<TABLE>
<S> <C> <C> <S>
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, 1995
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 as
Class of November 10, 1995
Common Stock, $5 Par Value 32,442,752<PAGE>
</TABLE>
Central Maine Power Company
INDEX
<TABLE>
Page No.
Part I. Financial Information
<S> <C> <S> <C> <C>
Consolidated Statement of Earnings for the Three Months
Ended September 30, 1995 and 1994 1
Consolidated Statement of Earnings for the Nine Months
Ended September 30, 1995 and 1994 2
Consolidated Balance Sheet - September 30, 1995 and
December 31, 1994:
Assets 3
Stockholders' Investment and Liabilities 4
Consolidated Statement of Cash Flows for the Nine Months
Ended September 30, 1995 and 1994 5
Notes to Consolidated Financial Statements 6
Management's Discussion and Analysis of Financial
Condition and Results of Operations 12
Part II. Other Information 18<PAGE>
</TABLE>
<TABLE>
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,
1995 1994
<S> <C> <C>
ELECTRIC OPERATING REVENUES $217,872 $233,543
OPERATING EXPENSES
Fuel Used for Company Generation 5,887 4,614
Purchased Power
Energy 99,221 110,944
Capacity (Note 2) 18,631 21,687
Other Operation 41,750 34,921
Maintenance 7,021 8,210
Depreciation and Amortization 13,315 13,992
Federal and State Income Taxes 4,260 8,529
Taxes Other Than Income Taxes 7,390 6,416
Total Operating Expenses 197,475 209,313
EQUITY IN EARNINGS OF ASSOCIATED COMPANIES 1,772 1,422
OPERATING INCOME 22,169 25,652
OTHER INCOME (EXPENSE)
Allowance for Equity Funds Used
During Construction 173 213
Other, Net 1,802 850
Income Taxes Applicable to Other
Income (Expense) (476) (290)
Total Other Income (Expense) 1,499 773
INCOME BEFORE INTEREST CHARGES 23,668 26,425
INTEREST CHARGES
Long-Term Debt 12,371 11,293
Other Interest 1,040 1,176
Allowance for Borrowed Funds Used
During Construction (143) (127)
Total Interest Charges 13,268 12,342
NET INCOME 10,400 14,083
DIVIDENDS ON PREFERRED STOCK 2,518 2,627
EARNINGS APPLICABLE TO COMMON STOCK $ 7,882 $ 11,456
WEIGHTED AVERAGE NUMBER OF COMMON SHARES
OUTSTANDING 32,442,752 32,442,752
EARNINGS PER SHARE OF COMMON STOCK $ 0.24 $0.35
DIVIDENDS DECLARED PER SHARE OF COMMON STOCK $0.225 $0.225
The accompanying notes are an integral part of these financial
statements./TABLE
<PAGE>
Central Maine Power Company
CONSOLIDATED STATEMENT OF EARNINGS
(Unaudited)
(Dollars in Thousands Except Per Share Amounts)
<TABLE>
<S> <C> <C>
For the Nine Months Ended
September 30,
1995 1994
ELECTRIC OPERATING REVENUES $683,768 $686,905
OPERATING EXPENSES
Fuel Used for Company Generation 15,441 13,685
Purchased Power
Energy 305,925 325,654
Capacity (Note 2) 73,799 56,632
Other Operation 131,227 106,995
Maintenance 21,960 23,035
Depreciation and Amortization 41,629 41,789
Federal and State Income Taxes 12,695 25,988
Taxes Other Than Income Taxes 20,759 19,068
Total Operating Expenses 623,435 612,846
EQUITY IN EARNINGS OF ASSOCIATED COMPANIES 5,249 4,435
OPERATING INCOME 65,582 78,494
OTHER INCOME (EXPENSE)
Allowance for Equity Funds Used
During Construction 483 637
Other, Net 4,748 (2,236)
Income Taxes Applicable to Other
Income (Expense) (1,719) 845
Total Other Income (Expense) 3,512 (754)
INCOME BEFORE INTEREST CHARGES 69,094 77,740
INTEREST CHARGES
Long-Term Debt 37,988 33,799
Other Interest 3,348 3,520
Allowance for Borrowed Funds Used
During Construction (399) (385)
Total Interest Charges 40,937 36,934
NET INCOME 28,157 40,806
DIVIDENDS ON PREFERRED STOCK 7,659 7,883
EARNINGS APPLICABLE TO COMMON STOCK $ 20,498 $ 32,923
WEIGHTED AVERAGE NUMBER OF COMMON
SHARES OUTSTANDING 32,442,752 32,442,292
EARNINGS PER SHARE OF COMMON STOCK $0.63 $1.01
DIVIDENDS DECLARED PER SHARE OF
COMMON STOCK $0.675 $0.675
The accompanying notes are an integral part of these financial
</TABLE>
statements.<PAGE>
Central Maine Power Company
CONSOLIDATED BALANCE SHEET
(Dollars in Thousands)
<TABLE>
<S> <C> <S> <C> <C>
Sept. 30, Dec. 31,
1995 1994
(Unaudited)
ASSETS
ELECTRIC PROPERTY, at Original Cost $1,600,637 $1,579,632
Less: Accumulated Depreciation 550,178 521,645
Electric Property in Service 1,050,459 1,057,987
Construction Work in Progress 16,942 13,647
Net Nuclear Fuel 1,563 2,181
Net Electric Property and Nuclear Fuel 1,068,964 1,073,815
INVESTMENTS IN ASSOCIATED COMPANIES, at Equity 53,682 49,602
Net Electric Property, Nuclear Fuel
and Investments in Associated
Companies 1,122,646 1,123,417
