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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
(Mark One)
X QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 1994
OR
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
Commission file number 1-5139
CENTRAL MAINE POWER COMPANY
(Exact name of registrant as specified in its charter)
Incorporated in Maine 01-0042740
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
83 Edison Drive, Augusta, Maine 04336
(Address of principal executive offices) (Zip Code)
207-623-3521
(Registrant's telephone number including area code)
(Former name, former address and former fiscal year, if changed
since last report.)
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 the filing
requirements for at least the past 90 days.
Yes X No
Indicate the number of shares outstanding of each of the
issuer's classes of Common Stock, as of the latest practicable
date.
Shares Outstanding
Class as of November 10, 1994
Common Stock, $5 Par Value 32,442,752<PAGE>
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Central Maine Power Company
INDEX
Page No.
Part I. Financial Information
Consolidated Statement of Earnings for the
Three Months Ended September 30, 1994 and 1993 1
Consolidated Statement of Earnings for the
Nine Months Ended September 30, 1994 and 1993 2
Consolidated Balance Sheet - September 30, 1994 and
December 31, 1993:
Assets 3
Stockholders' Investment and Liabilities 4
Consolidated Statement of Cash Flows for the
Nine Months Ended September 30, 1994 and 1993 5
Notes to Consolidated Financial Statements 6
Management's Discussion and Analysis of Financial
Condition and Results of Operations 20
Part II. Other Information 28<PAGE>
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PART I - FINANCIAL INFORMATION
Item 1. Financial Statements
Central Maine Power Company
CONSOLIDATED STATEMENT OF EARNINGS
(Unaudited)
(Dollars in Thousands Except Per Share Amounts)
For the Three Months
Ended
September 30,
1994 1993
ELECTRIC OPERATING REVENUES $233,543 $227,383
OPERATING EXPENSES
Fuel Used for Company Generation 4,614 8,338
Purchased Power
Energy 110,944 104,615
Capacity 21,687 25,745
Other Operation 34,921 35,949
Maintenance 8,210 9,402
Depreciation and Amortization 13,992 13,254
Federal and State Income Taxes 8,529 2,804
Taxes Other Than Income Taxes 6,416 7,012
Total Operating Expenses 209,313 207,119
EQUITY IN EARNINGS OF ASSOCIATED COMPANIES 1,422 1,359
OPERATING INCOME 25,652 21,623
OTHER INCOME (EXPENSE)
Allowance for Equity Funds Used During
Construction 213 427
Other, Net 850 1,440
Income Taxes Applicable to Other Income
(Expense) (290) 1,615
Total Other Income (Expense) 773 3,482
INCOME BEFORE INTEREST CHARGES 26,425 25,105
INTEREST CHARGES
Long-Term Debt 11,293 10,050
Other Interest 1,176 1,724
Allowance for Borrowed Funds Used During
Construction (127) (230)
Total Interest Charges 12,342 11,544
NET INCOME 14,083 13,561
DIVIDENDS ON PREFERRED STOCK 2,627 2,099
EARNINGS APPLICABLE TO COMMON STOCK $ 11,456 $ 11,462
WEIGHTED AVERAGE NUMBER OF SHARES OF COMMON
STOCK OUTSTANDING 32,442,752 31,916,822
EARNINGS PER SHARE OF COMMON STOCK $0.35 $0.36
DIVIDENDS DECLARED PER SHARE OF COMMON STOCK $0.225 $0.39
The accompanying notes are an integral part of these financial statements.<PAGE>
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Central Maine Power Company
CONSOLIDATED STATEMENT OF EARNINGS
(Unaudited)
(Dollars in Thousands Except Per Share Amounts)
For the Nine Months
Ended
September 30,
1994 1993
ELECTRIC OPERATING REVENUES $686,905 $662,357
OPERATING EXPENSES
Fuel Used for Company Generation 13,685 14,111
Purchased Power
Energy 325,654 299,417
Capacity 56,632 66,491
Other Operation 106,995 108,955
Maintenance 23,035 24,141
Depreciation and Amortization 41,789 39,459
Federal and State Income Taxes 25,988 18,159
Taxes Other Than Income Taxes 19,068 16,672
Total Operating Expenses 612,846 587,405
EQUITY IN EARNINGS OF ASSOCIATED COMPANIES 4,435 4,196
OPERATING INCOME 78,494 79,148
OTHER INCOME (EXPENSE)
Allowance for Equity Funds Used During
Construction 637 1,311
Other, Net (2,236) 3,000
Income Taxes Applicable to Other Income
(Expense) 845 1,571
Total Other Income (Expense) (754) 5,882
INCOME BEFORE INTEREST CHARGES 77,740 85,030
INTEREST CHARGES
Long-Term Debt 33,799 31,853
Other Interest 3,520 5,078
Allowance for Borrowed Funds Used During
Construction (385) (737)
Total Interest Charges 36,934 36,194
NET INCOME 40,806 48,836
DIVIDENDS ON PREFERRED STOCK 7,883 6,459
EARNINGS APPLICABLE TO COMMON STOCK $ 32,923 $ 42,377
WEIGHTED AVERAGE NUMBER OF SHARES OF COMMON
STOCK OUTSTANDING 32,442,292 31,629,986
EARNINGS PER SHARE OF COMMON STOCK $1.01 $1.34
DIVIDENDS DECLARED PER SHARE OF COMMON STOCK $0.675 $1.17
The accompanying notes are an integral part of these financial statements.<PAGE>
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Central Maine Power Company
CONSOLIDATED BALANCE SHEET
(Dollars in Thousands)
Sept. 30, Dec. 31,
1994 1993
(Unaudited)
ASSETS
ELECTRIC PROPERTY, at Original Cost $1,570,979 $1,564,875
Less: Accumulated Depreciation 512,741 503,280
Electric Property in Service 1,058,238 1,061,595
Construction Work in Progress 17,035 19,689
Net Nuclear Fuel 1,347 1,822
Net Electric Property 1,076,620 1,083,106
INVESTMENTS IN ASSOCIATED COMPANIES, at Equity 48,130 47,452
Net Electric Property and Investments in
Associated Companies 1,124,750 1,130,558
CURRENT ASSETS
Cash and Temporary Cash Investments 51,027 1,956
Accounts Receivable, Less Allowances for
Uncollectible Accounts of $2,434 in 1994 and
$2,704 in 1993
Service - Billed 69,135 83,330
- Unbilled 45,560 67,022
Other Accounts Receivable 6,596 10,651
Prepaid Income Taxes 6,881 1,335
Undercollected Retail Fuel Costs 74,209 84,708
Inventories, at Average Cost
Fuel Oil 4,691 6,939
Materials and Supplies 14,024 14,430
Funds on Deposit With Trustee 27,787 27,758
Prepayments and Other Current Assets 12,953 8,008
Total Current Assets 312,863 306,137
DEFERRED CHARGES AND OTHER ASSETS
Recoverable Costs of Seabrook 1 and Abandoned
Projects, Net 104,092 110,443
Regulatory Assets-Deferred Taxes 240,062 237,387
Yankee Atomic Purchased-Power Contract 28,943 32,775
Deferred Charges and Other Assets 286,815 187,562
Total Deferred Charges and Other Assets 659,912 568,167
TOTAL ASSETS $2,097,525 $2,004,862
The accompanying notes are an integral part of these financial statements.<PAGE>
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Central Maine Power Company
CONSOLIDATED BALANCE SHEET
(Dollars in Thousands)
Sept. 30, Dec. 31,
1994 1993
(Unaudited)
STOCKHOLDERS' INVESTMENT AND LIABILITIES
CAPITALIZATION
Common Stock Investment $ 565,319 $ 553,389
Preferred Stock 65,571 65,571
Redeemable Preferred Stock 80,000 80,000
Long-Term Obligations 578,867 581,844
Total Capitalization 1,289,757 1,280,804
CURRENT LIABILITIES AND INTERIM FINANCING
Interim Financing 45,000 68,500
Sinking-Fund Requirements 3,339 3,421
Accounts Payable 73,079 94,417
Dividends Payable 9,932 9,468
Accrued Interest 8,622 12,680
Miscellaneous Current Liabilities 13,288 13,137
Total Current Liabilities and Interim
Financing 153,260 201,623
COMMITMENTS AND CONTINGENCIES
RESERVES AND DEFERRED CREDITS
Accumulated Deferred Income Taxes 370,230 341,349
Unamortized Investment Tax Credits 35,470 36,679
Regulatory Liabilities-Deferred Taxes 52,566 49,734
Yankee Atomic Purchased-Power Contract 28,943 32,775
