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, 2001 Commission File No. 1-10922
BANGOR HYDRO-ELECTRIC COMPANY
(Exact Name of Registrant as specified in its charter)
MAINE 01-0024370
(State of Incorporation) (I.R.S. Employer ID No.)
33 STATE STREET, BANGOR, MAINE 04401
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code 207-945-5621
Securities registered pursuant to Section 12(g) of the Act:
TITLE OF EACH CLASS
7% Preferred Stock, $100 Par Value
4 1/4% Preferred Stock, $100 Par Value
4% Preferred Stock Series A, $100 Par Value
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
-----
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 1, 2002 of the voting stock held by
non-affiliates of the registrant was $3.32 million.
BANGOR HYDRO-ELECTRIC COMPANY
TABLE OF CONTENTS
PART I Page
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Item 1. Business 4
Item 2. Properties 5
Item 3. Legal Proceedings 6
Item 4. Submission of Matters to a Vote of Security Holders 6
Executive Officers of the Registrant 9
PART II
Item 5. Market for Registrant's Common Equity and Related
Stockholder Matter 9
Item 6. Selected Financial Data 10
Item 7. Management's Discussion and Analysis of Results of
Operations and Financial Condition 12
Item 8. Financial Statements and Supplementary Data 25
Consolidated Statements of Income 25
Consolidated Balance Sheets 26
Consolidated Statements of Capitalization 28
Consolidated Statements of Cash Flows 29
Consolidated Statements of Common Stock Investment 30
Notes to Consolidated to Financial Statements 31
Report of Independent Accountants 58
Item 7A Quantitative and Qualitative Disclosures About
Market Risk 59
Item 9. Changes in and Disagreements with Independent
Accountants on Accounting and Financial Disclosure 59
PART III
Item 10. Directors and Executive Officers of the Registrant 59
Item 11. Executive Compensation 59
Item 12. Security Ownership of Certain Beneficial Owners and
Management 60
Item 13. Certain Relationships and Related Transactions 60
PART IV
Item 14. Exhibits, Financial Statement Schedule, and Reports
on Form 8-K 61
Signatures 62
Schedule VIII - Reserve for Doubtful Accounts 63
Exhibits Delivered with this Report 64
Exhibits Incorporated Herein by Reference 65
PART I
ITEM 1 BUSINESS
(a) General development of business
Bangor Hydro-Electric Company (the Company) is a public utility incorporated
in Maine in 1924. Effective October 10, 2001, pursuant to an Agreement and
Plan of Merger, the Company became a wholly owned subsidiary of Emera Inc.
of Halifax, Nova Scotia (Emera).
For a discussion of general developments that have occurred in the Company's
business since January 1, 2001, see See Item 7, "Management's Discussion and
Analysis of Results of Operations and Financial Condition - Recent Events
Affecting the Company".
(a) Regulatory and Rate Matters
See Item 7, "Management's Discussion and Analysis of Results of Operations
and Financial Condition - Recent Events Affecting the Company - Current Rate
Filings" and Item 8, "Notes to Consolidated Financial Statements - Note 11 -
Industry Restructuring and Rate Regulation".
(b) Financial information about segments
The Company has no material segments outside of the electric business.
(c) Narrative description of business
(i) Principal business
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 190,000 people.
The Company serves approximately 107,000 customers in portions of the
counties of Penobscot, Hancock, Washington, Waldo, Piscataquis and
Aroostook.
On March 1, 2000, the Company's obligation to generate or otherwise
supply electric energy terminated as part of the restructuring of the
electric utility industry in Maine. Although the Company has no long-
term supply responsibility, the Maine Public Utilities Commission (MPUC)
can mandate that the Company be the default standard offer provider. In
February 2001, the MPUC directed the Company to provide energy services
to customers as the standard offer provider for the period March 1, 2001
through February 28, 2002. However, the MPUC has selected third party
suppliers to provide energy services to customers as the standard offer
provider for the period March 1, 2002 through February 28, 2003.
(ii) New product or segment - Not applicable
(iii) Sources and availability of raw materials
Not applicable. The Company is primarily engaged in the delivery of
electric energy.
(iv) Franchises - Not applicable
(v) Seasonal business
Sales of electricity are highest during the winter months primarily due to
heating requirements and fewer daylight hours.
(vi) Working capital items
The Company has been granted, through the ratemaking process, an allowance
for working capital to operate its ongoing electric utility system.
(vii) Single customer - Not applicable
(viii) Backlog of orders - Not applicable
(ix) Business subject to renegotiation - Not applicable
(x) Competitive conditions
The Company is a regulated public utility with an exclusive franchise to
provide electricity delivery service within its service territory.
(xi) Research and development - Not applicable
(xii) Environmental matters
See Item 7, "Management's Discussion and Analysis of Results of Operations
and Financial Condition - Contingencies and Disclosures About Market Risk"
and Item 8, "Notes to Consolidated Financial Statements - Note 14 -
Contingencies" for a discussion of Environmental Matters.
(xiii) Number of employees
As of December 31, 2001, the Company had 423 full time employees.
(d) Financial information about geographical areas - Not applicable
ITEM 2 PROPERTIES
The Company owns approximately 550 miles of transmission lines and
approximately 4,600 miles of distribution lines to serve its customers in
portions of the counties of Penobscot, Hancock, Washington, Waldo,
Piscataquis and Aroostook, Maine. 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.
Pursuant to the issuance of various first mortgage bond issues, all of the
Company's property, real, personal or mixed, including real estate,
easements, lines, poles, wires, generating stations, buildings and
equipment, is subject to the lien of a Mortgage and Deed of Trust Securing
First Mortgage Bonds dated as of July 1, 1936 as supplemented and amended,
with Citibank, N.A. (formerly City Bank Farmers Trust Company) as Trustee.
Pursuant to the issuance of various additional financings, all of BHE's
property, real, personal or mixed, including real estate, easements,
lines, poles, wires, generating stations, and buildings is further
subject to the lien of a General and Refunding Mortgage Indenture and
Deed of Trust dated as of June 1, 1995 as supplemented and amended, with
The Chase Manhattan Bank (formerly Chemical Bank) as Trustee. This
mortgage presently serves as a "second mortgage" on the Company's
property, but is intended to become the Company's first mortgage once all
outstanding first mortgage bonds are retired.
ITEM 3 LEGAL PROCEEDINGS
See Item 7, "Management's Discussion and Analysis of Results of Operations
and Financial Condition - Recent Events Affecting the Company - Current Rate
Filings." See also Item 7, "Management's Discussion and Analysis of
Results of Operations and Financial Condition - Contingencies and
Disclosures About Market Risk" and Item 8, "Notes to Consolidated Financial
Statements - Note 14 - Contingencies" 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
At a meeting of shareholders held on December 19, 2001, the following
actions were taken. Note that Common Shares are weighted at 1/12 of a vote
per share in calculating the total vote. "Non-Votes" are the aggregation of
unreturned ballots, abstentions, and ballots on which no vote was cast for
the particular question.
1) Election of Directors:
Nominees:
Class I (for terms expiring in 2002):
Robert S. Briggs
Common For: 7,363,424
Common Against: 0
Preferred For: 36,541
Preferred Against: 440
Preferred Non-Vote: 10,359
Total For: 650,160
Total Against: 440
Total Non-Vote: 10,359
Norman A. Ledwin
Common For: 7,363,424
Common Against: 0
Preferred For: 36,591
Preferred Against: 390
Preferred Non-Vote: 10,359
Total For: 650,210
Total Against: 390
Total Non-Vote: 10,359
Elizabeth A. MacDonald
Common For: 7,363,424
Common Against: 0
Preferred For: 36,591
Preferred Against: 390
Preferred Non-Vote: 10,359
Total For: 650,210
Total Against: 390
Total Non-Vote: 10,359
Class II (for terms expiring in 2003):
Jane J. Bush
Common For: 7,363,424
Common Against: 0
Preferred For: 36,591
Preferred Against: 390
Preferred Non-Vote: 10,359
Total For: 650,210
Total Against: 390
Total Non-Vote: 10,359
David McD. Mann
Common For: 7,363,424
Common Against: 0
Preferred For: 36,591
Preferred Against: 390
Preferred Non-Vote: 10,359
Total For: 650,210
Total Against: 390
Total Non-Vote: 10,359
Richard J. Smith
Common For: 7,363,424
Common Against: 0
Preferred For: 36,591
Preferred Against: 390
Preferred Non-Vote: 10,359
Total For: 650,210
Total Against: 390
Total Non-Vote: 10,359
Class III (for terms expiring in 2004):
Christopher G. Huskilson
Common For: 7,363,424
Common Against: 0
Preferred For: 36,591
Preferred Against: 390
Preferred Non-Vote: 10,359
Total For: 650,210
Total Against: 390
Total Non-Vote: 10,359
Carroll R. Lee
Common For: 7,363,424
Common Against: 0
Preferred For: 36,591
Preferred Against: 390
Preferred Non-Vote: 10,359
Total For: 650,210
Total Against: 390
Total Non-Vote: 10,359
Ronald E. Smith
Common For: 7,363,424
Common Against: 0
Preferred For: 36,591
Preferred Against: 390
Preferred Non-Vote: 10,359
Total For: 650,210
Total Against: 390
Total Non-Vote: 10,359
2) RESOLVED that the Articles of Incorporation of the Company, as amended
to date, be further amended to reduce the minimum number of Directors of the
Company from 9 Directors to 3 Directors.
Common For: 7,363,424
Common Against: 0
Preferred For: 35,250
Preferred Against: 1,614
Preferred Non-Vote: 10,516
Total For: 648,829
Total Against: 1,614
Total Non-Vote: 10,516
3) RESOLVED that the By-Laws of the Company, as amended to date, be further
amended to eliminate the requirement that Directors be stockholders of the
Company, thereby conforming the Company's By-Laws with the minimum
requirement under the Maine Business Corporations Act.
Common For: 7,363,424
Common Against: 0
Preferred For: 14,214
Preferred Against: 3,785
Preferred Non-Vote: 29,341
Total For: 627,833
Total Against: 3,785
Total Non-Vote: 29,341
4) RESOLVED that the By-Laws of the Company, as amended to date, be further
amended to remove references to and special conditions related to the 8.76%
series of non-voting preferred stock, such series having been redeemed in
1999.
Common For: 7,363,424
Common Against: 0
Preferred For: 17,182
Preferred Against: 136
Preferred Non-Vote: 30,022
Total For: 627,833
Total Against: 136
Total Non-Vote: 30,022
5) RESOLVED to ratify and approve the actions of the Officers and the Board
of Directors taken since the most recent Annual Meeting of Shareholders.
Common For: 7,363,424
Common Against: 0
Preferred For: 34,674
Preferred Against: 297
Preferred Non-Vote: 12,369
Total For: 648,293
Total Against: 297
Total Non-Vote: 12,369
-------------------------------------
Executive officers of the Registrant
Name Age Positions, offices and business
experience - January 1997 to date
Carroll R. Lee 52 President (from October 17, 2001); Senior
Vice President and Chief Operating
Officer prior thereto.
Frederick S. Samp 51 Vice President - Finance & Law; Chief
Financial Officer
Paul A. LeBlanc 54 Vice President - Human Resources &
Information Services
The officers hold office until their respective successors are elected and
qualified.
PART II
ITEM 5 MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
MATTERS
BHE Holdings Inc., a wholly-owned subsidiary of Emera, owns all of the
Company's common stock. For information regarding dividends declared see
Item 8 - Consolidated Statements of Income; Consolidated Statements of Cash
Flows; and Consolidated Statement of Common Stock Investment.
BANGOR HYDRO-ELECTRIC COMPANY
Item 6
Selected Financial Data
Six-Year Statistical Summary
(Unaudited)
2001 2000 1999 1998 1997 1996
Megawatt Hours (MWH) Generated And Purchased
Hydro Generation (Company) 65,392 90,719 205,265 275,379 262,377 321,532
Nuclear Generation (Maine Yankee) - - - - - 348,719
Oil (Company) 2,435 3,142 69,026 96,476 69,580 26,912
Biomass/Refuse 150,401 152,060 137,384 156,051 159,990 163,279
NEPOOL/Other Purchases 1,782,797 1,914,615 1,629,643 1,522,125 1,583,093 1,359,116
----------- ----------- ----------- ----------- ----------- -----------
Total Generated & Purchased 2,001,025 2,160,536 2,041,318 2,050,031 2,075,040 2,219,558
Less Line Losses and Company Use 130,067 140,470 143,198 139,028 147,298 141,426
----------- ----------- ----------- ----------- ----------- -----------
Remainder-MWH sold 1,870,958 2,020,066 1,898,120 1,911,003 1,927,742 2,078,132
=========== =========== =========== =========== =========== ===========
Classification of Sales-MWH
Residential 546,144 558,596 533,566 522,836 533,161 536,490
Commercial 583,829 570,963 545,087 524,292 515,904 508,331
Industrial 462,792 604,959 667,059 662,382 687,365 652,087
Lighting 8,742 8,859 8,911 8,901 8,780 8,945
Wholesale 2,676 2,799 2,716 2,704 3,841 4,486
----------- ----------- ----------- ----------- ----------- -----------
Total MWH Billed to Customers 1,604,183 1,746,176 1,757,339 1,721,115 1,749,051 1,710,339
Unbilled Sales-Net Increase (Decrease) 4,343 2,629 11,772 1,040 33,011 2,998
----------- ----------- ----------- ----------- ----------- -----------
Total Delivered Sales (MWH) 1,608,526 1,748,805 1,769,111 1,722,155 1,782,062 1,713,337
(Less) Interruptible Sales 22,305 178,943 230,378 248,091 265,438 237,553
----------- ----------- ----------- ----------- ----------- -----------
Total Firm Delivered Sales (MWH) 1,586,221 1,569,862 1,538,733 1,474,064 1,516,624 1,475,784
Off-System Sales 262,432 271,261 129,009 188,848 145,680 364,795
----------- ----------- ----------- ----------- ----------- -----------
Total Energy Sales (MWH) 1,870,958 2,020,066 1,898,120 1,911,003 1,927,742 2,078,132
=========== =========== =========== =========== =========== ===========
Electric Operating Revenues and Expenses (000's)
Electric Operating Revenues
Residential $ 50,264 $ 57,746 $ 73,304 $ 71,396 $ 67,532 $ 66,805
Commercial 37,795 44,329 63,093 60,191 55,391 54,010
Industrial 15,516 23,749 43,560 42,645 41,930 39,105
Lighting 1,837 1,929 2,268 2,207 2,065 2,032
Wholesale 19 63 220 235 310 314
----------- ----------- ----------- ----------- ----------- -----------
Total Revenue from Customers $ 105,431 $ 127,816 $ 182,445 $ 176,674 $ 167,228 $ 162,266
Standard Offer Service Revenue 84,589 66,134 - - - -
----------- ----------- ----------- ----------- ----------- -----------
Total Operating Revenue $ 190,020 $ 193,950 $ 182,445 $ 176,674 $ 167,228 $ 162,266
Unbilled Sales-Net Increase (Decrease) 815 (5,014) 2,042 481 2,375 408
----------- ----------- ----------- ----------- ----------- -----------
Total Revenue $ 190,835 $ 188,936 $ 184,487 $ 177,155 $ 169,603 $ 162,674
(Less) Interruptible Revenue 1,687 4,973 10,049 11,064 11,215 9,537
----------- ----------- ----------- ----------- ----------- -----------
Total Firm Revenue $ 189,148 $ 183,963 $ 174,438 $ 166,091 $ 158,388 $ 153,137
Off-System Revenue 19,125 19,352 12,947 14,630 13,615 18,384
----------- ----------- ----------- ----------- ----------- -----------
Total Electric Operating Revenues $ 209,960 $ 208,288 $ 197,434 $ 191,785 $ 183,218 $ 181,058
=========== =========== =========== =========== =========== ===========
Operating Expenses
Fuel for Generation and Purchased Power $ 34,299 $ 44,144 $ 80,748 $ 82,027 $ 92,792 $ 78,477
Standard Offer Service Purchased Power 82,839 65,553 - - - -
Operating and Maintenance Expense 38,868 37,212 36,492 34,448 32,471 32,441
Depreciation and Amortization 26,205 26,776 30,565 31,891 35,104 29,965
Taxes 11,752 12,228 14,032 11,642 3,168 10,249
----------- ----------- ----------- ----------- ----------- -----------
Total Operating Expenses $ 193,963 $ 185,913 $ 161,837 $ 160,008 $ 163,535 $ 151,132
=========== =========== =========== =========== =========== ===========
Summary of Operations (000's)
Operating Revenue $ 217,580 $ 212,338 $ 197,994 $ 195,144 $ 187,324 $ 187,374
Operating Expenses 193,963 185,913 161,837 160,008 163,535 151,132
Other Income (Loss) (including equity AFDC) (654) 613 2,806 1,292 1,292 1,466
Interest Expense (net of borrowed AFDC) 14,273 15,936 20,683 24,963 25,467 26,425
----------- ----------- ----------- ----------- ----------- -----------
Net Income (Loss) $ 8,690 $ 11,102 $ 18,280 $ 11,465 $ (386) $ 11,283
Less Preferred Dividends 266 266 945 1,244 1,376 1,537
----------- ----------- ----------- ----------- ----------- -----------
Earnings (Loss) on Common Stock $ 8,424 $ 10,836 $ 17,335 $ 10,221 $ (1,762) $ 9,746
=========== =========== =========== =========== =========== ===========
BANGOR HYDRO-ELECTRIC COMPANY
Item 6
Selected Financial Data
Six-Year Statistical Summary
(Unaudited)
2001 2000 1999 1998 1997 1996
Selected Financial Data
Total Assets (000's) $ 678,245 $ 532,220 $ 543,950 $ 605,688 $ 600,583 $ 556,629
Electric Plant (000's)
Total Electric Plant $ 341,143 $ 327,247 $ 318,435 $ 372,782 $ 358,878 $ 341,526
Depreciation Reserve 93,985 86,684 84,825 101,633 96,595 87,736
----------- ----------- ----------- ----------- ----------- -----------
Net Electric Plant $ 247,158 $ 240,563 $ 233,610 $ 271,149 $ 262,283 $ 253,790
=========== =========== =========== =========== =========== ===========
Capitalization (000's)
Short-Term Debt $ 8,000 $ - $ - $ 12,000 $ 34,000 $ 32,500
Long-Term Debt 131,968 161,960 183,300 263,028 221,643 274,221
Redeemable Preferred Stock - - - 7,604 9,137 10,670
Preferred Stock 4,734 4,734 4,734 4,734 4,734 4,734
Common Equity 205,557 137,420 132,722 118,864 106,558 108,321
----------- ----------- ----------- ----------- ----------- -----------
Total $ 350,259 $ 304,114 $ 320,756 $ 406,230 $ 376,072 $ 430,446
=========== =========== =========== =========== =========== ===========
Capital Structure Ratios (%)
Short-Term Debt 2.3 % - % - % 3.0 % 9.1 % 7.5 %
Long-Term Debt 37.7 % 53.2 % 57.1 % 64.7 % 58.9 % 63.7 %
Preferred Stock 1.3 % 1.6 % 1.5 % 3.0 % 3.7 % 3.6 %
Common Stock 58.7 % 45.2 % 41.4 % 29.3 % 28.3 % 25.2 %
----------- ----------- ----------- ----------- ----------- -----------
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 7,363,424 7,336,174
Shares Outstanding (Year End) 7,363,424 7,363,424 7,363,424 7,363,424 7,363,424 7,363,424
Number of Common Stockholders (Year End) 1 6,222 5,678 6,328 6,868 7,734
Basic Earnings (Loss) Per Common Share $ 1.14 $ 1.47 $ 2.35 $ 1.39 $ (0.24) $ 1.33
Diluted Earnings (Loss) Per Common Share $ 1.08 $ 1.30 $ 2.08 $ 1.33 $ (0.24) $ 1.33
Dividends Declared Per Common Share $ 0.60 $ 0.80 $ 0.45 $ - $ - $ 0.72
Book Value Per Common Share $ 17.26 $ 18.66 $ 18.02 $ 16.14 $ 14.47 $ 14.71
Return on Common Equity 6.30 % 7.98 % 13.81 % 9.11 % (1.64)% 9.09 %
Ratio of AFDC to Common Stock Earnings 14 % 3 % (4)% 11 % (48)% 12 %
Ratio of Earnings to Fixed Charges 1.89 % 2.11 % 2.25 % 1.59 % 0.86 % 1.50 %
Payout Ratio 53 % 54 % 26 % - % - % 54 %
Percentage of Construction Expenditures
Funded Internally 100 % 100 % 100 % 100 % 100 % 100 %
=========== =========== =========== =========== =========== ===========
Residential Customer Data
Average Number of Customers 93,398 92,656 91,726 90,888 90,433 89,769
Kilowatt-Hours per Customer 5,847 6,029 5,817 5,753 5,896 5,976
Revenue per Customer $ 538.17 $ 623.23 $ 799.16 $ 785.54 $ 746.76 $ 744.19
Revenue per Kilowatt-Hour in Cents 9.20 10.34 13.74 13.65 12.67 12.45
=========== =========== =========== =========== =========== ===========
Miscellaneous System Data
Net System Capability at Time of Peak
(MW) Firm* 182.23 98.98 273.72 381.54 344.44 373.04
System Peak Demand (MW) 290.37 304.71 293.08 281.63 277.06 274.32
Reserve Margin at Time of Peak** (37.2)% (67.5)% (6.6)% 35.5 % 24.3 % 36.0 %
System Load Factor 68.4 % 70.8 % 74.5 % 75.4 % 79.5 % 77.0 %
=========== =========== =========== =========== =========== ===========
* The net system capability was reduced subsequent to the generation asset sale, which accord in May 1999..