CURRENT ASSETS
Cash and Temporary Cash Investments 61,695 58,112
Accounts Receivable, Less Allowance for
Uncollectible Accounts of $3,310 in 1995
and $3,301 in 1994
Service - Billed 71,753 81,289
- Unbilled 33,068 38,153
Other Accounts Receivable 8,351 12,088
Prepaid Income Taxes 1,863 28,068
Inventories, at Average Cost
Fuel Oil 3,181 4,113
Materials and Supplies 13,887 13,026
Funds on Deposit With Trustee 27,910 27,820
Prepayments and Other Current Assets 9,383 9,337
Total Current Assets 231,091 272,006
DEFERRED CHARGES AND OTHER ASSETS
Recoverable Costs of Seabrook 1 and Abandoned
Projects, Net 96,977 101,976
Regulatory Assets-Deferred Taxes 234,013 233,234
Yankee Atomic Purchase Power Contract 34,130 38,777
Other Deferred Charges and Other Assets 267,647 276,597
Deferred Charges and Other Assets, Net 632,767 650,584
TOTAL ASSETS $1,986,504 $2,046,007
The accompanying notes are an integral part of these financial
</TABLE>
statements.<PAGE>
Central Maine Power Company
CONSOLIDATED BALANCE SHEET
(Dollars in Thousands)
<TABLE>
<S> <C> <C>
Sept. 30, Dec. 31,
1995 1994
(Unaudited)
STOCKHOLDERS' INVESTMENT AND LIABILITIES
CAPITALIZATION
Common Stock Investment $ 490,003 $ 491,323
Preferred Stock 65,571 65,571
Redeemable Preferred Stock 74,528 80,000
Long-Term Obligations 627,833 638,841
Total Capitalization 1,257,935 1,275,735
CURRENT LIABILITIES AND INTERIM FINANCING
Interim Financing 39,000 63,000
Sinking Fund Requirements 2,584 2,580
Accounts Payable 71,032 97,800
Dividends Payable 9,823 9,932
Accrued Interest 9,921 14,102
Maine Yankee Sleeving Accrual 7,893 -
Miscellaneous Current Liabilities 18,922 10,535
Total Current Liabilities and
Interim Financing 159,175 197,949
COMMITMENTS AND CONTINGENCIES
RESERVES AND DEFERRED CREDITS
Accumulated Deferred Income Taxes 354,707 348,287
Unamortized Investment Tax Credits 32,958 34,167
Regulatory Liabilities-Deferred Taxes 55,001 53,937
Yankee Atomic Purchase Power Contract 34,130 38,777
Other Reserves and Deferred Credits 92,598 97,155
Total Reserves and Deferred Credits 569,394 572,323
TOTAL STOCKHOLDERS' INVESTMENT
AND LIABILITIES $1,986,504 $2,046,007
The accompanying notes are an integral part of these financial
</TABLE>
statements.<PAGE>
Central Maine Power Company
CONSOLIDATED STATEMENT OF CASH FLOWS
(Unaudited)
(Dollars in Thousands)
(Note 1)
<TABLE>
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For the Nine Months
Ended
September 30,
1995 1994
CASH FROM OPERATIONS
Net Income $ 28,157 $ 40,806
Items Not Requiring (Providing) Cash:
Depreciation and Amortization 61,101 53,825
Deferred Income Taxes and Investment Tax
Credits, Net 4,177 26,511
Maine Yankee Sleeving Accrual 7,893 -
Allowance for Equity Funds Used During
Construction (483) (637)
Changes in Certain Assets and Liabilities:
Accounts Receivable 18,358 39,712
Other Current Assets (136) (4,974)
Inventories 71 2,654
Retail Fuel Costs - 10,499
Accounts Payable (24,685) (19,895)
Accrued Interest (4,181) (4,058)
Prepaid Income Taxes 26,205 (5,546)
Miscellaneous Current Liabilities 8,387 151
Deferred Energy Management Costs (2,524) (4,017)
Maine Yankee Outage Accrual (6,780) (6,247)
Purchase Power Contracts (10,675) (4,996)
Other, Net 2,210 10,251
Net Cash Provided by Operating Activities 107,095 134,039
INVESTING ACTIVITIES
Construction Expenditures (32,673) (29,743)
Changes in Accounts Payable-Investing Activities (2,083) (1,443)
Investment in Associated Companies (600) -
Net Cash Used by Investing Activities (35,356) (31,186)
FINANCING ACTIVITIES
Issuances:
Common Stock - 927
Mortgage Bonds - 25,000
Medium-Term Notes 30,000 -
Redemptions:
Short-Term Obligations - (25,500)
Other Long-Term Obligations - (860)
Preferred Stock (5,472) -
Medium-Term Notes (55,000) (24,000)
Short-Term - Medium-Term Notes (8,000) -
Dividends:
Common Stock (21,916) (21,916)
Preferred Stock (7,768) (7,433)
Net Cash (Used) Provided by Financing
Activities (68,156) (53,782)
Net Increase (Decrease) in Cash 3,583 49,071
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD 58,112 1,956
CASH AND CASH EQUIVALENTS, END OF PERIOD $ 61,695 $ 51,027
</TABLE>
The accompanying notes are an integral part of these financial statements.<PAGE>
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 should be read with the Annual Report on Form 10-K for the
year ended December 31, 1994 (Form 10-K), and 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.
