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FORM 10-K
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15 (d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the Fiscal year ended December 31, 2000 Commission File No. 0-505
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BANGOR HYDRO-ELECTRIC COMPANY
-----------------------------
(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.)
3 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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(7,363,424 shares outstanding at March 20, 2001)
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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, 2001 of the voting stock held by
non-affiliates of the registrant was $194.4 million.
This Page Intentionally Left Blank
FORM 10-K
FOR THE FISCAL YEAR ENDED DECEMBER 31, 2000
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 11
-Power Supply Commitments 11
-Maine Yankee 12
-Environmental Matters 14
Item 3: Legal Proceedings 14
Item 4: Submission of Matters to a Vote of Security Holders 14
PART II:
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Item 5: Market for Registrant's Common Equity and Related
Stockholder Matters 15
Item 6: Selected Financial Data 17
Item 7: Management's Discussion and Analysis of Results
of Operations and Financial Condition 19
Item 8: Financial Statements & Supplementary Data 34
-Consolidated Statements of Income 34
-Consolidated Balance Sheets 35
-Consolidated Statements of Capitalizations 37
-Consolidated Statements of Cash Flows 38
-Consolidated Statements of Common Stock Investment 39
-Notes to Consolidated Financial Statements 40
1) Nature of Operations and Summary of Significant
Accounting Policies 40
2) Income Taxes 42
3) Common and Preferred Stock and Earnings Per Share 45
4) Lending Agreements and Monetization of Power
Sale Contract 46
5) Postretirement Benefits 48
6) Jointly Owned Facilities and Power Supply
Commitments 52
7) Recovery of Seabrook Investment and Sale of
Seabrook Interest 62
8) Unaudited Quarterly Financial Data 63
9) Fair Value of Financial Instruments 63
10) Industry Restructuring and Rate Regulation 64
11) Proposed Merger Agreement with Emera 67
12) Construction of Facilities for Casco Bay Energy 68
13) Storm Damage 68
14) Derivative Financial Instruments 69
15) Contingencies 69
15) New Accounting Pronouncements 70
Report of Independent Accountants 71
Item 7A: Quantitative and Qualitative Disclosures about
Market Risk 72
Item 9: Changes in and Disagreements with Audit Firms on
Financial Disclosures 72
PART III:
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Item 10: Directors and Executive Officers of the Registrant 72
Item 11: Executive Compensation 74
Item 12: Security Ownership of Certain Beneficial Owners
and Management 76
Item 13: Certain Relationships and Related Transactions 78
PART IV:
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Item 14: Exhibits, Financial Statement Schedules, and
Reports on Form 8-K 79
Signatures 80
Schedule VIII - Reserve for Doubtful Accounts 81
EXHIBIT INDEX:
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Exhibits Filed Herewith 82
Exhibits Incorporated Herein by Reference 83
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, the proposed merger with Emera, 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 owns approximately 580 miles of transmission lines and
approximately 4,500 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."), Bangor Fiber Company, Inc. ("Bangor Fiber"),
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 Bangor
Var Co., see "Joint Ventures." Bangor Fiber was incorporated in 2000 to
supply fiber optic communications cable to communications companies and
cable service providers and other related activities. 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.
With the implementation of competition in the electric utility industry
starting March 1, 2000, and excluding the standard-offer service, the
Company is no longer selling electricity to customers. The Company's T&D
and stranded cost charges to customers, though, continue to be based on
customers' electricity usage measured in kilowatt-hours (KWH). See "Certain
Issues Facing the Company - Changes in the Electric Utility Industry and in
Regulation," below, and Item 7, "Management's Discussion and Analysis of
Results of Operations and Financial Condition - Recent Events Affecting The
Electric Utility Industry And The Company - Implementation of Competition
in Electric Utility Industry" and Note 10 to the Consolidated Financial
Statements included in Item 8, below. In 2000, 32.0% of the Company's KWH
sales were to residential customers, 33.3% were to commercial customers,
34.7% 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 2000, however, the Company experienced its maximum peak
electric demand during the summer months, with the peak of approximately
304.7 megawatts ("MW") occurring on September 1, 2000.
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, the regional transmission and generation reliability
organization for the New England region. 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 ("FERC") 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 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 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.
PROPOSED MERGER AGREEMENT WITH EMERA - On June 29, 2000, the Company entered
into a definitive merger agreement with Emera of Halifax, Nova Scotia,
pursuant to which Emera will acquire all of the outstanding shares of common
stock of Bangor Hydro for US$26.50 per share in cash. After the closing of
the merger, each of Bangor Hydro's outstanding warrants to purchase common
stock will entitle the holder to receive US$26.50 in cash, less the exercise
price. For a discussion of the common stock warrants, see Note 6 of the
notes to the consolidated financial statements. The equity market value of
the transaction is approximately $206 million. The transaction will take
the form of a merger of Bangor Hydro with a U.S. corporate subsidiary to be
formed by Emera. Upon completion of the merger, Bangor Hydro will be a
wholly-owned subsidiary of Emera. Bangor Hydro's outstanding debt and
preferred stock will not be affected by the transaction. The transaction is
subject to a number of approvals, including the approval of Bangor Hydro's
shareholders, which was accomplished on October 24, 2000, and regulatory
approvals from the Maine Public Utilities Commission (MPUC), the Federal
Energy Regulatory Commission (FERC), which occurred on January 5, 2001 and
January 24, 2001, respectively, and the U.S. Securities and Exchange
Commission (SEC) under the Public Utility Holding Company Act of 1935.
Proceedings are pending at the SEC for what is anticipated to be the last
major regulatory approval. The processes for all necessary regulatory
approvals are expected to be complete in the first half of 2001. The MPUC
order requires the Company to file an alternative rate plan with the MPUC
within two months after the completion of the merger with Emera or June 30,
2001, whichever is earlier.
CERTAIN ISSUES FACING THE COMPANY
---------------------------------
LOSS OF MAJOR CUSTOMER - HoltraChem Manufacturing Company, a major user of
the Company's transmission and distribution services, ceased production at
its Orrington, Maine manufacturing facility in mid-October, 2000. For a
discussion of the impact of this event on the Company 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 - Loss of a Major Customer."
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 MPUC to provide so-called "standard offer" service.
For the period March 1, 2000 through February 28, 2001 and again for the
period March 1, 2001 through February 28, 2002, the MPUC ordered the Company
to assume the responsibility to provide for 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 - Implementation of Competition in Electric Utility
Industry" 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.
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.
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
--------------------
The Company's construction program consists of extensions and
improvements of its transmission and distribution facilities, capital
improvements to the Company's internal computer and information systems and
other general projects within the Company's service area. The Company
projects that capital expenditures will aggregate approximately $45-50
million in the period 2001 through 2003.
RATES AND REGULATION
--------------------
RATE MATTERS - In February 2000, the Company received a final rate order
from the MPUC setting its distribution and stranded cost rates effective
March 1, 2000. The Company's total annual revenue requirement as set in the
rate proceedings, including transmission, distribution and stranded,
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.
Stranded costs represent approximately 40% of the Company annual cost of
service, although this amount is expected to decline over time. The MPUC is
required to review and reevaluate the stranded cost recovery no less
frequently than every three years. 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.
On February 26, 2001, the FERC issued an Order approving transmission
rates for the Company. Pursuant to federal policy, upon implementation of
retail electric service unbundling as part of the electric industry
restructuring scheme enacted by the State of Maine, rates for retail
transmission service became subject to FERC jurisdiction. Costs relating to
the provision of transmission service represent approximately 10% of the
Company's annual cost of service. Under the FERC Order approving new
transmission rates, a "formula" rate was approved, allowing the Company to
adjust its rates annually to reflect changes in the Company's costs and its
sales volume during the preceding calendar year.
As part of its Order dated December 18, 2000 approving the Company's
proposed merger with Emera, the MPUC required the Company to propose no
later than June 30, 2001 an Alternative Rate Plan to govern distribution
rates. In recent years, the MPUC has indicated a preference for alternative
forms of rate regulation. The Company was previously subject to such a
ratemaking scheme from 1998 to 2000.
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
--------------
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. See Note 6 to the
Consolidated Financial Statement included in Item 8, below
BANGOR VAR CO. - In 1990, the Company formed Bangor Var Co., whose sole
function is to be a 50% general partner in Chester SVC Partnership
("Chester"), a partnership which owns a static var compensator (SVC), which
is electrical equipment that supports the Phase 2 transmission line. See
Note 6 to the Consolidated Financial Statement included in Item 8, below.
MEPCO - The Company owns 14.2% of the common stock of Maine Electric Power
Company ("MEPCO"). MEPCO owns and operates electric transmission facilities
from Wiscasset, Maine, to the Maine-New Brunswick border. See Note 6 to the
Consolidated Financial Statement included in Item 8, below
EMPLOYEES
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At December 31, 2000, the Company had 427 full time employees
approximately 48% 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 COMMITMENTS
------------------------
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.
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
- ----------- ---------------------- -----------------------
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, 2001 through February 28, 2002, 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 - Implementation of Competition in
Electric Utility Industry" and Note 10 to the Consolidated Financial
Statements included in Item 8, below. The Company intends to meet its
obligations through short and intermediate term contracts and spot market
purchases, a strategy that has been approved by the MPUC.
MAINE YANKEE
------------
GENERAL - The Company owns 7% of the common stock of Maine Yankee, which
owns and, prior to its permanent closure in 1997, operated an 880 MW nuclear
generating plant in Wiscasset, Maine. Maine Yankee, which had commenced
commercial operation on January 1, 1973, is the only nuclear facility in
which the Company has an ownership interest. The Company's equity ownership
in the plant had entitled the Company to about 7% of the output pursuant to
a cost-based power contract. Pursuant to a contract with Maine Yankee, the
Company is obligated to pay its pro rata share of Maine Yankee's operating
expenses, including decommissioning costs. In addition, under a Capital
Funds Agreement entered into by the Company and the other sponsor utilities,
the Company may be required to make its pro rata share of future capital
contributions to Maine Yankee if needed to finance capital expenditures.
PERMANENT SHUTDOWN OF THE MAINE YANKEE PLANT - On August 6, 1997, the Board
of Directors of Maine Yankee voted to permanently cease power operations at
Maine Yankee and to begin decommissioning the plant. See Note 6 to the
Consolidated Financial Statement included in Item 8, below.
MAINE YANKEE RATE CASE SETTLEMENT - See Note 6 to the Consolidated Financial
Statement included in Item 8, below.
TERMINATION OF DECOMMISSIONING OPERATIONS CONTRACT - See Note 6 to the
Consolidated Financial Statement included in Item 8, below.
LOW-LEVEL WASTE DISPOSAL. The federal Low-Level Radioactive Waste Policy
Amendments 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. The states of Maine, Texas and
Vermont entered into a compact for the disposal of low-level waste over a
30-year period 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. 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 approved by
Congress in September 1998. However, in October 1998 the Texas Natural
Resource Conservation Commission denied a permit for the proposed west Texas
site, and construction of such a facility in Texas is uncertain. Maine
Yankee expects the Texas Legislature to consider low-level waste issues at
its session that convened in January 2001.
Maine Yankee is currently shipping its low-level waste to other
facilities licensed to accept this material. Maine Yankee is unable to
predict whether or when a facility in Texas will be licensed and built or
whether or when the State of Maine will assess any payments required under
the compact.
NUCLEAR INSURANCE. The Price-Anderson Act is a federal statue providing, among
other things, a limit on the maximum liability for damages resulting from a
nuclear incident. Coverage for the liability is provided for by existing
private insurance and retrospective assessments for costs in excess of those
covered by insurance, up to $88.1 million for each reactor owned, with a maximum
assessment of $10 million per reactor in any year. However, after appropriate
exemptive action by the NRC Maine Yankee, and therefore its sponsors, are not
responsible for retrospective assessments resulting from any event or incident
occurring after January 7, 1999.
SPENT FUEL - Maine Yankee's spent fuel is currently stored in the spent fuel
pool at the plant site. Federal legislation enacted in 1987 directed the DOE
to proceed with the studies necessary to develop and operate a permanent high-
level waste (spent fuel) disposal site at Yucca Mountain, Nevada. The
legislation also provided for the possible development of a Monitored
Retrievable Storage ("MRS") facility and abandoned plans to identify and
select a second permanent disposal site. An MRS facility would provide
temporary storage for high-level waste prior to eventual permanent disposal.
The DOE has indicated that the permanent disposal site is not expected to open
before 2010, although originally scheduled to open in 1998.
In November 1997 the U.S. Court of Appeals for the District of Columbia
Circuit confirmed the DOE's obligation under the Nuclear Waste Policy Act of
1982 to take responsibility for spent nuclear fuel in 1998.
After an unsuccessful effort by Maine Yankee in the same court to compel the
DOE to take Maine Yankee's spent fuel, in June 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. In November 1998 the
Court granted summary judgment in favor of Maine Yankee, ruling that the DOE had
violated its contractual obligations, but leaving the amount of damages incurred
by Maine Yankee for later determination by the Court. Since then the parties
have been engaged in discovery and resolving pre-trial issues in the damages
phase of the proceeding. Maine Yankee is continuing to pursue its claim for
damages vigorously, but cannot predict the outcome of its claim. At the same
time, as an interim measure until the DOE meets its contractual obligations to
dispose of Maine Yankee's spent fuel, the Company is proceeding with
construction of an independent spent fuel storage installation 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
---------------------
See Item 7, "Management's Discussion and Analysis of Results of Operations
and Financial Condition - Contingencies and Disclosures About Market Risk" for
a discussion of Environmental Matters.
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
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ITEM 5 MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
- ------ ---------------------------------------------------------------------
As of December 31, 2000, there were 6,222 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
- ------------- ---- --- ---------
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................ $17 3/8 $12 9/16 $.20
Second Quarter............... 24 7/16 14 3/8 .20
Third Quarter................ 24 1/2 23 5/16 .20
Fourth Quarter............... 25 3/4 24 3/16 .20
2001
- ----
First Quarter
(through March 20, 2001).. $26 1/8 $25 1/4 $.20
Approximately 84% 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.
In addition, pursuant to the definitive merger agreement with Emera dated June
29, 2000, the Company may not increase the rate of dividends on common stock
to more than $.25 per share per quarter.