** While the reserve margin at time of peak in 2001, 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 COMPANY
MERGER WITH EMERA - In early October 2001, final regulatory approvals
for the merger between the Company and Emera, Inc. (Emera) were
received. On October 10, 2001, Emera completed the acquisition of all
of the outstanding common stock of the Company for US$26.806 per share
in cash. The purchase increases Emera's customer base by 25% and
broadens the Company's presence in the expanding northeast energy
market. Emera also owns Nova Scotia Power, a fully integrated electric
utility that supplies substantially all of the generation, transmission
and distribution of electricity in Nova Scotia; and has an interest in
the Maritimes & Northeast Pipeline, which transports Sable natural gas
through Maine to Boston. The acquisition transaction was accounted for
using purchase accounting. The cost in excess of the fair value of the
net assets acquired, amounting to approximately $82.5 million at
December 31, 2001, is recorded as goodwill on the consolidated balance
sheets.
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.
CURRENT RATE FILINGS - On October 12, 2001, the Company filed a
proposal with the MPUC for an alternative rate plan (ARP) that would
govern its rates for distribution service over a four year period.
Such a filing was required by the Maine Public Utilities Commission
(MPUC) as a condition of its approval of the Company's acquisition by
Emera. In addition to distribution service rates, the Company's ARP
proposal included proposed incentives to improve the efficiency and the
service quality of power delivery services to Bangor Hydro's customers.
The Company's proposal included an initial increase in distribution
rates of approximately $3.4 million, with additional annual adjustments
during the term of the ARP at a rate below that of inflation. However,
as a result of a scheduled reduction in standard offer service, the
combined impact of rate changes for most customers would be a reduction
of approximately 10% (or about $8 per month for a typical residential
customer) during 2002. There is no legal deadline for the MPUC to
complete such a proceeding.
On October 18, 2001, the Company filed a notice of its intent to file a
request for a general increase in distribution rates of approximately
$6.4 million. Under Maine law, utilities are required to provide a
minimum of sixty days notice of their intent to file such a request.
This filing was made as an alternative to the Company's ARP filing,
although it does not preclude simultaneous or subsequent implementation
of an ARP. Once filed, the MPUC must process such a request within
nine months.
In November 2001, the MPUC Hearing Examiner administering the ARP
proceeding suspended that proceeding pending the Company's filing of a
request for a general increase in distribution rates.
On January 11, 2002, the MPUC requested comments on a Draft Order that
would initiate a management investigation of the Company, as permitted
by Maine law, as part of its investigation of the Company's anticipated
request for a general increase in distribution rates. On January 17,
2002, in response to this Draft Order, the Company offered to defer
filing its request for a general increase in distribution rates and
asked the MPUC to defer initiating the management investigation to
permit the Company and interested parties a three month period to
pursue a settlement of the ARP proceeding with the expectation that
such a settlement would also terminate the proposed request for a
general increase in rates and the management investigation. At a
deliberative session held on January 22, 2002, the MPUC deferred
issuing an order initiating a management investigation for 90 days to
allow the parties to pursue a settlement of these related rate matters.
On February 14, 2002, the Company presented to the MPUC a proposed
resolution of the ongoing ARP proceeding that calls for a multi-year
freeze in the distribution portion of the Company's electric rates. In
order to comply with such a rate freeze without an adverse impact on
the Company's earnings, the Company believes that it will be necessary
to implement significant reductions in its operating costs as compared
to current levels. The Company believes that such operating cost
reductions can be implemented without adversely affecting service
quality. At this time, however, management cannot predict the outcome
of the ARP proceeding with the MPUC, and the Company has not identified
the timing or the nature of the cost reductions to be implemented.
RESULTS OF OPERATIONS
EARNINGS - Basic earnings per common share were $1.14, $1.47, and
$2.35, for the years ended 2001, 2000 and 1999, respectively. The
earned return on average common equity was 6.3% in 2001, 8% in 2000 and
13.8% in 1999.
The reduction in earnings in 2001 as compared to 2000 was due to
several factors. In 2001, the Company incurred approximately $3.9
million ($.33 reduction in earnings per common share) of costs
associated with the merger with Emera, as compared to $3 million in
2000 ($.24 reduction in earnings per common share). Also, in 2001, as
a result of a settlement of certain issues with the parties
participating in the Company's stranded cost rate filing with the MPUC,
the Company charged to expense approximately $1.7 million ($.13
reduction in earnings per common share). Finally negatively impacting
earnings in 2001 was the establishment of a $615,000 reserve ($.05
reduction in earnings per common share) associated with adjustments to
revenue related to filings with the New England Power Pool (NEPOOL).
The relatively high level of earnings in 1999 as compared to 2000 was
in part attributable to a number of one-time benefits in 1999 amounting
to approximately $.52 per common 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 (HQ). 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 $.14
per common share after taxes.
Several other major changes account for the difference between 2000 and
1999 earnings. The largest change is attributable to new rates
implemented by order of the MPUC effective March 1, 2000 that reflect a
lower authorized return on equity of 11% in Maine's restructured
electric industry. Also affecting earnings in 2000 were costs billed
to the Company associated with transmission constraints in New England
($.15 per common share after taxes), as well as the recognition of
costs related to the 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
a $1.2 million ($.10 per common share after taxes) gain on the sale of
the Company's wholly-owned subsidiary, Penobscot Natural Gas (Penobscot
Gas).
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.
With the implementation of retail competition effective March 1, 2000,
comparisons of electric operating revenues for 2001 as compared to 2000
are difficult. Total electric operating revenues, including standard-
offer service, increased by approximately $5.2 million, or 2.5%, in
2001 in comparison to 2000. Principally as a result of increases in
standard-offer service rates as ordered by the MPUC in 2000 and 2001,
electric operating revenues attributable to energy sales were
approximately $13.6 million higher in the 2001. From the March 1,
2000 through March 1, 2001, the cumulative increase in standard-offer
service rates was approximately 60%. This impact of the increased
standard-offer rates was offset to some extent by an 8% reduction in
total energy sales in 2001, due principally to the shutdown of the
Company's largest retail customer, HoltraChem Manufacturing Company
(HoltraChem) in September 2000, the weak economy in the Company's
service territory and by the impacts of warmer than average weather in
2001. Effective July 1, 2001, and providing for an increase in
revenues, the Company entered into a special rate contract with a large
industrial customer to provide fully bundled electric service (both T&D
and energy) to this customer. Formerly, the Company was only providing
T&D service to this customer. The Company has entered into a power
purchase contract to procure the power necessary to serve this customer
under this contract. Principally as a result of the new contract, the
Company recognized approximately $2.8 million in greater electric
operating revenues associated with this customer in 2001 as compared to
2000.
Other revenues, which decreased by approximately $8.3 million in the
2001 period, were most affected by a $11.8 million reduction in
revenues associated with the standard-offer service deferral mechanism.
In 2001, the Company's energy sales related to standard-offer revenues
were greater than the associated costs of providing the standard-offer
service, and consequently the Company's recorded reductions in other
revenues of approximately $8.8 million. In the 2000 period, starting
March 1, the Company recorded additional other revenues of
approximately $3 million as a result of standard-offer costs exceeding
energy sales related standard-offer revenues. The decreased other
revenues in 2001 were offset to some extent by Holtrachem revenue
sharing, which was a $1.1 million reduction in revenues in 2000, while,
as a result of the Holtrachem plant shutdown, there was no revenue
sharing in 2001.
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 7 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 rate
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.
EXPENSES - Total fuel for generation and purchased power expense,
including the standard offer, increased approximately $7.4 million in
2001 as compared to 2000. Standard offer purchased power expense for
the comparable periods of March through December of each year was $3.5
million higher in 2001. The increase is due to higher power prices,
offset by reductions in standard offer sales. Also, in connection with
the previously discussed new special rate contract with a large
industrial customer, in 2001 the Company incurred $2.3 million of
purchased power expense associated with serving this customer. Further
increasing purchased power expense in 2001 was the establishment of the
previously discussed reserve in connection with potential regulatory
loss exposure. Also increasing purchased power expense was the
recording of a $615,000 reserve associated with adjustments to revenue
related to filings with the NEPOOL. Finally, in the first two months
of 2001, purchased power costs were also higher, since the Company
purchased significantly more power on the spot power market as compared
to 2000 as a result of the expiration of the power contracts that had
been in place in the 2000 period. Further, the market prices for power
were higher due to higher fuel prices and possibly lack of sufficient
competition in the generation market.
Offsetting these increases to some extent in 2001 were lower
transmission related costs, including those associated with NEPOOL. In
2001, the Company also realized reduced transmission costs as a result
of the construction of additional qualifying transmission facilities
whose costs are recoverable from the other NEPOOL transmission owners.
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 fewer power
contracts in place than 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 for 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
comparable 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.
Other operation and maintenance (O&M) expense increased by
approximately $1.7 million in 2001 relative to 2000. The single largest
item impacting the increased expense was related to pension expense,
which was approximately $1.4 million greater in 2001 as compared to
2000. This was due principally to changes in actuarial assumptions
used in calculating pension expense and the end of the amortization of
the transition pension benefit in 2001. Also in 2001, bad debt expense
increased by approximately $610,000 due to the write-off of amounts
associated with the Chapter 11 bankruptcy filing of a large industrial
customer, a greater level of write-offs of standard offer receivables
and in 2000 bad debt expense was reduced by a $200,000 decrease in the
reserve for bad debts. These increases were offset to some extent by a
reduction in legal and regulatory related costs in 2001, as there was a
greater level of regulatory activities in 2000 in relation to 2001.
Other 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 11 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.
Depreciation and amortization expense increased by approximately
$866,000 in 2001 relative to 2000 and by approximately $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 in both 2001
and 2000. Also increasing depreciation expense in 2001 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.
The Company's expenses over the period 1999-2001 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 have 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 $3.9 million in 2001, $3.7 million in
2000 and $2.8 million in 1999.
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 2001, 2000 and 1999.
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 $1.6 million in 2001, $1.5 million in 2000 and $1 million in
1999.
In connection with the electric utility industry restructuring in
Maine, the Company was required to sell its generation related assets.
As a result, in May 1999 the Company completed the sale of its
generation assets and certain transmission rights to PP&L Global, Inc.
(PP&L). The Company realized a gain on this sale of approximately
$29.8 million, of which $29.3 million was required by the MPUC to be
deferred for the future benefit of ratepayers. Effective with the
implementation of new rates on March 1, 2000, 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 through May 2001 by an annualized total of
$2.5 million. Effective April 15, 2001, and through February 28, 2002,
in an effort to mitigate the effects of increased energy prices for the
Company's large customers, the MPUC ordered the Company to reduce its
distribution and stranded cost electric rates to certain large
customers by $.008/kWh. To fund this rate reduction and corresponding
decrease in revenues, the MPUC ordered the Company to accelerate the
amortization of the deferred asset sale gain in an amount necessary to
offset the estimated decrease in revenues caused by the rate reduction.
The asset sale gain amortization is expected to be increased by
approximately $2.5 million over the 10 1/2 month period the reduced rates
are in effect. Also, the Company's FERC jurisdictional transmission
rates changed on June 1, 2001. Consistent with 2000, the Company has
proposed to reduce its distribution rates via an adjustment to the
asset sale gain amortization to offset the change in the transmission
rates effective June 1, 2001. The annualized accelerated amortization
associated with the transmission rate change amounts to approximately
$1.6 million and ends in May 2002.
The increase in property and other taxes in 2001 relative to 2000 was
due primarily to higher property taxes, resulting from electric plant
additions and increased property tax rates.
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 total federal and state income taxes for both 2001 as
compared to 2000 and for 2000 in relation to 1999 was principally a
function of lower earnings in 2001 and 2000 as compared to the prior
years. 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 $445,000 in
2001 relative to 2000 due mainly to approximately $526,000 in carrying
costs being recorded on the deferred asset sale gain in 2000. The
Company also recorded increased carrying costs on exercised PERC common
stock warrants in 2001 relative to 2000. Offsetting these increases to
some extent was less AFDC associated with lower levels of construction
in 2001.
AFDC 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.
Other income, net of income taxes decreased by approximately $1.7
million in 2001 principally as a result of the previously discussed
$1.2 million gain on the sale of Penobscot Gas in 2000. Also
incremental costs associated with the Company's merger with Emera were
$3.9 million in 2001 as compared to $3 million in 2000. Finally,
investment income decreased by approximately $539,000 in the 2001
period due principally to reductions in the Company's available cash
balances from the 1999 generation asset sale (see the section on
Liquidity and Capital Resources).
Other income decreased by approximately $2.7 million in 2000 relative
to 1999 principally as a result of a $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 effect of
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 Co., Inc. (Penobscot Hydro), in July 1999
(See Note 7 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 previously discussed gain on sale of Penobscot Gas
in 2000.
Long-term debt interest expense decreased $1.4 million in 2001 in
relation to 2000 due primarily to repayments on the Company's long-term
debt in each year. In June 2001 and June 2000, the Company made $15.1
million and $14 million in principal payments, respectively, on the
Finance Authority of Maine (FAME) Revenue Notes. Also, monthly
principal payments on the $24.8 million medium term notes amounting to
approximately $6.2 million and $5.5 million, respectively, in 2001 and
2000. These were offset to some extent by interest expense in 2001
associated with a $13.7 million note established in October 2001 with
the Municipal Review Committee in connection with the exercise of
common stock warrants. See note 5 to the consolidated financial
statements for a discussion of this new debt.
Long-term debt interest expense decreased $3.8 million in 2000 as
compared to 1999 as a result of principal repayments in 2000 and 1999
on various long-term debt issues. See the section on liquidity, capital
requirements and capital resources for a more complete discussion of
the long-term debt repayments in 2000 and 1999.
Other interest expense increased by approximately $116,000 in 2001 due
principally to borrowings and fees under the Company's revolving credit
facility. Weighted average borrowings outstanding were approximately
$3 million in 2001, while in 2000 there were no borrowings under the
revolving credit facility. This was offset to some extent by a
reduction in the amortization of debt issuance costs in 2001 as a
result of the end of the amortization period of certain deferred debt
issuance costs in June 2001 and June 2000.
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.
LIQUIDITY, CAPITAL REQUIREMENTS, AND CAPITAL RESOURCES
The Consolidated Statements of Cash Flows reflect events for the years
ended December 2001, 2000 and 1999 as they affect the Company's
liquidity. Net cash provided by operations was approximately $25.3
million in 2001, $37.6 million in 2000 and $47.4 million in 1999.
The approximately $12.3 million reduction in operating cash flows in
2001 in relation to 2000 was the result of several factors. The
largest single item impacting this change was cash payments to the PERC
common stock warrant holders in connection with the exercise of
warrants in each period (See Note 7 to the Consolidated Financial
Statements). In 2001 approximately $14.2 million in payments were made
to the holders of the warrants, while in 2000 these payments amounted
to only $2.1 million. Cash flows from operations were further impacted
in 2001 by lower earnings as compared to the year 2000. Operating cash
flows are also impacted in both 2001 and 2000 by the standard-offer
service. In 2001, the Company's standard-offer service revenues
exceeded associated costs by approximately $8.8 million, while in 2000,
the costs exceeded revenues by approximately $3 million. Also cash
flows were negatively impacted by the previously discussed $.008/kWh
rate reductions provided to certain large customers starting in April
2001. While earnings impacts of the rate discounts are negated by
additional asset sale gain amortization to offset the rate discounts,
cash flows are negatively impacted by providing the $2.5 million in
rate discounts over the 10 1/2 month period the reduced rates are in
effect.
Changes in accounts receivable and accounts payable in the statement of
cash flows are also greatly impacted by the standard-offer related
revenues and purchased power obligations. Enhancing cash flows to some
extent in 2001 was the receipt in October 2001 of $2.6 million
associated with the settlement of a dispute regarding the sale of a
jointly owned property in which the Company had an interest. See Note
11 to the Consolidated Financial Statements for a discussion of this
transaction.
Negatively impacting cash flows in the 2000 as compared to 1999 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.
Over the last three years, capital expenditures have been $16.4 million
in 2001, $16.7 million in 2000 and $20.3 million in 1999. In 2001,
approximately $9.5 million of the capital expenditures were related to
the Company's electric distribution system, $1.6 million was associated
with the electric transmission system, and the remaining $5.3 million
was expended in connection with customer information system changes
necessitated by the electric industry restructuring, other general
property and equipment, software, and internal combustion facilities.
In 2000, approximately $8.2 million of the capital expenditures were
related to the 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. 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 $1.25
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 Penobscot Hydro.
Also impacting cash flows in 1999 were Graham Station property sale
proceeds. This sale is discussed in note 11 to the consolidated
financial statements. 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.
The increase in dividends paid on common stock in 2001 as compared to
2000 was due to an increase in the common dividend from $.15 to $.20
per share in March 2000. The increase in common dividends paid in
2000 relative to 1999 was a result of the reinstatement of the
Company's common dividend in the second quarter of 1999, as well as the
increase in the common dividend in March 2000.
The reduction in preferred dividends paid in 2000 as compared to 1999
resulted from the final redemption of the remaining outstanding 8.76%
mandatory redeemable preferred stock 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.
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. 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.
The Company had maintained full borrowing capacity under its revolving
credit facility from the second quarter of 1999 through June 2001, but
it became necessary to renew borrowings under the revolving line in
June 2001 to fund the required FAME debt payment of $15 million. The
Company's utilization of the line of credit was also impacted by the
approximately $3.8 million in incremental merger costs in 2001 and the
cash payments to common stock warrant holders in 2001 amounting to
approximately $14.2 million. The Company's borrowings under this
arrangement amounted to $8 million at December 31, 2001. On June 29,
2001, the Company extended the revolving credit agreement until October
1, 2001, and the agreement was further extended until March 31, 2002.
Also, the Company entered into a promissory note that allows the
Company to borrow up to an additional $10 million. This unsecured
facility is used by the Company to manage working capital needs, and
the interest rate setting mechanism and other major terms of the note
are similar to terms in the revolving credit agreement.
Capital and operating needs in 2001, 2000 and 1999 were met through
internally generated funds, the Company's revolving credit line and
generation asset sale proceeds. Under the current projections of cash
needs, the new credit facilities discussed above should provide
adequate borrowing capacity until a longer term financing structure is
implemented.
The Company has approximately $121.7 million of first mortgage bonds
and other long-term debt maturities in the period 2002-2006.
OTHER MATTERS
MAINE YANKEE - TERMINATION OF DECOMMISSIONING OPERATIONS CONTRACT - In
May 2000 Maine Yankee terminated its decommissioning operations
contract with Stone & Webster Engineering Corp. (Stone & Webster)
pursuant to the terms of the contract. Stone & Webster disputed Maine
Yankee's grounds for the termination. In June 2000 Stone & Webster
filed a voluntary petition under Chapter 11 of the United States
Bankruptcy Code with the United States Bankruptcy Court for the
District of Delaware.
Upon the contract termination Maine Yankee temporarily assumed the
general contractor role and entered into interim agreements with Stone
& Webster and obtained assignments of several subcontracts in order to
allow decommissioning work to continue and to avoid the adverse
consequences of an abrupt or inefficient demobilization from the Plant
site. Decommissioning of the Plant site continued, with major emphasis
directed to maintaining the schedule on 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. After
assessing its long-term alternatives for safely and efficiently
completing the decommissioning, including evaluating proposals from
prospective successor general contractors, on January 26, 2001 Maine
Yankee announced that it would continue to manage the project itself.
In June 2000 Federal Insurance Company (Federal), which had provided
performance and payment bonds in the amount of approximately $38.5
million each in connection with the decommissioning operations
contract, filed a declaratory- judgment complaint against Maine Yankee
in the Bankruptcy Court in Delaware, which was subsequently transferred
to the United States District Court in Maine. The complaint alleged
that Maine Yankee had improperly terminated the decommissioning
operations contract with Stone & Webster and had failed to give proper
notice of the termination to Federal under the contract, and that
Federal had no further obligations under the bonds.
After extensive discovery and resolution of certain preliminary issues
by the court, in December 2001 Maine Yankee and Federal entered into a
settlement agreement pursuant to which Federal paid Maine Yankee $44
million on January 18, 2002. That amount represents full payment under
the performance bond, plus an additional amount under the payment bond
reflecting certain payments made by Maine Yankee to subcontractors and
suppliers who had not been fully paid by Stone & Webster. Maine Yankee
deposited the payment in its decommissioning trust fund to offset past
and future expenses resulting from the failures of Stone & Webster.
The deposit was reflected on Maine Yankee's 2001 financial statements.
Maine Yankee is continuing to pursue its claim for damages that was
originally filed against Stone & Webster and its parent corporations in
August 2000 in the Bankruptcy Court in Delaware. After recognizing the
payment from Federal, Maine Yankee has asserted a right to recover an
additional $21 million in that court from the bankrupt estate. The
hearing on the claim was held in late 2001, and Maine Yankee expects a
decision from the court later in 2002. Recovery of such an additional
amount in the Bankruptcy Court is contingent on a number of factors
beyond Maine Yankee's control, including the extent to which the
bankrupt estate has assets available to pay any amount determined to be
recoverable. Maine Yankee therefore cannot predict what amount, if
any, it will recover on this claim.
On February 27, 2002, Stone & Webster filed a claim for approximately
$6.9 million against Maine Yankee in the Bankruptcy Court in Delaware for
alleged breaches of contract and to subordinate Maine Yankee's claims.
Maine Yankee cannot predict the outcome of the new claim.
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 decommissioning
contractor difficulties will have a material adverse impact on the
Company's results of operations, financial condition or cash flows.
CRITICAL ACCOUNTING POLICIES - We prepare our financial statements in
conformity with accounting principles generally accepted in the United
States. Judgments and uncertainties about the application of these
accounting policies along with estimates and other assumptions may
affect reported results.
REGULATION - As a regulated electric utility, the Company prepares its
financial statements in accordance with Statement of Financial
Accounting Standards No. 71, "Accounting for the Effects of Certain
Types of Regulation", (SFAS No. 71) for its regulated business. In
order for a Company to report under SFAS No. 71, the Company's rates
must be designed to recover its costs of providing service and must be
able to collect those rates from customers. If rate recovery becomes
unlikely or uncertain, whether due to competition or regulatory action,
this accounting standard would no longer apply to the Company's
regulated operations. In the event the Company determines that it no
longer meets the criteria for applying SFAS No. 71, the accounting
impact would be an extraordinary non-cash charge to operations of an
amount that could be material. Management periodically reviews these
criteria to ensure the continuing application of SFAS No. 71 is
appropriate. Based on a current evaluation of the various factors and
conditions that are expected to impact future cost recovery, Management
believes future recovery of its regulatory assets are probable.
