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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