The adoption of the Alternative Rate Plan (ARP), effective
January 1, 1995, eliminated the reconcilable fuel clause used
under traditional rate-of-return regulation to account for and
collect fuel and purchased-power energy costs. Fuel revenues are
now recorded as they are billed rather than deferred and
reflected in revenues over time periods established by the Maine
Public Utilities Commission (MPUC). These effects complicate
quarter-to-quarter comparisons, but seasonality issues will not
affect calendar year comparisons.
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 the nine months
ended September 30, 1995 and 1994 for interest, net of amounts
capitalized, amounted to $41.9 million and $37.6 million,
respectively. Income taxes refunded, net of amounts paid,
amounted to $15.9 million for the nine months ended September 30,
1995, versus a net amount paid of $4.2 million for the
corresponding period in 1994. Income taxes totaling $24.3
million were refunded in the third quarter of 1995, and $28.8
million year-to-date. The Company incurred no new capital lease
obligations in either period.
2. Commitments and Contingencies
(a) Maine Yankee Atomic Power Company Steam Generator Tubes -
The Company, through its equity investment totaling
approximately $26.8 million at September 30, 1995, owns a
38-percent stock interest in Maine Yankee Atomic Power
Company (Maine Yankee), which owns and operates an 860-
megawatt nuclear generating plant in Wiscasset, Maine (the
Maine Yankee Plant or the Plant), and is entitled under a<PAGE>
cost-based power contract to an approximately equal
percentage of the Plant's output. The Maine Yankee Plant,
like other pressurized water reactors, experienced
degradation of its steam generator tubes, principally in the
form of circumferential cracking, which, until early 1995,
was believed to be limited to a relatively small number of
tubes. During the refueling-and-maintenance shutdown that
commenced in early February 1995, Maine Yankee detected
through new inspection methods increased degradation of the
Plant's steam generator tubes to the extent that
approximately 60 percent of the Plant's 17,000 steam
generator tubes appeared to have defects to some degree.
Several courses of action were evaluated to address the
matter, and mitigation of the problem by plugging additional
tubes was not a viable option.
The substantial increase in the number of degraded tubes
resulted in substantial additional costs to Maine Yankee,
with the Company being responsible for its pro-rata share.
In addition, the Company is incurring substantial
replacement power costs, the amount depending on the
duration of the outage and the prices paid for the
replacement power.
With the termination of the reconcilable fuel-and-purchased-
power adjustment under the ARP, costs of replacement power
during a Maine Yankee outage are in general being treated
like other Company expenses, i.e., limited by the ARP's
price-index mechanism, and are not being deferred and
collected through a specific fuel-rate adjustment, as under
pre-1995 ratemaking. Under the ARP no additional price
increase other than the 2.43 percent increase effective July
1, 1995, associated with the price index, will take effect
in 1995 as a result of the Maine Yankee outage. Although
the ARP contains provisions that could result in rate
adjustments based on low earnings or the incurring of
extraordinary costs by the Company, neither provision will
affect prices in 1995.
Following a detailed analysis of the safety, technical and
financial considerations associated with the defective steam
generator tubes, Maine Yankee has been repairing the tubes
by inserting and welding short reinforcing sleeves of an
improved material in all of the Plant's steam generator
tubes. Similar repairs have been completed at other nuclear
plants in the United States and abroad, but not on the scale
of the Maine Yankee project.
On May 22, 1995, the federal Nuclear Regulatory Commission
(NRC) issued a license approving the sleeving process of
Westinghouse Electric Corporation (Westinghouse) for the
Plant. On the same day, the Board of Directors of Maine
Yankee authorized management to undertake the sleeving
project, and on May 24, 1995, Maine Yankee selected
Westinghouse as the contractor for the project. The
sleeving project started in early June and is nearing
completion, with the Plant expected to return to service by
the end of 1995. On October 25, 1995, Maine Yankee began
re-loading fuel into the Plant's reactor.
Maine Yankee is recording the sleeving costs as maintenance
expense. The Company estimated its share of such costs to
be $15.0 million and recorded a one-time charge for that<PAGE>
amount to purchased power-capacity expense in the second
quarter of 1995. Maine Yankee has billed the Company $7.1
million as of September 30, 1995, for costs incurred. In
addition, the Company is incurring additional fuel costs
over and above what it would have incurred if the Maine
Yankee Plant had continued to operate, in the range of
approximately $3.5 million to $4.5 million per month while
the outage persists, and both the Company and Maine Yankee
have implemented cost-reduction measures to partially offset
the additional costs. The Company's incremental
replacement-power costs were approximately $11 million in
the third quarter, and approximately $22 million for the
nine months ended September 30, 1995.
