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