Other Reserves and Deferred Credits 167,299 61,898
Total Reserves and Deferred Credits 654,508 522,435
TOTAL STOCKHOLDERS' INVESTMENT AND
LIABILITIES $2,097,525 $2,004,862
The accompanying notes are an integral part of these financial statements.<PAGE>
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Central Maine Power Company
CONSOLIDATED STATEMENT OF CASH FLOWS
(Unaudited)
(Dollars in Thousands)
(Note 1) For the Nine Months
Ended
Sept. 30,
1994 1993
CASH FROM OPERATIONS
Net Income $ 40,806 $ 48,836
Items Not Requiring (Providing) Cash:
Depreciation and Amortization 53,825 46,772
Deferred Income Taxes and Investment Tax Credits,
Net 26,511 4,707
Allowance for Equity Funds Used During
Construction (637) (1,311)
Changes in Certain Assets and Liabilities:
Accounts Receivable 39,712 13,349
Other Current Assets (4,974) (28,280)
Inventories 2,654 2,048
Retail Fuel Costs 10,499 3,092
Accounts Payable (19,895) 1,737
Accrued Income Taxes and Interest (9,604) (7,658)
Miscellaneous Current Liabilities 151 (1,113)
Deferred Energy Management Costs (4,017) (4,482)
Maine Yankee Outage Accrual (6,247) (6,380)
Other, Net 5,255 (8,563)
Net Cash Provided By Operating Activities 134,039 62,754
INVESTING ACTIVITIES
Construction Expenditures (29,743) (37,798)
Changes in Accounts Payable - Investing
Activities (1,443) (3,631)
Net Cash Used by Investing Activities (31,186) (41,429)
FINANCING ACTIVITIES
Issuances:
Common Stock 927 19,276
Mortgage Bonds 25,000 185,000
Redemptions:
Short-Term Obligations, Net (25,500) (7,000)
Premium on Redemptions - (8,671)
Preferred Stock - (7,125)
Mortgage Bonds - (150,000)
Other Long-Term Obligations, Net (24,860) (9,368)
Dividends:
Common Stock (21,916) (36,841)
Preferred Stock (7,433) (6,723)
Net Cash Used by Financing Activities (53,782) (21,452)
Net Increase In Cash and Cash Equivalents 49,071 (127)
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD 1,956 926
CASH AND CASH EQUIVALENTS, END OF PERIOD $51,027 $ 799
The accompanying notes are an integral part of these financial statements.<PAGE>
</TABLE>
Central Maine Power Company
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Summary of Significant Accounting Policies
Certain information in footnote disclosures normally included
in financial statements prepared in accordance with generally
accepted accounting principles has been condensed or omitted
in this Form 10-Q pursuant to the rules and regulations of
the Securities and Exchange Commission. However, the
disclosures herein, when read with the Annual Report on Form
10-K for the year ended December 31, 1993 (Form 10-K), are
adequate to make the information presented herein not
misleading.
The consolidated financial statements include the accounts of
Central Maine Power Company (the Company) and its 78
percent-owned subsidiary, Maine Electric Power Company, Inc.
(MEPCO). The Company accounts for its investments in
associated companies not subject to consolidation using the
equity method.
The Company's significant accounting policies are contained
in Note 1 of Notes to Consolidated Financial Statements in
the Company's Form 10-K. For interim accounting periods the
policies are the same. The interim financial statements
reflect all adjustments that are, in the opinion of
management, necessary to a fair statement of results for the
interim periods presented. All such adjustments are of a
normal recurring nature.
For purposes of the statement of cash flows, the Company
considers all highly liquid instruments purchased having
maturities of three months or less to be cash equivalents.
Supplemental Cash Flow Disclosure - Cash paid for interest,
net of amounts capitalized, for the nine months ended
September 30, 1994 and 1993 amounted to $36.7 million and
$38.6 million, respectively. Income taxes paid amounted to
$4.2 million and $14.7 million for the nine months ended
September 30, 1994 and 1993, respectively. The Company
incurred no new capital lease obligations in either period.
2. Commitments and Contingencies
Legal and Environmental Matters - The Company is a party in
legal and administrative proceedings that arise in the normal
course of business. As discussed in Note 4 of Notes to
Consolidated Financial Statements in the Company's Form 10-K,
in connection with one such proceeding, the Company has been
named a potentially responsible party and has been incurring
costs to determine the best method of cleaning up an Augusta,
Maine, site formerly owned by a salvage company and
identified by the Environmental Protection Agency (EPA) as
containing soil contaminated by polychlorinated biphenyls
(PCBs) from equipment originally owned by the Company.
Initial tests on the site have been completed and more
complex technological studies are still in progress. Prior
to the April 1994 change in the cleanup standard discussed
below, the Company believed that its share of the remaining
costs of the cleanup would total between $7 million and $11<PAGE>
million, depending on the level of cleanup ultimately
required and other variable factors. Such estimate was net
of an agreed partial insurance recovery and considered the
court-ordered contributions of 41-percent from Westinghouse
Electric Co. and 12.5 percent from the former owners, but
excluded contributions from the other insurance carriers the
Company has sued, or any other third parties. As a result,
the Company has recorded an estimated liability of $6 million
and an equal regulatory asset, reflecting the anticipated
ratemaking recovery of such costs when ultimately paid.
On April 8, 1994, the EPA announced changes to the remedy it
had previously selected, the principal change being to adjust
the soil cleanup standard to ten parts per million from the
one part per million established in the EPA's 1989 Record of
Decision, on the part of the site where PCBs were found in
their highest concentration. The EPA stated that the purpose
of adjusting the standard of cleanup was to accommodate the
selected technology's current inability to eliminate PCBs and
other chemical components on the site to the original
standard. On July 11, 1994, the EPA formally approved the
previously announced changes.
In September 1994, in connection with the 12.5 percent court-
ordered contribution from the former owners, the Company
agreed to a settlement of all claims against the former
owners and received $15,000 as their 12.5 percent share of
the cleanup costs. The excess of their share above the
$15,000 will be subject to the cost-sharing agreement between
the Company and the insurance company.
Approximately $2.5 million of costs incurred from August 9,
1991, to date have been deferred. Company believes it is now
more probable that its share of the remaining cleanup costs
will total near the lower end of its previously estimated
range of $6 million to $11 million, based on the selected
cleanup method and the new standard, and considering the new
level of third-party contributions as described above. The
Company cannot predict with certainty the level and timing of
the cleanup costs, the extent they will be covered by
insurance, or the ratemaking treatment of such costs, but
believes it should recover substantially all of such costs
through insurance and rates. The Company also believes that
the ultimate resolution of the legal and environmental
proceedings in which it is currently involved will not have a
material adverse effect on its financial condition.