Although the repairs are on schedule to be completed by the
end of 1995, the Company cannot predict with certainty how
long the Plant will be out of service. The impact of the
Company's replacement-power costs and its share of the Maine
Yankee sleeving costs will have a material adverse effect on
the Company's financial results for 1995.
(b) 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
was 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.
In July 1994, the EPA approved 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 inability to reduce
PCBs and other chemical components on the site to the
original standard.
In June 1995, after discussions between the Company and the
EPA, design work on the selected remedy was suspended. On
July 7, 1995, the Company formally requested that the EPA
abandon that remedy for an already-designated alternative
remedy that the Company believes could result in
substantially lower costs. On October 10, 1995, the EPA
approved the new remedy after determining that the old
remedy was no longer feasible or cost-effective at the site.
The new remedy involves transporting the contaminated soil
to a secure off-site landfill.
The Company believes that its share of the remaining costs
of the cleanup under the new method could total
approximately $4 million to $5 million. Such estimate is
net of an agreed partial insurance recovery and the 1993
court-ordered contribution of 41 percent from Westinghouse
Electric Corp., but does not reflect any possible
contributions from other insurance carriers the Company has
sued, or any other parties. The Company has recorded an<PAGE>
estimated liability of $11 million, the pre-October 10, 1995
estimated cost of clean-up, and an equal regulatory asset,
reflecting an accounting order to defer such costs and the
anticipated ratemaking recovery of such costs when
ultimately paid. As a result of the change in remedy, the
Company is reviewing its estimate of its minimum liability.
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.
3. Regulatory Matters
Alternative Rate Plan - In December 1994, the MPUC approved a
stipulation signed by most of the parties to the Company's ARP
proceeding. See Note 3 to Consolidated Financial Statements
included in the Company's Form 10-K for a detailed description of
the ARP. This follow-up proceeding to the Company's 1993 base-
rate case was ordered by the MPUC in an effort to develop a five-
year plan containing price-cap, profit-sharing, and pricing-
flexibility components. Although the ARP is a major reform, the
MPUC will continue to regulate the Company's operations and
prices and provide for continued recovery of deferred costs.
The Company believes, as stated in the MPUC's order approving the
ARP, that operation under the ARP continues to meet the criteria
of SFAS No. 71. In its order, the MPUC reaffirmed the
applicability of previous accounting orders allowing the Company
to reflect amounts as deferred charges and regulatory assets. 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.
The ARP contains a mechanism that provides price-caps on 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 applies to all of
the Company's retail rates, including the Company's fuel-and-
purchased-power cost, which previously had been treated
separately. Under the ARP, fuel expense is no longer subject to
reconciliation or specific rate recovery, but is subject to the
annual indexed price-cap changes.<PAGE>
The ARP also provides for partial flow-through to ratepayers of
cost savings from non-utility generator contract buy-outs and
restructuring, recovery of energy-management costs, penalties for
failure to attain customer-service and energy-efficiency targets,
and specific recovery of half the costs of the transition to the
accounting method required by Statement of Financial Accounting
Standards No. 106, "Accounting for Postretirement Benefits Other
Than Pensions" (SFAS No. 106), the remaining 50 percent to be
recovered through the annual price-cap change. The ARP 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 have a disproportionate effect on the Company or
the electric power industry.
The ARP also contains provisions to protect the Company and
ratepayers against unforeseen adverse results from its operation.
These include review by the MPUC if the Company's actual return
on equity falls outside the designated 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.
On July 1, 1995, the Company's first annual increase in rates and
rate-element caps under the ARP of 2.43 percent became effective.
The components of the increase included the inflation index of
2.92 percent, reduced by a productivity offset of 0.5 percent and
increased by 0.01 percent for flowthrough items and mandated
costs. Under prior long-term agreements, price discounts for
competitively targeted customer classes are not affected by the
increase.
4. Capitalization and Interim Financing
On May 24, 1995, the shareholders of the Company, by a vote of
50.36 percent to 49.64 percent, approved a shareholder proposal
at the Company's annual meeting of shareholders recommending
redemption of the rights and termination of the Shareholder
Rights Plan adopted by the Company on September 28, 1994, (see
Note 7 of Notes to Consolidated Financial Statements in the
Company's Form 10-K). The Shareholder Rights Plan was meant to
provide protection against abusive or discriminatory takeover
tactics. On July 19, 1995, the Board of Directors of the Company
terminated, effective immediately, the right to exercise the
Rights issued to its shareholders pursuant to the Shareholder
Rights Plan and ordered the redemption of the Rights. The Board
directed payment of the redemption price of $.01 per Right on
August 28, 1995, to holders of record at the close of business on
August 14, 1995. This one-time payment amounted to $324,428.
5. Pensions and Other Postemployment Benefits
In May 1995, the Company announced a Special Retirement Offer
(SRO) to all employees aged 50 or more who had at least five
years of continuous service. The goal of the SRO was to help the
Company achieve financial savings and make the organizational
changes it needs to be an effective competitor in the energy
marketplace. Approximately 200 employees accepted the SRO.