OTHER - Electric Operating Revenue consists primarily of amounts
charged for electricity delivered to customers during the period. The
Company records unbilled revenue, based on estimates of electric
service rendered and not billed at the end of an accounting period, in
order to match revenue with related costs. We reserve an estimate for
potential uncollectible customer accounts based on historical
uncollectible experience and specific customer identification where
practical. Depreciation of electric plant is provided using the
straight-line method at rates designed to allocate the original cost of
properties over their estimated service lives. Income taxes are
recorded in accordance with SFAS No. 109, "Accounting for Income
Taxes."
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 merger 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.
CONTINGENCIES AND DISCLOSURES ABOUT MARKET RISK
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, 2001, the
liability recorded by the Company for its estimated environmental
remediation costs amounted to approximately $435,000. The Company's
actual future environmental remediation costs may be different as
additional factors become known.
In 2001 the Company expended approximately $544,000 in operations 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 13 to the Consolidated Financial Statements). As of
December 31, 2001, the Company had $5.5 million of medium term notes
outstanding which bear floating, LIBOR-based rates (1.87375% LIBO rate
at December 31, 2001). 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 5 to the Consolidated Financial Statements for a
discussion of these medium term notes.
Item 8
Financial Statements & Supplementary Data
BANGOR HYDRO-ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF INCOME
For the Years Ended December 31,
Predecessor
---------------------------------------------------
Period From
Period From January 1,
Acquisition 2001
Date to Through
December 31, Acquisition
2001 Date 2000 1999
-------------- -------------- -------------- --------------
Electric Operating Revenues:
Electric operating revenue (Note 1) $ 34,326,272 $ 98,664,499 $ 146,204,013 $ 197,994,796
Standard offer service (Note 11) 17,476,348 67,112,864 66,133,532 -
-- ------------ - ------------ - ------------ - -------------
$ 51,802,620 $ 165,777,363 $ 212,337,545 $ 197,994,796
-- ------------ - ------------ - ------------ - -------------
Operating Expenses:
Fuel for generation and purchased power (Notes 1 and 4) $ 8,711,924 $ 25,587,586 $ 44,144,334 $ 80,748,385
Standard offer service purchased power (Note 11) 16,945,383 65,893,732 65,552,980 -
Other operation and maintenance (Notes 1 and 6) 10,019,568 28,848,107 37,211,862 36,491,666
Depreciation and amortization (Note 1) 2,198,158 7,826,371 9,158,885 8,063,939
Amortization of Seabrook nuclear unit (Note 8) 424,763 1,274,287 1,699,050 1,699,050
Amortization of contract buyouts and restructuring (Note 7) 5,639,281 16,917,843 22,311,448 20,801,816
Amortization of deferred asset sale gain (Note 11) (2,105,076) (5,971,057) (6,393,038) -
Taxes -
Local property and other 1,181,771 3,817,948 4,795,698 5,059,140
Income (Note 3) 2,038,384 4,713,760 7,432,261 8,973,166
-- ------------ - ------------- - ------------ - ------------
$ 45,054,156 $ 148,908,577 $ 185,913,480 $ 161,837,162
-- ------------ - ------------- - ------------ - ------------
Operating Income $ 6,748,464 $ 16,868,786 $ 26,424,065 $ 36,157,634
Other Income And (Deductions):
Allowance for equity funds used during construction (Note 1) $ 139,532 $ 464,541 $ 158,698 $ (326,026)
Other, net of applicable income taxes (Notes 1, 3, 7 and 11) 157,452 (1,416,135) 454,715 3,132,097
-- ------------ - ------------- - ------------ - ------------
Income Before Interest Expense $ 7,045,448 $ 15,917,192 $ 27,037,478 $ 38,963,705
-- ------------ - ------------- - ------------ - ------------
Interest Expense:
Long-term debt (Notes 5 and 13) $ 3,393,733 $ 10,429,419 $ 15,211,905 $ 19,004,624
Other (Note 5) 286,443 722,586 893,455 1,393,547
Allowance for borrowed funds used during construction (Note 1) (135,676) (423,431) (169,929) 284,933
-- ------------ - ------------- - ------------ - ------------
$ 3,544,500 $ 10,728,574 $ 15,935,431 $ 20,683,104
-- ------------ - ------------- - ------------ - ------------
Net Income $ 3,500,948 $ 5,188,618 $ 11,102,047 $ 18,280,601
Dividends On Preferred Stock (Note 4) 66,429 199,141 265,570 945,396
-- ------------ - ------------- - ------------ - ------------
Earnings Applicable To Common Stock $ 3,434,519 $ 4,989,477 $ 10,836,477 $ 17,335,205
== ============ = ============= = ============ = ============
Weighted Average Number Of Shares Outstanding (Note 4) 7,363,424 7,363,424 7,363,424 7,363,424
-- ------------ - ------------- - ------------ - ------------
Earnings Per Common Share (Note 4):
Basic $ .47 $ .67 $ 1.47 $ 2.35
Diluted .47 .61 1.30 2.08
== ============ = ============= = ============ = ============
Dividends Declared Per Common Share $ - $ .60 $ .80 $ .45
== ============ = ============= = ============ = ============
The accompanying notes are an integral part of these consolidated financial statements.
BANGOR HYDRO-ELECTRIC COMPANY
CONSOLIDATED BALANCE SHEETS
December 31,
Predecessor
Assets 2001 2000
Investment In Utility Plant:
Electric plant in service, at original cost (Note 12) $ 328,559,986 $ 316,167,622
Less - Accumulated depreciation and amortization (Note 1) 93,984,836 86,684,205
- ------------ - ------------
$ 234,575,150 $ 229,483,417
Construction work in progress (Note 1) 7,307,837 5,457,707
- ------------ - ------------
$ 241,882,987 $ 234,941,124
Investments in corporate joint ventures: (Notes 1 and 7)
Maine Yankee Atomic Power Company $ 4,421,884 $ 4,949,696
Maine Electric Power Company, Inc. 853,562 672,581
- ------------ - ------------
$ 247,158,433 $ 240,563,401
- ------------ - ------------
Other Investments, at cost (Note 9) $ 3,497,681 $ 3,174,561
- ------------ - ------------
Funds held by trustee, at cost (Notes 5 and 9) $ 22,694,648 $ 22,696,405
- ------------ - ------------
Current Assets:
Cash and cash equivalents (Notes 1 and 9) $ 884,617 $ 12,462,780
Accounts receivable, net of reserve ($761,000 in 2001 and 2000) 19,268,889 21,731,869
Unbilled revenue receivable (Note 1) 15,379,708 15,778,696
Inventories, at average cost:
Material and supplies 2,531,853 2,585,107
Fuel oil 53,320 93,746
Prepaid expenses 671,267 829,181
- ------------ - ------------
Total current assets $ 38,789,654 $ 53,481,379
- ------------ - ------------
Regulatory Assets and Deferred Charges:
Goodwill-EMERA Acquisition (Note 2) $ 82,537,291 $ -
Investment in Seabrook nuclear project, net of accumulated amortization
of $35,270,346 in 2001 and $33,571,296 in 2000 (Notes 8 and 11) 23,571,729 25,270,779
Costs to terminate/restructure purchased power contracts, net of accumulated
amortization of $145,729,090 in 2001 and $123,171,966 in 2000 (Notes 7 and 11) 92,057,206 99,312,319
Maine Yankee decommissioning costs (Notes 7 and 11) 37,306,576 43,028,107
Above-market purchased power contract obligation (Notes 11 and 13) 73,954,000 -
Other regulatory assets (Notes 3,5,6 and 11) 52,657,562 41,025,080
Other deferred charges 4,019,969 3,667,769
- ------------ - ------------
Total regulatory assets and deferred charges $ 366,104,333 $ 212,304,054
- ------------ - ------------
Total Assets $ 678,244,749 $ 532,219,800
============== ==============
The accompanying notes are an integral part of these consolidated financial statements.
BANGOR HYDRO-ELECTRIC COMPANY
CONSOLIDATED BALANCE SHEETS
December 31,
Predecessor
Stockholders' Investment and Liabilities 2001 2000
Capitalization: (see accompanying statement)
Common stock investment (Note 4) $ 205,556,673 $ 137,419,659
Preferred stock (Note 4) 4,734,000 4,734,000
Long-term debt, net of current portion (Notes 5, 9 and 13) 131,967,827 161,960,000
- ------------ - ------------
Total capitalization $ 342,258,500 $ 304,113,659
- ------------ - ------------
Current Liabilities:
Notes payable - banks (Note 5) $ 8,000,000 $ -
- ------------ - ------------
Other current liabilities -
Current portion of long-term debt (Notes 5 and 9) $ 43,245,891 $ 21,340,000
Accounts payable 22,491,785 24,785,193
Dividends payable 66,429 1,539,114
Accrued interest 2,663,225 2,529,237
Customers' deposits 572,867 502,276
Current income taxes payable 1,916,892 305,323
- ------------ - ------------
Total other current liabilities $ 70,957,089 $ 51,001,143
- ------------ - ------------
Total current liabilities $ 78,957,089 $ 51,001,143
- ------------ - ------------
Regulatory and Other Long-term Liabilities (Note 3)
Deferred income taxes - Seabrook $ 12,223,523 $ 13,109,098
Other accumulated deferred income taxes 47,405,476 58,314,350
Maine Yankee decommissioning liability (Note 7) 37,306,576 43,028,107
Deferred gain on asset sale (Note 11) 14,574,316 22,788,408
Above-market purchased power contract obligation (Note 13) 73,954,000 -
Other regulatory liabilities (Note 11) 18,961,715 12,556,052
Unamortized investment tax credits 1,311,928 1,452,059
Accrued pension and postretirement benefit costs (Note 6) 39,655,265 12,124,106
Other long-term liabilities (Notes 7 and 12) 11,636,361 13,732,818
- ------------ - ------------
Total regulatory and other long-term liabilities $ 257,029,160 $ 177,104,998
- ------------ - ------------
Total Stockholders' Investment and Liabilities $ 678,244,749 $ 532,219,800
= ============ = ============
The accompanying notes are an integral part of these consolidated financial statements.
BANGOR HYDRO-ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF CAPITALIZATION
December 31,
Predecessor
2001 2000
Common Stock Investment (Notes 1,2 and 4)
Common stock, par value $5 per share- $ 36,817,120 $ 36,817,120
Authorized -- 10,000,000 shares
Outstanding -- 7,363,424 shares in 2001 and 2000
Amounts paid in excess of par value 165,352,312 58,642,367
Accumulated other comprehensive loss (47,278) -
Retained earnings 3,434,519 41,960,172
- -------------- -------------
Total common stock investment $ 205,556,673 $ 137,419,659
- -------------- -------------
Preferred Stock, Non-participating, cumulative, par value $100 per share,
authorized 600,000 shares (Note 4):
Not redemable or redeemable solely at the option of the issuer-
7%, Noncallable, 25,000 shares authorized and outstanding $ 2,500,000 $ 2,500,000
4.25%, Callable at $100, 4,840 shares authorized and outstanding 484,000 484,000
4%, Series A, Callable at $110, 17,500 shares authorized and outstanding 1,750,000 1,750,000
- -------------- -------------
$ 4,734,000 $ 4,734,000
- -------------- -------------
Long-Term Debt (Notes 5, 9 and 14)
First Mortgage Bonds-
10.25% Series due 2020 $ 30,000,000 $ 30,000,000
8.98% Series due 2022 20,000,000 20,000,000
7.38% Series due 2002 20,000,000 20,000,000
7.30% Series due 2003 15,000,000 15,000,000
- -------------- -------------
$ 85,000,000 $ 85,000,000
- -------------- -------------
Other Long-Term Debt-
Finance Authority of Maine - Taxable Electric Rate
Stabilization Revenue Notes, 7.03% Series 1995A, due 2005 $ 71,500,000 $ 86,600,000
Medium Term Notes, Variable interest rate-LIBO rate plus 1.125%, due 2002 5,460,000 11,700,000
Municipal Review Committee Note, 5%, due 2008 13,234,394 -
Other miscellaneous notes payable, 3.90%, due 2003 19,324 -
- -------------- -------------
$ 90,213,718 $ 98,300,000
Less: Current portion of long-term debt 43,245,891 21,340,000
- -------------- -------------
$ 46,967,827 $ 76,960,000
- -------------- -------------
Total Long-Term Debt $ 131,967,827 $ 161,960,000
- -------------- -------------
Total Capitalization $ 342,258,500 $ 304,113,659
= ============ = ============
The accompanying notes are an integral part of these consolidated financial statements.
BANGOR HYDRO-ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the years ended December 31,
Predecessor
Period From Period From
Acquisition January 1,
Date to 2001 Through
December 31, Acquisition
2001 Date 2000 1999
Cash Flows From Operating Activities:
Net income $ 3,500,948 $ 5,188,618 $ 11,102,047 $ 18,280,601
Adjustments to reconcile net income to net cash
from operating activities:
Depreciation and amortization 2,198,158 7,826,371 9,158,885 8,063,939
Amortization of Seabrook nuclear project (Note 8) 424,763 1,274,287 1,699,050 1,699,050
Amortization of contract buyouts and
restructuring (Note 7) 5,639,281 16,917,843 22,311,448 20,801,816
Amortization of deferred asset sale gain (Note 11) (2,105,076) (5,971,057) (6,393,038) -
Other amortizations 375,024 1,193,607 1,896,179 2,590,725
Allowance for equity funds used during
construction (Note 1) (139,532) (464,541) (158,698) 326,026
Deferred income tax provision and amortization of
investment tax credits (Note 3) (212,917) (5,976,077) (2,765,264) (131,897)
Gain on sale of subsidiary (Notes 7 and 11) - - (1,205,727) (523,390)
Deferred Maine Yankee replacement power cost
write-off (Note 7) - - 1,992,848 -
Flow-through of unamortized investment tax credits
and excess deferred income taxes (Note 3) - - - (1,485,131)
Changes in assets and liabilities:
Costs to restructure purchased power
contract (Note 7) (250,000) (750,000) (1,000,000) (1,099,000)
Deferred standard-offer service costs (Note 11) 4,265,218 4,580,779 (2,988,823) -
Deferred special rate contract revenues (Note 11) (910,954) (1,404,194) (1,368,948) -
Exercise of PERC warrants-cash paid in lieu
of issuing shares (Note 7) (4,951,550) (9,225,892) (2,129,387) (3,321,710)
Deferred Wyman#4 litigation settlement
proceeds (Note 11) 2,592,294 - - -
Deferred incremental Maine Yankee costs (Note 7) - - 807,616 2,886,401
Deferred incremental ice storm costs - - - 1,817,851
Deferred costs associated with generation
asset sale (Note 11) - - 107,765 (5,266,689)
Payment received related to terminated
purchased power contract (Note 7) - - - 1,750,000
Accounts receivable, net and unbilled revenue (1,291,684) 1,298,321 (5,113,248) (2,759,315)
Accounts payable (1,032,699) (1,359,942) 10,609,785 (11,081)
Accrued interest (703,043) 837,030 (23,521) (921,611)
Current and deferred income taxes (293,705) 2,253,111 (10,093) 3,755,913
Accrued postretirement benefit costs (Note 6) 589,050 1,533,939 1,322,206 1,608,414
Other current assets and liabilities, net (257,941) 580,127 202,486 (356,034)
Other, net (5,530) (501,752) (433,387) (345,523)
- -------------- --------------- --------------- --------------
Net Increase in Cash From Operating Activities: $ 7,430,105 $ 17,830,578 $ 37,620,181 $ 47,359,355
- -------------- --------------- --------------- --------------
Cash Flows From Investing Activities:
Construction expenditures $ (6,264,489) $ (10,083,839) $ (16,680,501) $ (20,323,360)
Allowance for borrowed funds used during
construction (Note 1) (135,676) (423,431) (169,929) 284,933
Asset sale proceeds (Note 11) - - - 79,587,841
Proceeds from sale of subsidiary (Notes 7 and 11) - - 1,250,000 10,000,000
Release of Graham Station property sale proceeds
held by trustee (Note 11) - - - 6,200,000
- -------------- --------------- --------------- --------------
Net (Decrease) Increase in Cash From Investing Activities $ (6,400,165) $ (10,507,270) $ (15,600,430) $ 75,749,414
- -------------- --------------- --------------- --------------
Cash Flows From Financing Activities:
Dividends on preferred stock $ (66,380) $ (199,190) $ (265,570) $ (1,127,882)
Dividends on common stock (1,472,685) (4,418,054) (5,522,567) (2,209,028)
Payments on long-term debt (Note 4) (2,054,457) (19,720,645) (19,460,000) (85,782,897)
Payments on mandatory redeemable preferred
stock (Note 4) - - - (9,243,742)
Short-term debt, net (Note 5) 2,000,000 6,000,000 - (12,000,000)
- -------------- --------------- --------------- --------------
Net Decrease in Cash From Financing Activities $ (1,593,522) $ (18,337,889) $ (25,248,137) $ (110,363,549)
- -------------- --------------- --------------- --------------
Net (Decrease) Increase in Cash and Cash Equivalents $ (563,582) $ (11,014,581) $ (3,228,386) $ 12,745,220
Cash and Cash Equivalents at Beginning of Year 1,448,199 12,462,780 15,691,166 2,945,946
- -------------- --------------- --------------- --------------
Cash and Cash Equivalents at End of Year $ 884,617 $ 1,448,199 $ 12,462,780 $ 15,691,166
============ ============= ============= ==============
The accompanying notes are an integral part of these consolidated financial statements.
BANGOR HYDRO-ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF COMMON STOCK INVESTMENT
Accumulated
Amounts Paid Other Total Common
Common in Excess of Retained Comprehensive Stock
Stock Par Value Earnings Loss Investment
-------- ------------ ----------- ------------ -------------
Balance December 31, 1998 $36,817,120 $ 59,054,203 $22,992,769 $ - $118,864,092
Net income - - 18,280,601 18,280,601
Cash dividends declared on-
Preferred stock - - (899,718) (899,718)
Common stock - - (3,313,541) (3,313,541)
Exercise of warrants-cash paid
in lieu of issuing shares (Note 4) - (410,052) - (410,052)
Transfer of mandatory redeemable 8.76%
preferred stock issuance costs to the deferred
asset sale gain (Note 11) 246,191 246,191
Other - - (45,678) (45,678)
------------ ------------ ------------ ------------ ------------
Balance December 31, 1999 $36,817,120 $ 58,890,342 $37,014,433 $ - $132,721,895
Net income - - 11,102,047 11,102,047
Cash dividends declared on-
Preferred stock - - (265,570) (265,570)
Common stock - - (5,890,738) (5,890,738)
Exercise of warrants-cash paid
in lieu of issuing shares (Note 4) - (247,975) - (247,975)
------------- ------------- ------------- ------------- --------------
Balance December 31, 2000 $36,817,120 $ 58,642,367 $41,960,172 $ - $137,419,659
Net income - - 8,689,566 8,689,566
Other comprehensive loss net of taxes:
Unrealized loss on interest rate swap (Note 13) (47,278) (47,278)
Total comprehensive income 8,642,288
Merger transactions (net) (Note 2) - 120,890,928 (42,531,595) - 78,359,333
Cash dividends declared on-
Preferred stock - - (265,570) - (265,570)
Common stock - - (4,418,054) - (4,418,054)
Exercise of warrants-cash paid
in lieu of issuing shares (Note 4) - (14,180,983) - - (14,180,983)
------------ ------------ ------------ ------------ --------------
Balance December 31, 2001 $36,817,120 $165,352,312 $ 3,434,519 $ (47,278) $205,556,673
------------ ------------ ------------ ------------ --------------
The accompanying notes are an integral part of these consolidated financial statements.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1. NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
NATURE OF OPERATIONS - Bangor Hydro-Electric Company (the Company) is a
public utility engaged in the transmission and distribution of electric
energy and other energy related services, with a service area of
approximately 5,275 square miles having a population of approximately
190,000 people. The Company serves approximately 107,000 customers in
portions of the Maine counties of Penobscot, Hancock, Washington,
Waldo, Piscataquis, and Aroostook. The Company's regulated operations
are subject to the regulatory authority of the Maine Public Utilities
Commission (MPUC) as to retail rates, accounting, service standards,
territory served, the issuance of securities and other matters. The
Company is also subject to the jurisdiction of the Federal Energy
Regulatory Commission (FERC) as to certain matters, including rates for
transmission services. The Company is a member of the New England Power
Pool (NEPOOL), and is interconnected with other New England utilities
to the south and with New Brunswick Power Corporation to the north.
BASIS OF CONSOLIDATION - The Consolidated Financial Statements of the
Company include its wholly- owned subsidiaries, Bangor Var Co., Inc.
(BVC), Bangor Energy Resale, Inc. (BERI), CareTaker, Inc. (CareTaker),
Bangor Fiber Co., Inc. (Bangor Fiber), and Bangor Line Co., Inc.
(Bangor Line), BERI was formed in 1997 as a special purpose vehicle to
permit Bangor Hydro's use of a power sales agreement as collateral for
a bank loan (see Note 5 for a discussion of this financing
arrangement). CareTaker was incorporated in 1997 and provides security
alarm services on a retail basis to residential and commercial
customers. Bangor Fiber was formed in 2000 to supply fiber optic
communications cable to communications companies and cable service
providers and other related activities. Bangor Line was formed in 2001
to provide engineering, permitting and design, geographic information
system and construction services to third parties. See Note 7 for
additional information with respect to BVC. All significant
intercompany balances and transactions have been eliminated. The
accounts of the Company are maintained in accordance with the Uniform
System of Accounts prescribed by the regulatory bodies having
jurisdiction.
