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, 2002 Commission File No. 1-10922
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BANGOR HYDRO-ELECTRIC COMPANY
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(Exact Name of Registrant as specified in its charter)
MAINE 01-0024370
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(State of Incorporation) (I.R.S. Employer ID No.)
33 State Street, Bangor, Maine 04401
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(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code 207-945-5621
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Securities registered pursuant to Section 12(g) of the Act:
Title of each class
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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 February 1, 2003 of the voting stock held by
non-affiliates of the registrant was $5.284 million.
This Page Intentionally Left Blank
BANGOR HYDRO-ELECTRIC COMPANY
TABLE OF CONTENTS
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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
PART II
Item 5. Market for Registrant's Common Equity and Related
Stockholder Matters 6
Item 6. Selected Financial Data 8
Item 7. Management's Discussion and Analysis of Results of
Operations and Financial Condition 10
Item 7A. Quantitative and Qualitative Disclosures About
Market Risk 26
Item 8. Financial Statements and Supplementary Data 27
Consolidated Statements of Income 27
Consolidated Balance Sheets 28
Consolidated Statements of Capitalization 30
Consolidated Statements of Cash Flows 31
Consolidated Statements of Common Stock Investment 32
Notes to Consolidated to Financial Statements 33
Report of Independent Accountants 60
Item 9. Changes in and Disagreements with Independent
Accountants on Accounting and Financial Disclosure 61
PART III
Item 10. Directors and Executive Officers of the Registrant 62
Item 11. Executive Compensation 64
Item 12. Security Ownership of Certain Beneficial Owners and
Management 69
Item 13. Certain Relationships and Related Transactions 70
Item 14. Controls and Procedures 71
PART IV
Item 15. Exhibits, Financial Statement Schedule, and Reports
on Form 8-K 71
Signatures 73
Principal Executive Officer's and Chief Financial Officer's
Certifications 74
Schedule II - Valuation and Qualifying Accounts and Reserves 77
Exhibits Delivered with this Report 78
Exhibits Incorporated Herein by Reference 79
PART I
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Item 1 Business
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(a) General development of business
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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, 2002, 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" and Item 8,
"Notes to Consolidated Financial Statements - Note 10 - 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
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The Company is a public utility primarily engaged in the transmission and
distribution of electric energy, with a service area of approximately
5,275 square miles having a population of approximately 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
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(v) Seasonal business
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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
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(viii) Backlog of orders - Not applicable
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(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
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(xii) Environmental matters
---------------------
See Item 7, "Management's Discussion and Analysis of Results of Operations
and Financial Condition - Other Matters - Environmental Matters" and Item 8,
"Notes to Consolidated Financial Statements - Note 13 - Contingencies" for a
discussion of Environmental Matters.
(xiii) Number of employees
-------------------
As of December 31, 2002, the Company had 313 full time employees.
(d) Financial information about geographical areas - Not applicable
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Item 2 Properties
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The Company owns approximately 550 miles of transmission lines and
approximately 4,200 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." See also
Item 7, "Management's Discussion and Analysis of Results of Operations and
Financial Condition - Other Matters - Environmental Matters " and Item 8,
"Notes to Consolidated Financial Statements - Note 13 - 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 - Not
- ------ ---------------------------------------------------
applicable.
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 Balance Sheets,
Consolidated Statements of Capitalization, Consolidated Statements of Cash
Flows; and Consolidated Statement of Common Stock Investment.
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BANGOR HYDRO-ELECTRIC COMPANY
Item 6
Selected Financial Data
Six-Year Statistical Summary
(Unaudited)
2002 2001 2000 1999 1998 1997
Megawatt Hours (MWH) Generated And Purchased
Hydro Generation *** 84,436 65,392 90,719 205,265 275,379 262,377
Oil (Company) 868 2,435 3,142 69,026 96,476 69,580
Biomass/Refuse (Purchased) 154,832 150,401 152,060 137,384 156,051 159,990
NEPOOL/Other Purchases 2,333,428 1,782,797 1,914,615 1,629,643 1,522,125 1,583,093
--------- --------- --------- --------- --------- ---------
Total Generated & Purchased 2,573,564 2,001,025 2,160,536 2,041,318 2,050,031 2,075,040
Less Line Losses and Company Use 128,282 130,067 140,470 143,198 139,028 147,298
--------- --------- --------- --------- --------- ---------
Remainder-MWH sold 2,445,282 1,870,958 2,020,066 1,898,120 1,911,003 1,927,742
========= ========= ========= ========= ========= =========
Classification of Sales-MWH
Residential 556,462 546,144 558,596 533,566 522,836 533,161
Commercial 571,372 583,829 570,963 545,087 524,292 515,904
Industrial 449,170 462,792 604,959 667,059 662,382 687,365
Lighting 8,719 8,742 8,859 8,911 8,901 8,780
Wholesale 2,925 2,676 2,799 2,716 2,704 3,841
---------- ---------- ---------- ---------- ---------- ----------
Total MWH Billed to Customers 1,588,648 1,604,183 1,746,176 1,757,339 1,721,115 1,749,051
Unbilled Sales-Net Increase 13,071 4,343 2,629 11,772 1,040 33,011
---------- ---------- ---------- ---------- ---------- ----------
Total Delivered Sales (MWH) 1,601,719 1,608,526 1,748,805 1,769,111 1,722,155 1,782,062
(Less) Interruptible Sales 55,235 22,305 178,943 230,378 248,091 265,438
---------- ---------- ---------- ---------- ---------- ----------
Total Firm Delivered Sales (MWH) 1,546,484 1,586,221 1,569,862 1,538,733 1,474,064 1,516,624
Off-System Sales 843,563 262,432 271,261 129,009 188,848 145,680
---------- ---------- ---------- ---------- ---------- ----------
Total Energy Sales (MWH) 2,445,282 1,870,958 2,020,066 1,898,120 1,911,003 1,927,742
========== ========== ========== ========== ========== ==========
Electric Operating Revenues and Expenses (000's)
Electric Operating Revenues
Residential $ 52,219 $ 50,264 $ 57,746 $ 73,304 $ 71,396 $ 67,532
Commercial 39,645 37,795 44,329 63,093 60,191 55,391
Industrial 15,879 15,516 23,749 43,560 42,645 41,930
Lighting 1,888 1,837 1,929 2,268 2,207 2,065
Wholesale 18 19 63 220 235 310
------------ ------------ ------------ ------------ ------------ ------------
Total Revenue from Customers $ 109,649 $ 105,431 $ 127,816 $ 182,445 $ 176,674 $ 167,228
Standard Offer Service Revenue 12,196 84,589 66,134 - - -
------------ ------------ ------------ ------------ ------------ ------------
Total Operating Revenue $ 121,845 $ 190,020 $ 193,950 $ 182,445 $ 176,674 $ 167,228
Unbilled Sales-Net Increase (Decrease) 1,245 815 (5,014) 2,042 481 2,375
------------ ------------ ------------ ------------ ------------ ------------
Total Revenue $ 123,090 $ 190,835 $ 188,936 $ 184,487 $ 177,155 $ 169,603
(Less) Interruptible Revenue 963 1,687 4,973 10,049 11,064 11,215
------------ ------------ ------------ ------------ ------------ ------------
Total Firm Revenue $ 122,127 $ 189,148 $ 183,963 $ 174,438 $ 166,091 $ 158,388
Off-System Revenue 39,712 18,952 19,352 12,947 14,630 13,615
------------ ------------ ------------ ------------ ------------ ------------
Total Electric Operating Revenues $ 162,802 $ 209,787 $ 208,288 $ 197,434 $ 191,785 $ 183,218
============ ============ ============ ============ ============ ============
Operating Expenses
Fuel for Generation and Purchased Power $ 61,670 $ 34,649 $ 44,509 $ 80,748 $ 82,027 $ 92,792
Standard Offer Service Purchased Power 11,508 82,839 65,553 - - -
Operating and Maintenance Expense 34,573 36,800 35,311 36,492 34,448 32,471
Depreciation and Amortization 24,537 27,751 28,312 30,565 31,891 35,104
Taxes 11,413 11,752 12,228 14,032 11,642 3,168
------------ ------------ ------------ ------------ ------------ ------------
Total Operating Expenses $ 143,701 $ 193,791 $ 185,913 $ 161,837 $ 160,008 $ 163,535
============ ============ ============ ============ ============ ============
Summary of Operations (000's)
Operating Revenue $ 167,738 $ 217,408 $ 212,338 $ 197,994 $ 195,144 $ 187,324
Operating Expenses 143,701 193,791 185,913 161,837 160,008 163,535
Other Income (Loss) (including equity AFDC) 1,303 (654) 613 2,806 1,292 1,292
Interest Expense (net of borrowed AFDC) 12,879 14,273 15,936 20,683 24,963 25,467
------------ ------------ ------------ ------------ ------------ ------------
Net Income (Loss) $ 12,461 $ 8,690 $ 11,102 $ 18,280 $ 11,465 $ (386)
Less Preferred Dividends 266 266 266 945 1,244 1,376
------------ ------------ ------------ ------------ ------------ ------------
Earnings (Loss) on Common Stock $ 12,195 $ 8,424 $ 10,836 $ 17,335 $ 10,221 $ (1,762)
============ ============ ============ ============ ============ ============
BANGOR HYDRO-ELECTRIC COMPANY
Item 6
Selected Financial Data
Six-Year Statistical Summary
(Unaudited)
2002 2001 2000 1999 1998 1997
Selected Financial Data
Total Assets (000's) $ 640,731 $ 678,245 $ 532,220 $ 543,950 $ 605,688 $ 600,583
============ =========== ============ ============ ============ ============
Electric Plant (000's)
Total Electric Plant $ 344,382 $ 341,143 $ 327,247 $ 318,435 $ 372,782 $ 358,878
Depreciation Reserve 97,473 93,985 86,684 84,825 101,633 96,595
------------ ------------ ------------ ------------ ------------ ------------
Net Electric Plant $ 246,909 $ 247,158 $ 240,563 $ 233,610 $ 271,149 $ 262,283
============ ============ ============ ============ ============ ============
Capitalization (000's)
Short-Term Debt $ 16,000 $ 8,000 $ - $ - $ 12,000 $ 34,000
Long-Term Debt 118,059 131,968 161,960 183,300 263,028 221,643
Redeemable Preferred Stock - - - - 7,604 9,137
Preferred Stock 4,734 4,734 4,734 4,734 4,734 4,734
Common Equity 206,266 205,557 137,420 132,722 118,864 106,558
------------ ---------- ------------ ------------ ------------ ------------
Total $ 345,059 $ 350,259 $ 304,114 $ 320,756 $ 406,230 $ 376,072
============ ============ ============ ============ ============ ============
Capital Structure Ratios (%)
Short-Term Debt 4.6 % 2.3 % - % - % 3.0 % 9.1 %
Long-Term Debt 34.2 % 37.7 % 53.2 % 57.1 % 64.7 % 58.9 %
Preferred Stock 1.4 % 1.3 % 1.6 % 1.5 % 3.0 % 3.7 %
Common Stock 59.8 % 58.7 % 45.2 % 41.4 % 29.3 % 28.3 %
------------ ------------ ------------ ------------ ------------ ------------
Total 100.0 % 100.0 % 100.0 % 100.0 % 100.0 % 100.0 %
============= ============ ============ =========== ============ ============
Miscellaneous Statistics
Shares Outstanding (Average) 7,363,424 7,363,424 7,363,424 7,363,424 7,363,424 7,363,424
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 1 6,222 5,678 6,328 6,868
Basic Earnings (Loss) Per Common Share $ 1.66 $ 1.14 $ 1.47 $ 2.35 $ 1.39 $ (0.24)
Diluted Earnings (Loss) Per Common Share $ 1.66 $ 1.08 $ 1.30 $ 2.08 $ 1.33 $ (0.24)
Dividends Declared Per Common Share $ 1.29 $ 0.60 $ 0.80 $ 0.45 $ - $ -
Book Value Per Common Share $ 17.65 $ 17.26 $ 18.66 $ 18.02 $ 16.14 $ 14.47
Return on Common Equity 9.46 % 6.30 % 7.98 % 13.81 % 9.11 % (1.64)%
Ratio of AFDC to Common Stock Earnings 8 % 14 % 3 % (4)% 11 % (48)%
Ratio of Earnings to Fixed Charges 2.35 % 1.89 % 2.11 % 2.25 % 1.59 % 0.86 %
Payout Ratio 78 % 53 % 54 % 26 % - % - %
Percentage of Construction Expenditures
Funded Internally 100 % 100 % 100 % 100 % 100 % 100 %
============ ============ ============ ============ ============ ============
Residential Customer Data
Average Number of Customers 94,510 93,398 92,656 91,726 90,888 90,433
Kilowatt-Hours per Customer 5,888 5,847 6,029 5,817 5,753 5,896
Revenue per Customer $ 552.52 $ 538.17 $ 623.23 $ 799.16 $ 785.54 $ 746.76
Revenue per Kilowatt-Hour in Cents 9.38 9.20 10.34 13.74 13.65 12.67
============= ============= ============= ============= ============= =============
Miscellaneous System Data
Net System Capability at Time of Peak
(MW) Firm* n/a 182.23 98.98 273.72 381.54 344.44
System Peak Demand (MW) 290.26 290.37 304.71 293.08 281.63 277.06
Reserve Margin at Time of Peak** n/a % (37.2)% (67.5)% (6.6)% 35.5 % 24.3 %
System Load Factor 68.0 % 68.4 % 70.8 % 74.5 % 75.4 % 79.5 %
============ ============ ============ ============ ============ ============
* The net system capability was reduced subsequent to the generation asset sale, which occurred in May 1999. As of
2002, BHE no longer provides generation capability to serve load.
** While the reserve margin at time of peak in 2001, 2000 and 1999 was negative, the system requirements were met
through spot market purchases. As of 2002,BHE no longer provides generation capability to serve load.
*** Subsequent to the generation asset sale in May 1999, Hydro generation was purchased.
ITEM 7
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL
CONDITION
Recent Events Affecting the Company
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REGULATORY PROCEEDINGS AND CORPORATE REORGANIZATION - As reported in
the 2001 Form 10-K, on February 14, 2002, the Company presented to the
Maine Public Utilities Commission (MPUC) a proposed resolution of the
ongoing Alternative Rate Plan (ARP) proceeding that called for a multi-
year freeze in the distribution portion of the Company's rates. The ARP
proceeding, as well as proposed proceedings to implement a general
increase in the Company's distribution rates and to initiate a
management investigation of the Company, were suspended to provide the
Company and interested parties additional time to negotiate a potential
settlement of these interrelated proceedings. On April 25, 2002, the
Company and other parties to the proceeding executed a stipulation to
present to the MPUC a single comprehensive ARP applying to the
Company's MPUC jurisdictional distribution revenue requirement and
rates. On June 6, 2002, the MPUC approved the ARP and also dismissed
the pending management investigation of the Company.
The terms of the ARP include a rate plan to be in effect through
December 31, 2007, with the Company's core distribution rates being
adjusted downward on July 1 of each year from 2003 to 2007, at annual
rates ranging from 2% to 2 3/4%. The Company is also allowed rate
adjustments associated with certain specified categories of costs. The
ARP also includes a mechanism whereby distribution returns on common
equity outside of a certain range will be shared evenly between the
Company and ratepayers. The Company is also required to meet certain
customer service quality standards during the term of the ARP, and rate
reduction penalties will result from not meeting the various
performance measures as set forth in the stipulation. Finally, the ARP
provides the Company with an accounting order allowing for the deferral
of employee transition costs during 2002 and 2003 in connection with
reductions in operating costs, which are discussed below. These
deferred costs are being amortized over a ten year period, starting in
June 2002.
Successful implementation of the ARP necessitated a significant
decrease in the Company's operating costs, and as a result, the Company
reorganized its operations in 2002. The internal restructuring, which
encompasses all aspects of the Company, has reduced operating costs by
approximately 20%-25%. The Company is also beginning to transfer a
portion of its fixed costs to variable costs, and improve processes to
enhance long-term performance. As part of the restructuring,
employment levels were reduced by approximately 25% in the second and
third quarters of 2002 through early retirement and severance
arrangements. Also in connection with the reorganization, the Company
has adopted an Asset Management Model in order to improve efficiency
and performance as well as lowering its operating costs. This model
puts the principal of market based solutions into practice. The total
employee transition costs incurred in 2002 were approximately $8.1
million and are recorded as a component of Other Regulatory Assets on
the consolidated balance sheets at December 31, 2002.