Power Purchase Contract Suit - In December 1992, the Company
terminated a 30-year power-purchase contract with Caithness
King of Maine Limited Partnership (Caithness) for the
purchase of approximately 80 megawatts of electric power from
a cogeneration project proposed for construction by Caithness
at Topsham, Maine. On March 17, 1993, after legal action was
threatened against the Company by Caithness, the Company
instituted a declaratory-judgment action against Caithness
and certain affiliated entities in the United States District
Court for the District of Maine seeking a judicial
confirmation of its right to terminate the contract. On
April 15, 1993, Caithness filed its response to the action,
including counterclaims alleging a breach of the contract by
the Company, among other claims, and seeking damages
estimated by Caithness to be in excess of $100 million or, in<PAGE>
the alternative, reformation of the contract, and other legal
relief.
In January 1994, a termination-and-settlement agreement was
reached between the parties, whereby Caithness would
terminate the project and release all rights, claims,
interests and entitlement thereunder, and the Company would
pay Caithness $5 million in consideration.
On April 4, 1994, the Maine Public Utilities Commission
(MPUC) approved a stipulation in which the Company agreed not
to seek recovery in rates of the costs incurred pursuant to
the termination and buy-out of its purchased-power contract
with Caithness. As a result, $4.5 million of costs not
previously charged to expense were reflected as a reduction
in other income (expense) during the first quarter of 1994.
See Note 3, "Regulatory Matters - Maine Public Utilities
Commission," for further discussion of the stipulation.
3. Regulatory Matters
Maine Public Utilities Commission - Refer to Note 3 of Notes
to Consolidated Financial Statements in the Company's Form
10-K for background on the Company's 1993 base-rate
proceeding.
a. On April 4, 1994, the MPUC approved a stipulation
supported by the Company and other parties to an earlier
proceeding on independent-power-producer contracts and
the Company's 1993 base-rate case. In the stipulation,
the Company agreed to write-off $5 million in purchased-
power costs, to be implemented through a one-time
reduction in its deferred fuel cost balance, and further
agreed not to seek recovery in rates of the approximately
$5.5 million (of which $4.5 million was deferred) in
costs incurred in pursuing the termination and buy-out in
January 1994 of its purchased-power contract with
Caithness. The Company also agreed to withdraw its
appeal to the Maine Supreme Judicial Court (Law Court) of
the MPUC's October 1993 order in its power-contract
investigation, which will have the effect of increasing
the Company's annual base revenues by approximately $4
million, the amount of the stayed one-half percent
return-on-equity penalty previously imposed by the MPUC,
and to withdraw its appeal to the Law Court of the MPUC's
December 1993 decision in the Company's base-rate case.
In return, the stipulation provided that the Company
would be subject to no further prudence investigation,
penalties or disallowances resulting from any actions
prior to March 1, 1994, in any respect in connection with
the two contracts that were the subject of the MPUC's
October 28, 1993 imprudence finding and the Caithness
contract. In the stipulation the parties also agreed
that any further prudence investigation by the MPUC of
the Company's administration of purchased-power contracts
before April 4, 1994, would conclude with the issuance of
a final MPUC order no later than October 1, 1994. Please
refer to section b. below for a discussion of a July 5,
1995 MPUC stipulation approval which resolved the
remaining issues related to this matter.<PAGE>
Finally, in addition to agreement on procedural matters,
the stipulation contained an agreement that the Company
would be subject to no further investigation,
disallowance or other financially adverse consequence
with respect to its administration of its "Capacity
Deficiency Fund" and would not be required to flow
through to ratepayers any amounts previously recorded to
that fund. That provision allowed the Company to
reverse, during the first quarter of 1994, the $4.1
million reserve previously credited, in 1993, against its
deferred fuel-cost balance.
b. On July 5, 1994, the MPUC approved a further stipulation
that provides that the Company will not be subject to any
further investigations, disallowances, or other
financially adverse consequences with respect to its
administration prior to March 22, 1994, of the Company's
larger Non-Utility Generator's (NUG) contracts (over ten
megawatts) totalling approximately 398 megawatts in the
aggregate, that were then being investigated by the MPUC.
In the approved stipulation the Company also agreed to
provide regular reports to the PUC on the status of
renegotiation of its high-cost NUG contracts and to
postpone current recovery of $0.5 million associated with
earned 1991 demand-side-management incentives. The
Company further agreed that it would not seek recovery of
such deferred incentives if its earned rate of return on
common equity exceeds 6.8% in 1994. The Company believes
that the PUC's approval of this stipulation resolves
another of the complex issues that have been posing risks
to the Company since the MPUC's initiation of a general
investigation of the Company's administration of NUG
contracts by its order of October 28, 1993.
c. MPUC Alternative Rate Plan - In its December 14, 1993,
base-rate order, the MPUC ordered that a follow-up
proceeding to the Company's base-rate proceeding be held
to implement by mid-1994 a rate-stability plan (sometimes
hereinafter referred to as an "alternative rate plan" or
"ARP") along the lines discussed in the order. The MPUC
encouraged the Company and the parties electing to
participate in the proceeding to work together to develop
a five-year plan containing price-cap, profit-sharing,
and pricing-flexibility components. The MPUC concluded
that such a plan would be likely to provide a number of
benefits that would outweigh the potential costs. The
Company engaged in discussions with the MPUC staff and
other interested parties over several months in an effort
to reach a consensus on such a plan.
On June 15, 1994, having been unsuccessful in reaching
agreement on some of the substantive issues, the Company
filed a proposed rate stability plan with the MPUC in a
new proceeding, on a schedule calling for a decision on
such a plan in late November of 1994. The plan filed by
the Company contained an index-based price-setting
mechanism, a sharing of excess profits and losses, a
pricing flexibility provision, and an annual review
procedure, among other provisions, and contemplated an
initial term of five years.
After hearings and discussions among the parties, on
October 14, 1994, the Company filed with the MPUC for its<PAGE>
approval a stipulation signed by most of the parties
participating in the ARP proceeding, including, among
others, the MPUC Staff and the Public Advocate. The
stipulation recites that its principal purpose is to
offer the MPUC "a single comprehensive Alternative Rate
Plan consistent with the objectives and guidance set
forth by the [MPUC in its December 14, 1993, base-rate
order]." The stipulation also recites that the parties
are supporting the five-year ARP for reasons that include
". . . potential benefits such as a higher degree of
price stability and predictability, reduced regulatory
costs, stronger incentives for cost minimization, the
shift of risks away from ratepayers, continuation of
comprehensive rate regulation and a form of regulation
that will allow CMP needed flexibility to compete in a
changing electric utility business environment."
The proposed ARP, which is stated in the stipulation to
be effective December 1, 1994, contains a price cap
mechanism that provides for the Company's retail rates to
increase annually on July 1, commencing July 1, 1995, by
a percentage combining (1) a price index, (2) a
productivity offset, (3) a sharing mechanism, and (4)
flow-through items and mandated costs. The price cap
would apply to all of the Company's retail rates,
including the Company fuel-and-purchased power, which
previously had been treated separately. Under the ARP no
separate fuel clause price adjustments would occur.
A specified standard inflation index would be used for
measuring inflation and establishing the basis for each
annual price change. The inflation index would be
reduced by the sum of two productivity factors, a general
productivity offset of 1.0% and a second formula-based
offset starting in 1996 intended to reflect the limited
effect of inflation on the Company's purchased-power
costs during the proposed five-year initial term of the
ARP.
The sharing mechanism would adjust the subsequent year's
July price change in the event the Company's earnings
were outside a range of 350 basis points above or below
the Company's allowed return on equity, starting at the
current 10.55% allowed return and indexed annually for
changes in capital costs. Outside that range, profits
and losses would be shared equally by the Company and
ratepayers. This feature would commence with the price
change of July 1, 1996, and reflect 1995 results.