This Page Intentionally Left Blank
BANGOR HYDRO-ELECTRIC COMPANY
Item 6
Selected Financial Data
Six-Year Statistical Summary
(Unaudited)
2000 1999 1998 1997 1996 1995
Megawatt Hours (MWH) Generated And Purchased
Hydro Generation (Company) 90,719 205,265 275,379 262,377 321,532 275,810
Nuclear Generation (Maine Yankee) - - - - 348,719 13,606
Oil (Company) 3,142 69,026 96,476 69,580 26,912 50,706
Biomass/Refuse 152,060 137,384 156,051 159,990 163,279 177,558
NEPOOL/Other Purchases 1,914,615 1,629,643 1,522,125 1,583,093 1,359,116 1,540,530
--------- --------- --------- --------- --------- ---------
Total Generated & Purchased 2,160,536 2,041,318 2,050,031 2,075,040 2,219,558 2,058,210
Less Line Losses and Company Use 140,470 143,198 139,028 147,298 141,426 140,128
--------- --------- --------- --------- --------- ---------
Remainder-MWH sold 2,020,066 1,898,120 1,911,003 1,927,742 2,078,132 1,918,082
========= ========= ========= ========= ========= =========
Classification of Sales-MWH
Residential 558,596 533,566 522,836 533,161 536,490 513,076
Commercial 570,963 545,087 524,292 515,904 508,331 507,243
Industrial 604,959 667,059 662,382 687,365 652,087 690,863
Lighting 8,859 8,911 8,901 8,780 8,945 9,547
Wholesale 2,799 2,716 2,704 3,841 4,486 10,961
--------- --------- --------- --------- --------- ---------
Total MWH Billed to Customers 1,746,176 1,757,339 1,721,115 1,749,051 1,710,339 1,731,690
Unbilled Sales-Net Increase (Decrease) 2,629 11,772 1,040 33,011 2,998 4,658
--------- --------- --------- --------- --------- ---------
Total Delivered Sales (MWH) 1,748,805 1,769,111 1,722,155 1,782,062 1,713,337 1,736,348
(Less) Interruptible Sales 78,943 230,378 248,091 265,438 237,553 295,818
--------- --------- --------- --------- --------- ---------
Total Firm Delivered Sales (MWH) 1,669,862 1,538,733 1,474,064 1,516,624 1,475,784 1,440,530
Off-System Sales 271,261 129,009 188,848 145,680 364,795 181,734
--------- --------- --------- --------- --------- ---------
Total Energy Sales (MWH) 2,020,066 1,898,120 1,911,003 1,927,742 2,078,132 1,918,082
========= ========= ========= ========= ========= =========
Electric Operating Revenues and Expenses (000's)
Electric Operating Revenues
Residential $ 57,746 $ 73,304 $ 71,396 $ 67,532 $ 66,805 $ 66,061
Commercial 44,329 63,093 60,191 55,391 54,010 54,702
Industrial 23,749 43,560 42,645 41,930 39,105 40,257
Lighting 1,929 2,268 2,207 2,065 2,032 2,051
Wholesale 63 220 235 310 314 859
----------- ------------ ------------ ------------ ------------ ------------
Total Revenue from Customers $ 127,816 $ 182,445 $ 176,674 $ 167,228 $ 162,266 $ 163,930
Standard Offer Service Revenue 56,657 - - - - -
Total Operating Revenue $ 184,473 $ 182,445 $ 176,674 $ 167,228 $ 162,266 $ 163,930
----------- ------------ ------------ ------------ ------------ ------------
Unbilled Sales-Net Increase (Decrease) 1,651 2,042 481 2,375 408 210
----------- ------------ ------------ ------------ ------------ ------------
Total Revenue $ 186,124 $ 184,487 $ 177,155 $ 169,603 $ 162,674 $ 164,140
(Less) Interruptible Revenue 4,973 10,049 11,064 11,215 9,537 11,149
----------- ------------ ------------ ------------ ------------ ------------
Total Firm Revenue $ 181,151 $ 174,438 $ 166,091 $ 158,388 $ 153,137 $ 152,991
Off-System Revenue 19,352 12,947 14,630 13,615 18,384 14,098
----------- ------------ ------------ ------------ ------------ ------------
Total Electric Operating Revenues $ 205,476 $ 197,434 $ 191,785 $ 183,218 $ 181,058 $ 178,238
=========== ============ ============ ============ ============ ============
Operating Expenses
Fuel for Generation and Purchased Power $ 44,144 $ 80,748 $ 82,027 $ 92,792 $ 78,477 $ 98,684
Standard Offer Service Purchased Power 65,553 - - - - -
Operating and Maintenance Expense 37,212 36,492 34,448 32,471 32,441 35,711
Depreciation and Amortization 26,776 30,565 31,891 35,104 29,965 20,544
Taxes 12,228 14,032 11,642 3,168 10,249 6,306
----------- ------------ ------------ ------------ ------------ ------------
Total Operating Expenses $ 185,913 $ 161,837 $ 160,008 $ 163,535 $ 151,132 $ 161,245
=========== ============ ============ ============ ============ ============
Summary of Operations (000's)
Operating Revenue $ 212,338 $ 197,994 $ 195,144 $ 187,324 $ 187,374 $ 184,914
Operating Expenses 185,913 161,837 160,008 163,535 151,132 161,245
Other Income (including equity AFDC) 613 2,806 1,292 1,292 1,466 760
Interest Expense (net of borrowed AFDC) 15,936 20,683 24,963 25,467 26,425 20,092
----------- ------------ ------------ ------------ ------------ ------------
Net Income (Loss) $ 11,102 $ 18,280 $ 11,465 $ (386)$ 11,283 $ 4,337
Less Preferred Dividends 266 945 1,244 1,376 1,537 1,702
----------- ------------ ------------ ------------ ------------ ------------
Earnings (Loss) on Common Stock $ 10,836 $ 17,335 $ 10,221 $ (1,762)$ 9,746 $ 2,635
=========== ============ ============ ============ ============ ============
Selected Financial Data
Total Assets (000's) $ 532,220 $ 543,950 $ 605,688 $ 600,583 $ 556,629 $ 566,076
Electric Plant (000's)
Total Electric Plant $ 327,247 $ 318,435 $ 372,782 $ 358,878 $ 341,526 $ 323,664
Depreciation Reserve 86,684 84,825 101,633 96,595 87,736 81,934
----------- ------------ ------------ ------------ ------------ ------------
Net Electric Plant $ 240,563 $ 233,610 $ 271,149 $ 262,283 $ 253,790 $ 241,730
=========== ============ ============ ============ ============ ============
Capitalization (000's)
Short-Term Debt $ - $ - $ 12,000 $ 34,000 $ 32,500 $ 35,000
Long-Term Debt 161,960 183,300 263,028 221,643 274,221 288,075
Redeemable Preferred Stock - - 7,604 9,137 10,670 12,070
Preferred Stock 4,734 4,734 4,734 4,734 4,734 4,734
Common Equity 137,420 132,722 118,864 106,558 108,321 103,192
----------- ------------ ------------ ------------ ------------ ------------
Total $ 304,114 $ 320,756 $ 406,230 $ 376,072 $ 430,446 $ 443,071
=========== ============ ============ ============ ============ ============
Capital Structure Ratios (%)
Short-Term Debt - % - % 3.0 % 9.1 % 7.5 % 7.9 %
Long-Term Debt 53.2 % 57.1 % 64.7 % 58.9 % 63.7 % 65.0 %
Preferred Stock 1.6 % 1.5 % 3.0 % 3.7 % 3.6 % 3.8 %
Common Stock 45.2 % 41.4 % 29.3 % 28.3 % 25.2 % 23.3 %
----------- ------------ ------------ ------------ ------------ ------------
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 7,363,424 7,336,174 7,264,360
Shares Outstanding (Year End) 7,363,424 7,363,424 7,363,424 7,363,424 7,363,424 7,301,557
Number of Common Stockholders (Year End) 6,222 5,678 6,328 6,868 7,734 8,250
Basic Earnings (Loss) Per Common Share $ 1.47 $ 2.35 $ 1.39 $ (0.24) $ 1.33 $ 0.36
Diluted Earnings (Loss) Per Common Share $ 1.30 $ 2.08 $ 1.33 $ (0.24) $ 1.33 $ 0.36
Dividends Declared Per Common Share $ 0.80 $ 0.45 $ - $ - $ 0.72 $ 0.87
Book Value Per Common Share $ 18.66 $ 18.02 $ 16.14 $ 14.47 $ 14.71 $ 14.13
Return on Common Equity 7.98 % 13.81 % 9.11 % (1.64)% 9.09 % 2.51 %
Ratio of AFDC to Common Stock Earnings 3 % (4)% 11 % (48)% 12 % 48 %
Ratio of Earnings to Fixed Charges 2.11 % 2.25 % 1.59 % 0.86 % 1.50 % 1.14 %
Payout Ratio 54 % 26 % - % - % 54 % 242 %
Percentage of Construction Expenditures
Funded Internally 100 % 100 % 100 % 100 % 100 % 86 %
=========== =========== =========== =========== =========== ===========
Residential Customer Data
Average Number of Customers 92,656 91,726 90,888 90,433 89,769 86,194
Kilowatt-Hours per Customer 6,029 5,817 5,753 5,896 5,976 5,953
Revenue per Customer $ 623.23 $ 799.16 $ 785.54 $ 746.76 $ 744.19 $ 766.42
Revenue per Kilowatt-Hour in Cents 10.34 13.74 13.65 12.67 12.45 12.88
=========== ============ =========== =========== =========== ===========
Miscellaneous System Data
Net System Capability at Time of Peak
(MW) Firm* 98.98 273.72 381.54 344.44 373.04 330.01
System Peak Demand (MW) 304.71 293.08 281.63 277.06 274.32 267.98
Reserve Margin at Time of Peak** (67.5)% (6.6)% 35.5 % 24.3 % 36.0 % 23.2 %
System Load Factor 70.8 % 74.5 % 75.4 % 79.5 % 77.0 % 79.9 %
=========== ============ =========== =========== =========== ===========
* The net system capability was reduced in 2000 and 1999 as a result of the generation asset sale.
** While the reserve margin at time of peak in 2000 and 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 UTILITY INDUSTRY AND THE COMPANY
- ---------------------------------------------------------------------
PROPOSED MERGER AGREEMENT WITH EMERA - On June 29, 2000, the Company
entered into a definitive merger agreement with Emera of Halifax, Nova
Scotia, pursuant to which Emera will acquire all of the outstanding
shares of common stock of Bangor Hydro for US$26.50 per share in cash.
After the closing of the merger, each of Bangor Hydro's outstanding
warrants to purchase common stock will entitle the holder to receive
US$26.50 in cash, less the exercise price. For a discussion of the
common stock warrants, see Note 6 of the notes to the consolidated
financial statements. The equity market value of the transaction is
approximately $206 million. The transaction will take the form of a
merger of Bangor Hydro with a U.S. corporate subsidiary to be formed by
Emera. Upon completion of the merger, Bangor Hydro will be a wholly-
owned subsidiary of Emera. Bangor Hydro's outstanding debt and
preferred stock will not be affected by the transaction. The
transaction is subject to a number of approvals, including the approval
of Bangor Hydro's shareholders, which was accomplished on October 24,
2000, and regulatory approvals from the Maine Public Utilities
Commission (MPUC), the Federal Energy Regulatory Commission (FERC),
which occurred on January 5, 2001 and January 24, 2001, respectively,
and the U.S. Securities and Exchange Commission (SEC) under the Public
Utility Holding Company Act of 1935. Proceedings are pending at the
SEC for what is anticipated to be the last major regulatory approval.
The processes for all necessary regulatory approvals are expected to be
complete in the first half of 2001. The MPUC order requires the Company
to file an alternative rate plan with the MPUC within two months after
the completion of the merger with Emera or June 30, 2001, whichever is
earlier.
The merger is part of Emera's strategy to grow its business beyond its
current borders. Bangor Hydro will operate as a standalone division of
Emera and will be the base for Emera to launch other initiatives. The
companies will share best practices learned from their respective
utility system operations.
Emera is a diversified energy and services company, with about 440,000
customers and (Cdn)$2.9 billion in assets. It owns 100% of Nova Scotia
Power, Inc., the primary electricity supplier in the province of Nova
Scotia. Emera's energy product line also includes bunker oil, diesel
fuel and light fuel oil, and the company has a 12.5% interest in the
Maritimes & Northeast Pipeline, which delivers Sable Island natural gas
to markets in Maritime Canada, and the northeastern United States.
IMPLEMENTATION OF COMPETITION IN ELECTRIC UTILITY INDUSTRY - In
connection with the state of Maine's electric industry restructuring
law, effective March 1, 2000, consumers of electricity had the right to
purchase generation services directly from competitive electricity
suppliers. In February 2000, and in connection with the
implementation of the restructuring law, the Company received a final
rate order from the MPUC setting its transmission and distribution
(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. The electric
utility industry restructuring and the Company's associated rate
proceedings at the MPUC are discussed in more detail in the 1999 Form
10-K.
As discussed in the 1999 Form 10-K, the restructuring law also provided
for a standard-offer service being available for all customers who did
not choose to purchase energy from a competitive supplier starting
March 1, 2000. As a result of the bids from competitive energy
suppliers to provide energy under the standard-offer service being
higher than anticipated, and as ordered by the MPUC, the Company
assumed the responsibility of being the standard-offer service provider
starting March 1, 2000 for a one-year period. The MPUC established the
schedule of rates the Company could charge for this service starting
March 1, 2000.
The Company entered into arrangements with third parties to purchase
the energy to serve the standard-offer customers. The Company is
allowed by the MPUC to defer the difference between revenues realized
from the standard-offer sales and the costs incurred to provide this
service, including carrying costs on the deferred balance. As a result
of this reconciliation mechanism, standard-offer related revenues and
expenses do not have any impact on the Company's earnings, although
they do result in increases in both categories in the Company's
consolidated statements of income. The deferred amount will be
recovered from/returned to customers in the future. Since March 1,
2000, when new rates went into effect, the costs of providing the
standard offer service have exceeded the revenues realized from
customers, and consequently, the Company has recorded a regulatory
asset of $3.1 million, including carrying costs, as of December 31,
2000 (which is included in Other regulatory assets on the Consolidated
Balance Sheets). The excess of costs is due principally to unusually
high purchased power costs for one day in May 2000, which is discussed
below, and higher than anticipated spot energy market prices in the
summer of 2000. As a result of the growth in the balance of this
regulatory asset, the MPUC approved standard offer service rate
increases for customers in each of August and October 2000. These rate
increases were necessitated to avoid a deficiency in standard offer
service revenues that the Company projected would otherwise result
based on actual costs already incurred and projected costs through
February 2001.
In October 2000, the MPUC issued a Request for Proposal seeking firms
willing to supply standard-offer service for the Company's service
territory. In part because of rapidly changing conditions in the
electricity markets, the MPUC did not receive any acceptable proposals.
In December 2000 the MPUC directed the Company to explore power supply
arrangement to assist the MPUC in fulfilling its obligation to provide
standard-offer service. In February 2001, based on orders from the
MPUC, the Company retained responsibility as the standard-offer service
provider starting March 1, 2001. The MPUC initially set the standard-
offer power supply price for small (residential and non-residential)
and medium non-residential electric customers located in the Company's
service territory for the period from March 1, 2001 through February
28, 2002 at a rate which is approximately 20% above the then current
standard-offer price. The MPUC also set the standard-offer electric
supply price for the Company's large customers for this same period at
a rate approximately 29% above the then current standard-offer price.
The MPUC also approved additional power contracts which the Company was
able to procure at the request of the MPUC locking in prices for a
portion of the projected standard-offer load over the next three years.
The Company will continue to be allowed by the MPUC to defer the
difference between revenues realized from the standard-offer sales and
the costs incurred to provide this service, including carrying costs on
the deferred balance.
BANGOR GAS INVESTMENT - As discussed in the 1999 Form 10-K, the Company
announced in late 1999 that it no longer intended to participate in the
Bangor Gas Company, LLC (Bangor Gas) joint venture and intended to sell
its joint venture interest. On July 13, 2000, the Company and
Penobscot Natural Gas Company (Penobscot Gas), the Company's wholly-
owned subsidiary which owned a 50% interest in Bangor Gas, completed a
stock purchase agreement to sell the Company's interest in Penobscot
Gas to Sempra Energy (Sempra). Sempra had owned the other 50% interest
in Bangor Gas. As previously discussed, a one-time gain on the sale of
Penobscot Gas of approximately $1.2 million was recognized in the third
quarter of 2000 and is included as a component of Other Income in the
Consolidated Statements of Income for the year ending December 31,
2000. The completion of this sale has no impact on the previously
discussed proposed merger agreement with Emera.
