company owned 8.33% (50 MW) of the oil-fired 600
MW Wyman Unit No. 4 in Yarmouth, Maine. In May 1999 the
Company sold its interest in Wyman 4 to PP&L Global as part
of its generation asset sale (see Note 10). The Company's
proportionate share of the direct expenses of this unit,
through the date of the sale, is included in the
corresponding operating expenses in the Consolidated
Statements of Income. Included in the Company's utility plant
at December 31, 1998 and 1997 were the following amounts with
respect to this unit:
1998 1997
- -------------------------------------------------------------------------
Electric plant in service $ 16,887,608 $ 16,886,776
Accumulated depreciation (9,851,639) (9,389,542)
- -------------------------------------------------------------------------
$ 7,035,969 $ 7,497,234
=========================================================================
NEPOOL/Hydro-Quebec Project - The Company is a 1.6%
participant in the NEPOOL/Hydro-Quebec Phase 1 project (Phase
1), a 690 MW DC intertie between the New England utilities
and Hydro-Quebec constructed by a subsidiary of another New
England utility at a cost of about $140 million. The
participants receive their respective share of savings from
energy transactions with Hydro-Quebec, and are obliged to pay
for their respective shares of the costs of ownership and
operation whether or not any savings are realized.
The Company is also a 1.5% participant in the NEPOOL/Hydro-
Quebec Phase 2 project (Phase 2), which involves an increase
to the capacity of the Phase 1 intertie to 2,000 MW. As in
the Phase 1 project, the Company receives a share of the
anticipated energy cost savings derived from purchases from
Hydro-Quebec and capacity benefits provided by the intertie
and is required to pay its share of the costs of ownership
and operation whether or not any savings are obtained. In
connection with the generation asset sale in May 1999, the
Company sold its rights as a participant in the regional
utilities agreement with Hydro-Quebec (see Note 10). The
Company, though, is still required to pay its share of the
costs of ownership and operation of the Hydro-Quebec
intertie. Also in connection with the asset sale, PP&L Global
(PP&L) has agreed to pay the Company $400,000 per year to
partially offset the Company's on-going Hydro-Quebec support
payments. Since the Company still has an obligation for the
costs of the Hydro-Quebec intertie, but it has sold the
rights to the benefits as a participant, a $7.5 million
liability (included in Other Long-term Liabilities) and
corresponding regulatory asset (included in Other Regulatory
Assets) have been recorded as of December 31, 1999 on the
Consolidated Balance Sheet representing the present value of
the Company's estimated future payments (net of the $400,000
to be received from PP&L) for costs of ownership and
operation of the Hydro-Quebec intertie.
Bangor Var Co. - In 1990, the Company formed BVC, whose sole
function is to be a 50% general partner in Chester, a
partnership which owns a static var compensator (SVC), which
is electrical equipment that supports the Phase 2
transmission line. A wholly-owned subsidiary of Central Maine
Power Company owns the other 50% interest in Chester. Chester
has financed the acquisition and construction of the SVC
through the issuance of $33 million in principal amount of
10.48% senior notes due 2020, and up to $3.25 million in
principal amount of additional notes due 2020 (collectively,
the SVC Notes). The holders of the SVC Notes are without
recourse against the partners or their parent companies and
may only look to Chester and to the collateral for payment.
The New England utilities which participate in Phase 2 have
agreed under a FERC approved contract to bear the cost of
Chester, on a cost of service basis, which includes a return
on and of all capital costs. Information relating to the
operations and financial position of Chester appears on page
42.
Penobscot Natural Gas Company - In 1998 the Company formed
Penobscot Gas, whose sole function was to be a 50% general
partner in Bangor Gas Company, LLC (Bangor Gas), which is
constructing a nat-ural gas distribution system in the
greater Bangor, Maine area. Sempra Energy, a joint venture of
Pacific Enterprises and Enova Corporation, owns the other 50%
interest in Bangor Gas. Gas service to Maine has become
feasible for the first time because of the development of the
Maritimes & Northeast Pipeline Project, extending from the
Sable Offshore Energy Project near Sable Island, Nova Scotia,
through the state of Maine and interconnecting with the
Tennessee Gas Pipeline in Dracut, Massachusetts. The pipeline
passes near the Bangor area. As the restructuring of the
electric industry in Maine has developed, the Company has
become increasingly cognizant of the need to focus on its
core electric transmission and distribution business.
Consequently the Company has determined that it no longer in-
tends to participate in the Bangor Gas joint venture and
intends to sell its joint venture interest. Penobscot Gas'
investment in Bangor Gas as of December 31, 1999 is
approximately $328,000 and is recorded as an Other Investment
on the Consolidated Balance Sheets. Management is currently
unable to predict the financial statement impact of this
decision.
At December 31, 1998, Penobscot Gas had approximately a
$77,000 equity investment in Bangor Gas. Penobscot Gas
recorded equity losses in Bangor Gas of approximately
$249,000 and $98,000 for the years ended December 31, 1999
and 1998, respectively. Bangor Gas' total assets, principally
construction work in progress, amounted to $12.5 million and
$2.9 million at December 31, 1999 and 1998, respectively.
Summary Financial Information for Bangor-Pacific and Chester
- ------------------------------------------------------------------------------------------------------
Bangor-Pacific Chester
- ------------------------------------------------------------------------------------------------------
(Dollars in Thousands)
- ------------------------------------------------------------------------------------------------------
1999* 1998 1997 1999 1998 1997
--------- --------- --------- --------- --------- ---------
Operations:
As reported by investee-
Operating Revenue $ 4,426 $ 7,309 $ 7,057 $ 4,406 $ 4,535 $ 4,642
- --------------------------------------------------------------------------------------------------------
Depreciation $ 511 $ 868 $ 870 $ 1,075 $ 1,075 $ 1,075
Interest expense 1,688 3,082 3,294 2,616 2,737 2,859
Other expenses, net 497 890 911 715 723 708
- --------------------------------------------------------------------------------------------------------
Operating expenses $ 2,696 $ 4,840 $ 5,075 $ 4,406 $ 4,535 $ 4,642
- --------------------------------------------------------------------------------------------------------
Net Income $ 1,730 $ 2,469 $ 1,982 $ - $ - $ -
========================================================================================================
Company's reported equity in net income $ 865 $ 1,235 $ 991 $ - $ - $ -
========================================================================================================
Financial Position:
As reported by investee-
Plant in service $ - $ 44,047 $ 44,047 $ 31,993 $ 31,993 $ 31,993
Accumulated depreciation - (9,031) (8,163) (9,598) (8,523) (7,447)
Other assets - 3,308 3,129 2,907 3,008 3,087
- --------------------------------------------------------------------------------------------------------
Total assets $ - $ 38,324 $ 39,013 $ 25,302 $ 26,478 $ 27,633
Less-
Long-term debt - 26,300 28,500 23,471 24,654 25,837
Other liabilities - 2,517 2,425 1,831 1,824 1,796
- --------------------------------------------------------------------------------------------------------
Net assets $ - $ 9,507 $ 8,088 $ - $ - $ -
========================================================================================================
Company's reported equity in net assets $ - $ 4,754 $ 4,044 $ - $ - $ -
========================================================================================================
*Financial information related to the operations of Bangor-Pacific is presented
for the first seven months of 1999, prior to the sale of PHC.
Small Power Production Facilities - As of the end of 1999, the
Company had contracts with six in-dependent, non-utility
power producers known as "small power production
facilities." The West Enfield Project, described below, is
one such facility. There are four other relatively small
hydroelectric facilities, and a 20 MW facility fueled by
municipal solid waste (see PERC discussion below). The cost
of power from the small power production facilities is more
than the Company would incur from other sources if it were
not obligated under these contracts, and, in the case of the
solid waste plant, substantially more. The prices were
negotiated at a time when oil prices were much higher than at
present, and when forecasts for the costs of the Company's
long-term power supply were higher than current forecasts.
The Company had been attempting to alleviate the adverse
impact of high-cost contracts with small power production
facilities. One method for doing so had been to pay a fixed
sum in return for terminating the contract. The first such
transaction was accomplished in 1993, and in 1995 the Company
succeeded in accomplishing two more. These contract
terminations have resulted in significant savings in
purchased power costs, and the Company believes such savings
will continue over the long term.
In the 1993 transaction, the Company negotiated an agreement
to cancel its long-term purchased power agreement with one of
the biomass plants, the Beaver Wood Joint Venture (Beaver
Wood), in June 1993. In connection with the cancellation, the
Company paid Beaver Wood $24 million in cash and issued a new
series of 12.25% First Mortgage Bonds due July 15, 2001 to
the holders of Beaver Wood's debt in the amount of $14.3
million in substitution for Beaver Wood's previously
outstanding 12.25% Secured Notes. The remaining outstanding
principal of these First Mortgage Bonds was repaid in August
1999 through the utilization of generation asset sale
proceeds. Also, in connection with the cancellation
agreement, a reconstituted Beaver Wood partnership paid
the Company $1 million at the time of settling the
transaction and agreed to pay the Company $1 million annually
for a six-year period beginning in 1994 in return for
retaining the ownership and the option of operating the
plant. The payments are secured by a mortgage on the property
of the Beaver Wood facility. In each of the years from 1994
through 1997 the Company received its $1 million payment. The
Company was entitled to receive the final two payments
totaling $2 million in 1998 and 1999 from Beaver Wood.
However, in July 1998, Beaver Wood indicated that it would
not be making the payment due at that time and requested the
Company agree to a lower payment. After assessing the
potential costs and benefits of foreclosing on the mortgage,
the Company determined that accepting a payment of $1.75
million would be a better alternative. This $1.75 million
payment was received in February 1999. Management believes it
is entitled to recover the $250,000 shortfall from its
customers.
In May 1993 the Company received an accounting order from the
MPUC related to this purchased power contract buyout. The
order stipulated that the Company could seek recovery of the
costs associated with the buyout in a future base rate case,
and could also record carrying costs on the deferred balance.
Consequently, a regulatory asset of $40.3 million was
recorded as of December 31, 1993. Effective with the imple-
mentation of new base rates on March 1, 1994, the Company
began recovering over a nine-year period the deferred
balance, net of the additional $6 million anticipated from
Beaver Wood. In connection with the temporary rate increase
effective July 1, 1997, the MPUC required the Company to
accelerate the amortization of this regulatory asset, and
effective December 12, 1997, the MPUC authorized the Company
to revert to the original amortization schedule. Effective
with the 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. Effective March 1, 2000, this
regulatory asset will be amoritized at an annual rate of $3.9
million through February 2003.