In February 2002, the MPUC issued an Order in connection with changes
in the Company's stranded cost rates. As a result of the Order, and to
recover the stranded costs created as a result of the restructuring of
the electric utility industry in the State of Maine, the Company's
stranded cost rates were increased effective March 1, 2002. The
stranded cost rate increase resulted in the Company's total electric
rates increasing by approximately 6.5%. The stranded cost rates are
set for a period not to exceed three years, although the Company has
the right to seek adjustments to these rates if certain economic
situations occur.
Also effective March 1, 2002, the Company is no longer responsible for
being the standard-offer service provider. The Company, though, still
has a standard-offer related power supply commitment with a third party
through February 2004 amounting to approximately $57 million. The
power delivered under this contract is being resold to one of the new
standard-offer service providers, with estimated revenues to be
realized of approximately $40 million. The difference between the cost
of the power and the resale revenues are being recovered in the
Company's stranded cost rates starting March 1, 2002. As a result of
the Company no longer being the standard-offer provider effective in
March 2002, and the previously discussed power contract obligation,
there is an impact on the comparability of revenues and expenses for
the 2002 periods presented in this filing in relation to 2001.
REDEMPTION OF PREFERRED STOCK - As reported in its Current Report on
Form 8-K dated December 9, 2002, the Company requested MPUC approval
for authority to redeem all or a portion of its outstanding preferred
stock. This approval was received on December 23, 2002. Also as
reported in its Current Report on Form 8-K dated December 9, 2002, the
Company was in the process of acquiring all or a portion of the shares
through a tender offer and a call of the shares. In the first quarter
of 2003 the Company completed the redemption of a significant portion
of its outstanding preferred stock, at a total cost of approximately
$4.7 million. As a result of these redemption's, the Company will now
seek de-registration of its preferred stock.
Results of Operations
- ---------------------
EARNINGS - Basic earnings per common share were $1.66, $1.14, and
$1.47, for the years ended 2002, 2001 and 2000, respectively. The
earned return on average common equity was 9.5% in 2002, 6.3% in 2001
and 8% in 2000.
The increase in earnings in 2002 in relation to 2001 was a result of
many factors. The single largest item was the approximately $3.9
million in costs incurred in 2001 associated with the Company's merger
with Emera ($.33 reduction in earnings per common share in 2001).
Also, principally as a result of the Company's workforce reductions in
2002, labor expense was approximately $1.9 million lower in 2002 as
compared to 2001 ($.15 increase in earnings per common share in 2002 as
compared to 2001). 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 in 2001).
Offsetting these year 2002 earnings enhancements to some extent was an
approximately $961,000 increase in pension and other postretirement
benefit costs in 2002 as compared to 2001 ($.08 reduction in earnings
per common share in 2002).
The reduction in earnings in 2001 as compared to 2000 was due to
several factors, the largest of which being costs associated with the
Company's merger with Emera in each year. In 2001, the Company incurred
approximately $3.9 million ($.33 reduction in earnings per common
share) of such costs as compared to $3 million in 2000 ($.24 reduction
in earnings per common share). Also, as previously discussed, in 2001,
the Company charged to expense approximately $1.7 million ($.13
reduction in earnings per common share) in connection with the stranded
cost rate filing settlement. 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).
REVENUES - With the implementation of competition in the electric
utility industry in the state of Maine starting March 1, 2000, and
excluding the provision of standard-offer service through February
2002, the Company no longer sells electricity to customers. The
Company's T&D and stranded cost charges to customers, though, continue
to be based on customers' electricity usage measured in kilowatt-hours
(kWh). Consequently, discussion related to electric operating revenues
will continue to have a kWh sales, or hereafter referred to as "energy
sales" component.
Electric operating revenues are as follows for 2002 as compared to
2001:
2002 2001 Change
Residential $ 53,460,057 $ 51,011,678 $2,448,379
Commercial 39,990,493 37,908,435 2,082,058
Industrial 10,335,054 9,895,889 439,165
Other 1,945,380 1,875,277 70,103
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Subtotal $105,730,984 $100,691,279 $5,039,705
Large Special Contracts 5,163,127 5,554,793 -391,666
----------------------------------------
Total Related to Energy Sales $110,894,111 $106,246,072 $4,648,039
Other Miscellaneous Revenues 4,935,070 7,620,164 -2,685,094
----------------------------------------
Total Electric Operating Revenue $115,829,181 $113,866,236 $1,962,945
----------------------------------------
Energy sales volume in gigawatt hours is as follows for each of 2002
and 2001:
2002 2001 Change
Residential 566.6 554.1 12.5
Commercial 583.5 584.9 -1.4
Industrial 196.5 206.1 -9.6
Other 11.9 11.5 .4
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Subtotal 1,358.5 1,356.6 1.9
Large Special Contracts 243.2 251.9 -8.7
----------------------------------------
Total Energy Sales 1,601.7 1,608.5 -6.8
----------------------------------------
Electric operating revenue increased by approximately $2 million in
2002 as compared to 2001. The increase was principally the result of
the previously discussed 6.54% rate increase associated with stranded
cost recovery. Also impacting the increased revenues somewhat in 2002
was a .14% increase in energy sales, which excludes certain large
special contract customers.
Other miscellaneous revenues were lower in 2002 as a result of a $1.8
million reduction in certain stranded cost related revenue deferrals.
The decrease is due to the implementation of new stranded
cost rates on March 1, 2002, as well as the impact of the previously
discussed loss in 2001 associated with the settlement of the stranded
cost rate filing. Also, other revenues associated with charging
electric generators for wheeling power over the Company's transmission
lines and out of its service territory were approximately $2.1 million
lower in 2002 compared to 2001. The decrease is due primarily to the
fact that the new standard offer service provider is purchasing power
from the Company to resell to standard offer customers in the Company's
service territory that, prior to March 1, 2002, was wheeled outside of
the service territory.
Off-system sales, which are sales related to power pool and inter-
connection agreements and resales of purchased power, were
approximately $20.8 million greater in 2002 in relation to 2001. The
increase is due principally to the previously discussed resale of power
associated with the former standard-offer power supply contract.
The $72.4 million decrease in standard-offer service revenues in 2002
is due mostly to the Company no longer being the standard-offer
provider effective March 1, 2002.
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 $5.1 million, or 2.4%, 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 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.
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 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,
excluding the standard offer, increased approximately $27 million in
2002 as compared to 2001. The largest item affecting the increased
expense was approximately $29.8 million of costs in 2002 associated
with the previously discussed former standard-offer power contract
obligation. Also, the Company incurred approximately $1.8 million in
greater expense in 2002 associated with other power purchases under
long-term contracts with small power production facilities, resulting
from increased generation in 2002. Offsetting these increases somewhat
was an approximately $1.3 million decrease in Maine Yankee costs in
2002. Also there was a $1.2 million decrease in purchased power costs
in 2002 in connection with serving a portion of a power sale contract.
This reduction was due to decreases in the market prices of power in
2002 as compared to 2001. Finally, effective July 1, 2001, and running
through February 28, 2002, 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
entered into a power purchase contract to procure the power necessary
to serve this customer under this contact. In the 2001 period the
Company incurred approximately $1.5 million in greater purchased power
costs associated with serving the customer as compared to the 2002
period.
The $71.3 million decrease in standard-offer service purchased power
expense in 2002 is due mostly to the Company no longer being the
standard-offer provider effective March 1, 2002.
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 loss in connection
with the stranded cost rate settlement. 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.
Other operation and maintenance (O&M) expense decreased by
approximately $2.2 million in 2002 as compared to 2001. Principally as
a result of the workforce reductions in 2002, O&M payroll
expense was approximately $1.9 million lower in 2002 relative to 2001.
Also, as a result of cost reduction efforts in 2002, other O&M non-
labor expenses were generally lower as compared to 2001. Due
principally to a refocus of the Company's line clearance program (tree
trimming) in 2002, the associated expense was approximately $864,000
lower in 2002 as compared to 2001. These decreases in other O&M
expense were offset somewhat by the previously discussed $961,000
increase in pension and other postretirement benefit costs in 2002 as
compared to 2001. The increased expense is principally attributable to
decreases in the discount rate used to actuarially compute the expense
as well as reduced expected returns on plan assets as a result of poor
stock market performance.
Other O&M expense increased by approximately $1.5 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.
Depreciation and amortization expense increased by approximately
$525,000 in 2002 relative to 2001 and by approximately $866,000 in 2001
as compared to 2000 due principally to additions to the Company's
electric plant in service in both 2002 and 2001. The Company is in
the process of conducting a depreciation study to determine the
appropriate useful lives for its plant assets as well as the propriety
of the level of the Company's depreciation reserve, with an anticipated
completion in 2003. Management cannot predict the results of the study
or how the results will be implemented within the context of the
Company's ARP.
The Company's expenses over the period 2000-2002 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 include
the amortization of purchased power contract buyouts/restructurings,
Seabrook investment, deferred asset sale gain, and deferred employee
transition costs. For a discussion of these regulatory assets and
liabilities, see Notes 7 and 10 to the consolidated financial
statements. Effective March 1, 2000, in connection with the
implementation of new electric rates associated with the electric
utility industry restructuring, the Company began amortizing certain
stranded cost related regulatory assets and liabilities that had been
previously deferred on the Company's balance sheets. Also, effective
March 1, 2002, with the implementation of new stranded cost electric
rates, certain of the previous amortizations were adjusted, and also
the Company began amortizing new stranded cost related regulatory
assets and liabilities that had been previously deferred on the
Company's balance sheets since March 1, 2000. The following
summarizes the components of the regulatory amortizations for 2002,
2001 and 2000:
2002 2001 2000
Contract buyouts and restructuring $20,274,191 $22,557,124 $22,311,448
Seabrook investment 1,699,050 1,699,050 1,699,050
Deferred asset sale gain (4,681,324) (8,076,133) (6,393,038)
Other stranded cost related regulatory
assets and liabilities (4,921,047) 386,908 382,295
Distribution related regulatory assets
and liabilities 1,159,530 1,159,530 1,153,687
Employee transition costs 458,021 - -
-------------------------------------
Total Regulatory Amortizations $13,988,421 $17,726,479 $19,153,442
-------------------------------------
The decrease in property and other taxes in 2002 in comparison to 2001
was principally due to a reduction in payroll taxes, resulting from the
previously discussed corporate downsizing in 2002. This was offset
somewhat by increased property taxes in 2002 caused by increases to
electric plant in service and higher property tax rates. In December
2002, the Company filed with the Internal Revenue Service (IRS) a
request for a change in the accounting for costs capitalized for income
tax reporting purposes. This request, if accepted, could result in an
approximately $6.7 million reduction in current income tax obligations.
Management cannot predict the outcome of this filing with the IRS.
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 total federal and state income taxes in 2002 relative
to 2001 was principally a function of the impact of $183,000 in
additional income tax expense in 2001 in connection with disallowed
investment tax credits, as well as adjustments in 2002 as a result of
filing the year 2001 income tax returns. These decreases were offset
by higher earnings in 2002. See Footnote 3 to the Consolidated
Financial Statements for a reconciliation of the Company's effective
income tax rate.
The decrease in total federal and state income taxes for 2001 as
compared to 2000 was principally a function of lower earnings in 2001
as compared to 2000.
OTHER INCOME AND (DEDUCTIONS) AND INTEREST EXPENSE - Allowance for
funds used during construction (AFDC), which includes carrying costs on
certain regulatory assets and liabilities, decreased by approximately
$219,000 in 2002 relative to 2001. The decrease was primarily a result
of the implementation of new stranded cost rates on March 1, 2002,
whereby the rate recovery of various regulatory assets began and the
accrual of carrying costs ended.
AFDC increased by $835,000 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 Penobscot Energy Recover Company (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.
Other income, net of income taxes increased by approximately $2.1
million in 2002 compared to 2001. The increase is due mostly to the
previously discussed $3.9 million in merger related costs incurred in
2001.
Other income, net of income taxes decreased by approximately $1.7
million in 2001 in comparison to 2000 principally as a result of a $1.2
million gain on the sale of the Company's formerly wholly-owned
subsidiary Penobscot Gas in 2000. Also merger related costs were $3.9
million in 2001 as compared to $3 million in 2000. Finally, investment
income was lower in 2001 due principally to reductions in the Company's
available cash balances from the 1999 generation asset sale.
Long-term debt interest expense decreased $1.7 million in 2002 relative
to 2001 due principally to repayments on the Company's long-term debt
in each year. In June 2002 and 2001, the Company made $16.1 million
and $15.1 million in principal payments, respectively, on the Company's
Finance Authority of Maine (FAME) Revenue Notes. Also, monthly
principal payments on the $24.8 million medium term notes, which were
fully repaid in July 2002, amounted to approximately $5.5 million and
$6.2 million, respectively, in 2002 and 2001. Also reducing 2002 long-
term debt interest expense was the retirement of the $20 million in
7.38% first mortgage bonds at the end of July 2002. These decreases
were offset to some extent by additional interest expense in 2002
resulting from the issuance of a $13.7 million note in October 2001
with the Municipal Review Committee (MRC) in connection with the
exercise of common stock warrants.
Long-term debt interest expense decreased $1.4 million in 2001 in
relation to 2000 due primarily to the 2001 repayments on the Company's
long-term debt discussed above, as well as debt repayments in 2001. In
June 2000, the Company made a $14 million principal payment on the FAME
Revenue Notes. Also, monthly principal payments on the $24.8 million
medium term notes amounted approximately $5.5 million in 2000. These
were offset to some extent by interest expense in 2001 associated with
the $13.7 million MRC note issued in October 2001.
Other interest expense increased approximately $170,000 in 2002
relative to 2001 principally to higher interest expense as a result of
increased borrowings under the Company's revolving credit facility.
Weighted average borrowings outstanding were approximately $21.8
million in 2002 as compared to $3 million in 2001. The increased
borrowings were necessitated to some extent by the funding of debt
service payments ($16.1 million in principal plus interest) on the FAME
Revenue Notes at the end of June 2002 and the retirement of $20 million
in 7.38% first mortgage bonds in July 2002. Also, other interest
expense was impacted somewhat by a $125,000 reduction in amortization
of debt issuance costs in 2002 due to the expiration of certain
amortizations and lower short-term interest rates in 2002.
Other interest expense increased by approximately $116,000 in 2001 in
relation to 2000 due principally to borrowings and fees under the
Company's revolving credit facility. 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.
Liquidity, Capital Requirements, and Capital Resources
- ------------------------------------------------------
The Consolidated Statements of Cash Flows reflect events for the years
ended December 2002, 2001 and 2000 as they affect the Company's
liquidity. Net cash provided by operations was approximately $33.9
million in 2002, $25.3 million in 2001 and $37.6 million in 2000.
The approximately $8.6 million increase in operating cash flows in 2002
relative to 2001 was due to several factors. The single largest item
affecting the comparability of operating cash flows in the two years
was approximately $14.2 million in payments in 2001 in connection with
the exercise of the Company's common stock warrants (See Note 7 to the
Consolidated Financial Statements). Also increasing operating cash
flows in 2002 as compared to 2001 was the impact of the approximately
$3.9 million in incremental merger related costs that were incurred in
2001. Operating cash flows are also impacted in each period by the
standard-offer service. In 2002, the Company's standard-offer service
costs exceeded revenues by approximately $2.1 million, while in 2001,
revenues exceeded associated costs by approximately $8.8 million.
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. Negatively impacting
operating cash flows in 2002 was $3.5 million in payments associated
with benefits provided to terminated employees in connection with the
previously discussed cost reduction efforts.
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. 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. 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. Also cash flows were
negatively impacted by a $.008/kWh rate reduction provided to certain
large customers starting in April 2001. While the earnings impact of
the rate discounts is 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 were in effect.
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 10 to the Consolidated Financial Statements for
a discussion of this transaction.