INCREASE IN COMMON STOCK DIVIDEND - On March 15, 2000 the Company's
board of directors declared a cash dividend on its common stock of $.20
per share. The quarterly dividend represented a $.05 increase over the
$.15 per share dividend declared in each of the prior three quarters.
In June of 1999, the board of directors resumed payment of quarterly
common stock dividends after having suspended them 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 in 1997 and is now in the
process of being decommissioned.
MAINE YANKEE - TERMINATION OF DECOMMISSIONING OPERATIONS CONTRACT - As
discussed in the 1999 Form 10-K, the Company owns 7% of the common
stock of Maine Yankee, which owns and, prior to its permanent closure
in 1997, operated an 880 megawatt nuclear generating plant (the Plant)
in Wiscasset, Maine. 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.
On May 4, 2000, Maine Yankee notified its decommissioning operations
contractor, Stone & Webster Engineering Corporation (Stone & Webster),
that it was terminating the decommissioning operations contract
pursuant to the terms of the contract. Stone & Webster subsequently
notified Maine Yankee that it was disputing Maine Yankee's grounds for
terminating the contract. On May 8, 2000, Stone & Webster announced a
proposed transaction in which it would transfer substantially all of
its assets in exchange for an immediate credit facility and other
consideration, including cash and stock. Stone & Webster said that the
credit facility was intended to enable it to address its liquidity
difficulties and continue to operate its businesses until the asset
sale was completed. Stone & Webster also announced that it intended to
seek bankruptcy court approval of the asset sale and credit agreement.
On June 2, 2000, Stone & Webster filed a voluntary petition under
Chapter 11 of the U.S. Bankruptcy Code with the United States
Bankruptcy Court for the District of Delaware. By Sale Order dated
July 13, 2000, the Bankruptcy Court approved the sale of substantially
all of Stone & Webster's assets to the successful bidder in the Chapter
11 sale, The Shaw Group, Inc. (Shaw), for cash, stock, and the
assumption of certain liabilities of Stone & Webster, and the proposed
transaction announced earlier by Stone & Webster was terminated. Stone
& Webster reported that the Shaw transaction was effectively closed on
July 14, 2000, and that it would continue to operate as a Debtor-in-
Possession subject to the supervision and orders of the Bankruptcy
Court.
Commencing in May 2000, Maine Yankee entered into interim agreements
with Stone & Webster in order to allow decommissioning work to continue
and avoid the adverse consequences of an abrupt or inefficient
demobilization from the Plant site. After obtaining assignments of
several subcontracts from Stone & Webster, Maine Yankee temporarily
assumed the general contractor role. The decommissioning of the Plant
site continued throughout 2000, with major emphasis directed to
maintaining the schedule of critical-path projects such as construction
of the ISFSI and preparation of the Plant's reactor vessel for eventual
shipment to an off-site disposal facility. During this period, Maine
Yankee performed comprehensive assessment of its long-term alternatives
for safely and efficiently completing the decommissioning, including
evaluating detailed competitive-bid proposals from prospective
successor general contractors. On January 26, 2001, Maine Yankee
announced its decision to continue to manage the decommissioning
project itself without an external general contractor.
On June 30, 2000, Federal Insurance Company (Federal), which provided
performance and payment bonds in the amount of approximately $37.6
million each in connection with the decommissioning operations
contract, filed a Complaint for Declaratory Judgement against Maine
Yankee in the United States Bankruptcy Court for the District of
Delaware, which was subsequently transferred to the United States
District Court in Maine. The Complaint, which seeks a declaration that
Federal has no obligation to pay Maine Yankee under the bonds, alleges
that Maine Yankee improperly terminated the decommissioning operations
contract with Stone & Webster and failed to give proper notice of the
termination to Federal under the contract, and that Federal therefore
had no further obligations under the bonds.
On August 24, 2000, Maine Yankee filed a $78.2 million claim in the
Stone & Webster Bankruptcy Court proceeding in Delaware seeking to
recover its additional costs caused by Stone & Webster's contract
default. Maine Yankee expects the court hearings in both proceedings to
take place later in 2001. Maine Yankee believes that its termination
of the Stone & Webster contract was proper and that it is entitled to
recover such additional costs in the bankruptcy proceeding or under the
bonds, but cannot predict the outcome of the litigation.
In connection with the state of Maine's electric industry restructuring
law, the Company was allowed the recovery of Maine Yankee
decommissioning costs as a component of its stranded costs. In the
Company's rate order from the MPUC that became effective March 1, 2000,
the Company was allowed to defer the amount of any future FERC ordered
changes in Maine Yankee's decommissioning collections. Consequently,
management does not believe that Maine Yankee's current decommissioning
contractor difficulties will have a material adverse impact on the
Company's results of operations, financial condition or cash flows.
MAINE YANKEE REPLACEMENT POWER COSTS - As discussed in the 1999 Form
10-K, under the Maine Yankee settlement agreement, the Maine owners of
Maine Yankee are required, for the period from March 1, 2000 through
December 1, 2004, to hold 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. As part of a further settlement, the Company's liability was
fixed at approximately $2.2 million to be reflected as a reduction in
stranded costs effective March 1, 2002. The Company charged to fuel
and purchased power expense and recorded as a regulatory liability $2
million in December 2000 representing the net present value of this
future obligation.
LOSS OF MAJOR CUSTOMER - On September 15, 2000 HoltraChem Manufacturing
Company (HoltraChem) ceased production at its Orrington, Maine
manufacturing facility and closed the facility in mid-October of 2000.
HoltraChem, a manufacturer of caustic soda and chlorine, has been a
major user of the Company's transmission and distribution services, and
before the restructuring of the electric utility industry in Maine in
March 2000, was a major purchaser of energy from the Company.
For the 12 months ended August 31, 2000, the Company earned
approximately $2.2 million pre-tax associated with the provision of
transmission and distribution services to HoltraChem, or approximately
9% of the Company's total pre-tax income during that period. The
previously discussed alternative rate plan filing required by the MPUC
will likely address the loss of revenues from HoltraChem.
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, the Company's proposed merger agreement with Emera,
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 2000, 1999 and 1998 as they affect the Company's
liquidity. Net cash provided by operations was $37.6 million in 2000,
$47.4 million in 1999, and $30.9 million in 1998.
Negatively impacting cash flows in the 2000 period was $3 million in
previously discussed deferred costs associated with the Company
providing standard-offer service to customers, as well as $1.4 million
in deferred costs for the period from March 1, 2000 through December
31, 2000, associated with a deficiency in actual revenues realized from
customers under special rate contracts as compared to the estimated
revenues for these customers utilized in setting the Company's new
electric rates starting March 1, 2000. The Company was granted a
deferral mechanism for the differences in these revenues in its
February 2000 rate order from the MPUC. Also negatively impacting cash
flows in 2000 was the impact of a lower authorized return on equity of
11% ordered by the MPUC effective March 1, 2000 with the advent of the
electric industry restructuring. Positively impacting cash flows from
operations in the 1999 period was the receipt of a $1.75 million
payment related to a terminated purchased power contract (See the 1999
Form 10-K).
These decreases in cash flows from operations for 2000 as compared to
1999 were offset to some extent by a $5.8 million reduction in interest
payments in 2000 principally as a result of long-term debt principal
payments discussed below. Also the Company incurred $5.3 million in
closing and selling costs associated with the generation asset sale in
1999.
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 13), 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).
Over the last three years, capital expenditures have been $16.7 million
in 2000, $20.3 million in 1999 and $18.2 million in 1998. In 2000,
approximately $8.2 million of the capital expenditures were related to
the Company's electric distribution system, $4.2 million was associated
with the electric transmission system, $2.4 million was expended in
connection with customer information system changes necessitated by the
electric industry restructuring, and the remainder related to other
general property and equipment, software, and internal combustion
facilities. 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 expenditures to total between
$45 and $50 million over the next three years, although it may be
necessary to adjust the budget for capital expenditures on a year-to-
year basis.
As previously discussed, in July 2000 the Company received $1.2 million
in connection with the sale of Penobscot Gas.
As discussed in the 1999 Form 10-K, 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 its wholly owned subsidiary, Penobscot Hydro Co., Inc.
(Penobscot Hydro).
Also impacting cash flows in 1999 and 1998 were Graham Station property
sale proceeds. This sale is discussed in the 1999 Form 10-K. The $6.2
million in proceeds associated with the sale of this property 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.
As previously discussed, the increase in dividends paid on common stock
in both 2000 and 1999 was a result of the reinstatement of the
Company's common dividend in the second quarter of 1999, and the
increase in the common dividend from $.15 to $.20 per share in March
2000. No common dividends were paid in 1998.
The reduction in preferred dividends paid in 2000 resulted from the
final redemption of the remaining outstanding 8.76% mandatory
redeemable preferred stock in October 1999. 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 in October
1999.
In 2000 the Company made $19.5 million in repayments on long-term debt,
including a $14 million principal payment at the end of June 2000 on
the Finance Authority of Maine Revenue Notes and $5.5 million in
payments on the $24.8 million medium term notes which are discussed
below.
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 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. Also in 1998 the
Company made a sinking fund payment of $1.5 million on this preferred
stock and a $94,000 make whole provision payment.
Capital and operating needs in 2000, 1999 and 1998 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 $133.3 million of first mortgage bonds
and other long-term debt maturities in the period 2001-2005.
RESULTS OF OPERATIONS
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EARNINGS - Basic earnings per common share were $1.47, $2.35, and
$1.39, for the years ended 2000, 1999 and 1998, respectively. Earned
return on average common equity was 8% in 2000, 13.8% in 1999 and 9.1%
in 1998.
The relatively high level of earnings in 1999 as compared to 2000 was
in part attributable to a number of one-time benefits amounting to
approximately $.52 per share. 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 resulting in a reduction to operation and
maintenance expense and producing a benefit to 1999 earnings of $.14
per share after taxes.
Several other major changes account for the difference between 2000 and
1999 earnings. The largest change is attributable to new rates
implemented by order of the MPUC effective March 1, 2000 that reflect a
lower authorized return on equity of 11% in Maine's restructured
electric industry. Also affecting earnings in 2000 were costs billed
to the Company associated with transmission constraints in New England
($.15 per common share after taxes), as well as the recognition of
costs related to the proposed merger ($.24 per common share after
taxes) with Emera, and a write-off associated with power costs to
replace generation from the Maine Yankee nuclear power plant ($.16 per
common share after taxes). Somewhat offsetting these charges to
earnings was the previously discussed $1.2 million ($.10 per common
share after taxes) gain on the sale of Penobscot Gas. Total revenues
and expenses for the periods presented are difficult to compare because
of changes associated with the introduction of retail competition
effective March 1, 2000.
Aside from the one-time items mentioned above, energy sales to the
Company's non-contract customers increased by 3.4% over 1999 showing
continued strength in the local economy.
Results for 1999 compared favorably to those in 1998 in part because of
the previously discussed one-time benefits to earnings in 1999. Aside
from these benefits, improvement in 1999 earnings was 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.
REVENUES - With the previously discussed implementation of competition
in the electric utility industry starting March 1, 2000, and excluding
the standard-offer service, the Company is no longer selling
electricity to customers. The Company's T&D and stranded cost charges
to customers, though, continue to be based on customers' electricity
usage measured in kilowatt-hours (KWH). Consequently, discussion
related to electric operating revenues will continue to have a KWH
sales, or hereafter referred to as "energy sales" component.
Electric operating revenue increased by $14.3 million in 2000 as
compared to 1999 due to several factors. Other revenues (not
attributable to KWH sales) were approximately $12.7 million greater in
2000 as compared to 1999 due principally to four factors. First, as a
result of the previously discussed deferral mechanism for the standard-
offer service revenues and costs, the Company recorded additional
revenue of $3 million in 2000 to recognize the standard-offer service
expenses in excess of revenues. Off-system sales, which are sales
related to power pool and interconnection agreements and resales of
purchased power, were approximately $6.4 million higher in 2000 as a
result of the Company's requirement to resell the capacity and energy
from its six purchased power contracts pursuant to Chapter 307 of
Maine's 1997 law restructuring the State's electric industry (See the
Note 6 to the Consolidated Financial Statements for a more complete
discussion). Also, primarily as a result of electric generators in the
Company's service territory wheeling power over the Company's
transmission lines and out of its service territory, the Company
recorded approximately $1.8 million in higher transmission wheeling
revenues in 2000 as compared to 1999. Finally, in 2000 the Company
recorded approximately $1.4 million of revenues associated with the
previously discussed deferral mechanism for special rate contracts.
Total electric operating revenues attributable to energy sales were
$1.6 million greater in 2000 than in 1999. Total energy sales were
1.2% or 20.3 million KWH's lower in 2000 as compared to 1999, largely
attributable to reduced sales to the Company's largest special contract
customers (64.5 million KWH reduction in energy sales and $6.9 million
reduction in electric operating revenues). These reduced special
contract customer sales and revenues were attributable to the
previously discussed shutdown of Holtrachem on September 15, 2000, and
sales to another large industrial customer in 2000. Sales to this
customer, which contribute a relatively low profit margin to the
Company, can vary greatly from year to year as they own self-generation
facilities. Reduced revenues for this group of customers were also
affected by certain of these large customers choosing a competitive
electricity supplier starting March 1, 2000 (197.5 million KWH's or 62%
of total large special contract energy sales for the period from March
through December 2000) and not contributing to the Company's standard-
offer service revenues. For those who have chosen standard-offer
service, corresponding revenues have been impacted by the various
associated rate changes in 2000 discussed below.
Exclusive of the Company's largest special contract customers, total
T&D and stranded cost revenues related to energy sales were $8.5
million higher in 2000 as compared to 1999 principally as a result of a
5.3% increase in energy sales and effect of various rate changes
discussed below. As with the large special contract customers, certain
non-special contract commercial customers have been able to purchase
electricity from competitive energy providers starting in March 2000
(37 million KWH's or 3% of total non-special contract energy sales for
the period from March through December 2000), and consequently, the
Company's electric operating revenues have been reduced. The increased
energy sales in 2000 were impacted by the previously discussed strength
in the local economy and colder weather in 2000 as compared to 1999.
As a result of the February 2000 rate order from the MPUC, the
Company's overall rates, including the impact of the initial standard-
offer prices, were reduced by approximately 2.9% starting March 1,
2000. The Company has also implemented various rate changes for its
standard-offer service as approved by the MPUC. The result of these
standard-offer rate changes for the period from March 1 through October
1, 2000 was an increase in the standard-offer prices of 36% for
residential and small commercial customers and 25% for large industrial
customers as compared to the prices when initially set by the MPUC on
March 1, 2000.
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 June 1, 1999, and an
overall 2.7% increase in energy 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
energy 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.
EXPENSES - Fuel for generation and purchased power expense increased
$28.9 million in 2000 as compared to 1999. Total power purchases in
2000 were fairly consistent with those in 1999 due to the Company
continuing to fulfill its long-term power purchase contract obligations
subsequent to the implementation of the electric industry restructuring
on March 1, 2000 and also procuring power to serve the standard-offer
load. In 2000, though, the Company purchased significantly more power
on the spot power market as compared to 1999 as a result of having less
power contracts than in place in 1999. These factors resulted in higher
fuel and purchased power costs in 2000. With more of the Company's
power purchases being made in the spot power market in 2000, the price
of the power was negatively affected by very high oil prices in 2000
and new market rules implemented by NEPOOL in May 1999, which set
prices for replacement purchases from the pool at market levels related
to supply and demand as opposed to actual marginal fuel costs. Also
impacting power cost increases in each year were very unusual
circumstances in NEPOOL for one day in each of the respective years,
with record-breaking loads occurring while many generators were still
out of service on spring maintenance. The result was on-peak power
prices that, for the June 1999 event were two to three times as great
as would normally occur during June. However, the May 2000 event
resulted in prices that were approximately five times as high as the
prices paid on the day in June 1999. The Company incurred
approximately $2 million more in purchased power costs on the day in
2000 as compared to the day in 1999. In connection with the previously
discussed standard-offer service deferral mechanism, the high power
costs for the day in May 2000 have been deferred and are recoverable
from customers in the future.