The 1995 transactions involved a "buyback" of the contracts
for the purchase of power from two biomass-fueled generating
plants in West Enfield and Jonesboro, Maine, which are
identical plants under common ownership. The buyback cost was
approximately $170 million, including transaction costs. The
buyback costs were deferred and recorded as a regulatory
asset and are being amortized and collected over a ten-year
period, beginning July 1, 1995. The cost of the buy-back was
financed entirely by new debt instruments, thereby
significantly increasing the Company's indebtedness (see Note
4).
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. PERC owns a 20 MW waste-to-energy
facility in Orrington, Maine, that provides solid waste
disposal services to many communities in central, eastern,
and northern Maine. The contract requires the Company to
purchase the electricity output of the plant until 2018 at a
price that is presently above the cost of alternative sources
of power, and, in the Company's opinion, is likely to remain
so. The Company's net purchased power under this
contract was approximately $13.2 million in 1999 and is
projected to be $15-16 million annually, net of
revenues from the resale of power to another utility (these
amounts are not reduced by the Company's pro rata share of
PERC's net revenues discussed below).
This major restructuring involved several separate components
including the following:
1) PERC refinanced $45 million in existing bonds with a
remaining five-year term over a twenty-year period using
tax exempt bonds issued by the Finance Authority of Maine
under its Electric Rate Stabilization Program.
2) PERC will share the net revenues generated by the
facility on a pro rata basis with the Company and the
Municipal Review Committee (MRC) which represents over 130
Maine municipalities receiving waste disposal service from
PERC. In 1999 and 1998 the Company realized $2.9 million
and $2 million, respectively, in savings associated with
its share of PERC net revenues. The Company expects to
realize approximately $3.6 million annually in such savings
through the term of the PERC contract.
3) The Company made a onetime payment of $6 million to PERC
in June 1998 and is making additional quarterly payments,
starting in October 1998, of $250,000 for four years
totaling $4 million.
4) The Company and PERC amended their existing power
purchase agreement to include the MRC as a party.
5) The MRC's constituent municipalities extended their
contracts with PERC by 15 years to supply solid waste to
the facility through 2018.
6) The Company issued two million warrants to purchase
common stock, one million each to PERC and the MRC. Each
warrant entitles the warrant holder to acquire one share of
the Company's common stock at a price of $7 per share. No
warrants could be exercised within the first nine months
after their issuance, and they are exercisable in 500,000
share blocks following the expiration of nine months, 21
months, 33 months, and 45 months from the closing date.
Upon exercise, the Company has the option, instead of
providing common stock, to pay cash equal to the difference
between the then market price of the stock and the exercise
price of $7 per share times the number of shares as to
which exercise is made. The MPUC has established a cap on
ratepayers' exposure to the cost of the warrants. Ratepayer
costs are limited to the difference between the higher of
$15 per share or the book value per share at the time the
warrants are exercised and the $7 exercise price. The
Company would not recover any costs above the cap from
ratepayers. As previously discussed in Note 3, in 1999,
349,999 common stock warrants were exercised (at a market
prices below the book value per common share at the time of
the exercise), and the Company exercised its option to pay
cash to the holders of the warrants instead of
actually issuing shares of common stock. These payments
amounted to approximately $3.3 million. Since the common
shares were not issued, and the Company had recorded the
estimated fair value of these warrants when issued in June
1998, amounting to approximately $400,000, as an addition
to the PERC regulatory asset, an adjustment has been made
in connection with the cash payments option to increase the
PERC regulatory asset by approximately $2.9 million as of
December 31, 1999.
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 could result
in cost savings to the Company over the next twenty years
with a net present value of $16-$22 million.
The refinancing by PERC was made possible by the Maine
Legislature through an amendment to the Electric Rate
Stabilization Program that allowed PERC to qualify for such
financing. Under the Program, the state of Maine's "moral
obligation" supports the new nonrecourse debt.
As of December 31, 1999, the Company has deferred, as a
regulatory asset, approximately $12.4 million in
connection with the PERC restructuring. As discussed above,
the Company is currently recovering the deferred PERC
restructuring costs in rates. Effective with the
implementation of new rates on March 1, 2000, the Company
will be recovering the full amount of deferred PERC
restructuring costs, including an estimate of the future
value of warrants to be exercised and the additional $250,000
quarterly payments discussed above, amounting to an annual
amortization of $1.6 million per year. The Company is not
receiving a return on unexercised warrants, but may accrue
carrying costs on the value of any warrants exercised until
the amounts are included in the determination of new rates in
the future.
West Enfield Project - In 1986, the Company entered into a
joint venture with a development subsidiary of Pacific
Lighting Corporation for the purpose of financing and
constructing the redevelopment of an old 3.8 MW hydroelectric
plant which the Company owned on the Penobscot River in
Enfield and Howland, Maine, into a 13 MW facility for the
purpose of operating the facility once it was completed.
Commercial operation of the redeveloped project began in
April 1988. PHC was formed to own the Company's 50% interest
in the joint venture, Bangor-Pacific. Bangor-Pacific financed
the cost of the redevelopment through the issuance in a
privately placed transaction of $40 million of fixed rate
term notes and a commitment for up to $5 million of floating
rate notes. The notes are secured by a mortgage on the
project and a security interest in a 50-year purchased power
contract, and the revenues expected thereunder, between the
Company and Bangor-Pacific.
In late July 1999, in connection with the generation asset
sale, the Company sold PHC to PP&L and received $10 million
in proceeds. The sale resulted in a gain of approximately
$5.2 million, of which $4.7 million has been deferred as part
of the deferred asset sale gain as of December 31, 1999 (see
Note 10). The remaining $.5 million of the gain relates to
the portion of the gain on sale of PHC which is allocable to
shareholders (recorded as Other Income in the Consolidated
Statements of Income for the year ending December 31, 1999).
Under the purchased power contract with Bangor-Pacific, if
the project operates as anticipated, payments by the Company
to Bangor-Pacific are estimated to be about $7.5 million. It
is possible that the Company would be required to make
payments under the contract regardless of whether any power
is delivered, in an amount of approximately $4 million per
year. However, the Company has the right to terminate the
contract if the failure to deliver power continues for a
period of twelve consecutive months. Information relating to
the operations of Bangor-Pacific appears on page 42.
Other Power Supply Commitments - The Company had a contract,
which started in June 1997, for the delivery of up to 60 MW
of power from another utility, ending February 29, 2000. This
contract was directly tied to the price of oil and the
Company hedged this purchase through its energy risk
management program (see Note 13 for a discussion of the
Company's fuel hedge program). The Company's purchased power
expense (including hedge settlements) under this contract was
approximately $11.6 million in 1999.
The Company also had a 40 MW purchase power contract tied
directly to the price of oil. The term of this contract was
January 1, 1999 through February 29, 2000. The Company also
hedged this purchase through its energy risk management
program, and the purchased power expense was approximately
$6.9 million in 1999.
As part of the generation asset sale to PP&L, the Company
entered into a Transitional Power Sales Agreement with PP&L's
subsidiary, Penobscot Hydro, to purchase the output from the
Company's former hydroelectric facilities. This
agreement became effective the day after the asset sale
closing in May 1999 and expired on February 29, 2000.
Purchased power expenses under the contract were
approximately $3.2 million for 1999.
In late 1999 the Company selected Morgan Stanley Dean Witter
& Co., subsidiary Morgan Stanley Capital Group Inc., (Morgan
Stanley) as the winning bidder for all of the capacity and
energy from its six purchased power contracts being auctioned
off pursuant to Chapter 307 of Maine's 1997 law restructuring
the State's electric industry. The purchased power contracts
provide 38 MWs of capacity and 218,000 MWHs of energy from
hydro and biomass generation in Maine. The Morgan Stanley
contract commenced March 1, 2000, the date when retail cus-
tomer choice for power supply commenced in Maine, and will
continue for a period of two years. This transaction has been
approved by the MPUC.
Included in the sale are 16 MWs of capacity and associated
energy from the Company's contract with PERC and all the
capacity and energy from the Company's 19 MW hydro contract
with Bangor-Pacific. Also a part of the transaction are all
of the energy and capacity from the Company's several smaller
agreements with Pumpkin Hill, Milo, Green Lake and Sebec
Hydro.
In connection with the Company's current rate proceeding with
the MPUC, the cost of energy and capacity associated with
these agreements, net of the revenues to be realized from the
resale to Morgan Stanley are being recovered from customers
as stranded costs. Also being recovered as stranded costs are
the Company's obligations under the regional utilities
agreements with Hydro-Quebec.
Basin Mills and Veazie Projects - As a result of increased
uncertainty about the recoverability of amounts invested
through 1993 in licensing activities for proposed additional
hydroelectric facilities, the Company had established a
reserve against those investments in the amount of $8.7
million as of December 31, 1993. Since 1993 the Company had
charged to non-operating expense all amounts related to these
licensing activities. The projects for which the reserve was
established are a proposed 38 MW generating facility located
at the so-called Basin Mills site on the Penobscot River in
Orono and Bradley, Maine, and an 8 MW addition to the
Company's existing dam and power station on the Penobscot
River in Veazie and Eddington, Maine. As discussed in Note
10, the Company's investment in the Basin Mills and Veazie
projects were included in the assets sold as part of its
generation asset sale, and the $8.7 million reserve was
reversed during 1999.
Note 7. Recovery of Seabrook Investment and Sale of Seabrook
Interest
- ------------------------------------------------------------
The Company was a participant in the Seabrook nuclear project
in Seabrook, New Hampshire. On December 31, 1984, the Company
had almost $87 million invested in Seabrook, but because the
uncertainties arising out of the Seabrook Project were having
an adverse impact on the Company's financial condition, an
agreement for the sale of Seabrook was reached in mid-1985
and was finally consummated in November 1986. During 1985, a
comprehensive agreement was negotiated among the Company, the
MPUC staff, and the Maine Public Advocate addressing the
recovery through rates of the Company's investment in
Seabrook (the Seabrook Stipulation). This negotiated
agreement was approved by the MPUC in late 1985. Although the
implementation of the Seabrook Stipulation significantly
improved the Company's financial condition, substantial
write-offs were required as a result of the determination
that a portion of the Company's investment in Seabrook would
not be recovered. In addition to the disallowance of certain
Seabrook costs, the Seabrook Stipulation also provided for
the recovery through customer rates of 70% of the Company's
year-end 1984 investment in Seabrook Unit 1 over 30 years,
and 60% of the Company's investment in Unit 2 over seven
years, with base rate treatment on the unamortized balances.