EQUITY METHOD OF ACCOUNTING - The Company accounts for its investments
in the common stock of Maine Yankee Atomic Power Company (Maine
Yankee) and Maine Electric Power Company, Inc. (MEPCO) under the equity
method of accounting, and records its proportionate share of the net
earnings of these companies as a reduction of fuel for generation and
purchased power expense. See Note 7 for additional information with
respect to these investments.
ELECTRIC OPERATING REVENUE - Electric Operating Revenue, including that
associated with standard offer service (See Note 11) consists primarily
of amounts charged for electricity delivered to customers during the
period. The Company records unbilled revenue, based on estimates of
electric service rendered and not billed at the end of an accounting
period, in order to match revenue with related costs. As of March 1,
2000, the Company bills customers for the energy supplied by
competitive energy providers (See Note 11). Competitive energy
providers are paid only after the funds are collected from customers.
The Company records accounts receivable for the amounts billed to
competitive energy customers and a corresponding accounts payable for
the amounts due to the energy supplier. No revenue is recognized as the
Company is acting as an agent.
DEPRECIATION OF ELECTRIC PLANT AND MAINTENANCE POLICY- Depreciation of
electric plant is provided using the straight-line method at rates
designed to allocate the original cost of properties over their
estimated service lives. The composite depreciation rate (excluding
intangible assets), expressed as a percentage of average depreciable
plant in service, and considering the amortization of overaccu-mulated
depreciation (discussed below), was approximately 2.9% in 2001, 2.9% in
2000 and 2.1% in 1999.
A study conducted as of December 31, 1996 determined that the
Company's reserve for depreciation was overaccumulated by
approximately $3.6 million. In connection with the MPUC's rate order in
February 1998, the Company was allowed to amortize this balance over a
two-year period, starting in February 1998. The Company recorded
approximately $307,000 in amortization in 2000 and $2.4 million in 1999
which reduced depreciation expense. The 1999 and 2000 amortizations
were increased as a result of the sale of the Company's hydroelectric
plant assets in May 1999.
The Company follows the practice of charging to maintenance the cost
of repairs, replacements and renewals of minor items considered to be
less than a unit of property. Costs of additions, replacements and
renewals of items considered to be units of property are charged to the
utility plant accounts, and any items retired are removed from such
accounts. The original costs of units of property retired and removal
costs, less salvage, are charged to the depreciation reserve.
Depreciation, local property taxes and other taxes not based on income,
which were charged to operating expenses, are stated separately in the
Consolidated Statements of Income. Rents, advertising and research and
development expenses are not significant. No royalty expenses were
incurred.
Maintenance expense was $10.1 million in 2001, $10 million in 2000 and
$9.5 million in 1999.
GOODWILL -In connection with the acquisition of the Company's common
stock by Emera, Inc. (Emera) in October 2001 (see Note 2), the excess
of the cost over the fair value of the net assets of the Company has
been recorded as goodwill on the Company's consolidated balance sheet.
In accordance with the implementation of Statement of Financial
Accounting Standards No. 141, "Business Combination", goodwill is no
longer amortized. The Company assesses the recoverability of goodwill
by using discounted cash flow analysis.
ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION (AFDC) - In accordance
with regulatory requirements of the MPUC, the Company capitalizes as
AFDC financing costs related to portions of its construction work in
progress, at a rate equal to its weighted cost of capital, into utility
plant with offsetting credits to other income and interest. This cost
is not an item of current cash income, but is recovered over the
service life of plant in the form of increased revenue collected as a
result of higher depreciation expense and return. In addition, carrying
costs on certain regulatory assets and liabilities, including the
deferred asset sale gain (see Note 11), were also capitalized and
included in AFDC in the Consolidated Statements of Income. The average
AFDC (carrying costs) rates computed by the Company were 9.1% in 2001,
9.3% for 2000 and 9.5% in 1999.
CASH AND CASH EQUIVALENTS - The Company considers all highly liquid
debt instruments purchased with an original maturity of three months or
less to be cash equivalents.
USE OF ESTIMATES - The preparation of financial statements in
conformity with generally accepted accounting principles requires
management to make estimates and assumptions that affect the reported
amounts of assets and liabilities and disclosure of contingent
liabilities at the date of the Consolidated Financial Statements and the
reported amounts of revenues and expenses during the reporting period.
Actual results could differ from those estimates.
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION - Cash paid for
interest, net of amounts capitalized was approximately $14.1 million,
$15.1 million and $20.9 million in 2001, 2000 and 1999,
respectively. Cash paid for income taxes was approximately $10.4
million, $10 million and $8.9 million in 2001, 2000 and 1999,
respectively. Non-cash financing activity: In October 2001 the
Company issued a $13,667,550 note payable in connection with the
exercise of common stock warrants. See Notes 5 and 7 for a discussion
of the note payable and the common stock warrants.
RISK MANAGEMENT AND DERIVATIVE FINANCIAL INSTRUMENTS - The Company's
major financial market risk exposure is changing interest rates.
Changing interest rates will affect interest paid on variable rate debt
and the fair value of fixed rate debt. The Company manages interest
rate risk through a combin-ation of both fixed and variable rate debt
instruments and an interest rate swap (see Notes 5 and 15). The
Company does not hold or issue derivatives for trading purposes. The
Company's accounting for derivatives used to manage risk is in
accordance with Statement of Financial Accounting Standards No. 133,
"Accounting for Derivative Instruments and Hedging Activities".
RECLASSIFICATIONS-Certain prior year amounts have been reclassified to
conform with the presentation used in the 2001 Consolidated Financial
Statements.
NOTE 2. MERGER WITH EMERA, INC.
In early October 2001, final regulatory approvals for the merger
between the Company and Emera, Inc. (Emera) were received. On October
10, 2001, Emera completed the acquisition of all of the outstanding
common stock of the Company for US$26.806 per share in cash. The
purchase increases Emera's customer base by 25% and broadens the
Company's presence in the expanding northeast energy market. Emera
also owns Nova Scotia Power, a fully integrated electric utility that
supplies substantially all of the generation, transmission and
distribution of electricity in Nova Scotia; and has an interest in the
Maritimes & Northeast Pipeline, which transports Sable natural gas
through Maine to Boston. The acquisition transaction was accounted for
using purchase accounting. The cost in excess of the fair value of the
net assets acquired, amounting to approximately $82.5 million at
December 31, 2001, is recorded as goodwill on the consolidated balance
sheet. As previously discussed, the goodwill will not be amortized,
but instead will be subject to an impairment test at least annually in
accordance with the provisions of Statement No. 142. Goodwill
associated with the Emera acquisition was not adjusted for any
impairment losses in 2001.
The following table summarizes the purchase accounting adjustments to
the accounts of the Company as of December 31, 2001:
Purchase
Accounting
Adjustments
----------------
Unbilled revenue receivable $ (2,855,331)
Goodwill 82,537,291
Regulatory assets (1,660,375)
----------------
Total Assets $ 78,021,585
=============
Common stock investment $ 78,359,333
Current liabilities (1,582,637)
Deferred asset sale gain 12,222
Other regulatory liabilities 1,232,667
---------------
Total Liabilities and Stockholders Equity $ 78,021,585
=============
As a result of the merger on October 12, 2001, as required under
purchase accounting by generally accepted accounting principles,
retained earnings of the Company were reset to zero and moved to
amounts paid in excess of par value. Also in connection with merger
related activities, the Company incurred approximately $3.9 million and
$3 million in incremental costs in 2001 and 2000, respectively. These
have been recorded as a component of Other Income (Expense) in the
Consolidated Statements of Income for 2001 and 2000.
NOTE 3. INCOME TAXES
The individual components of federal and state income taxes reflected
in the Consolidated Statements of Income for 2001, 2000 and 1999 are
stated in the table below.
Year Ended December 31, 2001 2000 1999
Current:
Federal $ 9,300,188 $ 7,445,626 $7,390,387
State 2,958,075 2,920,769 2,314,251
---------------- -------------- -----------
$12,258,263 $10,366,395 $9,704,638
--------------- ------------- --------------
Deferred:
Federal $ (3,935,012) $ (1,618,863) $ (252,473)
State (2,113,851) (1,006,733) (447,641)
--------------- --------------- --------------
$(6,048,863) $ (2,625,596) $ (700,114)
--------------- --------------- --------------
Investment Tax Credits, Net $ 42,951 $ (139,668) $ (317,877)
--------------- --------------- --------------
Total Provision $ 6,252,351 $ 7,601,131 $ 8,686,647
Allocated to Other Income 499,793 (168,870) 286,519
--------------- --------------- --------------
Charged to Operating Expens $ 6,752,144 $ 7,432,261 $ 8,973,166
============= =========== ===============
Under the federal income tax laws, the Company received investment tax
credits (ITC) on qualified property additions through 1986. ITC
utilized were deferred and are being amortized over the life of the
related property. In 1999 the Company utilized the remaining available
ITC of about $3.2 million to reduce its federal income tax obligation.
In 2000, the Company utilized the remaining $3.6 million of federal
alternative minimum tax credits to reduce its regular income tax
liability while in 1999, the Company utilized $4.2 million of federal
and state alternative minimum tax credits. These net operating losses
were principally due to the Company deducting for income tax reporting
purposes the costs of the purchased power contract terminations in
1995, which were deferred for financial reporting purposes (see Note
7).
The table below reconciles the income tax provision, calculated by
multiplying income before federal income taxes (as reported on the
Consolidated Statements of Income) by the statutory federal income
tax rate to the federal income tax expense reported on the Consolidated
Statements of Income. The difference is represented by the permanent
and timing differences for which deferred taxes are not provided for
ratemaking purposes.
2001 2000 1999
-----------------------------------
(Dollars in Thousands)
Amount % Amount % Amount %
----------------------------------------
Federal income tax provision at
statutory rate $5,230 35.0% $6,546 35.0% $9,439 35.0%
Less (Plus) permanent differences
in tax expense resulting from
statutory exclusions from taxable
income:
Dividend received deduction
related to earnings
of associated companies 74 .5 164 .9 253 .9
Equity component of AFDC 170 1.1 138 .7 185 .7
Asset sale gain permanent
differences (349) (2.3) (276) (1.5) - -
Amortization of equity
component of AFDC on recoverable
Seabrook investment (160) (1.0) (160) (.8) (160) (.6)
Other 2 - 32 .1 (29) (.1)
-------------------------------------------
Federal income tax provision before
effect of 0 timing differences $5,493 36.7% $6,648 35.6% $9,190 34.1%
Less (Plus) timing differences
that are flowed through for
rate-making and accounting purposes:
Amortization of debt component
of AFDC and capitalized
overheads on recoverable
Seabrook investment (151) (1.0) (151) (.8) (151) (.6)
Book depreciation greater
than tax depreciation (85) (.6) (69) (.4) (85) (.3)
Equity earnings in excess
of (less than) dividends 102 .7 (41) (.2) (276) (1.0)
State income tax liability
deducted for federal
income tax purposes 424 2.8 550 2.8 673 2.5
Reversal of excess deferred
income taxes 230 1.5 147 .8 167 .6
Amortization of investment
tax credits 140 .9 140 .8 350 1.3
Investment tax credits and
excess deferred taxes
flowed through - - - - 1,485 5.5
Other (392) (2.6) 43 .4 27 .1
-------------------------------------------
Federal income tax provision $5,225 35.0% $6,029 32.2% $7,000 26.0%
===========================================
In accordance with Statement of Financial Accounting Standards No. 109
"Accounting for Income Taxes" (FAS 109), the Company recorded
cumulative net additional deferred income tax liabilities of
approximately $10.3 million as of December 31, 2001 and $16.4 million
as of December 31, 2000. These additional deferred income tax
liabilities have resulted from the accrual of deferred taxes on
temporary differences on which deferred taxes had not been previously
accrued ($16.0 million and $25.3 million as of December 31, 2001 and
2000, respectively), offset by the effect of the 1987 change to lower
income tax rates (reduced by the 1% increase in the federal income tax
rate in 1993) that will be refunded to customers over time ($4.9
million and $8.1 million as of December 31, 2001 and 2000,
respectively), and the establishment of deferred tax assets on
unamortized investment tax credits ($776,000 and $858,000 as of
December 31, 2001 and 2000, respectively). These latter amounts have
been recorded in Other Regulatory Liabilities at December 31, 2001 and
2000. The accrual of the additional amount of deferred tax liabilities
have been offset by regulatory assets which represent the customers'
future payment of these income taxes when the taxes are, in fact,
expensed. As a result of this accounting, the Consolidated Statements
of Income are not affected by the implementation of FAS 109. The rate-
making practices followed by the MPUC permit the Company to recover
federal and state income taxes payable currently, and to recover some,
but not all, deferred taxes that would otherwise be recorded in
accordance with FAS 109 in the absence of regulatory accounting. The
individual components of other accumulated deferred income taxes are as
follows at December 31, 2001 and 2000:
2001 2000
--------------- -----------------
Deferred Income Tax Liabilities:
Costs to terminate/restructure
purchased power contracts $26,362,744 $ 35,091,730
Excess book over tax basis of
electric plant in service 37,117,206 37,156,847
Investment in jointly-owned companies 1,476,037 1,358,081
Other regulatory assets 2,547,116 3,655,033
Other 138,374 120,104
---------------- --------------
$ 67,641,477 $ 77,381,795
------------------- ----------------
Deferred Income Tax Assets:
Deferred asset sale gain $ 5,901,889 $ 8,776,804
Accrued pension and postretirement
benefit costs 5,734,119 4,500,464
Other regulatory liabilities 5,369,662 1,441,734
Other 3,230,331 4,348,443
------------------ ---------------
$ 20,236,001 $ 19,067,445
------------------ ----------------
Total other accumulated deferred
income taxes $ 47,405,476 $ 58,314,350
============ ============
As a result of the Company's generation asset sale to PP&L Global in
1999 (see Note 11), the Company realized $1.5 million in income tax
benefits associated with the recognition of previously unamortized
deferred ITC associated with the generation assets sold and the
reversal of the excess deferred income taxes associated with these
assets. These income tax benefits have been recorded as a component of
Other Income in the Consolidated Statements of Income in 1999.
NOTE 4. COMMON AND PREFERRED STOCK AND EARNINGS PER SHARE
COMMON STOCK - In connection with the Company's merger with Emera on
October 10, 2001, Emera owns all of the Company's outstanding common
shares. The common stock has general voting rights of one vote per
twelve shares owned.
PREFERRED STOCK - Authorized but unissued shares of 552,660 (plus
additional shares equal in number to such presently outstanding shares
as may be retired) may be issued with such preferences, restrictions or
qualifications as the board of directors may determine. Any new shares
so issued will be required to be issued with per share voting rights no
greater than that of the common stock. The callable preferred stock may
be called in whole or in part upon any dividend date by appropriate
resolution of the board of directors. The currently outstanding
preferred stock has general voting rights of one vote per share. With
regard to payment of dividends or assets available in the event of
liquidation, preferred stock ranks prior to common stock.
EXERCISE OF COMMON STOCK WARRANTS - In 2001, the remaining 1,437,215 of
outstanding common stock warrants were exercised, which were issued in
connection with the PERC purchased power contract restructuring, were
exercised at market prices ranging from $25.625 to $26.806 per share.
For a complete discussion of the PERC contract restructuring and the
issuance of warrants, see Note 7. For 736,315 of the warrants, the
Company exercised its option to pay cash to the holders of the warrants
instead of actually issuing shares of common stock. These payments
amounted to approximately $14.2 million. For 700,900 of unexercised
warrants associated with the Municipal Review Committee (MRC), the
Company and the MRC entered into an agreement whereby the Company,
instead of issuing shares or paying cash, established a note payable to
the MRC in the amount of $13,667,550, at an interest rate of 5% and a
term of seven years. See Note 5 for a discussion of the MRC debt.
Since the common shares were not issued, and the Company had recorded
the estimated fair value of these warrants when issued in June 1998 as
a $1.4 million addition to paid-in capital, an adjustment has been made
in connection with the cash payments option and the MRC note payable to
reduce paid-in capital by this amount as of December 31, 2001.
Also as a result of the exercise of the warrants in 2001, the MPUC, in
connection with its order approving the Company's merger with Emera,
established a cap on the value of the warrants that could be recorded
as a regulatory asset for exercises in 2001. Since all of the warrant
exercises in 2001 were in excess of this cap, the Company was required
to write-off this excess amount to paid-in capital. The charges, which
reduced paid-in capital, amounted to approximately $12.6 million in
2001. See Note 7 for a complete discussion of the impact of the MPUC's
orders concerning the PERC warrants.
In 2000, 212,786 common stock warrants, which were issued in connection
with the PERC purchased power contract restructuring, were exercised at
market prices ranging from $14.75 to $24.8125 per share. The Company
exercised its option to pay cash to the holders of the warrants instead
of actually issuing shares of common stock. These payments amounted to
approximately $2.5 million. Since the common shares were not issued,
and the Company had recorded the estimated fair value of these warrants
when issued in June 1998 as a $248,000 addition to paid-in capital, an
adjustment has been made in connection with the cash payments option to
reduce paid-in capital by this amount as of December 31, 2000.
In 1999, 349,999 common stock warrants, which were issued in connection
with the PERC purchased power contract restructuring, were exercised at
market prices ranging from $16.0625 to $16.75 per share. The Company
exercised its option to pay cash to the holders of the warrants instead
of actually issuing shares of common stock. These payments amounted to
approximately $3.3 million. Since the common shares were not issued,
and the Company had recorded the estimated fair value of these warrants
when issued in June 1998 as a $410,000 adjustment to paid-in capital,
an adjustment was made in connection with the cash payments option to
reduce paid-in capital by this amount as of December 31, 1999.
EARNINGS PER SHARE - The following table reconciles basic and diluted
earnings per common share assuming all outstanding common stock
warrants were converted to common shares (see Note 7 for
discussion of warrants issued in connection with the PERC purchased
power contract restructuring). For 2001 the Predecessor period is
from January 1, 2001 through the acquisition date, and the Successor
period is from the acquisition date to December 31, 2001.
Successor Predecessor
2001 2001 2000 1999
------------- ------------- ---------- ----------
Earnings applicable to
common stock $3,434,519 $4,989,477 $10,836,477 $17,335,205
----------- ------------- ------------ -----------
Average common shares
outstanding 7,363,424 7,363,424 7,363,424 7,363,424
Plus: incremental shares
from assumed conversion
of outstanding warrants - 791,745 990,099 984,200
------------ --------- ----------- ---------
Average common shares
outstanding plus assumed
warrants converted 7,363,424 8,155,169 8,353,523 8,347,624
------------- ----------- ----------- ----------
Basic earnings per
common share $.47 $.67 $1.47 $2.35
------------- ------------- ----------- ----------
Diluted earnings per
common share $.47 $.61 $1.30 $2.08
======== ========= ========= ========
NOTE 5. LENDING AGREEMENTS AND MONETIZATION OF POWER SALE CONTRACT
On June 29, 1998, the Company entered into an Amended and Restated
Revolving Credit and Term Loan Agreement with a new group of lenders
that provided a two-year term loan of $45 million and a three year
revolving credit commitment of $30 million. The amended credit
agreement is secured by $82.5 million of non-interest bearing First
Mortgage Bonds. The term loan was fully repaid in May of 1999. The
terms of the amended credit agreement have been extended to March 31,
2002 and the First Mortgage Bonds have expired.
By the terms of the credit agreement, the Company may borrow, at its
option, at rates, as defined in the agreement, based on the London
Interbank Offered (LIBO) rate, or the base rate, which is the higher of
the agent bank's defined base rate or one-half of one percent (1/2%)
above the federal funds interest rate. The applicable risk premium
based on the Company's corporate credit rating is added to the core
interest rate, which results in the total combined interest rate for
borrowing under the agreement. A required commitment fee, based on the
Company's available revolving credit commitment, is also priced
according to the Company's corporate credit rating.
On June 29, 2001, the Company, as permitted under the Amended and
Restated Credit and Term Loan Agreement, entered into a Promissory Note
with FleetBoston Financial that allows the Company to borrow up to an
additional $10 million. This unsecured facility is used by the Company
to manage working capital needs, and the interest rate setting
mechanism and other major terms of the Note are similar to terms in the
Amended and Restated Credit and Term Loan Agreement. The original
facility expired on October 1, 2001, but has subsequently been extended
to March 31, 2002.
Both facilities contain certain financial covenants related to the
Company's debt ratio, fixed charge coverage, net worth, and limitation
on the payment of common dividends. The Company was in compliance with
all covenants associated with these agreements during 2001 and 2000.
The Company provided power directly to UNITIL Power Corp. (UNITIL), a
New Hampshire based electric utility, at significantly above-market
rates, with the contract term ending in the year 2003. On March 31,
1998, the Company completed a transaction with lenders and one of its
wholly owned subsidiaries, BERI (see below) that provided a loan of
approximately $23.3 million in net proceeds secured by the value of the
UNITIL contract. As a requirement of the financing, the Company
established BERI, a special purpose entity which holds the medium term
notes and acts as a conduit between Bangor Hydro and UNITIL for the
procurement of power under the terms of the original power sales
contract between the two parties.
The loan was comprised of $24.8 million in medium term notes, with a
term of 53 months. BERI must maintain a capital reserve fund of $1.5
million, funded with proceeds from the loan, which will be used to pay
the final installment of principal and interest due in 2002. The assets
in the capital reserve fund are held by a third party trustee and
invested in money market funds whose investments are limited to
commercial paper, corporate notes and bonds, certificates of deposit,
municipal bonds, U.S. Agency obligations and repurchase agreements.
Interest is payable, at the Company's option, under the agreement at
the LIBO rate plus 1.125% or the base rate, which is the higher of (a)
the lending bank's reported "base rate" and (b) one-half of one percent
(1/2%) above the federal funds effective interest rate. The Company
has historically selected the LIBO rate interest option. To provide
interest rate protection through the maturity date of the term loan, in
April 1998, BERI entered into an interest rate swap agreement with one
of the lending banks. The interest rate swap fixed the LIBO interest
rate on the medium term notes at 5.72%. As a result of the interest
rate swap agreement, BERI incurred additional interest expense in 2001
amounting to approximately $103,000, while in 2000 BERI realized
reduced interest expense of approximately $96,000. The agreement also
contains certain financial covenants, with which BERI was in compliance
during 2001 and 2000.