Increased fuel and purchased power expense was also impacted by higher
ISO New England (ISO) expenses in 2000 as compared to 1999, due to the
implementation of NEPOOL new market rules in May 1999 and $1.9 million
in previously discussed ISO costs in 2000 associated with transmission
constraints. Also increasing fuel and purchased power expense in 2000
was $2 million charged to expense in connection with the previously
discussed write-off associated with power costs to replace generation
from the Maine Yankee nuclear power plant.
The increased expense in 2000 as compared to 1999 was also due to the
previously discussed settlement of the dispute with HQ which resulted
in a $747,000 reduction in expense in the first quarter of 1999, and
the settlement of a dispute related to NEPOOL, which resulted in a
$896,000 reduction in expense in the second quarter of 1999.
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 previously discussed unusually high
replacement power costs incurred in June 1999, 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 the previously discussed 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.
Other operation and maintenance (O&M) expense increased by
approximately $720,000 in 2000 as compared to 1999. Increasing other
O&M expense in 2000 was a $1.7 million increase in O&M payroll due
principally to less labor in 2000 being charged to capital projects as
compared to 1999 as a result of less construction activity in 2000, and
the impact of a 4% wage rate increase for bargaining unit employees on
January 1, 2000 and various wage rate increases for non-bargaining unit
employees. Further increasing other O&M in 2000 was the amortization
expense of approximately $680,000 associated with incremental costs
deferred in connection with the implementation of the electric utility
industry restructuring (see Note 10 to the Consolidated Financial
Statements). Recovery of the cost deferrals was allowed in rates in
the Company's February 2000 rate order from the MPUC over a three year
period starting March 1, 2000. Decreasing other O&M expense in 1999
was a $706,000 increase in overhead expenses allocated to capital
projects. This increased overhead allocation in 1999 was principally a
result of major construction activities being performed by the Company
in connection with the Maine Independence Station, a new 520 megawatt
gas fired generation facility in Veazie, Maine, which has subsequently
become operational and is connected to the regional transmission power
grid. The Company was reimbursed by the owner of the facility for the
construction costs incurred, including overhead expense.
Offsetting these increases to some extent in 2000 was a $1.3 million
decrease in incremental expenditures related to electric utility
industry restructuring activities, costs associated with assessment and
testing of systems for year 2000 compliance, and an upgrade to the
Company's customer information system which was completed in May 1999.
Also reducing other O&M expense in 2000 was a decrease in pension and
other postretirement benefit expense of $1 million, resulting
principally from plan amendments in 1999 and changes in actuarial
assumptions.
Other 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 FERC 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 the previously
discussed major construction activities being performed by the Company
in connection with the Maine Independence Station. 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.
Depreciation and amortization expense increased $1.1 million in 2000 as
compared to 1999 due principally to two factors, the first being
additions to the Company's electric plant in service. Also increasing
depreciation expense in 2000 was the effect of a depreciation study
conducted in December 1996, which 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 amortization was increased in June 1999 as a result
of the Company's generation asset sale. See Note 1 to the Consolidated
Financial Statements for a complete discussion of this transaction.
The amortization recorded as a reduction in depreciation expense in
1999 amounted to $2.2 million as compared to $308,000 of amortization
in 2000.
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.
The Company's expenses over the period 1998-2000 have been
significantly affected by amortizations authorized by the MPUC and
charged annually against earnings. The MPUC has specifically authorized
the inclusion of these expenses in the Company's electric rates. Absent
such regulatory authority, the expenses that gave rise to the
amortizations would have been charged to operations when incurred.
Instead, the recognition of such expenses has been deferred, and appear
on the Consolidated Balance Sheets as assets on the strength of the
regulatory authority to amortize them and 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 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 $3.7 million in 2000, $2.8 million in
1999 and $2.9 million in 1998.
The approximately $170 million of costs associated with the 1995
purchased power contract buy-back were deferred and recorded as a
regulatory asset, to be amortized and collected over a ten-year period,
beginning July 1, 1995. Amortization expense related to this contract
buyout amounted to $17 million in each of 2000, 1999 and 1998.
Prior to the implementation of new rates in March 2000, the Company was
recovering deferred PERC restructuring costs at an annual rate of $1
million. Effective March 1, 2000, recovery of PERC restructuring costs
was adjusted to include the estimated future value of warrants to be
exercised. The adjusted annual amortization amounted to $1.6 million.
The amortization expense associated with PERC contract restructuring
costs was $1.5 million in 2000, $1 million in 1999 and $500,000 in
1998.
Effective with the March 1, 2000 rate change, the Company began
amortizing the deferred asset sale gain over a 70 month period. The
annual amortization amounts are to be recorded in an uneven manner in
order to levelize the Company's revenue requirement over this period.
As a result of an increase in the Company's FERC regulated transmission
rates on June 1, 2000, and the desire to not increase rates to its
retail customers close to the implementation of electric industry
restructuring, which occurred on March 1, 2000, the Company agreed to
reduce its MPUC jurisdictional distribution rates in an amount equal to
the increase in its transmission rates. The reduction in the
distribution rates was accomplished by accelerating the amortization of
the deferred asset sale gain by an annualized total of $2.5 million.
The Company recorded $491,000 of amortization for April and May of 2000
and increased the monthly amortization to $703,000 starting in June
2000.
The decrease in property and other taxes in 2000 period 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 and higher
property tax rates.
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.
The decrease in total federal and state income taxes was principally a
function of lower earnings in 2000 as compared to 1999, while the
increases in income taxes in 1999 was due principally to greater
earnings as compared to 1998. See Footnote 2 to the Consolidated
Financial Statements for a reconciliation of the Company's effective
income tax rate.
OTHER INCOME AND (DEDUCTIONS) AND INTEREST EXPENSE - Allowance for
funds used during construction (AFDC), which includes carrying costs on
certain regulatory assets and liabilities, increased by approximately
$940,000 in 2000 relative to 1999 due mainly to a $1.25 million
increase in carrying costs being recorded on the deferred asset sale
gain in 1999. This increase was offset to some extent by a $378,000
reduction in AFDC being recorded on construction work in progress in
2000 due principally to decreased construction costs.
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.
Other income decreased by approximately $2.7 million in 2000
principally as a result of the previously discussed $1.5 million income
tax benefit recorded in 1999 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 and the
previously discussed incremental merger related costs ($1.8 million,
net of tax) incurred in 2000. Also decreasing other income in 2000 as
compared to 1999 was a $310,000, net of tax, gain on sale of the
Company's wholly-owned subsidiary, Penobscot Hydro, in July 1999 (See
Note 6 to the Consolidated Financial Statements for a discussion of
this sale). These decreases in other income in 2000 were offset to
some extent by the $714,000, net of tax, gain on the previously
discussed sale of Penobscot Gas in July
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 ; the previously discussed $310,000,
net of tax gain on sale of Penobscot Hydro; and the Company earned
greater interest income as a result of investments utilizing the
generation asset sale proceeds.
Long-term debt interest expense decreased $3.8 million in 2000 as
compared to 1999 and $3.9 million in 1999 as compared to 1998 as a
result of the previously discussed principal repayments in 1998, 1999
and 2000 on various long-term debt issues.
Other interest expense decreased $500,000 in 2000 due principally to a
reduction in the amortization of debt issuance costs in 2000. The
amortization decrease was primarily attributable to the end of the
amortization of certain deferred debt issuance costs in 1999 as a
result of the repayment of long-term debt through the utilization of
generation asset sale proceeds and the end of the amortization period
of certain deferred debt issuance costs in June 2000. Also impacting
the reduction in other interest expense was $11 million in weighted
average borrowings under the Company's revolving credit facility for
the first quarter of 1999 as compared to no outstanding borrowings in
2000. 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 $1.4 million due principally to a $20
million reduction in weighted average short-term borrowings outstanding
in 1999 as compared to 1998.
CONTINGENCIES AND DISCLOSURES ABOUT MARKET RISK
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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 (DEP) under various Maine environmental statutes. The
Company is actively engaged in complying with these federal and state
acts and statutes, and it has not, to date, encountered material
difficulties in connection with such compliance.
In 1992, the Company received notice from the DEP that it was
investigating the cleanup of several sites in Maine that were used in
the past for the disposal of waste oil and other hazardous substances,
and that the Company, as a generator of waste oil that was disposed at
those sites, may be liable for certain cleanup costs. The Company
learned in October 1995 that the EPA placed one of those sites on the
National Priorities List under the Comprehensive Environmental
Response, Compensation and Liability Act and would 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 on 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, and possible effects of future legislation or regulation and
the possible effects of technological changes. At December 31, 2000,
the liability recorded by the Company for its estimated environmental
remediation costs amounted to $282,000. The Company's actual future
environmental remediation costs may be higher as additional factors
become known.
In 2000 the Company expended approximately $291,000 in operations
expense and $103,000 in capital expenditures to comply with
environmental standards for air, water and hazardous materials.
DISCLOSURES ABOUT MARKET RISK - The Company's major financial market
risk exposure is changing interest rates. Changes in 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, which is associated with the Company's medium term
notes (See Note 14 to the Consolidated Financial Statements). As of
December 31, 2000, the Company had $11.7 million of medium term notes
outstanding which bear floating, LIBOR-based rates (6.56125% LIBO rate
at December 31, 2000). The interest rate swap fixes the interest rate
on the medium term notes at 5.72% for the full notional amount of the
debt. See Note 4 to the Consolidated Financial Statements for a
discussion of these medium term notes.
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. Based
on current guidance, management does not believe that the adoption of
SFAS 133 will have a material effect on the Company's financial
statements.
Item 8
Financial Statements & Supplementary Data
- -----------------------------------------
BANGOR HYDRO-ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF INCOME
For the Years Ended December 31,
2000 1999 1998
Electric Operating Revenues
Electric operating revenue (Note 1) $ 146,204,013 $ 197,994,796 $ 195,144,007
Standard offer service (Note 10) 66,133,532 - -
------------- --------------- ---------------
$ 212,337,545 $ 197,994,796 $ 195,144,007
------------- --------------- ---------------
Operating Expenses:
Fuel for generation and purchased power (Notes 1 and 3) $ 44,144,334 $ 80,748,385 $ 82,026,860
Standard offer service purchased power (Note 10) 65,552,980 - -
Other operation and maintenance (Notes 1 and 5) 37,211,862 36,491,666 34,448,324
Depreciation and amortization (Note 1) 9,158,885 8,063,939 9,749,229
Amortization of Seabrook nuclear unit (Note 7) 1,699,050 1,699,050 1,699,050
Amortization of contract buyouts and restructuring (Note 6) 22,311,448 20,801,816 20,442,441
Amortization of deferred asset sale gain (Note 10) (6,393,038) - -
Taxes -
Local property and other 4,795,698 5,059,140 5,549,049
Income (Note 2) 7,432,261 8,973,166 6,093,286
------------- --------------- ---------------
$ 185,913,480 $ 161,837,162 $ 160,008,239
------------- --------------- ---------------
Operating Income $ 26,424,065 $ 36,157,634 $ 35,135,768
Other Income And (Deductions):
Allowance for equity funds used during construction (Note 1) $ 158,698 $ (326,026) $ 430,028
Other, net of applicable income taxes (Notes 1, 2, 6 and 11) 454,715 3,132,097 862,723
------------- --------------- ---------------
Income Before Interest Expense $ 27,037,478 $ 38,963,705 $ 36,428,519
------------- --------------- ---------------
Interest Expense:
Long-term debt (Notes 4 and 13) $ 15,211,905 $ 19,004,624 $ 22,906,021
Other (Note 4) 893,455 1,393,547 2,750,863
Allowance for borrowed funds used during construction (Note 1) (169,929) 284,933 (693,682)
------------- --------------- ---------------
$ 15,935,431 $ 20,683,104 $ 24,963,202
------------- --------------- ---------------
Net Income $ 11,102,047 $ 18,280,601 $ 11,465,317
Dividends On Preferred Stock (Note 3) 265,570 945,396 1,244,488
------------- --------------- ---------------
Earnings Applicable To Common Stock $ 10,836,477 $ 17,335,205 $ 10,220,829
------------- --------------- ---------------
Weighted Average Number Of Shares Outstanding (Note 3) 7,363,424 7,363,424 7,363,424
------------- --------------- ---------------
Earnings Per Common Share (Note 3):
Basic $ 1.47 $ 2.35 $ 1.39
Diluted 1.30 2.08 1.33
------------- --------------- ---------------
Dividends Declared Per Common Share $ .80 $ .45 $ -
------------- --------------- ---------------
The accompanying notes are an integral part of these consolidated financial statements.
Item 8
Financial Statements & Supplementary Data
- -----------------------------------------
BANGOR HYDRO-ELECTRIC COMPANY
CONSOLIDATED BALANCE SHEETS
December 31,
Assets 2000 1999
Investment In Utility Plant:
Electric plant in service, at original cost (Notes 6, 10 and 12) $ 316,167,622 $ 306,970,789
Less - Accumulated depreciation and amortization (Notes 1, 6 and 10) 86,684,205 84,825,432
------------- -------------
$ 229,483,417 $ 222,145,357
Construction work in progress (Note 1) 5,457,707 5,668,246
------------- -------------
$ 234,941,124 $ 227,813,603
Investments in corporate joint ventures: (Notes 1 and 6)
Maine Yankee Atomic Power Company $ 4,949,696 $ 5,266,697
Maine Electric Power Company, Inc. 672,581 529,630
------------- -------------
$ 240,563,401 $ 233,609,930
------------- -------------
Other Investments, at cost (Notes 6 and 9) $ 3,174,561 $ 3,629,431
------------- -------------
Funds held by trustee, at cost (Notes 4, 9 and 10) $ 22,696,405 $ 22,698,843
------------- -------------
Current Assets:
Cash and cash equivalents (Notes 1 and 9) $ 12,462,780 $ 15,691,166
Accounts receivable, net of reserve ($761,000 in 2000 and $1,075,000 in 1999) 21,731,869 18,269,672
Unbilled revenue receivable (Note 1) 15,778,696 14,127,645
Inventories, at average cost:
Material and supplies 2,585,107 2,792,904
Fuel oil 93,746 45,310
Prepaid expenses 829,181 927,998
------------- -------------
Total current assets $ 53,481,379 $ 51,854,695
------------- -------------
Regulatory Assets and Deferred Charges:
Investment in Seabrook nuclear project, net of accumulated amortization
of $33,571,296 in 2000 and $31,872,246 in 1999 (Notes 7 and 10) $ 25,270,779 $ 26,969,829
Costs to terminate/restructure purchased power contracts, net of accumulated
amortization of $123,171,966 in 2000 and $100,860,518 in 1999
(Notes 6 and 10) 99,312,319 118,565,234
Maine Yankee decommissioning costs (Notes 6 and 10) 43,028,107 46,041,644
Other regulatory assets (Notes 2,5,6,10, and 13) 41,025,080 36,925,665
Other deferred charges 3,667,769 3,655,009
------------- -------------
Total regulatory assets and deferred charges $ 212,304,054 $ 232,157,381
------------- -------------
Total Assets $ 532,219,800 $ 543,950,280
============= =============
Stockholders' Investment and Liabilities
Capitalization: (see accompanying statement)
Common stock investment (Note 3) $ 137,419,659 $ 132,721,895
Preferred stock (Note 3) 4,734,000 4,734,000
Long-term debt, net of current portion (Notes 4, 9 and 13) 161,960,000 183,300,000
------------- -------------
Total capitalization $ 304,113,659 $ 320,755,895
------------- -------------
Current Liabilities:
Notes payable - banks (Note 4) $ - $ -
------------- -------------
Other current liabilities -
Current portion of long-term debt (Notes 4 and 9) $ 21,340,000 $ 19,460,000
Accounts payable 24,785,193 14,175,408
Dividends payable 1,539,114 1,170,942
Accrued interest 2,529,237 2,552,758
Customers' deposits 502,276 398,897
Current income taxes payable 305,323 4,125,696
------------- -------------
Total other current liabilities $ 51,001,143 $ 41,883,701
------------- -------------
Total current liabilities $ 51,001,143 $ 41,883,701
------------- -------------
Commitments and Contingencies (Notes 6, 12 and 15)
Regulatory and Other Long-term Liabilities (Note 2)
Deferred income taxes - Seabrook $ 13,109,098 $ 13,994,668
Other accumulated deferred income taxes 58,314,350 55,826,890
Maine Yankee decommissioning liability (Note 6) 43,028,107 46,041,644
Deferred gain on asset sale (Note 10) 22,788,408 29,357,358
Other regulatory liabilities (Note 10) 12,556,052 9,872,188
Unamortized investment tax credits 1,452,059 1,591,727
Accrued pension and postretirement benefit costs (Note 5) 12,124,106 11,301,057
Other long-term liabilities (Notes 6 and 12) 13,732,818 13,325,152
------------- -------------
Total regulatory and other long-term liabilities $ 177,104,998 $ 181,310,684
------------- -------------
Total Stockholders' Investment and Liabilities $ 532,219,800 $ 543,950,280
============= =============
The accompanying notes are an integral part of these consolidated financial statements.