The proposed ARP also provides for partial flow-through
to ratepayers of cost savings from non-utility generator
contract buy-outs and restructuring, recovery of demand-
side management costs, penalties for failure to attain
customer-service and energy-efficiency targets, and
specific recovery of half the costs of the transition to
Statement of Financial Accounting Standards No. 106
accounting treatment of post-retirement benefits other
than pensions, the remaining 50% to be recovered through
the annual price index increase. The proposed plan also
generally defines mandated costs that would be
recoverable by the Company notwithstanding the index-
based price cap. To receive such treatment a mandated
cost's revenue requirement must exceed $3 million and<PAGE>
must be one that has a disproportionate effect on the
Company or the electric power industry. According to the
stipulation, such costs might include those arising from
special tax, regulatory, and accounting changes, and
natural disasters. As part of the stipulation and in
order to mitigate price pressures, reduce ratepayer risks
and better position itself to achieve timely restoration
of competitive financial results the Company agreed that,
upon approval of the stipulation, it would take the
following before-tax charges against 1994 earnings, at
that time:
(1) the unrecovered balance of its deferred fuel and
purchased-power costs as of December 31, 1994, which
the Company estimates will be approximately $57
million;
(2) the unrecovered balance of deferred demand-side
management costs for 1993 and 1994, which the Company
estimates will be approximately $17 million;
(3) the unrecovered balance of deferred Electric Revenue
Adjustment Mechanism (ERAM) revenues as of December 31,
1994, which the Company estimates will be approximately
$24 million; and
(4) the unrecovered balance of deferred costs related to
the possible extension of the operating life of one of
the Company's generating stations, as of December 31,
1994, which the Company estimates will be approximately
$2.5 million.
On an after-tax basis, these would total approximately
$60 million.
The proposed ARP would provide the Company the benefits
of needed pricing flexibility through the ability to set
prices between defined floor and ceiling levels in three
service categories: (1) existing customer classes, (2)
new customer classes for optional targeted services, and
(3) special-rate contracts. The Company believes that
the added flexibility will position it more favorably to
meet the competition from other energy sources that has
eroded segments of its customer base. Some price
adjustments could be implemented upon 30 days' notice by
the Company, while certain others would be subject to
expedited review by the MPUC.
The stipulation also contains provisions to protect the
Company and ratepayers against unforeseen adverse results
from the operation of the ARP. These include review by
the MPUC if the Company's actual return on equity falls
outside the designated return-on-equity range two years
in a row, a mid-period review of the ARP by the MPUC in
1997 (including possible modification or termination),
and a "final" review by the MPUC in 1999 to determine
whether or with what changes the ARP should continue in
effect after 1999.
Finally, the stipulation states that the parties consider
it to represent an integrated solution to the issues in
the ARP proceeding resulting from a balancing of
competing interests and objectives and that it will be<PAGE>
null and void and not binding on the parties if the MPUC
does not accept it without modification. In a statement
issued contemporaneously with the filing the Company said
the "negotiated ARP required compromises from all parties
but preserved a vital balance..." and that it "offered
[the Company] the opportunity to act more quickly and
competitively in those sectors of our business that are
opening to competition, while continuing MPUC oversight
of the conduct of our traditional responsibilities." The
Company cannot predict whether the MPUC will approve the
stipulation or whether, or in what form, an alternative
rate plan for the Company will result from the MPUC
proceeding. A decision is expected in mid-December 1994.
The Company believes that operation under the ARP and the
stipulation would continue to meet the criteria of
Statement of Accounting Standards No. 71 "Accounting for
the Effects of Certain Types of Regulation" (SFAS No.
71). As a result, the Company will continue to apply the
provisions of SFAS No. 71 to its accounting transactions
and in its future financial statements.
d. On July 18, 1994, the MPUC approved a stipulation entered
into by the Company and other parties providing for an
annual increase of $23.3 million. The increase is
primarily for the fuel cost recoveries except for $0.8
million for recovery of non-utility generator contract
buyout or restructuring costs and $0.6 million in
unrecovered 1991 demand-side management incentives
pursuant to the July 5, 1994 purchased-power contract
prudence stipulation discussed above.
In addition, the approved fuel-related stipulation
provided for an expedited approval process for the
Company to implement new special-rate contracts with
individual customers. The expedited treatment is limited
to contracts totaling in the aggregate not more than 45
megawatts of demand and is subject to other eligibility
criteria, but the Company believes the new approval
process will provide significant flexibility and more
rapid price adjustments in meeting the increased
competition affecting its customer base. The July 18
stipulation approval also resolved other ratemaking and
accounting matters that had been pending before the MPUC.
e. In its Orders dated August 5, 1994 and August 18, 1994,
the Commission approved a stipulation related to the
buyout of the power purchase contract by the Company and
acquisition of a 32 MW wood-generating facility located
in Fort Fairfield, Maine by the Company's subsequently
established subsidiary, Aroostook Valley Electric
Company. The stipulation entered into by the Company and
other parties provides for a rate decrease of $4 million
effective December 1, 1994. The Industrial Energy
Consumer Group (IECG) appealed the Commission's Orders
and, on September 28, 1994, the parties including the
IECG entered into a stipulation which will decrease rates
an additional $1.6 million which, combined with the $4
million rate decrease, will decrease rates by $5.6
million effective December 1, 1994. The Company financed
the buyout and acquisition through the Finance Authority
of Maine (FAME). See "Non-utility Generators" below for
a further discussion of the FAME financing.<PAGE>
Federal Energy Regulatory Commission - Refer to Note 3 of
Notes to Consolidated Financial Statements in the Company's
Form 10-K for background information on the Federal Energy
Regulatory Commission (FERC) order requiring the Company to
revise its rates to a level reflecting the filed cost of
service associated with each of 14 contracts for non-
territorial sales, rather than the negotiated market-based
levels.
The utility that had received the major share of the amount
refunded by the Company pursuant to the original FERC refund
order requested reconsideration of the later FERC rescission
order. In April, 1994, the FERC approved a settlement
agreement filed by the Company and the utility that received
the major share of the original amount refunded by the
Company, that required the Company to make cash payments of
$0.4 million and sales of system power at a discount to that
utility. A similar proposal was negotiated with another
party and approved by the FERC in July 1994. As a result of
these negotiations the Company reflected approximately $0.6
million as a reduction in Electric Operating Revenues during
the first quarter of 1994.
Non-utility Generators - On April 15, 1994, the Governor of
Maine signed into law a bill allowing FAME to borrow up to
$100 million to lend to electric utilities for financing buy-
outs or other changes in NUG contracts that would save money
for customers. The State agency's bonds, which do not pledge
the full faith and credit of the state, would nevertheless,
with similar terms, be likely to bear lower interest rates
than the bonds of the Company with its down-graded credit
rating. All agreements under the new law must be approved by
the MPUC and must be completed by May 1, 1995. The new law
became effective July 14, 1994.
On June 9, 1994, the Company announced that it had agreed to
buy out a NUG contract for a 33-megawatt wood-fired
generating plant in Fort Fairfield, Maine. The Company
agreed to pay $76 million to buy out the contract and $2
million to acquire the generating plant, and anticipated
savings of approximately $44.5 million based on the future
payments that would have been required over the remaining
eight-year life of the contract.
The buyout is part of the Company's plan to stabilize its
rates and improve its competitive position by reducing its
own expenses, cutting NUG costs, and achieving pricing
reforms from the MPUC.