As a result, the Company recorded a one-time charge of $4.8
million associated with the SRO in the second quarter of 1995.
The SRO also included certain permanent retirement-benefit<PAGE>
enhancements for all employees, the cost of which will be
amortized to pension expense over the remaining service life of
active employees.
6. Income Taxes
The effective federal income tax rate for the year ended December
31, 1994 was 31.2%. For the three and the nine months ended
September 30, 1995 the effective federal tax rates were 27.1% and
30.7%, 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
The third quarter of 1995 generated net income of $10.4 million
compared to $14.1 million for the corresponding period in 1994.
Year-to-date net income was $28.2 million versus $40.8 million
for the 1994 period.
Year-to-date net income was affected by the second quarter 1995,
one-time, pre-tax charges of $15.0 million for the Company's
entire estimated cost of tube sleeving at Maine Yankee (see Note
2 "Commitments and Contingencies - Maine Yankee Atomic Power
Company Steam Generator Tubes"), and $4.8 million of costs
associated with the SRO that reduced the work force by 200 for
employees accepting the offer as of June 30, 1995 (see Note 5
"Pensions and Other Postemployment Benefits").
Earnings applicable to Common Stock were $7.9 million or $0.24
per share for the third quarter compared to earnings of $11.5
million or $0.35 per share for the comparable period in 1994.
Year-to-date earnings applicable to Common Stock were $20.5
million or $0.63 per share and $32.9 million or $1.01 per share
in 1994. The one-time charges, net of tax, included in the year-
to-date numbers were $8.9 million or $0.27 per Common Share for
Maine Yankee tube-sleeving and $2.8 million or $0.09 per share
for the SRO.
Operating revenues decreased by $3.1 million or 0.5 percent to
$684 million in the first nine months of 1995. Operating
revenues for the third quarter of 1995 of $218 million were 6.7
percent less than the third quarter of 1994.
Revenues were affected by flat or lower kilowatt-hour sales, a
1994 price increase for most customers, price discounts for
competitively targeted customer classes and the elimination under
the ARP that took effect January 1, 1995, of reconciliation
treatment for fuel and purchased-power expenses.
The adoption of the ARP effective January 1, 1995 had a
significant impact on the results of operations for the first
nine months of 1995 when compared to 1994. The ARP price-cap
method of ratemaking eliminates the reconcilable fuel clause used
under traditional rate-of-return regulation to account for and
collect fuel and purchased-power energy costs. One impact of
this change is that seasonality in prices and certain accounting
treatments for fuel revenues can produce more volatility in
quarterly results than occurred under the prior ratemaking
treatment. These effects complicate quarter-to-quarter
comparisons, but seasonality issues will not affect calendar year
comparisons.
Under that discontinued mechanism, fluctuations in fuel costs
required the Company to record unbilled fuel revenue for any fuel
costs incurred in excess of the amounts actually collected in
each respective period. If fuel collections exceeded fuel costs
a charge to revenue was made during that period. The effect of
the fuel cost adjustment mechanism was to ensure that all fuel
costs incurred were ultimately collected from customers at some
time in the future. This fuel mechanism also resulted in the
allocation of a greater portion of the customers' rates to fuel
revenues in the winter months and traditionally resulted in a<PAGE>
charge to revenues in the winter months as fuel revenues
collected normally exceed fuel costs. With the elimination of
the reconcilable fuel mechanism under the ARP, fuel revenues are
now recorded as they are billed. Therefore, the traditional
charge to revenues for fuel overcollections in the winter months
no longer occurs, affecting revenues for the first nine months of
1995.
Service-area sales for the third quarter of 1995 totaled
approximately 2.3 billion kilowatt-hours and were 0.7 percent
greater than the third quarter of 1994. Service-area sales of
electricity totaled approximately 6.8 billion kilowatt-hours for
the nine-month period ended September 30, 1995, a decrease of 3.1
percent compared to the first nine months of 1994.
<TABLE>
<S> <C> <C> <C> <C> <C> <C>
Service Area Kilowatt-hour Sales (Millions of KWHs)
Period Ended September 30,
Three Months Nine Months
% %
1995 1994 Change 1995 1994 Change
Residential 665.8 653.5 1.9% 2,117.1 2,196.2 (3.6)%
Commercial 664.9 651.1 2.1 1,873.9 1,871.8 0.1
Industrial 957.8 966.1 (0.9) 2,702.2 2,827.8 (4.4)
Other 34.5 37.1 (6.8) 102.3 116.2 (11.9)
2,323.0 2,307.8 0.7% 6,795.5 7,012.0 (3.1)%
</TABLE>
The changes in service area kilowatt-hour sales reflect the
following:
Kilowatt-hour sales to residential customers increased by
1.9 percent in the third quarter and decreased by 3.6
percent for the nine months ended September 30, 1995
compared to 1994; usage per customer increased 0.8 percent
in the third quarter and decreased 4.7 percent for the nine
months ended September 30, 1995. Warmer than normal winter
temperatures and declines in the space and water heating
subclass usage contributed to the annual decrease.