Item 8
Financial Statements & Supplementary Data
BANGOR HYDRO-ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF CAPITALIZATION
December 31,
2000 1999
---- ----
Common Stock Investment (Notes 1 and 3)
Common stock, par value $5 per share- $ 36,817,120 $ 36,817,120
Authorized -- 10,000,000 shares
Outstanding -- 7,363,424 shares in 2000 and 1999
Amounts paid in excess of par value 58,642,367 58,890,342
Retained earnings 41,960,172 37,014,433
-------------- -------------
Total common stock investment $ 137,419,659 $ 132,721,895
Preferred Stock, Non-participating, cumulative, par value $100 per share, -------------- -------------
authorized 600,000 shares (Note 3):
Not redemable or redeemable solely at the option of the issuer-
7%, Noncallable, 25,000 shares authorized and outstanding $ 2,500,000 $ 2,500,000
4.25%, 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
Long-Term Debt (Notes 4, 9 and 14) -------------- -------------
First Mortgage Bonds-
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
-------------- -------------
$ 85,000,000 $ 85,000,000
Other Long-Term Debt- -------------- -------------
Finance Authority of Maine - Taxable Electric Rate
Stabilization Revenue Notes, 7.03% Series 1995A, due 2005 $ 86,600,000 $ 100,600,000
Medium Term Notes, Variable interest rate-LIBO rate plus 1.125%, due 2002 11,700,000 17,160,000
-------------- -------------
$ 98,300,000 $ 117,760,000
Less: Current portion of long-term debt 21,340,000 19,460,000
-------------- -------------
$ 76,960,000 $ 98,300,000
-------------- -------------
Total Long-Term Debt $ 161,960,000 $ 183,300,000
-------------- -------------
Total Capitalization $ 304,113,659 $ 320,755,895
============== =============
The accompanying notes are an integral part of these consolidated financial statements.
Item 8
Financial Statements & Supplementary Data
- -----------------------------------------
BANGOR HYDRO-ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the years ended December 31,
2000 1999 1998
---- --- ----
Cash Flows From Operating Activities:
Net income $ 11,102,047 $ 18,280,601 $ 11,465,317
Adjustments to reconcile net income to net cash
from operating activities:
Depreciation and amortization 9,158,885 8,063,939 9,749,229
Amortization of Seabrook nuclear project (Note 7) 1,699,050 1,699,050 1,699,050
Amortization of contract buyouts and restructuring (Note 6) 22,311,448 20,801,816 20,442,441
Amortization of deferred asset sale gain (Note 10) (6,393,038) - -
Other amortizations 1,896,179 2,590,725 2,035,505
Allowance for equity funds used during construction (Note 1) (158,698) 326,026 (430,028)
Deferred income tax provision and amortization of
investment tax credits (Note 2) (2,765,264) (131,897) 5,876,874
Gain on sale of subsidiary (Notes 6 and 10) (1,205,727) (523,390) -
Deferred Maine Yankee replacement power cost write-off (Note 6) 1,992,848 - -
Flow-through of unamortized investment tax credits
and excess deferred income taxes (Note 2) - (1,485,131) -
Changes in assets and liabilities:
Costs to restructure purchased power contract (Note 6) (1,000,000) (1,099,000) (7,704,185)
Deferred standard-offer service costs (Note 10) (2,988,823) - -
Deferred special rate contract revenues (Note 10) (1,368,948) - -
Deferred incremental Maine Yankee costs (Note 6) 807,616 2,886,401 (793,608)
Deferred incremental ice storm costs (Note 11) - 1,817,851 (4,200,423)
Deferred costs associated with generation asset sale (Note 10) 107,765 (5,266,689) (2,317,688)
Exercise of PERC warrants-cash paid in lieu of issuing shares (Note 6) (2,129,387) (3,321,710) -
Payment received related to terminated purchased power contract (Note 6 - 1,750,000 -
Deferred revenue - - (1,285,101)
Accounts receivable, net and unbilled revenue (5,113,248) (2,759,315) (1,423,947)
Accounts payable 10,609,785 (11,081) 724,721
Accrued interest (23,521) (921,611) (192,272)
Current and deferred income taxes (10,093) 3,755,913 121,153
Accrued postretirement benefit costs (Note 5) 1,322,206 1,608,414 600,699
Other current assets and liabilities, net 202,486 (356,034) (22,036)
Other, net (433,387) (345,523) (3,413,741)
------------- -------------- -------------
Net Increase in Cash From Operating Activities: $ 37,620,181 $ 47,359,355 $ 30,931,960
Cash Flows From Investing Activities: ------------- -------------- -------------
Construction expenditures $ (16,680,501) $ (20,323,360) $ (18,240,226)
Asset sale proceeds (Note 10) - 79,587,841 6,200,000
Proceeds from sale of subsidiary (Notes 6 and 10) 1,250,000 10,000,000 -
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) (169,929) 284,933 (693,682)
------------- -------------- -------------
Net (Decrease) Increase in Cash From Investing Activities $ (15,600,430) $ 75,749,414 $ (18,933,908)
Cash Flows From Financing Activities: ------------- -------------- -------------
Dividends on preferred stock $ ($265,570)$ (1,127,882) $ (1,216,434)
Dividends on common stock (5,522,567) (2,209,028) -
Payments on long-term debt (Note 4) (19,460,000) (85,782,897) (53,478,554)
Payments on mandatory redeemable preferred stock (Note 4) - (9,243,742) (1,593,914)
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)
------------- -------------- -------------
Net Decrease in Cash From Financing Activities $ (25,248,137) $ (110,363,549) $ (9,988,902)
------------- -------------- -------------
Net (Decrease) Increase in Cash and Cash Equivalents $ (3,228,386) $ 12,745,220 $ 2,009,150
Cash and Cash Equivalents at Beginning of Year 15,691,166 2,945,946 936,796
------------- -------------- -------------
Cash and Cash Equivalents at End of Year $ 12,462,780 $ 15,691,166 $ 2,945,946
============= ============== =============
The accompanying notes are an integral part of these consolidated financial statements.
Item 8
Financial Statements & Supplementary Data
- -----------------------------------------
BANGOR HYDRO-ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF COMMON STOCK INVESTMENT
Amounts Paid Total Common
Common in Excess of Retained Stock
Stock Par Value Earnings Investment
----------- ----------- ----------- ------------
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
Net income - - 11,102,047 11,102,047
Cash dividends declared on-
Preferred stock - - (265,570) (265,570)
Common stock - - (5,890,738) (5,890,738)
Exercise of warrants-cash paid
in lieu of issuing shares (Note 3) - (247,975) - (247,975)
----------- ----------- ----------- ------------
Balance December 31, 2000 $36,817,120 $58,642,367 $41,960,172 $137,419,659
----------- ----------- ----------- ------------
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 transmission and distribution 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, Bangor Var Co., Inc.
(BVC), Bangor Energy Resale, Inc. (BERI), CareTaker, Inc. (CareTaker),
Bangor Fiber Co., Inc. (Bangor Fiber), Penobscot Natural Gas Co., Inc.
(Penobscot Gas) for the first six months of 2000, and Penobscot Hydro
Co, Inc. (PHC) for the first seven months of 1999. The Company sold
Penobscot Gas in early July 2000 and PHC in late July 1999. See Notes
6 and 10 for a detailed discussion of the Penobscot Gas and PHC sales,
respectively. 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). CareTaker was incorporated in 1997 and provides security
alarm services on a retail basis to residential and commercial
customers. Bangor Fiber was formed in 2000 to supply fiber optic
communications cable to communications companies and cable service
providers and other related activities. See Note 6 for additional
information with respect to BVC, Penobscot Gas and PHC. 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, including that
associated with standard offer service (See Note 10) 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. As of March 1,
2000, the Company bills customers for the energy supplied by
competitive energy providers (See Note 10). Competitive energy
providers are paid only after the funds are collected from customers.
The Company records accounts receivable for the amounts billed to
competitive energy customers and a corresponding accounts payable for
the amounts due to the energy supplier. No revenue is recognized as the
Company is acting as an agent.
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 overaccu-
mulated depreciation (discussed below), was approximately 2.9% in 2000,
2.1% in 1999 and 2.5% in 1998.
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 $307,000 in amortization in 2000, $2.4 million in 1999
and $1.6 million in 1998 which reduced depreciation expense. The 1999
and 2000 amortizations were increased as a result 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 $10 million in 2000, $9.5 million in 1999 and
$7 million in 1998.
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 filed with the FERC for authorization to reclassify the
reserve for licensed hydro projects, classified as appropriated
retained earnings, to unappropriated earnings. Such authorization was
received in February 2001 and the reserve was reclassified from
appropriated retained earnings to unappropriated retained earnings at
December 31, 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 2000
and 1999 and included in AFDC in the Consolidated Statements of Income.
The average AFDC (carrying costs) rates computed by the Company were
9.3% in 2000, 9.5% for 1999 and 9.1% in 1998.
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 $15.1 million,
$20.9 million and $23.8 million in 2000, 1999 and 1998,
respectively. Cash paid for income taxes was approximately $10 million,
$8.9 million and $655,000 in 2000, 1999 and 1998, respectively. Non-
cash 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 exposure is changing interest rates.
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 combin-ation of both fixed and variable rate debt
instruments and an interest rate swap (see Notes 4 and 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 2000 Consolidated Financial
Statements.
NOTE 2. INCOME TAXES
- --------------------
The individual components of federal and state income taxes reflected
in the Consolidated Statements of Income for 2000, 1999 and 1998 are
stated in the table below.
Year Ended December 31, 2000 1999 1998
Current:
Federal $ 7,445,626 $7,390,387 $ 725,466
State 2,920,769 2,314,251 195,876
----------- ---------- ----------
$10,366,395 $9,704,638 $ 921,342
----------- ---------- ---------
Deferred:
Federal-Other $ (1,276,946) $ 89,444 $5,089,469
State-Other (934,560) (375,468) 1,442,801
Federal-Seabrook (341,917) (341,917) (341,917)
State-Seabrook (72,173) (72,173) (72,173)
----------- ------------ ------------
$ (2,625,596) $ (700,114) $6,118,180
-------------- ------------- ------------
Investment Tax Credits, Net $ (139,668) $ (317,877) $ 385,805)
-------------- ------------- ----------
Total Provision $ 7,601,131 $8,686,647 $6,653,717
Allocated to Other Income (168,870) 286,519 (560,431)
-------------- ------------- -----------
Charged to Operating Expense $ 7,432,261 $8,973,166 $6,093,286
============ ========== ===========
The table below reconciles the income tax provision, calculated by
multiplying income before federal income taxes (as reported on the
Consolidated Statements of Income) by the statutory federal income
tax rate to the federal income tax expense reported on the Consolidated
Statements of Income. The difference is represented by the permanent
and timing differences for which deferred taxes are not provided for
ratemaking purposes.
2000 1999 1998
-------------------------------------
(Dollars in Thousands)
Amount % Amount % Amount %
-------------------------------------------
Federal income tax provision at
statutory rate $6,546 35.0% $9,439 35.0% $6,342 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 164 .9 253 .9 40 .2
Equity component of AFDC 138 .7 185 .7 151 .8
Amortization of equity component
of AFDC on recoverable Seabrook
investment (160) (.8) (160) (.6) (160) (.9)
Other 33 .1 (29) (.1) (28) (.1)
--------------------------------------------
Federal income tax provision before
effect of timing differences $6,371 34.1% $9,190 34.1% $6,339 35.0%
Less (Plus) timing differences
that are flowed through for
rate-making and accounting
purposes:
Amortization of debt component
of AFDC and capitalized
overheads on recoverable
Seabrook investment (151) (.8) (151) (.6) (151) (.8)
Book depreciation greater than
tax depreciation (69) (.4) (85) (.3) (88) (.5)
Equity earnings in excess of
(less than) dividends (41) (.2) (276) (1.0) 201 1.1
Amortization of deferred asset
sale gain (276) (1.5) - - - -
State income tax liability
deducted for federal
income tax purposes 550 2.9 673 2.5 498 2.8
Reversal of excess deferred
income taxes 147 .8 167 .6 124 .7
Amortization of investment
tax credits 140 .8 350 1.3 241 1.3
Investment tax credits and
excess deferred taxes
flowed through - - 1,485 5.5 - -
Other 42 .3 27 .1 282 1.5
---------------------------------------------------
Federal income tax provision $6,029 32.2% $7,000 26.0% $5,232 28.9%
===================================================
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. In 2000, the Company utilized the remaining $3.6 million of
federal alternative minimum tax credits to reduce its regular income
tax liability while in 1999, the Company utilized $4.2 million of
federal and state alternative minimum tax credits. In 1998 the Company
utilized approximately $31.9 million 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
cumulative net additional deferred income tax liabilities of
approximately $16.4 million as of December 31, 2000 and $16 million as
of December 31, 1999. 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
($25.3 million and $24.8 million as of December 31, 2000 and 1999,
respectively), offset by the effect of the 1987 change to lower income
tax rates (reduced by the 1% increase in the federal income tax rate in
1993) that will be refunded to customers over time ($8.1 million and
$7.9 million as of December 31, 2000 and 1999, respectively), and the
establishment of deferred tax assets on unamortized investment tax
credits ($858,000 and $900,000 as of December 31, 2000 and 1999,
respectively). These latter amounts have been recorded in Other
Regulatory Liabilities at December 31, 2000 and 1999. 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, 2000 and 1999:
2000 1999
-------------- --------------
Deferred Income Tax Liabilities:
Costs to terminate/restructure purchased
power contracts $35,091,730 $ 42,793,031
Excess book over tax basis of electric
plant in service 37,184,354 35,395,877
Investment in jointly-owned companies 1,358,081 1,492,533
Deferred standard-offer service costs 1,248,764 -
Deferred incremental ice storm costs 1,156,526 1,429,579
Deferred restructuring related costs 454,142 681,031
Other 817,035 319,488
------------ -------------
$ 77,310,632 $ 82,111,539
------------ -------------
Deferred Income Tax Assets:
Deferred asset sale gain $ 8,776,804 $ 12,121,099
Accrued pension and postretirement
benefit costs 4,500,464 4,127,529
Deferred state income tax benefit 1,724,310 3,317,437
Unamortized investment tax credit 858,554 941,134
Deferred write-off of Maine Yankee replacement
power costs 813,234 -
Deferred incremental Maine Yankee costs 673,783 453,414
Reserve for bad debts 632,652 719,981
Deferred taxes provided on alternative
minimum tax - 3,627,596
Other 1,016,481 976,459
-------------- -------------
$ 18,996,282 $ 26,284,649
------------- -------------
Total other accumulated deferred income taxes $ 58,314,350 $ 55,826,890
============ ============
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 the recognition of previously 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
regard 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 1998. In 1998 the Company made a $1.5 million sinking
fund payment, as well as approximately $94,000 under the make whole
provision.