The following summarizes the Company's capital expenditures for each of
2002, 2001 and 2000:
($000's) 2002 2001 2000
Electric distribution system $ 7,916 $ 9,513 $ 8,188
Electric transmission system 1,415 1,590 4,184
Other, including general
property and software 763 5,245 4,309
--------------------------------
Total capital expenditures $10,094 $16,348 $16,681
--------------------------------
Other capital expenditures in 2001 and 2000 included significant
amounts in connection with customer information system changes
necessitated by the restructuring of the electric industry on March 1,
2000. The Company expects its capital expenditures to total between
$35 and $40 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.
In 2002, the Company made $9.5 million in common dividend payments to
its parent company, Emera, while in 2001, four quarterly common
dividend payments of $.20 per share were paid to previous common
shareholders. 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 payments on long-term debt in 2002 was due principally
to higher monthly principal payments on the $24.8 million medium term
notes in 2002 as compared to 2001, and at the end of June 2002 the
Company made a $16.1 million principal payment on the FAME revenue
notes, as compared to a $15.1 million principal payment at the end of
June 2001. Also, in July 2002 the Company retired $20 million of 7.38%
first mortgage bonds. Finally, the Company made approximately $1.5
million of principal payments in 2002 on the $13.7 million MRC note as
compared to approximately $433,000 in payments in 2001.
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 FAME Revenue Notes and $5.5 million in payments on the $24.8
million medium term notes.
In connection with the final principal and interest payment on the
$24.8 million medium term notes in 2002, the Company utilized $1.5
million of funds that had been maintained in a capital reserve fund
since this debt had been issued in 1998.
As discussed in Note 5 to the consolidated financial statements, in
December 2002, the Company received $20 million in proceeds in
connection with the issuance of 6.09% senior unsecured notes.
The proceeds were utilized to paydown outstanding amounts under the
Company's revolving credit facility.
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 $15.1 million. The
Company's utilization of the line of credit was also impacted by the
merger costs in 2001 and the cash payments to common stock warrant
holders. 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 and then until March 31, 2002, and the agreement was
further extended until June 30, 2003 with some modifications. The
facility was increased to $60 million to accommodate the certain debt
retirements in 2002, another pricing level was added to recognize the
Company's improved credit and certain modifications were made to some of
the financial covenants. 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. The Company's
outstanding borrowings under these short-term borrowing facilities
amounted to $16 million at December 31, 2002.
Capital and operating needs in 2002, 2001 and 2000 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 or other longer-term financing vehicles.
The Company has approximately $81.2 million of first mortgage bonds and
other long-term debt maturities in the period 2003-2007.
CONTRACTUAL CASH OBLIGATIONS AND OTHER COMMERCIAL COMMITMENTS - The
following tables quantify the Company's future contractual obligations
and commercial commitments as of December 31, 2002 ($ in 000's):
Payments Due by Period
----------------------
Less than After 5
Contractual Obligations: Total 1Year 1-3 years 4-5 years years
- ----------------------- ----- ----- --------- --------- -----
Long-term Debt $152,196 $34,137 $43,661 $ 5,276 $ 69,122
Operating Leases 2,242 860 993 389 -
Long-term Purchased
Power Commitments 278,992 22,516 35,541 31,365 189,570
-------- ------- ------- -------- -------
Total Contractual Cash
Obligations $433,430 $57,513 $80,195 $37,030 $258,692
======== ======= ======= ======= ========
See Notes 5 and 7 to the consolidated financial statements for a
discussion of the Company's long-term debt obligations and long-term
purchased power contract commitments.
Amount of Committed Expiration per Period
-----------------------------------------
Total
Other Commercial Amounts Less than After 5
Commitments: Committed 1Year 1-3 years 4-5 years years
----------- --------- ----- --------- --------- -----
Lines of Credit $54,000 $54,000 $ - $ - $ -
------- ------- -------- -------- -------
Total Commercial
Commitments $54,000 $54,000 $ - $ - $ -
======= ======= ======== ======== =======
See Note 5 to the consolidated financial statements for a discussion of
the Company's short-term credit facilities.
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. 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. The settlement was reflected on Maine
Yankee's 2001 financial statements. That amount represented full
payment under the performance bond, plus an additional amount under the
payment bond reflecting certain payments previously 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.
In addition, Maine Yankee has continued to pursue its claims 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 asserted a
right to recover an additional $21 million in that court from the
bankrupt estates. In February 2002 Stone & Webster filed a claim for
approximately $7 million against Maine Yankee in the Bankruptcy Court
in Delaware for alleged breaches of contract and to subordinate any
Maine Yankee claims. On May 30, 2002, the court concluded extensive
hearings and argument by allowing a claim in favor of Maine Yankee
under section 502(c) of the Bankruptcy Code, in the estimated amount of
$20.8 million against each of the three principal bankrupt estates
(jointly and severally). The Court's ruling also effectively precluded
approximately $4 million of Stone & Webster's February 2002 claim
against Maine Yankee, while offering no opinion or findings on the
remainder, the resolution of which will, if necessary, be the subject
of further proceedings. The actual cash amount to be recovered by
Maine Yankee on this allowed claim remains contingent on a number of
factors beyond Maine Yankee's control, including without limitation the
extent to which the bankrupt estates ultimately have assets
available to pay the claim, the final disposition of Stone & Webster's
February 2002 claim, and possible reconsideration of the ruling in the
future based on actual expenses of completing the decommissioning.
Maine Yankee therefore cannot predict the final outcome of the
Bankruptcy Court proceeding.
MAINE YANKEE - NUCLEAR FUEL STORAGE - Federal legislation enacted in
1987 directed the Department of Energy (DOE) to proceed with the
studies necessary to develop and operate a permanent high-level waste
(spent fuel) repository at Yucca Mountain, Nevada. The project has
encountered delays, and the DOE has indicated that the permanent
disposal site is not expected to open before 2010, although originally
scheduled to open in 1998.
In accordance with the process set forth in the legislation, in
February 2002 the Secretary of Energy recommended the Yucca Mountain
site to the President for the development of a nuclear waste
repository, and the President then recommended development of the site
to the Congress. As provided in the statutory procedure, the State of
Nevada formally objected to the site in April 2002, and in July 2002
the Congress overrode the objection. Construction of the repository
requires the approval of the Nuclear Regulatory Commission (NRC), upon
application of the DOE and after a public adjudicatory hearing, as well
as a second NRC approval after completion of construction to operate
the facility. The Company cannot predict the timing or results of
those proceedings.
In November 1997 the U.S. Court of Appeals for the District of Columbia
Circuit confirmed the obligation of the DOE under the Nuclear Waste
Policy Act of 1982 to take responsibility for spent nuclear fuel from
commercial reactors in January 1998. After an unsuccessful effort by
Maine Yankee in the same court to compel the DOE to take Maine Yankee's
spent fuel, in June 1998 Maine Yankee filed a claim for money damages
in the U.S. Court of Federal Claims for the costs associated with the
DOE's default. In November 1998 the Court granted summary judgment in
favor of Maine Yankee, ruling that the DOE had violated its contractual
obligations, but leaving the amount of damages incurred by Maine Yankee
for later determination by the Court. Since then the parties have been
engaged in extensive discovery and resolution of pre-trial issues in
the damages phase of the proceeding. Maine Yankee is pursuing its
claim for determination of damages vigorously, but cannot predict the
outcome or timing of the determination.
At the same time, as an interim measure until the DOE meets its
contractual obligation to dispose of Maine Yankee's spent fuel at Yucca
Mountain or elsewhere, the Company constructed an independent spent
fuel storage installation (ISFSI), utilizing dry-cask storage, on the
Plant site and is in the process of transferring the spent fuel from
the spent-fuel pool to the individual casks and the casks to the ISFSI.
The company's total cost of maintaining the ISFSI will be substantially
affected by heightened security costs and by the length of time it is
required to operate the ISFSI before the DOE honors its contractual
obligation to take the fuel from the site. The Company's current
decommissioning cost estimated is based on an assumption that its
operation of the ISFSI will end in 2023, but the actual period of
operation and cost may vary.
On January 15, 2003, the Company notified NAC International (NAC), the
contractor responsible for providing for the fabrication of the spent-
fuel casks and transferring the fuel to the casks and the casks to the
ISFSI, that the Company was terminating its contract with NAC pursuant
to the terms of the contract. NAC had been experiencing financial
difficulties and had requested relief from the terms of the contract.
Maine Yankee believes that NAC had also failed to perform its
contractual obligations in accordance with the terms of the contract
and provide adequate assurance of its ability to do so in the future.
NAC has indicated that it disputes Maine Yankee's basis for terminating
the contract and has served Maine Yankee with a demand to arbitrate the
dispute, while at the same time the parties have been in negotiations
to resolve the situation. In the meantime, Maine Yankee has entered
into contracts with the major subcontractors and resumed the transfer
of fuel to the ISFSI under its own management. Maine Yankee believes
that its termination of the NAC contract was legally justified, but
cannot predict the outcome of the negotiations or arbitration
proceeding.
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 stranded cost rate orders from the MPUC that became effective
on March 1, 2000 and 2002, 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 or nuclear fuel
storage issues will have a material adverse impact on the Company's
results of operations, financial condition or cash flows.
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 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, 2002,
the liability recorded by the Company for its estimated environmental
remediation costs amounted to approximately $411,000. The Company's
actual future environmental remediation costs may be different as
additional factors become known. In 2002 the Company expended
approximately $171,000 in operations to comply with environmental
standards for air, water and hazardous materials.
NEW ACCOUNTING PRONOUNCEMENT - In June 2002, the Financial Accounting
Standards Board issued Statement No. 143, "Accounting for Asset
Retirement Obligations". This Statement addresses financial accounting
and reporting for obligations associated with the retirement of
tangible long-lived assets and the associated asset retirement costs.
It applies to legal obligations associated with the retirement of long-
lived assets that result from acquisition, construction, development
and (or) the normal operation of a long-lived asset, except for certain
obligations of lessees. This Statement is effective for financial
statements issued for fiscal years beginning after June 15, 2002.
Management does not believe that the implementation of this Statement
will materially impact the Company's financial position, earnings or
cash flows, principally as a result of the regulatory accounting
utilized by the Company.
In November 2002, the Financial Accounting Standards Board issued
Interpretation No. 45, "Guarantor's Accounting and Disclosure
Requirements for Guarantees, Including Indirect Guarantees of
Indebtedness of Others" (FIN 45). Along with new disclosure
requirements, FIN 45 requires guarantors to recognize at the inception
of certain guarantees a liability for the fair value of the obligation
undertaken in issuing the guarantee. This differs from the current
practice to record a liability only when a loss is probable and
reasonably estimable. The recognition and measurement provisions of
FIN 45 are applicable on a prospective basis to guarantees issued or
modified after December 31, 2002. The adoption of FIN 45 is not
expected to have a material effect on the Company's results of
operations or financial position.
In December 2002, the Financial Accounting Standards Board issued
Interpretation No. 46, "Consolidation of Variable Interest Entities, an
Interpretation of ARB No. 51" (FIN 46). FIN 46 requires certain
variable interest entities to be consolidated by the primary
beneficiary of the entity if the equity investors in the entity do not
have the characteristics of a controlling financial interest or do not
have sufficient equity at risk for the entity to finance its activities
without additional subordinated financial support from the other
parties. FIN 46 is effective for all new variable interest entities
created or acquired after January 31, 2003. For variable interest
entities created or acquired before February 1, 2003, the provisions of
FIN 46 must be applied for the first interim or annual period beginning
after June 15, 2003. Management is currently evaluating the impact of
the adoption of FIN 46 and does not anticipate that it will have a
material effect on the Company's result of operations or financial
position.
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.
Pension and Other Postretirement Benefits - Assumptions used in
determining projected benefit obligations and the fair values of plan
assets for the Company's pension plans and other postretirement benefit
plans are evaluated periodically by management in consultation with
outside actuaries. Changes in assumptions are based on relevant
company data, such as rate of increase in compensation levels and the
long-term rate of return on plan assets. Critical assumptions, such as
the discount rate used to measure the benefit obligations, the expected
long-term rate of return on plan assets and health care cost projections,
are evaluated and updated annually. The Company has assumed that the
expected long-term rate of return on plan assets will be 8%, a 1% reduction
from the assumption utilized in 2001.
At the end of each year, the Company determines the discount rate that
reflects the current rate at which pension liabilities could be
effectively settled. This rate should be in line with rates for high
quality fixed income investments available for the period to maturity
of the pension benefits, and changes as long-term interest rates
change. At year-end 2002, we determined this rate to be 6.75%.
Postretirement benefit plan discount rates are the same as those used
by our defined benefit pension plan in accordance with the provisions
of Statement of Financial Accounting Standards No. 106, "Employers'
Accounting for Postretirement Benefits Other Than Pensions".
In the fourth quarter of 2002, the Company recorded a non-cash
adjustment to equity through other comprehensive loss of approximately
$2 million to reflect additional minimum pension liability. Based on
the current assumptions, as well as the impact of recent market
declines in the value of pension assets, the Company estimates that the
pension expense for 2003 will increase approximately $1.5 million over
the 2002 expense. Also, the Company will be required to start making
contributions to its pension plan in 2003, amounting to approximately
$2.1 million.
The trend in health care costs is difficult to estimate and it has an
important effect on postretirement liabilities. The 2002 health care
cost trend rate, which is the weighted average annual projected rate of
increase in the per capita cost of covered benefits, was 9%. This rate
is assumed to decrease to 5% by 2008 and then remain at that level.
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."
FORWARD LOOKING STATEMENTS - 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, developments in the
legislative, regulatory and competitive environments in which the
Company operates and other circumstances that could affect revenues and
costs.
ITEM 7A
QUANTITATIVE AND QUALITATIVE 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. The Company also was a party to an interest
rate swap associated with the variable rate medium term notes (See Note
13 to the 2001 Form 10-K). This debt was fully repaid in July 2002.
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
2002 2001 Date 2000
---- ---- ---- ----
Electric Operating Revenues:
Electric operating revenue (Note 1) $ 115,829,181 $ 29,919,908 $ 83,946,328 $ 126,852,407
Off-system sales (Note 7) 39,712,482 4,234,118 14,718,171 19,351,606
Standard offer service (Note 10) 12,195,953 17,476,348 67,112,864 66,133,532
------------- ------------ ------------- -------------
$ 167,737,616 $ 51,630,374 $ 165,777,363 $ 212,337,545
------------- ------------ ------------- -------------
Operating Expenses:
Fuel for generation and purchased power (Notes 1 and 4) $ 61,670,112 $ 8,670,095 $ 25,978,835 $ 44,509,554
Standard offer service purchased power (Note 10) 11,507,606 16,945,383 65,893,732 65,552,980
Other operation and maintenance (Notes 1 and 6) 34,572,636 9,502,542 27,297,029 35,310,660
Depreciation and amortization (Note 1) 10,549,148 2,198,158 7,826,371 9,158,885
Regulatory amortizations (Notes 7, 8 and 10) 13,988,421 4,345,577 13,380,902 19,153,442
Taxes -
Local property and other 4,859,734 1,181,771 3,817,948 4,795,698
Income (Note 3) 6,553,102 2,038,384 4,713,760 7,432,261
------------- ------------ ------------- -------------
$ 143,700,759 $ 44,881,910 $ 148,908,577 $ 185,913,480
------------- ------------ ------------- -------------
Operating Income $ 24,036,857 $ 6,748,464 $ 16,868,786 $ 26,424,065
Other Income And (Deductions):
Allowance for equity funds used during
construction (Note 1) 497,920 139,532 464,541 158,698
Other, net of applicable income taxes (Notes 2 and 3) 805,363 157,452 (1,416,135) 454,715
------------- ------------ ------------- -------------
Income Before Interest Expense $ 25,340,140 $ 7,045,448 $ 15,917,192 $ 27,037,478
------------- ------------ ------------- -------------
Interest Expense:
Long-term debt (Note 5) $ 12,145,601 $ 3,393,733 $ 10,429,419 $ 15,211,905
Other (Note 5) 1,179,320 286,443 722,586 893,455
Allowance for borrowed funds used during
construction (Note 1) (446,083) (135,676) (423,431) (169,929)
------------- ------------ ------------- -------------
$ 12,878,838 $ 3,544,500 $ 10,728,574 $ 15,935,431
------------- ------------ ------------- -------------
Net Income $ 12,461,302 $ 3,500,948 $ 5,188,618 $ 11,102,047
Dividends On Preferred Stock (Note 4) 265,570 66,429 199,141 265,570
------------- ------------ ------------- -------------
Earnings Applicable To Common Stock $ 12,195,732 $ 3,434,519 $ 4,989,477 $ 10,836,477
============= ============ ============= =============
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 $ 1.66 $ .47 $ .67 $ 1.47
Diluted 1.66 .47 .61 1.30
------------- ------------ ------------- -------------
Dividends Declared Per Common Share $ 1.29 $ - $ .60 $ .80
------------- ------------ ------------- -------------
The accompanying notes are an integral part of these consolidated financial statements.