As of December 31, 1992, the Company's investment in
Seabrook Unit 2 was fully amortized.
Note 8. Unaudited Quarterly Financial Data
- ------------------------------------------
Unaudited quarterly financial data pertaining to the results of operations
are shown below
Quarter Ended
------------------------------------------
Mar. 31 June 30 Sept. 30 Dec. 31
------------------------------------------
1999 DOLLARS IN THOUSANDS EXCEPT PER SHARE AMOUNTS)
- ----------------------------------------------------------------------
Electric Operating Revenue $ 50,222 $ 47,299 $ 51,452 $ 49,022
Operating Income 9,886 8,502 9,331 8,439
Net Income 4,212 3,452 5,037 5,580
Basic Earnings Per Share
of Common Stock $ .53 $ .43 $ .65 $ .74
======================================================================
1998
- ----------------------------
Electric Operating Revenue $ 49,100 $ 46,601 $ 49,158 $ 50,285
Operating Income 8,410 8,006 9,087 9,633
Net Income (Loss) 2,408 2,267 2,949 3,841
Basic Earnings (Loss) Per Share
of Common Stock $ .28 $ .27 $ .36 $ .48
======================================================================
1997
- ----------------------------
Electric Operating Revenue $ 48,176 $ 42,236 $ 47,557 $ 49,356
Operating Income 6,657 4,896 5,902 6,334
Net Income 716 (1,037) (188) 122
Basic Earnings Per Share of
Common Stock $ .05 $ (.19) $ (.07) $ (.03)
======================================================================
Note 9. Fair Value of Financial Instruments
- -------------------------------------------
The following represents the estimated fair value at December
31, 1999 of each class of financial instrument for which it
is practical to estimate the value:
Cash and cash equivalents: the carrying amount of $15,691,166
approximates fair value.
Funds held by trustee-money market funds and U.S. Treasury
Bills: the carrying amount of $2,240,714 approximates fair
value.
The fair values of other financial instruments at December
31, 1999 based upon similar issuances of comparable companies
are as follows:
In Thousands Carrying Amount Fair Value
- ---------------------------------------------- --------------- ----------
Funds held by trustee-guaranteed investment contract $21,192 $21,038
First Mortgage Bonds 85,000 91,433
FAME Revenue Notes 100,600 98,340
Medium Term Notes-LIBO rate plus 1.125% 17,160 17,160
Note 10. Industry Restructuring and Rate Regulation
- ---------------------------------------------------
Industry Restructuring - As discussed in the 1998 Form 10-K,
in 1997, the Maine Legislation 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
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, in 1999
the Company completed transactions to sell most of its
generation related assets to PP&L.
3) Billing and metering services will be subject to
competition beginning March 1, 2002, but the legislation
permits the MPUC to establish an earlier date, no sooner
than March 1, 2000. There is currently activity within the
legislature to extend the date one year to March 1, 2003
and limit the scope of the competitive billing and metering
services to only the largest industrial customers. If such
a change is enacted, the implementation of competitive
billing and metering would not have significant impact on
the Company or its operations.
4) The Company will continue to provide transmission and
distribution (T&D) services which will be subject to
continued regulation by the FERC and MPUC, respectively.
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").
Sale of the Company's Generating Assets - On May 27, 1999, the
Company completed most of the transaction for the sale of its
electric generating assets and certain transmission rights to
PP&L. The purchase price for the assets transferred was $79
million.
The sale involved all but one of the Company's hydroelectric
plants on the Penobscot, Piscataquis, and Union rivers and
Bangor Hydro's 8.33% ownership interest in the Wyman Unit #4
oil-fired plant in Yarmouth, Maine-a total base load
capacity of 83 megawatts. The sale also involved a transfer
by the Company of rights to transmit power over the MEPCO
transmission facilities connecting NEPOOL to New Brunswick
Canada; the Company's rights as a participant in the regional
utilities' agreement with Hydro-Quebec pursuant to an agency
agreement; and the Company's rights to develop a second high
voltage transmission line that will connect NEPOOL to New
Brunswick, Canada.
The Company conducted an auction in 1998, which led to the
signing of a purchase and sale agreement with PP&L in late
September 1998. The purchase and sale agreement also included
the Company's 50% interest in the 13 megawatt West Enfield
hydro station on the Penobscot River. In late July 1999, the
Company received $10 million in proceeds from the transfer of
the economic interest in that project, and in late August
1999, the MPUC approved the sale to PP&L of PHC. The Company
has utilized a significant portion of the net proceeds of the
sale to reduce outstanding debt and preferred stock.
The Company realized a net gain on the sale related to the
PP&L sale of approximately $24.8 million, and $24.3 million
of this amount has been recorded as a deferred liability at
December 31, 1999 on the Consolidated Balance Sheets.
Included in the determination of the deferred gain on sale is
the accrual of carrying costs on the deferred gain balance,
the selling and closing costs associated with the asset sale,
the costs incurred for the early retirement of debt and
preferred stock through the utilization of asset sale
proceeds, income tax expense impacts associated with the
asset sale gain, and the net expense associated with the sale
of its generating assets and the simultaneous purchased power
buyback agreement with PP&L (see below for a discussion of
the net expense). As specified in the most recent rate order
from the MPUC, which is discussed below, the deferred gain
will be utilized over a 70 month period to reduce electric
rates effective March 1, 2000. As discussed in Note 6, the
other $.5 million of the gain on the sale of Penobscot Hydro
that is allocable to shareholders, pursuant to orders of the
MPUC, has been recorded as other income in 1999.
As discussed in the 1998 Form 10-K, 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 Company realized a net gain from the sale of
$5.1 million, which has been recorded as a deferred liability
at December 31, 1999. Included in the determination of this
deferred gain is the accrual of carrying costs on the
deferred gain balance, the selling and closing costs
associated with the asset sale, and the net savings
associated with the sale of these assets (through reduced
depreciation and property tax expense, and the return on
these assets included in the Company's rates through March 1,
2000). Consistent with the deferred gain on sale of
generating assets discussed above, this $5.1 million gain
will also be utilized to reduce electric rates starting March
1, 2000.
In connection with the sale, the $6.2 million in proceeds
were deposited with a third party trustee, as a requirement
under the Company's bond indenture. The $6.2 million was
released by the trustee in January 1999 and was 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. As of December 31, 1999,
approximately $383,000 of this amount had been expended on
environmental remediation activities. Management does not
expect the total environmental remediation costs to exceed
$400,000.
As discussed above, as a result of the sale of the Company's
generation assets, the Company was required by the MPUC to
defer all savings, for the period from the asset sale through
February 29, 2000, associated with the sale of its generating
assets and the simultaneous purchased power buyback agreement
with PP&L. This included savings associated with the Casco
Bay Energy sale in September 1998. Any net savings or expense
for this period are to be flowed-back to/recovered from
customers effective with new rates on March 1, 2000. As of
December 31, 1999 the net expense recorded as a reduction of
the deferred asset sale gain amounted to approximately
$225,000. The reason for the net expense is due principally
to unusually high purchased power costs during the hot
weather in early June and in July 1999 to replace generation
lost from the asset sale to PP&L. Since these high costs
would not have occurred if the Company had not sold these
assets, the Company has recorded the net expense as a
reduction of the deferred asset sale gain.
Current Rate Proceedings - The Company has been involved in
rate proceedings with the MPUC since mid-1998 to determine
its revenue requirement as a T&D utility starting March 1,
2000 and the recoverability of the Company's stranded costs.
In February 2000, the Company received a final rate order
from the MPUC setting its T&D and stranded cost rates
effective March 1, 2000. The Company's total annual revenue
requirement as set in the rate proceedings, including $40
million associated with stranded cost recovery, amounted to
$103.2 million. The stranded cost recovery includes the
decommissioning and other plant closure expenses for Maine
Yankee.
In 2003 and every three years thereafter until the stranded
costs are recovered, the MPUC shall review and reevaluate the
stranded cost recovery. Customers reducing or eliminating
their consumption of electricity by switching to self-
generation, conversion to alternative fuels or utilizing
demand-side management measures cannot be assessed exit or
entry fees.
Deferral of Restructuring Related Costs - Also as part of the
restructuring law, employees, other than officers, displaced
as a result of retail competition are entitled to certain
severance benefits and retraining programs, and these costs
are recoverable through charges collected by the regulated
distribution company. In connection with this part of the
law, the Company incurred approximately $840,000 in benefit
costs associated with the employees terminated as a result of
the generation asset sale. This amount has been deferred as a
component of Other Regulatory Assets on the Consolidated
Balance Sheets as of December 31, 1999. In 1999, the Company
had also been incurring significant costs in connection with
implementing various aspects of the electric industry
restructuring. Consequently, the Company filed an accounting
order request with the MPUC in 1999 to seek the deferral of
certain incremental costs associated with this effort. In
September 1999 the Company received an accounting order from
the MPUC related to the Company's request which approved the
deferral of certain incremental restructuring related costs.
In connection with the accounting order, the Company has
deferred, as a component of Other Regulatory Assets on the
Consolidated Balance Sheets as of December 31, 1999,
approximately $829,000 of restructuring costs. As a result of
the current rate order received from the MPUC, the Company
will start recovery of the deferred restructuring costs
discussed above, amounting to $1.7 million, on March 1, 2000
over a three-year period. Based on the accounting order, the
Company will also defer, for future recovery, certain
additional incremental restructuring costs incurred from
January 1, 2000 through the advent of retail competition on
March 1, 2000.
Alternative Rate Plan Filing - In May 1999, the MPUC approved
a portion of the Company's February 1999 request for rate
adjustment under the so-called Alternative Rate Plan.
Pursuant to the MPUC Order, the Company implemented an
increase in its standard tariff of about 1.36% effective June
1, 1999. An alternative rate plan is a method of utility
regulation intended to replace the costly, controversial
periodic rate increase proceedings of the past. Under such a
plan, utilities are permitted to adjust rates annually based
on a formula tied to inflation minus a "productivity
factor". Adjustments for certain specified categories of
costs that are unrelated to inflation are also permitted. The
MPUC implemented this plan for the Company in 1998.
The 1999 increase was comprised entirely of the recovery of
some of the specified categories of costs that are unrelated
to inflation. This was made up mostly of the recovery of a
portion (about $1.4 million, or about 25%) of the costs
incurred to recover from the 1998 ice storm (see Note 11 ).
The inflation component actually contributed to a reduction
of the 1999 adjustment because the productivity factor offset
of 1.2% exceeded the inflation rate of .9%. The Alternative
Rate Plan will not be in effect with the implementation of
new rates on March 1, 2000, and the Company is uncertain if
any alternative rate plan will be adopted in the future.