Commercial sales increased by 2.1 percent and 0.1 percent
for the three-month and nine-month periods from 1994,
reflecting increases or flat sales in most sectors for the
quarter and moderate growth in the retail and transporta-
tion, communication and utility sectors year-to-date.
Industrial kilowatt-hour sales decreased by 0.9 percent in
the third quarter and by 4.4 percent for the nine months
ended September 30, 1995 compared to 1994 due primarily to
decreased sales to the pulp and paper industry of 4.4
percent in the third quarter and 9.1 percent for the nine-
month period ended September 30, 1995. This sector accounts
for approximately 63 percent of the industrial sales
category. The primary factor in the decline in sales to
this industry was the loss of 127 million kilowatt-hours of
sales formerly made to a customer who began taking service
from another utility in late 1994. See Note 4 to
Consolidated Financial Statements in the Company's Form 10-K
for a detailed discussion of this matter. A sales increase
of 6.1 percent for the third quarter and 4.6 percent for the
nine months ended September 30, 1995 occurred in all other
industrial customers as a group.<PAGE>
The components of the change in electric operating revenues for
the nine months ended September 30, 1995, as compared to the same
period in 1994, are as follows:
<TABLE>
<S> <C> <C>
Three Nine
Months Months
(Dollars in Thousands)
Revenues from Kilowatt-hour Sales $(17,790) $(10,574)
Other Operating Revenues, including
Maine Electric Power Company, Inc. 2,119 7,437
Total Change in Electric Operating
Revenues $(15,671) $(3,137)
</TABLE>
Total service-area base revenues decreased for the third quarter
and the nine months ended September 30, 1995 reflecting flat or
lower kilowatt-hour sales, a December 1994 annual price decrease
totaling $5.6 million, and the discounted rates given
competitively positioned customers effective with the ARP.
Seasonal fluctuations in fuel revenues will continue throughout
the remainder of 1995. For a complete discussion of discounted
rates, see Note 4 to Consolidated Financial Statements in the
Company's Form 10-K.
MEPCO's electric sales and transmission revenues from New England
utilities other than the Company (included in other operating
revenues in the preceding table) amounted to $4.2 million and
$1.5 million in the third quarters of 1995 and 1994,
respectively. These same totals for the nine-months ended
September 30, 1995 and 1994 were $8.7 million and $4.3 million,
respectively. Under a Participation Agreement that terminates on
July 1, 1996, subject to certain rights to continued
participation, all of MEPCO's costs, including a return on
invested capital, are paid by the participating utilities
(Participants), which include the Company and most of the larger
New England electric companies. The level of MEPCO's revenues
and expenses changes depending upon the level of energy purchases
by Participants.
Purchased power-capacity expense decreased by $3.1 million in the
third quarter of 1995 and increased by $17.2 million in the nine
months ended September 30, 1995. The nine-month period includes
the one-time pre-tax charge of $15.0 million for the Company's
entire estimated cost of the tube sleeving at Maine Yankee. The
Maine Yankee charge, which represents CMP's share of the
previously reported estimated total repair cost of $40.0 million,
was accrued in the second quarter of 1995; actual billings for
repair work will continue through year-end 1995. Other charges
in the nine-month period included higher nuclear capacity expense
at two other nuclear plants in which the Company has an equity
interest. The year-to-date expense comparison also includes the
1994 credit for the reversal of a $4.1 million "capacity
deficiency fund". A January 1994 MPUC-approved stipulation
favorably resolved all issues related to that fund.
Other operation and maintenance expenses increased by $5.6
million compared to the third quarter of 1994 and $23.2 million
compared to the first nine months of 1994. These increases
primarily reflect significantly higher monthly charges for
amortization of purchased-power contract buy-outs and the one-
time pre-tax charge of $4.8 million for costs associated with the
Company's SRO. Energy-management expenses increased slightly in<PAGE>
both periods.
Federal and state income taxes decreased by $4.1 million in the
third quarter and by $10.7 million for the nine months ended
September 30, 1995. Federal and state income taxes fluctuate
with the level of pre-tax earnings and the regulatory treatment
of taxes by the MPUC. Lower pre-tax earnings were attributable to
lower sales levels and the one-time charges for Maine Yankee tube
sleeving and the SRO. The tax effects, applicable to the nine
months ended September 30, 1995, of these one-time charges were
decreases of $6.1 million for Maine Yankee tube sleeving and $2.0
million for the SRO.
Interest on long-term debt during the third quarter of 1995
increased by approximately $1.1 million and $4.2 million for the
first nine months of 1995 while other interest expense decreased
slightly compared to 1994. The increase reflects higher levels
of outstanding long-term debt when compared to 1994. The
increased debt results from the issuance of additional mortgage
bonds during 1994 and the note to the Finance Authority of Maine
issued to finance the buyout of a large non-utility generator
(NUG) contract in 1994.
Liquidity and Capital Resources
Approximately $100.8 million of cash was provided during the
first nine months of 1995 from net income before non-cash items,
primarily depreciation and amortization and the accrual of the
estimated cost of the Maine Yankee tube sleeving. During such
period, approximately $6.3 million of cash was provided by
fluctuations in certain assets and liabilities and from other
operating activities.