Item 8
- ------
Financial Statements & Supplementary Data
- -----------------------------------------
BANGOR HYDRO-ELECTRIC COMPANY
CONSOLIDATED BALANCE SHEETS
December 31,
Assets 2002 2001
---- ----
Investment In Utility Plant:
Electric plant in service, at original cost (Note 11) $ 333,410,221 $ 328,559,986
Less - Accumulated depreciation and amortization (Note 1) 97,473,295 93,984,836
------------- -------------
$ 235,936,926 $ 234,575,150
Construction work in progress (Note 1) 5,933,988 7,307,837
------------- -------------
$ 241,870,914 $ 241,882,987
Investments in corporate joint ventures: (Notes 1 and 7)
Maine Yankee Atomic Power Company $ 4,033,846 $ 4,421,884
Maine Electric Power Company, Inc. 1,004,473 853,562
------------- -------------
$ 246,909,233 $ 247,158,433
------------- -------------
Other Investments, at cost (Note 9) $ 3,590,720 $ 3,497,681
------------- -------------
Funds held by trustee, at cost (Notes 5 and 9) $ 21,191,940 $ 22,694,648
------------- -------------
Current Assets:
Cash and cash equivalents (Notes 1 and 9) $ 988,752 $ 884,617
Accounts receivable, net of reserve ($1,085,052 in 2002 and $761,000 in 2001) 21,027,291 19,268,889
Unbilled revenue receivable (Note 1) 8,318,821 15,379,708
Inventories, at average cost:
Material and supplies 2,466,988 2,531,853
Fuel oil 44,860 53,320
Prepaid expenses 285,212 671,267
------------- -------------
Total current assets $ 33,131,924 $ 38,789,654
------------- -------------
Regulatory Assets and Deferred Charges:
Goodwill-EMERA Acquisition (Note 2) $ 82,537,291 $ 82,537,291
Investment in Seabrook nuclear project, net of accumulated amortization
of $36,969,396 in 2002 and $35,270,346 in 2001 (Notes 8 and 10) 21,872,679 23,571,729
Costs to terminate/restructure purchased power contracts, net of accumulated
amortization of $166,003,281 in 2002 and $145,729,090 in 2001 (Notes 7 and 10) 72,675,931 92,057,206
Maine Yankee decommissioning costs (Notes 7 and 10) 31,101,273 37,306,576
Above-market purchased power contract obligation (Notes 10 and 13) 63,341,000 73,954,000
Other regulatory assets (Notes 3, 5, 6, 7 and 10) 57,843,677 52,657,562
Other deferred charges (Note 6) 6,535,328 4,019,969
------------- -------------
Total regulatory assets and deferred charges $ 335,907,179 $ 366,104,333
------------- -------------
Total Assets $ 640,730,996 $ 678,244,749
============= =============
The accompanying notes are an integral part of these consolidated financial statements.
Item 8
- ------
Financial Statements & Supplementary Data
- -----------------------------------------
BANGOR HYDRO-ELECTRIC COMPANY
CONSOLIDATED BALANCE SHEETS
December 31,
Stockholders' Investment and Liabilities 2002 2001
---- ----
Capitalization: (see accompanying statement)
Common stock investment (Notes 4 and 6) $ 206,266,149 $ 205,556,673
Preferred stock (Note 4) 4,734,000 4,734,000
Long-term debt, net of current portion (Notes 5 and 9) 118,058,636 131,967,827
------------- -------------
Total capitalization $ 329,058,785 $ 342,258,500
------------- -------------
Current Liabilities:
Notes payable - banks (Note 5) $ 16,000,000 $ 8,000,000
------------- -------------
Other current liabilities -
Current portion of long-term debt (Notes 5 and 9) $ 34,137,342 $ 43,245,891
Accounts payable 20,281,376 22,491,785
Dividends payable 66,429 66,429
Accrued interest 2,092,608 2,663,225
Customers' deposits 572,291 572,867
Current income taxes (refundable) payable (355,008) 1,916,892
------------- -------------
Total other current liabilities $ 56,795,038 $ 70,957,089
------------- -------------
Total current liabilities $ 72,795,038 $ 78,957,089
------------- -------------
Regulatory and Other Long-term Liabilities (Note 3)
Deferred income taxes - Seabrook $ 11,337,954 $ 12,223,523
Other accumulated deferred income taxes 48,947,440 47,405,476
Maine Yankee decommissioning liability (Note 7) 31,101,273 37,306,576
Deferred gain on asset sale (Note 10) 9,888,574 14,574,316
Above-market purchased power contract obligation (Note 13) 63,341,000 73,954,000
Other regulatory liabilities (Notes 7 and 10) 11,264,848 18,961,715
Unamortized investment tax credits 1,185,596 1,311,928
Accrued pension and postretirement benefit costs (Note 6) 50,494,119 39,655,265
Other long-term liabilities (Notes 7 and 11) 11,316,369 11,636,361
------------- -------------
Total regulatory and other long-term liabilities $ 238,877,173 $ 257,029,160
------------- -------------
Total Stockholders' Investment and Liabilities $ 640,730,996 $ 678,244,749
============= =============
The accompanying notes are an integral part of these consolidated financial statements.
Item 8
- ------
Financial Statements & Supplementary Data
- -----------------------------------------
BANGOR HYDRO-ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF CAPITALIZATION
December 31,
2002 2001
---- ----
Common Stock Investment (Notes 1, 2 and 4)
Common stock, no par value, stated value $5 per share- $ 36,817,120 $ 36,817,120
Authorized -- 10,000,000 shares
Outstanding -- 7,363,424 shares
Amounts paid in excess of par value 165,352,312 165,352,312
Accumulated other comprehensive loss (Note 6) (2,033,534) (47,278)
Retained earnings 6,130,251 3,434,519
------------- -------------
Total common stock investment $ 206,266,149 $ 205,556,673
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 and 9) ------------- -------------
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
7.30% Series due 2003 15,000,000 15,000,000
7.38% Series due 2002 - 20,000,000
------------- -------------
$ 65,000,000 $ 85,000,000
Other Long-Term Debt- ------------- -------------
Finance Authority of Maine - Taxable Electric Rate
Stabilization Revenue Notes, 7.03% Series 1995A, due 2005 $ 55,400,000 $ 71,500,000
Medium Term Notes, Variable interest rate-LIBO rate plus 1.125%, due 2002 - 5,460,000
Municipal Review Committee Note, 5%, due 2008 11,780,660 13,234,394
Senior unsecured note, 6.09%, due 2012 20,000,000 -
Other miscellaneous notes payable, 3.90%, due 2006 15,318 19,324
------------- -------------
$ 87,195,978 $ 90,213,718
Less: Current portion of long-term debt 34,137,342 43,245,891
------------- -------------
$ 53,058,636 $ 46,967,827
------------- -------------
Total Long-Term Debt $ 118,058,636 $ 131,967,827
------------- -------------
Total Capitalization $ 329,058,785 $ 342,258,500
============= =============
The accompanying notes are an integral part of these consolidated financial statements.
Item 8
- ------
Financial Statements & Supplementary Data
- -----------------------------------------
BANGOR HYDRO-ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the years ended December 31,
Predecessor
-----------
Period From Period From
Acquisition January 1,
Date to 2001 Through
December 31, Acquisition
2002 2001 Date 2000
-------------- ------------ ------------- -------------
Cash Flows From Operating Activities:
Net income $ 12,461,302 $ 3,500,948 $ 5,188,618 $ 11,102,047
Adjustments to reconcile net income to net cash
from operating activities:
Depreciation and amortization 10,549,148 2,198,158 7,826,371 9,158,885
Amortization of Seabrook nuclear project (Note 8) 1,699,050 424,763 1,274,287 1,699,050
Amortization of contract buyouts and restructuring (Note 7) 20,274,191 5,639,281 16,917,843 22,311,448
Amortization of deferred asset sale gain (Note 10) (4,681,324) (2,105,076) (5,971,057) (6,393,038)
Other amortizations (3,330,048) 375,024 1,193,607 1,896,179
Allowance for equity funds used during construction (Note 1) (497,920) (139,532) (464,541) (158,698)
Deferred income tax provision and amortization of
investment tax credits (Note 3) 1,625,652 (212,917) (5,976,077) (2,765,264)
Gain on sale of subsidiary - - - (1,205,727)
Deferred Maine Yankee replacement power cost write-off (Note 7) - - - 1,992,848
Changes in assets and liabilities:
Costs to restructure purchased power contract (Note 7) (750,000) (250,000) (750,000) (1,000,000)
Deferred standard-offer service costs (Note 10) (2,138,380) 4,265,218 4,580,779 (2,988,823)
Deferred special rate contract revenues (Note 10) (115,711) (910,954) (1,404,194) (1,368,948)
Employee transition costs (Note 10) (3,535,097) - - -
Exercise of PERC warrants-cash paid in lieu of
issuing shares (Note 7) - (4,951,550) (9,225,892) (2,129,387)
Deferred Wyman#4 litigation settlement proceeds (Note 10) - 2,592,294 - -
Deferred incremental Maine Yankee costs (Note 7) - - - 807,616
Deferred costs associated with generation asset sale (Note 10) - - - 107,765
Accounts receivable, net and unbilled revenue 5,302,485 (1,291,684) 1,298,321 (5,113,248)
Accounts payable (3,759,662) (1,032,699) (1,359,942) 10,609,785
Accrued interest (570,617) (703,043) 837,030 (23,521)
Current and deferred income taxes (2,271,900) (293,705) 2,253,111 (10,093)
Accrued pension and postretirement benefit costs (Note 6) 4,294,357 840,025 2,183,113 823,049
Other current assets and liabilities, net 458,802 (257,941) 580,127 202,486
Other, net (1,086,422) (256,505) (1,150,926) 65,770
-------------- ------------ ------------- -------------
Net Increase in Cash From Operating Activities: $ 33,927,906 $ 7,430,105 $ 17,830,578 $ 37,620,181
Cash Flows From Investing Activities: -------------- ------------ ------------- -------------
Construction expenditures $ (10,094,378)$ (6,264,489) $ (10,083,839) $ (16,680,501)
Allowance for borrowed funds used during construction (Note 1) (446,083) (135,676) (423,431) (169,929)
Proceeds from sale of subsidiary - - - 1,250,000
-------------- ------------ ------------- -------------
Net Decrease in Cash From Investing Activities $ (10,540,461)$ (6,400,165) $ (10,507,270) $ (15,600,430)
Cash Flows From Financing Activities: -------------- ------------ ------------- -------------
Dividends on preferred stock $ (265,570)$ (66,380) $ (199,190) $ (265,570)
Dividends on common stock (9,500,000) (1,472,685) (4,418,054) (5,522,567)
Payments on long-term debt (Note 5) (43,017,740) (2,054,457) (19,720,645) (19,460,000)
Capital reserve funds used in repayment on long-term debt 1,500,000 - - -
Proceeds from issuance of long-term debt (Note 5) 20,000,000 - - -
Short-term debt, net (Note 5) 8,000,000 2,000,000 6,000,000 -
-------------- ------------ ------------- -------------
Net Decrease in Cash From Financing Activities $ (23,283,310)$ (1,593,522) $ (18,337,889) $ (25,248,137)
-------------- ------------ ------------- -------------
Net Increase (Decrease) in Cash and Cash Equivalents $ 104,135 $ (563,582) $ (11,014,581) $ (3,228,386)
Cash and Cash Equivalents at Beginning of Year 884,617 1,448,199 12,462,780 15,691,166
-------------- ------------ ------------- -------------
Cash and Cash Equivalents at End of Year $ 988,752 $ 884,617 $ 1,448,199 $ 12,462,780
============== ============ ============= =============
The accompanying notes are an integral part of these consolidated financial statements.
Item 8
- ------
Financial Statements & Supplementary Data
- -----------------------------------------
BANGOR HYDRO-ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF COMMON STOCK INVESTMENT
Accumulated
Amounts Paid Other Total Common
Common in Excess of Retained Comprehensive Stock
Stock Par Value Earnings Loss Investment
------------- ------------- ------------- ---------------- -------------
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 - - - (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
Net income - - 12,461,302 12,461,302
Other comprehensive loss net of taxes:
Unrealized gain on interest rate swap - - - 47,278 47,278
Minimum pension liability (Note 6) - - - (2,033,534) (2,033,534)
------------
Total comprehensive income 10,475,046
Cash dividends declared on- ------------
Preferred stock - - (265,570) - (265,570)
Common stock - - (9,500,000) - (9,500,000)
----------- ------------ ----------- ------------ ------------
Balance December 31, 2002 $36,817,120 $165,352,312 $ 6,130,251 $ (2,033,534) $206,266,149
=========== ============ =========== ============= ============
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 10) consists primarily
of amounts charged for electricity delivered to customers during the
period. The Company records unbilled revenue, based on estimates of
electric service rendered and not billed at the end of an accounting
period, in order to match revenue with related costs. As of March 1,
2000, the Company bills customers for the energy supplied by
competitive energy providers (See Note 10). Competitive energy
providers are paid only after the funds are collected from customers.
The Company records accounts receivable for the amounts billed to
competitive energy customers and a corresponding accounts payable for
the amounts due to the energy supplier. No revenue is recognized as the
Company is acting as an agent. 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.
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 was approximately 2.9% in each of 2002, 2001 and 2000.
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 $7.8 million in 2002, $10.1 million in 2001 and
$10 million in 2000.
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 Combinations", 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 10), were also capitalized and
included in AFDC in the Consolidated Statements of Income. The average
AFDC (carrying costs) rates computed by the Company were 8.8% in 2002,
9.1% for 2001 and 9.3% in 2000.
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 $12.6 million,
$14.1 million and $15.1 million in 2002, 2001 and 2000,
respectively. Cash paid for income taxes was approximately $9.6
million, $10.4 million and $10 million in 2002, 2001 and 2000,
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 combination of both fixed and variable rate
debt instruments and an interest rate swap which terminated in 2002 (see
Note 5). 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".
In November 2002 the Company purchased a weather hedge for the 2002-
2003 heating season. The hedge is designed to protect against the
negative impacts of warmer than normal weather on the Company's
electric operating revenues. The cost of the weather hedge is being
amortized over the 2002- 2003 heating season. No income was recognized
for this weather hedge in 2002 due to the colder than normal weather.
See Note 12.
RECLASSIFICATIONS-Certain prior year amounts have been reclassified to
conform with the presentation used in the 2002 Consolidated Financial
Statements.
Note 2. Merger with Emera, Inc.
- --------------------------------
On October 10, 2001, Emera, Inc. (Emera) completed the acquisition of
all of the outstanding common stock of the Company for US$26.806 per
share in cash. 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 is recorded as goodwill on the consolidated balance sheets. As
previously discussed, the goodwill is not being amortized, but instead
is subject to an impairment test at least annually in accordance with
the provisions of Statement of Financial Accounting Standards No. 142,
"Goodwill and Other Intangible Assets". Goodwill associated with the
Emera acquisition was not adjusted for any impairment losses in 2002 or
2001.
As a result of the merger, and 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 were recorded as a component of
Other Income (Expense) in the Consolidated Statements of Income for
2001 and 2000.