Regulatory Assets and Meeting the Requirements of SFAS 71-
The Company is subject to the provisions of Statement of
Financial Accounting Standards No. 71, "Accounting for the
Effects of Certain Types of Regulation" (SFAS 71). SFAS 71
allows the establishment of regulatory assets for costs
accumulated for certain items other than the usual and
customary capital assets, and allows the deferral of the
income statement impact of those costs if they are expected
to be recovered in future rates. As of December 31, 1999, the
Company has regulatory assets, net of regulatory liabilities,
of approximately $189 million. The Company continues to meet
the requirements of SFAS 71 since the Company's rates are
intended to recover the cost of service plus a rate of return
on the Company's investment, as well as providing specific
recovery of costs deferred in prior periods.
The recent legislation enacted in Maine associated with
industry restructuring specifically addressed the issue of
cost recovery of regulatory assets stranded as a result of
industry restructuring. Specifically, the legislation
requires the MPUC, when retail access begins, to provide a
"reasonable opportunity" for the recovery of stranded costs
through the rates of the transmission and distribution
company, comparable to the utility's opportunity to recover
stranded costs before the implementation of retail access
under the legislation. The final rate order from the MPUC
effective March 1, 2000 did not result in the Company writing
off any stranded costs, but if the Company had not been
allowed full recovery of its stranded costs, it would be
required to write-off any disallowed costs. As provided for
in Emerging Issues Task Force Issue No. 97-4, "Deregulation
of the Pricing of Electricity," the Company will continue to
record regulatory assets in a manner consistent with SFAS 71
as long as future recovery is probable, since the Maine
legislation provides the opportunity to recover regulatory
assets including stranded costs through the rates of the T&D
company. The Company anticipates, based on current generally
accepted accounting principles, that SFAS 71 will continue to
apply to the regulated T&D segments of its business.
If the Company failed to meet the requirements of SFAS 71,
due to legislative or regulatory initiatives, the Company
would be required to revert to Statement of Financial
Accounting Standards No. 101, "Regulated Enterprises-
Accounting for the Discontinuation of Application of FASB No.
71" (SFAS 101). If, under SFAS 101, legislative or
regulatory changes and/or competition result in electric
rates which do not fully recover the Company's costs, a
write-down of assets could be required. The Company does not
anticipate any write-down of assets at this time.
Standard Offer Service - The restructuring law also provided for
a standard-offer service being available for all customers
who do not choose to purchase energy from a competitive
supplier starting March 1, 2000. The MPUC solicited bids from
competitive energy suppliers to provide energy under the
standard offer service, but all bids were rejected as too
high. Consequently, as permitted by the Maine legislature,
the MPUC has ordered the Company to assume the responsibility
of being the standard offer service provider starting March
1, 2000 for a one-year period. The MPUC has established the
schedule of rates that the Company may charge for the
standard offer service. The Company must purchase the energy
for these customers from third parties, and the MPUC has
allowed the Company to defer the difference between the
revenues realized from the standard offer sales and the costs
incurred to provide this service. This deferred amount will
be recovered from/returned to customers in a future rate
proceeding.
Note 11. Storm Damage
- ---------------------
As discussed in the 1998 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 these had been deferred as of
December 31, 1998. The MPUC issued an order authorizing the
Company to defer incremental, non-capitalized storm damage
expenses for future recovery through the rates charged to
customers. As discussed in Note 10, the Company began
recovering these deferred costs starting on June 1, 1999,
over a four-year period, as part of its annual rate
adjustment pursuant to its Alternative Rate Plan. In October
1999, the Company received approximately $1.8 million in
funds from the state of Maine as its share of the state's
federal assistance. The $1.8 million was recorded as a
reduction of the deferred ice storm costs, and the deferred
balance as of December 31, 1999, which amounted to $1.9
million, is included as a component of Other Regulatory
Assets on the Consolidated Balance Sheets. In connection with
the Company's recent rate order from the MPUC, the
amortization and recovery of these deferred costs were
adjusted to reflect the receipt of the federal funds.
Note 12. Construction of Facilities for Casco Bay Energy
- --------------------------------------------------------
The Company has an agreement with Casco Bay whereby the
Company has agreed to construct various transmission
facilities required to allow a generating facility being
constructed in Veazie, Maine to interconnect with the
Company's electrical system and deliver its output to the New
England Power Pool Transmission Facility (PTF) grid. Under
this agreement, Casco Bay has agreed to advance funds
necessary to pay for such construction. In the event that the
new facilities qualify as PTF and the FERC approves an
amendment to the NEPOOL Agreement which provides for cost
sharing of such construction costs, approximately 50% of the
construction funds advanced would be refunded to Casco Bay by
customers of NEPOOL over an approximately 30-year period. At
the end of 1999, the Company had recorded $3.8 million for
PTF facilities and a corresponding Long-term Payable subject
to such potential treatment. These amounts are included on
the Consolidated Balance Sheets as components of Electric
Plant in Service and Other Long-term Liabilites,
respectively.
Note 13. Derivative Financial Instruments
- -----------------------------------------
Interest Rate Caps - In 1995, the Company entered into
interest rate cap agreements (the cap or caps) with three
financial institutions related to its $60 million of medium
term notes to manage its exposure to interest rate
fluctuations. Under the caps, the LIBO rate was capped at
7.25% over the five-year term of the medium term notes for
the full notional amount of $60 million. At the beginning of
each calendar quarter the notional interest rate was set by
the financial institutions based on the current LIBO rate.
The Company was to be reimbursed for incremental interest
expense incurred in excess of the 7.25% cap. During 1997,
1998 and 1999, through the date of the final repayment of the
medium term notes in May 1999, the notional rate was not in
excess of 7.25%. This interest rate cap is no longer
providing interest rate risk management due to the repayment
of this debt.
Fuel Swaps - Through the advent of retail competition on March
1, 2000, the Company purchased, rather than generated itself,
virtually all of the energy required to service its retail
business. These purchased energy prices varied with changes
in the price or availability of the underlying fuel sources,
and the risk of such price volatility was not covered by a
rate mechanism, such as a fuel adjustment clause. A
significant portion of the Company's exposure to purchased
energy price volatility had been closely matched to changes
in residual oil prices. To manage the oil-related risk of
energy price fluctuations, the Company had entered into
agreements known as "swaps", essentially in which the
Company agreed to pay a fixed price for a specific quantity
of a specific commodity (residual oil in this case), for a
given time period. This transferred the risk (or the benefit)
of commodity price fluctuations to the other party to the
agreement for the given period of time. These were strictly
financial transactions, and no delivery of the underlying
commodity was taken. Settlements occurred on a monthly basis
and the cash receipts/payments arising from the "swap"
transactions offset corresponding increases/decreases in the
Company's purchased energy costs.
The Company entered into "swap" transactions for 1999 and
1998 amounting to 1,600,000 and 1,180,000 barrels of residual
oil, respectively. As a result of market movements in 1999
and 1998 the Company received cash payments of
approximately $1.8 million in 1999 and made cash payments of
$5.1 million in 1998 associated with the swap
transactions.
The cash paid/received from the "swaps" was recorded as an
increase/reduction in fuel for generation and purchased power
expense in the Consolidated Statements of Income. As a result
of these hedging activities, the Company managed a
substantial portion of the risk of energy price fluctuations,
which allowed the Company to more accurately predict its
future purchased energy costs and cash flow requirements. To
ensure the Company maintained a hedging, and not a
speculative position, the Company had established official
policies, procedures and controls for its fuel hedging
program.
The Company managed the credit risk related to the fuel swaps
through credit limits, collateral instruments, monitoring
procedures, and diversification of counterparties. Basis risk
was the risk that changes in the Company's costs did not move
perfectly in tandem with the index/commodity specified in the
swap. While basis risk existed with the residual oil swaps,
the relationship between the Company's oil related purchased
power costs and the index was highly correlated. As a result
of the achievement of this high degree of correlation, the
"swaps" were accounted for as hedges, and were not
speculative financial instruments.
At December 31, 1999, the Company was a party to "swaps"
covering 265,000 barrels of residual oil for the first two
months of the year 2000. With the advent of retail
competition in the electric utility industry starting March
1, 2000, and the Company providing only standard offer
service to customers in the retail market, the utilization of
fuel swaps will no longer be required (see Note 10). The
Company received approximately $2.1 million in cash payments
associated with swap transactions in January and February
2000.
Interest Rate Swap - As discussed in Note 4, in connection with
the $24.8 million in BERI medium term notes, BERI entered
into an interest rate swap arrangement with a major financial
institution to provide interest rate protection through the
maturity date of the term loan. The interest rate swap fixed
the LIBO interest rate on the medium term notes at 5.72%.
BERI will be reimbursed for incremental interest expense
incurred in excess of the 5.72% and incurs additional expense
for incremental interest expense below 5.72%. Market risk is
the potential loss arising from adverse changes in interest
rates. The fair value of the interest rate swap at December
31, 1999 is a negative $203,769 and represents the estimated
payment that would be made to terminate the agreement.
Note 14. Contingencies
- ----------------------
Environmental Matters - In 1992, the Company received notice
from the Maine Department of Environmental Protection that it
was investigating the cleanup of several sites in Maine that
were used in the past for the disposal of waste oil and other
hazardous substances, and that the Company, as a generator of
waste oil that was disposed at those sites, may be liable for
certain cleanup costs. The Company learned in October 1995
that the United States Environmental Protection Agency placed
one of 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.
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 this waste disposal site. 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, 1999, the liability
recorded by the Company for its estimated environmental
remediation costs amounted to $331,000. The Company's actual
future environmental remediation costs may be higher as
additional factors become known.
PRICEWATERHOUSECOOPERS LLP
Report of Independent Accountants
To the Stockholders and Directors of Bangor Hydro-Electric Company:
In our opinion, the accompanying consolidated balance sheets and statements
of capitalization and the related consolidated statements of income, common
stock investment and cash flows present fairly, in all material respects, the
financial position of Bangor Hydro-Electric Company (the Company) and its
subsidiaries at December 31, 1999 and 1998, and the results of their
operations and their cash flows for each of the three years in the period
ended December 31, 1999 in conformity with accounting principles generally
accepted in the United States. These financial statements are the
responsibility of the Company's management; our responsibility is to express
an opinion on these financial statements based on our audits. We conducted
our audits of these statements in accordance with auditing standards
generally accepted in the United States, which require that we plan and
perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining,
on a test basis, evidence supporting the amounts and disclosures in the
financial statements, assessing the accounting principles used and
significant estimates made by management, and evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for the opinion expressed above.