On June 14, 1994, the Company filed an application with the
MPUC, under the new law, for a certificate of approval for
the Fort Fairfield buyout. Several parties, including the
Town of Fort Fairfield, intervened in the MPUC proceeding in
opposition to the Company's application, based largely on the
adverse local impacts of the contemplated closing of the
plant. On August 5, 1994, the MPUC issued an order approving
a stipulation entered into by the Company with the Town of
Fort Fairfield and other intervenors. In approving the
stipulation the MPUC granted its certificate of approval with
the statutory findings required for the FAME financing, and
provided for recovery in rates of the Company's contractual
cost of the buyout. In its negotiated settlement with the
Town of Fort Fairfield incorporated in the stipulation, the<PAGE>
Company agreed to continue operation of the plant for a
minimum of three years, provided that certain plant-
efficiency criteria can be met, and the Town agreed to
support the Company's efforts to obtain the necessary
regulatory and financing approvals, among other
considerations.
The Company has been engaged in discussions with fuel
suppliers and potential purchasers of the output of the plant
in an effort to develop the most cost-effective plan for
continuing operation of the plant. The MPUC's approval of
the stipulation provided for recognition in the Company's
future rates of costs expected to be incurred by the Company
in the operation of the plant, as well as estimated
purchased-power cost savings.
During the third quarter of 1994 the Company recorded a $76
million obligation reflecting its agreement to buy out the
NUG contract. The cost of this buy-out was reflected as a
regulatory asset in accordance with the MPUC's decision to
provide future recovery of the amortization of the cost of
the buy-out over the original life of the contract.
In September 1994, FAME approved the Company's application
for funds to finance the buy-out, pursuant to the new Maine
law. On October 26, 1994 FAME issued $79.3 million of
Taxable Electric Rate Stabilization Revenue Notes Series
1994A (FAME Notes). FAME and the Company entered into a Loan
Agreement under which the Company issued FAME a Note for
approximately $66.4 million, (Company Note) evidencing a loan
in that amount. The proceeds of the loan, along with $13
million of the Company's own funds, were used to buy out the
Fort Fairfield contract. Interest on the Company Note is
paid semi-annually each January 1 and July 1 at an annual
interest rate of 8.16%. The Company Note calls for only
interest payments for the first two years of the note
followed by annual sinking-fund payments from January 1, 1987
through maturity in 2005. The Notes are not subject to
redemption prior to maturity. The remaining $12.9 million of
FAME Notes' proceeds were placed in a Capital Reserve
Account. The amount in the Capital Reserve Account is equal
to the highest amount of principal and interest on the FAME
Notes to accrue and come due in any year the FAME Notes are
outstanding. The amounts invested in the Capital Reserve
Account were initially invested in money-market accounts.
Under the terms of the Loan Agreement, the Company is also
responsible for or receives the benefit from the interest
rate differential and investment gains and losses on the
Capital Reserve Account.
In connection with the buy-out and related purchase of the
generating facility in Fort Fairfield, in October 1994 the
Company formed a wholly-owned subsidiary, Aroostook Valley
Electric Company (AVEC), to own and operate the Fort
Fairfield generating facility in accordance with the terms of
the stipulation discussed above. The Company purchased all
of the common stock of AVEC for $2 million. On October 26,
1994, AVEC paid the former owners of the Fort Fairfield
facility $2 million and took title to the facility. In
connection with the FAME financing, AVEC granted FAME a
mortgage on the facility.<PAGE>
During the third quarter of 1994, the Company reached
agreement with three additional NUGs which give the Company
options to restructure their contracts through periodic
payments, of which approximately $30 million was reflected as
an obligation during the third quarter of 1994. These buy-
outs represent 79 megawatts of capacity and should result in
savings of approximately $39 million over the next five
years.
Wholesale Customer - As previously reported, on July 28,
1993, the Town of Madison Electric Works (Madison), a
wholesale customer of the Company, announced that it had
selected a competitive bid from Northeast Utilities (NU) and
was entering negotiations for NU to become its wholesale
electric supplier for a period of up to ten years. NU, a
Connecticut-based holding company with substantial excess
generating capacity, had submitted a bid to provide up to 45
megawatts of capacity at a rate that would initially be well
below the Company's existing rates. Substantially all of the
45 megawatts would supply the large paper-making facility of
Madison Paper Industries (MPI) in Madison's service territory
that has been served directly by the Company under a special
service agreement with Madison during the last 12 years.
Madison proposed to start taking power from NU in late 1994
for that portion required to serve MPI and in late 1996 for
its remaining requirements.
On May 16, 1994, the Company, Madison and NU entered into a
settlement agreement that resolved, subject to regulatory
approvals, all issues in dispute among the parties relating
to Madison and MPI. Under the agreement, which was filed
with the MPUC as part of a stipulation among the parties to
the agreement and other intervenors in the MPUC proceeding,
the related MPUC and FERC regulatory proceedings were deemed
to be settled among the parties, and the Company withdrew its
request for compensation for stranded investment. In return,
NU agreed to pay the Company $8.4 million over a seven-year
period, MPI agreed to pay the Company $1.4 million over a
three-year period, a transmission rate was agreed upon for
the Company's transmission service to Madison commencing
September 1, 1994, and the parties agreed that Madison would
be supplied by NU through 2003, with Madison having an option
for an additional five years. In addition, NU and the
Company agreed to a five-year capacity exchange arrangement
designed to achieve significant replacement power cost
savings for the Company when the Company's largest source of
generation, the Maine Yankee Atomic Power Company plant, is
off-line. On May 26, 1994, the MPUC approved the
stipulation. The agreement must also be approved by the
FERC. The agreement provides more economic benefit to the
Company than if it had under-bid NU for Madison's business,
but less than if Madison stayed on the Company's system at
the former rates.
The Company will record the amounts received under this
contract as the amounts are received. As discussed above,
the MPUC, in its July 1994 Order in the Company's Fuel Cost
Recovery proceeding, required the Company to allocate the
cash payments, the capacity exchange savings and the
transmission revenues 60% to base non-fuel revenues and 40%
to fuel revenues.<PAGE>
Madison is the largest of the Company's three wholesale
customers. The Company has reached agreement with its other
two wholesale customers to continue to supply them at
negotiated prices and margins that are lower than the
previous averages.
Residents of several small areas in the Company's service
territory have publicly expressed interest in investigating
the feasibility of organizing local electric utility
districts for the purpose of providing their own electric
service with power purchased from a selected supplier. Four
Maine communities voted on November 8, 1994 on questions
regarding the creation of municipal electric districts. In
three of the towns, Westbrook, Norway and Old Orchard Beach,
the proposals were defeated. The fourth, Jay, voted to
create a district, and must, if the town's further
investigation indicates that pursuing a district is feasible,
obtain the approval of the MPUC before furnishing utility
service. The Company believes that such actions are not in
the best interests of either its customers or its investors
and will strongly oppose them. The Company further believes
that formidable obstacles will be encountered by Jay or any
other group in attempting to implement the formation of such
districts, including obtaining the required findings by the
MPUC and economically acquiring or constructing the necessary
facilities for a local utility system. The Company cannot,
however, predict the ultimate results of such initiatives.
4. Capitalization and Interim Financing
On September 28, 1994, the Board of Directors of the Company
adopted a shareholder rights plan and declared a dividend of
one common share purchase right (a Right) for each
outstanding share of the common stock, par value $5.00 per
share, of the Company (the Common Shares). The dividend was
distributed to the shareholders of record as of the close of
business on October 17, 1994. Each Right entitles the
registered holder to purchase from the Company, one Common
Share at an initial purchase price of $40 per Common Share,
subject to adjustment.