Note 3. Income Taxes
- ---------------------
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 $10.5 million as of December 31, 2002 and $10.3 million
as of December 31, 2001. 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 ($15.7 million and $16.0 million as of December 31, 2002 and
2001, 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 ($4.5
million and $4.9 million as of December 31, 2002 and 2001,
respectively), and the establishment of deferred tax assets on
unamortized investment tax credits ($701,000 and $776,000 as of
December 31, 2002 and 2001, respectively). These latter amounts have
been recorded in Other Regulatory Liabilities at December 31, 2002 and
2001. 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, 2002 and 2001:
2002 2001
------------ -------------
Deferred Income Tax Liabilities:
Costs to terminate/restructure purchased
power contracts $ 18,877,652 $ 26,362,744
Excess book over tax basis of electric
plant in service 42,237,261 37,117,206
Investment in jointly-owned companies 1,676,838 1,476,037
Other regulatory assets 4,177,045 2,547,116
Other 93,100 138,374
------------ ------------
$ 67,061,896 $ 67,641,477
------------ ------------
Deferred Income Tax Assets:
Deferred asset sale gain $ 4,255,984 $ 5,901,889
Accrued pension and postretirement
benefit costs 7,486,547 5,734,119
Other regulatory liabilities 2,312,651 5,369,662
Other 4,059,274 3,230,331
------------ ------------
$ 18,114,456 $ 20,236,001
------------ ------------
Total other accumulated deferred income taxes $ 48,947,440 $ 47,405,476
============ ============
The individual components of federal and state income taxes reflected
in the Consolidated Statements of Income for 2002, 2001 and 2000 are
stated in the table below.
Year Ended December 31, 2002 2001 2000
- ------------------------------------------------------------------------
Current Income Tax Provision $ 5,481,256 $12,258,263 $10,366,395
Deferred Income Tax Provision 1,751,984 (6,048,863) (2,625,596)
Investment Tax Credits, Net (126,332) 42,951 (139,668)
----------- ----------- -----------
Total Provision $ 7,106,908 $ 6,252,351 $ 7,601,131
Allocated to Other Income (553,806) 499,793 (168,870)
----------- ----------- -----------
Charged to Operating Expense $ 6,553,102 $ 6,752,144 $ 7,432,261
============ ============ ===========
The Company's effective tax rate differed from the statutory rate of 35% due
to the following:
2002 2001 2000
---------------------------------------------
(Dollars in Thousands)
Amount % Amount % Amount %
---------------------------------------------
Federal income tax provision at
statutory rate $6,849 35.0% $5,230 35.0% $6,546 35.0%
Less (Plus) permanent differences
in tax expense resulting from
statutory exclusions from
taxable income:
Asset sale gain permanent
differences (201) (1.0) (349) (2.3) (276) (1.5)
Amortization of equity component
of AFDC on recoverable Seabrook
investment (160) (.8) (160) (1.0) (160) (.8)
Other 468 2.3 246 1.6 334 1.7
---------------------------------------------
Federal income tax provision
before effect of timing
differences $6,742 34.5% $5,493 36.7% $6,648 35.6%
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) (.7) (151) (1.0) (151) (.8)
State income tax liability
deducted for federal income
tax purposes 591 3.0 424 2.8 550 2.8
Reversal of excess deferred
income taxes 319 1.6 230 .5 147 .8
Amortization of investment
tax credits 126 .6 140 .9 140 .8
Other (18) - (375) (2.5) (67) (.2)
---------------------------------------------
Federal income tax provision $5,875 30.0% $5,225 35.0% $6,029 32.2%
=============================================
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.
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
2002 2001 2001 2000
----------- ---------- ---------- -----------
Earnings applicable to
common stock $12,195,732 $3,434,519 $4,989,477 $10,836,477
----------- ---------- ---------- -----------
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
----------- ---------- ---------- -----------
Average common shares
outstanding plus assumed
warrants converted 7,363,424 7,363,424 8,155,169 8,353,523
----------- ---------- ---------- -----------
Basic earnings per
common share $1.66 $.47 $.67 $1.47
----------- ---------- ---------- -----------
Diluted earnings per
common share $1.66 $.47 $.61 $1.30
=========== ========== ========== ===========
Note 5. Lending Agreements
- ---------------------------
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.
On December 20, 2002, the Company received proceeds from the private
placement issuance of a $20 million senior unsecured note. The note
has a term of ten years, a fixed interest rate of 6.09% and payments of
interest on a semiannual basis. The $20 million principal borrowing is
to be paid at maturity.
Current maturities of the first mortgage bonds and other long-term debt
for the five years subsequent to December 31, 2002, amounting to
$81,239,236, are $34,137,342 in 2003, $20,314,371 in 2004, $21,830,717
in 2005, $2,318,969 in 2006, and $2,637,837 in 2007.
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, and the
First Mortgage Bonds have expired. On June 29, 2001, the Company
extended the revolving credit agreement until October 1 and then until
March 31, 2002, and the agreement was further extended until June 30,
2003 with some modifications. The facility was increased to $60
million to accommodate the certain debt retirements in 2002, another
pricing level was added to recognize the Company's improved credit and
certain modifications were made to some of the financial covenants.
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 a financial institution 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 also subsequently been
extended to June 30, 2003.
In connection with debt agreements the Company must comply with 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 in compliance with all covenants associated with its
lending agreements.
Certain information related to the Company's short-term credit
facilities is as follows:
2002 2001 2000
----------- ----------- -----------
Total credit available
at end of period $70,000,000 $40,000,000 $30,000,000
Unused credit at end
of period $54,000,000 $32,000,000 $30,000,000
Borrowings outstanding at end
of period $16,000,000 $ 8,000,000 -
Effective interest rate (exclusive
of fees) on borrowings outstanding
at end of period 2.4% 4.4% -%
Average daily outstanding borrowings
for the period $21,782,192 $ 3,031,507 $ -
Weighted daily average annual
interest rate (exclusive of fees) 2.8% 4.4% -%
Highest level of borrowings outstanding
at any month-end during the period $45,000,000 $ 8,000,000 $ -
=========== ============ ========
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
former senior executives.
There were no employer contributions to the noncontributory pension
plan in 2002, 2001 or 2000. The plan's assets are composed of fixed
income securities, equity securities and cash equivalents. In 2002, as
a result of a corporate restructuring, the Company implemented an early
retirement program which provided for enhanced pension benefits for the
early retirees.
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 2002, 2001 and
2000 and the major assumptions used to determine these amounts
(includes both the funded and unfunded plans). Total pension expense
(income) included the following components:
2002 2001 2000
----------- ---------- ----------
Service cost-benefits earned
during the period $ 916,726 $1,387,841 $1,186,910
Interest cost on projected
benefit obligation 3,920,015 3,622,633 3,479,260
Expected return on plan assets (3,925,587) 4,260,894) (4,460,416)
Amortization of unrecognized
asset and gains (losses) (568,643) (6,958) (664,911)
----------- ---------- ----------
Total pension expense (income) $ 342,511 $ 742,622 $ (459,157)
=========== ========== ==========
The following table sets forth the plans' funded status at December 31,
2002 and 2001:
2002 2001
------------- -------------
Change in Projected Benefit Obligation
Balance as of December 31, 2001 and 2000 $ 53,382,582 $ 47,951,796
Service cost 916,726 1,387,841
Interest cost 3,920,015 3,622,633
Benefits paid (3,396,922) (2,863,257)
Amendments 2,054,108 -
(Gains) and losses 2,278,722 3,283,569
Other - Special termination charge 1,612,956 -
------------- -------------
Balance as of December 31, 2002 and 2001 $ 60,768,187 $ 53,382,582
------------- -------------
Change in Plan Assets
Balance as of December 31, 2001 and 2000 $ 41,430,955 $ 48,425,866
Employer contributions 130,441 54,142
Benefits paid (3,396,922) (2,863,257)
Actual return, less expenses (3,700,541) (4,185,796)
------------- -------------
Balance as of December 31, 2002 and 2001 $ 34,463,933 $ 41,430,955
------------- -------------
Funded status $ (26,304,254) $ (11,951,627)
Unrecognized prior service cost 2,474,374 -
Unrecognized (gain) or loss 8,872,460 (1,180,767)
------------- -------------
Accrued pension at December 31, 2002 and 2001 $ (14,957,420) $ (13,132,394)
============= =============
Amounts recognized in the statement of financial
position consist of:
Accrued benefit liability $ (20,866,817) $ (13,132,394)
Intangible asset 2,474,374 -
Accumulated other comprehensive income 3,435,023 -
------------- -------------
Net amount recognized $ (14,957,420) $ (13,132,394)
============= =============
The discount rate and rate of increase in future compensation levels
used to determine pension obligations, effective January 1, 2003, are
6.75% and 4%, respectively, and were used to calculate the plans'
funded status at December 31, 2002.
Significant assumptions used to determine the pension expense (income)
for each year were as follows:
2002 2001 2000
------- ----------- -----
Discount rate* 7.25% 7.75%/7.25% 8.0%
Rate of increase in future compensation levels 4.0% 4.0% 4.0%
Expected long-term rate of return on plan assets 8.0% 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 provisions of Financial Accounting Standards Board Statement No.
87, "Employers' Accounting for Pensions", requires the Company to
record an additional minimum liability of $5,909,397 at December 31,
2002. This liability represents the amount by which the accumulated
benefit obligation exceeds the sum of the fair market value of plan
assets and accrued amounts previously recorded. The additional
liability may be offset by an intangible asset to the extent of
previously unrecognized prior service cost. The intangible asset of
$2,474,374 at December 31, 2002 is included in Other Deferred Charges
on the Consolidated Balance Sheets. The remaining amount of $3,435,023
is recorded as a component of stockholders' equity, net of related tax
benefits of $1,401,489, is included in Accumulated Other Comprehensive
Loss on the Consolidated Statement of Common Stock Investment at
December 31, 2002.
As a result of regulatory accounting as approved in the Company's
Alternative Rate Plan (See Note 10), the Company deferred $1,612,956,
as a regulatory asset, related to this special termination charge. As
a result of this accounting, the pension expense for 2002 was
unaffected, while the pension liability was increased at December 31,
2002.
In 2001, as a result of purchase accounting, all unrecognized actuarial
gains and losses, prior service cost and the net transition asset were
eliminated as of the merger 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
$1,214,065 in 2002 and $211,670 in 2001 for the period subsequent to
the merger.
The accumulated benefit obligation for the unfunded supplemental
pension plan with accumulated benefit obligations in excess of plan
assets was $2,501,699 and $2,201,171 as of December 31, 2002 and 2001,
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 Company maintains 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 $864,000 in 2002
and $1.3 million in 2001. The VEBA's assets are composed of United States
Treasury money market funds. The Company's general policy is to contribute
to the VEBA amounts necessary to fund claims and administrative costs.
The actuarially determined net periodic postretirement benefit cost for
2002, 2001 and 2000 and the major assumptions used to determine these
amounts are shown in the following tables:
2002 2001 2000
----------- ----------- -----------
Service cost of benefits earned $ 583,496 $ 632,590 $ 573,740
Interest cost on accumulated
postretirement benefit obligation 2,043,548 1,848,813 1,716,563
Actual return on plan assets (16,190) (37,836) (22,002)
Amortization of unrecognized
transition obligation - 375,900 501,200
Other deferrals, net (8,810) 271,727 280,255
---------- ---------- ----------
Net periodic postretirement benefit
cost $2,602,044 $3,091,194 $3,049,756
========== ========== ==========
The following table sets forth the benefit plan's funded status at
December 31, 2002 and 2001.
2002 2001
------------ ------------
Change in Accumulated Postretirement
Benefit Obligation
Balance as of December 31, 2001 and 2000 $ 27,488,444 $ 23,874,192
Service cost 583,496 632,590
Interest cost 2,043,548 1,848,813
Claims paid (1,053,187) (979,648)
Gains and losses 1,532,744 2,112,497
Other - Special termination charge 1,366,357 -
------------ ------------
Balance as of December 31, 2002 and 2001 $ 31,961,402 $ 27,488,444
------------ ------------
Change in Plan Assets
Balance as of December 31, 2001 and 2000 $ 1,014,038 $ 879,734
Employer contributions 863,969 1,250,743
Retiree contributions 81,529 44,038
Claims/benefit payments and administrative
fees (1,053,187) (1,198,313)
Actual return 16,190 37,836
------------- ------------
Balance as of December 31, 2002 and 2001 $ 922,539 $ 1,014,038
------------- ------------
Funded status $(31,038,863) $(26,474,406)
Unrecognized (gain) loss 1,411,561 (48,465)
------------ ------------
Accrued postretirement benefit cost at
December 31, 2002 and 2001 $(29,627,302) $(26,522,871)
============ ============
The discount rate and near-term and long-term health care cost trend
rates used to determine postretirement benefit obligations, effective
January 1, 2003, and the Plan's funded status at December 31, 2002,
were 6.75%, 9% and 5%, respectively.
Significant assumptions used to determine the net periodic
postretirement benefit cost for each year were as follows:
2002 2001 2000
------ ------------- --------
Discount rate * 7.25% 7.75%/7.25% 8.0%
Health care cost trend rate,
employees less than age 65-
Near-term 9.0% 7.5% 7.0%
Long-term 5.0% 5.0% 5.0%
Health care cost trend rate,
employees greater than age 65-
Near-term 9.0% 7.5% 7.0%
Long-term 5.0% 5.0% 5.0%
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.
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 approximately $1.13 million in
2002 and $283,000 in 2001 for the period subsequent to the merger.
Assumed health care cost trend rates have a significant effect on the
amounts reported for the health care plan. A one-percentage-point
change in assumed health care cost trend rates would have the following
effect:
1% Increase 1% Decrease
------------ -------------
Effect on total of service and interest
cost components $ 508,177 $ (396,482)
Effect on postretirement benefit obligation 5,906,425 (4,639,789)
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 $271,000 in
2002, $363,000 in 2001 and $370,000 in 2000.
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 2002 to 2008,
excluding funds already collected, is approximately $502 million
(undiscounted). The Company's share of the estimated cost at December
31, 2002 is approximately $31.1 million and is recorded as a regulatory
asset and decommissioning liability. The regulatory asset was recorded
for the full amount of the decommissioning and plant closure costs due
to the state's industry restructuring legislation (see Note 10)
allowing the Company future recovery of nuclear decommissioning
expenses related to Maine Yankee, as well as the Company being allowed
a recovery mechanism in its February 2002 rate order for Maine Yankee
non-decommissioning plant closure costs. Accumulated decommissioning
funds at December 31, 2002 had an adjusted market value of $109.1
million of which the Company's share was approximately $7.6 million.
Maine Yankee, starting in 2001, began a program of systematically
redeeming its common stock from its owners. In 2001, the Company
received approximately $703,000 in proceeds associated with the
redemption of 5,264 common shares, while in 2002 the Company received
an additional $525,000 in connection with the redemption of 3,955
common shares. At December 31, 2002, the Company holds 25,781 common
shares of Maine Yankee.
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.
Summary Financial Information for Maine Yankee and MEPCO is as follows
(dollars in thousands):
- -----------------------------------------------------------------------
Maine Yankee MEPCO
- ----------------------------------------------------------------------------
2002 2001 2000 2002 2001 2000
---- ---- ---- ---- ---- ----
Operations:
As reported by investee-
Operating revenues $ 58,924 $ 61,994 $ 43,813 $4,365 $4,514 $4,029
======== ======== ======== ====== ====== ======
Earnings applicable to
common stock $ 3,947 $ 4,371 $ 4,640 $1,068 $1,192 $1,381
======== ======== ======== ====== ====== ======
Amounts reported by the
Company-
Purchased power costs $ 4,068 $ 5,198 $ 5,013 $ - $ - $ -
Equity in net income (280) (310) (320) ( 168) (195) (157)
-------- -------- -------- ------ ------- ------
Net purchased power
expense $ 3,788 $ 4,888 $ 4,693 $ (168) $ (195) $ (157)
======== ======== ======== ======= ====== ======
Financial Position:
As reported by investee-
Total assets $679,975 $802,118 $915,097 $7,680 $6,870 $5,873
Less-
Preferred stock - - 15,000 - - -
Long-term debt 21,600 31,200 40,800 - - -
Other liabilities and
deferred credits 600,656 707,643 788,703 608 770 863
-------- -------- -------- ------ ------ ------
Net assets $ 57,719 $ 63,275 $ 70,594 $7,072 $6,100 $5,010
========= ======== ======== ====== ====== ======
Company's reported equity-
Equity in net assets $ 4,040 $ 4,429 $ 4,942 $1,004 $ 866 $ 711
Adjust Company's
estimated to actual (6) (7) 8 - (12) (38)
--------- -------- -------- ------ ------ ------
Equity in net assets
as reported $ 4,034 $ 4,422 $ 4,950 $1,004 $ 854 $ 673
========= ======== ======== ====== ====== ======
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.