EXERCISE OF WARRANTS - In 2000, 212,786 common stock warrants, which
were issued in connection with the PERC purchased power contract
restructuring, were exercised at market prices ranging from
$14.75 to $24.8125 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 $2.5 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 a $248,000 addition to paid-in
capital, an adjustment has been made in connection with the cash payments
option to reduce paid-in capital by this amount as of December 31, 2000.
At December 31, 2000 there were approximately 1.4 million unexercised
common stock warrants in connection with the PERC contract
restructuring.
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. 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 a $410,000 adjustment to paid-in capital,
an adjustment was made in connection with the cash payments option to
reduce paid-in capital by this amount 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):
2000 1999 1998
----------- ----------- -----------
Earnings applicable to common stock $10,836,477 $17,335,205 $10,220,829
------------ ------------ -----------
Average common shares outstanding 7,363,424 7,363,424 7,363,424
Plus: incremental shares from assumed
conversion of outstanding warrants 990,099 984,200 329,778
------------ ------------ ---------
Average common shares outstanding plus
assumed warrants converted 8,353,523 8,347,624 7,693,202
------------ ----------- -----------
Basic earnings per common share $1.47 $2.35 $1.39
------------- ------------ -----------
Diluted earnings per common share $1.30 $2.08 $1.33
============= ============ ==========
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 revolving
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 2000 and 1999.
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
commercial paper, corporate notes and bonds, certificates of deposit,
municipal bonds, U.S. Agency obligations and repurchase agreements.
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. The Company
has historically selected the LIBO rate interest option. 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 realized reduced interest expense of $96,168
in 2000 and 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 2000 and 1999.
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, which began 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:
2000 1999 1998
----------- ----------- -----------
Total credit available at end of period $30,000,000 $30,000,000 $30,000,000
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
Effective interest rate (exclusive of fees) on
borrowings outstanding at end of period -% -% 7.2%
Average daily outstanding borrowings for
the period $ - $ 2,802,740 $20,369,863
Weighted daily average annual interest rate -% 6.7% 7.9%
Highest level of borrowings outstanding at any
month-end during the period $ - $13,000,000 $37,500,000
=========== =========== ===========
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, 2000, amounting to $133,300,000,
are $21,340,000 in 2001, $41,560,000 in 2002, $32,200,000 in 2003,
$18,400,000 in 2004, and $19,800,000 in 2005.
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.
There were no employer contributions to the noncontributory pension
plan in 2000, 1999 or 1998. The plan's assets are composed of fixed
income securities, equity securities and cash equivalents.
The following tables detail the funded status of the plan, the amounts
recognized in the Company's Consolidated Financial Statements, the
components of pension (income) expense for 2000, 1999 and
1998 and the major assumptions used to determine these amounts
(includes both the funded and unfunded plans).
Total pension (income) expense included the following components:
2000 1999 1998
---------- ---------- ----------
Service cost-benefits earned during
the period $1,186,910 $1,439,047 $1,208,393
Interest cost on projected benefit
obligation 3,479,260 3,295,172 3,107,258
Expected return on plan assets (4,460,416) (4,317,379) (3,737,267)
Amortization of unrecognized asset and
gains (losses) (664,911) 252,043 (333,507)
------------ ---------- -----------
Total pension (income) expense $ (459,157) $ 668,883 $ 244,877
============ ========== ===========
The following table sets forth the plans' funded status at December 31,
2000 and 1999:
2000 1999
----------- -----------
Change in Projected Benefit Obligation
Balance as of December 31, 1999 and 1998 $45,165,460 $48,215,365
Service cost 1,186,910 1,439,047
Interest cost 3,479,260 3,295,172
Benefits paid (2,900,824) (2,965,723)
Amendments - 1,047,567
(Gains) and losses 1,020,990 (5,865,968)
----------- -----------
Balance as of December 31, 2000 and 1999 $47,951,796 $45,165,460
----------- -----------
Change in Plan Assets
Balance as of December 31, 1999 and 1998 $51,834,730 $49,495,200
Employer contributions 40,000 40,000
Benefits paid (2,900,824) (2,965,723)
Actual return, less expenses (548,040) 5,265,253
----------- -----------
Balance as of December 31, 2000 and 1999 $48,425,866 $51,834,730
----------- -----------
Funded status $ 474,070 $ 6,669,270
Unrecognized net transition asset (390,175) (1,322,500)
Unrecognized prior service cost 2,630,838 3,290,845
Unrecognized gain (4,756,609) (11,178,648)
----------- -----------
Accrued pension balance at
December 31, 2000 and 1999 $ (2,041,876) $ (2,541,033)
============ ============
The accumulated benefit obligation for the unfunded supplemental
pension plan with accumulated benefit obligations in excess of plan
assets was $1,999,298 and $1,220,982 as of December 31, 2000 and 1999,
respectively.
2000 1999 1998
------ ----- -----
Significant assumptions used were-
Discount rate 8.0% 6.75% 7.0%
Rate of increase in future compensation levels 4.0% 4.0% 4.0%
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, 2001, are
7.75% and 4%, respectively, and were used to calculate the plans'
funded status at December 31, 2000.
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 $1.7 million in
2000 and $1.3 million in each of 1999 and 1998. The VEBA's assets are
composed of United States Treasury money market funds. The Company's
general policy is to contribute to the VEBA amounts necessary to fund
claims and administrative costs.
The actuarially determined net periodic postretirement benefit cost for
2000, 1999 and 1998 and the major assumptions used to determine these
amounts are shown in the following tables:
2000 1999 1998
---------- ---------- ----------
Service cost of benefits earned $ 573,740 $ 583,385 $ 401,856
Interest cost on accumulated postretirement
benefit obligation 1,716,563 1,518,092 1,060,671
Actual return on plan assets (22,002) (9,710) (10,608)
Amortization of unrecognized transition
obligation 501,200 501,200 501,200
Other deferrals, net 280,255 405,834 (14,392)
---------- --------- ----------
Net periodic postretirement benefit cost $3,049,756 $2,998,801 $1,938,727
========== ========== ==========
The following table sets forth the benefit plan's funded status at
December 31, 2000 and 1999.
2000 999
------------ ------------
Change in Accumulated Postretirement
Benefit Obligation
Balance as of December 31, 1999 and 1998 $ 20,720,833 $ 19,073,629
Service cost 573,740 583,385
Interest cost 1,716,563 1,518,092
Claims paid (1,091,334) (1,301,239)
Gains and losses 1,954,390 846,966
------------- ------------
Balance as of December 31, 2000 and 1999 $ 23,874,192 $ 20,720,833
------------ ------------
Change in Plan Assets
Balance as of December 31, 1999 and 1998 $ 358,971 $ 321,408
Employer contributions 1,727,550 1,347,000
Retiree contributions 43,428 47,152
Claims paid (1,091,334) (1,301,239)
Actual return, less expenses (158,881) (55,350)
------------ -------------
Balance as of December 31, 2000 and 1999 $ 879,734 $ 358,971
------------ -------------
Funded status $(22,994,458) $(20,361,862)
Unrecognized net transition obligation 6,013,600 6,514,800
Unrecognized loss 6,898,628 5,087,038
------------ ------------
Accrued postretirement benefit cost balance at
December 31, 2000 and 1999 $(10,082,230) $ (8,760,024)
============ ============
2000 1999 1998
------ ------ -----
Significant assumptions used were-
Discount rate 8.0% 6.75% 7.0%
Health care cost trend rate,
employees less than age 65-
Near-term 7.0% 7.5% 8.0%
Long-term 5.0% 4.5% 5.0%
Health care cost trend rate,
employees greater than age 65-
Near-term 7.0% 7.5% 8.0%
Long-term 5.0% 4.5% 5.0%
Rate of return on plan assets 5.0% 5.0% 5.0%
The discount rate used to determine postretirement benefit obligations,
effective January 1, 2001, and the Plan's funded status at December 31,
2000, was 7.75%.
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 $ 402,129 $ (318,515)
Effect on postretirement benefit obligation 3,103,456 (2,517,883)
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
was deferred and is recorded as a regulatory asset at December 31,
1999. Recovery of this regulatory asset began starting March 1, 2000
over a three-year period as specified in the Company's 2000 rate order
from the MPUC.
The estimates of the Company's accrued pension and postretirement
benefit costs involve the utilization of significant assumptions.
Changes in any one of 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 $370,000 in
2000, $331,000 in 1999 and $330,000 in 1998.
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.
Plant Shutdown and Rate Case Settlement - On August 6, 1997, the board
of directors of Maine Yankee voted to permanently cease power
operations at 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 Nuclear Regulatory Commission was scheduled to expire
in 2008.
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 29 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, as amended, are
also filed with the FERC.
In November 1997, Maine Yankee submitted for filing certain amendments
to the Power Contracts (the Amendatory Agreements) and revised rates to
reflect the decision to shut down the Plant and to request approval of
an increase in the decommissioning component of its formula rates.
Maine Yankee's submittal also requested certain other rate changes,
including recovery of unamortized investment (including fuel) and
certain changes to its billing formula, consistent with the
nonoperating status of the Plant.
During 1998 and early 1999, the parties to the FERC proceeding,
including, among others, the MPUC staff, the Maine Office of the Public
Advocate and the Secondary Purchasers, engaged in extensive discovery
and negotiations, which resulted in the filing of a settlement
agreement with the FERC in January 1999. A separately negotiated
settlement filed with the FERC in February 1999 resolved the issues
raised by the Secondary Purchasers by limiting the amounts of their
payments 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 were approved by the FERC
on June 1, 1999. The settlements constitute a full settlement of all
issues raised in the FERC proceeding, including decommissioning cost
issues and the issues pertaining to the prudence of the management,
operation, and decision to permanently cease operation of the Plant.
The primary settlement provides for Maine Yankee to recover amounts
intended to cover the costs of decommissioning and those associated
with the construction and maintenance of an of an off-site independent
spent fuel storage installation (ISFSI). The settlement also provides
for recovery of the unamortized investment (including fuel) in the
Plant, together with a return on equity of 6.50% on limited equity
balances. 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, Maine Yankee agreed
to file with the FERC a rate proceeding that will have an effective
date of no later than January 1, 2004, when major decommissioning
activities are expected to be nearing completion. As a separate part
of the settlement, the three Maine Sponsors of Maine Yankee, the MPUC
Staff, and the Office of the Public Advocate entered into a further
agreement (Maine 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 Company believes that the settlement, including the Maine
Agreement, constituted a reasonable resolution of the issues raised in
the Maine Yankee FERC proceeding, and eliminated significant
uncertainties concerning the Company's future financial performance.
Under the Maine Agreement, the Company would continue to recover its
Maine Yankee costs , although the allowed return on equity associated
with the Company's equity balance in Maine Yankee was set at 6.50%.
The final major provision of the Maine Agreement required 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 exceeded 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. As
part of a further settlement, the Company's liability was fixed at
approximately $2.2 million to be reflected as a reduction in stranded
costs effective March 1, 2002. The Company charged to fuel and
purchased power expense and recorded as a regulatory liability $2
million in December 2000 representing the net present value of this future
obligation
Termination of Decommissioning Operations Contract - On May 4, 2000,
Maine Yankee notified its decommissioning operations contractor, Stone
& Webster Engineering Corporation (Stone & Webster), that it was
terminating the decommissioning operations contract pursuant to the
terms of the contract. Stone & Webster subsequently notified Maine
Yankee that it was disputing Maine Yankee's grounds for terminating the
contract. On May 8, 2000, Stone & Webster announced a proposed
transaction in which it would transfer substantially all of its assets
in exchange for an immediate credit facility and other consideration,
including cash and stock. Stone & Webster said that the credit
facility was intended to enable it to address its liquidity
difficulties and continue to operate its businesses until the asset
sale was completed. Stone & Webster also announced that it intended to
seek bankruptcy court approval of the asset sale and credit agreement.
On June 2, 2000, Stone & Webster filed a voluntary petition under
Chapter 11 of the U.S. Bankruptcy Code with the United States
Bankruptcy Court for the District of Delaware. By Sale Order dated
July 13, 2000, the Bankruptcy Court approved the sale of substantially
all of Stone & Webster's assets to the successful bidder in the Chapter
11 sale, The Shaw Group, Inc. (Shaw), for cash, stock, and the
assumption of certain liabilities of Stone & Webster, and the proposed
transaction announced earlier by Stone & Webster was terminated. Stone
& Webster reported that the Shaw transaction was effectively closed on
July 14, 2000, and that it would continue to operate as a Debtor-in-
Possession subject to the supervision and orders of the Bankruptcy
Court.
Commencing in May 2000, Maine Yankee entered into interim agreements
with Stone & Webster in order to allow decommissioning work to continue
and avoid the adverse consequences of an abrupt or inefficient
demobilization from the Plant site. After obtaining assignments of
several subcontracts from Stone & Webster, Maine Yankee temporarily
assumed the general contractor role. The decom-missioning of the Plant
site continued throughout 2000, with major emphasis directed to
maintaining the schedule of critical-path projects such as construction
of the ISFSI and preparation of the Plant's reactor vessel for eventual
shipment to an off-site disposal facility. During this period, Maine
Yankee performed comprehensive assessment of its long-term alternatives
for safely and efficiently completing the decommissioning, including
evaluating detailed competitive-bid proposals from prospective
successor general contractors. On January 26, 2001, Maine Yankee
announced its decision to continue to manage the decommissioning
project itself without an external general contractor.
On June 30, 2000, Federal Insurance Company (Federal), which provided
performance and payment bonds in the amount of approximately $37.6
million each in connection with the decommissioning operations
contract, filed a Complaint for Declaratory Judgement against Maine
Yankee in the United States Bankruptcy Court for the District of
Delaware, which was subsequently transferred to the United States
District Court in Maine. The Complaint, which seeks a declaration that
Federal has no obligation to pay Maine Yankee under the bonds, alleges
that Maine Yankee improperly terminated the decommissioning operations
contract with Stone & Webster and failed to give proper notice of the
termination to Federal under the contract, and that Federal therefore
had no further obligations under the bonds.