In connection with financing the costs of the purchased power contract
buyback accomplished in June 1995 (see Note 6), the Company entered
into a Loan Agreement with the Finance Authority of Maine (FAME), a
body corporate and politic and public instrumentality of the state of
Maine. Pursuant to authorizing legislation in Maine, FAME issued $126
million of notes through a private placement, the
repayment of which is the responsibility of the Company under the terms
of the Loan Agreement. Of that amount, approximately $105 million was
made available to the Company to finance a portion of the buyback and
approximately $21 million was set aside in a capital reserve fund. The
notes bear interest at an annual rate of 7.03%, mature on July 1, 2005
and are subject to a schedule of annual principal payments, which began
on July 1, 1998. The amount held in the capital reserve fund will be used
to pay the final installment of principal and interest due in 2005. The
assets in the capital reserve fund are held by a third party trustee and
invested in a guaranteed investment contract, earning interest at an
annual rate of 6.51%. The interest earnings are utilized to offset the
semiannual interest payments on the FAME notes.
In order to secure the FAME notes, the Company executed a General and
Refunding Mortgage Indenture and Deed of Trust establishing a lien on
the Company's property junior to the lien under the Company's First
Mortgage Bonds Indenture. The Company may not issue any additional
First Mortgage Bonds in the future. The Company issued bonds to FAME
under the new mortgage in the amount of $126 million. Under the
provisions of the first mortgage bond indenture, substantially all of
the Company's plant and property has been mortgaged to secure the
Company's first mortgage bonds.
On October 10, 2001, the Company issued a unsecured promissory note to
the MRC for the amount of $13,667,550 (MRC Promissory Note). The
Company and the MRC agreed to terms and conditions of
the MRC Promissory Note under which the Company shall make a series of
cash payments to the MRC upon the exercise of warrants on the closing
of the merger with Emera, Inc. (See Notes 4 and 7 for a discussion of
the PERC common stock warrants). The MRC Promissory Note has a term
of seven years, a fixed interest rate of 5%, and payments of interest
and principal on a quarterly basis. The MRC has the right to defer
some or all of any of the quarterly payments within the same Note Year
(August 1 to July 31), upon at least a 14 days' prior written notice to
the Company.
Current maturities of the first mortgage bonds and other long-term debt
for the five years subsequent to December 31, 2001, amounting to
$121,619,152, are $43,245,904 in 2002, $33,909,192 in 2003, $20,314,371
in 2004, $21,830,717 in 2005, and $2,318,968 in 2006.
Certain information related to total short-term borrowings under the
Credit Agreements and the lines of credit is as follows:
2001 2000 1999
------------- ----------- ---------------
Total credit available at end
of period $40,000,000 $30,000,000 $30,000,000
Unused credit at end of period $32,000,000 $30,000,000 $30,000,000
Borrowings outstanding at end
of period $ 8,000,000 - -
Effective interest rate
(exclusive of fees) on
borrowings outstanding at
end of period 4.4% -% -%
Average daily outstanding
borrowings for the period $ 3,031,507 $ - $ 2,802,740
Weighted daily average annual
interest rate
exclusive of fees) 4.4% -% 6.7%
Highest level of borrowings
outstanding at any
month-end during the period $ 8,000,000 $ - $13,000,000
=========== ============= ===========
NOTE 6. POSTRETIREMENT BENEFITS
The Company has a noncontributory pension plan covering substantially
all of its employees. Benefits under the plan are generally based on
the employee's years of service and compensation during the years
preceding retirement. The Company's general policy is to contribute to
the funds the amounts deductible for federal income tax purposes. The
Company also has an unfunded noncontributory supplemental non-qualified
pension plan that provides additional retirement benefits to certain
management employees.
There were no employer contributions to the noncontributory pension
plan in 2001, 2000 or 1999. The plan's assets are composed of fixed
income securities, equity securities and cash equivalents.
The following tables detail the funded status of the plan, the amounts
recognized in the Company's Consolidated Financial Statements, the
components of pension (income) expense for 2001, 2000 and
1999 and the major assumptions used to determine these amounts
(includes both the funded and unfunded plans).
Total pension expense (income) included the following components:
2001 2000 1999
------------- ----------- -----------
Service cost-benefits earned
during the period $1,387,841 $1,186,910 $1,439,047
Interest cost on projected
benefit obligation 3,622,633 3,479,260 3,295,172
Expected return on plan assets (4,260,894) (4,460,416) (4,317,379)
Amortization of unrecognized
asset and gains (losses) (6,958) (664,911) 252,043
------------- ------------- ----------
Total pension expense (income) $ 742,622 $ (459,157) $ 668,883
=========== =========== ===========
2001 2000 1999
---------- --------- ---------
Significant assumptions used were-
Discount rate* 7.75% / 7.25% 8.0% 6.75%
Rate of increase in future
compensation levels 4.0% 4.0% 4.0%
Expected long-term rate of
return on plan assets 9.0% 9.0% 9.0%
* In 2001, a 7.75% discount rate was used prior to the acquisition, and
7.25% was subsequent to the acquisition.
The following table sets forth the plans' funded status at December 31,
2001 and 2000:
2001 2000
-------------- ---------------
Change in Projected Benefit Obligation
Balance as of December 31, 2000 and 1999 $ 47,951,796 $45,165,460
Service cost 1,387,841 1,186,910
Interest cost 3,622,633 3,479,260
Benefits paid (2,863,257) (2,900,824)
(Gains) and losses 3,283,569 1,020,990
-------------- -------------
Balance as of December 31, 2001 and 2000 $ 53,382,582 $47,951,796
-------------- -------------
Change in Plan Assets
Balance as of December 31, 2000 and 1999 $ 48,425,866 $51,834,730
Employer contributions 54,142 40,000
Benefits paid (2,863,257) (2,900,824)
Actual return, less expenses (4,185,796) (548,040)
-------------- --------------
Balance as of December 31, 2001 and 2000 $ 41,430,955 $48,425,866
-------------- --------------
Funded status $(11,951,627) $ 474,070
Unrecognized net transition asset - (390,175)
Unrecognized prior service cost - 2,630,838
Unrecognized gain (1,180,767) (4,756,609)
---------------- -------------
Accrued pension at December 31, 2001 and 2000 $(13,132,394) $ (2,041,876)
============== ============
As a result of purchase accounting, all unrecognized actuarial gains
and losses, prior service cost and the net transition asset were
eliminated as of October 10, 2001, the merger date with Emera. As a
result of regulatory accounting, a regulatory asset of $10.4 million,
equal to these unrecognized amounts, was established at the merger
date. The Company is amortizing this balance over the same period at
which the corresponding gains and losses were being amortized when they
were a component of pension expense. Amortization expense amounted to
$211,670 in 2001 for the period subsequent to the merger.
The discount rate and rate of increase in future compensation levels
used to determine pension obligations, effective January 1, 2002, are
7.25% and 4%, respectively, and were used to calculate the plans'
funded status at December 31, 2001.
The accumulated benefit obligation for the unfunded supplemental
pension plan with accumulated benefit obligations in excess of plan
assets was $2,201,171 and $1,999,298 as of December 31, 2001 and 2000,
respectively.
In addition to pension benefits, the Company provides certain health
care and life insurance benefits to its retired employees.
Substantially all of the Company's employees may become eligible for
retiree benefits if they reach normal retirement age while working for
the Company. The actuarially determined net periodic postretirement
benefit cost for 2001, 2000 and 1999 and the major assumptions used to
determine these amounts are shown in the following tables:
2001 2000 1999
------------- ----------- ----------
Service cost of benefits earned $ 632,590 $ 573,740 $ 583,385
Interest cost on accumulated
postretirement benefit obligation 1,848,813 1,716,563 1,518,092
Actual return on plan assets (37,836) (22,002) (9,710)
Amortization of unrecognized
transition obligation 375,900 501,200 501,200
Other deferrals, net 271,727 280,255 405,834
------------- ------------ ------------
Net periodic postretirement
benefit cost $3,091,194 $3,049,756 $2,998,801
========== ========== ==========
The following table sets forth the benefit plan's funded status at
December 31, 2001 and 2000.
2001 2000
-------------- ------------
Change in Accumulated Postretirement
Benefit Obligation
Balance as of December 31, 2000 and 1999 $ 23,874,192 $ 20,720,833
Service cost 632,590 573,740
Interest cost 1,848,813 1,716,563
Claims paid (979,648) (1,091,334)
Gains and losses 2,112,497 1,954,390
--------------- -------------
Balance as of December 31, 2001 and 2000 $ 27,488,444 $ 23,874,192
--------------- -------------
Change in Plan Assets
Balance as of December 31, 2000 and 1999 $ 879,734 $ 358,971
Employer contributions 1,250,743 1,727,550
Retiree contributions 44,038 43,428
Claims paid (979,648) (1,091,334)
Actual return, less expenses (180,829) (158,881)
-------------- -------------
Balance as of December 31, 2001 and 2000 $ 1,014,038 $ 879,734
------------- -------------
Funded status $(26,474,406) $(22,994,458)
Unrecognized net transition obligation - 6,013,600
Unrecognized (gain) loss (48,465) 6,898,628
-------------- -------------
Accrued postretirement benefit cost at
December 31, 2001 and 2000 $(26,522,871) $(10,082,230)
============= ============
As a result of purchase accounting, all unrecognized actuarial gains
and losses, prior service cost and the unrecognized net transition
obligation were eliminated as of October 10, 2001, the merger date with
Emera. As a result of regulatory accounting, a regulatory asset of
$14.6 million, equal to these unrecognized amounts, was established at
the merger date. The Company is amortizing this balance over the same
period at which the corresponding gains and losses were being amortized
when they were a component of the net periodic postretirement benefit
cost. Amortization expense amounted to $282,537 in 2001 for the period
subsequent to the merger.
The MPUC in 1993 issued a final accounting rule in connection with
Statement of Financial Accounting Standards No. 106, "Employers'
Accounting for Postretirement Benefits Other Than Pensions" (SFAS
106), which adopted this pronouncement for ratemaking purposes and
authorized the Company to defer the excess of the net periodic
postretirement benefit cost recognized under SFAS 106 over the pay-as-
you-go amount in 1993 through February 28, 1994, and to include such
excess as a regulatory asset pending inclusion in the new base rates,
effective March 1, 1994. This regulatory asset, which amounted to
$705,283 at February 28, 1994, is being recovered, beginning March 1,
1994, over a ten-year period.
In 1994 the Company established an irrevocable external Voluntary
Employee Benefit Association Trust Fund (VEBA) to fund the payment of
postretirement medical and life insurance benefits. Company
contributions to the VEBA amounted to approximately $1.3 million in
2001 and $1.7 million in 2000. The VEBA's assets are composed of United
States Treasury money market funds. The Company's general policy is to
contribute to the VEBA amounts necessary to fund claims and
administrative costs.
2001 2000 1999
------------ -------- -------
Significant assumptions used were-
Discount rate * 7.75% /7.25% 8.0% 6.75%
Health care cost trend rate,
employees less than age 65-
Near-term 7.5% 7.0% 7.5%
Long-term 5.0% 5.0% 4.5%
Health care cost trend rate,
employees greater than age 65-
Near-term 7.5% 7.0% 7.5%
Long-term 5.0% 5.0% 4.5%
Rate of return on plan assets 5.0% 5.0% 5.0%
* In 2001, a 7.75% discount rate was used prior to the acquisition, and
7.25% was subsequent to the acquisition.
The discount rate used to determine postretirement benefit obligations,
effective January 1, 2002, and the Plan's funded status at December 31,
2001, was 7.25%.
Assumed health care cost trend rates have a significant effect on the
amounts reported for the health care plan. A one-percentage-point
change in assumed health care cost trend rates would have the following
effect:
1% Increase 1% Decreas
------------- ------------
Effect on total of service and
interest cost components $ 451,011 $ (355,321)
Effect on postretirement benefit obligation 4,580,571 (3,658,701)
In 1999 the Company incurred $469,000 and $175,587 in special
termination benefits associated with enhanced pension and
postretirement medical benefits, respectively, provided to employees
who were displaced due to the asset sale to PP&L Global (see Note 11).
The state of Maine electric utility restructuring legislation allowed
utilities to recover the costs of providing such benefits to the
workers displaced due to the sale of the Company's generation assets,
and consequently, the special termination benefits expense of $644,587
was deferred and is recorded as a regulatory asset at December 31,
1999. Recovery of this regulatory asset began starting March 1, 2000 over a
three-year period as specified in the Company's 2000 rate order from
the MPUC.
The estimates of the Company's accrued pension and postretirement
benefit costs involve the utilization of significant assumptions.
Changes in any one of these assumptions could impact the liabilities in
the near term.
The Company also provides a defined contribution 401(k) savings plan
for substantially all of its employees. The Company's matching of
employee voluntary contributions amounted to approximately $363,000 in
2001, $370,000 in 2000 and $331,000 in 1999.
NOTE 7. JOINTLY OWNED FACILITIES AND POWER SUPPLY COMMITMENTS
MAINE YANKEE - The Company owns 7% of the common stock of Maine Yankee,
which owns and, prior to its permanent closure in 1997, operated an 880
megawatt (MW) nuclear generating plant (the Plant) in Wiscasset, Maine.
Maine Yankee, which had commenced commercial operation on January 1,
1973, is the only nuclear facility in which the Company has an
ownership interest. The Company's equity ownership in the plant had
entitled the Company to about 7% of the output pursuant to a cost-based
power contract. Pursuant to a contract with Maine Yankee, the Company
is obligated to pay its pro rata share of Maine Yankee's operating
expenses, including decommissioning costs. In addition, under a Capital
Funds Agreement entered into by the Company and the other sponsor
utilities, the Company may be required to make its pro rata share of
future capital contributions to Maine Yankee if needed to finance
capital expenditures.
Plant Shutdown and Rate Case Settlement - On August 6, 1997, the board
of directors of Maine Yankee voted to permanently cease power
operations at the Plant and to begin decommissioning the Plant. The
Plant had experienced a number of operational and regulatory problems
and did not operate after December 6, 1996. The decision to close the
Plant permanently was based on an economic analysis of the costs, risks
and uncertainties associated with operating the Plant compared to those
associated with closing and decommissioning it. The Plant's operating
license from the Nuclear Regulatory Commission was scheduled to expire
in 2008.
The entire output of the Plant had been sold at wholesale by Maine
Yankee to ten New England electric utilities, which collectively own
all of the common equity of Maine Yankee; a portion of that output
(approximately 6.2%) was in turn resold by certain of the owner
utilities to 29 municipal and cooperative utilities in New England (the
Secondary Purchasers). Maine Yankee recovered, and since the shutdown
decision has continued to recover, its costs of providing service
through a formula rate filed with the FERC and contained in Power
Contracts with its utility purchasers, which, as amended, are also
filed with the FERC.
In November 1997, Maine Yankee submitted for filing certain amendments
to the Power Contracts (the Amendatory Agreements) and revised rates to
reflect the decision to shut down the Plant and to request approval of
an increase in the decommissioning component of its formula rates.
Maine Yankee's submittal also requested certain other rate changes,
including recovery of unamortized investment (including fuel) and
certain changes to its billing formula, consistent with the
nonoperating status of the Plant.
During 1998 and early 1999, the parties to the FERC proceeding,
including, among others, the MPUC staff, the Maine Office of the Public
Advocate and the Secondary Purchasers, engaged in extensive discovery
and negotiations, which resulted in the filing of a settlement
agreement with the FERC in January 1999. A separately negotiated
settlement filed with the FERC in February 1999 resolved the issues
raised by the Secondary Purchasers by limiting the amounts of their
payments for decom-missioning the Plant and by settling other points of
contention affecting individual Secondary Purchasers. Both settlements
were found to be in the public interest and were approved by the FERC
on June 1, 1999. The settlements constitute a full settlement of all
issues raised in the FERC proceeding, including decommissioning cost
issues and the issues pertaining to the prudence of the management,
operation, and decision to permanently cease operation of the Plant.
The primary settlement provides for Maine Yankee to recover amounts
intended to cover the costs of decommissioning and those associated
with the construction and maintenance of an of an off-site independent
spent fuel storage installation (ISFSI). The settlement also provides
for recovery of the unamortized investment (including fuel) in the
Plant, together with a return on equity of 6.50% on limited equity
balances. The Settling Parties also agreed not to contest the
effectiveness of the Amendatory Agreements submitted to FERC as part of
the original filing, subject to certain limitations including the right
to challenge any accelerated recovery of unamortized investment under
the terms of the Amendatory Agreements after a required informational
filing with the FERC by Maine Yankee. In addition, Maine Yankee agreed
to file with the FERC a rate proceeding that will have an effective
date of no later than January 1, 2004, when major decommissioning
activities are expected to be nearing completion. As a separate part
of the settlement, the three Maine Sponsors of Maine Yankee, the MPUC
Staff, and the Office of the Public Advocate entered into a further
agreement (Maine Agreement) resolving retail rate issues and other
issues specific to the Maine parties, including those that had been
raised concerning the prudence of the operation and shutdown of the
Plant. The Company believes that the settlement, including the Maine
Agreement, constituted a reasonable resolution of the issues raised in
the Maine Yankee FERC proceeding, and eliminated significant
uncertainties concerning the Company's future financial performance.
Under the Maine Agreement, the Company would continue to recover its
Maine Yankee costs , although the allowed return on equity associated
with the Company's equity balance in Maine Yankee was set at 6.50%.
The final major provision of the Maine Agreement required the Maine
owners, for the period from March 1, 2000, through December 1, 2004, to
hold their Maine retail ratepayers harmless from the amounts by which
the replacement power costs for Maine Yankee exceeded the replacement
power costs assumed in the report to the Maine Yankee board of
directors that served as a basis for the Plant shutdown decision. As
part of a further settlement, the Company's liability was fixed at
approximately $2.2 million to be reflected as a reduction in stranded
costs effective March 1, 2002. The Company charged to fuel and
purchased power expense and recorded as a regulatory liability $2
million in December 2000 representing the net present value of this future
obligation.
Maine Yankee's most recent estimate of the total costs of
decommissioning and plant closure, for the period from 2001 to 2008,
excluding funds already collected, is $596 million (undiscounted). The
Company's share of the estimated cost at December 31, 2001 is
approximately $37.3 million and is recorded as a regulatory asset and
decommissioning liability. The regulatory asset was recorded for the
full amount of the decommissioning and plant closure costs due to the
state's industry restructuring legislation (see Note 11) allowing the
Company future recovery of nuclear decommissioning expenses related to
Maine Yankee, as well as the Company being allowed a recovery mechanism
in its February 2000 rate order for Maine Yankee non-decommissioning
plant closure costs. Accumulated decommissioning funds at December 31,
2001 had an adjusted market value of $157.1 million of which the
Company's share was approximately $11 million.
MEPCO - The Company owns 14.2% of the common stock of MEPCO. MEPCO owns
and operates electric transmission facilities from Wiscasset, Maine, to
the Maine-New Brunswick border. Information relating to the operations
and financial position of Maine Yankee and MEPCO appears later in Note
6. In connection with the Company's generation asset sale in May 1999
(see Note 11), the Company sold certain of its rights to MEPCO
transmission capacity.
NEPOOL/Hydro-Quebec Project - The Company is a 1.6% participant in the
NEPOOL/Hydro-Quebec Phase 1 project (Phase 1), a 690 MW DC intertie
between the New England utilities and Hydro-Quebec constructed by a
subsidiary of another New England utility at a cost of about $140 million.
The participants receive their respective share of savings from energy
transactions with Hydro-Quebec, and are obliged to pay for their respective
shares of the costs of ownership and operation whether or not any savings
are realized.
The Company is also a 1.5% participant in the NEPOOL/Hydro-Quebec Phase
2 project (Phase 2), which involves an increase to the capacity of the
Phase 1 intertie to 2,000 MW. As in the Phase 1 project, the Company
receives a share of the anticipated energy cost savings derived from
purchases from Hydro-Quebec and capacity benefits provided by the
intertie and is required to pay its share of the costs of ownership and
operation whether or not any savings are obtained. In connection with
the generation asset sale in May 1999, the Company sold its rights as a
participant in the regional utilities agreement with Hydro-Quebec (see
Note 11). The Company, though, is still required to pay its share of
the costs of ownership and operation of the Hydro-Quebec intertie. Also
in connection with the asset sale, PP&L Global (PP&L) has agreed to pay
the Company $400,000 per year to partially offset the Company's on-
going Hydro-Quebec support payments. Since the Company still has an
obligation for the costs of the Hydro-Quebec intertie, but it has sold
the rights to the benefits as a participant, an $6 million liability
(included in Other Long-term Liabilities) and corresponding regulatory
asset (included in Other Regulatory Assets) have been recorded as of
December 31, 2001 on the Consolidated Balance Sheet representing the
present value of the Company's estimated future payments (net of the
$400,000 to be received from PP&L) for costs of ownership and operation
of the Hydro-Quebec intertie.
BANGOR VAR CO. - In 1990, the Company formed BVC, whose sole function
is to be a 50% general partner in Chester, a partnership which owns a
static var compensator (SVC), which is electrical equipment that
supports the Phase 2 transmission line. A wholly-owned subsidiary of
Central Maine Power Company owns the other 50% interest in Chester.
Chester has financed the acquisition and construction of the SVC
through the issuance of $33 million in principal amount of 10.48%
senior notes due 2020, and up to $3.25 million in principal amount of
additional notes due 2020 (collectively, the SVC Notes). The holders of
the SVC Notes are without recourse against the partners or their parent
companies and may only look to Chester and to the collateral for
payment. The New England utilities which participate in Phase 2 have
agreed under a FERC approved contract to bear the cost of Chester, on a
cost of service basis, which includes a return on and of all capital
costs.