The Rights become exercisable or transferrable apart from the
Common Shares, ten business days following a public
announcement that a person or group has acquired beneficial
ownership of, or commences a tender or exchange offer for,
20% or more of the outstanding Common Shares (acquiring
person). The holder of each right not owned by the acquiring
person would be entitled to purchase Common Shares having a
market value equal to two times the exercise price of the
Right (i.e., at a 50% discount).
The purchase price payable and the number of Common Shares
issuable upon exercise of the Rights are subject to
adjustment from time to time and under certain circumstances.
The Rights will expire on the earlier of (i) the close of
business on October 31, 2004, (ii) the time at which the
Rights are redeemed by the Company or (iii) the time at which
the Rights are exchanged for Common Shares at an exchange
ratio of one Common Share per Right, as adjusted by the
Company.<PAGE>
At any time prior to a person or group acquiring 20% or more
of the outstanding common stock, the Board of Directors of
the Company may redeem the then outstanding Rights in whole,
but not in part, at a price of $.01 per Right, subject to
adjustment. The redemption of the rights may be made
effective at such time, on such basis and with such
conditions as the Board of Directors in its sole discretion
may establish. Immediately upon any redemption of the
Rights, the right to exercise the Rights will terminate and
the only right of the holders of Rights will be to receive
the redemption price.
The terms of the Rights may be amended by the Board of
Directors of the Company without the consent of the holders
of the Rights, including, an amendment to lower the threshold
for an Acquiring Person from 20% to not less than the greater
of (i) any percentage greater than the largest percentage of
the outstanding Common Shares then known by the Company to be
beneficially owned by any Person and (ii) 10%.
5. Income Taxes
The effective federal income tax rate for the year ended
December 31, 1993 was 23.5%. For the three and the nine
months ended September 30, 1994 the effective federal tax
rates were 33.4% and 33.8%, respectively. Federal and state
income taxes fluctuate with the level of pre-tax earnings and
the regulatory treatment of taxes by the MPUC. Certain tax
benefits which were reflected as a reduction in tax expense
in the earlier year expired and, therefore, were not
available to reduce tax expenses in the current periods.<PAGE>
Item 2: Management's Discussion and Analysis of Financial
Condition and Results of Operations
Operating Results
Operating revenues increased by $24.5 million or 3.7 percent to
$687 million in the first nine months of 1994 from $662 million
in the first nine months of 1993. Operating revenues for the
third quarter of 1994 of $234 million were 2.7 percent more than
the third quarter of 1993. Revenues reflect rate increases as a
result of the 1993 base rate case, fuel and Electric Revenue
Adjustment Mechanism (ERAM) decisions and a stipulation approved
by the Maine Public Utilities Commission (MPUC) in April 1994.
Net Income for the third quarter of 1994 was $14.1 million
compared to $13.6 million for the third quarter of 1993. Year-
to-date Net Income in 1994 was $40.8 million compared to $48.8
million for the corresponding period in 1993. Earnings
applicable to Common Stock were $11.5 million or $0.35 per share
for the three months ended September 30, 1994 and $11.5 million
or $0.36 per share for the comparable period in 1993. Year-to-
date earnings applicable to Common Stock in 1994 were $32.9
million or $1.01 per share and $42.4 million or $1.34 per share
in 1993. Weak sales due to economic and competitive pressures,
the impact of a disappointing rate case decision in December
1993, higher taxes and the April 1994 stipulation discussed
below, are the primary factors affecting the decline in year-to-
date earnings.
Average shares outstanding increased due to the issuance of 0.4
million shares since September 1993 through the Company's
Dividend Reinvestment and Common Stock Purchase Plan. Effective
January 1994, the Company elected to purchase shares pursuant to
the plan on the market, rather than issue new shares.
The combination of low sales growth on a year-to-date basis, due
to economic and competitive pressures, and an inadequate rate
case decision in December 1993, offer the Company no reasonable
opportunity to achieve a level of 1994 earnings near the 1993
level or its currently allowed rate of 10.55 percent on common
equity. The reduction in the Company's earnings capacity for the
near term takes into account the significant reductions in
previously planned 1994 operation, maintenance and capital
expenditures.
The Company continues its objectives of seeking cost reductions
and cost control, restructuring prices, achieving price
flexibility to enhance its ability to compete for sales and
seeking rate recovery of the costs of providing electric service.
In another move towards this goal, the Company and other parties
have filed a stipulation with the MPUC proposing an Alternate
Rate Plan that would limit annual price increases with an
inflation-based index and provide the Company with pricing
flexibility. The Alternate Rate Plan, which is discussed in Note
3 to Consolidated Financial Statements, if approved, would result
in the recognition, at the time of approval, of certain charges
that would result in a net loss for the current year.
As discussed further in Note 3 to Consolidated Financial
Statements "Regulatory Matters - Maine Public Utilities
Commission," on April 4, 1994, the MPUC unanimously approved a
negotiated settlement of a two-year-old dispute over the<PAGE>
Company's administration of contracts with non-utility generators
(NUGs). The stipulation required a one-time $5 million write-off
of unrecovered fuel costs, precluded recovery of $4.5 million of
the costs of terminating the Caithness King NUG contract and
permitted retention of $4.1 million of payments associated with
the capacity deficiency fund. As a result, earnings for the nine
months ended September 30, 1994 reflect a net reduction of $3.5
million before taxes, or approximately $2.0 million or $0.06 per
share after taxes. During the first twelve months, the
stipulation will result in a net reduction in earnings of $1.5
million before taxes, or approximately $900,000 or $0.03 per
share after taxes.
The Company believes that the approval of the stipulation by the
MPUC resolved or limited a number of complex issues that were
posing significant risks to the Company.
Service-area sales of electricity totaled approximately 7.0
billion kilowatt-hours for the nine-month period ended September
30, 1994, an increase of 0.8% over the first nine months of 1993.
Service-area sales for the third quarter of 1994 totaled
approximately 2.3 billion kilowatt-hours, which were 0.4 % more
than the third quarter of 1993.
<TABLE>
<S> <C> <C> <C> <C> <C> <C>
Service Area Kilowatt-hour Sales (Millions of KWHs)
Period Ended September 30,
Three Months Nine Months
%
1994 1993 % Change 1994 1993 Change
Residential 653.5 645.7 1.2% 2,196.2 2,191.7 0.2%
Commercial 651.1 624.7 4.2 1,871.8 1,801.4 3.9
Industrial 966.1 990.9 (2.5) 2,827.8 2,849.2 (0.8)
Other 37.1 38.1 (2.7) 116.2 115.6 0.4
Total 2,307.8 2,299.4 0.4% 7,012.0 6,957.9 0.8%
</TABLE>
The changes in service area kilowatt-hour sales reflect the
following:
Kilowatt-hour sales to residential customers increased by
1.2% in the third quarter and 0.2% for the nine months
ended September 30, 1994 compared to 1993; while the
number of customers increased approximately 1%, usage per
customer was down 0.8%, with a decline in the space and
water heating subclass usage continuing during the first
nine months of 1994.
Commercial sales increased by 4.2% in the third quarter
and 3.9% for the nine months ended September 30, 1994 from
1993 due primarily to increases in the service, retail and
wholesale sectors' usage while sales in the other sectors
increased also. Sales to the service sector comprise
approximately 31% of the Company's commercial sales.