On August 24, 2000, Maine Yankee filed a $78.2 million claim in the
Stone & Webster Bankruptcy Court proceeding in Delaware seeking to
recover its additional costs caused by Stone & Webster's contract
default. Maine Yankee expects the court hearings in both proceedings to
take place later in 2001. Maine Yankee believes that its termination
of the Stone & Webster contract was proper and that it is entitled to
recover such additional costs in the bankruptcy proceeding or under the
bonds, but cannot predict the outcome of the litigation.
In connection with the state of Maine's electric industry restructuring
law, the Company was allowed the recovery of Maine Yankee
decommissioning costs as a component of its stranded costs. In the
Company's rate order from the MPUC that became effective March 1, 2000,
the Company was allowed to defer the amount of any future FERC ordered
changes in Maine Yankee's decommissioning collections. Consequently,
management does not believe that Maine Yankee's current decom-
missioning contractor difficulties will have a material adverse impact
on the Company's results of operations, financial condition or cash
flows.
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, 2000 is
approximately $43 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
state's 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 2000 rate order for Maine Yankee non-decommissioning
plant closure costs. Accumulated decommissioning funds at December 31,
2000 had an adjusted market value of $156.2 million of which the
Company's share was approximately $10.9 million.
MEPCO - The Company owns 14.2% of the common stock of MEPCO. MEPCO owns
and operates electric transmission facilities from Wiscasset, Maine, to
the Maine-New Brunswick border. Information relating to the operations
and financial position of Maine Yankee and MEPCO appears later in Note
6. In connection with the Company's generation asset sale in May 1999
(see Note 10), the Company sold certain of its rights to MEPCO
transmission capacity.
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, an $8 million liability
(included in Other Long-term Liabilities) and corresponding regulatory
asset (included in Other Regulatory Assets) have been recorded as of
December 31, 2000 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.
Summary Financial Information for Maine Yankee and MEPCO is as follows
(dollars in thousands):
- ----------------------------------------------------------------------
Maine Yankee MEPCO
- ----------------------------------------------------------------------
2000 1999 1998 2000 1999 1998
--------- ---------- ---------- --------- -------- ------
Operations:
As reported by investee-
Operating revenue $ 43,813 $ 69,439 $ 110,608 $ 4,029 $ 2,936 $ 3,514
-------- ---------- ---------- -------- ------- ------
Amortization/depreciation and
decommissioning
collections $ 47,611 $ 55,286 $ 57,617 $ 319 $ 326 $ 364
Interest and preferred
dividends 14,829 14,079 15,958 55 72 77
Other (income)
expenses, net (23,267) (4,789) 32,117 2,274 (771) 2,125
--------- --------- --------- --------- ------ ----
Operating expenses $ 39,173 $ 64,576 $ 105,692 $ 2,648 $ (373) $2,566
-------- --------- --------- -------- ------- -----
Earnings applicable
to common stock $ 4,640 $ 4,863 $ 4,916 $ 1,381 $ 3,309 $ 948
======== ========= ========= ======== ======= =====
Amounts reported by
the Company-
Purchased power
costs $ 5,013 $ 4,368 $ 7,185 $ - $ - $ -
Equity in net
income (320) (83) (215) ( 224) (199) (123)
-------- --------- ---------- -------- ------- ------
Net purchased
power expense $ 4,693 $ 4,285 $ 6,970 $ (224) $ (199) $(123)
========= ========= ========= ======= ====== =====
Financial Position:
As reported by investee-
Plant in service $ 685 $ 685 $ 687 $25,593 $23,493 $23,633
Accumulated
depreciation - - - (23,075) (23,015)(22,899)
Other assets and
deferred charges 892,693 1,049,287 1,182,611 3,355 7,589 4,781
--------- --------- --------- ------- ------- ------
Total assets $ 893,378 $1,049,972 $1,183,298 $ 5,873 $ 8,067 $ 5,515
Less-
Preferred stock 15,000 15,000 16,800 - - -
Long-term debt 40,800 54,000 68,433 - - 220
Other liabilities
and deferred
credits 766,984 905,994 1,018,575 863 4,339 2,079
--------- --------- -------- --------- ------- ------
Net assets $ 70,594 $ 74,978 $ 79,490 $ 5,010 $ 3,728 $ 3,216
========= ========= ========== ======== ======= =======
Company's reported
equity-
Equity in net
assets $ 4,942 $ 5,248 $ 5,564 $ 711 $ 529 $ 457
Adjust Company's
estimated to
actual 8 19 (125) (38) 1 (18)
--------- --------- ----------- --------- ------- -------
Equity in net assets
as reported $ 4,950 $ 5,267 $ 5,439 $ 673 530 $ 439
========= ========= ========== ======= ======= =======
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,
with respect to this unit, was electric plant in service of $16,887,608
and accumulated depreciation of $(9,851,639).
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 later in Note 6.
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 natural gas
distribution system in the greater Bangor, Maine area. Sempra Energy
(Sempra), a joint venture of Pacific Enterprises and Enova Corporation,
owned 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 became increasingly cognizant of the need to focus on its core
electric transmission and distribution business. Consequently the
Company determined that it no longer intended to participate in the
Bangor Gas joint venture, and on July 13, 2000, the Company and
Penobscot Gas completed a stock purchase agreement to sell the
Company's interest in Penobscot Gas to Sempra. A one-time gain on the
sale of Penobscot Gas of approximately $1.2 million was recognized
in the third quarter of 2000 and is included as a component of Other
Income in the Consolidated Statements of Income for the year ending
December 31, 2000. The completion of this sale has no impact on the
proposed merger agreement with Emera which is discussed in Note 11.
At December 31, 1999 and 1998, Penobscot Gas had approximately a
$328,000 and $77,000 equity investment in Bangor Gas, respectively.
Penobscot Gas recorded equity losses in Bangor Gas of approximately
$274,000, $249,000 and $98,000 for the years ended December 31, 2000,
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 2000 1999 1998
--------- --------- --------- --------- -------
Operations:
As reported by investee-
Operating Revenue $ 4,426 $ 7,309 $ 4,235 $ 4,406 $4,535
--------- --------- --------- --------- ------
Depreciation $ 511 $ 868 $ 1,076 $ 1,075 $1,075
Interest expense 1,688 3,082 2,495 2,616 2,737
Other expenses, net 497 890 664 715 723
----------- ---------- ---------- ---------- -----
Operating expenses $ 2,696 $ 4,840 $ 4,235 $ 4,406 $4,535
----------- ---------- ---------- ---------- ------
Net Income $ 1,730 $ 2,469 $ - $ - $ -
========= ========= ========== ========= ======
Company's reported
equity in net
income $ 865 $ 1,235 $ - $ - $ -
========== ========= ========= ========== ======
Financial Position:
As reported by investee-
Plant in service $ - $ 44,047 $ 32,028 $ 31,993 $ 31,993
Accumulated
depreciation - (9,031) (10,632) (9,598) (8,523)
Other assets - 3,308 2,686 3,003 3,008
---------- ---------- ---------- ---------- -------
Total assets $ - $ 38,324 $ 24,082 $ 25,398 $ 26,478
Less-
Long-term debt - 26,300 22,288 23,471 24,654
Other liabilities - 2,517 1,794 1,927 1,824
----------- ---------- ---------- ---------- --------
Net assets $ - $ 9,507 $ - $ - $ -
=========== ========= ========= ========= ========
Company's reported
equity in net
assets $ - $ 4,754 $ - $ - $ -
=========== ========= ========= ========= ========
*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 2000, 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 were 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, and therefore it has been recorded as a
regulatory asset as of December 31, 2000.
In May 1993 the Company received an accounting order from the MPUC
related to this purchased power contract buyout. The order stipulated
that the Company could seek recovery of the costs associated with the
buyout in a future base rate case, and could also record carrying costs
on the deferred balance. Consequently, a regulatory asset of $40.3
million was recorded as of December 31, 1993. Effective with the
implementation of new base rates on March 1, 1994, the Company began
recovering over a nine-year period the deferred balance, net of the
additional $6 million anticipated from Beaver Wood. In connection with
the temporary rate increase effective July 1, 1997, the MPUC required
the Company to accelerate the amortization of this regulatory asset,
and effective December 12, 1997, the MPUC authorized the Company to
revert to the original amortization schedule. Effective with the 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 is being 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 expense under
this contract was approximately $14.9 million in 2000 and is projected
to be $15-16 million annually, net of revenues from the resale of power
to another utility through 2002, and is projected to be approximately
$20-$30 million annually from 2003 through the end of the contract.
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 2000, 1999 and 1998 the Company
realized $3.5 million, $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 2000 and 1999, 212,786 and 349,999 common
stock warrants were exercised (at a market prices below the book
value per common share at the time of the exercise), respectively,
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 $2.5 million in 2000 and
$3.3 million in 1999. 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 $248,000 and
$410,000 for the 2000 and 1999 warrants, respectively, 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 $2.1 million and $2.9 million as of December 31, 2000 and
1999, respectively. The additional regulatory assets in 2000 was reduced
by approximately $375,000 to reflect the value of the warrants
exercised at a price in excess of the previously discussed cap.
This amount was charged to fuel for generation and purchased power
expense in 2000.
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, 2000, the Company has deferred, as a regulatory
asset, approximately $14 million in connection with the PERC
restructuring. Effective with the implementation of new rates on March
1, 2000, the Company began 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
was deferred as part of the deferred asset sale gain as of December 31,
1999 (see Note 10). The remaining $.5 million of the gain related to
the portion of the gain on sale of PHC which was 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 earlier in Note 6.
OTHER POWER SUPPLY COMMITMENTS - The Company had a contract, which
started on March 1, 2000, for the delivery of up to 100 MW of power
from another utility, ending February 28, 2001. The energy delivered in
connection with the contract was used to serve a portion of the
standard offer service customer load. See Note 10 for a discussion of
the standard offer service. The Company's purchased power expense under
this contract was approximately $26 million in 2000.
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 customer
choice for power supply commenced in Maine, and will continue for a
period of two years. This transaction was 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. The Company recorded $4.5 million in revenues from the
resale of power to Morgan Stanley in 2000.
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 (Dollars in thousands except for per share
amounts):
Quarter Ended
--------------------------------------------
Mar. 31 June 30 Sept. 30 Dec. 31
--------------------------------------------
2000
- ------
Electric Operating Revenue $ 50,121 $ 48,563 $ 58,641 $ 55,012
Operating Income 8,307 4,652 6,535 6,930
Net Income 3,937 1,339 3,940 1,885
Basic Earnings Per Share
of Common Stock $ .53 $ .17 $ .53 $ .25
========== ========= ========= ===========
1999
- ------
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 2,408 2,267 2,949 3,841
Basic Earnings Per Share
of Common Stock $ .28 $ .27 $ .36 $ .48
========== ========= ========= ===========
Note 9. Fair Value of Financial Instruments
- -------------------------------------------
The following represents the estimated fair value at December 31, 2000
of each class of financial instrument for which it is practical to
estimate the value:
Cash and cash equivalents-including investments in commercial paper,
U.S. bank certificates of deposits and bankers' acceptances, and
variable rate master demand notes: the carrying amount of $12,462,780
approximates fair value.
Funds held by trustees and miscellaneous special deposits-Money market
funds and U.S. Treasury Bills: the carrying amount of $1,914,221
approximates fair value.
The fair values of other financial instruments at December 31, 2000
based upon similar issuances of comparable companies are as follows:
(In Thousands)
Carrying Amount Fair Value
--------------- ----------
Funds held by trustee-guaranteed investment contract $21,188 $22,069
First Mortgage Bonds 85,000 95,619
FAME Revenue Notes 86,600 87,787
Medium Term Notes-LIBO rate plus 1.125% 11,700 11,700
Note 10. Industry Restructuring and Rate Regulation
- ---------------------------------------------------
INDUSTRY RESTRUCTURING - In connection with the state of Maine's
electric industry restructuring law, effective March 1, 2000, consumers
of electricity had the right to purchase generation services directly
from competitive electricity suppliers. In February 2000, and in
connection with the implementation of the restructuring law, the
Company received a final rate order from the MPUC setting its
transmission and distribution 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.
The restructuring law also provided for a standard-offer service being
available for all customers who did not choose to purchase energy from
a competitive supplier starting March 1, 2000. As a result of the bids
from competitive energy suppliers to provide energy under the standard-
offer service being higher than anticipated, and as ordered by the
MPUC, the Company assumed the responsibility of being the standard-
offer service provider starting March 1, 2000 for a one-year period.
The MPUC established the schedule of rates the Company could charge for
this service starting March 1, 2000.
The Company entered into arrangements with third parties to purchase
the energy to serve the standard- offer customers. The Company is
allowed by the MPUC to defer the difference between revenues realized
from the standard-offer sales and the costs incurred to provide this
service, including carrying costs on the deferred balance. The deferred
amount will be recovered from/returned to customers in the future.
Since March 1, 2000, when new rates went into effect, the costs of
providing the standard offer service have exceeded the revenues
realized from customers, and consequently, the Company has recorded a
regulatory asset of $3.1 million, including carrying costs, as of
December 31, 2000 (which is included in Other regulatory assets on the
Consolidated Balance Sheets). The excess of costs is due principally
to unusually high purchased power costs for one day in May 2000, which
is discussed below, and higher than anticipated spot energy market
prices in the summer of 2000. As a result of the growth in the balance
of this regulatory asset, the MPUC approved standard offer service rate
increases for customers in each of August and October 2000. These rate
increases were necessitated to avoid a in the balance of this
regulatory asset, the MPUC approved standard offer service rate
increases for customers in August and October 2000. These rate increases
were necessitated to avoid a deficiency in standard offer service revenues
that the Company projected would otherwise result based on actual costs
already incurred and projected costs through February 2001.
In October 2000, the MPUC issued a Request for Proposal seeking firms
willing to supply standard-offer service for the Company's service
territory. In part because of rapidly changing conditions in the
electricity markets, the MPUC did not receive any acceptable proposals.
In December 2000 the MPUC directed the Company to explore power supply
arrangement to assist the MPUC in fulfilling its obligation to provide
standard-offer service. In February 2001, based on orders from the
MPUC, the Company retained responsibility as the standard-offer service
provider starting March 1, 2001. The MPUC initially set the standard-
offer power supply price for small (residential and non-residential)
and medium non-residential electric customers located in the Company's
service territory for the period from March 1, 2001 through February
28, 2002 at a rate which is approximately 20% above the then current
standard-offer price. The MPUC also set the standard-offer electric
supply price for the Company's large customers for this same period at
a rate approximately 29% above the then current standard-offer price.
The MPUC also approved additional power contracts which the Company was
able to procure at the request of the MPUC locking in prices for a
portion of the projected standard-offer load over the next three years.
The Company will continue to be allowed by the MPUC to defer the
difference between revenues realized from the standard-offer sales and
the costs incurred to provide this service, including carrying costs on
the deferred balance.
As a result of the previously discussed reconciliation mechanism,
standard-offer related revenues and expenses do not have any impact on
the Company's earnings, although they do result in increases in both
categories in the Company's Consolidated Statements of Income.
Consequently, the Consolidated Statement of Income for 2000 has been
modified to reflect the separate presentation of standard-offer service
revenues and purchased power expenses.