Summary Financial Information for Maine Yankee and MEPCO is as follows
(dollars in thousands):
- ----------------------------------------------------------------------------
Maine Yankee MEPCO
- ----------------------------------------------------------------------------
2001 2000 1999 2001 2000 1999
------ -------- ------ ------ ------- -------
Operations:
As reported by investee-
Operating revenue $ 61,994 $ 43,813 $ 69,439 $ 4,514 $ 4,029 $ 2,936
-------- --------- --------- --------- ------- -------
Amortization/depreciation
and decommissioning
collections $ 47,586 $ 47,611 $ 55,286 $ 274 $ 319 $ 326
Interest and preferred
dividends 10,987 14,829 14,079 40 55 72
Other (income) expenses,
net (950) (23,267) (4,789) 3,008 2,274 (771)
----------- ----------- ---------- ------- -------- -------
Operating expenses $ 57,623 $ 39,173 $ 64,576 $ 3,322 $ 2,648 $ (373)
----------- --------- ---------- -------- -------- ------
Earnings applicable to
common stock $ 4,371 $ 4,640 $ 4,86 $ 1,192 $ 1,381 $3,309
========== ======== ======== ======= ======= ======
Amounts reported
by the Company-
Purchased power
costs $ 5,198 $ 5,013 $ 4,368 $ - $ - $ -
Equity in net
income (310) (320) (83) ( 19 (157) (199)
----------- --------------------- ------- -------- -----
Net purchased
power expense $ 4,888 $ 4,693 $ 4,285 $ (195) $ (157) $ (199)
========= ======== ======== ====== ====== =====
Financial Position:
As reported by investee-
Plant in service $ 685 $ 685 $ 685 $25,860 $25,593 $23,493
Accumulated
depreciation - - - (23,231) (23,075) (23,015)
Other assets and
deferred charges 801,433 914,412 1,049,287 4,241 3,355 7,589
---------- --------- ----------- --------- ------- ------
Total assets $ 802,118 $915,097 $1,049,972 $ 6,870 $5,873 $8,067
Less-
Preferred stock - 15,000 15,000 - - -
Long-term debt 31,200 40,800 54,000 - - -
Other liabilities
and deferred
credits 707,643 788,703 905,994 770 863 4,339
--------- --------- ----------- --------- -------- ------
Net assets $ 63,275 $ 70,594 $ 74,978 $6,100 $5,010 $ 3,728
========= ======== ========== ====== ====== =======
Company's reported equity-
Equity in net
assets $ 4,429 $ 4,942 $ 5,248 $ 866 $ 711 $ 529
Adjust Company's
estimated
to actual (7) 8 19 (12) (38) 1
------------ ----------- ------------ -------- --------- ----
Equity in net assets
as reported $ 4,422 $ 4,950 $ 5,267 $ 854 $ 673 $ 530
=========== ======== ========== ======== ====== ======
Power Supply Commitments - As of the end of 2001, the Company had
contracts with six in-dependent, non-utility power producers known as
"small power production facilities." The West Enfield Project,
described below, is one such facility. There are four other relatively
small hydroelectric facilities, and a 20 MW facility fueled by
municipal solid waste (see PERC discussion below). The cost of power
from the small power production facilities is more than the Company
would incur from other sources if it were not obligated under these
contracts, and, in the case of the solid waste plant, substantially
more. The prices were negotiated at a time when oil prices were much
higher than at present, and when forecasts for the costs of the
Company's long-term power supply were higher than current forecasts.
West Enfield Project - In 1986, the Company entered into a joint
venture with a development subsidiary of Pacific Lighting Corporation
for the purpose of financing and constructing the redevelopment of an
old 3.8 MW hydroelectric plant which the Company owned on the Penobscot
River in Enfield and Howland, Maine, into a 13 MW facility for the
purpose of operating the facility once it was completed. Commercial
operation of the redeveloped project began in April 1988. PHC was
formed to own the Company's 50% interest in the joint venture, Bangor-
Pacific. Bangor-Pacific financed the cost of the redevelopment through
the issuance in a privately placed transaction of $40 million of fixed
rate term notes and a commitment for up to $5 million of floating rate
notes. The notes are secured by a mortgage on the project and a
security interest in a 50-year purchased power contract, and the
revenues expected thereunder, between the Company and Bangor-Pacific.
In late July 1999, in connection with the generation asset sale, the
Company sold PHC to PP&L and received $10 million in proceeds. The sale
resulted in a gain of approximately $5.2 million, of which $4.7 million
was deferred as part of the deferred asset sale gain (see Note 11). The
remaining $.5 million of the gain related to the portion of the gain on
sale of PHC which was allocable to shareholders (recorded as Other
Income in the Consolidated Statements of Income for the year ending
December 31, 1999).
PERC - PERC owns a 20 MW waste-to-energy facility in Orrington, Maine,
that provides solid waste disposal services to many communities in
central, eastern, and northern Maine. The contract requires the Company
to purchase the electricity output of the plant until 2018 at a price
that is presently above the cost of alternative sources of power, and,
in the Company's opinion, is likely to remain so. The Company's
purchased power expense, net of revenues from the resale of power to
another utility, under this contract was approximately $15.1 million in
2001, is projected to be approximately $16 million in 2002, $20 million
in 2003, and to increase over the remainder of the contract up to $28
million in the last full year, 2017. Also as a result of a 1998
contract restructuring (discussed below), PERC will share the net
revenues generated by the facility on a pro rata basis with the Company
and the MRC, which represents over 130 Maine municipalities receiving
waste disposal service from PERC. In 2001, 2000 and 1999 the Company
realized $3.5 million, $3.5 million and $2.9 million, respectively, in
savings associated with its share of PERC net revenues. The Company
expects to realize approximately $3.6 million annually in such savings
through the term of the PERC contract.
Other Power Supply Commitments - The Company entered into a contract,
which started on March 1, 2001, for the delivery of up to 160 MW of
power from a third party, ending February 28, 2004. The energy
delivered in connection with the contract is used to serve a portion of
the standard offer service customer load. The Company's purchased
power expense under this contract was approximately $21 million in
2001, and is estimated to be approximately $39.4 million in 2002, $24.1
million in 2003 and $3.5 million in 2004. See Note 11 for a discussion
of the standard offer service.
In late 1999 the Company selected the winning bidder for all of the
capacity and energy from its six purchased power contracts being
auctioned off pursuant to Chapter 307 of the MPUC's rules for
regulation of electric utilities. The contract commenced March 1, 2000,
the date when retail customer choice for power supply commenced in
Maine, and continued through February 28, 2002. The Company recorded
$4.4 million in revenues from the resale of power under this contract
in 2001.
In the fall of 2001, the MPUC selected the winning bidder to supply the
small customer class of standard offer service starting in March 2002.
Their bid was contingent upon being selected as buyer of all of the
capacity and energy from the Company's previously discussed six
purchased power contracts, two-year standard offer related energy
supply contract and the output of the Company's diesel units. The
period of sale will commence March 1, 2002, and will continue for a
period of three years. The revenues to be realized under this
contract, as well as the final two months in 2002 of the Chapter 307
sales related contract discussed above, are estimated to be
approximately $36.9 million in 2002, $25.6 million in 2003, $11 million
2004 and $2 million in 2005.
Rate Recovery - In connection with the Company's stranded cost rate
proceeding with the MPUC, Maine Yankee decommissioning and other
closure costs, obligations associated with Hydro-Quebec, the cost of
energy and capacity associated with the power purchase contracts and
revenues associated with the sales agreements discussed in this note
are being recovered from customers as stranded costs.
PURCHASED POWER CONTRACT BUYOUTS AND RESTRUCTURING - During the 1990's,
the Company attempted to alleviate the adverse impact of high-cost
contracts with small power production facilities. One method for doing
so was to pay a fixed sum in return for terminating the contract. The
first such transaction was accomplished in 1993, and in 1995 the
Company succeeded in accomplishing two more.
In the 1993 transaction, the Company negotiated an agreement to cancel
its long-term purchased power agreement with one of the biomass plants,
the Beaver Wood Joint Venture (Beaver Wood), in June
1993. In connection with the cancellation, the Company paid Beaver Wood
$24 million in cash and issued a new series of 12.25% First Mortgage
Bonds due July 15, 2001 to the holders of Beaver Wood's debt in the
amount of $14.3 million in substitution for Beaver Wood's previously
outstanding 12.25% Secured Notes. Also, in connection with the
cancellation agreement, a reconstituted Beaver Wood partnership paid
the Company $1 million at the time of settling the transaction and
agreed to pay the Company $1 million annually for a six-year period
beginning in 1994 in return for retaining the ownership and the option
of operating the plant. The payments were secured by a mortgage on the
property of the Beaver Wood facility. In each of the years from 1994
through 1997 the Company received its $1 million payment. The Company
was entitled to receive the final two payments totaling $2 million in
1998 and 1999 from Beaver Wood. However, in July 1998, Beaver Wood
indicated that it would not be making the payment due at that time and
requested the Company agree to a lower payment. After assessing the
potential costs and benefits of foreclosing on the mortgage, the
Company determined that accepting a payment of $1.75 million would be a
better alternative. This $1.75 million payment was received in February
1999. The Company has recorded the $250,000 shortfall as a regulatory
asset as of December 31, 2001, and this amount will be recovered from
customers in connection with the Company's stranded cost recovery. The
Company established a regulatory asset associated with the cost of the
buyout, and with the implementation of new base rates on March 1, 1994,
the Company began recovering over a nine-year period the deferred
balance, net of the additional $6 million anticipated from Beaver Wood.
This regulatory asset is being amortized at an annual rate of $3.9
million through February 2003.
The 1995 transactions involved a "buyback" of the contracts for the
purchase of power from two biomass-fueled generating plants in West
Enfield and Jonesboro, Maine, which are identical plants under common
ownership. The buyback cost was approximately $170 million, including
transaction costs. The buyback costs were deferred and recorded as a
regulatory asset and are being amortized and collected over a ten-year
period, beginning July 1, 1995, at an annual expense of $17 million.
The cost of the buyback was financed entirely by new debt instruments,
thereby significantly increasing the Company's indebtedness (see Note
5).
In June 1998 the Company successfully completed a major restructuring
of its obligations under various agreements with PERC. It is
anticipated that the restructuring will result in a substantial savings
for the Company. As previously discussed, in connection with this
restructuring, PERC will share the net revenues generated by the
facility on a pro rata basis with the Company and the MRC over the
remaining term of the PERC contract. which represents over 130 Maine
municipalities receiving waste disposal service from PERC. The
Company also made a one-time payment of $6 million to PERC in June 1998
and is making additional quarterly payments, starting in October 1998,
of $250,000 for four years totaling $4 million. These amounts are
recorded as regulatory assets when the payments are made.
Finally, in connection with the PERC contract restructuring in 1998,
the Company issued two million warrants to purchase common stock, one
million each to PERC and the MRC. Each warrant entitled the warrant
holder to acquire one share of the Company's common stock at a price of
$7 per share. No warrants could be exercised within the first nine
months after their issuance, and they were exercisable in 500,000 share
blocks following the expiration of nine months, 21 months, 33 months,
and 45 months from the closing date. Upon exercise, the Company had the
option, instead of providing common stock, to pay cash equal to the
difference between the then market price of the stock and the exercise
price of $7 per share times the number of shares as to which exercise
is made. The MPUC established a cap on ratepayers' exposure to the cost
of the warrants. Ratepayer costs were limited to the difference between
the higher of $15 per share or the book value per share at the time the
warrants are exercised and the $7 exercise price. This cap was further
modified by the MPUC in 2001 in connection with the approval of the
Company's merger with Emera. For any warrants which were exercised after
the merger approval in January 2001, the cap on the ratepayers' exposure
was set at $10.50 per share ($17.50 per share less the $7 exercise price).
The Company will not recover any costs above the cap from ratepayers, and
as previously discussed, these amounts were charged against paid-in capital
in 2001.
As previously discussed in Note 4, in 2001, the remaining 1,437,215 of
outstanding common stock warrants were exercised. For 736,315 of these
warrants, the Company exercised its option to pay cash to the holders
of the warrants instead of actually issuing shares of common stock.
These payments amounted to approximately $14.2 million. For 700,900 of
unexercised warrants associated with the MRC, the Company and the MRC
entered into an agreement whereby the Company, instead of issuing
shares or paying cash, established the previously discussed note
payable to the MRC. As a result of the exercise of the warrants in 2001
and the affects of the cap on the ratepayers' exposure as set by the
MPUC, the Company increased its regulatory asset associated with the
PERC contract restructuring by approximately $13.7 million in 2001.
In 2000 and 1999, 212,786 and 349,999 common stock warrants were
exercised (at a market prices below the book value per common share at
the time of the exercise), respectively, and the Company exercised its
option to pay cash to the holders of the warrants instead of actually
issuing shares of common stock. These payments amounted to
approximately $2.5 million in 2000 and $3.3 million in 1999. As a
result of the exercise of the warrants in 2000 and 1999 and the cap on
the ratepayers' exposure as set by the MPUC, the Company increased its
regulatory asset associated with the PERC contract restructuring by
approximately $1.9 million in 2000 and $2.9 million in 1999.
As of December 31, 2001, the Company has deferred, as a regulatory
asset, approximately $27.6 million in costs associated with the PERC
contract restructuring. Effective with the implementation of new rates
on March 1, 2000, the Company began recovering the full amount of
deferred PERC restructuring costs, including an estimate of the future
value of warrants to be exercised and the additional $250,000
quarterly payments discussed above, amounting to an annual amortization
of $1.6 million per year. The Company had been involved in 2001 and
early 2002 in a regulatory proceeding at the MPUC to reset
stranded cost electric rates starting March 1, 2002. Effective with
the new electric rates set by the MPUC, the annual amortization expense
associated with the recovery of the PERC restructuring costs was
adjusted to $1.7 million annually.
NOTE 8. RECOVERY OF SEABROOK INVESTMENT AND SALE OF SEABROOK INTEREST
The Company was a participant in the Seabrook nuclear project in
Seabrook, New Hampshire. On December 31, 1984, the Company had almost
$87 million invested in Seabrook, but because the uncertainties arising
out of the Seabrook Project were having an adverse impact on the
Company's financial condition, an agreement for the sale of Seabrook
was reached in mid-1985 and was finally consummated in November 1986.
During 1985, a comprehensive agreement was negotiated among the
Company, the MPUC staff, and the Maine Public Advocate addressing the
recovery through rates of the Company's investment in Seabrook (the
Seabrook Stipulation). This negotiated agreement was approved by the
MPUC in late 1985. Although the implementation of the Seabrook
Stipulation significantly improved the Company's financial condition,
substantial write-offs were required as a result of the determination
that a portion of the Company's investment in Seabrook would not be
recovered. In addition to the disallowance of certain Seabrook costs,
the Seabrook Stipulation also provided for the recovery through
customer rates of 70% of the Company's year-end 1984 investment in
Seabrook Unit 1 over 30 years, and 60% of the Company's investment in
Unit 2 over seven years, with base rate treatment on the unamortized
balances. As of December 31, 1992, the Company's investment in Seabrook
Unit 2 was fully amortized.
NOTE 9. FAIR VALUE OF FINANCIAL INSTRUMENTS
The following represents the estimated fair value at December 31, 2001
of each class of financial instrument for which it is practical to
estimate the value:
Cash and cash equivalents-including money market funds and repurchase
agreements: the carrying amount of $884,617 approximates fair value.
Funds held by trustees, associated with the BERI capital reserve fund
and miscellaneous special deposits-Money market funds and U.S. Treasury
Bills: the carrying amount of $2,189,638 approximates fair value.
The fair values of other financial instruments at December 31, 2001
based upon similar issuances of comparable companies are as follows:
(In Thousands) Carrying Amount Fair Value
----------------- ------------
Funds held by trustee-guaranteed investment contract $21,191 $22,409
First Mortgage Bonds 85,000 98,876
FAME Revenue Notes 71,500 75,909
Medium Term Notes-LIBO rate plus 1.125% 5,460 5,460
Municipal Review Committee Note Payable 13,234 12,147
Short-term debt 8,000 8,000
NOTE 10. UNAUDITED QUARTERLY FINANCIAL DATA
Unaudited quarterly financial data pertaining to the results of
operations are shown below (Dollars in thousands except for per share
amounts):
Quarter Ended
-------------------------------------------
Mar. 31 June 30 Sept. 30 Dec. 31
-------------------------------------------
2001
- ------
Electric Operating Revenue $ 56,204 $ 54,003 $ 55,570 $ 51,803
Operating Income 7,627 3,169 6,099 6,722
Net Income (Loss) 4,584 (201) 3,062 1,244
Basic Earnings (Loss) Per
Share of Common Stock $ .6 $ (.04) $ 41 $ .16
======== ========= ======= ========
2000
- ------
Electric Operating Revenue $ 50,121 $ 48,563 $ 58,641 $ 55,012
Operating Income 8,307 4,652 6,535 6,930
Net Income 3,937 1,339 3,940 1,885
Basic Earnings Per Share
of Common Stock $ .53 $ .17 $ .53 $ .25
========= ========= ======= ========
1999
- ------
Electric Operating Revenue $ 50,222 $ 47,299 $ 51,452 $ 49,022
Operating Income 9,886 8,502 9,331 8,439
Net Income 4,212 3,452 5,037 5,580
Basic Earnings Per Share
of Common Stock $ .53 $ .43 $ .65 $ .74
========= ========== ========= =======
NOTE 11. INDUSTRY RESTRUCTURING AND RATE REGULATION
INDUSTRY RESTRUCTURING - In connection with the state of Maine's
electric industry restructuring law, effective March 1, 2000, consumers
of electricity had the right to purchase generation services directly
from competitive electricity suppliers. In February 2000, and in
connection with the implementation of the restructuring law, the
Company received a final rate order from the MPUC setting its
transmission and distribution and stranded cost rates effective March
1, 2000. The Company's total annual revenue requirement as set in the
rate proceedings, including $40 million associated with stranded cost
recovery, amounted to $103.2 million. The stranded cost recovery
includes the decommissioning and other plant closure expenses for Maine
Yankee. There were no write-offs of previously deferred costs based on
the final rate order.
In Maine, stranded costs are treated in the same manner as most other
costs and may be included in calculations for prospective rate changes.
Absent any rate proceedings, however, in 2003 and every three years
thereafter until the stranded costs are recovered, the MPUC shall
review and reevaluate the stranded cost recovery. Customers reducing
or eliminating their consumption of electricity by switching to self-
generation, conversion to alternative fuels or utilizing demand-side
management measures cannot be assessed exit or entry fees.
The restructuring law also provided for a standard-offer service being
available for all customers who did not choose to purchase energy from
a competitive supplier starting March 1, 2000. As a result of the bids
from competitive energy suppliers to provide energy under the standard-
offer service being higher than anticipated in both 2000 and 2001, and
as ordered by the MPUC, the Company assumed the responsibility of being
the standard-offer service provider starting March 1, 2000 for the
period ending February 28, 2002. 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 has
been allowed by the MPUC to defer, for future ratemaking treatment, 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. Since March 1, 2000, when new rates went into
effect, on a cumulative basis, the revenues realized from standard offer
customers have exceeded the costs of providing the standard offer service,
and consequently, the Company has recorded a regulatory liability of
approximately $5.7 million, including carrying costs, as of December
31, 2001 (which is included in Other regulatory liabilities on the
Consolidated Balance Sheets). Effective March 1, 2002, with the
implementation of new stranded cost rates as approved by the MPUC, the
Company began amortizing the deferred standard offer liability balance
over a two year period. Also effective March 1, 2002, as a result of
new bids received from competitive energy providers, the Company is no
longer serving as the standard offer service provider. The Company
is, though, serving as the billing and collection agent under the
standard offer program.
As a result of the previously discussed reconciliation mechanism,
standard-offer related revenues and expenses do not have any impact on
the Company's earnings, although they do result in increases in both
categories in the Company's Consolidated Statements of Income.
Consequently, the Consolidated Statement of Income for 2001 and 2000
has been modified to reflect the separate presentation of standard-
offer service revenues and purchased power expenses.
CURRENT RATE FILINGS - On October 12, 2001, the Company filed a
proposal with the MPUC for an alternative rate plan (ARP) that would
govern its rates for distribution service over a four year period.
Such a filing was required by the MPUC as a condition of its approval
of the Company's acquisition by Emera. In addition to distribution
service rates, the Company's ARP proposal included proposed incentives
to improve the efficiency and the service quality of power delivery
services to Bangor Hydro's customers. The Company's proposal included
an initial increase in distribution rates of approximately $3.4
million, with additional annual adjustments during the term of the ARP
at a rate below that of inflation. However, as a result of a scheduled
reduction in standard offer service, the combined impact of rate
changes for most customers would be a reduction of approximately 10%
(or about $8 per month for a typical residential customer) during 2002.
There is no legal deadline for the MPUC to complete such a proceeding.
On October 18, 2001, the Company filed a notice of its intent to file a
request for a general increase in distribution rates of approximately
$6.4 million. Under Maine law, utilities are required to provide a
minimum of sixty days notice of their intent to file such a request.
This filing was made as an alternative to the Company's ARP filing,
although it does not preclude simultaneous or subsequent implementation
of an ARP. Once filed, the MPUC must process such a request within
nine months.
In November 2001, the MPUC Hearing Examiner administering the ARP
proceeding suspended that proceeding pending the Company's filing of a
request for a general increase in distribution rates.
On January 11, 2002, the MPUC requested comments on a Draft Order that
would initiate a management investigation of the Company, as permitted
by Maine law, as part of its investigation of the Company's anticipated
request for a general increase in distribution rates. On January 17,
2002, in response to this Draft Order, the Company offered to defer
filing its request for a general increase in distribution rates and
asked the MPUC to defer initiating the management investigation to
permit the Company and interested parties a three month period to
pursue a settlement of the ARP proceeding with the expectation that
such a settlement would also terminate the proposed request for a
general increase in rates and the management investigation. At a
deliberative session held on January 22, 2002, the MPUC deferred
issuing an order initiating a management investigation for 90 days to
allow the parties to pursue a settlement of these related rate matters.
Management cannot predict the outcome of the regulatory proceedings
associated with the Company's rate proposals with the MPUC.