February 9, 2000
/s/ PRICEWATERHOUSECOOPERS LLP
ITEM 7A QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
- ------- ----------------------------------------------------------
See Item 7, "Management's Discussion and Analysis of Results of
Operations and Financial Condition - Contingencies and Risk Management" and
Note 13 to the Consolidated Financial Statement included in Item 8, above,
for a discussion of certain derivative financial instruments held by the
Company.
ITEM 9 CHANGES IN AND DISAGREEMENTS WITH AUDIT FIRMS ON FINANCIAL
- ------ ----------------------------------------------------------
DISCLOSURE
- ----------
There have been no changes in or disagreements with audit firms on
financial disclosure.
PART III
- --------
ITEM 10 DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
- ------- --------------------------------------------------
The following table sets forth the nominees and the directors whose
terms continue, their ages, other positions held by them with the Company,
the date when they first became a director and their business experience
during the last five years (including any other directorship held by them in
any company with a class of securities registered pursuant to Section 12 of
the Securities Exchange Act of 1934 or subject to the requirements of Section
15(d) of that Act, or in any company registered as an investment company
under the Investment Company Act of 1940 (referred to in the table as
"Reporting Companies")):
Name and Became Business Experience During Last 5 Years
Position (Age) Director and Other Directorships
- -----------------------------------------------------------------------------
CLASS II (NOMINEES FOR TERM EXPIRING IN 2000)
Robert S. Briggs (56)
Chairman of the Board, President
& Chief Executive Officer
1985 Chairman of the Board; President and Chief
Executive Officer of the Company; Director
of Maine Yankee Atomic Power Company;
Trustee of Eastern Maine Medical Center
William C. Bullock, Jr. (63)
Director 1982 Chairman of the Board and Director of
Merrill Merchants Bancshares, Inc. (a
reporting company) and its subsidiary,
Merrill Merchants Bank; Director of
Eastern Maine Healthcare
Joseph H. Cyr (59)
Director 1998 President of John T. Cyr & Sons, Inc., a
school and charter bus company; Director
of Merrill Merchants Bancshares, Inc. (a
reporting company) and its subsidiary,
Merrill Merchants Bank
CLASS I (DIRECTORS WHOSE TERMS EXPIRE IN 2002)
Marion M. Kane (55)
Director 1996 President of the Barr Foundation,
a not-for-profit charitable organization
that manages a charitable trust;
until December 31, 1999, President
of the Maine Community Foundation,
a not-for-profit charitable foundation
that manages a pool of individual
charitable funds; Director of Maine
Bank and Trust Company
Norman A. Ledwin (58)
Director 1996 President and Chief Executive
Officer and a Director of Eastern
Maine Healthcare, a healthcare
organization made up of not-for-
profit and for-profit entities
(including Eastern Maine Medical
Center, a not-for-profit regional
acute care hospital facility
James E. Rier, Jr.(54)
Director 1998 President of Rier Motors Co., an
automobile dealership located in Machias,
Maine
CLASS III (DIRECTORS WHOSE TERMS EXPIRE IN 2001)
Carroll R. Lee (50)
Senior Vice President
& Chief Operating Officer
and Director 1991 Senior Vice President and Chief Operating
Officer of the Company; Director of Maine
Yankee Atomic Power Company; Director of
Maine Electric Power Company, Inc.;
President of the Board of Community
Health and Counseling Service, a not-for-
profit supplier of home and mental health
care services
David M. Carlisle (61)
Director 1989 President, Prentiss & Carlisle Companies,
a timberland management company; Director
of Bangor Savings Bank; Director of
Eastern Maine Healthcare
Jane J. Bush (54)
Director 1990 Vice President and co-owner of Coastal
Ventures, a retailing company
The Board of Directors has three standing committees: an Audit
Committee, an Investment Committee and a Compensation Committee. The Audit
Committee, consisting of Ms. Bush (Chair), Mr. Carlisle, Mr. Rier and Ms.
Kane reviews with the independent public accountants the scope and results
of their audit and other services to the Company, reviews the adequacy of the
Company's internal accounting controls and reports to the Board as necessary.
The Compensation Committee, consisting of Mr. Bullock (Chair), Mr. Cyr and
Mr. Ledwin, reviews the Company's executive compensation and compensation
policies in general, and makes recommendations to the full Board of
Directors. The Investment Committee, consisting of Mr. Bullock (Chair), Mr.
Carlisle, Ms. Kane, Mr. Briggs and other non-director members of management,
oversees the investments of the Company's pension funds. The Board does not
have a nominating or similar committee. Committee appointments will be
reviewed after the Annual Meeting. Directors who are not employees of the
Company appoint from their own number the members of the Audit Committee and
the Compensation Committee. Other committee assignments are made by the
Chairman of the Board.
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 56 President & Chief Executive
Officer since January 1991
Carroll R. Lee 50 Senior Vice President and
Chief Operating Officer since
December, 1996
Frederick S. Samp 49 Vice President - Finance &
Law since 1995; Chief Financial
Officer since 1995
Paul A. LeBlanc 52 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,
General Counsel, Corporate Secretary and Clerk from 1988 until 1995, and
Treasurer from 1995 until 1999. 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 11 EXECUTIVE COMPENSATION
- ------- ----------------------
The following table shows, for the fiscal years ending December 31,
1999, 1998 and 1997, the cash compensation paid by the Company to the Chief
Executive Officer and to the other executive officers whose total salary and
bonus exceeded $100,000:
SUMMARY COMPENSATION TABLE - ANNUAL COMPENSATION
Other Annual
Name and Principal Position Year Salary Bonus Compensation*
- -------------------------------------------------------------------------
Robert S. Briggs 1999 $207,549 $66,499 $3,200
Chairman of the Board, President 1998 $200,981 $41,726 $3,200
& Chief Executive Officer 1997 186,170 12,175 3,724
Carroll R. Lee 1999 $161,149 $37,968 $3,200
Senior Vice President & 1998 $153,645 $24,468 $3,200
Chief Operating Officer 1997 140,663 9,899 2,813
Frederick S. Samp 1999 $112,574 $21,457 $2,527
Vice President-Finance & Law 1998 $101,807 $14,337 $2,159
Paul A. LeBlanc 1999 $101,031 $19,197 $2,246
Vice President - Human Resources 1998 $ 94,961 $12,093 $1,984
& Information Services
* For each named executive officer, Other Annual Compensation consists of the
Company's matching contribution to a 401(k) Plan.
The executive officers participate in a defined benefit pension plan
that is also applicable to all employees. In addition, the executive
officers are parties to Supplemental Benefit Agreements with the Company
under which additional retirement benefits are to be paid. Said agreements
define the total pension amount to be paid to the executive officer by the
Company, with the supplemental amount defined as the difference between this
total amount due and the amount due to the executive officer under the tax
qualified pension plan. These supplemental benefits are not funded, although
the Company maintains insurance policies on the lives of the executive
officers that would reimburse the Company for the cost of the benefits upon
the death of the covered officer. The total amount of pension benefit, as
defined under the Supplemental Benefit Agreements, is a function of the
executive officer's age at retirement and his average total compensation over
a three year period. Under the Supplemental Benefit Agreements, no pension
amount would be due until the executive officer reaches age 55. At age 55,
the executive officer would be entitled to receive 50% of his or her average
total compensation over a three year period. The total pension amount to be
paid upon retirement would increase proportionately until a retirement age of
62, at which point the executive officer would be entitled to receive 75% of
his or her average total compensation over a three year. The following table
sets forth estimated annual benefit amounts payable upon retirement to the
executive officers:
Age at Retirement
- -----------------------------------------------------------------------------
Average Total
Compensation 55 56 57 58 59 60 61 62+
$100,000 $50,000 $53,000 $57,000 $60,000 $64,000 $68,000 $72,000 $75,000
$150,000 75,000 79,500 85,500 90,000 96,000 102,000 108,000 112,500
$200,000 100,000 106,000 114,000 120,000 128,000 136,000 144,000 150,000
$250,000 125,000 132,500 142,500 150,000 160,000 170,000 180,000 187,500
$300,000 150,000 159,000 171,000 180,000 192,000 204,000 216,000 225,000
Compensation covered by both the under the defined plan applicable to
all employees and the Supplemental Retirement Agreements is total basic
compensation exclusive of overtime, bonuses, and other extra, contingent or
supplemental compensation, and inclusive of compensation deferred pursuant to
the Company's Section 401(k) Plan. It is essentially the same as the amount
shown as "Salary" in the Summary Compensation Table above. Compensation
covered under the tax qualified pension plan is limited to the amount set
forth in IRC Section 415. Compensation covered by the Supplemental Benefit
Agreements is total compensation inclusive of bonuses, and other, contingent
or supplemental compensation, and compensation deferred pursuant to the
Company's Section 401(k) Plan. It is essentially the same as the amount shown
as "Salary" and "Bonus" in the Summary Compensation Table above.
"Average Total Compensation" for both plans is computed using the
average of the total annual compensation actually paid by the Company to the
Executive during the three (3) consecutive calendar years in which the
Executive's total compensation from the Company was the highest.
The total annual pension amounts shown in the Pension Plan Table above
are payable for the remainder of the executive officer's life after
retirement. If the executive officer's spouse survives the executive
officer, the spouse will receive an annual benefit for the remainder of her
life equal to 50% of the annual benefit to the executive officer. The total
annual pension amounts shown in the Pension Plan Table are not subject to any
deduction for Social Security or other offset amounts.
The named executive officers are parties to agreements under which in
the event 1) of a change of control of the Company as defined in the
agreements and 2) the covered party leaves the employment of the Company
within one year after the change of control, he would be entitled to receive
a payment equal to two years' salary (three years' salary if he is not
eligible for early retirement under the defined benefit pension plan at the
time) based upon his average salary over the past five years. He would also
be entitled to receive the Company's standard health, life insurance and
disability benefits for a period of two years.
The executive officers also participate in a long-term disability income
plan which is also applicable to all employees. Under the plan, after 90 days
of disability, employees are entitled to receive 66 2/3% of their basic
monthly earnings up to a maximum monthly benefit of $5,000.
ITEM 12 SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
- ------- -----------------------------------------------
AND MANAGEMENT
--------------
(a) Security Ownership of Certain Beneficial Owners
The following table sets forth as of December 31, 1999 information with
respect to persons known to management to be the beneficial owners of more
than 5% of any class of voting securities of the Company:
Title of Class: Common Stock
Name and Address of Beneficial Owner:
FMR Corp.