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 approximately $5.6 million liability
(included in Other Long-term Liabilities) and corresponding regulatory asset
(included in Other Regulatory Assets) have been recorded as of
December 31, 2002 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.
POWER SUPPLY COMMITMENTS - As of the end of 2002, the Company had long-
term power supply contracts with six independent, 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. As discussed below, the power purchased under these
contracts are resold to third parties under a separate contracts.
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. The Company's
purchased power expense under this contract was approximately $6.3 million
in 2002, $5.7 million in 2001 and $6.7 million in 2000, and
is projected to be approximately $6.8 million in each of 2003 and 2004
and to steadily decrease over the remainder of the contract down to
approximately $4 million in the last full year, 2023.
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.
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. A portion of the PERC
output is resold to a third party under a power sales contract that
ends in February 2003 (discussed below). The Company's purchased power
expense under this contract was approximately $20.2 million in 2002,
$19.3 million in 2001 and $19.1 million in 2000, and is projected to be
approximately $17.2 million in 2003, $17.6 million in 2004, and to
increase over the remainder of the contract up to $22 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 2002, 2001 and 2000 the Company realized $3.6
million, $3.5 million and $3.5 million, respectively, in savings
associated with its share of PERC net revenues. The Company expects to
realize similar levels of 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 was used to serve a portion
of the standard offer service customer load through February 28, 2002.
Subsequent to this date, the Company has resold this power to one of
the new standard offer service providers in the Company's service
territory. The Company's purchased power expense under this contract
was approximately $37.5 million in 2002 and $21 million in 2001, and is
estimated to be approximately $24.1 million in 2003 and $3.5 million in
2004. The non-standard offer related revenues associated with the
resale of power amounted to $20.2 million in 2002 and is estimated to
be approximately $17.1 million in 2003 and $2.7 million in 2004. This
resale of power is recorded as a component of Off-system Sales in the
Consolidated Statements of Income for 2002. See Note 10 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
$1.4 million, $4.4 million and $4.5 million in revenues from the resale
of power under this contract in 2002, 2001 and 2000, respectively.
These revenues are recorded as a component of Off-system Sales in the
Consolidated Statements of Income.
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 commenced on March 1, 2002, and will continue for a
period of three years. The revenues realized under this contract
(excluding the portion related to the two-year standard offer related
energy supply contract discussed above), as well as the final two
months in 2002 of the previous Chapter 307 sales related contract, were
approximately $5.8 million in 2002, and are estimated to be $8.5
million in 2003, $8.4 million 2004 and $1.4 million in 2005. This
resale of power is recorded as a component of Off-system Sales in the
Consolidated Statements of Income for 2002.
The Company is also party to a power sales contract with another
utility that ends in February 2003. The source of the power to supply
this customer is from a portion of the PERC purchased power contract
and from market purchases. The portion of the power sales contract
associated with market purchases ended in August 2002. The Company
realized $12.3 million, $14.5 million and $14.7 million
of revenues under this contract in 2002, 2001 and 2000, and these
amounts are reflected recorded as a component of Off-system Sales in
the Consolidated Statements of Income.
Rate Recovery - For a discussion of the rate recovery associated with
these power supply commitments, see Note 10.
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, which was financed entirely by new debt
instruments (See Note 5) 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.
Effective with the implementation of new stranded cost rates on March
1, 2002, the amortization period for this regulatory asset was extended
until February 28, 2006, and the annual expense was reduced to $14.2
million.
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 made additional quarterly payments, starting in October 1998, of
$250,000 for four years totaling $4 million. These amounts are
recorded were regulatory assets when the payments were 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, 2002, the Company has deferred, as a regulatory
asset, approximately $27.6 million in costs associated with the PERC
contract restructuring. In its stranded cost rates, the Company is
recovering, over the remaining term of the PERC contract, the full
amount of deferred PERC restructuring costs, including the value of
warrants exercised and the additional $250,000 quarterly payments
discussed above, amounting to an annual amortization of $1.7 million
per year.
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. The regulatory asset is being recovered as
a component of the Company's stranded costs, and the annual amortization
expense amounts to approximately $1.7 million.
Note 9. Fair Value of Financial Instruments
- -------------------------------------------
The following represents the estimated fair value at December 31, 2002
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 $988,752 approximates fair value.
Funds held by trustees, associated with miscellaneous special deposits-
U.S. Treasury Bills: the carrying amount of $1,007,252 approximates
fair value.
The fair values of other financial instruments at December 31, 2002
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 $23,421
First Mortgage Bonds 65,000 83,917
FAME Revenue Notes 55,400 59,693
Senior Unsecured Note 20,000 20,172
Municipal Review Committee Note Payable 11,781 11,769
Short-term debt 16,000 16,000
Note 10. Industry Restructuring and Rate Regulation
- ---------------------------------------------------
In 1997, the Maine legislature enacted a comprehensive law providing
for the restructuring of the electric industry in Maine. The principal
aspects of the law were as follows:
- - Effective March 1, 2000, retail consumers of electricity had the
right to purchase energy supply directly from competitive electricity
suppliers;
- - Electric utilities were required to divest of their generating assets
and restrictions were imposed limiting their participation in
generation and marketing activities;
- - Electric utilities were provided with the opportunity to recover
their prudently incurred stranded costs; and
- - The MPUC was directed to conduct a competitive solicitation process
to select a standard-offer provider to serve the needs of customers
unable to find a competitive supplier or uninterested in doing so.
The Maine restructuring law has essentially been fully implemented.
As a result of the industry restructuring, the Company has been
primarily engaged in the transmission and distribution of electric
energy. Electric rates for the Company's customers are divided into
four components, which are discussed below, (i) transmission, (ii)
distribution, (iii) stranded costs, and (iv) energy service. The rates
charged to customers for transmission, distribution and stranded costs
are established in distinct regulatory proceedings. The Company's
revenues are generated by a delivery charge encompassing transmission,
distribution and stranded costs, and the Company is not presently
involved in supplying energy to retail customers. The delivery charge,
though, continues to be based on customers electricity usage measured
in kilowatt hours ("kWh").
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 began returning this amount to customers starting March 1,
2002 over a two year period in connection with a change in its stranded
cost rates.
DISTRIBUTION SERVICE
Distribution revenues represent approximately 50% of the Company's
total electric operating revenues. On June 6, 2002, the MPUC approved
an Alternative Rate Plan (ARP) and dismissed a pending management
investigation of the Company. The terms of the ARP include a rate plan
to be in effect through December 31, 2007, with the Company's core
distribution rates being adjusted downward on July 1 of each year from
2003 to 2007, at annual rates ranging from 2% to 2 3/4%. The Company
is also allowed rate adjustments associated with certain specified
categories of costs. The ARP also includes a mechanism whereby
distribution returns on common equity below 17% and above 5% in any
given year will be retained by the Company. Earnings in excess of this
range and earnings shortfalls below the range will be shared evenly
between the Company and ratepayers. The Company is also required to
meet certain customer service quality standards during the term of the
ARP, and rate reduction penalties will result from not meeting the
various performance measures as set forth in the stipulation. Finally,
the ARP provides the Company with an accounting order allowing for the
deferral and ten year amortization of employee transition costs during
2002 and 2003 in connection with reductions in the cost of operations.
Successful implementation of the ARP necessitated a significant
decrease in the Company's operating costs, and as a result, the Company
reorganized its operations in 2002. The internal restructuring, which
encompasses all aspects of the Company, has reduced operating costs by
approximately 20%-25%. The Company is also beginning to transfer a
portion of its fixed costs to variable costs, and improve processes to
enhance long-term performance. As part of the restructuring,
employment levels were reduced by approximately 25% in the second and
third quarters of 2002 through early retirement and severance
arrangements. The total employee transition costs incurred in 2002 were
approximately $8.1 million and are recorded as a component of Other
Regulatory Assets on the consolidated balance sheets at December 31,
2002. These deferred costs are being amortized over a ten-year period,
starting in June 2002.
STRANDED COST SERVICE
Stranded cost revenues represent approximately 40% of the Company's
total electric operating revenues. Pursuant to the Maine restructuring
law, electric utilities are entitled to recover all prudently incurred
stranded costs that cannot reasonably be mitigated. In February 2002,
the MPUC issued an order allowing the Company to increase its rates to
recover the stranded costs created as a result of the restructuring of
the electric utility industry in the State of Maine. The stranded cost
rate increase, effective March 1, 2002, resulted in the Company's total
electric rates increasing by approximately 6.5%. The stranded cost
rates are set for a period not to exceed three years, although the
Company has the right to seek adjustments to these rates if certain
economic situations occur. 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.
In connection with the Company's stranded cost rate proceeding with the
MPUC the principal regulatory assets and liabilities being recovered
from/returned to customers as stranded costs are as follows:
- - Maine Yankee decommissioning and other closure costs (See Note 7)
- - Obligations associated with Hydro-Quebec (See Note 7)
- - The cost of energy and capacity associated with the power purchase
contracts, net of revenues from resale (See Note 7)
- - Purchased power contract buyout and restructuring costs (See Note 7)
- - Seabrook investment (See Note 8)
- - Deferred special rate contract revenues (See below in Note 10)
- - Deferred asset sale gain (See Above in Note 10)
- - Deferred standard offer costs (See Below in Note 10)
- - Deferred Maine Yankee replacement power cost write-off (See Note 7)
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. In
2002, for January and February, the Company recorded a regulatory asset
and additional revenues of approximately $.6 million. Effective March
1, 2002, with the implementation of new stranded cost rates, these
deferrals ceased, and the Company began amortizing the deferred special
rate contract revenue regulatory asset balance over a four year period.
Effective March 1, 2002, the Company began recording new special rate
contract revenue deferrals in connection with a new rate contract with
a large industrial customer. The Company is realizing stranded cost
related revenues from this customer that are in excess of amounts
assumed in the latest stranded cost rate proceeding. As a result, and
as ordered by the MPUC, the Company is recording a reduction in the
deferred special rate contract revenue regulatory asset and a reduction
in revenues. The revenue deferrals associated with this customer
amounted to $.5 million for the period from March 2002 to December
2002. The net deferred special rate contract revenue regulatory asset
amounts to $2.5 million at December 31, 2002 and is included as a
component of Other Regulatory Assets in the Consolidated Balance
Sheets.
TRANSMISSION SERVICE
Transmission revenues represent approximately 10% of the Company's
total electric operating revenue. The regulation of electric
transmission has also been undergoing substantial restructuring. In New
England, these changes have included the restructuring of NEPOOL and
the formation of the New England Independent System Operator, ISO-New
England (ISO-NE) in March 1997. ISO-NE is an independent entity operating
under contract with NEPOOL to manage the New England region's electric bulk
power generation and transmission systems and administering the region's
open access transmission tariff. The Company's transmission facilities are
already under the operational control of ISO-New England and rates for retail
transmission service are subject to FERC jurisdiction.
In February 2001, the FERC last issued an order approving transmission
rates for service provided on or after March 1, 2000. Under the FERC
Order approving these transmission rates, a "formula" rate was
approved, allowing the Company to adjust its rates annually to reflect
changes in the Company's costs and its sales volume during the
preceding calendar year. The Company's transmission rate formula will
be subject to review by FERC during 2003. In addition, ongoing FERC
initiatives to restructure the transmission industry may ultimately
result in a different transmission cost recovery structure.
ENERGY SERVICE
The Company is not presently engaged in selling energy to customers.
Pursuant to the Maine restructuring law, all customers have the right
to select a competitive energy supplier to serve their energy
requirements. For customers unable to do so, or uninterested in doing
so, standard offer service is provided by default. The MPUC is
responsible for selecting a standard offer provider through a
competitive solicitation process. The solicitation process is
anticipated to be conducted every three years for residential and small
commercial customers and every year for large commercial and industrial
customers. For the period March 2000 through February 2002, the MPUC
rejected results of the competitive solicitation process for the
Company's customers and directed the Company to arrange for standard
offer service. 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 was
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 exceeded the costs of providing the standard offer
service, and consequently, the Company recorded a regulatory liability.
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. The
deferred balance amounted to approximately $1 million as of December
31, 2002 (which is included in Other regulatory liabilities on the
Consolidated Balance Sheets). Also, as previously discussed, 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 2002, 2001 and
2000 has been modified to reflect the separate presentation of
standard-offer service revenues and purchased power expenses.
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, 2002, the Company has regulatory assets, net of regulatory
liabilities, of approximately $225.7 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 11. 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. The refunds
amounted to approximately $582,000 in 2002, $513,000 in 2001 and
$300,000 in 2000. At the end of 2002, the Company had recorded
approximately $4 million of electric plant in service for these PTF
facilities and a corresponding long-term payable of $3.8 million. The
long-term payable is included on the Consolidated Balance Sheets as a
component of Other Long-term Liabilities.
Note 12. 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, 2002 and 2001 represents
a liability of approximately $63.3 million and $74 million,
respectively. 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.
WEATHER HEDGE - In November 2002 the Company purchased a weather hedge
for the 2002-2003 heating season. The hedge is designed to protect
against the negative impacts of warmer than normal weather on the
Company's electric operating revenues. The cost of the weather hedge
was approximately $87,000 which is being amortized over the 2002- 2003
heating season. No income was recognized for this weather hedge in 2002
due to the colder than normal weather. The fair value of this
financial instrument at December 31, 2002 is de minimis.
Note 13. 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, 2002, the
liability recorded by the Company for its estimated environmental remediation
costs amounted to approximately $411,000. The Company's actual future
environmental remediation costs may be different as additional factors
become known.
Note 14. New Accounting Pronouncement
- --------------------------------------
In June 2002, the Financial Accounting Standards Board issued Statement
No. 143, "Accounting for Asset Retirement Obligations". This Statement
addresses financial accounting and reporting for obligations associated
with the retirement of tangible long-lived assets and the associated
asset retirement costs. It applies to legal obligations associated
with the retirement of long-lived assets that result from acquisition,
construction, development and (or) the normal operation of a long-lived
asset, except for certain obligations of lessees. This Statement is
effective for financial statements issued for fiscal years beginning after
June 15, 2002. Management does not believe that the implementation of this
Statement will materially impact the Company's financial position,
earnings or cash flows, principally as a result of the regulatory
accounting utilized by the Company.
Note 15. 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):
Quarters Ended
-------------------------------------------
Mar. 31, June 30, Sept. 30, Dec. 31,
--------- -------- --------- --------
2002
- ----
Operating Revenues $ 48,645 $ 38,285 $ 40,881 $ 39,927
Operating Income 6,292 4,559 7,008 6,178
Net Income 3,028 1,765 4,301 3,367
Basic Earnings Per Share
of Common Stock $ .40 $ .23 $ .58 $ .45
======== ======== ======== ========
2001
- ----
Operating Revenues $ 56,204 $ 54,003 $ 55,570 $ 51,631
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 $ .61 $ (.04) $ .41 $ .16
======== ======== ======== ========
2000
- ----
Operating Revenues $ 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
======== ======== ======== ========
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, 2002 and 2001, and for the years 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.
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 2002 and 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, 2002 and
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 1 to the consolidated financial statements, in 2002 the
Company adopted Financial Accounting Standards No. 142, "Goodwill and Other
Intangible Assets" and Financial Accounting Standards No. 141, "Business
Combinations".
February 5, 2003 /s/ Ernst & Young LLP
Ernst & Young LLP is a member of Ernst & Young International, Ltd.