SALES OF THE COMPANY'S GENERATING ASSETS - In September 1998, the
Company sold certain property and equipment at its Graham Station site
in Veazie, Maine, to Casco Bay Energy for $6.2 million. On May 27,
1999, the Company completed most of the transaction for the sale of its
electric generating assets and certain transmission rights to PP&L. The
purchase price for the assets transferred was $79 million.
The sale involved all but one of the Company's hydroelectric plants on
the Penobscot, Piscataquis, and Union rivers and Bangor Hydro's 8.33%
ownership interest in the Wyman Unit #4 oil-fired plant in Yarmouth,
Maine-a total base load capacity of 83 megawatts. The sale also
involved a transfer by the Company of rights to transmit power over the
MEPCO transmission facilities connecting NEPOOL to New Brunswick
Canada; the Company's rights as a participant in the regional
utilities' agreement with Hydro-Quebec pursuant to an agency agreement;
and the Company's rights to develop a second high voltage transmission
line that will connect NEPOOL to New Brunswick, Canada.
The Company realized a net gain on the sale related to these sales of
approximately $29.8 million, and $29.3 million of this amount was
recorded as a deferred liability at February 29, 2000, on the
Consolidated Balance Sheets. As discussed in Note 7, the other $.5
million of the gain on the sale of Penobscot Hydro that was allocable
to shareholders, pursuant to orders of the MPUC, was recorded as other
income in 1999. 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 being 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 so 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 through May 2001 by an
annualized total of $2.5 million.
Effective April 15, 2001, and through February 28, 2002, in an effort
to mitigate the effects of increased energy prices for the Company's
large customers, the MPUC ordered the Company to reduce its
distribution and stranded cost electric rates to certain large
customers by $.008/kWh. To fund this rate reduction and corresponding
decrease in revenues, the MPUC ordered the Company to accelerate the
amortization of the deferred asset sale gain in an amount necessary to
offset the estimated decrease in revenues caused by the rate reduction.
The asset sale gain amortization was increased by approximately $2.5
million over the 10 1/2 month period the reduced rates was in effect.
Also, the Company's FERC jurisdictional transmission rates changed on
June 1, 2001. Consistent with 2000, the Company reduced its
distribution rates via an adjustment to the asset sale gain
amortization to offset the change in the transmission rates effective
June 1, 2001. The annualized accelerated amortization associated with
the transmission rate change amounts to approximately $1.6 million and
ends in May 2002.
In April 1999 Central Maine Power Company (CMP), sold all of its
interest in the Wyman generating units and ancillary property,
including its 59% interest in Unit 4. On August 31, 1999, 11 minority
owners of Wyman #4, including Bangor Hydro, served a Demand for
Arbitration on CMP with respect to the sale of Wyman #4. The Demand
asserted that the minority owners were entitled to a share of the
proceeds from CMP's sale of Wyman. On April 23, 2001, CMP and the
minority owners reached a settlement agreement to dispose of all claims
raised in the Demand for Arbitration. Under the terms of the
agreement, CMP agreed to pay the minority owners $12 million in
exchange for a full release from all claims arising from CMP's sale of
Wyman. In July 2001 the MPUC issued an order approving the settlement
agreement, and in October 2001 the Company received its share of the
settlement from CMP amounting to approximately $2.6 million. This
amount was deferred as a regulatory liability per the MPUC order, and
the Company will begin returning this amount to customers starting
March 1, 2002 in connection with a change in its stranded cost rates.
DEFERRED SPECIAL RATE CONTRACT REVENUES - Also in connection with the
February 2000 rate order from the MPUC, and starting March 1, 2000, the
Company was granted a deferral mechanism for the difference in actual
revenues realized from customers under special rate contracts as
compared to the estimated revenues from these customers utilized in
setting the Company's new electric rates starting March 1, 2000. Under
this deferral mechanism, the Company recorded a regulatory asset and
additional revenues of approximately $1.4 million for the period from
March 1, 2000 through December 31, 2000. In 2001, the Company's
special rate contract revenue deferrals amounted to approximately $1.6
million, of which $2.3 million was recorded as additional revenue and
$700,000 was recorded as an increase in goodwill. The increase in
goodwill was a result of certain adjustments to the deferrals approved
by the MPUC in the Company's recent stranded cost rate proceeding. The
regulatory asset is included as a component of Other Regulatory Assets
in the Consolidated Balance Sheets at December 31, 2001 and 2000.
REGULATORY ASSETS AND MEETING THE REQUIREMENTS OF SFAS 71 - The Company
is subject to the provisions of Statement of Financial Accounting
Standards No. 71, "Accounting for the Effects of
Certain Types of Regulation" (SFAS 71). SFAS 71 allows the
establishment of regulatory assets for costs accumulated for certain
items other than the usual and customary capital assets, and allows the
deferral of the income statement impact of those costs if they are
expected to be recovered in future rates. As of December 31, 2001, the
Company has regulatory assets, net of regulatory liabilities, of
approximately $246 million. The Company continues to meet the
requirements of SFAS 71 since the Company's rates are intended to
recover the cost of service plus a rate of return on the Company's
investment, as well as providing specific recovery of costs deferred in
prior periods.
The legislation enacted in Maine associated with industry restructuring
specifically addressed the issue of cost recovery of regulatory assets
stranded as a result of industry restructuring. Specifically, the
legislation requires the MPUC, when retail access begins, to provide a
"reasonable opportunity" for the recovery of stranded costs through the
rates of the transmission and distribution company, comparable to the
utility's opportunity to recover stranded costs before the
implementation of retail access under the legislation. The final rate
orders from the MPUC effective March 1, 2000 and March 1, 2002 did not
result in the Company writing off any stranded costs, but if the
Company had not been allowed full recovery of its stranded costs, it
would be required to write-off any disallowed costs. As provided for in
Emerging Issues Task Force Issue No. 97-4, "Deregulation of the Pricing
of Electricity," the Company will continue to record regulatory assets
in a manner consistent with SFAS 71 as long as future recovery is
probable, since the Maine legislation provides the opportunity to
recover regulatory assets including stranded costs through the rates of
the T&D company. The Company anticipates, based on current
generally accepted accounting principles, that SFAS 71 will continue to
apply to the regulated T&D segments of its business.
If the Company failed to meet the requirements of SFAS 71, due to
legislative or regulatory initiatives, the Company would be required to
apply Statement of Financial Accounting Standards No. 101, "Regulated
Enterprises-Accounting for the Discontinuation of Application of FASB
No. 71" (SFAS 101). If legislative or regulatory changes and/or
competition result in electric rates which do not fully recover the
Company's costs, a write-down of regulatory assets would be required.
The Company does not anticipate any write-down of assets at this time.
NOTE 12. CONSTRUCTION OF FACILITIES FOR CASCO BAY ENERGY
The Company entered into an agreement with Casco Bay whereby the
Company agreed to construct various transmission facilities required to
allow a generating facility being constructed in Veazie, Maine to
interconnect with the Company's electrical system and deliver its
output to the New England Power Pool Transmission Facility (PTF) grid.
Under this agreement, Casco Bay agreed to advance funds necessary to pay
for such construction. Pursuant to a FERC order approving an amendment to
the NEPOOL Agreement, approximately 50% of the construction funds advanced
are being refunded to Casco Bay by customers of NEPOOL over an
approximately 30-year period. The Company began refunding such
construction costs to Casco Bay starting in June 2000. At the end of
2001, the Company had recorded approximately $4 million for PTF
facilities and a corresponding Long-term Payable of $3.7 million. These
amounts are included on the Consolidated Balance Sheets as components
of Electric Plant in Service and Other Long-term Liabilities,
respectively.
NOTE 13. DERIVATIVE FINANCIAL INSTRUMENTS
Effective January 1, 2001, the Company adopted Statement of Financial
Accounting Standards (SFAS) No. 133, "Accounting for Derivative
Instruments and Hedging Activities," as amended by SFAS No. 138. This
new accounting standard requires that all derivative instruments be
recorded on the balance sheet at fair value and establishes criteria
for designation and effectiveness of hedging relationships. The effect
of adopting this standard was not material to the Company's
consolidated financial statements.
The accounting for derivative financial instruments can change based on
guidance received from the Derivatives Implementation Group (DIG). The
DIG identifies practice issues that arise from applying the
requirements of SFAS 133 and advises the Financial Accounting Standards
Board on how to resolve those issues.
PURCHASED POWER CONTRACTS - In the second quarter of 2001, the DIG
reached a conclusion as to the interpretation of clearly and closely
related contracts that qualify for the normal purchase and sales
exception under SFAS 133. The conclusion of the DIG was that for
contracts with prices indexed to the Consumer Price Index (CPI), these
would not qualify for the normal purchase and sale exception under SFAS
133 and would need to be accounted for as derivatives under this
statement effective July 1, 2001. The Company has two power contracts
(one purchase and one sale) with prices indexed to a broad price
measure similar to the CPI, that were excluded from the scope of SFAS
133 on January 1, 2001, as a result of the normal purchase and sale
exception. Given the DIG's conclusion, the Company, effective July 1,
2001, began to account for these power contracts as derivatives in
accordance with SFAS 133 and recorded them at fair value on the
Company's consolidated balance sheet in the third quarter of 2001.
The fair value of the above-market portion of these contracts as of
December 31, 2001 represents a liability of approximately $74.0
million. The Company has recorded a regulatory asset to offset this
liability, since the Company is currently recovering the net above-
market cost of these contracts as part of its stranded cost recovery.
As a result of this regulatory accounting, the recording of these
contracts on the Company's consolidated balance sheet does not result
in an impact on earnings.
INTEREST RATE SWAP - As discussed in Note 5, in connection with the
$24.8 million in BERI medium term notes, BERI entered into an interest
rate swap arrangement with a major financial institution to provide
interest rate protection through the maturity date of the term loan.
The interest rate swap fixed the LIBO interest rate on the medium term
notes at 5.72%. BERI will be reimbursed for incremental interest
expense incurred in excess of the 5.72% and incurs additional expense
for incremental interest expense below 5.72%. Market risk is the
potential loss arising from adverse changes in interest rates. The fair
value of the interest rate swap at December 31, 2001 is ($79,862) and
represents the estimated payment that would be paid to terminate the
agreement.
NOTE 14. CONTINGENCIES
ENVIRONMENTAL MATTERS - In 1992, the Company received notice from the
Maine Department of Environmental Protection that it was investigating
the cleanup of several sites in Maine that were used in the past for
the disposal of waste oil and other hazardous substances, and that the
Company, as a generator of waste oil that was disposed at those sites,
may be liable for certain cleanup costs. The Company learned in
October 1995 that the United States Environmental Protection Agency
placed one of those sites on the National Priorities List under the
Comprehensive Environmental Response, Compensation, and Liability Act
and will pursue potentially responsible parties. With respect to this
site, the Company is one of a number of waste generators under
investigation.
The Company has recorded a liability, based upon currently available
information, for what it believes are the estimated environmental
remediation costs that the Company expects to incur for this waste
disposal site. Additional future environmental cleanup costs are not
reasonably estimable due to a number of factors, including the unknown
magnitude of possible contamination, the appropriate remediation
methods, the possible effects of future legislation or regulation and
the possible effects of technological changes. At December 31, 2001,
the liability recorded by the Company for its estimated environmental
remediation costs amounted to approximately $435,000. The Company's
actual future environmental remediation costs may be different as
additional factors become known.
ERNST & YOUNG Ernst & Young LLP Phone: (617) 266-2000
200 Clarendon Street Fax: (617) 266-5843
Boston, Massachusetts 02116-5072 www.ey.com
Report of Independent Auditors
To the Stockholders and Directors of
Bangor Hydro-Electric Company
We have audited the consolidated financial statements listed in the index
appearing under Item 14(a) and the financial statement schedule appearing
under Item 14(b) as of December 31, 2001, and for the year then ended.
These financial statements and financial statement schedule are the
responsibility of the Company's management. Our responsibility is to
express an opinion on these financial statements and financial statement
schedule based on our audit. The financial statements of Bangor Hydro-
Electric Company and financial statement schedules for the years ended
December 31, 2000 and 1999 were audited by other auditors whose report dated
February 2, 2001 expressed an unqualified opinion on those statements and
schedules.
We conducted our audit in accordance with auditing standards generally
accepted in the United States. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining,
on a test basis, evidence supporting the amounts and disclosures in the
financial statements. An audit also includes assessing the accounting
principles used and significant estimates made by management, as well as
evaluating the overall financial statement presentation. We believe that
our audit provides a reasonable basis for our opinion.
In our opinion, the 2001 consolidated financial statements referred to above
present fairly, in all material respects, the consolidated financial
position of Bangor Hydro-Electric Company at December 31, 2001, and the
consolidated results of its operations and its cash flows for the year then
ended in conformity with accounting principles generally accepted in the
United States. Also, in our opinion, the related financial statement
schedules, when considered in relation to the basic financial statements
taken as a whole, present fairly in all material respects the information
set forth therein.
As discussed in Note 13 and Note 1, respectively, of the consolidated
financial statements, in 2001 the Company changed its method of accounting
for derivative financial instruments and for goodwill.
February 1, 2002 /s/ Ernst & Young LLP
---------------------
Ernst & Young LLP is a member of Ernst & Young International, Ltd.
ITEM 7A QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
See Item 7, "Management's Discussion and Analysis of Results of Operations and
Financial Condition -Contingencies and Disclosures About Market Risk", and Item
8, Note 13, "Derivative Financial Instruments" for a discussion of certain
derivative financial instruments held by the Company.
ITEM 9 CHANGES IN AND DISAGREEMENTS WITH INDEPENDENT ACCOUNTANTS ON
FINANCIAL DISCLOSURE
At a regularly scheduled meeting of the Board of Directors held on November
21, 2001, the Board appointed Ernst & Young LLP, P.O. Box 2007, Station CRO,
13th Floor, 1959 Upper Water Street, Halifax, N.S. B3J 2Z1 to serve as the
Company's Independent Public Accountants for the Company's 2001 and 2002
fiscal years, thereby discontinuing the Company's retention of
PricewaterhouseCoopers, LLP, One Post Office Square, Boston, Massachusetts
02109, in this capacity. The decision to change accountants was approved by
the Audit Committee of the Board. Ernst & Young serves as independent
auditors to Emera Inc., a parent of the Company.
PricewaterhouseCoopers's report on the financial statements for 1999 and 2000
did not contain any adverse opinion or a disclaimer of opinion, nor was it
qualified or modified as to uncertainty, audit scope, or accounting principles.
During the Company's 1999 and 2000 fiscal years and during 2001 prior to the
dismissal of PricewaterhouseCoopers, the Company had no disagreements with
PricewaterhouseCoopers on any matter of accounting principles or practices,
financial statement disclosure, or auditing scope or procedure, which
disagreement(s), if not resolved to the satisfaction of the former
accountant, would have caused it to make reference to the subject matter of
the disagreement(s) in connection with its report. For a full disclosure
regarding this change in accountants, please refer to the Company's Report
on Form 8-K dated for events occurring on November 21, 2001 which is
incorporated herein by reference.
PART III
ITEM 10 DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
See Item 4 above, and see the information under "Election of Directors" in
the Company's definitive proxy statement for the annual meeting of
stockholders to be held on April 24, 2002, which information is incorporated
herein by reference.
ITEM 11 EXECUTIVE COMPENSATION
See the information under "Executive Compensation" in the Company's
definitive proxy statement for the annual meeting of stockholders to be held
on April 24, 2002, which information is incorporated herein by reference.
ITEM 12 SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
(a) Security Ownership of Certain Beneficial Owners
See the Company's definitive proxy statement for the annual meeting of
stockholders to be held on April 24, 2002, which information is
incorporated herein by reference.
(b) Security Ownership of Management
See the Company's definitive proxy statement for the annual meeting of
stockholders to be held on April 24, 2002, which information is
incorporated herein by reference.
(c) Changes in Control
Effective October 10, 2001, pursuant to an Agreement and Plan of Merger,
the Company became a wholly owned subsidiary of Emera Inc. of Halifax,
Nova Scotia through Emera's purchase of 100% of the Company's common
equity. The Company is unaware of any arrangements, including any
pledge by any person of securities of the Company or any of its parents,
the operation of which may at a subsequent date result in a change in
control of the registrant.
ITEM 13 CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
See the information under "Compensation Committee Interlocks and Insider
Participation" in the Company's definitive proxy statement for the annual
meeting of stockholders to be held on April 24, 2002, which information is
incorporated herein by reference.
PART IV
ITEM 14 EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(a) Consolidated Financial Statements of the Company covered by the Report
of the of Independent Auditors (See Item 8):
Consolidated Statements of Income for the Years Ended
December 31, 2001, 2000 and 1999
Consolidated Balance Sheets - December 31, 2001 and
2000
Consolidated Statements of Capitalization - December 31, 2001
and 2000
Consolidated Statements of Cash Flows for the Years Ended
December 31, 2001, 2000 and 1999
Consolidated Statements of Common Stock Investment
for the Years ended December 31, 2001, 2000 and 1999
Notes to Consolidated Financial Statements
Report of Independent Accountants
(b) Schedules
Report of Independent Accountants
Schedule VIII - Reserves for Doubtful Accounts
All other schedules are omitted as the required information is
inapplicable or the information is presented in the Company's
consolidated financial statements or related notes.
(c) Exhibits
See Exhibit Index.
(d) Reports on Form 8-K
A current report on Form 8-K for the Fourth Quarter of 2001 was filed
regarding the Company's Change in Accountants effective November 21, 2001.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed
on its behalf by the undersigned, thereunto duly authorized.
Bangor Hydro-Electric Company
/s/ Carroll R. Lee
------------------------
By: Carroll R. Lee
President and
Chief Operating Officer
Pursuant to the requirements of the Securities and Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dates indicated.
/s/ Elizabeth A. MacDonald
--------------------------
Robert S. Briggs Elizabeth A. MacDonald
Director Director
/s/ David McD.Mann
------------------
Jane J. Bush David McD. Mann
Director Chairman of the Board
/s/ Christopher G. Huskilson /s/ Richard J. Smith
- ---------------------------- --------------------
Christopher G. Huskilson Richard J. Smith
Vice Chairman, Director Director
/s/ Norman A. Ledwin /s/ Ronald E. Smith
- -------------------- -------------------
Norman A. Ledwin Ronald E. Smith
Director Director
/s/ Carroll R. Lee /s/ Frederick S. Samp
- ------------------ ---------------------
Carroll R. Lee Frederick S. Samp
Director, President Vice President - Finance & Law
and Chief Operating (Chief Financial Officer)
Officer
David R. Black
--------------
David R. Black
Controller
(Chief Accounting Officer)
Each of the above signatures is affixed as of February 28, 2002.
SCHEDULE VIII
RESERVE FOR DOUBTFUL ACCOUNTS
-----------------------------
Additions
-----------------------------
Balance at Charged to Charged to Balance at
Beginning Costs and Other End
Of Period Expenses Accounts Deductions of Period
---------------------------------------------------- -------------
2001
Reserve for Doubtful Accounts $ 761,000 $1,884,630 $ - $1,884,630 (A) $ 761,000
--------- --------- --------- --------- ---------
2000
Reserve for Doubtful Accounts $ 1,075,000 $1,275,016 $ - $1,589,016 (B) $ 761,000
--------- --------- --------- --------- ---------
1999
Reserve for Doubtful Accounts $ 1,075,000 $1,475,395 $ - $1,475,395 (A) $1,075,000
--------- --------- --------- --------- ---------
NOTE:
(A) Accounts written off, less recoveries.
(B) Accounts written off, less recoveries. For 2000 includes reduction in
reserve for doubtful accounts of $314,000.
EXHIBIT INDEX
EXHIBITS INCLUDED HEREWITH
3. Articles of Incorporation and By-Laws
3(a) Articles of Merger dated October 10, 2001
3(b) Articles of Amendment dated January 8, 2002, reducing the minimum
number of directors from 9 to 3
3(c) By-Laws of the Company, Amended and Restated as of December 19,
2001
10. Material Contracts
10(a) Line Agreement dated as of June 29, 2001 Agreement By and Among the
Company and Fleet National Bank
10(b) Promissory Note dated as of June 29, 2001 Agreement By and Among
the Company and Fleet National Bank 10(a)
10(c) Promissory Note dated as of October 10, 2001 from the Company to
the Municipal Review Committee, Inc.
10(d) Amendment No. 3 entered into as
of December 31, 2001 to the 1998 Amended and Restated Revolving
Credit Agreement and Term Loan Agreement By and Among the Company
and Fleet National Bank as Agent
10(e) Amendment No. 2 dated as of December 31, 2001 to Promissory Note By
and Among the Company and Fleet National Ban
EXHIBIT INDEX
EXHIBITS INCORPORATED HEREIN BY REFERENCE
EXHIBIT NO. DESCRIPTION OF EXHIBIT INCORPORATED BY REFERENCE TO:
- ----------- ---------------------- -----------------------------
3. ARTICLES OF INCORPORATION & BY-LAWS
-----------------------------------
3.1 Company's Certificate Form S-2, Reg. No. 33-39181,
of Organization, together Exhibit 3.1
with all amendments thereto
3.2 Articles of Amendment Form S-2, Reg. No. 33-63500,
increasing Company's Exhibit 4.3
authorized capital stock
3.3 Articles of Amendment Form 10-K, 1995, Exhibit 3(a)
changing Corporate Clerk
3.4 Articles of Amendment Form 10-K, 1998, Exhibit 3(a)
Allowing Use of Similar Name
4. INSTRUMENTS DEFINING THE RIGHTS OF SECURITY HOLDERS
---------------------------------------------------
4.1 Mortgage and Deed of Form S-1, Reg. No. 2-54452,
Trust dated as of Exhibit 4(b)(1)
July 1, 1936, re
First Mortgage Bonds
4.2 Supplemental Indenture Form S-1, Reg. No. 2-54452,
dated as of December 1, Exhibit 4(b)(2)
1945, amending the
Mortgage
4.3 Supplemental Indenture Form S-1, Reg. No. 2-54452
dated as of September 1, Exhibit 4(b)(4)
1969, re 8 1/4% Series
Bonds, together with form
of purchase agreement.