82 Devonshire Street
Boston, Massachusetts 02109
Amount and Nature of Beneficial Ownership: 736,300 shares
Percent of Class: 10.0%
(b) Security Ownership of Management
The following table sets forth as of February 28, 1999 information with
respect to the beneficial ownership of equity securities by directors,
nominees for the office of director and named executive officers:
Title of Class Name of Beneficial Owner Beneficially Owned*
- --------------------------------------------------------------------
Common Robert S. Briggs 5,244
Preferred Robert S. Briggs 28
Common William C. Bullock, Jr. 10,000
Common Jane J. Bush 300
Common David M. Carlisle 2,427
Common Joseph H. Cyr 1,683
Common Marion M. Kane 260
Common Paul A. LeBlanc 452
Common Norman A. Ledwin 180
Common Carroll R. Lee 1,930
Common James E. Rier, Jr. 300
Common Frederick S. Samp 349
Common Directors & Executive
Officers as a group (11) 23,152
Preferred Directors & Executive
Officers as a group (11) 28
* The directors and executive officers of the Company as a group own a
beneficial interest in less than 1% of the Company's Common and Preferred
Stock.
(c) Changes in Control
Not applicable.
ITEM 13 CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
- ------- ----------------------------------------------
COMPENSATION COMMITTEE INTERLOCKS - During 1999, Mr. Briggs, the Chairman of
the Company's Board of Directors and its President and Chief Executive
Officer, served as a Trustee of Eastern Maine Medical Center, a hospital
facility located in Bangor, Maine. Mr. Ledwin, who serves on the Board's
Compensation Committee, is President, Chief Executive Officer and a Director
of Eastern Maine Healthcare, the organization that owns and operates Eastern
Maine Medical Center.
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS - During 1999, the Company
made payments to Eastern Maine Healthcare, its subsidiaries and affiliates,
of $1,030,777. Mr. Ledwin, who serves on the Board of Directors and the
Board's Compensation Committee, is President, Chief Executive Officer and a
Director of Eastern Maine Healthcare. Eastern Maine Healthcare owns and
operates Eastern Maine Medical Center, the second largest hospital in the
State of Maine and the largest in the region served by the Company, as well
as several other health care organizations in the region. The Company
provides health care benefits to its employees through a self insured managed
care plan. An independent plan administrator negotiates on behalf of the
Company the rates for health care services paid to individual providers under
the plan, including Eastern Maine Healthcare and its affiliates.
PART IV
- -------
ITEM 14 EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS
- ------- ----------------------------------------------------
ON FORM 8-K
-------------
(a) Consolidated Financial Statements of the Company
covered by the Report of the of Independent
Auditors (See Item 8):
Consolidated Statements of Income for the Years Ended
December 31, 1999, 1998 and 1997
Consolidated Balance Sheets - December 31, 1999 and
1998
Consolidated Statements of Common Stock Investment
for the Years ended December 31, 1999, 1998 and 1997
Consolidated Statements of Capitalization - December
31, 1999 and 1998
Consolidated Statements of Cash Flows
for the Years Ended December 31, 1999, 1998 and 1997
Notes to Consolidated Financial Statements
Report of Independent Accountants
(b) Schedules
Report of Independent Accountants
Schedule VIII - Reserves for Doubtful Accounts and Insurance
All other schedules are omitted as the required information is
inapplicable or the information is presented in the Company's
consolidated financial statements or related notes.
(c) Exhibits
See Exhibit Index, page
(d) Reports on Form 8-K
The Company has no current reports on Form 8-K.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed
on its behalf by the undersigned, thereunto duly authorized.
Bangor Hydro-Electric Company
/s/ Robert S. Briggs
---------------------------
By: Robert S. Briggs
President and
Chairman of the Board
Pursuant to the requirements of the Securities and Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dates indicated.
/s/ Robert S. Briggs /s/ Marion M. Kane
- ---------------------- ---------------------
Robert S. Briggs Marion M. Kane
President and Director
Chairman of the Board
/s/ William C. Bullock, Jr. /s/ Norman A. Ledwin
- --------------------------- --------------------
William C. Bullock, Jr. Norman A. Ledwin
Director Director
/s/ Jane J. Bush /s/ James E. Rier, Jr.
- ----------------- -----------------------
Jane J. Bush James E. Rier, Jr.
Director Director
/s/ David M. Carlisle /s/ Carroll R. Lee
- --------------------- ------------------
David M. Carlisle Carroll R. Lee
Director Director, Senior Vice
President and Chief
Operating Officer
/s/ Joseph H. Cyr /s/ Frederick S. Samp
- ----------------- ----------------------
Joseph H. Cyr Frederick S. Samp
Director Vice President - Finance & Law
(Chief Financial Officer)
/s/ David R. Black
-------------------
David R. Black
Controller
(Chief Accounting Officer)
Each of the above signatures is affixed as of March 15, 2000.
PRICEWATERHOUSECOOPERS LLP
Report of Independent Accountants on
Financial Statement Schedules
To the Stockholders and Directors
of Bangor Hydro-Electric Company:
Our report on the consolidated financial statements of Bangor Hydro-Electric
Company is included in Item 8 of the Form 10-K. In connection with our
audits of such financial statements, we have also audited the financial
statement schedule listed in the index in Item 14(b) of this Form 10-K. In
our opinion, this financial statement schedule presents fairly, in all
material respects, the information set forth therein when read in
conjunction with the related consolidated financial statements.
February 9, 2000
/s/ PRICEWATERHOUSECOOPERS LLP
SCHEDULE VIII
RESERVES FOR DOUBTFUL ACCOUNTS AND INSURANCE
--------------------------------------------
Additions
------------------------
Balance at Charged to Charged to Balance at
Beginning Costs and Other End
Of Period Expenses Accounts Deductions of Period
------- ------- ------- ------- -------
1999
Reserve for Doubtful Accounts $ 1,075,000 $ 1,475,395 $ - $ 1,475,395 (A) $ 1,075,000
----------- ----------- ---------- ----------- -----------
1998
Reserve for Doubtful Accounts $ 1,450,000 $ 1,345,536 $ - $ 1,720,536 (A) $ 1,075,000
----------- ----------- ---------- ----------- -----------
1997
Reserve for Doubtful Accounts $ 1,450,000 $ 1,401,313 $ - $ 1,401,313 (A) $ 1,450,000
----------- ----------- ---------- ----------- -----------
NOTE:
(A) Accounts written off, less recoveries. For 1998 includes reduction in reserve for
doubtful accounts of $375,000.
EXHIBIT INDEX
Exhibits Filed Herewith
-----------------------
Exhibit No. Description of Exhibit
- ----------- ---------------------
10. Material Contracts
------------------
10(a) Asset Purchase Implementation
Agreement, dated as of May 27,
1999, by and among Bangor Hydro-
Electric Company, Penobscot Hydro
Co., Inc. and Penobscot Hydro, LLC
10(b) 33rd Amendment to the NEPOOL
Agreement dated December 1, 1996
10(c) Form of Agreement with
certain Executive Officers
providing benefits upon
a change of control
10(d) Form of Agreement with
certain Executive Officers
providing supplemental
death and retirement
benefits
Exhibits Incorporated Herein by Reference
-----------------------------------------
Exhibit No. Description of Exhibit Incorporated by Reference To:
- ----------- ---------------------- ----------------------------
3. Articles of Incorporation & By-Laws
-----------------------------------
3.1 Company's Certificate Form S-2, Reg. No. 33-39181,
of Organization, together Exhibit 3.1
with all amendments thereto
3.2 Articles of Amendment Form S-2, Reg. No. 33-63500,
increasing Company's Exhibit 4.3
authorized capital stock
3.3 Articles of Amendment Form 10-K, 1995, Exhibit 3(a)
changing Corporate Clerk
3.4 By-Laws of the Company Form S-2, Reg. No. 33-63500,
Exhibit 4.4
3.5 Articles of Amendment Form 10-K, 1998, Exhibit 3(a)
Allowing Use of Similar Name
4. Instruments Defining the Rights of Security Holders
---------------------------------------------------
4.1 Mortgage and Deed of Form S-1, Reg. No. 2-54452,
Trust dated as of Exhibit 4(b)(1)
July 1, 1936, re
First Mortgage Bonds
4.2 Supplemental Indenture Form S-1, Reg. No. 2-54452,
dated as of December 1, Exhibit 4(b)(2)
1945, amending the
Mortgage
4.3 Supplemental Indenture Form S-1, Reg. No. 2-54452
dated as of September 1, Exhibit 4(b)(4)
1969, re 8 1/4% Series
Bonds, together with form
of purchase agreement.
(Supplemental indentures
and purchase agreements
with respect to prior
issues are substantially
identical in substantive
content to the 8 1/4%
Series documents).
4.4 Supplemental Indenture Form 10-K, 1975, Exhibit B
dated as of November 1,
1975, re 10 1/2% Series
Bonds, together with form
of purchase agreement
4.5 Supplemental Indenture Form 8-K, 6/28/76, Exhibit A
dated as of June 1, 1976,
re 9 1/4% Series Bonds
4.6 Supplemental Indenture Form S-7, Reg. No. 2-61589,
dated as of January 1, Exhibit 5(a)(7)
1978, re 8.6% Series
Bonds, together with form
of purchase agreement
4.7 Supplemental Indenture Form 10-Q, 3rd Quarter 1979,
dated as of August 1, Exhibit A
1979, re 10.25% Series
Bonds, together with form
of purchase agreement
Common Stock Purchase Plan
4.8 Supplemental Indenture Form 10-Q, 1st Quarter, 1981,
dated as of April 1, Exhibit A
1981 re 15.25% Series
Bonds, together with form
of purchase agreement
4.9 Supplemental Indenture Form 10-Q, 2nd Quarter 1981,
dated as of July 30, Exhibit (4)
1981 re 16.50% Series
Bonds, together with form
of purchase agreement
4.10 Bond Purchase Agreement, Form 10-K, 1983, Exhibit 4(a)
including form of
supplemental indenture,
with respect to First
Mortgage Bonds, 12.50%
Series due 1998
4.11 Bond Purchase Agreement, Form 10-K, 1984, Exhibit 4(a)
including form of
supplemental indenture,
with respect to First
Mortgage Bonds, 17.35%
Series due 1994
4.12 Bond Purchase Agreement Form 10-Q, First Quarter,
dated as of March 1, 1989 1989, Exhibit 4.1
including form of
supplemental indenture,
with respect to First
Mortgage Bonds, 10.25%
Series due 2019
4.13 Bond Purchase Agreement Form 10-K, 1990, Exhibit 4(b)
dated as of June 15, 1990
including form of
supplemental indenture,
with respect to First
Mortgage Bonds, 10.25%
Series due 2020
4.14 Loan Agreement by and Form 10-Q, 3rd Quarter 1995,
Finance Authority of Exhibit 4.1
Maine and Bangor Hydro-
Electric Company
4.15 Purchase Contract dated Form 10-Q, 3rd Quarter 1995,
as of June 28, 1995 among Exhibit 4.3
the Finance Authority of
Maine and Bangor Hydro-
Electric Company and
Prudential Securities
Incorporated
4.16 General and Refunding Form 10-Q, 3rd Quarter 1995,
Mortgage Indenture and Exhibit 4.4
Deed of Trust - Bangor
Hydro-Electric Company
to Chemical Bank, As
Trustee, Dated as of
June 1, 1995
4.17 Supplemental Indenture Form 10-Q, 3rd Quarter 1995,
Dated as of June 15, 1995 Exhibit 4.5
to General and Refunding
Mortgage Indenture and Deed
of Trust dated as of June
1, 1995 (Bangor Hydro-
Electric Company to Chemical
Bank).