Industrial kilowatt-hour sales decreased by 2.5% in the
third quarter and 0.8% for the nine months ended September<PAGE>
30, 1994 over 1993. Sales to the pulp and paper industry
decreased by 2.8% for the third quarter and by 1.2% year-
to-date 1994. The decline in sales on a quarterly and
year-to-date basis to this industry was due primarily to
higher than normal purchases in January 1993, and the
addition of 10 megawatts of generation by one customer in
March 1993 and, as discussed in Note 3 to Consolidated
Financial Statements "Regulatory Matters - Wholesale
Customer", Madison Paper Industries going off the
Company's system beginning in September 1994. The pulp
and paper industry accounts for approximately 60% of the
industrial sales category. A sales increase of 0.2% over
the first nine months of 1993 occurred to all other
industrial customers as a group. <PAGE>
The components of the change in electric operating revenues for
the nine months ended September 30, 1994, as compared to the same
period in 1993, are as follows:
<TABLE>
<S> <C> <S> <C> <C>
Three Nine
Months Months
(Dollars in Millions)
Revenues from Kilowatt-hour Sales:
Total Service-Area Base Revenue $ 8.0 $ 22.9
Fuel Cost Recoveries 3.1 20.8
Non-Territorial Base Revenue 0.7 1.9
Revenues from Kilowatt-hour Sales 11.8 45.6
Other Operating Revenues:
Electric Revenue Adjustment
Mechanism Including
Revenue Adjustment-Tax Flowback (3.3) (17.8)
Other, including Maine Electric
Power Company, Inc. (2.3) (3.3)
Total Change in Electric Operating
Revenues $ 6.2 $ 24.5
</TABLE>
Total service-area base revenues increased for the third quarter
and first nine months of 1994 reflecting slightly higher
kilowatt-hour sales, the July 1993 increase in rates to continue
collection of accrued ERAM revenue and the increase of $26.2
million pursuant to the MPUC's base rate case decision effective
December 1, 1993. Fuel Revenue increases reflect a fuel cost
adjustment increase effective August 1, 1994 of $21.9, annually,
and the changes discussed below relating to Fuel Used for Company
Generation and Purchased-Power Energy expense. Other revenues
reflect the elimination of ERAM accruals, effective December 1,
1993.
The Company's Fuel Used for Company Generation and Purchased
Power-Energy expenses are recoverable through approved fuel
tariffs while Purchased Power-Energy incurred by Maine Electric
Power Company, Inc. (MEPCO) is billed to MEPCO's Participants.
The Company's Fuel Used for Company Generation, which consists
primarily of Company-owned oil-fired generation, decreased by
$3.7 million in the third quarter of 1994 over the third quarter
of 1993 and by $0.4 million for the nine-month period ended
September 30, 1994. Compared to 1993, total oil-fired megawatt-
hour generation decreased by 45.3% in the third quarter of 1994
but increased by 5.2% year-to-date 1994. The cost of this
generation on a per megawatt-hour basis was 3.2% lower for the
third quarter and 9.0% lower for the nine months ended September
30, 1994, as a result of decreases in the price of oil purchased.<PAGE>
The Company's Purchased Power-Energy expense increased by $6.3
million in the third quarter and by $26.2 million for the nine
months ended September 30, 1994 due primarily to purchases from
non-utility generators. Total megawatt-hour purchases increased
by 32 megawatt-hours and 160 megawatt-hours over the prior year
quarter and prior year-to-date. The cost of this energy on a per
megawatt-hour basis increased by 3.2% for the third quarter and
by 5.4% for the first nine months of 1994, respectively,
primarily due to pre-set price increases.
Purchased-Power Capacity expense decreased $4.1 million and $9.9
million when compared to the third quarter and the nine months
ended September 30, 1993. The decrease is primarily related to
the $4.1 million reserve recorded during the third quarter of
1993 to reflect the expectation, at that time, that the Company
would be required to refund that amount of "Capacity Deficiency
Fund". The reserve was reversed during the first quarter of
1994. See the further discussion of this matter in Note 3 to
Consolidated Financial Statements "Regulatory Matters - Maine
Public Utilities Commission".
Other Operation and Maintenance expenses decreased by $2.2
million and $3.1 million compared to the third quarter and first
nine months of 1993. Despite reflecting severance costs
associated with restructuring plans in early 1994 which
eliminated 225 full-time equivalent positions, increases in
expenses of the Electric Lifeline Program (the MPUC-mandated low-
income energy assistance program) and other planned cost
increases, ongoing cost control activities directed toward
limiting growth in this area are continuing.
Federal and state income taxes fluctuate with the level of pre-
tax earnings and the regulatory treatment of taxes by the MPUC
and increased by $7.6 million and $8.6 million for the third
quarter and year-to-date 1994, respectively. Certain tax
benefits which were reflected as a reduction in tax expense in
the earlier year expired and therefore were not available to
reduce tax expenses in the current periods.
Interest on long-term debt increased $1.2 million for the third
quarter of 1994 and $1.9 million for the nine months ended
June 30, 1994 while other interest expense decreased by $0.5
million and $1.6 million for the third quarter and year-to-date
period ended September 30, 1994, respectively. These changes are
the result of converting short-term borrowing into long-term debt
and an increase in total debt outstanding and slightly higher
overall interest rates.
Liquidity and Capital Resources
Approximately $120.5 million of cash was provided during the
first nine months of 1994 from net income before non-cash items,
primarily depreciation and amortization. During such period,
approximately $13.5 million of cash was provided by fluctuations
in certain assets and liabilities and from other operating
activities.
In April 1994, the Company issued $25 million of Series U 7.45%
(Adjustable Rate) General and Refunding Mortgage Bonds, due 1998,
through a private placement. The Series U Bonds do not have a
sinking fund requirement and are redeemable at the option of the
Company under certain circumstances. Also during the first nine
months of 1994 the Company reduced the level of short-term<PAGE>
borrowing outstanding by $25.5 million and reduced the level of
other long-term obligations by $24.9 million. Dividends paid on
common stock were $21.9 million, while preferred-stock dividends
utilized $7.4 million of cash.
Refer to Note 3 to Consolidated Financial Statements, "Regulatory
Matters - Non-Utility Generators", for a discussion of the
financing entered into with the Finance Authority of Maine
related to the buy-out of one of the Company's non-utility
generator contracts.
Investing activities, primarily construction expenditures,
utilized $31.2 million in cash during the first nine months of
1994 for generating projects, transmission, distribution, and
general construction expenditures.
In order to accommodate existing and future loads on its electric
system the Company is engaged in a continuing construction
program. The Company's plans for improvements and expansions,
its load forecast and its power resources are under a process of
continuing review. Actual construction expenditures will depend
upon the availability of capital and other resources, load
forecasts, customer growth and general business conditions.
In June 1994, the Company entered into an agreement with a large
institutional investor under which the investor agreed to
purchase from the Company up to $25 million of additional General
and Refunding Mortgage Bonds on or before April 15, 1995, subject
to certain terms and conditions. Bonds issued pursuant to the
agreement must be due on or before April 15, 1998.
The ultimate nature, timing and amount of financing for the
Company's total construction programs, refinancing and
energy-management capital requirements will be determined in
light of market conditions, earnings and other relevant factors.
To support its short-term capital requirements, the Company
maintains an unsecured $50-million revolving credit agreement
with several banks that can be used to support commercial paper
borrowing or as short-term financing. However, access to
commercial paper markets has been substantially reduced, if not
eliminated, as a result of the downgrading of the Company's
credit ratings during 1993. The amount of outstanding short-term
borrowing will fluctuate with day-to-day operational needs, the
timing of long-term financing, and market conditions.
On November 9, 1994, the Company entered into a Competitive
Advance and Revolving Credit Facility (Revolving Credit
Facility), with several banks and Chemical Bank, as agent for the
lenders, to provide up to $80 million of revolving credit loans.
The Revolving Credit Facility supplements the existing $50
million revolving-credit agreement and replaces the Company's $73
million of individual lines of credit. The revolving credit
loans under the Revolving Credit Facility may consist of
"Eurodollar Loans" or "ABR Loans", or a combination thereof.