(Supplemental indentures
and purchase agreements
with respect to prior
issues are substantially
identical in substantive
content to the 8 1/4%
Series documents).
4.4 Supplemental Indenture Form 10-K, 1975, Exhibit B
dated as of November 1,
1975, re 10 1/2% Series
Bonds, together with form
of purchase agreement
4.5 Supplemental Indenture Form 8-K, 6/28/76, Exhibit A
dated as of June 1, 1976,
re 9 1/4% Series Bonds
4.6 Supplemental Indenture Form S-7, Reg. No. 2-61589,
dated as of January 1, Exhibit 5(a)(7)
1978, re 8.6% Series
Bonds, together with form
of purchase agreement
4.7 Supplemental Indenture Form 10-Q, 3rd Quarter 1979,
dated as of August 1, Exhibit A
1979, re 10.25% Series
Bonds, together with form
of purchase agreement
Common Stock Purchase Plan
4.8 Supplemental Indenture Form 10-Q, 1st Quarter, 1981,
dated as of April 1, Exhibit A
1981 re 15.25% Series
Bonds, together with form
of purchase agreement
4.9 Supplemental Indenture Form 10-Q, 2nd Quarter 1981,
dated as of July 30, Exhibit (4)
1981 re 16.50% Series
Bonds, together with form
of purchase agreement
4.10 Bond Purchase Agreement, Form 10-K, 1983, Exhibit 4(a)
including form of
supplemental indenture,
with respect to First
Mortgage Bonds, 12.50%
Series due 1998
4.11 Bond Purchase Agreement, Form 10-K, 1984, Exhibit 4(a)
including form of
supplemental indenture,
with respect to First
Mortgage Bonds, 17.35%
Series due 1994
4.12 Bond Purchase Agreement Form 10-Q, First Quarter,
dated as of March 1, 1989 1989, Exhibit 4.1
including form of
supplemental indenture,
with respect to First
Mortgage Bonds, 10.25%
Series due 2019
4.13 Bond Purchase Agreement Form 10-K, 1990, Exhibit 4(b)
dated as of June 15, 1990
including form of
supplemental indenture,
with respect to First
Mortgage Bonds, 10.25%
Series due 2020
4.14 Loan Agreement by and Form 10-Q, 3rd Quarter 1995,
Finance Authority of Exhibit 4.1
Maine and Bangor Hydro-
Electric Company
4.15 Purchase Contract dated Form 10-Q, 3rd Quarter 1995,
as of June 28, 1995 among Exhibit 4.3
the Finance Authority of
Maine and Bangor Hydro-
Electric Company and
Prudential Securities
Incorporated
4.16 General and Refunding Form 10-Q, 3rd Quarter 1995,
Mortgage Indenture and Exhibit 4.4
Deed of Trust - Bangor
Hydro-Electric Company
to Chemical Bank, As
Trustee, Dated as of
June 1, 1995
4.17 Supplemental Indenture Form 10-Q, 3rd Quarter 1995,
Dated as of June 15, 1995 Exhibit 4.5
to General and Refunding
Mortgage Indenture and Deed
of Trust dated as of June
1, 1995 (Bangor Hydro-
Electric Company to Chemical
Bank).
4.18 Supplemental Indenture as Form 10-Q, 3rd Quarter 1995,
of June 29, 1995 to
Mortgage and Deed of Trust
dated as of July 1, 1936
(Bangor Hydro-Electric
Company to Citibank, N.A.
at Trustee).
4.19 Supplemental Indenture Form 10-K, 1995, Exhibit 4(a)
Dated as of October 1, 1995 (Identified as Exhibit 10(a))
to General and Refunding
Mortgage and Deed of Trust
dated as of June 1, 1995
(Bangor Hydro-Electric
Company to Chemical Bank).
4.20 TERM LOAN AGREEMENT Form 10-Q, First Quarter 1998,
dated as of March 31, 1998 Exhibit 4(a)
among BANGOR ENERGY RESALE,
INC., BANKBOSTON, N.A. and
the certain other lending
institutions and
BANKBOSTON, N.A., as Agent,
including all Exhibits thereto
4.21 GUARANTY, dated as of March 31, Form 10-Q, First Quarter 1998,
1998, by BANGOR HYDRO Exhibit 4(b)
- -ELECTRIC COMPANY, in favor of
(a) BANKBOSTON, N.A., as Agent,
for itself and the other
lending institutions which are
or may become parties to a Term
Loan Agreement, dated as of
March 31, 1998
4.22 Warrant to Purchase Form 10-Q, Second Quarter 1998,
Common Stock Granted to Exhibit 4(a)
the Municipal Review
Committee, Inc. on
June 26, 1998
4.23 Supplemental Indenture Form 10-Q, Second Quarter 1998,
Dated as of June 29, 1998 Exhibit 4(d)
between the Company and
Citibank, N.A.
10. MATERIAL CONTRACTS
------------------
10.1 New England Power Pool Form S-7, Reg. No. 2-69904,
Agreement dated as of Exhibit 10(a)(3)
September 1, 1971, with
all amendments through
December 1980
10.2 Copy of Twelfth Amendment Form S-7, Reg. No. 2-69904,
dated as of June 16, 1980 Exhibit 10(a)(4)
to the Agreement for Joint
Ownership, Construction and
Operation of New Hampshire
Nuclear Units
10.3 Participation Agreement Form S-1, Reg. No. 2-54452,
dated June 20, 1969 Exhibit 13(a)(2)(a)-1
between Maine Electric
Power Company, Inc.
("MEPCO") and the Company
10.4 Agreement dated June Form S-1, Reg. No. 2-54452,
29, 1969 among Maine Exhibit 13(a)(2)(a)-2
participants in MEPCO
Participation Agreement
10.5 Power Contract dated Form S-1, Reg. No. 2-54452,
May 20, 1968 between Exhibit 13(a)(3)(a)
Maine Yankee Atomic
Power Company ("Maine
Yankee") and the
Company and other
utilities
10.6 Stockholder Agreement Form S-1, Reg. No. 2-54452,
dated May 20, 1968 Exhibit 13(a)(3)(b)
among stockholders of
Maine Yankee, (including
the Company).
10.7 Capital Funds Agreement Form S-1, Reg. No. 2-54452,
dated May 29,1968 Exhibit 13(a)(3)(c)
between Maine Yankee
and sponsors, including
the Company
10.8 Maine Yankee Transmission Form S-1, Reg. No. 2-54452,
Agreement dated April 1, Exhibit 13(a)(3)(d)
1971 among the Company
and other utilities
10.9 Modification of Maine Form S-1, Reg. No. 2-54452,
Yankee Transmission Exhibit 13(a)(3)(f)
Agreement of December
1, 1972
10.10 Forms of contracts Form 10-Q, 2nd Qtr. 1982,
concerning the Company's Exhibit 10
participation with
other New England
utilities in the
proposed Quebec
interconnection
10.11 Third Amendment dated Form 10-K, 1983, Exhibit 10.2
as of November 1, 1982
to Preliminary Quebec
Interconnection Support
Agreement
10.12 Second Amendment dated Form 10-K, 1983, Exhibit 10.3
as of November 1, 1982
to Agreement With
Respect to Use of
Quebec Interconnection
10.13 Amendment No. 2 dated Form 10-K, 1983, Exhibit 10.4
as of November 1, 1982,
to Phase 1 Terminal
Facility Support
Agreement (Quebec
Interconnection)
10.14 Amendment No. 2 dated Form 10-K, 1983, Exhibit 10.5
as of November 1, 1982
to Phase 1 Vermont
Transmission Line
Support Agreement
(Quebec Interconnection)
10.15 Fourth Amendment Form 10-Q, 1st Quarter 1983,
dated as of March 1, Exhibit 10.1
1983, to Preliminary
Quebec Interconnection
Support Agreement
10.16 Amendment dated as of Form 10-Q, 2nd Quarter 1983,
September 1, 1981 Exhibit 10.3
to New England Power
Pool Agreement
10.17 Amendment dated as of Form 10-Q, 2nd Quarter 1983,
June 1, 1982 to New Exhibit 10.4
England Power Pool
Agreement
10.18 Amendment dated as of Form 10-Q, 2nd Quarter 1983,
June 15, 1983 to New Exhibit 10.5
England Power Pool
Agreement
10.19 Amendment dated as of Form 10-Q, 3rd Quarter 1983,
October 1, 1983 to Exhibit 10.1
New England Power Pool
Agreement
10.20 Amendment No. 1 to the Form 10-K, 1983, Exhibit 10(b)
Maine Yankee Power
Contract
10.21 Amendment No. 2 to the Form 10-K, 1983, Exhibit 10(c)
Maine Yankee Power
Contract
10.22 Additional Power Con- Form 10-K, 1983, Exhibit 10(d)
tract between Maine
Yankee and its sponsors,
including the Company
10.23 Preliminary Support Form 10-K, 1984, Exhibit 10(b)
Agreement - Phase 2 of
Hydro-Quebec Inter-
connection
10.24 Amendment dated September 1, Form 10-K, 1985, Exhibit 10(b)
1985 to Agreement with
respect to Use of Quebec
Interconnection
10.25 Energy Contract dated Form 10-K, 1985, Exhibit 10(c)
March 1983 between NEPOOL
and Hydro-Quebec re:
Hydro-Quebec Phase I
interconnection project
10.26 Energy Banking Agreement Form 10-K, 1985, Exhibit 10(d)
dated March 1983 between
NEPOOL and Hydro-Quebec re
Hydro-Quebec Phase I
interconnection project
10.27 Interconnection Agreement Form 10-K, 1985, Exhibit 10(e)
dated March 1983 between
NEPOOL and Hydro-Quebec re:
Hydro-Quebec Phase I
interconnection project
10.28 Amendment dated September 1 Form 10-K, 1985, Exhibit 10(f)
1985 to NEPOOL Agreement
re: Hydro-Quebec Phase II
interconnection project
10.29 Firm Energy Contract dated Form 10-K, 1985, Exhibit 10(g)
October 14, 1985 between
New England utilities and
Hydro-Quebec re: Hydro-
Quebec Phase II
interconnection project
10.30 Boston Edison AC Facilities Form 10-K, 1985, Exhibit 10(h)
Support Agreement dated June
1, 1985 re: Hydro-Quebec
Phase II interconnection
project
10.31 Phase II New England Form 10-K, 1985, Exhibit 10(i)
Power AC Facilities
Support Agreement dated
June 1, 1985 re: Hydro-
Quebec Phase II
interconnection project
10.32 Phase II Massachusetts Form 10-K, 1985, Exhibit 10(j)
Transmission Facilities
Support Agreement dated
June 1, 1985 re: Hydro-
Quebec Phase II
interconnection project
10.33 Phase II New Hampshire Form 10-K, 1985, Exhibit 10(k)
Facilities Support
Agreement dated June 1,
1985 re: Hydro-Quebec
Phase II interconnection
project
10.34 First Amendment dated Form 10-K, 1985, Exhibit 10(l)
March 1, 1985 and Second
Amendment dated January 1,
1986 to Preliminary Quebec
Interconnection Support
Agreement - Phase II
10.35 Amendment No. 3 dated Form 10-K, 1985, Exhibit 10(m)
October 1, 1984 to Maine
Yankee Power Contract
10.36 Amendment No. 1 dated Form 10-K, 1985, Exhibit 10(n)
August 1, 1985 to Maine
Yankee Capital Funds
Agreement
10.37 Amendments dated August 1, Form 10-K, 1985, Exhibit 10(o)
1985, August 15, 1985, and
January 1, 1986 to
NEPOOL Agreement
10.38 Third Amendment to Vermont Form 10-Q, 1st Quarter 1986,
Transmission Line Support Exhibit 10.2
Agreement
10.39 First Amendment to Hydro- Form 10-Q, 1st Quarter 1986,
Quebec Phase I Intercon- Exhibit 10.3
nection Agreement
10.40 First Amendment to Hydro- Form 10-Q, 2nd Quarter 1986,
Quebec Phase II Exhibit 10.1
Massachusetts Trans-
mission Facilities
Support Agreement
10.41 First Amendment to Hydro- Form 10-Q, 2nd Quarter 1986,
Quebec Phase II New Exhibit 10.2
Hampshire Transmission
Facilities Support
Agreement
10.42 First Amendment to Hydro- Form 10-Q, 2nd Quarter 1986,
Quebec Phase II New England Exhibit 10.3
Power AC Facilities
Support Agreement
10.43 First Amendment to Form 10-Q, 2nd Quarter 1986,
Hydro-Quebec Phase II Exhibit 10.4
Boston Edison Company AC
Facilities Support
Agreement
10.44 Amendment Number 3 to Form 10-Q, 3rd Quarter 1986,
Hydro-Quebec Phase l Exhibit 10.1
Terminal Facility Support
Agreement
10.45 Amendment Number 3 to Form 10-Q, 3rd Quarter 1986,
Hydro-Quebec Phase I Exhibit 10.2
Vermont Transmission Line
Support Agreement
10.46 Power Sale Agreement for Form 10-Q, 3rd Quarter 1986,
sale of approximately Exhibit 10.3
31 MW of system power by
Bangor Hydro-Electric
Company to UNITIL
Power Corp.
10.47 Purchase Agreement with Form 10-Q, 3rd Quarter 1986,
respect to Wyman No. 4 Exhibit 10.4
between Bangor Hydro-
Electric Company and
Fitchburg Gas and Electric
Light Company
10.48 Power Purchase Agreement Form 10-K, 1986, Exhibit 10(i)
dated June 9, 1986 and
Amendment No. 1 thereto
dated January 14, 1987,
between the Company and
Bangor-Pacific Hydro
Associates (formerly West
Enfield Associates)
10.49 Power Sale Agreement dated Form 10-K, 1986, Exhibit 10(l)
August 1, 1986, and First
Amendment thereto, between
the Company and Unitil
Power Corp. re Wyman No. 4
10.50 Third Amendment to Pre- Form 10-K, 1987, Exhibit 10(a)
liminary Quebec Intercon-
nection Support Agreement -
Phase II
10.51 Fourth Amendment to Pre- Form 10-K, 1987, Exhibit 10(b)
liminary Quebec Intercon-
nection Support Agreement -
Phase II
10.52 Fifth Amendment to Pre- Form 10-K, 1987, Exhibit 10(c)
liminary Quebec Intercon-
nection Support Agreement -
Phase II
10.53 Sixth Amendment to Pre- Form 10-K, 1987, Exhibit 10(d)
liminary Quebec Intercon-
nection Support Agreement -
Phase II
10.54 Seventh Amendment to Pre- Form 10-K, 1987, Exhibit 10(e)
liminary Quebec Intercon-
nection Support Agreement -
Phase II
10.55 Amendment to New England Form 10-K, 1987, Exhibit 10(f)
Power Pool Agreement dated
March 1, 1988
10.56 Ninth Amendment to Form 10-K, 1988, Exhibit 10(b)
Preliminary Quebec
Interconnection Support
Agreement - Phase II
10.57 Tenth Amendment to Form 10-K, 1988, Exhibit 10(c)
Preliminary Quebec
Interconnection Support
Agreement - Phase II
10.58 Second Amendment to Form 10-K, 1988, Exhibit 10(d)
Massachusetts Trans-
mission Facilities
Support Agreement
10.59 Third Amendment to Form 10-K, 1988, Exhibit 10(e)
Massachusetts Trans-
mission Facilities
Support Agreement
10.60 Fourth Amendment to Form 10-K, 1988, Exhibit 10(f)
Massachusetts Trans-
mission Facilities
Support Agreement
10.61 Fifth Amendment to Form 10-K, 1988, Exhibit 10(g)
Massachusetts Trans-
mission Facilities
Support Agreement
10.62 Sixth Amendment to Form 10-K, 1988, Exhibit 10(h)
Massachusetts Trans-
mission Facilities
Support Agreement
10.63 Second Amendment to Form 10-K, 1988, Exhibit 10(i)
New Hampshire Trans-
mission Facilities
Support Agreement
10.64 Third Amendment to Form 10-K, 1988, Exhibit 10(j)
New Hampshire Trans-
mission Facilities
Support Agreement
10.65 Fourth Amendment to Form 10-K, 1988, Exhibit 10(k)
New Hampshire Trans-
mission Facilities
Support Agreement
10.66 Fifth Amendment to Form 10-K, 1988, Exhibit 10(l)
New Hampshire Trans-
mission Facilities
Support Agreement
10.67 Sixth Amendment to Form 10-K, 1988, Exhibit 10(m)
New Hampshire Trans-
mission Facilities
Support Agreement
10.68 Second Amendment to Form 10-K, 1988, Exhibit 10(n)
Phase II AC New England
Power Facilities Sup-
port Agreement
10.69 Third Amendment to Form 10-K, 1988, Exhibit 10(o)
Phase II AC New England
Power Facilities Sup-
port Agreement
10.70 Fourth Amendment to Form 10-K, 1988, Exhibit 10(p)
Phase II AC New England
Power Facilities Sup-
port Agreement
10.71 Fifth Amendment to Form 10-K, 1988, Exhibit 10(q)
Phase II AC New England
Power Facilities Sup-
port Agreement
10.72 Second Amendment to Form 10-K, 1988, Exhibit 10(r)
Phase II Boston Edison
AC Facilities Support
Agreement
10.73 Third Amendment to Form 10-K, 1988, Exhibit 10(s)
Phase II Boston Edison
AC Facilities Support
Agreement
10.74 Fourth Amendment to Form 10-K, 1988, Exhibit 10(t)
Phase II Boston Edison
AC Facilities Support
Agreement
10.75 Fifth Amendment to Form 10-K, 1988, Exhibit 10(u)
Phase II Boston Edison
AC Facilities Support
Agreement
10.76 Letter of Assurances, Form 10-K, 1988, Exhibit 10(v)
Consents and Agreements
With Respect to Credit
Facility Financing for
Phase II Hydro-Quebec
Financing
10.77 401 (k) Plan for Non- Form 10-K, 1988, Exhibit 10(x)
Union Employees
10.78 Agreement for the Form S-2, Reg. No. 33-39181,
Purchase and Sale of Exhibit 10.82
Electricity dated as of
June 21, 1984 between
Penobscot Energy Recovery
Company and the Company
10.79 Amendment No. 1 as of Form S-2, Reg. No. 33-39181,
March 24, 1986 to the Exhibit 10.83
Agreement for the Purchase
and Sale of Electricity
dated as of June 21, 1984
between Penobscot Energy
Recovery Company and the
Company
10.80 Partnership Agreement Form S-2, Reg. No. 33-39181,
dated as of July 1, 1990 Exhibit 10.85
between NORVARCO and
Bangor Var Co., Inc.
10.81 Purchase Agreement between Form 10-Q, 3rd Quarter 1995,
Babcock-Ultrapower Exhibit 10.1
Jonseboro and Bangor Hydro-
Electric Company
10.82 Purchase Agreement between Form 10-Q, 3rd Quarter 1995,
Babcock-Ultrapower West Exhibit 10.2
Enfield and Bangor Hydro-
Electric Company
10.83 ASSIGNMENT OF CONTRACTS Form 10-Q, 1st Quarter 1998,
AND ENTITLEMENTS, made March Exhibit 10(a)
31, 1998 by and between Bangor
Hydro-Electric Company and
Bangor Energy Resale, Inc.
10.84 Rate Agreement made October 30, Form 10-Q, 1st Quarter 1998,
1997, by and between Bangor Exhibit 10(b)
Hydro-Electric Company and
Bangor Energy Resale, Inc.
10.85 Management and Support Services Form 10-Q, 1st Quarter 1998,
Agreement made March 31, 1998 Exhibit 10(c)
by and between Bangor Hydro-
Electric Company and Bangor
Energy Resale, Inc.
10.86 Surplus Cash Agreement Form 10-Q, 2nd Quarter 1998,
dated as of June 26, 1998 Exhibit 10(a)
among the Company,
Penobscot Energy Recovery
Company Limited
Partnership and the
Municipal Review
Committee, Inc.
10.87 Guaranty Agreement dated Form 10-Q, 2nd Quarter 1998,
as of June 1, 1998 Exhibit 10(b)
between the Company and
The Chase Manhattan Bank
10.88 Amendment No. 2 to Form 10-Q, 2nd Quarter 1998,
Purchase Power Agreement Exhibit 10(c)
dated as of June 26, 1998
between the Company and
Penobscot Energy Recovery
Company Limited
Partnership
10.89 Amended and Restated Form 10-Q, 2nd Quarter 1998,
Revolving Credit And Exhibit 10(d)
Term Loan Agreement
dated as of June 19, 1998
between the Company and
BankBoston, N.A. and Fleet
National Bank
10.90 Asset Purchase Agreement Form 8-K, September 25, 1998
dated as of September 25, Exhibit 2
1998 between Bangor Hydro-
Electric Company and PP&L
Global, Inc. (schedules and
exhibits omitted).
10.91 Asset Purchase Implementation Form 10-K, 2000, Exhibit 10(a)
Agreement, dated as of May 27,
1999, by and among Bangor Hydro-
Electric Company, Penobscot Hydro
Co., Inc. and Penobscot Hydro, LLC
10.92 33rd Amendment to the NEPOOL Form 10-K, 2000, Exhibit 10(b)
Agreement dated December 1, 1996
10.93 Form of Agreement with Form 10-K, 2000, Exhibit 10(c)
certain Executive Officers
providing benefits upon
a change of control
10.94 Form of Agreement with Form 10-K, 2000, Exhibit 10(d)
certain Executive Officers
providing supplemental
death and retirement benefits
10.95 Agreement and Plan of Merger by Form 8-K, June 29, 2000,
and Among Bangor Hydro-Electric Exhibit 2.1
Company and NS Power Holdings
Incorporated dated as of
June 29, 2000
10.96 Amendment No. 1 to Agreement Form 8-K, October 10, 2001,
and Plan of Merger dated as of Exhibit 2.2
August 28, 2001 by an Among
the Company and Emera, Inc.