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 $24.6 million, and $24.1 million of this amount was
recorded as a deferred liability at February 29, 2000, on the
Consolidated Balance Sheets. Included in the determination of the
deferred gain on sale was 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. As discussed in Note 6,
the other $.5 million of the gain on the sale of Penobscot Hydro that
was allocable to shareholders, pursuant to orders of the MPUC, was
recorded as other income in 1999. As specified in the February 2000
rate order from the MPUC, which is discussed above, the deferred gain
is being utilized over a 70 month period to reduce electric rates
effective March 1, 2000. The annual amortization amounts are to be
recorded in an uneven manner in order to levelize the Company's revenue
requirement over this period. As a result of an increase in the
Company's FERC regulated transmission rates on June 1, 2000, and the
desire to not increase rates to its retail customers close to the
implementation of electric industry restructuring, which occurred on
March 1, 2000, the Company agreed to reduce its MPUC jurisdictional
distribution rates in an amount equal to the increase in its
transmission rates. The reduction in the distribution rates was
accomplished by accelerating the amortization of the deferred asset
sale gain by an annualized total of $2.5 million. The Company recorded
$491,000 of amortization for April and May of 2000 and increased the
monthly amortization to $703,000 starting in June 2000.
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 $5.2 million,
which was recorded as a deferred liability at February 29, 2000.
Included in the determination of this deferred gain was 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 February 29, 2000). Consistent with the
deferred gain on sale of generating assets discussed above, this $5.2
million gain also began to 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, 2000, the
environmental remediation activities have been completed through the
utilization the these funds.
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 was 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 also deferred, as a component of Other
Regulatory Assets on the Consolidated Balance Sheets as of February 29,
2000, approximately $932,000 of restructuring costs. As a result of the
February 2000 rate order received from the MPUC, the Company began recovering
on March 1, 2000, the deferred restructuring costs discussed above over a
three-year period.
DEFERRED SPECIAL RATE CONTRACT REVENUES - Also in connection with the
February 2000 rate order from the MPUC, and starting March 1, 2000, the
Company was granted a deferral mechanism for the difference in actual
revenues realized from customers under special rate contracts as
compared to the estimated revenues from these customers utilized in
setting the Company's new electric rates starting March 1, 2000. Under
this deferral mechanism, the Company recorded a regulatory asset and
additional revenues of approximately $1.4 million for the period from
March 1, 2000 through December 31, 2000. The regulatory asset is
included as a component of Other Regulatory Assets in the Consolidated
Balance Sheet at December 31, 2000 and the additional revenues are
included as a component of Electric Operating Revenue in the
Consolidated Statements of Income for 2000.
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, 2000, the
Company has regulatory assets, net of regulatory liabilities, of
approximately $173.3 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
apply Statement of Financial Accounting Standards No. 101, "Regulated
Enterprises-Accounting for the Discontinuation of Application of FASB
No. 71" (SFAS 101). If legislative or regulatory changes and/or
competition result in electric rates which do not fully recover the
Company's costs, a write-down of regulatory assets would be required.
The Company does not anticipate any write-down of assets at this time.
Note 11. Proposed Merger Agreement With Emera
- ----------------------------------------------
On June 29, 2000, the Company entered into a definitive merger
agreement with Emera of Halifax, Nova Scotia, pursuant to which Emera
will acquire all of the outstanding shares of common stock of Bangor
Hydro for US$26.50 per share in cash. After the closing of the merger,
each of Bangor Hydro's outstanding warrants to purchase common stock
will entitle the holder to receive US$26.50 in cash, less the exercise
price. For a discussion of the common stock warrants, see Note 6 of
the notes to the consolidated financial statements. The equity market
value of the transaction is approximately $206 million. The transaction
will take the form of a merger of Bangor Hydro with a U.S. corporate
subsidiary to be formed by Emera. Upon completion of the merger, Bangor
Hydro will be a wholly-owned subsidiary of Emera. Bangor Hydro's outstanding
debt and preferred stock will not be affected by the transaction. The
transaction is subject to a number of approvals, including the approval
of Bangor Hydro's shareholders, which was accomplished on October 24,
2000, and regulatory approvals from the MPUC, and the FERC, which
occurred on January 5, 2001 and January 24, 2001, respectively, and the
U.S. Securities and Exchange Commission (SEC) under the Public Utility
Holding Company Act of 1935. Proceedings are pending at the SEC for
what is anticipated to be the last major regulatory approval. The
processes for all necessary regulatory approvals are expected to be
complete in the first half of 2001. The MPUC order requires the Company
to file an alternative rate plan with the MPUC within two months after
the completion of the merger with Emera or June 30, 2001, whichever is
earlier.
In connection with merger related activities, the Company incurred
approximately $3 million in incremental costs in 2000. These have been
recorded as a component of Other Income (Expense) in the Consolidated
Statements of Income for 2000.
Note 12. Construction of Facilities for Casco Bay Energy
- --------------------------------------------------------
The Company entered into an agreement with Casco Bay whereby the
Company 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 agreed to advance funds necessary to
pay for such construction. Pursuant to a FERC order approving an
amendment to the NEPOOL Agreement, approximately 50% of the
construction funds advanced will be refunded to Casco Bay by customers
of NEPOOL over an approximately 30-year period. The Company began
refunding such construction costs to Casco Bay starting in June 2000.
At the end of 2000, the Company had recorded $4.1 million for PTF
facilities and a corresponding Long-term Payable of $4 million. These
amounts are included on the Consolidated Balance Sheets as components
of Electric Plant in Service and Other Long-term Liabilities,
respectively.
Note 13. Storm Damage
- ---------------------
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. In connection with the Company's February
2000 rate order from the MPUC, the amortization and recovery of these
deferred costs were adjusted effective March 1, 2000 to reflect the
receipt of the federal funds. The deferred balance as of December 31,
2000, which amounted to $1.3 million, is included as a component of
Other Regulatory Assets on the Consolidated Balance Sheets.
Note 14. Derivative Financial Instruments
- -------------------------------------------
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.
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 was no longer required (see Note 10). The
Company received approximately $2.1 million in cash payments associated
with swap transactions in January and February 2000. The Company
entered into "swap" transactions for 1999 amounting to 1,600,000
barrels of residual oil, respectively. As a result of market movements
in 1999 the Company received cash payments of approximately $1.8
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. The relationship between the
Company's oil related purchased power costs and the index specified in
the swap 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.
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, 2000 is $9,428 and
represents the estimated payment that would be received to terminate
the agreement.
Note 15. 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, 2000,
the liability recorded by the Company for its estimated environmental
remediation costs amounted to $282,000. The Company's actual future
environmental remediation costs may be higher as additional factors
become known.
Note 16. 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. Based
on current guidance, management does not believe that the adoption of
SFAS 133 will have a material effect on the Company's financial
statements.
PricewaterhouseCoopers
Report of Independent Accountants
To the Stockholders and Directors of
Bangor Hydro-Electric Company:
In our opinion, the consolidated financial statements listed in the index
appearing under Item 14(a) present fairly, in all material respects, the
financial position of Bangor Hydro-Electric Company (the "Company") and its
subsidiaries at December 31, 2000 and 1999, and the results of their
operations and their cash flows for each of the three years in the period
ended December 31, 2000 in conformity with accounting principles generally
accepted in the United States of America. In addition, in our opinion, the
financial statement schedule listed in the index appearing under Item 14(b)
present fairly, in all material respects, the information set forth therein
when read in conjunction with the related consolidated financial statements.
These financial statements and financial statement schedules are the
responsibility of the Company's management; our responsibility is to express
an opinion on these financial statements and financial statement schedules
based on our audits. We conducted our audits of these statements in
accordance with auditing standards generally accepted in the United States of
America, 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 our opinion.
PricewaterhouseCoopers LLP
Boston, MA
February 2, 2001
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 Disclosures About
Market Risk" 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 III (DIRECTORS WHOSE TERMS EXPIRE IN 2001)
Carroll R. Lee (51)
Senior Vice President
& Chief Operating
Officer and Director 1991 Senior Vice President and Chief Operating
Officer of the Company; 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 (62)
Director 1989 President, Prentiss & Carlisle Companies,
a timberland management company; Director
of Bangor Savings Bank; Director of
Eastern Maine Healthcare
Jane J. Bush (55)
Director 1990 Vice President and co-owner of Coastal
Ventures, a retailing company
CLASS I (DIRECTORS WHOSE TERMS EXPIRE IN 2002)
Marion M. Kane (56)
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 (59)
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.(55)
Director 1998 Former President of Rier Motors Co., an
automobile dealership located in Machias,
Maine
CLASS II (DIRECTORS WHOSE TERMS EXPIRE IN 2003)
Robert S. Briggs (57)
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. (64)
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 (60)
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
In 2000, the Board met on fourteen occasions. 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 Audit Committee met five
times during 2000. 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 Compensation Committee met once during 2000. 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 Compensation Committee met
twice during 2000. The Board does not have a nominating or similar
committee. 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 57 President & Chief Executive
Officer since January 1991
Carroll R. Lee 51 Senior Vice President and
Chief Operating Officer since
December, 1996
Frederick S. Samp 50 Vice President - Finance &
Law since 1995; Chief Financial
Officer since September, 1995
Paul A. LeBlanc 53 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,
2000, 1999, and 1998, 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 2000 $236,102 $6,564 $3,400
Chairman of the Board, President 1999 $207,549 $66,499 $3,200
& Chief Executive Officer 1998 $200,981 $41,726 $3,200
Carroll R. Lee 2000 $180,289 $5,029 $3,400
Senior Vice President & 1999 $161,149 $37,968 $3,200
Chief Operating Officer 1998 $153,645 $24,468 $3,200
Frederick S. Samp 2000 $131,206 $3,664 $3,046
Vice President-Finance & Law 1999 $112,574 $21,457 $2,527
1998 $101,807 $14,337 $2,159
Paul A. LeBlanc 2000 $121,285 $3,383 $2,800
Vice President-Human Resources 1999 $101,031 $19,197 $2,246
& Information Services 1998 $ 94,961 $12,093 $1,984
* 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 tax qualified 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 applicable to all employees.
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 upon
retirement 75% of his or her average total compensation over a three-year
period. The following table sets forth estimated annual benefit amounts
payable upon retirement after age 55 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 under the defined plan applicable to all employees
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. Compensation covered
under the tax qualified pension plan is limited to the amount set forth in
IRC Section 415. Subject to this limitation, it is essentially the same as
the amount shown as "Salary" in the Summary Compensation Table above.
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 based upon his average salary over the
past three 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.
Directors who are not employees of the Company are paid a fee of $500
per meeting for attendance at regular or special meetings of the Board, and
$500 per meeting for attendance at committee meetings (unless the committee
meeting is held the same day as another meeting for which a full meeting fee
is paid, in which case the fee is $250). The directors are also paid an
annual retainer of $6,000. Directors who are employees of the Company
receive no fee for their services as directors.
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, 2000 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:
Name and Address Title
Percentage
of Beneficial Owners of Class No. of Shares of Shares
- -------------------- -------- ------------- ---------
GAMCO Investors, Inc., Common Stock 599,700 8.16%(1)
Gabelli Funds, LLC and
Related Entities
One Corporate Center
Rye, New York 10580
FMR Corp. Common Stock 505,200 6.86%(2)
82 Devonshire Street
Boston, Massachusetts 02109
Dimensional Fund Advisors Inc. Common Stock 387,300 5.26%(3)
1299 Ocean Avenue, 11th Floor
Santa Monica, California 90401
(1) Ten entities and two individuals were included in schedule 13D/A filed
with the SEC on February 15, 2001. In addition to the two entities listed
above, Gabelli Associates Limited, Gabelli Associates Fund, Gabelli
Performance Partnership, L.P., Gabelli Fund, LDC, Gabelli Advisors, Inc.,
Gabelli Foundation, Inc., Gabelli Group Capital Partners, Inc., Gabelli Asset
Management Inc., Marc J. Gabelli and Mario J. Gabelli were included. GAMCO
Investors, Inc. is the beneficial owner of 440,100 of Bangor Hydro common
stock, 5.98% of the class.
(2) According to the 13G/A filed with the SEC on February 13, 2001.
(3) According to the 13G filed with the SEC on February 2, 2001.
(b) Security Ownership of Management
The following table sets forth as of December 31, 2000 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 6,644
Preferred Robert S. Briggs 28
Common William C. Bullock, Jr. 7,000
Common Jane J. Bush 303
Common David M. Carlisle 2,443
Common Joseph H. Cyr 1,747
Common Marion M. Kane 260
Common Paul A. LeBlanc 455
Common Norman A. Ledwin 180
Common Carroll R. Lee 1,965
Common James E. Rier, Jr. 300
Common Frederick S. Samp 816
Common Directors & Executive
Officers as a group (11) 22,113
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
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 - Proposed Merger Agreement with Emera" for
a discussion of the Company's pending acquisition by Emera. The Company is
unaware of any other arrangements regarding changes in control, including
any pledge by any person of securities of the registrant or any of its
parents, the operation of which may at a subsequent date result in a change
in control of the Company.
ITEM 13 CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
- ------- ----------------------------------------------
COMPENSATION COMMITTEE INTERLOCKS - During 2000, 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 2000, the Company
made payments to Eastern Maine Healthcare, its subsidiaries and affiliates,
of $655,124. 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, 2000, 1999 and 1998
Consolidated Balance Sheets - December 31, 2000 and
1999
Consolidated Statements of Common Stock Investment
for the Years ended December 31, 2000, 1999 and 1998
Consolidated Statements of Capitalization - December
31, 2000 and 1999
Consolidated Statements of Cash Flows
for the Years Ended December 31, 2000, 1999 and 1998
Notes to Consolidated Financial Statements
Report of Independent Accountants
(b) Schedules
Schedule VIII - Reserve for Doubtful Accounts
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/ 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/ 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 21, 2001.
SCHEDULE VIII
RESERVE FOR DOUBTFUL ACCOUNTS
-----------------------------
Additions
-----------------------------
Balance at Charged to Charged to Balance at
Beginning Costs and Other End
Of Period Expenses Accounts Deductions of Period
------------- ------------- ------------- --------------- -------------
2000
Reserve for Doubtful Accounts $ 1,075,000 $ 1,275,016 $ - $ 1,589,016 (C) $ 761,000
------------- ------------- ------------- ------------- -------------
1999
Reserve for Doubtful Accounts $ 1,075,000 $ 1,475,395 $ - $ 1,475,395 (B) $ 1,075,000
------------- ------------- ------------- ------------- -------------
1998
Reserve for Doubtful Accounts $ 1,450,000 $ 1,345,536 $ - $ 1,720,536 (A) $ 1,075,000
------------- ------------- ------------- ------------- -------------
NOTE:
(A) Accounts written off, less recoveries. For 1998 includes reduction in reserve
for doubtful accounts of $375,000.
(B) Accounts written off, less recoveries.
(C) Accounts written off, less recoveries. For 2000 includes reduction in reserve
for doubtful accounts of $314,000.
EXHIBIT INDEX
Exhibits Filed Herewith
------------------------
Exhibit No. Description of Exhibit
NONE
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
10.82 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).
10.99 Asset Purchase Implementation Form 10-K, 2000, Exhibit 10(a)
Agreement, dated as of May 27,
1999, by and among Bangor Hydro-
Electric Company, Penobscot Hydro
Co., Inc. and Penobscot Hydro, LLC
10.100 33rd Amendment to the NEPOOL Form 10-K, 2000, Exhibit 10(b)
Agreement dated December 1, 1996
10.101 Form of Agreement with Form 10-K, 2000, Exhibit 10(c)
certain Executive Officers
providing benefits upon
a change of control
10.102 Form of Agreement with Form 10-K, 2000, Exhibit 10(d)
certain Executive Officers
providing supplemental
death and retirement benefits
10.103 Agreement and Plan of Merger by Form 8-K, June 29, 2000,
and Among Bangor Hydro-Electric Exhibit 2.1
Company and NS Power Holdings
Incorporated dated as of
June 29, 2000