Borrowings of Eurodollar Loans would bear an interest rate based
on average rates offered in the interbank eurodollar market.
Borrowings of ABR Loans would bear interest at the higher of the
Prime Rate, a certificate of deposit rate plus 1%, or the Federal
Funds Rate plus 1/2 of 1%.
The revolving Credit Facility has a term of 364 days. However,
it can be terminated 90 days after the Company's Standard &<PAGE>
Poor's Rating Group (S&P) rating falls below "BB+" or the
Company's Moody's Investors Service, Inc. (Moody's) rating falls
below "Baa3" or the Company's Duff & Phelps Credit Rating Company
(D&P) rating falls below "BBB-", and the condition still exists
on the 90th day.
The annual fees on the Revolving Credit Facility range from .375%
to .5% of the unused portion of the commitment, depending on the
S&P, Moody's and D&P ratings.
The last credit-rating action relating to the Company's
securities was announced on April 6, 1994, when S&P revised its
outlook on the Company's securities from "negative" to "stable"
and affirmed its ratings on the Company's senior secured debt at
"BB+", its senior unsecured debt at "BB-", its preferred stock at
"B+" and its commercial paper at "B". S&P cited the MPUC's April
4, 1994 approval of the stipulation resolving uncertainty
relating to purchased-power contract investigations as a reason
for the revision.
The Company has been engaging in discussions with its 32 largest
customers with the objective of entering into multi-year rate
agreements that would ensure retention of those customers. These
large customers have competitive options that the Company
believes must be addressed by lowering the tariff (i.e., price)
to a competitive level. The Company expects that such agreements
will lower the revenue contribution of these customers. The
Company cannot predict the results of those discussions, but
implementation of such agreements is dependent on effectiveness
of the ARP.
With the advent of the municipalization initiatives in the
Company's service territory and the continued focus of the
electric utility industry on the potential costs and benefits of
retail wheeling, the Company has become increasingly concerned
with the possibility that certain costs incurred for the benefit
of its customers would not be recoverable when customers leave
its system for power-supply competitors or otherwise (stranded
investment). Both the FERC and the MPUC have initiated
proceedings on the stranded investment issue, with the MPUC
rulemaking proceeding scheduled to conclude in the Spring of
1995. The Company cannot predict the outcome of the
jurisdictional questions between the FERC and the state
regulatory commissions involved in stranded-investment issues,
nor can it predict the results of those proceedings. <PAGE>
PART II - OTHER INFORMATION
Item 1. Legal Proceedings
Environmental Matters. For a discussion of administrative
and judicial proceedings concerning cleanup of a site
containing soil contaminated by PCB's from equipment
originally owned by the Company, see Note 2, "Commitments
and Contingencies," "Legal and Environmental Matters,"
which is incorporated herein by reference.
Alternative Rate Plan. Reference is specifically made to
Note 3, "Regulatory Matters," Section, "Alternative Rate
Plan," for a discussion of a stipulation before the Maine
Public Utilities Commission that, if adopted, would
revise the existing system of retail rate regulation for
the Company and cause the Company to take material
charges against earnings in the period the stipulation is
adopted.
Regulatory Matters. For a discussion of certain other
regulatory matters affecting the Company, see Note 3,
"Regulatory Matters," which is incorporated herein by
reference.
Items 2. through 5. Not applicable
Item 6. Exhibits and Reports on Form 8-K
(a) Exhibits. None.
(b) Reports on Form 8-K. The Company filed the following
reports on Form 8-K during the third quarter of 1994 and
thereafter to date:
Date of Report Items Reported
July 5, 1994 Item 5
(a) Approval of Stipulation in Power Contracts Prudence
Investigation. On July 5, 1994 the PUC approved a
stipulation that provided that the Company would not be
subject to any further investigations, disallowances, or
other financially adverse consequences with respect to
administration prior to March 22, 1994, of its
administration of its large non-utility generator
contracts that were being investigated.
(b) Approval of Fuel Cost Adjustment Stipulation. On
July 18, 1994, the MPUC approved a stipulation entered
into by the Company and other parties providing for an
annual fuel revenue increase of $23.3 million.
In addition, the approved fuel-related stipulation
provides for an expedited approval process for the
Company to implement new special-rate contracts with
individual customers.
Date of Report Items Reported
October 14, 1994 Item 5<PAGE>
On October 14, 1994, the Company filed with the Maine
Public Utilities Commission (the "PUC")for its approval a
stipulation approved by most of the parties to an ongoing
proceeding on an Alternative Rate Plan ("ARP").
Date of Report Items Reported
October 17, 1994 Item 5
On September 28, 1994, the Board of Directors of The
Company adopted a shareholder rights plan and declared a
dividend of one common share purchase right (a "Right")
for each outstanding share of common stock, payable to
shareholders of record as of the close of business on
October 17, 1994.<PAGE>
Signatures
Pursuant to the requirements of the Securities Exchange Act of
1934, the registrant has duly caused this report to be signed on
its behalf by the undersigned thereunto duly authorized.
CENTRAL MAINE POWER COMPANY
(Registrant)
Date: November 10, 1994 /S/R. S. Howe
R. S. Howe, Comptroller (Chief Accounting
Officer)
/S/D. E. Marsh
David E. Marsh, Vice President, Corporate
Services, and Chief Financial Officer
(Principal Financial Officer and duly
authorized officer)<PAGE>
<TABLE> <S> <C>
<ARTICLE> UT
<LEGEND>
This schedule contains summary financial information extracted from Central
Maine Power Company's Form 10-Q for the period ended September 30, 1994 and is
qualified in its entirety by reference to such financial statements.
</LEGEND>
<S> <C>
<PERIOD-TYPE> QTR-3
<FISCAL-YEAR-END> DEC-31-1993
<PERIOD-END> SEP-30-1994
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 1,076,620
<OTHER-PROPERTY-AND-INVEST> 48,130
<TOTAL-CURRENT-ASSETS> 312,863
<TOTAL-DEFERRED-CHARGES> 659,912
<OTHER-ASSETS> 0<F1>
<TOTAL-ASSETS> 2,097,525
<COMMON> 162,214
<CAPITAL-SURPLUS-PAID-IN> 275,457
<RETAINED-EARNINGS> 127,648
<TOTAL-COMMON-STOCKHOLDERS-EQ> 565,319
80,000
65,571
<LONG-TERM-DEBT-NET> 537,445
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 45,000
0
<CAPITAL-LEASE-OBLIGATIONS> 41,422
<LEASES-CURRENT> 3,339
<OTHER-ITEMS-CAPITAL-AND-LIAB> 759,429
<TOT-CAPITALIZATION-AND-LIAB> 2,097,525
<GROSS-OPERATING-REVENUE> 686,905
<INCOME-TAX-EXPENSE> 25,988
<OTHER-OPERATING-EXPENSES> 586,868
<TOTAL-OPERATING-EXPENSES> 612,846
<OPERATING-INCOME-LOSS> 78,494
<OTHER-INCOME-NET> (754)
<INCOME-BEFORE-INTEREST-EXPEN> 77,740
<TOTAL-INTEREST-EXPENSE> 36,934
<NET-INCOME> 40,806
7,883
<EARNINGS-AVAILABLE-FOR-COMM> 32,923
<COMMON-STOCK-DIVIDENDS> 21,916
<TOTAL-INTEREST-ON-BONDS> 30,761
<CASH-FLOW-OPERATIONS> 134,039
<EPS-PRIMARY> 1.01
<EPS-DILUTED> 1.01
<FN>
<F1>Other Assets are included in "Deferred Charges and
Other Assets" on the Balance Sheet.
</FN>
</TABLE>