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 report on the financial statements for 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 2000 fiscal year and during 2001 prior to the retention
of Ernst & Young, 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. During the two most
recently completed fiscal years or during 2001, PricewaterhouseCoopers (A)
did not advise the Company that the internal controls necessary for the
Company to develop reliable financial statements do not exist; (B) did not
advise the Company that information had come to their attention that had led
them to no longer be able to rely on management's representations, or that
had made them unwilling to be associated with the financial statements
prepared by management; (C) did not advise the Company of the need to expand
significantly the scope of its audit, or that information had come to their
attention during the two most recently completed fiscal years or during 2001,
that if further investigated may: (i) materially impact the fairness or
reliability of either: a previously issued audit report or the underlying
financial statements; or the financial statements issued or to be issued
covering the fiscal period(s) subsequent to the date of the most recent
financial statements covered by an audit report (including information that
may prevent it from rendering an unqualified audit report on those financial
statements), or (ii) cause them to be unwilling to rely on management's
representations or be associated with the Company's financial statements, and
therefore the discontinuation of the retention of PricewaterhouseCoopers did
not prevent such an expansion of the scope of their audit or their ability to
conduct such further investigation; and (D)(1) did not advise the Company
that information had come to their attention that they had concluded
materially impacted the fairness or reliability of either (i) a previously
issued audit report or the underlying financial statements, or (ii) the
financial statements issued or to be issued covering the fiscal period(s)
subsequent to the date of the most recent financial statements covered by an
audit report (including information that, unless resolved to
PricewaterhouseCoopers' satisfaction, would prevent them from rendering an
unqualified audit report on those financial statements), and therefore the
dismissal of PricewaterhouseCoopers' did not prevent the resolution of any
issue that had not been resolved to PricewaterhouseCoopers' satisfaction
prior to discontinuation of the retention of PricewaterhouseCoopers.
By letter to the Company dated as of December 18, 2001, a copy of which was
filed with the Securities and Exchange Commission by the Company as an
Amendment to its 2001 Proxy Statement on February 21, 2002,
PricewaterhouseCoopers stated that it agreed with the Company's statements
relating to the change in accountants that were included in the Company's
Proxy Statement for the annual meeting of shareholders held on December 19,
2001. The Company's statements in that Proxy Statement are identical in all
material respects to the statements contained herein.
Since the appointment of Ernst & Young as the Company's independent auditors
in 2001, the Company has had no disagreements with Ernst & Young regarding
financial disclosure.
PART III
- --------
Item 10 Directors and Executive Officers of the Registrant
- -----------------------------------------------------------
The following is a list of the directors and executive officers of the Company,
and for each a description of the following: (i) current principal occupation
or employment and the name, principal business and address of any corporation
or organization in which the employment or occupation is conducted; (ii)
material occupations, positions, offices or employment during the past five
years, giving the starting and ending dates of each and the name, principal
business and address of any corporation or other organization in which the
occupation, position, office or employment was carried on; and (iii) country
of citizenship.
Unless otherwise noted below, none of the following persons has been convicted
in a criminal proceeding during the past five years (excluding traffic
violations or similar misdemeanors), and none of the following persons has
during the past five years been a party to any judicial or administrative
proceeding (except for matters that were dismissed without sanction or
settlement) that resulted in a judgment, decree or final order enjoining the
person from future violations of, or prohibiting activities subject to, federal
or state securities laws, or a finding of any violation of federal or state
securities laws.
NAME AGE POSITION
- ---- --- --------
David McD. Mann 63 Chairman of the Board
Christopher G. Huskilson 45 Director, Vice Chairman
Jane J. Bush 57 Director
Norman A. Ledwin 60 Director
Elizabeth A. MacDonald 56 Director
Ronald E. Smith 52 Director
Raymond R. Robinson 44 Chief Operating Officer
David R. Black 55 Treasurer, Controller, CFO
David McD. Mann has been a Director and Chairman of the Board since Bangor
Hydro's merger with Emera in October, 2001. Mr. Mann also serves as President
and Chief Executive Officer and Director of Emera Inc. Until July, 1996, Mr.
Mann was a senior partner with the Halifax, Nova Scotia law firm of Cox Downie.
Mr. Mann's business address is 1894 Barrington Street, Halifax, Nova Scotia
B3J 2A8. Mr. Mann is a citizen of Canada.
Christopher G. Huskilson has been a Director and Vice Chairman of the Board
since Bangor Hydro's merger with Emera in October, 2001. Mr. Huskilson also
serves as Chief Operating Officer of Nova Scotia Power Inc., a subsidiary of
Emera. Mr. Huskilson's business address is 1894 Barrington Street, Halifax,
Nova Scotia B3J 2A8. Mr. Huskilson is a citizen of Canada.
Jane J. Bush has been a Director since 1990. Ms. Bush is President and
co-owner of Coastal Ventures, a retailing company. Ms. Bush's business
address is 11 Addison Rd, Columbia Falls, ME 04623. Ms. Bush is a citizen
of the United States.
Norman A. Ledwin has been a Director since 1996. Mr. Ledwin is President and
Chief Executive Officer and a Director of Eastern Maine Healthcare, a health
care organization made up of not-for-profit and for-profit entities (including
Eastern Maine Medical Center, a not-for-profit regional acute care hospital
facility). Mr. Ledwin's business address is 489 State St., Bangor, Maine
04401. Mr. Ledwin is a citizen of the United States.
Elizabeth A. MacDonald has been a Director since Bangor Hydro's merger with
Emera in October, 2001. Ms. MacDonald also serves as Vice President, Human
Resources of Emera. Until November, 2001, Ms. MacDonald was Vice President -
Human Resources of Nova Scotia Power Inc. Ms. MacDonald's business address is
1894 Barrington Street, Halifax, Nova Scotia B3J 2A8. Ms. MacDonald is a
citizen of Canada.
Ronald E. Smith has been a Director since Bangor Hydro's merger with Emera in
October, 2001. Mr. Smith also serves as Chief Financial Officer of Emera. From
September, 1999 to October, 2000, Mr. Smith was an independent consultant. From
March, 1999 to September, 1999, Mr. Smith was Chief Financial Officer,
Telecommunications, for Aliant Inc. Prior to March 1999 was Chief Financial
Officer for Maritime Tel & Tel Co. Ltd. Mr. Smith's business address is 1894
Barrington Street, Halifax, Nova Scotia B3J 2A8. Mr. Smith is a citizen of
Canada.
Raymond R. Robinson has been Chief Operating Officer of Bangor Hydro since
April, 2002. From 2001 until 2002, Mr. Robinson served as Vice President,
Utility Integration for Emera. Prior to 2001, Mr. Robinson served as President
and Chief Executive Officer of Yukon Energy Corporation. Mr. Robinson's
business address is 33 State St., Bangor, Maine 04401. Mr. Robinson is a
citizen of Canada.
David R. Black has been Treasurer and Controller and Chief Financial Officer
of Bangor Hydro since April, 2002. Prior to April, 2002, Mr. Black was
Controller of Bangor Hydro. Mr. Black's business address is 33 State St.,
Bangor, Maine 04401. Mr. Black is a citizen of the United States.
In 2002, the Board met on six occasions.
The Board of Directors has one standing committee, its Audit Committee. The
Audit Committee reviews with the independent public accountants the scope and
results of their audit and other services to the Company, reviews the
adequacy of the Company's internal accounting controls and reports to the
Board at the Directors' meeting following each Audit Committee meeting or as
necessary. The Audit Committee presently consists of Jane J. Bush, who is
Chair of the Committee, Norman A. Ledwin and Ronald E. Smith. Mr. Smith is
not independent under the listing standards of the New York Stock Exchange or
under Section 301 of the Sarbanes-Oxley Act (15 USC Sec. 78f) since he is an
employee of Emera Inc., a parent of the Company. With respect to Mr. Ledwin,
the Board determined that Mr. Ledwin's affiliation with Eastern Maine
Healthcare, which has an indirect business relationship with the Company,
does not interfere with his exercise of independent judgment. The Audit
Committee met five times during 2002. Audit Committee members are appointed
by the Board and the Chair of the Committee is selected by Committee members.
The Board does not have a compensation, investment or nominating committee.
Item 11 Executive Compensation
- ------- ----------------------
The following table shows, for the fiscal years ending December 31, 2002, 2001,
and 2000, the cash compensation paid to the principal executive officer and to
the other executive officers whose total salary and bonus exceeded $100,000:
SUMMARY COMPENSATION TABLE - ANNUAL COMPENSATION
Annual Compensation Long term compensation
---------------------- ------------------------------
Awards Payouts
----------------------
Other ------------
Year Salary Bonus Annual Restricted Securities
All Other
Compen- Stock Underlying LTIP Payouts Compensation
Sation Awards Options/SARs ($) ($)
(#)
(b) (c) (d) (e) (f) (g) (h) (i)
- -----------------------------------------------------------------------------------------------------------------
Carroll R. Lee 2002 $98,654 none none $454,638
President
& Chief
Operating
Officer 2001 190,131 $101,760 $3,400 none
(Retired June
2002) 2000 180,289 $5,029 $3,400 none
- ------------------------------------------------------------------------------------------------------------------
Raymond
Robinson 2002 $117,337 $51,271 $160 17,500* $1,498
Chief Operating
Officer
(Appointed
June
2002)
- ------------------------------------------------------------------------------------------------------------------
David R.
Black 2002 $92,680 $10,243 $2,391
Controller
- ------------------------------------------------------------------------------------------------------------------
Frederick S.
Samp 2002 $49,362 none none $272,743
Vice
President
- - Finance
& Law 2001 138,624 $61,283 $3,400 none
(Resigned
May
2002) 2000 131,206 $3,664 $3,046 none
- ------------------------------------------------------------------------------------------------------------------
Paul A.
LeBlanc 2002 $68,654 none none $249,920
Vice
President
- - Human
Resources 2001 128,066 $51,186 $3,400 none
& Information
Services 2000 121,085 $3,383 $2,800 none
(Retired
June
2002)
- ------------------------------------------------------------------------------------------------------------------
* - The Stock Options granted to Mr. Robinson are for shares of Emera.
Stock Options Granted During the Most Recent Fiscal Year - 2002
- ---------------------------------------------------------------
The following table shows information regarding grants of stock options made
to the Named Executive Officers during the fiscal year ended December 31,
2002. The stock options are granted pursuant to Emera's stock option plan
and are options to purchase the stock of Emera, Inc. granted by Emera, the
Company's ultimate parent. Mr. Robinson is eligible to participate in the
Emera corporate stock option plan as the principal executive officer of a
significant operating subsidiary. Emera's shares are traded on the Toronto
Stock Exchange under the symbol "EMA". Emera shares trade in Canadian
dollars. The exchange rate as of December 31, 2002 was US$1.5796 to
CAN$1.00.
Market Value of
% of Total Securities
Securities Options Exercise or Underlying
Under Granted to Base Options on the
Options Employees Price Date of Grant
Granted in $/Common $/Common Expiration
Name (#) 2002 Share Share Date
<s> <c> <c> <c> <c> <c>
Raymond Robinson 17,500 100%* 16.50 16.50 Feb. 13, 2012
* - Mr. Robinson's 2002 award represents 3.18% of the options granted under
the Emera corporate stock option plan during 2002.
If Mr. Robinson's 2002 options appreciated at 5% per year through February
13, 2012, the potential realizable value of the options in nominal U.S.
dollars would be $94,397.59. If Mr. Robinson's 2002 options appreciated at
10% per year through February 13, 2012, the potential realizable value of the
options in nominal U.S. dollars would be $240,491.90. Each of these
calculations is based upon a December 31, 2002 stock price of CAN$16.05 per
share of Emera common stock and an exchange rate of US$1.5796 to CAN$1.00.
Stock Option Exercises During the Most Recent Fiscal Year - 2002
- ----------------------------------------------------------------
The following table shows information regarding exercise of stock options by
the Named Executive Officers during the fiscal year ended December 31, 2002.
The stock options are options to purchase the stock of Emera, Inc. granted
by Emera, the Company's ultimate parent. Emera shares trade in Canadian
dollars. The exchange rate as of December 31, 2002 was US$1.5796 to
CAN$1.00.
Securities
Acquired Aggregate Unexercised Value of Unexercised
On Value Options at In-the-Money Options at
Exercise Realized December 31, 2002 December 31, 2002
Name (#) ($) (#) ($)
Exercisable Unexercisable Exercisable Unexercisable
<s> <c> <c> <c> <c> <c> <c>
Raymond Robinson 0 0.00 2,500* 25,000* 2,374 7,122
* - Mr. Robinson was awarded 10,000 stock options during 2001 as an employee
of Emera prior to the October, 2001 completion of the Bangor Hydro merger
with Emera.
None of the Named Executive Officers received compensation under a Long Term
Incentive Plan during 2002.
Pension Plan Tables
- -------------------
Mr. Robinson participates in the Emera corporate pension plan. The Pension
Plan Table below sets out the estimated annual benefits payable to
participants in the Emera plan upon retirement at age 60 for the various
salary/years of service combinations as shown. Pension payments and the
average annual compensation upon which the pension payments are determined
are in Canadian dollars. The table is shown in Canadian currency and the
exchange rate as of December 31, 2002 was US$1.5796 to CAN$1.00.
Years of Credited Service at Retirement Age of 60
Remuneration 15 20 25 30 35
_____________________________________________________________________________
($) ($) ($) ($) ($) ($)
100,000 30,000 40,000 50,000 60,000 70,000
200,000 60,000 80,000 100,000 120,000 140,000
300,000 90,000 120,000 150,000 180,000 210,000
400,000 120,000 160,000 200,000 240,000 280,000
500,000 150,000 200,000 250,000 300,000 350,000
600,000 180,000 240,000 300,000 360,000 420,000
700,000 210,000 280,000 350,000 420,000 490,000
800,000 240,000 320,000 400,000 480,000 560,000
Pension benefits paid under this pension plan are based on two percent of the
average of the five highest years' earnings multiplied by each year of
credited service. The pension is payable upon the earlier of:
(i) age 60; or
(ii) age 55, provided that age and years of service add to at least 85.
A member may also retire on a reduced formula provided the member has
attained age 55 but does not qualify for the Rule of 85.
Members of the Emera pension plan contribute 5.4 percent of eligible earnings
up to the year's maximum pensionable earnings ("YMPE") under the Canada
Pension Plan, and seven percent of earnings over the YMPE, to the maximum
amount permitted by Canada Customs and Revenue Agency regulations. Pension
amounts in excess of such regulations do not require employee contributions.
Spousal benefits are paid on the death of a member at the rate of 60 percent
of regular pension benefits. The pension plan is indexed to the consumer
price index to a maximum of six percent per annum. Upon reaching age 65,
pension benefits under the pension plan are reduced to reflect commencement
of payments under the Canada Pension Plan (CPP).
The major portion of the above pension will be provided by the pension plan.
Due to Canada Customs and Revenue Agency's limitations on the maximum
pension benefit which may be paid under the pension plan, a portion of the
pension earned after January 1, 1992 will be provided under the terms of a
Supplementary Employee Retirement Plan which will be secured by a letter of
credit.
Mr. Robinson's benefit service, which includes his service at Emera prior to
assuming his duties with Bangor Hydro, is two years (rounded to the nearest
year).
Mr. Black participates in a tax-qualified defined benefit pension plan that
is also applicable to all Bangor Hydro employees. The following table sets
forth estimated annual benefit amounts payable upon retirement to persons in
specified compensation and benefit service classifications assuming their
retirement at the normal retirement age (65) in 2003.
Years of Benefit Service
- ---------------------------------------------------------------------------
Average Annual
Compensation 5 10 15 20 25 30
$ 50,000 $ 4,339 $ 8,678 $13,016 $17,355 $21,694 $26,033
75,000 6,839 13,678 20,516 27,355 34,194 41,033
100,000 9,339 18,678 28,016 37,355 46,694 56,033
150,000 14,339 28,678 43,016 57,355 71,694 86,033
200,000 14,672 29,344 44,016 58,688 73,361 88,033
Compensation covered by the plan is total basic compensation exclusive of
overtime, bonuses, and other extra, contingent or supplemental compensation,
and is cash compensation plus compensation deferred pursuant to the Company's
Section 401(k) Plan. It is essentially the same as the amount shown as
"Salary" in the Summary Compensation Table above. The annual retirement
benefit is the greater of the following:
a. The benefit accrued as of December 31, 1988 under a prior plan formula.
b. 2.0% "average annual compensation" minus 0.4% of "covered
compensation", times years of "benefit service".
The benefit may not be larger than limits set forth in IRC Section 415.
"Average annual compensation" is computed using the 36 consecutive months
yielding the highest average, and "benefit service" generally means years of
employment after age 21 and one year of service, up to a maximum of 30 years.