During the first nine months of 1995, the Company reduced the
level of preferred stock outstanding by $5.5 million through
normal sinking fund requirements. Dividends paid on common stock
were $21.9 million, while preferred-stock dividends utilized $7.8
million of cash. Medium-Term Notes were reduced by $33.0
million.
Investing activities, primarily construction expenditures,
utilized $35.4 million in cash during the first nine months of
1995 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-supply sources 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.
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<PAGE>
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 replaced the Company's $73
million of individual lines of credit.
Several credit-rating actions relating to the Company's
securities took place in early 1995, when the Company's actions
taken during 1994 with respect to cost control, NUG cost
reductions, the regulatory reform under the ARP, and the
competitive pricing agreements with large customers, were
recognized by Moody's Investors Service (Moody's) which upgraded
the Company's ratings on preferred stock and commercial paper,
and Duff & Phelps Credit Rating Co. (Duff & Phelps), which
upgraded its preferred stock rating. After announcement of the
Maine Yankee steam generator tube issues Duff & Phelps placed the
Company on "credit watch" for possible downgrade, but on May 25,
1995, removed the Company's fixed-income securities from "Rating
Watch--Down" and reaffirmed the Company's ratings. Moody's
reaffirmed its ratings of the Company's securities on June 19,
1995, including its negative rating outlook. Standard and Poor's
Corp. continues to monitor the Maine Yankee situation and its
impact on its ratings of the Company's securities.
Stranded Costs
The enactment by Congress of the Energy Policy Act of 1992
accelerated planning by electric utilities, including the
Company, for the anticipated transition to a more competitive
industry. The functional areas in which competition will take
place, the regulatory changes that will be implemented, and the
resulting structure of both the industry and the Company are all
uncertain, but the likelihood of a transition to direct
competition to serve retail customers is widely anticipated. A
departure from traditional regulation, however, could have
substantial impacts on the value of utility assets and on the
ability of electric utilities to recover their costs through
rates. In the absence of full recovery, utilities would find
their above-market costs to be "stranded", or unrecoverable, in
the new competitive setting.
The Company has substantial exposure to cost stranding relative
to its size, principally in the form of its long-term contract
obligations to buy non-utility power at average prices above
prices that could currently be achieved in the open market. In
addition, the Company's deferred charges, which are being
recovered in rates, could be impaired. Based on current costs
and obligations the present value of excess costs over market
rates for electricity could be as much as approximately three to
four times the amount of the Company's common equity. However,
the amount of the Company's embedded costs in excess of what
could be recovered if electricity prices were set at market
levels that could be potentially at risk of recovery is dependent
on such factors as the length of the transition period to open
competition, the market rate for electricity, the terms and
conditions, including stranded cost recovery provisions, of open<PAGE>
competition and the overall level of the Company's costs.
On March 29, 1995, as part of a broader Notice of Proposed
Rulemaking (NOPR) related to open transmission access and
stranded costs, and designed to facilitate the development of a
competitive market, the Federal Energy Regulatory Commission
(FERC) expressed support for the principle that utilities are
entitled to full recovery of their "legitimate and verifiable"
stranded costs at both the state and federal levels. Earlier,
the MPUC had initiated a rulemaking proceeding on stranded costs
at the retail level with a preliminary proposal that recommended
less than full recovery of such costs, but terminated its
proceeding after FERC issued its NOPR to avoid "parallel and
duplicative proceedings". A diverse committee appointed by the
Maine Legislature is in the process of developing recommendations
for the MPUC on the future structure of the electric utility
industry in Maine.
Substantial opposition has emerged in the FERC proceeding to
allowing full recovery of stranded costs, largely from customer
groups and NUGs. The stranding of a major portion of its costs
would have a material adverse effect on the Company's results of
operations, depending on the amounts involved. The Company
believes that it is entitled to recover substantially all of its
potentially strandable costs under existing regulatory
principles, but cannot predict how much of such costs it will
ultimately be allowed to recover at the state or federal level.<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.
Regulatory Matters. For a discussion of certain other Regulatory
matters affecting the Company, see Note 3, "Regulatory Matters,"
which is incorporated herein by reference.
Item 2. through Item 4. Not applicable
Item 5. Other Events
Maine Yankee Steam Generator Tubes. For a discussion of issues
arising from the discovery of a large number of degraded steam
generator tubes at the Maine Yankee plant see Note 2,
"Commitments and Contingencies," "Maine Yankee Atomic Power
Company Steam Generator Tubes," which is incorporated herein by
reference.
Stranded Costs. The enactment by Congress of the Energy Policy
Act of 1992 accelerated planning by electric utilities, including
the Company, for the anticipated transition to a more competitive
industry. The functional areas in which competition will take
place, the regulatory changes that will be implemented, and the
resulting structure of both the industry and the Company are all
uncertain, but the likelihood of a transition to direct
competition to serve retail customers is widely anticipated. A
departure from traditional regulation, however, could have
substantial impacts on the value of utility assets and on the
ability of electric utilities to recover their costs through
rates. In the absence of full recovery, utilities would find
their above-market costs to be "stranded", or unrecoverable, in
the new competitive setting.