4.18 Supplemental Indenture as Form 10-Q, 3rd Quarter 1995,
of June 29, 1995 to
Mortgage and Deed of Trust
dated as of July 1, 1936
(Bangor Hydro-Electric
Company to Citibank, N.A.
at Trustee).
4.19 Supplemental Indenture Form 10-K, 1995, Exhibit 4(a)
Dated as of October 1, 1995 (Identified as Exhibit 10(a))
to General and Refunding
Mortgage and Deed of Trust
dated as of June 1, 1995
(Bangor Hydro-Electric
Company to Chemical Bank).
4.20 TERM LOAN AGREEMENT Form 10-Q, First Quarter 1998,
dated as of March 31, 1998 Exhibit 4(a)
among BANGOR ENERGY RESALE,
INC., BANKBOSTON, N.A. and
the certain other lending
institutions and
BANKBOSTON, N.A., as Agent,
including all Exhibits thereto
4.21 GUARANTY, dated as of March 31, Form 10-Q, First Quarter 1998,
1998, by BANGOR HYDRO Exhibit 4(b)
-ELECTRIC COMPANY, in favor of
(a) BANKBOSTON, N.A., as Agent,
for itself and the other
lending institutions which are
or may become parties to a Term
Loan Agreement, dated as of
March 31, 1998
4.22 Warrant to Purchase Form 10-Q, Second Quarter 1998,
Common Stock Granted to Exhibit 4(a)
the Municipal Review
Committee, Inc. on
June 26, 1998
4.23 Warrant to Purchase Form 10-Q, Second Quarter 1998,
Common Stock Dated Exhibit 4(b)
Granted to PERC
Management Company
Limited Partnership on
June 26, 1998
4.24 Warrant to Purchase Form 10-Q, Second Quarter 1998,
Common Stock Granted to Exhibit 4(c)
Energy National, Inc. on
June 26, 1998
4.25 Supplemental Indenture Form 10-Q, Second Quarter 1998,
Dated as of June 29, 1998 Exhibit 4(d)
between the Company and
Citibank, N.A.
10. Material Contracts
------------------
10.1 New England Power Pool Form S-7, Reg. No. 2-69904,
Agreement dated as of Exhibit 10(a)(3)
September 1, 1971, with
all amendments through
December 1980
10.2 Copy of Twelfth Amendment Form S-7, Reg. No. 2-69904,
dated as of June 16, 1980 Exhibit 10(a)(4)
to the Agreement for Joint
Ownership, Construction and
Operation of New Hampshire
Nuclear Units
10.3 Participation Agreement Form S-1, Reg. No. 2-54452,
dated June 20, 1969 Exhibit 13(a)(2)(a)-1
between Maine Electric
Power Company, Inc.
("MEPCO") and the Company
10.4 Agreement dated June Form S-1, Reg. No. 2-54452,
29, 1969 among Maine Exhibit 13(a)(2)(a)-2
participants in MEPCO
Participation Agreement
10.5 Power Contract dated Form S-1, Reg. No. 2-54452,
May 20, 1968 between Exhibit 13(a)(3)(a)
Maine Yankee Atomic
Power Company ("Maine
Yankee") and the
Company and other
utilities
10.6 Stockholder Agreement Form S-1, Reg. No. 2-54452,
dated May 20, 1968 Exhibit 13(a)(3)(b)
among stockholders of
Maine Yankee, (including
the Company).
10.7 Capital Funds Agreement Form S-1, Reg. No. 2-54452,
dated May 29,1968 Exhibit 13(a)(3)(c)
between Maine Yankee
and sponsors, including
the Company
10.8 Maine Yankee Transmission Form S-1, Reg. No. 2-54452,
Agreement dated April 1, Exhibit 13(a)(3)(d)
1971 among the Company
and other utilities
10.9 Modification of Maine Form S-1, Reg. No. 2-54452,
Yankee Transmission Exhibit 13(a)(3)(f)
Agreement of December
1, 1972
10.10 Agreement for Joint Form S-1, Reg. No. 2-54452,
Ownership, Construction Exhibit 13(a)(4)(a)
and Operation dated
November 1, 1974 of
Wyman Unit No. 4 among
Central Maine Power
Company, the Company
and other utilities
10.11 Amendment No. 1 dated Form S-1, Reg. No. 2-54452,
June 30, 1975 to Wyman 4 Exhibit 13(a)(4)(b)
Agreement of November 1,
1974
10.12 Transmission Agreement Form S-1, Reg. No. 2-54452,
dated November 1, 1974 Exhibit 13(a)(4)(c)
re Wyman Unit No. 4
among Central Maine
Power Company and other
utilities
10.13 Employee Stock Ownership Form S-7, Reg. No. 2-59747,
Plan, including related Exhibit 5(a)(2)
trust agreements, dated
June 1, 1977
10.14 Sample of binder relating Form S-7, Reg. No. 2-59747,
to contingent liability Exhibit 5(a)(4)
for nuclear incidents
10.15 Amendment No. 2 dated Form 10-K, 1976, Exhibit H(2)
August 16, 1976 to Joint
Ownership Agreement
dated November 1, 1974
with Central Maine Power
Company and others re
Wyman Unit No. 4
10.16 Forms of contracts Form 10-Q, 2nd Qtr. 1982,
concerning the Company's Exhibit 10
participation with
other New England
utilities in the
proposed Quebec
interconnection
10.17 Third Amendment dated Form 10-K, 1983, Exhibit 10.2
as of November 1, 1982
to Preliminary Quebec
Interconnection Support
Agreement
10.18 Second Amendment dated Form 10-K, 1983, Exhibit 10.3
as of November 1, 1982
to Agreement With
Respect to Use of
Quebec Interconnection
10.19 Amendment No. 2 dated Form 10-K, 1983, Exhibit 10.4
as of November 1, 1982,
to Phase 1 Terminal
Facility Support
Agreement (Quebec
Interconnection)
10.20 Amendment No. 2 dated Form 10-K, 1983, Exhibit 10.5
as of November 1, 1982
to Phase 1 Vermont
Transmission Line
Support Agreement
(Quebec Interconnection)
10.21 Fourth Amendment Form 10-Q, 1st Quarter 1983,
dated as of March 1, Exhibit 10.1
1983, to Preliminary
Quebec Interconnection
Support Agreement
10.22 Amendment dated as of Form 10-Q, 2nd Quarter 1983,
September 1, 1981 Exhibit 10.3
to New England Power
Pool Agreement
10.23 Amendment dated as of Form 10-Q, 2nd Quarter 1983,
June 1, 1982 to New Exhibit 10.4
England Power Pool
Agreement
10.24 Amendment dated as of Form 10-Q, 2nd Quarter 1983,
June 15, 1983 to New Exhibit 10.5
England Power Pool
Agreement
10.25 Amendment dated as of Form 10-Q, 3rd Quarter 1983,
October 1, 1983 to Exhibit 10.1
New England Power Pool
Agreement
10.26 Amendment No. 1 to the Form 10-K, 1983, Exhibit 10(b)
Maine Yankee Power
Contract
10.27 Amendment No. 2 to the Form 10-K, 1983, Exhibit 10(c)
Maine Yankee Power
Contract
10.28 Additional Power Con- Form 10-K, 1983, Exhibit 10(d)
tract between Maine
Yankee and its sponsors,
including the Company
10.29 Preliminary Support Form 10-K, 1984, Exhibit 10(b)
Agreement - Phase 2 of
Hydro-Quebec Inter-
connection
10.30 Amendment dated September 1, Form 10-K, 1985, Exhibit 10(b)
1985 to Agreement with
respect to Use of Quebec
Interconnection
10.31 Energy Contract dated Form 10-K, 1985, Exhibit 10(c)
March 1983 between NEPOOL
and Hydro-Quebec re:
Hydro-Quebec Phase I
interconnection project
10.32 Energy Banking Agreement Form 10-K, 1985, Exhibit 10(d)
dated March 1983 between
NEPOOL and Hydro-Quebec re
Hydro-Quebec Phase I
interconnection project
10.33 Interconnection Agreement Form 10-K, 1985, Exhibit 10(e)
dated March 1983 between
NEPOOL and Hydro-Quebec re:
Hydro-Quebec Phase I
interconnection project
10.34 Amendment dated September 1 Form 10-K, 1985, Exhibit 10(f)
1985 to NEPOOL Agreement
re: Hydro-Quebec Phase II
interconnection project
10.35 Firm Energy Contract dated Form 10-K, 1985, Exhibit 10(g)
October 14, 1985 between
New England utilities and
Hydro-Quebec re: Hydro-
Quebec Phase II
interconnection project
10.36 Boston Edison AC Facilities Form 10-K, 1985, Exhibit 10(h)
Support Agreement dated June
1, 1985 re: Hydro-Quebec
Phase II interconnection
project
10.37 Phase II New England Form 10-K, 1985, Exhibit 10(i)
Power AC Facilities
Support Agreement dated
June 1, 1985 re: Hydro-
Quebec Phase II
interconnection project
10.38 Phase II Massachusetts Form 10-K, 1985, Exhibit 10(j)
Transmission Facilities
Support Agreement dated
June 1, 1985 re: Hydro-
Quebec Phase II
interconnection project
10.39 Phase II New Hampshire Form 10-K, 1985, Exhibit 10(k)
Facilities Support
Agreement dated June 1,
1985 re: Hydro-Quebec
Phase II interconnection
project
10.40 First Amendment dated Form 10-K, 1985, Exhibit 10(l)
March 1, 1985 and Second
Amendment dated January 1,
1986 to Preliminary Quebec
Interconnection Support
Agreement - Phase II
10.41 Amendment No. 3 dated Form 10-K, 1985, Exhibit 10(m)
October 1, 1984 to Maine
Yankee Power Contract
10.42 Amendment No. 1 dated Form 10-K, 1985, Exhibit 10(n)
August 1, 1985 to Maine
Yankee Capital Funds
Agreement
10.43 Amendments dated August 1, Form 10-K, 1985, Exhibit 10(o)
1985, August 15, 1985, and
January 1, 1986 to
NEPOOL Agreement
10.44 Third Amendment to Vermont Form 10-Q, 1st Quarter 1986,
Transmission Line Support Exhibit 10.2
Agreement
10.45 First Amendment to Hydro- Form 10-Q, 1st Quarter 1986,
Quebec Phase I Intercon- Exhibit 10.3
nection Agreement
10.46 First Amendment to Hydro- Form 10-Q, 2nd Quarter 1986,
Quebec Phase II Exhibit 10.1
Massachusetts Trans-
mission Facilities
Support Agreement
10.47 First Amendment to Hydro- Form 10-Q, 2nd Quarter 1986,
Quebec Phase II New Exhibit 10.2
Hampshire Transmission
Facilities Support
Agreement
10.48 First Amendment to Hydro- Form 10-Q, 2nd Quarter 1986,
Quebec Phase II New England Exhibit 10.3
Power AC Facilities
Support Agreement
10.49 First Amendment to Form 10-Q, 2nd Quarter 1986,
Hydro-Quebec Phase II Exhibit 10.4
Boston Edison Company AC
Facilities Support
Agreement
10.50 Amendment Number 3 to Form 10-Q, 3rd Quarter 1986,
Hydro-Quebec Phase l Exhibit 10.1
Terminal Facility Support
Agreement
10.51 Amendment Number 3 to Form 10-Q, 3rd Quarter 1986,
Hydro-Quebec Phase I Exhibit 10.2
Vermont Transmission Line
Support Agreement
10.52 Power Sale Agreement for Form 10-Q, 3rd Quarter 1986,
sale of approximately Exhibit 10.3
31 MW of system power by
Bangor Hydro-Electric
Company to UNITIL
Power Corp.