"Covered compensation" is the average (without indexing) of the Social
Security Taxable Wage Bases for the 35 calendar years ending with the year an
individual attains Social Security Normal Retirement Age. It is assumed that
the taxable wage base in effect at the beginning of the plan calculation year
will remain the same for all future years. The benefit amount is payable in
a life annuity form in full upon retirement at age 62 and in proportionately
reduced amounts upon termination down to age 55.
In 2002, as part of an amendment to the defined benefit pension plan
applicable to all Bangor Hydro employees designed to implement an early
retirement program, all qualified employees' years of benefit service and
ages were enhanced by five years and three years respectively. This
enhancement increased Mr. Black's age for purposes of the plan to age 57.
Prior to the enhancement, Mr. Black had already reached the maximum 30 years
of benefit service.
Messrs. Lee, Samp, and LeBlanc participated in the tax qualified defined
benefit pension plan applicable to all Bangor Hydro employees at the time of
their respective retirement/resignation from the Company in 2002. In
addition, Messrs. Lee, Samp, and LeBlanc are parties to Supplemental Benefit
Agreements with the Company under which additional retirement benefits are to
be paid. Said agreements define the total pension amount to be paid to the
executive officer by the Company, with the supplemental amount defined as the
difference between this total amount due and the amount due to the executive
officer under the tax qualified pension plan applicable to all employees.
The total amount of pension benefit, as defined under the Supplemental
Benefit Agreements, is a function of the executive officer's age at
retirement and his average total compensation over a three-year period.
Under the Supplemental Benefit Agreements, no pension amount would be due
until the executive officer reaches age 55. At age 55, the executive officer
would be entitled to receive 50% of his or her average total compensation
over a three-year period. The total pension amount to be paid upon
retirement would increase proportionately until a retirement age of 62, at
which point the executive officer would be entitled to receive upon
retirement 75% of his or her average total compensation over a three-year
period.
Pursuant to modifications to his individual agreements prior to his
resignation in 2002, Mr. Samp's age was enhanced from 51 to 53. At the time
of their respective retirements in 2002, Mr. Lee had attained a natural age
of 53 and Mr. LeBlanc had attained a natural age of 54. In addition,
pursuant to the amendment to the tax qualified defined benefit pension plan
applicable to all Bangor Hydro employees designed to implement an early
retirement program, Messrs. Lee, Samp, and LeBlanc each had their benefit
service enhanced by five years and age enhanced by three years, so that their
respective ages and years of benefit service for purposes of this tax
qualified plan at the times of their respective retirement/resignation in
2002, rounded to the nearest year, were as follows: Mr. Lee, age - 56, years
of service - 30 (the maximum); Mr. Samp, age - 54, years of service - 21; and
Mr. LeBlanc, age - 58, years of service - 30 (the maximum).
The following table sets forth estimated annual benefit amounts payable upon
retirement after age 55 to Messrs. Lee, Samp, and LeBlanc under the
Supplemental Benefit Agreements:
Age at Retirement
___________________________________________________________________________
Average Total
Compensation 55 56 57 58 59 60 61 62+
$100,000 $50,000 $53,000 $57,000 $60,000 $64,000 $68,000 $72,000 $75,000
$150,000 75,000 79,500 85,500 90,000 96,000 102,000 108,000 112,500
$200,000 100,000 106,000 114,000 120,000 128,000 136,000 144,000 150,000
$250,000 125,000 132,500 142,500 150,000 160,000 170,000 180,000 187,500
$300,000 150,000 159,000 171,000 180,000 192,000 204,000 216,000 225,000
Compensation covered by the Supplemental Benefit Agreements is total
compensation inclusive of bonuses, and other, contingent or supplemental
compensation, and compensation deferred pursuant to the Company's Section
401(k) Plan.
"Average Total Compensation" under the Supplemental Benefit Agreements is
computed using the average of the total annual compensation actually paid by
the Company to the Executive during the thirty-six consecutive calendar months
in which the Executive's total compensation from the Company was the highest.
The total annual pension amounts shown in the Pension Plan Table above are
payable for the remainder of the executive officer's life after retirement. If
the executive officer's spouse survives the executive officer, the spouse will
receive an annual benefit for the remainder of her life equal to 50% of the
annual benefit to the executive officer. The total annual pension amounts
shown in the Pension Plan Table are not subject to any deduction for Social
Security or other offset amounts.
Employment Contracts
- --------------------
Mr. Robinson is party to an employment agreement with Emera that specifies
his entitlement to salary, participation in compensation plans and other
benefits, and an automobile allowance. In addition, Mr. Robinson is entitled
to a severance payment of 18 months if he is removed from office without just
cause.
Mr. Black is party to an employment agreement with the Company that specifies
his entitlement to salary and participation in benefit plans. Mr. Black is
entitled to receive his salary and benefits for the remaining term of his
employment contract if he is removed from office without cause. Mr. Black's
employment agreement expires March 31, 2003.
Messrs. Lee, Samp, and LeBlanc are parties to agreements under which in the
event 1) of a change of control of the Company as defined in the agreements and
2) the covered party leaves the employment of the Company within one year after
the change of control, he would be entitled to receive a payment equal to two
years' salary based upon his average salary over the past three years. He
would also be entitled to receive the Company's standard health, life
insurance and disability benefits for a period of two years. Based upon the
completion of the Company's merger with Emera Inc., Messrs. Lee, Samp, and
LeBlanc were entitled to receive this benefit upon leaving the employment of
the Company prior to October 10, 2002. The respective retirement/resignation
of Messrs. Lee, Samp, and LeBlanc during 2002 constituted such termination of
employment pursuant to the terms of these agreements.
Compensation of Directors
- -------------------------
Directors who are not employees of the Company, Emera Inc. or other Emera
affiliates are paid a fee of $500 per meeting for attendance at regular or
special meetings of the Board, and $500 per meeting for attendance at
committee meetings (unless the committee meeting is held the same day as
another meeting for which a full meeting fee is paid, in which case the fee
is $250). The directors are also paid an annual retainer of $6,000.
Directors who are employees of the Company, Emera Inc. or other Emera
affiliates receive no fee for their services as directors.
Item 12 Security Ownership of Certain Beneficial Owners and Management
- ------- --------------------------------------------------------------
(a) Security Ownership of Certain Beneficial Owners
As of February 1, 2003, the Company had outstanding 47,340 shares of Preferred
Stock having general voting rights of one vote per share and 7,363,424 shares
of Common Stock having general voting rights of one-twelfth of one vote per
share.
The following table sets forth as of February 1, 2003 information with respect
to persons known to management to be the beneficial owners of more than 5% of
any class of voting securities of the Company:
Title of Class
- ---------------
Common Stock
Name and Address of Beneficial Owner
- ------------------------------------------------
BHE Holdings Inc.
566 Washington Road
Rye, New Hampshire 03870
Amount and Nature of Beneficial Ownership
- ------------------------------------------------------
7,363,424 shares
Percent of Class
- --------------------
100.0% (see (b) below)
(b) Security Ownership of Management
The following table sets forth as of February 1, 2003 information with
respect to the beneficial ownership of equity securities by directors,
nominees for the office of director and named executive officers:
Title of Class Name of Beneficial Owner Beneficially Owned*
- ---------------------------------------------------------------------------
Common Jane J. Bush 1
Common Christopher G. Huskilson 1
Common Norman A. Ledwin 1
Common Elizabeth A. MacDonald 1
Common David McD. Mann 1
Common Ronald E. Smith 1
Common David R. Black 0
Common Raymond R. Robinson 0
Common Directors & Executive
Officers as a group (8) 6
Preferred Directors & Executive
Officers as a group (8) 0
* The directors and executive officers of the Company as a group own a
beneficial interest in less than 1% of the Company's Common and Preferred
Stock.
(c) Changes in Control
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
- ------- ----------------------------------------------
Compensation Committee Interlocks - None. The Company does not have a
compensation committee.
Certain Relationships and Related Transactions - During 2002, the Company
made payments to Eastern Maine Healthcare, its subsidiaries and affiliates,
of $906,655. Mr. Ledwin, who serves on the Board of Directors and the
Board's Compensation Committee, is President, Chief Executive Officer and a
Director of Eastern Maine Healthcare. Eastern Maine Healthcare owns and
operates Eastern Maine Medical Center, the second largest hospital in the
State of Maine and the largest in the region served by the Company, as well
as several other health care organizations in the region. The Company
provides health care benefits to its employees through a self insured managed
care plan. An independent plan administrator negotiates on behalf of the
Company the rates for health care services paid to individual providers under
the plan, including Eastern Maine Healthcare and its affiliates.
PART IV
- -------
Item 14 Controls and Procedures
- ------- -----------------------
During the 90-day period prior to the filing date of this report, management,
including the Company's Principal Executive Officer and Chief Financial
Officer, evaluated the effectiveness of the design and operation of the
Company's disclosure controls and procedures. Based upon, and as of the date
of that evaluation, the Principal Executive Officer and Chief Financial
Officer concluded that the disclosure controls and procedures were effective,
in all material respects, to ensure that information required to be disclosed
in the reports the Company files and submits under the Exchange Act is
recorded, processed, summarized and reported as and when required.
There have been no significant changes in the Company's internal controls or
in other factors that could significantly affect internal controls subsequent
to the date the Company carried out its evaluation.
Item 15 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, 2002, 2001 and 2000
Consolidated Balance Sheets - December 31, 2002 and
2001
Consolidated Statements of Capitalization - December 31, 2002
and 2001
Consolidated Statements of Cash Flows for the Years Ended
December 31, 2002, 2001 and 2000
Consolidated Statements of Common Stock Investment
for the Years ended December 31, 2002, 2001 and 2000
Notes to Consolidated Financial Statements
Report of Independent Accountants
(b) Schedules
Report of Independent Accountants
Schedule II - Valuation and Qualifying Accounts and Reserves
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
Current reports on Form 8-K for the Fourth Quarter of 2002 dated
December 9, 2002 and December 31, 2002 were filed regarding the
Company's announced redemption of its 4% and 4 1/4% series of preferred
stock.
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/ Raymond R. Robinson
-----------------------
By: Raymond R. Robinson
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/ David McD. Mann
- ---------------- -------------------
Jane J. Bush David McD. Mann
Director Chairman of the Board
/s/ Christopher G. Huskilson /s/ Ronald E. Smith
- ---------------------------- -------------------
Christopher G. Huskilson Ronald E. Smith
Vice Chairman, Director Director
/s/ Norman A. Ledwin /s/ David R. Black
- -------------------- ------------------
Norman A. Ledwin David R. Black
Director Treasurer, Controller, CFO
- --------------------------
Elizabeth A. MacDonald
Director
Each of the above signatures is affixed as of March 28, 2003.
CERTIFICATIONS
CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
In connection with the Annual Report of Bangor Hydro-Electric Company (the
Company) on Form 10-K for the year ending December 31, 2002 as filed with the
Securities and Exchange Commission on March 28, 2003, we, the undersigned,
certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section
906 of the Sarbanes-Oxley Act of 2002, that:
(1) The Report fully complies with the requirements of Section 13(a) or
15(d) of the Securities Exchange Act of 1934, and
(2) The information contained in the Report fairly presents, in all
material respects, the financial condition and result of operations
of the Company.
/s/ David R. Black
- ------------------
David R. Black
Chief Financial Officer
March 28, 2003
/s/ Raymond R. Robinson
- -----------------------
Raymond R. Robinson
Principal Executive Officer
March 28, 2003
This certification is made solely for purpose of 18 U.S.C. Section 1350,
subject to the knowledge standard contained therein, and not for any other
purpose.
I, David R. Black, certify that:
1. I have reviewed this annual report on Form 10-K of Bangor Hydro-Electric
Company;
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary
to make the statements made, in light of the circumstances under which
such statements were made, not misleading with respect to the period
covered by this annual report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all
material respects the financial condition, results of operations and cash
flows of the registrant as of, and for, the periods presented in this
annual report;
4. The registrant's other certifying officer and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and
we have:
a) designed such disclosure controls and procedures to ensure that material
information relating to the registrant, including its consolidated
subsidiaries, is made known to us by others within those entities,
particularly during the period in which this annual report is being
prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and
procedures as of a date within 90 days prior to the filing date of this
annual report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the effectiveness
of the disclosure controls and procedures based on our evaluation as of
the Evaluation Date;
5. The registrant's other certifying officer and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent function):
a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have
identified for the registrant's auditors any material weaknesses in
internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls; and
6. The registrant's other certifying officer and I have indicated in this
annual report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal
controls subsequent to the date of our most recent evaluation, including
any corrective actions with regard to significant deficiencies and
material weaknesses.
Date: March 28, 2003
/s/ David R. Black
- ------------------
David R. Black
Chief Financial Officer
I, Raymond R. Robinson, certify that:
1. I have reviewed this annual report on Form 10-K of Bangor Hydro-Electric
Company;
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary
to make the statements made, in light of the circumstances under which
such statements were made, not misleading with respect to the period
covered by this annual report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all
material respects the financial condition, results of operations and cash
flows of the registrant as of, and for, the periods presented in this
annual report;
4. The registrant's other certifying officer and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and
we have:
a) designed such disclosure controls and procedures to ensure that material
information relating to the registrant, including its consolidated
subsidiaries, is made known to us by others within those entities,
particularly during the period in which this annual report is being
prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and
procedures as of a date within 90 days prior to the filing date of this
annual report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the effectiveness
of the disclosure controls and procedures based on our evaluation as of
the Evaluation Date;
5. The registrant's other certifying officer and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent function):
a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have
identified for the registrant's auditors any material weaknesses in
internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls; and
6. The registrant's other certifying officer and I have indicated in this
annual report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal
controls subsequent to the date of our most recent evaluation, including
any corrective actions with regard to significant deficiencies and
material weaknesses.
Date: March 28, 2003
/s/ Raymond R. Robinson
- -----------------------
Raymond R. Robinson
Principal Executive Officer
SCHEDULE II
Valuation and Qualifying Accounts and Reserves
------------------------------------------------------------
Additions
-----------------------------
Balance at Charged to Charged to Balance at
Beginning Costs and Other End
Of Period Expenses Accounts Deductions of Period
------------------------------------------------------ -------------
2002
Reserve for Doubtful Accounts $ 761,000 $1,801,158 $ 249,052 $1,726,158 (A) $1,085,052
---------- ---------- ---------- ---------- ----------
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
---------- ---------- ---------- ---------- ----------
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 Amendment dated May 15, 2002, granting the Board of
Directors authority to repurchase stock and to make equity distributions
to shareholders
3(b) Articles of Amendment dated June 17, 2002, reducing the par value
of the Company's common stock from $5.00 to $0.00.
10. Material Contracts
10(a) Note Purchase Agreement dated as of December 20, 2002 By and Among
the Company and Thrivent Financial for Lutherans
10(b) Amendment No. 4 entered into as of March 29, 2002 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(c) Amendment No. 5 entered into as of September 13, 2002 to the 1998
Amended and Restated Revolving Credit Agreement and Term Loan
Agreement By and Among the Company and Fleet National Bank as Agent
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
3.5 Articles of Merger dated October Form 10-K, 2001, Exhibit 3(a)
10, 2001
3.6 Articles of Amendment dated January Form 10-K, 2001, Exhibit 3(b)
8, 2002, reducing the minimum number
of directors from 9 to 3
3.7 By-Laws of the Company, Amended Form 10-K, 2001, Exhibit 3(c)
and Restated as of December 19, 2001
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 o 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.
10.97 Line Agreement dated as of June Form 10-K, 2001, Exhibit 10(a)
29, 2001 Agreement By and Among
the Company and Fleet National Bank
10.98 Promissory Note dated as of June 29, Form 10-K, 2001, Exhibit 10(b)
2001 Agreement By and Among the
Company and Fleet National Bank 10(a)
10.99 Promissory Note dated as of October Form 10-K, 2001, Exhibit 10(c)
10, 2001 from the Company to the
Municipal Review Committee, Inc.
10.100 Amendment No. 3 entered into as of Form 10-K, 2001, Exhibit 10(b)
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
10.101 Amendment No. 2 dated as of December Form 10-K, 2001, Exhibit 10(b)
31, 2001 to Promissory Note By and
Among the Company and Fleet National
Bank