SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 8-K
CURRENT REPORT
Pursuant to Section 13 or 15(d) of the
Securities Exchange Act of 1934
Date of Report (Date of earliest event reported): October 14,
1994
CENTRAL MAINE POWER COMPANY
(Exact name of registrant as specified in its charter)
Maine 1-5139 01-0042740
(State of Incorporation) (Commission (IRS Employer
File Number) Identification Number)
83 Edison Drive, Augusta, Maine 04336
(Address of principal executive offices) (zip code)
Registrant's telephone number, including area code:(207) 623-3521<PAGE>
Item 1 through Item 4. Not applicable.
Item 5. Other Events.
(a) Alternative rate plan stipulation and planned
restructuring charges. As previously reported, in its
December 14, 1993, base-rate order, the Maine Public Utilities
Commission (the "MPUC") ordered that a follow-up proceeding to
the Company's base-rate proceeding be held to implement my 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
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,<PAGE>
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
buyouts and restructurings, 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 Financial Accounting Standards Board
Standard No. 106 accounting treatment of post-retirement benefits
other than pensions. 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 must exceed $3 million and 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 better position
itself to achieve timely restoration of competitive financial
results the Company agreed that it would take the following
before-tax "restructuring charges" against 1994 earnings:
(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<PAGE>
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 adjust rates
below the price-cap limit 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 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.
Item 6 through Item 8. Not applicable.<PAGE>
SIGNATURE
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
By:
David E. Marsh
Vice President, Corporate Services,
and Chief Financial Officer
Dated: October 14, 1994<PAGE>