The Company has substantial exposure to cost stranding relative
to its size, principally in the form of its long-term contract
obligations to buy non-utility power at average prices above
prices that could currently be achieved in the open market. In
addition, the Company's deferred charges, which are being
recovered in rates, could be impaired. Based on current costs
and obligations the present value of excess costs over market
rates for electricity could be as much as approximately three to
four times the amount of the Company's common equity. However,
the amount of the Company's embedded costs in excess of what
could be recovered if electricity prices were set at market
levels that could be potentially at risk of recovery is dependent
on such factors as the length of the transition period to open
competition, the market rate for electricity, the terms and
conditions, including stranded cost recovery provisions, of open
competition and the overall level of the Company's costs.
On March 29, 1995, as part of a broader Notice of Proposed
Rulemaking ("NOPR") related to open transmission access and
stranded costs, and designed to facilitate the development of a
competitive market, the Federal Energy Regulatory Commission<PAGE>
("FERC") expressed support for the principle that utilities are
entitled to full recovery of their "legitimate and verifiable"
stranded costs at both the state and federal levels. Earlier,
the MPUC had initiated a rulemaking proceeding on stranded costs
at the retail level with a preliminary proposal that recommended
less than full recovery of such costs, but terminated its
proceeding after FERC issued its NOPR to avoid "parallel and
duplicative proceedings". A diverse committee appointed by the
Maine Legislature is in the process of developing recommendations
for the MPUC on the future structure of the electric utility
industry in Maine.
Substantial opposition has emerged in the FERC proceeding to
allowing full recovery of stranded costs, largely from customer
groups and NUGs. The stranding of a major portion of its costs
would have a material adverse effect on the Company's results of
operations, depending on the amounts involved. The Company
believes that it is entitled to recover substantially all of its
potentially strandable costs under existing regulatory
principles, but cannot predict how much of such costs it will
ultimately be allowed to recover at the state or federal level.
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 1995
and thereafter to date:
Date of Report Items Reported
July 19, 1995 Item 5
(a) The Company announced its second-quarter financial results,
pointing out specifically that one-time accounting charges for
the costs of the steam-generator tube sleeving project at the
Maine Yankee plant and the costs of an early retirement program
at the Company had resulted in an $11.2 million second-quarter
loss for the Company.
(b) The Company also reported that on July 19, 1995, its Board
of Directors had terminated the right to exercise the rights
issued under its Shareholder Rights Plan, effective immediately,
and that it would pay the redemption price of one cent per right
on August 28, 1995, to holders of record on August 14, 1995.
(c) The Company also reported that Robert E. Tuoriniemi had been
elected Comptroller of the Company, effective August 1, 1995, to
fill the vacancy caused by a retirement.<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 13, 1995 /S/Robert E. Tuoriniemi
Robert E. Tuoriniemi, Comptroller (Chief
Accounting Officer)
/S/David E. Marsh
David E. Marsh, Vice President,
Corporate Services, Treasurer and Chief
Financial Officer (Principal Financial
Officer and duly authorized officer)<PAGE>
<TABLE> <S> <C>
<ARTICLE> UT
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 9-MOS
<FISCAL-YEAR-END> DEC-31-1994
<PERIOD-END> SEP-30-1995
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 1,068,964
<OTHER-PROPERTY-AND-INVEST> 53,682
<TOTAL-CURRENT-ASSETS> 231,091
<TOTAL-DEFERRED-CHARGES> 632,767
<OTHER-ASSETS> 0<F1>
<TOTAL-ASSETS> 1,986,504
<COMMON> 162,214
<CAPITAL-SURPLUS-PAID-IN> 276,234
<RETAINED-EARNINGS> 51,555
<TOTAL-COMMON-STOCKHOLDERS-EQ> 490,003
74,528
65,571
<LONG-TERM-DEBT-NET> 591,686
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 39,860
0
<CAPITAL-LEASE-OBLIGATIONS> 36,147
<LEASES-CURRENT> 1,724
<OTHER-ITEMS-CAPITAL-AND-LIAB> 686,985
<TOT-CAPITALIZATION-AND-LIAB> 1,986,504
<GROSS-OPERATING-REVENUE> 683,768
<INCOME-TAX-EXPENSE> 12,695
<OTHER-OPERATING-EXPENSES> 610,740
<TOTAL-OPERATING-EXPENSES> 623,435
<OPERATING-INCOME-LOSS> 65,582
<OTHER-INCOME-NET> 3,512
<INCOME-BEFORE-INTEREST-EXPEN> 69,094
<TOTAL-INTEREST-EXPENSE> 40,937
<NET-INCOME> 28,157
7,659
<EARNINGS-AVAILABLE-FOR-COMM> 20,498
<COMMON-STOCK-DIVIDENDS> 21,916
<TOTAL-INTEREST-ON-BONDS> 23,070
<CASH-FLOW-OPERATIONS> 107,095
<EPS-PRIMARY> 0.63
<EPS-DILUTED> 0.63
<FN>
<F1>Included in Total Deferred Charges.
</FN>
<PAGE>
</TABLE>