10.53 Purchase Agreement with Form 10-Q, 3rd Quarter 1986,
respect to Wyman No. 4 Exhibit 10.4
between Bangor Hydro-
Electric Company and
Fitchburg Gas and Electric
Light Company
10.54 Power Purchase Agreement Form 10-K, 1986, Exhibit 10(i)
dated June 9, 1986 and
Amendment No. 1 thereto
dated January 14, 1987,
between the Company and
Bangor-Pacific Hydro
Associates (formerly West
Enfield Associates)
10.55 Power Sale Agreement dated Form 10-K, 1986, Exhibit 10(l)
August 1, 1986, and First
Amendment thereto, between
the Company and Unitil
Power Corp. re Wyman No. 4
10.56 Third Amendment to Pre- Form 10-K, 1987, Exhibit 10(a)
liminary Quebec Intercon-
nection Support Agreement -
Phase II
10.57 Fourth Amendment to Pre- Form 10-K, 1987, Exhibit 10(b)
liminary Quebec Intercon-
nection Support Agreement -
Phase II
10.58 Fifth Amendment to Pre- Form 10-K, 1987, Exhibit 10(c)
liminary Quebec Intercon-
nection Support Agreement -
Phase II
10.59 Sixth Amendment to Pre- Form 10-K, 1987, Exhibit 10(d)
liminary Quebec Intercon-
nection Support Agreement -
Phase II
10.60 Seventh Amendment to Pre- Form 10-K, 1987, Exhibit 10(e)
liminary Quebec Intercon-
nection Support Agreement -
Phase II
10.61 Amendment to New England Form 10-K, 1987, Exhibit 10(f)
Power Pool Agreement dated
March 1, 1988
10.62 Second Amendment to Credit Form 10-K, 1987, Exhibit 10(h)
Agreement, dated as of July
22, 1987, among the Company
and the Banks named therein
10.63 Dividend Reinvestment and Form 10-K, 1987, Exhibit 10(i)
Common Stock Purchase Plan
Effective as of December 1,
1987
10.64 Ninth Amendment to Form 10-K, 1988, Exhibit 10(b)
Preliminary Quebec
Interconnection Support
Agreement - Phase II
10.65 Tenth Amendment to Form 10-K, 1988, Exhibit 10(c)
Preliminary Quebec
Interconnection Support
Agreement - Phase II
10.66 Second Amendment to Form 10-K, 1988, Exhibit 10(d)
Massachusetts Trans-
mission Facilities
Support Agreement
10.67 Third Amendment to Form 10-K, 1988, Exhibit 10(e)
Massachusetts Trans-
mission Facilities
Support Agreement
10.68 Fourth Amendment to Form 10-K, 1988, Exhibit 10(f)
Massachusetts Trans-
mission Facilities
Support Agreement
10.69 Fifth Amendment to Form 10-K, 1988, Exhibit 10(g)
Massachusetts Trans-
mission Facilities
Support Agreement
10.70 Sixth Amendment to Form 10-K, 1988, Exhibit 10(h)
Massachusetts Trans-
mission Facilities
Support Agreement
10.71 Second Amendment to Form 10-K, 1988, Exhibit 10(i)
New Hampshire Trans-
mission Facilities
Support Agreement
10.72 Third Amendment to Form 10-K, 1988, Exhibit 10(j)
New Hampshire Trans-
mission Facilities
Support Agreement
10.73 Fourth Amendment to Form 10-K, 1988, Exhibit 10(k)
New Hampshire Trans-
mission Facilities
Support Agreement
10.74 Fifth Amendment to Form 10-K, 1988, Exhibit 10(l)
New Hampshire Trans-
mission Facilities
Support Agreement
10.75 Sixth Amendment to Form 10-K, 1988, Exhibit 10(m)
New Hampshire Trans-
mission Facilities
Support Agreement
10.76 Second Amendment to Form 10-K, 1988, Exhibit 10(n)
Phase II AC New England
Power Facilities Sup-
port Agreement
10.77 Third Amendment to Form 10-K, 1988, Exhibit 10(o)
Phase II AC New England
Power Facilities Sup-
port Agreement
10.78 Fourth Amendment to Form 10-K, 1988, Exhibit 10(p)
Phase II AC New England
Power Facilities Sup-
port Agreement
10.79 Fifth Amendment to Form 10-K, 1988, Exhibit 10(q)
Phase II AC New England
Power Facilities Sup-
port Agreement
10.80 Second Amendment to Form 10-K, 1988, Exhibit 10(r)
Phase II Boston Edison
AC Facilities Support
Agreement
10.81 Third Amendment to Form 10-K, 1988, Exhibit 10(s)
Phase II Boston Edison
AC Facilities Support
Agreement
110.82 Fourth Amendment to Form 10-K, 1988, Exhibit 10(t)
Phase II Boston Edison
AC Facilities Support
Agreement
10.83 Fifth Amendment to Form 10-K, 1988, Exhibit 10(u)
Phase II Boston Edison
AC Facilities Support
Agreement
10.84 Letter of Assurances, Form 10-K, 1988, Exhibit 10(v)
Consents and Agreements
With Respect to Credit
Facility Financing for
Phase II Hydro-Quebec
Financing
10.85 401 (k) Plan for Non- Form 10-K, 1988, Exhibit 10(x)
Union Employees
10.86 Agreement for the Form S-2, Reg. No. 33-39181,
Purchase and Sale of Exhibit 10.82
Electricity dated as of
June 21, 1984 between
Penobscot Energy Recovery
Company and the Company
10.87 Amendment No. 1 as of Form S-2, Reg. No. 33-39181,
March 24, 1986 to the Exhibit 10.83
Agreement for the Purchase
and Sale of Electricity
dated as of June 21, 1984
between Penobscot Energy
Recovery Company and the
Company
10.88 Partnership Agreement Form S-2, Reg. No. 33-39181,
dated as of July 1, 1990 Exhibit 10.85
between NORVARCO and
Bangor Var Co., Inc.
10.89 Purchase Agreement between Form 10-Q, 3rd Quarter 1995,
Babcock-Ultrapower Exhibit 10.1
Jonseboro and Bangor Hydro-
Electric Company
10.90 Purchase Agreement between Form 10-Q, 3rd Quarter 1995,
Babcock-Ultrapower West Exhibit 10.2
Enfield and Bangor Hydro-
Electric Company
10.91 ASSIGNMENT OF CONTRACTS Form 10-Q, 1st Quarter 1998,
AND ENTITLEMENTS, made March Exhibit 10(a)
31, 1998 by and between Bangor
Hydro-Electric Company and
Bangor Energy Resale, Inc.
10.92 Rate Agreement made October 30, Form 10-Q, 1st Quarter 1998,
1997, by and between Bangor Exhibit 10(b)
Hydro-Electric Company and
Bangor Energy Resale, Inc.
10.93 Management and Support Services Form 10-Q, 1st Quarter 1998,
Agreement made March 31, 1998 Exhibit 10(c)
by and between Bangor Hydro-
Electric Company and Bangor
Energy Resale, Inc.
10.94 Surplus Cash Agreement Form 10-Q, 2nd Quarter 1998,
dated as of June 26, 1998 Exhibit 10(a)
among the Company,
Penobscot Energy Recovery
Company Limited
Partnership and the
Municipal Review
Committee, Inc.
10.95 Guaranty Agreement dated Form 10-Q, 2nd Quarter 1998,
as of June 1, 1998 Exhibit 10(b)
between the Company and
The Chase Manhattan Bank
10.96 Amendment No. 2 to Form 10-Q, 2nd Quarter 1998,
Purchase Power Agreement Exhibit 10(c)
dated as of June 26, 1998
between the Company and
Penobscot Energy Recovery
Company Limited
Partnership
10.97 Amended and Restated Form 10-Q, 2nd Quarter 1998,
Revolving Credit And Exhibit 10(d)
Term Loan Agreement
dated as of June 19, 1998
between the Company and
BankBoston, N.A. and Fleet
National Bank
10.98 Asset Purchase Agreement Form 8-K, September 25, 1998
dated as of September 25, Exhibit 2
1998 between Bangor Hydro-
Electric Company and PP&L
Global, Inc. (schedules and
exhibits omitted).